Classification of EOR methods. Source: A Realistic Look at Enhanced Oil Recovery by S.M. Farouq Ali and S. Thomas

Enhanced Oil Recovery (EOR) (also called Tertiary Recovery, as opposed to Primary Recovery and Secondary Recovery) is a technique for increasing the amount of hydrocarbon that can be extracted from a reservoir using thermal, chemical, miscible gas injection, or other methods. Sometimes the term quaternary recovery is used to refer to more advanced, speculative, EOR techniques.[1][2][3][4]

When a oil/gas field reaches the mature stage within its lifecyle, its ability to produced hydrocarbon under "natural" or conventional means significantly diminishes to an uneconomical extend. Enhanced Oil Recovery is often employed to economically maximize the productivity from these fields. Using EOR, 30-60%, or more, of the reservoir's original oil can be extracted[5] compared with 20-40% from Primary Recovery and Secondary Recovery.


Methods to recover the last drop of oil from the developed oil fields with gas flood.

Since 1981 we have consumed oil faster than we have found it. Oil production in 33 out of 48 countries has now peaked, including Kuwait, Russia and Mexico. Global oil production is now also approaching an all time peak and can potentially end our Industrial Civilization. The most distinguished and prominent geologists, oil industry experts, energy analysts and organizations all agree that big trouble is brewing.

The world now consumes 85 million barrels of oil per day, or 40,000 gallons per second, and demand is growing exponentially.

There are only two alternates to address the present situation of oil needs one is Acclerating New Explorations to produce more oil. But taking the statistics into consideration there have been no significant discoveries of new oil since 2002. In 2001 there were 8 large scale discoveries, and in 2002 there were 3 such discoveries. In 2003 there were no large scale discoveries of oil. [6]

So, the second alternative is to Increase the production rates from the present oil flowing wells by developing more efficient methods for recovering oil which remains in the ground in known reservoirs after the first and second phases of conventional oil production.

This report concentrates on the second approach and assesses the potential for increasing domestic production from such known reservoirs by implementing different technologies.

Reservoir characteristics

Broadly speaking, there are three main reservoir characteristics that matter to production. The character of the reservoir rock (porosity and permeability), the composition and purity of the crude, and the strength and nature of the drive mechanism all influence the flow rate and ultimate productivity of a reservoir. Reservoir depth, orientation, and complexity are also importantfactors.[7]

Before going directly into the EOR techniques one should know the life of the producing oil well and stages involved in.

Life of a hydrocarbon reservoir

The life of a hydrocarbon reservoir goes through three distinct phases where various techniques are employed to maintain crude oil production at maximum levels. The primary importance of these techniques is to force oil into the wellhead where it can be pumped to the surface and to increase the oil production rates.

Recovery of hydrocarbons from an oil reservoir is commonly recognized to occur in several recovery stages. These are:

  1. Primary recovery
  2. Secondary recovery
  3. Tertiary recovery (Enhanced Oil Recovery, EOR)

Primary recovery

Oil extracted from its natural flow from a well by its pore pressure is considered as a primary recovery. There are several different energy sources, and each gives rise to a drive mechanism. Early in the history of a reservoir the drive mechanism will not be known. It is determined by analysis of production data (reservoir pressure and fluid production ratios). The earliest possible determination of the drive mechanism is a primary goal in the early life of the reservoir, as its knowledge can greatly improve the management and recovery of reserves from the reservoir in its middle and later life.

There are five important drive mechanisms (or combinations). These are:

  1. Solution gas drive
  2. Gas cap drive
  3. Water drive
  4. Gravity drainage
  5. Combination or mixed drive

The reservoir pressure and GOR trends for each of the main (first) three drive mechanisms is shown as Figures 1 and 2.

Fig 1, 2 indicates the resorvoir pressure and GOR trends. Source: MSc Course Notes Reservoir Drives, Chapter 3.
Table 1 indicates the % of oil recovery by primary stage of production. Source: MSc Course Notes Reservoir Drives, Chapter 3.

Table 1 is a clear indication of the percentage of oil recovery by primary recovery from the different drive mechanisms and there is plenty of oil still left out for extraction. The primary recovery stage reaches its limit either when the reservoir pressure is so low that the production rates are not economical, or when the proportions of gas or water in the production stream are too high. So this indicates that there is a need for other mechanical ways to extract the remaining.

Secondary oil recovery process. Image Source: Google Images.

Secondary recovery

Secondary oil recovery is employed when the pressure inside the well drops to levels that make primary recovery no longer viable. Pressure is the key to collecting oil from the natural underground rock formations in which it forms.

The second stage of hydrocarbon production during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding. Normally, gas is injected into the gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form or enhanced recovery.

The secondary recovery stage reaches its limit when the injected fluid (water or gas) is produced in considerable amounts from the production wells and the production is no longer economical. The successive use of primary recovery and secondary recovery in an oil reservoir produces about 15% to 30% of the original oil in place.

Tertiary recovery (Enhanced Oil Recovery, EOR)

The term enhanced oil recovery (EOR) basically refers to the recovery of oil by any method beyond the primary, secondary stage of oil production. It is defined as the production of crude oil from reservoirs through processes taken to increase the primary reservoir drive. These processes may include pressure maintenance, injection of displacing fluids, or other methods such as thermal techniques. There fore, by definition, EOR techniques include all methods that are used to increase cumulative oil produced (oil recovery) as much as possible.[8]

Enhanced oil recovery can be divided into two major types of techniques: Thermal and Non-thermal recovery. Figure 2 is a representation of the same.

Thermal methods

Thermal EOR methods which stimulate oil inflow rate and increase the oil well productivity are based on artificial temperature increase in the well hole and the bottom zone area. These methods are used mainly for the production of highly paraffin oil. The warming leads to oil liquefaction, melting down of paraffin, resinous substances accumulated on the pipes surface and in the bottom hole area.

The major techniques include:

Steam injection
Heat from the steam reduces the oil viscosity and increases its mobility. Source: Petros

Steam oil drive is an EOR method mostly used to displace high-viscosity oil. In this process steam is injected from the surface down to the low temperature and high viscosity oil formations through special steam injection wells.

The steam with a high heat capacity provides the oil formation with a significant amount of heat energy which heats the reservoir oil and reduces its relative permeability and viscosity. As a result the following three zones differing in temperature and saturation appear in the oil bearing formation:

  1. Steam area around the injection well with the temperature varying from the temperature of steam to the temperature of condensation (400-200 °C), which provides extraction of oil light fractions (oil distillation) and displacement of oil in the formation, i.e., joint filtration of steam and light oil fractions.
  2. Hot condensate zone, in which temperature varies from the temperature of the condensation beginning (200 °C) to the reservoir temperature and hot condensate (water) displaces oil under non- isothermal conditions.
  3. Zone with the initial formation temperature not covered by thermal effect. In this zone oil is displaced by reservoir water.

After steam heating the following processes take place: oil is distillated, reservoir fluids viscosity is reducing and all the formation agents are expanding their volumes, permeability, wet ability of formation and mobility of water and oil are also changing.

Cyclic steam treatment: Cyclic steam treatment is a periodic direct steam injection into the oil formation through production wells. After the injection period the well is shut in for some time and then is put back on production of heated (low viscosity) oil and condensed steam. The purpose of this technology is to heat the formation and oil in the bottom-hole zone of the producing wells, to reduce oil viscosity, to locally increase the reservoir pressure, to improve the filtration conditions and to increase the oil inflow to the well.

The mechanism of the processes occurring in the formation is quite complicated and accompanied by the same phenomena as in the steam treatment, but in addition to this in this case there occur a countercurrent capillary filtration and redistribution of the reservoir liquid when the well is shut in. During injection the steam penetrates into the most permeable reservoir layers and large pore zones. While soaking in the heated zone of the formation there is an active redistribution of saturation due to capillary forces: hot condensate replaces low-viscosity oil in the small pores and low permeable layers and forces it to the larger pores and higher permeable layers.

Such redistribution of oil and condensate saturation in oil reservoir is the physical basis of the process of oil extraction using cycling steam treatment. Without capillary exchange of oil and condensate during cycling steam soaking the impact would be minimal and limited to the first cycle only.

In situ combustion

(Injection of a hot gas that combusts with the oil in place.) The EOR method of oil extraction is based on the ability of reservoir hydrocarbons (oil) to join the air oxidation reaction with oxygen, accompanied with a release of large amounts of heat. It differs from burning on the surface. Generation of heat directly in the reservoir is the main advantage of this method.

In situ combustion starts near the bottom-hole of an injection well usually by means of air heating and further injections. The sources of the heat are commonly special bottom-hole electric heaters, gas burners and oxidation reactions.

After burning fire source at the well bottom-hole is set the further in situ combustion is supported by continuous air injection into the formation and diversion of the combustion products (N2, CO2, etc.) from the fire front.

Oil remaining in the formation after the displacement front is utilized as a fuel for further combustion. As a result the heaviest fractions of crude oil are burned out.

Figure: In-situ combustion EOR. Source: Petros

In case of conventional (dry) in-situ combustion the process is carried out by injecting only air into the oil reservoir. Since the air heat capacity is lower than that of the reservoir rock the rock heating front is moving behind the air combustion front. As a result the bulk of the heat generated in the formation (up to 80% or more) remains behind the air combustion front and is hardly used for the displacement but largely dissipated in the surrounding reservoir rock.

This heat has some positive impact on the subsequent displacement of oil by water in the reservoir zones not covered by the in-situ combustion process. It`s, however, clear, that the use of the bulk of the heat in the area ahead of the combustion front, i.e. approximation of the generated heat to the front of oil displacement, significantly increases the efficiency of the process.

Moving of the heat forward to the front is possible if an agent (such as water) with a higher than air heat capacity is added to the injected air. This EOR method of wet combustion has been recently successfully applied in some Russian oil fields and abroad.

During the wet in-situ combustion water injected into the formation together with air evaporates after contacting the heated rock. The vapor transfers heat to the reservoir zone ahead of the combustion front where large heated areas saturated with steam and condensed hot water are created.[9]

Limitation of Thermal methods:

This Process is applicable:

  • In shallow and thick, high permeability sand stone and unconsolidated sand to avoid heat loss in well and adjacent formation
  • Steam flooding is not normally used in carbonate formation and also where water sensitive clays are present
  • Also high mobility and challenging of steam may make the process unattractive
  • In high depth reservoir maintaining steam quality is not possible
  • Because of very high temperature special metallurgy
  • Tubing required in producers and injectors
  • Cost per incremental barrels is high
  • Normally 1/3 of incremental oil is used in generation of Steam.[10]

Benefits of Thermal Processes:

The benefits of thermal EOR processes include:

  • Improved sweep efficiency
  • Increased steam injectivity
  • Decrease in the number of wells required for field development
  • Longer well exposure
  • Lower pressure drop and injection pressure
  • Less heat loss as there is greater contact with the reservoir.[11]

Criteria for selecting Thermal process:

Non thermal methods

This is classified into different ways as follows:

A) Chemical methods

B) Microbial methods

C) Gas Drives

Each of the following will be discussed in this section

Chemical methods

Various chemical EOR processes

  • Surfactant flooding
  • Alkaline flooding
  • Polymer flooding

These methods are first of all suitable for enhanced oil recovery from the heavily depleted, flooded formations with scattered, irregular oil saturation.

The methods are applied in the deposits with low viscosity oil (no more than 10 mPa*s), low salinity water, where productive formations are represented by carbonated collectors with low permeability.

Surfactant flooding (including foam): Flood displacement is aimed at reducing the surface tension at the oil-water border, increasing oil mobility and improving its displacement by water. Due to improving the wet ability of rocks, water is better absorbed into the pores filled with oil. As a result water faster moves in the formation and displaces more oil.

Polymer displacement: During polymer flooding a high molecular chemical reagent – polymer (polyacrylamide) is dissolved in water. This reagent has the ability even at low concentrations to significantly increase water viscosity reducing its mobility and thus increase the coverage of reservoirs flooding.

Polymers are “thickening” the displacement water. This reduces difference between oil and water viscosities and as a result effectively prevents water breaking through oil due to viscosity difference or heterogeneity of the formation physical characteristics.

In addition polymer solutions of high viscosity displace not only oil, but also water from the porous medium. Therefore they interact with the skeleton of the porous medium, i.e. rock and its cementing substance. This causes the adsorption of polymer molecules which fall out of solution on the surface of the porous medium and cover the channels or impair filtration of water. The polymer solution preferably enters highly permeable layers and at the expense of increase in viscosity of the solution and reduce in conductivity of the medium there is a significant decrease in the dynamic heterogeneity of fluid flow and, consequently, increase in the coverage of reservoirs by water flooding.

Alkaline displacement: The EOR method of alkaline displacement is based on the interaction of alkalis with formation oil and rock. Oil interacts with organic acids, resulting into the formation of surface-active substances that reduces surface tension at the interface of oil-alkaline solution and increases rocks wet ability. Alkaline solution is one of the most effective ways to reduce the contact angle of water wetting of rock, i.e. hydrophilization of porous medium which leads to increased rate of oil displacement by water.

Basic mechanism involves:

  • Reduction in interfacial tension between oil and brine
  • Solubilization of released oil
  • Change in the wet ability towards more water wet
  • Reducing mobility contrast between crude oil and displacing fluid
  • Selection of chemical EOR processes
  • Type of reservoir
  • Rock mineralogy, clay, heterogeneity
  • Reservoir pay thickness, K, Ø
  • Reservoir temperature
  • Reservoir oil properties
  • Salinity of formation water and presence of bivalent cations

Limitations of chemical EOR processes:

  • Adsorption of chemicals on rock surfaces, particularly in carbonate formations and sandstone formations containing zeolites/clays.
  • Chromatographic separation of chemical where thickness vary
  • Dilution of chemical in active water reservoir
  • Incompatibility with formation fluids in which high bivalent-cations are present
  • High temperature and high salinity limits application of chemical processes. Reaction of alkali with clays and swelling causes permeability reduction
  • Advantages of chemical EOR processes
  • Right blend of chemical system can increase recovery factor by 15-20 %
  • Chemical processes can be combined with other EOR processes to derive advantage of each other
  • Processes can be tailor made to suit specific crude and reservoir conditions
  • Can be applied in both sandstone and carbonate formations
  • Can improve recovery of polymer flooding after it reaches its limit

Screening criteria for chemical process:

Microbial methods

Microbial enhanced oil recovery refers to the use of microorganisms to retrieve additional oil from existing wells, thereby enhancing the petroleum production of an oil reservoir. These technologies are based on biological processes with the use of microbial targets. During the process, microorganisms are delivered into the formation and they metabolize petroleum hydrocarbons and generate the following oil displacement useful products:

  • Alcohols, solvents and weak acids, which lead to a decrease in viscosity, oil fluidity temperature, as well as remove paraffin’s and heavy oil from porous rocks, increasing the permeability of the latter.
  • Biopolymers, which when dissolved in water, increase its density and facilitate oil recovery.
  • Biological surface-active substances, which make oil surface more slippery, reducing rock friction.
  • Gases that increase pressure inside the formation, and help to push oil to the well bore. [12][13]

The microorganisms for MEOR should have the following potential properties:

  • Small Size
  • Resistant to High Temperatures
  • Resistant against High Pressure
  • Capability of Withstand Brine and Seawater
  • Anaerobic Using of Nutrients
  • Unfastidious Nutritional requirements
  • Appropriate Biochemical Construction for Production Suitable Amounts of MEOR Chemicals
  • Lack of any Undesirable Characteristics

Advantages and Disadvantages of MEOR

Advantages of MEOR4

  • The injected bacteria and nutrient are inexpensive and easy to obtain and handle in the field
  • Economically attractive for marginally producing oil fields; a suitable alternative before the abandonment of marginal wells
  • According to a statistical evaluation (1995 in U.S.), 81% of all MEOR projects demonstrated a positive incremental increase in oil production and no decrease in oil production as a result of MEOR processes
  • The implementation of the process needs only minor modifications of the existing field facilities
  • The costs of the injected fluids are not dependent on oil prices
  • MEOR processes are particularly suited for carbonate oil reservoirs where some EOR technologies cannot be applied with good efficiency
  • The effects of bacterial activity within the reservoir are magnified by their growth whole, while in EOR technologies the effects of the additives tend to decrease with time and distance
  • MEOR products are all biodegradable and will not be accumulated in the environment, so environmentally friendly

Disadvantages of MEOR

  • Safety, Health, and Environment (SHE)
  • A better understanding of the mechanisms of MEOR
  • The ability of bacteria to plug reservoirs
  • Numerical simulations should be developed to guide the application of MEOR in fields
  • Lack of talents.

Selection criteria for microbial EOR implementation:

Gas injection

This process is mostly applied in light and tight reservoir because of its high microscopic displacement efficiency and can be combined with other recovery processes such as water or surfactant system. It can be applied in both miscible and immiscible ways

Various types of gas flooding various types of gas flooding

  • Hydrocarbon flooding (LPG,Air, Enriched and Lean gas)
  • CO2 flooding
  • N2 and Flue gas injection

AirInjection: Air injection is a technique for enhanced oil recovery (EOR) with several advantages. The injection gas source is air, which can be supplied anywhere, and the main facility required is simply an air compressor. Initial investment and operating costs are therefore lower than for other EOR methods. The main oil recovery mechanisms are the flue gas sweeping and thermal effect generated from oxidation and combustion reactions. Moreover, air can be applied even in low permeable reservoirs where water cannot be injected. However, the evaluation method for this technology is difficult, because oxidation and combustion reactions are complicated.

The advantages of the method include:

  • Use of air, that is an inexpensive agent;
  • Use of the natural energy of the formation, i.e. high formation temperatures (over 60-70 oС) for the spontaneous initiation of intraformational oxidation processes and creation of an efficient displacing agent.[14]

CO2Flooding: Carbon dioxide dissolves in water much better than hydrocarbon gases. The solubility of carbon dioxide in water increases with increasing of pressure and decreases with increasing of temperature.

When dissolved in water, carbon dioxide viscosity increases slightly and this increase is insignificant. With the mass content of 3-5% carbon dioxide in water its viscosity increases only by 20-30%. Formed by dissolving CO2 in water, carbonic acid N2CO3 dissolves some types of the rock cement increasing reservoir permeability. Clay water swell able also reduces because of the carbon dioxide. Carbon dioxide dissolves in oil 4-10 times better than in water, so it can pass from the aqueous solution into the oil. During the transition interfacial tension between oil and water becomes very low greatly improving the oil displacement process. Carbon dioxide in water contributes to the washing -off of the oil film which covers the primary rocks, and reduces the possibility of the water film breaking. As a result, drops of oil at a low interfacial tension roam freely in the pore channels and the oil phase permeability increases.

When CO2 dissolves in oil viscosity of oil decreases, its density increases, while the oil volume increases significantly: the oil swells.1,5-1,7 times increased oil volume with dissolved CO2 in it makes a particularly large contribution to oil recovery improvement in the low-viscosity oil reservoirs. In displacing high-viscosity oil the major factor that increases the rate of displacement is a decrease of oil viscosity due to dissolving CO2 in it. The larger the initial value of oil viscosity, the stronger is this decrease.

When reservoir pressure is above the pressure of full miscibility of formation oil with CO2, carbon dioxide will displace oil as an ordinary solvent. In this case three zones occur in the formation original formation oil, a transitional zone (from the properties of the original oil to the properties of the injected agent) and a zone of pure CO2. If CO2 is injected in the already water flooded formation, oil that displaces formation water, occur before the CO2 zone.

The volume expansion of oil due to the influence of dissolved CO2 on it, together with the change of viscosity of liquids (a decrease in oil viscosity and increase in water viscosity) are the main factors determining the efficiency of carbon dioxide use in oil extraction in general and extraction of oil from flooded reservoirs in particular.

Screening criteria for CO2 flooding:

Nitrogen and other HC flooding:

Nitrogen flooding can be a viable EOR method if the following conditions exist in the candidate reservoir:

  1. The reservoir oil must be rich in ethane through hexane (C2-C6) or lighter hydrocarbons. These crudes arecharacterized as "light oils" having an API gravity higher than 35 degrees.
  2. The oil should have a high formation-volume factor – the capability of absorbing added gas under reservoir conditions.
  3. The oil should be under saturated or low in methane (C1).
  4. The reservoir should be at least 5,000 feet deep to withstand the high injection pressure (in excess of 5,000 psi) necessary for the oil to attain miscibility with nitrogen without fracturing the producing formation.

Gaseous nitrogen (N2) is attractive for flooding this type of reservoir because it can be manufactured on site at less cost thanother alternatives. Since it can be extracted from air by cryogenic separation, there is an unlimited source, and beingcompletely inert it is noncorrosive. In general, when nitrogen is injected into a reservoir, it forms a miscible front by vaporizing some of the lighter components from the oil. This gas, now enriched to some extent, continues to move away from the injection wells, contacting new oil and vaporizing more components, thereby enriching it still further. As this action continues, the leading edge of this gas front becomes so enriched that it goes into solution, or becomes miscible, with the reservoir oil. At this time, the interface between the oil and gas disappears, and the fluids blend as one.

Continued injection of nitrogen pushes the miscible front (which continually renews itself) through the reservoir, moving a bank of displaced oil toward production wells. Water slugs are injected alternately with the nitrogen to increase the sweep efficiency and oil recovery.

At the surface, the produced reservoir fluids may be separated, not only for the oil but also for natural gas liquids and injected nitrogen.

Nitrogen Flooding
This method can be used as a substitute for CO2 in deep reservoirs with high API gravity oil. When injected at high pressure, nitrogen can form a miscible slug which aids in freeing the oil from the reservoir rock.

Screening criteria for N2 flooding:

Advantages of different gas flooding processes:

  • CO2 flood process can be applied to wider range of reservoir because of its lower miscibility than that for vaporizing gas drive
  • Oil recovery is high in miscible displacement, less in immiscible displacement
  • It swells the oil and reduces its viscosity even before miscibility’s achieved CO2 flooding HC flooding
  • Recovery factor in miscible HC flooding (LPG & Enriched) is quite high
  • Suitable for tight as well as light oil reservoirs
  • Can be applied both in carbonate and sandstone formations
  • Can be applied in reservoir depths ranging from 1000-5000 meters
  • It is a cheaper process and large volume can be applied
  • Can be applied in deep, tight and light reservoirsN2 Flooding.

Limitations of Gas flooding processes Limitations of Gas flooding processes

  • N2 /Flue gas Flooding /Flue gas Flooding
  • Can be applied only in high gravity and deep reservoirs
  • Miscibility pressure is quite high, can not be applied in depleted reservoirs with high temperature
  • Separation from non hydrocarbon gases from hydrocarbon gases at the surface
  • Recovery efficiency is low (<5%) compared to other gas processesHC Flooding HC Flooding
  • Required pressure for LPG is 1280 psi
  • 4000 to 5000 psi is required for high pressure gas drive
  • Solvent trapped may not be recovered in LPG method
  • Low viscosity results in poor vertical and horizontal sweep efficiency
  • Large quantity of available hydrocarbons are required

Steps for successful EOR project

Following figure shows the proper steps for choosing the proper methods for implementing the oil recovery.Fig 11. [15]

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[16]. 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.

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. [17] 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.[18]

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.[19] EPA has issued Underground Injection Control (UIC) regulations in order to protect drinking water sources.[20] 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.[18]

Source of information