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Under normal operation the air supply maintain s the required air for holding the valve open and charging the air storage tank. The check valve at the ai r storage tank inlet ensures a pneumatic supply for assist in cl osing the valve. No safety-related make up supply is required for closure of the MSIVs for safe plant shutdown. | Under normal operation the air supply maintain s the required air for holding the valve open and charging the air storage tank. The check valve at the ai r storage tank inlet ensures a pneumatic supply for assist in cl osing the valve. No safety-related make up supply is required for closure of the MSIVs for safe plant shutdown. | ||
The removal of electrical power or failure of both the solenoids on the control valve automatically initiates closure of the MSIVs. Safety-related components ensuring removal of power to the solenoids when required are the only electrical power requirement. Section 9.3.1 describes the compressed air systems. | The removal of electrical power or failure of both the solenoids on the control valve automatically initiates closure of the MSIVs. Safety-related components ensuring removal of power to the solenoids when required are the only electrical power requirement. Section | ||
====9.3.1 describes==== | |||
the compressed air systems. | |||
Equalizing lines connecting steam lines outside of the containment are used to equalize pressure across the main steam line isolation valves prior to restart following a steam line isolation. Assuming all steam lin e isolation valves have closed, the outer containment isolation valves are opened first and the drain lines ar e used to warm up and pressurize the outside steam lines. Following warmup the inboard main steam line is olation valves are opened. | Equalizing lines connecting steam lines outside of the containment are used to equalize pressure across the main steam line isolation valves prior to restart following a steam line isolation. Assuming all steam lin e isolation valves have closed, the outer containment isolation valves are opened first and the drain lines ar e used to warm up and pressurize the outside steam lines. Following warmup the inboard main steam line is olation valves are opened. | ||
| Line 753: | Line 756: | ||
10.4.6.6 Demineralizer Resins | 10.4.6.6 Demineralizer Resins | ||
Compliance with Regulatory Guide 1.56 is discussed in Section 1.8. | Compliance with Regulatory Guide 1.56 is discussed in Section | ||
===1.8. Pressure=== | |||
precoat filter/deminera lizer media on individual vessels is replaced on a cyclic basis when the pressure drop exceeds 25 psid or the effluent conductivity exceeds 0.065 | |||
µS/cm during normal operating conditions. The c onductivity limitation does not apply when condenser vacuum is broken and during the period when condenser vacuum is being restored. | µS/cm during normal operating conditions. The c onductivity limitation does not apply when condenser vacuum is broken and during the period when condenser vacuum is being restored. | ||
| Line 777: | Line 782: | ||
10.4.7.2 System Description | 10.4.7.2 System Description | ||
The condensate and feedwater system shown in Figure 10.4-6 is a six-heater regenerative feedwater heating cycle. The extraction stea m system supplying h eating steam to each feedwater heater is shown in Figure 10.4-7. A discussion of the c ondensate supply system is presented in Section 9.2.6. | The condensate and feedwater system shown in Figure 10.4-6 is a six-heater regenerative feedwater heating cycle. The extraction stea m system supplying h eating steam to each feedwater heater is shown in Figure 10.4-7. A discussion of the c ondensate supply system is presented in Section | ||
====9.2.6. Feedwater==== | |||
heaters 1, 2, 3, a nd 4 are divided into three one-third capacity parallel trains; heaters nmber 5 and 6 are split into two one-half capacity parallel strings. The final feedwater temperature is approximately 421°F at design output. Tube material for RFW-HX-6A and RFW-HX-6B is type 316 stainless steel. For th e rest of the heaters the tubes are type 304 stainless steel. The first-stage heaters are located in the co ndenser exhaust neck. | |||
Figure 10.4-8 shows the heater drain system. All feedwater heater drains are cascaded back to the condenser (6-5-4-3-2-1 condenser). Reheater drains are ca rried to the number 6 heaters whereas the moisture se parators drain to the number 5 heaters. | Figure 10.4-8 shows the heater drain system. All feedwater heater drains are cascaded back to the condenser (6-5-4-3-2-1 condenser). Reheater drains are ca rried to the number 6 heaters whereas the moisture se parators drain to the number 5 heaters. | ||
Revision as of 19:14, 12 October 2018
| ML14010A305 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 12/30/2013 |
| From: | Energy Northwest |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML14010A476 | List:
|
| References | |
| GO2-13-174 | |
| Download: ML14010A305 (87) | |
Text
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 10
STEAM AND POWER CONVERSION SYSTEM
TABLE OF CONTENTS
Section Page LDCN-05-009 10-i 10.1
SUMMARY
DESCRIPTION...........................................................10.1-1 10.2 TURBINE GENERATOR...............................................................10.2-1 10.2.1 DESIGN BASIS........................................................................10.
2-1 10.2.2 SYSTEM DE SCRIPTION............................................................10.2-1 10.2.3 TURBINE DI SK INTEGRITY......................................................10.2-6 10.2.4 SAFETY EVALUATION............................................................10.2-6 10.3 MAIN STEAM SUPPLY SYSTEM...................................................10.3-1 10.3.1 DESIGN BASES.......................................................................10.
3-1 10.3.2 SYSTEM DE SCRIPTION............................................................10.3-1 10.3.3 SAFETY EVALUATION............................................................10.3-2 10.3.4 INSPECTION AND TESTING REQUIREMENTS.............................10.3-3 10.3.5 WATER CH EMISTRY...............................................................10.3-3 10.3.6 STEAM AND FEEDWATE R SYSTEM MATERIALS........................10.3-3 10.3.6.1 Fracture Toughness..................................................................10.3-3 10.3.6.2 Materials Se lection and Fabrication..............................................10.3-3
10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4-1 10.4.1 MAIN CO NDENSER.................................................................10.4-1 10.4.1.1 Design Bases..........................................................................10.4-1 10.4.1.2 System Description..................................................................10.4-2 10.4.1.3 Safety Evaluation....................................................................10.
4-2 10.4.1.4 Tests and Inspections................................................................10.4-4 10.4.1.5 Instrumentation.......................................................................10.
4-4 10.4.2 MAIN CONDENSER EVACUATION SYSTEM...............................10.4-5 10.4.2.1 Design Bases..........................................................................10.4-5 10.4.2.2 System Description..................................................................10.4-5 10.4.2.3 Safety Evaluation....................................................................10.
4-6 10.4.2.4 Tests and Inspections................................................................10.4-6 10.4.2.5 Instrumentation.......................................................................10.
4-6 10.4.3 TURBINE GLAND SEALING SYSTEM.........................................10.4-7 10.4.3.1 Design Bases..........................................................................10.4-7 10.4.3.2 System Description..................................................................10.4-7 10.4.3.3 Safety Evaluation....................................................................10.
4-8 10.4.3.4 Tests and Inspection.................................................................10.4-9 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 10
STEAM AND POWER CONVERSION SYSTEM
TABLE OF CONTENTS (Continued)
Section Page LDCN-06-042,06-046 10-ii 10.4.3.5 Instrumentation.......................................................................10.
4-9 10.4.4 TURBINE BYPASS SYSTEM......................................................10.4-9 10.4.4.1 Design Bases..........................................................................10.4-9 10.4.4.2 System Description..................................................................10.4-10 10.4.4.3 Safety Evaluation....................................................................10.
4-11 10.4.4.4 Tests and Inspections................................................................10.4-11 10.4.4.5 Instrumentation.......................................................................10.
4-11 10.4.5 CIRCULATING WATER SYSTEM...............................................10.4-12 10.4.5.1 Design Bases..........................................................................10.
4-12 10.4.5.2 System Description..................................................................10.4-12 10.4.5.3 Safety Evaluation....................................................................10.
4-13 10.4.5.4 Tests and Inspections................................................................10.4-16 10.4.5.5 Instrumentation.......................................................................10.
4-17 10.4.6 CONDENSATE FILTER DEMINERALIZER SYSTEM......................10.4-17 10.4.6.1 Design Bases..........................................................................10.
4-17 10.4.6.2 System Description..................................................................10.4-19 10.4.6.3 Safety Evaluation....................................................................10.
4-20 10.4.6.4 Tests and Inspections................................................................10.4-20 10.4.6.5 Instrumentation.......................................................................10.
4-20 10.4.6.6 Demineralizer Resins................................................................10.4-21 10.4.6.7 Water Chemistry Analyses.........................................................10.
4-21 10.4.7 CONDENSATE AND F EEDWATER SYSTEMS...............................
10.4-22 10.4.7.1 Design Bases..........................................................................10.
4-22 10.4.7.2 System Description..................................................................10.4-22 10.4.7.3 Safety Evaluation....................................................................10.
4-24 10.4.7.4 Tests and Inspections................................................................10.4-24 10.4.7.5 Instrumentation.......................................................................10.
4-25 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEMS.............................
10.4-25 10.4.9 AUXILIARY F EEDWATER SYSTEM...........................................10.4-25 10.4.10 HYDROGEN WATER CH EMISTRY SYSTEM.................................10.4-25 10.4.10.1 Design Bases..........................................................................10.
4-25 10.4.10.2 System Description..................................................................10.4.26 10.4.10.2.1 Hydrogen Stor age and Supply Facility.........................................10.
4-26 10.4.10.2.2 Hydrogen and Air Injection......................................................10.
4-27 10.4.10.3 Safety Evaluation....................................................................10.
4-27 10.4.10.4 Tests and Inspections...............................................................10.4-30 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 10
STEAM AND POWER CONVERSION SYSTEM
TABLE OF CONTENTS (Continued)
Section Page LDCN-03-069 10-iii 10.4.10.5 Instrumentation......................................................................10.
4-30 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 10 STEAM AND POWER CONVERSION SYSTEM
LIST OF TABLES
Number Title Page LDCN-03-069 10-iv 10.1-1 Design and Performance Charac teristics of Power Conversion System............................................................................10.1-3
10.4-1 Feedwater System Equipm ent Characteristics.............................10.4-33
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 Chapter 10
STEAM AND POWER CONVERSION SYSTEM
LIST OF FIGURES
Number Title LDCN-11-000 10-v 10.1-1 1237418 kW Net Load Heat Balance
10.1-2 1292191 kW Net Load Heat Balance
10.2-1 Acceptable Range for Contro l Valve Normal Closure Motion
10.2-2 Turbine Stop Valve Closure Characteristic
10.2-3 Turbine Control Valve Fa st Closure Characteristic
10.2-4 Alternating Current (ac)
Turbine Generator Gas Diagram 10.2-5 Alternating Current (ac) Tu rbine Generator Gas Supply Outline
10.2-6 Electrohydraulic HP Fluid and Lube Oil Diagram (Sheets 1 through 3)
10.2-7 Turbine Generator Control Elementary Diagram (Sheets 1 through 3)
10.3-1 Main Steam Supply Syst em (Sheets 1 through 3)
10.3-2 Main Steam Supply System Piping
10.4-1 Main Condenser Evacuation System
10.4-2 Turbine Gland Sealing System
10.4-3 Turbine B ypass Valve Outline 10.4-4 Flow Diagram - Circulating Water System - Turbine Generator Building and Yard (Sheets 1 through 3)
10.4-5 Flow Diagram - Radioactive Waste System Condensate Demineralization
10.4-6 Flow Diagram - Condensate and F eedwater Systems (Sheets 1 through 3)
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 10
STEAM AND POWER CONVERSION SYSTEM
LIST OF FIGURES (Continued)
Number Title LDCN-03-069 10-vi 10.4-7 Flow Diagram - Extraction Steam and Heater Vents - Turbine Generator Building (Sheets 1 and 2) 10.4-8 Flow Diagram - Heater Drain System - Turbine Generator Building (Sheets 1 through 3)
10.4-9 Flow Diagram - Hydrogen Water Ch emistry - Turbine Generator Building and Hydrogen Storage and Supply F acility (Sheets 1 through 3)
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-014 10.1-1 Chapter 10
STEAM AND POWER CONVERSION SYSTEM
10.1
SUMMARY
DESCRIPTION
The steam and power conversion system is designed to produce electrical energy through conversion of a portion of the thermal energy contained in the steam supplied from the reactor, to condense the main turbine exha ust steam, and to re turn condensate to th e reactor as heated feedwater with a major portion of its gaseous dissolved and particulate impurities removed.
The power conversion system uses the Rankine steam cycle with a closed regenerative feedwater heating cycle. It has the capability to accept 105% of the reactor's rated steam flow. Steam leaves the reactor vessel at 1035 psia. Steam enters the turbine at 1000 psia with a 0.30% moisture content. The turbine is a tandem-compound turbin e generator having a six-flow exhaust end. Steam is exhausted into a triple pr essure condenser designed for a 2.4-in. Hg average backpressure and is condensed with circula ting water cooled by mechanical draft cooling towers. Six stages of regenerative feedwater hea ting are provided, four heated with extraction steam from the lo w pressure turbines and two from the high pressure turbine.
The final design feedwater temperature at normal full load is 421°F.
The major components of the st eam and power conversion system are the turbine generator, main condenser, condensate pum ps, condensate booster pumps, mechanical vacuum pumps, steam jet air ejectors, turbine gland seali ng system (which includes gland seal steam evaporators and condenser), turbine bypass system , condensate filter demi neralizers, turbine driven reactor feed pumps, feedwater heaters, and condensate st orage facilities. The turbine cycle heat balance for rated and 104.1%
maximum calculated power are given in Figures 10.1-1 and 10.1-2. These figures are representativ e of the overall power conversion system.
The saturated steam produced by the boiling water reactor is passed through the high pressure turbine where the steam is expanded and is then exhausted to two moistu re separator/reheaters (two reheat stages) arranged in parallel. The moisture separato rs remove the moisture content of the steam and superheat the steam before it en ters the low pressure turbines where the steam is expanded further.
Steam for the first-stage reheater is taken from the first extraction point of the high pressure turbine while steam for th e second-stage reheater is taken fr om the main steam header. From the low pressure turbines, th e steam is exhausted into th e main condenser where it is condensed and deaerated. The condensate pumps take suction from th e condenser hotwell and deliver the condensate through the gland seal steam condenser, st eam-jet air ejector condenser, offgas condenser, and condensat e demineralizers to the condens ate booster pump suction. The condensate booster pumps then disc harge through the low pressure feedwater heater trains to
C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 10.1-2 the reactor feedwater pumps.
The reactor feedwater pumps s upply feedwater through the high pressure feedwater heaters to the reactor. Steam for heating the feedwater in the heating cycle is supplied from turbine extracti ons. The drains from the feedwater heaters, the reheaters, and the moisture separators are cascaded to the next lower pressure feedwater heater and finally discharged to the condenser.
The ability of the plant to follow system loads depends on the adjustment of the reactor power level. The steam admission valves are controlled by the initial pressure regulator so that the turbine receives the proper amount of steam requi red for the load demand.
The turbine speed governor, however, may override the initial pressure regulat or to close the steam admission valves if an increase in system frequency or loss of generator load causes an increase in turbine speed. Reactor steam in excess of that whic h the admission valves will pass is bypassed directly to the main condenser through pressure controlled bypass valves. Load rejection in excess of bypass capacity causes the react or safety/relief valves to open.
The main turbine, main condenser, and moisture separator/reheat ers are located in a shielded area with controlled access to limit personnel exposure.
The portions of the power conversion system which constitute part of the reactor coolant
pressure boundary are the main steam lines exte nding from the reactor pressure vessel to the outermost containment isolation valve.
Table 3.2-1 indicates the safety class, quality group classification, and seismic category of the power conversion system. Environmental design bases are disc ussed in Section 3.11.
Table 10.1-1 presents a summary of important design and performance characteristics of the steam and power conversion system.
The design of various steam and condensate instrumentation syst ems are based on the need to monitor and control normal power generation system functions such as level, flow, pressure, and temperature. The instrumentation provide s information that enab les the control room operator to start up, operate, and shut down these systems.
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-014 10.1-3 Table 10.1-1
Design and Performance Characteristics of Power Conversion System a Turbine Data Manufacturer Westinghouse HPT building block BB 296 LPT building block BB 281R LPT type/LSB length (in.) TC6F/47 Number of casings 1-HP, 3-LP
Backpressure zones (in. Hg abs) 1.89/2.36/2.99 (2.4 average)
Generator Rating (kVA) 1,230,000 Gross output (MWe) 1230 Power factor 0.975 Voltage (volts) 25,000 Phase/frequency (Hz) 3/60 Hydrogen pressure (psig) 75-78
Steam conditions at throttle valve Flow (lb/hr) 14,127,313 Pressure (psia) 1000 Temperature ( F) 544.6 Enthalpy (Btu/lb) 1189.5 Moisture content, maximum (%) 0.30
Turbine cycle heat rate (Btu/kW-hr) 9613 Final feedwater temperature ( F) 420.9 Turbine cycle arrangement Steam reheat stages 2 Number of feedwater heating stages 6 Feedwater heater in condenser neck First stage
Type of condensate demineralizer Powdered resin
Main steam bypass capacity (%)
25 a All data based on 100% load. See Figure 10.1-1.
Figure Amendment 62 December 2013 Form No. 960690 LDCN-12-020 Draw. No.Rev.1237418 kW Net Load Heat Balance 960222.24 10.1-1**1 Y J HTR 1 168.6T DC Reheater HTR 2 204.3T DC 11647599W 1085.7H F 1 Regulators CBP CP B N T D GC SJAE R E X 1 C M 173.6T 141.5 h A HTR 3 256.6T DC HTR 4 291.2T DC HTR 5 370.6T DC P S L E S T C X Condenser L M N H F G G 1 X D H GLO STM EVAP HTR 6 425.9T DC G F R P Y I M N Z U X A B TV U Z Moisture Separator Reheater ID=25F ID=25F 174P 1196.3H J14968341 (1191.0 - 398.7) + 32000 (1191.0 - 84.7) 1237418 Net Heat =Rate= 9613 BTU/kWHr (3) Double Flow LP Turbines RSV TV F 1 990P 1.89 2.36 2.99 Inch HgA 6720W 114.9T 82.9h 210.3T 178.4h OGCH = 1000H Make Up zero W 32000W 84.7h CRD Cooling Water 125.6T 93.5h 115.6T 84.7h 367.3T 341.5h 14968341W 420.9T 398.7hH = 2.97h 329P 308W 167P 518.4T 1282.4H BFPT TV CV Zero W HP Turbine W - Flow lb/hr P - Pressure PsiA
H - Enthalpy Btu/lb
T - Temperature Deg F
M - Moisture %
Note: Calculations Assure
Generator Rewind LEGEND 9976815W 1282. 4 H 201W 1198.4H 3617W 1198.4H 6920W 1198.4H 1396W 1198.4H 13839W 1198.4H 12941W 1198.4H 160442W 1282.4H 167P 160442W 1005.5H 2.36 Inch HgA 1047.3H 1030.6H 2.77P 1071.7H 1057.7H 5.95P 1101.0H 1092.0H 12.9P 1155.3H 34.3P 1196.2H 60.1P 163P 12941W 1198.4H 4533W 1198.4H 2635800W 1001.7H 0.9283P 2635800W 1006.8H 1.1591P 2635800W 1016.6H 1.4685P 143442W 106.3H 60838W 1047.3H 124530W 137.6H 416398W 1071.1H 5.80P 87950W 173.7H 339784W 1101.0H 12.6P 33.4P 163.6T 132.6h 199.3T 168.4h 209.3T 177.5h 1155.3H 525488W 251.6T 221.1h 1220P 13018kW 261.6T 230.4h 365.6T 338.6h 30799W 338.6h 1085.7H 1122387W 174P 286.2T 256.3h 368985W 1196.2H 58.6P 9220W 1135.5H 461013W 425.7H 18670W 406.0h 836922W 1124.6H 36165W 410.4h 36165W 1135.5H 296.2T 265.8h 1510342W 343.0H 174P 410P 470234W 1135.5H 16736W 1191.0H 836778W 539.5H 1135.5H 412P 1124.6H 1122.7H 337P 1085.7H 179P 2070W 1192.9H 5 30W 1198.4H 1059W 1198.4H 14127313W 1191.0H 8 100W 1191.0H 11420W 1191.0H 29235W 1198.4H 1256W 1198.4H 200W 1198.4H 677P 1168.3H 3617W 1198.4H 6919W 1198.4H 853513W 1191.0H ZeroW 1000P 15000346W 1191.0H 544.6T 0.30M 377.3T 350.7h G 1 Columbia Generating Station Final Safety Analysis Report (1191.0 - 403.4) + 32000 15718551*9995W 1138.1H 16792W 1191.0H 11420W 1191.0H 8 100W 1191.0H 1396W 1198.4H Figure Form No. 960690 LDCN-12-020 Draw. No.Rev.1292191 kW Net Load Heat Balance 960222.25 10.1-2 Columbia Generating Station Final Safety Analysis Report 313W F 1 Regulators CBP CP B N T D GC SJAE R E X 1 C HTR 1 170.4T DC M 175.4T 143.4h HTR 2 206.6T DC A HTR 3 259.3T DC HTR 4 294.3T DC HTR 5 374.4T DC P S L E S T C X Condenser L M N H F G G 1 X 1 D H GLO STM EVAP HTR 6 430.2T DC G F R P Y L M N Z U X A B TV Y J U Z Moisture Separator Reheater Reheater ID=25F ID=25F 182P 1197.0H J* (1191.0 - 84.6) 1292191 Net Heat =Rate= 9608 BTU/kWHr (3) Double Flow LP Turbines RSV TV F 1 990P 1.89 2.36 2.99 Inch HgA 6720W 114.9T 82.9h 210.3T 178.4h OGCH = 1000H Make Up Zero W 32000W 84.6h CRD Cooling Water 125.5T 93.5h 115.5T 84.6h 371.2T 345.6h 15718551W 425.2T 403.4hH = 2.98h 344P 175P 516.4T 1281.6H BFPT TV CV Zero W HP Turbine W - Flow lb/hr P - Pressure PsiA
H - Enthalpy Btu/lb
T - Temperature Deg F
M - Moisture %
Note: Calculations Assure
Generator Rewind LEGEND 10475206W 1281.6H 200W 1198.4H 3782W 1198.4H 7154W 1198.4H 14309W 1198.4H 12941W 1198.4H 167712W 1281.6H 166P 167712W 1002.7H 2.36 Inch HgA 1047.0H 1030.2H 2.90P 1070.7H 1057.1H 6.21P 1100.5H 1091.4H 13.5P 1154.7H 35.9P 1195.6H 63.1P 171P 1294.1W 1198.4H 4533W 1198.4H 2751820W 1000.9H 0.9283P 2754820W 1005.2H 1.1591P 2754820W 1014.2H 1.4685P 151665W 108.1H 63598W 1047.0H 132354W 139.6h 456441W 1070.7H 6.05P 93888W 176.0h 361298W 1100.5H 13.2P 35.0P 165.4T 134.4h 201.6T 170.7h 211.6T 179.8h 1154.7H 558169W 254.3T 223.8h 1220P 13707kW 264.3T 233.1h 369.4T 342.7h 31274W 342.7h 1087.8H 1194551W 183P 289.3T 259.5h 39333.2W 1195.6H 61.5P 12213038W 1087.8H 499769W 431.3h 19028W 411.0h 906449W 1126.9H 36420W 410.4h 36420W 1138.1H 299.3T 269.0h 1570121W 347.2H 182P 431P 509765W 1138.1H 839592W 539.5h 1138.0H 433P 1126.9H 1125.0H 354P 1087.8H 188P 2070W 1192.9H 530W 1198.4H 1059W 1198.4H 14874459W 1191.0H 29705W 1198.4H 1256W 1198.4H 201W 1198.4H 713P 1171.2H 3782W 1198.4H 7155W 1198.4H 856384W 1191.0H Zero W 1000P 15750363W 1191.0H 544.6T 0.30M 381.2T 354.8h G 1 Amendment 62 December 2013 C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 10.2-1 10.2 TURBINE GENERATOR 10.2.1 DESIGN BASIS
The turbine generator is designed to receive steam from the boiling water reactor, convert a portion of the thermal energy contained in the steam to electric energy, and provide extraction steam for feedwater heating.
The turbine generator, associated systems, and control characteristics, are integrated with the features of the reactor and associated systems to obtain an efficient and safe power generator unit. The turbine generator is designed to function only during normal plant conditions including startup, power generation, and shutdown. The turbine generator is not required for safe shutdown of the reactor nor to perform safe ty functions. The turb ine generator equipment is in strict conformance with the latest edition in effect at the time of fabrication, of ANSI C.50.10, ANSI C.50.13, and the IEEE standards.
The major portion of the manufacture was performed during 1975. The original LP turbine rotors were replaced with fully integral rotors during 1992. Safety class and seismic cate gory are presented in Section 3.2.
The turbine generator design conditions are included in Table 10.1-1.
The turbine generator is intended for base load operation. Normal load swings are limited to the rate of change of power output of the nucle ar steam supply system.
The turbine governor valves are capable of full stroke opening and closure within 7 sec for adequate pressure control pe rformance. Normal governor valve closure is shown in Figure 10.2-1.
During events resulting in turb ine throttle or governor valve fast closure, turbine inlet steam flow is not reduced faster than permitted by Figures 10.2-2 or 10.2-3.
10.2.2 SYSTEM DESCRIPTION
The main turbine is a tandem-compound unit, consisting of one double-flow high pressure turbine and three double-flow low pressure turbines (Figure 10.3-1
), running at 1800 rpm with 47 in. last-stage blades. Exha ust steam from the high pressure turbine passes through two moisture separator/reheaters (two stage reheat) before entering th e low pressure turbine inlets.
The exhaust steam from the thr ee low pressure turbines is c ondensed in the main condenser.
The generator is a three phase, 60 cycle, 25, 000 V, 1800 rpm unit rated at 1,230,000 kVA at 0.975 power factor. The stator is water cooled and the ro tor is hydrogen cooled. The hydrogen system is designed to mi nimize the hazard from fires or explosions as discussed in Appendix F.
C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 3 9 10.2-2 The design of the system, Figures 10.2-4 and 10.2-5, and the specified operating procedures are such that explosive mixtures are not possible under normal operating conditions. The hydrogen gas supply system includes a storage trailer and stor age cylinders used as backup if the trailer supply runs low. Pr essure regulators are mounted on bo th the storage trailer and the bottle manifold for control of the hydrogen gas, and a circuit for supplying and controlling the carbon dioxide used in purging the generator during filling and degasi ng operations. To prevent hydrogen leakage by the generator shaft seals, a hydrogen seal oil system is provided.
The hydrogen seal oil system, which includes pumps and controls, deaerates the oil before it is sent to the shaft seals.
The fundamental rule is that hydrogen and air should never be mixed. Carbon dioxide is used as an intermediate gas when ch anging either from air to hydr ogen or from hydrogen to air.
When changing from one gas to another, the ge nerator is vented to the atmosphere. The valves, pressure gauges, regul ators, and other equipment in the hydrogen gas supply system permit introducing hydrogen or prevent the flow of hydrogen into the generator and also provide means of controlling the gas pressure within the generator.
Steam is transported from the reactor by four main steam lines and fl ows through the turbine throttle valves and governor valves to the high pressure turbine.
The steam lines are combined upstream of the throttle and gove rnor valves. The turbine bypa ss valves are located upstream of the turbine throttle valves to permit steam bypass to the ma in condenser during transient conditions.
Two branch lines from the main steam heater supply steam to the two second-stage reheaters per moisture separator. The steam for the two first-stage reheaters per moisture separator is supplied by extraction lines from the high pressure turbine (see Figure 10.3-1
). Moisture preseparator units remove moisture from the lower high-pressure turbine discharge exhaust steam as it exits the turbine.
The moisture separator/reheaters remove the moisture from the high-pressure turbine exhaust steam and superheat the steam prior to admission to the low pressure turbines, thereby improving overall cycle efficiency.
Extraction steam from the high pressure turbine is used in the first-stage reheater and for feedwater heating in heaters No. 5 and 6. Extraction steam from the low pressure turbines is used fo r the first, second, third, and fourth stage feedwater heaters.
Moisture separator/reheater relief valves are provided to prevent overpressurizing the moisture separator/reheaters and the crossove r lines in the event of crossover throttle or intercept valve closure; these relief valves discharge to the main
condenser.
The turbine generator is equipped with a digital electrohydraulic (DEH) control system. See Section 7.7.1.5 for a detailed description of the turbine control system.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-057 10.2-3 There are four methods of turbine overspeed control protection:
- c. Digital control overspeed trip, and d. Digital trip overspeed trip.
DEH Speed Control The DEH speed control is designed to maintain turbine speed within 2-3 rpm of setpoint during startup; after the turbine generator has been synchronized to the grid , the grid frequency controls turbine speed.
The DEH control system monitors turbine speed via three speed sensors. Upon detecting a sepa ration from the grid and a re sulting overspeed condition, the DEH speed control will rapidly close the governor valves via their servo-valves preventing an excessive overspeed c ondition from occurring.
Overspeed Protection Controller The OPC primary function is to avoid excessive turbine overspeed such that a turbine trip is avoided. At 103% of rated speed, the OPC solenoids open, rapidly closing the governor and intercept valves to arrest the overspeed before it reaches the tr ip setting. When turbine speed falls below 101%, turbine speed control is returned to the DEH speed control mode.
Digital Control Overspeed Trip, Digital Trip Overspeed Trip and Quadvoter Hydraulic Trip Block If the turbine accelerates further than 103% of rated spee d, the digital cont rol overspeed trip logic in the DEH control system will provide a trip signal that caus es the quadvoter hydraulic trip block to de-energize and trip the turbine. Additionally, the digital trip overspeed trip has three redundant speed sensors and will initiate an independent trip of the quadvoter hydraulic trip block. Both the digital c ontrol overspeed trip and the dig ital trip overspeed trip use two out of three overspeed logic to initiate the trip signal prior to reaching 111% of rated speed.
These signals cause the output module for the quadvoter to simultaneously de-energize, or trip, all of the quadvoter valves.
Redundant power supplies are auctioneered to assure loss of one power supply does not cause the quadvoter to trip. The quadvoter provides two channels, each with tw o solenoid valves in series, to depressurize the trip header and trip all the throttle, governor, intercept and reheat stop valves. The quadvoter design assures th at a single failure of a quadvoter valve will neither cause the turbine to trip nor prevent the turb ine from tripping if required. The DEH control system is designed to maintain th e turbine speed below 120% of rated speed.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-057 10.2-4 The quadvoter trip block assembly is a fail-safe design. Therefor e a loss of all power or a loss of all signals to the quadvoter solenoids would cause a turbine trip as all of the quadvoter solenoid valves would de-energi ze. The turbine overspeed control equipment and electrical wiring may be destroyed by a po stulated piping failure; however , this loss would result in a turbine trip based on th e fail-safe design. A missile may destroy the electromagnetic speed pickups and associated electrical wiring, but the turbine will still trip on loss of all speed probe signals. Missile damage to the hydraulic lines for the trip block asse mbly would result in a loss of high pressure fluid thereby depressurizi ng the trip header and causing a turbine trip.
The operation of the DEH control system is co ntinuously monitored du ring turbine generator operation. Detection of turbine speed variation is accomplished by the speed-control unit discussed in Section 7.7.1.5. The overspeed protection cont roller and two digital overspeed trips are tested during reactor startup from refueling outages. The turbine throttle, governor, interceptor, reheat stop valves and quadvoter solenoid valves are periodically tested during operation. Turbine throttle, governor, intercep tor and reheat stop va lves are periodically inspected. The manner and freque ncy of the inspection and testi ng will take into consideration the manufacturer's and others' recommendati ons and missile proba bility analysis (see Section 3.5.1.3) in conjunction with the plant generating requirements.
Instrumentation for the turbine generator is provided in the control room and is described in Section 7.7.1.5.
The turbine is equipped for norma l operations with a shaft-driv en lubricating oil pump and ac motor-driven lubricating oil pump for startup, shutdown, and turning gear, or for emergencies
whenever oil pressure falls below set pressure. The turbine is also provided with a dc motor-driven lubricating oil pump with power supplied from storage batteries for emergency operation.
The turbine shaft is supplied w ith "clean" (essentially nonrad ioactive) sealing steam which prevents outleakage of steam from the high-pressure turbine and inleakage of air to the low pressure turbines. An evaporator generates es sentially nonradioactive steam for turbine gland sealing (see Section 10.4.3).
Overpressure protection of the turbine exhaust hoods and the main condenser shell is provided by rupture diaphragms on the exhaust hoods.
The turbine incorporates prot ective devices including the exhaust hood relief diaphragms, exhaust hood temperature alarm, pilot dump valve for closing the extraction steam nonreturn valves, low vacuum alarm, thru st bearing wear alarm, and low bearing oil pressure alarm.
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-11-014 10.2-5 In addition, the following tabulation is a list of the turbine generator protective trips:
Mechanical Faults Electrical Faults
Low vacuum Generator power differential
Thrust bearing wear Generator underfrequency
Low oil pressure Genera tor differential current
Overspeed Generator stator ground
Manual Generator loss of excitation
Anti-motoring Genera tor negative sequence
Low DEH pressure Generator overcurrent during starting
Low EH (electrohydraulic) Genera tor stator ground during starting fluid level Generator overexcitation
Reactor high water level Generator/transformer overall differential
RCIC-V-13 and 45 open Manual
Moisture separator reheater shell side high level Unit lockout
Loss of DEH control power Unit overall lockout
Both Throttle Valves on a steam chest closed
The main steam throttle and govern or valves are located in the steam chest asse mbly which is parallel to the axis of the high pressure turbine. The nominal closure time for a fully open throttle or governor valve is 0.
15 sec. A failure of one governor valve causes the other valves to increase or decreas e their opening to compensa te for that valve. If one valve fails open at low load condition, the other valv es close. If the closing of th e other valves is not enough to compensate for that valve, the turbine load increases proportional to steam flow.
The reheat stop and intercept valves are in-line valves located in the crossover piping between the moisture separator/reheater and low pressure turbine. The closure time upon depressionization of the trip header for a fully open valve is 0.15 sec.
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 10.2-6 The valves described above are periodically tested as requi red by the Licensee Controlled Specifications (LCS) by using the DEH control system during power operation. Pressure variations caused by closing a governor valve cause the other governor valves to open.
Therefore, testing must be done at a reduced power level to provide sufficient margin for pressure control. Details of the pressure control syst em are discussed in Section 7.7.1.5. In addition, one of each valve will have its internals periodically inspected as required by the LCS.
Each of the extraction steam lin es has a reverse current valve and a gate valve, with the exception of the extraction lines to low pressure number 1 heaters. These valves are located near the condenser. On turbin e trip the reverse current valv es close immediately on reverse flow. Because of the fast cl osure and the short distance between these valves and the extraction points at the turbine, the amount of steam in thes e lines does not affect the turbine coastdown following a turbine trip.
10.2.3 TURBINE DISK INTEGRITY
Analysis of potential turbine missile hazards and drawings showing the orientation of the turbine with respect to important structures are presented in Section 3.5.1.3.
10.2.4 SAFETY EVALUATION
The steam entering the high pressure turbine ma y contain fission, c oolant activation, and activated corrosion products. The anticipated concentration of nitrogen-16, which is the dominant radionuclide entering the high pressu re turbine, is discussed in Section 12.2. Moisture separation and transit time between the high pressure and low pressure turbines reduces the concentration of ra dionuclides in the steam prior to entering the low pressure turbine. Most of the gaseous radioactivity is removed by the steam-jet air ejector and routed to the offgas system (see Section 11.3). The condensate in the condenser hotwell contains significantly less radioactive material than the inlet steam.
Access to the turbine area is controlled. Radiation levels associated with turbine components are described in Section 12.2 and shielding requirements are discussed in Section 12.3.
Acceptable Range for Control ValveNormal Closure Motion 950021.39 10.2-1 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.P = Initial Steam Flow, Percent Steam flow at Turbine Inlet - Percent of Initial Steam Flow Nuclear Boiler Rated T v = Actual Control Valve Full Stroke Closure Time (Slowest)
T 1 T 2 = (T v T 3 = (T v T 3 (T v-1.5)P(All Time Units in Seconds)
R = 100 -100 80 60 40 20 0 0 T 1 T 3 T 2Time After Start of Control Valve Normal Closure Motion (Sec)
Acceptable Region for Normal Closure of Turbine Control Valves R Columbia Generating StationFinal Safety Analysis Report Turbine Stop Valve Closure Characteristic 950021.40 10.2-2 Figure Amendment 53 November 1998Form No. 960690.veR.oN .warD 100 80 60 40 20 002.001.0 0 Time After Start of Stop Valve Closure Motion (Sec)
Turbine Inlet Steam Flow, Percent of Initial Steam FlowAcceptable Region forTurbine Stop Valve Closure Response Columbia Generating Station Final Safety Analysis Report Turbine Control Valve Fast Closure Characteristic 950021.41 10.2-3 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.100 80 60 40 20 0 0 TTime After Start of Control Valve Fast Closure Motion (Sec)
Acceptable Region forTurbine Control Valve Fast Closure ResponseTime, T in seconds is defined as the initial percent nuclear boiler rated
steam flow multiplied by 0.0008 sec.
Columbia Generating StationFinal Safety Analysis ReportTrubine Inlet Steam Flow, Percent of Initial Steam Flow Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-4 25 M957AC Turbine Generator Gas DiagramRev.FigureDraw. No.Amendment 62December 2013 Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-5 4 01-00,60AC Turbine Generator Gas Supply OutlineRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-6.1 16 M959Electrohydraulic HP Fluid and Lube Oil DiagramRev.FigureDraw. No.Amendment 61December 2011 Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-6.2 8 M960Electrohydraulic HP Fluid and Lube Oil DiagramRev.FigureDraw. No.
Form No. 960690ai LDCN-06-000 Columbia Generating StationFinal Safety Analysis Report 10.2-6.3 2 M959AElectrohydraulic HP Fluid and Lube Oil DiagramRev.FigureDraw. No.Amendment 61December 2011 Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-7.1 13 E520-1Turbine Generator Control Elementary DiagramRev.FigureDraw. No.
Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-7.2 32 E520-4Turbine Generator Control Elementary DiagramRev.FigureDraw. No.
Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.2-7.3 39 E520-5Turbine Generator Control Elementary DiagramRev.FigureDraw. No.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009,06-000 10.3-1 10.3 MAIN STEAM SUPPLY SYSTEM
10.3.1 DESIGN BASES
The main steam supply system is designed for the following conditions:
- a. Deliver steam from the reactor to th e turbine generator from warmup to 105%
of rated load, b. Provide steam for the second-stage reheaters and steam-jet air ejectors, c. Bypass steam to the main condenser during startup and in the event steam requirements of the turbine generator are less than that prod uced by the reactor,
- d. Provide steam to the gland seal stea m evaporator during startup, low load operation, and shutdown,
- e. Provide steam to drive reactor feed water pumps during startup and low load operation, and
- f. Provide steam to the offgas preheaters.
The design pressure and temperature of th e main steam piping is 1250 psig and 575°F.
The main steam lines are designed to include ac cesses to permit inservice inspection and testing (refer to Sections 5.2.4 and 6.6).
Design codes are given in Table 3.2-1, item 2, Nuclear Boiler System, and item 43 , Power Conversion System. The envir onmental design bases for the ma in steam supply system are contained in Section 3.11.
10.3.2 SYSTEM DESCRIPTION
The main steam supply system is shown in Figures 10.3-1 and piping drawings are shown in Figures 3.6-32 , 3.6-33 , 3.6-34 , 3.6-35 , 3.6-50 , 3.6-51 , 3.6-53 , 3.6-58 , 3.6-60 , and 10.3-2. The main steam line piping consists of four 30-in. (26-in. in reactor building) lines extending from the reactor pressure vessel to the main steam header located upstream of the turbine stop and control valves. This head er placement ensures a positive means of bypassing steam via the turbine bypass system during transient conditions and startup. Branch lines from the main steam line provide the steam requirements for the reactor feed pumps, second stage reheaters, gland seal steam evaporator, offgas preheaters, and steam jet air ejectors.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.3-2 The MSIVs are a wye-pattern-type globe valve utilizing pneumatic air to open and spring load with pneumatic air assist to cl ose. Energizing control valves provide pilot and actuator air to open the valve. Deenergizing the control valves removes pilot air which vents actuator opening air and directs air to assist the spring force in closing the valve.
Loss of compressed air fa ilure mode results are a. Loss of compressed air due to loss of nonseismic air lines
- results in loss of pilot air and closure of the MSIV by both spring force and pneumatic air cylinder force.
- b. Loss of compressed air due to loss of Seismic Category I air lines f results in loss of both pilot air and actuator air with the MSIVs closing by spring force only.
Under normal operation the air supply maintain s the required air for holding the valve open and charging the air storage tank. The check valve at the ai r storage tank inlet ensures a pneumatic supply for assist in cl osing the valve. No safety-related make up supply is required for closure of the MSIVs for safe plant shutdown.
The removal of electrical power or failure of both the solenoids on the control valve automatically initiates closure of the MSIVs. Safety-related components ensuring removal of power to the solenoids when required are the only electrical power requirement. Section
9.3.1 describes
the compressed air systems.
Equalizing lines connecting steam lines outside of the containment are used to equalize pressure across the main steam line isolation valves prior to restart following a steam line isolation. Assuming all steam lin e isolation valves have closed, the outer containment isolation valves are opened first and the drain lines ar e used to warm up and pressurize the outside steam lines. Following warmup the inboard main steam line is olation valves are opened.
10.3.3 SAFETY EVALUATION
Table 3.2-1 lists the applicable seismi c category, quality group classi fication, and safety class for the main steam supply system. The effects of main steam line breaks and other accident conditions outside the containment are evaluated in Chapter 15. Protection against dynamic effects associated with the postulated rupture of piping inside or outsi de of containment is discussed in Section 3.6.
- Nonseismic lines are those lines supplying air to the isolati on valve upstream of the check valve and to the pilot side of the air pilot valves (Figure 9.3-1 , detail B).
f Seismic Category I lines include an air storag e tank, check valve, a nd lines from the check valve to the actua tor pilot valve (Figure 9.3-1, detail B).
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.3-3 10.3.4 INSPECTION AND TESTING REQUIREMENTS
The main steam lines were hydros tatically tested prior to initial operation. Nondestructive testing is performed in accordance with the applicable code requirements.
Preoperational and inservice inspection of th e main steam lines a nd the main steam line isolation valves are presented in Sections 5.2.4 and 6.6. The use of four main steam lines permits inspection and testing of the turbine stop, control, reheat stop, and intercept valves and main steam line isolation valves during plant operation with a minimum of load reduction.
10.3.5 WATER CHEMISTRY
This section is not applicable to a BWR. See Section 10.4.6 for reactor coolant water chemistry considerations.
10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS
10.3.6.1 Fracture Toughness
Impact tests in accordance with the size limitations specified in ASME Code Section III, Class 1, are performed on all ASME Code Section III, Class 1, main steam and feedwater materials, as well as Class 2 main steam system materials for all pressure retaining ferritic steel parts. The tests are conducted at a temperature of 45°F or lower in accordance with NB or NC-2310 of the Summer 1972 or Winter 1973 Addendum of ASME Code Section III, as applicable.
10.3.6.2 Materials Sel ection and Fabrication
All materials used for portions of the main steam system describe d in this section are included in Appendix I to Section III of the ASME Boiler and Pressure Vessel (B&PV) Code. The requirements for welding the main steam piping from the reactor to the turbine generator are in accordance with ASME Section III, 1971 Edition through the Winter 1973 Addenda. The welding requirements for other steam and feedwater piping are in accordance with ANSI B31.1, Oct ober 1973 (see Section 3.2).
Cleaning of components in the main steam sy stem is in accordance with ANSI N45.2.1 (October 1973) or ASTM A380-57 (October 1973) for stainless st eel surfaces and Regulatory Guide 1.37.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.3-4 Degree of conformance to the following Regul atory Guides is a ddressed in Section 1.8: 1.31, Control of Stainless Steel We lding; 1.36, Nonmetallic Ther mal Insulation for Austenitic Stainless Steel; 1.44, Control of the Use of Sensitized Stainless Steel; 1.
50, Control of Preheat Temperature for Welding of Low-Alloy Steel; a nd 1.71, Welder Qualification for Areas of Limited Accessibility.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.3-1.1 38 M502-1 Main Steam Supply SystemRev.FigureDraw. No.Amendment 62December 2013 Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.3-1.2 29 M502-2 Main Steam Supply SystemRev.FigureDraw. No.
Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.3-1.3 19 M502-3 Main Steam Supply SystemRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.3-2 103 M529 Main Steam Supply System PipingRev.FigureDraw. No.Amendment 62December 2013 C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-014 10.4-1 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM
10.4.1 MAIN CONDENSER
10.4.1.1 Design Bases
The purpose of the main condenser is to provide a heat sink for condensing the turbine exhaust steam, turbine bypass steam, reac tor feed pump drive turbine exhaust steam, and to provide a receiver for miscellaneous drains. It also provides deaeration, noncondensable gas removal, and storage of condensate, whic h is returned to the condens ate system after a period of radioactive decay.
The main condenser is designed for the following conditions (a pproximate values):
- a. Duty 7.7 x 10 9 Btu/hr b. Circulating water flow 555,600 gpm c. Circulating water inlet temperatures 78°F
- d. Circulating water outlet temperatures 106°F
- e. Total steam condensed 8,128,700 lb/hr f. Total condensate outflow 15,017,000 lb/hr g. Outlet temperature of condensate 105.0°F h. Condenser pressure (triple) 2.4 in Hg abs (average) i. Cleanliness factor 85%
- j. Number of passes 1
- k. Air inleakage flow rate limit 50 scfm
- l. Hotwell storage capacity 163,000 gal
The main condenser is designed to accept a maximum of 25% of the rated reactor steam flow from the turbine bypass system (described in Section 10.4.4) plus 75% of the rated reactor steam flow through the turbine. This steam flow is accommodated without increasing the condenser backpressure to the tu rbine trip setpoint or exceedi ng the allowable turbine exhaust temperature.
The main condenser is designed to deaerate th e condensate and provide an oxygen content in the hotwell condensate betw een 30-100 ppb per liter over the entire load range.
Feedwater quality is maintained by the condensate filter demineralizer system described in Section 10.4.6.
The condenser hotwell is designed to contain the condensate that is required during 5 minutes of full power operation of the turbine. Ba ffling in the hotwell provides a minimum of
3 minutes condensate hold-up time wh ich permits the decay of shor t-lived radioactive isotopes.
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-014 10.4-2 Condenser construction is desi gned in accordance with requireme nts of the Heat Exchange Institute, Standards for Steam Surface Condensers (October 1971
). Construction of condenser module bundle replacement is designed in accordance with the Tenth Edition.
The piping associated with the condenser is designed, fabricat ed, inspected, a nd erected in accordance with ANSI B31.1 (October 1971). Seismic category, safety class, and design codes are discussed in Section 3.2.
10.4.1.2 System Description
Steam from the low-pressure turb ine is exhausted directly downward into the condenser shells through exhaust openings in the bottom of th e turbine casings and is condensed. The condenser serves as a heat sink for several other flows, such as exhaust steam from the reactor feedwater pump turbines, cascading feedwater h eater drains, air eject or condenser drains, gland seal steam condenser drain, feedwater heater shell ope rating vents, turbine gland seals, and the offgas preheater drains.
Other flows to the condenser originate from the startup vents of the condensate pumps, the reactor feedwater pumps, condensate booster pumps, the condensate pumps, feedwater line startup flushing, reactor feedwater pump turbin e drains, low-point drai ns, condensate makeup, reactor water cleanup (RWCU), a nd feedwater heater dumps or drains. All high temperature drains into the condenser shell have impingement baffl es or spray pipes to prevent the steam and entrained water particles from impinging on the surface of the tubes. Stainless steel lagging is provided where require d to protect other condenser components. The bypass valves are described in Section 10.4.4.2.
During transient conditions, the condenser is designed to receive turbine bypass steam and feedwater heater and drain tank high-level discharges. The condenser is also designed to receive relief valve discharges from moisture separators, feedwater heater shells, steam seal regulators, and various steam supply lines.
The condenser is cooled by the circulating water syst em described in Section 10.4.5. Air inleakage and noncondensable ga ses are removed by the main condenser evacuation system described in Section 10.4.2. Before leaving the condenser, the condensate is deaer ated to reduce the level of dissolved oxygen.
10.4.1.3 Safety Evaluation
During operation, radioactive steam , gases, and condensate are pres ent in the shell of the main condenser. The inventory of radioactive contaminants duri ng operation is discussed in Section 12.2.1.2.2.7. Shielding for and controlled access to the main condens er is provided in C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-014 10.4-3 Chapter 12. The means of controlling a nd detecting the leakage of this radioactive inventory in and out of the main condens er is discussed in Sections 11.3 and 11.5.2.2.
Hydrogen is generated by radiolysis in the reactor and injected by the Hydrogen Water Chemistry system.
Hydrogen generation buil dup during operation is prevented by continuous evacuation of the main condenser by the air re moval system (see Section 10.4.2) and the offgas system (see Section 11.3.2). The radiolytic decompos ition rate at rated power is 102 scfm of hydrogen and 51 scfm of oxygen. Hydrogen is introduced into the condensate
/feedwater system to mitigate intergranular stress corrosion cr acking (IGSCC). The addition of hydrogen into a feedwater system results in reduced radiolysis. The net hydrogen in the steam during Hydrogen Water Chemistry (HWC) is less than during norma l water chemistry (NWC) (without hydrogen injection). During plant shutdown, there are no hydrogen sources to the condenser. Hydrogen injection is shut down whenever the reactor is shut down.
The inadvertent introduction of hydrogen to condensate/feedwate r, from HWC, during extended shutdowns is prevented by isolation of the hydrogen supply, and purging the hydrogen injection system with nitrogen.
The main condenser is not required for safe shutdown of the reactor and does not perform safety functions. However, de gradation of the condenser in the form of a leak, loss of circulating water, or air ejec tor malfunction could lead to a loss of condenser vacuum which removes the effective ability of the condenser as a heat sink.
As a consequence, loss of vacuum provides a main steam isolati on valve closure signal. See Section 7.3.1.1.2 for a further description. Due to the distance of th e main condenser from sa fety-related equipment areas, there will be no damage to necessary safe shutdown equipment from flooding caused by
failure of the condenser.
Exhaust hood overheating protection is provided by sprays located downstream of the last-stage blades of the turbine.
Loss of main condenser vacuum causes the turbine to trip. Should the turbine stop valves, control valves, or bypass valves fail to close on loss of condenser vacuum, rupture diaphragms on each turbine exhaust connection to the condenser protect the condenser and turbine exhaust hoods against overpressurization.
In this event, steam would exhaust to the turbine building.
The main condenser is constructed with titanium tubes and the tubesheet is titanium clad carbon steel. Corrosion protection of the wett ed carbon steel water box es, inlet and outlet valves, and circulating water piping is being performed by a combination of a high quality coating, the use of stai nless steels, and sacrifi cal anodes. The sacrific al anodes attach to the wall of the water boxes and will pr ovide protection in case of a ny coating breaches or coating failure. All small bore nozzles on the circulatin g water side penetrati ng the water box 4 inches and less are of stainless steel.
The water box coating will wrap into these connections to
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-014 10.4-4 prevent any carbon steel exposure.
Isolation kits will electrica lly isolate any attached drain piping to help minimize a ny stray current corrosion.
10.4.1.4 Tests and Inspections
The condenser shell received a field hydrostatic test prior to initial operation. This test consisted of filling the condenser shell with water, and inspec ting the entire tube sheet and shell welds and surfaces for visible leakage and/or excessive deflection.
The condenser module bundle repla cement final test for tube or joint leakage was performed using a vacuum-bubble leak test.
During normal plant operation, the followi ng parameters are routinely monitored:
- a. Condenser vacuum,
- b. Conductivity, and
- c. Condensate temperature.
Any divergence from established limits for thes e parameters requires an investigation and testing as necessary to determine the extent of the divergence and correct the problem.
10.4.1.5 Instrumentation
The condenser shell is provided with local and remote hotwell le vel and pressure indication.
The remote indication is by means of indicators and alarms in the main control room. The condensate level in the condenser hotwell is maintained with in proper limits by automatic controls that provide for transf er of condensate to and from the condensate storage tanks as needed to satisfy the requirements of the steam system. Condensate temperature is measured in the outlet line of the condensate pumps.
Turbine exhaust hood temperature is monitored and controlled with water sprays to provide protection from exhaust hood overheating.
A main condenser low vacuum alarm is provide
- d. Automatic turbine trip is activated on continued loss of main condenser vacuum followed by main steam isolation valve closure on further degradation of conde nser vacuum. See Section 7.3.1.1.2 for a further description of main steam isolation.
Water box pressure and temperatur e measurements are provided.
Circulating water inleakage to the main conde nser is monitored by conductivity elements located in the tube sh eet troughs, in the condenser outle t line, and at the condensate pump discharge line (alarm in the main control room). Conductivity of the condensate demineralizer
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 10.4-5 influent is monitored and alarmed in the radwaste control room.
A conductivity/chemical species sampling and measurement system is available for characterizing inleakage. Leakage is controlled (prevented) to the exte nt possible by maintaining chemistry control in the circulating water to provide optimization between scale fo rmation and corrosion.
Tube leakage can be corrected by isolating and draining the tube sect ions containing leaking tubes and then locating and plugging the leaking tube.
10.4.2 MAIN CONDENSER EVACUATION SYSTEM
10.4.2.1 Design Bases The main condenser evacuation system removes ga ses from the turbine generator, the reactor feedwater pump turbines, and the main condenser during plant startup and maintains the condenser essentially free of nonc ondensable gases duri ng operation. This system handles all noncondensable gases wh ich may enter the main turbine and reactor feed pump turbines through their seals, the condensate piping, or whic h is generated by dissoci ation of water in the reactor. The main condenser evacuation system discharges to the offg as system through the steam jet air ejectors during normal operation (see Section 11.3).
The piping system associated with the main condenser evac uation system is designed, fabricated, and erected in acco rdance with ANSI B31.1 (October 1971). The air removal equipment is designed in accordance with the standards for Steam Surface Condensers, published by the Heat Excha nge Institute (October 1971).
10.4.2.2 System Description
The main condenser evacuation system include s, for normal operation, two 100%-capacity steam jet air ejector units. Each unit consists of a twin-element first-stage steam jet air ejector and a single-element second-stage, steam jet air ejector which discharges to the offgas system.
The capacity of each steam jet air ejector unit is 663 scfm at 70°F tota l equivalent of mixed gases and vapor at 1-in. Hg absolute. The main condenser design air inleakage flow rate is 50 scfm.
Two mechanical vacuum pumps are provided for hogging operation during startup (see Figure 10.4-1). During startup, both mechanical vacuum pumps can be used to rapidly remove air and noncondensable gases from the main condenser.
The discharge from the vacuum pumps is routed with the gland seal st eam exhauster discharge to the reactor building elevated release duct. Because the reactor power is low, a minimal amount of activity is discharged to the environment. A radiation detector monitors the discharge and isolates the vac uum pumps when the radiation le vel exceeds established limits.
The vacuum pumps operate until suff icient steam pressure is availa ble to start the steam jet air ejector.
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 10.4-6 The source of steam to operate the steam jet air ejector is taken from the main steam header branch line, with steam pressure being regulated by the steam jet air ejector control valves. Air inleakage, noncondensable gase s, as well as entrained wate r vapor, are removed from the main condenser by the first stage of the steam jet air ejector.
The gas-vapor mixture is then discharged into the ejector conde nser where the vapor is conden sed. The resulting condensate is drained back to the main condenser via a l oop seal. The ejector condenser is cooled by the condensate discharge from th e condensate pumps. The noncondensing second stage of the steam jet air ejector removes the noncondensable gases and some entrained vapor from the ejector condenser and exha usts them to the offg as system (see Section 11.3). The offgas system processes the noncondensable ga ses and limits the re lease of radioac tive gases to the environment.
10.4.2.3 Safety Evaluation
The main condenser evacuation system is not safe ty related. Consequen tly, the system is not designed to Seismic Category I re quirements. Safety class and design codes are presented in Section 3.2.
The radionuclides in the effluent from the steam jet air ejector unit have been evaluated in Section 11.3.
The offgas from the main conde nser contains hydrogen gas from dissociation of water in the reactor and from hydrogen injection. In the se cond-stage steam jet air ejector, sufficient steam is provided to dilute the hydrogen content to less than 4% by volume to keep the mixture below flammability limits.
10.4.2.4 Tests and Inspections
The mechanical vacuum pumps and the steam jet air ejectors were cleaned, inspected, and tested at the vendors' plant. System preoperational test s as described in Chapter 14 were successfully performed after in stallation. Main condenser evacuation system monitoring during normal operation along with routine maintenance and inspection ensures proper functioning and performance in accordance with its design bases.
Instrumentation permits the operators to monitor system performance dur ing operation.
10.4.2.5 Instrumentation A radiation monitor is installed in the air removal piping discharge to the reactor building elevated release duct (a common exhaust line to the mechanical vacuum pumps and the gland seal steam condenser exhaust). A high-radiation signal from the monitor will trip both mechanical vacuum pump motors: The trip causes the suction and discharge valves to close and trips the mechanical vacuum pump seal water pumps. The vacuum pump is equipped with instrumentation to ensure proper operation (Figure 10.4-1
).
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December2005 10.4-7 A main steam line radiation monitor (MSLRM) hi gh-radiation signal also trips both mechanical vacuum pump motors. The signa l will also trip both gland se al steam condens er exhauster motors (see Section 11.5.2.1.1
). Low steam flow to the second-stag e air ejector causes a signal to close the inlet gas valves to the first-stage air ejector. Stea m pressure indicators for the fi rst- and second-stage ejectors and a steam flow indicator for the second-stage ej ector are provided in the main control room.
10.4.3 TURBINE GLAND SEALING SYSTEM 10.4.3.1 Design Bases
- a. The turbine gland sealing system preven ts air leakage into, or radioactive steam leakage out of, the main turbine and reactor feedwater pump turbines; and
- b. The turbine gland sealing system is designed to provide nonradioactive (clean) sealing steam, at all loads, to the turbine shaft glands and valve stems (main stop, control reheat stop, intercept, and bypass valves
). The condensate from the gland seal steam condenser is returned to the main condenser, and the noncondensable gases (inleak ing air) are exhausted to the reactor building elevated release duct.
The turbine gland sealing system is in strict conf ormance with the latest edition in effect at the time of fabrication of the applicable ANSI, AS ME, and IEEE standards.
The major portion of manufacture was performed during 1975. The gland seal steam evaporators are designed, fabricated, inspected, te sted, and stamped in accordance with Section VIII of the ASME Boiler and Pressure Vessel (B&PV) C ode and the Standards of the Tubular Exchanger Manufacturers Association, Class R (May 1972). Seismic category, safety class, and design codes are provided in Section 3.2.
10.4.3.2 System Description
The turbine gland sealing system consists of tw o 100%-capacity gland seal steam evaporators, seal steam pressure regulators, seal steam header, gland se al steam condens er, exhauster blowers, and the associated piping, valves, and inst rumentation (see Figures 10.3-1 and 10.4-2). Sealing steam for turbine shaft seal glands and valve stem seal gl ands (stop, control, reheat stop, intercept, and bypa ss valves) is supplied from the se al steam header at 200 psig.
The source of sealing steam is from the gland seal steam evaporators or the auxiliary steam boiler. The sealing steam is produced in an evaporator which is heated by extraction steam taken from the high pressure turbine. The condensate fed to the evaporator is taken from the suction header of the reactor feedwater pumps in the feedwater system. During startup and low load operations, a branch line taken off the main steam header supplies the necessary heating steam for the evaporator.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December2005 10.4-8 Separate seal stea m regulators are provided to re gulate th e pressure of sea ling steam for the high pressure turbine, each low pressure turbine, each reactor feed pump turbine shaft seal, the bypass valve assembly, and the main stop and control valve assembly stems.
Since the low pressure (LP) tu rbine and reactor feedwater pump turbine exhaust pressures are at a vacuum, sufficient sealing steam is supplied to maintain positive pressu re in the glands to prevent air inleakage along the shaft. The high pressure (HP) turbine exhaust pressure varies with load and is approximately 177 psia at its maximum. The sy stem is designed to maintain the seal steam supply to the HP turbine glands at a pressure of 16 to 20 psi above HP turbine exhaust to prevent HP turbine exhaust steam leakage through the shaft gland seal.
The main stop, control, and by pass valve stems are provided with an intermediate zone to which sealing steam is supplied. This nonradio active steam leaks in bot h directions, towards the HP stem leakoff and towards the LP stem leakoff. The HP stem leakoff contains radioactive steam and is directed to an LP feedwater heater. The LP steam leakoff is nonradioactive and is sent to the gland seal st eam condenser. The reheat stop and intercept valve stems are supplied with sealing steam at a pressure greater than the crossove r pressure so that any leakage that occurs is into the crossover pipes.
The reactor feedwater pump turbines at the high pressure end are provided with sealing steam at an intermediate point in the turbine gland seal. This nonradioactive steam leaks in both directions, towards the HP end leakoff and to wards the LP end leako ff. The HP leakoff contains radioactive steam and is directed to the sixth stage of the turbine. The LP steam leakoff is nonradioactive and is se nt to the gland seal steam c ondenser. Sealing steam for the reactor feed pump turbine LP stop valve, HP st op valve, and control va lve is provided in a similar manner.
The outer leakoff of all glands is routed to th e gland seal steam condens er which is maintained at a slight vacuum by the exha uster blower. During plant oper ation, the gland seal steam condenser and one motor-driven blower is in operation. The exhauste r blower discharges gland air inleakage to the atmosphere via the reactor building elevated release duct. The gland seal steam condenser is cooled by the main condensate flow.
The steam evaporator is a shell-and-tube heat exchanger designed to provide a continuous supply of clean sealing steam to the seal steam header.
10.4.3.3 Safety Evaluation
The turbine gland sealing syst em is not safety related.
A supply of clean steam is al ways available from either of two 100%-capacity steam evaporators or the auxiliary steam boiler. Should the steam packing exha uster fail to function, C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-9 the sealing steam would continue to flow into the turbine and would be the only steam that could flow out of the glands and into the turbine building. Therefore, no reactor steam would be released to the environment.
A radiation monitor in the discharge of the blower alerts the operator to tube ruptures in the gland seal steam evaporator or other system ma lfunctions. Sealing system radioactive releases are discussed in Section 11.3.
Relief valves in the seal steam system prevent excessive steam pressure. The valves vent to the condenser and atmosphere.
10.4.3.4 Tests and Inspection
Prior to installation at the site , the gland seal steam evaporator and gland seal steam condensers were cleaned, inspected, and test ed at the vendor's plant. Pr eoperational testing of this equipment included a hydrostatic test for visual inspection of welded joints to confirm leaktightness. The turbine gla nd sealing system is regularly inspected and monitored during operation to ensure proper f unctioning and performance in accordance with its design bases.
10.4.3.5 Instrumentation
The level in both the shell a nd tube sides of the steam evaporator are controlled by level-control valves: the condens ate (shell) side by ma intaining the water level surrounding the tubes and the steam side by maintaining the water level in the steam ev aporator drain tank.
The flow of heating steam is regulated by the steam pressure control valve.
Liquid level in the gland seal st eam condenser is maintained by a trap connected to the main condenser. A local pressure indicator and high-level alarm switch are provided on the gland seal steam condenser. Temper ature and pressure gauges and test points are provided to monitor operation and testing of the system.
Instruments for monitori ng system operation are provided in the main control room. Low and hi gh level alarms are prov ided on the gland seal steam evaporator.
10.4.4 TURBINE BYPASS SYSTEM
10.4.4.1 Design Bases
- a. The turbine bypass system controls reactor steam pressure by sending excess steam flow directly to the main condenser. This perm its independent control of reactor pressure and power during reactor vessel heatup to rated pressure prior to and while the turbine is brought up to speed and synchronized under turbine speed-load control and when cooling down the reactor. Following main turbine generator trips and during power operation when the reactor steam generation
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-057 10.4-10 exceeds the transient turbine steam requirements, the turbine bypass controls reactor overpressure within its capacity and in accordance with the steam generation rate;
- b. The turbine bypass system capacity is 25% of rated reactor steam flow. The bypass system can accommodate a 25% turb ine load rejection without causing a significant change in reactor steam flow; and
- c. The turbine bypass valv es are capable of re mote manual operation.
10.4.4.2 System Description
The turbine bypass system consists of four hyd raulically operated control valves which are mounted on a valve manifold (see Figure 10.4-3
). They are connected to the main steam line header upstream of the turbine main stop valves by four 10 in. lines. The four individual valves lower the pressure of the steam by reduc ing its flow velocity before it enters the condenser system.
Each valve outlet discharges into the manifold which is piped directly to pressure-reducing perforated pipes located in the condenser shell (see Figure 10.3-1
).
The turbine DEH control system is designed to prevent spurious or unnecessary opening of the bypass valves, due to control signal noise or minor transients. The four valves in the manifold are operated automatically by the control system. The amount of steam flow allowed to pass through the turbine is limited by the DEH control system demand signal, which limits the amount that the governor valves can open. Th e DEH control system controls the governor valve position to maintain react or pressure. When the gove rnor valve opening position, required to maintain reactor pressure, exceeds the load demand limit, a signal is sent to the bypass valves to open to maintain reactor pressure. The bypass valves automatically trip closed whenever the vacuum in the main condenser is greater than approximately 23 in. Hg absolute. They have regulation capability and a fast-opening re sponse approximately equivalent to the fast closure of the turbine stop and control valves.
The turbine bypass system piping and valves ar e designed to the cla ss and seismic category presented in Table 3.2-1. The valve body is forged car bon steel while the internals are stainless steel. The environm ental design bases for this system are contained in Section 3.11.
Each valve is sized for 8% of the total rated flow; however, all four valves are designed for 25% of the total flow. If the bypass system cap acity is exceeded, the ma in steam relief valves open on high reactor pressure and excess steam is vented to the suppression pool.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-11 10.4.4.3 Safety Evaluation The effects of a malfunction of the turbine bypass system valves and the effects of such failures on other systems and component s are evaluated in Section 15.2.2.
All safety-related compon ents and the turbine speed control system are located remote from the turbine bypass piping and valves. The bypass sy stem is located on th e second floor of the turbine building (see Figure 1.2-3) and the speed control and safety-related components are located on the floor above, thus being sepa rated by a concrete fl oor and wall making any adverse affects from a high-energy line failure in the turbine bypass system extremely unlikely. The turbine overspeed protection system is a fail-safe design, as described in Section 10.2.2.
The effects of a steam line break on the safety-related components in the turbine building are discussed in Section 3.6.1.
10.4.4.4 Tests and Inspections
The opening and closing of the turbine bypass system valves were checked during initial startup and shutdown for perfor mance and timing. The bypass steam lines upstream of the bypass valves to MS-V-146 were hy drostatically tested to conf irm leaktightness. Radiography and visual inspection of all pipe weld joints were performed on this piping. The branch connections and branch lines of this piping were examined in accordance with ANSI B31.1 rules.
Each turbine bypass valve can be tested independently and remotely dur ing plant operation.
The testing is conducted as require d by the Technical Specifications.
10.4.4.5 Instrumentation
The controls and valves are designed so that the bypass valves shut on loss of control system electric power or hydraulic pressure. For testing the bypass valves during operation, the stroke time of the individual valves is increased during testing to limit the rate of bypass flow increase and decrease to approximately 1% per sec of reactor rated flow. Upon turbine trip or generator load rejection, the st art of bypass steam flow is not de layed more than 0.1 sec after the start of the stop valve or the control valve fast closure motion. A minimum of 80% of the rated bypass capacity is establishe d within 0.3 sec after the start of the stop valve or the control valve closure motion. For mo re detail refer to Section 7.7.1.5.
C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-031 10.4-12 10.4.5 CIRCULATING WATER SYSTEM
10.4.5.1 Design Bases
The circulating water system is designed to pr ovide cooling water for the condenser using the atmosphere as a heat sink via si x circular mechanical-induced dr aft cooling towers designed to remove 7.962 x 10 9 Btu/hr from the circulating water.
The design heat gain in the condenser is approximately 7.7 x 10 9 Btu/hr. In addition, the cooling towers have the capacity to cool the plant service water during normal operation and the standby service water during shutdown operation. The operation of the towers is not essential to the safety of the plant.
Makeup for tower evapora tion, wind loss, and blowdown is obtained from the Columbia River by makeup pumps. Cooled blowdown from the cooling towers is discharged to the river.
Chemical treatment is provided for the circulat ing water system to preclude scale, biological growth, and consequent fouling of heat transfer surfaces.
The piping system associated with the circulating water system is designed, fabricated, inspected, and erected in acco rdance with ANSI B31.1 (Oct ober 1973) and AWWA C201.
Major piping components are fabricated from carbon steel.
Seismic category, safety classification and design c odes are given in Section 3.2.
10.4.5.2 System Description
The circulating water system is shown schematically in Figure 10.4-4. The circulating water system is a closed cycle cooling system using six mechanical induced draft, cross-flow cooling towers. Three circulating water pumps, each having a total head of 95 ft at 186,000 gpm, are provided. These pumps, located in the circulat ing water pump house, take suction from a common intake plenum and disc harge through a common 12-ft-d iameter pipe to the three waterboxes of the single-pass trip le-pressure zone condenser. Th e water from the condenser is returned to the cooling towers, cooled, and collected in the cooling tower basins which supply the circulating water pumps intake plenum.
In addition, as part of the cooling tower piping, a cooling tower bypass is provided for plant startup during the winter to prevent icing conditions at the towers. Inlet motor-operated valves are provided at each tower to isolate a tower for maintenance.
The towers are designed such that the buildup of ice will not re strict air flow through the louvers. Temperature range and low water temperature limits are maintained during reduced heat loads by shutting down individual towers (fans and flow) as required. In extreme cold weather, desired cold water temperatures can be achieved with all fan motors shut down but free to rotate with natural draft through the towers.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-13 The six mechanical draft cooling towers are located such that there can be no physical interaction between them and plant structures important to safety in the unlikely event of a tower collapse.
The quantity of makeup water to the system is dependent upon co oling tower evaporation, drift losses, and system blowdown re quirements. The system blowdown quantity is dependent on the concentration of dissolved solids allowed in the circulating water. The concentration of dissolved solids varies with operating status and the cycles of concentration which are controlled by operation of the bl owdown valve. Makeup to the circulating water system is provided via the cooling tower makeup pumps located in a pump house adjacent to the Columbia River. The makeup pumps are designed to pump 12,500 gpm each with a TDH of 204 ft; the makeup flow can be directed into the circulating water bay or to one or both of the plant service water pump suctions by means of a weir box and sluice gate arrangement located in the circulating water inlet bay.
The evaporative-type cooling towers have the potential for crea ting visible plumes of water vapor under certain atmospheric conditions. The cooling tower system is designed to keep this environmental impact minimal. The cooling tower plumes rare ly produce ground level fog or ice in the basin area where the plan t is located and do not restrict traffic at the local airports.
Since fogging occurs naturally in the area, the es timated incremental occurrences of fog attributable to cooling tower operations are small compared to the natural occurrences.
Cooling tower drift has been identified as a cause of arcing in switchyard equipment.
Switchyard equipment is monitore d and cleaned (as necessary) to preclude this phenomenon. Offsite environmental effects are monitored per Section 4.2.1 of the Environmental Protection Plan.
The radiological impact and the impact of thermal discharges on the environment are insignificant. The effect of cooling tower blow down has no significant effect on the Columbia River temperature, and the environmental effect of chemical discharges is considered negligible. The system has no measurable effect on area groundwater.
The environmental considerations mentioned above are discussed in detail in Chapter 5 of the Environmental Report - Operating License Stage.
10.4.5.3 Safety Evaluation The circulating water system is a non-safety-rel ated system. Conseque ntly, the circulating water system is not designe d to Seismic Category I re quirements. See Section 9.2.5 for a description of the ultimate heat sink which is designed to perform safety-related functions.
The condenser design ensures that the pressure on the tube side is al ways maintained higher than the pressure on the shell si de, thus eliminating leakage into the circ ulating water system C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-14 should tube failure occur. C onsequently, the design of the ci rculating water system precludes radioactive leakage into the system. Chemicals used to treat the CW system to preclude scale and biological growth and to control pH are evaluated in accordan ce with administrative controls to ensure compatibility with systems and components.
Two evaluations were performed to determine the effects of a postulated failure in the circulating water system inside the turbine bui lding: a "realistic ev aluation" and a bounding evaluation. For the "realistic evaluation," a m oderate energy crack was postulated to occur in the circulating water system barriers (e.g., the r ubber expansion joints) at the inlet to the main condenser. The inlet side was se lected because it yields the se verest results. For the bounding evaluation, a complete circumferentia l expansion joint break was assumed.
The entire condenser area is dr ained by means of sumps (see Figure 9.3-9
), each equipped with duplex pumps. Sumps T-2 and T-3, servici ng the inlet and outlet of the condenser, each have 50 gpm pumps. Each of these sumps is equipped with a level alarm and is therefore capable of detecting a circulati ng water system barrier failure.
The level alarm will annunciate in the main control room upon reaching high level, providing a m eans of detecting the postulated failure within 5 minutes.
"Realistic" Break
The crack area for this postulated failure was assumed to be equal to one-half the pipe diameter times one-half the pipe wall thickness.
A d x t=22 (see Section 3.6.2.1.4.2)
The flow exiting from such a crack would be an orifice flow. The head at expansion joint for normal three-pump operation at 186,000 gpm each was determined (from system energy gradients) to be 90 ft. The flow for these conditions was calculated to be
Q = 1737 gpm
The system has different operati ng pressures for the various m odes of pump operation. The piping was designed for an internal pressure of 60 psig, which is well above the design energy gradient.
The motor-operated inlet and outle t valves at the condenser ar e designed and manufactured to close in 60 sec to avoid excessive pressures caused by fast valv e closure. Therefore, rapid valve closure is not a consideration. After closure of the inle t and outlet valves, however, the system will be operating with two-thirds of the condenser cap acity. With three circulating water pumps in operation and two sections of the condenser in operation, the system flow as determined from the pump operating point diagram will be approxi mately 450,000 gpm.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-15 Comparing the system en ergy gradients for this mode of operation to that when all three condenser units are in operation, the re sultant difference in pressures will be
- a. At the inlet side, an increase of approximately 4.3 ft of head (2 psi) occurs, b. At the outlet side, a d ecrease of approximately 5.2 ft of head (2 psi) occurs.
Detection of the postulated failure will occur within 5 minutes, as described above, by the annunciation in the control room of the sump high level alarm. It is assumed that there will be a 15-minute time allowance for an operator in the control room to check the circulating water system barriers and close both the inlet and outle t valves of one unit of the condenser as may be required. This closure is accomplished by the activation of a remote manual switch in the control room, and therefore no control circuitry time delays nor coastdown times are involved. Flow will continue, however, after valve closure for about 106 minutes at a decreasing rate, until the remaining water from the c ondenser is comple tely discharged.
In the first 5 minutes after a crack, 8435 gal of wa ter will spill into the inlet basin. The capacity of each basin and its capability to store excess flow were calculated to be as follows:
- a. Inlet basin: 22,500 ga l from el. 436 to el. 441, b. Outlet basin: 27,500 gal fr om el. 436 to el. 441, and c. Net volume under condenser: 180, 500 gal from el. 433 to el. 441.
The time required to fill the inlet basin, after a postulated crack occurs, is computed to be 13.3 minutes. This includes the 50-gpm outflow from the sump pump. The circulating water leakage flow will continue for 6.7 minutes afte r filling the inlet basin, until reaching the total estimated shutoff time of 20 minutes. It can be assumed that 10% of th is water will flow out over the floor at el. 441, and the remainder, about 10,170 gal, will flow into the condenser
basin area. During this same time period, four sump pumps in the condenser basin area will have alternately pumped out 670 gal, leaving 9500 gal or 0.42 ft of water in the condenser basin. The rate of ri se of water, therefore, is 0.021 ft/minute during the first 20 minutes after the postulated crack occurs. Note that on the high sump level, both pumps run simultaneously rather than alternately, thus doubling the calculated outflow capacity.
After the valves are cl osed, the water contained in the c ondenser unit water box will continue to discharge to the area. The quantity of water remaining is estimated to be 87,000 gal. The flow will vary with a diminishing head, the head going from about 25 ft to 0 ft. Using a 20-ft head and the same orifice flow criteria, the rate of flow will be approximately 819 gpm, discharging the remaining water in about 106 minutes. There w ill be an outflow from all the sump pumps of 150 gpm, with 10% of the flow fr om the crack again assumed to flow out over the floor. The water will accumulate in th e condenser basin at about 590 gpm. After 106 minutes, the water level in th is basin will rise an additiona l 2.77 ft, at 0.0261 ft/minute.
The total height of water when the discharge has stopped is therefore 3.19 ft to el. 436.19.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-03-040 10.4-16 This elevation is 5 ft below the floor level of the turbine building (el. 441), thus there will be no impacts on safety-related e quipment from this event.
Boundary Evaluation
A complete circumferential expa nsion joint break in the circul ating water system would result in the release of large amounts of water into th e turbine generator building. The water would fill the net volume under the condenser, tripping the sump high level alarms that annunciate in the main control room. Remote-manual operation of the circula ting water pumps and butterfly valves is provided in the main cont rol room to mitig ate the accident.
Disregarding operator action, however, the foll owing evaluation is provided. Water would spill across the grade level floor of the turbine generator buildi ng at el. 441 ft, exiting through the railroad bay and access doors.
Water could flow into the re actor building st airwells and elevator shafts from 441-ft el. dow n to the 422-ft 3-in. el., eventu ally filling the stairwells and elevator shafts with water. There is no safety-related equipment located in the stairwells or elevator shafts. The access doors to the emergency core cooling system (ECCS) and RCIC/CRD pump rooms at el. 422 ft 3 in. are designed to withstand a static head of approximately 44 ft (measured from centerline of door) of water. All penetrations into the reactor building below the 466 ft el. are designed to minimize flooding effects. Flooding will not affect any required safe shutdown equipment in the reactor building.
Water could also spill across th e grade level floor into the ra dwaste/control building. The basement level of this building is 437 ft. It is thus possible to fl ood this level with 4 ft of water before the water would exit at grade level (441 ft) through access doors. No safety-related components will be affected by this flooding.
The railroad bay and access doors of the turbine generator building are not watertight and are not designed to withstand any static head of water; therefore, no significant depth of wate r could accumulate in the turbine generator building. All safety-related e quipment in the turbine generator building is located above the 471-ft el. and would not be affected.
In conclusion, a complete circum ferential expansion jo int break in the circ ulating water system inside the turbine generator building would have no effect on safety-related equipment.
Discharge operation of water accumulated under the condens er shall be performed in accordance with radioactivity checking requirements for sump discharges.
10.4.5.4 Tests and Inspections
All system components , except the condenser, are accessible during operation and may be inspected visually. The circulating water pumps were tested during pr eoperational testing.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-17 The condenser was field hydrosta tically tested in acco rdance with the Steam Surface Condenser Standards published by the Heat Exchange Institute.
All major components were inspected and cleaned prior to installation in the system, and preoperational tests were performed after system installation.
Sampling stations and test connections are provided to allow inservice testing during operation of the system.
10.4.5.5 Instrumentation The circulating water pumps are individually equi pped with shutoff valves that are interlocked with their respective pump motors to prevent startup unless the valve is closed and to prevent shutdown unless the valve is less than 15% open. Isolation valves are provided at the inlets of each condenser shell, which enab le any water box to be isolated. The isolation valves are equipped with limit switches and ar e operated by manual switches located in the main control room. The system is monitored for te mperature, pressure, level, and pH.
10.4.6 CONDENSATE FILTER DEMINERALIZER SYSTEM
10.4.6.1 Design Bases
The condensate filter demineraliz er system capacity is 32,000 gpm, which is in excess of the 100% rated system cap acity of 30,400 gpm.
As a design basis for this system, the effluent water quality is as follows:
NORMAL OPERATION FEEDWATER QUALITY TO THE REACTOR a Parameter Frequency Limit Sample Conductivity 0.1
µmho/cm at 25°C b Continuous pH 6.5 to 7.5 at 25°C As Required Total Metallic Impurity 15 parts per billion (ppb) W eekly; collected Filter Sample continuously Total Copper (Cu) 2 ppb Weekly Total Iron 5 ppb Weekly
_____________
___________
a Measure after the last f eedwater heater unless noted.
b Measured at demi neralizer outlet.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-05-006 10.4-18 Nickel (Ni) 2 ppb Weekly Total Silica (SiO
- 2) 5 ppb As Required Chloride (Cl) 10 ppb c Daily Oxygen 20 to 200 ppb Continuous The design basis effluent water quality and sampling frequency wa s originally specified based on vendor fuel warranty and regulatory guidance. Since that time, enhanced analytical and
testing techniques have determined that considerably lower co ncentrations of impurities can cause damage to system components. Through industry sponsored resear ch, guidelines that are much more restrictive than the original design specifications have been develope d and adopted.
The implementation and documentati on of these more restrictive sp ecifications is controlled by chemistry administrative procedures.
This results in th e system being designed to maintain feedwater quality such that the reactor water limits are not exceeded. Th is is achieved by the following:
- a. Operation of the system to a less than 0.065
µS/cm conductivity end-point.
After reaching this limit during normal operating conditions, the filter-demineralizer(s) are taken o ff line, backwashed , and precoated;
- b. Establishing metallic impurity limits to preserved fuel performance by controlling the amount available for de position on heat transfer and fluid transport surfaces. In addition, controlling corrosion product input minimizes the radiological impact from corrosion product activation, transport, and deposition;
- c. Controlling undesirable anionic (chloride and sulfate) impurity input to maintain the reactor coolant concentrations below the levels where stress corrosion cracking is induced; and
- d. Control of feedwater di ssolved oxygen levels between 20 and 200 ppb falls in the minimal portion of the combined gene ralized and pitting corrosion curve for carbon steel piping. Piping is preserved and corrosion product activation, transport, and deposition are restricted.
This ensures that in conjunction with the RWCU system, reactor water quality will be maintained.
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___________
c Or 25% of influent level, whichever is lower, to maintain reactor water quality of 200 ppb at rated operating pressure.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-19 The condensate filter-demineralizers are desi gned, fabricated, tested, and stamped in accordance with the ASME B&PV Code Section VIII, Divi sion 1 (November 1971). Seismic category, safety class, and design codes are presented in Section 3.2. 10.4.6.2 System Description
The condensate filter demineraliz er system consists of th e necessary piping, valves, appurtenances, and instrumenta tion to control the condensate impurity concentration during plant operation (see Figure 10.4-5
).
Six filter demineralizers are provided to polish 1 00% of the condensate flow: five or six are normally in operation at full power. The six filter demineralizers a nd associated piping, valves, and instrumentation are similar and piped in parallel.
Each filter demineralizer has an associated hold pump which is brought into service during low flow conditions to recirculate condensate through the filter demineralizer and hold the precoat material on the filter elements.
The individual effluent lines from the filter deminera lizer vessels are provi ded with resin traps to prevent passage of ion exchange resins to the feedwater system.
The system design incorporates the following service systems which are common to all filter demineralizers:
- a. Chemical mixing and supply system to circulate a chemical cleaning solution (e.g., inhibited citric acid) for the pur pose of cleaning the filter demineralizer units and directing the waste to the chemical waste system (this system is not normally used);
- b. A backwash system to remove the spent resin from the filter demineralizers and direct the radioactive waste to th e backwash receiving tank (for further discussion of the backwash system disc harge to the liquid waste management system, see Section 11.2); and
- c. A precoat system wherein fresh precoat material is prepared and then circulated through the filter demineralizers to coat the filter elements.
The system control panels are located outside the equipment ar eas to permit remote operation of the condensate filter demineralizers without requiring the operator to enter high radiation areas.
The control panel has a graphic display. All major isolation valves, position indicators, and instrumentation are displayed at their respective locations.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-20 10.4.6.3 Safety Evaluation
The condensate filter demineraliz er system removes corrosion pr oducts, condenser inleakage impurities, and impurities presen t in the condensed steam.
Purified condensate and feedwate r limits ensure sustained, sa fe plant operation by preserving the integrity of nuclear steam s upply system components, vessel internals, fuel, and transport piping. Due to improved water quality limits, any appreci able circulating water inleakage would result in water chemistry conditions outside acceptable limits and require action(s) to return the water quality to within applicable limits for continued plant operation.
Compliance with Regulatory Guide 1.56 is discussed in Section 1.8.
10.4.6.4 Tests and Inspections
The original condensate filter demineralizers, precoat and chemical mixing tanks, holding pumps, and system valves were hydrostatically tested prior to shipment by the manufacturer.
Field tests were perfor med after equipment installation to check satisfactory operation and functioning of control e quipment, as well as to demonstr ate guarantee performance. The guarantee performance test was governed by the ASTM Testi ng Method Procedures for High Purity Industrial Water.
10.4.6.5 Instrumentation
Instrumentation is provided for the condensate filter demineralizer system for proper operation, control, and protection against malfunction of the equipment.
The system design includes automatic flow balancing control for each filter demineralizer to maintain equal flow through each of the operating vessels by regulating the effluent discharge valve. The filter demineralizer flows are normally balanced manually and routinely monitored to maintain adequate flow balance. The cumulative flow through each filter demineralizer is recorded. Conductivity elements downstream of the flow contro l valves measure and record demineralizer performance. Differential pressure and conductivity alarms for each filter demineralizer annuncia te when the pressure differential across a unit reaches a predetermined value or when the effluent conductivity indi cates a significant reduc tion in ion exchange capacity. System influent and effluent conductiv ity are monitored and r ecorded. Alarms are provided for individual demineralizer differential pressures and outlet conductivities, and for the system inlet and outlet conductivities. These alarms annunciate at predetermined levels and C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 10.4-21 corrective action is initiated in accordance with plant pro cedures and licensee controlled specifications.
Conductivity instrumentation is calibrated in accordance with applicab le ASTM Procedures.
An automatic bypass maintains the condensate system flow in the event the number of filter demineralizers in ope ration or the flow capacity of the units (due to clogging) is inadequate to handle the required flow.
The resin replacement equipment is designed for semiautomatic operation. A remote manual override is included as an alternate mode of operation.
Conductivity recorders, a grab sample rack with the necessary instrumentation and appurtenances to test influent and effluent condensate, differen tial pressure monitors, pressure indicators, and local alarms are provided for each unit in additi on to the main graphic display control panel.
10.4.6.6 Demineralizer Resins
Compliance with Regulatory Guide 1.56 is discussed in Section
1.8. Pressure
precoat filter/deminera lizer media on individual vessels is replaced on a cyclic basis when the pressure drop exceeds 25 psid or the effluent conductivity exceeds 0.065
µS/cm during normal operating conditions. The c onductivity limitation does not apply when condenser vacuum is broken and during the period when condenser vacuum is being restored.
10.4.6.7 Water Chemistry Analyses
The filter-demineralizer condition during normal power opera tion is assessed by the effluent conductivity and ionic content. The influent co nductivity is related to impurity concentration through the equivalent cond uctance of the constituents of the process fluid.
Chemical analysis methods used for determina tion of conductivity and ionic content are as follows:
Conductivity Measured in accordance to ASTM-D-1125
Chloride Determined by ion chromat ography in accordance with the vendor's operating manual.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-042 10.4-22 10.4.7 CONDENSATE AND FEEDWATER SYSTEMS
10.4.7.1 Design Bases
The condensate and feedwater system provides a reliable source of high purity feedwater during both normal operation and an ticipated transient conditions. The system is designed with sufficient capacity to provide for 110% of the feedwater fl ow at rated load. This provides sufficient margin to pr ovide flow under anticipated transient conditions. The feedwater heaters are designed to provide the required temperatur e of feedwater to the reactor. The final feedwater temperature is 421°F at rated load.
The condensate and feedwater system is designed and fabricated in accordance with
ANSI B31.1, (October 1973) and ASME B&PV Code, Sect ion VIII, Pressure Vessels (November 1971) and 2004 AS ME B&PV Code,Section VIII, including 2005 Addenda for RFW-HX-6A and RFW-HX-6B. Seismic catego ry and safety cla ss are discussed in Section 3.2. The environmental design bases for this system are in Section 3.11.
10.4.7.2 System Description
The condensate and feedwater system shown in Figure 10.4-6 is a six-heater regenerative feedwater heating cycle. The extraction stea m system supplying h eating steam to each feedwater heater is shown in Figure 10.4-7. A discussion of the c ondensate supply system is presented in Section
9.2.6. Feedwater
heaters 1, 2, 3, a nd 4 are divided into three one-third capacity parallel trains; heaters nmber 5 and 6 are split into two one-half capacity parallel strings. The final feedwater temperature is approximately 421°F at design output. Tube material for RFW-HX-6A and RFW-HX-6B is type 316 stainless steel. For th e rest of the heaters the tubes are type 304 stainless steel. The first-stage heaters are located in the co ndenser exhaust neck.
Figure 10.4-8 shows the heater drain system. All feedwater heater drains are cascaded back to the condenser (6-5-4-3-2-1 condenser). Reheater drains are ca rried to the number 6 heaters whereas the moisture se parators drain to the number 5 heaters.
Condensate from the condenser hotwell is pumped by three motor-driven pumps of one-third capacity each. The condensate is pumped through the gland s eal steam condenser, the steam jet air ejector condensers, the offgas condens er, the condensate demineralization system, and then to the suction of the condensate booster pumps. The condensate pumps are designed to pump approximately 11,000 gpm each with a TDH of 375 ft.
Three motor-driven cond ensate booster pumps are provided in the system. The capacity of the booster pumps matches that of the condensate pumps, one-third capacity for each pump at design rated feedwater flow.
The booster pumps provide the required head to pump the
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.4-23 condensate through the five low pressure heater s and provide sufficient excess head to ensure sufficient net positive suction head (NPSH) at the reacto r feedwater pumps suction.
The condensate booster pumps are designed to pump approximately 11,000 gpm each with a TDH of 925 ft. Using the condensate pumps, the condensate booster pu mps and a series of heat exchangers, the system de livers 14,981,600 lb/hr of condens ate at 467 psig and 366°F to the reactor feedwater pumps. Minimum flow through the gland seal steam condenser and steam jet air ejector condenser is controlled by using a recirculation control valve located in the condensate pump discharge lines to permit recirculation of condensate to the condenser.
Two one-half nominal capacity tu rbine-driven reactor feedwate r pumps are provided. Each pump is capable of providing two-thirds of the rated feedwater flow during one pump operation. Minimum flow through the reactor feedwater pumps is controlled by using recirculation control valves located in the pum p discharge lines to pe rmit recirculation of feedwater to the condenser.
To minimize the corrosion product input to the r eactor, a startup recirculation line is provided from the reactor feedwater supply lines, downstream of the high pressure feedwater heaters, to the main condenser.
The feedwater control system automatically controls the flow of feedwater into the reactor pressure vessel to maintain the water level in the vessel within predet ermined levels during all modes of plant operation.
A hydrogen injection system is installed across the condensat e booster pumps. The system uses discharge pressure to the pumps to feed dissolved hydrogen into the suction of the booster pumps.
A depleted zinc oxide (DZO) passi ve injection system (zinc) is installed across the feedwater pumps. The discharge pressure of the pumps can be used to inject a soluble zinc solution into the suction header of the fe edwater pumps. Injection of zinc reduces the radioactive contamination on primary piping and compon ents by reducing the le vels of cobalt-60.
An iron injection system, insta lled on the suction line of the condensate booster pumps, can be used to inject an iron oxalate solution into the reactor feedwater. This iron injection system can be used to increase the reactor feedwater iron concentrati on to build a thin iron film on the inside of the piping to the vessel , vessel internals, and on the fuel.
Table 10.4-1 presents some of the major characte ristics of equipment in this system.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-046 10.4-24 10.4.7.3 Safety Evaluation
During operation, radioactive steam and condensate are present in the feedwater heating portion of the system which includes the extraction steam piping, feedwater heater shells, heater drain piping, and heater vent piping. Shielding and controlled access are discussed in Chapter 12. The condensate and feedwater system is designed to mini mize leakage with welded construction used through out the piping system. Feedwater heater shell-side relief valve discharges and operating ve nts are routed to the condenser.
The condensate and feedwater syst em is not required to effect or support the safe shutdown of the reactor or perfor m safety functions.
If it is necessary to remove a component such as a feedwater heater, pump, or control valve from service, continued operation of the system is possible by use of the multistream arrangement and the provisions for isolating and bypassing equi pment and sections of the system.
The analysis of both the condensate and feedwater individual component failures is bounded by the feedwater component system failure analysis. These analyses are provided in Sections 15.1.1 , 15.1.2 , and 15.2.7. Included also in Section 15.6.6, are the isolation provisions that minimize release of radioactivity to the environment.
Criteria for feedwater isolation of the reactor coolant system is presented in Section 6.2.4.
10.4.7.4 Tests and Inspections
Each feedwater heater, heater drain tank, condensate pump, condensate booster pump, reactor feedwater pump, and system valv es were shop hydrosta tically tested at 1.
5 times their design pressure. All pumps were shop pe rformance tested. All tube join ts of feedwater heaters were shop leak tested. Prior to initial operation por tions of the completed ANSI B31.1 feedwater system welds were 100% X-rayed.
The remainder of the comp leted condensate and feedwater system received a field hydrostatic test.
Pressure, temperature, conductivity , and flow instrumentation are provided to monitor system performance during operation. A separate, additional wireless m onitoring system comprised of pressure, temperature and flow measuring equi pment, is installed to monitor Feedwater Heaters 6A and 6B, as well as the Main Condensate Heater s 5A and 5B. The EMI/RFI characteristics were evaluated and found to be acceptable. Inservice inspection of applicable reactor feedwater piping is presented in Section 5.2.4.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.4-25 10.4.7.5 Instrumentation Feedwater flow-control instrumentation measures the feedwater flow rate from the condensate and feedwater system. This measurement is used by the feedwater control system that regulates the feedwater flow to the reactor to meet system demands. The feedwater control system is described in Section 7.7.1.4.
The isolation criteria for the feedwater system is loss of feedwate r flow. Isolation valves are remotely operated from the ma in control room using signals which indicate loss of feedwater flow.
Instrumentation and controls re gulate pump recirculation flow rate for the condensate pumps, condensate booster pumps, and reactor feed pumps. Measurements of pump suction and discharge pressures are provided for all pumps in the system. Samp ling means are provided for monitoring the quality of the final feedwater (see Section 9.3.2). Temperature measurements are provided for each stage of feedwater heati ng and these include measurements at the inlet and outlet on both the steam and water sides of the heaters. Steam-pressure measurements are provided at each feedwater heater.
Instrumentation and controls are provided for regula ting the heater drain flow ra te to maintain the proper condensate level in each feedwate r heater shell and h eater drain tank. High-level alarm and automatic dump-to-condenser on high level are provided.
Pressure, temperature, conductivity , and flow instrumentation are provided to monitor system performance. The operation of the hotwell ma keup and high level dump valves is controlled by the hotwell level controller (Figure 10.4-6
).
10.4.8 STEAM GENERATOR BLOWDOWN SYSTEMS
This section is not applicable to a BWR.
10.4.9 AUXILIARY FEEDWATER SYSTEM
This section is not applicable to a BWR.
10.4.10 HYDROGEN WATER CHEMISTRY SYSTEM 10.4.10.1 Design Bases
The Hydrogen Water Chemistry System (HWC) is designed to lower the electrochemical corrosion potential (ECP) of reacto r coolant. Studies have shown that the lowering of ECP in the core below -230 mVSHE will mitigate any existing intergra nular stress corrosion cracking (IGSCC) and prevents future development of IGSCC in stainless stee l components in the reactor coolant recirculation pipi ng and lower reactor internals.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.4-26 The HWC system injects hydrogen into the feedwater stream, incr easing the concentration of dissolved hydrogen in reactor coolant. The pr esence of dissolved hy drogen suppresses the radiolytic generation of oxygen in the core and acts as a catalyst for the recombination of hydrogen and oxidants on the surf ace of piping and reactor internals. As a result, oxygen concentrations are reduced. Th e lower oxygen concentration reduces the ECP of the coolant.
The HWC system can inject up to 30 SCFM of hydrogen into the condensate/feedwater stream, resulting in a hydrogen co ncentration of up to 0.52 pp m in feedwater. Since the radiolytic generation of oxygen is suppressed, HWC also inj ects Service Air into the condenser Offgas stream to ensure that a stoichiometic ratio of hydroge n and oxygen are maintained for recombination.
10.4.10.2 System Description
The HWC system is shown schematically in Figures 10.4-9.1 , 10.4-9.2 , and 10.4-9.3. The system consists of a Hydroge n Storage and Supply Facility (HSSF), a hydrogen injection module, an air injection module, and a main control panel. The HSSF is located approximately 0.6 miles south-s outheast of the Plant. A buried 2-inch pipe supplies hydrogen gas from the HSSF to the Turbine Generator Building (TGB) at approximately 200 psig. The hydrogen injection modu le, located on TGB 441, regulates the gas flow to a sparger in a bypass line across the c ondensate booster pumps.
10.4.10.2.1 Hydrogen Storage and Supply Facility
The HSSF stores up to 14,000 gallons of liquid hydrogen at approximately 80 psig. The liquid H 2 is pumped, vaporized, and stored in six AS ME storage tubes at a pproximately 2450 psig.
The ASME tubes have a 40,000 SCF capacity, and serve as the primary source of gaseous H 2 for the HWC system. Gaseous hydrogen flows to a pressure control manifo ld that reduces the pressure to the 200 psig for supply to the TGB.
Two 100% capacity parallel pump tr ains, each with its own vapor izer, are provided for system reliability. One pump operates wh ile the other acts as a backup. The ASME storage tubes are pressurized in a batch process, with pumping initiated when pressure in the tubes decays to approximately 650 psig.
The HSSF has a backup tube trailer that st ores approximately 120,000 SCF of gaseous H
- 2. The HSSF has space for a second tube trailer that is used in the event of the functional loss of the liquid H 2 supply. Upon deple tion of the inventory in the AS ME tubes, the plant supply of hydrogen automatically switches to th e tube trailer. As the inventory of the tube trailer is depleted, a replacement tube trailer is brought in. The depleted tube trailer is removed, replenished, and returned. In this way, th e HSSF ensures a conti nuous, reliable supply of gaseous H 2 to the HWC system.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-07-018 10.4-27 The HSSF also has a liquid nitrogen storage tank and vaporizer. Gaseous nitrogen is used for HSSF control functions and purging operations.
The operation of the hydrogen supply system at the HSSF is normally automatic, using programmable logic controllers (PLCs) located in a local pump control panel and hydrogen control panel.
The piping at the HSSF is designed to ASME B31.3, Chemical Plant and Petroleum Refinery Piping. The underground yard pi ping is designed to the require ments of ASME B31.1, Power Piping. All liquid and gas storage vessels ar e designed, fabricated, and stamped as ASME Boiler and Pressure Vess el Code,Section VIII, Division I, Unfired Pressure Vessels. The applicable fire protec tion codes are found in Appendix F Table F.3-1.
10.4.10.2.2 Hydrogen and Air Injection
The rate of hydrogen injection is regulated by a PLC in the HWC main control panel, located on the 471 elevation of the TGB. Hydrogen injection is manually initiated above 5% reactor power, and is then automatically maintained at a rate propor tional to reactor power when above 20% power. The injection rate is modulated based on reactor power.
HWC's suppression of radiolysis in the core results in an imbala nce of hydrogen and oxygen in the condenser offgas str eam. This imbalance is corrected by the injection of air into the Offgas system, upstream of the catalytic hydrogen recombiners. Th e Service Air system supplies the air for injection into offgas. The injection system is designe d for a maximum flow rate of 93 SCFM.
The air injection rate is modul ated based upon the rate of hydr ogen injection. Since air leakage into the condenser cont ributes to the oxygen available fo r recombination, the required rate of air injection is reduced to account for the rate of air in-leakage.
The Mitigation Monitoring System (MMS) provides an indication of ECP in the reactor water. The MMS system contains an iron oxide element and a platinum element that may be used for measurement of the ECP of reactor water. ECP may also be monitored using an ECP LPRM probe in the core (see Section 7.6.1.4.2.2). The MMS and ECP LPRM provide an initial correlation of ECP to hydrogen injection to establish a baseline for operation of HWC.
10.4.10.3 Safety Evaluation
The HWC system does not fall within the defini tions of any of the safety classifications identified in FSAR Section 3.2.3. However, the storage and handling of a combustible gas entails numerous safety issues that were addressed in the system's design.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.4-28 The system was designed, procured, and installed to Quality Class II and Seismic Category II requirements. Exceptions are identified below.
- HWC cable terminations, electrical relays, and switc hes in the main control room panels are Quality Class I. Indi cating lights in control room panels are Seismic Category 1M.
- HWC piping in the interfacing portion of the offgas system is Quality Class II+.
- The HSSF liquid hydrogen storage tank, its support foundation and soil were analyzed and installed to Quality Class I and Seismic Catego ry I requirements.
All tanks and pipelines are provided with relief valves for overpressure protection. The liquid H 2 storage tank has redundant rupture discs for added protection.
The effects of the cata strophic failures of HSSF tanks at normal or elevated pressure were analyzed, and it was determined that the energy from such failu res would not directly affect safety related or important to safety structures, systems, or componen ts. Missiles generated from vessel failures at normal operating pressure would have insufficient energy to reach safety related or important to safety structures, systems, or components. Analysis has shown that missiles generated from an over pressuri zation event would have a total annual probability of impact less than 10
-7 and therefore are not considered credible.
The hydrogen storage tanks at the HSSF are designed to stay in place for all natural phenomena (i.e., earthquakes, torn ado winds, floods). No event will cause the tanks to be transported closer to the Plant. Local flooding from a Probable Maximum Precipitation (PMP) event would submerge the tanks (see Section 2.4.2.3), but not dislodge them. Similarly, the vent stack of the liquid H 2 storage tank is designed for flood conditions, with its outlet above PMP flood level. The vent stack design ensu res that the tank will continue to off-gas vaporized hydrogen during the flood.
The HSSF is not designed to withstand tornado missiles. A tornado missile could cause the gross failure of a storage tank at the HSSF. However, as no ted above, vessel failures have no effect on safety related or important to safety structur es, systems, or components.
Similarly, an atmospheric release of all hydrogen stored at the HSSF will have no adverse impact on control room habitability. The HSSF has a maximum storage capacity of approximately 9800 pounds of liquid and gaseous hydrogen. Th e storage of this amount of hydrogen at the HSSF is not considered a hazard for control room ha bitability due to the distance from the plant air and remote air intakes to the HSSF.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 10.4-29 Malfunctions at the HSSF will not have any adverse impact on Plant safety. The major potential effect of failures is the loss of supply of gaseous hydrogen for injection into condensate. The loss of hydrogen injection will cause a release of metallic radionuclides in reactor coolant, a transient N 16 spike in the Main Steam lines and increase ECP in the reactor core. The Plant will continue to operate safely on loss of H 2 injection.
The buried supply line between the HSSF and th e Plant is welded 2 in. schedule 80 pipe. Since the buried pipe passes under, and is routed next to a railroad track, the design was
demonstrated to be in compliance with the American Railway Engineering Association (AREA) Manual for Railway Engineering.
In the area of the Plant, the buried H 2 supply line is encased in a guard pipe. The guard pipe provides mechanical protection, a nd a means to monitor the pipe fo r leakage. The vent of the buried line's guard pipe is directed to a hydrogen detector at the hydrogen supply valve station immediately outside the TGB. Hydrogen detectors are also locat ed in the hydrogen injection module and at the Condensate syst em injection point. The HWC sy stem is automatically shut down upon receipt of a high-high hydrogen signal from any of these detectors.
The hydrogen does not add to the combustible materi al in the TGB, since it is contained within welded pipe, and appropriate flow-limiting devi ces are included in the system. Excess flow valves are located in the supply line at both the HSSF a nd outside the TGB. The automatic closure of either excess flow valve would mitig ate the effects of rupt ures of the hydrogen supply line in or around the TGB.
The inadvertent introduction of hydrogen to condensate/feedwater during extended shutdowns is prevented by isolation of the hydrogen supply, and purging the hydrogen injection system with nitrogen.
The injection of hydrogen results in a transient increase in N 16 activity in steam exiting the reactor, and an increase in the transport of metallic radionuclid es to the recirculation system's piping and components. These effects are similar to those resu lting from NobleChem injection (Section 5.2.3.2.2). The increased dose rates have no effect on equipmen t qualification.
The injection of hydrogen into feedwater reduces ra diolysis in the reactor core, and results in a net reduction of hydrogen in Ma in Steam. The injection of hydrogen decreases secondary-side concentrations of dissolved ox ygen. Secondary side chemistr y is maintained in accordance with EPRI NP-5283-SR-A, "Guidelines for Permanent BWR Hydrogen Water Chemistry Installations". Dissolved oxyge n is maintained in a range where Flow-Accelerated Corrosion (FAC) will not be exacerbated.
Hydrogen injection terminates automatically when feedwater flow drops below 25%.
Hydrogen injection can also be termin ated manually from the control room.
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-037 10.4-30 The injection of air into offgas increases the tr ansport rate of radio active species through the system with no adverse effect on system function. Offsite releases are maintain ed within the limits of 10 CFR 50 Appendix I and 10 CFR 20 Appendix B, Table II.
With the lowered net flow of hydrogen through offgas, the condenser's steam jet air ejectors provide sufficient dilution steam to maintain the hydrogen c oncentration below the maximum allowable concentration of 4% by volume (FSAR Section 10.4.2.3).
10.4.10.4 Tests and Inspections
The Hydrogen Water Chemistry system underwent a series of factory accep tance tests and site tests. The tests verifi ed the operability of components, th e logic of PLC programming, and the functionality of the integrated system. Site testing included the tuning of the HWC system to achieve the required ECP in th e core, and benchmarking the Co lumbia Station's response to hydrogen and air injection.
10.4.10.5 Instrumentation
The Hydrogen Water Chemistry system is controlled by an integrated system of instrumentation and programmable logic controllers.
The HSSF is automatically operated by two PLCs , one located in the pu mp control panel and the other in the hydrogen control panel. The PLCs:
- Control and monitor the hydrogen pu mps and associated interlocks,
- Contain industrial safety interl ocks for the HSSF facility, and
- Provide system status, process and alar m data to a remote annunciator panel.
The remote annunciator pane l is located in the chemistry labo ratory of the Radwaste Building, el 487. The panel includes a human-machine interface PC that displays mimics, process information, and all HSSF alarms. The pane l has one control inte rface with the HSSF, allowing the remote isolation of the HSSF from the Plant. The panel also receives HWC process information from a PLC in the HWC control pa nel, located on TGB el 441. The HWC control panel's PLC controls the inje ction of hydrogen and ai r into the condensate and offgas systems, respectively.
The PLC control logic is ba sed upon input flow signals from the hydrogen control module, oxyge n control module, and feedwater system. In addition, the PLC receives signals from TGB hydrogen leakage detectors, offgas hydrogen analyzers, and a
C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-037,07-018 10.4-31 summed alarm from the HSSF PLCs. Finally, the PLC receives an enable signal from a switch located on a panel in the main control room. The switch is a permissive for the operation of the hydrogen water chem istry system. The switch can also be used to shut the system down.
Hydrogen and air injection is manually initiated from the HWC Control Panel. Injection is automatically terminated by the PLC when the reactor is shut down. Injection can also be manually terminated at the HWC control panel.
Alarms from the HSSF and the HWC injectio n system are annunciated at the HWC control panel and in the main control room. HSSF process alarms display as a summed "HSSF Trouble Alarm" at the HWC control panel and as "HWC Trouble" in the main control room. The HWC control panel has annunciators for the di splay of specific, loca l process alarms. The HWC process alarms also actuate the summed "HWC Trouble" alarm in the main control room.
Any manual or automatic shutdow n of HWC is annunciated as "HWC Shutdown" in the main control room. Automatic shutdown occurs if any of the following signals is received:
Reactor Scram Offgas Isolation High Hydrogen Flow PLC Fault High Hydrogen Pressure Loss of Feedwater or H 2 Flow Signal Low Process Air Pressure Offgas Analyzers O.O.S.
High-High Area Hydrogen Low Condensate flow at Injector Offgas % Hydrogen High Shutdown Purge Local Shutdown Demand Control Room Shutdown Demand
These signals simultaneously annunc iate on the HWC control panel.
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December2005
Table 10.4-1 Feedwater System Equipment Characteristics a 10.4-33 Condensate pumps Quantity 3 Capacity a 11,000 gpm/pump Total discharge head 375 ft Minimum flow 5600 gpm/pump Driver 1250 hp ac motor Condensate booster pumps Quantity 3 Capacity a 11,030 gpm/pump Total discharge head 925 ft Minimum flow 2500 gpm/pump Driver 3000 hp ac motor Reactor feedwater pumps Quantity 2 Capacity a 18,520 gpm/pump Total discharge head 2585 ft Minimum flow Designed for 4600 gpm/pump at 5100 ft breakdown Driver Steamturbine Steam jet air ejectors condenser Quantity 2-100%
Minimum cooling flow 5000 gpm Gland seal steam condenser Quantity 2-100%
Design flow 6500 gpm Pressure drop 6 psi
C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Table 10.4-1 Feedwater System Equipment Characteristics (Continued) 10.4-34 Feedwater heaters Quantity 16 (one-third capacity up to and including heater 4 and one-half capacity for
heaters 5 and 6)
Condensate (tube-side original design conditions)
Heaters Flow/Chain (lb/hr) Pressure Drop at Design Flow (psi) Inlet Temp (°F) Outlet Temp (°F) 1A, 1B, 1C 4,752,000 5.8 109.4 168.8 2A, 2B, 2C 4,752,000 5.4 168.8 208.5 3A, 3B, 3C 4,752,000 3.5 208.5 262.1 4A, 4B, 4C 4,752,000 6.0 262.1 291.3 5A, 5B 7,128,000 4.0 291.3 358.4 6A, 6B 7,128,000 9.9 360.1 419.8 a Capacity is based on 115% of the orig inal rated condensat e/feedwater flow.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-1 56M511Main Condenser Evacuation SystemRev.FigureDraw. No.Amendment 61December 2011 Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-2 13 01-00,143,1Turbine Gland Sealing SystemRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-4.1 159 M507-1Flow Diagram - Circulating Water System - Turbine Generator Building and YardRev.FigureDraw. No.Amendment 62December 2013 Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-4.2 7 M507-2Flow Diagram - Circulating Water System - Turbine Generator Building and YardRev.FigureDraw. No.
Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-4.3 13 M507-3Flow Diagram - Circulating Water System - Turbine Generator Building and YardRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-5 69 M534Flow Diagram - Radioactive Waste System Condensate DemineralizationRev.FigureDraw. No.Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 105 M504-1 10.4-6.1 Flow Diagram - Condensate and Feedwater SystemsRev.FigureDraw. No.Amendment 62December 2013 Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-6.2 11 M504-2 Flow Diagram - Condensate and Feedwater SystemsRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 1 M504-3 10.4-6.3 Flow Diagram - Condensate andFeedwater SystemsRev.FigureDraw. No.Amendment 61December 2011 Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-7.1 12 M503-1 Flow Diagram - Extraction Steam andHeater Vents - Turbine Generator BuildingRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-7.2 4 M503-2 Flow Diagram - Extraction Steam and Heater Vents - Turbine Generator BuildingRev.FigureDraw. No.Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-8.1 19 M505-1Flow Diagram - Heater Drain System - Turbine Generator BuildingRev.FigureDraw. No.Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-8.2 12 M505-2Flow Diagram - Heater Drain System -Turbine Generator BuildingRev.FigureDraw. No.Amendment 61December 2011 Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-8.3 8 M505-3Flow Diagram - Heater Drain System -Turbine Generator BuildingRev.FigureDraw. No.
Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-9.1 4 M986-1Flow Diagram - Hydrogen Water ChemistryTurbine Generator Building and Hydrogen Storage and Supply FacilityRev.FigureDraw. No.Amendment 60December 2009 Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-9.2 2 M986-2Flow Diagram - Hydrogen Water ChemistryTurbine Generator Building and Hydrogen Storage and Supply FacilityRev.FigureDraw. No.
Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 10.4-9.3 2 M986-3Flow Diagram - Hydrogen Water ChemistryTurbine Generator Building and Hydrogen Storage and Supply FacilityRev.FigureDraw. No.