CO2 Processing Unit Challenges in Meeting the Required CO2 Quality by Stanley Santos IEA Greenhouse Gas R&D Programme & Jinying Yan Vattenfall R&D AB

Presentation Outline Been in existence for 15 years. Factor affecting the design and operation of CO2 processing unit Air Ingress / O2 in the flue gas / Inerts from the Air Separation Unit SO2 and SO3 NO and NO2 CO Review of NOx and SOx reaction during compression Limitation that we should expect in the following equipment: Compressors BAHX Available CO2 Processing Unit Scheme Air Products Air Liquide Praxair Economics of Removing the Inerts Been in existence for 15 years. Responsible for first getting CCS into IPCC SAR as a mitigation option. Major on CCS but is only one of the options.

Impact of the Inerts / O2 to the CO2 Processing Units

Impact of impurities on the CO2 concentration Where do the impurities come from? Fuel’s nitrogen and sulfur Oxygen excess  3 – 3.5% / 4.5 – 5% O2-residue Air separation unit  98% O2-purity: 2% Ar  95% O2-purity: 3.8% Ar + 1.2% N2 Air leakage  approx. 3 % of flue gas flow for a new conventional power plant  up to 10 % over the years for power plants in use Air Leakage Air leakage is a major source of impurities and needs to be reduced by appropriate design Impact of impurities on the CO2 concentration

CO2 Purity Depends On Feed Pressure Composition Feed Pressure, bar At -55°C

CO2 Recovery Depends On Feed Composition At -55°C, 30 bar

CO2 Recovery Depends On Feed Composition Vent CO2 Composition Feed Composition At -55°C, 30 bar

CO2 Purity and Recovery -55°C is as cold as we can make the phase separation CO2 purity depends on pressure At 30 bar and -55°C, CO2 purity is 95% Higher pressure gives lower purity CO2 CO2 recovery depends on pressure Lower pressure gives lower CO2 recovery At 15 bar and -55°C, CO2 recovery is 75% At 30 bar and -55°C, CO2 recovery is 90% CO2 recovery depends on feed composition Increases from zero at 25mol% to 90% at 75mol% Reducing air ingress increases CO2 capture rate

Consideration of NOx SO2 and SO3

Results from IFRF study (APG4)

Expected trends of SO2 emissions from Oxyfuel Boilers (Results from IFRF 3MWth)

SO3 Emissions (Results from ANL-EERC, IVD Stuttgart, Callide/IHI)

NOx SO2 Reactions in the CO2 Compression System In the presence of water and oxygen, NO and SO2 reacts to form H2SO4 and HNO3 during compression. SO2 is converted to Sulphuric Acid, NO2 converted to Nitric Acid: NO + ½ O2 = NO2 (1) Slow 2 NO2 = N2O4 (2) Fast 2 NO2 + H2O = HNO2 + HNO3 (3) Slow 3 HNO2 = HNO3 + 2 NO + H2O (4) Fast NO2 + SO2 = NO + SO3 (5) Fast SO3 + H2O = H2SO4 (6) Fast Rate increases with Pressure to the 3rd power only feasible at elevated pressure No Nitric Acid is formed until all the SO2 is converted Pressure, reactor design and residence times, are important.

CO2 Compression and Purification System – Removal of SO2, NOx and Hg SO2 removal: 100% NOx removal: 90-99% 1.02 bar 30°C 67% CO2 8% H2O 25% Inerts SOx NOx 30 bar to Driers Saturated 30°C 76% CO2 24% Inerts Water 15 bar BFW 30 bar cw Condensate cw cw Dilute HNO3 Dilute H2SO4 HNO3 Hg

CO concentration at the Vent Do we really need a low NOx burners?

Challenges in Dealing with CO2 Quality Do we need the FGD system? How does it impact the NOx / SOx reaction if FGD were installed? Do we need low NOx burners? How we deal with the CO at the vent? How do we disposed / clean up the liquid effluents from the compressors’ knock down water? What would be the long term impact to the compressor due to the H2SO4 mist formed during the compression?

The Challenge of Sulphur Management of Power Plant The type of sulphur products that could be recovered from the power plants should be explored during the feasibility study. We need to determine which sulphur products that could be generated by the process are feasible or not? CaSO4 H2SO4 SO2 (NH4)2SO4 and many others

Impact of Impurities to the Compressors Key impurities that could impact the operation and design of the compressors water ingestion problem Design of the water condenser prior to the CO2 processing unit is critical to minimised such problem. Design of the water knockout system in the compressor’s intercooler units particulate matters Compressor companies assumes a 1-2 mg/Nm3 for a turbo machinery type compressors as tolerable. Is this enough? Impact of Hg in the compressor H2SO4 mist This is still a big challenge! This could cause long term problem of impeller erosion. Picture showing the consequence of liquid ingestion to a reciprocating compressor. Centrifugal compressor tends to tolerate some level of liquid ingestion but to what extent?

Impact of Impurities to the Compressors Brazed Aluminium Heat Exchanger (BAHX) is the very heart of the CO2 processing unit. Limitations: Fluids passing through the HX should be mercury and copper media free. Any particulate matter contaminating the HX could increase its pressure drop therefore OPEX. BAHX are not tolerable to fluids with high alkalinity (i.e. > pH 8) and high acidity (i.e. < pH 5).

Challenges in Dealing with CO2 Quality How deep should the water removal be by the flue condenser prior to the initial compression stage of the CO2 processing plant? What level of particulate matters could be tolerable? In the oil and gas industry – it is a common practice to remove mercury down to 0.01 μg/Nm3. Is this reasonable for oxyfuel power plants? Where should be the best position to remove the mercury? Upstream or downstream prior to compression?

Review of the Different CO2 Processing Scheme in the Literature

Air Products Scheme

Air Products Patents US Patent Applications US Patent 2008/0173585 (A1) – July 2008 2008/0176174 (A1) – July 2008 US Patent 416716 (B2) – Aug. 2008

Air Liquide

Air Liquide’s Patents US Patent Applications 2008/0196583 (A1) – August 2008 2008/0196584 (A1) – August 2008 2008/0196585 (A1) – August 2008 2008/0196587 (A1) – August 2008 2009/0013871(A1) – January 2009 2009/0013717(A1) – January 2009 2009/0013868(A1) – January 2009

Praxair US Patent Application 2007/0231244 (A1)

Factors to be Considered in Evaluation Various Schemes Analysis should include the NOx and SOx reaction mechanism. This could eliminate schemes which are feasible or not feasible. Energy consumption CO2 recovery rate CO2 purity Type of CO2 products (liquid, gaseous, or supercritical CO2)

The Important Challenges Ahead… The use of impure CO2 as refrigerant in a larger scale should be demonstrated. The disposal of removed impurities from the CO2 processing plant or from the flue gas processing are issues needs to be addressed. The further recovery of CO2 and O2 at the vent is an area where some saving could be obtained.

Economics of the Removal of the Inerts

Early Mistakes in Dealing with CO2 Specifications It is important to note that it is not possible to have one specification that can cover all cases. Each specification is dependent on individual project/s based on the analysis of the whole chain of CO2 capture, transport and storage

Gas Composition in Current CO2 Pipeline

Composition (Mole%) of Oxycombustion Flue Gas Multiple Reactive and Inert Components Dramatically Alter the Characteristics of the Flue Gas Presentation from GHGT-9 – Washington DC NO / NO2 can’t be ignored because it plays an important role in the reaction of SO2 forming SO3 and H2SO4 Composition (Mole%) of Oxycombustion Flue Gas Condensate is highly acidic due to oxidation of SO2 ,which reacts with water to produce sulfuric acid; pH < 0.5 Mixing other gases with CO2 changes fluid properties (NOx intentionally left out of this discussion) Gas North Dakota Lignite Montana Decker Illinois #6 CO2 59.6 59.5 58.1 N2 16.0 16.3 17.6 Ar 2.4 2.5 H2O 17.4 O2 4.1 4.0 SO2 0.38 0.14 0.10

DYNAMIS PROJECT SPECIFICATION New Experimental Results from Imperial College indicate NO/SOx reaction occurs even at low concentration. The presence of water even at low concentration could be an issue. SO3 – is a very strong desiccating agent