Pre-Drill Pore Pressure and Fracture Gradient Prediction Based on Pressure Cell Models for Onshore Unconventional Gas, Sichuan Basin, China

Abstract

Abstract Prediction methods for pore pressure (PP) and fracture gradient (FG) developed for conventional resources include the use of normal compaction trends derived from correlations of log-based porosity with vertical effective stress (VES) and translation of pressures from offset wells to prospect locations using fluid densities and contacts. These techniques are less effective in unconventional plays like tight sands and shales because of disconnected fluids and difficulties in distinguishing PP from gas effects on the shale resistivity and compressional sonic velocities typically used for determining porosity. Unconventional resources require alternative prediction techniques such as pressure cell models, in which individual formation layers exhibit either constant overpressure (OP, difference between PP and hydrostatic pressure) or constant VES (difference between overburden stress and PP). Direct measurements from pressure gauges or estimated pressures from drilling indicators such as connection gases and kicks are used to calibrate the amount of OP or VES for each layer or pressure cell. The modeled pressures are translated to specific well locations by adjusting for differences in stratigraphic depth following either constant OP (typical for permeable formations) or constant VES (for tight formations). Fracture gradients are calculated from the PP forecasts based on horizontal-to-vertical effective stress ratios (ESRs) calibrated against total horizontal stresses determined from field data such as leak-off tests and drilling losses. Pressure cell models developed for the Sichuan Basin and evaluated against subsequent drilling experience indicate that: (1) consideration of all available offset data in combination with local geology is required to determine whether constant OP or constant VES is appropriate for each formation layer; (2) pressure-cell values can vary with both depth and area; (3) different ESRs are required for different lithologies and for depleted versus virgin pressures; and (4) all available field data (not only the nearest offset well) needs to be considered to provide realistic lower and upper bounds on PP and FG. The pressure-cell techniques described here can be calibrated with local field data and applied to unconventional resources worldwide to provide an effective method for predicting PP and FG in environments where conventional PP-FG prediction methods break down. Introduction Prediction methods for pore pressure (PP) and fracture gradient (FG) developed for conventional resources include the use of normal compaction trends derived from correlations of log-based porosity with vertical effective stress (VES) and translation of pressures from offset wells to prospect locations using fluid densities and contacts (Bowers 1995; Purkayastha et al. 2014). These techniques are less effective in unconventional plays like tight sands and shales because of disconnected fluids and difficulties in distinguishing PP from gas effects on the shale resistivity and compressional sonic velocities typically used for determining porosity (Couzens-Schultz et al. 2013).