Carbon Markets

Carbon markets refer to the trade of carbon credits between parties and are either compliance or voluntary. By leveraging market forces, carbon markets enable least-cost pathways toward emissions reductions targets and incentivise investment in CCS infrastructure and networks. Carbon markets have grown considerably over recent years, and with such rapid growth, there is a current need for collective understanding of how CCS can work in current and future markets.


Compliance carbon markets (CCMs) are implemented and regulated by national or regional authorities. Compliance markets typically utilise cap-and-trade schemes, whereby the cap represents a limit of how many tonnes of CO2 can be emitted by the industries covered in the scheme. This leads to a specific number of tradeable carbon allowances given to each company over a fixed period of time, giving them the legal right to emit an equivalent amount of CO2. In principle, if a company reduces its emissions below the limit, unused allowances can be traded with other companies that require additional allowances.

The price of allowances is determined by the market, so emitters can choose the most cost-effective approach between purchasing allowances and investing in technologies to reduce their emissions. Over time, governments may reduce allowances given to emitters to meet more ambitious emissions targets. This increases the scarcity of allowances, thereby increasing their price. As the price of allowances increases, investing in technologies such as CCS becomes economically more viable for emitters.

Compliance markets, known as emissions trading systems (ETS), are increasing in number and distribution. Based on data from the International Carbon Action Partnership, an estimated 25 national and sub-national ETSs are in force, nine are in development and 14 are under consideration (1).

Currently, there are two large jurisdictions for compliance markets that include CCS protocols – the EU ETS and the California Low-Carbon Fuel Standard (2,3). Cap-and-trade systems in Tokyo and Quebec do not have CCS protocols, but since they operate in countries with CCS activity, CCS could potentially be included in the future (4,5). This was seen in California, which instituted a CCS protocol under the Low-Carbon Fuel Standard years after it launched its ETS (3). Similarly, the EU ETS adopted a CCS directive some years after it was launched.



Voluntary carbon markets (VCM) are created by private organisations and are self-regulated. VCMs underwent record growth last year, and the market could reach US$50–100 billion per year by 2030, driven by net-zero commitments from the private sector (6). VCMs enable investors, governments, non-government organisations and businesses to purchase carbon offsets, called verified emissions reductions (VERs), from project developers and other third parties. VERs are generated by projects that are assessed using greenhouse gas (GHG) reduction methodologies. Projects are then registered in a VCM registry, which tracks the generation of and trade in VERs. As organisations make increasingly ambitious climate pledges, many of them have few cost-effective options to reduce their emissions. Carbon offsets provide companies with a practical and scalable means through which they can achieve emissions reductions. In practice, a company’s carbon offset strategy operates in tandem with efforts to reduce emissions directly.


Figure 18: Worldwide Carbon Markets – Compliance and Voluntary (Source: World Bank 2022)




CCMs and VCMs use different standards and systems, meaning that project developers must satisfy the requirements of multiple methodologies for different systems. This diminishes the potential impact of carbon markets, increasing the cost of decarbonising the world’s economy. Article 6 of the Paris Agreement has the potential to overcome this challenge by increasing coordination between governments and the private sector to harmonise project methodologies. Specifically, Article 6 enables countries to trade with one another to achieve their nationally determined contributions (NDC). It has been estimated that US$250 billion per year in savings can be attained by 2030 as a result of Article 6, although this will be much determined by how well it functions (7). In July 2022, the supervisory body responsible for implementing the mechanism for trade under Article 6 was operationalised.

Precedents exist for some market linkages, such as between Switzerland’s ETS and the EU ETS, and between Quebec’s and California’s systems. Other types of overlaps found in markets today see emission allowances traded alongside carbon offsets. For example, California’s Cap-and-Trade Compliance Offsets Program allows entities covered by the cap to satisfy a percentage of their regulatory obligations through the trade of VERs under the Verra registry.[1]

The need to include CCS in Article 6 is underpinned by the fact that carbon dioxide removal (CDR) is vital to unlocking the ‘net’ in net-zero emissions and achieving the 1.5˚C goal of the Paris Agreement. The use of CCS networks can further streamline cost and resource efficiency, especially when planned on a regional or global level.



CCS plays a versatile role in supplying point-source capture and storage as well as CDR, while offering the capacity to store CO2 over longer and more permanent timeframes than other mitigation/removal options. While the price of a CCS carbon credit will be determined by underlying market supply and demand interactions, credits generated by CCS projects could attain higher values because geological storage of CO2 is much more secure than storage via nature based solutions (eg, storage in trees or soil). Prices of CCS-generated credits could also increase if market participants would be willing to pay a premium for innovative and novel solutions such as DACCS and BECCS, which currently have no methodologies in place. To further unlock and scale up CCS-related climate action in carbon markets, the CCS+[2] Initiative is working on delivering an integrated methodological framework for generating carbon credits for the full suite of CCS activities for the VCMs and Article 6 (8). The upcoming years will indeed be critical to establishing ways to direct investment and climate finance to CCS, with current thought leadership in academic and industry circles focusing on carbon sequestration/storage units (CSU) and carbon storage obligations (CSO)/carbon takeback obligations as a solution to enhancing the expected value resulting from permanent geological storage (9–11).




[1] Verra is one of the leading VCM registries with almost 1,600 registered projects.

[2] [The CCS+ Initiative includes the plus sign to indicate the use of CCS at point-source, CCUS and CDR in carbon markets.



  1. International Carbon Action Partnership. ICAP ETS map [Internet]. [cited 2022 Aug 4]. Available from:
  2. European Commission. Implementation of the CCS Directive [Internet]. Implementation of the CCS Directive. 2022 [cited 2022 Jun 21]. Available from:
  3. California Air Resources Board. Carbon Capture and Sequestration Protocol under the Low Carbon Fuel Standard. 2018.
  4. Bureau of Environment, Tokyo Metropolitan Government. Tokyo Cap-and-Trade Program [Internet]. Tokyo Cap-and-Trade Program. 2022 [cited 2022 Jun 15]. Available from:
  5. Gouvernement du Québec, Ministère de l’Environnement et de la Lutte contre les changements climatiques. The Carbon Market – a Green Economy Growth Tool! [Internet]. The Carbon Market – a Green Economy Growth Tool! 2022 [cited 2022 Jun 14]. Available from:
  6. The Oxford Institute for Energy Studies. The Evolution of Carbon Markets and their Role in Climate Mitigation and Sustainable Development. New Oxford Energy Forum . 2022 Jun;
  7. IETA. CLPC_A6 summary_highres no crops. 2019.
  8. CCS+ Initiative [Internet]. [cited 2022 Aug 12]. Available from:

Carbon removals

Carbon dioxide removal (CDR) technologies remove carbon dioxide from the atmosphere. The Intergovernmental Panel on Climate Change (IPCC) finds that all scenarios that limit warming to no more than 1.5˚C deploy CDR technologies. Further, most models are unable to find pathways that limit warming to 1.5˚C without CDR technologies (1).


Direct air carbon capture and storage (DACCS) removes CO2 directly from the atmosphere, while bioenergy with carbon capture and storage (BECCS) captures CO2 from bioenergy combustion. Because BECCS provides both CDR and usable energy, BECCS is typically a lower cost option than DACCS. BECCS, though, is limited by the sustainable biomass available for energy, approximately 131 EJ per year globally (2).

Recent economic modelling by the Global CCS Institute found that reaching net-zero (based on IPCC SSP1-1.9) is expected to require the maximum possible deployment of BECCS (3), which is determined by the availability of sustainable biomass. The deployment of DACCS however is determined by its future cost, which is uncertain.  To understand the potential role of DACCS in achieving net-zero, the Institute examined a range of possible DACCS costs from US$137 per tCO2 to US$412 per tCO2 (compared to the IPCC DACCS cost range of US$100–300 per tCO2). The Institute’s model provided results that are broadly consistent with the IPCC’s projections of DACCS & BECCS deployment.


Figure 19: Cumulative CDR through 2100 (GtCO2)[1] 


IPCC 226-842 109-539 333-1,221
Global CCS Institute 491-510 1.2-786 511-1,277


Staying within the remaining carbon budget through this century will be more difficult and costly without CDR. The scale of the energy transition to net-zero is staggering. Advanced fuels and their infrastructure must be developed, the electricity sector must decarbonise, and industry and transport must be transformed. CDR can buy time so that the rate of transformation is more manageable for the hardest-to-abate, highest-cost applications (3). CDR can also act as insurance if unexpected constraints arise in other decarbonisation pathways (3).



Another result from the Institute’s modelling is that the earliest DACCS would be deployed on an economic basis without any dedicated DACCS incentives is 2043, with the lowest-cost DACCS assumption (US$137 per tCO2), but not until 2062 with the highest-cost assumption (US$412 per tCO2). Figure 21 shows the economic breakeven point by year and cost of DACCS.


Figure 20: Breakeven costs for DACCS over time (assumes no DACCS-specific incentives)




The economic deployment of DACCS beyond the breakeven point depends on how low the cost of DACCS is and how early that breakeven occurs. Very little DACCS is deployed if the cost is higher than US$350 per tCO2. Significant levels of DACCS are economic between US$137 and US$223 per CO2 (16 GtCO2 and 8 GtCO2, respectively, by 2065). 


Figure 21: Quantities of CO2 stored from DACCS at different costs over time



Figure 22 shows how different DACCS cost assumptions affect other types of CCS, including BECCS, electricity fossil CCS, industry CCS, and hydrogen CCS. BECCS remains constant regardless of the cost of DACCS, as do, for the most part, industry and electricity CCS. The lower the cost of DACCS, the more it is cost-effective in offsetting emissions that would otherwise be decarbonised through a hydrogen pathway, which in turn reduces the need for both green and blue hydrogen and the CCS associated with blue hydrogen.


Figure 22: Cumulative CO2 stored from 2022 to 2065 by CCS type as the cost of DACCS changes





The primary driver for CDR is the pathway toward net-zero emissions by mid-century. All available BECCS is likely to be deployed because it offers CDR and energy. The lower the cost of DACCS, the more it will be deployed, the lower the price of CO2 that will result, and the lower the cost of the transition to net-zero. According to Institute’s modelling, the potential cost savings are huge. If the future cost of DACCS can be reduced to US$ 200 per tonne of CO2, the net present value of savings in the global energy system would be around US$1 trillion (3). If the future cost of DACCS can be reduced to US$137 per tonne of CO2, the net present value of savings in the global energy system would be around US$3 trillion. 

In an effort to drive DACCS technology toward commercialisation to reduce the overall costs of reaching net-zero, governments are implementing specific policies for DACCS. For example, the US Department of Energy announced in May that it would provide US$3.5 billion in funding to four direct air capture hubs over the next five years (4). DACCS also qualifies in the US for 45Q tax credits of US$180 per tCO2 stored (5). Canada recently announced an investment tax credit of 60 per cent for direct air capture equipment till 2030 and 30 per cent till 2040 (6).

An individual country is unlikely to invest in DACCS at a level needed for globally optimal benefits. Therefore, cooperation among countries is critical to ensuring that DACCS can reach levels that benefit all. This cooperation would fall within Article 6 of the Paris Agreement and the UNFCCC process. One possible approach would be for a group of like-minded countries to form a club and pool money to invest in DACCS projects to drive commercialisation (7).



[1] The model for the Institute’s analysis runs to the year 2065. The CDR results for 2065 were assumed to repeat for years 2061–2100 to arrive at an approximate value for the 21st century for comparison with the IPCC results.



Hydrogen produced with very low life cycle greenhouse gas emissions (clean hydrogen) has broad application in supporting the achievement of net-zero emissions.

Clean hydrogen can be combined with carbon to create synthetic fuels to replace conventional fossil fuels. It can be used in fuel cells to generate electricity and may be used as a feedstock for many chemical processes. Projections of future clean hydrogen demand exceed 500 Mtpa by 2050 compared to total hydrogen production today of approximately 120 Mtpa, including clean hydrogen production of only around 1 Mtpa[1] (1).

Potential suppliers of blue hydrogen, produced with fossil fuels and CCS, have responded by investing in new projects. As of September 2022, there were 40 hydrogen facilities with CCS in varying stages of development including seven in operation[2]. The production capacity of each of these facilities ranges from tens of thousands to hundreds of thousands of tonnes of hydrogen per year.

A large investment in hydrogen transport infrastructure will be required to deliver hydrogen to demand centres. The expected international trade in clean hydrogen will require a fleet of purpose-built ships together with loading and offloading terminals at ports. The Hydrogen Energy Supply Chain (HESC) pilot project has demonstrated the transport of liquid hydrogen from Victoria in Australia to Kobe in Japan. Port infrastructure was constructed at the Port of Hastings in Victoria and in Kobe, and a purpose-built ship, the Suiso Frontier, successfully unloaded the liquid hydrogen on 25 February 2022 (2).

Hydrogen has an extremely low boiling temperature of -253°C, which adds to the cost of cooling and transporting hydrogen by ship. Consequently, other options, such as the transport of hydrogen as ammonia (NH3), are also being pursued. There is already significant international shipping of ammonia across a network of 120 ports with appropriate facilities and using 120 ships that are capable of carrying semi-refrigerated ammonia as cargo (3).

Blue hydrogen project developers are predominantly from the petroleum and industrial chemical industries who currently produce hydrogen using conventional emissions-intense methods such as reformation of natural gas or gasification of coal without CCS. For these companies, moving from conventional hydrogen production to blue hydrogen production is evolutionary, not revolutionary, from a business perspective. Hydrogen production and the management of gases are their core competencies. Oil and gas producers also understand the behaviour of fluids (such as dense phase CO2) in the subsurface, and operating injection and production wells, and implementing subsurface monitoring programs are routine operations for them. Further, these industries have a strong strategic driver to shift their businesses to support the achievement of net-zero emissions. Production of blue hydrogen allows them to apply their existing knowledge and expertise to a new business opportunity, and in some cases, to use infrastructure and resources (for example, pipelines and platforms) that would otherwise become redundant. These industries are very well positioned to win a large share of any future clean hydrogen market due to the cost competitiveness of blue hydrogen compared to green hydrogen; the scale of their operations; existing competencies and resources, including financial resources; and strong strategic motivation.


Figure 23: Number of Hydrogen Production Facilities with CCS by Development Status[3]



Over time, newer technologies, such as Shell’s Gas Partial Oxidation process, will replace older technologies such as steam methane reformation. The current fleet of operating hydrogen production facilities with CCS – the oldest being 40 years old – are retrofits of CCS to existing hydrogen production facilities. They were not designed to achieve very high CO2 capture rates because there was no requirement or financial incentive to do so. Consequently, they only capture around 60 per cent of their scope one emissions. The next generation of blue hydrogen facilities is being designed from the ground up to achieve very high capture rates. Ninety-five per cent capture is becoming the default capture rate, with some facilities expected to approach 100 per cent capture. Ultimately, the market will demand hydrogen with very low life cycle emission intensity. Blue (and green) hydrogen production facilities will need to demonstrate they meet this high standard to access this market, and new facilities are being designed on that basis.

While production of blue hydrogen can ramp up relatively quickly, this is contingent on there being sufficient demand to justify the investment. The cost of clean hydrogen is a significant factor in creating demand. Hydrogen must compete with conventional fossil energy, which is relatively low cost and enjoys all the benefits of incumbency (for example, distribution infrastructure, supply chains, and mature utilisation technologies). Creating demand for clean hydrogen requires policy that creates value from the emission abatement it provides, as well as significant investment in hydrogen production, storage and distribution infrastructure. Governments have recognised this; the IEA reports that 15 national governments plus the European Union have adopted national hydrogen strategies, almost all with targets and funding (4). Nine of those national strategies, and the European Union strategy, include blue hydrogen.




[1] Includes hydrogen produced in synthesis gas

[2] Includes hydrogen produced in synthesis gas

[3] Includes hydrogen produced in synthesis gas



  1. Hydrogen Council. Hydrogen scaling up: A sustainable pathway for the global energy transition. 2017.
  2. HESC. Successful Completion of Pilot Project Report [Internet]. 2022 [cited 2022 Aug 5]. Available from:
  3. International Trade Rules for Hydrogen and its Carriers: Information and Issues for Consideration [Internet]. 2022 [cited 2022 Aug 5]. Available from:
  4. International Energy Agency. Global Hydrogen Review 2021 [Internet]. 2021 Nov. Available from:




The role of finance in supporting the more widespread deployment of CCS is critical. At the country level, several governments have again sought to prioritise the technology through the provision of a variety of targeted incentives and grants. In parallel, however, it is clear that far greater support from the private finance sector will be required to align investments with a net-zero pathway and provide more tangible assistance to enable widespread CCS deployment.

In line with the wider shift toward green lending and sustainable investing, increased focus has been placed on the role of green or sustainability-focused taxonomies. Taxonomies of this nature now provide guidance to investors as to which activities and investments may formally be classified as environmentally sustainable. In several jurisdictions, regulations and secondary guidance setting out the application and scope of these taxonomies is already in place, while work is underway in many other jurisdictions to develop further examples in the coming years. Efforts to harmonise approaches and adopt the use of common principles has been highlighted by many as an important approach toward a globally consistent approach.

Significantly, CCS has already been formally recognised as an economic activity within the EU’s taxonomy, with the subsequent delegated Act setting out technical screening criteria. While this approach has afforded the technology a pathway within the EU model, it will be critical to ensure that other schemes in development around the world also reflect this view and approach.

The examination of environmental social and governance (ESG) factors is increasingly a feature of wider financing and investment decisions. Recent years have seen ESG factors rise from the periphery to become an important aspect of corporate decision making. Climate-related issues have become synonymous with the “E” factor, occupying a significant space within the ESG landscape, and have resulted in increasingly detailed consideration by corporations, investors and the wider public.

While financial and litigation risks continue to motivate companies to focus on climate considerations in their reporting, a focus on mandatory reporting obligations is now expected to drive further climate-related disclosures in the future. Public and private sector net-zero commitments are also a key driver for closer scrutiny of ESG disclosures by shareholders and financiers. Investors are now keen to ensure that companies are aligning their activities with their net-zero commitments and as a result, are looking for companies to provide clear and consistent disclosure statements. The emergence of several net-zero disclosure frameworks, standards and protocols are indicative of the weight that is now afforded to this information.

Where CCS fits within the ESG reporting space, if at all, has been the subject of previous analysis undertaken by the Global CCS Institute. Although clearly not excluded, the quality and utility of information generated through current reporting methodologies may not meet the needs of either project proponents or end-users of this information.

The Institute’s recent analysis, however, has considered in greater detail how project proponents and investors may leverage the benefits of their CCS-related investments and project operations in the context of the wider reporting environment.[1] In accordance with the prevalent view that far greater consolidation and harmonisation of reporting schemes will be required, the Institute has proposed a methodology that aims to highlight how CCS-specific factors may be included within the parameters of existing, well-defined reporting pathways.

[1] An ESG Reporting Methodology to Support CCS-related Investment



[1] An ESG Reporting Methodology to Support CCS-related Investment




CCS is an essential pathway for key industrial applications. Industries such as cement, iron and steel, and chemicals all have characteristics that make them challenging for decarbonisation (the so-called “hard-to-abate” industries).

CCS is an essential pathway for key industrial applications. Industries such as cement, iron and steel, and chemicals all have characteristics that make them challenging for decarbonisation (the so-called “hard-to-abate” industries).

CO2 is an unavoidable chemical by-product of the calcination reaction that is at the heart of cement manufacturing. On top of this, cement is produced at temperatures well above 600˚C; temperatures typically produced by the combustion of fossil fuels. As such, even if biofuels or other low-carbon sources of heat are used in cement kilns, this CO2 will still need to be managed. This dual-sourcing, as well as the vast global demand for cement for construction, makes the cement industry highly CO2 emissions-intensive, accounting for around eight per cent of global anthropogenic greenhouse gas emissions (1).

The world’s first cement CCS project is under construction at the Norcem cement plant in Brevik, Norway. Part of the Langskip network, this project is intended to capture 400,000 tonnes per year of CO2 with an amine-based absorption capture plant. It is expected to be operational in 2024 and will liquefy CO2 for ship transport to the Naturgassparken CO2 facility for ultimate storage under the North Sea. Larger scale cement CCS projects are in early development by LafargeHolcim (US) and Hanson Cement (UK).

Cement is proving to be an active sector for new CO2 capture innovations. Technology company Calix is testing its novel calciner reactor in the LEILAC project in Belgium. This reactor is novel in that it keeps calcination CO2 (high purity) and the heat sources separate, with indirect heating through a tubular reactor wall. Effectively a form of inherent capture (CO2 is produced in a pure state), this approach offers a new pathway for the cement sector in the future, as well as the potential to exploit new heat sources such as renewable electricity, further decarbonising the process.

Many of the world’s cement kilns produce CO2 at much smaller scales than seen in natural gas processing plants or in thermal electricity generation. This scale impacts on CO2 capture cost, as capture cost per tonne typically rises with reduced scale of the CO2 source (2). As such, cement kilns can have higher capture costs than some other applications. This represents an opportunity for capture technology companies to bring their cost advantage to bear on this sector. Firms such as Carbon Clean and Svante are good examples of capture technology development that is ideally placed for medium-scale applications, such as in the cement sector.

The global iron and steel sector is also a major contributor to global CO2 emissions. During iron production from iron ore, carbon-based reductants (such as coal) react with oxygen in the ore to form CO2. There is one operational CCS plant in this sector, at the Emirates Steel facility in Abu Dhabi. This amine-based capture plant has a capacity of 800,000 tonnes per year of CO2, significantly reducing the emissions of its host Direct Reduced Iron facility.

Alternative, non-carbon-based ironmaking pathways are also in development, based on hydrogen as a reductant. These may form a basis for new iron and steelmaking facilities into the future. If successful, they could become another use for decarbonised hydrogen – including hydrogen produced from natural gas with CCS.

The global chemicals sector is another significant emitter of CO2 globally, especially ammonia and ammonia-derived fertilisers (such as ammonium nitrate). Ammonia is synthesised using a reaction of nitrogen and hydrogen. Almost all the hydrogen used in ammonia production today is produced from fossil fuels, primarily with steam-methane reforming. A shift to decarbonised hydrogen, including blue hydrogen in large utility-scale hydrogen plants, would enable deep decarbonisation of this essential sector.



  1. Ellis LD, Badel AF, Chiang ML, J-Y Park R, Chiang YM. Toward electrochemical synthesis of cement-An electrolyzer-based process for decarbonating CaCO 3 while producing useful gas streams. PNAS [Internet]. 2019 [cited 2022 Jul 22];117(23). Available from:
  2. Kearns D, Liu H, Consoli C. TECHNOLOGY READINESS AND COSTS OF CCS. 2021 Mar.



Evolution of storage

The rate of carbon dioxide storage, currently around 40 million tonnes per year must grow to billions of tonnes per year to meet climate targets. Historically, most carbon dioxide has been used for enhanced oil recovery (EOR). Whilst effectively all carbon dioxide injected for EOR is permanently trapped in the pore space that previously held the oil, the majority of future storage will not be associated with EOR.

The historic dominance of CO2 stored through EOR is understandable given the CCS industry was born out of EOR in the US. These facilities showed that million-tonne CO2 injection rates at multimillion-tonne storage sites were possible. Importantly, monitoring confirms that all the CO2 injected is ultimately stored. This monitoring has laid the foundation for CCS to become a critical climate change technology.

Today, deep saline formations are the most common type of CO2 storage reservoir across all storage facilities (over 150) at all stages of development from operational through to early development phases, and including completed facilities (Figure 25). CCS deployment is expanding with a greater diversity of geographies and storage targets. CO2 storage facilities targeting deep saline formations are most substantial in North America and the North Sea. Storage in depleted oil fields is also set to become more common, for example in the UK and in Australia and Southeast Asia.


Figure 24: Count of completed, current and future CO2 storage projects across storage types and geographies. Data derived from over 150 CCS facilities, including commercial and demonstration projects (over 100,000 tpa CO2) across all stages of development.    



The trend of storing CO2 via dedicated geological storage is evident in comparing the deployment pipeline of facilities coming online and those actively storing – deep saline formations dominate the portfolio of emerging facilities (Figure 25). A focus on deep saline formations rather than depleted fields is an interesting development. Historically, the expectation was that the low-cost, fast-to-develop depleted fields would be targeted first. But facilities are clearly targeting deep saline formations. This is evident in both North America and a lesser extent in Europe (Figure 24).

Two reasons emerge for this choice. First, CCS networks that dominate the development pipeline focus on deep saline formations; those networks have multimillion-tonne-per-annum injection rates. Second, the pipeline includes a substantial portion of facilities from the US and the North Sea (UK and Europe). Both these regions have access to volumetrically significant (over 1,000 Mt), high-quality deep saline formations as their nearest and therefore first option for storage.

There is clear evidence in comparing operational facilities today with the pipeline in the future, that there is a greater diversity of storage targets. Depleted fields are significant to future project development, mainly in the UK North Sea. In addition, the EOR pipeline is still growing, particularly in the US and Middle East.


Figure 25: Potential and current CO2 stored across storage types and deployment status. Data derived from over 150 CCS facilities, including commercial and demonstration projects (over 100,000 tpa CO2) across all stages of deployment 



Perhaps the most important trend in geological storage is that the average injection rate per project is increasing. Operational facilities, on average, inject just over 1 Mtpa CO2. That average could more than double within a decade as new larger projects commence operation. Storage projects associated with CCS networks in development generally have injection rates of around 5 Mtpa. Further, storage operators are now announcing 10 Mtpa CO2 rates or more (1). This growth in injection rate has emerged in the past two to three years.


Figure 26: The average injection rate (million tonnes per annum) of commercial CCS facilities in the deployment pipeline. Data derived from over 30 CCS facilities with dedicated geological storage, including commercial and demonstration projects (over 100,000 tpa CO2), across all stages of deployment.




The geological characteristics of dedicated storage resources (i.e. non EOR) vary widely. Facilities are targeting or actively injecting into thin reservoirs with low permeability, through to multi-Darcy (very high permeability – almost like sand on the beach) reservoirs hundreds of metres thick. The highest quality deep saline formation is not necessarily the best option, with operators needing to balance many factors. For example, injecting into a higher quality formation means the CO2 spreads further, increasing the monitoring area required.

Whilst the range of reservoir permeabilities and thicknesses that have been utilised for CO2 storage is quite broad, there appears to be a geological sweet spot at a permeability of around 300 millidarcies and a formation thickness of 100–200 metres. This combination may be described quantitatively by injectivity potential which is the mathematical product of reservoir permeability and thickness. Most projects inject between 1 and 10 Mtpa of CO2 into storage reservoirs with injectivity potential of between 10 and 100 Darcy-metres according to Hoffman et al. (2015) (2).


Figure 27: Injectivity of storage sites across the entire pipeline of facilities
Adapted and modified from Hoffman, N., George Carman, Mohammad Bagheri, Todd Goebel, & The CarbonNet Project. (2015). Site characterisation for carbon storage in the near shore Gippsland Basin.


The diversity of storage types, geological conditions, and injection rates will likely increase with the ongoing development of storage resources across new geographies and geological basins. Much like sectors adopting CCS for decarbonisation, the geological sites for storage are diversifying as more resources are developed.



  1. Santos. Globally significant carbon capture and storage project a step closer. 2022.
  2. Hoffman N, George Carman, Mohammad Bagheri, Todd Goebel, The CarbonNet Project. Site characterisation for carbon storage in the near shore Gippsland Basin. Melbourne; 2015.




As CCS networks have emerged as a key CCS deployment model, the development of shared transport and storage infrastructure has become a focus for project developers and policymakers.

Shared infrastructure includes all the capital equipment required to move CO2 from capture plants to its ultimate permanent storage site: pipelines; compression systems; ships; port facilities, such as CO2 liquefaction plants and temporary holding tanks; and ultimately storage installations where multiple CO2 sources can be injected into storage in shared wells.

Infrastructure projects enable better economics for the transport and storage of CO2. By taking advantage of economies of scale, shared pipelines enable long-distance transport at a much lower cost per tonne of CO2 than would be possible with dedicated, smaller capacity pipelines. Infrastructure also enables more rapid deployment of CCS at scale, by aggregating the parts of the life cycle (pipelines and storage) with longer timelines.

Infrastructure projects are under development by existing players in the oil and gas sector who have long histories of building pipeline projects and drilling wells. These projects fit well with the experience and core competencies of these companies.

In the US, ExxonMobil is leading the Houston Ship Channel CCS infrastructure project. Incorporating 14 companies operating emissions-intensive businesses in the Houston region, this world-scale network project will involve the development of shared CO2 pipelines in the Houston Ship Channel region. Companies such as Air Liquide, BASF and Shell have agreed to participate in the project (1). The use of shared infrastructure (pipelines and offshore storage wells in the Gulf of Mexico) will greatly improve the economics of CO2 transport and storage in the region.

In the UK, the East Coast Cluster is working to aggregate CO2 captured from a multitude of industrial and energy facilities. In addition to these onshore pipeline networks, supporting infrastructure in the form of offshore pipelines and offshore storage facilities is being developed under the Northern Endurance Partnership (2). This large-scale offshore storage project will become essential infrastructure for the entire Humber and Teesside industrial region, enabling up to 27 Mtpa of captured CO2 to be stored far more cost effectively than multiple, smaller storage projects.

In Europe, Equinor and Fluxys have announced plans for a world-scale CO2 subsea pipeline from Belgium to storage sites in the Norwegian North Sea (3). This 1,000 km long pipeline, with an anticipated capacity of 20–40 Mtpa, is intended to support the transport of captured CO2 from Belgium and surrounding countries as an open-access transport system. This would form an essential backbone of CO2 pipeline infrastructure across Northwestern Europe. In the Dutch North Sea, the Aramis project will provide open-access CO2 transport and storage services through an offshore pipeline to depleted gas fields.

As well as pipelines, shipping is emerging as an essential transport vector for CO2 – often when CO2 sources and storage sites are too far apart for pipelines. Ship-based CO2 transport relies on the refrigeration of CO2 to liquefy it, making it denser and enabling ships to transport larger tonnages for a given volume. Early ship designs, such as those used in the Langskip network in Norway, are dedicated carriers shuttling CO2 from particular individual CO2 capture facilities in Oslo and Brevik. As such, their 7,500 m3 CO2 volume is determined by logistics, with shipping distance and annual CO2 volume the key considerations (4). These early ships were adapted from existing LPG carrier designs. It is anticipated that future CO2 ships will likely be developed with larger capacities to facilitate longer open water shipping routes, using clean sheet designs.

In Iceland, CO2 storage company Carbfix is developing the Coda project (5). Leveraging the low-cost basalt storage available in Iceland, this CO2 terminal will enable CO2 to be shipped from across Northwestern and Western Europe. CO2 port infrastructure like Coda is expected to become a common feature of coastal CCS networks more generally. Ship-based CO2 movements increase the scale of CCS networks and will require CO2 loading facilities (at source ports) and unloading facilities (at receiving ports). A key advantage of port facilities is that CO2 transport routes can change over time (unlike pipelines), allowing ships to take CO2 to the lowest-cost storage facilities in a region.

As well as industrial players, governments play a key role in the incentivisation and development of CCS infrastructure. For example, the CarbonNet pipeline and storage project in Victoria, Australia has been an ongoing effort to develop a new storage sector for energy and industrial businesses in the state. Similarly, the Alberta Carbon Trunk Line (ACTL) project in Alberta, Canada has benefited from public support to kickstart the CCS sector in the region, building a world-scale pipeline connecting CO2 sources to storage resources 240 km away.

This support goes beyond technical work – it includes supportive regulations to enable a firm legal basis to undertake storage, guidance for pipeline route development, and government support for early-stage exploration to confirm storage resource quality. These are key roles for governments to help overcome some of the early barriers to infrastructure development.

The continued growth and scale-up of CCS to enable CCS to move to gigatonne scales globally, will depend on more pipelines, storage projects and shipping infrastructure over the coming decades.



  1. Proposed Houston CCS hub gains supermajor support | Upstream Online [Internet]. [cited 2022 Jul 22]. Available from:
  2. East Coast Cluster [Internet]. [cited 2022 Jul 22]. Available from:
  3. Ole Ketil Helgesen. Equinor and Fluxys unveil plans for CO2 pipeline from Belgium to Norwegian offshore CCS | Upstream Online [Internet]. Upstream Online. 2022 [cited 2022 Jul 22]. Available from:
  4. Northern Lights. What it takes to ship CO2 [Internet]. [cited 2022 Jul 22]. Available from:
  5. Carbfix. Carbfix signs agreement with Danish shipping company for the transfer of CO2 [Internet]. [cited 2022 Jul 22]. Available from:–danish-shipping-company-for-the-transfer-of-co2

Timelines for CCS project development

Building a new CCS facility or retrofitting CCS to an existing facility is a major industrial project requiring the full suite of studies, from concept through pre-feasibility and feasibility, before detailed engineering studies commence.

The complexities of identifying and negotiating commercial agreements with counterparties where required (for example, CO2 offtake agreements) and completing environmental impact assessment processes, as well as obtaining the necessary tenements and approvals for geological storage of CO2 from regulators, generally requires years to complete. This is assuming that appropriate legislation for the regulation of CCS has been promulgated; in most jurisdictions, this is still not the case. The development of a CCS project shares many similarities with mining and mineral processing and oil or gas production projects; a large complex CCS project may take a decade to progress from concept to operation.

The identification and appraisal of geological resources for the storage of CO2 is a costly and time-consuming process. It requires a desktop review of existing geological models covering the area in question, “imaging” of the subsurface using seismic techniques and complex data processing, and finally, the drilling of a well to collect core samples for analysis and to undertake small scale injection testing. These activities typically take a few years to complete and are subject to the availability of geoscientists with appropriate experience and the critical equipment required to collect data and drill wells. Storage appraisal is on the critical path for CCS deployment.

Figure 28 is a highly simplified Gantt chart for the development of a complex CCS project, assuming appropriate CCS regulation is in place and there is no significant community opposition. It is possible to deliver a complex project in less time if relevant pre-existing studies are available (for example, storage site appraisal or capture engineering studies).


Figure 28: Simplified Gantt chart for a complex CCS project



At the other end of the spectrum, less complex CCS projects can be developed in less than five years. These projects will generally require CO2 capture processes that are simple to integrate with the CO2 source, are vertically integrated (no offtake agreements), utilise existing infrastructure and/or access rights, and access geological storage resources that are already well characterised and not facing any significant risk of community opposition. An excellent example of a less complex CCS project is Santos’s Cooper Basin CCS Project in Australia, which is scheduled to commence operation in 2024. This project will capture CO2 from gas processing facilities and, using an existing pipeline corridor, transport it 50 km to a depleted hydrocarbon reservoir for storage. Santos will own and operate every element of the project, which is in a remote part of Australia with extremely low population density.

While there are likely many opportunities around the world to develop less complex CCS projects such as the Cooper Basin CCS Project, these represent a minority of the total capacity required to meet climate targets. CCS projects in development today typically have disaggregated value chains and connect to a CO2 transport and storage network because of the cost and the risk benefits that networks provide. The downside is increased complexity and longer development timelines.

In the last few years, as CCS networks have emerged, the scale and complexity of CCS projects has increased significantly. A large majority of these projects are leveraging some existing studies, most commonly related to geological storage resources. Those with access to pre-existing studies would be expected to advance to operation in less than nine years, but some may take longer. Large industrial projects take time to develop. If ambitious climate targets are to be met, the majority of projects that will deliver multi-mega-tonne-per-year-abatement in the 2030s need to commence development in the 2020s. In addition, less complex projects that can be delivered in five years or less should be pursued with urgency. Policymakers must take these timelines into account and develop policy that incentivises investment in more complex and less complex CCS projects to support net-zero strategies. Further, capacity-building across all relevant disciplines, especially geoscience, will be necessary in some developing countries, particularly those without a well developed petroleum production industry.