Enhanced Gas Recovery Using CO2 Foam Fracturing Fluid in Tight Gas Reservoirs in the Cooper Basin
NICHOLLS, Sophie, QAYYUM, Muhammad, WOODWARD,Callum
Engineering Honours 2015
Australian School of Petroleum
University of Adelaide
Hydraulic fracturing is commonly used to stimulate production from tight gas reservoirs. During a hydraulic fracture treatment some of the fracturing fluid will leak-off from the fracture and invade into the reservoir. In tight gas reservoirs the invaded fracturing water may cause damage to reservoir permeability and fracture conductivity. Consequently, the use of water based fracturing fluids in tight gas reservoirs may limit the potential well productivity and result in long
The Cooper Basin is Australia's primary source of onshore gas production. Water-based hydraulic fracturing fluids have been used in the Cooper Basin since 1968 to stimulate gas wells. The purpose of this study is to determine the applicability of CO2 foams to enhance production and improve flow-back in tight gas reservoirs in the Cooper Basin.
Historically most hydraulic fracture treatments in the Cooper Basin, Australia have used a water based fracturing fluid with a crosslinked gel. There are number of alternatives to water-based fracturing fluid that could potentially be used to enhance productivity. CO2 foams has been used successfully in tight gas reservoirs in Canada, USA and Europe to reduce the amount of damage to the reservoir permeability and fracture conductivity as well as accelerate the flow-back of the fracturing fluid.
The aim of this project was to determine the feasibility of using CO2 foam fracturing fluid for tight gas reservoirs in the Cooper Basin. To achieve this, issues with water-based fracturing fluids in the Cooper Basin were investigated and previously conducted CO2 fracture treatments were modelled. 3D hydraulic fracture models were built in GOHFER to determine fracture properties including size, proppant distribution and fluid leak-off for two tight wells in the Cooper Basin. IHS WellTest was used to analyse diagnostic fracture injection tests and validate reservoir properties in GOHFER. The fracture results from GOHFER were input in Eclipse to investigate the stimulated production pro les for the fractured well. Sensitivities were run in GOHFER and Eclipse by varying fracture treatment parameters and fracturing fluids to determine the impact these variables had upon fracture properties, well productivity and clean-up volumes.
It was discovered that CO2 foam can be used to increase the fracture length and well productivity in tight gas reservoirs in the Cooper Basin when compared to conventional water-based fracturing fluids. However, it was observed that the flow-back volume was not improved with the use of CO2 foam; there is uncertainty in this result due to restrictions imposed by the modelling software. From the sensitivity analysis performed the optimum CO2 foam quality, for use in the Cooper Basin is 60-70. It can be concluded that CO2 foam is the superior fracture fluid in the Cooper Basin in terms of fracture size and productivity enhancement. However, further work is required to determine whether CO2 foam fracture treatments are the optimal economic choice.