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.)
