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

2. 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.

3. Impact of the Inerts / O2 to the CO2 Processing Units

4. 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

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

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

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

8. 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

9. Consideration of NOx SO2 and SO3

10. Results from IFRF study (APG4)

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

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

13. 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.

14. CO2 Compression and Purification System – Removal of SO2, NOx and Hg
SO2 removal: 100% NOx removal: %
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

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

17. 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?

18. 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

19. 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?

20. 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).

21. 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?

22. Review of the Different CO2 Processing Scheme in the Literature

23. Air Products Scheme

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

25. Air Liquide

26. Air Liquide’s Patents US Patent Applications
2008/ (A1) – August 2008
2008/ (A1) – August 2008
2008/ (A1) – August 2008
2008/ (A1) – August 2008
2009/ (A1) – January 2009
2009/ (A1) – January 2009
2009/ (A1) – January 2009

27. Praxair US Patent Application 2007/0231244 (A1)

28. 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)

29. 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.

30. Economics of the Removal of the Inerts

40. 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

41. Gas Composition in Current CO2 Pipeline

42. 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

43. 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