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Unconventional oil and gas resources have large reserves and are difficult to develop. Reservoir fracturing is a key technical means for the development of unconventional oil and gas resources. Natural fractures and induced fractures are irregular and complex. To address the issue that existing fracture characterization methods cannot accurately depict the true shapes and width variations of fractures, a method based on unstructured PEBI grids for characterizing irregular and complex fractures was proposed. First, a natural fracture characterization process based on PEBI grids was established, allowing for accurate characterization of natural fractures in any region or a specified area. Second, a characterization and optimization method for induced fractures based on Delaunay triangulation and PEBI grids was developed, analyzing the impact of grid size and optimization iterations on fracture characterization accuracy. Third, a method for characterizing non-planar fractures using unstructured grids was established, enabling the depiction of curved fractures, making the fracture morphology and distribution more consistent with actual conditions. Fourth, a method for characterizing non-uniform fracture width was proposed, achieving fine characterization of fractures with non-uniform distribution of width and conductivity along the same fracture. Fifth, a complex fracture network characterization method coupling irregular induced fractures and irregular natural fractures in the whole area and specified regions was realized. For fracture network characterization under complex conditions such as large-scale intersections of natural and induced fractures, non-uniform fracture width distribution, and non-planar frac- tures, adjusting the number of grid optimization iterations could improve the quality of the fracture network characterization. Utilizing the advantage of PEBI grids to flexibly and accurately approximate complex fracture boundary conditions, this method enabled the rapid and accurate handling of a large number of irregular natural and induced fractures. The developed method for characterizing irregular and complex fractures helps improve the accuracy of fracture network characterization and numerical simulation calculations in unconventional oil and gas reservoirs.

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The results of the second trial production of the gas hydrate reservoir in the Shenhu area of the South China Sea show that the production of a gas hydrate reservoir by horizontal wells can greatly increase the daily gas production, but the current trial production is still far below the minimum production required for commercial development. Compared with a single horizontal well, a fishbone well has a larger reservoir contact area and is expected to achieve higher productivity in the depressurization development of gas hydrate reservoirs. However, there is still a lack of systematic research on the application of fishbone wells in Class I gas hydrate reservoirs. In this paper, a grid system for gas hydrate reservoirs containing fishbone wells is first established using the PEBI unstructured grid, and fine-grained simulation of reservoirs near the bottom of the wells is achieved by adaptive grid encryption while ensuring computational efficiency. On this basis, Tough + Hydrate software is adopted to simulate the productivity and physical field change of a fishbone well with different branching numbers. The results show that: the higher the number of branches in a fishbone well, the faster the free water production rate, reservoir depressurization, and free gas production rate in the initial stage of depressurization development, and the faster depressurization can effectively promote hydrate dissociation. Compared with a single horizontal well, the cumulative gas production of a six branch fishbone well can increase by 59.3%. Therefore, using multi-branch fishbone depressurization to develop Class I gas hydrate reservoirs can effectively improve productivity and the depressurization effect, but the hydrate dissociation will absorb a lot of heat and lead to a rapid decrease in reservoir temperature and hydrate dissociation rate. At the end of the simulation, the hydrate dissociation rate of all schemes was lower than 50%. In the later stage of depressurization development, the combined development method of heat injection and depressurization is expected to further provide sufficient thermal energy for hydrate dissociation and promote the dissociation of the hydrate. [ABSTRACT FROM AUTHOR]

Mesh generation lies at the interface of geological modeling and reservoir simulation. Highly skewed or very small grid cells may be necessary to accurately capture the geometry of geological features, but the resulting poorly scaled or small grid cells can have a substantial negative impact on simulator accuracy and speed. One way to minimize numerical errors caused by gridding complex structures is to simulate on high-quality Voronoi meshes, which reduce grid orientation effects in fluid flow. This work presents a complete methodology to create Voronoi simulation grids, model fluid flow in complex geological systems, and visualize the results. A recently developed Voronoi meshing method that can automatically generate provably good unstructured meshes that conform to input surfaces creating closed volumes is used. Initially an analytical benchmark simulation is presented to validate the quality of the meshes and simulation results and demonstrate the superiority of simulation results using Voronoi meshes over flexed-hexahedral meshes on a domain with internal features. Next, meshes are created for test structures representing four of the most common geological features in the subsurface: layering, pinch-out, an interior lens that tapers to zero thickness on all sides and a fault with offset. Two benchmark flow simulations are run for each test structure. Finally, a realistic geological example for CO 2 injection into an anticline is simulated. Three realizations of the Voronoi mesh at the same resolution are generated for the simulations. Each mesh is highly refined near the injection wells and coarse in areas of less interest. These three meshes are used to model the CO 2 plume in the subsurface as it migrates to the top of the structure and then fills downward. Simulations on the meshes with randomly generated elements inside the input volumes each give slightly different fingering patterns for the viscous-unstable buoyant gas flow. The results presented in this work show a promising step towards utilizing fully automated Voronoi meshing for subsurface flow simulations in complex geology. [ABSTRACT FROM AUTHOR]

Complex fracture systems including natural fractures and hydraulic fractures exist in shale gas reservoir with fractured horizontal well development. The flow of shale gas is a multi-scale flow process from microscopic nanometer pores to macroscopic large fractures. Due to the complexity of seepage mechanism and fracture parameters, it is difficult to realize fine numerical simulation for fractured horizontal wells in shale gas reservoirs. Mechanisms of adsorption–desorption on the surface of shale pores, slippage and Knudsen diffusion in the nanometer pores, Darcy and non-Darcy seepage in the matrix block and fractures are considered comprehensively in this paper. Through fine description of the complex fracture systems after horizontal well fracturing in shale gas reservoir, the problems of conventional corner point grids which are inflexible, directional, difficult to geometrically discretize arbitrarily oriented fractures are overcome. Discrete fracture network model based on unstructured perpendicular bisection grids is built in the numerical simulation. The results indicate that the discrete fracture network model can accurately describe fracture parameters including length, azimuth and density, and that the influences of fracture parameters on development effect of fractured horizontal well can be finely simulated. Cumulative production rate of shale gas is positively related to fracture half-length, fracture segments and fracture conductivity. When total fracture length is constant, fracturing effect is better if single fracture half-length or penetration ratio is relatively large and fracturing segments are moderate. Research results provide theoretical support for optimal design of fractured horizontal well in shale gas reservoir. [ABSTRACT FROM AUTHOR]

Klinkenberg number is not constant in tight- and shale-gas reservoir. We first derived an expression of b / p in Klinkenberg apparent permeability correlation based on Knudsen number, which is a function of µ / p in an isothermal shale-reservoir system. For pressure in [15 MPa, 30 MPa], µ / p changes slowly and is very small, and the permeability correction factor is 1.15 for 17 MPa, 1.14 for 20 MPa, 1.12 for 28 MPa for the case in this paper. To characterize the physics of multi-transport mechanisms, and gas adsorption and desorption, a mathematical model for flow in tight- and shale-gas reservoirs with wellbore storage effect is used to understand transient pressure response. A full implicit numerical simulation based on PEBI gridding is developed to quantify the transient pressure behaviors for flow in tight- and shale-gas reservoirs. Based on numerical results, we firstly find that the adsorption makes the curves of the bottom-hole pressure (BHP) have a seeming singular point. The intrinsic permeability determines the position of the seeming singular point, and the ultimate adsorption capacity (UAC) determines the size of the angle around the seeming singular point. Because the turning points appear at early time flow, the position and angle of the seeming singular point may give us an economic and quick methodology to approximately estimate the UAC and intrinsic permeability for the tight- and shale-gas reservoir. This phenomenon can help us to understand the behavior of the flow in tight- and shale-gas reservoir better. [ABSTRACT FROM AUTHOR]

Natural gas in unconventional gas reservoirs typically contains multiple gas components. Existing models incorporate either the unique flow mechanisms in tight and shale gas reservoirs (slip flow) or multi-component sorption isotherm without combining them. In this work, we developed a compositional flow code incorporating slip flow and multi-component sorption using the extended Langmuir isotherm (EL). The model was discretized using finite volume method based on unstructured Perpendicular Bisection (PEBI) grids for their local orthogonality and flexibility in handling irregular shaped domain. The code was verified using ECLIPSE-CBM for multi-component sorption and using ECLIPSE with modified transmissibility for slip flow calculation. The model was further validated by reproducing the pressure build up data during well shut-in period in a tight gas reservoir in Xinjiang, China. The developed code was used to understand and quantify the importance of multi-component EL isotherm and slip flow. The evolution of the bottom-hole pressure (BHP), sorption volume, and gas composition was also simulated under various reservoir conditions including different initial gas compositions, sorption capacities, and reservoir sizes. The deviations caused by representing shale gas as pure methane using single-component Langmuir isotherm can reach as much as 90% for BHP and 45% for sorbed volume if the initial methane composition was 80%. The predicted produced gas composition with the EL isotherm showed a unique constant composition (CC) stage before the gas flow reached the domain boundary, indicating the potential use of gas composition as another type of data to infer reservoir boundary and flow regimes. The developed code offers a powerful tool to understand gas flow and sorption, as well as an analyzing tool to identify reservoir boundary and flow regimes compared to traditional well test method, which requires expensive measurements of BHP. [ABSTRACT FROM AUTHOR]

With the development of deep learning algorithms, neural networks (NNs) have been widely used in physics, computer science, and other fields. Solving partial differential equations (PDEs) based on NNs is one of the research hotspots. The existing methods can be divided into two categories: one is data-driven method, and the other is physics-constrained method. Physical-constrained method is more popular due to the convenience of constructing NNs and excellent generalization ability. However, the physical-constrained method cannot ensure the solution precision when PDEs are more complex, such as seepage equations with source and sink terms. In this paper, an improved physics-constrained PDE solution method is proposed that incorporates potential features of the PDE in the loss functions. A gradient model is proposed to describe the potential feature based on spatial pressure distribution, which can be used as the additional signpost to guide NNs to approximate PDEs. The gradient models are described as special neurons that are added into the hidden layer of the NN. Based on the new ideas, the seepage equation is well solved without using any exact solutions. The effectiveness of the proposed method is verified by numerical simulation results based on PEBI grid. • An improved PDE solution method is proposed based on physics-constrained neural network. • A gradient model is proposed based on spatial distribution features to help signpost neural network (SNN) converge. • SNNs reduces the network parameters required to achieve the local minimum and improves the solution accuracy. [ABSTRACT FROM AUTHOR]

During the process of fracture parameters optimization by numerical simulation, the fracture parameters determination, such as half fracture length, conductivity and number of fractures, dependent primarily on the changes of daily output curve or accumulative production curve. We identify the point where the change trend becomes weaker and take the inflection point as the optimal parameters. But the similarity of each change trend at the optimal parameters point, it is difficult to accurately determine which one is the best. Different people lead to different optimal results. After analyzing the rules of curve decline rate, transferring the dynamical production data by introducing the K-value method, optimal fracture parameters could be obtained intuitively. On the basis of curve treated by K value method the optimal parameter range can be determined, which could eliminate errors caused by the human factor. [ABSTRACT FROM AUTHOR]