Chemical EOR – Part B
1. Is there a correlation between (a) IFT reduction; and (b) ‘capillary forces’ reduction (during the alteration of the reservoir rock surface’s wettability from oil-wet towards enhanced water-wet) – associated with a surfactant-aided chemical EOR?
If so, does such correlation work in a completely different way for a ‘carbonate reservoir’ – from that of a ‘sandstone reservoir’? What is the associated ‘scale’ at which we find this distinction?
To what extent, do we remain successful towards achieving ‘IFT reduction’ and ‘wettability alteration’ in HPHT reservoirs?
How about the operational and post-production treatment costs associated with such costly (and sometimes toxic) chemical flooding associated with HPHT reservoirs?
2. As against the case of surfactants, how do we ensure that the injected nanoparticles, particularly under adverse reservoir conditions - get stabilized by the presence of capillary forces? Feasible to capture the functionality and stability of such nanoparticles under HPHT conditions @ lab-scale? Also, would it remain feasible to capture the way, the nanoparticles encourage the blocking of high-permeable zones, and subsequently, diverting the injected fluid into oil bearing zones in the reservoir? 3. Whether the application nanoparticles remain justified under Darcian approach - despite its potential ‘to mitigate IFT’ and ‘to reverse wettability of reservoir rock’s surface’ resulting from the nanoparticle’s ‘enhanced specific surface area’, ‘enhanced stability against high pressure and high temperature’ along with its distinct ‘intrinsic physicochemical properties (surface/interfacial properties)’?
4. Whether the shift of nanofluid’s rheological behavior from Newtonian to non-Newtonian – by the introduction nanoparticles remain uniform through all pore-sizes – towards successfully displacing oil?
To what extent, the role of ‘disjoining pressure’ becomes sensitive in dictating the resultant enhancement in the oil displacement as a function of size, shape, volume-fraction, surface-charge and polydispersity of nanoparticles?
Feasible to capture the way, the injected nanoparticles - gets restructured within the multi-phase fluid flow petroleum reservoir system that exerts a definite excess pressure @ lab-scale using experimental investigations either directly or indirectly?
To what extent, the ‘aggregation of nanoparticles’; and the ‘hyper-activated nanoparticle’s interaction with the reservoir rock’s mineral surface’ under adverse reservoir conditions hinder the very objective of injecting nanoparticles with the hope that it would sweep/penetrate the maximum possible reservoir volume?
5. Feasible to capture the details associated with the formation of stable nanoparticle dispersion through hydrodynamic-forces (dispersion ability), thermal motion of particles (heat carrying capacity / rigidity) and inter-particle interactions (agglomerative/catalytic nature) @ lab-scale?
- Badges
- Science topic
- Similar topics
- Analytical Chemistry
- Column