The most widely advocated method of carbon capture and storage involves the injection of CO2 into underground geological formations. Key to the development of this geological sequestration technology is the existence of suitable high-integrity geological sites for the safe, long-term storage of CO2. Unlike depleted oil and gas reservoirs which are historically proven to be well-defined, formations with saline brines may not have a similar proven sealing capacity. In the main, complex geochemical reactions occur in the supercritical CO2 / brine / host rock environment which can cause significant changes in the porosity, permeability and injectivity of the formation. Depending of the nature of the processes, the effects of the underground injection of CO2 may (1) yield increased storage capacity of the target horizon, or (2) lead to increased potential for leakage beyond the confining layers of the saline formation, or (3) impede the injection exercise as a whole. It is conceivable that accelerated, localized mineral carbonation could be induced at strategic places between the CO2 plume and fault zones or facies changes present in deep saline formations, in order to prevent the migration of CO2 outside the confined layers of the reservoir. The South African electricity producer, Eskom, generated 36.01 million tons of coal- combustion fly ash in 2010. About 5.6% were reused for the production of cement. The remaining 33.89 million tons were safely disposed of and managed on Eskom ash dumps and dams which are located adjacent to their corresponding power stations. South Africa has a long history regarding the development of new applications for this material and is very active in the development of ash technologies. Concurrently, the power industry is also a major carbon dioxide (CO2 ) emitter, with Eskom’s emissions approximating 225 million tons for 2010. In this study, the author introduces a theoretical concept whereby fly ash in a slurry form could be injected at strategic sites of deep saline formations. The purpose of this injection strategy is to prevent the migration of injected anthropogenic CO2 plumes beyond the confining layers of the formations, via induced in situ localized, accelerated mineral carbonation. The proposed application falls within the carbon capture and storage (CCS) initiative by geological sequestration and aims at improving the integrity of deep saline formations which may be at risk of leakage upon injection of CO2. The use of coal-combustion fly ash in industrial mineral carbonation and the research involving its applications in carbon capture and storage (CCS) has internationally gained increased attention. However, the work involving fly ash in industrial mineral carbonation has only focused on the sequestration of sub-critical CO2. This work demonstrates for the first time that fly ash can react with supercritical CO2 under varying pressure and temperature conditions. The experiments were conducted following an assumed geothermal gradient for deep saline reservoirs, as described by Viljoen, 2010, i.e. 44°C/80bar and 50°C/100bar. Ultra-pure water was used as a solvent. The duration of experiments ranged from 60 minutes to 7 days. Under these T/ P conditions, carbonates in the form of calcite (CaCO3 ) were only detected at completion of the 7 days experiment. Further investigation was undertaken at 90°C/90bar for 2 hours using synthetic brine as a solvent, in order to mimic the composition of deep saline formations. This work yielded both aragonite and calcite, which formed as sheets at the base and on the walls of the batch reactor. The carbonated sheet fragments were examined using scanning electron microscopy (SEM) and were found to have an approximate thickness of 16 μm. A thinner layer of white precipitate on the walls of the reactor was composed of aragonite and calcite and contained an amorphous phase of carbonate of ca. 1% by volume. The mineralogical composition of these carbonated sheets was confirmed using XRD, which demonstrated the presence of aragonite (23%), calcite (3%) and fly ash minerals (e.g. mullite, quartz). It also contained an XRD-amorphous phase of about 37%. These sheets were thus enriched in calcium and carbon but also other elements were found to be present (Al, Si, Na, Mg and Cl) as shown by SEM. It is, however, unclear whether these elements identified in the spectrum are part of the sheet or are rather indicative of an effect of analytical volume created by the SEM electron beam being larger than the thickness of the sheet. Small amounts of S were also detected. Fly ash particles as well as a small number of needle-shaped gypsum crystals were visibly embedded in the sheet (SEM). Copyright / Dissertation (MSc)--University of Pretoria, 2012. / Geology / unrestricted

Owing to the excess of carbon dioxide emissions in the atmosphere, a transition to a neutral carbon economy is needed. In this framework, Carbon Capture and Storage (CCS), and Carbon Capture Utilization and Storage (CCUS) become essential areas of development. Sequestering CO2 into different geological media such as deep saline aquifers and hydrocarbon reservoirs reduces the net anthropogenic gas emissions. In 2020, the global CO2 emissions corresponded to 31.5 gigatons. In the case of Saudi Arabia, the Riyadh province emitted 45.8 megatons. This study aims to evaluate for the first time the CO2 storage potential of the Unayzah Formation in Saudi Arabia, identify the primary trapping mechanisms, and capture the effects of the highly heterogeneous reservoir. CO2 injection in geological media is challenging because of the complexity of the geological properties and the CO2 phase behavior at super-critical conditions. In the present evaluation, we constructed a geological model only with public domain data. Similarly, we obtained different scenarios of the model on account of the uncertainty in the geological parameters. Later on, we selected a base model representing a conservative scenario to perform high-resolution simulations to determine the dominant mechanisms influencing the storage efficiency. In the main analysis, we simulated continuous injection of CO2 for forty years followed by twenty years of monitoring. We tested the injectivity of the reservoir showing it is possible to inject 1 and 2 megatons in vertical and horizontal wells, respectively. Likewise, lower injection rates improved solubility and residual trapping. Residual trapping is dominant, and it could reach fifty percent, while solubility could reach up to fifteen percent of the total CO2 injected. Along with these scenarios, we performed an Uncertainty Analysis based on porosity and permeability multipliers, salinity, and hysteresis effect. Finally, we demonstrated the effectiveness of the seal, and the structural and stratigraphic trapping. Until the development of the current analysis, there is no evidence of public domain studies assessing the storage potential into saline aquifers in Saudi Arabia. This contribution is essential for developing CCUS and promoting a circular carbon economy in line with the Vision of the Kingdom for the future.

<p>The rising carbon dioxide emissions contributing to climate change has lead to the examination of potential ways to mitigate the environmental impact. One such method is through the geological sequestration of carbon (CCS). Although there are several different forms of geological sequestration (i.e. Saline Aquifers, Oil and Gas Reservoirs, Unminable Coal Seams) the current projects are just initiating the large scale-testing phase. The lead entry point into CCS projects is to combine the sequestration with enhanced oil recovery (EOR) due to the improved economic model as a result of the oil recovery and the pre-existing knowledge of the geological structures. The potential scope of CCS-EOR projects throughout the continental United States in terms of a systematic examination of individual reservoir storage potential has not been examined. Instead the majority of the research completed has centered on either estimating the total United States storage potential or the potential of a single specific reservoir.</p><p>The purpose of this paper is to examine the relationship between oil recovery, carbon dioxide storage and cost during CCS-EOR. The characteristics of the oil and gas reservoirs examined in this study from the Nehring Oil and Gas Database were used in the CCS-EOR model developed by Sean McCoy to estimate the lifting and storage costs of the different reservoirs throughout the continental United States. This allows for an examination of both technical and financial viability of CCS-EOR as an intermediate step for future CCS projects in other geological formations. </p><p>One option for mitigating climate change is to store industrial CO2 emissions in geologic reservoirs as part of a process known as carbon capture and storage (CCS). There is general consensus that large-scale deployment of CCS would best be initiated by combining geologic sequestration with enhanced oil recovery (EOR), which can use CO2 to improve production from declining oil fields. Revenues from the produced oil could help offset the current high costs of CCS. </p><p>The cumulative potential of CCS-EOR in the continental U.S. has been evaluated in terms of both CO2 storage capacity and additional oil production. This thesis examines the same potential, but on a reservoir-by-reservoir basis. Reservoir properties from the Nehring Oil and Gas Database are used as inputs to a CCS-EOR model developed by McCoy (YR) to estimate the storage capacity, oil production and CCS-EOR costs for over 10,000 oil reservoirs located throughout the continental United States. </p><p>We find that 86% of the reservoirs could store &#8804;1 y or CO2 emissions from a single 500 MW coal-fired power plant (i.e., 3 Mtons CO2). Less than 1% of the reservoirs, on the other hand, appear capable of storing &#8805;30 y of CO2 emissions from a 500 MW plan. But these larger reservoirs are also estimated to contain 48% of the predicted additional oil that could be produced through CCS-EOR. The McCoy model also predicts that the reservoirs will on average produce 4.5 bbl of oil for each ton of sequestered CO2, a ratio known as the utilization factor. This utilization factor is 1.5 times higher that arrived at by the U.S. Department of Energy, and leads to a cumulative production of oil for all the reservoirs examined of ~183 billion barrels along with a cumulative storage capacity of 41 Mtons CO2. This is equivalent to 26.5 y of current oil consumption by the nation, and 8.5 y of current coal plant emissions.</p> / Thesis

The responsible management and reduction of carbon dioxide (CO2) emissions to the atmosphere requires consideration of alternative options for disposal and long-term sequestration of CO2 generated at hydrocarbon-fueled power plants and large industrial sources. A number of “conventional” options for geological sequestration of CO2 are currently being evaluated worldwide, including disposal of CO2 in depleted oil and gas reservoirs, in deep saline aquifers, and in unrecoverable coal beds, typically in gaseous or liquid form or as a supercritical fluid. Although these geological settings may constitute the most readily accessible sites for immediate utilization, it is unlikely that they represent sufficient cumulative storage capacity to keep pace with global CO2 production and future disposal requirements. In addition, the requirement for long-term maintenance of CO2 sequestered in fluid form, raises concerns regarding the possible mobility of disposed CO2 over the longer term. The Geological Survey of Canada (GSC) has investigated potential opportunities to sequester CO2 in solid form in Canadian geologic reservoirs having pressure and temperature conditions suitable for the formation and long-term stability of CO2 hydrate. Initial screening of candidate reservoirs has identified substantial potentials for CO2 sequestration as gas hydrate in extensive porous sandstone and limestone formations beneath portions of the Canadian Great Lakes, and in areas of the Mackenzie-Beaufort hydrocarbon development region in northern Canada. A significant but less robust capacity has been identified in the oil and gas production regions of northeastern Alberta.

Started as an EOR technique to produce oil, injection of carbon dioxide which is essentially a greenhouse gas is becoming more and more important. Although there are a number of mathematical modeling studies, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to characterize relevant chemical reactions associated with injection and storage of CO2 in carbonate formations. Porosity changes along the core plugs and the corresponding permeability changes are reported for varying CO2 injection rates, temperature and salt concentrations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. It was observed that either a permeability improvement or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related to distribution of pores, brine composition and as well the thermodynamic conditions. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. Calcite scaling is mainly influenced by orientation and horizontal flow resulted in larger calcite deposition compared to vertical flow. The duration of CO2 &ndash / rock contact and the amount of area contacted by CO2 seems to have a more pronounced effect compared to rate effect. The experiments were modeled using a multi-phase, non-isothermal commercial simulator where solution and deposition of calcite were considered by the means of chemical reactions. The calibrated model was then used to analyze field scale injections and to model the potential CO2 sequestration capacity of a hypothetical carbonate aquifer formation. It was observed that solubility and hydrodynamic storage of CO2 is larger compared to mineral trapping.

Le réchauffement climatique est lié aux augmentations des concentrations de gaz à effet de serre dans l'atmosphère terrestre et en particulier aux émissions anthropiques de CO₂. La séquestration géologique a la capacité et la longévité potentielles pour diminuer de façon significative les émissions anthropiques de CO₂. Cette séquestration à grande profondeur induit des risques de fuite des réservoirs géologiques. Parmi les scénarios de fuite envisagés, celui d'une fuite diffuse est le plus inquiétant puisque sans surveillance, cette fuite pourrait perdurer et entrainer des séquelles sur l'environnement ainsi que des risques pour les populations. Des outils et protocoles de surveillance doivent donc être mis au point pour la surveillance en proche surface. Ce travail de thèse s'inscrit dans le cadre de cette problématique. Il a pour objectif la caractérisation, la quantification et la modélisation du transport et des interactions du CO₂ dans une zone non saturée carbonatée. Ce travail a suivi une approche expérimentale sur un site pilote naturel à Saint-Emilion (Gironde, France), avec la réalisation de fuites diffuses en ZNS carbonatée. Cette étude aborde plusieurs thématiques: la description et l'instrumentation du site pilote naturel ; la caractérisation physico-chimique de l'hétérogénéité du réservoir carbonaté ; l'étude du fonctionnement naturel de la ZNS carbonatée et en particulier la mise en place d'une ligne de base des concentrations en CO₂ ; la caractérisation de l'extension des panaches de gaz suite à des expériences de fuite diffuse dans la ZNS carbonatée et l'étude par simulation numérique des interactions gaz-eau-roche lors d'une fuite diffuse de CO₂ dans une ZNS carbonatée. Les résultats de ces travaux montrent l'importance de la caractérisation de l'hétérogénéité du réservoir carbonaté ainsi que des techniques d'échantillonnage et d'analyse des différentes phases en présence. L'établissement de la ligne de base a une importance particulière pour permettre de distinguer les variations naturelles de celles induites par une fuite diffuse de CO₂ dans la ZNS carbonatée. Les modes de transport du CO₂ vont évoluer en fonction des paramètres physico-chimiques. Ce transport se fait par advection et/ou par diffusion. L'utilisation de gaz inertes au niveau du site de séquestration géologique est très importante puisque la détection de ces traceurs permettrait de prédire les arrivées de panaches de CO₂ en proche surface. Par ailleurs, les interactions chimiques doivent être prises en compte dans les modèles de transport afin de pouvoir définir les facteurs de retard et l'impact d'une fuite diffuse de CO₂ sur une ZNS carbonatée. / Global warming is related to atmospheric greenhouse gas concentration increase and especially anthropogenic CO₂ emissions. Geologic sequestration has the potential capacity and the longevity to significantly diminish anthropogenic CO₂ emissions. This sequestration in deep geological formation induces leakage risks from the geological reservoir. Several leakage scenarios have been imagined. Since it could continue for a long period, inducing environmental issues and risks for human, the scenario of a diffusive leakage is the most worrying. Thus, monitoring tools and protocols are needed to set up a near-surface monitoring plan. The present thesis deals with this problematic. The aims are the characterisation, the quantification and the modelling of transport and interactions of CO₂ in a carbonate unsaturated zone. This was achieved following an experimental approach on a natural pilot site in Saint-Emilion (Gironde, France), where diffusive gas leakage experiments were set up in a carbonate unsaturated zone. Different aspects were investigated during the study: natural pilot site description and instrumentation; the physical and chemical characterisation of carbonate reservoir heterogeneity; the natural functioning of the carbonate unsaturated zone and especially the set-up of a CO₂ concentrations baseline; the characterisation of gas plume extension following induced diffusive leakage in the carbonate unsaturated zone and the study of gas-water-rock interactions during a CO₂ diffusive leakage in a carbonate unsaturated zone through numerical simulations. The results show the importance of the carbonate reservoir heterogeneity characterisation as well as the sampling and analysing methods for the different phases. The baseline set-up is of main interest since it allows discrimination between the induced and the natural CO₂ concentrations variations. The transfer of CO₂ in a carbonate unsaturated zone is varying in function of physical and chemical properties. This transfer is done by diffusion and/or advection. Because the detection of the noble gases allows the prediction of CO₂ plume arrival, the use of tracers in the sequestration site is of main importance. The chemical interactions have to be taken under account in transport models in order to predict delay factors and the impact of a CO₂ leakage in a carbonate unsaturated zone.