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Carbon dioxide (CO2) injection has been identified as an important means to achieve hydrocarbon reservoir potential whilst mitigating the greenhouse gas effect. CO2 injection into depleted oil reservoirs is very often accompanied by chemical interactions between the formation rock and in situ formed solute. Sandstone formations were expected to contain less reactive minerals in their composition, compared with carbonate counterparts. However, the evolution of petrophysical parameters may change due to different clay content in different sandstone rocks. In this manuscript, we evaluate possible petrophysical parameter evolution in layered sandstone core sample during miscible CO2 water alternating gas (WAG) injection. The stratified core sample is composed of two axially split half sandstone plugs each with different permeability. Grey Berea, Bandera Brown, and Kirby sandstone were used to represent low, moderate and high clay content, respectively. Core flooding experiments were conducted using CO2, brine (7 wt % NaCl + 5 wt % KCl + 5 wt % CaCl2.2H2O) and n-C10 at a temperature and pressure of 343 K and 17.23 MPa, respectively. Porosity and pore size distribution of the samples were measured using nuclear magnetic resonance (NMR) before and after flooding. In addition, a high-resolution medical X-ray computed tomography (XCT) scanner was used to detect any change in pores along the core sample. The results showed a reasonable increase in the post-flood porosity about 1.0% as a maximum. The results also revealed that the changes in porosity are correlated reasonably with the clay minerals amount in the sample (i.e. higher clay mineral amount leads to higher evolution). The X-ray CT images and NMR results confirmed changes in pore spaces and pore size distribution across the core sample. These changes possibly attributed to clay minerals migration which released by mineral dissolution and subsequent pore throat plugging. NMR results also revealed that the larger the pore size, accompanied by high clay mineral amount, the higher the evolution. This may be attributed to the higher contact surfaces at these pores with the injected CO2 (in-situ formed carbonic brine). Our results provide insight into how clay content may affect CO2/sandstone reaction in the presence of permeability/mineralogy heterogeneity. In addition, it highlights the control of clay content on rock petrophysical parameter evolution, thus its significance in modelling CO2 injection in sandstone reservoirs. |
