Unconventional reservoirs, such as shale-gas or tight-oil reservoirs, are generally highly fractured, including hydraulic fractures, stimulated and non-stimulated natural fractures of various sizes, embedded in lowpermeability formations. One of the main production mechanisms in unconventional reservoirs is the flow exchange between matrix and fracture media. However, due to extremely-low matrix permeability, the matrix/fracture exchange is very slow and the transient flow may last several to tens of years, i.e. almost the entire production life. The commonly-used dual-porosity modelling approach involves a computation of pseudo-steady-state matrix-fracture transfers with homogenized fluid and flow properties within the matrix medium. This kind of model clearly fails to handle the long-lasting matrix/fracture interaction in very-low permeability reservoirs, especially for multi-pahse flow with phase change problems. Moreover, a dualporosity model is not adapted for the simulation of matrix/fracture exchange when fractures are described by a DFN (Discrete Fracture Network). This paper presents an EDFM (Embedded Discrete Fracture Model) based on the MINC (Multiple INteracting Continua) proximity function to overcome this insufficiency of the conventional dual-porosity model.

No abstract

Unconventional gas resources from tight sand and shale gas reservoirs have received great attention in the past decade and become the focus of the petroleum industry as well as energy resources worldwide, because of their large reserves as well as technical advances in developing unconventional resources. Compared to conventional reservoirs, gas production in ultra-lowpermeability unconventional reservoirs is driven by highly non-linear flow equations and involves many coexisting processes due to the presence of multi-scale fracture networks, and to the heterogeneous nature of a porous/fractured and stress-sensitive rock. Therefore, quantifying flow in unconventional gas reservoirs remains a significant challenge.In this paper, we discuss a mathematical model and a numerical approach for simulating the production of unconventional gas reservoirs, in order to assess well performance and understand the critical parameters that affect gas recovery. Specifically, we consider the flow behavior in a stimulated reservoir volume (SRV) including a tight matrix and multi-scale fracture networks, namely primary hydraulic fractures, induced secondary fractures and micro-fractures. The feasibility and the limits in the use of single-porosity or dual-porosity reservoir models to simulate gas flow in such a system are discussed, and a multiporosity approach is evaluated. The impacts of various physics related to unconventional gas reservoirs, such as adsorption/desorption, Klinkenberg and geomechanical effects, are quantified.This work helps to improve simulation technologies for low-permeability unconventional gas reservoirs. An appropriate modeling approach actually underlies effective simulation tools for quantitative studies of unconventional reservoir dynamics and performance, taking into account multi-scale fracture impacts on gas production, well and stimulation design, and optimal production schedules in field development.

Summary The unconventional gas resources from tight and shale gas reservoirs have received great attention in the past decade and have become the focus of the petroleum industry. Shale gas reservoirs have specific characteristics, such as tight reservoir rock with nanodarcy permeability. Multistage hydraulic fracturing is required for such low-permeability reservoirs to create very complex fracture networks and therefore to connect effectively a huge reservoir volume to the wellbore. During hydraulic fracturing, an enormous amount of water is injected into the formation, where only 25–60% is reproduced during flowback and a long production period. A major concern with hydraulic fracturing is the water-blocking effect in tight formations caused by the high capillary pressure and the presence of water-sensitive clays. High water saturation in the invaded zone near the fracture face may reduce gas relative permeability greatly and may impede gas production. In this paper, we consider the numerical techniques to simulate during hydraulic fracturing the water invasion or formation damage and its impact on the gas production in shale gas reservoirs. Two-phase-flow simulations are considered in a large stimulated reservoir volume (SRV) containing extremely low-permeability tight matrix and multiscale fracture networks including primary hydraulic fractures, induced secondary fractures, and natural fractures. To simulate the water-blocking phenomenon, it is usually required to explicitly discretize the fracture network and use very fine meshes around the fractures. On the one hand, the commonly used single-porosity model is not suitable for this kind of problem, because a large number of gridblocks is required to simulate the fracture network and fracture–matrix interaction. On the other hand, a dual-porosity (DP) model may also be not applicable, because of the long transient duration with large block sizes of ultralow-permeability matrix. In this paper, we study the applicability of the MINC (multiple interacting continuum) method, and use a hybrid approach between matrix and fractures to correctly simulate the fracturing-fluid invasion and its backflow during hydraulic fracturing. This approach allows us to quantify the fracturing water invasion and its formation-damage effect in the whole SRV.