Thermal EOR
1. Feasible to capture ‘severe gas channeling’ in addition to thermal energy loss that restrict the sustainable and stable development of heavy oil (where, the high content in resin and asphaltene increases significantly heavy oil’s viscosity; and worsens heavy oil’s fluidity; and eventually making heavy oil difficult to recover) either @ laboratory-scale or @ pilot-scale?
2. To what extent, non-thermal methods such as chemical flooding could be applied for an efficient recovery of heavy oil, rather than by conventional heavy oil recovery methods (steam-flooding; huff and puff; and ISC)?
If yes, whether the fluidity of heavy oil be improved significantly by injecting surface-active fluid (surfactants; or, macromolecular polymers; or, alkaline) into the reservoir (which forms an oil-in-water emulsion with low viscosity)?
If so, do these surface-active substances tend to emulsify heavy oil efficiently in the absence of applying significant amount of external energy, while managing to reduce the viscosity of heavy oil significantly and simultaneously increasing the recovery of heavy oil?
OR
Would we require the existence of oil-phase either in ‘in-situ formation of micro-emulsion’ (surfactant concentration should be greater than CMC) or ‘micro-emulsion flooding’ (an isotropic colloidal dispersion system spontaneously formed by mixing water, surfactant, co-surfactant and oil phases; and which remains to be thermodynamically, a stable system with large specific surface area, small particle size and unique solubilization capability), which would possibly tend to contribute to the significant viscosity reduction of heavy oil?
Also, whether the injection of micro-emulsion would significantly increase the cycle production time and peak oil production; and also the periodic oil productions from wells?
3. Upon developing a micro-emulsion-type oil displacement agent formulation deduced from pseudo-ternary phase diagram for enhancing oil recovery, if the observed optimal injection rates @ laboratory-scale pertains to 0.2 PV of injected micro-emulsions with the injection rate of 0.2 ml/min; and the subsequent water injection rate of 0.3 ml/min, corresponding to the maximum total oil recovery efficiency of 45%; and the enhanced oil recovery efficiency of 30% following conventional water flooding process, then, what would be respective expected efficiencies upon implementing the same @ field-scale?
Whether the way
(a) the micro-emulsion-type oil displacement agent solubilizes the heavy oil;
(b) the way, the viscosity of heavy oil gets reduced and the way, the flowability gets increased; and
(c) the way, the heavy oil gets emulsified to O/W emulsions and change the wettability of oil-wet rock -
would remain to be the same
both @ laboratory-scale as well as @ field-scale?
In our research on 'ASSESSMENT OF POLYMER, FOAM AND CO2 INJECTIONS FOR HEAVY OIL PRODUCTION USING NUMERICAL SIMULATION,' we found that the most effective method for heavy oil production depends on the specific characteristics of the reservoir. Our numerical simulations indicate that the polymer injection technique resulted in the highest cumulative oil production, closely followed by the foam injection method. In contrast, the carbon dioxide injection method was observed to be the least effective based on our simulation results. These findings underscore the importance of tailoring recovery methods to reservoir conditions and highlight the promise of polymer and foam injections in optimizing heavy oil production rates.
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