Pore- to field-scale modelling of three-phase flow processes in heterogeneous reservoirs with arbitrary wettability
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Most reservoirs, such as carbonate reservoirs not only have structural heterogeneities (e.g. complexly shaped geobodies or fractures). But they also have distributed wettabilities and are mixed- to oil-wet. The interplay of structural and wettability heterogeneities impacts sweep efficiency and oil recovery. Choosing the appropriate Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) technique based on adequate predictions of oil recovery requires a sound understanding of the fundamental controls on fluid flow in mixed- to oil-wet andstructurally complex rocks. The underlying multiphase flow processes are modelled with physically robust flow functions, i.e. relative permeability and capillary pressure functions. Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during Water-Alternating-Gas (WAG) injection. In this work we use pore-network modelling, a reliable and physically based simulation tool, to predict three-phase flow functions. We have developed a new three-phase flow pore-network model for rocks with arbitrary wettability, which allows us to analyse the fundamental multi-phase displacement processes. Unlike other models, our model combines three main features: (I) A novel thermodynamic criterion for formation and collapse of oil layers that strongly depends on the fluid spreading behaviour and the rock wettability. The model hence captures film/layer flow of oil accurately, which impacts, in particular, the oil relative permeability at low oil saturation and hence the accurate prediction of residual oil. (II) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows accurate modelling of the mobilization of disconnected phase clusters that arise during higher order (WAG) floods. (III) The model takes as input realistic 3D pore-networks extracted from pore-space reconstruction methods and Computed Tomography (CT) images, preserving both topology and pore shape of the rock. The model comprises a constrained set of parameters that can be tuned to mimic the wetting state of a given reservoir. We have validated our model against available experimental data for a range of wettabilities. We demonstrate the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points and for different rock types. This revealed a wide range of three-phase relative permeabilities and residual saturations. The pore-scale generated three-phase flow functions have then been used in a heterogeneous reservoir model. Here we demonstrate their impact on the sweep efficiency after gas injection and WAG for a range of realistic wettability scenarios. We show that the uncertainty in flow functions can be as big as the geological uncertainty in a reservoir model that was history matched for an extended waterflood.