A paper prepared for the American Public Power Association (APPA) and several other parties offers details on carbon capture utilization and sequestration (CCUS) projects representing various stages of technology development and scale underway in North America.
The paper, which also identifies further work for CCUS to contribute to a low-carbon energy grid, points out that CCUS initially was focused on coal-fired carbon dioxide (CO2) emissions. The report features several CCUS projects at public power utilities and/or communities.
Over the last decade, other work has pursued potential application to natural gas-fired combined-cycle generating assets, the report said.
Twelve CCUS projects located in North America are either operating, operable but on hold, or the subject of detailed engineering studies, according to the paper. (click here for the paper).
“Operating issues encountered by some of the first projects -- augmented by research aimed to reduce cost and improve reliability -- could potentially lead to full-scale CCUS demonstrations,” the paper noted.
Four categories of carbon capture technology are under development. These are absorption processes, typically employing an amine solvent, adsorption utilizing a solid substrate, membranes for CO2 separation, and cryogenic separation.
The paper said that most large-scale CCUS projects in North America -- four addressing natural gas-fired combined cycle and eight coal-fired generators -- employ absorption processes and utilize second-generation solvents that can lower operating and capital cost relative to earlier versions of the process.
Four natural gas-fired combined-cycle projects are developing process designs. Three of these projects are near CO2 pipelines or fields that may accommodate geologic sequestration.
Of the eight pulverized coal projects, two are either operating or operational and on-hold.
Design studies are in progress at five other domestic U.S. generating stations, including Nebraska Public Power District’s Gerald Gentleman Station.
The predominant control technology is amine-based absorption, applying “lessons learned” from two projects: Boundary Dam Unit 3 and Petra Nova, the paper said.
It noted that most pulverized coal sites benefit from proximity to oil fields or pipeline transport for CO2 storage.
The U.S. Department of Energy is funding approximately 75 evolving processes in the four previously defined categories to achieve a target CO2 cost of $30 per metric ton (tonnes). “The outcome of this program employing bench-scale, pilot plant, and large-scale projects could be additional CCUS options with lower cost and improved reliability,” the paper said.
The report also addresses the CCUS value chain, specifically pipelines, and storage, and discusses the topic of cost evaluation.
The paper said that while capturing CO2 from power plant emissions, successful CCUS requires a complete “value-chain” of activities.
“The creation of a functioning and economical value chain is equally important to CO2 capture for CCUS to be a viable option. This includes both pipelines to transport CO2 and storage facilities.”
CO2 pipeline infrastructure currently totals 5,500 miles and is located mainly within U.S. oil-producing states and Canadian provinces.
“Some stakeholders are estimating the need for pipeline inventory to increase four to more than 10-fold for it to be able to significantly contribute to large reductions in emitted CO2,” the paper stated.
CO2 pipelines operate at significantly higher operating pressure than for natural gas transport, the paper noted.
But, according to the paper, experience shows that CO2 pipelines are safe. “There has not been a single human fatality or serious injury reported in the U.S. from transporting or storing CO2.”
The paper also pointed out that the cost to build CO2 pipelines is highly variable and depends on length, routing, and need for contaminant removal.
With respect to storage, enhanced oil recovery (EOR) is routinely used by the petroleum industry and has proven to be a reliable means to sequester CO2, the paper said.
The DOE projects 186 billion tonnes to 232 billion tonnes of capacity while the petroleum industry estimates 247 billion tonnes to 479 billion tonnes.
Deep saline reservoirs offer the largest capacity and are the most prominent but not the only option. Unlike EOR, there is no revenue to offset cost, the report said.
DOE estimates storage costs vary from $1/tonne to $18/tonne.
A key metric to gauge CCUS's economic viability is the cost to avoid a tonne of CO2.
Preliminary results for most U.S. coal-fired projects predict cost at or below DOE’s reference study cost of $55/tonne and potentially approaching the target of $30/tonne.
The eleven projects operating and planned will identify process improvements to lower cost and improve reliability, the paper said.
“Advanced capture technologies and pipeline ‘hub’ concepts have the potential to further lower cost. Success in these endeavors -- requiring resources and a workable development timetable -- can enable CCUS to provide reliable CO2 capture and safe byproduct storage.”
Along with APPA, the paper was prepared for the Edison Electric Institute, National Rural Electric Cooperative Association, Tri-State Generation and Transmission Cooperative, Indiana Electric Association, WEC Energy Group, Louisville Gas & Electric and KU Energy, and Arizona's Salt River Project.