Fundamentals of Carbon Dioxide-Enhanced Oil Recovery 

(CO2-EOR)—A Supporting Document of the Assessment 

Methodology for Hydrocarbon Recovery Using CO2-EOR 

Associated with Carbon Sequestration

By Mahendra K. Verma

Open-File Report 2015–1071

U.S. Department of the Interior

U.S. Geological Survey
ii

U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2015 

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Suggested citation:

Verma, M.K., 2015, Fundamentals of carbon dioxide-enhanced oil recovery (CO2-EOR)—A supporting document of 

the assessment methodology for hydrocarbon recovery using CO2-EOR associated with carbon sequestration: U.S. 

Geological Survey Open-File Report 2015–1071, 19 p., http://dx.doi.org/10.3133/ofr20151071. 

ISSN 2331-1258 (online)
iii

Contents

Introduction................................................................................................................................................................. 1

Background............................................................................................................................................................. 1

Objective................................................................................................................................................................. 1

CO2-Enhanced Oil Recovery (EOR) Process ............................................................................................................. 2

General ................................................................................................................................................................... 2

Geologic Framework............................................................................................................................................... 3

Significance of Variables ..................................................................................................................................... 3

Reservoir Engineering Aspect................................................................................................................................. 3

Properties of CO2 ................................................................................................................................................ 5

Fundamentals of the CO2-EOR Process ............................................................................................................. 5

CO2 Flood/Injection Designs ............................................................................................................................... 9

Oil Recovery Factor or Efficiency ...................................................................................................................... 12

CO2-EOR Process—Performance Evaluation and Simulation .......................................................................... 12

Operational Aspect ................................................................................................................................................... 14

CO2 Source........................................................................................................................................................... 14

Surface Facilities................................................................................................................................................... 14

CO2-EOR and the World........................................................................................................................................... 14

Technological Challenges......................................................................................................................................... 15

Residual Oil Zone (ROZ)/Transition Zone (TZ)..................................................................................................... 15

“Next Generation” CO2-EOR Technology ............................................................................................................. 15

Conclusions.............................................................................................................................................................. 16

References Cited...................................................................................................................................................... 16

Figures

1. Plot showing U.S. oil production in barrels per day associated with various enhanced oil recovery 

(EOR) methods.............................................................................................................................................. 5

2. Slim-tube oil recoveries at increasing pressures for fixed oil composition and temperatures ........................ 6

3. The schematic of the CO2 (carbon dioxide) miscible process showing the transition zone between 

the injection and production well.................................................................................................................... 7

4. Minimum miscibility pressure (MMP) correlation with molecular weight (MW) of C5+ components 

and reservoir temperature ............................................................................................................................. 8

5. Lasater (1958) correlation relating the molecular weight of C5+ components with oil gravity ......................... 8

6. Solubility of carbon dioxide (CO2) in Day crude oil (from Moran field in Kansas) as a function of 

pressure and temperature ............................................................................................................................. 9

7. Schematic of various carbon dioxide (CO2) flood-injectant designs in oil reservoirs.................................... 11

8. A typical plot of incremental oil recovery with carbon dioxide (CO2)-enhanced oil recovery and the 

injection volume (CO2 + H2O [water]) .......................................................................................................... 13

Table

1. Summary of carbon dioxide projects within the United States ....................................................................... 4
iv

Conversion Factors

Inch/Pound to SI

Multiply By To obtain

Length

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

Area

acre 4,047 square meter (m2)

acre 0.4047 hectare (ha)

acre 0.4047 square hectometer (hm2) 

acre 0.004047 square kilometer (km2)

square inch (in2) 6.452 square centimeter (cm2)

Volume

barrel (bbl), (petroleum, 

1 barrel=42 gal)

0.1590 cubic meter (m3) 

acre-foot (acre-ft) 1,233 cubic meter (m3)

acre-foot (acre-ft) 0.001233 cubic hectometer (hm3) 

Flow rate

gallon per day (gal/d) 0.003785 cubic meter per day (m3/d)

Mass

pound, avoirdupois (lb) 0.4536 kilogram (kg) 

Pressure

pound per square inch (lb/in2) 6.895 kilopascal (kPa) 

Temperature in degrees Celsius (°C) may be converted to degrees Fahrenheit (°F) as follows:

°F=(1.8×°C)+32

Temperature in degrees Fahrenheit (°F) may be converted to degrees Celsius (°C) as follows:

°C=(°F-32)/1.8
v

Abbreviations

API American Petroleum Institute

CO2 carbon dioxide

EOR enhanced oil recovery

EPA U.S. Environmental Protection Agency

EISA U.S. Energy Independence and Security Act of 2007

HCPV hydrocarbon pore volume

MMP minimum miscibility pressure

OOIP original oil-in-place

ROZ residual oil zone

TDS total dissolved solids

TZ transition zone

USGS U.S. Geological Survey

WAG water-alternating-gas
Fundamentals of Carbon Dioxide-Enhanced Oil Recovery 

(CO2-EOR)—A Supporting Document of the Assessment 

Methodology for Hydrocarbon Recovery Using CO2-EOR 

Associated with Carbon Sequestration

By Mahendra K. Verma

Introduction

Background 

Under the U.S. Energy Independence and Security Act of 2007 (EISA; U.S. Congress, 2007, 

Public Law 110–140) legislation, the U.S. Geological Survey (USGS) developed a probability-based 

methodology to assess the Nation’s technically accessible geologic storage resources available for 

sequestration of carbon dioxide (CO2) (Brennan and others, 2010; Blondes and others, 2013), 

independent of economic constraints. With the completion of the assessment of CO2 geologic storage 

resources using the above methodology (U.S. Geological Survey Geologic Carbon Dioxide Storage 

Resources Assessment Team, 2013a,b,c), the first part of the USGS’s commitment of the EISA 

legislation was fulfilled. The second part of the USGS commitment under the EISA legislation is to 

assess the hydrocarbon recovery potential in oil and gas fields within the sedimentary basins of the 

United States using CO2-enhanced oil recovery (CO2-EOR) methods. Higher primary recoveries in 

excess of 70 percent in gas reservoirs (Comelson, 1974; Alejandro and Lopez, 2000) and the cost of 

additional facilities required for CO2 injection make the CO2-EOR process economically unattractive, 

and as a result, there has been no reported attempt to consider application of tertiary recovery in gas 

reservoirs. Therefore, only oil reservoirs will be included in the assessment, and gas reservoirs will not 

be discussed here. Equivalent to the recoverable oil volume or the total oil produced is the reservoir pore 

space available for sequestration (storage) of industrial carbon dioxide. 

Objective

The objective of this report is to provide basic technical information regarding the CO2-EOR 

process, which is at the core of the assessment methodology, to estimate the technically recoverable oil 

within the fields of the identified sedimentary basins of the United States. Emphasis is on CO2-EOR 

because this is currently one technology being considered as an ultimate long-term geologic storage 

solution for CO2 owing to its economic profitability from incremental oil production offsetting the cost 

of carbon sequestration. 
2

CO2-Enhanced Oil Recovery (EOR) Process

General

After discovery, an oilfield is initially developed and produced using primary recovery 

mechanisms in which natural reservoir energy—expansion of dissolved gases, change in rock volume, 

gravity, and aquifer influx—drive the hydrocarbon fluids from the reservoir to the wellbores as pressure 

declines with fluid (oil, water, or gas) production. Primary oil recoveries range between 5 and 20 

percent (Stalkup, 1984) of the original oil-in-place (OOIP). These low recoveries prompt field operators 

to find ways to improve recovery through the application of secondary recovery methods, which provide 

additional energy to the reservoir. Secondary recovery methods entail injecting either water and (or) 

natural gas into the reservoir for repressurizing and (or) pressure maintenance and to potentially act as a 

water and (or) gas drive to displace oil. This helps to sustain higher production rates and extends the 

productive life of the reservoir. Normal practice has been to inject natural gas into the gas cap or at the 

top of reservoir and inject water below the oil-water contact. The oil recoveries at the end of both the 

primary and secondary recovery phases are generally in the range of 20–40 percent of the OOIP,

although in some cases, recoveries could be lower or higher (Stalkup, 1984). Tzimas and others (2005) 

have reported a slightly higher recovery range of 35–45 percent of OOIP at the end of secondary 

recovery in their study of North Sea oil reservoirs. 

A substantial amount of residual oil remains in the reservoir at the end of secondary recovery 

and becomes the target for additional recovery using tertiary recovery or enhanced oil recovery (EOR)

methods. For the purpose of this paper, tertiary recovery or EOR methods refer to those methods used to 

recover oil not recovered from the secondary processes. The terminology improved oil recovery (IOR) is 

also used in the petroleum industry and is loosely defined as having a wider scope of practices to 

increase oil recovery as compared to tertiary recovery or EOR. In addition to what is classified as EOR, 

the IOR includes secondary recovery processes, such as waterflooding and gas pressure maintenance, 

and improvements for better sweep efficiency and conformance such as increasing mobility control, 

infill drilling, and horizontal wells (Taber and others, 1997; Stosur and others, 2003). 

A classification by van Poollen and Associates (1981) of EOR methods has the following three 

categories:

1. Thermal methods, which include steam stimulation (also known as “huff and puff”), steam flood 

(including hot water injection), and in situ combustion; 

2. Chemical methods, which include surfactant-polymer injection, polymer flooding, and caustic 

flooding; and, 

3. Miscible displacement methods, which include injection of hydrocarbon gas, CO2, or inert gas 

under high pressure. 

The immiscible displacement method with CO2 injection, although not mentioned in the above 

classification, is also used for EOR and is briefly described in the section Fundamentals of the CO2-

EOR Process. 

CO2-EOR has two major advantages: (1) additional hydrocarbon recovery that promotes energy 

independence and (2) CO2 storage to reduce atmospheric emissions of CO2. The focus in this report is 

only on additional oil recovery using CO2-EOR. 

As part of the development work for a better understanding of the CO2-EOR process, several 

researchers have reported higher oil recoveries with carbonated water based on their experimental work 

as early as 1951 (Martin, 1951; Johnson and others, 1952; Holm, 1959).The first field-wide application 

took place in 1972 at the SACROC (Scurry Area Canyon Reef Operators Committee) Unit in the 
3

Permian Basin where the CO2 was transported via a 200-mile-long pipeline from the Delaware-Val 

Verde Basin. The process proved to be a technical success but required optimization of the CO2 slug 

size or the amount of CO2 injected for its economic viability (Kane, 1979). Because of the availability 

of CO2 in adequate quantities from both natural and industrial sources in the region, there were more 

field-wide successful applications of the CO2-EOR process in the Permian Basin than any other region 

in the United States, and the area continued to show an increasing number of reservoirs with CO2-EOR 

as a preferred option. 

Geologic Framework

All reservoir lithologies, including siliciclastic, carbonate, and others, are suitable for CO2-EOR 

application as long as they have interconnected pore space for fluid accumulation and flow and also

have an adequate seal to entrap hydrocarbons. Geology is a critical element in reservoir development 

and exploitation, particularly when CO2-EOR is considered. The oil recovery is influenced by geologic 

features such as rock and fluid characteristics, porosity, permeability, and structural or stratigraphic 

features such as faults and other barriers to oil or gas movement. A good reservoir characterization leads 

to improved estimates of OOIP values as well as to a better understanding of reservoir behavior. 

Significance of Variables 

The technically recoverable volumes of oil will depend on the OOIP values and respective 

recovery factors. The OOIP value is calculated volumetrically, using the equation below: 

OOIP =

(7758 ∗ A ∗ h ∗ Ø ∗ Soi)

Boi (1) 

7758 = multiplying factor, barrels/acre-feet 

A = reservoir area, acres

h = average net reservoir thickness, feet 

Ø = average porosity of formation, dimensionless 

Soi = initial oil saturation in pore space, fraction

Boi = oil formation volume factor at initial reservoir pressure, reservoir barrel/stock tank barrel

Recovery factors are a function of the fluid displacement and areal and vertical sweep

efficiencies. Probabilistic estimates will be affected by the accuracies of the individual variables used in 

the calculations; therefore, accurate parameter estimates are important. 

Reservoir Engineering Aspect

The CO2 from a natural or industrial source is injected into a selected oil reservoir either as 

continuous gas or as water-alternating-gas injection also known as WAG, as described in the section 

CO2 Flood Injection/Designs. Not all reservoirs are suitable for CO2-EOR and are screened based on 

factors such as reservoir geology, minimum miscibility pressure (MMP), oil gravity, and viscosity to 

help identify the most likely candidates for miscible CO2. In preliminary screening, reservoirs having a 

minimum mid-point reservoir depth of 3,000 feet or deeper were selected because the temperature and 

pressure at that depth foster miscibility of CO2 with the reservoir oil and also helps to accommodate 

high-pressure CO2 injection. Any deviation from the above criteria for choosing a reservoir would 

depend on the size of the reservoir and potential hydrocarbon recovery. The U.S Environmental 

Protection Agency (EPA) (2009, 2010) regulations for the protection of underground sources of 

drinking water (USDW) state that formations containing water with less than 10,000 mg/L (milligrams 
4

per liter) total dissolved solids (TDS) are to be avoided for CO2 storage; however, exemptions may be 

obtained from the EPA for CO2-EOR projects.

Most of the CO2-EOR applications have historically been in reservoirs with medium to light 

gravity oils, as can be seen from the 123 CO2-EOR projects (Koottungal, 2012; Kuuskraa, 2012) 

currently active in the United States in Colorado, Louisiana, Mississippi, New Mexico, Michigan, 

Oklahoma, Texas, Utah, and Wyoming. Of these projects, 114, including two unreported (Kuuskraa, 

2012), are miscible projects in reservoirs with light to ultra-light oils (gravity in excess of 28 o

API

[American Petroleum Institute, an oil gravity measure, in degrees] and viscosity of less than 3 centipoise 

[cp]) except for two reservoirs and nine immiscible projects in reservoirs with heavy to light oils 

(gravity ranging from 11 to 35 oAPI). A summary of all the CO2-EOR projects within the United States

is presented in table 1 (Koottungal, 2012). Based on the records from active EOR projects within the

United States, oil production from CO2-EOR has continued to increase compared to other EOR methods 

(fig. 1).

Table 1. Summary of carbon dioxide projects within the United States (Koottungal, 2012). 

[Perm., permeability; Temp., temperature; NA, not available; md, millidarcy; °API, American Petroleum Institute, an oil 

gravity measure, in degrees; cp, centipoise, a measure of oil viscosity; °F, degrees Fahrenheit; ss., sandstone; ls., limestone; 

dol., dolomite; trip., tripolite] 

Number of 

projects Lithology Porosity(percent)

Perm. 

(md)

Depth

(feet)

Gravity

(°API)

Viscosity

(cp)

Temp. 

(°F)

Miscible

42 ss. 7–26 16–280 1,600–11,950 30–45 0.6–3.0 82–257

2 ss./ls.-dol. 10 4–5 5,400–6,400 35 1 170–181

41 dol. 7–5 2–28 4,000–11,100 28–42 0.6–6.0 86–232

12 dol./ls. 3–12 2–5 4,900–6,700 31–44 0.4–1.8 100–139

6 ls. 4–20 5–70 5,600–6,800 39–43 0.4–1.5 125–135

1 dol./trip. chert 13.5 9 8,000 40 NA 122

7 tripolite 18–24 2–5 5,200–7,500 40–44 0.4–1.0 101–123

1 inadequate data

Immiscible

8 ss. 17–30 30–1,000 1,500–8,500 11–35 0.6–45 99–198

1 dol. 17 175 1,400 30 6 82
5

Figure 1. Plot showing U.S. oil production in barrels per day associated with various enhanced oil recovery 

(EOR) methods (Koottungal, 2012, and Kuuskraa, 2012). HC, hydrocarbon; CO2, carbon dioxide.

Because of its special properties, CO2 improves oil recovery by lowering interfacial tension, 

swelling the oil, reducing oil viscosity, and by mobilizing the lighter components of the oil. In order to 

fully understand CO2-EOR, it is important to look at the properties of CO2 and the fundamentals of the 

CO2-EOR process. 

Properties of CO2 

At atmospheric temperature and pressure, CO2 is a colorless, odorless gas and about 1.5 times 

heavier than air. The critical pressure and temperature of CO2 are 1,070.6 psia (pounds per square inch 

absolute) (73.82 kPa [kilopascals]) and 87.9 °F (31.1 °C [degrees Celsius]), respectively, and at this 

point, CO2 gas and liquid coexist. At higher than critical pressures and temperatures, CO2 is in the 

supercritical state and forms a phase whose density is close to that of a liquid, even though its viscosity 

remains quite low (0.05–0.08 cp). This dense phase CO2 can extract hydrocarbon components from oil 

more easily than gaseous CO2 (Jarrell and others, 2002) and is in this supercritical state for CO2-EOR. 

Although the low CO2 viscosity is detrimental to oil sweep, with the CO2 dissolution in oil, the oil 

viscosity is also lowered, which in turn helps improve oil recoveries. Liquid CO2 exists between its 

critical temperature and pressure and its triple-point temperature (–69.9 °F [–56.6 °C]) and pressure 

(75.1 psia [517.8 kPa]) and is normally transported as a liquid for economic and operational 

considerations. The properties of CO2 are available from various sources including online at

http://www.uigi.com/carbondioxide.html#Properties.

Fundamentals of the CO2-EOR Process

The CO2-EOR process recovers oil that remains in the reservoir after primary and secondary 

recovery by contacting and mobilizing stranded oil through improving the volumetric sweep (Ev) and 

displacement efficiencies (Ed), which are further discussed in the section Oil Recovery Factor or 

Efficiency. The injected CO2 may become miscible or remain immiscible with oil, depending on 

0

100

200

300

400

500

600

700

800

1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

Production in 1000s barrels/day

Year

U.S. EOR Production

Thermal

Flue gas injection

CO2 injection

HC gas injection

Nitrogen injection

Chemicall 
6

reservoir pressure, temperature, and oil properties. The miscible CO2-EOR process typically achieves 

higher recoveries than the immiscible process, and therefore, it is a preferred option. 

Miscible Mode. The pressure at which miscibility occurs is defined as the minimum miscibility 

pressure (MMP). Holm and Josendal (1974) defined the MMP as the pressure at which more than 80 

percent of oil-in-place (OIP) is recovered at CO2 breakthrough. Although more recently, an oil recovery 

of at least 90 percent at 1.2 HCPV (hydrocarbon pore volume) of CO2 injected is often used as a rule-ofthumb for estimating MMP (Yellig and Metcalfe, 1980). Oil recovery increases rapidly with increasing 

pressure then flattens out when MMP is reached, as shown in figure 2. 

Figure 2. Slim-tube oil recoveries at increasing pressures for fixed oil composition and temperatures (from Yellig 

and Metcalfe, 1980). CO2, carbon dioxide; psia, pounds per square inch absolute; %, percent.

There are three types of hydrocarbon miscible mechanisms: (1) first contact; (2) vaporizing gas 

drive, also known as high-pressure gas drive; and (3) the condensing gas drive, sometimes called 

enriched gas drive (Stalkup, 1983). 

A. First-contact miscible solvents mix with reservoir oil in all proportions, and the mixture 

remains in one phase. Other solvents, like CO2, are not miscible on the first contact, but they 

do develop miscibility on multiple contacts, known as dynamic miscibility, resulting in much 

improved oil recovery. 

B. The vaporizing gas-drive process achieves dynamic miscibility by in situ vaporization of the 

intermediate-molecular-weight hydrocarbons from the reservoir oil into the injected gas or 

CO2. 

C. The condensing gas-drive process achieves dynamic miscibility by in situ transfer of 

intermediate-molecular-weight hydrocarbons (or CO2 in case of CO2-EOR) into the reservoir 

oil. 

When the reservoir pressure is above the MMP, miscibility between CO2 and reservoir oil is 

achieved with time as displacement occurs in what is classified as multiple-contact or dynamic 

miscibility. The intermediate and higher molecular weight hydrocarbons from the reservoir oil vaporize 

into the CO2 (vaporization gas-drive process) and part of the injected CO2 dissolves into the oil 
7

(condensation gas-drive process) (Merchant, 2010). This mass transfer between the oil and CO2 allows 

the two phases to become completely miscible without any interface and helps to develop a transition 

zone (Jarrell and others, 2002) that is miscible with oil in the front and with CO2 in the back (fig. 3). 

Figure 3. The schematic of the CO2 (carbon dioxide) miscible process showing the transition zone between the 

injection and production well. (Modified from Jarrell and others, 2002.) 

Slim-tube tests are conducted in a laboratory to determine the MMP and are considered more 

reliable than the mathematical models or correlations. Because slim-tube tests are expensive, 

mathematical models and correlations are two additional options available to estimate MMP. 

Mathematical models provide better results and use equilibrium data and an equation-of-state (EOS) and 

have a more rigorous procedure for calculating MMP than do correlations. Correlations are easy to use, 

although they have limitations and are only recommended to use in the absence of slim-tube test or 

mathematical models. The Holm and Josendal (1974) correlation in combination with Mungan’s (1981) 

extensions takes into account the molecular weight of the C5+ components of the reservoir oil and the 

reservoir temperature (fig. 4), and for a correlation, provides good estimates of MMP. The Lasater 

(1958) correlation does not estimate MMP but rather is used to estimate the molecular weight of the C5+

components of the reservoir oil as a function of oil gravity in degree API (fig. 5) and can be used in 

conjunction with the Holm and Josendal (1974) correlation for MMP. 
8

Figure 4. Minimum miscibility pressure (MMP) correlation with molecular weight (MW) of C5+ components and

reservoir temperature (Mungan, 1981). psia, pounds per square inch absolute.

Figure 5. Lasater (1958) correlation relating the molecular weight of C5+ components with oil gravity. 

°API, American Petroleum Institute, an oil gravity measure, in degrees.

As long as the reservoir pressure is above MMP but below fracture pressure, theoretically the oil 

recoveries could be as high as 90 percent of the original OOIP in the CO2-swept region (Taber and 

others, 1997). However, recoveries in most fields are generally lower because of reservoir complexity in 

terms of lithology, structure, fractures, capillary pressure, rock wettability, oil viscosity and gravity, and 

permeability contrast between various zones in the reservoir. 

1400

1800

2200

2600

3000

3400

100.00 120.00 140.00 160.00 180.00 200.00 220.00 240.00

MMP, psia

Temperature, degree Fahrenheit

MMP: Mungan_Holm_Josendal

MW _C5+180

MW_C5+ 200

MW_C5+ 220

MW_C5+ 240

MW_C5+260

MW_C5+280

MW_C5+300

MW_C5+340

15

20

25

30

35

40

45

50

55

100 150 200 250 300 350 400 450 500

Tank Oil gravity, oAPI

Effective molecular weight of stock tank oil

Lasater Correlation
9

Although the lithology (sandstone and carbonate) does not have a direct effect on the CO2-EOR 

process, it does come into play due to the reaction of CO2 with the porous medium of some rocks, for 

example, limestone and dolomite, and results in higher permeability (Holm, 1959, 1963) and also can 

improve recovery. 

Immiscible Mode. When the reservoir pressure is below the MMP or the reservoir oil 

composition is not favorable, the CO2 and oil will not form a single phase and will not be miscible. 

However, CO2 will dissolve in the oil causing oil swelling and viscosity reduction that both help to 

improve sweep efficiency and will facilitate additional oil recovery (Martin and Taber, 1992). Like 

hydrocarbon gases, CO2 solubility in oil increases with pressure and decreases with temperature, as can 

be seen from figure 6 (Simon and Graue, 1965; Welker and Dunlop, 1963). 

 

Figure 6. Solubility of carbon dioxide (CO2) in a crude oil from Moran field in Kansas as a function of pressure 

and temperature (from Welker and Dunlop, 1963). psia, pounds per square inch absolute; SCF/STB, standard 

cubic feet per stock tank barrel; F, degrees Fahrenheit.

The role of various reservoir and geologic parameters on the mechanism and displacement 

behavior of the CO2-EOR process as well as injection design are described in the following sections. 

CO2 Flood/Injection Designs 

After screening the oil reservoirs for the CO2-EOR candidates comes the task of developing a 

design for optimal recovery efficiency of the flooding process. Depending on the reservoir geology, 

fluid and rock properties, timing relative to waterflooding, and well-pattern configuration, the CO2-EOR 

flood may use one of several recovery methods as described below (Jarrell and others, 2002) and shown 

in figure 7. 

I. Continuous CO2 injection: This process requires continuous injection of a 

predetermined volume of CO2 with no other fluid. Sometimes a lighter gas, such as 

nitrogen, follows CO2 injection to maximize gravity segregation. This approach is

0

100

200

300

400

500

0 200 400 600 800

CO2 Solubility in oil, SCF/STB

Pressure, psia

 80 F

100 F

120 F

140 F

160 F
10

implemented after primary recovery and is generally suitable for gravity drainage of 

reservoirs with medium to light oil as well as reservoirs that are strongly water-wet or are 

sensitive to waterflooding. 

II. Continuous CO2 injection followed with water: This process is the same as the 

continuous CO2 injection process except for chase water that follows the total injected 

CO2 slug volume. This process works well in reservoirs of low permeability or 

moderately homogenous reservoirs. 

III. Conventional water-alternating-gas (WAG) followed with water: In this process, a 

predetermined volume of CO2 is injected in cycles alternating with equal volumes of 

water. The water alternating with CO2 injection helps overcome the gas override and 

reduces the CO2 channeling thereby improving overall CO2 sweep efficiency. This 

process is suitable for most of the reservoirs with permeability contrasts among various 

layers.

IV. Tapered WAG: This design is similar in concept to the conventional WAG but with 

gradual reduction in the injected CO2 volume relative to the water volume. With an 

objective to improve CO2 utilization, tapered WAG is the method most widely used

today because this design improves the efficiency of the flood and prevents early 

breakthrough of the CO2, thus less recycled CO2 and better oil recoveries. The CO2

utilization is the volume of CO2 used to produce a barrel of oil and is reported either as a 

gross volume, including the recycled CO2, or a net volume. 

V. WAG followed with gas: This process is a conventional WAG process followed by a 

chase of less expensive gas (for example air or nitrogen) after the full CO2 slug volume 

has been injected.
11

Figure 7. Schematic of various carbon dioxide (CO2) flood-injectant designs in oil reservoirs (from Jarrell and 

others, 2002). Cont.= continuous; Cont./Wtr = continuous CO2 chased with water; WAG/Wtr = conventional wateralternating-gas (WAG) CO2 flood-chased with water; TWAG/Wtr = tapered water-alternating-gas CO2 flood-chased 

with water; WAG/Gas = conventional WAG chased with gas. 

Also, injection pattern improves sweep efficiency, and one of the widely used patterns is a 

normal five-spot (four injection wells at the corners and a production well at the center) or an inverted 

five-spot (four production wells at the corners with an injection well at the center), and in some cases, 

seven- or nine-spot patterns. The well pattern could even be a line drive, where the injection wells are 

located in a straight line parallel to the production wells, if the permeability distribution and other 

geologic features favor it. The selection of pattern is based on reservoir and fluid properties as well as 

on reservoir response to fluid injection, which is evaluated through analysis of reservoir performance 

manually but often using reservoir simulation as a tool; a brief description is given in the section CO2-

EOR Process—Performance Evaluation and Simulation. 
12

Oil Recovery Factor or Efficiency

Oil recovery efficiency (ER) is a measure of the effectiveness of enhanced oil recovery process 

and has two components: volumetric sweep efficiency (EV) and displacement efficiency (ED) (Ghedan, 

2009). 

ER =Ev ∗ ED (2) 

Volumetric sweep efficiency (Ev) is a measure of the volume of a reservoir contacted by the 

injected fluid and depends on the injection pattern selected, fractures in the reservoir, position of gas-oil 

and oil-water contacts, reservoir thickness, permeability and areal and vertical heterogeneity, mobility

ratio, density difference between the displacing and the displaced fluid, and flow rate. The displacement 

efficiency (ED) relates to the displacement or mobilization of oil at the pore level and is defined as the 

fraction of oil that has been recovered from a zone swept by a waterflood or other displacement process. 

Displacement efficiency is a function of reservoir pressure and temperature, oil composition, fluid 

behavior and properties, saturation history of rock-fluid system, slug size, mobility ratio, rock 

wettability, rock-pore geometry, and structure (Ghedan, 2009; Schlumberger, 1998). Displacement 

efficiency is equal to (1–Swi–Sor)/(1–Swi), where Swi is the initial or connate water saturation and Sor is 

the residual oil saturation.

Volumetric efficiency (EV) is a product of both areal efficiency (EA) and vertical efficiency (EI), 

as shown by the following equation (Ghedan, 2009). 

Ev = EA ∗ EI (3) 

The areal sweep efficiency (EA) is defined as the fraction of the pattern area from which 

reservoir fluid is displaced by the injected phase at the time of breakthrough, and it is affected by 

parameters such as formation dip angle and dip azimuth, presence of fractures, mobility ratio, injection 

pattern, and directional permeability. The vertical displacement efficiency (EI) is defined as the ratio of 

the cumulative height of the vertical sections of the pay zone that are contacted by injection fluid to the 

total vertical pay-zone height, and it depends on parameters such as mobility ratio, total volume of fluid 

injected, and the permeability contrast between different pay zones (Ghedan, 2009; Schlumberger, 

1998). 

Combining equations 2 and 3, the ER can be shown as 

ER = EA ∗ EI ∗ ED (4) 

CO2-EOR Process—Performance Evaluation and Simulation 

Before conducting a CO2-EOR application, its feasibility is evaluated by checking the CO2

miscibility with reservoir oil using correlations or, if necessary, conducting laboratory tests to determine 

MMP and viscosity. Once the miscibility is established and all other reservoir parameters are favorable, 

a pilot test is conducted to check the success of the CO2-EOR process on a small scale in the field. If all 

results are positive, reservoir simulation is carried out to (a) scale-up the EOR process to an entire oil 

field and (b) define the optimum design of the WAG ratio and hydrocarbon pore volume (HCPV) 

injection volumes for maximum oil recovery. (Note: The HCPV injection is defined as the volume of 

injectant in terms of the fraction of a reservoir’s hydrocarbon pore volume, which is equivalent to OOIP 

in reservoir barrels or cubic feet.)

The planning phase of a CO2-EOR process includes reservoir simulation for a better 

understanding of reservoir performance and a pilot test to verify the simulation forecast. 
13

Reservoir simulation is essentially a three-step procedure—(1) data input and initialization,

whereby all the reservoir parameters input into the simulator are accurate and realistically represent the 

reservoir; (2) history-matching, where the results of simulation are compared with the historical 

production and pressure data, and the values of some of the sensitive parameters are adjusted to achieve 

a good match between the simulation results and historical production and pressure data; and (3) 

forecast, which includes running several scenarios of various WAG ratios and total HCPV injections to 

determine the optimum design of the CO2-EOR flood for maximum oil recovery. 

The performance of a CO2-EOR process is continuously monitored by analyzing all the aspects 

of process—integrity of the slug of CO2 and water, performance of oil-production wells, gas-oil ratio 

and water cut, and the injection wells for fluid distribution among various reservoir layers. Based on the 

analysis results, necessary corrective or remedial measures are taken to keep up the performance of the 

individual production and injection wells, thereby helping to improve the recovery factor and the project 

economics. 

Of the various parameters, the injection volume (CO2 and water) in a WAG flood has the most 

significant effect on the recovery factor, as can be seen from the statistical study by Azzolina and others 

(2014) on 31 CO2-EOR candidates. The study revealed that although recoveries of individual reservoirs 

differed from each other, they all showed a similar trend of oil recovery increase with injection volume 

of CO2 and water (in terms of HCPV) as shown in figure 8. In order to compare the performance of all 

the reservoirs, it was necessary to extrapolate the recovery to a common injection volume (300-percent

HCPV).

Figure 8. A typical plot of incremental oil recovery with carbon dioxide (CO2)-enhanced oil recovery and the 

injection volume (CO2 + H2O [water]) (from Azzolina and others, 2014). RF, recovery factor; HCPVI, hydrocarbon 

pore volume injection. 
14

Operational Aspect

There are several operational aspects that need to be considered before planning to implement 

the CO2-EOR in a suitable oil reservoir. 

CO2 Source

There are three possible sources of CO2: (1) natural hydrocarbon gas reservoirs containing CO2

as an impurity (generally less than 25 percent), (2) industrial or anthropogenic sources with wide 

variation of CO2 percentage in the effluent, and (3) natural CO2 reservoirs. Depending on the purity, the 

source gas would require processing in order to bring the CO2 concentration high enough (90–98 

percent) for EOR, especially for a miscible process (Jarrell and others, 2002).

Surface Facilities

The facility requirements for CO2-EOR are basically similar to what is required for a waterflood 

with the exception of the CO2 injection facility, which includes the following three basic elements.

1. Extraction—CO2 is extracted from the separator gas, which begins to show increasing quantities 

of CO2 after its breakthrough in producing wells. 

2. Processing—CO2 is purified to specification after its extraction from the separator gas and is 

dehydrated before compression.

3. Compression—CO2 is compressed to raise its pressure for injection.

In addition, gas (natural gas and CO2) gathering lines, CO2 distribution lines, and metering are 

required as a part of the facility design for the CO2-EOR operation. 

As a part of field-wide application, additional injection wells may be required. Well details in 

terms of their count, locations to comply with well pattern (for example, regular five-spot, inverse fivespot, and so forth), and respective injection rates are usually decided on the basis of simulation results 

and field experience. Injection-well requirements may be fulfilled by drilling new wells and (or) 

recompleting older wells. Infill drilling may be useful in some cases to help improve reservoir areal 

coverage as well as expand pattern flood across the field, whereas step-out drilling may be a better 

option in other situations. 

CO2-EOR and the World 

As of 2012, there were 15 CO2-EOR projects outside of the United States—six in Canada, three 

in Brazil, five in Trinidad, and one in Turkey (Koottungal, 2012). Of the six CO2-EOR miscible projects 

in Canada, the Weyburn project is the most significant because it was the first project with the primary 

objective of injecting CO2 for additional oil recovery as well as for carbon sequestration to help mitigate 

climate change. In recent years, there have been some serious efforts by Scottish Carbon Capture & 

Storage (SCCS), the Scottish Government, and other companies to investigate the possible application 

of CO2-EOR in the North Sea. This interest is based on the potential for additional oil recovery from 

depleted oil fields using CO2 captured from power plants and industry (BBC News, 2012). The 

objective is to gain a better understanding of the use of CO2 in EOR operations with the goal of 

extending the producing life of North Sea oil fields using CO2 captured from large emitters, such as 

power plants and industrial facilities, and permanently store the greenhouse gas in offshore oil 

reservoirs. It is estimated that there is the potential to recover 24 billion barrels of additional oil in the 

North Sea using the CO2-EOR process. 
15

Al-Aryani and others (2011) have reported on the first CO2-EOR pilot test in the Middle East 

where pulsed neutron logging was used to monitor the performance of a CO2 flood in one of the largest 

oil fields in Abu Dhabi, United Arab Emirates. The results of this test will be viewed with great interest 

based on the fact that it will have a significant impact on the application of CO2-EOR in many oil-rich 

countries in the Middle East with the potential for very large additional oil recoveries. In India, a CO2-

EOR feasibility study was implemented in an oil field on the west coast, but the results are not yet 

publically available (Srivastava and others, 2012). In China, there is ongoing research and pilot testing 

of CO2-EOR and carbon sequestration in the Jilin oil field with plans to expand to other fields (Peng, 

2011). 

The CO2-EOR has proven to be an economically viable option for EOR, as can be seen by the 

number of currently active CO2-EOR projects (Koottungal, 2012). Therefore, it is expected that its 

scope will be further widened for its application to many more oil fields around the world. 

Technological Challenges

Although the CO2-EOR process has been successfully implemented in many conventional 

reservoirs in the United States and around the world, there are still technical challenges to address such 

as its application to oil reservoirs with somewhat unfavorable geologic, reservoir, and operating 

environments and its application to unconventional reservoirs. This challenge has spurred innovation in 

research and development and led to advances such as recovery from the residual oil zone (ROZ) and 

transition zone (TZ), and “next generation” CO2-EOR technology. These advances are not included in 

the assessment but have the potential to significantly impact the hydrocarbon resource base in the near 

future and are briefly discussed below. 

Residual Oil Zone (ROZ)/Transition Zone (TZ)

In his report “Stranded Oil in the Residual Oil Zone,” Melzer (2006) highlighted the significance 

of the transition zone (TZ) and residual oil zone (ROZ) in terms of additional oil potential that can be 

tapped with a successfully tested tertiary oil recovery process, that is, CO2-EOR. The TZ is defined as 

the section beneath the traditional oil-water contact, and the ROZ is the zone that is below the TZ and is 

formed due to capillary, hydrodynamic, or structural forces. The significance of these zones can be 

determined from the estimate of oil that exists in the TZ and ROZ and the potential to recover additional 

oil from nine fields in the Permian Basin. A preliminary estimate shows that the TZ and ROZ in the 

Wasson and Seminole fields hold about 4 billion barrels of oil, and in seven other fields (Adair, Cowden 

North and South, Fuhrman-Mascho, Means, Reeves, Seminole East, and Yellowhouse) hold 4 billion 

barrels. It is estimated that of the 8 billion barrels of oil in the TZ and ROZ in the nine fields combined, 

about 3 billion barrels, is potentially recoverable (Melzer, 2006). 

There are currently many active ROZ CO2-EOR pilots and commercially producing projects in 

the Permian Basin. As recovery from the ROZ has only recently been researched and implemented, data 

and industry experience are currently limited.

“Next Generation” CO2-EOR Technology

The current “best practices” CO2-EOR technology generally recovers 5–15 percent of the OOIP, 

still leaving behind a large volume of oil due to (a) insufficient injection of CO2, (b) poor sweep 

efficiency, (c) poor displacement efficiency, (d) lack of CO2 contact with remaining oil resources, and 

(e) inadequate management control, as described by Remson (2010). The “next generation” CO2-EOR 

technology could theoretically recover as much as 20 percent of the OOIP. These recoveries may seem 
16

to be lower than what could be expected from CO2-EOR but that is because of the impact of economics. 

The National Energy Technology Laboratory (NETL) proposed four specific “next generation” CO2-

EOR technology options with the intent to increase the recoveries from current “best practices” 

technologies as summarized below (Remson, 2010). 

1. Increasing CO2 injection volumes, 

2. Optimizing flood design and well placement for extracting more of the residual oil, 

3. Improving the mobility ratio by increasing the viscosity of water by use of polymers, and

4. Extending miscibility by reducing the miscibility pressure through the use of liquefied petroleum 

gas (LPG). 

A few more items could be added to the above list, such as use of advancements in drilling 

technology to drill long horizontal and multiple lateral wells, monitoring the oil front using the timelapse three-dimensional (3-D) seismic surveys, also known as four-dimensional (4-D) seismic surveys, 

and production logging. Some of the technologies such as drilling horizontal lateral wells and increasing 

the slug size of CO2 have recently been implemented into active CO2-EOR floods and have shown 

positive results. In the Peregrino field in Brazil, Statoil reported an increase in recovery factor from 10 

percent to approximately 20 percent, attributing it to a high degree of reservoir exposure, drilling of long 

horizontal wells, and improved water injection (http://www.ogfj.com/articles/2012/11/horizontaldrilling-enhancing-improved-oil-recovery-in-brazil.html, accessed on January 14, 2015). Carpenter 

(2014) reported on the overall benefits of drilling horizontal wells in a marginal oil field in China, which 

included improving the economics of the field. 

A statistical analysis of CO2-EOR process by Azzolina and others (2014) reveals that oil 

recovery improves with an increase in the HCPV injection of CO2+water in a WAG process. 

Conclusions

The combined primary and secondary oil recovery is reported to be in the range of 20–40 

percent of the OOIP (Stalkup, 1984). As a result, there is a large volume of potentially recoverable oil 

left in the reservoir, which becomes the target for a suitable EOR processes. Of the various EOR 

processes, CO2-EOR is the most widely used process with the highest potential for additional recovery. 

With the goal to maximize recovery, a miscible CO2-EOR process is preferred over the 

immiscible one. For the CO2-EOR process, the CO2 can be injected either as a continuous stream, 

water-alternating-gas (CO2), also known as WAG, or as tapering WAG. Because injection volume of 

CO2 and water in a WAG flood has a major influence on the recovery factor, it should be evaluated for 

maximum recovery. Also, there is room for improvement in recovery with the CO2-EOR process 

through the use of next generation processes, which include the use of polymers to adjust the mobility 

ratio, horizontal well technology, time-lapse 3-D seismic surveys (also known as 4-D seismic surveys) 

to locate sweet spots, and various improvements in well-completion technology.

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