Generalization of Dual-Porosity-System Representation and Reservoir Simulation of Hydraulic Fracturing-Stimulated Shale Gas Reservoirs

Abstract

Recently, we have developed a new methodology to model hydraulic fracturing-induced fracture networks and subsequently simulate a shale gas reservoir as a dual-porosity system. The reservoir geological, geophysical and petrophysical characteristic data are integrated to build geological framework and property models. Microseismic responses are used to delineate stimulated reservoir volumes. Microseismic events and/or natural fracture intensity are utilized to estimate the initial intensity of this induced fracture network. The fracture intensity is further calibrated using hydraulic fracturing job data and reservoir geomechanical properties through a fracture propagation mechanism. In this paper, we show a significant extension of the modeling methodology to handle more general scenarios of stimulated shale reservoirs. We introduce a superposition technique to process the overlapping of microseismic mapping responses from different stages of "simul-frac" and/or "zipper-frac" operations in a single well or in multiple wells. The improved method takes into account different fracture network geometries. Various models for volume expansion by stimulation are investigated for proppant placement estimations. In the ideal viscous fluid-proppant transportation scenario, proppant and fracture conductivity distributions can be calculated with mass conservation corresponding to different fracture network geometries and volume expansion models. Both fracture intensity and fracture network conductivity are used to create dual porosity simulation model inputs. Considering that for most shale gas wells there is no microseismic data, we introduce a modeling procedure incorporating treatment data and geomechanical parameters in which the fracture network geometry can be specified based on well completion data and field experience. We also present the general workflow through a demo case from data input, fracture network geometry configuration, calibration and calculations, and output of dual-porosity model parameters for reservoir simulation. This extended methodology can be efficiently applied not only to modeling of singlewell shale gas reservoir but also to modeling of multiple wells where their drainage volumes are inter-connected. A field example demonstrates the applications of the new modeling methodology, which provides a unique, effective means for modeling and simulation study as well as history-matching calibration of stimulated shale gas reservoirs.

Exergy, Energy, and Gas Flow Analysis of Hydrofractured Shale Gas Extraction

“…After hydraulic fracturing, gas starts to flow from the highpressure low-permeability matrix to the formed lower-pressure high-permeability hydraulic fractures. The shale gas reservoir is usually [2,[37][38][39][40][41][42] assumed to be a "dual porosity" system, in which the matrix block and the fractures made in it are characterized by different (but constant) porosities and permeabiliies, treated therefore as two interconnected different porous media. The gas flow through them is typically assumed in the literature to be one-dimensional.…”

Simulation and Mathematical Modeling of Stimulated Shale Gas Reservoirs

“…This was done by matching experimental fracture permeability data with specific correlation data. Their study involved examining the effects of pressure-dependent natural fracture permeability on production from shale gas wells by selecting specific correlations from 29 Single porosity and dual-porosity models are compared 30 for assessing scenarios of a horizontal well producing gas and water, and geomechanical aspects were evaluated 31 for their impact on well performance. Although in situ stress affects the matrix and natural fracture permeability, it is also known to affect the created hydraulic fracture permeability.…”