CO2 Capture And Storage Technology Research Articles

Instantaneous Capture and Mineralization of Flue Gas Carbon Dioxide: Pilot Scale Study

Multiple CO2 capture and storage (CCS) processes are required to address anthropogenic CO2 problems. However, a method which can directly capture and mineralize CO2 at a point source, under actual field conditions, has advantages and could help offset the cost associated with the conventional CCS technologies. The mineral carbonation (MC), a process of converting CO2 into stable minerals (mineralization), has been studied extensively to store CO2. However, most of the MC studies have been largely investigated at laboratory scale. Objectives of this research were to develop a pilot scale AMC (accelerated mineral carbonation) process and test the effects of flue gas moisture content on carbonation of fly ash particles. A pilot scale AMC process consisting of a moisture reducing drum (MRD), a heater/humidifier, and a fluidized-bed reactor (FBR) was developed and tested by reacting flue gas with fly ash particles at one of the largest coal-fired power plants (2120 MW) in the USA. The experiments were conducted over a period of 2 hr at ~ 300 SCFM flow-rates, at a controlled pressure (115.1 kPa), and under different flue gas moisture contents (2-16%). The flue gas CO2 and SO2 concentrations were monitored before and during the experiments by an industrial grade gas analyzer. Fly ash samples were collected from the reactor sample port from 0-120 minutes and analyzed for total inorganic carbon (C), sulfur (S), and mercury (Hg). From C, S, and Hg concentrations, %calcium carbonate (CaCO3), %sulfate (SO42-), and %mercury carbonate (HgCO3) were calculated, respectively. Results suggested significant mineralization of flue gas CO2, SO2, and Hg within 10-15 minutes of reaction. Among different moisture conditions, ~16% showed highest conversion of flue gas CO2 and SO2 to %CaCO3 and %SO42- in fly ash samples. For example, an increase of almost 4% in CaCO3 content of fly ash was observed. Overall, the AMC process is cost-effective with minimum carbon footprint and can be retrofitted to coal fired power plants (existing and/or new) as a post-combustion unit to minimize flue gas CO2, SO2, and Hg emissions into the atmosphere. Used in conjunction with capture and geologic sequestration, the AMC process has the potential to reduce overall cost associated with CO2 separation/compression/transportation/pore space/brine water treatment. It could also help protect sensitive amines and carbon filters used in flue gas CO2 capture and separation process and extend their life.

Instantaneous Capture and Mineralization of Flue Gas Carbon Dioxide: Pilot Scale Study

AbstractMultiple CO2 capture and storage (CCS) processes are required to address anthropogenic CO2 problems. However, a method which can directly capture and mineralize CO2 at a point source, under actual field conditions, has advantages and could help offset the cost associated with the conventional CCS technologies. The mineral carbonation (MC), a process of converting CO2 into stable minerals (mineralization), has been studied extensively to store CO2. However, most of the MC studies have been largely investigated at laboratory scale. Objectives of this research were to develop a pilot scale AMC (accelerated mineral carbonation) process and test the effects of flue gas moisture content on carbonation of fly ash particles. A pilot scale AMC process consisting of a moisture reducing drum (MRD), a heater/humidifier, and a fluidized-bed reactor (FBR) was developed and tested by reacting flue gas with fly ash particles at one of the largest coal-fired power plants (2120 MW) in the USA. The experiments were conducted over a period of 2 hr at ~ 300 SCFM flow-rates, at a controlled pressure (115.1 kPa), and under different flue gas moisture contents (2-16%). The flue gas CO2 and SO2 concentrations were monitored before and during the experiments by an industrial grade gas analyzer. Fly ash samples were collected from the reactor sample port from 0-120 minutes and analyzed for total inorganic carbon (C), sulfur (S), and mercury (Hg). From C, S, and Hg concentrations, %calcium carbonate (CaCO3), %sulfate (SO42-), and %mercury carbonate (HgCO3) were calculated, respectively. Results suggested significant mineralization of flue gas CO2, SO2, and Hg within 10-15 minutes of reaction. Among different moisture conditions, ~16% showed highest conversion of flue gas CO2 and SO2 to %CaCO3 and %SO42- in fly ash samples. For example, an increase of almost 4% in CaCO3 content of fly ash was observed. Overall, the AMC process is cost-effective with minimum carbon footprint and can be retrofitted to coal fired power plants (existing and/or new) as a post-combustion unit to minimize flue gas CO2, SO2, and Hg emissions into the atmosphere. Used in conjunction with capture and geologic sequestration, the AMC process has the potential to reduce overall cost associated with CO2 separation/compression/transportation/pore space/brine water treatment. It could also help protect sensitive amines and carbon filters used in flue gas CO2 capture and separation process and extend their life.

Emissions of SO2 and NOx during Oxy−Fuel CFB Combustion Tests in a Mini-Circulating Fluidized Bed Combustion Reactor

Anthropogenic CO2 production is primarily driven by fossil fuel combustion, and the current energy demand situation gives no indication that this will change in the near future. In consequence, it is increasingly necessary to find ways to reduce these emissions when fossil fuel is used. CO2 capture and storage (CCS) appears to be among the most promising approaches. All of the CCS technologies involve producing a nearly pure stream of CO2, either by concentrating it in some manner from the flue gases or by using pure oxygen as the combustion gas. The latter option, oxy−fuel combustion, has now been well studied for pulverized coal combustion, but to date has received relatively little attention in the case of oxy−fuel circulating fluidized bed combustion (CFBC). Recently, oxy−fuel FBC has been examined in a 100 kW pilot plant operating with flue gas recycle at CanmetEnergy. The results strongly support the view that this technology offers all of the advantages of air-fired FBC, with one possible exception...

Nuclear Versus Coal Plus CCS: A Comparison of Two Competitive Base-Load Climate Control Options

In this paper we analyze the relative importance and mutual behavior of two competing base-load electricity generation options that each are capable of contributing significantly to the abatement of global CO2 emissions: nuclear energy and coal-based power production complemented with CO2 capture and storage (CCS). We also investigate how, in scenarios from an integrated assessment model that simulates the economics of a climate-constrained world, the prospects for nuclear energy would change if exogenous limitations on the spread of nuclear technology were relaxed. Using the climate change economics model WITCH we find that until 2050 the resulting growth rates of nuclear electricity generation capacity become comparable to historical rates observed during the 1980s. Given that nuclear energy continues to face serious challenges and contention, we inspect how extensive the improvements of coal-based power equipped with CCS technology would need to be if our model is to significantly scale down the construction of new nuclear power plants.

Long-term CO 2 emissions reduction target and scenarios of power sector in Taiwan

This study analyses a series of carbon dioxide (CO 2) emissions abatement scenarios of the power sector in Taiwan according to the Sustainable Energy Policy Guidelines, which was released by Executive Yuan in June 2008. The MARKAL-MACRO energy model was adopted to evaluate economic impacts and optimal energy deployment for CO 2 emissions reduction scenarios. This study includes analyses of life extension of nuclear power plant, the construction of new nuclear power units, commercialized timing of fossil fuel power plants with CO 2 capture and storage (CCS) technology and two alternative flexible trajectories of CO 2 emissions constraints. The CO 2 emissions reduction target in reference reduction scenario is back to 70% of 2000 levels in 2050. The two alternative flexible scenarios, Rt4 and Rt5, are back to 70% of 2005 and 80% of 2005 levels in 2050. The results show that nuclear power plants and CCS technology will further lower the marginal cost of CO 2 emissions reduction. Gross domestic product (GDP) loss rate in reference reduction scenario is 16.9% in 2050, but 8.9% and 6.4% in Rt4 and Rt5, respectively. This study shows the economic impacts in achieving Taiwan's CO 2 emissions mitigation targets and reveals feasible CO 2 emissions reduction strategies for the power sector.

Geological and geophysical aspects of the underground CO2 storage

Observed impact of carbon dioxide (CO2) emissions on the climate changes resulted in significant intensification of the research focused on the development of the technologies, which would enable CO2 capture from the flu gases and its safe storage in the adequately selected geological formations. The member countries of the European Union (UE-27) worked out special CCS (CO2 Capture and Storage) directive concerning industrial application of this technology. It must be emphasized, that extremely important and difficult from the technical point of view is its final stage connected with CO2 storage process itself. The paper presents key geological problems, which may occur during above mentioned stage of CCS technology, it draws also attention on the problem of monitoring the locations selected for CO2 storage. It points out significant role of geophysical methods for effective application in this domain.

Regulatory Framework to Accommodate Geological Storage of CO2 in Alberta

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121000, "Guidelines for a Regulatory Framework To Accommodate Geological Storage of CO2 in Alberta," by M. Zeidouni, SPE, M. Moore, and D. Keith, University of Calgary, prepared for the 2009 SPE Americas E&P Environmental & Safety Conference, San Antonio, Texas, 23-25 March. The paper has not been peer reviewed. A variety of methods has been proposed to reduce the effects of carbon dioxide (CO2) emissions. One method is CO2 capture and storage (CCS) in geological formations. Despite exceptional CCS potential in the Province of Alberta, Canada, legal and regulatory issues must be resolved to allow implementation. Without changes, there will not be enough certainty to enable the industry to make appropriate decisions that encourage investment. Introduction The Canadian federal government has announced a national objective to reduce emissions nationally by 20% from current levels by 2020, and by 60 to 70% by 2050. Various target levels have been defined for greenhouse-gas (GHG) emissions in Alberta. Alberta is the first province in Canada to introduce legislation to reduce GHG-emission intensity from large industrial sources. Large companies in Alberta emitting more than 100 000 t/a of GHGs will have to reduce their annual emissions intensity by 12%, or they will be charged USD 15/t (all costs are in 2005 dollars) above the 12% target. Alberta claims that it wants to cut its projected GHG emissions in half, by 200 Mt, by 2050. CCS CCS is a process for reducing GHG emissions into the atmosphere by first extracting CO2 from gas streams typically emitted during electricity production, fuel processing, and other industrial process. Once captured and compressed, the CO2 would be transported by pipeline or tanker to a storage site, often to be injected into an underground storage site (or geological formation). Potential sites for geological storage of CO2 include enhanced oil recovery by use of CO2, CO2 storage (CS) in depleted oil and gas reservoirs, replacement of methane by CO2 in deep coalbeds, injection of CO2 in deep saline aquifers, and CS in salt caverns. Among these options, saline aquifers possess the highest potential for CS in Alberta. Preliminary estimates indicate that the capacity of the Alberta basin to sequester CO2 dissolved in the formation waters at depths greater than 1000 m is on the order of 4000 Gt of CO2. Challenges and Deployment High capital costs and regulatory issues are the main challenges to CCS. Although all the components of CCS technology (i.e., capture, transport, and storage) are available and being demonstrated, they are not fully integrated in commercial-scale facilities. The current cost of CCS is USD 65 to 85/t of CO2. This cost is predicted to reduce to USD 20 to 30/t of CO2 after the technology is fully commercialized, which is expected to occur along with technology advancement after 2020. Financial and regulatory support is needed to make this happen. The industry requires policy and regulatory certainty to assess financial risks of carrying on with investment.

An integrated approach to CCS: A Canadian environmental superpower opportunity

Abstract The wide-scale public and governmental pressure to reduce the emissions of greenhouse gasses in developed nations has the potential to threaten the future growth and profitability of energy intensive industries. Because of this new paradigm, a group of 20 major oil & gas, power, fertilizer and chemical producers in Canada joined forces in 2005 to form the Integrated CO 2 Network (I CO 2 N) group of companies. This group recognized that developing CO 2 capture and storage (CCS) within a vision of a long -term, large-scale integrated system would ensure that the technology is developed as quickly and cost -effectively as possible, and would encourage continued economi c growth decoupled from increases in greenhouse gas (GHG) emissions. Decisions about a phased and integrated CCS system requires a long -term focus on Canada’s energy and environmental policy objectives (2020 and beyond). This paper outlines the efforts to date by I CO 2 N to move CCS for ward in Canada—through its work on the economics of deploying CCS technology in Canada, what deployment of an integrated CO 2 capture, transportation and storage network can look like and the evaluation of public private partnerships to share in the risks of early CCS adoption. Analysis is presented that quantifies the overall potential of the technology and explores the benefits and costs associated with CCS, including the associated benefits of the development of an EOR industry through the deployment o f an integrated CCS system. It also puts forward 5 key elements of deployment that are necessary to enable the widespread deployment of CCS at lowest possible cost. The I CO 2 N group of companies includes the following nineteen companies: Suncor, TransAlt a, Sherrit, Agrium, Air Products, Shell, Husky, ConocoPhillips, Syncrude, Imperial Oil, Nexen, Canadian Natural Resources Limited, Keyera, EPC OR, Total, Chevron, StatoilHydro, Opti, Devon, and BP.

How may CCS technology affect the electricity market in North-Western Europe?

Abstract The EU electricity market is changing. Electricity demand in Europe is on the rise, the power plant fleet is aging, and a large share of the capacity will need to be replaced in the coming decades. An ambitious target has been formulated for the share of renewable energy, and CO 2 prices are anticipated to increase. On top of this, CO 2 Capture and Storage (CCS) has appeared as an important technology in the transition to a long term sustainable energy supply. This paper discusses the implications all of the above developments for the EU electricity market, with an emphasis on the market North Western Europe. On the whole electricity prices in North Western Europe until 2020 are anticipated to increase, but this may only partly be ascribed to the pending introduction of CCS.

Capacity building in developing economies: building on the APEC and CSLF experience

Developing countries such as China, India, Mexico and Brazil are major energy producers and users, and emitters of CO2, and these countries are becoming aware of both the need to reduce anthropogenic CO2 emissions into the atmosphere and of CO2 capture and storage (CCS) as an enabling technology. One of the challenges faced in the implementation of CCS technologies, particularly in developing countries, is the shortage, sometimes absence, of a skilled technical and scientific workforce, but also a lack of knowledge about, and understanding of this technology among decision makers. The Asia Pacific Economic Cooperation (APEC) initiated in 2004 the development of a capacity building program that consisted of developing training modules and offering training workshops in developing countries around the Pacific Rim that are major CO2 emitters such as China, South Korea and Mexico. At the same time, the Carbon Sequestration Leadership Forum (CSLF) has established a Task Force on Capacity Building that has similarly developed a program for providing capacity building to the seven CSLF members that are developing economies. A series of capacity building workshops has been offered throughout 2007 and 2008. Based on the experience to date of both initiatives, some of the key learnings for future capacity building workshops are: 1) holding workshops in conjunction with a technical conference or similar event; 2) ensuring participation of key decision makers; 3) ensuring a varied workshop format; 4) ensuring that the workshop material addresses also the specific conditions of the host country; 5) ensuring organization of the material that allows flexible participation; and 6) providing printed material and simultaneous translation.

Study on multi-objective optimization of load dispatch including renewable energy and CCS technologies

This paper mainly studies the multi-objective optimization of load dispatch of power systems including renewable energy and CO2 capture and storage (CCS) technologies. The improved environmental/economic load dispatch model for the power system is constructed, considering the renewable energy utilization and CCS technologies. A novel singular weighted method (SWM) has been proposed in this paper for solving this kind of multi-objective and multi-constraint optimization problem. A power system with five generators has been applied in one case study to test the model and SWM. It was concluded that the share that each unit takes is not linear; however, the optimal results are largely relevant to the characteristics of the units. In addition, the research results showed that with the increment of the weight coefficient for a certain objective function, the optimization result was closer to the single optimization result for that objective function; and with the increase of forecast demand load, a 35 MW wind energy unit and a 200 MW water energy unit should be built. Copyright © 2009 John Wiley & Sons, Ltd.

日本におけるＣＯ２地中貯留の経済性評価

The official discussion on the post-Kyoto framework and target of CO2 emissions reductions began. In order to stabilize atmospheric CO2 emissions, the world should tackle to require deep cuts of CO2 emissions. CO2 capture and storage (CCS) technology is expected to play an important role in the deep cuts. This paper summarizes the cost of the geological storage of CO2 in Japan in order to consider future research, development and deployment (RDD these would be based on the information of the obtained cost structure. According to the analysis results, the costs, particularly those of the transportation by pipeline and of CO2 injection, strongly depend on the scale of the facilities. Therefore, the distance of the transportation of CO2 should be minimized in the case of small-scale storage, particularly in Japan. A mixed-integer programming model has been developed to take into account the adverse effects arising from the scale of economy with regard to the transportation and injection cost for the geological storage of CO2. The model is designed to evaluate CCS and other CO2 mitigation technologies in the energy systems of Japan. With all these adverse effects due to the scale of economy, the geological storage of CO2 will still be one of the important options for CO2 emission reduction in Japan for most of the analyzed cases in this study.

CO2 Capture and Storage with Leakage in an Energy-Climate Model

Geological CO2 capture and storage (CCS) is among the main near-term contenders for addressing the problem of global climate change. Even in a baseline scenario, with no comprehensive international climate policy, a moderate level of CCS technology is expected to be deployed, given the economic benefits associated with enhanced oil and gas recovery. With stringent climate change control, CCS technologies will probably be installed on an industrial scale. Geologically stored CO2, however, may leak back to the atmosphere, which could render CCS ineffective as climate change reduction option. This article presents a long-term energy scenario study for Europe, in which we assess the significance for climate policy making of leakage of CO2 artificially stored in underground geological formations. A detailed sensitivity analysis is performed for the CO2 leakage rate with the bottom-up energy systems model MARKAL, enriched for this purpose with a large set of CO2 capture technologies (in the power sector, industry, and for the production of hydrogen) and storage options (among which enhanced oil and gas recovery, enhanced coal bed methane recovery, depleted fossil fuel fields, and aquifers). Through a series of model runs, we confirm that a leakage rate of 0.1%/year seems acceptable for CCS to constitute a meaningful climate change mitigation option, whereas one of 1%/year is not. CCS is essentially no option to achieve CO2 emission reductions when the leakage rate is as high as 1%/year, so more reductions need to be achieved through the use of renewables or nuclear power, or in sectors like industry and transport. We calculate that under strict climate control policy, the cumulative captured and geologically stored CO2 by 2100 in the electricity sector, when the leakage rate is 0.1%/year, amounts to about 45,000 MtCO2. Only a little over 10,000 MtCO2 cumulative power-generation-related emissions are captured and stored underground by the end of the century when the leakage rate is 1%/year. Overall marginal CO2 abatement costs increase from a few €/tCO2 today to well over 150 €/tCO2 in 2100, under an atmospheric CO2 concentration constraint of 550 ppmv. Carbon costs in 2100 turn out to be about 40 €/tCO2 higher when the annual leakage rate is 1%/year in comparison to when there is no CO2 leakage. Irrespective of whether CCS deployment is affected by gradual CO2 seepage, the annual welfare loss in Europe induced by the implementation of policies preventing “dangerous anthropogenic interference with the climate system” (under our assumption, implying a climate stabilisation target of 550 ppmv CO2 concentration) remains below 0.5% of GDP during the entire century.

Directed technical change and the adoption of CO 2 abatement technology: The case of CO 2 capture and storage

This paper studies the cost-effectiveness of combining traditional environmental policy, such as CO 2-trading schemes, and technology policy that has aims of reducing the cost and speeding the adoption of CO 2 abatement technology. For this purpose, we develop a dynamic general equilibrium model that captures empirical links between CO 2 emissions associated with energy use, directed technical change and the economy. We specify CO 2 capture and storage (CCS) as a discrete CO 2 abatement technology. We find that combining CO 2-trading schemes with an adoption subsidy is the most effective instrument to induce adoption of the CCS technology. Such a subsidy directly improves the competitiveness of the CCS technology by compensating for its markup over the cost of conventional electricity. Yet, introducing R&D subsidies throughout the entire economy leads to faster adoption of the CCS technology as well and in addition can be cost-effective in achieving the abatement target.

Economic evaluation of the geological storage of CO 2 considering the scale of economy

CO 2 capture and storage (CCS) technology is expected to play an important role in the efforts directed toward long-term CO 2 emission reduction. This paper analyzes the cost of the geological storage of CO 2 in Japan in order to consider future research, development and deployment (RD&D); these would be based on the information of the obtained cost structure. According to the analysis results, the costs, particularly those of the transportation by pipeline and of CO 2 injection, strongly depend on the scale of the facilities. Therefore, the distance of the transportation of CO 2 should be minimized in the case of small-scale storage, particularly in Japan. In addition, the potential injection rate per well is another key factor for the injection cost. Based on the analyzed cost, the injection cost of the geological storage of CO 2 in Japan for individual storage sites is estimated, and the cost–potential curve is obtained. A mixed-integer programming model has been developed to take into account these characteristics of the CCS technology and its adverse effects arising from the scale of economy with regard to the transportation and injection cost for the geological storage of CO 2. The model is designed to evaluate CCS and other CO 2 mitigation technologies in the energy systems of Japan. With all these adverse effects due to the scale of economy, the geological storage of CO 2 will be one of the important options for CO 2 emission reduction in Japan.

The low cost of geological assessment for underground CO2 storage: Policy and economic implications

The costs for carbon dioxide (CO2) capture and storage (CCS) in geologic formations is estimated to be $6–75/t CO2. In the absence of a mandate to reduce greenhouse gas emissions or some other significant incentive for CCS deployment, this cost effectively limits CCS technology deployment to small niche markets and stymies the potential for further technological development through learning by doing until these disincentives for the free venting of CO2 are in place. By far, the largest current fraction of these costs is capture (including compression and dehydration), commonly estimated at $25–60/t CO2 for power plant applications, followed by CO2 transport and storage, estimated at $0–15/t CO2. Of the storage costs, only a small fraction of the cost will go to accurate geological characterization. These one time costs are probably on the order of $0.1/t CO2 or less as these costs are spread out over the many millions of tons likely to be injected into a field over many decades. Geologic assessments include information central to capacity prediction, risk estimation for the target intervals and development facilities engineering. Since assessment costs are roughly two orders of magnitude smaller than capture costs, and assessment products carry other tangible societal benefits, such as improved accuracy in fossil fuel and ground water reserves estimates, government or joint private–public funding of major assessment initiatives should underpin early policy choices regarding CO2 storage deployment and should serve as a point of entry for policy makers and regulators. Early assessment is also likely to improve the knowledge base upon which the first commercial CCS deployments will rest.

Identifying Cost-Effective CO2 Control Levels for Amine-Based CO2 Capture Systems

Studies of CO2 capture and storage (CCS) from coal-fired power plants typically assume a capture efficiency near 90%, although the basis for a particular choice usually is not discussed. Nor do studies systematically explore a range of CO2 capture efficiencies to identify the most cost-effective levels of CO2 control and the key factors that affect such levels. An exploration of these issues is the focus of this paper. As part of the United States Department of Energy's Carbon Sequestration Program, we have developed an integrated modeling framework (called IECM-cs) to evaluate the performance and cost of alternative CCS technologies and power systems in the context of plant-level multipollutant control requirements. This paper uses IECM-cs to identify the most cost-effective level of CO2 control using currently available amine-based CO2 capture technology for PC plants. Two general cases are of interest. First, we examine the effects of systematically increasing the CO2 capture efficiency of an amine-based system for PC applications over a broad range. We report two measures of cost: (i) capital cost and (ii) cost-effectiveness (cost per tonne of CO2 avoided) relative to similar plants without CCS. Second, we examine the cost-effectiveness of plant designs that partially bypass the amine capture unit so as to achieve low to moderate reductions of CO2, but at lower overall cost. Results from these cases are compared to the conventional case of a capture unit treating the entire flue gas stream. In each case, we identify the most cost-effective strategies and the key factors that affect those results.