An Experimental Study of CO<Subscript>2</Subscript> Exsolution and Relative Permeability Measurements During CO<Subscript>2</Subscript> Saturated Water Depressurization

Dissolution of CO₂ into brine is an important and favorable trapping mechanism for geologic storage of CO₂. There are scenarios, however, where dissolved CO₂ may migrate out of the storage reservoir. Under these conditions, CO₂ will exsolve from solution during depressurization of the brine, leading to the formation of separate phase CO₂. For example, a CO₂ sequestration system with a brine-permeable caprock may be favored to allow for pressure relief in the sequestration reservoir. In this case, CO₂-rich brine may be transported upwards along a pressure gradient caused by CO₂ injection. Here we conduct an experimental study of CO₂ exsolution to observe the behavior of exsolved gas under a wide range of depressurization. Exsolution experiments in highly permeable Berea sandstones and low permeability Mount Simon sandstones are presented. Using X-ray CT scanning, the evolution of gas phase CO₂ and its spatial distribution is observed. In addition, we measure relative permeability for exsolved CO₂ and water in sandstone rocks based on mass balances and continuous observation of the pressure drop across the core from 12.41 to 2.76 MPa. The results show that the minimum CO₂ saturation at which the exsolved CO₂ phase mobilization occurs is from 11.7 to 15.5%. Exsolved CO₂ is distributed uniformly in homogeneous rock samples with no statistical correlation between porosity and CO₂ saturation observed. No gravitational redistribution of exsolved CO₂ was observed after depressurization, even in the high permeability core. Significant differences exist between the exsolved CO₂ and water relative permeabilities, compared to relative permeabilities derived from steady-state drainage relative permeability measurements in the same cores. Specifically, very low CO₂ and water relative permeabilities are measured in the exsolution experiments, even when the CO₂ saturation is as high as 40%. The large relative permeability reduction in both the water and CO₂ phases is hypothesized to result from the presence of disconnected gas bubbles in this two-phase flow system. This feature is also thought to be favorable for storage security after CO₂ injection.     

Modeling of Rocks and Cement Alteration due to CO<Subscript>2</Subscript> Injection in an Exploited Gas Reservoir

The injection of CO₂ in exploited natural gas reservoirs as a means to reduce greenhouse gas (GHG) emissions is highly attractive as it takes place in well-known geological structures of proven integrity with respect to gas leakage. The injection of a reactive gas such as CO₂ puts emphasis on the possible alteration of reservoir and caprock formations and especially of the wells’ cement sheaths induced by the modification of chemical equilibria. Such studies are important for injectivity assurance, wellbore integrity, and risk assessment required for CO₂ sequestration site qualification. Within a R&D project funded by Eni, we set up a numerical model to investigate the rock–cement alterations driven by the injection of CO₂ into a depleted sweet natural gas pool. The simulations are performed with the TOUGHREACT simulator (Xu et al. in Comput Geosci 32:145–165, 2006) coupled to the TMGAS EOS module (Battistelli and Marcolini in Int J Greenh Gas Control 3:481–493, 2009) developed for the TOUGH2 family of reservoir simulators (Pruess et al. in TOUGH2 User’s Guide, Version 2.0, 1999). On the basis of field data, the system is considered in isothermal (50°C) and isobaric (128.5 bar) conditions. The effects of the evolving reservoir gas composition are taken into account before, during, and after CO₂ injection. Fully water-saturated conditions were assumed for the cement sheath and caprock domains. The gas phase does not flow by advection from the reservoir into the interacting domains so that molecular diffusion in the aqueous phase is the most important process controlling the mass transport occurring in the system under study.     

Effects of CO<Subscript>2</Subscript> Compressibility on CO<Subscript>2</Subscript> Storage in Deep Saline Aquifers

The injection of supercritical CO₂ in deep saline aquifers leads to the formation of a CO₂ plume that tends to float above the formation brine. As pressure builds up, CO₂ properties, i.e. density and viscosity, can vary significantly. Current analytical solutions do not account for CO₂ compressibility. In this article, we investigate numerically and analytically the effect of this variability on the position of the interface between the CO₂-rich phase and the formation brine. We introduce a correction to account for CO₂ compressibility (density variations) and viscosity variations in current analytical solutions. We find that the error in the interface position caused by neglecting CO₂ compressibility is relatively small when viscous forces dominate. However, it can become significant when gravity forces dominate, which is likely to occur at late times of injection.     

Influence of Permeability Heterogeneity on Miscible CO<Subscript>2</Subscript> Flooding Efficiency in Sandstone Reservoirs: An Experimental Investigation

In this study, we systematically investigate the effect of core-scale heterogeneity on the performance of miscible CO₂ flooding under various injection modes (secondary and tertiary). Manufactured heterogeneous core plugs are used to simulate vertical and horizontal heterogeneity that may be present in a reservoir. A sample with vertical heterogeneity (i.e. a layered sample) is constructed using two axially cut half plugs each with a distinctly different permeability value. In these samples, the permeability ratio (PR) defines the ratio between the permeabilities of adjacent half plugs. Horizontal heterogeneity (i.e. a composite sample) is introduced by stacking two or three short cylindrical core segments each with a different permeability value. Our special sample construction techniques have also enabled us to investigate the effect of permeability ratio and crossflow in layered samples and axial arrangement of core segments in composite samples on the ultimate recovery of the floods. Core flooding experiments are conducted with an n-Decane–brine–CO₂ system at a pore pressure of 17.2 MPa and a temperature of 343 K. At this temperature, the minimum miscibility pressure of CO₂ with n-Decane is 12.6–12.7 MPa so it is expected that at 17.2 MPa CO₂ is fully miscible with n-Decane. The results obtained for both the composite and layered samples indicate that CO₂ injection would achieve the highest recovery factor (RF) when performed under the secondary mode (e.g. layered: 79.00%, composite: 89.83%) compared with the tertiary mode (e.g. layered: 73.2%, composite: 86.2%). This may be attributed to the effect of water shielding which impedes the access of the injected CO₂ to the residual oil under the tertiary injection mode. It is also found that the oil recovery from a layered sample decreases noticeably with an increase in the PR as higher PR makes the displacement more uneven due to CO₂ channelling. The RFs of 93.4, 87.89, 77.9 and 69.8% correspond to PRs of 1, 2.5, 5, and 12.5, respectively. In addition, for the layered samples, crossflow was found to have an important role during the recovery process; however, due to excessive channelling, this effect tends to diminish as PR increases. Compared with the layered heterogeneity, the effect of composite heterogeneity on the RF seems to be very subtle as the RF is found to be almost independent from the permeability sequence along the length of a composite sample. This outcome may have been caused by the small diameter of the plugs resulting in invariable 1-D floods.     

Pore Scale Modeling of Reactive Transport Involved in Geologic CO<Subscript>2</Subscript> Sequestration

We apply a multi-component reactive transport lattice Boltzmann model developed in previous studies for modeling the injection of a CO₂-saturated brine into various porous media structures at temperatures T = 25 and 80°C. In the various cases considered the porous medium consists initially of calcite with varying grain size and shape. A chemical system consisting of Na⁺, Ca²⁺, Mg²⁺, H⁺, CO₂^°(aq){{\rm CO}_2^{\circ}{\rm (aq)}}, and Cl⁻ is considered. Flow and transport by advection and diffusion of aqueous species, combined with homogeneous reactions occurring in the bulk fluid, as well as the dissolution of calcite and precipitation of dolomite are simulated at the pore scale. The effects of the structure of the porous media on reactive transport are investigated. The results are compared with a continuum-scale model and the discrepancies between the pore- and continuum-scale models are discussed. This study sheds some light on the fundamental physics occurring at the pore scale for reactive transport involved in geologic CO₂ sequestration.     

Nonequilibrium molecular radiation behind the front of a strong shock wave in the CO<Subscript>2</Subscript>-N<Subscript>2</Subscript>-O<Subscript>2</Subscript> mixture

Models of population of some radiating electron-vibrational states of CO, CN, and C₂ molecules are developed. The characteristics of radiation in a chemically nonequilibrium flow behind the front of a strong shock wave in a mixture of gases constituting the Martian atmosphere are calculated. The numerical data are compared with experimental results.Translated from Prikladnaya Mekhanika i Tekhnicheskaya Fizika, Vol. 46, No. 2, pp. 13–22, March–April, 2005     

Injection and Storage of CO<Subscript>2</Subscript> in Deep Saline Aquifers: Analytical Solution for CO<Subscript>2</Subscript> Plume Evolution During Injection

Injection of fluids into deep saline aquifers is practiced in several industrial activities, and is being considered as part of a possible mitigation strategy to reduce anthropogenic emissions of carbon dioxide into the atmosphere. Injection of CO₂ into deep saline aquifers involves CO₂ as a supercritical fluid that is less dense and less viscous than the resident formation water. These fluid properties lead to gravity override and possible viscous fingering. With relatively mild assumptions regarding fluid properties and displacement patterns, an analytical solution may be derived to describe the space–time evolution of the CO₂ plume. The solution uses arguments of energy minimization, and reduces to a simple radial form of the Buckley–Leverett solution for conditions of viscous domination. In order to test the applicability of the analytical solution to the CO₂ injection problem, we consider a wide range of subsurface conditions, characteristic of sedimentary basins around the world, that are expected to apply to possible CO₂ injection scenarios. For comparison, we run numerical simulations with an industry standard simulator, and show that the new analytical solution matches a full numerical solution for the entire range of CO₂ injection scenarios considered. The analytical solution provides a tool to estimate practical quantities associated with CO₂ injection, including maximum spatial extent of a plume and the shape of the overriding less-dense CO₂ front.     

In-Situ Capillary Trapping of CO<Subscript>2</Subscript> by Co-Injection

Co-injection of water with CO₂ is an effective scheme to control initial gas saturation in porous media. A fractional flow rate of water of approximately 5–10% is sufficient to reduce initial gas saturations. After water injection following the co-injection, most of the gas injected in the porous media is trapped by capillarity with a low fractional volume of migrating gas. In this study, we first derive an analytical model to predict the gas saturation levels for co-injection with water. The initial gas saturation is controlled by the fractional flow ratio in the co-injection process. Next, we experimentally investigate the effect of initial gas saturation on residual gas saturation at capillary trapping by co-injecting gas and water followed by pure water injection, using a water and nitrogen system at room temperature. Depending on relative permeability, initial gas saturation is reduced by co-injection of water. If the initial saturation in the Berea sandstone core is controlled at 20–40%, most of the gas is trapped by capillarity, and less than 20% of the gas with respect to the injected gas volume is migrated by water injection. In the packed bed of Toyoura standard sand, the initial gas saturation is approximately 20% for a wide range of gas with a fractional flow rate from 0.50 to 0.95. The residual gas saturation for these conditions is approximately 15%. Less than approximately 25% of the gas migrates by water injection. The amount of water required for co-injection systems is estimated on the basis of the analytical model and experimental results.     

Enhanced CO<Subscript>2</Subscript> Storage and Sequestration in Deep Saline Aquifers by Nanoparticles: Commingled Disposal of Depleted Uranium and CO<Subscript>2</Subscript>

Geological storage of anthropogenic CO₂ emissions in deep saline aquifers has recently received tremendous attention in the scientific literature. Injected buoyant CO₂ accumulates at the top part of the aquifer under a sealing cap rock. Potential buoyant movement of CO₂ has caused some concern that the high-pressure CO₂ could breach the seal rock. However, CO₂ will diffuse into the brine underneath and generate a slightly denser fluid that may induce instability and convective mixing. Onset times of instability and convective mixing performance depend on the physical properties of the rock and fluids, such as permeability and density contrast. We present the novel idea of adding nanoparticles (NPs) to injected CO₂ to increase density contrast between the CO₂-rich brine and the underlying resident brine and, consequently, decrease onset time of instability and increase convective mixing. The analyses show that 0.001 volume fraction of NPs added to the CO₂ stream shortens onset time of mixing by approximately 80% and increases convective mixing by 50%. If it thus originally takes 5 years for the overlying CO₂ to start convective mixing, by adding NPs, onset time of mixing reduces to 1 year, and after initiation of convective mixing, mixing improves by 50%. A reduction of the CO₂ leakage risk ensues. In addition to other metallic NPs, use of processed depleted uranium oxide (DU) as the NPs is also proposed. DU-NPs are potentially stable and might be safely commingled with CO₂ to store in saline aquifers.     

Numerical Simulations of the Thermal Impact of Supercritical CO<Subscript>2</Subscript> Injection on Chemical Reactivity in a Carbonate Saline Reservoir

Geological sequestration of CO₂ offers a promising solution for reducing net emissions of greenhouse gases into the atmosphere. This emerging technology must make it possible to inject CO₂ into deep saline aquifers or oil- and gas-depleted reservoirs in the supercritical state (P > 7.4MPa and T > 31.1°C) to achieve a higher density and therefore occupy less volume underground. Previous experimental and numerical simulations have demonstrated that massive CO₂ injection in saline reservoirs causes a major disequilibrium of the physical and geochemical characteristics of the host aquifer. The near-well injection zone seems to constitute an underground hydrogeological system particularly impacted by supercritical CO₂ injection and the most sensitive area, where chemical phenomena (e.g. mineral dissolution/precipitation) can have a major impact on the porosity and permeability. Furthermore, these phenomena are highly sensitive to temperature. This study, based on numerical multi-phase simulations, investigates thermal effects during CO₂ injection into a deep carbonate formation. Different thermal processes and their influence on the chemical and mineral reactivity of the saline reservoir are discussed. This study underlines both the minor effects of intrinsic thermal and thermodynamic processes on mineral reactivity in carbonate aquifers, and the influence of anthropic thermal processes (e.g. injection temperature) on the carbonates’ behaviour.     

Sensitivity Study of Simulation Parameters Controlling CO<Subscript>2</Subscript> Trapping Mechanisms in Saline Formations

The primary purpose of this study is to understand quantitative characteristics of mobile, residual, and dissolved CO₂ trapping mechanisms within ranges of systematic variations in different geologic and hydrologic parameters. For this purpose, we conducted an extensive suite of numerical simulations to evaluate the sensitivities included in these parameters. We generated two-dimensional numerical models representing subsurface porous media with various permutations of vertical and horizontal permeability (k _v and k _h), porosity (f{\phi}), maximum residual CO₂ saturation (S_gr^max{S_{\rm gr}^{\max}}), and brine density (ρ _br). Simulation results indicate that residual CO₂ trapping increases proportionally to k_v, k_h, S_gr^max{k_{\rm v}, k_{\rm h}, S_{\rm gr}^{\max}} and ρ _br but is inversely proportional to f.{\phi.} In addition, the amount of dissolution-trapped CO₂ increases with k _v and k _h, but does not vary with f{\phi } , and decreases with S_gr^max{S_{\rm gr}^{\max}} and ρ _br. Additionally, the distance of buoyancy-driven CO₂ migration increases proportionally to k _v and ρ _br only and is inversely proportional to k_h, f{k_{\rm h}, \phi } , and S_gr^max{S_{\rm gr}^{\max}} . These complex behaviors occur because the chosen sensitivity parameters perturb the distances of vertical and horizontal CO₂ plume migration, pore volume size, and fraction of trapped CO₂ in both pores and formation fluids. Finally, in an effort to characterize complex relationships among residual CO₂ trapping and buoyancy-driven CO₂ migration, we quantified three characteristic zones. Zone I, expressing the variations of S_gr^max{S_{\rm gr}^{\max}} and k _h, represents the optimized conditions for geologic CO₂ sequestration. Zone II, showing the variation of f{\phi} , would be preferred for secure CO₂ sequestration since CO₂ has less potential to escape from the target formation. In zone III, both residual CO₂ trapping and buoyancy-driven migration distance increase with k _v and ρ _br.     

Thermodynamic Conditions of Formation of CO<Subscript>2</Subscript> Hydrate in Carbon Dioxide Injection into a Methane Hydrate Reservoir

The mechanism of replacement of methane by carbon dioxide in the hydrate in the process of CO₂ injection into a reservoir with formation of fronts of methane hydrate dissociation and carbon dioxide hydrate generation is investigated. It is found that such a replacement regime can be implemented in both low- and high-permeability reservoirs. It is shown that in the highintensity injection regime the heat flux from the well does not affect propagation of the fronts of methane hydrate dissociation and carbon dioxide hydrate generation. In this case the replacement regime is maintained by only the heat released at formation of carbon dioxide hydrate. An increase in the injection pressure may lead to suppression of methane hydrate dissociation and termination of the replacement reaction. The critical diagrams of existence of the regime of conversion of methane hydrate to carbon dioxide hydrate are constructed.     

Investigation of hydrodynamic instability of CO<Subscript>2</Subscript> injection into an aquifer

The two-dimensional problem of supercritical carbon dioxide injection into an aquifer is solved. Shocks and rarefaction waves propagating in a sequence from an injection well into the formation are described within the framework of a complete nonisothermal model of flows in a porous medium. In the approximation of isothermal immiscible water and carbon dioxide flow the hydrodynamic stability of the leading displacement front is investigated for various reservoir pressures and temperatures. The parameters of unstable fronts are determined using a sufficient instability condition formulated in analytic form. The approximate analytic results are supported by the direct numerical simulation of CO₂ injection using the complete model in which thermal effects and phase transitions are taken into account.     

Quantification of Density-Driven Natural Convection for Dissolution Mechanism in CO<Subscript>2</Subscript> Sequestration

Dissolution of CO₂ into brine causes the density of the mixture to increase. The density gradient induces natural convection in the liquid phase, which is a favorable process of practical interest for CO₂ storage. Correct estimation of the dissolution rate is important because the time scale for dissolution corresponds to the time scale over which free phase CO₂ has a chance to leak out. However, for this estimation, the challenging simulation on the basis of convection–diffusion equation must be done. In this study, pseudo-diffusion coefficient is introduced which accounts for the rate of mass transferring by both convection and diffusion mechanisms. Experimental tests in fluid continuum and porous media were performed to measure the real rate of dissolution of CO₂ into water during the time. The pseudo diffusion coefficient of CO₂ into water was evaluated by the theory of pressure decay and this coefficient is used as a key parameter to quantify the natural convection and its effect on mass transfer of CO₂. For each experiment, fraction of ultimate dissolution is calculated from measured pressure data and the results are compared with predicted values from analytical solution. Measured CO₂ mass transfer rate from experiments are in reasonable agreement with values calculated from diffusion equation performed on the basis of pseudo-diffusion coefficient. It is suggested that solving diffusion equation with pseudo diffusion coefficient herein could be used as a simple and rapid tool to calculate the rate of mass transfer of CO₂ in CCS projects.     

Analysis on heat transfer correlations of supercritical CO<Subscript>2</Subscript> cooled in horizontal circular tubes

The objective of the present study is to analyze the heat transfer correlations of supercritical CO₂ cooled in horizontal circular tubes. In the paper, heat transfer correlations are first reviewed and compared with the experimental data at different heat fluxes. The results show that most of the previous correlations agree well with the experimental data under lower heat flux, but fail to predict the heat transfer coefficient well when the heat flux is as high as 33 kW/m². The study of buoyancy effect on convective heat transfer shows that buoyancy effect significantly affects the heat transfer with the increase of heat flux, and both free and forced convections operate in the turbulence flow during supercritical CO₂ cooling process. The influencing factors on heat transfer coefficient are summarized and the new correlation can be developed with the four dimensionless numbers.     

Modeling Gas Transport in the Shallow Subsurface During the ZERT CO<Subscript>2</Subscript> Release Test

We used the multiphase and multicomponent TOUGH2/EOS7CA model to carry out predictive simulations of CO₂ injection into the shallow subsurface of an agricultural field in Bozeman, Montana. The purpose of the simulations was to inform the choice of CO₂ injection rate and design of monitoring and detection activities for a CO₂ release experiment. The release experiment configuration consists of a long horizontal well (70 m) installed at a depth of approximately 2.5 m into which CO₂ is injected to mimic leakage from a geologic carbon sequestration site through a linear feature such as a fault. We estimated the permeability of the soil and cobble layers present at the site by manual inversion of measurements of soil CO₂ flux from a vertical-well CO₂ release. Based on these estimated permeability values, predictive simulations for the horizontal well showed that CO₂ injection just below the water table creates an effective gas-flow pathway through the saturated zone up to the unsaturated zone. Once in the unsaturated zone, CO₂ spreads out laterally within the cobble layer, where liquid saturation is relatively low. CO₂ also migrates upward into the soil layer through the capillary barrier and seeps out at the ground surface. The simulations predicted a breakthrough time of approximately two days for the 100kg d⁻¹ injection rate, which also produced a flux within the range desired for testing detection and monitoring approaches. The seepage area produced by the model was approximately five meters wide above the horizontal well, compatible with the detection and monitoring methods tested. For a given flow rate, gas-phase diffusion of CO₂ tends to dominate over advection near the ground surface, where the CO₂ concentration gradient is large, while advection dominates deeper in the system.     

Pressure Buildup During CO<Subscript>2</Subscript> Injection into a Closed Brine Aquifer

CO₂ injected into porous formations is accommodated by reduction in the volume of the formation fluid and enlargement of the pore space, through compression of the formation fluids and rock material, respectively. A critical issue is how the resulting pressure buildup will affect the mechanical integrity of the host formation and caprock. Building on an existing approximate solution for formations of infinite radial extent, this article presents an explicit approximate solution for estimating pressure buildup due to injection of CO₂ into closed brine aquifers of finite radial extent. The analysis is also applicable for injection into a formation containing multiple wells, in which each well acts as if it were in a quasi-circular closed region. The approximate solution is validated by comparison with vertically averaged results obtained using TOUGH2 with ECO2N (where many of the simplifying assumptions are relaxed), and is shown to be very accurate over wide ranges of the relevant parameter space. The resulting equations for the pressure distribution are explicit, and can be easily implemented within spreadsheet software for estimating CO₂ injection capacity.     

CO<Subscript>2</Subscript> injection into saline carbonate aquifer formations I: laboratory investigation

Although there are a number of mathematical modeling studies for carbon dioxide (CO₂) injection into aquifer formations, 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 analyze permeability and porosity changes as well as to characterize relevant chemical reactions associated with injection and storage of CO₂ in carbonate formations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. Highly heterogeneous cores drilled from a carbonate aquifer formation located in South East Turkey were used during the experiments. Porosity changes along the core plugs and the corresponding permeability changes are reported for different CO₂ injection rates and different salt concentrations of formation water. It was observed that either a permeability increase 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 thermodynamic conditions. As the salt concentration decreases, porosity and the permeability decreases are less pronounced. Calcite deposition is mainly influenced by orientation, with horizontal flow resulting in larger calcite deposition compared to vertical flow.     

Matched Boundary Extrapolation Solutions for CO<Subscript>2</Subscript> Well-Injection into a Saline Aquifer

The injection of supercritical CO₂ through wells into deep brine reservoirs is a topic of interest for geologic carbon sequestration. The injected CO₂ is predominantly immiscible with the brine and its low density relative to brine leads to strong buoyancy effects. The displacement of brine by CO₂ in general is a multidimensional, complex nonlinear problem that requires numerical methods to solve. The approximations of vertical equilibrium and complete gravity segregation (sharp interface) have been introduced to reduce the complexity and dimensionality of the problem. Furthermore, for the radial displacement process considered here, the problem can be formulated in terms of a similarity variable that reduces spatial and temporal dependencies to a single variable. However, the resulting ordinary differential equation is still nonlinear and exact solutions are not available. The existing analytical solutions are approximations limited to certain parameter ranges that become inaccurate over a large portion of the parameter space. Here, I use a matched boundary extrapolation method to provide much greater accuracy for analytical/semi-analytical approximations over the full parameter range.