Numerical Simulations of the Effects of CO2 Geological Storage on the Flow and Salinity of Formation Water in the Gippsland Basin

Abstract

The key objective of the study was to reduce uncertainties related to geological carbon storage (GCS) in Victoria by numerical simulations of the potential effects of CO₂ injection on groundwater resources and petroleum fields in the near-shore area of the Gippsland Basin. The injection target is the Latrobe Group, which forms a sloping aquifer system with various intra-formational seals, containing low-salinity water in the on- and near-shore area and becoming increasingly saline towards the offshore where the majority of petroleum fields are located. The Latrobe aquifer has been identified as a suitable candidate for large-scale GCS. There are regulatory safeguards in place to protect groundwater and petroleum. Therefore, understanding how CO₂ injection affects the fluid flow in the transition zone from fresh to saline water is critical for the selection of an appropriate offshore storage site in the near-shore area. The fluid inclusion data demonstrate that paleo-salinities of formation water in the Latrobe aquifer were generally higher than present-day salinities. The oldest formation water age of 30–40 thousand years from water samples in the onshore Latrobe aquifer in conjunction with first-order numerical simulations constrain the emplacement of freshwater to its current extent to approximately the last 200 thousand years. Simulation results of injecting up to 100 million tonnes of CO₂ (~150–200 million m³ at reservoir conditions) into the upper part of the Latrobe aquifer in the near shore area do not show a potential for significant salinity increase in the onshore parts of the aquifer. Changes in salinity due to injection occur mainly where salinity gradients are high, i.e. along the transition between freshwater and higher salinity water. These results are in agreement with other simulation studies in the literature, suggesting that GCS does not result in significant brine displacement in the far-field of an injection site, particularly if, as in the case of the Gippsland Basin, the injection volume corresponds to less than 0.05% of the connected aquifer volume. Fluid production of approximately 400 million m³ from an active gas field caused a pressure decline of up to an equivalent of 90 m freshwater head in the offshore parts of the Latrobe aquifer. This resulted in a smaller area of simulated pressure impact from CO₂ injection and additional storage capacity compared to injection into a hydrostatically-pressured aquifer.

AAPG Datapages/Search and Discovery Article #90217 © 2015 International Conference & Exhibition, Melbourne, Australia, September 13-16, 2015