Teesside University

Teesside University School of Science and Engineering MSc. Petroleum Engineering

Challenges of CO2 Injection in Middle East Carbonate Reservoirs An enhanced oil recovery technique in heterogeneous reservoirs

By: Nwaiche Jason Chinedu Supervisor: Dr Sina Gomari

A thesis submitted in partial fulfilment of the requirements for the award of Master of Science Degree in Petroleum Engineering

September 2015

SCHOOL OF SCIENCE AND ENGINEERING

DECLARATION OF ORIGINALITY This is to certify that the work is entirely my own and not of any other person, unless explicitly acknowledged (including citation of published and unpublished sources). The work has not previously been submitted in any form to the Teesside University or to any other institution for assessment for any other purpose.

Signed _________________________________________________

Date ___________________________________________________

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DEDICATION This project is dedicated to God Almighty and in memory of my lovely dad- Late Sir Jason Nwaiche.

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ABSTRACT The growing global campaign and awareness on global warming and climate change and ways of reducing the greenhouse gas emissions into the atmosphere has raised a lot of concern towards ways of possibly reducing the amount of carbon dioxide (CO2) which is a major contributor to global warming within the environment. Over the past few decades, the injection and trapping of carbon dioxide (CO2) gas into petroleum reservoirs like sandstones, shale and carbonates have become a globally accepted enhanced oil recovery technique and an efficient carbon storage process. Carbonate reservoirs have been studied to contain most of the world’s oil and gas, with the Middle East as one of the major zones dominated by carbonate formations. With carbonate reservoirs understood to have large volumes of oil, there still exist some challenges regarding the recovery of these oil from carbonate reservoirs due to their heterogeneous nature. Some of the challenges identified included early gas breakthrough due to viscous fingering effect of CO2, acid effect of carbonates when in contact with CO2 and reservoir brine, oil recovery challenges due to the effects of CO2 on the reservoir permeability, CO2 injection rates on oil recovery, injection effect of CO2 on oil viscosity and CO2 injection effect on the relative permeability of oil. This research has been carried out using a typical carbonate reservoir data from a Middle East field. A carbonate reservoir model was developed using Eclipse reservoir simulator software and based on some of the available field data, so as to investigate some of the challenging scenarios experienced in carbonate formations during CO2 injection and their effects on oil recovery factor from the reservoir. The developed eclipse model was set to run on a time-step of 10 years so as to predict the performance of the reservoir over time. Sensitivity studies on oil recovery factor was carried out to examine how changes in CO2 injection rate, CO2 density and reservoir oil density can affect the oil recovery from carbonate reservoirs and to know the most critical effect regarding oil recovery during CO2 flooding. The result shows that CO2 density has the most significant oil recovery at 17.05% followed by the CO2 injection rate with a recovery factor of 16.5% after 10years of production while the oil density has no influence on oil recovery during CO2 injection.

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TABLE OF CONTENTS DECLARATION OF ORIGINALITY ............................................................................. ii DEDICATION ................................................................................................................. iii ABSTRACT..................................................................................................................... iv TABLE OF CONTENTS.................................................................................................. v LIST OF FIGURES ....................................................................................................... viii LIST OF TABLES ............................................................................................................ x ACKNOWLEDGEMENTS ............................................................................................. xi ACRONYM TERMS ...................................................................................................... xii Chapter 1 INTRODUCTION............................................................................................ 1 1.1

Background ........................................................................................................ 2

1.2

Problem Identification and Justification ............................................................ 3

1.3

Dissertation Structure ......................................................................................... 4

1.4

Objectives of the Project .................................................................................... 5

Chapter 2 LITERATURE REVIEW ................................................................................. 6 2.1

Definition of Fundamental Reservoir and Fluid Parameters.............................. 7

2.1.1

Porosity ....................................................................................................... 7

2.1.2

Permeability ................................................................................................ 7

2.1.3

Fluid Saturation........................................................................................... 8

2.1.4

Interfacial Tension ...................................................................................... 9

2.1.5

Wettability ................................................................................................ 10

2.1.6

Relative Permeability ................................................................................ 12

2.1.7

Miscibility ................................................................................................. 13

2.1.8

Viscosity ................................................................................................... 14

2.2

General Overview and Description of Carbonate Reservoirs .......................... 15

2.2.1

Classification of Carbonate Reservoirs..................................................... 15

2.2.2

Carbonate Reservoir Characterization ...................................................... 17

2.2.3

Major Problems Associated with Carbonate Reservoirs .......................... 20

2.2.4

Mechanisms of Oil Recovery from Carbonate Reservoirs ....................... 22

2.3

Process of Oil Recovery from Reservoirs ........................................................ 23

2.3.1

Primary Recovery Stage ........................................................................... 23 v


2.3.2

Secondary Recovery Stage ....................................................................... 23

2.3.3

Tertiary Recovery Stage ........................................................................... 24

2.4

Current Enhanced Oil Recovery Methods ....................................................... 25

2.4.1

Thermal Enhanced Oil Recovery .............................................................. 26

2.4.2

Gas Injection Enhanced Oil Recovery ...................................................... 26

2.4.3

Chemical Injection Enhanced Oil Recovery ............................................. 27

2.4.4

Microbial Enhanced Oil Recovery (MEOR) ............................................ 27

2.5

EOR Screening Criteria.................................................................................... 28

2.5.1

EOR Screening Method ............................................................................ 29

2.5.2

MMP Estimation for CO2 Gas Injection ................................................... 29

2.6

Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) .................................... 32

2.6.1

General Overview of CO2-EOR ............................................................... 32

2.6.2

Application of CO2 Enhanced Oil Recovery in Carbonate Reservoirs .... 33

2.6.3

Mechanisms of CO2 Oil Recovery ........................................................... 35

2.6.4

CO2 Injection Techniques ......................................................................... 35

2.6.5

General Benefits of CO2-EOR ................................................................. 38

2.6.6

Some General Challenges of CO2-EOR .................................................. 38

2.7

Review of Current and Future CO2-EOR in the Middle East ......................... 40

2.7.1

Some Identified Challenges in Middle East Reservoirs ........................... 41

Chapter 3 METHODOLOGY ......................................................................................... 43 3.1

Reservoir Description....................................................................................... 44

3.1.1 Reservoir and Fluid Properties ....................................................................... 44 3.1.2 3.2

Modelling of Carbonate Reservoir Using Eclipse Simulator ........................... 47

3.2.1 3.3

Model Description .................................................................................... 46

Data Requirements for Eclipse Modelling of a Carbonate Reservoir ...... 48

Description of Scenarios Investigated .............................................................. 51

3.3.1

Base Case .................................................................................................. 51

3.3.2

Scenario 1a- Effect of CO2 Injection on Oil Recovery Factor ................. 52

3.3.3

Scenario 1b- Effect of CO2 Injection on Carbonate Reservoir Permeability 52

3.3.4

Scenario 2- Effects of CO2 Injection on Oil Relative Permeability ......... 53

3.3.5

Scenario 3- Viscosity effects of CO2 Injection Rates on Oil Viscosity .... 53

3.4

Sensitivity Analysis .......................................................................................... 54

Chapter 4 RESULTS AND DISCUSSION .................................................................... 55 vi


4.1

Results and Discussion ..................................................................................... 56

4.2

Effect of CO2 on Overall Oil Recovery Factor ............................................... 57

4.3

Effect of CO2 on Carbonate Reservoir Permeability ....................................... 58

4.4

Effect of CO2 on Relative Permeability .......................................................... 62

4.5

Sensitivity Analysis on Oil Recovery Factor ................................................... 64

4.5.1

Sensitivity on CO2 Injection Rates ........................................................... 65

4.5.2

Sensitivity on CO2 Density ...................................................................... 66

4.5.3

Sensitivity on Oil Density ......................................................................... 67

Chapter 5 CONCLUSIONS AND RECOMMENDATIONS ........................................ 68 5.1

Conclusions ...................................................................................................... 69

5.2

Recommendations ............................................................................................ 70

REFERENCES ............................................................................................................... 71 APPENDIX ..................................................................................................................... 76

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LIST OF FIGURES Figure 2. 1 Graphical method of estimating absolute permeability.................................. 8 Figure 2. 2 Surface tension existing between oil, water and reservoir surface ................ 9 Figure 2. 3 Wettability determinations by contact angle ................................................ 11 Figure 2. 4 A typical 2-phase relative permeability plot of a water-wet and oil-wet reservoir ....................................................................................................... 12 Figure 2. 5 Limestone composed of calcites from Tyrone, Pennsylvania ...................... 16 Figure 2. 6 Dolomite crystals from Penfield, New York ................................................ 16 Figure 2. 7 Middle East fractured carbonate rock from Ras Al Khaimah ...................... 18 Figure 2. 8 Different wettability scenarios experienced in hydrocarbon reservoirs ....... 21 Figure 2. 9 Stages of Oil recovery from a reservoir. ..................................................... 24 Figure 2. 10 Various techniques and classifications of oil recovery ............................ 25 Figure 2. 11 Summary of the general EOR selection criteria ......................................... 28 Figure 2. 12 Overview of the miscible CO2-EOR process ............................................. 32 Figure 2. 13 Slim-tube laboratory method for estimating MMP showing the effects of pressure on oil recovery. .............................................................................. 34 Figure 2. 14 Gantt chart showing the various CO2 injection techniques and plans ....... 37 Figure 2. 15 Middle East CO2 emissions from 1980 to 2005 ....................................... 40 Figure 2. 16 Some of the current and future EOR projects in the Middle East . ........... 41 Figure 2. 17 Summary of some technical challenges facing most Middle East countrie ...................................................................................................................... 42

Figure 3. 1 Oil PVT data of the modelled reservoir (Odeh, 1981) Figure 3. 2 Gas PVT Data of the modelled reservoir .................................................... 45

Figure 3. 3 Oil-Gas Relative permeability data modelled .............................................. 45 Figure 3. 4 Modelled reservoir grid definition and well locations ................................. 46 Figure 3. 5 Overview of the modelled reservoir at various saturations .......................... 47 Figure 3. 6 Designed project flowchart for CO2 modelling in Eclipse .......................... 48 Figure 3. 7 Reservoir modelling process using Eclipse .................................................. 49 Figure 3. 8 Modelled reservoir flowviz showing the location of wells and gas saturation ...................................................................................................................... 51 viii


Figure 3. 9 Model 2-phase relative permeability data used in base case model (Odeh, 1981) ............................................................................................................ 52

Figure 4. 1 Effect of CO2 on overall oil recovery factor ................................................ 57 Figure 4. 2 Effect of CO2 on the reservoir pressure........................................................ 58 Figure 4. 3 Oil recovery from low permeable (k=0.9) reservoir at 0%, 15%, 50% and 100% CO2 Injection rates............................................................................. 59 Figure 4. 4 Oil recovery from low permeable (k=12) reservoir at 0%, 15%, 50% and 100% CO2 Injection rates............................................................................. 60 Figure 4. 5 Oil recovery from low permeable (k=100) reservoir at 0%, 15%, 50% and 100% CO2 Injection rates............................................................................. 61 Figure 4. 6 Calculated relative permeability data using Corey’s equation applied in scenario 2 ..................................................................................................... 62 Figure 4. 7 Effect of CO2 on relative permeability in Base Case and Scenario 2 .......... 63 Figure 4. 8 Sensitivity of ±20% CO2 injection rate on Oil Recovery ............................. 65 Figure 4. 9 Sensitivity of ±20% CO2 gas density on oil recovery .................................. 66 Figure 4. 10 Sensitivity of ±20% oil density on oil recovery ......................................... 67

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LIST OF TABLES Table 2. 1 Wettability determination using Craig rule of thumb ................................... 11 Table 2. 2 Physical properties of some carbonate rocks ................................................. 17 Table 2. 3 Typical carbonate reservoir characteristics for CO2-EOR............................. 19 Table 2. 4 Screening criteria for Miscible or Immiscible CO2 Flooding………………29 Table 2. 5 Summary of the best-fit coefficients used in Eq. 2.13 for pure CO2 MMP ... 30 Table 2. 6 Summary of the best-fit coefficients used in Eq. 2.14 for impure CO2 MMP ...................................................................................................................... 31 Table 2. 7 Basic comparison of CO2-EOR Injection Options ....................................... 33 Table 3. 1 Reservoir of study with well properties ......................................................... 44 Table 3. 2 Sensitivity analysis (± 20%) values for investigated parameters .................. 54

Table 4. 1 Oil recovery factor (%) from ± 20% sensitivity analysis .............................. 64 Table 4. 2 Result of oil recovery volumes (bbls) for ± 20% sensitivity analysis ........... 64

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ACKNOWLEDGEMENTS I wish to once again express my gratitude to God Almighty for his grace and support throughout course of my programme and for the life and provisions he sustained me with. I cannot thank enough also my unique and adorable family for all your support; morally, financially and spiritually. Indeed I hold you all to a high esteem. To Teesside University, I cannot thank you enough for the provision of a sound academic and learning environment, mentoring, and support especially for the provision of the Schlumberger Eclipse and Petrel licenses that enabled this work to be done. To all the Library and Learning hub staff especially Mr. Anthony Flint, that were of great positive influence and support to me, I say thank you. I remain most grateful to you Dr. Sina Rezaei-Gomari, for in you I did not only find a supervisor for this study, I was also among those lucky to have you as a father, a mentor, a brother and a friend. Your advices, commitment, supports, encouragement and thorough supervision remain a part of me and made the positive difference in this research. I cannot thank you enough but in all I pray God grants you more wisdom and continues to uplift you into higher grounds. To my colleagues and mates especially Pavelly, Anthony, Nic, Anthonio, Jamil, Theo, Sophia, Clinton, Afam, Dubem and Bunmi, it was indeed an honour meeting you all and you made my short stay at Teesside University warm and memorable. I remember the days of our studying together, tutorials, vacations and lots more and in another world, I would still choose you all as friends, brothers and sisters because each one of you left a positive influence on me.

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ACRONYM TERMS : : Bg:

Gas density Porosity Gas formation volume factor

BHP: Bottom Hole Pressure CCS: Carbon Capture and Sequestration GHG: Green House Gases GOC: Gas Oil Contact E-100: Eclipse 100 Reservoir Simulator EOR: Enhanced Oil Recovery HCPV: Hydrocarbon pore volume IFT:

Interfacial tension

k:

Reservoir permeability

Kr:

Relative permeability

MMP: Minimum Miscibility Pressure OOIP: Original Oil in Place Sor

Residual oil saturation

WOC: Water Oil Contact :

Viscosity

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Chapter 1 INTRODUCTION

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1.1

Background

Carbon dioxide has been considered one of the challenging greenhouse gases (GHG) causing global warming in the world today (Reichle et al., 1999). Over the years, the storage of CO2 as a sequestration process (CCS) has however been considered as a viable technique not just for the reduction in the atmospheric concentration of CO2 gas, but also for enhanced oil recovery (EOR) in the petroleum and gas industry. Usually, these volumes of injected CO2 in the depleted oil and gas reservoirs or water aquifers, finds their way through an injector well down to the formation where they are either stored permanently or used to maintain depleted reservoir pressure to enhance the recovery of oil. However, the history of the use CO2 gas as an EOR technique dates back to the early 50’s when the early use of CO2 in carbonated water-flooding and oil recovery was carried out (McPherson et al., 2001). Ever since then, studies have been carried out and are still being carried out to investigate the best and most efficient but economical ways of sequestrating CO2 so as to be useful in oil recovery. Injecting CO2 into geological reservoirs like the carbonates, sandstones, shale and deep saline reservoirs have been applied in the following mechanisms that allow CO2 to displace initially saturated rock pores as a free gas or as a dissolved gas. These mechanisms are; hydrodynamic trapping, solubility trapping (Reichle et al., 1999) and mineral trapping (McPherson et al., 2001 and Goldberg et.al, 2001). Therefore suggesting that major CO2 storage can be ideally carried out in depleted oil and gas reservoirs. The Middle East region has been characterized mainly with carbonate reservoir formations and over the years have been seen as a major global oil producing area, which accounts for about a quarter of the entire global oil production total (Petroleum Economist Magazine, 2010 and Al-Mutairi, Menahi and Kokal, 2011). With this promising trend, there has been an increase in the availability of CO2 for EOR purposes in most Middle East countries thereby helping to reduce atmospheric concentration of GHGs in these affected areas. For example, in the United Arab Emirates (UAE), targets have been set to reduce the atmospheric CO2 by 14-15% with a view towards achieving that through CO2-EOR techniques (Canty, 2011).

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Although the global trend in the use of CO2 as an EOR technique continues to increase due to the ability of CO2 to recover about 60% or more of the original oil in place, there may be some challenges posed by this gas when injected into carbonate reservoirs. This however may be due to the heterogeneous nature of carbonate rock matrices and the tight pore distribution generally (Manaar, 2013). CO2 on its own has some other impending problems associated to its use in carbonate reservoirs and some of these problems may include: early gas breakthrough of the injected CO2 due to viscosity fingering and may lead to little or no oil recovery; corrosion related problems due to CO2 acid effects when in contact with fluids within drilled wells and the economic problems resulting from large volume of CO2 gas used in the EOR (Salman, Juma and Matrouk, 2007).

1.2

Problem Identification and Justification

The heterogeneous nature of most, if not all carbonate reservoirs have always been a problem in reservoir engineering and enhanced oil recovery. In order to investigate some of these challenges facing carbonate reservoirs, modelling a typical carbonate reservoir from the Middle East using a field development and production data is important so as to investigate some issues regarding oil recovery from carbonate reservoirs like carbonate reservoir permeability, reservoir wettability, CO2 injection rate, and the mechanisms of injection have all been considered in this research so as to identify the most challenging property facing carbonate reservoirs during CO2 injection for enhanced oil recovery; especially those located within the Middle East.

3


1.3

Dissertation Structure

This research project is structured in the following order; 

Chapter 1 highlights on the general background of enhanced oil recovery using gas injection technique in carbonate reservoirs. It also shows the structure of the research as well as the research objectives.



Chapter 2 provides a detailed overview of literatures on carbonate reservoirs; properties and types, carbon dioxide (CO2) injection into depleted reservoirs for enhanced oil recovery and some of the current EOR practises in the Middle East.



Chapter 3 provides detailed procedures involved in modelling a typical Middle East carbonate reservoir and the various data required for the simulation run. It also involved the scenarios modified so as to investigate effects of CO2-EOR on carbonates as well as the sensitivity analysis carried out on oil recovery factor.



Chapter 4 provides interpretation of the simulation results and discussions on scenarios modelled in Chapter 3 with critical and technical reasoning in comparison with some other previous and existing researches reviewed.



Chapter 5 highlights some of the conclusions drawn from the study and possible recommendations for subsequent researches on CO2-EOR in carbonate formations.

4


1.4

Objectives of the Project

The objectives of this project have been streamlined to: 1. Model a typical Middle East carbonate reservoir for CO2 injection using Schlumberger Eclipse (E-100) simulation software so as to have a clear understanding of the behaviour of the carbonate reservoirs to CO2 gas. 2. Investigate the effects of CO2 injection on carbonate reservoirs’ permeability and oil recovery. 3. Create scenarios to investigate the effects of CO2 on oil relative permeability in fractured reservoirs. 4. Investigate the effects of injecting CO2 gas at different concentrations on the reservoir oil viscosity. 5. Evaluate the reservoir performance at different scenarios and sensitivities to oil recovery factor in order to propose the best possible working scenario to be used for CO2-EOR projects in carbonate reservoirs.

5


Chapter 2 LITERATURE REVIEW

6


2.1

Definition of Fundamental Reservoir and Fluid Parameters

The flow of fluid in reservoir systems is one considered as flow through porous media and it is governed by the general Darcy’s law (Zolotukhin, 2000). In view of this principle, some of the fluid and reservoir properties controlling the general flow of oil, water and gas in a porous reservoir during CO2-EOR are discussed as follows; 2.1.1 Porosity Porosity is simply a reservoir property used in calculating the volume of pores located within reservoir geometry. It is mathematically expressed as the volume of pores in a reservoir over the total volume of the reservoir. This makes porosity a unit less parameter and thus express in percentage (%). Usually, the pore volume of a reservoir is saturated with fluids e.g. gas, oil and water at different levels of saturation (Selley, 1998 and Ahmed, 2010). Although there are many types of porosity, the general form of it is expressed mathematically as:

(eq. 2.1) When estimating the overall volume of fluid located within (i.e. fluid in place) a particular reservoir, porosity is considered a very important parameter. Porosity can exist in two (2) major forms within a reservoir and these are effective and absolute porosities. While effective porosity is simply the porosity ratio of the connected pores within a reservoir, the absolute porosity is however the porosity ratio of the total volume of pores against the overall rock volume as seen in eq.1 (Selley, 1998).

2.1.2 Permeability Permeability is also a very important reservoir parameter which describes the rate or ability of fluids to flow through a porous layer (i.e. network of connected pores). Permeability and porosity are usually directly proportional to each other (i.e. they can be affected by similar factors) (Zolotukhin, 2000). Permeability measurement is in milli-darcy (mD) or in darcy (D) and it is denoted by the letter ‘k’. Similar to porosity, the general form of permeability is known as the absolute permeability which is defined as the permeability of a reservoir at one fluid phase saturation and it is calculated mathematically from Darcy’s law in equation (2) (Ahmed, 2010): 7


(eq. 2.2) Another method for estimating absolute permeability of a reservoir is by plotting the rate of change of in a porous medium over pressure change. The slope of this graphical plot gives the estimation for absolute permeability Figure 2.1 (Tiab, 2012).

Figure 2. 1 Graphical method of estimating absolute permeability (Zolotukhin, 2000)

Generally, the proper definition and combination of porosity and permeability of any reservoir is very important in estimating the potential of a reservoir in terms of its overall fluid in place. 2.1.3 Fluid Saturation Fluid saturation is also an important reservoir property which expresses the proportion of gas, oil and water present within the pores of a reservoir. Similar to porosity and permeability, fluid saturation within a reservoir is also important in evaluating the reservoir potential. At any reservoir condition, the overall saturation of fluids is considered to be 100 percent and thus can be expressed mathematically as (Buckley and Leverett, 1942; Han and Batzle, 2004 and Komeev et. al., 2004); (eq. 2.3) (eq. 2.4) (eq. 2.5) (eq. 2.6) 8


Equation (3) is used to estimate the general form of fluid saturation for a three (3) phase fluid saturation in a reservoir comprising of gas saturation (Sg), oil saturation (So) and water saturation (Sw). Equations 4, 5 and 6 on the other hand are the simple forms of saturation for two (2) phase fluid saturations within a porous reservoir. According to Ezekwe (2010), the overall oil in place for a reservoir is a function of the fluid saturation, porosity, and reservoir volume and this is expressed mathematically as; (eq. 2.7) OR

Porosity * (

)

(eq. 2.8)

2.1.4 Interfacial Tension Between immiscible fluids and the reservoir rock surface, there exists a surface tension which tries to balance forces horizontally Figure 2.2.

Figure 2. 2 Surface tension existing between oil, water and reservoir surface (Willhite, 1986; Anderson, 1986)

Using Young’s equation (eq. 9), these forces can be balanced horizontally to give;

(eq. 2.9) The interfacial forces existing between the fluid phases present in the reservoir are denoted by

(oil and reservoir surface),

(water and reservoir surface) and 9


(oil and water). It is however important to note that fluid-to-fluid interfacial tension and contact angle can be measured while fluid-to-reservoir interfacial tension may not be measurable (Willhite, 1986). 2.1.5 Wettability Abdallah Wael et.al (1986), described wettability as the ability of a solid material (reservoir) having much preference for the fluid it is in contact with, over the ones it is not in contact with. According to Anderson (1987), wettability has been observed to affect relative permeability because wettability plays a key role in the location, migration and trapping of fluids within reservoirs.

Methods of Measuring Wettability There are a lot of methods used in determining the wettability of a reservoir or rock. According to Anderson (1986), methods for determining wettability can be categorized as either quantitative or qualitative. The quantitative methods include; -

Contact Angle Measurement

This is one of the widely used quantitative methods for determining reservoir wettability and is usually applied for variations in temperature, pressure and water chemistry inartificial reservoirs with pure fluids. For reservoirs to be classified as water-wet, contact angle ranges from 00 to 750. For neutrally-wet reservoirs, it is around 750 to 1200 and while for oil-wet cases, contact angle is measured around 1200 to 1800 (Anderson, 1986). Figure 2.3 tries to show the various contact angle variations for wettability measurement. Other forms of quantitative measurement of wettability includes; Amott, US Bureau of Mines (USBM), Electrical resistivity. On the other hand, the qualitative measurement of wettability involves methods such as relative permeability, recovery curves and flotation method. Another widely used method for determining wettability is the ‘Craig rule of thumb’ and is highlighted in Table 2.1.

10


Figure 2. 3 Wettability determinations by contact angle (Anderson, 1986)

Table 2. 1 Wettability determination using Craig rule of thumb (Satter, Iqbal, and Buchwalter, 2008) WATER-WET

OIL- WET

Connate Water Saturation

> 20%-25% PV

Saturation at which Kro = Krw Krw at maximum water saturation (i.e. at floodout)

> 50% PV of Water Saturation In general, 1400 ft

Depth (ft)

2.5.1 EOR Screening Method The benefits of EOR screening to petroleum engineers in order to make appropriate decisions as to the type of EOR technique to be applied, lies in the aim of optimizing the recovery of oil from reservoirs while achieving profit. Stalkup (1983) and Taber (1990) were both of the opinion that optimum profit in the application of EOR can be achieved with less volume (barrels) of injection fluids, producing one barrel (1bbl) of oil at reservoir conditions. After a global review of some EOR projects with emphasis on the successfully applied EOR projects, Taber, Martin and Seright (1997) in their studies came up with a screening criterion known as ‘Minimum Miscibility Pressure (MMP)’. Schlumberger (2015) defined it as ‘the lowest achievable pressure to which first or multiple-contact miscibility can be achieved (.i.e. it is the minimum miscible pressure at which the interfacial tension between two separate phase fluids is considered to be zero). 2.5.2 MMP Estimation for CO2 Gas Injection Yuan et.al (2005) developed the correlation for the estimation of MMP for CO2 gas injection into reservoirs using ‘quadratic fits of analytical MMP with temperature’. This correlation was developed from 70 analytical MMP data calculated with equation of state (EOS) characterization for 9 oils and 41 experimented slim-tube MMPs so as to account for prediction accuracy. 29


(

) (eq. 2.13)

Where MMPpure a1- a10 MC7+ PC2-6 T

= Estimated MMP from correlation of pure CO2 gas injection = Coefficients from a regression of the data = Molecular weight of C7+ = Total mole percent of C2-C6 composition in injected gas (%) = Temperature of the reservoir ( )

It is also important to note that the values of MC7+ and PC2-6 ranges from 139 - 319 and 2.0 – 40.3% respectively, while the reservoir temperature ranges from 71 - 300 (Bourdarot and Ghedan, 2011).

Table 2. 5 Summary of the best-fit coefficients used in Eq. 2.13 for pure CO2 MMP developed from (Bourdarot and Ghedan, 2011)

a1 = -1.4634E+03 a2 = 6.612E+00 a6 = 8.1661E+03

a3 = -4.4979E+01

a7 = -1.2258E-01 a8 = 1.2283E-03

a4 = 2.139E+00 a5 = 1.1667E-01 a9 = -4.0152E-06 a10 = -9.2577E+04

However, to account for impurities in the composition of the injected gas, which may be as a result of methane (CH4), ethane (C2H6) or hydrogen sulfide (H2S) contents in the CO2 gas stream due to inefficiency in separation and recycling, a new correlation was developed (Bourdarot and Ghedan, 2011) to account for only CO2 gas streams with up to 40% CH4 in it.

(eq. 2.14)

Where, m=

(

)

While the corresponding values of a1 to a10 are gotten from Table 2.5.

30


Table 2. 6 Summary of the best-fit coefficients used in Eq. 2.14 for impure CO2 MMP developed from (Bourdarot and Ghedan, 2011)

a1 = -6.5996E-02 a2 = -1.5246E-04 a3 = -1.3807E-03

a4 = 6.2384E-04 a5 = -6.7725E-07

a6 = -2.7344E-02

a9 = -3.1436E-11 a10 = -1.9566E-08

a7 = -2.6953E-06 a8 = 1.7279E-08

31


2.6

Carbon Dioxide Enhanced Oil Recovery (CO2-EOR)

2.6.1 General Overview of CO2-EOR CO2-EOR is a tertiary enhanced oil recovery technique which involves the use of CO 2 gas in in recovering hydrocarbon fluids (oil and gas) from reservoirs under a very high injection pressure. This is achieved by injecting the CO2 gas so as to get it in contact with the remaining oil in the reservoir ‘by increasing the reservoir volumetric oil sweep (Ev) and displacement (Ed) efficiencies respectively’ (Verma, 2015). In other to improve the recovery efficiency of the CO2-EOR process, often times the CO2 gas is injected alongside water and because CO2 is highly soluble in water, the both fluids are then injected in alternating order with the water primarily focused on increasing all swelling while the CO2 takes care of the oil viscosity reduction thereby making it easier for the reservoir oil to flow.

Figure 2. 12 Overview of the miscible CO2-EOR process (Verma, 2015)

However, at the point of recovery or production, not all the CO2 injected into the reservoir are recovered from the production zone as some of the injected volumes of CO2 finds themselves permanently stored in the reservoir (Perhsad et.al, 2012). By continuously injecting CO2 in the reservoir, the volume of saturated oil within the reservoir reduces as the CO2 gas saturation on the other hand increases. This has proven as one major way of sequestrating atmospheric CO2 concentration thereby using it to 32


improve oil recovery (Metz et.al, 2005). Injecting CO2 for EOR practise focuses primarily on the recovery of the residual oil saturation within a reservoir after primary production of the reservoir and secondary injection of water have been carried out with CO2 able to recover about 54% of the original oil in place within the reservoir (Ghedan, 2009). 2.6.2 Application of CO2 Enhanced Oil Recovery in Carbonate Reservoirs The application of CO2-EOR is usually carried out in two (2) options as either a miscible flooding option or an immiscible flooding option.

Table 2. 7 Basic comparison of CO2-EOR Injection Options (Andrei et. al, 2011) Miscible Option

Immiscible Option

Potential for Oil recovery

Less at (4 – 12)% OOIP

More at about 18% OOIP

Applied Project Scale

Small scale

Large scale

Oil production timing

Early (< 3years)

Late (> 5years)

EOR Duration

Short

Long

Mechanism of Oil recovery

Complex

Simple

Injection Period

Prior to water flood or Usually after water flood after

Storage potential of CO2



Low

High

Miscible Option

This one of the major CO2 injection options applied in carbonate reservoirs. It involves injecting the CO2 gas at pressure known as the minimum miscibility pressure (MMP). At this pressure, about 80% of the reservoir OOIP can be effectively produced when the injected CO2 gas breaks through (Holm and Josendal, 1974). However, recent developments in research surrounding CO2-EOR continues to show more recovery potentials existing for CO2-EOR projects and the conceptual rule of thumb being applied today (Yellig and Metcalfe, 1980) for estimating the minimum miscible pressure shows that injecting CO2 at about 1.2 HCPV, can recover as much as up to 90% OOIP this is true because at increased pressure; either through injected gas (CO2) or within the reservoir, oil recovery is also increased as seen in Figure 2.4. 33


Figure 2. 13 Slim-tube laboratory method for estimating MMP showing the effects of pressure on oil recovery (Yellig and Metcalfe, 1980)



Immiscible Option

Unlike the miscible option, the immiscible CO2 injection is often applied to reservoirs with heavier oil or when the reservoir pressure drops below the minimum miscibility pressure which makes it impossible for homogeneous mixing of the fluids due to the presence of interfacial tension between the oil and other fluids within the reservoir. In an immiscible CO2 process, part of the injected CO2 is absorbed into the reservoir fluids and part forms a free-gas phase in the reservoir.

34


2.6.3 Mechanisms of CO2 Oil Recovery For CO2 enhanced oil recovery efficiency, large volume of CO2 gas is initially injected into the reservoir which is usually about 30% and above of the HCPV (oil in place). At this high volume and injection, the following mechanisms have been observed and studied to enhance oil recovery (Taber, Martin and Seright, 1997): 

CO2 dissolves in the reservoir oil due to its solubility with oil and causes the oil to swell.



CO2 reduces the oil viscosity of the formation fluid.



CO2 reduces the existence of IFT between the oil and gas phases thereby encouraging miscibility.



CO2 attains miscibility with the reservoir oil at high pressure thereby enhancing the oil recovery.

2.6.4 CO2 Injection Techniques Injecting CO2 gas into reservoirs for oil recovery depends on a lot of factors. Some of these are the nature of the reservoir, the composition and properties of fluids in place within the reservoir, well location and pattern. Some of the basic CO2 injection techniques applied today include (Jarrell, 2002; Verma 2015): 

Continuous or Dry CO2 Injection Technique This injection technique makes use of the constant injection of only a known volume of CO2 gas into the reservoir. It may also be supplemented with the injection of lighter gases for gravity segregation effects. Continuous CO2 injection is most suitable for strong water-wet reservoirs and reservoirs having medium to light oil because the dry injected CO2 gas can help in gravity drainage thereby allowing for more oil to be recovered or drained.



Water Alternating Gas Injection Technique (WAG) This is usually considered as the conventional technique for injecting CO2 into most reservoirs because it involves an intermittent injection of gas and water which has a better sweep efficiency than other techniques. It is also beneficial because of its ability to overcome the effects of early gas breakthrough due 35


gravity fingering effect, thereby allowing for a better contact and sweeping of the residual oil within the reservoir. WAG is most suitable for reservoirs like carbonates that have varying vertical permeability. 

Continuous CO2 Injection Plus Water This technique is quite similar to the dry or continuous CO2 injection technique and the WAG, but here a fixed volume of CO2 gas is injected into the reservoir and after the known volume has been injected, a chase water is then injected to help the injected gas have a good sweep effect of oil when it comes in contact with the reservoir oil. Continuous CO2 plus water technique can be applied in slightly homogeneous and tight (low permeable) reservoirs like the shale.



Tapered Water Alternating Gas Injection Technique (Tapered WAG) Tapered WAG as a technique of injecting CO2 is comparable to WAG. It is primarily used to enhance the CO2 utilization and sweep efficiency at lower volumes of injected CO2 thereby limiting the volume of recycled CO2 into the reservoir. The CO2 utilization is thus described as the total volume of gas (CO2) needed to recover one barrel (1bbl) of oil from a reservoir.



WAG plus Gas This is simply a modified injection technique of the conventional WAG. Here, air, nitrogen or other inexpensive gases are injected after a large volume of CO2 and water has been injected at intervals. It is mainly used for improved sweeping and oil drainage in very tight formations.

36


Figure 2. 14 Gantt chart showing the various CO2 injection techniques and plans (Jarrel (2002)

37


2.6.5 General Benefits of CO2-EOR Although the application of CO2 injection for EOR purposes in carbonate reservoirs is not widely being used because of some economics regarding the cost of efficiently capturing CO2 or industrially generating CO2 for EOR purpose, there still exist some merits associated with this technique, especially in carbonate formations. According to Hughes (2006), some of these identified advantages include: 

The suitability of CO2 to be applied in a variety of reservoirs unlike other injected fluids.



CO2 can easily attain miscibility with reservoir oil at very low MMP, which is unlikely of other gases such as N2 and natural gases.



When injected together with water in a WAG technique, CO2 has a very high displacement efficiency on reservoir oil because it is soluble in water and helps make the oil denser through swelling while the water helps in residual oil contact drainage.



CO2-EOR helps in the reduction of the interfacial forces existing between the oil and water phases thereby increasing miscibility.



Unlike other fluids and gases, CO2 can be applied in reservoirs with heavy hydrocarbons (i.e. C15 to C30).



The application of CO2-EOR through injection of CO2 helps reduce global warming effects through reduction in atmospheric concentration of greenhouse gases.

2.6.6

Some General Challenges of CO2-EOR

Contrarily to the numerous advantages experienced in the CO2-EOR process, Salman, Juma and Al Matrouk (2007) were of the opinion that there exist some other challenges with regards to CO2 injection and its interaction with fluids within the reservoir. Some of these problems include: 

The huge economic demand for large volumes of CO2 to be injected in order to displace oil makes CO2-EOR a limited practise.



Early CO2 gas breakthrough, which is experienced mostly during dry gas injection, due to the fingering effect CO2 has on reservoir oil during injection.

38


When this is experienced, usually there is a reduction or complete drop in the volume of oil recovered from the reservoir. 

CO2 gas can possibly result in some flow assurance problems like corrosion of pipelines during transportation to the reservoir.



In carbonate reservoirs, injected CO2 when in contact with the formation brine can undergo a chemical reaction to form a carbonic acid which although helps in the fracturing of carbonate calcites, may afterwards migrate to block other permeable layers within the reservoir, thereby reducing their permeability and consequently affecting oil recovery negatively (Mohamed, He and Nasr, 2011).

39


2.7

Review of Current and Future CO2-EOR in the Middle East

There still exist some limitations towards the use of CO2 in the Middle East world, irrespective of the world’s largest volume of hydrocarbon located in the Middle East carbonate reservoirs. Although most Middle East countries are utilizing CO2 for other industrial purposes like in the food and beverage processing, pharmaceutical and chemical industries (Wright, 2007), resulting in high CO2 emissions from Middle East (Figure 2.14).

Figure 2. 15 Middle East CO2 emissions from 1980 to 2005 (Algharaib, 2013)

However, other countries within the Middle East such as Saudi Arabia, Qatar, Kuwait and UAE have all contributed to about $750 million towards cutting down on CO2 emissions from the area while the likes of Abu Dhabi (Ghawar), Turkey (Bati Raman) and UAE (Masdar) have all invested in current projects aimed at capturing CO2 from key emission sources and injecting it into reservoirs for EOR purposes (Figure 2.15), with future projects expected within areas like Oman, Iran, Qatar and Dubai (Algharaib, 2013; Manaar, 2013).

40


Figure 2. 16 Some of the current and future EOR projects in the Middle East (Manaar, 2013)

2.7.1 Some Identified Challenges in Middle East Reservoirs Technically, some of the identified problems associated with most Middle East reservoirs; which are characterized to be mostly carbonate formations include (Manaar, 2013): 

Middle East reservoirs are highly heterogeneous and contain mostly heavy oils which are found in carbonates.



Most carbonate reservoirs in the Middle East are fractured.



Most of their carbonate reservoirs experience complicated flow through their permeable layers (fractures).



The most dominant EOR techniques applied in the Middle East are the steam flooding, CO2 injection and miscible gas injections due to the gravity of oil and each of these techniques require a sound knowledge and comprehension of the fractured networks within the carbonate formations.



Fracture networks (permeability) within Middle East carbonates can vary greatly due to the injection and production techniques applied.

41




While the carbonate reservoir permeability may support some of the EOR processes like the steam injection by increasing the temperature of the reservoir oil, it does however hinder some other EOR techniques like the CO2 injection by leading to early gas breakthrough due to CO2 viscous fingering.

Figure 2. 17 Summary of some technical challenges facing most Middle East countries (Manaar, 2013)

42


Chapter 3 METHODOLOGY

43


3.1

Reservoir Description

3.1.1 Reservoir and Fluid Properties The reservoir of study is from an under-saturated Middle East carbonate field (Oheh, 1981). The reservoir description and some other properties are described in Table 3.1. Fluid properties including PVT data, relative permeability data are also highlighted in Figures 3.1, 3.2 and 3.3. However, modifications were made to these reservoir properties so at to properly ensure its effectiveness towards CO2 injection and was modelled using the Eclipse Blackoil Simulation software by Schlumberger Ltd. The initial problem of the reservoir involved the oil production from its pores and thus it was considered to be under-saturated (i.e. the reservoir pressure was observed to be greater than the oil bubble point). The reservoir was characterized to have three layers of varying permeability highlighting the heterogeneity of carbonate reservoirs.

Table 3. 1 Reservoir of study with well properties CARBONATE RESERVOIR PROPERTIES Reservoir Type

Carbonate

Parameters Original Pressure at Datum (8400ft) Minimum miscibility pressure Porosity Permeability Range (along X, Y and Z directions) Rock Compressibility Temperature Capillary pressure Wellbore Diameter CO2 Injection Rate Minimum Oil Production Rate Maximum Oil Production Rate Oil API O Gravity Gas Density Gas Specific Gravity Skin Initial oil saturation

Value 4800 1000 0.3 35 – 200 3.0x10-5 200 0 0.5 100 1000 20000 32.75 0.06054 0.792 0 0.88

44

Units psia psia mD psi-1 0 F ft MMSCF/D STB/D STB/D O (degrees) lb/ft3 -


Figure 3.1 Oil PVT Data of the modelled reservoir (Odeh, 1981)

Figure 3. 2 Gas PVT Data of the modelled reservoir

Figure 3. 3 Oil-Gas Relative permeability data modelled

45


3.1.2 Model Description

Figure 3. 4 Modelled reservoir grid definition and well locations The simulated reservoir was modelled using the Eclipse Cartesian gridding system to have 300 grids blocks distributed (as 10x10x3) along X, Y and Z directions respectively Figure 3.1. Two vertical wells (one injector and one producer) were developed in the model using the direct line injection pattern where the wells were directly situated opposite each other with the injector well located at grid (1, 1) and the producer well located at grid (1, 10). The reservoir depth was modelled at 8400ft having a pressure of 4200psia and the gasoil contact (GOC) and oil-water contact (OWC) were at 8200ft and 8500ft respectively. CO2 gas was then injected at the top layer of the reservoir at a BHP depth of 8335ft to allow the reservoir oil to swell and for the CO2 to sweep the oil towards the producer well, while the produced oil was from the bottom at a depth of 8400ft. The producer was modelled at a target production rate of 20000 STB/Day and a minimum bottom-hole pressure of 1000psi whereas the CO2 Injector well was modelled to constantly inject large volume of CO2 gas at 100000 Mscf/day so as to allow enough volume of gas to effectively sweep the oil to the producer. Figure 3.2 shows the various saturation profiles of the reservoir at initial conditions.

46


Figure 3. 5 Overview of the modelled reservoir at various saturations

3.2

Modelling of Carbonate Reservoir Using Eclipse Simulator

Schlumberger’s licensed reservoir simulator software known as Eclipse was chosen for the modelling part of this research work based on the software’s vast industrial use in major oil and gas companies in the world. It also consists of a user-friendly approach towards data computation, processing and human readable result prints which are also compatible with other reservoir modelling & description and data processing software like Petrel, CMG, and Microsoft Excel. Reservoir model was built as a black-oil model using Eclipse 100 (E-100). While some input parameters were provided by Odeh (1981), some other parameters like the pore size distribution, permeability, oil API gravity were modelled to depict a typical Middle East Carbonate reservoir. The modelling flowchart followed in the building of the carbonate reservoir model is described in Figure 3.3 alongside some of the data input steps using E-100 (Schlumberger, 2013).

47


Figure 3. 6 Designed project flowchart for CO2 modelling in Eclipse

3.2.1

Data Requirements for Eclipse Modelling of a Carbonate Reservoir

One of the important approaches towards building a good reservoir involves an understanding of the data collection process of a simulator because a good reservoir data can positively affect the outcome of the simulated model and may also be of economic importance towards cost (Satter et.al, 2008). The general input data required for building a reservoir varies a lot depending on the type and nature of formation to be modelled. Eclipse 100 uses a systematic approach for modelling as described in Figure 3.4. It involves building the reservoir models in eight (8) segments, viz; ‘Runspec, Grid, Edit, Props, Regions, Solutions, Summary and Schedule sections’.

48


Figure 3. 7 Reservoir modelling process using Eclipse



RUNSPEC This is usually the beginning section when building an Eclipse data file and it highlights features like the title of the model, dimensions of the grid blocks used in the model, the units of measurement, simulation run start date, the fluid phases present in the model, etc. Usually, as it is peculiar to eclipse data files, associated data of basic eclipse keywords are accompanied by a forward slash (/) which marks the end or termination of a specific keyword.



GRID This is the section of an Eclipse 100 simulation data input file that involves the definition of the reservoir geometric features like the porosity, permeability, netto-gross ratios (NTG) for the individual grid cells in the reservoir block model. Eclipse understands two (2) grid options, either the radial grid geometry or the Cartesian grid geometry and the choice of grid options affects the type and choice of keywords to be used in this Grid Section (Schlumberger, 2004).

49




EDIT This section of the input data file is primarily focused on commands for defining the pore volume, transmissibility, diffusivity and non-neighbour connections of the grid data entered in the Grid Section. It is also important to state that this Edit input section is an optional section in eclipse data compilation and thus can be automatically computed by eclipse during the running of the programme.



PROPS This section is primarily used for inputting the carbonate reservoir properties like relative permeability, pressure, compressibility, volume and temperature as well as basic fluid properties like the fluid viscosity, density. It is among the required or compulsory sections in eclipse data file.



REGIONS The regions section is an optional section in eclipse data file, but it is however important for models that have different relative permeability data.



SOLUTION This section is mainly used for the initialization of the model and equilibrating the data file prior to simulation. It is also a required section for eclipse data compilation.



SUMMARY The summary section though is an optional section, but is very useful in defining the expected result print and outputs from simulation runs that would be written to the report files.



SCHEDULE The schedule section is the last section in eclipse data file used in defining well properties like the well locations, the type of injection fluids, techniques of injection, injection rates, production fluid type, rate of production, and the duration of simulation run (time-step).

50


3.3

Description of Scenarios Investigated

3.3.1 Base Case By modifying the geologic field data from the described Middle East carbonate reservoir, a Base Case Model was developed for this study and ran using the Blackoil reservoir simulator Eclipse developed by Schlumberger Ltd. The base case was developed to have the reservoir produce at Primary recovery using its own natural energy and initial pressure of 4800psia by shutting the gas injector well located at grid (1,1) while oil is allowed to be produced from the producer well at a target rate of 20000 STB/Day from the grid (10,10). The base case model was also characterized to have an effective porosity of 30% (0.30) all over the reservoir while the Permeability in the X and Y directions were modelled at 200mD for the top layer (Z1), 80mD for the middle layer (Z2) and 35md for the bottom layer (Z3) as shown in Figure 3.5.

Figure 3. 8 Modelled reservoir flowviz showing the location of wells and gas saturation

51


Base Case Oil-Wet Relative Permability 1.2

Rlative Permeability, Kr

1 0.8 0.6 0.4 0.2 0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Sg Krg

Kro

Figure 3. 9 Model 2-phase relative permeability data used in base case model (Odeh, 1981)

3.3.2 Scenario 1a- Effect of CO2 Injection on Oil Recovery Factor In other to investigate the effect of the injected CO2 gas on the overall oil recovery rate from the reservoir, the base case model was modified to have CO2 injected at a 100% high volume rate of 100000MScf/Day, with the recovery factors of the base case and scenario 1a compared.

3.3.3 Scenario 1b- Effect of CO2 Injection on Carbonate Reservoir Permeability Due to the limitations of Eclipse simulator to estimate changes on rock permeability in its output files, the Scenario 1a was modified by altering the permeability near the producer wellbore to high permeability (100mD), average permeability (12mD) and low permeability (0.9mD) and also having CO2 gas injected at various pore-volume rates of 0%, 15%, 50% and 100% saturation into the carbonate reservoir. The outcome of this modification was termed ‘Scenario 1b’. This scenario was primarily developed to investigate the prevailing effects of rock permeability and CO2 injection rates on oil recovery thereby highlighting the resultant effects of CO2 injection rates on the carbonate reservoir permeability.

52


3.3.4 Scenario 2- Effects of CO2 Injection on Oil Relative Permeability Scenario 2 was developed by modifying the oil-wet relative permeability data initially used in the base case with a new relative permeability end point data from a CO 2 core flood experiment on low permeable carbonate reservoirs conducted by Chukwudeme and Hamouda (2009). A 2-Phase Relative permeability data for Scenario 2 was however developed using Corey’s Exponential equation (Eq. 3.3 and 3.4) and applying the end point relative permeability (Kro = 1.0 and Krg = 1.58) at 800C and 140bar from experiment by Chukwudeme and Hamouda (2009).

For Drainage relative permeability

(eq. 3.1)

For Imbibition relative permeability

(eq. 3.2)

(eq. 3.3)

[

]

(eq. 3.4)

This scenario was primarily developed to investigate the effects of injecting CO 2 gas at different volume rates and its resulting effects on the oil relative permeability (Kro).

3.3.5 Scenario 3- Viscosity effects of CO2 Injection Rates on Oil Viscosity To study the effects of CO2 and its various injection rates highlighted in scenario 2 on the oil viscosity, Scenario 3 was developed by using the new CO2 relative permeability data derived from the Corey’s correlation and implementing it into Scenario 1b by injecting CO2 at 0%, 15%, 50% and 100% saturations so as to study its effect on the reservoir oil viscosity and influence on oil recovery.

However, owing to these developed scenarios (Base, 1a, 1b, 2 and 3), a general oil recovery factor comparative analysis was carried out on each of the scenarios and the base case to investigate the overall effects of using CO2 gas as an EOR fluid. This analysis was followed by a sensitivity analysis on CO2 gas injection rates, carbonate 53


reservoir permeability, oil relative permeability and reservoir oil viscosity to find out the most and least effective parameter(s) that affects CO2-EOR most and which could be considered when planning and developing CO2-EOR projects for carbonate reservoir fields, especially in Middle East formations.

3.4

Sensitivity Analysis

In order to evaluate the impacts of positive and negative variations in CO2 injection rate, oil density and CO2 density on overall oil recovery, 20% sensitivity analysis was carried out on these parameters to determine how their changes can affect oil recovery from carbonate reservoirs. This yielded a low, base and high case for each of these parameters. Table 3.1 shows the various parameter values at ± 20%. Table 3. 2 Sensitivity analysis (± 20%) values for investigated parameters Parameter

Low

Base

High

CO2 Injection Rate

80000

100000

120000

MMSCF/Day

MMSCF/Day

MMSCF/Day

Oil Density

39.28

49.1

58.92

CO2 Density

0.04843

0.06054

0.07265

54


Chapter 4 RESULTS AND DISCUSSION

55


4.1

Results and Discussion

The estimation of reservoir original oil in place from the modelled reservoir properties like porosity, reservoir volume (area and depth) and residual oil saturation using Eq. 4.1 shows that at initial saturations, the reservoir of interest is saturated with hydrocarbon oil within its pore volumes of about 394,971,428 barrels.

Eq. 4.1

Where AArea of reservoir geometry (ft2) hDepth of reservoir (ft)

øSoi -

Reservoir porosity Residual or initial oil saturation

56


4.2

Effect of CO2 on Overall Oil Recovery Factor

The field oil recovery efficiency plot in Figure 4.1 clearly shows the effect of CO 2 gas injection on the overall oil recovery from the modelled carbonate reservoir over time period of 10 years. From this plot, the recovery factor of the base case producing at a primarily production rate after 10years is estimated at 4.8% of the OOIP and the results shown in Figure 4.1 while the effect of the same reservoir to recover oil after 10 years of injection of CO2 gas is estimated at 16% of the OOIP. The recovery factors for the other years of production are also highlighted on Table 4.2. The outcome of this result shows that the efficient injection of CO2 gas into a carbonate reservoir can be deployed successfully to enhance the recovery of oil from carbonate reservoirs by 11.2%. Although this recovery factor is in line with Canty’s findings (Canty, 2011), it however varies significantly from Sheng’s claim of oil recovery at around 35% of the OOIP. It is also important to highlight that this recovery did not take into cognisance of the reservoir permeability near the producer wellbore and the CO2 injection rates.

Figure 4. 1 Effect of CO2 on overall oil recovery factor

57


Furthermore, this effect is also reflected from the field pressure profile in Figure 4.2 which shows that the CO2 helps boost and maintain the formation pressure within the reservoir during production.

Figure 4. 2 Effect of CO2 on the reservoir pressure

4.3

Effect of CO2 on Carbonate Reservoir Permeability

The effects of the modelled carbonate reservoir permeability near the producer wellbore (grid 10, 10, 3) from 35mD to various permeability ranges is explained in Scenario 1b. From Figure 4.3; showing the oil recovery factor from the reservoir assuming it to have a very low permeability (k=0.9mD), averagely low permeability (k=12mD) and high permeability (k=100mD) near the producer wellbore respectively at 0%, 15%, 50% and 100% injection rates, the following can be deduced from Figure 4.3:

58


Figure 4. 3 Oil recovery from low permeable (k=0.9) reservoir at 0%, 15%, 50% and 100% CO2 Injection rates

At a very low permeability of less than 1mD, injecting CO2 at about 50% injection rate yields a better oil recovery (both economically and technically) compared to the other rates of injection; especially the optimal injection at 100% CO2 saturation. This is because of the possible effect of an early gas breakthrough in the 100% CO2 injection rate which occurred around 8years after injection compared to the other injection rates. The breakthrough was as a result of the viscous effect of CO2 (gas fingering) during a continuous dry gas injection at high rate into a reservoir with low permeability near the producer wellbore. This effect was observed for a tstep of 10 years. Another possible effect of the drop in oil recovery from the tight carbonate reservoir zone is as a result of the acid effect of the CO2 with carbonates (CaCO3) usually when in contact with formation brine (eq. 4.2). The reactiveness of CO2, brine and carbonates results in the formation of carbonic acid which helps in the dissolution of large chunks of calcites around the injector well but these dissolved calcites finds their way through the effective permeability within the reservoir away from the point of injection and towards the point of 59


exit (producer). By so doing, although a large volume of the CO2 has dissolved a fair enough volume of the carbonate reservoir permeability, this acidizing effect does not actually yield more oil from the producing well, suggesting claims to the findings of Mohamed, He and Nasr (2011) that permeability near the injector wellbore always increases due to the effect of carbonic acid on carbonate reservoirs which helps to improve their permeability, but with increased injection temperature and continuous injection, the dissolved calcites re-precipitates along other permeable paths within the reservoir leading to a reduction in carbonate reservoir permeability and a subsequent reduction in volume of oil produced.

Figure 4. 4 Oil recovery from low permeable (k=12) reservoir at 0%, 15%, 50% and 100% CO2 Injection rates

H2O + CO2 + CaCO3

Ca (HCO3)2

60

(eq. 4.2)


Figure 4. 5 Oil recovery from low permeable (k=100) reservoir at 0%, 15%, 50% and 100% CO2 Injection rates

Contrarily to the observed effects in Figure 4.3 at a low permeability, Figures 4.4 and 4.5 both shows that at an improved average permeability or a high permeability of carbonate reservoirs near the wellbore, oil recovery could be improved and which is directly proportional to the volume and injection rate of the displacing fluid (CO2) injected. With this outcome, acidizing or fracturing of the reservoir near the producer well can be applied under reviewed economic and technical basis to effectively and efficiently recover more hydrocarbon fluid in place with the carbonate reservoir irrespective of the volume of CO 2 gas injected. However, by comparing this oil recovery efficiency effect to the oil production rate in bbl/day for 10 years, injecting 100% CO2 into the reservoir having high permeability near the producer wellbore yielded about 16.8% of the OOIP but this is marred by an early gas breakthrough around 3 years after production started, causing the drop in oil production from 20000 bbl/day to 8000 bbl/day after 10 years (Figure 4.6). It could also be as a result of pressure drop due to the high rate of reservoir depletion. 61


4.4

Effect of CO2 on Relative Permeability

Scenario 2 Relative Permeability 1.400

Relative permeability, Kr

1.200 1.000 0.800 0.600 0.400 0.200 0.000 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Sg Krg

Kro

Figure 4. 6 Calculated relative permeability data using Corey’s equation applied in scenario 2

The outcome of Scenario 2 as shown in Figure 4.7 shows that increasing the saturation of the non-wetting phase (in this case SCO2), increases its relative permeability and therefore results in the reduction in saturation of the wetting fluid (oil) (drainage process); which is one of the primary reasons of EOR as found by Anderson (1986) and who also correlated wettability to relative permeability. Although this effect is observed due to the tertiary dry and continuous gas injection technique applied in the two scenarios. It is however important to note that in water-wet carbonate reservoirs, continuous dry gas injection could result in the higher relative permeability of the non-wetting phase (CO2) at increased saturation rates of the gas.

62

1


Figure 4. 7 Effect of CO2 on relative permeability in Base Case and Scenario 2

63


4.5

Sensitivity Analysis on Oil Recovery Factor

The outcome of the 20% sensitivity analysis on oil recovery factor as a factor of variations and changes in CO2 injection rates, CO2 density and reservoir oil density is highlighted on Table 4.1. The corresponding volume of oil recovered from the sensitivity analysis is also expressed in Table 4.2

Table 4. 1 Oil recovery factor (%) from ± 20% sensitivity analysis Recovery Factor (%) Parameter

Low

Base

High

CO2 Injection Rate

15.24

15.94

16.50

Oil Density

15.94

15.94

15.94

CO2 Density

14.63

15.94

17.05

Table 4. 2 Result of oil recovery volumes (bbls) for ± 20% sensitivity analysis Volume of recovered oil (bbl)

CO2 Injection Rate

CO2 Density

High (120%)

65170285.71

67342628.57 62958445.71

Base (100%)

62958445.71

62958445.71 62958445.71

Low (80%)

60193645.71

57784320

64

Oil Density

62958445.71


4.5.1 Sensitivity on CO2 Injection Rates

Figure 4. 8 Sensitivity of ±20% CO2 injection rate on Oil Recovery

At the Base case, injecting CO2 at 100000 MMSCF/Day has an oil recovery factor of 16% OOIP after 10 years of injection (Figure 4.8). However, by injecting the same CO2 gas at ±20% (i.e. 120000MMSCF/Day and 800000MMSCF/Day), Figure 4.8 shows no significant difference in oil recovery for the 3 injection rates after the first 6 years of injection, as all injection rates yielded a recovery factor of 7.5% OOIP. Afterwards, oil recovery increased with increase in CO2 injection rate and after 10years of production, the 20% increase in CO2 injection rate showed have the best yield in oil recovery. The significance of this sensitivity shows therefore that for economic reasons, injecting CO2 from the early stages of production at 80000MMSCF/Day may be advisable because the same volume of oil can be recovered from the reservoir even at 100000MMSCF/Day and 120000MMSCF/Day injection rates respectively.

65


The sensitivity also shows that for improved oil recovery, CO2 injection may be implemented after 6 years of production thereby improving the recovery of oil from 7.5% to 16.5% (over 100% OOIP).

4.5.2 Sensitivity on CO2 Density

Figure 4. 9 Sensitivity of ±20% CO2 gas density on oil recovery The outcome of the sensitivity of oil recovery due to the CO2 gas density shows (Fig. 4.9) that for 5 years of oil production, the injected CO2 density has no effect on oil recovery because the reservoir was still at an initial under-saturated state but as the reservoir oil is depleted, the effects of injecting CO2 gas is observed from 6 years of production. With the base case CO2 density at 0.06054 at 100000MMSCF/Day, oil recovery factor measured 14.63%. The importance of this sensitivity therefore highlights on the injection technique of the CO2 gas. Suggesting that possible water alternating gas (WAG) injection technique can be utilized instead of the dry gas injection in carbonate reservoirs so as to increase the density of the gas. Although injecting water alongside the gas should only be carried out

66


from 6 years of production as the reservoir approaches a saturated state as shown in Figure 4.9. 4.5.3 Sensitivity on Oil Density

Figure 4. 10 Sensitivity of ±20% oil density on oil recovery

The results of the sensitivity analysis carried out on oil recovery based on ±20% variations in oil density (figure 4.10) shows that increasing or decreasing the oil density has no actual effect on oil recovery as the three (3) cases show an equivalent oil recovery after 10 years of oil production. This shows that provided the reservoir oil and the injected CO2 gas are in a miscible stat volume of oil recovered irrespective of how dense or light the reservoir oil is, remains the same.

67


Chapter 5 CONCLUSIONS AND RECOMMENDATIONS

68


5.1

Conclusions

The following conclusions were drawn after carrying out this research; 

Applying CO2 injection in carbonate reservoirs, especially the oil-wet carbonates in Middle East is a good and positive EOR technique.



At miscible conditions, the sensitivity of CO2 injection rates proves the most influencing parameter on oil recovery from carbonate reservoirs.



The injections rates of CO2 can affect the recovery factor of a reservoir depending on its permeability variations near the production wells.



Relative permeability of CO2 gas in an oil-gas phase and the reservoir wettability are two (2) key properties that can affect the mobility of oil from carbonate reservoirs and its residual oil after secondary and tertiary production phases.



Direct dry gas injection of CO2 in carbonate reservoirs can lead to an early gas breakthrough due to CO2 viscous fingering on reservoir oil which results in reduction of the volume of oil recovered as well as flow assurance problem like corrosion of the pipeline.



Water alternating gas (WAG) injection technique can be applied alongside CO2 in the higher permeable zones within a carbonate reservoir than in low permeable (tight) zones so as to mitigate the impacts of viscous fingering, gravity settling and early gas breakthrough experienced during dry and continuous CO2 gas injection.

69


5.2

Recommendations

Based on the findings of this research, the following are recommended for future study; 

Compositional fluid properties should be considered when modelling CO2 injection for EOR in carbonate reservoirs using Eclipse 300.



Effects of temperature variations during CO2 injection should be considered for accurate evaluation of CO2 injection effects on oil viscosity.



To avoid early gas breakthrough and due to CO2 fingering, WAG should be applied for more porous and permeable reservoirs.



For oilfields with single injector and single producers, injecting CO2 at super critical rates should be considered for ultimate oil recovery instead of drilling more injector wells due to the economic implications of new wells.

70


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75


APPENDIX Estimated relative permeability values using Corey’s equation At Sg =1, So = 0 = (0.0) = 0 (

) [

]=

[

]=0

At Sg = 0.5, So= 0.5 = (0.5)4 = 0.0625 (

) [

]=

[

] = 0.1875

At Sg =0.15, So = 0.85 = (0.85) = 0.5220 (

) [

]=

[

] = 0.706

At Sg =0, So = 1 = (0.0) = 1 (

) [

]=

[

76

]=1


Base Case Eclipse Model Data File

77


78

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