De ökande växthusgasutsläppen till atmosfären leder till skadliga effekter för jordens klimat. Växthusgasutsläppen minskar i för långsam takt för att klimatpolitiska mål ska kunna nås, till exempel Parisavtalet från 2015. Koldioxidlagring eller CCS (Carbon Capture and Storage) ses som en viktig teknik för att minska industriers utsläpp, speciellt inom energiproduktion men även inom cementindustri, för att minska utsläpp från tillverkningsprocessen. I den här studien undersöks möjligheterna för koldioxidlagring i ett område i sydöstra Östersjön. Syftet är att undersöka möjligheten att Gotland kan reducera en stor del av sina koldioxidutsläpp genom CCS-teknik. En source to sink-matchning utförs genom att matcha koldioxidutsläppen från utvalda industrier på Gotland med geologiska reservoarer i Östersjön, för att se om reservoarerna kan lagra koldioxiden. Resultaten visar att lagringskapaciteten i området är enorm teoretiskt sett, i praktiken är kapaciteten låg och det krävs en undersökning av ett större område än det som undersöktes i denna studie. Kostnaderna för CCS-teknik är mycket höga och det krävs statliga finansieringar inledningsvis för implementering. Kostnaden för koldioxidutsläpp bör vara högre än kostnaden för koldioxidlagring. Teknikutveckling, samhällsförändring och samarbete mellan länder är viktigt för att öka takten av CCS implementering. / Increasing greenhouse gas emissions will lead to harmful effects on the climate of the Earth. The emissions are decreasing too slowly in order to achieve policy objectives such as the Paris Agreement, 2015. CCS (Carbon Capture and Storage) is considered important to reduce industrial emissions, especially in the energy generation sector, but also in the cement industry, to reduce emissions connected to the production processes. The possibilities for CCS in an area in the southeastern Baltic Sea are investigated. The objective is to investigate the possibility that Gotland can reduce a great deal of its carbon dioxide emissions through CCS-technology. A source-to-sink match is performed by matching emissions from selected industries in Gotland with geological reservoirs in the Baltic Sea, to see if the reservoirs can store carbon dioxide. The results show that the theoretical storage capacity in the area is huge, but in practice it´s low. This shows that a study of larger areas is required. The costs of CCS technology are very high, government funding is initially required. The cost of carbon dioxide emissions should be higher than the cost of carbon dioxide storage. Technology development, social change and cooperation between countries are needed to increase the pace of CCS implementation.

Carbon capture and storage (CCS) is a technology that is developed with the aim of decreasing the emissions of the greenhouse gas carbon dioxide (CO2) in order to mitigate global climate change. However, citizens strongly oppose the technology in areas where carbon storages are supposed to be constructed. With the help of framing theory, this work analyzes four German anti-CCS citizens’ initiatives. Qualitatively studying publicly available material from their websites, their diagnostic, prognostic, and motivational frames on the issue are reconstructed. Guided by a first research question about what frames on CCS are constructed by the citizens’ initiatives, the frames are then compared to each other, showing that political opportunity structures as well as local factors regarding particularly the prevalent type of energy production are taken up to some extent. Systematically retracing the arguments, this study aims on investigating into the connections between local and global issues and interests around CCS. This entails potential for generalization regarding the decision-making process in the area of conflict when society, environment, technology, economic and political actors are involved. Afterwards, a second research question is taken up – the frames’ relation to sustainability. They are discussed in the wider context of sustainable development because of the close connection between the climate change and the sustainability discourse. Moreover, proponents as well as opponents use parts of the sustainability concept for their arguments. This highlights the difficulties of a sustainable decision-making process in which a variety of interests are interwoven and partly contradicting each other. It is concluded that both, comprehensive information and transparent communication, between all actors are the first steps towards a more sustainable decision-making process but that structurally as well as technically more than this is required, especially regarding the acceptance of the outcome. Research on sustainability as an increasingly influential paradigm can pave the way in this regard.

<p>The changes to the environment caused by anthropogenic climate change pose major challenges for energy production in the next century. Carbon Capture and Storage (CCS) is a group of technologies that would permit the continued use of carbon-intense fuels such as coal for energy production while avoiding further impact on the global climate system. The mechanism most often proposed for storage is injection of CO2 below the surface of the Earth in geological media, with the most promising option for CO2 reservoirs being deep saline aquifers (DSA's). Unlike oil and gas reservoirs, deep saline aquifers are poorly characterized and the variability in their properties is large enough to have a high impact on the overall physical and economic viability of CCS. Storage in saline aquifers is likely to be a very high-capacity resource, but its economic viability is almost unknown. We consider the impact of geological variability on the total viability of the CO2 storage system from several perspectives. First, we examine the theoretical range of costs of storage by coupling a physical and economic model of CO2 storage with a range of possible geological settings. With the relevant properties of rock extending over several orders of magnitude, it is not surprising that we find costs and storage potential ranging over several orders of magnitude. Second, we use georeferenced data to evaluate the spatial distribution of cost and capacity. When paired together to build a marginal abatement cost curve (MACC), this cost and capacity data indicates that low cost and high capacity are collocated; storage in these promising areas is likely to be quite viable but may not be available to all CO2 sources. However, when we continue to explore the impact of geological variability on realistic, commercial-scale site sizes by invoking capacity and pressure management constraints, we find that the distribution costs and footprints of these sites may be prohibitively high. The combination of issues with onshore storage in geological media leads us to begin to evaluate offshore storage potential. By considering the temperature and pressure regimes at the seafloor, we locate and quantify marine strata that has "self-sealing" properties, a storage option that we find is plentiful off the coasts of the United States. We conclude that further research into transport optimization that takes into account the true variation in geological media is necessary to determine the distribution of costs for carbon capture and storage to permit the full evaluation of CCS as a mitigation option.</p> / Dissertation

Carbon dioxide capture and storage (CCS) is considered one of the key technologies for reducing atmospheric emissions of CO₂ from human activities (IPCC, 2005). The scale of potential deployment of CCS is enormous spanning manufacturing, power generation and hydrocarbon extraction worldwide. Uncertainty, cost-benefit challenges, market barriers and failures, and promotion and regulation of infrastructure are the main obstacles for deploying CCS technology in a broad scale. In a CCS project, it is the operator’s responsibility to guarantee the CO₂ containment while complying with environmental regulations and CO₂ contractual requirements with the source emitter. Acquiring new information (e.g. seismic, logs, production data, etc.) about a particular field can reduce the uncertainty about the reservoir properties and can (but not necessarily) influence the decisions affecting the deployment of a CCS project. The main objective of this study is to provide a decision-analysis framework to quantify the Value of Information (VOI) in a CCS project that faces uncertainties about permeability values in the reservoir. This uncertainty translates into risks of CO₂ migration out of the containment zone (or lease zone), non-compliance with contractual requirements on CO₂ storage capacity, and leakage of CO₂ to sources of Underground Source of Drinking Water (USDW). The field under analysis has been idealized based on a real project located in Texas. Subsurface modeling of the upper Frio Formation (injection zone) was conducted using well logs, field-specific GIS data, and other relevant published literature. The idealized model was run for different scenarios with different permeability distributions. The VOI was quantified by defining prior scenarios based on the current knowledge of a reservoir, contractual requirements, and regulatory constraints. The project operator has the option to obtain more reliable estimates of permeability, which will help to reduce the uncertainty of the CO₂ behavior and storage capacity of the formation. The accuracy of the information gathering activities is then applied to the prior probabilities (Bayesian inference) to infer the value of such data. / text

Today, and for the foreseeable future, coal and other fossil fuels will provide a major portion of the energy services demanded by both developed and developing countries around the word. In order to reduce the emissions of carbon dioxide associated with combustion of coal for electricity generation, a wide range of carbon capture technologies are being developed. This thesis models the oxyfuel carbon capture process for pulverized coal and presents performance and cost estimates of this system in comparison to other low-carbon fossil fuel generators. Detailed process models for oxygen production, flue gas treatment, and carbon dioxide purification have been developed along with the calculation strategies necessary to employ these components in alternative oxyfuel system configurations for different types of coal-fired power plants. These new oxyfuel process models have been implemented in the widely-used Integrated Environmental Control Model (IECM) to facilitate systematic comparisons with other low-carbon options employing fossil fuels. Assumptions about uncertainties in the performance characteristics of gas separation processes and flue gas duct sealing technology, as well as plant utilization and financing parameters, were found to produce a wide range of cost estimates for oxyfuel systems. In case studies of a new 500 MW power plant burning sub-bituminous Powder River Basin coal, the estimated levelized cost of electricity (LCOE) 95% confidence interval (CI) was 86 to 150 [$/MWh] for an oxyfuel system producing a high-purity [99.5 mol% CO2] carbon dioxide product while capturing 90% of the flue gas carbon dioxide. For a CoCapture oxyfuel system capturing 100% of the flue gas CO2 together with all other flue gas constituents, the estimated LCOE 95% CI was 90 to 153 [$/MWh] (all costs in constant 2012 US Dollars). Using the IECM, an oxyfuel system for CO2 capture also was compared under uncertainty to an existing amine-based post-combustion capture system for a new 500 MW power plant, with both systems capturing 90% of the CO2 and producing a high-purity stream for pipeline transport to a geological sequestration site. The resulting distribution for the cost of CO2 avoided showed the oxyfuel-based system had a 95% CI of 44 to 126 [$/tonne CO2] while the amine-based system cost 95% CI ranged from 50 to 133 [$/tonne CO2]. The oxyfuel cost distribution had a longer tail toward more expensive configurations but over 70% of the distribution showed the oxyfuel-based system to be ~10[$/tonne CO2] lower in cost compared to the amine-based capture system. An evaluation of several low-carbon generation options fueled by coal and natural gas further considered both direct and indirect greenhouse gas emissions. This analysis showed oxyfuel to be economically competitive with all capture system considered, and also indicated oxyfuel to be the preferred carbon capture technology for minimizing overall carbon intensity. Combined, these results suggest that oxyfuel is a promising carbon capture technology, and the only one which offers the unique ability to capture all the combustion gases to become a truly zero emission coal plant. Realization of the latter option, however, is contingent on the development of new regulatory policies for underground injection of mixed flue gas streams that is outside the scope of this thesis.

No description available.

Production in Canada’s oil sands has been increasing, with a projected rate of 4.5 million barrels per day by 2025. Two production techniques are currently used, mining and in-situ, with the latter projected to constitute ~57% of all production by that time. Although in-situ extraction methods such as Steam Assisted Gravity Drainage (SAGD) are less invasive than mining, they result in more greenhouse gas (GHG) emissions per barrel and require large amounts of water that must be treated and recycled with a make-up water requirement of about 10%. CanmetENERGY is developing a steam generation technology called the High Pressure Oxy-fired Direct Contact Steam Generator (HiPrOx/DCSG, or DCSG for short) that will reduce these water requirements and sequester GHGs. This study evaluates the technical feasibility of this technology using process simulations, bench-scale testing, and pilot-scale testing. At first, a method in which to integrate the DCSG into the SAGD process was presented and process modeling of expected system performance was undertaken. The process simulations indicated that DCSG decreased the energy intensity of SAGD by up to 7.6% compared to the base SAGD case without carbon capture and storage (CCS), and up to 12.0% compared to the base SAGD case with CCS. Bench-scale testing was then performed using a pressurized thermogravimetric analyzer (PTGA) in order to investigate the effects of increased pressure and high moisture environments on a Canadian lignite coal char’s reactivity. It was found that under reaction kinetic-controlled conditions at atmospheric pressure, the increased addition of steam led to a reduction in burning time. The findings may have resulted from the lower heat capacity and higher thermal conductivity of steam compared to CO2. At increased pressures, CO2 inhibited burnout due to its higher heat capacity, lower thermal conductivity, and its effect on C(O) concentrations on the particle surface. When steam was added, the inhibiting effects of CO2 were counteracted, resulting in burnout rates similar to pressurized O2/N2 environments. These preliminary results suggested that the technology was feasible at a bench-scale level. Conflicting literature between bench-scale and pilot-scale studies indicated that pilot-scale testing would be advantageous as a next step. At the pilot-scale, testing was performed using n-butanol, graphite slurry, and n-butanol/graphite slurry mixtures covering lower and upper ends in fuel reactivity. It was found that stable combustion was attainable, with high conversion efficiencies in all cases. With the n-butanol, it was possible to achieve low excess oxygen requirements, which minimizes corrosion issues and reduce energy requirements associated with oxygen generation. With graphite slurry, it was found that it was possible to sustain combustion in these high moisture environments and that high conversion was achieved as indicated by the undetectable levels of carbonaceous materials observed in downstream equipment. Overall, these studies indicate that DCSG is technically feasible from the perspectives of energy and combustion efficiencies as well as from a steam generation point of view. Future work includes the investigation of possible corrosion associated with the product gas, the effect of CO2 on bitumen production, the nature of the mineral melt formed by the deposition of the dissolved and suspended solids from the water in the combustor, and possible scaling issues in the steam generator and piping associated with mineral deposits from the dissolved and suspended solids in the produced water is recommended.

Geologic carbon storage (GCS) is a crucial part of a proposed mitigation strategy to reduce the anthropogenic CO2 emissions to the atmosphere. During this process, CO2 is injected as super critical carbon dioxide (SC-CO2) in confined deep subsurface storage units, such as saline aquifers and depleted oil reservoirs. The deposition of vast amounts of CO2 in subsurface geologic formations may ultimately lead to CO2 leakage into overlying freshwater aquifers. Introduction of CO2 into these subsurface environments will greatly increase the CO2 concentration and will create CO2 concentration gradients that drive changes in the microbial communities present. While it is expected that altered microbial communities will impact the biogeochemistry of the subsurface, there is no information available on how CO2 gradients will impact these communities. The overarching goal of this dissertation is to understand how CO2 exposure will impact subsurface microbial communities at temperature and pressure that are relevant to GCS and CO2 leakage scenarios. To meet this goal, unfiltered, aqueous samples from a deep saline aquifer, a depleted oil reservoir, and a fresh water aquifer were exposed to varied concentrations of CO2 at reservoir pressure and temperature. The microbial ecology of the samples was examined using molecular, DNA-based techniques. The results from these studies were also compared across the sites to determine any existing trends. Results reveal that increasing CO2 leads to decreased DNA concentrations regardless of the site, suggesting that microbial processes will be significantly hindered or absent nearest the CO2 injection/leakage plume where CO2 concentrations are highest. At CO2 exposures expected downgradient from the CO2 plume, selected microorganisms emerged as dominant in the CO2 exposed conditions. Results suggest that the altered microbial community was site specific and highly dependent on pH. The site-dependent results suggests no ability to predict the emerging dominant species for other CO2exposed environments. This body of work improves the understanding of how a subsurface microbial community may respond to conditions expected from geologic carbon storage and CO2 leakage. This is the first step for understanding how a CO2 altered microbial community may impact injectivity, permanence of stored CO2, and subsurface water quality. .

A model for the evaluation of CO2-EOR projects has been developed. This model includes both reservoir simulation to handle reservoir properties, fluid flow and injection and production schedules, and a numerical economic model that generates a monthly cash flow stream from the outputs of the reservoir model. This model is general enough to be used with any project and provide a solid common basis to all of them. This model was used to evaluate CO2-EOR injection and production strategies and develop an optimization workflow. Producer constraints (maximum oil and gas production rates) should be optimized first to generate a reference case. Further improvements can then be obtained by optimizing the injection starting date and the injection plateau rate. Investigation of sensitivity of CO2-EOR to the presence of an aquifer showed that CO2 injection can limit water influx in the reservoir and is beneficial to recovery, even with a strong water drive. The influence of some key parameters was evaluated: the producer should be completed in the top part of the reservoir, while the injector should be completed over the entire thickness; it is recommended but not mandatory that the injection should start as early as possible to allow for lower water cut limit. Finally, the sensitivity of the economics of the projects to some key parameters was evaluated. The most influent parameter is by far the oil price, but other parameters such as the CO2 source to field distance, the pipeline cost scenario, the CO2 source type or the CO2 market price have roughly the same influence. It is therefore possible to offset an increase of one of them by reducing another.

I assess the potential of seismic and time-domain controlled-source electromagnetic (CSEM) methods to monitor carbon dioxide (CO2) migration through the application of a monitorability workflow. The monitorability workflow describes a numerical modelling approach to model variations in the synthetic time-lapse response due to CO2 migration. The workflow consists of fluid-flow modelling, rock-physics modelling and synthetic seismic or CSEM forward modelling. I model CO2 injected into a simple, homogeneous reservoir model before applying the workflow to a heterogeneous model of the Bunter Sandstone reservoir, a potential CO2 storage reservoir in the UK sector of the North Sea. The aim of this thesis is to model the ability of seismic and time-domain CSEM methods to detect CO2 plume growth, migration and evolution within a reservoir, as well as the ability to image a migrating front of CO2. The ability to image CO2 plume growth and migration within a reservoir has not been demonstrated in the field of CSEM monitoring. To address this, I conduct a feasibility study, simulating the time-lapse CSEM time-domain response of CO2 injected into a saline reservoir following the multi-transient electromagnetic (MTEM) method. The MTEM method measures the full bandwidth response. First, I model the response to a simple homogeneous 3D CO2 body, gradually increasing the width and depth of the CO2. This is an analogue to vertical and lateral CO2 migration in a reservoir. I then assess the ability of CSEM to detect CO2 plume growth and evolution within the heterogeneous Bunter Sandstone reservoir model. I demonstrate the potential to detect stored and migrating CO2 and present the synthetic results as time-lapse common-offset time sections. The CO2 plume is imaged clearly and in the right coordinates. The ability to image seismically a migrating front of CO2 remains challenging due to uncertainties regarding the pore-scale saturation distribution of fluids within the reservoir and, in turn, the most appropriate rock-physics model to simulate this: uniform or patchy saturation. I account for this by modelling both saturation models, to calculate the possible range of expected seismic velocities prior to generating and interpreting the seismic response. I demonstrate the ability of seismic methods to image CO2 plume growth and evolution in the Bunter Sandstone saline reservoir model and highlight clear differences between the two rock-physics models. I then modify the Bunter Sandstone reservoir to depict a depleted gas field by including 20% residual gas saturation. I assess the importance and implication of patchy saturation and present results which suggest that seismic techniques may be able to detect CO2 injected into depleted hydrocarbon fields.