The growing urgency to address climate change by policymakers, industry, and investors appears to have reinvigorated carbon capture and storage (CCS) deployment. More than 50 CCS facilities at power plants are in various stages of development worldwide. Why has it taken so long, and is it sustainable?
Nearly a decade since the world’s first power generation carbon capture and storage (CCS) project began commercial operation, only three others have followed it.
The first project, SaskPower’s 115-MW Boundary Dam 3 in Saskatchewan, Canada, became the world’s first coal-fired power facility to implement carbon capture successfully in 2014. The project included boiler modifications and replacement of an old steam turbine with a new one integrated with carbon dioxide (CO2) and sulfur dioxide (SO2) removal mechanisms. The plant was recognized as POWER’s Plant of the Year in 2015 as a result of the innovative retrofit. Since it went online, the facility has been capable of capturing up to 1 million metric tons (Mt) per year for enhanced oil recovery (EOR) and geologic storage.
In 2017, Petra Nova, another landmark power generation CCS project, marked commercial operation. The project, which also earned POWER’s Plant of the Year award, is designed to capture at least 90% of the CO2 emissions from the low-pressure, oxygen-containing stream of flue gas from the 650-MW coal-fired boiler at NRG Energy’s W.A. Parish Unit 8 in Fort Bend County, Texas, and provide a capture capacity that is equivalent to a 240-MW gross unit. Jointly developed by NRG Energy and Japanese oil and gas firm JX Nippon, the project uses the Kansai Mitsubishi Carbon Dioxide Recovery Process (KM CDR Process). The amine-based gas-treating process was adapted and scaled by Mitsubishi Heavy Industries (MHI). The CO2 is dried, compressed, and transported via an 81-mile pipeline to the West Ranch oilfield (West Ranch) in Jackson County, Texas, where it is injected for EOR. While Petra Nova was mothballed in May 2020 owing to economic conditions rooted in the collapse of oil and power prices at the outset of the COVID pandemic, JX Nippon has since acquired full ownership of the project and restarted operations in September 2023.
Three years after Petra Nova, Chinese power generator Shenhua Guohua Jinjie Energy, a subsidiary of Shenhua Group, began operating a CCS facility at a coal-fired power plant located in the Jinjie Economic and Technological Development Zone in China’s Shaanxi province. The plant, located at the Shenfu coalfield, currently has four 600-MW subcritical air-cooled coal units and is exploring two sets of carbon capture. Its first project, which began operations in 2020, captures 150,000 tonnes per annum (tpa) of CO2 with an amine-based post-combustion carbon capture facility. The second facility is a testing-scale solid adsorption system with a capacity of 1,000 tpa CO2. The project’s captured CO2 is transported via tanker truck to the Liujiagou deep saline formation within the Ordos Basin, an injection site of the previous Shenhua Ordos CCS demonstration project that injected and stored 300,000 tonnes of CO2 captured from a nearby Ordos coal liquefaction plant.
1. China Energy’s 500,000 tonnes per annum carbon capture facility at the Taizhou coal-fired power plant in Jiangsu province. Courtesy: China Energy
In June 2023, meanwhile, China Energy launched a 500,000 tpa carbon capture utilization and storage (CCUS) facility at the Taizhou coal-fired power plant in Jiangsu province (Figure 1). The project, currently the largest coal-fired CCUS project in Asia, uses an amine-based post-combustion technology. China Energy says the project was achieved through breakthroughs in its high-performance absorption tower and high-efficiency amine recovery. Some of the captured CO2 will be transported to Sinopec East China Petroleum Bureau for EOR.
“Next, Taizhou Power Plant will join hands with related enterprises, universities, and research institutions to conduct research in fields such as the production of methanol with carbon dioxide and hydrogen and refined chemical products so as to enhance the value of carbon dioxide, further facilitate the full-cycle carbon industrial chain from capture to utilization, and accelerate the transition of coal-fired power CCUS from technological demonstration to industrialized, clustered development,” the company said in June.
Big Momentum for CCS
According to the Global CCS Institute, getting these four projects up and running marks significant progress for CCS adoption in the power sector. In November 2023, the Melbourne, Australia–based international think tank, whose mission is to accelerate the deployment of CCS technologies, suggested 53 power generation CCS projects are “in the pipeline.” These projects are part of a worldwide fleet of 41 projects that are already operational in other industries (with a combined capacity to capture 49 Mt), and part of a larger 351-project pipeline under development globally.
“New projects are being announced weekly,” noted Global CCS Institute CEO Jarad Daniels. “The CCS project pipeline has exhibited strong year-on-year growth over the last six years, growing at a compound rate of more than 35% per annum since 2017.” Initially concentrated in specific sectors, CCS is now branching into a wide array of industries. While its most significant adoption is currently centered on the ethanol industry and natural gas processing, the institute’s database highlights applications in hydrogen and chemicals, fertilizer, iron, steel, bioethanol, and waste-to-energy. “It’s also interesting to note that as time passes, CCS is being applied to industries with higher capture costs, such as in electricity generation, cement, and direct air capture [DAC],” the group has said.
Diversification of CCS projects is also notable in the power sector. The Global CCS Institute’s database suggests nearly a third of newly announced projects seek to abate emissions from gas generation, and several projects involve biomass and waste-based power generation.
At the same time, the CCS industry is witnessing “the birth of a new industry,” CO2 transport and storage, Daniels said. “As of [July 2023], there were 101 transport in storage projects in our project pipeline,” he noted. “Each of these projects aims to provide CO2 transport and storage services to third parties, leveraging the cost and risk advantages of networks in anticipation of robust future demand.”
Momentum Driven by Policy
Overall, growth is being driven by multiple factors, foremost among them, “strong policy,” particularly in North America and Europe, Daniels said. As a whole, CCS is becoming a prominent feature of public policy, with CCS included in governmental climate pledges. That comes hand-in-hand with a “steady reduction in capture costs over time,” he said, which has strengthened the business case for investment driven by policy.
In 2022, the U.S. Congress updated and expanded the 2018-introduced 45Q tax credit, and, with passage of the Inflation Reduction Act, increased the credit from $50 to $85/tonne for power generation facilities storing CO2 in saline geologic formations. As the Department of Transportation continues work on rulemaking to update standards for CO2 pipelines, including requirements related to emergency preparedness and response, the Environmental Protection Agency (EPA) has received “an unprecedented number of Class VI permit applications,” for CO2 injection. Texas regulators have so far issued the first air permits for gas-fired plants equipped with CCS: Calpine’s 896-MW Baytown project and the 1,217-MW Deer Park Energy Center (Figure 2).
2. The Deer Park Energy Center, a 1.2-GW natural gas combined cycle power plant located in Deer Park, Texas—the largest power plant in Calpine’s fleet—is set to host one of the world’s largest carbon capture projects. The project is designed to capture 95% or more of total CO2 emissions from flue gas generated from all five turbines at the plant. Courtesy: Calpine
As significantly, the EPA in May 2023 issued a proposed rule that would set an emission standard based on 90% carbon capture at existing coal steam units starting in 2030 for any coal plant that plans to operate after January 2040. Under the proposal, owners and operators of new and existing baseload gas combined cycle units could also choose to comply with the rule by installing CCUS at a 90% capture rate by 2035. (In the proposal, the EPA applies the standard to individual units with a nameplate capacity of more than 300 MW operating on average at a 50% capacity factor.)
In Canada, a federal emissions reduction plan expects national CCS capacity to grow at least 15 Mtpa by 2030, while a federally mandated carbon price is slated to increase to CA$170/per tonne. Ottawa has also announced significant support for CCS deployment, including an investment tax credit that will cover up to 50% of the capital cost of CO2 capture projects until 2030.
Elsewhere around the world, the European Union, which already has a carbon trading program, is bolstering CCS through its Innovation Fund, along with individual national subsidies in Denmark, the Netherlands, Norway, and the UK. The UK, notably, is heavily invested in developing CCS “clusters,” including in northwest England and Wales, on the east coast, and Humber in Teeside. In Asia, progress is tangible in Japan, Singapore, South Korea, and notably, China. Meanwhile, Brazil is mulling a bill that would establish a legal framework for CCS.
Technology Not a Hurdle
Still, a pervading concern, particularly in the power sector, is how quickly CCS can be deployed to make an actionable impact on global energy emissions. “While [recent policy] progress is encouraging, achieving climate targets will require annual CO2 storage rates of about 1 gigaton per annum by 2030 and multiple gigatons by mid-century,” Daniels said. “So there’s still much good work for all of us to do. As more projects progress from planning to development to the execution phase, permitting, public engagement, and project management will increasingly become more critical.”
Most power CCS projects, including those in the pipeline, utilize post-combustion, pre-combustion, and oxyfuel combustion technologies. Solvent-based systems using amine, the most mature CCS technology type, appear to be the most widely adopted, though solid adsorption systems are also being explored.
According to John Thompson, Markets and Technology director at the Clean Air Task Force, a think tank that works to safeguard against the impacts of climate change by catalyzing the global development of climate-protecting technologies, the biggest hurdles aren’t technology.
“It’s money,” he told POWER. “If you look at carbon capture, it’s a pollution control technology and it only happens in one of two cases: You either require it by regulation to clean up emissions or you have some kind of tax incentives that pay for the cost.” In the U.S., where 23 power CCS projects now are under development, the biggest challenge relates to costs, he noted. “What’s really changed is the tax credits,” which have furnished the industry with an optimal economic profile, he said. Though costs for coal plant capture generally vary by configuration, they are generally consistent.
A Focus on Costs and Performance
The Department of Energy (DOE), which has been investigating the latest cost details for CCS, has released several reports examining a range of capture levels both for coal and gas plants. In a recent report, Pathways to Commercial Liftoff: Carbon Management, the DOE uses a 12-year payback period, a range of transport and storage ($10–$40 per metric ton), and considers first/nth plant impacts. “For retrofitting coal plants, the low cost is $63 per metric ton to capture, store, and inject CO2 underground. For natural gas plants, the range begins at $96 per metric ton for capture, transport, and storage,” Thompson noted.
However, the upper-end costs described in the Pathways report “are much higher,” and they do not help evaluate a world characterized by emission standards and 45Q tax credits “because plants at this high-end range are poor candidates to install carbon capture and storage. These plants generally are operating infrequently or approaching the end of their useful life,” he noted.
Thompson suggested costs are generally distributed around $70/ton for coal sites and about $85 to $90/ton for combined cycle natural gas. “The big variation on coal and gas plants is going to be how far you have to transport it,” he noted. “If the government is paying $85 in these tax codes, and your costs are $80, $85, $90, or $95, or $100, that’s probably close enough that you can afford to do it.”
Still, CCS may not be suitable for all fossil fuel generation, Thompson noted. “It’s helpful to think of coal plants in three buckets. There are plants that are going to close in the next five, or six, or seven years. Those aren’t good candidates for carbon capture,” he said. Better candidates would be plants slated to close in the late 2030s or 2040s, and by the 2040s, coal and gas plants may have no option but to consider CCS, he suggested.
Carbon capture’s impact on plant performance has also been a concern. A significant issue pertains to the reduction in net power output (derate) due to the large parasitic steam and power loads required for appreciable levels of carbon capture. According to the DOE, post-combustion capture has been shown to reduce the net plant efficiency of an equivalent plant without capture by 20% or more. And, along with cost and performance concerns, frequently cited traditional impediments to plant retrofits include projected plant downtime during construction, plant layout and footprint restrictions, reuse of equipment or resources, and permitting requirements. However, Thompson suggested that the CCS tradeoff, if leveraged with a tax credit, may be justified. “In many models we’ve seen, when you have 45Q and you add CCS to your plant, your plant actually ends up dispatching more,” he said.
Ultimately, Thompson is optimistic that more CCS deployments in the power sector will furnish the industry with crucial carbon management experience. For now, no silver bullet has emerged that could address decarbonization while maintaining the power sector’s crucial mission of providing reliable and affordable power, he noted. “A lot of people understand the complexity and magnitude of trying to scale up wind and solar facilities, the amount of transmission, and the amount of land,” it will take to replace existing generation, he noted. “This is one of the most difficult transitions.”
How CCS will pan out as new technologies emerge on the power landscape to competitively offset fossil fuels remains unclear, he acknowledged, but market signals from incentives and regulations may encourage future advancements. “That means incumbent technologies like amines will be driven toward better solvents and better integration. When you have a better solvent, you can shrink the tower absorber, and when you shrink the absorber, you shrink the capital costs. And when you have better integration, you get more efficiency that allows you to shrink the footprint, which in turn drives reductions in price.”