Hydraulic fractures can enhance well productivity from stress sensitive naturally fractured reservoirs such as coalbed methane or coal seam gas (CSG) reservoirs. Graded proppant injection (GPI) has been proposed to enhance long-term, far-field interconnectivity between the created hydraulic and short-term, enhanced natural fracture permeability, resulting from fracture fluid leakoff and lowered net effective stress. This novel study shows how applying GPI with hydraulic fracturing treatments resulting in an increased stimulated reservoir volume (SRV) can enhance well productivity and improve CSG well economics.
A commercially available reservoir model and history-matched hydraulically fractured coal seam case is used to evaluate well performance differences between a hydraulic fractured reservoir and one including GPI application. A dual-porosity system and Palmer and Mansoori model are used to simulate initial and long-term permeability accounting for reservoir depletion (i.e., increased net effective stress, matrix shrinkage). A previously validated case study is used to describe the post-embedment benefits of GPI based on the porosity model and history-matched reservoir properties. A net present value (NPV) can then be calculated for each scenario, based on the production differences and typical Australian CSG costs.
Our results show that permeability enhancement is achieved beyond the hydraulically fractured region for all post-GPI stimulation cases. An optimal SRV can be found relative to permeability that maximises the incremental NPV from GPI application. The next most significant parameters after permeability that influence the economic outcomes are fracture porosity and coal compressibility. A larger SRV yields higher cumulative gas production over 30 years with up to 7.2 times increase over gas production without GPI. This study substantially increases our understanding on how to model and understand the benefit of GPI application along with hydraulic fracturing to increase the SRV in CSG wells.