Typical alkaline-surfactant-polymer flood injection sequence. (Image courtesy of Surtek)

About 300 Bbbl of oil are trapped in identified geologic structures within producing US fields. This is the target for enhanced oil recovery (EOR) and represents the single largest source of future US oil supply.

Even at current prices, chemical flood technologies are one group of techniques that could be used to produce a portion of this vast resource. They include techniques to change injected fluid-flow patterns, allowing oil to be produced from a greater percentage of the reservoir. In general, these techniques do not reduce waterflood residual oil saturation. They include polymer gelation and mobility-control polymer floods.

Other chemical flood techniques include alkaline-polymer, surfactant-polymer, and alkaline-surfactant-polymer floods. These reduce waterflood residual oil saturation while simultaneously improving reservoir contact by the injected fluids.

Chemical flooding can be applied to any location as long as vehicles can haul equipment and chemicals to the site. Connection to a pipeline or other infrastructure, as with CO2 flooding, is not required.

Successful chemical flooding requires that the operator understand the reservoir and chemical process being considered. Implementing a chemical flood must include sound reservoir engineering and geologic analyses using available or easily attainable data, including how injected fluids flow through the reservoir, waterflood oil recovery, volume of oil in the reservoir targeted for chemical flooding, waters available for chemical dissolution, and injectivity potential.

The engineer can then decide if the reservoir is a candidate for chemical flooding, the type to be used, and how to implement the flood. Numerical simulation can be a useful tool to assimilate data. Data from laboratory evaluations not only show what technique to use but provide an estimate of the volume of additional oil that can be produced, allowing for an informed go/no-go decision.

Numerical simulation is the next logical step to translate laboratory studies to field performance. Numerical simulation validates the geological model with a history match of existing field performance and validation of the chemical model by matching corefloods that use reservoir rock. Oil production forecasts can then calculate project economics. Injection plant and chemicals for injection represent 95% or more of the total cost.

Once reservoir engineering evaluations, laboratory studies, and numerical simulation have shown that a technology can clear economic hurdles, proper facilities design and construction is essential. Injected chemical solutions must have proper chemical concentrations and express the physical properties dictated by the laboratory study. In addition, water treatment is an essential part of the mixing plant and can be a significant portion of the facility. Project implementation does not simply mean design, fabrication, and installation of appropriate chemical EOR processing and injection facility. Implementation really refers to successfully duplicating laboratory results on a field level.

Even with a proper injection plan, a project can fail if field operations are neglected. Finally, continual monitoring of the project so as to make adjustments as necessary is important to maximize oil recovery.

Gauging efficiency factors

All oil recovery operations attempt to improve the two efficiency factors, volume contact efficiency (EV) and displacement efficiency (ED).

Chemical flooding technologies can affect one or both of the efficiency factors. Mobility-control polymer flood and gel polymer improve EV. Surfactants and alkali improve ED. Alkaline-polymer, surfactant-polymer, and alkaline-surfactant-polymer flood technologies improve both EV and ED simultaneously, maximizing oil recovery.

Mechanistically, polymer technologies improve EV by either blocking flow into high-capacity matrices or altering the mobility of injected fluids. Injected fluids’ mobility is altered by increasing the injected solution viscosity and decreasing the matrix permeability to the injected fluid, or both simultaneously.

A mobility control polymer flood is a large-volume injection of anionic polymer at concentrations sufficient to increase the injected aqueous phase viscosity, reducing the mobility ratio to more favorable levels. Polymer injection could result in 5% to 10% additional oil in applicable reservoirs. Reservoir characteristics that make a reservoir amenable to mobility control flooding are 1) it is a waterflood candidate, 2) the mobility ratio is adverse, and 3) reservoir heterogeneity exists but is not so highly fractured that direct channels exist between an injection well and a production well.

In a polymer gel treatment a gelant composed of polymer and a cross-linking agent are injected into targeted thief zones of an oil reservoir with the objective of reducing permeability or plugging off those zones to water injection. Gel treatments generally are near-wellbore treatments of limited volume, altering vertical contact efficiency.

Highly fractured reservoirs or injection wells with high-capacity thief zones are the best candidates. Lenticular noflow boundaries are a benefit.

Surfactants and alkali improve ED primarily by decreasing the interfacial tension between oil and injected fluid, allowing the oil saturation of the matrix to be lowered below that achievable by water. Surfactants and alkali can also change the wettability or the affinity of the rock to contact both oil and water, thereby improving oil recovery.
Alkali, when combined with either surfactant or polymer, can increase oil recovery by 1) reacting with components of the crude oil to produce inexpensive surfactant in situ, 2) improving the performance of the surfactant and polymer through reduced adsorption onto the rock matrix, 3) reducing the size of polymer, which allows the injected fluid to enter smaller pore throats, 4) increasing activity of both the polymer and surfactant by reducing divalent cation mixing in situ, 5) acting as a mild biocide, and 6) other aspects as dictated by water used for chemical dissolution. Blending polymer with alkali, surfactant, or both imparts all the mechanistic oil recovery methodology to the injected fluid.

Figure 1 shows a typical injection sequence for an alkaline-surfactant- polymer flood. In this case, alkali plus surfactant mixed with polymer is injected for 0.3 to 0.4 pore volume followed by a similar volume of polymer solution. Injection is into an injection well with injected fluid and an oil bank moving through the reservoir to a production well.

Injection sequence example

The Rapdan mobility control polymer flood is an excellent example of oil acceleration by injection of a large volume of polymer solution. The Rapdan Unit is located in the southwest corner of the province of Saskatchewan, Canada, approximately 18 miles (30 km) from the Montana border. The 11,200-acre unit was discovered in 1953 and unitized in 1957. It produces from the Upper Shaunavon (Jurassic) formation at a depth of 4,590 ft (1,400 m).

The Rapdan polymer flood is located in the southeast flank of the field, containing the thickest sand deposit and the best reservoir quality. The Rapdan unit has 105 MMbbl of original oil in place (OOIP). No significant aquifer is present, although some formation water was produced at the southeast edge of the pool during primary production. Average connate water saturation is 30%.

The total polymer flood pilot increased in production from 409 b/d in the 1986-87 time period to a peak production of 1,132 b/d in June 1990 with a corresponding oil cut increase from 18% to a peak of 36% in June 1990. Through February 2009 a total 8.3 MMbbl of oil or 44.8% OOIP has been produced by primary, waterflood, and polymer flood. Numerical simulation waterflood prediction was 5.8 MMbbl of oil or 31.3% OOIP. Accelerated oil produced was 2.5 MMbbl or 13.5% OOIP. Chemical, plant, and operations cost per incremental barrel are US $2.05.