POLICY ANALYSIS pubs.acs.org/est
Analysis and Status of Post-Combustion Carbon Dioxide Capture Technologies Abhoyjit S. Bhown* and Brice C. Freeman Electric Power Research Institute (EPRI), 3420 Hillview Avenue, Palo Alto, California 94304, United States
bS Supporting Information ABSTRACT: The Electric Power Research Institute (EPRI) undertook a multiyear effort to understand the landscape of postcombustion CO2 capture technologies globally. In this paper we discuss several central issues facing CO2 capture involving scale, energy, and overall status of development. We argue that the scale of CO2 emissions is sufficiently large to place inherent limits on the types of capture processes that could be deployed broadly. We also discuss the minimum energy usage in terms of a parasitic load on a power plant. Finally, we present summary findings of the landscape of capture technologies using an index of technology readiness levels.
’ INTRODUCTION A number of governmental agencies at the state, federal, and international levels are actively discussing limitations on the emissions of greenhouse gases (GHG), including CO2. The electricity generation industry is among the first group of emission sources being targeted for GHG reductions, including CO2, because coal-fired power plants are the largest stationary point-source emitters of anthropogenic CO2.1 Regulations requiring the electric generation industry to reduce CO2 emissions have already emerged at the state2 and local levels, and are expected at the national level in the United States. Even without explicit legislation, requests to add new coal-fired power plants are being denied at the local permitting level on the basis that they do not include CO2 controls at the onset or have no plans to add them in the near term.3 Indeed in 2009, coal supplied only 44.5% of U.S. electricity, down from 48.2% in 2008 and over 50% in years prior.4 Table 1 shows that in 2008, CO2 emissions from electricity generation in the U.S. accounted for about 40% of anthropogenic CO2 emissions and 34% of the total anthropogenic GHG emissions.5,6 Globally, approximately 31.2 Gt CO2 was emitted in 2008 from fossil fuel combustion and cement, dropping by 1.3% in 2009.7 One option for controlling CO2 emissions is carbon capture and storage (CCS), where CO2 is separated from flue gas and permanently stored in large subsurface geologic reservoirs. In part, due to the absence of national and international regulations, or limited carbon markets, no postcombustion CO2 capture (PCC) systems have been demonstrated at utility-scale on any coal- or gas-fired power plants thus far. Moreover, no PCC technologies are available for order with commercial guarantees for coal-fired power plants, though some companies provide r 2011 American Chemical Society
guarantees for commercial-scale gas-fired power plants today with intentions for coal-fired power plants by 2012.8 Near-term PCC technologies are being developed and demonstrated at subscale and are progressing toward market readiness, but these first-generation capture technologies are energy intensive and, when implemented, will significantly increase the cost of electricity (COE) for the host power plant.9,10 CCS economics typically include the cost of capture and compression, and sometimes transport and storage. Costs are commonly reported in $/tonne CO2 captured or $/tonne CO2 avoided, which are defined elsewhere.9,10 The International Energy Agency (IEA) summarized the findings from recent CCS economic studies from leading institutions and reported the average cost for capture and compression to be $58/tonne CO2 avoided, not including transport and storage, leading to 63% rise in the levelized cost of electricity.11 Recognizing the need to reduce these costs, the U.S. Department of Energy (DOE) set a goal for CO2 mitigation technologies to be widely deployable by 2020 that can achieve less than 35% COE increase with the following: 90% CO2 capture, compression to 140 bar (2000 psi), 160 km (100 miles) transportation, 1525 m (5000 ft) injection, and 100-year storage with measurement, monitoring, and verification.12 Among capture, compression, transport, and storage, CO2 capture is the most expensive, representing 6070% of the total CCS cost, with compression requiring ∼20%, and the balance for transport, Received: December 21, 2010 Accepted: September 9, 2011 Revised: September 7, 2011 Published: September 12, 2011 8624
dx.doi.org/10.1021/es104291d | Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology
POLICY ANALYSIS
Table 1. Anthropogenic Greenhouse Gas Emissions, United States for 20085,6 CO2 emission source
a
Gt CO2
CO2 from electricity generation
2.36
CO2 from non-electricity energy CO2 from other sources
3.37 0.11
total anthropogenic CO2
5.84
total anthropogenic non-CO2 GHGa
1.12
total anthropogenic GHG, CO2(equiv.)
6.96
Based on CO2 equivalent 100-year global warming potential
injection, and monitoring,9,10 and is, as such, the primary focus for CCS cost reduction opportunities.13 Moreover, because capture is energy intensive, capture energy has the largest influence on the CO2 capture cost; therefore, low-energy CO2 capture is the most direct route to achieve lower cost CCS. In an effort to promote the development of low-energy capture technologies, EPRI undertook an effort to identify, vet, and appropriately accelerate emerging PCC technologies that show promise in this area.1417 Over 120 technologies have been evaluated thus far. This technology review campaign provided EPRI with insights on the state of the science and technology of capture systems, some of which are presented in this paper.
’ CHALLENGES FACING CAPTURE SOLUTIONS Central to postcombustion CO2 capture are two challenges: the scale of CO2 emissions and the energy of separation. To discuss these challenges, we focus on coal-fired power plants, which generate nearly 45% of electricity in the U.S.4 Flue gas from coal-fired power plants typically contains 7075% N2, 1015% CO2, 810% H2O, 34% O2, with trace levels of SOx, NOx, and other compounds.10 For this paper, we use 13% CO2 as a typical value. The Energy Information Administration (EIA) reports annual CO2 emissions from each U.S. power plant, and their data show the average CO2 emission in 2009 to be 25.17 t CO2/MWe-day generated or 9187 t CO2/MWe-year generated.18 Note that these values reflect the actual electricity generated, without regard to the capacity factor, which is the ratio of the actual generation to name plate generation during a fixed time period. In part due to the recent financial recession and the shift of power generation away from coal, the U.S. coal fleet had an average capacity factor of 63.8% in 2009, substantially lower than the 72.2% in prior years.4 Scale of Emissions. At 2360 Mt/year, the scale of anthropogenic CO2 emissions from U.S. electricity generation plants is vast. To provide perspective, Table 2 shows the production levels of the 50 largest produced chemicals for 2009 in the U.S. and globally, based on estimates from the latest year for which these figures are available publicly. Our estimates were in some cases extrapolated from 200219 and adjusted to account for changes in production.20,21 Moreover, these data are from the chemical industry, and do not include all possible industries that may produce the same chemicals as well. The accuracy of each chemical listed may therefore vary; nonetheless, even under such approximations, some important observations can be drawn. These observations are important because some capture processes propose to use chemicals to capture power plant flue gas CO2 or produce a saleable product in a once-through process, akin to SO2 capture by limestone to produce gypsum, and thereby
avoid the very large energy penalties to regenerate solvents or sorbents. In a hypothetical case wherein a PCC process uses a commodity chemical to capture CO2 in an equimolar ratio, i.e., one mole of the chemical captures permanently one mole of CO2, then the “GWe-yr at 90% capture” columns in Table 2 show the maximum coal-fired power plant generation in GWe-yr whose flue gas (containing 13% CO2) could be treated at a 90% capture rate before depleting either the U.S. or global supplies of that chemical. For example, a process that uses one mole of ammonia to capture one mole of CO2 in a nonregenerative system will exhaust the domestic supply of ammonia after treating CO2 emitted from only 4.4 GWe-yr of coal-fired power plant generation, equivalent to 2.2% of U.S. generation. A more efficient process that might use one mole of a chemical to capture two or three moles of CO2 would correspondingly decrease chemical intake of the capture process by a factor of two or three. Even so, such changes would not materially affect the fact that current supplies of commodity chemicals are small relative to the 200 GWe-yr of coal-fired generation, representing 63.8% of the 314 GWe installed capacity in the U.S., or the >1000 GWe-yr coalfired generation worldwide. Note also that many of these chemicals are themselves precursors to others chemicals also on the list. For example, nearly 60% of sulfuric acid (no. 1) is used to make phosphoric acid (no. 10) and about 60% of propylene (no. 7) is used to make polypropylene (no. 18). Hence, the annual total of 419 Mt (approximately 8700 Gmoles) of the top 50 chemicals already double-counts a portion of material actually available. Finally, note that in this hypothetical process, it is certainly possible to increase the production of a chemical if it is favorable for CO2 capture, but then the combination of its manufacture, transportation, and its use in the capture process itself must yield an overall net reduction of CO2 in order to have a net reduction in anthropogenic CO2 emissions. However, the chemical industry as a whole, as exemplified in Table 2, yields a net increase in CO2 emission because it involves the use of large quantities of energy or involves chemistry that releases CO2 somewhere in a production chain.22 This analysis leads to two important conclusions. First, any capture process that uses a commodity chemical as a reagent to capture CO2 in a “once-through” manner will quickly exhaust the global supply of that chemical before making a meaningful reduction in CO2 emissions. For the process to be widely applicable, the capture process must employ regenerative chemistry, use membranes for separation, or devise a method for producing a reagent in quantities many times higher than the current manufacturing capacity of the entire chemical industry while ensuring that a net reduction of CO2 still occurs. This argument, therefore, severely limits the potential of “oncethrough” CO2 capture processes. The second conclusion is that any process that uses CO2 as a reactant to produce a chemical or other commodity product will overwhelm global market demand for the produced product. Although once-through capture methods may be technically feasible, their cost estimates often depend on the salability of the produced products to offset an otherwise high-cost CO2 capture process. In such cases, widespread applicability of the process would not be economically feasible because doing so would saturate U.S. or global markets for that chemical by orders of magnitude, effectively dropping the product’s price to near 8625
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology
POLICY ANALYSIS
Table 2. Approximate Production of Top 50 Chemicals in 20091921 estimated U.S.
estimated global GWe-yr at
Mt
GWe-yr at
90% capture
Gmola
Mt
90% capture
1
sulfuric acid
38.7
394
2.1
199.9
1879
2
nitrogen
32.5
1159
6.2
139.6
4595
24.5
3
ethylene
25.0
781
4.2
112.6
3243
17.3
4
oxygen
23.3
829
4.4
100.0
3287
17.5
5
lime
19.4
347
1.8
283.0
4653
24.8
6
polyethylene (HDPE, LDPE, etc.)
17.0
530
2.8
60.0
1729
9.2
7 8
propylene ammonia, synthetic anhydrous
15.3 13.9
354 818
1.9 4.4
53.0 153.9
1134 8332
6.0 44.3
9
chlorine
12.0
169
0.9
61.2
795
4.2
10
phosphoric acid
11.4
116
0.6
22.0
207
1.1
45b
acetic acid
2.3
38
0.2
8.0
123
0.7
46
propylene oxide
2.1
37
0.2
6.3
100
0.5
47
phenolic resins
2.1
21
0.1
6.8
63
0.3
48
calcium carbonate (precipitated)
2.0
20
0.1
13.0
120
0.6
49 50
butadiene (1.3) nylon resins and fibers
2.0 1.9
36 8
0.2 0.0
10.3 2.3
175 8
0.9 0.0
total
a
Gmola
419
8,681
46
2009 coal-fired generation, GWe-yr4
200
installed coal-fired capacity, GWe4
314
2,412
48,385
10.0
257 >1000+ >1000+
CO2 from electricity
2,400
54,545
∼9600
218,182
CO2 from all sources
6,000
136,364
∼31200
750,000
For polymers, the number of moles represents the moles of repeating units. b Numbers 11-44 are provided in Supporting Information Table S.1.
zero. This argument, therefore, severely limits the beneficial use of CO2 insofar as it involves saleable chemicals. Note that the annual combined mass of the top 50 chemicals manufactured in the U.S. totals approximately 419 Mt whereas the electricity generation sector in the U.S. alone emits nearly six times that amount of CO2 and the U.S. emits about 15 times. Similar ratios are true for global chemical production relative to CO2 emissions. And assuming an equimolar reaction and 90% CO2 capture, the top 50 chemicals combined in the U.S. could only capture CO2 emitted from 46 GWe-yr of coal-fired electricity generation in the U.S., a fraction of the 200 GWe-yr actual generation. Likewise, the global top 50 chemicals could capture CO2 from about 257 GWe-yr of coal-fired electricity, a fraction of the global generation. To further this perspective on scale, Table S.2 in the Supporting Information shows the ten largest CO2 emitters in the U.S. electricity generation sector in 2009.18 These power plants typically consist of multiple boilers, each capable of producing sufficient steam to generate a few hundred MWe of electricity. The ten power plants shown in the table generate a sum of 29 GWe-yr electricity and emit about 192 Mt CO2, almost onehalf of the estimated tonnage of the top 50 chemicals produced the United States. Plant Scherer, the largest of these, annually emits 24.1 Mt of CO2, about the same as all ethylene produced by the U.S. chemical industry. By contrast, CO2 for enhanced oil recovery (EOR) in the U.S., which represents the majority of CO2 utilized in the U.S., is approximately 65 Mt/year.23 This is about equivalent to the emissions from 10 GWe of coal-fired power plants, i.e., the top
four power plants could supply all of the CO2 needed for EOR in the U.S. In terms of storage potential, however, we note that a recent study estimated the U.S. has approximately 3500 GWe-yr of CO2 emissions from coal-fired power plants.23 These data demonstrate the first challenge in CO2 capture: the scale of CO2 emissions, which places inherent limits on potential capture technologies and limits the beneficial use of CO2. We next turn our attention the second major challenge in CO2 capture: the energy required. Energy of Separation. As stated earlier, the energy of regeneration factors strongly in the overall cost of capture. To understand how much improvement is possible from CO2 capture improvements to current state of the art, it is necessary to determine the theoretical minimum amount of energy that is required to perform the separation of CO2 from the remaining constituents in flue gas. In this analysis, we specifically focus on capture and exclude compression since, as noted earlier, capture has the most potential for cost reductions and efficiency improvement. Moreover, the minimum energy needed to compress CO2 from atmospheric pressure to pipeline pressure is about the same as the minimum energy needed to separate CO2 from the flue gas of a typical coal-fired power plant.24 However, while new compressor concepts hope to reduce capital cost, not much efficiency gains can be expected from commercial compressors,24,25 and as we note earlier, compression represents only about 2030% of the energy needed for CCS, while capture represents 7080%, at least for near-term technologies. To separate a mixture such as flue gas into its pure components, the minimum amount of work that must be done is equal 8626
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology
POLICY ANALYSIS
Figure 1. Isothermal separation of a mixture.
to the change in Gibbs function (free energy) of a reversible process26 Emin ¼ ΔG ΔH TΔS
ð1Þ
where Emin is the minimum energy required, ΔG is the change in Gibbs function, ΔH is the change in enthalpy, T is absolute temperature, and ΔS is the change in entropy. Because no reaction takes place, ΔH is zero, and the minimum work for separation is only the change in entropy of mixing. As a reasonable approximation, we may assume that flue gas is an ideal binary mixture of CO2 and “inerts” representing all non-CO2 constituents, which gives26 Emin ¼ ΔGmix ¼ TΔSmix ¼ RT
∑i xi ln xi
require only 90% CO2 capture, as shown in the Isothermal Separation Unit I of Figure 1b. Flue gas containing 13% CO2 could be separated into two streams: one stream containing 100% CO2 equal to 90% of the CO2 originally in the flue gas, and the other stream containing inerts and the 10% of CO2 not captured. To calculate the entropy of mixing in Unit I shown in Figure 1b, which is the CO2 capture process of interest, we calculate the entropy of mixing of the overall separation of Units I and II into pure components, and subtract the entropy of mixing in Unit II. If xCO2 is the mole fraction of CO2 in flue gas, and η is the fraction of CO2 captured in the first separation, then (1 η)xCO2 is the mole fraction of CO2 fed into Unit II. Equation 2 therefore implies that the entropy change in Unit I (per mole CO2 captured) is given by þ II þ II Emin ¼ ΔGImix ¼ ΔGImix ΔGIImix ¼ RTðΔSImix ΔSIImix Þ
¼ RT½xCO2 ln xCO2 þ ð1 xCO2 Þlnð1 xCO2 Þ
RT f½xCO2 ln xCO2 þ ð1 xCO2 Þlnð1 xCO2 Þ ηxCO2 ½1 ηx½ð1 ηÞxCO2 lnfð1 ηÞxCO2 g
¼
ð2Þ where ΔGmix is the change in the Gibbs function due to mixing per mole of mixture, R is the universal gas constant, T is the absolute temperature, ΔSmix is the change in entropy due to mixing, xi is the mole fraction of component i, and xCO2 is the mole fraction of CO2. Note that eq 2 reflects the entropy change per mole mixture when the mixture is separated completely into pure components as shown in Figure 1a, whereas ΔGmix/xCO2 is the change in Gibbs function per mole CO2. At 40 °C, completely separating a flue gas containing 13% CO2 into pure CO2 and pure “inerts” will take a minimum energy of 1006 J/mol mixture, equivalent to 7738 J/mol CO2 or 0.1758 GJ/tonne CO2. Practical processes have a finite selectivity, and therefore the separated CO2 stream is never 100% pure. It often contains some amount of other flue gas components, e.g., water, oxygen, nitrogen, etc., that transport with CO2. These other components must often be further separated by supplemental methods to achieve a stream of sufficient CO2 purity to meet transportation and storage purity requirements, but for this calculation, we have assumed the final CO2 stream to be 100% pure. Moreover, complete separation of flue gas into pure components is not necessarily required for CO2 capture operations. For example, a PCC application may
þ f1 ð1 ηÞxCO2 glnf1 ð1 ηÞxCO2 gg
ð3Þ
At 40 °C, separating pure CO2 from a flue gas containing 13% CO2 at 90% capture will take a minimum energy of 0.1611 GJ/tonne CO2 captured. We can compare this minimum energy of separation to the electrical energy generated by a coal-fired power plant. The average U.S. coal-fired power plant emits approximately 9187 tonnes CO2 for each (MWe-yr) of net electricity it generates, as described earlier. Expressed differently, this value is equivalent to 3.43 GJ of net electricity generated per tonne of CO2 emitted. For 100% capture, the minimum energy needed to capture each tonne of CO2 shown by eq 2 is 0.1758 GJ, which is 5.12% of the electrical energy generated by the power plant. At 90% capture, eq 3 showed the minimum value as 0.1611 GJ for each tonne of CO2 captured, which is 4.22% of the electrical energy generated by the power plant. Hence, if the only source of energy to separate 13% CO2 in flue gas were the electricity generated by the same coal-fired power plant, the thermodynamic minimum parasitic load would be 5.12% 8627
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology
POLICY ANALYSIS
Figure 2. Minimum energy penalty.
at 100% capture and 4.22% at 90% capture. Such calculations can be extended to other CO2 concentrations and percent captured via eq 3. The yellow lines in Figure 2 show these results at 40 °C and are directly proportional to the absolute temperature. For typical flue-gas capture conditions of 1115% CO2 and 90% capture from a power plant emitting 25.17 tonnes CO2/MWeday, the minimum energy penalty is about 4.04.5% of the net electricity generated before capture as shown in the lines in Figure 2. Based on generation and emissions data from the EIA, the shaded yellow region in Figure 2 shows the minimum energy as the upper 90th percentile and lower 10th percentile bounds of U.S. power plants assuming their flue gas contained 13% CO2.4 Note that the yellow lines in the figure represent the minimum energy for capture, and specifically do not include any makeup power. From a thermodynamic and separations perspective, this is an important metric to consider. From a policy and electricity generation perspective, however, energy penalty is often reported to be the increase in fuel input on a fixed net power output, i.e., to include makeup power that was lost due to CCS.9,27 Under such a definition, the increase required to deliver a fixed net power is therefore higher than that shown in Figure 2 and is given by the equation27 PL ¼
1 1 1 pl
ð4Þ
where pl is the parasitic load of the capture process itself and PL is the increase in input fuel to provide the same net power after a capture process. The blue lines and blue shaded area in Figure 2 show the result of applying eq 4 to the yellow lines and shaded area in Figure 2, i.e., the minimum increase in fuel requirement for the same net power output. Note again, these values exclude compression. Further note that if energy is extracted from the power plant that is not used to generate electricity, e.g., waste heat, then the parasitic load could be less, but the amount of energy required per tonne CO2 captured does not change. Likewise, if steam from the steam cycle were used to drive the CO2 capture process, which is typically the case in conventional solvent-based capture systems, then the energy penalty could be lower if the capture process can use the steam more efficiently than converting it to electricity that
subsequently drives the capture process. Indeed, all solvent processes are thermally integrated into the power plant to minimize the parasitic load on electricity generation. For comparison, a hypothetical CO2 separation process, not including compression, based on aqueous solutions of monoethanol amine (MEA) imposes approximately a 20% reduction in net plant output,10 or about five times the calculated minimum energy. The work done by multistage compression is about 810% of net plant output,10 or about twice the minimum energy, again highlighting the fact that capture is far more energy inefficient than compression. We believe that in order to overcome these two central challenges in CO2 capture, scale and energy penalty, a trio of expertise working synergistically is needed: chemists to develop new capture chemistry, process engineers concurrently working to design processes around the new chemistry, and power plant personnel concurrently working to integrate the process with a power plant. In addition to the challenge of scale of emissions and energy for capture just discussed, there are additional practical constraints such as limited water availability, limited land availability, and the tolerance of capture solvents to other flue gas constituents. Other Constraints. A detailed engineering study modeling an advanced amine capture system found that the capture equipment required 40 400 m2 (10 acres) of land for a 850 MWe power plant application, whose equipment normally occupies 257 000 m2 (63 acres).28 For some power plants, space for CCS is either not available or not close enough to the stack such that CCS may be impractical or require too many changes to the plant infrastructure. Additionally, some capture processes require nearly twice as much cooling water on a per-MWe basis relative to that used by the host power plant, which may not be available in some plant locations or may come at a very high cost.29 Finally, flue gas contains heavy metals, SOx, NOx, and a myriad of other compounds, which the capture process must tolerate or additional pretreatment equipment must be added, which will increase both the cost and energy penalty of the process. These issues are power-plant specific, but nearly all plants will have some limiting factors that will influence the type or size of capture equipment options. Capture processes which are less demanding with regard to these constraints (water, land, flue gas pretreatment) will have a greater potential to be widely applicable.
’ STATUS OF TECHNOLOGY DEVELOPMENT In our work,1417 we actively sought process developers, reviewed major literature articles, and identified postcombustion capture processes that we could technically evaluate. Technologies in very early stages or early science were largely omitted, leaving approximately 120 postcombustion CO2 capture technologies where we could identify the underlying separation method, determine approximate mass and energy balances, potential constraints, and for most, a state of development. Virtually all capture processes used an absorbent (solvent), adsorbent, membrane, converted CO2 to a mineral, or employed biofixation. As part of the evaluation, 95 of the 120 technologies were assigned a state of development status using a Technology Readiness Level (TRL) taxonomy. Originally developed by the NASA for conveying the readiness of a technology for space applications,30 the TRL system has since been adopted by EPRI and other public and private agencies.31,32 The TRL system divides the development process into nine discrete levels from the conceptual stage at TRL of 1 to full-scale tested commercial products TRL of 9. 8628
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology Each TRL step is described in Table S.3 (see Supporting Information). We assigned each capture process a TRL level at the time of its review. Figure 3 shows a histogram of the results from EPRI’s study. The majority of PCC technologies are absorption-based processes (60%), followed by membrane (14%), mineralization (14%), and adsorption (12%). This result is perhaps reflective of the fact that absorption technologies are widely used already in the broader chemical process and oil/gas production industries, and hence operational confidence of the basic process is relatively high. Most of the technologies reviewed are in the earlier stages of development with a few moving from the laboratory to pilot operations. Among the capture technologies which showed the most promise for lower cost (low energetics) operation, the majority rank in the TRL 2 to 4 level, indicating that they will require significant time to achieve commercial status. Although the capture technologies EPRI reviewed did not include many in the TRL 1 tier, this does not reflect the population of capture processes. This is attributable to the fact that the first TRL phase is very short-lived and the subject technology is not frequently disclosed publically or it represents basic science that is not yet focused on a capture process per se. Capture technologies are generally disclosed by the developer only after they have cleared TRL 2. In terms of timing, Figure S.1 (see Supporting Information) represents EPRI’s translation of Alstom’s projections for their Chilled Ammonia Process33 into TRL taxonomy, under a wellfunded and aggressive development schedule. Even under these conditions, the total development cycle is nearly 1015 years. Table 3 shows the general state of capture development for the three major types of capture methods. The usage of the technology in the chemical process industry and operational confidence are obviously correlated. For absorption-based processes, the major source of the energy penalty is from the thermal regeneration of the solvent. The energy penalty for adsorbent-based processes uses thermal and/or vacuum regeneration, while membrane processes generally rely on a vacuum applied to the permeate-side to separate CO2. Though we considered mineralization processes, they are considered “once-through” processes and are therefore subject to the constraints of supply of the reagents and disposal of products as discussed earlier. The following section reviews each of the three primary capture methods and describes the current state and themes of development for each type. Absorption. Absorption refers to the uptake of CO2 into the bulk phase of another material—for example, dissolving CO2 molecules into a liquid solution. This contrasts to adsorption, where CO2 molecules adhere to the surface of a solid particle. Both are used widely in the chemical, petrochemical, and other industries, with absorption being more common than adsorption. The absorption cycle is based on temperature dependent acidbase reaction wherein the CO2, which is acidic, reacts with a basic solution at flue gas temperatures (4060 °C). After reacting with CO2, the “loaded” solution is directed to a regeneration vessel where the solvent is heated to reverse the reaction thus liberating gaseous CO2 which is then collected, dried, compressed, and transported to a storage reservoir. State of Development. Among the three major separation methods considered for CO2 capture, absorption is the most mature. Absorption processes are common in the chemical process industries, and there is significant commercial experience
POLICY ANALYSIS
Figure 3. Distribution of post-combustion CO2 capture technology types by TRL ranking.
with their operation including for CCS applications and treating natural gas. This stems from the fact that absorption-based processes are generally less expensive for large-scale separations, easier to operate, and are more robust than other processes. Indeed, all the near-term CO2 capture processes are solventbased, as are the majority of the less-developed capture processes. One challenge for CO2 capture is to develop solvents that regenerate using minimal energy. This challenge is difficult because low regeneration energy solutions typically have a low heat of absorption, which translates to poor CO2 absorption characteristics. The near-term CO2 capture technologies impose an estimated 2530% parasitic load on the net power output (including CO2 compression to pipeline requirements) of a typical coal-fired power plant in order to capture 90% of emitted CO2.10,28 Though absorption technologies continue to improve, these advances offer only incremental gains. Still, because of widespread commercial use of absorption processes, even such incremental advances are commercially significant. Current research efforts in absorption focus on lowering the heat of regeneration. A common point of reference for performance is 30 wt % aqueous MEA, which, depending on variances in process design, requires approximately 3.6 GJ of energy for each tonne of CO2 captured, imposing parasitic load of approximately 20% on a coal-fired power plant in the absence of compression; with compression, this value increases to 30%.10 Regeneration occurs at approximately 120 °C under slight pressure, with a number of factors determining the optimal operating condition for a given plant. There are multiple approaches to lowering the regeneration energy, all based on modifying the solvent. The first approach is to increase the solvents’ concentration above 30 wt % so as to reduce the working volume of solvent needed to capture CO2 and then to add corrosion inhibitors and other additives to mitigate the adverse effects of operating at higher concentrations. This results in lower sensible heating requirements, less water evaporation in the reboiler, and consequently lower regeneration energy. Fluor’s Econamine FG+ is one example of a process that has reduced regeneration energy by increasing the solvent concentration, adding corrosion inhibitors, and optimizing the process integration.34 A second approach is to use different solvents that are still based on aqueous alkanomines but either have lower capacity and/or lower reaction kinetics. Examples include diethanolamine (DEA), methyldiethanolamine (MDEA), various secondary amines, various tertiary amines, and numerous blends of amines. Additional differentiation comes from process optimization and thermal integration into the plant. Cansolv is one example of a 8629
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology
POLICY ANALYSIS
Table 3. State of Post-Combustion CO2 Capture Development absorbent
membrane
commercial usage in CPIa
high
moderate
operational confidence
high
high, but complex
low to moderate
primary source of
solvent regeneration
sorbent regeneration
compression on feed and/
energy penalty development trends a
adsorbent
(thermal) new chemistry, thermal integration
low/niche
(thermal/vacuum)
or vacuum on permeate
new chemistry, process configuration
new membrane, process configuration
CPI = Chemical process industries.
process using blends of amines.35 In contrast to alkanomines, Alstom’s chilled ammonia process (CAP) uses aqueous ammonium salts (ammonium carbonate) to capture CO2 as ammonium bicarbonate, and aims to make use of waste heat and to regenerate at elevated temperatures and pressures to reduce downstream compression.36 In general, this collection of aqueous solvents represents the near-term CO2 capture technologies. Remaining approaches to absorption, which have a longer path to commercialization, involve changing the absorption chemistry itself or using promoters (catalysts) to enhance the rate of absorption. Examples include computationally designed solvents, the use of “fast” amines such as piperazine37 to improve reaction kinetics, and the use of industrial enzymes (carbonic anhydrase)38 as a catalyst to increase the kinetics of aqueous CO2 reactions. Though amine-based solvents are more common, other solvents with affinity for CO2 such as ionic liquids39 and siloxanes40 are also being investigated. Most of these are at conceptual or early lab scale testing. These also aim to reduce the energy of regeneration, while some offer the additional advantage of potentially reducing the gasliquid contactor volume. The other challenge is to produce low cost solvents. All solvents degrade during operation and must be replaced, imparting both disposal cost and replacement cost for the operator. Some solvents with the best performance also happen to be the most expensive to produce. The overall operational economics will ultimately dictate the extent to which higher-performing, highercost solvents offer a lower cost of capture compared to lowerperforming, lower-cost solvents. Adsorption. Adsorption refers to uptake of CO2 molecules onto the surface of a solid sorbent, to which they adhere via weaker van der Waals forces (physisorption) or stronger covalent bonding (chemisorption). This contrasts to absorption, where CO2 molecules dissolve into the bulk of the material itself. Adsorption processes can be implemented several different ways, with the adsorbent used in packed beds or fluidized beds. In a packed bed, adsorbent is loaded into a column, flue gas flows through the void spaces between the adsorbent particles, and the CO2 adsorbs onto the particle surfaces. In fluidized beds, flue gas flows upward through a column at higher velocities such that the adsorbent particles are suspended in the gas flow. In both approaches, the adsorbent selectively adsorbs more CO2 relative to the other constituents passing through the column. The adsorbent is typically regenerated by changing the pressure (lower pressure) and/or temperature (higher temperate) to liberate the adsorbed CO2. In a packed bed, this is accomplished by switching the flue gas flow to a second column, and heating the CO2-laden adsorbent in the first column to drive off the CO2. In a fluidized bed, the sorbent is typically conveyed continuously to the regenerator column and then back to the absorber column. State of Development. Adsorption-based separation processes are used at large-scale in chemical process industry
applications, but they are less common than absorption-based systems. Because adsorption can be used in different process configurations, both adsorbent properties and process design can strongly influence the effectiveness of separation. Consequently, developing adsorption processes for very large-scale CO2 capture would require development of both adsorbent materials and corresponding processes.41 Adsorbents being developed for CO2 capture exhibit a variety of origins, characteristics, and chemistries. Low-cost, moistureinsensitive carbonaceous adsorbents are being investigated at the University of Wyoming.42 Metal oxide frameworks (MOFs), which are nanoporous materials synthesized via the self-assembly of metal or metal oxide vertices interconnected by rigid organic linker molecules, are being investigated at a variety of universities such as University of California at Los Angeles,43 Berkeley44 and elsewhere.45 Other types of materials are also being investigated at early stages. None of these have yet advanced beyond lab-scale testing, with large-scale production and accompanying process development largely unknown. In addition, it is not yet known whether the benefits of using novel adsorbents will be sufficient to offset their anticipated higher cost. Hence, some researchers have taken the approach of using less sophisticated and inexpensive adsorbents, and employing them in novel process designs to capture CO2. Research groups pursuing this strategy include RTI in North Carolina,46 and The Ohio State University.47 Many of these are at bench scales. Membranes. Membranes separate CO2 from flue gas because the transport speed of a gas constituent through the membrane is proportional to its permeability, defined as the product of its solubility and diffusivity in the membrane material. If CO2 has a higher permeability than other constituents of flue gas, then CO2 preferentially permeates it. In some cases, chemical agents that selectively react with CO2 are added to the membrane to facilitate CO2 transport. Under typical conditions, CO2 will transport across a membrane only if the partial pressure of CO2 is higher on the side of the membrane that contacts the flue gas than on the other. A partial pressure gradient of CO2 can be obtained by pressurizing the flue gas on one side of the membrane, applying a vacuum on the other side of the membrane, or both. In effect, applying this pressure differential provides the energy for separation. State of Development. Membrane separation processes are used much less frequently in chemical process industrial applications compared to either absorption or adsorption. With few exceptions such as reverse osmosis, large-scale membranes are not commonly available or used in the chemical process industries. However, there is a commercial polymeric membrane process from UOP (Separex) that removes CO2 from natural gas, in applications with a gas flow rate equivalent to that from the flue gas from a 300-MWe power plant.48 Though this polymer is not suitable for separating CO2 from flue gas, it does demonstrate 8630
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology that the general scale of membrane systems is within the range required for coal-fired power plant applications. Coal-fired power plants present some unique challenges for membranes. Particulates can deposit on the membrane surface, decreasing its permeability or damaging it physically over time.49 Another issue is that membranes deployed at power plant scale require a very large membrane area. For example, a 600-MWe power plant could require more than 1 million square meters of membrane which must be packaged into modular containers. Large modules today are typically 3546 cm diameter (1418 in.), 0.91.2 m long (34 ft), and contain a membrane area of 50100 m2 (5381076 ft2) that is spirally wound around a central tube. Thousands of such membrane modules connected in a serial and parallel piping network would be required to treat flue gas emissions from a typical power plant, presenting engineering design challenges to ensure proper and efficient gas distribution since flue gas is at relatively low pressures. Despite these challenges, membranes are attractive because they can be arranged in a relatively small footprint (about 0.4 ha [1.0 acre] for a 600-MWe power plant) and potentially impose a small energy penalty.50 Some membranes will also permeate the water present in flue gas, which offers the possibility to “harvest” water that may be used by the host power plant. Current membrane development efforts are at laboratory or bench scales, with much effort directed to developing new materials.
’ DISCUSSION CO2 capture presents two central challenges that we have attempted to quantify and provide perspectives: scale and energy. The scale of CO2 emissions is several multiples larger that the commodity chemicals made by the chemical industry. This places limits on capture processes that use or generate commodity chemicals, suggesting that regenerative chemistry or membranebased separation, and not “once-through” chemistry to capture CO2, is needed in order for a capture process to be widely deployed. As explained earlier, the minimum parasitic load to capture 90% of the CO2 from a typical coal-fired power plant is about 44.5% of the net electrical output as measured from the same plant without capture. Actual processes, such as capture by MEA without compression, require about five times this minimum energy with careful thermal integration into the power plant. In addition CO2 capture processes face a variety of additional challenges including limited land space, limited water availability, tolerance to other flue gas constituents, and other local power plant criteria, such as major O&M intervals and turn down ability. The Technology Readiness Level index can be a useful tool to ascertain the landscape of CO2 capture technologies. The majority of capture processes continue to focus on absorption, followed by adsorption, membranes, and other separation methods. This is due to the fact that absorption is more widely practiced in the chemical process industries and has practical advantages at large scales. However, unless radically different capture chemistries are investigated, only incremental advances in absorption solvents and processes are likely to ensue. Adsorption and membrane technologies both require process development along with material development, and will require more development than absorption. Hybrid systems are largely unexplored. A final and critical point is that in our analysis, the current landscape of CO2 capture technology development involves
POLICY ANALYSIS
three groups working largely independently of each other: chemists who design and synthesize appropriate separation materials, process engineers who can design separation processes around those materials, and power plant engineers who can integrate the process into a power plant. We strongly believe that the emergence of breakthrough technologies will require close interdisciplinary collaboration among these groups, who further need to have a technical understanding of how each depends on the other.
’ ASSOCIATED CONTENT
bS
Supporting Information. Full, expanded tables and figures that have been cited in the text. This material is available free of charge via the Internet at http://pubs.acs.org.
’ AUTHOR INFORMATION Corresponding Author
*E-mail:
[email protected].
’ ACKNOWLEDGMENT We thank Dr. George Offen for his feedback and comments on this manuscript, Adam Berger for preparation of key figures, and Katarina Fustar for preparation of the manuscript. We also acknowledge and thank the reviewers for the very helpful and thorough feedback on the manuscript. ’ REFERENCES (1) Center for Global Development, Science Daily, November 15, 2007; http://www.sciencedaily.com/releases/2007/11/071114163448.htm. (2) California’s Global Warming Solutions Act of 2006. Assembly Bill 32. (3) $45.3 Billion in US Coal-Fired Power Plants Cancelled in 2007; Resource Media, January 8, 2009. (4) U.S. Energy Information Administration (EIA). Electric Power Annual 2009; DOE/EIA-0348 (2009); Washington, DC, 2011. (5) U.S. Energy Information Agency (EIA). Emissions of Greenhouse Gases in the United States, 2010; http://www.eia.doe.gov/oiaf/ 1605/ggrpt/carbon.html (accessed June 25, 2011). (6) U.S. Energy Information Agency (EIA). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 19902008; http://www.epa.gov/climatechange/emissions/usinventoryreport.html (accessed June 25, 2011). (7) Friedlingstein, P.; Houghton, R. A.; Marland, G.; Hackler, J.; Boden, T. A.; Conway, T. J.; Canadell, J. G.; Raupach, M. R.; Ciais, P.; Le Quere, C. Update on CO2 Emissions. Nat. Geosci. 2010, 3, 811–812. (8) Holton, S.; Yonekawa, S.; Irvin, N. MHI’s KM-CDR PostCombustion CO2 Capture Process Overview and Coal-Fired 500 ton per day Demonstration Project Update, Tenth Annual Carbon Capture & Sequestration Conference, Pittsburgh, PA, May 4, 2011. (9) Metz, B., Davidson, O., Coninck, H. C. d., Loos, M., Meyer, L. A., Eds. IPCC Special Report on Carbon Dioxide Capture and Storage; Prepared by Working Group III of the Intergovenmental Panel on Climate Change; Cambridge University Press: Cambridge, UK, 2005. (10) Carbon Dioxide Capture from Existing Coal-Fired Power Plants; DOE/NETL-401/110907; National Energy Technology Laboratory, November 2007. (11) Finkeenrath, M. Cost and Performance of Carbon Dioxide Capture from Power Generation; International Energy Agency, 2011. (12) Ciferno, J. Overview of DOE/NETL CO2 Capture R&D Program, Presentation at the Annual NETL CO2 Capture Technology for Existing Plants R&D Meeting, Pittsburgh, PA, March 2009. 8631
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
Environmental Science & Technology (13) Booras, G.; Holt, N.; Marasigan, J. Updated Cost and Performance Estimates for Clean Coal Technologies Including CO2 Capture; Product ID 1014223; EPRI: Palo Alto, CA, 2008. (14) Freeman, B.; Rhudy, R. Assessment of CO2 Capture Options Currently Under Development; PID 1012796; EPRI: Palo Alto, CA, 2007. (15) Bhown, A. S.; Freeman, B. Program on Technology Innovation: Post-Combustion CO2 Capture Technology Development; PID 1016995; EPRI: Palo Alto, CA, 2008. (16) Bhown, A. S.; Freeman, B. Post-Combustion CO2 Capture Technology Development; PID 1017644; EPRI: Palo Alto, CA, 2009. (17) Bhown, A. S.; Freeman, B. Post-Combustion CO2 Capture Technology Development; PID 1019812; EPRI: Palo Alto, CA, 2010. (18) U.S. Department of Energy, Energy Information Administration (EIA). 2010 November EIA-923 Monthly Time Series File, Sources EIA-923 and EIA-860; http://www.eia.gov/cneaf/electricity/page/ eia906_920.html (accessed June 25, 2011). (19) Guide to the Business of Chemistry; American Chemistry Council: Washington, DC, 2003. (20) American Chemistry Council. Production Index, 2008, 2009, 2010. (21) C&EN Staff. Gains In Chemical Output Level Off. Chem. Eng. News 2008, 86, 61–70. (22) Worell, E.; Phylipsen, D.; Einstein, D.; Martin, N. Energy Use and Energy Intensity of the U.S. Chemical Industry; Lawrence Berkeley National Laboratory: Berkeley, CA, 2010; http://escholarship.org/uc/ item/2925w8g6;jsessionid=8B5AC06A6916F20CA2C9D4F3894CB980#page-1 (accessed June 25, 2011). (23) Role of Enhanced Oil Recovery in Accelerating the Deployment of Carbon Capture and Sequestration, A Massachusetts Institute of Technology Energy Initiative and Bureau of Economic Geology at the University of Texas at Austin Symposium, (Austin), TX, July 23, 2010. (24) McGlashan, N. R.; Marquis, A. J. Availability Analysis of PostCombustion Carbon Capture Systems: Minimum Work Input. Proc. Inst. Mech. Eng., Part C 2007, 221, 1057–1065. (25) Koopman, A.; Bahr, D. The Impact of CO2 Compressor Characteristics and Integration in Post Combustion Carbon Capture Carbon Sequestration Comparative Economic Analysis. In Proceedings of ASME Turbo Expo 2010, June 1418, 2010, Glasgow, UK. (26) Rao, Y. V. C. Postulational and Statistical Thermodynamics; Allied Publishers: New Delhi, 1994. (27) Rubin, E.; Chen, C.; Rao, A. Cost and Performance of Fossil Fuel Power Plants with CO2 Capture and Storage. Energy Policy 2007, 35, 4444–4454. (28) Dillon, D.; Chu, R.; Choi, G.; Harper, W.; Sugita, S. An Engineering and Economic Assessment of Post-Combustion CO2 Capture for Ultra-Supercritical Pulverized Coal Power Plant Applications, Phase II Task 3 Final Report; PID 1017515; EPRI: Palo Alto, CA, 2010. (29) Cost and Performance Baseline for Fossil Energy Plants. Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2; DOE/2010/ 1397; National Energy Technology Laboratory, 2010. (30) Mankins, J. Technology Readiness Levels: A White Paper; NASA, April 1995. (31) Nolte, W. Technology Readiness Level Calculator; Air Force Research Laboratory, October 2003. (32) U.S. Department of Energy. Technology Readiness Assessment Guide; DOE G 413.3-4; October 12, 2009. (33) Ericson, A. The Role of CCS in the Decarbonization of Power. Presentation at 8th Annual Conference on Carbon Capture and Sequestration, Pittsburgh, PA, May 5, 2009. (34) Simonson, T.; Parish W. A. CCS Demonstration Plant (FE0003311). Presentation at 2010 NETL CO2 Capture Technology Meeting, Pittsburgh, PA, September 2010. (35) Hakka, L.; Ouimet, M. Method of Recovery of CO2 from Gas Streams. US Patent 7,056,482, June 6, 2006. (36) Kozak, F.; Petig, A.; Morris, E.; Rhudy, R.; Thimsen, D. Chilled Ammonia Process for CO2 Capture. Energy Procedia 2009, 1, 1419–1426. (37) Freeman, S.; Dugas, R.; Van Wagener, D. H.; Nguyen, T.; Rochelle, G. T. Carbon Dioxide Capture with Concentrated, Aqueous Piperazine. Int. J. Greenhouse Gas Control 2010, 4 (2), 119–124.
POLICY ANALYSIS
(38) Voyer, N.; Fradette, S. An Efficient Technology Platform for the Capture and Regeneration of CO2 Exploiting the Catalytic Power of Carbonic Anhydrase. Seventh Annual Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May 58, 2008. (39) Bara, J.; Carlisle, T. K.; Gabriel, C. J.; Camper, D.; Finotello, A.; Gin, D. L.; Noble, R. D. Guide to CO2 Separations in ImidazoliumBased Room Temperature Ionic Liquids. Ind. Eng. Chem. Res. 2009, 48 (6), 2739–2751. (40) Perry, R.; Grocela-Rocha, T.; O’Brien, M.; Genovese, S.; Wood, B.; Soloveichik, G.; Rubinsztajn, M.; Kniajanski, S.; Draper, S.; Enick, R.; Johnson, J. K.; Xie, H.; Tapriyal, D. Aminosilicone Solvents for CO2 Capture. ChemSusChem 2010, 3 (8), 919–930. (41) Sjostrom, S.; Krutka, H. Evaluation of Solid Sorbents as a Retrofit Technology for CO2 Capture. Fuel 2010, 89 (6), 1298–1306. (42) Radosz, M.; Hu, X.; Krutkramelis, K.; Shen, Y. Flue Gas Carbon Capture on Carbonaceous Sorbents: Toward a Low-Cost Multifunctional Carbon Filter for Green Energy Producers. Indus. Eng. Chem. Res. 2008, 47 (10), 3783–3794. (43) Deng, H.; Doonan, C.; Furukawa, H.; Ferreira, R.; Towne, J.; Knobler, C.; Wang, B.; Yaghi, O. Multiple Functional Groups of Varying Ratios in Metal-Organic Frameworks. Science 2010, 327 (5967), 846–850. (44) Demessence, A.; D’Alessandro, D.; Foo, M.; Long, J. Strong CO2 Binding in a Water-Stable, Triazolae-Bridged Metal-Organic Framework Functionalized with Ethylenediamine. J. Am. Chem. Soc. 2009, 131 (25), 8784–8786. (45) Keskin, S.; van Heest, T.; Sholl, D. Can Metal-organic Framework Materials Play a Useful Role in Large-Scale Carbon Dioxide Separations? ChemSusChem 2010, 3 (8), 879–891. (46) Liang, Y.; Harrison, P; Gupta, R. P.; Green, A.; McMichael, W. J. Carbon Dioxide Capture Using Dry Sodium-Based Sorbents. Energy Fuels 2004, 18 (2), 569–575. (47) Gupta, H.; Fan, L. S. Carbonation-Calcination Cycle Using High reactivity Calcium Oxide for Carbon Dioxide Separation from Flue Gas. Ind. Eng. Chem. Res. 2002, 41 (16), 4035–4042. (48) Baker, R. W.; Lokhandwala, K. Natural Gas Processing with Membranes: An Overview. Ind. Eng. Chem. Res. 2008, 47 (7), 2109–212. (49) Pakala, N.; Bhown, A. Effect of Particulate Matter on Mass Transfer through Microporous Hollow Fiber Membranes. J. Membr. Sci. 1996, 111 (1), 71–79. (50) Merkel, T.; Lin, H.; Wei, X.; Baker, R. Power Plant PostCombustion Carbon Dioxide Capture: An Opportunity for Membranes. J. Membr. Sci. 2010, 359 (12), 126–139.
8632
dx.doi.org/10.1021/es104291d |Environ. Sci. Technol. 2011, 45, 8624–8632
