Abstract:

A 3D geomechanical model of a hydraulic fracture treatment in the Horn River Basin was calibrated by comparing synthetic microseismic events to field data. Using this calibrated model, sensitivity studies were performed to determine the effect of geological parameters and operational variables on the resulting fracture geometry and microseismic response. Microseismic geomechanics was shown to be a reliable calibration methodology for this model because changes in hydraulic fracture geometry were reflected by changes in the microseismic calibration. The results show that the orientation of the DFN is a key parameter driving the microseismic response. When hydraulic fractures intersect natural fractures at high angles, the pre-existing fractures are stimulated more and exhibit a greater microseismic response. Application of the calibrated model to optimize completion changes is demonstrated by investigating the effect of several potential changes on fracture geometry.

Introduction

Hydraulic fracturing of horizontal wells has been an important factor in the development of low permeability formations such as shales (Gale et al., 2007). The high-pressure injection of hydraulic fracturing fluid creates tensile fractures which may connect with and activate natural fractures. Hydraulic fracture modeling requires close coupling between the hydraulic (fluid flow) and mechanical models. For tight formations, the geomechanical aspect of the model is even more important than in conventional reservoirs, because natural fractures can play an important role in production.

Hydraulic fracturing typically causes microseismicity, usually through shear deformation (slip) on natural fractures and bedding planes. This microseismicity is the only far-field measurement of fracture geometry, and can be used to calibrate geomechanical models of fracture geometry and proppant distribution.

This paper presents a case study in which a coupled hydraulic-geomechanical simulator (3DEC, Damjanac and Cundall, 2016) is used to simulate hydraulic fracture growth in a naturally fractured formation and predict the corresponding microseismicity. The mechanical model is constructed with principal stresses, pore pressure and mechanical properties obtained from well logs, and a Discrete Fracture Network (DFN) is embedded in the stimulated area. The evolution of the mechanical deformation during the hydraulic fracturing process is simulated, including both the creation of new (hydraulic) fractures and the activation of pre-existing natural fractures. The model is calibrated by comparing the synthetic microseismic (MS) events with the field data.

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