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.     

Study on heat transfer and pressure drop characteristics of internal heat exchangers in CO<Subscript>2</Subscript> system under cooling condition

In order to study the heat transfer and pressure drop on four types of internal heat exchangers (IHXs) of a CO₂ system, the experiment and numerical analysis were performed under a cooling condition. The configuration of the IHXs was a coaxial type and a micro-channel type. Two loops on the gas cooler part and the evaporator part were made, for experiment. And the section-by-section method and Hardy-Cross method were used for the numerical analysis. The capacity and pressure drop of the IHX are larger at the micro-channel type than at the coaxial type. When increasing the mass flow rate and the IHX length the capacity and pressure drop increase. The pressure drop of the evaporator loop is much larger than that of the gas cooler loop. The performance of the IHX was affected with operating condition of the gas-cooler and evaporator. The deviations between the experimental result and the numerical result are about ±20% for the micro-channel type and ±10% for the coaxial type. Thus, the new CO₂ heat transfer correlation should be developed to precisely predict a CO₂ heat transfer.     

Numerical study of conjugate heat transfer in rectangular microchannel heat sink with Al<Subscript>2</Subscript>O<Subscript>3</Subscript>/H<Subscript>2</Subscript>O nanofluid

In the present paper, conjugate heat transfer approach has been used to numerically study laminar forced convective heat transfer characteristics of Al₂O₃/H₂O nanofluid flowing in a silicon microchannel heat sink (MCHS) of rectangular cross-section using thermal dispersion model. Results are presented in terms of thermal resistance that characterizes MCHS performance. It is observed that use of nanofluid improves MCHS performance by reducing fin (conductive) thermal resistance.     

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.     

Experimental and numerical investigation on heat transfer characteristics of supercritical R1234ze(E) cooled in horizontal tubes

The heat transfer characteristics of supercritical fluids in tubes have been considered indispensable for the design and optimization of the heat exchanger and the energy conversion system. Specifically the cooling heat transfer of supercritical R1234ze(E) in horizontal tubes is a promising heat-power conversion technology; however, there is a scarcity of conducted research in available literature. The present work, the first-ever study in this direction, aims to thoroughly investigate the heat transfer characteristics of supercritical R1234ze(E) which is cooled in horizontal tubes. Experimental work was performed to thoroughly explore and inspect the heat transfer characteristics of supercritical R1234ze(E) passing through the tube of 4.12 mm diameter at 4–5 MPa pressure and 240–400 kg/m² s mass flux. Furthermore, the simulation study, supporting the experimental investigation under the same conditions of pressure and mass flux, extended the range of tube diameter up to 9.44 mm. The effects of pressure, mass flux and tube diameter on the heat transfer coefficient were carefully analyzed in the present research work. Based on the simulation results and experimental results, heat transfer correlations were newly developed by separating the region above and below the pseudo-critical temperature. The average absolute deviation between the calculated Nusselt numbers by the numerical correlation and the simulation results was found 2.87%; the average absolute deviation between the calculated Nusselt numbers by the experimental correlation and the experimental results was found 5.3%.     

CFD studies on natural convection heat transfer of Al<Subscript>2</Subscript>O<Subscript>3</Subscript>-water nanofluids

This work is focused on numerical simulations of natural convection heat transfer in Al₂O₃-water nanofluids using computational fluid dynamics approach. Fluent v6.3 is used to simulate water based nanofluid considering it as a single phase. Thermo-physical properties of the nanofluids are considered in terms of volume fraction and size of nanoparticles, size of base fluid molecule and temperature. The numerical values of effective thermal conductivity have also been compared with the experimental values available in the literature. The numerical result simulated shows decrease in heat transfer with increase in particle volume fraction. Computed result shows similar trend in increase of Nusselt number with Relayigh number as depicted by experimental results. Streamlines and temperature profiles are plotted to demonstrate the effect.     

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.     

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     

STREAMLINE-BASED MATHEMATICAL MODEL FOR CO2 MISCIBLE FLOODING

According to the research theory of improved black oil simulator, a practical mathematical model for C02 miscible flooding was presented. In the model, the miscible process simulation was realized by adjusting oil/gas relative permeability and effective viscosity under the condition of miscible flow. In order to predict the production performance fast, streamline method is employed to solve this model as an alternative to traditional finite difference methods. Based on streamline distribution of steady-state flow through porous media with complex boundary confirmed with the boundary element method (BEM), an explicit total variation diminishing (TVD) method is used to solve the one-dimensional flow problem. At the same time, influences of development scheme, solvent slug size, and injection periods on CO2 drive recovery are discussed. The model has the advantages of less information need, fast calculation, and adaptation to calculate CO2 drive performance of all kinds of patterns in a random shaped porous media with assembly boundary. It can be an effective tool for early stage screening andmiscible oil field.reservoir dynamic management of the CO2 miscible oil field.     

Impact of CO<Subscript>2</Subscript> Injection on Flow Behavior of Coalbed Methane Reservoirs

On the basis of observations at four enhanced coalbed methane (ECBM)/CO₂ sequestration pilots, a laboratory-scale study was conducted to understand the flow behavior of coal in a methane/CO₂ environment. Sorption-induced volumetric strain was first measured by flooding fresh coal samples with adsorptive gases (methane and CO₂). In order to replicate the CO₂–ECBM process, CO₂ was then injected into a methane-saturated core to measure the incremental “swelling.” As a separate effort, the permeability of a coal core, held under triaxial stress, was measured using methane. This was followed by CO₂ flooding to replace the methane. In order to best replicate the conditions in situ, the core was held under uniaxial strain, that is, no horizontal strain was permitted during CO₂ flooding. Instead, the horizontal stress was adjusted to ensure zero strain. The results showed that the relative strain ratio for CO₂/methane was between 2 and 3.5. The measured volumetric strains were also fitted using a Langmuir-type model, thus enabling calculation of the strain at any gas pressure and using the analytical permeability models. For permeability work, effort was made to increase the horizontal stress to achieve the desired zero horizontal strain condition expected under in situ condition, but this became impossible because the “excess” stress required to maintain this condition was very large, resulting in sample failure. Finally, when CO₂ was introduced and horizontal strain was permitted, permeability reduction was an order of magnitude greater, suggesting that the “excess” stress would have reduced it significantly further. The positive finding of the work was that the “excess” stresses associated with injection of CO₂ are large. The excess stresses generated might be sufficient to cause microfracturing and increased permeability, and improved injectivity. Also, there might be a weakening effect resulting from repeated CO₂ injection, as has been found to be the case with thermal cycling of rocks.     

Effect of Vertical Heterogeneity on Long-Term Migration of CO<Subscript>2</Subscript> in Saline Formations

For deep injection of CO₂ in thick saline formations, the movements of both the free gas phase and dissolved CO₂ are sensitive to variations in vertical permeability. A simple model for vertical heterogeneity was studied, consisting of a random distribution of horizontal impermeable barriers with a given overall volume fraction and distribution of lengths. Analytical results were obtained for the distribution of values for the permeability, and compared to numerical simulations of deep CO₂ injection and convection in heterogeneous formations, using multiple realizations for the permeability distribution. It is shown that for a formation of thickness H, the breakthrough times in two dimensions for deep injection scale as H ² for moderate injection rates. In comparison to heterogeneous shale distributions, a homogeneous medium with equivalent effective vertical permeability has a longer breakthrough time for deep injection, and a longer onset time for convection.     

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.     

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.     

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.     

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.     

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.