The third stage of enhanced recovery from an oil and gas production well begins when after pressure maintenance and water flood operations have already been in place. The addition of a second force for enhancing oil production progresses a well from the second stage of recovery to the third and final stage. While it’s the last stage, it may often be wise to install both second and third stage recovery systems as early as is practical. At that point, the well is most likely still producing at high enough levels to pay for the equipment and can be used to extend the life of the well.
There can be a wide range of forces used for producing oil, but there are a few that are used commonly. Water and heat can be used together to create steam. Water and CO2 might be injected, or slugged, alternately into the well, as could water and polymer chemicals. Water generally serves as one of the two forces, as it’s easily available and well understood.
The term ‘tertiary recovery’ is an older term that’s not as popular as it once was. As mentioned above, techniques that were once considered part of tertiary recovery may be installed and sued at any point in the well’s life, so the distinction is not as meaningful as it once was.
These methods involve injecting a fluid or solvent into the reservoir. Miscibility is the measure of two substances tendency to mix. Water and oil are generally immiscible, meaning they do not mix. Miscible displacement methods use a fluid or chemical solvent that will mix completely with the oil and help release it from the rock formation. A second force, generally water or gas, is injected after the solvent to force it into the formation and to sweep the solvent and oil together to the producing well.
A few of the different solvents, gases, and fluids used for miscible displacement include refined hydrocarbons and hydrocarbon gases, liquefied petroleum gases, CO2, and inert nitrogen gas. Inert gas has become increasingly popular.
CO2 injection is the most form of miscible displacement. Carbon dioxide is injected into the reservoir and followed up with a slug of water. The CO2 is swept through the formation, and recovered from production wells. The CO2 can be separated from other gases produced from a well and reused. The CO2 will work as a solution gas drive in the reservoir, as it is soluble in both water and oil and will therefore cause the fluids to swell. This increases pressure which results in an increase in production. This is more efficient than natural gas or LPG gas.
While more efficient, using CO2 for miscible displacement does have a few drawbacks. When CO2 and water are used together, the mixture will result in carbonic acid, which is extremely corrosive. When injecting CO2, the wellhead will usually need to be prepared by installing stainless steel bolts, seals, and other fittings. It may also be difficult for CO2 to mix with heavier oil elements, which can reduce the technique’s efficiency.
Inert Gas Injection
Injecting inert nitrogen gas is similar to injecting dry natural gas. Inert gas may need a higher pressure than natural gas to best mix with emulsion, but it can be swept through a formation more than once.
Thermal methods includes different techniques for using heat to increase production.
This term refers to injecting steam down a well, and then recovering it directly from the same well. The same general process can also be referred to as huff and puff, steam injection, or steam soak. The steam is injected over a number of days, generally between a week and a month. The well is shut in for a few days, which allows the steam to heat the reservoir. The heat thins the oil, which eases flow of the oil through the reservoir.
After the well is returned to production, the oil is allowed to flow until the rate slows to the point that the process needs to be repeated. At this point, the operation will most likely be changed to steam injection.
Hot Water Injection
Steam and hot water flood work essentially the same way as water flood or gas injection; the steam is injected and then sweeps to a second well where it is produced with natural gas and emulsion. As heat spreads through the formation, the oil expands which leads to an increase in production.
Steam and hot water injection make up about ⅕ of enhanced recovery operations. Wells for flooding steam require about 5 acres of land, and the technique can be used with reservoirs from 10 ft to 5,000 ft deep. Hot water can also be used, but is less efficient.
In Situ Combustion
In situ combustion is the practice of lighting a fire within a formation, burning the oil and using the heat generated to increase production. Injecting compressed air drives the fire across the reservoir. As the fire moves, the oil’s viscosity drops which allows the oil to expand. That can lead to an increase in production.
In situ combustion can take 2 forms, either forward or reverse. With forward combustion, the fire is ignited near the air injection well and then driven across the formation to the production wells. With reverse combustion, the fire is first driven away from the initial air injection well to producing wells. After a certain point, the direction is reversed and what was initially the injection well becomes a production well.
In situ combustion may not be economical in every case. Variations on this basic process, called wet and partially wet combustion, are being developed to address these issues.
Methods of tertiary recovery that use chemicals are used in only a few cases. The chemicals are often too expensive too be economical, and the other equipment can also be quite expensive. Using the chemicals also comes with some risk.
Surfactants are chemicals that breaks down the surface tension between two substances. In this case, the chemicals are used to break down the interfacial tension between water and oil. Surfactants may also be called micro-emulsions, soluble oil, or micellar solution. The surfactants are followed up by a polymer injection, which provides mobility control.
This particular method of enhanced recovery is not as efficient as others, as reservoir rock can absorb the surfactants, and it can also become more difficult to mobilize oil.
Polymers have large molecules which can increase the viscosity of water. This can make water flooding operations more efficient. Polymers used in this technique are generally either polyacrylamides or polysaccharides. Polyacrylamides are used in concentrations from 50 ppm to 1000 ppm. This polymer decreases the permeability of reservoir rock, which can decrease the mobility of injected fluid. Polysaccharides, on the other hand, do little to reduce permeability of rock but increase the viscosity of fluids. Using polymers can increase production over the long term.
Alkaline flooding raises the alkalinity of the water injected into the reservoir, which can improve production. Alkalinity is measured by pH. A pH of 7 is considered neutral. A substance with a lower pH is acidic, while a pH of 7 or higher is considered an alkaline, also called a base. A fluid with a pH of 12-13 is the most you’ll want to use.
The cost of alkaline flooding is fairly low compared to some of the other techniques. The increase in production is not a large as some other tertiary recovery methods, but the cost is low enough that profits are higher.
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