Identifying Well Treatment Candidates and Strategies for Enhancing Hydraulic Fractures System Complexity

Abstract

One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity. In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance. The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant. This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible treatment scenarios applied to a wide range of reservoir and rock geomechanical properties. It shows that wells with certain combinations of Young's modulus, Poisson's ratio, stress anisotropy, and fracture gradients are not suitable candidates for creating complexity in the hydraulic fractures system.