Investigation of relative flow characteristics of brine-saturated reservoir formation: A numerical study of the Hawkesbury formation

Published on Sep 1, 2017in Journal of Natural Gas Science and Engineering3.859
· DOI :10.1016/j.jngse.2017.06.029
Tharaka Dilanka Rathnaweera15
Estimated H-index: 15
(Monash University),
Pathegama Gamage Ranjith48
Estimated H-index: 48
(Monash University)
+ 3 AuthorsA.S. Ranathunga12
Estimated H-index: 12
(Monash University)
Abstract Precise knowledge of the relative flow behaviour of CO 2 and brine during CO 2 sequestration in deep saline aquifers and its impact on the sequestration process is required to ensure the safety and efficiency of sequestration projects. This numerical study therefore aims to identify the interaction-induced relative flow behaviour of reservoir rock and its influence on the hydro-mechanical and geochemical phenomena in deep saline aquifers. COMSOL Multiphysics numerical simulator was used to develop a laboratory-scale relative flow model to simulate the CO 2 movement and brine drainage processes in brine-saturated Hawkesbury sandstone samples and finally, was extended it into a field-scale numerical model which can simulate the hydro-mechanical, mineralogical and geochemical behaviours of deep saline aquifers under CO 2 sequestration conditions. A 2-D axisymmetric pore-elastic model was developed using the pore-elastic module available in COMSOL and Buckely-Leverett flow theory was applied to the model using pre-defined partial differential equations. The proposed laboratory-scale model was first validated using experimental permeability data conducted under triaxial drained conditions and the model was then extended to predict relative flow characteristics, such as brine and CO 2 saturation and CO 2 pressure distribution along the sample length under different injection pressures, including both sub- and super-critical conditions and finally, real CO 2 sequestration processes. According to the results, the developed laboratory-scale model simulates the experimental results reasonably well with less than 10% relative error. The numerical results also reveal that there is a considerable effect of CO 2 phase change on the final distribution of the CO 2 and brine saturation profiles. In addition, the CO 2 pressure distribution along the sample length shows a non-linear relationship between the CO 2 pressure and sample length. According to the results of the field-scale model, the long-term interaction of CO 2 causes Hawkesbury formation's pore structure to significantly change.
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