VGP Technical Report 52 - Fluid dynamic and geomechanical modelling, Onshore Otway Basin, Victoria.
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Product description:About the Victorian Gas Program: The Victorian Gas Program (VGP) is a comprehensive science-led program, incorporating geoscientific and environmental research to assess the risks, benefits and impacts of potential onshore conventional gas exploration and production. The program is also investigating the potential for further discoveries of onshore conventional and offshore gas in the Otway and Gippsland geological basins and assessing the feasibility of additional onshore underground gas storage in depleted reservoirs around the Port Campbell area. The VGP includes an extensive, proactive and phased community and stakeholder engagement program, through which the results of the scientific studies are being communicated. Executive summary: The opportunity for further underground gas storage (UGS) in depleted gas fields in the onshore Otway Basin is being investigated as part of the Victorian Gas Program (VGP). There are currently three depleted gas fields used for UGS in Victoria. These sites are in the Port Campbell area in the onshore Otway Basin. This report presents a dynamic modelling study that assessed the suitability of representative structures for UGS using publicly available data. The simulation study involved coupled flow and geomechanical modelling, that assessed natural gas storage capacity as well as the geomechanical impacts of repeated injection and production cycles on the reservoir. The aim of this study was to gain insight into key dynamic parameters that could impact storage capacity, injectivity and deliverability, as well as the impact of pressure cycles on reservoir rock properties and faults at reservoir boundaries. Fluid flow modelling was conducted on two representative structures of the Waarre Formation unit C. Both models represent storage in depleted natural gas reservoirs in a sealed tilted fault block. The first model was a simple ‘slab’ model with simulations conducted to study the impact of absolute reservoir permeability, relative permeability, aquifer support, cushion gas injection and pre-production of the reservoir prior to storage. Simulations were then conducted on the second ‘complex’ model, which contained more geological detail with facies representative of the formations above and below the Waarre Formation unit C. Absolute reservoir permeability and the initial condition of the reservoir were investigated, along with an additional set of case studies related to well location, with an optimally located well at the crest of the reservoir and an off-centre sub-optimal well on the flank of the structure. The two criteria used to measure the impact on the complex model were pressure at the well and gas production rate. Overall, the water and gas production rates of the first cycle of gas storage have the highest sensitivity to the reservoir parameters and engineering constraints investigated in this study. In most of the scenarios, a cushion of gas develops in the reservoir over time and the gas and water production rates converge to the rates observed in the base case model within a few cycles of gas storage and production. The key reservoir parameter considered in this study, that impacts gas injection pressure, is pressure support to the gas reservoir from surrounding aquifers. The key engineering constraint for efficient gas cycling in the complex model was well placement. The outputs from the fluid flow modelling were forward-coupled with FLAC3D, a software package used for geomechanical modelling. The geomechanical modelling provided insights into key dynamic parameters that could impact storage capacity, injectivity and deliverability, as well as the impact of pressure cycles on reservoir rock properties and faults at reservoir boundaries. Prior to simulating the geomechanical stress response on the complex model, case studies were performed on hypothetical thin (25 m) and thick (50 m) reservoirs. Two operational scenarios were considered for the hypothetical thin reservoir. The first involved continuous injection, whereas the second involved cycles of injection and production intended to mimic what would occur during a gas storage and recovery operation. This second operational scenario was the basis for the hypothetical thick reservoir, where two different boundary conditions for pressure support to the gas reservoir from surrounding aquifers was considered, and the complex model simulations. The small changes in pore pressure, predicted as part of the fluid flow modelling, indicated that fault initiation or reactivation did not occur. Furthermore, any surface displacement that was predicted was so small (i.e. orders of magnitude less than one millimetre) that it was considered practically negligible. The simulations also indicated that plastic deformation did not occur because the rock within the reservoir remained within the elastic regime. Consequently, based on these predictions, the potential for degradation to reservoir integrity is low. Bibliographic reference: LaForce, T., Lu, M., Connell, L., Ricard, L., Buschkuehle, M. & Dance, T., 2021. Victorian Gas Program Technical Report 52. Department of Jobs, Precincts and Regions. Download: The downloadable version of this report is supplied in PDF format (25 MB). | ||||||
