CO2 Sequestration In Geological Formations Research Articles

Numerical investigations on the performance of sc-CO2 sequestration in heterogeneous deep saline aquifers under non-isothermal conditions

CO2 sequestration in geological formations is an efficient step towards mitigating climate change by reducing global warming. The CO2 emitted from natural sources and anthropogenic activities is injected into geological formations. The flow and transport of CO2 during sequestration operations require in-depth knowledge of the effects of the type of geological formation. The present work analyses the CO2 migration and storage in a heterogeneous deep saline aquifer with variable porosity and evolving permeability under non-isothermal flow conditions while upscaling the capillary pressure using the Leverett J-function. The developed numerical model is history-matched with CO2 gas saturation profiles reported using analytical and numerical approaches. The novelty of the present work lies in its ability to capture fine-scale heterogeneities in the aquifer, which is modelled through variation in the porosity (ϕ) distribution and the permeability (k). The thermal-hydraulic numerical analysis projected a pronounced effect of the degree of heterogeneity arising from the variation in porosity and permeability on pressure buildup along the top of the formation decreasing from a maximum of about 6.41 MPa at the injection well to about 0.933 MPa at 1200 m and affecting gas characteristics and transmission. The thermal front could only propagate to a maximum extent of about 142 m from the injection well in aquifers, while gas plume lengths migrated to a maximum plume length of about 1010 m. The permeability and porosity of the aquifer are critically observed to vary during the sequestration by a ratio (k/k0) of about 1.07 to 1.01 and a percentage of about 0.791 % – 3.136 % in the low permeable conditions. Maximum effective storage of CO2 by a factor of 0.95 observed in low-permeable heterogeneous aquifers with normally distributed porosity affirms maintenance of optimum gas injection rates below the fracture gradient in these formations to sequester the CO2 economically.

Advancing subsurface analysis: Integrating computer vision and deep learning for the near real-time interpretation of borehole image logs in the Illinois Basin-Decatur Project

The accurate quantification and mapping of subsurface natural fracture systems using borehole imaging logs are critical for the success of CO2 sequestration in geologic formations, optimization of engineered geothermal systems, and hydrocarbon production enhancement. However, traditional interpretation processes suffer from time-consuming procedures and human bias. To address these challenges and expedite fracture analysis, we investigated the application of integrated computer vision and DL workflows to automate image log analysis. Specifically, the design of our workflow was crafted to swiftly detect fractures and baffles by using actual electrical resistivity of borehole wall from microresistivity imaging device alongside their binary representation. This novel approach significantly reduces computational time while providing invaluable insights. By incorporating conventional logging and microseismic data, we present a regional subsurface natural fracture mapping technique. Through the minimization of human bias in image log analysis, our automated workflow achieves reduced fracture interpretation time and costs while ensuring robust and reproducible results. We demonstrated the efficacy of our approach by applying the workflow to the Illinois Basin-Decatur Project site. The automated workflow successfully identified major fractured zones, multiple baffles, and an interbedded layer with a high resolution of 0.01 ft or 0.12 in. (0.3 cm) and can be upscaled to any desired resolution. Validation through microseismic and image log interpretations allows for accurate and near-real-time mapping of fractures and baffles, significantly enhancing CO2 pressure forecasting and postinjection site care. Our approach stands out due to its robustness, consistency, and reduced computational cost compared with alternative feature extraction technologies. It presents exciting possibilities for advancing CO2 sequestration and engineered geothermal efforts by offering comprehensive and efficient fracture mapping solutions. This technology can contribute significantly to the optimization of CO2 sequestration projects, facilitating sustainable environmental practices, and combating climate change.

A general review of CO2 sequestration in underground geological formations and assessment of depleted hydrocarbon reservoirs in the Niger Delta

This paper investigates the viability of CO2 storage in geological formations, including depleted hydrocarbon reservoirs applying 3-dimensional seismic and well data of the Niger Delta region as a case study for CO2 sequestration, which represents an essential initiative for the reduction of greenhouse gas emissions. Different theoretical and experimental studies from literature on CO2 sequestration in geological formations across the world, including the Niger Delta, are reviewed. The Niger Delta basin has a high potential for CO2 sequestration, and this indication is shown through the review of research papers undertaken outside and within the basin, which reveal the presence of massive hydrocarbon fields, lateral continuity of reservoir, reservoir-seal pairs, faults, and traps, developed hydrocarbon fields, appropriate reservoir depth. The gaps identified from the review of various research studies are analyzed to form the basis of a future research investigation for capturing, removing, and storing CO2 in depleted hydrocarbon reservoirs and other geological formations. The authors deduced that accurate injection pressure, rate, and depth estimation are critical factors for CO2 sequestration and need to be thoroughly investigated.

Hertz‐Mindlin Theory of Contacting Grains and the Effective‐Medium Approximation for the Permeability of Deforming Porous Media

AbstractEstimating flow and transport properties of porous media that undergo deformation as a result of applying an external pressure or stress is important to a wide variety of processes, ranging from shale formations into which a fracking liquid is injected to CO2 sequestration in geological formations. We propose a novel model for estimating the effective permeability of such porous media. Given the pore‐size distribution (PSD) of a porous medium before deformation, as well as the Young's modulus of its grains, the model uses Hertz‐Mindlin theory of contact between grains to compute the new PSD that results from applying an external pressure P to the medium and utilizes the updated PSD in the effective‐medium approximation to estimate the effective permeability at P. Comparison between the predictions and experimental data for several types of sandstones indicates excellent agreement between the two.

CO2 and alkane minimum miscible pressure estimation by the extrapolation of interfacial tension

CO2 sequestration in geological formations which can be achieved via injecting the captured CO2 into the pores of depleted oil/gas reservoirs or saline aquifers, is a potential method for reducing greenhouse gas emission. Oil production by CO2 injection, known as the CO2 enhanced oil recovery (CO2-EOR) technique, is a utilization of CO2 with both economic and environmental benefits. The interfacial tension (IFT) and minimum miscible pressure (MMP) of gas–oil system under reservoir conditions are crucial to evaluate the feasibility of this scheme as they determine the eventual improvement of oil recovery efficiency and CO2 storage capacity of reservoir. Thus, it is of great significance to conduct the laboratory experiments on the IFT and MMP of binary systems containing CO2 and oil. In this study, we measured the IFT between CO2 and alkanes with the pendant drop method at a temperature of 298–373 K and pressure of 0.1–15 MPa. The MMP of CO2–alkane was evaluated respectively through the direct observation of gas–oil interface disappearance and by finding the IFT vanishing point using an exponential extrapolation of the IFT values under different pressures. The experimental results indicate that the CO2–alkane IFTs decrease sharply with pressure across the experiment's temperature range. They increase with temperature at higher pressure but decrease at lower pressure in the experimental pressure range. They also increase slightly with carbon number of the alkane at high temperatures. The CO2–alkane IFT exhibits the weakest dependence on the temperature at the high pressure (4–6 MPa) and the high temperature (T > 323 K). Moreover, the linear increase of the CO2–alkane MMP with the temperature was observed and slops increase with the increasing carbon number of the alkane.

Three-phase non-isothermal flow behavior of CO2-brine leakage from wellbores

CO2 leakage from the subsurface is one of the major concerns in relation to CO2 sequestration in geological formations. In this study we propose a transient, three-phase non-isothermal flow model to describe the relevant CO2-water (brine) leakage process through a wellbore. The model is formulated on the basis of the T2WELL program by incorporating the ECO2M equation of state and a three-phase drift-flux model. Three case studies are presented for verification, validation, and application of the proposed CO2-leakage model. In case-1, an analytical solution is derived as a limiting case of the present model, and it allows one to obtain an analytical insight into the flow profile when the leakage scenario is a two-phase steady one without phase transition. Comparison of this analytical solution with the relevant numerical solution shows that both are fully consistent. In case-2, we compare our numerical model with a classic Darcy-law-based CO2-leakage model, demonstrating that the latter one would generate significant deviations because of excluding the inertia effect. In case-3, we use the present model to simulate the potential CO2-leakage profile in the Ordos CO2-sequestration site (China), and demonstrate that very sophisticated flow scenarios could be created, in which three-phase co-existence regime could be present, and highly oscillating flow profile would occur. The temperature of the leaking fluid with high-concentration of CO2 may also drop dramatically because of the Joule-Thomson effect, even leading to formation of ice phase at the wellhead. Our model may be useful for evaluating the potential of CO2 leakage from wellbores, and for assessing the safety issues related to CO2 geological storage.

Acquisition of temporal-spatial geochemical information in ore-forming and carbon-dioxide sequestration systems: Computational simulation approach

Temporal-spatial distributions of geochemical data in geoinformatics are very important for mineral exploration in the upper crust of the Earth and for the treatment of geoenvironmental issues such as CO2 sequestration in geological formations. To understand ore-forming processes associated with mineral exploration, it is necessary to acquire geochemical information regarding orebody formation and mineralization in hydrothermal systems within the upper crust of the Earth in the past. On the contrary, to generate a safe design for CO2 sequestration in a geological formation, it is necessary to predict the composition of geochemical environment after CO2 sequestration and test such predictions through acquiring geochemical information in the future, so that the safety and feasibility of the design can be adequately assessed. The computational simulation approach is used, in this paper, to facilitate and guide these acquisition procedures. To demonstrate the feasibility and usefulness of the computational simulation approach in this aspect, a simplified ore-forming system associated with the Australian Broken Hill Pb and Zn mine, which belongs to a natural system, and a fluid-rock reaction system involving CO2 sequestration in a geological formation, which belongs to a man-made system, are considered to model geochemical information. The related computational simulation results demonstrate that the computational simulation method is not only applicable for simulating the ore-forming processes in hydrothermal systems within the upper crust of the Earth, but also useful for acquiring both the ancient geochemical information associated with ore-forming systems and the future geochemical information associated with geoenvironmental systems.

Sorption equilibrium and kinetics of CO2 on clay minerals from subcritical to supercritical conditions: CO2 sequestration at nanoscale interfaces

CO2 sequestration in geological formations has attracted attention as a promising method to reduce anthropogenic CO2 emission. CO2 sorption at nanoscale interfaces of clay minerals were studied from subcritical to supercritical conditions because clay minerals are a constituent of various rocks such as a cap rock, reservoir rock and coal mineral matter. The sorption capacity and kinetics of CO2 on montmorillonite, illite, and sepiolite were measured by a gravimetric method. Sepiolite had the highest sorption capacity at all experimental conditions. After high CO2 pressure sorption, the desorption isotherm on montmorillonite showed significant hysteresis, but the hysteresis on illite and sepiolite was relatively weak. The excess sorption isotherms of all clay minerals showed a maximum near the critical pressure and the absolute sorption isotherms approached the saturation over the critical density value of CO2. The surface area changes of clay minerals by supercritical CO2 sorption were observed by comparing the N2 sorption isotherms between the raw material and post-experiment sample. The CO2 sorption rates on clay minerals were within a single order of magnitude (10−8 m2/s). The results at nanoscale interfaces can contribute to understanding the sorption capacity and sealing integrity of sedimentary rocks in CO2 geological storage.

The applicability of C-14 measurements in the soil gas for the assessment of leakage out of underground carbon dioxide reservoirs

Abstract Poland, due to the ratification of the Kioto Protocol, is obliged to diminish the emission of greenhouse gases. One of the possible solutions of this problem is CO2 sequestration (CCS - carbon capture and storage). Such an option is a priority in the European Union. On the other hand, CO2 sequestration may be potentially risky in the case of gas leakage from underground reservoirs. The most dangerous event may be a sudden release of the gas onto the surface. Therefore, it is very important to know if there is any escape of CO2 from underground gas reservoirs, created as a result of sequestration. Such information is crucial to ensure safety of the population in areas located above geological reservoirs. It is possible to assess the origin of carbon dioxide, if the measurement of radiocarbon 14C concentration in this gas is done. If CO2 contains no 14C, it means, that the origin of the gas is either geological or the gas has been produced as a result of combustion of fossil fuels, like coal. A lot of efforts are focused on the development of monitoring methods to ensure safety of CO2 sequestration in geological formations. A radiometric method has been tested for such a purpose. The main goal of the investigations was to check the application possibility of such a method. The technique is based on the liquid scintillation counting of samples. The gas sample is at first bubbled through the carbon dioxide adsorbent, afterwards the adsorbent is mixed with a dedicated cocktail and measured in a low-background liquid scintillation spectrometer Quantulus. The described method enables measurements of 14C in mine and soil gas samples.

Numerical Modeling of a Potential Geological CO 2 Sequestration Site at Minden (Germany)

We study opportunities for CO2 sequestration in geological formations of the state North Rhine Westphalia in Germany. Simulations are performed for evaluating a potential site within the Bunter sandstone formation near the town of Minden in a depth of around 3,000 m using the numerical simulator TOUGHREACT. Our focus is on three CO2 storage mechanisms: (1) hydrodynamic trapping, (2) dissolution trapping, and (3) mineral trapping. The results show that due to buoyancy the injected CO2 phase initially migrates towards the top of the reservoir and is hydrodynamically trapped beneath the confining layer of the cap rock. Then, the CO2 spreads laterally and dissolves partially in the formation water. The dissolution of CO2 results in an increase of the density of the brine causing a downward migration until it settles after 10,000 years at the bottom of the reservoir. The simulations indicate that after 10,000 years, 15% (17 Mt) from a total of 114 Mt injected CO2 are trapped hydrodynamically, 20% (23 Mt) are trapped by dissolution, and 65% (74 Mt) are fixed in newly formed carbonates such as dawsonite, ankerite, and siderite. Within our study pressure increases near the injection well by a factor of 1.1 which is lower than the upper limit usually accepted in gas storage operations. The mineral reactions cause a net decrease of porosity and in turn a decrease of permeability down to 9% of the initial value in parts of the reservoir.

Supercritical fluid behavior at nanoscale interfaces: Implications for CO2 sequestration in geologic formations

Injection of CO2 into subsurface geologic formations has been identified as a key strategy for mitigating the impact of anthropogenic emissions of CO2. A key aspect of this process is the prevention of leakage from the host formation by an effective cap or seal rock which has low porosity and permeability characteristics. Shales comprise the majority of cap rocks encountered in subsurface injection sites with pore sizes typically less than 100 nm and whose surface chemistries are dominated by quartz (SiO2) and clays. We report the behavior of pure CO2 interacting with simple substrates, i.e. SiO2 and muscovite, that act as proxies for more complex mineralogical systems. Modeling of small-angle neutron scattering (SANS) data taken from CO2–silica aerogel (95% porosity; ∼7 nm pores) interactions indicates the presence of fluid depletion for conditions above the critical density. A theoretical framework, i.e. integral equation approximation (IEA), is presented that describes the fundamental behavior of near-critical adsorption onto a non-confining substrate that is consistent with SANS experimental results. Structural and dynamic behavior for supercritical CO2 interaction with muscovite (KAl2Si3AlO10(OH)2) was assessed by classical molecular dynamics (CMD). These results indicate the development of distinct layers of CO2 within slit pores, reduced mobility by one to two orders of magnitude compared to bulk CO2 depending on pore size and formation of bonds between CO2 oxygens and H from muscovite hydroxyls. Analysis of simple, well-characterized fluid-substrate systems can provide details on the thermodynamic, structural and dynamic properties of CO2 at conditions relevant to sequestration.

Dynamics of Vertical Displacement in Porous Media Associated With CO2 Sequestration

Summary The problem of CO2 sequestration in geologic formations is analyzed from a fundamental perspective. In order to clearly understand the first order behavior of the system, the mechanisms of trapping, dissolution and chemical reactions are not accounted for. The analysis is concerned with the post-injection period when the CO2 plume rises due to buoyancy. Characteristics of the plume for a 1D problem show that a pair of shocks moving in opposite directions is produced at the top end. The downward moving shock interacts with the bottom end of the plume resulting in a decrease in the maximum value of the CO2 saturation. High accuracy numerical simulations are employed to understand the 2D mechanisms of plume evolution in terms of the viscosity ratio and the capillary number. 2D results show that the plume rises to significantly lower depth, in shorter times, as compared to the 1D problem. This behavior is governed by the 2D velocity field around the plume that additionally leads to spanwise wave interactions and results in a faster decrease of the maximum CO2 saturation. The initial dimensions of the plume have a strong influence on the time scales of the wave interactions. The maximum upward velocity that is generated due to buoyancy is closely related to the maximum saturation and decays rapidly to very small values with a decrease in saturation. In the case where the viscosity of CO2 is a tenth of the viscosity of the surrounding fluid, the plume rises up about 500 m in 700 yrs. Our results provide an upper bound on the maximum rise distance and the sequestration time for the problem involving trapping and dissolution. Comparison with experimental results show that the buoyancy velocity obtained from our results is of the same order as observed in the experiments.

Numerical Modeling of CO2 Sequestration in Geologic Formations - Recent Results and Open Challenges

Rising atmospheric concentrations of CO2, and their role in global warming, have prompted efforts to reduce emissions of CO2 from burning of fossil fuels. An attractive mitigation option under consideration in many countries is the injection of CO2 from stationary sources, such as fossil-fueled power plants, into deep, stable geologic formations, where it would be stored and kept out of the atmosphere for time periods of hundreds to thousands of years or more. Potential geologic storage reservoirs include depleted or depleting oil and gas reservoirs, unmineable coal seams, and saline formations. While oil and gas reservoirs may provide some attractive early targets for CO2 storage, estimates for geographic regions worldwide have suggested that only saline formations would provide sufficient storage capacity to substantially impact atmospheric releases. This paper will focus on CO2 storage in saline formations.Injection of CO2 into a saline aquifer will give rise to immiscible displacement of brine by the advancing CO2. The lower viscosity of CO2 relative to aqueous fluids provides a potential for hydrodynamic instabilities during the displacement process. At typical subsurface conditions of temperature and pressure, CO2 is less dense than aqueous fluids and is subject to upward buoyancy force in environments where pressures are controlled by an ambient aqueous phase. Thus CO2 would tend to rise towards the top of a permeable formation and accumulate beneath the caprock. Some CO2 will also dissolve in the aqueous phase, while the CO2-rich phase may dissolve some formation waters, which would tend to dry out the vicinity of the injection wells. CO2 will make formation waters more acidic, and will induce chemical rections that may precipitate and dissolve mineral phases (Xu et al., 2004). As a consequence of CO2 injection, significant pressurization of formation fluids would occur over large areas. These pressurization effects will change effective stresses, and may cause movement along faults with associated seismicity and increases in permeability that could lead to leakage from the storage reservoir (Rutqvist and Tsang, 2005).