Development of an improved numerical model for fracture propagation in hydraulic fracturing of low-permeability formations using FracproPT software

Abstract

The primary technologies employed to access unconventional resources today are horizontal drilling and single or multi-stage fracturing. Micro-seismic data frequently corroborates that hydraulic fracturing in shale reservoirs generates intricate fracture networks due to complex geology and the activation of pre-existing natural fractures, which cannot be accurately represented by traditional planar bi-wing fracture models.''

This research utilizes a dataset of reservoir characteristics, petrophysical features, and fracture treatments to develop a novel, sophisticated simulation model that demonstrates enhanced techniques for optimizing oil and gas output. The primary factors examined that significantly influence fracture behavior are flow rate, kind of proppants, and fracturing fluid.

The fracturing behavior and its controlling and optimization are the primary components utilized to augment production. The FracproPT software demonstrates the impact of proppant, flow rate, and fracturing fluid.

A comparison between a real model and a simulation model is presented, as the production of the stimulated well can be improved through the implementation of superior simulation models in future well stimulation efforts.

The ideal final fracture therapy is defined by maximal fracture length, width, and height.''

The research shows laboratory data for multiple fracturing fluids exhibiting varying surface activities, which were pumped into the assembly chamber. Recent fracture therapies have effectively employed a slick water formulation including water and dry polymer, with or without the inclusion of surfactant (Tri-ethanol Amine - TEA). This study evaluates commonly used surfactants and a microemulsion technology.

Simulation results indicate that the ideal fracture shape and conductivity, constrained by pumping limitations, are achieved at an injection rate of 100 bpm, a gel loading of 50 ppg, and a proppant size of 20/40 mesh sand. This paper enhances comprehension of fracture behavior in reservoirs and acts as a reference for optimizing hydraulic fracturing techniques.