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It is often highly difficult to predict the main flow path of reactive fluids in porous media with complexly distributed fractures and/or caves. Based on Darcy's law, this research defines the control domain of fractures/caves that represents the interference range of fractures/caves. This control domain can be used to identify the connectivity possibility between fractures/caves and predict the flow paths of reactive fluids at the optimal flow rate. Furthermore, after simplifying the geometry of fractures/caves, a threshold geometric aspect ratio of 20 is set to distinguish fractures and caves, concerning the flow mechanisms, by clarifying the ranges of control domains. Moreover, the control domain theory is combined with the two-scale continuum model for acidizing carbonate rocks to estimate the flow paths of acid in fractured-vuggy carbonate rocks at an optimal flow rate, thereby validating the accuracy of the reactive fluid main flow path estimation based on the control domain theory. The primary criterion to determine the reactive transport in porous media with complex fracture/cave distribution is the overlap degrees of control domains of adjacent isobaric bodies along their width and length directions, while the directions of isobaric bodies offer supplementary material. If the control domains of two isobaric bodies overlap with each other perpendicular to the flow direction, these isobaric bodies have higher odds of connected fluid flow. [ABSTRACT FROM AUTHOR]

A coupled approach of fluid flow and geomechanics is proposed in this study to quantitatively understand the hydraulic fracturing‐induced poroelastic effects that activate pre‐existing faults and trigger earthquake swarms near Crooked Lake, Alberta. The 3D poroelastic simulation of the seismogenic fault zone is then conducted to characterize the pressure diffusion and stress perturbation that led to fault activation. Results show that the poroelastic effects on the high‐permeable damage zones of a conductive‐barrier fault triggered the sequential activation of the seismogenic fault in the basement and Winterburn Formation. In addition, the high‐permeable damage zones act as conduits for pore pressure diffusion along the fault, whereas the fault core functions as a barrier to prevent crossing flow. The poroelastic effects in terms of pressure diffusion and stress perturbation in response to fluid injection facilitated the fault slip and hence triggered the Mw 3.6 earthquake in the basement formation 40 days after the fracturing operations. Moreover, the mainshock created negative Coulomb failure stress changes, inhibiting further fault slip in the basement formation. Subsequently, the stimulation of another well facilitated poroelastic effects on the fault damage zone in top Winterburn Formation, reactivating the same fault with an Mw 4.1 earthquake 8 days after the initiation of treatments. It is essential to optimize the injection site selection near the existing faults to reduce risks of the induced earthquakes near Crooked Lake. Key Points: Poroelastic effects on damage zones of a conductive‐barrier fault has led to fault reactivation in the basement and Winterburn FormationThe empirical net injection‐Mw relations are not adaptable in cases with direct HF‐fault hydrological connectionsThe location of injection sites is essential to mitigate risks of future induced earthquakes near existing faults [ABSTRACT FROM AUTHOR]

The mutual coupling effect between the fluid flow and the in situ stress fields cannot be ignored during the development of natural fractured reservoirs (NFRs), such as in the waterflooding process. In this study, a discrete fracture model is proposed to simulate the rock deformation and two-phase flow behaviors of oil and water in the NFR. The numerical solution of the model is achieved via the finite-element method and control-volume finite-element method. The numerical simulator is verified using commercial software, and a perfect agreement is obtained. Finally, sensitivity analysis is conducted on the key parameters in the model, such as fracture parameters, matrix permeability, and injection intensity. Results show that the fluid–solid coupling effect gradually weakens with production time. The degree of the fluid–solid coupling on cumulative oil production becomes smaller as the permeability of the matrix increases. Fracture connectivity controls the velocity and direction of the water flood front. Water injection intensity directly affects the natural fracture opening deformation and well productivity. The research and the numerical results obtained in this paper can provide theoretical guidance for the optimal design of water flooding operations in NFR. [ABSTRACT FROM AUTHOR]

In this study, a simulation model of fracture network geometry in fractured and porous elastic reservoirs is established based on the globally embedded three‐dimensional cohesive zone model (3D CZM). The effects of stress interference between natural fractures (NFs), horizontal stress difference (HSD), injection rate, and fluid viscosity on fracture geometry were studied and the phenomenon of rapid failure of unconventional reservoir productivity was explained from a coupling fluid flow/geomechanics perspective. The intersection behavior of hydraulic fracture (HF) and NF is simulated; the simulation results are in good agreement with Blanton's criterion, proving the reliability of the 3D CZM. The research results show that in the process of hydraulic fracturing, in addition to the strong stress interference between HFs, there is also strong stress interference between NFs. Stress interference has an important impact on the traction separation of cohesive elements (CEs) and a continuous dynamic impact on the NF opening. For reservoirs with a small HSD, higher injection rate and fluid viscosity produce smaller stimulated reservoir volume (SRV) length, but larger SRV width. Complex fracture networks tend to develop in the vicinity of horizontal wellbores, which leads to rapid failure of productivity. For this kind of reservoir, minimizing the impact of stress interference with a small injection rate is recommended instead of maximizing the injection rate and fluid viscosity. For reservoirs with a large HSD, lower injection rate and fluid viscosity produce larger SRV length and smaller SRV width. The fracture geometries tend to develop simple straight fractures, which leads to low initial productivity. Thus, adopting a relatively large injection rate and fluid viscosity is recommended to make full use of stress interference effects to increase the development of complex fractures near horizontal wellbores. The results of this study can serve as a guide in evaluating fracture complexity, SRV, proppant migration, drainage reservoir volume (DRV), and well completion design; they can also promote the in‐depth understanding of the coupling effect between fluid flow and geomechanics. [ABSTRACT FROM AUTHOR]

Dynamic capillarity commonly exists for multiphase flow in porous media, during which fluid viscosity varies and has strong influence. Displacement experiments are conducted on water‐wet, fractured tight rock at in situ pressure and temperature of an oil reservoir via a specially designed apparatus to investigate the effects of fluid viscosity on the dynamic capillarity. The dynamic effect in the matrix is examined through the measurement and calculation of capillary pressure, the dynamic coefficient, and the fluid flow behavior. The results show that with a higher oil viscosity: (a) both the steady and the dynamic capillary pressures reverse their directions more quickly and behave as larger resistances in the matrix; (b) the difference between the steady and the dynamic capillary pressures becomes around 5%‐19% more significant; (c) water saturation changes more slowly corresponding to the lower water relative permeability, while oil relative permeability quickly becomes lower than that during the basic displacement process; and (d) the dynamic coefficient becomes 2‐3 times higher, and the dynamic contact angle becomes 10%‐25% larger, showing a more variable interface. A contact angle advancement coefficient is proposed to identify the significance of contact angle advancement and the competition between capillary pressure and viscous force. The findings of this study can help for better understanding of multiphase flow in tight reservoirs and enhancing oil recovery. [ABSTRACT FROM AUTHOR]

Perforation is the key to the successful implementation of hydraulic fracturing. The research on perforation mechanism is of great significance to perforation planning, completion design, hydraulic fracturing design, and proppant migration analysis. In this paper, a finite element model for simulating crack initiation and propagation in the presence of multiple perforations is established based on the global embedded cohesive zone model (CZM). The reservoir is considered as a dense, low-permeability porous elastic medium, and the coupling between fluid flow and geomechanics, as well as the back-stress effect, are considered. The Blanton's (1982) criteria were used to verify the accuracy of the global embedded CZM. Then five cases are used to discuss the effects of perforation density, horizontal stress difference (HSD) on fracture initiation, propagation, and fracture complexity. The results show: There are four competitive fracture initiation modes for multiple perforations: First, fracture initiation at an early stage and keeping on; Second, hole deformed but not cracked; Third, fracture initiation first and then close; Fourth, at the beginning, there is no fracture initiation, initiation later. With the increase of perforation density, affected by the decrease of flow distribution, increase of friction and stress interference, the initiation rate of perforations gradually decreases, and the fracture pressure shows a tendency of decreasing first and then increasing. When multiple perforations exist, the crack propagation changes from complex to simple, and the number of cracks changes from more to less. Finally, the expansion mode is formed with 2–3 main cracks as the main and micro cracks as the auxiliary. The increase of perforation density can increase the complexity of fractures around the wellbore, and is beneficial to the diversion of fractures and the expansion of the impact range of fractures. However, it can also cause distortion and deformation of the fracture wall and decrease of fracture opening near the wellbore, which can lead to difficulty in proppant migration. Under low HSD, under the influence of stress inversion, connected horizontal cracks are easy to form between holes, and the fractures are easier to turn and more complicated. Under high HSD, disconnected horizontal micro-cracks can be formed between holes, and the main fractures tend to develop into simple straight fractures. The results of our research have important practical guiding significance for the development of perforation plan, hydraulic fracturing design and proppant migration analysis. • Models for simulating crack initiation and propagation is established based on the CZM. • There are four competitive fracture initiation types for multiple perforations. • Perforation density and stress difference have great influence on fracture complexity. • The results have important significance for the perforation plan. [ABSTRACT FROM AUTHOR]

Abstract The pressure transient technique, such as pulse decay method (PDM), has been considered an advanced approach to measure the permeability of the coalbed methane(CBM) and shale gas formations as such approach is more efficient, accurate and effective compared to that of the conventional flowrate measurement method. A constant isothermal gas compressibility factor is assumed over the testing pressure range in the experimental studies when using the PDM, which could lead to an inaccurate measured permeability. In this study, a nonlinear parabolic partial differential equation (PDE) model, taking the isothermal gas compressibility factor (gas compressibility) as a pressure dependent variable, was established to examine how pressure responses are affected by the gas compressibility variation. A novel and practical finite difference scheme was then proposed to efficiently and accurately solve the nonlinear PDE model, providing a powerful tool to numerically investigate the gas flow behavior in the CBM and shale rocks. Analytical solution for the PDE model was derived rigorously to investigate the influence of gas compressibility on the calculated permeability. Laboratory experiments were also conducted on coal permeability measurement and characteristics of the pressure pulse decay plots verified the effect of the gas compressibility on the pressure responses, especially under low pressures. Both numerical and experimental results demonstrated that the gas compressibility is a crucial parameter that should be considered for the permeability calculations in CBM and shale reservoirs. It is found that the difference in the pressure response that is predicted between the nonlinear model and the linear model with a constant gas compressibility can reach up to 41.1% at the testing pressure of 0.7 MPa. In addition, the difference in the measured permeability obtained from the two models increases as gas depletion proceeds. And also, it is suggested that both pressure changes in the upstream and downstream reservoirs should be used for permeability calculation to minimize the influence of gas compressibility on calculated permeability. This study extends the applicability of the pressure transient technique and provides an effective way to accurately measure permeability of unconventional tight gas reservoirs. Highlights • A nonlinear model is derived to represent pressure decay in time and space. • A novel finite difference scheme is proposed to solve the nonlinear model. • An in-depth comparison is conducted between the linear and nonlinear model. • Three different analytical solutions are derived for permeability calculation. • Gas compressibility is verified to play a role in measured permeability. [ABSTRACT FROM AUTHOR]

The development of fractured reservoirs can benefit from the use of foams, as they can enter fractures to increase the flow resistance of high-permeability zones, thereby redirecting fluid flow toward low-permeability zones. This can reduce the leak-off of working fluids during flow and improve the reservoir stimulation efficiency. The fracture visualization models applicable to micro-scale foam flow are developed to fully reveal the flow and plugging behavior of foams in micro-fractures. The models are accompanied by the implementation of the micro-fracture foam flow experiments. The experiment results show that with the increasing flow rate and foaming agent concentration, foams become smaller, more homogeneous, stable, and capable of plugging micro-fractures. However, both significantly large and small gas-liquid ratios degrade these properties of foams. For optimal results, a gas/liquid flow rate of 100–150 μL/min, a gas-liquid ratio of 2–4, and a foaming agent concentration of higher than 0.75 wt% are recommended. During foam flow, foams preferably enter wider fractures, where they accumulate and become trapped, plugging the flow channels. This results in a diversion of the subsequent foams towards narrower fractures, leading to more effective plugging of the fractures. [Display omitted] [ABSTRACT FROM AUTHOR]

Linear composite reservoirs, which can be represented as linear assemblies of distinct homogeneous regions, are among the most common types of ideal heterogeneous reservoirs. Many types of heterogeneous reservoirs, such as conventional and unconventional (tight) fluvio-deltaic reservoirs, meandering stream reservoirs, and fault reservoirs, can be approximated as linear composite systems. However, few studies have focused on the analysis and modeling of fractured wells, which are commonly used to produce tight oil/gas in such systems. In this paper, we present an analytical solution for fluid flows in a vertical finite-conductivity fractured well at an arbitrary position with arbitrary azimuth of fracture plane and in rectangular bounded anisotropic multi-region linear composite reservoirs considering finite-conductivity (partially communicating) faults. The solution is obtained by applying the methods of equivalent transformation, Green's function, and Laplace-finite Fourier cosine transformation. The standard log–log type curves, the dimensionless pressure, and its derivative with respect to t D / C D , of the transient pressure response are plotted. Then, the behavior of two well-known linear composite systems (multi-region composite reservoirs and fault reservoirs) and a general linear composite system are examined. The effects of the relevant parameters were analyzed. It is shown that each main characteristic pressure behavior of wellbore storage and the skin, fractured well, linear composite structure, and finite-conductivity (partially communicating) faults can be identified on the type curves by their characteristic flow regimes. However, the characteristic behavior of each region may be masked by others in the complex multi-region case. It is also shown that the behavior of a fractured well in a general linear reservoir can be considered as a combinational behavior of the fault and multi-region composite reservoir. The presented solution can also be used in well testing to obtain reservoir and well parameters. • An analytical solution for a fractured well with an arbitrary azimuth in anisotropic composite reservoirs is presented. • Closed multi-region linear composite system with two kinds of faults of a finite-conductivity fractured well were considered. • The accuracy and efficiency of present solution is verified. • The effect of relevant parameters on pressure transients was modeled and analyzed. • The pressure behavior of general composite case can be considered as a combinational behavior of some simplified cases. [ABSTRACT FROM AUTHOR]

• A unified dynamic capillary effect model is proposed with influential parameters. • Ranges of coefficients are specifically proposed for fractured tight porous media. • The proposed model can reasonably explain the fluid-porous media system properties. The dynamic capillary effect in capillary pressure plays a significant role during the non-equilibrium flow in porous media for various chemical, environmental and petroleum processes. A unified model is developed in this work to estimate the dynamic capillary effect in matrix during the non-equilibrium flow in tight porous media. Multiple influential parameters (especially fluid viscosity, surfactant and fracture with inconsistent effects) and the interplays between them are comprehensively considered. Firstly, a databank of the relationship between the dynamic capillary coefficient and the main controlling parameters is established through non-equilibrium flow experiments on the fractured and intact tight core samples. Secondly, the previously unclear correlations between the dynamic capillary coefficient and the influential parameters are determined individually, which are then incorporated into an overall model based on the Buckingham's π-theorem. The proposed model is further validated and simplified, showing accurate matches with the R2 ≈ 0.95. At last, the sensitivity analysis of five different non-equilibrium flow conditions is conducted, through which effects of the influential parameters on the dynamic capillary effect are investigated. The proposed model can reasonably explain the porous media properties, the easiness and uniformity of the fluid flow, and the effect of viscous force for the non-equilibrium flow in tight porous media. The findings of this study can help for a better understanding of multiphase flow in tight porous media. [ABSTRACT FROM AUTHOR]