INJECTING CO2 AS AN ENHANCED OIL RECOVERY TECHNIQUE IN CARBONATE RESERVOIRS AND ITS EFFECT ON...

8/18/2019 INJECTING CO2 AS AN ENHANCED OIL RECOVERY TECHNIQUE IN CARBONATE RESERVOIRS AND ITS EFFECT ON RE…

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HERIOT WATT UNIVERSITY

INSTITUTE OF PETROLEUM ENGINEERING

Supervisor: Prof. Mehran Sohrabi

MSc Petroleum Engineering

Project Report 2010-2011

Mohsen Askari

“INJECTING CO2 AS AN ENHANCED OIL

RECOVERY TECHNIQUE IN CARBONATERESERVOIRS AND ITS EFFECT ON

RECOVERY FACTOR”


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Declaration

I, Mohsen Askari, confirm that this work submitted for assessment is my

own and is expressed in my own words. Any uses made within it of the

works of other authors in any form (e.g. ideas, equations, figures, text,

tables, programs) are properly acknowledged at the point of their use. A

list of the references employed is included.

Signed: Mohsen Askari

Date: 21/08/2011


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Acknowledgment

I am really thankful to my beloved family for all their support and love throughout my

life without whom I would not be standing in the position which I am now.

I would like to thank my supervisor Prof. Mehran Sohrabi for all his valuable guidance

throughout the project.

I am also sincerely thankful to Dr.Gillian Pickup for all her guidance and help in the

simulation part of the project and her dedication to answering questions and emails.

I would also like to acknowledge Mr.Alireza Kazemi for his help in the simulation model

of the project.

And last but definitely not the least I want to express my gratitude to Debbie Williams for

all the efforts and guidance throughout the course.


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1. Executive summary

Fast consummation and demand for sources of energy have been growing quite rapidly in

the recent years. More or less about 50% of the world energy is supplied by fossil fuel.

As the conventional reservoirs have been already explored and produced the new

methods of recovery need to be introduced for depletion of unconventional reservoirs

such as shale gas, tight gas and heavy oil reservoirs in order to fulfill the world demand

for energy.

Fig 1: World proven oil reservoirs (2006)

There are many methods of increasing the recovery, EOR (enhanced oil recovery) among

all CO2 (carbon dioxide) injection has been proved to be one of the most effective ones.

This is not just because of the good recovery achieved by CO2 injection but also the issue

of green house gases and the importance of CO2 sequestration under subsurface as an

effective method of reducing the CO2 in the atmosphere.


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The natural depletion of a reservoir would give a recovery of around 15 to 30%.with

using IOR (improved oil recovery) techniques it could increase to about 40 to

45%.considering both recoveries still around 50 to 60% of the oil would be left in

reservoir. Therefore the main objective nowadays is to increase the recovery efficiency of

the reservoir and extract the remaining oil. Having in mind that almost half of the world

reservoirs are made of carbonate rocks with relatively low recovery, different EOR

techniques need to be used out of which CO2 injection is one of the most efficient ones.

As both carbonate reservoirs and CO2 have complex characteristics the idea of using

CO2 injection as a technique for EOR purpose could be really complicated. This could

become even worse when the environmental hazards and economical viability are the

concerns.

CO2 injection can increase the recovery efficiency in three ways:

Reservoir pressure maintenance

Piston like displacement (Immiscible displacement)

Altering oil properties (miscible displacement)

In my project I will be investigating the properties of carbonate reservoirs and the

challenges and difficulties associated with it as well as the investigation of CO2, its

displacement methods and injection schemes.

I will also perform some experiments on a carbonate model using CMG IMEX and GEM.

The experiments on the model would be natural depletion, waterflooding, continues CO2

injection, CO2 WAG injection and CO2 SWAG injection.


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2. Literature review

2.1.

Carbonate reservoir

Around 3000 billion barrels of oil and 3000 trillion cubic feet of gas in place are stored in

carbonate reservoirs which make around 60% of oil and 40% gas of the world’s

hydrocarbon reserves. This will create great challenges for exploration and production in

terms of technology and methods for increasing the recovery. This is more feasible and

applicable in Middle East which contains around 62% of world’s proven oil reservoirs

out of which more than 70% are in carbonate reservoirs and 40% of world’s gas

reservoirs out of which more than 90% are reserved in carbonate reservoirs.

2.1.1. Introduction

Carbonates are marine environment deposited sediments which have a biological origin

and are greatly sensitive to environmental changes. There is also the effect of temperature

which affects the biogenic activity and therefore the sediment production.

The main components of carbonate rocks are fragments of marine organism, coral,

skeletons, algae and some calcium carbonate. This will make the carbonate rocks

chemically more reactive as compared to sandstones. The other factor that differentiates

between sandstone and carbonates is the distance where they have been formed and the

place they have been deposited. Carbonates are generally deposited closed to the place

where they have been formed where sands can move hundreds of kilometers down the

stream or river before the final deposition. At the beginning of deposition carbonate rocks


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contain a relatively high porosity of around 30% to 70%. But as mentioned before due to

high level of chemical and physical reaction the porosity will decrease.

Fig 2: components of carbonate rocks

2.1.2. Mineralogy

Unlike most of the carbonate reservoir properties mineralogy is quite simple. The main

minerals are calcite, dolomite and minor clay. Secondary mineral consist of quarts, chert

and anhydrite. Although depending on the depositional environment other minerals such

as phosphate, siderite, pyrite feldspar and clay minerals could also be present which are

called accessory minerals.

2.1.3. HeterogeneityIn general carbonate reservoir rocks have been proved to be more heterogeneous than

sandstone reservoirs. They normally contain a wider range of pore classes and therefore


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more likely for the multiphase properties to be different. This is one of the greatest

challenges in evaluation of carbonate rocks in early stages.

Fig 3: Heterogeneity in carbonate reservoir rocks

2.1.4. Diagenesis

Basically Diagenesis refers to the changes that happen to a sedimentary structure after it

is deposited and before it is metamorphosed. That includes changes in shape, volume,

size or chemical composition after the crystalline constituents or detrital biogenic have

been deposited. There are different types of Diagenesis mechanisms. It could be either

mechanical, biological, chemical or a combination of all. A simple example for

mechanical mechanism is the reduction of volume during the burial.

Biological diagenesis consists of rasping, grinding or erosion of the rock surfaces by

animals or plants.


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In carbonate reservoirs chemical diagenesis is by far the most important mechanism. It

basically is the interaction of water and rock which proceeds in rates dictated by rock-

water equilibrium. The main processes involve dissolution, cementation, recrystalization

and replacement. Diagenesis has quite a dramatic effect on porosity and permeability in

carbonate rocks. Carbonate sediments have quite a high porosity and permeability range

(30%-70%) at deposition stage. But after burial in reservoir depth and sediment alter the

properties will sharply decrease, resulting large abrupt variations in rock type distribution

in carbonate reservoirs.

Fig 4: Diagenesis in carbonate reservoirs

2.1.5. Porosity

The pore space inside the rock grains which is the potential space for containing the

hydrocarbon is called porosity. The total porosity refers to the total pore space regardless

of connectivity of the pores. But reservoir specialists are concerned about the

interconnected pores which have the capability of fluid transmission. This is called


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effective porosity. Porosity generally varies with several factors such as fabric, fracture

geometry and texture. In a fractured rock the porosity is determined with fracture width,

spacing of the fracture and presence or absence of mineralization. In biogenic rocks the

growth fabric and skeletal microstructure have the greatest affect on porosity and in other

rocks grain shape. Sorting and packing are the affective factors. Diagenesis which is the

chemical and physical change of the reservoir properties could either decrease or increase

the porosity. It can decrease it by plugging the pores with cement or closing them by

compaction or it can increase the porosity by dissolution or even creation of new porosity

by recrystalization or replacement.

Fig 5: Porosity in carbonate rocks


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As mentioned earlier the porosity in carbonate rocks are either created or altered by

depositional processes, diagenetic process or mechanical fracturing. A genetic

classification of different porosity, the causes and effects, the factors affecting porosity

and the result of it could be illustrated in a triangular diagram presented below:

Fig 6: Triangular diagram of carbonate rock porosity

2.1.6. Permeability

The importance of permeability as a property of the rock is that it is directly related to the

rate at which hydrocarbon could be produced. There is a vast range of permeability from

0.01 millidarcy to over 1 Darcy. Although the permeability of 0.1 millidarcy is the


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minimum desired permeability needed for oil production. Permeability is derived from

Darcy’s law:

Where Q is rate of flow, k is permeability, is fluid viscosity, (dP)/L is the potential drop

across a horizontal sample, and A is the cross-sectional area of the sample.

Fig 7: permeability in a rock

Permeability is generally expressed in 3 different ways:

1-Specific permeability: this is the permeability of a rock to a single fluid. It is normally

done on core samples in laboratories.

2-effective permeability: this is the permeability to another fluid where the reservoir

rock is saturated. This is the effective permeability of the rock to oil when the rock is

saturated with water.


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3-relative permeability: This is the effective permeability ratio at a specific saturation to

absolute permeability at 100% saturation.

The similarity between porosity and permeability is the effect of variations in fabric and

texture of a reservoir rock. Sometimes a small change in porosity can cause a dramatic

change in permeability. For example in a Siliciclastic sandstone reservoir 1% increase in

porosity can change permeability by a factor of 7 to 10%.

But unlike the porosity grain size has a big effect on permeability as well as packing,

sorting and fabric. For example in a fine grained rock with high intergranular porosity the

permeability is relatively lower.

In an ideal situation where the rock grain size is uniform and the porosity is intergranular

the permeability would be varying as the forth power of the average pore radius or in the

other term as the square of the grain diameter.

In real situations especially in carbonate reservoirs this is not the case. The various

genetic pore types and pore-pore throat geometries are the factors which greatly affect the

permeability. This is because permeability depends on the geometry of the pore throats

rather than the size of the pore. Although this is not a fixed rule and in some cases the

pore dimensions changes could be predictable by pore throat dimensions.

2.1.7. Wettability

In general wettability is the tendency of one fluid to be attracted to a solid surface which

in case of the reservoir is the rock rather than another fluid present.


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Fig 8: Oil wet and water wet reservoirs

In comparison with sandstone reservoirs, Spontaneous imbibitions do not happen or is

slower in carbonate reservoirs. Based on the researches on equilibrated water contact

angels oils in carbonate reservoirs it has been proven that around 85% of carbonate rocks

are oil wet and the remaining 15% are either water wet or intermediate. This clearly

shows that majority of the carbonate reservoirs are oil wet which means the oil is tending

to be attracted to the rock grains and hence much harder to recover. As mentioned before

in the heterogeneity section the heterogeneous properties of carbonate rocks makes the

issue of wettability a part of it. The effecting factors on reservoir wettability are:

Surface compounds

Brine Chemistry

Temperature and pressure

Brine PH

Mineralogy


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2.1.8. Capillary pressure

Based on the American Heritage Dictionary (1992) the definition of capillary pressure is:

“The force that results from greater adhesion of a liquid to a solid surface than internal

cohesion of the liquid itself and that causes the liquid to be raised against a vertical

surface, as water is in a clean glass tube. It is the force that allows a porous material to

soak up a liquid. ”

Surface tension and wettability which as mentioned before is the tendency of a liquid to

attract to a solid surface are the two factors that affect the interactive tension mentioned

above.

Fig 9: Capillary pressure

In the term of recovery capillary pressure can be a force to drive the non wetting fluid

through the pore throats where the reservoir is already saturated with a wetting fluid.

As we know capillary pressure is inversely related to pore throat radius. But this is

applicable for a model with cylindrical pore throats which is not the case in carbonate

reservoirs. Carbonate reservoirs have much more complex geometries and heterogeneity


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that another term should be used for them. The term is called effective radius which is

calculated using the below formula:

Where is the interfacial tension of the air-mercury system, is the air-mercury solid

contact angle and Pc is the capillary pressure. In carbonate reservoirs which are normally

oil wet the capillary pressure is a function of four factors:

Pore size

Pore structure

Interfacial tension

Contact angle

2.1.9. Naturally fractured reservoir

One of the properties of carbonate rocks is that they are more brittle and fragile compared

to sandstones when they are exposed to stress. This is the main reason most of the

carbonate reservoirs are naturally fractured.

Fig 10: Fractures in carbonate rock core sample


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Fractures in carbonate rock could be formed in very different scales. It could be from

microscopic scale to fractures with length of kilometers which are called swarms. The

presence of these different scale fractures creates a very complex flow network in

carbonate reservoirs. In spite of the mentioned problem there is a good side of fractures

as well. Fractures can increase the porosity and Permeability which can lead to better

recovery of the reservoir. But a reservoir is defined as a naturally fractured reservoir if

only there is presence of a network of fractures with various degrees of distribution

throughout the reservoir. There are several factors that make difference between a

carbonate reservoir and a normal conventional one and they are as follow:

1-Anisotropy: carbonate reservoirs are formed after the chemical and physical reactions

of the sediments. Considering the diagenesis and the fractures porosity and permeability

would be altered which makes an irregular permeability and porosity distribution. Hence

there is a big difference between horizontal and vertical permeability.

2-Porosity and permeability: as explained before porosity and permeability in carbonate

reservoirs differ from the ones in clastic reservoir which is mainly due to depositional

condition. The porosity in carbonate rocks are either connected porosity which is the

interconnected pores between the grains or vugs which is the unconnected pores that are

formed during the diagenesis of the rock or fracture porosity or dual porosity which is

formed due to stress and on the formation.

3-Micro fracture: micro fractures are very small fractures in the rock in the term of

length and width. Although micro fractures do not have a big affect on porosity but they

surly help in better recovery by increasing the matrix permeability.


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4-Transition zone: generally the transition zone is not formed in fractured carbonate

reservoirs because the capillary pressure is neglected therefore the fluid will be in

equilibrium at oil water contact (OWC) and gas oil contact (GOC) base on density and

gravity.

5-fracture gas cap: the gas cap is formed generally by liberation of the gas from the oil

and its movement toward the upper part of the fracture network. This is a phenomenon

that occurs when the pressure gradient of the flow is very low toward the wellbore which

is totally different with the situation where the liberated gas moves toward the wellbore

due to high mobility and low viscosity of the fluid.

6- Super K: the term of super K refers to the situation where there are big fractures in the

reservoir with very high permeability. In the first glance it looks to be an advantage but in

the case where injection is used for increasing the recovery it becomes a big disadvantage

as it causes the fingering of the injected fluid and therefore early breakthrough of the

injected fluid.

7-fluid contact: compared to matrix the fluid contact remains stable in carbonate

reservoirs due to negligible capillary pressure. But there is a bigger chance of coning due

to much higher permeability of the fractures.


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2.2.

Carbon Dioxide (CO2)

2.2.1. Introduction

CO2 injection is one of the methods which are used for enhanced oil recovery. This

technique can be useful in two different aspects. The first benefit is the increase in the

recovery and hydrocarbon production which will lead to more revenue. The other aspect

is sequestration of CO2 under the subsurface as CO2 is one of the main gases involved in

global warming and green house gas effect.

In carbonate reservoirs due to presence of high permeability fractures sequestration of

CO2 could be more interesting compared to clastic reservoirs. But there are other factors

which affect this process that need to be taken into account.

In the case of CO2 injection for miscibility process and enhanced recovery the

characterization of the reservoir has the biggest impact. Using the simulation models and

experimenting different scenarios perhaps is the best available option to gather extra

evidence on reservoir behavior.

2.2.2. CO2 physical properties

CO2 is a colorless, non combustible and odorless gas which is Inert at surface

temperature and finds liquid properties once exposed to reservoir condition. Pure CO2

has a critical temperature of 88 degree Fahrenheit and a critical pressure of 1070 Psia.

There are many ways in which CO2 can help in better recovery:

1-Oil Swelling: the forming of bubbles in oil by CO2 which ultimately enhances the oil

displacement at the pore scale is one of the ways for better recovery.


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2- Oil viscosity reduction: viscosity of the oil decreases once it is mixed with CO2 and

hence will flow more easily as the mobility increases as the viscosity decreases.

3-Oil density reduction: solubility of CO2 in oil will decrease the density and therefore

increased the mobility of the oil.

4-Vaporization: vaporization of CO2 can extract some portion of the oil and enhance the

recovery.

5-Interfacial tension reduction: by reducing the interfacial tension between oil and

water it makes the displacement more effective.

6-Miscibility generation: Miscibility could be regenerated if it is lost during the process.

2.2.3. CO2 phase diagram

Due to increase in the oil price and CO2 injection projects which started in 1960 study of

CO2 phase behavior has been done in order to determine the maximum miscible pressure

(MMP). These investigations which have been done on both pure and impure CO2 have

been carried out during the last 50 years. In a case where a compositional simulator is

used to predict the performance of a reservoir with volatile oil or condensate phase

behavior study of CO2 would be very important

Fig 11: CO2 phase diagram


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2.2.4. Miscible displacement

Miscibility is the ability of two fluids or materials to form a single fluid. In other term

when interfacial tension between the oil in the reservoir and the displacement fluid equals

zero which makes the swept zone’s residual oil saturation equal zero then miscible

displacement is taking place.

Fig 12: Carbon dioxide miscible displacement

Miscible displacement could be categorized in two categories:

1-First contact miscibility (FCM): this means when injecting the CO2 all the properties

will mix with reservoir oil. In this case any amount of CO2 injected will remain as a

single phase with the reservoir oil. In practical term generally a primary slug of CO2 will

be injected in small volume with the ability of miscibility in the oil. This slug then would

be followed by the larger slug known as secondary slug. The factor that plays a big role

in determination of size of primary slug is the economics. The other factor that needs to


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be into consideration is that the primary slug should be miscible in the secondary on. This

will prevent the material trapping in the reservoir caused by primary slug of CO2.

2-Mulitiple contact miscibility (MCM): the difference between MCM and FCM is that

in MCM the miscibility does not occur at the first contact. The process will take place

when several contacts are formed between the injected CO2 and the reservoir oil. In the

other term MCM occurs as a result of in-situ compositional changes and mass transfer

between the injected CO2 and the reservoir oil.

In the reservoir the mechanism of miscibility is as follow: at the beginning CO2

condensates into the reservoir oil and makes it lighter. This happens because the methane

is extracted from the oil. Now at this stage the light components of the oil vaporize and

mix into the CO2 phase. This mass transfer process between CO2 and the oil continues

till eventually both fluid are mixed and become indistinguishable in term of properties.

The key point in the process is that for miscibility high pressure is needed. Generally

because the reservoir pressure is high enough for the process the CO2 should be

compressed in such way to reach the desired density which makes it miscible in reservoir

oil. This pressure is called minimum miscible pressure (MMP). In other term this

pressure is the minimum pressure needed for CO2 and oil to be miscible together.

2.2.5. Immiscible displacement

In immiscible displacement unlike miscible displacement there is no phase change

between injected CO2 and the reservoir oil. The main reason immiscible displacement is

applied is to maintain the pressure in the reservoir in order to maintain the recovery.


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Fig 13: Carbon dioxide immiscible displacement

Basically immiscible displacement method is applied in 4 different ways:

Improving the recovery drainage

Recovering attic oil above uppermost perforation

Vaporization of light hydrocarbons in volatile oil or condensate reservoirs

Prevention of oil migration into gas cap in natural water drive reservoirs

2.2.6. Near miscible displacement

Near miscible displacement is an improved recovery technique that happens when the

reservoir fluid pressure is increase to just below minimum miscible pressure. The

recovery in this case is better than immiscible displacement but not as good as miscible

displacement. This technique is best suitable for the cases where there is a lack of

injection fluid due to many reasons such as remote location of injection facilities. The

other advantage of near miscible displacement is its better recovery compared to

waterflooding technique.


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2.3.

Injection techniques

2.3.1. Introduction

In the previous chapter the miscibility process and CO2 reaction with the reservoir oil

was studied. In this chapter different method of CO2 injection, the challenges associated

with each, advantages and disadvantages will be investigated.

2.3.2. Continues CO2 injection

In this method CO2 would be injected in the reservoir from the injection well in a

continuous process. In other term CO2 would be injected as the displacing fluid. The

displacement process would be either in miscible, immiscible or near miscible

displacement.

Fig 14: continues CO2 injection


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There are some advantages and disadvantages for continuous CO2 injection:

Advantages:

Quick response in production recovery due to mobility factor

Easier and faster achievement in stable injection rate

Minimization of water blocking

Disadvantages:

Poor sweep efficiency

CO2 usage in a less efficient manner

Difficulties and challenges of gas handling

Early CO2 water breakthrough resulting less recovery

2.3.3. CO2 WAG (water alternating gas) injection

Generally CO2 Wag injection is a more popular and demanding technique as it has a

better recovery in comparison with pure CO2 or water injection. This is because it is

combined by the advantage of CO2 injection which is good displacement efficiency and

advantage of waterflooding which is good macroscopic sweep efficiency which

ultimately leads to a better recovery and reservoir performance. In other term better

mobility control and improved macroscopic displacement in this method is the

mechanism that results in better recovery.


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Fig 15: CO2 WAG injection

Advantages:

Improved sweep efficiency

Better reservoir performance and recovery

Better CO2 utility

Disadvantages:

Longer response time from oil in comparison with continues CO2 injection.

Existence of high mobile water in a reservoir which has been waterflooded can

lead to a less efficiency even if injection process is above MMP.

Injection loss

Higher possibilities of water blocking


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2.3.4. CO2 SWAG (simultaneously water alternating

gas) injection

The SWAG method consists of simultaneously injecting water alternating CO2. This

method itself consists of two different methods: Conventional and unconventional.

In conventional method water and CO2 are injected together in the reservoir from the

same well. In unconventional method CO2 is injected to the bottom of the reservoir

where water is injected in the upper part of the reservoir using different injection wells.

The unconventional method is used expecting CO2 to migrate to the top of the reservoir

and water slumps down to the bottom of the reservoir and hence increasing the sweep

efficiency.

Advantages:

Proved to have the best recovery in some scenarios

Provides more stable GOR and easier gas handling

Disadvantages:

More complex operation compared to other techniques

Need of more accurate monitoring of injection systems


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2.3.5. CO2 Super critical injection

In super critical phase CO2 has a very unique phase behavior. It acts both as liquid and

gas. This helps in better recovery using the density property of the liquid phase and

viscosity property of the gas.

This method is the most applied technique in the industry due to the best achievable

recovery.

In order to achieve the super critical properties the pressure should be above 1500 Psia

and temperature above 80 degree Fahrenheit.


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3.

Simulation experiments

3.1. Introduction

C. Kerans et al (1994) have done an integrated characterization of carbonate ramp

reservoirs using Permian San Andres formation outcrop analogs. The San Andres

Formation of the Permian basin is representative of carbonate ramp reservoirs in that it

has highly stratified character, complex facies and permeability structure, and generally

low recovery efficiencies of 30% of original oil in place.

Fig 16: Rock fabric flow units in San Andres outcrop

The data obtained in this research have been used by Alireza Kazemi in Heriot-Watt

University in order to make a 2D model for simulation experiments.


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3.2. Grid Model

The grid model that has been used for experiments in the simulation part of the project is

52 x 1 x 55 2D model. This model best fits the simulation because of very heterogeneous

characteristics of the reservoir and the time which was needed for CMG GEM software to

run the simulations.

Fig 17: 2D grid model

As shown in the figure above an injector and a producer well have been located in the

edges of the model in vertical position. They would be used in order to simulate different

scenarios on the model. Only in CO2 SWAG injection the producer well will be replaced

by another injector well and the producer well will be located in the middle of the model.


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This is because the SWAG experiment done in the model is unconventional and therefore

two injector wells were needed.

3.3. Depletion case

In the depletion case the reservoir is depleted in natural drive condition. The production

is done by a single well set to produce at 100 bbl/day from all the layers. The simulation

starts at first of January 2011 and ends up on first of January 2032.

The recovery proves to be poor around 17 %. This is probably due to very low

permeability of the reservoir and absence of aquifer support.

Fig 18: depletion drive case recovery factor


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3.4. Waterflooding case

In the water flooding case the water is injected into the reservoir using an injection well

at the rate of 30 bbls/day. Both production and injection starts at first of January 2011 and

end up at the beginning of 2032. The recovery factor increases in comparison with the

natural depletion drive case up to around 21%. This is because of the reservoir pressure

maintenance achieved by water injection. The other factor that is causing the recovery to

increase is the increase in sweep efficiency. The injected water slumps due to gravity and

pushes the oil toward the production well.

Fig 19: Waterflooding case recovery factor


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3.5. Continues CO2 injection

In the CO2 injection method CO2 is injected into the reservoir continually at the rate of

1700 ft3/day. This is 3 times of the production rate of 100 bbls/day. Both injection and

production start at the beginning of 2011 and end up at the start of 2032. The recovery

increases up to around 24.5% and therefore better than natural depletion and

waterflooding case. This clearly shows that CO2 injection could be a better option

compared to the other scenarios. The reason for better recovery is probably the pressure

maintenance of the reservoir as a result of injection. But the other factor which is the

more important one is the miscibility of CO2 into the reservoir oil. This causes the

density and viscosity of the oil to decrease and oil mobility to increase and therefore

results in better recovery.

Fig 20: Continuous CO2 injection case recovery factor


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3.6. CO2 WAG injection

Same as other scenarios the injection of CO2 and water has been done using an injection

well. Water has been injected at 22 bbls/day and CO2 has been injected at the rate of 400

ft3/day. The alternating cycle has been set for every six months and same as other cases

production starts at 2011 and finishes at 2032. As shown in the picture recovery increases

up to around 36%. This proves a significant decrease in CO2 injection rate needed. This

could be due to effect of water acting like a piston that pushes the oil toward the wellbore

and increase in sweep efficiency due to water slumping. Miscibility of CO2 with oil and

increasing the mobility ration is also an important factor in increasing recovery.

Fig 21: CO2 WAG injection case recovery factor


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3.7. CO2 SWAG injection

In this case unlike the other scenarios two injection wells have been used for

unconventional SWAG CO2 injection. First injector well is injecting CO2 at the rate of

300 ft3/day at the bottom layers of the reservoir. The second injector is injecting water at

the rate of 26 bbls/day at the top layers of the reservoir. The production well has been

positioned at the center of the model. This scenario shows the best recovery factor of

about 40% among all cases and even a less amount of injected CO2 needed. This is

because when CO2 is injected at the bottom layers it tends to move upwards due to

gravity and with the miscibility effect it helps in increasing the recovery. In the other

hand the water that has been injected on the top layers slumps down toward the bottom of

the reservoir due to gravity and increases the sweep efficiency and hence increasing the

recovery factor.

Fig 22: CO2 SWAG injection case recovery factor


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All the cases recovery factor is illustrated in one graph in the below picture:

Fig 23: All cases recovery factor

3.8. Increasing injection rate

As a sensitivity analysis the injection rate in waterflooding, continuous CO2 injection,

CO2 WAG injection and CO2 SWAG injection cases have been increased by 25% of the

original rates. The experiment proves that increasing the injection rate by 25% has the

biggest impact on CO2 WAG injection case. The recovery increases for about 3% and

gives a total recovery almost as much as SWAG injection case. This suggests that by

increasing the injection rate in some cases a better recovery could be achieved but other

considerations such as early breakthrough, water fingering and rate stability control need

to be taken into account.


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Fig 24: All cases recovery factor after 25% increase in injection rate

3.9. Decreasing injection rate

The same scenario for sensitivity has been done but this time with 25% decrease in

injection rate. The outputs show the same results as above and prove the CO2 WAG

injection scenario to be the most sensitive case to injection rate changes with a change of

around 4.5%.


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Fig 25: All cases recovery factor after 25% decrease in injection rate

3.10. Impurity of CO2

Sensitivity analysis was done on the cases with CO2 injection to see the effect of N2

impurity. The results show that up to 20% of N2 impurity in the injected CO2 does not

have a big influence on recovery factor.

As illustrated in the below graph 20% N2 impurity has the biggest affect on continuous

CO2 injection case of less than 1%. In other cases the effect is almost negligible. One of

the ways that N2 impurity can affect recovery factor is that it will increase the MMP and

causes the miscibility in the reservoir to be lost and hence decrease the recovery factor.


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Fig 26: Effect of N2 impurity on recovery factor


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4.

Conclusion

The purpose of this project was to determine the effect of different methods of CO2

injection on reservoir performance and recovery facto. This study showed that CO2

injection can help in increasing the reservoir oil recovery. But it should be considered

that for CO2 injection a stable source of CO2 is needed. The other factor that needs to be

taken into consideration is the difficulties associated with CO2 injection such as

reduction of permeability or pipe choking caused by power carbon. But considering all

this factors CO2 injection have proved to be one of the best techniques for increasing oil

recovery as well as reduction of green house gas effect using the available technology.

The model that has been used in this project is a 52 x 1 x 55 2D model based on the

research paper done by C. Kerans et al (1994) on San Andres outcrop. Different recovery

techniques were experienced on the model and CO2 SWAG injection proved to have the

best recovery of around 40% followed by CO2 WAG injection with a recovery of 36%

and CO2 continuous injection with a recovery of around 25%.

Sensitivity analysis on injection rate showed the biggest impact on CO2 WAG injection.

This is probably due to the cycle in CO2 and water injection. The ratio between the

injected fluids need more research in order to achieve the best ratio for the optimum

recovery.

N2 impurity of the injected CO2 up to 20% did not have a considerable effect on the

recovery but as mentioned before it could have an effect on the MMP and causing

difficulties in miscibility process.


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There are few points for more investigations:

As mentioned above a more detailed investigation and research is recommended

in order to come up with the best injected fluids ratio in WAG and SWAG

injection method.

Effect of impurity could be investigated more especially taking into account the

impurity caused by N2, H2S and C2-C4 components.

Grid size effect on recovery factor is another area that could be studied even in

more details.

Miscibility process and the effect of different factors on it also need a much more

detailed investigation which was not done in this project due to lack of time.


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5. References

1. Carbon Dioxide miscible flooding: past, present and outlook for future.

F.I Stalkup, SPE-AIME, Atlantic Richfield Co.

2. A single Co2 injection well Minitest in a low permeability carbonate reservoir.

Royal J. Watts, SPE. U.S. DOE. James B. Gehr, SPE, Allegheny land & Mineral

Co.

3. Evaluation of the carbon dioxide flooding processes. L. Wally Holm, SPE,

Unocal Science and technology Div.

4. Comparison between CO2, CO2 WAG and CO2 SWAG injection. Nwajiaku

Stanley N.

5.

Carbon dioxide flooding. F. David Martin, SPE, and J.J. Taber, SPE, New Mexico

petroleum recovery research center.

6.

CO2 for enhanced oil recovery. www.CO2.nu

7. Enhanced Oil Recovery Field Experiences in Carbonate Reservoirs in the United

States. Eduardo Manrique, Mariano Gurfinkel, Viviana Muci

8.

Screening, Evaluation, and Ranking of Oil Reservoirs Suitable for CO2-Flood

EOR and Carbon Dioxide Sequestration. J. SHAW Adams Pearson Associates

S. BACHU Alberta Geological Survey

9.

The impact of injection strategy in carbonate reservoir using CO2. Syed

Muhammad Danish Abbas

10.

CO2 injection in carbonates. O. Izgec and B. Demiral


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11. EOR field experiences in carbonate reservoirs in the United States. E.J Manrique,

Norwest Questa engineering

12. CO2 EOR potential in naturally fractured Haft Kel field, Iran. Sayyed Ahmad

Alavian, NTNU, and Curtis H. Whitson, SPE, NTNU/PERA

13. Integrated Characterization of Carbonate Ramp Reservoirs Using Permian San

Andres Formation Outcrop Analogs. C. Kerans, F. Jerry Lucia, and R. K. Senger

14.

Rock-Fluid characterization for miscible CO2 injection: Residual oil zone,

Seminole field, Permian basin. M.M. Honarpour, N.R. Nagarajan

15.

Tertiary oil recovery and CO2 sequestration by carbonated water injection (CWI)

N.I. Kechut. SPE, M.Riazi, SPE.

16. www.slb.com

17.

www.mendeley.com/research/co2-injection-carbonates/

18. www.enhancedoilrecovery.com/co2-eor.htm

19.

www.sciencedaily.com/releases/2005/01/050110091718.htm

20.

www.fekete.com/aboutus/index.asp

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