Enhanced oil recovery

Enhanced oil recovery, also called tertiary recovery, is the extraction of crude oil from an oil field that cannot be extracted after primary and secondary recovery methods have been completely exhausted. Whereas primary and secondary recovery techniques rely on the pressure differential between the surface and the underground well, enhanced oil recovery functions by altering the physical or chemical properties of the oil itself in order to make it easier to extract. When EOR is used, 30% to 60% or more of a reservoir's oil can be extracted, compared to 20% to 40% using only primary and secondary recovery.
There are four main EOR techniques: carbon dioxide injection, gas injection, thermal EOR, and chemical EOR. More advanced, speculative EOR techniques are sometimes called quaternary recovery. Carbon dioxide injection, known as CO₂-EOR, is the most common method. In this method, CO₂ is injected into a depleted oil field and is mostly left underground.
CO₂-EOR is usually performed using CO₂ from naturally occurring underground deposits. It is also sometimes performed using CO₂ captured from the flue gas of industrial facilities. When EOR is done using CO₂ captured from flue gas, the process can prevent some emissions from escaping. However, there is controversy over whether the overall process is beneficial for the climate. EOR operations are energy-intensive, which leads to more emissions, and further emissions are produced when the recovered oil is burned.
EOR adds to the cost of producing oil but can be economically attractive if the price of oil is high. The U.S. Department of Energy estimates that 20 billion tons of captured CO₂ could produce 67 billion barrels of economically recoverable oil. As a means of boosting domestic oil production, the US federal tax code began to include incentives for EOR in 1979.

Purpose

Crude oil development and production can include up to three distinct phases: primary, secondary, and tertiary recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques which bring the oil to the surface. But only about 10 percent of a reservoir's original oil in place is typically produced during primary recovery. Secondary recovery techniques extend a field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.
Producers have attempted several tertiary, or enhanced oil recovery, techniques that offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place.

Methods

The main classes of EOR technologies are:

CO₂ EOR: CO₂ is injected into the subsurface.
Other gas injection EOR: similar to CO₂-EOR, but with other gases injected such as natural gas or nitrogen.
Thermal EOR: steam is used to heat the oil in the ground, reducing its viscosity and making it easier to move. This is most often applied in heavy oil reservoirs.
Chemical EOR: water soluble polymers and/or surfactants are added to water that is injected into the subsurface. Polymer-loaded water has a high viscosity and can push more oil out of the pores in the oil-bearing formation. Surfactants reduce the surface tension of the oil, improving its ability to be displaced by water.
Other EOR: this class contains all other technologies such as microbial EOR, in which micro-organisms are injected in the reservoir, or combustion EOR, which involves in-situ burning of some of the oil to generate both heat and gases that help the rest of the oil move more easily.

In 2017, there were 374 EOR projects worldwide. Of these, 44% were CO₂-EOR, 12% were other gas injection EOR, 32% were thermal EOR, 9% were chemical EOR, and 2% were other EOR methods.

Injection of CO₂ or other gases

Gas injection or miscible flooding is presently the most-commonly used approach in enhanced oil recovery. Miscible flooding is a general term for injection processes that introduce miscible gases into the reservoir. A miscible displacement process maintains reservoir pressure and improves oil displacement because the interfacial tension between oil and gas is reduced. This refers to removing the interface between the two interacting fluids. This allows for total displacement efficiency.
Gases used include CO₂, natural gas or nitrogen. The fluid most commonly used for miscible displacement is carbon dioxide because it reduces the oil viscosity and is less expensive than liquefied petroleum gas. Oil displacement by carbon dioxide injection relies on the phase behavior of the mixtures of that gas and the crude, which are strongly dependent on reservoir temperature, pressure and crude oil composition.
Using CO₂ for enhanced oil recovery was first investigated and patented in 1952. The process was first commercially attempted in 1977 in Scurry County, Texas. Since then, the process has become extensively used in the Permian basin region of the US and is now more recently is being pursued in many different states. It is now being more actively pursued in China and throughout the rest of the world.
Most CO₂ injected in CO₂-EOR projects comes from naturally occurring underground CO₂ deposits. Some CO₂ used in EOR is captured from industrial facilities such as natural gas processing plants, using carbon capture technology.

Supercritical carbon dioxide

CO₂ is particularly effective in reservoirs deeper than 2,000 ft., where CO₂ will be in a supercritical state. In high pressure applications with lighter oils, CO₂ is miscible with the oil, with resultant swelling of the oil, and reduction in viscosity, and possibly also with a reduction in the surface tension with the reservoir rock. In the case of low pressure reservoirs or heavy oils, CO₂ will form an immiscible fluid, or will only partially mix with the oil. Some oil swelling may occur, and oil viscosity can still be significantly reduced.
In these applications, between one-half and two-thirds of the injected CO₂ returns with the produced oil and is usually re-injected into the reservoir to minimize operating costs. The remainder is trapped in the oil reservoir by various means. Carbon dioxide as a solvent has the benefit of being more economical than other similarly miscible fluids such as propane and butane.

Water-alternating-gas (WAG)

Water-alternating-gas injection is another technique employed in EOR. Water is used in addition to carbon dioxide. A saline solution is used here so that carbonate formations in oil wells are not disturbed. Water and carbon dioxide are injected into the oil well for larger recovery, as they typically have low miscibility with oil. Use of both water and carbon dioxide also lowers the mobility of carbon dioxide, causing the gas to displace more oil. According to a study done by Kovscek, using small slugs of both carbon dioxide and water allows for quick recovery of the oil. Additionally, in a study done by Dang in 2014, using water with a lower salinity allows for greater oil removal, and greater geochemical interactions.

Thermal injection

In this approach, various methods are used to heat the crude oil in the formation to reduce its viscosity and/or vaporize part of the oil and thus decrease the mobility ratio. The increased heat reduces the surface tension and increases the permeability of the oil. The heated oil may also vaporize and then condense forming improved oil. Methods include cyclic steam injection, steam flooding and combustion. These methods improve the sweep efficiency and the displacement efficiency. Steam injection has been used commercially since the 1960s in California fields. In solar thermal enhanced oil recovery, a solar array is used to produce the steam.

Steam flooding

Steam flooding is one means of introducing heat to the reservoir by pumping steam into the well with a pattern similar to that of water injection. Eventually the steam condenses to hot water; in the steam zone the oil evaporates, and in the hot water zone the oil expands. As a result, the oil expands, the viscosity drops, and the permeability increases. To ensure success the process has to be cyclical. This is the principal enhanced oil recovery program in use today.

Fire flooding

Fire flooding works best when the oil saturation and porosity are high. Combustion generates the heat within the reservoir itself. Continuous injection of air or other gas mixture with high oxygen content will maintain the flame front. As the fire burns, it moves through the reservoir toward production wells. Heat from the fire reduces oil viscosity and helps vaporize reservoir water to steam. The steam, hot water, combustion gas and a bank of distilled solvent all act to drive oil in front of the fire toward production wells.
There are three methods of combustion: Dry forward, reverse and wet combustion. Dry forward uses an igniter to set fire to the oil. As the fire progresses the oil is pushed away from the fire toward the producing well. In reverse the air injection and the ignition occur from opposite directions. In wet combustion water is injected just behind the front and turned into steam by the hot rock. This quenches the fire and spreads the heat more evenly.

Chemical injection

The injection of various chemicals, usually as dilute solutions, have been used to aid mobility and the reduction in surface tension. Injection of alkaline or caustic solutions into reservoirs with oil that have organic acids naturally occurring in the oil will result in the production of soap that may lower the interfacial tension enough to increase production. Injection of a dilute solution of a water-soluble polymer to increase the viscosity of the injected water can increase the amount of oil recovered in some formations. Dilute solutions of surfactants such as petroleum sulfonates or biosurfactants such as rhamnolipids may be injected to lower the interfacial tension or capillary pressure that impedes oil droplets from moving through a reservoir, this is analyzed in terms of the bond number, relating capillary forces to gravitational ones. Special formulations of oil, water and surfactant, microemulsions, can be particularly effective in reducing interfacial tension. Application of these methods is usually limited by the cost of the chemicals and their adsorption and loss onto the rock of the oil containing formation. In all of these methods the chemicals are injected into several wells and the production occurs in other nearby wells.