Page 356 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Enhanced Oil Recovery Methods 323

Polymer-thickened water is then injected to push the mobilized oil-water bank to
the producing wells. Water-soluble polymers can be used in a similar fashion with
alkaline flooding. For micellar/polymer flooding, the concentration of polymer used
may be similar to the value given for polymer flooding, but the volume of polymer
solution may be increased to 50% or more of a reservoir pore volume.

Alkaline Floodlng. Alkaline or caustic flooding consists of injecting aqueous
solutions of sodium hydroxide, sodium carbonate, sodium silicate or potassium
hydroxide. The alkaline chemicals react with organic acids in certain crude oils
to produce surfactants in situ that dramatically lower the interfacial tension
between water and oil. The alkaline agents also react with the reservoir rock
surfaces to alter wettability-either from oil-wet to water-wet, or vice versa. Other
mechanisms include emulsification and entrainment of oil or emulsification and
entrapment of oil to aid in mobility control. Since an early patent in the 1920s
described the use of caustic for improved recovery of oil, much research and
some field tests have been conducted. Slug size of the alkaline solution is often
10%-15% PV, concentrations of the alkaline chemical are normally 0.2% to 5%.
Recent tests are using large amounts of relatively high concentrations. A preflush
of fresh or softened water often precedes the alkaline slug, and a drive fluid
(either water or polymer-thickened water) follows the alkaline slug.

SurfactantlPolymer Floodlng. Surfactant use for oil recovery is not a recent
development. Patents in the late 1920s and early 1930s proposed the use of low
concentrations of detergents to reduce the interfacial tension between water and
oil. To overcome the slow rate of advance of the detergent, Taber [389] proposed
very high concentrations (-10%) of detergent in aqueous solution.
During the la* 1950s and early 1960s, several different present-day methods
of using surfactants for enhanced recovery were developed. A review of these
methods is beyond the scope of this chapter and is available in the literature
[390-3931. In some systems, a small slug (> about 5% PV) was proposed that
included a high concentration of surfactant (normally 5%-10%). In many cases,
the microemulsion includes surfactant, hydrocarbon, water, an electrolyte (salt),
and a cosohrent (usually an alcohol). These methods ordinarily used a slug (30%-
50% PV) of polymer-thickened water to provide mobility control in displacing
the surfactant and oil-water bank to the producing wells. The polymers used
are the same as those discussed in the previous section. In most cases, low-cost
petroleum sulfonates or blenda with other surfactants have been used. Inter-
mediate surfactant concentrations and low concentration systems (low tension
waterf loodmg) have also been proposed. The lower surfactant concentration
systems may or may not contain polymer in the surfactant slug, but will utilize
a larger slug (30%-100% PV) of polymer solution.

Alkallne/Surfacttmt/Polymer Floodlng. A recent development uses a combina-
tion of chemicals to lower process costs by lowering injection cost and reducing
surfactant adsorption. These mixtures, termed alkaline/surfactant/polymer
(ASP), permit the injection of larger slugs of injectant because of the lower cost.

Gas Injection Methods
Hydrocarbon Mlscible Floodlng

Gas injection is certainly one of the oldest methods utilized by engineers to
improve recovery, and its use has increased recently, although most of the new
expansion has been coming from the nonhydrocarbon gases [394]. Because of