Solvent Methods

One of the earliest methods for producing additional oil is through the use of solvents

to extract the oil from the permeable media. In the early 1960s, interest centered on

injecting liquified petroleum gas (LPG) in small “slugs” and then displacing the LPG

by a dry “chase” gas. This process became economically less attractive as the value

of the solvent increased. In the late 1970s, interest in solvent methods resurged

because of an increased oil price and more confidence in the ability to estimate oil

recovery. During this period, the leading solvent became carbon dioxide though

several other fluids were used also (Stalkup, 1985).

Two fluids that mix together in all proportions within a single-fluid phase are

miscible. Therefore, miscible agents would mix in all proportions with the oil to be

displaced. But most practical miscible agents exhibit only partial miscibility toward

the crude oil itself, so we use the term solvent flooding in this text. Many solvents, of

course, will become miscible with crude under the right conditions, but all solvents of

commercial interest are immiscible to an aqueous phase.

Solvent flooding refers to those EOR techniques whose main oil recovering

function is because of extraction, dissolution, vaporization, solubilization, condensation,

or some other phase behavior change involving the crude. These methods

have other, sometimes very important, oil recovery mechanisms (viscosity reduction,

oil swelling, solution gas drive), but the primary mechanism must be extraction.

This oil extraction can be brought about by many fluids: organic alcohols,

ketones, refined hydrocarbons, condensed petroleum gas (LPG), natural gas and

liquified natural gas (LNG), carbon dioxide, air, nitrogen, exhaust gas, flue gas, and

others. In this chapter, we emphasize miscible flooding with gaseous solvents CO2,

CH4, and N2, but you should remember there are many potential agents.

7-1 GENERAL DISCUSSION OF SOLVENT FLOODING

Considering the wide variety of solvents, process types, and reservoirs, our

discussion must ignore one or more interesting variations. Thus in this section, we

discuss CO2 solvent flooding, and later, we indicate more general aspects of solvent

flooding.

Figure 7-1 shows an idealized vertical cross section between an injection and

production well. By far the most common application of solvent methods is in a

displacement mode as shown, but injection and production through the same wells

have been reported (Monger and Coma, 1986). Solvent injection commences into a

reservoir in some stage of depletion, most commonly at residual oil or true tertiary

conditions. Most solvent floods are in reservoirs containing light crudes (less than 3

mPa-s oil viscosity) though there are exceptions (Goodrich, 1980). The solvent may

be introduced continuously in undiluted form, alternated with water in the

water-alternating-gas (WAG) process as in Fig. 7-1, or even injected simultaneously

with water through paired injection wells. Water is injected with the solvent in this

fashion to reduce the usually unfavorable mobility ratio between the solvent and the

oil. Carbon dioxide, in particular, can be injected dissolved in water in a distinctly

immiscible fashion that recovers oil through swelling and viscosity reduction

(Martin, 1951).

If the solvent is completely (first-contact) miscible with the oil, the process

has a very high ultimate displacement efficiency since there can be no residual phases

(see Sec. 5-4). If the solvent is only partially miscible with the crude, the total

composition in the mixing zone (miscible zone in Fig. 7-1) between the solvent and

the oil can change to generate or develop miscibility in situ. Regardless of whether

the displacement is developed or first-contact miscible, the solvent must immiscibly

displace any mobile water present with the resident fluids.

The economics of the process usually dictates that the solvent cannot be

injected indefinitely. Therefore, a finite amount or slug of solvent is usually followed

by a chase fluid whose function is to drive the solvent toward the production wells.

This chase fluid––N2, air, water, and dry natural gas seem to be the most common

choices––may not itself be a good solvent. But it is selected to be compatible with the

solvent and because it is available in large quantities. The similarity between the

chase fluid in solvent flooding and the mobility buffer drive in micellar-polymer

flooding is evident in Figs. 7-1 and 9-1.

Though the process shown in Fig. 7-1 appears relatively simple, the

displacement efficiency and volumetric sweep efficiency are quite complex. In Secs.

7-6 and 7-8, we apply the theory of Chaps. 5 and 6 to solvent flooding, but first we

must discuss selected physical properties of solvents and solvent–crude oil systems.

7-2 SOLVENT PROPERTIES

Figure 7-2 shows phase behavior data (P-T diagram) for various pure components

and air. For each curve, the line connecting the triple and critical points is the vapor

pressure curve; the extension below the triple point is the sublimation curve (see Sec.

4-1). The fusion curve is not shown. The pressure–temperature plot for air is really an

envelope, but its molecular weight distribution is so narrow that it appears as a line in

Fig. 7-2. Flue gas is also a mixture of nitrogen, carbon monoxide, and carbon dioxide

with a similarly narrow molecular weight distribution; its P-T curve would fall near

the nitrogen curve in Fig. 7-2.

The critical pressures for most components fall within a relatively narrow

range of 3.4–6.8 MPa (500–1,000 psia), but critical temperatures vary over a much

wider range. The critical temperatures of most components increase with increasing

molecular weight. Carbon dioxide (molecular weight, MW = 44) is an exception to

this trend with a critical temperature of 304 K (87.8°F), which is closer to the critical

temperature of ethane (MW = 30) than to propane (MW = 44). (See Vukalovich and

Altunin (1968) for a massive compilation of CO2 properties.) Most reservoir

applications would be in the temperature range of 294–394 K (70–250°F) and at

pressures greater than 6.8 MPa (1,000 psia); hence air, N2, and dry natural gas will all

be supercritical fluids at reservoir conditions. Solvents such as LPG, in the molecular

weight range of butane or heavier, will be liquids. Carbon dioxide will usually be a

supercritical fluid since most reservoir temperatures are above the critical

temperature. The proximity to its critical temperature gives CO2 more liquidlike

properties than the lighter solvents.

Figures 7-3 and 7-4 give compressibilities factors for air and carbon dioxide,

respectively. From these the fluid density ρ3 can be calculated

In Eq. (7.2-2), Ts and Ps are the standard temperature and pressure, respectively. All

fluids become more liquidlike, at a fixed temperature and pressure, as the molecular

weight increases. The anomalous behavior of CO2 is again manifest by comparing its

density and formation volume factor to that of air. For CO2 at 339 K (150°F) and 17

MPa (2,500 psia), ρ3 = 0.69 g/cm3, and B3 = 2.69 dm3/SCM. The values for air at the

same temperature and pressure are ρ3 = 0.16 g/cm3, and B3 = 7.31 dm3/SCM. The

CO2 density is much closer to a typical light oil density than is the air density; hence

CO2 is much less prone to gravity segregation during a displacement than is air.

Usually, gravity segregation in a CO2 flood is more likely where the water saturation

is high since CO2 tends to segregate more from water than oil.

From the formation volume factors, 370 SCM of CO2 is required to fill one

cubic meter of reservoir volume, whereas only 140 SCM air is required at the same

temperature and pressure. Thus about three times as many moles (recall that B3 is a

specific molar volume) of CO2 are required to fill the same reservoir volume as air.

Figures 7-5 and 7-6 give the viscosities of a natural gas mixture and pure

CO2. Over the pressure and temperature range shown, which includes the conditions

of interest in EOR, the viscosities of natural gas, and CH4, air, flue gas, and N2 are

about the same. But the CO2 viscosity is generally two or three times higher. Relative

to a hydrocarbon liquid or water viscosity, the values are still low, so there should be

no appreciable difference in the ease of injection of these solvents. However, the

CO2––crude-oil mobility ratio will be two or three times smaller than the other light

solvents; hence volumetric sweep efficiency will generally be better for CO2. (For the

correlations for other solvents and solvent mixtures, see McCain, 1973; Reid et al.,

1977; and Gas Processors Suppliers Association, 1973.)