Progress in Energy and Combustion Science 63 (2017) 146 172
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Progress in Energy and Combustion Science
journal homepage: www.elsevier.com/locate/pecs
CO2 capture from the industry sector
PraveenTagedP Bainsa,b, Peter Psarrasa, Jennifer Wilcoxa,*
TagedPDepartment of Chemical and Biological Engineering, Colorado School of Mines, Golden, CO 80401, USA b Department of Energy Resources Engineering, Stanford University, Stanford, CA 94305, USA
ARTICLETAGEDP INFO ABSTRACTTAGEDP
Article History: It is widely accepted that greenhouse gas emissions, especially CO2, must be significantly reduced to pre- Received 11 January 2017 vent catastrophic global warming. Carbon capture and reliable storage (CCS) is one path towards controlling Accepted 9 July 2017 emissions, and serves as a key component to climate change mitigation and will serve as a bridge between Available online 17 August 2017 the fossil fuel energy of today and the renewable energy of the future. Although fossil-fueled power plants
emit the vast majority of stationary CO2, there are many industries that emit purer streams of CO2, which Keywords:TagedP result in reduced cost for separation. Moreover, many industries outside of electricity generation do not Climate change have ready alternatives for becoming low-carbon and CCS may be their only option. The thermodynamic Carbon capture from industry Cement manufacturing minimum work for separation was calculated for a variety of CO2 emissions streams from various indus- Iron and steel production tries, followed by a Sherwood analysis of capture cost. The Sherwood plot correlates the relationship Petroleum refining between concentrations of a target substance with the cost to separate it from the remaining components. Natural gas processing As the target concentration increases, the cost to separate decreases on a molar basis. Furthermore, the low- est cost opportunities for deploying first-of-a-kind CCS technology were found to be in the Midwest and along the Gulf Coast. Many high purity industries, such as ethanol production, ammonia production and natural gas processing, are located in these regions. The southern Midwest and Gulf Coast are also co- located with potential geologic sequestration sites and enhanced oil recovery opportunities. As a starting point, these sites may provide the demonstration and knowledge necessary for reducing carbon capture technology costs across all industries, and improving the economic viability for CCS and climate change mit- igation. The various industries considered in this review were examined from a dilution and impact per- spective to determine the best path forward in terms of prioritizing for carbon capture. A possible
implementation pathway is presented that initially focuses on CO2 capture from ethanol production, fol- lowed by the cement industry, ammonia, and then natural gas processing and ethylene oxide production. While natural gas processing and ethylene oxide production produce high purity streams, they only account
for relatively small portions of industrial process CO2. Finally, petroleum refineries account for almost a fifth of industrial process CO2, but are comprised of numerous low-purity CO2 streams. These qualities make these three industries less attractive for initial CC implementation, and better suited for consideration towards the end of the industrial CC pathway. © 2017 Elsevier Ltd. All rights reserved.
Contents 1. Introduction ...... 147
2. Process CO2 versus combustion CO2 ...... 148 3. The cost of capture: minimum work and economic cost ...... 149 3.1. Minimum work of separation ...... 149 3.2. Sherwood analysis...... 149
3.3. The cost of CO2 capture...... 150 3.4. Top CO2 emitters from the industrial sector...... 151 3.4.1. Petroleum refining...... 151 3.4.1.1. Process heaters ...... 151 3.4.1.2. Utilities (Electricity and steam generation)...... 153
* Corresponding author. E-mail addresses: [email protected], [email protected] (J. Wilcox). http://dx.doi.org/10.1016/j.pecs.2017.07.001 0360-1285/© 2017 Elsevier Ltd. All rights reserved. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 147
3.4.1.3. Fluid catalytic cracker (FCC) ...... 153 3.4.1.4. Hydrogen production ...... 153 3.4.2. Ethylene production ...... 154 3.4.2.1. Process overview...... 154 3.4.3. Cement production ...... 154 3.4.3.1. Process overview...... 154 3.4.4. Iron and steel production ...... 156 3.4.4.1. Process overview primary BF/BOF...... 156 3.4.4.2. Process overview secondary EAF ...... 156 3.4.4.3. Process conditions BF/BOF...... 157 3.4.5. Ethylene oxide production ...... 157 3.4.5.1. Process overview air oxidation ...... 157 3.4.5.2. Process overview direct oxygen oxidation ...... 158 3.4.5.3. Process conditions ...... 158 3.4.6. Hydrogen production...... 159 3.4.6.1. Process overview...... 159 3.4.7. Ammonia processing ...... 160 3.4.7.1. Process overview...... 161 3.4.8. Natural gas processing ...... 162 3.4.8.1. Process overview...... 162 3.4.9. Ethanol production...... 163 3.4.9.1. Process overview dry-milling ...... 163 3.4.9.2. Process overview wet-milling...... 163 3.4.9.3. Process conditions and cost ...... 164 4. Why country-level emissions? ...... 164 4.1. Process versus combustion CO2 ...... 165
4.2. CO2 sources by purity ...... 165 4.3. A note on CO2 utilization...... 167 5. Conclusions...... 167
1. Introduction costsTagedP associated with installing and demonstrating first-of-a-kind technology. ClimateTagedP change has been a topic of much debate over the past ThereTagedP have been many studies that have focused on the top four several decades. Increased levels of carbon dioxide (CO2)and emitting industries (i.e., iron and steel, cement, petroleum refining other greenhouse gases (GHG) are responsible for the global and petrochemical). Farla et al. published one of the first industrial warming that fuels climate change. As the acceptance of climate assessments of CCS in 1995, focusing on the Netherlands, while Van- change has increased, so too has the related discussion on ways sant published a chapter dedicated to characterizing the top-emit- to adapt to and mitigate its existence. The most recent example ting industries within the European Union [15,16]. In 2005, the is the 21st Conference of Parties (COP21), held in Paris, France in Intergovernmental Panel on Climate Change (IPCC) released its Spe- December 2015. Since 1992, the Conference of Parties has been cial Report on Carbon Dioxide Capture and Storage, discussing the held annually to revisit ideas and plans set by the United Nations emissions and CO2 purity from the industries already mentioned as Convention on Climate Change (UNFCCC) [1]. COP21 represented well as natural gas processing [7]. The United Nations Industrial an unprecedented moment for climate change action, as over Development Organization (UNIDO) offers several CCS industrial 190 countries agreed to curb GHG emissions to limit the global sectoral reports (biomass, high-purity, iron and steel, refineries and temperature rise to below 2 °C [2]. Within the U.S., further action cement) and collaborated with the International Energy Agency to cut carbon emissions has taken place. In August of 2015, Pres- (IEA) on a CCS technology roadmap [17 22]. The IEA also published ident Obama and the EPA announced the Clean Power Plan, a few sectoral reports of its own, as well as a comprehensive look at whichplacescarbonemissionlimitsonexistingandfuture reducing emissions from a multitude of industries [10,23,24].A power plants. Although it is under review by the Supreme Court, more recent techno-economic assessment of the top four emitting it could be a historic moment for the U.S. as the first ever industries can be found in Kuramochi et al. [25]. national emissions standards [3,4]. TheTagedP global CCS Institute published a report on CCS for iron and CarbonTagedP dioxide makes up the majority of GHG emissions, steel production, as did Gielen [26,27]. The European Cement accounting for 65% of global and 82% of U.S. emissions [4,5]. The U.S. Research Academy (ECRA) released a report on the potential for CCS alone emits approximately 16% of the global CO2 emissions, second within the cement industry [28], while the U.S. EPA published a only to China's 30% [6]. Given the country's contribution to CO2 report on reducing GHG emissions from the petroleum refining emissions, the U.S. must lead the charge to reduce these emissions. industry and hydrogen production [29,30]. The National Energy Carbon capture and storage provides one possible solution. Technology Laboratory (NETL) examined several high and low purity
CarbonTagedP capture and storage (CCS) is considered a critical part sources of CO2 and performed capture cost estimates for both retro- of many climate change mitigation plans, as it provides a bridge fit and greenfield sites [31]. Xu et al., and Kheshgi and Prince have between our current fossil-fuel based economy and a renewable discussed the value and sequestration potential of CO2 emitted dur- energy future [7 14]. To achieve CCS on a wide-scale within sta- ing ethanol fermentation [32,33]. Finally, Wilcox summarized vari- tionary sources, a way to reduce implementation costs could be ous industrial and power plant sources of CO2, as well as potential application at a smaller scale. This opportunity exists when con- geological sequestration and utilization opportunities. She then out- sidering the industrial sector of CO2 emissions. Identifying areas lined the theory and calculation of thermodynamic minimum work of lowest carbon capture (CC) cost will help to offset additional for separating CO2 from gaseous streams [34]. 148 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
AllTagedP of these documents briefly describe the industrial process and conditionsTagedP (i.e., temperature, pressure and CO2 concentration), summarize the techno-economic feasibility of capturing the CO2 which are required to understand how best to capture CO2 from dif- emitted from the process. While each document provides salient ferent industries and to calculate the minimum capture work and information on the top CO2-emitting industries, none of them con- Sherwood cost estimation. A Sherwood plot correlates the relation- tain all of the information necessary to fully analyze industries for ship between concentrations of a target substance with the cost to their CCS potential or tie the CCS potential to geographical regions. separate it from the remaining components, as outlined by House This work intends to provide an updated compendium of CCS oppor- et al [37]. Top-emitting industries are considered, encompassing tunities for the United States. dilute, high-purity, combustion, and process emissions. Spatial anal-
Finally,TagedP several papers have tied together CO2 sources and sinks to ysis in the form of geographic information systems (GIS) is then create CO2 supply chain networks. For instance, Hasan et al. opti- used to bring together key CCS data within the U.S. to determine the mized the CO2 supply chain network between all major CO2-emitting “low-hanging fruit” of CCS and to identify the facilities that have the sources and potential sequestration sites identified by the National lowest CO2 capture cost. Carbon Sequestration Database and Geographic Information System
(NATCARB) [35]. Their spatial analysis considered different types of 2. Process CO2 versus combustion CO2 CO2 sources, capture technologies, capture materials, CO2 pipelines, and locations of storage sites. The resulting optimization estimated a WhenTagedP discussing CO2 emissions from industrial point sources, a total annual cost of $58.1 $106.6 billion to reduce 50 80% of the distinction can be made between “combustion” and “process” CO2. current stationary sourced CO2. While very comprehensive, the study Combustion emissions occur from burning carbonaceous fuels, such only includes CO2 emitted from the flue gas of fossil fuel combustion as natural gas, coal and petroleum, while process emissions account and therefore omits the potential for capture of higher purity sources for all other CO2 released, usually from chemical reactions that are of CO2, which would inevitably result in lower capture costs. required to produce a desired product. Reduction of iron ore into MiddletonTagedP et al. examined high-purity CO2 sources (e.g., acid gas iron, limestone into lime and water-gas shift reactions are examples removal, ammonia, ethanol, hydrogen and natural CO2 formations) of such process reactions. In several instances, process and combus- currently supplying CO2 for enhanced oil-recovery (EOR), and per- tion emissions can occur within the same unit. When process and formed a spatial and life-cycle assessment on potential supply sites combustion emissions are mixed, there is the potential for higher “ ” [36]. They found that much of the U.S. lies in a CO2 desert ,or purity CO2 streams if new and innovative unit designs can separate greater than 500 km from the nearest high-purity CO2 source. They the process reactions from the heat requirements. These two types also found that CO2 from natural formations have the largest carbon of emissions will be discussed in greater detail as each industry is footprint, suggesting that capturing CO2 from high-purity industry considered. sources have an even greater benefit for CO2 reduction since it would TheTagedP industries are ordered from the least concentrated source of leave naturally occurring CO2 in the ground, and limit CO2 emitted CO2 to the most concentrated. For each industry, a base case facility from the extraction phase. This study, however, only includes certain is discussed. The base case was chosen to be the largest U.S. emitter industries and restricts CO2 storage opportunities to EOR. within that industry. Annual emission numbers for 2014 are taken ThisTagedP review aims to collect all CC-relevant data into a single study from the EPA's online FLIGHT database [38]. The process conditions to enable an in-depth analysis of the CCS potential with a focus on (i.e., temperature, pressure, CO2 concentration) for CC-relevant gas the contiguous U.S. The analysis includes a two-level perspective: streams are also provided. nationally across the U.S. and within individual facilities. The facil- TableTagedP 1 displays a breakdown of CO2 emissions by the top-emit- ity-level details include CO2-emitting process units and process ting industries. Fossil fuel combustion makes up the core of U.S. CO2
Table 1
2014 U.S. CO2 emissions from the top-emitting industries.
a b Stationary source 2014 emissions (MMT CO2) % of total CO2 emissions % of total stationary CO2 emissions
Fossil fuel combustion 5208.2 93.74% 90.89% Coal 1653.7 29.76% 43.31% Petroleum 2127.5 38.29% 11.46% Natural gas 1426.6 25.68% 36.11% Electricity generation (fossil fuel) 2039.3 36.70% 53.41% Refineriesc 53.6 0.96% 1.40% Natural gas processingc 17.2 0.31% 0.45% Iron and steel production 55.4 1.00% 1.45% Petrochemical productiond 26.5 0.48% 0.69% Ethylene production 18.8 0.34% 0.49% Ethylene oxide production 1.3 0.02% 0.03% Hydrogen productionc 42.5 0.77% 1.11% Ethanol (Fermentation)e 40.1 0.72% 1.05% Cement production(c) 38.8 (64.3) 0.70% (1.16%) 1.02% (1.68%) Lime production 17.4 0.31% 0.45% Ammonia production(c) 9.4 (14.6) 0.17% (0.26%) 0.25% (0.38%)
All other data was obtained from the US Greenhouse Gas Inventory: 1990 2014 (EPA). For cement production, only CO2 produced from
the calcination reaction is included. For ammonia production, emissions were adjusted to remove CO2 captured for urea production. a Include emissions from transportation sector (mobile emissions) within fossil fuel combustion. b Does not include emissions from transportation sector (mobile emissions). c Data obtained from US GHGRP 2014 FLIGHT database. For these industries, both process and combustion emissions are reported when emitted through a common stack; otherwise combustion emissions are not included. For ammonia production, emission data
includes captive H2 production emissions (which are excluded from H2 production emissions) and CO2 captured for urea production. d Petrochemical Production includes ethylene oxide and ethylene production emissions. e Ethanol (Fermentation) was estimated using an emission factor of 6.29 lbs CO2/gallon ethanol (Xu et al, 2010), and EIA ethanol pro- duction data without denaturant for 2014. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 149
emissions,TagedP with petroleum combustion producing the most emis- COTagedP 2. A 90% CO2 capture rate at 95% CO2 purity was assumed for all sions. However, petroleum combustion is mainly used in transporta- CO2-relevant gas streams, except for those with initial (feed) stream tion (gasoline), which leaves coal as the greatest contributor to purities greater than 95%. In this case, CO2 purity that matched the stationary national emissions. In general, fossil-fueled electricity initial feed stream's purity were assumed, resulting in zero theoreti- generation is the greatest emitter of CO2, contributing over 55% to cal minimum work required for separation. total stationary emissions. Just under 75% of these emissions origi- nate from coal, with most of the balance made up by natural gas. 3.2. Sherwood analysis TheTagedP remaining emitters as shown in Table 1 account for approxi- mately 19% of stationary emissions. Petroleum refining, which is the ATagedP Sherwood analysis was performed to estimate the cost of cap- second largest U.S. industry emitter, still emits 11 times less CO2 turing CO from the capture-relevant industrial gas streams. The than power plants. With such a great disparity between power 2 Sherwood plot (Fig. 2) illustrates that as concentration of a target plants and other industries, it can be easy to overlook the potential substance within a gas stream decreases, its separation costs of capturing industrial process CO2. Industrial process CO2 (also increase. This relationship was developed by Thomas K. Sherwood in referred to as “industry CO2” in this review) may be relatively small, 1959 when he investigated how the market prices of a metal varied but it is unavoidable. As renewable energy generation continues to with the initial concentration of the ore in the raw material. House, increase and displace fossil fuel electricity generation, industry CO2 et al extended this idea to the amount of CO present in a gas stream will constitute an increasingly larger portion of global emissions. 2 that undergoes separation [37]. Fig. 2 displays various gas separation Moreover, unlike fossil fuel-fired power plants, many industries technologies available today and the relationship between initial tar- have few or no CO2-free alternatives for manufacturing their prod- get concentrations and the separation (capture) costs. The data points ucts. While some research is underway to investigate novel produc- shown were calculated from Dr. Ed Rubin's Integrated Environmental tion pathways for some industries, they are highly unlikely to be Control Model (IECM), which simulates gaseous capture technology ready for commercialization on a time scale required to prevent cat- for power plant flue gas [40]. These costs are for Nth-of-a-kind tech- astrophic climate change. nology, and only include capital cost. In the case of the CO2 data Furthermore,TagedP many industries produce CO2 streams at much points, this means compression costs are not included. The data greater purity than power plant flue gas. For example, natural gas points represent the following separation technologies: selective cat- processing and ethanol fermentation can produce near pure streams alytic reduction (SCR) to remove parts per million (ppm)-level NOx; of CO2. Higher purity translates into lower capture costs, as will be wet flue gas desulfurization (WFGD) and lime spray drying (LSD) to discussed in the following section. Low capture costs are important remove ppm-levels of SO (corresponding to the high and low prices for promoting first-of-a-kind CCS technology, whose costs can be fur- x of SO separation, respectively); chemical absorption with MEA CO ther reduced through learning and iterating until it is feasible to use x 2 scrubbing for pulverized coal combustion (PCC) plant with 13% CO2 on larger, more dilute sources of CO2 such as power plants. There- in the flue gas; and physical absorption with Selexol CO scrubbing fore, industrial facilities may be the first adopters of CCS technology. 2 for the integrated combined cycle (IGCC) power plant with 36% CO2 in the flue gas. Due to the variety of separation technologies included 3. The cost of capture: minimum work and economic cost in the Sherwood plot, the subsequent capture cost estimates are technology agnostic. Eq. (2) enumerates the linear fit between the 3.1. Minimum work of separation logarithmic prices of capture and the logarithmic target substance concentration (in molar concentration). ATagedP simplified CO2 separation schematic is shown in Fig. 1. The CO2 Eq.TagedP (2) was used to calculate estimated CO2 capture costs for cap- is removed from feed stream A, resulting in two product streams, i. ture-relevant gas streams. Once again, these capture costs only e., stream B with mostly CO2, and stream C with very little CO2. encompass capital costs, not compression costs for CCS. TheTagedP derivation of the minimum work is provided by House, et al [37]. The minimum work for separation is achieved at isothermal, $ log Price ¼ 0:5558 logðÞ mole fraction of CO2½ % 1:8462 isobaric conditions, reducing the minimum work equation into the kg Gibb's Free Energy difference between the product and feed streams. ð2Þ The streams are assumed to behave as ideal gases, since the gas interactions are negligible in the streams considered [39].
TheTagedP thermodynamic minimum work to separate CO2 from a gas stream was calculated using Eq. (1): ÂÃÀÁ ÀÁÂ ÀÁ ¼ CO2 CO2 þ B CO2 B CO2 þ CO2 CO2 W min RT nB ln yB nB ln yB RT nC ln yC ÀÁÂÃÀÁ ÀÁ þ C CO2 C CO2 CO2 CO2 þ A CO2 A CO2 ðÞ nC ln yC RT nA ln yA nA ln yA 1
WhereTagedP Wmin is the minimum separation work in kJ/mol, R is the universal gas constant 8.314 J/(mol K), T is the temperature in Kelvin, CO2 i-CO ni is the moles of CO2 in stream i,ni 2 are the remaining moles CO2 in stream i without CO2, yi is the mole fraction of CO2 in gas i-CO2 stream i, and yi is the mole fraction of the remaining gas without
Fig. 2. Sherwood plot for gas separation technologies. Separation technologies
include selective catalytic reduction (SCR) for both NOx values, wet flue gas desulfuri-
Fig. 1. Simplified CO2 separation diagram, where CO2 in feed stream A is removed, zation (WFGD) for the higher SOx value, lime spray drying (LSD) for the lower SOx resulting in a mostly CO2 product stream B, and a product stream C with very little value, MEA scrubbing for the CO2 PCC value, and Selexol scrubbing for the CO2 IGCC 2 CO2. value [40].R value is 0.990. 150 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Table 2
Summary of process conditions used in the minimum work and Sherwood cost estimates for the U.S.’s top CO2 emitting industries. The percent of total U.S. emissions reflects the entire industry, and use 2014 numbers. The emissions numbers for each power plant reflect fossil fuel combusted solely for electricity generation purposes.
CO2 source CO2 content CO2 process unit Temperature ( °C) Flue gas component % of U.S. emissions
Petroleum power plant 3 8% Furnace 40 65 CO2, NOx, SOx, O2,N2 0.5
Natural gas power plant 3 5% Gas turbine 93 106 (after HRSG) CO2, NOx, SOx, CO, O2,N2, 8.0 Hg, As, Se
Coal power plant 10 15% Steam boiler furnace 40 65 CO2, NOx, SOx, CO, O2,N2, 28.3 Hg, As, Se
Cement production 30% Precalciner 150 350 CO2,H2O, N2, hydrocarbons, 1.2
volatiles (K2O, Na2O, S, Cl)
14 33% High T Kiln (calcination) 150 350 CO2,H2O, N2, hydrocarbons,
volatiles (K2O, Na2O, S, Cl) Petroleum refineries 8 10% Process heaters 160 190 Depends on fuel used 3.1 3 5% Utilities (steam, electricity) 160 190 Depends on fuel used
10 20% Fluid catalytic cracker (FCC) 160 190 O2,CO2,H2O, N2, Ar, CO, (regeneration of catalyst) NOx,SOx
30 45%, 98 100% H2 purification 20-40 (for PSA), 100 120 CO2,H2, CO, CH4 (for chemisorption)
Iron and steel 20 - 27% Blast furnace (high CO2 if 100 H2,N2, CO, CO2,H2S 1.0 manufacturing BFG is burned)
16 42% Basic oxygen Furnace (high »100 H2,N2, CO, CO2,H2S
CO2 from burning BOF gas)
Ethylene production 7 12% Steam cracking 160 215 H2O, CO, NOx, SOx, O2,N2, 0.3
CO2
Ethylene oxide production »30%, 98 100% Absorption unit to purify EO 16 32 (for water adsorp- Mainly CO2,H2O, N2, (air 0.02
(lower end is air oxida- tion), 100 ¡120 oxidation) some CH4, eth- tion, higher end is oxygen (chemisorption) ylene, EO oxidation)
Ammonia processing 98 100% H2 purification 100 120 (chemisorption) CO2,H2,O2,CH4 0.3
Natural gas processing 96 99% Acid gas removal/CO2 100 120 96 - 99% CO2, 1-4% CHx 0.3 absorption (low P (mainly methane, trace stripper) amounts ethane, propane,
butane), H2O, N2
Hydrogen production 30 45%, 98 100% H2 purification (lower end is 20 40 (for PSA), 100 120 CO2,H2, CO, CH4, After 0.8
(15 20% in stream before PSA, higher end for CO2 (for chemisorption) chemisorption: »100%
purification) specific separation) CO2
Ethanol production 98 99% Fermentation 35 CO2, ethanol, methanol, H2S, 0.7 dimethyl sulphide, acetal- dehyde, ethyl acetate
3.3. The cost of CO2 capture assumptionTagedP of 95% capture purity). Such industries include ethylene oxide, hydrogen, ammonia, and ethanol production, as well as natu-
ATagedP summary of the process conditions (i.e., CO2 concentration, ral gas processing. Such pure streams of CO2 may only require dehy- CO2-emitting process unit and temperature) are listed in Table 2. dration and compression. There is still an associated capital cost for These values were used to calculate the minimum work and esti- building the capture system in addition to operational and mainte- mated financial costs for capturing CO2 from the top-emitting indus- nance costs, resulting in $14 per metric ton of CO2 capture on aver- tries, with the results shown in Table 3. It is apparent that as the CO2 age. For comparison, the National Energy Technology Laboratory purity in the capture-relevant stream decreases, the associated mini- (NETL) recently estimated carbon capture costs for high purity mum work and capture costs increase. For any industrial process industrial sources, resulting in costs of $11.68 $23.09 per metric that produces a stream with greater than 95% CO2 purity, the theo- ton of CO2 captured [31]. retical minimum work to capture it is near zero (given the
Table 3
The minimum work and Sherwood capture cost estimates for top CO2 emitting industries in the U.S.
Source CO2 content (mol %) % of US emissions Minimum work (kJ/mol CO2 capt) Cost ($/tonne CO2 captured)
Natural gasa 3 5 24.8 10.7 12.7 75 100 Petroleuma 3 8 7.9 7.8 11.3 58 100 Coala 10 15 29.8 6.2 7.9 41 51 Refineries 3 20 1.0 7.4 15.5 35 100 Ethylene production 7 12 0.3 9.4 12.8 46 62 Cement production 14 33 1.2 5.2 12.6 26 42 Iron and steel production (BOF)b 20 27 (16 42) 1.0 5.3 6.4 (3.7 7.1) 31 35 (23 39) Ethylene oxide productionc 30, 98 100 0.02 0 4.0 14 28 Hydrogen productionc 30 45, 98 100 0.8 0 4.0 14 28 Ammonia processing 98 100 0.4 0 14 Natural gas processing 96 99 0.3 0 14 Ethanol (Fermentation) 98 99 0.7 0 14 a Only includes stationary fossil fuel combustion as percentage of total U.S. emissions. b For iron and steel production, numbers in parenthesis specifically refer to the basic oxygen furnace (BOF) process unit. c Multiple CO2 content ranges occur due to multiple process pathways available. See industry section for more detail. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 151
ItTagedP should be emphasized that the Sherwood plot estimates Nth- greaterTagedP fraction of CO2 in their corresponding process exhaust of-a-kind capture costs; therefore, as capture technology matures streams. Here, a thorough analysis of process design is presented, for each industry, we should see greater convergence of costs. For with special consideration to process features that would lend to the example, while amine-based post-combustion carbon capture at facile accommodation of capture technology. For each industry cement plants currently have capture costs averaging around $110 described, a representative facility was chosen to illustrate the allo- per metric ton of CO2, it has been shown that chemical looping can cation of CO2 emissions on-site. These base cases were chosen to be reduce costs to the $20 $45 per metric ton of CO2 [41]. These the largest emitters reported in the EPA GHGRP. Emissions at other reduced costs align well with the $26 $42 per metric ton of CO2 facilities will vary. estimated by Sherwood analysis.
OnTagedP the other end, for a CO2 concentration of only 3% in the flue gas stream, the minimum work required increases to 13 kJ per mole 3.4.1.TagedP Petroleum refining TagedP fi of CO2 captured. The cost increases to $100 per metric ton of CO2 The U.S. is the world's largest re ner of crude oil. In 2012, around captured; in other words, there is about a 5-fold increase in capture 144 U.S. refineries produced 803 MMT of petroleum products, net- cost when the concentration decreases by a factor of approximately ting around 22% of global production's 3580 MMT of petroleum fi 30. The highest capture costs are associated with natural gas and products [42]. Around 170 MMT CO2 were emitted by the U.S re n- petroleum-fired power plants. Coal-fired power plants, the largest ing industry in 2014, with 53.6 MMT CO2 of these emissions from emitter of stationary CO2, require on average 6 8 kJ per mole of CO2 process reactions only [43]. In 2008, roughly 818 MMT CO2 were captured, about 25% 50% less energy than capturing from natural emitted globally [21]. TagedP fi gas-fired power plants. Capturing CO2 from coal-fired power plants Petroleum re neries produce various fuels and chemical feed- costs between 30% and 56% less than capturing from natural gas- stock through the distillation of crude oil followed by reforming and fired plants. cracking. While there are many sources of GHG emissions on site, as Overall,TagedP the minimum work ranges from near zero up to approxi- seen in Fig. 5, the majority originate from combustion of fuels, and mately 13 kJ per mole of CO2 captured, with costs ranging from $14 almost all (over 97%) of the emissions are CO2 [21]. The four largest fi fl to $100 per metric ton of CO2 captured. Industrial facilities have the sources of CO2 in a re nery are process heaters, utilities, uid cata- potential to demonstrate CCS technology at about one fifth of power lytic cracker (FCC) and hydrogen production, though a given site plant's capture costs, once again underscoring industrial process may not have all of these units [21].
CO2’s role in assisting the implementation of CCS technology. 3.4.1.1.TagedP Process heaters. TagedPBetween 30 60% of total refinery emissions come from process heaters. Major units include steam reforming,
3.4. Top CO2 emitters from the industrial sector steam cracking, catalytic reforming and the distillation column preheater. Steam reforming and steam cracking will be explored fur-
MajorTagedP industrial emitters of CO2 are summarized in Figs. 3 and 4 ther in the sections on hydrogen production and ethylene produc- according to CO2 purities, total emissions (MMT per annum) and tion. In general, the CO2 content in the flue gases range from 8 10%. number of U.S. facilities reporting to the EPA GHGRP. These emission The CO2 content depends on which fuels are being combusted. In the sources remain promising targets for capture uptake due to the U.S., refineries mainly use natural gas and refinery fuel gas. Refinery
Fig. 3. Summary of CO2 purities of major U.S. industrial emitters of CO2. *BF = blast furnace, BOF = basic oxygen furnace, PSA = pressure swing absorption. 152 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 4. Summary of major U.S. industrial emitters of CO2. Number in parentheses indicates the number of U.S. facilities reporting to the EPA GHGRP. *Petrochemicals includes eth- ylene production (28.1 33.7 MMT) and ethylene oxide production (3.5 3.7 MMT).
fuelTagedP gas (RFG) is roughly composed of 30% H2, 35% C1, and 35% C2 by TheTagedP exhaust temperature will also depend on the process type, volume. CO2-emitting combustion reactions could then look like: though the convection section of fired heaters can significantly reduce the flue gas temperature [44]. For distillation, exit tempera- CH4 þ 2O2 ! CO2 þ 2H2O ð3Þ tures are around 400 °C; for catalytic reformers, 495 525 °C; for C2H6 þ 3:5O2 ! 2CO2 þ 3H2O ð4Þ steam methane reformers, 180 200 °C at the stack; and for steam
Fig. 5. Breakdown of GHG emissions for petroleum refineries across the U.S. Over 97% of the GHG emissions are CO2. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 153
Fig. 6. Process diagram for petroleum refining. 2014 emissions numbers provided by U.S. GHGRP for ExxonMobil Bt Site in Baytown, TX.
cracking,TagedP 800 850 °C at the unit's exit [45]. At the exhaust stack, 30TagedP 45% [51,18,16]. The gas stream exits at a temperature of 20 40 ° temperatures range from 160 200 °C for all process heaters [45,46]. C [49].Refineries are more likely to employ PSA units due to greater impurities in the feedstock.
3.4.1.2.TagedP Utilities (Electricity and steam generation). On-siteTagedP electricity TheTagedP CO2 producing reaction occurs in two steps: steam methane and steam generation can account for 20 50% of refinery CO2 emis- reformation (SMR) and water gas shift (WGS), as shown in Eqs. (5) sions [21]. Coupled electricity and steam generation is called com- and (6), respectively. bined heat and power (CHP). In refineries, RFG and supplemental CH4 þ H2O ! 3H2 þ CO ð5Þ natural gas are combusted in air and sent to a gas turbine to create electricity. The exhaust gases then pass through heat exchangers to CO þ H2O ! CO2 þ H2 ð6Þ produce steam [47]. The exhaust gas contains approximately 4% CO 2 Fig.TagedP 6 depicts a potential process configuration for petroleum by volume and exits between 160 °C and 190 °C [21,46]. refining, based on ExxonMobil's Bt Site in Baytown, TX. Table 4 dis- plays the CO emissions from the different various processes of the 3.4.1.3.TagedP Fluid catalytic cracker (FCC). TagedPA fluid catalytic Cracker (FCC) 2 plant. Process heating accounts for the greater number of emissions, can account for 20 50% of a refineries CO emissions. The FCC uses 2 though the FCC is the largest single emitter of CO . There was no heat, pressure and catalysts to break down large hydrocarbons into 2 hydrogen production associated with this site in particular, though more valuable products. During the reaction, carbon is deposited on there is a petrochemical plant located at the site. In this specific case the catalyst, deactivating it. The catalyst is sent to regenerator for the process heating emissions were taken to be the stationary com- decoking. The catalyst coke is combusted in air, producing CO and bustion emissions listed for this facility under the U.S. GHGRP CO , the CO in the flue gas stream is converted to CO in a CO boiler, 2 2 reporting. These emissions likely include steam generation, though and the boiler captures the heat released for steam production [21]. data was not available to confirm this, and includes stationary com- The stream exits the boiler at 160 190 °C and contains 10 20% CO 2 bustion that occurs for the petrochemical plant. The combination of by volume [46,21]. stationary combustion emissions skews the breakdown of emissions at the base case facility, though it is likely that process heating would 3.4.1.4.TagedP Hydrogen production. TagedPHydrogen production can account for
5 20% of total refinery CO2 emissions [21]. Roughly one third of all U.S. refineries have on-site hydrogen production [29]. The relevant Table 4 fi process step is the purification of hydrogen. Hydrogen purification Breakdown of 2014 CO2 emissions from ExxonMobil's petroleum re nery in Bay- town, TX [38]. may be completed either using CO2 scrubbing or pressure swing absorption (PSA), though PSA has been the dominant technology CO2 source CO2 emissions (metric tons) % of facility emissions since the mid-1980s [48]. When CO scrubbing is used, an absorp- 2 Process heaters 8359,658 80.30% tion column using an amine solution is used to specifically remove Fluid catalytic cracking 1849,208 17.80% CO2 from the product stream. The CO2 is then released from the Sulfur recovery 140,722 1.40% stripping column at high purities (»99%) and temperatures between Flares 52,751 0.51% 100 120 °C [49,50]. PSA targets hydrogen specifically, with all other Catalytic reforming 2046 0.02% Process vents 1693 0.02% impurities, including CO2, exiting as off-gas. Subsequently, PSA TOTAL 10,406,077 100% results in a lower concentration of CO2 in the gas stream, between 154 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
produceTagedP the majority of emissions even with adjusted numbers. As otherTagedP process heaters. The flue gas is then vented, releasing CO2 into stated previously, petroleum refineries located in the U.S. mainly the atmosphere [15]. burn natural gas and RFG in process heaters. RFG consist of light C1 TheTagedP light method of ethylene production prevails in the U.S., to C4 hydrocarbons, H2,H2S and other light top gases from distilla- using natural gas, ethane, propane and butane as feedstock rather tion columns that are not condensed in the overhead condenser than heavier hydrocarbons like naphtha. The latter three feedstocks [29]. are known as liquefied petroleum gas (LPG), and comprised around
PetroleumTagedP refineries are distinctive among the CO2-intensive 90% of fresh feed in the U.S. in 2013. Of this, over 65% consisted of industries in that there are numerous CO2-producing units. The dis- ethane [15,56 58]. perse nature of these units can make it difficult to implement CCS Fig.TagedP 7 shows a process diagram for ethylene production, and without a common stack. For example, instead of trying to place CC includes emissions numbers from the Westlake Petrochemical LP in devices at each process heater exhaust stack, it may be best to focus Sulphur, LA. The breakdown of CO2 emissions at this site is given in on the largest single CO2 emitters. Additionally, each refinery is Table 5. For the base case, there are ethylene production units and it uniquely configured to produce a distinctive portfolio of products, was assumed that all furnaces labeled with a reference to one of the which depend on the petroleum feedstock used; therefore, a CC production units was part of the steam cracker for that production design for one refinery will not likely fit another refinery. unit. The facility is required by the U.S. GHGRP to report the fraction
GivenTagedP the variety of CO2 emitting units in refineries, there is also of CO2 emitted that comes from burning ethylene off-gas. Overall, a wide range of minimum work for separation and capture costs. about 12.4% of combustion emissions from the steam crackers were The minimum work for separation ranges from 7.4 to 15.5 kJ/mol attributed to ethylene off-gas. While ethylene off-gas only contrib-
CO2 captured excluding hydrogen production, and less than 4.0 kJ/ utes 5.5% to total facility CO2 emissions, the steam crackers account mol CO2 captured for hydrogen. The Sherwood analysis yielded a for 44.1% of total facility emissions. Flares associated with each of capture cost ranging from $35 to $100 per MT of CO2 captured, the ethylene production units emit 49.3% of total facility CO2. excluding H2 production. Hydrogen production capture costs range CombustionTagedP of the off-gas and natural gas and other fossil fuels between $14 and $28 per MT of CO2 captured; oil refineries would leads to CO2 emissions. Steam cracking consumes the greatest likely incur the higher end of the H2 production capture cost range amount of energy at refineries and petrochemical plants, A negligi- due to the prevalence of PSA purification, which results in a more ble amount of CO2 is emitted during decoking of the furnace, in dilute stream of CO2. which steam or a steam and air mixture react with carbon to pro- duce CO and CO2 [59]. The concentration of CO2 in the flue gases ranges from 7 12% CO2, though it depends on the ratio of off-gas (CH ,H) to primary fuel and the exact composition of the off-gas 3.4.2.TagedP Ethylene production 4 2 [7]. The flue gas temperature ranges between 160 °C to 215 °C [46]. TheTagedP U.S. ranks as the top producer of ethylene (C H ), a feedstock 2 4 FarlaTagedP et al. estimated that the cost of capturing and transporting widely used to produce chemicals, such as polyethylene, ethylene (by train) CO from a 10% CO flue gas stream is $45 per metric ton oxide and ethylene chloride [52]. In 2013, the U.S. produced 28.1 2 2 of CO avoided [15]. Given that costs for avoided emissions are MMT of ethylene, capturing about 19.7% of world production [53]. 2 higher than costs for captured CO , and transportation was included Many ethylene production sites are co-located at petroleum refiner- 2 in Farla et al.’s analysis, the Sherwood cost estimations are slightly ies, since petroleum products serve as a feedstock for ethylene. higher at $46 $62 per metric ton of CO captured. Around 18.8 MMT CO were emitted by U.S. ethylene production in 2 2 Finally,TagedP there are a couple of CC projects involving ethylene pro- 2014 [38]. duction. Mitsui Chemicals in Japan are capturing the CO2 and using it to make methanol while at least one ethylene plant is capturing 3.4.2.1.TagedP Process overview. FractionalTagedP distillation is performed on nat- their CO and sending it for sequestration in Denmark's, Sweden's, ural gas and other feedstocks to obtain ethane (C H ), propane 2 2 6 and Norway's Kattegat Skagerrak project [60,22,61]. (C3H8) and/or butane (C4H10). The hydrocarbon feed (e.g., ethane and propane) each undergo steam cracking, also known as pyrolysis, 3.4.3.TagedP Cement production at high temperatures. Steam crackers consist of furnaces which heat CementTagedP production is one of the largest CO -emitting industries the feedstock in tubes running through the combustion chamber. At 2 globally, with the U.S. contributing 64.3 MMT of CO in 2014 [38].In high temperatures, hydrocarbon chains break down, forming dou- 2 2014, the U.S. produced 82.6 MMT of cement while the world pro- ble-bonded and lighter single-bonded hydrocarbons (Eqs. (7) and duced a total of 4180 MMT. China accounts for the majority of pro- (8)). For an ethane and propane mixture, the temperatures range duction, claiming 59.6% of global cement production. The runner-up, between 650 and 815 °C, while an ethane-only feed is cracked at India, only captured 6.6% of the production [62]. Although the U.S. 800 850 °C [49]. only makes up 1.9% of world production, any technology improve- C H ! C H þ H ð Þ 2 6 2 4 2 7 ments that occur from implementing CC in the U.S. can be extended to countries like China. C3H8 ! C2H4 þ CH4 ð8Þ TheTagedP cracked gaseous products, ranging from hydrogen to heavy 3.4.3.1.TagedP Process overview. CementTagedP is produced from calcium carbon- fuel oil are immediately quenched at 400 °C in a heat exchanger to ate (CaCO3), also known as limestone. Raw materials such as lime- prevent the reactions from breaking down all hydrocarbons to meth- stone and the oxides of aluminum, silicon and iron are first grinded ane, CH4 [54,55]. Further water injection into the product stream and then travel to the preheater and the precalciner, where it is pre- cools it down to 40 50 °C. The product stream is compressed and heated using flue gas from the rotary kiln. The limestone undergoes fractionated to yield purer streams of ethylene, propylene, butadi- its initial calcination, or reduction, in the precalciner, where addi- ene, etc. The liquid stream leaves at the bottom of the column and tional heat is provided via fuel combustion (Eq. (9)). After these pre- undergoes further processing and distillation. The ethane and pro- liminary processes, the limestone and other components enter the pane streams are recycled back to the steam cracking unit. For rotary kiln to undergo further reduction into lime (CaO). Pulverized heavier feedstock such as naptha, an additional separation step is coal or another fuel is blown into the kiln and combusted, providing required (e.g., cryogenic unit) to isolate the ethylene [56]. The light- the heat required for the reactions. Different chemical reactions est off-gases (CH4,H2 and by-product propane, ethane) are com- occur within the temperature zones in the kiln. The first zone dehy- busted with natural gas to provide heat for the steam cracker or drates the incoming material at 20 900 °C. Calcination occurs at P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 155
Fig. 7. Process diagram for an ethylene production plant. Emission numbers taken from U.S. GHGRP for Westlake Petrochemicals LP in Sulphur, LA for 2014. temperaturesTagedP between 850 °C and 950 °C. Clinkerization occurs at combustionTagedP in the precalciner. A stream of flue gas and air may also the highest temperatures in the kiln, between 1200 °C and 1450 °C be siphoned off of the air quencher, bypass the kiln and flow directly [23]. to the preheater as combustion air. Fig. 8 shows that the majority of emissions come from the preheater exhaust stack rather than the air CaCO3 þ heat ! CaO þ CO2 ð9Þ quencher stack after the rotary kiln. The flue gas then continues to TheTagedP clinker pellets enter another grinder or mill where it is an electrostatic precipitator before being vented. The CO2 content in grinded and mixed with gypsum, forming cement [63]. the flue gas ranges from 14% to 33% CO2, and exits at a temperature TheTagedP major emitter of CO in cement production is the rotary kiln. 2 between 150 °C and 350 °C. [64 66]. The higher CO2 content is likely In the kiln, CO is emitted from both fuel combustion (usually coal) 2 associated with the additional calcination CO2 in the precalciner and and limestone calcination. In the U.S., coal is the primary fuel used in preheater. the kiln, accounting for 59% of the heat consumed. Petroleum coke TheTagedP vast majority of U.S. cement plants, about 90%, use the more and waste fuels make up the remainder of heat input [62]. Cement energy efficient “dry process” [62]. The dry process uses less water production illustrates how process and combustion emissions can during the raw material grinding and crushing, requiring less heat be combined in a single unit. Just over half of the CO2 originates for input for the dehydration stage. the calcination, while just under half of the emissions originate from TheTagedP U.S. is home to one of the first cement plants with CC tech- the combustion of fuel [64,65]. nology. Skyonic has retrofitted a cement plant in Texas with CC. The TheTagedP kiln flue gas takes one of several paths. The flue gas may exit CO2 is then converted into baking soda, creating an additional reve- at the end of the kiln, where it travels through an air quenching nue stream [67]. Other projects worldwide are also underway at cooler and an electrostatic precipitator before being vented, or it the European Cement Research Academy (ECRA), they are using oxy- may flow through the precalciner and preheater, where further CO 2 fuel configurations to capture the CO2 before the heat generation, is added during calcination of incoming limestone and the fuel and in Norway and Taiwan, post-combustion CC projects are under- way [23]. Finally,TagedP the International Energy Agency's Greenhouse Gas pro- Table 5 gram (IEA GHG) estimated post-combustion captures costs of $161 CO2 emissions breakdown for the base case ethylene production facility, Westlake per metric ton of CO2 avoided [23]. Their configuration included a Petrochemicals LP in Sulphur, LA. Numbers taken from U.S. GHGRP for 2014. CHP plant to generate steam for regenerating the amine solution
Unit CO2 emissions (metric ton) Percent of total CO2 used to capture the CO2. The Sherwood analysis yielded a capture cost of $26 - $42 per metric ton of CO captured. However, as dis- Steam crackers 870,607.60 44.14% 2 Off-gas combustion 107,669.40 5.46% cussed earlier, chemical looping produces carbon capture costs Process heaters (boilers) 124,551.50 6.31% between $20 and $45 per metric ton of CO2. Once again, the technol- Flares 977,318.50 49.55% ogy agnostic and Nth-of-a-kind qualities of the Sherwood analysis Associated with ethylene pro- 973,103.10 49.33% can produce estimates that may be lower than those from initial duction unit TOTAL 1972,477.60 100.00% technology options. 156 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 8. Process diagram for cement production. 2014 emission numbers taken from U.S. GHGRP for Holcim Inc. Genevieve Plant in Bloomsdale, MO.
3.4.4.TagedP Iron and steel production TagedPthe oven. The tar, ammonia and light oil are removed, leaving light TheTagedP U.S. is the fourth largest producer of iron and steel in the hydrocarbons such as methane and hydrogen. This cleaned coke world at 5.3% of global production in 2014. China is the largest pro- oven gas (COG) can be combusted for heating the coke oven or other ducer, capturing 49.4% of the 1665.2 MMT global production, fol- processes or simply flared. In nonrecovery coke ovens, the off-gases lowed by the EU at 10.1% and Japan at 6.6% [68]. Within iron and are not sent to a separation process; instead, the COG gas is burned steelmaking, iron production accounts for 70-80% of CO2 emissions as-is, with heat recovered for steam or electricity generation [70]. [26]. The U.S. emitted 55.4 MMT CO2 from iron and steel production SinterTagedP production occurs in a separate unit as coke is produced. In in 2014. sintering, iron ore fines are heated to melt into pellets for the blast ThereTagedP are several routes for iron and steelmaking. Primary steel furnace. Coke breeze (fine particles of coke) are used as the fuel production uses mostly iron to produce steel, while secondary steel source [69]. Next, iron ore, sintered iron ore, limestone flux and coke production uses mostly recycled scrap steel. Within primary steel enter the blast furnace. The blast furnace transforms the iron ore production, there are two major pathways: the blast furnace with into pig iron, the precursor to steel. Hot air is blasted from the bot- basic oxygen furnace (BF/BOF) and the direct-reduced iron with the tom of the furnace, combusting with the coke to create carbon mon- electric arc furnace (DRI/EAF). The CO2 is already captured at DRI/ oxide (CO). The CO reacts with the iron ore to remove the oxygen, EAF plants to improve the quality of the recycled reduction gas [27]. reducing it to iron. The overall reduction reactions as well as individ- Secondary steel production always uses an electric arc furnace ual reactions are shown in Fig. 9 [71]. The blast furnace is another (EAF). Within the U.S., about 40% of iron and steel industry uses the example of process and combustion emissions combined into a sin- BF/BOF process, while the remaining 60% uses the secondary EAF gle unit. The blast furnace gas (BFG) is the collected and combusted process. Since the DRI/EAF process is not used in the U.S., it will not to Cowper heaters to preheat the incoming blast air before being be discussed here. Furthermore, the secondary EAF process emits vented. much less CO2 than the primary BOF process due to reduced energy TheTagedP molten iron, also known as pig iron, is siphoned out of the requirements by using recycled scrap steel instead of manufacturing bottom of the BF and sent to the basic oxygen furnace (BOF) for iron. Additionally, the recycled steel enters the process already steelmaking. In the BOF, pig iron and steel scraps react with pure reduced, so the emissions-intensive iron-making stage is bypassed oxygen to remove the remaining carbon and other impurities [72]. and between 70 80% of emissions are avoided [26]. While EAF con- Around 80% of the BOF input material is pig iron, with scrap steel sume large amounts of electrical energy, fossil fuel combustion may making up the balance. The reduction reactions create mostly CO be off-set using alternative electricity generation sources. with some CO2; initially, the BOF gas composition is 16% CO2 and InTagedP the case of CCS, the blast furnace in the BF/BOF process is the 70% CO. The CO is combusted at the top of the furnace before being largest single emitter of CO2 in the iron and steelmaking process; vented, increasing the CO2 content to up to 42% [15]. The heat from therefore, the BF/BOF process will be the focus of this section. combustion can be used in a HRSG, or it can simply be cooled before being cleaned. If needed, an extra decarburization step may occur to 3.4.4.1.TagedP Process overview primary BF/BOF. TagedPPrimary iron and steel- further purify the steel and remove carbon. making facilities utilizing the blast furnace and basic oxygen furnace pathway are known as “integrated steel mills”. First, coke is pro- 3.4.4.2.TagedP Process overview secondary EAF. SecondaryTagedP EAF facilities are duced in a coke oven. There are two coke production configurations: known as “mini-mills”. The majority of their feedstock is recycled by-product and nonrecovery. Coal is carbonized in an almost oxy- steel in the form of scraps, while up to 10% of the feedstock can be gen-free environment at high temperatures to create coke. Coke pro- pig iron. The scrap steel is sent to an electric arc furnace (EAF), which duction allows the carbon content to become concentrated [69].In charges the metal and creates an electrical arc which melts the steel, by-product coke ovens, the off-gases are collected from the top of removing carbon and impurities. Alloying reagents and slag material P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 157
Fig. 9. Blast furnace diagram and associated reactions.
areTagedP included in the EAF for further refining [72]. Since coke produc- TagedPand capture cost than if only natural gas had been used. The theoret- tion, sintering and iron ore reduction are avoided, and fuels are not ical minimum work to capture the CO2 from the blast furnace is necessarily combusted on-site for electricity needs, much less CO2 is 5.3 6.4 kJ per mole CO2 captured, while the Sherwood capture cost emitted at mini-mills. is $31 $35 per MT of CO2 captured.
3.4.4.3.TagedP Process conditions BF/BOF. CarbonTagedP dioxide is emitted from the combustion of coke breeze in the sintering plant, the combustion 3.4.5.TagedP Ethylene oxide production of coke oven gas in the coke oven, the blast furnace, and the basic TheTagedP U.S. is one of the world's largest producer of ethylene oxide oxygen furnace, in addition to other process heating and flaring. The (EO), along with China and Saudi Arabia. The U.S. alone is responsible
CO2 concentrations are as follows: 5 10% in the sintering plant for approximately 15% of global production in 2013 [73]. [74] Like exhaust gas, 25% in the coke oven exhaust, 20 27% from the blast ethylene, EO is widely used in the chemical industry, and is often furnace (latter concentration from combustion of BFG), and 16 42% produced at petrochemical plants located at or near refineries. CO2 from the BOF (latter concentration from combustion of BOF gas). emissions from EO production numbered at 1.3 MMT CO2 in 2014; Although exact exhaust temperatures were not found for coke oven while this is small compared to other industries, the purity of EO's or sintering plants, it is reasonable to assume exhaust from all four process streams still make it an attractive option for carbon capture processes have temperatures around 100 °C, as most streams are [73]. cleaned and cooled before being vented [25,27]. All exhaust streams ThereTagedP are two types of EO production pathways: air oxidation or are at 1 bar. direct oxygen oxidation. In both cases, ethylene is oxidized into eth- AsTagedP mentioned previously and confirmed by the emissions break- ylene oxide. The majority of U.S. production uses the direct oxidation down for the iron and steel base case (Fig. 10), the blast furnace is pathway [75]. Both pathways are described in this section. the greatest single source of CO2 at iron and steel plants. Though process heaters combined account for 59% of the base case's emis- 3.4.5.1.TagedP Process overview air oxidation. Ethylene,TagedP the feedstock for sions (Fig. 11), they are dispersed throughout the plant without a EO, and air enter a reactor with a silver catalyst at a temperature common stack, making CC difficult. In the blast furnace, it is impor- between 200 °C to 300 °C and pressure between 10 to 30 bar and tant to note once more that both process and combustion CO2 are undergoes oxidation. The reactor product stream flows to the pri- combined into one vessel. Although it is unclear how much of the mary absorber, where water adsorbs the EO, and the dissolved EO
CO2 emitted from the blast furnace are process versus combusted, stream travels to the desorber unit, while a portion of the overhead determining a way to separate the combustion from the reduction stream is sent back to the reactor as recycle. The remaining overhead reactions could lead to a purer stream of CO2 from the blast furnace gases pass through another coupled secondary, or purge, reactor and and reduced cost for CO2 capture. EO water absorber. Nitrogen (N2) and CO2 are vented from the purge TableTagedP 6 shows the breakdown of the CO2 emissions by fuel at the absorber, resulting in a 30% CO2 content stream. The EO then enters base case plant. BFG accounts for 78% of the CO2 emissions from a desorption unit to recycle the water, and finally enters a stripper combustion, while natural gas (primary fuel) only accounts for 17%. distillation column to remove any remaining N2,CO2, and other The combustion of BFG produces CO2 concentrations at 20 27%, impurities. Due to the N2, the CO2 concentration is once again higher than the typical natural gas CO2 concentration of 3 5% for diluted to 30% by volume in the exit stream [76]. The purified EO gas turbines or 7 10% for boilers, resulting in lower minimum work stream continues to further processing to create ethylene glycol and 158 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 10. Process diagram for blast furnace and basic oxygen furnace primary iron and steel production. 2014 emission numbers taken from U.S. GHGRP for U.S. Steel Corps plant in Gary, IN.
otherTagedP products [17]. Fig. 12 provides a pictorial representation of the puriTagedP fication step, the stripper unit, where the stripper removes any air oxidation pathway. remaining light inert gases such as CO2, though only a small amount is released. The EO stream continues on for further processing [76]. 3.4.5.2.TagedP Process overview direct oxygen oxidation. InTagedP direct oxidation Fig.TagedP 13 shows the process diagram for ethylene oxide production via near-pure oxygen, ethylene and oxygen similarly enter a reactor for the Equistar Chemical plant in Pasadena, TX, where over 95% of with silver catalyst. The reaction temperature and pressure are on-site emissions come from the purification of ethylene oxide. slightly different than in the air oxidation pathway; temperatures range from 200 °C to 300 °C, with pressures between 10 to 30 bar 3.4.5.3.TagedP Process conditions. TagedPIn the air oxidation pathway, CO2 is emit- [18]. The reactor product stream enters a primary absorber column, ted from a secondary reactor and the stripper column at a concentra- where once again water physically adsorbs EO. The overhead gases, tion of 30%. The oxygen oxidation pathway releases CO2 from the including CO2, enter a CO2-specific absorber column using the hot CO2-desportion unit and the stripper, resulting in »99% purity CO2 potassium carbonate process (HPCP). The potassium carbonate [17,15]. In all cases, the exit CO2 stream has a temperature between absorbs the CO2, and travels to the desorption column to recycle the 100 °C to 120 °C after chemisorption [49]. absorbent and release the CO2, and an almost pure stream (»99%) of EOTagedP production and the following sections illustrate high purity CO2 is vented. sources of CO2.CO2 capture is actually already built into the EO TheTagedP EO-rich product stream, dissolved in water, enters a desorp- industry through the purification steps. The only steps needed for an tion unit for regeneration. The EO stream then heads to the final almost pure stream of CO2 is dehydration and compression. EO
Fig. 11. Breakdown of 2014 CO2 emissions from the base case facility, U.S. Steel Corps at Gary, IN. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 159
Table 6 TagedPwhich do not emit process CO2 [77]. Approximately 60 MMT of CO2 Breakdown of 2014 CO emissions by fuel type at the U.S. Steel 2 were emitted from H2 production in 2008, with over 70% of emission Corps iron and steel plant in Gary, IN. coming from on-purpose captive applications such as petroleum fi Fuel type Emissions (MT CO2) % of Total re neries and ammonia plants. Merchant H2 outside of these indus- tries accounted for almost all of the remaining CO (Table 7). The U. Blast furnace gas 6677,544.70 78.07% 2 Coke oven gas 402,759.00 4.71% S. GHGRP reported 42.5 MMT CO2 from H2 production in 2014, Natural gas 1455,276.70 17.01% though these emissions exclude captive H2 production in the ammo- Residual fuel oil no. 6 17,763.00 0.21% nia industry. The U.S. GHGRP includes emissions from refinery H2 TOTAL 8553,343.40 100.00% production within the H2 industry tally. InTagedP the U.S., around 95% of H2 production uses natural gas reform- ing, also called steam methane reforming (SMR); this section will productionTagedP is an excellent candidate for implement CCS technology, focus on SMR as the main production process [78]. Finally, although since direct oxygen oxidation is prevalent in the U.S. and results in a an increasing amount of H production is purified using PSA rather low-cost opportunity. 2 than CO scrubbing with an amine solution, both processes will be FarlaTagedP et al. estimated that CO capture from EO production would 2 2 discussed. only cost $9 per metric ton of CO2 avoided in 1995, which would translate to about $14 in 2014 dollars [15]. The Sherwood analysis 3.4.6.1.TagedP Process overview. TagedPNatural gas is the feedstock of H2 produc- estimated costs to be between $14 and $28 per metric ton of CO2 tion using the steam methane reformation (SMR) technique. Before captured. Since CO avoided costs are generally higher than its corre- 2 entering the reactor, the natural gas undergoes hydrodesulphuriza- sponding CO2 captured costs, Farla's cost estimate is quite a bit lower tion to remove any H S that could poison the catalysts in the than the Sherwood estimate. 2 reformer [79]. The natural gas then enters the SMR unit, where it reacts with steam at high temperatures (700 °C 1000 °C) at pres- TagedP 3.4.6. Hydrogen production sures of 3 25 bar [78]. At this point, CO2 is produced through the TagedP In 2008, the U.S. produced 10 11 MMT of hydrogen (H2), captur- combustion of methane and through the SMR reaction (Eqs. (10) and ing between 25 and 27% of global production. The majority of H2 (11)). However, unlike in the cement rotary kiln or the iron blast fur- production is for captive use in the chemical and refinery industries, nace, the combustion and process reactions are separate. The com- indicating that H2 production occurs at the same site as or very close bustion occurs in the furnace, while the reaction takes place in “ ” to other major sources of CO2. Captive use refers to H2 produced reactor within the SMR furnace (Fig. 14). The combustion flue gases “ ” and consumed on-site, while merchant H2 is produced on-site and contain CO2 concentrations around 7 10%, and exit at temperatures “ sold to other companies. Furthermore, H2 production may be on- between 160 °C and 200 °C [7]. After the SMR reactor, the CO2 con- ” “ ” purpose or produced as a byproduct of another process. On-pur- centration is around 7 12% by volume, while H2 makes up 69 78% pose merchant production accounted for 15.3% of 2006 production, [49]. while on-purpose captive accounted for 48.7% of production. CH þ H O þ heat ! CO þ 3H ð10Þ Byproduct production accounted for around 36% of total U.S. produc- 4 2 2 tion in 2006. The majority of byproduct H2 come from catalytic CO þ H2O ! CO2 þ H2 þ heat ð11Þ reforming at petroleum refineries and chlorine-alkali production,
Fig. 12. Process diagram for ethylene oxide air oxidation pathway. 160 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 13. Process diagram of ethylene oxide production using the direct oxygen oxidation pathway. 2014 emission numbers are taken from the U.S. GHGRP for Equistar Chemicals
Limited Partnership Bayport Plant in Pasadena, TX. Note that emissions are in metric tons of CO2.
TheTagedP H2 product stream then enters a two-stage water-gas shift atTagedP a temperature between 100 °C and 120 °C [49]. In both cases, car- (WGS) converter to produce more H2 and the high temperature bon capture systems would be placed after the H2 purification step. WGS reactor contains iron oxide catalysts at 300 °C 450 °C, while DueTagedP to the range in CO2 purity in target streams, the Sherwood the low temperature WGS reactor contains copper and zinc oxide analysis cost for capture ranges from $14 per MT of CO2 captured for catalysts are 200 °C 250 °C. The CO2 content in the stream after the high purity to $28 per MT of CO2 captured for lower purities. The lit- WGS converter is 15 20% by volume, while the H2 content is 77 to erature estimates a cost of $5 to $70 per MT of CO2 net captured, 79% [49,18]. which is equivalent to CO2 avoided; the extremes are quite a bit TheTagedP final step in H2 production is purification. Hydrogen may be lower and higher than the Sherwood costs [82]. purified in several ways. The most common are by pressure swing WhileTagedP PSA is becoming more prevalent in the H2 production absorption (PSA) and chemical absorption of CO2 followed by metha- industry, a simple way to promote CCS is to encourage new facilities nation. Fig. 15 shows the process overview for hydrogen production, to use the CO2 scrubbing purification method instead. The PSA train and displays emission numbers from Air Products Port Arthur Facil- could also be expanded to include CO2 removal. The hydrogen pro- ity, where the hydrogen purification produces 74% of the total on- duction industry may also prove useful in providing experience for site CO2 emission. pre-combustion CC technology, as both require SMR and WGS units InTagedP PSA, as shown in Fig. 16,H2 is targeted for removal, with all to produce H2 as fuel while capturing CO2. remaining impurities being vented. This method is popular amongst fi petroleum re neries, as there are many impurities in the syngas 3.4.7.TagedP Ammonia processing stream. The CO2 is diluted by the other gases, resulting in a CO2 con- TheTagedP U.S. produced 11.3 MMT of ammonia (NH3) in 2014, captur- tent between 30 to 45% CO2 [18,16]. The gas is vented at 20 °C to 40 ° ing 6% of the world's 176.3 MMT of production, and trailing China, C and 1 bar [50,80]. The H2 stream then undergoes methanation to remove any remaining CO2 and CO as CH4. WhenTagedP CO2 amine scrubbing is used, a much higher purity of CO2 is released. During desorption, the CO2 exits at 98.5 to 100% [81,18]
Table 7
Estimated 2008 CO2 emissions from hydrogen production [30]. Production type from [77].
Hydrogen Business sector Estimated CO2 CO2 breakdown production type emissions (MMT per year)
On-purpose Merchant H2 17 28.3% merchant On-purpose captive Oil refineries 25 41.7% On-purpose captive Ammonia plants 18 30.0% On-purpose captive Methanol plants None 0.0% Byproduct Chlorine plants None 0.0% Other < 1 < 1% TOTAL 60 100% Fig. 14. Steam methane reformer unit used in hydrogen production. Process and combustion CO2 are produced in separate parts of the unit. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 161
Fig. 15. Process diagram for hydrogen production using a CO2 scrubbing technology. 2014 emission numbers taken from U.S. GHGRP for Air Products Port Arthur Facility in Port Arthur, TX.
RussiaTagedP and India. China led with 33% of global production [83]. In the hydrogenTagedP is purified using CO2 amine absorption or HPCP producing U.S., around 88% of ammonia went into fertilization production [84]. high purity CO2 streams for carbon capture [86]. About 9.4 MMT of CO2 were released in the U.S. in the same year, according to the U.S. GHGRP. The emissions include captive hydro- 3.4.7.1.TagedP Process overview. TagedPNatural gas first undergoes desulfurization gen production emissions, but do not include CO2 captured for urea to remove any H2S that can contaminate the catalysts in the reactors. production. The natural gas and steam enter the primary reformer, which produ-
HydrogenTagedP production and ammonia have many process similari- ces CO and H2 at temperatures of 730 °C (Eq. (10)) [87]. The product ties. To produce ammonia, hydrogen must first be produced and stream, containing 7 12% CO2,69 78% H2 and 9 13% CO by vol- then reacted with nitrogen, usually sourced from air. Two-stage ume, then enters the secondary reformer. Compressed air is injected steam methane reforming (SMR) is the main ammonia production into the secondary reformer reactor to obtain a 3:1 ratio of H:N pathway used in the U.S. In 2011, around 92.5% of ammonia was pro- atoms for ammonia synthesis [88]. Partial oxidation of CH4 also duced using natural gas feedstock [85]. Partial oxidation is another occurs, yielding CO, H2, and H2O(Eq. (12)) [15]. After the secondary potential pathway, but will not be discussed further in this section. reformation, the product stream contains 7 12% CO2,55 57% H2, The process CO2, formed during SMR and WGS, is emitted during the 22 24% N2, and 12 15% CO by volume [49]. H2 purification step. However, within the ammonia industry, most CH4 þ O2 ! CO þ H2 þ H2O ð12Þ
Fig. 16. Process diagram for hydrogen production using pressure-swing absorption. 162 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
TheTagedP product stream then enters a high temperature and lower 3.4.8.TagedP Natural gas processing temperature WGS reactor, while the H2 and N2 streams are then TheTagedP U.S. is the world leader in natural gas production and subse- purified using CO2 scrubbing, as PSA would also remove the N2 quently natural gas processing. In 2014, the U.S. produced 20.7% of needed for ammonia synthesis. The CO2 absorption may be per- the world's supply [89]. In 2014, 56 MMT CO2 were emitted in the U. formed using an amine solution or potassium carbonate (HPCP). S. Combustion CO2 from process heaters comprised 65% of total CO2 is released at purities of 98.5 to 100% and a temperature emissions, while process emissions from venting and flaring made between 100 °C and 120 °C [49].TheH2 and N2 product stream up the balance. Within process emissions, 62% of CO2, or 22% of total then undergoes methanation to remove any residual CO and CO2 CO2, came from acid gas removal (AGR). AGR mainly consists of as CH4 [87]. removing CO2 from natural gas produced at the well [90,91]. TheTagedP N2 and H2 are then reacted together to produce ammonia, and the ammonia undergoes further separation. If urea is produced 3.4.8.1.TagedP Process overview. TagedPNatural gas produced at a wellhead con- on-site, the CO2 from the absorber column is sent to reactor so that tains mainly methane (CH4), but also smaller amounts of ethane, it may react with the ammonia to form urea (NH2CONH2) in a two- butane, propane and pentane as well as undesirables such as water, step reaction (Eqs. (13) and (14)). H2S, CO2, He and N2 [92]. The acid gases H2S and CO2 “sour” the gas mixture; removing these gases “sweetens” the natural gas and con- 2NH3 þ CO2 ! NH2COONH4 ð13Þ stitutes one part of the cleaning process [18]. TagedP NH2COONH4 ! H2O þ NH2CONH2 ð14Þ There are four main natural gas processing steps: oil and conden- sate removal, water removal (dehydration), acid gas removal (sweet- TheTagedP two main points of divergence from the hydrogen production ening), and separation of natural gas liquids. The oil and condensate process described previously are the secondary reformer and the removal occurs at the wellhead. Condensate, also known as natural CO -specific removal step using either amine or potassium carbon- 2 gasoline, consists of heavier hydrocarbons (C5 and heavier) that are ate. As with hydrogen production, CO is released from two main 2 liquid at ambient T [92]. The product stream is then dehydrated, locations: the amine desorption unit and the steam reformer flue either at the wellhead or further downstream. gas. The amine absorption unit, which contains process CO , exits at 2 TheTagedP raw natural gas travels from the wellhead to the processing purities of 98.5% to 100% CO and a temperature between 100 °C and 2 plant to undergo AGR. Initial CO content in raw natural gas can vary 120 °C. The flue gas, containing combustion CO , exits with a CO 2 2 2 from 2% to 70% by volume [18]. In AGR, H S and CO impurities are concentration between 7 and 10% CO at a temperature between 2 2 2 removed to meet natural gas pipeline specifications, usually less 160 °C and 200 °C. than 2% CO by volume. An amine absorption system or membrane Fig.TagedP 17 shows the base case ammonia plant located in Donalds- 2 separate the H S and CO from the natural gas stream. Over 95% of ville, LA. Just under 60% of the 5.32 total MMT CO come from the 2 2 2 AGR processes use amine absorption [92,93]. The acid gas stream CO desorption, though some of this CO is used for urea production 2 2 then enters a Claus process unit, where the H S is converted to ele- and sold to other companies. The combustion CO from the reform- 2 2 mental sulfur and recovered. A relatively pure stream of CO ers account for around 19% of the CO emitted, with the urea boiler 2 2 (96 99% by volume) exits the Claus unit. The CO stream is either making up the balance. 2 incinerated, vented or captured for enhanced oil recovery (EOR) TheTagedP high purity CO stream results in a Sherwood cost of $14 per 2 [18,94]. MT of CO captured. Rubin estimated capture costs of $5 to $70 per 2 TheTagedP final processing step is to separate the natural gas liquids. ton of net CO captured for ammonia, hydrogen and natural gas 2 The stream is fractionated into valuable hydrocarbon streams processing plants [82]. Once again, while these estimates are for including methane, ethane, propane, butane and pentane and avoided CO , the extremes are much lower and higher than the Sher- 2 heavier. Fig. 18 depicts the natural gas processing system. Acid gas wood estimates. removal accounted for over 58% of on-site CO2 emissions. The
Fig. 17. Process diagram for ammonia manufacturing. 2014 emission numbers taken from U.S. GHGRP for CF Industries Nitrogen LLC in Donaldsville, LA. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 163
Fig. 18. Process diagram for natural gas processing. 2014 emission numbers were taken from U.S. GHGRP for the Shute Creek Facility near Kemmerer, WY. Total facility CO2 emis- sions were 3.02 MMT.
remainingTagedP CO2 comes almost exclusively from stationary combus- 3.4.9.1.TagedP Process overview dry-milling. MillingTagedP is the first step in eth- tion, though a fraction of CO2 is emitted from flaring. anol production. Entire corn kernels are ground into a flour called CarbonTagedP dioxide is emitted from process heaters and the AGR unit. “meal”, keeping all grain components together. Water is added in Carbon capture technology would be best placed after the Claus the slurry stage, creating “mash”. Enzymes are added to convert unit, due to a high purity of CO2, between 96 99% by volume [18]. starch to simple sugars, and ammonia is added for pH control and The temperature of the exit stream is between 100 °C and 120 °C at a yeast nutrient. The mash is next sent to a high temperature cooker pressure of 1 bar [95 97] to kill off bacteria. The mash is then cooled before traveling to the
CapturingTagedP CO2 at natural gas processing is relatively low cost, as fermenters, where yeast is introduced. The fermentation step can the amine system already performs the most energy and economi- take from 40 to 50 hours. During this, the glucose in the simple sug- cally expensive step in CCS. Some natural gas processing sites ars is converted to ethanol and CO2 (Eq. (15)). already capture their CO2 for EOR purposes, indicating that experi- C6H12O6 ! 2CO2 þ 2C2H5OH ð15Þ ence in CC already exists. The Sherwood analysis estimates a cost of OnceTagedP fermentation is complete, the ethanol is separated from the $14 per MT of CO2 captured, while Rubin once again estimates a cost solid grain residue “stillage” in a distillation column. The ethanol is of $5 to $70 per MT of CO2 avoided [82]. then dehydrated to 200 proof using molecular sieves. Finally, a dena- turant is added to the ethanol to make it undrinkable. The product is 3.4.9.TagedP Ethanol production stored until shipment [99]. Fig. 19 visualizes the dry-milling process, TheTagedP majority of ethanol is produced in the U.S. and Brazil. In and includes emission numbers from the ADM Corn Processing facil- 2013, the U.S. produced 13,321 millions of gallons of corn-based eth- ity in Cedar Rapids, IA. anol, capturing 57% of global production. Brazil produced 6267 mil- OnTagedP average within the U.S., about 35% of the CO2 emitted from lions of gallons of sugar cane-based ethanol in the same year [98]. ethanol plants comes from combustion, while the remaining 65%
More than 30% of the U.S. merchant CO2 market is sourced from eth- comes from fermentation. Although biogenic CO2 is not recorded anol plants due to the almost pure stream of CO2 that is released under the U.S. GHGRP, ethanol plants nonetheless emit a significant during fermentation [99]. In 2014, around 40.1 MMT of CO2 were amount of CO2 and should be considered candidates for CCS. CCS released from fermentation alone (see Table 1 footnotes). combined with biofuels allow for “carbon negative” fuels, or fuels
EthanolTagedP may be produced from corn or sugar cane. Since the vast that sequester more CO2 during production than is released upon majority of U.S. ethanol production uses corn feedstock, the corn combustion. ethanol process will be the focus of this section [32,100]. Further- more, ethanol production may use dry-milling or wet-milling. More 3.4.9.2.TagedP Process overview wet-milling. TagedPThe main difference between than 80% of U.S. production uses dry-milling, though both will be wet-milling and dry-milling is the separation of grain components described [101]. in the first step. In wet-milling, the corn kernels are soaked in water 164 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 19. Process diagram for dry-milling ethanol production. 2014 process heating emission numbers taken from U.S. GHGRP and fermentation emissions estimated using 2014 EIA production capacity data for ADM Corn Processing facility in Cedar Rapids, IA. andTagedP dilute sulfurous acid to separate the grain into starch, protein emissions.TagedP With these in hand, we can begin to regionally character- and fiber components. The components are then isolated from each ize emissions and CCS opportunities. other as they travel through a set of grinders and separators. The PetrochemicalTagedP plants (ethylene, ethylene oxide) and petroleum fiber and steeping liquor from the first step are dried to produce refineries are grouped along the Texan and Louisianan Gulf Coast, as corn gluten feed. The feed is sold to the livestock industry. The pro- well as near New Jersey ports. California (Bay Area and Los Angeles) tein, in the form of gluten, is filtered and dried to make corn gluten and Washington (Seattle) also house refineries, in addition to hydro- meal for feed. The remaining starch and water may then be pro- gen plants. Many hydrogen facilities are located near or at refineries, cesses in one of three ways: fermented into ethanol, dried and sold or are scattered throughout the Midwest. Similarly, ammonia plants, as modified corn starch, or processed into corn syrup. If ethanol is which use hydrogen feedstock, are located near hydrogen sites, pre- made, it follows the same steps as discussed in the dry-milling pro- dominantly in the Midwest and Louisiana. cess [99]. NaturalTagedP gas processing and ethanol production produce nearly
pure streams of CO2. Though these sources tend to emit smaller 3.4.9.3.TagedP Process conditions and cost. CarbonTagedP dioxide is emitted from amounts of CO2, there are many of them and they tend to be near the fermenter at purities of 98 99% by volume, and almost ambient one another. Clusters of natural gas processing operations are found conditions of 35 °C and 1 bar [33,102]. At such high CO2 purity, Xu in North Dakota, down through Wyoming, Colorado and New Mex- et al. estimated a cost of $6 to $12 per MT of CO2 captured, a bit ico, with the majority of natural gas processing occurring in Okla- lower than the Sherwood estimates of $14 per MT of CO2 captured homa, Texas and Louisiana. Ethanol production is prevalent in the [33]. The low cost of capture coupled with industry experience in Midwest, particularly Iowa, Minnesota, Illinois, Indiana and capturing CO2 for the merchant market create a very favorable situa- Nebraska. Several facilities produce a significant amount of CO2,on tion for CC. Adding CC to ethanol plants appear to be one of the most par with larger emitters like cement. viable options explored in this work [17,60]. CementTagedP production, lime production, hydrogen production and
iron and steel manufacturing tend to emit large amounts of CO2 from single facilities, making them attractive for CC technology. Iron 4. Why country-level emissions? and steel plants are generally aggregated along the north and east- ern parts of the Midwest (northern Minnesota, Michigan, Illinois, AlthoughTagedP the focus in this review is on opportunities to apply CCS Indiana, Ohio) and parts of the East Coast (Pennsylvania and New to U.S.-based industries, it is equally important to investigate CO2 Jersey to South Carolina). Cement production facilities, which consis- emissions on a global scale to develop a broader understanding and tently emit large amounts of process CO2, are scattered fairly evenly complete the picture of CC's potential. This is considered a first step across the U.S. Finally, lime production is located primarily in the toward developing a clear pathway, with the hope that the U.S. will interior of the U.S., within the Midwest and the West. take the lead on some of these projects. Combining facility locations Overall,TagedP ethanol and ammonia production and natural gas proc- with the costs of carbon capture allows for outlining the “low-hang- essing produce the purest streams of CO2. Hydrogen, cement and ing fruit” of CC. Once these facilities have been identified, spatial lime production consistently produce the greatest amount of process analysis is further used to match CO2 sources with potential sinks. CO2, followed by iron and steel manufacturing. Table 8 lists the top Only by zooming out from a facility to a national perspective can we ten CO2 emitters by state for each category of emissions, while truly realize the impact of CCS and create project pathways for Fig. 21 visualizes process-only CO2 emissions on a state level. Texas fl implementation. Fig. 20 provides a nationwide visualization of CO2 trumps all other states, and electricity generation CO2 greatly in u- emissions, while Fig. 21 showcases industrial process-only ences the top capture-relevant CO2 emitters. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 165
Fig. 20. Total CO2 emissions from the top stationary sources for 2014. Include combustion and process emissions. Emission data sourced from the U.S. GHGRP.
4.1. Process versus combustion CO2 TheTagedP largest pure CO2 emitters (96 100% CO2) are ammonia and ethanol, with a few natural gas processing plants included. Hydrogen
ProcessTagedP CO2 has been the main focus of the discussion thus far, is the next purest stream of CO2, but is already potentially more than but many facilities emit significant amounts of combustion CO2 for half the concentration of CO2 as the pure streams (30 45% CO2). For- process heating and other thermal needs. Fig. 22 depicts and com- tunately, this does not correspond to a tripling of capture costs at the pares process emissions to combustion emissions at each facility. On lower concentration end; costs only increase from $14 to $28 per ton the whole, it appears that combustion emissions are fairly balanced of CO2 captured. with process CO2. Cement and lime production facilities tend to SinceTagedP many of these high purity sources are located in the Mid- have significantly more process CO2 to combustion. The same is true west and along the Gulf Coast, these are the regions of the U.S. that for a few ammonia, iron and steel plants and ethanol plants, though have the greatest potential for first-of-a-kind CC technology. In other the difference is not nearly as large for ethanol plants. The opposite words, the Midwest and the Gulf Coast hold the “low-hanging fruit” is true for refineries, petrochemical and hydrogen plants, with com- of CCS. More specifically, the central and southern Midwest, and bustion emissions only slightly greater than process emissions. Gulf Coast are the regions that CCS pilot plants and demonstration projects should target, as they will result in the cheapest initial cap-
4.2. CO2 sources by purity ture costs, and are co-located with potential sequestration sites (Fig. 25). If all of these high purity sources (pure sources plus hydro-
CombiningTagedP data on location, quantity and purity of the CO2 point gen) were captured, it would account for about 5% of total U.S. car- sources creates a picture of the CC potential within the U.S. and iden- bon emissions. While this is small relative to the CO2 reduction tifies the “low-hanging fruit”. Fig. 23 shows such an image, with the required to mitigate climate change, it is nonetheless a first step to
CO2 quantities and qualities visualized. Each color corresponds to deploying CCS on a wider scale. the CO2 purity of the capture-relevant stream, with darker colors ATagedP few facilities also already appear to use CC technology to pro- indicating higher purity. In this case, petroleum refineries were con- vide CO2 for injection into enhanced oil recovery (EOR) sites sidered more concentrated than coal power plants since the cap- (Fig. 24). Ammonia plants in Louisiana, northern Texas and North ture-relevant process CO2 neglected process heating. Process Dakota are connected via CO2 pipelines to nearby EOR fields. There heating is the lower end of the refining CO2 concentration range; are other numerous industrial CO2 sources by these pipelines, although the 3 20% range is shown for consistency in this work, in including natural gas processing, hydrogen, lime, and petrochemical reality the CO2 sources shown are likely to have concentrations production plants and petroleum refineries. While it is unclear between 10 20%. whether any of these facilities are used to provide CO2 to the fields, HydrogenTagedP production was considered to be within the 30 45% it nevertheless shows the potential of tapping into these existing purity range, since this is associated with the PSA purification pro- CO2 resources for utilization and leaving natural CO2 in the ground. cess, which is increasingly used in industry. However, it should be Despite the fact that EOR is a CO2 utilization rather than sequestra- noted that some of these hydrogen plants could also be in the tion, as the CO2 is not monitored or verified to remain underground, 96 99% CO2 range. it still provides an economic incentive for capturing CO2 from nearby 166 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 21. Industrial process-only (no electricity generation) CO2 emissions for the U.S. by (a, top) facility and by (b, bottom) state. Emission data sourced from the U.S. GHGRP.
Table 8
Top ten CO2 emitting states for (a) (left) capture-relevant CO2, (b) (center) electricity generation CO2, and (c) (right) indus-
trial process CO2.
Total capture-relevant CO2 Electricity generation CO2 Industrial process CO2
State Quantity (MMT CO2) State Quantity (MMT CO2) State Quantity (MMT CO2)
Texas 283.17 Texas 231.98 Texas 51.20 Indiana 120.28 Florida 109.95 Louisiana 27.14 Florida 114.15 Indiana 101.88 California 25.34 Ohio 107.85 Ohio 95.92 Indiana 18.40 Pennsylvania 102.34 Pennsylvania 94.75 Iowa 12.35 Illinois 92.06 Kentucky 84.53 Illinois 12.10 Kentucky 88.94 Illinois 79.96 Ohio 11.93 Missouri 80.08 West Virginia 69.98 Missouri 10.99 Alabama 76.79 Missouri 69.09 Alabama 8.61 Louisiana 74.88 Alabama 68.18 Michigan 8.47 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 167
Fig. 22. Process CO2 and combustion CO2 for industrial facilities only (non-electricity generating facilities). Emission data sourced from the U.S. GHGRP.
facilities.TagedP The EOR market can further to help offset the capture costs COTagedP 2 conversions are often energy-intensive due to the thermody- for building the initial CC fleet. namic stability of fully oxidized carbon. Hence, full life-cycle assess- ments will often reveal that carbon utilization is carbon positive
using traditional grid power and conventional routes for H2 produc- 4.3. A note on CO2 utilization tion, emitting more CO2 than is consumed during utilization [110,111]. Coupling of these opportunities to renewable energy is InTagedP addition to reliable storage, carbon dioxide utilization (CCU) often a knee-jerk solution to this unfavorable carbon balance; how- and reuse has gained traction as an alternative fate for captured CO2. ever, detailed analyses must be performed at the regional level to This route has the advantage of creating revenue from a waste prod- determine if it is not more efficient to place such renewable energy uct, which in theory could be applied to offset capture, compression directly into the power grid. Even in the face of carbon-positive utili- and transport costs. Additionally, this route may be advantageous or zation, in some cases, CO2-based processing is less carbon intensive desirable in areas where reliable storage opportunities do not exist, than the incumbent process. For example, an industrial case study or exist at distances which are cost prohibitive from a transportation shows CO2 emissions reductions on the order of 11 19% when CO2 perspective. Carbon dioxide utilization opportunities include, but is employed in polyurethane production [112]. Nevertheless, these are not limited to, EOR, mineral carbonation, food and beverage collective points serve to highlight the complexities in considering processing, urea production and yield boosting, liquid fuel produc- CCU, and the necessity for reliable LCA data for gaining proper tion, and many other avenues using CO2 as a chemical feedstock. insights; thus, such opportunities are not explored in this review. Several reviews have presented these opportunities in great detail [103 107]. 5. Conclusions ItTagedP is important to consider several factors when weighing the potential benefits of CCU. First, very few utilization opportunities Facility-levelTagedP analysis of the top CO2-emitting industries is exist at the scale to make a direct impact on climate. Of current required to fully understand the potential for CCS in the United opportunities, EOR owns the significant majority of the CO2 utiliza- States. Capture costs and minimum separation work can be calcu- tion market. Even with this large share [108], US demand (ca. 70 Mt/ lated when the process conditions of capture-relevant CO2 streams a) would only offset 1% of annual US CO2 emissions. One utilization are known. Although fossil-fueled power plants dominate stationary opportunity with sufficient scalability to impact climate is CO2 to CO2 emissions, other industries may provide a cheaper pathway fuels, with future potential cited at the gigatonne scale [109]. How- toward CCS deployment. Many industrial processes also lack CO2- ever, oxidized fuels immediately recommit CO2 to the atmosphere; free alternatives, making CCS necessary for their future success. thus, it is important to consider the period of carbon fixation if such ItTagedP is useful to know which process unit is the largest CO2 emitter utilized CO2 is to be counted against climate change. within an industry. Capture technology implemented at that one 168 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172
Fig. 23. Capture-relevant CO2 emissions by size and purity. Purity corresponds to capture cost, with higher purity CO2 sources costing less on a per mole CO2 captured basis. Emission data sourced from the U.S. GHGRP. unitTagedP will maximize emissions reduction for a minimal cost. Indus- ontoTagedP many individual emitting units, and choosing a single unit may tries with a single large CO2 source unit, such as cement production not have as much of an impact as in other industries. Additionally, and iron and steel manufacturing, are therefore attractive CCS candi- refineries’ distinct site configurations make it difficult to determine dates. However, even in these cases, process heating emissions can a CC implementation standard across the industry. Several indus- still account for more than half of all on-site CO2. Process heaters tries, including hydrogen production, ammonia production, and nat- tend to be comprised of multiple units, further exacerbating CCS ural gas processing, already have CC technology built into their installation challenges. purification steps in the form of amine absorption. These three PetroleumTagedP refineries face a unique challenge with their myriad industries and ethanol production form the high-purity set of indus- processes. It would be very problematic to retrofit CCS technology tries, or industries that produce CO2 streams pure enough that no
Fig. 24. Capture-relevant CO2 sources by size and purity, with EOR sites and existing and future CO2 pipelines. Emission data sourced from the U.S. GHGRP. P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 169
Fig. 25. CO2 top-emitting sources and potential sinks and utilization sites (EOR), with current and proposed CO2 pipelines included. Emission data sourced from the U.S. GHGRP.
additionalTagedP CO2 separation is required. Existing CC paves the way for NaturalTagedP gas processing and ethylene oxide, while they produce easily completing a CCS retrofit by only adding processing units such high purity streams, only account for relatively small portions of as dehydration and compression. industrial process CO2. On the other hand, petroleum refineries TableTagedP 9 summarizes several salient features for choosing a path- account for almost a fifth of industrial process CO2, but are com- way forward for implementing CC. For instance, industries where prised of numerous lower purity CO2 streams. These qualities make process CO2 and combustion CO2 are combined could indicate an these three industries less attractive for initial CC implementation, increased complexity in designing a capture system if only process and better suited for consideration towards the end of the industrial
CO2 is targeted. However, if the industry accounts for a large portion CC pathway. Finally, ethylene production emits relatively small of process emissions across many industries, prioritizing it for car- amounts of dilute CO2, making it the last industry to be considered bon capture could produce a greater mitigation impact than other on the CC pathway. industries. Considering these factors, a possible implementation ItTagedP is also important to consider the largest single emitters of CO2: pathway would focus on ethanol production facilities first, as they power plants. Fossil-fuel power plants are unlikely to disappear on a produce high purity streams which make up 65% of on-site emis- time scale necessary to mitigate climate change. CCS provides a sions and account for sizable portion of total industrial process CO2 pathway for fossil-fueled power plants to act as a bridge between considered in this review. The cement industry would be the next today and a low-carbon, renewable energy future. Though power contender, given a large percentage of on-site emissions emanate plant flue gas is relatively dilute in CO2 and therefore expensive to from the cement kiln, and cement accounts for almost a quarter of separate, capture costs may be reduced by using the knowledge total industrial process CO2. gained from first implementing the technology on industrial sour- TheTagedP ammonia industry would make an attractive third choice, ces. due to its high purity stream of CO2 that accounts for 63% of on-site TheTagedP picture of CCS potential within the U.S. is completed by tak- CO2 emissions. Hydrogen production could be considered next, as it ing facility-level data and combining it with geographic CO2 point produces a relatively high purity CO2 stream which accounts for a source data. Emerging trends create a deeper understanding of majority of on-site emissions. Iron and steel manufacturing produces nationwide emissions, and allow areas of lowest capture cost to be several low to moderately concentrated CO2 streams, and the blast identified. Overall, Texas emits the most CO2 from both electricity furnace produces a mixed process and combustion stream of CO2. generation and industrial processes. In addition to Texas, Louisiana The division between process and combustion within the blast fur- and the Midwest emit the most process CO2, while the eastern Mid- nace is a complicated one. The combustion of coke produces CO, west (stretching from Missouri to Pennsylvania) and Florida emit which then reduces iron ore and creates CO2. Extricating process the most electricity generation CO2. Capturing all of the capture-rel- CO2 from combustion CO2 is therefore a tricky task, and may further evant process CO2 could cost between $6.17 and $11.13 billion U.S. complicate the capture process if a redesign if desired. These factors per year, and would offset roughly 5% of total 2014 U.S. CO2 emis- push iron and steel manufacturing further down the CC pathway. sions. Capturing all capture-relevant CO2 (from both process and 170 Table 9 Characteristics of industries to help identify the low-hanging fruit of CCS.
Industry Process and Number of low Number of medium Number of high Percentage of CO2 Percentage of CO2 Percentage of total Percentage of total c,d d combustion CO2 purity streams purity streams purity streams from process from combustion industry process industry CO2 a,b a a combined? (0% 10% CO2) (10% 50% CO2) (50% 100% CO2) CO2
Ethanol Production No 1 (fermentation) 64.87% 35.13% 14.5% 11.1% Ammonia No 1 (SMR heater) 1 (amine scrubbing) 62.55% 37.45% 5.5% 3.9% Processing Natural gas No 1 (flares) 1 (acid gas removal) 25.97% 74.03% 6.5% 9.4% processing Hydrogen No 1 (SMR heater) 1 (PSA tail gas) 1 (amine scrubbing) 92.79% 7.21% 15.9% 15.2% Productione Iron and Steel Yes 2 (sinter plant, 3 (BF, BOF, coke 45.33% 54.67% 11.4% 13.5% Production flares) oven) Cement Production Yes (»50% process) 2 (precalciner, 93.19% 6.81% 24.3% 11.0%
[64] cement kiln) 146 (2017) 63 Science Combustion and Energy in Progress / al. et Bains P. e Petroleum Refining No 1 (flares) 2 (FCC, catalytic 1(H2 production) 25.63% 74.37% 20.1% 29.3% reforming) Ethylene No 2 (steam cracker, 13.32% 86.68% 1.2% 6.4% Productione flares) Ethylene Oxidef No 1 (flares) 1 (air oxidation 1 (oxygen oxidation 0.5% 0.2% pathway) pathway) a by volume. b All industries can count process heating as a low purity stream. c When process and combustion CO2 are emitted from the same stack, the U.S. Greenhouse Gas Reporting Program counts all of the CO2 as process CO2, which may lead to some artificially higher aver- age percentage of CO2 considered Process. This is especially true for cement production and iron and steel production, as process and combustion CO2 are created from within the same chamber for cer- tain process units. Hydrogen production's high percentage of CO2 considered process is likely due to PSA tail gas being combusted for heat in combination with other fuels. d Facility averages across each industry. e The vast majority of facilities that containted more than one industry were petroleum refineries pair with either hydrogen production or ethylene production. As combustion emissions are reported in aggregate for each facility, the following method was used to assign combustion CO2 emissions to each industry: the average percentage of CO2 considered process was taken over all single-industry hydrogen and ethylene production facilities, and used to allocate combustion CO2 to their industry. The remaining combustion CO2 was then allocated to the petroleum refining industry. f Ethylene oxide total process CO2 taken from U.S. Inventory of Greenhouse Gases: 1990 2014 [73]. 172 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146 172 171 electricityTagedP generation) could cost between $93.35 to $122.53 billion TagedP[22] International Energy Agency (IEA) & United Nations International Development Organization (UNIDO). Technology roadmap: carbon capture and storage in U.S. per year, and could displace around 41% of CO2 emissions. industrial applications. International Energy Agency; 2011. TheTagedP minimum work of separation and Sherwood cost analysis TagedP[23] International Energy Agency Greenhouse Gas R&D Programme (IEA GHG). CO2 show that as the CO2 purity in a capture stream increases, the work capture in the cement industry. UK: IEA GHG; 2008. and capture cost on a molar basis decrease. This is critical to finding TagedP[24] International Energy Agency (IEA). Energy technology transitions for industry: strategies for the next industrial revolution. Paris: International Energy Agency; the lowest cost opportunities for CCS pilot plant deployment. The 2009. GIS analysis also shows that higher-purity point sources also tend to TagedP[25] Kuramochi T, Ramirez A, Turkenburg W, Faaij A. Comparative assessment of emit less CO2 than dilute sources. By combining capture cost data CO2 capture technologies for carbon-intensive industrial processes. Prog Energ – with the geographical locations of different industrial point sources, Combust 2012;38:87 112. TagedP[26] Ultra-Low CO Steelmaking (ULCOS). CCS for iron and steel production. http:// the “low-hanging fruit” of CCS have been located in the Midwest and www.globalccsinstitute.com/insights/authors/dennisvanpuyvelde/2013/08/23/ along the Gulf Coast. These regions have many high-purity CO2 ccs-iron-and-steel-production;; 2013 [Accessed 14.06.10]. TagedP industries, such as ethanol production, natural gas processing, [27] Gielen D. CO2 removal in the iron and steel industry. Energ Convers Manage 2002;44:1027–37. ammonia production and hydrogen production. The southern Mid- TagedP[28] Hoenigg V, Hoppe H, Emberger B. Carbon capture technology - options and west and Gulf Coast are also co-located with potential geological potentials for the cement industry. Duesseldorf: European Cement Research sequestration sites, another important piece to the CCS puzzle. Academy; Report No. PCA R&D Serial No. 3022 2007. TagedP[29] U.S. Environmental Protection Agency. Available and emerging technologies for Therefore, southern Midwest and Gulf Coast are the regions in the reducing greenhouse gas emissions from the petroleum refining industry. United States that should be targeted for implementing CCS pilot Research Triangle Park (NC): U.S. Environmental Protection Agency; 2010. plants and demonstration projects. TagedP[30] U.S. Environmental Protection Agency. Technical support document for hydro- gen Production: proposed rule for mandatory reporting of greenhouse gases. Washington, D.C: U.S. Environmental Protection Agency; 2008.
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