A Simulation Study of Carbon Dioxide Sequestration in a Depleted Oil Reservoir

Limits to Paris compatibility of CO2 capture and utilization

Qatar is the biggest exporter of liquefied natural gas, LNG, in the world and is a main oil-producing member of The Organization of Petroleum Exporting Countries, OPEC. A fossil fuel-based industry emerged around the ports of Ras Laffan and Mesaieed, Qatar's industrial cities, perusing industrial diversity and maximising the huge fossil fuel reserves that serve as the primary feedstock for the industrial sector. LNG, crude oil, and petroleum products has given Qatar a per capita GDP that ranks among the highest in the world with the lowest unemployment. This also has given Qatar a per capita CO 2 emissions among the highest in the world. A recent report from The World Health Organisation, stated that the capital of Qatar, Doha, is one of the world's most polluted cities and its air ranked the 12th highest average levels of small and fine particles which are particularly dangerous to health [1]. The people and wise leadership of Qatar recognizes the significance of the problem and made environmental development one of the four pillars of Qatar National Vision 2030. The vision places environmental preservation for Qatar's future generations at the forefront. Qatar Carbonates and Carbon Storage Research Centre is an example demonstrating Qatar's commitment to preserve the envioronment by investigating and implementing key technologies such as carbon capture and storage (CCS) to address the next step in climate change. CCS in deep saline aquifers is an important process for CO 2 reduction on industrial scales. The aim of CCS is to safely sequester CO 2 generated from stationary sources, such as power-plants, into aquifers and depleted oil reservoirs. It is considered a valuable option to reduce greenhouse gases and has been proposed as a practical technology to tackle climate change [2–4]. The importance of CCS as a key option to mitigate CO 2 emissions and combat climate change has been highlighted also in a report by the International Energy Agency (IEA) and suggests that CCS could contribute to a 17% reduction in global CO 2 emissions by 2035 [5]. Previously, carbon dioxide injection into the subsurface has mainly been used for enhanced oil recovery (EOR) purposes. That gave rise to Carbon capture, utilization and storage (CCUS) processes in mature oil reservoirs where CO 2 is first used to enhance oil recovery and then ultimately stored in the reservoir. The incremental hydrocarbon recoveries associated with CCUS make it more attractive to implement compared to CCS. It have significant energy, economic and environmental benefits and is considered an important component in achieving the widespread commercial deployment of CCS technology. Residual trapping of CO 2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO 2 migration within the reservoir. Observations and modelling have shown how capillary, or residual, trapping leads to the immobilisation of CO 2 in saline aquifer reservoirs, limiting the extent of plume migration, enhancing the security and capacity of CO 2 storage [6,7]. In contrast, carbonate hydrocarbon reservoirs are characterised by a mixed-wet state in which the capillary trapping of nonpolar fluids have been observed to be significantly reduced relative to trapping in rocks typical of saline aquifers unaltered by the presence of hydrocarbons [8,9]. There are, however, no observations characterising the extent of capillary trapping that will take place with CO 2 in mixed-wet carbonate rocks, the same rock type found in Qatar's subsurface geological formations and many other giant oil reservoirs in the Middle East that hold most of the oil in the world [10, 11]. Experimental tests of CO 2 and brine in carbonate rocks at reservoir conditions are very challenging due to the complex and reactive nature of carbonates when dealing with corrosive fluids pair of CO 2 and brine. In this study, we compare residual trapping efficiency in water-wet and mixed-wet carbonates systems on the same rock sample before and after wettability alteration by aging with oil mixture of Arabian medium crude oil. The experimental work was conducted using a state of the art multi-scale imaging laboratory (core and pore scale) developed at Imperial College London designed to characterise reactive transport and multiphase flow, with and without chemical reaction for CO 2 -brine systems in both sandstone and carbonate rocks at reservoir conditions [12]. The flow loop included stir reactor to equilibrate rock with fluids, high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner and micro x-ray scanner for in situ saturation monitoring. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO 2 and brine at reservoir conditions with the ability to preserve the rock sample from reacting to carbonic acid. We report the initial-residual CO 2 saturation curve and the resulting parameterisation of hysteresis models for both water-wet and mixed-wet systems. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO 2 saturation in a single core-flood. Upon subsequent flooding with CO 2 -equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial residual curve. Observations were made on a single Estaillades limestone core sample. It was made first on its original water-wet state, then were measured again after altering the wetting properties to a mixed-wet system. In particular, CO 2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly on both core and pore scales. A carefully designed wettability alteration programme was designed in this study to replicate a mixed-wet carbonate system similar to those found in Qatari oil reservoirs. At the pore level, oil can precipitate asphaltene and other heavy components after long exposure with the rock changing the wetting state of the surface to oil-wet. A mixture of the evacuated crude oil with an organic precipitant, n-heptane, was used to deposit a stable oil-wet film. The precipitant substituted some of the evaporated and oxidised light hydrocarbon originally existed in the crude and deposited asphaltene to generate a stable strongly oil-wet film layer. Filtration experiments were carried out to sensibly precipitate enough asphaltene for a stable and strong oil-wet film without over precipitating and causing fine migration that can damage the core sample. The weight fraction of asphaltene precipitated with different fractions of crude-precipitant mixtures were measured. The diluent consisted of toluene as the solvent and heptane as the precipitant. 40 ml of the diluent was thoroughly mixed with 1 ml of Arabian Medium crude oil at 11 different precipitant/solvent volume ratios ranging from 0–100% at 10% increments and then left in the dark for 48 hours to allow the system to come to equilibrium. The mass of precipitated asphaltenes was measured in each mixture by vacuum filtration using a 0.45 micron polytetrafluoroethylene hydrophobic filter paper (Millipore) and evaporation of any remaining liquid oil from the filter paper. No asphaltene was precipitated at low precipitant volume fraction and only above the onset of precipitation, a linear relationship was seen between the wt% precipitated asphaltenes and the volume % of the precipitant in the mixture. The onset for asphaltene precipitation for an oil mixture of Arabian Medium crude oil and heptane alone without solvent was calculated at the onset using the volume fractions of the components with the mixing rule. The sample's wettability was altered to a mixed-wet using the appropriate oil mixture as measured using the filtration test and the oil was then removed from the sample by CO 2 enhanced oil recovery injected above the minimum miscibility pressure. This allowed for producing unique dataset and a great complement to the more theoretical analysis. That is if we make a surface oil-wet (to water), how does it behave in the presence of a gas. Here we show that residual CO 2 trapping in mixed-wet carbonate rocks characteristic of hydrocarbon reservoirs is significantly less than trapping in water-wet systems characteristic of saline aquifers. We found that in the native water-wet state of the carbonate sample, the extent of trapping of CO 2 and N 2 were indistinguishable, consistent with past studies of trapping and multiphase flow properties in water-wet sandstones [13, 14]. After alteration of the wetting state of the same rock sample with oil, the residual trapping of N 2 was reduced compared to the amount in the pre-altered rock. Surprisingly, the trapping of CO 2 was reduced even further. The unique results were complemented with pore scale observations to investigate the balance of interfacial tensions and contact angles in three-phase flow. Our results show that one of the key processes for maximising CO 2 storage capacity and security is significantly weakened in hydrocarbon reservoirs relative to saline aquifers. We anticipate this work to highlight a key issue for the early deployment of carbon storage – that

Addressing climate change urgently requires effective carbon capture and storage (CCS) strategies to lower atmospheric carbon dioxide (CO2) levels. Depleted oil and gas reservoirs and saline aquifers are promising for CO2 geological sequestration due to their significant storage capacities. Furthermore, CO2 injection for Enhanced Oil Recovery (EOR) is a potential storage option for CO2 when CO2 flow back is controlled. Therefore, this study provides a techno-economic analysis to evaluate the feasibility, efficiency, and economic analysis of these different geological storage options for CO2 storage. The economic evaluations were conducted in compliance with Section 45Q tax credits for financial viability. The analysis employs a multidisciplinary methodology combining geological assessments, engineering principles, and economic models. It focuses on the long-term impact of injecting CO2. Additionally, it evaluates supercritical CO2 behavior to estimate potential trapping mechanisms and identify factors affecting sequestration efficiency and safety. Economic analysis is central to this study, detailing the costs associated with CO2 capture, compression, transportation, injection, and monitoring. The study also considers the influence of policies, regulations, and market conditions on CCS project economics, identifying incentives and barriers. The findings of this study affirm the potential of depleted oil and gas reservoirs and saline aquifers as viable CO2 storage solutions, offering a nuanced understanding of their role in global carbon mitigation efforts. The results show the economic superiority of the depleted oil and gas reservoirs in storing CO2 if the storage capacity is ignored (i.e., if all storing options are capable of storing the desired CO2 — 1 MM metric tons in this study). The results highlight that storing CO2 in depleted oil and gas reservoirs exhibits the highest financial viability, particularly when used in conjunction with Direct Air Capture (DAC) technologies. These options demonstrate the greatest Net Present Values (NPVs), making them attractive for large-scale CO2 storage projects. Compliant DAC facilities, particularly those utilizing depleted oil and gas reservoirs, achieve NPVs upwards of $27 million, underscoring their economic superiority. While saline aquifers and EOR present viable options due to higher storing capacity, their financial performance is generally lower compared to depleted oil and gas reservoirs if uniform stored volume is considered. The study also notes the significant cost variations influenced by factors such as CO2 capture, transportation, and storage technologies, alongside the availability of financial incentives. By outlining the challenges and opportunities, the study provides essential insights for stakeholders in CCS projects, suggesting a pathway through the complexities of CO2 sequestration towards sustainable climate action. Compliance with regulatory standards, particularly the Section 45Q tax credits, is emphasized as crucial for achieving positive financial outcomes and ensuring the success of CCS initiatives.

Sequestration of carbon dioxide (CO2) in depleted or partially depleted oil reservoirs is an immediate, cost-effective option to reduce CO2 emissions into the atmosphere. Carbon dioxide has been injected into oil reservoirs for the purpose of enhancing oil recovery (EOR). With EOR, the goal is to maximize the oil production by minimizing the use of CO2 while with sequestration, the goal is to maximize the storage of the CO2. During EOR, a significant amount of CO2 may be sequestered in the reservoir. If CO2 emissions are regulated, the EOR process may therefore be able to earn sequestration credits in addition to oil revenues. We develop a theoretical framework that analyzes the co-optimization of oil extraction and CO2 sequestration. The economic analysis takes into account factors such as capture, transportation and recycling costs. This paper discusses the effects of several injection strategies and injection timing on optimization of oil recovery - CO2 storage capacity for a synthetic, three dimensional, heterogeneous reservoir model. A simulation study is completed using a 3-D compositional simulator " ECLIPSE 300?? and an optimization algorithm in order to optimize the net present value of oil recovery and CO2 storage. A number of simulations are studied to achieve comprehensive understanding of the financial performance of coupled CO2 sequestration and EOR projects. The simulations have showed that the projects would be unprofitable for immiscible cases when using costs typical of current CO2 capture from power plants unless there is some form of credit for storage. In contrast, in miscible cases, the projects may be profitable even without considering any CO2 credits and their profitability is further enhanced with possible carbon credits. The results show that innovative reservoir engineering techniques are required for co-optimizing CO2 storage and oil recovery. 1. Introduction CO2 concentration in the atmosphere has drastically increased over the past 250 years from 280 to 380 ppm (Bryant 1997). The major cause of increasing CO2 emissions into the air has been recognized as the dramatic increase in the fossil fuel consumption for energy production. Increasing concentrations of CO2 leads to climate change via enhancing the natural greenhouse effect. Several measures have been suggested to control the problem of increasing CO2 emissions in the air. One of such measures is to decrease carbon intensity of energy production, which means less CO2 per specified amount of produced energy (Forooghi, Hamouda and Eilertsen 2009). CO2 emissions can also be reduced by increasing the share of renewable energies in the energy consumption portfolio. The most promising, immediate option for reducing a large amount of CO2 is, however, the long-term sequestration of CO2 in geological formations. Depleted or mature oil and gas reservoirs, deep saline formations, and unminable coalbeds are usually considered as the most applicable CO2 sequestration formations (Bachu 2003). Geological CO2 storage as the effective option to mitigate atmospheric CO2 emissions has been considered since the 1990's and has been implemented at a large scale for the first time in Norway (Moritis 2002). Oil and gas reservoirs are good candidates for sequestration because industrial experiences already exist for CO2 injection. Regarding economic aspects of the sequestration process, coupled enhanced oil recovery (EOR) and sequestration processes have advantages since the increased oil recovery will offset some of the costs of CO2 sequestration process. The Weyburn CO2 sequestration and EOR project is an example of commercial coupled CO2 EOR and sequestration process, which has shown a great success in terms of both objectives of the project (Malik and Islam 2000). In this project, carbon dioxide is transported from the North Dakota coalgasification plant through pipelines and is injected into the Weyburn oil field.

Large reductions in carbon dioxide (CO2) emissions are needed to mitigate the impacts of climate change. One method of achieving such reductions is CO2 capture and storage (CCS). CCS requires the capture of carbon dioxide (CO2) at a large industrial facility, such as a power plant, and its transport to a geological storage site where CO2 is sequestered. If implemented, CCS could allow fossil fuels to be used with little or no CO2emissions until alternative energy sources are more widely deployed. Large volumes of CO2 are most efficiently transported by pipeline and stored either in deep saline aquifers or in oil reservoirs, where CO2 is used for enhanced oil recovery (EOR). This thesis describes a suite of models developed to estimate the project-specific cost of CO2 transport and storage. Engineering-economic models of pipeline CO2 transport, CO2-flood EOR, and aquifer storage were developed for this purpose. The models incorporate a probabilistic analysis capability that is used to quantify the sensitivity of transport and storage cost to variability and uncertainty in the model input parameters. The cost of CO2 pipeline transport is shown to be sensitive to the region of construction, in addition to factors such as the length and design capacity of the pipeline. The cost of CO2 storage in saline aquifers is shown to be most sensitive to factors affecting site characterization cost. For EOR projects, CO2 storage has traditionally been a secondary effect of oil recovery; thus, a levelized cost of CO2 storage cannot be defined. Instead EOR projects were evaluated based on the breakeven price of CO2 (i.e., the price of CO2 at which the project net present value is zero). The breakeven CO2 price is shown to be most sensitive to oil prices, losses of CO2 outside the productive zone of the reservoir, and reservoir pressure. Future research should include collection and aggregation of more specific data characterizing possible sites for aquifer storage and applications of these models to this data. The implications of alternative regulations and requirements for site characterization should also be studied to more fully assess cost impacts.

The highly urbanized area around Los Angeles is dotted with oil fields and refineries. Oil wells perch in yards, parking lots, even schools. The Wilmington oil field, which stretches beneath much of the land between Los Angeles and its port, as well as for miles off the coast, supplies numerous local refineries that in recent years have shut down repeatedly during power outages. Restarting the facilities often causes clouds of odorous and potentially hazardous gas to be released. After a 3 October 2007 shutdown, for example, a ConocoPhillips refinery released a cloud of “yellow, metallic dust” containing what company representatives called “a mixture of iron, copper, nickel, aluminum, carbon, and other elements,” according to the local DailyBreeze.com news service.

Summary Formation damage is a general term that describes factors harming well productivity and injectability. To mitigate the greenhouse effect caused by the presence of carbon dioxide (CO2) in the atmosphere, scientists have proposed storing CO2 in depleted oil and gas reservoirs, aiming to result in enhanced oil recovery (EOR). This approach, despite its benefits, can also result in formation damage, including salt precipitation, leading to reduced porosity and permeability, thereby affecting injectability and productivity. In this study, we used glass micromodels with homogeneous and heterogeneous patterns to comprehensively and visually investigate the salt precipitation during CO2 injection in carbon capture and storage (CCS) and EOR processes. In addition, we ivestigated virtually the impact of porous media type, brine concentration, CO2 injection flow rate, and different salt types, as well as a comparative analysis of these variables. Three different brines containing sodium chloride, calcium chloride, and potassium chloride were utilized, using reservoir oil experiments. With increasing salt concentration, salt precipitation increased in all parts of the porous media, and with increasing CO2 injection rate, the amount of salt precipitation decreased, especially at the entrance of the porous media. In the homogeneous micromodel, more salt precipitate formed than in the heterogeneous micromodel, and the distribution of salt precipitation was more regular because it had more regular pores and porosity. The amount of salt precipitation in CCS is more than in EOR because, in CCS, the amount of brines in pores is more. Sodium chloride salt caused more precipitation during CO2 injection due to its lower van der Waals radius than other salts.

ABSTRACT: Carbon Capture and Storage (CCS) is globally recognized as the most effective method for achieving the ‘dual-carbon’ goals. The depleted oil reservoirs in the Ordos Basin of China have significant potential for carbon storage. In the process of CO2 geological burial, caprock, serving as a natural barrier for CO2, is crucial element in preventing CO2 from escaping to the upper layers and ensuring the safety of carbon sequestration. After CO2 injection into the reservoir, it affects the mechanical properties of the caprock and alters it sealing ability. Therefore, it is necessary to conduct relevant research to explore the evolution characteristics of the mechanical properties and sealing ability of the caprock during CO2 injection. This paper has conducted experiments on the evolution of the mechanical property of caprock before and after CO2 exposure. Furthermore, it delves into the research on the breakthrough pressure of CO2 in the caprock, aiming to determine the CO2 sealing characteristics of caprock. The results indicate that CO2 injection causes a slight change in the mechanical properties of the caprock. Compressive and tensile strength show a decreasing trend, and the elastic modulus experiences a decrease, which mainly caused by partial dissolution of mineral and alterations in rock pore structure observed by SEM. The breakthrough pressure of CO2 in target caprock range from 2.08 to 10.27 MPa. With increasing permeability, the CO2 breakthrough pressure significantly reduces, while CO2 breakthrough pressure averagely decreases by 9.7% under SC-CO2 exposure. The above research showed that CO2 injection will not only cause changes in the mechanical properties and a decrease in breakthrough pressure for caprock. This study can provide theoretical guidance for carbon sequestration in depleted oil reservoirs and the sealing feasibility analysis of the caprock against CO2. 1. INTRODUCTON Carbon capture and storage (CCS) is widely recognized as one of the main pathways for reducing carbon emissions, playing a crucial role in supporting China's achievement of its "dual carbon" goals. The mature development and scaled application of CO2 storage technology are of strategic importance [1-4]. CO2 storage primarily involves geological structures such as depleted/exhausted oil and gas reservoirs, deep saline aquifers, and unmineable coal seams [5-7]. Depleted/exhausted oil and gas reservoirs, due to their well-developed geological structures and infrastructure, make CO2 storage more straightforward and economically viable. Additionally, injecting CO2 into depleted/exhausted oil and gas reservoirs not only helps maintain the integrity of the reservoir's pressure system but also holds potential for enhancing the displacement of residual oil. Therefore, utilizing depleted/exhausted oil and gas reservoirs for carbon storage is not only significant in terms of economic prospects but also presents positive development [8, 9].

Geological performance evaluation of CO2 sequestration in depleted oil reservoirs: A simulation study on the effect of water saturation and vertical to horizontal permeability ratio

Increasing emissions of greenhouse gases (GHGs) have been identified as the main contributor to global warming and climate change. Carbon dioxide (CO2) is the primary anthropogenic GHG. Carbon capture and storage (CCS) is widely recognized as a key mitigation technology that can significantly reduce CO2 emissions during combustion. It involves capturing CO2 from large stationary sources and subsequently storing it in various reservoirs such as depleted oil or gas reservoirs, saline aquifers and deep unmineable coal seams. In this work, a finite-scenario based two-stage stochastic mixed integer linear programming (MILP) model is developed for planning the retrofit of power plants with carbon capture (CC) technology and the subsequent CO2 source-sink matching in CCS supply chains under uncertainty. This model can be used to select appropriate sources, capture technologies and sinks and maximize the amount of captured and stored CO2 under the presence of uncertainty. Furthermore, to control risk at the optimal deployment of CCS systems, probabilistic financial risk metric is incorporated into the model. A case study is used to demonstrate the application of the proposed model. The computational results show that after risk management, risk of the expectation amount of captured and stored CO2 is reduced.

Carbon dioxide (CO2) emissions, the most important anthropogenic greenhouse gas (GHG), can be reduced by CO2 capture and storage (CCS). This strategy is applicable to many large stationary sources including power generation plants, oil and gas refinery, cement production and other industrial sectors generating large point source of CO2. While the technology for CCS is currently available, significant improvements are needed to enhance confidence in storage security. In 1996, the first CCS project established for the purpose of mitigation of CO2 emission began injecting CO2 into deep geological formation in offshore aquifer in the North Sea, Norway. Since that time, science has advanced in areas such as geophysics, chemical engineering, monitoring and verification, and other areas, while also governments have funded demonstration projects at various sizes ranging from small-scale proof of concept to industrial-scale demonstration projects. Five industrial-scale CCS projects are currently operational globally with more than 0.035 Pg of CO2 captured and stored since 1996. Observations from these industrial scale projects and commercial CO2 enhanced oil recovery (CO2-EOR), engineered natural analogues as well as theoretical consideration, models and laboratory studies have suggested that appropriately selected and well managed CCS sites are likely to retain almost all of injected CO2 for long time and provide the benefits for the intended purpose of CCS. However, CCS is still struggling to gain foothold as one of the main options for mitigating climate change due to high costs, advances in other options including renewable energy, as well as discovery of shale natural gas and the associated hydrological fracturing extraction techniques, absence of international action by governments and private sectors on climate change, economic crisis-induced low carbon (C) prices, and public skepticism. The estimated costs for CCS varies widely depending on the application—such as gas clean-up versus electricity generation, type of fuel, capture technology , and assumptions about the baseline technology. Generally, for current technology, CCS would increase cost of generating electricity by 50–100%, and parasitic energy requirement of 15–30%. In this case, capital costs and energy requirements are the major cost drivers. In addition, significant scale-up compared to existing CCS activities will be needed to achieve intended large reductions of CO2 emissions. For example, a 5- to 10-fold scale-up in the size of individual projects is needed to capture and store emissions from a typical coal-fired power plant of 500–1000 MW, while a thousand-fold scale-up in size of current CCS enterprise would be needed to reduce emissions by 1 Pg C yr−1. The estimated global oil and gas reservoirs are 1000 Pg CO2, saline aquifers global potential capacity ranges from 4000 to 23,000 Pg CO2. However, there is considerable debate about how much storage capacity actually exists and is available for CCS, particularly in saline aquifers. Research, improved geological assessments and commercial scale demonstration projects will be needed to verify the estimated capacity and improve confidence in storage capacity estimates.

The challenges facing offshore CO2 enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects are presented in this paper along with potential solutions based on the oil and gas (O&G) industry's CO2 EOR and CCS experience and technology as applied in a few offshore locations. Prospects for future offshore projects are also discussed based on the O&G industry's experience, technology, and best practices. These achievements are the result of a safe and successful 58-year history of well construction and operations in land-based, commercial CO2 EOR projects. Achieving CCS by injecting CO2 into saline formations or for EOR in mature oil reservoirs is a safe and effective method to reduce GHG (greenhouse gas) emissions. The IPCC has defined enhanced oil and gas recovery via CO2 injection as a recognized form of CCS. Using existing industry experience and technology developed over the past 58 years, CO2 injection into oil reservoirs for EOR has been safely and effectively applied in 18,077 active wells worldwide (17,112 in USA) according to the latest EOR survey (O&GJ, 2010). Production from natural gas reservoirs has also benefitted from CO2 injection in enhanced gas recovery (EGR) applications. Key results are summarized and major conclusions presented from studies by the American Petroleum Institute; Advanced Resources International; European Commission, DG-Joint Research Centre, Institute for Energy; Kinder Morgan; Norwegian Petroleum Directorate; Bellona Foundation; Norwegian University of Science and Technology; SINTEF Petroleum Research; and others. Conclusions from these studies point to the substantial value of current industry experience as a sound basis for offshore CCS applications. Offshore CCS/EOR may be more viable than onshore options for areas with high population densities, where offshore reservoirs are within reasonable distances from land, or where there are existing offshore O&G facilities and wells. The technical knowledge base of the petroleum industry can be leveraged for the development of CCS with a strong understanding of the pros and cons of offshore projects, operating experience with safe and economic CO2 capture, transportation, injection, and understanding of subsurface formations for future CO2 EOR/CCS applications. Introduction Oil and Gas Industry Experience The first patent for CO2 EOR was granted in 1952 (Whorton). The Texas Railroad Commission (TRRC report) proposed CCS rule states that " the first three projects (immiscible) were in Osage County, Oklahoma from 1958 to 1962.?? Another early CO2 EOR project was in Jones County, near Abilene, Texas in the Mead Strawn field in 1964 (Holm). The first large-scale, commercial CO2 EOR project (Langston) began operations in 1972 at the SACROC field in West Texas, which continues in operation today. Many more CO2 " flood?? EOR projects have started since then. By 2010, CO2 EOR projects had reached a global total of 127 (112 in USA) with 12 more planned for the USA, as reported in the EOR survey by the Oil and Gas Journal (O&GJ, 2010). Rising oil prices, low cost sources of high purity CO2, and access to miscible fields with large amounts of unrecovered oil have supported growth in CO2 based EOR in the U.S., which now accounts for 272 mbd (O&GJ, 2010) or over 8% of total Lower 48 crude production of 3.22 mmbd in the 2nd quarter 2010, as reported by the U.S. Energy Information Administration.

CO2-sequestration in deep geological formations has been suggested as an option to reduce greenhouse gas emissions. Saline aquifers are one of the most promising options for carbon dioxide storage. It has been investigated that if the layer of aquifer is deep enough, at depths more than 800 meters, dissolution of CO2 into brine causes density of the mixture to increase. If the corresponding Rayleigh number of the porous medium is enough to initiate convection currents, the rate of dissolution will increase. Early time dissolution of CO2 in brine is mainly dominated by molecular diffusion while the late time dissolution is predominantly governed by convective mixing mechanism. In this paper, linear stability analysis of densitydriven miscible flow for carbon dioxide sequestration in deep inclined saline aquifers is presented. The effect of inclination and its influence on the pattern of convection cells has been investigated and the results are compared with the horizontal layer. The current analysis provides approximations for initial wavelength of the convective instabilities and onset of convection that help in selecting suitable candidates for geological CO2 sequestration sites. Introduction Carbon dioxide sequestration is the capture and safe storage of carbon dioxide that would otherwise emit to the atmosphere. Sequestration refers to any storage scheme that can keep CO2 out of the atmosphere [1]. In general, storage sites of carbon dioxide can be divided into two categories, geological sites and marine sites. Carbon dioxide sequestration in deep geological formations has been suggested as a way of reducing greenhouse gas emissions. Geologic sequestration of CO2 is the capture of CO2 from major sources, transporting it usually by pipeline, and injecting it into underground formations such as oil and gas reservoirs, saline aquifers, and unmineable coal seams for geologically significant period of time [2, 3]. Unlike coal bed methane reserves and oil reservoirs, sequestration of CO2 in deep saline aquifers does not produce value-added by-products, but it has other advantages. While there are uncertainties, the world's total capacity to store CO2 deep underground is large [4]. They are generally unused and are available in many parts of the world [5]. It has been estimated that deep saline formations in the United States could potentially store up to 500 billion tones of CO2. Most existing large CO2 point sources are within easy access to a saline formation injection point, and therefore sequestration in saline formations is compatible with a strategy of transforming large portions of the existing energy and industrial assets to near-zero carbon emissions via low-cost carbon sequestration retrofits [3]. However, it is important to investigate the behavior of CO2 injected into aquifers for effective and safe use of storage. Geological storage of CO2 as a greenhouse gas mitigation option was proposed in the 1970s [6], but little research was done until the early 1990s, when the idea gained credibility through the work of individual research groups [7–10]. When CO2 is injected into the formation above its critical temperature and pressure the density of supercritical carbon dioxide is usually less than brine.

CO2 sequestration in deep geological formations has been suggested as an option to reduce greenhouse gas emissions. Saline aquifers are one of the most promising options for carbon dioxide storage. It has been shown that the dissolution of CO2 into brine causes the density of the mixture to increase. If the corresponding Rayleigh number of the porous medium is enough to initiate convection currents, the rate of dissolution will increase. Early time dissolution of CO2 in brine is mainly dominated by molecular diffusion, while late time dissolution is predominantly governed by a convective mixing mechanism. In this paper, linear stability analysis of density-driven miscible flow for carbon dioxide sequestration in deep inclined and homogeneous saline aquifers is presented. The effect of inclination and its influence on the pattern of convection cells has been investigated and the results are compared with the horizontal layer. The current analysis provides approximations for the initial wavelength of the convective instabilities and the onset of convection that helps in selecting suitable candidates for geological CO2 sequestration sites. Introduction Carbon dioxide sequestration is the capture and safe storage of carbon dioxide that would otherwise emit to the atmosphere. Sequestration refers to any storage scheme that can keep CO2 out of the atmosphere(1). In general, proposed storage sites of carbon dioxide can be divided into two categories: geological sites and marine sites. Carbon dioxide sequestration in deep geological formations has been suggested as a way of reducing greenhouse gas emissions. Geologic sequestration of CO2 is the capture of CO2 from major sources, transporting it usually by pipeline, and injecting it into underground formations such as oil and gas reservoirs, saline aquifers and unmineable coal seams for a significant period of time(2, 3). Unlike coalbed methane reserves and oil reservoirs, sequestration of CO2 in deep saline aquifers does not produce value-added by-products, but it has other advantages. While there are uncertainties regarding the scope, the world's total capacity to store CO2 deep underground is large(4). Underground formations are generally unused and are available in many parts of the world(5). It has been estimated that deep saline formations in the United States could potentially store up to 500 billion tonnes of CO2. Most existing large CO2 point sources are within easy access to a saline formation injection point and, therefore, sequestration in saline formations is compatible with a strategy of transforming large portions of the existing energy and industrial assets to near-zero carbon emissions via low-cost carbon sequestration retrofits(3). However, it is important to investigate the behaviour of CO2 injected into aquifers for effective and safe use of storage. Geological storage of CO2 as a greenhouse gas mitigation option was proposed in the 1970s(6), but little research was done until the early 1990s when the idea gained credibility through the work of individual research groups(7–10). When CO2 is injected into the formation above its critical temperature and pressure, the density of supercritical carbon dioxide is usually less than brine. This density difference causes CO2 to migrate upwards to the top of the formation under an impermeable caprock.

Best Practice for Transitioning from Carbon Dioxide (CO2) Enhanced Oil Recovery EOR to CO2 Storage