Geologically, reservoirs are physically huge in volume, well insulated from surface fluctuations in temperature and thus exhibit a constant temperature dictated by the local geothermal temperature gradient, nominally on the order of 1.5oF/100ft of depth, with some variation locale to locale.

Reservoir pressure, on the other hand, is directly influenced by reservoir recovery practices. When hydrocarbons are withdrawn from a reservoir, it’s pressure declines. Depending on the results of the slim tube experiments described above, it is possible that reservoir pressure may be found to be below the MMP (Minimum Miscibility Pressure). If so, CO2 (Carbon Dioxide) can still be injected, but the efficiency of the recovery process is adversely impacted. Typically, this does not occur since, after primary depletion, water flooding operations commence which restore reservoir pressure to values above the MMP.

CO2 Mobility and Reservoir Heterogeneity

In a CO2 EOR flood, a variety of factors will influence process performance. Because the viscosity of CO2 at reservoir conditions is much lower than that of most oils, viscous instability will limit the sweep efficiency of the displacement and, therefore, oil recovery. In addition, reservoir rock is extremely heterogeneous, exhibiting zones of high permeability in close proximity to those of low permeability. These permeability differences may be innate, that is caused by differences in pore structure at the time of geological deposition, or a product of fractures, natural or man-made.

CO2 dispersion in reservoir 

Reservoir heterogeneity and the adverse effects of CO2 viscosity must be contended with to optimize oil recovery. Two basic strategies have been developed by the petroleum industry to cope with these conditions, namely:

1. Alternately inject cycles of CO2 and water in the so called WAG (water alternating gas) process. This technique forms sequential banks of fluids in the reservoir rock: oil, CO2 and water, that migrate from the injection to the production wells.

2. Add chemical agents, such as: ethoxylated and/or unethoxylated species, fluroacrylate-styrene copolymers, lignosulfonates, etc, to CO2 to form stable foams that increase its viscosity without compromising its efficacy. These stiffened foams facilitate formation of oil and CO2 banks, which migrate from injector to producer while suppressing adverse hydrodynamic instabilities, such as fingering, which lead to vertical fluid stratification and reduced oil recovery
In some form, WAG operation occurs in all CO2 EOR floods, while field economics and reservoir heterogeneity dictate whether viscosifiers will be used.


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