graduation project ..complete - النهائي

Hayat Private University

Petroleum Engineering

Fourth Year – Group B

Graduation Project (E.O.R by CO2 injection in heterogeneous Reservoir)

Prepared by: Zaid Haider

Shivan Saman

Muslat Ibrahim

Supervised by: Mr. Haval Hawez

E.O.R by C02 injection in heterogeneous reservoir

Acknowledge

We are grateful to the God for the good health and wellbeing that were necessary

to complete this graduation project .

We place on record, our sincere thank you to Dr. Mohammed al-SaherAyoub

Dean of the Faculty, for the continues encouragement.

We wish to express our sincere thanks to Dr. Falah Hussein Khalaf , head of the

Faculty, for providing us with all the necessary facilities for the research.

We are also grateful to Mr. Haval Hawez , lecturer, in the Department of

petroleum engineering. We are extremely thankful and indebted to him for

sharing expertise, and sincere and valuable guidance and encouragement

extended to us.

We take this opportunity to express gratitude to all of the Department faculty

members for their help and support. We also thank our parents for the unceasing

encouragement, support and attention.

In the end, do not forget to thank the Committee precious because it gave us

enough time to discuss about the project in addition to the important advice and

guidance.


Table of contents

ACKNOWLEDGE 2

TABLE OF CONTENTS 3

TABLE OF FIGURES 4

ABSTRACT 5

CHAPTER ONE: INTRODUCTION 6

1.1 HETEROGENEITY: 11

CHAPTER 2: LITERATURE REVIEW 13

2.1. BACKGROUND OF EOR (TERTIARY RECOVERY) 13

2.2. EOR FROM CO2 INJECTION 15

2.3. REVIEW OF WAG 17

2.4. MINIMUM MISCIBLE PRESSURE (MMP) 21

2.5. WAG CLASSIFICATION 22

2.5.1. MISCIBLE WAG INJECTION: 23

2.5.2. IMMISCIBLE WAG INJECTION: 23

2.6. FACTORS AFFECTING WAG INJECTION 23

2.6.1. RESERVOIR HETEROGENEITY: 24

2.6.2. FLUID PROPERTIES AND ROCK FLUID INTERACTION: 24

2.6.3. AVAILABILITY AND COMPOSITION OF INJECTION GAS: 24

2.6.4. WAG RATIO: 24

2.6.5. INJECTION PATTERN: 25

2.6.6. WAG CYCLE TIME: 25

CHAPTER 3: CO2 MISCIBLE FLOODING CASE STUDIES 26

3.1 SACROC FOUR-PATTERN FLOOD 26

3.2 MEANS SAN ANDRES UNIT 28

3.3 DENVER UNIT 30

3.4 WATER ALTERNATING GAS RATIO 31

CHAPTER FOUR : SIMULATION STRATEGY AND SCENARIOS: 33

CHAPTER FIVE : RESULTS AND DISCUSSION 37

CHAPTER SIX : CONCLUSIONS AND RECOMMENDATION FOR FURTHER WORK: 41

6.1 CONCLUSIONS: 41

6.2 RECOMMENDATION FOR FURTHER WORK 41

REFERENCES 42


Table of figures

Figure(1): Classification of E.O.R _______________________________________________________ 9

Figure (2) : EOR by CO2 ______________________________________________________________ 9

Figure(3) :Generation CO2 EOR recovery _______________________________________________ 10

Figure(4) :CO2 injection _____________________________________________________________ 10

Figure (5): Shows a flowchart of oil recovery methods (Doghaish,2009) ______________________ 14

Figure (6) : CO2 injection processes ___________________________________________________ 16

Figure (7): Shows oil recovery vs. tome in WAG test after CO2 injection (Nezhad et al., 2006) _____ 20

Figure (8): Shows oil recovery vs. time in WAG test after water flooding (Nezhdad et al., 2006) ___ 20

Figure (9): Shows oil recovery during WAG injection for two different brines (Kulkarni and Rao, 2005)

________________________________________________________________________________ 21

Figure (10 ):Production history, SACROC four-pattern pilot. (From Healy, Holstein, and

Batycky: “Status of Miscible Flooding Technology,” Proc., 14th World Petroleum

Congress, Improved Recovery and Heavy Oil, 1994.© John Wiley & Sons Limited.

Reproduced with permission.) ____________________________________________________ 26

Figure (11) :SACROC pattern area, performance, and simulator match. (From Healy,

Holstein, and Batycky: “Status of Miscible Flooding Technology,” Proc., 14th

World Petroleum Congress, Improved Recovery and Heavy Oil, 1994. © John Wiley &

Sons Limited. Reproduced with permission. _______________________________________ 27

Figure (12) : Means San Andres miscible project performance _______________________ 29

Figure (13): Production performance of the Denver Unit miscible project. _____________ 31

Figure (14): FloViz visualization shows well ___________________________________________ 33

Figure (15): oil-water relative permeability curve ____________________________________ 36

Figure (16): Field oil efficiency versus time (years) _______________________________________ 37

Figure(17):Floviz visualization during miscible CO2 injection _______________________________ 38

Figure (18) : Gas injection rate versus time (years). _______________________________________ 40


Abstract

This project identify how carbon dioxide will be injected in the

heterogeneous reservoir for the purpose of maintain reservoir

pressure at level making it able to produce oil.

The project will pass through the problems of losing the

pressure and how to solve the problem by inject co2 in the

reservoir .

The project include three real solved examples of different

fields .

And the project also contain real data to design reservoir by

ECLIPSE program.


Chapter One: Introduction

Since more than a century the human world has become depends mainly on oil,

and in the middle of the last century, the American (Edwin Drake) was able to

get oil by drilling process.

For years, energy experts have been warning about our increasing dependence

on imported oil. Although the countries has abundant oil reserves, oil companies

usually recover only about (32%) of the oil in a typical reservoir. That is, for every

barrel of oil withdrawn from an oil field, two are left behind. Recovering all the

oil discovered is impossible; however, increasing production levels is a constant

goal. Extracting even a relatively small additional amount of oil is important to

the nation’s energy future.

The methods of oil production did not reach the required level at that time and

did not get a high yield of the layer where it remained huge amounts of oil are

located in the pores of the oil reservoirs, that prompting the scientists to look for

capable way of extracting these quantities till they reached ways give energy

over the reservoir energy and raised production of the reservoir and named

these roads ''Enhanced Oil Recovery (EOR)'' .

Oil recovery operations traditionally have been subdivided into three stages:

primary, secondary, and tertiary. Historically, these stages described the

production from a reservoir in a chronological sense. Primary production, the

initial production stage, resulted from the displacement energy naturally existing

in a reservoir. Secondary recovery, the second stage of operations, usually was

implemented after primary production declined. Traditional secondary recovery

processes are waterflooding, pressure maintenance, and gas injection, although

the term secondary recovery is now almost synonymous with waterflooding.

Tertiary recovery, the third stage of production ,was that obtained after

waterflooding(or whatever process was used). Tertiary processes used miscible

gases, chemicals, and/or thermal energy to displace additional after the

secondary recovery process became uneconomical.

The drawback to consideration of the three stages as a chronological sequence

is that many reservoir production operations are not conducted in the specified


order. A well-known example is production of the heavy oils that occur

throughout much of the world, If the crude is sufficiently viscous, it may not flow

at economic rates under natural energy drives, so primary production would be

negligible. For such reservoirs, waterflooding would not be feasible; therefore,

the use of thermal energy might be the only way to recover a significant amount

of oil. In this case, a method considered to be a tertiary process in a normal

chronological depletion sequence would be used as the first, and perhaps final,

method of recovery In other situations, the so-called tertiary process might be

applied as a secondary operation in lieu of waterflooding. This action might be

dictated by such factors as the nature of the tertiary process availability of and

economics. For example water flood before application of the tertiary process

would diminish the overall effectiveness, then the waterflooding stage might

reasonably be bypassed.

Because of such situations, the term "tertiary recovery" fell into disfavor in

petroleum engineering literature and the designation of enhanced oil recovery"

(EOR) became more accepted. Another descriptive designation commonly used

is improved oil recovery (IOR), which includes EOR but also encompasses a

broader range of activities, e.g., reservoir characterization, improved reservoir

management, and infill drilling.

Because of the difficulty of chronological oil-production classification,

classification based on process description is more useful and is now the

generally accepted approach, although the naming of the processes still

incorporates the earlier scheme based on chronology. Oil recovery processes

now are classified as primary, Secondary, and EOR processes.

Primary recovery results from the use of natural energy present in a reservoir

as the main source of energy for the displacement of oil to producing wells.

These natural energy sources solution recovery drive, gas-cap drive, natural

waterdrive,fluid and rock expansion, and gravity drainage. The particular

mechanism of lifting oil to the surface, once it is in the wellbore,is not a factor in

the classification scheme. Secondary recovery results from the augmentation of

natural energy through injection of water or gas to displace oil toward producing

wells. Gas injection, in this case, is either into a gas cap for pressure

maintenance and gas-cap expansion or into oil-column wells to displace oil

immiscibly according to relative permeability and volumetric sweepout

considerations. Gas processes based on other mechanisms, such as oil swelling.

oil viscosity reduction, or favorable phase behavior, are considered EOR


processes. An immiscible rates gas displacement is not as efficient as a

waterflood and is used in frequently as a secondary recovery process today.

(Its use in earlier there times was much more prevalent). Today; waterflooding

is almost recover synonymous with the secondary recovery classification.

EOR results principally from the injection of gases or liquid chemicals and/or

the use of thermal energy. Hydrocarbon gases, CO2 nitrogen, and flue gases

are among the gases used in EOR processes. The use of a gas is considered an

EOR process the recovery efficiency significantly depends on a mechanism other

than immiscible frontal displacement characterized by high-interfacial tension

(IFT) permeabilities. A number of liquid chemicals are commonly used,

including polymers, surfactants, and hydrocarbon solvents. Thermal processes

typically consist of the use of steam or hot water, or rely on the in-situ

generation of thermal energy through oil combustion in the reservoir rock.

EOR processes often involve the injection of more than one fluid In a typical

case, a relatively small volume of an expensive chemical (primary slug) is

injected to mobilize the oil. This primary slug is displaced with a larger volume of

a relatively inexpensive chemical (secondary slug). The purpose of the

secondary slug is displace the primary slug efficiently with as little deterioration

as possible of the primary slug. In some cases, additional fluids of even lower

unit cost are injected after a secondary slug to reduce expenses .In such a case

of multiple fluid injection, all injected fluids are considered to be part of the EOR

process, even though the final chemical slug might be water or dry gas that is

injected solely to displace volumetrically the fluids injected earlier in the

process.


Figure(1): Classification of E.O.R

Figure (2) : EOR by CO2


Figure(3) :Generation CO2 EOR recovery

Figure(4) :CO2 injection


1.1 Heterogeneity: Reservoir heterogeneity is defined by (Tarek, 2001) as ‘a variation in reservoir

properties as a function of space’. The effectiveness of recovering oil from the

reservoir will depend on how well the layers communicate with each other. In

order for effective communication to occur, barriers to fluid flow such as faults,

lateral faces variation, lenses and unconformities should not exist. It is

recognized that one of the main reasons for the failure of most EOR projects is

due to reservoir heterogeneity (Donaldson et al., 1989). Therefore, before

embarking on any EOR project, it is essential to have a better understanding of

the reservoir size, shape and heterogeneity by conducting interference tests and

pressure history analysis (Donaldson et al., 1989).

The effect of heterogeneity can be distinct in different reservoirs, affecting

various parameters such as capillary pressure, relative permeability, and

mobility ratios. The presence of different permeability’s and heterogeneity in a

reservoir, affects the displacement of the native fluids by the injected fluid.

Channeling of the solvent through high permeability regions reduces the storage

and displacement efficiency of the displacing solvent. However, it strongly

affects the efficiency in the WAG process design, since this phenomenon

controls the injection and sweep patterns in the flood. This phenomenon can

cause large variations in the vertical and horizontal permeability of the reservoir.

Vertical permeability is influenced by cross flow, Viscous, capillary, gravity and

dispersive forces (Madhav, 2003). However, high recoveries result from low

vertical to horizontal permeability ratio because the gravity segregation does not

dominate the fluid flow behavior.

In reservoirs with high stratification, the displacement fronts created that will

travel according to the permeability of each layer. The fronts in the most

permeable layers will be located furthest because the injected fluid will traverse

the more permeable layers easily while bypassing the less permeable layers of

the reservoir. This will lead to lower recovery because the less permeable layers,

which may have more residual oil, are not effectively swept by the injected fluid.

Operators try to solve this problem by injecting plugs of resin or cement to

temporarily plug off the most permeable parts (Latil, 1980).


Random heterogeneity occurs in both carbonate and sandstone reservoirs. The

reservoir consists of layers of different permeable zones separated by thin

deposits of shale. This may occur in both the horizontal and vertical directions

and the horizontal permeability may be better than the vertical permeability.

Since the different layers have differing permeability, the advancement of the

displacement front does not follow a regular pattern. The thin shale deposits

that separate the layers aid the recovery process by preventing the injecting

fluid from crossing over to the most permeable layers. This will enable the

injected fluid to effectively sweep each stratified layer thus increasing the sweep

efficiency and the overall recovery efficiency (Donaldson et al., 1988).


Chapter 2: Literature Review

2.1. Background of EOR (Tertiary Recovery)

Enhanced oil recovery (EOR) is the process of obtaining stranded oil not recovered from an oil

reservoir through certain extraction processes. EOR uses methods including thermal recovery,

gas injection, chemical injection and low-salinity water flooding. Although these techniques

are expensive and not always effective, scientists are particularly interested in EOR's potential

to increase domestic oil production. It is also called "tertiary recovery."

Tertiary recovery is a technique used to extract the remaining oil from previously drilled and

now less desirable reservoirs where primary and secondary extraction methods are no longer

cost effective. Tertiary recovery has proven worthwhile in several parts of the United States,

including Utah, Texas and Mississippi, where these reservoirs are less desirable because their

oil is more difficult to extract or requires more processing. Either problem means that

recovering this oil is more expensive and probably less profitable, but tertiary recovery can

still be profitable if market prices for oil are high enough.

Enhanced oil recovery also referred to as tertiary recovery is a sophisticated recovery

technique that is applied to increase or boost the flow of fluid within the reservoir. It involves

the injection of fluid other than just conventional water and immiscible gas into the reservoir

in order to effectively increase oil production (Zerón, 2012). These methods go beyond

primary and secondary recovery by reducing the viscosity of the fluid and increasing the

mobility of the oil. Tertiary recovery is normally applied to recover more of the residual oil

remaining in the reservoir after both primary and secondary recoveries have reached their

economic limit. The methods includes: thermal, chemical, gas, and microbial (Speight, 2009).

A flowchart of the three recovery methods is shown in Fig. (5)


Figure (5): Shows a flowchart of oil recovery methods (Doghaish,2009)


2.2. EOR from CO2 injection

One way to stimulate tertiary recovery is to inject carbon dioxide (CO2) into a reservoir. This

method can yield as much as 17% of a field's original oil in place. Occidental Petroleum,

Danbury Resources and Anadarko Petroleum have used this technique in North America. One

difficulty with CO2 injection is that petroleum companies must secure an adequate supply of

CO2 before they can implement tertiary recovery.

Oil reservoirs are deep underground, with the oil and gas contained in porous rock at high

temperatures and pressures. Around 5 – 20%, of the oil can be produced from the field under

its own pressure (primary production), but in most fields water is injected to displace the oil.

This still leaves at least 50% of the oil behind in the reservoir. Further recovery can be

obtained by injecting carbon dioxide that both displaces and dissolves the remaining oil. At

least 71 projects worldwide use CO2flooding and produce a total of over 170 000 barrels of oil

a day, worth around $1.3 billion a year. The cost of producing an extra barrel of oil ranges

from $5 to $8 and thus is profitable at the present price of nearly $20 a barrel. In the majority

of these cases, the carbon dioxide comes from natural underground sources and is piped to

the oil field. The potential use of CO2 flooding would be considerably greater, if large

quantities of the gas, extracted from power stations, were available at low cost. For every

kilogram of CO2 injected, approximately one to one quarter of a kilogram of extra oil will be

recovered. For most projects about as much carbon dioxide is disposed of in the reservoir as is

generated when the oil is burnt. When CO2 is at a sufficiently high pressure to form mixtures

with the crude oil that are miscible in laboratory tests, up to 40% of the oil remaining in the

field after water flooding can be recovered. Approximately half the water flooded oil fields in

the US could be exploited profitably by CO2 injection. Carbon dioxide flooding of the larger

North Sea fields is a particularly attractive prospect, because the crude oil is light (composed

of low molecular weight hydrocarbons) and the geology of the reservoirs is less

heterogeneous than the American fields. A profitable project would be possible if the gas

could be provided and piped to the reservoir at a cost of around $3.50 per thousand cubic

feet or less.

CO2-EOR works most commonly by injecting CO2 into already developed oil fields where it

mixes with and “releases” the oil from the formation, thereby freeing it to move to production

wells. CO2 that emerges with the oil is separated in above-ground facilities and re-injected

into the formation. CO2-EOR projects resemble a closed-loop system where the CO2 is

injected, produces oil, is stored in the formation, or is recycled back into the injection well.


Today, most of the CO2 used in EOR operations is from natural underground ‘domes’ of CO2.

With the natural supply of CO2 limited, man-made CO2 from the captured CO2 emissions of

power plants and industrial facilities (e.g., fertilizer production, ethanol production, cement

and steel plants) can be used to boost oil production through EOR. Once CO2 is captured from

these facilities, it is compressed and transported by pipeline to oil fields.

Figure (6) : CO2 injection processes

During tertiary production, oil field operators use an injecting (usually CO2) to react with the

oil to change its properties and allow it to flow more freely within the reservoir. Almost pure

CO2 (>95 percent of the overall composition) has the property of mixing with oil to swell it,

make it lighter, detach it from the rock surfaces, and cause the oil to flow more freely within

the reservoir to producer wells. In a closed loop system, CO2 mixed with recovered oil is

separated in above-ground equipment for reinjection. CO2-EOR typically produces between 4-

15 percent of the original oil in place (ARI, 2010).

CO2 injected into a reservoir through an injection well acts as a kind of super solvent as it

passes through the oil reservoir. The CO2 dissolves into the oil that it contacts, decreasing the

oils viscosity and surface tension, allowing the oil to be extracted through producing wells.

Exploration and production activity in most oil reservoirs results in the recovery of only a

portion (30-60%) of the original oil in place, leaving a significant amount of oil that can be

recovered using CO2 enhanced oil recovery. Our CO2 enhanced oil recovery efforts have

demonstrated our ability to recover on average an additional 17% of the original oil in place,

and in some cases, we are exceeding 17%.


2.3. Review of WAG

The first reported WAG injection was done in the North Pembina oil field in Alberta, Canada in

1957 (Stenby et al., 2001). This pilot project which was reported to have been operated by

Mobil did not report any injectivity abnormalities (Mirkalaei et al., 2011). Another early work

involving WAG was conducted by Caudle and Dyes in (1958). They proposed and conducted

laboratory experiments of simultaneous water and gas injection on core plugs and the results

showed an ultimate sweep efficiency of about 90% compared to 60% sweep efficiency of gas

flooding alone. Since then, more WAG recovery methods have been studied in the laboratory,

tested and implemented in many fields around the world. An extensive literature review of

WAG field applications found in the literature was done by Stenby et al. (2001). They reviewed

59 WAG field cases both miscible and immiscible. The majority of the fields were reported to

be successful. The fields reviewed showed an increased recovery of 5% to 10% OOIP but

recovery increases of 20% OOIP were reported in some fields.

The increased oil recovery was attributed to the improved microscopic displacement of gas

flooding and improved macroscopic sweep by water injection as well as compositional

exchange between the gas and the oil. In the North Sea, WAG injection leads to improved

recovery through contact of the unswept zone of the reservoir, particularly the attic and the

cellar oilthrough the exploitation of gas segregation to the top and accumulation of water at

the bottom. Stenby et al. (2001) also explains how the horizontal (areal) sweep efficiency and

vertical sweep efficiency contributes to the total recovery efficiency. The horizontal sweep

efficiency depends on the stability of the displacement front which is defined by the mobility

ratio .The mobility ratio during gas injection is given by:


On the stability of the displacement front which is defined by the mobility ratio.

The mobility ratio during gas injection is given by:

𝑀 = 𝑘𝑟𝑔

𝜇𝑔

𝜇𝑜

𝑘𝑟𝑜

Efficiency, is given by:

𝑅𝑜𝑔

=(𝜗 𝜇𝑜𝐾𝑔 ∆𝜌

)(𝐿ℎ

)

Where:

𝜗 = 𝐷𝑎𝑟𝑐𝑦 𝑣𝑖𝑙𝑜𝑠𝑖𝑡𝑦 (𝑚/𝑠)

𝜇𝑜=𝑣𝑖𝑠𝑐𝑜𝑠𝑖𝑡𝑦 (

𝑘𝑔𝑚

.𝑠 )

𝐿 = 𝐷𝑖𝑠𝑡𝑎𝑛𝑐𝑒 𝑏𝑒𝑡𝑤𝑒𝑒𝑛 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠 (𝑚)

K= Permeability (m2)

G= Gravitational acceleration (m/s2)

H= height of displacement zone (m)

∆𝜌 = 𝑑𝑒𝑛𝑠𝑖𝑡𝑦 𝑑𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑐𝑒 (𝑘𝑔/𝑚2)


The greater the height of the displacement zone, the lesser the viscous gravity ratio and also

the greater the vertical sweep efficiency which means a higher recovery factor provided the

other factors remain unchanged (Arogundade, Shahverdi, & Sohrabi, 2013).Righi et al. (2004)

conducted an experimental study of tertiary immiscible WAG injection by flooding several 38

mm diameter core plugs with water and gas slugs. Their experimental results show that WAG

injection significantly increases tertiary oil recovery efficiency, leading to final residual oil

saturations as low as 13% pore volume (PV). According to them, the higher oil recovery

efficiency of IWAG over the water flooding was due to several mechanisms, one of which is

the improvement in volumetric sweep by the water following gas. In this mechanism, the free

gas present in the porous medium causes the relative permeability of the water in the three

phase zone (gas, water and oil) to be less than that in pores occupied by only water and oil.

This can lead to diversion of water to unswept areas, thus improving the macroscopic sweep

efficiency. Another mechanism of recovery is the reduction in interfacial tension (IFT).

The fact that gas-oil IFT is lower than water-oil IFT enables the gas to dispel more oil from the

pore spaces that may not be accessible by the water. This improves the microscopic

displacement efficiency. The trapping of gas following on imbibitions cycle is another method

through which oil recovery increases during WAG. The trapped gas causes oil mobilization at

low saturation and as a result, the three phase residual oil saturation is effectively reduced.

The improvement inrecovery efficiency of WAG was also due to the compositional exchange

between the oil and the injected gas. The injected gas can cause oil swelling and a reduction

of the oil viscosity. Reduction in the viscosity makes the oil more mobile and therefore easier

to flow. Reduction in oil viscosity also leads to favorable mobility ratio in under saturated

reservoirs (Righi et al., 2004). Kulkarni and Rao (2005) performed several laboratory

investigations of miscible and immiscible WAG process performance. The experiments were

carried out by flooding Berea sandstone core samples saturated with n-decane and brine with

CO2 gas and two types of brine.

In one experiment, 5% NaCl brine and in the other experiment Yates reservoir brine was used

as the injected fluid. The results of the flooding test showed an increase in the recovery of oil

by 9 cc (8.3% OOIP) and 11 cc (9.9% OOIP) for immiscible WAG and 41 cc (35.0% OOIP) and 29

cc (25.4% OOIP) for miscible WAG. The graph of one of the core experiments is shown below

in Fig(7)


Figure (7): Shows oil recovery vs. tome in WAG test after CO2 injection (Nezhad et al., 2006)

Figure (8): Shows oil recovery vs. time in WAG test after water flooding (Nezhdad et al., 2006)


Figure (9): Shows oil recovery during WAG injection for two different brines (Kulkarni and Rao, 2005)

2.4. Minimum miscible pressure (MMP)

The injection of carbon dioxide (CO2) for secondary and tertiary oil recovery has received

considerable attention in the industry because of its high displacement efficiency and

relatively low cost. Miscible recovery of a reservoir oil can be achieved by CO2 displacement

at a pressure level greater than a certain minimum. This minimum pressure is hereafter

defined as the CO2 minimum miscibility pressure (MMP). The CO2 MMP is an important

parameter for screening and selecting reservoirs for CO2 injection projects. For the highest

recovery, a candidate reservoir must be capable of withstanding an average reservoir

pressure greater than the CO2 MMP. A knowledge of the CO2 MMP is also important when

selecting a model to predict or simulate reservoir performance as a result Of CO2 injection.

The injection gases most commonly used for enhanced oil recovery processes are generally

not miscible upon first contact with the reservoir fluids that they are displacing. Miscible gas

injection into an oil reservoir is among the most widely used enhanced oil recovery techniques

and its applications are increasingly evident in oil production worldwide. Two important

concepts associated with the description of miscible gas injection processes are the Minimum

Miscibility Pressure (MMP)and Minimum Miscibility Enrichment (MME). TheMMP has typically

been accepted as the pressure at which practical maximum recovery efficiency is observed. In

other words, it is the lowest pressure at which gas and oil become miscible at a fixed

temperature and the displacement process becomes very efficient(Ayirala and Rao, 2006). It is


considered as one of the most important factors in the selection of candidate reservoirs for

gas injection at which miscible recovery takesplace and it determines the efficiency of oil

displacement by gas.

MMP can be measured by employing experimentaland non-experimental methodologies. In

the industry,there are many experimental techniques available to estimate MMP such as; slim

tube (Yellig and Metcalfe,1980; Huang and Dyer, 1993), rising bubble apparatus(Christiansen

and Haines, 1984), multi-contact experiment or mixing-cell experiment (Bryant and

Monger,1988; Menzie and Nielsen, 1963; Turek et al., 1988),pressure-composition diagram

(Orr and Jensen, 1984),vanishing interfacial tension (Gasem et al., 1993), fallingdrop

technique (Zhou and Orr, 1995), vapour density(Harmon and Grigg, 1988) and high pressure

visual sapphire cell (Hagen and Kossack, 1986). The non-experimental methods consist of both

analytical andnumerical approaches. All empirical correlations (Alston et al., 1985; Kuo, 1985;

Glaso, 1985; Orr and Silva,1987) and Equation of State (EOS) also belong to theanalytical

techniques. In EOS techniques for MMP calculations, the complex multicomponent system

isstreamlined into its lite, medium and heavy ends along with pseudo components. A two

phase region is developed and subsequently the critical region identificationgives the value of

MMP (Yurkiw and Flock, 1994).Non-experimental computational methods are fast

andconvenient alternatives to otherwise slow and expensiveexperimental procedures. This

research focuses onthe analytical aspect of MMP estimation. It introducesa non-parametric

model to improve the MMPestimation.

2.5. WAG classification

WAG injection can be classified into different forms by the method of fluid injection. The most

common classification is the difference between miscible and immiscible injection processes.

Miscible or immiscible injections are function of the properties of the displaced oil and

injected gas as well as the pressure and temperature of the reservoir (Lyons & Plisga, 2005).

Other less common classifications include: Hybrid WAG injection, simultaneous WAG injection

(SWAG),Water Alternating Steam Process (WASP) and foam assisted WAG injection (FAWAG).


2.5.1. Miscible WAG Injection:

In this type of WAG process, the reservoir pressure is maintained above the minimum

miscibility pressure (MMP) of the fluids. MMP is the minimum pressure required for

miscibility to occur between two fluids. Miscibility occurs when the two fluids mix in all

proportions without the formation of interference between them (Donaldson, Chilingar, &

Yen, 1989). If the pressure is allowed to fall below MMP, miscibility will be lost. In the real

field operation, it is often difficult to maintain MMP and as a result there is back and forth

between miscible and immiscible WAGinjection. The majority of WAG injections have been

classified as miscible and are mostly applied onshore, where wells are arranged in closed well

spacing (Stenby et al., 2001). Miscible WAG injection gives better oil recovery than immiscible

WAG injection.

2.5.2. Immiscible WAG Injection:

The purpose of this type of WAG injection is to stabilize the front and increase contact with

the upswept areas of the reservoir. The displacement of oil by immiscible gas injection has

higher microscopic sweep efficiency than by water. However, the very high mobility of gas

due to its low viscosity results in poor macroscopic sweep efficiency and consequently poor

recovery of oil during immiscible gas injection. So immiscible WAG injection is applied to

overcome this problem because the water helps to control the mobility of the gas and

increase macroscopicsweep efficiency (Fatemi et al, 2011). This type of WAG injection has

fewer records of field application. The experiment performed with this study is immiscible

WAG injection.

2.6. Factors affecting WAG injection

The success of water alternating gas injection (WAG) as an enhanced oil recovery method

depends on reservoir characteristics and fluid properties (Latil, 1980). Injection and

production well arrangement, and WAG parameters are two other important factors that

affect the WAG recovery process.


2.6.1. Reservoir heterogeneity:

Reservoir heterogeneity is a function of the porosity/permeability distribution due to

lithological variation during sedimentary deposition which is further complicated by

mechanical processes related to deformation and chemical processes associated with

digenesis. Fluid flow in reservoirs is affected by heterogeneity at a range of scales, from

submetre up to 10’s of meters, but the predominant control is exerted by bedding, pore fluid

changes, and digenetic effects at the metre-scale (Grammer, et al, 2004).

2.6.2. Fluid properties and rock fluid interaction:

Viscosity is the single most important fluid property in EOR projects because it controls the

flow of fluids in the reservoir. It is defined as the resistance of the fluid to flow (Tarek, 2001).

The lower the viscosity of a fluid, the easier it can flow in porous media and vice versa. The

viscosity of crude oil is highly dependent on temperature, pressure, oil gravity, gas gravity and

gas solubility. If everything else remains the same, the higher the viscosity of oil, the higher

the residual oil saturation (Latil, 1980).

2.6.3. Availability and composition of injection gas:

In the design of WAG processes, the availability of gas, in terms of quantity and composition,

plays a vital role. Usually, the gas produced with oil from a reservoir is re-injected during the

WAG process. Gas composition, in particular, is critical in WAG process design because it is a

deciding parameter that determines whether the process is going to be miscible or immiscible

under the prevailing conditions of pressure and temperature within the reservoir (Bon and

Sarma, 2009; Jianwei et al., 2008).

2.6.4. WAG ratio:

The WAG ratio is highly significant in WAG process design (Chen et al., 2010, Farshid et al,

2010). A WAG ratio of 1:1 is normally used in field applications. However, the WAG ratio

strongly depends on reservoir’s wettability and availability of the gas to be injected (Jackson

et al., 1985; John and Reid, 2000). In general, it is preferable to inject higher gas volumes as

compared to water in oil-wet reservoirs. The amount of volumes to be injected at the desired

pressures strongly affects the cost of surface facilities, like compressors and pumps, which in

turn strongly influences the WAG ratios due to economic constraints.


2.6.5. Injection pattern:

The choice of the Wells spacing, in WAG process design, is very important because of the fact

that the sweep efficiency of the oil is strongly affected by distance between the injector and the

producer well (Christensen et al., 1998, 2001; Mohammad et al., 2010).

In many cases, a Five-spot injection pattern is very popular, as it can provide better control on

frontal displacement (Zahoor, 2011). Chase and Tood (1984) reported about well’s orientation

and theirs opinion is that the combination of vertical producers with horizontal injectors can

give better recovery. The advances in computer technology and software development have

made this possible, that the optimum location of wells and their orientation, together with

parameters like WAG ratio, can be selected through simulation studies by preparing a different

numbers of scenarios (different field development models of reservoir) and analysing the front

propagation and recovery enhancement (Farzaneh et al. 2009).

2.6.6. WAG cycle time:

Other variable that can be considered in optimizing WAG scheme include the timing of switch

from gas to water. Furthermore, the sequencing of gas, water and WAG injection across a large

field can offer significant opportunities for increases gas storage (X. WU, 2004). Previous

WAG cycle design procedures used steady state methodology and accepted industry rules of

thumb. The use of a simulator permits a more rigorous analysis to optimize WAG cycle

parameters such as cycle time (Pritchard, 1992). (X. WU, 2004) recommends to examine

different cycle lengths by simulating WAG process, in this way we will get to know which

cycle lengths is recommendable for our specific case and also get to know the effect of slug

sizes of water and gas on oil recovery.


Chapter 3: CO2 miscible flooding case studies

whereby carbon dioxide is injected into an Carbon dioxide (CO2) flooding is a process

oil reservoir in order to increase output when extracting oil. There have been more

miscible flood projects than any other type of 2CO

The three examples reviewed below are considered typical of such applications:

SACROC four-pattern flood

Means San Andres Unit

Wasson Denver Unit

3.1 SACROC four-pattern flood

This project (SACROC) has been completed. It was thoroughly waterflooded before

starting miscible injection. This sequence allows a straightforward evaluation of

increased recovery because of miscible displacement.

Fig. (10) shows the oil-production rate for the end of the waterflood and the miscible

flood. Actual field data are represented by the solid curve, and the forecast decline

curve for a continuing waterflood is shown as the dotted curve. The difference

between the actual field rate and the forecast waterflood decline represents increased

recovery resulting from the miscible project (shaded area); the amount is given in

million stock tank barrels (MMSTB). Additional reservoir performance data, including

primary plus secondary (P + S), miscible, and total recovery, are given in the upper-

right-hand box as a percent original oil in place (OOIP). These data are given in terms

of cumulative recovery to date as well as projected ultimate recovery.

Fig. (10) – Production history, SACROC four-pattern pilot. (From Healy, Holstein, and Batycky: “Status of Miscible Flooding Technology,” Proc., 14th World Petroleum Congress, Improved Recovery and Heavy Oil, 1994.© John Wiley & Sons Limited. Reproduced with permission.)

http://petrowiki.org/Miscible_flooding

http://petrowiki.org/Waterflooding


After completing the waterflood in 1981, the CO2 flood was initiated with the same

wells and injection patterns. The four-pattern area encompasses 600 acres and 19

MMSTB (3.0 million m3) OOIP. The well pattern is an inverted nine-spot with 40-acre

well spacing. Shortly after starting CO2 injection, there was an increase in oil-

production rate. The enhanced oil recovery (EOR) of 1.7 MMSTB (0.3 million m3) is

equivalent to 9% OOIP, which, when added to primary plus secondary recovery (57%

OOIP), gives a total recovery of 66% OOIP. Net CO2 use was 3.2 Mscf/STB of

increased recovery (570 std m3/m3).

This project demonstrated that incremental oil can be recovered by a miscible flood

after an efficient waterflood. In this case, water injectivity after CO2 injection was

higher than during the waterflood, thus enabling oil to be recovered more quickly.

Fig. (11) illustrates the comparison of actual miscible flood performance to that

predicted with a four-component compositional simulator. The Todd-Longstaff mixing

model[11] was used to account for viscous fingering, and phase behavior was

represented by a pseudoternary diagram. Two major empirically based physical

parameters, Sorm and a viscous-fingering parameter, were used to model local

displacement and sweep efficiencies. Sorm was based on laboratory displacement tests

using representative samples of reservoir rock and fluids. The first step in simulation

was to history match the waterflood. This enabled fine-tuning of the reservoir

description model. The compositional simulator was then used to calculate

performance of the miscible flood without further adjustment to any match parameters.

Fig. (11) – SACROC pattern area, performance, and simulator match. (From Healy, Holstein, and Batycky: “Status of Miscible Flooding Technology,” Proc., 14th World Petroleum Congress, Improved Recovery and Heavy Oil, 1994. © John Wiley & Sons Limited. Reproduced with permission.

As shown in Fig (11), the simulation of cumulative oil recovery vs. cumulative injection

for the miscible flood agrees reasonably well with actual field results. The produced

water/oil ratio from the simulation is also in reasonable agreement with field results.

Waterflood sweep efficiency was 74%, and the miscible flood sweep efficiency was

44%. These sweep efficiencies were determined from analysis of the simulation

studies.

http://petrowiki.org/CO2_miscible_flooding_case_studies#cite_note-r11-11

http://petrowiki.org/Compositional_simulation_of_miscible_processes


3.2 Means San Andres Unit

This field, located in the eastern edge of the Central Basin Platform of the Permian

Basin, produces primarily from the Permian-aged San Andres formation. It was

discovered in 1934; waterflooding began in 1963. The field was developed initially on

40-acre spacing and subsequently drilled to 20-acre spacing after the start of

waterflooding. The flooding pattern was first peripheral, then a three-to-one line drive,

and finally an inverted nine-spot that proved most efficient for this reservoir.

Reservoir characteristics are:

Porosity of 9%

Permeability of 20 md

Swi of 35%

Tr of 95°F

Net-to-gross ratio of 0.18

Oil gravity of 29°API

μoi of 6 cp.

An oil viscosity of 6 cp makes the waterflood mobility ratio relatively high. From

pressure cores and laboratory corefloods, waterflood residual oil saturation was

estimated to be 34% of pore volume. A CO2 miscible project was evaluated with

laboratory investigations, field pilots, and reservoir simulations. The pilot tests

indicated that CO2 could successfully mobilize the waterflood residual oil. Even though

it is difficult to determine the governing mechanisms for improved oil recovery, it

appears that after the initial direct displacement of oil by the solvent bank, lighter

components of the remaining oil are recovered by extraction.

The original CO2 project of 167 patterns on approximately 6,700 acres (which

contained 82% of OOIP) was expanded to 7,830 acres as evaluation of performance

indicated additional prospective areas. Factors affecting process design were:

Oil viscosity of 6 cp

High minimum miscibility pressure (MMP)

Low formation parting pressure that make operating pressure a critical

factor.

On the basis of the MMP estimation of 1,850 to 2,300 psi by slimtube experiments and

the formation parting pressure of approximately 2,800 psi, a 2,000-psi operating

pressure was selected.

Assessment of the economic viability of CO2 miscible flooding was based on pattern-

element simulations for representative project areas that were then used in a scaleup

program to forecast total project incremental recovery. A 2:1 water-alternating-gas

(WAG) ratio and primary CO2 slug size of 0.40 hydrocarbon pore volume (HCPV) were

selected as optimum. Updated simulations after gaining operating experience

indicated that a CO2 slug size of 0.60 HCPV was better.

http://petrowiki.org/Waterflooding

http://petrowiki.org/Reservoir_simulation


Results of the infill-drilling program and CO2 flood combined for a total unit oil

production increase from approximately 8,500 B/D in 1983 to approximately 16,000

B/D in 1987, as illustrated in 'Fig. (12) Much effort has been made to distinguish

between the contributions of infill drilling, improved waterflooding, and miscible

displacement.

Originally incremental oil recovery resulting from infill drilling was projected to be 5.3%

OOIP, while the incremental recovery resulting from CO2 flooding was to be 7.1%

OOIP. These recovery estimates have increased over time as a result of an

effectivereservoir management program. Current estimates of recovery resulting from

primary and waterflooding methods exceed 30% of OOIP, and incremental recovery

resulting from the miscible CO2 flood is more than 15% of the OOIP.

Fig (12) – Means San Andres miscible project performance

Utilization of new infill wells for injectors helped minimize downhole mechanical

problems. A continuous injection-well profiling program is maintained for flood-

management purposes. Increasing the WAG frequency minimized gas breakthrough

between some WAG injectors and offsetting producers experiencing rapid gas

breakthrough. While a detailed history-matching simulation of the test did not indicate

solvent channeling through known, high-permeability leached layers to be a problem,

all other indicators suggested otherwise. Dealing with leached pathways continues to

be a challenge. History matching also indicated some loss of CO2 into the basal water

zone.

Several production enhancements have improved field and miscible project

performance. First, a 360-acre, nine-pattern pilot was implemented in the North Dome

to evaluate the Lower San Andres (LSA) potential. Results showed that additional

reserves could be captured from this deeper horizon, although produced-water

volumes exceeded initial projections and limited near-term LSA development because

of facility constraints. Once water-handling issues were addressed, 59 additional wells

were deepened to the LSA in 1992. Performance of these wells provided more insight

into factors affecting reservoir performance and resulted in the deepening of an

http://petrowiki.org/Reservoir_management_programs


additional 81 injectors and producers and upgrading of facilities to handle more water

and gas.

Several different types of profile modifications were attempted throughout the 1990s.

Early foam and polymer treatments were discontinued because of limited, short-term

benefits. Preliminary results from a recent conformance program indicate the

possibility to mechanically isolate mature intervals and redirect CO2 into oil-bearing

intervals that would otherwise remain uncontacted.

The miscible project performance is exceeding previous recovery projections. To

better characterize the reservoir and improve business decisions for the asset, a

detailed geologic study incorporating engineering and geologic data was used to

provide the framework for 3D, three-phase reservoir simulation. Benefits of the study

include increasing original oil in place (OOIP) by 40%, identifying the potential in the

residual oil zone found below the observed oil/water contact in the LSA, and gaining a

better understanding of reservoir continuity using flow units identified with sequence

stratigraphy.

Future possibilities for the miscible project include:

Expanding the CO2-flood project on the basis of the geologic study

Continuing the mechanical-isolation program to maximize sweep efficiency

Fine tuning other programs such as varying WAG ratios to further optimize

flood performance and enhance profitability.

3.3 Denver Unit

The Wasson Denver Unit CO2 flood, started in 1983, is one of the larger industry

CO2 projects [28,000 acres, 2.1 BSTB (0.33 billion m3) OOIP]. No new wells were

drilled initially for this project; however, there was significant reconfiguration of the

inverted nine-spot patterns (20-acre well spacing) being used in the waterflood

preceding miscible injection. Unit performance is shown in Fig.(13) for the period

beginning with the waterflood through the first 19 years of miscible CO2 injection. The

reservoir was depressured from 3,200 to 2,200 psi to reduce the amount of trapped

CO2. Oil response occurred after approximately 6 to 8 months. Unit oil production rates

have been sustained since the start of CO2 injection as a result of response to miscible

injection and to the continuing efforts of reservoir management practices that identify

more patterns to miscible flood and ways to improve volumetric sweep with well

workovers and conversions. The first CO2 production occurred almost simultaneously

with incremental oil production.

http://petrowiki.org/Foams_for_conformance_improvement

http://petrowiki.org/Polymers_for_conformance_improvement

http://petrowiki.org/Conformance_improvement

http://petrowiki.org/Reservoir_simulation

http://petrowiki.org/Reservoir_management_programs


Fig (13) – Production performance of the Denver Unit miscible project.

There are uncertainties in the continued waterflood curve because of the usual

difficulties in estimating waterflood decline and additional uncertainties introduced as a

result of pattern reconfiguration and other modifications that may have affected future

waterflood performance as well as miscible recovery.

3.4 Water alternating gas ratio

Different WAG ratios were implemented in different areas of the field to determine the

most effective method. In the "Continuous Area," CO2 was injected continuously for

approximately 7 years, and then some patterns were converted to 1:1 WAG to reduce

CO2 producing rates. Oil rates were sustained after WAG started.

In the "WAG Area," HCPV injection rate was maintained at a level comparable to the

Continuous Area. The WAG ratio was approximately 1:1. Incremental production

response was poorer than in the Continuous Area, with a maximum of only about 17%

of the waterflood oil rate at the start of CO2 injection. In addition, there was about a

30% loss of water injectivity, and injection pressures exceeded fracturing pressure on

water cycles. The area was converted to a line drive in 1988.

As a result of the experience described above, a "Hybrid Process" was applied in a

final area of the field to capture the early response of continuous injection and the

long-term gas management of WAG. In this process, CO2 is injected continuously for 4

to 6 years, followed by 1:1 WAG, until a 60% (or larger) HCPV volume of CO2 is

injected. The final phase will be continuous water injection.

The project has performed well overall. There were a few problems in the western part

of the field, where the WAG process was used. Water injection at the desired rates

was difficult, and solvent was lost to the gas cap in a limited portion of the reservoir.

Neither of these was a complete surprise because the operator recognized both as


potential problems during the design phase of the project. The slug process used in

the eastern part of the field has performed well, and an increase in the CO2 slug size is

being considered.

A fully compositional, fieldwide simulation model is being used to match field and

individual-well performance. The simulator is then used to identify locations (which

may require infill drilling or horizontal wells) for project expansion, which wells to shut

in or return to production, where solvent losses are occurring, and needed changes in

WAG ratios. Opportunities for infill drilling and pattern conversion were implemented

and added several million barrels of recoverable oil.

The original estimated CO2 slug size of 0.4 to 0.6 HCPV has now been increased to

0.72%. The current estimated ultimate EOR is 16.7% OOIP. Continued improvements

in reservoir management may improve this outlook.


Chapter Four : Simulation strategy and scenarios: Three dimensional (3D) models were constructed in order to analyze WAG

behavior in a heterogeneous reservoir as shown in Figure 1. There were

applied different features of the heterogeneous reservoir in terms of

characterize rock properties (permeability, porosity, compressibility) and fluid

properties (viscosity, density) of a typical heterogeneous reservoir. The

compositional reservoir simulator (Eclipse 300) model was applying to

predict and monitor the effect of CO2 injection on field oil efficiency and the

reservoir behavior using five spot models involve four injectors (A,B,C,D

wells)and single producer (Well P) as illustrated in Figure (14).

Figure (14): FloViz visualization shows well


CO2 gas injection was set up to inject under reservoir condition and the wells

were located based on the five spot systems. In addition, WAG flooding was

performed on the same system in order to compare their results with the two CO2

flooding processes. The model consisted of four injectors and single producer

wells with 20x20x6 cells. The model included several low porous and permeable

layers of the hydrocarbon reservoir. The initial reservoir pressure was about 4000

psi at 5390 ft at temperature of 219 °C. The input porosity is ranged about 0.07 to

0.18 with changeable permeability according to X, Y and Z directions. In

addition, the model consists of seven numbers of comments (MC1, MC2, M C3,

MC4, MC5, CO2, and N2). The total injection and production period was about 20

and 40 years, and the other input data are listed in Table ( 1) .


Table1: Input parameters to study of the carbonate reservoir.

Parameter Value

No. of global cells 2400

(20x20x6)

Porosity 0.07 to 0.18

Permeability (x,y,z) [mD] 10 to 77

Initial Reservoir Pressure [Psia] 4000

Initial Oil Saturation 0.7

Initial Water Saturation 0.2

Depth [ft] 6109

Bottom Hole Pressure [Psia] 3000

Injection Rate

CO2 [MSCFD] 10

Water [STBD] 200

]3Density [lb/ftOil 49

]3Water Density [lb/ft 63

]3Density [lb/ft 2CO 0.117


The oil-wet characteristic is considered in this rock reservoir for fluid and rock

properties by the oil-water relative permeability curve as shown in Figure (15).

Figure (15)

There was assumed that the reservoir fluid involve oil, gas and water, but, without

free gas and solution gas. The gas existing in the reservoir represents only CO2

gas. When CO2 gas is injected into the reservoir, CO2 becomes immiscible with

oil at the first contact.


Chapter Five : Results and Discussion

It can be noticed that the field oil efficiency increased significantly during

miscible CO2 injection for a short period of time. Whereas, there is a moderated

increase during WAG injection for short period, because miscible CO2 helps the

oil as a pressure support to dissolve and expand, and then go through the reservoir

matrix and the production well. Figure 3 shows the effect of oil recovery with

respect to the amount of CO2 gas injected into the field. It can be clearly seen that

as CO2 miscible gas is injected into the reservoir, the efficiency of oil recovery

increases significantly. On the other hand, it is shown on Figure 3 that field oil

efficiency improved significantly during WAG injection for a long period of time.

Whereas, there is a moderated increase during miscible CO2 injection for a long

period of time. There is shown that the reservoir heterogeneity has a great effect

on the fluid recovery and reduces the sweep efficiency.

Figure(16): Field oil efficiency versus time (years).


override of the CO2 only recovering the attic oil .The added effect of CO2 gas

dropping through the lower layers due to gravity and thus creating a better

sweeping action can explain the improved efficiency achieved with high

permeability in the top layer. Comparison on the speed of frontal advance

showed that a faster advance will produce better oil recovery with amounts of

CO2 micsible injection, but results in the smaller overall efficiency as a lower

advance during immicible CO2 injection.

In addition, there is also noticed some unsweep zones during CO2 miscible

injection as a result of the unfavorable mobility ratio. CO2 flows through high

permeable zones and leaves low permeable zones (unsweep zones) because of

unfavorable mobility ratio. flows to the high permeable layers because of

unfavourable mobility ratio as shown in Figure (17).

Figure(17):Floviz visualization during miscible CO2 injection


Also, the low recovery records because of low density that can cause gravity

override of the CO2 only recovering the attic oil .The added effect of CO2 gas

dropping through the lower layers due to gravity and thus creating a better

sweeping action can explain the improved efficiency achieved with high

permeability in the top layer. Comparison on the speed of frontal advance

showed that a faster advance will produce better oil recovery with amounts of

CO2 micsible injection, but results in the smaller overall efficiency as a lower

advance during immicible CO2 injection.

Therefore, WAG injection is preferred to inject into carbonate reservoirs because

it reduces fingering. WAG injection controls mobility ratio that makes later time

breakthrough. CO2 injection has lower recovery effeciency compared to WAG

injection that is related to increasing visosity, controlling mobility ratio,

increasing desnsity as shown in Figure (18).

There is notiecd that the heterogeneity has a great effct on the flow of the

injection fluid as shown in Figure 1. However, the same rate of fluid injected at

the beginning but the fow will be higher in well A, B compared to well C, D. It is

noticed that thw wll C, D are more heterogeneous compared well A and B. In

addition, WAG has a greated pressure support and maintenace compared CO2

injection because it controls mobility ration and also increases water viscosity as

illustrated in Figure (18).


Figure (18) : Gas injection rate versus time (years).


Chapter Six : Conclusions and Recommendation for Further Work:

6.1 Conclusions:

1- WAG injection is a good candidate to recover oil in heterogeneous

reservoirs.

2- WAG injection has better recovery factor than miscible CO2 injection into

heterogeneous reservoirs for a long period of time.

3- WAG injection has lower recovery factor than miscible CO2 injection into

heterogeneous reservoirs for a short period of time.

4- Highest gas production total was recorded during miscible CO2 injection.

5- CO2 injection might cause physical and chemical trapping

6- WAG process can control sweep efficiency during CO2 injection, but it can

also react with the carbonate components.

6.2 Recommendation for Further Work

More studies should be considered in order to investigate the combined

mechanisms to maximize oil recovery factor. Further research should be done to

examine the effect of WAG injection with the aid of water even using other

chemical additives into the heterogeneous reservoirs.


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