Pore Scale modeling in carbonate reservoir is challenging and important for getting an accurate reservoir characterization, enhanced oil recovery (EOR) and reservoir management. In this case, 3D pore-scale modeling for immiscible and near miscible three phase flow in gas and water alternating gas (WAG) flooding of carbonate reservoir. It is useful to predict and guide SCAL based to access effects on pore-scale and EOR of field scale. A Research has been started in carbonate reservoir with water alternating gas (WAG) injection activity which has various heterogeneity conditions such as: porosity, permeability, relative permeability, cementation, saturation exponent, rock types, fluid types/contacts, interfacial tension, wettability and capillary pressure. Inaccurate to characterize and model of these reservoir properties and fluid will lead to give high uncertainty of reservoir characterization, minimum oil recovery and reservoir management concern. The reliable pore-scale modeling approach is needed by the data integration of various sources such as those from petrophysical, reservoir, geology and geophysical data. Research and utilize of X-ray CT in micro and nano to capture the 3D network structure of representative reservoir rock properties. In prediction and guide SCAL based; investigation the effects (sensitivity) of interfacial tensions, contact angles, wettability and spreading coefficient into miscibility on the oil layers between gas and water in a fully interconnected three-phase flow pore-network model. Utilize thermodynamic criteria for rock properties and oil layers, which affect the oil relative permeability at low oil saturation for accurate prediction of residual oil and maximize oil recovery. In 3D Pore scale modeling workflow; validation with SCAL-lab. up scaling to well logs and field with utilizing logs, formation pressure/sampling/testing and combination with structural data of geology-seismic are necessary in field scale modeling approach. It will provide reliable rock type/properties for a reservoir dynamic model. The special approach needs to be developed and used in simulation model for getting appropriate relative-permeability, rock type/properties and water saturation in Gas and Water Alternating Gas (WAG) flooding of carbonate reservoirs. Thus it can give an accurate and robust of reservoir characterization, maximize oil recovery and reservoir management.

The physics of multi-phase displacement processes in the individual pores of a connected pore-network of a rock ultimately controls how oil, gas and water move in reservoir rocks and how readily they can be produced. These pore scale processes, including piston-like displacement, snap off, film-flow and fluid redistribution have been studied traditionally in pore-network simulations as well as in 2D micro-model experiments. However, recent advances in X-ray computed micro-tomography (CT) techniques now enable us to visualize and monitor these processes in 3D during in-situ core flooding experiments at pore-scale resolution. This provides new information on the spatial and temporal evolution of oil and water phase clusters and films. In this paper, we present results of a suite of two-phase fluid displacement experiments performed on a dolomite core plug. The experiments consist of a series of fluid injections and in-situ CT scans of the core in certain time steps during the drainage and imbibition displacement processes. The fluid phases are brine and a mineral oil. A simple, low-cost and highly X-ray transparent design for core flooding cells is introduced. Our experiments and CT images allow us to visualize the 3D fluid structures of each phase during fluid displacements in carbonate rocks with excellent clarity. Piston-like displacement and snap off mechanisms have been captured clearly in 3D. In addition, the formation, collapse and reorganisation of brine films surrounding oil blobs in individual pores were clearly visualised. However, the formation of oil films, which could provide connectivity for the hydrocarbon phase at low saturations, could not be observed in these experiments. The observed displacement processes and the particular oil-water/rock configurations seen in the displacements suggest the rock is preferentially water wet.