Carbon capture and storage: research conclusions?

Carbon capture and storage (CCS) prevents CO2 from entering the atmosphere. Options include the amine process, blue hydrogen, novel combustion technologies and cutting edge sorbents and membranes. Total CCS costs range from $80-130/ton, while blue value chains seem to be accelerating rapidly in the US. This article summarizes the top conclusions from our carbon capture and storage research.

What is carbon capture and storage? CO2 is a greenhouse gas. But it is also an inevitable product of many energy-releasing reactions, from biology, to materials, to industrial energy, because of the high enthalpy of the C=O bond, at 1,072 kJ/mol. Carbon capture and storage technologies therefore aim to capture unavoidable CO2, purify it, transport it, and sequester it, to prevent it from contributing to climate change.

What are the costs of carbon capture and storage? 10-20% of all decarbonization in our roadmap to net zero will come from CCS, with the limit set by economic costs, ranging from $80-130/ton on today’s technologies, which is towards the upper end of what is affordable. Costs vary by CO2 concentration, by industry, by process unit, but will hopefully be deflated by emerging technologies.

Amines are the incumbent technology among 40MTpa of past carbon capture and storage projects, bubbling CO2-containing exhaust gases through an absorber column of lean amines, which react with CO2 to form rich amines. The CO2 can later be re-released and concentrated by steam-treating the amines in a regenerator. Base case costs are $40-50/ton to absorb the CO2 (model here). Energy costs range from 2.5-3.7GJ/ton. Energy penalties are 15-45% (note here). But a possible operational show-stopper is the emissions of amines and toxic degradation products (note here), with MEA breaking down at 1.75 kg/ton into a nasty soup (data here). Avoiding amine degradation is crucial and usually requires treatment of exhaust gases, to remove dusts, SO2, NOXs, a post-wash and limits on the ramp rates of power plants. This all adds costs.

Leading amines for CCS, which have been de-risked by use in multiple world-scale projects are MHI KS-1/KS-21 and Shell CANSOLV. We have also screened novel amines developed by Aker Carbon Capture (JustCatch), Advantage Energy (Entropy) and Carbon Clean. And alternatives to amines such as potassium carbonates. In our view, this space holds exciting potential, although decision-makers should consider the correct baselines, hidden costs and technology risks.

Blue hydrogen is an alternative to post-combustion CCS, directly converting the methane molecule (CH4) into relatively pure streams of H2, as an energy carrier or feedstock, and CO2 as a waste product for disposal. The two gases are separated via swing adsorption. The technology is mature, there are no issues with toxic emissions, and the world already produces 110MTpa of grey hydrogen, including 10MTpa in the US (data here), mostly via SMRs, emitting 9 tons of CO2 per ton of H2. 60% of the CO2 from an SMR is highly concentrated, and can readily be captured. An adapted design, ATR, can capture over 90% of the CO2 and is also technically mature (note here). Our economic model for blue hydrogen is here. An ATR technology leader is Topsoe.

Blue materials. The US seems to be leading in CCS, over 500MTpa of projects could proceed in the next decade (note here), and 45Q reforms under the Inflation Reduction Act are already kickstarting a boom in blue value chains, from blue ammonia, to blue steel, to blue chemicals. This exciting theme is gathering momentum at a fast pace and could even disrupt global gas balances and LNG exports (note here).

Novel combustion technologies are also maturing rapidly, which may facilitate CCS without amines. NET Power has developed a breakthrough power generation technology, combusting natural gas and pure oxygen in an atmosphere of pure CO2. Thus the combustion products are a pure mix of CO2 and H2O. The CO2 can easily be sequestered, yielding CO2 intensity of 0.04-0.08 kg/kWh, 98-99% below the current US power grid. Costs are 6-8c/kWh (note here, model here). We have also explored similar concepts ranging from chemical looping combustion to molten carbonate fuel cells and solid oxide fuel cells.

Transporting CO2 usually costs $4/ton/100km in a pipeline (model here). But CO2 is a strange gas to compress (note here). CO2 pipelines run above 100-bar, where CO2 becomes super-critical and behaves more like a liquid (e.g., it can be pumped). CO2 can also be liquefied 80% more easily than other gases, for a cost of $15/ton, merely by pressurizing it above 5.2-bar then chilling to -40C (model here). This opens up the possibility of trucking small-scale CO2 for c$17/ton per 100-miles (note here, model here). Similarly, seaborne transport of CO2 costs $8/ton/1,000-miles (model here), and this also opens up a possibility for the LNG industry to ship LNG out, CO2 back (note here). Ships could also capture their own CO2 with onboard CCS for $100/ton (note here).

CO2 disposal requires injecting CO2 into disposal wells at 60-120 bar of pressure. Our base case cost is $20/ton, but can vary from $5-50/ton (model here) and there can be risks (data here). CO2-EOR can re-coup costs of sequestration with an oil price around $50/bbl (note here, model here) and in the past we had hoped this would also drive a subsequent wave of low-carbon production via shale-EOR (note here).

CO2 utilization aims to make valuable use of the CO2 molecules rather than simply pumping them into the ground. Enhancing the concentration of CO2 in greenhouses can improve agricultural yields by c30% (note here). Some chemical pathways use CO2 directly, making methanol, formaldehyde and polyurethanes. The CO2 molecule can also be electrolysed to produce other feedstocks, but costs are c$800/ton (model here). CO2 utilization for curing cement industry is being explored by Solidia and CarbonCure. Other CO2 utilization companies are screened here. The challenge in all of these niches is scaling up to absorb GTpa-scale CO2 within MTpa-scale supply chains.

Direct air capture is a frontier for CCS that aims to absorb CO2, not from an exhaust gas with 4-40% concentration, but from the atmosphere, with 0.04% concentration. On the one hand, this is obviously more thermodynamically demanding, as dictated by the entropy of mixing, but on the other hand, the minimum theoretical energy for DAC is only 140kWh/ton, and the world has simply not invented a process yet that is more than 5-10% thermodynamically efficient. We have modeled solutions from Carbon Engineering at c$300/ton and from Climeworks at c$1,000/ton. Our DAC cost model is here.

Membranes. Next-generation membranes could separate 95% of the CO2 in a flue gas, into 95% pure permeate, for a cost of $20/ton and an energy penalty below 10%, which exceeds the best amines (note here). But today’s costs are higher, especially for pipeline grade CO2 at 99% purity (model here). A CCS membrane leader is MTR (screened here).

Metal organic frameworks are a novel class of materials with high porosity and exceptional tunability, which could become a CCS game-changer, but cannot yet be de-risked (note here). We have screened companies such as Svante in our work.

Cryogenics. The costs to separate the 20% oxygen fraction from air in a cryogenic air separation unit average $100/ton using 300kWh/ton of electricity (model here). If you have a concentrated CO2 stream (e.g., 10-40%) then cryogenics may be an option.

Some summary charts, workings and data-points from our carbon capture and storage research are aggregated in this data-file. All of our broader CCS research is summarized on our CCS category pages.

CCS absorbers: unit sizing and residence times?

CCS absorbers

Post-combustion CCS plants flow CO2 into an absorber unit, where it will react with a solvent, usually a cocktail of amines. This data-file quantifies operating parameters for CCS absorbers, such as their sizes, residency times, inlet temperatures, structural packings and the implications for retro-fitting CCS at pre-existing power plants.

Post-combustion CCS aims to capture the CO2 from pre-existing industrial facilities and power plants, by flowing exhaust gases upwards through an absorber unit, while a solvent simultaneously flows downwards and reacts with the CO2. Costs, energy penalties and leading solvent candidates are covered in our CCS research.

But how hard is it to find space for these absorber units at pre-existing industrial facilities? This data-file has compiled key parameters from various technical papers, most aiming for 90% capture rates.

Across a dozen CCS examples in the data-file, each m/s of inlet gas requires 7 m3 of absorber capacity. Hence the absorber units for a world-scale 500MW power plant can reach 3,000 – 10,000 m3 of volume, usually across 2-4 absorbers with 10-15m diameters and 15-25m heights.

For the ultimate space requirements of the CCS plant, multiply by 2-5x, for the desorbers, utilities, piping and balance of plant.

This model calculates the size of the absorber unit required, as a function of height, diameter, residency time, CO2 inlet concentration, CO2 capture rate, solvent properties and structural packing.

Generally larger absorber units are required at industrial facilities with higher CO2 inlet concentrations and lower target CO2 levels.

For example, removing 90% of the 4%-concentrated CO2 from our base case natural gas burner requires a 12m absorber. Absorbing 90% of the 12%-concentrated CO2 from a coal boiler requires a 20m absorber.

CCS absorbers
Larger absorber units are required for CCS plants that start with more CO2 and absorb more CO2

The average residency time within a CCS absorber is below 10-seconds. Although the number depends on the unit size, flow velocity, amine quality and temperature. These can all be flexed in the data-file.

CCS absorbers
Residence time for a CCS absorber is usually below 10 seconds. Hotter inlet gas and solvent allows for shorter residence times.

Smaller and less expensive absorbers are possible with faster-acting amines, shorter residency times and greater structural packing.

A listed mid-cap company based in Switzerland was often mentioned in technical papers, with a product range of packing materials that can achieve 200-1,200 m2/m3 of internal surface area to promote gas-liquid exchange and slim-line CCS absorbers.

Hot potassium carbonate CCS: energy economics?

Potassium carbonate CCS

Hot potassium carbonate is a post-combustion CCS technology that bypasses the degradation issues of amines, and can help to decarbonize power, BECCS and cement plants. We think costs are around $100/ton and energy penalties are 30-50%. Potassium carbonate CCS can be stress-tested in this data-file, across 50 inputs.

Potassium carbonate (K2CO3) is a safe, abundant and low-cost salt that can absorb CO2, as soluble CO3(2-) ion reacts with H2O and CO2 to form 2 x HCO3(-) ions. The rich solution can then be steam-treated to re-release pure CO2, forming a CCS process.

Potassium carbonate has been used at over 600 hundred natural gas sweetening plants historically, removing small quantities of acid gases from pressurized gas streams (e.g., in the range of 20-bar) (aka the Benfield Process).

The great advantage of potassium carbonate CCS over the amine process is that there are no toxic breakdown products. This may be particularly helpful when the combustion source is burning waste, biomass/BECCS or cement plants.

The disadvantage of potassium carbonate CCS is that the reaction between CO2 and K2CO3 is slow. For more context see our overview of CCS absorber units. Thus realistic plant designs require higher temperatures (80-100ºC) and pressures (12-20 bar). This can create large energy penalties for potassium carbonate CCS, quantified herein.

What energy penalties for K2CO3 CCS? If there is only 4-12% CO2 in the exhaust gas of a boiler or burner, then compressing the entire exhaust stream towards the middle of this range can use up 65-90% of the useful energy released by combusting the fuel.

The best option to lower the energy penalties is to re-capture the energy of exhaust gas compression. This is achieved by re-expanding these compressed and CO2-depleted gases back across a turbine (which may directly drive the input compressors; for more background, please see our overview of thermodynamics and CCS energy penalties).

Potassium carbonate CCS
Energy penalties for CCS using hot potassium carbonate in percent kg per kWh and GJ per ton of CO2

Capsol Technologies (formerly known as Sargas) is listed in Norway and has filed patents for variations of this process running back to 2003 (tabulated in the data-file). It is currently developing what could be “Europe’s first large-scale negative emissions plant” capturing the CO2 from a bio-energy plant in Stockholm.

What energy economics for Capsol Technologies’ process? We have read some of Capsol’s patents, its claims of pressure recapture and steam-recirculation, and can simplistically model how this would impact costs and energy penalties (quantified in the data-file in $/ton, in % energy penalty terms, in kWh/ton or GJ/ton, and in kg/kWh CO2 intensities).

Others have looked to reduce the requisite pressurization energy for potassium carbonate CCS by blending K2CO3 with amines (often piperazine). But this seems to defeat the rationale for using potassium carbonate in the first place, which was to avoid emissions of amines or their toxic breakdown products.

Another interesting option could be exhaust gas recirculation, to boost CO2 concentrations and lower compression loads. In some configurations oxygen blending can further lower the volumes of gases that need to be compressed and cover the energy costs of oxygen generation in an air separation plant.

This data-file allows you to stress-test the energy penalties for potassium carbonate CCS in percentage terms, in kWh/ton, GJ/ton and to compute the resultant CO2 intensity of generated electricity in kg/kWh.

Origen Carbon: DAC breakthrough?

Origen DAC technology

Origen Carbon Solutions is developing a novel DAC technology, producing CaO sorbent via the oxy-fuelled calcining of limestone with no net CO2 emissions. It is similar to the NET Power cycle, but adapted for a limestone kiln. The concept is very interesting. Our base case costs are $200-300/ton of CO2. This data-file contains our Origen DAC technology review.

Origen Carbon Solutions was spun-out from the University of Oxford in 2013, now has around c50 employees and is privately owned, with recent capital from HBM Holdings, Elemental Exelerator and Frontier (i.e., Stripe, Google, Meta).

The ZerCal process, being piloted by Origen in 2023, aims to decompose limestone (CaCO3) using an oxy-fired flash calcining process which emits no net CO2. The CaO can then be used as a DAC sorbent, reacting with atmospheric CO2 to form CaCO3 solids.

A key challenge in post-combustion CCS is the need to separate CO2 (4-40% concentration) from air (mostly nitrogen). Amines can do this, but the process is costly, energy intensive and amines can be degraded by contaminants.

Oxy-combustion is an alternative approach that avoids introducing air/nitrogen into the combustion process, instead re-circulating exhaust gases, and then adding pure oxygen from an air separation unit or swing adsorption plant.

Hence the post-combustion reaction products are limited to CO2 and water (i.e., there is no nitrogen). CO2 and H2O can easily be separated. In the power sector, a similar approach is famously being taken by NET Power to produce very low-carbon gas power.

Oxy-combustion in limestone kilns is covered in Origen’s patents (schematic below). Note that this is different from other DAC designs. It is not an L-DAC design, nor an S-DAC design, nor an E-DAC design, but an oxy-fired combustion design.

Origen DAC technology
Schematic for oxy-fuelled calcining DAC

DAC costs of $200-300/ton may be achievable based on simple, back-of-the-envelope calculations, using Origen’s patent disclosures. Please download the data-file to stress-test capex costs, gas prices, oxygen costs, limestone costs, and other opex.

Possible DAC costs from oxy-fuelled calcination of limestone

CaO is an interesting DAC sorbent because it will slowly react with ambient CO2 without having to incur the high energy costs of fans and blowers. It could work well in petroleum basins with stranded gas that might otherwise be flared.

Another advantage that is cited in the patents is that the oxygen plant and excess heat from the oxy-fuelled calcining reaction can demand shift to help backstop (increasingly volatile) power grids (i.e., a ‘smooth operator‘), including amidst the build out of renewables.

Another particularly interesting patent adapts the process to oil shale that contains over c20% organic material and over c30% carbonate. It is noted that oxy-fired combustion of this low-grade resource could generate heat and electricity, its own CO2 could be captured directly from the plant, while the ‘waste product’ of CaO could be used as a DAC sorbent (see row 8 of the Patents tab for some mind-blowing numbers!).

Our Origen DAC technology review draws out details from these disclosures, excitement over the concept, and key question marks that remain for de-risking commercialization.

DAC to the future?

Direct air capture

A new wave of DAC companies has been emerging rapidly since 2019, targeting 50-90% lower costs and energy penalties than incumbent S-DAC and L-DAC, potentially reaching $100/ton and 500kWh/ton in the 2030s. Five opportunities excite us and warrant partial de-risking in this 19-page report. Could DAC even beat batteries and hydrogen in smoothing renewable-heavy grids?

Verdox: DAC technology breakthrough?

Verdox DAC technology

This data-file reviews Verdox DAC technology, optimizing polyanthraquinones and polynaphthoquinones, then depositing them on porous carbon nanotube scaffolds, using similar methods to lithium ion batteries. These quinones are shown to selectively adsorb CO2 when a voltage is applied, then desorb them when a reverse voltage is applied, unlocking 70% lower energy penalties than incumbent L-DAC and S-DAC?

Verdox is a spin-out from MIT, founded in 2019, which raised $80M in February-2022, to develop an electro-chemical DAC system. In February-2022, Aluminium-producer, Hydro, also invested a further $20M in Verdox (as the off-gas from aluminium smelters has 1% CO2).

Electrochemical DAC allows gas to flow through an electrochemical cell with low resistance, adsorbs CO2 by applying a voltage, then later releases the CO2 by applying a reverse voltage. Our recent DAC review sees potential in this approach, including via a rising number of next-generation DAC companies.

The Verdox patents that we reviewed used quinones, mostly naphthoquinones, anthraquinones (images below) and polymers of these quinones such as polyanthraquinones (cited in press articles) as electrochemically active sorbents.

When a voltage is applied, quinones can reduce (gain one electron per C=O group). The reduced naphthoquinones can selectively react with CO2.

Different R-groups in positions (*1 through *8 of the images below) and different additives on the carbon scaffold alter the electron donating properties of the naphthoquinones to C=O groups, and in turn, alter the tendency to adsorb and desorb CO2.

Verdox DAC technology
Naphtoquinones reaction with CO2
Verdox DAC technology
Antrhraquinones reaction with CO2

Carbon scaffold. In a functioning electrochemical DAC system, polyanthraquinones and polynaphthoquinones will be deposited on scaffolds of porous carbon nanotubes. The patents contain excellent details. Interestingly, the manufacturing process is quite similar to today’s battery cathode manufacturing. And some of the patents specifically name-check Huntsman’s MIRALON nano-carbon as an input.

Please download the data-file for our conclusions into Verdox DAC technology, how much we can de-risk from the patents, and other specific details (performance, cost, other cell materials, likely manufacturing details).

DAC companies: direct air capture screen?

DAC companies

Leading direct air capture companies (DAC companies) are assessed in this data-file, aggregating company disclosures, project disclosures and other data from patents and technical papers. The landscape is evolving particularly rapidly, trebling in the past half-decade, especially towards novel DAC solutions.

Most of the DAC companies in this data-file are private, with an average of c65 employees, and focuses ranging across L-DAC, S-DAC, CO2 mineralizations, project development and novel electrochemical approaches. The data-file covers each company, its approach, headquarters, employee count, capital raising and recent news that stood out to us.

Half a decade ago, the DAC company landscape was dominated by well-known leaders, such as Carbon Engineering, Climeworks and Global Thermostat (all founded in 2009-2010).

However in the past half-decade, the size of the space has trebled, with a clear focus upon next-generation DAC designs (or as we call it, ‘DAC to the future‘) which could confer materially lower energy intensities and financial costs, using advanced sorbents, passive DAC, mineralization and electrochemical systems. Many are at the pilot stage.

DAC companies
Emergence of DAC companies over time

Large projects are compiled in the projects tab, ranging from Climeworks’ 4kTpa Orca demonstration plant that started up in 2021 using geothermal energy in Iceland; through to the first 1MTpa-scale projects being progressed by 1PointFive, the consortium between Occidental and Carbon Engineering. The largest proposed project we have seen is 5MTpa.

Modularity is also a growing topic amongst emerging DAC companies, which may not build MTpa-scale plants but tens of thousands of 10-1,000 Tpa modules, which will be cheaper to manufacture and can integrate with other facilities.

Electrochemical DAC excites us most and we will undertake TSE patent reviews into some of these companies in due course.

Fans and blowers: costs and energy consumption?

Fans and blowers

Fans and blowers comprise a $7bn pa market, moving low-pressure gases through industrial and commercial facilities. Typical costs might run at $0.025/ton of air flow to earn a return on $200/kW equipment costs and 0.3kWh/ton of energy consumption. 3,000 tons of air flow may be required per ton of CO2 in a direct air capture (DAC) plant.

Fans and blowers comprise a $7bn pa global market, moving large volumes of air for industrial and commercial purposes, at pressure closer to atmospheric pressure (up to 1.11x pressurization for a fan, up to 1.2x pressurization for a blower).

A good rule of thumb is that moving 1 ton of air through an industrial facility ‘costs’ 2.5 cents, using 0.3 kWh/ton of electricity and in order to re-coup a return on a $200/kW investment (as aggregated from equipment providers, chart below).

Fans and blowers
Capex costs of fans and blowers decline for larger and lower pressure units and a good average is $200 per kW

However, these numbers can all vary, rising considerably when there is more resistance in the system, and fans/blowers must work to overcome larger total pressure drops. The simple energy economics are that power consumption (in Watts, aka Joules per second) is a product of air flow (in m3/second) x the total pressure increase imparted to the air (in Pa, aka J/m3). In turn, the dynamic pressure rise is a square function of flow velocity.

Fans and blowers
Energy costs of fans and blowers in kWh per ton decay with wider flow volumes and rise linearly with static and dynamic pressure loads

The economic costs and energy costs of blowers and fans might sound small, but note that a direct air capture (DAC) plant will need to move something like 3,000 tons of air per ton of CO2 that is captured, which could cost $75/ton and 300-900kWh/ton of electricity just circulating air through the plant.

As a comparison, compressors typically step up gas pressures from 2-100x depending on the application, with costs around $850/kW in a $140bn pa global market today.

Underlying data into the capex, energy consumption and volumetric flow rates are tabulated in the tabs overleaf, simply aggregating public disclosures across companies supplying fans and blowers.

MHI CCS technology: performance, costs and emissions?

MHI has deployed an amine-based CO2 capture technology, in 15 plants globally, going back to 1999. Reboiler duties are around 2.6 GJ/ton on a 10% CO2 feed. Capture rates and capture purity are high. Degradation and amine emissions are controlled, and c80-90% below MEA. CCS costs and complexities remain high. In our view, this is the true baseline for future next-generation amines to beat. This data-file aggregates notes and datapoints into MHI CCS technology.

KM-CDR is the Kansai Mitsubishi Carbon Dioxide Recovery Process, honed over three decades, by Mitsubishi Heavy Industries, from solvents through to entire CCS plants.

This data file aggregates useful reference data-points for decision-makers who care about parameters like CCS economics, energy penalties, amine degradation and technology risks.

Development timeline of MHI CCS technology? R&D into KM-CDR began in 1990, a 2Tpd pilot started in 1991 at Nanko power station, Japan; and the KM-CDR process was effectively developed by 1994, with the first commercial facility starting up in 1999. Details in the data-file.

MHI’s CCS technology has since been deployed in fifteen facilities globally, with almost 4MTpa of CCS capacity, of which over half are smaller facilities purifying CO2 for urea production, and the largest is the 1.4MTpa Petra Nova CCS project, which was the largest coal+CCS project in the world when it started up in 2016.

Is MHI’s CDR process ready for true CCS? The ‘success’ of Petra Nova remains somewhat controversial. The project started up on time and on budget, captured over 3.5MT of CO2 from 2017-19 and disclosed a CO2 capture rate of 92.4% when operating, piping away 99% pure CO2, for use in EOR at Hilcorp’s West Ranch Oil field. On the other hand, in its first three years of operation, “It suffered outages on 265 full days and 107 partial days, mostly in its first two years of operation” largely linked to CO2 pipeline availability, and was shut down for economic reasons in 2020. More details in the data-file.

The solvent for MHI’s CCS technology is KS-1, and more recently KS-21, a sterically hindered amine, supplemented by additives and promoters.

From reviewing technical papers, our best guess is that regeneration energy is 2.6 GJ/ton (40% below MEA), assuming a feed of 10% CO2 concentration, as is typical at a coal plant (more data here). Details on each study are in the data-file.

Average regeneration energy for MHI's KS-1 solvent is estimated at 2.6 GJ/ton

Degradation and amine emissions to the air of the MHI solvent are also discussed in the data-file, but in summary, we think they are 80-90% lower than MEA, especially when CO2 capture plants are fitted with all the usual bells and whistles to remove particulates, NOx and SO2 from exhaust gases upstream of the CO2 absorber unit, then the exhaust from the absorber is cleaned up with multi-stage washing (chart below).

Costs remain quite high in our view, and are likely well above the $50/ton in our economic model of a simple amine capture plant. This is mainly due to capex costs. Although MHI has been refining its CCS process, with smaller units, more modularity and improved solvents. Details are discussed in the Notes tab of the data-file.

What are the right baseline metrics for CCS solvents? Many CCS projects that have crossed our screen have seriously considered using MHI’s CCS process, and it is often the front-runner solution. This is because it is a fully engineered solution, with a track record, has been deployed at scale, has decent energy penalties and acceptably low degradation and emissions to air. Arguably, Shell’s CANSOLV is in a similar position.

Hence in our view, it is somewhat misleading when a new CCS technology advertises its performance ‘relative to MEA‘, which has notoriously high degradation rates and an regeneration energy requirement of 3.5-3.7 GJ/ton.

It is like claiming to have developed an automotive technology, which is a breakthrough when compared to the Ford Model T; or a portable electronics technology, which is a breakthrough when compared to the original 2007 Apple iPhone.

We would strongly advise developers of novel amines to publicly disclose their base case solvent regeneration energy (in GJ/ton of CO2), their base case degradation rates (in kg/ton of CO2, alongside exhaust gas purity parameters) and their expected amine emissions rates (in ppm of exhaust gas, with or without a water wash unit).

Further details on MHI’s CCS technology are explored in the data-file, a good baseline against which to compare other amine solvents and reactor designs. All of our CCS research is available here for TSE clients.

Entropy CCS: natural gas CCS breakthrough?

Entropy CCS technology

Advantage Energy is a Montney gas and oil producer, which recently sourced a $300M investment from Brookfield to scale up its Entropy23 amine blend for natural-gas CCS. Entropy CCS technology has captured 90-93% of the CO2 at the first pilot plant at Glacier, Alberta, with 2.4 GJ/ton reboiler duty, which is 40% below MEA. This 7-page report summarizes Entropy patent details, confirming a moat around the technology, but three key points for de-risking.

Two challenges for post-combustion CCS have recently been in focus in our research. The first one is energy penalties of CCS (note here, data here). And the second one is amine degradation and possible release of toxic breakdown products to the atmosphere (note here).

One solution is to scrub the gas extensively before it reaches a CCS plant, including with a SO2 scrubber, SCR denox loop and electrostatic precipitator, which all add cost. Another solution is to prioritize relatively pure input streams and stable CCS solvents. For example we have recently looked at Aker’s JustCatch and Shell’s CANSOLV.

Advantage Energy, listed on TSX, has also been gaining attention in CCS markets, as it claims to have developed a solvent with low reboiler duty, low degradation rates. The Entropy CCS solvent has been tested at multi-kTpa scale at the Glacier gas plant in Alberta, and Brookfield has agreed to invest $300M in its scale-up (page 3).

We reviewed a highly detailed, 58-page patent from Entropy Inc in 2023, covering 25 different solvents that were tested in the lab, and scored the technology on our usual patent assessment framework.

Based on our Entropy CCS technology review, we can confidently guess what the solvent blend is (i.e., specific components, chart below), how and why it works, how degradation has been tested in the past, and whether there is a moat around the technology (pages 4-6).

Remaining challenges: what residual areas to de-risk for Entropy CCS technology? We outline three constructive findings, which decision-makers may wish to consider and explore. They are noted on page 7.

Copyright: Thunder Said Energy, 2019-2023.