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

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.Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 201

Experimental and simulation study of foam stability and the effects on hydraulic fracture proppant placement

Foam has previously been used as fracturing fluid; however, there have not been enough study on foam stability and its effectiveness on proppant placement during hydraulic fracturing. In this paper, an experimental study was performed using free drainage method at 90 °C. Then, the rheological characterization of foam was produced based on dynamic foam quality change during foam drainage experiments and also based on viscosity breakdown by disproportionation. Subsequently, a 3-D hydraulically fracturing simulation was developed to evaluate the foam performance as a fracturing fluid using different vertical well scenarios. The results show that foam stability is dependent not only on the overall treatment time but also to fracture closure on proppant. For example, longer closure time accelerate proppant settling and accumulation at the bottom of the fracture, lowering propped area, and reducing productivity. The simulation results indicate that this lower productivity can be attributed to the final propped area, proppant distribution confirming the relationship between foam stability, foam rheology, proppant transport and fracture effectiveness

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures