ML19324C988

Amendment 28 to Updated Final Safety Analysis Report, Chapter 5, Containment - Redacted

ML19324C988
Person / Time
Site:	Browns Ferry
Issue date:	10/04/2019
From:	Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation
References
Download: ML19324C988 (174)

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{{#Wiki_filter:BFN-27 5.0-i CONTAINMENT TABLE OF CONTENTS 5.0 CONTAINMENT........................................................................................................................ 5.1-1 5.1 Summary Description................................................................................................................ 5.1-1 5.1.1 General...................................................................................................................... 5.1-1 5.1.2 Primary Containment................................................................................................. 5.1-1 5.1.3 Secondary Containment............................................................................................ 5.1-1 5.2 Primary Containment System.................................................................................................... 5.2-1 5.2.1 Safety Objective......................................................................................................... 5.2-1 5.2.2 Safety Design Basis................................................................................................... 5.2-1 5.2.3 Description................................................................................................................. 5.2-2 5.2.4 Safety Evaluation....................................................................................................... 5.2-22 5.2.5 Inspection and Testing............................................................................................... 5.2-36 5.2.6 Combustible Gas Control in Primary Containment..................................................... 5.2-39 5.2.7 Hardened Wetwell Vent............................................................................................. 5.2-51 5.2.8 Hardened Containment Venting Systems.5.2-52 5.3 Secondary Containment System............................................................................................... 5.3-1 5.3.1 Safety Objective......................................................................................................... 5.3-1 5.3.2 Safety Design Basis................................................................................................... 5.3-1 5.3.3 Secondary Containment System Description............................................................. 5.3-2 5.3.4 Safety Evaluation....................................................................................................... 5.3-20 5.3.5 Inspection and Testing............................................................................................... 5.3-25

BFN-27 5.0-ii CONTAINMENT LIST OF TABLES Table Title 5.2-1 Principal Design Parameters and Characteristics of Primary Containment 5.2-2 Principle Primary Containment Penetrations and Associated Isolation Valves 5.2-3 (Deleted) 5.2-4 (Deleted)

BFN-28 5.0-iii CONTAINMENT LIST OF ILLUSTRATIONS Figure Title 5.2-1a Primary Containment Vessels 5.2-1b (Deleted) 5.2-1c (Deleted) 5.2-2 (Deleted) 5.2-2a sht 1 Primary Containment System, Mechanical Control Diagram 5.2-2a sht 2 Primary Containment System - Mechanical Control Diagram 5.2-2a sht 3 Primary Containment System - Mechanical Control Diagram 5.2-2b Primary Containment System, Mechanical Control Diagram 5.2-2c Primary Containment System, Mechanical Control Diagram 5.2-2d Primary Containment System - Mechanical Control Diagram 5.2-2e Primary Containment System - Mechanical Control Diagram 5.2-2f Primary Containment System - Mechanical Control Diagram 5.2-2g Primary Containment System - Mechanical Control Diagram 5.2-3 Types of Penetrations for Process Lines 5.2-4 Penetration Assembly for Process Lines 5.2-4a Compression Fitting Assembly for Small, Low Pressure Line Penetrations 5.2-5 Electrical and Control Penetration 5.2-5b (Deleted) 5.2-5c (Deleted) 5.2-5d (Deleted) 5.2-5e (Deleted) 5.2-6a sht 1 Containment Inerting Mechanical Control Diagram 5.2-6a sht 2 Containment Inerting System - Mechanical Control Diagram 5.2-6a sht 3 Containment Inerting System - Mechanical Control Diagram 5.2-6a sht 4 Containment Inerting System - Mechanical Control Diagram 5.2-6a sht 5 Containment Inerting System - Mechanical Control Diagram 5.2-6a sht 6 Containment Inerting System - Mechanical Control Diagram 5.2-6a sht 7 Containment Inerting System - Mechanical Control Diagram 5.2-6b Primary Containment Cooling Temperature Monitoring System - Mechanical Control Diagram (Unit 1) 5.2-6c Primary Containment Cooling Temperature Monitoring System - Mechanical Control Diagram (Unit 2) 5.2-6d Primary Containment Cooling Temperature Monitoring System - Mechanical Control Diagram (Unit 3) 5.2-6e Drywell Pipe Whip Protection 5.2-6f Drywell Vent Pipe Expansion Bellows 5.2-6g Drywell Vent Pipe Expansion Bellows View A 5.2-7 sht 1 Containment Atmosphere Dilution System, Flow Diagram 5.2-7 sht 2 Containment Atmosphere Dilution System - Flow Diagram 5.2-7 sht 3 Containment Atmosphere Dilution System - Flow Diagram 5.2-8 sht 1 Containment Atmosphere Dilution System, Mechanical Control Diagram 5.2-8 sht 2 Containment Atmosphere Dilution System - Mechanical Control Diagram 5.2-8 sht 3 Containment Atmosphere Dilution System - Mechanical Control Diagram

BFN-28 5.0-iv CONTAINMENT LIST OF ILLUSTRATIONS (Cont'd) Figure Title 5.2-9 (Deleted) 5.2-10 (Deleted) 5.2-11 (Deleted) 5.2-12 (Deleted) 5.2-13 Hydrogen and Oxygen Concentrations in Containment Following LOCA without Nitrogen Injection (Safety Guide 7 Assumptions, ATRIUM 10 Fuel, No Containment Leakage, 3952 MWt) 5.2-13a (Deleted) 5.2-14 Hydrogen and Oxygen Concentrations in Drywell Following LOCA with Nitrogen Injection (Safety Guide 7 Assumptions, ATRIUM 10 Fuel, No Containment Leakage, 3952 MWt) 5.2-14a (Deleted) 5.2-15 Hydrogen and Oxygen Concentrations in Pressure Suppression Chamber Following LOCA with Nitrogen Injection (Safety Guide 7 Assumptions, ATRIUM 10 Fuel, No Containment Leakage, 3952 MWt) 5.2-15a (Deleted) 5.2-16 Maximum Nitrogen Required for Dilution, scf at 20 degrees C and one atm (Safety Guide 7 Assumptions, ATRIUM 10 Fuel, No Containment Leakage, 3952 MWt) 5.2-16a (Deleted) 5.2-17 Maximum Containment Pressure Following LOCA with Nitrogen Injection (Safety Guide 7 Assumptions, ATRIUM 10 Fuel, No Containment Leakage, 3952 MWt) 5.2-17a (Deleted) 5.2-18 (Deleted) 5.2-19 Convection Flow Path Through Personnel Access Room 5.2-20 Convection Flow Path Through Personnel Access Room 5.2-21 Convection Flow Path Through Personnel Access Room 5.2-22 (Deleted) 5.3-1 Secondary Containment Typical Pipe Penetration 5.3-2 Secondary Containment Typical Electrical Penetrations 5.3-2a Secondary Containment Typical Horizontal Penetrations Through Wall Requiring Pressure Seal 5.3-2b Secondary Containment Typical Vertical Penetration Through Floor Requiring Pressure Seal 5.3-2c Side View of Secondary Containment Horizontal Penetration Through Wall Requiring Pressure Seal 5.3-2d Secondary Containment Typical Penetration Through Wall or Floor Opening Not Requiring a Pressure Seal 5.3-3a Heating and Ventilation Air Flow Diagram 5.3-3b Heating and Ventilating-Standby Gas Treatment System, Flow Diagram 5.3-3c Unit 2 - Heating and Ventilation Air Flow, Flow Diagram 5.3-3d Heating and Ventilation - Flow Diagram 5.3-4 (Deleted)

BFN-27 5.0-v CONTAINMENT LIST OF ILLUSTRATIONS (Cont'd) Figure Title 5.3-5 Secondary Containment Typical Duct Penetration 5.3-6 (Deleted) 5.3-7 (Deleted) 5.3-8 (Deleted) 5.3-9 Standby Gas Treatment System, Mechanical Control Diagram 5.3-10 Browns Ferry Purge System

BFN-27 5.1-1 5.0 CONTAINMENT 5.1

SUMMARY

DESCRIPTION 5.1.1 General The containment systems provide a multibarrier, pressure suppression containment employing containment-in-depth principles in the design. The fuel, fuel cladding, and Reactor Coolant System form barriers to the release of fission products and are described in other sections of the report. Herein is described a containment system which is composed of a primary containment and a secondary containment. 5.1.2 Primary Containment The primary containment (as described in Section 5.2.3) consists of a drywell, corresponding steel penetrations, a pressure suppression chamber and vent system, a hardened containment venting system (Units 1 and 2), a hardened wetwell vent (Unit 3), isolation valves, containment cooling systems, pressure differential equipment, instrumentation and other service equipment. 5.1.3 Secondary Containment The secondary containment consists of the entire Reactor Building (as described in Section 5.3). Low-leakage dampers and valves are used to isolate the secondary containment, and the Standby Gas Treatment System is used to maintain the secondary containment at a negative pressure and provide for a controlled, filtered, elevated release of the secondary containment atmosphere under abnormal conditions.

BFN-27 5.2-1 5.2 PRIMARY CONTAINMENT SYSTEM 5.2.1 Safety Objective The safety objective of the Primary Containment System is to provide the capability, in the event of the postulated loss-of-coolant accident, to limit the release of fission products to the plant environs so that offsite doses would be within the guideline values of 10 CFR 50.67. 5.2.2 Safety Design Basis

1.

The Primary Containment System shall have the capability to withstand the peak transient pressure which could occur due to the postulated loss-of-coolant accident, i.e., a mechanical failure of the Reactor Primary System equivalent to the circumferential rupture of one of the main recirculation pipes.

2.

The containment design basis for metal-water reactions and other chemical reactions subsequent to the postulated loss-of-coolant accident shall be consistent with the performance objectives of the Reactor Core Standby Cooling System.

3.

The Primary Containment System shall have the capability to maintain the functional integrity of the system indefinitely after the postulated loss-of-coolant accident.

4.

The containment design shall be adequate to permit filling the primary containment vessel with water above the reactor core.

5.

The Primary Containment System shall be designed to provide means to rapidly condense the steam portion of the flow from the postulated rupture of a recirculation line so that the peak transient pressure shall be substantially less than containment design pressure.

6.

The Primary Containment System shall be designed to provide means to conduct the flow from postulated pipe ruptures to the pressure suppression pool, to distribute such flow uniformly throughout the pool, and to limit pressure differentials between the drywell and the pressure suppression chamber during the various post-accident cooling modes.

7.

The Primary Containment System shall have the capability of limiting leakage during and following the postulated accident to values which are substantially less than leakage rates which would result in offsite doses approaching the reference doses in 10 CFR 50.67.

BFN-27 5.2-2

8.

The Primary Containment System shall have the capability to conduct periodically such leakage tests as may be appropriate to confirm the integrity of the containment at the peak transient pressure resulting from the postulated accident.

9.

The Primary Containment System shall have the capability to withstand jet forces associated with the flow from the postulated rupture of any pipe within the containment.

10.

The Primary Containment System shall provide the capability for rapid closure or isolation of all pipes or ducts which penetrate the primary containment by means which provide a containment barrier in such pipes or ducts as effective as is required to maintain leakage within permissible limits.

11.

The primary containment shall have the capability of being purged with nitrogen to reduce and maintain the containment atmosphere to less than 4 percent oxygen.

12.

The primary containment shall have the capability to withstand the hydrodynamic loading resulting from a postulated LOCA or main steam relief valve actuation. 5.2.3 Description 5.2.3.1 General Each unit employs a pressure suppression containment system which houses the reactor vessel, the reactor coolant recirculating loops, and other branch connections of the Reactor Primary System. The pressure suppression system consists of a drywell, a pressure suppression chamber (alternatively referred to as the torus or wetwell) which stores a large volume of water, a connecting vent system between the drywell and the pressure suppression chamber, isolation valves, containment cooling systems, equipment for establishing and maintaining a pressure differential between the drywell and pressure suppression chamber, and other service equipment. In the event of a process system piping failure within the drywell, reactor water and steam would be released into the drywell air space. The resulting increased drywell pressure would then force a mixture of air, steam, and water through the vents into the pool of water which is stored in the pressure suppression chamber. The steam would condense rapidly and completely in the pressure suppression pool, resulting in rapid pressure reduction in the drywell. Air that is transferred to the pressure suppression chamber pressurizes the chamber and is subsequently vented to the drywell to equalize the pressure between the two vessels. Cooling systems are provided to remove heat

BFN-27 5.2-3 from the drywell and from the water in the pressure suppression chamber, thus cooling the primary containment, when required, under accident conditions. Appropriate isolation valves are actuated during this period to ensure containment of radioactive materials within the primary containment which might be released from the reactor during the course of the accident. If long-term cooling capability is lost, resulting in a pressure increase that would jeopardize the structural integrity of the primary containment, the hardened containment venting system (HCVS) (Units 1 and 2) or hardened wetwell vent (HWWV) (Unit 3) would relieve the corresponding pressure increase. The Primary Containment System is designed as a Class I system (except the drywell pressure suppression chamber pressure differential subsystem -Reference Section 5.2.3.9) in accordance with Appendix C, "Structural Qualification of Subsystems and Components," to the BFNP FSAR. 5.2.3.2 Drywell The drywell is a steel pressure vessel with a spherical lower portion 67 feet in diameter, and a cylindrical upper portion 38 feet 6 inches in diameter. The overall height is approximately 115 feet. The design, fabrication, inspection and testing of the drywell vessel comply with requirements of the ASME Boiler and Pressure Vessel Code, 1965 edition, Section III, Class B, which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywell are fabricated of SA-516 plate. The drywell is designed for a maximum internal pressure of 62 psig coincident with a temperature of 281F, plus the dead, live, and seismic loads imposed on the shell. Thus, in accordance with the ASME Boiler and Pressure Vessel Code, Section III, the drywell design pressure is 56 psig. Thermal stresses in the steel shell due to temperature gradients were taken into account in the design. Special precautions not required by codes were taken in the fabrication of the steel drywell shell. The plate was preheated to a minimum temperature of 200F prior to welding of all seams whose thickness exceeds 1-1/4 inches, regardless of surrounding air temperature. Preheat at a minimum of 100F was applied prior to welding of all seams 1-1/4 inches or less in thickness if the ambient temperature fell below 50F. Charpy V-notch specimens were used for impact testing of plate and forging material to give assurance of proper material properties. Plates, forgings and pipe associated with the drywell have an initial NDT temperature of 0F or lower when tested in accordance with the appropriate code for the materials. It is contended that the drywell will not be pressurized or subjected to substantial stress at temperatures below 30F. The drywell is enclosed in reinforced concrete for shielding purposes to provide additional resistance to deformation and buckling of the drywell over areas where the concrete backs up the steel shell. Above the transition zone, the drywell is

BFN-27 5.2-4 separated from the reinforced concrete by a gap of approximately 2 inches. This gap is filled with polyurethane foam. Irradiation tests have shown that no change in the resilient characteristics will take place for exposures up to 108R. The polyurethane foam filler is 2-1/4 inches maximum thickness polyester-based, flexible foamed slab having the following physical properties. Density 0.116 lb/ft3 Compression set 10 percent at 50 percent compressibility Compressibility 35 percent at 1.0 psi maximum Resilience 20 percent minimum Service temperature 285F maximum The sizing of the expansion gap, in which the foam slab was placed, was based on an ultimate steel shell temperature of 281F and an internal pressure of 56 psi following a postulated reactor loss-of-coolant accident. The maximum pressure and thermal growth as related to compression of the foam slab occurs at the bottom of the juncture of the spherical lower portion and cylindrical upper portion. The total vertical growth was calculated to be 1.02 inches and the horizontal growth 0.36 inches. For the normal operating condition at a temperature of 150F and pressure of 2.0 psi, the growth at the bottom of the knuckle was calculated to be 0.33 inches vertical and 0.14 inches horizontal. In the event of a loss-of-coolant accident, the foam slab would be compressed about 50 percent and the maximum permanent set would be less than 0.1 inch. There is no objection to the substitution of space for foamed slab. Shielding over the top of the drywell is provided by removable, segmented, reinforced concrete shield plugs. In addition to the drywell head, one double door airlock, one bolted CRD removal hatch, and two bolted equipment hatches are provided for access to the drywell. The doors are mechanically interlocked so that neither door may be operated unless the other door is closed and locked. The drywell head and hatch covers are bolted in place and sealed with gaskets. The seals on the hatches and drywell head are designed with double gaskets with intermediate leak taps and are thus capable of being tested for leakage.

BFN-27 5.2-5 The drywell is not normally entered during MODE 1, but access is permissible during MODE 2 or MODE 3. Provisions are made to supply breathing apparatus to personnel while in the drywell, if necessary. During normal reactor operation, the drywell is essentially at atmospheric pressure. The design temperature (during normal operation) is 150F bulk volumetric average DW temperature at 100F RBCCW supply water. This is the maximum value used for the initial drywell temperature at the beginning of a LOCA event. The actual operating temperature is less than this value and is specified in the plant operating procedures. This temperature is maintained by recirculating the drywell atmosphere across forced draft air cooling units which, in turn, are cooled by the Reactor Building Closed Cooling Water System. (See Subsection 10.6.) Provisions made for protection of the drywell against missiles and pipe whipping which could damage the primary containment are discussed in paragraph 5.2.4.6. The primary containment vessels are designed to permit flooding as a means of post-accident recovery following a loss-of-coolant accident. A water volume of approximately 250,000 cubic feet is necessary to accomplish containment flooding to above core level. It is necessary to vent the containment vessels during the reflooding process to prevent overpressurization. The standby coolant supply used to flood the primary containment is discussed in Subsection 4.8, "Residual Heat Removal System." The exposed portions of the interior of the drywell were originally sandblasted and provided with a protective coating consisting of an inorganic zinc primer (Amercoat Dimetcoat 6) with an epoxy topcoat (Amercoat 66). Any repairs or replacement of this protective coating system are performed using other coating system(s) that are design basis accident qualified to ANSI N101.2-1972 and approved by TVA. It is expected that this coating system will satisfactorily withstand temperatures and pressures of the steam environment postulated during a design basis loss-of-coolant accident as described in Section 14.0 of the FSAR. Test panels were exposed to steam-water atmospheres under comparable or greater temperatures and pressures with negligible deterioration. In some cases discoloration and small (<1/8 inch) blisters were observed. 5.2.3.3 Pressure Suppression Chamber and Vent System 5.2.3.3.1 General Description The vent system, which connects the drywell and pressure suppression chamber, conducts flow from the drywell to the pressure suppression chamber without

BFN-28 5.2-6 excessive resistance and distributes this flow effectively and uniformly in the pool following a postulated pipe rupture in the drywell. The pressure suppression chamber receives this flow, condenses the steam portion of this flow, and contains non-condensable gases and fission products driven into the pressure suppression chamber. The pressure suppression chamber-to-drywell vacuum breakers limit the pressure differential between the drywell and pressure suppression chamber. The pressure suppression chamber is designed for the same leakage rate as the drywell. Large vent pipes form a connection between the drywell and the pressure suppression chamber. A total of eight circular vent pipes are provided, each having a diameter of 6.75 feet. The vent pipes are designed for an internal pressure of 56 psig (the ASME Boiler and Pressure Vessel Code, Section III, allows a maximum internal pressure of 62 psig) coincident with a temperature of 281F and are designed to withstand an external pressure of 2 psi above internal pressure. Jet deflectors are provided in the drywell at the entrance of each vent pipe to prevent possible damage to the vent pipes from jet forces which might accompany a pipe break in the drywell. The vent pipes are fabricated of SA-516 steel, and comply with requirements of the ASME Boiler and Pressure Vessel Code, Section III, Subsection B. Expansion joints are provided on each vent pipe to accommodate differential motion between the drywell and pressure suppression chamber. The pressure suppression chamber is a steel pressure vessel in the shape of a torus below and encircling the drywell, with a centerline diameter of approximately 111 feet and a cross-sectional diameter of 31 feet. As a result of the torus modifications on all three units, the maximum water volume in the torus is approximately 131,400 ft3 (see note on Table 5.2-1). The pressure suppression chamber is held by supports which transmit vertical and seismic loading to the reinforced concrete foundation slab of the Reactor Building. Space is provided outside the pressure suppression chamber for inspection and maintenance. The eight drywell vents are connected to a 4-foot, 9-inch diameter vent header in the form of a torus which is contained within the airspace of the pressure suppression chamber. Projecting downward from the header are 96 downcomer pipes, 24 inches in diameter, and terminating approximately 3 feet 10 inches (maximum, see note on Table 5.2-1) below the water surface of the pool. T-quenchers have been added to replace the ramshead discharge devices at the end of the main steam relief valve discharge pipes to assure the controlled release and condensation of steam and reduce stresses on the torus and tailpipe assemblies. The vent header and vent pipes have the same temperature and pressure design requirements as the pressure suppression chamber. Vacuum breakers discharge from the pressure suppression chamber into the drywell to limit the pressure differential

BFN-27 5.2-7 and to prevent a backflow of water from the pressure suppression pool into the vent header system. Vacuum breaker sizing is based on Moss Landing test configurations. The system to establish and maintain a controlled pressure differential between the drywell and pressure suppression chamber during normal operations is described in paragraph 5.2.3.9. The pressure suppression chamber is designed to the same material and code requirements as the steel drywell vessel. All attachments to the torus are by full penetration welds. The HCVS (Units1 and 2) or HWWV (Unit 3) can mitigate the consequences of a severe accident that would cause the pressure of the torus to exceed 56 psig by venting primary containment. The HCVS connects the Unit 1 and 2 torus to independent vents for each unit which discharges above the Unit 1 and 2 Reactor Buildings. The HWWV connects the torus of Unit 3 to a header which discharges in the stack via a 14" pipe. During each refueling and each shutdown for required maintenance inside the containment, the containment is purged to restore a normal air atmosphere and to reduce the amount of gaseous and airborne radioactivity present. These purges are accomplished through the ventilation purge connections and are normally passed through a containment purge filter train (HEPA and charcoal filters) before release through the normal reactor building ventilation system. A vent from the primary containment is provided which will normally be closed, but which will permit the vent discharge to be routed to the Standby Gas Treatment System so that release of gases from the primary containment is controlled, and so that effluents are filtered and monitored before dispersal through the stack. A 30-inch ECCS suction header with a wall thickness of 1/2-inch minimum circumscribes the pressure suppression chamber at El. 525 feet 4 inches. Four 30-inch tees are used to connect the suction header to the pressure suppression chamber. The suction header is supported vertically and horizontally by brackets attached to the 16 cradles. Four strainers on connecting lines between the suction header and the pressure suppression chamber have been provided. The strainers are a stacked disk design having a large surface area to accommodate debris that may be generated by the dynamic forces in a LOCA and other debris that may be resident in the containment such as sludge and paint chips. The strainer design is governed by debris generation assumptions in accordance with the Boiling Water Reactor Operating Group Utility Resolution Guidance for ECCS Suction Strainer Blockage (GE NEDO-32686, R0, Dated November 1, 1996). The strainers are designed to

BFN-27 5.2-8 provide acceptable head loss while saturated with reflective metal insulation from primary system piping combined with other debris. The suction header and its connecting pipes are designed, constructed, tested, and inspected in accordance with the same requirements as the pressure suppression chamber. Additional safety is provided by locating the four connecting pipes in unused portions of the pressure suppression chamber so that they will not be directly subjected to the water jet issuing from the downcomers. The suction header is designed to accommodate a temperature differential between itself and the pressure suppression chamber. Hydraulic snubbers are used to support the suction header to provide seismic supports that will prevent any abrupt lateral movement due to earthquake, but will not offer resistance to relatively slow thermal expansion. The suction lines from the RHR, HPCI, and Core Spray systems are supplied from this header. The RCIC System is also supplied from this header via the Core Spray System supply piping. The interior carbon steel surface of the pressure suppression chamber and all other exposed carbon steel surfaces within the pressure suppression chamber were originally coated for corrosion protection with Valspar Hi-Build Epoxy 78:00. This coating has passed test criteria for a design basis accident (DBA) for carbon steel substrate as outlined in ANSI N101.2-1972. Any repairs or replacement of this protective coating system are performed using other coating system(s) that are design basis accident qualified to ANSI N101.2-1972 and approved by TVA. The RCIC and HPCI turbine exhaust spargers may be uncoated carbon steel. Additionally the following stainless steel components and structures within the Unit 2 and Unit 3 pressure suppression chambers have been found to be coated:

1.

T-quenchers

2.

Main Vent Bellows

3.

Miscellaneous support steel on the torus walkway

4.

Electrical Conduits

5.

Electrical Junction Boxes

6.

Small bore piping and valve bodies Based on the qualification of the Valspar 78 coating, the controlled surface preparation and application of the coating on the stainless steel components by qualified individuals, the in-place adhesion testing of the coating, and the degree of resiliency exhibited by the coating to different removal methods, TVA has concluded that Valspar 78 will behave the same on stainless steel as it will on carbon steel when applied properly. Therefore, no disbonding of the coating is expected during design basis accident conditions. For Unit 1, coatings on stainless steel components in the pressure suppression chamber were either removed or are accounted for as unqualified coatings.

BFN-27 5.2-9 For all three units, unqualified coatings are maintained within margins with respect to ECCS Suction Strainer sizing assumptions. 5.2.3.3.2 Description of the Pressure Suppression Pool (Torus) Modifications The original design of the BFNP containment system considered postulated accident loads previously associated with a loss-of-coolant accident (LOCA), seismic loads, dead loads, jet-impingement loads, hydrostatic loads (due to water in the pressure suppression chamber), overload pressure test loads, and construction loads. However, since the establishment of the original design criteria, additional loading conditions were identified. These conditions were discovered as a result of GE performing large scale testing of the Mark III containment design and in-plant testing of Mark I containments. New pressure suppression pool loads which had not explicitly been included in the containment design bases were identified. These loads result from dynamic effects of drywell air and steam being rapidly released to the pressure suppression pool (torus) during a postulated LOCA and during main steam relief valve discharge associated with plant transient operating conditions. As a result, the Mark I Owners Group was established, with GE serving as the lead technical organization. The efforts of the Owners Group were to be accomplished in two phases: a short term program (STP) and a long term program (LTP). The objective of the STP was to verify that the Mark I containment and related structures were capable of sustaining the additional hydrodynamic loads before the more detailed results of the LTP were available. The STP structural acceptance criteria used to evaluate the design of the torus and related structures were based on providing adequate margins of safety, i.e., a safety-to-failure factor of 2, to justify continued operation of the plant. A report on torus main steam relief valve piping and vent header support modifications (Kaiser Engineer Report No. 75-83-R, dated October, 1975) was submitted to the NRC on December 18, 1975. The NRC staff's conclusions relative to the STP are documented in NUREG-0408, dated December, 1977. Subsequently, exemptions relating to the structural factor of safety requirements of 10 CFR 50.55(a) were granted by the NRC, while the more comprehensive LTP was being conducted. The Mark I Owners Group developed the "Mark I Containment Program, Program Action Plan" and submitted it to the NRC in March, 1977. As a result of discussions with NRC, Revision 1 to the Program Action Plan was submitted February 11, 1977 (GE Topical Report EW 7610.09).

BFN-27 5.2-10 TVA initiated analysis activity for the BFNP torus integrity long term program in March, 1977. GE and the Mark I Owners Group members worked together to develop load definitions and structural acceptance criteria (for the LTP) that were generically acceptable to the NRC. A partially complete Load Definition Report was issued by GE in December, 1978. In March, 1979, the initial Load Definition Report (GE Topical Report NEDO-21888, "Mark I Containment Program Load Definition Report") was submitted to the NRC for review. A series of experimental and analytical programs were conducted by the Mark I Owners Group to provide the bases for the generic load definition and structural acceptance criteria. The NRC issued NUREG 0661 (Safety Evaluation Report for the Long Term Program) in July, 1980. This Safety Evaluation Report included Revision 1 of the NRC acceptance criteria for the Mark I containment LTP. GE subsequently revised and published application guides for load definitions in September, 1980 (including revisions to NEDO-21888 and NEDO-24583). The approved structural acceptance criteria (NUREG-0661, Appendix A), include 27 different load combinations for which the entire torus, vent system, torus internals, and attached piping must be analyzed. BFN unique analyses have been completed and associated modifications to the torus and related structures, systems, and components have been installed. These modifications meet the requirements of NUREG-0661. In addition, a plant-unique main steam relief valve (MSRV) discharge test has been performed as part of the BFNP unique analysis, as requested by the NRC in NUREG-0661. This test confirmed the methods used to calculate containment loads from the various MSRV discharge cases. These tests were performed after all torus modifications significantly affecting measured torus motion effects were in their final configuration. The final configuration of torus integrity modifications is described in the Browns Ferry Nuclear Plant Torus Integrity Long Term Program Plant Unique Analysis Report first submitted to NRC in January 1984 and supplemented by submittals in September 1984 and January 1985. See FSAR Sections C.2.5, C.3.5, and C.5.3 for additional information on this subject. The operation of the units in their partially modified state has been evaluated. The modifications improve the margin of safety of the torus.

BFN-27 5.2-11 5.2.3.4 Penetrations 5.2.3.4.1 General In order to maintain designed containment integrity, containment penetrations have the following design characteristics:

a.

They are capable of withstanding the peak transient pressure which could occur due to the postulated rupture of any pipe inside the drywell.

b.

They are capable of withstanding the forces caused by impingement of the fluid from the rupture of the largest local pipe or connection without failure.

c.

They are capable of accommodating the thermal and mechanical stresses which may be encountered during all modes of operation without failure. The number and size of the principle primary containment penetrations and associated isolation valves are shown in Table 5.2-2. 5.2.3.4.2 Pipe Penetrations Four types of pipe penetrations are utilized as required by stress conditions. Type A is used where stress levels would exceed the allowable design limits if a bellows were not used. The design permits leak-testing of the bellows during plant operation. Type B is used where stress levels would not exceed the allowable design limits if a bellows were not used. These types of penetrations are illustrated in Figure 5.2-3. Where stress levels are within the allowable design limits without the use of Types A or B, the penetration assemblies illustrated in Figures 5.2-4 or 5.2-4a are suitable. The piping penetrations for which movement provisions are made are the high temperature lines such as the steam lines and other reactor system lines. The penetration sleeve passes through the concrete and is welded in the primary containment vessel. The process line that passes through the penetration is free to move axially, and a bellows expansion joint is provided to accommodate the movement. A guard pipe immediately surrounds the process line and is designed to protect the bellows and maintain the penetration seal should the process line fail within the penetration. Insulation and air gaps are provided to reduce thermal stress. If necessary, these lines are anchored outside the containment to limit the movement of the line relative to the containment. The bellows accommodates the relative movement between the pipe and the containment shell. This design is

BFN-27 5.2-12 utilized to assure reasonable integrity of the flexing penetration during plant operation. The steam line, as it passes through the drywell containment vessel and the concrete biological shield, is enclosed in a guard pipe that is attached to the main steam line through a multiple head fitting. This fitting is a one-piece forging with integral flues or nozzles and is designed to meet all requirements of the ASME Boiler and Pressure Vessel Code, Section III. The forging is radiographed and ultrasonically tested as specified by this code. The guard pipe and fittings are designed to the same pressure requirements as the steam line. The steam line penetration sleeve is welded to the drywell and extends through the biological shield, where it is welded to a bellows which, in turn, is welded to the guard pipe. The bellows assembly accommodates the relative thermal expansion of the steam pipe and drywell. The steam pipe is guided through pipe supports at each end of the penetration assembly to allow steam pipe movement parallel to the penetration and to limit pipe reactions of the penetration to allowable stress levels. Two isolation valves are provided. The external valve is located as close to the drywell penetration sleeve as practical, and the inside valve is located downstream of the reactor vessel main steam relief valves. The design of the penetration takes into account the simultaneous stresses associated with normal thermal expansion, live and dead loads, seismic loads, and loads associated with a loss-of-coolant accident within the drywell. For failure of the steam pipe taken at random, the design takes into account the loadings given above in addition to the jet force loadings resulting from the failure. For these conditions, the resultant stresses in the pipe and penetration components do not exceed the code allowable design stress. The cold piping and ventilation duct penetrations are welded directly to the sleeves. (See Figure 5.2-4.) Bellows and guard pipes are not necessary in this design, since the thermal stresses are small and are accounted for in the design of the weld joints. Small, low-pressure lines which do not connect to the reactor system are run through larger pipes sealed by welded end plates. The plates are drilled, tapped, and equipped with compression fittings. (See Figure 5.2-4a.) Connections are provided for leak testing of this type penetration. 5.2.3.4.3 Electrical Penetration The electrical penetrations include electrical power, signal and instrument leads. A typical penetration is shown in Figure 5.2-5. The penetration assembly consists of header plates welded into the assembly at each end to form a double pressure barrier.

BFN-27 5.2-13 The electrical conductors are hermetically sealed into the header plates with insulating material to form a leak tight configuration which is leak tested after installation and provides a means for periodic testing. The penetration assembly is welded to the containment nozzle by a single weld ring. 5.2.3.4.4 TIP Penetrations TIP guide tubes pass from the Reactor Building through the primary containment. The insertion guide tubes pass through double O-ring sealed, flanged penetrations on the primary containment. The guide tubes are connected in the flanged penetration by means of brazing, which meets the requirements of the ASME Boiler and Pressure Vessel Code, Section VIII. These seals would also meet the intent of Section III of the code, even though the code has no provisions for qualifying the procedures or performances. The flanged TIP penetrations are bolted to flanged nozzles which are welded to the primary containment. 5.2.3.4.5 Personnel and Equipment Access Locks One personnel access lock is provided for access to the drywell. The lock has two sealed doors in series, and 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 at all times when primary containment is required. The locking mechanisms will hold the doors tight against the seals, and door design will ensure a tight seal when the doors are subjected to design accident pressure. The space between the air-lock doors can be pressurized to test for leakage through the door seals. An access hatch with double testable seals is provided on the drywell head. This hatch is bolted in place. Two 12-foot diameter equipment access hatches with double, testable seals are also provided. These hatches are bolted in place. One 2-foot diameter CRD removal hatch with double, testable seals is provided. The hatch is bolted in place. 5.2.3.4.6 Access to the Pressure Suppression Chamber Access to the pressure suppression chamber is provided at three locations from the Reactor Building. There are two 4-foot diameter and one about 3 1/2-foot diameter hatches with double testable seals and bolted covers. The access hatches will be bolted closed when primary containment is required and will be opened only when the primary coolant temperature is 212F and the pressure suppression function of the torus is not required to be operational.

BFN-27 5.2-14 5.2.3.4.7 Access for Refueling Operations The top portion of the drywell vessel is removed during refueling operations. The head is held in place by bolts and is sealed with a double seal arrangement. The head is bolted closed when primary containment is required, and will be opened only when the primary coolant temperature is 212F and the pressure suppression function of the torus is not required to be operational. The double seal on the head flange provides a method for determining the leak tightness after the drywell head has been installed. 5.2.3.5 Isolation Valves The criteria governing isolation valves for the various categories of penetrations are as follows. (See Subsection 7.3, "Primary Containment and Reactor Vessel Isolation Control System".)

a.

Pipes or ducts which penetrate the primary containment and which connect to the reactor primary system, or are open to the drywell free air space, are provided with at least two isolation valves in series. Excluding check valves and closed manual valves, valves in this category are designed to close automatically from selected signals and shall be capable of remote-manual actuation from the control room. (See Table 5.2-2.)

b.

The two valves are physically separated. On lines connecting to the reactor primary system, one valve is located inside the primary containment and the second outside the primary containment as close to the primary containment wall as practical.

c.

Lines that penetrate the primary containment, and which neither connect to the reactor primary system nor are open into the primary containment, are provided with at least one valve which may be located outside the primary containment. Valves in this category are capable of manual actuation from the control room.

d.

Motive power for the valves on process lines which require two valves are physically independent sources to provide a high probability that no single accidental event could interrupt motive power to both closure devices. Loss of power to each electrical division is detected and annunciated.

BFN-27 5.2-15

e.

For design basis breaks in a main steam line downstream of the outboard main steam isolation valve, isolation valve closure time is such that the valve will be closed prior to the start of uncovering the fuel.

f.

Valves, sensors, and other automatic devices essential to the isolation of the containment are provided with means to periodically test the functional performance of the equipment. Such tests include demonstration of proper working conditions, correct setpoint of sensors, proper speed of responses, and operability of fail-safe features.

g.

The control circuits for the isolation valves are designed so as to prevent the valves from automatically reopening when primary containment isolation logic is reset.

h.

The leakage from HCVS (Units 1 and 2) or HWWV (Unit 3) Primary Containment Isolation Valves FCV-064-0221 and FCV-064-0222 is designed, tested, and maintained to ensure the Control Room and offsite dose limits of 10 CFR 50.67 are not exceeded following a design basis accident. The following are exceptions to the above isolation valve criteria.

a.

Automatic isolation valves are not provided on the outlet lines from the pressure suppression chamber to the core spray and RHR pumps. These lines return to the containment and are required to be open during post-accident conditions for operation of these systems.

b.

No automatic isolation valves are provided on the Control Rod Drive Hydraulic System lines. These lines are isolated by means of the normally closed hydraulic system control valves located in the Reactor Building, and by means of check valves comprising a part of the drive mechanisms.

c.

TIP isolation valves and small diameter instrument lines.

d.

Automatic isolation signals are not provided to the two isolation valves for the HCVS (Units 1 and 2) or the HWWV (Unit 3). These valves are closed during all design basis accidents/events. Both valves will be maintained closed by separate remote key-locked permissive control switches in the Main Control Room to prevent power from being supplied to the solenoid valves which serve the valve operators. They fail closed on loss of electrical power and/or pneumatic supply. These valves are only opened for surveillance or to operate the HCVS (Units 1 and 2) or the HWWV (Unit 3) (purposely violating primary containment) to preserve the structural integrity of the torus.

BFN-27 5.2-16 Table 5.2-2 is a listing of the principal isolation valves. The table indicates the number and service of the valves, the motive power which actuates the valve, and the closure time of the valve. The main steam lines have air-powered valves. Studies have shown this arrangement to have a high reliability with respect to functional performance. These valves are closed automatically by the signals indicated in Table 5.2-2. (See Subsection 4.6, "Main Steam line Isolation Valves.") Influent lines, such as the feedwater lines which connect to the reactor vessel, have one check valve inside and one check valve or motor-operated isolation valve outside the primary containment. An AC operator is chosen for the motor-operated valves, since the motor is simpler in construction and is assessed as having higher overall reliability than a DC motor for the same service. The check valves close automatically by reverse flow through the pipe. TIP System guide tubes are provided with an isolation valve which closes automatically upon receipt of proper signal and after the TIP cable and fission chamber have been retracted. Manual operator intervention to reset the insertion logic for the TIP system is required in the event a Group 8 isolation signal causes the TIP ball valves to isolate upon withdrawal of the probe. This feature ensures containment integrity is maintained in the event of design basis accident. In series with this isolation valve, an additional, or back-up, isolation shear valve is included. Both valves are located outside the drywell. The function of the shear valve is to assure integrity of the containment even in the unlikely event that the present isolation valve should fail to close or the chamber drive cable should fail to retract, if it should be extended in the guide tube during the time that containment isolation is required. This valve is designed to shear the cable and seal the guide tube, if necessary, upon a manual actuation signal. Valve position (full open or full closed) of the automatic closing valves is indicated in the control room. Closing of the shear valves will be performed by operator action from the control room. Each shear valve will be operated independently. The valve is an explosive-type valve, DC operated, with monitoring of each actuating circuit provided. In the event of a containment isolation signal, the TIP System receives a command to retract the traveling probes for the five machines. Upon full retraction, the isolation valves are then closed automatically. If a traveling probe were jammed in the tube run such that it could not be retracted, this information would be supplied to the operator who would, in turn, investigate the situation to determine if the shear valve should be operated. Lines such as the closed cooling water lines, which neither connect to the reactor primary system nor are open into the primary containment, are provided with at

BFN-27 5.2-17 least one remotely operable valve located outside the primary containment, or a check valve on the influent line outside the containment. Instrumentation piping connecting to the reactor primary system which leaves the primary containment is dead ended at instruments located in the Reactor Building except for the reactor recirculation sample line for the PASS (see Section 10.21). These lines are provided with manual isolation valves and an excess flow check valve. The reactor recirculation sample line for the PASS is taken from a jet pump instrument line downstream of the excess flow check valve with integral restricting orifice. This small (1/2-inch, schedule 80) line is normally isolated near the tie-in point on the jet pump instrument line by a remote manual solenoid valve controlled from the main control room. This solenoid valve would only be open during periodic testing of the PASS or during PASS sampling operations, post-accident, when the reactor is at high pressures. For large break LOCA's where reactor vessel pressure may not be sufficient to provide sufficient head to obtain a sample from this tie-in, the PASS connection on the RHR system (see Section 10.21) would be used. Although not performing a strict containment isolation function, this solenoid valve will be local leak rate tested since the sample line can communicate with the environment through the PASS sample panel located in the turbine building. Instrumentation piping, which opens into the drywell and pressure suppression chamber and whose external branches terminate in dead end service and are capable of withstanding drywell design conditions, utilize one locally operated block valve. The Containment Atmospheric Dilution inlet lines to the drywell and pressure suppression chamber contain a solenoid operated valve and a check valve. Both valves are located outside primary containment. All isolation valves (except non-testable check valves, RHR/LPCI System I and System II, and Core Spray System I and System II inboard isolation check valves and H2O2 CAM sampling isolation valves) are provided with limit switches which are used to indicate in the control room that the valves are either open or closed. For the isolation valves in the sampling and sample return lines in the H2O2 CAM System, the valve position is identified in the control room by indication of energization of the solenoid valves. Note: For Units 1, 2, and 3, the RHR check valve actuator, controls and indication functions have been deleted. All power actuated isolation valves are capable of being actuated from the control room. The ECCS inboard isolation check valves can only be actuated during cold shutdown (MODE 4 or MODE 5) when control air is connected.

BFN-27 5.2-18 5.2.3.6. Primary Containment Venting and Vacuum Relief (Figures 5.2-2a - Sheets 1, 2, and 3) The drywell is maintained at approximately 1.3 psid by the delta-P compressor and the suppression pool is maintained slightly above atmospheric during normal plant operation in order to ensure that containment pressures are maintained within design limits. The containment is periodically vented to eliminate pressure fluctuations caused by temperature changes during various operating modes. This is accomplished through vent connections which normally discharge to the SBGT system. When the reactor is at a temperature greater than 212F (Modes 1, 2, or 3) the inboard vent valves are normally open and the outboard vent valve is normally closed. The pressure suppression chamber is vented separately to SBGT. The purge valves leading to ductwork on Units 1, 2, and 3 are designed to isolate within 2.5 seconds to allow purging during operation, as limited by the technical specifications. (See FSAR, paragraph 5.3.3.6.3) The closure time for valve 76-24 is equal to or less than five seconds. This valve is in a hard-piped system, and a five-second closure time meets NRC Branch Technical Position CSB 6-4. Protective screens have been installed before the first isolation valve outside primary containment in the containment purge piping to comply with CSB 6-4, to protect the valves from debris which might affect isolation. Automatic vacuum relief devices are used to prevent the primary containment from exceeding the external design pressure. The drywell vacuum relief valves draw air from the pressure suppression chamber. The pressure suppression chamber vacuum relief device draws air from the Reactor Building. The pressure suppression chamber vacuum relief system consists of two vacuum breakers in series in each of two lines to atmosphere. One valve is air-operated and is actuated by a differential pressure signal; upon loss of electrical power or air, the valve will fail in the open position. The second valve is self-actuating. The combined pressure drop at rated flow through both valves does not exceed the difference between pressure suppression chamber design external pressure and maximum atmospheric pressure. The force required to open each self-actuating vacuum breaker is periodically determined in accordance with Technical Specification 3.6.1.5 surveillance requirements. A visual inspection of the self-actuating vacuum breakers is also performed as part of the surveillance procedure. The drywell vacuum breakers, which connect the pressure suppression chamber and drywell, are sized on the basis of the Bodega Bay pressure suppression

BFN-27 5.2-19 system tests.1 The vacuum breaker flow area is proportional to the flow area of the vents connecting the drywell and pressure suppression pool. Their chief purpose is to prevent excessive water level increase in that portion of the vent discharge lines that is submerged in pressure suppression pool water, which results in a pressure differential across the vent pipe. The Bodega Bay tests regarding 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 (twelve 18-inch valves) selected on this test basis is more than adequate to limit the pressure differential between the pressure suppression chamber and drywell during post-accident drywell cooling operations to a value which is within suppression system design values. The drywell vacuum breaker valves FCV-64-28A through 28M, are located in the pressure suppression chamber and use silicone rubber as the seat material. These valves function to prevent steam from bypassing the pressure suppression chamber, thus they assure pressure suppression. The silicone valve seats are functional for the temperature and exposure dose for several hours. The material approaches its radiation damage limit at 107 rad after several hours; however, by this time the valves have performed their function of assuring pressure suppression. 5.2.3.7 Primary Containment Normal Heating, Ventilation, and Air Conditioning Systems Maintaining each drywell average ambient temperature 150F during normal plant operation assures that the insulation on motors, isolation valves, operators and sensors, instrument cable, electrical cable and gasket materials or sealants used at the penetrations has a sustained life without deterioration. Each drywell is cooled during normal operation of the unit by a closed loop ventilation system designed to hold the average temperature in the drywell to 150F. (See Subsection 10.6, "Reactor Building Closed Cooling Water System".) The atmosphere is circulated in the drywell normally by eight fans assembled in two groups of five, with one spare in each group (ten fans total). Spare fans may be placed in service at operator discretion to provide additional margin. Each fan has an individual cooling coil associated with it. Water from the Reactor Building Closed Cooling Water system is employed to remove heat from the coolers. The drywell blowers and Reactor Building Closed Cooling Water System (RBCCWS) are kept in service upon extended loss of offsite power. This serves 1 Bodega Bay Preliminary Hazards Summary Report, Appendix 1, Docket 50-205, December 28, 1962

BFN-28 5.2-20 to prevent high drywell temperatures and associated equipment damage in units that have not sustained a loss-of-coolant accident (LOCA). Continued operation of the RBCCWS is desirable because this system provides the preferred method of cooling the drywell; however, the RBCCWS is not essential to safety. In the event of failure of the RBCCWS and drywell blowers such that the drywell temperature in non-LOCA units could exceed the design value, the operator has sufficient time to manually initiate drywell cooling using torus water, the RHR pumps, and containment spray headers. The loss of offsite power leads to the drywell blowers being unavailable for a short term. The worst case unavailability is when a 480-V load shed signal is received where restarting of the drywell cooling is delayed until the diesel generator loading will accept loading of the blowers. This leads to the conservative estimates of drywell temperature and pressure for the short term transients in the drywell under normal operating conditions for the non-accident unit (e.g., all equipment operates as expected). Emergency power reactivates the cooling which immediately terminates the temperature and pressure rises. For Units 1 and 2, six of the blowers are automatically returned in a staggered sequence from 40 to 90 seconds. While maintaining diesel generator load limits, as required, additional blowers are manually returned to service. The drywell pressure increases above 2.45 psig (drywell high-pressure setpoint) for a short period of time (satisfying half of the logic for an accident signal); however, the full accident signal is not created because normal reactor pressure is above the 450 psig low reactor pressure limit. The drywell air-space temperature remains below maximum containment design temperature limit. For Unit 3, eight of the drywell blowers are automatically returned after 40 seconds. The drywell pressure remains below the 2.45 psig limit above which satisfies half of the logic for an accident signal (the other half is low reactor pressure below 450 psig), and the drywell air-space temperature remains below the maximum containment design temperature. In consideration of single failures, adequate drywell cooling may not be available to prevent a high drywell pressure signal from being received. In order to prevent a full accident signal from being received when reactor pressure reduces to the low reactor pressure setpoint on the units that have not sustained a LOCA, operator action can be taken to bypass the high drywell pressure signal. In this scenario, HPCI is initiated upon receiving the high drywell pressure signal and maintains reactor level. The drywell air-space temperature remains below maximum containment design temperature limit (Subsection 5.2.3).

BFN-27 5.2-21 Separate fans located outside the drywell are used to purge the drywell prior to entering this area for maintenance work. (See Subsection 5.3, "Secondary Containment System.") The Primary Containment Ventilation System is shown in Figures 5.2-2a - Sheets 1, 2, and 3. 5.2.3.8 Containment Inerting System Following each startup (within 24-hours after thermal power is 15% rated thermal power), the primary containment is purged of air with pure nitrogen until the atmosphere contains less than 4 percent oxygen. The Containment Inerting System is used during the initial purging of the primary containment and provides a supply of makeup nitrogen. The system consists of two liquid nitrogen storage tanks with two makeup vaporizers, a common purge vaporizer, pressure reducing valves and controllers, instrumentation valves and piping as shown in Figures 5.2-6a sheets 1, 3, 4, and 6. Nitrogen is supplied from the common onsite storage tanks through the common purge vaporizer or makeup vaporizers where the liquid nitrogen is converted to the gaseous state. The gaseous nitrogen then flows through the purge or makeup pressure-reducing valves and flow meters into each containment pressure suppression chamber or drywell, where it mixes with the air. A safety valve in the nitrogen supply system prevents overpressurization of the containment. The purge supply piping is configured such that it is possible to establish a large bypass path from the drywell to the pressure suppression chamber. If this path is established, then the pressure suppression function of the primary containment could be compromised. Administrative controls prevent the simultaneous purging or inerting of the drywell and the pressure suppression chamber except when the unit is at cold shutdown (MODE 4 or MODE 5). The drywell ventilation blowers are normally operated during the purge operation to maximize mixing of the nitrogen and air. Gases purged from the containment are vented either through the Reactor Building Ventilation System (containment purge) or the Standby Gas Treatment System. The Reactor Building exhaust route will be used for radioactivity releases of low concentration. When releasing drywell atmosphere through the building exhaust, the radioactivity release is filtered by both HEPA and charcoal adsorbers, monitored, and recorded by the plant ventilation exhaust radiation monitoring system (FSAR paragraph 7.12.6). Radioactivity in the exhaust would also be detected by the Reactor Building Ventilation Radiation Monitoring System (FSAR paragraph 7.12.5). High radioactivity would result in primary and secondary containment isolation and automatic startup of the Standby Gas Treatment System. The stack exhaust route will result in the effluent being processed by the

BFN-27 5.2-22 HEPA filters and charcoal adsorbers in the Standby Gas Treatment System. The processed stream is then monitored by the main stack radiation system (FSAR paragraph 7.12.3) and released through the plant stack. Purging continues until the oxygen content of the containment atmosphere is less than 4 percent as measured by the oxygen analyzer (Figures 5.2-6a sheets 2, 5, and 7). This takes approximately 4 hours and requires 3 to 5 containment atmosphere volumetric changes. The inerting system also continues to supply makeup gas, required by temperature changes and leakage, during planned operations. This makeup includes gas vented from pneumatic equipment inside the drywell that utilizes nitrogen supplied from the Drywell Control Air System. The primary containment is held at a slight positive pressure by the inerting system as a means of leak-rate monitoring. The atmosphere is monitored and results are recorded in the Main Control Room. Both the purge and makeup operations of the inerting system are controlled from the control room. A high oxygen concentration alarm is located in the control room. 5.2.3.9 Drywell-Pressure Suppression Chamber Pressure Differential System Each unit has a system to maintain a controlled pressure differential between the drywell and the pressure suppression chamber. This system consists of a compressor connected into the primary containment purge line to form a loop connecting the drywell and the pressure suppression chamber. Nitrogen is pumped from the pressure suppression chamber to the drywell to create the pressure differential. The compressor is an Ingersoll-Rand, non-lubricated type capable of providing 136 SCFM at a maximum discharge pressure of 125 psig. Details of the connections into the primary containment purge line showing the associated isolation valves and location of the compressor within the system are shown on Figures 5.3-3a, 5.3-3c, and 5.3-3d. The system is set to establish an operating pressure difference between the drywell and the pressure suppression chamber in the range of 1.1 to 1.35 psi, with the drywell at the higher pressure. Pressure differential control is operated by either of two independent channels. A 0-2 psid pressure transmitter provides the determination of system pressure differential. Water level control within the pressure suppression chamber is also conducted with either of two transmitters and indicators. The system is not a safety system and therefore is automatically isolated in the event of a LOCA. The purpose of the drywell-pressure suppression chamber pressure differential system is to reduce the thermo-hydrodynamic loads imposed on the pressure suppression chamber during a blowdown following a LOCA.

BFN-27 5.2-23 5.2.4 Safety Evaluation 5.2.4.1 General The primary containment and its associated safeguards systems are designed to accomplish four principal functions, namely:

a.

To accommodate the transient pressures and temperatures associated with the equipment failures within the containment,

b.

To accommodate and mitigate the effects of potential metal-water reaction subsequent to postulated accidents involving loss of coolant,

c.

To provide a high integrity barrier against leakage of any fission products associated with these equipment failures, and

d.

To provide containment protection against damaging effects of missiles. These factors are considered in the following evaluation of the integrated Primary Containment System. 5.2.4.2 Primary Containment Characteristics During Reactor Blowdown In order to establish a design basis for the pressure suppression containment with regard to pressure rating and steam condensing capability, the maximum rupture size of the reactor primary system must be defined. For this design, an instantaneous, circumferential rupture of one 28-inch recirculation line has been selected as a basis for determining the maximum gross drywell pressure and the condensing capability of the pressure suppression system. The selection of an equipment failure of this size for the design basis is entirely arbitrary, since circumferential failure of a recirculation pipe is considered to be of such low probability as to be considered incredible. Nevertheless, for design purposes these failure conditions have been selected to establish the containment parameters, but the failure modes and the magnitude of failures are assessed as being incredible. The design pressure is established on the basis of the Bodega Bay pressure suppression tests. The design pressure is primarily a function of the postulated rupture area, the drywell to pressure suppression chamber vent area and configuration, vent submergence below the water level in the pressure suppression pool, and the final equilibrium pressure in the pressure suppression chamber.

BFN-27 5.2-24 In establishing the containment design, circumferential pipe ruptures are assumed with sufficient distance separation to allow full potential flow from each end of the pipe. For pre-uprate conditions, normal pipeline flow losses are not considered in establishing rupture flow rates. The containment design parameters listed in Table 5.2-1 are concerned primarily with the effects on the primary containment caused by the blowdown immediately following the postulated double-ended rupture of the recirculation piping. The parameters having the greatest effect on drywell design pressure are the ratio of pipe break area to total vent area, the vent submergence below the water level in the pressure suppression pool, initial system pressure, and the equilibrium pressure in the pressure suppression chamber before the postulated rupture. Sufficient water is provided in the pressure suppression pool to accommodate the initial energy which can be transiently released into the drywell from the postulated pipe failure. The pressure suppression chamber is sized to contain this water, plus the water displaced from the reactor primary system together with the free air initially contained in the drywell. The difference in the key parameters is either in the conservative direction or results in second order effects on the peak pressure, leading to the conclusion that the design will result in significantly lower pressure peaks than those measured. The primary containment response analysis to the design basis loss-of-coolant accident is presented in Section 14.0, "Plant Safety Analysis." The break area assumed (for the purpose of calculating the containment peak transient pressure and establishing the break vent area ratio) was 4.2 ft2. This is equivalent to the total area of 10 jet pump injection nozzles, and the recirculation suction line in the broken loop. This area gives a break-to-vent area ratio which is within the range tested during the Bodega Bay series of pressure suppression tests. In calculating the peak pressures for pre-uprate conditions, no credit has been taken for pipe friction, the pump, and flow nozzle which will significantly reduce the flow. Under all operating conditions (Unit 2 only), one valve in the equalizing line between the two reactor recirculation pump discharge pipes shall be open and the other valve shall be closed. The reactor recirculation equalizing line and associated valves have been removed for Units 1 and 3. 5.2.4.3 Primary Containment Characteristics after Reactor Blowdown After the blowdown of the primary coolant into the drywell immediately following the recirculation line break, the temperature of the pressure suppression chamber

BFN-28 5.2-25 water approaches 152ºF. The maximum primary containment system pressure is 49.1 psig. Most of the non-condensable gases would be transported to the pressure suppression chamber during the blowdown. However, soon after initiation of the drywell spray, they would redistribute between the drywell and pressure suppression chamber via the vacuum breaker system as the spray reduces drywell pressure. Redundant drywell instrumentation is provided in the control room for the operator. Drywell temperatures are printed out, and the readings of any two separated sensors can be used to determine the temperature of the drywell atmosphere to alleviate the problem of local variations. High drywell temperature (160F, Process Limit) is annunciated in the control room. Drywell pressure is indicated and recorded in the control room and torus pressure (about 2 psi lower reading, but considered redundant indication) is indicated in the control room. High drywell pressure (20 PSIG, Nominal Setpoint) is annunciated in the control room. Annunciation is also provided if either of two criteria is exceeded: (1) high drywell pressure (35 PSIG, Process Limit), or (2) high drywell pressure (2.5 PSIG, Process Limit) exists for approximately 30 minutes coincident with high drywell temperature (281F, Process Limit). This information is provided to the operator, through both indication and alarm, for manual initiation of containment spray in accordance with the emergency operating instructions. Therefore, the containment temperature will be limited to its design value for all loss of coolant accidents. The Unit 1, Unit 2, and Unit 3 Torus Water Level Monitoring Instruments LT-64-159A and LT-64-159B measure torus water level from 2 feet above the bottom of the torus (below the lowest ECCS suction) to 5 feet above normal level. The torus level monitors are to be used to supply information to the operator for use in determining the nature of an accident and for better understanding of post-accident conditions for Unit 1, Unit 2, and Unit 3. The Core Spray System removes the decay heat and stored heat from the core, thereby minimizing core heatup and any metal-water reaction. The core heat would be removed from the reactor vessel through the broken recirculation line in the form of hot liquid. This hot liquid would combine with liquid from the drywell spray and flow into the pressure suppression chamber via the drywell to pressure suppression chamber connecting vents. Steam flow would be negligible. The energy transported to the pressure suppression chamber water would be removed from the primary containment system by the RHR system heat exchangers in the containment cooling mode.

BFN-28 5.2-26 In order to assess the primary containment response after the blowdown, primary containment analysis was performed. The result of these analyses are presented in Section 14.12, Analysis of the Primary Containment Response. 5.2.4.4 Primary Containment Capability The pressure of the primary containment system depends on both the system temperatures and the amount of non-condensable gases. Thus, the capability of the system to house resulting gases from metal-water reaction varies with the rate and extent of the reaction. Capability is defined as the maximum percent of fuel channels and fuel cladding material which can enter into a metal-water reaction during a specified duration without the design pressure of the containment structure being exceeded. The analysis of the postulated loss-of-coolant accident, discussed in Section 14.0 and Section 6.0, shows that the operation of either of the two Core Spray Systems will maintain continuity of core cooling such that the extent of the resultant metal-water reaction would be less than 0.1 percent. However, to evaluate the containment system design capability, various percentages of metal-water reaction were assumed to take place over various durations of time. This analysis presents an arbitrary method of measuring system capability without requiring prediction of the detailed events in a particular accident condition. The results are presented in Section 14.0.

BFN-27 5.2-27 5.2.4.5 Primary Containment Leakage Analysis The primary containment for each unit is constructed in such a manner that it can be verified initially that, at the maximum pressure resulting from the design basis accident, the leakage rate is not in excess of 2.0 percent per day of the free volume of the primary containment (La). Two tests were performed. The initial test was performed at a reduced pressure of 25 psig (Pt) to determine the leakage rate (Ltm). The second test was performed at 49.6 psig (Pa) to measure the leakage rate (Lam). The leakage characteristics yielded by measurements Ltm and Lam were used to establish the maximum allowable reduced pressure leakage rate (Lt). To verify primary containment integrity throughout the service life of the unit, periodic leakage rate tests will be performed. Details of the leakage rate tests are provided in the Primary Containment Leakage Rate Testing Program as referenced by Technical Specification, Section 5.5.12. 5.2.4.6 Missile and Pipe Whip Prevention In the design of the primary containment and of the components therein, special consideration has been given to missile and pipe whip prevention under the assumed accident conditions. The following summarizes the pertinent design considerations. The containment penetrations and isolation valves are protected from pipe whip by anchors located at or near the isolation valves. Large pipes that penetrate the containment are designed so that, if necessary, they have anchors or limit stops located outside the containment to limit the movement of the pipe. These stops are designed to withstand the jet forces associated with the postulated break of the pipe and thus maintain the integrity of the containment. The space between the containment vessel and the concrete is controlled, so that in areas which are not backed up by concrete and are subjected to jet forces the integrity of the containment will not be violated. Concrete backing is not available for the vent openings to the pressure suppression chamber and jet deflectors are put across these openings for jet protection. The quality control of the fabrication of the pipe, the inspection of the pipe, and the conservative design of the pipe is given a high degree of attention. This approach to prevent pipe failure is substantiated by the long history in the utility industry,

BFN-27 5.2-28 during which time no such circumferential pipe failures have been recorded for the piping materials to be used for this plant. If a pipe leak should occur, means for detecting even small leaks are available in the design so that proper action could be taken before they could develop into an appreciable break. Therefore, based upon the conservative piping design utilizing proven engineering design practice, the proper choice of piping materials, the use of conservative quality control standards and procedures for piping fabrication and installation, and extensive studies of modes of pipe failure, it is concluded that pipes will not break in such a manner as to bring about movement of the pipes sufficient to damage the primary containment vessel. Nevertheless, the recirculation lines within the primary containment are provided with a system of pipe restraints designed to limit excessive motion associated with pipe split or circumferential break. The design utilizes a number of supports and limit stops which permit thermal expansion of the pipe. Both types of breaks, the circumferential break or the longitudinal split, are considered in the support and limit stop arrangement. Even though the emphasis has been placed on the prevention of the occurrence of a pipe whip, special care is also taken in component arrangements to see that equipment associated with Engineered Safety Systems, such as the core spray and the LPCI, are segregated in such a manner that the failure of one cannot cause the failure of the other. Both core spray lines enter the upper cylindrical portion of the drywell and are connected to the pressure vessel nozzles in an arrangement that precludes whip in one line from affecting the other line. In addition, the arrangement prevents whip of one recirculation line from affecting both core spray lines. Each LPCI injection loop injects coolant through separate portions of the recirculation system 180 apart. Each containment spray header and support structure is designed to withstand a load equivalent to the jet forces associated with a break of the largest pipe within the drywell. The containment spray headers are physically separated by 25 feet. With the exception of the incore monitoring detectors, sensors associated with the Reactor Protection System, including the drywell pressure detectors, are located external to the drywell and concrete structure, and are thus protected; however, the incore monitoring detectors are physically separated in the drywell, as are the sensing lines to the other aforementioned instruments. The redundant channels of reactor level and pressure sensing lines are located in the cylindrical section of the drywell 180 apart for maximum physical separation. The redundant channels of sensing lines are physically separated to the maximum possible extent and exit the drywell approximately 180 apart. Additionally, the control rod drive mechanisms are located in a concrete vault that provides protection. In addition, the energy-absorbing material is added to the interior of the drywell surface to the maximum possible extent, in those areas potentially subject to damage from a circumferential break at a weld joint in mainsteam, feedwater, and

BFN-27 5.2-29 RHR piping, and limited only by existing installation. The extent of this coverage is shown in Figure 5.2-6e. The energy-absorbing system absorbs the initial impact of the pipe section and distributes the force over a portion of the primary containment shell and biological shield wall concrete. The material is manufactured by the H. H. Robertson Company and is modified type "DFK" siding with 1/4-inch steel plate spot welded to each face. This composite material has been referred to as "Tornado Siding." The panel protection capability was tested by a dynamic method of striking the panels with a wood plank (4-inches x 12-inches at 105 lb), measuring its velocity at impact, and calculating the average energy absorption capacity. This total average energy was calculated to be 930,000 ft-lb/sq ft. Therefore, this siding is capable of absorbing approximately 1 x 106 ft-lb of kinetic energy/ft2. The siding (24-inches x 24-inches panels) is attached to (1/2-inch studs, welded) the steel containment pressure vessel. The use of small panels permits the material to follow the contour of the vessel. The material, or the design intent of this method of attachment, should not restrict access to piping welds or component welds for in-service inspection. The energy-absorbing system has a negligible effect on the free containment volume and no effect on the accident analysis. Although it has been concluded that, with the application of conservative piping design and proven engineering practices, pipes will not break in such a manner as to bring about movement of pipes sufficient to damage the primary containment vessel, the design of the containment and piping systems does consider the possibility of missiles being generated from the failure of flanged joints, such as valve bonnets, valve stems, and recirculation pumps, and from instrumentation such as thermowells. The design philosophy is that there be no missiles which will penetrate the containment. This is accomplished in practice through the specific design of the containment and contained systems, which takes into account the potential for generation of missiles and minimizes the possibility of containment violation. In considering potential missile sources of this nature, none have been found against which further design action is required. The most positive manner to achieve missile prevention is through basic equipment arrangement such that, if failure should occur, the direction of flight of the missile is away from the containment vessel. The arrangement of plant components takes this possibility into account even though such missiles may not have enough energy to penetrate the containment. Analyses have led to the conclusion that if instruments, ejected thermowells, etc., should become missiles, they would not have sufficient energy to penetrate the containment. It has also been concluded that large, massive rotating

BFN-27 5.2-30 components, such as the reactor recirculating pump motors, would not have sufficient energy to move this mass to the containment wall. The coolant flow from a double-ended break of the recirculation piping could cause a recirculation pump and motor to overspeed. Due to this overspeed possibility, a study was conducted by General Electric to assess the missile possibilities that could result from pipe breaks at various locations. The results of this study have been submitted to the AEC by General Electric in Licensing Topical Report NEDO-10677, Analysis of Recirculation Pump Overspeed in a Typical General Electric Boiling Water Reactor (October 1972). This report recommends the installation of a decoupling device between the pump and motor to prevent destructive motor overspeed. The GE document Analysis of Recirculation Pump Under Accident Conditions dated January 14, 1977, demonstrated that there is no need for protective equipment on the recirculation pumps in GE BWRs. Decoupling devices were not installed in the recirculation pumps at BFN. A probability study was initiated by GE to see if additional restraints to maintain pipe alignment after the pipe break in order to contain the pump missiles were warranted. A summary of this study, "Probabilistic Analysis of the Effects of Missiles Formed in the Recirculation System Following Postulated Pipe Rupture," has been submitted as part of Docket No. 50-333 in FSAR Supplement 20 to the James A. FitzPatrick Nuclear Power Plant license application. This study concluded that:

1.

The cost would be prohibitive because of construction delays,

2.

The combined probability of a LOCA and damage to the containment from a recirculation pump missile is sufficiently low to be identified as a Class 9 accident, and, therefore, no specific action to prevent its occurrence is

required,

3.

The probability of releasing additional radioactive material is slightly increased when recirculation pump missiles are considered, but the overall probability of a radioactive release is still extremely small, and

4.

Incorporation of additional restraints would not provide substantially greater protection for the health and safety of the public, whereas the cost is disproportionally increased for the concomitant minimal increase in overall safety. The assumptions in the analysis and the piping layout inside the containment are such that this study is conservative for the Browns Ferry Nuclear Plant. Thus, this probabilistic study is applicable without modifications. A similar study for missile

BFN-27 5.2-31 shields, to protect the containment and piping inside the containment, was not conducted because it would not differ substantially from this study. It would reach the same general conclusions previously reached for additional piping restraints. Therefore, neither additional restraints nor missile shields are warranted in the Browns Ferry Nuclear Plant. Also, the pump impellers and motor rotors, upon failure, would be contained within their housings and would not generate missiles. There is the potential for valve bonnets to become missiles based on the assumption of failure of all bonnet bolts. This requires instantaneous, clean severance of all bolts, without any overturning motion. The damage potential is dependent upon the size of the valve and system in which the valve is located. Therefore, valve arrangement is important and is taken into consideration in the overall plant design. In addition to the care with which equipment is oriented with regard to potential missile generation, special care is taken in component arrangements to see that equipment associated with Engineered Safety Systems, such as the core spray and the containment spray, is segregated in such a manner that the failure of one cannot cause the failure of the other, or that the failure of any component which would bring about the need for these Engineered Safeguard Systems would not render the safeguard system inoperable. In addition, each containment spray header and support structure is designed to withstand a load equivalent to the jet forces associated with a break of the largest pipe within the drywell. With the exception of the incore monitoring detectors, sensors associated with the Reactor Protection System, including the drywell pressure detectors, are located external to the drywell and concrete structure, and are thus protected. Additionally, the control rod drive mechanisms are located in a concrete vault that provides protection. The pressure suppression chamber has no source of internal or external missile generation, and the vent pipes joining it with the drywell are protected by the jet deflectors. The vent discharge headers and piping are designed to withstand the jet reaction force caused by flow discharge into the pressure suppression pool. Redundant subsections of vital systems are physically separated within the primary containment to minimize the probability that more than one redundant subsection could be damaged. The drywell is completely enclosed in a reinforced concrete structure having a thickness of 4 to 6 feet. This concrete structure, in addition to serving as the basic biological shielding for the reactor system, also provides a major mechanical barrier for the protection of the drywell and reactor system against potential missiles generated external to the primary containment, including pipeline failures of the main steam, feedwater, HPCI steam, RCIC steam, and reactor water cleanup lines. There are two segmented shield plugs above the drywell, each 3-ft thick, and separated vertically by 1 inch. The top corner, edges, and bottom corner of the

BFN-27 5.2-32 plugs are formed by 1/2-inch steel plate anchored by headed concrete anchors. Each plug is supported along the periphery by a ledge on the drywell concrete structure. The ledges are formed by the stainless steel plate which lines the reactor well cavity. Headed concrete anchors are used to anchor the plate at the ledges. The segmented, reinforced concrete shield plug above the drywell has been analyzed for the impact of those missiles which have been postulated to reach the refueling floor level. These missiles are identified in GE Topical Report GE APED-5696, "Tornado Protection for the Spent Fuel Storage Pool." November 1968. The method of analysis is that given for structural design for impulsive loads, Chapter 3, Section IV, Department of the Army Technical Manual, TM 5-855-1, Fundamentals of Protective Design, July 1965. The analysis shows that one 3-ft thick plug is capable of resisting the missile having the greatest impact energy. None of the postulated missiles will penetrate the plug to a depth that will cause scabbing of the underside. To provide for possible movement as a result of operating and accident loads, 1/2-inch clearance is provided between the shield plugs and the drywell concrete structure. Frictional forces can be developed at the plug support points on the steel plate surfaces which form the edges of the plugs and the supporting ledges. The plugs and the ledges are capable of resisting the forces developed. 5.2.4.7 Penetrations In order to minimize post-accident containment leakage, the containment penetrations are designed to withstand the normal environmental conditions which may prevail during plant operation, and to retain their integrity during the following postulated accidents. Pipelines which penetrate the containment shell, and which are capable of exerting a reaction force due to line thermal expansion or containment movement which cannot be restrained by the containment shell, are provided with bellows expansion seals, appropriate guards, limit stops, or anchors as required to maintain stresses within allowable design limits. These design features are utilized to ensure integrity of the penetration during plant operation and during accident conditions. Pipelines which penetrate the containment where the reactive forces can be restrained by the containment shell are provided with full strength attachment welds between the pipe and the containment shell. These penetrations are designed for long-term integrity without the use of a bellows seal. Electrical penetration assemblies require special design consideration to achieve zero

BFN-27 5.2-33 leakage because of the design restriction imposed by creepage characteristics of electrical insulation. TIP guide tubes and their penetrations also require special design considerations, due to the fact that they are the means of passage from the interior of the reactor vessel to the Reactor Building for the TIP fission chamber and its electromechanical drive cable. The TIP guide tubes within the RPV are designed to ASME Boiler and Pressure Vessel Code, Section III. The drywell penetrations have double-seal testable flange, with the guide tube brazed to the flange as described in paragraph 5.2.3.4.4. A personnel access lock is provided with interlocked double doors, so that access may be made to the containment while the reactor primary system is pressurized. Double doors are provided to assure that containment integrity is maintained while access is being made. Equipment access hatches are sealed in place, using flexible double seals to assure leak-tightness. These openings are closed at all times when containment is required. The containment shell, electrical penetrations, and piping penetrations are metallic components (with a ceramic filler, or equivalent, in the electrical penetrations) that are designed to pressure vessel standards; thus, no degradation will occur from temperature, pressure, or radiation damage. Inspection and surveillance provide additional assurance of integrity and functional performance of the penetrations. For this reason, provisions are made to leak-test electrical penetrations, the personnel access lock, the access hatches, and those pipe penetrations having bellows seals. This can be accomplished without pressurizing the entire containment system. Provisions are made in the design of the integrated containment system to monitor for gross leakage of the primary containment to demonstrate that all penetrations are sealed during plant operation. This function is performed by the containment atmospheric control system, as described in paragraph 5.2.3.8. 5.2.4.8 Isolation Valves One of the basic purposes of the Primary Containment System is to provide a minimum of one protective barrier between the reactor core and the environmental surroundings subsequent to an accident involving failure of the piping components of the reactor primary system. To fulfill its role as an insurance barrier, the primary containment is designed to remain intact before, during, and subsequent to any design basis accident of the process system installed either inside or outside the primary containment. The process system and the primary containment are considered as separate systems, but where process lines

BFN-27 5.2-34 penetrate the containment, the penetration design achieves the same integrity as the primary containment structure itself. The process line isolation valves are designed to achieve the containment function inside the process lines when required. Since a rupture of a large line penetrating the containment and connecting to the reactor coolant system may be postulated to take place at the containment boundary, the isolation valve for that line is required to be located within the containment. This inboard valve in each line is required to be closed automatically on various indications of reactor coolant loss. A certain degree of additional reliability is added if a second valve, located outboard on the containment and as close as practical to it, is included. This second valve also closes automatically if the inboard valve is normally open during reactor operation. If a failure involves one valve, the second valve is available to function as the containment barrier. By physically separating the two valves, there is less likelihood that a failure of one valve would cause a failure of the second. The two valves in series are provided with independent power sources. The ability of the steam line penetration and the associated steam line isolation valves to fulfill the containment safety design basis (paragraph 5.2.2), under several postulated conditions of the steam line, is shown below by consideration of various assumed steam line break locations.

a.

The failure occurs within 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 a loss-of-coolant accident, except that the pressure transient is less severe since the blowdown rate is slower. Both isolation valves close upon receipt of the signal indicating low water level in the reactor vessel. 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 within the drywell and renders the inner isolation valve inoperable. Again, the reactor steam will blow down into the primary containment. The outer isolation valve will close upon receipt of the low water level signal, and the reactor becomes isolated within the primary containment, as above.

c.

The failure occurs downstream of the inner isolation valve either within the drywell or within the guard pipe. Both isolation valves will close upon receipt of a signal indicating low water level in the reactor vessel. The guard pipe is designed to accommodate

BFN-27 5.2-35 such a failure without damage to the drywell penetration bellows, and the design of the pipeline supports protects its welded juncture to the drywell vessel. Thus, the reactor vessel is isolated within the primary containment by means of the inner isolation valve, and the primary containment integrity is maintained 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 outer isolation valve and the turbine. The steam will blow down directly into the pipe tunnel or the Turbine Building. Steam releases into the tunnel are detected by temperature sensors. When these sensors detect a high temperature condition in the steam tunnel, they initiate main steam isolation. This action isolates the reactor, completes the containment integrity, and places two barriers in series between the reactor core and the outside environment. Pipe supports prevent containment damage. The offsite consequences of this failure are presented in the accident analysis as discussed in Section 14.0, "Plant Safety Analysis." It should be noted also that the turbine stop valves, located in the steam lines just ahead of the turbine, will provide a backup containment barrier, in addition to the outer isolation valves, for such breaks as a, b, and c as discussed above. The exceptions to the arrangement of isolation valves described above (1 inboard, 1 outboard), for lines connecting directly to the containment or reactor primary system, are made only in the cases where it leads to a less desirable situation because of required operation or maintenance of the system in which the valves are located. In the cases where, for example, the two isolation valves are located outside the containment, special attention is given to assure that the piping to the isolation valves has an integrity at least equal to the containment. The TIP system isolation valves are normally closed. When the TIP system cable is inserted, the valve of the selected tube opens automatically and the chamber and cable are inserted. Insertion, calibration, and retraction of the chamber and cable require approximately 5 minutes. Retraction requires a maximum of 1-1/2 minutes. If closure of the valve is required during calibration, the isolation signal causes the cable to be retracted and the valve to close automatically on completion of cable withdrawal. A manually actuated shear valve is also provided in the event the cable cannot be withdrawn. Reinsertion of the TIP probe upon clearing of the Group 8 isolation signal requires manual operator intervention to reset the insertion logic.

BFN-27 5.2-36 It is not 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 which are open to the drywell, and some effluent process lines. However, under these conditions, it is essential that containment and Core Standby Cooling Systems be operable. For this reason, specific signals are utilized for isolation of the various process and safeguards systems (see Subsection 7.3). Isolation valves must be closed before significant amounts of fission products are released from the reactor core under design basis accident conditions. Because the amount of radioactive materials 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 below the top of the core. All of the primary containment system isolation valves, shown on FSAR Figures 5.2-2a sheets 1, 2, and 3, utilize either elastomer or metal seats. All the valves with elastomer seats are located outside the primary containment. The elastomer valve seats are designed to withstand the temperature and exposure dose for their locations. The elastomer seat isolation valves will maintain their structural integrity and leak tightness following a DBA. The isolation valves which utilize metal seats will maintain their structural integrity and leak tightness following a DBA. Valves, sensors, and other automatic devices essential to the isolation of the containment are provided with means for periodically testing the functional performance of the equipment. Such tests are necessary to provide reasonable assurance that the containment isolation devices perform as required when called upon to do so. 5.2.4.9 Containment Inerting System In the event of a loss-of-coolant accident, the Core Standby Cooling Systems prevent generation of significant quantities of hydrogen capable of being ignited. Maintaining the oxygen content of the primary containment atmosphere at less than 4 percent ensures no combustion of the hydrogen and oxygen, thus assuring containment integrity. 5.2.5 Inspection and Testing The following represents areas of surveillance and testing that are provided for the various systems or components of the primary containments as they apply during construction or plant operation. Access is provided to conduct periodic in-service examinations of the primary containment boundary in accordance with the

BFN-27 5.2-37 applicable subsections of ASME Section XI Code. The area and type of examinations are contained in plant procedures. 5.2.5.1 Primary Containment Integrity and Leak Tightness Fabrication procedures, nondestructive testing, and sample coupon tests are in accordance with the ASME Boiler and Pressure Vessel Code, Section III, Subsection B. Provisions were made to test the integrity of the primary containment systems during construction phases. These tests included a pneumatic test of the drywell and pressure suppression chamber at 1.25 times their design pressure in accordance with code requirements. After installation of new penetrations in the drywell or suppression chamber, leakage tests will be conducted in accordance with applicable codes. Periodic integrated leakage rate tests are performed as required by the plant technical specifications. Since both the drywell and pressure suppression chamber have the same design pressure, it is possible to test the entire primary containment at the same pressure and without the necessity of providing temporary closures to isolate the pressure suppression chamber from the drywell. Penetrations welded directly to the primary containment are tested with the complete containment vessel. Inspections during these tests, periodic in-service inspections, and tests throughout plant life ensure early detection and repair of any leaks or other deterioration of the primary containment. 5.2.5.2 Penetrations With the exception of the pipe penetrations which are welded directly to the primary containment shell, it is possible to leak-test individual containment penetrations without pressurizing the entire containment system. For those with double seals, testing may be accomplished by pressurizing the penetration between the double seals utilizing the pressure tap. Leak detection may then be accomplished by use of a soap solution, pressure decay, displacement, mass flow method, or volume flow method. Pipe penetrations which must accommodate thermal movement are provided with double expansion bellows. The bellows expansion joints are designed for the containment system design pressure, and the inner bellows can be checked for leak tightness when the containment system is pressurized. In addition, these joints are provided with a test tap so that the space between the bellows can be pressurized to the calculated peak accident pressure to permit testing the individual penetrations for leakage. The drywell to pressure suppression chamber vent pipe expansion bellows are not designed to be separately tested to verify leak tightness. The leak tightness of the drywell to pressure suppression chamber vent pipe expansion bellows is verified

BFN-28 5.2-38 during the periodic integrated leak-rate tests of the primary containment. These expansion bellows are an integral part of the primary containment vessel and, therefore, are not considered as penetrations per se. These bellows were designed as Class B vessels in accordance with the 1965 edition of the ASME Boiler and Pressure Vessel Code, Section III, Nuclear Vessels, and Code Cases 1177 and 1330. The manufacturing process began with a 0.078-inch thick plate made of Type 304 stainless steel that was formed into tubing, 84 inches in diameter and 24 inches in length, with two longitudinal seam welds. These welds were given a 100-percent radiography test prior to forming the convolutions, and a magnetic particle examination was given to all the butt welds used in the assembly process. After fabrication, cover plates were added to each bellows in order to conduct leak-tightness tests with Freon-12 and hydrostatic tests with 95 psig externally applied pressure. These tests and examinations verified the structural integrity of the bellows before the cover plates were removed in preparation for installation of the bellows in the Browns Ferry plant. An integrated leak-test was conducted on the completed containment (with bellows installed) that verified the initial structural integrity of the "as-built" primary containment. Periodic integrated leak testing of these bellows is sufficient since their normal deflections are only a small fraction of the design values and, also, the number of flexure cycles is only a small fraction of the limiting value. Thus, the likelihood of these bellows developing a leak is extremely small, and the test frequency proposed is the same as for the containment vessel proper. Sketches of the drywell vent pipe expansion bellows are provided in Figures 5.2-6f and -6g. The pneumatic test pressure is not less than 49.1 psig. The design pressure is 56 psig, and the manufacturer's test pressure is 70 psig. Electrical penetrations are also provided with double seals and are separately testable. The test taps and the seals are so located that the tests of the electrical penetrations can be conducted without entering or pressurizing the drywell or pressure suppression chamber. All containment closures which are fitted with resilient seals or bellows are separately testable to verify leak tightness. The covers on flanged closures, such as the equipment access hatch cover, the drywell head, access hatches and personnel air lock compartment are provided with double seals and with a test tap which will allow pressurizing the space between the seals without pressurizing the entire containment system. In addition, provision is made so that the space between the airlock doors can be pressurized to full drywell design pressure. The double O-ring seal type penetrations are designed to allow testing between the seals up to the containment design pressure.

BFN-27 5.2-39 5.2.5.3 Isolation Valves The test capabilities which are incorporated in the primary containment system to permit leak detection testing of containment isolation valves as specified in Table 5.2-2 are separated into two categories. The first category consists of those pipelines which open into the containment and do not terminate in closed loops outside the containment but contain two isolation valves in series. Test taps are provided between the two valves which permit leakage monitoring of the first valve when the containment is pressurized. The test tap can also be used to pressurize between the two valves to permit leakage testing of both valves simultaneously. The valves, associated sensors, and equipment which will be subjected to containment pressures during the periodic leakage test are designed to withstand containment design pressure without failure or loss of functional performance. The functional performance of these devices has been verified by demonstration either during the leakage tests or subsequent to the test but prior to startup. The second category consists of those pipelines which connect to the reactor system and contain two isolation valves in series. A leak-off line is provided between the two valves, and a drain line is provided downstream of the outboard valve. This arrangement permits monitoring of leakage on the inboard and outboard valves during reactor system hydrostatic tests, which can be conducted at pressures exceeding the reactor system operating pressure. Surveillance requirements for primary containment isolation valves are given in Subsection 3.6.1.3 of the Technical Specifications. 5.2.5.4 Containment Inerting System The Containment Inerting System is proven operable by its use during normal plant operations. Portions of the system normally closed to flow can be tested to ensure their operability and the integrity of the system. 5.2.6 Combustible Gas Control in Primary Containment In normal operation, the primary containment atmosphere is maintained at less than 4.0 percent oxygen by volume, with the balance in nitrogen. Following a loss-of-coolant accident, hydrogen is evolved within the containment from metal-water reactions, and hydrogen and oxygen are produced by radiolysis of water. These are the only significant sources of hydrogen and oxygen. If the concentrations of hydrogen and oxygen were not controlled, a combustible gas

BFN-27 5.2-40 mixture could be produced. To ensure that a combustible gas mixture does not form, the oxygen concentration is kept below 5 percent by volume, or the hydrogen concentration is kept below 4 percent by volume. The concentration of combustible gases in containment following a loss-of-coolant accident is controlled by a Containment Atmosphere Dilution (CAD) system. This system is capable of keeping the concentration of oxygen in the containment atmosphere below 5 percent when hydrogen and oxygen generation rates specified in Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, are assumed. In the event that post-accident monitoring showed that hydrogen and oxygen generation rates were substantially below those specified in the guide, the system could be operated to maintain either the hydrogen concentration below 4 percent or the oxygen concentration below 5 percent. 5.2.6.1 Design Basis

a.

The CAD system shall be a shared system, capable of supplying nitrogen to the primary containment of Unit 1, Unit 2, and Unit 3.

b.

The CAD system shall be capable of supplying nitrogen at a rate sufficient to maintain the oxygen concentrations of both the drywell and pressure suppression chamber atmospheres below 5.0 percent by volume, based on hydrogen and oxygen generation rates as set forth in AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident.

c.

The containment atmosphere dilution portion of the CAD system shall be designed as an engineered safety feature. The system shall be operated remote-manually from the Main Control Room and shall be designed for possible startup 10 hours after a LOCA.

d.

The Containment Air Monitoring (CAM) system provides a monitor for measuring oxygen and hydrogen concentrations inside primary containment. Equipment is also provided for sensor calibration.

e.

The CAD system shall include means for releasing gas from either the drywell or the pressure suppression chamber in a controlled manner. The gas shall be released via the Standby Gas Treatment System. The containment vent portion of the CAD system is not an engineered safety feature since the venting function is not required to maintain the containment oxygen concentration below the 5 percent limit. However, redundant vent paths to the Standby Gas Treatment System are provided. Under severe accident conditions with loss of long term decay heat

BFN-28 5.2-41 removal capability, the HCVS (Units 1 and 2) or the HWWV (Unit 3) may be used in lieu of CAD system venting to control primary containment pressure. The HCVS (Units 1 and 2) shall release gas from the pressure suppression chamber directly to the independent release points above the Unit 1 and 2 Reactor Buildings. The HWWV system (Unit 3) shall release gas from the pressure suppression chamber directly to the plant stack via an independent vent path.

f.

Nitrogen storage capacity sufficient for 7 days of post-LOCA operation shall be provided.

g.

The containment pressure shall not exceed 30 psig as a result of CAD system operation.

h.

The CAD system shall provide an emergency source of nitrogen to the Automatic Depressurization System (ADS) main steam relief valve accumulators. This capability meets the requirements of NUREG-0737, Item II.K.3.28. The CAD system shall provide backup supply of nitrogen to operate the HCVS valves (Units 1 and 2) and the HWWV valves (Unit 3) in the event control air is not available. 5.2.6.2 CAD System Design The CAD system design is similar among units. A flow diagram of the Unit 1, Unit 2, and Unit 3 CAD system is shown in Figures 5.2-7 sheets 1, 2, and 3 and a control diagram is shown in Figures 5.2-8 sheets 1, 2 and 3. The system includes nitrogen supply facilities and gas release facilities. The CAD system nitrogen supply facilities include two trains, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber. Each train includes a liquid nitrogen supply tank, an ambient vaporizer, an electric heater, a manifold with branches to each primary containment, and pressure, flow, and temperature controls. The nitrogen storage tanks have a total volume of 4000 gallons each. The tanks are filled to approximately 3400 gallons maximum level leaving a gas volume above the liquid. The required technical specification level of 2615 gallons for Unit 2 and 2615 gallons for Units 1 and 3 is adequate for the first 7 days of CAD operation. The gas above the liquid in the tank is maintained at a minimum pressure of 100 psig. The nitrogen vaporizers use the ambient atmosphere as the heat source. Each is capable of producing 100 SCFM of gas when the atmospheric temperature is -20F. The gas temperature is about 20 below ambient temperature.

BFN-28 5.2-42 Unqualified electric heaters are provided for use during cold weather to warm the gas. This is done to avoid brittle fracture problems in the carbon steel lines to which the stainless steel nitrogen supply piping connects at the drywell and pressure suppression chamber. The heaters have a capacity of 3 kilowatts each and are thermostatically controlled to maintain an effluent temperature between 50F and 60F. The heater in train A is supplied from reactor MOV board 1C, and the heater in train B is supplied from reactor MOV board 3B. With nitrogen-operated valve 0-FCV-84-5 (train A) or 0-FCV-84-16 (train B) open, nitrogen is admitted to the drywell by opening solenoid-operated valve FSV-84-8A or FSV-84-8D, and to the pressure suppression chamber by opening solenoid-operated valve FSV-84-8B or FSV-84-8C. An isolation bypass switch for FSV-84-8A & 8D and 8B & 8C is provided to permit possible operation of the CAD system 16 hours after a LOCA. Manual valves 84-37 and 84-38 are preset to limit the flow to 100 CFM. The two nitrogen storage tanks and their associated vaporizers are located outdoors at least 150 feet south of the Reactor Building. The A tank is positioned in front of the far west end of the Unit 2 Reactor Building, and the B tank is positioned past the east end of the Reactor Building and the Unit 3 Diesel Generator Building. The tanks and vaporizers are located so as to permit free circulation of air around the vaporizers. Nitrogen supply lines run around the south side of the Reactor Building, and branch lines to each unit enter the building through six large steel and concrete pipe tunnels. Inside the building, each of the six branch lines is brought to a location near primary containment where it branches into two lines, one of which goes to the drywell and the other to the pressure suppression chamber. The two

BFN-27 5.2-43 branches serving the drywell are joined and connect into the drywell air purge line (refer to Figures 5.2-2a sheets 1, 2, and 3) at a point between the drywell and the first isolation valve. The two branches serving the pressure suppression chamber are joined and connect into the pressure suppression chamber air purge line (refer to Figures 5.2-2a - Sheets 1, 2 and 3) at a point between the pressure suppression chamber and the first isolation valve. Thermocouple TE-84-32 is inserted into the nitrogen supply line that connects into the drywell air purge lines. Thermocouple TE-84-31 is inserted into the nitrogen supply line that connects into the pressure suppression chamber air purge line. In the event that the temperature sensed by any of these six thermocouples drops to 45F, an alarm is actuated in the Main Control Room. This alarm (light) alerts the operator that the nitrogen supply valve which is open should be closed. Dual paths are provided for releasing gas from the drywell or the pressure suppression chamber. Each path includes a butterfly valve, a throttle valve, a pressure switch, and a flow element. The butterfly valves and throttle valve FCV-84-20 automatically close on a containment isolation signal. Key operated switches are provided for bypassing the containment isolation signals for the butterfly valves when the reactor mode switch is not in the RUN position (MODE 1). Except during surveillance testing or a LOCA, throttle valve FCV-84-19 remains closed. Depending on the path selected, the appropriate butterfly valve in the vent system is opened and the CAD system flow control valve FCV-84-19 or FCV-84-20 is opened. The flow rate is regulated at 100 CFM by the flow control valve, which, in turn, is controlled by the associated flow transmitter, FT-84-19 or FT-84-20. Pressure switch PS-84-21 or PS-84-22 closes the flow control valve FCV-84-19 or FCV-84-20. Oxygen and hydrogen monitoring systems are described elsewhere in this section under the heading of "CAM System". The CAD system, including nitrogen storage tanks, vaporizers, piping, and valves, is an Engineered Safeguards System and is designed to meet seismic Class I requirements. The system is designed in accordance with the following:

a.

United States Atomic Energy Commission (USAEC), Safety Guides for Water-Cooled Nuclear Power Plants, revised March 10, 1971, Safety Guide No. 7, "Control of Combustible Gas Concentration in Containment Following a Loss-of-Coolant Accident."

b.

USA Standard Code for Pressure Piping, Power Piping, USAS B31.1.0, 1967 edition, as published by the American Society of Mechanical Engineers, as supplemented by the requirements of the applicable GE

BFN-27 5.2-44 specifications, which are implemented in lieu of the outdated B31 Nuclear Code Cases - N2, N7, N9, and N10. The installation is in accordance with existing plant construction specifications for the applicable TVA piping classification.

c.

Institute of Electrical and Electronics Engineers (IEEE), IEEE 279-1971, Nuclear Power Plant Protection Systems. The nitrogen storage tanks and vaporizers are constructed of stainless steel and aluminum alloy. Nitrogen supply valves and piping are of stainless steel. Carbon steel piping and valves are used in the gas release lines. The minimum design pressure for the CAD system piping is 150 psig. Portions of the system are designed to withstand higher pressures. Valves in the system which are not hand-operated employ several means for actuation and are operable from the Main Control Room. Flow control valves 0-FCV-84-5 and 0-FCV-84-16 are nitrogen operated. Valves FSV-84-8A through FSV-84-8D are solenoid operated. Valves FCV-84-19 and FCV-84-20 are operated with instrument air or with nitrogen. The containment isolation valves used in CAD system operation (FCV-64-29, FCV-64-31, FCV-64-32, and FCV-64-34 on Figures 5.2-8 sheets 1, 2, and 3) are air-or nitrogen-operated valves which fail closed on loss of air and nitrogen. Since the station air supply might not be available in a post-LOCA situation, nitrogen from the CAD system supply manifolds is used as a backup gas for actuating the valves. Nitrogen from the train A manifold supplies valves FCV-64-29, FCV-64-32, and FCV-84-19, while nitrogen from the train B manifold supplies valves FCV-64-31, FCV-64-34, and FCV-84-20. Nitrogen from the CAD system train A manifold also is used as a backup gas for actuating the torus vacuum breaker valves FCV-64-20 and FCV-64-21. No special provisions are made for mixing the added nitrogen with the containment atmosphere. The CAD concept is based on maintaining the oxygen concentration below the Safety Guide 7 limit of 5 percent; thus, the only concern from a mixing viewpoint is the potential degree of non-uniformity in oxygen concentration that would occur in the containment. There are three mixing forces existing in the containment after a loss-of-coolant accident: diffusion, natural convection, and forced convection. Forced convection is the most difficult mixing force to quantitatively evaluate, and detailed calculations of its effects on concentration gradients have not been done. However, detailed calculations have been done on the other two mixing forces, that is, diffusion and natural convection. The details of this analysis were presented in Amendment 2 of the Duane Arnold Energy Center FSAR in response to question G1.1(d). The referenced calculations showed that the maximum oxygen concentration deviation would be 2 percent from the average at the surface of the pressure suppression pool using

BFN-27 5.2-45 conservative assumptions relative to the natural convection driving force. Less conservative assumptions for natural convection would result in a maximum concentration deviation of only 0.3 percent. In other words, given an average oxygen concentration of 5 percent, the maximum concentration at the pressure suppression pool surface would be 5.10 percent, or, less conservatively, 5.015 percent. Based on the results of this analysis, it has been concluded that the assumption of a uniform oxygen concentration in the containment is reasonable. To promote mixing, containment sprays can be operated intermittently. CAM System A Containment Air Monitoring (CAM) system is provided (one per unit) to monitor both hydrogen and oxygen in the drywell and torus. Measurement capability is provided over the range of 0-100 percent hydrogen concentration in a containment pressure range of -2.7 psig to 56 psig. Indication of hydrogen concentration in the containment atmosphere is provided in the control room. The CAM systems consist of a sampling loop comprised of piping, isolation valves and a sample return pump; an analyzer located outside containment; and control room readout and control equipment. All piping and valves from the containment to the analyzer cabinets are ASME III, Class 2. All equipment necessary for post-LOCA operation is seismic Class I. The cabinets containing the sensors are supplied from a 120 VAC I&C bus and the pumps are powered from a 480 VAC MOV board. The solenoid operated isolation valves can be remotely operated from the control room by a key-locked switch which overrides the primary containment isolation signal. The CAM systems and associated electrical equipment can be supplied from non-divisional power. The containment isolation valves must be supplied from 1E power. The valves will fail closed on loss of power. The pumps used to pull an air sample are bellows type (Units 2 and 3) and diaphragm type (Unit 1) pumps capable of pulling a sample from either the drywell or the torus in less than two minutes. The samples are exhausted back into the torus. The temperature and humidity of the sample gas are controlled to ensure reliable and accurate readings. Less than two minutes is required to pull a sample from either the drywell or the torus. The piping and pressure retaining components are designed to withstand at least 56 psig. The system is also capable of operating when the drywell or the torus is under a vacuum down to -2.7 psig. The analyzers are Reg. Guide 1.97, Category 3 and are not required to withstand post-accident radiation exposure, nor are they engineered safeguards systems.

BFN-27 5.2-46 CAD System Operation The CAD system is operated manually. Following a LOCA, records will be kept of hydrogen and oxygen concentrations and pressures in the drywell and pressure suppression chamber, and calculations will be made of the production rates of hydrogen and oxygen in each of these volumes. Nitrogen additions will be made periodically, as needed, to keep the oxygen content below 5 percent in each volume. Additions will be made separately to the drywell and the pressure suppression chamber. The amount of nitrogen to be added may be determined by the following equation: VN Vi ci cf 1

where VN = volume of nitrogen to be added, SCF Vi = volume of gas in drywell or pressure suppression chamber before nitrogen addition, SCF Ci = initial concentration of oxygen or hydrogen Cf = desired final concentration of oxygen or hydrogen. If hydrogen and oxygen production rates approach those assumed in Safety Guide 7, the containment pressure will increase and may reach the predetermined limit of 30 psig. Before this pressure is reached, containment venting will be initiated. Gas releases will be made periodically and will be made separately from the drywell and pressure suppression chamber. Releases will be made during periods when meteorological conditions are most favorable. Gas will be released at a rate of about l00 CFM until the desired volume has been released. Releases are continued until the containment pressure has been reduced to atmospheric. Nitrogen additions will be continued during the period in which the containment pressure is being reduced to atmospheric. Additions and releases will be made at different times. The operator manually controls nitrogen venting time and frequency. Changes in containment pressure are slow. To reduce containment pressure by one psi, for example, 19,000 SCF of gas would be released. At 100 CFM, the release time would be about 190 minutes. The operator will have available to him information on the pressure, temperature, hydrogen content, oxygen content, radioactivity in the containment atmosphere,

BFN-28 5.2-47 and amount of nitrogen added for both the drywell and pressure suppression chamber. Meteorological information will be available also. Using this information, an operator can safely follow the venting procedure without exceeding the 10 CFR 50.67 limits following a LOCA. 5.2.6.3 Design Evaluation The post LOCA containment gas concentration for hydrogen and oxygen concentrations versus time curves for the CAD System are described below. This analysis was based on the following assumptions: Extended Power Uprate (EPU) condition Safety Guide 7 design basis requirements No containment leakage Hydrogen gas generated from the metal water reaction is included as a diluent in the calculation of nitrogen capacity to maintain oxygen concentration below 5% by volume Initial drywell and wetwell oxygen concentration is 4% Post LOCA containment temperature versus time profile used in the analysis Is conservative with respect to the EPU post LOCA containment temperatre versus time profile. Increase in post LOCA containment temperature due to the potential increase of decay heat from the effects of additional actinides and activation products (SIL-6362) is beneficial to the CAD system and, therefore, bounded by the temperature profile used. Decay heat data are based on finite exponential series expressions defined in the U.S. NRC Standard Review Plan 6.2.5, Appendix A. These fuel-independent generic decay heat data are conservative and, as stated in the SRP, over-predict the standard curve specified by the American Nuclear Society Standard ANS 5.1-1979 by 20% between the decay times of 400 and 4x107 seconds. These conservative decay heat data bound best-estimate decay heat curves applicable for the Browns Ferry fuel design, including the effects of additional actinides and activation products (SIL-636). Two post LOCA conditions were evaluated:

1. Design Basis Case - conditions are one RHR loop operating, 95F cooling water, 95F initial suppression pool temperature and no containment sprays operating. The design basis case determines the nitrogen storage capacity required for the CAD system 2 GE Nuclear Energy Service Information Letter SIL-636 Rev.1, Additional Terms included in Reactor Decay Heat Calculations. (June 2001).

BFN-28 5.2-48

2. Bounding Case - cold conditions are one RHR loop in service, 40F cooling water, 60F initial suppression pool temperature, and no containment sprays operating. These conditions minimize the beneficial dilution effects of water vapor in the containment. The bounding case demonstrates that adequate operator response time and time to replenish nitrogen storage capacity exist for the full range of plant conditions.

AREVA Design Evaluation A full core load of ATRIUM 10 fuel was assumed for the calculation of the active cladding mass. The results for the design basis case, under EPU conditions, are reflected by the figures summarized below: Figure 5.2-13 provides the hydrogen and oxygen concentrations in the drywell and pressure suppression chamber following a LOCA without dilution for ATRIUM 10 fuel. Figure 5.2-14 provides the hydrogen and oxygen concentrations in the drywell with dilution for ATRIUM 10 fuel. Figure 5.2-15 provides the hydrogen and oxygen concentrations in the pressure suppression chamber with dilution for ATRIUM 10 fuel. Figure 5.2-16 provides the maximum nitrogen required for dilution for ATRIUM 10 fuel. This shows that a maximum of about 200,000 SCF of nitrogen would be required in the first seven days following a LOCA. 2615 gallons of liquid nitrogen is equivalent to 200,000 SCF of gaseous nitrogen. In normal operation, the tanks will be refilled to maintain a minimum of 2615 gallons of nitrogen as required by technical specifications. Figure 5.2-17 provides the maximum containment pressure following LOCA with dilution for ATRIUM 10 fuel. For the design basis case after the design basis LOCA during the first 42 hours, water vapor in the drywell atmosphere and hydrogen produced by the metal-water reaction are sufficient to keep the oxygen concentration in the drywell below five percent. In the pressure suppression chamber, the oxygen concentration remains below five percent for the first 30 hours. Figures 5.2-14 and 5.2-15 include the effect of dilution by water vapor as well as hydrogen. The water vapor content is based on assumed post-LOCA conditions, which give maximum containment pressure.

BFN-28 5.2-49 For the bounding case, nitrogen injection is not expected to be required for 27 hours in the drywell and 12 hours in the suppression pool. These initiation times meet the minimum 10 hour design basis and do not challenge the operators capability to begin injection at the appropriate time. Since the CAD nitrogen storage capacity is defined by the design basis case, CAD would need to be replenished in 6.5 days at the bounding case conditions. These results confirm acceptable CAD capability for the full range of plant conditions. ATRIUM-10 and ATRIUM-10XM fuel assemblies were assessed per the following

Reference:

FS1-0019597, Revision 1, Browns Ferry Units 1, 2, and 3 Extended Power Uprate Task Report, Task 411: Combustible Gas Control in Containment. The fuel designs were found to meet Technical Specification Requirements and Bases assumptions. ATRIUM-10 results remain bounding. General Design Evaluation The CAD System operation during a LOCA can be carried out without exceeding 10 CFR 50.67 doses without exceeding a containment pressure of 30 psig. The dose calculation assumptions associated with fission product release to the environs by secondary containment are contained in FSAR, Chapter 14, Subsection 14.6.3.6. With the provision of a redundant CAD System vent mechanisms as a backup containment purge system is not required. The nitrogen supply can be easily replenished from multiple facilities within seven days. There are multiple liquid nitrogen distribution facilities that are located within a one-day travel distance from Browns Ferry. All enclosed areas and compartments of the Reactor Building have been examined with respect to possible hazards resulting from leakage from the containment. This examination showed that leakage to open areas of the Reactor Building will not produce hazardous gas mixtures. Adequate mixing occurs as a result of the high diffusion rate of hydrogen and some convection. Leakage into the space between the drywell and the surrounding concrete will not present a hazard because there is no ignition source. In addition, there is no ignition source

BFN-28 5.2-50 in the space above the drywell head. Similarly, there are no ignition sources in the clearance spaces between the shield plugs for the equipment access hatches, and the biological shield around the drywell. Two areas requiring consideration are the pressure suppression chamber room and the personnel access room. Of the two areas, the personnel access room is the worst case. The pressure suppression chamber room has several openings that will allow convective mixing with other Reactor Building areas. The total rate of leakage from the primary containment is based on the design criterion of 2 percent of the drywell volume per day at peak accident pressure. From Figure 5.2-14, the maximum concentration of hydrogen in the containment atmosphere with no leakage (for ATRIUM-10 fuel) is about 14 volume percent and occurs about 48 hours after the LOCA. It is postulated that a substantial portion of the total drywell leakage may occur through the two equipment access hatches and the personnel airlock. The personnel airlock is 7 feet in diameter and is equipped with double seals. Each equipment hatch is 12-feet 10-inches in diameter. It is assumed that the rate of in-leakage to the personnel access room is 1/6 of the total leakage from the drywell. This is very conservative, since leakage must occur through two doors to reach the access room. A convection flow path (see Figures 5.2-19, 5.2-20, and 5.2-21) exists from the pressure suppression chamber area to the personnel access room through floor sleeves. The return path for the cooler Reactor Building air is through the stairwell to the lower Reactor Building area (see Figure 5.2-21). Calculations show that a differential temperature of 20F will produce a flow of 10 SCFM through the convective path described. It can be concluded from this analysis that no hazard is produced as a result of leakage from the containment to enclosed areas of the Reactor Building. Further, the Standby Gas Treatment System will remove the hydrogen from the Reactor Building so that the hydrogen concentration in the building will not reach a hazardous level. The volume of the secondary containment is just below 9 million cubic feet and the Standby Gas Treatment System allowable surveillance in-leakage is given in Section 5.3.3.7. Based on this flow rate, the building volume will be changed at least once every day. It is not anticipated that the integrity of the primary containment will deteriorate to a point where excessive leakage will occur following a design basis accident.

BFN-27 5.2-51 Capability is provided to release gas from primary containment through the Standby Gas Treatment System using CAD system vent valves should primary containment integrity be challenged from overpressure following a design basis accident. Under severe accident conditions with loss of long term decay heat removal capability, the HCVS (Units 1 and 2) or HWWV (Unit 3) may be used in lieu of CAD system venting to control primary containment pressure. 5.2.6.4 Testing and Inspections Preoperational tests of the completed installation were conducted to establish that individual components perform as required. Following interconnection with the individual units, each train of the nitrogen supply portion of the CAD system was operated to supply nitrogen to the primary containment. Manual valves 84-37 and 84-38 in the gas supply manifold were adjusted to limit flow to 100 CFM. The flow control valves in the gas release paths (FCV-84-19 and FCV-84-20) were adjusted to limit flow to 100 CFM, using air supplied through the test connections. 5.2.7 Hardened Wetwell Vent (Unit 3) 5.2.7.1 Introduction The consequences of several beyond design basis accident scenarios are more severe than the accidents previously considered herein. The primary containment pressure during these accidents is estimated to exceed its design capacity. Thus, the primary containment fails, potentially to the environment as well. The HWWV provides an emergency primary containment vent path to prevent, or at least slow down, the buildup of potentially damaging pressure within the primary containment. 5.2.7.2 System Description The HWWV provides a direct vent path from the torus (wetwell) to an exhaust point inside the concrete portion of the plant stack above elevation 666.5'. The vent flow path exits the torus via the existing 20" pressure suppression chamber supply, which will be isolated during venting by the existing primary containment isolation valve FCV-64-19. Unit 3 HWWV path consists of torus penetration X-205, the 20" pressure suppression chamber supply piping downstream of valve FCV-64-20, and a 14" line to a 14" header. The 14" header runs underground in the yard and then discharges in the stack above elevation 666.5'. Two 14" pneumatically operated butterfly valves (FCV-64-221 and FCV-64-222) provide primary containment isolation and can be remotely operated from the Main Control Room. A manual valve, 64-737, is located downstream of the primary

BFN-27 5.2-52 containment isolation valves to provide isolation from the header for maintenance purposes. The HWWV has a maximum operating and design pressure and temperature of 56 psig and 304oF. Electrical power to the HWWV isolation valves shall be from essential DC sources to ensure availability during the Station Blackout Event. The vent pipe is safety-related TVA piping Class D (similar to ASME III Class 2) up to and inclusive of the outboard containment isolation valve. The downstream piping is non-safety related and is TVA piping Class P (similar to ASME III Class 3). A pneumatic supply from System 032 (Control Air) with System 084 (Containment Air Dilution) backup serves each operator for primary containment isolation valves FCV-064-0221 and FCV-064-0222. The CAD supply and associated control air piping is safety-related and is supported Seismic Class I to ensure its availability. During normal plant operation, the HWWV containment isolation valves will remain closed. In response to a severe accident (long-term loss of decay heat removal), plant management could direct the control room operators to employ the HWWV to relieve excessive pressure within the containment. In this case, the operator will follow a written Emergency Operating Procedure for HWWV operation. 5.2.7.3 Radiological Consequences of HWWV Use The exhaust gases released by the HWWV following a beyond design basis accident would have initially been "washed" by the pressure suppression pool water which would reduce the particulate released. These exhaust gases are vented to the highest vent point (main stack), avoiding the ground level release of radioactive material from containment failure due to over-pressurization. 5.2.8 Hardened Containment Venting System (Units 1 and 2) 5.2.8.1 Introduction The consequences of several beyond design basis accident scenarios are more severe than the accidents previously considered herein. The primary containment pressure during these accidents is estimated to exceed its design capacity. Thus, the primary containment fails, potentially to the environment as well. The HCVS provides an emergency primary containment vent path to prevent, or at least slow down, the buildup of potentially damaging pressure within the primary containment.

BFN-27 5.2-53 5.2.8.2 System Description The HCVS provides a direct vent path from the torus (wetwell) to independent release points above the Unit 1 and 2 Reactor Buildings at an elevation of 741-6. The vent flow path exits the torus via the existing 20" pressure suppression chamber supply, which will be isolated during venting by the existing primary containment isolation valve FCV-64-19. The Unit 1 and 2 HCVS path consists of torus penetration X-205, the 20" pressure suppression chamber supply piping downstream of valve FCV-64-20, and a 14" line that exits the Reactor Building. The 14" Sch 30 pipe transitions to 14 Sch 40 exterior to the Reactor Building in an underground valve pit before turning and routing vertically up the exterior of the Reactor Building. At the 664 elevation the pipe turns to enter the refuel floor area and then continuing to the vent termination point at elevation 741-6 above the Reactor Building roof. Two 14" pneumatically operated butterfly valves (FCV 221 and FCV-64-222) provide primary containment isolation and can be remotely operated from the Main Control Room. The HCVS has a design pressure and temperature of 62 psig and 350oF and a maximum operating pressure of 56 psig. Electrical power to the HCVS isolation valves is from RMOV boards which remain powered during an Extended Loss of AC Power (ELAP) event. Power is available via manual transfer for each isolation valve to a dedicated HCVS battery system which ensures operability during the first 24 hours of an ELAP. The vent pipe is safety-related TVA piping Class D (similar to ASME III Class 2) up to and inclusive of the outboard containment isolation valve. The downstream piping is non-safety related and is TVA piping Class P (similar to ASME III Class 3) up to the valve pit flange location, downstream the piping is TVA piping Class M up to the vent release point. A pneumatic supply from System 032 (Control Air) with System 084 (Containment Air Dilution) backup serves each operator for primary containment isolation valves FCV-064-0221 and FCV-064-0222. The CAD supply and associated control air piping is safety-related and is supported Seismic Class I to ensure its availability. A backup nitrogen system is provided to ensure continued operation during the first 24 hours during an ELAP event resulting in a loss of Control Air or CAD. During normal plant operation, the HCVS containment isolation valves will remain closed. In response to a severe accident (long-term loss of decay heat removal), plant management could direct the control room operators to employ the HCVS to relieve excessive pressure within the containment. In this case, the operator will follow a written Emergency Operating Procedure for HCVS operation.

BFN-27 5.2-54 5.2.8.3 Radiological Consequences of HCVS Use The exhaust gases released by the HCVS following a beyond design basis accident would have initially been "washed" by the pressure suppression pool water which would reduce the particulate released. These exhaust gases are vented to a release point above the Unit 1 and 2 Reactor Buildings.

BFN-28 Table 5.2-1 (Sheet 1) PRINCIPAL DESIGN PARAMETERS AND CHARACTERISTICS OF PRIMARY CONTAINMENT Pressure suppression chamber internal design pressure 56 psig external design pressure 2 psig Drywell internal design pressure 56 psig external design pressure 2 psig Drywell free volume 171,000 ft3 (max)*1 Pressure suppression chamber free volume (min.) 119,400 ft3 *1 Pressure suppression pool water volume (max.) 135,000 ft3 *1, 2 Submergence of vent pipe below pressure suppression pool surface (low water level) 2.92 ft suppression pool surface (high water level) 3.83 ft* Design temperature of drywell 281F Design temperature of pressure suppression chamber 281F Downcomer vent pressure loss factor 5.32* Ratio of break area/total vent area 0.012* Drywell free volume/pressure suppression chamber free volume 1.43* Primary system volume/pressure suppression pool volume 0.201* Drywell free volume/primary system volume 6.48* RHR Heat Exchanger K-value, BTU/sec-ºF/HX 265

• These values did not change as a direct result of increasing power but represent parameters that were reevaluated as part of the power uprate and extended power uprate analyses.

1These values are conservative analytical limits used in the analysis which include analysis conservatism and the effect of instrument inaccuracies. 2This value is an analytical limit and may not match the value listed in the Technical Specification Bases which lists an operational limit.

BFN-28 Table 5.2-1 (Sheet 2) PRINCIPAL DESIGN PARAMETERS AND CHARACTERISTICS OF PRIMARY CONTAINMENT Calculated maximum pressure after blowdown (no prepurge) Drywell 49.1 psig Pressure suppression chamber 30.2 psig Initial pressure suppression pool temperature rise 57ºF Leakage rate at design accident pressure 2.0% per day

BFN-28 Table 5.2-2 (Sheet 1 of 14) PRINCIPLE PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes 1 X-7A FCV-1-14 AO Globe 26 Main Steam Line A IBIC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7A FCV-1-15 AO Globe 26 Main Steam Line A OBOC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7B FCV-1-26 AO Globe 26 Main Steam Line B IBIC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7B FCV-1-27 AO Globe 26 Main Steam Line B OBOC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7C FCV-1-37 AO Globe 26 Main Steam Line C IBIC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7C FCV-1-38 AO Globe 26 Main Steam Line C OBOC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7D FCV-1-51 AO Globe 26 Main Steam Line D IBIC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-7D FCV-1-52 AO Globe 26 Main Steam Line D OBOC O GC 3<T<5 Air, AC, DC Air, Spring 7 1 X-8 FCV-1-55 MOV Gate 3 Main Steam Line Drain IBIC C SC 15 AC AC 1 1 X-8 FCV-1-56 MOV Gate 3 Main Steam Line Drain OBOC C SC 15 DC DC 1 N/A 1-X-20 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2-X-20 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 3-X-20 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 1-X-20 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2-X-20 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 3-X-20 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A X-9A 3-554 Check 24 Feedwater Line A 0BOC O P N/A Process Process 1 N/A X-9A 3-558 Check 24 Feedwater Line A IBIC O P N/A Process Process 1 N/A X-9B 3-568 Check 24 Feedwater Line B OBOC O P N/A Process Process 1

BFN-27 Table 5.2-2 (Sheet 2 of 14) PRINCIPLE PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes N/A X-9B 3-572 Check 24 Feedwater Line B IBIC O P N/A Process Process 1 N/A 1-X-22 1-32-915 Check 1 Control Air Supply IBIC O P N/A Process Process 1 N/A 2-X-22 2-32-2163 Check 1 Control Air Supply IBIC O P N/A Process Process 1 N/A 3-X-22 3-32-2163 Check 1 Control Air Supply IBIC O P N/A Process Process 1 N/A X-50B 32-2516 Check 3/4 Control Air Supply IBIC O P N/A Process Process 1 N/A X-50B 32-2521 Check 3/4 Control Air Supply OBOC O P N/A Process Process 1 N/A X-22 32-336 Check 1 Control Air Supply OBOC O P N/A Process Process 1 N/A 1-X-48 Flanged N/A N/A ILRT Compressor Connection N/A C N/A N/A N/A N/A 9 N/A 2-X-48 Flanged N/A N/A ILRT Compressor Connection N/A C N/A N/A N/A N/A 9 N/A 3-X-48 Flanged N/A N/A ILRT Compressor Connection N/A C N/A N/A N/A N/A 9 N/A 1-X-21 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2-X-21 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 3-X-21 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 1-X-21 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2-X-21 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 3-X-21 PLUGGED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 1 Does Not Open on Signal D&P Isolates on B Only X-41 FCV-43-13 AO Globe 3/4 Reactor Water Sample IBIC C SC 5 Air, AC Spring 1

BFN-27 Table 5.2-2 (Sheet 3 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes 1 Isolates on B Only X-41 FCV-43-14 AO Globe 3/4 Reactor Water Sample OBOC C SC 5 Air, AC Spring 1 6 X-229J FSV-43-40* SOL Globe 1/2 PASS Sample Return IBOC C SC N/A AC Spring 1 6 X-229J FSV-43-42* SOL Globe 1/2 PASS Sample Return OBOC C SC N/A AC Spring 1 6 N/A FSV-43-50 SOL Globe 1/2 PASS Liquid Sample IBOC C SC N/A AC Spring 59 6 N/A FSV-43-56 SOL Globe 1/2 PASS Liquid Sample OBOC C SC N/A AC Spring 59 N/A X-42 63-525 Check 1-1/2 SLC To Reactor OBOC C P N/A Process Process 60 N/A X-42 63-526 Check 1-1/2 SLC To Reactor IBIC C P N/A Process Process 60 N/A X-205 64-800 Check 20 Torus Vacuum Relief OBOC C P N/A Process Process 1 N/A X-205 64-801 Check 20 Torus Vacuum Relief OBOC C P N/A Process Process 1 6 X-231 FCV-64-139 AO Globe 3 Drywell/Torus DP Compressor Suction OBOC C SC 10 Air, AC Spring 1 6 X-26 FCV-64-140 AO Globe 2 Drywell/Torus DP Compressor Discharge OBOC C SC 10 Air, AC Spring 1 6 X-25 FCV-64-17 AO Butterfly 20 Cooling/Purge Air To Containment OBOC C SC 2.5 Air, AC Spring 1 6 X-25 FCV-64-18 AO Butterfly 18 Cooling/Purge Air To Drywell IBOC C SC 2.5 Air, AC Spring 1 6 X-205 FCV-64-19 AO Butterfly 20 Cooling/Purge Air To Pressure Suppression Chamber IBOC C SC 2.5 Air, AC Spring 1 N/A X-205 FCV-64-20 AO Butterfly 20 Torus Vacuum Relief IBOC C N/A N/A Spring Air, AC 1 N/A X-205 FCV-64-21 AO Butterfly 20 Torus Vacuum Relief IBOC C N/A N/A Spring Air, AC 1 6 X-26 FCV-64-29 AO Butterfly 18 Drywell Exhaust IBOC C SC 2.5 Air, AC Spring 1 6 X-26 FCV-64-30 AO Butterfly 18 Drywell Exhaust OBOC C SC 2.5 Air, AC Spring 1 6 X-26 FCV-64-31 AO Butterfly 2 Drywell Exhaust Bypass Valve To Standby Gas IBOC O GC 5 Air, AC Spring 1

BFN-27 Table 5.2-2 (Sheet 4 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes 6 X-231 FCV-64-32 AO Butterfly 18 Torus Exhaust IBOC C SC 2.5 Air, AC Spring 1 6 X-231 FCV-64-33 AO Butterfly 18 Torus Exhaust OBOC C SC 2.5 Air, AC Spring 1 6 X-231 FCV-64-34 AO Butterfly 2 Torus Exhaust Bypass Valve To Standby Gas IBOC O GC 5 Air, AC Spring 1 N/A X-205 FCV-64-221 AO Butterfly 14 Hardened Wetwell Vent (Unit 3) / Hardened Containment Vent (Units 1 and 2) IBOC C N/A N/A Air, DC Spring 1, 51 N/A X-205 FCV-64-222 AO Butterfly 14 Hardened Wetwell Vent (Unit 3) / Hardened Containment Vent (Units 1 and 2) OBOC C N/A N/A Air, DC Spring 1, 51 N/A X-37C 68-508 Check 3/4 Recirc Pump Seal Water IBIC O P N/A Process Process 1 N/A X-38C 68-523 Check 3/4 Recirc Pump Seal Water IBIC O P N/A Process Process 1 N/A X-37C 68-550 Check 3/4 Recirc Pump Seal Water OBOC O P N/A Process Process 1 N/A X-38C 68-555 Check 3/4 Recirc Pump Seal Water OBOC O P N/A Process Process 1 N/A 1-X-9B 1-69-629 Check 4 RWCU System Return OBOC O P N/A Process Process 1 N/A 2-X-9B 2-69-630 Check 4 RWCU System Return OBOC O P N/A Process Process 1 N/A 3-X-9B 3-69-629 Check 4 RWCU System Return OBOC O P N/A Process Process 1 3 X-14 FCV-69-1 MOV Gate` 6 RWCU Suction IBIC O GC 30 AC AC 1 3 X-14 FCV-69-2 MOV Gate 6 RWCU Suction OBOC O GC 30 DC DC 1 N/A X-23 70-506 Check 8 RBCCW Drywell Supply OBOC O P N/A Process Process 1 N/A X-24 FCV-70-47 MOV Gate 8 RBCCW Drywell Return OBOC O GC N/A AC AC 1, 4 N/A X-210A 71-547 Check 2 RCIC Pump Minimum Flow Bypass OBOC C P N/A Process Process 59 N/A X-212 & X-218 71-580 Check 10 RCIC Turbine Exhaust OBOC C P N/A Process Process 1 N/A X-221 71-592 Check 2 RCIC Vacuum Pump Discharge OBOC C P N/A Process Process 59

BFN-27 Table 5.2-2 (Sheet 5 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes N/A X-227A FCV-71-17 MOV Gate 6 RCIC Pump Suction IBOC C SC N/A DC DC 59 N/A X-227A FCV-71-18 MOV Gate 6 RCIC Pump Suction OBOC C SC N/A DC DC 59 5 X-10 FCV-71-2 MOV Gate 3 Steam To RCIC IBIC O GC 15 AC AC 1 5 X-10 FCV-71-3 MOV Gate 3 Steam To RCIC OBOC O GC 15 DC DC 1 N/A X-210A FCV-71-34 MOV Globe 2 RCIC Pump Minimum Flow Bypass IBOC C SC N/A DC DC 59 N/A X-9B 1-CKV-71-40 Check 6 RCIC Pump Discharge IBOC C P N/A Process Process 1 N/A X-9B 2-CKV-71-40 Check 6 RCIC Pump Discharge IBOC C P N/A Process Process 1 N/A X-9B 3-CKV-71-40 Check 6 RCIC Pump Discharge IBOC C P N/A Process Process 1 N/A X-212 & X-218 71-14 Globe Stop Check 8 RCIC Turbine Exhaust IBOC C P N/A Process Process 1 N/A X-221 71-32 Globe Stop Check 2 RCIC Vacuum Pump Discharge IBOC C P N/A Process Process 59 N/A X-210B CKV-73-559 Check 4 HPCI Miniflow Bypass OBOC C P N/A Process Process 59 N/A X-214 & X-220 2/3-CKV 603 Check 16 HPCI Turbine Exhaust OBOC C P N/A Process Process 1 N/A X-214 & X-218 1-CKV-73-603 Check 16 HPCI Turbine Exhaust OBOC C P N/A Process Process 1 4 X-11 FCV-73-2 MOV Gate 10 Steam To HPCI IBIC O GC 20 AC AC 1 4 X-226 FCV-73-26 MOV Gate 16 HPCI Pump Suction IBOC C SC 80 DC DC 59 4 X-226 FCV-73-27 MOV Gate 16 HPCI Pump Suction OBOC C SC 80 DC DC 59 4 X-11 FCV-73-3 MOV Gate 10 Steam To HPCI OBOC O GC 20 DC DC 1 N/A X-210B FCV-73-30 MOV Globe 4 HPCI Miniflow Bypass IBOC C SC N/A DC DC 59 N/A X-9A 1-CKV-73-45 Check 14 HPCI To Feedwater Line A OBOC C P N/A Process Process 1 4 X-11 FCV-73-81 MOV Gate 1 HPCI Warm Up Bypass OBOC C SC 10 AC AC 1

BFN-27 Table 5.2-2 (Sheet 6 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes N/A X-214 & X-220 2/3-73-23 Globe Stop Check 16 HPCI Turbine Exhaust IBOC C P N/A Process Process 1 N/A X-214 & X-218 1-73-23 Globe Stop Check 16 HPCI Turbine Exhaust IBOC C P N/A Process Process 1 N/A X-12 74-661 Check 3/4 RHR Shutdown Cooling Press Relief Bypass IBIC C P N/A Process Process 1 N/A X-12 74-662 Check 3/4 RHR Shutdown Cooling Press Relief Bypass IBIC C P N/A Process Process 1 N/A X-213B 74-722 Manual Gate 8 Torus Drain IBOC C SC N/A Manual Manual 59 N/A N/A 74-792 Check 2 PSC Head Tank To RHR OBOC O P N/A Process Process 59 N/A N/A 74-802 Check 2 PSC Head Tank To RHR OBOC O P N/A Process Process 59 N/A N/A 74-803 Check 2 PSC Head Tank To RHR IBOC O P N/A Process Process 59 N/A N/A 74-804 Check 2 PSC Head Tank To RHR IBOC O P N/A Process Process 59 N/A 1-X-222 CAPPED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 3-X-222 CAPPED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2 X-12 FCV-74-47 MOV Gate 20 (RHR) Shutdown Cooling Suction OBOC C SC 40 DC DC 1 N/A X-9A 2-CKV-73-45 Check 14 HPCI To Feedwater Line A OBOC C P N/A Process Process 1 N/A X-9A 3-CKV-73-45 Check 14 HPCI To Feedwater Line A OBOC C P N/A Process Process 1 2 X-12 FCV-74-48 MOV Gate 20 (RHR) Shutdown Cooling Suction IBIC C SC 40 AC AC 1 2 X-13A FCV-74-53 MOV Gate 24 RHR-LPCI To Reactor OBOC C SC 40 AC AC 63 N/A X-13A FCV-74-54 Check 24 RHR-LPCI To Reactor IBIC C P N/A Process Process 63 N/A 2-X-222 CAPPED N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A X-211A FCV-74-57 MOV Gate 18 RHR Containment Cooling OBOC C SC N/A AC AC 61

BFN-27 Table 5.2-2 (Sheet 7 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes N/A X-211A FCV-74-58 MOV Globe 4 RHR Containment Cooling IBOC C SC N/A AC AC 61 N/A 1-X-39A 1-FCV-74-60 MOV Gate 12 RHR Drywell Spray OBOC C P N/A AC AC 62 N/A 2-X-39B 2-FCV-74-60 MOV Gate 12 RHR Drywell Spray OBOC C P N/A AC AC 62 N/A 3-X-39B 3-FCV-74-60 MOV Gate 12 RHR Drywell Spray OBOC C P N/A AC AC 62 N/A 1-X-39A 1-FCV-74-61 MOV Gate 12 RHR Drywell Spray IBOC C P N/A AC AC 62 N/A 2-X-39B 2-FCV-74-61 MOV Gate 12 RHR Drywell Spray IBOC C P N/A AC AC 62 N/A 3-X-39B 3-FCV-74-61 MOV Gate 12 RHR Drywell Spray IBOC C P N/A AC AC 62 2 X-13B FCV-74-67 MOV Gate 24 RHR-LPCI To Reactor OBOC C SC 40 AC AC 63 N/A X-13B FCV-74-68 Check 24 RHR-LPCI To Reactor IBIC C P N/A Process Process 63 N/A X-211B FCV-74-71 MOV Gate 18 RHR Containment Cooling OBOC C SC N/A AC AC 61 N/A X-211B FCV-74-72 MOV Globe 4 RHR Containment Cooling IBOC C SC N/A AC AC 61 N/A X-225A SMV-74-226 Globe 3/4 RHR PMP Suction Sample Valve IBOC C SC N/A Manual Manual 4 N/A X-225B SMV-74-227 Globe 3/4 RHR PMP Suction Sample Valve IBOC C SC N/A Manual Manual 4 N/A 1-X-39B 1-FCV-74-74 MOV Gate 12 RHR Drywell Spray OBOC C P N/A AC AC 62 N/A 2-X-39A 2-FCV-74-74 MOV Gate 12 RHR Drywell Spray OBOC C P N/A AC AC 62 N/A 3-X-39A 3-FCV-74-74 MOV Gate 12 RHR Drywell Spray OBOC C P N/A AC AC 62 N/A 1-X-39B 1-FCV-74-75 MOV Gate 12 RHR Drywell Spray IBOC C P N/A AC AC 62 N/A 2-X-39A 2-FCV-74-75 MOV Gate 12 RHR Drywell Spray IBOC C P N/A AC AC 62 N/A 3-X-39A 3-FCV-74-75 MOV Gate 12 RHR Drywell Spray IBOC C P N/A AC AC 62 N/A N/A 75-606 Check 2 PSC Head Tank To Core Spray IBOC O P N/A Process Process 59 N/A N/A 75-607 Check 2 PSC Head Tank To Core Spray OBOC O P N/A Process Process 59 N/A N/A 75-609 Check 2 PSC Head Tank To Core Spray IBOC O P N/A Process Process 59

BFN-27 Table 5.2-2 (Sheet 8 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes N/A N/A 75-610 Check 2 PSC Head Tank To Core Spray OBOC O P N/A Process Process 59 N/A X-16A FCV-75-25 MOV Gate 12 Core Spray To Reactor OBOC C SC N/A AC AC 63 N/A X-16A 1-CKV-75-26 Check 12 Core Spray To Reactor IBIC C P N/A Process Process 63 N/A X-16A 2-CKV-75-26 Check 12 Core Spray To Reactor IBIC C P N/A Process Process 63 N/A X-16A 3-CKV-75-26 Check 12 Core Spray To Reactor IBIC C P N/A Process Process 63 N/A X-16B FCV-75-53 MOV Gate 12 Core Spray To Reactor OBOC C SC N/A AC AC 63 N/A X-16B 1-CKV-75-54 Check 12 Core Spray To Reactor IBIC C P N/A Process Process 63 N/A X-16B 2-CKV-75-54 Check 12 Core Spray To Reactor IBIC C P N/A Process Process 63 N/A X-16B 3-CKV-75-54 Check 12 Core Spray To Reactor IBIC C P N/A Process Process 63 2 X-227A FCV-75-57 AO Globe 3 Pressure Suppression Chamber Drain IBOC O GC 15 Air, AC Spring 59 2 X-227A FCV-75-58 AO Globe 3 Pressure Suppression Chamber Drain OBOC O GC 15 Air, AC Spring 59 N/A X-35F 76-653 Check 3/8 TIP Nitrogen Purge IBOC C C N/A Process Process 1 6 X-25 FCV-76-17 AO Butterfly 2 Containment Inerting N2 Makeup OBOC C SC 5 Air, AC Spring 1 6 X-25 FCV-76-18 AO Butterfly 2 Containment Inerting Drywell N2 Makeup IBOC C SC 5 Air, AC Spring 1 6 X-205 FCV-76-19 AO Butterfly 2 Containment Inerting - PSC N2 Makeup IBOC C SC 5 Air, AC Spring 1 6 X-25 FCV-76-24 AO Butterfly 10 Containment Nitrogen Purge OBOC C SC 5 Air, AC Spring 1 6 X-27F FSV-76-49 SOL Globe 1/2 Drywell Analyzer A Sample IBOC O/C GC/SC N/A AC Spring 1 6 X-27F FSV-76-50 SOL Globe 1/2 Drywell Analyzer A Sample OBOC O/C GC/SC N/A AC Spring 1 6 1-X-229D 1-FSV-76-55 SOL Gate 1/2 Torus Analyzer A Sample IBOC O/C GC/SC N/A AC Spring 1

BFN-27 Table 5.2-2 (Sheet 9 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes 6 2-X-229D 2-FSV-76-55 SOL Globe 1/2 Torus Analyzer A Sample IBOC O/C GC/SC N/A AC Spring 1 6 3-X-229N 3-FSV-76-55 SOL Globe 1/2 Torus Analyzer A Sample IBOC O/C GC/SC N/A AC Spring 1 6 1-X-229D 1-FSV-76-56 SOL Gate 1/2 Torus Analyzer A Sampler OBOC O/C GC/SC N/A AC Spring 1 6 2-X-229D 2-FSV-76-56 SOL Globe 1/2 Torus Analyzer A Sampler OBOC O/C GC/SC N/A AC Spring 1 6 3-X-229N 3-FSV-76-56 SOL Globe 1/2 Torus Analyzer A Sampler OBOC O/C GC/SC N/A AC Spring 1 6 1-X-229B 1-FSV-76-57 SOL Gate 1/2 Analyzer A Sample Return IBOC O GC N/A AC Spring 1 6 2-X-229B 2-FSV-76-57 SOL Globe 1/2 Analyzer A Sample Return IBOC O GC N/A AC Spring 1 6 3-X-229A 3-FSV-76-57 SOL Globe 1/2 Analyzer A Sample Return IBOC O GC N/A AC Spring 1 6 1-X-229B 1-FSV-76-58 SOL Gate 1/2 Analyzer A Sample Return OBOC O GC N/A AC Spring 1 6 2-X-229B 2-FSV-76-58 SOL Globe 1/2 Analyzer A Sample Return OBOC O GC N/A AC Spring 1 6 3-X-229A 3-FSV-76-58 SOL Globe 1/2 Analyzer A Sample Return OBOC O GC N/A AC Spring 1 2 X-19 1-FCV-77-15A AO Ball 3 Drywell Equipment Drain Sump Discharge IBOC O GC 15 Air, AC Spring 1 2 X-19 1-FCV-77-15B AO Ball 3 Drywell Equipment Drain Sump Discharge OBOC C GC 15 Air, AC Spring 1 2 X-18 1-FCV-77-2A AO Ball 3 Drywell Floor Drain Sump Discharge IBOC O GC 15 Air, AC Spring 1 2 X-18 1-FCV-77-2B AO Ball 3 Drywell Floor Drain Sump Discharge OBOC C GC 15 Air, AC Spring 1 2 X-19 2-FCV-77-15A AO Ball 3 Drywell Equipment Drain Sump Discharge IBOC O GC 15 Air, AC Spring 1

BFN-28 Table 5.2-2 (Sheet 10 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes 2 X-19 2-FCV-77-15B AO Ball 3 Drywell Equipment Drain Sump Discharge OBOC C GC 15 Air, AC Spring 1 2 X-18 2-FCV-77-2A AO Ball 3 Drywell Floor Drain Sump Discharge IBOC O GC 15 Air, AC Spring 1 2 X-18 2-FCV-77-2B AO Ball 3 Drywell Floor Drain Sump Discharge OBOC C GC 15 Air, AC Spring 1 2 X-19 3-FCV-77-15A AO Ball 3 Drywell Equipment Drain Sump Discharge IBOC O GC 15 Air, AC Spring 1 2 X-19 3-FCV-77-15B AO Ball 3 Drywell Equipment Drain Sump Discharge OBOC C GC 15 Air, AC Spring 1 2 X-18 3-FCV-77-2A AO Ball 3 Drywell Floor Drain Sump Discharge IBOC O GC 15 Air, AC Spring 1 2 X-18 3-FCV-77-2B AO Ball 3 Drywell Floor Drain Sump Discharge OBOC C GC 15 Air, AC Spring 1 N/A X-25 84-600 Check 2 CAD Admission To Drywell OBOC C P N/A Process Process 1 N/A X-205 84-601 Check 2 CAD Admission To Torus OBOC C P N/A Process Process 1 N/A X-25 84-602 Check 2 CAD Admission To Drywell OBOC C P N/A Process Process 1 N/A X-205 84-603 Check 2 CAD Admission To Torus OBOC C P N/A Process Process 1 N/A X-50B 1-84-683 Gate 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A Manual Manual 1 N/A X-22 1-84-686 Gate 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A Manual Manual 1 N/A X-50B 2-84-683 Manual Ball 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A Manual Manual 1 N/A X-22 2-84-686 Manual Ball 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A Manual Manual 1 N/A X-231 FCV-84-19 AO Globe 2 CAD System Containment Exhaust To Standby Gas (65) OBOC C SC N/A Air, AC Spring 1

BFN-28 Table 5.2-2 (Sheet 11 of 14) ISLN Group Signal Notes PEN. No. Valve UNID (A,B) Valve Type Valve Size (In.) Type of Service Cntmt. Lctn. Normal Status Action on Initiating Signal Max Opr. Time (Sec.) Power Open Close See Notes 6 X-26 FCV-84-20 AO Globe 2 CAD Containment To Standby Gas (65) OBOC C SC 10 Air, AC Spring 1 N/A X-50B 3-84-683 Gate 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A Manual Manual 1 N/A X-22 3-84-686 Gate 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A Manual Manual 1 N/A X-25 FSV-84-8A SOL Globe 2 CAD Admission To Drywell IBOC C SC N/A AC Spring 1 N/A X-205 FSV-84-8B SOL Globe 2 CAD Admission To Torus IBOC C SC N/A AC Spring 1 N/A X-205 FSV-84-8C SOL Globe 2 CAD Admission To Torus IBOC C SC N/A AC Spring 1 N/A X-25 FSV-84-8D SOL Globe 2 CAD Admission To Drywell IBOC C SC N/A AC Spring 1 N/A X-50B FSV-84-48 SOL Globe 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A AC Spring 1 N/A X-22 FSV-84-49 SOL Globe 1 CAD Crosstie To Drywell Control Air OBOC C N/A N/A AC Spring 1 6 X-50A FSV-90-254A SOL Gate 1 Airborne Radiation Monitoring IBOC O GC 10 AC AC 1 6 X-50D FSV-90-254B SOL Gate 1 Airborne Radiation Monitoring IBOC O GC 10 AC AC 1 6 X-50A & X-50D FSV-90-255 SOL Gate 1 Airborne Radiation Monitoring OBOC O GC 10 AC AC 1 6 X-50C FSV-90-257A SOL Gate 1 Airborne Radiation Monitoring OBOC O GC 10 AC AC 1 6 X-50C FSV-90-257B SOL Gate 1 Airborne Radiation Monitoring IBOC O GC 10 AC AC 1 8 X-35A FCV-94-501 SOL Ball 3/8 TIP Guide Tube IBOC C GC N/A AC AC 1 8 X-35B FCV-94-502 SOL Ball 3/8 TIP Guide Tube IBOC C GC N/A AC AC 1 8 X-35C FCV-94-503 SOL Ball 3/8 TIP Guide Tube IBOC C GC N/A AC AC 1 8 X-35D FCV-94-504 SOL Ball 3/8 TIP Guide Tube IBOC C GC N/A AC AC 1 8 X-35E FCV-94-505 SOL Ball 3/8 TIP Guide Tube IBOC C GC N/A AC AC 1

BFN-28 Table 5.2-2 (Sheet 12 of 14) PRINCIPLE PRIMARY CONTAINMENT PENETRATIONS AND ASSOCIATED ISOLATION VALVES GENERAL NOTES: LEGEND A. Unid Numbers Shown Are Typical For All Three Units Unless Otherwise Noted. O = Open C = Closed B. This Table Does Not List All Primary Containment Valves, For Example, Instrument Line Root Valves, Excess Flow Check Valves, Vent Valves, Panel Isolation Valves And Panel Valves. This Table Should Not Be Used In Determining The Primary Containment Boundary Or Appendix J Testing Boundary. SC = Stays Closed GC = Goes Closed P = Process IBIC

=

Inboard Inside Containment OBOC

=

Outboard Outside Containment IBOC

=

Inboard Outside Containment NOTES: (Correspond to Containment Leak Rate Program Note Numbers) ISOLATION GROUP NOTES:

1.

Primary Containment Isolation Valve(S) Requiring LLRT At Not Less Than 49.1 psig. Group 1 = B, D, P

3.

Primary Containment Isolation Valves That Are In Closed Loop, Seismic Class I Lines That Will Be Water Sealed During A DBA. These Valves Will Be Tested But Not Included In The 60-Percent La Tabulation. Group 2 = A, F Group 3 = A, J Group 4 = L, E

4.

Primary Containment Isolation Valves That Are Manually Operated. Group 5 = K, G Group 6 = A, F, Z

7.

Primary Containment Isolation Valves Requiring LLRT At Not Less Than 25-Psig. Group 7 = (Deleted) Group 8 = A, F

9.

These Components Require Local Leak Rate Testing At Not Less Than 49.1 psig.

51.

The Maximum Allowable Leak Rate For These Valve Is 10 Scfh.

59. Sealed by water in a pathway that is not a potential Containment Atmospheric Pathway during and following the DBA that produces peak containment pressure; therefore, local leak rate testing is not required by ANSI/ANS 56.8-1994 and NEI 94-01.

60. Primary Containment Isolation Valve that is not a potential Containment Atmospheric Pathway during and following the DBA that produces peak containment pressure; therefore, local leak rate testing is not required by ANSI/ANS 56.8-1994 and NEI 94-01.

61. Torus Spray valve that is sealed by water in a pathway that is not a potential Containment Atmospheric Pathway during and following the DBA that produces peak containment pressure; therefore, local leak rate testing is not reuqired by ANSI/ANS 56.8-1994 and NEI 94-01.

62. Drywell Spray Valve that is sealed by water in a pathway that is not a potential Containment Atmospheric Pathway during and following the DBA that produces peak containment pressure; therefore, local leak rate testing is not required by ANSI/ANS 56.8-1994 and NEI 94-01.

63. Pressure Isolation Valve that is in a pathway that is not a potential Containment Atmospheric Pathway during and following the DBA that produces peak containment pressure; therefore, local leak rate testing is not required by ANSI/ANS 56.8-1994 and NEI 94-01. However, it is required to be leak tested by the In-Service Testing Program.

BFN-27 Table 5.2-2 (Sheet 13 of 14) SIGNAL DESCRIPTION A. Reactor Vessel Low Water Level (Level 3) B. Reactor Vessel Low-Low-Low Water Level (Level 1) D. Main Steamline Break (Steamline High Space Temperature Or High Steam Flow) E. High Pressure Between Diaphragm Rupture Discs On HPCI Turbine Exhaust F. High Drywell Pressure G. High Pressure Between Diaphragm Rupture Discs On RCIC Turbine Exhaust J. High Temperature In The Areas Occupied By RWCU Equipment (RWCU Heat Exchanger Room Or RWCU Pump Rooms 2A And 2B), Or High Temperature In The RWCU Pipe Trench Or High Temperature In The Main Steam Valve Vault. Alarm And Close Cleanup System Isolation Valves. K. Line Break In RCIC System Steamline To Turbine (High Steamline Space Temperature, High Steam Flow, Or Low Steamline Pressure) L. Line Break In HPCI System Steamline To Turbine (High Steamline Space Temperature, High Steam Flow, Or Low Steamline Pressure) P. Low Main Steamline Pressure At Inlet To Turbine (Run Mode Only) Z. Reactor Building Ventilation Exhaust High Radiation

• For Units 2 and 3 only.

BFN-27 Table 5.2-3 (Deleted by Amendment 18)

BFN-27 TABLE 5.2-4 (Deleted by Amendment 17)

BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRIMARY CONTAINMENT VESSELS FIGURE 5.2-1a SECURITY RELATED INFORMATION FIGURE WITHHELD UNDER 10 CFR 2.390

BFN-16 Figures 5.2-1 b through 5.2-1c Deleted

BFN-16 Figure 5.2-2 Deleted by Amendment 11 1); ( I

HOH I-U-019J£t,-I.... Lt I ,;:;,:,:;,_,.<>>-i!lill-f~ r -lE© ,,..,..,..,,_,. <1,)---l!EE>-+---IEX!> L-lll) 5 4 AMENDMENT 27 PO'IERHOUSE UNIT 1 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT D B PR I MARY CONTA I NMENT SYSTEM A MECHAN ICAL CONTROL DIAGRAM FIGURE 5.2-20 SH 1

o~oo -t9-0L93H>-Z III tt lfw,.....,o-...,,,_..., ,r.-'"'"""_,,...,,_,, AMENDMENT 27 PO'IERHOUSE UNIT2 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRIMARY CONTA INMENT SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5. 2-20 SH 2 G 8 A

zso~ l-t9-0l93Lt-E L9 ~ ~ cc ~< - <~ o!!! .... ~ '1' I I I (Hs\\_ I 64-23A ----t ~ I I POI RI 64-22 64-23A y I I ?' 0 / / / / / / N / / w / /

e..

/ z / / / / / z / / / N / / w ' / cc U) / / / ~ / /,< I RI 64-238 i (Hs\\_ I 64-239 ----+ ~ I I l 3-47E3847-8, 83 1 0 m w ' w ' 0 w t I -+---i ~ ! ~

---

./x0i 1 164-11C Ill 64-118 Ill

"-r-" < .Ill m I I W I I r-- co I "f ~ I u, n

c I

~ ~ I ~ r- ------*-, PDM I ~ I 64-2A

• 1*

( FCO\\ I ~ 64-118 I ~~~f~ ~ I I '--ll O FANXA ! ~ 0 ~ fAN-64-118 I 1 XS _______ fas'\\ I r-- 64-12 64-12C1 'T"' ...........,.. I l'l ~ I RPS ANALOG TRIP POWER 13-47E610-99-1~-~--~ I >-47E610-99-1 >--, DIV IIA>----§> !>-47E610-99-1 >--, DIV 18 >----@v@ !>-47E610-99-1 >--, DIV IIB>----§)© ECCS ANALOG ~05 5 TRIP POWER r ~ l>-47'610-71-2>--~+-ID I L-@) riED !3-47E610-71-2>--~+~ ~ ~ N '

sl w

w ffi ix 8 f w I 9-3A 0 ,-LC.,. w iii /PDA' 8 ~~ 64-27 VI~ O~< i 3 I 6.!:3-7 w ~ I L-N,... zo.... -w - ~.... w W< w ~~ "' ~o.... WU, ' ~- " 3-47E3847-8,A4 1~3_-_45_E_6_14_-_6_~r-' 8 7 ~-,~~3_-4_5_E_6_2_D_-_3__.r---~ REACTOR f?~ESUPPL Y -' ~ m w 0 " 6 REFUELING FLOOR EXHAUST FANS r--------* I r----* 'JFf. ~ 9-25 FCO 64-9A 1 3-45E614-6 r-, ,---t\\.J\\J'l-e,. TO REFUELING I ZONE (fp,-25 HS 64-9 PA-64-58 r-<THIS DWG,DS I I X I FCO 64-10A

• ~"'

9-25 I I ~-----~ J.t-25 L!§__) 64-10 ~ t-43-45E670-27 I I I ~ ~ " ~ 0 ~ ' w U) ~ ~ ~ 0 ' DEMIN WATER i----(ID@ Jt-81 {PIS\\ 61*E-5B RI 64-58E 25-SA 9-81 PT __ jPis\\_ _____ ~---- 64-578 64-578 I ~ ~ I I 25-SA I (Pr\\_ __ jris\\:'~~~--l---- 64-570 6t::JD 5 --~ 3-45E670-26 X-27 --@)@ r----------------------------------------------------------~-----~------------------------, 3-47E3847-5,A3 PUMP MOTOR D PUMP MOTOR C ~ 64-71 w 0s\\i t 64-70 Ci MCC ~ ~ ~ ~ MCC 0s\\i ~ )';;{ 64_69 ~ IL-64-68 FS Lf-l,L.JC1.l~~64-12A 1 I r--- FSV 1 I 64-11 Ay--y'-t.J~U ~ I PUMP MOTOR 8 PUMP t.fOTORS 8 &. D ~ T ~ IL-64-72 64-73 ~ ~ I v I ~ r---------+----J Stt.., 1118 I I I I I I I I I I ~ ! FAN A I / XS \\..J F AN-64-11 A 1 64-11A T L----1 XS-64-118 ~9-25 r.;:;-'-. .L...l§..l ~---- 64-11 A ~ w ~ w ' ~ /FCO\\ 64-11A X 13-45E614-5 ~-, I r-13-45E614-6 I I 25-213 { >-_,POS ROOM 64;:3,A/C AIR 64;;:221 }*QOM AIR ~ OUTSIDE AIR 3-FAN-064-0135 MAIN STEAM VAULT EXH BOOSTER FAN (1S-64-67A,C3 9-3 9-19 Go UD 64-159 64-1608 'r' LT-64-15981 1 [E)----1 x5-6A L-.,.-J PT' [J][:J_ __ J 64-1608 ~ SEE NOTE 6 PI 64 9-82 I 3-45[670-32 ~- - --------~-pis\\ I 64-57A I ~ I X-52 I 19-82 ~- - ________ i_ft!S\\ ~ 64-57C ~ 4 25-6A ./PT'i 64-57C LIMITER N N w w ~ ~ N ~ ~ w w /FCO\\ cc cc 64-12A REACTOR ZONE EXHAUST FANS 25-222 UD 64 I ...li15.25 t------ 64-38 I ~ I 125-222 A 64-38 ~----t---1-/'Hs\\ 64-68 I 64-68 I ~----i--l/'Hs\\ 64-72 I 64-72 ~ I ~ I L--..----------------~ I 64-12A ROOM ~ I ~ A ROOM TO CORE SPRAY PUMP MOTORS A & C I 'r' I I I I I ~ I FAN 8 64-128 AIR COOLER A CLR-64-68 AIR FAN-64-68 COOLER CLR-64-72 FAN-64-72 FAN-64-12A RHR PUMP MOTOR A COOLER CORE SPRAY NW ROOM COOLER NE ROOM COOLER TYPICAL .--i91 I /, 9-25 1.... ~ II~ PUMP MOTOR COOLERS 8, C & D TYPICAL NOTES: 9-25 {FSv\\_ ___________..... _ Gs\\ 64-43 I 64-43 S 3-47E3847-7,C2 I ,. THIS CONTROL DIAGRAM COVERS PORTIONS Of THE FOLLOWING SYSTEMS: A. PRIMARY CONTAINMENT SYSTEM.

8.

SECONDARY CONTAINMENT SYSTEM. C. ATMOSPHERIC CONTROL SYSTEM. I I I I I I FCO!E------'x,,._~*~*-1!1 64-3A I L--j3-45E614-6 I D. REACTOR AND TURBINE BUILDING VENTILATION SYSTEM. THE DIAGRAM INCORPORATES THOSE CONTROL DEVICES NECESSARY FOR AIR PURGE OF THE DRYWELL, DRYWELL PRESSURE INTERLOCKS TO ENGINEERED SAFEGUARD SYSTEMS AND PROTECTION SYSTEM, REACTOR AND TURBINE BUILDING ISOLATION. AND ZONE CONTROL RELATIVE TO BUILDING PRESSURE LEVELS AND RADIATION LEVELS. REFER TO THE LOGIC DIAGRAM 47E611-64 SERIES FOR THE SPECIFIC INTERLOCK FUNCTIONS RELATIVE TO THE FOLLOWING:

2.

A. ISOLATION Of THE REFUELING ZONE AND REACTOR ZONE ON HIGH RADIATION.

8.

CONDITIONS CAUSING TRANSFER TO THE STANDBY GAS TREATMENT SYSTEM. C. D. VACUUM RELIEF FOR THE DRYWELL. INTERLOCK AND VENTILATING FOR TRIP REQUIREMENTS RELATIVE TO HIGH AND LOW (VACUUM) PRESSURE IN THE REACTOR BUILDING. E. INTERLOCK FUNCTIONS FROM DRYWELL PRESSURE SENSORS RELATIVE TO REACTOR PROTECTION SYSTEM. ENGINEERED SAFEGUARD SYSTEM, ANO AUTO SLOWDOWN SYSTEM. DRYWELL PRESSURE AND TEMPERATURE AND SUPPRESSION POOL PRESSURE, TEMPERATURE, AND LEVEL ARE RECORDED AND/OR INDICATED IN THE MAIN CONTROL ROOM. FE J--~~~~~~~~~~~--t~ 64-38 ~

@t--1 r--39:

'r.::;{_~I I.... ~ 9-25

3.

9-25 THE NORMAL REACTOR BUILDING VENTILATION CONTROL IS THROUGH POC-64-1 AND PDC-64-2 WHICH MAINTAIN THE REACTOR BUILDING AT -1/4" Of WATER PRESSURE. 1268 3 ~., 11"JC<,. I I I I I I I I ,~u-*-* -- 0 0 -- 6

• l l

4.

5.

6.

IN THE EVENT THAT VACUUM INSIDE THE REACTOR ZONE INCREASES FROM THE NORMAL (-3/8* Of WATER) PDIC-64-16 SENDS AN OPENING SIGNAL TO PDC0-&4-16 TO ALLOW OUTSIDE AIR TO ENTER THE BUILDING. IF EITHER PDS-64-62A OR POS-64-628 SENSES A POSITIVE PRESSURE GREATER THAN 1/4" Of WATER, OR IF EITHER PDS-64-62C OR PDS-64-62D SENSES A ~RESSURE MORE NEGATIVE THAN -1/4* OF WATER, THEY WILL TRIP BOTH THE ZONE SUPPLY AND EXHAUST FANS. FIELD TO CONNECT PORTABLE GAUGE AND PLANT AIR, VALVED AS NECESSARY. TO DRYWELL FLANGE EACH TIME DRYWELL HEAD IS REFITTED, TO TEST SEAL OF HEAD. PURGE AIR FILTER. CRYENCO CONTRACT 85083. I 13-45E614-5 r-i I

7.

8.

INSTRUMENT TAG NUMBERS ARE PREFIXED UNIT 3 UNLESS OTHERWISE NOTED. 2-47E610-64-1,E2 FROM HPC1 3-47E610-73-1,C2 TO FCV-84-20 3-47E610-84-1,G7 ~25 64 MACH. ROOM X ~ 4-608

9.

10.

11.

FOR REACTOR BUILDING VENTILATION AND REFUEL FLOOR RADIATION MONITORING SEE 3-47E610-90-1. THE VALVE POSITION LIGHTS COVERED BY THIS NOTE ARE LOCATED ON THE GRAPHIC DISPLAY PANEL (9-3). INDICATING LIGHTS AND HANDSWITCHES LOCATED ON 3-9-3 GRAPHIC DISPLAY PANEL.

12. UNIDS ON DRAWING ARE FOR REFERENCE ONLY AND ARE ABBREVIATED TO MEET SPACE CONSTRAINTS, REFER TO MEL FOR COMPLETE UNIDS.

SYMBOLS: OIL FILLED RESERVOIR AND LINE CONTROL AIR SUPPLY REFERENCE DRAWINGS: 0-47E800-1.........,.. FLOW DIAGRAM-GENERAL PLANT SYSTEMS 0-47E800-2............ MECHANICAL-SYMBOLS AND FLOW DIAGRAM DRAWING INDEX 47W600-SERIES......,.. INSTRUMENTS AND CONTROLS MEL...............,... INSTRUMENT TABULATIONS 47E605-SERIES......... CONTROL BOARDS 3-47E610-24-1......... CONTROL DIAGRAM-RAW CCXJLING WATER 3-47E610-76-1......,.. CONTAINMENT INERTING SYSTEM CONTROL TO REFUELING ZONE X ~---I T REST :,o.,_J ROOM I -"' DIAGRAM 3-47E844-2............ FLOW DIAGRAM-RAW COOLING WATER 3-47E3847-SERIES...... FLOW DIAGRAM-CONTROL AIR SYSTEM 0,3-47E865-SERIES..... TURBINE & REACTOR BLOG. H&V AIRFLOW ~'*---++ COMPANION DRAWINGS: 1-47E610-64-1, -2 & -3 2-47E610-64-1, -2 & -3 3-47E610-64-2 & -3 TO FCV-64-141 AND DRYWELL COMPRESSOR 3-47E610-64-2,F2 I __ J ELEVATOR SHAFT 3-47E610-85-1......... CONTROL DIAGRAM-CRD HYDRAULIC SYSTEM 3-47E610-73-1......... MECHANICAL CONTROL DIAGRAM-HPCI SYSTEM 3-47E610-84-1......... CONTROL DIAGRAM-CONTAINMENT ATtdOSPHERIC DILUTION SYSTEM 3-47E610-90-1......... CONTROL DIAGRAM-RADIATION MONITORING SYSTEM 0-47E845-2............ FLOW DIAGRAM-COMPRESSED AIR-STATION SERVICE 3-47E856-2............ FLOW DIAGRAM-DEMINERALIZED WATER SYSTEM 3-45E614-5,-6......... WIRING DIAGRAM 120V AC/250V DC VALVES AND MISCELLANEOUS SCHEMATIC DIAGRAM 3-45E614-19........... WIRING DIAGRAM 12DV AC[250V DC VALVES AND MISCELLANEOUS SCHEMATIC DIAGRAM 0-45E777-4............ WIRING DIAGRAM 480V UNIT AUXILIARY POWER SCHEMATIC DIAGRAM 3-45E777-3,-5,-6...... WIRING DIAGRAM 480V UNIT AUXILIARY POWER SCHEMATIC DIAGRAM 3-45E670-26,-27....... WIRING DIAGRAMS EMERGENCY CORE CCXJLING SYSTEM DIVISION 1 ANALOG TRIP UNITS SCHEMATIC DIAGRAM 3-45E670-32,-33....... WIRING DIAGRAMS EMERGENCY CORE COOLING SYSTEM DIVISION II ANALOG TRIP UNITS SCHEMATIC DIAGRAM 3-45E671-57........... WIRING DIAGRAMS REACTOR PROTECTIVE SYSTEM DIVISION IIA ANALOG TRIP UNITS SCHEMATIC DIAGRAMS 3-45E671-51........... WIRING DIAGRAMS REACTOR PROTECTIVE SYSTEM DIVISION IA ANALOG TRIP UNITS SCHEM DIAGRAMS. 3-45W671-63........... WIRING DIAGRAM REACTOR PROTECTIVE SYSTEM DIVISION II 8 ANALOG TRIP UNITS SCHEMATIC DIAGRAMS 3-45E671-69........... WIRING DIAGRAM REACTOR PROTECTIVE SYSTEM DIVISION II 8 ANALOG TRIP UNITS SCHEMATIC DIAGRAMS 3-45E779-16........... WIRING DIAGRAM 480V SHUTDOWN AUXILIARY POWER SCHEMATIC DIAGRAM 3-45E777-21.,......... 480V WIRING DIAGRAM AUX POWER SCHEMATIC DIAGRAM 3-45E620-8.-10........ KEY DIAGRAM ANNUNCIATOR SYSTEM 3-47E812-1............ FLOW DIAGRAM HIGH PRESSURE COOLANT INJECTION SYSTEM 3-47E865-12..,........ FLOW DIAGRAM HEATING & VENTILATING GE DRAWINGS: AIR HOW 21A1053............ GENERAL REQUIREMENTS FOR VACUUM BREAKERS 21A1363............ PRIMARY CONTAINMENT VENT, BUTTERFLY VALVES 22A1132AE.......... CONTAINMENT ISOLATION SYSTEM 22A1169..,......... DESIGN SPECIFICATION FOR REACTOR CONTAINMENT 3-730E927-17....... PRIMARY CONTROL ISOLATION SYSTEM 3-730E927-16....... PRIMARY CONTAINMENT ISOLATION SYSTEM AMENDMENT 28 POWERHOUSE UNIT 3 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT CONTAINMENT SYSTEM PRIMARY MECHANICAL CONTROL DIAGRAM FIGURE 5.2-2a SH 3 H G F E D C B A

.--------------------r---- -,:-* I ~- m;.l!':r........ 8 AMENDMENT 22 UNIT ! BROWNS FERRY NUCLEAR PLANT f INAL SAFETY ANALYSIS REPORT H C F 0 C B PRIMARY CONTAINMENT SYSTEM A ME CHAN [CAL CONTROL DI AC RAM f'JGURE 5. 2-2b

8 5 I 1, -------0~=-~--~rf";!'; - oc,...... im i ~~

• "'.. ~*

I i: -~ 1, ~.* I: ___ J l.......... **** E'.:::-'. ___ c.:c--1 no\\~ 13.) ~ 4? 4? -'l- *.,. ~, I l ___ _ 3 H G C B

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• ~

8':-r:------+-----1 li!il ~f ~:t-~:--~~i:.._--_.___-----:!'_--j ~* 1 ! i = ---f ,--------'----* --1~r* I i Hru,--,.~ I 7 -ri*- o-----... --. AMENDMENT 17 UNIT ) BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRl lilARY CONTAINMENT SYSTEU I.IECHANICAL CONTROL DIAGRAM FIGURE 5,2-2d H G F E D C B A

8 lD~ £-t9-0 !93Lt-£ ~ LS DIVISION I r TORUS PENETRATION (TYP) ~7 x-23;;_1;~ 6~:161,-T-~,--r---.:..,----r-------------, r----------j 9-81 L_ @.,.-, ~ I X-2348 TW TE I 8 1 6+-1*1 64-161.--T-~.---r--- 9-871 --- 1 --- 9-87 ------, : 9-3 j_ __________ j 9-87 L_ @61s~ +-- ©61J I r--1--- @61

x-234C rw r, --T-~--r _____ 1 ___ J_ __ 1-------, i 11 i1 s+-1s1 s+-161c

~c 9-87 I I +-I _,1 L ~,...J I I I I L __ 1_.£HNL__! ___ l 9-87 -~c I I I I L---1-CHN.b..L_-,

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---

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TR r---------- 9-87 ~DI 64-161L ~ CHNL 5 64-161 X-234E -@fr, I _r------1----_.... I o+-1i~ 5~'..151,-T-.~~1s1.--r--- 9-81 I ----r-- I---- ,-----I-~~~~~-.// I I I L ~_j I I I r---1-ciiNcs _ _, f-;_234r _______ _, 9-87 -~,-, I I I I,-:-------J 9-87 1 rw r, __ T _ _;,:;;;sc __ r----- 1 ----1---- 1 ______ _J 1 1 64-161f 64-161f ~f 9-87 I I ~-87 I I t------ 64-161M I I L ~,...J TM I I t------------' 9_87 -~r I +-- 64-161K I I I I X-2J4G TW TE ~ I I l ~87 64-161 64-1610-T-~"-t- @-87 :----r----------_J : r1 -----~,l r-----------' 64-161G; I I I X-234H -@fr,9-87 I I 9-87 I TW TE --T-TM --r----- I ___ _j _____________ _J L ~ -t I 64-161 64-161H 64-161H 9-87

---

~K 3-45E664-3 ~!-----------J L_ @.,Rf--------------------,

I ~7J DIVISION II 24VDC POWER SUPPLY FOR ALL - 161 LOOP INSTRUMENTS r----- 1 I I I t------ TS 64-162K SUPPRESSION POOL AVERAGE TEMPERATURE REFLASH: HI HI-HI HI-HI-HI I 9-88 t------ @62M ~13_-_4s_,_._.4_-_3_._._1o~~r----------, I 9-88 8 I X-2:55A TW TE ~ 1 64-162 64-1s2,-~-~,--r---.:.8a----r-------------, I -----------, L-~n I I r 9-88 ~A I I i x-2358 rw r, --.l.-~--r----- i1 ----'------------, i I 64-102 64-1 2s ~* 9-88 I 9_88 I 1------------, L_~_j t--~ II I I s-aa ~el I y s2J i x-23sc rw r, --.l.-~--r _____ 1 ___ _._ __ 1-------, i i1 1 64-162 64-162c ~c 9_881 1 L_ @bc..J 11 11 IL L_ I X-235D ~ 9-88 I 1 TW TE __ j__ TM --r----- 1---_J 1 _ I-----, L ___ _ 64-162D 64-162D 64-162D 9-88 I ~88 t------------, 9-88 L_ @2DT ____ J ~i:"'--------- 1 x-23s, rw r, --.l.-~--r----- 11 -----.--- i ____ _r----- 1 64-162 64-162E ~E 9-88 I 1------------, L _ _/rs'\\___"_J I I I 1r-- l 9-88 ~,-, I I I 1 i x-23sr rw r, --.l.-~--r----- i ----1---- i ______ _J i i 64-162r 64-162r ~r 9-88 I I ~-88 I I I -@9-3 j_ ___ - TI I r-64-102 I I I II L ______ J:J][:J ~ I I I I CHNL 1 -I-CHNL2----, =I CHNL 3,-\\ I _ 1_£!!~.!.--~-3 _j CHNL 9 TR CHNL 5 -=:.. 64-162 - -.£HJ:!1....!! -./ / __ gj,NJ...Z.._~ I __ CHNL 8 ___ J ~-----------, 9-88 L_ @62r-t +-I -~62K II I X-235G TW r, , _fn.t'C a-3 I 64-102 64-1620-+-~c-r---.:.88 :----,-.----------_J I r-----~*2* SUPPRESSION POOL SINGLE ELEMENT HI OR ELEMENT FAILURE L-----------, L_~,.... II II II 9-88 ~G 1 X-235H TW TE __ j_ _ _!n.t'C __ T _____ 11 ___ _j _____________ _J I 64-162 64-162H ~H 9-88 I L-@v62sf-------------------J I @:8J 24VDC POWER SUPPLY FOR All - 162 LOOP INSTRUMENTS SUPPRESSION POOL TEMPERATURE MONITORING SYSTEM 3-47E3847-10 FROM SHV-32-270+ 3-47E3847-10 FROM SHV-32-2703 7 6 5 r-----------------------------------------1 1 3 @ 6 @ 5 @ 4 7 @ 8 @ 2 @ 3 @ 9 @ 0 (TE\\ ~5 (TE\\ ~7 (TE\\ ~* (TE\\ ~8 (TE\\ ~6 El. 653'-6" EL. 625'-0" 4 EL. 584'-0" El. 562'-0" PRIMARY CONTAINMENT L-----------~--

---

~

"""---- SEE NOTE 4 INTEGRATED LEAK RATE TEST ELEMENTS (SEE 0-47W600-122 FOR GENERAL PLANT LOCATIONS) HCVS PIPE 1 -----r--i 3-45E614-6f-l I I I I I )-.(<or, 1 o I ~A I ~ A 64-222 y ~-4 ~:TE 10 El 741 '-s* -, (n\\9-3 64-60 y ~NL-925-236 64-60 y 1...!iOTES 5.t. 6 I --, ~~ 64-SOA 64-608 rev __ x 6+~ " ~--ili~o-;,~;------~ r-----r-i 3-45E614-51 I I I I I I I I ~ ~ I NOTE 10 I ~ ~ I I ~ :l. I ~-4 Y A ~ ~~ L--~

• ~1/222

>a<-, FSV "' O ~......, 64-221 E ~:TE 10 S 1-...-t.,,._. FCV -- X 64-221 If ~--ili~o-;,~;------~ 3-47E610-64-1,C6 DET 3A3 UNIT 3 HARDENED CONTAINMENT VENT (3-47E610-64-1) 3 EL 666.5' r-lf----ABANDONED IN PLACE COMPANION DRAWINGS: 1-47E610-64-1, -2.t. -3 2-47E610-64-1, -2.t. -3 J-47E610-64-1.t. -2 NOTES:

1. FOR GENERAL NOTES AND REFERENCE DRAWINGS SEE 3-47E610-64-1.

2. ALL INSTRUMENT TAG NUMBERS FOR DIVISION I ARE 161 AND DIVISION II ARE 162

3. DELETED

4. TEMPERATURE ELEMENTS UTILIZED FOR LEAK TESTING DATA ARE INSTALLED IN THE PLANT AND ARE NORMALLY NOT ELECTRICALLY CONNECTED. THESE TE, WILL BE CONNECTED TO PORTABLE INSTRUMENTATION AS NECESSARY FOR LEAK RATE OR MISCELLANEOUS TESTING.

5. STRAP ON T/C DUAL ELEMENT TEMPERATURE SENSOR.

6. TIC-64-60 ONLY RECEIVES INPUT FROM TE-64-60A. CABLE FROM TE-64-608 JS SPARED AND ISOLATED IN LPNL-925-236.

REFERENCE DRAWINGS: J-45E614-21..... RECORDER SCHEMATIC DIAGRAM J-45E664-3...... WIRING DIAGRAM - TORUS TEMPERATURE MONITORING SYSTEM SCHEMATIC DIAGRAM SH-3 3-45E3690-41.... ICS BLOCK DIAGRAM 0-47W600-122.... MECHANICAL INSTRUMENTS AND CONTROLS 3-791E490-2..... PNL J-9-3 CONNECTION DIAGRAM BAILEY CONTROLS Co.lPANY - TVA CONTRACT 82PJ3-830911: 0566641.... ANALOG L~IC 08083601,.. CABINET ARRANGEMENT 08083602... SCHEMATIC 08083603... SCHEMATIC 0808360+... POWER DISTRIBUTION 08083605... EXTERNAL CONNECTION DIAGRAM 08083606... EXTERNAL CONNECTION DIAGRAM E3053355... CABINET ASSEMBLY ARRANGEMENT AMENDMENT POWERHOUSE UNIT 3 28 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRIMARY CONTAINMENT SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5.2-2e H G F E D C B A

POWERHOUSE UNIT 1 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRIMARY CONTAINMENT SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5.2-2f

G D C B 8 5 3

BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT Types of Penetrations for Process Lines FIGURE 5.2-3

\\ \\.. 't, "I, t I &~~ ,~

• A** -,' 1\\1
• .'~.~ A 1 6...,z~-

~ I I f ...., '-"-..:.~.... *-*--_;.'..;;*;..:*_'.;:._,,;;.~~----~.: . J~,,,p;,* fJ,...,

• I

~ ,,A*w,.,, ' ~:..; iMENDMENT 16 y Bi~:tMsr FERRY NUCLEAR,p LAH T FIIIIA_I.. SAFETY ANALYSIS REPORT

- ~-*x.

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BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT Compression Fitting Assembly for Small, Low Pressure Line Penetrations FIGURE 5.2-4a

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BFN-28 Figures 5.2-5b through 5.2-5e Deleted

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AMENDMENT 27 PO'IERHOUSE.I. YARO UNITS1,1,0 BROWNS FERRY NUCLEAR PL ANT FINAL SAFETY ANALYS I S REPORT D C 8 CONTAI NMENT I NERTING SYSTEM A MECHANICAL CONTROL DI AGRAM FIGURE 5. 2-60 SH 1

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AMENDMENT 25 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT CONHINMENT INERTINGSYSTEM MECHANICALCONTROLOIAGRAM

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AMENDMENT 25 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRIMARY CONTAINMENT COOLING TEMPERATURE MONITORING MECHANICAL CONTROL DIAGRAM FIGURE 5.2-Sb

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..,. 1-oe-Ol93Lt-~ l'I LS I AMENDMENT 25 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT PRIMARY CONTAINMENT A TEMPERATURE MONITORING SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5.2-6d

BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT Drywell Pipe Whip Projection Figure No. 5.2-6e SECURITY RELATED INFORMATION FIGURE WITHHELD UNDER 10 CFR 2.390

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POWERHOUSE UNITS 1 & 0 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT CONTAINMENT ATMOSPHERE DILUTION SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5.2-8 SH 1

POWERHOUSE & YARD UNIT 2 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT CONTAINMENT ATMOSPHERE DILUTION SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5.2-8 SH 2

POWERHOUSE & YARD UNIT 3 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT CONTAINMENT ATMOSPHERE DILUTION SYSTEM MECHANICAL CONTROL DIAGRAM FIGURE 5.2-8 SH 3

BFN-16 Figures 5.2-9 through 5.2-10 Deleted

BFN-18 Figure 5.2-11 (Deleted by Amendment 17)

BFN-16 Figure 5.2-12 Deleted

BFN-28 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT HYDROGEN AND OXYGEN CONCENTRATIONS IN CONTAINMENT FOLLOWING LOCA WITHOUT NITROGEN INJECTION (SAFETY GUIDE 7 ASSUMPTIONS, ATRIUM-10 FUEL, NO CONTAINMENT LEAKAGE, 3952 MWt) FIGURE 5.2-13

BFN-28 Figure 5.2-13a Deleted by Amendment 28

BFN-28     BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT HYDROGEN AND OXYGEN CONCENTRATIONS IN DRYWELL FOLLOWING LOCA WITHOUT NITROGEN INJECTION (SAFETY GUIDE 7 ASSUMPTIONS, ATRIUM-10 FUEL, NO CONTAINMENT LEAKAGE, 3952 MWt) FIGURE 5.2-14

BFN-28 Figure 5.2-14a Deleted by Amendment 28

BFN-28 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT HYDROGEN AND OXYGEN CONCENTRATIONS IN PRESSURE SUPPRESSION CHAMBER FOLLOWING LOCA WITH NITROGEN INJECTION (SAFETY GUIDE 7 ASSUMPTIONS, ATRIUM-10 FUEL, NO CONTAINMENT LEAKAGE, 3952 MWt) FIGURE 5.2-15

BFN-28 Figure 5.2-15a Deleted by Amendment 28   

BFN-28     BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT MAXIMUM NITROGEN REQUIRED FOR DILUTION, SGF AT 20 DEGREES C AND 1 ATM (SAFETY GUIDE 7 ASSUMPTIONS, ATRIUM-10 FUEL, NO CONTAINMENT LEAKAGE, 3952 MWt) FIGURE 5.2-16

BFN-28 Figure 5.2-16a Deleted by Amendment 28 

BFN-28 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT MAXIMUM CONTAINMENT PRESSURE FOLLOWING LOCA WITH NITROGEN INJECTION (SAFETY GUIDE 7 ASSUMPTIONS, ATRIUM-10 FUEL, NO CONTAINMENT LEAKAGE, 3952 MWt) FIGURE 5.2-17

BFN-28 Figure 5.2-17a Deleted by Amendment 28

BFN-17 Figure 5.2-18 (Deleted by Amendment 17)

EL 580.Q EL 565.0 El519.0 El..639.0 .. ~' """',.._.._ PERSONNEL ELEVATION ACCESS ROOM ROOF OPENINGS AREtfiQR VALVE OPERATORS. MINIMUM FLOW ARE~ i, l()iSQ. FT. 10.!i"R DETAIL A, ( PLAN Vlf;,W~) (L 510) *., 10.511 R AMENDMENT 16 .BRQINNS FER~tJ~11¢t;EAR PLANT FINAL SAFETf,i.NAl.,"VSIS REPORT '

~ I fJ 200 6 a ~ 1mmm1umu STAIRWAYS .*~ 1.. 113'-*" FLOOR PLAN EL 565.0 FLOOR QPENINGS SLEEVE OD ID °"OFH.lt<IQ'ttlRU-llEEVI INCl<UOINO"INSULATION FLOW AREA AMENDMENT 16 (INJ UN.I (INJ (FT.21 1 38 31i.&7 21 3.6 2 31 36.17 29 2.3 3 38 311.17 21 2.3 4 24 23.81 U, 1.316 ....!:L Oii-..ctl1111 Fl-Pat!,1 Th,ou_. Penollllll Aca11flloam TOTAL 11.1 FIGURE 5~;.20

PLAN EL. 519 _*%] AMENDMENT 16 ,tiV l4UCLEAR '!\\.ANT ' / ANALYSIS REPORT. ci-,;~~ flow Path 11mMii'! '. ~ norinll AaNtl Room : FIGURE 6.2-21 . {t.

BFN-16 Figure 5.2-22, Sheets 1, 2, and 3 Deleted by Amendment 15.

BFN-27 5.3-1 5.3 SECONDARY CONTAINMENT SYSTEM 5.3.1 Safety Objective The safety objective of the Secondary Containment System is to limit the release of radioactivity to the environs after an accident so that the resulting exposures are kept to a practical minimum and are within the guideline values given in published regulations (10 CFR 20 and 10 CFR 50.67 as applicable). 5.3.2 Safety Design Basis The Secondary Containment System provides secondary containment when the primary containments are intact. In the event of release of radioactivity to the Reactor Building atmosphere, the Secondary Containment System contains the necessary reliable, redundant components and subsystems to isolate, to contain, and to assure controlled filtered elevated release of Secondary Containment Building atmosphere. The Secondary Containment System can provide primary containment when any of the three Primary Containment Systems are open such as during refueling (MODE 5) and maintenance operations. During normal operation and when isolated, the secondary containment is maintained at a negative pressure relative to the building exterior. When isolated, the secondary containment atmosphere is filtered by the Standby Gas Treatment System and released from the plant stack. Provision is made for removal of decay heat from activity deposited on filters. The secondary containment inleakage rate is less than the SGTS capacity when the building is subjected to an internal negative pressure of 0.25 inch of water. Wind conditions are considered. The Reactor Building superstructure siding is designed to withstand internal pressure in excess of 57.6 lb/ft2 without structural failure. Pressures in excess of 50 lb/ft2 will be relieved by blowoff panels in the siding. The above-grade exterior concrete walls are designed for pressures up to 250 lb/ft2 without structural failure. The roof is designed for 50 lb/ft2 live load and 25 lb/ft2 dead load. The roof internal pressure design goal is 5-inches water gauge1 (see page III-145 of Reference 1). The loads from fans, ducts, and tanks are carried directly to the building steel and do not load the deck.

BFN-27 5.3-2 The tornado design basis is a pressure decrease of 3 psi at a rate of 0.6 psi per second. (See Question 2.1 of Amendment 2 of the Browns Ferry Unit 3 Design and Analysis Report.) The Reactor Building and the Standby Gas Treatment Building are Class I structures. The Standby Gas Treatment System (SGTS) and Secondary Containment System are designed as Class I systems except for the penetrations through the secondary containment membrane and SGTS drains. These penetrations are designed to limit the inleakage flow in order to maintain a negative pressure inside secondary containment following a Design Basis Earthquake. SGTS drains have been designed to meet Seismic Class II pressure retention requirements. The operation of the Secondary Containment System is independent of offsite power and normal generation system capacity. The individual components and subsystems which receive a signal to isolate secondary containment and for operation of standby gas treatment are testable during normal operation of the nuclear systems. The Standby Gas Treatment System and associated ventilation system active components are designed to the single-failure criteria for engineered safeguards. Air cooling units provide for the removal of heat from equipment and piping losses from RHR, Core Spray, and RCIC Systems. 5.3.3 Secondary Containment System Description 5.3.3.1 General The Reactor Building exterior walls, roof, floor, penetrations, and qualified membrane extensions form the secondary containment membrane. The Raw Cooling Water discharge lines from each unit are seismically qualified pressure boundary extensions from the Reactor Building penetration out to the point underground where the steel discharge lines join clay pipe in the yard. During refueling/maintenance activities (ex., OB MSIV, FW check valve maintenance) when secondary containment is required, secondary containment membrane may be extended to analyzed boundaries. The Primary Containment Systems and essentially all of the Emergency Core Cooling Systems for the three reactors are located inside the bounds of the Secondary Containment System. The Reactor Building substructure consists of poured-in-place reinforced concrete exterior walls that extend up to the refueling floor. The refueling room floor is also made of reinforced poured-in-place concrete. The superstructure of the Reactor Building above the refueling floor is a

BFN-27 5.3-3 structural steel frame. This frame supports the roof decking and the overhead crane tracks, as well as the foamwall stepped fascia panels and the insulated metal siding panels. The built-up roof, the stepped fascia panels, and the metal siding form the secondary containment membrane above the refueling floor. The reinforced concrete exterior walls and the structural steel for the superstructure will withstand the design basis tornado. (See paragraph 12.2.2 for tornado considerations and missile protection.) The superstructure siding is assumed to be removed in the design basis tornado. However, the superstructure design is adequate in the event the siding is not removed because (a) the blowout panels will prevent excessive pressure differentials, and (b) the structural steel frame is designed for the full-wind load with all of the siding in place. For a major steam line rupture, the excess pressure would be relieved through blowout panels. Small ruptures would probably be contained in the Reactor Building without relieving the blowout panels. Large blowout panels are located in the main steam valve room of each unit. This prevents overpressurization of the Reactor Building for a main steam line rupture between the second isolation valve and the secondary containment wall. For steam line failures in the Reactor Building, but outside the drywell and outside the main steam valve room, the pressure would be relieved to the refueling room by the hatches and hatchways. The pressure within would then be relieved to the large blowout panels in the insulated metal siding. Secondary containment is isolated and operation of the Standby Gas Treatment System (SGTS) initiated by low reactor water level, high drywell pressure, high radiation in a Reactor Building ventilation system, or a manual signal from the Main Control Room. Subsection 5.3.3.2 describes the sequence and logic for isolation of the secondary containment system. Subsection 7.3, "Primary Containment and Reactor Vessel Isolation Control System," describes the actuation signals for the secondary containment isolation and startup of standby gas treatment. The Units 1, 2, and 3 air dilution ducts, the Units 2 and 3 air dilution duct cross connects to SGTS, the cubicle exhaust duct, the steam packing exhaust duct and the cubicle and steam packing exhaust bypasses are automatically isolated from the stack and SGTS by redundant, safety-related, backdraft dampers which shut on backdraft or no flow. The use of these dampers limit the amount of a ground-level radioactive release during Design Basis Accidents which use SGTS to mitigate the radiological consequences of these Design Basis Accidents. Subsection 14.6, 'Analysis of Design Basis Accidents', evaluates the radiological consequences of design basis accidents.

BFN-27 5.3-4 5.3.3.2 Zone Ventilation System The Reactor Building is divided into four ventilation zones which may be isolated independently. The refueling room which is common to the three units forms the refueling zone. The individual units below the refueling floor form the three reactor zones. The four-zone ventilation control system provides increased capability for localizing the consequences of an accident or radioactive release such that the effect may be localized in one zone while maintaining the ability to isolate the entire Reactor Building if necessary. With one or more zones isolated, normal operations may be continued in the unaffected zones. If radiation is detected in an unisolated zone, that zone too would isolate and the entire Reactor Building would still meet the requirements of secondary containment by assuring filtered elevated release. The zone system is not an engineered safeguard, and the failure of the zone system would not in any way prevent isolation or reduce the capacity of the Secondary Containment System. A reactor zone is isolated upon isolation of the primary containment in that particular zone, by high radiation level in the ventilation exhaust duct leaving that particular zone, or by manual alignment. The refueling zone is always isolated when any reactor zone is isolated. The refueling zone only is isolated by a manual signal or by a high radiation signal from any of the six radiation monitors that serve the refueling zone (see FSAR Section 7.12.5). Upon isolation, all of the ventilation systems serving the isolated zone or zones are shut down, the ducts are isolated, and the Standby Gas Treatment System is started and begins exhausting from the isolated zone or zones. 5.3.3.3 Reactor Building Description The Reactor Building is built on bedrock. A description of the underlying rock formation is found in Subsection 2.5, "Geology and Seismology." The structural design basis of the reinforced concrete walls, the refueling floor, and the steel superstructure framing are discussed in Subsection 12.2, "Principal Structures and Foundations." The Reactor Building roof consists of a metal deck, insulation, and built-up composition roofing. The deck is made of 18-gauge 3-inch-deep galvanized steel deck. The deck is formed from U.S. Standard gauge structural quality steel that conforms to ASTM Specification A 245. The metal roof deck is covered with a 2-inch-thick layer of rigid insulation. Just prior to installing the insulation, the deck will receive a vapor barrier consisting of a vapor barrier felt and steep asphalt. The insulation is secured to the deck with hot asphalt. The insulation is covered with a single ply asphalt base felt which is in turn covered with a 4 ply felt, fiberglass roof insulation, 3 plys of fiberglass felt, and is topped with a modified bitumen roof membrane which has an aluminum roof coating on its top. Special

BFN-27 5.3-5 attention is given to the joints where the built-up portion joins the parapet and penetrations to assure a permanent leak-tight installation. The siding panels form the secondary containment wall membrane on the superstructure. The vertical panels are made up of 18-gauge galvanized steel, insulated panels 12-inches wide and 1-1/2-inches thick faced with aluminum V-beam sheets. The steel panels are joined on the edges with 1-1/2-inch deep interlocking male and female ribs. The female rib is factory-caulked with a resilient caulking compound. A finned vinyl weatherstrip gasket is secured to the male leg with double-sided, pressure-sensitive tape. The male-female joint is then drawn up tight in place and locked by button-punching on 4-foot centers. A full 1/4-inch resilient caulk bead is laid along the downturned sides of the female joints. This provides a triple seal. The ends of the vertical insulated panels are sealed with a double row of pressure-sensitive tape laid side by side with the fasteners passing between the two rows of tape. Each stainless steel fastener is individually sealed. The exposed joint edges are continuously caulked. The stepped fascia and accent panels are made of foamwall panels. The foamwall panels are made from urethane foam sheets bonded between 0.04-inch thick aluminum sheathing. All joints at the end of the panels are sealed with metal batten strips. The battens are double-sealed to the aluminum sheath with pressure-sensitive tape. The inner batten is attached to the outer batten with sheet metal screws. The corner joints at the steps are either tongue-and-groove or flashed. The tongue-and-groove joints are formed on the ends of the foamwalled panels. The tongue-and-groove joints are triple-sealed. The inner joint and the tongue joint are sealed with pressure-sensitive tape. The outside joint is caulked. The flashed joints are sealed with double rows of pressure-sensitive tape with the fasteners placed between the rows of tape. 5.3.3.4 Relief Panels Excessive pressure differentials due to steam line ruptures and tornadoes are prevented by venting to the atmosphere through relief panels. Two sets of relief panels and a flow limiter prevent the overpressurization of the Secondary Containment System. These consist of the main steam relief panels, the exterior siding panels and the HPCI flow limiter. Main steam ruptures would be vented to the Turbine Building through main steam relief panels. The exterior siding panels vent the refueling room to the atmosphere. The zonal relief panels were removed to form the combined zone secondary containment system. Steam line ruptures other than main steam ruptures, and excess air vents during a tornado depressurization vent to the refueling floor. The combined zone configuration allows free flow of each reactor zone atmosphere with the common refuel zone atmosphere.

BFN-27 5.3-6 The portion of each main steam vault inside the Secondary Containment System is separated from the main steam tunnel in the turbine bay by large blowout panels made of several sections. These panels have an unobstructed area of approximately 360 square feet and are designed to relieve at 90 lb/ft2. For large ruptures in the main steam vault the panels would relieve the steam and the steam would flow to the Turbine Building through a second set of relief panels, around the turbine foundation openings into the Turbine Building, and then to the atmosphere. The relief panels are held in place with necked aluminum rupture bolts. The panel sections are made of 10-gauge sheet metal, and the panel edges are sealed to the building steel. The panels are chained on one side to assure that the panels cannot collect on obstructions downstream, thereby blocking the flow area. The steam vault is designed to withstand an internal pressure of 1440 lb/ft2. The biological shield penetrations from the drywell are sealed to prevent high external pressure on the drywell. The remainder of the vault is not leaktight, and some steam would leak to the Reactor Building through the access door and through ventilation penetrations. Steam releases into the tunnel are detected by temperature sensors. When these sensors detect a high temperature condition in the steam tunnel, they initiate main steam line isolation but not RCIC isolation. If the break is in the 40 feet of RCIC steam piping traversing this area, the RCIC high-flow sensors are the only automatic sensors providing protection for RCIC breaks in the tunnel. (There are no RCIC temperature sensors located in the tunnel.) A RCIC steam line break that discharges less than 3 times the RCIC rated flow does not actuate the RCIC isolation valves; therefore, the steam pressure increases in the tunnel unless the operator responds to the emergency and manually isolates the RCIC. Radiation detectors in the reactor zone ventilation exhaust will sense the leak and will isolate that unit's reactor zone and the refueling zone. Lack of operator action permits the pressure to increase until the steam is eventually relieved through the tunnel blowout panels into the Turbine Building. Continuation of the blowdown causes venting of steam from the Turbine Building; however, steam leaks without liquid release produce insignificant radiological doses. A high radiation level will be detected by the turbine area radiation monitoring instrumentation and will annunciate in the control room; thus, the operator would be alerted to examine his information display. An indication of RCIC steam flow without a concurrent reactor low water level, but with high tunnel temperature and with main steam line isolation, would be indicative of a RCIC steam line break in the tunnel area. The operator could then isolate RCIC (a very important system but not designated as a Emergency Core Cooling System), or he could dispatch someone to the Turbine Building to perform a survey. The operator's examination could take as long as 10 minutes before he deduces that the RCIC steam line probably has ruptured and manually isolates the RCIC steam line. The offsite doses for an undetected 300 percent RCIC steam leak in the tunnel that continues for this long (10 minutes) are less than 1 percent of the TEDE 10 CFR 50.67

BFN-27 5.3-7 guideline values. (These dose calculations were made using the methods and assumptions discussed in Chapter 14 of the FSAR.) Each HPCI turbine steam supply line contains a flow limiter which limits the flow to approximately three times the maximum required for the HPCI turbine. With this flow limiter, a rupture of the HPCI steam supply line or any other line relieving steam to the secondary containment would relieve to the zone containing the rupture. All of the zones were connected to the refueling floor with relief panels that were designed to relieve at 36 lb/ft2. The elevator shafts in the Reactor Building are not in any of the four zones. In the event of a tornado depressurization, the elevator shafts would relieve to the refueling floor through relief panels of 25-square feet each. Each new fuel vault is vented to the refueling zone through an 8-inch diameter vent pipe. BFN now utilizes a combined zone secondary containment which opens the Units 1, 2, and 3 reactor zones to the refueling zone during operation. The combined zone is created by removing the refuel floor equipment hatch covers which are equipped with blowout panels at El. 664 on Units 2 and 3 and the Unit 1 secondary containment equipment access shaft removable panels at El. 565, 593, 621, and 639. This configuration allows the total secondary containment in-leakage limits to be distributed into any of the four secondary containment zones. The exterior siding relief panels are located on the north and south walls of the refueling room floor. The total panel area is 3200 square feet. This is equally distributed on the north and south walls. These 1600 square feet on each wall are divided equally along the three units even though they join a common room. The joints in the blowout panel are similar to the other joints in the vertical insulated siding except they are not button punched. The panels are held in place with necked aluminum rupture bolts. 5.3.3.5 Locks and Penetration All entrances and exits to and from the Reactor Building are through personnel and equipment locks. These locks are shown on Figures 1.6-2, 1.6-3 sheets 1 and 2, 1.6-5, 1.6-6, 1.6-11, 1.6-12, and 1.6-13. Two personnel locks in the north wall of the Reactor Building at EL. 565 lead to the Reactor Building from EL. 565 of the Turbine Building. One lock leads to either Unit 1 or Unit 2, the second personnel lock leads to either Unit 2 or Unit 3. These two personnel locks are the normal access to the Reactor Building. Two personnel locks at El. 565 extended through the south wall of the Reactor Building and to the outside by passing under the berm. They will be used when equipment or fuel is being passed through the large equipment lock. There are six personnel locks between the control bay and the Reactor Building at El. 621.25 and El. 593. These provide emergency exits

BFN-27 5.3-8 from the control bay and emergency access from the Reactor Building to the shutdown board rooms. Small equipment locks serve Unit 2 and Unit 3 and lead to EL. 565 of the Turbine Building. Two personnel locks on the north side of the refueling floor (EL. 664) lead to the stairs for access to the Reactor Building roof and the control bay roof. The personnel and small equipment lock doors have locking devices powered from the 120-V AC Plant Preferred Electrical System. When one door is open, the locking devices will be engaged, which prevents the other door from being opened. The doors are also interlocked with a Main Control Room alarm which annunciates in the highly unlikely event that both doors are opened simultaneously. The doors for the personnel locks and the two small equipment locks are weather stripped to reduce infiltration. The six emergency access locks require a magnetically coded card-key access control system, or on failure of the individual card readers, the door latches will be left open. Both failures will be annunciated in the Unit 1 Main Control Room and action initiated to secure the doors with a key-operated deadbolt. For personnel access locks and the equipment access locks construction and loads information. (See FSAR Section 12.2.2.1.6.) After initial installation, all doors will be tested for operation of hinges, latches, and keylocks. Doors and locking mechanisms are to be inspected periodically for free operation and interlock functions. These inspections include an examination of the frame sealant to determine if cracks are developing and only normal deterioration is taking place. Also included in the inspection program is the weather stripping which is evaluated for fit and deterioration. New and spent fuel and other items enter and leave the Reactor Building through a large equipment lock located in the south wall of Unit 1 at EL. 565. The large motor-operated double doors at each end of the large equipment lock are fitted with inflatable pneumatic seals. The air to operate the inflatable seals is supplied from two independent air receivers, one for each set of door seals, that are supplied from the Control Air System. Two check valves in series on the receivers control air supply lines prevent depressurizing the system upon loss of control air. The receiver capacity is adequate to inflate the seals twice and maintain the seal including system leakage for at least 30 days of operation without makeup from the Control Air System. The 30 day duration is based on minimizing secondary containment membrane leakage so that overall post-accident releases to the environment do not exceed those assumed for control room and offsite calculated 30 day doses. The air system is designed so that the system leakage rate may be determined with the seals inflated to assure that the receiver capacity is adequate to supply inflation air for a minimum of 30 days. Low pressure in the seals on both sets of doors can occur only when low pressure occurs in the system. Loss of seal pressure is annunciated in the Main Control

BFN-27 5.3-9 Room. The doors are interlocked to ensure secondary containment integrity. The doors and the air system are designed for the maximum earthquake loads. A sub-door is installed in one leaf of each of the inner and outer equipment access doors. The sub-door is used to provide an alternate method of egress/ingress of equipment during construction and maintenance activities. The sub-doors are so designed that, when used, no additional loading of the large equipment access doors will occur. This is accomplished with a removable ramp design. A fork lift vehicle with a capacity of 15,000 lbs. is able to pass over the access lock door threshold without putting loads on the access door frame, hinges, or seal. The sub-doors and equipment access lock doors are mechanically interlocked such that no two doors may be opened at a given time. The mechanical interlocking system is designed utilizing four keyed alike, key retaining padlocks. One key will be available for use and administratively controlled. The key is retained within the lock until the door is closed and secure. The local control panel to each access lock door and both the inner and outer sub-doors will be interlocked using this method. Each sub-door is equipped with a (non-inflatable) mechanical seal. The design function of each sub-door is consistent with that of the access lock doors and will provide containment integrity functions. The sub-doors are an element of the access lock doors and when not in use become a functional component of the equipment access lock doors. Significant Condition Report (SCR) BFNNEB 8601 Revision 1 documented a discrepancy between Section 5.3, Appendix F and the secondary containment piping penetration configurations installed in the plant. The discrepancy identified was a difference between the plant configuration and the FSAR. Section 5.3 and Appendix F identified the secondary containment piping penetrations as Seismic Class I while the actual configurations did not always appear to be Seismic Class I. To resolve this SCR, analysis of the existing secondary containment penetrations was performed by EQE Engineering, Inc. to determine the potential for a pipe break on both sides of the secondary containment boundary. Such a break would result in an increase in the air leakage rate into secondary containment. This evaluation2, dated October 12, 1988, documents that although class I design requirements were not necessarily met, the secondary containment piping does meet Seismic Class II pressure retention requirements such that there is no credible likelihood of pipe breaks which would result in leakage area increases into the secondary containment volume for systems existing prior to this date. Any piping systems which are installed after October 12, 1988, are required to satisfy the isolation requirements given in the following paragraphs. Secondary containment piping penetrations can be divided into two groups. The first group covers penetrations for systems that are open in the secondary containment and open to the outside environment. These penetrations contain

BFN-27 5.3-10 double isolation valves. The section of pipe or duct from the secondary containment through the second isolation valve is designed to withstand the maximum earthquake. The isolating valves in this group close automatically by zone upon secondary containment isolation, or they may be operated manually from the Main Control Room. The valves have position-indicating lights in the Main Control Room. The second group covers penetrations for systems that do not open into the secondary containment. These closed systems that are designed for the maximum earthquake throughout the secondary containment do not have isolation valves at the secondary containment membrane. All lines that are not analyzed for the maximum earthquake, except as noted below, have a means of sealing the line at the secondary containment membrane, and the section of pipe from the seal to the containment membrane is designed to withstand the maximum earthquake. Lines postulated to break by an earthquake without means of sealing the line at the secondary containment membrane have been analyzed to maintain the secondary containment inleakage rate less than the SGTS capacity when the building is subjected to an internal negative pressure of 0.25 inch of water. These seals are arranged to prevent inflow into the secondary containment through a ruptured line when the secondary containment is under negative pressure of 3-inches water gauge. For lines that only flow out of secondary containment, check valves, water seals or other qualified methods of ensuring containment integrity are used. Lines that have flow into secondary containment or in both directions are sealed by either remote manual valves operated from the Main Control Room, or water-seal legs or check valves that require in excess of 3-inches water gauge to open; or the lines have been analyzed to maintain the secondary containment inleakage rate less than the SGTS capacity when the building is subjected to an internal negative pressure of 0.25 inch of water. All piping or ducts serving a secondary containment pressure boundary function complies with Seismic Class I or Seismic Class II pressure retention criteria. No credit is taken for the RCW discharge lines check valves' seats and disks to provide secondary containment isolation. The RCW discharge lines external to the reactor building penetrations and within the Seismic Class I service water tunnels are seismically qualified for pressure boundary retention out to the point underground where the carbon steel discharge lines join clay pipe. The clay pipe portion of the discharge lines tie into the respective unit's Condenser Circulating Water (CCW) conduit which discharges into the river. Either RCW discharge flow or river water level provide a water seal against secondary containment air inleakage under all plant operating modes and accidents. River water level is routinely monitored for low level to detect the potential for uncovering the RCW discharge flow path at the CCW conduit. During a design basis earthquake, the underground clay piping could fail, but the ends of the carbon steel RCW discharge lines would be sealed under the yard soil.

BFN-27 5.3-11 The supply and exhaust ventilating duct penetrations fall in the open system category. Low-leakage dampers are used for this service. The damper frame is a 6-inch extruded aluminum channel. The extruded aluminum airfoil-shaped damper blades seal on the edges with a resilient seat and on the ends with stainless steel pressure plates. The pneumatic damper operators close upon loss of air or control signal. Typical piping penetration seals are shown in Figure 5.3-1. All electrical penetrations are sealed with sealant around the conductors. Figures 5.3-2 and 5.3-2a through 5.3-2d show typical penetrations for both conductors in cable trays and for conductors in conduit. Figure 5.3-5 shows a typical duct penetration and seal. All functional through-wall penetrations of the concrete Reactor Building walls (i.e., penetrations through which electrical conductors or process fluid piping pass) enter the environs below grade level or into adjoining concrete structures which provide tornado and wind-driven missile protection. A single 4-inch mechanical sleeve (spare penetration) on the Unit 2 Reactor Building south wall, eight 4-inch conduit penetrations on the Unit 1 Reactor Building south wall, and several small penetrations (2-inches or less nominal diameter) that provide access to the atmosphere for equipment control penetrate above ground level and are exposed to the ambient environment. The spare penetration is sealed on both ends by blind flanges. The conduit penetrations are equipped with iron fittings that will withstand tornado and wind-driven missiles on both the interior and exterior sides of the penetration. The small penetrations contain piping which is connected to closed systems inside the Reactor Building. Thus, the integrity of secondary containment is preserved. Analysis has shown that the probability of these penetrations being breached by a tornado or wind-driven missile is so unlikely as to constitute an incredible event. Their exposure to the ambient environment is, therefore, acceptable. All Reactor Building penetrations are readily accessible and can be visually inspected. If the plant experiences a tornado that threatens the integrity of secondary containment, an inspection and test can be conducted. Several ducts and conduit pass through the insulating siding panels. Where these penetrations are made in the siding, the siding is sealed directly to the duct or conduit similar to the joints where the siding is sealed to structural steel and concrete walls. Zone penetrations are similar to the secondary containment penetrations except piping penetrations are designed for normal loads and do not necessarily contain isolation valves.

BFN-27 5.3-12 5.3.3.6 Reactor Building Heating and Ventilating System The Reactor Building is heated, cooled, and ventilated during normal and shutdown operation by a circulating air system. The Reactor Building Heating and Ventilating System is shut down and isolated when that zone of secondary containment is isolated and connected to the SGTS. While the Reactor Building Heating and Ventilating System is not an engineered safeguard, certain components do perform engineered safeguards functions. The double isolation valves and the equipment area cooling units serve engineered safeguards systems and are designed to engineered safeguards standards and criteria. The double isolation valves are described in paragraph 5.3.3.5. The equipment area cooling units remove the heat from the basement rooms during operation of RHR and Core Spray Systems. These air-cooling units are described in paragraph 5.3.3.6.2. Duct penetrations through fire area boundaries in the Reactor Building are evaluated for fire protection adequacy and, where necessary, are protected by fire dampers. The flow diagram for the Reactor Building Heating and Ventilating Systems and Standby Gas Treatment is shown in Figures 5.3-3a, 5.3-3b, 5.3-3c, and 5.3-3d. 5.3.3.6.1 Basic Ventilating System The ventilation system provides 100 percent makeup air. Outside air is taken from grade level on the south side of the Reactor Building. The air is filtered, then passes across hot water coils for winter heating and through evaporative coolers for summer cooling, and, hence, to four supply fans per unit. Two 100-percent capacity supply fans per unit furnish air to the refueling zone. Two 100-percent capacity fans supply air to each of the unit reactor zones. The filters, coils, coolers, and supply fans are located outside the Reactor Building. The ventilation system air flow values to the refueling room are shown on Figures 5.3-3a, 5.3-3c, and 5.3-3d (these values can be reduced by 1/2 during heating season). This provides a minimum of 2.7 changes of air per hour, except in the heating season when the flow may be reduced to a minimum of 1.35 changes of air per hour. The air is distributed to the south side only of the refueling room. The air flow in the room is directed across the clean areas to the less clean areas and finally collected around the periphery of the fuel storage pool (including the dryer and separator pool and refueling well when primary containment is open) and other areas of high potential for contamination. The reactor zone ventilation system air flow values are shown on Figures 5.3-3a, 5.3-3c, and 5.3-3d (these values can be reduced by 1/2 during heating season). This provides 4.0 changes of air per hour, except during the heating season when the flow may be reduced to 2.0 changes per hour. This air is distributed to the

BFN-27 5.3-13 clean areas of the four main floors (El. 565, El. 593, El. 621.25, and El. 639). A portion of this air is collected for exhaust after sweeping across the open rooms. The remainder of the air flows to areas with a higher potential for contamination, and then is collected for exhaust. Rooms below El. 565 are ventilated by supplying air down the open stairwells to each of the corner rooms, then into the pressure suppression chamber and the HPCI room where the air is collected for exhaust. The TIP room, the steam and feedwater valve room, and all rooms containing Reactor Water Cleanup System components are maintained at a negative pressure. Air flows from the main rooms into these rooms through backflow dampers. The exhaust from the CRD repair room is routed through HEPA filters directly into the reactor zone exhaust system upstream of the radiation monitors. The exhaust from these rooms is collected and routed to the Reactor Building roof. The ventilation air from the Reactor Building is ducted to exhaust fans located on the Reactor Building roof. One-hundred percent standby exhaust-fan capacity is provided. The refueling zone fans exhaust through a fan stack with the top at El. 730.25. The reactor zone fans exhaust through a fan stack with the top at El. 733.25. The air from each zone is monitored before release. High activity will isolate the secondary containment ventilation zones with the high activity (see Subsection 5.3.3.2). Normal ventilation air exhaust is not filtered. 5.3.3.6.2 Equipment Area Cooling The RHR pumps and the core spray pumps are located in the basement rooms of the Reactor Building. The heat loss from the motors, pumps, and piping is removed by air-cooling units. The air-cooling units are designed to maintain the air at 148 degrees F when the unit is supplied with 95 degrees F cooling water. There is one air-handling unit for each RHR pump. The cooled discharge from each air-handling unit is ducted to and directed across the RHR pump motor. One air-handling unit serves both core spray pumps in the same compartment. The cooled air-handling unit discharge flow is divided, with half directed to and across each spray pump motor. Each unit in the RHR rooms removes 405,000 Btu/hr under design conditions. The units in the core spray pump rooms remove either 508,000 or 405,000 Btu/hr. The larger units are installed in the core spray rooms that contain control rod drive pumps. A reliable Class I source of cooling water for the Core Spray pump room cooling units and the RHR pump room equipment area cooling units is supplied from the Emergency Equipment Cooling Water System. The EECW system is described in Subsection 10.10, "Emergency Equipment Cooling Water System." The electric power for the equipment area cooling units is taken from the 480-V Reactor MOV boards. The cooling units in each RHR pump room are fed from separate, independent boards of the same divisional power source as the pumps.

BFN-27 5.3-14 An equipment area air-cooling unit starts automatically when a RHR pump (or a core spray pump) in that compartment starts. The air-cooling units also start automatically when compartment temperatures approach 100 degrees F. The control system meets the single-failure criteria of IEEE-279. The equipment area cooling units are factory-assembled self-contained package units. The package unit and the associated ducting are designed to withstand the maximum earthquake. 5.3.3.6.3 Primary Containment Purge The Reactor Building ventilation system can supply 6000 cfm to each drywell or 6000 cfm to each pressure suppression chamber. This air is used for purge and ventilation of the Primary Containment System. The purge and ventilation exhaust from the primary containment is first processed by a filter train assembly and then channeled through the Reactor Building roof exhaust system. Such an installation allows either the drywell or the suppression chamber to be purged on each of the three plant units simultaneously. The purge supply piping is configured such that it is possible to establish a large bypass path from the drywell to the pressure suppression chamber. If this path is established, then the pressure suppression function of the primary containment could be compromised. Administrative controls prevent the simultaneous purging or inerting of the drywell and the pressure suppression chamber except when the unit is at cold shutdown (MODE 4 or Mode 5). The primary containment purge and ventilation system is isolated from the primary containment by two isolation valves in series, during power operation. Furthermore, these valves cannot be reopened if high radiation exists in the Reactor Building ventilation ducts. These valves are part of the primary containment that is described in Subsection 5.2, "Primary Containment System." An operability analysis of the containment purge valves was performed to justify the design of the containment purge system. The analyses show that the purge valves are adequate for closure against DBA forces. Modifications (new solenoids) have been made on the purge line isolation valves on all units to reduce the valve closure times for the large purge valves from about 15 seconds to less than 5 seconds. The reduced stroke time brings the valve closure time into conformance with NRC Branch Technical Position CSB 6-4. This significantly reduces the analytical dose and also protects against pressurization of appurtenant duct work as discussed in TVA submittals (L. M. Mills to Thomas A. Ippolito) dated March 17, 1980 and June 2, 1981 and resolved in an NRC letter to TVA (D. B. Vassallo to H. G. Parris) dated July 1, 1985. In addition, six purge valves have been rotated to assure a uniform flow distribution on the valve disc. Debris screens on the purge lines have also been provided to ensure that isolation

BFN-27 5.3-15 valve closure is not prevented by debris which might become entrained in the escaping steam and air. These provisions allow use of the main purge valves, as restricted by the technical specifications, during operation. The purge valves involved are shown schematically in Figure 5.3-10. The purge and ventilation filter assembly contains the following components in sequence of flow: a high-efficiency particulate absolute filter, a carbon absorber, and a fan. The first component of the filter assembly is a HEPA filter. This filter assembly has the capability of removing radioactive particulate 0.3 micron in size and larger with an efficiency of 99.95 percent. The bank consists of six 2-foot square standard high-efficiency particulate filter elements. Each filter has a waterproof, fire-retardant, glass fiber filter media in a frame. The second component is an activated charcoal bed. The adsorber unit is a standard size unit tray type capable of removing 99.955 percent of radioactive iodine as elemental iodine and 85 percent of radioactive iodine as methyl iodine with an intake flow at 90 percent relative humidity. The holding capacity is 2.5 milligrams of radioactive iodine per gram of carbon with 95 percent elemental iodine and 5 percent methyl iodine. The minimum retention time of the air is 0.25 seconds. The final component in the filter assembly is a centrifugal fan having a capacity of 6000 cfm at 8.5-inches water gauge. The fan is driven by a 15-hp, V-belt drive, electric motor. 5.3.3.7 Standby Gas Treatment System The Standby Gas Treatment System provides a means for minimizing the release of radioactive material from the containment to the environs by filtering and exhausting the air from any or all zones of the Reactor Building and maintaining the building at a negative pressure (such that air leakage is into, not out of, the building) during containment isolation conditions. Elevated release is assured by exhausting to the plant stack. The basic system consists of a suction duct system, three filter trains and blowers, and a discharge vent system. The suction duct system exhausts from the normal ventilation exhaust duct of each of the three reactor zones ahead of the isolation valves and from the refueling zone independent of the normal ventilation system. Each train contains seven major components. In the direction of flow, these components are: (1) moisture separator, (2) relative humidity heater, (3) prefilter, (4) upstream HEPA filter, (5) charcoal filter, (6) downstream HEPA filter, and (7) blower. The second through seventh components are, in order, approximately 1.5, 5, 10, 13, 20, and 34 feet, respectively, from the moisture separator.

BFN-28 5.3-16 The three filter trains and blowers are arranged in parallel and are located in two Standby Gas Treatment System buildings. (See Subsection 12.2, "Principal Structures and Foundations".) In the SGTS building containing two filter trains and blowers, each blower is normally aligned with its respective filter train, but either blower can be used with either filter train. Inside this building, the trains are separated by a 42-inch thick concrete-shield wall. The third train is located in the second building. All three trains share a common suction manifold. In this way, each of the three trains is connected to all three reactor zones and the refueling zone. Upon an accident signal, all three SGTS units will start. Allowable surveillance inleakage occurs as a result of ongoing secondary containment maintenance and/or modifications, siding and roof leakage, HVAC damper leakage, airlock door leakage, penetration leakage, and other similar leakages. The limiting value for the allowable surveillance inleakage is specified by Technical Specification SR 3.6.4.1.4. The design basis margin is the flow required to compensate for the increase in leakage following a design basis event. The design basis margin is based on a calculated value of the increased leakage through the secondary containment boundary due to a design basis event. The minimum acceptable capacity is the sum of the allowable surveillance inleakage and the design basis margin. The minimum acceptable flow rate of two SGTS trains is equal to the flow rate defined by the minimum acceptable capacity. The three Standby Gas Treatment blowers share a common discharge header which is connected to the 600-foot high plant stack through a dual underground piping network. Both Standby Gas Treatment buildings are located west of the Reactor Building under the berm. The diagram of the Standby Gas Treatment System is shown on Figures 5.3-3a, 5.3-3b, 5.3-3c, and 5.3-3d. The ducts, filter trains, blowers, and associated valves are designed to withstand the maximum earthquake without impairing the ability of the system to operate at design capability. The design of the ducts and equipment, such as valves and operators, etc., prevents introduction of foreign materials such as lubricants into the air stream. The radiolytic heating in the filter train is approximately 984 watts. Any heat is removed by the flowing air when a train is in service. When it is required to remove heat from one train with the other trains in service, a small bypass stream is drawn through the train that requires heat removal. When it is necessary to remove heat with all trains shut down, a stream of room air is supplied to the train that requires cooling, then exhausted up the stack by one or more of the blowers. All of the cooling functions are controlled manually from the main control center. All power-operated valves and dampers have position-indicating lights in the Main Control Room.

BFN-27 5.3-17 The Units 2 and 3 offgas air dilution ducts cross connect to SGTS, the cubicle exhaust duct, the steam packing exhaust duct, and the cubicle and steam packing exhaust bypasses are automatically isolated from the stack and SGTS by redundant, safety-related, backdraft dampers which shut on backdraft or no flow during periods of SGTS operation. Such isolation limits a ground-level release from SGTS in the event that the dilution fans are not operating. Because the dilution fans are not nuclear safety-related, their operation cannot be assured during or after a design basis accident. Chapter 14 includes the evaluation of the radiological consequences from Design Basis Accidents which require the use of these isolation dampers to mitigate the radiological consequences. The standby gas treatment flow rate is measured downstream of the filter trains. The flow rate is indicated in the Main Control Room during SGTS operation. The moisture separator is designed to remove 99.9 percent of moisture particles 2 microns or larger, and 30 percent of 1-micron sized particles. The design inlet conditions are 9000 cfm of 140 degree F air with 36 lb/min of entrained moisture. The separator consists of six 2-foot square woven mesh modules with the mesh mounted vertically. Separator pressure drop is less than 1.2-inches water gauge with the design flow conditions. The filter will withstand a pressure differential of 4-inches water gauge without structural damage. The moisture separator drains by gravity to two standby gas treatment sumps. Sump pumps powered from the 480-V diesel auxiliary boards for trains A and B sump and 480-V SGT board for the train C sump, pump the drains from the sump to the Radwaste Building waste collector tank. The second component of each filter train is an electric air heater capable of a total output of at least 40 kW. The purpose of the air heater is to reduce the relative humidity of the influent to less than 70 percent. The heater is energized automatically with startup of the Standby Gas Treatment System and remains energized throughout operation. The heater is interlocked to prevent heater burnout on high heater temperature. A bulb and capillary type temperature sensor is used in conjunction with the relative humidity heater. The sensor is mounted near the heater module and is close to the heater elements, with an air space between. The sensor is set to trip the heater off at a sensor temperature of 180 degrees F and thus prevent overheating. The heater is made of hairpin elements; each Incoloy-sheathed element is 0.5 inch in diameter. The pressure drop across the element is about 0.1-inch water gauge. The heaters are powered from the 480-V diesel auxiliary boards for trains A and B and from the 480-V SGT board for train C.

BFN-27 5.3-18 The third element of the filter train is a prefilter. The prefilter is used to remove large particulates and protect the high-efficiency particulate filter. The prefilter has an efficiency of at least 40 percent using the NBS dustspot method with atmospheric dust. The clean pressure drop is less than 0.2-inch water gauge. The filter will withstand a differential pressure of 1-inch water gauge without structural failure. The fourth unit in the filter train is a high-efficiency particulate filter. This filter removes radioactive particulates 0.3 micron in size and larger with an efficiency of up to 99.97 percent. The bank consists of nine 2-foot square filter elements of the standard high-efficiency particulate filter element design. Each filter has a waterproof, fire-retardant, glass-fiber filter media built in an integral frame. The frame of each element is held against a gasket and a flat plate surface by four independent clamps. Periodic inplace testing assures that the filter efficiency is > 99 percent using the standard DOP test. The clean pressure drop is less than 1-inch water gauge. The filter is capable of withstanding a moisture loading in the form of mist or fog that will produce a pressure of 10-inches water gauge for 15 minutes; the filter will not suffer permanent damage or a decrease in efficiency after the filter has dried out. The fifth element in the filter train is an activated charcoal bed. The charcoal adsorbers in each train of the Standby Gas Treatment System are mounted in dual tray module stainless steel drawers. A train has 27 of these drawers with each drawer having a nominal rating of 330 cfm. Each drawer contains approximately 44 lb. of charcoal--a total of 1200 lb. per train. The drawers are arranged in a single bank of nine horizontal rows, with each row being three drawers wide. The drawers are mounted in a rigid welded, leaktight, stainless steel case. The air flows vertically through each drawer containing a 2-inch thick layer of charcoal. This vertical air flow through the charcoal is equally distributed across all of the drawers. The drawers are sealed to the bulkhead frame with continuous gaskets. The drawers are held in place with individual clamps. The flow resistance of the clean charcoal bed is less than 1 inch of water gauge. The minimum residence time in the adsorbent is 0.25 second per 2-inch bed depth when processing Reactor Building effluent in a post-accident environment. Charcoal decay heat removal air flows are established through the cross connection duct of any idle SGTS filter train provided the two remaining filter train fans are operating and the respective decay heat inlet damper (FCO-65-4,-26 or -52) is open. Also by running an individual filter train's fan and opening up either its decay heat inlet damper of its normal inlet damper (FCO-65-3, -25 or -51) charcoal decay heat can be removed. Any one of the methods is adequate to prevent excessive charcoal temperatures or iodine desorption.

BFN-28 5.3-19 A humidity detector upstream of the charcoal initiates alarms in the Main Control Room when relative humidity exceeds 80 percent. The impregnated charcoal has a minimum ignition temperature of 330 degrees C (625 degrees F). The maximum ash content is 6.5 weight percent maximum. The particle size is 8-14 Tyler mesh with a packed density of 0.39 to 0.45 grams per cc and a BET surface area of 1400 to 1500 square meters per gram. The charcoal in all three trains is maintained above the maximum dewpoint temperature of the gas that could enter upon startup of the Standby Gas Treatment System by an electric heater installed in the inlet of each train capable of a total output of at least 40 kW. The purpose of the heater is to reduce the relative humidity of the influent. The heater is energized automatically with startup of the Standby Gas Treatment System and remains energized throughout operation, except during high heater temperature. Operation of each SGT train with the heaters on (automatic heater cycling to maintain temperature) for 15 continuous minutes every 31 days verifies operability of the system. Typically, the laboratory test for activated carbon shows its capability of removing at least 95 percent of iodine in the form of methyl iodide, CH3I, and 95 percent of elemental iodine under entering conditions of 70 percent relative humidity. The sixth unit in the filter train is a second high-efficiency particulate air filter. This filter is identical in characteristics to the first HEPA filter; however, the function is not the same. Since the first filter removes essentially all (99 percent) of the particulates from the Reactor Building atmosphere prior to it reaching the charcoal absorber, the function of the second HEPA filter is to preclude the passage of any remaining radioactive particulates, especially carbon from the charcoal absorber. This function is ensured by performance of DOP testing discussed 5.3.5.2. Filter trains A and B are cross-connected downstream of the second high-efficiency particulate filter. The cross connection is isolated by a single electrically operated damper (FCO-65-22) which can be manually operated from the Main Control Room, this damper is normally closed. Two manual dampers (DMP-65-24 and -2) are in parallel to FCO-65-22, these dampers are locked in their required positions. Filter train C is cross-connected through a bypass heat decay line via manual valve DMP-65-66 which is left open. The last element in the Standby Gas Treatment System filter train is a blower. The blower is a heavy-duty industrial fan that develops approximately 16 inches of water gauge pressure while delivering approximately 9500 cfm. Each fan is

BFN-27 5.3-20 driven with a 30-hp electric motor through a V-belt drive. The blowers may be isolated from their trains by intake dampers. These dampers are electrically operated and controlled from the Main Control Room. Each blower is followed by a back draft damper. The blowers for trains A and B are powered from the independent 480-V diesel auxiliary boards and the blower for train C is powered from the independent 480-V SGT board. Control logic for the Standby Gas Treatment System automatically and concurrently starts all three filter trains upon receipt of an accident signal. All three trains will continue to run for the duration of the accident. Should one train fail, the two remaining trains will continue to provide the minimum flow requirements. Any two SGTS trains must maintain the minimum acceptable capacity at 1/4-inch of water negative pressure for all four zones of secondary containment. Local and remote manual control of dampers and blowers is provided, including instrumentation and controls in the reactor control rooms. A temperature sensor is interlocked with the humidity control heater controls to prevent burnout due to high heater temperature. The blowers of trains A, B, and C discharge to a common header. This header discharges to the stack through dual underground pipeline. The two parallel pipelines are 30-inch outside diameter, 3/8-inch thick welded steel pipe. The activity released by the Standby Gas Treatment System is monitored by the Main Stack Radiation Monitoring System described in Subsection 7.12, "Process Radiation Monitoring." The isolation and control dampers in Standby Gas Treatment System trains A and B are electrically operated with the power supplied for each train (from the Units 1 and 2 independent 480-V diesel auxiliary boards). The isolation and control dampers for train C are electrically operated with the power supplied from the independent 480-V SGT board. 5.3.4 Safety Evaluation 5.3.4.1 Secondary Containment Isolation The secondary containment isolation is initiated from any of three signals: low reactor water level, high drywell pressure or high activity in a ventilation exhaust duct, or by manual alignment and operation from the Main Control Room. Each signal simultaneously isolates the secondary containment zone or zones, shuts down normal ventilation equipment, opens dampers to and from the Standby Gas Treatment System and starts the Standby Gas Treatment System blower. The isolation condition is removed and the Standby Gas Treatment System shut down only by manual reset. Subsection 5.3.3.2 describes the sequence and logic for isolation of the secondary containment system. The control system is described

BFN-27 5.3-21 and evaluated in Subsection 7.3, "Primary Containment and Reactor Vessel Isolation Control System." Upon secondary containment isolation, the SGTS is required to maintain a negative pressure inside secondary containment. The SGTS is required to maintain a 1/4-inch of water negative pressure with a flow equal to the minimum acceptable capacity as discussed in Section 5.3.3.7. This inleakage considers the total infiltration including locks, roof, siding, and isolation dampers in addition to requirements for seismic and thermal expansion effects. The relief panels for the main steam tunnel are designed to relieve at 90 lb/ft2. The relief panels in the vertical siding are designed to relieve at 50 lb/ft2. All relief panels are held in place with necked aluminum rupture bolts. Sample bolts have been laboratory-tested to failure. These bolts failed within plus or minus 10 percent of the design value. The SGTS power supply and damper arrangement meet single-failure criteria. The power supply for trains A and B is taken from the 480-V diesel auxiliary boards with each train supplied from a separate board and the damper in the crosstie supplied from both boards. Train C is powered by the 480-V SGT board. A power failure to any train will result in a fail-safe condition in that train. The damper downstream of each blower is a gravity-type backflow damper and will prevent backflow through the blower. The damper upstream of the filter bank and the damper that supplies cooling air from the room will fail closed, thereby assuring that any suction is from secondary containment. The bypass cooling stream valves fail closed; however, it is powered from the same source as the blower in a companion train. Thus, a cooling mode is always assured with any two blowers powered, and in some arrangements with one blower powered. All other dampers will fail open. By manual positioning of dampers in the train A and train B crosstie, and in the powered train, either filter bank A or filter bank B can be used with blower A or blower B assuring a maximum utilization of components. Two out of three Standby Gas Treatment System blowers are adequate to keep all three Reactor Building zones and the refueling zone at a pressure of 1/4-inch water gauge below atmospheric. Reduction in flow due to filter loading will be sufficiently offset by the reduction in the required flow capacity due to the diminishing nature of the thermal expansion effect. In the Chapter 14 radiological dose analyses, no credit is taken for secondary containment during the Control Rod Drop Accident, Refueling Accident, or Main Steam Line Break Accident.

BFN-27 5.3-22 5.3.4.2 Standby Gas Treatment Instrumentation and Control The objective of the SGTS is to maintain the secondary containment at a negative pressure so the release mode is through the SGTS and to process all effluent from the Reactor Building when required, thereby limiting the discharge of radioactive material to the environs. The system accomplishes its objective by maintaining the Reactor Building at a slightly negative pressure relative to the atmosphere and filtering all the exhaust. The SGTS control and instrumentation provide the logic and signals to allow the equipment or redundant components to become functional as required to cope with any radioactivity releases. Thus, the controls and instrumentation assure that the performance of the SGTS is such that the radioactivity released to the environs is kept to a practical minimum and well within the guideline values of 10 CFR 20 and 10 CFR 50.67. The design bases for the SGTS controls and instrumentation to protect the health and safety of the public are as follows:

1.

All three SGTS trains automatically start in the event of a secondary containment isolation signal.

2.

Low system flow will be indicated and annunciated in the Main Control Room.

3.

The trains may be controlled manually from the Main Control Room with provision for complete remote manual operation of filter bank A with either blower A or B, filter bank B with either blower A or B, or filter bank C with blower C.

4.

Manual alignment will provide for decay heat removal from fission products deposited on any filter bank using one of several flow paths.

5.

Gas temperatures will be indicated, heater temperatures which are high will be annunciated, and overall filter bank pressure differential will be indicated and high values annunciated in the Main Control Room.

6.

Misalignment of the control switches and instrumentation which places any train in the standby mode under normal operating conditions will be annunciated in the Main Control Room.

7.

Misalignment of dampers or blowers in the trains will be annunciated in the Main Control Room. The above design bases were incorporated in a controls and instrumentation scheme that is reflected in the control diagram shown in Figure 5.3-9. Separate controls and instrumentation are associated with the three independent SGTS

BFN-27 5.3-23 trains of filter banks, blowers, dampers, and ducts. The logic initially places all trains in the auto mode and allows for trains to be placed in the standby mode. Accident signals will initiate action in all three SGTS filter trains. This action consists of alignment of the dampers, starting the blowers, and energizing the relative humidity heaters when sufficient flow is established in the ducts. The total time required to switch from the normal containment ventilation system to the Standby Gas Treatment System upon detection of high radiation is relatively small. The radiation monitor response time is 1 second, and the refuel zone exhaust dampers will close in approximately 15 seconds. Startup of the Standby Gas Treatment System blower motors is within 5 seconds from the time of the signal. The proper dampers (electric-motor-driven) in the SGTS trains are opened on Secondary Containment accident signal to allow flow of effluent to the SGTS trains. All Standby Gas Treatment System trains will be producing adequate flow when required to mitigate the consequences of an accident. In the event of concurrent loss of offsite power, the diesel start time of 10 seconds must be added to the total times to switch over from normal containment ventilation system to the Standby Gas Treatment System. The SGTS is designed to maintain this negative pressure under accident conditions with the response time mentioned above. Thermal expansion due to loss of cooling decreases with time and provides extra margin for the SGTS to maintain the negative pressure. Thus, the secondary containment is maintained at some slight negative pressure, unfiltered release is prevented, and the health and safety of the general public is protected. The time required to bring the secondary containment to the design negative pressure is not crucial to the safety of the plant but is used to ensure secondary containment boundary integrity and verify SGTS operability. The normal ventilation system maintains the Reactor Building at approximately 1/4 inch of water negative pressure relative to the outside environment. At the outset of the accident, the normal ventilation is isolated and the Standby Gas Treatment System is initiated. As discussed above, the Standby Gas Treatment System must wait for the diesels to start if offsite power is lost. As discussed in Chapter 14, the Reactor Building becomes pressurized relative to the outside environment for a short period of time during the initial phase of an accident. This is due to the isolation of the normal ventilation, the time required to start the Standby Gas Treatment System and thermal expansion of the air inside the Reactor Building due to the heat loads inside the building. However, negative pressure would be re-established in secondary containment prior to fission product release times specified by RG 1.183. All dampers except the blower discharge backdraft dampers have position-indicating switches that operate position-indicating lights in the Main

BFN-27 5.3-24 Control Room. Limit switches on the dampers, contacts in the blower control switch, and contacts in the train selector switches indicate misalignment for automatic train operation. During a LOCA, there is no delay in initiating action in any train. However, during a LOCA and a Loss of Offsite Power (LOP), there is a 40-second delay in initiating action on Trains A and B. There is no delay in initiating action on Train C for a LOP/LOCA. Gas temperatures of the relative humidity heater and the charcoal bed are measured and indicated both locally and in the Main Control Room as shown in Figure 5.3-9. High temperature in the charcoal bed and in the relative humidity heater are annunciated in the Main Control Room. The overall filter train pressure differential is measured and indicated in the Main Control Room. High pressure differential is annunciated. Each train, with its associated controls and instruments, is supplied with emergency power. This power is taken from separate emergency power supplies to guarantee that two trains are always available in case of loss of offsite power. The system is also arranged so that power failures that interrupt flow in an operating train may only momentarily reduce the rate at which the system processes effluent. Separations criteria require that the power supplies be completely separate. However, the single crosstie damper which is normally supplied by train A power will be supplied by train B power upon loss of train A power and will automatically revert back to train A power if that source is restored. Each 120-V circuit leading to the switch is fused so that short-circuits will cause isolation of either or both circuits as required. Fuses are also provided to protect the connecting leads of the low-voltage annunciator circuit from short-circuits in the train selector switches. The Main Control Room has annunciators to alert the operators of malfunctions in the system such as low flow, containment isolation signals with any train in the standby mode, power failures that interrupt flow in a train, and dampers improperly aligned. In the event of malfunction of both trains A and B, these trains can be manually aligned and controlled to use either filter bank with either blower. This operation is completely manual and will be used to circumvent some, but not all, combinations of multiple failures. This type of operation requires power along with the pertinent controls and instrumentation to some parts of both trains and is therefore not available for the complete loss of power to either train. The design of the controls and instrumentation makes it possible for removal of decay heat from fission products deposited on the filter bank of any train. If one bank is in operation with flow from the secondary containment, there are sufficient dampers and valves in the system to remove decay heat from a shutdown bank. Crosstie valves are positioned to provide a small cooling flow through the

BFN-27 5.3-25 shutdown filter bank, through the decay heat removal crosstie line and then through the blower of the operating train. In the event the train from which decay heat is being removed has suffered a complete loss of power, the decay heat cooling flow can be bled into the train from the building through a damper powered from the same source as the adjacent operating train. Thus, the controls and instrumentation assure that the removal of decay heat from the shutdown filter bank is accomplished while maintaining the safety objective of filtering the major fraction of the containment atmosphere through the operating train. In time, it may be desirable to discontinue the secondary containment function, but removal of decay heat from the filter banks is still required. Provisions are incorporated in the controls and instrumentation such that cooling can be provided by bleeding building air into the system upstream of the filters. A blower is always available to produce flow through the train from which the decay heat is to be removed. All of these alignments to remove the decay heat are manual. In the Chapter 14 radiological dose analyses, no credit is taken for SGTS operation during the Control Rod Drop Accident, Refueling Accident, or Main Steam Line Break Accident. In the Chapter 14 radiological dose analyses, no credit is taken for the SGTS charcoal adsorber during the Loss of Coolant Accident. 5.3.5 Inspection and Testing 5.3.5.1 Secondary Containment The secondary containment siding has been laboratory tested by the siding vendor. The laboratory test consisted of both leakage tests and strength and deflection tests. The tests were conducted in the manner described in Section 9 of ASTM 372-61. The infiltration rate is determined from the flow measured at the Standby Gas Treatment System filter train. During normal operating conditions, the total inleakage for the four zones must be less than the allowable surveillance inleakage value given in Section 5.3.3.7. Permanent test connections are located in the section of duct between and adjacent to low-leakage dampers used to isolate the ventilation supply and exhaust ducts. These test connections are arranged and sized so that the composite leakage across both dampers can be determined. All ventilation ducts contain sealed manholes which may be used to visually inspect the damper blades, resilient seals, and operating mechanisms. Necked rupture bolts identical to those used to secure the relief panels in place are factory tested to confirm the relieving load and to determine the relieving time

BFN-27 5.3-26 for the relief panels. The relief panels are visually inspected periodically to assure that the panels have not partially relieved and thereby opened cracks in the siding. 5.3.5.2 Standby Gas Treatment System The Standby Gas Treatment System filtration trains and blowers are arranged such that one redundant train and its associated blower may be serviced or tested while the other two trains are ready to operate. In the event of a signal to isolate secondary containment and start the Standby Gas Treatment System, the test signal will be overridden. The Standby Gas Treatment System filtration trains are equipped for complete testing of the HEPA filters and the charcoal adsorbers. The filter housing and related ducting is designed to assure mixing for uniform distribution of DOP and Freon. The charcoal adsorber bypass flow will be determined using an inplace Freon leak test. The Freon will be injected into the flowing gas stream well upstream of the adsorber. The mixed stream will be sampled upstream and downstream of the adsorber and the ratio of concentrations will be used to calculate the bypass flow. Standard testing procedures and apparatus will be used; these are described in Section 7.5.1 of ORNL-NSIC-65, "Design Construction and Testing of High Efficiency Air Filtration Systems for Nuclear Applications." DOP injection and detection connections are located upstream and downstream of both banks of the HEPA filters. Freon injection and detection connections are located upstream and downstream of the charcoal adsorbers. These connections and portable test equipment provide all essentials for the HEPA filters and the charcoal adsorbers. The filtration efficiency and charcoal effectiveness are determined periodically. Inspections of each filter will be performed at intervals specified in the Ventilation Filter Testing Program. Whenever a HEPA or charcoal filter is replaced, inplace DOP and Freon tests will be performed. The effect of DOP retention and poison in charcoal was investigated by Wendell Anderson of the Naval Research Laboratory. Tests show that activated charcoal can adsorb up to approximately 0.25 gram of organic material per gram of charcoal. At lesser values, the charcoal will continue its intended function. Consequently, the adsorption of small amounts of DOP, due to testing, would have a negligible effect on adsorption qualities of the charcoal. It should be noted that DOP has a negligible vapor pressure and, therefore, it is not likely to be stripped from either the HEPA filters or the charcoal filters once a particle has impacted on either material. In making these tests, NRL utilized three particle sizes: (1) less than 0.1 micron, (2) 0.15 micron, and (3) larger than 5 microns. Only the first and a small portion of the second sizes would pass through the

BFN-27 5.3-27 HEPA filters to any extent. Only these small parts and vapors may be considered adsorbed by the charcoal. However, the quantities involved in any reasonable estimate of testing over the lifetime of charcoal filters is insufficient to lower their efficiency by any detectable amount. The ignition and combustion properties of activated carbon containing adsorbed hydrocarbons were studied by F. J. Woods and J. E. Johnson of the Naval Research Laboratory (NRL-6090, 1964). They classified ignitions into induced ignition and spontaneous ignition and concluded that for induced ignition, a carbon saturated with hydrocarbon generally had a flash point about the same as the liquid hydrocarbon, but not lower. If the carbon was not quite saturated with hydrocarbon, a flash point somewhat higher than that of the liquid was obtained. For spontaneous ignition, it was found that the flash point increases with decreasing hydrocarbon concentration and is generally above 500 degrees F for both coal-based carbon and coconut carbon when the hydrocarbon concentration is less than 10 wt. percent. It is therefore concluded that the ignition temperature of the charcoal does not change appreciably due to the presence of the small amount of DOP. Permanently mounted differential pressure gauges are mounted across the moisture separator, the prefilter, the HEPA filters, and the charcoal adsorber. The pressure differential across these elements and the system flow is analyzed during periodic testing to determine the extent of dust loading and plugging of the filters and adsorber. The effectiveness of the standby gas treatment filters is monitored by preoperational tests, periodic inplace standard DOP and Freon tests, and scheduled laboratory tests to demonstrate charcoal adsorptivity. The DOP aerosol is generated from liquid dioctyl-phthalate using dry air or by heating to produce a stable aerosol with proper particle size distribution in accordance with ANSI N510-1975. The aerosol generator is capable of supplying sufficient DOP to test for leaks using the 9,000-cfm design flow of one train of the Standby Gas Treatment System. The DOP particulate detection instrumentation is capable of detecting small changes in concentration of the aerosol. The instrumentation has a threshold sensitivity and range adequate to satisfy the recommendations of ANSI N510-1975, Testing of Nuclear Air-Cleaning Systems, as required by the Ventilation Filter Testing Program.

BFN-27 5.3-28 Halogenated hydrocarbon (Freon) tests of the charcoal bed absorbtion efficiency and integrity are also conducted in accordance with the recommendations of ANSI N510-1975 as required by the Ventilation Filter Testing Program. The frequent leak tests, preoperational and periodic inplace Freon and DOP tests, and scheduled laboratory tests of charcoal adsorptivity assure that the HEPA and charcoal filter system will perform its intended function. Therefore, iodine monitoring is not necessary. The heater used to maintain the charcoal bed above the dewpoint temperature, the temperature-indicating and alarm instrumentation, the differential pressure gauges, and the flow instruments are periodically tested and calibrated. Testing and inspections of the controls and instrumentation will be made periodically. The dampers will be tested by operation of manual switches in the Main Control Room and observation of the position-indicating lights in the Main Control Room. The auto start signals and alarm functions will be functionally tested by applying test signals, simulating malfunction by switch operation/fuse removal, and observing results. 5.3.5.3 Equipment Area Cooling Units The equipment area cooling units in the basement of the Reactor Building are tested during initial operation of the RHR pumps and the core spray pumps, and with each subsequent test of these systems. The cooling water supply to the cooling units was initially tested with EECW (Subsection 10.10, "Emergency Equipment Cooling Water") and is tested periodically in the same manner.

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-,_oor Ope:1!.ns Not Req'.lirins a

'?re ssur e Se a.!.

ZfOM I (-!.983Lt-O l"I L9 1-1/4" DOP SAMPLE CONNECTION ECAY COOLING AIR INLET y 1/2' PLUG (TYP 4) t 1-t-*oo RTV-65-212A RTV-65-201A ~ 8 ~ l---.r:;0:::::::-- 1.800 3tr2 ~ 3tr3 1.800 HTR-30-183 HTR-30-184 ____,y. ____.._ _______ :.Y-----11.. --...,..., fJt:~al/fAS BUILDING HEATER A 15 KW STAND GAS TREATMENT BUILDING SUPPLY FAN A FAN-30-192 FAN A 0 FAN-65-18 1/4" FREON SAMPLE 8" CONNECTION 1-"---IH 1/2" 1.. ABANDONED IN PLACE DMP-65-24 STANDBY G TREATMENT BUILDING SUPPLY FAN B FAN-30-193 1.. STANDBY GAS TREATMENT BUILDING HEATER 8 15 KW FAN B FAN-65-40 1/4" 4 * (NOTE 7) 4.. B" ~-'----I f I----'-~ 1 /2" E--1 L-f,oo\\ ~ gM:~*65-39 DMP-65-1~~1--~-~-~_,;7 _______....,,.... _ _._6_.. _____ ~---.---*-*_,*L....------------1,-~..:6;_" _________ _ 1 2" PDT 65-5 .250" RTV 211 A RTV 210A RTV 209A PD! 65-9 RTV 208A .250" RTV 207A PD! 65-8 RTV 206A.250" / DMP-65-16 6" X DMP-65-22 6' 8" 4" 4" '--'----I/I---'--..... 8" 0 0 (ME\\ 65-13 o-8' 8" I HEPA FILTERS FLT-65-10 TW 65-46 DMP-65-2 (NOTE 7) TI o -1,---"5*5-1 5 TE CHARCOAL FILTERS 65-148 0 0 0 Fl T-65-9 1/2" DOP.t. FREON SAMPLE CONN (PLUGGED) (TYP 13) HEPA FILTERS Fl T-65-8 8" I TE 65-14A TE 65-36A TE I 8" HEPA FILTERS Fl T-65-32 1/2" DOP.t. FREON SAMPLE CONN (PLUGGED) (TYP 14) 65-368 CHARCOAL FILTERS FLT-65-31 HEPA FILTERS Fl T-65-30 ROUGHING FILTERS OR PREFILTERS _,I DMP-65-38 ooo-+-I (TW\\ 65-37 -o 0 0 0 1 /2' 1/4' 250" RTV 223A POI 65-32 RTV 222A (iiv\\ 1-'2.,5~0 *---3: 65-47 0 0 RTV-65-220A RTV-65-218A 250" PDT 65-27 ~ RTV 205A (TW\\ (TW\\ ROUGHING FILTERS OR PREFILTERS FLT-65-7 Fl T-65-29 (TW\\ (TW\\ RTV 217A PD! 65-7 RTV 204A .250" RTV 203A PD! 65-6 RTV 202A 65-44 65-11 DRAIN TO SUMP 2.. l--+---,--IKJ--"----lloo\\(0-47E830-1. 87) 0 65-33 65-45 0 -v\\J\\r-TE 65-34;;,-t;;--,....-,J.,..--, POI 65-29 RH CONTROL HEATERS HTR-65-34 RTV-65-216A ~ 250" /TE\\ ~~--3: 65-348 RTV 215A DRAIN TO SUMP 2" (0-47E830-1, 87) <,oa--=--1>1-""T----f-lJ,-"T"'__, 1-1 /2' POI 65-28 t 1/2" CAPPED DRAIN (TYP 5) . 250" 1-1/2" MOISTURE SEPARATORS SEP-65-6 RTV 214A .250* 1'--+1/2" CAPPED 1--1>'<:J-...;..;;;.;;....1 DRAIN ( TYP 5) l-t-*oo 1-47E865-1. 81. N /2" J" DOP.t. FREON INJECTION 1 /4' X OMP-65-3 1.-~FREON INJECTION POINT 1,800 _+/-_ ~ELIEF VEN~ 1-47E865-1, D1 FROM REFUELING FLOOR 8 FILTER TRAIN A ___ ---A_DECAY HEAT --v-REt.OVAL AIR DMP-65-4 SUMP VENT 10 DUCT -+7E830-1, 86 DECAY HEAT REMOVAL AIR STANDBY GAS TREATMENT BLDG NO. 1 rG\\ 6)1 FILTER -,/'----* t. TRAIN 8 X DMP-65-26 1 /4" ~~. 65-25~DMP-65-25 1, 800 _+/-_ 1/2" 3" DOP.t. FREON INJECTION ooo-+-I ~ELIEF VEN'j;\\ 7 6 5 (NOTE 12) (NOTE 11) (NOTE 10) DECAY COOLING AIR INLET FREON SAMPLE CONNECTION ~ HTR-30-190 HTR-30-191 ~4 1/4~10-195 of-,,--....... _1 _. 8_o_o_l ___ __.__________ _1_._8_0_0-1..... --.,..,0 STANDBY GAS TREATMENT BUILDING HEATER C 15 KW STANDBY GAS TREATMENT ~ BUILDING SUPPLY FAN C (FCO' FAN-30-194 65-67 f M+-'!:---D-.P---;;:-;'"08-,,r,;,,-,!i' 3/8" CAP FAN C FAN-65-69 DMP 65-66 (NOTE 7 > 6' DOP TEST CONN-----... l-t-*oo

v.

.250" 1/2" DOP.t. FREON SAMPLE CONN (PLUGGED) (TYP 17) 0 (TW\\ 65-64 DMP-65-67 ,.L._.L.-'{ DMP-65-509 INLET VANE DMP-65-552 (SEE NOTE 3) .250" ABANDONED IN PLACE RTV-65-235A PD! 65-58 RTV-65-234A .250" 0 I-----"'""'---------:[ CHARCOAL FILTERS FLT-65-57 (TW\\ ME 65-BJA,---'65_61 1-1/2" CAPPED DRAIN (TYP 4) RTV-S5-233A PD! 65-57 RTV-65-232A RTV-65-231A 0 0 0 0 6" DOP TEST PORR~--t;:;--;; 0 (TYP 3 PLACES) 0 0 0 0 HEPA FILTERS FLT-65-56 PD! ROUGH I NG FILTERS 65-56 TE 65~8 RH CONTROL HEATERS HTR-65-60 hw\\ 65-62 MOISTURE SEPARATORS SEP-65-54 1-t-*oo 1,800 _+/-_ ~ELIEF VEN~ FILTER TRAIN C 4 OR PREFILTERS FLT-65-55 RTV-65-230A .250" RTV-65-229A PD! 65-55 .250" FIS l----"""--2t:3"'8A::]-...J..-!,65-70A~--~ ~ (SPARE) RTV-65 . 250' -228A ITE,f---"""""--------:--:=~i: 65-SOA RTV-65 -227A DRAIN TO SUMP IO 47E830 9 E3' ~-~- PD! ,:/ 65-54 .250" 237A .250" 6" DOP ~ TEST PORT 65-52 --Y---+- x DMP-65-52 N RTV-65-226A DECAY HEAT REMOVAL AIR 1.-~FREON INJECTION POINT STANDBY GAS TREATMENT BLDG NO. 2 3 N STANDBY GAS TREATMENT BUILDING SUPPLY FAN D FAN-30-195 STANDBY GAS i~Iti~~~THEATER D 15 KW 1 /2" 1 /4' PDT 65-53 1/2" SUMP VENT TO DUCT 0-47E830-9 E7 ~ELIEF VE~ El 1168.0 ABANDONED IN PLACE FRC>A DILUTION FANS 2-47E809-2,G2 3-47E809-2,G1 1.ODO 1 2" 1 2" 3-SHV-65-510 2-SHV-65-513 FE 65-50 FE 65-71 PLANT STACK (2) 1/2" INST CONN I lo 47E851 1,02:> 0-47E830-1,F8 NOTES:

1. FOR GENERAL NOTES AND REFERENCE DRAWINGS SEE 0-47E865-2.

2. All INSTRUMENTS PREFIXED BY ("O"l UNLESS OTHERWISE NOTED.

3. FAN C INLET VANES TO BE ADJUSTED FOR PROPER AIR FLOW AND LOCKED IN POSITION AFTER SYSTEM BALANCING IS COMPLETED.

4. All VALVES PREFIXED BY (0-65) UNLESS OTHERWISE NOTED.

5. AIR FLOW RATES SHOWN ARE IN CFM.

6. DELETED

7. DAMPERS 0-DMP-065-002, -024 AND -066 SHALL BE ADJUSTED TO MEET A DESIGN DECAY HEAT REMOVAL FLOW RATE OF 175 TO 800 CFM FOR EACH OF THE THREE FILTER TRAINS. THESE DAMPERS SHALL THEN BE LOCKED IN PLACE.

8. FLOW FROM THE DILUTION FANS IS THROTTLED TO PROVIDE BLOCKING FLOW TO THE SGT SYSTEM TO PREVENT OFFGAS BACKFLOW THROUGH THE SGT DUCT.

9. FE-65-42A. -428. FE-65-20A. -208 AND FE-65-70A. -708 ARE ABANDONED IN PLACE AND ONLY PROVIDE PRESSURE BOUNDARY.

10. VALVE 1-64-737 AND DOWNSTREAM UNIT 1 HWWV PIPING ARE DISCONNECTED AND SEALED FROM THE CO~N HEADER TO THE PLANT STACK PER DCN 71389.

11. VALVE 2-64-737 AND DOWNSTREAM UNIT 2 HWWV PIPING ARE DISCONNECTED AND SEALED FROM THE CO~N HEADER TO THE PLANT STACK PER DCN 71390.

12. VALVE 3-64-737 AND DOWNSTREAM UNIT 3 HWWV PIPING ARE DISCONNECTED AND SEALED FROM THE COM~N HEADER TO THE PLANT STACK PER DCN 71391.

REFERENCE DRAWINGS, MEL...................... INSTRUMENT TABULATION DRAWINGS FOR SYSTEM JO 0-15E500-1....,.,........ POWER SYSTEM KEY DIAGRAM 0-15E500-2......,........ POWER SYSTEM KEY DIAGRAM 3-15E500-3............... POWER SYSTEM KEY DIAGRAM 0-45N3772-2...,.,........ WIRING DIAGRAMS YARD UNIT D LEGEND PHYSICAL BARRIER OR BOUNDARY BETWEEN UNITS AMENDMENT 28 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT HEATING STANDBY AND VENTILATING GAS TREATMENT SYSTEM FLOW DIAGRAM FIGURE 5.3-3b H G F E D C B A

• ~

.~* ~ 5 ~ ~TAIL KU HEATING AND VENTILATING AIR FLOW FLOW DIAGRAM f IGURE 5. 3-Jc B A

O!.Oij ?: ~-!.983Lt-£ l9 (P:;:\\ 64-58F ,-t:,:XJ,-~...._..-......., PT 832 I ,'\\ 201 A s+:=_sc A~~ 64-1608 64-57A 64-58A ( I 203A r, N .1 FL T-~-702 In ---..--~~F=A~N~6:4~13~,~~ HTR-64--J.::./ 587 584 CHARCOAL FILTERS FLT-64-701 ~STURE '--8::.YJ- ~~~6"1 '@a .500'\\, ~:~~L RADIAL INLET VOLUME DAt.FERS

'r-*2-'--+>4---i<l-""""3_*_* ----\\~it---'--------,

(1 EACH SIDE OF FAN) r X I w + NOTE 14 ~ (FCV\\ .~ (FCV\\ + ~ ( X27l J PRIMARY CONTAINMENT PURGE AIR SYSTEM FILTER ASSEMBLY 1/2" OR-64-142 NT ON 47EB44-2, G7 PI 3/4" 64-14 , 4' 570 ', 0 '. ~ (TE) (TE) ~ 64-222 ~ Gtp1 '------5.. 4~-~60'-A-6-'4"'--6.. 08-"';o...~-1~1--"'-"----I f I l+ *,. 'i (RE\\ N X X

1 206A A

45,000

/ rcoi I 1/co, ~5(~4-4~ 205A l-l[XXJ--"T----,..---,PT FL T-G4-7oo DETAIL 3E12 E3 ~~~6w] Jr,-;2;.**---l<l~i:3;.".l.f 585 586 I.., f3~*~* ~-4:,*;_--QA~FJT!ER~C~OO;!QiLJE]Rq ~ X 9~2 '""c-.1 NOTE 15 N ' N 6~0 PT /:-"T"--.&.

• ---"T",tx:(1--'

X T F AN-64-4A

i 202A j_

_)_ 64:!7 ~ (ei\\ (er'\\ ~ 64-58H 64-560 FAN-64-12A PS ~--,-----1 64-jjS 1 CLR-64-144 SEP-64-144°'" TW 6+-143 ELEV IIACH ROOM

• N

~ FAN-64-3A

• -~.-----**2~25f----,
• :i. N w

PDT ~ 6 -1J,8 6~8 201A REFUELING FLOOR EXHAUST FANS (ONE ON STANDBY) 45,000 PT 7 6.::.14 REACTOR ZONE EXHAUST FANS (ONE ON STANDBY) 234 DET 3F12 (rec\\ 64-608 +-+-:~ --11-t-TOILET 60C I' + --1-+- x STAIR AND ELEVATOR SHAFT 0 0 N STEAM TRAP 235 l 236 .----1: -t-10,800 1----1: -t-10. 800 t---: --/'- 1 o, 800 1----1: -t-1 0, 800 PS 6~E N PT 6~G /-- PT r---..JL...--~~-*i;*:...~:gx~2oi!j,~oir)r1 ~ 1 210A OPEN EQUIPMENT HATCH NOTE 13 DETAIL 3C12 AG, 86 EL 664.0 4,500 -t-1-:-..... 4,500 -t-1--......- 719 9,000 ~x DETAIL 3D12 84 A.. "I ~ X I ANCHOR@ EL 677'-6* S~.~..---, r 4-1/2" BELOW FC0-64-10 I~ I~ /'8

• 1 ~
• 1 18,000 NOTE 5 (9,000)

I.F -g 0 ~ - 18,000 ROOF REFUELING ROOM ~ ~* r.1111: r.,21,~-------------~ I -t-1-:-z- -t--14.soo> 14.500> -t- - ~-+- -~-+- -t-~ 2,050--/'- 1---, ... --: --/'- 3, 700 1---1 --/'- 3, 700 1---*--/'- 3,700 3,200 -t--1-.-- r" (3,000) ~e---------------,-' _.__ I-_ ACTUAL SPACE ABOVE DRYIELL 2,050 -,~ (3,000) LOCATION NORMALLY VENTILATED 718 EL 639.0 -t-, 2,050 -'--1--._- DRYER._ SEPARATOR 400!- .-,'l"'".'I --,~ STORAGE POOL .....---+', __,,_ 400 717 ~.- ~---~---~~~ ~ ' ~ 2,050-.}- ~ co S: 716

g N

(3,000) 2.050-.}- ~ ~ 715 co w 2.050-f"-~,- r 714 .alO OPEN / / ~ V EQUIPMENT ~ X26 HATCH ,n NOTE 13 I I (6,000)--/'- I 1,, 6,000 6,000 6,000 FUEL STORAGE POOL SEE NOTE 6 i..:-1-+- 18,000 ~~ s'4~00~4i FE 7,850 ..---------......... 6.-3...... ~I ~~I_._~ FE FE .--------1 sy2 553 6e7 3-WAY SUPPORT @ EL 664'-0", 2'-6-1/2" ~ BELOW FC0-64-42 /'--------' EL 664.0 r-1-+- 3,150 650 -t-i-REACTOR CU FILTER DMNRLZ CUBICLES lF lF /F EL 639. O lF r:::...'_k ~ -.,-,----r-<* l,_ 6-,-0-------------1-so-,-----------.... -._,=3==-------------'-l/_.,.,i 1 14.650 I TYP 3 PLACES~ 400 ~ ~ ..----1:-t-3,300 I

• 1

/ 3,850 \\ 6~x,~x PC PURGE AIR SYSTE" FILTER ASSEMBLY FI 6t:!t2 2,000 -1,- ~---- STAIR SUPPLY FAN FAN-64-60 X 0 0 + 1----1: -t-3, 250 t---: --/'- 3,250 1----1: -t-3. 250 N 8.600 537

36. 150 I

61.200 I I I I I gg~IiH-3J 25.950 22,800 I I FUEL POJ HX &1o-ii_v_E_N_T-ts1---... -----------------,--"----3-,1-.4-.----~-------_,-,,-1<4"'-' -_-----,-F--'"""-'"'-'"'--;,---;----------------"-----, ~/ ~/3-47E855-1 As.es.cs 70.N<-..,...._12,900 _*=5* -i.;;>t--'-'--'112* x 1* I 2,250--."- -~- r-564 n:sT CONN 1616 723 _l _lFUEL POOL COOLJNt PU"P -t-1--......- VENTS 3-47E855-1 A4,C4?:: (6,000) I I co O 1 --6-,-8 f.c-r_u_A_L__ YTo 3-FCV-84-20 F

• ACTUAL 4.300 4.300 r-.

'j-0 LOCATION 1* EL 565.0 {- {- 2,300 -t-:-~ 1 F (6,000) (6,000) 4,000 f ~ ~ ~ _..,.. _,..,- ~l~~LING STATION FCV E.L~6~2~1~.0~~"~.... -- 3-47E862-1,G6/ 6141~rc~n?~ i-RICU ~ '-1.!0_I_\\. 8 I EXHAUST FANS =:i:': ~~.,~- 6~ 0 -7 "l l ~ x SAW'LING 2 ¥ 3e-33 co 01 I__.,- ~ r-. T STATION~ I -;::~:i:;J:,.--, O r;;/ J o 3-- o nr8 ~ I~ I (,,11 64-~6 ~ CONT ON 3-47E844-2, G7 1 50 CF" @ I" P COMPRESSOR 50 PSIG CMP-64-142 STEAM _ _TRAP STN-64-735 _ _ NOTES: 574 TRP-64-736 N r;; -b-47E852-2, ES '), DET 3A12 C2 571 573 ~ - ~ (;\\ 64-143

1. FOR GENERAL NOTES AND REFERENCE DRAWINGS SEE 0-47E865-2.

2. ALL INSTRUMENTS ARE PREFIXED "3-* UNLESS OTHERWISE NOTED.

3. ALL VALVES ARE PREFIXED "3-64-" UNLESS OTHERWISE NOTED.

4. DAMPER NOT OPERABLE, SEE 3-47E610-64-1.

5. AIR QUANTITIES SHOWN IN PARENTHESES (9,000) ARE NOT NORMALLY CIRCULATED. THESE BRANCHES MAY BE ALIGNED FOR AUGMENTED VENTILATION ON THE DRYER/SEPARATOR POOL OR THE REACTOR CAVITY. WHEN USED. ANY DESIRED FLOW THROUGH THESE BRANCHES SHOULD BE SUBTRACTED FROM THE REMAINING BRANCHES.

6. REACTOR WATER LEVEL REFERENCE LEGS (SYS 003; DWG 3-47E803-5)

FROM REACTOR NOZZLE N128 PENETRATE THE DRYWELL THROUGH THE 18" CONTAINMENT PURGE LINE AT X26 AND PENETRATE THE PURGE LINE AT THE POINT INDICATED.

7. VENT, DRAIN AND TEST CONNECTIONS 1-1/2" ANO BELOW CAN BE PROVIDED WITH PIPE CAPS OR HOSE CONNECTION FITTINGS WHERE REQUIRED BY PLANT PERSONNEL.

THIS CONFIGURATION 15 SUPPORTED BY ENGINEERING CALCULATION CD-Q0999-923399.

8. A SPECIFIC AIR FLOW RATE IS NOT REQUIRED THROUGH THE BRANCH LINE DUCT.

THE ONLY CONCERN IS THAT THE REQUIRED FLOW RATE 15 DELIVERED THROUGH THE MAIN DUCTWORK.

9. ALL VALVES IDENTIFIED AS *rev" HAVE VALVE OPERATORS.

THE MEL UNID FOR THE VALVE OPERATOR IS DEVELOPED AS FOLLOWS: VALVE DRAWING UNIO FCV-64-17 VALVE OPERATOR *EL UNID 3-WOP-064-0017

10. WITH THE REACTOR ZONE EXHAUST FANS OPERATING IN FAST SPEED AND WITH THE MAIN STEAM VAULT EXHAUST BOOSTER FAN RUNNING, EXHAUST FLOW FROM THE VAULT WILL BE APPROXIMATELY 11,000 CFM.

WITH REACTOR ZONE EXHAUST FANS OFF ANO THE MAIN STEAM VAULT EXHAUST BOOSTER FAN RUNNING. FLOW FROM THE VAULT WILL BE APPROXIMATELY 9,000 CFM. WITH REACTOR ZONE EXHAUST FANS IN SLOW SPEED. THE MAIN STEAM VAULT EXHAUST BOOSTER FAN SHOULD BE TURNED OFF TO AVOID BACK FLOW INTO THE REACTOR BUILDING LOWER LEVEL VENTILATION DUCTWORK.

11. THE 6" FLANGE COVER AND TEST PLUG SHALL BE INSTALLED ON OW PENETRATION X-48 DURING NORMAL OPERATIONS.

, 2. A SET OF ACCELEROMETERS MAY BE MOUNTED ONTO THE INNER PILLOW BLOCK BEARINGS FOR THE RHR & CS ROOM COOLERS, 3-CLR-64-68, -69,-70,-71,-72 & -73. EACH SET MAY CONSIST OF THREE ACCELER-OMETERS (CTC AC102-1A. IMI 608A11. OR EQUAL) CONNECTED TO THE BEARING TO PROVIDE INDEPENDENT THREE-AXIS ACCELERATION DATA. THE ACCELEROMETERS ARE ALLOWED TO BE ATTACHED TO THE BEARINGS BY MEANS OF AN INSTALLATION STUD (1/4" DIA. MAX) SET INTO A DRILLED AND TAPPED HOLE. THE MAXIMUM bEPTH OF THE HOLE IS THE DIAMETER OF THE STUD. HOLE LOCATIONS (IN THE BEARINGS) SHALL BE APPROVED BY CIVIL ENGINEERING OR PREDICTIVE MAINTE-NANCE WITHIN IMPLEMENTING DOCUMENTS. A CABLE (CTC C8111-A2A-006-Z, OR EQUAL) FOR EACH AXIS MAY BE INSTALLED TO CARRY DATA FROM THE ACCELEROMETERS TO BULKHEAD CONNECTORS (CTC CB910-2A, OR EQUAL). THE BULKHEAD CONNECTORS ARE ALLOWED TO BE IN-STALLED IN THE OUTER SHEET METAL OF THE COOLER AND LABELED TO INDICATE AXIS ANO BEARING APPLICABILITY. CABLES BETWEEN THE CONNECTORS AND THE ACCELEROMETERS SHALL BE SECURED TO THE INTERNAL FRAMING OR SHEET METAL OF THE COOLERS WITH CABLE TIE WRAPS, MOUNTING EYELETS. MOUNTING CRADLES OR MOUNTING SADDLES (McMASTER CARR 7130K55. 7566K28. 7566K13. ALL ITEMS OR EQUAL) TO ENSURE THAT NO INTERACTION CAN OCCUR BETWEEN THE CABLES AND THE ROTATING ELEMENTS OF THE COOLERS. MAXIMUM SPACING ON ATTACHMENT POINTS WILL BE 18 INCHES. EXCESS CABLE LENGTH SHALL BE COILED ANO SECURED AT THE BULKHEAD CONNECTOR ENO OF THE CABLE WITH ADDITIONAL CABLE TIE WRAPS. REFERENCE EDC 69350A. TO UNIT 2 HEATING AND OPEN I "e !;:,J, / 051 / ~51 / "'51 / ~51 EQUIPMENT _L 3,650-tf,-~,- ~ HATCH ~/ 750--,- HEPA \\ '/ 711 / ~ /~ I I I I ~ VENTILATION SYSTEM -l-----ia~12-47E2865-12,0~ I ~ ~-FRCM 3-FCV-76-19 3-47E860-1, E5 2" 215 , /2. L-,j)CXJ---':.=.-{~POT r 4-20 216 1/2' f-,j)CX]---':.::.-1,POT 4-21 ,cEL 565.0 l F ~,-60_7 __ F ---..:.; FRCM CONTAINMENT

---

/

ATMOSPHERE 606 DILUTION SYSTEM NOTE 13 F IF EL 621 0 lt)/F T FILTER\\L...TEST PORT F F F F F F F F ~E!,_L_l6~2~1c_,!'_0~~=========1 -< t,_ l6o8* ~762~6~---.-~~~* -1621 FLT 30-102 620 I/5,, /505 {6~1~1----(6-22--~-1624 / 6-2_3 ___ { 6-25_____ r----l, -J'-, 4,650 2,450-t-l-,- I 706 t 5,300 ......,6"'5"0----,------------------------,,,,.,.+--' ""---1, -J'- 4

• 650 2
• 450 -t-I--._ -

RICU RECIRCN r" I 722 0 707 PUMP ROOM [ FROM 3-73-620 -t-1--......- L-( 3-47E862-1.H5 I ot--/\\--t:+4,650 I 2,450--/'-l-7~- -t" I ~/ } -t--:1,800 .. 1...... ----------<Q-47E812-1. "I 3,150 {- ~ ~ It) "r "r "T co Ji u.. 0 RICU HEAT r-. I 2,350 ,n 2,350 2,350 EXCH ROClt / :! 1i-,- ~~ I EQUIPMENT RICU BACKWASH PUMP ROOM -g 0. m

13. THE UNIT 3 REACTOR BUILDING EQUIPMENT HATCHES AT ALL ELEVATIONS SHALL BE COMPLETELY OPEN DURING OPERATION Of UNIT 3 IN MODES 1. 2 AND 3. ANY TEMPORARY COVER PLACED OVER A UNIT 3 EQUIPMENT HATCH WHEN OPERATING IN MODES 1, 2 OR 3 SHALL BE ELEVATED OVER THE HATCH HIGH ENOUGH TO PROVIDE AN AIR FLOW AREA EQUAL TO OR GREATER THAN THE AREA Of THE EQUIPMENT HATCH BEING COVERED. IN MODES 4 ANO 5. ANY UNIT 3 REACTOR BUILDING EQUIPMENT HATCH CAN BE PARTIALLY CLOSED

(*.,.INSTALLATION Of 3 REMOVABLE EQUIPMENT HATCH COVER PANELS). A MIN MUM OPENING OF 60 SQUARE FEET JS REQUIRED TO SUPPORT THE COMBINED ZONE SECONDARY CONTAINMENT SYSTEM IN MODES 4 AND 5.

14. STRAP ON T/C DUAL ELEMENT TEMPERATURE SENSOR.

15. THE RADIATION DETECTOR (RE) IS LOCATED ON THE HCVS PIPING ANO DOES NOT PENETRATE THE PIPING.

DET 3B12 86 T ~ ~ "\\ O ~:~ =RCN -~ ~:~ =~*ASH 544 n OPEN ......... -..----*/ / _) -t-1,800 1,700-+- / ~ y 7,000 ~ "' HATCH 536 /- ~ Tr' T T ",r ~ /F -t-- f-F NOTE 13 EL 593.0 JL _l1 F F F EL 593.0 601 +i 600 ~-2-.-50_0_-t-~~1--N-....... ~---~-0-4--l--,c-'hc....,~2~.~50~0-1.. 6_0"'2""""-------"'7....,7"'00._ ____________ \\.... _______________

• ___________,_*_'_"" __ 1._.~,-5~---------ll6-0-3--t--'2'-':----l6_0-_4~~~~~~~~~~~~-,0-E_T_3_A_12_(_G_1)~

UNIT SEPARATION NOTE: 6003 7

• ooo

-t-5. 950 E J a / Ill / I TO 3-FCV-84-19 POI 600.! -t-r l--tl-t-5, 950 mr1~ !~~ 2~, ~~~~V-76_18 TEMPORARY DUCT CONNECTION~ 3_47E862_1,F7~1-...... X r l}:4c_ 141 ~,.,.: 64_22

--,i/TO AIR WASHER 7,000 8

......(;;', ::J.i'.'.'.:~ ~l.r.,_. ~ 3_47E860_1, ES PUMP A -+-.. 30,000-, m

zLiJ:zn('.I

"':::":;::::::::;--""'.r--------*'5*'*6*5*0---------------r----------------I--------------"""--:----------:--:~~~-----.. ~ INDICATES SEISMIC MARKUP t!:.I BOUNDARY LEGEND FE co *8~2::ii:: ~......... )- l I 'Hs' ~ ~716-2~/ ~76-26 ~ 2i~3~~ 511 ETAIL 3C12 (G7) DETAIL 3012 (G5) 135 0 ~ 1-----'2~*.... -..- ' ~----....,' OET 3A12 (G1) 1---.J HS 1 N N ~>-->- 0 /'. \\ / '\\ ~:.#1'\\/'II-0 FC X LU ~-------~ I I 6t:_;5A rs5n~~, 543 Ji FT J, lL<OII?,... ~ 3-47E862~ \\E71 / DRYWELL C - "

• ,,* PM 64-33

~ I I r -, 703 ~~ ! 65-0205._ ~ ~ t : "ATCH x 3 )' ~I SEE DETAIL OA15 i AIR....... -! I ~I~i7) \\ \\_,. '-....,.-=~ -I FAN 135 f'...t-'-'--t----.....--.. 3/4' ~ [;; / 64-23A o-47E555-15,o7 (rec\\ ~ EXTRACTOR ~CV....1 549 l FROM CAD NITROGEN / _~-- 137 513 PHYSICAL BARRIER OR BOUNDARY BETWEEN UNITS COMPANION DRAWINGS: 0-47E865-2.-4 THRU 1-47E865-1,-3 2-47E865-3, -13 3-47E865-3,-8,-10 / (i"'DCO' FAN 64 64-38 FCV 64-19 FCV :,_ FCV 514 I VALVE TANK A 6" T.I.P, o MATCH X FCV o c::-,_ X~ PRESSURE RELIEF O f ~ S{a!-A 38 - - 'g' 64 6A 8 ~7 64_2,); ~ 6b8 3" SROOMYSTEM ! ~- I g~~!i,! LINE A (A2) / ;J. 64_3 ~ m / '*-. ~i,-, 64~;.!'..e !- & ~~~~s~:~:IS~f~iION 'Eiu ~02. ---A_

• ~

NOTE 11 I ~-48 I "7. "r co J.::* 2" r;; // t o 'A 'Ii( S3YS47TEE"8632-T, WF-584,31 ---t I 11 / ~ /-/ i".: ../ / "':;: ! } \\ / -'-- 1-7~ w-?_21--1 __,,_ ' J +j ~ -t-11 @. ~AN-64-y, ~!Ail'}- x - OET ;F;2 '~~,. ~o~ -+- ~II i1~~L <fl"' A ., ~.Y ~~: ~l5tf"" ll ~

o

"' ;,r;,, EL 565.o 561 / ;:; i ( ~ ! :{ (Qr x SEE ~DTE 4 rr, ~~~~u~~wo> g~i 11 L [.':~,

l 552

- i,.,;;2,;., 6:, 5:"=j1~~-L Q(-~L=-s;~;~::~::::::::::::::::~::---.~~?"<:;,:~:*:* =.;-~-:_:_:_:_~-::-~-... -~-_,,,,.*..,,,,-_______________ JL ______..J..C.:,=..:.:.:::..: __ JL ____________ 5_,_2_00- ~~~~ ~OOMcoRE SPRAY A/c ~ / ~ ;:::! I O .Cl 'I (C8) 3/4" I" i \\ UNIT 8 - CORE SPRAY 8/0 ANO,>-- ( / ~ 8 _j REFUELING FLOOR FCO x AIR COOLING UNITS 4-46 I CRD PUMP ROOM _J

r SUPPLY FANS 4-1 g

A (ACU-64-68) / {- o - -2" / "'!'.l AIR COOLING UNITS rn / rn "z ill< CONE ON STANDBY) \\.,,-,.... 0 I C (ACU-64-70) A ~£~~-~4-55 1 ~ 8 ~., A (ACU-64-72) l'.t:: / l'.t:: 'Pnr.n\\ (NOTE 8) - 7 ( HS\\ g 8 (ACU-64-73) ~/~ := iS (rec\\ 141o/ X en 64-68,70 loo... co LT 212 214 LT lo FROMCADNITROGENPRESSURE (NOTES)---....,. §/~ ; f --4 ~ 6i: ~i,~~ \\ Q }TL~---~-, {-~ ~ s~_,,1t::.l.,fI:::L:-::J.,,c,,12 64-159A-

• ~ :

64:!_598 ""'<"--::~~lZpl~t~ ~r 12 ~ ! ..}- ~ t--R-E-<LI3E~4,v;~6V2E-,T,A;; B ~ rn~:=;~i_! 0 ) ~ ~ ~ "-. ~ -....""7.) X COOLING COILS ~ "\\ 64~ 71 210A ~ ~ ~ FCV\\'- I I C/ / Z O 'fl+. ~ x x ~~ii lleccLR-S4-s19) x2090 1 1.. r 112.. ~ 8A\\ \\1-x112- ~MATCH I KNMOTOR --!'-/ t-t- .......... § Q D CCLR-64-71 l

• 7 \\.____.....

ML 1,x2060 Ml-LINE A CFAN-64_72 > 5,000 -+- / ~ 6l4-2 ~¥.t FCO ~~ :: e -..t-:- \\_ r.---------*--1 L1" -X205

• -+-

6:1-.~20A\\-112*~* 4-: *JX 31 5~9A :r:12* C (A7) I 8 (FAN-64-73)- / ~ t FCO 64-14AAB mo FAN* I I~ frs\\.J ~\\ \\. I M~ r \\. ( 5.ooo)( J><;O C Ml-I 8~H a rn:988 g~~ J O 'E( 64-13A&B~ ~~ MOTOR l...AIR COOLING 64~71 1 xs.OOO) 73-221A ~ ~ 208A 1"... / FAN-4-128 ~ RMS ~~,..., ~ UNITS ~ ""--..::::;__,~---~,~.- _______..::::, _ _,.~ (LE\\ri:O:J---PXl>I-' {HS\\__ ~ l,....__..___.. l / RMS

c::c

'---8 (ACU-64-69) ( TS \\._.J (LE\\ rJ??,)---1?,?,1:,t..l ~ ~ 64-66 683 675- _) 64-72. 73 ---,- SUMP VENT / l~TS REACTOR ZONE ~~ 0 (ACU-64-71) 64-68. 70 PDT 64-54 685. 679 . Ft-I FILTER MATCH LINE t CORE t ,( I TS 1 SUPPLY FANS

ii:!

8 (FAN-S4-59 l J (TS\\ IEAST_)---;A,-J.;B:::3l SPRAY D (FAN-64-71) 64-137 211 213 2,650 ONLY 6~-2,38 (ONE ON STANDBY) ~ y __J 1 l PLIIP ,, 1 ~ 1

• 1-2" OE"INERALIZEO 1 "-

64:-72, 73 y .---,,MOTORSc.__-, 1 ,._SEE DETAIL OA15 SUMP VENT 1 DEMINERALIZEO "f-j:o(]--{:i:,~f-' 1 3-47E865-15.07 FILTER EAST 4 000 WATER WATER 1-684 676-HPCI SYSTEM 64-2'8 ___., /TO AIR WASHER & WEST RHR I ) 1' 686 680 I 3-47E856-2) t:1 t:""'- ROOM T 5 000 f PU"P 8 PUMP ROCM co 3-47E856-2 -~*.=4-I " 'Ill"...,. co L______ 681 682 EL 519.0 677 678 EL 519.0 8 I

• --~~';;.l~I LS-73-57A, LS-73-578 su*~

RHR PUMP MOTORS "2'-"--< 3-47E812-1 Cs'>--'~"~2~*------~ 7 I 6 I 5 t 4 I SUMP I 3 -9.-11.-15.-16 AMENDMENT 28 POWERHOUSE UNIT 3 - REACTOR BUILDING BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT HEATING AND VENTILATION FLOW DIAGRAM FIGURE 5.3-3d H G F E D C B A

BFN-16 Figure 5.3-4 Deleted by Amendment 9

• Flexible C

... iai onnec.. I J '-~-- I .d ,JJ, q ... I"'."!. -- i p, A I - \\ i l I 1 ~ j I> A I> t> t> p -q ~, V J I G k t (T:fp ) e.s *

Bolted FJ.a:cge (Tn.)

~ I I Jn 1----* *-- "~ ~ -* I r~ D ~ I c__ ( r I --- I I ~. T I 1 I ',nm ble ction come l I AMENDMENT 16 BROWNS FERRY NUCLEAR PLANT Fl NAL SAFETY ANALYSIS REPORT Secondary Containment Typical Duct Penetration

• Figuu 5.3-5

BFN-16 Figures 5.3-6 through 5.3-8 Deleted by Amendment 7.

E=:J-- ! ':I ~" ~ _________________________ i AMENDMENT 23 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT SHNDSYGASTREATMENTSYSTEM f.lECHAN!CALCONTROLDIAGRAM FIGURE 5.3-9 C

AMENDMENT 16 BROWNS FERRY NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT BROWNS FERRY PURGE SYSTIM FIGURE S.3-10 FkOM 1 2 SUPPLY / 76-24 Q 64-19/ /64-18 20* ,a* 1911 DRYWELL SUPPRESSION CHAMBER \\ 64-29 lr-~ 'L,.~*- f wm,,~, \\ 64-33 I \\ 64-32 18"}}