Fluid Flow In Fractures Research Articles

Pore-scale insight into the effect of porous walls on fluid flow in rough-walled fractures

This study investigates the influence of porous walls on fluid flow behavior in single rough-walled fractures. A series of direct numerical simulations (DNS) were conducted to examine fluid flow through rough-walled fractures surrounded by porous walls under various hydraulic gradients. The simulation results clearly demonstrate the progressively significant impact of porous walls on flow characteristics as porosity increases. Regression analyses indicate that the Forchheimer's law, which characterizes the nonlinear flow of rock fractures, remains valid in the presence of porous walls. Moreover, increased porosity enhances fluid exchange and leads to an increased ability for single fractures to transmit fluid. Two double-parameter equations were established to quantitatively characterize the effects of porous walls on hydraulic conductivity of the fracture and fluid exchange between porous walls and the fracture. Further analysis revealed that the angle between the fracture profile and main flow direction profoundly influences the inflow/outflow exchange between the fracture and its adjacent porous walls. Moreover, the pore-scale results indicate that it is unreasonable to equate the effect of porous walls with slip boundaries as suggested in previous studies. The results and findings of this study deepen our understanding of flow behavior at the interface between the rough-walled fracture and adjacent porous walls, and they serve as a basis for accurately simulating large-scale fracture networks that consider the hydraulic contribution of fracture walls.

A new theoretical model for the nonlinear flow in a rough rock fracture under shear

Shear deformations significantly affect the nonlinearity of fluid flow in rock fractures. To estimate this nonlinear flow using the Izbash equation, it is necessary to determine the Izbash coefficients. However, their parametric expressions are rarely mentioned, particularly when the shear-flow process is involved. This study proposed an improved Izbash equation-based model by incorporating the Darcy–Weisbach equation, along with a friction factor. The proposed model considers two asymptotic cases. At low Re regime, the fluid flow regime is dominated by the viscous effect, and the proposed model can be approximated to the cubic law. When Re reaches a certain threshold (Res), the fluid flow transitions into a fully turbulent flow regime where the inertia force dominates the fluid behaviours. Consequently, the proposed model is equivalent to the quadratic term of the Forchheimer equation. The proposed model is verified with the experimental results conducted on 5 rough fracture surfaces with normal stress from 0.5 to 3 MPa. Good correlations between the experimental and analytical curves illustrated that the proposed model of strong theoretical foundation yielded good prediction signified by the Normalised Objective Function (NOF) and an average error (σ¯ave) within 0.18 and 15 %, respectively.

Numerical Simulation of Turbulent Fluid Flow in Rough Rock Fracture: 2D Case

We investigate both laminar and turbulent flow regimes in a rough-walled rock fracture via numerical CFD simulations. While previous studies were limited to either fully viscous Darcy or inertial Forchheimer laminar flow regimes, we chose to cover the widest possible Reynolds number range of 0.1–10^6. We introduce CFD simulation of a turbulent flow for rough-walled fractures, implementing RANS approach to turbulence modeling. We focus on 2D fracture geometries and implement changes in both shear displacement and wall roughness, systematically examining their effect on fracture permeability and friction factor in a manner similar to the fundamental studies of the flow in rough-walled pipes. For a curvilinear fracture, laminar flow becomes non-stationary between Re , {sim } , 10^2–10^3, earlier for larger shear displacement and wall roughness. Laminar–turbulent transition starting at Re_{textrm{cr}} , {sim } , 2300 may lead to a sharp drop in permeability depending on the fracture geometry; this gap vanishes for larger shear displacement and wall roughness. Depending on the fracture geometry, bottlenecks closing with shear become a major negative factor for the overall permeability.

Coupled fluid flow, solute transport and dissolution processes in discrete fracture networks: An advanced Discontinuous Galerkin model

Modeling dissolution processes in discrete fracture networks (DFNs) is a challenging task. Challenges are related to the highly nonlinear coupling between flow, mass transport, and reactive processes associated with fracture aperture evolution by dissolution. Further, advection-dominated transport due to fast fluid flow in fractures renders the problem more complex from a computational point of view, as traditional numerical methods may introduce unphysical oscillations or excessive numerical diffusion. The Discontinuous Galerkin (DG) method is known to be suitable for the simulation of advection-dominated transport. In this work, an advanced DG model is developed to model transport with dissolution in DFNs. We propose an upwind formulation to deal with the upstream concentration at the intersection of several fractures. The upstream concentration at an intersection node is calculated based on the average nodal concentrations of all the fractures having an inflow at that node, weighted by the volumetric fluxes of these fractures. The dispersion term is discretized with the Mixed Finite Element (MFE) method, which ensures the continuity of the dispersive flux at the intersection of fractures with different apertures. The obtained nonlinear coupled flow-transport-dissolution equations are discretized in time with a high-order scheme via the method of lines (MOL). Numerical examples and comparisons with standard finite element (FE) and finite volume (FV) solutions are performed to investigate the correctness and efficiency of the developed model. Results show that the new DG-DFN model avoids unphysical oscillations encountered with the standard FE method and strongly reduces the numerical diffusion observed with the upwind FV scheme. The DG-DFN model is then used to investigate the effect of the dissolution rate on the flow, transport, and aperture evolution processes for a single fracture and for a DFN. A quasi-linear evolution of the fracture aperture is observed for low dissolution rates. For high dissolution rates, a funnel-shaped enlargement is observed with a significant widening for the fractures near the inlet and minor effects for those away from the injection location.

Study on Fracture Surface Damage and Fluid Flow Characteristics of Hot Dry Rock with Different Failure Modes under Repeated Thermal Shock

Study on Fracture Surface Damage and Fluid Flow Characteristics of Hot Dry Rock with Different Failure Modes under Repeated Thermal Shock

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

With the increasing global demand for oil and gas, the development of unconventional resources such as shale gas is becoming ever more important. The key to developing unconventional oil and gas resources lies in horizontal wells with multistage fracturing technology. In the process of horizontal well segmentation fracturing, the distribution of the proppant among multiple clusters has a significant influence on the fracturing effect. However, the influence of various factors on the entry of proppant into the perforation and then into the fracture along the wellbore is unclear. In this paper, based on the flow characteristics of proppants in fracturing fluids, we investigate the wellbore–perforation proppant transport using a Eulerian multiphase flow model. The effect of different factors on proppant entry into the perforation in horizontal wells is studied. We first verify that the computational fluid dynamics model satisfies the accuracy requirements for studying the sand-carrying efficiency of proppants in a perforation cluster. Second, the effects of the proppant size, proppant density, fracturing fluid viscosity, perforation diameter, and fracturing fluid flow rate on the proppant transport efficiency are investigated. Finally, a mathematical model of the sand-carrying efficiency is established by multivariate nonlinear fitting. The results show that the proppant size has a more significant effect on proppant settling at low wellbore flow rates. Increasing the diameter of the proppant particles can accelerate proppant settling. Higher wellbore flow rates tend to reduce the sand-carrying efficiency, although using a low-density proppant can mitigate the effect of the wellbore flow rate. At low wellbore flow rates, increasing the perforation size makes it easier for the proppant to enter bottom perforations. Increasing the fluid viscosity helps to distribute the proppant evenly between perforations in different directions, but this effect diminishes as the flow rate increases. Finally, a formula for the wellbore sand-carrying efficiency is obtained and validated, providing a basis for optimizing the distribution of the proppant in the perforation. The results from this paper enhance our understanding of the sand and fluid feeding patterns of each perforation cluster and provide direction for improving the construction process and enhancing the fracture inflow capacity.

An XFEM-based hydro-mechanical model to consider the non-Darcy flow in complex fracture networks

Geotechnical instability and failure are closely related to the hydro-mechanical coupled behavior of fractured rocks, and the existing studies often regard the fracture seepage as linear Darcy flow. Due to the neglect of non-Darcy effect caused by rough rock wall and high flow velocity, the estimated rock deformation and seepage flow can lead to incorrect assessment of geotechnical risks. Hence, this study proposed an efficient and robust hydro-mechanical (HM) coupled model to consider non-Darcy flow in complex fracture networks. The fractured rock mass's mechanical response, including the fracture surface's frictional contact, was calculated using the XFEM solver, and the widely used Forchheimer's law was adopted to describe the non-Darcy flow along the fractures. The fracture segments cut by mechanical element edges are considered one-dimensional flow elements, and the Newton-Raphson iteration method is adopted to solve the Forchheimer equation directly. To consider the influence of fracture deformation on the conductivity of fractures, the Barton-Bandis model was adopted to determine the hydraulic aperture of the fractures when the fracture was closed. Subsequently, a staggering Newton-Raphson method can be developed to decouple the fracture deformation and fluid flow process. Experimental results were adopted to validate the accuracy of the numerical model, and several numerical cases were used to illustrate the efficiency and robustness of the proposed model. The effects of inlet pressure, confining stress, and non-Darcy effect on the HM-coupled behavior of fractured rock were investigated. Numerical results suggested that the distribution of fluid pressure and failure process of rock mass based on Darcy assumption could be dramatically changed after considering the nonlinear seepage behavior.

Effect of fracture geometry, topology and connectivity on energy recovery from enhanced geothermal systems

A combination of hydraulic fracturing and horizontal wells is now being used to tap geothermal energy from naturally fractured reservoirs. Fully grid-based numerical models are currently used to simulate heat recovery from enhanced geothermal systems (EGS). Such models require a fine unstructured mesh and are computationally expensive. In this paper we present a computationally efficient model that allows us to accurately simulate fracture propagation, fluid flow, and heat transfer in networks of natural fractures that may be created in naturally fractured geothermal reservoirs.The integrated simulator is developed by combining the displacement discontinuity method (DDM) for fracture propagation in naturally fractured reservoirs with a general Green's function solution for fluid and heat flow from the matrix to the fracture. This eliminates the need to discretize the matrix domain resulting in a very computationally efficient solution. A discrete fracture network (DFN) approach is used to represent the pre-existing natural fractures.The model is first validated against an analytical solution for fluid flow and heat transfer in a rock matrix with a single fracture. The computation time with and without discretizing the rock matrix shows a 100-fold reduction in computation cost with very little loss in accuracy. Parametric studies are conducted to investigate the effect of the distribution of natural fracture density, length, and orientation. The results show that the efficiency of tapping geothermal energy is impacted by geometrical and topological complexities of the fracture network and in particular the connectivity of backbone fractures. It is, therefore, important to optimize (not maximize) the connectivity and complexity of the backbone fracture network. The computationally efficient model presented here provides a practical tool for optimizing operational parameters for efficient geothermal production.

Numerical simulation of multi-fracture propagation in staged multi-cluster SC-CO2 fracturing of horizontal wells

Numerical simulation research on fracture propagation in SC-CO2 (supercritical carbon dioxide) fracturing mainly focuses on a single fracture, and the multifracture propagation law of SC-CO2 fracturing under the influence of multiple factors is ambiguous. In this study, based on the boundary element method, a three-dimensional, plane propagation model of multicluster SC-CO2 fracturing in multifractured horizontal wells, which considers the three-dimensional, elastic deformation of the reservoir rock mass, the two-dimensional flow of SC-CO2 fracturing fluid in fractures, the change in SC-CO2 physical parameters during fracturing and the flow distribution of each cluster fracture, is established. The influence of geological factors and construction factors on the propagation law of SC-CO2 fracturing in multifractured horizontal wells is explored. The results show that compared with slick water fracturing, the hole friction of SC-CO2 fracturing effectively balances the negative effect of induced stress between two fractures, inhibits the liquid entry advantage of heel-end fractures, and increases the reconstruction area in the reservoir. SC-CO2 fracturing in multifractured horizontal wells minimizes the energy loss of the fracture tip in different ways with different reservoir stress differences. Increasing the displacement and crack spacing are conducive to promoting the uniform expansion of SC-CO2 multicrack propagation. Based on the liquid volume distribution index, the construction parameters are optimized. The construction displacement of SC-CO2 multicluster fracturing should be greater than 10 m3 min−1, the hole diameter should be less than 14 mm, and the number of boreholes in each perforation cluster should be less than 16.

Hybrid numerical methods for modelling multi-physics mass transport in coal

It is a challenging task to predict and analyse the transient flow physics in unconventional complex geological formations such as coal seams. This is due to the multi-scale multi-physics nature of processes taking place in coal seam gas reservoirs. Therefore, numerical tools allowing the incorporation of various flow physics inherent to coal into the simulation routine are of particular importance. At the pore-scale, the rock images obtained by micro-computed tomography are frequently used for flow modelling in porous or fractured media by direct numerical simulations (Lattice Boltzman method or by solving Navier Stokes equations) or by utilising so-called pore-network modelling. Both methods have advantages and drawbacks, while their hybridisation may allow us avoid some of the major pitfalls. Due to a limited number of research dedicated to image-based pore-scale modelling in coal, we develop a hybrid numerical model that combines the Hagen-Poiseuille analytical solution and the volume of fluid advection scheme for fluid flow in fractures with the continuum Darcy flow in the coal matrix. The explicit coupling of fluid flow across the fracture-matrix domains is implemented via corresponding source terms in the governing equations. Besides, additional physics including sorption and matrix swelling-shrinkage phenomena are introduced into the numerical model. The hybrid solver is validated against analytical solutions and a previously developed Darcy-Brinkman-Stokes framework, which has similar functionality for modelling fluid flow in coal seams. To validate the developed model and show its capability to capture multi-scale multi-physics flow in coal, several illustrative simulations are conducted using synthetic and realistic digital images of coal. As a result, the accuracy of the hybrid solver was within 4% when compared to the Darcy-Brinkman-Stokes framework for flow simulation on realistic geometry. Besides, the non-parallelised hybrid model outperformed the parallelised direct numerical simulation, being more than 90 times faster in terms of computational time. The findings are beneficial for conducting larger core-scale simulations of multi-scale multi-physics flow in coal seams with potential applications to natural gas production, hydrogen storage, and carbon dioxide geosequestration.

The variations and mechanisms of coal wettability affected by fracturing fluids with different concentrations of Ca2+ during fracturing

In low-porosity, low-permeability, and high-adsorption coalbed methane (CBM) reservoirs, the flow of fracturing fluid and methane gas is strongly affected by the wettability of coal. Ca2+ in mine water can affect the wettability of coal by changing the properties of the fracturing fluid, thus affecting the recovery efficiency of CBM. To investigate the mechanism of the wetting properties of bituminous coal by fracturing fluid with different concentrations of Ca2+, contact angle and T2 distribution curves were tested using an interfacial rheometer and low-field nuclear magnetic resonance (LF-NMR), and changes in water absorption and functional groups of coal soaked by fracturing fluid with different concentrations of Ca2+ were described using a precision electronic balance, X-ray photoelectron spectroscopy (XPS) and Fourier transform infrared spectroscopy (FTIR) to evaluate the wetting properties of coal. Molecular dynamics simulation was used to characterize the microscopic wetting properties of water molecules on the coal surface. Results show that when the concentration of Ca2+ is lower than 50 mg/L, the surface tension of the fracturing fluid gradually decreases, and the lowest value is 27.66 mN/m at 50 mg/L. The overall change in the contact angle and T2g value was lower than that of the control group (no Ca2+). The content of oxygen-containing functional groups on the surface of coal increased by 22.30%, and the content of C-O functional groups inside coal increased by 3.55%. The relative concentration and density of water molecules on the coal surface increase with increasing molecular diffusion ability. These results indicate that when the Ca2+ concentration is lower than 50 mg/L, the wettability of coal is enhanced, and thus, the fracturing fluid and methane gas flow capacity is improved. However, with increasing Ca2+ concentration, this phenomenon is reversed, and the water absorption of coal decreases, indicating that the wetting ability of coal decreases. The results of this study provide theoretical guidance that can be used to improve the recovery of CBM by fracturing and permeability enhancement measures, and preparing fracturing fluid in mine water to strengthen the protection of freshwater resources.

Numerical simulation of three-dimensional fracturing fracture propagation in radial wells

A fracture propagation model of radial well fracturing is established based on the finite element-meshless method. The model considers the coupling effect of fracturing fluid flow and rock matrix deformation. The fracture geometries of radial well fracturing are simulated, the induction effect of radial well on the fracture is quantitatively characterized, and the influences of azimuth, horizontal principle stress difference, and reservoir matrix permeability on the fracture geometries are revealed. The radial wells can induce the fractures to extend parallel to their axes when two radial wells in the same layer are fractured. When the radial wells are symmetrically distributed along the direction of the minimum horizontal principle stress with the azimuth greater than 15°, the extrusion effect reduces the fracture length of radial wells. When the radial wells are symmetrically distributed along the direction of the maximum horizontal principal stress, the extrusion increases the fracture length of the radial wells. The fracture geometries are controlled by the rectification of radial borehole, the extrusion between radial wells in the same layer, and the deflection of the maximum horizontal principal stress. When the radial wells are distributed along the minimum horizontal principal stress symmetrically, the fracture length induced by the radial well decreases with the increase of azimuth; in contrast, when the radial wells are distributed along the maximum horizontal principal stress symmetrically, the fracture length induced by the radial well first decreases and then increases with the increase of azimuth. The fracture length induced by the radial well decreases with the increase of horizontal principal stress difference. The increase of rock matrix permeability and pore pressure of the matrix around radial wells makes the inducing effect of the radial well on fractures increase.

Numerical simulation of proppant migration in horizontal wells with multi-fracture fracturing

For horizontal wells fracturing in unconventional reservoirs, the fracture morphology and proppant migration are severely affected by the interfering effects among multiple fractures propagation. Current numerical simulation for proppant migration did not reveal the interrelation among flow distribution, fracture length and sandbank shape during multiple fractures propagation. In this study, a proppant migration model is proposed by combining the displacement discontinuity method (DDM) and the Eulerian-Lagrangian method (E-L M), which implement dynamic multiple fractures propagation simulation as well as the changing state of flow distribution for each fracture. The accuracy of the numerical model is verified by laboratory experiments. The sensitivity parameters of proppant settlement are analyzed, and two dimensionless parameters, height ratio γ and area ratio η are proposed for proppant migration evaluation. The results show that with a lower fracturing fluid flow rate, fluid viscosity, the height ratio γ is lower, and the area ratio η is higher, which also results in the proppant being more likely to accumulate at the fracture entrance. As the proppant particle size increases from 100 μm to 500 μm, the dimensionless height ratio γ and the dimensionless area ratio η decrease significantly. Increase in fracture spacing during horizontal well multi-cluster fracturing results in a limited improvement for proppant settlement. Formation elastic modulus has an appreciable impact on proppant migration in multi-fracture propagation, high elastic modulus formation leads to an ununiform proppant placement over long distances.

A global inertial permeability for fluid flow in rock fractures: Criterion and significance

Fluid flow in rock fractures is described by Darcy's law and its nonlinear extension, the Forchheimer equation in form of a quadratic polynomial. Since the nonlinearity of the Forchheimer equation, determining its key coefficient of inertial permeability (i.e., the quadratic coefficient representing inertial losses) requires a series of flow tests under different hydraulic gradients. However, how to choose the volumetric flux range for deriving inertial permeability is never scrutinized. Here we report a seemly irrational dependency of inertial permeability on volumetric flux range by massive direct numerical simulations of fluid flow in rock fractures. This variation presents traceability and is closely related to the evolution of microscale eddies and macroscale flow regimes. A concept of global inertial permeability is thus proposed from this traceable variation, which can reproduce the whole flow regime in rock fractures. Two parametrized criterion models are subsequently established for calculating global inertial permeability using the lowest cost and ensuring its accuracy: one in terms of minimum Reynolds number for practical purposes, and the other in terms of minimum eddy volume ratio for mechanistic interpretation. Further discussions indicate that the proposed global inertial permeability is of great importance to non-Darcian flow prediction and flow regime assessment. Moreover, the parameterized criterion models in the form of power-law function for determining global inertial permeability, drawn from 2D fracture simulations, can apply to 3D fractures and large-scale fractured rock aquifers. The findings and results in this study are of great significance for accurately evaluating the hydraulic conductivity of rock fractures, especially at relatively high flow rates, and are useful for many geophysical and industrial applications.

Reconstruct lower‐dimensional crack paths from phase‐field point cloud

AbstractBecause of the smeared representation of phase‐field fracture, reconstructing lower‐dimensional crack paths is challenging, which may impede the further applications of the phase‐field method in the modeling of fault friction and fluid flow in fracture. In the present work, we propose to capture the crack curves or surfaces from two‐dimensional or three‐dimensional phase‐field point cloud using an optimized ridge regression algorithm, and k‐nearest neighbor and principal component analysis are used to estimate the normal direction of each segment on the identified discrete crack path. The sensitivity and computational efficiency of the proposed method are investigated thoroughly. Subsequently, this method is extended to reconstruct the complex discrete fracture networks. Finally, several benchmarks for fracture, fault friction and fluid flow problems are presented to demonstrate the strength of the proposed approach.

Stress Interferences between Fractures and Fracturing Stages of a Horizontal Well in a Sandy Conglomerate Reservoir in Junggar Basin, Northwest China

The sandy conglomerate reservoirs in the Mahu oilfield located in the Junggar Basin of Northwest China are featured by a significant horizontal stress difference between two directions, making formations easy to form double-wing fractures upon hydraulic fracturing instead of creating a complex fracture network. In addition, as the well spacing or interval cluster spacing decreases, the stress interferences between hydraulic fractures strengthen accordingly, leading to more difficulties in the prediction of fracture propagation patterns. Given the geological characteristics in the study area, an extended finite element method (XFEM) based hydraulic fracture model that can handle fracturing fluid flow distribution was proposed to evaluate the seepage, stress, and damage of the formation under hydraulic fracturing. The influences of the initial stress difference, cluster spacing, and fracturing stage sequence on the hydraulic fracture stress interference and the fracture propagation were investigated, producing discoveries that include: (1) as the fractures propagate, the stress difference between two fractures changes as well, and such change is also affected by the initial stress difference and the fracture distance; (2) the postfracturing stress difference first decreases but then increases with the increase in cluster spacing; (3) as the cluster spacing increases, the interfracture stress interference decreases. In addition, the outer fractures suppress the length of the middle fractures, thus limiting the stimulated reservoir area (SRA); (4) for the cases of creating multistage fractures, the later fracturing stage experiences both the interfracture and the interstage stress interferences from the prefracturing stage. As the fracture width changes with time, the nonplanar fracture feature of the later fracturing stage becomes more evident while the corresponding SRA decreases.

The effect of fluid flow in the longitudinal fracture along a borehole axis on Stoneley wave propagation

The characterization of fractures is essential to increase the production of hydrocarbon and geothermal resources. In this study, we investigate the effect of the fluid flow in the longitudinal fracture along a borehole on the dispersion and attenuation behavior of Stoneley waves using numerical experiments. In general, incorporating a fracture with the aperture of several tens to hundreds of micrometers into 3D seismic modeling is challenging with high calculational costs. We develop a novel numerical scheme that includes a 2D fluid flow simulation embedded into a 3D wave propagation modeling to address this problem. We devise an approach for capturing the effects of the fluid flow in the fractures of arbitrary aperture widths, which could be much thinner than the grid spacing of a 3D wave propagation simulation. A comparison of the numerical results from our scheme with the analytical solution indicates good agreement, supporting the method’s validity. This developed scheme is applied to the coupled simulation between the Stoneley wave propagation along the borehole axis and induced fluid flow inside a longitudinal fracture with different fracture apertures, fluid viscosity, and dynamic hydraulic conductivity. The modified matrix pencil algorithm applied to the recorded waveforms estimates the dispersion and attenuation of the Stoneley mode. The numerical results reveal the effect of the fracture aperture and fluid viscosity on the dispersion and attenuation behavior of the Stoneley waves. Based on the results, we demonstrate our scheme is an innovative method for estimating the aperture of the fracture and viscosity of the fluid by analyzing the dispersion and attenuation properties of the Stoneley waves.

Experimental evaluation of the flow resistance of CO2 foam fracturing fluids and simulation prediction for fracture propagation

Shale gas fracturing requires huge amounts of water, but most well pads are located mainly in hilly areas where water is scarce. Water supply issues have limited the industrialization of shale gas development. CO2 foam fracturing fluids can meet the requirements for large-scale hydraulic fracturing of shale gas and relieve pressure on water resources. Friction calculations of CO2 foam fracturing fluids in conduit flow are key to the reliability of overall fracturing procedures, affecting fracture targeting and reservoir stimulation effects. Through the analysis of the experimental data of carbon dioxide foam fracturing fluid flow under the simulated reservoir conditions, the influence of pressure, temperature, shear rate, foam quality and other factors on the friction characteristics of CO2 foam fracturing fluid was obtained, and the mathematical calculation model of the friction coefficient of CO2 foam fracturing fluid was established, and the pipe string friction and bottom hole pressure during the fracturing process were obtained, Thus, the shape and extension behavior of hydraulic fractures in the process of carbon dioxide foam fracturing in shale reservoir are simulated and predicted, which provides a theoretical basis for effective evaluation of fracturing effect.

A Study on Fracture Propagation Law of CO2 Composite Fracturing in Shale Reservoir

Background: In recent years, CO2 composite fracturing technology has been widely used in unconventional reservoirs. Compared to conventional hydraulic fracturing, CO2 fracturing can create complex fractures, replenish formation energy and reduce oil flow resistance. For shale oil reservoirs with natural fractures, CO2 composite fracturing can not only give full play to the advantages of complex fracture networks created by CO2 but also make use of water-based fracturing fluid to create long fractures with high conductivity. Methods: Based on fracture fluid flow, stress interference, natural fracture description, and CO2 phase change equation, a CO2 composite fracture propagation model was established in this paper to simulate the effects of fracturing fluid type, CO2 proportion, construction scale, natural fracture development, fracturing fluid injection rate and other factors on the propagation morphology of CO2 injection fracture network in shale oil reservoirs. Results: The results show that the water-based fracturing fluid is beneficial to the formation of long main fractures, but the overall complexity of the fracture network and the effective stimulated volume of the fracture network are significantly lower than that of CO2 fracturing. The application of the appropriate proportion of CO2 composite fracturing fluid can give full play to the comprehensive advantages of CO2 and water-based fracturing fluid and realize the full stimulation of the reservoir. CO2 fracturing in shale oil reservoirs with low principal stress difference and high natural fracture development extent can communicate natural fractures in a large range and form a complex fracture network. For shale oil reservoirs with natural fractures, a high fracturing fluid injection rate can significantly improve the complexity of the fracture network. Conclusion: The CO2 composite fracturing technology is applied to horizontal wells in X shale reservoir, and the production after fracturing is significantly higher than that of offset wells, which can be applied in the same type of reservoir and has broad application prospects.

The effect of fracturing on permeability in carbonate reservoir rocks

Hydrocarbon flow rates from tight carbonate reservoirs often depend on the distribution and properties of fractures throughout the reservoir interval. Hence, quantification of fracture parameters can contribute to understanding of reservoir characteristics and reservoir potential. In this paper, natural fractures in tight carbonate reservoir rocks of the Upper Cretaceous Shiranish Formation in the Taq Taq field (Kurdistan Region of North Iraq) were examined primarily using core samples, XRMI micro-resistivity image logs and conventional wireline logs, with additional dynamic data from well tests and mud logs. The Shiranish Formation is composed of a variety of limestones and argillaceous limestones with arithmetic mean matrix porosity and geometric mean permeability values of 1.64 ± 0.37% and 0.0223 ± 0.59 mD, respectively. However, fracturing has enhanced the permeability by up to four orders of magnitude above the maximum matrix permeability (1.79 ± 0.59 mD). Hydrocarbons are produced entirely from the fracture network in these rock types in the Taq Taq reservoir. Observed open and partially-open fractures have NE-SW orientations; these are classified as macro-fractures with average aperture of 0.17 ± 0.18 mm, arithmetic mean height of 11.70 ± 45.40 mm and arithmetic mean length of 26.7 ± 32.32 cm, where the uncertainties are standard deviations. Fracture aperture size and fracture height control fracture permeability and fluid flow. However, while fracture frequency has no effect on permeability, fracture distance distribution influences flow rates and hydrocarbon production. The dominant NE-SW trending fractures are more likely to remain open within the NE-SW oriented present day stress field at Taq Taq. Furthermore, the effect of overburden stress on the permeability and production rate was examined in laboratory tests on core plugs by increasing the confining stress during permeability measurements using constant flow rates. It was found that the magnitude of fracture permeability was reduced by 70% by applying 4000 psi of confining stress. In the reservoir, this effect would be exacerbated by reduced reservoir fluid pressures as a function of production. However, fractures with apertures greater than 0.10 mm are preserved as productive fractures even at high confining pressures and implying that hydraulic fracturing could open existing fractures significantly, enhancing production. This last observation implies that the use of hydraulic fracturing in tight carbonate reservoirs with natural fracturing is likely to be commercially viable.