Progress in Energy and Combustion Sciencejlwilcox/documents/bains_industry.pdfimplementation pathway is presented that initially focuses on CO 2 capture from ethanol production, fol-lowed

Progress in Energy and Combustion Science 63 (2017) 146�172

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Progress in Energy and Combustion Science

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CO2 capture from the industry sector

TaggedPPraveen Bainsa,b, Peter Psarrasa, Jennifer Wilcoxa,*TaggedP

aDepartment of Chemical and Biological Engineering, Colorado School of Mines, Golden, CO 80401, USAbDepartment of Energy Resources Engineering, Stanford University, Stanford, CA 94305, USA

TAGGEDPA R T I C L E I N F O

Article History:Received 11 January 2017Accepted 9 July 2017Available online 17 August 2017

* Corresponding author.E-mail addresses: [email protected], wilcox@m

http://dx.doi.org/10.1016/j.pecs.2017.07.0010360-1285/© 2017 Elsevier Ltd. All rights reserved.

TAGGEDPA B S T R A C T

It is widely accepted that greenhouse gas emissions, especially CO2, must be significantly reduced to pre-vent catastrophic global warming. Carbon capture and reliable storage (CCS) is one path towards controllingemissions, and serves as a key component to climate change mitigation and will serve as a bridge betweenthe fossil fuel energy of today and the renewable energy of the future. Although fossil-fueled power plantsemit the vast majority of stationary CO2, there are many industries that emit purer streams of CO2, whichresult in reduced cost for separation. Moreover, many industries outside of electricity generation do nothave ready alternatives for becoming low-carbon and CCS may be their only option. The thermodynamicminimum work for separation was calculated for a variety of CO2 emissions streams from various indus-tries, followed by a Sherwood analysis of capture cost. The Sherwood plot correlates the relationshipbetween concentrations of a target substance with the cost to separate it from the remaining components.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 andalong the Gulf Coast. Many high purity industries, such as ethanol production, ammonia production andnatural 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 startingpoint, these sites may provide the demonstration and knowledge necessary for reducing carbon capturetechnology 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 possibleimplementation 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 accountfor relatively small portions of industrial process CO2. Finally, petroleum refineries account for almost a fifthof industrial process CO2, but are comprised of numerous low-purity CO2 streams. These qualities makethese three industries less attractive for initial CC implementation, and better suited for considerationtowards the end of the industrial CC pathway.

© 2017 Elsevier Ltd. All rights reserved.

TaggedPKeywords:
Climate changeCarbon capture from industryCement manufacturingIron and steel productionPetroleum refiningNatural gas processing
ines.edu (J. Wilcox).

Contents
1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1472. Process CO2 versus combustion CO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1483. The cost of capture: minimumwork and economic cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
3.1. Minimumwork of separation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1493.2. Sherwood analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1493.3. The cost of CO2 capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1503.4. Top CO2 emitters from the industrial sector. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

3.4.1. Petroleum refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1513.4.1.1. Process heaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1513.4.1.2. Utilities (Electricity and steam generation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

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3.4.1.3. Fluid catalytic cracker (FCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1533.4.1.4. Hydrogen production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

3.4.2. Ethylene production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1543.4.2.1. Process overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

3.4.3. Cement production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1543.4.3.1. Process overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

3.4.4. Iron and steel production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1563.4.4.1. Process overview�primary BF/BOF. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1563.4.4.2. Process overview�secondary EAF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1563.4.4.3. Process conditions�BF/BOF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

3.4.5. Ethylene oxide production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1573.4.5.1. Process overview�air oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1573.4.5.2. Process overview�direct oxygen oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1583.4.5.3. Process conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158

3.4.6. Hydrogen production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1593.4.6.1. Process overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

3.4.7. Ammonia processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1603.4.7.1. Process overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161

3.4.8. Natural gas processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1623.4.8.1. Process overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162

3.4.9. Ethanol production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1633.4.9.1. Process overview�dry-milling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1633.4.9.2. Process overview�wet-milling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1633.4.9.3. Process conditions and cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

4. Why country-level emissions? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1644.1. Process versus combustion CO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1654.2. CO2 sources by purity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1654.3. A note on CO2 utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167

5. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167

1. Introduction

TaggedPClimate change has been a topic of much debate over the pastseveral decades. Increased levels of carbon dioxide (CO2) andother greenhouse gases (GHG) are responsible for the globalwarming that fuels climate change. As the acceptance of climatechange has increased, so too has the related discussion on waysto adapt to and mitigate its existence. The most recent exampleis the 21st Conference of Parties (COP21), held in Paris, France inDecember 2015. Since 1992, the Conference of Parties has beenheld annually to revisit ideas and plans set by the United NationsConvention on Climate Change (UNFCCC) [1]. COP21 representedan unprecedented moment for climate change action, as over190 countries agreed to curb GHG emissions to limit the globaltemperature rise to below 2 °C [2]. Within the U.S., further actionto cut carbon emissions has taken place. In August of 2015, Pres-ident Obama and the EPA announced the Clean Power Plan,which places carbon emission limits on existing and futurepower plants. Although it is under review by the Supreme Court,it could be a historic moment for the U.S. as the first evernational emissions standards [3,4].

TaggedPCarbon dioxide makes up the majority of GHG emissions,accounting for 65% of global and 82% of U.S. emissions [4,5]. The U.S.alone emits approximately 16% of the global CO2 emissions, secondonly to China's 30% [6]. Given the country's contribution to CO2

emissions, the U.S. must lead the charge to reduce these emissions.Carbon capture and storage provides one possible solution.

TaggedPCarbon capture and storage (CCS) is considered a critical partof many climate change mitigation plans, as it provides a bridgebetween our current fossil-fuel based economy and a renewableenergy future [7�14]. To achieve CCS on a wide-scale within sta-tionary sources, a way to reduce implementation costs could beapplication at a smaller scale. This opportunity exists when con-sidering the industrial sector of CO2 emissions. Identifying areasof lowest carbon capture (CC) cost will help to offset additional

TaggedPcosts associated with installing and demonstrating first-of-a-kindtechnology.

TaggedPThere have been many studies that have focused on the top fouremitting industries (i.e., iron and steel, cement, petroleum refiningand petrochemical). Farla et al. published one of the first industrialassessments of CCS in 1995, focusing on the Netherlands, while Van-sant published a chapter dedicated to characterizing the top-emit-ting industries within the European Union [15,16]. In 2005, theIntergovernmental Panel on Climate Change (IPCC) released its Spe-cial Report on Carbon Dioxide Capture and Storage, discussing theemissions and CO2 purity from the industries already mentioned aswell as natural gas processing [7]. The United Nations IndustrialDevelopment Organization (UNIDO) offers several CCS industrialsectoral reports (biomass, high-purity, iron and steel, refineries andcement) and collaborated with the International Energy Agency(IEA) on a CCS technology roadmap [17�22]. The IEA also publisheda few sectoral reports of its own, as well as a comprehensive look atreducing emissions from a multitude of industries [10,23,24]. Amore recent techno-economic assessment of the top four emittingindustries can be found in Kuramochi et al. [25].

TaggedPThe global CCS Institute published a report on CCS for iron andsteel production, as did Gielen [26,27]. The European CementResearch Academy (ECRA) released a report on the potential for CCSwithin the cement industry [28], while the U.S. EPA published areport on reducing GHG emissions from the petroleum refiningindustry and hydrogen production [29,30]. The National EnergyTechnology Laboratory (NETL) examined several high and low puritysources of CO2 and performed capture cost estimates for both retro-fit and greenfield sites [31]. Xu et al., and Kheshgi and Prince havediscussed the value and sequestration potential of CO2 emitted dur-ing ethanol fermentation [32,33]. Finally, Wilcox summarized vari-ous industrial and power plant sources of CO2, as well as potentialgeological sequestration and utilization opportunities. She then out-lined the theory and calculation of thermodynamic minimum workfor separating CO2 from gaseous streams [34].

148 P. Bains et al. / Progress in Energy and Combustion Science 63 (2017) 146�172

TaggedPAll of these documents briefly describe the industrial process andsummarize the techno-economic feasibility of capturing the CO2

emitted from the process. While each document provides salientinformation on the top CO2-emitting industries, none of them con-tain all of the information necessary to fully analyze industries fortheir CCS potential or tie the CCS potential to geographical regions.This work intends to provide an updated compendium of CCS oppor-tunities for the United States.

TaggedPFinally, several papers have tied together CO2 sources and sinks tocreate CO2 supply chain networks. For instance, Hasan et al. opti-mized the CO2 supply chain network between all major CO2-emittingsources and potential sequestration sites identified by the NationalCarbon Sequestration Database and Geographic Information System(NATCARB) [35]. Their spatial analysis considered different types ofCO2 sources, capture technologies, capture materials, CO2 pipelines,and locations of storage sites. The resulting optimization estimated atotal annual cost of $58.1�$106.6 billion to reduce 50�80% of thecurrent stationary sourced CO2. While very comprehensive, the studyonly includes CO2 emitted from the flue gas of fossil fuel combustionand therefore omits the potential for capture of higher purity sourcesof CO2, which would inevitably result in lower capture costs.

TaggedPMiddleton et al. examined high-purity CO2 sources (e.g., acid gasremoval, ammonia, ethanol, hydrogen and natural CO2 formations)currently supplying CO2 for enhanced oil-recovery (EOR), and per-formed a spatial and life-cycle assessment on potential supply sites[36]. They found that much of the U.S. lies in a “CO2 desert”, orgreater than 500 km from the nearest high-purity CO2 source. Theyalso found that CO2 from natural formations have the largest carbonfootprint, suggesting that capturing CO2 from high-purity industrysources have an even greater benefit for CO2 reduction since it wouldleave naturally occurring CO2 in the ground, and limit CO2 emittedfrom the extraction phase. This study, however, only includes certainindustries and restricts CO2 storage opportunities to EOR.

TaggedPThis review aims to collect all CC-relevant data into a single studyto enable an in-depth analysis of the CCS potential with a focus onthe contiguous U.S. The analysis includes a two-level perspective:nationally across the U.S. and within individual facilities. The facil-ity-level details include CO2-emitting process units and process

Table 12014 U.S. CO2 emissions from the top-emitting industries.

Stationary source 2014 emissions (MMT CO2)a

Fossil fuel combustion 5208.2Coal 1653.7Petroleum 2127.5Natural gas 1426.6Electricity generation (fossil fuel) 2039.3Refineriesc 53.6Natural gas processingc 17.2Iron and steel production 55.4Petrochemical productiond 26.5Ethylene production 18.8Ethylene oxide production 1.3Hydrogen productionc 42.5Ethanol (Fermentation)e 40.1Cement production(c) 38.8 (64.3)Lime production 17.4Ammonia production(c) 9.4 (14.6)

All other data was obtained from the US Greenhouse Gas Inventory: 19the calcination reaction is included. For ammonia production, emission

a Include emissions from transportation sector (mobile emissions) wb Does not include emissions from transportation sector (mobile emc Data obtained from US GHGRP 2014 FLIGHT database. For these

when emitted through a common stack; otherwise combustion emisincludes captive H2 production emissions (which are excluded from H2

d Petrochemical Production includes ethylene oxide and ethylene pre Ethanol (Fermentation) was estimated using an emission factor of

duction data without denaturant for 2014.

TaggedPconditions (i.e., temperature, pressure and CO2 concentration),which are required to understand how best to capture CO2 from dif-ferent industries and to calculate the minimum capture work andSherwood cost estimation. A Sherwood plot correlates the relation-ship between concentrations of a target substance with the cost toseparate it from the remaining components, as outlined by Houseet al [37]. Top-emitting industries are considered, encompassingdilute, high-purity, combustion, and process emissions. Spatial anal-ysis in the form of geographic information systems (GIS) is thenused to bring together key CCS data within the U.S. to determine the“low-hanging fruit” of CCS and to identify the facilities that have thelowest CO2 capture cost.

2. Process CO2 versus combustion CO2

TaggedPWhen discussing CO2 emissions from industrial point sources, adistinction can be made between “combustion” and “process” CO2.Combustion emissions occur from burning carbonaceous fuels, suchas natural gas, coal and petroleum, while process emissions accountfor all other CO2 released, usually from chemical reactions that arerequired to produce a desired product. Reduction of iron ore intoiron, limestone into lime and water-gas shift reactions are examplesof such process reactions. In several instances, process and combus-tion emissions can occur within the same unit. When process andcombustion emissions are mixed, there is the potential for higherpurity CO2 streams if new and innovative unit designs can separatethe process reactions from the heat requirements. These two typesof emissions will be discussed in greater detail as each industry isconsidered.

TaggedPThe industries are ordered from the least concentrated source ofCO2 to the most concentrated. For each industry, a base case facilityis discussed. The base case was chosen to be the largest U.S. emitterwithin that industry. Annual emission numbers for 2014 are takenfrom the EPA's online FLIGHT database [38]. The process conditions(i.e., temperature, pressure, CO2 concentration) for CC-relevant gasstreams are also provided.

TaggedPTable 1 displays a breakdown of CO2 emissions by the top-emit-ting industries. Fossil fuel combustion makes up the core of U.S. CO2

% of total CO2 emissions % of total stationary CO2 emissionsb

93.74% 90.89%29.76% 43.31%38.29% 11.46%25.68% 36.11%36.70% 53.41%0.96% 1.40%0.31% 0.45%1.00% 1.45%0.48% 0.69%0.34% 0.49%0.02% 0.03%0.77% 1.11%0.72% 1.05%0.70% (1.16%) 1.02% (1.68%)0.31% 0.45%0.17% (0.26%) 0.25% (0.38%)

90 � 2014 (EPA). For cement production, only CO2 produced froms were adjusted to remove CO2 captured for urea production.ithin fossil fuel combustion.issions).industries, both process and combustion emissions are reportedsions are not included. For ammonia production, emission dataproduction emissions) and CO2 captured for urea production.oduction emissions.6.29 lbs CO2/gallon ethanol (Xu et al, 2010), and EIA ethanol pro-


TaggedPemissions, with petroleum combustion producing the most emis-sions. However, petroleum combustion is mainly used in transporta-tion (gasoline), which leaves coal as the greatest contributor tostationary national emissions. In general, fossil-fueled electricitygeneration is the greatest emitter of CO2, contributing over 55% tototal stationary emissions. Just under 75% of these emissions origi-nate from coal, with most of the balance made up by natural gas.

TaggedPThe remaining emitters as shown in Table 1 account for approxi-mately 19% of stationary emissions. Petroleum refining, which is thesecond largest U.S. industry emitter, still emits 11 times less CO2

than power plants. With such a great disparity between powerplants and other industries, it can be easy to overlook the potentialof capturing industrial process CO2. Industrial process CO2 (alsoreferred to as “industry CO2” in this review) may be relatively small,but it is unavoidable. As renewable energy generation continues toincrease and displace fossil fuel electricity generation, industry CO2

will constitute an increasingly larger portion of global emissions.Moreover, unlike fossil fuel-fired power plants, many industrieshave few or no CO2-free alternatives for manufacturing their prod-ucts. While some research is underway to investigate novel produc-tion pathways for some industries, they are highly unlikely to beready for commercialization on a time scale required to prevent cat-astrophic climate change.

TaggedPFurthermore, many industries produce CO2 streams at muchgreater purity than power plant flue gas. For example, natural gasprocessing and ethanol fermentation can produce near pure streamsof CO2. Higher purity translates into lower capture costs, as will bediscussed in the following section. Low capture costs are importantfor promoting first-of-a-kind CCS technology, whose costs can be fur-ther reduced through learning and iterating until it is feasible to useon larger, more dilute sources of CO2 such as power plants. There-fore, industrial facilities may be the first adopters of CCS technology.

3. The cost of capture: minimumwork and economic cost

3.1. Minimum work of separation

TaggedPA simplified CO2 separation schematic is shown in Fig. 1. The CO2

is removed from feed stream A, resulting in two product streams, i.e., stream B with mostly CO2, and stream C with very little CO2.

TaggedPThe derivation of the minimum work is provided by House, et al[37]. The minimum work for separation is achieved at isothermal,isobaric conditions, reducing the minimum work equation into theGibb's Free Energy difference between the product and feed streams.The streams are assumed to behave as ideal gases, since the gasinteractions are negligible in the streams considered [39].

TaggedPThe thermodynamic minimum work to separate CO2 from a gasstream was calculated using Eq. (1):

Wmin ¼ RT nCO2B ln yCO2B

� �þ nB�CO2B ln yB�CO2B

� �� þ RT nCO2C ln yCO2C

� ��

þnC�CO2C ln yC�CO2C

� ��RT nCO2A ln yCO2A

� �þ nA�CO2A ln yA�CO2A

� �� ð1ÞTaggedPWhere 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,ni

CO2 is the moles of CO2 in stream i, nii-CO

2 are the remaining molesin stream i without CO2, yiCO2 is the mole fraction of CO2 in gasstream i, and yi

i-CO2 is the mole fraction of the remaining gas without

Fig. 1. Simplified CO2 separation diagram, where CO2 in feed stream A is removed,resulting in a mostly CO2 product stream B, and a product stream C with very littleCO2.

TaggedPCO2. A 90% CO2 capture rate at 95% CO2 purity was assumed for allCO2-relevant gas streams, except for those with initial (feed) streampurities greater than 95%. In this case, CO2 purity that matched theinitial feed stream's purity were assumed, resulting in zero theoreti-cal minimumwork required for separation.

3.2. Sherwood analysis

TaggedPA Sherwood analysis was performed to estimate the cost of cap-turing CO2 from the capture-relevant industrial gas streams. TheSherwood plot (Fig. 2) illustrates that as concentration of a targetsubstance within a gas stream decreases, its separation costsincrease. This relationship was developed by Thomas K. Sherwood in1959 when he investigated how the market prices of a metal variedwith the initial concentration of the ore in the raw material. House,et al extended this idea to the amount of CO2 present in a gas streamthat undergoes separation [37]. Fig. 2 displays various gas separationtechnologies available today and the relationship between initial tar-get concentrations and the separation (capture) costs. The data pointsshown were calculated from Dr. Ed Rubin's Integrated EnvironmentalControl Model (IECM), which simulates gaseous capture technologyfor power plant flue gas [40]. These costs are for Nth-of-a-kind tech-nology, and only include capital cost. In the case of the CO2 datapoints, this means compression costs are not included. The datapoints represent the following separation technologies: selective cat-alytic reduction (SCR) to remove parts per million (ppm)-level NOx;wet flue gas desulfurization (WFGD) and lime spray drying (LSD) toremove ppm-levels of SOx (corresponding to the high and low pricesof SOx separation, respectively); chemical absorption with MEA CO2

scrubbing for pulverized coal combustion (PCC) plant with 13% CO2

in the flue gas; and physical absorption with Selexol CO2 scrubbingfor the integrated combined cycle (IGCC) power plant with 36% CO2

in the flue gas. Due to the variety of separation technologies includedin the Sherwood plot, the subsequent capture cost estimates aretechnology agnostic. Eq. (2) enumerates the linear fit between thelogarithmic prices of capture and the logarithmic target substanceconcentration (in molar concentration).

TaggedPEq. (2) was used to calculate estimated CO2 capture costs for cap-ture-relevant gas streams. Once again, these capture costs onlyencompass capital costs, not compression costs for CCS.

log Price$kg

� �� ¼�0:5558 � log mole fraction of CO2 %½ �ð Þ�1:8462

ð2Þ

Fig. 2. Sherwood plot for gas separation technologies. Separation technologiesinclude selective catalytic reduction (SCR) for both NOx values, wet flue gas desulfuri-zation (WFGD) for the higher SOx value, lime spray drying (LSD) for the lower SOx

value, MEA scrubbing for the CO2 PCC value, and Selexol scrubbing for the CO2 IGCCvalue [40]. R2 value is 0.990.

Table 2Summary 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 reflectsthe 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 0.5Natural gas power plant 3�5% Gas turbine 93�106 (after HRSG) CO2, NOx, SOx, CO, O2, N2,

Hg, As, Se8.0

Coal power plant 10�15% Steam boiler furnace 40 � 65 CO2, NOx, SOx, CO, O2, N2,

Hg, As, Se28.3

Cement production 30% Precalciner 150 � 350 CO2, H2O, N2, hydrocarbons,volatiles (K2O, Na2O, S, Cl)

1.2

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 3.13 � 5% Utilities (steam, electricity) 160�190 Depends on fuel used10�20% Fluid catalytic cracker (FCC)

(regeneration of catalyst)160�190 O2, CO2, H2O, N2, Ar, CO,

NOx,SOx30 � 45%, 98�100% H2 purification 20-40 (for PSA), 100�120

(for chemisorption)CO2, H2, CO, CH4

Iron and steelmanufacturing

20 - 27% Blast furnace (high CO2 ifBFG is burned)

100 H2, N2, CO, CO2, H2S 1.0

16 � 42% Basic oxygen Furnace (highCO2 from burning BOFgas)

»100 H2, N2, CO, CO2, H2S

Ethylene production 7�12% Steam cracking 160�215 H2O, CO, NOx, SOx, O2, N2,CO2

0.3

Ethylene oxide production »30%, 98�100% Absorption unit to purify EO(lower end is air oxida-tion, higher end is oxygenoxidation)

16�32 (for water adsorp-tion), 100 ¡120(chemisorption)

Mainly CO2, H2O, N2, (airoxidation) some CH4, eth-ylene, EO

0.02

Ammonia processing 98�100% H2 purification 100�120 (chemisorption) CO2, H2, O2, CH4 0.3Natural gas processing 96�99% Acid gas removal/CO2

absorption (low Pstripper)

100�120 96 - 99% CO2, 1-4% CHx(mainly methane, traceamounts ethane, propane,butane), H2O, N2

0.3

Hydrogen production 30 � 45%, 98�100%(15�20% in stream beforepurification)

H2 purification (lower end isPSA, higher end for CO2

specific separation)

20�40 (for PSA), 100�120(for chemisorption)

CO2, H2, CO, CH4, Afterchemisorption: »100%CO2

0.8

Ethanol production 98 � 99% Fermentation 35 CO2, ethanol, methanol, H2S,dimethyl sulphide, acetal-dehyde, ethyl acetate

0.7


3.3. The cost of CO2 capture

TaggedPA summary of the process conditions (i.e., CO2 concentration,CO2-emitting process unit and temperature) are listed in Table 2.These values were used to calculate the minimum work and esti-mated financial costs for capturing CO2 from the top-emitting indus-tries, with the results shown in Table 3. It is apparent that as the CO2

purity in the capture-relevant stream decreases, the associated mini-mum work and capture costs increase. For any industrial processthat produces a stream with greater than 95% CO2 purity, the theo-retical minimum work to capture it is near zero (given the

Table 3The minimumwork and Sherwood capture cost estimates for top CO2 emitting

Source CO2 content (mol %) % of US emission

Natural gasa 3�5 24.8Petroleuma 3�8 7.9Coala 10�15 29.8Refineries 3�20 1.0Ethylene production 7�12 0.3Cement production 14�33 1.2Iron and steel production (BOF)b 20�27 (16�42) 1.0Ethylene oxide productionc 30, 98�100 0.02Hydrogen productionc 30�45, 98�100 0.8Ammonia processing 98�100 0.4Natural gas processing 96�99 0.3Ethanol (Fermentation) 98�99 0.7a Only includes stationary fossil fuel combustion as percentage of total U.S. eb For iron and steel production, numbers in parenthesis specifically refer toc Multiple CO2 content ranges occur due to multiple process pathways avail

TaggedPassumption of 95% capture purity). Such industries include ethyleneoxide, hydrogen, ammonia, and ethanol production, as well as natu-ral gas processing. Such pure streams of CO2 may only require dehy-dration and compression. There is still an associated capital cost forbuilding the capture system in addition to operational and mainte-nance costs, resulting in $14 per metric ton of CO2 capture on aver-age. For comparison, the National Energy Technology Laboratory(NETL) recently estimated carbon capture costs for high purityindustrial sources, resulting in costs of $11.68�$23.09 per metricton of CO2 captured [31].

industries in the U.S.

s Minimumwork (kJ/mol CO2 capt) Cost ($/tonne CO2 captured)

10.7�12.7 75�1007.8�11.3 58�1006.2�7.9 41�517.4�15.5 35�1009.4 � 12.8 46�625.2�12.6 26�425.3�6.4 (3.7�7.1) 31�35 (23�39)0�4.0 14�280�4.0 14�280 140 140 14

missions.the basic oxygen furnace (BOF) process unit.able. See industry section for more detail.


TaggedPIt should be emphasized that the Sherwood plot estimates Nth-of-a-kind capture costs; therefore, as capture technology maturesfor each industry, we should see greater convergence of costs. Forexample, while amine-based post-combustion carbon capture atcement plants currently have capture costs averaging around $110per metric ton of CO2, it has been shown that chemical looping canreduce costs to the $20�$45 per metric ton of CO2 [41]. Thesereduced costs align well with the $26�$42 per metric ton of CO2

estimated by Sherwood analysis.TaggedPOn the other end, for a CO2 concentration of only 3% in the flue

gas stream, the minimum work required increases to 13 kJ per moleof CO2 captured. The cost increases to $100 per metric ton of CO2

captured; in other words, there is about a 5-fold increase in capturecost when the concentration decreases by a factor of approximately30. The highest capture costs are associated with natural gas andpetroleum-fired power plants. Coal-fired power plants, the largestemitter of stationary CO2, require on average 6�8 kJ per mole of CO2

captured, about 25%�50% less energy than capturing from naturalgas-fired power plants. Capturing CO2 from coal-fired power plantscosts between 30% and 56% less than capturing from natural gas-fired plants.

TaggedPOverall, the minimum work ranges from near zero up to approxi-mately 13 kJ per mole of CO2 captured, with costs ranging from $14to $100 per metric ton of CO2 captured. Industrial facilities have thepotential to demonstrate CCS technology at about one fifth of powerplant's capture costs, once again underscoring industrial processCO2’s role in assisting the implementation of CCS technology.

3.4. Top CO2 emitters from the industrial sector

TaggedPMajor industrial emitters of CO2 are summarized in Figs. 3 and 4according to CO2 purities, total emissions (MMT per annum) andnumber of U.S. facilities reporting to the EPA GHGRP. These emissionsources remain promising targets for capture uptake due to the

Fig. 3. Summary of CO2 purities of major U.S. industrial emitters of CO2. *BF = b

TaggedPgreater fraction of CO2 in their corresponding process exhauststreams. Here, a thorough analysis of process design is presented,with special consideration to process features that would lend to thefacile accommodation of capture technology. For each industrydescribed, a representative facility was chosen to illustrate the allo-cation of CO2 emissions on-site. These base cases were chosen to bethe largest emitters reported in the EPA GHGRP. Emissions at otherfacilities will vary.

TaggedP3.4.1. Petroleum refiningTaggedPThe U.S. is the world's largest refiner of crude oil. In 2012, around

144 U.S. refineries produced 803 MMT of petroleum products, net-ting around 22% of global production's 3580 MMT of petroleumproducts [42]. Around 170 MMT CO2 were emitted by the U.S refin-ing industry in 2014, with 53.6 MMT CO2 of these emissions fromprocess reactions only [43]. In 2008, roughly 818 MMT CO2 wereemitted globally [21].

TaggedPPetroleum refineries produce various fuels and chemical feed-stock through the distillation of crude oil followed by reforming andcracking. While there are many sources of GHG emissions on site, asseen in Fig. 5, the majority originate from combustion of fuels, andalmost all (over 97%) of the emissions are CO2 [21]. The four largestsources of CO2 in a refinery are process heaters, utilities, fluid cata-lytic cracker (FCC) and hydrogen production, though a given sitemay not have all of these units [21].

TaggedP3.4.1.1. Process heaters. TaggedPBetween 30�60% of total refinery emissionscome from process heaters. Major units include steam reforming,steam cracking, catalytic reforming and the distillation columnpreheater. Steam reforming and steam cracking will be explored fur-ther in the sections on hydrogen production and ethylene produc-tion. In general, the CO2 content in the flue gases range from 8�10%.The CO2 content depends on which fuels are being combusted. In theU.S., refineries mainly use natural gas and refinery fuel gas. Refinery

last furnace, BOF = basic oxygen furnace, PSA = pressure swing absorption.

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).


TaggedPfuel gas (RFG) is roughly composed of 30% H2, 35% C1, and 35% C2 byvolume. CO2-emitting combustion reactions could then look like:

CH4 þ 2O2 !CO2 þ 2H2O ð3Þ

C2H6 þ 3:5O2 !2CO2 þ 3H2O ð4Þ

Fig. 5. Breakdown of GHG emissions for petroleum refineries

TaggedPThe exhaust temperature will also depend on the process type,though the convection section of fired heaters can significantlyreduce the flue gas temperature [44]. For distillation, exit tempera-tures are around 400 °C; for catalytic reformers, 495�525 °C; forsteam methane reformers, 180�200 °C at the stack; and for steam

across the U.S. Over 97% of the GHG emissions are CO2.

Fig. 6. Process diagram for petroleum refining. 2014 emissions numbers provided by U.S. GHGRP for ExxonMobil Bt Site in Baytown, TX.

Table 4Breakdown of 2014 CO2 emissions from ExxonMobil's petroleum refinery in Bay-town, TX [38].

CO2 source CO2 emissions (metric tons) % of facility emissions

Process heaters 8359,658 80.30%Fluid catalytic cracking 1849,208 17.80%Sulfur recovery 140,722 1.40%Flares 52,751 0.51%Catalytic reforming 2046 0.02%Process vents 1693 0.02%TOTAL 10,406,077 100%


TaggedPcracking, 800�850 °C at the unit's exit [45]. At the exhaust stack,temperatures range from 160�200 °C for all process heaters [45,46].

TaggedP3.4.1.2. Utilities (Electricity and steam generation). TaggedPOn-site electricityand steam generation can account for 20�50% of refinery CO2 emis-sions [21]. Coupled electricity and steam generation is called com-bined heat and power (CHP). In refineries, RFG and supplementalnatural gas are combusted in air and sent to a gas turbine to createelectricity. The exhaust gases then pass through heat exchangers toproduce steam [47]. The exhaust gas contains approximately 4% CO2

by volume and exits between 160 °C and 190 °C [21,46].

TaggedP3.4.1.3. Fluid catalytic cracker (FCC). TaggedPA fluid catalytic Cracker (FCC)can account for 20�50% of a refineries CO2 emissions. The FCC usesheat, pressure and catalysts to break down large hydrocarbons intomore valuable products. During the reaction, carbon is deposited onthe catalyst, deactivating it. The catalyst is sent to regenerator fordecoking. The catalyst coke is combusted in air, producing CO andCO2, the CO in the flue gas stream is converted to CO2 in a CO boiler,and the boiler captures the heat released for steam production [21].The stream exits the boiler at 160�190 °C and contains 10�20% CO2

by volume [46,21].

TaggedP3.4.1.4. Hydrogen production. TaggedPHydrogen production can account for5�20% of total refinery CO2 emissions [21]. Roughly one third of allU.S. refineries have on-site hydrogen production [29]. The relevantprocess step is the purification of hydrogen. Hydrogen purificationmay be completed either using CO2 scrubbing or pressure swingabsorption (PSA), though PSA has been the dominant technologysince the mid-1980s [48]. When CO2 scrubbing is used, an absorp-tion column using an amine solution is used to specifically removeCO2 from the product stream. The CO2 is then released from thestripping column at high purities (»99%) and temperatures between100�120 °C [49,50]. PSA targets hydrogen specifically, with all otherimpurities, including CO2, exiting as off-gas. Subsequently, PSAresults in a lower concentration of CO2 in the gas stream, between

TaggedP30�45% [51,18,16]. The gas stream exits at a temperature of 20�40 °C [49]. Refineries are more likely to employ PSA units due to greaterimpurities in the feedstock.

TaggedPThe CO2 producing reaction occurs in two steps: steam methanereformation (SMR) and water gas shift (WGS), as shown in Eqs. (5)and (6), respectively.

CH4 þH2O!3H2 þ CO ð5Þ

COþH2O!CO2 þH2 ð6ÞTaggedPFig. 6 depicts a potential process configuration for petroleum

refining, based on ExxonMobil's Bt Site in Baytown, TX. Table 4 dis-plays the CO2 emissions from the different various processes of theplant. Process heating accounts for the greater number of emissions,though the FCC is the largest single emitter of CO2. There was nohydrogen production associated with this site in particular, thoughthere is a petrochemical plant located at the site. In this specific casethe process heating emissions were taken to be the stationary com-bustion emissions listed for this facility under the U.S. GHGRPreporting. These emissions likely include steam generation, thoughdata was not available to confirm this, and includes stationary com-bustion that occurs for the petrochemical plant. The combination ofstationary combustion emissions skews the breakdown of emissionsat the base case facility, though it is likely that process heating would


TaggedPproduce the majority of emissions even with adjusted numbers. Asstated previously, petroleum refineries located in the U.S. mainlyburn natural gas and RFG in process heaters. RFG consist of light C1to C4 hydrocarbons, H2, H2S and other light top gases from distilla-tion columns that are not condensed in the overhead condenser[29].

TaggedPPetroleum refineries are distinctive among the CO2-intensiveindustries in that there are numerous CO2-producing units. The dis-perse nature of these units can make it difficult to implement CCSwithout a common stack. For example, instead of trying to place CCdevices at each process heater exhaust stack, it may be best to focuson the largest single CO2 emitters. Additionally, each refinery isuniquely configured to produce a distinctive portfolio of products,which depend on the petroleum feedstock used; therefore, a CCdesign for one refinery will not likely fit another refinery.

TaggedPGiven the variety of CO2 emitting units in refineries, there is alsoa wide range of minimum work for separation and capture costs.The minimum work for separation ranges from 7.4 to 15.5 kJ/molCO2 captured excluding hydrogen production, and less than 4.0 kJ/mol CO2 captured for hydrogen. The Sherwood analysis yielded acapture cost ranging from $35 to $100 per MT of CO2 captured,excluding H2 production. Hydrogen production capture costs rangebetween $14 and $28 per MT of CO2 captured; oil refineries wouldlikely incur the higher end of the H2 production capture cost rangedue to the prevalence of PSA purification, which results in a moredilute stream of CO2.

TaggedP3.4.2. Ethylene productionTaggedPThe U.S. ranks as the top producer of ethylene (C2H4), a feedstock

widely used to produce chemicals, such as polyethylene, ethyleneoxide and ethylene chloride [52]. In 2013, the U.S. produced 28.1MMT of ethylene, capturing about 19.7% of world production [53].Many ethylene production sites are co-located at petroleum refiner-ies, since petroleum products serve as a feedstock for ethylene.Around 18.8 MMT CO2 were emitted by U.S. ethylene production in2014 [38].

TaggedP3.4.2.1. Process overview. TaggedPFractional distillation is performed on nat-ural gas and other feedstocks to obtain ethane (C2H6), propane(C3H8) and/or butane (C4H10). The hydrocarbon feed (e.g., ethaneand propane) each undergo steam cracking, also known as pyrolysis,at high temperatures. Steam crackers consist of furnaces which heatthe feedstock in tubes running through the combustion chamber. Athigh temperatures, hydrocarbon chains break down, forming dou-ble-bonded and lighter single-bonded hydrocarbons (Eqs. (7) and(8)). For an ethane and propane mixture, the temperatures rangebetween 650 and 815 °C, while an ethane-only feed is cracked at800�850 °C [49].

C2H6 !C2H4 þH2 ð7Þ

C3H8 !C2H4 þ CH4 ð8ÞTaggedPThe cracked gaseous products, ranging from hydrogen to heavy

fuel oil are immediately quenched at 400 °C in a heat exchanger toprevent the reactions from breaking down all hydrocarbons to meth-ane, CH4 [54,55]. Further water injection into the product streamcools it down to 40�50 °C. The product stream is compressed andfractionated to yield purer streams of ethylene, propylene, butadi-ene, etc. The liquid stream leaves at the bottom of the column andundergoes further processing and distillation. The ethane and pro-pane streams are recycled back to the steam cracking unit. Forheavier feedstock such as naptha, an additional separation step isrequired (e.g., cryogenic unit) to isolate the ethylene [56]. The light-est off-gases (CH4, H2 and by-product propane, ethane) are com-busted with natural gas to provide heat for the steam cracker or

TaggedPother process heaters. The flue gas is then vented, releasing CO2 intothe atmosphere [15].

TaggedPThe light method of ethylene production prevails in the U.S.,using natural gas, ethane, propane and butane as feedstock ratherthan heavier hydrocarbons like naphtha. The latter three feedstocksare known as liquefied petroleum gas (LPG), and comprised around90% of fresh feed in the U.S. in 2013. Of this, over 65% consisted ofethane [15,56�58].

TaggedPFig. 7 shows a process diagram for ethylene production, andincludes emissions numbers from the Westlake Petrochemical LP inSulphur, LA. The breakdown of CO2 emissions at this site is given inTable 5. For the base case, there are ethylene production units and itwas assumed that all furnaces labeled with a reference to one of theproduction units was part of the steam cracker for that productionunit. The facility is required by the U.S. GHGRP to report the fractionof CO2 emitted that comes from burning ethylene off-gas. Overall,about 12.4% of combustion emissions from the steam crackers wereattributed to ethylene off-gas. While ethylene off-gas only contrib-utes 5.5% to total facility CO2 emissions, the steam crackers accountfor 44.1% of total facility emissions. Flares associated with each ofthe ethylene production units emit 49.3% of total facility CO2.

TaggedPCombustion of the off-gas and natural gas and other fossil fuelsleads to CO2 emissions. Steam cracking consumes the greatestamount of energy at refineries and petrochemical plants, A negligi-ble amount of CO2 is emitted during decoking of the furnace, inwhich steam or a steam and air mixture react with carbon to pro-duce CO and CO2 [59]. The concentration of CO2 in the flue gasesranges from 7�12% CO2, though it depends on the ratio of off-gas(CH4, H2) to primary fuel and the exact composition of the off-gas[7]. The flue gas temperature ranges between 160 °C to 215 °C [46].

TaggedPFarla et al. estimated that the cost of capturing and transporting(by train) CO2 from a 10% CO2 flue gas stream is $45 per metric tonof CO2 avoided [15]. Given that costs for avoided emissions arehigher than costs for captured CO2, and transportation was includedin Farla et al.’s analysis, the Sherwood cost estimations are slightlyhigher at $46�$62 per metric ton of CO2 captured.

TaggedPFinally, there are a couple of CC projects involving ethylene pro-duction. Mitsui Chemicals in Japan are capturing the CO2 and usingit to make methanol while at least one ethylene plant is capturingtheir CO2 and sending it for sequestration in Denmark's, Sweden's,and Norway's Kattegat�Skagerrak project [60,22,61].

TaggedP3.4.3. Cement productionTaggedPCement production is one of the largest CO2-emitting industries

globally, with the U.S. contributing 64.3 MMT of CO2 in 2014 [38]. In2014, the U.S. produced 82.6 MMT of cement while the world pro-duced a total of 4180 MMT. China accounts for the majority of pro-duction, claiming 59.6% of global cement production. The runner-up,India, only captured 6.6% of the production [62]. Although the U.S.only makes up 1.9% of world production, any technology improve-ments that occur from implementing CC in the U.S. can be extendedto countries like China.

TaggedP3.4.3.1. Process overview. TaggedPCement is produced from calcium carbon-ate (CaCO3), also known as limestone. Raw materials such as lime-stone and the oxides of aluminum, silicon and iron are first grindedand then travel to the preheater and the precalciner, where it is pre-heated using flue gas from the rotary kiln. The limestone undergoesits initial calcination, or reduction, in the precalciner, where addi-tional heat is provided via fuel combustion (Eq. (9)). After these pre-liminary processes, the limestone and other components enter therotary kiln to undergo further reduction into lime (CaO). Pulverizedcoal or another fuel is blown into the kiln and combusted, providingthe heat required for the reactions. Different chemical reactionsoccur within the temperature zones in the kiln. The first zone dehy-drates the incoming material at 20�900 °C. Calcination occurs at

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.


TaggedPtemperatures between 850 °C and 950 °C. Clinkerization occurs atthe highest temperatures in the kiln, between 1200 °C and 1450 °C[23].

CaCO3 þ heat!CaOþ CO2 ð9ÞTaggedPThe clinker pellets enter another grinder or mill where it is

grinded and mixed with gypsum, forming cement [63].TaggedPThe major emitter of CO2 in cement production is the rotary kiln.

In the kiln, CO2 is emitted from both fuel combustion (usually coal)and limestone calcination. In the U.S., coal is the primary fuel used inthe kiln, accounting for 59% of the heat consumed. Petroleum cokeand waste fuels make up the remainder of heat input [62]. Cementproduction illustrates how process and combustion emissions canbe combined in a single unit. Just over half of the CO2 originates forthe calcination, while just under half of the emissions originate fromthe combustion of fuel [64,65].

TaggedPThe kiln flue gas takes one of several paths. The flue gas may exitat the end of the kiln, where it travels through an air quenchingcooler and an electrostatic precipitator before being vented, or itmay flow through the precalciner and preheater, where further CO2

is added during calcination of incoming limestone and the fuel

Table 5CO2 emissions breakdown for the base case ethylene production facility, WestlakePetrochemicals LP in Sulphur, LA. Numbers taken from U.S. GHGRP for 2014.

Unit CO2 emissions (metric ton) Percent of total CO2

Steam crackers 870,607.60 44.14%Off-gas combustion 107,669.40 5.46%Process heaters (boilers) 124,551.50 6.31%Flares 977,318.50 49.55%Associated with ethylene pro-duction unit

973,103.10 49.33%

TOTAL 1972,477.60 100.00%

TaggedPcombustion in the precalciner. A stream of flue gas and air may alsobe siphoned off of the air quencher, bypass the kiln and flow directlyto the preheater as combustion air. Fig. 8 shows that the majority ofemissions come from the preheater exhaust stack rather than the airquencher stack after the rotary kiln. The flue gas then continues toan electrostatic precipitator before being vented. The CO2 content inthe flue gas ranges from 14% to 33% CO2, and exits at a temperaturebetween 150 °C and 350 °C. [64�66]. The higher CO2 content is likelyassociated with the additional calcination CO2 in the precalciner andpreheater.

TaggedPThe vast majority of U.S. cement plants, about 90%, use the moreenergy efficient “dry process” [62]. The dry process uses less waterduring the raw material grinding and crushing, requiring less heatinput for the dehydration stage.

TaggedPThe U.S. is home to one of the first cement plants with CC tech-nology. Skyonic has retrofitted a cement plant in Texas with CC. TheCO2 is then converted into baking soda, creating an additional reve-nue stream [67]. Other projects worldwide are also underway�atthe European Cement Research Academy (ECRA), they are using oxy-fuel configurations to capture the CO2 before the heat generation,and in Norway and Taiwan, post-combustion CC projects are under-way [23].

TaggedPFinally, the International Energy Agency's Greenhouse Gas pro-gram (IEA GHG) estimated post-combustion captures costs of $161per metric ton of CO2 avoided [23]. Their configuration included aCHP plant to generate steam for regenerating the amine solutionused to capture the CO2. The Sherwood analysis yielded a capturecost of $26 - $42 per metric ton of CO2 captured. However, as dis-cussed earlier, chemical looping produces carbon capture costsbetween $20 and $45 per metric ton of CO2. Once again, the technol-ogy agnostic and Nth-of-a-kind qualities of the Sherwood analysiscan produce estimates that may be lower than those from initialtechnology options.

Fig. 8. Process diagram for cement production. 2014 emission numbers taken from U.S. GHGRP for Holcim Inc. Genevieve Plant in Bloomsdale, MO.


TaggedP3.4.4. Iron and steel productionTaggedPThe U.S. is the fourth largest producer of iron and steel in the

world at 5.3% of global production in 2014. China is the largest pro-ducer, capturing 49.4% of the 1665.2 MMT global production, fol-lowed by the EU at 10.1% and Japan at 6.6% [68]. Within iron andsteelmaking, iron production accounts for 70-80% of CO2 emissions[26]. The U.S. emitted 55.4 MMT CO2 from iron and steel productionin 2014.

TaggedPThere are several routes for iron and steelmaking. Primary steelproduction uses mostly iron to produce steel, while secondary steelproduction uses mostly recycled scrap steel. Within primary steelproduction, there are two major pathways: the blast furnace withbasic oxygen furnace (BF/BOF) and the direct-reduced iron with theelectric arc furnace (DRI/EAF). The CO2 is already captured at DRI/EAF plants to improve the quality of the recycled reduction gas [27].Secondary steel production always uses an electric arc furnace(EAF). Within the U.S., about 40% of iron and steel industry uses theBF/BOF process, while the remaining 60% uses the secondary EAFprocess. Since the DRI/EAF process is not used in the U.S., it will notbe discussed here. Furthermore, the secondary EAF process emitsmuch less CO2 than the primary BOF process due to reduced energyrequirements by using recycled scrap steel instead of manufacturingiron. Additionally, the recycled steel enters the process alreadyreduced, so the emissions-intensive iron-making stage is bypassedand between 70�80% of emissions are avoided [26]. While EAF con-sume large amounts of electrical energy, fossil fuel combustion maybe off-set using alternative electricity generation sources.

TaggedPIn the case of CCS, the blast furnace in the BF/BOF process is thelargest single emitter of CO2 in the iron and steelmaking process;therefore, the BF/BOF process will be the focus of this section.

TaggedP3.4.4.1. Process overview�primary BF/BOF. TaggedPPrimary iron and steel-making facilities utilizing the blast furnace and basic oxygen furnacepathway are known as “integrated steel mills”. First, coke is pro-duced in a coke oven. There are two coke production configurations:by-product and nonrecovery. Coal is carbonized in an almost oxy-gen-free environment at high temperatures to create coke. Coke pro-duction allows the carbon content to become concentrated [69]. Inby-product coke ovens, the off-gases are collected from the top of

TaggedPthe oven. The tar, ammonia and light oil are removed, leaving lighthydrocarbons such as methane and hydrogen. This cleaned cokeoven gas (COG) can be combusted for heating the coke oven or otherprocesses or simply flared. In nonrecovery coke ovens, the off-gasesare not sent to a separation process; instead, the COG gas is burnedas-is, with heat recovered for steam or electricity generation [70].

TaggedPSinter production occurs in a separate unit as coke is produced. Insintering, iron ore fines are heated to melt into pellets for the blastfurnace. Coke breeze (fine particles of coke) are used as the fuelsource [69]. Next, iron ore, sintered iron ore, limestone flux and cokeenter the blast furnace. The blast furnace transforms the iron oreinto pig iron, the precursor to steel. Hot air is blasted from the bot-tom of the furnace, combusting with the coke to create carbon mon-oxide (CO). The CO reacts with the iron ore to remove the oxygen,reducing it to iron. The overall reduction reactions as well as individ-ual reactions are shown in Fig. 9 [71]. The blast furnace is anotherexample of process and combustion emissions combined into a sin-gle unit. The blast furnace gas (BFG) is the collected and combustedto Cowper heaters to preheat the incoming blast air before beingvented.

TaggedPThe molten iron, also known as pig iron, is siphoned out of thebottom of the BF and sent to the basic oxygen furnace (BOF) forsteelmaking. In the BOF, pig iron and steel scraps react with pureoxygen to remove the remaining carbon and other impurities [72].Around 80% of the BOF input material is pig iron, with scrap steelmaking up the balance. The reduction reactions create mostly COwith some CO2; initially, the BOF gas composition is 16% CO2 and70% CO. The CO is combusted at the top of the furnace before beingvented, increasing the CO2 content to up to 42% [15]. The heat fromcombustion can be used in a HRSG, or it can simply be cooled beforebeing cleaned. If needed, an extra decarburization step may occur tofurther purify the steel and remove carbon.

TaggedP3.4.4.2. Process overview�secondary EAF. TaggedPSecondary EAF facilities areknown as “mini-mills”. The majority of their feedstock is recycledsteel in the form of scraps, while up to 10% of the feedstock can bepig iron. The scrap steel is sent to an electric arc furnace (EAF), whichcharges the metal and creates an electrical arc which melts the steel,removing carbon and impurities. Alloying reagents and slag material

Fig. 9. Blast furnace diagram and associated reactions.


TaggedPare included in the EAF for further refining [72]. Since coke produc-tion, sintering and iron ore reduction are avoided, and fuels are notnecessarily combusted on-site for electricity needs, much less CO2 isemitted at mini-mills.

TaggedP3.4.4.3. Process conditions�BF/BOF. TaggedPCarbon dioxide is emitted fromthe combustion of coke breeze in the sintering plant, the combustionof coke oven gas in the coke oven, the blast furnace, and the basicoxygen furnace, in addition to other process heating and flaring. TheCO2 concentrations are as follows: 5�10% in the sintering plantexhaust gas, 25% in the coke oven exhaust, 20�27% from the blastfurnace (latter concentration from combustion of BFG), and 16�42%from the BOF (latter concentration from combustion of BOF gas).Although exact exhaust temperatures were not found for coke ovenor sintering plants, it is reasonable to assume exhaust from all fourprocesses have temperatures around 100 °C, as most streams arecleaned and cooled before being vented [25,27]. All exhaust streamsare at 1 bar.

TaggedPAs mentioned previously and confirmed by the emissions break-down for the iron and steel base case (Fig. 10), the blast furnace isthe greatest single source of CO2 at iron and steel plants. Thoughprocess heaters combined account for 59% of the base case's emis-sions (Fig. 11), they are dispersed throughout the plant without acommon stack, making CC difficult. In the blast furnace, it is impor-tant to note once more that both process and combustion CO2 arecombined into one vessel. Although it is unclear how much of theCO2 emitted from the blast furnace are process versus combusted,determining a way to separate the combustion from the reductionreactions could lead to a purer stream of CO2 from the blast furnaceand reduced cost for CO2 capture.

TaggedPTable 6 shows the breakdown of the CO2 emissions by fuel at thebase case plant. BFG accounts for 78% of the CO2 emissions fromcombustion, while natural gas (primary fuel) only accounts for 17%.The combustion of BFG produces CO2 concentrations at 20�27%,higher than the typical natural gas CO2 concentration of 3�5% forgas turbines or 7�10% for boilers, resulting in lower minimum work

TaggedPand capture cost than if only natural gas had been used. The theoret-ical minimum work to capture the CO2 from the blast furnace is5.3�6.4 kJ per mole CO2 captured, while the Sherwood capture costis $31�$35 per MT of CO2 captured.

TaggedP3.4.5. Ethylene oxide productionTaggedPThe U.S. is one of the world's largest producer of ethylene oxide

(EO), along with China and Saudi Arabia. The U.S. alone is responsiblefor approximately 15% of global production in 2013 [73]. [74] Likeethylene, EO is widely used in the chemical industry, and is oftenproduced at petrochemical plants located at or near refineries. CO2

emissions from EO production numbered at 1.3 MMT CO2 in 2014;while this is small compared to other industries, the purity of EO'sprocess streams still make it an attractive option for carbon capture[73].

TaggedPThere are two types of EO production pathways: air oxidation ordirect oxygen oxidation. In both cases, ethylene is oxidized into eth-ylene oxide. The majority of U.S. production uses the direct oxidationpathway [75]. Both pathways are described in this section.

TaggedP3.4.5.1. Process overview�air oxidation. TaggedPEthylene, the feedstock forEO, and air enter a reactor with a silver catalyst at a temperaturebetween 200 °C to 300 °C and pressure between 10 to 30 bar andundergoes oxidation. The reactor product stream flows to the pri-mary absorber, where water adsorbs the EO, and the dissolved EOstream travels to the desorber unit, while a portion of the overheadstream is sent back to the reactor as recycle. The remaining overheadgases pass through another coupled secondary, or purge, reactor andEO water absorber. Nitrogen (N2) and CO2 are vented from the purgeabsorber, resulting in a 30% CO2 content stream. The EO then entersa desorption unit to recycle the water, and finally enters a stripperdistillation column to remove any remaining N2, CO2, and otherimpurities. Due to the N2, the CO2 concentration is once againdiluted to 30% by volume in the exit stream [76]. The purified EOstream continues to further processing to create ethylene glycol and

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 inGary, IN.


TaggedPother products [17]. Fig. 12 provides a pictorial representation of theair oxidation pathway.

TaggedP3.4.5.2. Process overview�direct oxygen oxidation. TaggedPIn direct oxidationvia near-pure oxygen, ethylene and oxygen similarly enter a reactorwith silver catalyst. The reaction temperature and pressure areslightly different than in the air oxidation pathway; temperaturesrange from 200 °C to 300 °C, with pressures between 10 to 30 bar[18]. The reactor product stream enters a primary absorber column,where once again water physically adsorbs EO. The overhead gases,including CO2, enter a CO2-specific absorber column using the hotpotassium carbonate process (HPCP). The potassium carbonateabsorbs the CO2, and travels to the desorption column to recycle theabsorbent and release the CO2, and an almost pure stream (»99%) ofCO2 is vented.

TaggedPThe EO-rich product stream, dissolved in water, enters a desorp-tion unit for regeneration. The EO stream then heads to the final

Fig. 11. Breakdown of 2014 CO2 emissions from th

TaggedPpurification step, the stripper unit, where the stripper removes anyremaining light inert gases such as CO2, though only a small amountis released. The EO stream continues on for further processing [76].

TaggedPFig. 13 shows the process diagram for ethylene oxide productionfor the Equistar Chemical plant in Pasadena, TX, where over 95% ofon-site emissions come from the purification of ethylene oxide.

TaggedP3.4.5.3. Process conditions. TaggedPIn the air oxidation pathway, CO2 is emit-ted from a secondary reactor and the stripper column at a concentra-tion of 30%. The oxygen oxidation pathway releases CO2 from theCO2-desportion unit and the stripper, resulting in »99% purity CO2

[17,15]. In all cases, the exit CO2 stream has a temperature between100 °C to 120 °C after chemisorption [49].

TaggedPEO production and the following sections illustrate high puritysources of CO2. CO2 capture is actually already built into the EOindustry through the purification steps. The only steps needed for analmost pure stream of CO2 is dehydration and compression. EO

e base case facility, U.S. Steel Corps at Gary, IN.

Table 6Breakdown of 2014 CO2 emissions by fuel type at the U.S. SteelCorps iron and steel plant in Gary, IN.

Fuel type Emissions (MT CO2) % of Total

Blast furnace gas 6677,544.70 78.07%Coke oven gas 402,759.00 4.71%Natural gas 1455,276.70 17.01%Residual fuel oil no. 6 17,763.00 0.21%TOTAL 8553,343.40 100.00%


TaggedPproduction is an excellent candidate for implement CCS technology,since direct oxygen oxidation is prevalent in the U.S. and results in alow-cost opportunity.

TaggedPFarla et al. estimated that CO2 capture from EO production wouldonly cost $9 per metric ton of CO2 avoided in 1995, which wouldtranslate to about $14 in 2014 dollars [15]. The Sherwood analysisestimated costs to be between $14 and $28 per metric ton of CO2

captured. Since CO2 avoided costs are generally higher than its corre-sponding CO2 captured costs, Farla's cost estimate is quite a bit lowerthan the Sherwood estimate.

TaggedP3.4.6. Hydrogen productionTaggedPIn 2008, the U.S. produced 10�11 MMT of hydrogen (H2), captur-

ing between 25 and 27% of global production. The majority of H2

production is for captive use in the chemical and refinery industries,indicating that H2 production occurs at the same site as or very closeto other major sources of CO2. “Captive” use refers to H2 producedand consumed on-site, while “merchant” H2 is produced on-site andsold to other companies. Furthermore, H2 production may be “on-purpose” or produced as a “byproduct” of another process. On-pur-pose merchant production accounted for 15.3% of 2006 production,while on-purpose captive accounted for 48.7% of production.Byproduct production accounted for around 36% of total U.S. produc-tion in 2006. The majority of byproduct H2 come from catalyticreforming at petroleum refineries and chlorine-alkali production,

Fig. 12. Process diagram for ethylen

TaggedPwhich do not emit process CO2 [77]. Approximately 60 MMT of CO2

were emitted from H2 production in 2008, with over 70% of emissioncoming from on-purpose captive applications such as petroleumrefineries and ammonia plants. Merchant H2 outside of these indus-tries accounted for almost all of the remaining CO2 (Table 7). The U.S. GHGRP reported 42.5 MMT CO2 from H2 production in 2014,though these emissions exclude captive H2 production in the ammo-nia industry. The U.S. GHGRP includes emissions from refinery H2

production within the H2 industry tally.TaggedPIn the U.S., around 95% of H2 production uses natural gas reform-

ing, also called steam methane reforming (SMR); this section willfocus on SMR as the main production process [78]. Finally, althoughan increasing amount of H2 production is purified using PSA ratherthan CO2 scrubbing with an amine solution, both processes will bediscussed.

TaggedP3.4.6.1. Process overview. TaggedPNatural gas is the feedstock of H2 produc-tion using the steam methane reformation (SMR) technique. Beforeentering the reactor, the natural gas undergoes hydrodesulphuriza-tion to remove any H2S that could poison the catalysts in thereformer [79]. The natural gas then enters the SMR unit, where itreacts with steam at high temperatures (700 °C�1000 °C) at pres-sures of 3�25 bar [78]. At this point, CO2 is produced through thecombustion of methane and through the SMR reaction (Eqs. (10) and(11)). However, unlike in the cement rotary kiln or the iron blast fur-nace, the combustion and process reactions are separate. The com-bustion occurs in the furnace, while the reaction takes place inreactor within the SMR furnace (Fig. 14). The combustion flue gasescontain CO2 concentrations around 7�10%, and exit at temperaturesbetween 160 °C and 200 °C [7]. After the SMR reactor, the CO2 con-centration is around 7�12% by volume, while H2 makes up 69�78%[49].

CH4 þH2Oþ heat!COþ 3H2 ð10Þ

COþH2O!CO2 þH2 þ heat ð11Þ

e oxide air oxidation pathway.

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 ChemicalsLimited Partnership Bayport Plant in Pasadena, TX. Note that emissions are in metric tons of CO2.


TaggedPThe H2 product stream then enters a two-stage water-gas shift(WGS) converter to produce more H2 and the high temperatureWGS reactor contains iron oxide catalysts at 300 °C�450 °C, whilethe low temperature WGS reactor contains copper and zinc oxidecatalysts are 200 °C�250 °C. The CO2 content in the stream after theWGS converter is 15�20% by volume, while the H2 content is 77 to79% [49,18].

TaggedPThe final step in H2 production is purification. Hydrogen may bepurified in several ways. The most common are by pressure swingabsorption (PSA) and chemical absorption of CO2 followed by metha-nation. Fig. 15 shows the process overview for hydrogen production,and displays emission numbers from Air Products Port Arthur Facil-ity, where the hydrogen purification produces 74% of the total on-site CO2 emission.

TaggedPIn PSA, as shown in Fig. 16, H2 is targeted for removal, with allremaining impurities being vented. This method is popular amongstpetroleum refineries, as there are many impurities in the syngasstream. The CO2 is diluted by the other gases, resulting in a CO2 con-tent between 30 to 45% CO2 [18,16]. The gas is vented at 20 °C to 40 °C and 1 bar [50,80]. The H2 stream then undergoes methanation toremove any remaining CO2 and CO as CH4.

TaggedPWhen 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 7Estimated 2008 CO2 emissions from hydrogen production [30]. Production type from[77].

Hydrogenproduction type

Business sector Estimated CO2

emissions (MMT peryear)

CO2 breakdown

On-purposemerchant

Merchant H2 17 28.3%

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%

TaggedPat a temperature between 100 °C and 120 °C [49]. In both cases, car-bon capture systems would be placed after the H2 purification step.

TaggedPDue to the range in CO2 purity in target streams, the Sherwoodanalysis cost for capture ranges from $14 per MT of CO2 captured forhigh purity to $28 per MT of CO2 captured for lower purities. The lit-erature estimates a cost of $5 to $70 per MT of CO2 net captured,which is equivalent to CO2 avoided; the extremes are quite a bitlower and higher than the Sherwood costs [82].

TaggedPWhile PSA is becoming more prevalent in the H2 productionindustry, a simple way to promote CCS is to encourage new facilitiesto use the CO2 scrubbing purification method instead. The PSA traincould also be expanded to include CO2 removal. The hydrogen pro-duction industry may also prove useful in providing experience forpre-combustion CC technology, as both require SMR and WGS unitsto produce H2 as fuel while capturing CO2.

TaggedP3.4.7. Ammonia processingTaggedPThe U.S. produced 11.3 MMT of ammonia (NH3) in 2014, captur-

ing 6% of the world's 176.3 MMT of production, and trailing China,

Fig. 14. Steam methane reformer unit used in hydrogen production. Process andcombustion CO2 are produced in separate parts of the unit.

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 PortArthur, TX.


TaggedPRussia and India. China led with 33% of global production [83]. In theU.S., around 88% of ammonia went into fertilization production [84].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-gen production emissions, but do not include CO2 captured for ureaproduction.

TaggedPHydrogen production and ammonia have many process similari-ties. To produce ammonia, hydrogen must first be produced andthen reacted with nitrogen, usually sourced from air. Two-stagesteam methane reforming (SMR) is the main ammonia productionpathway used in the U.S. In 2011, around 92.5% of ammonia was pro-duced using natural gas feedstock [85]. Partial oxidation is anotherpotential pathway, but will not be discussed further in this section.The process CO2, formed during SMR and WGS, is emitted during theH2 purification step. However, within the ammonia industry, most

Fig. 16. Process diagram for hydrogen produ

TaggedPhydrogen is purified using CO2 amine absorption or HPCP producinghigh purity CO2 streams for carbon capture [86].

TaggedP3.4.7.1. Process overview. TaggedPNatural gas first undergoes desulfurizationto remove any H2S that can contaminate the catalysts in the reactors.The natural gas and steam enter the primary reformer, which produ-ces CO and H2 at temperatures of 730 °C (Eq. (10)) [87]. The productstream, containing 7�12% CO2, 69�78% H2 and 9�13% CO by vol-ume, then enters the secondary reformer. Compressed air is injectedinto the secondary reformer reactor to obtain a 3:1 ratio of H:Natoms for ammonia synthesis [88]. Partial oxidation of CH4 alsooccurs, yielding CO, H2, and H2O (Eq. (12)) [15]. After the secondaryreformation, the product stream contains 7�12% CO2, 55�57% H2,22�24% N2, and 12�15% CO by volume [49].

CH4 þO2 !COþH2 þH2O ð12Þ

ction using pressure-swing absorption.


TaggedPThe product stream then enters a high temperature and lowertemperature WGS reactor, while the H2 and N2 streams are thenpurified using CO2 scrubbing, as PSA would also remove the N2

needed for ammonia synthesis. The CO2 absorption may be per-formed using an amine solution or potassium carbonate (HPCP).CO2 is released at purities of 98.5 to 100% and a temperaturebetween 100 °C and 120 °C [49]. The H2 and N2 product streamthen undergoes methanation to remove any residual CO and CO2

as CH4 [87].TaggedPThe N2 and H2 are then reacted together to produce ammonia,

and the ammonia undergoes further separation. If urea is producedon-site, the CO2 from the absorber column is sent to reactor so thatit may react with the ammonia to form urea (NH2CONH2) in a two-step reaction (Eqs. (13) and (14)).

2NH3 þ CO2 !NH2COONH4 ð13Þ

NH2COONH4 !H2Oþ NH2CONH2 ð14ÞTaggedPThe twomain points of divergence from the hydrogen production

process described previously are the secondary reformer and theCO2-specific removal step using either amine or potassium carbon-ate. As with hydrogen production, CO2 is released from two mainlocations: the amine desorption unit and the steam reformer fluegas. The amine absorption unit, which contains process CO2, exits atpurities of 98.5% to 100% CO2 and a temperature between 100 °C and120 °C. The flue gas, containing combustion CO2, exits with a CO2

concentration between 7 and 10% CO2 at a temperature between160 °C and 200 °C.

TaggedPFig. 17 shows the base case ammonia plant located in Donalds-ville, LA. Just under 60% of the 5.32 total MMT CO2 come from theCO2 desorption, though some of this CO2 is used for urea productionand sold to other companies. The combustion CO2 from the reform-ers account for around 19% of the CO2 emitted, with the urea boilermaking up the balance.

TaggedPThe high purity CO2 stream results in a Sherwood cost of $14 perMT of CO2 captured. Rubin estimated capture costs of $5 to $70 perton of net CO2 captured for ammonia, hydrogen and natural gasprocessing plants [82]. Once again, while these estimates are foravoided CO2, the extremes are much lower and higher than the Sher-wood estimates.

Fig. 17. Process diagram for ammonia manufacturing. 2014 emission numbers

TaggedP3.4.8. Natural gas processingTaggedPThe U.S. is the world leader in natural gas production and subse-

quently natural gas processing. In 2014, the U.S. produced 20.7% ofthe world's supply [89]. In 2014, 56 MMT CO2 were emitted in the U.S. Combustion CO2 from process heaters comprised 65% of totalemissions, while process emissions from venting and flaring madeup the balance. Within process emissions, 62% of CO2, or 22% of totalCO2, came from acid gas removal (AGR). AGR mainly consists ofremoving CO2 from natural gas produced at the well [90,91].

TaggedP3.4.8.1. Process overview. TaggedPNatural gas produced at a wellhead con-tains mainly methane (CH4), but also smaller amounts of ethane,butane, propane and pentane as well as undesirables such as water,H2S, CO2, He and N2 [92]. The acid gases H2S and CO2 “sour” the gasmixture; removing these gases “sweetens” the natural gas and con-stitutes one part of the cleaning process [18].

TaggedPThere are four main natural gas processing steps: oil and conden-sate removal, water removal (dehydration), acid gas removal (sweet-ening), and separation of natural gas liquids. The oil and condensateremoval occurs at the wellhead. Condensate, also known as naturalgasoline, consists of heavier hydrocarbons (C5 and heavier) that areliquid at ambient T [92]. The product stream is then dehydrated,either at the wellhead or further downstream.

TaggedPThe raw natural gas travels from the wellhead to the processingplant to undergo AGR. Initial CO2 content in raw natural gas can varyfrom 2% to 70% by volume [18]. In AGR, H2S and CO2 impurities areremoved to meet natural gas pipeline specifications, usually lessthan 2% CO2 by volume. An amine absorption system or membraneseparate the H2S and CO2 from the natural gas stream. Over 95% ofAGR processes use amine absorption [92,93]. The acid gas streamthen enters a Claus process unit, where the H2S is converted to ele-mental sulfur and recovered. A relatively pure stream of CO2

(96�99% by volume) exits the Claus unit. The CO2 stream is eitherincinerated, vented or captured for enhanced oil recovery (EOR)[18,94].

TaggedPThe final processing step is to separate the natural gas liquids.The stream is fractionated into valuable hydrocarbon streamsincluding methane, ethane, propane, butane and pentane andheavier. Fig. 18 depicts the natural gas processing system. Acid gasremoval accounted for over 58% of on-site CO2 emissions. The

taken from U.S. GHGRP for CF Industries Nitrogen LLC in Donaldsville, LA.

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.


TaggedPremaining CO2 comes almost exclusively from stationary combus-tion, though a fraction of CO2 is emitted from flaring.

TaggedPCarbon dioxide is emitted from process heaters and the AGR unit.Carbon capture technology would be best placed after the Clausunit, due to a high purity of CO2, between 96�99% by volume [18].The temperature of the exit stream is between 100 °C and 120 °C at apressure of 1 bar [95�97]

TaggedPCapturing CO2 at natural gas processing is relatively low cost, asthe amine system already performs the most energy and economi-cally expensive step in CCS. Some natural gas processing sitesalready capture their CO2 for EOR purposes, indicating that experi-ence in CC already exists. The Sherwood analysis estimates a cost of$14 per MT of CO2 captured, while Rubin once again estimates a costof $5 to $70 per MT of CO2 avoided [82].

TaggedP3.4.9. Ethanol productionTaggedPThe majority of ethanol is produced in the U.S. and Brazil. In

2013, the U.S. produced 13,321 millions of gallons of corn-based eth-anol, capturing 57% of global production. Brazil produced 6267 mil-lions of gallons of sugar cane-based ethanol in the same year [98].More than 30% of the U.S. merchant CO2 market is sourced from eth-anol plants due to the almost pure stream of CO2 that is releasedduring fermentation [99]. In 2014, around 40.1 MMT of CO2 werereleased from fermentation alone (see Table 1 footnotes).

TaggedPEthanol may be produced from corn or sugar cane. Since the vastmajority of U.S. ethanol production uses corn feedstock, the cornethanol process will be the focus of this section [32,100]. Further-more, ethanol production may use dry-milling or wet-milling. Morethan 80% of U.S. production uses dry-milling, though both will bedescribed [101].

TaggedP3.4.9.1. Process overview�dry-milling. TaggedPMilling is the first step in eth-anol production. Entire corn kernels are ground into a flour called“meal”, keeping all grain components together. Water is added inthe slurry stage, creating “mash”. Enzymes are added to convertstarch to simple sugars, and ammonia is added for pH control andyeast nutrient. The mash is next sent to a high temperature cookerto kill off bacteria. The mash is then cooled before traveling to thefermenters, where yeast is introduced. The fermentation step cantake from 40 to 50 hours. During this, the glucose in the simple sug-ars is converted to ethanol and CO2 (Eq. (15)).

C6H12O6 !2CO2 þ 2C2H5OH ð15ÞTaggedPOnce fermentation is complete, the ethanol is separated from the

solid grain residue “stillage” in a distillation column. The ethanol isthen dehydrated to 200 proof using molecular sieves. Finally, a dena-turant is added to the ethanol to make it undrinkable. The product isstored until shipment [99]. Fig. 19 visualizes the dry-milling process,and includes emission numbers from the ADM Corn Processing facil-ity in Cedar Rapids, IA.

TaggedPOn average within the U.S., about 35% of the CO2 emitted fromethanol plants comes from combustion, while the remaining 65%comes from fermentation. Although biogenic CO2 is not recordedunder the U.S. GHGRP, ethanol plants nonetheless emit a significantamount of CO2 and should be considered candidates for CCS. CCScombined with biofuels allow for “carbon negative” fuels, or fuelsthat sequester more CO2 during production than is released uponcombustion.

TaggedP3.4.9.2. Process overview�wet-milling. TaggedPThe main difference betweenwet-milling and dry-milling is the separation of grain componentsin the first step. In wet-milling, the corn kernels are soaked in water

Fig. 19. Process diagram for dry-milling ethanol production. 2014 process heating emission numbers taken from U.S. GHGRP and fermentation emissions estimated using 2014EIA production capacity data for ADM Corn Processing facility in Cedar Rapids, IA.


TaggedPand dilute sulfurous acid to separate the grain into starch, proteinand fiber components. The components are then isolated from eachother as they travel through a set of grinders and separators. Thefiber and steeping liquor from the first step are dried to producecorn gluten feed. The feed is sold to the livestock industry. The pro-tein, in the form of gluten, is filtered and dried to make corn glutenmeal for feed. The remaining starch and water may then be pro-cesses in one of three ways: fermented into ethanol, dried and soldas modified corn starch, or processed into corn syrup. If ethanol ismade, it follows the same steps as discussed in the dry-milling pro-cess [99].

TaggedP3.4.9.3. Process conditions and cost. TaggedPCarbon dioxide is emitted fromthe fermenter at purities of 98�99% by volume, and almost ambientconditions of 35 °C and 1 bar [33,102]. At such high CO2 purity, Xuet al. estimated a cost of $6 to $12 per MT of CO2 captured, a bitlower than the Sherwood estimates of $14 per MT of CO2 captured[33]. The low cost of capture coupled with industry experience incapturing CO2 for the merchant market create a very favorable situa-tion for CC. Adding CC to ethanol plants appear to be one of the mostviable options explored in this work [17,60].

4. Why country-level emissions?

TaggedPAlthough the focus in this review is on opportunities to apply CCSto U.S.-based industries, it is equally important to investigate CO2

emissions on a global scale to develop a broader understanding andcomplete the picture of CC's potential. This is considered a first steptoward developing a clear pathway, with the hope that the U.S. willtake the lead on some of these projects. Combining facility locationswith the costs of carbon capture allows for outlining the “low-hang-ing fruit” of CC. Once these facilities have been identified, spatialanalysis is further used to match CO2 sources with potential sinks.Only by zooming out from a facility to a national perspective can wetruly realize the impact of CCS and create project pathways forimplementation. Fig. 20 provides a nationwide visualization of CO2

emissions, while Fig. 21 showcases industrial process-only

TaggedPemissions. With these in hand, we can begin to regionally character-ize emissions and CCS opportunities.

TaggedPPetrochemical plants (ethylene, ethylene oxide) and petroleumrefineries are grouped along the Texan and Louisianan Gulf Coast, aswell as near New Jersey ports. California (Bay Area and Los Angeles)and Washington (Seattle) also house refineries, in addition to hydro-gen plants. Many hydrogen facilities are located near or at refineries,or are scattered throughout the Midwest. Similarly, ammonia plants,which use hydrogen feedstock, are located near hydrogen sites, pre-dominantly in the Midwest and Louisiana.

TaggedPNatural gas processing and ethanol production produce nearlypure streams of CO2. Though these sources tend to emit smalleramounts of CO2, there are many of them and they tend to be nearone another. Clusters of natural gas processing operations are foundin North Dakota, down through Wyoming, Colorado and New Mex-ico, with the majority of natural gas processing occurring in Okla-homa, Texas and Louisiana. Ethanol production is prevalent in theMidwest, particularly Iowa, Minnesota, Illinois, Indiana andNebraska. Several facilities produce a significant amount of CO2, onpar with larger emitters like cement.

TaggedPCement production, lime production, hydrogen production andiron and steel manufacturing tend to emit large amounts of CO2

from single facilities, making them attractive for CC technology. Ironand steel plants are generally aggregated along the north and east-ern parts of the Midwest (northern Minnesota, Michigan, Illinois,Indiana, Ohio) and parts of the East Coast (Pennsylvania and NewJersey to South Carolina). Cement production facilities, which consis-tently emit large amounts of process CO2, are scattered fairly evenlyacross the U.S. Finally, lime production is located primarily in theinterior of the U.S., within the Midwest and the West.

TaggedPOverall, ethanol and ammonia production and natural gas proc-essing produce the purest streams of CO2. Hydrogen, cement andlime production consistently produce the greatest amount of processCO2, followed by iron and steel manufacturing. Table 8 lists the topten CO2 emitters by state for each category of emissions, whileFig. 21 visualizes process-only CO2 emissions on a state level. Texastrumps all other states, and electricity generation CO2 greatly influ-ences the top capture-relevant CO2 emitters.

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

TaggedPProcess CO2 has been the main focus of the discussion thus far,but many facilities emit significant amounts of combustion CO2 forprocess heating and other thermal needs. Fig. 22 depicts and com-pares process emissions to combustion emissions at each facility. Onthe whole, it appears that combustion emissions are fairly balancedwith process CO2. Cement and lime production facilities tend tohave significantly more process CO2 to combustion. The same is truefor a few ammonia, iron and steel plants and ethanol plants, thoughthe difference is not nearly as large for ethanol plants. The oppositeis true for refineries, petrochemical and hydrogen plants, with com-bustion emissions only slightly greater than process emissions.

4.2. CO2 sources by purity

TaggedPCombining data on location, quantity and purity of the CO2 pointsources creates a picture of the CC potential within the U.S. and iden-tifies the “low-hanging fruit”. Fig. 23 shows such an image, with theCO2 quantities and qualities visualized. Each color corresponds tothe CO2 purity of the capture-relevant stream, with darker colorsindicating higher purity. In this case, petroleum refineries were con-sidered more concentrated than coal power plants since the cap-ture-relevant process CO2 neglected process heating. Processheating is the lower end of the refining CO2 concentration range;although the 3�20% range is shown for consistency in this work, inreality the CO2 sources shown are likely to have concentrationsbetween 10�20%.

TaggedPHydrogen production was considered to be within the 30�45%purity range, since this is associated with the PSA purification pro-cess, which is increasingly used in industry. However, it should benoted that some of these hydrogen plants could also be in the96�99% CO2 range.

TaggedPThe largest pure CO2 emitters (96�100% CO2) are ammonia andethanol, with a few natural gas processing plants included. Hydrogenis the next purest stream of CO2, but is already potentially more thanhalf the concentration of CO2 as the pure streams (30�45% CO2). For-tunately, this does not correspond to a tripling of capture costs at thelower concentration end; costs only increase from $14 to $28 per tonof CO2 captured.

TaggedPSince many of these high purity sources are located in the Mid-west and along the Gulf Coast, these are the regions of the U.S. thathave the greatest potential for first-of-a-kind CC technology. In otherwords, the Midwest and the Gulf Coast hold the “low-hanging fruit”of CCS. More specifically, the central and southern Midwest, andGulf Coast are the regions that CCS pilot plants and demonstrationprojects should target, as they will result in the cheapest initial cap-ture costs, and are co-located with potential sequestration sites(Fig. 25). If all of these high purity sources (pure sources plus hydro-gen) were captured, it would account for about 5% of total U.S. car-bon emissions. While this is small relative to the CO2 reductionrequired to mitigate climate change, it is nonetheless a first step todeploying CCS on a wider scale.

TaggedPA few facilities also already appear to use CC technology to pro-vide CO2 for injection into enhanced oil recovery (EOR) sites(Fig. 24). Ammonia plants in Louisiana, northern Texas and NorthDakota are connected via CO2 pipelines to nearby EOR fields. Thereare other numerous industrial CO2 sources by these pipelines,including natural gas processing, hydrogen, lime, and petrochemicalproduction plants and petroleum refineries. While it is unclearwhether any of these facilities are used to provide CO2 to the fields,it nevertheless shows the potential of tapping into these existingCO2 resources for utilization and leaving natural CO2 in the ground.Despite the fact that EOR is a CO2 utilization rather than sequestra-tion, as the CO2 is not monitored or verified to remain underground,it still provides an economic incentive for capturing CO2 from nearby

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 8Top 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 51.20Indiana 120.28 Florida 109.95 Louisiana 27.14Florida 114.15 Indiana 101.88 California 25.34Ohio 107.85 Ohio 95.92 Indiana 18.40Pennsylvania 102.34 Pennsylvania 94.75 Iowa 12.35Illinois 92.06 Kentucky 84.53 Illinois 12.10Kentucky 88.94 Illinois 79.96 Ohio 11.93Missouri 80.08 West Virginia 69.98 Missouri 10.99Alabama 76.79 Missouri 69.09 Alabama 8.61Louisiana 74.88 Alabama 68.18 Michigan 8.47


Fig. 22. Process CO2 and combustion CO2 for industrial facilities only (non-electricity generating facilities). Emission data sourced from the U.S. GHGRP.


TaggedPfacilities. The EOR market can further to help offset the capture costsfor building the initial CC fleet.

4.3. A note on CO2 utilization

TaggedPIn addition to reliable storage, carbon dioxide utilization (CCU)and reuse has gained traction as an alternative fate for captured CO2.This route has the advantage of creating revenue from a waste prod-uct, which in theory could be applied to offset capture, compressionand transport costs. Additionally, this route may be advantageous ordesirable in areas where reliable storage opportunities do not exist,or exist at distances which are cost prohibitive from a transportationperspective. Carbon dioxide utilization opportunities include, butare not limited to, EOR, mineral carbonation, food and beverageprocessing, urea production and yield boosting, liquid fuel produc-tion, and many other avenues using CO2 as a chemical feedstock.Several reviews have presented these opportunities in great detail[103�107].

TaggedPIt is important to consider several factors when weighing thepotential benefits of CCU. First, very few utilization opportunitiesexist at the scale to make a direct impact on climate. Of currentopportunities, EOR owns the significant majority of the CO2 utiliza-tion market. Even with this large share [108], US demand (ca. 70 Mt/a) would only offset 1% of annual US CO2 emissions. One utilizationopportunity with sufficient scalability to impact climate is CO2 tofuels, with future potential cited at the gigatonne scale [109]. How-ever, oxidized fuels immediately recommit CO2 to the atmosphere;thus, it is important to consider the period of carbon fixation if suchutilized CO2 is to be counted against climate change.

TaggedPCO2 conversions are often energy-intensive due to the thermody-namic stability of fully oxidized carbon. Hence, full life-cycle assess-ments will often reveal that carbon utilization is carbon positiveusing traditional grid power and conventional routes for H2 produc-tion, emitting more CO2 than is consumed during utilization[110,111]. Coupling of these opportunities to renewable energy isoften a knee-jerk solution to this unfavorable carbon balance; how-ever, detailed analyses must be performed at the regional level todetermine if it is not more efficient to place such renewable energydirectly into the power grid. Even in the face of carbon-positive utili-zation, in some cases, CO2-based processing is less carbon intensivethan the incumbent process. For example, an industrial case studyshows CO2 emissions reductions on the order of 11�19% when CO2

is employed in polyurethane production [112]. Nevertheless, thesecollective points serve to highlight the complexities in consideringCCU, and the necessity for reliable LCA data for gaining properinsights; thus, such opportunities are not explored in this review.

5. Conclusions

TaggedPFacility-level analysis of the top CO2-emitting industries isrequired to fully understand the potential for CCS in the UnitedStates. Capture costs and minimum separation work can be calcu-lated when the process conditions of capture-relevant CO2 streamsare known. Although fossil-fueled power plants dominate stationaryCO2 emissions, other industries may provide a cheaper pathwaytoward CCS deployment. Many industrial processes also lack CO2-free alternatives, making CCS necessary for their future success.

TaggedPIt is useful to know which process unit is the largest CO2 emitterwithin an industry. Capture technology implemented at that one

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.


TaggedPunit will maximize emissions reduction for a minimal cost. Indus-tries with a single large CO2 source unit, such as cement productionand iron and steel manufacturing, are therefore attractive CCS candi-dates. However, even in these cases, process heating emissions canstill account for more than half of all on-site CO2. Process heaterstend to be comprised of multiple units, further exacerbating CCSinstallation challenges.

TaggedPPetroleum refineries face a unique challenge with their myriadprocesses. It would be very problematic to retrofit CCS technology

Fig. 24. Capture-relevant CO2 sources by size and purity, with EOR sites and exi

TaggedPonto many individual emitting units, and choosing a single unit maynot have as much of an impact as in other industries. Additionally,refineries’ distinct site configurations make it difficult to determinea CC implementation standard across the industry. Several indus-tries, including hydrogen production, ammonia production, and nat-ural gas processing, already have CC technology built into theirpurification steps in the form of amine absorption. These threeindustries and ethanol production form the high-purity set of indus-tries, or industries that produce CO2 streams pure enough that no

sting and future CO2 pipelines. Emission data sourced from the U.S. GHGRP.

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.


TaggedPadditional CO2 separation is required. Existing CC paves the way foreasily completing a CCS retrofit by only adding processing units suchas dehydration and compression.

TaggedPTable 9 summarizes several salient features for choosing a path-way forward for implementing CC. For instance, industries whereprocess CO2 and combustion CO2 are combined could indicate anincreased complexity in designing a capture system if only processCO2 is targeted. However, if the industry accounts for a large portionof process emissions across many industries, prioritizing it for car-bon capture could produce a greater mitigation impact than otherindustries. Considering these factors, a possible implementationpathway would focus on ethanol production facilities first, as theyproduce high purity streams which make up 65% of on-site emis-sions and account for sizable portion of total industrial process CO2

considered in this review. The cement industry would be the nextcontender, given a large percentage of on-site emissions emanatefrom the cement kiln, and cement accounts for almost a quarter oftotal industrial process CO2.

TaggedPThe ammonia industry would make an attractive third choice,due to its high purity stream of CO2 that accounts for 63% of on-siteCO2 emissions. Hydrogen production could be considered next, as itproduces a relatively high purity CO2 stream which accounts for amajority of on-site emissions. Iron and steel manufacturing producesseveral low to moderately concentrated CO2 streams, and the blastfurnace produces a mixed process and combustion stream of CO2.The division between process and combustion within the blast fur-nace is a complicated one. The combustion of coke produces CO,which then reduces iron ore and creates CO2. Extricating processCO2 from combustion CO2 is therefore a tricky task, and may furthercomplicate the capture process if a redesign if desired. These factorspush iron and steel manufacturing further down the CC pathway.

TaggedPNatural gas processing and ethylene oxide, while they producehigh purity streams, only account for relatively small portions ofindustrial process CO2. On the other hand, petroleum refineriesaccount for almost a fifth of industrial process CO2, but are com-prised of numerous lower purity CO2 streams. These qualities makethese three industries less attractive for initial CC implementation,and better suited for consideration towards the end of the industrialCC pathway. Finally, ethylene production emits relatively smallamounts of dilute CO2, making it the last industry to be consideredon the CC pathway.

TaggedPIt is also important to consider the largest single emitters of CO2:power plants. Fossil-fuel power plants are unlikely to disappear on atime scale necessary to mitigate climate change. CCS provides apathway for fossil-fueled power plants to act as a bridge betweentoday and a low-carbon, renewable energy future. Though powerplant flue gas is relatively dilute in CO2 and therefore expensive toseparate, capture costs may be reduced by using the knowledgegained from first implementing the technology on industrial sour-ces.

TaggedPThe picture of CCS potential within the U.S. is completed by tak-ing facility-level data and combining it with geographic CO2 pointsource data. Emerging trends create a deeper understanding ofnationwide emissions, and allow areas of lowest capture cost to beidentified. Overall, Texas emits the most CO2 from both electricitygeneration and industrial processes. In addition to Texas, Louisianaand the Midwest emit the most process CO2, while the eastern Mid-west (stretching from Missouri to Pennsylvania) and Florida emitthe most electricity generation CO2. Capturing all of the capture-rel-evant process CO2 could cost between $6.17 and $11.13 billion U.S.per year, and would offset roughly 5% of total 2014 U.S. CO2 emis-sions. Capturing all capture-relevant CO2 (from both process and

Table 9Characteristics of industries to help identify the low-hanging fruit of CCS.

Industry Process andcombustion CO2

combined?

Number of lowpurity streams(0%�10% CO2)a,b

Number of mediumpurity streams(10%�50% CO2)a

Number of highpurity streams(50%�100% CO2)a

Percentage of CO2

from processc,dPercentage of CO2

from combustiondPercentage of totalindustry processCO2

Percentage of totalindustry CO2

Ethanol Production No � � 1 (fermentation) 64.87% 35.13% 14.5% 11.1%Ammonia

ProcessingNo 1 (SMR heater) � 1 (amine scrubbing) 62.55% 37.45% 5.5% 3.9%

Natural gasprocessing

No 1 (flares) � 1 (acid gas removal) 25.97% 74.03% 6.5% 9.4%

HydrogenProductione

No 1 (SMR heater) 1 (PSA tail gas) 1 (amine scrubbing) 92.79% 7.21% 15.9% 15.2%

Iron and SteelProduction

Yes 2 (sinter plant,flares)

3 (BF, BOF, cokeoven)

� 45.33% 54.67% 11.4% 13.5%

Cement Production Yes (»50% process)[64]

� 2 (precalciner,cement kiln)

� 93.19% 6.81% 24.3% 11.0%

Petroleum Refininge No 1 (flares) 2 (FCC, catalyticreforming)

1 (H2 production) 25.63% 74.37% 20.1% 29.3%

EthyleneProductione

No 2 (steam cracker,flares)

� � 13.32% 86.68% 1.2% 6.4%

Ethylene Oxidef No 1 (flares) 1 (air oxidationpathway)

1 (oxygen oxidationpathway)

� � 0.5% 0.2%

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-industryhydrogen 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].

170P.Bains

etal./Progressin

Energyand

Combustion

Science63

(2017)146�

172


TaggedPelectricity generation) could cost between $93.35 to $122.53 billionU.S. per year, and could displace around 41% of CO2 emissions.

TaggedPThe minimum work of separation and Sherwood cost analysisshow that as the CO2 purity in a capture stream increases, the workand capture cost on a molar basis decrease. This is critical to findingthe lowest cost opportunities for CCS pilot plant deployment. TheGIS analysis also shows that higher-purity point sources also tend toemit less CO2 than dilute sources. By combining capture cost datawith the geographical locations of different industrial point sources,the “low-hanging fruit” of CCS have been located in the Midwest andalong the Gulf Coast. These regions have many high-purity CO2

industries, such as ethanol production, natural gas processing,ammonia production and hydrogen production. The southern Mid-west and Gulf Coast are also co-located with potential geologicalsequestration sites, another important piece to the CCS puzzle.Therefore, southern Midwest and Gulf Coast are the regions in theUnited States that should be targeted for implementing CCS pilotplants and demonstration projects.

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Documents

Progress in Energy and Combustion Sciencejlwilcox/documents/bains_industry.pdfimplementation pathway is presented that initially focuses on CO 2 capture from ethanol production, fol-lowed