An Introduction to Miscible Flooding for Enhanced Oil Recovery

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miscible [ mĭs′ə-bəl ] adj.
Capable of being and remaining mixed in all proportions

 

Miscible. The deceptively simple relationship between certain solvents and oil, as defined above, enables incremental, tertiary reserves recovery for many oil reservoirs.

Miscible floods are tertiary recovery schemes where the definition of ‘miscible’ is as shown in the box above. The table below summarizes recovery factors (RF) associated with a sample of common reserves recovery mechanisms:

1 Recovery Factors are approximate. There are many examples of RFs outside of these ranges, both high and low.
Mechanism Class Description Incremental RF1 Total RF1
Primary Fluid + Rock Expansion 5 – 15% 5 – 15%
Fluid + Rock Exp + natural aquifer 10 – 25% 10 – 25%
Secondary Waterflood 10 – 25% 20 – 50%
Primary Polymer Flood 15 – 25% 35 – 75%
Hydrocarbon Miscible Flood 10 – 20% 30 – 70%
CO2 Miscible Flood 15 – 30% 35 – 80%

How does Miscible Flooding (MF) Work?

To appreciate how MF works, it is important to understand how the fluids in an oil reservoir behave during extraction. A virgin oil reservoir typically contains oil, dissolved natural gas, and water at a pressure that is primarily dependent on its depth.

During primary depletion, both the reservoir rock and the fluid it contains expand as reservoir pressure is reduced. Reservoir rock expansion is negligible, while the fluid expansion can be substantial. Natural gas dissolved in oil remains in solution with the oil until reservoir pressure declines below the bubble point (Pb). When that occurs, the dissolved gas begins to escape the oil, much like bubbles of CO2 being released from a carbonated beverage when it is opened. The ‘free’ gas migrates to the top of the reservoir, creating a gas cap, which continues to expand as reservoir pressure drops. Liberating dissolved gas from oil causes the oil to become more viscous (thicker) and less mobile in the reservoir. At the extreme, most of the dissolved gas leaves a solution, and the remaining ‘dead’ oil may become immobile in the rock due to its elevated viscosity.

The reservoir may benefit from an underlying aquifer (a geological formation containing or conducting ground water) that acts to support pressure by replacing produced fluids with aquifer water. The degree of connection that the aquifer has with the reservoir determines how effective that pressure support may be.

Miscible flooding differs from secondary recovery schemes in that the injectant blends completely with the hydrocarbon being produced. This important distinction is what enables the higher RFs associated with miscible flooding.

Waterflooding improves oil recovery by maintaining reservoir pressure (dissolved gas remains in, or returns to, solution) and by physically sweeping oil towards producing wells (Figure 1). Due to the density difference between oil and water, gravity will tend to cause the injected water to fall toward the base of the reservoir, impairing sweep efficiency. In addition, water, with its low viscosity, is more mobile in the reservoir than oil, so it can migrate through the reservoir more easily than oil. The resultant ‘viscous fingering’ also impairs sweep efficiency, as illustrated in Figures 1 and 2. Viscous fingering is aggravated by reservoir heterogeneity, with a high permeability reservoir, including open faults and fractures, enabling water to bypass oil saturated areas to reach producing wells prematurely. This behavior short-circuits the oil sweep, resulting in poor sweep efficiency and the potential to strand oil in the reservoir.

Example Flooding Performance
Figure 1 - Waterflood versus Miscible Flood Sweep Efficiency

Miscible solvent injection achieves its improved recovery factor over waterflooding with one additional mechanism beyond pressure maintenance and the physical sweep of oil toward producers. The solvent mixes perfectly with the reservoir hydrocarbon it contacts, both swelling the liquid and reducing its viscosity (Figure 2). Previously immobile oil, trapped in smaller pores in the reservoir rock, is now mobile enough to be extracted. Typical miscible solvents like ethane, CO2 and N2 are much less dense than reservoir liquids. That means they have the opposite problem to water, resulting in ‘gravity override’ as illustrated in Figure 2, where the solvent rises to the top of the reservoir. Viscous fingering and channeling through higher permeability streaks, faults, and fractures remain as potential impairments to a MF sweep efficiency.

Factors Affecting Miscible Recovery
Figure 2 - MF Solvent Behavior on Pore and Field Scales

To counteract the gravity override problem of MF solvents, a process known as Water Alternating Gas (WAG) is almost universally applied. A slug of miscible solvent is followed by a slug of water, with the water slugs acting to buffer the override potential of the solvent. The solvent slug is trapped between the water slugs, limiting its horizontal reach to override the oil. Slug sizes are described by their fraction of Hydrocarbon Pore Volume (HCPV, porosity net of water saturation) with individual slugs typically representing 0.01 to 0.04 pore volumes.

Compatibility with waterflooding is often considered a prerequisite for miscible flooding.