Optimizing Hydraulic Fracturing Treatment Integrating Geomechanical Analysis and Reservoir Simulation for a Fractured Tight Gas Reservoir, Tarim Basin, China

Abstract

Abstract" comprehensive geomechanical study was carried out to optimize stimulation for a fractured tight gas reservoir in the northwest Tarim "asin. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stimulation of natural fractures by shear slippage, creating a conductive, complex fracture network. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States." field-scale geomechanical model was built using core, well log, drilling data and experiences characterizing the in-situ stress, pore pressure and rock mechanical properties in both overburden and reservoir sections. "orehole image data collected in three offset wells were used to characterize the in-situ natural fracture system in the reservoir. The pressure required to stimulate the natural fracture systems by shear slippage in the current stress field was predicted. The injection of low-viscosity slickwater was simulated and the resulting shape of the stimulated reservoir volume was predicted using a dual-porosity, dual-permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. " hydraulic fracturing design and evaluation simulator was used to model the geometry and conductivity of the principal hydraulic fracture filled with proppant. Fracture growth in the presence of the lithology-based stress contrast and rock properties was computed, taking into account leakage of the injected fluid into the stimulated reservoir volume

Numerical Modeling of Variable Fluid Injection-Rate Modes on Fracturing Network Evolution in Naturally Fractured Formations

“…The average reservoir porosity is about 7% and the average permeability is about 0.07 mD. The gross reservoir thickness is about 180-220 m. Gui et al [8] have studied the geomechanical properties by a comprehensive use of core data, well log and drilling data, etc. Figure 2a is the statistical result of natural fractures developed in the gas play.…”

“…The combinations of these statistical characteristics that describe the geometrical properties of a DFN defined by the macro-scale connectivity and directional flow preference of the DFN are essential for the fluid transport characterization of an unconventional reservoir. According to the results from core data, well log data and drilling data [8], we developed the corresponding DFN model to represent the three natural fracture groups.…”

“…The orientation of the natural fractures has been converted according to direction of the simulations, the maximum horizontal stress (SHmax). The dimensions of the fractures have been converted by similarity criterion [1,8]. The model represents a 2D horizontal section of a reservoir with a laboratory scale.…”

“…The input material mechanical parameters for the numerical model are based on the work by Gui et al [8], the main parameters used for hydraulic fracturing were obtained by similarity criterion, as is shown in Table 1. For all the SHmax was 21.2 MPa, the simulations, the minimum horizontal stress (SHmin) was 20.5 MPa.…”

“…The injection rate and injection pressure along with viscosity of the fluid are the operational parameters that can be used to effectively design hydraulic fracturing. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity in some gas shale formations [1,7,8]. Currently, the general mechanism leading to the success of water fracturing in shale gas reservoirs is that a complex fracture network is created by stimulation of pre-existing natural fractures.…”