University of Tripoli

Faculty of Engineering
Petroleum Engineering Department
M.Sc. Degree Studies

Advanced Topics in Enhanced Oil Recovery

PE618

CO2 Injection for EOR Process

Prepared by
Marwa Abdul Magid Mohamed Alageili
021-16-703

Supervised by
Dr.Nori Ben Hamida
Table of Contents
1 Introduction ....................................................................................................................................... 5
1.1 Oil Production Schemes ................................................................................................................ 5
1.2 How Oil is Produced ..................................................................................................................... 5
1.3 Factors Affecting the Oil Production and Recovery ..................................................................... 8
2 Enhanced Oil Recovery .................................................................................................................. 12
2.1 Definition of Enhanced Oil Recovery ......................................................................................... 12
2.2 Factors Affecting the EOR .......................................................................................................... 12
2.3 Description of the EOR techniques ............................................................................................. 14
3 Co2 Injection for EOR Processes ................................................................................................. 22
3.1 Concept ...................................................................................................................................... 22
3.2 Idea .............................................................................................................................................. 23
3.3 Factors affecting the process ....................................................................................................... 24
3.4 The mechanism under which the process working ..................................................................... 24
3.5 Devices Required ....................................................................................................................... 26
3.6 State of Art ................................................................................................................................. 30
3.7 The Process Implementation ...................................................................................................... 32
3.8 Expected Results from the application of the process ................................................................ 33
3.9 The process Calculation .............................................................................................................. 34
3.10 Economics of the process .......................................................................................................... 36
3.11 Current Status............................................................................................................................ 37
3.12 Case Study ................................................................................................................................ 40
3.13 Conclusion and Remarks .......................................................................................................... 61

Table of Tables
Table 1 : Reservoir Fluid Composition ............................................................................................ 42
Table 2 : Reservoir Fluid Components after splitting ...................................................................... 43
Table 3 : Grouping Method .............................................................................................................. 44
Table 4 : Reservoir Fluid components and their properties after grouping ...................................... 44
Table 5 : Ultimate recovery at various pressures .............................................................................. 49
Table 6 : Simulation results of immiscible CO2 injection scenario ................................................. 55
Table 7 : Simulation results of miscible CO2 injection scenario ..................................................... 57
Table 8 : Simulation results of Natural depletion and the best immiscible and miscible CO2
injection scenarios ............................................................................................................................ 58

Table of Figures
Figure1 : Reservoir Pressure tends by drive mechanisms .................................................................. 6

2
Figure2 : The different oil recovery stages and the corresponding oil recovery factor ..................... 8
Figure3 : A deposition dead end within a barrier bar depositional environment ................................ 9
Figure4 : Depth Requirement for EOR process ............................................................................... 12
Figure5 : Viscosity Criteria for EOR Process .................................................................................. 13
Figure6 : Permeability Criteria for EOR process ............................................................................. 13
Figure7 : Transition zone and concentration profile of the solvent in miscible flooding ............... 18
Figure8 : Relation of density of CO2 to temperature and pressure .................................................. 22
Figure9 : Illustration of the zones that develop in miscible CO2 flooding ..................................... 25
Figure10 : Typical CO2 injection well head .................................................................................... 27
Figure11 : Schematic of CO2 injection well .................................................................................... 28
Figure12 : Domestic Oil Production form CO2 EOR ..................................................................... 31
Figure13 : U.S CO2 EOR activity ................................................................................................... 31
Figure14 : CO2 gas injection process .............................................................................................. 32
Figure15 : Schematic view of slim tube test apparatus .................................................................... 35
Figure16 : MMP estimation by recovery curves at different pressures ........................................... 35
Figure17 : Costs and Economics of CO2 projects ........................................................................... 36
Figure18 : EOR production in USA ................................................................................................ 37
Figure19 : Current EOR Production from contributing countries .................................................... 38
Figure20 : Major EOR projects and production worldwide ............................................................ 39
Figure21 : Shapes of phase diagram before and after grouping ....................................................... 45
Figure22 : NTG property in the sector model .................................................................................. 47
Figure23 : Permeability property in the sector model ..................................................................... 47
Figure24 : Porosity property in the sector model ............................................................................. 48
Figure25: Recovery factor versus pressure to determine MMP ...................................................... 50
Figure26 : Map view of the location and position of horizontal and vertical wells ......................... 51
Figure27 : History matching results of field pressure ...................................................................... 52
Figure28: Field oil production total average field pressure in the natural depletion scenario ......... 53
Figure29: Field oil production rate and field oil efficiency in the natural depletion scenario ......... 54
Figure30: Field oil efficiency at different injection rates in the immiscible CO2 scenarios ............ 55
Figure31: Operation of the reservoir in the immiscible CO2 injection scenario with an injection rate
of 17,000 Mscf/day .......................................................................................................................... 56
Figure32: Operation of the reservoir in the miscible CO2 injection scenario with an injection rate of
30,000 Mscf/day ............................................................................................................................... 57
Figure33: Comparison of average field pressure values in natural depletion and the best immiscible
and miscible CO2 injection scenarios .............................................................................................. 59
Figure34 : Comparison of field oil efficiency values in natural depletion and the best immiscible
and miscible CO2 injection scenarios ............................................................................................. 59

3
Introduction:

4
1 Introduction:

1.1 Oil Production Schemes:

The initial production of hydrocarbons from an underground reservoir is accomplished by the
use of natural reservoir energy .This type of production is termed primary production.
When the natural reservoir energy has been depleted, it becomes necessary to augment the
natural energy with an external source. This is usually accomplished by the injection of fluids,
either a natural gas or water .The use of this injection scheme is called a secondary recovery
operation.
Tertiary Recovery processes were developed for application in situations in which secondary
processes had become ineffective .However, the same tertiary processes were also considered
for reservoir application for which secondary recovery techniques were not used because of
low recovery potential. For most reservoirs, it is advantageous to begin a secondary or a tertiary
process concurrent with primary production .For these applications, the term enhanced oil
recovery (EOR) was introduced. [1]

1.2 How Oil is produced [2]:

During the life of a producing oil field, several production stages are encountered .Initially,
when a field is brought into production, oil flows naturally to the surface due to current
reservoir pressure in the primary stage. As reservoir pressure drops, water is typically injected
to boost the pressure to displace the oil in the secondary stage .Lastly, the remaining oil can be
recovered by a variety of methods such as CO2 injection, natural gas miscible injection, and
steam recovery in a tertiary of enhanced oil recovery (EOR) Phase.

1.2.1 Primary Recovery [2]:

It is the stage when the natural energy of the reservoir is used to transport hydrocarbons
towards and out of the production wells. 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:
a. Solution gas drive.
b. Gas cap drive.
c. Water drive.
d. Gravity drainage.
e. Combination or mixed drive.
These drives can maintain the reservoir pressure, though water drive maintains much higher
than the gas drives as show in the following figure.

5
 Figure 1: Reservoir Pressure tends by drive mechanisms [2]

a. Solution gas drive :

In solution gas drive, the expansion of the dissolved gases in the oil and water provides
most of the reservoirs drive energy .Solution Gas Drive is associated to two types of
Reservoirs that are related to pressure; under saturated reservoirs (no free gases in oil ),
drive energy is provided only by the bulk expansion of the reservoir rock and liquids ,
saturated reservoirs, where the pressure is less than the bubble point pressure. A decline
in reservoir pressure causes bubbles of gas to expand .Thus gas expansion is the primary
reservoir drive for reservoirs below the bubble point .Oil recovery from this type is
typically between 20% and 30% of original oil in place.

b. Gas cap Drive :

As production continues, the gas cap expands pushing the gas oil contact (GOC)
downwards. Eventually the GOC will reach the production wells and the gas oil ratio
(GOR) will increase by large amounts. The recovery of gas can reservoirs can be (20%
to 40 % OOIP).

c. Water Drive:
The drive energy is provided by an aquifer that interfaces with the oil in the reservoir
at the oil –water contact (OWC). As production continues, and oil is extracted from the
reservoir, the aquifer expands into the reservoir displacing the oil .The recovery from
water driven reservoirs is usually good (20-60% OIIP). Oil production from a strongly
water driven reservoir remains fairly constant until water driven reservoir remains fairly
constant until water breakthrough occurs. When water breakthrough does occur the well
can either be shut –down or assisted using gas lift.

6
 d. Gravity drainage:
Is a fourth drive force that might be considered for drive mechanism where the density
differences between oil and gas and water result in their natural segregation in the
reservoir .This process can be used as a drive mechanism , but is relatively weak , and
in practice is only used in combination with other drive mechanisms.

e. Combination drive:
In practice a reservoir usually incorporates at least two main drive mechanisms.
Therefore, Combination or Mixed Drive can be accounted as the fifth type of Drives.

f. Oil lifting by gas or pumps:

In addition to the previous drive mechanisms, artificial lifting is considered as a primary
recovery , which is a process used to increase pressure within the reservoir when the
natural dive energy of the reservoir is not strong enough to push the oil to the surface .
The two main categories of artificial lift include pumping systems and gas lift. Gas lift
method injects compressed gas into the well to re-establish pressure, making it produce.
On the other hand, jack pumps are submersed and used to lift the oil to the surface.

1.2.2 Secondary Recovery:

After initial discover and production, typical oil reservoirs lose the drive mechanism of gas or
water that originally forced the oil to the surface. The second stage of hydrocarbon production
in which an external fluid such as water: usually named Water flooding or water injection or
gas: referred to as Gas flooding or gas injection, is injected into the reservoir through injection
well located in rock that has fluid communication with production wells.
a. Water Flooding :
Water Flooding is implemented by injecting water into a set of wells while producing
from the surrounding wells. Water flooding projects are generally implemented to
accomplish reservoir pressure maintenance and /or dispose of brine water (or produced
formation water), and /or as a water drive to displace oil from the injector wells to the
producer wells.

b. Gas Flooding :
This method is similar to water flooding in principal , and is used to maintain gas cap
pressure even if oil displacement is not required .Usually the produced natural gas is
re-injected to the reservoir in order to maintain reservoir pressure rather than to displace
the hydrocarbon. Later in this paper, gas injection methods are discussed in order to
displace oil as well as to maintain the reservoir pressure .These techniques include gases
such as carbon dioxide or nitrogen.
Eventually many oil fields usually produce only 12-15% of the OIIP. By secondary
recovery methods, another 15-20% may be produced.

1.2.3 Tertiary Recovery (Enhanced Oil Recovery):

Primary production and secondary recovery methods on the average produce less than
one third of the original oil in place (OOIP) .Tertiary Recovery (Enhanced Recovery
Techniques) , EOR , can be used to recover additional hydrocarbons. EOR introduce

7
 fluids that reduce viscosity and improve flow. These fluids could consist of gases that
are miscible with oil such as carbon dioxide or nitrogen, steam, air or oxygen, polymer
solutions, gels, surfactant –polymer formulation, alkaline-surfactant –polymer
formulation, or microorganism formulations.

Figure 2: The different oil recovery stages and the corresponding oil recovery factor [2]

1.3 Factors affecting the oil production and recovery [3]:

Oil companies will want to maximize the value of a field by getting as much of the hydrocarbon
out of it as possible. However, it is not feasible to recover all of the hydrocarbons from a
reservoir. Only a certain percentage of the total hydrocarbons will be recovered from a field,
and this is known as the recovery factor.
The magnitude of the recovery factor of an oil field depends on a complex interplay of
geological, physical and economic elements.

 Geological factors controlling recovery:

A key variable controlling the amount of oil recovered from a field is the degree of
geological heterogeneity. Oil will tend to be stranded within dead ends and low
permeability rock intervals as a consequence of this heterogeneity. An example of a
depositional dead end is a back barrier sandstone thinning and pinching out up dip
within a lagoonal shale as shown in the Figure 3.

8
 Figure 3: A depositional dead end within a barrier -bar depositional environment [3]

Structural complexity influences the recovery factor form oil fields. Heavily faulted
reservoirs will contain numerous structural dead ends , especially if the faults are
sealing. If there is a low density of widely spaced sealing faults, the drainage
volumes may still end up large enough to remain as oil targets. With an increasing
density of faults at a closer spacing , there will be a greater number of marginal and
uneconomic volumes, with less target oil volumes.

 Physical Factors controlling recovery :

Oil recovery from primary depletion : when hydrocarbons are produces from a
reservoir, the fluid pressure decreases. As the reservoir pressure is the force pushing the
hydrocarbon up to the surface, production rates will start to fall off at the wellheads.
Nevertheless, there are mechanism of natural energy inherent within the reservoir itself
which help to reduce the rate of pressure decline in the wells. The magnitude of this
reservoir energy can have a significant influence on primary recovery factors.

Oil recovery from water flooded reservoirs:

 The Effect of viscosity of recovery :
Oil viscosity has an impact on the recovery factor. Water will readily displace low –
viscosity oil to form a stable flood front. The oil is pushed a head of an extensive
cushion of water.
Where the oil is heavier and more viscous, the water will tend to finger through the oil
column in an irregular manner, breaking through to the production wells rapidly. Large
volumes of water will need to be circulated through the reservoir in order to obtain
economic oil recovery.

 Economic Factors:
An important economic factor controlling the recovery from fields is whether they are
onshore or offshore. Wells are much cheaper to drill onshore and the overall cost of the
operation is substantially less.
Recovery factors are higher for onshore fields compared to offshore fields. Onshore
fields tend to be drilled with a closer well spacing than is practical offshore.

9
The second reason for better recoveries onshore is that the wells are profitable mush
longer than offshore wells. For instance , it has been estimated by U.S .Department of
Energy that 20% of all the oil price produces in the United states comes from well
producing less than 15BOPD. No offshore well would make any money from rates as
low as this . Offshore wells are expensive to run and will be shut in as uneconomic
even when the oil production rate is still relatively high. Production tends to decline
asymptotically in predictable manner, and when an offshore field is abandoned at a high
rate of production, there is a long tail of potential production beyond this point that
would be economic onshore.

10
Enhanced Oil Recovery:

11
2 Enhanced Oil Recovery:
2.1 Definition of Enhanced Oil Recovery:
Enhanced Oil Recovery is the implementation of various techniques for increasing the amount
of crude oil that can be extracted from an oil field .Enhanced oil recovery is also called
Improved oil recovery or tertiary recovery.[4]
In another way, EOR refers to the recovery of oil through the injection of fluids and energy not
normally present in the reservoir. The objective of the injected fluids are to achieve mainly two
purposes; First is to boost the natural energy in the reservoir ; second is to interact with the
reservoir rock /oil system to create conditions favorable for residual oil recovery that leads to
reduce the interfacial tension between the displacing fluid and oil, increase the capillary
number , reduce capillary forces , increase the drive water viscosity , Provide mobility –control
, create oil swelling ,reduce oil viscosity , alter the wettability of reservoir rock .[2]

2.2 Factors affecting the EOR [4]:

Before applying EOR the following factors should be considered:
a. Depth
b. Viscosity
c. Permeability

Figure 4: Depth Requirement for EOR Process [4]

12
 Figure 5: Viscosity Criteria for EOR Processes [4]

Figure 6: Permeability Criteria for EOR Processes [4]

13
2.3 Description of the EOR techniques:
The goal of enhanced oil recovery processes is to recover at least a part of the remaining oil –
in –place .These methods change the reservoir fluid properties. The objective of EOR is to
increase the pressure difference between the reservoir and production wells, or to increase the
mobility of the oil by reduction of the oil viscosity or decrease of the interfacial tension between
the displacing fluids and oil . There are several EOR processes that are considered to be
promising: [4]
a. Chemical Processes
b. Thermal Processes
c. Miscible displacement processes.
d. Others

2.3.1 Chemical Processes [1] :

Chemical flooding relies on the addition of one or more chemical compounds to an injected
fluid either to reduce the interfacial tension between the reservoir oil and the injected fluid
or to improve the sweep efficiency of the injected fluid.
There are three general methods in chemical flooding technology.
The first is polymer flooding, in which a large macromolecule is used to increase the
displacing fluid viscosity. This leads to improved sweep efficiency in the reservoir.
The second and third methods, micellar– polymer and alkaline flooding, make use of
chemicals that reduce the interfacial tension between an oil and a displacing fluid.

a. Polymer Processes:
The addition of large-molecular-weight molecules called polymers to an injected water
can often increase the effectiveness of a conventional water flood. Polymers are usually
added to the water in concentrations ranging from 250 to 2000 parts per million (ppm).
A polymer solution is more viscous than a brine without polymer. In a flooding
application, the increased viscosity will alter the mobility
Ratio between the injected fluid and the reservoir oil. The improved mobility ratio will
lead to better vertical and areal sweep efficiencies and thus higher oil recoveries.
Polymers have also been used to alter gross permeability variations in some reservoirs.
In this application, polymers form a gel-like material by cross-linking with other
chemical species. The polymer gel sets up in large permeability streaks and diverts the
flow of any injected fluid to a different location.
Two general types of polymers have been used. These are synthetically produced
polyacrylamides and biologically produced polysaccharides.
Polymer flooding has not been successful in high temperature reservoirs. Neither
polymer type has exhibited sufficiently long-term stability above 160◦F in moderate-
salinity or heavy-salinity brines.
Polymer flooding has the best application in moderately heterogeneous reservoirs and
reservoirs containing oils with viscosities less than 100 centipoise (cp).

14
b. Micellar –Polymer Processes:
The micellar–polymer process uses a surfactant to lower the interfacial tension between
the injected fluid and the reservoir oil. A surfactant is a surface-active agent that
contains a hydrophobic (“dislikes” water) part to the molecule and a hydrophilic
(“likes” water) part. The surfactant migrates to the interface between the oil and water
Phases and helps make the two phases more miscible. Interfacial tensions can be
reduced from ∼30 dyn/cm, found in typical water flooding applications, to 10−4
dyn/cm with the addition of as little as 0.1–5.0 wt % surfactant to water– oil systems.
Soaps and detergents used in the cleaning industry are surfactants. The same principles
involved in washing soiled linen or greasy hands are used in “washing”
Residual oil off rock formations. As the interfacial tension between an oil phase and a
water phase is reduced, the capacity of the aqueous phase to displace the trapped oil
Phase from the pores of the rock matrix increases. The reduction of interfacial tension
results in a shifting of the relative permeability curves such that the oil will flow
more readily at lower oil saturations.

c. Alkaline Processes:
When an alkaline solution is mixed with certain crude oils, surfactant molecules are
formed. When the formation of surfactant molecules occurs in situ, the interfacial
tension between the brine and oil phases could be reduced. The reduction of interfacial
tension causes the microscopic displacement efficiency to increase, which thereby
increases oil recovery. Alkaline substances that have been used include sodium
hydroxide, sodium orthosilicate, sodium met silicate, sodium carbonate, ammonia, and
ammonium hydroxide. Sodium hydroxide has been the most popular. Sodium
orthosilicate has some advantages in brines with a high divalent ion content.

There are optimum concentrations of alkaline and salt and optimum pH where the
interfacial tension values experience a minimum. Finding these requires a screening
procedure similar to the one discussed above for the micellar– polymer process. When
the interfacial tension is lowered to a point where the capillary number is greater than
10−5, oil can be mobilized and displaced.

Several mechanisms have been identified that aid oil recovery in the alkaline process.
These include the following: lowering of interfacial tension, emulsification of
oil, and wettability changes in the rock formation. All three mechanisms can affect the
microscopic displacement efficiency, and emulsification can also affect the
macroscopic displacement efficiency. If a wettability change is desired, a high (2.0–5.0
wt %) concentration of alkaline should be used. Otherwise, concentrations of the order
of 0.5–2.0 wt % of alkaline are used.

15
2.3.2 Thermal Flooding [1] :
Primary and secondary production from reservoirs containing heavy, low-gravity crude oils is
usually a small fraction of the initial oil in place. This is due to the fact that these types of oils
are very thick and viscous and as a result do not migrate readily to producing wells.
Three types of processes will be discussed in this section: steam cycling, steam drive, and in
situ combustion. In addition to the lowering of the crude oil viscosity, there are other
mechanisms by which these three processes recover oil. These mechanisms will also be
discussed.
a. Steam Stimulation Processes:
The steam stimulation process was discovered by accident in the Mene Grande Tar Sands,
Venezuela, in 1959. During a steam injection trial, it was decided to relieve the pressure
from the injection well by back flowing the well. When this was done, a very high oil
production rate was observed. Since this discovery, many fields have been placed on steam
stimulation.
The steam stimulation process, also known as the steam huff and puff, steam soak, or cyclic
steam injection, begins with the injection of 5000–15,000 bbl. of high-quality steam. This
can take a period of days to weeks to accomplish. The well is then shut in, and the steam is
allowed to soak the area around the injection well. This soak period is fairly short, usually
from 1 to 5 days. The injection well is then placed on production. The length of the
production period is dictated by the oil production rate but can last from several months to
a year or more. The cycle is repeated as many times as is economically feasible. The
oil production will decrease with each new cycle. Mechanisms of oil recovery due to this
process include (1) reduction of flow resistance near the well bore by reducing the crude
oil viscosity and (2) enhancement of the solution gas drive mechanism by decreasing the
gas solubility in an oil as temperature increases.
The oil recoveries obtained from steam stimulation processes are much smaller than the oil
recoveries that could be obtained from a steam drive. However, it should be apparent that
the steam stimulation process is much less expensive to operate. The cyclic steam
stimulation process is the most common thermal recovery technique. Recoveries of
additional oil have ranged from 0.21 to 5.0 bbl. of oil per barrel of steam injected.

b. Steam Drive Processes:

The steam drive process is much like a conventional water flood. Once a pattern
arrangement is established, steam is injected into several injection wells while the oil is
produced from other wells. This is different from the steam stimulation process, whereby
the oil is produced from the same well into which the steam is injected. As the steam is
injected into the formation, the thermal energy is used to heat the reservoir oil.
Unfortunately, the energy also heats the entire environment such as formation rock and
water. Some energy is also lost to the under burden and overburden. Once the oil viscosity
is reduced by the increased temperature, the oil can flow more readily to the producing
wells. The steam moves through the reservoir and comes in contact with cold oil, rock, and
water. As the steam comes in contact with the cold environment, it condenses and a hot
16
 water bank is formed. This hot water bank acts as a water flood and pushes additional oil
to the producing wells.
Several mechanisms have been identified that are responsible for the production of oil from
a steam drive. These include thermal expansion of the crude oil, viscosity reduction of the
crude oil, changes in surface forces as the reservoir temperature increases, and steam
distillation of the lighter portions of the crude oil.

c. In Situ Combustion :
Early attempts at in situ combustion involved what is referred to as the forward dry
combustion process? The crude oil was ignited downhole, and then a stream of air
or oxygen-enriched air was injected in the well where the combustion was originated.
The flame front was then propagated through the reservoir. Large portions of heat
energy were lost to the overburden and underburden with this process.
The number of in situ combustion projects has decreased since 1980. Environmental
and other operational problems have proved to be more than what some operators want
to deal with.

2.3.3 Miscible Flooding:

A miscible process is one in which the interfacial tension is zero; that is, the displacing fluid
and the residual oil mix to form one phase. If the interfacial tension is zero, then the capillary
number becomes infinite and the microscopic displacement efficiency is maximized.
There are, in general, two types of miscible processes. One is referred to as the single-contact
miscible process and involves such injection fluids as liquefied petroleum gases (LPGs) and
alcohols. The injected fluids are miscible with residual oil immediately on contact. The second
type is the multiple-contact, or dynamic, miscible process. The injected fluids in this case are
usually methane, inert fluids, or an enriched methane gas supplemented with a C2–C6 fraction.
The injected fluid and oil are usually not miscible on first contact but rely on a process of
chemical exchange between phases to achieve miscibility [1] .
Implies that the displacing fluid is miscible with the reservoir oil either at first contact (SCM)
or after multiple contacts (MCM). A narrow transition zone (mixing zone) develops between
the displacing fluid and the reservoir oil, inducing a piston-like displacement. The mixing
zone and the solvent profile spread as the flood advances. The change in concentration profile
of the displacing fluid with time is shown in Figure 3. Interfacial tension is reduced to zero in
miscible flooding, therefore, Nc = ∞. Displacement efficiency approaches 1 if the mobility
ratio is favorable (M < 1). The mixing zone and the solvent profile spread as the flood
advances [5].
The various miscible flooding methods include:
a. Miscible slug process,
b. enriched gas drive,
c. vaporizing gas drive,
d. High pressure gas (CO2 or N2) injection.

17
Figure 7: Transition Zone and concentration profile of the solvent in miscible flooding [5]

a. Miscible Slug Process[5]:

It is an SCM (single contact miscible) type process, where a solvent, such as propane
or pentane, is injected in a slug form (4-5% HCPV). The miscible slug is driven using
a gas such as methane or nitrogen, or water. This method is applicable to sandstone,
carbonate or reef-type reservoirs, but is best suited for reef-type reservoirs. Gravity
segregation is the inherent problem in miscible flooding. Viscous instabilities can be
dominant, and displacement efficiency can be poor.
Reef-type reservoirs can afford vertical gravity stabilized floods, which can give
recoveries as high as 90% OOIP. Several such floods have been highly successful in
Alberta, Canada. Availability of solvent and reservoir geology are the deciding factors
in the feasibility of the process. Hydrate formation and asphaltene precipitation can be
problematic.

b. Enriched Gas Drive [5]:

This is an MCM type process, and involves the continuous injection of a gas such as
natural gas, flue gas or nitrogen, enriched with C2-C4 fractions. At moderately high
pressures (8-12 MPa), these fractions condense into the reservoir oil and develop a
transition zone. Miscibility is achieved after multiple contacts between the injected gas
and the reservoir oil.
Increase in oil phase volume and reduction in viscosity contrast can also be contributing
mechanisms towards enhanced recovery. The process is limited to deep reservoirs
(>6000 ft) because of the pressure requirement for miscibility.

18
 c. Vaporized Gas Drive [5] :
This also is an MCM type process, and involves the continuous injection of natural gas,
flue gas or nitrogen under high pressure (10-15 MPa). Under these conditions, the C2-
C6 fractions are vaporized from the oil into the injected gas. A transition zone develops
and miscibility is achieved after multiple contacts. A limiting condition is that the oil
must have sufficiently high C2-C6 fractions to develop miscibility.
Also, the injection pressure must be lower than the reservoir saturation pressure to allow
vaporization of the fractions. Applicability is limited to reservoirs that can withstand
high pressures.

d. CO2 Miscible [5] :

CO2 Miscible method has been gaining prominence in recent years, partly due to the
possibility of CO2 sequestration. Apart from environmental objectives, CO2 is a unique
displacing agent, because it has relatively low minimum miscibility pressures (MMP)
with a wide range of crude oils. CO2 extracts heavier fractions (C5-C30) from the
reservoir oil and develops miscibility after multiple contacts. The process is applicable
to light and medium light oils (>30° API) in shallow reservoirs at low temperatures.
CO2 requirement is of the order of 500-1500 sm3/sm3 oil, depending on the reservoir
and oil characteristics. Many injection schemes are in use for this method. Particularly
notable among them is the WAG (Water Alternating Gas) process, were water and CO2
are alternated in small slugs, until the required CO2 slug size is reached (about 20%
HCPV).
This approach tends to reduce the viscous instabilities. Cost and availability and the
necessary infrastructure of CO2 are therefore major factors in the feasibility of the
process. Asphaltene precipitation can be a problem in some cases. Currently there are
80 CO2 floods in North America.

e. N2 Miscible [5] :
This process is similar to CO2 miscible process in principle and mechanisms involved
to achieve miscibility, however, N2 has high MMP with most reservoir oils. This
method is applicable to light and medium light oils (>30° API), in deep reservoirs with
moderate temperatures. Cantarell N2 flood project in Mexico is the largest of its kind
at present, and is currently producing about 500 000 B/D of incremental oil.

2.3.4 Other:
a. Acoustic Enhanced Oil Recovery[6] :
 One of the less popular methods is acoustic wave stimulation also known as elastic
wave or seismic wave or vibration stimulation.
 Acoustic waves reduce interfacial tension between fluid interfaces
 Vibration due to acoustic waves produces great useful influence on oil-water relative
permeability curve and capillary pressure cure, and can reduce the residual oil
saturation and oil viscosity
 Vibration with certain frequencies can promote production of residual oil
 Vibrations - It mobilizes residual oil, improves permeability

19
 It is postulated that as the elastic waves migrate through the porous media they cause
deformation of the grain structure.
 Once the waves have passed the grains relax back into their normal structure and in so
doing cause a vibrational frequency.
 This high frequency waveform causes oil droplets, otherwise too small to move, to
coalesce into larger, mobile droplets. Similarly oil films are transformed into mobile
droplets.

b. Microbial Flooding [1]:

Microbial enhanced oil recovery (MEOR) flooding involves the injection of
microorganisms that react with the reservoir fluids to assist in the production of residual
oil. There are two general types of MEOR processes –those in which microorganisms
react with reservoir fluids to generate surfactants and those in which microorganisms
react with reservoir fluids to generate polymers.
MEOR systems can be designed for reservoirs that have either a high or low degree of
channeling. Therefore, MEOR applications require a thorough knowledge of the
reservoir.
Mineral content of the reservoir brine will also affect the growth of microorganisms.
 Problems in Applying Microbial Processes:
Since microorganisms can be reacted to form either polymers or surfactants, a
knowledge of the reservoir characteristics is critical. If the reservoir is fairly
Heterogeneous, then it would be desirable to generate polymers in situ that
could be used to divert fluid flow from high to low permeability channels. If the
reservoir ha low injectivity, then using microorganisms that produced polymers
could be very damaging to flow of fluids near the well bore. Hence, a thorough
knowledge of the reservoir characteristics, particularly those immediately
around the well bore, is extremely important.
MEOR processes have been applied in reservoirs with brines up to less than
100,000 ppm, rock Permaebilities greater than 75 mD, and depths less than 6800
ft. This depth corresponds to a temperature of about 75C. Most MEOR projects
have been performed with light crude oils having API gravities between 30 and
40. These should be considered ‘Rule of Thumb ’criteria. The most important
consideration in selecting a microorganisms –reservoir system is to conduct
compatibility tests to make sure that microorganism’s growth can be achieved.

20
CO2 as Gas Injection for EOR Processes

21
3 CO2 as Gas Injection for EOR processes:

3.1 Concept of CO2 gas injection for EOR Processes:

From a fundamental point of view, CO2 EOR works on a very simple principle,
namely, that given the right physical conditions, CO2 will mix miscible with oil,
acting much like a thinning agent, much the same way that gasoline does with
motor oil. After miscible mixing, the fluid is displaced by a chase phase, typically
water. [7]
In more scientific terminology, Holm describes miscibility as: “the ability of
two or more substances to form a single homogeneous phase when mixed in all
proportions. For petroleum reservoirs, miscibility is defined as that physical
condition between two or more fluids that will permit them to mix in all proportions
without the existence of an interface. If two fluid phases form after some amount
of one fluid is added to others, the fluids are considered immiscible. [7]
Pure CO2 is a non-combustible gas having no color or odour. The molecular weight of CO2 is
44.010 g/mol and in given pressure and temperature CO2 is denser than air. Figure 7 shows the
influence of pressure and temperature on the density of CO2. [8]

Figure 8: Relation of the density of CO2 to Temperature and pressure [8]

22
Below the critical temperature, CO2 can exist either as a gas or liquid. After exceeding the
critical temperature CO2 exists as a gas. However when pressure is exceeding the critical
pressure, the CO2 becomes a supercritical fluid. [8]
CO2 at its supercritical pressure and temperature is completely miscible with oil. Because of
that, oil moves through the rock pore spaces more easily yielding more oil production. (Institute
for 21st century energy). As the reservoir fluids are produced through the production wells, the
reservoir pressure will decline. Then the injected CO2 has the ability to reconvert into gaseous
state and provides a gas lift which is similar to original reservoir natural gas pressure. [8]
The main advantage of CO2 compared to other gasses is its ability to extract heavy hydrocarbon
components up to the range C30. Some of the main characteristics of CO2 which are effective
in extracting oil from porous rock are mentioned below. [8]
 CO2 Promotes swelling:
Oil swelling occurs due to solubility of CO2 in oil. Pressure ,temperature and the oil
composition are the main key parameters which effect on the degree of swelling.
Swelling is important because the residual oil saturation is inversely proportional to the
swelling factor. [8]

 CO2 reduces oil viscosity :

The dissolving of CO2 in oil reduces the oil viscosity as well .But the overall viscosity
reduction depends on the initial oil viscosity. The reduction of oil viscosity will be
larger if the initial oil viscosity is high. [8]

 Interfacial Tension reduction :

CO2 has the ability to reduce the interfacial tension by dissolving in oil. This has
significant influence on the relative permeability curves and increase the oil relative
permeability. [8]

 CO2 exerts an acidic effect on rock :

CO2 dissolves in water and forms carbonic water in the front section of CO2 injection.
This leads to dissolution o calcite in the rock formation as following reaction .
𝐻2 𝑂 + 𝐶𝑂2 + 𝐶𝑎𝐶𝑂3 → 𝐶𝑎(𝐻𝐶𝑂3 )2
These rates of reactions in carbonated rocks are faster than in sand stones. Because of
this , the porosity and the permeability of the formation can be changed due to CO2
injection . [8]

 CO2 reduces the effect of gravity segregation:

CO2 has the ability to reduce density differences between oil and water by dissolving
in oil and water. This leads to reduced chance of gravity segregation. [8]

3.2 Idea of CO2 Injection gas for EOR Process [7]:

Technically, the critical consideration is that in miscible displacement the residual oil saturation
that is the oil left after being miscibly contacted with CO2, is reduced nearly to zero. This leads
to high oil recoveries and favorable project economics. This is in distinction to immiscible

23
displacements where considerable residual oil saturations can remain ,often leading to
unfavorable project economics.
Flooding a reservoir with CO2 can occur either miscibly of immiscibly . Miscible CO2
displacement is only achieved under a specific combination of conditions , which are set by
four variables : Reservoir temperature, reservoir pressure, injected gas composition , and oil
chemical composition .

3.3 Factors affection CO2 gas injection for EOR processes [7]:
In CO2 EOR flood, a variety of factors will influence processes performance.
Because the viscosity of CO2 at reservoir condition is much lower than that of the most oils ,
viscous instability will limit sweep efficiency of the displacement and , therefore, oil recovery
. In addition, reservoir rock is extremely heterogeneous, exhibiting zones of high permeability
in close proximity to those of low permeability. These permeability differences may be innate,
that is caused by differences in pore structure at the time of geological deposition, or a product
of fractures, natural or man-made.

3.4 The mechanism under which CO2 gas injection for EOR processes is
working [7]:
The main mechanism of CO2 –EOR depend on the conditions of injecting CO2, the reservoir
condition (Pressure and Temperature) and the oil composition.
Generally CO2 is not miscible with reservoir oil at first contact. At sufficiently high pressures
and temperatures, CO2 achieves dynamic miscibility with oil through multiple contacts. The
minimum pressure at which CO2 and oil are completely mixed with each other at any
proportion is called minimum miscibility pressure (MMP). Injection of CO2 at a pressure equal
to or above the MMP is called miscible CO2 EOR and CO2 flooding at a pressure below the
MMP is called immiscible CO2 EOR.

3.4.1 Miscible CO2 EOR:

CO2 EOR can be achieved when CO2 is flooded into a reservoir having low viscous oil , at a
pressure equal to or higher than MMP. Mixing reservoir oil with CO2 does not happen
instantaneously .When the reservoir oil is in contact with the injected CO2 , the oil begins to
dissolve into the dense CO2 and the dense CO2 begins to dissolve into the oil . Eventually the
oil and the injected CO2 become one single phase due to repeated contacts with time . The
instance where CO2 is completely mixed with oil , is termed as miscible CO2 EOR. Under this
process vaporization of crude oil , development of miscibility , and reduction of interfacial
tension occurs within the reservoir .This leads to more oil production due to more efficient
sweep of oil .
When miscible CO2 EOR is performing , several compositional zones are developed in the
displacement direction within the reservoirs as shown in Figure 9.

24
 Figure 9: Illustration of the zones that develop in miscible CO2 flooding [7]

As the first point of contacting CO2 with reservoir oil , a miscible front will be generated . IN
this front lighter hydrocarbon molecules will be transferred gradually from the oil to CO2. Then
this front will dissolve in oil and act as a single phase under favorable pressure and temperature
conditions. This makes it easier for the oil to move towards the production wells.
Most of the oil recovery operations are designed to maintain the reservoir pressure above the
MMP in order to operate under fully miscible conditions. These pressure conditions can be
achieved naturally in the reservoir below about 800 m of depth.
3.4.2 Immiscible CO2 –EOR:
When the reservoir pressure is not sufficient to exceed the MMP or the reservoir contains oil
having high density and viscosity (heavy oil ) immiscible CO2-EOR is carried out . Even
though the miscibility between oil and CO2 is not significant ; CO2 will dissolve in the oil
phase. Hence reduction of crude oil viscosity and swelling occur and these are the most
important effects under the immiscible CO2 EOR process. In addition to that the reservoir oil
is pushed effectively towards the production well by the injected CO2.Therefore due to these
mechanisms , an additional portion of the remaining oil in the reservoir can be recovered. In
generally , immiscible CO2-EOR is much less efficient compared to miscible CO2-EOR in
recovering the residual oil.

3.4.3 Limitation of CO2 EOR:

Supplying CO2 to the place where the oil fields are located is one of the major challenges for
CO2 EOR. Availability of low cost CO2 is the main challenge. This includes all cost for
purchasing and transportation. To obtain a great performance the purity of CO2 should be
higher than 95% .Thus , purifying cost should also be considered .From the amount of CO2
currently used for EOR , about 75% is extracted from naturally occurring deposits located near
the oil fields in order to ensure economic feasibility . The rest is the captured CO2 from
industrial processes such as power plants fertilizer, manufacturing plants etc.
The problem associated with CO2 EOR are gravity tonguing and viscous fingering .These are
due to high mobility, lower density and viscosity of CO2 compared to the oil in the reservoir.
IN order to avoid these problems to some extent and improve the sweep efficiency , the
following methods are carried out:

25
  WAG(Water Alternating Gas) Process :
In order to improve sweep efficiency water and CO2 are injected to the formation as
alternating slugs.

 Injection of foaming solutions together with CO2:

By adding foaming solutions in more permeable areas of the reservoir , the mobility of
CO2 can be reduced. Hence sweep efficiency can be improved.

 Installation of well packers and inflow control devices.

CO2 EOR is not suitable for all oil fields and the effectiveness of CO2 EOR depends on several
factors such as oil composition , depth ,temperature and other characteristics of the reservoir .
The characteristics of the reservoir such as reservoir heterogeneities ,porosity ,permeability and
wettability must be considered when designing a CO2 EOR system.

3.5 Devices Required for CO2 gas injection for EOR Processes:
The technologies for drilling and completing CO2 injection wells are well developed.
American petroleum Institute published a number of specification and Recommended practices
for casing and tubing, and well cements such as :API Specification 5C1-Recommended
practices for Care and use of casing and tubing, API RP 10B-2-Recommended practice for
testing well cement, API specification 10A –specification on Cements and Materials for well
cementing, API RP 10D -2-Recommended practice for centralizer placement and stop collar
testing, and API specification 11D1-packers and Bridge plugs. [8]
Most aspects of drilling and completing such wells are similar or identical to that of drilling
and completing a conventional gas (or other) injection well or a gas storage well, with the
exception that much of the downhole equipment must be upgraded for high pressure and
corrosion resistance. The well is completed at the surface by installing a wellhead and
‘Christmas Tree’ that sits on top of the wellhead and is an assembly of valves, pressure gauges
and chokes. Devices are connected to the ‘Christmas Tree’ that allow the monitoring of
pressure temperature, and injection rates (Figure 10) . The combine well head has casing
annulus valves to access all annular spaces to measure the pressure between the casing strings
and between the casing and production tubular. Above the Christmas tree a CO2 injection
valves is mounted and an access valve for running wirelines from the top. [9]

26
 Figure 10: Typical Co2 injection well head [9]

Typical components of an injection well that are relevant to maintaining mechanical integrity
and to ensuring that fluids do not migrate from the injection zone into USDWs are the casing
,tubing ,cement and packer (Figure 11). The well components should be designed to withstand
the maximum anticipated stress in each direction. [9]

27
 Figure 11: Schematic of CO2 Injection well [9]

3.5.1 Casing [9]:

An injection well typically consists of one or more casings. Leaks in the casing can allow fluid
to escape into unintended zones or allow fluid movement between zones. The construction
materials selected for the casing and the casing design must be appropriate for the fluids and
stresses encountered at the site –specific down hole environment. Carbon dioxide in
combination with water forms carbonic acid , which is corrosive to many materials .
Native fluids can also contain corrosive elements such as brines and hydrogen sulfide. In CO2
injection wells, the spaces between the long string casing and their intermediate casing and the
surface casing as well as between the casings and the geologic formation are required to be
filled with cement, along all casings.
3.5.2 Tubing [9] :
The tubing runs inside the long string casing from the ground surface down to the injection
zone. The injected fluid moves down the tubing , and out through the perforations in the long
string casing , and into the injection zone. The tubing ends at a point just below the packer. The
space between the long string casing and tubing must be filled with a non-corrosive packer
fluid. The tubing forms another barrier between the injected fluid and the long string casing. It

28
must be designed to withstand the stresses and fluids with which it will come into contact. The
tubing and long string casing act together to form two levels of protection between the carbon
dioxide stream and the geologic formation above the injection zone. A safety valve/profile
nipple can be used to isolate the wellbore from the formation to allow the tubing string to be
replaced. Injection will be conducted through the perforated casing. In the base case there is no
stimulation method used, but hydro fracturing may be an option. Using acids to improve
injectivity is not recommended because of the possible damage to the cement sheath and casing.

3.5.3 Cement[9] :
Cement is important for providing structural support of the casing, preventing contact of the
casing with corrosive formation fluids, and preventing vertical movement of carbon dioxide.
Some of the most current researches indicate that a good cement job is one of the key factors
in effective zonal isolation. The proper placement of the cement is critical, as error can be
difficult to fix later on. Failing to cement the entire length of casing , failure of the cement to
bond with the casing or formation, not centralizing the casing during cementing, cracking and
alteration of the cement can all allow migration of fluids along the wellbore. If carbon dioxide
escapes the injection zone through the wellbore because of a failed cement job, the injection
process must be interrupted to perform costly remedial cementing treatments. In a worst case
scenario, failure of the cement sheath can result in the total loss of a well. During the injection
phase , cement will only encounter CO2 . However after the injection phase and all the free
CO2 around the wellbore is dissolved in the brine , the wellbore will be attacked by carbonic
acid (H2CO3). The carbonic acid will only attack the reservoir portion of the production casing,
therefore special consideration of CO2 cement needs only to be considered for the reservoir ,
primary seal and a safety zone above the reservoir. Regular cement should be sufficient over
the CO2 resistant cement . However since two different cement slurries will be used, CO2
resistant cement that is compatible with regular Portland Cement has to be used to prevent flash
setting.
3.5.4 Packer[9] :
A packer is a sealing device which keeps fluid from migrating from the injection zone into the
annulus between the long string casing and tubing. The tubing is set on a retrievable packer
above the injection zone to ease the changing of the tubing if pitting is identified during regular
inspections. A packer must also be made of materials that are compatible with fluids which it
will come into contact.
3.5.5 Design Requirements [9]:
All new CO2 injection wells have to be cased and cemented to prevent the migration of fluids
into or between underground sources of drinking water. The casing and cement used in the
construction of each newly drilled well has to be designed for the life expectancy of the well.
In determining and specifying casing and cementing requirements, the following factors has to
be considered :
1. Depth to the injection zone.
2. Injection pressure, external pressure, internal pressure , axial loading .
3. Hole size.
4. Size and grade of all casing strings(wall thickness, diameter , nominal weight, length ,
joint specification, and construction material).

29
 5. Corrosiveness of injected fluids and formation fluids.
6. Lithology of injection and confining zones
7. Type and grade of cement .
The following information concerning the injection zone has to be determined or calculated for
new wells:
1. Fluid pressure.
2. Fracture pressure
3. Physical and Chemical characteristics of the formation fluids.
3.5.6 Surface Facilities [10]:
The facility requirement for CO2-EOR are basically similar to what is required for a water
flood 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 part of the facility design for the CO2-EOR operation.

3.6 Sate of Art of CO2 gas injection for EOR Processes [11]:
CO2 based enhanced oil recovery ,using state of the art (SOA) technology , is already being
implemented in US, particularly in the oil fields of the Permian Basin of west Texas , the Gulf
Coast and the Rockies.
 CO2 EOR currently provides about 284,000 barrels of oil per day in the U.S, equal to
6% of U.S. crude oil production, Figure 12. CO2-EOR has been underway for several
decades, starting initially in the Permian Basin and expanding to 123 CO2-EOR
projects currently installed in numerous regions of the country, Figure13.

 In 2010, a total of 62 million metric tons of CO2 was supplied to EOR operations in the
U.S,.Approximately 20% (13 million metric tons) of this CO2 came from industrial
sources ,natural gas processing plants ,and hydrocarbon conversion facilities. By 2020,
approximately 14 MT of additional CO2 supply will become available from large –
scale integrated CCUS projects in the U.S. Department of Energy’s (DOE) portfolio.
 A robust network of pipelines exist in the Permian Basin that transports this CO2 from
natural CO2 deposits and gas processing plants to the Denver City Hub, Figure 13. In
addition, numerous new CO2 pipelines have recently been placed on line to deliver
CO2 to Gulf Coast and Rocky Mountain oil fields. These include Denbury’s 320 mile
Green Pipeline along the Gulf Coast, Occidental Petroleum’s new $850 million Century
natural gas /CO2 processing plant and pipeline facilities in West Texas, and Denbury’s
Green Core CO2 pipeline linking the Lost Cabin gas processing plant and other CO2
sources in Wyoming to Rocky Mountain oil fields ,Figure 13.

30
Figure 12: Domestic Oil Production from CO2-EOR [11]

Pr

Figure 13: U.S CO2 -EOR Activity [11]

31
3.7 The Process Implementations of CO2 gas injection for EOR Processes [12]:

1. CO2 is injected into the reservoir via injection wells.

2. The CO2 reduces the viscosity of the trapped oil so it flows more easily .
3. Water can be injected in alternating cycles with CO2 to sweep the oil to the producing
wells.
4. Production wells pump the oil , along with CO2, produced water and any associated
natural gas to the surface.
5. The CO2 and associated natural gas are separated at the production satellite facility.
Natural gas liquids are extracted and sold and the CO2 is recycled for reinjection.
6. The oil and produced water are separated at the central tank battery. The oil is piped to
holding tanks where it is metered and sold.
7. The produced water is transported to the central water injection station and is
pressurized for reinjection.

Figure 14: CO2 gas injection process [12]

32
3.7.1 CO2 Flood/Injection Designs [10]:
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 water flooding, and well –pattern
configuration, the CO2-EOR flood may use one of several recovery methods as described
below (Jarrell and others, 2002):
1. 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
implemented after primary recovery and is generally suitable for gravity drainage of
reservoir with medium to light oil as well as reservoirs that are strongly water –wet or
are sensitive to water flooding.

2. 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.

3. 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
reduce the CO2 channeling thereby improving overall CO2 sweep efficiency. This
process is suitable for most of the reservoirs with permeability contrast among various
layers.

4. Tapered WAG: This design is similar in concept to the conventional WAG but with
gradual reduction in the injection 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.

5. WAG followed with gas : This process is 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.

3.8 Expected Results from the application of CO2 gas injection for EOR
Processes [13]:
The greatest difference compared to other gases is that CO2 can extract heavier components
up to C30. The solubility of CO2 in hydrocarbon oil causes the oil to swell. CO2 expands oil
to a greater extent than methane does. The swelling depends on the amount of methane in the
oil . Because the CO2 does not displace all of the methane when it contacts a reservoir fluid,

33
the more methane there is in the oil, the less is the swelling of oil. CO2 has the following
characteristics in the flood process:
 It promotes swelling
 It reduces oil viscosity
 It increases oil density
 It is soluble in water
 It can vaporize and extract portions of the oil
 It achieves miscibility at pressures of only 100 to 300 bar.
 It reduces water density
 It reduces the difference between oil and water density and then reduce the change for
gravity segregation
 It reduces the surface tension of oil and water and result in more effective displacement.

3.9 The process calculation for CO2 gas injection:

CO2 based EOR scenarios can be applied into the reservoirs under two distinct processes of
immiscible and miscible CO2 injection. The Minimum Miscibility Pressure (MMP) of the
crude oil CO2 system is the key parameter used in the recognition of CO2 injection processes
whether they are miscible or immiscible. The MMP of CO2 is defined as the minimum pressure
under which CO2 can achieve multi contact miscibility with the crude oil . It has also been
proved that the MMP of CO2 for a reservoir oil depends on the reservoir temperature, oil
composition and the purity of injected CO2. [14]
The slim tube method is the most commonly used techniques among the proposed experimental
methods for determining the MMP. In addition, there are some other experimental methods
that are relatively cheaper and easier to employ, including rising bubble apparatus (RBA) and
vanishing interfacial tension (VIT), in order to measure the IFT experimentally. [14]
The most common method used to determine the conditions at which miscible displacement is
achieved is known as a slim tube experiment. A long (40-80 ft), small diameter (1/4 in), high
–pressure tube is packed with clean sand (or glass beads) to achieve a fluid permeability of 3
to 5 Darcies. It is then saturated with the reservoir oil of interest and the apparatus is maintained
at reservoir temperature. A series of floods are conducted at different pressures, while the exact
composition of the displacing CO2,(it may be either highly purified ,>96% CO2 , or mixed
with other hydrocarbon gases such as methane CH4, ethane C2H6 , propane C3H8 , etc) is
injected . A correlation between oil recovery versus pressure is developed .Miscible
displacement is achieved at the flooding pressure or minimum miscibility pressure (MMP)
where about 95% of the oil in the tube is recovered after about 1.3 pore volumes of fluid have
been injected .Below this pressure , oil recovery decreases dramatically . [13]

34
 Figure 15: Schematic view of slim tube test apparatus [13]

Figure 16: MMP estimation by recovery curves at different pressures [13]

35
3.10 Economics of CO2 gas injection for EOR Processes [15]:
Implementing a CO2 EOR project is a capital –intensive undertaking. It involves drilling or
reworking wells to serve as both injectors and producers, installing a CO2 recycle plant and
corrosion resistant field production infrastructure, and laying CO2 gathering and transportation
pipelines. Generally, however, the single largest project cost is the purchase of CO2. As such,
operators strive to optimize and reduce the cost of its purchase and injection wherever possible.
Higher oil prices in recent years have significantly improved the economics of CO2 EOR.
However, oil field costs have also increased sharply, reducing the economic margin essential
for justifying this oil recovery option to operators who still see it as bearing significant risk.
Both capital and operating costs for an EOR project can vary over a range, and the value of
CO2 behaves as a commodity, priced at pressure, pipeline quality, and accessibility, so it is
important for an operator to understand how these factors might change. Total CO2 costs (both
purchase price and recycle costs) can amount to 25 to 50 percent of the cost per barrel of oil
produced. In addition to the high up –front capital costs of the CO2 supply /injection /recycling
scheme, the initial CO2 injection volume must be purchased well in advance of the onset of
incremental production. Hence, the return on investment for CO2 EOR tends to be low, with a
gradual, long –term payout.

Figure 17: Costs and Economic of CO2 projects [15]

Given the significant front-end investment in wells, recycle equipment, and CO2 ,the time
delay in achieving an incremental oil production response and the potential risk of unexpected
geologic heterogeneity significantly reducing the expected response ,CO2 EOR is still
considered to be a risky investment by many operators , particularly in areas and reservoirs
36
where it has not been implemented previously . Oil reservoirs with higher capital cost
requirements and less favorable ratios of CO2 injected to incremental oil produced will not
achieve an economically justifiable return on investment without advanced, high-efficiency
CO2 EOR technology and /or fiscal /tax incentives for storing CO2.
A 2008 study by INTEK FOR DOE sought to test the economics of a potential linkage between
the most likely candidate CO2 EOR reservoirs and their most likely matching industrial CO2
sources. The study concluded that as much as 30 trillion cubic feet of CO2 or -5 billion cubic
feet per day at peak rates of injection –could ultimately be stored under this scenario, with a
resulting incremental increase in U.S. Oil production of 5.5 billion barrels over 25 years.

3.11 Current Status of CO2 gas injection for EOR Processes [6]:
Most of the EOR activity took place in the USA in the past, and the bulk of the production
came from that country. Figure 18 shows the EOR production during the last 20 years in USA.
The total EOR production in USA is declining. The major contributor was thermal methods,
and that is also on the decline, mainly because most attractive reservoirs have already been
exploited. Production from gas injection is increasing, and that is mainly due to CO2 floods.
Production from chemical floods is non-existent at present. The total EOR production in the
USA today constitutes about 12% of the total domestic oil production.

Figure 18: EOR Production in the USA [6]

The total word oil production today (including condensate and natural gas liquids) is 84.5
million B/D. EOR production worldwide is about 2.5X106 B/D, and almost all of it comes from

37
USA, Mexico , Venezuela ,Canada ,Indonesia and China, as seen in Figure 19.Figure 20 show
the breakdown of the production from the contributing countries. Thermal methods are
dominant in five countries .Chemical floods are active in China , the total production being
200000 B/D in 2006.
Recent advancements in technology and the current economic climate have resulted in a
renewed interest in EOR. Future growth of EOR will depend on both technology and oil price.
Long term commitments in capital and human resources , as well as in R&D, are essential for
success in EOR practice. While EOR screening methods are useful tools , recovery methods
that are considered unattractive in most reservoirs can be applicable in specific situations. Also
proven EOR methods may be adapted to adverse conditions, as experienced in Canada.
Considering the widening gas between demand and supply of energy , EOR will continue to
play a significant role in improving recovery factors.

Figure 19: Current EOR Production from Contributing Countries (Percentage are those of the
total EOR production of 2.5 million B/D) [6]

38
 Figure 20: Major EOR Projects and Production Worldwide [6]

CO2 as injection gas for Oil recovery has been mentioned as early as 1916 in the literature, but
it was dismissed as a laboratory curiosity due to the absence of large and economically priced
supplies. But in the early 1950s the industry started to look more seriously into miscible
flooding. It began with looking at first contact miscible floods projects by using propane, LPG
and natural gas. But these solvents were soon regarded to be too expensive and unsuitable at
that time because of their low viscosity and density, which could result in low volumetric sweep
efficiency. As a result of rejecting those solvents, CO2 was again on the agenda. The first
project , the Ritchie field , started CO2 injection in 1964. This was a small project, and first in
1972 the bigger CO2 project. SACROC Unit in Scurry country in the Permian Basin, started
to inject CO2 as an immiscible secondary recovery mechanism. After that , CO2 floods have
been used successfully throughout several areas in the US, especially in the Permian Basin.
Outside the US, CO2 floods have been implemented in Canada , Hungary , Turkey , Trinidad
and Brazil. [13]
Expect from US, there are not many CO2 floods worldwide. The main reason for this has most
probably to do with availability of CO2. Huge volumes are required, and there are lack of both
infrastructure and sources in most of the oil producing regions world wide , except from US,
especially in the Permian Basin . Today there are about 78 CO2 floods in operation worldwide,
67 in US, 2 in Canada , 2 in Turkey, 5 in Trinidad and 1 in Brazil. But all together there have
been more than 100 EOR projects with CO2 flooding since first flood took place. [13]

39
Operations History [13]:
 USA: 85 Projects
 Canada: 8 projects
 Hungary: 3 projects
 Turkey :2 projects
 Trinidad: 5 projects
 Brazil: 1project, onshore oil field

United States[13] :
 67 floods (66 miscible and 1 immiscible)
 The first large project SACROC started in January 1972.
 Average life of producing properties is about 12 years.
 21 companies are operating floods in 2001 (1 to 16 projects)
 There are over 6,400 producing wells and 4,200 injection wells.
 Depth varies from 820 to 3280 m.
Canada [13]:
 Retlaw Mannvile: Nov.1983 (Immiscible CO2, Terminated)
 Joffre Viking Pool: Jan , 1984 (Miscible CO2, Operating)
 Abandoned field: (produced about 16% OOIP in mature area)
 Midale Midale Beds: July , 1986 (Miscible CO2, suspended)
 Harmattan East Rundle: 1988, (Miscible CO2, Terminated)
 Zama Keg River :1995 (Miscible acid gas , Terminated)
 Elswick Midale Beds: Apr,2000 (Miscible CO2 suspended)
 Weyburn Midale Beds: Oct,2000 (Miscible CO2, Operating)
Other Countries [13]:
 Hungary: 3 Projects 1971-1996 (Immiscible CO2 , Terminated)
 Turkey : 2 Projects 1986 (Immiscible CO2, Operating)
 Trinidad: 5 Projects 1974 (Immiscible CO2, Operating )
 Brazil : 1 Project (Aracas Field , Miscible Operating)

3.12 Case Studies of CO2 gas injection for EOR Processes [16]:
Evaluation of Miscible and Immiscible CO2 injection in one of the Iranian Oil Fields

3.12.1 Abstract:
Carbon dioxide CO2 flooding is one of the most important methods for enhances oil recovery
(EOR) because it not only increases oil recovery but also causes a reduction of greenhouse gas
emissions. It is a very complex system, involving phase behavior that could increase the
recovery of oil by means of swelling, evaporation and decreasing viscosity of the oil. In this
study, a reservoir modeling approach was used to evaluate immiscible and miscible CO2

40
flooding in a fractured oil field. To reduce simulation time , fluid components have been
grouped in to 10 pseudo –components .The 3-parameter, Peng-Robinson Equation of State
(EOS) was used to match PVT experimental data by using the PVTi software. A one
dimensional slim –tube model was defined using ECLIPSE 300 software to determine the
minimum miscibility pressure(MMP) for injection of CO2. FloGrid Software has been used
for making a reservoir static model and the reservoir model was calibrated using manual and
assisted history matching methods. Then various scenarios of natural depletion, immiscible and
miscible CO2 injection have been simulated by ECLIPSE 300 software and then the simulation
results of scenarios have been compared. Investigation of simulation results shows that the oil
recovery factor in immiscible CO2 injection scenarios is more than other methods.
3.12.2 Introduction:
Carbon dioxide concentration in the atmosphere has been increasing as well as greenhouse
gases since the beginning of the Industrial Revolution by anthropogenic activities. The increase
in mainly attributed to the combustion of fossil fuels for energy production. Of all the other
greenhouse gases , CO2 is responsible for about 64% of the enhanced greenhouse effect,
making it the target for mitigation of greenhouse gases. The pre-industrial era,CO2
concentration was about 280 ppm. Presently, it reaches 370 ppm as a result global temperature
has risen. In order to decrease global warming emission concentration of carbon dioxide should
be reduced. One of the available methods for minimizing CO2 concentration in the atmosphere
is the application of CO2 for injecting into oil reservoir in order to enhance oil recovery (EOR).
The use of CO2 for EOR is considered one of the most promising methods for commercial
application. Among gas injection processes, CO2 is preferred to hydrocarbon gases (HC)
because of its lower cost, high displacement efficiency and the potential for concomitant
environment benefits through its disposal in the petroleum reservoir.
Carbon dioxide could displace oil by either miscible or immiscible displacement. For pressure
below MMP, immiscible displacement of oil takes place, in which oil viscosity reduction,
swelling of reservoir oil , reduction of interfacial tension, and solution gas drive are major
driving mechanisms. This combination of mechanism enables a portion of the reservoir’s
remaining oil to be mobilized and produced. At pressures above MMP, the most dominant
mechanism is miscibility between CO2 and the reservoir oil. Miscible displacement by CO2 is
a much preferred process to immiscible displacement. The miscible process , is best application
to light and medium gravity crude oils, and the immiscible process ,may apply to heavy oils.
The goal of this study is the investigation of immiscible and miscible CO2 injection in order to
optimize the recovery of a field with a dual porosity system. The field is located in the
southwest of Iran. This oil field has two reservoirs : Gurpi and a shallower Asmari reservoir.
Main reservoir in this field is the Asmari formation with Oligocene and Miocene ages which
is divided into seven zones. Therefore, only the Asmari formation has been producing oil at
commercial scale.
The Asmari formation in this field consists mostly of carbonate that appear to be naturally
fractured with a low permeability matrix. The matrix has a porosity and permeability of about
0.088% and 3.4 md, respectively. A fracture network is distributed in the reservoir and the
fracture has porosity and permeability of about 0.002% and 3124 md, respectively also water
saturation is about 36%. Based on the studies performed by National Iranian Oil company the
original oil in place (OOIP) for this field is estimated to be 2126 MMstb.

41
Because the fracture network is well distributed, it is the dominant path for the flow of the fluid
in the reservoir. The reservoir has no initial gas cap and permeability and the size of aquifer is
very low to keep up the pressure of the reservoir. Based on the material balance calculations
and production behavior of the field, this field is an under saturated oil reservoir.

3.12.3 Fluid Properties:

The initial bubble pint pressure was 1904 psia, and the reservoir temperature is 250oF. Also
initial reservoir pressure is 5830 psia. Solution gas –oil ratio at the initial bubble point pressure
is 480scf/stb. The oil has 20.93 oAPI gravity.
Oil reservoirs with this API are suitable for CO2 flooding. Experimental PVT data were
provided by the field operator. These data contain constant composition expansion (CCE) data,
differential liberation (DL) data at the reservoir temperature (250oF), and separator tests.
Table1 gives reservoir fluid composition.

Table 1: Reservoir Fluid Composition:

Component Mole%
H2S 2.04
N2 0.22
CO2 4.36
C1 22.21
C2 6.84
C3 5.11
IC4 0.84
NC4 2.48
IC5 0.81
NC5 0.95
C6 0.92
C7 6.36
C8 4.36
C9 2.62
C10 3.16
C11 2.33
C12+ 34.39
MW C12+ 310
Sp.Gr C12+ 0.9637

3.12.4 Splitting, grouping and fitting the EOS:

In this study, a PVTi software has been used for characterization of the reservoir oil sample.
Insufficient description of heavier hydrocarbons reduces the accuracy of PVT predictions.
Therefore PVT matching generally starts with splitting the plus components into two or three
pseudo components, specifically when there are many of them compared with the other
components.

42
C12+ component was splitted into two pseudo components by Whitson’s method as shown in
Table 2. And also the Lee-Kesler correlation selected as critical properties correlation and
acentric properties correlation to describe the newly defined components.

Table 2: Reservoir fluid Components after splitting

Component Mole% Molecular Weight Specific Gravity

H2S 2.04
N2 0.22
CO2 4.36
C1 22.21
C2 6.84
C3 5.11
IC4 0.84
NC4 2.48
IC5 0.81
NC5 0.95
C6 0.92
C7 6.36
C8 4.36
C9 2.62
C10 3.16
C11 2.33
C12+ 21.86 219.84 0.88987
C24+ 12.53 467.3 1.0155

The next step is grouping the components; components with similar molecular weight must be
put in the one group. The main reason for grouping components is to speed –up the
compositional simulation. In compositional simulation the number of grouped components
depends on the process that is modeled. For miscibility, more than 10 components may
sometimes be needed. In general ,4-10 components should be enough to describe the phase
behavior. In the grouping processes usually obvious candidates are to group IC4 with NC4,
and IC5 with NC5. But there are some exceptions usually N2 added to C1 and CO2 added to
C2. In PVTi, the main criterion for a successful grouping is whether the new grouped
components can predict observed experimental results at least as well as the original ungrouped
components. Considering CO2 injection, after several experiments we grouped C2,C3,IC4 and
NC4 together, IC5 ,NC5 and C6 together, C7, C8 and C9 together and C10 and C11 together
as shown in Table 3 and finally in this study 10 components have been made to describe phase
behavior of the reservoir fluid . Table 4 shows reservoir fluid component and their properties
after grouping . After grouping , comparison of shapes of the phase diagrams before and after
grouping (Figure 21) indicates that they are close to each other therefore a good grouping has
been achieved.
The last stage was fit an EOS to have an agreement between the observed data and results
calculated with the EOS. The 3-parameter, Peng –Robinson Equation of State (EOS) was used

43
in this case study. Peng-Robinson EOS, a cubic EOS that was developed by Peng Robinson in
1976, has been shown to accurately model hydrocarbons and is the most widely used EOS in
compositional reservoir simulators.

Table 3: Grouping Method:

Row Component New Index Group

1 H2S 1 H2S
2 N2 2 N2
3 CO2 3 CO2
4 C1 4 C1
5 C3 5 C2-C4
6 C3 5 C2-C4
7 IC4 5 C2-C4
8 NC4 5 C2-C4
9 IC5 6 C5-C6
10 NC5 6 C5-C6
11 C6 6 C5-C6
12 C7 7 C7-C9
13 C8 7 C7-C9
14 C9 7 C7-C9
15 C10 8 C10-C11
16 C11 8 C10-C11
17 C12+ 9 C12-C23
18 C24+ 10 C24+

Table 4: Reservoir Fluid Components and their properties after grouping:

Component Mole% Weight Molecular Specific

Fraction% Weight Gravity
H2S 2.04 0.48704
N2 0.22 0.043178
CO2 4.36 1.3444
C1 22.21 2.4964
C2-C4 15.27 4.3718 40.864 0.56491
C5-C6 2.68 1.4311 76.219 0.64444
C7-C9 13.34 9.7673 104.51 0.73777
C10-C11 5.49 5.3664 139.52 0.78267
C12-C23 21.86 33.669 219.84 0.88987
C24+ 12.53 41.023 467.3 1.0155

44
Figure 21: Shapes of the phase diagram (a) Before and (b) After Grouping

45
3.12.5 Model Description:
In this study, a sector model was built by means of the FloGrid module of ECLIPSE simulation
software for investigation of various processes and parameters on the field. The sector is
portion of the reservoir and its connected production and injection wells were drilled in this
section .
This model was built on the basis of the structure maps obtained in the geological study.
Therefore, geometry of reservoir was constructed on the basis 8 structural contour maps
obtained for depth. Theses maps were digitized and used for making a geological model.
Reservoir properties such as porosity, permeability and net-to –gross (NTG) ratios in the three
directions were provided on the petrophysical study. Therefore, 7 contour maps for porosity,
permeability and net – to –gross ratios were used. After digitizing, theses maps have been used
for making a model of the reservoir . The type of gridding was selected as corner point
geometry because it was more accurate than the block center. In this study , in order to have
more accurate results , zone 1 was divided into two layers. So, the dual porosity model has 20
layers (10 for the matrix and 10 for the fractures).
The sector model is a 6.5 km model and its dimensions are as shown below:
Nx(the number of grids in x-direction)=65,size of each x grid block is about 100 m.
Ny(the number of grids in y-direction)=65, size of each y grid block is about 100m.
Nz (the number of grids in z-direction)=10 .Therefore this model contains 42,250 grids.
Figures 22-24 show the different properties of the sector model such as NTG, permeability and
porosity. The OIP for this sector is estimated to be 820.25 MMstb and that is more than one
third of the total OIP estimated for this field. Therefore increasing recovery of oil in this sector
can have an important influence on the total of oil.

46
 Figure 22: NTG Property in the sector Model

Figure 23: Permeability Property in the sector Model

47
 Figure 24: Porosity Property in the sector Model

3.12.6 Determination of CO2 minimum miscibility pressure (MMP):

The minimum miscibility pressure (MMP) is the lowest pressure at which multi-contact
miscibility can be achieved .In the petroleum reservoirs, miscibility is defined as that physical
condition between two or more fluids that will permit them to mix in all properties without the
existence of an interface.
The minimum miscibility pressure is one of the most important factors in the plan and operation
of miscible CO2 flooding process. Displacement efficiency depends on minimum miscibility
pressure and a dependable estimation of minimum miscibility pressure can help the operator to
design the injection condition and surface facilities. The main factors affecting miscibility are
the reservoir fluid composition, injection gas composition, reservoir temperature and pressure.
There are many methods for calculating the MMP such as Slim tube , rising bubble apparatus
and types of correlation.
In this study , one dimensional compositional simulation of the slim-tube model was performed
to determine the minimum miscibility pressure (MMP) of CO2 with the reservoir fluid. The
ECLIPSE 300 was used . This model has 600 grids with a porosity and permeability of 0.15
and 2000 md , respectively . The length of the model was selected as 100 m to ensure that
developed miscibility is formed and also 1cm for the width and height to minimize the result
of transition region length. Smaller diameter tubing is justified to prevent viscous fingering .
In the ECLIPSE 300 software the keywords FULLIMP and MISCIBLE were selected as the

48
solution method and the dependence of capillary pressure and relative permeability on surface
tension, respectively.
In order to produce a constant bottom hole pressure (BHP), the injection well was placed at the
first grid of the model (1,1,1) and the production well was placed at the end of the simulation
grid of the model (600,1,1).
The usual and more standard way to terminate displacement in slim-tube simulations is to
monitor the amount of injected gas. In fact, the amount of injected gas is the most important
factor for ending the simulation. In general the displacement is often ended after injecting 1.2
pore volumes (PV) of injected gas and then the oil recovery factor at 1.2 pore volumes of
injected gas is plotted as a function of pressure. The break-over pressure in these recovery
curves is estimated as the minimum miscibility pressure.
To find the minimum miscibility pressure (MMP) for CO2 and the reservoir fluid , several
slim-tube simulations were run at different displacement pressures using a model with 600 grid
blocks and then the ultimate recovery factor for each pressure was determined as shown in
table 5. Recovery factor at 1.2 pore volumes of CO2 injected is plotted versus pressure to
determine MMP as shown in Figure 25. According to theses results the MMP for CO2 injection
is about 4630 psia.

Table 5: Ultimate Recovery at Various Pressures:

Pressure (psia) Recovery Factor (%)

1911 54.34
2646 61.61
3675 73.75
4410 85.59
5145 87.90
5733 88.19
6174 88.54
6615 88.93
7056 89.13
7644 89.79
8085 90.10
8820 91.94
9261 92.87

49
 Figure 25: Recovery Factor versus Pressure to determien MMP

3.12.7 Reservoir Simulation Scenarios:

In this part of the study the purpose is to evaluate different scenarios of natural depletion ,
immiscible and miscible CO2 injection as enhanced oil recovery methods for this reservoir.
Nine wells were drilled in the sector model .Six of them (P1,P2,P3,P4,P5,P6) were classified
as production wells which were divided into two types of production wells: horizontal wells
(P1,P4,P6) and vertical wells (P2,P3,P5) also in order to evaluate CO2 injection scenarios three
vertical injection wells were located in the center of production wells (I1,I2,I3). In order to
determine that layers should be perforated for injection and production wells , the permeability
of different layers was evaluated. After taking various runs, horizontal production wells were
perforated in the fifth layer (nearly in the middle of the oil column) and vertical production
wells were perforated in the fourth , fifth and sixth layers. Also injection wells were perforated
in the sixth, seventh and eighth layers. A map view of the location and position of the 6
production wells and 3 injection wells is shown in Figure 26.
Before running different scenarios in order to have fair comparison , it needs to have a history
matching between pressure or flow data of the field and simulated model . The aim of history
matching is to find a model such that the difference between the performance of the model and
the history of a reservoir is minimized.
History matching is usually has done by hand (a trail and error process). For model adjustment
in history matching process, usually the parameters that have the minimum confidence and
maximum effect have been changed. These parameters are matrix and fracture permeability,
transfer coefficient between matrix and fracture , aquifer parameters , porosity and block
height. Therefore at the beginning of the history matching process sensitivity analysis was

50
performed on key parameters. Results show that porosity and permeability of the fracture and
compressibility factor are effective parameters in accordance with past field performance and
the model. Figure 27 Shows a good matching has been achieved between of calculated pressure
in model and pressure history of the field. After the history matching process the model is set
for prediction of different scenarios. At the end of 2010 average field pressure was 4410 psia.
The wellbore diameter is 0.7 ft in all cases and the time of simulation in all scenarios was 20
years (2010-2030).
The economical limits for shutting the production wells in all scenarios are given below :
 Maximum GOR : 1800 scf/stb
 Maximum water-cut: 45%
 Minimum oil Production rate : 150 stb/day

Figure 26: Map view of the location and position of horizontal and vertical wells

51
 Figure 27: History Matching Results of Field Pressure

3.12.7.1 Natural Depletion:

Selected sector model has six production wells (three horizontal wells and three vertical wells)
and rate of field oil production was set at 18,000 stb/day divided between six wells i.e, 3000
stb/day per well and the bottom hole pressure was set to 1900 psi.
The result of natural depletion scenario is shown in Figure 28 and 29. Figure 28 shows the field
total oil production at the natural depletion scenario from the year of 2010-2030. As shown in
this figure until the year of 2019 , filed oil production is increasing but after it the field faces
the reduction of oil production as it is specific in the figure , in other words the field faced the
half time of its life. Therefore, in order to increase oil production we need to apply enhanced
oil recovery methods.

52
 Figure 28: Field Oil Production total and average field pressure in the natural depletion
scenarios

Figure 29 illustrates the total of oil production rate for the field. As shown in this figure the
field oil production rate is decreasing during 2017-2030. Therefore this field needs to study
enhanced oil recovery methods to increase the amount of oil production.
At the end of 20 years of natural depletion scenario as shown in Figure 28 average field
pressure 1841 psia and is based on oil in the place estimated in this sector (820.25 MMstb), the
ultimate recovery factor will be approximately 15.07% as shown in Figure 29. Total pressure
drop at the end of natural depletion scenario is 2500 psia that can have bad effects on the
reservoir and in this condition gas injection such as CO2 injection can be helpful and it can to
increase the ultimate recovery factor and decrease the pressure drop.

53
 Figure 29: Field oil production rate and field oil efficiency in the natural depletion scenario

3.12.7.2 Immiscible CO2 Injection:

As mentioned above in order to investigate the CO2 injection scenario three injection wells
were located in the center of the production wells . Since the average field pressure before gas
injection was 4410 psia, the injection pressure must be higher , also fracturing pressure for this
field is 6200 psia therefore we cannot inject more than this pressure because of its damaging
result on the rock of the reservoir . The injection pressure for injection well at immiscible CO2
injection scenario was set o 4500 psia. The BHP for all production wells was 1900 psia. And
also the total production rate for production wells was 18,000 stb/day , i,e 3000 stb/day per
well.
The simulation model was run in specific conditions (3 gas injection wells and 6 oil production
wells) and the immiscible CO2 injection scenario was assumed to last 20 years. The only factor
that was variable in the scenarios was the injection rate. In the immiscible CO2 injection
scenario several simulations were run to find the optimum injection rate therefore CO2 was
injected at different rates of 3000 ,5000,7000 ,8000,10000,12000,15000 and 17000 Mscf/day.
The optimum injection rate sector model has the best oil recovery factor . Simulation results of
the immiscible CO2 injection scenario with different injection rates are shown in Table 6.
According to simulation results the best scenario was immiscible CO2 injection with an
injection rate of 17000 Mscf/day. At the end of 20 years in the immiscible CO2 injection
scenario as is shown in Figure 30 and based on oil in place estimated in this sector (820.25
MMstb) , the ultimate recovery factor for the injection rate of 17000 Mscf/day will be
approximately 34.45%. Operation of this reservoir with an injection rate of 17000 Mscf/day is
shown in Figure 31.

54
In this scenario field oil production total, average field pressure are 9.94X107 stb and 3053
psia, respectively. As a result the pressure drop in the immiscible CO2 injection is lower than
the natural depletion scenario and also the ultimate recovery factor in this scenario is more than
the natural depletion scenario.
Table 6: Simulation Results of Immiscible CO2 Injection scenarios:

Scenario Injection FOE % FOPT (stb) FPR (psia) FOSAT %

Rate(
Mscf/day)
1 3000 23.18 6.82E+7 1865 68.85
2 5000 25.61 7.52E+7 1888 66.79
3 7000 27.83 8.16E+7 1911 64.91
4 8000 30.02 8.79E+7 1936 63.05
5 10000 31.99 9.36E+7 2146 61.36
6 12000 33.59 9.81E+7 2401 60.04
7 15000 34.22 9.92E+7 2789 59.50
8 17000 34.45 9.94E+7 3053 59.34

Figure 30: Field Oil efficiency at different injection rates in the immiscible CO2 scenarios

55
Figure 31: Operation of the reservoir in the immiscible CO2 injection scenario with an injection
rate of 17,000 Mscf/day

3.12.7.3 Miscible CO2 Injection:

In the miscible CO2 injection scenario, location and position of production wells and injection
wells were similar with the immiscible injection scenario. The injection pressure for injection
wells at miscible CO2 injection scenario was set to 5100 psia.
The BHP for all of production wells was 1900 psia. And also the total production rate for
production wells was 18,000 stb/day, i.e., 3000 stb/day per well. In order to find the optimum
injection rate CO2 was injected at different rates of 12,000, 16,000, 20,000, 24,000, 27,000,
30,000,000 and 36,000 Mscf/day. Simulation results of the miscible CO2 injection scenario
with different injection rates are shown in Table 7.
According to simulation results the best scenario was miscible CO2 injection with an injection
rate of 30,000 Mscf/day. Operation of this reservoir with an injection rate of 30,000 Mscf/day
is shown in Figure 32. In this scenario at the end of 20 years total field oil production and
average field pressure are 1.041 · 108 stb and 5095 psia, respectively. Also based on oil in
place estimated in this sector (820.25 MMstb), the ultimate recovery factor will be
approximately 36.59%. The most stable displacement with the highest recovery was achieved
at an injection rate of 30,000 Mscf/day therefore the optimum injection rate for miscible CO2
injection scenario is 30,000 Mscf/day.
As could be seen in Table 7 an injection rate of 24,000 Mscf/day and more establishes miscible
processes, because the average field pressure in these scenarios was higher than the minimum
miscibility pressure.

56
When CO2 with an injection rate of 33,000 Mscf/day and more is injected into the sector model,
gas injected moves rapidly through fractures and almost without contact with the oil in the
matrix blocks produced in the production wells. This occurrence can be explained as fingering
in fractured reservoirs and it causes an increase in gas oil ratio in the production wells.
Therefore some of production wells would shut down after some time because the gas oil ratio
in these production wells is more than the economical limit so it causes a decrease in oil
recovery factor as is shown in Table 7.

Table 7: Simulation Results of Miscible CO2 Injection scenario:

Scenarios Injection FOE % FOPT FPR FOSAT FGOR

Rate (stb) (psia) % (Mscf/stb)
(Mscf/day)
1 12000 33.70 9.861E+7 2700 59.91 0.5677
2 16000 34.26 9.938E+7 3554 59.43 0.6943
3 20000 34.50 9.945E+7 4018 59.09 0.8240
4 24000 34.94 9.959E+7 4650 58.44 0.9681
5 27000 35.71 1.018E+8 4926 57.35 1.074
6 30000 36.59 1.041E+8 5095 56.94 1.130
7 33000 35.68 1.015E+8 5099 57.77 1.233
8 36000 35.15 9.999E+7 5101 57.99 1.301

Figure 32: Operation of the resevrior in the miscible CO2 injection scenario with an injectino
rate of 30,000 Mscf/day

57
3.12.8 Comparison of reservoir in different scenarios at their optimum injection rates:
As previously mentioned the optimum injection rates for immiscible and miscible CO2
injection scenarios were 17,000 Mscf/day and 30,000 Mscf/day, respectively. So these
scenarios were selected and compared with the natural depletion scenario. The results of these
scenarios are shown in Table 8 and Figure. 33 and 34. As could be seen in Table 8 in the natural
depletion scenario, filed total oil production is 4.48 · 107 stb while in the best immiscible and
miscible CO2 injection scenarios this is 9.94 · 107 stb and 1.041 · 108 stb, respectively
therefore the best scenario for this reservoir is miscible CO2 injection as shown in Figure 29.
At the end of the natural depletion scenario the average field pressure is 1841 psia but in the
best immiscible and miscible CO2 injection scenarios average field pressure is 3053 psia and
5095 psia, respectively thus the best scenario for injection into this reservoir is the miscible
CO2 injection because it increases the reservoir pressure and also a pressure drop in immiscible
CO2 injection is lower than for natural depletion as shown in Figure 34.
Oil recovery factor is 15.07% of OOIP in the natural depletion scenario and for the best
immiscible and miscible CO2 injection scenarios it is 34.45 of OOIP and 36.59 of OOIP
respectively therefore the best scenario for this reservoir is miscible CO2 injection. However,
economical cost and asphaltene precipitation must be studied more in these scenarios.

Table 8: Simulation results of Natural Depletion and the best immiscible and miscbile CO2
injection scenarios:

Scenarios FOE % FOPT (stb) FPR (psia) FOSAT %

Natural 15.07 4.48E+7 1841 75.65
Depletion
Immiscible 34.45 9.94E+7 3053 59.34
CO2 injection
(17,000
Mscf/day)
Miscible CO2 36.59 1.041E+8 5095 56.94
injection
(30,000
Mscf/day)

58
 Figure 33: Comparison of average field pressure values in natural depletion and the best
immiscible and miscible CO2 injection scenarios

Figure 34: Comparison of field oil efficiency values in natural depletion and the best immiscible
and miscible CO2 injection scenarios

59
3.12.9 Conclusion:

1. By using a slim –tube model, the minimum miscibility pressure for CO2 and reservoir
fluid was determined, this value was 4630 psia.
2. The injection rate is the most important parameter that can affect the oil recovery factor
, specifically in fractured reservoirs. The optimum injection rates for immiscible and
miscible CO2 injection scenarios were 17,000 Mscf/day and 30,000 Mscf/day
respectively.
3. According to the results in the miscible CO2 injection scenario with an injection orate
of 30,000 Mscf/day at the end of 20 years filed total oil production, average field
pressure and oil recovery factor are 1.041X108 stb, 5095 psia and 36.59% respectively,
therefore this scenario is the best scenario for produce from this reservoir.
4. In the miscible CO2 injection scenario, increasing the gas injection rate leads to quicker
movement of gas toward production wells with the result that the gas oil ratio is more
than the gas oil ratio limit (180 scf/stb) thus it causes the shutdown of some of the
production wells and the oil recovery factor will be less.
5. In the heavy oil reservoir the reach to miscible displacement is very hard, therefore, it
is recommended that in these reservoirs we should use the immiscible injection.

60
3.13 Conclusions and Remarks:

 The Enhanced Oil Recovery methods can increase oil reservoir recovery up to 60-70%.
There are numerous factors influencing the successful EOR process implementation,
starting from fluid and reservoir properties for preliminary selection of EOR Method,
conducting the laboratory testing, development of accurate reservoir numerical model,
pilot test implementation and monitoring to the profitable project’s application at the
whole reservoir area. [4]

 Justification of EOR application is directly depending on the crude oil prices at the
world market. [4]

 The most important parameter to be considered during CO2 EOR is the residual oil
saturation. [8]

 The success of CO2-EOR system depends on its ability to reduce the residual oil
saturation. Compared to the effect of the residual oil saturation, the effect of the
curvature of the relative permeability curves is insignificant. [5]

61
References:
[1]. Ronald E.Terry, Enhanced Oil Recovery, Brigham Young University.
[2]. Abubaker H.Alagerni, Zulkefli Bin Yaacob, Abdurahman H.Nour, An Overview of oil
production stages: Enhanced Oil Recovery Techniques and Nitrogen Injection,
International Journal of Environmental Science and Development VOL6.No 9 Sep, 2015.
[3]. Shepherd M, 2009. Factors Influencing Recovery form Oil and Gas Fields, Oil Field
production Geology: AAPG Memoir 91, P 37-46.
[4]. Chandram Udubasseri, Technical Consultant, EOR Methods.
[5]. S.Thomas , Enhances Oil Recovery –An Overview , Oil and Gas Science and Technology
Rev, IFP , VOL 63(2008) No 1,PP 9-19
[6]. Jerushank K.Pillay, Johannes Masuku, Meran Rajballi, An Introduction to Acoustic
Enhanced Oil Recovery.
[7]. James P.Meyer, Summary of Carbon Dioxide Enhanced Oil Recovery (CO2 EOR)
injection well technology, Parker Rd, Suite 102 B, Plano Texas 75075.
[8]. L.B.J Chathurangani, Britt M.Halvorsen, Near Well Simulation of CO2 injection for
Enhanced Oil Recovery (EOR) , Telemark University College , Faculty of Technology
Norway.
[9]. Design and Mechanical integrity of CO2 injection wells, University of Zagreb Faculty of
Mining, Geology and Petroleum Engineering.
[10]. Mahendra K.Verma, Fundamental 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 , USGS Science for a
changing world.
[11]. Vello A. Kuuskraa, Micheal L.Godec, Phil Dipietro, CO2 Utilization from ‘Next
Generation’ CO2 Enhanced Oil Recovery Technology, Energy Procedia 37 (2013) 6854-
6866.
[12]. EOR: Enhanced Oil Recovery , ENHANCED ENERGY INC,
www.enhanceenergy.com
[13]. Odd Magne Mathiassen, CO2 as Injection Gas for Enhanced Oil Recovery and
Estimation of the Potential on the Norwegian Continental Shelf, NTUU Norwegian
University of Science and Technology Department of Petroleum Engineering and Applied
Geophysics.
[14]. Ali Abedini, Mechanism of Oil Recovery During Cyclic CO2 injection Process : Impact
of Fluid Interaction, operating Parameters and Porous Medium, Petroleum System
Engineering , University of Regina , July 2014.
[15]. Carbon Dioxide Enhanced Oil Recovery, National Energy Technology Department,
U.S Department of ENERGY.
[16]. Aref H. Fath, Abdol R. Pouranfard , Evaluation of Miscible and Immiscible CO2
Injection in One of the Iranian Oil Fields, Egyptian Petroleum Research Institute ,
Egyptian Journal of Petroleum (2014) 23,255-270.

62