Parallel-Simulator Framework for Multipermeability Modeling With Discrete Fractures for Unconventional and Tight Gas Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1370-1385 ◽  
Author(s):  
Larry S. Fung ◽  
Shouhong Du
Keyword(s):  
Organic Matter ◽  
Transient Flow ◽  
Domain Decomposition Method ◽  
Knudsen Diffusion ◽  
Fracture Network ◽  
Simulation System ◽  
Hydraulic Fractures ◽  
Mathematical Framework ◽  
Fine Grid ◽  
Shale Reservoirs

Summary Economic gas rate from ultralow-permeability shale reservoirs requires the creation of a complex fracture network in a large volume known as the stimulated reservoir volume (SRV). The fracture network connects a large surface area of the reservoir to the well. It is created by injecting low-viscosity fracturing fluid (slickwater) at very high rates in multiple stages along the horizontal wellbore. Numerical simulation is used to evaluate the stimulation designs and completion strategy. Microseismic (MS) -survey fracture mapping can provide a measurement of the overall SRV and an estimate of the fracture patterns. Special core analyses provide estimates of shale-matrix permeability. The extent of the fracture network indicates that there is insufficient proppant volume, and many stimulated fractures may be only partially propped or may be unpropped. Thus, fracture conductivity will vary spatially caused by uneven proppant distribution and temporally caused by stress sensitivity upon pressure decline during production. Because of the vast contrast in conductivity between stimulated/hydraulic fractures (darcy-ft) and shale matrix (nd-ft), the transient response in matrix/fracture flow cannot be captured accurately if the stimulated fractures are approximated with large dual-continuum (DC) gridblocks. The gridding requirement to achieve an accurate solution in fractured shale reservoirs is investigated and discussed. In this work, the stimulated and hydraulic fractures are discretized explicitly to form a discrete fracture network (DFN). This paper discusses the mathematical framework and parallel numerical methods for simulating unconventional reservoirs. The simulation methods incorporate known mechanisms and processes for shale, which include gas sorption in organic matter; combined Knudsen diffusion and viscous flow in nanopores; stress-sensitive fracture permeability; and velocity-dependent flow in the high-conductivity hydraulic fractures. The simulation system is based on a general finite-volume method that includes a multiconnected multicontinuum (MC) representation of the pore system with either a compositional or a black-oil fluid description. The MC model is used to represent the storage and intercommunication among the various porosities in shale (organic matter, inorganic matter, fine unstimulated natural fractures). Unconventional simulation involves many more nonlinearities, and the extreme contrast in permeabilities will make the problems harder to solve. We discuss numerical implementation of the methods for modeling the mechanisms and processes in fractured shale. In addition, we discuss the MC formulation, the discretization method, the unstructured parallel domain-decomposition method, and the solution method for the simulation system. Finally, we explain our efforts in numerical validation of the system with fine-grid single-porosity simulation. We show numerical examples to demonstrate the applications of the simulator and to study the transient flow behavior in shale reservoirs. The effects of the various mechanisms for gas production are also evaluated.

What are the Dominant Flow Regimes During Carbon Dioxide Propagation in Shale Reservoirs’ Matrix, Natural Fractures and Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Viscous Flow ◽  
Flow Regime ◽  
Knudsen Diffusion ◽  
Flow Regimes ◽  
Hydraulic Fractures ◽  
Transition Flow ◽  
Pore Sizes ◽  
Thermodynamic Conditions ◽  
Shale Reservoirs

Abstract Carbon dioxide (CO2) injection in low permeability shale reservoirs has recently gained much attention due to the claims that it has a large recovery factor and can also be used in CO2 storage operations. This research investigates the different flow regimes that the CO2 will exhibit during its propagation through the fractures, micropores, and the nanopores in unconventional shale reservoirs to accurately evaluate the mechanism by which CO2 recovers oil from these reservoirs. One of the most widely used tools to distinguish between different flow regimes is the Knudsen Number. Initially, a mathematical analysis of the different flow regimes that can be observed in pore sizes ranging between 0.2 nanometer and more than 2 micrometers was undergone at different pressure and temperature conditions to distinguish between the different flow regimes that the CO2 will exhibit in the different pore sizes. Based on the results, several flow regime maps were conducted for different pore sizes. The pore sizes were grouped together in separate maps based on the flow regimes exhibited at different thermodynamic conditions. Based on the results, it was found that Knudsen diffusion dominated the flow regime in nanopores ranging between 0.2 nanometers, up to 1 nanometer. Pore sizes between 2 and 10 nanometers were dominated by both a transition flow, and slip flow. At 25 nanometer, and up to 100 nanometers, three flow regimes can be observed, including gas slippage flow, transition flow, and viscous flow. When the pore size reached 150 nanometers, Knudsen diffusion and transition flow disappeared, and the slippage and viscous flow regimes were dominant. At pore sizes above one micrometer, the flow was viscous for all thermodynamic conditions. This indicated that in the larger pore sizes the flow will be mainly viscous flow, which is usually modeled using Darcy's law, while in the extremely small pore sizes the dominating flow regime is Knudsen diffusion, which can be modeled using Knudsen's Diffusion law or in cases where surface diffusion is dominant, Fick's law of diffusion can be applied. The mechanism by which the CO2 improves recovery in unconventional shale reservoirs is not fully understood to this date, which is the main reason why this process has proven successful in some shale plays, and failed in others. This research studies the flow behavior of the CO2 in the different features that could be present in the shale reservoir to illustrate the mechanism by which oil recovery can be increased.

scholarly journals Effect of Joint Geometrical Parameters on Hydraulic Fracture Network Propagation in Naturally Jointed Shale Reservoirs

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-23 ◽  
Author(s):  
Zhaohui Chong ◽  
Qiangling Yao ◽  
Xuehua Li
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Geometrical Parameters ◽  
Breakdown Pressure ◽  
Opening Mode ◽  
Hydraulic Fracture Network ◽  
Shale Reservoirs ◽  
Network Pattern

The presence of a significant amount of discontinuous joints results in the inhomogeneous nature of the shale reservoirs. The geometrical parameters of these joints exert effects on the propagation of a hydraulic fracture network in the hydraulic fracturing process. Therefore, mechanisms of fluid injection-induced fracture initiation and propagation in jointed reservoirs should be well understood to unleash the full potential of hydraulic fracturing. In this paper, a coupled hydromechanical model based on the discrete element method is developed to explore the effect of the geometrical parameters of the joints on the breakdown pressure, the number and proportion of hydraulic fractures, and the hydraulic fracture network pattern generated in shale reservoirs. The microparameters of the matrix and joint used in the shale reservoir model are calibrated through the physical experiment. The hydraulic parameters used in the model are validated through comparing the breakdown pressure derived from numerical modeling against that calculated from the theoretical equation. Sensitivity analysis is performed on the geometrical parameters of the joints. Results demonstrate that the HFN pattern resulting from hydraulic fracturing can be roughly divided into four types, i.e., crossing mode, tip-to-tip mode, step path mode, and opening mode. As β (joint orientation with respect to horizontal principal stress in plane) increases from 0° to 15° or 30°, the hydraulic fracture network pattern changes from tip-to-tip mode to crossing mode, followed by a gradual decrease in the breakdown pressure and the number of cracks. In this case, the hydraulic fracture network pattern is controlled by both γ (joint step angle) and β. When β is 45° or 60°, the crossing mode gains dominance, and the breakdown pressure and the number of cracks reach the lowest level. In this case, the HFN pattern is essentially dependent on β and d (joint spacing). As β reaches 75° or 90°, the step path mode is ubiquitous in all shale reservoirs, and the breakdown pressure and the number of the cracks both increase. In this case, β has a direct effect on the HFN pattern. In shale reservoirs with the same β, either decrease in k (joint persistency) and e (joint aperture) or increase in d leads to the increase in the breakdown pressure and the number of cracks. It is also found that changes in d and e result in the variation in the proportion of different types of hydraulic fractures. The opening mode of the hydraulic fracture network pattern is observed when e increases to 1.2 × 10−2 m.

Time-lapse X-ray imaging of deformation modes in organic-rich Green River Shale heated under confinement

2020 ◽  
Author(s):  
Maya Kobchenko ◽  
Anne Pluymakers ◽  
Benoit Cordonnier ◽  
François Renard
Keyword(s):  
Organic Matter ◽  
Rock Physics ◽  
Fracture Network ◽  
High Energy ◽  
External Loading ◽  
Hydraulic Fractures ◽  
Burial History ◽  
X Ray ◽  
In Situ Conditions

<p>Shales are layered sedimentary rocks, which can be almost impermeable for fluids and act as seals and cap-rock, or, if a shale layer hosts a fracture network, it can act as a fluid reservoir and/or a conduit.  Organic-rich shales contain organic matter - kerogen, which can transform from solid-state to oil and gas during shale burial and exposure to heat. When the organic matter is decomposing into lighter molecular weight hydrocarbons, the pore-pressure inside the shale rock increases and can drive propagation of hydraulic fractures and strongly modify the permeability of these tight rocks. Density, geometry, extension, and connectivity of the final fracture network depend on the combination of the heating conditions and history of external loading experienced by the shale reservoir. Here, we have performed a series of rock physics experiments where organic-.rich shale samples were heated, under in situ conditions, and the development of microfractures was imaged through time. We used the high-energy X-ray beam produced at the European Synchrotron Radiation Facility to acquire dynamic microtomography images and monitor different modes of the shale deformation in-situ in 3D. We reproduce natural conditions of the shale deformation processes using a combination of vertical load, confining and heating of the shale samples. Shales feature natural mineral and silt lamination and hydraulic fractures easily propagate parallel to these laminae if no overburden stress is applied. However, if the principal external load becomes vertical, perpendicular to the shale lamination, the fracture propagation direction can deviate from the horizontal one. Together horizontal and vertical fractures form a three-dimensional connected fracture network, which provides escaping pathways for generated hydrocarbons. Our experiments demonstrate that tight shale rocks, which are often considered as impermeable, could have hosted transient episodes of micro-fracturing and high permeability during burial history.</p>

Time-lapse synchrotron X-ray imaging of deformation modes in organic-rich Green River Shale heated under confinement 

2021 ◽  
Author(s):  
Maya Kobchenko ◽  
Anne Pluymakers ◽  
Benoit Cordonnier ◽  
Nazmul Mondol ◽  
Francois Renard
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Fracture Network ◽  
High Energy ◽  
External Loading ◽  
Hydraulic Fractures ◽  
Burial History ◽  
X Ray ◽  
In Situ Conditions

<p>Shales are layered sedimentary rocks, which can be almost impermeable for fluids and act as seals and cap-rocks, or if a shale layer hosts a fracture network, it can act as a fluid reservoir and/or conduit. Organic-rich shales contain organic matter - kerogen, which can transform from solid-state to oil and gas during burial and exposure to a suitable temperature. When hydrocarbons are expelled from the organic matter due to maturation, pore-pressure increases, which drives the propagation of hydraulic fractures, a mechanism identified to explain oil and gas primary migration. Density, geometry, extension, and connectivity of the final fracture network depend on the combination of the heating conditions and history of external loading experienced by the shale. Here, we have performed a series of rock physics experiments where organic-rich shale samples were heated, under in situ conditions, and the development of microfractures was imaged through time. We used the high-energy X-ray beam produced at the European Synchrotron Radiation Facility to acquire dynamic microtomography images and monitor different modes of shale deformation in-situ in 3D. We reproduced natural conditions of the shale deformation processes using a combination of axial load, confining pressure, and heating of the shale samples. Shales feature natural sedimentary laminations and hydraulic fractures propagate parallel to these laminae if no overburden stress is applied. However, if the principal external load becomes vertical, perpendicular to the shale lamination, the fracture propagation direction can deviate from the horizontal one. Together horizontal and vertical fractures form a three-dimensional connected fracture network, which provides escaping pathways for generated hydrocarbons. Our experiments demonstrate that tight shale rocks, which are often considered impermeable, could host transient episodes of micro-fracturing and high permeability during burial history.</p>

scholarly journals Numerical Investigation on Propagation Behaviors of a Three-Dimensional Fracture Network Coupled with Microseismicity in Fractured Shale Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8297
Author(s):  
Jianfa Wu ◽  
Haoyong Huang ◽  
Ersi Xu ◽  
Junfeng Li ◽  
Xiaohua Wang
Keyword(s):  
Three Dimensional ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Injection Rate ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Hydraulic Fracture Network ◽  
Shale Reservoirs ◽  
Stimulation Efficiency ◽  
Viscosity Fluid

The formation mechanism and propagation behaviors of a three-dimensional hydraulic fracture network in fractured shale reservoirs remain unclear, especially when the scale of hydraulic fractures is much larger than that of natural fractures. In this study, taking the well XH in the Longmaxi shale reservoir in the Sichuan Basin, China as an example, we develop a fully three-dimensional numerical model for hydraulic fracturing coupled with microseismicity based on the discrete lattice method. We introduce a randomly generated discrete fracture network into the proposed model and explore the formation mechanism of the hydraulic fracture network under the condition that the hydraulic fractures are much larger than natural fractures in scale. Moreover, microseismic events are inversely synthesized in the numerical model, which allows the evolution of the fracture network to be monitored and evaluated quantitatively. In addition, we analyze the effects of injection rate, horizontal stress difference, and fluid viscosity on fracture propagation. Our results show that when the scale of hydraulic fractures is much larger than that of natural fractures, the fracture morphology of “main hydraulic fractures + complex secondary fractures” is mainly formed. We find that a high injection rate can not only create a complex fracture network, but also improve the uniform propagation of multi-cluster fractures and enhance far-field stimulation efficiency. Optimizing the horizontal wellbore intervals with low horizontal stress differences as the sweet spots of hydraulic fracturing is also beneficial to improve the stimulation efficiency. For zones with a large number of natural fractures, it is recommended to use an injection schedule with high viscosity fluid early and low viscosity fluid late to allow the hydraulic fractures to propagate to the far-field to maximize the stimulation effect.

Rate Transient Analysis of Heterogeneous Unconventional Gas Reservoir Using a Fractional Decline Model

2021 ◽  
Author(s):  
Loc Luong
Keyword(s):  
Gas Flow ◽  
Transient Flow ◽  
Fractured Reservoirs ◽  
Synthetic Data ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Curve Matching ◽  
Reservoir Properties ◽  
Type Curve ◽  
Type Curves

Abstract In this study, an extended version of the fractional decline model is analytically developed for gas flow in fracture reservoir using the anomalous diffusion equation incorporated with the fractional calculus and equation of state. The model can represent the heterogeneity of complex fracture networks and can further be used to interpret reservoir properties by performing type-curve matching of flow rate and cumulative production from multi-fractured horizontal wells in unconventional reservoirs. To address the limitations of conventional planar fracture idealization, the hydraulic fractures in this present study are integrated with the fracture network, and the fractional diffusivity is solved for a horizontal wellbore. Upon establishing and solving the governing equation in the Laplace domain, the solutions are converted back to the real-time and space domain by performing numerical Laplace inversion. A set of distinctive type curves is generated on the basis of an infinite conductivity horizontal well model, considering early and middle times, in order to capture the heterogeneity of the fractal network in the reservoir model. Application of this new model is demonstrated through type-curve matching of two synthetic cases of simulation data obtained from commercial software; the cases cover orthogonal evenly and unevenly distributed networks. Results from these examples show an acceptable match between the fractional decline model and synthetic data and, hence, showcase the applicability of this model to capture the transient flow in heterogeneous fractured reservoirs.

scholarly journals Simulation of methane adsorption in diverse organic pores in shale reservoirs with multi-period geological evolution

2021 ◽  
Author(s):  
Shangbin Chen ◽  
Chu Zhang ◽  
Xueyuan Li ◽  
Yingkun Zhang ◽  
Xiaoqi Wang
Keyword(s):  
Organic Matter ◽  
Pore Size ◽  
Adsorption Capacity ◽  
Thermal Evolution ◽  
Methane Adsorption ◽  
Storage Site ◽  
Pressure Sensitivity ◽  
Adsorption Characteristics ◽  
Shale Reservoirs ◽  
Organic Pores

AbstractIn shale reservoirs, the organic pores with various structures formed during the thermal evolution of organic matter are the main storage site for adsorbed methane. However, in the process of thermal evolution, the adsorption characteristics of methane in multi type and multi-scale organic matter pores have not been sufficiently studied. In this study, the molecular simulation method was used to study the adsorption characteristics of methane based on the geological conditions of Longmaxi Formation shale reservoir in Sichuan Basin, China. The results show that the characteristics of pore structure will affect the methane adsorption characteristics. The adsorption capacity of slit-pores for methane is much higher than that of cylindrical pores. The groove space inside the pore will change the density distribution of methane molecules in the pore, greatly improve the adsorption capacity of the pore, and increase the pressure sensitivity of the adsorption process. Although the variation of methane adsorption characteristics of different shapes is not consistent with pore size, all pores have the strongest methane adsorption capacity when the pore size is about 2 nm. In addition, the changes of temperature and pressure during the thermal evolution are also important factors to control the methane adsorption characteristics. The pore adsorption capacity first increases and then decreases with the increase of pressure, and increases with the increase of temperature. In the early stage of thermal evolution, pore adsorption capacity is strong and pressure sensitivity is weak; while in the late stage, it is on the contrary.

scholarly journals Numerical simulation on the simultaneous stress interference of parallel multiple hydraulic fractures

2021 ◽  
pp. 014459872110019
Author(s):  
Weiyong Lu ◽  
Changchun He
Keyword(s):  
Principal Stress ◽  
Hydraulic Fracture ◽  
Stress Ratio ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Fracture Spacing ◽  
Induced Stress ◽  
Minimum Principal Stress ◽  
Fracturing Process ◽  
Stress Ratios

During horizontal well staged fracturing, there is stress interference between multiple transverse fractures in the same perforation cluster. Theoretical analysis and numerical calculation methods are applied in this study. We analysed the mechanism of induced stress interference in a single fracture under different fracture spacings and principal stress ratios. We also investigated the hydraulic fracture morphology and synchronous expansion process under different fracture spacings and principal stress ratios. The results show that the essence of induced stress is the stress increment in the area around the hydraulic fracture. Induced stress had a dual role in the fracturing process. It created favourable ground stress conditions for the diversion of hydraulic fractures and the formation of complex fracture network systems, inhibited fracture expansion in local areas, stopped hydraulic fractures, and prevented the formation of effective fractures. The curves of the maximum principal stress, minimum principal stress, and induced principal stress difference with distance under different fracture lengths, different fracture spacings, and different principal stress ratios were consistent overall. With a small fracture spacing and a small principal stress ratio, intermediate hydraulic fractures were difficult to initiate or arrest soon after initiation, fractures did not expand easily, and the expansion speed of lateral hydraulic fractures was fast. Moreover, with a smaller fracture spacing and a smaller principal stress ratio, hydraulic fractures were more prone to steering, and even new fractures were produced in the minimum principal stress direction, which was beneficial to the fracture network communication in the reservoir. When the local stress and fracture spacing were appropriate, the intermediate fracture could expand normally, which could effectively increase the reservoir permeability.

scholarly journals Numerical modeling of complex hydraulic fracture networks based on the discontinuous deformation analysis (DDA) method

2021 ◽  
pp. 014459872098153
Author(s):  
Yanzhi Hu ◽  
Xiao Li ◽  
Zhaobin Zhang ◽  
Jianming He ◽  
Guanfang Li
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Discontinuous Deformation Analysis ◽  
Deformation Analysis ◽  
Fracture Networks ◽  
Proposed Model ◽  
Discontinuous Deformation ◽  
Shale Reservoirs ◽  
Dda Method

Hydraulic fracturing is one of the most important technologies for shale gas production. Complex hydraulic fracture networks can be stimulated in shale reservoirs due to the existence of numerous natural fractures. The prediction of the complex fracture network remains a difficult and challenging problem. This paper presents a fully coupled hydromechanical model for complex hydraulic fracture network propagation based on the discontinuous deformation analysis (DDA) method. In the proposed model, the fracture propagation and rock mass deformation are simulated under the framework of DDA, and the fluid flow within fractures is simulated using lubrication theory. In particular, the natural fracture network is considered by using the discrete fracture network (DFN) model. The proposed model is widely verified against several analytical and experimental results. All the numerical results show good agreement. Then, this model is applied to field-scale modeling of hydraulic fracturing in naturally fractured shale reservoirs. The simulation results show that the proposed model can capture the evolution process of complex hydraulic fracture networks. This work offers a feasible numerical tool for investigating hydraulic fracturing processes, which may be useful for optimizing the fracturing design of shale gas reservoirs.

Efficient Localized Nonlinear Solution Strategies for Unconventional-Reservoir Simulation with Complex Fractures

2021 ◽  
Author(s):  
Jiamin Jiang
Keyword(s):  
Transient Flow ◽  
A Priori ◽  
Time Discretization ◽  
Unconventional Reservoirs ◽  
Hydraulic Fractures ◽  
Nonlinear Solution ◽  
Compositional Model ◽  
Simulation Speed ◽  
Flow Mechanisms ◽  
Solution Accuracy

Abstract It is very challenging to simulate unconventional reservoirs efficiently and accurately. Transient flow can last for a long time and sharp solution (pressure, saturation, compositions) gradients are induced because of the severe permeability contrast between fracture and matrix. Although high-resolution models for well and fracture are required to achieve adequate resolution, they are computationally too demanding for practical field models with many stages of hydraulic fracture. The paper aims to innovate localization strategies that take advantage of locality on timestep and Newton iteration levels. The strategies readily accommodate to complicated flow mechanisms and multiscale fracture networks in unconventional reservoirs. Large simulation speed-up can be obtained if performing localized computations only for the solution regions that will change. We develop an a-priori method to exploit the locality, based on the diffusive character of the Newton updates of pressure. The method makes adequate estimate of the active computational gridblock for the next iterate. The active gridblock set marks the ones need to be solved, and then the solution to local linear system is accordingly computed. Fully Implicit Scheme is used for time discretization. We study several challenging multi-phase and compositional model cases with explicit fractures. The test results demonstrate that significant solution locality of variables exist on timestep and iteration levels. A nonlinear solution update usually has sparsity, and the nonlinear convergence is restricted by a limited fraction of the simulation model. Through aggressive localization, the proposed methods can prevent overly conservative estimate, and thus achieve significant computational speedup. In comparison to a standard Newton method, the novel solver techniques achieve greatly improved solving efficiency. Furthermore, the Newton convergence exhibits no degradation, and there is no impact on the solution accuracy. Previous works in the literature largely relate to the meshing aspect that accommodates to horizontal wells and hydraulic fractures. We instead develop new nonlinear strategies to perform localization. In particular, the adaptive DD method produces proper domain partitions according to the fluid flow and nonlinear updates. This results in an effective strategy that maintains solution accuracy and convergence behavior.

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