Fracture Network Conductivity Research Articles

Experimental investigation of proppant settling in complex hydraulic-natural fracture system in shale reservoirs

The general development mode of shale gas reservoirs, as an unconventional resource, cannot yield good results. Hydraulic fracturing is a widely used method in the development of unconventional reservoirs. This method’s nature is to create hydraulic fractures in the reservoir, providing a flow path for oil and gas. To achieve a satisfying output, fracture dimensions matter greatly, as well as the fracture effective period. Maintaining these parameters requires that proppant can be distributed in fracture systems abundantly and evenly such that reservoirs can have durable fractures with good conductivity.Shale gas reservoirs have small porosity and permeability. Gas contained in them is difficult to exploit; thus, massive stimulation methods are needed. Conventional fracturing usually aims to create a long single planar fracture in a reservoir, while in shale gas reservoirs, complicated fracture networks are needed. Thus, the fracturing method in shale gas reservoirs should take natural fractures into consideration, link original micro-fractures in the reservoir, and increase the drainage area as much as possible. This type of fracturing method is called volume fracturing. Volume fracturing can also create multiple artificial fractures perpendicular to the main fracture, improving the stimulation effect and extending the stimulation effective period.Proppant distribution is critical to maintaining fracture network conductivity and enhancing a shale gas reservoir’s output. Moreover, proppant migration and settling during fracturing can affect the activation of natural fractures and the formation of fracture networks greatly, as well as the final effective fracture geometry. The body of research concerning proppant’s distribution law in conventional single fractures is quite mature, but the distribution law in complicated fracture networks has not been thoroughly elucidated. Obviously, the current understanding cannot satisfy the demand of practical stimulation. This paper considers the difference of the proppant distribution law between complicated fracture networks and conventional fractures and uses a self-designed complex fracture network simulation device to study proppant migration and the settling law in a complicated fracture network. The research results provide theoretical support for fracturing design in shale gas reservoirs.

Scaling solutions for connectivity and conductivity of continuous random networks.

Connectivity and conductivity of two-dimensional fracture networks (FNs), as an important type of continuous random networks, are examined systematically through Monte Carlo simulations under a variety of conditions, including different power law distributions of the fracture lengths and domain sizes. The simulation results are analyzed using analogies of the percolation theory for discrete random networks. With a characteristic length scale and conductivity scale introduced, we show that the connectivity and conductivity of FNs can be well described by universal scaling solutions. These solutions shed light on previous observations of scale-dependent FN behavior and provide a powerful method for quantifying effective bulk properties of continuous random networks.

Equivalent channel network model for permeability and electrical conductivity of fracture networks

It is remarkable that the permeability k and electrical conductivity σ of saturated, fractured rock exhibit a power law relationship with exponent r as pressure is applied to the rock. To understand this behavior, the fracture network is viewed as a collection of connected, planar fractures. This allows the construction of algebraic expressions for the transport properties of the fracture network, in which the local effective properties, namely, the hydraulic aperture dh and the electric aperture de of the representative planar fracture (the “equivalent channel”), are distinguished from the network properties (e.g., fracture connectivity) parameterized by the tortuosity factors τh and τe. This “equivalent channel network model” reproduces the observed power law behavior on the conditions that dh3 ∝ der and τh ∝ τer over the range of applied pressures. The first condition is met, as demonstrated by calculations for a variety of simulated planar fractures using the Reynolds equations for fluid and current flow. The value of the exponent r is found to indicate the degree to which the fracture resembles a porous medium but cannot otherwise identify fracture surface or aperture characteristics. No direct evidence currently exists to support the second condition; however, such a power law relationship has been demonstrated elsewhere for simulated porous media.