Methodology for predicting reservoir breakdown pressure and fracture opening pressure in low-permeability reservoirs based on an in situ stress simulation

Abstract

Using numerical simulations of the paleostress field during the time of fracture formation, we predict the occurrence of fractures in the reservoirs of the second member of the Funing Formation in the Tongcheng fault zone, Subei basin, East China. We use sonic velocity measurements from rock cores and microseismic monitoring to determine the in situ stress, which is combined with fracture data to calculate the magnitude of the in situ stress at the well site. By determining the mechanical parameters of the rock, we use the finite element method (FEM) to develop a geomechanical model and conduct numerical simulations of the in situ stress field. Based on the occurrence of fractures and the numerical simulation results of the in situ stress field, we predict the opening pressure and opening sequence of natural fractures in the reservoirs. The results indicate that the maximum horizontal principal stress in the second member of the Funing Formation in the Tongcheng fault zone is oriented ENE. During the injection process, the ENE-trending fractures open first, and the ESE-trending fractures open later. The opening pressure of the fractures increases as the angle between the fracture strike and the maximum horizontal principal stress increases, and the burial depth of the fractures also has a relatively positive correlation with the opening pressure. At the structurally high site (1850 m–2350 m), the opening pressure of the fractures is in the range of 25 MPa–50 MPa, and at the structurally low site (3300 m–4000 m), the opening pressure of the fractures is in the range of 45 MPa–75 MPa. By calculating the actual fracture pressure of the reservoirs, we propose using different injection pressures in different blocks to ensure the high and stable production of oil from wells.