Process Economics Program Report 180
Published: Dec-87
The separation of carbon dioxide from gaseous mixtures is an essential part of natural gas production and of some chemical operations such as the manufacture of ammonia and hydrogen. Methane-rich natural gas from underground wells is usually contaminated with acid gases, mainly CO2 and to a lesser degree, sulfur-containing components such as H2S and COS. To produce fuel gas of acceptable quality it is necessary to separate these acid gases. In NH3 and H2 production, CO2 is an unavoidable by-product of the syngas generation step (regardless of whether the route used is natural gas steam reforming, hydrocarbon partial oxidation, or coal gasification), which must be separated before further downstream processing is possible.
Virtually all commercial processes for CO2 separation are based on absorption in liquid solvents. The solvents used may be categorized into two types--chemical solvents (such as aqueous solutions of monoethanolamine or potassium carbonate, where the mechanism of absorption is via a reversible chemical reaction) or physical solvents (such as methanol used in Rectisol® or dimethyl ethers of polyethylene glycols used in Selexoll® , where the absorption of CO, and other acid gases is without chemical reactions). When significant quantities of sulfur-bearing acid gases (H25 and COS) are present with CO2 (as from the partial oxidation of vacuum residuum or coal gasification) the solvents used must selectively split the sulfur-bearing gases from the CO2 to facilitate sulfur recovery. (Both the Rectisol® and Selexoll® processes achieve this.)
The substantial worldwide, solid/liquid CO2 industry is primarily based on the availability of CO2 as a by-product of other operations. Besides NH3 and H2 plants, which have comprised the main sources of supply, other sources include fermentation ethanol and ethylene oxide plants. These sources furnish the high purity CO2 needed for the solid/liquid segment.
The gaseous CO2 market segment has been very small if we exclude the manufacture of urea and of sodium carbonates--where the source of supply has always been captive. However, following the sharp rise in oil prices during the late seventies/early eighties, a new major use for gaseous CO2 emerged in the United States. This is enhanced oil recovery (EOR) by the "miscible-gas flooding" technique. Since a lower purity CO2 product can be used for this application and because of the large volumes needed, the original interest was centered on sources such as natural gas processing and natural CO2 wells (such as those in Colorado, Mississippi, New Mexico, and Wyoming). Although these two sources provide the lowest cost CO2 there was also a growing interest in the potentially large quantities of CO2, available in alternative sources such as power plant flue gases and the gaseous effluent from cement plants.
In this report we examine the technology and economics
of CO2 separation from natural gas fired power plant flue gases.
Two processes are evaluated--one based on the Dow Gas Specl® FT-1 technology
(which uses proprietary monoethanolamine solutions containing corrosion inhibitors)
and the other based on Benfield technology (which uses K2CO3solutions).
For comparison we also examine the economics of CO2 separation from
NH3 syngas mixtures with these two types of solvents. The monoethanolamine
solvent process is based on Union Carbide Corporationís AAGl® (Advanced
Amine Guard) technology, and the K2CO3 process is based
on Benfieldís LoHeatl® technology. We also present an outline of the CO2
industry status with particular reference to the United States, Western Europe,
and Japan, and a technical review of CO2 separation processes.
Process Economics Program Report 180A
Published: Dec-2004
90% of the
world's energy is derived from fossil fuels. Emissions of CO2 have risen from
20.7 billion tonnes of CO2 in 1990 to 24.1 billion tonnes in 2002, a rise of
over 16%. Hence, the Kyoto protocol and attempts to slow and ultimately reverse
the increase in emissions of greenhouse gases will have profound economical
and geopolitical effects. However, so have the potential effects of global warming.
This creates strong interests and lobbies both against and for the implementation
of Kyoto.
Given this,
there has been increasing interest in the capture of CO2 and its subsequent
sequestration. Options for disposal of CO2 after capture include storage in
former oil and gas fields, injection into coal seams to liberate sorbed methane,
ocean disposal, or saline aquifer injection. Fixation of CO2 by reforestation
and changes in agricultural practice, while relatively cheap, can only offset
a small part of the projected CO2 emissions for the next century.
Given this,
there has been increasing interest in the capture of CO2 and its subsequent
sequestration. Options for disposal of CO2 after capture include storage in
former oil and gas fields, injection into coal seams to liberate sorbed methane,
ocean disposal, or saline aquifer injection. Fixation of CO2 by reforestation
and changes in agricultural practice, while relatively cheap, can only offset
a small part of the projected CO2 emissions for the next century.
Geological
storage of CO2 by injection into saline aquifers appears the most practical,
in terms of capacity and widespread geographical availability, but this method
means that the stored CO2 will be underground in supercritical phase for centuries.
The potential of a catastrophic release of CO2 if such underground reservoirs
were created is still being quantified. C
Currently favored
options for CO2 capture at the power plant include post-combustion CO2 removal,
pre-combustion CO2 capture with temperature-swing regeneration. Our report includes
conceptual designs and costs for the use of amine solvents for both post-combustion
CO2 removal and pre-combustion removal of CO2 by reforming and water-shift reaction
with natural gas-fired combined cycle generation (NGCC). Our estimated costs
for both methods are above those by previous researchers who have examined this
topic. This reflects a more conservative design strategy in our concept of the
processes, a higher natural gas price, as well as a higher efficiency penalty
for CO2 capture in our scenarios.
The technologies
for CO2 capture, with the exception of the ultimate sequestration of CO2, are
proven technologies, largely borrowed from other chemical processes (such as
ammonia and hydrogen production) which could easily be implemented in the short
to medium term. This technology creates a path where a fossil fuel, natural
gas, can continue to play a major role in power production but CO2 emissions
can also be drastically reduced, without imposing an unconscionable economic
price. We would predict a window between 2020-2030 where the technology might
be used. Earlier than this window, we would expect that CO2 emissions credits
would be unlikely to at a price where the use of the technology would be economically
justified.
The PEP report abstracts shown above are provided as a complete historical reference of related PEP reports. The production cost estimates are updated in the PEP Yearbook. Lists of all PEP reports and reviews are available here.
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