Abstract

This study analyzes in detail the different pressure depletion patterns occurring when the effective conductivities of the various hydraulic fractures in a stage are different. Currently prevalent modeling practice commonly assigns the same fracture conductivity to the fractures in each stage, assuming uniform contributions to the production of the well. Recent studies, however, have shown that geomechanical stress shadowing effects during the fracturing of rocks with high horizontal stress anisotropy may result in considerable spatial variation of hydraulic fracture quality. For example, in a stage with three clusters, only one "super-fracture" may consume the entirety of the injected fluid, and the created fracture performance will significantly differ from the intended completion design. Our study shows that the drained rock volume (DRV) and pressure drawdown patterns around individual hydraulic fractures may significantly vary, depending upon the conductivity of the hydraulic fractures. We use both a numerical reservoir simulator (CMG) and a Eulerian particle tracking model, based on complex analysis methods (CAM). Our study shows that the fluid flux from individual hydraulic fractures may spatially vary, mainly due to fracture interference, even when the fracture conductivity is the same. A field example from the Eagle Ford shale play is presented. This systematic study leads to a better understanding of the effects on well performance of either variable or constant hydraulic fracture conductivities within the same fracture stage (e.g., due to even or uneven proppant concentration). Our results can be applied to wells from any unconventional play to better manage the DRV, based on fracture treatment design and execution quality (e.g., perforation and proppant placement), and improve the fracture treatment plan accordingly. Ultimately, the findings reported here can be used to mitigate the adverse impacts of flow interference in closely spaced hydraulic fractures.

1. Introduction

The development of unconventional shale reservoirs has increased rapidly due to the technological advancements in multi-pad horizontal drilling with numerous transverse hydraulic fractures. The hydraulic fractures enhance the conductivity of the reservoirs previously deemed uneconomic due to their low permeability. However, even with closely spaced hydraulic fractures, the recovery factor of unconventional shale reservoirs remains extremely low (e.g., as low as ~4% for Midland basin wells; Khanal et al., 2019). The low recovery factor for hydraulically fractured unconventional wells can partly be attributed to water oil ratios of 3 or higher in certain shale wells, but is also due to highly complex and unpredictable interactions of hydraulic fractures competing for fluid withdrawal from the drainage space. The determination and optimization of hydraulic fracture geometry, the distribution of the proppant within the fractures, the number of producing fractures, effective fracture half-lengths/conductivity and other attributes remain key concerns in the oil and gas industry.

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