CCS Costs Research Articles

Carbon prices and CCS investment: A comparative study between the European Union and China

Carbon Capture and Storage is considered as a key option for climate change mitigation; policy makers and investors need to know when CCS becomes economically attractive. Integrating CCS in a power plant adds significant costs which can be offset by a sufficient CO2 price. However, most markets have failed: currently, the weak carbon price threatens CCS deployment in the European Union (EU). In China, a carbon regulation is appearing and CCS encounters a rising interest. This study investigates two questions: how much is the extra-cost of a CCS plant in the EU in comparison with China? Second, what is the CO2 price beyond which CCS plants become more profitable than reference plants in the EU and in China? To address these issues, I conducted a literature review on public studies about CCS costs. To objectively assess the profitability of CCS plants, I constructed a net present value model to calculate the Levelised Cost of Electricity and the breakeven CO2 price. CCS plants become the most profitable plant type beyond 115€/tCO2 in the EU vs. 45€/tCO2 in China (offshore transport and storage costs). I advise on the optimal plant type choice depending on the CO2 price in both countries.

Development of a techno-economic model for dynamic calculation of cost of electricity, energy demand and CO2 emissions of an integrated UCG–CCS process

Underground coal gasification (UCG) allows for the utilization of coal reserves not exploitable due to unfavorable geology and economic boundary conditions. The present study examines underground coal gasification economics converting deep-situated coals into a high-calorific UCG synthesis gas. Utilizing UCG synthesis gas to fuel a combined cycle gas turbine (CCGT) considering CO2 capture and its subsequent storage (CCS) in the underground voids resulting from coal consumption, the coupled process offers an economic low carbon option to coal fired power generation for a study area in Bulgaria. The selected coal deposit is not suitable for conventional mining due to great depths, but it may be exploitable by UCG. Cost-effectiveness, CO2 emissions and energy demand of the coupled process are analyzed using a techno-economic model specifically developed for that purpose. Capital and operational expenditure are ascertained from calculations considering six dynamic sub-models describing the UCG-CCGT-CCS process flow and aiming at determination of the costs of electricity (COE). Calculation results show that COE account to 71.67 €/MWh considering 20.5% CCS costs and 79.5% emission charges. The results show that the coupled UCG-CCGT-CCS process should be considered as an economic and low carbon option for power generation for the selected study area.

Preliminary Feasibility Study for On-Site Hydrogen Station with Distributed CO2 Capture and Storage System

Abstract It is important to produce Carbon-Free Hydrogen for FCV. Current Japanese situation, it is difficult to fully supply the Carbon Free Hydrogen is generated by water-electrolysis (WER) using renewable energy. This study presents the Steam reforming for natural gas (NSR) with decentralized CCS system for producing Carbon-Free Hydrogen. The CCS cost is covered by the differential cost between WER and NSR Hydrogen production cost. Our preliminary investigation suggests the differential cost between WER and NSR Hydrogen enough to cover the cost of decentralized CCS (under 1000 ton-CO2/y). We also analyze the feasibility of Mother-Daughter type of Hydrogen supplement system with decentralized CCS. In this case, NSR with CCS system has advantage against WER Hydrogen production systems. These investigations clearly indicate the high potential of NSR with CCS system but it is carefully discussion about CO2 behavior in the reservoir by well-established and newly developing methods for safety.

Modelling the Deployment of CO2 Storage in U.S. Gas-bearing Shales

Abstract The proliferation of commercial development in U.S. gas-bearing shales helped to drive a twelve-fold increase in domestic gas production between 2000 and 2010, and the nation's gas production rates continue to grow. While shales have long been regarded as a desirable caprock for CCS operations because of their low permeability and porosity, there is increasing interest in the feasibility of injecting CO2 into shales to enhance methane recovery and augment CO2 storage. Laboratory work published in recent years observes that shales with adsorbed methane appear to exhibit a stronger affinity for CO2 adsorption, offering the potential to drive additional CH4 recovery beyond primary production and perhaps the potential to store a larger volume of CO2 than the volume of methane displaced. Recent research by the authors on the revenues associated with CO2-enhanced gas recovery (CO2-EGR) in gas-bearing shales estimates that, based on a range of EGR response rates, the average revenue per ton of CO2 for projects managed over both EGR and subsequent storage-only phases could range from $0.50 to $18/tCO2. While perhaps not as profitable as EOR, for regions where lower-cost storage options may be limited, shales could represent another “early opportunity” storage option if proven feasible for reliable EGR and CO2 storage. Significant storage potential exists in gas shales, with theoretical CO2 storage resources estimated at approximately 30-50 GtCO2. However, an analysis of the comprehensive cost competitiveness of these various options is necessary to understand the degree to which they might meaningfully impact U.S. CCS deployment or costs. This preliminary analysis shows that the degree to which EGR-based CO2 storage could play a role in commercial-scale deployment is heavily dependent upon the offsetting revenues associated with incremental recovery; modeling the low revenue case resulted in only five shale-based projects, while under the high revenue case, shales accounted for as much as 20 percent of total U.S. storage in the first 20 years of deployment. Interestingly, even in this highest revenue case, there appear to be no negative-cost projects that would be profitable in a no-policy environment as modeled under the assumptions employed. While this reflects a very first look at the potential for shales, it is clear that more laboratory and experimental work are needed to reduce uncertainty in key variables and begin to differentiate and identify high-potential shales for early pilot study.

Integrating Carbon Capture and Storage with Energy Production from Saline Aquifers: A Strategy to Offset the Energy Cost of CCS

Abstract Extraction of brine containing methane and geothermal energy from saline aquifers has been considered as a method to offset the cost of carbon capture and storage. This study estimates the potential of power generation from methane and heat and compares it with the power required for capture and storage. Nine aquifer models were prepared from average conditions of several wells in the Gulf Coast at depths from 8,000 to 16,000 ft. Reservoir simulation study was performed to estimate the amounts of stored carbon dioxide and produced methane and heat. The study found that the power generation potential from below the depth of 11,000 ft offsets the power required for capture and storage processes.

Development Status and Energy Penalty of Carbon Dioxide Capture Technologies

Carbon dioxide is claimed to be responsible for 60 percent of the global warming caused by greenhouse gases. CCS is important for reducing CO2emissions. Most technologies are in demonstration stage. Carbon capture accounts for two thirds of total cost of CCS. The trend of CCS is also described.

Examining CCS Deployment Potential in China Via Application of an Integrated CCS Cost Curve

Previously published cost curves focusing on CO2 transport and storage have helped illustrate the large potential for CCS technologies to deploy in China. This paper examines results from recent work to incorporate the costs of CO2 capture and compression into integrated cost curves that more fully reflect expected costs across the set of large, industrial CO2 sources and better illuminate the possible value of CCS to this fast-growing economy. Results show that significant potential exists for large-scale deployment of CCS at costs less than $70/tCO2. Mapping the cost curve results confirms that the majority of existing CO2 point sources may be able to utilize CCS technologies, and that except for many sources in southern China onshore storage capacity appears accessible and sufficient for decades of large-scale deployment.

Cutting costs of catching carbon—Intertemporal effects under imperfect climate policy

We use a two-period model to investigate intertemporal effects of cost reductions in climate change mitigation technologies for the power sector. The effect of cost reductions for CCS depends on how carbon taxes are set. If there is no carbon tax in period 1, but an optimally set carbon tax in period 2, a CCS cost reduction may reduce early emissions. Such an innovation may therefore be more desirable than comparable cost cuts related to renewable energy. The finding rests on the incentives fossil fuel owners face. If future profitability is reduced, they speed up extraction (the ‘green paradox’), and vice versa.

Technology Focus: CO2 Applications (July 2011)

Technology Focus The CO2 supply-and-demand trends for enhanced-oil-recovery (EOR) projects are diverging, and many EOR projects, especially in the US, are hindered by lack of sufficient economic CO2 volume and infrastructure. The CO2-supply deficiency—and because a portion of the estimated 30+ Gt/year of anthropogenic CO2 worldwide could supply future EOR projects sufficiently—is driving the EOR industry to be an enabler for early carbon-capture-and-storage (CCS)/sequestration technology and infrastructure development. As EOR/CCS develops, the potentially huge, yet unproven, storage capacity of deep saline formations may become more realistic. The methodology of how to quantify and use saline aquifers is in the developing stages with technical debates. Geotechnical and transportation issues for CCS are similar to those for EOR processes, but there are differences because of their different purposes. EOR projects have fairly short-term time scales, of several 10s of years after initiation of EOR processes. CCS projects have similar 10s of years of injection time, but indefinite time scales (1,000s of years) for the mineralization processes to be effective. Geological and mineralogical models; coupled geochemistry, geomechanical, and transport models; seal-integrity issues typical of hydrocarbon-phase-behavior physics; large time-scale differences; subsurface uncertainties; and limited or no performance data complicate optimization of CO2-capacity determination and efforts to model the CCS process(es) and sites compared with modeling typical or even atypical EOR projects. Except for natural-gas plants, business models of large stationary facilities generally view CO2 as a waste. To an operator, CO2 is an expensive but useful fluid to enhance hydrocarbon recovery. In May 2010, the US Environmental Protection Agency issued its final rule addressing greenhouse-gas emissions from large stationary sources and defined CO2 as a pollutant at certain high concentrations, not as a waste. Future business venues for EOR/CCS most likely will include partnerships and alliances with power plants and other large stationary generators to provide and economically capture, use, and store CO2, thus creating a limited CCS industry enabled by the EOR industry. CO2 Applications additional reading available at OnePetro: www.onepetro.org SPE 139588 • “The Significance of Caprock-Sealing Integrity for CO2 Storage” by A. Busch, Shell, et al. SPE 134028 • “Drainage and Imbibition CO2/Brine Relative Permeability Curves at Reservoir Conditions for Carbonate Formations” by D. Brant Bennion, SPE, Weatherford, et al. SPE 131609 • “Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK” by Min Jin, SPE, Heriot-Watt University, et al. SPE 139716 • “Perspectives on CCS Cost and Economics” by H.S. Kheshgi, SPE, ExxonMobil, et al.

Carbon capture and storage in China — main findings from China-UK Near Zero Emissions Coal (NZEC) initiative

Abstract The China-UK Near Zero Emissions Coal (NZEC) Initiative examined options for carbon (CO 2 ) capture, transport and geological storage in China. It was developed under the 2005 EU-China NZEC Agreement which aims to demonstrate CCS in China and the EU. Collaborative research activities were conducted jointly by Chinese and UK experts from 30 organisations. China’s energy demand is expected to continue growing significantly; however the share of coal is projected to decrease to around 50% by 2050. For the power generation and energy intensive industrial sectors, all of which remain heavily dependent on coal, CCS is the only option that can ensure a significant reduction in CO 2 emissions. A range of CO 2 capture technologies in coal-fired power generation have been examined. The more promising, near term options are post-combustion capture using Monoethanolamine in a state of the art pulverised coal power plant and pre-combustion capture in an Integrated Gasification Combined Cycle unit. The cost of electricity generation with capture would be 463 and 413 RMB per MWh respectively for these options. Less mature capture technology options offer some potential to lower the overall cost, but this is within the range of uncertainties. Storage assessments were undertaken in two basins in North East China. These have potential to make use of CO 2 for Enhanced Oil Recovery (EOR) although the reservoirs are geologically complex and well integrity may be a significant risk. While CO 2 EOR would provide the opportunity for gaining initial experience with CO 2 injection and storage, the capacity available for EOR in these regions appears insufficient for large scale CCS. It would therefore be necessary to assess and ultimately use saline aquifers for storage. An extensive saline aquifer formation has been identified in the Songliao Basin through the project. The average cost of electricity generation taking account of capture, transport and storage costs (assuming a storage site 200 km from the power plant) would be 470 RMB per MWh for the most mature capture options, an increase of around 200 RMB per MWh compared with a Pulverised Coal reference plant without CCS. This is equivalent to a cost of avoided emissions of about 280 RMB (US $50.0) per tonne of CO 2 . There are several challenges that need to be addressed for CCS in China. These include the extra cost and energy penalty of CCS, the novelty of the technology, the lack of regulations governing the storage of CO 2 underground and the availability of the necessary equipment for deployment of CCS in China. The China-UK NZEC Initiative has shown that CCS could provide a key, low carbon option for coal-based industry in China, particularly for power generation, which would enable the continued use of coal with reduced greenhouse gas emissions. An Memorandum of Understanding was signed by the European Commission and Chinese Ministry of Science and Technology for Phase II of the China-EU NZEC Agreement in November 2009. Phase II will involve the selection of a demonstration project and the completion of a feasibility study. Phase III will involve the construction and operation of a CCS demonstration project in China.

New CCS system integration with CO2 carrier and liquefaction process

Abstract For most CCS projects, captured CO2 is transported by pipeline, in contrast to shipping it, which has only been introduced as a secondary option for long distances and small amounts. This paper provides some possible alternatives to reduce the total cost of CCS through CO2 shipping. The benefits of HP pump in power consumption is considered and a new total CCS chain is suggested, which can be divided into capture, liquefaction (or compression to supercritical fluid), transport by ship, compression by HP pump, and storage. With a highly efficient liquefaction process, CO2 shipping costs can be reduced under a new total CCS chain. The results of our study show that an optimal size needs to be adopted for each CCS project, enabling CO2 shipping to be more cost efficient. DSME has developed a concept design for a large CO2 carrier that has the potential to be more cost-effective than conventional transport. Therefore, CO2 transport by ship should now be seriously re-considered as an effective transport method on a project-by-project basis.

Numerical studies on the aquifer storage of CO2 containing N2

Abstract The high cost of CO 2 capture is the one of most important barriers to large-scale CCS deployment. Impure CO 2 geological storage might be a cost-effective way to cut down the total cost of CCS by lowering the requirement of CO 2 capture or revenue-adding impurities. Primary cost analysis shows that injection of CO 2 containing some part N 2 might cut down the total CCS cost by lowing the capture requirement of CO 2 . Based on PVT characters of N 2 -CO 2 mixture, viscosity, relative permeability, capillary pressure model, hydraulic dispersion, geochemistry and COMSOL-Multiphysics software, the simulation tool is established and the migration process of N 2 -CO 2 mixture in sandstone core was studied by the tool. The numerical simulation have shown that preferential CO 2 solubility in brine compared to that of N 2 results in CO 2 being stripped off at the leading edge of the displacement front of fluid mixture containing N 2 that advances through the aqueous phase. The chromatographic partitioning process of CO 2 in gas phase can separate nitrogen and trap CO 2 in aquifer during preferential flow process, which caused by preferential solubility and mineral trapping during the CO 2 displacement process. The impact of N 2 will affect the migration of CO 2 plume, especially the migration front a lot underground

Jumpstarting CCS using refinery CO2 for enhanced oil recovery

Abstract Widespread adoption of carbon [dioxide] capture and storage (CCS) is limited by infrastructure, market, and cost barriers. Like most nascent technologies, it will be critical to overcome these barriers to fully realize the potential of CCS. Capturing CO2 from the oil refining process and using this CO2 for enhanced oil recovery (EOR) is an appealing scenario for knocking down these barriers, jumpstarting a CCS industry, and driving down the cost of CCS technology. CO2 capture from oil refineries can be relatively inexpensive when compared to other stationary sources (supply), EOR provides a market for CO2 (demand), and the spatial proximity of oil fields and refineries reduces transportation issues (cost, right of way, etc.). The oil industry should play a key role in the evolution of CCS since it has vested interests and experience with capturing, transporting, and injecting (and storing) CO2 underground. In this paper we study the deployment of CCS infrastructure to support CO2 capture from the oil refining industry and EOR and long term geologic storage of the CO2 for the US Gulf States. This region accounts for approximately 45% of US refining capacity, a large percentage of active EOR projects, and an extensive network of pipeline rights-of-way (natural gas, crude and refined oil) including over 80% of the existing CO2 pipelines. Presently, the oil industry predominantly uses natural sources of CO2 for EOR; an obvious goal of integrating CCS technology into the oil industry is displace the natural CO2 sources with anthropogenic CO2. The region is also responsible for approximately 450 Mt CO2 emissions annually from fossil-fuel electricity generation; an oil industry-driven CO2 market and CCS infrastructure could provide the necessary stimulus for capturing this CO2 in the coming decades. Our approach uses an economic-engineering model to geospatially deploy CCS infrastructure (capture, transportation, and storage) in response to a price on CO2 or a desired CO2 capture amount. The model considers and integrates each of the interdependent CCS components. It calculates at which oil refineries it is cost -effective to capture CO2, where and how new CO2 pipelines should be networked together, and which EOR oil fields balance CCS costs and CO2 credit as well as providing the best long term storage potential. The combination of capture, transport, and storage infrastructure is highly dependent on the CO2 price, both as an inducement (for EOR) and disincentive (price to emit CO2). Consequently, we examine how the expansion of CCS infrastructure could develop given differing CO2 scenarios, including variation in capture and storage costs. Our results show how a CO2 management network (capture, transport, and storage infrastructure) could develop given a set of oil refineries and EOR reservoirs in the US Gulf Coast region. The model outputs and results can be used to help plan policy and regulation for CO2 capture and storage, and help guide how the oil industry could jumpstart a CCS industry.

How storage uncertainty will drive CCS infrastructure

Abstract This study focuses on the basin and site scales to identify physical constraints for CO2 injection and source-sink infrastructure. We analyze the sequestration of CO2 emissions associated with conventional and unconventional fossil fuel development in the Uinta-Piceance Basins, Colorado and Utah, USA. This area is underlain by abundant saline formations with excellent potential geologic sequestration. Land access, as a proxy for pore space access, is an important consideration in this area of rugged terrain, protected natural areas, and Indian and private lands. We integrate a model o f geologic CO2 sequestration (CO2-PENS) and a model of infrastructure optimization (SimCCS) to evaluate the design of CCS infrastructure under uncertainty. This research focuses on the effect of uncertainty in properties of sequestration reservoirs on CCS infrastructure, including the dedicated CO2 pipeline network and which sources should capture CO2 or where new CO2 emitting facilities should be located. CO2 source emissions and capture costs can be estimated with reasonable certainty based on current separation technologies. In contrast, the actual capacity and injectivity of saline aquifers (sinks) may vary over several orders of magnitude compared with estimated values, due to geologic heterogeneities that affect porosity, permeability, thickness, and extent of the saline aquifers. We report on modeling using CO2-PENS, an injectivity/capacity and risk assessment simulator package for geologic sequestration, and SimCCS, a geospatial decision optimization model for comprehensively designing CCS infrastructure. CO2-PENS uses statistically distributed input parameter values to characterize CO2 migration through the sequestration reservoir, caprock, and overlying freshwater aquifers, as well as potential leakage pathways like wellbores and faults. Representative parameter ranges were developed for the Cretaceous Castlegate and Jurassic Entrada sandstones, widespread permeable saline formations in the UintaPiceance basins. A GIS mask based on land use, land ownership, slope, and hydrology was developed to define land surface access for developing sequestration sites. Several sites of varying area and formation depth were defined for both the Castlegate and Entrada formations. Using the Monte Carlo modeling capability of CO2-PENS, multiple realizations were run for each site in order to develop probability density functions (PDFs) of reservoir capacity and cost for sequestration of various rates of CO2 delivery. These PDFs were provided to SimCCS for use in the calculation of optimal pipeline networks among CO2 sources and sinks. SimCCS plans CCS infrastructure with respect to objective functions that include information on financial budget, regional CO2 capture target, or a price on carbon (i.e., what scale of infrastructure is economically feasible). Because the model simultaneously examines source-network-sink components, it is ideal for analyzing the impact of sink uncertainty on overall CCS infrastructure. Model outputs include CCS costs, spatial network routing, and the scale at which deploying CCS infrastructure makes sense. Coupling CO2-PENS and SimCCS, both state-of-the-art models, allows us for the first time to examine how reservoir uncertainty propagates through, or even drives, the entire CCS infrastructure system. In our study this effect is evidenced by preferential selection of sinks with spatially proximal alternatives, robust pipeline networks that can respond to changes in CO2 flow, and sources chosen that make economical sense (though not necessarily financially optimal) and integrate well into a dynamic CCS system.

An energy network with polygeneration system and CCS suitable for China

Abstract An energy network with polygeneration system and CCS suitable for China was proposed in our previous work in consideration of low-cost CCS and energy providing safety. In this paper, based on life-cycle analysis, the role of the Energy Network has been investigated at the national level. Results show that with the import dependency of oil controlled in the range of 40%–60% during 2020 to 2030, up to 22% of the total capacity of coal fired supercritical power plants may be replaced by hundreds of new polygeneration plants for electricity and alternative fuels. When the oil import dependency will be kept from 40% to 60%, the Energy Network can save 20%–30% of energy and cut down 30%–40% of total costs every year compared to the present method with coal fired supercritical power plants and traditional alternative fuel plants with CO 2 capture. And the Energy Network can capture more than 0.1 billion tons of CO 2 with high concentration over 98% each year. Moreover, from the aspect of CCS, this Energy Network can realize as low as 15$/t of total CCS cost due to the quite low energy penalties of CO 2 capture in the polygeneration systems and the combination of CO 2 sources and storage sites. The new Energy Network has realized the proper combination of energy utilization and CO 2 capture and storage according to the unique state of China. It is suitable for China and may play an important role in CCS in the future.

A comparative analysis of regulations for the geologic storage of carbon dioxide

Abstract This paper presents a summary of the main international and national regulations for geologic storage of carbon dioxide. The international group includes the EU Directives, London Convention, and OSPAR. For the national regulations, three countries were covered in this study: United States, Canada, and Australia. In addition to these regulations, a group of guidelines and best practice manuals were also included in this study. As discussion, although this paper recognizes that current legislations have contributed for the regulation of this technology, it is still necessary the development of new rules in other regions. Industry will not invest in large CCS plants without such regulations because of high CCS costs and large financial risks related to CCS.

Geocapacity: economic feasibility of CCS in networked systems

A Decision Support System (DSS) has been developed to evaluate the technical and economical feasibility of CO2 storage in the subsurface. The DSS performs a detailed, stochastic analysis of the technical and economical aspects of a CCS project, which consists of any number of CO2 sources and sinks plus the connecting pipeline network. The DSS uses the database of CO2 emission points and storage locations in Europe that has been compiled in the EU Geocapacity project. The system is a combination of an internet application, which visualises the database and allows the user to select sources and sinks and create a pipeline network, and an application to be run on a local computer, which performs a stochastic analysis of the costs of a CO2 capture, transport and storage system. The DSS provides not only an estimate of the total CCS cost, but also an analysis of the elements in the CCS chain (capture, compression, transport and storage), enabling a feasibility analysis on several levels. © 2009 Elsevier Ltd. All rights reserved.