Intermediate storage of carbon dioxide in geological formations: A technical perspective

Enhanced oil recovery (EOR) through CO₂ flooding has been practiced on a commercial basis for the last 35 years and continues today at several sites, currently injecting in total over 30 million tons of CO₂ annually. This practice is currently exclusively for economic gain, but can potentially contribute to the reduction of emissions of greenhouse gases provided it is implemented on a large scale. Optimal operations in distributing CO₂ to CO₂-EOR or enhanced gas recovery (EGR) projects (referred to here collectively as CO₂-EHR) on a large scale and long time span imply that intermediate storage of CO₂ in geological formations may be a key component. Intermediate storage is defined as the storage of CO₂ in geological media for a limited time span such that the CO₂ can be sufficiently reproduced for later use in CO₂-EHR. This paper investigates the technical aspects, key individual parameters and possibilities of intermediate storage of CO₂ in geological formations aiming at large scale implementation of carbon dioxide capture and storage (CCS) for deep emission reduction. The main parameters are thus the depth of injection and density, CO₂ flow and transport processes, storage mechanisms, reservoir heterogeneity, the presence of impurities, the type of the reservoirs and the duration of intermediate storage. Structural traps with no flow of formation water combined with proper injection planning such as gas-phase injection favour intermediate storage in deep saline aquifers. In depleted oil and gas fields, high permeability, homogeneous reservoirs with structural traps (e.g. anticlinal structures) are good candidates for intermediate CO₂ storage. Intuitively, depleted natural gas reservoirs can be potential candidates for intermediate storage of carbon dioxide due to similarity in storage characteristics.     

Geological storage of CO2 in saline aquifers—A review of the experience from existing storage operations

The experience from CO₂ injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snøhvit, In Salah, acid-gas injection) demonstrates that CO₂ geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO₂ plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO₂ had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO₂/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.     

A model for the CO2 capture potential

Global warming is a result of increasing anthropogenic CO₂ emissions, and the consequences will be dramatic climate changes if no action is taken. One of the main global challenges in the years to come is therefore to reduce the CO₂ emissions.Increasing energy efficiency and a transition to renewable energy as the major energy source can reduce CO₂ emissions, but such measures can only lead to significant emission reductions in the long-term. Carbon capture and storage (CCS) is a promising technological option for reducing CO₂ emissions on a shorter time scale.A model to calculate the CO₂ capture potential has been developed, and it is estimated that 25 billion tonnes CO₂ can be captured and stored within the EU by 2050. Globally, 236 billion tonnes CO₂ can be captured and stored by 2050. The calculations indicate that wide implementation of CCS can reduce CO₂ emissions by 54% in the EU and 33% globally in 2050 compared to emission levels today.Such a reduction in emissions is not sufficient to stabilize the climate. Therefore, the strategy to achieve the necessary CO₂ emissions reductions must be a combination of (1) increasing energy efficiency, (2) switching from fossil fuel to renewable energy sources, and (3) wide implementation of CCS.     

Regulatory challenges and managing public perception in planning a geological storage pilot project in Australia

The implementation of geological storage of CO₂ requires not only further research and development but also the demonstration of carbon dioxide capture and storage (CCS) technology as a viable option. A pilot program is an important first step towards building industry and community confidence in the application of CCS. The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Australia's leading research organisation in CCS, has initiated a comprehensive research and demonstration program in the Otway Basin in South-West Victoria. As the first project of its kind in Australia, the Otway Basin Pilot Project (OBPP) has faced a number of regulatory and organisational challenges while having to concurrently address public perception. The Otway Basin site with its natural CO₂ accumulations and many depleted natural gas fields offers an appropriate CO₂ storage site to test scientific and regulatory concepts and evaluate public response through social research. The project aims to show that CO₂ can be safely captured, transported and stored deep underground under local conditions, and also monitored and verified. Planning has been ongoing for over a year, baseline studies are underway and the project is targeted to start injection in 2007.     

The impact of electric passenger transport technology under an economy-wide climate policy in the United States: Carbon dioxide emissions,coal use,and carbon dioxide capture and storage

Plug-in hybrid electric vehicles (PHEVs) have the potential to be an economic means of reducing direct (or tailpipe) carbon dioxide (CO₂) emissions from the transportation sector. However, without a climate policy that places a limit on CO₂ emissions from the electric generation sector, the net impact of widespread deployment of PHEVs on overall U.S. CO₂ emissions is not as clear. A comprehensive analysis must consider jointly the transportation and electricity sectors, along with feedbacks to the rest of the energy system. In this paper, we use the Pacific Northwest National Laboratory's MiniCAM model to perform an integrated economic analysis of the penetration of PHEVs and the resulting impact on total U.S. CO₂ emissions. In MiniCAM, the deployment of PHEVs (or any technology) is determined based on its relative economics compared to all other methods of providing fuels and energy carriers to serve passenger transportation demands. Under the assumptions used in this analysis where PHEVs obtain 50–60% of the market for passenger automobiles and light-duty trucks, the ability to deploy PHEVs under the two climate policies modelled here results in over 400 million tons (MT) CO₂ per year of additional cost-effective emissions reductions from the U.S. economy by 2050. In addition to investments in nuclear and renewables, one of the key technology options for mitigating emissions in the electric sector is CO₂ capture and storage (CCS). The additional demand for geologic CO₂ storage created by the introduction of the PHEVs is relatively modest: approximately equal to the cumulative geologic CO₂ storage demanded by two to three large 1000 megawatt (MW) coal-fired power plants using CCS over a 50-year period. The introduction of PHEVs into the U.S. transportation sector, coupled with climate policies such as those examined here, could also reduce U.S. demand for oil by 20–30% by 2050 compared to today's levels.     

Legal and regulatory challenges in the implementation of CO2 geological storage: An Alberta and Canadian perspective

Alberta is the province with the largest CO₂ emissions in Canada, with approximately two-thirds of emissions originating from large stationary sources. Due to the fortuitous association of large CO₂ sources with the storage capacity offered by the underlying Alberta basin, it is expected that large-scale CO₂ geological storage in Canada will occur in Alberta first, and both levels of governments are contemplating measures to facilitate implementation. A review of the current provincial and federal legislation and regulations presented in this paper indicates that the existing legal and regulatory regime is reasonably sufficient, with some modifications, to accommodate the active injection phase of CO₂ capture and storage (CCS) operations, and the early takers of this new technology. However, governments in Alberta and Canada, and likely everywhere, need to address several pressing issues dealing mainly with the CCS post-operational phase. These issues, reviewed in this paper from an Alberta and Canadian perspective, fall into several categories: jurisdictional, property (ownership), regulatory and liability. Because Alberta is a landlocked province, matters relating to CO₂ storage under the seabed will not be addressed here except when discussing matters of jurisdiction and CO₂ classification. Possible models for post-injection liability transfer to the state are also presented. Although this review is focused on western Canada conditions, the issues are broad enough to be of interest in other jurisdictions, which may also adopt parts of the legal and regulatory framework that is quite well developed in Alberta.     

Lessons learned from natural and industrial analogues for storage of carbon dioxide

The deployment of CCS (carbon capture and storage) at industrial scale implies the development of effective monitoring tools. Noble gases are tracers usually proposed to track CO₂. This methodology, combined with the geochemistry of carbon isotopes, has been tested on available analogues.At first, gases from natural analogues were sampled in the Colorado Plateau and in the French carbogaseous provinces, in both well-confined and leaking-sites. Second, we performed a 2-years tracing experience on an underground natural gas storage, sampling gas each month during injection and withdrawal periods.In natural analogues, the geochemical fingerprints are dependent on the containment criterion and on the geological context, giving tools to detect a leakage of deep-CO₂ toward surface. This study also provides information on the origin of CO₂, as well as residence time of fluids within the crust and clues on the physico-chemical processes occurring during the geological story.The study on the industrial analogue demonstrates the feasibility of using noble gases as tracers of CO₂. Withdrawn gases follow geochemical trends coherent with mixing processes between injected gas end-members. Physico-chemical processes revealed by the tracing occur at transient state.These two complementary studies proved the interest of geochemical monitoring to survey the CO₂ behaviour, and gave information on its use.     

Modeling the impacts of climate policy on the deployment of carbon dioxide capture and geologic storage across electric power regions in the United States

This paper summarizes the results of a first-of-its-kind holistic, integrated economic analysis of the potential role of carbon dioxide (CO₂) capture and storage (CCS) technologies across the regional segments of the United States (U.S.) electric power sector, over the time frame 2005–2045, in response to two hypothetical emissions control policies analyzed against two potential energy supply futures that include updated and substantially higher projected prices for natural gas. This paper's detailed analysis is made possible by combining two specialized models developed at Battelle: the Battelle CO₂-GIS to determine the regional capacity and cost of CO₂ transport and geologic storage; and the Battelle Carbon Management Electricity Model, an electric system optimal capacity expansion and dispatch model, to examine the investment and operation of electric power technologies with CCS against the background of other options. A key feature of this paper's analysis is an attempt to explicitly model the inherent heterogeneities that exist in both the nation's current and future electricity generation infrastructure and in its candidate deep geologic CO₂ storage formations. Overall, between 180 and 580 gigawatts (GW) of coal-fired integrated gasification combined cycle with CCS (IGCC + CCS) capacity is built by 2045 in these four scenarios, requiring between 12 and 41 gigatonnes of CO₂ (GtCO₂) storage in regional deep geologic reservoirs across the U.S. Nearly all of this CO₂ is from new IGCC + CCS systems, which start to deploy after 2025. Relatively little IGCC + CCS capacity is built before that time, primarily under unique niche opportunities. For the most part, CO₂ emissions prices will likely need to be sustained at over $20/tonne CO₂ before CCS begins to deploy on a large scale within the electric power sector. Within these broad national trends, a highly nuanced picture of CCS deployment across the U.S. emerges. Across the four scenarios studied here, power plant builders and operators within some North American Electric Reliability Council (NERC) regions do not employ any CCS while other regions build more than 100 GW of CCS-enabled generation capacity. One region sees as much as 50% of its geologic CO₂ storage reservoirs’ total theoretical capacity consumed by 2045, while most of the regions still have more than 90% of their potential storage capacity available to meet storage needs in the second half of the century and beyond. A detailed presentation of the results for power plant builds and operation in two key regions: ECAR in the Midwest and ERCOT in Texas, provides further insight into the diverse set of economic decisions that generate the national and aggregate regional results.     

Actuarial risk assessment of expected fatalities attributable to carbon capture and storage in 2050

This study estimates the human cost of failures in the CCS industry in 2050, using the actuarial approach. The range of expected fatalities is assessed integrating all steps of the CCS chain: additional coal production, coal transportation, carbon capture, transport, injection and storage, based on empirical evidence from technical or social analogues. The main finding is that a few hundred fatalities per year should be expected if the technology is used to avoid emitting 3.67 GtCO₂ year⁻¹ in 2050 at baseload coal power plants. The large majority of fatalities are attributable to mining and delivering more coal. These risks compare to today's industrial hazards: technical, knowable and occupational dangers for which there are socially acceptable non-zero risk levels. Some contemporary European societies tolerate about one fatality per thousand years around industrial installations. If storage sites perform like that, then expected fatalities per year due to leakage should have a minor contribution in the total expected fatalities per year: less than one. But to statistically validate such a safety level, reliability theory and the technology roadmap suggest that CO₂ storage demonstration projects over the next 20 years have to cause exactly zero fatality.     

An engineering-economic model of pipeline transport of CO2 with application to carbon capture and storage

Carbon dioxide capture and storage (CCS) involves the capture of CO₂ at a large industrial facility, such as a power plant, and its transport to a geological (or other) storage site where CO₂ is sequestered. Previous work has identified pipeline transport of liquid CO₂ as the most economical method of transport for large volumes of CO₂. However, there is little published work on the economics of CO₂ pipeline transport. The objective of this paper is to estimate total cost and the cost per tonne of transporting varying amounts of CO₂ over a range of distances for different regions of the continental United States. An engineering-economic model of pipeline CO₂ transport is developed for this purpose. The model incorporates a probabilistic analysis capability that can be used to quantify the sensitivity of transport cost to variability and uncertainty in the model input parameters. The results of a case study show a pipeline cost of US$ 1.16 per tonne of CO₂ transported for a 100 km pipeline constructed in the Midwest handling 5 million tonnes of CO₂ per year (the approximate output of an 800 MW coal-fired power plant with carbon capture). For the same set of assumptions, the cost of transport is US$ 0.39 per tonne lower in the Central US and US$ 0.20 per tonne higher in the Northeast US. Costs are sensitive to the design capacity of the pipeline and the pipeline length. For example, decreasing the design capacity of the Midwest US pipeline to 2 million tonnes per year increases the cost to US$ 2.23 per tonne of CO₂ for a 100 km pipeline, and US$ 4.06 per tonne CO₂ for a 200 km pipeline. An illustrative probabilistic analysis assigns uncertainty distributions to the pipeline capacity factor, pipeline inlet pressure, capital recovery factor, annual O&M cost, and escalation factors for capital cost components. The result indicates a 90% probability that the cost per tonne of CO₂ is between US$ 1.03 and US$ 2.63 per tonne of CO₂ transported in the Midwest US. In this case, the transport cost is shown to be most sensitive to the pipeline capacity factor and the capital recovery factor. The analytical model elaborated in this paper can be used to estimate pipeline costs for a broad range of potential CCS projects. It can also be used in conjunction with models producing more detailed estimates for specific projects, which requires substantially more information on site-specific factors affecting pipeline routing.     

The acceptability of CO2 capture and storage (CCS) in Europe: An assessment of the key determining factors: Part 1. Scientific,technical and economic dimensions

The ACCSEPT project, which ran from January 2006 to December 2007, identified and analysed the main factors which have been influencing the emergence of CO₂ capture and geological storage (CCS) within the European Union (EU). The key clusters of factors concern science and technology, law and regulation, economics, and social acceptance. These factors have been analysed through interviews, a large-scale questionnaire conducted in 2006, and discussions in two stakeholder workshops (2006 and 2007). In Part I of this paper, we aim to distil the key messages and findings with regards to scientific, technical, legal and economic issues. There are no compelling scientific, technical, legal, or economic reasons why CCS could not be widely deployed in the forthcoming decades as part of a package of climate change mitigation options. In order to facilitate this deployment, governments at both the EU and Member State levels have an important role to play, in particular in establishing a robust and transparent legal framework (e.g. governing long-term environmental liability) and a strong policy framework providing sufficient and long-term incentives for CCS and CO₂ transportation networks.     

Energy technology modelling of major carbon abatement options

The International Energy Agency Energy Technologies Perspectives (ETP) model is used to assess the prospects for carbon abatement options, including carbon capture and storage, up to 2050. Three main scenarios are considered: a Baseline scenario with current energy policies, an accelerated technology scenario that seeks to return energy-related CO₂ emissions in 2050 to their level in 2005, and a scenario for which CO₂ emissions are reduced at 50% of current levels by 2050. To reach these emissions reduction targets, annual global CO₂ emissions in the year 2050 must be reduced by 35 GtCO₂ to 48 GtCO₂ compared to the Baseline scenario. The analysis presented here shows that a broad portfolio of emissions reducing technologies will need to be deployed across all economic sectors of the global economy to reach these targets. Carbon dioxide capture and storage (CCS) is one of the suite of technologies employed across the globe to reach these targets. CCS adoption occurs in many aspects of the global economy and accounts for 14–19% of all emissions reductions. The total amount of CO₂ captured and stored in deep geologic reservoirs up to 2050 ranges between 5.1 GtCO₂ and 10.4 GtCO₂ in these two climate policy scenarios. Up to 2030, more than half of total CCS deployment takes place in OECD countries. After 2035, emerging economies account for more than half of total CCS use. This paper also demonstrates that as the climate policy becomes more stringent it will be necessary for CCS to deploy more extensively in many different industries outside of the electric power sector which often receives the most attention in discussions of CCS's role in addressing climate change.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Dynamis CO2 quality recommendations

In the carbon capture and storage (CCS) chain, transport and storage set different requirements for the composition of the gas stream mainly containing carbon dioxide (CO₂). Currently, there is a lack of standards to define the required quality for CO₂ pipelines. This study investigates and recommends likely maximum allowable concentrations of impurities in the CO₂ for safe transportation in pipelines. The focus is on CO₂ streams from pre-combustion processes. Among the issues addressed are safety and toxicity limits, compression work, hydrate formation, corrosion and free water formation, including the cross-effect of H₂S and H₂O and of H₂O and CH₄.     

CO2 capture and storage from a bioethanol plant: Carbon and energy footprint and economic assessment

Biomass energy and carbon capture and storage (BECCS) can lead to a net removal of atmospheric CO₂. This paper investigates environmental and economic performances of CCS retrofit applied to two mid-sized refineries producing ethanol from sugar beets. Located in the Region Centre France, each refinery has two major CO₂ sources: fermentation and cogeneration units. “carbon and energy footprint” (CEF) and “discounted cash flow” (DCF) analyses show that such a project could be a good opportunity for CCS early deployment. CCS retrofit on fermentation only with natural gas fired cogeneration improves CEF of ethanol production and consumption by 60% without increasing much the non renewable energy consumption. CCS retrofit on fermentation and natural gas fired cogeneration is even more appealing by decreasing of 115% CO₂ emissions, while increasing non renewable energy consumption by 40%. DCF shows that significant project rates of return can be achieved for such small sources if both a stringent carbon policy and direct subsidies corresponding to 25% of necessary investment are assumed. We also underlined that transport and storage cost dilution can be realistically achieved by clustering emissions from various plants located in the same area. On a single plant basis, increasing ethanol production can also produce strong economies of scale.     

CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank

Climate change is being caused by greenhouse gases such as carbon dioxide (CO₂). Carbon capture and storage (CCS) is of interest to the scientific community as one way of achieving significant global reductions of atmospheric CO₂ emissions in the medium term. CO₂ would be captured from large stationary sources such as power plants and transported via pipelines under high pressure conditions to underground storage. If a downward leakage from a surface transportation system module occurs, the CO₂ would undergo a large temperature reduction and form a bank of “dry ice” on the ground surface; the sublimation of the gas from this bank represents an area source term for subsequent atmospheric dispersion, with an emission rate dependent on the energy balance at the bank surface. Gaseous CO₂ is denser than air and tends to remain close to the surface; it is an asphyxiant, a cerebral vasodilator and at high concentrations causes rapid circulatory insufficiency leading to coma and death. Hence a subliming bank of dry ice represents safety hazard. A model is presented for evaluating the energy balance and sublimation rate at the surface of a solid frozen CO₂ bank under different environmental conditions. The results suggest that subliming gas behaves as a proper dense gas (i.e. it remains close to the ground surface) only for low ambient wind speeds.     

Assessing the economic feasibility of regional deep saline aquifer CO2 injection and storage: A geomechanics-based workflow applied to the Rose Run sandstone in Eastern Ohio, USA

Typical top-down regional assessments of CO₂ storage feasibility are sufficient for determining the maximum volumetric capacity of deep saline aquifers. However, they do not reflect the regional economic feasibility of storage. This is controlled, in part, by the number and type of injection wells that are necessary to achieve regional CO₂ storage goals. In contrast, the geomechanics-based assessment workflow that we present in this paper follows a bottom-up approach for evaluating regional deep saline aquifer CO₂ storage feasibility. The CO₂ storage capacity of an aquifer is a function of its porous volume as well as its CO₂ injectivity. For a saline aquifer to be considered feasible in this assessment it must be able to store a specified amount of CO₂ at a reasonable cost per ton of CO₂. The proposed assessment workflow has seven steps that include (1) defining the storage project and goals, (2) characterizing the geology and developing a geomechanical model of the aquifer, (3) constructing 3D aquifer models, (4) simulating CO₂ injection, (5,6) evaluating CO₂ injection and storage feasibility (with and without injection well stimulation), and (7) determining whether it is economically feasible to proceed with the storage project. The workflow was applied to a case study of the Rose Run sandstone aquifer in the Eastern Ohio River Valley, USA. We found that it is feasible in this region to inject 113 Mt CO₂/year for 30 years at an associated well cost of less than US $1.31/t CO₂, but only if injectivity enhancement techniques such as hydraulic fracturing and injection induced micro-seismicity are implemented.     

Global energy and emissions scenarios for effective climate change mitigation—Deterministic and stochastic scenarios with the TIAM model

The achievement possibilities of the EU 2 °C climate target have been assessed with the ETSAP TIAM global energy systems model. Cost-effective global and regional mitigation scenarios of carbon dioxide, methane, nitrous oxide and F-gases were calculated with alternative assumptions on emissions trading. In the mitigation scenarios, an 85% reduction in CO₂ emissions is needed from the baseline, and very significant changes in the energy system towards emission-free sources take place during this century. The largest new technology groups are carbon-capture and storage (CCS), nuclear power, wind power, advanced bioenergy technologies and energy efficiency measures. CCS technologies contributed a 5.5-Pg CO₂ annual emission reduction by 2050 and 12 Pg CO₂ reduction by 2100. Also large-scale forestation measures were found cost-efficient. Forestation measures reached their maximum impact of 7.7 Pg CO₂ annual emission reduction in 2080. The effects of uncertainties in the climate sensitivity have been analysed with stochastic scenarios.