ENHANCED OIL RECOVERY
1. Apart from ‘reversal of wettability’, to what extent, chemical EOR by the addition of nano-particles in the absence of surfactants (or stabilizers or surfactant-like chemicals) would really lead to ‘IFT reduction’ at the larger field-scale?
If not, whether the fraction of IFT reduction by nanoparticles would tend to remain to be zero - when both nanoparticles and surfactants are driven together?
If yes, how exactly nano-particles aid the surfactants towards accelerating the magnitude of IFT reduction?
2. Feasible to enhance the oil recovery at the real field-scale - using nanoparticle concentrations – well-below ‘one percent’ - as observed at the laboratory-scale using experimental investigations - towards altering the wettability?
If not, how could we bridge the gap between laboratory-scale observation and the actual requirement of nanoparticles with the real field-scale scenario?
3. How practical would it remain to have a control over modifying the properties of nanoparticles; or to have a control over the functionalization of nanoparticles; or in selecting the coating materials of nanoparticles – as a function of a specific reservoir condition – at the real field-scale (and not at the laboratory-scale)?
4. Apart from ‘reversal of wettability’, to what extent, chemical EOR by the addition of nano-particles in the absence of surfactants lead to ‘log-jamming’ or ‘pore-plugging’?
Would it remain feasible to ensure that the ‘radius of nanoparticles’ to remain to be (a little bit) greater than the ‘pore-throats’ – at the larger field-scale – so that these nanoparticles resulting from ‘log-jamming’ would try to plug the paths of already swept zones; and thereby, leading the ‘oil flow’ to get diverted into the unswept zones of the reservoir?
To what extent, will we be able to avoid the accumulation of nanoparticles at the entry of the unswept pathways (resulting from pore-plugging) that eventually leads to a mitigated oil recovery?
Are we really selecting nanoparticles - only after, the careful consideration of ‘mean free path’ (including size, shape and aspect ratio) of nanoparticles; and the ‘pore size distribution’ of real field reservoir conditions?
5. Would it remain feasible to delineate the fraction associated with the ‘agglomeration of nanoparticles that results in precipitation on the surface of rock by gravity forces’ – from that of the ‘nanoparticles that remain adsorbed to the surface of rock due to surface charges’ in an oil-wet reservoir?
6. While polymers enhance the ‘viscosity of water’, could nanoparticles would remain efficient enough in mitigating the ‘viscosity of oil’ – on top of ‘reversing the wettability’ in an ‘oil reservoir’?
7. To what extent, will we be able control the pH of the formation fluid at the larger field-scale - which essentially governs the electrokinetic properties (DLVO) of nanoparticles that dictate the stability of nanofluids?
Feasible to measure the electrophoretic mobility (as a function of the velocity of suspended particles induced by an electrical field over the strength of an electrical field) of nanoparticles @ field-scale in order to have a control on the stability of nanoparticles?
8. Does ‘elevated temperature’ always remain to be an advantage for nanoparticles to remain to be efficient - as the ‘Brownian motion of nanoparticles gets intensified with increasing temperature’?
9. What would be the difference in the optimum value of nanoparticle concentration that is expected between the observed laboratory values and the actual field-scale requirement – towards preventing the scale formation?
10. Coupled effect of nanoparticles with surfactants/polymers/foams/low-salinity water: Are we able to bridge the gap between experimental observations at the laboratory-scale and the real field complexities associated with the larger field-scale?
I really liked your questions. Back in 2016, there was the same question about whether low-salinity water flooding could really work at the field scale. We knew that some lab-scale studies showed that changing the water's saltiness had an effect, but they had to inject a lot of water into the samples, like 20-25 pore volumes (PV). The problem is, doing the same thing on a bigger scale in the field is impractical. I reached out to a friend who is a manager of a petroleum field, and he told me that, due to the size of the reservoir, after 17 years of waterflooding operations, they only reached 0.79 of the reservoir's PV. Additionally, using low-salinity water is much easier to control than injecting nanoparticles, as you mentioned. Another critical issue is whether simulators and computational models can handle these complex multiphase mechanisms. In my opinion, the key to making decisions like these lies in finding a company that has the courage and capability to try nanoparticle flooding on a pilot scale. Going from the lab to the field is no easy task. If you're interested, a couple of articles, namely 171794-MS and 165253-MS, can give you some ideas on how to transition between different scales. You might also want to check out my own article on the least field operations of Chemical EOR methods. Article Strategy for Optimum Chemical Enhanced Oil Recovery Field Operation
As I stated in the above article, the problem is not only about injecting or producing chemicals; one challenging issue is monitoring them alongside the reservoir. It's pretty interesting!
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