Rock deformation is an important mechanism in shale reservoirs and occurs simultaneously with gas flow during the production period. It may not only result in production variation, but also have an impact on reservoir flow behaviors. Accurate simulation of gas flow in deformable reservoirs is challenging considering dual porosity structure of shale reservoirs. Besides, the complex fracture network topology and interactions further complicates the simulation of the fracture system. In this work, we implement a discrete fracture model (DFM), in which the reservoir is divided into the matrix and fracture system. The DFMs use flexible Delaunay triangulation to represent individual fractures, hence they could handle complex fracture network. Based on the comprehensive study of the deformation of matrix and fracture, a flow model that considers rock deformation is presented to predict well production and reservoir dynamics. Numerical simulations are conducted to investigate the influence of rock deformation on a reservoir with complex fracture network. Results under no deformation (ND) condition and integrated deformation (ID) condition show that rock deformation has an obvious impact on the gas production and the pressure distribution. The percentage of production loss increases with reservoir pressure, while decreases as matrix permeability or fracture conductivity increases. Comparisons of production loss caused by the individual deformation depict that the natural fracture deformation (NFD) is dominant, the hydraulic fracture deformation (HFD) is minor, while the matrix deformation (MD) is negligible. Less percentage of production loss caused by the ID is observed than the sum caused by the NFD, the HFD, and the MD.

Nowadays horizontal wells, combined with hydraulic fracturing technology, have been widely used to produce tight gas at an economic rate. The production performance of the horizontal well can be predicted by analytical or numerical models. In most models, the horizontal wells are assumed to be fractured by bi-wing fractures. However, recent micro-seismic measurements depict a dendritic-like morphology of hydraulic fractures in tight gas reservoirs. This indicates the conventional fracture models are sometimes inapplicable for tight gas simulation.In this paper, a modified off-center well model was coupled in the discrete fracture model (DFM) to predict the production performance of dendritic-like stimulated horizontal wells. Finite volume method was used to discretize the partial differential equations, and the linearized equation system was solved iteratively in a fully implicit scheme. The off-center well model was verified against ECLIPSE. A field case of multi-stage fractured horizontal well from a shale gas reservoir was studied.In addition, the effects of some fracture geometric parameters (e.g., fracture angle, fracture asymmetry and fracture branch number) on well production were investigated in detail. Results show that fracture angle has high relevance to the production performance in that cumulative production tends to be higher with more evenly distributed angles. Fracture asymmetry seems to have little influence upon the production. Fracture branch number has a strong influence on enhancing gas production, but the influence becomes weaker with increasing branch number. This paper provides us a better understanding of dendritic-like fractured gas reservoirs.

Most fracture patterns near the well region are more fickle in tight gas field than that in literature. In this paper, a modified discrete fractured well model is presented to account for dynamic characteristics of a vertical well with multiple asymmetrical fractures (MAF). Fracture closure effect is also coupled in the revised numerical model, leading to a more rapidly loss of gas production. The productivity of a vertical well with MAF is investigated by comparing to a fractured well with one single equivalent fracture (EF). Furthermore, the effect of fracture conductivity on cumulative production is discussed. Results show that EF representation can cause up to 45.4 percent less production than MAF. Fracture conductivity is proved to be closely related to cumulative production.

针对致密油气开发中的复杂裂缝 ,提出了采用PEBI网格表征水力压裂中不同类型裂缝(裂缝与水平井筒轴线垂直、裂缝沿水平井筒轴线方向 ,以及裂缝与水平井筒轴线成一定角度)的方法.基于PEBI网格及有限体积离散 ,研发了水平井多段压裂数值模拟程序 ,通过解析解验证该程序对水平井多段压裂的产能分析结果的准确性.以新疆油田某井为例 ,设计多种压裂方案 ,分别计算每种压裂方案下的产能 ,在此基础上 ,给出压裂优化方案建议.考虑到水力裂缝的时效性 ,选取一年内的产能数据 ,模拟计算了180 d生产数据 ,模拟结果与半年内实际油产量递减规律一致.

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 mu/p in an isothermal shale-reservoir system. For pressure in [15 MPa, 30 MPa], mu/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. (c) 2014 Elsevier B.V. All rights reserved.

复杂的流动机理、水平井与多段压裂的开发技术,导致页岩气数值模拟更为复杂。根据水平井及裂缝周围的流动特征,提出了多段压裂水平井的PEBI网格划分方法,即裂缝及水平井两端的扇形区域按径向流规律布点,裂缝及水平井的其它部位按线性流进行布点。将页岩简化为均匀介质,建立了耦合井储的数学模型,并基于全隐式离散格式进行了数值模拟。数值计算表明,多段压裂的水平井裂缝流动特征明显,在线性流阶段压力降落与压力导数曲线平行。在流动由线性流转为拟径向流后,曲线出现径向流特征,径向流特征的维持时间与油藏区域的大小相关。

Flow mechanism of shale gas is complex and key development technology is multi-stage fractured horizontal well, which increase the complex of the numerical simulation. According to the flow characteristics near the fracture and horizontal well, a meshing method is proposed. The grid points are distributed radically in sector near the end points of the well and fractures, and distributed horizontally near the other part of the well and fractures. Without considering the mechanisms of desorption and diffusion, a fully implicit gas model is proposed coupling with the well storage. Numerical simulation shows that during the linear flow near the fractures, pressure change is parallel to its derivative. Duringthe tran-sition the linear flow is converted to pseudo radical flow.