Enhanced oil recovery
Enhanced Oil Recovery (abbreviated EOR) is a generic term for techniques for increasing the amount of crude oil that can be extracted from an oil field. Enhanced oil recovery is also called improved oil recovery or tertiary recovery (as opposed to primary and secondary recovery). Sometimes the term quaternary recovery is used to refer to more advanced, speculative, EOR techniques. Using EOR, 30 to 60 percent or more of the reservoir's original oil can be extracted, compared with 20 to 40 percent using primary and secondary recovery.
|This section does not cite any references or sources. (October 2012)|
The volumetric sweep efficiency at any time is the fraction of the total reservoir volume contacted by the injected fluid during the recovery. When using water, consideration of the mobility of the fluids, is an important factor when determining the area and vertical sweep efficiencies. This would help to determine the mobility ratio. If M is less than 1 then oil is capable of travelling at a rate equivalent to the water. An increase in the viscosity of the oil would mean that M would increase and this would lead to the injected fluid moving around the oil. This would also make it harder for the oil to penetrate the pore. To improve this ratio then the viscosity of the water has to be increased. When M is greater than 1 the displacing fluid has greater mobility than the displaced fluid. Also the position of the water injection and the flooding patterns would go a long way to determining the recovery patterns. Also to consider in oil recovery is the position and orientation of the injection wells around the production well. As the mobility ratio increases the sweep efficiency decreases. Once a channel of water exists between the injector and the producer then little additional oil would be recovered.
If permeability varies vertically then an irregular vertical fluid front can develop and this is as a result of the differing permeabilities and the mobility ratio.
Displacement efficiency refers to the fraction of oil that is swept from unit volume of reservoir upon injection. This depends on the mobility ratio, the wettability of the rock and the pore geometry. The wettability is determined by whether or not the grains preferentially absorb oil over water.
Gas injection 
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 water is reduced. This refers to removing the interface between the two interacting fluids. This allows for total displacement efficiency. 
3E Global, along with its strategic alliances, are working with mineral owners and energy companies to offer comprehensive EOR programs. Their process involves a proprietary all organic hydro carbon chemical used to infuse oil in the formation with Super Heated Nitrogen and CO2. This process reduces surface tension while raising the gravity of the oil thus increasing production by 100% - 700% or more in most wells. As an added benefit this process often enhances production in surrounding wells.
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 behaviour of the mixtures of that gas and the crude, which are strongly dependent on reservoir temperature, pressure and crude oil composition.
Miscible solvents 
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 has 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. Special formulations of oil, water and surfactant, microemulsions, can be particularly effective in this. 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.
Polymer flooding 
Polymer flooding is a means of injecting long chain polymer molecules in an effort to increase the injected water viscosity. The addition of these chemicals means that the fluid would behave like a non-Newtonian fluid; at low velocities it is resistant to flow. This method not only improves the mobility ratio (by lowering it) but also the vertical and areal sweep efficiency. The polymer causes a reduction in the permeability and allows the preferential filling of the high permeable zones in the reservoir. This lowers flow velocity and increases the sweep area.
Surfactant Polymer flooding these are surface active agents that help to break down the surface tension between the oil and water. This allows for the oil and water to separate. The effect of the surfactant depends on the concentration. In low concentrations the rate is gradual but in higher concentrations the rate is increased until such time that the surfactant is diluted by the formation fluids. It also improves the mobility of the fluids and reverses the rock wettablity.
Primary surfactants usually have Co-surfactants, activity boosters, Co-solvents added to them to improve stability of the formulation.
Caustic flooding is the addition of sodium hydroxide to injection water to aid recovery. It does this by lowering the surface tension, reversing the rock wettability, emulsification of the oil, mobilization of the oil and helps in drawing the oil out of the rock.
Microbial injection 
|This section relies on references to primary sources. (October 2012)|
Microbial injection is part of microbial enhanced oil recovery and is rarely used because of its higher cost and because the developments is not widely accepted. These microbes function either by partially digesting long hydrocarbon molecules, by generating biosurfactants, or by emitting carbon dioxide (which then functions as described in Gas injection above).
Three approaches have been used to achieve microbial injection. In the first approach, bacterial cultures mixed with a food source (a carbohydrate such as molasses is commonly used) are injected into the oil field. In the second approach, used since 1985, nutrients are injected into the ground to nurture existing microbial bodies; these nutrients cause the bacteria to increase production of the natural surfactants they normally use to metabolize crude oil underground. After the injected nutrients are consumed, the microbes go into near-shutdown mode, their exteriors become hydrophilic, and they migrate to the oil-water interface area, where they cause oil droplets to form from the larger oil mass, making the droplets more likely to migrate to the wellhead. This approach has been used in oilfields near the Four Corners and in the Beverly Hills Oil Field in Beverly Hills, California.
The third approach is used to address the problem of paraffin wax components of the crude oil, which tend to precipitate as the crude flows to the surface. Since the Earth's surface is considerably cooler than the petroleum deposits (a temperature drop of 9-10-14 °C per thousand feet of depth is usual).
Liquid carbon dioxide superfluids 
Carbon dioxide 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.
Hydrocarbon displacement 
Hydrocarbon displacement is where a slug of hydrocarbon gas is pushed into the reservoir in order to form a miscible phase at high pressure. This however suffers from poor mobility ratio, and the solvent’s ability to dissolve the oil is reduced as it goes through. As with all methods, this is only attempted when it is deemed economical.
Thermal methods 
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 drive 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 2011 solar thermal enhanced oil recovery projects were started in California and Oman, this method is similar to thermal EOR but uses a solar array to produce the steam.
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 Flood 
Fire flood 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 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.
Economic costs and benefits 
Adding oil recovery methods adds to the cost of oil — in the case of CO2 typically between 0.5-8.0 US$ per tonne of CO2. The increased extraction of oil on the other hand, is an economic benefit with the revenue depending on prevailing oil prices. Onshore EOR has paid in the range of a net 10-16 US$ per tonne of CO2 injected for oil prices of 15-20 US$/barrel. Prevailing prices depend on many factors but can determine the economic suitability of any procedure, with more procedures and more expensive procedures being economically viable at higher prices. Example: With oil prices at around 90 US$/barrel, the economic benefit is about 70 US$ per tonne CO2.
Examples of current EOR projects 
In Canada, a CO2-EOR project has been established by Cenovus Energy at the Weyburn Oil Field in southern Saskatchewan since 2000. The project is expected to inject a net 18 million ton CO2 and recover an additional 130 million barrels (21,000,000 m3) of oil, extending the life of the oil field by 25 years. There is a projected 26+ million tonnes (net of production) of CO2 to be stored in Weyburn, plus another 8.5 million tonnes (net of production) stored at the Weyburn-Midale Carbon Dioxide Project, resulting in a net reduction in atmospheric CO2). That's the equivalent of taking nearly 7 million cars off the road for a year. Since CO2 injection began in late 2000, the EOR project has performed largely as predicted. Currently, some 1600 m3 (10,063 barrels) per day of incremental oil is being produced from the field.
Potential for EOR in United States 
The United States has been using EOR for several decades. For over 30 years, oil fields in the Permian Basin have implemented CO2 EOR using naturally sourced CO2 from New Mexico and Colorado. The Department of Energy (DOE) has estimated that full use of 'next generation' CO2-EOR in United States could generate an additional 240 billion barrels (38 km3) of recoverable oil resources. Developing this potential would depend on the availability of commercial CO2 in large volumes, which could be made possible by widespread use of carbon capture and storage. For comparison, the total undeveloped US domestic oil resources still in the ground total more than 1 trillion barrels (160 km3), most of it remaining unrecoverable. The DOE estimates that if the EOR potential were to be fully realised, state and local treasuries would gain $280 billion in revenues from future royalties, severance taxes, and state income taxes on oil production, aside from other economic benefits.
Environmental impacts 
Enhanced oil recovery wells typically produce large quantities of brine at the surface. The brine may contain toxic metals and radioactive substances, as well as being very salty. This can be very damaging to drinking water sources and the environment generally if not properly controlled.
In the United States, injection well activity is regulated by the United States Environmental Protection Agency (EPA) and state governments under the Safe Drinking Water Act. EPA has issued Underground Injection Control (UIC) regulations in order to protect drinking water sources. Enhanced oil recovery wells are regulated as Class II wells by the EPA. The regulations require well operators to reinject the brine used for recovery deep underground in Class II Disposal Wells.
See also 
- Wikiversity:Enhanced oil recovery
- Carbon capture and storage
- Gas reinjection
- Injection well
- Steam assisted gravity drainage
- Steam injection (oil industry)
- Water injection (oil production)
- Downhole Seismic Stimulation
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