Search Results (13)

The characteristics of CO₂ seepage in reservoirs have important research significance in the field of CCS technology application. However, the characteristics of macro-scale seepage are affected by the geometrical characteristics of micro-scale media, such as pore size and particle shape. Therefore, in this work, a series of numerical simulations were carried out using the phase field method to study the effect of pore structure simplification on micro-scale displacement process. The influences of capillary number, wettability, viscosity ratio, interfacial tension, and fracture development are discussed. The results show that the overall displacement patterns of the real pore model and the simplified particle model are almost similar, but the oil trapping mechanisms were totally different. There are differences in flow pattern, number of dominant flow channels, sensitivity to influencing factors and final recovery efficiency. The real pore model shows higher displacement efficiency. The decrease in oil wet strength of rock will change the CO₂ displacement mode from pointing to piston displacement. At the same time, the frequency of breakage will be reduced, thus improving the continuity of CO₂. When both pores and fractures are developed in the porous media, CO₂ preferentially diffuses along the fractures and has an obvious front and finger phenomenon. When CO₂ diffuses, it converges from the pore medium to the fracture and diverges from the fracture to the pore medium. The shape of fracture development in the dual medium will largely determine the CO₂ diffusion pattern. Full article

In recent years, fracturing-flooding technology has achieved a series of successful practices in the development of low-permeability oil reservoirs. However, research on the dynamic behavior of fracturing-flooding remains limited. In this paper, a dual medium model considering anisotropic characteristics is established for the target blocks. Multiple sets of conventional water injection transitions and multi-cycle fracturing-flooding operations are designed for simulation to explore the subsequent optimal operational schemes. Simulations are conducted on the optimal transitions between conventional water injection and multi-cycle fracturing-flooding schemes for different reservoir models with varying physical properties to study the dynamic behavior of fracturing-flooding in oil reservoirs with different properties. The results indicate that, for conventional water injection schemes, the optimal transition time for both the target well group and other reservoirs with different properties corresponds to a formation pressure coefficient between 1.2 and 1.3, with the optimal injection–production ratio being 1:1. From the perspective of water cut, the accumulated oil production of multi-cycle fracturing-flooding is higher than that of conventional water injection. The optimal multi-cycle fracturing-flooding schemes for both the target well group and other reservoirs with different properties are to start fracturing-flooding when the formation pressure coefficient is around 0.8 and to begin production when it reaches 1.4. Full article

Hydraulic measures such as hydraulic slotting and hydraulic fracturing are commonly used in coal seam pressure relief and permeability enhancement. Two-phase flow patterns of CH₄–water in pore-sized coal seams after hydraulic measures are critical to improve gas extraction efficiency. The phase field module in COMSOL Multiphysics™ 5.4 and the classical ordered porous media model were used in this paper. The characteristics of CH₄–water two-phase immiscible displacement in coal seams under different capillary numbers (Ca) and viscosity ratios (M) were simulated and quantitatively analyzed. By changing the contact angle of the porous media, the flow patterns of CH₄–water two-phase in coal with different wettability were simulated. Results show that wettability significantly affects the displacement efficiency of CH₄. Additionally, by constructing a dual-permeability model to simulate the varying local permeability of the coal, the flow patterns of different Ca and M in dual-permeability media were further investigated. It is found that CH₄ preferentially invades high-permeability regions, and the displacement efficiency in low-permeability regions increases with higher Ca and M, providing a reference for gas extraction from coal seams after hydraulic measures. Full article

The interpretation of the results of hydrogeological field observations and the modeling of fractured porous subsurface media is often conducted using dual-porosity and/or dual-permeability concepts. These concepts, however, do not consider the effects of spatial and temporal variations and uncertainties, or fuzziness, in the evaluation of the subsurface flow characteristics of fractured porous media. The goal of the paper is to introduce a concept of fuzzy dual permeability of fractured porous media based on the fuzzy system analysis of the results of ponded infiltration tests in fractured basalt. The author revisited the results of the tests conducted in areas close to the Idaho National Laboratory (INL), Idaho, USA: small-scale (approximately 0.5 m²) ponded tests at the Hell’s Half Acre site, mesoscale (56 m²) ponded tests at the Box Canyon site, and a large-scale infiltration test (31,416 m²) at the Radioactive Waste Management Complex at INL. Methods of fuzzy clustering and fuzzy regression were applied to describe the time-depth waterfront penetration and to characterize the phenomena of rapid flow through a predominantly fractured component and slow flow through a predominantly porous matrix component. The concept of fuzzy dual permeability is presented using a series of fuzzy membership functions of the waterfront propagation with depth and time. To describe the time variation of the flux, a fuzzy Horton’s model is presented. The developed concept can be used for the uncertainty quantification in flow and transport in geologic media. Full article

In 1923, Karl Terzaghi developed the theory of soil consolidation in which he introduced the concept of effective stress (ES). Over the past century, various theoretical aspects have been unraveled regarding the Effective Stress Principle (ESP) and the fluid–porous-medium interaction in deformable permeable media; nevertheless, some aspects have been debated for a long time, and some perplexities are still perceived among scientists and professionals. By way of example, in the study of flow in deformable permeable media, particularly in fractured porous systems, some problems are still open. This review is aimed at providing an overview of the progress achieved over the past century in the theoretical and experimental treatment of ESP—with particular reference to saturated porous media—and of the geomechanical aspects of fluid flow and fluid–rock interaction, trying to answer to some common questions among professionals, such as what is the correct expression for the ES to be used in applications and why there are various formulations? Additionally, we try to answer questions related to the modeling of fluid flow in fractured porous media. Therefore, this review paper is divided into two main sections, “Effective Stress Principle” and “Fluid Flow, Consolidation, and Fluid–Rock Interaction”. In the first section, the basic concepts and the theory underlying the ESP are preliminarily illustrated, with a simple but rigorous theoretical proof, and, subsequently, historical remarks are provided. The second illustrates the different adopted theoretical approaches to fluid flow, starting from Terzaghi’s theory of one-dimensional consolidation up to the recent dual- and multiple-porosity models. Full article

Based on the statistical self-similar fractal characteristics of the microstructure of porous media, the total flow rate and permeability of Newtonian fluids in the rough fracture network and rough matrix pores are derived, respectively. According to the connection structure between fractures and pores, the permeability analysis model of fluids in a matrix-embedded fracture network is established. The comparison between the predicted values of the model and the experimental data shows that the predicted values of the permeability of the rough fracture network and the rough matrix pores decrease with the increase in the relative roughness of the fractures and matrix pores, and are lower than the experimental data. Meanwhile, the predicted total flow rate of a rough fractured dual porous media is lower than that of a smooth fractal model and experimental data. In addition, it is also found that the larger the average inclination angle and the relative roughness of the fracture network, the smaller the permeability of the fractured dual porous media, and the relative roughness of the fracture network has a far greater influence on fluid permeability in the fractured dual porous media than the relative roughness of the matrix pores. Full article

When conducting numerical upscaling, either for a fractured or a porous medium, it is important to account for anisotropy because in general, the resulting upscaled conductivity is anisotropic. Measurements made at different scales also demonstrate the existence of anisotropy of hydraulic conductivity. At the “microscopic” scale, the anisotropy results from the preferential flatness of grains, presence of shale, or variation of grain size in successive laminations. At a larger scale, the anisotropy results from preferential orientation of highly conductive geological features (channels, fracture families) or alternations of high and low conductive features (stratification, bedding, crossbedding). Previous surveys of homogenization techniques demonstrate that a wide variety of approaches exists to define and calculate the equivalent conductivity tensor. Consequently, the resulting equivalent conductivities obtained by these different methods are not necessarily equal, and they do not have the same mathematical properties (some are symmetric, others are not, for example). We present an overview of different techniques allowing a quantitative evaluation of the anisotropic equivalent conductivity for heterogeneous porous media, via numerical simulations and, in some cases, analytical approaches. New approaches to equivalent permeability are proposed for heterogeneous media, as well as discontinuous (composite) media, and also some extensions to 2D fractured networks. One of the main focuses of the paper is to explore the relations between these various definitions and the resulting properties of the anisotropic equivalent conductivity, such as tensorial or non-tensorial behavior of the anisotropic conductivity; symmetry and positiveness of the conductivity tensor (or not); dual conductivity/resistivity tensors; continuity and robustness of equivalent conductivity with respect to domain geometry and boundary conditions. In this paper, we emphasize some of the implications of the different approaches for the resulting equivalent permeabilities. Full article

This study aims to develop and evaluate fracturing nanofluids from the laboratory to the field trial with the dual purpose of increasing heavy crude oil mobility and reducing formation damage caused by the remaining fracturing fluid (FF). Two fumed silica nanoparticles of different sizes, and alumina nanoparticles were modified on the surface through basic and acidic treatments. The nanoparticles were characterized by transmission electron microscopy, dynamic light scattering, zeta potential and total acidity. The rheological behavior of the linear gel and the heavy crude oil after adding different chemical nature nanoparticles were measured at two concentrations of 100 and 1000 mg/L. Also, the contact angle assessed the alteration of the rock wettability. The nanoparticle with better performance was the raw fumed silica of 7 nm at 1000 mg/L. These were employed to prepare a fracturing nanofluid from a commercial FF. Both fluids were evaluated through their rheological behavior as a function of time at high pressure following the API RP39 test, and spontaneous imbibition tests were carried out to assess the FF’s capacity to modify the wettability of the porous media. It was possible to conclude that the inclusion of 7 nm commercial silica nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation without altering the rheological properties of the system. Displacement tests were also performed on proppant and rock samples at reservoir conditions of overburden and pore pressures of 3200 and 1200 psi, respectively, while the temperature was set at 77 °C and the flow rate at 0.3 cm³/min. According to the effective oil permeability, a decrease of 31% in the damage was obtained. Based on these results, the fracturing nanofluid was selected and used in the first worldwide field application in a Colombian oil field with a basic sediment and water (BSW%) of 100 and without oil production. After two weeks of the hydraulic fracture operation, crude oil was produced. Finally, one year after this work, crude oil viscosity and BSW% kept showing reductions near 75% and 33%, respectively; and having passed two years, the cumulative incremental oil production is around 120,000 barrels. Full article

The existing productivity models of staged fractured horizontal wells in tight oil reservoir are mainly linear flow models based on the idealized dual-medium fracture network structure, which have a certain limitation when applied to the production prediction. Aiming at the difficulty in describing the shape of the complex fractal fracture network, a two-dimensional heterogeneous structure model of the fracture network is proposed in this paper. Considering the deformation characteristics of porous media and the characteristic of non-Darcy fluid flow, a three-zone steady-state productivity model with the combination of radial and linear flow is established. To eliminate strong nonlinear characteristics of the mathematical model, a fractional step method is employed to deduce the production formulas of staged fractured horizontal wells under infinite and finite conductivity fractures. The established productivity model is verified with the actual data of three horizontal wells in different blocks of S oilfield, and the error between the model calculation results and the actual production data is less than 4%. The analysis results of productivity sensitive factors show that production of horizontal wells is primarily influenced by the reservoir physical properties and fracturing parameters. The steady-state productivity model established in this study can be applied to effectively predict the average production of a horizontal well in stable stage of production, and it has theoretical and practical application value for improving the development effect of tight oil reservoir. Full article

Barite scalings are a common cause of permanent formation damage to deep geothermal reservoirs. Well injectivity can be impaired because the ooling of saline fluids reduces the solubility of barite, and the continuous re-injection of supersaturated fluids forces barite to precipitate in the host rock. Stimulated reservoirs in the Upper Rhine Graben often have multiple relevant flow paths in the porous matrix and fracture zones, sometimes spanning multiple stratigraphical units to achieve the economically necessary injectivity. While the influence of barite scaling on injectivity has been investigated for purely porous media, the role of fractures within reservoirs consisting of both fractured and porous sections is still not well understood. Here, we present hydro-chemical simulations of a dual-layer geothermal reservoir to study the long-term impact of barite scale formation on well injectivity. Our results show that, compared to purely porous reservoirs, fractured porous reservoirs have a significantly reduced scaling risk by up to $50\%$, depending on the flow rate ratio of fractures. Injectivity loss is doubled, however, if the amount of active fractures is increased by one order of magnitude, while the mean fracture aperture is decreased, provided the fractured aquifer dictates the injection rate. We conclude that fractured, and especially hydraulically stimulated, reservoirs are generally less affected by barite scaling and that large, but few, fractures are favourable. We present a scaling score for fractured-porous reservoirs, which is composed of easily derivable quantities such as the radial equilibrium length and precipitation potential. This score is suggested for use approximating the scaling potential and its impact on injectivity of a fractured-porous reservoir for geothermal exploitation. Full article

Carbon sequestration in deep saline aquifers was recently developed at the industrial scale. CO₂ injection experiences in carbonates are quite limited, most of them coming from projects carried out in porous mediums in the USA and Canada. Hontomín (Spain) is the actual on-shore injection pilot in Europe, being a naturally fractured carbonate reservoir where innovative CO₂ injection strategies are being performed within the ENOS Project. CO₂ migration through the fracture network existing on site produces hydrodynamic, mechanical and geochemical effectsdifferent from those caused by the injection in mediums with a high matrix permeability. The interpretation of these effects is required to design safe and efficient injection strategies in these formations. For this, it is necessary to determine the evolution of pressure, temperature and flow rate during the injection, as well as the period of pressure recovery during the fall-off phase. The first results from the not-continuous injections (8–24 h) conducted at Hontomín reveal the injection of liquid CO₂ (density value of 0.828 t/m³) and the fluid transmissivity through the fractures. Taking into account the evolution of the pressure and flow rate showed variations of up to 23% and 30% respectively, which means that the relevant changes of injectivity took place. The results were modeled with a compositional dual media model which accounts for both temperature effects and multiphase flow hysteresis because alternative brine and CO₂ injections were conducted. Advanced modeling shows the lateral extension of CO₂ and the temperature disturbance away from the well. Full article

Microscopic flow in fractured porous media is a typical problem for the exploitation of tight reservoirs. The rapid-flow in the fractured porous-media is of great significance to efficient and continuous oil/gas exploitation. The fractures are expected to enhance flow conductivity and mass transfer between matrix and fractures, and to improve oil displacement during water flooding. However, the fractures may also lead to water channeling under some conditions. The understanding on the mechanism of the microscopic flow in the fractured porous media has been insufficient until now. In this paper, a two-dimensional pore-fracture network model is presented to study the role of fractures in the flow. The effects of two main dimensionless parameters, fracture length to network length l_f/l and fracture density N_f/N, on the absolute permeability and the oil displacement efficiency are investigated. The results show that the flow in the matrix plays a controlling role at a low fracture density. Once the fracture density exceeds a certain value, the flow is controlled by fractures. With the increase of the fracture density, the oil displacement efficiency develops into three typical stages: when N_f/N < 0.1, the oil displacement efficiency increases rapidly; when 0.1 < N_f/N < 0.5, the oil displacement efficiency changes slowly; and when N_f/N > 0.5, the oil displacement efficiency decreases rapidly. In the case l_f/l > 0.8, the water mainly flows through a concentrated path connected by some fractures, resulting in it bypassing most oil regions, and thus the oil displacement efficiency decreases rapidly, similar to the water channeling. Full article

Reduced-order modeling approaches for gas flow in dual-porosity dual-permeability porous media are studied based on the proper orthogonal decomposition (POD) method combined with Galerkin projection. The typical modeling approach for non-porous-medium liquid flow problems is not appropriate for this compressible gas flow in a dual-continuum porous media. The reason is that non-zero mass transfer for the dual-continuum system can be generated artificially via the typical POD projection, violating the mass-conservation nature and causing the failure of the POD modeling. A new POD modeling approach is proposed considering the mass conservation of the whole matrix fracture system. Computation can be accelerated as much as 720 times with high precision (reconstruction errors as slow as 7.69 × 10⁻⁴%~3.87% for the matrix and 8.27 × 10⁻⁴%~2.84% for the fracture). Full article