June 2021

Sustainability

A critical analysis of CO₂ capture technologies

The use of fossil fuels as a source of energy continues to add carbon dioxide to the atmosphere, causing detrimental effects to the environment.

Scientists around the world are working to reduce the effects of CO₂ emissions, and many research efforts are ongoing at both academic and industrial levels.

Among the available CO₂ capture technologies, solvent-based technologies are commercially proven and practiced in many industries. Despite the commercialization of solvent-based technologies, research on CO₂ capture processes is still vigorously being pursued to significantly minimize capital and operating costs per ton of CO₂ capture, while improving operational reliability.

In the last decade, solid sorbents have been recognized as a very promising technology for CO₂ capture, with the potential to overcome the existing limitations of solvent-based technologies. This article highlights the recent developments in commercial solvent-based technologies and compares their economics with a proprietary hydrated sorbent process^a for CO₂ capture recently developed by the authors’ company.

Contributing to global warming and environmental damage

Rapid industrial growth globally has increased CO₂ emissions from pre-industrial levels of 280 ppm to 407.4 ppm in 2018—up 2.4 ppm since 2017—and is growing rapidly at approximately 1.5 ppm/yr–2.5 ppm/yr.¹ Coal is the second-largest source of primary energy: China, India and the U.S. have accounted for 85% of the net increase in CO₂ emissions. Fossil fuel combustion supplies more than 85% of energy for industrial activities and is the major contributor of CO₂ emissions.² Moreover, fossil fuels will remain the major sources of energy for the next several decades.

The process of carbon capture and storage (CCS) has the potential to reduce future world emissions from energy by 20%.³ According to the Global CCS Institute CO₂RE database, in 2018, 23 large-scale CCS facilities were in operation or under construction, capturing ~40 MMtpy of CO₂.⁴ The separation of CO₂ from the source consumes approximately 75% of the total cost of the CCS system, which impacts system implementation.⁵ Therefore, it is necessary to employ a cost-effective technology for CO₂ separation from flue gas.

Three main techniques are commercially used for CO₂ capture:

• A post-combustion capture process, which involves CO₂ capture from flue gas after the complete combustion of fuel
• A pre-combustion capture process in which fuel is placed in the furnace by first converting coal into a clean-burning gas and stripping out the CO₂ released by the process
• An oxyfuel process, which burns the coal in the pure oxygen-rich atmosphere, resulting in an exhaust gas
  with almost pure CO₂.⁶

Among these technologies, the post-combustion capture technique involves a higher cost of capture per ton of CO₂, as it involves the diluted concentration of flue gas (i.e., < 15%).⁷ Based on the technological readiness level (TRL), the available post-combustion capture technologies can be classified at various stages of development.

Abanades, et al., reviewed various CO₂ capture technologies in the context of post-combustion capture, including calcium looping, chemical looping, post-combustion capture using adsorbent, solvent and membrane, and concluded that post-combustion capture is the most mature and successful technique for CO₂ capture using solvent.⁸ In recent years, the solid sorbent route is garnering the most attention for use in the post-combustion capture process due to its inherent advantage of wider temperature range application from ambient temperature to 700°C, less waste formation during cycling, and the safe disposal of spent solid sorbent without undue environmental precautions.⁷

Published literature on CO₂ capture by the adsorption technique using porous organic frameworks, supported alkali metal carbonate and membranes has shown considerable CO₂ capture capacity. However, the high temperature and resource requirements to regenerate the solid sorbent negatively influences the overall cost and time efficiency of the process.⁹

In this article, the most recent and promising developments in post-combustion capture technologies that are at pilot and commercial scale are reviewed critically. Further, the proprietary hydrated CO₂ sorbent process^a is discussed and compared, as well as its economic and energy estimates vs. the conventional and hindered amine process.

Post-combustion CO₂ capture technologies

The two major technologies for post-combustion capture are based on solvents and solid sorbents. These two technologies differ, particularly in terms of reaction rate, CO₂ capture capacity, absorption/regeneration temperature, capital cost, corrosivity, mass and heat transfer and stability (thermal, oxidative and chemical, where chemical stability denotes reactivity against the impurities present in the flue gas).⁹

SOLVENT TECHNOLOGIES

The solvent route is based on chemical absorption of CO₂ from the source, such as a coal-fired power plant. The development of a CO₂ capture technology depends on parameters that include energy demand, cyclic capacity, solvent stability, reactivity, volatility, environmental sustainability and availability.¹⁰ Solvent-based technologies are categorized based on the solvent used in the CO₂ capture process.

Conventional amine absorption process (CAAP)

A conventional amine absorption process applied to the flue gas (10 kPa CO₂–15 kPa CO₂) for CO₂ capture using monoethanolamine (MEA) as a solvent involves absorption at 40°C–45°C and desorption at 115°C–120°C. An aqueous MEA solution (20 wt%–30 wt%) can achieve a high level of CO₂ capture (90% or more) due to the fast kinetics and strong chemical reaction. The typical minimum stripper reboiler duties for CAAP are ~3.6 GJ/metric t–4 GJ/metric t of CO₂ captured.^11,12 In the solvent-based process, gas and liquid streams are contacted in a counter-current fashion. A simplified flow diagram of this process is given in FIG. 1.

One commercial example of a CAAP is Econamine FGSM (EFG), a Fluor proprietary conventional amine-based technology used for large-scale, post-combustion CO₂ capture. The EFG technology is the first and most widely applied process that has extensive proven operating experience in the removal of CO₂ from high-oxygen content flue gases. The Econamine FGSM technology uses a 30 wt% MEA as the absorption solvent, with chemical inhibitors to counter the effects of corrosion caused by oxygen in the flue gas. This process is best operated at low levels of sulfur dioxide (SO₂) (< 10 ppmv) and nitrogen oxide (NO_x) (< 20 ppmv) to avoid excessive solvent degradation.¹³

MEA has good rates of CO₂ mass transfer, is low in cost and readily biodegradable but suffers from moderate rates of oxidative, thermal degradation and moderate levels of toxicity. It is also corrosive when used at higher concentrations and is particularly suited to low-CO₂, partial-pressure applications.¹⁴ The major drawback of such a process is its high energy consumption of 3.6 GJ/metric t–4 GJ/metric t of CO₂ capture and, therefore, high operating cost. The capital cost is also quite high with very tall absorption and desorption towers required for a high percentage of CO₂ capture. Another major difficulty is high solvent degradation in the presence of oxygen in flue gas, as well as an excess corrosion rate demanding high metallurgy for both the absorber and desorber columns.

Hindered amine absorption process

With the potential of large-scale power plant CO₂ mitigation, technology developers—such as Mitsubishi Heavy Industries (KM-CDR process), Linde-BASF (OASE blue process) and Carbon Clean Solution Ltd. (CDRMax™ process)—have begun to optimize chemical absorbing technologies to reduce the overall operating and capital costs of CO₂ capture. The modifications focused are primarily on thermal integration of the CO₂ capture system with the power plant and development of improved solvent formulations with lower stripping steam demand, lower solvent circulation rates than CAAP, and reduced solvent degradation. These process improvements have the potential to reduce the cost and energy intensity of post-combustion CO₂ capture by an estimated 30% compared to a conventional amine route.

Recent commercial solvent technologies for CO₂ capture are based on the use of hindered amine solvent or blends of amines with additives to reduce problems related to equipment corrosion, amine degradation and high energy consumption. Hindered amine solvents are basically derivative of tertiary amine, which has greater absorption capacity but lower CO₂ mass transfer rates than sterically unhindered primary and secondary amines. Blending of hindered amine solvent with additives can help to overcome the mass transfer problem.

MHI’s CO₂ capture technology

To overcome the issues of CAAP, Mitsubishi Heavy Industries (MHI) has developed a post-combustion CO₂ capture technology called the KM-CDR™ (Kansai Mitsubishi Carbon Dioxide Recovery) process. It uses KS-1™ solvent, which has low energy consumption, minimal solvent loss and low corrosivity.¹⁵ The KM-CDR process can capture more than 90% of the CO₂ from a flue gas stream and the produced CO₂ is more than 99.9% pure. The use of steam in MHI’s KM-CDR technology (0.98 metric t/metric t–1.48 metric t/metric t of CO₂) is lower than CAAP. So far, MHI has commercialized 13 CO₂ capture plants to produce fertilizer, methanol and oil.¹⁶ The world’s largest CO₂ capture plant (4,776 metric tpd) on a coal-fired power plant to Petra Nova Parish Holdings LLC was delivered by MHI in 2016. Details of the plant are provided in TABLE 1.

MHI improved its CO₂ capture technology by implementing a new system into the KM-CDR process. Three of the major improvements are:

1. A load adjustment control system that helps maintain smooth operation for the dynamic flue gas changes in the host coal-fired plant. This allows the desired CO₂ recovery ratio, capture amount and steam consumption rate to be maintained, even if the CO₂ concentration in the flue gas changes significantly.
2. An improved amine emissions reduction system that reduces the loss of solvent. The improved system reduces amine emissions by more than 90% compared to the conventional system.
3. The recently improved energy saving system improves energy efficiency by reducing steam consumption by 5%.

However, such hindered amine-based processes are generally very sensitive to SO₂ and (in particular) sulfur trioxide (SO₃) impurities; therefore, they require additional, deeper desulfurization of the flue gas—implying increased CAPEX compared to the CAAP route.

OASE Blue Technology for CO₂ capture

Linde and BASF Group jointly developed a post-combustion capture technology using BASF’s novel propriety solvent.¹⁷ This technology offers significant benefits for CO₂ capture as it saves 20% on energy input over CAAP and has superior oxygen stability, significantly reducing solvent consumption. This collaboration completed a pilot-sale demonstration at the National Carbon Capture Center (NCCC) on a coal-fired power plant flue gas in 2014, and final commissioning was completed in January 2015. The design capacity of the operation was 1 MWe–1.5 MWe and it requires less regeneration energy (2.8 GJ/metric t of CO₂) than the conventional amine process at regenerator pressure of 3.4 bar absolute. The pilot plant captures up to 30 tpd of CO₂ at more than 90% capture rate, and CO₂ purity was > 99.9%. BASF and The Linde Group’s Engineering Division have agreed to further develop the process with demonstrations at other facilities.

Carbon Clean Solution Ltd. (CCSL) technology for CO₂ capture

CCSL has developed a process, CDRMax™, that operates at near atmospheric pressure, enabling 95% CO₂ recovery and > 99% purity that can be used to produce fuels and chemicals.¹⁸ The salient features of the technology are:

• Reduction in energy consumption of 27%
• Loss of amine solvent reduced by eight times
• Reduction in equipment corrosion by seven times
• Reduction in amine emissions by five times.

CCSL can capture CO₂ at the cost of $30/metric t, while other available technologies achieve $45/metric t–$60/metric t. The company’s first plant, with a capacity of 60,000 metric tpy, came online in 2016 in partnership with Tuticorin Alkali Chemicals and Fertilizers in India; the plant converts recovered CO₂ from its coal-fired boiler into soda ash. The technology uses a solvent called amine promoted buffer salt (APBS), which causes less corrosion. The APBS is a mixture of hindered amine (2-amino-2-methyl-1, 3-propandiol), potassium salt of amino carboxylic acid or amino sulfonic acids and about 75 wt% of water. The CCSL solvent has significantly higher CO₂ loading capacity compared to the commercially used solvents MDEA and dimethyl ether of polyethylene glycol (DEPG). Heat of reaction for the CCSL solvent is 39.2 kJ/mol CO₂, which is 20% lower than that of MDEA (48.9 kJ/mol CO₂). This solvent can handle 80 times more CO₂ than other amine-based solvents. The absorption temperature of the CDRMax™ process is between 50°C–70°C and the stripper temperature is at 80°C–120°C. CCSL claims 40% lower OPEX and 30% lower CAPEX than a conventional CO₂ capture technology.

Drawbacks of solvent-based technologies

Solvent-based technologies have the inherent advantage of being ‘‘end-of-pipe’’ technologies, like existing technologies for the mitigation of sulfur oxide (SO_x), NO_x and hydrogen sulfide (H₂S) emissions. Moreover, their addition to power plants, either as a retrofit or as new build, will not unduly affect the flexibility of operations demanded of these facilities.³ However, solvent-based technologies have major disadvantages, including:

• Large equipment size
• Large volumes of solvents required
• Amine-based solvents are corrosive in nature
• Susceptible to degradation, even by trace amounts of flue gas impurities (particularly SO_x and O₂)
• Produces toxic byproducts on heating
• Emissions of solvents from recovery columns must be scrubbed and eliminated
• High amount of steam requirement
• Disposal of expired solvents is problematic
• Energy and CAPEX-intensive process.

Shortcomings in existing solvent-based technologies have driven research to develop solid adsorbent-based technologies for CO₂ capture. Adsorption processes using solid regenerable sorbents capable of capturing CO₂ from flue gas streams have many potential advantages compared to conventional amine-based absorption process, such as reduced energy for regeneration, greater adsorption capacity, selectivity and ease of handling.

Solid sorbent technology

The CO₂ capture process was also studied over various solid sorbents, such as zeolites 13X, metal organic framework (MOF), activated carbon, supported alkali metal carbonate, etc. Among these sorbents, supported alkali metal carbonate are widely studied as a capture media for CO₂ from a diluted gas stream using a thermal swing adsorption process.¹⁹ Alkali metal carbonate can capture CO₂ within the temperature range of 50°C–100°C, with regeneration at 120°C–200°C, which makes it a potential sorbent to capture CO₂ from coal-fired power plants with wet flue gas desulfurization (FGD). The main drawbacks of alkali metal carbonate sorbents are the requirement of higher regeneration temperature and handling of solid phase.⁷

The developed proprietary hydrated sorbent process^a for CO₂ capture (HSC) provides the desired characteristics required for the commercial plant. The developed sorbent shows high adsorption capacity, fast adsorption/desorption kinetics and multi-cycle stability. The process utilizes potassium carbonate supported on solid support as a sorbent. The salient features of the solid sorbents are:

• Higher surface area (35 m²/g) and pore volume (0.15 cm³/g) despite high loading of active species
• Higher adsorption capacity (3.2 mmol/g)
• Multi-cycle stability
• Lower regeneration temperature (120°C–130°C)
• Stability with flue gas impurities (SO_x, NO_x, O₂, etc.)
• Minimal reliability issues.

The hydrated sorbent process follows carbonate-bicarbonate chemistry according to the following reaction schemes:

      Pre-treatment: K₂CO₃ + 1.5H₂O → K₂CO₃. 1.5H₂O
          ΔH = –40 kJ/mol

      Adsorption: K₂CO₃. 1.5H₂O + CO₂ ↔ 2KHCO₃ + 0.5H₂O    
          ΔH = –101 kJ/mol

      Partial regeneration: 2KHCO₃ + 0.5H₂O ↔ K₂CO₃. 1.5H₂O + CO₂
          ΔH = 40 kJ/mol

      Full regeneration: 2KHCO₃ ↔ K₂CO₃ + CO₂ + H₂O              
          ΔH = 141 kJ/mol

The supported alkali carbonate sorbents in the presence of H₂O form hydrated species, which in turn can capture CO₂ to form bicarbonate species at temperatures 70°C–90°C. By performing a moderate temperature swing of 120°C–130°C, the bicarbonate decomposes and releases a CO₂/H₂O mixture that can be converted into a “sequestration-ready” CO₂ stream by steam condensation.

Unlike amine-based absorption, there is no heat demand for vaporization of water or corrosion/solvent degradation issues. The important feature of the proprietary process is the ability of the sorbent to adsorb at higher temperatures of 70°C–90°C, and regenerate at 120°C–130°C; therefore, the temperature difference between adsorption and regeneration is only 40°C–50°C, which is suitably utilized for the heat pump to further minimize heat demand.

The lower temperature differential between adsorption and regeneration is helpful in an effective temperature approach for heating and cooling of adsorbent in addition to its thermal stability. The proprietary hydrated sorbent process can be used for:

• Natural gas-fired power plant flue gas with nominal make-up quantity (0.5 kg/metric t of CO₂)
• Coal-fired power plant flue gas incorporating wet FGD (for SO_x levels < 20 ppm).

Conversely, NO_x tolerance for the proprietary sorbent^a is expected to be much better than amine systems due to its inertness towards NO_x. It is important to note that there is no concern for oxygen presence in the flue gas for this technology, unlike a conventional amine system.

The innovations in sorbent and process were instrumental in achieving minimum OPEX in the HSC process. The overall heat demand in the HSC process is significantly lowered by partial regeneration of sorbent in accordance with hydration chemistry, as discussed here. As a result, a significant reduction is seen in regeneration heat demand from 141 kJ/mol CO₂ (non-hydrated) to 70 kJ/mol CO₂ (hydrated). In addition to no heat loss due to water evaporation in the solid sorbent, this results in an overall 60%–70% lower energy demand per ton of CO₂ capture vs. a conventional amine process for rich and lean concentrations of CO₂ in flue gas from a coal-fired power plant/FCC flue gas and natural gas-fired power plant, respectively.

Unlike in a conventional amine absorption system—where it is not possible to minimize energy demand beyond a point since the heat loss due to evaporation of water is unavoidable—the proprietary hydrated sorbent process for CO₂ capture works on the principle of circulating fluidized bed reactors with solid hydrated sorbent circulating between the adsorber and regenerator, as shown in FIG. 2.

Furthermore, the closer ∆T between adsorption and desorption allows the heat pump concept to extract and utilize low-temperature (120°C–180°C) streams available in a refinery or power plant. This reduces the energy consumption close to 80%–90% of CAAP, when heat integration is done with a low-temperature (120°C–180°C) process stream in a refinery and power plant.

A recent circulating fluidized bed pilot plant study with high-capacity HSC sorbent has demonstrated 93% CO₂ removal on a continuous basis at steady state. The sorbent has also shown excellent stability. The high-capacity HSC sorbent has shown 3.2 mmol/g of CO₂ capture capacity, which is one of the highest values among published research, including all amines and solid sorbents.

The circulating fluidized bed in the HSC process exhibits a very good heat transfer rate, as in the case of a liquid amine system. The sorbent is thermally stable, attrition resistant, non-corrosive, non-sticky/free-flowing in the operating regime and demonstrates excellent heat transfer and fluidization properties of Geldart-A particles. The comparison of key parameters for the proprietary process vs. a conventional amine process for rich flue gas case is summarized in TABLE 2.

TABLE 2 clearly shows the advantage of the hydrated sorbent process^a for CO₂ capture over solvent-based commercial technologies. The net energy demand for per mol of CO₂ capture in the hydrated sorbent process is ~ 40% of the conventional amine process and less than the hindered amine process. The hydrated sorbent process creates significant savings in per metric t cost of a CO₂ capture plant by driving down the operating and capital costs by 70% and 40%, respectively, over the CAAP route.

Takeaway

Solvent-based technologies based on hindered amine have shown potential progress to develop CO₂ capture technology and reduce CAPEX and OPEX by process heat integration, use of amine blend solvent and additive, etc. However, recent developments in hydrated solid sorbent have shown potential to substitute a solvent-based technology for CO₂ capture. Unlike gas-liquid contacting for amine—where the absorber vessels’ heights are very large and tall to satisfy the flooding and mass transfer requirement—the circulating bed system used for CO₂ capture is very compact in height and can provide much higher capacity in a single unit compared to an amine absorption system.

The overall operating cost of the proprietary process is 70% lower, whereas the CAPEX cost is 40% lower than a conventional amine process (due to the vessel size with no exotic metallurgy, unlike amine). The hydrated sorbent process is well demonstrated for continuous sorbent circulating mode in a pilot plant with 35 kg inventory. The effects of various parameters were studied and resulted in CO₂ removal efficiency of > 90% and purity above 99%. The pilot trial provided definite indications towards the efficacy and scalability of the hydrated sorbent process for capturing CO₂ from stationary point sources in a power plant, refinery or petrochemicals facility. HP

ACKNOWLEDGEMENTS

The authors thank Reliance Industries Ltd. (RIL) for its cooperation in executing all the experiments discussed here.

NOTES

         ^a Reliance Industries Ltd.’s Hydrated sorbent CO₂ Capture Process.

LITERATURE CITED

1. International Energy Agency (EIA), “Global energy and CO₂ status report 2018,” March 2018.
2.  Oschatz, M. and M. Antonietti, “A search for selectivity to enable CO₂ capture with porous adsorbents,” Energy & Environmental Science, Iss. 1, 2018.
3. aszeldine, R. S., “Carbon capture and storage: How green can black be?” Science, September 2009.
4. Carbon Capture Journal, Iss. 67, January/February 2019.
5. Nie, L., Y. Mu, J. Jin, J. Chen and J. Mi, “Recent developments and consideration issues in solid adsorbents for CO₂ capture from flue gas,” Chinese Journal of Chemical Engineering, Vol. 26, Iss. 11, November 2018.
6. MacDowell, N., N. Florin, A. Buchard, J. Hallett, A. Galindo, G. Jackson, C. S. Adjiman, C. K. Williams, N. Shah and P. Fennell, “An overview of CO₂ capture technologies,” Energy & Environmental Science, Iss. 11, 2010.
7. Wang, J., L. Huang, R. Yang, Z. Zhang, J. Wu, Y. Gao, Q. Wang, D. O’Hare and Z. Zhong, “Recent advances in solid sorbents for CO₂ capture and new development trends,” Energy & Environmental Science, Iss. 11, 2014.
8. Abanades, J. C., B. Arias, A. Lyngfelt, T. Mattisson, D. E. Wiley and H. Li, “Emerging CO₂ capture systems,” International Journal of Greenhouse Gas Control, 2015.
9. Amte, V., A. K. Das, S. Sengupta, M. Yadav, S. Mandal, A. Pal, A. Gupta, R. Bhujade, S. R. Akuri and R. Dongara, “Single compression system and process for capturing carbon dioxide,” Patent #: US10166502B2.
10. Bhattacharyya, D. and D. C. Miller, “Post-combustion CO₂ capture technologies—a review of processes for solvent-based and sorbent-based CO₂ capture,” Current Opinion in Chemical Engineering, Vol. 17, August 2017.
11. Creamer, A. E. and B. Gao, “Carbon-based adsorbents for post-combustion CO₂ capture: A critical review,” Environmental Science & Technology, June 2016.
12.  U.S. Department of Energy (DOE)/NETL Carbon capture program, “Carbon dioxide capture handbook,” August 2015.
13. Reddy, S., J. Yonkoski, H. Rode, R. Irons and W. Albrecht, “Fluor’s Econamine FG Plus^SM completes test program at Uniper’s Wilhelmshaven coal power plant” Energy Procedia, Vol. 114, July 2017.
14. Wang, M., A. S. Joel, C. Ramshaw, D. Eimer and N. M. Musa, “Process intensification for post-combustion CO₂ capture with chemical absorption: A critical review,” Applied Energy, Vol. 158, November 2015.
15. Hirata, T., H. Nagayasu, T. Yonekawa, M. Inui, T. Kamijo, Y. Kubota, T. Tsujiuchi, D. Shimada, T. Wall and J. Thomas, “Current status of MHI CO₂ capture plant technology, 500-tpd CCS demonstration of test results and reliable technologies applied to coal fired flue gas,” Energy Procedia, December 2014.
16. Hirata, T., S. Kishimoto, M. Inui, T. Tsujiuchi, D. Shimada and S. Kawasaki, “MHI’s commercial experiences with CO₂ capture and recent R&D activities,” Mitsubishi Heavy Industries Technical Review, Vol. 55, March 2018.
17. Online: https://www.basf.com/global/en/media/news-releases/2016/07/p-IR-160719.html
18. Patkar, A. and P. Bumb, “Carbon capture technology for flue gas applications,” CMTC conference, Houston, Texas, July 17–20, 2017.
19. Sengupta, S., V. Amte, R. Dongara, A. K. Das, H. Bhunia and P. K. Bajpai, “Effects of the adsorbent preparation method for CO₂ capture from flue gas using K₂CO₃/Al₂O₃ adsorbents,” Energy Fuels, December 2014.

The Authors

Related Articles

From the Archive

Comments