Explore the vast range of titles available.

Rate transient analysis (RTA) is a practical and cost‐effective method for CO2 injection data analysis and storage capacity evaluation of saline aquifers. However, the nonlinear behavior introduced by two‐phase CO2–brine flow, coupled with pressure‐dependent fluid and rock properties, significantly limits the applicability of conventional production‐based RTA models, which typically assume single‐phase flow and rely solely on pressure propagation. To overcome these limitations, this study presents a novel two‐phase RTA method that, for the first time, explicitly incorporates both pressure evolution and CO2 front migration, while accounting for the nonlinearities associated with brine displacement and pressure‐sensitive reservoir behavior. First, a two‐phase flow model is developed for CO2 injection in saline aquifers, and an analytical solution is derived by introducing new definitions of pseudo‐pressure and pseudo‐time that capture the effects of both multiphase flow and pressure‐dependent properties. By introducing distinct definitions of the radius of investigation (ROI) for the pressure front and the CO2 front, average pressure and saturation are evaluated based on their respective controlling regions and incorporated into the estimation of pseudotime. Second, a two‐step RTA approach is proposed to analyze CO2 injection data, including flow regime identification using a two‐phase diagnostic plot and subsurface properties estimation using a specialty plot. Finally, we provide a workflow that integrates formation properties evaluation with storage capacity prediction under the more realistic conditions of variable injection. The proposed method is validated using synthetic data from numerical simulations and a field example from the Illinois Basin Decatur Project (IBDP). The close estimation of CO2 storage capacity, reservoir pore‐volume, and permeability confirm the accuracy of the proposed model and demonstrate the method's reliability compared with numerical simulations for rapid assessment of storage potential and analytical RTA methods for considering the specific nonlinearities. With the proposed approach, the scattered CO2 injection pressure and rate data are, for the first time, transformed into clear straight‐line behaviors with unique slope, revealing the underlying two‐phase flow characteristics during CO2 injection up to the injection limit.

Cyclic solvent injection, known as solvent huff-n-puff, is one of the promising techniques for enhancing oil recovery from shale reservoirs. This study investigates the huff-n-puff performance in ultratight shale reservoirs by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, and black oil) and different injection gases (CO2, C2H6, and C3H8). A dual-porosity compositional model is utilized to comprehensively evaluate the impact of multicomponent diffusion, adsorption, and hysteresis on the production performance of each reservoir fluid and the retention capacity of the injection gases. The results show that the huff-n-puff process improves oil recovery by 4–6% when injected with 10% PV of gas. Huff-n-puff efficiency increases with decreasing gas-oil ratio (GOR). C2H6 provides the highest recovery for the black oil and volatile oil systems, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and adsorption are essential mechanisms to be considered when modeling gas injection in shale reservoirs. However, the relative permeability hysteresis effect is not significant. Diffusion impact increases with GOR, while adsorption impact decreases with increasing GOR. Oil density reduction caused by diffusion is observed more during the soaking period considering that the diffusion of the injected gas caused a low prediction error, while adsorption for the injected gas showed a noticeable error.

Performance of a polymer flood process requires the knowledge of rheological behavior of the polymer solution and reservoir properties such as rock wettability. To provide a better understanding of effects of polymer chemistry and wettability on the performance of a polymer flood process, a comprehensive experimental study was conducted using a two-dimensional glass micromodel. A series of water and polymer flood processes were carried out at different polymer molecular weights, degrees of polymer hydrolysis, and polymer concentrations in both water-wet and oil-wet systems. Image processing technique was applied to analyze and compare microscopic and macroscopic displacement behaviors of polymer solution in each experiment. From micro-scale observations, the configuration of connate water film, polymer solution trapping, flow of continuous and discontinuous strings of polymer solution, piston-type displacement of oil, snap-off of polymer solution, distorted flow of polymer solution, emulsion formation, and microscopic pore-to-pore sweep of oil phase were observed and analyzed in the strongly oil-wet and water-wet media. Rheological experiments showed that a higher polymer molecular weight, degree of hydrolysis, and concentration result in a higher apparent viscosity for polymer solution and lower oil–polymer viscosity ratio. It is also shown that these parameters have different impacts on the oil recovery in different wettabilities. Moreover, a water-wet medium generally had higher recovery in contrast with an oil-wet medium. This experimental study illustrates the successful application of glass micromodel techniques for studying enhanced oil recovery (EOR) processes in five-spot pattern and provides a useful reference for understanding the displacement behaviors in a typical polymer flood process.

Natural convection induced by carbon dioxide (CO2) dissolution from a gas cap into the resident formation brine of a deep saline aquifer in the presence of a capillary transition zone is an important phenomenon that can accelerate the dissolution process, reducing the risk of CO2 leakage to the shallower formations. Majority of past investigations on the instability of the diffusive boundary layer assumed a sharp CO2–brine interface with constant CO2 concentration at the top of the aquifer, i.e., single-phase system. However, this assumption may lead to erroneous estimates of the onset of natural convection. The present study demonstrates the significant effect of the capillary transition zone on the onset of natural convection in a two-phase system in which a buoyant CO2 plume overlaid a water-saturated porous layer. Using the quasi-steady-state approximation (QSSA), we performed a linear stability analysis to assess critical times, critical wavenumbers, and neutral stability curves as a function of Bond number. We show that the capillary transition zone could potentially accelerate the evolution of the natural convection by sixfold. Furthermore, we characterized the instability problem for capillary-dominant, in-transition, and buoyancy-dominant systems. In the capillary-dominant systems, capillary transition zone has a strong role in destabilizing the diffusive boundary layer. In contrast, in the buoyancy-dominant systems, the buoyancy force is the sole cause of the instability, and the effect of the capillary transition zone can be ignored. Our findings provide further insight into the understanding of the natural convection in the two-phase CO2–brine system and the long-term fate of the injected CO2 in deep saline aquifers.

This study presents a buoyancy-driven stability analysis in a three-dimensional inclined porous medium with a capillary transition zone that is formed between a non-wetting and an underlying wetting phase. In this two-phase, two-component, partially miscible system, a solute from a non-wetting phase diffuses into a porous layer saturated with a wetting-phase fluid, creating a dense diffusive boundary layer beneath an established capillary transition zone. Transient concentration and gravity-driven velocity fields are derived for the wetting phase while the saturation field remains fixed. Linear stability analysis with the quasi-steady-state approximation is employed to determine the onset of solutal convective instability for buoyancy-dominant, in-transition and capillary-dominant systems. The analysis of the problem leads to a differential eigenvalue problem composed of a system of three complex-valued equations that are numerically solved to determine the critical times, critical wavenumbers and neutral stability curves as a function of inclination angle for different Bond numbers. The layer inclination is shown to play an essential role in the stability of the problem, where the gravity-driven flow removes solute concentrations in the diffusive boundary layer. The results indicate that the horizontal porous layer exhibits the fastest onset of instability, and longitudinal rolls are always more unstable than oblique and transverse rolls. The inclination angle has a more substantial impact on stabilizing the diffusive boundary layer in the buoyancy-dominant than in the capillary-dominant systems. Furthermore, for both buoyancy-dominant and capillary-dominant systems, the critical times and wavenumbers vary exponentially with inclination angle ≤ 60° and follow the Stirling model.

High-pressure fluid transport in nanoporous media such as shale formations requires further understanding because conventional continuum approaches become inadequate due to their ultralow permeability and complexity of transport mechanisms. We propose a species-based approach for modelling two partially miscible, multicomponent fluids in nanoporous media – one that does not rely on conventional bulk fluid transport frameworks but on species movement. We develop a numerical model for species transport of partially miscible, non-ideal fluid mixtures using the chemical potential gradient as the driving force. The model considers the binary friction concept to include the friction between fluid molecules as well as between fluid molecules and pore walls, and incorporates the key multicomponent transport mechanisms – Knudsen, viscous and molecular diffusion. Under single-phase conditions, the system under consideration is quantified by introducing multicomponent Sherwood number (Sh), Péclet number (Pe) and fluid–solid friction modulus (φ). Despite the complexity of fluid transport in nanopores, the steady-state single-phase transport results reveal the contribution of diffusion in nanopores, where all parameters collapse on a set of master curves for the multicomponent Sh with a dependence on multicomponent Pe and φ. Unsteady state, two-phase transport modelling of the codiffusion process shows that light and intermediate alkanes are produced much higher than heavy alkanes when the vapour phase appears. We demonstrate that the pressure gradient is also crucial in promoting CO2 and alkane mixing during counterdiffusion processes. These results stress the need for a paradigm shift from classical bulk flow modelling to species-based transport modelling in nanoporous media.

This paper presents a simple method to estimate ultimate recovery factors (URF) of ultratight reservoirs based on equilibrium by diffusion in which URF is only a function of changes in hydrocarbon density between initial and final states. URF is defined at infinite time and therefore does not depend on the transient behavior. Although URF may not be achievable during the life-cycle of the field development and production, it provides valuable insights on the role of phase behavior. We show that equilibrium phase behavior defines the absolute upper-bound for URF during primary production and explains the poor recovery from shale oil reservoirs compared to the high recovery factor in shale gas reservoirs in a unifying way. Further, we quantify how injected solvent compositions (CH 4 , CO 2 , N 2 , and C 2 H 6 ) during huff’n’puff enhanced oil recovery (EOR) improve recovery based on density reduction and compositional dilution, and show that the largest percentage increase in recovery occurs for heavier oils. Our calculations provide a practical means to define the URF from primary production as a function of reservoir fluid composition, temperature, and pressure drawdown. In addition, our calculations articulate incremental URF (IURF) of solvent huff‘n’puff based on net solvent transfer into ultratight rock, which is a key design consideration. The results illustrate that solvent transfer dilutes the hydrocarbons in place, thus maximizing long-term hydrocarbon recovery. Net mass transfer can be improved by enhancing the diffusion of solvent into the matrix based on the huff‘n’puff design parameters including solvent composition, drawdown pressure, and the net amount of solvent injected based on optimal frequency and cycle duration.

This study presents some theoretical results on the effects of capillary transition zone and aquifer background flow on the mass transfer of carbon dioxide (CO2) from a stationary plume of CO2 into formation brine and also provides a perspective on the progress in modeling and experimental observations of physical aspects of CO2 dissolution in deep saline aquifers. One of the main focuses of this study is to mathematically analyze the behavior of CO2 convective dissolution in the absence and presence of a capillary transition zone and to investigate its impact on the onset of natural convection and subsequent convective mixing. Through performing a linear stability analysis, suitable criteria are developed that predict the onset of convection and initial wavelength of the instabilities as a function of system parameters. The instability problem is characterized by capillary-dominant and buoyancy-dominant regimes with a transition in between. It is shown that capillarity plays a strong role in destabilizing the diffusive boundary layer in the capillary-dominant regime, while it is negligible in the buoyancy-dominant regime. Using direct numerical simulations, key features of the two-phase convective mixing are described and several global quantities, such as the total CO2 dissolution, Sherwood number, swelling factor, and interface velocity are measured. The significant effect of the capillary transition zone on the dissolution of CO2 under a buoyant plume in saline aquifers is explained; and, the link between the capillary transition zone and the volume change, due to CO2 dissolution and the interface velocity over the mixing process, is demonstrated. Another focus of this study is to develop mathematical models that capture the evolution of the CO2 dissolution in aquifers subject to background flows in the absence and presence of natural convection. Using the semi-analytical solution and direct numerical simulations, detailed behavior of background flow on the dissolution and transport of CO2 during its geostorage in saline aquifers, which include the processes of diffusion, advection, and free convection. The findings of this study provide further insight into the understanding of solubility trapping physical features and the long-term fate of the injected CO2 in deep saline aquifers.