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CURRENT STATUS OF CO2 CAPTURE
TECHNOLOGY DEVELOPMENT AND
APPLICATION
Value-Added Report
Prepared for:
Andrea McNemar
National Energy Technology Laboratory
U.S. Department of Energy
3610 Collins Ferry Road
PO Box 880, M/S P03D
Morgantown, WV 26507-0880
Cooperative Agreement No. DE-FC26-05NT42592
Prepared by:
Robert M. Cowan
Melanie D. Jensen
Peng Pei
Edward N. Steadman
John A. Harju
Energy & Environmental Research Center
University of North Dakota
15 North 23rd Street, Stop 9018
Grand Forks, ND 58202-9018
2011-EERC-03-08 January 2011
Approved
DOE DISCLAIMER
This report was prepared as an account of work sponsored by an agency of the United
States Government. Neither the United States Government, nor any agency thereof, nor any of
their employees makes any warranty, express or implied, or assumes any legal liability or
responsibility for the accuracy, completeness, or usefulness of any information, apparatus,
product, or process disclosed or represents that its use would not infringe privately owned rights.
Reference herein to any specific commercial product, process, or service by trade name,
trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement,
recommendation, or favoring by the United States Government or any agency thereof. The views
and opinions of authors expressed herein do not necessarily state or reflect those of the United
States Government or any agency thereof.
EERC DISCLAIMER
LEGAL NOTICE This research report was prepared by the Energy & Environmental
Research Center (EERC), an agency of the University of North Dakota, as an account of work
sponsored by the U.S. Department of Energy (DOE) National Energy Technology Laboratory.
Because of the research nature of the work performed, neither the EERC nor any of its
employees makes any warranty, express or implied, or assumes any legal liability or
responsibility for the accuracy, completeness, or usefulness of any information, apparatus,
product, or process disclosed or represents that its use would not infringe privately owned rights.
Reference herein to any specific commercial product, process, or service by trade name,
trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement
or recommendation by the EERC.
CURRENT STATUS OF CO2 CAPTURE TECHNOLOGY DEVELOPMENT AND
APPLICATION
ABSTRACT
The Energy & Environmental Research Center has prepared an overview of the current
status of carbon capture technology development and application. The overview covers
technologies that apply to the three combustion platforms: precombustion, during combustion
(oxycombustion and chemical-looping combustion), and postcombustion. The technologies
reviewed fall into the categories of physical and chemical absorption; physical and chemical
adsorption; oxygen-, hydrogen-, and carbon dioxide-CO2-permeable membrane processes;
cryogenic processes; mineralization; and photosynthesis and chemical and biochemical reduction
processes. The document provides an overview of the technical basis for each separation
technique and information on nearly 100 technologies and/or research efforts.
i TABLE OF CONTENTS
LIST OF FIGURES ....................................................................................................................... iii
LIST OF TABLES ......................................................................................................................... vi
NOMENCLATURE ..................................................................................................................... vii
EXECUTIVE SUMMARY .......................................................................................................... xii
INTRODUCTION .......................................................................................................................... 1
CO2 CAPTURE PLATFORMS ...................................................................................................... 1
Precombustion ....................................................................................................................... 1 
During Combustion ............................................................................................................... 3 
Oxycombustion ............................................................................................................ 3 
Chemical-Looping Combustion ................................................................................... 6 
Postcombustion ..................................................................................................................... 7 
CO2 CAPTURE AND SEPARATION TECHNOLOGIES ........................................................... 8 
Absorption ............................................................................................................................. 9 
Physical Absorption Technologies .............................................................................. 9 
Commercially Available Chemical Absorption Technologies .................................. 15 
Pilot- and Demonstration-Scale Chemical Absorption Technologies ....................... 22 
Developing Technologies for Chemical Absorption ................................................. 36 
Adsorption ........................................................................................................................... 51 
ADA–Environmental Solutions Adsorbent Screening Study .................................... 53 
Physical Adsorption (TSA, PSA, and ESA) .............................................................. 54 
Chemical Adsorption ................................................................................................. 59 
Membranes .......................................................................................................................... 66 
Air Separation for Oxycombustion and Gasification ................................................ 70 
Hydrogen Separation and Integrated Precombustion Capture
Systems ...................................................................................................................... 71 
Postcombustion Capture ............................................................................................ 77 
Cryogenic Cooling .............................................................................................................. 81 
Cryogenic Carbon Capture System ........................................................................... 81 
Controlled Freeze Zone (CFZ) Cryogenic CO2 Separation Process ......................... 82 
Mineralization ..................................................................................................................... 82 
Alcoa – CO2 Capture Process with Bauxite Waste ................................................... 83 
Alkaline Fly Ash-Based CO2 Capture ....................................................................... 84 
Accelerated Weathering ............................................................................................. 85 
Calera ......................................................................................................................... 85 
Continued . . .
ii TABLES OF CONTENTS (continued)
C-Quest Chemical Sorbent System ........................................................................... 87 
SkyMine® Process ..................................................................................................... 87
New Sky Energy ........................................................................................................ 87 
Cemtrex – Carbondox Process .................................................................................. 88
Reduction ............................................................................................................................ 88 
Photosynthesis ........................................................................................................... 88 
Chemical and Biochemical Processes ....................................................................... 90 
EVALUATION AND DIRECT COMPARISON OF CAPTURE TECHNOLOGIES BY
THE PCO2C .................................................................................................................................. 93
SUMMARY .................................................................................................................................. 93 
REFERENCES ............................................................................................................................. 94
INDEX ........................................................................................................................................ 123
CO2 CAPTURE TECHNOLOGIES .............................................................................. Appendix A
iii
LIST OF FIGURES
1 Schematic of precombustion CO2 capture ............................................................................ 2
2 Schematic of an oxycombustion system ............................................................................... 4
3 Chemical-looping combustion .............................................................................................. 6
4 Schematic for postcombustion CO2 capture .......................................................................... 7
5 Carbon capture technology categories .................................................................................. 8
6 Chemical solvent-based absorber–stripper for CO2 capture ............................................... 10
7 CO2 loading capacity of different solvents ......................................................................... 11
8 Selexol process schematic ................................................................................................... 12
9 Process scheme for the Rectisol process ............................................................................. 14
10 Regeneration efficiency in the desorber for a reboiler duty of 2.5–8.5 MW ...................... 17
11 Decreasing thermal energy requirement for use of chemical solvents in
commercial-scale CO2 capture plants .................................................................................. 17
12 The Fluor Econamine FG Plus for coal-fired power plant flue gas .................................... 20
13 MHI CO2 capture reference plants ...................................................................................... 21
14 Benfield process .................................................................................................................. 23
15 Aker Clean Carbon’s MTU for testing chemical solvent-based CO2 capture ..................... 24
16 ALSTOM CAP .................................................................................................................... 25
17 Simplified process flow diagram of the Cansolv SO2–CO2 integrated capture process ..... 28
18 HTC Purenergy CCS system ............................................................................................... 30
19 BASF screening of substances for use in chemical absorption CO2 capture ...................... 31
20 Postcombustion CO2 capture pilot plant in Niederaussem, Germany ................................. 31
Continued . . .
iv LIST OF FIGURES (continued)
21 Powerspan’s proprietary solvent ECO2 process .................................................................. 32
22 Sargas process ..................................................................................................................... 34
23 Amino acid–salt absorption reaction scheme ...................................................................... 35
24 Membrane absorption with gas on shell side ...................................................................... 37
25 Cost comparison of CORAL solvents to MEA ................................................................... 38
26 Akermin immobilized carbonic anhydrase ......................................................................... 42
27 Conceptual illustration of the Carbozyme contained liquid membrane permeator ............. 42
28 Carbozyme proprietary absorber–stripper system ............................................................... 43
29 Relative CO2 transfer rate using no enzyme (blue), enzyme immobilized to column
packing (red), and enzyme suspended in solution (green) .................................................. 44
30 Relative improvement in CO2 absorption observed in five chemical absorption
solutions .............................................................................................................................. 44
31 IVCAP process .................................................................................................................... 45
32 Synthetic small-molecule catalysts based on the active center of carbonic anhydrase ....... 47
33 Capture mechanism of a one-component reversible ionic liquid ........................................ 50
34 General scheme for PSA ..................................................................................................... 52
35 Classification of adsorbent types based on ADA–ES screening tests ................................. 54
36 Porous cage structure of zeolite ZSM-5 .............................................................................. 55
37 ATMI’s adsorbent carbon materials .................................................................................... 56
38 Schematic of SRI International novel carbon sorbent system ............................................. 57
39 Scheme showing the steps employed in the ESA process to capture CO2 from flue
gases .................................................................................................................................... 58
Continued . . .
v LIST OF FIGURES (continued)
40 RTI International capture process using dry regenerable sorbent ....................................... 60
41 Dry carbonate process ......................................................................................................... 61
42 Examples of MOF structures ............................................................................................... 63
43 CO2 capture unit with metal monolithic amine-grafted zeolites ......................................... 66
44 Work required to develop membrane separation technologies ........................................... 68
45 Types of membranes used in separations ............................................................................ 68
46 Separation behavior in membranes ..................................................................................... 69
47 Gas flow paths in membrane modules ................................................................................ 69
48 Eltron’s oxygen transport membrane .................................................................................. 72
49 Schematic of catalytic membrane reactor with oxygen transport membrane and
photomicrograph of the oxygen-permeable CMR ............................................................... 73
50 Eltron’s hydrogen transport membrane ............................................................................... 74
51 Sketch of the new HMR Process with HMR syngas reactor and separate CO2 removal
unit ....................................................................................................................................... 75
52 HMR monolith .................................................................................................................... 75
53 CO2/N2 selectivity versus CO2 permeance plot comparing membrane performance .......... 78
54 MTR’s process design for flue gas CO2 capture ................................................................. 79
55 Packing design of the MTR membrane modules ................................................................ 79
56 Flow diagram for the CCC process ..................................................................................... 81
57 ExxonMobil CFZ technology .............................................................................................. 83
58 Alcoa CO2 capture system ................................................................................................... 84
Continued . . .
vi LIST OF FIGURES (continued)
59 Accelerated weathering of high-magnesium-content minerals ........................................... 85
60 Calera CO2 capture and mineralization process .................................................................. 86
61 Electrochemical generation of alkalinity for the Calera CO2 capture and mineralization
process ................................................................................................................................. 86
LIST OF TABLES
1 Performance Penalties of a Chilled Ammonia CO2 Separation System ............................. 26 
2 List of Cansolv CO2 Pilot Projects Through Early 2008 .................................................... 28 
3 Five Reactor System Types for Use of Solid Sorbents ....................................................... 53 
vii
NOMENCLATURE
AAP advanced amine process
ADA–ES ADA–Environmental Solutions
ADEME French Environment and Energy Management Agency
AEP American Electric Power
AHPC activated hot potassium carbonate
aMDEA activated methyldiethanolamine
Ar argon
ARPA-E Advanced Research Projects Agency – Energy
As arsenic
ASU air separation unit
atm atmosphere
ATMI Advanced Technology Materials, Inc.
AVS Antelope Valley Station
AZEP advanced zero emission power plant
Btu British thermal unit
°C degree Celsius
CA carbonic anhydrase
CaCO3 calcium carbonate
CaO calcium oxide
CAP chilled ammonia process
CCC cryogenic carbon capture
CCP CO2 Capture Project
CCPI Clean Coal Power Initiative
CCS carbon capture and storage
CDCL coal direct chemical looping
CFCMS carbon fiber composite molecular sieve
CFZ controlled-freeze zone
CLC chemical-looping combustion
CMR catalytic membrane reactor
CO carbon monoxide
CO2 carbon dioxide
COE cost of electricity
COS carbonyl sulfide
CSM Colorado School of Mines
CTI Cansolv Technologies, Inc.
DCC direct-contact cooler
DEA diethanolamine
DEP Department of Environmental Protection
DGA diglycolamine
DICP Dalian Institute of Chemical Physics
DIPA diisopropanolamine
DMC dimethylcarbonate
Continued . . .
viii
NOMENCLATURE (continued)
DOE U.S. Department of Energy
DSME Daewoo Shipbuilding & Marine Engineering Co. Ltd.
ECBM enhanced coalbed methane
ECN Energieonderzoek Centrum Nederland (Netherlands Energy Research
Foundation)
ECO electrocatalytic oxidation
EERC Energy & Environmental Research Center
EET Environmental Energy Technology, Inc.
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EPRI Electric Power Research Institute
ESA electrical swing adsorption
ESP electrostatic precipitator
°F degree Fahrenheit
FGD flue gas desulfurization
GTI Gas Technology Institute
H2 hydrogen
H2S hydrogen sulfide
ha hectare
HAMR hybrid adsorption membrane reactor
HAS hyperbranched aluminosilica
HCl hydrochloric acid
Hg mercury
HHV higher heating value
hr hour
HR heat of reaction
HMR hydrogen membrane reformer
IGCC integrated gasification combined cycle
IL ionic liquid
IMPACCT Innovative Materials & Processes for Advanced Carbon Capture Technologies
INEEL Idaho National Energy and Engineering Laboratory
ISGS Illinois State Geological Survey
ITM ion transport membrane
IVCAP integrated vacuum carbonate absorption process
K2CO3 potassium carbonate
KHCO3 potassium bicarbonate
kg kilogram
KHMAS Kvaerner Hybrid Membrane Absorption System
kJ kilojoules
KM CDR Kansai Mitsubishi Carbon Dioxide Recovery
kWe kilowatt electrical
kWh kilowatt hour
Continued . . .
ix NOMENCLATURE (continued)
kWth kilowatt thermal
kPa kilopascal
LANL Los Alamos National Laboratory
lb pound
LDH layered double hydroxide
LHV lower heating value
LP low pressure
m meter
m3 cubic meter
MCM mixed conducting membrane
MDEA methyldiethanolamine
MEA monoethanolamine
MgCO3 magnesium carbonate
MgO magnesium oxide
Mg(OH)2 magnesium hydroxide
MHI Mitsubishi Heavy Industries
MJ megajoules
MMBtu million Btu
MPCRF multipollutant control research facility
MOF metal organic framework
MPa megapascal
MR membrane reactor
MTR Membrane Technology & Research, Inc.
MTU mobile test unit
MVA monitoring, verification, and accounting
MW megawatt
MWe megawatt electrical
MWh megawatt hour
N2 nitrogen
NAM N-acetylmorpholine
NaCl sodium chloride
Na2CO3 sodium carbonate
NaHCO3 sodium bicarbonate
NaOH sodium hydroxide
NETL National Energy Technology Laboratory
NFM N-formylmorpholine
NH3 ammonia
Nm3 normal cubic meter
NMP N-methyl-2-pyrrolidone
NO2 nitrogen dioxide
NOx nitrogen oxides
Continued . . .
x NOMENCLATURE (continued)
NSE New Sky Energy
NSG Neumann Systems Group, Inc.
NTUA National Technical University of Athens
O2 oxygen
ORNL Oak Ridge National Laboratory
PAMAM poly(amidoamine)
PBI polybenzimidazole
pc pulverized coal
PCCC postcombustion carbon capture
PCO2C Partnership for Carbon Capture
PCOR Plains CO2 Reduction (Partnership)
Pd palladium
PDC Process Design Center
PEEK polyether ether ketone
PFBC pressurized fluidized-bed combustion
PNGC pressurized natural gas combustion
PNNL Pacific Northwest National Laboratory
POSTCAP™ Siemens Technology for postcombustion CO2 capture
ppm parts per million
ppmv parts per million by volume
PSA pressure swing adsorption
psi pounds per square inch
psia pounds per square inch absolute (gauge pressure plus barometric pressure,
which is about 14.7 psi)
psig pounds per square inch gauge
PTFE polytetrafluoroethylene
PVDF polyvinylidene fluoride
PZ piperazine
RITE Research Institute of Innovative Technology for the Earth
RTIL room-temperature ionic liquid
scfd standard cubic feet per day
SCR selective catalytic reduction
SEWGS sorption-enhanced water–gas shift
SO2 sulfur dioxide
SO3 sulfur trioxide
SOx sulfur oxides
SRI Stanford Research Institute
STEP Solar Thermal Electrochemical Photo (carbon capture)
TEA triethanolamine
TIPS ThermoEnergy Integrated Power System
TRE theoretical regeneration energy
TSA temperature swing adsorption
Continued . . .
xi NOMENCLATURE (continued)
tonne metric ton
ton short ton
UTRC United Technologies Research Center
vol% volume percent
VPSA vacuum pressure swing adsorption
VSA vacuum swing adsorption
WGS water–gas shift
ZIF zeolitic imidazolate framework 
xii
CURRENT STATUS OF CO2 CAPTURE TECHNOLOGY DEVELOPMENT AND
APPLICATION
EXECUTIVE SUMMARY
Industries around the world are investigating ways to decrease their carbon footprint as
concerns are raised about the effects of carbon dioxide (CO2) as a greenhouse gas. These
methods include improving process efficiencies so that less carbon-based fuel is used, switching
to fuels with lower fossil carbon content (e.g., biomass or biomass blends, augmentation by wind
or solar power), and capture of the CO2 produced for either beneficial reuse or for permanent
storage. CO2 capture, which will be required at most, if not all, existing power generation
facilities to meet the current national CO2 reduction goals, is currently an expensive process. For
this reason, considerable effort is being focused on the development of more efficient, costeffective capture techniques. This report identifies and briefly discusses carbon capture
technologies that are currently available and/or under development. The vendors who are
involved in the sale and/or development of these technologies are also identified, as are the key
technical references, which provide technical and economic details for those readers interested in
investigating the individual capture technologies in more detail.
The CO2 capture technologies that are addressed in this report are summarized in
Figure ES-1, which provides an illustration of the technical approaches that can be taken to effect
the capture of CO2 derived from fossil fuel combustion. As shown, there are three opportunities,
or platforms, for capturing CO2 from fossil fuel combustion systems: before (pre), during
(through combustion modification), and after (post) combustion. The specific categories of CO2
capture technologies that are available for use in one or more of these platforms include
absorption, adsorption, membranes, and other techniques such as mineralization, reduction, and
cryogenic methods. The Plains CO2 Reduction (PCOR) Partnership has gathered information on
the state of the art of these CO2 capture technologies as applied to each of these three platforms.
Every effort has been made to provide the most comprehensive information possible, but because
of the proprietary and dynamic nature of technology development, not every CO2 capture
technology currently under development has been included. This report summarizes most of the
relevant technologies for which information is currently available.
Precombustion
Precombustion removal refers to near-complete capture of the CO2 prior to fuel
combustion and is usually implemented in conjunction with gasification (of coal, coke, waste
biomass, or residual oil) or steam reforming/partial oxidation of natural gas to produce syngas,
which contains carbon monoxide and hydrogen (H2). Subsequent conversion via the water–gas
shift reaction produces CO2 from the CO, resulting in H2-rich syngas. This syngas (often with
xiii
Figure ES-1. Carbon capture technology categories.
nitrogen added for temperature control) can be combusted in gas turbines, boilers, or furnaces.
Purified H2 can be used in fuel cells.
Typical CO2 stream concentrations before capture are 25 to 40 volume percent at pressures
ranging from 360 to 725 psia. This high partial pressure of CO2, relative to that of combustion
flue gas, enables separation using physical solvents. A physical solvent utilizes the pressuredependent solubility of CO2 in the solvent (as opposed to a chemical reaction with the solvent) to
separate the CO2 from the mixed-gas stream. Processes being developed for using physical
adsorbents (e.g,. zeolites, activated carbon), chemical adsorbents (e.g., metal oxides and metal
hydroxides), and membrane systems including those that are selectively permeable to oxygen,
hydrogen, or carbon are commercially applied in the gas-processing industries, and some are at
small pilot demonstration scale for use in CO2 capture, but most are currently at the research and
development stage.
The majority of the commercial capture technologies, e.g., Selexol™, Rectisol®, and
Purisol®, were developed in the mid-1900s and were utilized for acid gas (hydrogen sulfide and
CO2) removal by the early developers of commercial synthetic fuel (synfuel)-manufacturing
plants (such as coal gasification). Hence, these technologies were an integral part of the synfuel
demonstration tests that were conducted by the Synthetic Fuels Development Corporation in the
early 1980s. The Synthetic Fuels Development Corporation was a U.S. government-funded
corporation established in 1980 by the Synthetic Fuels Corporation Act to create a financial
bridge for the development and construction of commercial synthetic fuel-manufacturing plants
in the United States. The efforts of the corporation focused heavily on the execution of
demonstration tests of coal conversion technologies throughout the country, including the Great
Plains Synfuels Plant in Beulah, North Dakota. The corporation was abolished in 1985 as a result
of the drop in worldwide oil prices that occurred in the early 1980s. Similarly, the use of
xiv
alkanolamines for acid gas management is also at a commercial scale, having been developed
early in the 20th century, with the first patent granted in 1930. This long history of largescale/commercial applications of these gas purification technologies has placed them as clear
front runners for the precombustion capture of CO2.
During Combustion
With process modification, a concentrated stream of CO2 can be generated during
combustion in a process called oxygen combustion, or oxycombustion. Substitution of pure
oxygen for the combustion air produces a CO2-rich flue gas that requires minimum processing
before use or permanent storage. Typically, the CO2 can be recovered by compressing, cooling,
and dehydrating the gas stream to remove traces of water that are generated during combustion.
When the end use requires it, any noncondensable contaminants that may be present such as N2,
nitrogen oxides oxygen (O2,) and argon can be removed by flashing in a gas–liquid separator.
The oxycombustion processes that are being developed include technologies represented
by modified or retrofitted combustion units, new combustion units, and other processes that
incorporate membranes into the combustion chamber (advanced zero emission power plant),
combine high-pressure combustion and exhaust gas condensation (ThermoEnergy Integrated
Power System), or utilize oxygen provided by metal oxide oxygen carriers to combust the fuel
(chemical looping). Oxycombustion can be performed at elevated temperature which requires the
use of specially designed combustion chambers (new construction) or with the recirculation of
flue gas so that combustion temperatures are controlled at or near those typically used in air-fed
boilers. Recirculated flue gas-based oxycombustion has the potential to be applied as a retrofit
technology, but its application will require eliminating virtually all leakage of air into the
combustion chamber and flue gas treatment path. Chemical-looping combustion (CLC)
technologies use solid oxidant materials (e.g., metal oxides) that are recirculated from air-contact
chambers to the combustion chamber through the use of moving beds or circulating fluidized
beds. It is unlikely that CLC will be applied as a retrofit technology. All of the “during
combustion” technologies are currently in the developmental stage.
Besides the combustion unit retrofits, which are necessary to accommodate the higher
temperatures that occur during combustion in an oxygen-rich environment or to allow for flue
gas recirculation as the dilution gas, the other processes are all under development at the large
pilot scale or below. For example, many groups are conducting chemical-looping development
studies, which include applications to the combustion of coal, petroleum coke, natural gas, and
syngas as well as use in syngas and hydrogen production and incorporation into integrated
gasification combined. ALSTOM has run a successful pilot-scale, 10-lb/hr chemical-looping coal
combustion system and is currently involved in scaling this to 1000 lb/hr. At the same time,
Eltron Research and Development has been awarded a Phase I Small Business Innovation
Research project funded by the U.S. Department of Energy (DOE) that will develop an advanced
coal gasification system based on the use of chemical looping.
In addition to the previously discussed developments, there is also a need to optimize the
separation of oxygen from air, minimizing the parasitic power load associated with this unit
operation of oxycombustion. Relative to coal gasification, combustion requires up to three times
xv the amount of pure oxygen. The air separation unit capacity and its associated parasitic power
load are commensurately larger. Separation of oxygen from air is expensive and is currently
performed at very large scale by cryogenic distillation. Other methods of separating oxygen for
use during oxycombustion are being developed, most notably oxygen or ion transport
membranes. These membranes operate at temperatures of roughly 500°C, meaning that oxygen
separation can be integrated with the combustion process, providing a theoretically significant
reduction in parasitic power loss and O2 production cost. Oxygen transport membranes are under
development by Praxair and ALSTOM Power, while an ion transport membrane process is being
developed by Air Products and Chemicals. Eltron Research and Development is an ion transport
membrane technology developer that has developed both O2-permeable and H2-permeable
membranes.
Postcombustion
The most common CO2 separation platform is postcombustion, where the CO2 is removed
from low-pressure, low-CO2-concentration flue gas following other pollution control devices.
Several types of postcombustion processes have been and are being developed to separate and
remove the CO2 from a flue gas stream, such as absorption, adsorption, membrane, and
cryogenic processes and other methods that include mineralization for either disposal or to
produce a mineral product and reduction to produce beneficial products such as fuels and/or
plastics.
Postcombustion technologies range in scale. There are commercial processes that have
been in use for acid gas management for many years. Some research processes are undergoing
either pilot- or demonstration-scale testing. Current early-phase research and development
processes involve small-scale testing of new chemicals, catalysts, membranes, and/or process
configurations. Postcombustion capture technologies are critically important to meeting the
national CO2 emission reduction goals because they are the technologies that can be applied to
the existing power generation fleet. Implementation of this emission control strategy can begin
immediately through the application of available commercial technologies, but it is critical that
parallel efforts continue to further optimize these technologies to improve both CO2 capture
efficiency and cost. Also of critical importance is the continued development of innovative
techniques that are less capital- and energy-intensive, are amenable to in-plant retrofits, and can
produce usable by-products from the captured CO2.
The following paragraphs describe some of the postcombustion technologies that could be
applied to CO2 capture from combustion systems. It is important to note that some of the
technologies listed here could also be applied to precombustion applications.
Absorption
Absorption systems that are used to capture CO2 include physical solvent-based absorption
systems that would be applicable for precombustion applications and chemical solvent-based
absorption systems for precombustion and postcombustion applications. The most typical system
design for both physical and chemical solvent use involves contacting the lean solvent and the
CO2-containing gas stream in an absorption tower. The loaded, or rich, solvent is then
xvi
regenerated. Physical solvents can be regenerated through pressure reduction and/or heating.
Chemical solvents are generally regenerated by heating, which reverses the reaction and releases
the CO2. The CO2-lean solvent is then recirculated for reuse. Amines are the most commonly
used chemical absorbent for CO2 separation from mixed-gas streams. The baseline amine is
monoethanolamine (MEA).
Other chemical absorption systems are being developed to improve the cost-effectiveness
of CO2 capture through higher CO2 absorption capacities, faster CO2 absorption rates, reduced
solvent degradation, reduced solvent corrosiveness, and lower-regeneration energy requirements.
These development and/or optimization efforts, which typically are amine- or ammonia-based,
range from bench to pilot scale.
New developments in the area of chemical absorption include the use of additional
solvents in absorber–stripper systems, the use of enzyme-based and enzyme-inspired catalysts,
the development of new absorbents for CO2 capture, and the development of mass-transfer
devices other than absorption towers.
Adsorption
Adsorption CO2 capture technologies remove CO2 from mixed-gas streams onto the
surface of solid sorbents. These sorbents generally have very high porosity, and therefore, high
surface areas are available per unit mass and per unit volume. As is the case with absorption,
adsorption can be a simple phase-partitioning physical adsorption or it can involve a chemical
reaction between the sorbent and CO2. Regeneration of the sorbent beds is typically performed
by temperature or pressure swing techniques, although work is being performed on electrical
swing adsorption processes.
Mixed Absorption–Adsorption
Mixed absorption–adsorption processes are those that employ a liquid absorbent (typically
a chemical absorbent) trapped in or on the solid support. These are often classified with
adsorption processes because they employ similar gas–solid contact arrangements (fixed-bed,
fluid-bed, or moving-bed reactors), but the actual capture process occurs in a liquid layer or
liquid droplet contained on or in the support. Most commonly, the chemical sorbent is an amine,
although ionic liquids are likely candidates for this type of use.
Membrane Processes
Membranes employ a permeable barrier between two fluid-phase zones. This permeable
barrier provides selective transport of CO2 or other gas component. Desirable membranes are
highly selective and have a high permeability for the molecule to be transported. Development of
successful membrane processes involves not only selection of membrane materials with
favorable properties but also the development of the physical devices or membrane modules that
allow the membranes to be used and the processing system in which the membrane module is
employed.
xvii
Polymer membranes can also be used for postcombustion CO2 capture and lowertemperature H2/CO2 separations. These processes are a hot topic and were recently given
considerable attention in a special issue of the Journal of Membrane Science that was dedicated
to the topic “Membranes and CO2 Separation.” The conclusions that may be reached from
review of the papers is that, while membrane-based postcombustion CO2 capture has not yet
developed to the point where it can be commercially applied, the advances being made in
materials, modules, and process design show promise that membrane processes will play a role
in the future.
Cryogenic
In cryogenic CO2 capture, a mixed-gas stream is compressed, and the heats of compression
and condensation are removed. The stream can be 1) compressed to about 1100 psia, with water
used to cool the stream; 2) compressed to 250–350 psia at 10° to 70°F, dehydrated using
activated alumina or silica gel, and the condensate distilled in a stripping column; or
3) dehydrated and cooled to even lower temperatures (−78.5° to −109°F or lower) in order to
condense the CO2.
Mineralization
CO2 capture by mineralization occurs when the CO2 forms a stable mineral carbonate or
bicarbonate. Typically, these materials are formed using calcium and magnesium cations. The
end products of the mineralization processes can either be disposed of, sold as a product, or used
to generate another useful product such as aggregate or a type of cement. Several organizations
are investigating this approach to carbon sequestration, with the goal of generating revenues to
offset the costs of CO2 capture and sequestration.
Reduction
Reduction is the chemical transformation of the CO2 to a reduced state through the input of
energy. This concept incorporates the conversion of CO2 into an organic compound such as a
polycarbonate plastic, a fuel, or some other desired product. The process makes sense from an
energy balance perspective only when the product is of high value, the fuel is effectively an
energy storage product made from an intermittent energy supply source (e.g., wind, solar), and/or
the fuel produced is useful in ways that the original source fuel was not (e.g., production of a
transportation fuel from coal-derived CO2). While many projects dealing with the beneficial
reuse of CO2 will use precaptured and prepurified CO2, some projects will be focused on the
direct capture of the CO2 from flue gas (after removal of common contaminants).
CO2 capture also can be coordinated with reduction of CO2 to a beneficial use product.
This approach is being performed and/or investigated in closed-environment agriculture for
growth of flowers and food crops and in coordination with the growth of algae, microalgae, and
cyanobacteria used in the production of biofuels. The reducing equivalents for these processes
are provided through the photosynthetic capture of solar energy.
xviii
Evaluation of Capture Technologies
The Partnership for CO2 Capture at the Energy & Environmental Research Center is a
multiclient-funded (DOE, utility, and industry participants) program separate from the PCOR
Partnership that is focused on CO2 capture technology testing, demonstration, and development.
Oxycombustion and postcombustion testing capabilities were added to an existing fuel-flexible
combustion test unit (coal, natural gas, biomass). This system already included a selective
catalytic reduction unit, an electrostatic precipitator, a fabric filter, wet flue gas desulfurization,
and a spray dryer absorber as well as facilities for testing ash fouling, flame behavior, and other
aspects of concern with respect to coal combustion. Oxycombustion tests using pure O2 and
recycled flue gas yielded flue gas CO2 concentrations as high as 85% and over 90% for short
periods of time. The retrofit for postcombustion capture included the addition of a solvent
absorber–stripper system for CO2 capture. Three solvents have been tested to date: MEA as a
base case, a mixture of methyldiethanolamine MDEA and piperazine, and a proprietary solvent,
H3-1, from Hitachi. Engineering economic analysis performed based on the experimental results
from the oxycombustion and postcombustion tests revealed that the least-cost alternative in terms
of both energy penalty and cost of electricity was the use of H3-1. Future work will include
testing of additional solvents as well as the Neumann Systems Group contactor as an alternative
to the traditional column-based absorber–stripper. Solid sorbent testing is planned as well. 
Summary of Capture Technologies
Appendix A summarizes the technologies included in this Executive Summary and
described in more detail in the report. The reader can use the appendix to make comparisons
between technologies within various broad topics. The main body of this report includes
descriptions of the various technologies that were derived from publicly available literature. For
more detail about a particular technology, the reader is invited to explore the sources listed for
that technology.
Conclusion
Considerable effort is being expended to develop a variety of cost-effective CO2 capture
technologies. Some technologies exist that can likely be applied in the near term, while others
will require many years of development, testing, and demonstration. A few of the technologies
offer the hope of being “game changers”—technologies that dramatically reduce CO2 emissions
at very low cost. Even so, there is still room for all entities with an interest or expertise in the
area of CO2 capture to be involved in addressing this critical research need as well as a vital need
for continued funding in the area.
1
CURRENT STATUS OF CO2 CAPTURE TECHNOLOGY DEVELOPMENT AND
APPLICATION
INTRODUCTION
As concerns are raised about the effects of greenhouse gas emissions, primarily carbon
dioxide (CO2), industries around the world are investigating ways to decrease their carbon
footprint. These methods include improving process efficiencies so that less carbon-based fuel is
used, switching to fuels with lower fossil carbon content (e.g., biomass or biomass blends,
augmentation by wind or solar power), and capture of the CO2 produced for either beneficial
reuse or for permanent storage. Because CO2 capture is currently an expensive process,
considerable effort is being focused on the development of more efficient, cost-effective capture
techniques.
There are three opportunities to capture CO2 from a fossil fuel combustion system: before,
during (through combustion modification), and after combustion. This report, prepared by the
Plains CO2 Reduction (PCOR) Partnership, discusses the state of the art in CO2 capture
technologies for each of these three platforms. Every effort has been made to make it as
comprehensive as possible, but because of the proprietary and dynamic nature of technology
development, it is not realistic to assume that every CO2 capture technology currently under
development has been included.
CO2 CAPTURE PLATFORMS
Precombustion
Precombustion removal refers to near-complete capture of CO2 prior to fuel combustion
and is usually implemented in conjunction with gasification (of coal, coke, waste biomass, or
residual oil) or steam reforming/partial oxidation of natural gas to produce syngas, which
contains carbon monoxide (CO) and hydrogen (H2). Subsequent conversion via the water–gas
shift (WGS) reaction produces CO2 from the CO, resulting in H2-rich syngas. This syngas (often
with nitrogen [N2] added for temperature control) can be combusted in gas turbines, boilers, or
furnaces or, when the H2 is sufficiently purified, used in fuel cells. Figure 1 is a flow sheet
showing precombustion CO2 capture. The ultimate precombustion CO2 capture facility for use in
power generation is an integrated gasification combined cycle (IGCC) system employing CO2
capture. The U.S. Department of Energy (DOE) FutureGen Initiative was targeted toward
building a full-scale facility that would serve as an example of the use of this process. On
August 5, 2010, DOE announced FutureGen 2.0 as an advanced oxycombustion technology 2
Figure 1. Schematic of precombustion CO2 capture (taken from Figueroa and others, 2008).
based power-generation facility (U.S. Department of Energy, 2010c). Air separation units
(ASUs) are commonly employed to provide oxygen for gasification and nitrogen for the dilution
gas for IGCC systems.
Typical CO2 stream concentrations before capture are 25 to 40 vol% at pressures of 363 to
725 psia, but the range can be as great as 15% to 60%, with pressures from 290 to 1015 psia (2 to
7 MPa) (Metz and others, 2005). The high partial pressure of CO2, relative to that in combustion
flue gas, enables easier separation through solvent scrubbing. Commercially available physical
solvents that have been applied to precombustion CO2 capture include UOP’s Selexol™ process
(UOP, LLC, 2009b), the Rectisol® process (developed independently by Linde and Lurgi) (Linde
AG, 2010b; Lurgi GmbH, 2010a), and Lurgi’s Purisol® process (Lurgi GmbH, 2010b). In these
processes, the gas flows through a packed-tower absorber where it contacts the physical solvent
and, as a consequence, acid gases such as CO2 and hydrogen sulfide (H2S) dissolve into the
solvent. The acid gas-rich solvent flows to a second tower (stripper) where the CO2 is released
and the solvent is regenerated, usually by reducing the pressure.
In refineries and ammonia production facilities, where a lower-partial-pressure CO2
(<220 psia, 1.5 MPa), H2-rich syngas is produced by gas reforming, CO2 is recovered during acid
gas removal using chemical solvents such as MDEA (methyldiethanolamine, a tertiary amine)
that have low regenerator heat loads. Older systems used hot potassium carbonate processes
(e.g., Benfield™, CATACARB®). Modifications of these processes using promoted carbonate
are more popular now. Pressure swing adsorption (PSA) is also used where high-purity hydrogen
is required (UOP, LLC, 2005).
The majority of the commercial capture technologies, e.g., Selexol, Rectisol, and Purisol,
were developed in the mid-1900’s and were utilized for acid gas (H2S and CO2) removal by the
early developers of commercial synthetic fuel (synfuel)-manufacturing plants (such as coal
gasification) (Riesenfeld and others, 1974a). Hence, these technologies were an integral part of
3
the synfuel demonstration tests that were conducted by the Synthetic Fuels Development
Corporation in the early 1980s. The Synthetic Fuels Development Corporation was a U.S.
government-funded corporation established in 1980 by the Synthetic Fuels Corporation Act to
create a financial bridge for the development and construction of commercial synthetic fuelmanufacturing plants in the United States (Public Law 96-294). The efforts of the corporation
focused heavily on the execution of demonstration tests of coal conversion technologies
throughout the country, including the Great Plains Synfuels Plant in Beulah, North Dakota. The
corporation was abolished in 1985 as a result of the drop in worldwide oil prices that occurred in
the early 1980s. Similarly, the use of alkanolamines for acid gas management is also at a
commercial scale, having been developed early in the 20th century, with the first patent granted
in 1930 (Riesenfeld and others, 1974b). This long history of large-scale/commercial applications
of these gas purification technologies has placed them as clear front runners for the
precombustion capture of CO2.
Additional CO2 separation technologies under development for use in precombustion
include high-temperature, hydrogen-permeable membranes; technologies based on the use of
magnesium oxide or calcium oxide carbonation with regeneration by calcining the produced
magnesium carbonate (MgCO3) or calcium carbonate (CaCO3) (chemical-looping process); and
modification of the gasification process to include the use of a catalyst and high-temperature
CO2-selective adsorbent. One example of this is the sorption-enhanced reaction that uses a
packed-bed reactor to perform steam methane reforming or the WGS reaction.
ASUs are used to supply purified O2 for gasification. The type of ASU typically used
employs cryogenic distillation of air. This is an energy-intensive process; therefore, much work
is being done to develop oxygen-permeable membranes and chemical looping to supply oxygen
for gasification (e.g., syngas chemical-looping process, coal direct chemical-looping [CDCL]
process). Chemical looping for oxygen supply and oxygen-permeable membranes are discussed
further in the section on CO2 capture during combustion.
During Combustion
Technologies designed to allow CO2 capture during combustion mostly fall into one of two
categories: oxycombustion, where purified oxygen is supplied as the combustion gas rather than
air, and chemical-looping combustion, where a solid chemical adsorbent that reacts with oxygen
(metal oxide) is used to transport oxygen from an air contact reactor to the combustion chamber
where the oxygen is used for combustion and the solid is returned to the air contact reactor for
regeneration.
Oxycombustion
Substitution of oxygen for all of the combustion air has been proposed to produce a CO2rich flue gas requiring minimum separation for use or sequestration. Conventional air
combustion processes in boilers or gas turbines produce flue gas that contains predominantly N2
(>80 vol%) and excess oxygen (O2) in addition to CO2 and water. Separation technologies must
separate CO2 from these other components. If the air is replaced by oxygen, the N2 content of the
flue gas approaches zero (assuming minimal air leakage into the system), and the flue gas
4
contains predominantly CO2 along with a small amount of excess oxygen, combustion water, and
other contaminants (e.g., sulfur oxides [SOx] and nitrogen oxides [NOx]). The CO2 can be
recovered by compression, cooling, and dehydration. The basic oxycombustion approach is
shown in Figure 2.
The levels of noncondensable impurities and thermodynamics limit recovery of CO2 and
affect the purity of the product stream. The concentration of CO2 can be targeted to a specific
intended end-use application such as beneficial reuse or sequestration. For enhanced coalbed
methane (ECBM) recovery, it may be acceptable to allow some constituents (e.g., N2) to be
present that would not be acceptable where a supercritical fluid is required for enhanced oil
recovery (EOR) or deep reservoir injection. Where a supercritical fluid is required,
noncondensable contaminants such as N2, O2, and argon (Ar) are removed by flashing (rapidly
decreasing the pressure) in a gas–liquid separator.
There are several advantages to oxycombustion. The volume of flue gas reaching
downstream systems is one-third to one-fifth that of conventional coal boilers. The process
produces a flue gas stream containing more than 80 vol% CO2, depending upon the fuel
composition, purity of oxygen from the ASU, and air leakage into the boiler. Impurities such as
sulfur dioxide (SO2), NOx, particulate, and mercury become concentrated in the flue gas, thus
reducing capital and operating costs for contaminant removal. Levels of NOx (mostly fuelderived) may be low enough to eliminate the need for further control, and capital and operating
cost savings (for control systems) may offset air separation capital and operating costs.
Just as there are advantages to oxycombustion, there are challenges to its application.
Relative to coal gasification, oxycombustion requires that up to three times the amount of
oxygen be supplied by the ASU. Therefore, the ASU capacity (and parasitic power load) will be
commensurately larger. Separation of oxygen from air is expensive and is currently performed at
Figure 2. Schematic of an oxycombustion system (taken from Figueroa and others, 2008).
5
very large scale by cryogenic distillation. Other methods of separating oxygen for use during
oxycombustion and gasification are being developed, most notably oxygen transport membranes
and ion transport membranes. These membranes operate at temperatures of roughly 500°C,
meaning that oxygen separation can be integrated with the combustion and/or gasification
process, providing a theoretically significant reduction in parasitic power loss and O2 production
cost. Oxygen transport membranes are under development by Praxair and ALSTOM Power,
while ion transport membranes are being developed by Air Products and Chemicals and Eltron
Research and Development. These efforts are discussed further in the section on membranes
found later in this report.
Other challenges that must be met include changes in heat balance that can lead to system
operation at out-of-design conditions and a need to better understand gas-phase flame properties
such as radiant heat transfer and flame speed (U.S. Department of Energy National Energy
Technology Laboratory, 2008a). The higher combustion temperature is typically moderated
through recycle of a portion of the CO2 exhaust gas and/or gaseous or liquid water (Metz and
others, 2005).
Retrofit applications would be designed to maintain the same steam outlet conditions. The
higher heat capacity of the gas should potentially facilitate greater heat absorption while
producing lower flue gas temperature. Higher heat absorption would result in higher boiler
efficiency, but this would be offset by a higher auxiliary power load for fan power to the recycle
gas used for temperature control.
Development efforts involving conventional pulverized coal (pc) testing with
oxycombustion are at the scale of several hundred kilowatts and less. Developers and testing
organizations include CanmetENERGY, Mitsui Babcock, American Air Liquide, Babcock &
Wilcox, Foster Wheeler North America, and the Energy & Environmental Research Center
(EERC).
Oxygen firing in circulating fluid-bed boilers may have an advantage over pc firing in that
a significant degree of temperature control can be achieved by recirculating the solids. Lower
flue gas recycle would reduce parasitic power load for fans. In addition, higher O2 concentrations
may be possible, resulting in a smaller boiler island size and reduced capital cost. Development
issues center around continuous solids recirculation. Currently, testing is at the large pilot scale,
with development efforts being conducted by ALSTOM Power, ABB, Praxair, and Parsons
Energy.
Other processes that feature combustion in oxygen include the following:
 The advanced zero emission power (AZEP) process, being developed by ALSTOM
Power, replaces the combustion chamber of an ordinary gas turbine with a mixed
conducting membrane (MCM) reactor that includes a combustor, a low-temperature
heat exchanger, an MCM, and a high-temperature heat exchanger. The MCM reactor
separates O2 from the air for combustion with a fuel (natural gas) (Sundkvist and others,
2001; Möller and others, 2006).
6
 The ThermoEnergy Integrated Power System (TIPS) process, under development by
ThermoEnergy Corporation, utilizes high-pressure combustion (700 to 1300 psi) and
facilitates the condensation of exhaust components such as water and CO2 in a
condensing heat exchanger (Fassbender, 2005).
Chemical-Looping Combustion
In chemical-looping combustion, there is no direct contact between the air and the fuel.
The process utilizes oxygen provided by metal oxide oxygen carriers to combust the fuel,
producing CO2 and water. Once the steam is condensed, a relatively pure stream of CO2 is
produced, ready for beneficial reuse or permanent storage. Figure 3 is a schematic of a chemicallooping system. Chemical-looping development work is being performed by many groups.
Current work includes application of chemical looping to combustion of coal, petroleum coke,
natural gas, and syngas as well as its use in syngas and H2 production and incorporation into
IGCC. Interest in this technology is evidenced by the 1st International Conference on Chemical
Looping, held in Lyon, France, in March 2010 (IFP, 2010). Conference topics included
preparation and selection of appropriate oxygen carrier materials, the study of process operating
conditions and performance, and process integration. Pilot testing has been performed on
gaseous fuels at a scale of 50 kWth at the Korean Institute of Energy Research (Ryu and others,
2010), 120 kWth at the Vienna University of Technology (Pröll and others, 2010), and on solid
fuels at scales up to 10 kWth at Chalmers University. ALSTOM has run a successful pilot-scale,
10-lb/hr chemical-looping coal combustion system and is currently involved in scaling this up to
1000 lb/hr. They have reported successful demonstration of a 65-kWth pilot and have specified a
3-MWth chemical-looping prototype system for coal combustion (Andrus and others, 2010). The
Figure 3. Chemical-looping combustion (taken from Richards and Guthrie, 2010).
7
metal oxide compounds used as oxygen adsorbents in chemical looping are discussed further in
the section on adsorption.
Postcombustion
The most common CO2 separation platform is postcombustion, where the CO2 is removed
from low-pressure (<2 psig), low-CO2-concentration (<15 vol%) flue gas following the pollution
control devices. Several types of postcombustion processes have been and are being developed to
separate and remove the CO2 from a flue gas stream. These include absorption, adsorption,
membrane, cryogenic processes, other methods that include mineralization for either disposal or
to produce a mineral product, and reduction to produce a fuel or other product (e.g., plant, algae,
plastic). A schematic representing a coal-fired power plant with postcombustion capture is
shown in Figure 4. The box representing CO2 capture can contain any of a wide variety of
postcombustion technologies.
In postcombustion CO2 capture, the flue gas stream exiting the boiler contains diluents in
the form of N2 (as much as 80% of the dry gas), O2 (2% to 8%), Ar, NOx, and water vapor. For
coal and fuel oil combustion, it will typically also contain significant quantities of SOx, volatile
metals such as mercury (Hg) and arsenic (As), and particulate. It is generally necessary to
process coal, petroleum coke, and fuel oil flue gas upstream of the carbon capture process in
order to control NOx concentrations and speciation, remove most of the SOx, and remove
substantially all of the particulates and volatile metals. Flue gas from natural gas-fired boilers
and natural gas- and syngas-fired turbines will generally require little to no processing upstream
of the postcombustion CO2 capture process because the fuel has been cleaned before combustion.
However, these flue gas streams typically have lower CO2 concentrations (<8% vs. <15% for
coal and petroleum coke combustion) and higher O2 concentrations, thus making capture more
difficult thermodynamically.
Figure 4. Schematic for postcombustion CO2 capture (taken from Figueroa and others, 2008).
8
A variety of postcombustion carbon capture technologies are available. All of them would
be located at the end of the pollution control system process train as follows. The boiler is fed
coal and air, and NOx emissions are controlled by boiler design and operation as well as a
selective catalytic reduction (SCR) reactor, which utilizes ammonia. Sorbent and activated
carbon injection are used to control mercury and other emissions, while an electrostatic
precipitator (ESP) or baghouse is used to control particulate emissions, and a wet flue gas
desulfurization (FGD) unit is used to control sulfur emissions. The CO2 capture system will
likely include a polishing scrubber to remove residual sulfur to very low levels (called deep
sulfur scrubbing), a blower to boost the flue gas pressure sufficiently to overcome the CO2
capture system pressure drop, the CO2 capture technology, and dehydration and compression
units needed for transportation of the CO2 to permanent geological storage and/or for use in
EOR.
Details on the postcombustion capture technologies are contained in the section covering
all CO2 capture and separation technologies. Compression, transportation, and storage are not
addressed in this report.
CO2 CAPTURE AND SEPARATION TECHNOLOGIES
Figure 5 shows the relationship between the various CO2 capture technology types, with
shading provided to indicate the most common use based on the CO2 capture categories that have
been discussed: precombustion, during combustion, and postcombustion. The specific
technologies are categorized into absorption, adsorption, membranes, other, and alternative mass
Figure 5. Carbon capture technology categories.
9
transfer. Absorption is broken down into physical and chemical absorption without the oftenused term “mixed” because all chemical absorption includes some component of physical
absorption and is, therefore, a mixed technology. Adsorption is separated into physical,
chemical, and mixed adsorption, where mixed adsorption refers to solid-supported liquid
absorbents. The membrane category incorporates all permeance-selective membrane systems and
is divided into organic (including liquid, gel, and composite membranes) and inorganic
membranes. Organic membranes are most commonly used in postcombustion applications and in
the separation of CO2 from natural gas and cooled syngas, while inorganic membranes are most
commonly used in precombustion and other high-temperature separations. The category “other”
has been used for mineralization and reduction methods as well as other methods such as
cryogenic separation of flue gas that do not fit elsewhere. A final section on alternative mass
transfer devices includes information on technologies that hold promise to decrease the size of
absorber and, in some cases, stripper towers by increasing the specific surface area of gas–liquid
contact (i.e., how much contact area there is in a given volume). The alternative mass transfer
technology section is presented with chemical absorption.
Absorption
Absorption removes CO2 from flue gas streams by contacting the flue gas with a solvent.
Chemical and physical absorption are most commonly performed in packed-bed absorber and
stripper towers. CO2 is dissolved by the solvent and, in the case of chemical absorption, reacts to
form a carbonate, bicarbonate, or carbamate associated with the chemical absorbent. Figure 6 is a
diagram of flue gas scrubbing with a chemical absorbent in an absorber–stripper arrangement.
CO2-rich solvent is sent to a stripper tower where the CO2 is released and the lean solvent is
recycled back to the absorption (scrubber) tower.
Common physical solvents (which are used at high pressure) include methanol (Rectisol),
dimethyl ethers of polyethylene glycol (Selexol), and N-methyl-2-pyrrolidone (Purisol). Other
physical solvents such as propylene carbonate (Fluor solvent, JEFFSOL®-PC), other alkylene
carbonates, and morpholine derivatives (Morphysorb®, which is a mixture of N-formylmorpholine and N-acetyl-morpholine) are also used. Chemical CO2 absorbents include various
amines (e.g., MEA [monoethanolamine], DEA [diethanolamine], MDEA), ammonia, amino acid
salts, metal carbonates, metal hydroxides, and reactive ionic liquids. Catalysts, promoters, and
chemicals to protect against oxidation of the chemical absorbent and corrosion of the equipment
are often added. One significant development is in the use of the enzyme carbonic anhydrase and
synthetic compounds based on the reactive center of carbonic anhydrase as a catalyst.
Physical Absorption Technologies
Physical absorption processes for precombustion CO2 capture are generally applied along
with other acid gas (H2S, carbonyl sulfide [COS]) removal methods from gasification and
methane reforming (H2 production). The ultimate precombustion CO2 capture facility for use in
power generation from coal is an IGCC employing carbon dioxide capture. It is likely that some
IGCC plants that capture carbon will use physical solvent-based CO2 capture.
10
Figure 6. Chemical solvent-based absorber–stripper for CO2 capture (taken from Jensen and
others, 2009).
Physical solvents are used for high-pressure applications because at high pressures the
capacity of CO2 loading in physical solvents can far exceed that for loading into chemical
solvents (Lurgi GmbH, 2010a). This is illustrated in Figure 7. The graph shows that CO2 loading
in the chemical solvents MEA and aMDEA® (activated MDEA) is higher than for Rectisol
(methanol) at lower partial pressures but levels off as pressure increases. For physical solvents,
the loading of CO2 continues to increase linearly with increasing pressure. While Rectisol shows
the highest CO2 loadings on this graph, this occurs at temperatures that are at least 60°C lower
than the other solvents. The energy cost of reducing syngas or natural gas to this temperature for
treatment and other concerns such as the concentrations of H2S, CO2, and other constituents in
the syngas influence the process selection decision. A good review of physical solvents for acid
gas removal has recently been published (Burr and Lyddon, 2009).
There are three commercially available physical absorbent systems that have been
marketed for capture of CO2 from gasification fuel (syngas) and high-pressure natural gas
sweetening:
 Selexol (UOP, LLC) [Genosorb® [Uhde GmbH] – dimethyl ethers of polyethylene
glycol
 Rectisol (Lurgi GmbH, Linde AG) – chilled methanol
 Purisol (Lurgi GmbH) – N-methyl-2-pyrrolidone (NMP)
11
Figure 7. CO2 loading capacity of different solvents (after Lurgi GmbH, 2010a).
Other physical solvents and physical solvent-based, high-pressure acid gas-scrubbing systems
are marketed, including JEFFSOL-PC (Fluor solvent, marketed by Huntsman Chemicals), which
is propylene carbonate, and Morphysorb (Uhde GmbH), which is composed of morpholine
derivatives N-formylmorpholine (NFM) and N-acetylmorpholine (NAM).
Research also continues on the use and development of new physical solvents, including
dimethyl carbonate and perfluorinated solvents. Mixtures of physical solvents and chemical
solvents such as Shell Sulfinol (a mixture of diisopropanolamine and tetrahydrothiophene-1,1dioxide) and UCARSOL™ LE Solvent 703 (LE-703, a Union Carbide Corporation-developed
solvent made and marketed by Dow), and tertiary amines (e.g., aMDEA) are used in similar
high-pressure acid gas removal applications.
Selexol
The Selexol technology from UOP, LLC, uses Dow Chemical’s Selexol solvent, which is a
mixture of dimethyl ethers of polyethylene glycol. The molecular formula is
CH3O(CH2CH2O)nCH3, where n is between 3 and 9 (Kuryachiy, 2007). A similar process,
Genosorb, based on a similar chemical solvent mixture of dimethyl ethers of polyethylene
glycol, is also available from Uhde GmbH.
The Selexol technology is a liquid physical solvent-based system for removing acid gases
(H2S, CO2, and COS) from natural gas and syngas. It was developed over 35 years ago, and
12
55 commercial Selexol units had been put into service as of 2002 (Ciferno and others, 2006). It is
applicable at feed pressures greater than 350 psia and acid gas concentrations of >5% by volume.
It is generally regarded that a CO2 capture efficiency of more than 85% can be achieved using
the Selexol process (Metz and others, 2005). Selexol has a minimum operating temperature of
0°F (−18°C) (Bucklin and Schendel, 1984) and is typically operated at no more than 100°F
(Ciferno and others, 2006).
Figure 8 shows the single-stage Selexol process, which is used when the concentration of
H2S in the gas stream is low. The gas is contacted with the Selexol solvent in the absorber tower.
The acid gas-rich Selexol flows to the stripper tower, where it is heated to release the acid gases
(primarily CO2). The Selexol solvent is recycled back to the absorber tower (UOP, LLC, 2009b).
Selexol preferentially removes H2S over CO2, so when it is present with CO2 as more than
a low-concentration contaminant (such as in syngas), a two-stage Selexol process is used. In this
embodiment, the H2S is removed in an initial absorption step and CO2 is removed during the
second absorption. The process contains various recycle loops, heat exchangers, and flash
separation drums. Breckenridge and others (2000) provide a good description of a two-stage
Selexol process.
Advantages of the Selexol process include the fact that it has a higher capacity to absorb
gases at high pressure than amines; less heat is required for CO2 regeneration than is the case for
amine processes; CO2 is delivered at higher pressures than amine processes, meaning that less
Figure 8. Selexol process schematic (taken from UOP, LLC, 2009b).
13
compression is required for transport to a geologic storage site; it does not form heat-stable salts
during removal of H2S and organic sulfur compounds; and simultaneous dehydration of the gas
stream is provided (Clare and Valentine, 1984).
Disadvantages include the fact that the flue gas must be cooled to about 100°F and that
CO2 is regenerated by flashing, which requires recompression of the CO2 stream for its transport
(Ciferno and others, 2006).
Information about the Selexol process can be found in multiple sources (Breckenridge and
others, 2000; Chen and Rubin, 2009; Chiesa and others, 2004; Doctor and others, 1996; U.S.
Department of Energy National Energy Technology Laboratory, 2000; Pei, 2008; Probstein and
Hicks, 2006; UOP, LLC, 2009b).
Rectisol
Rectisol technology is available from both Linde AG and Lurgi GmbH and uses methanol
as the solvent. Lurgi provides the most complete description and process flow diagram for use in
H2S removal and CO2 capture in syngas production (Lurgi GmbH, 2010a). Linde does not
provide a process flow diagram showing CO2 capture (Linde AG, 2010b). Prosernat IFP Group
Technologies (2010) also supplies a methanol-based gas treatment process under the trade name
Ifpexol® but appears not to be targeting it for CO2 capture (Offshore Magazine, 2002).
The Rectisol process uses refrigerated methanol and usually operates at temperatures
between −40° and −80°F (−40° and −62°C), although it can be operated at temperatures as low
as −95° (−70.5°C) (Burr and Lyddon, 2009). Therefore, significant syngas cooling and reheating
and a high electricity use demand for refrigeration come with the use of the Rectisol process.
Great flexibility in process flow is possible for effecting a variety of separations, which may be
useful for syngas separation into various components. A process flow diagram for the Rectisol
process is given in Figure 9. All impurities and trace contaminants, such as CO2 (<2 ppmv),
COS, and H2S (sulfur <0.1 ppmv), are removed in a single absorption process, thus generating an
ultrapure product gas. In the single-stage Rectisol process for natural gas cleaning without CO2
capture, N2 stripping is used to separate the CO2 from the methanol. When applied to syngas
production, a two-stage Rectisol process is used for medium-pressure partial oxidation, with
once-through Rectisol purification used for high-pressure partial oxidation (Hochgesand, 1970).
Advantages of using the Rectisol process include low power consumption; inexpensive,
easily available solvent; and flexibility in process configuration. The high refrigeration costs hurt
the economics compared to Selexol and Purisol for H2S removal where CO2 remains in the
treated gas (i.e., where CO2 capture is not required), but the high CO2-loading capacity allows
low solvent flow rates compared to other physical solvent processes and helps make the
economics of the Rectisol process favorable for CO2 capture applications (Ranke and Mohr,
1985).
14
Figure 9. Process scheme for the Rectisol process (taken from Lurgi GmbH, 2010a).
Precombustion carbon capture using the Rectisol process is practiced at Dakota
Gasification Company’s Great Plains Synfuels Plant. The synfuels plant gasifies North Dakota
lignite to produce synthetic natural gas and other products and captures up to 50% of the carbon
originating in the coal as CO2 (a large portion of the remaining carbon is not emitted as much
remains in the synthetic natural gas and other organic carbon-based products produced by the
facility). Dakota Gasification Company presents more information on carbon capture at its
synfuels plant on its Web site (Dakota Gasification Company, 2010). Additional information
about the Rectisol process can be found in Hochgesand (1970), Linde AG (2010b), and Lurgi
GmbH (2010a).
Purisol
The Purisol process is marketed by Lurgi GmbH; however, it does not appear to be
actively marketing Purisol at this time and does not provide a separate brochure for Purisol. The
solvent used in the Purisol process is NMP. Purisol is used at temperatures between ambient and,
with refrigeration, about 5°F (15°C) (Burr and Lyddon, 2009).
Other Physical Solvents
JEFFSOL-PC
JEFFSOL-PC (aka Fluor solvent) is available from Huntsman Chemicals. It has been used
in the Fluor Solvent Process licensed by Fluor since the late 1950s. It is applicable for CO2
15
removal where little to no H2S is present. The operating temperature for JEFFSOL-PC systems is
limited to a range of 0°F (−18°C) to 149°F (65°C). It can be operated at intermediate pressures.
More information on JEFFSOL-PC is available in Burr and Lyddon (2009), Huntsman
Chemicals (2010), and Fluor Corporation (2010c).
Morphysorb
Morphysorb is a physical solvent for acid gas removal, marketed by Uhde GmbH. The
solvent is a mixture of two morpholine derivatives, NFM and NAM, and it is highly selective for
H2S. It is not clear that it would be applicable for use in CO2 capture. More detailed information
is available on the Uhde GmbH Web site (Uhde GmbH, 2010).
Shell Sulfinol
This process is sometimes listed as a physical solvent process, but it is a combined
physical and chemical solvent process. The physical solvent tetrahydrothiophene-1,1-dioxide
(sulfolane) makes up 25% by volume of the mixture (Burlington Resources Canada Ltd., 2010).
The chemical solvent diisopropanolamine (DIPA), a secondary amine, makes up approximately
35% to 45% by volume of the mixture (Burlington Resources Canada Ltd., 2010). The relative
amounts of DIPA and sulfolane are adjusted for each application. It is used mainly in natural gas
or syngas treatment where removal of both H2S and CO2 is important. It is used in a standard
absorber–stripper arrangement. While it is not expected to gain widespread use for
postcombustion CO2 capture, there is reasonable potential for it to be used in precombustion
applications (Burlington Resources Canada Ltd., 2010). More information on the Shell Sulfinol
process is available online (Surface Production Facility, 2010a, b).
Physical Solvents under Development
Recent research reports on new physical solvents include a study on the use of DMC
(dimethyl carbonate) by Gui and others (2010) and a report on the use of a perflorinated solvent
(PP25 solvents, perfluoro-perhydro-benzyltetralin, C17F30) by Heintz and others (2006). The
goal is to find a solvent with CO2 capacity approaching that of refrigerated methanol (Rectisol)
while operating at a much higher temperature. Gui and others (2010) conclude that DMC has a
greater ability to dissolve CO2 than propylene carbonate (JEFFSOL-PC) and methanol (Rectisol)
when used at the same temperature and the solubility of CO2 in DMC at room temperature
(25°C, 78°F) is close to that in methanol at −10°C (14°F).
Commercially Available Chemical Absorption Technologies
While physical absorption technologies are often used in precombustion CO2 capture and
almost never considered for postcombustion CO2 capture, chemical absorption technologies are
used in both precombustion and postcombustion CO2 capture. The original chemical absorbent
technologies—those applied before the use of amines—were based on the use of caustic
(hydroxide solutions) and hot carbonate solutions. The hot carbonate processes still have
commercial viability in precombustion CO2 capture. Regeneration of hydroxide solutions
16
requires excessive amounts of energy, but these solutions do find use in mineralization
applications.
The most readily available chemical absorption system for flue gas CO2 capture is amine
scrubbing with MEA. MEA is the most alkaline of the alkanolamines, a group of amines that
includes DEA, diglycolamine (DGA), DIPA, and triethanolamine (TEA). Along with being the
most alkaline MEA, it is the most strongly reactive of the alkanolamines listed, with respect to
both kinetics (the speed of the reaction with CO2) and thermodynamics (the strength of the
chemical bond). This means it is easier to remove CO2 from a flue gas with MEA than with the
other alkanolamines, but it costs more energy to strip the CO2 from solution in order to produce a
purified CO2 produce and regenerate the solvent for reuse.
Amine-based processes for acid gas removal can be and are commercially employed in
both precombustion and postcombustion CO2 capture applications, with MEA being the
traditional solvent of choice for lower-pressure applications and aMDEA (MDEA solution with
an activator, effectively a catalyst, added to it) the traditional solvent of choice for higherpressure applications. Several other reactive chemical solvents and solutions are also being
developed along with amines, hot carbonates, and caustics. These include ammonia (actually
ammonium carbonate), metal carbonate solutions applied at lower temperatures, amino acid
salts, and reactive ionic liquids. Catalysts, promoters, and chemicals to protect against oxidation
of the chemical absorbent and corrosion of the equipment are often added to chemical
absorbents. One area of significant development is the use of the enzyme carbonic anhydrase and
synthetic compounds based on the reactive center of carbonic anhydrase as a catalyst.
A primary advantage expected from the selection of chemical absorbents other than MEA
is reduction in the energy penalty of CO2 capture. This expected reduction would come primarily
from a reduction in the reboiler heat duty, where the decreased reboiler heat duty would come
largely from a decrease in the thermodynamic strength of the CO2–chemical absorbent bond and,
thus, a reduction in the temperature of the steam and the amount of steam required to effect the
desorption/stripping of the CO2. Other factors that affect reboiler heat duty on a CO2-masscaptured basis are the relative magnitude of CO2 loading of lean and rich solutions and the
concentration of the chemical absorbent in the absorbent mixture (Sakwattanapong and others,
2005; Oexmann and Kather, 2010; Ziaii and others, 2009).
Figure 10 illustrates the change in regeneration efficiency with respect to temperature for
three chemical solvents: ammonia, DGA, and MEA. It is clear from the plot that much higher
temperatures are required for regeneration (stripping) of MEA than for ammonia. DGA acts
differently, with a gradual increase in regeneration efficiency with temperature over the full
range.
The other improvements in energy efficiency of amine and other chemical solvent-based
systems come from process improvements such as optimizing solution chemistry through
adjustments in chemical concentration and the use of additives, the use of intercoolers in
absorption towers, and better process integration, particularly with respect to heat exchange and
heat recovery. Figure 11 illustrates the improvements made in lowering the thermal energy
required for MEA and other amine-based systems over time.
17
Figure 10. Regeneration efficiency in the desorber for a reboiler duty of 2.5–8.5 MW (after
Pellegrini and others, 2010).
Figure 11. Decreasing thermal energy requirement for use of chemical solvents in commercialscale CO2 capture plants (the value shown for third-generation solvents illustrates the goal of the
SOLVit development program) (taken from Nustad, 2009).
18
There are several commercially available chemical absorption systems that have been
marketed and commercially applied for capture of CO2:
 MEA-based processes
 Fluor’s Econamine FG℠ and Econamine FG Plus℠ processes – MEA
 Lummus Technology/CB&I – Lummus MEA absorption process – MEA
 Kansi Mitsubishi Carbon Dioxide Recovery (KM CDR) Process – KS-1 proprietary
(hindered secondary) amine
 Activated hot-potassium carbonate processes
 Benfield process – UOP, LLC
 CATACARB Process – Eickmeyer & Associates
 Exxon Flexsorb® HP process
 Giammarco-Vetrocoke’s process
MEA-Based Processes
Several commercial facilities use MEA-based solvents to capture CO2 from coal-, fuel oil-,
and natural gas-derived flue gas streams for use in the food industry and other beneficial uses.
These plants have had capacities in the range of 100 to 1100 tons/day, which is
significantly less than the 9000 tons/day produced by a 500-MW coal-fired plant. Commercial
providers of MEA-based CO2 capture technology include Fluor (Econamine FG and Econamine
FG Plus) and Lummus Technology/CB&I. MEA is also widely used for H2S scrubbing at oil
refineries and in acid gas removal from raw natural gas.
A diagram of a generic system employing an MEA process for CO2 capture was presented
in Figure 6. Flue gas cooled to approximately 110°F and compressed to 17.5 psia by a
centrifugal blower (to overcome the gas path pressure drop) enters the absorber base and flows
upward countercurrent to the lean MEA solution. CO2 is removed from the flue gas in the
packed-bed absorber column through direct contact with the MEA solution. The CO2-depleted
flue gas is exhausted to the atmosphere. The CO2-rich solution is heated in a heat exchanger
(cross exchanger) and sent to the stripper unit where low-pressure steam (taken from the steam
turbine crossover) is supplied to the reboiler for the thermal energy needed to liberate the
absorbed CO2. The CO2 vapor is condensed, cooled, and sent to a multistage compressor where
the CO2 is compressed to a pressure of over 1200 psia. The CO2-laden stream is dehydrated
using glycol or molecular sieve processes. After drying, the CO2 is ready for transport and
sequestration.
The MEA process can achieve flue gas CO2 recoveries of 80% to 95%, with product CO2
purities over 99 vol% (Metz and others, 2005). However, the MEA process also requires a
significant amount of power to operate pumps and blowers for gas and solvent circulation. The
largest parasitic load to the power cycle is associated with the steam used for solvent
regeneration. Solvent desorption heat consumption can be as high as 2.7 to 3.2 million Btu/ton
CO2 (Metz and others, 2005). Additional issues with the process are equipment corrosion;
19
solvent degradation caused by the presence of dissolved O2 and other impurities; or reaction with
SO2, SO3, and NOx to produce nonregenerable, heat-stable salts. This requires SO2 levels below
10 ppm, NO2 levels below 20 ppm, and NOx below 400 ppm. Solvent degradation and loss also
occur during regeneration.
Fluor – Econamine FG and Econamine FG Plus Processes
The Econamine FG capture system was developed by the Fluor Corporation after it
acquired the technology from Dow Chemical. It uses the primary amine MEA to capture CO2
from flue gas in a regenerable reaction. The technology is applicable to gas streams containing
3% to 20% CO2, with oxygen concentrations as high as 15% (by volume) (Fluor Corporation,
2010b). Proprietary corrosion and oxidation inhibitors are added to the MEA solvent to prevent
degradation. The first generation of the system, known as Econamine FG used a 30% by weight
MEA formulation. Econamine FG Plus technology is an advanced version of the Econamine FG
technology, with significant improvements to the solvent and system. The improved solvent
formulation provides a faster reaction rate and higher CO2-loading capacity. The process
improvements include a split-flow configuration, lean vapor compression, absorber intercooling,
and integrated steam generation (Reddy and others, 2003). These are claimed to have reduced
steam consumption by 20% and electricity consumption by 18% over the past 6 years (Broeils
and Johnson, 2009). Figure 12 is a schematic of the Econamine FG Plus carbon capture process
proceeded by a two-stage direct-contact cooler (DCC). Energy consumption for the Econamine
FG Plus system is 1395 Btu/lb CO2 captured.
Fluor’s Econamine systems are commercially operated in 24 plants around the world, with
10 additional plants on order (Reddy and others, 2008). The Econamine process can be applied
to power plants, steam reformers, and ammonia and MEA production plants. The Econamine FG
process is installed at a natural gas-fired power plant in Bellingham, Massachusetts, where
365 short tons per day of CO2 is recovered. Fluor and E.ON Energy plan to conduct a
demonstration of CO2 capture at a supercritical coal-fired plant using the Econamine FG Plus
system. The process has also been selected for a DOE-supported Clean Coal Power Initiative
(CCPI 3) project in which NRG Energy will evaluate the economine FG Plus process at the W.A.
Parish plant (U.S. Department of Energy National Energy Technology Laboratory, 2010f). The
goal is to capture up to 400,000 metric tons per year (1095 metric tons/day) of CO2. Detailed
information on the Fluor Econamine FG and FG Plus processes is available from the Fluor
Corporation (2010a).
Lummus MEA Absorption Process
The Lummus MEA absorption process, also known as the Kerr-McGee/ABB Lummus
Crest process (Barchas and Davis, 1992), has been used to recover CO2 from coke and coal-fired
boilers, delivering CO2 for soda ash and liquid CO2 preparations. It uses a 15%–20% by weight
aqueous MEA solution with corrosion and oxidation inhibitors. The largest-capacity plant using
this process produces 800 tons of CO2 per day while utilizing two parallel trains (Arnold and
others, 1982). The process has been used for production of both food- and chemical-grade CO2
for many years. Typically, about 75% to 90% of the CO2 in the flue gas is captured using this
20
Figure 12. The Fluor Econamine FG Plus for coal-fired power plant flue gas (taken from Broeils
and Johnson, 2009).
technology, producing a nearly pure (>99%) CO2 product stream (Rubin and Rao, 2002). The
process employs the same configuration as the other standard absorber–stripper processes.
The Lummus scrubber system is installed at the Shady Point cogeneration plant in Panama,
Oklahoma. The 320-MWe-net-output cogeneration plant is a circulating fluidized-bed
combustion-based facility that fires hard coal. The plant consumes roughly 800,000 metric tons
of coal each year. Approximately 5% of the flue gas is diverted and transported to the adjacent
CO2 capture plant by centrifugal blowers. About 65,000 lb/hr of 75-psig steam is used in the
capture facility to extract 200 tons per day of food-grade CO2 from the plant’s flue gas
(International Energy Agency, 2009a).
Another demonstration project using the Lummus scrubber at commercial scale is the
Warrior Run power plant in Cumberland, Maryland, a 180-MW cogeneration plant based on
circulating fluidized-bed combustion technology (International Energy Agency, 2009b). Nearly
150 tons of liquid CO2 per day is sold for fire extinguishers and food cooling. About 4 MW of
the gross electrical output is used to operate the capture plant (Page and others, 2009).
21
Mitsubishi Heavy Industries (MHI) – KM CDR Process
The KM CDR process offered by MHI is an intercooled absorber–thermal desorption
stripper (steam fed reboiler) CO2 capture process that uses the sterically hindered amine KS-1.
The process flow diagram is very similar to that for any other absorber–stripper process. The
hindered amine chemical absorbent KS-1 is reported to have a molecular structure that is tailored
to enhance its reactivity toward CO2. Reported benefits of the process include low regeneration
heat requirements, low solvent degradation without the use of additives or inhibitors, and low
amine losses (Jansen and others, 2007).
The history and capacity of MHI’s research, demonstration, and commercial plants for CO2
capture from natural gas and coal are shown in Figure 13. MHI has a significant and aggressive
history with development and demonstration of large-scale CO2 capture plants. The company
currently offers the KM CDR at full commercial scale, with performance guarantees for natural
gas-fired power plants. MHI expects to be able to offer similar full commercial-scale KM CDR
plants with performance guarantees once they gain sufficient operational experience with largescale facilities run on coal-derived flue gas (Iijima and others, 2010). Operation of the planned
facilities listed in Figure 13 would likely provide the desired operational experience necessary to
allow MHI to provide performance guarantees. More detailed information on MHI’s KM CDR
process is available from numerous sources (Iijima and others, 2010; Kamijo and others, 2004;
Mitsubishi Heavy Industries, 2006, 2010; Mimura and others, 2000; Ronald, 2008; Ohishi and
others, 2006; Yagi and others, 2006).
Figure 13. MHI CO2 Capture reference plants (the yellow-circled points represent planned
facilities) (taken from Iijima and others, 2010).
22
Activated Hot-Potassium Carbonate Processes
Commercially available activated hot-potassium carbonate (AHPC) processes employ
aqueous potassium carbonate (K2CO3) as the reactive solvent with an activator (catalyst) for the
chemical absorption of CO2 in an absorber operated at a relatively high temperature and high
pressure. The processes are applicable to precombustion capture. To improve CO2 absorption
mass transfer and to inhibit corrosion, proprietary activators and inhibitors are added. The most
widely licensed of the AHPC systems are the Benfield process, with over 675 units worldwide,
licensed by UOP, LLC (2010), and the CATACARB process, with over 100 units licensed as of
1992 by Eickmeyer & Associates (CATACARB, 2010). Other commercial AHPC processes are
the Exxon Flexsorb HP process, which uses a hindered-amine activator, and GiammarcoVetrocoke’s process, which uses an organic activator.
The Benfield and CATACARB processes are commercially offered for applications at a
minimum CO2 partial pressure of 210 to 345 kPa (1 atm = 101.325 kPa) and an optimum
operating pressure of 700 kPa. Solvent regeneration is accomplished through pressure reduction
and heating. Literature discussing the Benfield process indicates that recent process
improvements (new activator and improved column internals) have resulted in reduced CO2
concentrations in the treated gas and reductions in regeneration heat and solution pumping
requirements) (Chapel and others, 1999).
The absorption and regeneration of acid gases in the Benfield process are based on the
following reactions:
K2CO3 + CO2 + H2O → 2KHCO3 [Eq. 1]
K2CO3 + H2S → KHS + KHCO3 [Eq. 2]
The absorption and regeneration of acid gases are conducted in a similar way to that of the
conventional amine or carbonate processes. The gas to be treated is fed to the bottom of the
absorber and flows countercurrently to the absorbing liquid supplied at the top of the absorber.
Acid gases are then absorbed by the absorbing liquid. The liquid that has absorbed the acid gases
is preheated and then supplied to the top of the regenerator where the acid gases are stripped by
steam for the regeneration of the liquid. The regenerated liquid is cooled and recirculated to the
absorber. The process is shown in Figure 14.
Pilot- and Demonstration-Scale Chemical Absorption Technologies
Other chemical solvent processes have been demonstrated at the pilot scale or are in the
process of moving to pilot-scale demonstration. They are discussed in the following subsections.
Aker Clean Carbon
Aker Clean Carbon is involved in work on chemical solvent carbon capture. Its activities
include the following:
23
Figure 14. Benfield process (taken from UOP, LLC, 2009a).
 Development of new solvents through involvement with the CASTOR project and
SOLVit.
 Construction and operation of a mobile test unit (MTU) for testing solvent performance
on real flue gas (Figure 15).
 Leading a 12-member consortium group to develop JustCatchTM technology, which
included study and front-end engineering design for a full-scale amine-based capture
plant.
 Selection for construction and management of a flexible amine pilot facility (capacity:
78,000 tons of CO2 per year) in Mongstad, Norway.
 Participation in the European CO2 Technology Centre at Mongstad, Norway.
 Full-scale plant project at Kårstø.
24
Figure 15. Aker Clean Carbon’s MTU for testing chemical solvent-based CO2 capture (taken
from Aker Solutions, 2010).
 Competing for a United Kingdom carbon capture and storage (CCS) coal project
(Scotland).
ALSTOM – Chilled Ammonia Process (CAP)
ALSTOM’s CAP is a solvent-based regenerable process that utilizes the low-temperature,
low-energy reaction of an aqueous ammonium carbonate solution with CO2 to form ammonium
bicarbonate. A schematic of CAP, showing the flue gas-cooling system, absorption system, and
regeneration system, is shown in Figure 16. The process captures CO2 from flue gas by directly
contacting it with a CO2-lean solution at temperatures below 20°C (40°F). In the primary
absorption reaction, ammonium carbonate reacts with CO2 in the flue gas to form ammonium
bicarbonate, which precipitates as a solid. This solid is concentrated and sent to the regeneration
unit where the chemical reaction is reversed through the application of heat. CO2 released by the
regeneration reaction pressurizes the system. The regenerated lean solution is returned to the
absorber where it is reused to capture CO2 once again. The process was designed for a CO2
removal efficiency of 90% (Kozak and others, 2009).
Absorption and regeneration are performed under optimal NH3/CO2 ratios, meaning that
appreciable free ammonia does not exist under the operating conditions, thus minimizing
potential for ammonia slip (loss to the atmosphere). The low-temperature absorption results in
high solubility of CO2 in the aqueous alkaline solution. CAP can be retrofitted onto existing
25
Figure 16. ALSTOM CAP (taken from ALSTOM Power, 2010a).
coal-fired power plants. The use of low-reaction-energy ammonium carbonate reduces the steam
input required to release the CO2. During regeneration, the scrubber operates at a pressure of
300 psi. This compares to the 15 psi at which amine systems produce CO2. This differential
offers significant savings in compression energy for CAP (Blankinship, 2008a).
Additional energy required for CAP, including auxiliary power and low-pressure steam for
the stripper, is much lower than the energy required by a traditional amine process. ALSTOM
believes CAP can reduce a power plant’s parasitic load for carbon capture to about 15% to 18%
from the approximately 30% parasitic load of a traditional MEA process (Blankinship, 2008a).
Other CAP advantages include a high CO2 load capacity for the solution (0.1 to 0.2 lb CO2 per lb
solution), low heat of reaction (HR), low cost of reagent, no degradation during absorption–
regeneration, and tolerance to oxygen and contaminants in the flue gas (Rhudy and Black, 2007).
Because the regeneration heat required (approximately 400–700 Btu/lb CO2 captured)
(Rhudy, 2006) is so much lower than that needed for MEA-based capture the system will have
much lower direct impact on an existing plant’s steam cycle – a significant advantage for retrofit
applications. The large refrigeration system needed to chill the flue gas and keep absorber
operating temperature below 50°F will consume electricity, but the electricity used should not
exceed that which can be produced by the low-pressure steam that would have been used to
regenerate MEA.
A baseline study of the auxiliary load and cost of a full-scale CO2 capture process found
that retrofitting a 462-MW supercritical pc-fired boiler operating at 40.5% net thermal efficiency
would result in only small performance penalties (Peltier, 2008). CO2 avoided cost was $19.7/ton
26
(Rhudy and Black, 2007). A comparison of a theoretical power plant with CAP installed to one
without CO2 capture is shown in Table 1 (Rhudy and Black, 2007).
ALSTOM has performed several projects in the course of preparing CAP for market.
These include, but are not limited to, the following three U.S.-based projects designed to provide
stepwise scale-up and demonstration to full commercial scale for pc-fired power plants:
 ALSTOM and the Electric Power Research Institute (EPRI) operated their first coalfired power plant flue gas demonstration project on a 1.7-MW (electric)-equivalent
slipstream at We Energies’ Pleasant Prairie plant in Wisconsin. This test demonstrated
90% CO2 capture; ammonia loss in the treated flue gas of <10 ppmv and the production
of high-quality CO2 (>99.5% purity). The pilot plant was operated for >7000 hours and
captured CO2 at a rate of over 35 tonnes/day (Kozak and others, 2010).
 Currently, ALSTOM is involved in the second-phase scale-up demonstration of CAP at
American Electric Power’s (AEP’s) Mountaineer plant in New Haven, West Virginia.
This phase will capture about 90% of the CO2 from flue gas equivalent to 30 MW of the
coal-fired power plant’s output. This is equivalent to over 250 tonnes/day. AEP and
Battelle Research Institute will sequester the captured CO2 at a nearby site.
 ALSTOM’s third step in preparing CAP for commercial use will be applying the
process at commercial scale at AEP’s Northeastern Station at Oologah, Oklahoma. CO2
will be captured from a full-scale pc plant generating 300 MW of electricity. The
approximately 1.5 million tons of CO2 per year that is captured will be used nearby for
EOR.
Table 1. Performance Penalties of a Chilled Ammonia CO2 Separation System
(Rhudy and Black, 2007)
Parameter
Supercritical pc Without CO2
Removal
Same Unit with CO2
Removal
Illinois No. 6 Coal Feed Rate,
lb/hr 333,542 333,542
Coal Heating Value, Btu/lb,
HHVa 11,666 11, 666
Boiler Heat Input, MMBtu 3891 3891
Low-Pressure Steam
Extracted for Reboiler, lb/hr
0 179,500
Steam Turbine Power, kW 498,319 484,995
Total Auxiliary Power, kW 29,050 53,950
Net Power Output, kW 462,058 421,171
Net Efficiency, %, HHV 40.5 37.0
CO2 Avoided Cost, $/ton CO2 Base 19.7
a Higher heating value.
27
Additional information on CAP can be found on ALSTOM Power’s Web site (ALSTOM Power,
2010a).
ALSTOM – Advanced Amine Process (AAP)
In addition to its work on CAP, ALSTOM is involved in development, pilot-scale work,
and front-end engineering and design of an advanced amine process in partnership with Dow
Chemical as the amine supplier. This has progressed to the selection of the Dow UCARSOL
FGC Solvent 3000 as the amine and operation of a demonstration project that captures CO2 from
the flue gas of a coal-fired boiler at the Dow-owned chemical facility in South Charleston, West
Virginia. The pilot project has been reported to have successfully operated for over 4500 hours,
captured 90% of the CO2 in the flue gas stream, and produced a CO2 containing at least 99.5%
CO2. The pilot project is scheduled to run until Fall 2011 (Electric Light and Power, 2010).
ALSTOM has also announced two other advanced amine process projects:
 An industrial demonstration facility to capture carbon dioxide at the Le Havre coal-fired
electric power plant in France, which is scheduled for start-up by 2012. The project
program includes execution, testing, evaluation, and validation phases of the CO2
capture unit at the production site. It is partially funded by the French governmental
body ADEME (The French Environment and Energy Management Agency) (ALSTOM
Power, 2010b).
 Study and engineering project for a 20-MWth lignite-powered facility at PGE
Belchatow, Poland (Kozak and others, 2010).
Cansolv CO2 Capture Process
Cansolv Technologies Inc. (CTI) offers two different amine-based systems that are capable
of capturing CO2. One is a fairly standard absorber–stripper arrangement designed for CO2
capture alone. The other is an integrated SO2 control and CO2 capture system, shown
schematically in Figure 17. CTI uses patented amine solutions DC-103 and DC-103B. Projectspecific issues determine which solution will be used. DC-103 has a lower regeneration energy
requirement (i.e., the parasitic energy load is lower) and slower kinetics (i.e., a larger absorption
tower is needed) than DC-103B (Shaw, 2009). Table 2 is a list of pilot projects in which CO2
capture was evaluated for the Cansolv process.
The Cansolv SO2–CO2 integrated capture process has been selected for two projects:
 The RWE Power carbon dioxide capture pilot project at Aberthaw power station in
South Wales, United Kingdom, will be a 3-MW-equivalent, with 50 tonnes per day of
CO2 captured from a slipstream from the pc-fired power plant. The pilot plant will be
operated for 2 years. Construction is expected to start in 2010, with commissioning
expected in 2011.
28
Figure 17. Simplified process flow diagram of the Cansolv SO2–CO2 integrated capture process
(taken from Just and Shaw, 2008).
Table 2. List of Cansolv CO2 Pilot Projects Through Early 2008 (Shaw, 2009)
Application Date Site
CO2 in the Gas,
vol% Removal, %
Natural Gas-Fired
Boiler
March–June 2004 Paprican,
Montreal, Canada
8 75
Coal-Fired Boiler November 2004 Pulp Mill Boiler,
USA
11.5 65
Coal-Fired Power
Plant
July–Sept 2006 SaskPower, Poplar
River, Canada
12 90
Blast Furnace April 2007–2008 Japan 22 90
Natural Gas-Fired
Boiler
May–Sept 2007 Shell-Statoil,
Norway
4.5 85
Cement Kiln Jan–Feb 2008 North America 20 90 and 45
 For SaskPower’s Boundary Dam integrated CCS demonstration project, SNC Lavalin
will serve as the engineering and construction firm. The SNC Lavalin–Cansolv proposal
was selected as the preferred of the three proposals which had been short-listed by
SaskPower in February 2009. Powerspan and Fluor were the two other candidate
capture technology providers. SaskPower will make a final decision on whether to
proceed with the Boundary Dam CCS project later in 2010. The project will be
29
supported by the Canadian government. The CO2 will be sold for use in EOR (Canada
Views, 2010).
HTC Purenergy Carbon Capture System
HTC Purenergy Inc. is a small, publicly traded company located in Regina, Saskatchewan,
Canada. Doosan Babcock jointly with its parent company, Doosan Heavy Industries and
Construction, holds an exclusive global technology licensing agreement with HTC Purenergy for
its postcombustion carbon capture (PCCC) technology (Doosan Babcock, 2008, 2010). The
global technology licensing agreement includes the right for Doosan Babcock to utilize products
and technologies developed by HTC Purenergy and the University of Regina Green House Gas
Technology Centre in Saskatchewan, Canada. HTC Purenergy has a close relationship with the
University of Regina and uses its Green House Gas Technology Centre facilities, scientists, and
engineers for research and development of its CO2 capture technology.
According to the HTC Web site (HTC Purenergy Inc., 2009) and press releases, HTC
Purenergy currently offers the Purenergy CCS system for postcombustion flue gas capture of
CO2. The Purenergy system is advertised to be preengineered, prebuilt, and modular using
technologies developed and validated for over 15 years at the University of Regina. A single
modular process train is stated to be capable of capturing up to 3000 tons per day of CO2. An
artist’s rendering of the system and is given in Figure 18.
The process falls into the category of a chemical absorbent-based, absorber–stripper-based
CO2 capture system with thermal regeneration of the solvent. Solvent selection, modular system
design, and process optimization appear to be the focus in preparing the process for deployment.
The claimed benefits of the advanced amine-scrubbing technology include:
 High efficiency with a reduction of energy consumption.
 Unique formulated solvents.
 Less corrosive solvents.
 Lower cooling water requirements.
 Reduced operating cost.
To date, there have been no large-scale pilot projects performed based on the use of this
technology, but Basin Electric Power Cooperative has selected it for the planned 120-MWequivalent slipstream carbon dioxide capture plant at its Antelope Valley Station (AVS) located
near Beulah, North Dakota (Basin Electric Power Cooperative, 2009).
Linde AG with BASF Solvents
In 2007, Linde AG and BASF signed a joint development agreement for design,
construction, testing, and commercialization of advanced PCCC technology. This included a
detailed study for selection of a chemical absorbent solution that started with the screening of
approximately 400 substances. The screening procedure, illustrated in Figure 19 narrowed the
list to approximately 15 substances that were tested in a miniplant and left two that will be tested
30
Figure 18. HTC Purenergy CCS system (The numbers represent process description statements
available on the company Web site) (taken from HTC Purenergy Inc., 2009).
in the approximately 7.2-tonne/day CO2 pilot plant. The pilot plant (Figure 20) has been
constructed at RWE Power’s lignite-fired power plant in Niederaussem, Germany, and can
process 60 mcf/hr of flue gas. Testing began in June 2009 with a target plant efficiency loss of
less than 10% and a CO2 avoidance cost of less than €30/tonne CO2 (Krishnamurthy and Holling,
2010).
Powerspan
Powerspan Ammonia-Based ECO2™ Process
Powerspan moved from use of aqueous ammonia to a proprietary solvent during the course
of operating its pilot project at FirstEnergy Generation Corporation’s R.E. Burger plant near
Shadyside, Ohio. The change in solvent occurred sometime in 2009 but was not made public
until a platform presentation at the 9th Annual CCS Conference in Pittsburgh, Pennsylvania, in
31
Figure 19. BASF screening of substances for use in chemical absorption CO2 capture (taken
from Krishnamurthy and Holling, 2010).
Figure 20. Postcombustion CO2 capture pilot plant in Niederaussem, Germany (taken from
Krishnamurthy and Holling, 2010).
32
May 2010 (Boyle and Andes, 2010). Because Powerspan is no longer using the aqueous
ammonia process, the details of that process will not be covered here except to say it differed
from ALSTOM’s CAP, most notably in that the flue gas was not cooled (as in CAP) and it was
integrated with Powerspan’s ECO process for SOx and NOx removal.
Powerspan Proprietary Solvent-Based ECO2 Process
Powerspan’s proprietary solvent ECO2 process appears to be a fairly standard thermal
swing absorption–regeneration process (Figure 21). The CO2 scrubber is a packed absorber
tower. The flue gas is accepted by the CO2 scrubber at or slightly cooled from the outlet
conditions of an SO2 scrubber. CO2 is absorbed into the solvent as the flue gas passes upward
through the absorber and the solvent flows downward (countercurrent flow). The resulting CO2rich solvent exits the CO2 scrubber, passes through a cross heat exchanger, and enters the top of
a regenerator (stripper).
Powerspan reports (Boyle and Andes, 2010) that its pilot facility work demonstrated
advantages of the ECO2 process that include:
– Low energy of regeneration (i.e., less than 1000 Btu/lb of CO2).
– High solvent stability (no thermal or oxidative breakdown at operating conditions).
– Low vapor pressure for the solvent at absorber operating conditions (avoiding the need
to water-wash the flue gas prior to release from the CO2 scrubber).
Figure 21. Powerspan’s proprietary solvent ECO2 process (taken from Boyle and Andes, 2010).
33
It also claims that the proprietary-solvent ECO2 process is capable of removing other acid
gas contaminants (e.g., SO2, SO3, NO2, and HCl) captured from the flue gas and into the solvent
at a low cost, thus allowing the process to function without a polishing scrubber (in many
applications). This process has not been described publicly.
WorleyParsons was hired to confirm the pilot study results and perform a modeling and
economic study on the process. It found that the Powerspan proprietary solvent-based ECO2
process would decrease the net output of the power plant from the CO2 capture process by 30%
as a result of steam extraction and the increased auxiliary load. This is a 9.97% reduction in plant
net efficiency for the subcritical steam cycle studied (Boyle and Andes, 2010).
An all-in capital cost estimate for a proprietary-solvent ECO2 system for a 220-MW net
reference plant was $304 million. The total estimated cost of captured CO2 was $36.61/ton
(valuing the lost net generating power at $50/MWh and assuming 40 ppm of SO2 in the inlet gas
stream) (Boyle and Andes, 2010).
Sargas Carbonate Process
Sargas AS, a Norwegian start-up company based in Oslo, has developed a pressurized
combustion, combined-cycle power generation system with CO2 capture. Two versions of this
power plant were designed, one for natural gas (pressurized natural gas combustion [PNGC],
100 MW) and one for coal (pressurized fluidized-bed combustion [PFBC], 400 MW). The
system is claimed to be a postcombustion, preexpansion design. This process differs
considerably from the other postcombustion technologies discussed because it is an integrated
power plant with a postcombustion capture process, not a CO2 capture process that can be used
on an existing plant.
The process, illustrated schematically in Figure 22, begins with compression of the air
prior to sending it to a pressurized boiler. In the boiler, either natural gas or coal is combusted
with the air. The generated steam is fed to a conventional steam turbine where it is expanded,
then condensed and returned to the boiler. The combustion is kept to about 2% excess of oxygen.
The flue gas from the boiler at 850°C is directed through the heat exchanger to cool down to
70°C. The cool flue gas enters an absorption column where it reacts with potassium carbonate to
remove CO2. A modified Benfield process (20–40 wt% of potassium carbonate) is used. The
decarbonized flue gas is sent back to the heat exchanger to reheat to 840°C. Then the flue gas is
fed to a gas turbine where it is expanded to produce power. The steam turbine generates about
80% of the electricity, and the gas turbine generates about 20% (Bryngelsson and Westermark,
2005).
Net efficiency for a 100-MW natural gas power plant is claimed to be 40% on a lowerheating-value (LHV) basis, with 95% CO2 capture. The projected 400-MW coal-fired power
plant would have a LHV new efficiency of 44%, with 98% CO2 captured (Bryngelsson and
Westermark, 2005).
34
Figure 22. Sargas process (taken from Sargas AS, 2010).
The technology was demonstrated at pilot scale in 2007 and early 2008 at a coal-fired
power plant in Stockholm (Bryngelsson and Westermark, 2009), and a 1-MW pilot-scale power
plant demonstration is currently in preparation in South Park, Pennsylvania. The South Park
project is a partnership between Sargas AS; Environmental Energy Technology, Inc. (EET); and
CONSOL Energy, Inc. A PFBC–EET clean coal technology system will be used to generate
power from waste coal and other fuels. This pilot project is located at CONSOL Energy’s R&D
facilities and received a $1.64 million grant from the Pennsylvania Department of Environmental
Protection (DEP) (CONSOL Energy, 2010).
Sargas AG has also made an alliance with Daewoo Shipbuilding & Marine Engineering
Co. Ltd. (DSME) of Korea to build and install their first 100-MW natural gas plant in
Hammerfest, Norway. They hope also to build their first 400-MW coal plant in west Norway in
the near future (Daewoo Shipbuilding & Marine Engineering Co. Ltd., 2009). Additional
information on the Sargas process can be found on the Sargas Web site (Sargas AS, 2010) and in
Bryngelsson and Westermark (2005), McRae and de Meyer (2006), and Siemens Power
Generation (2006).
Siemens POSTCAP™ Process
Siemens has developed a postcombustion CO2 capture process called the POSTCAP
process that is based on the use of an amino acid–salt solution as the chemical absorbent
(Jockenhoevel and others, 2009). This technology was developed by Siemens and the power
company E.ON through the German Federal Ministry of Economics and Technology-funded
POSTCAP project. The solvent features include a high CO2 capture rate, low-energy demand, a
35
low rate of solvent degradation, production of a high-purity CO2 stream, and low environmental
risk (Jockenhoevel and others, 2009).
The salts of amino acids react with CO2 in much the same way as normal amines, i.e., by
carbamate, carbonate, and bicarbonate formation (as shown in Figure 23) and have low
sensitivity to degradation by oxygen and temperature (Jockenhoevel and others, 2009).
The amino acid–salt solution is used in a conventional absorber–stripper capture process
that Siemens has modified with respect to material integration, energy integration of the
compression unit, and integration with the power plant in order to exploit the potential for
minimizing the carbon capture cost. Siemens reports that its amino acid–salt-based solvent used
in a conventional process would consume 0.97 MWh/ton CO2. This is estimated to decrease to
0.64 MWh/ton of CO2 using the improved process (Jockenhoevel and others, 2009) The
currently estimated CO2 capture costs (including CO2 compression but without transport and
storage) are approximately $44/ton of CO2 in the early commercial phase (i.e., prior to 2020) and
approximately $30/ton of CO2 in the mature commercial phase (before 2030) (Jockenhoevel and
others, 2009).
Siemens and E.ON started a pilot CO2 capture facility in late September 2009 at an E.ON
power plant near Frankfurt, Germany. The test will run until the end of 2010. The results
achieved and the operating performance of the pilot plant will serve as the basis for the largescale Fortum Meri-Pori Demonstration Plant (Finland) scheduled to begin operation in 2015.
CO2 capture is planned to be performed on 50% of the flue gas for this 565-MW facility. In June
Figure 23. Amino acid–salt absorption reaction scheme (taken from Jockenhoevel and others,
2009).
36
2009, Siemens signed an agreement with TNO, the Netherlands Organization for Applied
Scientific Research, aimed at the further advancement of the second generation of the amino
acid–salt-based carbon capture technology (Siemens Energy and TNO, 2009). TNO has a long
history of work on the development and use of amino acid salts for CO2 capture applications.
On July 7, 2010, DOE announced that it will provide funding for Siemens Energy to
design, install, and operate a pilot plant for treating a slipstream (1 MW equivalent) at the TECO
Energy Big Bend Station (Tampa, Florida) to demonstrate POSTCAP technology for
postcombustion CO2 gas capture (U.S. Department of Energy, 2010a).
Developing Technologies for Chemical Absorption
Use of Mass Transfer Devices Other than Absorption Towers
For the chemical absorption solutions having very fast reaction kinetics, there can be
substantial benefits derived from increasing the amount of gas–liquid contact area present in a
given volume of the absorption and/or stripping vessel. This can be done in a variety of ways,
two of which are presented here: the use of membrane contactors and the use of a liquid jet
contactor.
Membrane Contactors
Membrane contactors are flat-sheet, spiral-wound, or hollow-fiber membrane modules in
which a porous membrane is used to separate the gas phase from an absorption solution. These
can offer very high surface areas (1000 m2/m3 or more) for mass transfer in a small volume and
can permit the use of solvent solutions that might not work well in an absorption tower because
of the tendency to foam or froth. A tenfold decrease in absorber volume is possible. Figure 24 is
an illustration of a hollow-fiber membrane absorber where the gas flow path is on the shell side
of the hollow-fiber tubes. The absorbing gas passes through the pores in the membrane and
dissolves in the absorption solvent, which is pumped through the bores of the hollow fibers.
Several entities have investigated the use of membrane contactors. Only a few examples are
given here.
Kvaerner Hybrid Membrane Absorption System (KHMAS)
The KHMAS is a gas–liquid membrane contactor that replaces a traditional absorber. The
KHMAS was developed by Kvaerner Process Systems, which has since merged with Aker
Process Systems. In the KHMAS, CO2 diffuses through a microporous, hydrophobic polymer
membrane into a flowing liquid. The solvent, rather than the membrane, provides the selectivity.
The KHMAS weighs 70% less and has a 65% smaller footprint than a conventional absorber.
The membranes used are flat-sheet polytetrafluoroethylene (PTFE) membranes from W.L. Gore
& Associates, Inc. A large number of membrane types were tested during development, but the
amines destroyed some and wetted others, causing blockage of the membrane pores and/or
leakage of solvent into the gas flow path (Falk Pedersen and Imai, 2003).
37
Figure 24. Membrane absorption with gas on shell side (taken from ten Asbroek and Feron,
2004).
The system was developed, modeled, scaled up, and pilot-tested between 1993 and 2004.
Testing of the KHMAS included work on natural gas sweetening, dehydration, and CO2 removal
from flue gas. A flue gas pilot project using MHI’s KS-1 solvent and the KHMAS at MHI’s
Nankotest facility in Japan found a statistically insignificant capital cost savings and a 19%
operating cost savings for CO2 capture versus MEA used in a conventional system (CO2 Capture
Project, 2004).
PoroGen Carbo-Lock™ Process for CO2 Capture
The PoroGen Carbo-Lock process is based on the use of a new fluorocarbon surfacemodified polyether ether ketone (PEEK) hollow-fiber membrane contactor (Zhou and others,
2010). The porous membrane was developed to be extremely hydrophobic in order to avoid the
pore wetting that has been observed for other hydrophobic membranes such as polyolefins like
polypropylene and, to a lesser extent, PTFE. The membrane contactor was introduced by the
PoroGen Corporation in 2008–2009. PoroGen is currently working with the Gas Technology
Institute (GTI) to test the membrane absorber on various physical and chemical solvents at both
high and low gas feed pressures.
On July 7, 2010, National Energy Technology Laboratory (NETL) announced that it was
funding a 3-year development project with GTI, PoroGen, and Aker Process Systems to develop
cost-effective hybrid separation technology for CO2 capture from flue gases based on a
combination of absorption and hollow-fiber membrane technologies (U.S. Department of Energy
38
National Energy Technology Laboratory, 2010h). Therefore, it appears that the project will
investigate the use of the PoroGen membrane in place of the PTFE membrane material in the
KHMAS.
TNO Membrane Absorber and CATO CO2 Catcher
TNO is a company headquartered in the Netherlands that has been involved in carbon
capture technology development for postcombustion capture through its work using amino acid
salt-based solvents that they refer to as CORAL solvents (Goetheer, 2009; Feron and ten
Asbroek, 2004). TNO applies these solvents in tower-based absorber–strippers and in systems
that incorporate the use of membrane absorbers. The TNO membrane absorber is 5 to 10 times
smaller than equivalent packed columns, which would reduce capital cost (Peters, 2009). The
membranes used in the TNO absorbers are made of polyolefins (e.g., polypropylene). As noted
earlier, TNO and Siemens are cooperating on further development of processes for CO2 capture
based on the use of amino acid salts (Siemens Energy and TNO, 2009).
Since April 2008, TNO has operated the CATO CO2 Catcher, a CO2-from-flue gas capture
pilot plant, at E.ON Benelux’s power plant near Rotterdam. (CATO is the Dutch national R&D
program for CO2 capture, transport, and storage.) The pilot test results indicate that the solvent is
remarkably stable under industry conditions, has a high capture rate, and compares favorably in
terms of energy consumption to the MEA standard. Cost of CO2 avoided and energy penalty
relative to the MEA benchmark are indicated in Figure 25 (Goetheer, 2009).
Additional information on the CATO CO2 Catcher project and the TNO membrane
absorber is available at multiple sources (Allaie and Jaspers, 2008; TNO, 2010; Feron and
Jansen, 2002; Goetheer, 2009).
Figure 25. Cost comparison of CORAL solvents to MEA (taken from Goetheer, 2009).
39
University of Kentucky Research Foundation’s Solvent–Membrane Hybrid
Postcombustion CO2 Capture Process
A research team at the University of Kentucky was recently awarded a DOE Advanced
Research Projects Agency – Energy (ARPA-E) project to develop a hybrid absorption solvent–
catalytic membrane for use in a postcombustion CO2 capture process (U.S. Department of
Energy Advanced Research Projects Agency – Energy, 2010a). The project description states
that the membrane will be a catalytic separator that couples nanofiltration separation and
catalysis. It is not clear if this will be a membrane contactor with catalytic activity or a liquid
membrane permeator with catalytic activity.
Neumann Systems Group, Inc., Liquid Jet Contactor – NeuStreamTM–C
The Neumann Systems Group, Inc. (NSG), is a technology and development company that
is focused on gas–liquid contact systems for chemical processing and emission control. NSG has
developed an integrated environmental control technology called NeuStreamTM–S that has shown
promise as a low-cost option for SO2 control for coal-fired boilers. The process consists of a
unique horizontal flow absorber that produces very high mass transfer rates while reducing the
overall footprint and energy consumption. A unique nozzle design produces flat jets of absorber
liquid (in the case of SO2 control, NSG uses a sodium hydroxide solution) that substantially
increase the surface area available for mass transfer by a factor of 10 over conventional spray
systems. The gas is injected in between the jets and parallel to the faces of the jets. This
configuration permits higher gas throughput without disrupting the jets or entraining liquid
droplets into the gas. The enhanced mass transfer and increased throughput of gas result in
smaller contactor/duct volumes and reduced manufacturing costs (Neumann and others, 2010).
NSG is extending the process to the future capture and processing of CO2 in a device called
NeuStream–C.
NSG claims that the improved mass transfer that is achieved in its treatment technology
will result in a substantially smaller treatment unit (by as much as a factor of 15), resulting in
significantly reduced capital investment. Because it is anticipated that less absorber liquid will be
required to achieve the desired removal, the operating costs for the gas treatment are also
expected to be substantially less.
The mass transfer system should provide the stated benefits when working with a highconcentration, high-pH solution with fast reaction kinetics (such as a hydroxide solution). The
difficulty with respect to the use of the system for CO2 capture versus SOx removal is the need to
regenerate the solvent. Orders of magnitude more CO2 than SOx must to be removed from coalfired power plant flue gas, and the rate of CO2 mass transfer is lower because of its lower
reaction rate. Suitable absorber liquids must be identified for the NeuStream–C to be applied to
CO2 capture. This type of testing using the NeuStream-C will be performed by the EERC’s
Partnership for CO2 Capture (PCO2C). Further information on the NeuStream process can be
found in multiple sources (Colorado Springs Utilities, 2009; Colorado Springs Gazette, 2008a–c,
2009; Electric Power Research Institute, 2008, 2010; Neumann Systems Group, Inc., 2009).
40
Use of Other Solvents in Absorber–Stripper Systems
Use of Piperazine
Dr. Gary Rochelle’s group at the University of Texas has done a considerable amount of
work on the use of piperazine (PZ), an organic compound that contains two secondary amine
groups, as a chemical absorbent alone in high concentration (Rochelle and others, 2010; Freeman
and others, 2010a, b) and in combination with potassium carbonate (U.S. Department of Energy
National Energy Technology Laboratory, 2010a; Cullinane and Rochelle, 2004). PZ has also
been added to MEA and MDEA, where it acts primarily as a promoter, increasing CO2
absorption rate (Dang and Rochelle, 2001; Cullinane and Rochelle, 2004).
The PZ-promoted potassium carbonate process has been studied at small pilot scale by the
Rochelle group and by Kather and Oexmann (2008). It promises lower-cost treatment compared
to MEA because of a lower heat duty for solvent regeneration and the use of much lower
temperatures for solvent regeneration (131°F compared to 248°F for MEA), which allows for the
use of waste heat rather than steam taken from the low-pressure (LP) turbine inlet. Some
concerns remain about the need for foaming control and the fact that the amount of CO2
transported per unit volume of solution per cycle is lower than that of a 30 wt% MEA solution.
This would require a larger column diameter, although this would be offset by the shorter
column heights afforded by the fast PZ kinetics. Economic analysis of the system indicates a
lower investment cost.
More recently, the Rochelle group has been promoting the use of concentrated PZ
(40 wt%). The use of this solution would permit absorption towers to be shorter and smaller in
diameter because the absorption capacity is 1.8 times that of 30 wt% MEA and the mass transfer
rate is double that of 30wt% MEA. In addition, PZ is thermally stable when regenerated by
distillation, is resistant to oxidation, and has a lower volatility, making it easier to prevent its loss
to the atmosphere. The energy cost of concentrated PZ is 10% to 20% lower than that for MEA,
and the CO2 product is generated at 11 to 17 atm (at 150°C), thus reducing compression costs
(Rochelle and others, 2010).
A recently announced DOE-funded project by the URS Group and partners will investigate
the use of concentrated PZ at a scale of 0.1 MW equivalent and then at a scale of 0.5 MW (U.S.
Department of Energy National Energy Technology Laboratory, 2010h). The larger-scale test
will be conducted at DOE’s National Carbon Capture Center. It is likely that this project will
involve Gary Rochelle’s group because URS is one of the funding partners of his Luminant
Carbon Management Program (Rochelle, 2009).
Enzyme-Based Catalysts
The carbonic anhydrases are metalloenzymes (most commonly containing zinc) that
catalyze the conversion of CO2 to bicarbonate ions, HCO3-, and hydrogen ions, H+. There are
several classes of carbonic anhydrases with significantly varied protein form, but all with a
common function: to catalyze the conversion of CO2 to bicarbonate. This conversion is carried
out by the enzyme first reacting with water to split it into a hydrogen ion and an enzyme 41
associated zinc hydroxide and the subsequent reaction of the zinc hydroxide form of the enzyme
with CO2 to form the bicarbonate ion. Because the rate of reaction of hydroxide ions with CO2 is
very fast compared to the rate of the combined hydration of CO2 to carbonic acid, CO2 + H2O →
H2CO3, and subsequent dissociation of carbonic acid to hydrogen ions and bicarbonate, the
enzyme is able to speed the reaction significantly in solutions with low hydroxide ion availability
(typically, a benefit at pH <10). The enzyme also catalyzes the reverse reaction of combining
hydrogen ions and bicarbonate to yield CO2 and water. In order to be of most benefit, the catalyst
needs to be present at the gas–liquid interface. This presents a challenge with respect to
engineering a system based on use of the catalyst while providing for long life of the enzyme.
Several companies are developing technologies based on the use of carbonic anhydrase for
CO2 capture. These efforts include improvements in the enzyme form and function, development
of methods for use of the enzyme in an engineered system, and development of specialized mass
transfer devices to take advantage of the enzyme function; one group is even developing a
synthetic analog of the enzyme’s active site and ways to use this catalyst.
Akermin – Immobilization of Carbonic Anhydrase
Akermin, Inc., is a large enzyme development and supply company that is developing a
carbonic anhydrase immobilization–stabilization method for use in CO2 capture from flue gas
(Akermin, Inc., 2009). The concept is to encapsulate the enzyme within tailored polymer
structures, which protects the enzyme, allowing for long lifetime. In addition, the enzyme is
distributed in the capture solution so that it is present at the gas–liquid interface, where it will
provide the most benefit. Figure 26 is a conceptual drawing of the enzyme contained in the
polymer structure. Akermin has been working on the technology for approximately 5 years and
was recently awarded a 2-year project to optimize its enzyme-containing solvent formulation and
demonstrate process efficacy by treating up to 2000 standard liters of simulated flue gas per
hour. (U.S. Department of Energy National Energy Technology Laboratory, 2010h).
Carbozyme – Contained Liquid Membrane Permeator and Membrane Absorber–
Stripper
Carbozyme, Inc., is a small technology development company that has been developing
carbonic anhydrase-based CO2 removal systems for advanced life support applications as well as
systems for CO2 capture from air and flue gas. Carbozyme’s systems are based on the use of
hollow-fiber membrane-based modules (Trachtenberg and others, 2005). The treated gas and
product gas flow through the bores of two sets of hollow fibers, one for the flue gas and one for
the product gas. The hollow fibers are separated by a liquid that acts as the permeance-selective
membrane. The enzyme carbonic anhydrase is immobilized to the shell side of the hollow-fiber
membranes in order to be present at the gas–liquid interface. The enzyme enables faster transport
of the CO2 by catalyzing the conversion of CO2 to bicarbonate at the flue gas–liquid interface
and bicarbonate to CO2 at the liquid–product gas interface. A vacuum-assisted water vapor
sweep provides the low CO2 partial pressure on the product side necessary to maintain a
favorable driving force for CO2 transport through the liquid membrane. A schematic of this
system, called a contained liquid membrane permeator, is shown in Figure 27.
42
Figure 26. Akermin immobilized carbonic anhydrase (taken from Akermin, Inc., 2009).
Figure 27. Conceptual illustration of the Carbozyme contained liquid membrane permeator
(taken from Smith and others, 2010).
Most recently, Carbozyme has reported on the use of a proprietary absorber–stripper
arrangement based on the same concept of using carbonic anhydrase immobilized at the gas–
liquid interface (Smith and others, 2010). This configuration is shown in Figure 28.
43
Figure 28. Carbozyme proprietary absorber–stripper system (after Smith and others, 2010;
Carbozyme, Inc., 2010).
CO2 Solution – Enzyme-Enhanced Amines
CO2 Solution, Inc., has been developing CO2 capture systems based on the use of the
enzyme carbonic anhydrase in packed-bed absorption tower-type absorber–stripper systems
(CO2 Solution, 2009). This concept allows solutions with low regeneration temperatures but also
having low rates of absorption to be viable candidates for postcombustion capture. Initially, the
company worked to immobilize the enzyme to the tower packing and studied the benefit of the
presence of the enzyme on the rate of CO2 absorption into metal carbonate and amine solutions.
The location of the enzyme at the liquid–solid interface rather than the gas–liquid interface
limited the benefit derived from the enzyme. Recently, CO2 Solution moved to immobilization of
the enzyme onto nano-sized carriers that allow the enzyme to be transported in the absorption
solution and, therefore, to be present at the gas–liquid interface (CO2 Solution, 2009). Figure 29
illustrates the relative improvement in absorption rate derived from the use of this free-flowing
enzyme compared to the use of the enzyme immobilized to the packing and the no-enzyme
condition for solutions of 4 M MDEA and 1.45 M potassium carbonate. Figure 30 compares the
free-flowing immobilized enzyme with the no enzyme condition for MEA, MDEA with a
chemical promoter, an amino acid salt, MDEA, and a carbonate solution. The greatest benefit is
derived for the solution with the slowest noncatalyzed absorption rate. CO2 Solution is still doing
laboratory-scale testing. Larger-scale integrated-system bench testing is planned for the period
2010 to 2012. Small-scale pilot testing and demonstration is planned for 2012 to 2014.
44
Figure 29. Relative CO2 transfer rate using no enzyme (blue), enzyme immobilized to column
packing (red), and enzyme suspended in solution (green) (taken from CO2 Solution, 2009).
Figure 30. Relative improvement in CO2 absorption observed in five chemical absorption
solutions (taken from CO2 Solution, 2009).
45
CO2 Solution has entered into a joint development agreement with Codexis, a major
enzyme supplier and developer. They will work together on a Codexis-led project recently
funded under a DOE ARPA-E Innovative Materials & Processes for Advanced Carbon Capture
Technologies (IMPACCT) project entitled Low-Cost Biological Catalyst to Enable Efficient CO2
Capture (U.S. Department of Energy Advanced Research Projects Agency – Energy, 2010e;
Codexis, Inc., 2010).
Integrated Vacuum Carbonate Absorption Process
The research and development team at the Illinois State Geological Survey (ISGS) is using
carbonic anhydrase as a catalyst to increase the rate of absorption and stripping of CO2 in its
integrated vacuum carbonate absorption process (IVCAP) for postcombustion CO2 capture. The
process is an absorption tower–stripper system that uses a potassium carbonate solution as the
chemical absorbent. Carbonic anhydrase is used as a catalyst (promoter), and the steam
requirement for stripping and stripping temperature are decreased by desorbing the CO2 under
low-pressure (vacuum) conditions. Stripping at low temperature allows the use of low-quality
steam (close to the exhaust end of the low-pressure turbine). Integration of the patented process
into a pc power plant is shown in Figure 31.
Figure 31. IVCAP process (taken from Chen and others, 2006).
46
Process simulations indicated that the process would reduce the electricity generation of a
533-MW-gross-output coal-fired power plant by 35.6 MW, compared to a 96.3-MW reduction
with the use of 30% MEA. The calculated CO2 avoidance costs from the process simulations
were $30.9/ton CO2 using IVCAP and $41/ton using MEA (Chen and others, 2006; Chen and
Lu, 2007; Lu, 2009; U.S. Department of Energy National Energy Technology Laboratory,
2009a). The research team recently reported progress on the immobilization of carbonic
anhydrase for use in the process (Lu and Rostam-Abadi, 2010).
Novozymes – Heat-Stable Carbonic Anhydrase
Novozymes is a major enzyme development and manufacturing company that holds a
patent (W02010014774A2) for the use of a membrane-based system for CO2 capture using
solutions containing carbonic anhydrase and has submitted a patent application
(US2010047866A1) related to high-temperature carbonic anhydrase for use in CO2 capture from
flue gas.
Synthetic Catalysts Based on Carbonic Anhydrase Active Site
A research group at Lawrence Livermore National Laboratory has been working to
develop small synthetic chemical molecules that mimic the catalytically active site of carbonic
anhydrase for use in CO2 capture applications. Recently, this group teamed with researchers at
the University of Illinois and Babcock & Wilcox to propose an ARPA-E-funded project that will
be led by the United Technologies Research Center. The project is entitled “Catalytic
Improvement of Solvent Capture Systems” and will focus on furthering the development of these
small-molecule catalysts and demonstrating their effective use under a range of process
conditions (U.S. Department of Energy Advanced Research Projects Agency – Energy, 2010c).
The compounds being studied are synthetic organometallic chemicals. Figure 32
(Lawrence Livermore National Laboratory, 2010) is an illustration of the enzyme carbonic
anhydrase, the catalytic center, and the small-molecule catalysts, which mimic the zinc complex
that serves as the catalytic center. Davy (2009) provides additional information on these types of
compounds.
New Absorbents for CO2 Capture
Ionic Liquids or Room-Temperature Ionic Liquids (RTIL)
Ionic liquids, or more accurately room-temperature ionic liquids (RTIL), are organic salts
that are liquid at or near room temperature. Some ionic liquids are physical absorbent CO2
solvents. Ionic liquids containing amine functional groups are chemical CO2 solvents. The
physical absorbent type of ionic liquids have relatively low heats of absorption, and similar to
other physical absorbents, the loading capacity is very low under postcombustion flue gas
conditions. This means that physical absorbent ionic liquids by themselves are not good
candidates for postcombustion CO2 capture but, instead, may be good candidates for use in
precombustion capture. When mixed with amines, physical solvent ionic liquids can be used for
47
Figure 32. Synthetic small-molecule catalysts based on the active center of carbonic anhydrase
(taken from Lawrence Livermore National Laboratory, 2010).
postcombustion capture. In this case, the ionic liquid acts as the bulk solvent in place of water
and the amine acts as the chemical solvent.
Chemical absorbent ionic liquids containing amine functional groups are good candidates
for postcombustion CO2 capture. Because RTILs are liquid salts of organic compounds, there is
an almost infinite variety of potential molecular structures, meaning that RTILs can be
engineered to have different properties for different applications and thus can be considered
“designer solvents.” Many university and corporate research groups are involved in designing,
synthesizing, and testing new RTILs for use as absorbents in CO2 capture applications. In
addition to the use of the ILs as liquid absorbents, there are efforts in the use of the ILs in liquid
membranes, as gels in membranes, and as the basis for polymers that are used to build solid
sorbents and membranes that can be used for gas separations.
Additional information on the physical and chemical absorption of CO2 into ionic liquids is
available in papers published by researchers from DuPont (Yokozeki and others, 2008) and
Eindhoven University in the Netherlands (Galán Sánchez, 2008). A brief overview of the efforts
of some of the entities working in this area is given in the following text.
ION Engineering, LLC
ION Engineering, LLC, is a company founded by members of a research group at the
University of Colorado that has been working on CO2 capture using ionic liquids. The group has
licensed technology from the University of Colorado for the use of IL–amine mixtures. The
company is working to integrate ILs into solvent-based gas processing, including flue gas carbon
capture and natural gas treatment. ION Engineering recently landed a 15-month ARPA–Efunded project to use a physical solvent ionic liquid–amine mixture in a bench-scale carbon
capture unit (U.S. Department of Energy, 2010a). The unit will be operated on a slipstream of
flue gas at an operating power plant.
48
University of Notre Dame
The DOE-funded research group at the University of Notre Dame has published many
papers and reports on its work in the development of RTILs for postcombustion CO2 capture. In
the most recent paper, Gurkan and others (2010) report success with the design and synthesis of
ILs that react with CO2 in a 1:1 stoichiometry, meaning that higher molar capacities have been
achieved. The paper also shows that changing the location of functional groups on these types of
ILs can change the reactivity, indicating that functionalized ILs can be designed for specific
applications.
Additional work by the research group at the University of Notre Dame includes
collaboration with Air Products and Chemicals, Babcock & Wilcox, DTE Energy, Merck/EMD
Chemicals, and Trimetric. Recently, Trimeric completed a systems analysis for CO2 capture
based on IL properties derived from the University of Notre Dame work (Myers and others,
2010). Trimeric determined that the CO2 capture from a pc-fired plant using ILs would have a
cost of electricity of 8.8¢ to 9.5 ¢/kWh where the base cost of electricity was 5 ¢/kWh without CO2
capture and 10.6 ¢/kWh with MEA- based CO2 capture. In other words, CO2 capture using ILs
having the properties specified in the study was estimated to be 11% to 17% lower than that for
capture using MEA.
While working on the liquid solvent ILs, Notre Dame researchers discovered a class of
ionic liquid compounds that are solids until their reaction with CO2 causes a phase change to a
liquid state. This behavior presents interesting possibilities for the development of novel CO2
capture processes. The group has received funding through ARPA–E IMPACCT to synthesize
and study more examples of this new class of compounds (U.S. Department of Energy Advanced
Research Projects Agency – Energy, 2010b). Additional sources of information for the
University of Notre Dame work on ILs include Maginn (2005a,b, 2008, 2009).
University of Colorado
The research group at the University of Colorado that is working on CO2 capture
developed the IL plus amines solution technology, which has been licensed to ION Engineering.
Additional information on the technology and other aspects of the work are available in the 2009
review paper on imidazolium-based RTILs (Bara and others, 2009). Most of the other work the
group has done on ionic liquids involves the use of ILs in supported liquid membranes,
composite membranes, and in the development of imidazolium-based polymers (Bara and others,
2010; Carlisle and others, 2010). The ionic liquid-based membrane work is covered in the
section on membrane separations.
University of Wyoming
Researchers at the University of Wyoming are working with a class of IL-based
compounds that they refer to as poly(ionic liquid)s. These are solid polymers made by
polymerizing imidazolium-based IL monomers. The researchers report that the poly(ionic
liquid)s have higher CO2 sorption capacities than RTILs, faster sorption–desorption rates, and
can be applied in novel sorbent and membrane material applications. The poly(ionic liquid)s
rapidly dissolve gaseous CO2 and release it when the pressure is reduced to vacuum levels. It
49
was found that the CO2 sorption capacity of poly(ionic liquid)s primarily depends on the
chemical structure, while the rate of CO2 sorption is affected by the surface area of the polymers.
A series of ionic liquid monomers and their polymers having different cation and anion
structures were synthesized and characterized. The CO2 absorption capacities ranged from 2.7 to
10.2 mol% (Tang and others, 2005a). Poly(ionic liquid)s with higher polar cations and anions
have higher CO2 solubility. Crosslinking of the polymer decreased the CO2 absorption capacity
of poly(ionic liquid)s.
Advantages of poly(ionic liquid)s include absorption capacities that are 6.0 to 7.6 times
those of RTILs; quick, complete desorption under vacuum; selective sorption of CO2 (i.e., O2
and N2 are not absorbed on the material), and limited adverse effects from moisture (Tang and
others, 2005c). The technology is currently expensive because of the expense of vacuum
desorption on a large scale and because poly(ionic liquid)s are not manufactured commercially.
More information on the poly(ionic liquid) work by researchers at the University of
Wyoming can be found in papers by Tang and others (2005b, 2009).
Georgia Institute of Technology
Researchers at Georgia Institute of Technology (Georgia Tech) have been studying two
different IL-based CO2 capture technologies: one-component reversible ionic liquid solvent for
CO2 capture and high-performance CO2 scrubbing based on hollow-fiber-supported designer
ionic liquid sponges. The first is a liquid sorbent technology, while the second is a hybrid solid
sorbent-type technology (mixed absorption/adsorption).
Reversible IL solvents are liquids that change from molecular liquids to ionic liquids
because of mild changes that are applied to the solution. An example is shown in Figure 33
where CO2 acts as the agent of change. The compound shown in Figure 33 was exposed to
gaseous CO2 at 1 atm and exothermically converted from the molecular liquid phase to an ionic
liquid. Stripping off the CO2 using inert gas or heating it to 50°–60°C converts it back to a
neutral liquid (Fadhel and others, 2009). The current work on the project is funded by DOE (U.S.
Department of Energy National Energy Technology Laboratory, 2009e). Updates on the progress
of the project are available on the Georgia Tech project Web site (Georgia Institute of
Technology, 2010).
The concept of high-performance CO2 scrubbing based on hollow-fiber-supported designer
ionic liquid sponges involves trapping ionic liquids inside hollow polymer fibers. The hollow
fibers would be used in either a temperature- or pressure swing adsorption-type system. This
project was funded under ARPA–E and is centered at Oak Ridge National Laboratory (ORNL)
(U.S. Department of Energy Advanced Research Projects Agency – Energy, 2010f).
GE Global Research
Two DOE-funded research projects on improved solvents for CO2 capture are being
performed by GE Global Research. The first of these, funded through the existing plants
program, is an investigation centered on synthesis of new liquid absorbents entitled “Novel High
50
Figure 33. Capture mechanism of a one-component reversible ionic liquid (taken from Eckert,
2009).
Capacity Oligomers for Low-Cost CO2 Capture.” The second is a new ARPA–E-funded project
entitled “CO2 Capture Process Using Phase-Changing Absorbents.”
High-Capacity Oligomers for CO2 Capture
An oligomer is a polymer with relatively few structural units that typically is highly
soluble in appropriate solvents. A research program is being conducted by a team of chemists,
chemical engineers, and molecular and process modelers from GE Global Research, GE Energy,
and the University of Pittsburgh. The program is using molecular modeling to identify suitable
candidate oligomers, to synthesize and determine the relevant physical and chemical properties
of these compounds, and to model the performance of a power plant integrated with an absorber–
stripper postcombustion capture system. Targeted absorbent properties are low volatility, high
CO2-loading capacity, low HR, high reaction rate, high desorption pressure, and low cost
(Grocela, 2009). The team has found that that certain amino silicones (some amino silicones
serve as one of the active ingredients in hair conditioners) meet these requirements and offer a
50% increase in CO2-loading capacity when combined in a nonaqueous glycol solvent (Perry
2010a).
CO2 Capture Process Using Phase-Changing Absorbents
During their work on the high-capacity oligomers, the GE-led team discovered that some
amino silicones, when used as a pure component liquid, react with the CO2 in the flue gas to
form a solid (Perry, 2010b). This approach offers the potential to utilize a solution having an
increased CO2 absorption capacity compared to the current cosolvent (amino silicone in glycol)
approach (Perry, 2010b). However, it will require a different process flow scheme in order to
employ it optimally for postcombustion CO2 capture. The GE-led team has received funding
through ARPA–E to develop a novel, cost-efficient CO2 capture process that uses the phasechanging absorbent (U.S. Department of Energy Advanced Research Projects Agency – Energy,
51
2010b). The project goals are <10% parasitic power load at 90% CO2 capture and <$25/ton CO2
capture cost. They anticipate that the process will require a smaller footprint than existing
postcombustion CO2 capture processes.
Adsorption
Adsorption is the partitioning of a molecule from a bulk fluid phase to the surface of a
solid. Typically, adsorption processes for CO2 capture include not only “true adsorption,” where
CO2 is adsorbed onto the surface of a solid, but also hybrid adsorption processes, where the real
mechanism is absorption of CO2 into a liquid that is supported on or in a solid particle.
Like absorption, the process of adsorption can be physical, where weak attractive forces
partition the CO2 onto the surface and into the pores of a solid, and chemical, where the CO2
reacts with functional groups on the solid surface to form a bicarbonate, carbonate, or carbamate.
The most common reactive functional group for chemical adsorption are metal carbonates, metal
oxides, metal hydroxides, or amino groups, the same reactive functional groups that do the work
in the solutions used as chemical absorbents.
Solids cannot be pumped from the vessel used to capture the CO2 from the flue gas to a
second vessel in which the purified CO2 is released and the sorbent regenerated in the same way
as a liquid. Therefore, the types of processes used for adsorbent-based CO2 capture differ from
the now-familiar absorber–stripper. The processes that are used can be categorized based on the
change made between the CO2 loading step and the release of CO2 from the solid as well as the
approach taken to contact the gas and the solid. These include:
 Pressure. In PSA, sorbent loading takes place under high-pressure. Pressure is released
or a vacuum applied in order to remove the adsorbed gas from the solid and regenerate
the adsorbent. Vacuum swing adsorption (VSA) and vacuum pressure swing adsorption
(VPSA) are special types of PSA where a vacuum is applied during regeneration.
 Temperature. In temperature swing adsorption (TSA), adsorption takes place at a low
temperature. Regeneration of the adsorbent is accomplished by heating the loaded
adsorbent, which causes the adsorbed gas to be released.
 Electric current. Electrical swing adsorption (ESA) is effectively a TSA process where
heating of the adsorbent is achieved by passing a current through the adsorbent. This
type of ESA is really a special type of TSA.
 Combined adsorption–reaction. These are not purely adsorption separation processes
but processes where adsorption is used in combination with a chemical reaction to
enhance the rate and/or extent of a desired reaction (e.g., sorption-enhanced WGS
process). Chemical-looping combustion, discussed in the “During Combustion” section
of this report, can be classified as a combined adsorption–reaction separation process
where the adsorbent is used to transport oxygen into the combustion reaction chamber.
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Traditionally, PSA and TSA are performed in fixed-bed adsorbers. Adsorbers are
cyclically operated in adsorption and desorption mode with multiple adsorbers used in series
and/or in parallel to permit continuous processing of gas. A series of adsorbers would be used to
produce high-quality product gas (or a low-discharge flue gas CO2 concentration) and to
maximize loading of the adsorbent before regeneration. Parallel flow paths would be used to
treat high gas flow rates in appropriately sized absorbers and/or to allow cycling of adsorption
and regeneration where a single adsorber is used rather than multiple adsorbers in series.
Figure 34 illustrates the general steps taken in a fixed-bed PSA system. The diagram shows the
product as the gas that is not adsorbed. For precombustion separation applications, both the
adsorbed (e.g., CO2) and not adsorbed (e.g., H2) gas would be desired as a product. Each fixed
bed is cycled through steps that include loading, depressurization, purging, and depressurization.
Optimizing the process cycle for removal and purification of CO2 in PSA is a topic of
considerable importance. Some of the recent work published in that area indicates that during
precombustion CO2 capture on shifted syngas, it should be possible to recover 99% pure H2
while capturing 92% of the CO2 at 96% purity (Agarwal and others, 2009). Moreover, these
cycles can recover more than 92% of the CO2 with a power consumption as low as
46.8 kWh/tonne CO2 captured. Other work on PSA cycles for CO2 capture from flue gas have
also indicated a good potential for high-percentage CO2 capture at high CO2 purities when using
appropriate sorbents and PSA cycles (Reynolds and others, 2005; Ritter, 2004).
Other types of adsorbers include expanded- and fluidized-bed adsorbers where the
adsorbent still stays in the same vessel but is not fixed in place. Advantages can be lower
pressure drop and low sensitivity to particulate contaminants. The use of fluidized-bed adsorbers
also enables operation in a mode where the solids are removed from the adsorption vessel and
Figure 34. General scheme for PSA (taken from Linde AG, 2010a).
53
transported to the regeneration vessel analogously to the way that liquid absorbents are
transported from the absorber to the stripper. In moving-bed adsorption, the sorbent is entrained
in the gas phase and transported to the location where it is separated from the gas phase.
Almost every type of adsorbent discussed has been incorporated into a membrane
separation system, usually as a composite polymer membrane containing very-small-particle-size
pieces of the solid material within the polymer matrix. Addition of the adsorbent alters the
properties of the membrane, helping to either speed the rate of transport of the desired gas or
slow the transport of other gases. Work on these composite membranes is discussed in the
membrane section of this report.
Table 3 contains a description of NETL’s view of the five reactor system types that can be
employed for solid sorbents for postcombustion CO2 capture (Richards, 2009). The reader should
note that these are all based on the use of a temperature swing between the adsorption (lowtemperature) and regeneration (high-temperature) steps. PSA would be more likely to be applied
to precombustion separations.
ADA–Environmental Solutions Adsorbent Screening Study
A DOE-funded project being performed by ADA–Environmental Solutions (ADA–ES)
involved the screening of physical and chemical adsorbents. ADA–ES screened over
100 materials classified into four categories: supported amines, carbon, zeolites, and carbonates
(Sjostrom, 2010). Figure 35 is a summary of the screening studies in which the sorbent types are
compared against MEA with respect to working capacity (how much CO2 can be captured and
released in one cycle per unit of adsorbent) and theoretical regeneration energy (TRE). The three
additional classifications given are thermal stability, thermal management, and any special issues
that present difficulties for that sorbent type. Green indicates a favorable characteristic, yellow
Table 3. Five Reactor System Types for Use of Solid Sorbents (Richards, 2009)
Structured-Bed Concept
• Fixed-bed adsorber, with internal heat removal
• Internal heating of same bed for regeneration
Moving-Bed Concept
• Moving-bed adsorber, with internal heat removal
• Moving-bed regenerator, with internal heating
Fluidized-Bed Concept
• Fluid-bed adsorber, with internal heat removal
• Moving-bed regenerator, with internal heating
Fixed-Bed Adsorber Concept
• Fixed-bed adsorber; adiabatic; multistage with interstage heat removal
• Heating of same bed for regeneration with hot fluid stream
Transport Reactor
• Circulating fluid-bed adsorber
• Circulating fluid- or moving-bed regenerator
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Figure 35. Classification of adsorbent types based on ADA–ES screening tests (taken from
Sjostrom, 2010).
indicates a characteristic that needs to be managed, and red indicates a characteristic that will
make it difficult to engineer a cost-effective solution using this type of system. It should be noted
that these rankings are for postcombustion capture. Different sorbents will be useful for
precombustion and during-combustion applications than those which are most favorable for
postcombustion capture. For example, while it appears from Figure 35 that supported amines
may have the most favorable characteristics for postcombustion capture, they would not be
useful for capture during combustion and are unlikely to be the best choice for precombustion
applications.
ADA–ES has selected the two most promising sorbents for testing in a 1-MW-equivalent
slipstream moving-bed contactor it plans to operate at three field sites: Southern Company and
Alabama Power’s E.C. Gaston Station, Luminant’s Martin Lake Station, and an Xcel Energy
plant (U.S. Department of Energy National Energy Technology Laboratory, 2009d).
Physical Adsorption (TSA, PSA, and ESA)
Zeolites
Zeolites are microporous aluminosilicate minerals that can occur naturally or be
synthesized. They are commonly used as molecular sieves for gas purification and drying.
Approximately 40 naturally occurring zeolites have been identified, and over 135 synthetic
zeolites have been synthesized. The mineral structure of a zeolite makes it look and behave as
molecular cage, as shown in Figure 36. The most common adsorption application for zeolites is
55
Figure 36. Porous cage structure of zeolite ZSM-5 (taken from Baerlocher and others, 2001).
removal of low concentrations of contaminants. Both pressure swing and temperature swing
regeneration are used to remove adsorbed contaminants from zeolites. Some zeolites commonly
used for moisture removal chemically react with CO2 to form carbonates that are not removed in
pressure swing applications.
Direct use of true zeolites for carbon capture is possible, but because they tend to have low
capacity, their potential for use in postcombustion capture applications has been largely
displaced by derivatives that include amine-functionalized zeolites, metal organic frameworks
(MOFs) that have similar physical cage structures but contain organic compounds as part of the
cage structure, and zeolitic imidazolate frameworks (ZIFs) that might be classified as a special
type of MOF. Some MOFs and ZIFs can act as physical absorbents, but with the inclusion of
appropriate reactive functional groups, it is possible to get higher-adsorption-capacity MOFs that
are chemical adsorbents. MOFs, ZIFs, zeolites that chemically react with CO2 to form
carbonates, and liquid absorbents supported in zeolites are discussed in the section on chemical
adsorbents.
Carbon Nanotubes and Activated Carbon
Carbon nanotubes and activated carbon act in a manner similar to zeolites in that small
pores act as molecular sieves, preferentially adsorbing molecules of a particular size. Many
research groups have investigated activated carbons and carbon nanotubes. The few highlighted
here are examples of the work being done that is focused on CO2 capture. Some research groups
have attached reactive functional groups to activated carbons and carbon nanotubes,
transforming them into reactive adsorbents. Others have trapped liquid absorbents in the
56
macropores of carbon-based solid supports, creating hybrid or mixed absorption/adsorption
media that can be used in adsorption-type process equipment. Much of the work with carbonbased adsorbents involves surface functionalization such that the carbon acts not only as a
physical adsorbent but also as a chemical adsorbent. Studies where the researchers have clearly
indicated the use of an amine functional group or attached amine are presented in a later section
of this report.
Advanced Technology Materials, Inc., and SRI International’s Novel Carbon
Sorbent
Advanced Technology Materials, Inc. (ATMI) and the SRI International are developing a
novel carbon-based CO2 sorbent with moderate thermal regeneration requirements (80°–100°C)
(Hornbostel, 2009). The researchers expect the sorbent to be low-cost, stable, have a low HR for
adsorption (25–28 kJ/mole CO2), and of high CO2 load capacity (0.1 to 0.2 kg of CO2 per kg of
sorbent (Hornbostel, 2009). The high-surface-area, carbon-based adsorbent will be chemically
functionalized in order to increase the selectivity and loading for CO2 capture and to reduce
thermal requirements for CO2 desorption. The only information available concerning the
structure of the sorbent is the image shown in Figure 37. ATMI also markets monolithic carbon
adsorbents that are used in the semiconductor industry (Advanced Technology Materials, Inc.,
2010).
Figure 37. ATMI’s adsorbent carbon materials (taken from U.S. Department of Energy National
Energy Technology Laboratory, 2009c).
57
The functionalized carbon adsorbent will be used in a moving-bed adsorber–regenerator, a
process similar to that typically used for liquid absorbent-based absorber–strippers and which is
shown in Figure 38. The flue gas stream is cooled in a DCC to decrease its temperature to nearambient conditions. The cooled flue gas from the DCC passes through a moving-bed reactor of
carbon sorbent pellets, and CO2 is absorbed. The CO2-laden sorbent is transported to a second
moving-bed reactor, where it is indirectly heated by steam coils to release the CO2. Technical
challenges with this system include competitive adsorption of moisture and other components in
the flue gas, removal of heat during adsorption to maintain a low-temperature environment for
the reaction, selection of a bed reactor, and heat exchange between the rich and lean sorbents.
The project plans to validate the performance of the carbon-based sorbent concept on a benchscale system, to perform parametric experiments to determine optimum operating conditions, and
to evaluate the technical and economic viability of the technology.
Electrical Swing Adsorption
In the ESA process, an electrically conductive carbon fiber material is used as the support
structure for an adsorbent material. This can be a physical adsorbent molecular sieve material
such as activated carbon or a zeolite or a chemical adsorbent such as a functionalized activated
carbon. The target gas molecules are adsorbed onto the material, which is sometimes referred to
as a fixed-bed carbon fiber composite molecular sieve (CFCMS). Regeneration of the sorbent is
achieved by passing a low-voltage electrical current through the continuous carbon skeleton.
This causes localized heating of the material and thus effects the thermal swing required to
desorb the CO2. An illustration of the seven-step cycle of an ESA system is shown in Figure 39.
Figure 38. Schematic of SRI International novel carbon sorbent system (taken from Hornbostel,
2009).
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Figure 39. Scheme showing the steps employed in the ESA process to capture CO2 from flue
gases, including 1) feed, 2) rinse with recycled gas, 3) internal rinse, 4) electrification,
5) depressurization, 6) purge, and 7) purge to provide gas for recycle (taken from Grande and
others, 2009).
Advertised advantages of ESA over TSA include faster heating (leading to shorter
regeneration times and higher unit productivities) and no requirement for sweep gas or steam to
carry the heat into the fixed bed so that the adsorbed gas is more easily recovered as an undiluted
product. It is easier to achieve a large temperature swing between the low adsorption temperature
and the high regeneration temperature, thus maximizing the working capacity of the adsorbent.
Four research groups have published work on the use of ESA for CO2 capture: CNRS in
Nancy, France (Ettlili and others, 2007); ORNL (Baker and others, 2006), the University of
Porto, Portugal (Grande and others, 2008, 2009, 2010); and a group at the University of
Queensland, St. Lucia, Australia (Ana and others, 2010). None of these efforts has proceeded
beyond the use of small lab-scale systems.
The group at ORNL has also investigated the use of ESA for the separation of air into
oxygen and nitrogen.
Si/Al Gels
Silicon/alumina gels are the amorphous cousins of the crystalline aluminosilicate zeolites.
They also serve as highly porous molecular sieves. Silica gels are finding most of their potential
for use in carbon capture not as physical adsorbents but in mixed adsorption/absorption as
supports for amines and ionic liquids and in chemical adsorption through attachment of amine
functional groups.
59
Chemical Adsorption
Metal Oxides and Other Minerals
Researchers at NETL have been conducting theoretical modeling studies on the use of
metal oxides and metal hydroxides as solid adsorbents for postcombustion CO2 capture. Through
the analysis, sodium and potassium bicarbonate–carbonate pairs (NaHCO3–Na2CO3, KHCO3–
K2CO3) as well as magnesium oxide (MgO) and magnesium hydroxide Mg(OH)2 have been
identified as good candidates for use as postcombustion CO2 adsorbents (Duan, 2010). Another
group at NETL has been studying the use of an Mg(OH)2-containing sorbent for precombustion
CO2 capture (Siriwardane and Stevens, 2009; Siriwardane and others, 2007). One advantage to
this approach appears to be the ability to perform the adsorption step at an elevated temperature
(200°−315°C) that would eliminate the need for the cooling that is required when using physical
solvents such as Rectisol in a coal gasification system. Thermodynamic analysis conducted with
the FactSage software package indicated that the Mg(OH)2 sorbent system is highly favorable for
CO2 capture at temperatures and pressures up to 400°C and 30 atm. MgCO3 formed during
sorption decomposes to release CO2 at temperatures as low as 375°C with pressures up to
20 atm. The MgO formed after CO2 release could be converted back to Mg(OH)2
(rehydroxylation) at temperatures up to 300°C at 20 atm. Experimental data confirmed sorbent
regeneration at 375°C, and a multicycle test conducted in a high-pressure fixed-bed reactor at
200°C with 28% CO2 showed stable reactivity during cyclic tests. The potential for use at high
pressure and high temperature is particularly advantageous for precombustion capture
applications, and the high-pressure regeneration is advantageous because it decreases CO2
compression costs.
Stabilized Calcium Oxide Adsorbents with Improved Durability for HighTemperature CO2 Capture
A group at Pacific Northwest National Laboratory (PNNL) has been working with calcium
oxide (CaO)-based adsorbents. The stated advantage is that these sorbents can be used at
elevated temperatures. Normally, CaO-based absorbents undergo a loss of CO2 transport
capacity over many carbonation–decarbonation cycles because of sintering. In the PNNL work, it
was found that mixing CaO precursors with small rodlike MgAl2O4 spinel nanoparticles
provided a CaO-based adsorbent with improved high-temperature durability (Li and others,
2010). The process that was developed created a 34 wt%-CO2 capacity adsorbent that was found
to be stable for over 65 carbonation−decarbonation cycles when carbonation (adsorption) was
performed at 650°C and calcination (decarbonation, or regeneration) was performed at 850°C (Li
and others, 2010). For comparison, the CO2 capacity of natural dolomite (which is 35 wt% MgO
and 65 wt% CaO) decreased rapidly from 25 wt% for the first cycle to less than 5 wt% for the
fiftieth cycle (Li and others, 2010).
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RTI International – Dry Sorbent-Based Capture Process
The RTI International high-temperature dry adsorbent-based, postcombustion capture
process development program is in the sixth year of NETL sponsorship. Research team members
and subcontract partners include RTI International; NETL; EPRI; ARCADIS, Inc.; the U.S.
Environmental Protection Agency (EPA); Sud-Chemie, Inc.; and Nexant.
The dry sorbent-based capture process is illustrated in Figure 40. The concept is to use a
metal carbonate-based adsorbent that is transformed into a metal bicarbonate in the adsorber and
then regenerated through release of CO2 in the regenerator. The metal carbonate-to-metal
bicarbonate swing allows a maximum CO2 transport of 1 gm of CO2 for every 2.4 gm of metal
(Na) carbonate that is fed to the adsorber each cycle (Nelson and others, 2009).
The adsorber is fed solid sodium carbonate that reacts with water and CO2 in the flue gas
to form solid sodium bicarbonate. This is an exothermic reaction that is performed at lower
temperatures, with intercooling to remove the HR. The bicarbonate solid is then transported to
the regenerator where heat is added to drive off the CO2 and water to regenerate the metal
carbonate. This is an endothermic reaction performed at higher temperatures, so heat must be
added to supply the required energy. A condenser is used to remove water from the CO2 stream,
and the CO2 is subjected to compression, drying, and if necessary, purification.
Figure 40. RTI International capture process using dry regenerable sorbent (taken from Gupta,
2004).
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Figure 41 is a schematic diagram of the system including a deep sulfur scrubber, a
downflow cocurrent adsorber, the steam-jacketed screw conveyer used for regeneration and
production of the purified CO2 gas stream, and the cooling-water-jacketed screw conveyer used
to move the sorbent back to the adsorber.
There are many advantages to the process, including low regeneration energy requirements
relative to amines, production of essentially pure CO2, and compatibility with current power
plant operating conditions. Challenges include the need for efficient heat removal to prevent selfextinguishing of the reaction, continuous circulation of solids, and the fact that the sorbent reacts
with other contaminants such as SO2 and particulate (Nelson and others, 2009).
Both the sorbent and the process have been tested with natural gas and coal-fired flue gas
at EPA’s multipollutant control research facility (MPCRF). The system was operated for 130 hr
on natural gas-derived flue gas containing approximately 6 vol% CO2. The maximum
CO2removal achieved was roughly 99%. When operated on coal-derived flue gas for 105 hr at a
CO2 concentration of about 10.5 vol% and a SO2 concentration of roughly 20 ppm (mixture of
eastern bituminous and Powder River Basin subbituminous coals), the maximum CO2 removal
was approximately 92% (Nelson and others, 2009).
Current work involves scaling up to a 1-ton/day CO2 capture system, with the sorbent
manufacturing partner Sud-Chemie, Inc., scaling its manufacturing capacity sufficient to provide
for that demonstration and planning for production of sufficient material for a 100-ton/day
Figure 41. Dry carbonate process (taken from Nelson and others, 2008).
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system by 2012. The target date for technology commercialization is 2015 (Nelson and others,
2009).
Regenerable Magnesium Oxide-Based Adsorbents
A group at the Illinois Institute of Technology and GTI developed regenerable MgO-based
adsorbents for use in capture of CO2 from raw syngas (Abbasian and others, 2005). The
magnesium-based sorbents were found to be useful over a temperature range of 300°–450°C and
at a pressure of 20 atm. CO2 adsorption through carbonation of the MgO occurs at gasification
process conditions, with sorbent regeneration being carried out by increasing the temperature to
produce a concentrated stream of CO2. The sorbents were prepared from dolomite (a type of
limestone). Partial calcinations and impregnation with potassium salts helped produce a
mechanically stable and highly reactive sorbent (Hassanzadeh and Abbasian, 2010). Tests found
that generation temperature greater than 425°C required a heat source other than waste heat and
that the reactivity gradually decreased during the sorption–regeneration cycles.
Sorption-Enhanced Water–Gas Shift (SEWGS) Process
The SEWGS process developed by Air Products and Chemicals, BP, and Energy Research
Centre of the Netherlands combines the use of a potassium-promoted hydrotalcite-based CO2
sorbent and a commercial iron–chromium shift catalyst (van Selow and others, 2009).
Hydrotalcite is an anionic clay mineral that has found use as an antacid. It is a secondary mineral
in the ultramafic rock serpentinite, one of the high magnesium-content rocks viewed as a
potential resource for use in accelerated weathering-based CO2 capture. The sorption process
involves formation of MgCO3. Sorbent regeneration occurs by stripping with low-pressure steam
at about 400°C (van Selow and others, 2008). In the process, multiple adiabatic fixed beds cycle
between the shift reaction with adsorption and regeneration steps. Removal of CO2 during the
shift reaction removes the normal equilibrium barrier presented by accumulation of CO2 in the
normal shift process, thus increasing the conversion efficiency.
SEWGS is capable of capturing more than 90% of the CO2 while producing a very pure
CO2 stream (Allam and others, 2004). The process shows promise for use in hydrogen
production and IGCC applications Cobden and others (2007). The SEWGS process has not yet
been commercialized but has been scaled to a large laboratory/pilot-scale, four-bed multicolumn
system as part of CACHET, a 3-year, integrated research project funded by the European
Commission and the international industrial/governmental CO2 Capture Project (CCP). Further
development and testing are under way, with large-scale pilot testing planned for the near future
(Energieonderzoek Centrum Nederland, 2010). Some of the other key references describing
development of SEWGS include those by Allam and others (2005) and Hufton and others
(2006).
Metal Organic Frameworks
MOFs are organic compound-containing cage structures. With the appropriate selection of
the organic and inorganic components, a self-assembling MOF is formed with engineered
macromolecular cavities that can act as sites for physical and/or chemical adsorption of CO2.
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MOFs could be applied to both precombustion and postcombustion capture. Figure 42 shows
some examples of the wide variety of MOF structures that have been built. It is apparent that
MOFs have pore and cage structures that are similar to zeolites, but because organic compounds
serve as part of the pore structure, a greater variety of pore sizes, cage structures, and inclusion
of reactive functional groups can be achieved than is possible with the inorganic zeolites. The
structures that have been built include examples with surface areas as high as 10,400 m2/gram
and CO2 storage capacities as high as 2.870 grams of CO2 per gram of MOF (Furukawa and
others, 2010). While having very high capacities is helpful, it is also desirable for a MOF to
exhibit fast adsorption and desorption rates. This can be accomplished by building MOFs with
pore structures that are a combination of larger and smaller pore sizes. Considerable attention is
also being paid to temperature and steam stability of MOFs (Benin and others, 2009). The most
likely process application for MOFs is in fixed-bed VPSA for postcombustion CO2 capture.
While many research groups have published work in the area of MOF development, the
leading activities are being performed include 1) a large DOE-funded project managed by UOP
and 2) work at University of California Los Angeles and South Korea’s Hydrogen Energy R&D
Center funded by BASF, the DOE Office of Basic Energy Sciences, and South Korea’s Ministry
of Education. The UOP project includes research groups at UOP, the University of Michigan,
Northwestern University, Vanderbilt University, and the University of Edinburgh.
Figure 42. Examples of MOF structures (taken from Yaghi, 2006).
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Additional information about MOFs can be found in the fact sheet for the NETL-funded
project “CO2 Removal from Flue Gas Using Microporous Metal Organic Frameworks” (U.S.
Department of Energy National Energy Technology Laboratory, 2010b) as well as in Willis and
others (2007) and Yazaydin and others (2009).
Zeolitic Imidazolate Framework
ZIFs can be thought of as a special type of MOFs. They are a class of crystalline
nanoporous materials made of zeolite minerals and imidazoles at the organic linkages
(imidazole’s are also used as ionic liquids and for making poly[ionic liquid] polymers).
Researchers at PNNL (Nune and others, 2010) and the University of Pittsburgh (Rankin and
others, 2009) are developing and testing ZIFs for CO2 capture. The work appears to be in the
early laboratory stage, with a focus on molecular modeling and synthesis of new materials.
TDA Dry Solid Sorbent
TDA Research, Babcock & Wilcox, Louisiana State University, and Western Research
Institute are developing a process that uses an alkalized alumina adsorbent to capture CO2 at
intermediate-temperature and near-ambient pressure. The physical adsorbent is regenerated with
low-pressure steam. The target adsorption gas–solid contact time is approximately 1.5 seconds,
and the target regeneration contact time is 1.5 minutes (Elliot and Srinivas, 2009). Results from
system modeling indicate that the TDA dry solid sorbent system with compression should
achieve a power loss of 20.7%, where the theoretical minimum is 13.46%. Additional
information is available in the project fact sheet (U.S. Department of Energy National Energy
Technology Laboratory, 2010d).
Novel Amine-Enriched Solid Sorbents
This technology was developed by NETL and is currently at the laboratory scale. The
sorbent consists of a carbon material with amine compounds fixed upon it. When exposed to a
CO2-rich stream, the amine sites react with the CO2. Temperature swing is used to release the
CO2. High sorption capacities on the order of 4 moles CO2/kg solid sorbent have been observed.
The use of tertiary amines requires lower energy for CO2 capture when compared with aqueous
amine absorbents. When compared to an aqueous solution, the solid has a low heat capacity, and
there is a smaller difference between adsorption and regeneration temperatures, meaning that the
regeneration energy requirement is low compared to that of MEA (783 Btu/lb CO2 and
1934 Btu/lb CO2, respectively) (Pennline and others, 2009; Tarka and Ciferno, 2005).
Comparison of Amine-Functionalized Carbon Nanotubes, Granular Activated
Carbon, and Zeolites
Lu and others at National Chung Hsing University, National Chiao Tung University, and
Industrial Technology Research Institute in Taiwan reported that amine functionalization of
carbon nanotubes provided greater enhancement of adsorption capacity than the same
functionalization on activated carbon or zeolites (Lu and others, 2008). Although the researchers
expected to see evidence of chemical adsorption because of the amine functional groups, the
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results suggested that physical adsorption is the principal mechanism. This would lead to a low
energy of desorption. The work is in early laboratory phase, and current efforts are focused on
investigating the reversibility of CO2 adsorption by these adsorbents.
Metal Monolithic Amine-Grafted Zeolites
The University of Akron and NETL have been working together to develop a CO2 capture
system that involves the novel integration of a metal monolith containing gas flow channels that
have amine-grafted zeolites plated to the walls and heat-transfer fluid flow channels that are used
for cooling during CO2 adsorption and heating during regeneration. Figure 43 summarizes the
approach. The metal monolith adsorber works like a specialized fixed-bed adsorber with a very
low pressure drop for gas flow and good heat-transfer characteristics for fast heating and cooling
during the transition between the adsorption and regeneration steps.
It is expected that the low cost of raw materials for the synthesis of zeolite-grafted amine
sorbents combined with the innovative application of metal monoliths as an adsorber structure
may lead to a breakthrough technology for the effective capture of CO2  from flue gas of coalfired power plants. Additional information is available in the project fact sheet entitled “Metal
Monolithic Amine-Grafted Zeolites for CO2 Capture” (U.S. Department of Energy National
Energy Technology Laboratory, 2010e).
University of Ottawa – Recyclable CO2 Adsorbent
Researchers at the University of Ottawa have developed recyclable CO2 adsorbents based
on surface-modified expanded mesoporous silica (Franchi and others, 2005; Belmabkhouta and
others, 2010). The materials exhibit a high adsorption capacity that is both fast and reversible.
The adsorbents can be used with both wet and dry gas streams. The most current research paper
(Belmabkhouta and others, 2010) indicates the use of the adsorbent to remove CO2 from air. The
use of these adsorbents for CO2 capture from flue gas has been licensed to Carbon Capture
Technologies, Inc., a branch of CSMG Technologies, Inc.
Hyperbranched Aminosilica
HAS adsorbents are chemical adsorbents created by polymerization of hyperbranched
amines onto a mesoporous silica substrate. Researchers at Georgia Tech and NETL have
succeeded in making several different examples of these materials with different polymeric
amines and different mesoporous silicates (Gray and others, 2010; Choi and others, 2009; Hicks
and others, 2008; Drese and others, 2009). Good CO2 adsorption and regeneration behavior has
been obtained over temperature ranges of 50°–75°C and 100°–120°C, respectively
(Environmental Protection Online, 2008). Performance was stable over multiple cycles, and the
adsorbents exhibited a low sensitivity to moisture. Loss of the amine from the surface is not a
problem with these adsorbents because the amine polymer is covalently bonded to the solid silica
substrate (Hicks and others, 2008).
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Figure 43. CO2 capture unit with metal monolithic amine-grafted zeolites (taken from Chuang,
2009).
Other groups involved in working with amine-functionalized silica include Liu and others
(2010) in Taiwan, Pirngruber and others (2009) in France, and Zheng and others (2005) at
PNNL. Recently, a group in China reported on amine group-containing ionic liquids
immobilized to porous silicate solids (Zhang and others, 2009). All of these projects are at the
small laboratory scale and are focused on developing adsorbents with favorable characteristics.
Membranes
A membrane is a structure that has lateral dimensions much greater than its thickness
through which mass transfer may occur under a variety of driving forces (Koros and others,
1996). Membrane-based gas separations used in carbon capture include those designed to
provide separation of oxygen from air for use in oxycombustion and gasification
(precombustion), those designed for use in precombustion applications including hydrogen
transport membranes and CO2-permeable membranes, and those used to perform separations of
postcombustion flue gas; these are primarily CO2-permeable membranes. It should be noted that
gas-permeable membranes are used commercially for treatment of natural gas in order to
upgrade it to pipeline quality, but these applications rarely capture the CO2 as a purified product.
Membranes can also be used as a means of providing gas–liquid contact in place of absorption
and/or stripping towers in a much smaller-volume device because of the very high surface area
per unit volume. This application was discussed in the “Use of Mass Transfer Devices Other
Than Absorption Towers” section of this report.
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Gas separation membranes use partial pressure as the driving force for transport.
Differences in the ease of transport of the various gas components provide the means for
separation. Because the partial pressure difference from the source side of the membrane to the
permeate side of the membrane is the driving force, it is easier to transport a selected gas
component when the source gas is at a high total pressure and that component is at a high
concentration. However, this situation cannot be present at all locations in a membrane
separation process if the requirement is removal of most of that component from the feed gas
(e.g., capture of 90% of the CO2) and collection of that component as a purified product (e.g.,
production of >95% pure CO2). Separation is achieved because differences in physical and/or
chemical interactions between the components present in a gas mixture with the membrane
material cause one component to permeate through the membrane faster than the other
component(s). The gas component with the highest solubility, fastest diffusion rate, or the ability
to ionize or otherwise interact with membrane components under the process conditions is
preferentially transported across the membrane.
Figure 44 illustrates the four areas of work involved in development of a new membrane
technology. These are development of the membrane material (advanced materials) with an
understanding of the basis for its performance including the chemistry and structure
(micromorphology), the development of the appropriate physical device (or module) and the
ability to make that device (module manufacture), and the design of the process system in which
to use that device (system development and modeling). These are shown together in the figure
because they are linked efforts that must be performed in concert.
Figure 45 is a representation of general types of membranes (Cowan, 2008). The figure
shows several types of polymer membranes, two types of liquid membranes, two types of
membrane structures, and lists other types of materials used as membranes. It does not provide a
comprehensive list but rather illustrates the diversity. The types of selective processes that occur
in these membranes are illustrated in Figure 46. It should be noted that more than one of these
selective processes can be involved in one membrane, especially if that membrane is a
composite, matrix composite, or liquid membrane. It should not be assumed that metal, ceramic,
or zeolite membranes cannot have complex structures or multiple selective processes. Finally,
while the basic format of all membranes is essentially a flat sheet or a tube, there is great variety
as to how these are packaged into membrane modules. Flat-sheet membranes can be used in
plate-and-frame-type modules or in a variety of spiral-wound module designs. Tubular
membranes (e.g., hollow-fiber membranes) are typically used to construct modules with epoxysealed tube sheets where the source gas flows through the inside of the tube and the permeate is
collected from the shell side (or vice-versa).
Gas flow paths in membrane modules generally follow one of four configurations,
illustrated in Figure 47. The feed gas is the mixed-gas stream that must be treated or separated.
The retentate gas is the effluent-treated feed gas that lost the components that passed through the
membrane. The permeate is the effluent gas that includes the gas molecules that passed through
the membrane as well as any sweep gas fed to that side of the membrane to act as a diluent (in
order to maintain a low partial pressure for the transported gas). Ideally for postcombustion
carbon capture, the feed gas (green) is a mixture of nitrogen (blue) and CO2 (yellow), and it
could be separated in one step without the use of a sweep gas (red). Realistically, it will require
multiple processing steps and/or the use of a sweep gas that can easily be separated from the CO2
(e.g., water vapor, which can be separated by condensation through cooling and compression).
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Figure 44. Work required to develop membrane separation technologies (adapted from Koros,
2008).
Figure 45. Types of membranes used in separations (taken from Cowan, 2008).
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Figure 46. Separation behavior in membranes (taken from Cowan, 2008).
Figure 47. Gas flow paths in membrane modules (taken from Cowan, 2008).
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The quality of the separation is determined by the membrane selectivity and by two
process parameters: 1) the ratio of the permeate flow to the feed flow, and 2) the ratio of
permeate pressure to the feed pressure. Depending upon the selectivity of the membrane, a highpurity CO2 product may require a large number of stages, leading to increased recompression
and capital costs. Membrane separation often competes with cryogenic separation and PSA when
medium quantities of low-purity product gas are required. Membrane separation technology is
currently better suited to treatment of mixed-gas streams fed from a high-pressure source, such
as natural gas processing.
Air Separation for Oxycombustion and Gasification
The traditional method used to obtain a high-volume supply of purified oxygen for
oxycombustion and gasification is to perform cryogenic distillation of air in an ASU. This is an
energy-intensive process that is likely to represent up to 58% of the parasitic energy load of an
oxycombustion carbon capture process (Varagani and others, 2005). Membrane separation
techniques are being developed as potential lower-energy replacements for cryogenic ASUs.
Oxygen-Permeable Membranes
Air Products – Ion Transport Membrane
Air Products and Chemicals, with financial assistance over several years from DOE, has
developed an ion transport membrane (ITM) oxygen purification system (Shelley, 2009). This
system is considered to be at near-commercial stage. It has been demonstrated in a 5-ton/day
pilot plant since 2006 and Air Products is currently working on a 150-ton/day test facility with
NETL. Air Products hopes to offer a small commercial-scale unit having a capacity of less than
800 tons/day by 2011 and to be operating a full commercial-scale test facility capable of
producing 2000 tons/day of oxygen by 2013. Details on the process can be found in the DOE
project fact sheet (U.S. Department of Energy National Energy Technology Laboratory, 2009b)
or an Air Products online brochure (Air Products and Chemicals, 2008).
Oxygen-Selective Polymer Membranes
Most polymers are either more permeable to oxygen over nitrogen or to nitrogen over
oxygen, meaning that the potential exists for development of a polymer membrane-based system
for purifying oxygen. Unfortunately, such a system has not yet been developed for the generation
of large quantities of pure oxygen from air. Commercial systems can be purchased for
membrane-based production of 50% O2 (Grasys, 2010), and several companies offer membranebased nitrogen purifiers that generate high-purity nitrogen from air. Polymer membranes
containing molecular sieves do show some promise for providing higher-purity oxygen from air.
The matrix composite polymer membranes that have been investigated for oxygen purification
include polymer membranes utilizing activated carbon (Jones and Koros, 1994; Kusworo and
others, 2010) or zeolites (Wang and others, 2002) as the molecular sieve.
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Hydrogen Separation and Integrated Precombustion Capture Systems
CO2-Selective Ceramic Membrane for WGS Reactions
Between 2000 and 2005, DOE funded work by Media and Process Technology, Inc., the
University of Southern California, and NETL on the development of a CO2-selective ceramic
membrane for WGS reactions with recovery of CO2. These membranes were developed for use
in a high-temperature membrane reactor (MR) designed to enhance the performance of the WGS
reaction through removal and capture of CO2. Two membranes were developed and tested: a
Mg-Al-CO3-layered double hydroxide (LDH) membrane and a carbonaeceous membrane. A
hybrid adsorption membrane reactor (HAMR) was also developed that provided close to 100%
CO conversion, a high-purity H2 product fuel, and a concentrated CO2 product. The HAMR used
the LDH as a particulate adsorbent and required off-line regeneration (Liu, 2005).
The tubular ceramic membranes used in the MR and HAMR are made of a porous ceramic
that has had its pores filled with hydrotalcite, making them impermeable to all the gases present
except CO2. The membrane tubes are filled with shift catalyst, which converts the CO and water
in the syngas to CO2 and H2. CO2 permeates through the hydrotalcite on the membrane, driving
further conversion of CO. This technology can be applied to syngas produced from coal
gasification. Advantages include a permeate stream that is essentially pure CO2; a H2 stream that
is maintained at near-syngas-generation pressures; the fact that the fuel gas stream contains both
H2 and water (which is advantageous because additional mass flow from water through the
turbine improves power production and efficiency); and a process that operates in the
conventional WGS temperature range of 300° to 600°C. Unfortunately, it is difficult to produce
defect-free membranes (Liu, 2005).
A mathematical model was developed to simulate the HAMR, and a laboratory-scale
reactor was constructed and operated to corroborate the model results. The project was
successful in demonstrating enhanced WGS efficiency for hydrogen production with
concomitant CO2 capture (Liu, 2005).
Combined Use of Oxygen Transport Membranes and Hydrogen Transport
Membranes for Carbon Capture in Natural Gas Reforming and Coal Gasification
Three membrane technologies developed by Eltron Research and Technology (ERT) are
included here: an oxygen transport membrane used to separate oxygen from air; a catalytic
membrane reactor (CMR) that serves as both an oxygen transport membrane and a catalytic layer
for in situ partial oxidation reforming of methane; and a dense metal alloy membrane for
hydrogen separation from the CO2 and H2O present in the shifted syngas. All three of these
technologies were developed with support from DOE and are discussed in a paper by Mundschau
and others (2006).
The oxygen transport membrane operates by dissociating oxygen molecules at the reducing
surface of the membrane. The oxygen ions are then transported across the ceramic membrane
and converted back to oxygen gas at the oxidizing surface. Electrons flow in the opposite
direction through the membrane, forming an electrochemical device that requires no electrical
energy input. The driving force is the oxygen partial pressure difference across the membrane,
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rather than the absolute pressure on each side. Only oxygen from the air side passes through the
membrane because only oxygen ions are mobile within the ceramic. No other gases, including
carbon monoxide, nitrogen, argon, and methane, are able to pass through the membrane (Eltron,
2009b). Figure 48 is a schematic of the oxygen transport membrane.
The CMR is made from a layer of a ceramic oxide material with a perovskite crystal
structure onto which methane steam-reforming catalysts (including noble metal catalysts) are
dispersed, a dense perovskite layer that is essentially completely selective toward oxygen, and a
support layer. Figure 49 contains a schematic representation of the CMR (top) and
photomicrograph of the oxygen-permeable catalytic membrane (bottom). The membrane
operates at high temperatures ranging from 850° to 1000°C. Tests on the tubular membranes
were performed continuously for up to 9 months under reaction conditions with differential
pressures of 250 psi (17.2 bar). The Perovskite materials were found to be stable under the test
conditions (Eltron, 2009c).
The dense metal alloy membrane used for H2 separation has a layer of hydrogen
dissociation catalyst on the feed side of the membrane and a catalyst that reduces dissociated
hydrogen back to molecular H2 on the other side of the membrane. Hydrogen partial pressure
serves as the driving force to move H2 across the membrane in dissociated form. Pure H2 is
produced on one side of the membrane and a high-pressure stream of CO2 and steam with a
small amount of CO is produced on the other. Sweep gas can be used for direct injection of the
H2 stream into a hydrogen turbine. When pure H2 production is desired, no sweep gas is
employed (Eltron, 2009a). Figure 50 is a schematic of the dense metal alloy hydrogen separation
membrane.
Figure 48. Eltron’s oxygen transport membrane (taken from Eltron, 2009b).
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Figure 49. Schematic of catalytic membrane reactor with oxygen transport membrane (top)
(taken from Mundschau, et al., 2006) and photomicrograph of the oxygen-permeable CMR
(bottom) (taken from Eltron, 2009c).
Palladium-Based Membrane Reactors
Several groups have been developing palladium-based membranes for use in
precombustion CO2 capture. These membranes have catalytic activity for the WGS reaction and
are permeable to hydrogen.
Palladium–Copper Alloy Membrane Reactor
NETL and the Colorado School of Mines (CSM) developed a palladium–copper alloy
membrane reactor for simultaneous catalysis of the WGS reaction and transport of H2 across the
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Figure 50. Eltron’s hydrogen transport membrane (taken from Eltron, 2009a).
membrane (Romanosky and others, 2007; Way and Thoen, 2006). The high temperature (900°C,
1652°F) and pressure of operation and the catalytic effect of the membrane eliminate the need
for a separate WGS catalyst. The palladium–copper alloys are resistant to H2S degradation.
Hydrogen Membrane Reformer (HMR)
The HMR gas power cycle is a precombustion carbon capture technology under
development by StatoilHydro. The HMR technology centers on a syngas reactor that is based on
a hydrogen-selective membrane. The reactor combines steam reforming, WGS reaction, and H2
separation. The reactor utilizes a dense MCM, which is a palladium/silver-based membrane with
theoretical infinite selectivity to H2 permeation. Figure 51 illustrates the process of the cycle. On
the feed side of the membrane in the reactor, natural gas or fuel gas is contacted with steam in
the presence of reforming catalyst to produce syngas. CO remaining in the syngas after
combustion is shifted in downstream shift reactors. A limited amount of air is supplied to the
permeate side of the membrane to combust all of the hydrogen that has passed through the
membrane, generating “CO2-free” heat for the endothermic steam–methane reactions.
Supplementary CO2 removal following the WGS reaction is achieved by using a conventional
absorption process (Smith and others, 2009).
The HMR reactor has been scaled up to a small-scale, square-channel, monolithic
membrane reactor depicted in Figure 52. A complete module is made of the monolith and two
manifolds at the ends. The monolith has porous walls and serves as a mechanical support for the
thin (30–50-μm) membrane, which is coated in every second channel. A full-scale reactor has
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Figure 51. Sketch of the new HMR process with HMR syngas reactor and separate CO2 removal
unit (taken from Smith and others, 2009).
Figure 52. HMR monolith (taken from Smith and others, 2009).
been conceptualized that would have a capacity for reforming 800–900 MW (LHV) natural gas
to syngas sufficient for generating 400 MWe (Smith and others, 2009).
Since start-up in 2001, the development of the HMR gas power cycle has been financed by
CCP, with cofunding from the Research Council of Norway. A new, less complicated HMR gas
power cycle has been developed and benchmarked. The efficiency loss and CO2 capture rate are
typically 8% and 85%, respectively. These values are lower than what was achievable using the
original HMR process. However, because of lower investment costs in the new process, it has a
CO2 avoidance cost that is approximately 20% below the original concept. Small-scale monolith
modules have been fabricated and tested under realistic HMR process conditions. Issues found
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during testing included a low hydrogen flux and difficulty maintaining a high driving force along
the reactor (Smith and others, 2009).
Hydrogen Membrane Reactor
A collaborative development partnership operated as part of the European CACHET
project has been developing hydrogen membrane reactors for CO2 capture. The partners include
Dalian Institute of Chemical Physics (DICP) from China, SINTEF from Norway, the National
Technical University of Athens (NTUA), the Process Design Center (PDC), and Energy
Research Centre of the Netherlands (ECN) (Jansen and others, 2010). The membrane is
composed of a pure palladium layer deposited on a tubular ceramic support. The manufacture of
these by DICP has been scaled up to 50-cm-long, 220-cm2-membrane-area tubes fitted with
high-temperature (700°C), high-pressure (38 bars) end caps provided by ECN. A laboratoryscale process development unit containing eight of the membrane tubes has been constructed and
is being tested. This device is capable of producing up to 25 kWt of H2 (Jansen and others, 2010).
Inorganic Nanoporous Membranes
The Inorganic Membrane Technology Laboratory at ORNL has developed hydrogenpermeable inorganic membranes for separation of H2 from syngas streams or the shift gas stream
from natural gas reforming, coal gasification, and refinery purge gases. The inorganic
membranes, which are three-layer composite membranes that include a nanoporous layer
(<5 nm pores) on a microporous layer (~0.5-µm pores) supported on a macroporous support
structure (~50-µm pores). Transport through the membranes is by molecular diffusion. It is
pressure-driven and is affected by temperature. Separation may occur by surface flow, molecular
sieving, Knudsen diffusion, or a combination of these mechanisms. As the temperature is
increased, the permeance of hydrogen increases faster than that of CO2, resulting in larger
separation factors (Bischoff and Judkins, 2006). Additional information can be found on the
ORNL Inorganic Membrane Technology Laboratory Web site (Oak Ridge National Laboratory,
2010).
High-Temperature Polymeric–Metallic Composite Membranes for H2/CO2
Separation
Idaho National Energy and Engineering Laboratory (INEEL) and collaborators with Los
Alamos National Laboratory (LANL), Pall Corporation, and Shell Oil Company are developing a
polymer membrane for high-temperature membrane CO2–H2 gas separations. The membrane is
composed of a thermally stable polybenzimidazole (PBI) thin-film composite layer on a porous
stainless steel substrate. The resulting composite membrane outperforms other high-temperature
membranes in terms of selectivity for the separation of H2. The metallic support structure allows
the membrane to be effective at higher pressures than conventional polymer membranes, and it
has been demonstrated at temperatures as high as 400°C. This is a H2 transport membrane so the
CO2 remains at high pressure, ready for transportation to geological storage (Berchtold and
others, 2006).
Additional information on the development of these membranes can be found in the project
fact sheet (U.S. Department of Energy National Energy Technology Laboratory, 2008b).
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Recently Announced DOE Funding for Membrane Separations for Coal Gasification
with Carbon Capture
On July 27, 2010, DOE announced the funding of four projects that will test membrane
technology to separate hydrogen and CO2 from coal or coal/biomass-derived synthesis gas
(syngas). Testing will be conducted using actual coal-derived synthesis gas. The projects are
intended to advance the technologies toward scale-up to membrane module demonstrations, with
the eventual goal of designing and fabricating commercial-scale processes for incorporation into
advanced power plants. Technology developers and the technologies receiving funding include
the following:
 Praxair, Inc., with partners T3 Scientific and CSM, will demonstrate palladium (Pd) and
Pd–alloy membranes on ceramic supports for hydrogen separation from coal-derived
syngas.
 United Technologies Research Center will partner with Power+Energy, Inc., to
demonstrate hydrogen separation from coal-derived syngas using Pd and Pd–alloy
membranes in three forms: dense metal, surface-modified dense metal, and
nanocomposite metal membranes.
 Western Research Institute will collaborate with Chart Energy and Chemicals and
Synkera Technologies to develop and test planar Pd-based ceramic–anodic aluminum
oxide membranes for hydrogen separation from coal-derived syngas streams.
 Worcester Polytechnic Institute will collaborate with Membrane Technology and
Research, Siemens Energy America, and T3 Scientific to demonstrate hydrogen
separation from coal-derived syngas using Pd and Pd–alloy membranes on porous
metal supports.
Further descriptions of the projects are available in the DOE press release about the funding
(U.S. Department of Energy, 2010b).
Postcombustion Capture
The September 1, 2010, issue of the Journal of Membrane Science is a special issue
dedicated to the topic “Membranes and CO2 Separation.” Among the interesting papers in the
issue (many of which are cited elsewhere in this document) is a paper by Brunetti and others
(2010) that provides the CO2 permeability and CO2/N2 selectivity of many of the “most
important” polymer materials, including matrix composite polymer membrane materials. The
authors also refer the reader to a paper by Powell and Qiao (2006) that contains a comprehensive
review of all polymeric CO2/N2 gas separation membranes reported in the literature before the
publication of their paper. The interested reader should consult those works if they wish to
compare the properties of a newly reported membrane material to those of materials already
reported in the literature.
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Other key papers in that issue related to postcombustion capture include papers by Zhao
and others (2010) and Merkel and others (2010). An important point illustrated in Zhao and
others (2010), Merkel and others (2010), and Brunetti and others (2010) is that the optimum
membrane properties for purification of CO2 from flue gas do not call for maximizing both
permeance and selectivity but rather to obtain very high permeance for membranes of moderate
selectivity. This is illustrated in Figure 53 (the figure was prepared by MTR, makers of the
Polaris™ membrane).
MTR Postcombustion CO2 Membrane
MTR has been funded by NETL to develop and test membrane-based capture of CO2 from
postcombustion flue gas. The work is based on modifications to the membranes and process
flows used in their commercial Polaris™ natural gas treatment membrane systems. MTR is also
developing CO2-selective membranes for use in H2 production applications (Ng and others,
2010).
Figure 54 is the process flow diagram for MTR’s system for membrane-based CO2
removal from flue gas. In this process, countercurrent sweep with combustion air provides a
“free” driving force. A CO2 capture efficiency of 90% can be achieved using about 15% of the
plant energy (Merkel and others, 2009). The membrane is a thin-film composite Pebax®
membrane made of polyether–polyamide copolymers (U.S. Department of Energy National
Energy Technology Laboratory, 2010c). The flat-sheet membranes are packaged into spiral Figure 53. CO2/N2 selectivity versus CO2 permeance plot comparing membrane performance
(taken from Merkel and others, 2010).
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Figure 54. MTR’s process design for flue gas CO2 capture (taken from Merkel and others, 2009).
wound modules. Figure 55 shows MTR’s packing design for the membrane modules. These
modules have been scaled up to full commercial size. A pilot demonstration project of MTR’s
system has been initiated at Arizona Public Service’s Cholla coal-fired power plant near
Phoenix, Arizona. The project was scheduled for start-up in late 2009 at a scale of 250,000 scfd
of flue gas, which should capture approximately 1 ton CO2/day (Merkel and others, 2009). The
project will be expanded to a scale of 20 tons CO2/day (equivalent to the CO2 generated by
1 MW of power generation) using funds from the DOE and project partners that include MTR,
EPRI, Southern Company, and Babcock & Wilcox (Membrane Technology Research, Inc.,
2010).
Figure 55. Packing design of the MTR membrane modules (taken from Merkel and others,
2009).
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Molecular Gate Membrane
Research Institute of Innovative Technology for the Earth (RITE) has developed composite
polymer membranes containing a layer that is highly selective for CO2. RITE calls these
molecular gate membranes (Research Institute of Innovative Technology for Earth, 2010a). The
membranes are highly permeable to CO2 but have low permeability for N2 and H2, so they are
potentially useful for both postcombustion and precombustion separations. The membrane
component that provides for the high selectivity for CO2 over both N2 and H2 is a branched
polymer containing multiple amine groups referred to as a modified poly (amidoamine), or
PAMAM, dendrimer. Because the PAMAM is actually a viscous liquid, the membrane could be
considered a supported liquid membrane. However, since the PAMAM is stabilized in a thin,
stable-polymer layer deposited on the surface of a support membrane, its structure and activity
are better described as a composite polymer membrane.
RITE has also produced small-scale (1-m-long, 1-in.-diameter) “commercial-sized”
modules of PAMAM dendrimer composite membrane. These have been tested at NETL for flue
gas separation and were found to be durable for more than 1000 hr of testing using real
combustion flue gas (Kazama and others, 2006). RITE is currently focused on improving both
the methods of making the membranes and their performance for CO2/H2 applications (Research
Institute of Innovative Technology for Earth, 2010b).
Gelled Ionic Liquid Membranes
A research group at the University of Colorado at Boulder with considerable experience in
developing membrane-based separations and working with ionic liquids received ARPA-E
funding to develop novel gelled ionic liquid membranes. The goal is to produce an extremely
thin membrane that is highly selective for CO2 and exhibits a very high CO2 permeance. The
research group recently published a paper on the development of a polymer membrane formed
through polymerization of ionic liquid imidazolium compounds, effectively making a true
polymer membrane with ionic liquid characteristics (Carlisle and others, 2010).
RTI International –PVDF-Based Polymers
RTI International, with funding from NETL and project partnership that includes Arkema,
Arcadis G&M, Generon IGS, and EPA, is developing a postcombustion capture membrane that
is made from PVDF (Toy and others, 2009; Toy and Figueroa, 2010). The project includes
testing of membrane modules made from Generon’s standard polycarbonate hollow fibers,
development of new fluorocarbon-based membranes by Arkema, assembly of a test skid for use
in 300-hr field testing on coal-fired flue gas, and modeling and economic analysis. The new
fluorocarbon-based membranes are expected to be resistant to acids and oxidants, be highly
permeable to CO2, and exhibit long-term durability as well as high thermal stability.
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Cryogenic Cooling
Cooling a mixed gas at a pressure of 1 atm to a temperature below the sublimation
temperature of CO2 (i.e., −78.5°C or −109°F) will desublimate CO2 from the gas phase by
forming “dry ice,” which is solid CO2. The gas being treated must be free of water vapor prior to
cryogenic cooling. Cryogenic cooling can be applied to previously purified CO2 and in
processing oxycombustion and/or chemical looping flue gas, but the focus here is on cryogenic
technologies that may find use in the purification step of carbon capture. Three companies are
working in this area: Sustainable Energy Solutions, which is marketing a postcombustion
cryogenic CO2 capture system, and Cool Energy Ltd. and ExxonMobil, which have each
developed cryogenic CO2 capture systems for natural gas that may also prove useful in
precombustion capture.
Cryogenic Carbon Capture System
Sustainable Energy Solutions’ cryogenic carbon capture (CCC) system is a
postcombustion process designed for retrofit applications. The process is said to be costeffective; to require minimal changes to the existing plant; not to require additional pollution
control devices upstream because it is advertised to also remove NOx, SO2, HCl, and Hg; to
increase turbine efficiency because the turbine outlet steam temperature is lower; and to offer the
potential for cooling water savings (Sustainable Energy Solutions, 2010a).
Figure 56 illustrates the CCC process. The flue gas is dried and cooled in a condensing
heat exchanger before moderate compression. The compression and cooling steps leave the flue
gas at a temperature slightly above the point where CO2 forms a solid (desublimation occurs at a
Figure 56. Flow diagram for the CCC process (taken from Sustainable Energy Solutions, 2010b).
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temperature of −100° to −135°C, depending on pressure). Solid CO2 is formed after an
expansion step where a decrease in flue gas pressure causes a drop in temperature. The solid CO2
is separated from the remaining N2, and both the CO2 and N2 are used to cool incoming gases in
a recuperative heat exchanger. This step also converts the remaining solid CO2 back to a liquid at
a final pressure of 100–200 atm (Sustainable Energy Solutions, 2010b). An intermediate step that
removes NOx, SO2, HCl, and Hg is not described.
A paper by Burt and others (2009) provides greater detail on the process and focuses on an
economic comparison between the CCC process and oxycombustion. The paper presents
estimated levelized costs for electricity and cost per avoided ton of CO2 for the CCC process
based on coal-fired power plant flue gas containing 14% CO2. The authors show CCC as being
between 30% and 45% cheaper than any competing technology, including postcombustion
capture with MEA, oxycombustion based on ASU or ITM, as well as IGCC with precombustion
capture. The calculated cost was $33 per ton of avoided CO2 for CCC versus the average cost of
the other four technologies of $57 per ton of avoided CO2.
The Clean Coal Technology Fund at the University of Wyoming has provided funding
($1,405,750) to Sustainable Energy Solutions to “investigate a new design for a fully integrated
bench-scale cryogenic carbon capture unit” (University of Wyoming, 2009).
Controlled Freeze Zone (CFZ) Cryogenic CO2 Separation Process
ExxonMobil developed the CFZ cryogenic CO2 separation process for capture of CO2 from
natural gas (Gault, 2008). The process is a single-step cryogenic separation that simultaneously
removes H2S and CO2 from natural gas and produces pipeline-quality natural gas and a liquefied
mixed-acid gas that can be used for enhanced oil or natural gas recovery and geologic carbon
storage (Northrop and Valencia, 2009). Figure 57 illustrates the process. ExxonMobil has
contracted URS to build a commercial-scale CFZ demonstration plant at the ExxonMobil
Upstream Research Company Shute Creek Treating Facility near LaBarge, Wyoming
(ExxonMobil, 2008). The latest news indicated that construction would be completed and
operations initiated in late 2009 (Powerplantccs.com, 2010).
Mineralization
Mineralization is the formation of a carbonate or bicarbonate solid from CO2. This type of
process leaves the carbon in the same oxidation state as the carbon in CO2, i.e., fully oxidized.
The processes described here do not regenerate CO2 from these solids but, instead, dispose of
them or supply them as a product for beneficial reuse. The offerings reviewed in this document
are those that combine the capture of CO2 with the formation of the mineral solid.
To capture CO2 by mineralization, there must be a source of cations that will form a stable
mineral carbonate or bicarbonate (carbonate preferred) as well as sufficient alkalinity to
neutralize the acidity of dissolved and hydrated CO2 (i.e., carbonic acid). The preferred cations
are calcium, magnesium, and sodium (both CaCO3 and MgCO3 have very low solubilities;
sodium is included because high-sodium-concentration brines [saline water] are widely
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Figure 57. ExxonMobil CFZ technology (taken from Gault, 2008).
available). The cations could be mined, pumped from a well or water body, or found in a waste
product. The alkalinity could be mined, found in a waste product, or produced. Processes based
on each of these methods have been proposed, tested, studied, and some are even being marketed
or readied for market. The key is that, in order to capture the CO2 permanently as a mineral for
disposal or use as a CO2 mineral-based product, the process must have an input of material and
alkalinity (or the production of alkalinity). If the material is readily available and of little or no
value or, better yet, is a waste that requires disposal and/or the product is of sufficient value, it
may make sense to use the process. In general, it is expected that these processes will find use in
niche markets. Entities that are marketing or conducting research in the area of mineralizationbased CO2 capture include Alcoa, the University of Wyoming, Columbia University, Calera,
Skyonic, and New Sky Energy.
Alcoa – CO2 Capture Process with Bauxite Waste
Alcoa developed a CO2 capture and bauxite waste disposal process that involves
mineralization and disposal of CO2 as a carbonate solid. The process, which is shown in
Figure 58, was developed at Alcoa’s Kwinana, Australia, facility (Alcoa, 2007). The bauxite
waste is a high-magnesium-content alkaline waste. The waste is contacted with flue gas in an
aqueous suspension, and the CO2 reacts with the hydroxide alkalinity to form bicarbonate ions
and then carbonate ions. The carbonate ions precipitate out as magnesium carbonate solids. The
neutralized waste is dried and disposed of in a landfill, as fill at the bauxite mine, or beneficially
used as road base, building materials, or as a soil amendment.
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Figure 58. Alcoa CO2 capture system (taken from Alcoa, 2007).
In a cooperative research project between NETL and Alcoa, a mixture of bauxite residue
and saline water was tested for its ability to capture CO2 (Dilmore and others, 2008). A 90:10 (by
volume) bauxite residue-to-brine mixture exhibited a CO2 sequestration capacity of greater than
9.5 g/L when exposed to pure CO2 at 20°C and 0.689 MPa. The laboratory test also suggested
that the CO2 sequestration capacity of the samples increases with aging.
Alcoa has continued to improve the process and was recently selected to receive Phase II
funding from DOE for a demonstration project (U.S. Department of Energy National Energy
Technology Laboratory, 2010g). From the information provided in the press release, it appears
that the exact process being used has changed from that shown in Figure 58 although the source
of alkalinity and the metal cations used for mineral formation remain the same.
Alkaline Fly Ash-Based CO2 Capture
Reddy and others (2010) studied the use of alkaline coal combustion fly ash to capture flue
gas CO2. The flue gas CO2 concentration was observed to decrease from 13.6% to 9.6%, and the
total carbon (as CaCO3) content of the fly ash increased from <0.02% to 3.9%. Hg and SO2
removal and mineralization were also observed. A preliminary economic analysis of the process
for 90% CO2 capture from a 532-MW power plant yielded a mineralization cost of $11/tonne
CO2 at a mineralization capacity of 207 kg CO2/tonne fly ash.
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Additional information on the project is available on the University of Wyoming Research
Products Center Web site (University of Wyoming, 2010).
Accelerated Weathering
The idea of using accelerated weathering of rocks containing high magnesium and calcium
concentrations was first popularized in the 1990s by Dr. Klaus Lackner when he was at LANL
(Lackner and others, 1995, 1998). In that work, he and his colleagues identified basaltic
ultramafic rocks as a good source, but difficulties with accelerated weathering stalled the
progress toward commercialization.
One of Dr. Lackner’s colleagues at Columbia University, Dr. Ah-Hyung Park, has worked
on the problem of accelerated weathering (Park and others, 2003). The weathered mineral
produces the calcium and magnesium as metal hydroxide, eliminating the need for added
alkalinity. The work focused on the use of chelating agents to accelerate weathering. Lackner
and Park also have funding from New York State Energy Research and Development Authority
to investigate the use of wollastonite deposits in New York state for the process (Lackner and
Park, 2010). The conceptual process can lead to minerals for disposal or beneficial use as
illustrated in Figure 59.
Calera
Additional work being done on CO2 capture through mineralization includes the work by
Calera Corporation. In their process, shown in Figures 60 and 61, the CO2 is combined with
minerals harvested from waste products including fly ash and/or brines (potentially waste brine
from seawater desalination) and alkalinity produced electrochemically (using the brines)
Figure 59. Accelerated weathering of high-magnesium-content minerals (taken from Lackner
and Park, 2010).
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Figure 60. Calera CO2 capture and mineralization process (taken from Calera Corporation,
2010b).
Figure 61. Electrochemical generation of alkalinity for the Calera CO2 capture and
mineralization process (taken from Calera Corporation, 2010a).
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(Calera Corporation, 2009). As shown in Figure 61, if the brine is sodium chloride (NaCl), the
electrochemical process produces NaOH and HCl. The NaOH could be used in the Calera
process, presumably to produce Na2CO3 as the product of CO2 capture. The gas–liquid
contacting system employed by the process is the NeuStream contactor from Neumann Systems
Group (Calera Corporation, 2009). The HCl would be sold as a product.
DOE and the Australian government are currently funding a project based on this process.
The project at Moss Landing, California, is located at a site formerly used for extracting
magnesium from seawater. Calera has been operating a CO2 pilot plant at the site of the Moss
Landing Cement Company for the last few years using flue gas from Dynegy’s Moss Landing
gas-fired power plant as the CO2 source. They have also operated a 0.3-MWth-equivalent coalfired boiler simulator (AllBusiness, 2010). In September 2009, DOE awarded a grant for
expansion of the Moss Landing facility to demonstration scale, treating a 50-MW-equivalent
slipstream from the Dynegy plant (AllBusiness, 2010).
Calera has been funded to perform a demonstration of its process on flue gas from the
lignite-fired Yallourn plant in Australia’s Latrobe Valley) (AllBusiness, 2010). This
demonstration will be at least 10-MW-equivalent in size.
C-Quest Chemical Sorbent System
The C-Quest chemical sorbent system is designed to significantly reduce CO2 emissions
from utility and industrial boilers. The sorbent ingredients are widely available, and the byproduct is a recyclable solid that can be disposed of safely. Capture rates are dependent on
several factors, including gas-to-sorbent ratios, temperatures, and retention times, although CO2
capture rates as high as 90% were obtained during laboratory testing at the EERC. The sorbent
captures other pollutants as well. In the laboratory, capture rates as high as 99% SO2, 90%
mercury, and 15% NOx were observed concurrently with the CO2 capture. Further testing is
being performed to determine capture efficiencies and other information required to determine an
ultimate cost per ton of CO2 captured. Current results are promising (Pavlish and others, 2008).
SkyMine® Process
Skyonic Corporation has developed the SkyMine process, a technology that uses brine as a
source of mineral ions for precipitation of solid carbonates and bicarbonates. Electrolysis is used
to produce hydroxide alkalinity for the formation of the carbonates and bicarbonates upon
absorption of CO2. The CO2 ends up as solid NaHCO3. Skyonic also claims that the process
removes SOx, NO2, and mercury (Skyonic, 2010). Skyonic has reported that it is conducting its
first commercial-scale pilot project at the Capitol Aggregates, Ltd., cement plant in San Antonio,
Texas (Yahoo Finance, 2010). Construction of this facility began in April 2010 (San Antonio
Business Journal, 2010).
New Sky Energy
New Sky Energy (NSE) is a Colorado-based company that is also working on a CO2
mineralization process based on electrochemical processing of brine and conversion of CO2 to
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Na2CO3. NSE claims that the process can trap 1.1 tons of CO2 per ton of NaOH and that it
produces materials that can be used in the manufacture of plastics, glass, and other goods (Jaffe,
2010). According to an NSE patent application (Little and others, 2008), the system is designed
to produce hydrogen, oxygen, base, and acid using electrochemical processes fed with power that
can be derived from a renewable energy source (most likely solar and/or wind power). The
company also has submitted a patent application that reveals a direct solar-to-water hydrolysis
process that would eliminate the need for photovoltaic solar- or wind-generated electricity.
In January 2010, NSE and CSM announced that NSE would fund a project at CSM to build
a fully operating, scalable model of the New Sky electrochemical carbon capture technology
(Colorado School of Mines, 2010).
Cemtrex – Carbondox Process
Cemtrex is developing a mineralization-based CO2 capture process called the Carbondox
process. The process captures CO2 from coal-fired flue gas using a corona catalyst and operates
via bicarbonate mechanisms in an aqueous medium. The process would be installed after the
FGD equipment at a pc power plant (Cemtrex, 2010).
Reduction
Reduction is the chemical transformation of the oxidized carbon to a reduced state through
the input of energy during the application of chemical, photochemical, electrochemical, and/or
biological processes. This concept incorporates the CO2 into an organic compound such as a
polycarbonate plastic, a fuel, or some other desired product. All of these processes require
energy to form at least one carbon–carbon or carbon–hydrogen bond. When a fuel made from
reduced CO2 is used to provide the energy for the reduction process, more energy is required to
make the fuel or other product than is present in the product. Therefore, the process makes sense
from an energy balance perspective only when the reduced carbon product is of high value, the
fuel is effectively an energy storage product made from an intermittent energy supply source
(e.g., wind, solar), and/or the fuel produced is useful in ways that the original source fuel was not
(e.g., production of a transportation fuel from coal-derived CO2).
Photosynthesis
Closed-Environment Agriculture
It is not uncommon for large greenhouse operations to use bottled CO2 or CO2 produced
from the combustion of propane or natural gas to supplement the CO2 available in ambient air
during intensive greenhouse production of food crops and flowers (Blom and others 2002).
WarmCO2, a company in Terneuzen, the Netherlands, provides industrial waste heat, anhydrous
ammonia, and CO2 from a fertilizer production facility to a 250-ha greenhouse horticultural
complex (Warm CO2, 2010; Rijckaert, 2009). Other flue gas CO2-to-closed environment
agriculture examples likely exist, but a thorough review of this area was beyond the scope of this
report.
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Algae and Microalgae
Capture of CO2 from combustion flue gas for direct use in algae production has been
widely investigated and has been applied commercially. The processes that show the most
promise are open-raceway algal ponds. Several projects attempted with photobioreactors have
failed based on economic analysis because of the cost of the reactor systems (Benneman,
2008a,b). For open raceways, the two choices for capture are direct sparging of the flue gas
through the water in the algal growth pond or raceway and use of an absorption tower. The
former requires a huge distribution system for the flue gas and would be expected to provide low
capture rates. The second requires transport of the growth medium and growth of the algae in
relatively high-alkalinity waters in order to ensure sufficient absorption capacity.
DOE funded an algae biofuels program through the National Renewable Energy
Laboratory from 1978 through 1996. The closeout report contains the lessons learned during that
program, including issues related to growth of algae using CO2 captured from flue gas (Sheehan
and others, 1998).
Other companies that are evaluating the capture of CO2 using algae are discussed in the
following text. It should be noted that this is a limited review of the many (mostly small start-up)
companies that hope to capitalize on interest in the use of algae for CO2 capture and the
production of biofuel, omega-3-rich oils, or other products.
Cyanotech Corporation
Cyanotech Corporation operates a 2-MWe combined-heat-and-power fuel oil/diesel
generator system with a flue gas scrubber for CO2 capture. The growth medium used for growing
a type of algae called spirulina is contacted with 8% CO2 flue gas (equaling 188 kg/hr CO2) in an
absorption tower. The company reports a CO2 capture efficiency of 75% and a capture rate of
67 tons/month of CO2. This is used to grow approximately 36 tons/month of spirulina in an
estimated 12 ha of algal ponds (Pedroni and others, 2001). The spirulina is marketed as a food
and a nutritional supplement (Cyanotech, 2010).
Seambiotic
Seambiotic has been developing a process for cultivating algae using flue gas from coalfired power stations. The algae captures the CO2 from the flue gas and will be used to produce
omega-3 fatty acid and biofuels products (Seambiotic, 2010). The company currently operates a
1000-m2 pilot-scale system at a power plant in Ashkelon, Israel (EcoSeed, 2010), and is in the
process of scaling up to large-scale industrial algae cultivation and production.
Pond Biofuels
Pond Biofuels has built an algae production facility using raw cement production
emissions as algae feedstock. The system is said to be a cost-effective method for scrubbing CO2
(Pond Biofuels, 2010). It is planned that the algae will be dried using waste heat from the cement
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plant and burned as fuel in the cement kilns. Alternatively, the algae could be processed into fuel
for the cement company’s fleet of trucks (Hamilton, 2010).
Other Biofuels-from-Algae Projects
On July 22, 2010, DOE announced funding for two flue gas CO2-to-algal-based-biofuel
production projects (U.S. Department of Energy National Energy Technology Laboratory,
2010g); the project descriptions are summarized in the following text.
Touchstone Research Laboratory
Touchstone Research Laboratory Ltd. will pilot-test an open-pond algae production
technology that is capable of capturing a minimum of 60% of the CO2 contained in the flue gas
from an industrial coal-fired source. The project objective is the production of biofuel and other
high-value coproducts. A novel phase change material will cover the algae pond surface to
regulate temperature, reduce evaporation, and control the infiltration of invasive species. Oils
extracted from harvested algae will be converted to biofuel. An anaerobic digestion process will
tested for the conversion of residual biomass to methane.
Phycal
Phycal will complete development of an integrated system designed for the production of
liquid biocrude from algae that has been cultivated using captured CO2. It is possible to blend the
algal biocrude with other fuels for power generation or to process it into a variety of renewable
replacement fuels such as jet fuel and biodiesel. Phycal will design, build, and operate the facility
in Hawaii.
Funded by Vattenfall
On July 23, 2010, the Swedish utility Vattenfall announced that it had launched a pilot
project to grow algae in a greenhouse environment. Vattenfall plans to investigate the economics
of using the technology to reduce CO2 emissions from coal-fired power plants (Vattenfall, 2010).
The algae will be used to produce biodiesel, biogas, and nutrient supplements for aquaculture
(fish farming).
Chemical and Biochemical Processes
Considerable effort is being made to find ways to economically use CO2 to make useful
products without requiring photosynthetic organisms or forming minerals. These efforts are
sometimes combined with the CO2 capture process rather than just using the captured CO2 as a
resource. This section of the report is not a comprehensive listing or analysis of all of the
processes under investigation but rather provides information concerning the breadth of these
efforts and direction to where the reader might find additional information.
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Production of Polymers
Numerous research groups have investigated the use of CO2 as a resource for the
manufacture of plastics and other chemical products. In fact, it is common for CO2 to serve as
resource in the manufacture of polycarbonate plastics. The first reports of CO2 incorporation into
polycarbonates using epoxides were published in the 1960s. The focus of the work listed here is
the direct use of CO2 in flue gas as the CO2 resource for polymer synthesis.
Polycarbonates are not the only chemical synthesis product that can be made from CO2.
The interested reader is referred to a recent article by Riduan and Zhang (2010) that reviews
chemical product synthesis using CO2 under “mild conditions.” In the article, the authors avoid
spending time on the “coupling of epoxides with CO2 to form cyclic carbonates or
polycarbonates because they have been well documented.” Instead, they refer to the reader to
several recent works and review articles on that topic.
One of the projects funded as part of DOE’s American Reinvestment and Recovery Act –
Industrial Sources into Useful Products Program is a CO2-to-polycarbonate plastics project (U.S.
Department of Energy National Energy Technology Laboratory, 2010g). Novomer Inc. will team
with Albemarle Corporation and the Eastman Kodak Co. to develop a process to convert waste
CO2 into a number of plastics for use in the packaging industry. Novomer has a novel catalyst
technology that reacts CO2 with petrochemical epoxides, creating a family of thermoplastic
polymers that are composed of up to 50 wt% CO2.
Generation of “ElectroFuels”
Through the ARPA-E program, DOE has provided funding for several “ElectroFuels”
projects designed to find ways to convert CO2 to liquid fuels. For the most part, these projects do
not employ organisms that normally perform photosynthesis or add the use of electricity to help
drive their metabolism. Rather, the ARPA-E objective is for projects to employ “metabolic
engineering and synthetic biological approaches for the efficient conversion of carbon dioxide to
liquid transportation fuels.” The projects which have been funded include the following:
 Columbia University – Biofuels from CO2 Using Ammonia-Oxidizing Bacteria in a
Reverse Microbial Fuel Cell
 Ginkgo BioWorks – Engineering E. Coli as an Electrofuels Chassis for Isooctane
Production
 Harvard Medical School–Wyss Institute – Engineering a Bacterial Reverse Fuel Cell
 Lawrence Berkeley National Laboratory – Development of an Integrated MicrobialElectroCatalytic System for Liquid Biofuel Production from CO2
 Massachusetts Institute of Technology – Bioprocess and Microbe Engineering for Total
Carbon Utilization in Biofuel Production
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 Massachusetts Institute of Technology – Engineering Ralstonia eutropha for Production
of Isobutanol Motor Fuel from CO2, H, O2
 Medical University of South Carolina – Electroalcoholgenesis–Bioelectrochemical
Reduction of CO2 to Butanol
 North Carolina State University – Hydrogen-Dependent Conversion of Carbon Dioxideto Liquid Electrofuels by Extremely Thermophilic Archaea
 OPX Biotechnologies, Inc. – Novel Biological Conversion of Hydrogen and Carbon
Dioxide Directly into Biodiesel
 Pennsylvania State University – Development of Rhodobacter as a Versatile Platform
for Fuels Production
 Regents of the University of California, Los Angeles – Electro-Autotrophic Synthesis of
Higher Alcohols
 The Ohio State University – Bioconversion of Carbon Dioxide to Biofuels by
Facultatively Autotrophic Hydrogen Bacteria
 University of Massachusetts Amherst – Electrofuels via Direct Electron Transfer from
Electrodes to Microbes
Descriptions of these projects can be found through the ARPA-E Web site (U.S.
Department of Energy Advanced Research Projects Agency – Energy, 2010d).
STEP Carbon Capture
Recently, researchers at George Washington University and Howard University in
Washington, D.C., published a paper on a closely related topic (Licht, and others, 2010). In their
paper, they describe experimental results from their development of a process they call STEP
(Solar Thermal Electrochemical Photo) carbon capture. The authors conclude that CO2 can be
captured at a solar energy efficiency from 34% to over 50% and that the process can be used to
produce solid carbon or CO and H2 that can be used to synthesize solar diesel fuel, synthetic jet
fuel, or other chemicals.
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EVALUATION AND DIRECT COMPARISON OF CAPTURE TECHNOLOGIES BY
THE PCO2C
The PCO2C at the EERC is a multiclient-funded program separate from the PCOR
Partnership that is focused on CO2 capture technology testing, demonstration, and development.
It is funded in part by DOE and in part by industry and utility participants. PCO2C is a multiplephase program. Phase I was recently completed, and Phase II was initiated. Phase I included the
addition of oxycombustion and postcombustion testing capabilities to an existing fuel-flexible
combustion test unit (coal, natural gas, biomass) that operates at approximately 550,000 Btu/hr
(about 60 to 100 coal feed lb/hr). This system already included an SCR unit, an ESP, a fabric
filter, wet FGD, and a spray dryer absorber as well as facilities for testing ash fouling, flame
behavior, and other aspects of concern with respect to coal combustion. Retrofit for
oxycombustion using pure O2 and recycled flue gas allowed for operation at conditions that
yielded flue gas CO2 concentrations as high as 85% and over 90% for short periods of time. The
retrofit for postcombustion capture included the addition of a solvent absorber–stripper system
for CO2 capture. Three solvents were tested in Phase I: MEA as a base case, a mixture of MDEA
and PZ, and a proprietary solvent, H3-1 from Hitachi. Engineering and economic analysis
performed based on the experimental results from the oxycombustion and postcombustion tests
revealed that the least-cost alternative in terms of both energy penalty and cost of electricity
(COE) was the use of H3-1. Phase II work will include testing of additional solvents and the
Neumann systems contactor (Neustream-C) as an alternative to the traditional column-based
absorber–stripper as well as the addition of solid sorbent testing.
SUMMARY
Considerable effort is being expended to develop a variety of cost-effective CO2 capture
technologies capable of meeting the DOE goals of 90% capture of CO2, 95% pure CO2 product,
and an increase in COE no greater than 35%. Some commercially available technologies can
meet the first two of these three goals, but even these have not yet been demonstrated for use at
full utility scale for coal-derived power generation. These commercial technologies, which have
estimated COE increases that are higher than the target, likely will be demonstrated at utility
scale in the next 3 to 5 years.
Emerging processes that have completed smaller-scale pilot tests and are in the process of
scaling up to larger demonstrations are likely to be available commercially in the next 5 to
10 years. Some of these technologies may meet the DOE goal.
Many other technologies still require extensive development, testing, and demonstration
before it will be known if they can reach DOE’s goals. The technologies that are the most similar
to existing technologies (e.g., new aqueous solution-based absorption solvents) will take much
less time to enter the market than those technologies for which there is little industrial or
commercial experience or which require significant development and scale. A few of these earlystage technologies offer the hope of being “game changers”—technologies that dramatically
reduce CO2 emissions at very low cost–although it is difficult to know how much promise they
will fulfill while they are still early in the development cycle.
94
Despite the existing effort, there is still room for all entities with an interest or expertise in
the area of CO2 capture to be involved in addressing this critical research need by offering new
concepts, improving on existing concepts, and providing advice, guidance, and crucial funding
toward further research, development, demonstration, and commercialization of CO2 capture
technologies.
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123
INDEX
Aberthaw power station, 27
absorption, 8, 9, 12, 13, 15, 16, 18, 19, 22,
24, 25, 27, 31, 32, 33, 35, 36, 37, 39, 40,
43, 44, 45, 46, 47, 49, 50, 51, 66, 74, 87,
89, 93
accelerated weathering, 62, 85
activated carbon, 8, 55, 57, 64, 70
activated hot-potassium carbonate process,
18, 22
ADA–Environmental Solutions (ADA–ES),
53, 54
adsorption, 2, 7, 8, 9, 49, 51, 52, 53, 54, 55,
56, 57, 58, 59, 62, 64, 65, 71
Advanced Technology Materials, Inc.
(ATMI), 56
advanced zero emission power (AZEP), 5
Air Products and Chemicals – Ion Transport
Membrane, 70
Air Products and Chemicals, 5, 48, 62, 70
air separation unit (ASU), 2, 3, 4, 70, 82
Aker Clean Carbon, 22, 24
Aker Process Systems, 36, 37
Akermin, Inc., 41,42
Alcoa, 83, 84
algae, 7, 89, 90
alkaline fly ash, 84
alkalized alumina adsorbent, 64
ALSTOM, 5, 6, 24, 25, 26, 27, 32
ALSTOM Advanced Amine Process (AAP),
27
ALSTOM Chilled Ammonia Process (CAP),
24, 25, 26, 27, 32
aMDEA (activated methyldiethanolamine),
10, 11, 16
American Air Liquide, 5
American Electric Power (AEP)
Mountaineer plant, 26
Northeastern station, 26
amine functionalized silica, 66
amine functionalized zeolite, 55, 64
amino acid salt, 9, 16, 34, 35, 36, 38, 43
aminosilicone, 50
ammonia, 2, 8, 9, 16, 19, 24, 26, 30, 32, 88,
91
Antelope Valley Station, 29
aqueous potassium carbonate, 22
ARCADIS, 60, 80
Arkema, 80
Babcock & Wilcox, 5, 46, 48, 64, 79
BASF, 29, 31, 63
Basin Electric Power Cooperative, 29
Benelux power plant, 38
Benfield, 2, 18, 22, 23, 33
biofuel, 89, 90, 91, 92
BP, 62
calcium oxide (CaO), 59
Calera, 83, 85, 86, 87
CanmetENERGY, 5
Cansolv, 27, 28
Carbo-Lock process, 37
Carbon Capture Technologies, Inc., 65
Carbondox Process, 88
carbon fiber composite molecular sieve
(CFCMS), 57
carbon nanotube 55, 64
carbonic anhydrase, 9, 16, 40, 41, 42, 43,
44, 45, 46, 47
Carbozyme Inc., 41, 42, 43
CASTOR project, 23
CATACARB, 2, 18, 22
catalytic membrane reactor (CMR), 71, 72,
73
CATO CO2 Catcher, 38
Cemtrex, 88
Chalmers University, 6
chemical looping, 3, 6, 7, 81
Clean Coal Power Initiative, 19
Clean Coal Technology Fund, 82
closed-environment agriculture, 88
CNRS, 58
CO2 Capture Project (CCP), 37, 62, 75
CO2 Solution, Inc., 43, 44, 45
CO2-selective ceramic membrane for WGS
reaction, 71
124
coal direct chemical-looping, 3
Codexis, 45
Colorado School of Mines, 73, 88
Columbia University, 83, 85, 91
composite membrane, 9, 48, 53, 67, 70, 76,
77, 78, 80
concentrated piperazine (PZ), 40
CONSOL Energy, Inc., 34
controlled-freeze zone (CFZ), 82, 83
Cool Energy Ltd., 81
CORAL solvent 38
C-Quest chemical sorbent system, 87
cryogenic cooling, 7, 9, 81, 82
cryogenic distillation, 3, 5, 70
Cyanotech Corporation, 89
Daewoo Shipbuilding & Marine
Engineering Co., 34
Dakota Gasification Company, 14
Dalian Institute of Chemical Physics
(DICP), 76
DEA (diethanolamine), 9, 16
dense metal alloy membrane, 71, 72, 74, 77
DGA (diglycolamine), 16, 17
diisopropanolamine (DIPA), 11, 15
dimethyl carbonate (DMC), 11, 15
dimethyl ethers of polyethylene glycol, 9,
10, 11
Doosan Babcock, 29
Doosan Heavy Industries, 29
Dow, 11, 19, 27
dry carbonate process, 61
dry regenerable sorbent, 60
DTE Energy, 48
DuPont, 47
E.ON, 19, 34, 35, 38
Econamine FG, 18, 19
Econamine FG Plus, 18, 19, 20
Eickmeyer & Associates, 18, 22
Eindhoven University in the Netherlands, 47
Electric Power Research Institute (EPRI),
26, 60, 79
electrical swing adsorption (ESA), 51, 54,
57, 58
ElectroFuels, 91, 92
Eltron Research and Development (ERT), 5,
71, 72, 73, 74
Energy & Environmental Research Center
(EERC), 5, 39, 87, 93
Energy Research Centre of the Netherlands
(ECN), 62, 76
Environmental Energy Technology, Inc.
(EET), 33
EPA, 60, 61, 80
EPA multipollutant control research facility
(MPCRF), 61
European CACHET project, 62, 76
European CO2 Technology Centre, 23
Exxon Flexsorb® HP process, 18, 22
ExxonMobil, 81, 82, 83
controlled freeze zone (CFZ) cryogenic CO2
separation process, 82, 83
fixed-bed adsorber, 52, 53, 63, 65
fluidized-bed adsorber, 52, 53
Fluor, 9, 11, 14, 18, 19, 20, 28
Fluor solvent, 9, 11, 14
Fortum Meri-Pori Demonstration Plant, 35
Foster Wheeler North America, 5
Gas Technology Institute (GTI), 37, 62
gasification, 1, 2, 3, 4, 9, 10, 14, 59, 62, 66,
69, 70, 71, 76, 77
gas-permeable membrane, 66
GE Energy, 49, 50
GE Global Research, 49, 50
gelled ionic liquid membrane, 80
Generon IGS, 80
Genosorb, 10, 11
George Washington University, 92
Georgia Institute of Technology, 49, 65
Giammarco-Vetrocoke’s process, 18, 22
Great Plains Synfuels Plant, 3, 14
Green House Gas Technology Centre, 29
greenhouse horticultural, 88
125
high-capacity oligomers for CO2 capture, 50
high-temperature membrane reactor, 71
hollow-fiber membrane, 36, 37, 41, 49, 67
hot carbonate, 15, 16
Howard University, 92
HTC Purenergy Inc, 29, 30
Huntsman Chemicals, 11, 14, 15
hybrid adsorption membrane reactor
(HAMR), 71
hydrogen membrane reactor, 76
hydrogen membrane reformer (HMR), 74,
75
hydrogen-permeable membrane, 3, 76
hydrogen-selective membrane, 74
hydrotalcite, 62, 71
hyperbranched aminosilica, 65
Idaho National Energy and Engineering
Laboratory (INEEL), 76
Ifpexol, 13
IGCC, 1, 2, 6, 9, 10, 62, 82
Illinois Institute of Technology, 62
Illinois State Geological Survey (ISGS), 45
imidazolium, 48, 80
Industrial Technology Research Institute, 64
ORNL Inorganic Membrane Technology
Laboratory, 76
inorganic nanoporous membrane, 76
integrated vacuum carbonate absorption
process (IVCAP), 45, 46
ION Engineering, LLC, 47, 48
ion transport membrane (ITM), 5, 70, 82
ionic liquid, 9, 16, 46, 47, 48, 49, 50, 59, 64,
66, 80
JEFFSOL®-PC, 9, 11, 14, 15
JustCatchTM technology, 23
Kansi Mitsubishi Carbon Dioxide Recovery
(KM CDR) Process, 18, 21
Kerr-McGee/ABB Lummus Crest process,
19
KHMAS, 36, 37, 38
Korean Institute of Energy Research, 6
KS-1, 18, 21, 37
Lawrence Livermore National Laboratory
(LLNL), 46, 47
Linde, 2, 10, 13, 14, 29, 52
liquid membrane, 36, 39, 41, 42, 48, 67, 80
Los Alamos National Laboratory (LANL),
76, 85
Louisiana State University, 64
Luminant Carbon Management Program, 40
Luminant Martin Lake Station, 54
Lummus, 18, 19, 20
Lurgi, 2, 10, 11, 13, 14
magnesium (Mg), 3, 59, 62, 82, 83, 85, 87
MDEA (methyldiethanolamine), 2, 9, 10,
11, 16, 40, 43, 93
MEA (monoethanolamine), 9, 10, 16, 18,
19, 25, 37, 38, 40, 43, 46, 48, 53, 64, 82,
93
Media and Process Technology, Inc., 71
membrane 66, 69, 70, 71, 76, 77, 80
membrane contactor, 36, 37, 39
membrane module, 36, 67, 69, 77, 79, 80
Membrane Technology & Research, Inc.
(MTR), 78, 79
Merck/EMD Chemicals, 48
mesoporous silicate, 65
metal hydroxide, 9, 51, 59
metal organic framework (MOF), 55, 62, 63,
64
metal oxide, 51, 59
methanol (Rectisol), 2, 9, 10, 11, 12, 13, 14,
15, 59
MgO (magnesium hydroxide), 58, 59, 61, 62
mineralization, 7, 9, 16, 82, 83, 84, 85, 86,
87, 88
Mitsubishi Heavy Industries (MHI) – KM
CDR Process, 18, 21
Mitsui Babcock, 5
mixed conducting membrane (MCM)
reactor, 5, 74
molecular gate membrane, 80
Morphysorb®, 9, 11, 15
moving-bed adsorber–regenerator, 53, 57
126
moving-bed adsorption, 53
MTR postcombustion CO2 membrane, 78
N-acetylmorpholine (NAM), 11, 15
National Chiao Tung University, 64
National Chung Hsing University, 64
National Technical University of Athens
(NTUA), 76
NETL, 37, 53, 59, 60, 64, 65, 70, 71, 73, 78,
80, 84
Neumann Systems Group (NSG), 39, 87
NeuStreamTM–C, 39, 93
NeuStreamTM–S, 39
New Sky Energy, 83, 87
Nexant, 60
N-formylmorpholine (NFM), 11, 15
N-methyl-2-pyrrolidone, 9, 10
Northwestern University, 63
novel amine-enriched solid sorbent, 64
Novozymes, 46
NRG Energy, 19
Oak Ridge National Laboratory (ORNL),
49, 58, 76
oxycombustion, 1, 3, 4, 5, 66, 70, 81, 82, 93
oxygen firing, 5
oxygen transport membrane, 4, 71
oxygen-permeable membrane, 3, 70
oxygen-selective polymer membrane, 70
Pacific Northwest National Laboratory
(PNNL), 59, 64, 66
Pall Corporation, 76
palladium-based membrane reactor, 73
palladium–copper alloy membrane reactor,
73
PAMAM, 80
Parsons Energy, 5
Partnership for CO2 Capture (PCO2C), 39,
93
perfluorinated solvent, 11
perfluoro-perhydro-benzyltetralin, 15
phase change, 48, 90
phase-changing absorbent, 50, 51
photosynthesis, 88, 91
piperazine, 40
Polaris, 78
poly(ionic liquid), 48, 49
polycarbonate, 91
polymer membrane, 67, 70, 76, 80
polymeric amine, 65
Pond Biofuels, 89
PoroGen Carbo-Lock™ process, 37
POSTCAP™, 34, 36
potassium carbonate, 2, 18, 22, 33, 40, 43,
45
Powerspan, 28, 30, 32, 33
Powerspan ammonia-based ECO2TM
Process, 30
Powerspan proprietary solvent-based ECO2
Process, 32, 33
Powerspan ECO process, 32
PP25 solvent, 15
Praxair, 5, 77
pressure swing, 49, 51, 55
pressure swing adsorption (PSA), 2, 51, 52,
53, 54, 63, 70
Process Design Center (PDC), 76
production of polymer, 91
propylene carbonate, 9, 11, 15
Prosernat IFP Group Technologies, 6, 13
PSA, 2, 51, 52, 53, 54, 63, 70
Purisol, 2, 9, 10, 13, 14
PVDF, 80
PZ (piperazine), 40, 93
Rectisol, 2, 9, 10, 11, 13, 14, 15, 59
recyclable CO2 adsorbent, 65
reduction, 7, 9, 88, 92
regenerable magnesium oxide-based
adsorbent, 62
Research Council of Norway, 75
Research Institute of Innovative Technology
for Earth (RITE), 80
reversible ionic liquid, 49, 50
room-temperature ionic liquid (RTIL), 46,
47, 48, 49
RTI International, 60, 80
127
RWE Power, 27, 30
Sargas carbonate process, 33, 34
SaskPower, 28
Seambiotic, 89
selectivity, 36, 56, 70, 74, 76, 77, 78, 80
Selexol, 2, 9, 10, 11, 12, 13
Shell Oil Company, 76
Shell Sulfinol, 11, 15
Siemens, 34, 35, 36, 38, 77
Siemens POSTCAP™ process, 34, 35, 36
silicon/alumina gel, 58
SINTEF, 76
SkyMine® process, 87
Skyonic, 83, 87
Skyonic Corporation, 87
small-molecule catalyst, 46, 47
Solar Thermal Electrochemical Photo
(STEP) carbon capture, 92
solid sodium bicarbonate, 60
solid sodium carbonate, 60
SOLVit, 17, 23
sorption-enhanced water–gas shift
(SEWGS) process, 62
South Korea Hydrogen Energy R&D Center,
63
South Korea Ministry of Education, 63
Southern Company and Alabama Power
E.C. Gaston Station, 54
SRI International, 56, 57
stabilized calcium oxide adsorbent, 59
StatoilHydro, 74
steam methane reforming, 3
STEP carbon capture, 92
sterically hindered amine KS-1, 21
Sud-Chemie, Inc., 60, 61
surface-modified expanded mesoporous
silica, 65
Sustainable Energy Solutions, 81, 82
synthetic organometallic chemical, 46
TDA dry solid sorbent, 64
TDA Research, 64
TECO Energy Big Bend Station, 36
temperature swing, 51, 53, 55, 58, 64
temperature swing adsorption (TSA), 51
tertiary amine, 11, 64
tetrahydrothiophene-1,1-dioxide, 11, 15
ThermoEnergy Corporation, 6
ThermoEnergy Integrated Power System
(TIPS) process, 6
TNO, 36, 38
Netherlands Organization for Applied
Scientific Research, 36
triethanolamine (TEA), 16
Trimetric, 48
TSA, 51, 52, 54, 58
U.S. Environmental Protection Agency
(EPA), 60, 61, 80
UCARSOL™ LE Solvent 703, 11
UCARSOL FGC Solvent 3000, 27
Uhde GmbH, 10, 11, 15
ultramafic rock, 62, 85
United Technologies Research Center, 77
University of Akron, 65
University of California Los Angeles, 63, 92
University of Colorado, 47, 48, 80
University of Edinburgh, 63
University of Illinois, 46
University of Kentucky, 39
University of Michigan, 63
University of Notre Dame, 48
University of Ottawa, 65
University of Pittsburgh, 50, 64
University of Porto, Portugal, 58
University of Queensland, 58
University of Regina, 29
University of Southern California, 71
University of Texas, 40
University of Wyoming, 48, 49, 82, 83, 85
UOP, 2, 10, 11, 13, 18, 22, 23, 63
URS (Group), 40, 82
vacuum swing adsorption (VSA), 51
Vanderbilt University, 63
Vienna University of Technology, 6
VPSA, 51, 63
128
W.A. Parish, 19
WarmCO2, 88
We Energies’ Pleasant Prairie plant, 26
Western Research Institute, 64, 77
WGS, 1, 3, 51, 62, 71, 73, 74
wollastonite, 85
WorleyParsons, 33
Xcel Energy, 54
ZSM-5, 55
zeolite, 53, 54, 55, 57, 58, 63, 64, 65, 66, 67,
70
zeolitic imidazolate framework (ZIF), 55, 64
APPENDIX A
CO2 CAPTURE TECHNOLOGIES
A-1
CO2 CAPTURE TECHNOLOGIES
This information is provided as a way to quickly compare the technologies described in the
body of the report. For each technology, the reader is provided with the technology name, the
developer, the status of development (laboratory research, small- or large-scale demonstration,
commercially available), and basic information on the process.
The information is organized into three sections, one for each capture platform:
precombustion, during combustion, and post combustion. It is important to note that this
organization scheme differs from that of the body of the report and was done to aid the reader
in comparing technologies within the platform(s) of interest to them. Some technologies are
applicable to more than one capture platform and, therefore, are listed in the table more than
once. In general, the information provides relatively little technical detail and no references to
literature. The reader is urged to consult the body of the report to find greater detail on a given
technology, citations to literature resources, and for background information concerning the
general technical approaches used for CO2 capture.
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CHEMICAL(S)
NOTES
PRECOMBUSTION
High partial pressures of CO2 are more favorable for use of physical solvent absorption and pressure swing adsorption using physical
adsorbents.
Physical Solvent-Based Absorption Processes
Selexol™
UOP LLC Physical solvent
absorption
Commercial
for gas
processing
Mixture of dimethyl
ethers of polyethylene
glycol
Double-stage Selexol
process removes both
H2S and CO2 from
high-pressure gas
streams. It is capable
of providing purified
CO2.
Rectisol® Linde/Lurgi Physical solvent
absorption
Commercial
for gas
processing; in
active use at
the Great
Plains
Synfuels Plant
Methanol Very low temperatures
are needed. This is
used for CO2 capture
from syngas at the
Great Plains Synfuels
Plant. The purified
CO2 is then
compressed and
shipped by pipeline to
Canada for enhanced
oil recovery.
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STATUS
CHEMICAL(S)
NOTES
Purisol® Lurgi Physical solvent
absorption
Commercial
for gas
processing
N-methyl-2pyrrolidone
Purisol process is
virtually identical to
Rectisol. Applied to
the gas produced from
partial oxidation of
heavy oils or coal
gasification, primarily
for sulfur recovery.
JEFFSOL®–PC
(Fluor solvent
process)
Huntsman
Chemicals
Physical solvent
absorption
Commercial
for gas
processing
Propylene carbonate
Application is lowH2S syngas.
Morphysorb Uhde GmbH Physical solvent
absorption
Commercial
for gas
processing
N-formyl-morpholine
(NFM) and N-acetylmorpholine (NAM)
Similar to the Selexol
process.
Ionic Liquids Various Physical solvent
absorption
Research –
laboratory
scale
Physical solvent ionic
liquids
Mixture of Chemical and Physical Solvents
Sulfinol® Shell Absorption process
using a mixture of a
physical solvent and
a chemical solvent
Commercial
for gas
processing
Sulfolane – physical
solvent; DIPA
(diisopropanolamine)
chemical solvent
Typically used for gas
with a H2S-to-CO2
ratio greater than 1:1
or where it is not
necessary to remove
the CO2 to the same
levels as is required
for H2S removal.
   
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CHEMICAL(S)
NOTES
Chemical Solvent-Based Absorption Processes
Hot Potassium Carbonate-Based Processes
Inorganic and organic catalysts are commonly used with metal carbonate processes, because without them, slow reaction kinetics limit
performance. Pressure of feed gas is 150 to 300 psi so not typically applicable to postcombustion.
CATACARB® Eickmeyer & Associates Chemical solvent
absorption
Commercial
for gas
processing
(ammonia
plants,
natural gas,
ethylene
oxide)
Hot potassium
carbonate with
catalyst
Applicable for
CO2 partial
pressures above
a minimum of
210 to 345 kPa
(30.5 to 50 psi)
with an
optimum of 700
kPa (101.5 psi).
Benfield™ UOP LLC Chemical solvent
absorption
Commercial
for gas
processing
(ammonia
plants,
natural gas,
ethylene
oxide)
Hot potassium
carbonate with
catalyst
Applicable for
CO2 partial
pressures above
a minimum of
210 to 345 kPa
(30.5 to 50 psi)
with an
optimum of 700
kPa (101.5 psi).
Flexsorb® HP Exxon Chemical solvent
absorption
Commercial
for gas
processing
(ammonia
plants,
natural gas,
ethylene
oxide)
Hot potassium
carbonate with
hindered amine
activator
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CHEMICAL(S)
NOTES
Other Giammarco-Vetrocoke Chemical solvent
absorption
Commercial
for gas
processing
(ammonia
plants,
natural gas,
ethylene
oxide)
Hot potassium
carbonate with
organic activator
Amine-Based Processes
Chemical solvents (typically amines) can be used for precombustion separations but they tend to be preferable to the physical solvents
only under lower-CO2–partial-pressure conditions.
MEA Various Chemical solvent
absorption
Commercial
for gas
processing
Monoethanolamine
(MEA) (primary
amine)
MEA is used
for removal of
H2S and CO2
from natural gas
and syngas, but
it is not
anticipated to
be an important
solvent for use
in precombustion
CCS
applications. It
is probably the
most popular
chemical
solvent used for
H2S removal.
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STATUS
CHEMICAL(S)
NOTES
MDEA Various Chemical solvent
absorption
Commercial
for gas
processing
Methyldiethanolamine
(MDEA) (secondary
amine)
MDEA is
probably the
most popular
amine used in
gas processing
for CO2
removal. Often
a catalyst is
added to
increase the rate
of CO2
absorption.
aMDEA®
BASF Chemical solvent
absorption with
catalyst
Commercial
for gas
processing
Methyldiethanolamine
(MDEA) (secondary
amine) with catalyst
(activator)
Registered
process
employing
activated
MDEA.
Physical Adsorption
Pressure-Swing Adsorption
Pressure swing adsorption is commonly used for oxygen purification but is typically more expensive at large scale than cryogenic
distillation. Pressure swing adsorption can also be used for CO2 removal from syngas and natural gas.
Zeolite Various Physical adsorption Commercial
for gas
processing
Activated Carbon Various Physical adsorption Research –
laboratory
scale
Carbon Nanotubes Various Physical adsorption Research –
laboratory
scale
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NOTES
Carbon-Based Sorbent Advanced Technology
Materials and SRI
International
Physical adsorption Research –
laboratory
scale
The groups are
working
together on a
novel carbonbased sorbent
for CO2
adsorption.
Electrical Swing
Adsorption
Oak Ridge National
Laboratory;
University of Porto,
Portugal;
Centre National de la
Recherche Scientifique,
Nancy, France; University of
Queensland, Australia
Physical adsorption Research –
laboratory
scale
Carbon fiber
composite
molecular
sieves most
commonly
serve as the
solid sorbent
and/or solid
sorbent support.
A low-voltage
current is used
to remove the
adsorbed CO2
by resistive
heating of the
sorbent.
   
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CHEMICAL(S)
NOTES
Chemical Adsorption
Chemical-Looping
Combustion
ALSTOM, Korean Institute
of Energy Research, Vienna
University of Technology,
Chalmers University
Chemical adsorption Research to
small pilot
scale.
Largest
system run
to date is
65-kWth
with a
3-MWth
system
planned.
Metal oxides used as
oxygen adsorbents
Process uses O2
provided by
metal oxide
carriers to
combust the
fuel, producing
CO2 and water.
Condensation
of the steam
produces a
relatively pure
stream of CO2.
Magnesium
Hydroxide-Containing
Sorbents
National Energy Technology
Laboratory
Chemical adsorption Research –
modeling
Magnesium hydroxide
(MgOH)
Investigating
the use of
magnesium
hydroxidecontaining
sorbents for
precombustion
CO2 capture.
These sorbents
show good
potential for use
at high pressure
and high
temperature.
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STATUS
CHEMICAL(S)
NOTES
Magnesium Oxide Illinois Institute of
Technology and the Gas
Technology Institute
Chemical adsorption Research –
laboratory
scale
Magnesium oxide
(MgO)
The magnesium
oxide
regenerable
adsorption
process
removes CO2
from raw
syngas at the
temperatures
and pressures
typically
encountered in
gasification.
Calcium Oxide-Based
Adsorbents
Pacific Northwest National
Laboratory
Chemical adsorption Research –
laboratory
scale
Calcium-oxide-based
materials (CaO)
This work has
been performed
with calcium
oxide-based
adsorbents at
elevated
temperatures.
Sorption-Enhanced
Water–Gas Shift
Reaction
Air Products and Chemicals,
BP,
Energy Research Centre of
the Netherlands
Chemical adsorption Large
laboratory
scale/small
pilot scale,
with largescale pilot
planned for
the near
future
Hydrotalcite, a
naturally occurring
aluminum magnesium
carbonate hydroxide
hydrate.
CO2-selective
hydrotalcite
adsorbent is
combined with
a water–gas
shift catalyst
and applied to
syngas
production
during natural
gas reforming.
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CHEMICAL(S)
NOTES
Membranes
Oxygen-Permeable Membranes
Ion Transport
Membrane
Air Products and Chemicals Membrane 5-ton
oxygen/day
pilot plant has
in operation
since 2006.
Currently
working on
150-ton/day
pilot. Scale to
800-ton/day
smallcommercial
unit planned for
2011 and 2000ton/day by
2013.
Inorganic membrane This is an
oxygen
purification
system used for
air separation.
OxygenSelective
Polymer
Membranes
Various Membrane Commercial (to
produce 50%
O2)
Polymer membrane Polymer
membranes
containing
molecular
sieves show
promise for
providing
higher-purity
O2 from air.
   
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STATUS
CHEMICAL(S)
NOTES
Membranes for Hydrogen Separation and Integrated Precombustion Systems
CO2-Selective
Ceramic Membrane
for Water–Gas Shift
Reactions
Media and Process
Technology, the
University of
Southern
California, and
National Energy
Technology
Laboratory
Membrane Research –
laboratory-scale
reactor and
modeling
Tubular ceramic
membrane whose pores
are filled with
hydrotalcite
This process uses a
CO2-selective ceramic
membrane inside a
water–gas shift reactor
that separates CO2
from gas produced
during coal
gasification.
Catalytic Membrane
Reactor
Eltron Research
and Technology
Membrane Research –
laboratory scale
development and
testing
completed
Layered membrane
with 1) ceramic oxide
material with methane
steam-reforming
catalysts, 2) dense
perovskite, and 3) a
support layer
The membrane
operates at high
temperature ranging
from 850° to 1000°C.
Palladium–Copper
Alloy Membrane
Reactor
National Energy
Technology
Laboratory and the
Colorado School
of Mines
Membrane Research –
laboratory scale
Palladium–copper alloy Simultaneously
catalyzes the water–
gas shift reaction and
transports hydrogen
across the membrane
to produce a highpressure CO2 stream.
Hydrogen
Membrane Reformer
StatoilHydro Membrane Research –
laboratory-scale
demonstration,
full-scale
conceptual
model
Hydrogen-selective
membrane
The reactor combines
steam reforming,
water–gas shift
reaction, and hydrogen
separation.
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CHEMICAL(S)
NOTES
HydrogenMembrane
Reactor
Dalian Institute of
Chemical Physics,
SINTEF,
National Technical
University of
Athens,
Process Design
Center,
Energy Research
Centre of the
Netherlands
Membrane Research –
laboratory scale
constructed and
tested (25 kWt)
Pure palladium on a
tubular ceramic support
Part of the European
CACHET project to
develop hydrogen
membrane reactors for
CO2 capture.
Inorganic
Nanoporous
Membrane
Oak Ridge
National
Laboratory
Membrane Research –
laboratory scale
Three-layer composite
inorganic membrane
The inorganic
nanoporous membrane
removes H2 from
syngas streams,
leaving CO2 as the
primary constituent in
the gas stream.
High-Temperature
Polymeric–Metallic
Composite
Membrane
Idaho National
Energy and
Engineering
Laboratory,
Los Alamos
National
Laboratory,
Pall Corporation,
Shell Oil
Company
Membrane Research –
laboratory scale
Polybenzimidazole
composite layer on a
porous stainless steel
substrate
For high-temperature
hydrogen/CO2
separation; applies
only to gasificationbased systems. The
process can deliver
CO2 at high pressures.
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CHEMICAL(S)
NOTES
PalladiumContaining
Membrane Reactors
Praxair, T3
Scientific, and
CSM
United
Technologies
Research Center
and
Power+Energy
Western Research
Institute, Chart
Energy and
Chemicals, and
Synkera
Technologies
Worcester
Polytechnic
Institute,
Membrane
Technology &
Research, Siemens
Energy America,
and T3 Scientific
Membrane Research –
research funding
announced in
July 2010
Palladium or
palladium-based
ceramic membranes
These four projects, all
funded by DOE
National Energy
Technology
Laboratory, are
investigating
membrane technology
to separate hydrogen
and CO2 from coalderived synthesis gas.
   
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DURING COMBUSTION
Combustion with
Pure Oxygen
(without flue gas
recirculation)
Various Other combustion
process
Research – pilot
scale
Pilot tests done in the
past but approach
mostly abandoned
because of cost and
difficulty of
construction and
maintenance
Combustion
temperatures are very
high. Requires boilers
made with special
materials. New
construction or major
retrofit/rebuild.
Combustion with
Pure Oxygen with
Flue Gas
Recirculation as the
Dilution Gas
ALSTOM,
ABB,
Praxair,
Parsons Energy
Other combustion
process
Research;
currently at pilot
scale, with active
development and
scale-up in
progress.
Oxygen New construction or
retrofit. Difficulty
with retrofit is
eliminating air leakage
into boiler, flue, and
other flue gas
treatment processes.
Chemical-Looping
Combustion
ALSTOM,
Korean Institute
of Energy
Research, Vienna
University of
Technology,
Chalmers
University
Chemical adsorption Research to
small pilot scale.
Metal oxides used as
oxygen adsorbents
Process uses oxygen
by metal oxide carriers
to combust the fuel,
producing CO2 and
water. Condensation
of the steam produces
a relatively pure
stream of CO2.
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Advanced Zero
Emission Power
Process
ALSTOM Membrane Research –
mathematical
modeling –
thermoeconomic
analysis
Mixed conducting
membrane
Replaces the
combustion chamber
of an ordinary gas
turbine with a mixed
conducting membrane
reactor that separates
O2 from the air for
combustion with a fuel
(natural gas).
ThermoEnergy
Integrated Power
System Process
ThermoEnergy
Corporation
Other combustion
process
Research –
patented process
Utilizes high-pressure
combustion (700 to
1300 psi) and
facilitates the
condensation of
exhaust components
such as water and CO2
in a condensing heat
exchanger.
   
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POSTCOMBUSTION
Physical Absorption
Physical solvent-based absorption processes are typically not used for postcombustion capture because of their low capacity for CO2 at
low pressures.
Econamine FG℠ and
Economine FG Plus℠
Fluor Chemical absorption Commercial for
smaller-scale
natural gas and
coal combustion
processes. Scaleup demonstrations
planned and in
progress.
Monoethanolamine
(30 wt% and higher for
FG and FG Plus,
respectively)
Used in 24 plants
around the world, with
10 plants on order.
Demonstration facility
of >1000 metric
tons/day of coal
combustion flue gas.
Lummus MEA
Absorption Process
(aka KerrMcGee/ABB Lummus
Crest process)
Randall Gas
Technologies, Inc.
(Division of
Lummus
Technology, a
CB&I Company)
Chemical absorption Commercial for
smaller-scale
natural gas
combustion
Monoethanolamine
(15–20 wt%)
Has been
commercially applied
to capture CO2 from
coke- and coal-fired
boilers. Largest plant
produces 800 tons/day
of CO2.
KM CDR Process Mitsubishi Heavy
Industries (MHI)
Chemical absorption Commercial for
natural gas
combustion flue
gas. Scale-up
demonstrations
are in progress
and planned for
coal combustion.
Sterically hindered
amines (KS-1)
MHI offers
performance
guarantees for
postcombustion for
natural gas-fired
boilers. Currently
working on a largescale demonstration
for coal-fired boilers.
   
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NOTES
Activated Hot
Potassium Carbonate
(Benfield,
CATACARB,
Flexsorb HP, others)
UOP, Eickmeyer
& Associates,
Exxon
GiammarcoVetrocoke
Chemical absorption Commercial for
gas processing;
research is being
done on the
applicability of
related potassium
carbonate-based
solutions (see
IVCAP and
piperazine)
Aqueous solution of
potassium carbonate
with catalysts added
to speed the
reactions.
Not directly applicable
to postcombustion
capture because higher
feed gas pressures are
typically required (see
precombustion section
of this table).
See also the Sargas
carbonate process, a
high-pressure
combustion system
that uses a modified
Benfield process.
Pilot and Demonstration Scale
Aker Clean Carbon
Mobile Test Unit
Aker Clean
Carbon
Chemical solvent
absorption
Pilot scale Various (amines) Mobile pilot-scale test
unit; construction and
management of
78,000-ton/year pilot
in Mongstad, Norway;
planning for full-scale
facility in Kårstø,
Norway.
Chilled Ammonia
Process
ALSTOM Chemical solvent
absorption (with
phase change)
Demonstration
Ammonium
carbonate
Small- and moderatescale pilot projects
have been completed
on coal-fired boiler
flue gas. Developing
commercial-scale
demonstration at
1.5 million tons/year.
   
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Advanced Amine
Process
ALSTOM Chemical solvent
absorption
Pilot/small
demonstration
Dow UCARSOL™
FGC Solvent 3000
(amine)
Small pilot-scale
project on coalderived flue gas is in
progress. Small
demonstration facility
under development.
20-MWth Front End
Engineering Design
(FEED) project.
Cansolv CO2 Capture
Process
Cansolv
Technologies, Inc.
Chemical solvent
absorption
Pilot scale Proprietary amine–
amine mixture
A 50-metric-ton/day
pilot project is
planned. Has been
short-listed for the
SaskPower Boundary
Dam project.
HTC Purenergy
Carbon Capture
System
HTC Purenergy,
Doosan Babcock,
University of
Regina,
Greenhouse Gas
Technology
Center
Chemical solvent
absorption
Pilot scale (?)
Company literature
indicates availability
of 3000-ton/day
preengineered
modular system. No
large-scale pilot
projects have been
performed to date.
Proprietary amine
or mixtures of
amines
Amine/amine mixtures
developed at the
University of Regina
in Saskatchewan,
Canada. Was selected
for Basin Electric
Power Cooperative
Antelope Valley
project (which has
been cancelled).
Advanced PCCC
Technology
Linde AG with
BASF-developed
solvents
Chemical solvent
absorption
Pilot scale Proprietary
chemical solvent
A 7.2-metric-ton/day
pilot plant at RWE
Power’s lignite-fired
power plant in
Niederaussem,
Germany, is planned.
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ECO2TM Powerspan
(Powerspan
initially licensed
an ammoniabased process
from the U.S.
Department of
Energy National
Energy
Technology
Laboratory. They
have since
switched to a
proprietary
solvent.)
Chemical solvent
absorption
Pilot scale/
Demonstration
Proprietary
chemical solvent
(originally aqueous
ammonia)
Initially ECO2 was
directly linked to
Powerspan’s
electrocatalytic
oxidation barrier
discharge reactor,
which was used to
oxidize flue gas
pollutants (NOx, SOx,
Hg) that were then
scrubbed using
ammonia solutions.
Now it is a separate
proprietary solvent
(probably amine or
amine mixture)
absorber/stripper
system.
POSTCAPTM Siemens,
E.ON
Chemical solvent
absorption
Pilot scale Amino acid salts Pilot-scale project in
progress at E.ON
power plant near
Frankfurt, Germany.
Demonstration-scale
(280-MW) plant
planned for 2015 in
Finland. 1-MW
slipstream pilot funded
by the U.S.
Department of Energy
for TECO Big Bend
Station in Tampa,
Florida.
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Laboratory Scale
Ionic Liquids or Room-Temperature Ionic Liquids
Physical Solvent
Room-Temperature
Ionic Liquid–Amine
Mixture
Ion Engineering,
LLC, University
of Colorado
Mixed physical
solvent and chemical
solvent absorption
Research Physical solventtype ionic liquid
and amine
Proceeding to benchscale pilot.
Chemical Solvent
Room Temperature
Ionic Liquids
University of
Notre Dame
(developer)
Other players/
sponsors:
U.S. Department
of Energy
National Energy
Technology
Laboratory,
Air Products and
Chemicals,
Babcock &
Wilcox,
DTE Energy,
Merck/EMD
Chemicals,
Trimeric
Chemical solvent
absorption
Research Various The University of
Notre Dame research
group has also
identified a class of
phase-changing
compounds that are
solid until they react
with CO2 to form an
ionic liquid.
   
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NOTES
Other RoomTemperature Ionic
Liquid Research
Various Chemical solvent
absorption
Research Various, including
imidazolium salts,
a special class of
ionic liquids that
contain high
concentration of
amine functional
groups
Much work is focused
on synthesis and/or
assessment of ionic
liquids. Other studies
use these as the basis
for making polymer
membranes and
adsorbents (see
membrane and
adsorption sections.
Aminosilicones General Electric
Global Research
with General
Electric Energy
and University of
Pittsburgh
Chemical solvent
absorption
Research Aminosilicones Aminosilicones can
serve as chemical
absorbents for CO2 in
nonaqueous glycol
solvent solutions.
Phase-Changing Compounds
Several research groups are working on the study of compounds that change phase (solid to liquid or liquid to solid) upon exposure to
CO2.
Aminosilicone with
Phase Change
General Electric
Global Research
Phase change (liquid
to solid)
Research Aminosilicones Some aminosilicones
change phases,
forming a solid phase
upon reaction with
CO2.
   
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Chilled Ammonia
Process (has phase
change)
ALSTOM Chemical solvent
absorption with phase
change
Demonstration
Ammonium
carbonate
Chilled ammonia
process involves
precipitation of solids
in the absorber column
that are concentrated
into a slurry that is
pumped to the stripper
column for
regeneration. Smalland moderate-scale
pilot projects
completed on coalfired boiler flue gas.
Developing
commercial-scale
demonstration at
1.5 million tons/year.
Compound that
Changes from Solid
to Ionic Liquid upon
Reaction with CO2
University of
Notre Dame
Phase change (solid
to liquid)
Research Ionic liquid The University of
Notre Dame research
group has identified a
class of phasechanging compounds
that are solid until they
react with CO2 to form
an ionic liquid.
   
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NOTES
Absorption with Catalysis
Use of catalysts to increase reaction rates in chemical solvent absorption/stripping has been commercial for as long as chemical
solvent absorption has been used. All of the original hot potassium carbonate processes employ “activators” that serve as catalysts.
Piperazine as a
Catalyst for
Potassium Carbonate
University of
Texas at Austin
Chemical solvent
absorption
Research Potassium carbonate
and piperazine
The addition of
piperazine accelerates
the rate of the CO2–
potassium carbonate
reaction. The use of
concentrated
piperazine without
potassium carbonate is
also being
investigated.
Immobilization of
Carbonic Anhydrase
Akermin Chemical solvent
absorption
Research Carbonic anhydrase
in aqueous solutions
of amines and/or
carbonate salts
Immobilized for
transport in a solution
(various solvents).
Contained Liquid
Permeator and/or
Membrane Absorber–
Stripper with
Carbonic Anhydrase
Carbozyme, Inc. Membrane-based
separation using a
chemical solvent
solution
Research Carbonic anhydrase
in aqueous solutions
of carbonate salts
Immobilized for use in
a liquid membrane or
membrane
absorber/stripper
(various solvents).
Enzyme-Enhanced
Amines
CO2 Solution, Inc.
with Codexis, Inc.
Chemical solvent
absorption
Research Carbonic anhydrase
in aqueous solutions
of amines and/or
carbonate salts
Immobilized in an
absorber or
immobilized to carrier
for use in an
absorber/stripper
(various solvents).
   
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NOTES
Integrated Vacuum
Carbonate Absorption
Process (IVCAP)
Illinois State
Geologic Survey
at the University
of Illinois,
Urbana–
Champaign
Chemical absorption Research Carbonic anhydrase
is immobilized to a
carrier for use in a
potassium carbonate
solution in a
particular process,
IVCAP
Employs a potassium
carbonate solution to
capture CO2 and uses
the enzyme carbonic
anhydrase as a
catalyst.
Synthetic Catalysts
Based on Carbonic
Anhydrase Active
Site
Partnership
between United
Technologies
Research Center,
Lawrence
Livermore
National
Laboratory, the
University of
Illinois, Babcock
& Wilcox
Chemical absorption Research This group is
developing a synthetic
catalyst that is
designed to provide
the active site of the
carbonic anhydrase in
a smaller molecule.
Modified Combustion Systems
Sargas Carbonate
Process (pressurized
natural gas
combustion;
pressurized fluidizedbed combustion)
Sargas AS Pressurizedcombustion
combined-cycle
power generation
system with CO2
capture
Demonstration
(1-MW-scale coal
demonstration in
progress, 100-MW
natural gas and
400-MW coal
planned)
Potassium carbonate A high-pressure
combustion system
using a modified
Benfield hot carbonate
process. Not
applicable for retrofit.
   
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Adsorption
Overview Study of
Physical and
Chemical Adsorbents
for Postcombustion
CO2 Capture
ADA-
Environmental
Solutions–DOE
funded adsorbent
screening study
Adsorption Research Various (amines,
carbon, zeolites, and
carbonates)
Analysis of physical
and chemical
adsorbents for use in
postcombustion
capture.
Physical Adsorption
Generally not important for postcombustion capture. Physical sorbents can serve as supports for chemical adsorbents or chemical
absorbents or be modified to become chemical adsorbents through attachment of appropriate functional groups (i.e., amine functional
groups).
Electrical Swing
Adsorption
Oak Ridge
National
Laboratory
University of
Porto, Portugal;
Centre National de
la Recherche
Scientifique,
Nancy, France
University of
Queensland,
Australia
Physical adsorption
and/or chemical
adsorption
Research – small
bench-scale
studies
Activated carbon
(monolith or carbon
fiber) composite with
zeolites
Activated
carbon/graphite is
used as an electrically
conductive support for
zeolite molecular
sieves that serve as the
solid sorbent. A lowvoltage current
removes the adsorbed
CO2 by resistive
heating.
Chemical Adsorption
Novel Carbon
Adsorbent
Advanced
Technology
Materials, Inc.,
SRI International
Chemical adsorption
with temperatureswing regeneration
Research Surfacefunctionalized carbon
Developers plan to
develop a moving-bed
adsorber/stripper
system based on the
use of a high-capacity
adsorbent.
   
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Metal Oxides and
Metal Hydroxides
National Energy
Technology
Laboratory
Chemical adsorption Research Sodium carbonate,
potassium carbonate,
magnesium oxide,
magnesium
hydroxide
Theoretical modeling
studies on the use of
metal oxides and
metal hydroxides as
solid adsorbents for
postcombustion CO2
capture.
Stabilized Calcium
Oxide Adsorbents
Pacific Northwest
National
Laboratory
Chemical adsorption Research Calcium oxide
(CaO ) adsorbent
with MgAl2O4 spinel
nanoparticles
Targeted for use at
high temperature
(650°C carbonation
and 850°C
calcination).
Dry Sorbent-Based
Capture Process
RTI International
with National
Energy
Technology
Laboratory;
Electric Power
Research Institute;
ARCADIS, Inc.;
U.S.
Environmental
Protection
Agency;
Sud-Chemie, Inc.
Nexant
Chemical adsorption 1-ton/day pilot
test, with target
commercialization
date of 2015
Metal carbonate CO2 reacts with lime
to form calcium
carbonate. Other
candidate sorbents
include sodium
bicarbonate, trona, and
potassium carbonate.
   
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Metal Organic
Frameworks (MOFs)
UOP, LLC,
University of
California at Los
Angeles,
University of
Michigan,
Northwestern
University,
Vanderbilt
University,
University of
Edinburgh, and
many others
Chemical adsorption Research MOFs Large metal oxide
molecules with
engineered
macromolecular
cavities that can
adsorb CO2. They may
contain functional
groups such as tertiary
amines to enhance
chemisorption of the
CO2.
Zeolite Imidazolate
Frameworks (ZIFs)
Pacific Northwest
National
Laboratory,
University of
Pittsburgh
Chemical adsorption Research ZIFs Class of crystalline
nanoporous materials
made of zeolite
minerals and
imidazoles at the
organic linkages.
   
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Surface-Modified
Expanded
Mesoporous Silica
University of
Ottawa
(Developer) and
Carbon Capture
Technologies,
Inc., a branch of
CSMG
Technologies, Inc.
(Licensee)
Chemical adsorbent Research Mesoporous silica Recyclable adsorbents
exhibit a high
adsorption capacity
that is both fast and
reversible. Can be
used with both wet
and dry gas streams.
TDA Dry Solid
Sorbent
TDA
Technologies,
Babcock &
Wilcox,
Louisiana State
University,
Western
Research Institute
Chemical adsorbent Research Alkalized alumina
adsorbent
Captures CO2 at
intermediate
temperatures and nearambient pressure.
Regenerated using
steam.
Novel AmineEnriched Solid
Sorbent
National Energy
Technology
Laboratory
Chemical adsorbent Research –
laboratory scale
Amine compound
grafted onto a carbon
support
High sorption
capacities with low
regeneration energy
requirements.
   
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NOTES
Metal Monolithic
Amine-Grafted
Zeolite Sorbent
University of
Akron,
National Energy
Technology
Laboratory
Mixed absorption/
adsorption
Research Amine-grafted
zeolites plated onto
the walls of a metal
monolith
Features the novel
integration of a metal
monolith with aminegrafted zeolites.
Polyionic Liquids University of
Wyoming
Chemical adsorption Research Polymers made from
ionic liquids
Focus is on the
development of
polymers referred to
as polyionic liquids.
Polymer-Entrapped
Ionic Liquids
Georgia Institute
of Technology
Mixed absorption/
adsorption
Research Ionic liquids trapped
in hollow fibers made
from normal
polymers
This “ionic liquid
sponge” is used like an
adsorbent in a
temperature or
pressure swing
adsorption-type
system.
Recyclable CO2
Adsorbent
University of
Ottawa
(Developer),
Carbon Capture
Technologies,
Inc., a branch of
CSMG
Technologies, Inc.
(Licensee)
Chemical adsorption Research Surface-modified
expanded
mesoporous silica
Recyclable adsorbents
exhibit a high
adsorption capacity
that is both fast and
reversible. Can be
used with both wet
and dry gas streams.
   
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Hyperbranched
Aluminosilica (HAS)
Georgia Institute
of Technology
Chemical adsorption Research Amine polymer
groups on a silica
substrate
Laboratory-scale
studies have shown
that HAS is reusable,
works in the presence
of moisture, and can
adsorb up to five times
as much as other
reusable materials.
Membranes
Polymer Membranes Various Selective transport of
CO2 across polymer
membranes
Research Various polymers and
polymer composites
with adsorbents
Journal of Membrane
Science September
2010 issue provides
excellent coverage of
this topic.
Polaris™ Membrane Membrane
Technology &
Research (MTR)
Selective transport of
CO2 across polymer
membranes
Small-scale pilot Polymer membrane Based on a
commercial
membrane. MTR is
also involved in the
use of membrane
systems for CO2
separation from
natural gas and is
investigating the use
of its membrane
systems for H2/CO2
separations.
   
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NOTES
Molecular Gate
Membrane
Research Institute
of Innovative
Technology for
the Earth – Japan
Selective transport of
CO2 across polymer
membranes
Research Composite polymer
membrane
The molecular gate
membrane consists of
a cardo-polyimide
membrane that only
allows CO2 molecules
to permeate the
membrane, blocking
N2 and H2 and
producing a CO2-rich
stream.
Gelled Ionic Liquids
Membranes
University of
Colorado
Selective transport of
CO2 across a liquid
membrane
Research Ionic liquid held as a
liquid membrane
supported in an
porous polymer
membrane
This research focuses
on the development of
novel gelled ionic
liquid membranes.
Polyvinylidene
Fluoride-Based
Polymer
RTI International Selective transport of
CO2 across polymer
membranes
Research Polymer membrane
made with
polyvinylidene
fluoride (PVDF)
This process takes
advantage of the
specific affinity that
the PVDF polymer has
for CO2.
Imidazolium SaltBased Polymer
Membrane
University of
Colorado
Selective transport of
CO2 across polymer
membranes
Research Polymerized
imidazolium salt
ionic liquid
compound that forms
a structural polymer
membrane
Development of
polymer membranes
based on direct
polymerization of a
class of ionic liquid
compounds known as
imidazolium salts.
   
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Carbozyme Liquid
Membrane Permeator
Carbozyme, Inc. Selective transport of
CO2 across a liquid
held between two
microporous polymer
membranes (enzymecatalyzed transport)
Research Aqueous solution of
metal carbonate salt
and/or amines with
immobilized CA
See section on
carbonic anhydrase.
Carbozyme has also
announced
development of a
membrane-based
absorber stripper; see
section on other
contactors for
absorption-based
separations.
Other
Other Contactors for Absorption-Based Separations
Membrane Contactors
Membrane contactors are flat-sheet, spiral-wound, or hollow-fiber membrane modules in which a porous membrane is used to separate
the gas phase from an absorption solution. High surface areas reduce the size of the absorber and stripper towers and permit the use of
solvent solutions that might not work well in an absorption tower because of the tendency to foam.
Kvaerner Hybrid
Membrane
Absorption System
Aker Process
Systems (Kvaerner
Process Systems)
Alternate absorption
contactor –
membrane absorber
Pilot scale with
Mitsubishi Heavy
Industries KS-1
solvent
Microporous
polytetrafluoroethylene membranes
Pilot study concluded
insignificant capital
cost savings and 19%
operating cost savings
when compared to
conventional MEA.
   
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PoroGen Carbo-Lock
Process
PoroGen Alternate absorption
contactor –
membrane absorber
Research –
laboratory scale,
recently funded for
3-year
development
project
Microporous hollowfiber polyether ether
keytone membranes
with fluorocarbonmodified surface.
3-year project includes
partnership of
PoroGen with Gas
Technology Institute
and Aker Process
Systems.
CATO CO2 Catcher TNO Alternate absorption
contactor –
membrane absorber
Pilot scale at E.ON
Benelux power
plant in
Rotterdam,
Netherlands
Microporous
polyolefin membrane
used with amino acid
salt-based absorbents
(CORAL solvents)
Solvent–Membrane
Hybrid
Postcombustion CO2
Capture Process
University of
Kentucky
Alternate absorption
contactor –
membrane absorber
Research –
laboratory scale
Microporous
membranes with
immobilized catalyst
Advanced Project
Research AgencyEnergy (ARPA–E)funded project
Carbozyme
Proprietary
Absorber–Stripper
System
Carbozyme Alternate absorption
contactor –
membrane absorber
Research –
laboratory scale
Microporous
membranes with
immobilized
carbonic anhydrase
See Carbozyme
contained-liquid
membrane permeator.
Membrane Absorbers Other researchers Various – many
universities (not
detailed with
references)
Research and
small-scale
demonstrations
various Many university
researchers have
published work on the
use of membrane
absorbers for use in
capturing CO2 into
solutions of chemical
absorbents including
metal hydroxides,
metal carbonates, and
amines.
   
A
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PROCESS
DEVELOPER(s)/
SUPPLIER(S)
CLASSIFICATION
STATUS
CHEMICAL(S)
NOTES
Other Novel Absorber Contactors
NeustreamTM-C Neumann Systems
Group, Inc.
Chemical solvent
absorption
Development stage
for CO2 capture
Various A unique horizontalflow absorber that
promises very high
mass transfer rates
while reducing the
overall system
footprint and energy
consumption.
Cryogenic CO2 Capture
Cryogenic Carbon
Capture System
Sustainable
Energy Solutions
Cryogenic CO2
capture
Bench-scale
project for
postcombustion
flue gas
Not applicable Target is
postcombustion
capture.
Cryogenic CO2Capturing System
Cool Energy Ltd. Cryogenic CO2
capture
Processing on
natural gas –
demonstration at
2 million scfd
Not applicable Target is natural gas
processing; may be
useful in
precombustion capture
as well.
Controlled Freeze
Zone Process
ExxonMobil Cryogenic CO2
capture
Construction of
full-scale natural
gas-processing
facility
Not applicable Target is natural gas
processing; may be
useful in
precombustion capture
as well.
   
A
-35
PROCESS
DEVELOPER(s)/
SUPPLIER(S)
CLASSIFICATION
STATUS
CHEMICAL(S)
NOTES
Mineralization
Bauxite Waste from
Aluminum Refining
Alcoa, Inc. CO2 capture by
mineralization
Demonstration Bauxite, alkaline
waste from aluminum
ore processing
Bauxite waste has a
high magnesium
content that is reacted
with CO2 to form
magnesium carbonate.
The neutralized waste
is dried and disposed of
in a landfill or as fill at
the bauxite mine or
beneficially used as
road base, building
materials, or as a soil
amendment.
Alkaline Fly AshBased CO2 Capture
Ohio State
University
CO2 capture by
mineralization
Laboratory scale Alkaline fly ash Flue gas is contacted
with alkaline fly ash to
form a residual with
CO2 sequestered as a
mineral carbonate.
Accelerated
Weathering of
Magnesium Silicate
Minerals
Columbia
University
CO2 capture by
mineralization
Laboratory scale Basaltic ultramafic
rocks (high in
magnesium)
In nature, CO2 reacts
with minerals such as
magnesium silicates
over a long period of
time to produce a stable
precipitate such as
magnesium carbonate.
Enhanced weathering
research is being
performed with the
goal of accelerating this
natural reaction.
A
-36
PROCESS
DEVELOPER(s)/
SUPPLIER(S)
CLASSIFICATION
STATUS
CHEMICAL(S)
NOTES
Calera CO2 Capture
Process
Calera
Corporation
CO2 capture by
mineralization
DOE and
Australian
government have
funded
demonstration
projects up to 50MW equivalent
Fly ash and brines Combines CO2 with
minerals harvested
from waste products
including fly ash and/or
brines to form usable
aggregate and/or
cement.
Electrochemical
methods are used to
generate the alkalinity
required for
mineralizing the CO2 as
a metal carbonate
and/or metal
bicarbonate.
C-Quest Chemical
Sorbent System
C-Quest
Technologies
CO2 capture by
mineralization
Laboratory-scale
testing
Variety of sorbent
ingredients
Makes use of widely
available sorbent
ingredients that react
with CO2.
SkyMine® Skyonic
Corporation
CO2 capture by
mineralization
“Commercialscale”
demonstration at a
cement plant
Brine Removes CO2 from
industrial waste gas
streams through
cogeneration of salable
carbonate and/or
bicarbonate minerals.
Electrochemical
methods are used to
generate alkalinity
from the brine.
   
A
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PROCESS
DEVELOPER(s)/
SUPPLIER(S)
CLASSIFICATION
STATUS
CHEMICAL(S)
NOTES
New Sky Energy
Electrochemical
Carbon Capture
Technology
New Sky Energy CO2 capture by
mineralization
Small
demonstration unit
being constructed
Brine Utilizes a salt solution
and an electrochemical
process to make
sodium hydroxide
(NaOH), which
spontaneously
combines with CO2 to
produce carbonates
such as sodium
carbonate and sodium
bicarbonate.
Reduction
Reduction of CO2 is the opposite of oxidation. Energy is required to form carbon–carbon and carbon–hydrogen bonds.
Photosynthetic Reduction
Photosynthesis –
Closed-Environment
Agriculture
Warm CO2
(Terneuzen, The
Netherlands);
likely others
CO2 capture by
reduction of CO2
Small-scale
commercial
Energy input from
sunlight
Waste heat, anhydrous
ammonia, and CO2 are
provided to a 1-mi2
greenhouse facility that
grows flowers and food
crops.
Photosynthesis –
Algae and Microalgae
Various CO2 capture by
reduction of CO2
Demonstration Energy input from
sunlight
Some proposed
systems use electric
lights. When electric
lights are used, the
process is not
economical.
   
A
-38
PROCESS
DEVELOPER(s)/
SUPPLIER(S)
CLASSIFICATION
STATUS
CHEMICAL(S)
NOTES
Algae for Nutritional
Supplement
Cyanotech CO2 capture by
reduction of CO2
Commercial scale Energy input for
reduction from
sunlight.
Small combined heat
and power system (2
MW) is used to supply
flue gas CO2 to algae
raceways used to grow
spirulina that is sold as
a nutritional
supplement.
Approximately 67
tons/month of CO2
yields 36 tons/month of
spirulina in
approximately 30 acres
of raceway.
Algae for Nutritional
Supplement and/or
Biofuels
Seambiotic CO2 capture by
reduction of CO2
Pilot scale Energy input for
reduction from
sunlight
1000-m2 pilot algae
production facility
using CO2 in flue gas
from a coal-fired power
station in Ashkelon,
Israel. Products
planned are omega-3
fatty acids and biofuels.
Algae for Biofuels Pond Biofuels CO2 capture by
reduction of CO2
Small pilot scale Energy input for
reduction from
sunlight
1500-ft2 indoor
demonstration facility
at St. Mary’s Cement
plant in Ontario,
Canada, to produce
biofuel.
   
A
-39
PROCESS
DEVELOPER(s)/
SUPPLIER(S)
CLASSIFICATION
STATUS
CHEMICAL(S)
NOTES
Other Biofuels- fromAlgae Projects
U.S. Department
of Energy NREL
(1978–1996),
Touchstone
Research
Laboratory,
Phycal
Vattenfall project
CO2 capture by
reduction of CO2
Small-to-mediumsize demonstration
Energy input for
reduction from
sunlight.
Biofuel is the main
product. Other products
include nutritional
supplements for
humans and/or fish.
Chemical and Biochemical Reduction
Production of
Polymers
Various Reduction of CO2 to
form cyclic
carbonates or
polycarbonates
Commercial use of
purified CO2 is
common. Research
is being done on
the direct use of
flue gas as CO2
source.
Energy input
required, typically
supplied by other
reagents involved in
the reaction
The U.S. Department
of Energy has funded
Novomer Inc. to
conduct a study in
conjunction with
Albermarle
Corporation and
Eastman Kodak
Company to develop
novel catalysts and a
process to make
thermoplastics
containing 50 wt%
CO2.
Generation of
Electrofuels
Various Reduction of CO2
using electrochemical
and biochemical
processes to make
liquid transportation
fuels.
Advanced
Research Projects
Agency-Energy
(ARPA-E)-funded
research projects
Various See sections on
generation of
“Electrofuels” and
“STEP Carbon
Capture.”

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