Wettability

Macro-scale properties of multi-phase fluid flow in a petroleum reservoir including Capillary Pressure curves and Relative Permeability remain closely related to the Wettability, because, wettability remains to be the major factor in the control of the location, flow and distribution of oil and water in a petroleum reservoir.

At a given saturation, the relative permeability of a fluid phase is higher when it is the non-wetting phase than when it is the wetting-phase, because, the non-wetting fluid mainly flows through larger pores and the wetting-phase fluid prefers to flow through smaller pores or flow along the solid surfaces.

As the reservoir wettability controls the fluid flow, how will we be able to characterize the fluid flow for a non-uniformly wet petroleum reservoir, using a uniformly wet rock sample @ laboratory-scale? If so, then, how precise, would the laboratory-based predictions for (a) Capillary Pressure – Saturation relationships; and for (b) Capillary Pressure – Saturation - Relative Permeability relationships?

Although pore-scale fluid flow mechanisms remain responsible for the macro-scale fluid flow phenomenon, whether, the real pore-scale fluid flow details can be readily accessed by traditional experiments?

Although, X-ray microtomography allow us to observe the multi-phase distributions in a petroleum reservoir at the pore-scale, it can only provide the static images at a certain state.

If so, then, do we need to depend on Lattice Boltzmann method, or, Dissipative Particle Dynamics, or, Smoothed Particle Dynamics method for simulating fluid flow in real pore structures?

During such exercises, whether the application of physics-informed machine learning (PIML) would do wonders?

1.Whether the wettability of the rock sample pertains to non-uniform wettability as found in reality?

2.If not, how are we taking into account the different regions of a petroleum reservoir rock having different wetting preferences @ lab-scale?

3.At field-scale, wettability distribution in a petroleum reservoir ‘may or may not’ depend on pore-size. Accordingly, how do we identify, whether the tested rock sample @ lab-scale corresponds to either Mixed-Wettability or Fractional-Wettability?

4.At field-scale, different minerals occurring in petroleum reservoir rocks may have their own wetting preferences. If so, then, how are we capturing such complex real-field wettability preferences using a very small rock sample @ lab-scale?

5. At lab-scale, how precisely, will we be able to capture the presence of organic species in crude oil getting adsorbed or deposited over the sample rock surfaces, which changes the wettability of the rock sample to a non-uniformly wet state?