Enhanced Oil Recovery (EOR) (also called Tertiary Recovery, as opposed to Primary

Recovery andSecondary 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.

Contents

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1 Introduction

2 Reservoir characteristics

3 Life of a hydrocarbon reservoir

o 3.1 Primary recovery

o 3.2 Secondary recovery

o 3.3 Tertiary recovery (Enhanced Oil Recovery, EOR)

3.3.1 Thermal methods

3.3.1.1 Steam injection

3.3.1.2 In situ combustion

3.3.2 Non thermal methods

3.3.2.1 Chemical methods

3.3.2.2 Microbial methods

3.3.2.3 Gas injection

4 Steps for successful EOR project

5 Economic costs and benefits

6 Potential for EOR in United States

7 Environmental impacts

8 Source of information

Introduction

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 ofcrude 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:

Source: Petroleum Federation of India (PetroFed)

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:

Source: Petroleum Federation of India (PetroFed)

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:

Source: Petroleum Federation of India (PetroFed)

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:

Source: Petroleum Federation of India

(PetroFed)

Nitrogen and other HC flooding:

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

candidate reservoir:

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.

The oil should have a high formation-volume factor – the capability of absorbing added

gas under reservoir conditions.

The oil should be under saturated or low in methane (C1).

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

Source: Petroleum Federation of India (PetroFed)

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]

Source: Petroleum Federation of India

(PetroFed)

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.