Numerical simulation of fracture propagation in deflagration-hydraulic composite fracturing of unconventional reservoirs

This paper presents an improved new reservoir simulation model. By applying reservoir engineering, numerical simulation, and fluid flow theory through porous media to the conditions of production engineering, and taking into consideration the triple medium of matrix, natural fracture, and hydraulic fracture for tight low permeable fractured gas reservoirs, the authors arrived at a comprehensive conclusion for the low non-Darcy and high non-Darcy flows. A corresponding solution model is also presented, made available through computer programming. The results derived from the fracturing reservoir software, developed specifically in this study for tight low permeable fractured gas reservoirs and which takes into account such various aspects as the direction of and influence of in situ stress, reservoirroperties, natural fracture system, and hydraulic fracture length, show that the fracturing reservoir plan for the Xin Chang gas field has been worked out. The results prove that simulation softwarecan work as a powerful tool to design a fracturing reservoir lan for tight low permeable fractured gas reservoirs. Introduction Efforts to narrow the gap between investment and output, and to extend production while keeping recovery reasonably stable, encourages the wide use of fracturing reservoir techniques in gas and oil fields to maximize the economic benefits. The key to fracturing a reservoir is forecasting the best well net or post-fracturing production performance, which can provide reliable data for an adjustment plan for gas and oil fields. On the one hand, within tight low permeable fractured gas reservoirs, the fluid has to overcome the minimum pressure gradient to flow, which is characterized by low non-Darcy flow. On the other hand, the gas velocity is very high in hydraulic fracture, which is usually characterized by high non- Darcy flow. This study takes into account both the low non-Darcy flow and the high non-Darcy flow and puts forward an improved fracturing reservoir mathematical model for tight low permeable fractured gas reservoirs. Fracturing Reservoir Mathematical Model of Tight Clastic Gas Reservoir Based on successful numerical simulations in fractured reservoirs, and considering the triple medium of matrix, natural fracture, and hydraulic fracture, the fracturing reservoir simulationodel using three-dimensional (3D), two-phase (water and gas) triple medium for tight clastic gas reservoir was developed in which the influence of low non-Darcy velocity and high non-Darcy velocity on fluid flow in tight low permeable fractured gas reservoirs was originally studied at length. The model includes: Mathematical Model of High Velocity Non-Darcy Flow Basic Flow Equations Equation Available In Full Paper....(1) where Equation Available In Full Paper....(2) Coefficient of High Velocity Non-Darcy Flow Equation Available In Full Paper....(3) Mathematical Model of Low Velocity Non-Darcy Flow Equation Available In Full Paper....(4) General Mathematical Model of Non-Darcy Flow Equation Available In Full Paper....(5) when α= 0, β?= 1, the above equation represents linear Darcy flow; when α= 0, β= 0, the above equation represents high velocity non-Darcy flow; and, when α?= 1, β= 1, the above equation represents low velocity non-Darcy flow.

This paper has been dedicated to the optimization of multi-stage hydraulic fracturing by providing a more thorough understanding of fracture and reservoir stress behavior. This is accomplished by the use of a fully coupled fracture propagation simulator that couples fracture mechanics and fluid dynamics, unlike past studies, which observe only simple interactions. The underlying objective is to eliminate the misappropriated energy caused by inter-fracture stress interaction and stress reorientation surrounding the induced fracture network by assessing stress magnitude as a function of operation conditions. This study is based upon an in-house numerical simulation model developed for hydraulic fracture propagation based upon the linear elastic fracture mechanic "LEFM" using finite element method. The elastic response of the 2-D solid medium and the fluid flow within the fracture is coupled to provide a more realistic depiction of these interactions. The magnitude of stress variation and reorientation is calculated in surrounding areas of simultaneous and sequential hydraulic fracturing of a horizontal well for a wide range of hydraulic fracturing propagation regimes for both homogenous and compositional models. Our study clearly shows that there is an optimum distance between hydraulic fractures below which, the change (variation) in magnitude and orientation of stresses leads to significant change in fracture geometry and propagation rate. This has been impacted mainly through mechanical interaction that leads to higher compressive stress concentrations between fractures. The mechanical interaction becomes stronger by increasing the number of fractures or altering the fracture spacing. The effects have also been investigated in a composite reservoir model with different mechanical properties (i.e., Young's modulus and Poisson's ratio), and operational conditions, such as injection rate and volume. Mechanical properties of different layers in a composite reservoir model significantly impact the fracture geometry and propagation rate when the fracture intercepts different layer boundaries. The magnitude of change in stresses and stress reorientation is also quantified in cross sections with respect to the fracture plane as the fracture propagates. This study provides an advanced understanding of multiple hydraulic fracturing stimulation and dynamics of fracture geometry, propagation rate and stress change in surrounding using our unique fully coupled hydraulic fracturing simulator. Moreover, it provides quantitative analysis of induced stresses and in-situ stress reorientation. The work is important for the optimization of Multi-stage hydraulic fracturing in unconventional reservoirs.

Low-permeability gas reservoirs generally have the lowproduction, production rapid productivity decline, and low-ultimate recovery. Staged fracturing is usually conducted for horizontal wells. Hydraulic fracturing technology isgenerally used to improve fracture conductivity and well productivity. How to accurately characterize and simulate the distribution characteristics of hydraulic fracture network in 3D space is particularly important. The stress interference between hydraulic fractures as the objective mechanical behavior in the process of staged fracturing affects the geometry fracture network and the productivity of the reservoir post-fracturing. The hydraulic fractures simulation in natural fractured reservoirs is complex shapes, mainly because natural fractures affect the propagation path of hydraulic fractures. The theoretical model used to describe the hydraulic fracturing in homogeneous reservoirs cannot accurately show the complexity of the spatial morphology of hydraulic fractures in naturally fractured formations. The operatorurgently needs a mechanical model that can show the stress interference behavior between multiple fractures and the direction of hydraulic fracture propagation, and be used to simulate the spatial form of multiple hydraulic fractures in staged fracturing of horizontal wells and their propagation behavior in naturally fractured formations. Aiming at the impact of natural fractures in the reservoir on the propagation path of hydraulic fractures, this paper established a mechanical model for distinguishing interference behavior of natural fractures and hydraulic fractures. And analyzed the stress field at the tip of the hydraulic fracture and the stress field acting on the natural fracture surface based on the theories related to rock mechanics and fracture mechanics. On the basis of coupling the 3D geomechanical model and the 3D Discrete Fracture Network (DFN) model, this paper established the discriminant model for hydraulic fractures penetrating natural fractures in 3D space to conduct hydraulic fracture propagation simulation for the horizontal well. The research results can be used to optimize the hydraulic fracturing treatment design,and provide technical support for the effective production and profitable development of low-permeability reservoir resources.

The application of hydraulic fracturing in unconventional reservoirs is a technique widely used to overcome the problem of low permeability in porous media. However, there are complex factors involved in understanding this technique, since the propagation of hydraulic fractures can be impacted by factors such as the state of stress in situ and the distribution of natural fractures, which may have different lengths, inclination angles and aperture values. Thus, based on the continuum mechanics and using the finite element method, this paper seeks to simulate the effect of hydraulic fracturing in porous media with a complex natural fractures network under the influence of different stress states. The modeling of the problem considers a fully coupled approach for solving the hydro-mechanical problem, with the Darcy’s law governing the fluid flow in the porous media and by the classical cubic law inside the fractures. For the representation of natural and hydraulic fractures, High Aspect Ratio Interface Finite Elements (HAR-IEs) associated with a suitable tensile damage model are used and inserted into the regular mesh via the Mesh Fragmentation Technique (MFT). The results obtained are validated with the literature and show that the model is capable of reproducing the complex scenarios of propagation and interaction between multiple fractures.

There are abundant tight oil and gas resources in glutenite reservoirs in China, and hydraulic fracturing is essential for developing this kind of resources. At present, the basic scientific problems involved in hydraulic fracturing of glutenite reservoirs, including simulation of fracture propagation, proppant transport and fracture conductivity, are not systematically clarified yet. The deficiencies of existing research ideas and methods are summarized, then suggested solutions and development prospects are proposed. The analysis shows that for the fracture propagation experiment, the establishment of a scalable glutenite sample preparation method and the experimental parameter conversion method is an urgent problem to be solved. The particle flow code (PFC) method has advantages in simulating the fracture propagation in microscopic scale. However, the simulation of fracture propagation in oilfield scale faces the problem of cross-scale calculation, so establishing a fast and effective cross-scale simulation method is very important. For the proppant transport experiment, the key is to develop plates with unidirectional filtration and different roughness to simulate the hydraulic fracture surface of glutenite reservoirs. The CFD-DEM coupling method to simulate the proppant transport has a good prospect, but it is necessary to consider the special properties of the glutenite reservoirs, and improve the mathematical model and explore corresponding solution method. The key to the experimental research of the fracture conductivity is to make samples that meet the size and shape requirements. Downhole drilled core, man-made rock and 3D printing technique can be adopted for sample procession. For computer simulation of conductivity prediction, combining PFC with CFD method to predict the conductivity of glutenite is an important exploration direction in the future.

Numerical reservoir models have some uncertainties inherent to them. This is partly because it is impossible to incorporate all complexities the real reservoirs have in nature. Furthermore, it is not uncommon that some of the required data is missing, in which case approximations or guesses are employed. It has been observed that numerical reservoir models with equally decent match with historical production data return significantly different numerical simulation conclusions which begs the obvious question, which conclusions should be taken into account before proceeding to the next step? In this study, a series of numerical reservoir models with different hydraulic fractures geometry are created based on a gas-producing well in an unconventional reservoir. Embedded discrete fracture model (EDFM) is used to embed hydraulic and natural fractures into the structured grid. Results show that the model with longer hydraulic fracture geometry has a significantly higher estimated ultimate recovery (EUR), likely due to it has a bigger total hydraulic fractures area. This suggests that a mistake in determining the most representative numerical reservoir model could lead to overestimation or underestimation of EUR which potentially translates to financial losses. It is recommended to use neighboring wells to determine which hydraulic fractures geometry does a well in question have, so that the potential problem mentioned above can be avoided. The effects of natural fractures presence are also investigated in an attempt to provide insights into how such type of fractures affect the gas production from a low permeability shale reservoir. INTRODUCTION The presence of fractures, in this case those that are manmade, has allowed low permeability shale reservoirs to produce hydrocarbons. Nonetheless, modeling such fractures representative enough to produce "correct" forecast is nontrivial. There are ampleuncertainties related to fractures and its properties in the reservoirs. This study uses a real dataset of a gas-producing well in a deep shale gas reservoir in Sichuan Basin. Three-dimensional discrete fracture network model is added to the model in order to simulate the effect of natural fractures to the well production. History-matched numerical models incorporated with embedded discrete fracture model (EDFM) are then created for simulation purposes. The concept of EDFM is illustrated in Fig. 1. EDFM itself has been argued to be able to accurately model any complex fractures in the reservoir without sacrificing the efficiency of structured grids (Xu et al., 2017, 2019; Sepehrnoori et al., 2020). It has been widely used in modeling complex fractures in unconventional reservoirs that also covers the existence of natural fractures, well spacing optimization with complex fracture hits, automatic history matching, and gas huff-n-puff for enhanced shale oil recovery (Yu and Sepehrnoori, 2018; Xu et al., 2018; Xu and Sepehrnoori, 2019; Ganjdanesh et al., 2019a, 2019b; Tripoppoom et al., 2020a, 2020b). A model has hydraulic fractures geometry greater in height but smaller in length than the other one. Another model has no natural fractures to simulate the effects of natural fractures on the gas production.

A single planar hydraulic fracture is typically the primary component used to simulate hydraulic fracturing stimulation in conventional reservoirs. However, in ultra-low-permeability shale reservoirs, a large system of fracture networks must be generated to produce hydrocarbons economically. Therefore, traditional modeling approaches centered on single planar fractures are inadequate for accurately representing the intricate geometry and behavior of fractures in these reservoirs. In previous works, 2D fractal fracture networks (FFNs) have been used to generate sets of hydraulic and natural fractures based on microseismic event (MSE) data. Since microseismic data are retrieved in 3D space, the aforementioned model cannot accurately represent induced fracture properties. The objective of this paper is to study in detail the recently developed 2D FFN model and propose a novel solution by expanding the previous model to accommodate real 3D microseismic data. First, the definitions of the 2D FFN model are described, and associated calibration mechanisms are proposed. Next, the 3D FFN model and its calibration system are demonstrated. While the novel 3D calibration solution utilizes an identical matching concept to the 2D methodology, the residual distances between the nodes and the MSE are calculated in 3D spaces. Finally, a set of real microseismic data are used to calibrate the generation of 3D fractals using the proposed workflow. The interactions between microseismicity and fractured reservoir dynamics are represented through the integration of fractal fracture models and microseismic data. This work contributes to advancing the current understanding of hydraulic fracturing in unconventional reservoirs and provides a valuable framework for improving fracture modeling’s accuracy in reservoir engineering applications.

Propagation of interfered hydraulic fractures by alternated radial-circumferential extensions and its impact on proppant distribution

Multistage stimulation horizontal wells are prerequisite technologies for efficient development of unconventional reservoir. However, the induced fracture network morphology from hydraulic fracturing is very complex and affected by many factors, such as the in situ stress, rock mechanical properties, and natural fracture distribution. The large numbers of natural fractures and strong reservoir heterogeneity in unconventional reservoirs result in enhanced complexity of induced fractures from hydraulic fracturing. Accurate description of fracture network morphology and the flow capacity in different fractures form an important basis for production forecasting, evaluation (or optimization) of stimulation design, and development plan optimization. This paper focuses on hydraulic fracturing in unconventional reservoirs and discusses the current research advances from four aspects: (1) the prediction of induced fracture propagation, (2) the simulation of fluid flow in complex fracture networks, (3) the inversion of fracture parameter (fracture porosity, fracture permeability, etc.), and (4) the optimization of hydraulic fracturing in unconventional reservoirs. In addition, this paper provides comparative analysis of the characteristics and shortcomings of the current research by outlining the key technical problems in the study of flow characterization, parameter inversion, and optimization methods for stimulation in unconventional reservoirs. This work can provide a certain guiding role for further research.

CDEM-based simulation of the 3D propagation of hydraulic fractures in heterogeneous Coalbed Methane reservoirs

Summary The shape, size, and orientation of natural fractures significantly impact the geometry of hydraulic fractures in unconventional reservoirs, such as shale gas/oil, tight gas, and enhanced geothermal system. The behaviors after the hydraulic fracture encounters natural fractures have been summarized as crossing, diverting, step over, and stopping based on a great number of numerical and experimental analysis with plain strain assumptions. However, under practical situations, the geometries of natural and hydraulic fractures are much more complex than the vertical and rectangular shape assumed by 2D models. The experimental studies on the role of height and inclination of natural fractures have revealed some other phenomena (e.g., bypassing process that the fluid-driven hydraulic fracture propagates up the back side of the natural fracture), which are unable to be captured in 2D. To better describe the intersection behaviors among different kind of fractures, a fully 3D model based on the displacement discontinuity method (DDM) is developed on top of our previous models, which only considered the propagation of hydraulic fractures. A novel crossing criterion to judge whether the hydraulic fracture will cross the cemented natural fracture in 3D is proposed. The successive node snapping scheme is adopted to construct conforming meshes for the evolving intersected curves between hydraulic and natural fracture surfaces, which only alters the location of a small fraction of nodes without changing the nodal connectivity. With this model, the evolution of fracture geometry after the hydraulic fracture intersects with the natural fractures of different toughness, size, orientation, and number is investigated. Because an extra dimension is considered, the fractures are allowed to propagate in more directions, resulting in a series of complex fracture geometries. The dynamic grid evolution method proposed in this work can promote the development of DDM in modeling fully 3D fracture networks in naturally fractured reservoirs.

The fractured basement gas reservoir in Yufutsu field was characterized by integrating static fracture information obtained from borehole micrtyo-resistivi images and dynamic information recorded during a massive hydraulic injection operation. Yufutsu gas reservoir is so called "fractured reservoir" seated in Cretaceous granite and Eocene conglomerate formation at around 4 - 5km depth in the Southern Ishikari Plain, central Hokkaido, Japan. One of the most important issues in the development of this reservoir is how to model the fracture system which contributes to the hydrocarbon migration. A massive hydraulic injection and microseismic monitoring operation was conducted in 2005 with an objective to delineate the spatial distribution of the fractures by stimulating pre-existing fractures. The injection schedule and anticipated areas of the stimulation were thoroughly designed and predicted by using a numerical simulator, which runs on a Discrete Fracture Network (DFN) model. The DFN model was created on the basis of fracture information obtained from borehole images. The injection of more than 5,600m3 of slick water, without any additives, effectively induced microseismic activities and accordingly improved the injectivity of the well. A preferential direction of the observed microseismic distribution showed a good consistency with the prediction. However, significant differences in the pressure responses were observed. These mismatches were fed back to modification of the model, which finally showed a reasonable match. Furthermore, a precise analysis of source locations and a focal mechanism analysis were applied to the representative microseismic multiplet events. Those two independent analyses revealed existence of two dominant orientations of the fracture system, which are consistent with the most likely orientations of shear slippages in the current stress condition around the injection well. Introduction One of the remarkable characteristics of the fractured reservoir is a wide variation of the well productivity. Many poorly productive wells and few highly productive wells are randomly distributed, which is a typical naturally fractured reservoir1. The wide variation in well-production is considered to be attributed to heterogeneity of fracture distribution. Therefore the delineation of spatial distribution of the fracture system contributing to the fluid flow is desired and challenging issue for optimal development of naturally fractured reservoirs. The Yufutsu oil and gas field is located in the Southern Ishikari Plain, central Hokkaido, in northern Japan. The reservoir, seated at around 4 km depth, is known as a so-called "fractured reservoir", where oil and gas have accumulated in cracks in the granite and overlying conglomerates.2 The rock itself has very little porosity and permeability. Space for the storage of gas/oil and paths for these hydrocarbons to move must be provided by various scales of fractures. Local variations in effective stress due to fault compartmentalization also can significantly impact reservoir production.3 Despite the extensive studies of the Yufutsu field, knowledge of the fracture network is limited around the boreholes. No reliable data of fractures away from the boreholes was available. The 2-D reflection seismic survey technique still does not have enough resolution to see fractures at 4km depth. This fact makes it difficult to delineate the overall fracture system and create a reliable reservoir model in this field. To challenge the issue and to gain more knowledge of the fracture system in the Yufutsu field, JAPEX conducted a massive hydraulic injection and microseismic monitoring experiment in May, 2005 by focusing the potential of microseismic monitoring as a tool for fracture delineation, which has been actively studied in a geothermal industry.4,5,6 JAPEX succeeded in inducing and recording thousands of microseismic events in the gas saturated reservoir and demonstrated the feasibility of this approach.

This paper presents an improved new reservoir simulation model. By applying reservoir engineering, numerical simulation, and fluid flow theory through porous media to the conditions of production engineering, and taking into consideration the triple medium of matrix, natural fracture, and hydraulic fracture for tight low permeable fractured gas reservoirs, the authors arrived at a comprehensive conclusion for the low non-Darcy and high non-Darcy flows. A corresponding solution model is also presented, made available through computer programming. The results derived from the fracturing reservoir software, developed specifically in this study for tight low permeable fractured gas reservoirs and which takes into account such various aspects as the direction of and influence of in situ stress, reservoir properties, natural fracture system, and hydraulic fracture length, show that the fracturing reservoir plan for the Xin Chang gas field has been worked out. The results prove that simulation software can work as a powerful tool to design a fracturing reservoir plan for tight low permeable fractured gas reservoirs.

ABSTRACT: The Changyuan block of Daqing oilfield in China has a shallow reservoir burial depth (<1000m), high permeability (>100mD), is in the late stage of development, and has a high water content (>95%). Hydraulic fracturing produced non-uniformly propagating horizontal fractures. At present, the mechanism and controlling factors of non-uniform propagation of horizontal fractures are not well understood. In this paper, based on the geological numerical model of Changyuan block, the non-uniform propagation of horizontal fracture is studied. The main conclusions are as follows: the horizontal fracture will expand in the direction of large fracture initiation stress difference (minimum horizontal principal stress - vertical stress); the main controlling factors for the non-uniform propagation of horizontal fracture are construction net pressure, temporary plugging distance, fracture initiation stress difference and its non-uniformity; with the increase of the fracture initiation stress difference non-uniformity, horizontal fractures increased flow conductivity, and the cumulative oil production volume will be increased. The micro-seismic monitoring results show that the non-uniform propagation law of horizontal fracture is in line with the actual situation. This is of great significance for the redevelopment of the shallow layer of the old oilfield. 1. INTRODUCTION At present, conventional shallow hyperpermeable reservoirs have entered the late stage of development, with high water content and very low oil recovery, and the remaining oil is mainly distributed in the reservoir with poor physical properties or imperfect injection and extraction zones. In order to realize the secondary development of high water content wells, it is necessary to carry out secondary utilization of residual oil. Hydraulic fracturing can be used to increase the mobility in the areas with poor physical properties and improve the injection and extraction relationship (Jintang Wang, 2019; Yanxin Lv, 2022; Chen B, 2022). Through experimental research and theoretical analysis, it is considered that the formation and propagation of hydraulic fractures are affected by many factors (Hou B, 2014; Li Q, 2015). In the early years, Warpinski (1987) pointed out that the horizontal stress difference, the relative angle relationship between hydraulic fractures and natural fractures, and the pumping pressure during fracturing would affect the formation and propagation of fractures based on the Mohr-Coulomb criterion. More laboratory experiments show that the propagation of hydraulic fractures is affected by the distribution of natural fractures in the reservoir, the original in-situ stress and the type of reservoir rock (Detournay E. 2016; Jia Y, 2016; Altammar, M. J., 2019). The shear strength of natural fractures and the magnitude of in-situ stress are related to the passage or cessation of hydraulic fractures (Blanton TL., 1982; Olson, J. E., 2012; Lei Q, 2022). At the same time, the mineral composition, Young ‘s modulus and tensile strength of reservoir rocks have an important influence on the morphology and effect of hydraulic fractures (Rickman, R., 2008; Zou, 2016; Huang, L., 2022). Numerical simulation is also an important method to study hydraulic fracturing. Finite element method (FEM) (Guo T, 2015; Ni, T, 2020), extended finite element method (XFEM) (Paul B, 2018; Zhou, Y., 2021), particle flow discrete element method (PFC) (Zheng H, 2020), finite-discrete element method (FDEM) (Shan Wu, 2022) and other methods are widely used to study the propagation of reservoir fractures (Songze Liao, 2024). Hu et al. (2021) conducted a two-dimensional XFEM simulation based on the Mohr-Coulomb yield criterion. The simulation results show that the influence of plastic deformation on fracture propagation cannot be ignored in the formation with large stress difference and friction angle. Zeng et al. simulated the fracture propagation process using XFEM based on Drucker-Prager criterion (Zeng Q, 2019). At present, Mohr-Coulomb criterion and Drucker-Prager criterion are widely used in elastoplastic rock constitutive models. The main difference between the two models is that the Drucker-Prager model considers hydrostatic pressure more comprehensively (Liu W, 2021).

Modeling and simulation of complex fracture network propagation with SRV fracturing in unconventional shale reservoirs