Carbon Capture & Storage (CCS)

Posted on by Brian Colwell

[this article was updated July 2nd, 2025]

In the depths of the North Sea, 250 kilometers off Norway’s coast, an invisible transformation has been quietly unfolding for nearly three decades. Since 1996, the Sleipner gas platform has been injecting a million tonnes of CO2 annually into sandstone formations a kilometer beneath the seabed—not as waste disposal, but as the world’s first commercial-scale demonstration that we can return carbon to where it came from. This pioneering project, born from Norway’s carbon tax rather than climate ambition, has stored over 20 million tonnes of CO2 without incident, proving that what nature took millions of years to sequester, human engineering can accomplish in decades.

Today, carbon capture and storage (CCS) has evolved from this single offshore experiment into a global industry operating across 50 facilities, with hundreds more in development. The technology promises to be a critical bridge between our fossil fuel-dependent present and a net-zero future, offering the tantalizing possibility of decarbonizing hard-to-abate industries while maintaining economic growth. From power plants retrofitted with amine scrubbers to direct air capture facilities pulling CO2 from the atmosphere, CCS encompasses a diverse toolkit of chemical engineering solutions that could potentially remove gigatonnes of carbon dioxide annually.

Understanding CCS Technology & Process Flow

Carbon Capture and Storage (CCS) represents a critical technology pathway for achieving global climate goals, with the International Energy Agency projecting it could contribute 22% of global greenhouse gas emission reductions by 2035. This comprehensive technical analysis examines the current state of CCS technologies, from fundamental capture processes through sequestration methods, while providing engineering professionals with detailed performance metrics, operational insights, and economic considerations based on the latest developments through 2025.

CCS operates as an integrated three-stage process comprising capture, transport, and storage. The capture stage involves separating CO2 from emission sources, achieving target efficiencies of 90-98% depending on the technology employed. CO2 concentrations vary significantly between applications, from 4-15% in post-combustion flue gas to 15-60% in pre-combustion syngas, with operating pressures ranging from atmospheric to 70 bar. Following capture, CO2 undergoes compression to its supercritical state (>73.8 bar, >31.1°C) for efficient transport via pipeline at 80-200 bar or ship transport at 6-18 bar in refrigerated form. The final storage stage involves injection into geological formations at depths exceeding 800 meters, where pressure and temperature conditions maintain CO2 in a dense phase suitable for permanent sequestration.

The technical complexity of CCS requires careful integration of chemical engineering principles, geological sciences, and process optimization. Each stage presents unique challenges: capture technologies must balance efficiency with energy penalties, transport systems require materials compatible with CO2’s corrosive properties when combined with water, and storage sites demand extensive characterization to ensure long-term containment. Understanding these interdependencies is crucial for successful CCS deployment.

What Are The Primary Carbon Capture Methods?

Carbon capture technology offers two primary methods for reducing industrial CO2 emissions: pre-combustion and post-combustion capture. Pre-combustion capture integrates with gasification processes, converting fuels into syngas at high temperatures (800-1500°C) before transforming carbon monoxide into CO2 through a water-gas shift reaction, ultimately producing clean hydrogen while capturing CO2 at high concentrations with relatively low energy consumption (1.5-2.5 GJ per tonne). Post-combustion capture, the more mature technology, removes CO2 from flue gas after fuel combustion using chemical solvents like amines that bind with CO2 in absorption towers, achieving 85-95% capture efficiency though with higher energy penalties (25-35%). While pre-combustion works best for new facilities designed around gasification and hydrogen production, post-combustion excels at retrofitting existing power plants and industrial facilities. Both methods employ various technologies including physical and chemical solvents, emerging adsorption materials like Metal-Organic Frameworks (MOFs), and membrane separation systems, with ongoing research focused on reducing energy consumption and costs to support global net-zero emission goals.

Pre-Combustion Carbon Capture

Pre-combustion capture integrates with gasification processes to produce hydrogen while capturing CO2 at higher concentrations and pressures than post-combustion systems. Gasification converts solid or liquid feedstocks to syngas at 800-1500°C and 30-70 bar, producing gas compositions of 30-60% CO, 25-40% H2, and 5-15% CO2. Entrained flow gasifiers operate at the highest temperatures (1200-1500°C) with oxygen, while fluidized bed systems work at 800-1000°C and fixed bed gasifiers at 700-900°C with air or oxygen.

The water-gas shift reaction (CO + H2O ⇌ CO2 + H2, ΔH = -41.1 kJ/mol) converts CO to CO2 and additional hydrogen. High-temperature shift catalysts (Fe2O3-Cr2O3) operate at 310-450°C achieving 90-95% CO conversion, while low-temperature shift catalysts (CuO-ZnO-Al2O3) work at 200-250°C for 95-99% conversion. Sour shift catalysts (CoO-MoO3) enable operation with sulfur-containing syngas at 200-350°C, eliminating the need for upstream sulfur removal.

Physical solvents excel in pre-combustion applications due to favorable high-pressure conditions. Selexol captures >90% of CO2 from streams containing 15-40% CO2 with energy consumption of 1.5-2.5 GJ/tonne CO2, while providing high H2S/CO2 selectivity for simultaneous acid gas removal. Rectisol achieves ultra-deep removal with <1 ppm sulfur levels, though refrigeration requirements increase energy consumption. These physical absorption processes benefit from multi-stage flash regeneration rather than thermal stripping, significantly reducing parasitic energy losses.

Post-Combustion Carbon Capture

Post-combustion capture, the most mature CCS technology, removes CO2 from flue gas after fuel combustion. The industry standard remains monoethanolamine (MEA) absorption, operating with 20-30 wt% aqueous solutions. MEA systems achieve 85-95% capture efficiency but impose significant energy penalties of 25-35%, requiring 3.5-4.2 GJ per tonne of CO2 captured. The absorber operates at 40-60°C and 1-2 bar, while the regenerator requires 100-120°C and 1.5-2 bar, with CO2 loading reaching 0.5-0.6 mol CO2/mol amine.

Advanced amine solvents offer improved performance characteristics. Piperazine (PZ) systems, using 8-12 wt% aqueous solutions, demonstrate 15-20% lower energy penalties than MEA while achieving higher CO2 loading of 0.6-0.8 mol CO2/mol amine. Sterically hindered amines like 2-amino-2-methyl-1-propanol (AMP) and methyldiethanolamine (MDEA) enable regeneration at 80-100°C versus 120°C for MEA, reducing energy consumption to 2.8-3.2 GJ/tonne CO2. Process configurations typically employ packed columns with 15-25 theoretical stages in the absorber, coupled with distillation columns for regeneration and rich-lean solvent heat integration achieving 70-85% heat recovery.

Physical absorption processes provide alternatives for high-pressure applications. The Selexol process, utilizing dimethyl ethers of polyethylene glycol, operates at 300-2000 psia and -10 to 40°C, achieving >99% CO2 removal with energy consumption of 0.8-1.2 GJ/tonne CO2. The Rectisol process employs methanol at -30 to -80°C and 20-60 bar, delivering >99.5% CO2 removal but requiring significant refrigeration energy. Both processes benefit from pressure-driven regeneration rather than thermal regeneration, making them particularly suitable for pre-combustion applications.

Adsorption technologies represent an emerging class of capture systems with potentially lower energy requirements. Metal-Organic Frameworks (MOFs) demonstrate exceptional performance with surface areas of 1500-7000 m²/g and CO2 uptake reaching 33.5 mmol/g at 35 bar. The benchmark UTSA-16 MOF has shown superior post-combustion capture performance, while CALF-20 has achieved commercial breakthrough with >450,000 steam cycles durability. Zeolites offer proven reliability with CO2 adsorption capacities of 6.3-7.0 mmol/g for 13X and LiX variants respectively, operating through pressure swing (PSA), vacuum swing (VSA), or temperature swing (TSA) adsorption cycles.

Membrane separation technologies provide modular, energy-efficient alternatives. Polymeric membranes based on polyimides, cellulose acetate, and polysulfone achieve CO2 permeabilities of 1-1000 Barrer with CO2/N2 selectivities of 10-80. Ceramic membranes enable high-temperature operation up to 600°C with CO2 permeance of 10-100 GPU. Mixed matrix membranes combining polymers with inorganic fillers demonstrate 20-50% performance improvements over pure polymers, though challenges remain in achieving defect-free fabrication at commercial scale.

What Are The Primary Carbon Storage Methods?

Carbon storage involves four primary methods. Enhanced Oil Recovery (EOR) is the most commercially mature approach, injecting CO2 into oil fields to boost production while permanently storing 50-80% of the injected gas. Deep saline aquifers offer the largest global storage potential at 3,000-5,630 billion tonnes capacity, trapping CO2 through structural, residual, solubility, and mineral mechanisms at depths of 800-3,000 meters. Coal seam storage exploits coal’s preference for CO2 over methane, displacing natural gas for use while locking away 200-400 kg of CO2 per cubic meter of coal. Alternative methods include basalt formations that rapidly convert 90-95% of CO2 to solid minerals within 2 years, depleted gas fields that leverage existing infrastructure, and salt caverns with exceptional sealing properties. Each method offers unique advantages—from EOR’s revenue generation to saline aquifers’ massive capacity—with selection depending on local geology and economic factors.

Enhanced Oil Recovery With CO2

CO2-enhanced oil recovery represents the most commercially mature sequestration pathway, combining revenue generation with permanent storage. Miscible flooding occurs when reservoir pressure exceeds the minimum miscibility pressure (MMP), eliminating interfacial tension and achieving 90-92% oil recovery at 1.2 pore volumes of CO2 injection. Recent empirical correlations indicate MMP = 11.222 – 0.355(API) – 0.2069(T) + 0.039(molecular composition factors), with typical values ranging from 16.4-30.6 MPa for light crude to 35-50 MPa for heavy crude oils.

Net CO2 utilization rates average 0.3-0.5 tonnes CO2 per barrel of oil produced, with gross injection rates of 1.0-2.0 tonnes per barrel accounting for recycling. Importantly, 50-80% of injected CO2 remains permanently sequestered, with 60-80% of produced CO2 recycled through surface facilities. Miscible flooding achieves 8-20% additional recovery over secondary methods, while immiscible flooding delivers 5-12% incremental recovery, bringing total recovery factors to 35-50% of original oil in place.

Monitoring technologies have evolved significantly, with 4D seismic surveys conducted at 3-5 year intervals detecting CO2 volumes >1,000 tonnes to depths of 3,000m. Amplitude changes of 10-30% indicate CO2 saturation variations, requiring specialized processing workflows for time-lapse analysis. Chemical tracers including perfluorocarbons and sulfur hexafluoride enable detection at 10^-15 to 10^-12 parts per trillion concentrations, with typical inter-well breakthrough times of 100-300 days providing critical flow path information.

Deep Saline Aquifer Storage

Saline aquifers offer the largest global storage potential, estimated at 3,000-5,630 Gt CO2 under pressure-limited scenarios. Successful storage requires minimum effective porosity of 10-15%, with optimal conditions at 15-25% porosity. Permeability must exceed 10 mD (10^-14 m²) for viable injection, with good reservoirs exhibiting 100-1,000 mD and excellent formations exceeding 1,000 mD. Storage depths must exceed 800m to maintain supercritical CO2 conditions, with optimal depths of 1,000-3,000m balancing injectivity with drilling costs.

Cap rock integrity proves critical, requiring continuous seals of 10-20m thickness with permeabilities <10^-18 m² and capillary entry pressures >1-10 MPa. Four distinct trapping mechanisms operate on different timescales: structural trapping provides immediate containment but highest leakage risk, residual trapping immobilizes 10-30% of CO2 within 10-100 years through capillary forces, solubility trapping dissolves 5-15% over 100-1,000 years following Henry’s Law (C_CO2 = k_H × P_CO2), and mineral trapping converts 1-5% to solid carbonates over 1,000-10,000 years at rates of 0.01-0.1 mol/m²/year.

Injection well design follows petroleum industry standards with modifications for CO2 service. Typical completions include 20-24″ surface casing to 100-200m, 13-3/8″ intermediate casing to 500-1,000m, and 9-5/8″ production casing to target depth. Class G or H cement with CO2-resistant additives prevents degradation, while 13Cr or 22Cr stainless steel tubing resists corrosion. Injection rates of 0.1-2.0 million tonnes CO2 per year per well require 4-1/2″ to 7″ tubing with CO2-resistant elastomer packers and optimized perforation designs.

Pressure management limits injection to 80-90% of fracture pressure, calculated as P_frac = 0.7-1.0 × (σ_v + P_p). Pressure buildup follows ΔP = (Q×μ×B)/(2πkh) × ln(r_e/r_w), monitored continuously with downhole gauges. Plume migration modeling employs Darcy velocity calculations (v = k/μ × (dP/dx – ρg sin α)) with mechanical and molecular dispersion (D = α_L×v + D_m) using specialized simulators like ECLIPSE, CMG-GEM, or TOUGH2/ECO2N with 10-100m grid resolution for accurate tracking.

Coal Seam Storage & Enhanced Coalbed Methane Recovery

Coal seam storage leverages preferential CO2 adsorption following Langmuir isotherm behavior: V = V_L × (P/(P_L + P)), where V represents adsorbed gas volume, V_L is maximum capacity, P is pressure, and P_L is half-saturation pressure. CO2 adsorption capacities reach 15-25 m³/tonne at 5 MPa versus 10-15 m³/tonne for methane, with selectivity ratios of 2-10:1 enabling enhanced coalbed methane recovery. Storage densities achieve 200-400 kg CO2/m³ coal, storing 2-5 tonnes CO2 per tonne of methane produced.

Coal swelling presents the primary operational challenge, with volumetric expansion of 1-5% following Langmuir-type relationships (ε = ε_L × (P/(P_L + P))). Permeability reduction can reach 50-95%, following exponential (k/k_0 = exp(-α×ΔP)) or cubic (k/k_0 = ((φ-φ_c)/(φ_0-φ_c))³) models. Mitigation strategies include 10-30% N2 co-injection to reduce swelling, horizontal well deployment for improved reservoir contact, and staged injection for gradual pressure buildup. Injection pressures of 3-8 MPa support rates of 100-500 tonnes CO2/day per well, with 4-8 production wells per injection well achieving 50-90% recovery of original gas in place.

Alternative Storage Methods

Basalt formations offer rapid mineralization potential, converting 90-95% of injected CO2 to solid carbonates within 2 years through reactions like CO2 + CaSiO3 + H2O → CaCO3 + SiO2 + heat. Global storage capacity in ocean ridge basalts reaches 100,000-250,000 Gt CO2. The Carbfix project in Iceland demonstrates successful implementation, co-injecting CO2 with water at 1:25 ratios into vesicular basalts with 5-15% porosity at 400-1,500m depths and 20-70°C temperatures.

Depleted gas fields provide proven containment with existing infrastructure, storing 80-100% of original gas volumes at 70-80% of initial reservoir pressure. Injection rates of 1-10 million tonnes CO2/year benefit from existing well networks for monitoring. Salt caverns offer exceptional seal quality with permeabilities <10^-20 m², requiring only 30% cushion gas versus 50-80% for other methods. Typical cavern volumes of 300,000-500,000 m³ support 1-2 million tonnes CO2/year injection at 5-15 MPa with 80-90% storage efficiency.

Final Thoughts

Carbon capture and storage has progressed from conceptual technology to commercial reality, with over 50 operational facilities demonstrating technical feasibility across diverse applications. However, the analysis reveals consistent challenges: no major CCS project has achieved initial cost, schedule, and performance targets simultaneously. Current global capacity of ~50 Mt CO2/year must expand nearly 10-fold by 2030 and 100-fold by 2050 to meet climate objectives – growth rates historically achieved only by transformational technologies during periods of intense deployment.

From an engineering perspective, the technology foundations are sound. Post-combustion amine systems achieve 85-95% capture rates, pre-combustion physical solvents operate efficiently at scale, and geological storage has proven effective for millions of tonnes annually. Recent innovations in MOFs, electrochemical systems, and process intensification promise step-change improvements in energy efficiency and cost. The successful operation of projects like Quest and Northern Lights demonstrates that well-designed, purpose-built facilities can meet or exceed performance targets.

Yet significant challenges persist. Energy penalties remain substantial at 15-35% for conventional systems. Capital costs of $500-1,500 per tonne of annual capacity challenge project economics. Geological uncertainties, evidenced by Gorgon’s underperformance and Sleipner’s unexpected plume behavior, require adaptive management approaches. The economic dependence on carbon pricing or oil revenues creates vulnerability to policy changes and commodity cycles.

The path forward requires simultaneous advancement on multiple fronts. Continued technology development must reduce capture energy requirements below 2 GJ/tonne CO2 while achieving costs below $50/tonne for industrial applications. Standardization and modularization can reduce capital costs through manufacturing economies. Enhanced characterization methods and monitoring technologies will improve storage reliability and public confidence. Policy frameworks must provide long-term certainty through carbon pricing above $70/tonne, streamlined permitting, and clear liability frameworks.

The critical question is not whether CCS technologies work – operational projects prove they do – but whether deployment can accelerate sufficiently to contribute meaningfully to climate mitigation. Current trajectory suggests 0.4-0.5 Gt CO2/year by 2030, far below the 1.0 Gt required. Achieving necessary scales demands treating CCS as essential infrastructure comparable to historical deployments of railroads, electricity grids, or telecommunications networks. This requires coordinated action from governments, industry, and engineering communities to demonstrate, standardize, and rapidly replicate successful designs.

Carbon capture and storage stands at a critical juncture. The technology has proven feasible but must demonstrate economic viability at scale. Recent policy enhancements and technological innovations provide momentum, but deployment rates must accelerate dramatically. Success requires moving beyond individual demonstration projects to systematic deployment of standardized, optimized facilities. The engineering community’s ability to deliver reliable, cost-effective CCS systems will significantly influence whether this technology fulfills its potential contribution to climate mitigation. The next decade will determine whether CCS transitions from promising technology to essential climate solution, with engineering innovation and execution as the critical enabling factors.

References