Chemical EOR
1. What is the average thickness of the brine film (1 nm??) that exists between reservoir rock mineral surfaces and crude-oil droplets – associated with a carbonate reservoir?
In such cases, whether the oil requires to be removed from solid rock surfaces, or, from relatively smoother brine surfaces?
With nanoparticle dispersion, what is the expected fraction of oil that remains directly in contact with the rock surface? With NPD, What is the expected fraction of oil that remains adhering to the solid rock surfaces through electrostatic forces? What will be the required threshold energy level towards separating oil from the surfaces given the imbalances between Brownian motion and electrostatic repulsion between nanoparticles (for a given nanoparticle size distribution)? Upon using Darcian approach, how would the details on the evolution of molecular structures of rock-brine interface and brine-oil interfaces approaching molecular thickness (from its original brine film thickness) would remain to be helpful?
If we have a slip @ brine-oil interface, how will we be able to quantify the effective viscosity of brine films?
2. Whether the degree of disjoining pressure associated with such brine films would significantly influence the resulting contact angle of oil droplets on rock surfaces?
Whether the alterations in ionic distributions in the Electric Double Layer of the brine film - as a function of brine film thickness and bulk ion concentration – would have an impact on the resulting contact angle?
3. With the thickness of the brine-film bounded between ‘rigid solid rock surface’ and relatively a ‘smooth diffusive oil surface’, would it remain feasible to upscale the details associated with Debye length of brine; the hydration diameter of ions in brine; the characteristic length of the density oscillation of brine molecules near solid rock surfaces; and the width of diffuse brine-oil interfaces – to a relatively larger pore-scale (leaving aside Darcy’s continuum-scale) – towards formulating a new EOR concept or facilitating the improvement of existing EOR technique?
Suresh Kumar Govindarajan
Professor (HAG)
https://home.iitm.ac.in/gskumar/
https://iitm.irins.org/profile/61643
12-Aug-2024
Hi Suresh - Not sure I know the precise answer because there are many carbonate surfaces in the pore system of a carbonate rock. Different types of surfaces as well as the effect of capillary pressure between the wetting and non-wetting phase in combination with the geometry of the surfaces will undoubtly affect the local thickness of the wetting film. But if you look at capillary pressure curves for carbonates (both oil-brine, air-brine and especially air-Hg capillary pressure curves) and take into account that many oil-brine and air-brine capillary pressure curves are not truly equilibrium curves (it takes too long time to reduce the water saturation due to the low relative permeability to water), then you can extract the irreducible water volume equal to the pore surface water. And if you combine the pore surface volume with the pore surface area (from tomography or BET), then you can estimate that the average thickness of the wetting phase at irreducible water saturation is around 5 nm in carbonates. This is of cause an average value and will be larger in the corners of the pore system and smaller on the flat pore walls away from the corners.
As the recorded Amott water and oil wettability clearly is a function of the maximum hydrocarbon saturation in the pore system I expect that when you reach this minimum average wetting film thickness the film will break/penetrated by the hydrocarbon phase that then may locally change the pore wall wettability and park the irreducible water in the corners.
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