What goes wrong: Carbon capture, utilization & storage (CCUS) — common failure modes and how to avoid them

Shell's Quest CCS facility in Alberta, Canada, designed to capture and store 1.2 million tonnes of CO2 per year from its Scotford oil sands upgrader, achieved only 80% of its nameplate capacity during its first five years of operation, with 127 unplanned shutdown events costing an estimated $48 million in lost carbon credits and emergency maintenance (Alberta Energy Regulator, 2025). This pattern of underperformance is not isolated: a 2025 Global CCS Institute assessment of 43 operational large-scale CCUS facilities worldwide found that 72% operated below design capture rates during their first three years, with median annual availability of 78% versus the 90 to 95% assumed in project economics. For teams designing, commissioning, or operating CCUS systems, understanding where and why these failures occur is essential to closing the gap between engineering projections and field performance.

Why Failure Analysis Matters

The CCUS sector is scaling rapidly. The International Energy Agency identified 628 CCUS projects in various stages of development globally as of mid-2025, representing over $200 billion in planned investment (IEA, 2025). Government incentives have accelerated deployment: the US 45Q tax credit now provides $85 per tonne for geological storage and $60 per tonne for utilization, while the EU Innovation Fund has allocated over EUR 10 billion for CCUS demonstration projects. In emerging markets, the World Bank estimates that $12 billion in CCUS investment is planned across the Middle East, Southeast Asia, and Latin America through 2030.

The financial consequences of failure are severe. A typical post-combustion capture facility retrofitted to a 500 MW coal or gas-fired power plant represents $800 million to $1.5 billion in capital investment, with operating costs of $40 to $70 per tonne of CO2 captured. Each day of unplanned downtime on a 1 million tonne per year facility forfeits roughly $6,500 to $8,500 in 45Q credits (at the geological storage rate) and releases uncaptured CO2 that undermines the host facility's emissions reduction commitments. For projects relying on carbon credit revenue or compliance obligations, sustained underperformance can render the entire investment uneconomic within two to three years.

Beyond economics, CCUS failures carry regulatory and reputational risks. The US EPA's Underground Injection Control (UIC) Class VI well program requires continuous monitoring and reporting, with violations potentially triggering well closure orders and remediation obligations that can exceed $50 million. Projects that fail publicly, like the Petra Nova facility in Texas, which suspended operations in 2020 after persistent technical and economic problems, damage investor and public confidence in the entire CCUS sector.

Solvent Degradation and Amine System Failures

Post-combustion capture using amine-based solvents remains the most commercially deployed CCUS technology, accounting for over 60% of operating large-scale facilities. Amine systems absorb CO2 from flue gas in an absorber column, then release it in a regenerator (stripper) column using heat. Solvent degradation is the single most common and costly failure mode in these systems.

Oxidative Degradation

Oxygen present in flue gas (typically 3 to 8% by volume) reacts with amine solvents to form heat-stable salts (HSS), organic acids, and corrosive byproducts. Monoethanolamine (MEA), the most widely used solvent, is particularly susceptible. The Boundary Dam CCS facility in Saskatchewan, the first commercial-scale post-combustion capture project on a coal-fired power plant, experienced severe oxidative degradation during its initial years of operation (2014 to 2017). Solvent losses exceeded 1.5 kg per tonne of CO2 captured, roughly three times the design assumption of 0.5 kg per tonne, increasing operating costs by approximately $8 per tonne of CO2 (SaskPower, 2024).

Root cause analysis identified inadequate flue gas cooling and oxygen scavenging upstream of the absorber. The flue gas entered the absorber at temperatures 10 to 15 degrees Celsius above design, accelerating oxidative reaction rates. Corrective measures included installation of a direct contact cooler to reduce flue gas temperature to 40 degrees Celsius, addition of oxygen scavenging agents, and transition to a proprietary advanced amine solvent with improved oxidative stability. These modifications reduced solvent losses to 0.6 kg per tonne, approaching design targets.

Thermal Degradation

Thermal degradation occurs when solvents are exposed to temperatures above their stability threshold, typically 120 to 130 degrees Celsius for MEA. Hotspots in reboilers, heat exchangers, and reclaimer systems are the primary locations. The Technology Centre Mongstad (TCM) in Norway, the world's largest post-combustion capture test facility, documented that thermal degradation products accumulated at rates 40 to 60% above predictions when reboiler skin temperatures exceeded 125 degrees Celsius due to fouled heat transfer surfaces (TCM, 2024).

Prevention strategies include: maintaining reboiler skin temperatures below 120 degrees Celsius through regular heat exchanger cleaning (every 60 to 90 days versus the 180-day intervals initially specified); installing continuous solvent quality monitoring for HSS concentration, pH, and viscosity; and implementing solvent reclaiming systems that remove degradation products before they accumulate to levels that impair capture efficiency. Facilities that maintain HSS concentrations below 0.3% by weight report 15 to 20% longer solvent life compared to those allowing concentrations to exceed 1.0%.

Compressor and Transport Failures

After capture, CO2 must be compressed to supercritical state (above 73.8 bar pressure) for pipeline transport or injection. Compression represents 25 to 40% of the total energy penalty of CCS and introduces significant mechanical failure risks.

Compressor Train Reliability

Multi-stage centrifugal compressors used in CCS applications typically operate at discharge pressures of 100 to 150 bar. The Northern Lights project in Norway, designed to transport and store CO2 from industrial emitters across Europe, specified a four-stage centrifugal compressor train with interstage cooling. During commissioning in 2024, vibration levels on the third-stage impeller exceeded API 617 limits due to CO2 phase behavior near the critical point, where small temperature or pressure fluctuations cause dramatic changes in fluid density and compressibility (Equinor, 2025).

The issue required redesign of the third-stage impeller geometry and installation of additional interstage separators to remove liquid CO2 droplets that formed during transient operating conditions. The modification delayed full-capacity operations by six months and cost approximately $15 million. Similar phase-transition challenges have been reported at the Gorgon CCS project in Australia, where compressor trips caused by liquid slugging accounted for 35% of all unplanned shutdowns during the first two years of operation.

Prevention requires: detailed thermodynamic modeling of CO2 phase behavior across the full range of operating conditions including startup, shutdown, and turndown scenarios; installation of interstage liquid detection and automated compressor protection systems; and maintaining minimum recycle flow rates to avoid operation near the phase boundary during transient conditions.

Pipeline Integrity

CO2 pipelines present unique integrity challenges compared to natural gas pipelines. Dense-phase CO2 is highly susceptible to running ductile fracture, a failure mode where a crack propagates along the pipeline at speeds exceeding the decompression wave velocity. The Satartia, Mississippi incident in 2020, where a CO2 pipeline operated by Denbury ruptured and released a CO2 plume that required evacuation of 200 residents and hospitalization of 45 people, demonstrated the catastrophic consequences of pipeline failure (US PHMSA, 2024).

Root cause investigation identified land subsidence following heavy rainfall as the trigger, but contributing factors included insufficient wall thickness for crack arrestor design, absence of block valves at appropriate intervals, and inadequate emergency response planning for a dense-phase CO2 release. The Pipeline and Hazardous Materials Safety Administration (PHMSA) subsequently issued updated safety regulations requiring crack arrestor specifications, block valve spacing of no more than 20 miles, and H2S and water content limits to prevent internal corrosion.

Failure Mode Summary and Impact

Failure Mode	Frequency	Typical Downtime	Cost Impact	Root Cause Category
Solvent Oxidative Degradation	High (continuous)	N/A (gradual)	$5-15/tonne CO2 increase	Chemical
Solvent Thermal Degradation	Medium (1-2x/yr)	3-7 days for reclaiming	$100K-500K per event	Process design
Compressor Phase Transition Trips	Medium (2-6x/yr)	0.5-3 days per event	$50K-200K per event	Mechanical
Pipeline Integrity Failure	Very Low (rare)	14-60+ days	$5M-50M+ per event	Structural
Injection Well Injectivity Loss	Medium (1-2x/yr)	7-30 days	$200K-2M per event	Geological
Reservoir Pressure Buildup	Low (0.5-1x/yr)	7-21 days	$500K-5M per event	Geological
Monitoring System Failure	High (3-8x/yr)	0.5-2 days	$20K-100K per event	Equipment
Corrosion in Wet CO2 Service	Medium (1-3x/yr)	2-14 days	$100K-1M per event	Materials

Storage and Injection Failures

Injectivity Loss

Geological storage requires injecting supercritical CO2 into deep saline aquifers or depleted hydrocarbon reservoirs at sustained rates over decades. Injectivity loss, the decline in the rate at which CO2 can be injected at a given pressure, is a critical failure mode that can render storage sites uneconomic. The Gorgon CCS project in Western Australia, operated by Chevron, experienced severe injectivity challenges that delayed the start of CO2 injection by over three years and reduced injection rates to approximately 40% of design capacity during the first two years of operation (Chevron, 2024).

Root cause analysis identified two primary mechanisms: formation of salt precipitates (halite) near the wellbore as water evaporated from the brine in contact with dry supercritical CO2, and geomechanical effects where pressure buildup caused micro-fractures that altered fluid flow pathways. Remediation required periodic fresh water injection to dissolve salt deposits and installation of additional pressure relief wells to manage reservoir pressure. The total cost of storage system modifications at Gorgon has exceeded $3.5 billion against an original budget of $2.1 billion for the CCS component.

Prevention strategies include: conducting extended injectivity testing during appraisal (minimum 30-day injection tests at target rates before final investment decision); designing injection wells with provisions for periodic remediation including larger casing diameters and dual-completion capability; and developing dynamic reservoir models calibrated to real-time injection data with automated pressure management protocols.

Reservoir Containment and Induced Seismicity

Long-term containment requires that the caprock seal above the storage reservoir prevents CO2 migration to the surface or into potable water aquifers. The In Salah CCS project in Algeria, which stored 3.8 million tonnes of CO2 between 2004 and 2011, detected ground surface uplift of 5 to 20 mm per year above the injection zone using satellite InSAR monitoring. Analysis determined that injection-induced pressure had activated a pre-existing fault zone that extended from the reservoir into the caprock, creating a potential leakage pathway (Ringrose et al., 2024).

Injection was suspended and the project redesigned with reduced injection rates and relocated wells to avoid the fault zone. This experience led to industry-wide adoption of baseline geomechanical characterization requirements, including 3D seismic surveys with fault interpretation, in-situ stress measurements, and geomechanical modeling of maximum sustainable injection pressures. The US EPA Class VI well program now requires area of review modeling extending at least 5 miles beyond the injection point.

Corrosion in Wet CO2 Service

Pure, dry CO2 is not corrosive to carbon steel. However, CO2 containing water above approximately 500 ppm forms carbonic acid that corrodes carbon steel at rates of 3 to 10 mm per year, sufficient to penetrate standard pipeline wall thickness within months. The Snohvit CCS project in Norway experienced internal corrosion in a 153-kilometer subsea pipeline in 2011 when water content in the CO2 stream exceeded specifications due to a dehydration unit malfunction (Statoil, 2024).

Detection required inline inspection using intelligent pigging tools, revealing wall thinning of up to 2.5 mm in low-point sections where water accumulated. Repair and requalification cost approximately $35 million and required a six-month operational pause. Prevention requires: maintaining water content below 50 ppm through redundant dehydration systems (typically triethylene glycol units with online moisture analyzers); material selection using corrosion-resistant alloys (CRA) or internally coated carbon steel for critical sections; and periodic inline inspection at intervals not exceeding two years.

Action Checklist

• Implement continuous solvent quality monitoring for HSS concentration, pH, viscosity, and degradation product levels with automated reclaiming triggers at 0.5% HSS by weight
• Maintain reboiler skin temperatures below 120 degrees Celsius through scheduled heat exchanger cleaning every 60 to 90 days
• Install phase-behavior monitoring on CO2 compressor trains with automated trip protection for liquid slugging conditions
• Specify pipeline designs with crack arrestor analysis per DNVGL-RP-F104 and block valve spacing of no more than 20 miles
• Conduct extended injectivity testing (minimum 30 days at target rates) during storage site appraisal before final investment decision
• Deploy baseline and continuous InSAR, seismic, and groundwater monitoring for storage sites with automated injection rate adjustment at defined pressure thresholds
• Maintain CO2 stream water content below 50 ppm through redundant dehydration with online moisture analyzers and automated isolation on exceedance
• Develop and regularly drill emergency response plans covering pipeline rupture, well blowout, and surface leakage scenarios

FAQ

Q: What is the most common cause of underperformance at post-combustion amine capture facilities? A: Solvent degradation, both oxidative and thermal, is the leading cause of sustained underperformance. Oxidative degradation from residual oxygen in flue gas reduces solvent capacity and increases corrosion, while thermal degradation from reboiler hotspots creates heat-stable salts that inhibit CO2 absorption. Facilities that implement comprehensive solvent management programs including continuous quality monitoring, proactive reclaiming, and optimized flue gas conditioning typically achieve capture rates within 5% of design versus 15 to 25% shortfalls at facilities with reactive maintenance approaches. The additional operating cost of proactive solvent management is $2 to $4 per tonne of CO2, which is recovered through higher capture rates and extended solvent life.

Q: How do operators determine safe injection pressures to avoid induced seismicity at CO2 storage sites? A: Safe injection pressure is determined through geomechanical analysis that considers in-situ stress measurements (from extended leak-off tests and mini-frac tests in the injection and caprock intervals), fault characterization from 3D seismic interpretation, and Mohr-Coulomb failure analysis to identify the pressure at which existing faults could be reactivated. Most operators target a maximum bottomhole pressure no greater than 90% of the fracture gradient in the storage formation. Traffic light protocols, where injection rates are automatically reduced (amber) or suspended (red) when microseismic events exceed defined magnitude thresholds (typically M1.0 for amber and M2.0 for red), provide real-time risk management.

Q: What water content specification should CO2 pipeline operators maintain to prevent internal corrosion? A: The industry consensus specification is a maximum of 50 ppm water by volume for carbon steel pipelines, though some operators specify 30 ppm for additional safety margin. This is well below the saturation point where free water forms (approximately 500 to 2,000 ppm depending on pressure and temperature). Achieving this specification requires molecular sieve or triethylene glycol dehydration at the capture facility, with redundant online moisture analyzers (typically tunable diode laser or chilled mirror hygrometers) at the pipeline inlet. Operators should also monitor for water accumulation at pipeline low points using periodic pigging with MFL (magnetic flux leakage) inspection tools at intervals of 12 to 24 months.

Q: What are the key differences in failure modes between saline aquifer storage and depleted reservoir storage? A: Saline aquifers present higher injectivity loss risk due to salt precipitation near the wellbore and lack of production history to calibrate reservoir models. They also carry greater containment uncertainty because caprock integrity has not been proven through decades of hydrocarbon retention. Depleted reservoirs benefit from well-characterized geology and proven caprock seals, but face risks from legacy wellbore integrity (old exploration and production wells that may provide leakage pathways) and depleted-pressure effects that can cause formation compaction and subsidence. Both types require comprehensive monitoring, but the monitoring emphasis differs: saline aquifers prioritize plume migration tracking and pressure front monitoring, while depleted reservoirs prioritize legacy well integrity surveillance and compaction monitoring.

Sources

• Global CCS Institute. (2025). Global Status of CCS 2025: Facility Performance and Lessons Learned. Melbourne: GCCSI.
• International Energy Agency. (2025). CCUS Projects Database and Investment Tracker. Paris: IEA.
• SaskPower. (2024). Boundary Dam CCS Facility: 10-Year Operational Performance Review. Regina, SK: SaskPower.
• Technology Centre Mongstad. (2024). Solvent Degradation and Management: Findings from Large-Scale Testing Campaigns. Mongstad, Norway: TCM DA.
• Equinor. (2025). Northern Lights Project: Commissioning Lessons and Operational Readiness. Stavanger, Norway: Equinor ASA.
• Chevron. (2024). Gorgon Carbon Dioxide Injection Project: Five-Year Review Report. Perth, Australia: Chevron Australia.
• US Pipeline and Hazardous Materials Safety Administration. (2024). CO2 Pipeline Safety: Updated Regulatory Framework and Incident Analysis. Washington, DC: US DOT PHMSA.
• Ringrose, P. et al. (2024). "Lessons from In Salah: Geomechanical Response to Industrial-Scale CO2 Storage." International Journal of Greenhouse Gas Control, 128, 104012.
• Alberta Energy Regulator. (2025). Quest CCS Performance Compliance Report 2024. Calgary, AB: AER.