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During the production of oil from a reservoir, oil moves towards the producer well through the pores of the sedimentary rocks in which it is contained. Historically, the pressure gradients needed to promote this movement have been provided by the release of the natural energy stored in the reservoir fluids, underlying aquifer and reservoir rocks—a process known as primary recovery. However, the amount of this natural energy is somewhat limited and the average reservoir pressure declines as oil is produced. As a result, the rate of oil production falls and the quantity of oil that can be recovered is small; typically less than 25% of the total amount of oil in the reservoir.

The oil recovery factor can be substantially increased by injecting fluids, either gas or water, into the reservoir to replace the oil that has been extracted, thus maintaining reservoir pressure. By using these techniques, the amount of oil recovered can be increased to about 50–60%. These were called secondary processes since they could restore production to fields that had reached their primary production limits. Pressure maintenance by water injection is now conventional practice, and it is used in the majority of new oil field developments. After the water injection scheme has reached its economic limit, the 40–50% of the oil that remains in the reservoir has two forms:

  1. Some of the oil remain as droplets or ganglia trapped within the rock pores in regions that have been swept by the waterflood, Figure 1. As much as 30% of the oil originally in these zones may be left in this way. The mechanism that causes this oil to become trapped and the forces that prevent the ganglia from being moved both depend upon the wetting characteristics of the rock and the oil/water interfacial tensions. These interfacial forces are generally several orders of magnitude higher than the viscous forces imparted by the flowing water. To move this trapped oil, therefore, it would be necessary either to reduce substantially the interfacial tension or to increase the viscous forces. Increasing the viscous forces by several orders of magnitude is not a practical option, however, since the pressures involved would be enough to fracture the rock matrix.

  2. A significant fraction of the reservoir remains unswept by the waterflood. Some of this unswept oil is in regions where the amount of oil that could be recovered makes it uneconomic to drill more wells; but much of it is in areas that have been bypassed by the waterflood. A number of factors account for this poor sweep efficiency:

  • The density of water is higher than that of oil and gravity forces cause the water to flow preferentially through the lower regions of the reservoir.

  • Heterogeneities within the reservoir cause fluids to flow preferentially through the high-permeability layers, Figure 2.

  • The streamlines which define the paths taken by the fluids as they flow from an injector to a producer well vary in length, Figure 3. Fluids flowing through the innermost streamtubes reach the producer well much earlier than those flowing through the outer streamtubes. As a result, high water cuts can occur before the oil in the outermost streamtubes has been fully displaced.

Oil ganglia trapped in the interstices of the rock matrix.

Figure 1. Oil ganglia trapped in the interstices of the rock matrix.

Example of sweep pattern occurring in heterogeneous reservoir having a high-permeability layer.

Figure 2. Example of sweep pattern occurring in heterogeneous reservoir having a high-permeability layer.

Example of streamline pattern for a single injector surrounded by four producer wells.

Figure 3. Example of streamline pattern for a single injector surrounded by four producer wells.

For each of these mechanisms, sweep efficiency is dependent upon the oil/water viscosity ratio. If the oil is more viscous than the water, sweep efficiency is low and vice versa.

By injecting suitable materials into the reservoir, the interfacial behavior and/or the viscous ratios can be changed. Interfacial tensions can be reduced by adding a surfactant to the injection water or by injecting a gas that is miscible with the oil. Viscosity ratios can be changed by adding a high molecular weight polymer to increase the viscosity of the injection water or by heating the reservoir to reduce the viscosity of the oil. These methods were originally called tertiary processes since they were used after secondary recovery had been completed, but they are more familiarly known as enhanced oil recovery processes. They fall into three main categories:

A fourth category includes some more speculative processes, such as the injection of microorganisms to recover oil.

Table 1.  Three main categories of enhanced oil/recovery processes

 Method Target oil
Gas injectionMiscible HydrocarbonResidual
 Carbon DioxideResidual
Chemical Surfactant Residual
Processes PolymerBy-passed
 Caustic Residual
 Polymer GelsBy-passed
Thermal Steam Injection Residual/By-passed
Processes Hot Water Residual/By-passed
 In Situ CombustionResidual/By-passed

Each of these processes is effective for a limited range of reservoir conditions so each application must be specifically designed for a particular situation.

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