The capture, transport and utilisation or storage of CO₂ as a successful mitigation strategy hinges on the availability of technologies at each stage of the process as well as on the development and expansion of CO₂ transport and storage networks. All of the steps along the value chain need to be technologically ready and developed in tandem for CCUS to scale up.

CCUS technologies are at varying levels of maturity today. Several technologies in CO₂ capture, transport, utilisation and storage are already deployed at large scale, but other technologies, including those that hold out the promise of better performance and lower unit costs, require further development. One way to assess where a technology is in its journey from the laboratory to the marketplace is to use the TRL scale, which provides a common framework that can be applied to any technology to assess and compare the maturity of technologies across and within different sectors.

The TRLs and categories used in this report (prototype, demonstration, early adoption and mature) refer not only to the stages of technological development, but also to their adoption in the market. Most technologies that are at the early adoption stage today have already gone through the full technological development cycle, but have not been labelled as “mature" because they have not been widely deployed yet – as is the case for most CCUS applications. A broad range of technologies therefore fall into the “early adoption” category, including many advanced CCUS technologies but also renewable technologies such as electric vehicles, onshore wind and solar PV, which are commercial and competitive but require further integration efforts. Technologies in the early adoption category can be scaled up rapidly once the necessary policy and legal framework conditions are in place.

Several applications of CCUS are already widely deployed today, including chemical absorption of CO₂ from ammonia production and natural gas processing, CO₂ use in the production of fertiliser (urea), and long-distance pipeline transport and injection of CO₂ for EOR. A number of other applications have been demonstrated at scale over the last decades, but are still at the early adoption stage, such as chemical absorption from coal-fired power generation and hydrogen production from natural gas, compression of CO₂ from bioethanol production and coal-to-chemicals plants, and CO₂ storage in saline aquifers. Several other applications, including DAC and CO₂ capture from cement and iron and steel making, are still at the demonstration or prototype stage. In each of these potential new applications, a range of CO₂ capture technologies need to be tailored to the particular conditions of each individual process.

In the Sustainable Development Scenario, nearly two-thirds of the cumulative emissions reductions from CCUS through to 2070 relative to the Stated Policies Scenario come from technologies that are currently at the prototype or demonstration stage. The other one-third comes from technologies that are already mature or at the early adoption stage, which can be scaled up rapidly, bringing forth incremental technological improvements and cost savings. In the decade to 2030, such technologies in power and fuel transformation, including hydrogen production, contribute around half of the cumulative emissions savings in the Sustainable Development Scenario. Most of these applications are based on chemical absorption as the CO₂ capture technology, with this already widely used in commercial capture facilities and embedded in demonstration plants today.

Major improvements to a wide range of technologies that are at the prototype or demonstration stage today are needed. Important applications that start to play a pivotal role in the next decade or so, but that still require a near-term push from RD&D, include chemical absorption from gas-fired power generation and cement and chemicals production, BECCS and CO₂ capture from iron and steel manufacturing. Some applications have multiple technology maturities as they represent several sub‑applications with different capture technologies (e.g. coal power generation), or different energy conversion or production processes from which the CO₂ is captured (e.g. other fuel transformation, chemicals, and iron and steel).

DAC and CO₂ conversion to synthetic hydrocarbon fuels, which play important roles later in the projection period, also require considerable further RD&D to ensure that they can start to be deployed at scale from the 2030s. Efforts to develop DAC early can provide an important technology hedge against the risk of slower-than-expected innovation or commercialisation of other technologies.

CO₂ capture is an integral part of several industrial processes and, accordingly, technologies to separate or capture CO₂ from flue gas streams have been commercially available for many decades. The most advanced and widely adopted capture technologies are chemical absorption and physical separation; other technologies include membranes and looping cycles such as chemical looping or calcium looping. In practice, the most appropriate capture technology for a given application depends on a number of factors, including the initial and final desired CO₂ concentration, operating pressure and temperature, composition and flow rate of the gas stream, integration with the original facility, and cost considerations.

The cost of capturing CO₂ can vary significantly, mainly according to the concentration of CO₂ in the gas stream from which it is being captured, the plant’s location, energy and steam supply, and integration with the original facility (Ferrari et al., 2019; IEAGHG, 2018c). For some processes, such as ethanol production or natural gas processing or after oxy-fuel combustion in applications such as power generation or cement, CO₂ can be already highly concentrated. This CO₂ can be simply pre-treated if necessary (e.g. dehydration) and then compressed for transport and storage or use at relatively low cost. For example, the cost of separating out the CO₂ contained in natural gas – which is often required for technical reasons before the gas can be sold or liquefied – can be as low as USD 15/t to USD 25/t2 For more diluted CO₂ streams, including the flue gas from power plants (where the CO₂ concentration is typically the 3-14%) or a blast furnace in a steel plant (20-27%), the cost of CO₂ capture is much higher (over USD 40/t of CO₂ and sometimes more than USD 100/t, accounting on average for around 75% of the total cost of CCUS (NPC, 2019).3

Most CO₂ capture systems have been designed to capture around 85-90% of the CO₂ from the point source, which results in the lowest cost per tonne of CO₂ captured. However, in a net-zero energy system, higher capture rates – approaching 100% – will be needed. This is technically and economically achievable according to recent studies.

The availability of infrastructure to transport CO₂ safely and reliably is an essential factor in enabling the deployment of CCUS. The two main options for the large-scale transport of CO₂ are via pipeline and ship, although for short distances and small volumes CO₂ can also be transported by truck or rail, albeit at higher cost per tonne of CO₂. Transport by pipeline has been practised for many years and is already deployed at large scale. Large-scale transportation of CO₂ by ship has not yet been demonstrated (TRL 4-7) but would have similarities to the shipping of liquefied petroleum gas (LPG) and LNG. Nonetheless, considerable possibilities for innovation remain, in particular for offshore unloading of CO_2, and spillovers from the general shipping industry, including automation and new propulsion technologies.

Economic factors and regulatory frameworks are the main considerations in the choice of CO₂ transport mode. Pipelines are the cheapest way of transporting CO₂ in large quantities onshore and, depending on the distance and volumes, offshore. There is already an extensive onshore CO₂ pipeline network in North America, with a combined length of more than 8 000 km – mostly in the United States. These onshore pipelines currently transport more than 70 Mt/year of CO₂, mainly for EOR. Combined with new policy incentives, including the 45Q tax credit, the vast existing pipeline network in the United States has been a key driver for recent project announcements. In June 2020, the Alberta Carbon Trunk Line (ACTL) in Canada came online with a pipeline capacity of 14.6 Mt CO₂, with significant excess capacity (some 90%) to accommodate CO₂ from future CCUS facilities. The ACTL received CAD 560 million (USD 430 million) in capital funding from the Canadian and Albertan governments, slightly below half of the CAD 1.2 billion (USD 920 million) estimated project cost (Government of Alberta, 2020; NRCAN, 2020a). There are also two CO₂ pipeline systems in Europe and two in the Middle East.

The share of pipeline transportation in the total cost of a CCUS project varies according to the quantity transported as well as the diameter, length and materials used in building the pipeline. Other factors include labour cost and the planned lifetime of the system. Location and geography are significant factors that affect the total cost as well. In most cases, transport represents well under one-quarter of the total cost of CCUS projects. Pipelines located in remote and sparsely populated regions cost about 50-80% less than in highly populated areas (Onyebuchi et al., 2018). Offshore pipelines can be 40-70% more expensive than the onshore pipelines. There are strong economies of scale based on pipeline capacity, with unit costs decreasing significantly with rising CO₂ capacity. Pipeline costs are also likely to differ substantially among regions as new projects are developed. The cost of new pipelines is estimated to be generally 30% lower in Asia than in Europe (World Bank, 2015).

While the properties of CO₂ lead to different design specifications compared with natural gas, CO₂ transport by pipeline bears many similarities to high-pressure transport of natural gas. Repurposing existing natural gas or oil pipelines, where feasible, would normally be much cheaper than building a new line. Design pressure and remaining service life are the two main considerations to be taken into account to evaluate the repurposing of existing oil and gas pipelines. Oil and gas pipelines typically operate at lower pressure, which leads to a reduction in CO₂ transport capacity compared with higher-pressure purpose-built CO₂ pipelines. Furthermore, many existing oil and gas pipelines have been in operation for more than 20 years. A case-by-case analysis is necessary to evaluate their remaining life, taking into account in particular internal corrosion and the remaining fatigue life (JRC, 2011). 

CO₂ transportation by ship to an offshore storage facility offers greater flexibility, particularly where there is more than one offshore storage facility available to accept CO₂. The flexibility of shipping can also facilitate the initial development of a CO₂ capture hubs, which could later be connected or converted into a more permanent pipeline network as CO₂ volumes grow. Today, only around 1 000 tonnes of food-quality CO₂ is shipped in Europe every year from large point sources to coastal distribution terminals. In recent years, interest in CO₂ shipping has increased in several regions and countries where offshore storage has been proposed, including in Europe, Japan and Korea. 

Large-scale transportation of CO₂ by ship has not yet been demonstrated but would have similarities to shipping of LPG and LNG.4 The supply chain would consist of several steps: CO₂ would first have to be liquefied and stored in tanks before being loaded onto ships for transport. Destinations may be other ports or offshore storage sites. Unloading onshore would be relatively straightforward, based on experience with current CO₂ shipping operations and from large-scale shipping of other gases, such as LPG and LNG. Offshore unloading, either to an offshore platform before conditioning and injection, or direct injection to the storage site after conditioning on ship, is not yet proven and the processes are less well-understood (IEAGHG, 2020b).

Shipping CO₂ by sea may be viable for regional CCUS clusters. In some instances, shipping can compete with pipelines on cost, especially for long-distance transport, which might be needed for countries with limited domestic storage resources. The share of capital in total costs is higher for pipelines than for ships, so shipping can be the cheapest option for long-distance transport of small volumes of CO₂ (up to around 2 Mt/year). This would be the case with several early industrial CCUS clusters across Europe (IEAGHG, 2020b).

CO₂ can be used as an input to a range of products and services. The potential applications for CO₂ use include direct use, where the CO₂ is not chemically altered (non‑conversion), and the transformation of CO₂ to a useful product (conversion). Today, around 230 Mt of CO₂ are used globally each year.5 The largest consumer is the fertiliser industry, which uses 125 Mt/year of CO₂ as a raw material in urea manufacturing, followed by the oil and gas industry, which consumes around 70 to 80 Mt per year for EOR. Other commercial uses of CO₂ include food and beverage production, cooling, water treatment, and greenhouses, where it is used to stimulate plant growth.

New CO₂ use pathways, involving chemical and biological technologies, offer opportunities for future CO₂ use. Many of these pathways are still in an early stage of development, but early opportunities are already being realised. There are three main categories of CO₂-based products:

• Fuels: The carbon in CO₂ can be used to convert hydrogen into a synthetic hydrocarbon fuel that is as easy to handle and use as a gaseous or liquid fossil fuel (see Chapter 2). The production of such fuels is highly energy-intensive and is most economically viable where both low-cost renewable energy and CO₂ are available. The largest plant currently in operation is the George Olah facility in Iceland, which converts around 5 600 tCO₂ per year into methanol using hydrogen produced from renewable electricity (CRI, 2019).
• Chemicals: The carbon in CO₂ can be used as an alternative to fossil fuels in the production of chemicals that require carbon to provide their structure and properties. These include polymers and primary chemicals such as ethylene and methanol, which are building blocks to produce an array of end-use chemicals. The need for hydrogen and energy varies significantly according to the chemical and production pathway. An example of a company active in the field is Covestro, which is operating a facility to produce around 5 000 t of polymers per year in Dormagen, Germany. CO₂ substitutes up to 20% of the fossil feedstock normally used in the process.
• Building materials: CO₂ can be used in the production of building materials to replace water in concrete, called CO₂ curing, or as a raw material in its constituents (cement and construction aggregates). The CO₂ is reacted with minerals or waste streams, such as iron slag, to form carbonates, the form of carbon that makes up concrete. This conversion pathway is typically less energy-intensive than for fuels and chemicals and involves permanent storage of CO₂ in the materials. Some CO₂-based building materials can have superior performance compared with their conventional counterparts. A few applications, such as the use of CO₂ in concrete mixing, are already commercially available in some markets today (IEA, 2019). Two North American companies, CarbonCure and Solidia, are leading the commercialisation of CO₂-curing technology, with CarbonCure now operating some 175 facilities in the United States and Canada (CarbonCure, 2020; Solidia, 2020). The British company Carbon8 is among the companies using CO₂ to convert waste materials into aggregates as a component of building materials. It is currently operating two commercial plants and aims to have five to six plants in operation by 2021 (Carbon8, 2019).

The prospects for CO₂-based products are very difficult to assess, as the technologies are generally at an early stage of development for many applications. Policy support will be crucial since they are likely to cost a lot more than conventional and alternative low-carbon products, mainly because of their high-energy intensity. The market for CO₂-based products is expected to remain small in the short term, but could grow rapidly in the longer term. A high-level screening of the theoretical potential for CO₂ use shows that it could reach as much as 5 GtCO₂/year for chemicals and building materials, and even more for synthetic hydrocarbon fuels (IEA, 2019). But in practice, these levels are unlikely to be attainable, mostly for economic reasons. Synthetic hydrocarbon fuels are unlikely to be able to compete with direct use of low-carbon hydrogen or electricity in most applications, but could become important in sectors that continue to need hydrocarbon fuels as the energy sector approaches net-zero emissions and where other fuel alternatives are limited, such as aviation. In the Sustainable Development Scenario, synthetic kerosene meets around 40% (250 Mtoe) of aviation energy demand in 2070, requiring around 830 Mt of CO₂.

Large-scale deployment of CO₂-based chemicals and fuels would involve large amounts of renewable electricity for their production, in particular for the generation of low-carbon hydrogen. In the Sustainable Development Scenario, the production of synthetic aviation fuels alone in 2070 requires around 5 500 TWh, which is around 8% of all the electricity produced worldwide in 2070.

The extent to which the capture and utilisation of CO₂ contributes to reducing emissions varies considerably depending on the origin of the CO₂ and the way the CO₂ is used. Quantifying the potential benefits in each case is less straightforward than for CO₂ storage as it depends on several factors.

Storing CO₂ involves the injection of captured CO₂ into a deep underground geological reservoir of porous rock overlaid by an impermeable layer of rocks, which seals the reservoir and prevents the upward migration of CO₂ and escape into the atmosphere. There are several types of reservoir suitable for CO₂ storage, with deep saline formations and depleted oil and gas reservoirs having the largest capacity. Deep saline formations are layers of porous and permeable rocks saturated with salty water (brine), which are widespread in both onshore and offshore sedimentary basins. Depleted oil and gas reservoirs are porous rock formations that have trapped crude oil or gas for millions of years before being extracted and which can similarly trap injected CO₂.

When CO₂ is injected into a reservoir, it flows through it, filling the pore space. The gas is usually compressed first to increase its density, turning it into a liquid. The reservoir must be at depths greater than 800 metres to retain the CO₂ in a dense liquid state. The CO₂ is permanently trapped in the reservoir through several mechanisms: structural trapping by the seal, solubility trapping in pore space water, residual trapping in individual or groups of pores, and mineral trapping by reacting with the reservoir rocks to form carbonate minerals. The nature and the type of the trapping mechanisms for reliable and effective CO₂ storage, which vary within and across the life of a site depending on geological conditions, are well-understood thanks to decades of experience in injecting CO₂ for EOR and dedicated storage.

CO₂ storage in rock formations (basalts) that have high concentrations of reactive chemicals is also possible, but is in an early stage of development (TRL 3). The injected CO₂ reacts with the chemical components to form stable minerals, trapping the CO₂. However, further testing and research is required to develop the technology, notably to determine water requirements, which can be considerable (IEAGHG, 2017).6 There are large basaltic formations in several regions around the world, and both onshore and offshore sites have been considered for storage. Such formations also exist in places, such as India, where there may be limited conventional storage capacity, potentially opening up new opportunities for CCUS.

The overall technical storage capacity for storing CO₂ underground worldwide is uncertain, particularly for saline aquifers where more site characterisation and exploration is still needed, but potentially very large. As such, it is unlikely to be a constraint on the development of CCUS. Total global storage capacity has been estimated at between 8 000 Gt and 55 000 Gt.7

The availability of storage differs considerably across regions, with Russia, North America and Africa holding the largest capacities. Substantial capacity is also thought to exist in Australia.

The vast majority of the estimated CO₂ storage capacity is onshore in deep saline aquifers and depleted oil and gas fields. Storage capacity is estimated to range from 6 000 Gt to 42 000 Gt for onshore sites. There is also significant offshore capacity ranging from 2 000 Gt to 13 000 Gt (taking into account only sites within 300 kilometres of the shore, at water depths of less than 300 metres, and outside the Arctic and Antarctic).

Even the lowest estimates of global storage capacity of around 8 000 Gt far exceeds the 220 Gt of CO₂ that is stored over the period 2020‑70 in the Sustainable Development Scenario. Despite the stark regional variation in storage capacity, only a few countries might face a shortfall in domestic storage capacity over that time frame.8

While notional storage volumes are considerable, a smaller fraction will most likely prove to be technically or commercially feasible. CO₂ storage capacity is analogous to oil or gas insofar as it is a natural resource requiring exploration and appraisal, involving extensive data gathering. While success rates might prove to be higher than in the oil and gas exploration sector, failure rates, costs and delays in the exploration and appraisal phase are likely to be significant. The process of moving along the Society of Petroleum Engineers CO₂ Storage Resource Management System (SRMS) scale from undiscovered resource status to sub‑commercial and then commercial status can take between 5 and 12 years for petroleum assets and even longer for undiscovered saline formations (OGCI, 2017). A valuable first step in characterising the progress of storage sites has been made by the OGCI’s CO₂ Storage Resource Catalogue, which classifies storage sites in 13 countries following closely the definitions of the SRMS (OGCI, 2020). The majority of resource assessments are not project-based and so are automatically categorised as non‑commercial on the SRMS scale.

The possibility that CO₂ stored underground could leak out has raised questions about the effectiveness of CCUS as a climate mitigation measure and public concerns about safety risks. Decades of experience with large-scale CO₂ storage has demonstrated that the risk of seepage of CO₂ to the atmosphere or the contamination of groundwater can be managed effectively. The probability and potential impact of such events have been studied comprehensively and have been found to be generally low, with risks declining over time. Nonetheless, careful storage site selection and thorough assessment is critical to ensure the safe and permanent storage of CO₂ and to reduce risks to acceptable levels. Thorough assessment includes detailed modelling of the anticipated behaviour of the CO₂ over time, together with ongoing monitoring, measurement and verification. A robust legal and regulatory framework is important to ensure appropriate site selection and safe operation of geological CO₂ storage sites. This already exists in many countries. Project developers and the public authorities have to address public concerns through effective stakeholder engagement.

The cost of developing CO₂ storage sites will be an important factor in how quickly CCUS is deployed in the coming decades in some regions, though generally costs are expected to be low relative to CO₂ capture. Current and estimated CO₂ storage costs vary significantly depending on the rate of CO₂ injection and the characteristics of the storage reservoirs, as well as the location of CO₂ storage sites. The cost of developing new sites, especially where CO₂ storage has not been carried out before, is very uncertain, particularly with regard to the effect of reservoir properties and characteristics.

In some cases, storage costs can be quite low. Indeed, when the CO₂ is stored as a consequence of CO₂-EOR operations, the cost of storage can effectively be negative net of the incremental revenues from oil production. More than half of onshore storage in the United States is estimated to be below USD 10/tCO₂, which would typically represent only a minor part of the overall cost of a CCUS project. Depleted oil and gas fields using existing wells are expected to be the cheapest storage option. A small number of storage reservoirs with less favourable storage conditions are caught in the asymptotic parts of the curve. About half of offshore storage is estimated to be available at costs below USD 35/tCO₂. Similar cost curves are expected to apply in other regions, but further research is needed to confirm this (Rubin, Davison and Herzog, 2015).

There is considerable potential for reducing costs along the CCUS supply chain. Some of the factors that will drive cost savings are specific to the different stages along the chain – capture, transport, use and storage – while others apply to all stages. Across the supply chain, cost reductions could be achieved in a number of ways:

• Learning by doing: There is evidence that the growing portfolio of large-scale CCUS projects has already contributed to cost reductions through learning-by-doing. For instance, the capture costs at Petra Nova are 35% lower than Boundary Dam, which was built just few years earlier, while a detailed feasibility study for retrofitting the Shand coal-fired power station in Canada with CCUS suggests that cost reductions of around 70% for capex and opex are possible, relative to the Boundary Dam project (GCCSI, 2019; IEAGHG, 2018b). Similarly, the Quest CCS project has identified that its capex would be 20% to 25% lower if the plant were to be built again today (IEAGHG, 2017). 
• Technology spillovers: Cost reductions may come from spillover effects (see section below) and learning-by-researching. In the Sustainable Development Scenario, CO₂ capture costs reduction based on learning-by-doing, learning-by-researching and spillover effects for applications in both power and industrial sectors has been estimated to be around 35% between 2019 and 2070.
• Reduced capital and operating costs: Capital costs have typically accounted for more than half of the total cost of capture at first-generation retrofitted plants. These costs can be reduced by economies of scale, improved site layout and modularisation, optimisation of the CCUS operating conditions and supply chain, and technology development. CCUS facilities can also have significant operating costs due to the additional energy required to operate the facilities, as well as solvents, chemical reagents, catalysts, the disposal of waste products and additional staff needed to run them. Operating costs can be reduced by means of optimised maintenance strategies, thermal energy and water use optimisation, increased compression efficiency, and digitalisation.
• Digitalisation: There are number of new technologies, including robotics, drones and autonomous systems, novel sensors, digital innovations, virtual and augmented reality, additive manufacturing, and advanced materials that could reduce costs along the CCUS chain. The greatest potential for reducing costs lies in the application of artificial intelligence and the internet of things in predictive maintenance and automation (IEAGHG, 2020a). The biggest scope for cutting costs using these technologies is thought to lie in storage.
• Improved business models: Business models that involve the separation of the capture, transport and storage components of the CCUS value chain, including through shared transport and storage infrastructure around industrial hubs, have potential to reduce unit costs through economies of scale while reducing commercial and technical risks. These risks increase the cost of capital and financing, which can have a large overall impact on project cost. decreases in the cost of capital in recent years have been vital to the global scaling-up of renewables (IEA, 2020c).10

Reducing the cost of CO₂ capture, including by lowering energy needs, has been the focus of a large amount of RD&D by private and public research centres around the world in recent years. The main potential areas for cutting both capital and operating costs include the use of innovative solvents, standardisation of capture units, modularisation and off-site manufacture, reduced contingencies, and better integration with the process plant, as well as increasing the size of facilities in order to exploit economies of scale and learning-by-doing benefits. Cost estimates for technologies at low TRLs are highly uncertain but generally, these technologies have greater potential for cost reduction than mature technologies that are well established in markets. Earlier-stage capture technologies, which could be deployed 10 to 20 years from now, could be 30% to 50% cheaper than current designs (NPC, 2019). Capture costs could also be lowered by designing innovative production technologies, such as the HIsarna steel-making process in which iron ore is processed almost directly into liquid iron using less energy and emitting less CO₂ (Bellona, 2018).

Knowledge and application spillovers – the positive externalities of learning-by-doing or learning-by-researching that increase the rate of innovation in a technology area that was not the target of the original innovation effort – can also bring down the cost of CO₂ capture. For instance, in the Sustainable Development Scenario, the learning gained from various applications of chemical absorption in industry and power generation (e.g. when CO₂ needs to be separated during standard process operations without being stored or used) cuts the cost of deploying this technology for CCUS by around 12%.

In power generation, capture costs are expected to be reduced by the adoption of various emerging technologies. For instance, electrochemical separation is projected to lower the LCOE with CO₂ capture by 30%; chemical absorption with advanced solvents and configurations, membrane separation, PSA and TSA, calcium looping, and cooling and liquefaction by between 10% and 30%; and pressurised oxy-fuel combustion, chemical looping combustion and sorption-enhanced water gas shift by up to 10% (IEAGHG, 2019a). These cost reductions are based on the current development trajectory of these technologies, which have recently moved from the prototype to the demonstration phase. For CCUS applied to industrial process emissions, capture cost reductions can be achieved not only through innovative technologies, but also through strategies such as capturing from units emitting larger volumes of CO₂ (e.g. recovery boilers rather than lime kilns for pulp and paper production) and recovering excess heat (e.g. in steel production) (IEAGHG, 2019c).

CO₂ transport by pipeline is a mature technology, with practical experience spanning several decades, mostly in North America. The maturity and relative simplicity of the technology has resulted in few technological improvements that have affected costs since the 1980s. Experience with CO₂ storage over the last decade has also grown, including with five dedicated storage operations (i.e. not associated with EOR) but the site-specific nature of geological storage makes it difficult to discern clear downward cost trends.

The main scope for reducing costs is by exploiting economies of scale through pooling of transport and storage demand. This can be achieved by developing industrial clusters with shared infrastructure (see Chapter 1). In some cases, the repurposing of existing oil and gas pipeline infrastructure could contribute to lowering costs (see above).

CO₂ transport and storage are expected to benefit from technology innovation and digitalisation that are currently revolutionising the oil and gas industry. The largest cost reductions are likely to come from advanced sensing and real-time monitoring technologies that allow for reduced downtime and early detection of CO₂ migration or leakage, due to improved tracking and predictive maintenance11 (IEA, 2017). Drones, robotics and automated systems will be particularly important as they can significantly reduce the need for labour, for example on offshore storage platforms. Smart drilling and developments in seismic analysis could also accelerate site appraisals and reduce costs. The potential for cost reductions through innovation is greater for CO₂ storage for which the costs of new projects are projected to fall by around 20-25% by 2040, (IEAGHG, 2020a).