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Wilcox-CarbonCapture.pdf
Chapter 1
Introduction to Carbon Capture
The capture of CO2 is motivated by the forecasted change in climate as a result
of the world’s dependence on fossil fuels for energy generation. Mitigation of CO2
emissions is the challenge of the future for stabilizing global warming.The separation
of CO2 from gas mixtures is a commercial activity today in hydrogen, ammonia, and
natural gas purification plants. Typically, the CO2 is vented to the atmosphere, but
in some cases, it is captured and used. The current primary uses of CO2 include
enhanced oil recovery (EOR) and the food industry (carbonated beverages). The
traditional approach for CO2 capture for these uses is solvent-based absorption. It
is unclear whether this technology will be the optimal choice to tackle the scale
of CO2 emitted on an annual basis (∼30 Gt worldwide). A new global interest in
extending CO2 capture to power plants is producing a dramatic expansion in R&D
and many new concepts associated with clean energy conversion processes. The
application of CO2 capture technologies beyond concentrated sources is in view, but
less tractable. The first and second laws of thermodynamics set boundaries on the
minimum work required for CO2 separation. Real separation processes will come
with irreversibilities and subsequent inefficiencies taking us further from best-case
scenarios. The inefficiency of a given process reveals itself in the form of operating
and maintenance, and capital costs.
The interconnected nature of multiple fields of science and engineering is essential. Appreciating the physical and chemical properties of the various CO2 emissions
sources serves as a critical first step. Envisioning methods for its capture will occupy
the next several decades of engineers, chemists, physicists, earth scientists, mathematicians, and social scientists. Where will the capture technology be applied? What
might the technology involve? Will we one day place systems in the desert to capture
dilute CO2 directly from air? Will we install CO2 separators on automobiles and airplanes so that consumers exchange CO2 for fuel at refueling stations? CO2 capture
is often considered in the context of point sources such as coal-fired power plants or
industrial processes, but breakthroughs in research must lead to applications of CO2
capture to an even wider realization of its abatement potential.
Process engineering, materials science, catalysis and nanoscience will likely play
key roles in hybridizing the known technologies toward an integrative approach
to meet the challenge. Figure 1.1 illustrates the multiple scales that a particular
J. Wilcox, Carbon Capture,
DOI 10.1007/978-1-4614-2215-0_1, © Springer Science+Business Media, LLC 2012
1
2
1 Introduction to Carbon Capture
Fig. 1.1 Schematic of the
overlap between the scales
across the portfolio of
solutions to CO2 capture
solution for CO2 capture may entail. At the heart of any CO2 capture technology
is the material and its required properties for optimizing mass transfer from a gas
mixture to a captured phase. The material may be a solvent, sorbent , membrane or
catalyst. Mass transfer acts as the bridge and links the optimal material properties with
the overall separation process, whether it is a combined absorber-stripper system,
sorption apparatus, membrane module, or catalytic reactor. The material properties,
mass transfer, and capture process must be considered as coupled and inherent to the
system in total. In this case, the system is defined as the CO2 capture environment
and the local surroundings of the capture assembly.
A CO2 capture technology may look quite different for the direct air capture of
CO2 (DAC) in which the concentration of CO2 is quite dilute, i.e., approximately
0.0390 mol% (390 ppm) versus its capture from the exhaust of a power plant, in which
its concentration is on average 12 mol%. In addition to the concentration difference,
CO2 capture from a power plant must overcome the challenge associated with the
timescale and throughput of emissions. For instance, a 500-MW power plant emits
on average 11,000 tons1 of CO2 per day. Direct air capture is much less efficient. For
example, assuming an air flow rate of 2 m/s, capturing 11,000 tons of CO2 per day
directly from the air requires a surface area of approximately 133,000 m2 to process
2.31 × 1010 m3 of air per day.2
This chapter provides a brief overview of CO2 sources, as well as the physical
and chemical nature of its environment. This overview motivates further discussion
of fuel oxidation and combustion, the heart of CO2 emissions. Knowledge of the
chemical composition of a given exhaust mixture allows for the determination of the
minimum work required for CO2 separation from the mixture. The 2nd-law efficiency
is defined as the ratio between this ideal minimum work and the real work associated
with the unit operations of the actual separation process. Known processes relying
on absorption, adsorption, membrane, and hybrid processes can then be investigated.
Chapter 2 focuses on Compression and Transport of CO2 . Knowledge of CO2 phase
behavior as a function of temperature and pressure throughout compression and
transport processes is crucial to determine safe and cost-effective approaches to
1
Throughout the textbook, “ton” is in reference to a metric ton and is sometimes referred to as
tonne, which is equal to 1000 kg.
2
This assumes 100% capture of the CO2 at a concentration in air of approximately 390 ppm.
1.1 Relationship Between CO2 and Climate
3
handling CO2 between the capture and potential-use stages. Once CO2 is captured
and compressed, the question becomes what to do with it. This will be addressed
shortly. The phase behavior of CO2 and fundamental equations associated with its
compression also play a role in separations processes. Although compression and
transport take place after CO2 capture, presenting this material prior to the separation
processes provides a foundation and set of equations referenced in future chapters.
Chapters 3–6 focus on Absorption, Adsorption, Membrane Technology, and Air
Separation, respectively. These broad-reaching chapters are motivated by the operating, maintenance, and capital costs of a given separation process. Costs are bridged
in step-wise fashion to the fundamental chemical and physical processes that underlie the mass transfer of CO2 from a gas to its captured form. In particular, Chapter 6
discusses air separation (i.e., the separation of air into N2 , O2 , and argon) as it
may play a key role in CO2 capture since N2 is the primary inert gas diluting most
CO2 -inclusive gas mixtures.
Chapters 7–9 examine nontraditional separation technologies that in the most
ideal sense may be considered carbon-neutral. The topics covered in these chapters
include the role that algae plays in CO2 capture, CO2 electrocatalysis and photocatalysis to fuel and chemicals, and mineral carbonation, respectively. These are
interesting approaches to consider in the CO2 capture portfolio since currently they
are investigated primarily as post-capture processes. For instance, the conversion
of CO2 via algae, electrocatalytic, and photocatalytic processes to a chemical or
fuel has mostly been investigated for the conversion of CO2 -rich gas streams as the
input. However, with technological advancements it may be possible to use such
approaches to combine CO2 capture and conversion in a single process. Chapter 9
discusses mineral carbonation, focusing on the potential to form mineral carbonates
from reacting CO2 with an alkalinity source. Natural and industrial waste byproduct
alkalinity sources are considered, with a particular focus on industrial waste alkalinity sources since the mineral carbonation process would be sequestering CO2 in
addition to other potentially hazardous components of the waste. The potential to
reuse the mineral carbonates as aggregate for construction applications may serve
as a driver to move this technology forward. These chapters review of each of these
processes and their current challenges.
The separation processes considered in Chaps. 3–6 for CO2 capture may be
broken down into their fundamental unit operations with the work requirements
determined for each stage of separation, such as blower power for gas compression
or pumping power for solvent transport. The reader can work through the application of a capture technology from a gas mixture containing CO2 and based upon the
local environment and composition, determine the feasibility of capture with current
separation tools or a hybrid thereof based upon its 2nd-law efficiency.
1.1
Relationship Between CO2 and Climate
The combustion of fossil fuels, i.e., coal, petroleum, and natural gas, is the major anthropogenic source of CO2 emissions, with an estimated 30 gigatons (Gt) CO2 (e.g.,
30 billion tons) generated per year as illustrated in Fig. 1.2 [1]. This figure shows the
4
1 Introduction to Carbon Capture
Fig. 1.2 Global fuel-based CO2 emissions from the period of 1970–2008 (total and by fuel type) [2]
breakdown of CO2 emissions by fuel type, with coal burning surpassing oil-sourced
emissions around 2004. Figure 1.3 shows the breakdown in CO2 emissions from
the top-emitting countries, with China surpassing the U.S. around 2006 [2]. It is
clear that human activities over the course of the 20th century, have led to increasing
greenhouse gas (GHG) emissions. Studies indicate that increases in CO2 concentration in the atmosphere leads to irreversible climate changes lasting up to 1,000 years,
even after elimination of emissions [3]. Additionally, even if anthropogenic GHG
emissions remained constant from today, the world would still experience continued
warming for several centuries [4]. For global mean temperature stabilization, GHG
emissions would have to cease today [3, 5], which is difficult due to our reliance on
the existing fossil-based energy and transportation infrastructure, which is expected
to contribute to GHG emissions for tens of years to come [6].
Examples of irreversible climate changes include atmospheric warming, dryseason rainfall reductions in several regions comparable to those of the “dust bowl”
era3 , more extreme weather events and inexorable sea level rise [3]. The carbonclimate response, which is defined as the ratio of temperature change to cumulative
3
The “dust bowl” era from 1930–1936 was a period of dust storms causing major ecological and
agricultural damage to the prairie lands of the U.S. (panhandles of Texas and Oklahoma, and
neighboring regions of New Mexico, Colorado, and Kansas) and Canada, causing severe drought
followed by decades of extensive farming without crop rotation or other techniques to prevent wind
erosion. Millions of acres of farmland became useless, with hundreds of thousands of people leaving
their homes and migrating to California and other states.
1.1 Relationship Between CO2 and Climate
5
Fig. 1.3 Global fuel-based CO2 emissions by top-emitting countries from 1990 to 2008 [2]
CO2 emissions is estimated at approximately 1.0–2.1◦ C per 3600 Gt of CO2 emitted
into the atmosphere [7]. The natural carbon cycle is responsible for a portion of
the removal of CO2 from the atmosphere, some to the oceans and some to terrestrial vegetation. The natural carbon cycle includes exchange with the land biosphere
(photosynthesis and deforestation), the surface layer of the ocean, and a much slower
penetration into the depth of the ocean, which is dependent upon vertical transport
and the buffering effect of the ocean’s chemistry [3]. The carbon flows associated
with global photosynthesis and respiration are generally an order of magnitude larger
in scale than the extraction and combustion of fossil fuel, but are largely in balance.
With updated estimates on CO2 emissions from both deforestation and coal combustion, estimated emissions from deforestation and forest degradation represent
approximately 12 to 13% of global anthropogenic CO2 emissions [8], different from
previous estimates of 20% [9]. In addition to CO2 , other GHGs include methane
(CH4 ), nitrous oxide (N2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
and sulfur hexafluoride (SF6 ). Researchers predict that non-CO2 GHG emissions
will constitute approximately4 one-third of total CO2 equivalent emissions over the
2000–2049 period [10]. This textbook, however, focuses primarily on the separation
of CO2 , which remains the primary anthropogenic contributor to climate change [11].
4
Based on 100-year global warming potentials.
6
1 Introduction to Carbon Capture
Table 1.1 Estimated 2011 U.S. CO2 exhaust emissions [2]
Source
Emissions sector (Mt CO2 /year)
Trans
Petroleum
1952.68
Natural gas
33.1
Coal
∼0
Total
Elec.
102.30
Comm. Ind.
54.93
319.11 163.06
1983.81
9.28
1985.79 2405.22 227.26
Exhaust mixture
Res.
Total
416.83 100.91 2627.64 CO2 (3–8 vol%)
SO2 ; NOX ; PM; CO
397.54 262.42 1175.24 CO2 (3–5 vol%)
NOx ; CO; PM
187.99
0.81 2181.89 CO2 (12–15 vol%) PM;
SO2 ; NOX ; CO; Hg
1002.6 364.14 5984.77
Table 1.2 Estimated 2008 U.S. and worldwide CO2 process emissions [15]
Non-Fossil
Emissions (Mt CO2 /year)
CO2 content (vol %)
Cement production
Refineries
Iron and steel production
Ethylene production
Ammonia processing
Natural gas production
Limestone consumption
Waste combustion
Soda ash manufacture
Aluminum manufacture
50 (world 2000)
159 (world 850)
19 (world 1000)
61 (world 260)
7 (world 150)
30 (world 50)
19
11 (electricity)
4
4 (world 8)
14–33
3–13
15
12
100
5–70
50
20
1.2
CO2 Sources and Sinks
The combustion of fossil fuels produces an estimated 30 Gt of CO2 per year. Deforestation of tropical regions accounts for an additional 4 Gt CO2 per year [8]. Due to
the natural carbon cycle and associated terrestrial and ocean CO2 sinks, the annual
increase in CO2 emissions averages approximately 15 Gt CO2 per year, which is
equivalent to 2 ppm per year. Fossil fuel-based emissions of CO2 may be sourced
from both stationary (e.g., power plant) and non-stationary systems (e.g., automobile). There are approximately 13 Gt CO2 per year on average from large stationary
sources globally, and approximately 2.5 Gt in the U.S. as illustrated in Table 1.1 [2].
In addition to CO2 emissions generation from the oxidation of fossil fuels, emissions
may also be sourced as a result of a chemical process. Although these emissions
sources represent a minor portion of total anthropogenic emissions, the chemical
processing method currently used may be required for the formation of a useful
product, such as cement or steel. Therefore, due to the difficulty of replacing CO2 generating chemical processes with others that are absent of CO2 , it is crucial that
these emissions sources are not disregarded.
Chemical Processes Although fossil-fuel oxidation processes produce the majority
of emissions, there is a fraction of emissions generated from chemical processes.
Examples presented in Table 1.2 [15] include cement manufacturing, iron and steel
1.2 CO2 Sources and Sinks
7
production, gas processing, oil refining, and ethylene production. Mitigation associated with the capture of CO2 from these industrial-based processes is small compared
to that of the transportation and electricity sectors; however, there may not be alternatives to the materials created from these processes, such as cement, iron and steel
production, etc. Several of these processes are discussed briefly.
Cement manufacturing results in CO2 emissions sourced from calcination in
addition to the fuel combustion emissions of the cement kilns. Estimated 2008 emissions worldwide from cement production were approximately 2 Gt of CO2 with
approximately 52 and 48% associated with the calcination process and cement kilns,
respectively. Portland cement is a mixture of primarily di- and tricalcium silicates
(2CaO·SiO2 , 3CaO·SiO2 ) with lesser amounts of other compounds including
calcium sulfate (CaSO4 ), magnesium, aluminum, and iron oxides, and tricalcium
aluminate (3CaO · Al2 O3 ). The primary reaction that takes place in this process is
the formation of calcium oxide and CO2 from calcium carbonate, which is highly
endothermic and requires 3.5–6.0 GJ per ton of cement produced.
Within the steel-making process a combination of emissions and the chemical
processes comprise the estimated 1 Gt of CO2 emitted worldwide. Steel-making,
generates CO2 as a result of carbon oxidation to carbon monoxide, which is required
for the reduction of hematite ore (Fe2 O3 ) to molten iron (pig iron). The CO2 is also
sourced from a combination of coal-burning and limestone calcination. In the second
stage of the steel-making process, the carbon content of pig iron is reduced in an
oxygen-fired furnace from approximately 4–5% down to 0.1–1%, and is known as
the basic oxygen steelmaking (BOS) process. Both of these steps produce a steel-slag
waste high in lime and iron content.
In 2008, roughly 630 refineries emitted on average 1.25 Mt each, resulting in
approximately 850 Mt of CO2 emitted in the atmosphere. In an oil refining process,
crude oil, a mixture of various hydrocarbon components ranging broadly in molecular
weight, is fractionated from lighter to heavier components. In a second stage, the
heavier components are catalytically “cracked” to form shorter hydrocarbon chains.
In addition to producing CO2 as a byproduct of the distillation and catalytic cracking
processes, the heat and electricity required for the methane reforming process used
in H2 production for hydrocracking and plant utilities produce additional CO2 .
Recovered natural gas from gas fields or other geologic sources often contains
varying levels of nonhydrocarbon components such as CO2 , N2 , H2 S, and helium.
Natural gas (primarily methane and ethane) and other light hydrocarbons such as
propane and butane, to less extent, are the valuable products in these cases, and
often the generated CO2 is a near-pure stream. Concentrations of approximately
20% CO2 are not uncommon in large natural gas fields. A unique case is Indonesia’s
Natuna field, which commercially produces natural gas containing approximately
70% CO2 [12].
Exhaust Emissions Comparing the sectors (electricity, transportation, industrial,
commercial, and residential), currently the electricity sector is the largest, representing 40% of total U.S. CO2 emissions. Among all the sectors, comparing the different
fossil fuel sources, i.e., coal, petroleum, and natural gas, petroleum constitutes the
8
1 Introduction to Carbon Capture
majority of the emissions at approximately 43%. Carbon capture technologies and
the appropriateness of their application are highly dependent upon the following four
factors: 1) the nature of the application, i.e., a coal-fired power plant, an automobile,
air, etc., 2) the concentration of CO2 in the gas mixture, 3) the chemical environment of CO2 , i.e., the presence of water vapor, acid species (SO2 , NOx ), particulate
matter (PM), etc., and 4) the physical conditions of the CO2 environment, i.e., the
temperature and pressure. A brief discussion of each of these factors highlights their
importance.
The concentration of CO2 plays a role in that the work required for separation
decreases as the CO2 concentration increases. The greater the CO2 content in a given
gas mixture, the easier it is to carry out the separation. This concept will be revisited
toward the end of the chapter. If the CO2 concentration in a gas mixture is too
low then certain separation processes may be ruled out under their current design.
For instance, in order for membrane technologies to be effective, a sufficient driving
force is required. One of the many benefits of membrane technology is reduced capital
cost. Membranes are a once-through technology in that the gas mixture enters the
membrane in one stream and leaves the membrane as two streams, with one of the
streams concentrated in CO2 . But since most of the sources of CO2 are fairly dilute
as shown in Table 1.1, this technology currently has limited application unless novel
measures are taken. The chemical-process-based sources of CO2 tend to have higher
concentrations making these processes targets for membrane technology application.
Examples include ammonia, hydrogen, and ethanol production facilities.
In addition, the chemical environment of CO2 is important when considering the
separation technology since some technologies may have a higher selectivity to other
chemical species in the gas mixture. For instance, in coal-fired flue gas water vapor
and acid gas species such as SO2 and NOx compounds may compete with CO2 for
binding in solution or on a material.
The final factor to consider is the temperature and pressure of the potential CO2
application. If a process occurs at high temperature or pressure it may be possible to
take advantage of the work stored at the given conditions for use in the separation
process. For instance, a catalytic reaction involving CO2 may be enhanced at high
temperature. An example of a catalytic approach for flue gas scrubbing is the case
of NOx reduction to water vapor and N2 from the catalytic reaction of NOx with
ammonia across vanadia-based catalysts. This approach to NOx reduction in a power
plant is referred to as selective catalytic reduction. Noncatalytic NOx reduction, in
which ammonia is injected directly into the boiler is also practiced, but is not as
effective as the catalytic approach [13]. Membrane technology is another example,
in that separation may be enhanced at high pressure.
Carrying out an exergy analysis [14] on a given CO2 generation source and capture
process is a useful exercise, which can aid in determining the potential irreversibilities
associated with each step. Exergy is defined as the amount of energy in a process
that is potentially available to do work. For instance, if one were to design a CO2
separation process that effectively used the thermal energy available at the high
temperature of the flue gas then this would be maximizing the exergy in the system.
The flue gas temperature ranges from approximately 650◦ C at the exit of the boiler
1.2 CO2 Sources and Sinks
9
Table 1.3 Current CO2 -EOR projects taking place in the U.S.a [17]
Location
W. Texas/New
Mexico/Arizona
Colorado/Wyoming
Mississippi/Louisiana
Michigan
Oklahoma
Saskatchewan
Total (MMcfd CO2 )
Total (Mt CO2 )
CO2 sources
Natural CO2 (Colorado/New Mexico)
Gas processing plants (W. Texas)
Gas processing plant (Wyoming)
Natural CO2 (Mississippi)
Ammonia plant (Michigan)
Fertilizer plant (Oklahoma)
Coal gasification plant (North Dakota)
CO2 supply (MMcfdb )
Natural
Anthropogenic
1670
105
–
680
–
–
–
2350
45
230
–
15
30
150
530
10
a
MIT EOR report estimates 65 Mt CO2 for EOR annually [18]
MMcfd stands for one million cubic feet per day of CO2 and may be converted to Mt CO2 per
year by dividing by 18.9 Mcf per metric ton and multiplying by 365
b
down to approximately 40–65◦ C at the stack. Current technologies such as absorption
and adsorption are exothermic processes that are enhanced at low temperatures and in
a traditional sense are not effective strategies for taking direct advantage of the exergy
of the high-temperature flue gas. For instance, the capture of CO2 is most effective at
low temperature for absorption and adsorption processes with the regeneration of the
solvent or sorbent most effective at elevated temperatures. Membrane separation and
catalytic-based technologies, may however, be enhanced at the elevated temperatures
(and pressures) available at exit boiler or gasifier conditions, depending on the specific
technology.
CO2 Usage and Sinks The primary use of CO2 is for EOR, which has been taking
place for several decades, beginning with the Permian Basin located in West Texas and
neighboring area of southeastern New Mexico, underlying an area of approximately
190,000 km2 . The primary source of CO2 for these activities include the natural CO2
reservoirs in Sheep Mountain and the McElmo dome, both located in Colorado,
and Bravo dome in New Mexico. The CO2 gas is transported to the fields of the
Permian Basin through pipeline networks. The existing networks of CO2 pipeline
in the U.S. are discussed in further detail in Chap. 2, Compression and Transport
of CO2 . Currently, on average, CO2 -EOR provides the equivalent of 5% of the
U.S. crude oil production at approximately 280,000 barrels of oil per day [16]. A
limitation of reaching higher EOR production is the availability of CO2 . Natural
CO2 fields provide approximately 45 Mt CO2 per year, with anthropogenic sources
slowly increasing (currently 10 Mt CO2 per year) as illustrated by the list of current
activities in Table 1.3 [17].
Although the discussion of CO2 -EOR thus far has been centered on the usage of
CO2 , EOR may also be a viable approach to potentially store CO2 . For instance, the
CO2 used for EOR is not completely recovered with the oil. In fact, only 20–40% of
the CO2 injected for EOR is produced with the oil, separated, and reinjected for additional production [18]. To date, EOR has not had any financial incentive to maximize
10
1 Introduction to Carbon Capture
CO2 left below ground. In fact, since the cost of oil recovery is closely coupled to the
purchase cost of CO2 , extensive reservoir design efforts have gone into minimizing
the CO2 required for enhanced recovery. If, on the other hand, the objective of CO2
injection is to increase the amount of CO2 left underground while recovering maximum oil, then the approach to the design question changes. If there were such an
incentive, likely an even larger fraction would stay below ground, via modifications
of EOR. Researchers at Stanford University have investigated the co-optimization
of CO2 storage with enhanced oil recovery [19]. Their investigations conclude that
traditional EOR techniques such as injecting CO2 and water in a sequential fashion
(i.e., water-alternating-gas process) are not conducive to CO2 storage. A suggested
modified approach includes a well-control process, in which wells producing large
volumes of gas are closed and only allowed to open as reservoir pressure increases.
In addition to co-optimization of CO2 storage with EOR, ongoing efforts exist for
coupled CO2 storage with enhanced coalbed methane recovery (ECBM) [20] and
potentially enhanced natural gas recovery from gas shales [21].
As previously discussed, postcombustion capture of CO2 has taken place commercially for decades, primarily for the purification of gas streams other than combustion
products. Amine use for CO2 capture was first patented in 1930 [22] and later in
1952 [23] for the purification of hydrocarbons. Since these times, its primary use has
been to meet purity specification requirements for natural gas distribution and the
food and beverage industry. Table 1.4 lists some selected power plant and industrial
facilities that capture, transport, and store (temporarily in the case of the food industry) CO2 in an integrated system. Comparing Tables 1.3 and 1.4, it is interesting
to notice the difference in scale of CO2 usage for EOR versus other industries. The
Bellingham Cogeneration Facility located in Massachusetts generates electricity and
uses a Fluor Econamine FGSM regenerable solvent process and is capable of recovering 85–95% of the flue gas CO2 for food-grade CO2 at 95–99% purity. It is important
to recognize that usage of CO2 in the food industry is not a mitigation option as the
CO2 is subsequently reemitted into the atmosphere, yet the usage of CO2 continues
to drive the advancement of the separation technologies.
One might consider the option of converting CO2 into additional useful products
such as carbonates as previously discussed, but taking a look into the current scale
of the worldwide chemical industry, one quickly recognizes that even if CO2 was
converted to useful products on the scale of every chemical produced worldwide,
this would still constitute less than 5% of the current fossil-based CO2 emissions.
Consider the scale of CO2 emissions associated with each of the primary energy
resources. The annual emissions5 generated from coal, petroleum, and gas are on the
order of 13, 11, and 6 Gt CO2 , respectively [2]. Collectively, the emissions associated
with the oxidation of fossil-based energy resources are on the order of 30 Gt CO2 per
year. Now, consider the top chemicals produced worldwide [24], which are shown
in Table 1.5.
Lime, sulfuric acid, ammonia, and ethylene production are on the order of 283,
200, 154, and 113 million tons in 2009, respectively. If one could capture the CO2
5
Data from 2008, IEA: Coal 12595 Gt CO2 ; Oil 10821 Gt CO2 ; Gas 5862 Gt CO2 .
1991
1996
2004
2005
2008
1978
1991
Startup
year
17
NA
NA
18
NA
43
17
Capacity
(MW)
Amine (Lummus)
Amine (Aker)
Amine (multiple)
Amine (MHI)
Amine (Aker)
Amine (Lummus)
Amine (Fluor)
Solvent
0.11
1.0
1.0
0.12
0.7
0.29
0.11
CO2 captured
(Mt/yr)
CO2 is captured from boiler flue gases and is used to carbonate brine for soda ash (sodium carbonate) production; soda ash is primarily used as a water
softener, but has other uses associated with pH regulation
a
Coal-fired power plant
Natural gas separation
Natural gas separation
Natural gas-fired power plant
Natural gas separation
Coal and petroleum coke-fired boilers
Natural gas-fired power plant
Projects located in the U.S.
IMC Global Inc. Soda Ash Plant (Trona, CA)a
Bellingham Cogeneration Facility (Bellingham, MA)
Projects located outside the U.S.
Soda Ash Botswana Sua Pan Plant (Botswana)
Statoil Sleipner West Gas Field (North Sea, Norway)
BP Gas Processing Plant (In Salah, Algeria)
Mitsubishi Chemical Kurosaki Plant (Kurosaki, Japan)
Snøhvit Field LNG and CO2 Storage Project
(North Sea, Norway)
Plant type
Project name and location
Table 1.4 Selected commercial postcombustion capture processes at power plants and industrial facilities [16]
1.2 CO2 Sources and Sinks
11
12
Table 1.5 Approximate
production of top 10
chemicals produced U.S. and
worldwide in 2009 [24]
1 Introduction to Carbon Capture
Chemical
U.S. (Mt)
World (Mt)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
38.7
32.5
25.0
23.3
19.4
17.0
15.3
13.9
12.0
11.4
199.9
139.6
112.6
100.0
283.0
60.0
53.0
153.9
61.2
22.0
Sulfuric acid
Nitrogena
Ethylene
Oxygena
Lime
Polyethylene
Propylene
Ammonia
Chlorine
Phosphoric acid
a
N2 and O2 are both sourced from air and each have unique
markets
Table 1.6 World CO2 storage
capacity estimates for several
geologic formations [15b, 26]
Geologic formation
Worldwide (Gt CO2 )
Deep saline aquifers
Depleted oil and gas fields
Unmineable coalbeds
1,000–10,000a
200–900
100–300
a
Source: IPCC (2007), deep saline aquifer capacity is
noted as uncertain
at scale and turn it into useable chemicals equating to the current market of these
top chemicals produced, this would mitigate a mere 2.5% of the CO2 generated
worldwide annually. This provides insight into the staggering scale of the fossil-based
CO2 emissions.
Although this book is focused solely on CO2 capture, it is important to recognize
the uses of CO2 that might aid in advancing capture technologies. Additionally, if
CO2 is captured on the scale that is anticipated required for minimizing negative
climate change impacts, the amount of CO2 captured will be far greater than the
current market usage. Carbon dioxide capture and storage (CCS) is expected to be a
primary component of the portfolio of options for mitigating CO2 emissions at the
required scale [15b, 25].
Storage possibilities include the geologic formations: deep saline aquifers, depleted oil and gas fields, and unmineable coalbeds. Table 1.6 lists the CO2 storage
capacity estimates for these primary types of geologic formations considered. The
accurate determination of the storage estimates presented in Table 1.6 is difficult,
which is why the estimates range so broadly [27]. The geological nature of a storage
site can be quite complex and each site can vary considerably.
The market for CO2 use and the storage potential for CO2 exist. The key is to
determine the most effective portfolio of solutions [28] for the variety of emissions
scenarios that exist to capture CO2 for the existing markets. Steam-based electricity
generation was not invented with the anticipation of capturing CO2 ; therefore, it is
reasonable to return to the beginning and to understand the formation pathway of
CO2 from the oxidation of fossil fuel and to possibly consider alternative approaches
1.3 Formation Pathways of CO2
13
to energy generation that could result in higher plant efficiencies with the inclusion
of CO2 capture.
1.3
Formation Pathways of CO2
As discussed previously, the primary sources of CO2 release into the atmosphere
are listed in Table 1.1, with the majority of the CO2 produced from the oxidation
of fossil fuels. Understanding CO2 capture technologies and envisioning solutions
to this challenge requires knowledge of how the CO2 is originally generated. This
involves some background on fuel oxidation mechanisms, combustion science, and
in general fuel-to-energy conversion processes. A more detailed description of the
basic fundamentals of combustion processes is available in Appendix A.
Coal Oxidation Coal is a sedimentary rock formed of fossilized vegetation of different types. Coal may be sourced deep underground (average depths of approximately
600 ft) or close to the surface, having taken up to 400 million years to form under
varying temperature and pressure conditions. The four major classes of coal, also
known as rank, are lignite, subbituminous, bituminous, and anthracite, in order
of youngest to oldest. The lowest ranked coal (lignite) has the lowest carbon content (∼60 mass%) and is highest in volatiles and moisture content, compared to the
highest rank coal, anthracite (carbon content ∼90 mass%) [29]. Coal is a complex
amorphous mixture of carbon, hydrogen, oxygen, sulfur, nitrogen, moisture, ash,
and trace metals. The ideal chemical composition of coal’s three principal elements
can be written as CHm On . Usually, m < 1 and m < n. Coal primarily consists of
carbon, hydrogen, and oxygen, but may also consist of nitrogen and sulfur, which
lead to the formation of NOx and SOx , respectively. Additionally, coal contains
volatile trace metals that evolve from the coal at the high temperature conditions of
the boiler. The trace metals, mercury, selenium, and arsenic are present at ppb levels
in most flue gases [30]. However, it is important to note that depending on the type
of coal and source from which the coal was mined, the chemical constituents may
vary significantly. The chemical composition of coal varies greatly depending upon
its rank and origin. Although coal combustion is a complex process since all coal is
unique, in general it is consistent in that initially moisture and volatiles are driven
off, followed by direct carbon oxidation.
Coal combustion is a heterogeneous reaction involving the oxidation of coal
through the transport to and subsequent reactivity of O2 with its surface. Heterogeneous implies that two phases are taking part in the reaction, i.e., the solid coal
surface and oxygen in the gas phase. The coal is comprised of pulverized porous
particles ranging in size from 75–300 μm depending upon the boiler type. Gas-phase
species reacting with the coal surface must diffuse through the intricate pore network
within the coal particles as depicted by the scanning electron microscopy image in
Fig. 1.4. In reality, the coal surface may be oxidized by a combination of species
present in the gas phase, that is, O2 , CO2 , and H2 O proceeding by the following
14
1 Introduction to Carbon Capture
Fig. 1.4 Scanning electron microscopy images of subbituminous coal. The image on the right is a
magnification of the particle on the left, both on the micron scale. (Courtesy of [1])
global reactions:
C + O2 → CO2
(1.1)
2C + O2 → 2CO
(1.2)
C + CO2 → 2CO
(1.3)
C + H2 O → CO + H2
(1.4)
A global reaction is one that is comprised of a series of elementary reactions, which
are reactions that proceed as they are written. For instance, Reaction (1.1) is not
elementary since the formation of gas-phase CO2 in this case would involve a series
of elementary steps such as O2 adsorption, O2 bond stretching, CO bond forming, etc.
At the high temperatures of coal combustion, a dominating reaction is heterogeneous
carbon oxidation to the formation of CO, followed by homogeneous CO oxidation
by O2 to CO2 .
Coal-to-Electricity Conversion Just under 50% of the electricity generated in the
U.S. is powered by coal-fired steam power plants. Figure 1.5 is a simplified version
of a power plant with the basic components responsible for generating power. Understanding the coal-to-electricity conversion process allows one to appreciate the
life cycle of CO2 from the oxidation of the coal’s carbon surface to the exit of the
stack. Figure 1.5 also shows how other scrubbing technologies have been arranged
downstream of the boiler exit. For instance, NOx reduction (i.e., mitigation) is taking
place here using a high-temperature catalyst so its placement is at the boiler exit to
maximize the thermal energy required for enhanced conversion. The removal of SOx
with an absorption set-up is placed at the lowest temperature available since absorption is an exothermic process. For CO2 capture, an additional scrubbing unit would
be placed in this plant configuration, with its exact location dependent upon the type
of separation process used (e.g., absorption, adsorption, membrane, or catalytic).
The steps of coal conversion to electricity are complex in reality, but are simplified
here for a general understanding of the process:
Fig. 1.5 Coal-fired power plant (Courtesy of The Babcock & Wilcox Company)
1.3 Formation Pathways of CO2
15
16
1 Introduction to Carbon Capture
1. During startup, the furnace is pre-heated by combustion of auxiliary fuel such as
natural gas or oil;
2. Pulverized coal powder is blown with air into a combustion chamber (boiler or
furnace) through a series of nozzles; combustion of the coal particles creates hot
combustion products;
3. Heat is transferred from the hot combustion products to water circulating in tubes
along the boiler walls; this produces superheated steam, which is the working
fluid for the steam turbines;
4. Pumps are used to increase the pressure of the working fluid;
5. Energy from the hot and pressurized steam is extracted in steam turbines that then
transmit the energy to electric generators;
6. The electric generators convert the shaft work of the turbines into alternating
current electricity;
7. Heat exchangers are used to condense the energy-drained steam from the turbines;
8. Pumps are used to return the condensed water to the boiler, where the cycle is
then repeated; and
9. Pollution control devices are used to scrub the flue gas of NOx (selective catalytic
reduction), particulate matter (electrostatic precipitators and/or fabric filters), and
SO2 (calcium-based flue gas desulfurization units or lime spray dryers). Some
power utilities are also equipped with activated carbon injection processes to
capture mercury emissions; currently there are no full-scale CO2 capture methods
in place.
Liquid Fuel and Natural Gas Oxidation Converting petroleum to power requires
evaporation and burning of a liquid fuel. Applications include diesel, rocket, and
gas-turbine engines, oil-fired boilers and furnaces. In liquid fuel oxidation, the fuel
is first vaporized and then combusted. Gas combustion may occur with or without
flame, and flames are usually characterized as premixed or diffusion flames. In flame
combustion, a reaction zone (flame) propagates through an air-fuel mixture where
the hot combustion products are left behind the flame with temperature and pressure
rising in the unburned fuel. In flameless combustion, rapid oxidation reactions occur
throughout the fuel leading to very rapid combustion. The volumetric exothermicity
that takes place in an engine is called autoignition. Premixed versus diffusion flames
are characterized by the level of mixing that takes place between the fuel and oxidizing agent. A spark-ignition engine is an example in which the fuel and oxidizing
agent are mixed prior to any combustion activity. On the other hand, within a diffusion flame the fuel is initially isolated from the oxidizing agent and the combustion
reaction takes place simultaneous to mixing with flame propagation at the interface
of the fuel and oxidant.
There are clear distinctions between the oxidation processes of coal, petroleum,
and gas and subsequent differences between the mechanisms of CO2 generation
in each case. Understanding more thoroughly the nature by which CO2 is formed
may lead to advancements in fuel-to-energy conversion processes that minimize its
generation. The capture of CO2 in a traditional pulverized coal combustion process
is termed postcombustion capture (PCC), since capture is taking place after the
1.4 Advanced Coal Conversion Processes
17
Table 1.7 Approximate efficiencies of various plants with and without CO2 capture (CC) [31]
Plant type
Plant efficiency w/out CC (%)a
Plant efficiency w/CC (%)
Coal, subcritical
Coal, supercritical
Coal, ultrasupercritical
NGCCb
IGCCc
33–39
38–44
43–47
45–51
37–44
23–25
29–31
34–37
38–43
32–39
a
Plant efficiency is based upon the high heating value (HHV) of the fuel
NGCC refers to a natural gas combined cycle power plant
c
IGCC refers to an integrated gasification combined cycle power plant
b
combustion process. Another possibility is to modify the fuel-to-energy conversion
process to maximize the concentration of CO2 as to minimize the work associated
with its separation.
1.4 Advanced Coal Conversion Processes
When fuel oxidation was first carried out for energy generation there was no intention
to capture the CO2 generated from the process. Air being the primary source of fuel
oxidation is approximately 78% N2 , 21% O2 , and 0.95% Ar by volume on a dry
basis, i.e., excluding moisture content (plus trace amounts of CO2 , Ne, He, Kr, and
Xe) [30]. The N2 is predominantly an inert gas throughout the combustion process,
thereby diluting the CO2 generated in the flue gas stream and increasing the work
required for CO2 separation. Table 1.7 shows the difference in the efficiency with
and without CO2 capture for various plants.
Advanced coal conversion processes6 are currently under development that reduce
the work required for separation by creating CO2 -concentrated gas outlet streams.
These include coal gasification, oxycombustion, and chemical looping combustion.
These processes in fact, could be carried out on any fossil-based energy resource.
Coal is primarily discussed since this is the most common energy resource available
worldwide. Figure 1.6 shows the pathway of each advanced energy conversion process with the energy resource options as coal, biomass, waste, petroleum coke/residue
or natural gas.
Gasification Coal gasification is a process in which the oxidation of coal is kept
at a minimum, with just enough exothermicity to provide the required energy for
driving the gasification reactions. The heat is controlled through the control of air
6
Although not discussed specifically, another energy conversion option is electrochemical conversion in a direct carbon fuel cell. Challenges are associated with the accessibility of the oxidizer to
the electrochemical reaction sites, but progress continues to be made in this field. [51, 52] Electrochemical conversion processes are described in more detail in Chapter 8, but are focused on CO2
reduction toward fuel synthesis, in which energy (renewable) is required as an input, rather than
direct carbon (e.g., coal, biomass, etc.) oxidation toward energy production.
18
1 Introduction to Carbon Capture
Fig. 1.6 Schematic of primary options for CO2 capture from various hydrocarbon-based energy
conversion processes
or more often, oxygen input into the gasifier. A limitation of gasification is the
need for an air separation unit (ASU) for the generation of high-purity O2 as a feed
gas to the gasifier. The gasification process suppresses the formation of water and
instead produces primarily CO and hydrogen gas (H2 ). IGCC systems operate at high
pressures (e.g., 500–700 psia) and require the oxidant stream to also be pressurized.
Gasification takes place rapidly at temperatures above 1260◦ C, which is greater than
the ash fusion temperature, allowing ash to become molten and separating easily
from the gas. In addition to H2 and CO, CH4 is generated in small amounts and H2 S
is also generated depending upon the extent of sulfur present in the energy resource.
The hot and pressurized synthesis gas exits the gasifier and a particulate control
device then removes particulate matter, after which steam is added to the fuel gas
(also known as synthesis or syngas) to promote the conversion of H2 and CO2 , which
is called the water gas shift reaction, i.e.,
CO + H2 O ↔ CO2 + H2
(1.5)
1.4 Advanced Coal Conversion Processes
19
Fig. 1.7 Detailed schematic of an integrated gasification combined cycle (IGCC) plant
and is exothermic by approximately 41 kJ/mol CO2 generated. The reaction is
equilibrium-limited, leading to an increase in conversion as temperature decreases.
The current industrial approach is to cool and clean the fuel stream before entering a
high-temperature shift reactor at approximately 315–445◦ C.This step is sometimes
followed by a low-temperature shift reactor that operates at approximately 200–
250◦ C. The equilibrium can be shifted using a catalytic metallic membrane reactor
selective to the removal of H2 on the right hand side of Reaction (1.5). These types
of reactors will be discussed in more detail in Chap. 5 on Membrane Technology.
Shifting the equilibrium to optimize conversion is preferred, since this limits the
cooling required of the gas stream.
The concentration of CO2 in this process is substantially greater than in coal
combustion making its separation from the fuel gas mixture easier. The capture of
CO2 in an IGCC process is termed precombustion capture since the fuel combustion
takes place after the capture process as demonstrated in Fig. 1.7. For electricity
generation, the synthesis gas (largely hydrogen) is burned directly and then passed
through a gas turbine for electricity generation. The heat recovered from this process
is used to generate steam, which is passed through a steam turbine for additional
electricity generation, resulting in a combined cycle. The efficiency of an IGCC
plant is on the order of 37–44%, compared to a newer existing ultrasupercritical
pulverized coal-fired power plant, which is on the order of 43–47%. It is important
to recognize the competition that will likely exist between steam and gas processes
as technologies are advanced (i.e., turbine technology) toward the handling of gas.
Although the cost of electricity of a traditional coal combustion power plant is lower
than that of an IGCC plant, with the inclusion of CO2 capture, the efficiency is higher
(see Table 1.7) and hence the cost is less in the gasification case [33].
20
1 Introduction to Carbon Capture
Fig. 1.8 Schematic of fuel and chemical products produced from a synthesis gas via the FischerTropsch (FT) process
Fischer-Tropsch Process Rather than directly combusting the synthesis gas in
an IGCC process, the syngas may also be converted to fuel and/or chemicals via
Fischer-Tropsch (FT) synthesis. The original inventors of the process were Franz
Fischer and Hans Tropsch, who worked at the Kaiser Wilhem Institute during the
1920s. The first commercialization took place in 1934, with the first industrial plant
in operation in Germany in 1936, with annual production of over 1 million tons of
FT liquid fuel at that time. The largest scale FT operation, based on a coal-to-liquid
(CTL) conversion process, is operated by Sasol in South Africa, which is high in coal
reserves and low in petroleum [34]. Due to oil embargos in opposition to Apartheid,
South Africa advanced their CTL process in an attempt to gain independence from
petroleum [35]. Figure 1.8 demonstrates the flexibility of the FT process in terms of
the variety of petroleum-based products that can result.
An important parameter for controlling the FT conversion and selectivity is the
hydrogen-carbon ratio (H/C). The required H/C ratio for commercial production of
hydrocarbon fuels, i.e., Diesel and gasoline is approximately 2 on a molar basis, while
the ratio ranges from 1.3–1.9 for petroleum crude oil and 0.8 for typical bituminous
coals [36]. A critical challenge for FT conversion is increasing the H/C ratio or the
H2 /CO ratio. The hydrogen content in the syngas enhances the conversion efficiency
toward the production of hydrocarbon products, with the additional hydrogen sourced
from steam during the gasification step. Steam reacts with CO resulting in the watergas shift reaction (i.e., CO + H2 O ↔ CO2 + H2 ). The effect of the water-gas shift
reaction can be varied depending on the type of FT catalyst, with the direction of the
1.4 Advanced Coal Conversion Processes
21
water-gas shift equilibrium dependent on the syngas composition [37]. Though the
H/C or the H2 /CO ratio for the FT process is increased through the addition of steam,
there is a subsequent efficiency penalty associated with the use of steam generated
from the gasifier, in addition to the condensation of unused steam after the FT reactor.
The future of coal-to-liquid processes may be limited due to: 1) its competition with
existing “alternative liquid fuels,” such as biofuels, as well as 2) its inevitable result
of net CO2 emissions since the H:C ratio is higher in liquids than in coal.
Oxyfuel Combustion Sometimes referred to as oxycombustion, oxyfuel combustion involves an ASU to allow coal to be burned in an oxygen-enriched environment,
which leads to minimal dilution of CO2 in the flue gas stream. The flue gas stream in
an oxyfuel combustion process includes primarily CO2 and water vapor, which can
be condensed out fairly easily. To prevent the temperatures in the boiler from getting
too large, up to 70% of the flue gas stream is recycled back to dilute the oxygenenriched environment and maintain temperatures similar to conventional air-blown
designs. Major challenges associated with the application or retrofit of oxyfuel combustion on an existing power plant is the cost of the ASU and potential leakage of
air into the flue gas stream. It is important to keep in mind, however, that a typical
stream from an ASU may contain approximately 3% N2 and 2% Ar depending upon
the method used for separation. In general, major oxyfuel developers now see the
primary application in new plants, or at existing plants that are “repowered” with
modern and more efficient boilers. The following demonstration plants are currently
in place: Vattenfall in Sweden [38], IHI in Japan [39], and Alstom Power in the
U.S. [40], with 2 × 900, 1000, and 450-MW capacities, respectively. Although the
cost of electricity is greater from an oxyfuel combustion plant compared to a coalfired plant with air, it has been shown that the cost may be lower with the inclusion
of CO2 capture [41].
Chemical Looping Combustion The chemical looping combustion process involves the injection of metal oxides into the boiler that act as oxygen transporters
(rather than air) for coal of natural gas oxidation, similar to the other processes previously discussed, minimizing the dilution of CO2 in the flue gas stream [42]. Within
the chemical looping process, the solid oxygen carrier circulates between two fluidized bed reactors to transport oxygen from the combustion air to the fuel. Typical
metal oxides include iron and nickel. Iron is low cost and nonhazardous making it an
optimal choice. The metal oxide is reduced in a fuel reactor (i.e., reduction reactor)
while oxidizing the fuel and is then transported into an air reactor (i.e., oxidation
reactor) where it is reoxidized by air. The carrier particles are then transported back
into the fuel reactor after passing through a cyclone for separation from the hot N2
and O2 gases. Benefits of this process are similar to those of oxyfuel combustion,
i.e., the flue gas is not diluted with N2 and this process leads to lower NOx formation.
However, it is important to note that the majority (∼70%) of the NOx formed is not
from the N2 in the combustion air, but rather, from the surface functional groups on
the coal itself. A simple schematic demonstrating the principle of chemical looping
combustion is shown in Fig. 1.9. Additional details regarding these advanced coal
conversion processes are available in the literature [43].
22
1 Introduction to Carbon Capture
Fig. 1.9 Schematic demonstrating the principle of chemical looping combustion
1.5
Minimum Thermodynamic Work for CO2 Separation
The first law of thermodynamics is concerned with the conservation of energy. The
change in total energy of the system going from state 1 to state 2 is equal to the heat
added to the system minus the work done, and can be expressed as,
Q − W = E1→2 ,
(1.6)
in which Q and W may be positive or negative with the sign indicating the direction
of energy flow. Examples of energies include internal energy, kinetic energy, and
potential energy. The internal energy is comprised of the molecular energies within
a given system, more specifically these include the energy contributions from the
translational, vibrational, and rotational degrees of freedom within a molecule. Kinetic energy can be expressed as 21 mv2 , where m is the mass of a moving object
and v is its velocity. Potential energy can be expressed as mgz, where m is the mass
of a stationary object, g is the acceleration due to gravity, and z is elevation. Additional energies exist such as nuclear, electromagnetic, etc., but are not necessary for
discussion in the context of CO2 capture.
The second law of thermodynamics is concerned with entropy, which is generated
during irreversible processes. Examples that include such irreversibilities are heat
transfer across a temperature gradient, friction, mixing or stirring processes, and
1.5 Minimum Thermodynamic Work for CO2 Separation
23
Fig. 1.10 Schematic of
carbon capture
many chemical reactions. Irreversible processes prevent a system from returning to
its original state and additionally, they reduce the available work (i.e., exergy) of a
given system.
The minimum work required to separate CO2 from a gas mixture can be calculated
based upon the combined first and second laws of thermodynamics. Figure 1.10 is
a representation of the a generic CO2 separation process along with the general
emissions source and capture technology with corresponding gas streams. Stream A
represents a CO2 -inclusive gas stream mixture (not limited to a combustion exhaust)
while stream B contains mostly CO2 depending upon the process purity, and stream
C contains primarily the remainder of gas stream A. Ideally, stream B would be
mostly (or all) CO2 and stream C would be very low (or zero) in CO2 .
The minimum work required for separating CO2 from a gas mixture for an isothermal (constant temperature) and isobaric (constant pressure) process is equal to the
negative of the difference in Gibbs free energy of the separated final states (streams
B and C in Fig. 1.10) from the mixed initial state (stream A in Fig. 1.10). For an
ideal gas (minimal gas species interactions), the Gibbs free energy change between
stream A to streams B and C is:
Wmin = Gsep = GB + GC − GA
(1.7)
For an ideal mixture, the partial molar Gibbs free energy for each gas is [44, 45]:
∂G
pi
◦
= Gi + RT ln
(1.8)
∂ni
p
such that pi is the partial pressure of the ith gas and p is total pressure. Therefore,
the total Gibbs free energy of an ideal gas mixture is:
∂G
GTOTAL =
ni
(1.9)
∂ni
i
The minimum work required to go from state 1 to states 2 and 3 is associated with
the free energy difference between the product and reactant states, which can be
calculated by combining Eqs. (1.8) and (1.9) as:
A−CO2 ◦
CO2
CO2
A−CO2
A−CO2
◦
2
GA = nCO
+
n
G
+
n
G
+
RT
n
ln
y
ln
y
CO2
A−CO2
A
A
A
A
A
A
B−CO2 ◦
CO2
CO2
B−CO2
B−CO2
◦
2
GB = nCO
G
+
n
G
+
RT
n
ln
y
ln
y
+
n
CO2
B−CO2
B
B
B
B
B
B
C−CO2 ◦
CO2
CO2
C−CO2
C−CO2
◦
2
GC = nCO
G
+
n
G
+
RT
n
ln
y
ln
y
+
n
,
CO2
C−CO2
C
C
C
C
C
C
(1.10)
24
1 Introduction to Carbon Capture
Fig. 1.11 Minimum thermodynamic work for various coal or gas-to-electricity conversions
And thus the minimum work is:
CO2
2
2
Wmin = RT nCO
ln yBB−CO2
+ nB−CO
B ln yB
B
CO2
2
2
+ RT nCO
ln yCC−CO2
+ nC−CO
C ln yC
C
CO2
A−CO2
A−CO2
2
− RT nCO
+
n
ln
y
ln
y
A
A
A
A
(1.11)
where R is the ideal gas constant (8.314 J/mol K), T is the absolute temperature,
yiCO2 is the mole fraction of CO2 in the gas mixture, i, such that i can represent either
stream A, B, or C in Fig. 1.10, and yii−CO2 represents the remainder of a given gas
stream A, B, or C. The quantity of greatest interest is the minimum work per mole
of CO2 removed, that is, Wmin /(nCO2 ). For T = 25◦ C (298 K), the minimum work
when beginning with coal flue gas at 12% CO2 , is 172 kJ/kg CO2 ; when beginning
with air at 0.04% CO2 , is 497 kJ/kgCO2 , which is approximately a factor of three
greater. The minimum work required for separation is highly dependent upon the
starting concentration of CO2 in a given gas mixture.
Figure 1.11 is a plot of the minimum work, Wmin at varying temperatures for
CO2 separation as a function of the molar concentration of CO2 in the initial gas
mixture. As the concentration of CO2 decreases, the minimum work required for
separation increases. Additionally, an increase in temperature leads to an increase in
the thermodynamic minimum work required for separation.
1.5 Minimum Thermodynamic Work for CO2 Separation
Example 1.1 Assume a 500-MW coal-fired power plant emits a flue gas
containing 4 kmol CO2 /s, 5 kmol H2 O/s, 1 kmol O2 /s and 20 kmol N2 /s. What
is the minimum work for the isothermal and isobaric separation of CO2 from
the flue gas mixture for 90% capture and 98% purity at 45◦ C?
Solution
Given: ṅCO2 = 4 kmol CO2 /s
ṅO2 = 1 kmol O2 /s
Capture = 0.90
ṅH2 O = 5 kmol H2 O/s
ṅN2 = 20 kmol N2 /s
Purity = 0.98
Using Eq. (1.11),
CO2
2
2
Wmin =RT nCO
ln yBB−CO2
+ nB−CO
B ln yB
B
CO2
2
2
+ RT nCO
ln yCC−CO2 ,
+ nC−CO
C ln yC
C
CO2
2
2
− RT nCO
+ nA−CO
ln yAA−CO2
A ln yA
A
where stream A is the flue gas mixture entering the separator, stream B at
98% purity contains 90% of the CO2 contained in stream A, and stream C
contains the remaining 10% of the CO2 contained in stream A. Performing a
mole balance on the separator yields:
2
Stream A: ṅCO
= 4 kmol CO2 /s
A
2
ṅA−CO
= 26 kmol A − CO2 /s
A
ṅA = 30 kmol A gas/s
yACO2
= 0.13
yAA−CO2 = 0.87
2
= (4 kmol CO2 /s)(0.90) = 3.6 kmol CO2 /s
Stream B: ṅCO
B
ṅB = (3.6 kmol CO2 /s)/(0.98)
= 3.67 kmol B gas/s to ensure 98% purity
2
ṅB−CO
B
= 3.67 kmol B gas/s − 3.6 kmol CO2 gas/s
= 0.07 kmol B − CO2 /s
yBCO2
= 0.98
yBB−CO2 = 0.02
2
= (4 kmol CO2 /s)(0.1) = 0.4 kmol CO2 /s
Stream C: ṅCO
C
ṅC = ṅA − ṅB
= 26.33 kmol C gas/s from the system (separator) molar
balance
25
26
1 Introduction to Carbon Capture
2
ṅC−CO
= 26.33 kmol C gas/s − 0.4 kmol CO2 gas/s
C
= 25.93 kmol C − CO2 /s
yCCO2 = 0.015
yCC−CO2 = 0.985
The flue gas is entering the separator at 45◦ C or 318 K. Substituting these
values into Eq. (1.11) yields a thermodynamic minimum work of 24,756 kJ/s
or 6.88 kJ/mol CO2 captured, with a CO2 capture rate of 3.6 kmol CO2 /s.
2nd-Law Efficiency Real systems will always use more energy than the thermodynamic minimum since the minimum is derived for a reversible isothermal process.
The capture of CO2 or more specifically, separating CO2 from a gas mixture, takes
significant work for dilute mixtures of CO2 and additional work for increased capture
and purity. The separation process may depend upon current technologies such as
absorption, adsorption, membranes, or some hybrid approach that has yet to be developed. Take for example absorption, which is outlined in Chap. 3; within this process
blowers are used to drive a flue gas upward through a packed bed or spray tower,
in which a liquid solvent is driven downward countercurrently using pump work.
Additional work is required through the addition of heat for the solvent regeneration
process, which drives the CO2 off in a pure stream for compression, which also takes
work. Each of these processes have associated efficiencies based upon irreversibilities, such as friction, heat transfer, gas expansion, gas mixing, etc.; therefore, the
actual work required for CO2 separation from a gas mixture deviates from the thermodynamic minimum work based upon the unit operations of the process and the extent
of their individual inefficiencies. The ratio of the reversible or thermodynamic minimum work to the real work is termed the 2nd-Law efficiency [46] and is defined as:
η2nd =
Wmin
Wreal
(1.12)
The chemistry and physics of the underlying mechanisms of the various unit
operations are discussed in the following chapters and analyzed in addition to the
design and process in which the underlying chemistry and physical principles exist.
Through the investigation of each of the steps in the given separation process there
will be the opportunity to question and probe the actual work required of a given
process and to assess the sensitivity of potentially tuning the related parameters to
maximize the process’s 2nd-law efficiency.
The 2nd-law efficiency has been investigated for a variety of gas scrubbing processes that span a wide range of concentrations. In Fig. 1.12, the 2nd-law efficiency is
plotted as a function of decreasing concentration for 90% CO2 capture from coal-fired
power and NGCC plants, as well as for varying levels of NOx , SOx and mercury (Hg)
scrubbing. For all “actual” work calculations, the Integrated Environmental Control
Module developed by Rubin et al. [47] from Carnegie Mellon University was used.
In the case of the postcombustion capture of CO2 , SOx , NOx , and Hg it was assumed
1.6 Cost of CO2 Capture
27
Fig. 1.12 Plot showing the relationship between the 2nd-law efficiency and concentration of initial
gas mixture
that low-sulfur Appalachian bituminous coal was burned in a 500-MW utility boiler.
The capture technologies assumed for CO2 , SOx , NOx , and Hg consisted of amine
scrubbing, wet flue gas desulfurization, selective catalytic reduction, and activated
carbon injection, respectively. In the case of NGCC, precombustion separation based
upon amine scrubbing is assumed for a 477-MW plant. It is interesting to note that
the 2nd-law efficiency decreases with decreasing CO2 concentration [48]. This implies that there are still efficiencies to gain in SOx , NOx , and Hg capture since these
processes do not include regeneration, yet they still follow the trend.
1.6
Cost of CO2 Capture
Costs of separation may be divided into technical versus non-technical costs. Examples of non-technical costs may include account depreciation and return on
investment, interest rate, labor, etc. Costs associated with the technology include
the cost of the equipment, chemicals used, power consumption to operate the separation process, power cost, etc. Additional factors that may affect the cost of CO2
capture include the choice of power plant and capture technology. For instance, will
an existing plant be retrofitted or will the capture technology be applied to a new
plant? The process design and variables associated with plant operation, such as plant
28
1 Introduction to Carbon Capture
Fig. 1.13 Sherwood plot of various gas scrubbing processes demonstrating the cost increase with
decreasing concentration
capacity, capture rate, and CO2 concentration in and out will also influence costs.
The system boundaries may influence the cost, for instance whether the capture technology is implemented on one facility or multiple plants or whether there will be
energy resource integration to power the capture process, such as the implementation
of natural gas, nuclear, wind, or solar. Whether a plant is a first-of-a-kind or nth plant
may also influence the cost as technology is learned and advanced with time.
The Sherwood plot [49] has proved to be a useful correlation for estimating the
separation cost as a function of starting concentration. Figure 1.13 provides a Sherwood plot demonstrating the relationship between cost increase with increasingly
dilute gas mixtures. Based upon the previous assumptions from the data plotted in
Fig. 1.12, the Sherwood correlation is illustrated in Fig. 1.13. The concentration of
each of these species in the flue gas is also listed in Table 1.8. It is clear that an
increase in dilution in the flue gas is correlated with an increase in the unit cost of
capture. The cost-to-concentration relationship for medium-sulfur coal compared to
the low-sulfur coal, i.e., 1270 versus 399 ppm, is also consistent with this trend. Similarly, amine scrubbing for a 477-MW NGCC power plant generating approximately
3.7 mol% CO2 follows the trend in that it is higher in cost compared to PCC in which
the CO2 concentration is approximately 12 mol% CO2 . Lightfoot and Cockrem [49]
described this concept well in a publication titled, What Are Dilute Solutions? Their
1.6 Cost of CO2 Capture
29
Table 1.8 Cost and scale of various coal and natural gas oxidation processes
Process
Price
($/kg)
Concentration
(mole fraction)
Emissions
(kg/day)
Cost
(1000s $/day)
CO2 –PCC
CO2 –NGCC
SOx (MS)
SOx (LS)
NOx
Hg
0.045
0.059
0.66
2.1
1.1
22000
0.121
0.0373
0.00127
0.000399 (399 ppm)
0.000387 (387 ppm)
5 × 10−9 (5 ppb)
8.59 × 106
3.01 × 106
8.94 × 104
2.32 × 104
1.11 × 104
0.951
392
178
59.6
50.4
12.5
21.6
assessment was that the “recovery of potentially valuable solutes from dilute solution
is dominated by the costs of processing large masses of unwanted materials.” It is
interesting to consider DAC in this context as CO2 is present in the air at similar concentrations of NOx in flue gas. However, the scale of the CO2 emissions compared
to NOx as shown in Table 1.8, makes this approach to CO2 mitigation less desirable
than capture from more concentrated sources. Similar to the results of Table 1.8,
recent investigations [48, 50] have concluded that cost estimates may be as high as
$1000 per ton of CO2 for DAC.
Defining the Cost of CO2 Avoided and Captured Imagine that a CO2 capture
system is installed at a fossil-fuel power plant, and that the energy required to operate
the capture system is provided by fossil fuels. In principle, nothing prevents the
capture system from emitting more CO2 than it captures. Such a system would be
counterproductive, however. One needs a vocabulary that distinguishes the gross CO2
removed by a capture device and the net CO2 that does not enter the atmosphere,
which is the gross CO2 removed minus the CO2 emitted by the capture system itself.
The concepts of gross and net CO2 prevented from entering the atmosphere are called
“captured CO2 ” and “avoided CO2 .” Avoided CO2 is always less than captured CO2
since any capture system will emit some CO2 . Equivalently, the cost of avoided CO2
(in dollars per ton of CO2 ) is always greater than the cost of CO2 captured.
Figure 1.14 provides a schematic demonstrating the differences between CO2
captured versus CO2 avoided for a typical power plant application, assuming that
the capture plant captures and stores 90% of the total generated CO2 emissions and
that some CO2 emissions will be associated with the energy needed to operate the
capture process itself. Thus, the cost of CO2 avoided is the cost of delivering a unit of
useful product (in this case, electricity) while avoiding a ton of CO2 emissions to the
atmosphere. Avoidance costs should always include the cost of CO2 compression,
transport and storage since “avoided” means not emitted into the atmosphere.
The cost of CO2 avoided for a power plant, Cavo , is calculated on a net kWh basis
by the equation,
$
/kWh cap − $ /kWh ref
(1.13)
Cavo $/ton CO2 = CO
CO2 /
2/
kWh ref −
kWh cap
such that $ /kWh ref and $ /kWh cap represent the cost per net kWh of electricity
produced by the reference and capture plant, respectively and CO2 /kWh ref and
30
1 Introduction to Carbon Capture
Fig. 1.14 Schematic demonstrating the difference in CO2 captured versus CO2 avoided for a pointsource capture scenario. Here, the capture plant produces the same useful product output as the
reference plant, so additional capacity is needed to operate the capture system. For a power plant
all values are typically normalized on the net kWh generated
CO
/kWh cap represent the tons of CO2 emitted to the atmosphere per net kWh of
electricity produced by the reference and capture plant, respectively.
In contrast, the cost per ton of CO2 captured, Ccap , can be calculated by the
equation,
$
/kWh cap − $ /kWh ref
Ccap $/tonCO2 =
(1.14)
CO2 /
kWh cap
2
such that the numerator again represents the incremental cost of the capture system, while the denominator is the quantity of CO2 captured, with all values again
normalized on the net plant output. The key difference from Eq. (1.13) is that the
capture cost does not include the cost of energy to operate the capture system; nor
does it typically include the costs of CO2 transport and storage. Thus, the cost per
ton captured is always less than the cost per ton avoided.
For a co-generation power plant that produces both electricity and heat, costs and
emissions can be normalized on the total equivalent thermal energy output (in kJ).
For other types of point sources, such as an oil refinery stack or a cement plant,
costs and emissions would be normalized on the relevant measure of useful output
(e.g., barrels of oil or tons of cement) when calculating the cost of CO2 avoided or
captured.
Cost for Direct Air Capture For CO2 removed directly from the atmosphere
(a concept being developed, but not yet practiced on a commercial scale) there
is no reference plant or specific product associated with the capture system, as with
point sources. Nonetheless, the concepts of gross and net CO2 removal from the
References
31
Fig. 1.15 Schematic
demonstrating the difference
between CO2 captured versus
CO2 generated for a DAC
scenario
atmosphere are analogous to those associated with emission prevention. The two
analogous concepts are again called CO2 captured (gross) and CO2 avoided (net).
The amount and cost of CO2 captured in the case of DAC is defined in the same way
as the previous method, namely the incremental cost of the capture system divided
by the amount of CO2 captured. Thus,
$ /yr
(1.15)
Ccap,DAC $/ton CO2 = CO DAC
2/
yr DAC
where the numerator is the levelized annual cost of the capture system and the
denominator is the annual average amount captured.
Figure 1.15 shows a schematic demonstrating the difference between avoided
versus captured. In the case of DAC there is only a capture plant since the CO2
emissions are captured directly from air, compressed, transported, and stored (or
sequestered). Similar to the point source definition, however, allowance is made for
the generation of emissions associated with the purchased energy resource(s) used
to fuel the DAC plant and the energy required to capture a given number of tons of
CO2 from the air. Effectively, the cost of CO2 avoided is the cost of the capture plant
(plus transport and storage costs) divided by the net amount captured, rather than
the total amount.
The cost of CO2 avoided, Cavo,DAC , in the case of DAC can be calculated by,
$ $ /yr DAC
/yr
Cavo,DAC $/ton CO2 = CO
= CO DAC
(1.16)
CO2 /
2/
2/
−
yr DAC
yr gen
yr net
such that the numerator represents the total annualized cost of building and operating
the DAC plant and the denominator represents the net number of tons captured
per year from the DAC plant. Energy to operate the plant typically will be some
combination of electricity and heat sourced by fossil fuels or renewables.
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