Carbon capture and storage: What can we learn from the project track record?

Background

To prevent atmospheric concentrations of CO₂ reaching levels that would cause dangerous global warming, there is broad scientific consensus that the geological storage of CO₂ will play a significant role. Greenhouse gas mitigation pathways developed by the International Panel on Climate Change (IPCC) and the International Energy Agency (IEA) require on the order of several billion tonnes of CO₂ to be stored annually by 2050.¹ Technologies known as carbon capture and storage (CCS) encompass the processes by which CO₂ is separated from emissions sources, transported, and injected deep below the earth’s surface for permanent storage. 

The fundamental technologies that comprise carbon capture and storage have been available for decades:    

• Capture – The first patents for CO₂ separation or ‘carbon capture’ were issued in the 1930s. By the 1960s, industries could choose from diverse commercial capture processes.²   
• Capture – At least 160 million tonnes of CO₂ are captured every year for use in industries such as food, drink, and fertilisers.³ 
• Transport – Over 8,500 kilometres of pipelines carry CO₂ in the United States. Over the last 50 years, they have transported over 500 million tons of CO₂.⁴  
• Storage – Injecting CO₂ deep underground is well understood. Over 20 million tonnes of CO₂ have been injected into dedicated geological storage sites for climate purposes in Norway since 1996. In the U.S., over 850 million metric tons have been injected safely since the 1970s for a process known as enhanced oil recovery.⁵   

However, combining these technologies to combat climate change is relatively new and can be more costly. The commercial production of CO₂ has historically focused on higher purity emissions sources from which the CO₂ can be more easily separated. But to combat climate change, carbon capture must be applied to a more diverse set of industries with few alternatives to decarbonise – such as cement, steel, and petrochemicals – where the cost of CO₂ capture is often much higher. Although CO₂ has long been stored geologically as a side effect of increasing profitable oil production, climate-oriented projects will increasingly have to store CO₂ in deep saline aquifers: essentially a waste disposal activity which only adds cost. In many cases, CO₂ transportation will also become more costly and complex, as industrial emission sources far from underground storage are required to send CO₂ to distant injection sites. 

41 commercial carbon capture and storage projects are identified by the Global CCS Institute (GCCSI) as operating today; these are large-scale facilities that both capture and store the CO₂ produced by industrial facilities or fossil power plants.⁶ However, most of them were not developed for climate purposes and are not required to operate in a way that minimises CO₂ emissions to the atmosphere or maximises the CO₂ they store. Many are purely commercial endeavours, where readily available by-product CO₂ could be sold to oil field operators for use in the oil production process known as enhanced oil recovery (EOR). Some have been developed to test new capture technologies, signal a corporate decarbonisation strategy, or achieve some degree of CO₂ reduction, but very few are incentivised or required to maximise their climate benefit. 

At the same time, many of the component technologies that will be required for the wider application of carbon capture and storage are operating successfully and at large scale as part of facilities which do not make the GCCSI’s list. The separation of CO₂ during the production of natural gas and fertiliser is commonplace, with hundreds of facilities operating worldwide. Even the capture of CO₂ from more challenging sources such as coal and gas combustion has been widely used for the production of CO₂ for its commercial use.⁷ Around 80% of the CO₂ used for EOR is not captured from industrial processes, but ‘mined’ from natural CO₂ reservoirs.⁵  

The 41 commercial projects therefore represent merely a snapshot of places where commercial or political incentives have led these existing technologies to align. 

Figure 1. a) Billion tonnes (Gt) of CO₂ stored annually in 2050 across the 95 IPCC scenarios that are compatible with 1.5°C of global warming with limited temperature ‘overshoot’

Figure 1. b) The scale-up of CO₂ storage in the International Energy Agency’s ‘Net Zero by 2050’ scenario^8,9 

Analysis of global decarbonisation pathways suggest we will need to capture and store billions of tonnes of CO₂ annually to limit warming to 1.5°C – this will undoubtedly present new technical, economic, and political challenges (Figure 1). In many cases it will require these existing technologies to be used at much greater scales, capture greater proportions of CO_2, or be applied to different gas compositions, which will bring engineering challenges and carry greater costs. CO₂ will be geologically stored in new locations which may not always respond exactly as predicted. Scientists and engineers in these fields are confident that any technical challenges can and must be overcome, and there is already ample evidence of such improvements being made as experience grows. 

The economic challenge has been the much greater barrier for more recent efforts to deploy CCS for climate benefit. Unlike most of the 41 projects identified by the GCCSI, it is purely a pollution control technology when used in this way. Like other pollution control technologies, it will only be implemented if there is a regulatory requirement or financial incentive to do so. In the case of carbon capture and storage, this could be a high price on carbon emissions. It is no surprise that those few projects that are driven by such regulatory measures have consistently maximised the CO₂ they store¹⁰, and more such projects will be developed as climate policy becomes more focused on achieving net zero. Despite gaining political interest as a climate technology in the 2000s, carbon capture and storage has not been adequately supported, leading to many projects being cancelled due to simple economics – no one will capture and store CO₂ for nothing. 

Carbon capture and storage project case studies

Natural gas processing 

The majority of projects classified as commercial CCS projects operating today involve the separation of CO₂ from natural gas (methane). This CO₂ is not man-made, but is found mixed in with the methane within the subterranean porous rocks that constitute natural gas reservoirs. Natural gas can contain a wide range of concentrations of CO₂ – up to 80% for some reservoirs – which typically needs to be lowered to below 3% or lower before the natural gas can be sold for consumption.¹² Technologies to separate CO₂ from natural gas were first developed in the 1930s and are now standard industrial practice (see Box 1).¹³ These technologies that have long been used for CO₂ separation from natural gas also form the basis of many of the CO₂ capture technologies which are now being more widely applied to other man-made sources of CO₂. 

Although separating CO₂ from natural gas is widespread, the CO₂ is usually simply vented to the atmosphere. Some facilities located close to suitable oil fields have obtained value from the CO₂ by-product by using it for EOR. These projects are often classified as early CCS projects, but they are driven by commercial rather than climate incentives. Since 1996, some natural gas processing plants have been driven by climate regulations to simply store the CO₂ they produce – without using it for oil production. Some others have still caried out EOR but sought to maximise the CO₂ stored for climate benefit. 

The Sleipner CCS project 

Description: The Sleipner CCS project is an offshore natural gas production platform located in the Norwegian North Sea. The gas extracted from the Sleipner West gas field contains around 4-9.5% CO₂, which must be reduced to a maximum of 2.5% to meet commercial requirements. The separation and geological storage of this excess CO₂ has been carried out since the start of gas production from the Sleipner West field in 1996, generally injecting up to 1 million tonnes of CO₂ per year. The project is operated by the oil and gas company Equinor (originally Statoil).^14,15 

CO₂ capture: The CO₂ is separated from the natural gas (methane) using a commercial process based on CO₂-binding chemicals known as amines. The process uses the amine monodiethylamine (MDEA) first developed by the oil company Elf (now TotalEnergies). 

CO₂ storage: The captured CO₂ is stored in a saline aquifer formation known as the Utsira sandstone, 800-1000 metres beneath the seabed.⁸ 

Motivation: In 1991, Norway introduced a carbon tax on offshore oil and gas activity, starting at a rate of $51 per tonne of CO₂ emitted and reaching $70 per tonne in 2023.¹⁶ This meant that it made financial sense for Sleipner to store the CO₂ it was already obliged to separate, rather than vent it to the atmosphere. Sleipner can be considered the first project globally to have implemented CCS purely for reasons of CO₂ abatement. 

Cost and financing: The total capital cost for the project has been estimated at $300 million.¹⁷ Operating costs are estimated at $0.75 million per year.¹⁸ 

Technical performance: The project has operated continuously since 1996, storing over 19 million tonnes of CO₂ by the end of 2022.¹⁹ Although the design capacity is 1 million tonnes per year, it has averaged 0.8 million tonnes per year for the first 20 years due to lower natural gas production – this has fallen still lower in recent years as production has declined.²⁰  

In 2013, a news article in Nature suggested that the discovery of fractures in the seabed could lead to leakages from the storage site.²¹ The fracture was emitting small volumes of water and dissolved gases. However, it was demonstrated that the fracture had been identified before CO₂ injection and the traces of gas emitted were natural methane leaks, with no CO₂ from Sleipner.²² The CO₂ store remains intact. 

Key takeaways: As the first large-scale example of geological CO₂ storage in Europe, the Sleipner project became a key reference for the technical and regulatory development of CO₂ storage in the region. It was used as a guide for the EU’s ‘Directive on geological storage of CO₂’, which is the regulatory basis for how all EU states (as well as the UK, Norway, Switzerland) ensure CO₂ is stored safely and permanently. The project has operated successfully since 1996, as well as demonstrating several important techniques for detailed monitoring of the stored CO₂, including time-lapse seismic imaging and pressure monitoring. This allows the underground ‘plume’ of spreading CO₂ to be monitored in high resolution (Figure 3). 

Figure 3. Seismic imaging of CO₂ storage Sleipner, showing the location and scale of the spreading CO₂ ‘plume’ in 2001.²³ 

The Snøhvit CCS project 

Description: The Snøhvit CCS project is associated with the Melkøya plant in the far north of Norway, which produces liquified natural gas (LNG) that can be exported by ship. Natural gas is produced from the Snøhvit gas field offshore and transported in a pipeline to the Melkøya plant onshore. The gas contains about 5-8% CO₂ which needs to be removed to very low levels (a few parts per million) to meet the more demanding requirements of LNG. The separated CO₂ is transported back offshore by a 153-km pipeline for injection into a deep geological storage formation. Gas production began in August 2007 and CO₂ storage in April 2008. It can store up to 700,000 tonnes of CO₂ per year.²⁴ 

CO₂ capture: The CO₂ is separated out using BASF’s ‘OASE White’ solvent, of which the main ingredient is MDEA. 

CO₂ storage: The CO₂ is injected into saline aquifers around 2.5 km below the seabed. It was originally stored in the Tubåen Formation from 2008 to 2011, before switching to the Stø Formation in 2011.  

Cost and financing: No data is available on the project cost. 

Motivation: Like Sleipner, Norway’s CO₂ tax created an economic incentive to store the CO₂. However, the project also seems to have been conceived as a technological showcase, with the aim of demonstrating that oil and gas reserves in the region could be exploited in Norway’s far north in a more environmentally sound way, and helping develop CCS at a time of growing interest in the technology by Norway and the companies involved. The Norwegian authorities made CCS a requirement of the development proceeding. 

Technical performance: By the end of 2021, the project had stored almost 7 million tonnes of CO₂.²⁵ The change in storage sites after three years of operation was necessary because a gradual rise in pressure was observed, indicating that the CO₂ could not spread to as much of the available space as first thought. This was resolved by injecting the CO₂ into a different formation since 2011, which has responded better. Annual CO₂ injection does not always reach the design capacity due to halts in production at the LNG plant. Most notably, a fire in 2020 led to the plant closing until 2022. CO₂ is only vented from the plant in exceptional circumstances, and requires an application for a permit.²⁶ 

Key takeaways: Snøhvit is a successful example of carbon capture and storage for the purpose of CO₂ abatement. The early change in storage site demonstrates how future projects may have to be flexible to uncertainties in geology, and that alternative storage options can and should be planned for. The project is also notable for including transportation of CO₂ from an onshore facility to an offshore injection site, which is the model used by Norway’s ‘Northern Lights’ CCS project (currently under construction). 

Shute Creek 

Description: The Shute Creek Treating Facility in Wyoming was constructed in the early 1980s to process natural gas from ExxonMobil’s LaBarge field, which contains around 65% CO₂ (giving it the lowest methane percentage in a commercial field at the time). The plant separates out CO₂, helium and hydrogen sulphide from the gas. From 1986, up to 4.3 million tonnes per year of a pure CO₂ stream generated by the plant were sold for use in EOR. In 2010, this maximum capacity was increased to 7 million tonnes per year. From 2005, around 0.4 million tonnes per year of CO₂ have also been reinjected into the original gas field as part of a waste stream which mostly consists of hydrogen sulphide. ExxonMobil state that the combined 7.4 million tonnes amount to over 75% of the CO₂ from the LaBarge field – the rest is vented to the atmosphere.²⁷ 

CO₂ capture:  CO₂ and hydrogen sulphide are removed from the natural gas using the commercial Selexol^TM process, first developed in the 1970s and widely used for natural gas processing and similar applications. The process produces around 9.6 million cubic metres of CO₂ per day in high purity streams (more than 95%), but a proportion of the gas is vented as part of more dilute waste streams. The plant’s capacity to sell the high purity CO₂ for EOR is dictated by its capacity to compress CO₂ to pipeline pressures – the compression capacity was expanded in 2010. 

CO₂ storage: Aside from the smaller acid gas waste stream stored in part of the LaBarge gas field, the plant’s CO₂ is sold to various EOR projects, in Rangely, Colorado and Balroil, Wyoming. 

Cost and financing: The 2.7 million tonne expansion in 2010 is reported to have cost $86 million.²⁸ 

Motivation: Potential income from CO₂ sales to oil producers is a bonus revenue stream for the facility, which generates large amounts of pure CO₂ as part of its normal operation. ExxonMobil apparently overestimated the demand for CO₂ for EOR in the area, with long term sales at only half the available volume until the late 2000s – ultimately due to low oil prices over this period, the remote location of the plant, and the lack of adequate CO₂ pipeline infrastructure. However, the Wyoming Oil and Gas Commission (a state regulator) put growing pressure on the facility to make more effort to market the CO₂ for EOR as a means of developing the state’s oil resource. In the late 2000s, higher oil prices led to new EOR projects and more CO₂ pipelines, allowing the expansion of the CO₂ compression capacity at Shute Creek. 

Technical performance: No reported issues, but transparent reporting is not required.

Key takeaways: The Shute Creek project has stored millions of tonnes of CO₂ which would otherwise have been released to the atmosphere. However, a significant portion of the CO₂ the plant captures is not stored, simply due to insufficient demand from local oil producers. In contrast to Norway, Wyoming has no regulations in place to prevent or disincentivise such releases.  

Gorgon CO₂ injection project 

Description: Chevron’s Gorgon CO₂ injection project takes CO₂ from a liquefied natural gas production facility in Western Australia. Chevron first commenced natural gas production at the offshore Gorgon gas field in 2016, producing a gas stream with an average of 14% CO₂ content.²⁹ This gas is processed at an onshore facility on Barrow Island, where the CO₂ must be removed in order for the methane to be liquefied for export by ship. The CCS part of the project started in 2019, and was designed to inject between 3.3 and 4 million tonnes per year of CO₂ into a dedicated storage site beneath Barrow Island.³⁰ 

CO₂ capture: The facility uses a commercial acid gas removal process for natural gas provided by BASF. 

CO₂ storage: The CO₂ is injected to depths of around 2.3 km into a deep saline reservoir known as the Dupuy formation, which consists of sandstone rock. 

Cost and financing: The CO₂ storage component of the project is reported to have cost AU$3.1 billion (USD$2 billion) to mid-2020, out of USD$54 billion for the entire gas production and processing facility.³¹ The project is a joint venture co-owned by Chevron (47.3%), Shell (25%), Exxon (25%) and three Japanese utilities (each with a stake below 2%).³² It received AU$60 million in funding from the Australian government’s Low Emissions Technology Demonstration Fund.  

Motivation: The Western Australian state government made CO₂ storage a requirement for the new gas production facility to proceed, imposing a condition of storing at least 80% of the CO₂ produced over every rolling five-year operating period. In 2021, this requirement was changed to 100% of the CO2 over successive five-year periods.³³ 

Technical performance: Storage of the separated CO₂ was originally meant to start at the same time as the gas production in 2016, but was delayed until August 2019. The delay was initially caused by final checks revealing that the system may allow water to condense in the CO₂ pipeline under some circumstances, which would cause corrosion. A water removal system was added prior to the CO₂ compressors, pushing back the start date. The facility reached its design injection capacity by February 2020, and stored 2.5 million tonnes by June 2020. However, it soon encountered problems with maintaining this rate of CO₂ injection. To prevent the pressure in the storage rock from increasing too much as CO₂ is injected, salty water (brine) has to be removed and re-injected into shallower rock formations. The sandstone formation targeted for CO₂ injection appears to have more unconsolidated (loosely bound) sand than expected, resulting in sand entering the brine stream and clogging up the wells where it is re-injected. Although equipment to remove these solids became operational in August 2021, Chevron concluded that it would not be possible to reach the design CO₂ injection rates without additional means of reducing the pressure in the storage reservoir. Another 2.26 million tonnes were stored in the financial year from June 2020 to June 2021, falling to 1.6 million tonnes in 2021/2022 and 1.71 million tonnes in 2022/23 as the issues with pressure in the reservoir persisted (Figure 4).³⁴ To enable the project to reach its design capacity, the company plans to add improved filtration systems to the existing water extraction wells, as well as drilling additional water extraction and injection wells.

Figure 4. Annual quantities of CO₂ removed from the natural gas produced at Gorgon and quantities injected for geological storage.³⁴ 

As of November 2023, Chevron reported having stored a total of 8.8 million tonnes since the project started. The first five years of operation of the natural gas plant – during most of which CO₂ storage had not yet started – led to a shortfall of 9.5 million tonnes of CO₂ against the regulatory requirement to store 80% of the CO₂ produced. To address this shortfall Chevron purchased 5.23 million tonnes of carbon offsets in 2022; these consist of Australian Carbon Credit Units (ACCUs) issued by the Australian government, Verified Emission Reductions (issued by the Gold Standard programme) and Verified Carbon Units (issued by the Verified Carbon Standard programme). These offsets are generated by projects such as renewable power, energy efficiency measures and ecosystem regeneration.³⁵ Chevron also invested AU$40 million in the Lower Carbon Grants Program – aimed at supporting local decarbonisation projects in Western Australia. Additional offsets will need to be purchased for the shortfall in the financial year 2023; however, from 2025 shortfalls will be addressed over fixed five-year periods. 

Key takeaways: The ongoing problems faced by the Gorgon CCS project highlight that geological storage sites can face unexpected technical challenges. Companies and governments planning to use CO₂ storage for decarbonisation should mitigate this risk by ensuring site characterisation is rigorously carried out and by developing contingency plans with several possible storage options – particularly for storage at this scale. The project’s use of greenhouse gas offsetting primarily through avoided emissions on voluntary carbon markets is a lower cost approach to mitigation which is unlikely to have as quantifiable a climate benefit as geological storage of the CO₂.³⁶ A more rigorous implementation of the regulatory requirement that Gorgon must use CCS as part of its ‘licence to operate’ would be to prevent the facility from producing additional geological CO₂ while the CO₂ storage is not functioning. Nevertheless, Gorgon represents an important step in improving our understanding of dedicated CO₂ storage technology at very large scales, and has prevented the emissions of nearly 9 million tonnes of CO₂. 

Hydrogen and ammonia production for petrochemicals and fertilisers

Other industries where the separation of CO₂ is already routinely carried out as part of the commercial process include fertiliser and petrochemicals; in both cases this CO₂ capture relates to the production of hydrogen. In a process called steam methane reforming, natural gas is first converted to a mixture of carbon monoxide and hydrogen known as ‘syngas’. The carbon monoxide is usually reacted with steam to produce CO₂ and more hydrogen. The useful hydrogen is then separated out using various processes, leaving CO₂ as a by-product.  

In fertiliser plants, the hydrogen is immediately converted to ammonia, which is the key precursor for most fertilisers. Many fertiliser plants react the hydrogen with some of the separated CO₂ to form urea (a form of nitrogen fertiliser), which re-releases the CO₂ when it is used in agriculture. Steam methane reforming is also an integral process in most oil refineries, where the hydrogen is used to remove sulphur and other impurities, as well as converting heavier oils to more valuable molecules. Together, these two industries each account for around half of the world’s hydrogen production – a process that collectively emits around 830 million tonnes of CO₂ each year.³⁸ 

How much additional purification is required for the CO₂ to be stored depends on the exact design of the hydrogen plant. In order to protect the catalysts used in ammonia synthesis, all ammonia plants already separate out the CO₂, so there are hundreds of examples of this ‘CO₂ capture’ process worldwide. These usually employ chemical solvents such as the MDEA process from BASF. Older steam methane reformers for oil refineries also used to selectively remove CO₂ in a similar way; however, modern units use a different process in which the discarded CO₂ stream still contains carbon monoxide, hydrogen, and other gases. These plants produce very pure hydrogen, but the CO₂ requires some further separation. This additional ‘CO₂ capture’ step is the target of the project case studies we see in industrial hydrogen production. 

However, the CO₂ from this ‘process stream’ represents only around 60% of the total emissions from the reformer, with another 40% associated with the combustion of fuel (usually natural gas or other hydrocarbon gases) to heat the process. Although it is more costly to capture this less-concentrated CO₂, there are many commercial fertiliser plants where capture from the combustion process is also carried out, usually in order to produce more CO₂ for urea synthesis. The largest of these capture 450 tonnes of CO₂ per day (~150,000 tonnes per year).³⁹  

Many new plans to equip hydrogen production with carbon capture have selected an alternative technology known as autothermal reforming, in which the CO₂ is produced in one stream and can be more easily separated in one process step. 

The Quest Carbon Capture and Storage project 

Description: The Quest project is an initiative led by Shell to capture and store at least 1 million tonnes of CO₂ per year from hydrogen production at the Scotford Upgrader plant in Alberta, Canada. The hydrogen is used for ‘upgrading’ of bitumen produced by Alberta’s oil sands operations; essentially converting heavier oils to lighter oils. Steam methane reformers are used to produce the hydrogen from natural gas, as well as from some of the waste gases produced by other processes at the plant. The reformers also produce a separate stream of CO₂ from the fuel combusted to provide heat, and the wider facility includes a gas-fired power plant to provide it with electricity and steam.^40,41 

Quest is designed to capture 80% of the CO₂ in the syngas produced by the three reformers, and the 1 million tonne target is based on the assumption they will run for 90% of the year. The project’s total design capacity of 1.2 million tonnes is based on continuous operation. The project started storing CO₂ in August 2015.  

CO₂ capture: The steam methane reformer produces syngas – a mix of carbon monoxide and hydrogen – which then undergoes a conversion to CO₂ and hydrogen. CO₂ is then removed from this gas using Shell’s ADIP-X process, which uses the monoethyldiamine (MDEA) solvent. This was an existing technology that had to be redesigned to meet the requirements of the plant. 

CO₂ storage: The CO₂ is transported around 64 km by pipeline and injected into a saline aquifer in the Basal Cambrian Sands, over 2 km below the surface. 

Cost and financing: Quest cost CA$790 million to build and has operating costs estimated at CA$30-35 million per year.⁴¹ It received CA$6.3 million from Alberta’s ‘Alberta Innovates’ fund and CA$745 from the province’s CCS Fund, of which 40% of goes towards the first ten years of operation. The project also received a grant of CA$120 million from the federal government towards pre-construction development (Natural Resources Canada).⁴⁰  

Motivation: The project was driven by the favourable funding environment created by the Alberta government and Shell’s strategic interest in developing CCS, as well as a specific interest in improving the greenhouse gas emissions of oil sand production, which is significantly worse than conventional production. In addition to the grant funding from the provincial and federal governments, Quest benefits from the generation of offset credits under Alberta’s ‘Technology Innovation and Emissions Reduction (TIER) Regulation’. Owing to its status as a ‘first of a kind’ project in the province, the project received two offset credits for every tonne of CO₂ avoided by carbon capture and storage, starting at a posted credit value of CA$15/tonne in 2015 and reaching CA$50 per tonne in 2022.⁴² This credit doubling was set to expire in 2025 or earlier if the project’s revenue ever exceeds its costs (this has reportedly occurred since the 2022 project summary). Following Canada’s federal ‘Greenhouse Gas Pollution Pricing Act’ in 2022, the value of credits in the TIER system must – at a minimum – follow a trajectory to CA$170/tonne of CO₂ in 2030, by increasing in CA$15 annual increments.⁴³ 

Technical performance: Performance data for Quest is made available in annual summary reports to the Alberta government. The facility has consistently captured and stored close to the 80% targeted, with an average capture rate of 79% over the period 2015-2021 for which data is available (Figure 5). Combined with consistent operation of the hydrogen unit, this has meant that the volume stored annually has usually been above the 1 million tonnes per year minimum target, except for in 2020 and 2022, when it fell to 0.94 and 0.97 million tonnes respectively. To calculate the net amount of CO₂ avoided by the project in each year, any emissions from powering the process itself are deducted, which average at 0.24 million tonnes per year. The annual reports also detail any technical issues that led to reduced capture rates, which typically include scheduled maintenance and various rapidly resolved equipment faults such as power trips or faulty valves. As of May 2024, Quest had stored 9 million tonnes of CO₂.⁴⁴ 

Figure 5. Quest CCS project performance over time⁴⁵ 

Key takeaways: Quest has implemented an existing CO₂ separation process at a larger scale than previously realised, and was also the third project globally to store CO₂ at large scale in a saline reservoir – solely for the purposes of emissions reduction. Overall, it has been a technical success, despite falling marginally short of its capture rate targets in some years. 

Air Products hydrogen production facility in Port Arthur 

Description: Industrial gas company Air Products operates two steam methane reformers in Valero’s Port Arthur oil refinery on Texas’s Gulf Coast. These supply over 200 million cubic feet per day of hydrogen to refineries in the wider area. Capture of at least 90% of the CO₂ from the first unit began in December 2012, and from the second unit in March 2013. Assuming continuous operation of the plant, approximately 1 million U.S. tons (0.925 metric tonnes) can be captured annually.^46,47 

CO₂ capture: CO₂ is separated from the reformer process stream using a proprietary Air Products process based on vacuum swing adsorption. The CO₂ is selectively absorbed onto a solid material, then a vacuum is applied to release pure CO₂. This relatively unusual process was used instead of solvents as it has no need for steam to drive the process, and was assessed to be lower cost. A similar concept was first used by Air Products at a hydrogen plant in Pennsylvania, to produce CO₂ for sale, where it has operated continuously since 1986. The CO₂ is also dried and compressed. 

CO₂ storage: A 21-km connector pipeline was constructed to take the CO₂ to an existing long-distance CO₂ pipeline on the Gulf Coast (Denbury’s ‘Green Pipeline’). The CO₂ is then transported up to 150 km and used for enhanced oil recovery in the West Hastings oil field. This field was subject to a monitoring and verification procedure to account for the quantity of CO₂ stored. 

Cost and financing: The total cost of the project was $431 million, with a U.S. Department of Energy grant contributing $284 million.⁴⁶ 

Motivation: The project was driven by the alignment of the DOE funding programme for industrial carbon capture and storage (under the American Recovery and Resilience Act) with Air Products’ strategic company goals. These included the opportunity to demonstrate the decarbonisation potential of the company’s growing industrial gas business, as well as the large-scale viability of their new CO₂ capture technology. 

Technical performance: The terms of the DOE grant required the project to operate for a demonstration period concluding in September 2017, when a final report was issued. This reported no major issues with the plant and plans to remain in operation ‘for at least the next few years’. As of 2024, the plant continues to operate. In May 2013, the plant conducted a ‘capacity test’ by demonstrating its maximum CO₂ capture capability over 24 hours. During this test it produced 4-5% more CO₂ than the design capture rate. In June 2016 the plant announced it had captured over 3 million tonnes of CO₂. However, it does not appear to routinely report the volumes it captures and store. The hydrogen plants are expected to run fairly continuously, but can occasionally turn down due to reduced hydrogen demand. 

To confirm permanent storage of the CO₂, the project was required to demonstrate adequate monitoring, verification and accounting activities to the Department of Energy. The steps normally taken by the enhanced oil recovery operator (Denbury Onshore) were considered sufficient, but were supplemented by additional monitoring work by the University of Texas at Austin and Dallas. 

Key takeaways: The project primarily demonstrated the use of the vacuum swing adsorption system for separation of large volumes of CO₂ from steam methane reformers. It met its performance requirements during the three-year demonstration period required by the U.S. DOE, but has made very little data publicly available since 2017, as it operates as a commercial provider of CO₂ to EOR.  

The Alberta Carbon Trunkline Project 

Description: The Alberta Carbon Trunkline in Canada is a 240 km-long CO₂ pipeline that carries CO₂ from a fertiliser plant (Nutrien Redwater) and a refinery (NWR Sturgeon) to a depleted oil reservoir for use in enhanced oil recovery. The project started operation in 2020, and can receive up to 1.3 million tonnes of CO₂ annually from NWR Sturgeon and up to around 0.2 million tonnes from Nutrien Redwater (increased to 0.3 million tonnes in 2023). Other sources of emissions are expected to connect to the pipeline in the future, which is able to accommodate up to 14.6 million tonnes per year. The project is a partnership between Enhance Energy, which owns and operates the oil field, Wolf Carbon Solutions, which owns and operates the pipeline, and NWR. 

CO₂ capture: The fertiliser plant produces a stream of CO₂ mixed with water, which is removed by dehydration equipment before the dry CO₂ is compressed and fed to the pipeline. The refinery uses the commercial Rectisol capture process to separate dry CO₂ from a syn gas mixture produced by the ‘gasification’ of heavy oils found in tar sands. Developed by Linde, the Rectisol process dissolves CO₂ in cold methanol and is widely used in the production of hydrogen, ammonia, methanol, carbon monoxide and other chemicals. 

CO₂ storage: CO₂ is shipped 240 km to Enhance Energy’s Clive Field, where it is injected into a depleted hydrocarbon reservoir approximately 2 km below the surface and utilized for enhanced oil recovery. The CO₂ is permanently stored, as any CO₂ returning to the surface with the oil is reinjected (known as a ‘closed loop’).  

Cost and financing: The full project cost approximately CA$1.2 billion. It received CA$63.2 million in a grant from the federal government (through Natural Resources Canada) and over the course of operations it will receive up to CA$495 million in funding from the Alberta government. The project also annually reports a total cost per tonne of CO₂ captured and stored (including all operational and capital costs), which was quoted as CA$102 per tonne in 2022.⁴⁸ Aside from the government grant, the economic viability of the project is supported by the revenues from hydrocarbon production from enhanced oil recovery and the generation of carbon credits under Alberta’s TIER regulation for large emitters.  

Motivation: Enhance and NWR teamed up in 2008 with the aim of giving multiple industries in the area access to CO₂ transport and storage infrastructure. The storage of industrial CO₂ in Alberta is incentivised by the generation of carbon credits under the province’s greenhouse gas compliance regulations, while emissions abatement at fuel production facilities is additionally incentivised by the federal government’s Clean Fuels Regulation.  

Technical Performance: The project provides annual summaries of operational performance and any issues encountered and annual quantities stored are also recorded by Enhance Energy and Alberta Carbon Registries.^48,49 Reporting from 2021 to 2022 shows that both CO₂ sources have sent slightly less than the maximum capacity each year, averaging a combined 1.15 million tonnes annually. However, this is due to the production processes at both sites experiencing more time offline, and therefore producing less CO₂ for capture. Over the first two full years of operation, the CO₂ capture equipment at the refinery has been available 97% of the time, while the CO₂ dehydration and compressor used at the fertiliser plant recorded over 99% availability. As of May 2024, Enhance Energy report having stored 5.1 Mt of CO₂ emissions since the start of the operations.⁵⁰ 

Key takeaways: The CO₂ capture technologies at the fertiliser plant and refinery are already widely used in their respective industries. The Alberta Carbon Trunkline primarily demonstrates that it is technically and commercially viable to build large-scale, shared pipelines for CO₂. The enhanced oil recovery operation is subject to an additional monitoring, measurement and verification programme to ensure that all the CO₂ is permanently stored.  

Bioethanol 

Bioethanol is typically made by fermenting types of biomass containing sugars or starch, such as cereal grains or sugar cane. The resulting ethanol can be used as an alternative to fossil-based transport fuels. Global bioethanol production is dominated by the U.S. (largely from corn) and Brazil (largely from sugarcane). The gas produced by bioethanol fermentation consists entirely of CO₂ and water, so ‘carbon capture’ at these sites requires only the addition of a water removal (dehydration) step and CO₂ compression. These processes are well-established technologies, but still represent an investment for the plant. There are also separate emissions associated with providing heat and power to the process and related production lines – often provided by fossil fuels. Given there are no ‘carbon tax’ penalties or restrictions on emitting non-fossil, biological CO₂, there has rarely been an incentive to avoid these emissions. However, direct incentives for CCS projects and low-carbon fuel production, are beginning to drive projects in this industry in the U.S., as well as growing interest in storing biological CO₂ as a form of ‘carbon dioxide removal’. 

Illinois Industrial Carbon Capture and Storage Project 

Description: Commissioned in 2017, the Illinois Industrial CCS project is designed to capture up to 1 million tonnes annually from bioethanol production at Archer Daniels Midland’s (ADM) Decatur plant. The project followed on from the smaller Illinois Basin Decatur Project, that captured 1000 tonnes of CO₂ per day from the same site, and ultimately stored one million tonnes of CO₂ over three years (2011-2014). The larger capture project was designed to add an additional capacity of 2000 tonnes per day from one set of ethanol fermenters. The Decatur site is a very large agricultural industry site, with several other emission sources including on-site fossil fuel power generation. 

CO₂ capture: Bioethanol fermentation at the plant produces a high purity CO₂ stream that contains less than 3% water. The CO₂ is dehydrated using a commercial tri-ethylene glycol absorption process and compressed to around 100 bar. 

CO₂ storage: The CO₂ is transported by pipeline for 1 mile and injected into the Mt Simon Sandstone formation, around 1.9 km below the surface.  

Cost and financing: The project cost $207 million and was supported by a DOE grant of $141 million. 

Motivation: The project was a public-private partnership between Archer Daniels Midland and the U.S. DOE, supported by funding from the American Recovery and Reinvestment Act (ARRA). It aimed to advance CO₂ storage research while also receiving a tax credit for CO₂ storage known as ‘45Q’. Introduced in 2008, the credit originally awarded $22 per ton of CO₂ stored in a saline aquifer (it was increased in 2018, and then again in 2022).  

Technical performance: Data from the Environmental Protection Agency (EPA) shows that the project has stored around 520 thousand tonnes annually, falling to 444 thousand tonnes in 2021 (Figure 6).⁵¹ The plant attributes this dip to reduced demand for ethanol as a result of the Covid pandemic, and preliminary 2023 data indicates a record injection level. According to ADM, the consistent operation at levels well below the stated design capacity for CO₂ storage (1 million tonnes per year) is generally associated with ethanol production below the plant’s maximum capability.⁵² However, the facility has also encountered some technical challenges that have had an impact on injection rates. Particularly when operating at lower ethanol production rates, too much ethanol or water can remain in the CO₂ stream, preventing it from being taken to compression and storage. It was also discovered that some lubricants in the compressor were entering the CO₂ and ultimately clogging parts of the injection well. This issue was resolved by a chemical cleaning of the injection well. Finally, there were minor equipment issues typical of chemical plants, including maintenance associated with freezing weather. 

Figure 6. Volumes of CO₂ injected annually at the Illinois Industrial CCS project⁵⁰ 

Key takeaways: The Decatur Project and the Illinois Industrial CCS project are the first projects to carry out the large-scale storage of CO₂ in a saline reservoir in the U.S., and among the first globally. Both projects have therefore provided valuable experience with dedicated CO₂ storage in these formations, including measurement, monitoring, and verification technologies.  CO₂ injection rates below the design rate are partly linked to lower-than-expected ethanol production, as well as technical issues encountered under certain operating conditions, which the project continues to address. The plant has a greater commercial incentive to optimise the functioning of its ethanol production process than to maximise the CO₂ it stores.    

Power generation 

Coal-fired power plants are some of the largest single sources of CO₂ in the world, and the sector as a whole emits nearly a quarter of global CO₂ emissions. Many researchers and governments therefore considered these facilities to be an early priority for the use of carbon capture and storage as a climate technology, and several large-scale projects were planned by power companies in Europe and North America in the late 2000s and early 2010s.  

Unlike the existing use of carbon capture in natural gas processing and petrochemicals, separating large quantities of CO₂ from power plant exhaust (known as flue gases) has no commercial purpose and was first seriously considered as an emissions mitigation option in the 1990s. Coal flue gas contains about 10-15% CO₂ and is at ambient pressure, so it takes more energy and larger equipment to separate the CO₂ than for natural gas or syngas. It also contains contaminants such as particulates and oxides of sulphur and nitrogen; in most regions, these already need to be largely removed to meet air quality standards, but many carbon capture processes can require the gas to undergo some further treatment.  

Despite these challenges, commercial processes for CO₂ capture from fossil fuel combustion predate interest in the technology for climate reasons. Demand for CO₂ from sectors, including the food and beverage industry, drove the development of many CO₂ capture plants on small-scale industrial combustion processes from the early 1980s, such as coal, gas and oil-fired boilers and furnaces, gas engines, and gas turbines.⁵³ These range in scale from around 100,000 to 500,000 tonnes of CO₂ per year, and separate CO₂ from gas mixtures of very similar composition to full-scale power plants. 

Using these existing CO₂ separation technologies or modified variants, many trials on coal power plant flue gas were carried out during the 1990s and 2000s, with the aim of eventually capturing CO₂ from a whole power generating unit – this would require capturing at least 1 million tonnes per year.⁵⁴  

As coal power plants have become subject to phase-out targets in Europe and Canada, and less economically competitive in the U.S., interest in some countries has shifted to gas power plants on the basis that they are likely to remain integral to the stable operation of the power grid. Gas power plant flue gas is more dilute in CO₂ than coal flue gas, at around 3-4%, but the technologies considered are very similar to those used for coal, and have also been tested or used commercially at smaller scales. The flue gas also has many fewer contaminants, but does contain higher levels of oxygen that can require removal. 

Interest in using carbon capture on coal power remains in the U.S., China, and India, where the large coal power fleets are expected to remain for several decades in some form (particularly in Asia). Several Chinese power companies have stated an ambition to equip a large coal power plant with carbon capture and storage in the next few years.⁵⁵  

Boundary Dam Carbon Capture Project 

Description: Boundary Dam is a coal-fired power plant in Saskatchewan, Canada, owned by the provincial utility SaskPower and currently comprises four separate generating units, all built in the 1970s.⁵⁶ Unit 3 was upgraded with a refurbished boiler and a new turbine, a process to remove sulfur oxides from the flue gas, and a carbon capture system designed to capture up to 90% of its emissions, or 3200 tonnes per day. The modernised unit has a net output of 150 MW, which is reduced to around 115 MW when the carbon capture is operating. Carbon capture and storage commenced in October 2014. 

CO₂ capture: The CO₂ is separated using an amine-based solvent developed by Shell Cansolv (a Canadian technology acquired by Shell in 2008). The chemical reacts with the flue gas CO₂ in a large absorber tower, and is regenerated to release CO₂ using steam extracted from the power plant. The process had first been tested at much smaller scales in the UK (50 tonnes of CO₂ per day) and South Africa (170 tonnes per day). 

CO₂ storage: Most of the CO₂ is sold for use in enhanced oil recovery at the Weyburn oil field and is transported there via a 70-km long pipeline. Any CO₂ that is not required by the oil field is stored in a deep saline reservoir (3.4 km below the surface) as part of a research project known as Aquistore.  

Cost and financing: The total cost of the project came to CA$1.47 billion. However, 30% of this cost was associated with the new boiler and turbine, roughly 20% on other emissions controls, and around 50% related to the carbon capture process. Unlike many coal plants, Boundary Dam did not have equipment to remove sulphur oxides from the flue gas (desulphurisation), which added to the total cost. The project received CA$240 million as a grant from the federal government. Expected income from the sale of CO₂ to EOR, as well as sulphuric acid and fly ash by-products were also integral to the business case. A ten-year contract for CO₂ offtake was agreed with oil field operator Cenovus in 2014 (now Whitecap Resources). 

Motivation: When the project was first conceived, a new federal regulation imposing a maximum carbon intensity on older power plants was anticipated, which was expected to make Saskatchewan’s coal power plants unviable in the long term. While also investing in wind power for the province, SaskPower required a long-term source of reliable back-up power, and regarded new gas power as economically risky, given its reliance on volatile gas prices.⁵⁷ The chosen alternative was to use CCS to decarbonise some of the existing coal units, which burn the low-cost, locally mined ‘lignite’ coal. The economic viability of this option was further boosted by the grant from the federal government and the income of CO₂ sales to the oil field operator. The anticipated regulation came into effect in 2015, requiring older power plants to emit no more than 420 tonnes of CO₂ per GWh generated – impossible for a coal plant without carbon capture. In 2018, this was extended to apply to all power plants, regardless of age, from 2030. In addition, a federal carbon price was imposed in 2019, reaching CA$80 in 2024 and intended to rise to CA$170 in 2030. 

Technical performance: As of May 2024, the Boundary Dam 3 CCS project has captured and stored over 6 million tonnes of CO₂, but has experienced several technical challenges since starting in 2014. Regular performance reporting provides insight into which factors are responsible for shortfalls (see Box 2) and how multiple issues have been successfully overcome (Figure 5).^58,59 Most of the problems during the first three years of operation were related to ash particulates from the power plant entering the system, leading to clogging and scaling of multiple pieces of equipment. This was a particular challenge at Boundary Dam due to the large quantity of fine ash produced by the local coal, and its use of relatively low-performance particulate removal systems. To deal with ash-related problems, SaskPower made modifications to the facility during shutdowns in 2015 and 2017, including installation of water spray systems to washout the unwanted particulates and additional ‘redundant’ equipment that allowed the plant to continue running while equipment is cleaned. Other issues addressed included cleaning of the solvent, which was degrading more than expected, and replacing a leaky solvent storage tank.  

Aside from the planned shutdown in 2017, the facility operated with relatively good reliability from 2016 to 2020, and reached 94% availability in 2020. However, the total CO₂ captured still averaged only around 60% during this period, primarily due to consistently less flue gas being sent to the capture plant than planned – less than 75% of the total gas flow in most years (Figure 7). This is generally a result of fouling and scaling of equipment limiting the amount of gas that can be drawn into the system and properly processed. While the early issues with ash contamination were mostly addressed, more recent problems relate to biological growth in the absorber, as well as solvent ‘foaming’. These problems are being addressed using chemical cleaning and ‘anti-foaming’ agents, and flue gas intake increased in 2022, but they have not been fully resolved.  

However, Figure 7 also highlights that the capture plant consistently captures around 90% of the CO₂ in the flue gas it receives; in other words, the chemical process is working as intended.  More detailed data shows the plant often captures well over 90% of the CO₂ it receives over a given hour, and has averaged over 95% in the past two years.⁵⁹

Figure 7. The performance of the CO₂ capture plant (CCP) at Boundary Dam 3 from 2016 to 2022⁵⁹

Major shutdowns occurred in 2021 and 2022 due to failures of the CO₂ compressor, which were attributed to manufacturing defects; these were resolved with replacement parts. More recent data shows that the capture plant has been operational 85% of the time in 2023, and over 92% in the first half of 2024.⁶⁰  The facility captured a record quantity of CO₂ over a 12-month period from July 2023 to June 2024 (882,273 tones), indicating that operational and design improvements are taking effect.⁶⁰

Shortfalls in CO₂ captured relative to the design maximum are also partly attributable to the plant operators choosing to run less CO₂ capture, either to maximise power output or because there is less demand from the oil field. The economic incentive to maximise CO₂ capture is becoming more significant as Canada’s carbon price increases. 

Key takeaways: Although the capture facility at Boundary Dam has experienced multiple technical challenges, they are typical of a first-ever demonstration of a new technology at full scale – particularly those involving chemical processes. There were some failings in the original plant design, particularly relating to inadequate flue gas cleaning and lack of equipment redundancy. The major issues faced by the project early on were all successfully addressed, and future plants will be better able to pre-empt these problems from the design stage. Rare failures of otherwise well-established commercial technologies – in particular, the CO₂ compressor – are of limited relevance to the general technical readiness of CO₂ capture technology, and should be more rapidly addressed as supply chains develop. As the power plant faces higher carbon prices, it is increasingly incentivised to adjust its output to a level that the capture plant is able to deal with – showing that, with the right policy tools, CO₂ capture technology is just one aspect of what’s needed to cut emissions. 

Petra Nova 

Description: Petra Nova is a carbon capture and storage project at NRG’s WA Parish coal and gas power plant in Texas – a large site including four coal-fired units built between 1977 and 1982. Carbon capture and storage was applied to around 40% of the flue gas emitted by the 615 MW Unit 8, usually expressed as ‘equivalent’ to a 240 MW plant, and amounting to a maximum of 1.4 million tonnes of CO₂ captured per year. The project began operating in 2017, but in September 2020 the capture plant stopped operating, citing the poor economics of oil production during the Covid-19 pandemic which harmed the business case centred on enhanced oil recovery. In 2023, JX Nippon purchased NRG’s 50% stake in the project, with the intention of using the facility to gain further technical experience with carbon capture. It was restarted in September 2023.⁶¹  

CO₂ capture: The CO₂ is captured using an amine-based solvent produced by Mitsubishi Heavy Industries. This process had previously been installed at 11 smaller commercial sites, mainly on the combustion flue gas produced by ammonia plants, as well as being tested on a coal plant from 2011.³⁹ The process is similar to the one used at Boundary Dam, but the flue gas required less additional cleaning, having already been treated for sulphur oxides. The steam used to regenerate the solvent is produced by a small, purpose-built gas-fired turbine.  

CO₂ storage: The capture CO₂ was sent to the West Ranch Oil Field for use in enhanced oil recovery.  

Cost and financing: The project cost $1 billion, of which $300 million was spent on work on the oil field and pipeline and $637 million on the capture plant site. It was a 50:50 joint venture between power company NRG and Japanese oil and gas company JX Nippon, which each contributed $300 million in equity.⁶² The project also received $167 million as a U.S. Department of Energy Grant for carbon capture and storage demonstration, with the remaining costs financed through loans from Japanese lenders aiming to support Japanese technology exports. 

Motivation: The early economic viability of Petra Nova was bolstered by the inclusion of the oil field operations within the project scope. Rather than selling CO₂ to a separate oil field operator, it directly receives income from the sale of the oil produced. However, this also made it more sensitive to the falling oil prices that led to its closure – it was conceived at a time when oil prices were around $100 per barrel. The project was also motivated by Japanese interest in promoting carbon capture technologies for export, and U.S. government interest in developing carbon capture and storage. 

Technical performance: As part of the DOE funding requirements, the project was required to submit a detailed report of its first three years of operation, from 2017 to 2019.⁶³ Over these three years, the project captured 83% of the planned volume of CO₂, but with a steady increase from 72% in 2017 to 95% in 2019 (Figure 8). Only a portion of this shortfall is attributable to issues with the capture plant, with other factors including issues at the oil field, the coal power plant, and the gas generator providing the steam. As at Boundary Dam, the CO2 capture process itself worked well when operating – removing 92.4% of the CO2 from the flue gas it received over the three years. The CO₂ capture shortfall was therefore due to equipment shutdowns, with the capture unit held responsible for 28% of these. Availability of the capture unit steadily improved over the three years, reaching 92% in 2019. Surprisingly, the gas plant used to power the process was responsible for a further 24% of outages, but these occurred mainly in the first year and were soon resolved with replacement parts.  

Outages at the capture plant were due to various issues including leaking heat exchangers and scaling of equipment caused by contaminants carried into the system. Unlike Boundary Dam, these contaminants were carried over from the limestone-based desulphurisation system used by WA Parish (and most coal power plants); this problem was partly mitigated by introducing a blocking wall in the flue gas ducting. The leaking heat exchangers were replaced in 2017 and parts of the CO₂ compressor – which also struggled with scaling by contaminants – were replaced in 2018. However, the replacement parts were not able to match the design performance under some operating conditions, such as in hot weather and when the power plant was operating at low output. The project’s report indicates that the budget did not allow for some major components to have back-up systems, which would have helped with reliability. 

Figure 8. CO₂ capture performance over Petra Nova’s first three years of operation.

Note: the planned CO₂ capture is lower in 2018 due to planned maintenance time on the capture unit.⁶³  

Key takeaways: The Petra Nova project provided vital experience with operating CO₂ capture from a power plant at a large scale, which has been used to optimise and adapt MHI’s technology for even larger scales and other applications. Partly based on the project learnings, MHI state that they have optimised the process to enable a 30% reduction in capital cost, mainly by using more compact, modular equipment.⁶⁴ As at Boundary Dam, downtime experienced by the project has mostly been related to the need to replace underperforming or poorly designed components, and performance noticeably improved as a result of modifications made over the course of the project. Again, preventing too many gas contaminants from entering the process seems to be a key challenge, but can also be addressed through equipment modifications and backup for key processes.  

Kemper County IGCC 

Description: Developed by power utility Southern Company, the Kemper County project in Mississippi was intended to be a new 582 MW power plant based on ‘integrated gasification combined cycle’ (IGCC) technology. Coal is first converted or ‘gasified’ to carbon monoxide and hydrogen, before most of the carbon monoxide is converted to CO₂ which is separated out for storage. The hydrogen and some remaining carbon monoxide is used to fuel a gas turbine and generate power. Following a costly construction delay of over three years, the plant started operating (without CO₂ capture) in 2016 but experienced technical problems with the coal gasification process.⁶⁵ As a result of the ongoing costs and falling U.S. gas prices, the State regulator ordered the coal-based process to be halted in 2017. Southern Company now run the turbines on natural gas, without carbon capture. If fully operational, the plant would have captured and stored up to 3 million tonnes of CO₂ annually. 

CO₂ capture: Separating CO₂ from gasified coal is easier than it is from normal power plant flue gas, as the CO₂ is at higher concentration and pressure. The commercial solvent ‘Selexol’ – which has been widely used for this application since the 1960s – was to be used at Kemper to separate 65% of the CO₂ in the gas stream. 

CO₂ storage: The CO₂ was to be sold to an oil field operator for use in enhanced oil recovery. 

Cost and financing: The project is reported to ultimately have cost up to $7.8 billion, although this includes elements external to the power plant, including creation of a new coal mine. Costs within the power plant project were reported as $5.2 billion. A breakdown of costs within the plant process is not publicly available, but the Selexol CO₂ capture process is estimated to cost around $80 million at this scale.⁶⁶ The project received a grant of $430 million from the U.S. Department of Energy for demonstrating carbon capture and storage. The cost overrun and delays have been partly attributed to construction on the plant starting before the design was completed.⁶⁷ 

Motivation: Southern Company wanted to exploit the significant cheap, local coal (lignite) resource in Mississippi, while demonstrating the new coal gasification technology they had developed. The ability to access the U.S. DOE funds for CCS demonstration was also a key enabling factor. 

Technical performance: First developed in the 1990s, IGCC power plants are a relatively well-understood but little-used form of power generation from coal, with only around 12 plants ever having been built (most of which have since been decommissioned). However, the coal gasification technology used at Kemper County was a new process developed by KBR and Southern Company, that had previously only been trialled at a much smaller scale. All the problems experienced during operation of the plant related to this process, rather than the Selexol CO₂ capture process, which is a well-established commercial technology for separating CO₂ from syngas. The capture process was tested over around 20 days and consistently achieved the 65% capture rate targeted.⁶⁵ However, the heat resistant lining of the coal gasifier was poorly installed and not suited to the wet coal that was eventually used, causing it to flake off. There were also leaks in the water tubes used to cool the gasifier. Nevertheless, Southern Company maintain that these issues had been resolved or were being resolved with replacement parts, citing the falling gas price as the main reason for the failure of the coal-based concept.   

Key takeaways: The project has little bearing on the development of CO₂ capture technology for applications where it is most likely to be used. The capture process worked as designed and problems with the plant were related to scaling up a relatively new coal gasification technology. Since Kemper, there has been a general decline in interest in IGCC as a coal power generation technology, although two large units were since commissioned in Japan and have operated successfully (without CO₂ capture). 

Bellingham 

Description: Bellingham is a 320 MW gas-fired power plant in Massachusetts. From 1991 to 2005, it operated a CO₂ capture process on a portion of the plant’s flue gases, equivalent to around 40 MW, and capturing 320-350 tonnes of CO₂ per day. The CO₂ was sold for use in the food industry.⁶⁸ 

CO₂ capture: The CO₂ was separated using Fluor’s Econamine FG Plus^SM, an amine-based solvent process. The process was developed for recovering CO₂ from flue gases by Dow Chemical in the early 1980s, and purchased by Fluor in 1989. 

CO₂ storage: The CO₂ was not stored, but used in the food industry and ultimately re-released to the atmosphere. 

Cost and financing: There is no data available on the cost of the CO₂ capture facility at Bellingham. 

Motivation: The project was motivated by the high demand for food-grade CO₂ in the 1990s. this later declined as natural gas prices increased in the early 2000s.  

Technical performance: Performance data is not available for this plant. 

Key takeaways: Bellingham remains the largest example of CO₂ capture operating on gas-fired power plant flue gases. As one of the earliest instances of large-scale CO₂ capture from combustion flue gases of any kind, it is regarded as having kickstarted the development of bespoke amine solvents for CO₂ capture for this application. While not conceived or operated for climate benefit, the project demonstrates that large-scale capture of CO₂ from this kind of source is technically possible, even in a commercial context. 

Steel 

New steel can be produced either from iron ore, or from the smelting of steel scrap. Although recycle rates are high (>85%), demand for new steel is such that the iron ore route (known as ‘primary steel’) still meets around 70% of global production. Around 90% of new steel production from iron ore uses coal-fired blast furnaces, which are very carbon intensive and have therefore been heavily researched as a target for carbon capture and storage. Another way of producing steel from iron ore is to make ‘direct reduced iron’ (DRI), which uses furnaces fired with natural gas and is therefore only used in a few countries with access to low-cost natural gas. DRI steel currently represents around 10% of global steel production.  

Carbon capture and storage has been trialled on blast furnace exhaust gases at the scale of around four thousand tonnes per year for research purposes, but has not yet been applied to a full-scale plant.  

Capturing CO₂ from DRI plants is more straight-forward, as the process is somewhat similar to methane reforming for hydrogen production. In fact, one of the two major DRI technologies available (Tenova’s Energiron) already incorporates CO₂ separation as a means of enhancing plant performance. There are several examples of these plants worldwide where the by-product CO₂ is sold to the food and beverage industry or other uses. The more widely used Midrex technology has also begun offering this option more recently.⁶⁹ As for steam methane reforming, there is another source of CO₂ emissions from the gas combustion used to heat the reactor. Tenova’s literature indicates that around 60% of the CO₂ emissions from the DRI can be avoided by the integrated CO₂ separation process. However, this represents a smaller fraction of total emissions from the overall steel-making process, of which around 50-70% can be from power generation. 

Al Reyadah Emirates Steel 

Description: The Emirates Steel plant in Abu Dhabi consists of two direct reduced iron (DRI) units constructed in 2007 and 2011, which produce around 4.2 million tonnes of steel annually. In 2016, ‘Al Reyadah’ or the Abu Dhabi Carbon Capture company was set up to develop and commercialise carbon capture and storage, identifying the steel plant as an ideal place to demonstrate the technologies. Storage of CO₂ from the steel plant commenced in November 2016, with the capacity to capture and store 800 thousand tonnes per year. 

CO₂ capture: CO₂ separation using monoethanolamine (MEA) was already an integral process in the HYL Energiron DRI technology used by the plant. The CO₂ is then dehydrated and compressed at the ‘Al Reyadah’ facility. 

CO₂ storage: The CO₂ is taken by Abu Dhabi National Oil Corporation (ADNOC) and transported 70 km for use in enhanced oil recovery. 

Cost and financing: Information on the project costs is not publicly available. The cost of CO₂ from the process has been estimated at $30/t; at this price, enhanced oil recovery is profitable, although still more expensive than conventional oil production in Abu Dhabi. 

Motivation: The project was a result of Abu Dhabi’s strategic goal of developing carbon capture and storage through the creation of Al Reyadah, while also developing an enhanced oil recovery as a route to boost oil production. EOR was first trialled at small scale in the emirate in 2009.  

Technical performance: The project does not make CO₂ capture and storage performance data publicly available. The plant can produce 4.2 million tonnes of steel per year, comprising two units producing 2 million tonnes of steel each, and one smaller 0.2 million tonne ‘micro-module’ (not treated with CCS). Tenova’s literature on the Energiron process suggests that direct emissions from each of the larger units should typically be around 770 thousand tonnes of CO₂, of which up to 60% (462 thousand tonnes) is treated by the CO₂ separation process.⁷⁰ This would suggest that the 400 thousand tonnes captured and stored by the Al Reyadah project represents capture of 87% from the processed gases. However, with no imperative to maximise the storage of CO₂ from the unit, it is likely that the process is optimised according to the requirements of the steel production facility and the CO₂ demand of the oil field. 

Key takeaways: The Al Reyadah project demonstrates the integration of several established CO₂ technologies. There are several other large Energiron plants already producing pure streams of CO₂, and the use of CO₂ in enhanced oil recovery is also well established, although had not previously been employed at such a scale in the United Arab Emirates. However, it represented a significant step for the Gulf region in gaining experience with CO₂ processing and transport, and raised the profile of the technology as an industrial decarbonisation option. 

Cement 

The cement industry is an important target for the application of carbon capture and storage technology, as it contributes around 7% of global CO₂ emissions and currently has no other options available for complete decarbonisation. Cement is made by heating natural minerals (limestone, clay, silica) in cement kilns to temperatures of up to 1450°C. Around a third to 40% of the CO₂ released by these plants comes from fossil fuel combustion to reach these high temperatures, but the majority is associated with the release of CO₂ from limestone (calcium carbonate). Switching to clean fuels would therefore only partially address the industry’s massive emissions problem. Despite the clear role for carbon capture and storage in decarbonising this sector, full-scale CO₂ capture from cement plants has not yet been demonstrated, but the first example is currently under construction at the Brevik cement plant in Norway. The Brevik project plans to capture around 50% of the flue gas from the cement kiln, amounting to 400,000 tonnes of CO₂ per year.⁷¹ This capture rate is determined by the availability of waste heat in the plant, which can be used to power the capture process and minimise the need for additional energy. 

Cement flue gas is generally higher in CO₂ concentration than coal power plant flue gases (at least 15%), but very similar technologies have been developed and tested for this application. There are now several other plans for full-scale carbon capture and storage on cement plants in Europe and North America, using a range of different technologies. 

Conclusions 

Building full-scale versions of climate technologies – sometimes known as ‘commercial projects’ – is a vital step towards more widespread adoption, and a step which most well-established technologies have had to go through, including offshore wind, nuclear, and air pollution controls for power plants. To be truly useful, new technologies need to become mundane, with standardised processes that can be mass fabricated and represent low-risk investments. At this point a technology is often referred to as ‘commercialised’, even though its commercial viability may depend entirely on environmental and climate policies and regulations. 

Carbon capture and storage is an umbrella term for a diverse range of techniques for handling CO₂ and permanently preventing it from reaching the atmosphere. Certain types of carbon capture and storage have already reached commercial status, but unsurprisingly only in applications where there is an economic value for the technology. As such, they mostly do not operate to maximise their benefit to the climate. On the other hand, applications where there is a climate imperative to develop carbon capture and storage technologies (cement, steel, petrochemicals, gas power, direct air capture) have often seen little or no testing at large scales. These applications rely on policy and/or regulations to make such trials financially viable.   

Examining the carbon capture and storage project track record therefore provides a mixed picture, with some well-established technologies operating for commercial gain and others designed to test the capabilities of new technologies at large scales. It is normal and even valuable for the true demonstration projects (such as Boundary Dam, Petra Nova, or Quest) to encounter technical issues and identify solutions. Fortunately, the issues encountered by these front-runners have been found to be surmountable – often requiring straight-forward practical fixes such as minor redesign of components, more rigorous cleaning of processed gas, or greater system redundancy to allow operation to continue while maintenance is carried out. The next iteration of each of these technologies should operate more efficiently, economically, and reliably, and the following iteration should perform still better. 

Ultimately, the climate science tells us that we need to make CO₂ capture and storage technologies work at very large scales – not just to cut emissions at the necessary speed, but for the inevitable task of removing CO₂ from the atmosphere. The successful projects we have today are sufficient to tell us that these technologies are able to meet this need. However, we also have a clearer idea that not every project attempted will work perfectly – some may face unexpected challenges, be poorly executed, or have weak incentives to perform. In the face of the climate imperative, the response to imperfect projects should be to redouble efforts to ensure that more projects are successful. This will require a combination of technical innovation and policies that ensure projects are designed and operated to maximise climate benefit. As such policies are now beginning to be implemented in several jurisdictions, including the U.S, Canada, and Europe, a new wave of large-scale CCS projects is emerging that can be expected to uphold a high standard of climate performance, and will be more usefully assessed in those terms.⁷² 

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