June 12th, 2021 | Updated on June 25th, 2022
Primary, secondary, and tertiary (or enhanced) recovery are three distinct stages of crude oil development and production in US oil reservoirs.
During the primary recovery process, the reservoir’s natural pressure or gravity forces oil into the wellbore, which is then brought to the surface using artificial lift methods (such as pumps).
However, during primary recovery, only approximately 10% of a reservoir’s initial oil in place is usually obtained.
Secondary recovery procedures mainly include pumping water or gas into a field to displace oil and push it to a production wellbore, resulting in the recovery of 20 to 40% of the available oil.
With most of the easy-to-produce oil already extracted from US oil fields, producers have tried several tertiary or enhanced oil recovery (EOR) methods with the potential to recover about 30 to 60 percent or even more from the residual oil zones (ROZs). To varying degrees, three key types of EOR have been proven to be commercially viable:
- Thermal Recovery: includes injecting the heat into the reservoir, in the form of steam, to reduce the viscosity, or thin, the heavy viscous oil, and enhance its ability to flow through. Thermal approaches account for more than 40% of EOR generation in the United States, especially in California.
- Gas Injection: employs gases that expand in a reservoir, such as natural gas, nitrogen, or carbon dioxide (CO2), to push more oil to a production wellbore or other gases that dissolve in the oil to decrease its viscosity and enhance its flow rate. In the United States, gas injection contributes to roughly 60% of EOR output.
- Chemical Injection: Long-chained molecules called polymers are used to improve the efficacy of waterfloods. At the same time, detergent-like surfactants are utilized to lower the surface tension that inhibits oil droplets from flowing through a reservoir. Chemical approaches account for around 1% of EOR generation in the United States.
How CO2 Injection Increases Oil Production
Co2 injection, also known as CO2 flooding, is injecting carbon dioxide into oil reservoirs to enhance the amount of oil produced and has been a common oil recovery method in the Permian Basin, where it was first tested in 1972.
Although more research work is going on, the continued application of CO2-EOR in the Permian region influenced by the availability of CO2 in the region has seen many successful recovery projects.
Carbon dioxide flooding is an excellent tertiary recovery technique when a reservoir’s pressure has been decreased by primary and secondary output.
It’s very effective in reservoirs deeper than 2,500 feet, whereby CO 2 will be supercritical, the API oil gravity will be greater than 22–25 degrees, and the residual oil saturation will be higher than 20%.
Carbon dioxide flooding is not impacted by the reservoir’s geology but rather by its porosity and permeability, making it feasible in sandstone and carbonate reservoirs.
The process follows the principle that The viscosity of any hydrocarbon will be lowered by pumping CO2 into the reservoir, making it easier to flow to the production well.
The initial stage in CO2 flooding is to inject water into the reservoir, which causes the reservoir pressure to rise.
After the reservoir has reached the desired pressure, the CO2 is pumped down via the same injection wells. CO2 gas is injected into the reservoir in order to make contact with the oil.
This results in a miscible zone that is easier to transport to the production well. CO2 injections are usually alternated with water injections, with the water acting as a vehicle to sweep the oil into the producing zone.
CO2-EOR provides two significant benefits: increased hydrocarbon recovery, which improves energy independence, and CO2 storage, which reduces CO2 emissions into the atmosphere.
Several researchers have claimed increased oil recoveries using carbonated water based on their experimental work as early as 1951 as part of the development effort to better understand the CO2-EOR process.
The Engineering Aspect Of CO2-EOR
As explained earlier, CO2 from a natural or industrial source is pumped into a specified oil reservoir as a continuous gas or as a water-alternating gas injection, commonly known as a WAG.
Not all reservoirs are eligible for CO2-EOR, and those that are, are screened based on parameters such as reservoir geology, minimum miscibility pressure (MMP), oil gravity, and viscosity to find the most probable candidates for miscible CO2.
Reservoirs with a minimum mid-point reservoir depth of 3,000 feet or deeper were chosen for preliminary screening because the temperature and pressure at that level promote CO2 miscibility with the reservoir oil while also allowing for high-pressure CO2 injection.
Any deviation from the criterion mentioned above for selecting a reservoir would be determined by the reservoir’s size and hydrocarbon recovery potential.
The US Environmental Protection Agency (EPA) regulations for the protection of underground sources of drinking water (USDW) state that CO2 storage should be avoided in formations containing water with less than 10,000 mg/L (milligrams per liter) total dissolved solids (TDS). However, the EPA may grant exemptions for CO2-EOR projects.