Solubility trapping of carbon dioxide (CO 2 ) in deep saline aquifers is considered one of the most effective methods for carbon sequestration. Dissolution of CO 2 into the brine may create gravitational instabilities that lead to the onset of convection, which greatly enhances the storage efficiency and reduces the possibilities of leakage. Convection appears in the form of downward traveling fingers of relatively dense, CO 2 ‐dissolved fluid. Many natural aquifer formations display considerable permeability anisotropy, where the horizontal permeability k h may be several times greater than the vertical permeability k z . It has been previously found that increasing k h for a fixed k z reduces the critical time t c at which onset occurs and the critical wavelength λ c with which the fingers initially form. We extend earlier work by showing how and why this occurs. Our results reveal new insights about λ c . We have studied the behavior for times greater than t c using high‐resolution numerical simulations. We show that the enhanced dissolution from convection can become significant much earlier in anisotropic media. Furthermore, the effects of anisotropy may be sustained for a long period of time. Our results suggest that permeability anisotropy can allow a wider range of aquifer formations to be considered for effective sequestration.
Abstract CO2 injection has been used to improve oil recovery for the past three decades. In recent years, the improved recovery method has become more attractive because of the dual effect; injection in the subsurface allows: 1) reduction of CO2 concentration in the atmosphere to reduce global warming, and 2) improved oil recovery. Some of the projects considered for CO2 injection are based on CO2 miscibility with oil at the minimum miscibility pressure (MMP). The MMP is often measured in a slim tube. The slim tube data are used for the purpose of field evaluation and for the tuning of the equations of state. The slim tube represents one-D horizontal flow. In this work, we will show that CO2 MMP, often measured in a slim tube, may not have relevance to CO2 injection in a 2D (or 3D) reservoir. When CO2 dissolves in the oil, the density often increases. The increase in density changes the flow path form one-D to two-D (downward flow). On the other hand, when a gas phase evolves from mixing of CO2 and the oil, the gas phase is often lighter than CO2 and the oil. In downdeep injection for the some of the cases when CO2 is heavier than the oil (in the conditions of some offshore high pressure field) the evolved gas phase moves upward due to buoyancy. As a result of these two density effects the compositional path in a reservoir is radically different from the flow path in a slim tube. The change in flow path may prevent miscibility development. The flow path is also altered from heterogeneity and from diffusion. In this work, we present results from simulation in slim tube and in a two-D vertical reservoir and show significant effect of gravity and heterogeneity. One main conclusion from this work is that for successful CO2 injection projects there is need to have accurate density data for CO2/oil mixture with different CO2 compositions.
Abstract Numerical modeling of asphaltene precipitation in petroleum reservoirs is important in relation to precipitation around the wellbore and in the reservoir domain. Production from some reservoirs results in asphaltene precipitation in the wellbore region, leading to production loss and need for cleanup. Fluid injection can also lead to injectivity loss due to asphaltene precipitation. There are also desirable processes in which precipitation of asphaltene can lead to "in-situ" upgrading of heavy oil recovery. Reservoir compositional models that are currently in use rely on cubic equations of state for asphaltene precipitation. The cubic equations, despite their relative reliability in describing reservoir fluids phase behavior, become unreliable in asphaltene-rich phase description. A number of non-cubic equations of state have been introduced to overcome the shortcomings of cubic equations. The cubic-plus-association equation of state (CPA-EOS) is perhaps the method of choice in modeling asphaltene precipitation in compositional modeling. When there is no asphaltene precipitation, the CPA-EOS becomes the standard cubic equation. In this work we implement the CPA-EOS in compositional modeling and introduce a simple technique to speed up considerably the root finding. Our efficient algorithm makes the additional cost from CPA-EOS insignificant. We also derive the basic equations for the total compressibility and total potential molar volume in our implementation of the CPA-EOS compositional modeling. Our new algorithm is introduced in a simple finite difference code. This work introduces a general framework for widespread use of the CPA-EOS in compositional modeling.
ABSTRACT Published imbibition experiments of an advancing fracture water level surrounding a single matrix block are simulated using a fine grid single porosity model and various double porosity models. The fine grid simulations show that a stationary water saturation profile quickly develops and advances in the matrix at the same rate as the fracture water level. A new double porosity transfer function for imbibition dominated matrix/fracture fluid exchange is presented based on stationary profile solutions of the fractional flow equation. This transfer function models the imbibition recovery for these advancing water level experiments better than the conventional double porosity imbibition formulations. It is shown that the stationary profile transfer function is best suited to systems where the time to develop the stationary profile is short relative to the length of the waterflood. The experimental data was also simulated using a diffusion equation with a nonlinear diffusion coefficient in combination with a moving boundary condition as the imbibition model. A constant diffusion coefficient based upon water relative permeability and capillary pressure gradient values at 1 − Sor matched the experimental results as well as the nonlinear diffusion coefficient, but required much less computer time. From analyzing two different diffusion type equations as imbibition models, we show that countercurrent imbibition is not a likely recovery mechanism for this type of advancing water level imbibition experiment.
Injection of sea water is the most common practice to displace oil in porous media in subsurface formations. In numerous studies, conventional surfactants at concentrations in a range of one weight percent have been proposed to be added to the injected water to improve oil recovery. Surfactants accumulate at the oil-water interface and may reduce the interfacial tension by three orders of magnitude or more, resulting in higher oil recovery. Recently, we have proposed the addition of ultralow concentration of a non-ionic surfactant to the injected water to increase interface viscoelasticity as a new process. The increase in interface viscoelasticity increases oil recovery from porous media. This alternative approach requires only a concentration of 100 ppm (two orders less than the conventional improved oil recovery) and therefore is potentially a much more efficient process. In this work, we present a comprehensive report of the process in an intermediate-wet carbonate rock. There is very little adsorption of the functional molecules to the rock surface. Because the critical micelle concentration is low (around 30 ppm), most of the molecules move to the fluid-fluid interface to form molecular structures, which give rise to an increase in interface elasticity. We also demonstrate that interface elasticity has a non-monotonic behavior with the salt concentration of injected brine, and an optimum salinity exists for maximum oil recovery.
Abstract In Part I of our study, stability analysis testing in the reduced space was formulated and its robustness and efficiency in comparison to the conventional approach was explored. In this paper, we present formulations including: 1) direct solution of the non-linear equations, and 2) minimization of Gibbs free energy for two-phase flash computations in the reduced space. We use various algorithms including the successive substitution (SS), Newton's method, globally-convergent modifications of Newton's method (line searches and trust region), and the dominant eigenvalue method (DEM) for direct solution of the non-linear equations defining two-phase flash and the minimization of Gibbs free energy. We also suggest a criterion based on the tangent-plane-distance (TPD) for the initialization from the equilibrium ratios. The proposed criterion has a significant effect on reducing the number of iterations. The results from various algorithms reveal that the direct solution of the non-linear equations in the reduced space combined with the use of the TPD criterion for initialization in the combined SS and Newton's method can make flash computations extremely efficient. The efficiency and robustness of flash computations in the critical region are especially remarkable.
Summary Wax precipitation for gas condensate fluids was studied in detail with a thermodynamic model. It was found that the precipitated wax phase can exhibit retrograde phenomena similar to that in gas condensates. As a result of pressure decrease (at a constant temperature), the amount of precipitated wax may first increase, then decrease, then increase again. The effect of pressure on wax precipitation from gas condensates was also studied. Pressure often shows an opposite effect in wax precipitation to that in liquids; however, the pressure effect is not universal. The model used in this work accounts for both the Poynting correction term and the solid-state phase transitions. Incorporation of these effects reconfirms the suitability of the multisolid phase for wax-precipitation calculations (both the onset and the amount).
'/%3e%3cuse xlink:href='%23a' transform='rotate(23.036 .093 25.536)'/%3e%3cuse xlink:href='%23a' transform='rotate(45.87 1.273 16.18)'/%3e%3cuse xlink:href='%23a' transform='rotate(69.945 .996 12.078)'/%3e%3cuse xlink:href='%23a' transform='rotate(20.66 -19.689 31.932)'/%3e%3c/svg%3e)