Estimation of Fracture Height in Tight Reserviors via a Finite Element Approach

Abstract

In tight reservoirs, the rock formations are typically less porous and permeable, which makes it more difficult for hydrocarbons to flow through them. In addition to length and conductivity, the height of a fracture is another critical parameter of the hydraulic fracturing treatments in unconventional tight/shale formations, which determines the stimulated reservoir volume. If the fracture height is too shallow, the volume of rock exposed to the fluid and proppant may not be sufficient to improve the reservoir’s production significantly. Conversely, if the fracture height is too deep, the injected fluid may not be able to propagate high enough to reach the desired formation. However, after years of research, fracture height has often been simplified in traditional or recent studies of fracture simulation and estimation. The objective of this work is to propose an innovative way to simulate the hydraulic fracturing process in both horizontal and vertical directions in tight formations with a well-built finite element numerical model. Fracture toughness KIC is calculated based on the Brazilian test. Vertical fracturing fluid was also considered, and the model was validated by fracture height monitoring data from a stimulated well in the Montney formation. The influence of rock and fluid properties on the fracture height propagation was studied thoroughly with sensitivity analysis. The results indicated the fracture height prediction model was in good accordance with the monitoring data collected from the field, with an error margin of 7.2%. Sensitivity analysis results showed that a high Young’s modulus led to a larger stress intensity factor at the fracture tip, thus further advancing the fracture. Minimum horizontal stress also tends to facilitate the fracture to propagate. The influence of Poisson’s ratio and fluid viscosity on fracture height propagation was also investigated.