Part 2: Case Studies
By Claudia Nyon and Abigael Eminza
Carbon Capture, Utilization, and Storage (CCUS) has long been promoted as a critical technology for reducing emissions from fossil fuels while supporting energy security. Over the past three decades, several high-profile projects have attempted to demonstrate the feasibility of capturing CO2 at scale and storing it underground. Some, like Petra Nova in Texas and Sleipner in the North Sea, have shown that capture and storage can work under the right conditions, offering valuable data and technical proof of concept. Others, however, such as Kemper County, Gorgon, and Boundary Dam, have struggled with spiraling costs, underperformance, and technical failures. Taken together, these projects reveal both the promise and the fragility of CCUS as a climate solution.
Success stories
The Petra Nova project in the US
Designed to capture approximately 90% of carbon dioxide from a power plant and inject it into an oil field to boost crude oil production, the Petra Nova project was completed on time and within budget (Dubin, 2017). The system diverts about 37% of the coal power plant’s emissions through a flue gas slipstream, capturing roughly 33% of total emissions, and requires a dedicated natural gas unit to meet the energy-intensive demands of the carbon-capture process. Captured CO2 is then injected into nearby oil fields for enhanced oil recovery, a process that increases crude oil flow by injecting CO2, water, or chemicals into reservoirs.
Although the project shut down during COVID-19 due to low oil prices (Dilon & Anchondo, 2020), it has been operating since 2023 (Power Engineering, 2023) after being bought by JX Nippon in 2022.
Sleipner, the world’s first commercial CCUS project.
The Sleipner project began CO2 injection in 1996 in response to Norway’s early-1990s carbon tax, which made carbon capture more profitable than just separating the carbon and releasing it into the atmosphere. This was particularly important because the gas contained about 9% CO2, above market specifications (Dickson, 2024). By 2016, Sleipner had reached its 20-year milestone, with 16 million tons of CO2 stored in the Utsira sandstone formation, located 800 meters beneath the seabed (Skalmeras, 2017).
Storing carbon underground is not an exact science, making Sleipner one of the most studied geological fields worldwide, with over 150 academic papers published (IEEFA, 2023). Their seismic datasets have been downloaded more than a thousand times.
Despite the studies, long-term stability remains uncertain. In 1999, three years after Sleipner began storage, CO2 had already migrated from its injection point to the top of the formation and into a previously unidentified shallow layer. Large amounts accumulated there, and if the layer had not been sealed, the CO2 might have escaped (IEEFA, 2023).
Rather than serving as models for CCS expansion, Sleipner and Snøhvit, another Norwegian project, raise doubts about whether sufficient capability, oversight, and sustained investment exist to keep CO2 securely stored beneath the sea permanently.
Failures
The Kemper project
The Kemper project was initially designed to capture approximately 65% of the plant’s CO2 using pre-combustion technology. However, costs quickly spiraled out of control. Originally estimated at US$2.4 billion, the project had an excess of $7.5 billion (Dubin, 2017).
Repeated delays and cost overruns eventually forced the suspension of work (Swartz, 2021). While the project was intended to gasify lignite coal and capture the resulting CO2, its original purpose was undermined when the plant shifted to natural gas, leaving much of the carbon capture equipment idle and unused.
Gorgon, Australia
Once hailed as a global showcase for CCS, Chevron’s Gorgon project has struggled to meet expectations. Located at the company’s massive LNG facility on Barrow Island, Gorgon was designed to strip CO2 from natural gas and store it underground. Yet, Chevron reports that it has so far buried just over 10 million tonnes of CO2, barely a third of its original target (Mercer, 2024).
Technical problems, particularly with reservoir pressure, have limited injection rates and delayed progress toward sequestering the promised 80% of the plant’s emissions. Since commencing operations in 2019, performance has steadily declined: CO2 capture dropped from 34% in 2022–23 to just 30% in 2023–24, representing only a small fraction of the facility’s total emissions (Denis-Ryan & Morrison, 2024). To compensate, Chevron has been forced to implement costly technical fixes and purchase carbon offsets.
The difficulties at Gorgon reflect a broader pattern. Wang et al. (2021) observe that most CCUS projects over the past three decades have either struggled or failed to achieve their objectives. Larger plant sizes, in particular, increase the risk of underperformance, and existing support mechanisms have not been sufficient to overcome these challenges. Achieving gigaton-scale deployment will therefore require reducing risk, improving returns, and better aligning technology, policy, investment, and deployment.
Boundary Dam, Canada
Canada’s Boundary Dam 3 (BD3) coal plant in Saskatchewan offers another example. In March 2021, BD3 marked the capture of its four millionth metric ton of CO2, two years later than forecast, underscoring its failure to achieve the 90% capture rate originally promised (Energi Media, 2024).
The retrofit cost more than CAD 1 billion, yet performance has consistently fallen short. Through 2023, the long-term capture rate averaged only 57% (IEEFA 2021). The system operates roughly 80% of the time, and when running, it processes just 73% of the plant’s flue gases, leaving a substantial portion of CO2 uncollected.
The plant has rarely achieved its design capacity of 3,200 metric tons per day and has never sustained that level for any extended period. SaskPower has since scaled back its capture target to 65% of emissions. Moreover, a significant portion of the CO2 collected is used for enhanced oil recovery (EOR), which in turn results in additional emissions, thereby reducing the net climate benefit considerably smaller than initially claimed (IEEFA, 2024).
Technical failures have compounded these shortcomings. In 2021, the CCS facility captured 43% less CO2 than the previous year after a breakdown in the main compressor motor forced the system offline for several months (Anchondo, 2022). Although repairs have since been completed, the outage illustrates how dependent carbon capture is on complex, custom-built equipment and how downtime can dramatically reduce emissions removal.
Key findings: The successes show that CCS can be technically feasible, completed on time and within budget, and deliver useful insights into subsurface CO₂ behavior. Yet, the failures highlight recurring challenges: escalating costs, reliance on volatile oil markets, technical underperformance, and uncertain long-term storage integrity. These case studies suggest that CCUS will require stronger policy frameworks, more consistent oversight, and sustained investment to scale effectively. Without these supports, large-scale deployment risks repeating the mixed track record seen so far.
In this series:
Part 1: Climate Mitigation and the Price of CCUS. Can be found here.
Part 2: Case Studies
Part 3: Malaysia’s Big Ambitions
Part 4: Issues for Successful Deployments
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