Simulation and optimisation of hydraulic fracturing and flowback in unconventional reservoirs: A case study in the Cooper Basin, South Australia

Abstract

This thesis presents and discusses the results of simulation and optimisation of hydraulic fracturing and flowback design in unconventional reservoirs using a case study from the Cooper Basin, South Australia. The Cooper Basin has a very large raw recoverable gas from unconventional gas resources estimated to be up to 187 trillion cubic feet. These resources are locked away in unconventional gas reservoirs such as tight sand, shale gas and deep coal seam gas. Hydraulic fracturing is a key technical approach to economical extraction of gas from these reservoirs. Hydraulic Fracturing has been used throughout the Cooper Basin as a method of gas extraction for several decades. However, there are numerous problems which have not yet been fully addressed leading to a sub-optimal gas production and higher operational costs which, typically, represents nearly half of the total project cost. Also, the downturn in the pricing of oil and gas over the past few years requires production companies to optimise their production methods in order to increase the volume of production without significantly increasing costs so as to remain competitive in the market. Extraction of gas from the Cooper Basin therefore demands proper data analysis and selection of wells to be undertaken carefully to achieve the best results. In this thesis, the following key issues are addressed for the optimization of hydraulic fracturing and flowback in the Cooper Basin: 1. The complexity of the stress regime is believed to be the main reason for the failure in some hydraulic fracturing operations in the Cooper Basin, as the stress can alternate between strike-slip, reverse and normal regimes along the wellbore. To better understand the complex stress, a validated Mechanical Earth Model (MEM) is developed using petrophysical log data. Then, the model was tuned by Diagnostic Fracturing Injection Test data to find a reliable in-situ stress and rock mechanical validate the modelling of hydraulic fracturing and flowback using generalised reduced gradients or nonlinear solving method. 2. Using an integrated simulation method and using advances in data analysis, a 3D planar hydraulic fracturing model integrated with a reservoir flow simulation is constructed for a tight sands in the Cowralli Field in the Cooper Basin and flow-back was predicted. 3. Because of pre-existing natural fractures and the complex stress regime, there is usually high Near-Wellbore Pressure Loss (NWBPL) and pressure dependent leak-off during hydraulic fracturing. In this thesis, tortuosity around the wellbore was found as the main reason and linked to 3D hydraulic fracturing simulation. 4. Using Discrete Fracture Network (DFNs) model, the well trajectory was optimized such that the interaction with pre-existing natural fractures are maximized. This optimised well placement was found to generate up to six times greater stimulated reservoir volume compared to the base model (without considering pre-existing natural fractures) 5. Alternatives to water-based fracturing fluid, Liquefied Petroleum Gas (LPG) and foam have also been used in the fracture propagation model and coupled with multiphase flow simulation and the optimized scenario was investigated. This thesis is presented in a “combination” form between conventional and publication formats. As such, it contains several peer reviewed publications, together with detailed chapters that describe the mathematical theory behind hydraulic fracturing and a comprehensive review of the Cooper Basin case study.