ML22278A225
| ML22278A225 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 09/19/2022 |
| From: | Constellation Energy Generation |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML22278A223 | List:
|
| References | |
| Download: ML22278A225 (202) | |
Text
LGS UFSAR CHAPTER 6 - ENGINEERED SAFETY FEATURES
6.0 INTRODUCTION
Engineered safety features are provided to mitigate the consequences of postulated serious accidents, even though these accidents are very unlikely. The following ESFs are discussed in this chapter:
- a. Containment systems (Section 6.2)
- 3. Containment heat removal system
- 4. Containment isolation system
- 5. Containment atmospheric control system
- b. ECCS (Section 6.3)
- 1. HPCI system
- 2. ADS
- 3. Core spray system
- 4. LPCI system
- c. Control room habitability system (Section 6.4)
- d. Fission product removal and control systems (Section 6.5)
In addition to the ESFs discussed in this chapter, other ESF systems discussed elsewhere are provided to limit the consequences of postulated accidents. The ESF systems are described in the sections of Chapter 6 and those sections referenced in Table 6.1-1; therefore, no optional sections are required.
The information provided herein demonstrates the following:
- a. The concepts on which the operation of each system is predicated have been proven by tests under simulated accident conditions and/or by conservative extrapolations from present knowledge and experience.
- b. Component reliability, system interdependency, redundancy, and separation of components or portions of systems, etc., ensure that the ESF accomplishes its intended purpose and functions for the period required.
- c. Provisions for testing, inspection, and surveillance are made to ensure that the ESF is dependable and effective on demand.
- d. The material used can withstand the postulated accident environment, including radiation levels, and the radiolytic decomposition products that may occur cannot interfere with any ESF.
CHAPTER 06 6.0-1 REV. 13, SEPTEMBER 2006
LGS UFSAR 6.1 ENGINEERED SAFETY FEATURE MATERIALS The materials used in the LGS ESF systems have been selected on the basis of an engineering review and evaluation for compatibility with:
- a. The normal and accident service conditions of the ESF system
- b. The normal and accident environmental conditions associated with the ESF system
- c. The maximum expected normal and accident radiation levels to which the ESF system will be subjected
- d. Other materials to preclude material interactions that could potentially impair the operation of the ESF systems The materials selected for the ESF systems are expected to function satisfactorily in their intended service without adverse effects on the service, performance, or operation of any ESF.
6.1.1 METALLIC MATERIALS In general, metallic materials used in ESF systems comply with the material specifications of ASME Section II. Pressure-retaining materials of the ESF systems comply with the quality requirements of their applicable quality group classification and ASME Section III classification.
Adherence to these requirements ensures that materials for the ESF systems are of the highest quality. Where it is not possible to adhere to the ASME material specifications, metallic materials have been selected in compliance with other nationally recognized standards, e.g., ASTM, where practicable, or chosen in compliance with current industry practice.
6.1.1.1 Materials Selection and Fabrication Metallic materials in ESF systems have been selected for a service life of 40 years, with due consideration of the effects of the service conditions on the properties of the material, as required by ASME Section III, Articles NB-2160, NC-2160, and ND-2160.
Pressure-retaining components are designed with appropriate corrosion allowances, considering the service conditions to which the material will be subjected, in accordance with the general requirements of ASME Section III, Articles NB-3120, NC-3120, and ND-3120.
6.1.1.1.1 NSSS Supplied Components 6.1.1.1.1.1 NSSS Material Specifications Table 6.1-2 lists the principal pressure-retaining materials and the appropriate material specifications for the NSSS supplied ESF components.
CHAPTER 06 6.1-1 REV. 20, SEPTEMBER 2020
LGS UFSAR 6.1.1.1.1.2 Compatibility of NSSS Construction Materials with Core Cooling Water and Containment Sprays Section 5.2.3.2.3 discusses compatibility of the reactor coolant with construction materials exposed to the reactor coolant. These same construction materials are found in other ESF components.
6.1.1.1.1.3 Controls for Austenitic Stainless Steel
- a. Control of the use of sensitized stainless steel Where practicable, stainless steel with a carbon content of less than 0.02% is used.
Controls to avoid severe sensitization are discussed in Section 5.2.3.4.1.1.
Compliance with Regulatory Guide 1.44 is discussed in Section 5.2.3.4.
- b. Process controls to minimize exposure to contaminants Process controls for austenitic stainless steel and compliance with Regulatory Guide 1.37 are discussed in Section 5.2.3.4.
- c. Use of cold-worked austenitic stainless steel Cold-worked austenitic stainless steel with a yield strength greater than 90,000 psi is not used in ESF systems.
- d. Avoidance of hot-cracking of stainless steel Process controls to avoid hot-cracking and compliance with Regulatory Guide 1.31 are discussed in Section 5.2.3.4.
6.1.1.1.2 Non-NSSS Supplied Components 6.1.1.1.2.1 Non-NSSS Material Specifications Material specifications for the principal pressure-retaining ferritic, austenitic, and nonferrous metals for non-NSSS supplied components are listed in Table 6.1-3.
6.1.1.1.2.2 Compatibility of Non-NSSS Construction Materials with Core Cooling Water and Containment Sprays Materials that would be exposed to the core cooling water and containment sprays if there is a LOCA are identified in Table 6.1-3. The metallic materials of the ESF systems have been evaluated for their compatibility with core cooling water and containment sprays. Demineralized water, with no additives, is employed for core cooling water and containment sprays. No radiolytic or pyrolytic decomposition of ESF material can occur during accident conditions, and the integrity of the containment or function of any other ESF cannot be affected by the action of core cooling water or containment spray systems.
CHAPTER 06 6.1-2 REV. 20, SEPTEMBER 2020
LGS UFSAR 6.1.1.1.3 Controls for Austenitic Stainless Steel
- a. Control of the use of sensitized stainless steel Design specifications call for ASME material, which is to be supplied in the solution annealed condition. Design specifications prohibit the use of materials that have been exposed to sensitizing temperatures in the range of 800F to 1500F unless they are subsequently solution annealed and water quenched or bright annealed.
Where practicable, stainless steel with a carbon content of less than 0.02% is used.
Compliance with Regulatory Guide 1.44 is discussed in Section 5.2.3.4.
- b. Process controls to minimize exposure to contaminants Design specifications for austenitic stainless steel components require that the material be cleaned using low halide cleaning solutions and that special care be exercised in the fabrication, shipment, storage, and construction to avoid contaminants. Conformance with Regulatory Guide 1.37 is discussed in Section 5.2.3.4.
- c. Use of cold-worked austenitic stainless steel Cold-worked austenitic stainless steels with yield strengths greater than 90,000 psi are not used in ESF systems. Therefore, there are no compatibility problems with core cooling water or the containment sprays.
- d. Use of nonmetallic thermal insulation for austenitic stainless steel Austenitic stainless steel piping inside the primary containment is insulated with nonmetallic thermal insulating materials. These nonmetallic insulating materials are either jacketed or encapsulated in stainless steel to protect against water entry.
(Nukon insulation is not required to be jacketed or encapsulated since it meets all G.E. specifications requirements for leachable chlorides, fluorides, sodium and silicates without jacketing.) Leachable concentrations of chlorides, fluorides, sodium, and silicates for all nonmetallic insulation on austenitic stainless steel inside the primary containment meet the positions of Regulatory Guide 1.36.
Conformance with Regulatory Guide 1.36 is discussed in Section 5.2.3.2.
- e. Avoidance of hot-cracking of stainless steel Process controls to avoid hot-cracking and compliance with Regulatory Guide 1.31 are discussed in Section 5.2.3.4.
6.1.1.2 Composition, Compatibility, and Stability of Containment and Core Spray Coolants The HPCI system is supplied from either the CST or the suppression pool. The core spray and LPCI are supplied from the suppression pool only. The containment spray mode of the RHR system, which uses the suppression pool as its source of supply, does not induce radiolytic or pyrolytic decomposition of ESF materials.
The Suppression Pool and CST water chemistry is normally maintained within the following guidelines:
CHAPTER 06 6.1-3 REV. 20, SEPTEMBER 2020
- a. pH: 5.3 to 8.6 at 25C
- b. Chloride: <0.5 ppm
- c. Conductivity: <10 mho/cm at 25C No corrosion inhibitors or other additives are present in either the CST water or the suppression pool water.
The makeup water for the SLCS (SLCS is not an ESF system but does have a safety-related function and is described in Section 9.3.5), is supplied from the demineralized water storage tank.
The makeup water for the CST is supplied from both the demineralized water storage tank and treated liquid radwaste. The makeup water to the suppression pool can be supplied from either the CST or the Refueling Water Storage Tanks. Water supplied to the demineralized water storage tank and the CST is continuously monitored by conductivity measuring devices that initiate alarms and divert flow to waste on high conductivity. Treated liquid radwaste is sampled and analyzed prior to transfer to the CST. This ensures water quality.
Chloride concentration in the SLCS tank is controlled by specifications on the sodium pentaborate and the demineralized water that is added to the tank.
Water quality is maintained in the CST by using the "A" condensate filter/demineralizer to remove impurities from the water. CST water is processed from the CST with the refueling water transfer pump and refueling water transfer system. Water quality is maintained in the suppression pool by a bleed and feed method. Water is drained from the suppression pool with the suppression pool cleanup pump. This water goes to the hotwell for cleanup with the condensate cleanup system.
Makeup water comes from the CST.
6.1.2 ORGANIC MATERIALS Tables 6.1-4 and 6.1-5, respectively, list the significant organic materials and coatings that exist within the primary containment. These materials in ESF components have been evaluated with regard to the expected service conditions and have been found to have no adverse effects on service, performance, or operation.
6.1.2.1 NSSS Supplied Components The only significant organic materials on NSSS equipment are the protective coatings used on carbon steel components. Most of the equipment is painted with a primer coat of inorganic zinc.
The quality assurance requirements in Regulatory Guide 1.54 were not imposed on painting material and paint application, because most equipment was ordered before the issuance of the guide.
Equipment specifications in place at the time of ordering much of the LGS equipment specified a primer coat of inorganic zinc. These coatings are not considered qualified under the guide because the specifications did not require the near white blasted surface needed to meet nuclear qualification.
The total amount of unqualified paint in the containment on NSSS equipment is estimated to be less than 12 kg. Equipment tightly covered with thermal insulation is not included in this total because potential paint debris could not escape to the suppression pool during a LOCA.
CHAPTER 06 6.1-4 REV. 20, SEPTEMBER 2020
LGS UFSAR 6.1.2.2 Non-NSSS Supplied Components The drywell liner is coated with modified phenolic epoxy, and exposed metal surfaces inside the drywell are coated with an inorganic zinc compound. These coatings have been qualified in accordance with ANSI N101.2. No radiolytic or pyrolytic decomposition or interaction with other ESF materials can occur.
The suppression pool liner is coated with an inorganic zinc compound that has been qualified in accordance with ANSI N101.2. Since the failure mode of inorganic zinc coatings is particulate rather then flaking in nature, this amount is not considered significant. No radiolytic or pyrolytic decomposition or interaction with other ESF materials can occur.
Non-NSSS coating practice and procedures are in conformance with ASTM D3843-93 as discussed in the Quality Assurance Topical Report (NO-AA-10).
6.1.2.3 Insoluble Debris Insoluble debris formed under DBA conditions inside containment, from unqualified organic paint surfaces and from corrosion products from galvanized steel and zinc paints without qualified organic top coats, will not adversely affect the performance of the LGS RHR or the containment spray systems which take suction from the suppression pool.
- a. The total amount of unqualified paint on both non-NSSS and NSSS supplied components has been reviewed and is summarized below. All coatings on non-NSSS equipment within the primary containment are qualified with the following exceptions:
- 1. Unqualified primers and mill coats have been applied to pipe, inside the drywell, that has insulation covering the coating. The insulation will prevent any potential debris from entering the suppression pool.
NOTE: The information presented above regarding the quality of unqualified coatings in the primary containment is historical and is based on an original design estimate and does not represent the current unqualified coatings inventory. Unqualified coatings in the primary containment are administratively controlled to ensure that the design basis limits for debris are not exceeded.
- 2. Heavy support steel in the drywell is coated with an inorganic zinc coating that passed DBA testing and is fully documented. Unqualified coatings on NSSS equipment have been reviewed and found to be less than 11.7 kg in total, as identified in Table 6.1-6. NSSS equipment has either 2-5 mils coating of inorganic zinc or 3-6 mils organic coating. The major equipment, the recirculation pump motors, have two coats of epoxy paint at 3-6 mils per coat.
- b. The following discussion explains why insoluble debris from unqualified organic paints and corrosion products from galvanized steel and zinc paints without qualified organic top coat will not adversely affect the performance of the RHR or containment spray systems.
CHAPTER 06 6.1-5 REV. 20, SEPTEMBER 2020
LGS UFSAR As discussed above, the only unqualified organic paints that could reach the suppression pool are on NSSS equipment. Due to the limited supply of NSSS unqualified paint noted in Table 6.1-6, it is not expected that the ECCS suction strainers would be sufficiently plugged so as to impair ECCS or containment spray performance. The redundant pair of suction strainers on each HPCI and RCIC suction line are sized to provide the design flow rate with each of the strainers 50%
plugged and are centered approximately midway between the suppression pool surface and wetwell floor. The RHR and Core Spray strainers are designed based on debris loading and zone of influence of the worst case pipe location. The suction strainers are discussed in detail in Section 6.2.2.2.
Galvanized steel and zinc paints without qualified organic top coats were used for various applications in the primary containment. The demineralized suppression pool water, which is used for containment spray, is maintained near-neutral and the containment atmosphere is inerted during plant operating conditions to reduce the corrosion of exposed galvanized steel or zinc paints to the lowest possible rate.
Typical zinc corrosion products produced in a neutral or near-neutral environment are zinc oxide and zinc carbonate. They are loosely adherent fluffy white substances. Because the zinc corrosion products are loosely adherent, they will not plug the ECCS suction strainers, containment spray nozzles, or ECCS pump seal flushing water circuits.
6.1.3 POST-ACCIDENT CHEMISTRY This section is not applicable to BWR plants.
NOTE: The information presented above regarding the quality of unqualified coatings in the primary containment is historical and is based on an original design estimate and does not represent the current unqualified coatings inventory. Unqualified coatings in the primary containment are administratively controlled to ensure that the design basis limits for debris are not exceeded.
CHAPTER 06 6.1-6 REV. 20, SEPTEMBER 2020
LGS UFSAR Table 6.1-1 ENGINEERED SAFETY FEATURES DISCUSSED IN OTHER CHAPTERS OF THE UFSAR ENGINEERED SAFETY FEATURE UFSAR LOCATION Chapter 4 Control rod velocity limiter 4.6.2 Control rod drive housing supports 4.6 Chapter 5 Overpressure protection 5.2.2 Main steam line flow restrictors 5.4.4 Main steam line isolation valves 5.4.5 Chapter 7 Instrumentation and controls for ESF systems 7.3 Chapter 8 Standby ac power system 8.3.1 Dc power system 8.3.2 Chapter 9 ESW system 9.2.2 RHRSW system 9.2.3 UHS 9.2.6 CSCWS 9.2.10 Primary containment HVAC 9.4.5 Diesel generator enclosure HVAC 9.4.6 Spray pond pump structure HVAC 9.4.7 Diesel generator systems 9.5.4-9.5.8 CHAPTER 06 6.1-7 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-2 NSSS SUPPLIED ENGINEERED SAFETY FEATURES COMPONENT MATERIALS SPECIFICATION COMPONENT FORM MATERIAL (ASTM/ASME)
RHR Heat Exchanger Shell, head, and Plate SA516, Grade 70 ASME channel Tube sheet Plate SA516, Grade 70 ASME Nozzles Forging SA105-II (Unit 2) ASME SA105 (Unit 1)
Flanges Forging SA105-II (Unit 2) ASME SA105 (Unit 1)
Tubes Tube SA249, Type 304L (Unit 2A) ASME SB676, Type AL-6XN (Unit 1 and Unit 2B)
Bolts Bar SA193, Grade B7 ASME Nuts Forging SA194, Grade 2H ASME RHR and CS Pumps Bowl Casting A536, Grade 65-45-12 ASTM Discharge head shell Plate A516, Grade 70 ASTM Discharge head cover Plate A516, Grade 70 ASTM Suction barrel shell Plate A516, Grade 70 ASTM and dished head Suction flange Forging A516, Grade 70 ASTM Discharge flange Forging A350, LF1 or LF2 ASTM Shaft Bar A276, Type 410 ASTM Impeller Forging A296, CA15 ASTM Studs Bolting A193, Grade B7 ASTM Nuts Nut A194, Grade 7 ASTM Cyclone separator A351, Grade CF8M ASTM body and cover CHAPTER 06 6.1-8 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.1-2 (Cont'd)
SPECIFICATION COMPONENT FORM MATERIAL (ASTM/ASME)
HPCI Pump Case Casting A216 ASTM Bearing housing Casting A278 ASTM Impeller Casting A276 ASTM Shaft Forging A276 ASTM Studs Forging A193 ASTM SLCS Pump Fluid cylinder Forging A182, F304 ASTM Cylinder head, Plate A285, Grade C ASTM valve cover, and stuffing box flange plate Cylinder head Bar A479, Type 304A ASTM extension, valve stop, and stuffing box Stuffing box gland Bar A564, Type 630 ASTM and plungers Studs Bar A193, Grade B7 ASTM Nuts Forging A194, Grade 7 ASTM SLCS Tank Tank Plate SA240, Type 304 ASME Fittings Forging SA782, Grade F304 ASME Pipe Pipe SA312, Type 304 ASME Welds Electrodes SFA5.4 & SFA5.9, ASME Types 308,308L, 316,316L CHAPTER 06 6.1-9 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.1-2 (Cont'd)
SPECIFICATION COMPONENT FORM MATERIAL (ASTM/ASME)
Control Rod Velocity Casting A351, Grade CF8 ASTM Limiter CHAPTER 06 6.1-10 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.1-3 PRINCIPAL PRESSURE-RETAINING MATERIALS FOR ESF COMPONENTS SYSTEM/COMPONENT MATERIAL_____
Containment Systems Primary containment:
Containment walls 4000 psi concrete Drywell and suppression SA285, Grade A chamber liner(1)
Drywell head(1) SA516, Grade 60 Penetrations(1) SA333, Grade 1; A120 Equipment hatches(1) SA516, Grade 60 or 70; SA537, Grade B Personnel access SA516, Grade 60 or 70; hatches(1) SA537, Grade B Suppression vent SA333, Grade 6; downcomers(1) SA516, Grade 60 Vacuum relief valve SA105 assemblies(1)
Pressure-retaining SA194, Grade 4 or 7; bolting(1) SA320, Grade L43; SA540, Grade B23, Class 5 Flued heads SA105; SA350, Grade LF2; SA182; Grade 316, 316L Secondary containment:
Ducts A526, A527, A36 Dampers A526, A157, A36 CHAPTER 06 6.1-11 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-3 (Cont'd)
SYSTEM/COMPONENT MATERIAL_____
Containment heat removal system:
Equipment(1) (2)
Piping(1) SA106, Grade B; SA155, Grade KC-70, Class 1; SA155, Grade C55, Class 1; SA53, Grade B Valves(1) SA216, Grade WCB; SA105 Pressure-retaining SA193, Grade B7; bolting(1) SA194, Grade 2H Welding material(1) E70-S2, E7018, E7016 Containment isolation system:
Valves(1) SA351, Grade CF8M; SA182, Grade F316; SA352, Grade LCB; SA350, Grade LF2; SA216, Grade WCB; SA182, Grade F316L; SA105 Pressure-retaining SA193, Grade B7; bolting(1) SA194, Grade 2H Welding material(1) E70-S2, E7018, E7016, ER308, ER308L, ER316, E308-16, E308L-16, E316-16 Combustible gas control system:
Piping SA106, Grade B; SA155, Grade KC-70, Class 1; SA358, Type 304, Class 1; SA312, Type 304; SA376, Type 304 Valves SA216, Grade WCB; SA105; SA351, Grade CF8M; SA182, Grade F316 CHAPTER 06 6.1-12 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-3 (Cont'd)
SYSTEM/COMPONENT MATERIAL_____
Recombiner SA182, SA240, SA312 or SA376 Blower SA234 WPB CS Pressure-retaining SA193, Grade B7; bolting SA194, Grade 2H Welding material E70-S2, E7018, E7016, ER308, ER308L, ER316, E308-16, E308L-16, E316-16 Emergency Core Cooling Systems HPCI:
Equipment(1) (2)
Piping(1) SA106, Grade B; SA155, Grade KC-70, Class 1; SA106, Grade C; A155, Grade KC-70 or KC-65 Class II Valves(1) SA216, Grade WCB SA105; A216, Grade WCB; A105 Pressure-retaining A193, Grade B7; bolting(1) SA193, Grade B7; SA194, Grade 2H; A194, Grade 2H Welding materials(1) E70-S2, E7018, E7016 Core spray:
Equipment(1) (2)
Piping(1) SA106, Grade B; SA155, Grade KC-70, Class 1; SA106, Grade C; SA312, Type 316L; SA333, Grade 6; A358, Type 304, Class II; A376 or A312, Type 304 SA358, Type 316L, Class 1 with 0.02% C max CHAPTER 06 6.1-13 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-3 (Cont'd)
SYSTEM/COMPONENT MATERIAL_____
Valves(1) SA351, Grade CF8M; SA182, Grade F316; SA352, Grade LCB; SA350, Grade LF2; SA216, Grade WCB; SA105; A216, Grade WCB; A105 Pressure-retaining SA193, Grade B7; bolting(1) SA194, Grade 2H Welding materials(1) E70-S2, E7018, E7016, ER308, ER308L, ER316, E308-16, E308L-16, E316-16 LPCI:
Equipment(1) (2)
Piping(1) SA358, Type 316L, Class 1 with 0.02% C max.;
SA358, Type 304, Class 1; SA312, Type 304; SA376, Type 304; SA333, Grade 6; SA106, Grade B; SA155, Grade KC-70, Class 1; SA155, Grade C55, Class 1; SA53, Grade B Valves(1) SA351, Grade CF8M; SA182, Grade F316; SA352, Grade LCB; SA350, Grade LF2, SA216, Grade WCB; SA105 Pressure-retaining SA193, Grade B7; bolting(1) SA194, Grade 2H CHAPTER 06 6.1-14 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-3 (Cont'd)
SYSTEM/COMPONENT MATERIAL_____
Welding materials(1) E70-S2, E7018, E7016, ER308, ER308L, ER316, E308-16, E308L-16, E316-16 ADS:
Piping(1) SA106, Grade B Pressure-retaining SA193, Grade B7 bolting(1)
Welding materials(1) E70-S2, E7018, E7016 Control Room Habitability System Blowers A283; B26 Alloy 356 Dampers A36; A526; A527 Ducts A526; A527; A36 Housing A36 Fission Product Removal and Control Systems SGTS:
Ducts A526; A527; A36 Housing A36 Valves A36; A516, Type 304 Dampers A526; A151, 1008/1018 Blowers A283; A242 Pressure-retaining A307-74 bolting Welding materials E70-S3, E70-S6 CREFAS:
Ducts A526; A527; A36 Dampers A526; A527; A36 CHAPTER 06 6.1-15 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-3 (Cont'd)
SYSTEM/COMPONENT MATERIAL_____
Housing A36; A240, Type 304; A193-87; A193-88; A276, Type 304; A312, Type 304; A182, Type 304 Blower A283; B26 Alloy RERS:
Ducts A526; A527; A36 Dampers A526; A527, A36 Housing A36; A240, Type 304; A193-87; A193-88; A276, Type 304; A312, Type 304; A182, Type 304 Blower A283; B26 Alloy 356 A108, Grade 1040; A575; A510, Grade 1010; A569; B209 Alloy 6061; A307 (1)
Material may be subjected to containment spray or core cooling water if there is a LOCA.
(2)
See Table 6.1-2 for material designations.
CHAPTER 06 6.1-16 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-4 ORGANIC MATERIALS WITHIN THE PRIMARY CONTAINMENT MATERIAL USE QUANTITY Kerite Type FR-HT/ Low voltage electrical Throughout Kerite Type FR power cable jacketing drywell and insulation material EPR/hypalon Medium voltage electrical Throughout power cable jacketing drywell and insulation material XLPE Instrumentation cable Throughout insulation/jacketing drywell material XLPE/neoprene Instrumentation cable Throughout insulation/jacketing drywell material Cross-linked Instrumentation coaxial Throughout polyolefin/ and triaxial insulation/ drywell alkaneimide jacketing material polymer Lube oil Reactor recirculation 120 gal pump motor (two motors per per unit unit)
Gear lube Valve motor operators 206 lbs per unit Silicone rubber Drywell duct-work and Throughout damper gaskets and drywell seals Cross-linked 480VAC and 120VAC outage Throughout polyethylene/ power cable insulation/ drywell chlorinated jacketing material (396 lbs polyethylene per Unit)
Cross-linked Armored coaxial cable Throughout polyethylene for video signals from drywell (XLPE) and drywell video cameras, polyvinyl also armored chloride (PVC) multiconductor cable for drywell video camera control and audio signals.
XLPE is used as insulating material, PVC as jacketing material.
CHAPTER 06 6.1-17 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-5 COATINGS USED INSIDE THE PRIMARY CONTAINMENT COATING TYPE INITIAL APPLICATION TOTAL COATING Special Mfr Std Total Film Shop Field THICKNESS AFTER (1)
CATEGORY ITEM DESCRIPTION Coating Coating Uncoated GENERIC TYPE Thickness Applied Applied 40 YEARS Carbon Containment dome X Modified phenolic 8-12 mils X 8-12 mils Steel epoxy Liner Plate Containment walls X Modified phenolic 8-12 mils X 8-12 mils epoxy Containment floor X Modified phenolic 8-12 mils X 8-12 mils epoxy Suppression chamber X Inorganic zinc 6-8 mils X 6-8 mils Structural Heavy support steel X Inorganic zinc 3-5 mils X 3-5 mils Steel Miscellaneous steel X Inorganic zinc 3-5 mils X 3-5 mils (3)
Handrails and gratings Exposed surface of X Inorganic zinc 3-5 mils X 3-5 mils steel inserts Hatches (equipment X Modified phenolic 8-10 mils X or X 8-10 mils and personnel) epoxy Steel Downcomer caps X Modified phenolic 8-12 mils X 8-12 mils Tubes epoxy Carbon Uninsulated X Inorganic zinc 3-5 mils X 3-5 mils Steel silicate Pipe Valve 2 inches and smaller X Inorganic zinc 3+/-0.5 mils X 3+/-0.5 mils Operators silicate CHAPTER 06 6.1-18 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-5 (Cont'd)
COATING TYPE INITIAL APPLICATION TOTAL COATING Special Mfr Std Total Film Shop Field THICKNESS AFTER CATEGORY ITEM DESCRIPTION Coating Coating Uncoated GENERIC TYPE(1) Thickness Applied Applied 40 YEARS 21/2 inches and X Epoxy polyamide 4.5 mils X 4.5 mils larger or modified epoxy (total) total phenolic inorganic zinc silicate Valves(7) 2 inches and smaller X Inorganic zinc 3-5 mils X 3-5 mils silicate Pipe Hangers 21/2 inches and X Inorganic zinc 3 mils X 3 mils larger 2 inches and smaller X Inorganic zinc 3 mils X 3 mils (5)
Mechanical Reactor recirculation Equipment pump Reactor recirculation X Modified phenolic 8-12 mils X 16-20 mils pump motor epoxy Fan cabinet X Epoxy polyamide or 7 mils X 7 mils (carbon steel) modified phenolic (minimum) (minimum) epoxy Fan housing X Primer: inorganic 7 mils X 11 mils zinc; finish:
Phenoline 305 (3)
HVAC ducts Concrete(2) RPV concrete X Sand-filled epoxy 65-250 mils X 65-250 mils and Masonry pedestal surfacing CHAPTER 06 6.1-19 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-5 (Cont'd)
COATING TYPE INITIAL APPLICATION TOTAL COATING Special Mfr Std Total Film Shop Field THICKNESS AFTER CATEGORY ITEM DESCRIPTION Coating Coating Uncoated GENERIC TYPE Thickness Applied Applied 40 YEARS (4)
Electrical Terminal and junction Equipment boxes(8)
(4)
Cable trays (4)
Conduits (4)
Cables (1)
Generic coating systems acceptable for containment use have been selected from suppliers who are prequalified to project standards and test criteria. Systems other than those listed are acceptable for specific units based on analysis of requirements.
(2)
Concrete coating limited to minimum area required for decontamination purposes.
(3)
No coating needed since material is galvanized.
(4)
No coating needed since aluminum is used.
(5)
No coating needed since material is stainless steel.
(6)
Cables are insulated (EPR insulation and polyolefin insulation).
(7)
Exterior coating system is identical to the pipe system in which the valve is installed.
(8)
Bakelite is used inside terminal boxes.
CHAPTER 06 6.1-20 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.1-6 ESTIMATED WEIGHT OF UNQUALIFIED PAINT ON NSSS CONTAINMENT EQUIPMENT COMPONENT WEIGHT (lbs)
Nuclear Boiler System 3.8 Reactor Recirculation System 6.9 CRD System 6.7 In-Vessel Service Equipment <0.1 Under-Vessel Servicing Equipment 6.0 RWCU System <0.4 RWCU Filter/Demineralizer System 1.9 TOTAL 25.8 (11.7 kg)
NOTE: The information presented above regarding the quality of unqualified coatings in the primary containment is historical and is based on an original design estimate and does not present the current unqualified coatings inventory. Unqualified coatings in the primary containment are administratively controlled to ensure that the design basis limits for debris are not exceeded.
CHAPTER 06 6.1-21 REV. 13, SEPTEMBER 2006
LGS UFSAR 6.2 CONTAINMENT SYSTEMS 6.2.1 CONTAINMENT FUNCTIONAL DESIGN 6.2.1.1 Pressure-Suppression Containment 6.2.1.1.1 Design Bases The pressure-suppression containment system is designed to have the following functional capabilities:
- a. The containment has the capability to maintain its functional integrity during and following the peak transient pressures and temperatures which would occur following any postulated LOCA. The design basis LOCA includes the worst single active failure (which leads to maximum containment pressure and temperature) and is further postulated to occur simultaneously with LOOP and a SSE. A discussion of the LOCA events is contained in Section 6.2.1.1.3.3.
- b. The containment, in combination with other accident mitigation systems, limits fission product leakage during and following the postulated DBA to values less than leakage rates that would result in offsite doses greater than those set forth in 10CFR50.67.
- c. The containment system can withstand coincident fluid jet forces associated with the flow from the postulated rupture of any pipe within the containment.
- d. The containment is designed to accommodate flooding up to the refueling floor elevation to permit removal of fuel assemblies from the reactor core after the postulated LOCA.
- e. The containment system is protected from and designed to withstand missiles from internal sources and excessive motion of pipes that could directly or indirectly endanger the integrity of the containment.
- f. The containment system provides the means to channel the flow from postulated pipe ruptures in the drywell to the pressure-suppression pool.
- g. The containment system is designed to allow for periodically conducted tests at the peak pressure calculated to result from the postulated DBA in order to confirm the leak-tight integrity of the containment and its penetrations.
- h. The containment system is provided with pressure relief capability for use following a postulated accident accompanied by the loss of containment heat removal capability when high containment radiation levels do not exist.
6.2.1.1.2 Design Features Section 3.8 describes the design features of the containment structure and internal structures.
Figures 3.8-1 through 3.8-8 show the general arrangement of the containment and internal structures.
CHAPTER 06 6.2-1 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.1.1.2.1 Protection from Dynamic Effects The containment structure and ESF system functions are protected from dynamic effects of postulated accidents as described in Sections 3.5 and 3.6.
6.2.1.1.2.2 Codes, Standards, and Guides Table 3.8-1 lists the applicable codes, standards, guides, and specifications for the containment structure and internal structures.
6.2.1.1.2.3 Functional Capability Tests The functional capability of the containment structure is verified by:
- a. Pressure testing the containment structure to 1.15 times the design pressure as required by Regulatory Guide 1.18 (Rev 1), and
- b. Leak rate testing the containment structure to the design accident pressure as required by 10CFR50, Appendix J.
Refer to Sections 3.8.1.7, 3.8.2.7, 3.8.3.7, and 6.2.6 for a description of the structural integrity test and the integrated leak rate test.
6.2.1.1.2.4 External Pressure Loading Conditions The containment structure is designed for an external to internal differential pressure of 5 psid.
6.2.1.1.2.5 Trapped Water that Cannot Return to Containment Sump Not applicable to pressure-suppression containment.
6.2.1.1.2.6 Containment and Subcompartment Atmosphere Sections 9.4.5 and 3.11 describe the pressure, temperature, and humidity limits within which all the Class 1E equipment located inside the containment structure is qualified to operate. Section 9.4.5 also describes the system that maintains these limits during normal plant operation.
6.2.1.1.3 Design Evaluation The information presented in this section is historical and is based on the original design basis conditions and does not represent current plant conditions or current methodology used to analyze the containment response following a LOCA. The methods and results that bound current plant conditions are described in Section 6.2.1.8. Table 6.2-4A provides the plant conditions used for the current analysis. The results presented here, however, do provide the basis for determining which events are limiting. They also demonstrate the relationship of the containment response to different input assumptions.
The limiting cases were reanalyzed in Section 6.2.1.8 for the current plant conditions using the current analysis methodology. The current reactor power and RPV pressure have been increased over the original design basis conditions. The short-term containment pressure and pool swell load response is dependent on the initial reactor pressure. The double-ended guillotine recirculation line break was reanalyzed for the current plant conditions because this break results in the limiting peak containment pressures and pool swell loads. The long-term containment pool temperature CHAPTER 06 6.2-2 REV. 21, SEPTEMBER 2022
LGS UFSAR response is dependent on the initial reactor power. Case C (loss of offsite power with no containment spray) was reanalyzed for the current plant conditions because this case results in the highest suppression pool temperature. The intermediate and small line breaks result in the highest peak drywell temperature however, these breaks were not reanalyzed at the current operating conditions. As described in Section 6.2.1.1.3.3.5.4, the limiting drywell temperature response is determined by steam enthalpy properties and is not sensitive to the increase in reactor operating pressure or power level. The main steam line break was not reanalyzed for the current plant operating conditions. The containment pressure and pool swell load response for the main steam break is bounded by the recirculation line break results. The drywell temperature response for the main steam line break is bounded by the small and intermediate line break results.
6.2.1.1.3.1 Summary Evaluation The key design values and the maximum calculated accident values of these parameters for the pressure-suppression containment are as follows:
Calculated Design Accident Parameter Value Value Drywell design pressure 55 psig 44.0 psig*
Drywell design temperature 340F 340F Suppression chamber design pressure 55 psig 30.57 psig*
Suppression chamber design temperature 220F 212.5F*
Peak drywell deck downward differential 30 psid 25.995 psid*
pressure
- NOTE: The calculated values presented in this table are based on the original design basis conditions. The calculated results for current plant conditions as shown in Table 6.2-5A.
The foregoing design and maximum calculated accident parameters are not determined from a single accident event but from an envelope of accident conditions. As a result, there is no single DBA for this containment system.
A maximum drywell and suppression chamber pressure occurs near the end of the blowdown phase of a LOCA. Approximately the same peak pressure occurs for the break of either a recirculation line or a main steam line. Both accidents are evaluated.
The most severe drywell temperature condition (peak temperature and duration) occurs for a small primary system rupture above the reactor water level that results in the blowdown of reactor steam to the drywell (small steam break). In order to demonstrate that breaks smaller than the rupture of the largest primary system pipe do not exceed the containment design parameters, the containment system responses to an intermediate size liquid break and a small size steam break are evaluated. The results show that the containment design conditions are not exceeded for these smaller break sizes.
CHAPTER 06 6.2-3 REV. 21, SEPTEMBER 2022
LGS UFSAR All of the analyses assume that the primary system and containment are initially at the maximum normal operating conditions. References are provided that describe relevant experimental verification of the analytical models used to evaluate the containment system response.
6.2.1.1.3.2 Containment Design Parameters Table 6.2-1 provides a listing of the key design parameters of the primary containment system including the design characteristics of the drywell, suppression pool, and the pressure-suppression vent system.
A diagram showing the geometric configuration of the downcomer is shown in Figure 6.2-1.
As described in Section 9.4.5, vacuum relief valve assemblies are provided to limit the degree to which suppression chamber pressure can exceed drywell pressure, and to prevent the drywell design negative pressure from being exceeded as described in Section 6.2.1.1.4. There are four assemblies, each mounted on the side of a downcomer on the flanges shown in Figure 6.2-1.
Each assembly consists of two vacuum relief valves mounted in series. A schematic diagram of a single vacuum relief valve is shown in Figure 9.4-6. The required number and size of the vacuum relief valve assemblies was determined as described in Section 6.2.1.1.3.3.1.5.
Table 6.2-2 provides the performance parameters of the related ESF systems that supplement the design conditions of Table 6.2-1 for containment cooling purposes during postblowdown long-term accident operation. Performance parameters given include those applicable to full capacity operation and those applicable to the conservatively reduced capacities assumed for containment analyses.
6.2.1.1.3.2.1 Downcomer Vent Flow Loss Coefficient The downcomer vent flow loss coefficient, K, is defined by:
P K = 2 (EQ. 6.2-1)
V /2gc and is calculated from standard references (References 6.2-1 and 6.2-2). In the above equation P is the total pressure drop across the downcomer, is the fluid density, and V is the flow velocity.
The total downcomer flow loss coefficient is modeled as the sum of three contributors: an entrance loss (K1), a length loss (K2), and an exit loss (K3). The entrance loss coefficient (K1) is calculated from Reference 6.2-1 using a hooded duct entrance geometry that very nearly approximates the standoff jet deflector shield feature of the LGS downcomer and (K1) is calculated to be 0.90. The length loss (K2) is represented by a resistance coefficient (fL/D) loss with (f) calculated from Reference 6.2-2 and (K2) calculated to be 0.33. The exit loss coefficient (K3) is calculated to be 1.0 from Reference 6.2-2, which when combined with the above yields an overall loss coefficient value of K = 2.23.
CHAPTER 06 6.2-4 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.1.1.3.3 Accident Response Analysis The containment functional evaluation is based on the consideration of several postulated accident conditions resulting in the release of reactor coolant to the containment. These accidents include the following:
- a. An instantaneous guillotine rupture of a recirculation line
- b. An instantaneous guillotine rupture of a main steam line
- c. An intermediate size liquid line rupture
- d. A small size steam line rupture Energy release from these accidents is discussed in Section 6.2.1.3.
6.2.1.1.3.3.1 Recirculation Line Break NOTE: The information presented in this section is historical and is based on the original design basis conditions. See the explanation at the beginning of Section 6.2.1.1.3.
Immediately following the rupture of the recirculation line, the flow out both sides of the break is limited to the maximum allowed by critical flow considerations. The total effective flow area is given in Figure 6.2-2. In the side adjacent to the suction nozzle, the flow corresponds to critical flow in the pipe cross-section. In the side adjacent to the injection nozzle, the flow corresponds to critical flow at the ten jet pump nozzles associated with the broken loop. Table 6.2-3 provides a summary of the break areas.
6.2.1.1.3.3.1.1 Assumptions for Reactor Blowdown The response of the RCS during the blowdown period of the accident is analyzed using the following assumptions:
- a. The initial conditions for the recirculation line break accident are such that the system energy is maximized and the system mass is minimized. That is:
- 1. The reactor is operating at 105% of rated steam flow. This maximizes the postaccident decay heat.
- 2. The service water temperature is at the maximum normal value.
- 3. The suppression pool mass is at the low water level.
- 4. The suppression pool temperature is at the maximum normal value.
- b. The recirculation line is considered to be severed instantly. This results in the most rapid coolant loss and depressurization of the vessel, with coolant being discharged from both ends of the break.
- c. Reactor power generation ceases at the time of accident initiation because of void formation in the core region. Scram occurs in less than one second from receipt of CHAPTER 06 6.2-5 REV. 21, SEPTEMBER 2022
LGS UFSAR the high drywell pressure signal. The difference in time between accident initiation and shutdown is negligible.
- d. The vessel depressurization flow rates are calculated using Moody's critical flow model (Reference 6.2-3) assuming "liquid only" outflow, since this assumption maximizes the energy release to the drywell. "Liquid only" outflow implies that all vapor formed in the RPV by bulk flashing rises to the surface instead of being entrained in the existing flow. Actually, some of the vapor would be entrained in the break flow which would significantly reduce the RPV discharge flow rates. Further, Moody's critical flow model which assumes annular, isentropic flow, thermodynamic phase equilibrium, and maximized slip ratio, accurately predicts vessel outflows through small diameter orifices. Actual rates through larger flow areas, however, are less than the model indicates because of the effects of a near homogeneous two-phase flow pattern and phase nonequilibrium. These effects are conservatively neglected in the analysis.
- e. The core decay heat and the sensible heat released in cooling the fuel to initial average coolant temperature are included in the RPV depressurization calculation.
The rate of energy release is calculated using a conservatively high heat transfer coefficient throughout the depressurization period. The resulting high energy release rate causes the RPV to maintain nearly rated pressure for approximately 20 seconds. The high RPV pressure increases the calculated blowdown flow rates, which is again conservative for analysis purposes. The sensible energy of the fuel stored at temperatures below the initial average coolant temperature is released to the vessel fluid along with the stored energy in the vessel and internals as vessel fluid temperatures decrease during the remainder of the transient calculation.
- f. The MSIVs start closing 0.5 seconds after the accident. They are fully closed in the shortest possible time of three seconds following closure initiation. In actuality, the closure signal for the MSIVs occurs from low-low-low reactor water level (level 1),
so the valves do not receive a signal to close for greater than four seconds, and the closing time may be as long as five seconds. By assuming rapid closure of these valves, the RPV is maintained at a high pressure, which maximizes the calculated discharge of high energy water into the drywell.
- g. Reactor feedwater flow is assumed to stop instantaneously at time t = zero. Since feedwater flow tends to depressurize the RPV, thereby reducing the discharge of steam and water into the drywell, this assumption is conservative for the short-term analysis.
- h. A complete LOOP occurs simultaneously with the pipe break. This condition results in the loss of power conversion system equipment and also requires that all vital systems for long-term cooling be supported by onsite power supplies.
6.2.1.1.3.3.1.2 Assumptions for Containment Pressurization The pressure response of the containment during the blowdown period of the accident is analyzed using the following assumptions:
CHAPTER 06 6.2-6 REV. 21, SEPTEMBER 2022
- a. Thermodynamic equilibrium exists in the drywell and suppression chamber. The analysis assumes complete mixing and the error introduced by this assumption is negligible.
- b. The fluid flowing through the downcomers is formed from a homogeneous mixture of the fluid in the drywell. The use of this assumption results in complete carryover of the drywell air and a higher positive flow rate of liquid droplets that conservatively minimizes downcomer pressure losses.
- c. The fluid flow in the downcomers is compressible except for the liquid phase.
- d. No heat loss occurs from the gases inside the primary containment. Actually condensation of some steam on the drywell surfaces would occur.
6.2.1.1.3.3.1.3 Assumptions for Long-Term Cooling Following the blowdown period, the ECCS (discussed in Section 6.3) provides water for core flooding, containment spray, and long-term decay heat removal. The containment pressure and temperature responses during this period are analyzed using the following assumptions:
- b. After 600 seconds, flow from one RHR pump can be diverted from the RPV to the containment cooling. This is a manual operation. Containment spray need not be actuated at all to keep the containment pressure below the containment design pressure. Analytically, no credit may be assumed for containment cooling earlier than 600 seconds after the accident and cooling is assumed to begin at 600 seconds. However, containment cooling will be initiated in accordance with plant emergency operating procedures based on plant conditions.
- c. The effects of decay energy, stored energy, sensible energy, energy added by ECCS pumps, and energy from the metal-water reaction on the suppression pool temperature are considered.
- d. The suppression pool is the only heat sink available in the containment system prior to initiation of the RHRSW system.
- e. After 600 seconds, the RHR heat exchangers are activated to remove energy from the containment via the RHR suppression pool cooling mode in conjunction with RHRSW system.
The performance of the ECCS equipment during the long-term cooling period is evaluated in Section 6.2.1.1.3.3.1.6 for each of the three cases of interest.
CHAPTER 06 6.2-7 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.1.1.3.3.1.4 Initial Conditions for Accident Analyses Table 6.2-4 provides the initial RCS and containment conditions used in all the accident response evaluations. The tabulation includes parameters for the reactor, the drywell, and the suppression chamber.
Table 6.2-3 provides the initial conditions and numerical values assumed for the recirculation line break accident as well as the sources of energy considered prior to the postulated pipe rupture.
The assumed conditions for the reactor blowdown are also provided.
The mass and energy release sources and rates for the containment response analyses are given in Section 6.2.1.3.
6.2.1.1.3.3.1.5 Short-Term Accident Response The calculated containment pressure and temperature responses for the recirculation line break are shown in Figures 6.2-3 and 6.2-4, respectively.
The suppression chamber is pressurized by the carryover of noncondensables from the drywell and by heatup of the suppression pool. As the vapor formed in the drywell is condensed in the suppression pool, the temperature of the suppression pool water peaks and the suppression chamber pressure stabilizes. The drywell pressure stabilizes at a slightly higher pressure, the difference being equal to the downcomer submergence. During the RPV depressurization phase, most of the noncondensable gases initially in the drywell are forced into the suppression chamber.
However, following depressurization the noncondensables redistribute between the drywell and suppression chamber via the vacuum relief valve system. This redistribution takes place as steam in the drywell is condensed by the relatively cool ECCS water which is beginning to cascade from the break causing the drywell pressure to decrease.
In the early design phase of the plant, conservative hand calculations were performed to establish the minimum number of operating vacuum breaker assemblies required. Two cases leading to potentially rapid drywell depressurization were considered for wetwell-to-drywell vacuum breaker sizing:
- a. The inadvertent actuation of one drywell spray train (10,000 gpm @ 90F, assumed)
- b. Maximum ECCS spillage (7750 lbm/sec @ 140F exit temperature, assumed) during the depressurization phase of the large recirculation outlet line break LOCA Each case was to determine the number of vacuum breaker valve assemblies required to ensure that the maximum differential pressure across the diaphragm slab in the upward direction does not exceed allowables. For the analyses, a conservatively low 3 psid across the diaphragm slab was used, well below the present design allowable of 20 psid upward.
In the analyses done for both cases, a. and b., it was conservatively assumed that all noncondensables have been removed to the wetwell vapor region prior to drywell depressurization.
In addition to this, for the Case a. accident a 100% spray efficiency, together with a drywell temperature of 273F, combine with the assumptions regarding spray rate and inlet temperature noted above, to render this analysis conservative. This results in a net drywell energy removal rate of approximately 321,000 Btu/sec.
CHAPTER 06 6.2-8 REV. 21, SEPTEMBER 2022
LGS UFSAR The analysis for Case b. assumes a drywell saturation temperature of 262F, an ECCS drop fall height of 42 feet, an average drop diameter of 1 inch (for calculating condensation heat transfer to the falling ECCS spillage), and an average heat transfer coefficient of 2300 Btu/hr-ft2-F (for calculating heat transfer from the drywell vapor region to the pool of ECCS spillage collected on the drywell floor). These considerations, combined with the assumptions regarding noncondensables and ECCS spillage rate and temperature, yield a net drywell energy removal rate of approximately 318,000 Btu/sec for an ECCS spillage spray effectiveness of 34%.
The two cases yield drywell energy removal rates of the same order of magnitude, with the inadvertent containment spray case being the larger, 321,000 Btu/sec. As such, this inadvertent spray actuation case controls the vacuum breaker sizing. The hand calculation established that three operable vacuum breaker valve assemblies each having a seat inner diameter of 18 inches, were required.
Subsequently, the inadvertent spray actuation (ISA) case was reanalyzed using a dynamic computer model, described in Section 6.2.1.1.4. This analysis was performed to verify that vacuum relief valve capacity is sufficient to prevent drywell depressurization below the design value of -5 psig. For purposes of vacuum relief valve sizing, primary containment negative pressure is more limiting than diaphragm slab differential pressure. The computer model conservatively approximated vacuum relief valve flow characteristics based on actual test data. Additional conservative assumptions were made to maximize the negative pressure in the drywell. The results confirmed that two operable vacuum relief valve assemblies were sufficient to prevent excessive drywell depressurization, as discussed in Section 6.2.1.1.4.
The ECCS supplies sufficient core cooling water to control core heatup and limit metal-water reaction to less than 1%. After the RPV is flooded to the height of the jet pump nozzles, the excess flow discharges through the recirculation line break into the drywell. This flow of water (steam flow is negligible), in the form of hot water which flows into the suppression chamber via the downcomers, transports the core decay heat out of the RPV through the broken recirculation line.
This flow provides a heat sink for the drywell atmosphere, and thereby causes the drywell to depressurize.
Table 6.2-5 provides the peak pressure, temperature, and time parameters for the recirculation line break as predicted for the conditions of Table 6.2-4 and as correspond with Figures 6.2-3 and 6.2-4. Figure 6.2-5 shows the time-dependent response of the drywell floor (diaphragm slab) differential pressure.
During the blowdown period of the LOCA, the downcomers conduct the flow of the steam-water gas mixture in the drywell to the suppression pool for condensation of the steam. The pressure differential between the drywell and suppression pool controls this flow. Figure 6.2-6 provides the mass flow versus time relationship through the downcomers for this accident.
6.2.1.1.3.3.1.6 Long-Term Accident Responses NOTE: The information in this Section is based on the original design basis conditions.
Only case C (Loss of Offsite Power with no Containment Spray) was reanalyzed for the current plant conditions because this case results in the highest suppression pool temperature. The methods and results that bound current plant conditions are described in Section 6.2.1.8.
In order to assess the adequacy of the containment following the initial blowdown transient, an analysis was made of the long-term temperature and pressure responses following the accident for each of three cases. The results of these analyses are described below. The analyses CHAPTER 06 6.2-9 REV. 21, SEPTEMBER 2022
LGS UFSAR assumptions for these cases are those discussed in Section 6.2.1.1.3.3.1.3. The initial pressure response of the containment (the first 600 seconds after the break) is the same for each case.
CASE A: All ECCS equipment operating - with containment spray This case assumes that offsite ac power is available to operate all cooling systems. During the first 600 seconds following pipe break, the HPCI, core spray, and all LPCI pumps are assumed to operate. All flow is injected directly into the reactor vessel.
After 600 seconds, RHRSW pumps are started and both RHR heat exchangers are aligned to remove energy from the containment. During this mode of operation the flow from two RHR pumps is routed through their associated RHR heat exchanger where it is cooled before being discharged into the drywell and suppression chamber spray headers. The CS system continues operation during this mode with both loops injecting into the vessel.
The containment pressure response to this set of conditions is shown as curve A in Figure 6.2-7. The corresponding drywell and suppression pool temperature responses are shown as curve A in Figures 6.2-8 and 6.2-9. After the initial blowdown and subsequent depressurization due to CS and LPCI core flooding, energy addition due to core decay heat results in a gradual pressure and temperature rise in the containment.
When the energy removal rate of the RHR system equals the energy addition rate from the decay heat, the containment pressure and temperature reach a second peak value and decrease gradually. Table 6.2-6 summarizes the equipment operation, the peak long-term containment pressure following the initial blowdown peak, and the peak suppression pool temperature.
CASE B: LOOP - with containment spray This case assumes that no offsite power is available following the accident with only minimum diesel power. The RHR system and the drywell and suppression chamber sprays are in operation after 600 seconds. During this mode of operation the RHR system flows through only one RHR heat exchanger and is directed to the spray headers while one LPCI pump and one CS loop continue to inject water into the vessel. The containment pressure response to this set of conditions is shown as curve B in Figure 6.2-7. The corresponding drywell and suppression pool temperature responses are shown as curve B in Figures 6.2-8 and 6.2-9. A summary of this case is given in Table 6.2-6.
CASE C: LOOP - no containment spray This case assumes that no offsite power is available following the accident with only minimum diesel power. After 600 seconds the sprays may be manually activated to further reduce containment pressure if desired. This analysis assumes that the drywell and suppression chamber sprays are not activated.
After 600 seconds, the RHRSW system and one RHR heat exchanger are activated to remove energy from the containment. The flow from one RHR pump is cooled by the RHR heat exchanger before being discharged into the reactor vessel while another RHR pump and one CS loop inject directly into the vessel.
CHAPTER 06 6.2-10 REV. 21, SEPTEMBER 2022
LGS UFSAR The containment pressure response to this set of conditions is shown as curve C in Figure 6.2-7. The corresponding drywell and suppression pool temperature responses are shown as curve C in Figures 6.2-8 and 6.2-9. A summary of this case is given in Table 6.2-6.
When comparing the "spray" case B with the "no spray" case C, the same RHR heat exchanger duty is obtained since the suppression pool temperature response is approximately the same, as shown in Figure 6.2-9. Thus, the same amount of energy is removed from the pool whether the exit flow from the RHR heat exchanger is injected into the reactor vessel, into the suppression pool, or into the drywell as spray. However, the peak containment pressure is higher for the "no spray" case, but the pressure is still much less than the containment design pressure.
Figure 6.2-10 shows the rate at which the RHR system heat exchanger removes heat from the suppression pool following a LOCA (Section 6.2.2 describes the containment cooling mode of the RHR system). The heat removal rate is shown for the three cases of interest (A, B and C). The first assumes that all the ECCS equipment is available, in addition to both RHR heat exchangers and their associated RHRSW pumps. The second and third cases are for the very degraded minimum cooling condition that limits the heat removal capacity to one heat exchanger. For all cases, it is conservatively assumed that at the time of the accident the RHRSW is at its maximum design temperature, as defined in Table 6.2-2.
6.2.1.1.3.3.1.7 Energy Balance During Accident In order to establish an energy distribution in the containment as a function of time (short-term or long-term) for this accident, the following energy sources and sinks are required:
- a. Blowdown energy release rates
- b. Decay heat rate and fuel relaxation sensible energy
- c. Sensible heat rate (vessel and internals)
- d. Pump heat rate
- e. Heat removal rate from suppression pool (Figure 6.2-10)
- f. Metal-water reaction heat rate Items a, b, c, d, and f are discussed in Section 6.2.1.3. A complete energy balance for the recirculation line break accident is given in Table 6.2-7 for the reactor system, the containment and the containment cooling systems at time zero, at the time of peak drywell pressure, at the end of reactor blowdown, and at the time of the long-term peak pressure in the containment.
6.2.1.1.3.3.1.8 Chronology of Accident Events A complete description of the containment response to the recirculation line break has been given in Sections 6.2.1.1.3.3.1.5 through 6.2.1.1.3.3.1.7. Results for this accident are shown in Figures 6.2-3 through 6.2-10. A chronological sequence of events for this accident from time zero is provided in Table 6.2-8.
6.2.1.1.3.3.2 Main Steam Line Break CHAPTER 06 6.2-11 REV. 21, SEPTEMBER 2022
LGS UFSAR NOTE: The information in this section for the main steam line break is based on the original design basis conditions. See explanation at the beginning of Section 6.2.1.1.3. The main steam line break was not reanalyzed for current plant conditions. The containment pressure and pool swell load response for the main steam line break is bounded by the small and intermediate line break results and remains unchanged by the change in plant operating conditions. The information presented in this section reasonably represents the general characteristics of the main steam line break analysis.
The assumed sudden rupture of a main steam line between the reactor vessel and the flow restricting orifice results in the maximum flow rate of primary system fluid and energy to the drywell.
This would in turn result in the maximum drywell differential pressure. The sequence of events immediately following the rupture of a main steam line between the reactor vessel and the flow restricting orifice has been determined. The flow on both sides of the break accelerates to the maximum allowed by the critical flow considerations. On the side adjacent to the reactor vessel, the flow corresponds to critical flow in the steam line break area. Blowdown through the other side of the break occurs because the steam lines are all interconnected at a point upstream of the turbine by the bypass header. This interconnection allows primary system fluid to flow from the three unbroken steam lines through the header and back into the drywell via the broken line. Flow is limited by critical flow in the steam line flow restricting orifice. The total effective flow area is given in Figure 6.2-11. The MSIVs are assumed to start closing at 0.5 seconds and are fully closed in the maximum time of 5 seconds following closure initiation. By assuming slow closure of these valves, a large effective break area is maintained for a longer period of time. The peak drywell floor differential pressure occurs before the reduction in effective break area and is therefore insensitive to any additional delay in closure of the isolation valves. An MSIV closure time longer than the 5 second maximum closure time would increase the break flow rate from the inventory side of the break (break to MSIV valve). However, this is offset by a lower flow rate from the vessel side of the break due to a decreasing vessel pressure. The net effect on the peak drywell pressure would be on the order of 1 psi. Section 6.2.1.3 provides the mass and energy release rates.
Immediately following the break, the total steam flow rate leaving the vessel exceeds the steam generation rate in the core, causing an initial depressurization of the RPV. Void formation in the reactor vessel water causes a rapid rise in the water level. It is conservatively assumed that the water level reaches the vessel steam nozzles one second after the break occurs. The water level rise time of one second is the minimum that can occur under any reactor operating condition. From that time on, a two-phase mixture is discharged from the break. During the first second of the blowdown, the blowdown flow consists of saturated steam. This steam enters the containment in a superheated condition at approximately 330F.
Figures 6.2-12 and 6.2-13 show the pressure and temperature responses of the drywell and suppression chamber during the primary system blowdown phase of the steam line break accident.
Figure 6.2-13 shows that the drywell atmosphere temperature approaches a peak after approximately one second of primary system steam blowdown. At that time, the water level in the vessel reaches the steam line nozzle elevation and the blowdown flow changes to a two-phase mixture. This increased flow causes a more rapid drywell pressure rise. The peak differential pressure occurs shortly after the vent clearing transient. As the blowdown proceeds, the primary system pressure and fluid inventory decrease and this results in reduced break flow rates. As a consequence, the flow rate in the downcomers and the differential pressure between the drywell and suppression chamber begin to decrease.
CHAPTER 06 6.2-12 REV. 21, SEPTEMBER 2022
LGS UFSAR Table 6.2-5 presents the peak pressures, peak temperatures and corresponding times of this accident as compared to the recirculation line break.
After the primary system pressure has dropped to the drywell pressure, the blowdown is over. At this time the drywell contains saturated steam, and the drywell and suppression chamber pressures stabilize. The pressure difference corresponds to the hydrostatic pressure of downcomer submergence.
The drywell and suppression pool remain in this equilibrium condition until the reactor vessel refloods. During this period, the ECCS pumps inject cooling water from the suppression pool into the reactor. This injection of water eventually floods the reactor vessel to the level of the steam line nozzles and the ECCS flow spills into the drywell. The water spillage condenses the steam in the drywell and thus reduces the drywell pressure. As soon as the drywell pressure drops below the suppression chamber pressure, the primary containment vacuum breakers open and noncondensable gases from the suppression chamber flow back into the drywell until the pressures in the two regions equalize.
6.2.1.1.3.3.3 Hot Standby Accident Analysis This section is not applicable to BWR 4.
6.2.1.1.3.3.4 Intermediate Size Breaks The information presented in this section for the intermediate size break is based on the original design basis conditions. As described in Section 6.2.1.1.3.5.4, the limiting drywell temperature response is determined by steam enthalpy properties and is not sensitive to the change in plant operating conditions. These breaks were not reanalyzed at the current operating conditions. The information presented in this section reasonably represents the general characteristics of the intermediate size break analysis. (See explanation at beginning of Section 6.2.1.1.3.)
An intermediate size break is analyzed as part of the containment performance evaluation to demonstrate that the consequences are no more severe than from a rupture of the largest primary system pipe. This classification covers those breaks for which the blowdown results in reactor depressurization and operation of the ECCS. This section describes the consequences to the containment of a 0.1 ft2 break below the RPV water level. This break area is chosen as being representative of the intermediate size break area range. These breaks can involve either reactor steam or liquid blowdown.
The 0.1 ft2 break was assumed to occur below the vessel water level to maximize the mass and energy release rates to the drywell. Based on the Moody slip flow model for the same-sized break, the total mass and energy release is greater for liquid break than for a steam break.
The initial reactor and containment conditions used in the analysis were the same as those used for the design basis accident as presented in Tables 6.2-1 and 6.2-4 and discussed in Section 6.2.1.1.3.3.1.
Following the 0.1 ft2 break, the drywell pressure increases at approximately 1 psi/sec. This drywell pressure transient is sufficiently slow so that the dynamic effect of the water in the downcomers is negligible and the downcomers clear when the drywell-to-suppression chamber differential pressure is equal to the downcomer submergence hydrostatic pressure.
CHAPTER 06 6.2-13 REV. 21, SEPTEMBER 2022
LGS UFSAR Figures 6.2-14 and 6.2-15 show the short-term drywell and suppression chamber pressure and temperature response, respectively. The ECCS response is discussed in Section 6.3.
Approximately 5 seconds after the 0.1 ft2 break occurs, air, steam, and water start to flow from the drywell to the suppression pool; the steam is condensed and the air enters the suppression chamber free space. The continual purging of drywell air to the suppression chamber results in a gradual pressurization of both the wetwell and drywell. The containment continues to gradually increase in pressure due to the long-term pool heatup.
The ECCS is initiated as a result of the 0.1 ft2 break as described in Section 7.3.1 and Table 6.3-2 and provides emergency cooling of the core. The operation of these systems is such that the reactor is depressurized in approximately 600 seconds. This terminates the blowdown phase of the transient.
In addition, the suppression pool temperature at the end of blowdown is the same as that of the recirculation line break because essentially the same amount of primary system energy is released during the blowdown. After reactor depressurization and reflood, water from the ECCS begins to flow out the break. This flow condenses the drywell steam and eventually causes the drywell and suppression chamber pressures to equalize in the same manner as happens following a recirculation line break.
The subsequent long-term suppression pool and containment heatup transient is essentially the same as for the recirculation line break.
In comparison to the short-term drywell pressure and temperature responses for a large recirculation line break, it can be concluded that the consequences of an intermediate size break are less severe than those of a recirculation line break. The comparison of the short-term wetwell pressure and temperature responses shows that the intermediate size break is not significantly more severe than the large recirculation line break.
6.2.1.1.3.3.5 Small Size Breaks The information presented in this section for the small size break is based on the original design basis conditions. As described in Section 6.2.1.1.3.3.5.4, the limiting drywell temperature response is determined by steam enthalpy properties and is not sensitive to the change in plant operating conditions. These breaks were not reanalyzed at the current operating conditions. The information presented in this section reasonably represents the general characteristics of the small size break analysis. (See explanation at beginning of Section 6.2.1.1.3.)
6.2.1.1.3.3.5.1 Reactor System Blowdown Considerations This section discusses the containment transient associated with small primary system line breaks.
The sizes of primary system ruptures in this category are those that do not result in reactor depressurization due either to loss of reactor coolant or automatic operation of the ECCS equipment. Following the occurrence of a break of this size, it is assumed that the reactor operators will initiate an orderly plant shutdown and depressurization of the reactor system. The thermodynamic process associated with the blowdown of primary system fluid from such a break is one of constant enthalpy. If the primary system break is below the water level, the blowdown flow will consist of reactor water. Blowdown from reactor pressure to the drywell pressure will flash approximately one-third of this water to steam and two-thirds will remain as liquid. Both phases of the blowdown flow will be at saturation conditions corresponding to the drywell pressure. Thus, if CHAPTER 06 6.2-14 REV. 21, SEPTEMBER 2022
LGS UFSAR the drywell is at atmospheric pressure (for example) the steam and liquid associated with the liquid blowdown would be at 212F.
If the primary system rupture is located above the RPV water level so that the blowdown flow consists of reactor steam only, the resultant steam temperature in the containment is significantly higher than the temperature associated with liquid blowdown. This is because the constant enthalpy depressurization of high pressure, saturated steam results in superheated conditions.
A small reactor steam leak (resulting in superheated steam) imposes the most severe temperature conditions on the drywell structures and the safety equipment in the drywell. For larger steam line breaks, the superheat temperature is nearly the same as for small breaks, but the duration of the high temperature condition is less for the larger break. This is because the larger breaks depressurize the reactor more rapidly than the orderly reactor shutdown that is assumed to be initiated for the small break.
6.2.1.1.3.3.5.2 Containment Response For drywell design considerations, the following sequence of events is assumed to occur. With the reactor and containment operating at the maximum normal conditions, a small break occurs that allows blowdown of reactor steam to the drywell. The resulting pressure increase in the drywell leads to a high drywell pressure signal that scrams the reactor and activates the containment isolation system. The drywell pressure continues to increase at a rate dependent upon the size of the steam leak. The pressure increase lowers the water level in the downcomers until the level reaches the bottom of the downcomers. At this time, air and steam start to enter the suppression pool. The steam is condensed and the air carried over to the suppression chamber free space.
The air carryover results in a gradual pressurization of the suppression chamber at a rate dependent upon the size of the steam leak. Once all the drywell air is carried over to the suppression chamber, short-term pressurization of the suppression chamber ceases and the system reaches an equilibrium condition. The drywell contains only superheated steam, and continued blowdown of reactor steam condenses in the suppression pool. The suppression pool temperature continues to increase until the RHR heat exchanger heat removal rate is equal to the decay heat release rate.
6.2.1.1.3.3.5.3 Recovery Operations The reactor operators are alerted to the incident by the high drywell pressure signal and the reactor scram. For the purpose of evaluating the duration of the superheat condition in the drywell, it is assumed that their response is to shut the reactor down in an orderly manner using the main condenser while limiting the reactor cooldown rate to 100F per hour. This results in the reactor primary system being depressurized within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. At this time, the blowdown flow to the drywell ceases and the superheat condition is terminated. If the plant operators elect to cool down and depressurize the reactor primary system more rapidly than at 100F per hour, then the drywell superheat condition will be shorter.
6.2.1.1.3.3.5.4 Drywell Design Temperature Considerations For drywell design purposes, it is assumed that there is a blowdown of reactor steam for the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> cooldown period. The design temperature is determined by finding the combination of primary system pressure and drywell pressure that produces the maximum steam temperature. The maximum steam temperature occurs when the primary system is at approximately 450 psia and the drywell pressure is maximum. Thus, for design purposes, it is assumed that the drywell is at 35 CHAPTER 06 6.2-15 REV. 21, SEPTEMBER 2022
LGS UFSAR psig; this results in a conservative temperature of 340F for the first 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. After the first 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of blowdown of reactor steam, the primary system pressure is reduced to a level that results in a temperature which is conservatively bounded by 320F for the remaining 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
6.2.1.1.3.4 Accident Analysis Models NOTE: The information presented in this section for the accident analysis models is based on the original analysis models and does not represent the current methodology used to analyze the containment response following a LOCA. See explanation at the beginning of Section 6.2.1.1.3.
6.2.1.1.3.4.1 Short-Term Pressurization Model The analytical models, assumptions, and methods used to evaluate the containment response during the reactor blowdown phase of a LOCA are described in References 6.2-4 and 6.2-5.
6.2.1.1.3.4.2 Long-Term Cooling Mode Once the RPV blowdown phase of the LOCA is over, a fairly simple model of the drywell and suppression chamber may be used. During the long-term, postblowdown transient, the RHR containment cooling system flow path (Section 6.2.2.2) is a closed-loop and the suppression pool mass is constant. Schematically, the cooling loop mode used for analysis is shown in Figure 6.2-16. Since there is no change in mass storage in the system (the RPV is reflooded during the blowdown phase of the accident), the mass flow rates shown in the figure are equal, thus:
mDo = mSo = meccs (EQ. 6.2-2) where:
mDo = mass flow rate out of RPV, lbm/sec mSo = mass flow rate out of suppression pool, lbm/sec meccs = mass flow rate into RPV, lbm/sec 6.2.1.1.3.4.3 Analytical Assumptions The key assumptions employed in the model are as follows:
- a. The drywell and suppression chamber atmospheres are both saturated (100%
relative humidity).
- b. The drywell atmosphere temperature is equal to the temperature of the coolant spilling from the RPV, or to the spray temperature if the sprays are activated.
- c. The suppression chamber atmosphere temperature is equal to the suppression pool temperature or to the spray temperature if the sprays are activated.
- d. No credit is taken for heat losses from the primary containment or to the containment internal structures.
6.2.1.1.3.4.4 Energy Balance Considerations CHAPTER 06 6.2-16 REV. 21, SEPTEMBER 2022
LGS UFSAR The rate of change of energy in the suppression pool, (Ep) , is given by:
dEp = d (MwS . uS) = uS . dMwS + MwS dus (EQ. 6.2-3) dt dt dt dt where:
MwS = mass of water in suppression pool, lbm uS = internal energy of water in suppression pool, Btu/lbm Since dMwS = 0 (because there is no change in mass storage), and at dt the conditions existing in the containment:
duS = Cv . dTS (EQ. 6.2-4) dt dt where:
Cv = 1.0 for the constant volume specific heat of water, Btu/lbm-F TS = suppression pool temperature, F The pool energy balance yields:
MwS . Cv . dTS = MDo . hD - MSo . hS (EQ. 6.2-5) dt where:
hD = enthalpy of water leaving RPV, Btu/lbm hS = enthalpy of water in suppression pool, Btu/lbm This equation can be rearranged to yield:
dTS = MDoh D MSo h s (EQ. 6.2-6) dt Cv M wS CHAPTER 06 6.2-17 REV. 21, SEPTEMBER 2022
LGS UFSAR An energy balance on the RHR heat exchanger yields:
hc = hs - qHX (EQ. 6.2-7)
MSo where:
hc = enthalpy of water entering RPV, Btu/lbm qHX = heat removal rate of heat exchanger, Btu/sec Similarly, an energy balance on the RPV yields:
h D = h c + qD + q e (EQ. 6.2-8)
Meccs where:
qD = core decay and pump heat rate, Btu/sec qe = sensible energy release rate, Btu/sec Combining Equations 6.2-2, 6.2-6, 6.2-7 and 6.2-8 gives:
dTS = qD + q e qHX (EQ. 6.2-9) dt C v M wS This differential equation is integrated by finite-difference techniques to yield the suppression pool temperature transient.
6.2.1.1.3.4.5 Containment Thermodynamic Conditions Once the energy equations are solved, the drywell and suppression chamber atmospheric temperatures can be calculated.
For the case in which no containment spray is operating, the suppression chamber temperature, (TW), will, at any time, be equal to the current temperature of the pool, (TS), and the drywell temperature, (TD), will be equal to the temperature of the fluid leaving the RPV. Thus:
TD = TS + qD + q e qHX andTW = TS (EQ. 6.2-10)
C p M eccs where:
Cp = constant pressure specific heat of water, Btu/lbm-F CHAPTER 06 6.2-18 REV. 21, SEPTEMBER 2022
LGS UFSAR For the case in which the containment spray is assumed to be operating, both the drywell and suppression chamber atmosphere will be at the spray temperature, Tsp, where:
q Tsp = TS HX and TD = TW = Tsp (EQ. 6.2-11)
Cp M eccs Using the suppression chamber and drywell atmosphere temperatures, and assumption (a) of Section 6.2.1.1.3.4.3 (drywell and suppression chamber saturated), it is possible to solve for the containment total pressures, since:
PS = PaS + PvS (EQ. 6.2-13) where:
PD = drywell total pressure, psia PaD = partial pressure of air in drywell, psia PvD = partial pressure of water vapor in drywell, psia PS = suppression chamber total pressure, psia PaS = partial pressure of air in the suppression chamber, psia PvS = partial pressure of water vapor in the suppression chamber, psia and, from the Ideal Gas Law:
PaD = MaD
VD
- 144 PaS = MaS
- RTW (EQ. 6.2-15)
VS
- 144 where:
MaD = mass of air in the drywell, lbm MaS = mass of air in the suppression chamber, lbm R = gas constant for air, ft-lbf/lbm-R VD = drywell free volume, ft3 VS = suppression chamber free volume, ft3 CHAPTER 06 6.2-19 REV. 21, SEPTEMBER 2022
LGS UFSAR With known values of TD and TW Equations 6.2-12, 6.2-13, 6.2-14, and 6.2-15 can be solved by transient analysis and iteration. This iteration procedure is also used to calculate the unknown quantities MaD and MaS.
6.2.1.1.3.4.6 Solution of Equations The transient analysis is based on successive time step integration of the suppression pool temperature. When this integration has been performed and the value of TS at the end of a time step has been calculated, a pressure balance is made. Using values of MaD and MaS from the end of the previous time step and the updated values of TD and TS, a check is made to determine if PS is greater than or equal to PD using equations 6.2-12, 6.2-13, 6.2-14 and 6.2-15. If PS is greater than or equal to PD , then the two values are made equal. The vacuum breakers between the drywell and suppression chamber ensure that PS cannot be greater than PD.
Hence, with PD = PS and knowing that:
MaD + MaS = constant; (EQ. 6.2-16) where the constant is the known total initial mass of air in the suppression chamber and drywell prior to the accident, Equations 6.2-12, 6.2-13, 6.2-14, and 6.2-15 can be solved for MaS, MaD, and Pa. It is conservatively assumed that the total mass of air remains constant, which ignores any containment leakage that might occur during the transient.
If, as a result of the end-of-time step pressure check, PS PD PS + H*g (EQ. 6.2-17)
VW
- 144
- gc where:
g = acceleration of gravity, ft/sec2 gc = constant of proportionality ft-lbm/lbf-sec2 H = submergence of downcomers, feet VW = specific volume of fluid in downcomer, ft3/lbm then the pressure in the drywell is higher than the pressure in the suppression chamber but not sufficiently so to depress the water to the bottom of the downcomers and thus permit air to flow from the drywell to the suppression chamber. Under these circumstances, no air transfer is assumed to have occurred during the time step, and Equations 6.2-12, 6.2-13, 6.2-14, and 6.2-15 are solved during the time step, and Equations 6.2-12, 6.2-13, 6.2-14, and 6.2-15 are solved using the updated temperatures with the same MaS and MaD values from the previous time step.
If the end-of-time step pressure check shows:
VW
- 144
- gc CHAPTER 06 6.2-20 REV. 21, SEPTEMBER 2022
LGS UFSAR then the drywell pressure is set to the value:
VW
- 144
- gc This requires that the drywell pressure can never exceed the suppression chamber pressure by more than the hydrostatic head associated with the submergence of the downcomers. To maintain this condition, some transfer of drywell air to the suppression chamber is required. The amount of air transfer is calculated by using Equation 6.2-16 and combining Equations 6.2-12, 6.2-13, 6.2-14, 6.2-15, and 6.2-19 to give:
PvD + MaD . RTD = PvS + MaS . RTW + H . g (EQ. 6.2-20) 144VD 144VS 144VWgc which can be solved for the unknown air masses. The total pressures can then be determined.
6.2.1.1.4 Negative Pressure Design Evaluation The primary containment has been designed for a negative pressure of -5 psig. The worst case for this consideration results from actuation of the drywell sprays. During such a transient, cold spray water is passed through the drywell atmosphere resulting in a drop in vapor region temperature and a corresponding drop in vapor region pressure. This condition was analyzed for LGS and a peak negative pressure of -4.85 psig was obtained for actuation of one drywell spray network.
With three operable vacuum relief valve assemblies (two operating and one redundant), a sensitivity study indicates that actuation of both drywell spray networks concurrently results in a pressure below -5 psig if the suppression pool temperature is below approximately 105F, assuming worst case conditions for all other variables. Actuation of both drywell spray networks is administratively controlled whenever the suppression pool temperature is below 105F.
Operation of the drywell sprays at LGS will be governed by appropriate EOPs, which will be written and revised to implement the BWROG EPGs. There will be no other procedural requirements or administrative directives that will cause drywell sprays to be used. In accordance with the EOPs, prior to initiating drywell sprays, the operators will be directed first to determine if the present combination of drywell temperature and drywell pressure fall below the drywell spray initiation limit.
If the combination of parameters is below the limit, the operator is directed to initiate drywell spray with a flow rate as specified in the EOPs. The drywell spray initiation limit and minimum drywell spray flow rate are calculated in accordance with the BWROG EPGs. These limits prevent the generation of drywell negative pressures relative to secondary containment and suppression pool that could be damaging to the containment vessel.
The inadvertent actuation of both drywell spray trains is also prevented by the type and location of the control room switches. The outboard valves are normally closed and have key-locked switches that are approximately 8 feet apart.
To determine the temporal pressure and temperature of the primary containment the conservation equations of mass and energy, along with the state equations for steam and air (noncondensable),
were written for the drywell and wetwell regions. A schematic of these two regions is presented in Figure 6.2-17. The various terms for the mass and energy transfer mechanisms are also presented in this figure. The systems of differential equations for each region are presented in the following sections (definition of nomenclature is provided below):
CHAPTER 06 6.2-21 REV. 21, SEPTEMBER 2022
LGS UFSAR Acond = suppression pool free surface area, ft2 AVB = vent area through vacuum breakers, ft2 CVB = vacuum breaker flow coefficient CP = specific heat at constant pressure for H2O, 1 Btu/lbm-F CP = specific heat at constant pressure for N2, O.247 Btu/lbm-R CV = specific heat at constant volume for H2O, 1 Btu/lbm-F Cv = specific heat at constant volume for N2, 0.176 Btu/lbm-R E = energy content, Btu gc = gravitational constant, 32.174 ft-lbm/lbf-sec2 h = specific enthalpy, Btu/lbm k = ratio of specific heats M = mass, lbm Mnc = noncondensable mass, lbm Mcond = condensate mass, lbm Mdrop = dropout mass, lbm Mevap = evaporated steam mass, lbm Mstm = steam mass, lbm P = pressure, psi R = gas constant, lbf-ft/lbm-R Q = transferred energy, Btu T = temperature, F T* = absolute temperature, R t = time, sec Ustm = steam specific energy, Btu/lbm V = volume, ft3 CHAPTER 06 6.2-22 REV. 21, SEPTEMBER 2022
LGS UFSAR v = specific volume, ft3/lbm Greek Symbols
= heat exchanger effectiveness
= spray efficiency
= minimum heat exchanger flow rate, lbm/sec
= density, lbm/ft3 Subscripts D - drywell region f - final, saturated liquid g - saturated vapor S - suppression pool liquid region, sump sat - saturated conditions spray - spray sv - suppression pool vapor region VB - vacuum breaker 6.2.1.1.4.1 Drywell Region As indicated in Figure 6.2-17, there are several mass transfer terms for the drywell region. These are: drywell spray rate ( mspray ), drywell vapor region condensation rate (or "rainout" due to dropping saturation temperature) ( m cond ), and wetwell-to-drywell vacuum breaker flow rate ( m VB ).
A mass balance on the drywell vapor region yields:
dM D = dM nc + dM stm (EQ. 6.2-21) dt dt dt
=(MVB + Mspray ) in (Mcond + Mspray ) out The spray water is assumed to be removed directly to the wetwell liquid region to disallow any potential for re-evaporation to the drywell, as well as to maintain a larger drywell vapor region volume, both of which serve to induce conservatism in the analysis. The requirement of maintaining saturation conditions for the steam component is imposed and results in the following relationship:
M stm = VD or dM stm = VD dv g dTD 2
(EQ. 6.2-22) v g(TD) dt v g(TD) dTD dt The energy balance for this region is:
dE D = (Ms pray C p (Tout 32) + Q VB ) in (EQ. 6.2-23) dt CHAPTER 06 6.2-23 REV. 21, SEPTEMBER 2022
LGS UFSAR (Mspray C p (Tf 32)+ Mcond h f (Tf )) out
=Mspray C p (Tout Tf ) Mcond h f (Tf ) + Q VB
- But, dE D = C*V TD* dM nc + ug (TD) dM stm (EQ. 6.2-24) dt dt dt dTD
+ M ncCV + M stm dug dTD dt so, C*V TD* dM nc + ug (TD) dMstm (EQ. 6.2-25) dt dt dTD
+ M ncCV + M stm dug dTD dt The spray efficiency, , is defined as follows:
Tf Tout M
= = f stm (EQ. 6.2-26)
TD Tout M nc The functional relationship is determined in the work of Reference 6.2-4 and is illustrated in Figure 6.2-18.
6.2.1.1.4.2 Wetwell Region The wetwell region is modeled in much the same way as the drywell region except that, due to the presence of the suppression pool, two subregions are identified: one to represent the wetwell vapor region, and one to represent the wetwell liquid region (suppression pool). The vapor region is denoted by subscript (sv). Mass and energy balances on this subregion yield the following:
dM sv = d(M nc)sv + d(M stm)sv dt dt dt
=(M evap)in (M VB (+ M cond)sv + M drop)out (EQ. 6.2-27)
As was the case in the drywell region, the wetwell vapor region is assumed to maintain saturated conditions. Therefore, CHAPTER 06 6.2-24 REV. 21, SEPTEMBER 2022
LGS UFSAR (M stm)sv = Vsv or (EQ. 6.2-28) v g(Tsv) d(M stm) sv = 1 Vsv dv g dV sv dT sv dt v g(Tsv) dt v g(Tsv) dTsv 2
dt From volume considerations, Vsv can change less than 2% and does so gradually throughout the transient. Therefore, the approximation is made that, dVsv ~ 0 (EQ. 6.2-29) dt The suppression pool represents a large surface for condensation and evaporation, thus resulting in a net mass transfer between the liquid and vapor subregions. This effect serves to maintain the wetwell vapor region in a saturated state and is therefore modeled with the terms m eva p and m drop .
The kinetic theory of condensation (Reference 6.2-5) is used to determine these mass transfer rates. This results in the following expressions:
gc 1/2 (Pstm) sv (M ) = 144 Acond 2Rstm (EQ. 6.2-30)
(Tsv) cond sv 1/2 M evap = 144 1/2 Acond gc (P )
- sat1/2 S (EQ. 6.2-31) 2Rstm (TS) where:
= -w ()1/2 (1 + erf (w)) - e-w² (EQ. 6.2-32)
G net (M evap + (M cond)sv) w = = (EQ. 6.2-33)
G std A cond stm (2gc R stm T*sv)1/2 w
erf (w) = 2 2 (EQ. 6.2-34) o ez dz 1/2
()
For the energy balance, dEsv = C*v Tsv
- d(M )
nc sv + (M nc)sv C v dTsv + ug(Tsv) d(M nc)sv (EQ. 6.2-35) dt dt dt dt
= (M stm)sv dug dTsv dTsv dt CHAPTER 06 6.2-25 REV. 21, SEPTEMBER 2022
= (Mevap h g (TS ))in (Q VB + (Mcond ) sv h f (Tsv ) + Mdrop h g (Tsv ))out The suppression pool region is denoted by subscript (S). Mass and energy balances on this subregion yield the following:
dMs = (Mdrop + Mc ond + (Mc ond ) s v )in (Mevap ) out (EQ. 6.2-36) dt dEs = Cv (Ts 32) dMs + MsCv dTs (EQ. 6.2-37) dt dt dt
=(Mcond h f (Tf ) + (Mcond ) sv h f (Tsv ) + Mdrop h f (Tsv )
+(Mspray C p (TfTs ))in (M h (T ) )
evap g s out Two additional mass and energy transfer mechanisms need further definition. These are vacuum breaker flows and RHR heat exchangers, discussed in the next two sections.
6.2.1.1.4.3 Vacuum Breakers Flows When sufficient differential pressure has built up across the diaphragm slab, the wetwell-to-drywell vacuum breaker assemblies open, allowing for transfer of mass and energy between these two regions. This transfer is described as follows:
1/2 rsvPsv PD 2/Ksv (Ksv +1)/Ksv C* A 2gcKsv PD VB VB K sv 1 P sv Psv PD 2 Ksv /(Ksv 1)
For Psv Ksv + 1 VB M = (EQ. 6.2-38)
(Ksv +1)/(Ksv 1) 1/2
- g K P r 2 CVB A VB c sv sv sv sv K + 1 Ksv/(Ksv 1)
PD 2 For Psv Ksv+ 1
- Mstm *
(M VB )stm =
Mstm + M nc sv CHAPTER 06 6.2-26 REV. 21, SEPTEMBER 2022
- M nc *
(M VB ) nc =
M stm + M nc sv P Knc + stm P
Ksv = NC Kstm (EQ. 6.2-41)
Ptot sv Ptot sv
- and, Q VB = (MVB ) stm h g (Tsv )+(MVB )nc Cp* Tsv *
(EQ. 6.2-42) 6.2.1.1.4.4 RHR Heat Exchangers In the drywell spray mode, the RHR system draws water from the suppression pool, passes it through the RHR heat exchangers, and injects it into the drywell vapor region. As such, the RHR heat exchangers must be modeled to reflect this condition. Therefore, Q HX = Mspray C p (TS Tout ) = C p (TS Tsw ) (EQ. 6.2-43) where:
= min(Mspray ,Msw ) (EQ. 6.2-44)
Combining these yields, Tout = TS *
(TS Tsw ) (EQ. 6.2-45)
Mspray 6.2.1.1.4.5 Summary The preceding equations, combined with the state equations for steam and air, yield a set of coupled equations which, when reduced and solved simultaneously, determine the dynamic response of the primary containment system to the postulated drywell spray accident.
The inherent conservatisms of this model are: to neglect transfer of sensible heat energy from equipment and structures to the drywell vapor region, to disallow re-evaporation of the condensed drywell steam, to maintain a large volume for the drywell region by transferring condensed steam mass directly to the suppression pool, and to require saturated conditions in the primary containment vapor regions.
In addition to the modeling conservatisms, initial conditions for the primary containment are also chosen to induce conservatism in the analysis. The presence of any noncondensables in the drywell tends to hold-up the depressurization rate of this region following spray actuation. Thus, a condition is postulated wherein a small break occurs within the drywell serving to pressurize this region and drive all the noncondensables from the drywell vapor space. This sets the initial CHAPTER 06 6.2-27 REV. 21, SEPTEMBER 2022
LGS UFSAR pressure distribution and, along with the assumptions regarding saturated conditions for the steam phase, the temperature distribution for all three regions - drywell, wetwell vapor region, and suppression pool. Normally the noncondensables are driven from the drywell to the wetwell.
However, when evaluating the reduction from 4 operable vacuum breakers to 3 operable vacuum breakers, it was assumed for a worst case analysis that a small amount of noncondensables is discharged to the reactor enclosure, prior to purge valve closure, and the remainder are driven to the wetwell vapor space. These initial conditions are presented under the heading "to" in Table 6.2-9.
The results of this analysis are illustrated in Figures 6.2-19 and 6.2-20. These results indicate a maximum negative drywell pressure of -4.85 psig.
6.2.1.1.5 Steam Bypass of the Suppression Pool NOTE: The information in this section for the steam bypass of the suppression pool is based on the original basis conditions. See explanation at the beginning of Section 6.2.1.1.3.
6.2.1.1.5.1 Protection Against Bypass Paths The pressure boundary penetrations between drywell and suppression chamber include the downcomers, which are fabricated, erected, and inspected in accordance with ASME Section III, Subsection NC, 1971 Edition with the exception of the tees supporting the primary containment vacuum relief valves. This special construction, inspection, and quality control ensures the integrity of this boundary. The design pressure differential and temperature for this boundary are defined in Table 6.2-1. Actual peak accident differential pressure and temperature for this boundary are provided in Table 6.2-5.
All penetrations of this boundary are welded except the vacuum relief valves supported by four tees and the blinds closing 10 spare nozzles in the downcomers. All penetrations are available for periodic visual inspection.
All potential bypass leakage paths have been considered. Every path has at least two isolation valves in the potential leakage path. These valves are high quality leak-tight containment isolation valves that are all normally closed and receive an isolation signal to close. All AOVs in these paths are failed closed.
6.2.1.1.5.2 Reactor Blowdown Conditions and Operator Response In the highly unlikely event of a primary system leak in the drywell accompanied by the existence of an open bypass path leakage between the drywell and suppression chamber, the suppression chamber is pressurized by the steam that enters through the leakage path (bypassing the suppression pool). For a given primary system break area, the maximum leakage that can be allowed is the amount that results in the containment pressure just reaching the design pressure at the end of reactor blowdown. The most limiting conditions, in terms of the smallest allowable leakage flow path area, occur for those primary system break sizes that do not cause rapid reactor depressurization, but do have a long leakage duration. This corresponds to break sizes less than approximately 0.4 ft2, which require some operator action to terminate the reactor blowdown.
Immediately after the postulated conditions given for a small primary system break, there is a fairly rapid rise in containment pressure as the noncondensable gases in the drywell are carried over to the suppression chamber. During this portion of the transient, it is assumed that the plant operators are unaware that a leakage path exists. For the maximum allowable leakage CHAPTER 06 6.2-28 REV. 21, SEPTEMBER 2022
LGS UFSAR calculations, it is assumed that the plant operators become aware of a potential leakage only when the drywell pressure reaches 30 psig. For conservatism, an additional 30 minute delay is assumed to occur before any corrective action to terminate the transient takes effect. At that time, the drywell pressure would be equal to the design pressure if the allowable leakage had occurred. The operator will be alerted to the existence of significant steam bypass leakage by the attendant drywell pressure increase which the operator will be monitoring as part of the EOPs. The operator will initiate the wetwell spray in accordance with the EOPs which will be based on the BWROG EPGs. The BWROG EPGs explicitly consider the possibility of suppression pool bypass leakage in determining spray initiation points.
Termination of the wetwell (and drywell) pressure increase is assured by the operation of only one of the two wetwell sprays.
6.2.1.1.5.3 Analytical Assumptions When calculating the allowable leakage capacities for a spectrum of break sizes, the following assumptions are made:
- a. Flow through the postulated leakage path is pure steam. For a given leakage path, if the leakage flow consists of a mixture of liquid and vapor, the total leakage mass flow rate is higher but the steam flow rate is less than for the case of pure steam leakage. Since only the steam entering the suppression chamber free space results in the additional containment pressurization, this is a conservative assumption.
- b. There is no condensation of the leakage flow on either the suppression pool surface or the containment and vent system structures. Since condensation acts to reduce the suppression chamber pressure, this is a conservative assumption. For an actual containment there is condensation, especially for the larger primary system break where vigorous agitation at the pool surface occurs during blowdown.
The following assumptions were made in performing the small break bypass leakage computations to demonstrate that operator action is not required for at least 30 minutes.
- a. The steam that leaks into the wetwell air space does not mix with the air already there.
- b. No portion of the steam that has leaked into the wetwell air space condenses.
- c. Only steam leaks into the wetwell; any air moving from the drywell into the wetwell goes through the vents.
- d. All of the air initially in the drywell is cleared into the wetwell before the moment when the operator is alerted.
- e. The vents do not refill with water during the time span considered in this procedure.
- f. The flow of steam through leakage paths is treated as being incompressible.
- g. The pressure difference across the leakage path is assumed to be constant and equal to the vent submerged hydrostatic pressure difference.
- h. The drywell pressure at which the operator is alerted is 30 psig.
CHAPTER 06 6.2-29 REV. 21, SEPTEMBER 2022
- i. The wetwell air temperature when the operator is alerted to the occurrence of bypass leakage is assumed to be equal to the initial wetwell temperature (95F).
Later, when the drywell pressure is reduced due to operator action, the wetwell air temperature is assumed to be 50F greater than the initial wetwell temperature, i.e.,
145F.
- j. Maximum allowable leakage area A/(k)1/2 = 0.05 ft2.
- k. The wetwell air space is saturated at the time of spray initiation.
The initial conditions assumed were:
Drywell Temperature 135F Drywell Pressure 15.45 psia Drywell Relative Humidity 20%
Wetwell Temperature 95F Wetwell Relative Humidity 100%
Drywell Volume 248390 ft3 (HWL)*
Wetwell Volume 149425 ft3 (HWL)*
Vent Submergence 12.25 ft (HWL)
Using the above assumptions and initial conditions, a small break LOCA in the drywell produces a constant drywell-to-wetwell pressure differential equivalent to the vent submergence static head (5.28 psid). The resulting bypass steam flow through the leakage path of A/(k)1/2 = 0.05 ft2 is 3.76 lbm/sec. The operator becomes alerted to the existence of bypass leakage when the drywell pressure reaches 30 psig. For the drywell pressure to increase from 30 psig to 55 psig (design pressure), the corresponding wetwell pressure rise is from 24.72 to 49.72 psig. Therefore, based on the amount of bypassed steam needed to produce this pressure rise, the operator has about 31 minutes to complete an action that will terminate the pressure increase.
The following shows the minimum required spray efficiency as a function of spray temperature.
Because the wetwell airspace is saturated when the spray is initiated (this conservative assumption maximizes pressurization at a given temperature), no net evaporation from hot downcomer surfaces will occur to counteract the spray depressurization effect. The mass flow rate of one spray system is 500 gpm. With two spray systems in operation, the required efficiency would be halved. The spray efficiency is typically on the order of 0.7 and, therefore, even with a single system is operation, the termination of the wetwell (and drywell) pressure increase is assured.
The assumed initial condition for Drywell temperature of 135F conservatively bounds an initial Drywell Temperature of 150F.
See Table 6.2-1 for final design volumes.
Required Efficiency of Spray Temperature 1 Wetwell Spray System 70F 0.22 90F 0.24 CHAPTER 06 6.2-30 REV. 21, SEPTEMBER 2022
LGS UFSAR 120F 0.28 6.2.1.1.5.4 Analytical Results The containment has been analyzed to determine the allowable leakage between the drywell and suppression chamber. Figure 6.2-21 shows the allowable leakage capacity (A/(k)1/2) as a function of the primary system break area. (A) is the area of the leakage flow path and (K) is the total geometric loss coefficient associated with the leakage flow path.
Figure 6.2-21 is a composite of two curves. If the break area is greater than approximately 0.4 ft2, natural reactor depressurization rapidly terminates the transient and maximum allowable leakage is correspondingly high. For break areas less than approximately 0.4 ft2, however, reactor blowdown is of long duration and the maximum allowable leakage is limited to small values. The smallest maximum allowable leakage capacity is at A/(K)1/2 = .046 ft2.
6.2.1.1.5.5 Tests and Inspections A visual inspection will be conducted at each refueling outage to detect possible drywell-to-suppression bypass leakage paths. A visual inspection of each primary containment vacuum relief valve assembly will be conducted during each refueling outage to verify that it is clear of foreign matter.
Vacuum breakers will be tested for operability at an interval specified by the Technical Specifications. This surveillance testing will be in accordance with the Technical Specifications.
6.2.1.1.5.6 Instrumentation The vacuum relief valve position indicator system has adequate sensitivity to detect a total valve opening, for all valves, that is less than the bypass capability for a small break. Outboard valve opening is detectable at a disk lift of 0.050 inch or greater off the valve seat. Inboard valve opening is detectable at a disk lift of 0.120 inch or greater off the valve seat. Even assuming that one outboard valve is in the fully open position and all other valves are open to their minimum detectable position, the total A/(k)1/2 is below 0.05 ft2. Therefore, the valve leakage, which is based on the assumption that the valve opening is evenly divided among all the vacuum breakers assemblies with one outboard valve in the fully open position, is well within the limits of acceptable bypass leakage.
6.2.1.1.6 Suppression Pool Dynamic Loads Hydrodynamic loads due to MSRV discharge and a LOCA are described in Appendix 3A.
6.2.1.1.7 Asymmetric Loading Conditions Asymmetric loads considered for the design of the containment structure include horizontal seismic and localized missile and pipe rupture loads. Refer to Section 3.7 for a description of the seismic analysis methods. Refer to Sections 3.6 and 3.8 for descriptions of the analytical methods used for pipe rupture and missile loads.
CHAPTER 06 6.2-31 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.1.1.8 Containment Environment Control The functional capability of the containment ventilation system to maintain the temperature, pressure, and humidity of the containment and subcompartments is discussed in Section 9.4.5.
6.2.1.1.9 Postaccident Monitoring A description of the postaccident monitoring systems is provided in Section 7.5.
6.2.1.2 Containment Subcompartments The containment subcompartments considered for LGS are the biological shield annulus and the drywell head region. The modeling procedures and considerations are presented in Appendix 6A.
6.2.1.3 Mass and Energy Release Analyses for Postulated LOCAs The information presented in this section for the mass and energy release analyses for postulated LOCAs is based on the original design basis conditions. The information presented in this section reasonably represent the general characteristics for the mass and energy release following a postulated LOCA. (See explanation at beginning of Section 6.2.1.1.3.)
This section presents information concerning the transient energy release rates from the reactor primary system to the containment system following a LOCA. Where the ECCS enter into the determination of energy released to the containment, the single failure criterion has been applied in order to maximize the energy release to the containment following a LOCA. Long-term responses and single failure analyses are discussed in Section 6.2.1.1.3.3.1.6.
6.2.1.3.1 Mass and Energy Release Data Table 6.2-10 provides the mass and enthalpy release data for the recirculation line break.
Blowdown steam and liquid flow rates approach zero in approximately 40 seconds and do not change significantly during the remainder of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period following the accident. Figures 6.2-22 and 6.2-23 show the blowdown flow rates for the recirculation line break graphically. These data were employed in the containment pressure-temperature transient analyses reported in Section 6.2.1.1.3.3.1.
Table 6.2-11 provides the mass and enthalpy release data for the main steam line break.
Blowdown steam and liquid flow rates approach zero in approximately 60 seconds and do not change significantly during the remainder of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period following the accident. Figure 6.2-24 shows the vessel blowdown flow rates for the main steam line break as a function of time after the postulated rupture. This information has been employed in the containment response analyses presented in Section 6.2.1.1.3.3.2.
6.2.1.3.2 Energy Sources The RCS conditions prior to the line break are presented in Tables 6.2-3 and 6.2-4. Reactor blowdown calculations for containment response analyses are based on these conditions during a LOCA.
The energy released to the containment during a LOCA is comprised of the following:
- a. Energy stored in the reactor system CHAPTER 06 6.2-32 REV. 21, SEPTEMBER 2022
- b. Energy generated by fission product decay
- c. Energy from fuel relaxation
- d. Sensible energy stored in the reactor structures
- e. Energy being added by the ECCS pumps
- f. Metal-water reaction energy These energy additions are discussed or referenced in this section. The pump heat rate used in evaluating the containment response to the LOCA is conservatively selected as a constant input of
.00434x106 Btu/sec to the system. The pump heat rate is added to the decay heat rate for inclusion in the analysis.
Following each postulated accident event, the stored energy in the reactor system and the energy generated by fission product decay are released. The rate of release of core decay heat for the evaluation of the containment response to a LOCA is provided in Table 6.2-12 as a function of time after accident initiation.
Following a LOCA, the sensible energy stored in the reactor primary system metal is transferred to the recirculating ECCS water and thus contributes to the suppression pool and containment heatup.
Figure 6.2-25 shows the temperature transients of the various primary system structures that contribute to this sensible energy transfer. Figure 6.2-26 shows the variation of the sensible heat content of the reactor vessel and internal structures during a recirculation line break accident based on the temperature transient responses.
6.2.1.3.3 Reactor Blowdown Model Description NOTE: The reactor blowdown model description provided below is for the original analysis models and do not represent the methods used to analyze current plant conditions.
Refer to the explanation provided at the beginning of Section 6.2.1.1.3.
The reactor primary system blowdown flow rates are evaluated with the model described in References 6.2-4 and 6.2-5.
6.2.1.3.4 Effects of Metal-Water Reaction The containment systems are designed to accommodate the effects of metal-water reactions and other chemical reactions that may occur following a LOCA. The amount of metal-water reaction that can be accommodated is consistent with the performance objectives of the ECCS. Section 6.2.5.3 provides a discussion on the generation of hydrogen within the containment by metal-water reaction. In evaluating the containment response, 0.002077x106 Btu/sec of heat from metal-water reaction is included for the first 120 seconds. The containment response is insensitive to the reaction time, even for the extremely conservative case where all of the energy is included prior to the occurrence of peak drywell pressure.
CHAPTER 06 6.2-33 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.1.3.5 Thermal-Hydraulic Data for Reactor Analysis Sufficient data to perform confirming thermodynamic evaluations of the containment are provided in Section 6.2.1.1.3.3 and associated tables, in particular, Table 6.2-4.
6.2.1.4 Pressurized Water Reactor - Not Applicable 6.2.1.5 Pressurized Water Reactor - Not Applicable 6.2.1.6 Testing and Inspection Preoperational containment testing and inspection programs are described in Section 3.8 and Chapter 14. Operational containment leakage rate testing and inspection programs are described in Section 6.2.6. The requirements and bases for acceptability are described in Chapter 16.
6.2.1.7 Instrumentation Requirements Containment pressure and temperature sensing and the associated actuating input to the ESF systems are discussed in Section 7.3. Refer to Section 7.5 for a discussion of the display instrumentation.
Containment airborne radioactivity monitoring is described in Section 12.3.4. Containment hydrogen monitoring is described in Section 6.2.5.
6.2.1.8 Containment System Performance at Power Rerate The UFSAR provides the results of analyses of the containment response to various postulated accidents that constitute the design basis for the containment. Operation with power rerate changes some of the conditions for the containment analyses. For example, the short-term DBA-LOCA containment response during the blowdown is governed by the blowdown flow rate. This blowdown flow rate is dependent on the reactor initial thermal-hydraulic conditions, such as vessel dome pressure and the mass and energy of the vessel fluid inventory, which change slightly with power rerate. Also, the long-term heat up of the suppression pool following a LOCA or a transient is governed by the ability of the RHR to remove decay heat. Since the decay heat depends on the initial reactor power level, the long-term containment response is affected by power rerate. The LGS containment response has been conservatively re-analyzed to demonstrate the plant's capability to operate at 110% of the original rated power.
The analyses were performed in accordance with Regulatory Guide 1.49 and Reference 6.2-25 using GE codes and models. The M3CPT code was used to model the short-term containment pressure and temperature response. The modeling used in M3CPT is described in References 6.2-26 through 6.2-28. Reference 6.2-26 and 6.2-27 describe the basic containment analytical models used in GE codes. Reference 6.2-28 describes the more detailed RPV model used in the containment analyses for power rerate. The SHEX code was used to model the long-term containment pressure and temperature response. The key models in SHEX are based on models described in References 6.2-26 and 6.2-27. The GE models and methods have been reviewed by the NRC (Reference 6.2-29). The NRC has approved the use of SHEX on a plant-specific basis, as described in Reference 6.2-30.
The significant input parameters and initial conditions for the power rerate containment analyses are shown in the Table 6.2-4A.
CHAPTER 06 6.2-34 REV. 21, SEPTEMBER 2022
LGS UFSAR The effects of power rerate on the containment dynamic loads due to a LOCA or SRV discharge have also been evaluated as described in Section 6.2.1.8.2. These loads were previously defined generically during the Mark II Containment Program as described in Reference 6.2-31 and accepted by the NRC in Reference 6.2-32 and 6.2-33. Plant-specific dynamic loads were also defined for the plant (Section 3A), which were accepted by the NRC in Reference 6.2-34. The evaluation of the LOCA containment dynamic loads is based primarily on the results of the short-term analysis described in Section 6.2.1.8.1.3. The SRV discharge load evaluation considers the change in the SRV opening setpoints with power rerate.
6.2.1.8.1 Containment Pressure and Temperature Response The short-term analysis is directed primarily at determining the containment pressure response during the initial blowdown of the reactor vessel inventory to the containment following a large break inside the drywell. The long-term analysis is directed primarily at the pool temperature response, considering the decay heat addition to the pool. The impact of power rerate on the events which yield the limiting containment pressure and temperature response is provided below.
6.2.1.8.1.1 Long-Term Suppression Pool Temperature Response 6.2.1.8.1.1.1 Bulk Pool Temperature The long-term bulk suppression pool temperature response for LGS with power rerate was evaluated for the DBA LOCA and includes the increased decay heat loads from SIL 636. The analysis was performed at 3528 MWt (Ref. 6.2-40, 6.2-41). Table 6.2-5A compares the calculated peak values for LOCA bulk pool temperature. The suppression pool temperature response is shown in Figure 6.2-9A. The peak bulk suppression pool temperature calculated is 203.4F. This temperature is within the suppression pool water temperature structural design value (220F), and does not exceed the low pressure ECCS pump limit of 212F.
6.2.1.8.1.1.2 Steam Bypass Case A concern during a LOCA event is steam bypass of the suppression pool due to leakage between the drywell and the wetwell airspace. Excess leakage could result in overpressurization of the primary containment. A steam bypass analysis was performed at 3694 MWt to ensure that there is sufficient time for a manual actuation of the containment spray to prevent the containment pressure from exceeding the design limit of 55 psig. The evaluation shows that power rerate has negligible impact on the suppression pool steam bypass effects. Reference 6.2-41 qualitatively equates the steam bypass event at 3458 MWt with the decay heat rates of SIL 636. At these conditions, it is expected that sufficient time for manual equation of containment spray is available to prevent containment pressure from exceeding 55 psig.
6.2.1.8.1.2 Containment Gas Temperature Response The drywell design temperature (340F) has been determined based on a bounding analysis of the superheated gas temperature which can be reached with blowdown of steam to the drywell during a LOCA. A small reactor steam leak (resulting in superheated steam) imposes the most severe temperature conditions on the drywell structures and the safety-related equipment in the drywell.
For larger steam line breaks, the superheat temperature is nearly the same as for the small breaks, but the duration of the high temperature condition is less for the large break. This is because the larger breaks depressurize the reactor more rapidly than the orderly reactor shutdown that is assumed to be initiated for the small breaks. The changes in the reactor vessel conditions with power rerate will increase the calculated long-term peak drywell gas temperature during a small CHAPTER 06 6.2-35 REV. 21, SEPTEMBER 2022
LGS UFSAR break LOCA by a maximum of a few degrees. However, it has been evaluated that the small break drywell gas temperature response with power rerate will not exceed the drywell design value. The short-term drywell and wetwell gas temperature response is shown in Figure 6.2-4A. The long-term drywell gas temperature response is shown in Figure 6.2-8A.
The wetwell gas space peak temperature response is calculated assuming short-term thermal equilibrium between the pool and wetwell gas space. For the long term containment response, the heat and mass transfer between the suppression pool and the wetwell air space is mechanically calculated. Table 6.2-5A shows the peak bulk pool temperature is 203.4F due to power rerate and SIL 636 (Reference 6.2-41). The peak wetwell gas space temperature is 210.7F. These temperatures are well below the design temperature of 220F.
6.2.1.8.1.3 Short-Term Containment Pressure Response Short-term containment pressure response analyses were performed for the limiting DBA LOCA which assumes a double-ended guillotine break of a recirculation suction line to demonstrate that operation with power rerate will not result in exceeding the containment design limits. The short-term analysis covers the blowdown period during which the maximum drywell pressure, wetwell pressure, and differential pressure between the drywell and wetwell occur. This analysis was conservatively performed at 102% of 110% of original rated power. The results of this short-term analysis are summarized in Table 6.2-5A. The short-term containment pressure response for power rerate is shown in Figure 6.2-3A. The long-term containment pressure response is shown in Figure 6.2-7A. Table 6.2-5A also includes comparisons of the pressure values calculated with power rerate to the design pressures values from previous calculations reported in the UFSAR. As shown by these results, the peak pressure values are below the design values.
6.2.1.8.2 Containment Dynamic Loads 6.2.1.8.2.1 LOCA Containment Dynamic Loads The LOCA containment dynamic loads analysis for power rerate is based primarily on the short-term LOCA analyses described in Section 6.2.1.8.1.3. These analyses provide calculated values for the controlling parameters for the dynamic loads throughout the blowdown. The key parameters are drywell and wetwell pressure, vent flow rate and suppression pool temperature.
The LOCA dynamic loads which are considered in the power rerate evaluation include pool swell, condensation oscillation (CO), and chugging.
The short-term containment response conditions with power rerate are within the conditions used to define the pool swell loads. The initial drywell pressurization rate used to define the pool swell load is negligibly affected by rerated power. The short-term containment response conditions for vent flow rate and pool temperature with power rerate are negligibly affected by power rerate. In addition, the containment conditions with power rerate in which CO and chugging would occur are within the range of test conditions used to define the CO and chugging loads. Therefore, the LOCA dynamic loads are not affected by power rerate.
6.2.1.8.2.2 SRV Containment Dynamic Loads Hydrodynamic loads generated by the actuation of Safety/Relief Valve (SRV) include both internal and external hydrodynamic loads. Internal loads include SRV discharge line loads and load on the quencher discharge device. External hydrodynamic loads include the suppression pool boundary pressure loads and the submerged structure loads. These loads are influenced by SRV opening CHAPTER 06 6.2-36 REV. 21, SEPTEMBER 2022
LGS UFSAR setpoint pressure, SRVDL geometry and submergence, initial air volume in SRVDL, quencher design and suppression pool geometry. The only parameter change introduced by power rerate which can affect SRV loads is the increase in SRV opening setpoint pressure which results in higher SRV flow rates and, therefore higher SRV loads.
The SRV analytical limits for setpoints show a 3.5% increase in the analytical values of the SRV opening pressure with power rerate. The increase in SRV setpoint pressure results in a corresponding 3.5% increase in flow rate and hydrodynamic loads. However, the original SRV external hydrodynamic load specification and the load specification on quenchers are defined based on a reference RPV pressure of 1276 psig. Comparison shows that the rerate increased SRV setpoint pressure and flow rate are still bounded by the referenced flow rate used to define the LGS T-quencher hydrodynamic loads (Reference 6.2-35). Therefore, the original containment dynamic and submerged structure loads remain bounding for power rerate. The same conclusion is also valid for the hydrodynamic loads on the quencher. The SRV discharge piping loads are included in the evaluation discussed in Appendix 3A and 3B.
6.2.1.8.2.3 Subcompartment Pressurization The design loads on the shield wall due to a postulated pipe break in the annulus between this wall and the reactor vessel are acceptable for the higher reactor pressure at rerated conditions. The shield wall design remains adequate because the original analyzed loads were based on mass and energy releases which bound the rerated conditions. The subcompartment pressurization evaluations for power rerate are provided in Appendix 6A.
6.2.2 Containment Heat Removal System 6.2.2.1 Design Bases The containment heat removal system (containment cooling system) prevents excessive containment temperatures following a LOCA so that containment integrity is maintained. To fulfill this purpose, the containment cooling system meets the following design bases:
- a. The system is designed to limit the long-term bulk temperature of the suppression pool without spray operation when considering the energy additions to the containment following a LOCA (see Reference 6.2-4). These energy additions, as a function of time, are provided in Section 6.2.1.3.2.
- b. The system is designed with sufficient capacity and redundancy so that a single failure of any active component, assuming a LOOP, cannot impair its capability to perform its safety-related function. The system is designed to remain operable following an SSE.
- c. The system is designed to operate under any of the following conditions: LOOP, adverse natural phenomena (such as tornadoes, hurricanes, earthquakes, floods, etc.), and site related events (such as high and moderate energy pipe breaks, externally generated missiles, and transportation accidents).
- d. Each active component of the system is testable during normal operation of the nuclear power plant.
6.2.2.2 System Design CHAPTER 06 6.2-37 REV. 21, SEPTEMBER 2022
LGS UFSAR The containment cooling system is an integral part of the RHR system as described in Section 5.4.7 and designed to seismic Category I requirements. The system is designed, fabricated, erected, and tested to quality Group B standards with the exception of the drywell and wetwell spray headers which were originally designed, fabricated, and erected to quality Group C standards but have been upgraded to quality Group B (Table 3.2-1). In the containment cooling mode, water is drawn from the suppression pool through redundant suction strainers, pumped through one or both RHR heat exchangers, and delivered to the vessel, the suppression pool, the drywell spray header, and/or the suppression pool vapor space spray header. Water from the RHRSW system is pumped through the heat exchanger tube side to remove heat from the suppression pool water. Two 100% capacity cooling loops are provided; each being mechanically and electrically separate from the other to achieve redundancy (Section 9.2.3). Power is supplied from the safeguard buses (Section 8.3). A P&ID and process diagram, including the process data, are provided in Section 5.4 for all design operating modes and conditions.
All ECCS and RCIC suction piping originating in the suppression pool is designed based on the following criteria:
- a. The allowable pressure drop across the redundant pair of strainers for each RCIC and HPCI suction line is 2 psi maximum at the design flow rate with each of the strainers 50% plugged in order to exceed the minimum required NPSH provided to the associated pump.
- b. The allowable dirty pressure drop across the redundant strainers for each of the RHR and Core Spray suction lines is 5 psi and 3.8 psi maximum, respectively, at the design flow rate in order to satisfy the minimum required NPSH provided to the associated pump. The dirty strainer pressure drop is based on the entire amount of fibrous debris generated in the drywell during a design basis LOCA (within the zone of influence of the worst case pipe break location) transported to the suppression pool and all fibrous debris is available to clog the strainer.
- c. The strainer mesh openings are sized to allow foreign particles of no greater than 0.0625 inches to pass through in order to prevent plugging of the containment spray nozzles and pump seal flushing water circuits.
- d. Each strainer is designed to withstand all seismic and hydrodynamic loads postulated to occur in the suppression pool. A dynamic loading analysis has been performed for the ECCS suction strainers that demonstrates their capability to adequately accommodate inertial loads (earthquake, SRV discharge, and LOCA condensation oscillation and chugging), operational loads (pressure and temperature), dead weight loads, and direct hydrodynamic loads. The latter loads are due to direct hydrodynamic SRV discharge (SRV air bubble loads) and downcomer discharges (LOCA air bubble, CO, chugging, water jet, and pool-swell loads). The mentioned loads are combined in accordance with Table 3A-20.
Figure 3A-27 presents elevations, dimensions, and orientations of the piping systems inside containment that are associated with the ECCS suction strainers.
- e. The RHR suction piping is arranged in the suppression pool considering the locations of the discharge piping, so that when operating in the suppression pool cooling mode the suppression pool is uniformly cooled.
CHAPTER 06 6.2-38 REV. 21, SEPTEMBER 2022
LGS UFSAR Each pump suction line penetrates the vertical wall of the suppression pool, leading directly to a "T" arrangement. The "T"s for the RCIC line and HPCI line are oriented vertically. The remaining "T"s are horizontal. The centerline of this "T" is 23 inches maximum from the suppression pool wall and 11'-11" below the minimum Technical Specification suppression pool water level. Each arm of the "T" is the same nominal pipe size as the suction line. The strainers are bolted to the arms of each "T" except Core Spray strainers which are attached to one arm of each "T". Each of the two strainers for each suction line provides more than 100% of the cross-sectional area of the suction line. The design drawing for the RCIC and HPCI strainers is shown in Figure 6.2-51. The design drawings for the RHR and Core Spray strainers are shown in Figure 6.2-51.
In the unlikely event of a high energy pipe break within the primary containment, debris created might migrate to the suppression pool and build-up on the RCIC and HPCI pump suction strainers, impairing operation of these pumps. Such debris considerations are part of USI A-43, "Containment Emergency Sump Performance." The manufacturer has addressed this concern on a generic basis in a topical report which has been reviewed and accepted by the NRC (Reference 6.2-23). A plant specific review of this concern was made.
The only credible sources of LOCA generated debris inside the primary containment that have the potential to clog pump suction strainers are the thermal insulation materials on piping and equipment. There are four types of insulation materials used inside the primary containment:
- a. Metallic reflective - used on reactor vessel.
- b. Fiberglass (Nukon) - used on piping, valves, and pumps.
- c. Fiberglass (antisweat) - used on chilled water piping.
- d. Stainless steel encapsulated low conductivity insulation - used on piping at the pipe whip restraints.
Fiberglass insulation inside primary containment is protected with stainless steel jackets except where it is not practical (pipe hangers, supports) or where shapes are not suitable (some valves and reactor nozzles). Insulation added in the Unit 1 drywell during power ascension testing was installed without jackets to simplify installation.
Insulation debris can enter the suppression pool only through the wetwell downcomers (Figure 6.2-1). There are several physical barriers that will minimize the amount and size of debris that enters the downcomers, as described below:
- a. Floor grating, walkways, stairs, structural steel, piping, etc., located above the drywell floor will trap the majority of dislodged insulation pieces before they can reach the drywell floor where the downcomers are located.
- b. Covers over downcomer openings will prevent debris from falling directly into a downcomer.
- c. Downcomer openings are above the floor. The downcomer pipes extend 18 inches above the drywell floor. This feature prevents entry of all heavier insulation debris due to the specific gravity of the debris and low velocity of the water converging on the downcomer rims. Floating debris, in most cases, will be partially submerged, which will prevent them from passing over the downcomer rim.
CHAPTER 06 6.2-39 REV. 21, SEPTEMBER 2022
- d. The clearances around the jet deflector assembly covering the downcomer openings are such that debris with dimensions larger than 10 inches will be blocked from entering the downcomer.
In the case of metallic reflective insulation, it will immediately sink to the bottom of the drywell floor pool, where the flow velocities are too low to transport this insulation over the downcomer rims into the suppression pool.
In the case of permanently installed antisweat insulation, the jacketing subjected to jet forces of a high energy line break is susceptible to being blown away along with the underlying fiberglass panels. The stainless steel jacketing is too dense to be transported to the wetwell. Loose fiberglass panels that fall to the floor float due to their low specific gravity and therefore could be carried over with the emergency core cooling water and be transported to the suppression pool.
However, due to the minimal quantity of antisweat insulation provided on piping in the drywell, and the filtering effect of the physical barriers noted above, it is improbable that sufficient antisweat insulation materials would be available to plug the pump suction strainers.
In the case of stainless steel encapsulated low conductivity insulation, the steel jackets are welded around the low conductivity insulation and would therefore be expected to stay intact even if the entire assembly is blown away from the piping due to jet forces of a high energy line break. If the low conductivity insulation remained dry within the steel jackets, the assembly would have a lower specific gravity than water, thus allowing the assembly to float. However, vent holes are provided in each assembly for pressure equalization, so the low conductivity insulation would become wet, in which case the assembly would have a higher specific gravity than water and would sink. If the low conductivity insulation remained dry long enough to allow it to float to the downcomer openings, the size of most individual insulation assemblies would be too large to pass through the downcomer jet deflector assemblies. Also, the submergence of most smaller assemblies will be too deep to pass over the downcomer rims. Thus, due to the minimal quantity of low conductivity insulation provided on piping in the drywell, and the low probability of any dislodged insulation assemblies being transported to the suppression pool, it is improbable that these insulation materials would plug the pump suction strainers.
There is a potential for some quantity of fiberglass insulation to travel to the suppression pool. An evaluation was made to estimate the maximum quantity of fiberglass insulation debris that might be generated by a LOCA, the amount of such debris that might enter the suppression pool and cover the ECCS strainers, the attendant pressure losses and resulting effect on the ECCS pump NPSH margins.
In this review, no credit was taken for the protective effect of stainless steel jackets on the fiberglass insulation. The head loss due to 50% plugging of the suction strainers concurrent with minimum postaccident NPSH conditions does not cause the available NPSH to drop below that required by the RCIC and HPCI pumps. Using more realistic considerations, it has been determined that other transport mechanisms will significantly reduce the actual amount of fibrous insulation debris that could migrate to the suppression pool and cover the pump strainers.
Large capacity passive pump suction strainers have been installed on each RHR and Core Spray suction line in the suppression pool via plant modification, in response to NRC I.E. Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors. The assumptions used in sizing these new strainers are consistent with the guidance specified in Regulatory Guidance 1.82, Revision 2, Water Sources for Long-Term Recirculation CHAPTER 06 6.2-40 REV. 21, SEPTEMBER 2022
LGS UFSAR Cooling Following a Loss-of Coolant Accident and NUREG/CR-6224, Parametric Study of the Potential for BWR ECCS Strainer Blockage Due to LOCA Generated Debris as described in PECO Energys letter from G. A. Hunger, Jr., Director Licensing, to USNRC, dated October 6, 1997, Request for Licensing Amendment Associated with ECCS Pump Suction Strainer Plant Modification.
It has been determined that the amount of fiberglass insulation debris generated by a LOCA jet impinging on nearby insulation will not jeopardize ECCS pump operation at LGS Units 1 & 2.
The containment cooling system is designed to withstand operating loads and loads resulting from natural phenomena. Components required to operate can be tested during normal plant operation so that reliability can be ensured. Construction codes and standards are covered in Section 5.4.7.
The containment cooling system is started manually. There are no signals that automatically initiate the system. Rather, the LPCI mode of RHR operation is automatically initiated from ECCS signals. The RHR system is realigned for containment cooling by the plant operator after the reactor vessel water level has been restored (Section 6.2.1). The RHR pumps are already operating. Containment cooling is initiated in loop A or B by manually starting the RHRSW pump; closing the heat exchanger bypass valve; opening the service water valves at the heat exchanger; closing the LPCI injection valve; and opening the pool return valve, not necessarily in this order. If a single failure has occurred that prevents system initiation, the other totally redundant system is placed into operation by following the same initiation procedure. If the operator chooses to use the containment spray to reduce containment pressure, he must close the LPCI injection valve and open the spray valves. An interlock prevents the operator from opening the drywell spray valves unless a containment high pressure signal is present.
The containment cooling system equipment is located in the reactor enclosure and protected from both internal and external floods. The equipment is located in separate compartments, the walls and doors of which are steam-tight and water-tight so that flooding due to leakage from piping in an adjacent containment cooling system or other ECCS compartment does not affect the redundant containment cooling system equipment. Flood design of the reactor enclosure is discussed in Section 3.4.
6.2.2.3 Design Evaluation If there is a postulated LOCA, the short-term energy release from the reactor primary system is dumped to the suppression pool. Subsequent to the accident, fission product decay heat results in a continuing energy input to the pool. The containment cooling system removes this energy that is input to the primary containment system, thus resulting in acceptable suppression pool temperatures and containment pressures.
To evaluate the adequacy of the containment cooling mode of the RHR system, the following sequence of events is assumed to occur:
- a. With the reactor initially operating at 3528 MWt, a LOCA occurs.
- b. A LOOP occurs and one emergency diesel fails to start and remains out of service during the entire transient. This is the worst single active failure.
- c. Only three LPCI pumps are activated and operated as a result of no offsite power and minimum onsite power. Section 6.3 describes the ECCS equipment.
CHAPTER 06 6.2-41 REV. 21, SEPTEMBER 2022
- d. No credit may be taken for manual actions within 10 minutes of a design basis accident. Analytically, it is assumed that containment heat removal begins at 10 minutes following a design basis LOCA. However, containment heat removal by activating an RHR heat exchanger for suppression pool cooling will be initiated in accordance with plant emergency operating procedures based on plant conditions.
Once containment cooling has been established, no further operator actions are required.
When calculating the long-term post-LOCA pool temperature transient, it is assumed that the initial suppression pool temperature and the RHRSW temperature are at their maximum values. This assumption maximizes the heat sink temperature to which the containment heat is rejected and thus maximizes the containment temperature. All heat sources in the containment are considered with no credit taken for any heat losses other than through the RHR heat exchanger. These heat sources are discussed in Section 6.2.1.3. In addition, the RHR heat exchanger is assumed to be in a fully fouled condition at the time the accident occurs. This conservatively minimizes the heat exchanger heat removal capacity.
Figure 6.2-10 shows the actual heat removal rate of the RHR heat exchanger. The resultant suppression pool temperature transient is described in Section 6.2.1.1.3.3.1 and is shown in Figure 6.2-9. Even with the degraded conditions outlined above, the maximum suppression pool temperature is maintained below the design limit of 220F.
The conservative evaluation procedure described above clearly demonstrates that the RHR system in the containment cooling mode meets its design objective of limiting the post-LOCA containment temperature transients safely.
6.2.2.4 Tests and Inspections The Suppression Pool floor and low pressure ECCS (RHR and Core Spray) suction strainers shall be visually inspected for sludge accumulation and foreign material. The visual inspection allows use of a remote camera in lieu of divers. The interval of these inspections shall be every other refueling outage.
Preoperational tests are performed to verify individual component operation, individual logic element operation, and system operation up to the drywell spray spargers. A sample of the sparger nozzles is bench-tested for flow rate versus pressure drop to evaluate the original hydraulic calculations. Finally, the spargers are tested by air to verify that all nozzles are clear.
The preoperational test program of the containment cooling system is described in Chapter 14.
A design flow functional test of the RHR pumps is performed for each pump during normal plant operation by taking suction from and returning to the suppression pool. The discharge valves to the reactor recirculation system loops remain closed during this test, and reactor operation is undisturbed.
An operational test of the discharge valves is performed by shutting the downstream valve after it has been satisfactorily tested, thereby establishing the RCPB at the downstream valve, and then operating the upstream valve. The discharge valves to the drywell spray headers are checked in a similar manner by operating the upstream and downstream valves individually. All these valves can be actuated from the control room by using remote manual switches. Control system design CHAPTER 06 6.2-42 REV. 21, SEPTEMBER 2022
LGS UFSAR provides automatic return from the test to the operating mode if LPCI initiation is required during testing.
The surveillance frequency for testing and inspection is discussed in Chapter 16.
6.2.2.5 Instrumentation Requirements The containment spray and suppression pool cooling modes of the RHR system are manually initiated from the control room. Once initiated, containment cooling performance is monitored by suppression pool temperature, flow, and containment pressure instrumentation. Details of the instrumentation are provided in Section 7.3.1.
6.2.3 SECONDARY CONTAINMENT FUNCTIONAL DESIGN The secondary containment consists of three distinct isolatable zones. Zones I and II are the Unit 1 and Unit 2 reactor enclosures, respectively. Zone III is the common refueling area. Each zone has an independent normal ventilation system which is capable of providing secondary containment zone isolation as required.
Each reactor enclosure (Zones I or II) completely encloses and provides secondary containment for its corresponding primary containment and reactor auxiliary or service equipment, including the RCIC system, RWCU system, SLCS, CRD system equipment, the ECCS, and electrical equipment components.
The common refueling area (Zone III) completely encloses and provides secondary containment for the refueling servicing equipment and spent fuel storage facilities for Units 1 and 2.
When a unit's primary containment is open, as it is during the refueling period, the associated reactor enclosure and common refueling area provide primary containment for the unit being refueled.
The ability to procedurally combine each of the reactor enclosure secondary containment zones to the common refueling area secondary containment zone exists. The combining of the associated isolation zones is accomplished via an interlock switch located on the auxiliary equipment room panels. Table 6.2-29 identifies the associated secondary containment ventilation system automatic isolation valves that are required for the combined zone alignment.
6.2.3.1 Design Bases
- a. The conditions that could exist following a LOCA or fuel handling accident require the establishment of a method of controlling any fission products that may leak into the secondary containment.
- b. The functional capability of the ventilation system to maintain negative pressure in the secondary containment with respect to the outdoors is discussed in Sections 6.5.1.1 and 9.4.2.
- c. The seismic design, leak-tightness, and internal and external design pressures of the secondary containment structure are discussed in Section 6.2.3.2 and Chapter 3.
CHAPTER 06 6.2-43 REV. 21, SEPTEMBER 2022
- d. The surveillance requirements for periodic inspection and functional testing of the secondary containment structure is discussed in the Technical Specifications.
6.2.3.2 System Design 6.2.3.2.1 Secondary Containment Design The secondary containment is designed and constructed in accordance with the design criteria outlined in Chapter 3. All of the major structural walls are constructed of reinforced concrete. All of the major structural floor slabs and roof slabs are constructed of reinforced concrete supported by structural steel framing.
The reactor enclosure secondary containment (Zones I and II) are designed to limit the inleakage to 200% of their zone free volume per day, and the refueling area secondary containment (Zone III) is designed to limit the inleakage to 50% of its zone free volume per day. These inleakage rates are based on a negative interior pressure of 0.25 in wg, while operating the SGTS. Following a LOCA the affected zone is maintained at this negative pressure by operation of the SGTS. The secondary containment zones are identified in Figures 6.2-27 through 6.2-35.
An analysis of the post-LOCA pressure transient in the Unit 1/2 reactor enclosure secondary containment was performed (Figure 6.2-52). The length of time following isolation signal initiation of the SGTS that the pressure in the secondary containment would exceed -0.25 in wg. is 15.5 minutes based on drawing down both reactor enclosures and the common refueling area simultaneously.
In addition to the pressure transient analysis, a detailed review has been performed to identify potential leakage paths from either the primary containment or the secondary containment to the common refueling area. This review resulted in the following changes which ensure that no leakage paths exits:
- a. A vent path from the reactor well to the reactor enclosure was added. When blind flanges are attached, the vent path will be through the associated opened drain lines or through a 1.5 inch hole in the blind flange.
- b. Normally closed valves on the reactor well skimmer drain lines were added.
- c. Provisions have been made to ensure that there is no flow path through the drain system between the refueling area and the reactor enclosure secondary containment.
Periodic tests are performed in accordance with the plant Technical Specifications to verify that the reactor enclosure secondary containment inleakage is less than 200% of its free volume per day at a negative interior pressure of 0.25 in wg.
The time line of events for actuating the SGTS is as follows:
Event Time (sec)
Start of accident 0 Signal to start diesel 3 Diesel ready to load 13 CHAPTER 06 6.2-44 REV. 21, SEPTEMBER 2022
LGS UFSAR Apply power to 480 V block 1 load 16 SGTS fans at rated speed 18 A maximum SGTS flow rate of 2800 cfm from a single reactor enclosure zone was used for the drawdown analysis.
The guidelines stated in the SRP 6.2.3 have been followed in calculating the drawdown time as noted:
a.
- 1. The heat transfer coefficients found in BTP CSB 6-1 apply to an atmosphere with high-energy blowdown where condensation on the primary containment surface is expected. Because the drawdown analysis was only 15.5 minutes long, the primary containment heat load was calculated as the steady-state load during normal operation when there are no condensation effects. This is accurate because LOCA conditions inside the primary containment will not affect the exterior surface temperature of the 6 foot containment wall significantly in 15.5 minutes. For steady-state heat load a conservative value was assumed.
- 2. Steady-state conduction and convection was calculated.
- 3. Radiant heat transfer was considered.
- b. Adiabatic boundary conditions were used.
- c. There will be negligible expansion of the 6 foot thick primary containment concrete walls in 15.5 minutes.
- d. Inleakage was considered.
- e. No credit was taken for outleakage.
- f. The analysis was based on the assumptions and delays indicated in the acceptance criteria.
- g. Heat loads generated within the secondary containment were considered.
- h. Fan performance characteristics were considered.
Information that demonstrates the external design pressure of the secondary containment structure ensures an adequate margin above the maximum expected external pressure for wind loadings, tornado loadings, and explosion loadings. This information is provided in Sections 3.3 and 2.2.3.
The openings provided for gaining access to the secondary containment are listed in Table 6.2-13, and are shown in Figures 6.2-27 through 6.2-33.
Personnel Access Doors:
At each secondary containment personnel access opening there are two doors, which are designated the inner door and the outer door. Each door is equipped with a door position switch to CHAPTER 06 6.2-45 REV. 21, SEPTEMBER 2022
LGS UFSAR provide monitoring. The monitoring circuitry consists of local indicating lights, local audible alarms, and control room annunciator lights and alarms. The monitoring operation is as follows:
- a. Both doors closed - the blue indicating lights located on both sides above each door are de-energized
- b. One door opened (either inner or outer) - the blue indicating lights above the door that is still closed are energized to warn against opening. The blue indicating lights above the opened door are still de-energized.
- c. Both doors opened - the blue indicating lights above each door are energized; an instantaneous audible local alarm is energized; a time delay relay is energized and, after a preset time, it energizes a control room annunciator to identify that secondary containment access has been breached.
Closure of one of the doors returns the system condition to the same status as in paragraph B, above.
Equipment Access Doors:
All equipment access doors are kept locked. Each door is equipped with a door position switch to provide constant monitoring. The monitoring circuitry consists of a blue light indication on both sides of each door; instantaneous audible local alarm; and time delayed alarm in the main control room. The monitoring operation is the same as for the Personnel Access Doors described above.
Entrances to the reactor enclosure are provided with air locks for separation. Access doors between reactor enclosure ventilation zones are provided with airlocks.
The railroad access shaft, located between Unit 1 and Unit 2, is accessible through airlocks to the reactor enclosures and through the refueling floor ventilation duct-work and access hatch to the refueling floor. The railroad access door position is constantly monitored and alarmed (in the plant security system), under the requirements defined in the Physical Security Plan. Administrative procedures require that the access shaft outside door be closed and locked unless the access shaft is sealed closed from the refueling area and the ventilation duct-work is blocked whenever the refueling area secondary containment is required to be maintained.
Each door and section of the hatch is equipped with a position switch to provide constant monitoring. The monitoring circuitry consists of a blue light indication on both sides of the railroad access door and the top of the refueling floor access hatch; instantaneous audible local alarm; and time delayed alarm in the main control room. The monitoring operation is the same as for the Personnel Access Doors described above.
The boundaries of the secondary containment are shown in Figures 6.2-27 through 6.2-35.
The secondary containment design data are in Table 6.2-14.
6.2.3.2.2 Secondary Containment Isolation System Isolation dampers and the plant protection signals that activate the secondary containment isolation system are described in Section 9.4.2.1.3.
CHAPTER 06 6.2-46 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.3.2.3 Containment Bypass Leakage Upon receipt of a reactor enclosure isolation signal, the RERS and the SGTS are automatically activated and begin to process all air flow streams from the reactor enclosure ventilation system.
Therefore, if a LOCA occurs, radioactivity that exfiltrates the steel-lined primary containment or piping systems containing radioactive fluids is collected and passed through the RERS and SGTS as described in Section 6.5.
The potential paths by which leakage from the primary containment can bypass the areas serviced by the SGTS have been evaluated. Table 6.2-15 identifies all primary containment penetrations, the termination region of all lines penetrating primary containment, and the bypass leakage barriers in each line. It has been determined that no potential bypass leakage paths exist except for the feedwater line following a feedwater line break inside containment and the TIP purge nitrogen supply line. No significant amounts of radioactivity will be released to the environment in either case, as discussed below.
Leakage through the containment isolation valves of the TIP purge line could be released from a break or equipment failure into the reactor enclosure, radwaste enclosure, or outdoors. Leakage into the reactor enclosure would not constitute a bypass leakage path because the reactor enclosure is serviced by the SGTS. Any leakage into the radwaste enclosure would not result in a significant release of radioactivity because of plateout, deposition, and transport delay within the TIP purge piping. The long lines within the reactor enclosure (>240 feet of 1 inch pipe and >220 feet of 6 inch pipe) and the presence of numerous valves in these lines (2 containment isolation valves, a 1/4 inch check valve, a 1/4 inch solenoid valve, a 1/4 inch metering valve, a 1 inch check valve, and a 1 inch globe valve) provide a long and tortuous route between the primary containment and the radwaste enclosure. Any leakage through the reactor enclosure and radwaste enclosure piping would be into the liquid nitrogen facility (tanks, vaporizers, control valves, etc.) located adjacent to the radwaste enclosure. The liquid nitrogen facility maintains system pressure at 50 psig.
A water seal cannot be maintained in the broken feedwater line by the feedwater fill system (Section 6.2.3.2.3.2) for the case of a feedwater line break inside containment. For this case, containment leakage may travel past the broken feedwater line's containment isolation valves into the portion of the feedwater line located in the turbine enclosure. However, a water seal in this portion of the feedwater line would be maintained by water from the CST as discussed in Section 6.2.3.2.3.1.
When designating the termination region, if either the system line that penetrates primary containment or any branch lines connecting to it penetrate the reactor enclosure, the termination region is listed in Table 6.2-15 as outside reactor enclosure. The types of bypass leakage barriers employed by these lines are:
- 1. Redundant primary containment isolation valves
- 2. Closed piping system inside primary containment
- 3. A water seal maintained for 30 days following a LOCA
- 4. The line beyond the outboard primary containment isolation valve is vented to the reactor enclosure by use of a vent line located upstream of the two block valves.
CHAPTER 06 6.2-47 REV. 21, SEPTEMBER 2022
- 5. A MSIV alternate drain pathway is provided.
- 6. The line contains a temporary spool piece that is removed during normal operation and replaced by blind flanges so that any leakage through the flange is into the reactor enclosure.
- 7. A closed seismic Category I piping system outside primary containment.
- 8. The line contains a spectacle flange with the blind side installed during normal operation. Any leakage through the flange will be into the reactor enclosure.
- 9. The line contains two spring loaded check valves and two manual stop valves.
Type 1 and Type 2 leakage barriers are considered to limit but not eliminate bypass leakage.
Leakage barriers of Type 3 through Type 9 are considered to effectively eliminate any bypass leakage.
Leakage from those lines terminating in the reactor enclosure is collected during the LOCA because the reactor enclosure is restored to and maintained at subatmospheric pressure and all exhaust is processed by the RERS and SGTS during these modes (Section 6.5). Therefore, lines terminating within the reactor enclosure are not considered potential bypass leakage paths.
Lines penetrating primary containment are isolated following a LOCA as described in Section 6.2.4.
All containment isolation valves and penetrations are designed to seismic Category I requirements.
The primary containment and penetration leakage is monitored during periodic tests as discussed in Section 6.2.6. Those penetrations for which credit is taken for water seals as a means of eliminating bypass leakage (Table 6.2-15) are preoperationally leak tested with water and Technical Specification leakage rates are given as water leak rates.
6.2.3.2.3.1 Water Seals In each case where water seals are used to eliminate the potential of reactor enclosure bypass leakage, a 30 day water seal is assured because either a loop seal is present or the water for the seal is provided from a large reservoir. The water seals for all of these lines will be maintained at a pressure greater than the peak containment accident pressure. Each of the water seals listed in Table 6.2-15 is discussed below (some penetrations may be listed more than once due to the presence of multiple types of water seals).
- a. Penetrations 9A, 9B, and 44:
The feedwater fill system (Section 6.2.3.2.3.2) is used to maintain a water seal in the lines downstream of these penetrations. The feedwater fill system cannot maintain a water seal in the feedwater lines (penetrations 9A and 9B) following a feedwater line break inside containment. However, for this case, a water seal will be maintained in the piping and equipment between the CST and the feedwater penetrations because:
- 1. The elevation of the primary containment penetrations is 287 ft.
- 2. The elevation of the minimum CST water level is 246 ft.
CHAPTER 06 6.2-48 REV. 21, SEPTEMBER 2022
- 3. The low point of the makeup water line is at elevation 220 ft.
Therefore, the water seal will be maintained in that portion of the piping system below el 246'. This water seal will be able to withstand the containment pressure resulting from a feedwater line break as discussed below.
Immediately after the line break, when containment pressure will be at its peak, the feedwater line will still have a pressure greater than the pressure in primary containment. The feedwater will flash into steam at the break until the line pressure matches the containment pressure, thus preventing any containment atmosphere from entering the line during this period. In addition, there are several valves in the feedwater line between the primary containment and the water seal. A pressure decrease will occur across each valve, reducing the pressure that the water seal will encounter. Figures 6.2-3 and 6.2-7 show the primary containment pressure transient following a recirculation line break. These figures show that the maximum long-term pressure post-LOCA is approximately 17 psig. The difference in elevation between the lowest point of the water seal and the minimum CST water level indicates a head of 20 psig, which is greater than the pressure that the primary containment will exert on the water seal.
The piping and equipment that comprise this potential bypass leakage flow path is continuously inspected during normal operation when pressures are more than ten times greater than post-LOCA pressures. Even considering liquid leakage from the components in the water seal, the volume of water contained in the CST is sufficiently large to ensure that a water seal is maintained for at least 30 days.
- b. Penetrations 204A, 204B, 207A, 207B, 208B, 210, 212, 215, 216, 217, 226A, 226B, 235, 236, 238, 239, and 240:
The lines associated with these penetrations all penetrate the wetwell above the suppression pool water level and terminate at least 4 feet below the minimum suppression pool water level. A 30 day water seal is therefore assured on the submerged portion of line.
- c. Penetrations 13A, 13B, 16A, 16B, 17, 39A, 39B, 45A-D, 205A, and 205B:
Piping connected to these penetrations is normally full of water and will be kept full after a LOCA due to operation of the ECCS and/or safeguard piping fill system.
The suppression pool is the water source for the ECCS and fill system, and therefore a 30 day water supply is assured.
The lines associated with these penetrations all penetrate the wetwell at least 11 feet below the minimum water level of the suppression pool, and therefore a 30 day water seal is assured.
- e. Penetrations 231A and 231B:
CHAPTER 06 6.2-49 REV. 21, SEPTEMBER 2022
LGS UFSAR The line to the containment isolation valves from the drywell floor drain sump is maintained full of water by an elevation difference between the sump and the valves. The line to the containment isolation valves from the drywell equipment drain tank is maintained full of water by an elevation difference between the tank and the valves.
- f. Penetrations 10, 11, 12, 44, 228D, and 241:
Lines associated with these penetrations that pass through the secondary containment boundary and take credit for water seals are provided with loop seals inside secondary containment, which eliminates the possibility of bypass leakage.
The HPCI and RCIC steam supply line connections to Auxiliary Steam contain spectacle flanges. After testing, the blind portion of the spectacle flange shall be installed. These spectacle flanges are shown on drawing M-55 (lines 4" GBD-137 and GBD-237) and on drawing M-50 (lines 3" GBD-136 and GBD-236).
- g. Penetration 14:
The minimum piping height inside primary containment of the RWCU supply line that branches off the recirculation loop is at el 267'. The primary containment penetration is at el 297' and the RPV penetration is at el 280'. This elevation difference ensures that a water seal is maintained in the line from the RPV to the containment isolation valves. The RWCU supply branch line that connects to the bottom of the vessel is normally full of water, and the water will be maintained in this line because it connects directly to, and below, the vessel.
The CRD insert and withdraw lines are normally full of water. A water seal will be maintained in these lines after a LOCA due to the elevation difference between the containment penetrations (el 265') and the connections to the control rod drives (el 215').
- i. Penetrations 23, 24, 53, 54, 55, and 56:
Both the drywell chilled water system and the RECW system have a system vent in the refueling area. A 30 day water seal is provided between the system vent and the containment penetrations. These systems are normally full of water and are inspected during normal operation, when system pressure is greater than post-LOCA containment pressure, to ensure that leakage is minimized. These systems have an interconnecting line between them which decreases the possibility of depleting their water seals. The systems each contain a head tank with a water-retaining boundary qualified to LOCA (hydrodynamic) loads. These tanks increase the system water inventory and maintain the head of water in the system piping greater than the maximum containment pressure following a LOCA.
- j. Penetration 61:
The recirculation pump seal purge lines are vented to secondary containment by use of vent lines located before two block valves and the secondary containment (drawings M-43 and M-46). The normally open block valves (HV127 and HV128)
CHAPTER 06 6.2-50 REV. 21, SEPTEMBER 2022
LGS UFSAR receive an automatic containment isolation signal to close, which is shown as Reference 18 on drawing M-46. It is not necessary for the containment isolation signal to also automatically open the (normally closed) vent valves. The seal lines are normally filled with water, which will spill into secondary containment when the vent valves open. To preclude the possibility of this happening in the event of a false LOCA, the vent valves will be manually actuated to open when the operator has verified that isolation and venting of these lines is required. The water in the lines will provide a temporary seal to prevent bypass leakage until the vent valves are opened.
6.2.3.2.3.2 Feedwater Fill System The feedwater fill system prevents the release of fission products through the feedwater containment isolation valves after a LOCA by providing a water seal downstream of the valves.
6.2.3.2.3.2.1 Safety Design Bases The feedwater fill system is designed with sufficient capacity and capability to prevent leakage through the feedwater lines under the conditions associated with the entire spectrum of LOCAs except for a feedwater line break inside containment.
The feedwater fill system conforms to seismic Category I requirements. Quality group classifications are shown in Table 3.2-1, Item XI.A. The system meets the intent of Regulatory Guide 1.96, where applicable.
The feedwater fill system is capable of performing its safety function considering the effects resulting from a LOCA, including missiles that may result from equipment failures, dynamic effects associated with pipe whip and jet forces, and normal operating and accident-caused local environmental conditions consistent with the design basis event. Furthermore, any portion of the feedwater fill system that is quality Group A and is located outside the primary containment structure is protected from missiles, pipe whip, and jet force effects originating outside the containment so that containment integrity is maintained.
The feedwater fill system is capable of performing its safety function following a LOCA and an assumed single active failure.
The feedwater fill system is designed so that effects resulting from a single active component failure do not affect the integrity or operability of the feedwater lines or the feedwater containment isolation valves.
The feedwater fill system is capable of performing its safety function following a LOOP coincident with a postulated design basis LOCA.
The feedwater fill system is designed to prevent leakage from the feedwater lines consistent with maintaining containment integrity for up to 30 days.
The feedwater fill system is manually actuated and is not required to be actuated sooner than 30 minutes after a LOCA.
The feedwater fill system, including instrumentation and circuits necessary for the functioning of the system, is designed in accordance with standards applicable to an ESF.
CHAPTER 06 6.2-51 REV. 21, SEPTEMBER 2022
LGS UFSAR The plant is designed to permit testing of the operability of the feedwater fill system controls and actuating devices during power operation, to the extent practicable, and to permit testing of the complete functioning of the system during plant shutdowns.
6.2.3.2.3.2.2 System Description The feedwater fill system is a subsystem of the safeguard piping fill system. The safeguard piping fill pumps provide suppression pool water as the water seal source for the feedwater lines (Section 6.3.2.2.6 and drawing M-52). The feedwater fill system consists of two fill trains, one from each fill pump. Each train is routed to both feedwater lines (drawing M-41).
Following a LOCA, the feedwater fill system is manually initiated from the control room. A water seal is provided by the fill system in both feedwater lines for all line breaks other than a feedwater line break inside containment. For this case, the feedwater fill system can be isolated from the broken feedwater line so that a water seal can be maintained in the intact feedwater line. A water seal inside the broken feedwater line cannot be maintained by the fill system for the case of a feedwater line break inside containment because the water escapes out the broken pipe into primary containment.
The sealing water to the valves eventually fills the feedwater lines up to the reactor vessel, and the water returns to the suppression pool through the LOCA break. Because the source of sealing water is the suppression pool, a 30 day water supply is assured. Operation of the feedwater fill system will not affect the function of the suppression pool because the seal water is eventually returned to the pool when the drywell is flooded back through the downcomers.
6.2.3.2.3.2.3 Safety Evaluation The feedwater fill system is designed to prevent the release of radioactivity through the feedwater line isolation valves by providing a continuous flow of water through the feedwater lines following a LOOP coincident with the postulated design basis LOCA. The two redundant fill trains are physically separated, except where the lines are interconnected, to minimize the exposure to missiles and to the effects of pipe whip or jet impingement from high energy line breaks.
The feedwater fill system is seismic Category I and is capable of performing its intended function following an active component failure. Each fill train is powered from a different division of the Class 1E power supply. Double series isolation valves are provided to ensure that no single active failure will affect the integrity of the feedwater lines.
Feedwater line pressure is indicated in the control room so that the operator can determine if there has been a feedwater line break inside containment. If so, the operator can isolate the system from the broken line and still provide fill system water to the intact line.
6.2.3.2.3.2.4 Instrumentation and Controls The instrumentation necessary for control and status indication of the feedwater fill system is classified as essential and, as such, is designed and qualified in accordance with applicable IEEE standards to function under seismic Category I and LOCA environmental loading conditions appropriate to its installation, with the control circuits designed to satisfy the mechanical and electrical separation criteria. Section 7.6 gives a control and instrumentation description.
CHAPTER 06 6.2-52 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.3.2.3.2.5 Inspection and Testing Preoperational tests for the safeguard piping fill system are discussed in Chapter 14. During plant operation, valves, piping, instrumentation, electrical circuits, and other components outside the steam tunnel can be inspected visually at any time. Complete system functional testing or isolation valve testing from fully closed-to-open and the return open-to-closed position is performed during reactor shutdown.
6.2.3.3 Design Evaluation The design evaluation of the secondary containment ventilation systems are given in Sections 6.5.1 and 9.4.2. The high energy lines within the secondary containment are identified and pipe ruptures analyzed in Section 3.6. The leak-off system on the nitrogen purge lines has two outboard block valves in series downstream of the leak-off vent valves and the secondary containment boundary. The liquid nitrogen facility is located outside of secondary containment.
Therefore, a failure of one of the outboard block valves does not prevent a negative pressure from being maintained in the secondary containment structure or result in leakage from the primary containment across the inboard valve to the environment.
6.2.3.4 Tests and Inspections The program for initial performance testing is described in Chapter 14. The program for periodic functional testing of the secondary containment structures including SGTS drawdown time and the secondary containment isolation system and system components is described in Chapter 16. The leak rate testing program and provisions are discussed in Section 6.5.1, as part of the SGTS tests.
6.2.3.5 Instrumentation Requirements The control systems to be employed for the actuation of the reactor enclosure ESF air handling systems are described in Section 7.3.
The control and monitoring instrumentation for the above systems is discussed in Sections 6.5.1 and 9.4.2. Design details and instrumentation logic are discussed in Section 7.3.
6.2.4 CONTAINMENT ISOLATION SYSTEM The containment isolation system is designed to prevent or limit the release of radioactive materials that may result from postulated accidents. This is accomplished by providing isolation barriers in all fluid lines that penetrate primary containment.
6.2.4.1 Design Bases
- a. The containment isolation system is designed to allow the normal or emergency passage of fluids through the containment boundary while preserving the ability of the boundary to prevent or limit the escape of radioactive materials that can result from postulated accidents.
- b. The containment isolation system is designed to either automatically isolate fluid penetrations or provide the capability for remote manual isolation from the control room.
CHAPTER 06 6.2-53 REV. 21, SEPTEMBER 2022
- c. The arrangement of containment isolation valves for fluid systems that penetrate the primary containment conforms to GDC 54, 55, 56, and 57 to the greatest extent practicable.
- d. Fluid instrument lines that penetrate primary containment conform to the isolation criteria of Regulatory Guide 1.11 to the greatest extent practicable.
- e. Containment isolation provisions are designed to withstand the most severe natural phenomenon or site-related event (e.g., earthquake, tornado, wind, flood, or transportation accident) without impairing their functions.
- f. The containment isolation system is designed with provisions for periodic operability and leak rate testing.
- g. Valve closure times are selected to limit the release of containment atmosphere to the environs, to mitigate offsite radiological consequences, and to ensure that ECCS effectiveness is not degraded.
- h. Design provisions are made to detect possible leakage from lines provided with remote manually controlled isolation valves.
- i. Isolation valves, actuators, and controls are protected against loss of functional capability from missiles and accident environments for which they are designed.
- j. Redundancy and physical separation are provided in the electrical and mechanical design to ensure that no single failure in the containment isolation system can prevent the system from performing its intended function (except as described in this section).
- k. The design of the control systems for automatic containment isolation valves is such that resetting the isolation signal does not result in the automatic reopening of containment isolation valves (except as described in this section).
6.2.4.2 System Design Table 6.2-17 lists the fluid system and instrument line containment penetrations and presents design information about each. Accompanying this table is Figure 6.2-36, which consists of diagrams for the various isolation valve arrangements. Cross references are provided between the diagrams and the table.
The plant protection signals and instrumentation that initiates containment isolation are discussed in Section 7.3.1.1.2.
Evaluation of the containment isolation system with respect to the following areas is discussed in separate sections as indicated:
- a. Code class and seismic design Section 3.2
- b. Missile protection Section 3.5
- c. Protection against dynamic Section 3.6 CHAPTER 06 6.2-54 REV. 21, SEPTEMBER 2022
LGS UFSAR effects associated with the postulated rupture of piping
- d. Environmental design Section 3.11 Debris transported to the suppression pool by the emergency core cooling water is prevented from entering the ECCS suction lines by suction strainers. The suction strainers are described in Section 6.2.2.
Assurance of the operability of valves and valve operators in the containment atmosphere under normal plant operating conditions and postulated accident conditions is discussed in Section 3.9.3.
Provisions for detecting leakage from systems connected to the RCPB which are provided with manual isolation valves are discussed in Section 5.2.5.
The design provisions for testing the operability of the isolation valves and the leakage rate of the containment isolation barriers are discussed in Section 6.2.6.
An alternate drain pathway is provided for the MSIVs, and is discussed in Section 6.7. A seismic Category I fill system provides a water seal for the feedwater lines, as discussed in Section 6.2.3.2.3.
Containment isolation valve closure times are selected to ensure rapid isolation of the containment following postulated accidents. The isolation valves, in lines that provide an open path from the containment to the environs, have closure times that limit the release of containment radioactivity to the environs to below 10CFR50.67 dose limits, mitigate the offsite radiological consequences, and ensure that ECCS effectiveness is not degraded. These valve closure times are identified with a double asterisk in Table 6.2-17. The isolation valves for lines in which HELBs can occur have closure times that limit the resultant pressure and temperature transients as well as the radiological consequences. These valve closure times are identified with a single asterisk in Table 6.2-17.
All of the isolation valve closure times listed in Table 6.2-17 are the actual closure times that the isolation valves were purchased with, which in all cases are equal to or lower than the closure times necessary to meet the aforementioned design requirements. The given valve closure times are the maximum time it takes for a valve to move to its fully closed position after power has reached the operator assembly. Those closure times which are required to be met to satisfy isolation valve closure time design requirements are identified by a single or double asterisk in Table 6.2-17.
The essential/nonessential classification of containment isolation valves, as listed in Table 6.2-17, was based on the following: those systems identified as essential are regarded as indispensable or are backup systems in the event of an accident; nonessential systems have been judged to not be required after an accident. The classification of essential and nonessential systems is given in Table 6.2-27.
Isolation valves are designed to be operable under environmental conditions such as maximum differential pressures, seismic occurrences, steam atmosphere, high temperature, and high humidity. The normal and accident environmental conditions are described in Section 3.11.
Refer to Table 6.2-17 for isolation valve power supplies.
CHAPTER 06 6.2-55 REV. 21, SEPTEMBER 2022
LGS UFSAR Motor-operated isolation valves remain in their last position upon failure of electrical power to the motor operator. Air operated containment isolation valves are spring-loaded to close upon loss of air or electrical power.
The design of the isolation valve system gives consideration to the possible adverse effects of sudden isolation valve closure when the plant systems are functioning under normal operation.
Reopening of the containment isolation valves requires deliberate operator action. The HPCI and RCIC steam line isolation valves are exceptions as discussed in Section 7.1.2.11. Control systems for the automatic containment isolation valves are discussed in Section 7.3.1.1.2.
The LGS containment purge valves have been designed to function if a LOCA should occur while the purge valves were open. The valve manufacturer has completed an extensive program of tests and analyses to demonstrate the operability of the valves in accordance with all published NRC guidelines and criteria. The following is a brief summary of the factors addressed in the valve operability qualification report (Reference 6.2-8):
- a. Valves are supplied in accordance with ASME Section III, Class 2 requirements
- b. Finite-element analyses have been used to determine valve component stress levels for limiting combinations of loads
- c. The impact of dynamic loadings is addressed by analysis and static load testing
- d. All valves are located outside containment, thus eliminating concern over the effects of containment pressure on pneumatic operator performance
- e. Air operators are equipped with springs to facilitate valve closure; accumulators or other pneumatic systems are not used for valve closure or sealing
- f. Valve dynamic torque coefficients have been determined by reduced-scale and full-scale testing
- g. The effects of installation geometry and arrangement have been fully considered
- h. Containment pressure has been conservatively assumed to be constant at its maximum pressure for all valve angles
- i. Back pressure caused by flow through downstream piping has been conservatively neglected
- j. Elastomeric materials are not used for valve seating surfaces
- k. Valve operators and pilot solenoids have been qualified to IEEE 323 (1974) and NUREG-0588 Category I requirements
- l. Motor operator performance has been demonstrated at minimum available voltage levels
- m. Motor operators are equipped with hand wheels which automatically disengage upon electric activation CHAPTER 06 6.2-56 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.4.3 Design Evaluation The main objective of the containment isolation system is to provide protection by limiting release to the environment of radioactive materials. This is accomplished by isolation of system lines penetrating the primary containment. Redundancy is provided so that the active failure of any single valve or component does not prevent containment isolation.
The arrangements of isolation valves are described in Table 6.2-17 and Figure 6.2-36. In general, isolation valves have redundancy in the mode of actuation as indicated in Table 6.2-17. A program of testing, described in Section 6.2.4.4, is maintained to ensure valve operability and leak-tightness.
The design specifications require each isolation valve to be operable under the most severe environmental conditions that it might experience. Protection from potential missiles is discussed in Section 3.5.
Provisions for administrative control of the proper position of all nonpowered isolation valves, including valves in test, vent, drain, and similar types of branch lines that serve as containment isolation barriers, are maintained. The test taps, vents, drains, and similar types of branch lines that constitute containment isolation barriers are equipped with manually closed isolation valves.
Administrative controls will ensure that the valves are locked closed after use.
All power-operated isolation valves have position indicators in the control room. Discussion of instrumentation and controls for the isolation valves is included in Chapter 7.
6.2.4.3.1 Evaluation Against General Design Criteria 6.2.4.3.1.1 Evaluation Against GDC 54 All piping systems penetrating containment, other than instrument lines, are designed in accordance with GDC 54.
6.2.4.3.1.2 Evaluation Against GDC 55 GDC 55 requires that lines which penetrate the primary containment and form a part of the RCPB must have two isolation valves; one inside the containment and one outside, unless it can be demonstrated that the containment isolation provisions for a specific class of lines are acceptable on some other basis.
The RCPB, as defined in 10CFR50, Section 50.2 (v), consists of the RPV, pressure-retaining appurtenances attached to the vessel, and valves and pipes that extend from the RPV up to and including the outermost isolation valve.
6.2.4.3.1.2.1 Influent Lines All influent lines that penetrate the primary containment and connect directly to the RCPB are equipped with at least two isolation valves, one inside the drywell, and the other outside the drywell and as close to the external side of the containment as practicable.
CHAPTER 06 6.2-57 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.4.3.1.2.1.1 Feedwater Line The feedwater lines are part of the RCPB as they penetrate the drywell to connect with the RPV.
Each of the two feedwater penetrations is provided with a series arrangement of three isolation valves:
- a. A check valve is provided inside the drywell as close to the containment wall as practicable. For a worst case break of a feedwater line inside containment, it would be impossible to ensure the operability of the inboard check valve due to pipe whip forces.
- b. A spring assisted check valve is provided outside the drywell as close to the containment wall as practicable. The spring forces the valve flapper in the closed direction, thus providing added assurance of valve seating in the event of low pressure in the supply piping. The spring will not prevent flow in the downstream (toward the vessel) direction but does create some flow restriction. An air operator is provided with the check valve assembly. This air operator is normally pressurized, thus compressing the spring and reducing the flow restriction.
- c. A third check valve is provided in the feedwater line outboard of the above described spring assisted check valve. The function of these valves is to:
- 1. Prevent HPCI, RCIC, and RWCU water from flowing upstream in the feedwater line, thus ensuring flow into the reactor vessel.
- 2. Provide isolation in the event of a feedwater line break upstream of this valve.
This third check valve includes a motor operator to seal the disc closed for long-term leakage control.
Additional isolation valves are provided on each of the lines connecting to the feedwater lines inboard of the check valve :
- 2. A spring assisted check valve is provided on the RWCU supply line. This valve is of a design similar to the outboard spring assisted feedwater check valves described above. This RWCU check valve is spring assisted to seal the disc closed for long-term leakage control.
In the Limerick SER Section 6.2.4, licensee committed to administrative procedures that will require isolation of the main feedwater, RWCU, RCIC, and HPCI system lines following an accident if these systems are not providing reactor coolant makeup. The NRC included this commitment in the SER to satisfy SRP 6.2.4.6.b criteria. Instead of using a leakage detection system in conjunction with a remote manual containment isolation valve, to satisfy SRP criteria, these valves would be procedurally controlled and remotely closed from the control room to provide long term leakage protection after a postulated LOCA to satisfy SRP criteria.
Plant procedures will require remote manual closure of the remote manual containment isolation valves in the main feedwater and RWCU systems, if reactor coolant makeup is no longer required.
The containment isolation valves in the RCIC and HPCI system automatically reposition closed, if CHAPTER 06 6.2-58 REV. 21, SEPTEMBER 2022
LGS UFSAR reactor coolant makeup is no longer required from these systems. Therefore, plant procedures will not be required to remote manually close the RCIC and HPCI containment isolation valves.
Limerick SER Section 6.2.4 also states that a remote-manual motor-operated valve upstream of the air-operated check valve on the RWCU branch line that can also be utilized to isolate this line. This non-safety related remote-manual motor-operated valve upstream of the air-operated check valve is not capable of, or required to support a safety related long-term leakage control function as described in the SER.
6.2.4.3.1.2.1.2 Core Spray (CS) Loop B The CS loop B line penetrates the drywell to inject directly into the RPV. Isolation is provided by two valves in the CS line, a pneumatic testable check valve inside the containment, and a spring assisted check valve outside the containment, with positions of both indicated in the main control room. The core spray loop B line is also provided with a normally closed pneumatic operated globe valve which bypasses the inboard isolation valve for equalization during testing.
Although not a containment isolation valve, a MOV is provided outboard of the spring assisted check valve to provide isolation of this flow path for long-term leakage control.
One branch of the HPCI line connects to the CS loop B upstream of the outboard spring assisted check valve. Although not a containment isolation valve, the HPCI line also contains a MOV outboard of the spring assisted check valve to provide isolation of this flow path for long-term leakage control.
6.2.4.3.1.2.1.3 LPCI and CS Loop A The LPCI lines and CS loop A line are provided with remote manually controlled gate valves outside and pneumatic testable check valves inside containment. Both types of valves are normally closed with the gate valves receiving an automatic signal to open at the appropriate time.
The check valves are located as close as practicable to the RPV. The normally closed check valves limit containment pressurization if there is a pipe rupture between the check valve and containment wall. The core spray loop A line and the LPCI lines are also each provided with a normally closed pneumatic operated globe valve which bypasses the inboard isolation valve for testing purposes.
6.2.4.3.1.2.1.4 Deleted 6.2.4.3.1.2.1.5 Recirculation Pump Seal Purge Line The recirculation pump seal purge line extends from the CRD supply line outside primary containment, penetrates primary containment through an excess flow check valve outside and a check valve inside containment, and connects to the recirculation pump seal housing. The 1 inch recirculation pump seal purge line is Quality Group Classification A from the pump up to and including the excess flow check valve outside containment. Should this line be postulated to fail and either one of the check valves is assumed to fail open, the flow rate through a broken line outside containment is calculated to be substantially less than that permitted for a broken instrument line. Therefore, the two check valves in series provide sufficient isolation capability for the postulated failure of this line.
6.2.4.3.1.2.1.6 Standby Liquid Control System Lines CHAPTER 06 6.2-59 REV. 21, SEPTEMBER 2022
LGS UFSAR The SLCS line penetrates the drywell and connects to the Core Spray loop B line. In addition to a simple check valve inside the drywell, a globe stop-check valve is located outside the drywell.
Since the SLCS line is a normally closed, nonflowing line, rupture of this line is of extremely remote probability. The globe stop check includes a motor operator to seal the valve closed for long-term leakage control.
6.2.4.3.1.2.1.7 RWCU System The RWCU pumps, heat exchangers, and filter/demineralizers are located outside the drywell.
The return line branches into three separate lines outside the drywell. One line connects to the RCIC line that connects to the B feedwater line penetrating the drywell and injecting directly into the RPV. The second branch connects directly to the A feedwater line that penetrates the drywell and injects directly into the RPV.
Isolation of both these lines is provided by the feedwater system check valves inside and outside the containment and a spring assisted check valve in the connecting RWCU return line.
Following a LOCA, it is desirable to maintain reactor coolant makeup. For this reason, the above remote manual containment isolation valves are not provided with automatic isolation signals.
However, plant procedures will require remote manual closure of the remote manual containment isolation valves, if reactor coolant makeup is no longer required.
The third line penetrates the drywell and then connects to the A feedwater line that injects directly into the RPV. This line is only used during outages. Isolation is provided by one locked closed globe valve inside containment and one locked closed globe valve outside containment. A 3/4 inch relief valve is provided outside containment between the two isolation valves for thermal relief.
6.2.4.3.1.2.1.8 RCIC Line The RCIC line connects to the B feedwater line outside containment that penetrates the drywell to inject directly into the RPV. The feedwater line has a check valve both inside and outside the drywell. In addition to these two isolation valves, a motor- operated gate valve is located in the RCIC line that is normally closed and receives an automatic signal to open. Following a LOCA, plant procedures will require remote manual closure of this isolation valve unless RCIC is providing reactor coolant makeup.
6.2.4.3.1.2.1.9 RHR Shutdown Cooling Return Each RHR shutdown cooling return line penetrates primary containment and discharges into a recirculation pump discharge line that injects directly into the RPV. Isolation is provided by an automatically actuated motor-operated globe valve outside containment and a pneumatic testable check valve and a spring-assist check valve inside containment. A normally closed pneumatic operated globe valve is provided which bypasses the inboard isolation testable check valve for equalization during testing. To increase the reliability of RHR shutdown cooling mode during refueling outages, the automatic isolation function of the RHR shutdown cooling mode return motor-operated valves is typically bypassed provided that automatic isolation is not required by the Technical Specifications or Technical Requirements Manual and the reactor cavity is flooded up.
Manual isolation capability is retained.
6.2.4.3.1.2.2 Effluent Lines CHAPTER 06 6.2-60 REV. 21, SEPTEMBER 2022
LGS UFSAR Effluent lines that form part of the RCPB and penetrate containment are equipped with at least two isolation valves; one inside the drywell and the other outside, located as close to the containment as practicable or justified on an alternate basis.
6.2.4.3.1.2.2.1 Main Steam, RCIC and HPCI Steam Lines, and RHR Shutdown Cooling Supply Line The main steam lines extend from the RPV to the main turbine and condenser system, and penetrate the primary containment. For these lines, isolation is provided by automatically actuated globe valves, one inside the containment and one just outside the containment. The MSIVs are spring-loaded, pneumatic, piston- operated globe valves designed to fail closed on loss of pneumatic pressure or loss of power to the solenoid-operated pilot valves. Each valve has two independent pilot valves supplied from independent power sources. Each MSIV has an accumulator to assist in its closure upon loss of normal supply. The springs and accumulator provide a local stored energy source dedicated to closure of an MSIV under all conditions which requires MSIV closure.
The main steam line drain connects to the main steam lines inside containment and extends through containment to the condenser. This line is provided with motor-operated gate valves inside and outside containment that receive an automatic isolation signal to close when the reactor water level drops below Level 1.
The RCIC turbine steam supply line from main steam line B is provided with two motor-operated, normally open globe valves, one inside and one outside the containment. These valves are closed on receipt of an RCIC isolation signal. The HPCI system turbine steam supply line from main steam line C is provided with motor-operated, normally open globe valves, one inside and one outside containment. These valves are closed on receipt of a HPCI isolation signal.
The RCIC and HPCI steam lines are each also provided with a normally closed motor-operated globe valve that bypasses the outboard isolation valve for steam supply line warmup purposes only. The valve in the RCIC steam line is closed upon receipt of an RCIC isolation signal, and the HPCI steam line valve is closed upon receipt of an HPCI isolation signal. The isolation signals are considered adequate because there is no consequence if the valves open or leak while the system is in operation and appropriate isolation signals are provided to secure the line when system isolation is required.
The RHR shutdown cooling supply line is provided with motor- operated gate valves, one inside and one outside containment, that receive an automatic isolation signal when isolation is required.
To increase the reliability of RHR shutdown cooling mode during refueling outages, the automatic isolation function of the RHR shutdown cooling mode supply motor-operated valves is typically bypassed provided that automatic isolation is not required by the Technical Specifications or Technical Requirements Manual and the reactor cavity is flooded up. Manual isolation capability is retained.
6.2.4.3.1.2.2.2 Main Steam and Recirculation System Sample Lines Sample lines from the main steam and recirculation lines penetrate the primary containment.
These lines are provided with air operated globe valves, one inside and one outside containment, that receive an automatic isolation signal if there is an accident, or fail closed on loss of air or electrical power.
6.2.4.3.1.2.3 CRD Lines CHAPTER 06 6.2-61 REV. 21, SEPTEMBER 2022
LGS UFSAR The CRD system has multiple lines, the insert and withdraw lines, that penetrate primary containment.
The classification of these lines is Quality Group B, and they are designed in accordance with ASME Section III, Class 2. The basis on which the CRD insert and withdraw lines are designed is commensurate with the safety importance of maintaining the pressure integrity of these lines.
The CRD insert and withdrawal lines are not provided with automatic containment isolation valves in order to maximize the reliability of the scram function. A ball check valve located in the CRD flange housing automatically seals the insert line in the event of a line break. The insert and withdrawal lines terminate in HCUs which contain multiple valves (manual, solenoid, air operated, and check valves) to control CRD movement, and limit leakage. The isolation function is provided by two redundant simple check valves outboard of the HCUs on each main water header (charging, cooling, drive and exhaust). All automatic valves in the HCUs are normally closed and are open only during rod movement. Because the scram valves in the HCU are normally open after a scram, the scram discharge volume is provided with redundant automatic vent and drain valves.
6.2.4.3.1.2.4 Conclusion on GDC 55 In order to ensure protection against the consequences of accidents involving the release of radioactive material, pipes that form the RCPB are shown to provide adequate isolation capabilities on a case-by-case basis. In all cases, a minimum of two barriers are shown to limit the release of radioactive materials.
The pressure-retaining components that comprise the RCPB are designed to meet other appropriate requirements that limit the probability or consequences of an accidental pipe rupture.
The quality requirements for these components ensure that they are designed, fabricated, and tested to the highest quality standards of all reactor plant components. The classification of components that comprise the RCPB are designed in accordance with ASME Section III, Class 1, with the exception of the CRD insert and withdrawal lines as discussed in Section 6.2.4.3.1.2.3 above.
It is therefore concluded that the design of piping systems that comprise the RCPB and penetrate containment either meet the explicit requirements of, or are acceptable alternatives to the explicit requirements of GDC 55.
6.2.4.3.1.3 Evaluation Against GDC 56 GDC 56 requires that lines which penetrate the containment and communicate with the containment interior must have two isolation valves; one inside the containment and one outside, unless it can be demonstrated that the containment isolation provisions for a specific class of lines are acceptable on some other basis.
6.2.4.3.1.3.1 Influent and Effluent Lines to Suppression Pool Typically, lines which connect directly to the suppression pool are provided with a single remote manual or automatic isolation valve. These valves are attached to lines which are an extension of the containment and are enclosed in a pump-room adjacent to the containment which has CHAPTER 06 6.2-62 REV. 21, SEPTEMBER 2022
LGS UFSAR provisions for environmental control of any fluid leakage. The lines to the suppression pool are always submerged so no containment atmosphere can impinge upon the valves.
The systems which the lines from the suppression pool connect to outside containment are closed systems meeting the appropriate requirements of closed systems, except for the suppression pool cleanup line and the RCIC vacuum pump discharge line. Both of these lines have redundant containment isolation valves.
The valves provide a barrier outside containment to prevent loss of suppression pool water should a leak develop downstream of the valves in the lines from the suppression pool. (The valves are either remotely closed from the control room or automatically closed to accomplish this. Leak detection is provided for the lines outside containment so that the operator can determine which valve is to be closed.) Should a leak develop outside containment, the fluid will be contained within compartments that have provisions for the environmental control of any fluid leakage. The configuration of the connection of the lines to the suppression pool assures that the connections are always submerged, and prevents escape of containment atmosphere.
6.2.4.3.1.3.1.1 CS, HPCI, and RHR Test Lines and Minimum Flow Bypass Lines The CS, HPCI, and RHR test and minimum flow bypass lines have isolation capabilities commensurate with the importance to safety of isolating these lines.
The RHR pump test lines connect to the associated minimum flow bypass lines outside primary containment and penetrate containment through normally open, remote manually controlled gate valves located directly on the containment. This reduces the number of penetrations through the primary containment, thus minimizing the potential pathways for radioactive material release.
The CS pump test lines have a normally closed, motor-operated globe valve located directly on the containment that receives an automatic isolation signal if there is an accident. The CS minimum flow bypass lines have a normally open motor-operated globe valve that receives an automatic isolation signal when adequate flow is established in the pump discharge lines.
The HPCI pump test line has a normally closed motor-operated gate valve located directly on the containment that receives an automatic isolation signal if there is an accident. The minimum flow bypass line has a normally closed motor-operated globe valve located directly on the containment that receives an automatic isolation signal when adequate flow is established in the pump discharge lines.
The CS, HPCI and RHR pump test and minimum flow bypass lines discharge below the surface of the suppression pool. Thus the lines are not directly open to the containment atmosphere.
6.2.4.3.1.3.1.2 RCIC Turbine Exhaust, Vacuum Pump Discharge, and RCIC Pump Minimum Flow Bypass Lines The lines that penetrate the containment and discharge to the suppression pool are equipped with a remote manually actuated valve. The RCIC turbine exhaust isolation valve is a normally open motor-operated gate valve. The vacuum pump discharge isolation valve is a normally open globe stop-check valve. The RCIC pump minimum flow bypass isolation valve is a normally closed motor-operated globe valve. In addition, there is a check valve upstream of each valve that provides positive actuation for immediate isolation if there is a break upstream of this valve. The gate valve in the RCIC turbine exhaust is designed to be key-locked open in the control room and CHAPTER 06 6.2-63 REV. 21, SEPTEMBER 2022
LGS UFSAR interlocked to preclude opening of the inlet steam valve to the turbine when the turbine exhaust valve is not in a fully open position. The RCIC vacuum pump discharge line is also normally key-locked open but has no requirement for interlocking with the steam inlet to the turbine. The RCIC vacuum pump discharge line is provided with a stop-check valve at the containment to automatically prevent flow out of the containment. This valve functions as both a check valve and a remote manually actuated globe valve. A remote manually actuated motor operator ensures the long-term positive closure of the stop-check valve. This arrangement ensures that the essential RCIC pump-turbine will be ready to operate in the event of a reactor vessel isolation occurrence accompanied by loss of feedwater flow. The RCIC pump minimum flow bypass line is isolated by a normally closed remote manually actuated valve that is automatically isolated when adequate flow is obtained in the pump discharge line, with a check valve installed upstream. These lines discharge below the surface of the suppression pool. Thus, the lines are not directly open to containment atmosphere.
6.2.4.3.1.3.1.3 RHR Heat Exchanger Vent Lines and Relief Valve Discharge Lines The Unit 2 RHR heat exchanger vent lines discharge to the suppression chamber via relief valve discharge lines and are provided with two normally closed, remotely controlled motor-operated globe valves. The inboard valves receive an automatic isolation signal if there is a LOCA. The Unit 1 and Unit 2 relief valve discharge lines are isolated by the relief valves themselves in a fashion similar to a check valve, and the relief setting on these valves is more than 1.5 times the containment design pressure. The lines discharge below the surface of the suppression pool.
Thus, the lines are not directly open to containment atmosphere.
6.2.4.3.1.3.1.4 HPCI Turbine Exhaust Line The HPCI turbine exhaust line that penetrates the primary containment and discharges to the suppression pool is equipped with a remote manually operated gate valve located directly on the containment. In addition, there is a stop-check upstream of the gate valve that provides positive actuation for immediate isolation if there is a break upstream of this valve. The gate valve is designed to be key-locked open and interlocked to preclude opening of the inlet steam valve to the turbine while the turbine exhaust valve is not fully open. This line discharges below the surface of the suppression pool. Thus, the line is not directly open to containment atmosphere.
6.2.4.3.1.3.1.5 RHR, RCIC, CS, and HPCI Pump Suction Lines The RHR, RCIC, CS, and HPCI suction lines contain motor-operated, remote manually actuated gate valves that provide assurance of isolating these lines if there is a break. These valves also provide long-term leakage control. In addition, the suction piping from the suppression chamber is considered an extension of containment since it must be available for long-term usage following a design basis LOCA, and as such, is designed to the same quality standards as the containment.
System reliability is greater with only one isolation valve in the line because the ECCS pumps must have the capability to take suction from the suppression pool in order to mitigate the consequences of an accident. The RHR suction lines are also provided with a relief valve that discharges back into the suppression pool through the suction line penetration. The relief valve discharge lines are isolated by the relief valves themselves in a fashion similar to a check valve.
6.2.4.3.1.3.1.6 Suppression Pool Cleanup Line CHAPTER 06 6.2-64 REV. 21, SEPTEMBER 2022
LGS UFSAR The suppression pool cleanup line is isolated by two normally closed motor-operated gate valves that close on receipt of a containment isolation signal and a relief valve (PSV-52-127) whose setting is more than 1.5 times the containment design pressure.
6.2.4.3.1.3.2 Influent and Effluent Lines from Drywell and Suppression Pool Free Volume 6.2.4.3.1.3.2.1 Containment Atmosphere Sampling Lines The sampling system lines that penetrate the containment and connect to the drywell and suppression chamber air volume are equipped with two normally open solenoid-operated isolation valves in series, located outside and as close to the containment as possible. These valves ensure isolation of these lines if there is a break; they also provide long-term leakage control. In addition, the piping is considered an extension of the containment boundary since it must be available for long-term usage following a design basis LOCA, and, as such, is designed to the same quality standards as the primary containment. The following containment atmosphere sampling isolation valves have ganged controls for reopening:
- a. Inboard drywell sample and return isolation valves SV-132, SV-134, and SV-150 are ganged on HS-132
- b. Inboard suppression pool sample and return valves SV-183 and SV-191 are ganged on HS-183
- c. Outboard drywell sample and return isolation valves SV-141, SV-142, SV-143, SV-144, SV-145, and SV-159 are ganged on HS-153
- d. Outboard suppression pool sample and return isolation valves SV-184, SV-185, SV-186, SV-190, and SV-195 are ganged on HS-187.
6.2.4.3.1.3.2.2 Drywell Equipment and Floor Drain Lines The drywell equipment and floor drain lines are each provided with two air operated spring-closed valves located outside the primary containment. One of these valves is normally open and one normally closed. The inner valve (normally open) is located directly on the containment. Both valves are automatically closed upon receipt of a containment isolation signal.
6.2.4.3.1.3.2.3 Containment Purge and Hydrogen Recombiner Lines The high volume purge lines for the drywell and suppression chamber are each provided with two isolation valves located outside the primary containment. The inboard valve in each line is a normally closed, air operated butterfly valve located as close as practical to the primary containment penetration. The outboard valve in each line is a normally closed, motor-operated butterfly valve. A nonsafety-related north stack effluent high radiation isolation signal is also provided for the containment purge valves (HV-104, 109, 114, 115, 112, 121, 124, 123, 131, 135, 147). A description of the type and the arrangement of containment isolation valves used in the low volume purge exhaust lines is provided in Section 9.4.5.1.2. Each of these valves receives automatic isolation signals.
The hydrogen recombiner lines connect to the high volume purge lines between the containment penetration and the inboard isolation valve. Each of the recombiner lines is provided with two normally closed MOVs that can be manually actuated from the control room. These isolation valves CHAPTER 06 6.2-65 REV. 21, SEPTEMBER 2022
LGS UFSAR each receive automatic isolation signals. For operation of the recombiners after a LOCA, the isolation signals to these valves are overridden by using key-locked bypass switches. All four isolation valves on each recombiner train are powered from the same channel of electrical power in order to minimize the impact on system reliability.
The ESF recombiner system (Section 6.2.5) is designed as a closed system outside containment in addition to the isolation valves described above. The containment isolation provisions for the recombiner lines meet all of the relevant design criteria in Regulatory Guide 1.141, ANSI N-271, and SRP 6.2.4, as described below:
- a. The closed system does not communicate with either the secondary containment atmosphere or the environment.
- b. The closed system has been designed, fabricated, installed, and stamped in accordance with ASME Section III, Class 2 requirements.
- c. The closed system has a design temperature and pressure at least equal to the containment design conditions. The design temperatures and pressures are as follows:
- 1. Nonoperating modes: 55 psig / 340F for stainless steel and carbon steel components
- 2. Operating conditions: stainless steel components (30 psig / 1400F)
- d. The closed system is designed as seismic Category I.
- e. The system is designed to withstand the loads and environmental conditions accompanying a LOCA.
- f. High energy and moderate energy pipe break effects will not affect hydrogen recombiner system continuity when the closed system is needed for containment isolation (Section 3.6.2).
- g. The recombiner system is designed to be leak-tight and will be periodically leak tested at the containment peak accident pressure.
- h. Any leakage from the system will be confined within the secondary containment and will be diluted and filtered prior to release.
- i. The closed system is protected from missiles (Section 3.5).
The high volume purge lines are provided with debris screens located at the point where each purge line terminates inside the primary containment. The debris screens are designated as seismic Category I and are designed to withstand the maximum differential pressure across the screen that could result from a LOCA.
6.2.4.3.1.3.2.4 RCIC and HPCI Turbine Exhaust Vacuum Breaker Lines These lines are provided with two normally open motor-operated remote manually actuated gate valves. The valves are automatically closed on receipt of an RCIC or HPCI isolation signal.
CHAPTER 06 6.2-66 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.4.3.1.3.2.5 Traversing Incore Probe The TIP system purge line is equipped with a normally open air operated globe valve outside containment and a check valve inside containment. The TIP system purge line air operated valve is normally open in order to provide a continuous supply of dry gas to the indexing mechanisms.
Upon receipt of a containment isolation signal, the TIP system purge line AOV is automatically closed. TIP drive cables are normally retracted except during calibration of the power range neutron detectors or when an actual TIP mapping operation is in progress. Under normal operating conditions, the TIP system guide tubes do not communicate with the containment atmosphere because purge air supplied to the box surrounding the indexing mechanism effectively precludes such communication. However, following a LOCA or containment pressurizing event, a check valve on the box will open resulting in direct communication between the containment atmosphere and the TIP guide tubes. Because the TIP system lines can be considered instrument lines, the isolation provisions for the TIP system are described in the evaluation of compliance with Regulatory Guide 1.11, Section 6.2.4.3.1.5.
6.2.4.3.1.3.2.6 Containment Spray The containment spray lines are provided with two normally closed, remote manually operated isolation valves outside the containment. The inner isolation valve is located directly on the containment.
6.2.4.3.1.3.2.7 Suppression Pool Spray The suppression pool spray lines are provided with normally closed isolation valves outside containment, located directly on the containment. The valves automatically close upon receipt of an isolation signal. The external pipe, designed to Quality Group B and seismic Category I requirements, provides the second isolation barrier. Because of the desired use of this system after a LOCA, the system reliability is greater with only one isolation valve in the line.
6.2.4.3.1.3.2.8 Drywell Radiation Sampling Lines The sampling system lines that penetrate the containment and connect to the drywell and suppression chamber air volume are equipped with two normally open solenoid-operated isolation valves in series, located outside and as close to the containment as possible. These valves ensure isolation of these lines if there should be a break; they also provide long-term leakage control.
In addition, the piping is considered an extension of the containment boundary and, as such, is designed to the same quality standards as the primary containment. The drywell radiation sampling isolation valves have ganged controls for reopening. Inboard sample and return isolation valves SV-190A and SV-190C are ganged on HS-190A. Outboard sample and return isolation valves SV-190B and SV-190D are ganged on HS-190B.
6.2.4.3.1.3.2.9 Primary Containment Instrument Gas The influent lines are provided with a normally open power-operated globe valve outside the containment and a check valve inside the containment. MOVs are used on the influent lines that contain the ADS gas supply. These are essential lines that provide a long-term backup to the ADS accumulators inside containment. The valves on these essential lines are remote manually operated and automatically isolate only when flow out of containment through these lines would be CHAPTER 06 6.2-67 REV. 21, SEPTEMBER 2022
LGS UFSAR possible (i.e., low differential pressure between the containment and the instrument gas line). The remaining influent lines are nonessential lines that use AOVs that are automatically closed on receipt of a containment isolation signal. The effluent line is provided with a normally open air operated globe valve outside and a motor-operated globe valve inside the containment that close automatically on receipt of a containment isolation signal.
6.2.4.3.1.3.2.10 Reactor Enclosure Cooling Water Each influent and effluent line is provided with two gate valves located outside containment. The inboard valves are motor- operated. The outboard valves on the ESW intertie lines are locked closed and the motor operators are not connected to any power supply. The outboard valves on the RECW lines (HV-108 and HV-111) are motor-operated and their controls are ganged on HS-108. Each of the MOVs can be remote manually closed from the control room. Automatic, diverse isolation signals are also provided to these valves. In addition, the containment isolation signals to these valves can be overridden by using key-locked bypass switches.
6.2.4.3.1.3.2.11 Drywell Chilled Water Each influent and effluent line is provided with two motor-operated gate valves located outside containment. The controls for these valves are ganged as follows:
- a. Loop A inboard influent and effluent isolation valves HV-128 and HV-129 are ganged on HS-128.
- b. Loop B inboard influent and effluent isolation valves HV-122 and HV-123 are ganged on HS-122.
- c. Loop A outboard influent and effluent isolation valves HV-120A, 121A, 124A and 125A are ganged on HSS-121A.
- d. Loop B outboard influent and effluent isolation valves HV-120B, 121B, 124B and 125B are ganged on HSS-121B.
The inboard valves are provided with automatic isolation signals as indicated in Table 6.2-17. The outboard isolation valves are normally aligned to the drywell chilled water system. Outboard valves HV-120A, HV-120B, HV-121A and HV-121B are provided with diverse, automatic isolation signals.
In addition, the containment isolation signals to these valves can be overridden by using key-locked bypass switches. The other outboard isolation valves, HV-124A, HV-124B, HV-125A, and HV-125B are normally closed valves and do not receive an automatic isolation signal to close.
These valves may be aligned to the RECW system only when containment isolation valves are not required to be operable or when the affected containment penetration is isolated as directed by the Technical Specifications and Technical Requirements Manual. These valves have administrative controls so that they are treated as locked closed valves.
6.2.4.3.1.3.3 Conclusion on GDC 56 In order to ensure protection against the consequences of accidents involving release of significant amounts of radioactive materials, pipes that penetrate the containment have been demonstrated to provide isolation capabilities on a case-by-case basis in accordance with GDC 56.
In addition to meeting isolation requirements, the pressure- retaining components of these systems are designed to the same quality standards equivalent to those used for the primary containment.
CHAPTER 06 6.2-68 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.4.3.1.4 Evaluation Against GDC 57 This GDC was not used in the design of containment penetrations for LGS.
6.2.4.3.1.5 Evaluation Against Regulatory Guide 1.11 Instrument lines that penetrate the containment from the RCPB conform to Regulatory Guide 1.11 in that they are equipped with a restricting orifice located inside the drywell and an EFCV located outside and as close as practicable to the containment. Should an instrument line that forms part of the reactor pressure boundary develop a leak outside the containment, a flow rate that results in a differential pressure across the valve of 3-10 psi causes the EFCV to close automatically.
Should an EFCV fail to close when required, the main flow path through the valve has a resistance to flow at least equivalent to a sharp-edged orifice of 0.375 inch diameter. Valve position indication is provided in the reactor enclosure. Those instrument lines that do not connect to the RCPB conform to Regulatory Guide 1.11 in that they are either equipped with an EFCV or an isolation valve capable of remote operation from the control room, and are sized or orificed to meet the criteria outlined in Regulatory Guide 1.11. The drywell pressure, suppression pool level, suppression chamber pressure, and drywell sump level instrument lines are:
- a. Provided with isolation valves capable of remote operation from the control room.
- b. Q-listed, as discussed in Section 3.2.
- c. Designed to seismic Category I standards.
- d. Designed to withstand containment design pressure and temperature.
- e. Terminate in the reactor enclosure, which is served by the SGTS.
The status of the isolation valves capable of remote operation from the control room is indicated in the control room.
The TIP system lines as shown in drawing M-59 and described below are considered instrument lines because:
- a. they function as instrument lines or support the operation of instrument lines, and
- b. they are small diameter lines.
TIP system isolation valves are provided on each guide tube immediately outside the containment.
Dual barrier protection is provided by a solenoid-operated ball valve and an explosive actuated cable shearing valve. The ball valve is closed except when a TIP is inserted. These valves prevent loss of reactor coolant in the event that an incore guide tube ruptures inside the reactor vessel and prevents the escape of primary containment atmosphere.
The guide tube ball valve solenoid is normally de-energized and the valve is in the closed position.
When the TIP starts forward, the valve solenoid is energized and the valve is held open against its spring. As the valve opens, it actuates a set of contacts which provide position indication at the TIP control panel and a permissive signal for TIP motion. Upon receipt of a containment isolation signal (reactor low water level or high drywell pressure), the TIP drive mechanism is signalled to CHAPTER 06 6.2-69 REV. 21, SEPTEMBER 2022
LGS UFSAR retract the TIP. As the TIP is withdrawn into its shield chamber outside containment, a position switch signals the ball valve to close.
The shear valve is provided as a backup in the event that a TIP cannot be retracted or a ball valve sticks open when containment isolation is required. In this event, the shear valve would be operated from the control room to cut the cable and seal the guide tube. Continuity of the shear valve squib firing circuits is continuously monitored by front panel indicator lights in the control room.
The guidelines of Regulatory Guide 1.11, section 1.b are met for the TIP system as discussed below.
An analysis of the maximum leakage rate from the TIP system and the offsite radiological effects under normal reactor operating conditions was performed. The analysis conservatively assumed that all TIP system lines suffered guillotine breaks just outside the containment boundary. Specific activity inside the primary containment was assumed to be at the maximum Technical Specification limit for iodine in the primary coolant. (This is an extreme conservatism because a primary coolant rather than drywell atmosphere source term was assumed.) To characterize maximum flow through the TIP system lines, the drywell was assumed to be at its maximum normal pressure (2.0 psig) and normal temperature (135F ). It was also conservatively assumed that all TIP probes are fully retracted. Under these conditions, total flow from the TIP system lines would be only 0.105 lbm/sec as compared to 2.2 lbm/sec for an instrument line which penetrates the reactor primary coolant boundary. The corresponding 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> site boundary dose for this flow rate (using worst case average annual meteorology) would be less than 0.03 rem thyroid. The conservatively calculated leak rate is extremely low and the offsite dose is a small fraction of 10CFR50.67 limits.
The TIP guide tubes are equipped with dual isolation valves located as close to containment as practical; a solenoid-actuated ball valve and an explosively actuated shear valve acting in series.
The ball valves are normally de-energized (in a closed position). Consequently, during normal operation, the containment isolation function for the TIP system is accomplished without the need for any action. Therefore, requirement of Regulatory Guide 1.11, section 1.C.1 is met. In the unlikely event of a LOCA while the TIP system is in operation, containment isolation is automatically accomplished as follows. Upon receipt of a containment isolation signal (reactor low water level or high drywell pressure), the TIP drive mechanism is automatically signaled to retract the TIP. As the TIP is withdrawn into its shield chamber, a position switch signals the ball valve to close. All TIP line ball valves open against a spring and will close on loss of power. The cable shearing valves are equipped with redundant explosive actuating devices increasing the isolation reliability of the system and are remote manually operated from the control room. The ball and shear valves are instrumented to indicate position (i.e., open or closed).
Accidental closure of the TIP line isolation valves does not create a safety hazard, nor is the TIP system required to operate during an accident to mitigate the consequences of that accident.
Therefore, the isolation provisions of the TIP system comply with the requirements of Regulatory Guide 1.11, section 1.C.2. When the TIP starts forward, the ball valve solenoid is energized and the valve is held open against its spring. This satisfies the requirement of section 1.C.3, and therefore satisfies all the requirements of Regulatory Guide 1.11, section 1.C.
The design of the TIP isolation system is commensurate with the importance to safety of isolating that system. It recognizes that the TIP system design is such that the TIP guide tube isolation ball valve is normally closed. Typically, a TIP scan requires insertion of the TIP probes into the reactor CHAPTER 06 6.2-70 REV. 21, SEPTEMBER 2022
LGS UFSAR vessel for a period of approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> per month. Over a one year period, this amounts to a total of 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> per year, or less than 2% of the time.
This evaluation bounds the effects of operating at a normal temperature of 150F, since total mass flow would be reduced.
Because of the normally closed state of the TIP ball valves, the probability of a release of radioactivity through the TIP guide tubes following a LOCA is extremely low. Even in the event of a LOCA, the TIP system design will reliably provide automatic isolation of any open TIP guide tubes by providing for automatic retraction of the TIP cable followed by automatic closure of the TIP ball valve. Should the ball valve fail to automatically close, that condition would be indicated to the operator in the control room. The operator could then manually actuate the shear valve in the control room to isolate that line.
The design of the TIP system isolation provisions is based on the low probability that the system will be called upon to isolate the containment following a significant fission product release to the containment atmosphere. Consequently, the power supplies and the controls for the TIP isolation valves are not safety-grade. However, the overall system reliability for isolation is high because: (1) the ball and shear valves are powered from separate power supplies, (2) the shear valves are powered from an onsite dc power source, (3) the ball, shear, and purge check valves, and the line from the containment to the outermost isolation valve are mechanically safety-grade, (4) upon loss of power the ball valves close, and (5) the TIP system receives automatic LOCA signals to retract and isolate.
In considering the potential magnitude of a fission product release through the TIP guide tubes as a result of a design basis LOCA event, it is appropriate to consider the event probability. There are several sequences of events which could lead to a fission product release through the TIP guide tubes. Any sequence which leads to a release must involve: (1) a design basis LOCA, and (2) a degraded core. The probability of this combination of events alone is on the order of 10-7 per reactor year. Additional failure(s) in the TIP isolation system have to be assumed for the release through the TIP guide tubes to occur. These failures would involve the ball and shear valves not closing as designed for various reasons such as a hot short causing the ball valves to fail open and the shear valve not closing after the cable is retracted. The inclusion of the additional failures would lower the probability of occurrence of the event by several orders of magnitude below the 10-7 per reactor year figure discussed above. This analysis assumes the proper functioning of nonsafety-grade power supplies and circuits for the TIP isolation valves in determining overall system reliability. The low probability of a fission product release to the environment through the TIP guide tubes demonstrates the adequacy of the current TIP isolation system design basis.
Although the above discussion indicates an extremely low likelihood of a fission product release through the TIP guide tubes or purge lines, the consequence of that release has been evaluated for the most probable event. That event would involve the failure of all five TIP guide tubes to isolate following a degraded core event. In this instance, the TIP probe substantially reduces the flow area in the TIP guide tube which provides a pathway for fission product release unless some other unlikely event (i.e., earthquake) were to occur at the same time and cause further equipment failures. The pathway for an atmospheric fission product release would be through the check valve in the indexer box (open due to a positive internal containment pressure), down the long and narrow annulus between the TIP probe/cable assembly and the guide tube, and out through the end of the guide tube located in the reactor enclosure. The probe/cable assembly are never completely withdrawn from the guide tube, so the annular flow restriction is maintained. For the CHAPTER 06 6.2-71 REV. 21, SEPTEMBER 2022
LGS UFSAR radiological analysis, Regulatory Guide 1.183 source terms and accident meteorology were assumed.
The results of the radiological evaluation show that the site boundary and low population zone doses for this limiting event using Regulatory Guide 1.183 assumptions are below 10CFR50.67 limits.
The low probability of fission product release and the results of the radiological evaluation satisfy the intent of Regulatory Guide 1.11, section 1.d.
6.2.4.3.1.6 Evaluation Against Regulatory Guide 1.141 The containment isolation system conforms to Regulatory Guide 1.141 except as discussed below:
Section 3.6.4 Single Valve and Closed System Both Outside Containment...
The single valve and piping between the containment and the valve shall be enclosed in a protective leak-tight or controlled leakage housing to prevent leakage to the atmosphere.
LGS Design:
For systems that fall into this category except for the ECCS pump suction lines, the single valve outside primary containment is not enclosed in a protective leak-tight or controlled leakage housing. Moderate energy lines that fall into this category do not connect to the RCPB and are not postulated to break concurrent with a LOCA. Therefore, neither reactor coolant nor post-LOCA containment atmosphere are released. However, any leakage is contained within the secondary containment and is diluted and filtered prior to release. The ECCS pump suction isolation valves are enclosed in pump rooms adjacent to the containment that have provisions for the environmental control of any fluid leakage.
The existing isolation provisions for the above lines meet the criteria set forth by ANSI N271 (1976). These isolation provisions consist of a line submerged in the suppression pool (except for the suppression pool spray line) and a valve outside containment. In addition, a closed system is provided as another containment isolation barrier. For each of the lines, the closed system outside containment is protected from missiles, designed to seismic Category I standards, classified safety class 2, and is designed to the temperature and pressure conditions that the system will encounter after an accident. Justification for the design of the valve nearest containment and any piping between containment and the valve is provided in the following discussion.
Section 3.6.5 Two Valves Outside Containment...
The valve nearest the containment wall and piping between the containment and that valve shall be enclosed in a protective leak-tight or controlled leakage housing to prevent leakage to the atmosphere.
LGS Design:
The lines listed below, which have containment isolation provisions that consist of two valves in series located outside primary containment, are moderate energy lines that do not connect to the RCPB. These lines are not postulated to experience a guillotine break. Locating the valves on these lines outside the primary containment is more practical than locating the valves inside CHAPTER 06 6.2-72 REV. 21, SEPTEMBER 2022
LGS UFSAR containment because of the adverse environment that is experienced when most of the valves may be needed (post-LOCA) and because this location allows inspections and maintenance to be performed on these valves during normal operation. The existing isolation provisions for all these lines meet the criteria set forth by ANSI N271 (1976).
The design of the valve nearest containment and any piping between the containment and the valve, for the following penetrations, is discussed below:
Penetration Line Valve X-25 Drywell purge supply 122 X-26 Drywell purge exhaust 113 X-28A Drywell H2/02 sample 134, 132 X-28B Drywell H2/02 sample 133 X-39A,B Containment Spray F021A,B X-35C-G TIP Drive 140A-E, 141A-E X-40G ILRT data acquisition 1057, 1071 X-117B Drywell radiation sampling 190A,B, 190C,D X-62 H2/02 sample return; 150 drywell purge makeup X-201A Suppression pool purge supply 125 X-202 Suppression pool purge exhaust 103 X-203A,B,C,D RHR pump suction F004A,B,C,D X-204A,B RHR pump test and minimum flow 125A,B X-205A,B Suppression pool spray F027A,B X-206A,B,C,D CS pump suction F001A,B,C,D X-207A,B CS pump test and flush F015A,B X-208B CS pump minimum flow F031B X-209 HPCI pump suction F042 X-210 HPCI turbine exhaust F072 X-212 HPCI pump test and flush F071 CHAPTER 06 6.2-73 REV. 21, SEPTEMBER 2022
LGS UFSAR X-214 RCIC pump suction F031 X-215 RCIC turbine exhaust F060 X-216 RCIC minimum flow F019 X-217 RCIC vacuum pump discharge F002 X-220A H2/02 sample return; 190 wetwell purge makeup X-221A Wetwell H2/02 sample 181 X-221B Wetwell H2/02 sample 183 X-226A,B RHR minimum flow 105A,B X-227 ILRT data acquisition 1073 X-228D HPCI vacuum relief F095 X-231A,B Drywell sump drains 110, 130 X-235 CS pump minimum flow F031A X-236 HPCI pump minimum flow F012 X-238 RHR relief valve discharge 106B X-239 RHR relief valve discharge 106A X-241 RCIC vacuum relief F084 These moderate energy lines are not postulated to break concurrent with a LOCA. Therefore, neither reactor coolant nor post-LOCA containment atmosphere are released. Analyses have been performed to ensure that the effects of postulated moderate energy line breaks will not prevent the safe shutdown of the plant. The results of these analyses are provided in Section 3.6.1.2.
Section 4.4.2 Method of Valve Actuation...
It should not be possible for remote manual operation to override the automatic isolation signal until the sequence of automatic events following a isolation signal is completed...
LGS Design:
This guideline is met for all remote manually operable valves with the exception of valves in systems that must be operated after an accident and that have been provided with a key-locked override switch for this purpose.
Section 5.3.2 - Leakage Rate Testing CHAPTER 06 6.2-74 REV. 21, SEPTEMBER 2022
LGS UFSAR Provisions and Methods. Provisions shall be made for leakage rate testing of containment isolation valves.
LGS Design:
Individual leakage rate tests are performed for containment isolation valves as indicated in Table 6.2-25.
6.2.4.3.2 Failure Mode and Effects Analyses A single failure can be defined as a failure of some component in any safety system that results in a loss or degradation of the system's capability to perform its safety function. Active components are defined as components that must perform a mechanical motion during the course of accomplishing a system safety function. 10CFR50, Appendix A requires that electrical systems be designed against passive single failures as well as active single failures. Section 3.1 describes the implementation of these requirements as well as GDC 17, 21, 35, 41, 44, 54, 55, and 56.
In single failure analysis of electrical systems, no distinction is made between mechanically active or passive components; all fluid system components, such as valves, are considered electrically active whether or not mechanical action is required.
6.2.4.4 Tests and Inspections The containment isolation system undergoes periodic testing during reactor operation. The functional capabilities of power-operated isolation valves are remotely tested manually from the main control room. During all modes of manual MOV operation using the handswitch from the main control room, a "dead zone" is present for a portion of the valve travel. The "dead zone" is present when the valve is not fully closed and green light only indication exists. If the valve is stopped in the "dead zone", operator action is required to restart the valve. By observing position indicators and changes in the affected system operation, the closing ability of a particular isolation valve is demonstrated.
A discussion of testing and inspection pertaining to isolation valves is provided in Section 6.2.1.6 and in Chapter 16. Table 6.2-17 lists all isolation valves.
Instruments are periodically tested and inspected. Test and/or calibration points are supplied with each instrument.
EFCVs are periodically tested to verify proper operation. As these valves are outside the containment and accessible, periodic visual inspection is performed in addition to the operational check.
Leak rate testing for the containment isolation system is discussed in Section 6.2.6.
6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT Limerick license amendment numbers 173/135 for Unit 1 and 2, respectively approved the removal of the hydrogen recombiner and hydrogen and oxygen monitoring controls from Technical Specifications. The following items were committed to as part of license amendment numbers 173/135.
CHAPTER 06 6.2-75 REV. 21, SEPTEMBER 2022
- 1. Limerick will maintain the hydrogen monitors within the Emergency and Operating procedures and the Maintenance Program.
- 2. Limerick will maintain the oxygen monitors within the Emergency and Operating Procedures and the Maintenance Program.
The revised Technical Specifications are based on the NRC revision to 10CFR50.44 (Combustible gas control for nuclear power reactors), which eliminated the design basis LOCA hydrogen release based on risk significance; eliminated the requirements for hydrogen control systems to mitigate such releases; and maintained the requirements for containment inerting, containment atmosphere mixing, monitoring of oxygen to verify the status of the inert containment, and monitoring of hydrogen for diagnosing beyond design basis accidents. Based on the revised rule removing the design basis requirements for beyond design basis accidents, the hydrogen recombiners can be eliminated in the future and the H2/O2 analyzers are downgraded to non-safety related and non-redundant. However, the recombiners and analyzers are currently being maintained as described in the UFSAR, except for removal of the system requirements from the Technical Specifications.
The analyzer system requirements removed from the Technical Specifications have been transferred to the Technical Requirements Manual (TRM).
Following a postulated LOCA, hydrogen gas may be generated within the primary containment as a result of the following processes:
- a. Metal-water reaction involving the Zircaloy fuel cladding and the reactor coolant
- b. Radiolytic decomposition of water in the reactor vessel and the suppression pool (oxygen also evolves in this process)
- c. Corrosion of metals and paints in the primary containment
To preclude the possibility of a combustible mixture of hydrogen and oxygen accumulating in the primary containment, the containment atmosphere is inerted with nitrogen gas during power operation of the reactor. The means provided for inerting the containment is described in Section 9.4.5.1. With the concentration of oxygen being controlled to below the lower flammability limit, the level of hydrogen buildup in the primary containment following a postulated LOCA is of no particular concern for combustible gas control.
To ensure that the oxygen concentration in the primary containment is maintained below the lower flammability limit, the following features are provided:
- a. A containment hydrogen recombiner subsystem
- b. A combustible gas analyzer subsystem
- c. The capability to mix the primary containment atmosphere to prevent the local accumulation of hydrogen and oxygen (accomplished by the drywell air cooling system, which is discussed in Section 9.4.5.2)
- d. The capability for a controlled purge of the primary containment following a LOCA (accomplished by the CAC system, which is discussed in Section 9.4.5.1)
CHAPTER 06 6.2-76 REV. 21, SEPTEMBER 2022
LGS UFSAR Both the containment hydrogen recombiner subsystem and the combustible gas analyzer subsystem are part of the CAC system, which is shown in drawing M-57.
6.2.5.1 Design Bases
- a. The containment hydrogen recombiner subsystem is designed to maintain the oxygen concentration in the primary containment below the lower flammability limit of 5% by volume.
- b. The combustible gas analyzer is designed to operate either in standby or continuous mode during normal operation. However, the combustible gas analyzer is required to continuously monitor hydrogen and oxygen concentrations in the primary containment following a LOCA.
- c. Those lines that penetrate the primary containment and are associated with the containment hydrogen recombiner subsystem and the combustible gas analyzer subsystem are provided with automatic isolation valves to ensure the integrity of the containment boundary during accident conditions. Two isolation valves in series are provided on the recombiner lines.
- d. The controls for containment isolation valves on lines associated with post-LOCA combustible gas control and monitoring are designed so that the valves may be reopened by utilizing key-locked bypass switches to override the isolation signals.
- e. The containment hydrogen recombiner subsystem and the safety-related portions of the drywell air cooling system are designed to remain functional after an SSE.
- f. The containment hydrogen recombiner subsystem, the combustible gas analyzer subsystem, and the safety-related features of the drywell air cooling system are designed so that a single failure of an active component, assuming a LOOP, cannot result in the loss of a safety function.
- g. The CAC system is designed to permit a controlled purge of the primary containment atmosphere following a LOCA, as a backup means of combustible gas control and as an aid in cleanup.
- h. The containment hydrogen recombiner subsystem, the combustible gas analyzer subsystem, and the portions of the CAC system that are related to post-LOCA purging are designed to facilitate periodic inspection and testing of safety-related features.
- i. The containment hydrogen recombiner subsystem, the combustible gas analyzer subsystem, and the safety-related portions of the drywell air cooling system are designed to remain operable in the environments existing in their respective areas following a LOCA.
6.2.5.2 System Description 6.2.5.2.1 Containment Hydrogen Recombiner Subsystem CHAPTER 06 6.2-77 REV. 21, SEPTEMBER 2022
LGS UFSAR The containment hydrogen recombiner subsystem is part of the CAC system, which is discussed in Section 9.4.5.1 and shown schematically in drawing M-57. The recombiner subsystem consists of two redundant hydrogen recombiner packages, each of which has adequate processing capacity to control the quantity of oxygen postulated to be generated in the primary containment after a LOCA.
The recombiners are of the thermal recombination type, manufactured by the Atomics International Division of Rockwell International. The recombiners are similar in design and construction to those described in Reference 6.2-9 and are identical to those described in Reference 6.2-10.
A schematic diagram of one recombiner package is shown in drawing M-58. Each hydrogen recombiner package consists of three modules: the recombiner skid assembly, the power cabinet, and the control cabinet. The recombiner skid assembly, which is shown in Figure 6.2-38, consists of the process components. The process components include valves, canned motor/blower assembly, gas heater pipe, reaction chamber, water spray cooler, and water separator. The gas heater pipe and the reaction chamber are located within an insulated enclosure that also contains electric heater elements. The recombiner skid assembly is located outside the primary containment in the reactor enclosure.
The power cabinet houses the power distribution components for the recombiner package. The cabinet is located adjacent to its associated recombiner skid assembly and contains the 480 V power supply, control transformer, blower motor starter, circuit breakers, control relays, and the silicon-controlled rectifiers that control electrical power to the heater elements.
The control cabinet contains all of the instrumentation, annunciators, lights, and switches necessary for operation of the recombiner package. The control cabinet is located in the control room.
Each recombiner package is designed to process 60 scfm of gas (inlet flow) containing 5% oxygen, or up to about 150 scfm of gas (inlet flow) containing 2% oxygen, with the balance consisting of unlimited amounts of hydrogen, nitrogen, and water vapor. Each recombiner package will also process up to about 150 scfm of air containing 4% hydrogen. As containment pressure decreases following an accident, recombiner flow may decrease below the 150 scfm nominal operating value, as discussed in Section 6.2.5.3. The recombination process is accomplished by increasing the temperature of the process stream to approximately 1300F, at which temperature the hydrogen and oxygen combine spontaneously to form water vapor by the reaction 2H2 + O2 --> 2H2O.
Virtually complete recombination occurs, so that the concentration of the limiting gas in the effluent from the recombiner package is negligible.
During recombiner operation, gas from the drywell flows through the high volume purge piping of the CAC system to the gas inlet piping of the recombiner package. The effluent from the recombiner package flows through the gas outlet piping to the high volume purge piping associated with the suppression chamber, and then into the suppression chamber. By taking suction from the drywell and discharging to the suppression chamber, a differential pressure is created between these two volumes. This differential pressure is limited to 1.0 psid by the primary containment vacuum relief valve assemblies (described in Section 9.4.5.1), that open to allow air to flow from the suppression chamber back into the drywell.
The recombiner gas inlet and outlet lines are each provided with two normally closed valves for containment isolation. These valves can be operated by hand switches in the control room, and are automatically closed upon receipt of a containment isolation signal. The isolation signals can be overriden by using key-locked bypass switches. The recombiner outlet lines are each provided with pressure relief valves to protect the outlet piping from overpressurization in the event of CHAPTER 06 6.2-78 REV. 21, SEPTEMBER 2022
LGS UFSAR recombiner cooling water line isolation valve leakage from the RHR system during recombiner isolation. Containment isolation is discussed further in Section 6.2.4.
Blank flanges will be installed on the outboard side of the isolation valves for pressure boundary maintenance.
The process stream entering the recombiner skid assembly flows first through a valve that is used to regulate the flow rate through the recombiner. Next along the process path is the blower, that provides sufficient head to overcome the system flow losses and also the 1.0 psid differential pressure between the drywell and the suppression chamber. From the blower, the gas flows through the gas heater pipe that spirals around the reaction chamber.
The gas is heated as it flows through the gas heater pipe, due to radiated heat from the electric heater elements and the reaction chamber. Next, the gas flows into the reaction chamber, where the exothermic recombination of hydrogen and oxygen occurs. The flow field in the reaction chamber is highly turbulent, with sufficient mixing to rapidly bring the inlet gas temperatures to a level where virtually complete recombination occurs. Reaction chamber temperature is not critical, and considerable deviation from the nominal operating temperature of 1300F may be tolerated without seriously affecting recombiner performance. The geometric configuration and volume of the reaction chamber provide gas flow movement and transport times so that recombination is completed over a varied range of hydrogen-oxygen concentrations. Recombined gas flows from the reaction chamber to the water spray cooler where it is cooled to less than 250F. The hot process gas is mixed with water spray in the throat region of a venturi, and the hot gas is cooled by vaporization of the water and by direct contact with the water droplets. The cooling water is supplied to the recombiners from the RHR system. Cooled gas flowing from the cooler is passed through a water separator that prevents any remaining water droplets from entering the gas recirculation line. The separated water drains down to the suppression pool through the recombiner gas outlet piping. Recirculation (dilution) gas is drawn from the top of the water separator and is routed to the recombiner gas inlet piping.
Operation of the hydrogen recombiner package is initiated manually from the control cabinet.
When gas flow has been established and the water inlet valve is fully open, the heater elements are energized. Less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> are required for the system to reach operating temperature.
As the temperature of the heated enclosure increases, the gas being circulated through the recombiner is heated. The recombination reaction begins to occur at the outlet of the gas heater pipe when the temperature at that location reaches approximately 1150F. When the temperature at the gas heater pipe outlet reaches 1300F, power to the heater elements is automatically turned off. When the gas heater pipe cools to the point at which it can no longer sustain the reaction, the reaction moves into the reaction chamber. When the temperature at the gas heater pipe outlet falls below 1300F, an interlock is cleared and power is returned to the heater elements at a lower level than during startup. Temperatures in the gas heater pipe stay below those required for reaction, so the reaction stays in the reaction chamber. A temperature controller located in the control cabinet is used to maintain reaction chamber temperature at about 1300F.
6.2.5.2.2 Combustible Gas Analyzer Subsystem The combustible gas analyzer subsystem is part of the CAC system, which is discussed in Section 9.4.5.1 and shown schematically in drawing M-57. The combustible gas analyzer subsystem consists of two analyzer packages, each of which contains a hydrogen sensor and an oxygen CHAPTER 06 6.2-79 REV. 21, SEPTEMBER 2022
LGS UFSAR sensor. The analyzer packages are provided with sufficient sample points so that both analyzer packages can take samples from either the drywell or the suppression chamber.
Each analyzer package consists of a sample cabinet located in the reactor enclosure and a remote control panel located in the control room. Sample points in the primary containment are located as follows:
- a. Drywell
- 1. el 291', azimuth 10; 15' from containment centerline
- 2. el 255', azimuth 215; 25' from containment centerline
- 3. el 242', azimuth 214; 1.5' from inside wall of reactor pedestal.
- b. Suppression chamber
- 1. el 222', azimuth 70; at inside of containment wall
- 2. el 222', azimuth 250; at inside of containment wall.
The sample suction and return lines are each provided with two normally open solenoid-operated valves for containment isolation. These valves are operated by hand switches in the control room, and are automatically closed upon receipt of a containment isolation signal. The isolation signals to the valves can be overridden by using key-locked bypass switches. Containment isolation is discussed further in Section 6.2.4.
Sample location is controlled by a touchscreen at remote control panel. Gases from the sample point thus selected are routed through a hydrogen sensor and an oxygen sensor located in the sample cabinet.
The operation of the hydrogen and oxygen sensors is based on the measurement of the partial pressure of the oxygen and/or hydrogen in the gas sample. The partial pressure sensors are galvanic in nature and consist of two electrodes; a catalytic sensing electrode and metal oxide counter electrode for the hydrogen sensor and gold electrode and metal counter electrode for the oxygen sensor. The electrodes for the sensors are immersed in an electrolyte. The electrodes are externally connected by a resistive load. When the ambient atmosphere contains hydrogen and/or oxygen, the gas is ionized at the sensing electrode. The end result is an exchange of electrons through the resistive load connecting the electrodes that is in proportion to the amount of hydrogen (or oxygen). The voltage developed across the external resistance or load, is a mVDC signal, directly proportional to the partial pressure of hydrogen (or oxygen). Note that each sensor is designed to respond only to hydrogen or only to oxygen and is insensitive to other gasses. The total pressure is measured so the partial pressures can be converted to a concentration of hydrogen or oxygen.
The hydrogen sensor has a range of 0% to 10% (by volume) and the oxygen sensor has a range of 0% to 25% (by volume). The calibrated range of each analyzer is 0% to 7%. The sensors are capable of providing oxygen and hydrogen measurement under ambient pressure and up to 73 PSI for components exposed to containment sample under accident conditions.
The hydrogen and oxygen concentrations are indicated at the remote control panel.
CHAPTER 06 6.2-80 REV. 21, SEPTEMBER 2022
LGS UFSAR Sample gases are drawn through the sensors by a positive displacement pump located in the sample cabinet. Sample gases discharged from the pump are routed back to the primary containment.
6.2.5.2.3 Containment Atmosphere Mixing The capability is provided to maintain the primary containment atmosphere in a thoroughly mixed condition following a LOCA in order to prevent nonuniform distributions of oxygen from occurring.
This function is performed by the drywell air cooling system, which is discussed in Section 9.4.5.2.
One fan in each of the unit coolers of the drywell air cooling system runs continuously during normal reactor operation and at least one fan in each of two of the safety-related coolers (1AV-212 or 1BV-212 and 1GV-212 or 1HV-212) continues to run after a LOCA to maintain containment in a thoroughly mixed condition.
The design of the primary containment is such that compartmentalization is minimized. The only regions of the drywell that are segregated to some extent from the remainder of the drywell are the drywell head area above the containment seal plate and the CRD area inside the reactor pedestal.
Oxygen is prevented from accumulating in a concentration in excess of 5% (volume) in these areas during normal and post-LOCA operation by the operation of the drywell air cooling system.
Following a LOCA, containment oxygen would be mixed by several mechanisms in addition to the operation of the drywell air cooling system. Sprays and natural convective mixing would contribute significantly to maintaining all gases at nearly uniform concentrations (Reference 6.2-20). The boiling mechanism associated with the radiolysis responsible for the release of oxygen from irradiated water (Reference 6.2-21) would also create a significant amount of turbulent mixing, steam condensation effects, and a temperature gradient. These effects would cause oxygen to be well mixed with steam as it entered the drywell from the line break.
6.2.5.2.4 Post-LOCA Purging The capability to purge the primary containment in order to control oxygen concentration and aid in cleanup after a LOCA is provided.
The BWROG EPGs make specific recommendations for Post-LOCA purging based on the hydrogen levels in containment. Post-LOCA purging using the low volume purge mode of CAC (discussed in section 9.4.5.1) is recommended when containment hydrogen levels are greater than a specific level in the BWROG EPGs, no deflagration can occur, and the containment can be purged without exceeding the normal release rate limits in the Technical Specifications or ODCM.
Post-LOCA low volume purging continues until the containment hydrogen levels fall below the recommended value specified in the BWROG EPGs. Gases exhausted from the containment during post-LOCA purging are processed through the RERS and SGTS in order to remove radioactive particulate and halogen contaminants prior to release to the environment.
If containment hydrogen levels continue to increase a high volume purge of the containment can be performed using nitrogen, depending on the potential for the hydrogen and oxygen concentration to result in a deflagration. Depending on the plant conditions at the time of the high volume purge, RERS and SGTS may or may not be available. Depending on the specific concentrations of hydrogen in containment at the time, offsite release rates are limited to those in the Technical Specifications or ODCM. The high volume purge can be used in accordance with BWROG EPG recommendations to prevent containment failure due to a deflagration and to minimize the consequences of the accident. Post-LOCA high volume purging continues until the CHAPTER 06 6.2-81 REV. 21, SEPTEMBER 2022
LGS UFSAR containment hydrogen levels fall below the recommended value specified in the BWROG EPGs.
The BWROG EPG recommendations regarding purging of the containment are incorporated in the EOPs.
6.2.5.2.5 Venting of Combustible Gases from the Reactor Vessel Combustible gases generated within the reactor vessel or its connected piping can accumulate in the steam space of the vessel following certain types of accidents. Several means are available to vent these gases from the reactor vessel into the primary containment, where they can be processed by the hydrogen recombiner subsystem.
Operation of either the HPCI or RCIC system provides one such means for combustible gas venting. Both of these systems utilize steam-driven turbines that take steam from the reactor vessel and discharge it to the suppression chamber. Any combustible gases present in the reactor vessel steam space are carried along in the steam driving the HPCI or RCIC turbines.
Combustible gases can also be vented from the reactor vessel through the use of the ADS. The ADS utilizes five of the MSRVs to discharge steam and any other gases present in the reactor vessel to the suppression chamber.
A third means that is available for combustible gas venting involves the RPV head vent line that runs from the top of the reactor vessel head to the drywell equipment drain sump. MOVs in this line can be opened to allow steam and other gases to be discharged to the drywell equipment drain sump. Any gases not condensed in the drain sump are released into the drywell through the drain sump's vent line.
6.2.5.3 Hydrogen and Oxygen Generation Analysis In establishing the design and assessing the capability of the hydrogen recombiner subsystem and the post-LOCA purge, an analysis was performed to determine the hydrogen and oxygen concentrations in the primary containment (drywell and suppression chamber) as a function of time following a postulated LOCA. The assumptions and design parameters used in this analysis are listed in Tables 6.2-18 and 6.2-19, respectively. These assumptions are in accordance with Regulatory Guide 1.7 (Reference 6.2-12). The computer program used to conduct these primary containment hydrogen and oxygen analyses is the Bechtel in-house computer code, HYDROGEN, which incorporates the models from Regulatory Guide 1.7, SRP 6.2.5, and the NRC Code COGAP. The analysis considered the generation of hydrogen gas from the following sources:
- a. Metal-water reaction involving the Zircaloy fuel cladding and the reactor coolant
- b. Radiolytic decomposition of water in the reactor vessel and the suppression pool
- c. Corrosion of metals and paints in the primary containment
- d. Release of free hydrogen already in the reactor coolant at the time of the LOCA Radiolytic decomposition of water is considered to be the only source of oxygen gas generation after a LOCA.
Metal-Water Reaction CHAPTER 06 6.2-82 REV. 21, SEPTEMBER 2022
LGS UFSAR As a result of a LOCA, fuel cladding temperatures rise beginning after blowdown and continuing until core reflood. Zirconium reacts with steam according to the following reaction (Reference 6.2-11):
Zr + 2H2O --> ZrO2 + 2H2 Thus, for each mole of zirconium that reacts, 2 moles of free hydrogen are produced. The extent of the metal-water reaction and associated hydrogen generation depends strongly on the course of events assumed for the accident and on the effectiveness of emergency cooling systems, since the metal-water reaction is highly temperature-dependent. Regulatory Guide 1.7 (Reference 6.2-12) conservatively states that the amount of hydrogen assumed to be generated by metal-water reaction in determining the performance requirements for combustible gas control systems should be five times the maximum amount calculated in accordance with 10CFR50, Appendix K, but no less than the amount that would result from reaction of all the metal in the outside surfaces of the cladding cylinders surrounding the fuel (excluding the cladding surrounding the plenum volume) to a depth of 0.00023 inch.
In accordance with Appendix K, calculations have determined that the maximum core wide metal-water reaction is 0.09% (weight). Five times this calculated value is 0.45% (weight). Based on the fuel design, a reaction that results in a cladding penetration depth of 0.00023 inch is well in excess of the Appendix K value. Therefore, since the metal-water reaction based on 0.00023 inch penetration depth is greater than five times the value calculated in accordance with Appendix K, the value based on 0.00023 inch cladding penetration reaction is used as the basis for determining the amount of hydrogen generated by the metal-water reaction.
The analysis assumes that the hydrogen from the metal-water reaction is generated during the first 2 minutes after the beginning of the accident. The hydrogen thus evolved is assumed to mix homogeneously with the drywell atmosphere.
Radiolysis Water is decomposed into free hydrogen and oxygen by the absorption of energy emitted by fission products contained in fuel and those mixed with the LOCA water. The quantities of hydrogen and oxygen that are produced by radiolysis are functions of both the energy of ionizing radiation absorbed by the LOCA water and the net hydrogen and oxygen radiolysis yields, G(H2) and G(O2), pertaining to the particular physical-chemical state of the irradiated water. As recommended in Regulatory Guide 1.7 (Reference 6.2-12), the net yields of hydrogen and oxygen from radiolysis of all LOCA water are conservatively assumed to be 0.5 molecule/100 eV for hydrogen and 0.25 molecule/100 eV for oxygen.
The total fission product decay power is taken from Reference 6.2-13, conservatively assuming a 730 day1 reactor operating time for fission product buildup. The results are comparable to those of proposed Standard ANS 5.1. The fission product distribution after the accident and the fractions of fission product radiation energy assumed to be absorbed by the LOCA water are listed in Table 6.2-18. The rates of energy absorption by the LOCA water are shown in Figure 6.2-39 and the integrated energy absorption is shown in Figure 6.2-40.
Corrosion The corrosion of zinc and aluminum located either in the drywell or the suppression chamber is evaluated as a potential source of hydrogen after a LOCA. One factor that affects the rate of CHAPTER 06 6.2-83 REV. 21, SEPTEMBER 2022
LGS UFSAR corrosion of either of these metals is the pH of the water with which the metal is in contact. Since no chemicals are added to the containment spray water, the pH of water in the primary containment after a LOCA should be approximately 7 (neutral).
Zinc in the primary containment is in two forms: zinc-based paint and galvanized steel. The masses and exposed areas of zinc-based paint and galvanized steel are listed in Table 6.2-19.
Corrosion of zinc in contact with water at a nominal pH of 7 is caused by two processes:
- 1. A one time cycle length of 27 months for Unit 1 cycle 7 and Unit 2 cycle 5 was evaluated to have a negligible impact on total fission product decay power.
- a. Zn + 2 H2O --> Zn(OH)2 + H2
- b. 2 Zn + 2 H2O + O2 --> 2 Zn(OH)2 Both reactions occur in the post-LOCA atmosphere of the containment, and the relative amount of corrosion due to reaction a. as compared to reaction b. depends on the availability of oxygen.
Galvanized steel and zinc-based paint surfaces that are not submerged are in contact with atmospheric oxygen along with the spray water; therefore, reaction b. is a major contributor to the corrosion of zinc. For the submerged surfaces, the oxygen present depends on the solubility of oxygen, which decreases with increasing temperature. For this situation, reaction a. dominates zinc corrosion.
A search of the literature available on the subject of zinc corrosion at a pH of 7 gives data for corrosion as a weight loss of zinc (References 6.2-14, 6.2-15, and 6.2-16) and also as hydrogen evolved (References 6.2-17 and 6.2-18). Van Rooyen (Reference 6.2-19) surveyed the available literature and formulated a corrosion rate. The data given as weight loss of zinc should be viewed carefully to determine which corrosion reaction is involved.
Other data are available for corrosion in water at higher pH levels or in water with NaOH additives.
However, these data are not applicable to a BWR.
Baylis (Reference 6.2-17) determined the hydrogen generated from a sample of zinc submerged in distilled water for different time periods. This study was performed for temperatures of 100F and lower. Therefore, the lower temperature corrosion domain can be inferred from this data.
The Franklin Institute Research Laboratories (Reference 6.2-18) performed a study of hydrogen evolution from zinc under simulated LOCA conditions and gave corrosion data for 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> periods. These data show that corrosion is faster for the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period than for the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period for different temperatures, except at the high temperature end (260F-300F) where the corrosion rates are comparable. This effect is due to the buildup of a corrosion-resistant zinc hydroxide protective layer that inhibits corrosion after an extended period of time.
Burchell (Reference 6.2-15) and Cox (References 6.2-14 and 6.2-16) present corrosion as a weight loss of zinc. In both cases, the corrosion rate is higher at the lower temperature domain, peaking at approximately 110F and then decreasing with increasing temperature. Since the solubility of oxygen decreases with increasing temperature, the decrease in the corrosion rates can be attributed to the depletion of oxygen available. Thus, these corrosion rates show that reaction CHAPTER 06 6.2-84 REV. 21, SEPTEMBER 2022
- b. is dominant in the oxygen-rich lower temperature water, and reaction a. becomes dominant with increasing temperature.
Van Rooyen (Reference 6.2-19) determined the corrosion rate of zinc from the available data, but did not differentiate whether the corrosion was due to reaction a. or b. Thus, Van Rooyen's calculated corrosion rate does not accurately present the hydrogen generated from the corrosion of zinc.
The data of References 6.2-17 and 6.2-18 on hydrogen generation from zinc corrosion are bounded by the following corrosion rate:
H (Zn) = 3.76x10-9 e(0.0218T) lb-moles/ft2-hr (EQ. 6.2-46) where:
T = temperature in degrees Fahrenheit This rate equation is used to calculate the hydrogen released due to zinc corrosion and corrosion of zinc paint by conservatively assuming that all corrosion is caused by reaction a.
Since containment spray water does not contain any chemical additives, the pH of the LOCA water is approximately 7. At this pH, the corrosion rate of aluminum is negligible even at high temperatures (References 6.2-14 and 6.2-15). Therefore, aluminum in the containment is not assumed to be the source of any hydrogen generation.
Hydrogen Existing in Reactor Coolant During normal operation of the reactor, free hydrogen exists in the coolant water in concentrations of 10-50 scc/kg of coolant. Although it is unlikely, it is assumed that all of this hydrogen is stripped from the coolant at the time of the LOCA. The total amount added to the containment atmosphere (corresponding to a concentration of 30 scc/kg of coolant) is listed in Table 6.2-19.
Results The curves of drywell pressure and temperature as a function of time after a LOCA, which are used in the analysis to adjust for the mass of steam in the drywell atmosphere, are shown in Figures 6.2-3, 6.2-4, 6.2-7, and 6.2-8.
Figure 6.2-41 shows the integrated production of hydrogen from all sources as a function of time after the postulated LOCA. The hydrogen concentrations in a noninerted containment over the short-term and long-term periods after a LOCA are shown in Figures 6.2-42 and 6.2-43, respectively. These figures show hydrogen concentrations for three cases: no hydrogen control, recombiner operation at 150 scfm, and a 150 scfm purge. The analysis shows that hydrogen concentration in the drywell reaches 4% (volume) at about 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> after the LOCA, if no control measures are taken. If operation of one recombiner package is started so that recombination begins when the hydrogen concentration reaches 3.5% (volume) (at 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> after the LOCA), the concentration peaks at 3.57% (volume) and then decreases as long as the recombiner remains in operation. This analysis assumes a flow rate of 150 scfm. As containment pressure decreases following an accident, recombiner flow may decrease below this value. Field tests show that the system resistance can limit flow to less than 150 scfm when the containment is at atmospheric pressure and normal temperature. Sensitivity calculations have been performed which demonstrate that the hydrogen concentration will not exceed 4 volume percent with a single CHAPTER 06 6.2-85 REV. 21, SEPTEMBER 2022
LGS UFSAR recombiner operating at a flow rate as low as 95 scfm. Actual recombiner flow rates exceed this requirement by a significant margin. For a 150 scfm purge beginning at 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br />, the hydrogen concentration continues to increase to a maximum of about 3.8% (volume), occurring at about 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> after the LOCA. The purge mode used as a basis for this calculation involves supply and exhaust evenly divided between the drywell and suppression chamber, without repressurization of the primary containment.
The oxygen concentrations in an inerted containment over the short-term and long-term periods after a LOCA are shown in Figures 6.2-44, 6.2-45, and 6.2-46. These figures show oxygen concentration for three cases: no oxygen control, recombiner operation at 60 scfm, and a 60 scfm purge. The oxygen concentration (volume percent) initially drops in both the drywell and suppression chamber because, following a LOCA, the blowdown and subsequent increases in containment temperature and pressure result in significant fractions of other gases, primarily steam. To account for the additional constituents, the volume percent of oxygen decreases. The analysis shows that oxygen concentration in the drywell reaches 5% (volume) at about 54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> after the LOCA, if no control measures are taken. If operation of one recombiner package is started so that recombination begins when the oxygen concentration reaches 4.5% (volume) (at about 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> after the LOCA), the concentration will peak at 4.92% (volume) and will then decrease as long as the recombiner remains in operation. For a 60 scfm purge beginning at 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br />, the oxygen concentration increases to a maximum of 4.61% (volume), occurring at about 54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> after the LOCA. The purge mode used as a basis for this calculation involves supply and exhaust evenly divided between the drywell and suppression chamber, without repressurization of the primary containment.
6.2.5.4 Safety Evaluation The containment hydrogen recombiner subsystem (including supporting structures) is designed to seismic Category I requirements as defined in Section 3.7. Except for tubing internal to the sample cabinets of the combustible gas analyzer subsystem, piping and tubing associated with both subsystems, except for some piping and the hydrogen cylinders of the gas analyzer subsystem, are designed, fabricated, inspected, and tested in accordance with the requirements of the ASME Section III, Class 2. All portions of the two subsystems are located within the reactor enclosure and control structure, which are designed to seismic Category I requirements as discussed in Section 3.8.4. H2 span gas cylinders are seismically supported in a location outside the reactor enclosure (and other safety-related areas) as required by BTP CMEB 9.5-1. Evaluation with respect to the following areas is discussed in sections as indicated:
- a. Protection from wind and tornado Section 3.3 effects
- b. Flood design Section 3.4
- c. Missile protection Section 3.5
- d. Protection against dynamic effects Section 3.6 associated with the postulated rupture of piping
- e. Environmental design Section 3.11 The containment hydrogen recombiner subsystem and the combustible gas analyzer subsystem both consist of two separate packages that are fully redundant and independent. The redundant packages are powered from different divisions of Class 1E power. A single failure in either CHAPTER 06 6.2-86 REV. 21, SEPTEMBER 2022
LGS UFSAR subsystem would only render the affected package unavailable, with the redundant package fully capable of performing the required function at full capacity. Failure modes and effects analyses for the containment hydrogen recombiner subsystem and the combustible gas analyzer subsystem are provided in Tables 6.2-20 and 6.2-21, respectively.
Each combustible gas analyzer sample line penetrating the primary containment is provided with redundant isolation valves powered from different divisions of Class 1E power. Since the isolation valves are of a type that fail closed upon loss of power, loss of power to any individual valve or to all valves powered from the same division does not disable the containment isolation function. In the event of a failure of any single valve to close when required, the redundant valve on the same line provides the isolation function. The bypass of an isolation signal to any valve is annunciated in the control room.
Containment isolation provisions for piping used in conjunction with hydrogen recombination and post-LOCA purging are discussed in Section 9.4.5.1.
The design pressures and temperatures for process components of the hydrogen recombiner packages are as follows:
- a. Nonoperating conditions: entire system 55 psig/340F
- b. Operating conditions:
Stainless steel components 30 psig/1400F (gas heater pipe, reaction chamber, and water spray cooler)
Carbon steel components 55 psig/340F (inlet piping, water separator, and outlet piping)
Since the post-LOCA primary containment pressure-temperature transient stays well below these design parameters for the time period greater than 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after the LOCA (Section 6.2.1), no restrictions exist on recombiner operation after this 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> period.
As shown in Figures 6.2-44, 6.2-45, and 6.2-46, the operation of one hydrogen recombiner package is sufficient to maintain post-LOCA oxygen concentrations in the containment below 5%
(volume). The analysis to determine post-LOCA oxygen concentrations assumes that hydrogen-oxygen recombination begins at 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> after the LOCA. Since the recombiner requires a maximum 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> heatup period (verified by surveillance testing) before complete recombination of oxygen in the process stream occurs, one recombiner package is activated at or prior to 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> after a LOCA.
In the extremely unlikely event that a LOCA occurs and both recombiner packages fail to function properly, purging may be utilized to control the oxygen concentration inside the containment. The oxygen generation analysis shows that the oxygen concentration reaches 4.5% (volume) at 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> after the LOCA, and that a 60 scfm purge initiated at that time ensures that the oxygen concentration remains below the 5% level. The effect of the purge on oxygen concentration is shown in Figures 6.2-44, 6.2-45, and 6.2-46.
CHAPTER 06 6.2-87 REV. 21, SEPTEMBER 2022
LGS UFSAR The BWROG EPGs make specific recommendations for Post-LOCA purging based on the hydrogen levels in containment. Post-LOCA purging using the low volume purge mode of CAC (discussed in section 9.4.5.1) is recommended when containment hydrogen levels are greater than a specific level in the BWROG EPGs, no deflagration can occur, and the containment can be purged without exceeding the normal release rate limits in the Technical Specifications or ODCM.
Post-LOCA low volume purging continues until the containment hydrogen levels fall below the recommended value specified in the BWROG EPGs. Gases exhausted from the containment during post-LOCA purging are processed through the RERS and SGTS in order to remove radioactive particulate and halogen contaminants prior to release to the environment.
If containment hydrogen levels continue to increase a high volume purge of the containment can be performed using nitrogen, or air depending on the potential for the hydrogen and oxygen concentration to result in a deflagration. Depending on the plant conditions at the time of the high volume purge, RERS and SGTS may or may not be available. Depending on the specific concentrations of hydrogen in containment at the time, offsite release rates are limited to those in the Technical Specifications or ODCM. The high volume purge can be used in accordance with BWROG EPG recommendations to prevent containment failure due to a deflagration and to minimize the consequences of the accident. Post-LOCA high volume purging continues until the containment hydrogen levels fall below the recommended value specified in the BWROG EPGs.
The BWROG EPG recommendations regarding purging of the containment are incorporated in the EOPs.
6.2.5.5 Tests and Inspections The containment hydrogen recombiner subsystem and the combustible gas analyzer subsystem are preoperationally tested in accordance with the requirements of Chapter 14 and periodically tested in accordance with the requirements of the maintenance program and the Technical Requirements Manual (TRM), respectively. Inservice inspection of the subsystems will be in accordance with the ASME Section XI, for ASME Section III, Class 2 components.
6.2.5.6 Instrumentation Applications 6.2.5.6.1 Containment Hydrogen Recombiner Subsystem The control cabinet for each hydrogen recombiner package contains the following devices (on the front side of the cabinet) that control and monitor the operation of the recombiner:
- a. Operate switch (HS-3)
- b. Inlet valve flow control switch (HS-1)
- c. Recirculation valve flow control switch (HS-2)
- d. Reaction chamber temperature controller (TIC-7)
- e. Flow/pressure recorder (XR-1)
- f. Temperature recorders (TRS-2 and TRS-4)
- g. Annunciator assembly Also located on the control cabinet, but on the rear of the cabinet, are eight hand switches (HS-6 through HS-10 and HS-14 through HS-16).
CHAPTER 06 6.2-88 REV. 21, SEPTEMBER 2022
LGS UFSAR The hydrogen recombiner packages have three basic modes of operation: standby, ready, and operate. The recombiner is kept in the "ready" mode when not being tested or otherwise operated.
Initially, when the recombiner subsystem is first energized or during maintenance, the system is placed in the "standby" mode. The trickle heaters are energized in order to keep the insulated enclosure warm in the "standby" and "ready" modes. The temperature controller is set at the value that will be used during initial operation of the recombiner. The recombiner is placed in the "ready" mode by actuating the service disconnect switches (HS-6 through HS-9) to the "on" position. The recombiner is left in the "ready" mode for approximately one hour, to allow circuits to stabilize before proceeding to the "operate" mode. Since the recombiner is normally in the "ready" mode, the one hour stabilization time is not a concern prior to going to the "operate" mode. The recombiner is placed in the "operate" mode by actuating switch HS-3, at which time the blower starts and the water inlet valve opens. Interlocks are provided to prevent the heater elements from being energized until the water inlet valve is fully open and the blower inlet gas flow rate exceeds the low flow setpoint. Recombiner inlet flow control and recirculation flow control is achieved using hand switches HS-1 and HS-2 in conjunction with flow/pressure recorder XR-1.
While the recombiner is in the "operate" mode, the "startup" light is on while the reaction chamber gas temperature remains below 1150F, and the "operate" light is on when this temperature has been exceeded.
The following process alarms are displayed on the annunciator:
- a. Blower inlet gas pressure (high)
- b. Blower inlet gas flow (low)
- c. Blower inlet gas temperature (high)
- d. Heater wall temperature (high)
- e. Reaction chamber gas temperature (high and low)
- f. Reaction chamber shell temperature (high)
- g. Return gas temperature (high)
Automatic shutdown of the recombiners (interruption of power to the blower and the heater elements) results if setpoints are exceeded for variables a, c, d, f, and g as listed above. If the setpoint is exceeded for variable b or heater temperature two-thirds through heater (high), heater outlet temperature (high), or the water inlet control valve is not fully open, power to the heater elements is interrupted but the blower continues to run.
The recombiner process alarms listed above are annunciated by a general trouble alarm external to the recombiner control cabinet, as well as by the annunciator on each recombiner control cabinet. Failure of the recombiner trickle heat is also annunciated by this general trouble alarm.
The gas outlet piping from each recombiner package is provided with a level switch to detect (and annunciate in the control room) the accumulation of water in the outlet piping. Such an occurrence could result from leakage of the recombiner cooling water inlet valve while the recombiner is not in operation.
CHAPTER 06 6.2-89 REV. 21, SEPTEMBER 2022
LGS UFSAR The following process variables are recorded on XR-1:
- a. Blower inlet pressure
- b. Recombiner inlet flow
- c. Blower inlet flow Separate modules provide alarm and trip outputs for variables a and c. These modules are mounted on an instrument rack located on the front side of the control cabinet.
The following process temperatures are recorded on TRS-2:
- a. Blower inlet temperature
- b. Reaction chamber shell temperature
- c. Return gas temperature The following process temperatures are recorded on TRS-4:
- a. Heater temperature two-thirds through heater
- b. Heater outlet temperature
- c. Heater wall temperature Process temperature alarm and trip outputs are provided by the temperature recorders.
The annunciator assembly is a backlighted legend plate, flasher, sequential type annunciator with a common horn. The annunciator, along with the TEST, ACKNOWLEDGE, and RESET push buttons are mounted on the front side of the control cabinet.
During normal conditions, the legend plate is dark and the horn is off. During abnormal conditions, the annunciator indicates an alarm by a fast flashing legend plate and by a horn. The operator can acknowledge the alarm by pressing the ACKNOWLEDGE push button. This causes the horn to stop sounding and the legend to stop flashing but remain lighted. When conditions return-to-normal, the legend changes from steady to slow flashing and the horn sounds. The operator can clear the alarm by pressing the RESET push button. This causes the window to become dark again.
The alarm sequence is different if the abnormal condition returns to normal before acknowledgement by the operator. In that case, pushing the ACKNOWLEDGE push button causes the legend to change from fast flashing to slow flashing. The horn remains on until the RESET push button is pressed.
The operator can functionally test the entire annunciator system by pressing the TEST push button.
After testing, the operator returns the annunciator to the ready condition by pressing the ACKNOWLEDGE and RESET push buttons in sequence.
CHAPTER 06 6.2-90 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.5.6.2 Combustible Gas Analyzer Subsystem The combustible gas analyzer packages are designed to be operable from the remote control panel and includes hydrogen and oxygen concentration indicators. Also provided in the control room are annunciation of high oxygen concentration and high hydrogen concentration, and analyzer package malfunction. Those malfunctions that are annunciated include out of range signal from the partial or total pressure sensors, calibration errors, system configuration errors, low flow, over pressurization, and module hardware faults.
Instrumentation and controls for the containment hydrogen recombiner subsystem and the combustible gas analyzer subsystem are discussed further in Section 7.3.1.1.6.
6.2.6 PRIMARY REACTOR CONTAINMENT LEAKAGE RATE TESTING This section presents the testing program for the primary reactor containment ILRTs (Type A tests), primary containment penetration leakage rate tests (Type B tests), and primary containment isolation valve leakage rate tests (Type C tests). This program complies with 10CFR50, Appendix A, General Design Criteria, and Performance Based Option B of 10CFR50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors", to the greatest extent practicable. The details of the program are defined in the Primary Containment Leak Rate Testing Program (PCLRTP) as identified in Chapter 16.
6.2.6.1 Primary Reactor Containment Integrated Leakage Rate Tests Upon completion of construction of the primary reactor containment, including installation of all portions of the mechanical, fluid, electrical, and instrumentation systems penetrating the containment associated with containment integrity; and upon satisfactory completion of the structural integrity tests as described in Section 3.8, the preoperational containment ILRT was performed in accordance with the requirements of Chapter 14 to verify that the actual containment leakage rate did not exceed the design limit.
Type A tests are conducted at intervals as described in PCLRTP. A general inspection of the accessible interior and exterior surfaces of the primary containment structure and components is performed in accordance with the PCLRTP, to uncover any evidence of structural deterioration that could affect either the containment structural integrity or leak-tightness. If there is evidence of structural deterioration, corrective action is taken. The structural deterioration and corrective action are reported in accordance with 10CFR50, Appendix J. Repairs or adjustments made to the containment boundary prior to the conduct of the Type A test shall be accounted for in the determination of the As-Found Type A test.
The ILRT (Type A) is performed to determine that the total leakage from the containment does not exceed the maximum allowable leakage rate (La) at the design basis LOCA maximum peak containment pressure (Pa), as defined in Chapter 16. Typical piping and instrumentation are shown in drawing M-60. Acceptance criteria and frequency are defined in the PCLRTP.
The Type A test is conducted in accordance with 10 CFR 50, Appendix J, Option B and the PCLRTP.
A typical data acquisition system is shown in drawing M-60. Prior to commencement of any Type A test the pretest requirements of ANSI/ANS N56.8-1994 are met with specifics as follows:
CHAPTER 06 6.2-91 REV. 21, SEPTEMBER 2022
- a. Those portions of fluid systems that are part of the RCPB, and are open directly to the primary containment atmosphere under postaccident conditions and become an extension of the boundary of the primary containment, are opened or vented to the containment atmosphere prior to and during the Type A test, except as noted in Table 6.2-24. Portions of closed systems inside the containment that penetrate primary containment and can rupture as a result of a LOCA are vented to the containment atmosphere, except as noted in Table 6.2-24.
- b. All systems not designed to remain water-filled post-LOCA are drained of water to the extent necessary to ensure exposure of the system primary containment isolation valves to containment air test pressure.
- c. Those portions of fluid systems that penetrate the primary containment, that are external to the containment and are not designed to provide a containment isolation barrier, are vented to the outside atmosphere, as applicable, to ensure that full postaccident differential pressure is maintained across the containment isolation barrier.
- d. Systems that are required to maintain the plant in a safe condition during the Type A test are operable in their normal mode and are not vented, as noted in Table 6.2-24.
- e. Systems that are normally filled with water and operating under postaccident conditions are not vented. However, the measured leakage rates (Type C) for containment isolation valves in these systems identified in Table 6.2-24 are reported in the Type A test final report.
- f. For planning and scheduling purposes, or ALARA considerations, pathways that are Type B or C tested within the previous 24 calendar months need not be vented or drained during the Type A test.
6.2.6.2 Primary Containment Penetration Leakage Rate Tests Containment penetrations with designs incorporating resilient seals, gaskets or sealant compounds, air locks and lock door seals, equipment and access hatch seals, and electrical canisters receive preoperational and periodic Type B leakage rate tests in accordance with 10CFR50, Appendix J, Option B and the PCLRTP. A list of all containment penetrations subject to Type B tests is provided in Table 6.2-25.
All Type B tests are conducted at pressure (Pa) as defined in Chapter 16. The acceptance criteria are given in the PCLRTP. Test methods are described in Section 6.2.6.3 below.
Penetrations with threaded caps are provided in the air lock to permit pressure testing of the door seals and the entire lock.
Penetrations for equalizing valves as described in Section 3.8.2.1.2 are provided in the air lock.
Figure 6.2-48 shows the locations of all mechanical and electrical penetrations in the air lock.
Figure 6.2-49 shows details of the door seals and the pressure test connection.
The personnel air lock volume is pressurized to primary containment peak accident pressure and tested periodically as described in Chapter 16 and the PCLRTP. During the air lock test, tie-downs CHAPTER 06 6.2-92 REV. 21, SEPTEMBER 2022
LGS UFSAR are installed from inside the lock on the inner door, since normal locking mechanisms are not designed to withstand a differential pressure across the door in the reverse direction in excess of 5 psig. See Figure 6.2-50 for details of the tie-downs for the inner door. The tie-downs are installed from within the air lock. The force exerted by the tie-downs on the inner door is not monitored.
Pressurizing the lock barrel also tests the lock mechanical and electrical penetrations, and the door seals.
The door seals are periodically tested at Pa as indicated in Chapter 16. Additionally, the door seals are tested after each opening at 10 psig without installing tie-downs as indicated in Chapter 16 and the PCLRTP.
6.2.6.3 Primary Containment Isolation Valve Leakage Rate Tests The containment isolation valves that are Type C tested are listed in Table 6.2-25.
Type B and C tests are performed by local pressurization, using either the pressure-decay or flowmeter method. For the majority of isolation valves, the test pressure is applied in the same direction that the valve would see when required to perform its safety function. There are a few exceptions where the test pressure is applied in the reverse direction. Further explanation is provided in Table 6.2-25. For the pressure decay method, the test volume is pressurized with air or nitrogen to at least Pa. The rate of decay of pressure of the known free air test volume is monitored to calculate leakage rate. For the flowmeter method, pressure is maintained in the test volume by making up air, nitrogen, or water (if applicable) through a calibrated flowmeter. The flowmeter fluid flow rate is the isolation valve leakage rate.
All isolation valve seats that are exposed to containment atmosphere subsequent to a LOCA are tested with air or nitrogen at pressure (Pa) as defined in Chapter 16.
Those valves which are in lines designed to be, or remain, filled with a liquid for at least 30 days subsequent to a LOCA are leakage rate tested with that liquid. The liquid leakage measured is neither converted to equivalent air leakage nor added to the Type B and C test totals. Isolation valves tested with liquid are identified in Table 6.2-25 and designated under note (15).
The acceptance criteria for all penetrations and isolation valves subject to Type B and C tests are given in Chapter 16 and the PCLRTP.
6.2.6.4 Scheduling and Reporting of Periodic Tests The periodic leakage rate test schedules for Types A, B and C tests are given in the PCLRTP.
Type B and C tests can be conducted at any time during normal plant operations or during shutdown periods, so long as the time interval between tests for any individual Type B or C test does not exceed the maximum allowable interval specified in the PCLRTP. Each time a Type B or C test is completed, the overall total leakage rate for all required Type B and C tests is corrected for any differences noted.
Provisions for reporting test results are given in the PCLRTP.
6.2.6.5 Special Testing Requirements 6.2.6.5.1 Drywell Steam Bypass Test CHAPTER 06 6.2-93 REV. 21, SEPTEMBER 2022
LGS UFSAR Following the drywell structural integrity test, described in Section 3.8.1.7, a preoperational drywell-to-wetwell leakage rate test is performed at the peak drywell-to-wetwell differential pressure. Table 14.2-4 gives the test descriptions. Also, drywell to wetwell leakage rate tests at a reduced differential pressure corresponding approximately to the submergence of the vents, defined in Chapter 16, are performed following the preoperational Type A test and periodically thereafter.
These drywell leakage rate tests verify, over the design life of the plant, that no paths for gross leakage from the drywell to the suppression chamber air space bypassing the pressure-suppression feature exist. The combination of the design pressure and reduced pressure leakage rate tests also verifies that the drywell performs adequately for the full range of postulated primary system break sizes. The drywell leakage rate limits specified in Chapter 16 for the above tests are based on a value of 10% of the allowable bypass A/(K)1/2 for small breaks that are described in Section 6.2.1.1.5.4.
Drywell leakage rate tests are performed with the drywell isolated from the suppression chamber.
Valves and system lineups are the same as for the Type A test except any paths for equalizing drywell and suppression chamber pressure open during the Type A test are isolated. The drywell atmosphere is allowed to stabilize for a period of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after attaining test pressure. Leakage rate test calculations, using the wetwell pressure rise method on Unit 1 and the wetwell pressure rise method on Unit 2, commence after the stabilization period.
The pressure rise method (Unit 1) is based on containment atmosphere pressure and temperature observations and the known wetwell free air volume specified in Table 6.2-1. Leakage rate is calculated from the pressure and temperature data, wetwell free air volume, and elapsed time.
The pressure rise method (Unit 2) is based on containment atmosphere pressure and temperature observations and the known wetwell volume specified in Table 6.2-1. Leakage rate is calculated from the pressure and temperature data, wetwell free air volume, and elapsed time.
When the drywell leakage rate test described above is not performed, an alternate test is performed to verify that each set of downcomer vacuum breaker valves does not provide a path for gross leakage from the drywell to the suppression chamber.
The periodic drywell leakage rate test and downcomer vacuum breaker valve leakage rate test pressures, test duration, and acceptance criteria are specified in Chapter 16. Periodic drywell leakage rate tests and downcomer vacuum breaker valve leakage tests are performed at the intervals specified in Chapter 16. This surveillance testing will be in accordance with the Technical Specifications.
6.2.6.5.2 Risk Informed Alternative Treatment Due to 10 CFR 50.69 There is a Risk Informed Categorization and Treatment Program at Limerick which is based on 10 CFR 50.69. This regulation provides an alternative approach for establishing requirements for treatment of SSCs using a risk-informed method of categorizing SSCs according to their safety significance. Specifically, for SSCs categorized as low safety significant, alternate treatment requirements may be implemented rather than treatments chosen by the Appendix J program. Refer to Section 13.5.5 for further information.
CHAPTER 06 6.2-94 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2.7 POSTACCIDENT SYSTEM ISOLATION Following an accident in which significant fuel damage is postulated to occur, a number of plant systems whose piping penetrates the primary containment may contain highly radioactive fluids.
Adequate system isolation features exist to ensure that the integrity of these systems will be maintained.
6.2.7.1 System Isolation Provisions The boundaries of potentially contaminated systems are adequately isolated by one of the following:
- a. Two normally closed manual valves
- b. One normally closed manual valve (low pressure piping)
- c. One or two normally closed manual valves and a cap
- d. One SRV or one rupture disc
- e. Two check valves
- f. One remotely actuated valve and one check valve
- g. Two remotely actuated valves In cases where a remotely actuated valve is required to change position to provide system isolation, the valve receives an auto isolation signal. In some cases a system isolation valve does not receive a direct isolation signal but is interlocked to close when a containment isolation valve or other valve opens to permit fluid flow from the containment.
Table 6.2-26 lists remotely actuated system isolation valves, their normal and required accident positions and their actuation signals. Containment isolation valves that also provide postaccident system isolation are not included in this table but are listed in Table 6.2-17.
6.2.7.2 Potentially Contaminated Systems The following systems whose piping penetrates primary containment may contain highly radioactive fluids after an accident. Other systems have been excluded from this list for the reasons discussed in Section 6.2.8.2.
- a. RHR System (drawing M-51)
- b. Core Spray System (drawing M-52)
- c. HPCI System (drawing M-55)
- d. RCIC System (drawing M-49)
CHAPTER 06 6.2-95 REV. 21, SEPTEMBER 2022
- f. Safeguard Piping Fill System (drawing M-52)
- g. PASS (drawing M-30)
- h. CAC System (drawing M-57) 6.2.8 LEAKAGE REDUCTION PROGRAM To ensure that leakage from systems that may be expected to handle highly radioactive fluids during or after an accident is maintained as-low-as-practical, a leakage reduction program will be established. System isolation provisions have been reviewed in conjunction with this effort and are discussed in Section 6.2.7.
6.2.8.1 Systems to be Leak Tested The following systems will be leak tested at 24-month intervals. The test conditions will simulate the expected operating conditions during an accident or transient:
- a. RHR System
- b. Core Spray System
- c. HPCI System
- d. RCIC System
- f. Safeguard Piping Fill System
- g. PASS (including portions of the Process Sampling System)
- h. CAC System (recombiner and sample loops only) 6.2.8.2 Systems Excluded from the Program The following systems are excluded from the leakage reduction program for the reasons given below:
- a. Reactor Recirculation System - The interfaces between the recirculation system and the systems outside containment (other than RHR) are isolated by containment isolation valves.
- b. RWCU - The RWCU system is isolated from the recirculation system by containment isolation valves.
- c. Main Steam System - The main steam system is isolated by containment isolation valves.
CHAPTER 06 6.2-96 REV. 21, SEPTEMBER 2022
- e. Process Sampling System - Sample lines from potentially contaminated sources inside the containment are isolated by containment isolation valves. Potentially contaminated sample lines from the RHR system, associated with postaccident sampling, will be leak tested with the postaccident sample system.
- f. Suppression Pool Cleanup System - The suppression pool cleanup system is isolated by containment isolation valves.
- g. RERS and SGTS - The reactor enclosure HVAC supply and exhaust valves will isolate the reactor enclosure upon receipt of high radiation isolation signal. The RERS and SGTS will then filter and exhaust air from the reactor enclosure and maintain a subatmospheric pressure. Because the source of radioactivity in these systems is airborne contamination resulting from previous leakage from the containment or contaminated systems, a leakage reduction program for the low pressure RERS/SGTS ducting would not significantly reduce the airborne radioactivity concentrations in the secondary containment. The recirculation and SGTS filters will be tested as described in Sections 6.5.1.3.4 and 6.5.1.1.4.
- h. Containment Radiation Sampling System - The containment radiation sampling system, used to provide an indication of primary leakage during normal operation, is isolated by containment isolation valves.
6.2.8.3 Leak Testing Method System leak test conditions will simulate the expected operating conditions during an accident.
Each component in the system will be inspected for leakage. Water leakage will be collected and measured. Steam leakage will be estimated and converted to an equivalent water leak rate. Gas systems will be bubble leak tested with a zero leakage acceptance criteria or leakage will be quantified by means of a pressure decay or helium leak test.
Leakage rate goals will be established for each system based on baseline data from the first tests.
Components whose leakage contributes significantly to the total leak rate or increases substantially between tests will be repaired to maintain total leakage as-low-as-practical.
6.
2.9 REFERENCES
6.2-1 I.E. Idel'chik, "Handbook of Hydraulic Resistance", AEC-TR-6630, pp. 2, 105, and 416, (1966).
6.2-2 "Flow of Fluids", Crane Technical Paper No. 410, Crane Co., Chicago, (1969).
6.2-3 F.J. Moody, "Maximum Two-Phase Vessel Blowdown from Pipes", Topical Report APED-4827, GE, (1965).
6.2-4 A.J. James, "The General Electric Pressure-Suppression Containment Analytical Model", NEDO-10320, (April 1971).
6.2-5 A.J. James, "The General Electric Pressure-Suppression Containment Analytical Model", Supplement 1 NEDO-10320, (May 1971).
CHAPTER 06 6.2-97 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2-6 Takashi Tagami, "Interim Report on Safety Assessment and Facilities Establishment (SAFE) Project", Hitachi Ltd., Tokyo, Japan, (February 28, 1966).
6.2-7 Donald J. Wilhelm, "Condensation of Metal Vapors: Mercury and the Kinetic Theory of Condensation", ANL-6948, (October 1964).
6.2-8 J.E. Krueger and R.C. Sansone, "Purge and Vent Valve Operability Qualification Analysis", Report 6-06-83, Prepared for PECo LGS Unit 1, Clow Corporation, (June 1983).
6.2-9 "Thermal Hydrogen Recombiner System for Water-Cooled Reactors," AI-75-2, (Rev
- 2) (P), Rockwell International, (July 1975).
6.2-10 "Thermal Hydrogen Recombiner System for Mark I and II Boiling Water Reactors,"
AI-77-55, Rockwell International, (September 1977).
6.2-11 H.A. McLain, "Potential Metal-Water Reaction in Light-Water-Cooled Power Reactors," ORNL-NSIC-23, pp. 4-17, (August 1968).
6.2-12 "Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident," Regulatory Guide 1.7 (Rev 2), NRC, (November 1978).
6.2-13 "Combustible Gas Control in Containment," SRP 6.2.5 (Rev 1), NRC.
6.2-14 H.H. Uhlig, "Corrosion Handbook", John Wiley & Sons, N.Y., pp. 39-43, (1948).
6.2-15 R.C. Burchell and D.D. Whyte, "Corrosion Study for Determining Hydrogen Generation from Aluminum and Zinc during Postaccident Conditions," WCAP-8776, (1976).
6.2-16 G.L. Cox, "Effect of Temperature on the Corrosion of Zinc," Industrial and Engineering Chemistry, Vol. 23, No. 8, p. 902, (1931).
6.2-17 J.R. Baylis, "Prevention of Corrosion and 'Red Water'," Journal of American Water Works Association, Vol. 5, pp. 598-633, (1926).
6.2-18 Franklin Institute Research Laboratories, "Hydrogen Evolution from Zinc Corrosion Under Simulated Loss-of-Coolant Accident Conditions," FIRC Report F-C 4290, (August 1976).
6.2-19 D. Van Rooyen, "Hydrogen Release Rate from Corrosion of Zinc and Aluminum,"
BNL, NUREG-24532, (May 1978).
6.2-20 G.J.E. Wilkutt; R.G.Gido; A. Kostell, "Hydrogen Mixing in a Closed Containment Compartment Based on a 1- Dimensional Model with Convective Effects", NUREG/
CR-1575, (September 1980).
6.2-21 "Generation and Mitigation of Combustible Gas Mixtures in Inerted BWR Mk I Containments," GE, NEDO-22155, (Draft NUREG - June 1982).
CHAPTER 06 6.2-98 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2-22 Letter from T.J. Dente (BWROG) to D.G. Eisenhut (NRC) "Supplement to BWR Owners Group Evaluation of NUREG-0737, Item II.E.4.2(7)", (June 14, 1982).
6.2-23 "Topical Report OCF-1, Nuclear Containment Isolation System", Owens-Corning Fiberglas Corporation, (January 1979).
6.2-24 Bechtel letter BLP-51146 (Doc Control No. 014444) dated March 28, 1990 "Response to NRC Questions on LGS ISA Analysis", and, Bechtel Report REPT M-005, Rev. 0 dated March 28, 1990 "Description of the Limerick Inadvertent Spray Actuation Analysis" (attached to Bechtel letter BLP-51146).
6.2-25 GE Nuclear Energy, "Generic Guidelines For GE Boiling Water Reactor Power Uprate," Licensing Topical Report NEDO-31897, Class I (Non-proprietary),
February 1992; and NEDC-31897P-A, Class III (Proprietary),May 1992.
6.2-26 NEDM-10320, "The GE Pressure Suppression Containment Analytical Model,"
March 1971.
6.2-27 NEDO-2533, "The General Electric Mark III Pressure Suppression Containment System Analytical Model," June 1974.
6.2-28 NEDO-20566A, "General Electric Company Analytical Model for Loss-Of-Coolant Analysis in Accordance with 10CFR50 Appendix K - Volume II," January 1976.
6.2-29 NUREG-0800, U.S. Nuclear Regulatory Commission, Standard Review Plan, Section 6.2.1.1.C, Pressure - Suppression Type BWR Containments," Revision 6, August 1984.
6.2-30 Letter from Ashok Thadani, Director Division of Systems Safety and Analysis, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission to Gary L.
Sozzi, Manager Technical Services, General Electric Nuclear Energy, "Use of SHEX Computer Program and ANSI/ANS 5.1-1979 Decay Heat Source Term for Containment Long-Term Pressure and Temperature Analysis," July 13, 1993.
6.2-31 NEDO-21061, "Mark II Containment Dynamic Forcing Functions Information Report," Rev. 4, November 1981.
6.2-32 NUREG-0487, U.S. Nuclear Regulatory Commission, "Mark II Containment Lead Plant Program Load Evaluation and Acceptance Criteria," October 1978.
6.2-33 NUREG-0808, U.S. Nuclear Regulatory Commission, "Mark II Containment Program Load Evaluation and Acceptance Criteria," August 1981.
6.2-34 U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the Operation of Limerick Generating Station,Units 1 and 2," NUREG-0991, August 1983, and Supplements (Docket Nos. 50-352 and 50-353).
6.2-35 D. Gobel, "Thermo-Hydraulic Quencher design of the Safety Relief System,"
Revision 1, R14-25/1978, Kraftwerk Union, April 1978.
CHAPTER 06 6.2-99 REV. 21, SEPTEMBER 2022
LGS UFSAR 6.2-36 USNRC I.E. Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors.
6.2-37 USNRC Regulatory Guide 1.82, Rev. 2, Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident, May 1996.
6.2-38 NUREG/CR-6224, Parametric Study of the Potential for BWR ECCS Strainer Blockage Due to LOCA Generated Debris.
6.2-39 Letter from G. A. Hunger, PECO Energy Director-Licensing to USNRC, Request for Licensing Amendment Associated with ECCS Pump Suction Strainer Plant Modification, October 6, 1997.
6.2-40 "Limerick Decay Heat Analysis," GE, GE-NE-0000-0006-9666-03, September 2002.
6.2-41 "Limerick Generating Station 1 & 2 SIL 636 Evaluation," GE, GE-NE-0000-0003-3779, June 2003.
6.2-42 "Post-LOCA Hydrogen Generation and Control Study (FSAR 6.2.5)," Calculation-0107, Revision 3A, April 2021.
CHAPTER 06 6.2-100 REV. 21, SEPTEMBER 2022
LGS UFSAR Table 6.2-1 (See Note)
CONTAINMENT DESIGN PARAMETERS*
SUPPRESSION DRYWELL CHAMBER DRYWELL AND SUPPRESSION CHAMBER Internal design pressure, psig 55 55 External to internal design 5 5 differential pressure, psid Drywell deck design differential 30 20 pressure, psid downward upward Design temperature, oF 340 220 Drywell net free air volume, ft3 Low level(4) 243,580(1)(2)
High level(4) 242,860(1)(2)
Design leak rate, % by weight/day 0.5 0.5 Maximum allowable leak rate, 0.5 0.5
% by weight/day Suppression chamber free air volume, ft3 Low level(4) 159,540(2)(3)
High level(4) 147,670(2)(3)
Suppression pool water volume, ft3 Low level(4) 122,120(2)(3)
High level(4) 134,600(2)(3)
Suppression pool surface area, ft2 Outside pedestal 4974(2)
Inside pedestal 293 Suppression pool depth, ft Low level 22' High level 24'-3" CHAPTER 06 6.2-101 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-1 (Cont'd)
SUPPRESSION DRYWELL CHAMBER VENT SYSTEM Number of downcomers 83(5)
Nominal downcomer diameter, ft 2 Total vent area, ft2 244.7(5)
Downcomer submergence, ft Low water level 10' High water level 12'-3" Downcomer loss coefficient 2.23(2)
(1)
Drywell volume includes downcomer air volume.
(2)
These values vary slightly from those actually used in the analysis. The difference in analysis results is negligible.
(3)
Including pedestal volume.
(4)
Low level and high level refer to suppression pool water level.
(5)
The original containment analysis included a total vent area of 256.5 square feet, equivalent to all 87 downcomers. Four of the downcomers have been capped. The impact of capping four downcomers on analysis results is negligable.
- NOTE: The information presented in this table was used for the original containment analysis and such should be considered historical. Refer to Table 6.2-4a for the parameters used in the current containment response analysis.
CHAPTER 06 6.2-102 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-2 ENGINEERED SAFETY FEATURE SYSTEMS INFORMATION FOR CONTAINMENT RESPONSE ANALYSES*
FULL CONTAINMENT ANALYSIS VALUE CAPACITY CASE A CASE B CASE C DRYWELL SPRAY Number of RHR pumps 2 2 1 0 Number of lines 2 2 1 0 Number of headers 2 2 1 0 Spray flow rate, 9,500 9,500 9,500 0 gpm/pump Spray thermal See Section 6.2.1.1.3.4.3 efficiency, %
SUPPRESSION CHAMBER SPRAY Number of RHR pumps 2 2 1 0 Number of lines 2 2 1 0 Number of headers 1 1 1 0 Spray flow rate, 500 500 500 0 gpm/pump Spray thermal See Section 6.2.1.1.3.4.3 efficiency, %
SUPPRESSION POOL COOLING SYSTEM Number of RHR pumps 2 2 1 1 Pump capacity, 10,000 10,000 10,000 10,000 gpm/pump RHR heat exchangers Type - Inverted - - - -
U-tube, single pass shell, multipass tubes, vertical mounting Number 2 2 1 1 CHAPTER 06 6.2-103 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-2 (Cont'd)
FULL CONTAINMENT ANALYSIS VALUE CAPACITY CASE A CASE B CASE C Heat transfer 6,281* - - -
area, ft2/unit Overall heat 228 * - - -
transfer coefficient, Btu/hr-ft2-F/unit RHRSW flow rate, 8000 5570 5570 5570 gpm/unit RHRSW temperature, oF - 95 95 95 Minimum design 40 - - -
Maximum design 95 - - -
Containment heat 128.5 x106 - - -
removal capability per unit, using 95F RHRSW and 212F pool temperature, Btu/hr Peak Containment 119.9 x106 - - -
Heat removal rate Btu/hr at peak suppression pool temperature of 203.4oF
- Actual heat transfer surface area and heat transfer coefficient vary with the condition of the heat exchanger (e.g. plugged or fouled tubes). Acceptance criteria are administratively controlled by plant surveillance procedures to assure that the RHR heat exchangers can provide the required Peak Containment Heat Removal Rate at the peak suppression pool water temperature.
- For two-unit operation with one RHRSW loop in service, the RHRSW design minimum required flow rate under accident conditions is 8000 gpm to the LOCA unit and between 5570 and 8000 gpm to the unit under normal shutdown conditions. An evaluation has been performed, however, to confirm that a RHRSW flow rate as low as 5570 gpm is sufficient to meet the design heat removal requirements of the unit with the LOCA under certain conditions.
CHAPTER 06 6.2-104 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-3 ACCIDENT ASSUMPTIONS AND INITIAL CONDITIONS FOR CONTAINMENT RESPONSE ANALYSES*
Components of effective break area (recirculation line break), ft2 Recirculation line 3.538 Jet pumps 0.537 Primary steam energy distribution(1), 106 Btu Steam energy 26.7 Liquid energy 365.0 Sensible energy Reactor vessel 93.97 Reactor internals (less core) 59.08 Primary system piping 23.2 Fuel(2) 6.299 Other assumptions used in analysis Feedwater valve closure time, sec Instantaneous MSIV closure time, sec Recirculation line break (includes 3.0 0.5 second delay)
Main steam line break (includes 5.0 0.5 second delay)
Scram time, sec <1 (1)
All energy values except fuel are based on a 32oF datum.
(2)
Fuel energy is based on a datum of 285oF.
- NOTE: The information presented in this table was used for the original containment analysis and such should be considered historical. Refer to Table 6.2-4a for the parameters used in the current containment response analysis.
CHAPTER 06 6.2-105 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-4 INITIAL CONDITIONS FOR CONTAINMENT RESPONSE ANALYSES*
Reactor power level, MWt 3,435 Average coolant pressure, psia 1,055 Average coolant temperature, F 551.1 Mass of RCS liquid, lb 669,900 Mass of RCS steam, lb 24,100 Volume of liquid in vessel, ft3 11,922.3 Volume of steam in vessel, ft3 10,122 Volume of liquid in recirculation 1,320.4 loops, ft3 Volume of steam in steam lines, ft3 1,218.0 Volume of liquid in feedwater line, ft3 1,232.5 Volume of liquid in miscellaneous Insignificant lines, ft3 Total reactor coolant volume, ft3 25,815.2 SUPPRESSION CONTAINMENT DRYWELL CHAMBER Pressure, psig 0.75 0.75 Air temperature, F 150 95 Relative humidity, % 20% 100%
Suppression pool water - 95 temperature, F Suppression pool water volume, ft3 - 118,655 Vent submergence, ft - 12'-3" (1) 105% of rated steam flow and normal liquid levels
- NOTE: The information presented in this table was used for the original containment analysis and such should be considered historical. Refer to Table 6.2-4a for the parameters used in the current containment response analysis.
CHAPTER 06 6.2-106 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-4A THE LGS POWER RERATE CONTAINMENT ANALYSIS I. Short-Term Analysis A. Drywell and Vent System Variable Units Value Used for Analysis Drywell Internal Design Pressure psig 55 Drywell Internal Design Temperature F 340 Drywell Deck Design Differential Pressure psid 30 (downward)
Drywell Free Volume (including vent system) ft3 243,580 Drywell Pressure psia 15.45 Drywell Temperature F 150 Drywell Relative Humidity % 20 Number of Downcomers 83 (1)
Downcomer Inside Diameter ft 1.9375 Downcomer Length ft 45.5 Downcomer Area (each) ft2 2.95 Total Downcomer Discharge Area ft2 244.7 (1)
Downcomer Submerge (HWL) ft 12.25 Total Downcomer Flow Loss Coefficient 2.23 (including exit loss)
B. Wetwell and Suppression Pool Variable Units Value Used for Analysis Wetwell Internal Design Pressure psig 55 Wetwell Deck Design Differential Pressure psid 20 (upward)
Wetwell Airspace Volume at high water level ft3 147,670 (including vent system)
Suppression Pool Volume (HWL) ft3 134,600 Suppression Pool Surface Area (outside pedestal) ft2 4,974 Suppression Pool Surface Area (inside pedestal ft2 293 Wetwell Pressure psia 15.45 Wetwell Airspace Temperature F 95 Suppression Pool Temperature F 95 Wetwell Relative Humidity % 100 (1) The original containment analysis included a total vent area of 256.5 square feet, equivalent to all 87 downcomers. Four of the downcomers have been capped. The impact of capping four downcomers on analysis results is negligable.
CHAPTER 06 6.2-107 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.2-4A THE LGS POWER RERATE CONTAINMENT ANALYSIS I. Short-Term Analysis (cont'd)
C. Reactor Initial Conditions RPV Saturation Downcomer Downcomer Rerated Power*/Flow Dome Pressure Enthalpy Enthalpy Subcooling Operating Point (psia) (Btu/lbm) (Btu/lbm) Btu/lbm 62RP/40F 1017 545.2 503.0 42.2 102RP/81F** 1068 552.8 526.1 26.7 102RP/87F 1068 552.8 527.7 25.1 102RP/100F 1068 552.8 531.3 21.5 102RP/110F 1068 552.8 533.4 19.4 62RP/40F - FFWTR 1009 543.9 487.9 56.0 102RP/81F - FFWTR** 1051 550.3 509.0 41.3 102RP/87F - FFWTR 1049 550.0 510.6 39.4 102RP/100F - FFWTR 1049 550.0 516.0 34.0 102RP/110F - FFWTR 1049 550.0 519.3 30.7
- RP (Rerate Power) is defined as 3458 MWt
- RP (Rerate Power) is defined here as 3622 MWt CHAPTER 06 6.2-108 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.2-4A THE LGS POWER RERATE CONTAINMENT ANALYSIS II. Long-Term Analysis*
A. Reactor Coolant System Variable Units Value Used for Analysis Reactor Power MWt 3528 (102% of 100%P)
Core Flow Rate lbm/hr 100.0E6 (100%F)
RPV Dome Pressure psia 1068 RPV Temperature F 552.5 Core Inlet Enthalpy Btu/lbm 531.3 RPV Inlet Feedwater Enthalpy (upstream Btu/lbm 411.4 of RWCU inlet)
Initial Steam Flow lbm/hr 15.451E6 Coolant System Total Free Volume ft3 23,492 Coolant System Liquid Volume ft3 13,108 B. Drywell and Vent System Variable Units Value Used for Analysis Drywell Free Volume ft3 243,580 (including vents)
Drywell Pressure psia 15.45 Drywell Temperature F 150 Drywell Relative Humidity % 20 Number of Downcomers 83 Downcomers Inside Diameter (Nominal) ft 1.9375 Total Vent Area ft2 244.7 Maximum Downcomer Submerge ft 10.0 Total Downcomer Flow Loss Coefficient 2.23 (including exit loss)
- The Long term containment analysis is performed for rerated conditions including the additional head load from SIL 636.
(Reference 6.2-41)
CHAPTER 06 6.2-109 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.2-4A THE LGS POWER RERATE CONTAINMENT ANALYSIS II. Long-Term Analysis(cont'd)
C. Suppression Chamber and Suppression Pool Variable Units Value Used for Analysis Suppression Chamber Airspace Volume ft3 147,670 (HWL) 159,540 (LWL)
Suppression Pool Volume ft3 134,300 (HWL) 118,655 (LWL)
Suppression Pool Surface Area ft2 5267 Suppression Chamber Airspace Pressure psia 15.45 Suppression Chamber Airspace F 95 Temperature Suppression Chamber Relative Humidity % 100 Suppression Pool Temperature F 95 D. RHR System Variable Units Value Used for Analysis Service Water Temperature F 95 Heat Exchanger K-Factor Btu/sec-F 305 RHR Pump Heat per Pump Hp 1250 CHAPTER 06 6.2-110 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.2-4A THE LGS POWER RERATE CONTAINMENT ANALYSIS II. Long-Term Analysis(cont'd)
E. ECCS Variable Units Value Used for Analysis HPCI Minimum Rated Flow at 0 to 200 psid gpm 5600 LPCS Minimum Rated Flow at 105 psid gpm 6250 (2 pumps)
Pump Heat per pump Hp 658 LPCI Minimum Rated Flow at 20 psid gpm 10000 (per pump)
Pump Heat per pump Hp 1250 F. Containment Spray Variable Units Value Used for Analysis Drywell Spray Flow Rate Per Pump gpm 9500 Pump Heat per Pump Hp 1187.5 HX K-Factor Btu/sec-F 289.8 Wetwell Spray Flow Rate Per Pump gpm 500 Pump Heat per Pump Hp 62.5 HX K-Factor Btu/sec-F 15.2 CHAPTER 06 6.2-111 REV. 16, SEPTEMBER 2012
SUMMARY
OF SHORT-TERM CONTAINMENT RESPONSES TO RECIRCULATION LINE AND MAIN STEAM LINE BREAKS MAIN RECIRCULATION STEAM LINE LINE BREAK BREAK___
Peak drywell pressure, psig 44.0 36.20 Peak drywell deck downward 25.995 19.5 differential pressure, psid Time of peak pressures, sec 13.66 20.12 Peak drywell temperature, F 290.9 330 Peak suppression chamber pressure, 30.57 30.55 psig Time of peak suppression chamber 34.75 50 pressure, sec Peak suppression pool temperature 135.7 136 during blowdown, F Calculated drywell pressure margin, % 20 34 Calculated suppression chamber 44 44 pressure margin, %
Calculated deck differential 13 35 pressure margin, %
Energy released to containment 262.23 -
at time of peak pressure, 106 Btu Energy absorbed by passive heat 0 0 sinks at time of peak pressure, 106Btu NOTE: The information presented in this table for the recirculation line break results is based on the original design basis conditions. Refer to Table 6.2-5A for the recirculation line break results for current plant conditions.
The information presented in this table for the main steam line break results is based on the original design basis conditions. As described in Section 6.2.1.1.3, the main steam line break was not reanalyzed for the current conditions; however, the results presented here reasonably represent the general characteristics of the main steam line break analysis results. See explanation at the beginning of Section 6.2.1.1.3.
CHAPTER 06 6.2-112 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-5A CONTAINMENT LOCA RESPONSE AT RERATE POWER Parameter Analysis Design Limit Peak Drywell Pressure (psig) 42.1 (1) 55 Peak Wetwell Pressure (psig) 39.0 (2) 55 Peak Drywell-to-Wetwell 28.5 (3) 30 Pressure Difference (psid)
Peak Bulk Pool Temperature (F)
(LOCA) 203.4 (4) 220*
212**
- Structural
- Low pressure ECCS pump NPSH @ 0 psig in the suppression chamber (1) Short Term Analysis performed for: Power=3694 MWt; Core Flow=110%; FWTR=105F (2) Short Term Analysis performed for: Power=3527 MWt; Core Flow=81%; FWTR=105F (3) Short Term Analysis performed for: Power=3694 MWt; Core Flow=100%; FWTR=0F (4) Long Term Analysis performed for: Power = 3528 MWt; Core Flow = 100%; FWTR = 0F (Initial Reactor pressure assumed to be 1053 psig)
CHAPTER 06 6.2-113 REV. 13, SEPTEMBER 2006
SUMMARY
OF LONG-TERM CONTAINMENT RESPONSES TO RECIRCULATION LINE AND MAIN STEAM LINE BREAKS CASE A CASE B CASE C Secondary peak suppression chamber 6.56 14.19 16.7 pressure, psig Peak suppression pool temperature, 173.6 211.3 212.5 o
F HPCI flow rate, gpm Not Used CS flow rate, gpm 12,500 6,250 6,250 RHR flow rate, gpm/pump 10,000 10,000 10,000 NOTE: The information presented in this table is based on the original design basis conditions. Refer to Table 6.2-5A for the Case C results for current plant conditions and methodology. The results for Cases A, B, and C shown is this table reasonably represent the general characteristics and relative differences between the three cases.
CHAPTER 06 6.2-114 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-7 ENERGY BALANCE FOR RECIRCULATION LINE BREAK ACCIDENT Energy, 106 Btu___________
DRYWELL LONG-PEAK END OF TERM PEAK INITIAL PRESSURE BLOWDOWN PRESSURE Reactor coolant 392.3 139.5 12.325 58.1 Fuel and cladding(1) 6.299 6.296 6.116 -
Core internals and primary 82.29 82.99 82.26 28.097 primary system piping Reactor vessel metal 93.97 93.97 93.97 32.56 Pump heat added 0 0 0.38045 185.3 Blowdown enthalpy(2) 0 262.23 409.6 409.6 Decay heat(3) 0 23.28 35.82 1,563.0 Metal-water reaction heat 0 0.02838 0.085 0.25 Drywell structures 0 0 0 0 Drywell air (4) (4) (4) 1.98 Drywell steam 2.236 56.33 42.06 9.79 Suppression chamber air 1.005 2.622 2.7233 1.097 Suppression chamber steam 0.3849 0.7054 1.0749 5.6238 Suppression pool water 64.3 666.4 823.8 1,382.7 Energy transferred by heat 0 0 0 1,304.0 exchangers Passive heat sinks 0 0 0 0 (1)
Does not include sensible energy in the fuel above initial reactor vessel saturation temperature (this energy is accounted for in decay heat as fuel relaxation energy)
(2)
Blowdown is accounted for in drywell condition, and should not be used to sum the total energy (3)
Includes fuel relaxation energy (4)
Included in drywell steam NOTE: The information presented in this table is based on the original design basis conditions. The current recirculations line break results are discussed in Section 6.2.1.8. The results presented here reasonably represent the general characteristics of the current recirculation line break analysis results.
CHAPTER 06 6.2-115 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-8 ACCIDENT CHRONOLOGY FOR RECIRCULATION LINE BREAK ACCIDENT (1)
TIME (SEC) MINIMUM ALL ECCS ECCS IN OPERATION AVAILABLE Vents cleared 0.733 0.733 Drywell reaches peak pressure 12.66 13.66 Maximum positive differential 0.85 0.85 pressure occurs Suppression chamber reaches 33.72 34.75 pressure peak Initiation of the ECCS 30 30 End of blowdown 36.35 37.69 Vessel reflooded 72.03 91.03 Initiation of RHR heat exchanger 600(2) 600(2)
Suppression chamber reaches 7,047 42,854 secondary pressure peak NOTE: (1) The information presented in this table is based on the original design basis conditions. The current recirculation line break results are discussed in Section 6.2.1.8. The results presented here reasonably represent the general characteristics of the current recirculation line break analysis results.
(2) Initiating time for analysis only. Containment heat removal will be initiated in accordance with emergency operating procedures based on plant conditions.
CHAPTER 06 6.2-116 REV. 14, SEPTEMBER 2008
LGS UFSAR Table 6.2-9 INITIAL AND BOUNDARY CONDITIONS FOR DRYWELL SPRAY ACTUATION ANALYSIS (Used in Reference 6.2 - 24 Analysis)
TABLE A(5) too(1) to(2)
Drywell Volume(3), ft3 242,860 242,860 Pressure, psia 13.7 35.61 Temperature, oF 135 260.3 Relative humidity, % 90 100 Spray rate, gpm/number of trains 0/0 9,500/1 Wetwell Volume - Vapor region(3), ft3 137,132 137,132
- Suppression pool(3), ft3 127,507 127,507 Pressure, psia 13.7 31.28 Temperature, oF 50 50 Relative humidity, % 100 100 Suppression pool free surface area, ft2 4,974 4,974 Wetwell-to-Drywell Vacuum Breakers Number of valve assemblies operable 4 of 4 (three required to operate and one redundant)
Flow area per assembly, ft2 2.05 Flow coefficient(4) 0.495 Vacuum breaker full open pressure(4) 4.48 (psid)
RHR System - Drywell Spray Mode Service water flow rate, gpm 9,000 Service water temperature, oF 40 Heat exchanger effectiveness 0.249 Spray Temperature: (Initially) 47.6F (at 300 seconds) 49.7F CHAPTER 06 6.2-117 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-9 INITIAL AND BOUNDARY CONDITIONS FOR DRYWELL SPRAY ACTUATION ANALYSIS (Used in Reference 6.2 - 24 Analysis)
TABLE B(5) too(1) to(2)
Drywell Volume(3), ft3 248,950 248,950 Pressure, psia 14.8 34.4 Temperature, oF 150 258.3 Relative humidity, % 100 100 Spray rate, gpm/number of trains 0/0 9,500/1 Wetwell Volume - Vapor region(3), ft3 146,283 146,283
- Suppression pool(3), ft3 127,507 127,507 Pressure, psia 14.8 29.1 Temperature, oF 50 50 Relative humidity, % 100 100 Suppression pool free surface area, ft2 4,983 4,983 Wetwell-to-Drywell Vacuum Breakers Number of valve assemblies operable 3 of 4 (two required to operate and one redundant)
Flow area per assembly, ft2 2.05 Flow coefficient(4) 0.495 Vacuum breaker full open pressure(4) 4.48 (psid)
RHR System - Drywell Spray Mode Service water flow rate, gpm 9,000 Service water temperature, oF 40 Heat exchanger effectiveness 0.249 Spray Temperature: (Initially) 47.6F (at 300 seconds) 49.7F (1)
Initial conditions prior to small break as discussed in Section 6.2.1.1.4.4 (2)
Conditions after small break, preceding drywell spray actuation (see Section 6.2.1.1.4.5).
(3)
High water level CHAPTER 06 6.2-118 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-9 INITIAL AND BOUNDARY CONDITIONS FOR DRYWELL SPRAY ACTUATION ANALYSIS (Used in Reference 6.2 - 24 Analysis)
(4)
Value given is for total flow path. Actual test results indicate that full open pressure differential across the vacuum breaker assembly only is 2.89 psid. For the ISA computer analysis, the following different pressures were used for opening the valves:
dp (across two valves) at which VB assembly starts to open equals 2.81 psid dp (from wetwell to drywell) at which VB assembly is fully open equals 4.48 psid (5)
The initial conditions and parameters differ slightly from those indicated in UFSAR Table 6.2-1; however, the use of the conditions and assumptions such as the loss of noncondensables through the purge lines, which were used in the ISA Analysis (reference 6.2-24) produces a more severe transient for purposes of comparing the performance of two vs three operating vacuum breaker valve assemblies. Table A provides the initial conditions used in the original analysis which assumes that the purge valves are closed.
The assumptions that are shown in Table B were used to created a worst case analysis to justify reducing the number of operable vacuum breakers from 4 to 3. This scenario assumes that the purge valves are open at the time of a small break LOCA.
CHAPTER 06 6.2-119 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-10 REACTOR BLOWDOWN DATA FOR RECIRCULATION LINE BREAK(1)(2)(3)(4)
REACTOR REACTOR VESSEL VESSEL LIQUID LIQUID STEAM STEAM TEMPERATURE TIME PRESSURE FLOW ENTHALPY FLOW ENTHALPY (oF) (sec) (psia) (lbm/sec) (Btu/lbm) (lbm/sec) (Btu/lbm) 551.1 - 1055 47620 550.1 - 1190.3 550.4 0.733 1048 47620 549.4 - 1190.5 549.9 1.03 1045 47620 549.1 - 1190.6 549.3 1.53 1040 47620 549.0 - 1190.65 548.5 3.16 1032 32290 547.5 - 1191.0 549.3 4.16 1040 32380 549.0 - 1190.65 550.2 5.16 1047 32470 549.3 - 1190.5 550.1 6.16 1055 32560 550.1 - 1190.3 552.5 8.16 1067 32700 552.1 - 1189.9 553.3 10.16 1074 32790 553.5 - 1189.5 552.8 13.66 1069 32720 552.2 - 1189.9 542.0 15.16 979.2 14160 538.5 4895 1192.8 518.7 18.16 803.2 10480 509.2 4438 1199.4 500.7 20.16 685.5 8518 487.7 4054 1202.5 454.3 25.00 441.6 4788 435.8 2919 1205.6 403.4 30.00 257.0 2387 387.53 1851 1202.4 328 35.00 100.7 2673 298.76 609.2 1187.9 294.6 37.5 61.78 2505 263.8 265.8 1178.2 292.8 37.69 60.06 - 262.5 277.7 1178.1 282.6 38.6 51.26 - 252.2 121 1175.1 281.0 38.75 49.98 - 250.2 - 1174.4 (1)
The volume of the primary system below the elevation of the recirculation line break is 4641 ft3.
(2)
The maximum diameter for the 251 sized vessel is 254 in corresponding to an inside cross-sectional vessel area of 352 ft2. (The actual flow area is a function of elevation due to the varying amount of space occupied by the vessel internals).
(3)
The surface area and maximum depth of the liquid pool formed on the drywell floor following a DBA LOCA and/or containment spray actuation are approximately 4800 ft2 and 18 inches, respectively.
(4)
The blowdown data provided includes the effect of ECCS additions prior to the end of blowdown. The amount of water in the vessel at the end of blowdown for the DBA is 1559 ft3.
NOTE: The information presented in this table is histroical and is based on the original design basis conditions. The current recirculation line break results are discussed in Section 6.2.1.8.
CHAPTER 06 6.2-120 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-11 REACTOR BLOWDOWN DATA FOR MAIN STEAM LINE BREAK(1)(2)(3)
REACTOR REACTOR VESSEL VESSEL LIQUID LIQUID STEAM STEAM TEMPERATURE TIME PRESSURE FLOW ENTHALPY FLOW ENTHALPY (oF) (sec) (psia) (lbm/sec) (Btu/lbm) (lbm/sec) (Btu/lbm) 551.1 - 1055 - 550.1 11650 1190.3 547.4 0.73 1023 - 546.1 8464.0 1191.6 546.5 1.0 1016 28250 544.2 1023.0 1191.3 547.0 1.499 1020 28120 545.7 1084.0 1191.7 547.2 2.06 1022 27950 545.7 1148.0 1191.7 547.3 2.56 1022 27730 545.7 1223.0 1191.7 547.3 3.06 1023 27600 545.7 1267.0 1191.7 547.3 4.06 1023 23960 545.7 1220.0 1191.7 547.8 5.18 1027 20710 546.8 1169.0 1191.6 548.2 8.18 1030 19880 546.0 1452.0 1191.5 547.2 10.1 1022 19190 545.7 1637.0 1191.7 540.7 15.1 968.8 16960 536.6 2069.0 1193.7 526.1 20.18 868.5 14130 518.0 2355.0 1197.5 509.0 25.18 737.7 11080 499.4 2431.0 1201.0 487.6 30.01 608.1 8285 473.0 2294.0 1203.4 460.7 35.03 470.2 5777 441.4 2046.0 1205.5 432.0 40.01 350.9 3695 410.5 1686.0 1204.4 395.3 45.18 234.4 2536 369.6 1164.0 1201.3 350.1 50.06 134.7 2570 321.8 604.9 1193.1 308.0 55.01 75.42 2442 278.0 237.9 1182.5 282.9 58.62 51.54 1126 252.28 58.74 1175.1 281.6 58.87 50.5 404.2 251.23 20.2 1174.7 280.5 59.12 49.56 - 249.18 - 1174.1 (1)
The volume of the primary system below the elevation of the main steam line break is 16,148 ft3.
(2)
The maximum diameter for the 251 sized vessel is 254 in corresponding to an inside cross-sectional vessel area of 352 ft2. (The actual flow area is a function of elevation due to the varying amount of space occupied by the vessel internals).
(3)
The surface area and maximum depth of the liquid pool formed on the drywell floor following a DBA LOCA and/or containment spray actuation are approximately 4800 ft2 and 18 inches, respectively.
NOTE: The information presented in this table is historical and is based on the original design basis conditions. As described in Section 6.2.1.1.3, the main steam line break was not reanalyzed for the current conditions; however, the results reasonably represent the general characteristics of the main steam line break analysis results.
CHAPTER 06 6.2-121 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-12 CORE DECAY HEAT FOLLOWING LOCA FOR CONTAINMENT ANALYSES TIME NORMALIZED (Sec) CORE HEAT(1) 0.0 1.00288 0.2 0.98188 0.6 0.74628 1.0 0.58218 2.0 0.54548 4.0 0.57113 6.0 0.53537 10.0 0.37232 20.0 0.11244 40.0 0.04215 60.0 0.03789 80.0 0.03575 100.0 0.03436 150.0 0.03197 220.0 0.02990 220.1 0.02702 300.0 0.02547 400.0 0.02408 600.0 0.02212 800.0 0.02069 1000.0 0.01956 2000.0 0.01599 3000.0 0.01400 1x104 0.01012 2x104 0.00850 4x104 0.00705 1X105 0.00546 (1)
Normalized to include fuel relaxation energy, pump heat, and metal-water reaction The information presented in this table is historical and was used in the original design basis for containment analysis. The current design basis analysis uses the decay heat model presented in ANSI/ANS 5.1-1979, as approved by the NRC (Ref. 6.2-30), including SIL 636 (Ref. 6.2-40)
CHAPTER 06 6.2-122 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-13 SECONDARY CONTAINMENT ACCESS OPENINGS ACCESS OPENING ELEVATION ROOM NUMBER (feet) TYPE OF ACCESS OPENING 201 201 Personnel access air lock 282 201 Personnel access air lock 300 217 Personnel access air lock 310 217 Railroad access air lock 301 217 Equipment access air lock 303 217 Personnel access air lock 308 217 Personnel access air lock 366 217 Personnel access air lock 367 217 Equipment access air lock 369 217 Personnel access air lock 377 217 Personnel access air lock 402A 253 Personnel access air lock 408 269 Personnel access air lock 481 269 Personnel access air lock 608 313 Personnel access air lock 606 313 Personnel access air lock 614 331 Personnel access air lock 642 313 Personnel access air lock 635 313 Personnel access air lock 650 331 Personnel access air lock 655 352 Personnel access air lock 703 352 Personnel access air lock 707 352 Personnel access air lock 654 352 Personnel access air lock 591(1) 360 Personnel access air lock 711(1) 360 Personnel access air lock (1)
These are access openings to the refueling area containment rather than the secondary containment.
CHAPTER 06 6.2-123 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-14 SECONDARY CONTAINMENT DESIGN DATA REACTOR ENCLOSURE VENTILATION ZONES I AND II, AND REFUELING AREA VENTILATION ZONE III Free volume, ft3: Zones I and II 1,800,000 each Zone III 2,200,000 Pressure Normal operation: Negative 0.25 in wg.
Postaccident: Negative 0.25 in wg.
Leak rate at postaccident pressure: 0.5 air change/day (Zone III) 2.0 air changes/day (Zones I and II)
SGTS Exhaust fans - common Number: 2 Type: centrifugal, single inlet single width Secondary containment atmosphere filtration prior to release to outdoors via SGTS fans Number: 2 Type: Zone I and II prefilter, HEPA, charcoal, HEPA in RERS followed by HEPA, charcoal, HEPA in SGTS Zone III prefilter, HEPA, charcoal, HEPA in SGTS TRANSIENT ANALYSIS Initial Conditions Pressure: negative 0.25 in wg.
Temperature: 104F Outside air temperature: 95F Thickness of secondary containment wall: 36 in Thickness of primary containment wall: 72 in CHAPTER 06 6.2-124 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-14 (Cont'd)
Thermal Characteristics Primary containment wall Thermal conductivity: 0.5 Btu/hr-ft-F Thermal capacitance: 25 Btu/ft3-F Secondary containment wall Thermal conductivity: 0.5 Btu/hr-ft-F Thermal capacitance: 25 Btu/ft3-F Heat transfer coefficients Primary containment atmosphere to primary containment wall: 1.46 Btu/hr-ft2-F Primary containment wall to secondary containment atmosphere: 1.46 Btu/hr-ft2-F Secondary containment wall to secondary containment atmosphere: 1.46 Btu/hr-ft2-F Primary containment emissivity: 0.9 Btu/hr-ft2-F Secondary containment emissivity: 0.9 Btu/hr-ft2-F CHAPTER 06 6.2-125 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-15 EVALUATION OF POTENTIAL SECONDARY CONTAINMENT BYPASS LEAKAGE PATHS CONTAINMENT TERMINATION BYPASS LEAKAGE POTENTIAL BYPASS PENETRATION SYSTEM REGION(1) BARRIERS(2) PATH 1 Equipment access door IRE Double O-Ring No 2 Equipment access door and IRE Double O-Ring No personnel lock 2 Service air supply to ORE 1,8 No personnel lock 3A Main steam line D flow IRE - No instrumentation 3B Instrument gas supply ORE 1,4 No 3C HPCI steam flow instrumentation IRE - No 3D Main steam line A flow IRE - No instrumentation 3D Instrument gas supply ORE 1,4 No 4 Head access manhole IRE Double O-Ring No 5 Spare - - -
6 CRD removal hatch IRE Double O-Ring No 7A-D Primary steam ORE 1,5 No 8 Primary steam line drain ORE 1,4 No 9A&B Feedwater ORE 1,3 No(3)(4) 10 Steam to RCIC turbine ORE 1,3,8 No 11 Steam to HPCI turbine ORE 1,3,8 No 12 RHR shutdown cooling supply ORE 1,3 No 13A&B RHR shutdown return ORE 1,3 No 14 RWCU supply ORE 1,3 No 15 Spare - - -
16A&B Core spray pump discharge ORE 1,3 No 17 RPV head spray (Unit 1 only) ORE 7 No (ABANDONED) 17 Spare (Unit 2 only) - - -
18 Spare - - -
19 Spare - - -
20A RPV level instrumentation IRE - No 20A LPCI P instrumentation IRE - No 20B LPCI P instrumentation IRE - No 20B RPV level instrumentation IRE - No 21 Spare - - -
22 Drywell pressure instrumentation IRE - No 23 Closed cooling water supply ORE 1,2,3 No 24 Closed cooling water return ORE 1,2,3 No 25 Drywell purge supply ORE 1,4,8 No 26 Drywell purge exhaust IRE - No 27A Instrument gas supply ORE 1,4 No 27B HPCI flow instrumentation IRE - No 28A Recirculation loop sample IRE - No 28A Drywell H2/O2 ORE 1,7 No 28B LPCI P instrumentation IRE - No 28B Drywell air sample ORE 1,7 No 29A RPV flange leakage instrumentation IRE - No 29B Core spray P instrumentation IRE - No 30A Main steam line D flow IRE - No instrumentation 30B Drywell pressure instrumentation IRE - No 30B Main steam line C flow IRE - No instrumentation 31A&B Jet pump flow instrumentation IRE - No 32A&B Jet pump flow instrumentation IRE - No 33A Pressure above core plate IRE - No instrumentation 33A Pressure below core plate IRE - No instrumentation CHAPTER 06 6.2-126 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-15 (Cont'd)
CONTAINMENT TERMINATION BYPASS LEAKAGE POTENTIAL BYPASS PENETRATION SYSTEM REGION(1) BARRIERS(2) PATH 33B RCIC steam flow instrumentation IRE - No 34A Main steam line C flow IRE - No instrumentation 34B Recirculation flow instrumentation IRE - No X-35A Spare - - -
35B Instrumentation gas to TIP ORE 1 No(4) indexing mechanism 35C-G TIP drives IRE - No 36 Spare - - -
37A-D CRD insert ORE 1,3 No 38A-D CRD withdraw ORE 1,3 No 39A&B Drywell spray ORE 1,3 No 40A-C Jet pump flow instrumentation IRE - No 40D Pressure below core plate IRE - No instrumentation 40E Drywell pressure instrumentation IRE - No 40F RCIC steam flow instrumentation IRE - No 40F Instrumentation gas suction ORE 1,4 No 40G ILRT data acquisition system ORE 1,8 No (2 lines) 40H Instrument gas supply ORE 1,4 No 40H Recirculation pump cooler flow IRE - No instrumentation 41 LPCI P instrumentation IRE - No 41 RWCU flow instrumentation IRE - No 42 SLCS IRE - No 43A Recirculation loop A P IRE - No instrumentation 43A Recirculation pump seal pressure IRE - No instrumentation 43B Main steam sample IRE - No 44 CRD/RWCU return ORE 1,3 No 45A-D LPCI ORE 1,3 No 46 Spare - - -
47 RWCU flow instrumentation IRE - No 48A RPV level instrumentation IRE - No 48A Core spray P instrumentation IRE - No 48B RPV level instrumentation IRE - No 49A&B Main steam line A&B flow IRE - No instrumentation 50A Drywell pressure instrumentation IRE - No 50A Recirculation flow instrumentation IRE - No 50B Recirculation pump seal pressure IRE - No instrumentation 50B Recirculation pump cooler flow IRE - No instrumentation 51A Recirculation line flow IRE - No instrumentation 51B Jet pump flow instrumentation IRE - No 52A Main steam line B flow IRE - No instrumentation 52B Recirculation line flow IRE - No instrumentation 53 Drywell chilled water supply ORE 1,2,3 No 54 Drywell chilled water return ORE 1,2,3 No 55 Drywell chilled water supply ORE 1,2,3 No 56 Drywell chilled water return ORE 1,2,3 No 57 RWCU flow instrumentation IRE - No CHAPTER 06 6.2-127 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-15 (Cont'd)
CONTAINMENT TERMINATION BYPASS LEAKAGE POTENTIAL BYPASS PENETRATION SYSTEM REGION(1) BARRIERS(2) PATH 58A Recirc loop B P instrumentation IRE - No 58B Spare - - -
59A&B Spare - - -
60 Spare - - -
61 Recirculation pump seal purge ORE 1,4 No 62 H2/O2 sample return ORE 1,4 No 63 Recirculation loop P IRE - No instrumentation; recirculation pump seal pressure instrumentation 64 Spare - - -
65A&B RPV pressure instrumentation IRE - No 65A&B RPV instrumentation reference ORE 9 No leg backfill system 66A RPV level instrumentation IRE - No 66A LPCI P instrumentation IRE - No 66B RPV level instrumentation IRE - No 66B LPCI P instrumentation IRE - No 67A&B RPV level and pressure IRE - No instrumentation 67A&B RPV instrumentation reference ORE 9 No leg backfill system 100A-D Neutron monitoring system - - -
101A-D Recirculation pump power - - -
102A&B Electrical spare - - -
103A&B Temperature and low level signals - - -
104A-D CRD position indicator - - -
105A-E Miscellaneous low voltage power - - -
106A-C Low voltage control - - -
107 Electrical spare - - -
108 Electrical spare - - -
109 Electrical spare - - -
110 Electrical spare - - -
111 Electrical spare - - -
112 Electrical spare - - -
113 Electrical spare - - -
114 Electrical spare - - -
115 Electrical spare - - -
116 SLCS IRE - No 117A Electrical spare - - -
117B Drywell radiation monitoring IRE - No 118A&B Electrical spare - - -
200A&B Access hatch - - -
201A Suppression pool purge supply ORE 1,4,8 No 201A (Unit 2) Hardened containment vent ORE 1,11 No Argon purge supply IRE 1,4 No 201B (Unit 1) Hardened containment vent Unit 1 ORO 1,11 No Argon purge supply IRE 1,4 No 201B (Unit 2) Spare - - -
202 Suppression pool purge exhaust IRE - No 203A-D RHR pump suction ORE 3 No 204A&B RHR pump test ORE 3 205A&B Suppression pool spray ORE 3 No 206A-D CS pump suction ORE 3 No 207A&B CS pump test and flush ORE 3 No 208A Spare - - -
208B CS pump minimum recirculation ORE 3 No 209 HPCI pump suction ORE 3 No 210 HPCI turbine exhaust ORE 3 No 211 Spare - - -
212 HPCI pump test and flush ORE 3 No 213 Spare - - -
214 RCIC pump suction ORE 3 No 215 RCIC turbine exhaust ORE 3 No 216 RCIC minimum flow ORE 3 No 217 RCIC vacuum pump discharge ORE 3 No 218 Instrument gas to vacuum relief ORE 1,4 No valves CHAPTER 06 6.2-128 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-15 (Cont'd)
CONTAINMENT TERMINATION BYPASS LEAKAGE POTENTIAL BYPASS PENETRATION SYSTEM REGION(1) BARRIERS(2) PATH 219A&B Suppression pool level IRE - No instrumentation 220A H2/O2 sample return ORE 1,4 No 220B (Unit 1) Suppression pool pressure instrumentation IRE - No 220B (Unit 2) Spare - - -
221A Wetwell H2/O2 sample ORE 1,7 No 221B Suppression pool air sample ORE 1,7 No 222 Indication and control - - -
223 Spare - - -
224 Spare - - -
225 Spare - - -
226A&B RHR minimum recirculation ORE 3 No 227 ILRT data acquisition system ORE 1,8 No 228A-C Spare - - -
228D HPCI vacuum relief ORE 1,3,8 No 229A (Unit 1) Spare - - -
229A (Unit 2) Suppression pool pressure IRE - No instrumentation 229B Spare - - -
230A Strain gauge instrumentation IRE - No 230B Drywell sump level instrumentation IRE - No 231A&B Drywell sump drains ORE 1,3 No 232A-S MSRV discharge - - -
235 CS pump minimum recirculation ORE 3 No 236 HPCI pump minimum recirculation ORE 3 No 237 Suppression pool cleanup pump ORE 1,3 No suction 238 RHR relief valve discharge ORE 3 No 239 RHR relief valve discharge ORE 3 No 240 RHR relief valve discharge ORE 3,10 No 241 RCIC vacuum relief ORE 1,3,8 No (1)
The termination regions are: IRE - Inside reactor enclosure ORE - Outside reactor enclosure (2)
The bypass leakage barriers are defined as follows (Section 6.2.3.3.3):
- 1. Redundant primary containment isolation valves.
- 2. Closed piping system inside containment.
- 3. A water seal maintained for 30 days following a LOCA.
- 4. The line beyond the outboard primary containment isolation valve is vented to the reactor enclosure by use of a vent line.
- 5. A MSIV alternate drain pathway (Section 6.7) is provided.
- 6. The line contains a temporary spool piece that is removed during normal operation and replaced by blind flanges so that any leakage through the flange is into the reactor enclosure.
- 7. Closed seismic Category I piping system outside containment.
- 8. The line contains a spectacle flange with the blind side installed during normal operation. Any leakage through the flange will be into the reactor enclosure.
- 9. The line contains two spring loaded check valves and two manual stop valves.
- 10. Blind flange permanently installed in line in the reactor enclosure.
- 11. Rupture disc installed downstream of primary containment isolation valves with burst pressure greater than maximum LOCA pressure.
(3)
The feedwater fill system will provide a water seal in the feedwater lines for all line breaks other than a feedwater line break inside containment. For a feedwater line break inside containment, a water seal is maintained by the CST water supply as discussed in Section 6.2.3.2.3.1.a.
(4)
No significant amounts of radioactivity will be released to the environment as discussed in Section 6.2.3.2.3.
CHAPTER 06 6.2-129 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-16 ACCIDENT CHRONOLOGY FOR MAIN STEAM LINE BREAK ACCIDENT Time Event 0 Break occurs 0 Scram assumed to occur 0 Isolation signal 0.5 MSIV start to close 1.0 Vessel water level reaches main steam line elevation 5.5 MSIV fully closed 30 ECCS flows start 59 End of blowdown 430 Vessel refloods NOTE: The information presented in this table is historical and is based on the original design basis conditions. As described in Section 6.2.1.1.3, the main steam line break was not reanalyzed for the current conditions; however, the results reasonably represent the general characteristics of the main steam line break analysis results.
CHAPTER 06 6.2-130 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-17 CONTAINMENT PENETRATION DATA LENGTH OF NRC PIPE FROM PRIMARY NORMAL POWER CONTAINMENT LINE GENERAL VALVE VALVE CONT. TO METHOD OF SECONDARY VALVE SHUTDOWN POST- FAILURE DIVERSE VALVE POWER PENETRATION LINE SIZE DESIGN ESF ESSENTIAL VALVE TYPE VALVE ARRANGEMENT TYPE C OUTSIDE ACTUATION METHOD OF POSITION VALVE ACCIDENT VALVE ISOLATION ISOLATION CLOSURE SOURCE NUMBER ISOLATED FLUID (in) CRITERION SYSTEM SYSTEM NUMBER (1) LOCATION (2) TEST VALVES (3) ACTUATION (4) POSITION POSITION POSITION SIGNAL(5) SIGNAL(12) TIME(6) (7) REMARKS X-3A-1 Instrumentation - Water/ 1 55 - - F070D XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line steam - - F073D XFC Outside 12" Flow - 0 0 0 - - - - -
D flow X-3A-2 Instrumentation - Water 1 55 - - F003A XFC Outside (40) No 2'-3" Flow - 0 0 0 - - - - -
recirc pump seal pressure X-3B Instrument Gas 1 56 No No 1005B CK Inside (22) Yes - Flow - 0 0 C - - - - -
gas supply No No 129B GB Outside 6" Comp air Spring 0 0 C C C,H,S Yes 4.4 sec B X-3C-1 Instrumentation - Steam 1 55 - - F024A XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
HPCI steam flow X-3C-2 Instrumentation - Steam 1 55 - - F024C XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
HPCI steam flow X-3D-1 Instrumentation - Steam/ 1 55 - - F070A XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line water - - F073A XFC Outside 12" Flow - 0 0 0 - - - - -
A flow X-3D-2 Instrument gas Gas 1 56 No Yes 1112 CK Inside (48) Yes - Flow - 0 0 C - - - - -
supply No Yes 151B GB Outside 7" AC motor Manual 0 0 C As is M NA 30 sec D X-7A-D Main steam Steam 26 55 No No F022A-D GB Inside (1) Yes - Instr gas Spring 0 C C C C,D,E,F,P,Q Yes 3-5*sec A/W No No F028A-D GB Outside 0" Comp air Spring 0 C C C C,D,E,F,P,Q Yes 3-5*sec B/X X-8 Main steam drain Steam/ 3 55 No No F016 GT Inside (33) Yes - AC motor Manual C 0 C As is C,D,E,F,P,Q Yes 30 sec A water No No F019 GT Outside 0" AC motor Manual C 0 C As is C,D,E,F,P,Q Yes Standard B mix X-9A,B Feedwater Water 24 55 Yes Yes F010A CK Inside (2) Yes - Flow - 0 C 0 - - - - -
No Yes F010B CH Inside - Flow - 0 C 0 - - - - -
Yes Yes F074A SLPACK Outside 0" Flow Spring 0 C 0 - - - - D No Yes F074B SLPACK Outside 0" Flow Spring 0 C 0 - - - - D No No F032A,B CK Outside 22'-2" Flow AC motor 0 C 0 As is - - - D No No 109A,B GT Outside 31'-6" AC motor Manual C C C As is RM No Standard D No No F039 SLPACK Outside 29'-6" Flow Spring 0 0 C - - - - N No Yes F013 GT Outside 20'-1" DC motor Manual C C 0 As is LFCC NA 23 sec A No Yes 1036A,B CK Outside 2'-6" Flow - C C 0 - - - - -
No Yes 130A,B GB Outside 124'-6" AC motor Manual C C C As is RM NA 30 sec A,B No Yes 133A,B GB Outside 70'-1" AC motor Manual C C 0 As is RM NA 30 sec A,B No No 1016 GB Outside 83'-2" Manual - C C C C - - - -
Yes Yes F105 GT Outside 22'-8" DC motor Manual C C 0 As is RM NA 30 sec B (19 )
X-10 Steam to RCIC Steam 3 55 No Yes F007 GB Inside (3) Yes - AC motor Manual 0 C 0 As is K,KA NA 7.2* sec C turbine No Yes F008 GB Outside 0" AC motor Manual 0 C 0 As is K,KA NA 7.2* sec A (14)
No No F076 GB Outside 3'-3" AC motor Manual C C C As is K,KA No 30 sec A X-11 Steam to HPCI Steam 10 55 No Yes F002 GB Inside (3) Yes - AC motor Manual 0 C 0 As is L,LA NA 12* sec D turbine No Yes F003 GB Outside 0" AC motor Manual 0 C 0 As is L,LA NA 12* sec B (14)
No No F100 GB Outside 6'-9" AC motor Manual C C C As is L,LA No 30 sec B X-12 RHR shutdown Water 20 55 No No F009 GT Inside (21) Yes - AC motor Manual C 0 C As is A,V Yes Standard A (15) cooling supply No No F008 GT Outside 17" AC motor Manual C 0 C As is A,V Yes Standard B (15)
No - 155 PSV Inside - Water - C C C As is - - - -
X-13A&B RHR shutdown Water 12 55 No No F050A,B TCK Inside (11) Yes - Flow Inst gas C 0 0 - A,V - - A,B (15) cooling return No No 151A,B GB Inside - Inst gas Spring C C C C A,V Yes 20 sec A (15)
No No F015A,B GB Outside 11" AC motor Manual C 0 C As is A,V Yes 29 sec B No No 1200A, B CK Inside - Flow Spring C C C C - - - -
X-14 RWCU supply Water 6 55 No No F001 GT Inside (20) Yes - AC motor Manual 0 0 C As is B,J,Y Yes 10* sec A No No F004 GT Outside 0" AC motor Manual 0 0 C As is B,J,Y Yes 10* sec B X-16A CS discharge Water 12 55 Yes Yes F006A TCK Inside (11) Yes - Flow Inst gas C C 0 - - - - A (9)
Yes Yes F039A GB Inside - Inst gas Spring C C C C - - 4.4 sec A Yes Yes F005 GT Outside 0" AC motor Manual C C 0 As is RM NA 12 sec A X-16B CS discharge Water 12 55 Yes Yes F006B TCK Inside (11) Yes - Flow Inst gas C C 0 - - - - B (9)
Yes Yes F039B GB Inside - Inst gas Spring C C C C - - 4.4 sec B Yes Yes 108 SLPACK Outside 0" Flow Spring C C 0 C - - - B (9)
X-17 RPV head spray - - - - - (21A) - - - - - - - - - - - -
(Unit 1 only)
(ABANDONED)
X-17 Spare - - - - - - - - - - - - - - - - - -
(Unit 2 only)
X-20A-1 Instrumentation - Water 1 55 - - F045B XFC Outside (37) No 14" Flow - 0 0 0 - - - - -
RPV level X-20A-2 Instrumentation - Water 1 55 - - 102B XFC Outside (40) No 14" Flow - 0 0 0 - - - - -
LPCI `B' dp X-20A-3 Instrumentation - Water 1 55 - - 103B XFC Outside (40) No 14" Flow - 0 0 0 - - - - -
LPCI `D' dp X-20B-1 Instrumentation - Water 1 55 - - F045C XFC Outside (37) No 2'-2" Flow - 0 0 0 - - - - -
RPV level X-20B-2 Instrumentation - Water 1 55 - - 102C XFC Outside (40) No 13" Flow - 0 0 0 - - - - -
LPCI `C' dp CHAPTER 06 6.2-131 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
LENGTH OF NRC PIPE FROM PRIMARY NORMAL POWER CONTAINMENT LINE GENERAL VALVE VALVE CONT. TO METHOD OF SECONDARY VALVE SHUTDOWN POST- FAILURE DIVERSE VALVE POWER PENETRATION LINE SIZE DESIGN ESF ESSENTIAL VALVE TYPE VALVE ARRANGEMENT TYPE C OUTSIDE ACTUATION METHOD OF POSITION VALVE ACCIDENT VALVE ISOLATION ISOLATION CLOSURE SOURCE NUMBER ISOLATED FLUID (in) CRITERION SYSTEM SYSTEM NUMBER (1) LOCATION (2) TEST VALVES (3) ACTUATION (4) POSITION POSITION POSITION SIGNAL(5) SIGNAL(12) TIME(6) (7) REMARKS X-21 Service air Gas 3 56 No No 1140 GT Inside (8) Yes - Manual - C C C - - - - -
air No No 1139 GT Outside 0" Manual - C C C - - - - -
X-22 Instrumentation - Gas 1 56 - - 147C GB Outside (41) No 8" AC motor Manual 0 0 0 As is RM - 30 sec C drywell pressure X-23 Recirc pump Water 4 56 No No 106 GT Outside (13) Yes 0" AC motor Manual 0 0 C As is C,H Yes Standard C cooling water No No 108 GT Outside 3'-11" AC motor Manual 0 0 C As is C,H Yes Standard D supply No No 109 GT Outside 5'-2" Manual - C C C - - - - -
X-24 Recirc pump Water 4 56 No No 107 GT Outside (13) Yes 0" AC motor Manual 0 0 C As is C,H Yes Standard C cooling water No No 111 GT Outside 3'-8" AC motor Manual 0 0 C As is C,H Yes Standard D return No No 110 GT Outside 5'-0" Manual - C C C - - - - -
X-25 Drywell purge Gas 24 56 No No HV-57-135 BF Outside (5) Yes 16'-7" AC motor Manual C 0 C As is B,H,W,U,S,R,T Yes 6** sec B (19) supply Yes Yes HV-57-121 BF Outside 3'-11" Comp air Spring C C C C B,H,W,U,S,R,T NA 5** sec A (23)
No No HV-57-123 BF Outside 3'-4" Comp air Spring C 0 C C B,H,W,U,S,R,T Yes 5** sec A Yes Yes HV-57-131 BF Outside 60'-7" Comp air Spring C C C C B,H,W,U,S,R,T NA 5** sec A (19), (23)
Yes Yes HV-57-163 BF Outside 3'-8" AC motor Manual C C 0 As is B,H,R,S NA 6 sec D No No HV-57-109 BF Outside 42'-2" AC motor Manual C C C As is B,H,W,U,S,R,T Yes 6** sec B (19)
Yes Yes FV-DO-101B GB Outside 251-1" AC motor Manual C C 0 As is B,H,R,S NA 80 sec D (19)
X-26 Drywell purge Gas 24 56 No No HV-57-115 BF Outside (27) Yes 53'-7" AC motor Manual C 0 C As is B,H,W,U,S,R,T Yes 6** sec A (19) exhaust Yes Yes SV-57-145 GB Outside 66'-9" AC coil - 0 0 0 C B,H,R,S NA 2 sec D (19)
No No HV-57-111 GB Outside 6'-6" AC motor Manual C C C As is B,H,U,S,R,T Yes 15** sec B (20)
No No HV-57-114 BF Outside 49'-7" Comp air Spring C 0 C C B,H,W,U,S,R,T Yes 5** sec B (19)
Yes Yes HV-57-161 BF Outside 47'-11" AC motor Manual C C 0 As is B,H,R,S NA 6 sec C (19)
No No HV-57-117 GB Outside 60'-3" Comp air Spring C C C C B,H,U,S,R,T Yes 5** sec A (19)
- - SV-57-139 GB Outside No 35'-5" AC coil - 0 0 0 C RM - 2 sec A (19)
Yes Yes FV-DO-101A GB Outside 78'-3" AC motor Manual C C 0 As is B,H,R,S NA 80 sec C (19)
X-27A Instrument gas Gas 1 56 No Yes 1128 CK Inside (48) Yes - Flow - 0 0 C - - - - -
supply No Yes 151A GB Outside 7" AC motor Manual 0 0 C As is M NA 30 sec C X-27B-1 Instrumentation - Steam 1 55 - - F024B XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
HPCI X-27B-2 Instrumentation - Steam 1 55 - - F024D XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
HPCI flow X-28A-1 Recirc loop Water 3/4 55 No No F019 GB Inside (9) Yes - Instr gas Spring C C C C B,D Yes 7 sec A (14) sample No No F020 GB Outside 4'-3" Comp air Spring C C C C B,D Yes 7 sec B (14)
X-28A-2 Drywell H2O2 Gas 1 56 Yes Yes 132 GB Outside (23) Yes 20" AC coil - 0 0 0 C B,H,R,S NA 2 sec B sample Yes Yes 142 GB Outside 3'-0" AC coil - 0 0 0 C B,H,R,S NA 2 sec D X-28A-3 Drywell H2O2 Gas 1 56 Yes Yes 134 GB Outside (23) Yes 20" AC coil - 0 0 0 C B,H,R,S NA 2 sec B sample Yes Yes 144 GB Outside 3'-0" AC coil - 0 0 0 C B,H,R,S NA 2 sec D X-28B Drywell H2O2 Gas 1 56 Yes Yes 133 GB Outside (23) Yes 17" AC coil - 0 0 0 C B,H,R,S NA 2 sec A sample Yes Yes 143 GB Outside 2'-11" AC coil - 0 0 0 C B,H,R,S NA 2 sec D Yes Yes 195 GB Outside 2'-11" AC coil - 0 0 0 C B,H,R,S NA 2 sec C X-29A Instrumentation - Water 1 55 - - F009 XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
RPV flange leakage X-29B Instrumentation - Water 1 55 - - F018A XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
CS WP X-30A Instrumentation - Water 1 55 - - F071D XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line - - F072D XFC Outside 12" Flow - 0 0 0 - - - - -
D flow X-30B-1 Instrumentation - Gas 1 56 - - 147A GB Outside (41) No 7" AC motor Manual 0 0 0 As is RM - 30 sec A drywell pressure X-30B-2 Instrumentation - Water 1 55 - - F071C XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line - - F072C XFC Outside 12" Flow - 0 0 0 - - - - -
C flow X-31A,B Instrumentation - Water 1 55 - - F059B,F,H XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
jet pump flow - - F059D XFC Outside 4'-7" Flow - 0 0 0 - - - - -
- - F051B XFC Outside 3'-4" Flow - 0 0 0 - - - - -
- - F053B XFC Outside 12" Flow - 0 0 0 - - - - -
X-32A,B Instrumentation - Water 1 55 - - F059M,S,U XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
jet pump flow - - F051D XFC Outside 3'-4" Flow - 0 0 0 - - - - -
- - F053D XFC Outside 12" Flow - 0 0 0 - - - - -
- - F059P XFC Outside 4'-6" Flow - 0 0 0 - - - - -
X-33A-1 Instrumentation - Water 1 55 - - F055 XFC Outside (37) No 2'-5" Flow - 0 0 0 - - - - -
pressure above - - F076 XFC Outside 4'-2" Flow - 0 0 0 - - - - -
core plate X-33A-2 Instrumentation - Water 1 55 - - F061 XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
pressure below core plate X-33B Instrumentation - Water 1 55 - - F044A,C XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
RCIC steam flow X-34A Instrumentation - Water 1 55 - - F070C XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line - - F073C XFC Outside 12" Flow - 0 0 0 - - - - -
C flow X-34B-1 Instrumentation - Water 1 55 - - F009C XFC Outside (40) No 18" Flow - 0 0 0 - - - - -
recirc flow - - F010D XFC Outside 3'-6" Flow - 0 0 0 - - - - -
CHAPTER 06 6.2-132 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
LENGTH OF NRC PIPE FROM PRIMARY NORMAL POWER CONTAINMENT LINE GENERAL VALVE VALVE CONT. TO METHOD OF SECONDARY VALVE SHUTDOWN POST- FAILURE DIVERSE VALVE POWER PENETRATION LINE SIZE DESIGN ESF ESSENTIAL VALVE TYPE VALVE ARRANGEMENT TYPE C OUTSIDE ACTUATION METHOD OF POSITION VALVE ACCIDENT VALVE ISOLATION ISOLATION CLOSURE SOURCE NUMBER ISOLATED FLUID (in) CRITERION SYSTEM SYSTEM NUMBER (1) LOCATION (2) TEST VALVES (3) ACTUATION (4) POSITION POSITION POSITION SIGNAL(5) SIGNAL(12) TIME(6) (7) REMARKS X-34B-2 Instrumentation - Water 1 55 - - F009D XFC Outside (40) No 2'-9" Flow - 0 0 0 - - - - -
recirc flow - - F010C XFC Outside 2'-9" Flow - 0 0 0 - - - - -
X-35B TIP purge Gas 1 56 No No 131 GB Outside (46) Yes 0" Comp air Spring 0 C C C B,H,S Yes 4.4 sec B No No 1056 CK Inside - Flow - 0 C C C - - - -
X-35C-G TIP drives Gas 3/8 56 No No 140A-E XP Outside (6) Yes 16" Explosion - 0 0 0 As is RM - - N (10)
No No 141A-E BL Outside 8" AC coil Spring C C C C B,H Yes - N (10)
X-37A-D CRD insert Water 1 55 Yes Yes - BLCK Inside (47) No - - - - - - - - - - - (11)
Yes Yes 46-1101 CK Outside - Yes - Flow - 0 0 C - - - - - (11) 46-1102 46-1108 46-1109 X-38A-D CRD withdraw Water 3/4 55 Yes Yes 46-1115 CK Outside (47) Yes - Flow - 0 0 C - - - - - (11) 46-1116 46-1122 46-1123 Yes Yes F180 GB Outside Yes Varies Comp air Spring 0 0 C C - NA 30 N (11)
Yes Yes F181 GB Outside (input Comp air Spring 0 0 C C - NA 30 N (11)
Yes Yes F010 GB Outside from Comp air Spring 0 0 C C - NA 25 N (11)
Yes Yes F011 GB Outside 185 HCUs Comp air Spring 0 0 C C - NA 25 N (11) with max.
of approx.
320')
X-39A,B Containment Water 16 56 Yes Yes F021A,B GT Outside (25) Yes 12" AC motor Manual C C C As is RM NA Standard A,B spray Yes Yes F016A,B GT Outside 8'-0" AC motor Manual C C C As is RM NA Standard A,B X-40A Instrumentation - Water 1 55 - - F059L,R XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
jet pump flow - - F059N XFC Outside 4'-7" Flow - 0 0 0 - - - - -
X-40B Instrumentation - Water 1 55 - - F059G XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
jet pump flow - - F051A XFC Outside 3'-4" Flow - 0 0 0 - - - - -
- - F053A XFC Outside 12" Flow - 0 0 0 - - - - -
X-40C Instrumentation - Water 1 55 - - F059A,E XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
jet pump flow - - F059C XFC Outside 4'-7" Flow - 0 0 0 - - - - -
X-40D-1 Instrumentation - Water 1 55 - - F057 XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
pressure below core plate X-40D-2 Instrumentation - Water 1 55 - - 170 XFC Outside (37) No 1'-10" Flow - 0 0 0 - - - - -
RWCU flow - - 171 XFC Outside 1'-10" Flow - 0 0 0 - - - - -
X-40E Instrumentation - Gas 1 56 - - 147D GB Outside (41) No 12" AC motor Manual 0 0 - As is RM - 30 sec D drywell pressure X-40F-1 Instrumentation - Steam 1 56 - - F044B,D XFC Outside (40) No 12" Flow Manual 0 0 0 - - - - D RCIC pressure X-40F-2 Instrument gas Gas 1 56 No No 101 GB Inside (4) Yes - AC motor Manual 0 0 C As is C,H,S Yes 30 sec A suction No No 102 GB Outside 8" Comp air Spring 0 0 C C C,H,S Yes 4.4 sec B X-40G-1 ILRT data Gas 3/4 56 No No 1057 GB Outside (31) Yes 7" Manual - C C C - - - - -
acquisition No No 1058 GB Outside 23" Manual - C C C - - - - -
X-40G-2 ILRT data Gas 3/4 56 No No 1071 GB Outside (31) Yes 7" Manual - C C C - - - - -
acquisition No No 1070 GB Outside 2'-10" Manual - C C C - - - - -
X-40H-1 Instrument gas Gas 1 56 No No 1005A CK Inside (22) Yes - Flow - 0 0 C - - - - -
supply No No 129A GB Outside 13" Comp air Spring 0 0 C C C,H,S Yes 4.4 sec A X-40H-2 Instrumentation - Water 1 56 - - 156B XFC Outside (44) No 12" Flow - 0 0 0 - - - - -
recirc pump cooler - - 157B XFC Outside 12" Flow - 0 0 0 - - - - -
X-41-1 Instrumentation - Water 1 55 - - 102A XFC Outside (40) No 2'-5" Flow - 0 0 0 - - - - -
RWCU flow - - 102B XFC Outside 13" Flow - 0 0 0 - - - - -
X-41-2 Instrumentation - Water 1 55 - - 103A XFC Outside (40) No 13" Flow - 0 0 0 - - - - -
LPCI `A' dp X-42 Standby liquid Sodium 2 55 Yes Yes F007 CK Inside (10) Yes - Flow - C C C - - - - -
control pentaborate Yes Yes F006A SCK Outside 8" Flow AC motor 0 0 0 - RM NA Standard A solution X-43A Instrumentation - Water 1 55 - - F040A,C XFC Outside (40) No 2'-3" Flow - 0 0 0 - - - - -
recirc loop A WP X-43B Main steam sample Steam 3/4 55 No No F084 GB Inside (9) Yes - Inst gas Spring C C C C B,D Yes 7 sec A No No F085 GB Outside 2'-6" Comp air Spring C C C C B,D Yes 7 sec B X-44 Alternate RWCU Water 4 55 No No 1017 GB Inside (14) Yes - Manual - C 0 C - - - - -
return No No 1016 GB Outside 20" Manual - C 0 C - - - - -
No - 112 PSV Outside 7'-6" Water pres - C C C - - - - -
X-45A-D LPCI Water 12 55 Yes Yes 142A,B,C,D GB Inside (11) Yes - Inst gas Spring C C C C - - 4.4 sec A,B,C,D Yes Yes F041A,B,C,D TCK Inside - Flow Inst gas C C 0 - - - - A,B,C,D Yes Yes F017A,B,C,D GT Outside 0" AC motor Manual C C 0 As is RM NA 24 sec A,B,C,D X-47 Instrumentation - Water 1 55 - - 102D XFC Outside (40) No 11" Flow - 0 0 0 - - - - -
RWCU flow X-48A-1 Instrumentation - Water 1 55 - - F065B XFC Outside (37) No 2'-6" Flow - 0 0 0 - - - - -
RPV level - - F047B XFC Outside 21" Flow - 0 0 0 - - - - -
X-48A-2 Instrumentation - Water 1 55 - - F018B XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
core spray WP CHAPTER 06 6.2-133 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
LENGTH OF NRC PIPE FROM PRIMARY NORMAL POWER CONTAINMENT LINE GENERAL VALVE VALVE CONT. TO METHOD OF SECONDARY VALVE SHUTDOWN POST- FAILURE DIVERSE VALVE POWER PENETRATION LINE SIZE DESIGN ESF ESSENTIAL VALVE TYPE VALVE ARRANGEMENT TYPE C OUTSIDE ACTUATION METHOD OF POSITION VALVE ACCIDENT VALVE ISOLATION ISOLATION CLOSURE SOURCE NUMBER ISOLATED FLUID (in) CRITERION SYSTEM SYSTEM NUMBER (1) LOCATION (2) TEST VALVES (3) ACTUATION (4) POSITION POSITION POSITION SIGNAL(5) SIGNAL(12) TIME(6) (7) REMARKS X-48B Instrumentation - Water 1 55 - - F065A XFC Outside (37) No 21" Flow - 0 0 0 - - - - -
RPV Level - - F047A XFC Outside 2'-6" Flow - 0 0 0 - - - - -
X-49A,B Instrumentation - Water/ 1 55 - - F071A,B XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line steam - - F072A,B XFC Outside 12" Flow - 0 0 0 - - - - -
A&B flow X-50A-1 Instrumentation - Gas 1 56 - - 147B GB Outside (41) No 7" AC motor Manual 0 0 0 As is RM - 30 sec B drywell pressure X-50A-2 Instrumentation - Water 1 55 - - F011A XFC Outside (40) No 2'-9" Flow - 0 0 0 - - - - -
recirc flow F012B XFC Outside 18" Flow - 0 0 0 - - - - -
X-50A-3 Instrumentation - Water 1 55 - - F011B XFC Outside (40) No 18" Flow - 0 0 0 - - - - -
recirc flow - - F012A XFC Outside 2'-9" Flow - 0 0 0 - - - - -
X-50B Instrumentation - Water 1 55 - - F004A XFC Outside (45) No 4'-11" Flow - 0 0 0 - - - - -
recirc pump seal pressure X-50B Instrumentation - Water 1 56 - - 156A XFC Outside (44) No 22" Flow - 0 0 0 - - - - -
recirc pump - - 157A XFC Outside 20" Flow - 0 0 0 - - - - -
cooler flow X-51A Instrumentation - Water 1 55 - - F009A,B XFC Outside (40) No 18" Flow - 0 0 0 - - - - -
recirc line flow - - F010A,B XFC Outside 18" Flow - 0 0 0 - - - - -
X-51B Instrumentation - Water 1 55 - - F059T XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
jet pump flow - - F051C XFC Outside 3'-4" Flow - 0 0 0 - - - - -
- - F053C XFC Outside 12" Flow - 0 0 0 - - - - -
X-52A Instrumentation - Water 1 55 - - F070B XFC Outside (40) No 12" Flow - 0 0 0 - - - - -
main steam line - - F073B XFC Outside 12" Flow - 0 0 0 - - - - -
B flow X-52B-1 Instrumentation - Water 1 55 - - F011C XFC Outside (40) No 2'-9" Flow - 0 0 0 - - - - -
recirc line flow - - F011D XFC Outside 18" Flow - 0 0 0 - - - - -
X-52B-2 Instrumentation - Water 1 55 - - F012C XFC Outside (40) No 2'-3" Flow - 0 0 0 - - - - -
recirc line flow - - F012D XFC Outside 18" Flow - 0 0 0 - - - - -
X-53 Chilled water Water 8 56 No No 128 GT Outside (13) Yes 0" AC motor Manual 0 0 C As is C,H Yes Standard B supply A No No 120A GT Outside 63'-10" AC motor Manual 0 0 C As is C,H Yes Standard A (19)
No No 125A GT Outside 63'-10" AC motor Manual C C C As is - - - - (21)
X-54 Chilled water Water 8 56 No No 129 GT Outside (13) Yes 0" AC motor Manual 0 0 C As is C,H Yes Standard B return "A" No No 121A GT Outside 67'-0" AC motor Manual 0 0 C As is C,H Yes Standard A (19)
No No 124A GT Outside 67'-0" AC motor Manual C C C As is - - - (21)
X-55 Chilled water Water 8 56 No No 122 GT Outside (13) Yes 0" AC motor Manual C C C As is C,H Yes Standard B supply "B" No No 120B GT Outside 46'-10" AC motor Manual 0 0 C As is C,H Yes Standard A (19)
No No 125B GT Outside 46'-10" AC motor Manual C C C As is - - - (21)
X-56 Chilled water Water 8 56 No No 123 GT Outside (13) Yes 0" AC motor Manual C C C As is C,H Yes Standard B return "B" No No 121B GT Outside 37'-2" AC motor Manual 0 0 C As is C,H Yes Standard A (19)
No No 124B GT Outside 37'-2" AC motor Manual C C C As is - - - (21)
X-57 Instrumentation - Water 1 55 - - 102C XFC Outside (40) No 11" Flow - 0 0 0 - - - - -
RWCU flow X-58A Instrumentation - Water 1 55 - - F040B XFC Outside (40) No 14" Flow - 0 0 0 - - - - -
recirc loop B WP X-61-1 Recirc pump seal Water 1 55 No No 1004A CK Inside (45) Yes - Flow - 0 C C - - - - -
purge - - 103A XFC Outside 20" Flow - 0 0 0 - - - - -
X-61-2 Recirc pump seal Water 1 55 No No 1004B CK Inside (45) Yes - Flow - 0 C C - - - - -
purge - - 103B XFC Outside 20" Flow - 0 0 0 - - - - -
X-62 H2/O2 sample Gas 1 56 Yes Yes 150 GB Outside (12) Yes 3'-3" AC coil - 0 0 0 C B,H,R,S NA 2 sec B return; drywell No No 116 GB Outside 6'-6" AC motor Manual C C C As is B,H,R,S Yes 30** sec D purge makeup Yes Yes 159 GB Outside 15'-9" AC coil - 0 0 0 C B,H,R,S NA 2 sec D (19)
Yes Yes 190 GB Outside 255'-8" AC coil - 0 0 0 C B,H,R,S NA 2 sec C Yes Yes 191 GB Outside 253'-1" AC coil - 0 0 0 C B,H,R,S NA 2 sec A X-63-1 Instrumentation - Water 1 55 - - F040D XFC Outside (40) No 3'-4" Flow - 0 0 0 - - - - -
recirc loop "B" dp X-63-2 Instrumentation - Water 1 55 - - F004B XFC Outside (45) No 12" Flow - 0 0 0 - - - - -
recirc pump seal - - F003B XFC Outside 12" Flow - 0 0 0 - - - - -
pressure X-65A,B Instrumentation - Water 1 55 - - F043B XFC Outside (37) No 14" Flow - 0 0 0 - - - - -
RPV pressure - - F049A XFC Outside 14" Flow - 0 0 0 - - - - -
X-66A-1 Instrumentation - Water 1 55 - - F045D XFC Outside (37) No 13" Flow - 0 0 0 - - - - -
RPV level X-66A-2 Instrumentation - Water 1 55 - - 102D XFC Outside (40) No 13" Flow - 0 0 0 - - - - -
LPCI "B" dp - - 103D XFC Outside 13" Flow - 0 0 0 - - - - -
X-66B-1 Instrumentation - Water 1 55 - - F045A XFC Outside (37) No 14" Flow - 0 0 0 - - - - -
RPV level X-66B-2 Instrumentation - Water 1 55 - - 102A XFC Outside (37) No 14" Flow - 0 0 0 - - - - -
LPCI "A" dp CHAPTER 06 6.2-134 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
LENGTH OF NRC PIPE FROM PRIMARY NORMAL POWER CONTAINMENT LINE GENERAL VALVE VALVE CONT. TO METHOD OF SECONDARY VALVE SHUTDOWN POST- FAILURE DIVERSE VALVE POWER PENETRATION LINE SIZE DESIGN ESF ESSENTIAL VALVE TYPE VALVE ARRANGEMENT TYPE C OUTSIDE ACTUATION METHOD OF POSITION VALVE ACCIDENT VALVE ISOLATION ISOLATION CLOSURE SOURCE NUMBER ISOLATED FLUID (in) CRITERION SYSTEM SYSTEM NUMBER (1) LOCATION (2) TEST VALVES (3) ACTUATION (4) POSITION POSITION POSITION SIGNAL(5) SIGNAL(12) TIME(6) (7) REMARKS X-67A Instrumentation - Water 1 55 - - F049B XFC Outside (37) No 13" Flow - 0 0 0 - - - - -
RPV pressure X-67B-1 Instrumentation - Water 1 55 - - F043A XFC Outside (37) No 12" Flow - 0 0 0 - - - - -
RPV pressure X-67B-2 Instrumentation - Water 1 55 - - F041 XFC Outside (37) No 11" Flow - 0 0 0 - - - - -
RPV level X-102A Instrumentation - Water 1 55 - - 185A XFC Outside (37) No 18" Flow - 0 0 0 - - - - -
jet pump flow X-107 Instrumentation - Water 1 55 - - 185B XFC Outside (37) No 18" Flow - 0 0 0 - - - - -
jet pump flow X-116 Standby liquid Sodium 2 55 Yes Yes F007 CK Inside (10) Yes - Flow - C C C - - - - -
control pentaborate Yes Yes F006B SCK Outside 16" Flow AC motor 0 0 0 As is RM NA Standard B solution X-117B-1 Drywell radiation Gas 1 56 No No 190-A,B GB Outside (23) Yes 9'-4" AC coil - 0 C C C B,H,R,S Yes 2 sec C,B sample supply and return X-117B-2 Drywell radiation Gas 1 56 No No 190-C,D GB Outside (23) Yes 10'-2" AC coil - 0 C C C B,H,R,S Yes 2 sec C,B (19) sample supply and return X-201A Suppression pool Gas 20 56 No No HV-57-109 BF Outside (7) Yes 42'-9" AC motor Manual C C C As is B,H,W,U,S,R,T Yes 6** sec B (19) purge supply No No HV-57-147 BF Outside 17'-5" AC motor Manual C 0 0 As is B,H,W,U,S,R,T Yes 6** sec B (19)
No No HV-57-124 BF Outside 13'-5" Comp air Spring C 0 C C B,H,W,U,S,R,T Yes 5** sec A (19)
Yes Yes HV-57-131 BF Outside 7'-9" Comp air Spring C C C C B,H,W,U,S,R,T NA 5** sec A (23)
Yes Yes HV-57-164 BF Outside 8'-2" AC motor Manual C C 0 As is B,H,R,S NA 6 sec D Yes Yes HV-57-121 BF Outside 69'-11" Comp air Spring C C C C B,H,W,U,S,R,T NA 5** sec A (19), (23)
Yes Yes HV-57-169 BF Outside 9'-6" AC motor Manual C C 0 As is B,H,R,S NA 6 sec D X-201A (Unit 2) Hardened Steam/ 12 56 No No HV-57V-280 BF Outside (7) Yes 13'-2" Comp Air Spring C C C C - NA Standard** N (19), (21)
Containment Non-Cond Gas Vent Steam/ 12 56 No No HV-57V-281 BF Outside (7) Yes 22'-1" Comp Air Spring C C C C - NA Standard** N (19), (21)
Non-Cond Gas X-201B Hardened Steam/20 56 No No HV-57V-180 BF Outside (7) Yes 16'-7" Comp Air Spring C C C C - NA Standard** N (19), (21)
Containment Non-Cond Gas Vent Steam/20 56 No No HV-57V-181 BF Outside (7) Yes 23'-5" Comp Air Spring C C C C - NA Standard** N (19), (21)
Non-Cond Gas X-202 Suppression pool Gas 18 56 Yes No HV-57-112 BF Outside (15) Yes 18'-6" AC motor Manual C 0 0 As is B,H,W,U,S,R,T NA 6** sec A (19) purge exhaust Yes Yes HV-57-185 GB Outside 24'-6" AC coil - 0 0 0 C B,H,R,S NA 2 sec C (19)
Yes Yes HV-57-162 BF Outside 3'-10" AC motor Manual C C 0 As is B,H,R,S NA 6 sec C No No HV-57-105 GB Outside 6'-10" AC motor Manual C C C As is B,H,U,S,R,T Yes 15** sec B (20)
No No HV-57-104 BF Outside 4'-0" Comp air Spring C 0 C C B,H,W,U,S,R,T Yes 5** sec B No No HV-57-118 BF Outside 32'-11" Comp air Spring C C C C B,H,U,S,R,T Yes 5** sec A (19)
Yes Yes HV-57-166 BF Outside 5'-9" AC motor Manual C C 0 As is B,H,R,S NA 6 sec C X-203A-D RHR pump suction Water 24 56 Yes Yes F004A,B,C,D GT Outside (16) No 0" AC motor Manual 0 0 0 As is RM NA Standard A,B,C,D (22)
Yes - F030A,B PSV Outside 46'-6" Water pres - C C C - - - - - (19)
Yes - F030C,D PSV Outside 35'-6" Water pres - C C C - - - - - (19)
X-204A,B RHR pump test Water 6 56 Yes Yes 125A,B GT Outside (36) No 0" AC motor Manual 0 0 0 As is RM NA Standard A,B (22) and min flow X-205A,B Suppression pool Water 6 56 Yes Yes F027A,B GB Outside (43) Yes 0" AC motor Manual 0 0 0 As is C,G NA 30 sec A,B spray X-206A-D CS pump suction Water 16 56 Yes Yes F001A,B,C,D GT Outside (42) No 0" AC motor Manual 0 0 0 As is RM NA Standard A,B (22)
X-207A,B CS pump test Water 10 56 Yes No F015A,B GB Outside (24) No 0" AC motor Manual C C C As is C,G Yes 15 sec A,B (22) and flush X-208B CS pump min flow Water 4 56 Yes Yes F031B GB Outside (24) No 0" AC motor Manual 0 C C As is LFCH NA 30 sec B (22)
X-209 HPCI pump suction Water 16 56 Yes Yes F042 GT Outside (42) No 0" DC motor Manual 0 0 0 As is L,LA NA Standard B (22)
X-210 HPCI turbine Water 12 56 Yes Yes F072 GT Outside (24) No 0" DC motor Manual 0 0 0 As is RM NA Standard B (22) exhaust X-212 HPCI pump test Water 4 56 Yes No F071 GT Outside (24) No 0" DC motor Manual C C C As is B,H Yes Standard B (22) and flush X-214 RCIC pump suction Water 6 56 Yes Yes F031 GT Outside (42) No 0" DC motor Manual C C 0 As is RM NA Standard A (22)
X-215 RCIC turbine Water 8 56 Yes Yes F060 GT Outside (24) No 0" DC motor Manual 0 0 0 As is RM NA Standard A (22) exhaust X-216 RCIC min flow Water 2 56 Yes Yes F019 GB Outside (24) No 0" DC motor Manual C C C As is LFRC NA 8 sec A (22)
X-217 RCIC vacuum Air 2 56 No No F002 SCK Outside (34) No 11" Flow DC motor 0 0 0 - RM No Standard A (14) discharge No No F028 CK Outside 6'-2" Flow - C C C - - - - -
(Unit 1)
X-217 RCIC vacuum Air 2 56 No No F002 SCK Outside (34) No 17" Flow DC motor 0 0 0 - RM No Standard A (14) discharge No No F028 CK Outside 6'-2" Flow - C C C - - - - -
(Unit 2)
X-218 Instrument gas Air 1 56 No No 1001 CK Inside (22) Yes -" Flow - 0 0 C - - - - -
supply No No 135 GB Outside 3" Comp air Manual 0 0 C - C,H,S Yes 4.4 sec B X-219A,B Instrumentation - Water 2 56 - - 120 GB Outside (38) No 0" AC motor Manual 0 0 0 As is RM - 30 sec B suppression - - 121 GB Outside 0" AC motor Manual 0 0 0 As is RM - 30 sec B pool level CHAPTER 06 6.2-135 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
LENGTH OF NRC PIPE FROM PRIMARY NORMAL POWER CONTAINMENT LINE GENERAL VALVE VALVE CONT. TO METHOD OF SECONDARY VALVE SHUTDOWN POST- FAILURE DIVERSE VALVE POWER PENETRATION LINE SIZE DESIGN ESF ESSENTIAL VALVE TYPE VALVE ARRANGEMENT TYPE C OUTSIDE ACTUATION METHOD OF POSITION VALVE ACCIDENT VALVE ISOLATION ISOLATION CLOSURE SOURCE NUMBER ISOLATED FLUID (in) CRITERION SYSTEM SYSTEM NUMBER (1) LOCATION (2) TEST VALVES (3) ACTUATION (4) POSITION POSITION POSITION SIGNAL(5) SIGNAL(12) TIME(6) (7) REMARKS X-220A H2/O2 sample Air 2 56 Yes Yes 190 GB Outside (12) Yes 10'-5" AC coil - 0 0 0 C B,H,R,S NA 2 sec C (19) return; wet-well Yes Yes 191 GB Outside 8'-5" AC coil - 0 0 0 C B,H,R,S NA 2 sec A purge makeup Yes Yes 116 GB Outside 14'-8" AC motor Manual C C C As is B,H,R,S NA 30** sec D Yes Yes 150 GB Outside 247'-9" AC coil - 0 0 0 C B,H,R,S NA 2 sec B Yes Yes 159 GB Outside 255'-3" AC coil - 0 0 0 C B,H,R,S NA 2 sec D X-220B Instrumentation - Air 2 56 - - 101 GB Outside (39) No 0" AC coil - 0 0 0 C RM - 2 sec A suppression pool pressure (Unit 1 only)
X-221A Wetwell H2/O2 Air 1 56 Yes Yes 181 GB Outside (29) Yes 2'-2" AC coil - 0 0 0 C B,H,R,S NA 2 sec B sample Yes Yes 141 GB Outside 3'-11" AC coil - 0 0 0 C B,H,R,S NA 2 sec D Yes Yes 184 GB Outside 3'-11" AC coil - 0 0 0 C B,H,R,S NA 2 sec C X-221B Wetwell H2/O2 Air 1 56 Yes Yes 183 GB Outside (23) Yes 2'-5" AC coil - 0 0 0 C B,H,R,S NA 2 sec A sample Yes Yes 186 GB Outside 3'-5" AC coil - 0 0 0 C B,H,R,S NA 2 sec C X-226A,B RHR min flow Water 4 56 Yes Yes 105A,B GT Outside (35) No 0" AC motor Manual 0 0 0 As is RM NA Standard C,D (22)
X-227 ILRT data Air 3/4 56 No No 1073 GB Outside (31) Yes 18" Manual - C C C - - - - -
acquisition No No 1074 GB Outisde 2'-9" Manual - C C C - - - - -
X-228D HPCI vacuum Air 4 56 Yes Yes F095 GT Outside (17) Yes 0" AC motor Manual 0 0 C As is H,LA NA Standard D (17) relief Yes Yes F093 GT Outside 12'-6" AC motor Manual 0 0 C As is H,LA NA Standard B (17), (19)
X-229A Instrumentation - Air 2 56 - - 201 GB Outside (39) No 0" AC coil - 0 0 0 C RM - 2 sec A suppression pool pressure (Unit 2 only)
X-230B Deactivated Water 1-1/2 56 - - 102 GB Outside (32a) No 3'-0" AC motor Manual C C C As is - - A (18)
Instrumentation - - - 112 GB Outside (32) 4" AC motor Manual 0 0 0 As is RM - 30 sec A drywell sumps - - 132 GB Outside 4" AC motor Manual 0 0 0 As is RM - 30 sec A X-231A,B Drywell sump Water 4 56 No No 110 GT Outside (28) No 0" Comp air Spring 0 C C C B,H Yes 20 sec A drains No No 130 GT Outside 0" Comp air Spring 0 C C C B,H Yes 20 sec A No No 111 GT Outside 3'-5" Comp air Spring C C C C B,H Yes 20 sec B No No 131 GT Outside 3'-5" Comp air Spring C C C C B,H Yes 20 sec B X-235 CS pump min flow Water 4 56 Yes Yes F031A GB Outside (24) No 0" AC motor Manual 0 C C As is LFCH NA 30 sec A (22)
(Unit 1)
X-235 CS pump min flow Water 4 56 Yes Yes F031A GB Outside (24) No 6" AC motor Manual 0 C C As is LFCH NA 30 sec A (Unit 2)
X-236 HPCI pump min flow Water 4 56 Yes Yes F012 GB Outside (24) No 0" DC motor Manual C C C As is LFHP NA 15 sec B (22)
X-237 Suppression pool Water 6 56 No No 127 GT Outside (26) No (U1)12" AC motor Manual C C C As is B,H Yes Standard A clean-up pump (U2)18" suction; level No No 128 GT Outside (U1)15'-11" AC motor Manual C C C As is B,H Yes Standard C (19) instrumentation (U2)16'-5" No - 127 PSV Outside (U1)4'-0" Water pres - C C C - - - - -
(U2)8'-3"
- - HV-139 GB Outside No (U1)4'-11" AC motor Manual 0 0 0 As is RM - 30 sec B (U2)4'-11"
- - SV-139 GB Outside No (U1)3'-7" AC coil - 0 0 0 C RM - 4 sec A (U2)2'-2" X-238 RHR relief valve Water 10 56 Yes - 106B PSV Outside (18) No 38'-4" Water pres - C C C - - - - - (19), (22) discharge (Unit 1) Yes No F104B GB Outside 34'-10" Manual - C C C - - - - - (19), (22)
X-238 RHR relief valve Water 10 56 Yes - 206B PSV Outside (18) No 38'-4" Water pres - C C C - - - - - (19), (22) discharge (Unit 2)
X-239 RHR relief valve Water 10 56 Yes - 106A PSV Outside (18) No 47'-0" Water pres - C C C - - - - - (19), (22) discharge (Unit 1) Yes No F103A GB Outside 36'-3" Manual - C C C - - - - - (19), (22)
X-239 RHR relief valve Water 10 56 Yes - 206A PSV Outside (18) No 47'-0" Water pres - C C C - - - - - (19), (22) discharge (Unit 2) Yes No F203A GB Outside 36'-3" AC motor Manual C C C As is C,G Yes 12 sec A (19), (22)
X-241 RCIC vacuum relief Water 3 56 Yes Yes F084 GT Outside (17) Yes 0" AC motor Manual 0 0 C As is H,KA NA 25 sec A (17)
Yes Yes F080 GT Outside 5'-6" AC motor Manual 0 0 C As is H,KA NA 25 sec B (17)
CHAPTER 06 6.2-136 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
(1) Valve Type:
Ball BL Butterfly BF Check Ck Gate GT Globe GB Pressure relief PSV Stop-check SCK Testable check TCK Spring load piston- SLPACK actuated check Explosive (shear) XP Excessive flow check XFC Ball check BLCK Hydraulic control unit HCU (2) See Figure 6.2-36. Numbers in this column refer to details in the figure.
(3) Ac MOVs required for isolation functions are powered from the ac standby power buses.
Dc operated isolation valves are powered from the station batteries.
(4) Normal valve position (open or closed) is the position during normal power operation of the reactor.
(5) Isolation Signal Codes Signal Description A* Reactor vessel level 3 trip (a scram occurs at this level also)
B* Reactor vessel level 2 trip C* Reactor vessel level 1 trip (main steam line isolation occurs at this level)
D* High radiation in main steam lines and vicinity E* Main steam line high flow Deleted F* High temperature in main steam tunnel or in vicinity of main steam lines in turbine enclosure CHAPTER 06 6.2-137 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
Signal Description G* High drywell pressure and low reactor vessel pressure H* High drywell pressure J* Line break in RWCU system (high differential flow, high temperature in RWCU compartments)
K* Break in RCIC steam line (high temperature in pipe routing area, high temperature or high differential temperature in RCIC compartment, high steam flow), or high RCIC turbine exhaust diaphragm pressure KA Low RCIC steam supply pressure L* Break in HPCI steam line (high temperature in pipe routing area, high temperature or high differential temperature in HPCI compartment, or high steam flow), or high HPCI turbine exhaust diaphragm pressure LA Low HPCI steam supply pressure LFHP With HPCI pumps running, opens on low flow in associated pipe, closes when flow is above setpoint LFRC With RCIC pump running, opens on low flow in associated pipe, closes when flow is above setpoint LFCH With CS pump running, opens on low flow in associated pipe, closes when flow is above setpoint.
LFCC Steam supply valve fully closed or RCIC turbine stop valve fully closed M* Low differential pressure between the instrument gas line and the primary containment P* Low main steam line pressure at inlet to turbine (RUN mode only)
Q* Low condenser vacuum and turbine stop valve in bypass mode or more than 90% open CHAPTER 06 6.2-138 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
Signal Description R* High radioactivity in refueling floor ventilation exhaust ducts S* High radiation in the reactor enclosure T Low differential pressure between the outside atmosphere and the refueling area U Low differential pressure between the outside atmosphere and the reactor enclosure V* High reactor pressure (shutdown cooling mode only)
W* North stack effluent high radiation Y SLCS actuated or RRCS actuated RM* Remote manual switch from control room (all power-operated isolation valves are capable of being operated remote manually from the control room)
- These are the isolation functions of the primary containment and reactor vessel isolation control system; other functions are given for information only.
(6) The standard closing rate for automatic isolation gate valves is based on a nominal line size of 12 inches. Using the standard closing rate, a 12 inch line is isolated in 60 seconds.
Conversion to closing time can be made on this basis using the actual size of the line in which the gate valve is installed.
The closure times for isolation valves in lines in which HELBs could occur are identified with a single asterisk. The closure times for isolation valves in lines which provide an open path from the containment to the environs are identified with a double asterisk. Closure times for the valves identified by a single or double asterisk are considered maximum closure times. Closure times for all other valves are nominal times.
The closure time for F105 is a maximum closure time.
CHAPTER 06 6.2-139 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
(7) Power Source Electrical Separation Source:
A - Class 1E electrical channel B - Class 1E electrical channel C - Class 1E electrical channel D - Class 1E electrical channel W - RPS electrical separation channel X - RPS electrical separation channel Y - RPS electrical separation channel Z - RPS electrical separation channel N - non-Class 1E For explanation of electrical separation channels, refer to Section 8.1.
(8) Deleted (9) The spring-loaded piston, which is actuated by an isolation signal or a loss of power, will not close this valve against normal flow on loss of power from the normal direction.
(10) The TIP drive guide tubes provide a path for the flexible drive cable of the TIP probes. The drive cable is automatically retracted on an isolation signal. When the drive cable is fully retracted, the ball valve closes. The shear valves is provided to isolate the guide tubes by cutting the cable if the drive cable cannot be withdrawn.
(11) The CRD insert and withdraw lines can be isolated outside containment. Upstream of the HCUs, two redundant simple check valves are provided on each main water header (i.e.
charging, cooling, drive and exhaust). Air operated scram inlet and outlet valves are also provided. Leakage may occur through the scram outlet valves. A low leakage flowrate will be treated by the clean radwaste system. Excessive leakage will result in either automatic scram or operator initiated scram. When scram is complete, the SDV system is automatically isolated by the redundant vent and drain valves.
(12) Only nonessential systems require diverse signals for automatic isolation. Therefore, this column is not applicable, (NA), for essential systems.
CHAPTER 06 6.2-140 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
(13) These valves are sealed closed whenever the reactor is critical and reactor pressure is greater then 600 psig. The valves are expected to be opened only in the following instances:
- a. Flushing of the condensate and feedwater systems during plant startup.
- b. RPV hydrostatic testing, which is conducted following each refueling outage prior to commencing plant startup.
(14) Diverse isolation signals are not sensed as discussed in Section 6.2.4.3.1.
(15) These valves are normally closed, will be open only during reactor shutdown, are interlocked to open only on low reactor pressure, and connect to a closed system outside containment. Therefore, closure times less then 60 seconds are not required.
(16) Deleted (17) Both isolation signals required for valve closure.
(18) Valve HV-61-102 is locked closed, the motor operator is normally de-energized and the valve position is controlled procedurally. The valve remains closed during 10 CFR50, Appendix J, Type A testing, and type C testing is not required. Valve HV-61-202 has been deleted from the Unit 2 design.
(19) All outside containment isolation valves have been located as close to containment as practical. Examples of containment isolation valve locations greater than 10 feet from containment are identified and justified below.
- a. Deleted
- b. Valves HV-F032A-B, HV-109A-B, HV-F039, HV-F013, HV-130A-B, HV-F105, HV-133A-B (Penetrations X-9A-B) provide a third isolation barrier for the feedwater lines. These valves are located at distances from the penetration dictated by equipment accessibility considerations.
- c. Valve 1016 (penetrations X-9A-B, X-44) also provides a third isolation barrier for the feedwater lines and an outboard isolation barrier for the alternate RWCU return penetration (X-44). The valve is located in closer proximity to the latter penetration.
CHAPTER 06 6.2-141 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
- d. Valves HV-121 & 131 (penetrations X-25, X-201A) are isolation valves for both drywell and wetwell penetrations. They have been located nearer to one penetration and therefore at some distance from the other.
- e. Relief valves F030A-D (penetrations X-203A-D) are located as close to the RHR pumps as possible in order to perform their intended function of providing overpressure protection for the pumps. These valves are part of a closed system outside containment.
- f. Relief valve 106B and globe valve F104B, (penetration X-238) have been located as close as practical to the RHR heat. Their location is dictated by functionality and pipe stress considerations. Valves 106A and F103A, (penetration X-239) are located similarly.
- g. DELETED
- h. Valves HV-114, HV-115 (penetration X-26) are restricted to their location because of necessary piping interties and for valve accessibility.
- i. Valve 109 (penetration X-25, X-201A) provides the outboard barrier for both the drywell penetration and the wetwell penetration. Physical separation of the penetrations and the resulting piping arrangement prohibits a closer placement to either penetration.
- j. Valves HV-57V-180 and HV-57V-181 (Unit 1 penetration X-201B) are associated with the hardened containment vent and located at distances from the penetration dictated by equipment located in the compartment. Valves HV-57V-280 and HV-57V-281 (Unit 2 penetration X-201A) are associated with the hardened containment vent and located at distances from the penetration dictated by equipment located in the compartment.
(20) Closure times of 6 seconds or less are provided for all isolation valves on the purge lines, with the exception of valves HV-57-105 and HV-57-111. Valves HV-57-105 and HV-57-111 are 2 inch MOVs in the low volume purge lines with closure times of 15 seconds or less.
This closure time has been justified by an analysis of the radiological consequences of a LOCA that occurs during purging, as discussed in Section 9.4.5.1.2.
(21) 124A, 124B, 125A, and 125B (penetrations X-53, X-54, X-55 and X-56) do not receive an automatic isolation signal. Valves HV-57V-180 and HV-57V-181 associated with Unit 1 penetration X-201B also do not receive automatic isolation signals and are not normally powered. Valves HV-57V-280 and HV-57V-281 associated with penetration X-201A (Unit
- 2) also do not receive automatic isolation signals and are not normally powered.These valves are administratively controlled such that these valves are treated as locked closed valves. Therefore, these valves do not have a required closure time.
(22) These lines are below the minimum water level in the suppression pool, the system is a closed system outside primary containment, and will maintain a water seal following an accident. Therefore, 10CFR50 Appendix J, Type C testing is not required.
CHAPTER 06 6.2-142 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-17 (Cont'd)
(23) There are electrical interlocks between HV-057-121 and HV-057-131 and in between HV-057-221 and HV-057-231, which prevent both interlocked valves from being open at the same time. This interlock is consistent with requirements of UFSAR Section 9.4.5.1.2.2 to limit the number of high volume purge lines in use during the operational modes of startup, power operation and hot shutdown to one supply line and one exhaust line.
CHAPTER 06 6.2-143 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-18 ASSUMPTIONS USED IN EVALUATING THE PRODUCTION OF COMBUSTIBLE GASES FOLLOWING A LOCA PARAMETER VALUE Fraction of fission product radiation energy absorbed by the coolant:
Betas from fission products 0.0 in fuel rods Betas from fission products 1.0 mixed with coolant Gammas from fission products 0.1 in fuel rods Gammas from fission products 1.0 mixed with coolant Hydrogen yield rate G(H2) 0.5 molecule/100 eV Oxygen yield rate G(02) 0.25 molecule/100 eV Extent of initial core metal- 0.00023 inch depth into water reaction involving cladding original cladding surrounding the fuel Evolution time of hydrogen 2 minutes produced from metal-water reaction Corrosion rate for zinc and 3.76x10-9 exp(0.0218T) zinc paint lb-moles/ft2-hr (where T = temperature in degrees Fahrenheit)
Fission product distribution model:
Coolant water 1% of solids + 50% of halogens Containment atmosphere 100% of noble gases Fuel rods All other fission products CHAPTER 06 6.2-144 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-19 PARAMETERS USED IN EVALUATING THE PRODUCTION OF HYDROGEN FOLLOWING A LOCA PARAMETER VALUE______
Reactor thermal power: 3,527 MWt (1)
Drywell free volume: 248,700 ft3 Suppression chamber free volume: 149,000 ft3 Zircaloy cladding surrounding active fuel:
Mass 67,700 lb (1)
Surface area 89,210 ft2 (1)
Zinc (as galvanized steel) in drywell:
Mass 1,850 lb Surface area 32,055 ft2 Zinc paint in drywell:
Volume of paint 1.92 ft3 Surface area 7,692 ft2 Zinc content of zinc paint 87%
Zinc paint in suppression chamber:
Volume of paint 39.67 ft3 Surface area 68,000 ft2 Zinc content of zinc paint 87%
Volume of free hydrogen normally 195 ft3 in reactor coolant (at 60oF and atmospheric pressure):
(1)
Reference 6.2-42 accounts for GE3 fuel at 3527 MWt.
CHAPTER 06 6.2-145 REV. 21, SEPTEMBER 2022
LGS UFSAR Table 6.2-20 CONTAINMENT HYDROGEN RECOMBINER SUBSYSTEM FAILURE MODES AND EFFECTS ANALYSIS PLANT OPERATING COMPONENT FAILURE EFFECT OF FAILURE FAILURE MODE EFFECT OF FAILURE MODE SYSTEM COMPONENT MODE ON THE SYSTEM DETECTION ON PLANT OPERATION Emergency (LOCA) Power supply LOOP Loss of both Alarm in the None. The recombiner recombiner packages control room packages are powered from the Class 1E buses. When standby power becomes available, the recombiner packages resume operation.
Emergency (LOCA Power supply Loss of one Class 1E Loss of one Alarm in the None. The redundant or LOCA + LOOP) bus or the associated recombiner package control room recombiner package diesel generator is unaffected and is activated manually by the operator.
Emergency (LOCA Containment isolation Failure of valve to No flow through Flow indication None. The redundant or LOCA + LOOP) valve in one gas reopen after recombiner package and low flow recombiner package inlet or gas outlet containment isolation alarm in the is unaffected line signal is bypassed control room and is activated manually by the operator.
Emergency (LOCA Blower in one Abnormally low blower Insufficient flow Flow indication None. The redundant or LOCA + LOOP) recombiner package speed or complete through recombiner and low flow recombiner package failure to operate package alarm in the is unaffected control room and is activated manually by the operator.
Emergency (LOCA Heater elements or Abnormally low Reaction chamber Alarm in the None. The redundant or LOCA + LOOP) SCRs in one heater output temperature too low control room recombiner package recombiner package for complete is unaffected recombination and is activated manually by the operator.
CHAPTER 06 6.2-146 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-20 (Cont'd)
PLANT OPERATING COMPONENT FAILURE EFFECT OF FAILURE FAILURE MODE EFFECT OF FAILURE MODE SYSTEM COMPONENT MODE ON THE SYSTEM DETECTION ON PLANT OPERATION Emergency (LOCA Water inlet valve in Failure to open Abnormally high Alarm in the None. The redundant or LOCA + LOOP) one recombiner fully return gas control room recombiner package package temperature is unaffected and is activated manually by the operator.
Emergency (LOCA Gas inlet valve in Case 1: Excessive High flow through the Flow indication None. The redundant or LOCA + LOOP) one recombiner valve opening recombiner package, and high recombiner package package with the possibility temperature is unaffected of excessive alarm in the and is activated temperatures in the control room manually by the reaction chamber operator.
Case 2: Insufficient Insufficient flow Flow indication None. The redundant valve opening through the and low flow recombiner package recombiner package alarm in the is unaffected control room and is activated manually by the operator.
CHAPTER 06 6.2-147 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-21 COMBUSTIBLE GAS ANALYZER SUBSYSTEM FAILURE MODES AND EFFECTS ANALYSIS PLANT OPERATING SYSTEM COMPONENT FAILURE EFFECT OF FAILURE FAILURE MODE EFFECT OF FAILURE ON MODE COMPONENT MODE ON THE SYSTEM DETECTION PLANT OPERATION Normal or Power supply LOOP Closure of Alarm in the None. The analyzer Emergency containment control room packages are powered isolation valves from the Class 1E on all sample buses. When standby lines. Loss of power becomes available, both analyzer the containment isolation packages. valves reopen and the analyzer packages resume operation.
Normal or 480V Fuses Loss of one fuse. A/B phase fuse failure A/B phase fuse None. The redundant analyzer Emergency would cause loss of failure would package is unaffected and one analyzer package. cause alarm in continues to operate.
C phase fuse failure the control room.
would cause pump not C phase fuse failure to start and analyzer would be detected package would not be upon use or during able to perform function. testing every month.
Emergency Power supply Loss of one Class 1E Loss of one Alarm in the None. The redundant analyzer (LOCA or bus or the analyzer control room package is unaffected and LOCA + LOOP) associated diesel package. continues to operate.
Generator. Closure of containment isolation valves on associated sample lines.
Emergency Sample pump Failure of the Loss of sample Alarm in the None. The redundant analyzer (LOCA or in one analyzer operating pump. flow through control room package is unaffected and LOCA + LOOP) package. the affected continues to operate.
analyzer package.
Emergency Hydrogen analyzer Analyzer cell Incorrect hydrogen Alarm in the None. The redundant analyzer (LOCA or cell in one analyzer failure. concentration control room package is unaffected and LOCA + LOOP) package, for the affected continues to operate.
analyzer package.
Emergency Oxygen analyzer Analyzer cell. Incorrect oxygen Alarm in the None. The redundant analyzer (LOCA or cell in one failure. concentration control room package is unaffected and LOCA + LOOP) analyzer package. for the affected continues to operate.
analyzer package.
CHAPTER 06 6.2-148 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-21 (Cont'd)
PLANT OPERATING SYSTEM COMPONENT FAILURE EFFECT OF FAILURE FAILURE MODE EFFECT OF FAILURE ON MODE COMPONENT MODE ON THE SYSTEM DETECTION PLANT OPERATION Emergency Sample line Failure of one Case A, a sample Case A: alarm None. The redundant analyzer (LOCA or containment valve to reopen suction line: inability in the control package is unaffected and LOCA + LOOP) isolation when containment to draw sample through room due to continues to operate.
valves. isolation signal affected line only. low flow is bypassed. when the affected line is selected.
Case B, a sample Case B: alarm return line: blockage in the control of all flow through room due to affected analyzer low flow package. Immediately.
Emergency Sample line Failure of one Reduction in Indicating None. The redundant valve (LOCA or containment valve to close containment isolation lights in the provides isolation.
LOCA + LOOP) isolation when containment barriers from two valves control room.
valves. isolation signal to one valve in the is received. affected line.
Normal or Other electrical Open circuits and Loss of functions Depending on failed None. The redundant analyzer Emergency components and shorted circuits or loss associated with component alarm package is unaffected and cables. of input / output due to failure of specific indication in control continues to operate.
various failure component (indication, room or failure will mechanisms or errors. alarms, controls, etc. be self-revealing.
Normal or MCR Signal Failure to provide Unable to obtain Depending on failed None. The redundant analyzer Emergency Conditioner and indication or control Combustible gas component alarm package is unaffected and PLC Assembly function. concentration readings. indication in control continues to operate.
room or failure will be self-revealing.
CHAPTER 06 6.2-149 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-22 The information in this table has been deleted CHAPTER 06 6.2-150 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-23 The information in this table has been deleted CHAPTER 06 6.2-151 REV. 13, SEPTEMBER 2006
LGS UFSAR Table 6.2-24 SYSTEM VENTING AND DRAINING EXCEPTIONS FOR PRIMARY CONTAINMENT INTEGRATED LEAKAGE RATE TEST I. The drywell chilled water system, located inside the primary containment, is required to maintain the plant in a stabilized condition during the Type A test and is not vented and operates in its normal mode.
II. Portions of systems that are normally filled with water and operating under post-LOCA conditions are not specifically vented to the containment atmosphere or to the outside atmosphere. They remain water-filled during the Type A test. These systems are listed below. (Note: Venting to the primary containment atmosphere does occur for these systems, since the reactor vessel is vented to the primary containment atmosphere and/or system penetrations are open to the suppression pool or containment atmospheres.)
III. For planning and scheduling purposes, or ALARA considerations, pathways that are Type B or C tested within the previous 24 calendar months need not be vented or drained during the Type A test.
System RCIC RHR CS HPCI CHAPTER 06 6.2-152 REV. 16, SEPTEMBER 2012
LGS UFSAR Table 6.2-25 CONTAINMENT PENETRATIONS COMPLIANCE WITH 10CFR50, APPENDIX J INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE
- Drywell head flange M-60 B Double O-Ring - 2 1 Equipment access door M-60 B Double O-Ring - 2 2 Equipment access door M-60 B Double O-Ring - 2 and personnel lock 3A Instrumentation - main M-41 A - XFC-F070D 1 steam line D flow XFC-F073D 3A Instrumentation - recirculation M-43 A - XFC-F003A 1 pump seal pressure 3B Instrument gas supply M-59 C CK-1005B HV-129B -
3C Instrumentation - HPCI M-55 A - XFC-F024A 1 steam flow 3C Instrumentation - HPCI M-55 A - XFC-F024C 1 steam flow 3D Instrumentation - main M-41 A - XFC-F070A 1 steam line A flow XFC-F073A 3D Instrument gas supply M-59 C CK-1112 MO-151B -
4 Head access manhole M-60 B Double O-Ring - 2 5 Spare - A - - -
6 CRD removal hatch M-60 B Double O-Ring - 2 7A-D Primary steam M-41 C AO-F022A-D AO-F028A-D 6 8 Primary steam line drain M-41 C MO-F016 MO-F019 4 CHAPTER 06 6.2-153 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 9A,B Feedwater M-41 C CK-F010A,B CK-F074A,B 7(MO-F105 CK-F032A,B only),
MO-109A,B 18, 24 CK-F039 MO-F013 MO-F105 CK-1036A,B MO-130A,B MO-133A,B 1016 10 Steam to RCIC turbine M-49 C MO-F007 MO-F008 5 MO-F076 11 Steam to HPCI turbine M-55 C MO-F002 MO-F003 5 MO-F100 12 RHR shutdown cooling supply M-51 C MO-F008 Closed system 33 13A,B RHR shutdown return M-51 C MO-F015A,B Closed system 33 14 RWCU supply M-44 C MO-F001 MO-F004 -
15 Spare - A - - -
16A CS pump discharge M-52 C MO-F005 Closed system 33 16B CS pump discharge M-52 C CK-108 Closed system 33 17 RPV head spray (Unit 1 only) M-51 A Welded Plate -
(ABANDONED) 17 Spare (Unit 2 only) M-51 A - - -
18 Spare - A - - -
19 Spare - A - - -
CHAPTER 06 6.2-154 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 20A Instrumentation - RPV level M-42 A - XFC-F045B 1 20A Instrumentation - LPCI P M-51 A - XFC-102B 1 20A Instrumentation - LPCI P M-51 A - XFC-103B 1 20B Instrumentation - RPV level M-42 A - XFC-F045C 1 20B Instrumentation - LPCI P M-51 A - XFC-102C 1 21 Service air M-15 C 1140 1139 -
22 Instrumentation - drywell M-42 A - MO-147C 11 pressure 23 Closed cooling water supply M-13 C MO-106 MO-108 12 MO-109 24 Closed cooling water return M-13 C MO-107 MO-111 12 MO-110 25 Drywell purge supply M-57 C AO-121 MO-109 3, 12, 25 B MO-163 FV-DO-101B AO-123 AO-131 Double O-Ring MO-135 Seal Assembly (3) 26 Drywell purge exhaust M-57 C SV-139 SV-145 3, 1 (SV-139 only)
B MO-161 FV-DO-101A 12, 25 MO-111 AO-117 AO-114 MO-115 Double O-Ring Seal Assembly (2) 27A Instrument gas supply M-59 C CK-1128 MO-151A -
27B Instrumentation - HPCI flow M-55 A - XFC-F024B 1 27B Instrumentation - HPCI flow M-55 A - XFC-FO24D 1 28A Recirc loop sample M-43 C AO-F019 AO-F020 -
CHAPTER 06 6.2-155 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 28A Drywell H2/O2 sample M-57 C SV-134 SV-144 12 28A Drywell H2/O2 sample M-57 C SV-132 SV-142 12 28B Drywell H2/O2 sample M-57 C SV-133 SV-143 12 SV-195 28B Spare - A - - -
29A Instrumentation - RPV M-41 A - XFC-F009 1, 28 flange leakage 29B Instrumentation - CS P M-52 A - XFC-F018A 1 30A Instrumentation - main M-41 A - XFC-F071D 1 steam line D flow XFC-F072D 30B Instrumentation - drywell M-42 A - MO-147A 11 pressure 30B Instrumentation - main M-41 A - XFC-F071C 1 steam line C flow XFC-F072C 31 Instrumentation - jet M-42 A - XFC-F059B,D,F,H 1 A,B pump flow XFC-F051B XFC-F053B 32 Instrumentation - jet M-42 A - XFC-F059M,P,S,U 1 A,B pump flow XFC-F051D XFC-F053D 33A Instrumentation - pressure M-42 A - XFC-F055 1 above core plate XFC-F076 33A Instrumentation - pressure M-42 A - XFC-F061 1 below core plate 33B Instrumentation - RCIC M-49 A - XFC-FO44A,C 1 steam flow 34A Instrumentation - main M-41 A - XFC-F070C 1 steam line C flow XFC-F073C CHAPTER 06 6.2-156 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 34B Instrumentation - recirculation M-43 A - XFC-F009C,D 1 flow XFC-F010C,D 35A Spare - A - - -
35B Instrument gas to TIP M-59 C CK-1056 AO-131 27 indexing mechanisms B Double O-Ring Seal 35C-G TIP drives M-59 C XV-141A-E XV-140A-E 12, 20, 27 B Double O-Ring Seal (5) 36 Spare - A - - -
37A-D CRD insert M-47 A Ball check - -
C - CK46-1101 13,15 CK46-1102 CK46-1108 CK46-1109 38A-D CRD withdraw M-47 C - CK46-1115 13,15 CK46-1116 CK46-1122 CK46-1123 C F010, F011 F180, F181 39A,B Drywell spray M-51 C MO-F021 A,B Closed system 4, 12, 33 40A Instrumentation - jet M-42 A - XFC-F059L,N,R 1 pump flow 40B Instrumentation - jet M-42 A - XFC-F059G 1 pump flow XFC-F051A XFC-F053A 40C Instrumentation - jet M-42 A - XFC-F059A,C,E 1 pump flow 40D Instrumentation - pressure M-42 A - XFC-F057 1 below core plate 40D Instrumentation - bottom M-44 A - XFC-170 1 drain flow XFC-171 40E Instrumentation - drywell M-42 A - MO-147D 11 pressure CHAPTER 06 6.2-157 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 40F Instrumentation - RCIC M-49 A - XFC-F044B,D 1 steam flow 40F Instrument gas suction M-59 C MO-101 AO-102 5 40G ILRT data acquisition system M-60 C 1057 1058 12, 30 40G ILRT data acquisition system M-60 C 1071 1070 12, 30 40H Instrument gas supply M-59 C CK-1005A AO-129A -
40H Instrumentation - recirculation M-87 A - XFC-156B 21 pump cooler flow XFC-157B 41 Instrumentation - RWCU flow M-44 A - XFC-102A,B 1 41 Instrumentation - LPCI P M-51 A - XFC-103A 1 42 SLCS M-48 C CK-F007 MO-F006A -
43A Instrumentation - recirculation M-43 A - XFC-F040A,C 1 loop A P; 43B Main steam sample M-41 C AO-F084 AO-F085 -
44 RWCU alternate return M-41 C 1017 1016 5, 24 PSV-112 45A-D LPCI M-51 C MO-F017A-D Closed system 33 46 Spare - A - - -
47 Instrumentation - RWCU flow M-44 A - XFC-102D 1 48A Instrumentation - RPV level M-42 A - XFC-F065B 1 XFC-F047B 48A Instrumentation - CS P M-52 A - XFC-F018B 1 CHAPTER 06 6.2-158 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 48B Instrumentation - RPV level M-42 A - XFC-F065A 1 XFC-F047A 49A,B Instrumentation - main M-41 A - XFC-F071A,B 1 steam line A & B flow XFC-F072A,B 50A Instrumentation - drywell M-42 A - MO-147B 11 pressure 50A Instrumentation - recirculation M-43 A - XFC-F011A,B 1 flow XFC-F012A,B 50B Instrumentation - recirculation M-43 A - XFC-F004A 1 pump seal pressure 50B Instrumentation - recirculation M-87 A - XFC-156A 21 pump cooler flow XFC-157A 51A Instrumentation - recirculation M-43 A - XFC-F009A,B 1 line flow XFC-F010A,B 51B Instrumentation - jet M-42 A - XFC-F059T 1 pump flow XFC-F051C XFC-F053C 52A Instrumentation - main M-41 A - XFC-F070B 1 steam line B flow XFC-F073B 52B Instrumentation - recirculation M-43 A - XFC-F011C,D 1 line flow XFC-F012C,D 53 Drywell chilled water supply M-87 C MO-128 MO120A, 12 MO125A 54 Drywell chilled water return M-87 C MO-129 MO121A, 12 MO124A 55 Drywell chilled water supply M-87 C MO-122 MO120B, 12 MO125B 56 Drywell chilled water return M-87 C MO-123 MO121B, MO124B 12 CHAPTER 06 6.2-159 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 57 Instrumentation - RWCU flow M-44 A - XFC-102C 1 58A Instrumentation - recirculation M-43 A - XFC-F040B 1 loop B P 58B Spare - A - - -
59A,B Spare - A - - -
60 Spare - A - - -
61 Recirculation pump seal purge M-43 C CK-1004A, B XFC-103A,B 1, 19 62 H2/O2 sample return M-57 C SV-150 MO-116 12 SV-159 SV-190 SV-191 63 Instrumentation - recirculation M-43 A - XFC-F003B 1 loop P; recirc pump XFC-F004B Seal pressure XFC-F040D 64 Spare - A - - -
65A,B Instrumentation - RPV M-42 A - XFC-F043B 1 pressure XFC-F049A 66A Instrumentation - RPV level M-42 A - XFC-F045D 1 66A Instrumentation - LPCI M-51 A - XFC-102D 1 P XFC-103D 66B Instrumentation - RPV level M-42 A - XFC-F045A 1 66B Instrumentation - LPCI M-51 A - XFC-102A 1 P XFC-103C 67A,B Instrumentation - RPV level; M-42 A - XFC-F041 1 RPV pressure XFC-F043A XFC-F049B CHAPTER 06 6.2-160 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 100 Neutron monitoring system M-60 B Canister - 8 A-D 101 Recirculation pump power M-60 B Canister - 8 A-D 102A Instrumentation - Jet pump flow M-42 A - XFC-185A 1 102B Electrical spare - A - - -
103A,B Temperature and low level M-60 B Canister - 8 signals 104 CRD position indicator M-60 B Canister - 8 A-D 105 Miscellaneous low voltage M-60 B Canister - 8 A-E power 106 Low voltage control M-60 B Canister - 8 A-C 107 Instrumentation - Jet pump flow M-42 A - XFC-185B 1 108 Electrical spare - A - - -
109 Electrical spare - A - - -
110 Electrical spare - A - - -
111 Electrical spare - A - - -
112 Electrical spare - A - - -
113 Electrical spare - A - - -
114 Electrical spare - A - - -
115 Electrical spare - A - - -
116 SLCS M-48 C CK-F007 MO-F006B -
CHAPTER 06 6.2-161 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 117A Electrical spare - A - - -
117B Drywell radiation monitoring M-26 C SV 190-A SV 190-B 12 supply and return SV 190-C SV 190-D 118 Electrical spare - A - - -
A,B 200 Access hatch M-60 B Double O-Ring - 2 A,B 201A Suppression pool purge M-57 C AO-131 AO-121 3, 12, 25 supply B MO-164 MO-169 AO-124 MO-147 Double O-Ring MO-109 Seal Assembly (3) 201A Hardened containment vent (Unit 2) M-57 C AO-280 AO-281 3, 12, 25 B Double O-Ring Seal Assembly (3) 201B Hardened containment vent (Unit 1) M-57 C AO-180 AO-181 3, 12, 25 B Double O-Ring Seal Assembly (2) 202 Suppression pool purge M-57 C MO-162 MO-166 3, 5 Exhaust B MO-105 AO-118 (MO-105)
AO-104 SV-185 (Unit 1 Double O-Ring MO-112 only),
Seal Assembly (2) 12, 25 203 RHR pump suction M-51 A Water seal MO-F004A-D 14 A-D PSV-F030A-D 204 RHR pump test line M-51 A Water seal MO-125A,B 14 A,B and containment cooling 205 Suppression pool spray M-51 C - MO-F027A,B 10, 12 A,B 206 CS pump suction M-52 A Water seal MO-F001A-D 14 A-D 207 CS pump test and flush M-52 A Water seal MO-F015A,B 14 A,B CHAPTER 06 6.2-162 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 208A Spare - A - - -
208B CS pump minimum recirc M-52 A Water seal MO-F031B 14 209 HPCI pump suction M-55 A Water seal MO-F042 14 210 HPCI turbine exhaust M-55 A Water seal MO-F072 14 211 Spare - A - - -
212 HPCI pump test and flush M-55 A Water seal MO-F071 14 213 Spare - A - - -
214 RCIC pump suction M-49 A Water seal MO-F031 14 215 RCIC turbine exhaust M-49 A Water seal MO-F060 14 216 RCIC minimum flow M-49 A Water seal MO-F019 14 217 RCIC vacuum pump discharge M-49 A MO-F002 CK-F028 34 218 Instrument - gas to M-59 C CK-1001 AO-135 -
vacuum relief valves 219 Instrumentation - M-55 A - MO-120 11 A,B suppression pool level MO-121 MO-126 31 220A H2/O2 sample return M-57 C SV-191 SV-190 12 MO-116 SV-150 SV-159 220B Instrumentation - M-57 A - SV-101 11 suppression pool pressure; suppression pool level (Unit 1 only) 220B Spare (Unit 2 only) - A - - -
221A Wetwell H2/O2 sample M-57 C SV-181 SV-141 12 SV-184 CHAPTER 06 6.2-163 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 221B Wetwell H2/O2 sample M-57 C SV-183 SV-186 12 222 Indication and control M-60 B Canister - 8 223 Spare - A - - -
224 Spare - A - - -
225 Spare M-51 A - - 2 (Unit 2 Only) 226A,B RHR minimum recirc M-51 A Water seal MO-105A,B 14 227 ILRT data acquisition system M-60 C 1073 1074 12 228A,B Spare - A - - -
228C Spare - A - - -
228D HPCI vacuum relief M-55 C MO-F095 MO-F093 4, 12 229A Spare (Unit 1 only) - A - - -
229A Instrumentation - suppression M-57 A - SV-201 11 pool pressure; suppression pool level (Unit 2 only) 229B Spare - A - - -
230A Strain gauge instrumentation - B Canister - 8 230B Instrumentation - drywell M-61 A - MO-102 29 sump level MO-112 MO-132 231A Drywell sump drains M-61 A AO-110 AO-111 12, 34 231B Drywell sump drains M-61 A AO-130 AO-131 12, 34 232 MSRV discharge M-41 - - - 16 A-S CHAPTER 06 6.2-164 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
INBOARD OUTBOARD ISOLATION BARRIER ISOLATION BARRIER PENETRATION TEST DESCRIPTION/ INSTRUMENT/
NUMBER SYSTEM DRAWING(17) TYPE VALVE NUMBER VALVE NUMBER NOTE 235 CS pump minimum recirc M-52 A Water Seal MO-F031A 14 236 HPCI pump minimum recirc M-55 A Water Seal MO-F012 14 237 Suppression pool cleanup M-52 A MO-127 MO-128 12, 34 pump suction PSV-127 237 Level instrumentation M-52 A - SV-139 11 MO-139 238 RHR relief valve discharge M-51 A Water Seal PSV-106B 14, 23 MO-F104B Double O-ring Seal Assembly (4) 239 RHR relief valve discharge M-51 A Water Seal MO-F103A 14, 23 PSV-106A Double O-ring Seal Assembly (4) 240 RHR relief valve discharge M-51 A Water Seal Double O-ring 32 Seal Assembly (3) 241 RCIC vacuum relief M-49 C MO-F084 MO-F080 4, 12 NOTES
- 1. Seismic Category I, Quality Group A instrument line with an orifice and excess flow check valve or remote manual isolation valve. The excess flow check valve is subjected to operability testing except as discussed in Note 28, but no Type C test is performed or required. The line does not isolate during a LOCA and can leak only if the line or instrument should rupture. Leak-tightness of the line is verified during the integrated leak rate test (Type A test) by conducting the test with these valves open.
- 2. Penetration is sealed by a blind flange or door with double O-ring seals. These seals are leakage rate tested by pressurizing between the O-rings. For more detail, see Section 6.2.6.2.
- 3. Inboard butterfly valve installed such that testing in the reverse direction is equivalent to testing in the forward direction.
- 4. Inboard gate valve tested in the reverse direction. Valve seating forces are greater than unseating forces due to post-LOCA containment pressure by at least a factor of 3.
- 5. Inboard globe valve installed such that testing in the reverse direction is conservative.
- 6. The primary steam penetrations are tested by pressurizing between the valves. Testing of the inboard MSIV in the reverse direction tends to unseat the valve and is therefore conservative. The valves are Type C tested at a test pressure of 22 psig.
- 7. Gate valve tested in the reverse direction. Valve seating forces are greater than unseating forces due to post-LOCA containment pressure by at least a factor of 3.
- 8. Electrical penetrations are tested by pressurizing between the seals CHAPTER 06 6.2-165 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
- 9. The isolation provisions for this penetration consist of two isolation valves and a closed system outside containment. Because a water seal is maintained in these lines by the safeguard piping fill system, the inboard valve may be tested with water. The outboard valve will be pneumatically tested.
- 10. The isolation provisions for this line consist of one isolation valve outside containment and a closed system outside containment. A single active failure can be accommodated. The closed system is missile-protected, seismic Category I, quality group B and designed to the temperature and pressure conditions that the system will encounter post-LOCA.
System leakage will be minimized in accordance with NUREG-0737, Item III.D.1.1. Any leakage out of the closed system will be into the reactor enclosure, thus facilitating collection and treatment.
- 11. The valve does not receive an isolation signal but remains open to measure containment conditions post-LOCA. Leak-tightness of the penetration is verified during the Type A test by conducting the test with these valves open.
- 12. All isolation barriers are located outside containment.
- 13. Isolation provisions for the CRD insert and withdrawal lines are described in Section 6.2.4.3.1.2.3. The SDV vent and drain valves are Type C tested. Redundant check valves are provided on each main water header (i.e. charging, cooling, drive and exhaust). These valves are Type C tested with water.
- 14. The isolation provisions for this line consist of a suppression pool water seal, at least one isolation valve outside containment, and a closed system outside containment. The isolation valve is not exposed to the primary containment atmosphere because the line terminates below the minimum water level of the suppression pool. The closed system is missile-protected, seismic Category I, quality group B, and designed to the temperature and pressure conditions that the system will encounter post-LOCA.
Because these valves will remain water covered following a LOCA, 10CFR50 Appendix J, Type C testing is not required. System leakage is minimized in accordance with NUREG-0737, Item III.D.1.1. Any leakage out of the closed system will be into the reactor enclosure, thus facilitating collection and treatment.
- 15. The isolation barrier remains water-filled post-LOCA and may be tested with water.
- 16. These lines penetrate the diaphragm slab and are not subject to Appendix J leakage rate testing.
- 17. Table 1.8-2 contains a cross-reference to figure numbers.
- 18. Feedwater penetrations will remain water-filled post-LOCA as described in Section 6.2.3.2.3.
- 19. Check valve used instead of flow orifice.
- 20. The ball valves (XV-141A-E) are Type C tested. It is not practical to leak test the shear valves (XV-140A-E) because squib detonation is required for closure; however, the following tests will be conducted to ensure that these valves will perform their intended function:
- a. The continuity of the explosive charge will be verified at least once per 31 days.
- b. One of the squib charges will be initiated at least once per 24 months. The replacement charge for the shear valve will be from the same manufacturing batch as the one fired, or from another batch that has been certified by having one sample from that batch successfully fired.
In addition, all charges will be replaced at the manufacturer's recommended intervals. These requirements will be incorporated into the plant administrative procedures and surveillance test procedures.
- 21. Seismic Category I, Quality Group B instrument line with an excess flow check valve. Because the instrument line is connected to a closed cooling water system inside containment, no flow orifice is provided. The excess flow check valve is subject to operability testing, but no Type C test is performed or required. The line does not isolate during a LOCA and can leak only if the line or instrument should rupture. Leak-tightness of the line is verified during the integrated leak rate test (Type A test) by conducting the test with these valves open.
- 22. Deleted CHAPTER 06 6.2-166 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-25 (Cont'd)
- 23. The RHR system safety pressure relief valves will be exempted from the initial LLRT. The relief valves in these lines will be exposed to containment pressure during the initial ILRT and all subsequent ILRTs. In addition, modifications will be performed at the first refueling to facilitate local testing or removal and bench testing of the relief valves during subsequent LLRTs. Justification for exclusion from separate testing of these valves as part of the initial LLRT program is based on the substantial containment isolation barriers provided by the design of the relief valves and the RHR system:
- a. The relief valves are maintained normally closed by their springs.
- b. The relief valves are oriented such that containment pressure would tend to seat the valve disc and enhance sealing.
- c. The relief valves are not exposed to the primary containment atmosphere because the lines terminate below the minimum water level of the suppression pool.
- d. The lines outside containment are part of a closed system which is missile-protected, Seismic Category I, quality group B, and designed to the temperature and pressure conditions that the system will encounter.
- e. System leakage will be minimized in accordance with NUREG-0737 Item III.D.1.1.
- f. Any leakage out of the system will be into the reactor enclosure, thus facilitating collection and treatment.
- g. Those relief valves that are flanged to facilitate removal will be equipped with double O-ring seal assemblies on the flange closest to primary containment.
- 24. Valve 41-1016 is an outboard isolation barrier for penetrations X-9A, B and X-44. Leakage through valve 41-1016 is included in the total for penetration X-44 only.
- 25. Butterfly valves are flanged. Those that serve as inboard isolation valves are equipped with double O-ring seal assemblies on the flange closest to primary containment.
These seals are leak rate tested by pressurizing between the O-rings.
- 26. Relief valves PSV-51-1F030A, B, and C are flanged to facilitate removal and ISI testing. PSV-51-1F030D will be flanged prior to the end of the first refueling outage. In all cases, the flanges closest to primary containment will be equipped with double O-ring seal assemblies prior to the end of the first refueling outage. The seals will be leak rate tested by pressurizing between the O-rings. In the interim, the flanged valves are equipped with gasketed connections. The connections are exposed to suppression pool water and are tested during the integrated leak rate test. In addition, they are inspected as part of the system leakage reduction program (Section 6.2.8).
- 27. Penetration is sealed by a flange with double O-ring seals. Both the TIP purge supply (Penetration X-35B) and the TIP drive tubes (Penetration X-35C through G) are welded to their respective flanges. The seals are leak rate tested by pressurizing between the O-rings.
- 28. The reactor vessel head seal leak detection line (Penetration X-29A) excess flow check valve is not subject to operability testing. This valve will not be exposed to primary system pressure except under the unlikely conditions of a seal failure where it could be partially pressurized by reactor pressure. Any leakage path is restricted at the source; therefore, this valve need not be operability tested.
- 29. Valve HV-61-102 is locked closed, the motor operator is normally de-energized and the valve position is controlled procedurally. The valve remains closed during 10 CFR 50, Appendix J Type A testing, and Type C testing is not required. Valve HV-61-202 has been deleted from the Unit 2 design.
- 30. Inboard valve will be tested from the containment side using a temporary test connection at the open pipe end inside the drywell.
- 31. Valve HV-55-126 has been used for Unit 1 only.
- 32. The isolation provisions for this line consist of a suppression pool water seal, blind flange, and a closed system outside containment. The flange is not exposed to the primary containment atmosphere because the line terminates below the minimum water level in the suppression pool. The line is not used to support the system's functions.
Because the line will maintain a water seal following a LOCA, 10 CFR 50 Appendix J, Type B testing is not required.
- 33. The isolation provisions for this line consist of one isolation valve outside containment and a closed system outside containment. A single active failure can be accommodated. The closed system does not communicate with the outside atmosphere, meets Seismic Category I and Safety Class 2 design requirements, designed to temperature and pressure conditions that the system will encounter post-LOCA, is protected from a HELB, is missile-protected, and is capable of being leak tested.
- 34. Type C testing of these valves is not required. A water seal for these lines will be maintained for 30 days.
CHAPTER 06 6.2-167 REV. 19, SEPTEMBER 2018
LGS UFSAR Table 6.2-26 REMOTELY ACTUATED VALVES REQUIRED FOR POSTACCIDENT SYSTEM ISOLATION(1)
Normal Boundary Valve Postaccident Actuation System Valve Location Position(2) Position(3) Signal(4)
HPCI HV-F008 HPCI to CST (Test Bypass) Closed Closed B, H HV-F011 HPCI/RCIC Test Return to CST Closed Closed B, H, IA HV-F025 HPCI Vacuum Tank Drain Open Closed IB HV-F026 HPCI Vacuum Tank Drain Closed Closed IB HV-F028 HPCI Steam Line Drain Open Closed IB HV-F029 HPCI Steam Line Drain Open Closed IB RCIC HV-F004 RCIC Vacuum Tank Drain Closed Closed IC HV-F005 RCIC Vacuum Tank Drain Open Closed IC HV-F022 RCIC to CST (Test Bypass) Closed Closed B, ID HV-F025 RCIC Steam Line Drain Open Closed 1C HV-F026 RCIC Steam Line Drain Open Closed IC RHR HV-F040 RHR to Liquid Radwaste Closed Closed H, A HV-F049 RHR to Liquid Radwaste Closed Closed H, A CHAPTER 06 6.2-168 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-26 (Cont'd)
Normal Boundary Valve Postaccident Actuation System Valve Location Position(2) Position(3) Signal(4) (6)
RHR HV-F079A, B RHR Sample Isolation Closed Closed H, A HV-F080A, B RHR Sample Isolation Closed Closed H, A Containment HV-116 Nitrogen Purge Supply Closed Closed B, H Atmospheric Control Reactor HV-030/031 Drywell Purge Exhaust Closed Closed B, H, R, T Enclosure HVAC HV-107/108 Reactor Enclosure Air Supply Open Closed B, H, R, T HV-117/118 Refueling Floor Air Supply Open Closed R, T HV-141/142 Reactor Enclosure Equipment Open Closed B, H, R, T Comp. Exhaust HV-157/158 Reactor Enclosure Exhaust Open Closed B, H, R, T HV-167/168 Refueling Floor Exhaust Open Closed R, T CRD Scram XV-F010 Scram Discharge Piping Vent Open Closed RPS Discharge XV-F180 Scram Discharge Piping Vent Open Closed RPS XV-F011 Scram Discharge Piping Drain Open Closed RPS XV-F181 Scram Discharge Piping Drain Open Closed RPS CHAPTER 06 6.2-169 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-26 (Cont'd)
(1)
Closure of these valves establishes a redundant boundary for potentially contaminated systems. Containment isolation valves that also provide system isolation are not included in this table (see Table 6.2-17). Where Unit 1 valves are listed, the design is typical for Unit 2.
(2)
Normal valve position (open or closed) is the position during normal power operation of the reactor.
(3)
Postaccident position is the required position of the valve during DBA conditions.
(4)
Actuation signal codes Signal Description A Reactor vessel level 3 trip (a scram occurs at this level also)
B Reactor vessel level 2 trip C Reactor vessel level 1 trip (main steam line isolation occurs at this level)
G High drywell pressure and low reactor vessel pressure H High drywell pressure IA Interlocked to close when any of the HPCI (F041) or RCIC suppression pool suction valves (HV49-F029 or HV49-F031) open IB Interlocked to close when the HPCI turbine steam supply isolation valve (F001) opens IC Interlocked to close when the RCIC turbine steam supply isolation valve (F045) opens ID Interlocked to close when the RCIC suppression pool suction valves (F029 or F031) open R High radioactivity in reactor enclosure or refueling floor ventilation exhaust ducts, as applicable T Low differential pressure between the outside atmosphere and either the secondary containment or refueling area, as applicable RPS Reactor Protection System Scram Signal (5)
DELETED (6)
With the Reactor Enclosure Secondary Containment Zones I or II interlocked with Refuel Area Secondary Containment Zone III, The Reactor Enclosure HVAC valve isolation signals are combined for all associated valves as follows: B, H, R, T. In addition, the same valves isolate on RE Vent. Exh. High Rad (S) and Outside Atmos. to RE - Low DP (U).
CHAPTER 06 6.2-170 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-27 ESSENTIAL/NONESSENTIAL SYSTEMS ESSENTIAL COMMENTS SLCS Yes Should be available as backup to CRD system.
LPCI Yes Safety System HPCI Yes Safety System Core Spray Yes Safety System Service Water No Not required for shutdown.
CAC Yes Combustible gas control function necessary to monitor and control containment hydrogen/oxygen levels.
ADS Yes Safety System/control RPV pressure SGTS Yes Necessary to control emissions to environment.
RECW No Not required for DBA, but necessary for the recirculation cleanup system operation and fuel pool heat exchangers.
RCIC Yes Necessary for core cooldown following isolation from the turbine condenser and feedwater makeup.
ESW Yes Necessary to remove heat following accident. Includes the UHS.
RHRSW Yes Necessary to remove heat following accident. Includes the UHS.
PCIG No Not required for shutdown.
Compressed Air No Not required for shutdown.
Main Steam No Not required for shutdown.
Feedwater Line No Not required for shutdown, except for the portion to which the RCIC and HPCI systems connects.
Sampling Systems No Not required for shutdown. Some sampling capability will be provided for postaccident assessment in accordance with NUREG-0737 Item II.B.3.
CHAPTER 06 6.2-171 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-27 (Cont'd)
ESSENTIAL COMMENTS CRD System Yes Parts of system are necessary for reactor shutdown.
RWCU No Not required for shutdown.
Radwaste Collection No Not required for shutdown.
Recirculation System No Not required for shutdown.
RHR Heat Exchangers Yes Main heat sink during isolation.
RHR Shutdown Cooling Yes Not essential, but desirable to use if available.
Not redundant, but safety-grade.
RHR Containment/Suppression Spray Yes Necessary to control pressure.
RHR - Suppression Pool Cooling Yes Main heat sink during isolation.
Drywell Chilled Water No Not required for shutdown, but desirable to keep running.
Clarified Water No Not required for shutdown.
Condensate No Not required for shutdown.
Fuel Pool Cooling No Not required for shutdown but continuous pool cooling is desired. Seismic Category I makeup line is provided.
Control Drywell Purge Yes Backup to hydrogen control.
MSIV Alternative Drain Yes Ensures that highly radioactive fluids are confined Pathway to the reactor building.
TIP System No Not required for shutdown.
Fire Protection System Yes Availability is essential for shutdown following a fire.
Makeup Demineralizer No Not required for shutdown.
ECCS Fill System Yes Required to ensure ECCS operability.
Feedwater Fill System Yes Required to mitigate radiological consequences.
CHAPTER 06 6.2-172 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-27 (Cont'd)
ESSENTIAL COMMENTS Primary Containment Leak Test No Not required for shutdown.
System Suppression Pool Cleanup System No Not required for shutdown.
Long-Term ADS Gas Supply Yes Long-term backup to ADS accumulators inside containment.
CHAPTER 06 6.2-173 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-28 REACTOR ENCLOSURE AND REFUELING AREA SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION VALVES-SEPERATE ZONE SYSTEM ALIGNMENT REACTOR ENCLOSURE (ZONE I) MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 1. Reactor Enclosure Ventilation 5 B,H,S,U Supply Valve HV-76-107
- 2. Reactor Enclosure Ventilation Supply Valve HV-76-108 5 B,H,S,U
- 3. Reactor Enclosure Ventilation Exhaust Valve HV-76-157 5 B,H,S,U
- 4. Reactor Enclosure Ventilation Exhaust Valve HV-76-158 5 B,H,S,U
- 5. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-141 5 B,H,S,U
- 6. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-142 5 B,H,S,U
- 7. Drywell Purge Exhaust Valve HV-76-30 5 B,H,S,U,R,T
- 8. Drywell Purge Exhaust Valve HV-76-31 5 B,H,S,U,R,T
- 9. Drywell Purge Exhaust Inboard Valve HV-57-214 (Unit 2) 5 B,H,S,U,W,R,T
- 10. Drywell Purge Exhaust Outboard Valve HV-57-215 (Unit 2) 6 B,H,S,U,W,R,T
- 11. Suppression Pool Purge Exhaust Inboard Valve HV-57-204 (Unit 2) 5 B,H,S,U,W,R,T
- 12. Suppression Pool Purge Exhaust Outboard Valve HV-57-212 (Unit 2) 6 B,H,S,U,W,R,T CHAPTER 06 6.2-174 REV. 15, SEPTEMBER 2010
LGS UFSAR TABLE 6.2-28 (Cont'd)
REACTOR ENCLOSURE (ZONE II)
MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 1. Reactor Enclosure Ventilation Supply Valve HV-76-207 5 B,H,S,U
- 2. Reactor Enclosure Ventilation Supply Valve HV-76-208 5 B,H,S,U
- 3. Reactor Enclosure Ventilation Exhaust Valve HV-76-257 5 B,H,S,U
- 4. Reactor Enclosure Ventilation Exhaust Valve HV-76-258 5 B,H,S,U
- 5. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-241 5 B,H,S,U
- 6. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-242 5 B,H,S,U
- 7. Drywell Purge Exhaust Valve HV-76-30 5 B,H,S,U,R,T
- 8. Drywell Purge Exhaust Valve HV-76-31 5 B,H,S,U,R,T
- 9. Drywell Purge Exhaust Inboard Valve HV-57-114 (Unit 1) 5 B,H,S,U,W,R,T
- 10. Drywell Purge Exhaust Outboard Valve HV-57-115 (Unit 1) 6 B,H,S,U,W,R,T
- 11. Suppression Pool Purge Exhaust Inboard Valve HV-57-104 (Unit 1) 5 B,H,S,U,W,R,T
- 12. Suppression Pool Purge Exhaust Outboard Valve HV-57-112 (Unit 1) 6 B,H,S,U,W,R,T (a) See LGS Technical Specification 3.3.2, Table 3.3.2-1 for isolation signals that operate each automatic isolation valve.
CHAPTER 06 6.2-175 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-28 (Cont'd)
REFUELING AREA (ZONE III)
MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 1. Refueling Area Ventilation 5 R,T Supply Valve HV-76-117 (Unit 1)
- 2. Refueling Area Ventilation Supply 5 R,T Valve HV-76-118 (Unit 1)
- 3. Refueling Area Ventilation Exhaust 5 R,T Valve HV-76-167 (Unit 1)
- 4. Refueling Area Ventilation Exhaust 5 R,T Valve HV-76-168 (Unit 1)
- 5. Refueling Area Ventilation Supply 5 R,T Valve HV-76-217 (Unit 2)
- 6. Refueling Area Ventilation Supply 5 R,T Valve HV-76-218 (Unit 2)
- 7. Refueling Area Ventilation Exhaust 5 R,T Valve HV-76-267 (Unit 2)
- 8. Refueling Area Ventilation Exhaust 5 R,T Valve HV-76-268 (Unit 2)
- 9. Drywell Purge Exhaust Valve HV-76-030 5 B,H,S,U,R,T
- 10. Drywell Purge Exhaust Valve HV-76-031 5 B,H,S,U,R,T
- 11. Drywell Purge Exhaust Inboard 5 B,H,S,U,W,R,T Valve HV-57-114 (Unit 1)
- 12. Drywell Purge Exhaust Outboard 6 B,H,S,U,W,R,T Valve HV-57-115 (Unit 1)
- 13. Suppression Pool Purge Exhaust Inboard 5 B,H,S,U,W,R,T Valve HV-57-104 (Unit 1)
- 14. Suppression Pool Purge Exhaust Outboard 6 B,H,S,U,W,R,T Valve HV-57-112 (Unit 1)
- 15. Drywell Purge Exhaust Inboard 5 B,H,S,U,W,R,T Valve HV-57-214 (Unit 2)
- 16. Drywell Purge Exhaust Outboard 6 B,H,S,U,W,R,T Valve HV-57-215 (Unit 2)
- 17. Suppression Pool Purge Exhaust 5 B,H,S,U,W,R,T, Inboard Valve HV-57-204 (Unit 2)
- 18. Suppression Pool Purge Exhaust 6 B,H,S,U,W,R,T Outboard Valve HV-57-212 (Unit 2)
(a) See UFSAR Table 6.2-17, note 5 for isolation signals that operate each automatic isolation valve.
CHAPTER 06 6.2-176 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-29 REACTOR ENCLOSURE AND REFUELING AREA SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION VALVES-COMBINED ZONE SYSTEM ALIGNMENT RX / REFUEL ENCL. (ZONE I & III)
MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 1. Reactor Enclosure Ventilation 5 B,H,S,U,R,T Supply Valve HV-76-107
- 2. Reactor Enclosure Ventilation Supply Valve HV-76-108 5 B,H,S,U,R,T
- 3. Reactor Enclosure Ventilation Exhaust Valve HV-76-157 5 B,H,S,U,R,T
- 4. Reactor Enclosure Ventilation Exhaust Valve HV-76-158 5 B,H,S,U,R,T
- 5. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-141 5 B,H,S,U,R,T
- 6. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-142 5 B,H,S,U,R,T
- 7. Drywell Purge Exhaust Valve HV-76-30 5 B,H,S,U,R,T
- 8. Drywell Purge Exhaust Valve HV-76-31 5 B,H,S,U,R,T
- 9. Drywell Purge Exhaust Inboard Valve HV-57-214 (Unit 2) 5 B,H,S,U,W,R,T
- 10. Drywell Purge Exhaust Outboard Valve HV-57-215 (Unit 2) 6 B,H,S,U,W,R,T
- 11. Suppression Pool Purge Exhaust Inboard Valve HV-57-204 (Unit 2) 5 B,H,S,U,W,R,T
- 12. Suppression Pool Purge Exhaust Outboard Valve HV-57-212 (Unit 2) 6 B,H,S,U,W,R,T
- 13. Refueling Area Ventilation Supply Valve HV-76-117 5 B,H,S,U,R,T
- 14. Refueling Area Ventilation Supply Valve HV-76-118 5 B,H,S,U,R,T
- 15. Refueling Area Ventilation Exhaust Valve HV-76-167 5 B,H,S,U,R,T
- 16. Refueling Area Ventilation Exhaust Valve HV-76-168 5 B,H,S,U,R,T
- 17. Refueling Area Ventilation Supply Valve HV-76-217 (Unit 2) 5 B,H,S,U,R,T
- 18. Refueling Area Ventilation Supply Valve HV-76-218 (Unit 2) 5 B,H,S,U,R,T
- 19. Refueling Area Ventilation Exhaust Valve HV-76-267 (Unit 2) 5 B,H,S,U,R,T
- 20. Refueling Area Ventilation Exhaust Valve HV-76-268 (Unit 2) 5 B,H,S,U,R,T TABLE 6.2-29 (Cont'd)
CHAPTER 06 6.2-177 REV. 15, SEPTEMBER 2010
LGS UFSAR ZONE I & III (Cont'd)
MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 21. Drywell Purge Exhaust Inboard 5 B,H,S,U,W,R,T Valve HV-57-114
- 22. Drywell Purge Exhaust Outboard 6 B,H,S,U,W,R,T Valve HV-57-115
- 23. Suppression Pool Purge Exhaust Inboard 5 B,H,S,U,W,R,T Valve HV-57-104
- 24. Suppression Pool Purge Exhaust Outboard 6 B,H,S,U,W,R,T Valve HV-57-112 CHAPTER 06 6.2-178 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-29 (Cont'd)
RX / REFUEL ENCL.(ZONE II & III)
MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 1. Reactor Enclosure Ventilation Supply Valve HV-76-207 5 B,H,S,U,R,T
- 2. Reactor Enclosure Ventilation Supply Valve HV-76-208 5 B,H,S,U,R,T
- 3. Reactor Enclosure Ventilation Exhaust Valve HV-76-257 5 B,H,S,U,R,T
- 4. Reactor Enclosure Ventilation Exhaust Valve HV-76-258 5 B,H,S,U,R,T
- 5. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-241 5 B,H,S,U,R,T
- 6. Reactor Enclosure Equipment Compartment Exhaust Valve HV-76-242 5 B,H,S,U,R,T
- 7. Drywell Purge Exhaust Valve HV-76-30 5 B,H,S,U,R,T
- 8. Drywell Purge Exhaust Valve HV-76-31 5 B,H,S,U,R,T
- 9. Drywell Purge Exhaust Inboard Valve HV-57-114 (Unit 1) 5 B,H,S,U,W,R,T
- 10. Drywell Purge Exhaust Outboard Valve HV-57-115 (Unit 1) 6 B,H,S,U,W,R,T
- 11. Suppression Pool Purge Exhaust Inboard Valve HV-57-104 (Unit 1) 5 B,H,S,U,W,R,T
- 12. Suppression Pool Purge Exhaust Outboard Valve HV-57-112 (Unit 1) 6 B,H,S,U,W,R,T
- 13. Refueling Area Ventilation Supply Valve HV-76-117 (Unit 1) 5 B,H,S,U,R,T
- 14. Refueling Area Ventilation Supply Valve HV-76-118 (Unit 1) 5 B,H,S,U,R,T
- 15. Refueling Area Ventilation Exhaust Valve HV-76-167 (Unit 1) 5 B,H,S,U,R,T
- 16. Refueling Area Ventilation Exhaust Valve HV-76-168 (Unit 1) 5 B,H,S,U,R,T
- 17. Refueling Area Ventilation Supply Valve HV-76-217 5 B,H,S,U,R,T
- 18. Refueling Area Ventilation Supply Valve HV-76-218 5 B,H,S,U,R,T
- 19. Refueling Area Ventilation Exhaust Valve HV-76-267 5 B,H,S,U,R,T
- 20. Refueling Area Ventilation Exhaust Valve HV-76-268 5 B,H,S,U,R,T CHAPTER 06 6.2-179 REV. 15, SEPTEMBER 2010
LGS UFSAR Table 6.2-29 (Cont'd)
ZONE II & III (Cont'd)
MAXIMUM ISOLATION TIME ISOLATION VALVE FUNCTION (Seconds) SIGNALS (a)
- 21. Drywell Purge Exhaust Inboard 5 B,H,S,U,W,R,T Valve HV-57-214
- 22. Drywell Purge Exhaust Outboard 6 B,H,S,U,W,R,T Valve HV-57-215
- 23. Suppression Pool Purge Exhaust 5 B,H,S,U,W,R,T Inboard Valve HV-57-204
- 24. Suppression Pool Purge Exhaust 6 B,H,S,U,W,R,T Outboard Valve HV-57-212 (a) See UFSAR Table 6.2-17, note 5 for isolation signals that operate each automatic isolation valve.
CHAPTER 06 6.2-180 REV. 15, SEPTEMBER 2010