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Frontiers of Chemical Science and Engineering

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Front. Chem. Sci. Eng.    2015, Vol. 9 Issue (2) : 125-141    https://doi.org/10.1007/s11705-015-1514-6
REVIEW ARTICLE
Review of solvent based carbon-dioxide capture technologies
Kathryn A. MUMFORD, Yue WU, Kathryn H. SMITH, Geoffrey W. STEVENS()
Peter Cook Centre for CCS Research, Particulate Fluids Processing Centre, Cooperative Centre for Greenhouse Gas Technologies, Department of Chemical and Biomolecular Engineering, The University of Melbourne, Victoria, Australia
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Abstract

Currently, a large proportion of global fossil fuel emissions originate from large point sources such as power generation or industrial processes. This trend is expected to continue until the year 2030 and beyond. Carbon capture and storage (CCS), a straightforward and effective carbon reduction approach, will play a significant role in reducing emissions from these sources into the future if atmospheric carbon dioxide (CO2) emissions are to be stabilized and global warming limited below a threshold of 2 °C. This review provides an update on the status of large scale integrated CCS technologies using solvent absorption for CO2 capture and provides an insight into the development of new solvents, including advanced amine solvents, amino acid salts, carbonate systems, aqueous ammonia, immiscible liquids and ionic liquids. These proposed new solvents aim to reduce the overall cost CO2 capture by improving the CO2 absorption rate, CO2 capture capacity, thereby reducing equipment size and decreasing the energy required for solvent regeneration.
Keywords carbon dioxide      carbon capture      solvent absorption      large scale     
Corresponding Author(s): Geoffrey W. STEVENS   
Online First Date: 23 June 2015    Issue Date: 14 July 2015
 Cite this article:   
Kathryn A. MUMFORD,Yue WU,Kathryn H. SMITH, et al. Review of solvent based carbon-dioxide capture technologies[J]. Front. Chem. Sci. Eng., 2015, 9(2): 125-141.
 URL:  
https://academic.hep.com.cn/fcse/EN/10.1007/s11705-015-1514-6
https://academic.hep.com.cn/fcse/EN/Y2015/V9/I2/125
Project lifecycle stage Solvent Facility Location Company Volume of CO2 /mtpa CO2 gas source Operation date Storage type Ref.
Operate CS: Amine, Shell Global Cansolv Boundary Dam Saskatchewan, Canada SaskPower 1.0 PCC lignite (post) 2014 EOR, geological storage [3]
Operate PS: Selexol Century Plant Texas, USA Occidential Petroleum & Sandridge Energy 8.4 Natural gas 2010 EOR [4]
Operate PS: Selexol Coffeyville Gasification Plant Kansas, USA Chaparral Energy 1.0 Fertiliser production (pre) 2013 EOR [5]
Operate CS: Benfield process Enid Fertilizer CO2-EOR Project Oklahoma, USA Chaparral Energy & Merit Energy 0.68 Fertiliser production (pre) 1982 EOR [6]
Operate PS: Rectisol Great Plains Synfuel Plant and Weyburn-Midale Project Saskatchewan, Canada Dakota Gasification (Basin Electric Power Cooperative) 3.0 IGCC (pre) 2000 EOR [7]
Operate PS: Selexol Lost Cabin Gas Plant Wyoming, USA Denbury Resources 0.9 Natural gas 2013 EOR [8]
Operate PS: Selexol Shute Creek Gas Processing Facility Wyoming, USA ExxonMobil 7.0 Natural gas 1986 EOR [9]
Operate CS: 45wt-% MDEA Sleipner?CO2 Storage Project North Sea, Norway Statoil, ExxonMobil E&P Norway, Total E&P Norge 0.9 Natural gas 1996 Dedicated geological storage [10]
Operate CS: Activated MDEA (BASF) Snøhvit CO2 Storage Project Barents Sea, Norway Statoil, Petoro, Total E&P Norge, GDF Suez E&P Norge, RWE DEA Norge 0.7 Natural gas 2008 Dedicated geological storage [11]
Operate PS: Selexol Val Verde Natural Gas Plants Texas, USA Sandridge Energy & Occidential Petroleum 1.3 Natural gas 1972 EOR [12]
Execute CS: Benfield process Alberta Carbon Trunk Line (‘ACTL’) with Agrium CO2 Stream Alberta, Canada Enhance Energy and Agrium 0.3–0.6 Fertiliser production (pre) 2015 EOR [13]
Execute PS: Rectisol Alberta Carbon Trunk Line (‘ACTL’) with North West Sturgeon Refinery CO2 Stream Alberta, Canada Enhance Energy and North West Redwater Partnership 1.2–1.4 IGCC (pre) 2017 EOR [14]
Execute CS: Activated MDEA Gorgon Carbon Dioxide Injection Project Western Australia, Australia Chevron, Shell, ExxonMobil, Osaka Gas, Tokyo Gas, Chubu Electric Power 3.4–4.0 Natural gas 2015 Dedicated geological storage [15]
Execute PS: Selexol Kemper County Energy Facility (formerly Kemper County IGCC Project) Mississippi, USA Mississippi Power (Southern Company) 3 IGCC (Brown coal) (pre) 2016 EOR [16]
Execute CS: Activated MDEA (Shell ADIP-X) Quest CCS Project Athabasca Oil Sands Project Alberta, Canada Shell Canada Energy, Chevron Canada Limited, Marathon Oil Canada Corp. 1.08 Hydrogen production (pre) 2015 Dedicated geological storage [17]
Execute CS: Diglycolamine Uthmaniyah CO2 EOR Demonstration Project Eastern Province, Saudi Arabia Saudi Aramco 0.8 Natural gas 2015 EOR [18,19]
Execute CS: Amine Abu Dhabi CCS Project (formerly Emirates Steel Industries (ESI) CCS Project) Abu Dhabi, United Arab Emirates Abu Dhabi National Oil Company, Abu Dhabi Future Energy Company 0.8 Iron and steel (pre) 2016 EOR [20]
Execute CS: Fluor Econamine FG PlusSM Petra Nova Carbon Capture Project Texas, USA NRG Energy, JX Nippon Oil & Gas Exploration 1.4 PCC (sub-bituminous coal) (post) 2016 EOR [21]
Tab.1  Currently operational and near-term carbon capture projects (PS: physical solvent; CS: chemical solvent; pre: pre-combustion capture: post; post-combustion capture)
Rectisol Companies: Linde AG, Lurgi AG.
Major components: chilled methanol.
Operating requirements or advantages:
(1)?Deep refrigeration (typical operation temperature is below 0 °C due to the fact that methanol has a relatively high vapour pressure at normal process conditions).
(2)?Water washing of effluent streams to prevent high solvent losses.
Limitations: exhibit higher selectivity for H2S over CO2.
Selexol [25] Companies: Norton, Dow, UOP.
Major components: dimethyl ether of polyethylene glycol (DPEG).
Operating requirement or advantages:
(1)?Exhibits the highest CO2 solubility among physical solvents.
(2)?No water wash is required due to a very low vapour pressure.
(3)?Able to operate at a broad temperature range: from 0 °C to 175 °C.
(4)?Selexol is less costly than Rectisol for CO2 sequestering.
Limitations: higher viscosity than most physical solvents, particularly at low temperatures, resulting in low mass transfer and high packing requirements.
Sepasolv-MPE Companies: BASF.
Major components: mixture of polyethylene glycol dialkyl ethers.
Operating requirements or advantages:
?Similar in performance and operation to Selexol process.
Limitations: no longer licensed.
Fluor solvent Companies: Fluor.
Major components: propylene carbonate (PC).
Operating requirements or advantages:
(1)?Has been in use since the late 1950s.
(2)?A higher vapour pressure than Selexol, although solvent losses are still low.
Limitations: It is not recommend for use if more than trace levels of H2S are present. It reacts irreversibly with water and is unstable at high temperatures and thus operating temperature is below 65 °C.
Purisol Companies: Lurgi GmbH.
Major components: N-methyl-2-pyrrolidone (NMP).
Operating requirements or advantages:
(1)?Water washing of treated and rejected acid gas should be taken into consideration for solvent recovery.
(2)?A higher vapour pressure than Selexol and Fluor solvent and therefore operates at ambient temperatures or below.
Limitations: exhibit higher selectivity for H2S over CO2.
Morphysorb [26] Companies: ThyssenKrupp.
Major components: N-formyl-morpholine (NFM) and N-acetyl-morpholine (NAM).
Operating requirements or advantages:
A specialty solvent first used industrially in 2002. It was developed for its high selectivity of acid gases over heavier hydrocarbons.
Tab.2  Various physical solvents used in acid gas separation
Solvent Facility Location Company Slip-stream /MW Processing capacity /(t CO2·d−1) Source Operational date Ref.
MEA Boundary Dam Power Station Saskatchewan, Canada SaskPower 4 Lignite/ brown coal 2000 [43,44]
MEA Tarong Power Station Tarong, Australia CSIRO 0.1 2 Black coal, PCC 2008 [45]
MEA Loy Yang Power Station Latrobe Valley, Australia CSIRO 1 Brown coal, PCC 2008 [46]
MEA Huaneng Beijing Cogeneration Plant Beijing, China CSIRO 8 8 Black coal, PCC 2008 [47,48]
MEA Jilin Oil Field Jilin Province, China PetroChina 550 Natural gas 2009 [49]
MEA Brindisi Power Plant Cortemaggiore, Italy ENEL 54 Coal 2011 [50]
MDEA Elcogas Puertollano Puertollano, Spain Elcogas 5 100 Coal and petcoke IGCC 2011 [51]
MEA
Advanced amine (H3-1)		 Tokyo Electric Power Station Yokosuka, Japan Hitachi <1 Coal, PCC Early 1990s [52]
Advanced amine (H3-1) SaskPower, Shand Power Station Estevan, Saskatchewan Hitachi 120 Canadian lignite 2014 [52]
MEA
Advanced amine (H3-1)		 E.W. Brown Generating Station Kentucky, USA Hitachi 0.7 15 Coal 2014 [53]
Advanced amine (UCARSOLTM FGC 3000) Dow Chemicals, South Charleston West Virginia, USA Dow Chemical 5 Coal, PCC 2009 [54]
MEA
Advanced amine (RS-1, RS-2, RS-3)		 International Test Centre for CO2 Capture University of Regina, Canada SaskPower 0.25 1 Steam boiler 2000 [55,56]
Advanced amine (Cansolv-Shell) Aberthaw Wales, UK RWE 3 50 Coal 2013 [57]
MEA
Advanced amine (CASTOR 1, CASTOR 2)		 Dong Energy Esbjerg, Denmark European Commission Funded, IFP-run 3 24 Coal, PCC 2008 [58]
Advanced amine (KoSol series) Boryeong Thermal Power Plant Boryeong, Republic of Korea KEPCO 10 2 Coal, PCC 2010 [59]
KS-1, KM-CDR Process MHI Hiroshima R&D Centre Hiroshima, Japan MHI 1 Coal, PCC 2004 [60]
KS-1, KM-CDR Process J-Power, Matsushima Thermal Power Station Nagasaki, Japan MHI 10 Coal, PCC 2006 [60]
KS-1, KM-CDR Process KEPCO, Nanko Natural Gas Osaka, Japan MHI 0.1 2 Natural gas 1991 [60]
KS-1, KM-CDR Process Georgia Power’s Plant Yates Georgia, USA MHI and Southern Company 0.1 Coal 2010 [22]
KS-1, KM-CDR Process Plant Barry Power Station Mobile, Alabama, USA MHI, Southern Energy, Electric Power Research Institute 25 410 Coal 2011 [61]
Advanced amine
(TNO CORAL)		 CATO-2 CO2 Catcher Rotterdam, Netherlands E .ON
TNO		 0.4 6 Coal, PCC 2008 [62,63]
Amine mixture Shidongkou China Huaneng 300 Coal 2011 [64]
Amine Ferrybridge CCSPilot100+ UK SSE 5 100 Coal 2012 [65]
CESAR-1, CESAR-2 Laboratory of Engineering Thermodynamics (LTD) European Union Enhanced Separation & Recovery 54–105 Prepared flue gas 2011 [66,67]
Mixed amine
Fluor Econamine FG PlusSM		 Wilhelmshaven Germany E. ON 70 Coal 2012 [68]
Ammonia Delta Electricity Munmorah Power Station Munmorah, Australia CSIRO 3 Black coal PCC 2009 [69]
Ammonia Burger Plant Shadyside, OH, USA First Energy 1 Coal, PCC 2008 [70]
Alstom chilled ammonia Pleasant Prairie WI, USA Alstom 5 40 Coal, PCC 2008–2009 [71]
Alstom chilled ammonia AEP Mountaineer WV, USA AEP 20 Coal, PCC 2009–2011 [72]
Alstom chilled ammonia Karlshamn, Power Plant Sweden E. ON 5 40 Sulphur oil 2009–2010 [73]
Amine, chilled ammonia European CO2 Test Centre Mongstad Mongstad, Norway Norwegian Government, Statoil, Sasol, Shell 280 Natural gas 2012 [74]
Amino acid salt
(Siemens PostCapTM)		 Polk Power Plant FL, USA TampaElectric 800 IGCC 2014 [75]
Amino acid salt
(Siemens PostCapTM)		 E. ON Staudinger, Germany Siemans 1 PCC and natural gas 2009, 2012 [76]
Immobilized carbonic anhydrase with potassium carbonate National Carbon Capture Center, Plant Gaston Alabama, USA Akermin 5.6 PCC 2012 [77,78]
MEA/Piperazine/Carbonate UT/SRP (University of Texas/Separations Research Program) University of Texas, USA University of Texas 0.1–0.5 1.3–5.9 Prepared flue gas 2002 [79]
Potassium carbonate Hazelwood Power Station Latrobe Valley, Australia CO2CRC 1–25 Brown coal PCC 2009–2013 [80]
Potassium carbonate HRL Research Gasifier Mulgrave, Victoria, Australia CO2CRC 1 IGCC 2009–2010 [81]
Piperazine (concentrated) URS (University of Texas) NCCC, USA Trimeric Corporation / University of Texas 0.1–0.5 Prepared flue gas 2013 [22]
Piperazine Colorado Springs Utilities Drake #7 Colorado Spring, CO, USA Neumann Systems Group 0.5 PCC 2014 [82]
Physical-dimethyl-ether of poly-ethylene-glycol (DEPEG) Willem-Alexander Power Plant Buggenum, Netherlands Vattenfall, Nuon 33 IGCC: coal and biomass 2011 [83]
Tab.3  Pilot plant facilities testing carbon capture solvents
Type Company Solvents Benefit Disadvantage Future work Ref.
Advanced amine Hitachi;
Dow;
KEPCO;
MHI;
Fluor;
Shell		 H3-1;
UCARSOLTM FGC 3000;
RS-1, RS-2, RS-3;
Cansolv;
CASTOR 1 & 2;
KS-1, KS-2, KS-3;
Fluor Econamines FG PlusSM		 Extensive operational/design experience available;
An extra degree of freedom determining the compositions of amine mixtures to optimise its performance		 Corrosion;
Solvent degradation; Form heat stable salts with SO2 and NO;
Amine emission;
Viscous		 Develop novel amine based solvents to lower regeneration energy required, oxidative degradation, corrosion, and increase reaction kinetics and absorption capacity;
Heat integration;
Equipment innovation such as intercooling system		 [22,119–121]
Amino acid salt Siemens;
BASF		 PostCap;
Puratreat		 Low vapour pressure;
Low oxidative degradation and emission;
Reactive towards CO2;
Low environmental impact;
Similar rate constants to MEA		 Forms heat stable salts with SO2 and NO;
High heat of regeneration		 Performance should be examined on a larger scale and in a real industrial situation [22,122–125]
Carbonate system UNOTechnology UNO MK3 Low vapour pressure;
Non-volatile;
No oxidative degradation;
Low toxicity;
Low regeneration energy;
Low environmental life-cycle impact;
Multi-impurity capture;
FGD unnecessary;
Low manufacture cost		 Reduced kinetics Scale up of plant based trials;
Process of design of large scale systems;
Examine new promoter systems;
Slurry handling system design and simulation		 [22,80,126]
Aqueous ammonia Alstom;
CSIRO;
PowerSpan		 CAP Does not decompose, high capacity, high purity product, competitive heat of regeneration High ammonia vapour pressure;
Slower kinetics than MEA;
Solid ammonium bicarbonate formation;
Ammonia emission;
Harsh conditions duo to operating temperature		 Additives to enhance CO2 absorption rate and suppress ammonia vapour, re-engineering industrial ammonium bicarbonate fertilizer production and combined capture of CO2 and SO2 [22,69,127–131]
Immiscible liquid 3H Company Self-concentrating absorbent CO2 capture process Low regeneration energy;
Non-aqueous environment to mitigate corrosion, degradation and formation of stable salts		 Mechanism and chemistry unsure;
Low maturity		 Develop new system using different liquids;
More testing and research on bench scale should be conducted		 [22]
Ionic liquid Notre Dame;
Georgia Tech.		 NDIL0046;
NDIL0157;
RevILs		 High thermal stability, no water evaporation in regeneration, no vapour pressure, tailorable Expensive;
High viscosity;
High selectivity to water		 Improve operating performance of ILs;
Improve process chemistry;
Integration of capture with manufacturing saleable goods, i.e., organic carbonates, formic acid		 [22,132–134]
Tab.4  Solvent summary
  
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