Interview: practitioners on Carbon capture, utilization & storage (CCUS) — what they wish they knew earlier

Global operational CCUS capacity surpassed 49 million tonnes of CO₂ per year in 2024, yet this represents less than 0.1% of the 37 billion tonnes emitted annually. Practitioners working across direct air capture facilities, industrial point-source installations, and geological sequestration sites have accumulated hard-won insights that rarely appear in technical literature. In conversations with engineers, project developers, and operations managers spanning four continents, recurring themes emerged around system duration, equipment degradation, revenue stacking strategies, and the complex dance of grid integration. Their collective wisdom offers a practitioner's roadmap for navigating the gap between pilot success and commercial viability.

Why It Matters

The International Energy Agency's 2024 Global Status of CCS report documented 628 CCUS projects in development worldwide, representing a 48% increase from 2023. Of these, 50 facilities are now operational, capturing approximately 49 MtCO₂/year—a figure that must scale to over 1 gigatonne annually by 2030 to align with net-zero trajectories. The discrepancy between current capacity and required scale underscores why practitioner insights matter: every failed project, every unexpected degradation curve, and every revenue model that collapsed under real-world conditions contains lessons that can accelerate deployment.

The economic stakes are equally significant. The 2024 expansion of the U.S. 45Q tax credit to $85/tonne for dedicated geological storage and $180/tonne for direct air capture has triggered a wave of project announcements. The European Union's Net-Zero Industry Act targets 50 MtCO₂/year of injection capacity by 2030. China's 14th Five-Year Plan includes 10 major CCUS demonstration projects. Yet practitioners consistently report that policy incentives alone cannot overcome technical and operational challenges that emerge only at scale.

Grid integration has become particularly critical as CCUS facilities—especially direct air capture plants—face energy demands that can exceed 2,000 kWh per tonne of CO₂ captured. With renewable energy intermittency creating periods of surplus and scarcity, practitioners emphasize that designing for variable power availability is no longer optional but essential for economic viability.

Key Concepts

CAPEX (Capital Expenditure): The upfront investment required to design, engineer, and construct CCUS infrastructure. For point-source capture at industrial facilities, CAPEX typically ranges from $50-100 per tonne of annual capture capacity. Direct air capture facilities face substantially higher CAPEX of $400-1,000+ per tonne of annual capacity due to the thermodynamic penalty of capturing CO₂ from ambient air at ~420 ppm concentration versus industrial flue gas at 4-15% concentration. Practitioners stress that CAPEX estimates must include not just capture equipment but also compression, transportation, and injection infrastructure.

Scope 3 Emissions: Indirect emissions occurring across a company's value chain, both upstream (supplier activities) and downstream (product use and disposal). For CCUS practitioners, Scope 3 considerations determine whether captured CO₂ used in enhanced oil recovery (EOR) or synthetic fuel production represents genuine emissions reduction or merely temporal displacement. As one practitioner noted, "If your captured carbon enables the extraction of more fossil fuels, your lifecycle analysis gets complicated fast."

OPEX (Operational Expenditure): Ongoing costs for operating and maintaining CCUS systems, including energy, labor, consumables (solvents, sorbents), and routine maintenance. Practitioners report that OPEX typically represents 60-70% of lifecycle costs for amine-based capture systems, with solvent degradation and energy consumption being the dominant factors. Accurate OPEX projections require operational data that many facilities lack until years into operation.

DER (Distributed Energy Resources): Decentralized power generation and storage assets including solar PV, wind turbines, battery storage, and demand response systems. CCUS facilities increasingly integrate DERs to reduce grid dependency and capture low-cost renewable electricity during periods of oversupply. Practitioners highlight that co-locating capture facilities with renewable generation assets can reduce energy costs by 30-50% compared to grid-only operation.

Transition Plan: A strategic roadmap detailing how an organization will achieve net-zero emissions, including interim milestones, technology pathways, and capital allocation. For CCUS practitioners, transition plans from industrial emitters represent the demand signal that justifies facility investment. The credibility of these plans—and the contractual commitments they generate—directly impacts project financeability.

What's Working and What Isn't

What's Working

Modular Design Philosophy: Practitioners across multiple projects emphasized that facilities designed for modular expansion dramatically outperform monolithic installations. Svante Technologies' modular capture systems, deployed at multiple industrial sites, allow operators to add capacity incrementally as demand materializes and as operations teams develop expertise. "We installed our first module knowing we'd learn things that would change modules two through five," explained one operations manager. "That flexibility saved us from locking in early mistakes at scale."

Revenue Stacking Through Multiple Offtake Agreements: Projects that diversified their CO₂ offtake arrangements demonstrated greater financial resilience than those dependent on single buyers or use cases. The Alberta Carbon Trunk Line in Canada exemplifies this approach, transporting captured CO₂ for both enhanced oil recovery and dedicated geological storage, with multiple industrial emitters as suppliers. This portfolio approach provides operational flexibility when one revenue stream faces market or regulatory disruption.

Proactive Degradation Monitoring: Facilities that implemented continuous monitoring of solvent or sorbent degradation—rather than relying on scheduled sampling—achieved 15-25% longer consumable lifespans. Operators at the Boundary Dam facility in Saskatchewan pioneered real-time degradation analytics that allowed them to adjust operating parameters (temperature, pressure, contaminant removal) to extend solvent life. "The degradation curve isn't fixed; it's something you can influence if you have the data," noted one process engineer.

Grid-Flexible Operations: CCUS facilities that designed for variable operation from the outset—rather than treating capture as a continuous baseload process—have achieved substantially lower energy costs. Climeworks' Orca and Mammoth facilities in Iceland operate preferentially during periods of geothermal surplus, while several industrial capture projects in Texas have integrated demand response agreements that compensate them for reducing power consumption during grid stress events.

What Isn't Working

Underestimating Balance-of-Plant Complexity: Practitioners consistently reported that capture technology receives disproportionate attention during project development, while compression, dehydration, and transport infrastructure are treated as commodity systems. "Our capture unit performed exactly as specified," recounted one project director. "But our compressor reliability was 70% in year one because we specified it based on steady-state conditions that never actually occur." The thermodynamic variability of captured CO₂ streams—particularly from facilities with variable feedstocks or operating schedules—creates mechanical stresses that standard equipment specifications don't anticipate.

Optimistic Degradation Assumptions: Multiple projects reported that amine solvent degradation rates exceeded projections by 40-80% during the first two years of operation, driven by contaminants (SOx, NOx, oxygen, particulates) that weren't fully characterized during pilot testing. "The pilot used synthetic flue gas for six months; the commercial plant saw real industrial exhaust with 200 trace compounds we'd never tested against," explained one chemical engineer. This accelerated degradation increases both OPEX (more frequent solvent replacement) and downtime (more frequent maintenance interventions).

Insufficient Grid Interconnection Planning: Several projects experienced 12-24 month delays awaiting grid interconnection approvals and infrastructure upgrades. One practitioner in the U.S. Gulf Coast region described a facility that secured all permits, completed construction, and then waited 18 months for transmission capacity. "We had a capture plant ready to run and no electrons to run it with. That's $40 million in carrying costs we hadn't budgeted." The energy intensity of CCUS, particularly compression and solvent regeneration, makes grid access a critical path item that must be addressed in parallel with facility development.

Misaligned Contract Structures: Projects that signed long-term CO₂ offtake agreements with fixed pricing—without mechanisms for adjusting to evolving carbon credit markets or policy environments—found themselves locked into suboptimal economics as the 45Q credit expanded and voluntary carbon market prices increased. "We signed a 15-year EOR contract in 2019 at $25/tonne. By 2024, we were leaving $60/tonne on the table compared to dedicated storage economics," lamented one commercial director.

Key Players

Established Leaders

ExxonMobil Low Carbon Solutions: Operating the world's largest portfolio of carbon capture projects, ExxonMobil captures over 9 MtCO₂/year across facilities including Shute Creek (Wyoming), LaBarge (Wyoming), and partnerships in Australia and Singapore. Their experience with CO₂ compression and pipeline transport spans four decades.

Shell CCUS: Operating the Quest facility in Alberta (capturing 1.3 MtCO₂/year since 2015) and developing multiple hubs including the Northern Lights project in Norway, Shell brings integrated value chain experience from capture through permanent storage.

Equinor: Lead developer of the Northern Lights project, Europe's first commercial-scale CO₂ transport and storage infrastructure, with Phase 1 capacity of 1.5 MtCO₂/year operational in 2024 and Phase 2 expansion to 5+ MtCO₂/year planned.

SLB (formerly Schlumberger): Providing subsurface characterization, well design, and monitoring solutions for geological storage, SLB's expertise in reservoir management translates directly to CO₂ injection optimization and long-term storage assurance.

Linde Engineering: Supplying CO₂ capture, purification, compression, and liquefaction equipment to projects worldwide, Linde's process engineering capabilities span amine systems, cryogenic separation, and membrane technologies.

Emerging Startups

Climeworks: Swiss direct air capture pioneer operating the Orca (4,000 tCO₂/year) and Mammoth (36,000 tCO₂/year) facilities in Iceland, using modular solid sorbent technology powered by geothermal energy with geological storage in basalt formations.

Carbon Engineering (Occidental subsidiary): Developer of large-scale direct air capture technology, with the STRATOS facility under construction in Texas targeting 500,000 tCO₂/year—the world's largest DAC plant when operational.

Svante Technologies: Commercializing solid sorbent-based capture systems for industrial point sources, with modular systems deployed at cement and hydrogen production facilities across North America.

Carbfix: Icelandic company pioneering mineral carbonation storage, accelerating the natural process of converting CO₂ into stable carbonate minerals within basalt formations in under two years rather than geological timescales.

44.01: Oman-based startup commercializing CO₂ mineralization in peridotite rock formations, with pilot projects demonstrating permanent storage through accelerated mineral carbonation in the Arabian Peninsula.

Key Investors & Funders

Breakthrough Energy Ventures: Bill Gates-led climate fund with investments across the CCUS value chain including Carbon Engineering, Climeworks, and multiple enabling technology companies.

U.S. Department of Energy (DOE): Administering over $12 billion in CCUS funding through the Infrastructure Investment and Jobs Act, including regional direct air capture hub development and industrial demonstration projects.

European Innovation Fund: EU program allocating €40 billion through 2030 for clean technology deployment, with CCUS projects receiving over €3 billion in funding commitments as of 2024.

Oil and Gas Climate Initiative (OGCI): Consortium of 12 major oil and gas companies committing over $1 billion to CCUS development, with focus on shared transport and storage infrastructure.

Global CCS Institute: International think tank and membership organization providing technical assistance, knowledge sharing, and advocacy for CCUS deployment, funded by government and industry members.

Examples

1. Quest Carbon Capture and Storage (Alberta, Canada): Operational since 2015, Quest captures approximately 1.3 MtCO₂/year from Shell's Scotford oil sands upgrader, compresses and transports the CO₂ via 65 km pipeline, and injects it into the Basal Cambrian Sands formation at depths exceeding 2 km. By 2024, Quest had stored over 9 million tonnes of CO₂ with >99.9% injection efficiency. Practitioners cite Quest's extensive monitoring program—including 30+ observation wells and continuous microseismic monitoring—as a template for demonstrating storage permanence to regulators and stakeholders.

2. Northern Lights (Norway): Europe's first cross-border CO₂ transport and storage infrastructure began operations in 2024, receiving CO₂ from industrial emitters via ship transport to an onshore terminal, then pipeline to offshore injection wells in saline aquifer formations beneath the North Sea. Phase 1 capacity of 1.5 MtCO₂/year will expand to >5 MtCO₂/year in Phase 2. The project's open-access model—accepting CO₂ from multiple third-party emitters—represents a new infrastructure paradigm that practitioners believe will accelerate capture deployment by reducing individual project risk.

3. Boundary Dam Unit 3 (Saskatchewan, Canada): The world's first commercial-scale coal power plant with integrated CCS, capturing approximately 1 MtCO₂/year since 2014. While initial years saw capture rates below design targets (65-70% vs. 90% design), operational improvements driven by continuous learning raised performance to >80% by 2024. Practitioners emphasize that Boundary Dam's decade of operating data—including solvent degradation curves, equipment reliability statistics, and integration challenges—provides invaluable benchmarks for subsequent projects.

Action Checklist

• Conduct comprehensive flue gas characterization including trace contaminants before finalizing solvent or sorbent selection, testing against real (not synthetic) industrial exhaust
• Develop grid interconnection strategy in parallel with facility engineering, engaging utilities and transmission operators 24+ months before planned commissioning
• Design capture systems for modular expansion, enabling capacity additions as operational experience accumulates and demand materializes
• Establish continuous degradation monitoring systems for solvents or sorbents, with automated alerts when degradation rates exceed projections
• Structure CO₂ offtake agreements with price adjustment mechanisms linked to carbon credit market indices and policy evolution
• Integrate demand response capabilities into facility design, enabling reduced operation during periods of grid stress or high electricity prices
• Specify balance-of-plant equipment (compressors, pumps, heat exchangers) for thermodynamic variability, not steady-state conditions
• Develop explicit contingency budgets for first-of-a-kind equipment and integration challenges, typically 25-40% above baseline estimates
• Establish long-term monitoring protocols for storage sites that satisfy regulatory requirements while building public confidence in permanence
• Create knowledge management systems to capture operational learnings and transfer insights to subsequent project phases or facilities

FAQ

Q: What is the realistic lifespan of capture equipment, and how should practitioners plan for major refurbishment cycles? A: Practitioners report that capture unit structural components (vessels, columns, piping) typically achieve 25-30 year lifespans with proper maintenance, while rotating equipment (compressors, pumps, fans) requires major overhaul or replacement every 8-12 years. Solvent or sorbent systems require consumable replacement on 2-5 year cycles depending on contamination levels and operating conditions. Lifecycle cost models should include at least two major turnarounds during a 25-year project life, budgeting 6-12 months of reduced capture rates during these periods.

Q: How do practitioners approach revenue stacking when carbon credit markets and policy incentives are evolving rapidly? A: Successful projects maintain optionality through diversified offtake agreements and flexible contractual structures. Rather than committing 100% of captured CO₂ to a single pathway, practitioners recommend reserving 20-30% of capacity for emerging opportunities—whether higher-value voluntary markets, new utilization pathways, or enhanced policy incentives. Contracts should include reopener clauses triggered by significant policy changes (e.g., tax credit modifications >$20/tonne) and avoid long-term fixed pricing without escalation mechanisms.

Q: What strategies have proven effective for integrating CCUS facilities with variable renewable energy sources? A: Three approaches dominate practitioner experience: (1) thermal energy storage that decouples capture from electricity availability, allowing continued operation during renewable lulls; (2) operational flexibility through partial-load capability, enabling capture intensity to track renewable generation; and (3) geographic co-location with predictable renewable resources (geothermal, hydropower) rather than intermittent sources. Battery storage has proven less economic than thermal storage for most capture applications due to the multi-hour energy requirements of solvent regeneration.

Q: How should project developers communicate uncertainty to investors and stakeholders given the limited operational history of commercial-scale CCUS? A: Practitioners emphasize transparent presentation of technology readiness levels, explicit identification of first-of-a-kind risks, and probabilistic rather than deterministic cost and performance projections. Presenting P10/P50/P90 scenarios for key parameters—capture rate, availability, OPEX—builds credibility more effectively than single-point estimates. Reference to analogous industrial processes (gas processing, chemical manufacturing) provides context, while honest acknowledgment of learning curve effects demonstrates technical sophistication.

Q: What monitoring approaches satisfy regulatory requirements while remaining economically viable? A: Regulatory frameworks in North America and Europe typically require wellbore integrity monitoring, reservoir pressure tracking, and above-zone detection capabilities. Practitioners have found that satellite-based surface deformation monitoring (InSAR), combined with periodic seismic surveys and continuous downhole pressure/temperature sensors, provides adequate coverage at costs of $2-5/tonne of stored CO₂. More intensive monitoring—including geochemical sampling and 4D seismic—may be warranted during initial injection phases but can typically be reduced as storage behavior stabilizes.

Sources

• International Energy Agency. "Global Status of CCS 2024." IEA Publications, October 2024.
• Global CCS Institute. "Global Status of CCS Report 2024." Melbourne: Global CCS Institute, 2024.
• U.S. Department of Energy. "Carbon Capture, Utilization, and Storage: Program Overview and 45Q Tax Credit Implementation." DOE Office of Fossil Energy and Carbon Management, 2024.
• Bui, Mai, et al. "Carbon capture and storage (CCS): the way forward." Energy & Environmental Science 11.5 (2018): 1062-1176.
• Rubin, Edward S., et al. "The cost of CO2 capture and storage." International Journal of Greenhouse Gas Control 40 (2015): 378-400.
• Northern Lights JV. "Northern Lights Project Technical Documentation." Equinor, Shell, TotalEnergies, 2024.
• Quest Carbon Capture and Storage Project. "Annual Performance Reports 2015-2024." Shell Canada, 2024.