Carbon transport & storage infrastructure KPIs by sector (with ranges)

Global CO2 transport and storage capacity must scale from roughly 50 million tonnes per year (Mtpa) today to over 1 billion tonnes per year by 2050 to meet net-zero targets, yet fewer than 30 dedicated CO2 pipelines operate worldwide and only a handful of geological storage sites have reached final investment decision. The KPIs that operators, regulators, and investors select to measure this infrastructure buildout will determine whether the carbon capture value chain achieves bankability or stalls in the pilot stage.

Why It Matters

Carbon transport and storage infrastructure sits between capture facilities and permanent sequestration, making it the critical bottleneck in the entire CCS value chain. Without pipelines, ships, or rail connections linking emitters to storage reservoirs, even the most advanced capture technology cannot deliver permanent CO2 removal. The EU's Net-Zero Industry Act targets 50 Mtpa of CO2 injection capacity by 2030. The US 45Q tax credit enhancement under the Inflation Reduction Act provides $85 per tonne for geological storage, creating a direct financial incentive for infrastructure developers to move rapidly.

The challenge extends beyond construction. Operators must demonstrate injection well integrity over decades, monitor subsurface plume migration across complex geological formations, and meet regulatory requirements that vary by jurisdiction. Pipeline operators face permitting timelines averaging 3-7 years in Europe and 2-5 years in the United States. For investors, transport and storage KPIs signal both project execution risk and long-term revenue predictability, particularly as governments move toward regulated access models for CO2 networks.

Measuring the right metrics at the right lifecycle stage separates credible projects from aspirational announcements. KPIs must cover capital efficiency, throughput utilization, storage permanence, and safety performance simultaneously.

Key Concepts

CO2 pipeline transport moves compressed or supercritical CO2 from capture facilities to storage sites. Pipelines operate at pressures of 100-150 bar and temperatures that maintain CO2 in a dense phase. Onshore pipelines dominate current infrastructure, but offshore pipelines are expanding for subsea geological storage. Pipeline design must account for CO2 impurity specifications, as water and hydrogen sulfide content affect corrosion rates and phase behavior.

Geological storage involves injecting CO2 into deep subsurface formations: depleted oil and gas reservoirs, deep saline aquifers, or unmineable coal seams. Saline aquifers offer the largest theoretical capacity (estimated at 1,000-10,000 gigatonnes globally) but require more characterization than depleted hydrocarbon reservoirs where subsurface data already exists.

Monitoring, reporting, and verification (MRV) for storage sites tracks the behavior of injected CO2 underground. MRV combines seismic surveys, wellbore pressure monitoring, groundwater sampling, and satellite-based surface deformation detection to confirm containment and quantify any potential leakage.

CO2 shipping is emerging as an alternative to pipelines for connecting dispersed capture sites to centralized storage hubs. Liquefied CO2 carriers operate at approximately -50 degrees Celsius and 7 bar pressure, with vessel capacities ranging from 7,500 to 50,000 cubic meters.

KPI Benchmarks by Sector

KPI	Sector	Low Range	Median	High Range	Unit
Pipeline capital cost	Onshore (new build)	0.8	1.5	3.0	$M/km
Pipeline capital cost	Offshore (new build)	2.5	4.0	7.0	$M/km
Pipeline utilization rate	Early-stage network	20%	40%	65%	% of design capacity
Pipeline utilization rate	Mature network	60%	80%	95%	% of design capacity
CO2 transport cost	Onshore pipeline (>200 km)	3	8	15	$/tCO2
CO2 transport cost	Offshore pipeline	8	18	35	$/tCO2
CO2 transport cost	Ship (500-1,500 km)	10	20	40	$/tCO2
Storage injection rate	Single well	0.3	0.7	1.5	Mtpa/well
Storage capital cost	Saline aquifer (new)	8	15	30	$/tCO2 capacity
Storage capital cost	Depleted reservoir (repurposed)	4	9	18	$/tCO2 capacity
Storage operating cost	Ongoing injection and MRV	3	8	15	$/tCO2 injected
Containment confidence	Mature sites (>5 yr operation)	99.5%	99.9%	99.99%	% CO2 retained
Permitting timeline	US (Class VI well)	2	3.5	6	years
Permitting timeline	EU (storage license)	3	5	8	years
MRV cost	Full monitoring program	0.5	2	5	$/tCO2 stored
Storage site characterization cost	Greenfield saline aquifer	30	80	200	$M per site

What's Working

Shared infrastructure models reducing per-tonne costs. The Northern Lights project in Norway, a joint venture between Equinor, Shell, and TotalEnergies, is the world's first open-access CO2 transport and storage network. Phase 1 delivers 1.5 Mtpa capacity with offshore pipeline and subsea injection at the Johansen formation. By aggregating volumes from multiple capture sources, Northern Lights drives transport costs below $15/tCO2 for connected European emitters. The UK's East Coast Cluster and HyNet Northwest follow similar shared-access models, with combined planned capacity exceeding 20 Mtpa by 2030. This hub approach amortizes characterization and pipeline costs across multiple users, reducing the financial risk for individual capture projects.

Depleted hydrocarbon reservoirs accelerating storage permitting. Projects repurposing exhausted oil and gas fields benefit from decades of subsurface data, including well logs, seismic surveys, and production histories. The Porthos project in the Netherlands plans to store 2.5 Mtpa in depleted gas fields beneath the North Sea, leveraging Shell's existing geological knowledge to reduce characterization timelines by 2-3 years compared to greenfield saline aquifer sites. In the US, Denbury (now Occidental subsidiary) operates the largest CO2 pipeline network at approximately 1,600 km, repurposing enhanced oil recovery infrastructure for dedicated geological storage. Reservoir conversion projects report site characterization costs 40-60% lower than new saline aquifer developments.

Digital MRV technologies improving containment verification. Satellite-based InSAR (Interferometric Synthetic Aperture Radar) detects surface deformation above storage sites at millimeter precision, providing early warning of pressure anomalies without physical well interventions. The Sleipner project in Norway, which has stored over 20 million tonnes of CO2 since 1996, uses time-lapse seismic monitoring to track plume migration with 95%+ accuracy against modeled predictions. Distributed fiber-optic sensing along injection wellbores provides continuous temperature and pressure data at meter-scale resolution, replacing periodic wireline surveys that cost $200,000-500,000 per intervention.

What's Not Working

Class VI permitting bottlenecks in the United States. The US Environmental Protection Agency has issued only 6 Class VI permits for CO2 injection wells as of early 2026, despite receiving over 180 applications since the 45Q enhancement. Average review timelines exceed 3 years, with some applications pending for over 5 years. Several states (Louisiana, North Dakota, Wyoming, West Virginia) have obtained or sought primacy to issue their own permits, but state-level capacity building takes 18-24 months. The permitting backlog threatens to strand $15-20 billion in announced capture investments that lack confirmed storage endpoints.

Pipeline routing and community opposition. The Navigator CO2 Ventures Heartland Greenway pipeline, which would have transported CO2 from ethanol plants across five US Midwest states, was canceled in 2024 after sustained landowner opposition and regulatory setbacks in South Dakota and Iowa. Summit Carbon Solutions' pipeline faced similar resistance before securing some approvals. Community concerns center on pipeline safety (CO2 releases can cause asphyxiation at high concentrations), land use impacts, and eminent domain proceedings. These dynamics add 12-24 months to development timelines and increase pre-development costs by $50-150 million for major cross-state projects.

Saline aquifer characterization uncertainty. While saline aquifers theoretically offer vast storage capacity, translating theoretical estimates into bankable reserves requires expensive appraisal programs. A single appraisal well costs $10-50 million depending on depth and location. Injectivity testing, caprock integrity assessment, and dynamic modeling can take 3-5 years before a final investment decision. The CarbonNet project in Australia's Gippsland Basin spent over A$150 million on characterization before reaching FID stage. For many developers, the gap between theoretical storage resource and proven storage reserve remains a barrier to financing, with lenders requiring P90 confidence levels that demand 2-4 appraisal wells per formation.

Key Players

Established Leaders

• Equinor: Norwegian energy company operating Northern Lights and the Sleipner/Snohvit storage sites. Combined operational storage experience exceeding 25 years and 25 million tonnes.
• Occidental (Oxy Low Carbon Ventures): US operator of the largest dedicated CO2 pipeline network through its Denbury subsidiary. Developing the Stratos direct air capture hub in Texas with 500,000 tpa storage capacity.
• Shell: Partner in Northern Lights and Porthos projects. Operates the Quest CCS facility in Alberta with over 8 million tonnes stored since 2015.
• Santos: Australian energy company developing the Moomba CCS project in the Cooper Basin, targeting 1.7 Mtpa storage in depleted gas reservoirs.

Emerging Startups

• Storegga: UK developer of the Acorn CCS project in Scotland, leveraging North Sea depleted fields and existing pipeline infrastructure for phased capacity buildout.
• Carbon Transport and Storage Company (CTSC): UK-based entity developing shared CO2 transport networks for industrial cluster decarbonization.
• Deep Sky: Canadian company building CO2 removal and storage infrastructure, combining direct air capture with geological sequestration in Quebec.
• Carbfix: Icelandic company pioneering mineral carbonation storage, injecting CO2 dissolved in water into basaltic rock formations where it mineralizes within 2 years.

Key Investors and Funders

• UK Infrastructure Bank: Committed funding to the East Coast Cluster and HyNet CCS transport and storage projects.
• European Commission Innovation Fund: Allocated over EUR 3 billion to large-scale CCS projects including transport and storage infrastructure.
• US Department of Energy (Carbon Storage Assurance Facility Enterprise): CarbonSAFE program funding integrated storage complex development with over $500 million in grants.

Action Checklist

1. Define transport mode selection criteria based on CO2 volume (pipelines above 1 Mtpa, shipping for dispersed sources below 0.5 Mtpa), distance, and offshore versus onshore routing.
2. Establish pipeline utilization rate targets by development phase: 40%+ in year one, scaling to 80%+ by year five through phased capacity commitments from capture operators.
3. Require storage site operators to demonstrate P50 injectivity and P90 containment confidence through appraisal well programs before committing transport infrastructure investment.
4. Implement continuous MRV systems combining downhole fiber-optic sensing, periodic seismic surveys, and satellite InSAR monitoring rather than relying on periodic well interventions alone.
5. Engage communities along pipeline corridors at least 18 months before permit applications, providing transparent safety data and negotiating voluntary easement terms.
6. Track permitting timeline KPIs against jurisdiction benchmarks and engage with state primacy programs where available to reduce Class VI or equivalent approval delays.
7. Structure transport tariffs using ship-or-pay contracts with 15-20 year terms to provide revenue certainty for infrastructure financing.

FAQ

What is the cost of transporting CO2 by pipeline versus ship? Onshore pipeline transport costs $3-15 per tonne of CO2 for distances over 200 km, while offshore pipelines run $8-35 per tonne depending on water depth and distance. CO2 shipping costs $10-40 per tonne for distances of 500-1,500 km but becomes competitive with pipelines for dispersed source-to-sink connections where pipeline routing is impractical or permit-constrained. The crossover point typically falls at 500-800 km for offshore routes.

How long does CO2 stay underground in geological storage? Properly characterized and managed geological storage sites retain CO2 for thousands to millions of years. The Sleipner project has demonstrated 99.99%+ containment over nearly 30 years of operation. Multiple trapping mechanisms work over time: structural trapping (caprock seal) provides immediate containment, residual trapping immobilizes CO2 in pore spaces within decades, solubility trapping dissolves CO2 into formation water over centuries, and mineral trapping permanently converts CO2 to carbonate minerals over millennia.

What are the main risks of CO2 pipeline transport? The primary risks include pipeline rupture causing localized CO2 release, which can create an asphyxiation hazard in low-lying areas due to CO2's density. Pipeline operators manage these risks through design standards (ASME B31.4 and DNV-RP-F104), continuous pressure monitoring, automatic shut-off valves, and minimum setback distances from populated areas. The CO2 pipeline safety record shows fewer incidents per mile than natural gas pipelines, with only one significant release event (Satartia, Mississippi, 2020) prompting updated safety protocols.

How much CO2 storage capacity exists globally? Theoretical global geological storage capacity is estimated at 8,000-55,000 gigatonnes of CO2 across saline aquifers, depleted oil and gas fields, and coal seams. However, bankable "proven" storage, meaning sites with completed characterization and regulatory approval, currently totals only 200-300 Mtpa of injection capacity. Bridging this gap between theoretical resource and permitted reserve is the central challenge for scaling CCS infrastructure.

Sources

1. Global CCS Institute. "Global Status of CCS 2025." GCCSI, 2025.
2. Northern Lights JV. "Phase 1 Development and Operations Update." Equinor, 2025.
3. International Energy Agency. "CCUS in Clean Energy Transitions." IEA, 2024.
4. US Environmental Protection Agency. "Class VI Permitting Status Report." EPA Underground Injection Control Program, 2025.
5. Zero Emissions Platform. "CO2 Transport and Storage Business Models in Europe." ZEP, 2024.
6. National Petroleum Council. "Meeting the Dual Challenge: Carbon Capture, Use, and Storage." NPC, 2024.
7. Intergovernmental Panel on Climate Change. "Carbon Dioxide Capture and Storage: Special Report Update." IPCC, 2024.