Case study: Carbon capture materials (sorbents, membranes) — a pilot that failed (and what it taught us)

In 2024, Chevron's Gorgon project in Australia delivered its worst performance since commissioning: a mere 30% capture rate against an 80% design target, at a staggering cost of $222 per tonne CO₂—roughly four times the economically viable threshold for most industrial applications. This flagship liquefied natural gas facility, equipped with state-of-the-art amine sorbent technology and backed by $3.2 billion in remediation investments, exemplifies the systemic failures plaguing carbon capture material deployments worldwide. Meanwhile, the UK has committed £21.7 billion over 25 years to carbon capture, utilisation, and storage (CCUS) infrastructure, with the first Track-1 clusters reaching Financial Close in December 2024. For UK policymakers evaluating material technology choices—between ammonia-based sorbents, amine solutions, metal-organic frameworks (MOFs), and membrane systems—understanding why pilots fail is essential to avoiding the hidden bottlenecks that have derailed projects from Australia to Norway. This case study examines the implementation trade-offs, stakeholder incentives, and material science limitations that determine whether capture facilities meet their targets or become expensive monuments to misaligned expectations.

Why It Matters

The UK's CCUS ambitions rest on capturing 20 million tonnes of CO₂ annually by 2030—a target requiring deployment of capture materials across power generation, cement, steel, and hydrogen production facilities. The October 2024 funding announcement allocated £3.9 billion for 2025–2026 alone, significantly exceeding the 25-year average of £880 million annually. This front-loaded investment creates intense pressure to select capture materials that will perform reliably at scale.

The material technology landscape presents UK project developers with fundamentally different risk profiles. Amine-based liquid solvents remain the dominant commercial technology, capturing approximately 85–95% of flue gas CO₂ at concentrations above 10%. However, these systems require substantial thermal energy for solvent regeneration—typically reducing power plant efficiency by 8–12 percentage points—and suffer from degradation in the presence of oxygen, sulphur compounds, and particulates common in industrial exhaust streams.

Solid sorbents, including ammonia-functionalised materials and MOFs, promise lower regeneration energy through temperature-swing adsorption rather than chemical absorption. Yet the transition from laboratory performance to operational reality has proven treacherous. Research published in 2024 demonstrated that CO₂ itself plays a dual role in sorbent degradation: catalysing oxidation reactions while simultaneously reducing polymer mobility. This finding undermines assumptions used in lifetime cost projections and explains why sorbent replacement cycles have consistently exceeded budgeted frequencies.

Membrane systems offer a third pathway, separating CO₂ through selective permeation rather than chemical reaction. The Wyoming Integrated Test Center achieved 90% recovery at 99.9% purity using Polaris™ membranes in 2024, demonstrating technical viability. However, membrane performance degrades sharply at CO₂ concentrations below 10%—precisely the conditions found in marine applications and low-concentration industrial sources that comprise a significant portion of UK emissions.

For UK infrastructure clusters—HyNet in the North West and the East Coast Cluster spanning Teesside and Humber—material selection will determine whether the £4 billion Net Zero Teesside project and the £2 billion Drax BECCS facility deliver on their combined 8.5 million tonne annual capture targets. The contingent liabilities assessed by HM Treasury range from £14.3 billion to £44.15 billion, reflecting the substantial downside risk if material technologies underperform.

Key Concepts

Ammonia Slip and Volatility Management: Ammonia-based carbon capture systems exploit ammonia's high theoretical CO₂ loading capacity—significantly greater than monoethanolamine (MEA) at equivalent concentrations—while offering lower regeneration energy requirements. However, ammonia's high vapour pressure creates persistent "slip" problems: ammonia escapes into both the treated flue gas stream and the concentrated CO₂ product stream, requiring extensive washing operations. The 2024 ScienceDirect review identified ammonia slip as the primary barrier to commercial deployment, noting that washing systems add 15–25% to capital costs while consuming additional energy that erodes the regeneration advantage. For UK facilities subject to Industrial Emissions Directive limits, ammonia slip concentrations exceeding 10 ppm trigger regulatory intervention—a threshold easily breached without sophisticated emission controls.

Sorbent Degradation Mechanisms: All capture materials degrade over operational cycles, but the mechanisms differ substantially between technology classes. Amine solvents suffer oxidative degradation producing corrosive acids and volatile organic compounds, requiring continuous solvent makeup at 0.5–2.0 kg per tonne CO₂ captured. Solid sorbents experience pore blockage, surface area reduction, and chemical transformation of active sites. Lawrence Livermore National Laboratory's September 2024 research revealed that temperature cycling accelerates chain scission in polymer-based sorbents, with CO₂-induced rigidity initially slowing degradation before ultimately promoting brittle failure. Membrane materials face plasticisation at high CO₂ partial pressures, losing selectivity as polymer chains become more mobile. Understanding these degradation pathways is essential for accurate lifecycle costing: a sorbent rated for 10,000 cycles in laboratory conditions may fail after 3,000 cycles in contaminated industrial streams.

Technology Readiness Level (TRL) Transition Risks: Carbon capture materials exhibit pronounced performance gaps between TRL 4–5 (laboratory validation) and TRL 7–8 (demonstration at scale). The US Department of Energy's 2024 pilot programme documented that equipment sourcing and cost estimation represent the primary failure modes during this transition. Laboratory tests use synthetic gas mixtures with controlled temperature, humidity, and contaminant profiles; operational environments introduce particulates, trace metals, varying flow rates, and unplanned shutdowns that stress materials beyond their design envelopes. The January 2026 termination of 223 DOE carbon capture projects underscores how few technologies successfully navigate this transition.

Energy Penalty and Parasitic Load: Carbon capture systems consume energy that would otherwise generate electricity or produce industrial output—the "energy penalty" or "parasitic load." For amine scrubbing, thermal regeneration energy dominates, requiring 2.5–4.0 GJ per tonne CO₂ depending on solvent formulation and stripper configuration. Solid sorbent systems using temperature-swing adsorption require less thermal energy (1.0–2.5 GJ/tonne) but face heat transfer limitations in packed beds. Membrane systems operate on pressure differentials, with electrical energy consumption of 360–500 kWh per tonne CO₂. The Drax BECCS project, for instance, will consume approximately 28% of each unit's gross energy output for carbon capture operations—a parasitic load that reduces saleable electricity and affects project economics profoundly.

What's Working and What Isn't

What's Working

Metal-Organic Framework Manufacturing Scale-Up: Svante's May 2025 launch of the world's first carbon capture filter gigafactory in Burnaby, British Columbia, represents a manufacturing breakthrough. The 141,000 square foot facility produces structured adsorbent beds using MOF materials supplied by BASF under commercial agreement, with capacity to manufacture filters capturing 10 million tonnes of CO₂ annually. The VeloxoTherm™ process achieves capture-release cycles in under 60 seconds—dramatically faster than competing solid sorbent systems—while delivering 95% pipeline-grade CO₂ suitable for geological storage or industrial utilisation. Strategic partnerships with Chevron, Climeworks, Samsung E&A, and Technip Energies provide diverse market access.

Modular Deployment Architectures: UK-based Carbon Clean has demonstrated that modular, mass-producible capture units can reduce capital costs for smaller emitters. Their proprietary solvent systems capture up to 95% of flue gas CO₂ in containerised modules suitable for cement works, refineries, and waste-to-energy facilities. This approach sidesteps the integration challenges that plagued first-generation mega-projects, enabling staged deployment that matches capture capacity to evolving regulatory requirements.

AI-Accelerated Sorbent Design: Orbital Materials is piloting AI-designed MOF sorbents at Civo's UK data centre in 2025, using machine learning to optimise pore geometry, surface chemistry, and thermal stability simultaneously. Traditional sorbent development cycles span 5–10 years from synthesis to commercial deployment; AI-guided design compresses this timeline substantially while exploring chemical spaces beyond human intuition.

Membrane Performance at High Concentrations: The US Department of Energy awarded FEED contracts for a 3 million tonne per year membrane facility at Wyoming's Integrated Test Center following successful 150 tonne-per-day pilot operations. For high-concentration CO₂ sources—hydrogen production, ammonia synthesis, natural gas processing—membranes achieve lower energy penalties than absorption-based alternatives, with demonstrated capture costs below $50 per tonne in favourable configurations.

What Isn't Working

Amine Sorbent Reliability at Scale: The Gorgon project's 2024 performance collapse—30% capture versus 80% design target—stemmed from reservoir pressure problems, sand clogging, and water management failures that amine sorbent specifications never anticipated. Despite $3.2 billion in remediation expenditure, fundamental equipment incompatibilities persist. Similarly, Boundary Dam's 2021–2022 shutdown resulted from manufacturing defects in CO₂ compressors that required multi-year replacement programmes. These failures demonstrate that sorbent performance depends on upstream and downstream equipment quality as much as intrinsic material properties.

Monitoring and Verification Accuracy: Norway's Sleipner project, often cited as carbon capture's success story, revealed systematic over-reporting in 2024: actual captured volumes were 28% below claimed figures due to defective monitoring systems. Only 106,000 tonnes were verified captured in 2023 against claims approaching 1 million tonnes. The project has not achieved design capture rates since 2001 and faces expected closure as the underlying gas field depletes. For UK projects requiring verified carbon credits or emissions compliance, monitoring uncertainty introduces financial risks beyond material performance.

Ammonia-Based Systems' Solid Precipitation: Low solubility of ammonium bicarbonate in ammonia capture systems causes solid formation in absorber columns, forcing operators to transport rich absorbent as slurry rather than liquid. This precipitation clogs equipment, reduces throughput, and necessitates specialised handling systems that increase both capital and operational expenditure. The constraint forces use of dilute ammonia solutions, sacrificing theoretical loading advantages.

Membrane Performance at Low Concentrations: Marine carbon capture applications—essential for decarbonising shipping emissions—cannot deploy membrane systems because CO₂ concentrations in ship exhaust (4–8%) fall below the threshold required for economically viable membrane separation. The 2024 MARAD technical assessment explicitly excluded membranes from marine applications, limiting their addressable market and concentrating deployment on industrial point sources with >10% CO₂ concentrations.

Key Players

Established Leaders

Drax Group plc — Operates the UK's largest single-site power station and is developing the £2 billion BECCS project with carbon capture equipment to be operational from 2027. The project faces legal challenges from Biofuelwatch UK regarding environmental impact assessment procedures and ongoing Ofgem investigation into biomass sustainability compliance. Despite controversies, Drax represents the largest committed UK BECCS investment.

Carbon Clean — UK-headquartered developer of proprietary solvent-based capture systems with £213.6 million in total funding. Their modular CycloneCC technology targets small-to-medium emitters excluded from megaproject economics. Deployments span cement, steel, and waste-to-energy applications across Europe and Asia.

Svante Technologies — Canadian MOF technology leader with £600 million total funding including Series E led by Chevron. The Redwood Gigafactory supplies structured adsorbent filters to Climeworks for DAC applications and industrial emitters globally. Board includes Steven Chu, Nobel Laureate and former US Secretary of Energy.

Shell UK — Partner in the Acorn project (Aberdeenshire) targeting 5 million tonnes CO₂ per year by 2030 through North Sea storage infrastructure. Leverages depleted oil and gas reservoirs for geological sequestration with established pipeline access.

bp — Lead developer of Net Zero Teesside, the UK's first Track-1 cluster project reaching Financial Close in December 2024. The £4 billion natural gas power plant with integrated capture targets 8.5 million tonnes CO₂ capacity, with construction commencing mid-2025.

Emerging Startups

Mission Zero Technologies (Norfolk, UK) — Opened direct air capture facility in April 2024 converting atmospheric CO₂ to limestone building materials. Raised £27.6 million Series A led by 2150 with participation from Fortescue, Siemens, and Breakthrough Energy Ventures. Integrates mineralisation into capture process, creating permanent storage.

Airhive (UK) — Develops mineral-based solid sorbents using fluidised reactor technology, achieving CO₂ capture in under 0.1 seconds on 100% renewable energy. Pre-seed funding from AP Ventures and Coca-Cola Europacific Partners in March 2024 supports pilot deployment at Coca-Cola bottling facilities.

Orbital Materials (UK) — Uses proprietary AI to design optimised MOF sorbents for warm-air capture applications. Piloting technology at Civo data centre in the UK through 2025, targeting the growing emissions from hyperscale computing infrastructure.

CyanoCapture (UK) — Biological capture approach using photosynthetic bacteria (Synechococcus) to absorb CO₂ without chemical sorbents or thermal regeneration. Offers pathway to combined capture and biofuel production, though scalability remains under development.

Key Investors & Funders

UK Research and Innovation (UKRI) — Principal public funder of UK carbon capture research through the Industrial Decarbonisation Research and Innovation Centre (IDRIC). Provides £50+ million annually for capture material development and pilot demonstration programmes.

Breakthrough Energy Ventures — Bill Gates-backed climate technology investor with portfolio companies spanning DAC, point-source capture, and carbon mineralisation. Co-invested in Mission Zero Technologies and maintains active carbon capture deal pipeline.

Chevron New Energies — Strategic investor in Svante ($318 million Series E lead) with operational pilot at Kern River facility in California. Represents oil and gas sector pivot toward carbon management as transition strategy.

Canada Growth Fund & UK Infrastructure Bank — Public investment vehicles providing patient capital for capital-intensive capture projects. The UK Infrastructure Bank has £22 billion deployment mandate with net zero infrastructure as priority sector.

Examples

1. Gorgon LNG Carbon Capture System — The $3.2 Billion Remediation

Chevron's Gorgon project in Western Australia commenced operations in 2016 as the world's largest geological carbon storage facility, designed to capture 4 million tonnes CO₂ annually from natural gas processing using amine sorbent technology. The $54 billion LNG facility included $2.5 billion for carbon capture and injection systems.

By 2024, cumulative performance failures had consumed an additional $3.2 billion in remediation costs. The capture rate collapsed to 30%—the project's worst year—against the 80% regulatory commitment. Root causes included reservoir pressure buildup preventing injection, sand clogging in wellhead equipment, and water management systems unable to handle formation fluids. The amine sorbent system performed to specification; the failure lay in inadequate geological characterisation and equipment specification for actual subsurface conditions.

The lesson for UK policymakers: sorbent technology selection cannot be evaluated independently from storage infrastructure. The East Coast Cluster's reliance on depleted North Sea reservoirs with established pressure regimes may avoid Gorgon's specific failure mode, but integrated system validation—not component testing—determines project success.

2. Drax BECCS Pilot — 27 Tonnes Versus 13 Million

Drax's biomass power station near Selby, Yorkshire, conducted pilot carbon capture trials demonstrating capture of 27 tonnes CO₂ over 90 days using amine solvent technology adapted for biomass flue gas. The station emits approximately 13 million tonnes CO₂ annually—meaning the pilot captured 0.0002% of annual emissions.

The January 2024 government approval for the full £2 billion BECCS project immediately attracted legal challenge from Biofuelwatch UK, arguing that Environmental Impact Assessment procedures failed to account for supply chain emissions (harvesting, pellet production, transatlantic shipping) and that biomass combustion flue gases differ substantially from the coal and gas streams for which amine solvents were optimised. The captured CO₂ requires transport infrastructure assessed separately from the main project—a regulatory segmentation critics argue obscures cumulative environmental impacts.

For UK policy, Drax illustrates the stakeholder incentive misalignments that complicate capture material evaluation. The project's economics depend on continued subsidy access beyond 2027 when current renewable obligation certificates expire; critics argue subsidy capture, not carbon capture, drives project design. The 28% energy penalty from capture operations reduces saleable electricity, affecting grid economics and potentially increasing fossil gas dispatch to compensate.

3. Sleipner Monitoring Failure — The Verification Gap

Norway's Sleipner project, operational since 1996, has been cited as carbon capture's proof of concept, with claimed storage of 1 million tonnes CO₂ annually in the Utsira saline formation. However, 2024 auditing revealed systematic monitoring failures: only 106,000 tonnes were verified captured in 2023—28% below official claims—due to defective measurement equipment and calibration drift.

Analysis indicated that Sleipner has not achieved its design capture rate since 2001. The project faces closure as the underlying Sleipner gas field depletes, leaving verification uncertainties that undermine confidence in long-term storage permanence claims.

For UK projects requiring certified emissions reductions for compliance or carbon market participation, Sleipner demonstrates that capture material performance metrics mean nothing without robust monitoring, reporting, and verification (MRV) infrastructure. The Track-1 clusters must invest in independent verification systems from project inception rather than discovering calibration failures decades into operation.

Action Checklist

• Commission integrated system validation: Avoid component-level testing in isolation. Require technology providers to demonstrate capture materials under actual flue gas conditions including particulates, trace contaminants, humidity, and temperature variations representative of UK industrial sources.

• Establish degradation monitoring protocols: Implement real-time sorbent performance tracking using online analysers for CO₂ capture efficiency, pressure drop across beds, and regeneration energy consumption. Set intervention thresholds that trigger maintenance before catastrophic failure.

• Validate storage reservoir compatibility: For projects relying on geological sequestration, require independent geological assessment of injection zone capacity, pressure management requirements, and potential well interference before finalising capture material specifications.

• Budget for realistic sorbent replacement cycles: Laboratory cycle ratings typically overstate operational lifetime by 2–3x. Financial models should assume 3,000–5,000 effective cycles rather than manufacturer claims of 10,000+ cycles.

• Assess regulatory exposure from ammonia slip: For ammonia-based systems, model emission scenarios against Industrial Emissions Directive limits and local authority permit conditions. Incorporate washing system costs and potential non-compliance penalties into project economics.

• Require independent MRV infrastructure: Specify third-party monitoring and verification systems separate from operator-provided instrumentation. The Sleipner experience demonstrates that operator self-reporting introduces systematic bias that compounds over project lifetime.

FAQ

Q: Why have so many high-profile carbon capture pilots failed to meet their targets despite mature sorbent technology?

A: Sorbent performance represents only one element of integrated capture systems. Gorgon's failure stemmed from reservoir pressure and equipment issues rather than amine chemistry; Boundary Dam experienced compressor manufacturing defects unrelated to solvent performance; Sleipner's monitoring failures masked underperformance for decades. Successful projects require integrated validation spanning capture materials, compression, transport, injection, and monitoring—not optimisation of individual components. UK projects should mandate system-level performance guarantees rather than material specifications.

Q: What are the hidden costs that cause ammonia-based capture systems to underperform their theoretical advantages?

A: Ammonia's high CO₂ loading capacity and lower regeneration energy create theoretical cost advantages over MEA-based systems. However, operational reality introduces countervailing costs: ammonia slip requires extensive washing systems adding 15–25% to capital expenditure; solid precipitation of ammonium bicarbonate necessitates slurry handling equipment and constrains absorber design; regulatory compliance with ammonia emission limits requires continuous monitoring and potential permit modifications. Projects should model these operational costs using demonstrated pilot data rather than theoretical equilibrium calculations.

Q: How should UK policymakers evaluate the trade-offs between liquid solvents, solid sorbents, and membrane systems for specific applications?

A: Application-specific CO₂ concentration determines the viable technology set. For high-concentration sources (>20% CO₂)—hydrogen production, ammonia synthesis, natural gas processing—membranes offer lowest energy penalty and capital costs. For medium-concentration sources (10–20% CO₂)—cement, steel, gas-fired power—amine solvents provide proven performance despite higher energy requirements. For low-concentration sources (<10% CO₂)—shipping, ambient air, low-efficiency combustion—only solid sorbents and advanced solvents remain viable, with MOF-based systems showing strongest recent development. Mixing technologies within clusters enables optimisation across diverse emission sources.

Q: What monitoring and verification standards should Track-1 clusters implement to avoid Sleipner-style reporting failures?

A: Independent third-party verification using multiple measurement methodologies provides the only robust defence against systematic monitoring errors. Clusters should deploy both direct measurement (mass flow meters, composition analysers) and indirect verification (pressure-volume analysis, seismic monitoring of storage formations). Calibration protocols must specify frequency, reference standards, and acceptable drift ranges. Annual independent audits comparing operator-reported volumes against third-party verification should be contractually required, with financial penalties for discrepancies exceeding defined tolerances.

Sources

• IEA. (2024). "CCUS Projects Around the World Are Reaching New Milestones." International Energy Agency Commentary.

• Clean Air Task Force. (2024). "UK's £21.7 Billion Funding for Carbon Capture and Storage Projects." CATF Analysis.

• ScienceDirect. (2024). "Enhancement Technologies of Ammonia-Based Carbon Capture: A Review of Developments and Challenges." International Journal of Greenhouse Gas Control.

• Lawrence Livermore National Laboratory. (2024). "New Research Could Extend the Lifetime of Key Carbon-Capture Materials." LLNL Research Findings.

• US Department of Energy. (2024). "Carbon Capture Large-Scale Pilot Projects: Programme Status Report." Office of Clean Energy Demonstrations.

• HM Treasury. (2024). "CCUS Contingent Liability Assessment: Fiscal Risk Analysis." UK Government Publication.

• Biofuelwatch UK. (2024). "Legal Challenge to Drax Power Station BECCS Development Consent Order." High Court Filing Documentation.

• Ember. (2024). "Drax: UK's Largest Single-Site Carbon Emitter Analysis." Ember Climate Think Tank.