CO2 Separation-State of the Art and Future Prospects

CO2 Separation – State of the Art and Future Prospects

Rodney Allam Director of Technology Overview

z This presentation covers CO2 capture techniques – Flue gas scrubbing

– Precombustion CO2 capture – Oxyfuel

z CO2 separation technologies – adsorption – membrane – absorption – Low temperature (primarily purification and liquefaction) z We will deal with options using existing technology together with new techniques requiring further development

3 Carbon Dioxide Management

Reducing CO2 Emissions

Sky Sky

CO2 N2 O2

Power & Heat Air

Fuel

4 Carbon Dioxide Management

Reducing CO2 Emissions

Sky Sky Sky N2 O2 CO2 N 2 Amine CO2 O 2 Absorption

Flue Gas Scrubbing Power & Heat Air • Enhanced Oil Recovery

• Enhanced Coal CO2 Bed Methane Compression & Dehydration • Old Oil/Gas Fields

• Saline Formations

Fuel

5 Carbon Dioxide Management

Reducing CO2 Emissions

Sky Sky Sky Sky N2 O2 CO2 N 2 Amine CO2 O 2 Absorption

Flue Gas Scrubbing Power & Heat Air • Enhanced Oil CO 2 Recovery Precombustion • Enhanced Coal Decarbonisation Reformer H2 CO N2 O2 2 Bed Methane + CO Sep Power & Heat 2 Air Compression & Dehydration • Old Oil/Gas Fields

• Saline Formations

Fuel

6 Carbon Dioxide Management

Reducing CO2 Emissions

Sky Sky Sky Sky N2 O2 CO2 N 2 Amine CO2 O 2 Absorption

Fuel

7 CO2 Separation Technologies Capabilities

Adsorption Membrane Absorption Cryogenic

Feed Low to High Medium to Low to High Medium to Pressure High High

CO2 Low Low Low Low to Pressure Medium

CO2 Medium to Low to Medium to High Purity High Medium High

CO2 Medium to Low High High Recovery High

8 CO2 Separation Technologies Commercial Applications

Adsorption Membrane Absorption Low Temp

Hydrogen Natural Gas Syngas CO2 Production Purification Purification Liquefaction

ASU Air Enhanced CO2 Clean-up Oil Recovery Recovery

Applications from Flue Gas

9 Flue Gas Scrubbing

z Typical CO2 Compositions…

CO2 Impurities Pressure

Natural Gas Turbine 3-4% low SOx and NOx 1 atm Exhaust levels, 12-15% O2

Coal/Oil Fired Boilers 11- high SOx and NOx 1 atm 14% levels, 2-5% O2

IGCC Syngas Turbine 4.5- Low SOx and NOx 1 atm Exhaust 6%

Blast Furnace Gas 25- SOx and NOx 1atm (after combustion) 30% present Cement Kiln off-gas 15- Could have many 1atm 35% impurities

10 Flue Gas Scrubbing

z Uses aqueous amine solvents – Sensitive to acidic impurities such as NO2, SO2, SO3 and HCl – Pretreatment requirement to achieve low levels of NO2, SO2, SO3 and HCl z Commercial systems available e.g. – Kerr-McGee / ABB Lumus Crest – Fluor Daniel ECONAMINE – MHI z Utilities required – Low pressure steam for regeneration – Power for pumping

11 Flue Gas Scrubbing – Current Developments z Advanced amine formulations – More resistant to acid gas impurities and oxygen – Lower regeneration energy z New contacting devices – Hybrid membrane absorption systems z High temperature regenerable solid sorbents – Lithium and Calcium Oxide based

12 General Arrangement For CO2- free Hydrogen Production

Steam Export Steam CO2 Fuel

Syngas Heat Shift H2 purification / Oxygen H2 Generation Recovery reactors CO2 separation

Waste Fuel Gas

13 Precombustion CO2 Capture – Natural Gas Based Systems z Conventional hydrogen production – SMR, POX, ATR – Convective Reforming Combined with the above

z Conventional CO2 removal – Chemical or physical absorption system – Adsorption using a PSA system z Comparative economics at

H2 42 MM SCFD H2(1986) B Beds Fuel gas or Product Recycle gas Gemini Amine System /PSA Feed Vacuum Capital 9800 13300 A Beds CO (M$) gas Pump 2 Product Operating 550 590 (M$/yr) Rinse Compressor 14 Precombustion CO2 Capture – Natural Gas Based Systems Concept Combine reforming or water gas shift reaction with high temperature CO2 removal to decarbonise gas turbine fuel

drive reaction this way

CH4 + H2O Ù CO + 3H2 CO + H2O Ù CO2 + H2

remove by adsorption Process goals

z Shift CO to low levels and simultaneously remove CO2

z Produce decarbonised H2 fuel at high T/P – No steam condensation – Higher electrical generation efficiency

15 A closer look at the SER process o Multiple adiabatic fixed beds containing mixture of shift catalyst and high

temperature CO2 adsorbent such as hydrotalcites o Cyclic operation, reaction step and regeneration steps o Regeneration by lowering pressure and purging with steam (Pressure Swing Adsorption, or PSA mode)

o Specific process cycle developed to achieve 90+% carbon recovery, 97+% CO2 purity, and 99+% H2 recovery

Reaction CO2 Depressur- Purge Equal- Pressur- Rinse isation isation isation

Decarbonised

H2 productRecycle Steam

Packed with catalyst and adsorbent

Feed CO2 rinse CO2 CO2 Feed (syngas) product product (syngas)

16 Water O2 ATR – 100 bar CO2 with SER Condenser

N2 Steam O 2 preheat ATR WHB HTS SER Feed Natural HRSG Gas Water Steam Steam H2 Steam Steam Steam Power Turbines Air HRSG Feed Power Water

17 Aspen simulation results with MDEA & SER systems

MDEA Air ATR Air ATR O2 ATR SD SER Carbon 94.2% 94.6% 96.2% removal 99.3% 99.3% 97.9% Efficiency 42.6% 41.8% 41.8% 48.9% 46.6% 47.3% $/tonne $34.85 - $30.29 CO 2 - - $24.02

18 Ion Transport Membrane

O2- Hot

Compressed Thin Air e- membrane Porous membrane Oxygen support

Product Dense, slotted vitiated backbone compressed-air

800-900°C 200-300 psig Product Withdrawal Tube

Pure A B Oxygen C

19 Gas Turbine ITM Integration

STEAM OXYGEN AIR HRSG

ELECTRIC POWER OXYGEN COMPRESSOR H2+ Diluent

‘AIR’ OXYGEN ION TRANSPORT HEAT MEMBRANE EXCHANGE

20 Commercial ITM Oxygen Vessel Concept: 350 tons/day

21 100 bar Power 380 MW CO2-Free Power and CO2 H2 220,000 Hydrogen From Coal Nm3/hr

CO2 @ 4,000 Fuelled System 100 bar tonne/day Coal

CO2/H2S Water/N2 Quench/ Coal Shift Physical Oxygen Heat Gasification reactors Absorption Recovery System H Product Ash/Slag 2

H H 2 2 Purification

Steam

N Steam 2 Steam Power Turbines Air Feed Heat Recovery Power Gas Turbine Water

22 Oxyfuel CO2 Capture

z Eliminates N2 from the flue gas by burning the fuel in oxygen z Recycle of flue gas can be used to vary the flame temperature z Combustion products contain:

– CO2 + H2O – Any inerts from air inleakage or oxygen impurities – Oxidation products and impurities from the fuel (SOx, NOx, HCl, Hg, etc.)

23 Oxyfuel Boiler Conversion (CCP Grangemouth System)

Local CO2 Drying and Compression Steam 63.0 kg/s O2 from ASU 15.08 kg/s StackStack 20.50 kg/s

Steam Air FD Fan ID Fan Heater Boiler

Fuel zCO2 z59.6 %w/w 74.51 kg/s zCO2 z17.4 %w/w zH O z29.6 %w/w 4.124.35 kg/skg/s 2 231°C zN2 z71.6 %w/w Air zO2 z1.6 %w/w zH O z9.5 %w/w41.06 kg/s Not required for Oxyfuel Infiltration zInerts z9.2 %w/w 2 zO2 z1.5 %w/w220°C firing but retained for air firing backup FGR Fan

24 Raw CO2 Treatment

Cooling water 2617 tonne/hr 24°C Dryers

Direct Compression Contact Boiler feed water 14.5 MW 12.2 tonne/hr Cooler

Flue gas (collected Water knockout from local 2.4 tonne/hr heaters or Total, kmol/hr 4,577 boilers) Cooling water return T, °C 30.00 P, bara 32.06 T, °C 283 2704 tonne/hr CO 77.19 mol% kmol/hr 8,777 2 44°C O2 3.21 mol% To central CO 40.77 mol% 2 Ar 4.03 mol% O 1.67 mol% purification 2 N 15.49 mol% Ar 2.10 mol% 2 system H2O 0.00 mol% N2 8.08 mol% SO2 0.08 mol% H2O 47.28 mol%

SO2 0.08 mol%

25 Central CO2 Purification and Compression System (CCP Grangemouth System)

Flue Gas Vent Warm Cold Exchanger Exchanger 9.8 bara Flue Gas Heater CO 25.1 mol% -55.8 °C 2 Flue Gas N2 47.8 mol% Expander Ar 13.6 mol%

O2 13.5 mol% Dry CO2 from local 19.6 bara drying and compression SO 0.0 mol% 2 areas -30.9 °C P 30 bara

CO2 77.0 mol% CO2 product for N2 14.3 mol% sequestration CO CO2 Ar 4.5 mol% 2 Compressor Compressor O2 4.1 mol%

SO2 0.1 mol% P 221 bara

CO2 96.2 mol%

N2 1.9 mol% Ar 1.1 mol%

O2 0.7 mol%

SO2 0.1mol% 26 27 Power Oxygen Air Separation Steam Turbines Oxyfuel PF Unit

Coal Coal Fired PF Boiler Mill Dust

Power Precipitator

Station CO2 Product

Inerts and Desiccant Direct Water AIR OXYFUEL Acid Gas Drier Cooling BFW Coal flow kg/sec (dry ash free) 47.9 47.9 Removal Heating value MW(LHV) 1554 1554 Power Water Inerts SO2 NOx Steam turbines MW 652 718 HCl Auxiliaries MW -26 -28 Oxygen plant MW - -103 z Cryogenic Air Separation Unit uses CO2 compression MW - -76.5 adiabatic air compressor Total net power MW 626 511 Net efficiency % 40.3 32.9 z CO2 compressor has two adiabatic Oxygen stages Flow tonne/day 0 11000 Purity % - 95 z Heat for condensate and boiler CO2 feedwater preheating Flow tonne/h 0 480 Pressure bara - 220 z Supercritical and Oxyfuel are suitable Purity % - 99.99 for retro-fit or new build Recovery % - 91.3 z Supercritical/Oxyfuel efficiency ~38% (approximately the same as IGCC) 28 Natural Gas Fired Oxyfuel Gas Turbine Combined Cycle Fuel Pressurized oxygen

Comp Turbine G

83% CO Condenser 2 Recycle 15% H2O

HRSG 1.8 % O2 96% CO2 2% H2O Heat 2.1 % O Water CO2 2 Steam to storage cycle Net Power 226 MW Efficiency ~45% LHV Oxygen 3400 tonne/day

29 A Water Quenched Direct Fuel Oxygen Combustion (CES Cycle) z No limit on steam temperature z Efficiencies >50% possible

* CH4, CO, H2, etc. Nitrogen

Reheater Air Air Separation Oxygen Plant Electrical Gas Generator HP IP LP Generator Crude Fuel Processing Fuel* Fuel Plant Multi-stage Turbines

Steam/CO2 (~90/10 % vol) Heat Recov- Coal, Refinery ery CO2 Carbon Direct Dioxide Residues, or Recovery Sales Biomass

Con- den- ser

Gas or Recycle Water EOR, ECBM, Oil Excess Water or Sequestration

30 The Chemical Looping Combustion Principle z Metal oxides of transition metals z Reactor Temperatures 800-1200°C z Either Brayton or Rankine steam cycle

No oxygen plant required

"Air"

Air 14% O2

Me MeO

CO + H O RED 2 2 Fuel

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