Carbon capture and storage (CCS) is widely seen as a critical technology for reducing atmospheric emissions of carbon dioxide (CO2) from power plants and other large industrial facilities, which are ...major sources of greenhouse gas emissions linked to global climate change. However, the high cost and energy requirements of current CO2 capture processes are major barriers to their use. This paper assesses the outlook for improved, lower-cost technologies for each of the three major approaches to CO2 capture, namely, post-combustion, pre-combustion and oxy-combustion capture. The advantages and limitations of each of method are discussed, along with the current status of projects and processes at various stages in the development cycle. We then review a variety of “roadmaps” developed by governmental and private-sector organizations to project the commercial roll-out and deployment of advanced capture technologies. For perspective, we also review recent experience with R&D programs to develop lower-cost technologies for SO2 and NOx capture at coal-fired power plants. For perspective on projected cost reductions for CO2 capture we further review past experience in cost trends for SO2 and NOx capture systems. The key insight for improved carbon capture technology is that achieving significant cost reductions will require not only a vigorous and sustained level of research and development (R&D), but also a substantial level of commercial deployment, which, in turn, requires a significant market for CO2 capture technologies. At present such a market does not yet exist. While various incentive programs can accelerate the development and deployment of improved CO2 capture systems, government actions that significantly limit CO2 emissions to the atmosphere ultimately are needed to realize substantial and sustained reductions in the future cost of CO2 capture.
CO
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capture and conversion to fuels using renewable energy is being promoted as a climate change mitigation measure that reduces fossil fuel use by effectively recycling carbon. We examine this ...claim, first for a typical CO
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capture and utilization (CCU) system producing methanol (MeOH), and then for a generalized system producing fuels from fossil carbon. The MeOH analysis shows CCU to be an inferior mitigation option compared to a system with CCS producing the same fuel without CO
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utilization. CCU also is far more costly. The generalized analysis further reveals that the mitigation potential of CCU for fuels production is limited to 50% of the original emissions of the reference system without CCU. We further highlight that the main challenge to CCU cost reduction is not the CO
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-to-fuel conversion step but the production of required carbon-free electricity at very low cost.
Proposed utilization schemes producing liquid fuels from captured CO
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offer fewer climate mitigation benefits at higher costs than alternative systems.
► There are significant differences in how major organizations estimate CCS costs. ► Not only do key assumptions vary but also the underlying methodology. ► Such differences lead to misunderstanding ...and mis-representation of CCS costs. ► Better methods and guidelines for estimating and reporting CCS costs are needed.
This paper reviews and compares the prevailing methods, metrics and assumptions underlying cost estimates for CO2 capture and storage (CCS) technologies applied to fossil fuel power plants. This assessment reveals a number of significant differences and inconsistencies across different studies, not only in key technical, economic and financial assumptions related to the cost of a CCS project (such as differences in plant size, fuel type, capacity factor, and cost of capital) but also in the underlying methods and cost elements that are included (or excluded) in a particular study (such as the omission of certain “owner's” costs or the cost of transport and storage). Such differences often are not apparent in the cost results that are reported publicly or in the technical literature. In other cases, measures that have very different meanings (such as the costs of CO2 avoided, CO2 captured and CO2 abated) are all reported in similar units of “dollars per ton CO2”. As a consequence, there is likely to be some degree confusion, misunderstanding and possible mis-representation of CCS costs. Given the widespread interest in the cost of CCS and the potential for lower-cost CO2 capture technology, methods to improve the consistency and transparency of CCS cost estimates are needed.
Carbon capture and storage (CCS) is broadly recognised as having the potential to play a key role in meeting climate change targets, delivering low carbon heat and power, decarbonising industry and, ...more recently, its ability to facilitate the net removal of CO
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from the atmosphere. However, despite this broad consensus and its technical maturity, CCS has not yet been deployed on a scale commensurate with the ambitions articulated a decade ago. Thus, in this paper we review the current state-of-the-art of CO
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capture, transport, utilisation and storage from a multi-scale perspective, moving from the global to molecular scales. In light of the COP21 commitments to limit warming to less than 2 °C, we extend the remit of this study to include the key negative emissions technologies (NETs) of bioenergy with CCS (BECCS), and direct air capture (DAC). Cognisant of the non-technical barriers to deploying CCS, we reflect on recent experience from the UK's CCS commercialisation programme and consider the commercial and political barriers to the large-scale deployment of CCS. In all areas, we focus on identifying and clearly articulating the key research challenges that could usefully be addressed in the coming decade.
Carbon capture and storage (CCS) is vital to climate change mitigation, and has application across the economy, in addition to facilitating atmospheric carbon dioxide removal resulting in emissions offsets and net negative emissions. This contribution reviews the state-of-the-art and identifies key challenges which must be overcome in order to pave the way for its large-scale deployment.
There has been an increasing interest in the application of membranes to flue gas separation, primarily driven by the need of carbon capture for significantly reducing greenhouse gas emissions. ...Historically, there has not been general consensus about the advantage of membranes against other methods such as liquid solvents for carbon capture. However, recent research indicates that advances in materials and process designs could significantly improve the separation performance of membrane capture systems, which make membrane technology competitive with other technologies for carbon capture. This paper mainly reviews membrane separation for the application to post-combustion CO2 capture with a focus on the developments and breakthroughs in membrane material design, process engineering, and engineering economics.
A variety of mathematical models have been proposed to characterize and quantify the dependency of electricity supply technology costs on various drivers of technological change. The most prevalent ...model form, called a learning curve, or experience curve, is a log-linear equation relating the unit cost of a technology to its cumulative installed capacity or electricity generated. This one-factor model is also the most common method used to represent endogenous technical change in large-scale energy-economic models that inform energy planning and policy analysis. A characteristic parameter is the “learning rate,” defined as the fractional reduction in cost for each doubling of cumulative production or capacity. In this paper, a literature review of the learning rates reported for 11 power generation technologies employing an array of fossil fuels, nuclear, and renewable energy sources is presented. The review also includes multi-factor models proposed for some energy technologies, especially two-factor models relating cost to cumulative expenditures for research and development (R&D) as well as the cumulative installed capacity or electricity production of a technology. For all technologies studied, we found substantial variability (as much as an order of magnitude) in reported learning rates across different studies. Such variability is not readily explained by systematic differences in the time intervals, geographic regions, choice of independent variable, or other parameters of each study. This uncertainty in learning rates, together with other limitations of current learning curve formulations, suggests the need for much more careful and systematic examination of the influence of how different factors and assumptions affect policy-relevant outcomes related to the future choice and cost of electricity supply and other energy technologies.
•We review models explaining the cost of 11 electricity supply technologies.•The most prevalent model is a log-linear equation characterized by a learning rate.•Reported learning rates for each technology vary considerably across studies.•More detailed models are limited by data requirements and verification.•Policy-relevant influences of learning curve uncertainties require systematic study.
•Cost estimates for advanced low-carbon technologies are widely sought but flawed.•Two categories of questions frame most cost analyses: “What if?” and “What will?”.•Conventional “bottom-up” costing ...is appropriate only for hypothetical (what if) designs.•A hybrid method of bottom-up and top-down costing is proposed for “what will” it cost.•This approach offers more realistic projections of future costs and the experience needed.
Energy research and development (R&D) programs throughout the world seek improved or lower-cost technology options that can generate electricity or other products with little or no emissions of greenhouse gases or other pollutants. Novel methods of CO2 capture and storage (CCS) as well as more efficient fossil fuel power plants are among the technologies widely being pursued. To assess the viability and competitiveness of a proposed new technology, a common figure of merit is the expected cost of a mature plant at commercial scale. This paper identifies critical shortcomings in the methods currently used to estimate such costs and proposes a new hybrid approach combining “bottom-up” and “top-down” methods to obtain more realistic cost projections for new advanced technologies. While this paper focuses on advanced fossil fuel plants the proposed methodological developments apply equally to all other advanced energy technologies.
This study develops an integrated technical and economic modeling framework to investigate the feasibility of ionic liquids (ILs) for precombustion carbon capture. The IL 1-hexyl-3-methylimidazolium ...bis(trifluoromethylsulfonyl)imide is modeled as a potential physical solvent for CO2 capture at integrated gasification combined cycle (IGCC) power plants. The analysis reveals that the energy penalty of the IL-based capture system comes mainly from the process and product streams compression and solvent pumping, while the major capital cost components are the compressors and absorbers. On the basis of the plant-level analysis, the cost of CO2 avoided by the IL-based capture and storage system is estimated to be $63 per tonne of CO2. Technical and economic comparisons between IL- and Selexol-based capture systems at the plant level show that an IL-based system could be a feasible option for CO2 capture. Improving the CO2 solubility of ILs can simplify the capture process configuration and lower the process energy and cost penalties to further enhance the viability of this technology.
This paper examines the cost of CO2 capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing ...method. This study takes a more systematic approach to analyze plants with an amine-based postcombustion CCS system with 90% CO2 capture. We employ sensitivity analyses together with a probabilistic analysis to quantify costs for plants with and without CCS under uncertainty or variability in key parameters. Results for new baseload plants indicate a likely increase in levelized cost of electricity (LCOE) of $20–32/MWh (constant 2007$) or $22–40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to $23–39/MWh and $25–46/MWh, respectively. Based on current cost estimates, our analysis further shows that a policy to encourage CCS at new NGCC plants via an emission tax or carbon price requires (at 95% confidence) a price of at least $125/t CO2 to ensure NGCC-CCS is cheaper than a plant without CCS. Higher costs are found for nonbaseload plants and CCS retrofits.
This study employs a power plant modeling tool to explore the feasibility of reducing unit-level emission rates of CO2 by 30% by retrofitting carbon capture, utilization, and storage (CCUS) to ...existing U.S. coal-fired electric generating units (EGUs). Our goal is to identify feasible EGUs and their key attributes. The results indicate that for about 60 gigawatts of the existing coal-fired capacity, the implementation of partial CO2 capture appears feasible, though its cost is highly dependent on the unit characteristics and fuel prices. Auxiliary gas-fired boilers can be employed to power a carbon capture process without significant increases in the cost of electricity generation. A complementary CO2 emission trading program can provide additional economic incentives for the deployment of CCS with 90% CO2 capture. Selling and utilizing the captured CO2 product for enhanced oil recovery can further accelerate CCUS deployment and also help reinforce a CO2 emission trading market. These efforts would allow existing coal-fired EGUs to continue to provide a significant share of the U.S. electricity demand.
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