Transient Interporosity Flow in Shale/Tight Oil Reservoirs: Model and Application

Abstract

The dual-porosity model has been used widely to describe the fracture network in well test or numerical simulation due to the high computational efficiency. The shape factor, which can be used to determine the capability of mass transfer between the matrix and fracture, is the core of the dual-porosity model. However, the conventional shape factor, which is usually obtained under pseudo-steady state assumption, has certain limitation in characterization of the mass transfer efficiency in a shale/tight reservoir. In this study, a new transient interporosity flow model has been established by considering the influence of nonlinear flow, stress sensitivity, and fracture pressure depletion. To solve this new model, a finite difference and Newton iteration method was applied. According to the Duhamel principle, the solution for time-dependent fracture pressure boundary condition has been obtained. The solution has been verified by using the fine-grid finite element method. Then, the influence of nonlinear flow, stress sensitivity, and fracture pressure depletion on shape factor and interporosity flow rate has been studied. The study results show that constant shape factors are not suitable for unconventional reservoirs, and the interporosity flow in the shale/tight reservoir is controlled by multiple factors. The new model can be used in test interpretation and numerical simulation, and also provides a new approach for the optimization of the perforation cluster number.

Variability of Double-Porosity Flow, Interporosity Flow Coefficient λ and Storage Ratio ω in Dolomites

“…Several approaches to the problem have been developed since the publication of the original Warren and Root paper [2]. An extensive comparison of all the approaches was performed by Lim and Aziz [28], Lai and Pao [29] and, finally, Huang et al [16]. Most methods are based on an analytical or numerical value, multiplied by an inverse value of the equivalent fracture length; this length depends on the number of fracture sets.…”

“…The double-porosity concept was later extended to triple-porosity systems [6,7], where the porosities include the common porosities of the matrix and fractures, as well as the vugs, microfractures and any other cavities occurring in the rock. The original doubleporosity model of Warren and Root [2] has been updated by other authors [8], such as Water 2024, 16, 1072 2 of 10 Odeh [9], Kazemi [10,11], de Swaan-O [12] and Serra et al [13], with the introduction of well storage, skin effects [4,14], and other approaches. Reviews of pumping tests in fractured rocks, including data or discussion of the λ and ω, are scarce but have been presented by Gringarten [15] and Kruseman and de Ridder [5].…”

“…The novelty of this approach is to present and discuss the values of both parameters for the different types of dolomites. Some authors have studied both parameters explicitly in the field of oil reservoirs [16] and for two-phase flow (oil + water) [17]. Most studies presented new theoretical models for either pumping test curve behavior or for the determination of either shape factors, interporosity flow coefficients, or new pumping test models, but the range of the studied parameters is rarely given (e.g., in R. Aguilera's discussion of the Serra et al paper [13]).…”

The Effect of Slickwater on Shale Properties and Main Influencing Factors in Hydraulic Fracturing

“…In conventional sandstone gas reservoirs, the entry of fracturing fluid can cause reservoir damage, and the backflow of fracturing fluid should be accelerated as much as possible to achieve a higher backflow rate. The field results of shale gas reservoir show that the production effect is better by means of shut-in the well for a period of time and pressure control at the wellhead [9,10]. The relevant research results indicate that due to the high content of clay minerals in shale, microfractures will occur in the shale after the invasion of fracturing fluid.…”

Mechanisms of Stress Sensitivity on Artificial Fracture Conductivity in the Flowback Stage of Shale Gas Wells

“…Due to developed micro/nano pores and extremely low permeability, shale reservoirs usually have no natural productivity, so they cannot be developed economically and effectively unless the mode of "horizontal well + volumetric fracturing" is adopted [3]. In the process of shale reservoir fracturing, a large amount of fluid and proppant is injected into the reservoirs, and a complex artificial fracture network is formed to improve the permeability of the shale reservoir [4][5][6][7]. Shale gas wells cannot be formally put into production until soaking, flowback, and testing are performed.…”