CCUS Absorption Market Size & Share Analysis - Growth Trends and Forecast (2027 - 2032)

Market Trends and Insights

Industrial Decarbonization Mandates and Carbon Pricing

Industrial decarbonization mandates create sustained demand for the CCUS absorption market by requiring emissions reductions without specifying a particular technology route. Absorption is often the practical option for industrial flue gases with high CO2 concentrations. The EU Emissions Trading System covers 40% of the European Union's total greenhouse gas emissions, creating ongoing compliance pressure for industrial operators. The EU Net-Zero Industry Act sets a 50 million metric tons per year CO2 injection capacity target for 2030 and requires oil and gas producers to contribute storage capacity based on their production levels. This increases available storage capacity and supports demand for capture at industrial sources. South Korea's CCUS Industry Promotion Bill, which took effect in February 2025, established a legal and business support framework for CCUS activities.

Tax Credits, Contracts for Difference, and Public Risk Sharing

Public risk-sharing measures support the CCUS absorption market by converting technical potential into predictable project revenue. The Section 45Q direct-pay option allows eligible project sponsors to access the full USD 85-per-metric-ton geological storage credit for projects that begin construction by 2032. This structure expands access beyond sponsors that can use tax equity. Final regulations for the Section 45V clean hydrogen credit took effect on January 10, 2025, and require certification of lifecycle greenhouse gas emissions for qualifying hydrogen production. Capture equipment can therefore be important for blue hydrogen projects seeking higher credit tiers. Japan selected 9 projects under its Advanced Carbon Capture and Storage (CCS) program in fiscal 2024, targeting 20 million metric tons of annual CO2 storage by 2030 through integrated support from capture to storage. Government-backed Contracts for Difference in the United Kingdom have also enabled project execution at CCS clusters where tax incentives alone would not resolve revenue uncertainty.

CCUS Hubs and Shared Transport and Storage Models

Shared transport and storage systems improve the economics of the CCUS absorption market by spreading pipeline and storage costs among multiple emitters. This lowers the minimum viable capture scale and gives mid-sized facilities access to infrastructure that previously favored large integrated operators. Northern Lights reached a final investment decision for Phase 2 in March 2025, with Equinor, Shell, and TotalEnergies committing NOK 7.5 billion (~USD 0.81 billion) to expand injection capacity from 1.5 million to at least 5 million metric tons per year by 2028. The expansion is supported by a 15-year commercial agreement with Stockholm Exergi for biogenic CO2. Phase 1 became operational in August 2025 as an open-access third-party transport and storage facility, with its 1.5 million metric ton annual capacity fully contracted. Providers with standardized equipment interfaces and experience in multi-site delivery are likely to benefit as hub-based projects become more common.

Expansion of Blue Hydrogen and Low-Emission Fuels

Blue hydrogen and other low-emission fuel projects create a new source of demand for the CCUS absorption market, as capture units are incorporated into plant design. Physical solvent systems are especially relevant where synthesis gas is processed at elevated pressure. Section 45V regulations place lifecycle emissions certification at the center of clean hydrogen eligibility in the United States, strengthening the commercial case for capture equipment at qualifying facilities. However, demand remains exposed to uncertain hydrogen offtake pricing, which can delay final investment decisions when capture capacity is designed around co-production. This risk differs from that of established CO2-enhanced oil recovery projects because it depends on demand for a newer fuel value chain.

Solvent Regeneration Energy Penalty

Amine regeneration remains a significant operational constraint for the CCUS absorption market. Chemical absorption typically requires 2.5 to 4 gigajoules of thermal energy per metric ton of CO2 recovered. At sites using fossil-sourced steam, 15% to 25% of gross CO2 avoided is consumed by the capture process itself. This reduces the quantity eligible for monetization under tax-credit and emissions-trading structures. Operating costs are also tied to natural gas prices, which adds uncertainty to the financing of long-life capture assets. Mitsubishi Heavy Industries (MHI) began operating a pilot plant using its KS-21 solvent at Korea Electric Power Corporation's (KEPCO) Himeji No. 2 Power Station in May 2025, reporting lower regeneration energy consumption and amine emissions than its prior KS-1 formulation.

Cross-Chain Coordination and Contract Risk

CCUS projects require alignment across capture, CO2 conditioning, transport, and storage. These activities involve different cost structures, liability arrangements, regulations, and counterparty risks. BASF shelved the Kairos Carbon Capture and Storage (CCS) investment in Antwerp in March 2025, despite EUR 500 million (~USD 559.67 million) in committed EU Innovation Fund support, demonstrating how commercial misalignment can halt a funded project. The EU CCS Directive requires monitoring plans, 5-year permit reviews, and financial provisions for post-closure CO2 management. These obligations extend liability across counterparties over decades. As a result, contract design can lengthen engineering and financing stages, even where the technology and funding are in place.

*Our forecasts treat driver/restraint impacts as directional, not additive. The impact forecasts reflect baseline growth, mix effects, and variable interactions.

CCUS Absorption Market Segment Analysis

Chemical absorption held 62.45% of the CCUS absorption market share in 2026. The segment is supported by the established use of amine-based post-combustion systems in natural gas processing, refining, power generation, and industrial sites. These systems can achieve CO2 capture rates of 90% or more from dilute flue gas at near-atmospheric pressure. BASF reports more than 500 reference plants for its OASE technology, reflecting a substantial installed base. Standardized engineering, operational data, and established solvent supply chains support further retrofit use.

Physical absorption is forecast to grow at a CAGR of 14.12% from 2027 to 2032. Blue hydrogen, pre-combustion, and natural gas sweetening projects favor physical solvents when operating pressure and CO2 partial pressure are high. Rectisol and Selexol can provide energy and capital advantages under those conditions. New hydrogen and ammonia plants can select physical systems from the design stage, while existing fossil-fuel assets often continue to use chemical absorption. Carbon Clean's CycloneCC combines rotating packed beds with an amine-promoted buffer-salt solvent, reducing the equipment footprint by up to 50% at mid-scale industrial sites.

Amine-based solvents held 55.12% of the CCUS absorption market share in 2026. Their position reflects more than three decades of commercial CCS use with monoethanolamine, diethanolamine, and proprietary blends. MHI had delivered 18 commercial plants using its KM CDR Process and Advanced KM CDR Process, with two plants under delivery as of December 2025. This reference base supports supplier selection where buyers require demonstrated capture performance. Standard designs also allow amines to serve a wide range of flue-gas compositions.

Alkali-based chemicals are forecast to grow at a CAGR of 14.56% from 2027 to 2032. Potassium carbonate, chilled ammonia variants, and mixed-salt processes suit high CO2 partial-pressure streams from cement kilns and steel blast furnaces. Their lower regeneration-energy requirements can improve economics where fuel and steam costs are high. Baker Hughes' Mixed Salt Process and Capsol Technologies' ambient-pressure chilled ammonia system are included in the Global CCS Institute's 2025 technology compendium. Ionic liquids, thermomorphic solvents, enzyme-accelerated carbonate systems, and amino acid salts remain emerging options that require regulatory approval and financing confidence for wider deployment.

Oil and gas accounted for 34.57% of the CCUS absorption market share in 2026. Decades of CO2-enhanced oil recovery had created CO2-handling infrastructure before current policy-driven deployment accelerated. Large emissions at individual facilities can support capture investments that smaller industrial sites cannot justify. Major operators, including ExxonMobil, Chevron, and Shell, are pursuing facility retrofits and carbon storage development. Power generation, chemical production, and petrochemicals also contribute to demand, particularly for ammonia and methanol plants that use acid-gas removal.

Cement is forecast to grow at a CAGR of 15.68% from 2027 to 2032, the highest rate among end-user industries. Limestone calcination accounts for 60% of the cement sector's CO2 output through a chemical reaction, so electrification and fuel switching cannot fully address this source. The IEA reported that planned near-zero-emissions cement capacity for 2030 had grown 30% to 35 million metric tons, but remained below the required pace. MHI and Worley received the December 2025 contract for the United Kingdom's first cement-plant CO2 capture project at Heidelberg Materials' Padeswood facility^[1]. The facility is designed to capture 800,000 metric tons per year and connect to the HyNet cluster.

Geography Analysis

North America

North America held 36.33% of the CCUS absorption market share in 2026. Section 45Q tax credits, established CO2 pipeline infrastructure, and more than 20 million metric tons per year of capture capacity in the United States lower the incremental transport cost of new projects. The Houston Ship Channel CCS hub involves ExxonMobil, Chevron, Linde, and 8 additional industrial partners, targeting up to 50 million metric tons of annual capture by 2030. Canada contributes through carbon pricing and oil sands decarbonization commitments, while Mexico remains at an earlier stage of feasibility assessment. Fluor is carrying out late-stage engineering for gas-fired power, blue hydrogen, waste-to-energy, and cement projects across North America and Europe.

Asia-Pacific

Asia-Pacific is forecast to expand at a 15.23% CAGR from 2027 to 2032, making it the fastest-growing region in the CCUS absorption market. In February 2025, Japan designated a sea area offshore of Tomakomai City as its first specified area under the CCS Business Act, initiating commercial storage licensing. Its 9 JOGMEC-backed Advanced CCS Projects are pursuing 20 million metric tons of annual storage capacity by 2030 across 6 industrial regions. South Korea's CCUS Industry Promotion Bill and subsequent KRW 300 billion loan program provide a legal and financing framework for commercial deployment. China's Green Technology Promotion Catalog sets a 50,000-metric-ton annual capture threshold for eligible coal-fired power and petrochemical projects, linking green finance to equipment procurement^[2].

Europe, South America, and the Middle East and Africa

Europe is supported by the EU Net-Zero Industry Act target of 50 million metric tons of annual CO2 injection capacity by 2030. Northern Lights Phase 2 extends Norwegian storage infrastructure, while the United Kingdom's HyNet and East Coast Cluster continue under government support. In August 2025, the Northern Endurance Partnership awarded Halliburton a contract to monitor the Endurance saline aquifer, with an initial annual injection capacity of 4 million metric tons, starting as early as 2027. South America is at an early stage, although MHI received a 2025 study contract for CO2 capture modules on Petrobras offshore vessels. Activity in the Middle East and Africa is building on national oil company decarbonization mandates and experience with CO2-enhanced oil recovery.