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Solvent saturation in miscible flooding

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In most compositionally enhanced solvent displacements, some of the solvent will be trapped permanently in the reservoir and will not be produced. This happens when water is used to drive a solvent slug and the oil displaced by the solvent. Solvent is trapped by advancing water much like oil is left as a residual in a waterflood. Solvent also can be trapped by oil that crossflows into a previously solvent-swept zone. In water-alternating-gas (WAG) flooding, solvent trapping can affect saturation through the mechanism of relative permeability hysteresis.

Factors affecting solvent trapping

Laboratory data indicate that there is little dependence of the trapped solvent saturation on whether water or oil is the trapping phase.[1] These data also show that the magnitude of the trapped solvent saturation is insensitive to whether the measurement is made

  • At reservoir or ambient conditions
  • On core plugs or composites of core plugs
  • Or on native state or extracted cores.

The magnitude of the trapped-solvent saturation depends on the magnitude of the maximum solvent saturation present when the solvent is trapped. This is illustrated in Fig. 1, which shows data for Prudhoe Bay cores.[1] In these experiments, various initial solvent saturations were established before the cores were flooded with either water or oil. There is a substantial degree of scatter in the data, but the trapped-solvent saturation clearly depends on the initial solvent saturation. Moreover, within the data scatter, the trapping is nearly independent of the liquid phase doing the trapping and even independent of a small oil saturation if it should happen to be present as a third phase.

According to Jerauld,[1] the relationship between trapped-solvent saturation and the maximum solvent saturation at the location at which trapping occurs is generally well represented by a "zero slope" adaptation of the Land curve:


In this equation, RTENOTITLE is the solvent trapped when the rock is 100% solvent saturated, and RTENOTITLE is the maximum solvent saturation at the location where trapping occurs. According to Eq. 1, if solvent subsequently is mobilized from this location only to be trapped again when the flowing saturation is lower, the retrapped solvent still attains the trapped saturation achieved at the previous maximum saturation. If on subsequent remobilization the solvent saturation should reach a higher value than the previous maximum, the trapped saturation will attain a new and higher value, according to Eq. 1.

The maximum trapped-solvent saturation, RTENOTITLE, when the rock initially is 100% solvent saturated depends strongly on both porosity and clay content, or microporosity. This is illustrated in Fig. 2 for data from various sandstones, which show a generally increasing trend for RTENOTITLE with decreasing porosity.[1]

Solvent relative permeability hysteresis

Because of the nature of solvent trapping, an important mechanism to be accounted for in WAG flooding is solvent relative permeability hysteresis. This is illustrated in Fig. 3. Consider solvent injection for the first WAG cycle. Solvent is the non-wetting phase, and solvent injection is a drainage process. The solvent relative permeability depends only on the solvent saturation. The solvent may be displacing only oil in the presence of connate water for a secondary flood, only water in the presence of waterflood residual oil for a tertiary flood, or both oil and water for a partially waterflooded reservoir. All these situations are approximated by the same solvent primary-drainage curve, and on the first WAG cycle the solvent relative permeabilities follow the primary-drainage curve AE. If at the end of the first solvent cycle a volume of solvent has been injected so that point B on the primary-drainage curve has been reached at a given location in the reservoir, the solvent saturation at this location will be SgB.

Now consider water injection on the first WAG cycle. Assume that the solvent saturation at the location in question remains SgB. (Actually, the saturation may increase somewhat as water at first displaces solvent past this location.) When water reaches this location, it will drive the solvent down to a trapped saturation, SgtD, at point D according to the trapped-solvent- vs. maximum-solvent-saturation relationship for the rock. This is an imbibition process, and the solvent relative permeability follows the curve BD.

When solvent is injected on the second WAG cycle, the solvent relative permeability follows the curve DB because Land’s evidence demonstrates that imbibition relative permeability often is nearly reversible.[2] It is important to take this hysteresis into account in a WAG simulation because the imbibition relative permeability is substantially less than the primary-drainage relative permeability and will cause the mobility ratio to be lower and the displacement more effective than would be the case with primary-drainage relative permeability only.

If the solvent saturation at the location in question never reaches SgB, solvent relative permeability will stay on the curve BD during the subsequent second-WAG-cycle water slug. If such a large solvent slug is injected that SgB is exceeded at this location, solvent relative permeability will once again follow the primary-drainage curve, perhaps to point E, and attain a new maximum solvent saturation at this location, SgE. Then, on the subsequent water cycle, the solvent relative permeability will follow a new imbibition curve, EC, and solvent will be trapped at a new trapped-solvent saturation, SgtC, according to the trapped-solvent- vs. maximum-solvent-saturation relationship.


S = saturation, fraction of pore volume
RTENOTITLE = maximum solvent saturation, fraction of pore volume
RTENOTITLE = solvent trapped when rock is 100% solvent saturated
Sgt = trapped gas saturation, fraction of pore volume


  1. 1.0 1.1 1.2 1.3 1.4 1.5 Jerauld, G.R. 1997. Prudhoe Bay Gas/Oil Relative Permeability. SPE Res Eng 12 (1): 66–73. SPE-35718-PA.
  2. Land, C.S. 1971. Comparison of Calculated with Experimental Imbibition Relative Permeability. Trans., AIME, 251.

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See also

Miscible flooding

Compositional simulation of miscible processes

Scaleup to full field miscible flood behavior