a study of oxidation reaction kinetics during an air ...€¦ · table 4. 2 oil and cutting samples...

A STUDY OF OXIDATION REACTION KINETICS DURING AN

AIR INJECTION PROCESS

SHYAMOL CHANDRA DAS

A thesis submitted for the degree of Master of Engineering Science

Australian School of Petroleum Faculty of Engineering, Computer & Mathematical Science

The University of Adelaide Adelaide, Australia

April 2009

ii

To my mothers love which always encourages me

iii

TABLE OF CONTENTS

List of Tables vi

List of Figures vii

Nomenclature ix

Abstract x

Statement of Originality xii

Acknowledgements xiii

Paper, Reports & Poster from this Study xv

Chapter 1: INTRODUCTION 1 1.1 Background 1

1.2 Research Objectives 3

1.3 Overview of Chapters 4

Chapter 2: RESEARCH BACKGROUND 5

2.1 Overview of Air Injection 5

2.2 Why Air Injection? 7

2.3 Is Air Injection Simple Gas Flood? 7

2.4 Candidate Reservoir Screening 8

2.4.1 Field Screening 9

2.4.2 Laboratory Screening 9

2.5 Air Injection Field Performance 10

2.6 Air Injection in Australian Basins 11

2.7 Summary of Current Research on Air Injection 14

Chapter 3: THEORETICAL ASPECTS OF AIR INJECTION 15

3.1 Oxidation Reactions Associated with Air Injection 15

3.1.1 Low Temperature Oxidation 15

3.1.2 Pyrolysis 17

3.1.3 High Temperature Oxidation 17

3.2 Air Injection of Light Oil versus In-situ Combustion of Heavy Oil 18

3.3 Factors Affecting the Oxidation Behaviour of Crude Oil 20

iv

3.1.1 Composition of Crude Oil/SARA Fraction 20

3.3.2 Clays, Metallic Additives and Reservoir Rock Composition 22

3.3.3 Total Pressure /Oxygen Partial Pressure 23

3.3.4 Instrumental Test Condition 24

3.4 Reaction Kinetics 25

3.5 Kinetic Parameter from Thermogram 26

Chapter 4: EXPERIMENTAL TECHNIQUE AND APPARATUS 28

4.1 Physical Test Apparatus 28

4.2 Thermal Analysis Apparatus 30

4.2.1 Thermogravimetric Analysis 31

4.2.2 Differential Scanning Calorimetry 32

4.3 Thermal Analysis Test Conditions 35

4.4 Thermal Test Procedure 36

4.4.1 TGA Test 36

4.4.2 DSC Test 37

4.5 Instrument Calibration 38

4.5.1 TGA Calibration 38

4.5.2 DSC Calibration 39

4.6 Sample Description 43

4.6.1 Sample Assembly 43

4.6.2 Sample Preparation 44

Chapter 5: EXPERIMENTAL RESULTS 45 5.1 Physical Tests 45

5.1.1 Specific Gravity 45

5.1.2 Viscosity 45

5.1.3 Compositional Analysis 46

5.2 Thermal Tests 46

5.2.1 Kenmore Field 50

5.2.2 Field B 63

Chapter 6: ANALYSIS OF RESULTS AND DISCUSSIONS 76 6.1 Discussions on Physical Test Results 76

6.1.1 Specific Gravity & Viscosity 76

6.1.2 Compositional Analysis 76

v

6.2 Discussions on Thermal Test Results 77

6.2.1 Kenmore Oils 77

6.2.2 Oils of Field B 78

6.3 Kinetic Parameters 80

Chapter 7: CONCLUSIONS AND RECOMMENDATIONS 82

7.1 Conclusions 83

7.2 Recommendations 84

REFERENCES 86

vi

LIST OF TABLES

Table 2. 1 Reservoir Properties of Prospective Basins in Australia 12 Table 2. 2 Cooper-Eromanga Basin–Oil Reservoir Properties 13

Table 4. 1 Principal Thermo Analytical Methods 30

Table 4. 2 Oil and Cutting Samples 44

Table 5. 1 Specific Gravity and API-gravity 46

Table 5. 3 Thermal Tests Performed in this Study 49

Table 6. 1 Kinetic Parameters 81

vii

LIST OF FIGURES

Fig.2.1 Conceptual Representation of Air Injection Process 6

Fig. 3.1 Crude Oil Oxidation Regions 20

Fig. 4.1 Setup of Rheo meter Physica MCR 301 29

Fig. 4.2 Clarus 500 GC–MS Apparatus Setup 29

Fig. 4.3 Schematic Diagram of a TGA Furnace Assembly 31

Fig. 4.4 View of the TA 2950 Thermogravimetric Analyser 32

Fig. 4.5 Schematic Diagram of a Heat Flux DSC Cell 33

Fig. 4.6 View of the DSC 2920 (TA Instruments) 33

Fig. 4.7 View of the DSC 2920 with Pressure Cell 34

Fig. 4.8 View of the High Pressure Cell of DSC 2920 34

Fig. 4.9 Super Heated Result of Kenmore Oil #34 with Rock #34 36

Fig. 4.10 Temperature Calibration of TGA Instrument by Nickel 38

Fig. 4.11 Temperature Calibration of TGA by Alumel 39

Fig. 4.12 DSC Baseline of DSC−2920 at 4500kPa in Air Environment 40

Fig. 4.13 Temperature Calibration Result for PDSC 41

Fig. 4.14 Reproducibility of TGA and DTG curve 42

Fig. 4.15 Reproducibility of TGA and DTG curve 42

Fig. 4.16 Reproducibility of Heat-flow Curve 43

Fig. 5.1 Viscosity Temperature Profile of Kenmore Crude Oil 47

Fig. 5.2 Hydrocarbon Distribution of Kenmore Crude Oil 47

Fig. 5.3 Viscosity Temperature Profile of Field B Crude Oil 48

Fig. 5 4 Hydrocarbon Distribution of Crude Oil B 48

Fig. 5.5 TGA of Kenmore Cutting #31 in Air and N2 Environments 50

Fig. 5.6 PDSC of Kenmore Cutting in Air and O2 Environments 51

Fig. 5.7 TGA of Kenmore Oil #32 in Air and N2 Environments 52

Fig. 5.8 DSC of Kenmore Oil #32 in Air at Atmospheric Pressure 53

Fig. 5.9 PDSC of Kenmore Oil #32 in Air and O2 Environments 54

Fig. 5.10 TGA of Kenmore Oil #32 and Cutting #31 in Air Environment 55

Fig. 5.11 PDSC of Kenmore Oil #32 and Cutting #31 in Air and O2 56

Fig. 5.12 TGA of Kenmore Cutting #34 in Air and N2 Environments 57

viii

Fig. 5.13 PDSC of Kenmore Rock #34 in Air Environment 57

Fig. 5.14 TGA of Kenmore Oil #34 in Air and N2 Environments 58

Fig. 5.15 DSC of Kenmore Oil #34 in Air at Atmospheric Pressure 59

Fig. 5.16 PDSC of Kenmore Oil #34 in Air and O2 Environments 60

Fig. 5.17 TGA of Kenmore Oil #34 with Cutting #34 in Air and N2 61

Fig. 5.18 TGA of Kenmore Oil #34 with Cutting #34 in N2 Environment 61

Fig. 5.19 TGA of Kenmore Oil #34 with Cutting #34 in Air 62

Fig. 5.20 PDSC of Kenmore Oil #34 and Cutting #34 in Air and O2 63

Fig. 5.21 TGA of Cutting Samples of Field B in Air Environment 64

Fig. 5.22 PDSC of E#22 Rock Cutting in Air Environment 65

Fig. 5.23 TGA of E #13 Oil in Air and N2 Environments 66

Fig. 5.24 PDSC of E #13 in Air Environment 67

Fig. 5.25 TGA of E #13 Oil and Cutting E#22 in Air Environment 68

Fig. 5.26 TGA of W #3 Oil in Air and N2 Environments 69

Fig. 5.27 TGA of W #5 Oil in Air and N2 Environments 70

Fig. 5.28 DSC of W #3 Oil in Air Environment 71

Fig. 5.29 PDSC of W #5 in Air Environment 72

Fig. 5.30 Details of TGA of W #3 Oil in Air Environment 73

Fig. 5.31 TGA of W #3 Oil and Cutting E#22 in Air Environment 73

Fig. 5.32 TGA of W #5 Oil and Cutting E#22 in Air Environment 74

Fig. 5.33 PDSC of W #3 with Rock Cuttings in Air Environment 75

Fig. 5.34 PDSC of W #5 with Rock Cuttings in Air Environment 75

ix

NOMENCLATURE

Abbreviations API – American Petroleum Indication

ARC – Accelerating Rate Calorimetry

DTA – Differential Thermal Analysis

DTG – Derivative Thermogravimetry

EGA – Evolved Gas Analysis

EOR – Enhanced Oil Recovery

GC – Gas Chromatography

HC – Hydrocarbon

HPAI – High Pressure Air Injection

HTC – High Temperature Combustion

IOR – Improved Oil Recovery

ISC – In situ Combustion

LTO – Low Temperature Oxidation

NTGR – Negative Temperature Gradient Region

PDSC – Pressurised Differential Scanning Calorimetry

RTO – Ramped Temperature Oxidation

SARA – Saturates, Resins, Aromatics, Asphaltenes

TG/TGA – Thermogravimetry/Thermogravimetric Analysis

Symbols α – fractional weight change of the sample = (w0-wt)/(w0-w∞)

β – Heating rate

E – activation energy of reaction

H – enthalpy to be released

k – specific reaction rate

R – universal gas constant

T – temperature

t – time

w∞ – final sample weight

w0 – initial sample weight

wt – sample weight at ‘t’

∆t – time interval

m, n – reaction order

x

ABSTRACT

Air injection is an enhanced oil recovery (EOR) process in which compressed air is

injected into a high temperature, light-oil reservoir. The oxygen in injected air is intended

to react with a fraction of reservoir oil at elevated temperature resulting in in-situ

generation of flue gases and steam, which, in turn, mobilize and drive the oil ahead

towards the producing wells. To understand and determine the feasibility of the air

injection process application to a given reservoir, it is necessary to understand the

oxidation behaviour of the crude oil.

The aim of this study is to screen two Australian light-oil reservoirs; Kenmore Oilfield,

Eromanga Basin, and another Australian onshore oil and gas field “B”* for air injection

EOR process, and to understand the oxidation reaction kinetics during air injection. It is

carried out by the thermogravimetric and differential scanning calorimetric (TGA/DSC)

studies to investigate the oxidation mechanism during an air injection process. There

has not been any TGA/DSC evaluation conducted to date with regard to air injection for

Australian light-oil reservoirs.

A series of thermal tests was performed to investigate the oxidation behaviour of two

selected reservoirs in both air and oxygen environments. The first step undertaken in

this study is thermogravimetric and calorimetric characterization of crude oils to (i)

identify the temperature range over which the oil reacts with oxygen, (ii) examine the

oxidation behaviour within the temperature identified, and (iii) evaluate the mass loss

characteristics during the oxidation. This study also examines the effect of pressure on

oxidation at different temperature ranges and the effect of core material (rock cutting) on

oxidation reactions. Finally, kinetic data are calculated from thermal tests results by

literature described method.

Kenmore and Field B both are high temperature and light-oil reservoirs. Hydrocarbon

distribution indicates that Kenmore oil contains 84 mole% of lower carbon number n-C5

n-C13 compounds. Reservoir B oil also contains a substantial amount (i.e., 95 mole %)

of lower carbon number n-C4 C19 compounds. These lighter components may

contribute favourably towards efficient oxidation. However, a high content of lighter ends

in the oil may also result in a lower fuel load. Generally, low molecular weight oil gives

fastest mass loss from heavy crude oil.

xi

Thermal tests on Kenmore oil showed two distinct exothermic reactivity regions in

temperatures of 200-340°C and 360-450°C, with a 85-95% mass loss when the

temperature reached 450°C. Reservoir B oil showed a wider exotherm range between

approximately 180°C-260°C with 90-95% mass loss by temperature 350°C. In the high

temperature range, the combustion reactions of Reservoir B oil are weaker than

Kenmore oil. This is due to insufficient fuel available for oxidations in high temperature

region. Reservoir B oil has more chance to auto ignite; but it has less sustainability to

the ignition process. Based on the sustainability study of the ignition process, between

the two reservoirs, Kenmore is the better candidate for air injection.

Based on the thermal tests, it is concluded that for light-oil oxidation, vaporization is the

dominant physical phenomenon. At low temperature range, the addition of the core

material enhanced the exothermic reactions of the oil. The elevated pressure

accelerated the bond scission reactions. The largest amount and highest rate of energy

generation occurred at the low temperature range. Activation energies (E) are calculated

from thermal test results and the value of ‘E’ in oil-with-core combined tests is smaller

than the oil-only test. This indicates that the rock material has a positive impact on the

combustion process. Moreover, the compositional analysis result addresses the

composition of oils, which can help understand the oxidation behaviour of light-oils.

* For confidentiality reasons, the field name is coded as Field B at the request of the operating company.

xii

STATEMENT OF ORIGINALITY

This work contains no material which has been accepted for the award of any other

degree or diploma in any university or other tertiary institution and, to the best of my

knowledge and belief, contains no material previously published or written by another

person, except where due reference has been made in the text.

I give consent to this copy of my thesis, when deposited in the University Library, being

made available for loan and photocopying, subject to the provisions of the Copyright Act

1968.

I also give permission for the digital version of my thesis to be made available on the

web, via the University’s digital research repository, the Library catalogue, the

Australasian Digital Theses Program (ADTP) and also through web search engines,

unless permission has been granted by the University to restrict access for a period of

time.

Shyamol Chandra Das

April 2009

xiii

ACKNOWLEDGEMENTS

The most important thing that must be said about working on this research project is that

it has been one of the most rewarding experiences of my life. It has given me the

opportunity to meet many wonderful people who have provided me much-appreciated

support during my study. For this they deserve the following acknowledgement.

My faith in academia is greatly increased by my supervisor Professor Hemanta Sarma. I

gratefully acknowledge the continuous support, technical advice and guidance I have

received from him during this study. His professionalism and responsibility always

inspired me to work promptly. Also, I have received continuous moral support and

individual non-academic advice from him in which I had the opportunity to ask him at

any time. I could not ask for better supervisors.

For the financial support, I thank the Australian School of Petroleum; The University of

Adelaide provided me the SANTOS scholarship. I would like to thank Beach Petroleum

Limited and Santos Limited for their support during this study, as well as Mark Pitkin and

Sarah McDonnell for their advice and technical assistance.

I recognize the laboratory support of Dr. Milena Ginic-Markovic and Dr. Rachel Pillar,

School of Chemistry, Physics and Earth Sciences, Flinders University for their

assistance in performing the thermal analyses of this work.

Further, I deeply appreciate my fellow researchers for their entertaining discussions and

encouragement as well the assistance I have received in different tasks throughout the

project. Here I must mention two names Prasant Jadhawar and Saju Menacherry for

their great support during the course of work, especially in writing period, also thanks to

all at third floor multicultural and serious researchers.

All the staff at the ASP, I would rather not mention any name in particular because it has

been a wonderful relationship with everyone and I am thankful for their support towards

the completion of this work.

Research is never an easy task. I am very grateful to my parents who since an early age

guided me through life. Special credit towards the completion of this thesis goes to my

xiv

mother and my family for their patience and encouragement; also I would like to thank

my brothers for putting up with me for higher goals.

Finally, my deepest thanks extended to my friend Naseem, who always inspired

motivation and excellence in any work undertaken for achieving my goals, and that I

have to admire her.

xv

PAPER, REPORTS & POSTER FROM THIS STUDY

Sarma H. and Das S., 2009. “Air Injection Potential in Kenmore Oilfield in Eromanga

Basin, Australia: A Screening Study Through Thermogravimetric and Calorimetric

Analyses”, Paper SPE-120595 presented at the 16th SPE Middle East Oil & Gas Show

and Conference; Bahrain International Exhibition Centre, Kingdom of Bahrain, 15-18

March.

Das S. and Sarma H., 2008. “Screening of Selected Australian Reservoirs for Air

Injection Process Candidate Reservoir: Kenmore Oilfield, Eromanga Basin”, report

submitted to Beach Petroleum Limited, June 5.

Das S., and Sarma H., 2008. “Screening Study of Field B for Air Injection Process”,

report submitted to Santos Limited, November 15.

Das S. 2008. “Burn and Earn: Air Injection EOR Technique for Australian Light-Oil

Reservoirs”, poster presented at the AIE National Postgraduate Student Energy Awards,

Sydney, Australia, November 18.

1

Chapter 1 INTRODUCTION

This chapter presents an overview of the research undertaken by this study, and then

the research objectives. Thesis organization in the form of chapters is also briefly

described in a later section.

1.1 Background Demand for energy is increasing throughout the world at a rapid rate due to industrial

development and population growth. This trend of increasing oil demand calls for new

additions to the known reserves and hence prompts more emphasis on the application

of the variety of Enhanced Oil Recovery (EOR) methods to mature and depleted

reservoirs. It is generally accepted that nearly two-thirds of the original oil-in-place

remains in the subsurface reservoirs after primary and secondary recovery processes.

The application of new methods of oil recovery has intensified due to the increasing

demand.

Air injection into light-oil reservoir has been regarded as an alternative EOR method for

both secondary and tertiary recovery processes (Adetunji et al., 2005; Fassihi et al.,

1983; Fassihi et al., 1996b; Fraim et al., 1997; Gutierrez et al., 2007; Hughes and

Sarma, 2006; Kumar et al., 2007; Moore et al., 2002; Ren et al., 2002). A number of air

injection projects for light oil have been reported in the literature since 1980 however,

the commercial projects are operated only in North America (Takabayashi et al., 2008).

The currently active and successful air injection projects are operated in the Williston

Basin in South and North Dakota. Other air injection projects are being considered

worldwide, such as in Indonesia (Clara et al., 2000), North Sea (Greaves et al., 1996),

and Argentina (Adetunji et al., 2005).

Air injection is an emerging enhanced oil recovery technique for low-permeability, high-

temperature (>70°C), and light-oil (>35° API) reservoirs. The success of this process

depends on the consumption of oxygen in injected air. This consumption of oxygen is

occurred by the oxidation reactions with the reservoir oil resulting in in-situ generation of

flue gases and steam, which, in turn, mobilize and drive the oil ahead towards the

Chapter 1: Introduction

2

producing wells. Thus, the energy required for the air injection process to work comes

from and within the reservoir itself with a typical 5-10% consumption of the reservoir-oil

during oxidation. This generated flue gas can be immiscible, partially miscible, or

completely miscible depending on the oil composition and reservoir temperature and

pressure.

There is some disagreement about the mechanism of air injection for light-oils. Some

researchers compare air injection with gas injection. Ren and Greaves (2002), pointed

out that air injection in light-oil reservoirs could be viewed as a conventional gas

injection process, as long as the oxygen in the injected air was removed efficiently in the

oil formation. The other analysis, Moore et al. (2002) have addressed different oxidation

behaviours of light-oil at different temperature intervals. The feasibility of the air injection

process depends on oxidation behaviour of reservoir oil, which is necessary to fully

understand this oxidation process for air injection technique’s development.

In recent years, thermal analysis techniques, such as thermogravimetric analysis (TG)

and differential scanning calorimetry (DSC) tests have been widely used to characterise

thermal behaviour and kinetics of crude oils (Bae, 1977; Drici and Vossoughi, 1985;

Ferguson et al., 2003; Kharrat and Vossoughi, 1985; Kok, 2002; Kok et al., 1997; Kok

and Keskin, 2001; Sarma et al., 2002; Verkoczy and Jha, 1986; Vossoughi et al., 1983).

The principal role of thermal analysis techniques is to provide information on the

oxidation behaviour of crude oil. In the literature, two successive oxidation reaction

regions are recognized from thermogravimetric and heat flow information of oils. The

lack of understanding of the physical and chemical mechanism of crude oil during

oxidation has hindered prediction and design of air injection projects.

The feasibility of the air injection technique primarily depends on the oxidation

characteristics of the candidate reservoir oil, e.g. the sustainability of the ignition front

during the course of the process. To understand and determine the feasibility of its

application to a given reservoir, it is necessary to understand the oxidation behaviour of

the crude oil. The oxidation behaviour of a given oil is reservoir specific, and no

screening guides have yet been published which predict the oxidation characteristic of a

specific reservoir. Therefore, extensive laboratory investigations are required to

ascertain reaction characteristics of the specific crude oil before any field application is

implemented.


3

Most of the combustion studies have been performed using heavy oils so discussion of

light oil oxidation behaviour is limited. Additionally, very limited kinetic data are available

in the petroleum literature on the rates and the nature of the oxidation reactions. The

high temperature combustion reactions of Australian light-oil reservoirs for air injection

are another concern. The present research is designed to alleviate the above gaps in

the literature and establish the kinetics data during the oxidation reactions on the

Australian light oil reservoirs.

1.2 Research Objectives The ultimate goal of the research is to understand the oxidation kinetics mechanism

during air injection and hence accurately and more realistically predict the performance

of the air injection technique. Thermogravimetric analyser and differential scanning

calorimeter experimental methods were carried out to investigate the combustion

mechanism during an air injection process. The objectives of the research are as

follows:

• Examine the temperature range and mass loss characteristics of selected

reservoir crude oil during oxidation reactions in air injection process. This helps

to predict the reaction temperature and find out the fraction of the crude oil that is

responsible for the reactivity. Mass loss characteristics determine the potentiality

of the air injection process.

• Evaluate the oxidation behaviour of crude oil at different pressure conditions.

This information is useful to investigate the reservoir crude oil properties by

pressure effects in the combustion process.

• Study the effect of reservoir rock on the crude oil oxidation behaviour then

provide the basis to develop the reservoir screening criteria for application of the

air injection process.

• Develop kinetic model parameters such as: order of reaction and the Arrhenius

rate constant for better simulation to predict the reservoir performance during air

injection.

Thus, the current study is a basic step towards reliable predictions for air injection

applications in Australian light-oil reservoirs, which in this study address the gaps in the


4

literature with regard to air injection laboratory data for Australian light-oil reservoirs

specifically Kenmore Oilfield and Field ‘B’ (an onshore oil and gas field).

1.3 Overview of Chapters Chapter 2 outlines the literature, which is available-including air injection fundamentals,

design consideration and screening criteria, and field application of air injection.

According to the available literature and the limited information of oxidation kinetics

during air injection, Chapter 2 discussed the relevance of the current study. Chapter 3

explains the oxidation behaviour of heavy and light oils, thermal analysis studies to

investigate the oxidation character and the factors that affect oxidation behaviour of

crude oil. Chapter 4 describes the experimental apparatus and their protocol used in

oxidation kinetics study to carry out this research, with justification for the experimental

conditions. Chapter 5 presents the results of the experiments performed in this work.

Chapter 6 provides the results and discussion of the effects of different parameters on

the thermal behaviour of the sample crude oils and rock cuttings. The summary of the

results and related conclusions from this research work is presented in Chapter 7.

Recommendations are also outlined for future research.

5

Chapter 2 Research Background

This chapter provides the research background information and detailed literature

survey required to understand the basis of this study. The air injection fundamentals,

overview of the process and necessary design consideration for implementation of the

process in the reservoir of interest is presented. The difference between air injection and

gasflood is discussed. Finally, this chapter reviews the field application of air injection

and its prospect in Australian light-oil reservoirs.

In recent years air injection has received much interest and a number of research

projects in light oil reservoirs have been documented in the literature (Adetunji et al.,

2005b; Clara et al., 2000; Fassihi and Gillham, 1993; Fassihi et al., 1996a; Fassihi et al.,

1997; Fraim et al., 1997; Gillham et al., 1998; Greaves et al., 2000; Gutierrez et al.,

2007; Kumar et al., 1995; Kumar et al., 2007; Moore et al., 2002; Ren et al., 2002;

Sarma et al., 2002; Turta and Singhal, 2001; Yannimaras and Tiffin, 1995). The

feasibility of the air injection process primarily depends on the oxidation characteristics

of the candidate reservoir oil and the sustainability of the ignition front during the

recovery process.

2.1 Overview of Air Injection In the air injection process, high-pressure air is injected into a reservoir to promote in-

situ oxidation of oil. The oxygen in the injected air reacts with a portion of crude oil.

When oxidation occur the reservoir temperature near the air-oil contact rises and

eventually, the oil ignites resulting in the in-situ generation of flue gases and steam. A

conceptual representation of the air injection process is described in Fig. 2.1. The

resulting flue gas mixture, which is primarily CO2 and nitrogen, provides the mobilizing

force that drives oil to the producing wells through a combination of several complex

mechanisms. Displacement, dissolution, oil swelling, wettability alteration and re-

pressurization are significant incremental recovery mechanisms (Clara et al., 2000;

Greaves et al., 1996; Hughes and Sarma, 2006; Turta and Singhal, 2001). However, in

Chapter 2: Research Background

6

the later stages of this process the thermal effect is expected to contribute more to the

oil production by way of oil-viscosity reduction.

Fig. 2.1–Conceptual Representation of Air Injection Process

During oxidation, both oxygen-addition and bond-scission reactions take place (Clara et

al., 2000; Moore et al., 2002). Oxygen addition reactions are believed to occur at the

lower temperature and these reactions are characterized by heavier oxygenated-

hydrocarbon products. Typically, the bond-scission reactions occur at higher

temperatures (Moore et al., 2002). In order to improve the efficiency of an air injection

process, it is necessary to have the knowledge of factors influencing the oxidation

process. The consumption of O2 in air is essential to the success of the process for it

prevents any undesirable microbial activities and minimizes operational risks of fire in

production wells and surface facilities (Hughes and Sarma, 2006).


7

2.2 Why Air Injection? Based on empirical data from field applications to date, the following arguments can be

made in favour of the air injection process:

• Air is universally abundant, and hence, does not pose any supply constraints

• The existing infrastructure can often be utilized (Fassihi et al., 1997)

• Superior injectivity of air in comparison with water (Kumar et al., 2008)

• Faster re-pressurization than with water, due to air compressibility

• Significant cost benefits as an alternative to other gas injectants; CO2, HC gas

and N2

• Technical and economic success in all projects to date (Fassihi et al., 1996b;

Kumar et al., 2008)

• Air injection process does not require water as a mobility control agent. This is a

significant advantage with regard to its implementation in water-scarce Australia.

2.3 Is Air Injection Simple Gas Flood? In air injection the resulting in-situ flue gas, primarily nitrogen and carbon oxides,

provides the mobilizing force at the downstream reaction region, sweeping reservoir

crude oil to the production wells. Early production during the air injection process is

related to re-pressurization and gasflood effects and in later stage; the influence of the

thermal effects would be expected to contribute more to the oil production by way of oil-

viscosity reduction.

There has been some discussion about the effective driving mechanisms associated

with the air injection process; some authors have assumed that it is essentially

attributable to the in-situ generated flue gas displacement and consequently the process

is analogous to a flue-gas injection, while others recognize the thermal nature of the

process. Clara et al. (2000) has explained the air injection process by separated

reservoir zones and proposed a laboratory strategy for evaluation of an air injection

project. It was stated that regardless of the oxidation zones, the air injection process in a

light-oil reservoir is comparable to a flue gas injection process. Hughes and Sarma

(2006) also stated that the aim of the air injection process in light-oil reservoirs is not to

generate heat and promote EOR by thermal effects rather, to create a gas drive by


8

generation of flue gas. Moreover, these authors stated that in the early phase of

recovery the gas drive is the dominant mechanism.

Fassihi (1992) compared the performance of air injection and flue-gas injection through

simulation. It was concluded that the air injection response was identical to the flue gas

response in light oil reservoir up to about two hydrocarbon pore volume injection

(HCPVI). Beyond this point, the oil displaced by the combustion front broke through,

resulting in a lower GOR accompanied by higher oil recovery. After injection of air, flue

gas is generated which then interacts with oil ahead of the combustion front. The

degree of swelling and stripping determines the volume of oil recovered when flue gas is

displacing the oil. Thus, it appears that up to the oil bank breakthrough, injection of

either flue gas or air results in the same oil recovery behaviour. However, the advantage

of injecting air over flue gas is its ability to mobilize the residual oil saturation.

Montes et al. (2008) have laboratory and field evidence that only for one pore volume

injection the air injection process is quite similar to a gas injection process. Considering

more than one pore volume point, the air injection process still has the potential to

recover additional oil via thermal effects, which cannot be recovered by simple

immiscible displacement. They confirmed the extra oil was due to thermal effects from

combustion front. Thus, the air injection project has the potential to yield higher

recoveries than a simple immiscible gasflood.

2.4 Candidate Reservoir Screening A number of screening guides have been published for combustion projects in heavy-oil

reservoirs (Awan et al., 2006; Taber and Martin, 1983; Taber et al., 1997a; Taber et al.,

1997b). However, the design parameters for heavy oil combustion projects are not

directly applicable to air injection operation. In addition, one reservoir is not like other

reservoir and the reactivity of given oil is specific. No screening guide has been

published which predicts the oxidation characteristics of a specific reservoir. Key

parameters of air injection projects are the amount of oil-in-place at the start of air

injection (essentially the porosity times oil saturation), the reservoir temperature, the

ability to deliver air to the reservoir, and the ability of the oil to spontaneous ignite and

the stability of oxygen uptake reactions (Moore et al., 2002). The amount of air needed

to sweep a unit volume of reservoir fuel is another important design parameter.


9

2.4.1 Field Screening

The significant screening parameters with regard to the field implementation of air

injection process include: oil-in-place at start of air injection, reservoir temperature, oil

reactivity and reservoir geology. As is the case for all EOR processes, the oil-in-place at

the start of air injection is a key economic parameter. It has a direct impact on the

incremental and cumulative injected air/produced oil ratios (Moore et al., 2004).

Reservoir temperature is the main parameter in terms of the ease of ignition of an air

injection process. As a rule of thumb, an initial reservoir temperature higher than 85°C is

desirable for the spontaneous ignition (Moore et al., 2004). The oil reactivity is extremely

important as the success and beginning of an air injection process depends on the

oxygen being reacted through bond scission or combustion reactions to form carbon

oxides. Reservoir geological characteristics take a major role in the outcome of air

injection projects. The geological structures as well as reservoir heterogeneities play a

significant role in the performance of air injection projects.

2.4.2 Laboratory Screening

A number of laboratory screening tests have been developed to access the potential of

reservoirs as a candidate for air injection. These tests are: the thermogravimetric and

pressurized differential scanning calorimetric (TG/PDSC) test, the combustion tube (CT)

test, the accelerating rate calorimeter (ARC) test, and the ramped temperature oxidation

(RTO) test (Moore et al., 2002). Only the functions of these experiments are discussed

here.

TGA/PDSC tests are used to identify the temperature ranges over which the oil will react

with O2 in air and to make connections to the fraction of the sample responsible for

reactivity. The ARC measures the intensity of the oxidation reactions as a function of

temperature under elevated pressure conditions. ARC tests also determine the

spontaneous ignition property of crude oil and estimate kinetic parameters and identify

the reaction regimes for the test oil (Sarma et al., 2002; Yannimaras and Tiffin, 1995).

The combustion tube test evaluates the amount of injected air needed to process a unit

volume of reservoir. The ramped temperature oxidation apparatus utilizes for

determination of oxygen uptake rate as a function of temperature starting at the actual

reservoir temperature. The low temperature oxidation rate versus temperature data

yields the Arrhenious parameters required to predict spontaneous ignition (Moore et al.


10

2004). To determine oil recovery efficiency after the injection, high pressure core flood

test is utilized. The slim tube test is used to estimate the minimum miscibility pressure.

2.5 Air Injection Field Performance In the literature a number of ongoing successful air injection field projects have been

reported, notably in the West Hackberry Field, Louisiana (Fassihi and Gillham, 1993;

Gillham et al., 1998); in Medicine Pole Hills (MPH) Unit, North Dakota (Fassihi et al.,

1997; Kumar et al., 1995); Buffalo, South Dakota (Gutierrez et al., 2008; Kumar et al.,

2007; Kumar et al., 2008); most recently, in the Horse Creek Field, North Dakota (Clara

et al., 1998; Germain and Geyelin, 1997; Watts et al., 1997). A pilot test is proposed in

the Handil Field in Indonesia (Clara et al., 2000). The first field pilot of air injection began

in 1963 on Sloss Field in Nebraska (Parrish et al., 1974a; Parrish et al., 1974b), where

Amoco’s COFCAW process (Combination of Forward Combustion and Waterflooding)

was applied in the deep, thin, light oil, watered out reservoir. This pilot recovered 43

percent of the oil after water flood.

The Buffalo Field comprises the oldest air injection projects currently in operation and

produces from the Red River formation (Gutierrez et al., 2007; Kumar et al., 2007). This

field was discovered in 1954 and laboratory and pilot tests for air injection were

completed in 1977. The second application of air injection was the West Heidelberg

pressure maintenance project in the state of Mississippi (USA) (Huffman et al., 1983),

which started in 1971 as a secondary recovery project in the deep Cotton Valley sands.

The air injection process was first commercially introduced as a secondary recovery

technique in the North and South Dakota portions of the Williston basin, (USA), which

was started in 1979 and continues to be a technical and economic success (Fassihi et

al., 1996b; Kumar et al., 2007; Kumar et al., 2008). Since its first application, air injection

has been applied successfully as both a secondary and tertiary (Double Displacement

Process, West Hackberry (Gillham et al., 1998; Gillham et al., 1997)) EOR process, over

a variety of reservoir scenarios, in both vertical and horizontal flooding modes. However,

full-field air injection projects have been developed in 1996 (Clara et al., 1998; Watts et

al., 1997), and a range of field pilots and evaluation studies are underway or have been

proposed in recent times (Clara et al., 2000); these have tended to focus on the use of

the process for tertiary recovery (Ren et al., 2002; Surguchev et al., 1999).


11

Another successful field is Medicine Pole Hills field where air injection was initiated in

1986, but only continued for two months before injection was stopped due to a decline in

the oil price. Injection recommenced in October 1987 and continued uninterrupted and

the process has increased oil production by a factor of three (Fassihi et al., 1996b). The

air injection incremental recovery has been estimated as an additional 14.2%.

2.6 Air Injection in Australian Basins There has not been any Australian field application even though several reservoirs

appear to meet the screening criteria (Hughes and Sarma, 2006) for the air injection

process. Most of Australia’s onshore hydrocarbon provinces are mature and depleted,

and oil price is another criterion that also supports EOR application in these areas. In

the past, Australian petroleum industries’ use of EOR has tended to be limited to more

traditional methods e.g. waterflooding or gas-lift. However, in the current time some

companies are trying to evaluate and implement more fit-for-purpose EOR methods.

The reservoir properties of Cooper-Eromanga, Carnarvon (Barrow Island) and Surat-

Bowen basins are presented in Table-2.1; these are potential reservoirs for air injection.

The general reservoir properties of Field ‘B’ appeared to be appropriate as an air

injection target. The reservoir properties of Cooper-Eromanga Basin i.e., high

temperature, low permeability reservoirs with low primary recovery are similar to

successful air injection projects of the Williston Basin. Its basic reservoir properties are

presented in Table-2.2. The reservoirs are hot and quite deep with sufficient residual oil

saturation; this fuel load is adequate to sustain the ignition process. These desirable

properties make Cooper-Eromanga Basin a high potential candidate for air injection.

The potential benefits of air injection when applied to fields in Australia, in combination

with favourable reservoir characteristics provided a strong motivation for air injection

application as an EOR technique.


12

Table2.1: General Reservoir Properties of Prospective Basins for Air Injection in Australia (Hughes and Sarma, 2006)

Basin Screening

Criteria Carnarvon

(Barrow Island)Cooper

Eromanga Suart-Bowen

(Moonie)

a1001984

Text Box

a1172507

Text Box

NOTE: This table is included on page 12 of the print copy of the thesis held in the University of Adelaide Library.


___________________________________________________________________

Table 2.2: Cooper-Eromanga Basin–Oil Reservoir Properties (Hughes and Sarma, 2006)

13

a1172507

Text Box

NOTE: This table is included on page 13 of the print copy of the thesis held in the University of Adelaide Library.


14

2.7 Summary of Current Research on Air Injection The literature discussed in this chapter has explained the fundamentals and the

overview of air injection process. It has also shown the similarity and divergence of air

injection with gasflood. In air injection, most of the beneficial mechanisms are favourable

at higher reservoir pressure and temperature. Some researchers pointed out that air

injection in light-oil reservoirs is a conventional gas injection process. However, it is

shown that different oxidation reactions of light-oil take place at different temperature

intervals.

The number of air injection projects for light-oil reservoir is increasing; the West

Hackberry Field, Medicine Pole Hills Unit, Buffalo, and Horse Creek Field are ongoing

successful air injection projects and some other air injection projects are being

considered worldwide. These successful air injection projects and most of the air

injection studies have been performed out side of Australia. There is very limited

information available regarding air injection process implementation in Australian light-oil

reservoirs. Hughes and Sarma (2006) provided screening criteria and general basin

properties of select three Australian basins. However, currently, there is no experimental

data available for screening and design of air injection projects in Australia. This study

was designed to screen Australian light-oil reservoirs for air injection technique by

developing experimental data.

15

Chapter 3 THEORETICAL ASPECTS OF AIR INJECTION

This chapter begins with the explanation of oxidation reactions of crude oils, including

the difference between the air injection process in light oil reservoir and in-situ

combustion in heavy oil reservoir. Then it follows the factors that have investigated the

effects of oil composition, rock surface area, pressure and instrument operating

conditions on the oxidation reactions. Oxidation reaction kinetics and its calculation

procedure for kinetic parameters from thermograms are also discussed at the end of this

chapter.

3.1 Oxidation Reactions Associated with Air Injection The feasibility of air injection technique primarily depends on the reaction between the

oxygen and the hydrocarbons. The oxidation reactions of crude oil included numerous

physical changes are that take place over different temperature ranges. Because crude

oil is a mixture of hydrocarbons and due to the chemical complexity of oxidation of crude

oil, in nearly all-available literature the lumped groups of reactions have been widely

employed rather than individual reactions. These groups are:

• low temperature oxidation (LTO),

• pyrolysis, and

• high temperature oxidation (HTO) or combustion

Most oxidation studies have focussed on the behaviour of heavy oils, and these reaction

regions were defined based on the behaviour of heavy oils.

3.1.1 Low Temperature Oxidation

During heavy oil oxidation process, the reactions between oxygen and the fractions of oil

occurring below 300°C are generally referred to as low temperature oxidation reactions

(Alexander et al., 1962; Bousaid and Ramey Jr, 1968; Burger and Sahuquet, 1972).

These reactions are heterogeneous and generally produce a partially oxygenated

Chapter 3: Theoretical Aspects of Air Injection

16

compounds and little or no carbon oxides (Mamora et al., 1993; Sarathi, 1998). Low

temperature oxidation reactions form some oxygenated hydrocarbon, and promote the

formation of higher molecular weight products. These reactions yield water and partially

oxygenated hydrocarbons such as carboxylic acids, aldehydes, ketones, alcohols and

hydroperoxides (Burger and Sahuquet, 1972). These products are usually not produced

individually, but they are the components with more complex hydrocarbon compounds.

The remaining oxygenated hydrocarbons are usually more viscous, less volatile and

denser than the original crude oils (Alexander et al., 1962; Bousaid and RameyJr, 1968).

Dabbous and Fulton (1974) showed that during LTO diffusion of oxygen into the oil

phase is faster than the oxidation reaction. Thus, LTO occurs with the oxygen dissolved

throughout the oil phase.

Alexander et al. (1962) studied the effect of LTO on fuel formation by subjecting a

sample of oil and sand to a heating schedule in the presence of air. They found that

these low temperature oxidation reactions are highly complex and these reactions

significantly affect in situ combustion process performance through fuel laydown and

displacement efficiency. Alexander et al. (1962) also found that low temperature

oxidation reactions increase the viscosity and boiling rage of oil. Density and viscosity of

oil is increased significantly by an increase of oxygen content of the feed gas and the

duration of reactions in low temperature oxidation. Bae (1977) found that crude oils

generally increase in total weight because of low temperature oxidation.

Low temperature oxidation reactions are chain reactions initiated by free radicals

(Burger and Sahuquet, 1972). The heat released during low temperature oxidation has

been used by several investigators to estimate the spontaneous ignition time for an in

situ combustion project (Burger, 1976; Gates and Ramey Jr., 1978). Light crude oils

have been found to be more susceptible to low temperature oxidation than heavy oils

(Dabbous and Fulton, 1974). Low air fluxes in the oxidation zone resulting from reservoir

heterogeneities and oxygen channelling promote low temperature oxidation reactions

(Sarathi, 1998). Poor combustion characteristics of the crude oil also tend to promote

low temperature oxidation due to low oxygen consumption.


17

3.1.2 Pyrolysis

As the reservoir temperature rises in an oxygen free environment, the oil undergoes

several overlying physical and chemical changes called pyrolysis, which is often also

referred to as fuel deposition reactions. Oil pyrolysis reactions are homogeneous and

endothermic. At the beginning of the pyrolysis, distillation occurs that vaporizes light

fractions from the liquid phase of a crude oil. Then, oil undergoes three kinds of

reactions: dehydrogenation, cracking and condensation (Sarathi, 1998). In the

dehydrogenation reactions, the hydrogen atoms are stripped from hydrocarbon

molecules, while leaving the carbon atoms untouched. In the cracking reactions, the

carbon–carbon bond of heavier hydrocarbon molecules is broken, which results in the

formation lower carbon number molecules. The light molecules or liquid phase products,

which are distilled, undertake condensation reactions. In the condensation reactions, the

number of carbon atoms in the molecules increases leading to the formation of heavier

carbon rich hydrocarbons.

Laboratory pyrolysis studies indicate that the reservoir lithology is an important

parameter in fuel deposition (Gates and Ramey Jr., 1978). Alexander et al. (1962) have

shown that the amount of fuel deposited increased with increasing initial oil saturation,

oil viscosity and carbon residue, and decreased with increasing atomic hydrogen–

carbon ratio and API gravity of the oil.

3.1.3 High Temperature Oxidation

The reaction between the oxygen in the injected air and the reservoir oil generally at

temperatures above 350°C is often referred to as high temperature oxidation (HTO) or

combustion. Combustion reaction is classically referred to as “bond scission” reactions

and represents the reactions where the oxygen breaks up the hydrocarbon molecules.

That is principally produced carbon-oxide (CO2 or CO) and water (Burger and Sahuquet,

1972). HTO reactions are heterogeneous reactions, i.e., gas-solid and gas-liquid

residue reactions, and the stoichiometry of an HTO reaction is given by Behnam and

Poettmann (1958):


18

[ ] OHnmCOCOmOnmCH n 222 21

221 ++−→⎥⎦

⎤⎢⎣⎡ +−+

Where n = atomic ratio of hydrogen to carbon and

m = fraction of carbon oxidized to CO

Commonly, HTO reactions occur at high temperatures. In heavier oils, bond scission

reactions will not be the dominant oxidation reactions at temperatures below about

450°C. However, in many of the high gravity, light oil reservoirs, these bond scission

reactions occur in the 150 to 300°C range (Moore et al., 2002). High temperature

oxidation is highly exothermic. Heat generated from these reactions provides the

thermal energy to sustain and propagate the combustion front in the in situ combustion

process.

3.2 Air Injection of Light Oil versus In-situ Combustion of

Heavy Oil Air Injection and in-situ combustion (ISC) are basically a gas injection oil recovery

process. However, there are many differences between in-situ combustion and air

injection, such as combustion temperature ranges, recovery mechanism, and

combustion mechanism. When air is injected in a light oil reservoir, the process is known

as air injection and if air is injected in a heavy oil reservoir, the technique is known as in-

situ combustion. The objective of air injection for light oil reservoirs is to produce flue

gas and improve oil recovery by flue gas sweeping (Clara et al., 2000). However, in the

in-situ combustion process, heat is used as a modifying agent to reduce the viscosity

and mobilize the oil towards producers and eventually improve the heavy oil recovery

(Sarathi, 1998).

In both air injection and in-situ combustion processes, various oxidation reactions exist

(Greaves et al., 1998). In the literature, common two-oxidation modes (low temperature

and high temperature oxidation) are widely accepted for light oils. Due to the relatively

high hydrogen content the light oils are more reactive than heavy oils, (Dabbous and

Fulton, 1974). In addition, light oils are more susceptible to low temperature oxidation.

Most of the oxygen consumed in the low temperature region is consumed by hydrogen

and hydrocarbon oxidation rather than carbon (coke) oxidation. Moore et al. (2002)


19

reported that for both light and heavy oil, effective displacement by thermal front

required the oxidation kinetics to be in the bond scission mode. For light oils, the bond

scission mode occurs in the low temperature range. However, for heavy oils the bond

scission reactions occur in the high temperature range. In many of the high gravity, light

oil reservoirs, bond scission reactions occur in the range from 230°C to 300°C, while in

heavier oils, bond scission reactions will not be the dominant oxidation reactions at

temperatures below about 450°C (Moore et al., 2002; Moore et al., 2004). They also

reported that the oxygen addition reactions constitute the dominant oxidation reactions

at temperatures below about 150°C for light oils and below approximately 300°C for

heavy oils. The differences in the reaction temperature ranges of light and heavy oils are

due to the differences in oil composition. The oxidation rate of light oil and heavy oil as a

function of temperature is shown in Fig. 3.1. Both lower temperature and higher

temperature zones show exothermic activity with energy generation by oxidation

reactions. In the lower temperature zone, there is a region where oxidation and energy

generation rates decrease with increasing temperature, is known as negative

temperature gradient region. The negative temperature region in both light and heavy oil

exhibits at the same temperature range. To achieve effective oil displacement in-situ

combustion or air injection projects must operate in the bond scission mode (Moore et

al., 1998). Therefore, for the potential design of an air injection process, it is necessary

to have the bond scission reaction temperature region.


20

Temperature (°C) Fig. 3.1–Crude Oil Oxidation Regions (Moore et al., 1998)

3.3 Factors Affecting the Oxidation Behaviour of Crude Oil Several studies had been made over the years in the laboratory to study the factors that

affect the crude oil oxidation reactions in the reservoir. These investigations indicate that

the nature and composition of the reservoir rock and the characteristics of the crude oil

influence the thermo-oxidative characteristics of the reservoir crudes. Surface area as

well as total pressure and oxygen partial pressure, and clay and metallic content have

an enormous influence on fuel deposition rate and its oxidation. Various instrumental

operating parameters (TGA/PDSC), such as heating rate, the flow rate of air also have

an effect on the oxidation behaviour. Studies conducted on the effect of these factors

are summarized in this section.

3.3.1 Composition of Crude oil/SARA Fraction

A number of researchers have investigated the oxidation behaviour of crude oil. Bae

(1977) was the first researcher who characterized crude oils based on their thermo-

oxidative response. His study indicated that the thermal characteristic of oil is unique

a1001984

Text Box

a1172507

Text Box

NOTE: This figure is included on page 20 of the print copy of the thesis held in the University of Adelaide Library.


21

and the fuel availability on combustion at a particular temperature and pressure varied

by the oil quality. Ciajolo and Barbella (1984) investigated the pyrolysis and oxidation

behaviour of various heavy oils and their separate paraffinic, aromatic, polar and

asphaltene fractions. They demonstrated that the thermal behaviour of heavy oil could

be interpreted in terms of reaction phases; low temperature phase (100-400°C) and

high temperature phase (400-600°C). The low temperature range involved the

volatilization of paraffinic and aromatic fractions. In the high temperature range, the

polar and asphaltene fractions were paralysed to produce carbon rich coke.

Verkoczy and Jha (1986) examined coke formation using TGA in a non-oxidizing

atmosphere and showed that coke formation was independent of oil density but might

depend on asphaltene content, which depended on the overall chemical composition of

the crude oil. Kok and Karacan (1998) also observed that the activation energy of the

combustion process was increased with asphaltene content raises. They also reported

that the calorific value due to the cracking reaction is related to the asphaltene content

and °API gravity of crude oil.

In recent years, there is some different observations and interpretations on SARA

(saturates, aromatics, resins, and asphaltenes) fractions in literatures. Verkoczy and

Freitag (1997) performed a study to investigate the oxidation behaviour of three heavy

oils and their SARA fractions using the thermal analysis technique. A comparison was

made between the process in the presence and in the absence of air that revealed the

temperature regions in which each of SARA fractions underwent oxygen uptake and

then combustion. They also found that asphaltene underwent low-temperature oxidation

and was more reactive than the other fractions.

Kok and Karacan (2000) studied SARA fraction effects during combustion using TGA.

They concluded that asphaltene molecules did not show exothermic activities until the

very high temperatures. There was no weight loss due to distillation and LTO however,

saturates show a huge weight loss in the LTO regions. Asphaltenes are the least heat

contributor in LTO region, but in HTO, it gives a great amount of heat and dominates the

process in terms of heat flow. In order to develop the heat of combustion Mendez-

Kuppe et al. (2008) conducted a study for three different types of crude oils and their

SARA fractions. The outcome of this study indicated that saturated and aromatic have

higher heating values than resins and asphaltenes.


22

Li et al. (2002) used thermal analysis techniques (TG and DTA) to investigate the

oxidation behaviour of pure saturated hydrocarbons and mixture of pure paraffin with

crude oils. They found that paraffin samples mainly contributed to low temperature

exothermic activities and released more heat at low temperature. In addition, they found

that the oxidation of paraffin depended on their molecular weight. With increasing

molecular weight, the exothermic peak temperatures both in low and high temperature

regions shifted to the higher temperature and more heat value is released.

3.3.2 Clays, Metallic Additives and Reservoir Rock Composition

Clays and fine sands, have very high specific surface area. They also contain heavy

metal derivatives and may act as a catalyst. Many studies appeared in the literature

investigating the effect of metallic additives on the oxidation characteristics of crude oil.

Studies by Fassihi et al., (1984); Vossoughi et al., (1982), indicated that the presence of

clays and fine sands in the matrix favour increased rates of coke formation. Vossoughi

et al. (1983) reported that the presence of silica and kaolinite enhanced crude oil

combustion. A significant reduction of activation energy was observed by the addition of

kaolinite to the crude oil, indicating that the kaolinite had a catalytic effect on crude oil.

Drici and Vossoughi (1985) observed the effect of the surface area on the oxidation

reactions, such as the test on crude oil in the presence of silica sand. The results

showed that the metal oxides concentration increased the amount of heat released in

the LTO reaction region gradually increase. The combustion peak temperature shifts to

a lower temperature and became smaller and smoother which reflects a more

homogeneous composition of solid residue.

Metals and metallic additives also affect the nature and the amount of fuel formed.

Shallcross et al. (1991) performed kinetic experiments with various metallic additives.

They found that iron and tin salts enhance fuel deposition and increase oxygen

consumption while copper, nickel and cadmium salts show no apparent effect. In

addition, Castanier et al. (1992) carried out a study of thirteen combustion tube runs with

metallic additives and the results showed that tin, iron and zinc enhance combustion

efficiency, while copper, nickel and cadmium have little or no effect. In addition, zinc is

found to be less effective compared to tin and iron. He et al. (2005) studied the effect of

metallic additives on in-situ combustion using combustion tube and kinetics cell. It was

observed that the combustion performance was improved using additives including


23

changing activation energies, greater oxygen consumption low temperature threshold

and more complete oxidation. They found kaolinite, even without metallic additive, also

has an effect on crude oil combustion.

Studies of the effect of reservoir minerals on in-situ combustion indicate metals promote

low temperature oxidation and increase fuel deposition (Burger and Sahuquet, 1972;

Drici and Vossoughi, 1985). Burger and Sahuquet (1972) performed oxidation kinetic

experiments and observed that the oxidation reactions could occur at lower temperature

and the area under the high temperature peak increases in the presence of additives.

They interpreted the first observation due to an increase in oxidation reaction rate and

the latter due to an increase in the deposited fuel amount.

3.3.3 Total Pressure /Oxygen Partial Pressure

The pressure effect on crude oil combustion was first studied by Bae (1977) using

differential thermal analysis and thermogravimetric instruments. This study concluded

that fuel availability depends on pressure and the peak temperature of exothermic

regions increase with the total pressure decrease. However, Yoshiki and Philips (1985)

concluded that, both low temperature and high temperature oxidation rates increased

with increasing pressure. Lukyaa et al. (1994) also reported that increased oxygen

partial pressure decreased the peak temperature within both of the low and high

temperature oxidation regions, indicating that the reaction rates increased. The overall

heat output of the oxidation region was increased until 50% oxygen level; beyond this

intensity, no further increase was observed.

Vossoughi and El-Shoubary (1989) investigated the effects of oxygen partial pressure

on coke combustion using thermogravimetric techniques. The thermogravimetric curves

and derivative thermogravimetric curves were subjected to kinetic analysis. The rate

equation produced indicated that the rate of coke combustion was proportional to the

oxygen partial pressure. Indrijarso et al. (1991) used a high pressure DSC to study the

effect of the total pressure, oxygen partial pressure, and sand particle size on the heat

evaluation during combustion of heavy oil. They concluded that increasing pressure

tended to increase the extent of low temperature oxidation, thus favouring fuel laydown.

Kok et al. (1997) also showed an increased heat release in the low temperature region

with increased total pressure for a light oil. They suggested that due to its light nature

the light oil is more susceptible to liquid hydrocarbon combustion.


24

3.3.4 Instrumental Test Condition

During crude oil combustion, the TGA/DSC result is affected by instrumental

parameters including heating rate, purge gas flow rate, oxygen partial pressure and

sample size (Nickle et al., 1987). It was reported that for every reaction regime, the peak

DTG temperature increased with increasing heating rate. The heating rate employed

affected the results calculated from thermal curves, such as enthalpy, peak temperature,

and fuel laydown. This study also examined the effect of flow rate of an oxidizing gas

and an inert gas in thermal analysis.

Li et al (2002) conducted DTA and DTG analyses on pure paraffin samples in air and

helium atmospheres at heating rate 1,2,3,5 and 7 °C/min. It was found that in both the

low and high temperature reaction regions, the exothermic peak temperatures increased

with increasing heating rate. They also found that the fuel laydown of a paraffin and

crude oil sample increased with decreasing heating rate and that was significant at low

heating rate. However, above 5 °C/min, the decrease in fuel laydown was linear and

quite small.

Yoshiki and Phillips (1985) did the kinetics study of Athabasca bitumen using the

thermal analyser. They demonstrated the effect of several heating rates on oxidation

and combustion reactions. Three types of combustion heating rates were used in their

study. They reported that at very high heating rates (24°C/min) the LTO and HTO peaks

coalesce. However, at very low heating rates (2.8°C/min), LTO is completely separable

from HTO region, also at high temperature, oxygen addition reactions are separable.

They concluded that the LTO region generated heat was not sufficient to accelerate

other oxidation reactions. At the intermediate heating rate (6.9°C/min) HTO and coke

formation occurred simultaneously, however the complete combustion was not

accelerated in the high temperature region. Finally, they concluded that heating rate has

a great influence on oxidation reactions and it may be used to control the amount of LTO

occurring, hence fuel availability during in situ combustion process. These conclusions

are partly supported by Verkoczy and Jha (1986) in their TGA and DSC investigation of

Saskatchewan heavy oils. Their study was conducted at a heating rate of 2° to 20°C/min

in helium and air atmosphere. They found that the oxidation and combustion reaction

rates were non-linearly dependent on the heating rate however coke formation was

independent of heating rate.


25

3.4 Reaction Kinetics Reaction kinetics can be defined as the study of the rate and extent of chemical

transformation of reactant to product. The oxidation reaction kinetics that takes place

during heating of the samples can be obtained by thermal analysis method. The kinetic

model of the in situ combustion process is developed using thermogravimetry and

differential scanning calorimetry data.

Bousaid and Ramey (1968), Dabbous and Fulton (1974) studied some early reaction

kinetics. In their experiments, the temperature of a sample of crude oil and sand mixture

was increased at a constant rate, or kept constant at the temperature of interest. The

rate of oxidation of crude oil in a porous medium Rc can be described as follows:

nf

mO

fc CkP

dtdC

R2

=−= ………………………………..………… (3.1)

where:

Cf = fuel concentration

k = rate constant

PO2 = partial pressure of oxygen

m, n = reaction orders

The reaction constant, k, is a function of temperature and follows the Arrhenius Rate

Law (Smith, 1981)

⎟⎠⎞

⎜⎝⎛−=

RTEAk r exp ………………………………………..………. (3.2)

where:

Ar = Arrhenius constant

E = activation energy

R = universal gas constant

Substituting Eq. (2) into Eq. (1) yields:

⎟⎠⎞

⎜⎝⎛−=−=

RTECPA

dtdC

R nf

mOr

fc exp

2 ………………………….…….. (3.3)


26

Using equation 3.3, the kinetic parameters, Ar, E, m and n can be obtained from

experimental data.

3.5 Kinetic Parameter from Thermogram The oxidation of hydrocarbon is a complicated phenomenon since numerous

components of crude oil are simultaneously oxidized. Several investigators (Coats and

Redfern, 1964; Dharwadkar et al., 1978; Freeman and Carroll, 1958; Mickelson and

Einhorn, 1970; Reich and Stivala, 1978; Rock, 1978) have presented procedures to

determine the kinetic parameters of a reaction from the TGA data. All of these models

are based on Arrhenius kinetic theory. The combustion reactions are described by the

following rate expression:

( )

( ) RTE

ERT

EAR

Tn

n

−⎥⎦

⎤⎢⎣

⎡⎟⎠⎞

⎜⎝⎛ −=⎥

⎦

⎤⎢⎣

⎡

−−− − 21ln

111ln 2

1

βα

…………..……………… (3.4)

By rearranging, integrating it is obtained the Coats and Redfern (1964) equation.

For all values of n ≠ 1

( )( ) RT

EERT

EAR

Tn

n

−⎥⎦

⎤⎢⎣

⎡⎟⎠⎞

⎜⎝⎛ −=⎥

⎦

⎤⎢⎣

⎡

−−− − 21ln

111ln 2

1

βα

……………………………….. (3.5)

For n = 1

( )RTE

ERT

EAR

T−⎥

⎦

⎤⎢⎣

⎡⎟⎠⎞

⎜⎝⎛ −=⎥⎦

⎤⎢⎣⎡ −−

21ln1lnln 2 βα

……………………………….. (3.6)

where, α =fractional weight change of the sample

∞−

−=

wwww to

0

α

wo = initial sample weight

wt = sample weight @ time ‘t’

w∞ = final sample weight

t = time

k = reaction rate

n = order of reaction


27

β = temperature increasing rate (dtdT

=β )

T = temperature at time‘t’

Thus a plot of either ( )

( ) ⎥⎦

⎤⎢⎣

⎡

−−− −

2

1

111ln

Tn

nα against

T1

or, when n =1 ( )

⎥⎦⎤

⎢⎣⎡ −− 2

1lnlnTα

against

T1

should result in a straight line of slope -RE

for the correct value of n. The value of E

obtained graphically is substituted in Eq. 3.5 & Eq. 3.6 to calculate the pre-exponential

factor Ar.

28

Chapter 4 EXPERIMENTAL TECHNIQUE AND APPARATUS

In this chapter, the experimental procedures of physical and thermal analyses are

explained. This includes a description of fundamentals of thermal apparatus, the test

conditions, and test preparations. The thermogravimetry (TG) tests were conducted

under ambient pressure. The differential scanning calorimetry (DSC) tests were

performed at ambient pressure as well the elevated pressure. Sample collection and

sample preparations are also explained in this chapter.

4.1 Physical Test Apparatus Density: Density was directly measured using the apparatus of DMA 4000. The DMA

4000 is based on patented U-tube oscillator, with a wide viscosity and temperature

range.

Viscosity: Viscosity was determined by Physica MCR 301. The apparatus set-up for the

viscosity measurement of crude oil is shown in Fig. 4.1. This instrument has temperature

control, measurement and observation parts. Maximum operational temperature was set

between 100°C and 15°C per min for heating rate.

Composition Analysis: The Clarus 500 Gas Chromatograph-Mass Spectrometer (GC-

MS) was used for compositional analysis. Apparatus setup is shown in Fig. 4.2. This

instrument has a dual-channel, temperature programmable stand-alone gas

chromatograph and a mass spectrometer. The mass spectrometer has a sophisticated

detector that provides mass spectrometry analysis. The Clarus 500 was controlled by a

personal computer based data system. Helium was used as the carrier gas. Operational

temperature was 25°C to 700°C. Individual peaks were separated by retention time and

all peaks were analysed by mass spectroscopy. Its dedicated software was then used

for comparing the mass spectrum with a known compounds spectrum.

Chapter 4: Experimental Technique and Apparatus

29

Fig. 4.1−Setup of Rheo meter Physica MCR 301

(Viscosity measurement apparatus)

Fig. 4.2−Clarus 500 GC–MS Apparatus Setup


30

4.2 Thermal Analysis Apparatus Generally, kinetic studies of in-situ combustion reactions are carried out using a variety

of thermal analysis techniques. Thermal analysis comprises a group of techniques in

which a physical property of a substance is measured as a function of temperature,

while the substance is subjected to a controlled temperature programme (Gallagher,

1997). More common thermal analytical methods are summarized in Table 4.1. Most of

these techniques use a linear heating rate to simplify data analysis.

Table 4.1−Principal Thermo Analytical Methods (Gallagher, 1997)

Property Technique Acronym

Mass Thermogravimetry TGA,TG

Apparent mass Thermomegnetometry TM

Volatiles Evolved gas detection EGD

Evolved gas analysis EGA

Thermal desorption

Radioactive decay Emanation thermal analysis ETA

Temperature Differential thermal analysis DTA

Heat or heat flux Differential scanning calorimetry DSC

Dimensions Thermodilatometry TD

Mechanical properties Thermomechanical analysis TMA

Dynamic mechanical analysis DMA, DMTA

Acoustical properties Thermosonimetry (emission) TS

Thermoacoustimetry (velocity)

Electrical properties Thermoelectometry DETA, DEA

Optical properties Thermooptometry TPA

Thermogravimetric analysis (TGA) and differential scanning calorimetry (DSC) are the

most widely used thermal analysis techniques to study the oxidation and combustion

behaviour of crude oil. The following section outlines these techniques briefly.


31

4.2.1 Thermogravimetric Analysis

Thermogravimetric analysis (TG or TGA) is a technique in which the mass of a

substance is measured as a function of temperature while the substance is subjected to

a controlled temperature programme. Mass loss can occur due to vapour emission (e.g.

evaporation, distillation, cracking) from sample whereas a mass gain can result from a

gas fixation by the sample. Derivative thermogravimetry (DTG) is the derivative of mass

change curve with respect to time (i.e., rate of weight lose or gain). When two changes

occur at temperatures, which are close, the DTG will resolve the curve into two distinct

regions.

In this study TA 2950 analyser was used; its furnace assembly is shown in Fig. 4.3 and

complete photograph is shown in Fig. 4.4. The sample was placed on an aluminium pan,

which was suspended from a sensitive microbalance and enclosed in a furnace. The

furnace and balance are then purged with the desired gas at a defined flow rate and the

furnace was heated according to a controlled programme. A quantitative plot of the

mass and/or mass change versus temperature was obtained.

Fig. 4.3−Schematic Diagram of a TGA Furnace Assembly (Gallagher, 1997)


32

Fig. 4.4−View of the TA 2950 Thermogravimetric Analyser

4.2.2 Differential Scanning Calorimetry

In the DSC technique, the difference in energy inputs into a substance and a reference

material is measured as a function of temperature whilst the substance and reference

material are subjected to a controlled temperature programme. DSC is usually regarded

as a quantitative technique. The quantitative measurement of energy is generally

calculated by integrating the input heat-flow difference as a function of temperature. If

additional heat is supplied to the sample, the process is endothermic. If it is supplied to

the reference side, then the process is exothermic.

A typical DSC cell comprises of a thermoelectric disc that transfers heat to two pans,

one containing the sample of interest and the other used as a reference (Fig. 4.5). The

pans are maintained under the controlled gas environment and are subjected to a user-

specified heating profile, which can include temperature ramp conditions. The resultant

heat flow signal may then be plotted as a function of temperature, with changes in heat

flow corresponding to either the absorption (endothermic) or release (exothermic) of

heat by the sample as compared to the reference. To ensure accuracy of temperature

readings, the DSC unit was calibrated periodically using a reference standard, and

repeatability tests were conducted. Used DSC 2920 for DSC test and its different


33

components are shown in Fig. 4.6 to Fig. 4.8. Fig 4.6 shows normal DSC and Fig. 4.7

and Fig. 4.8 show pressure DSC and high-pressure cell, respectively.

Fig. 4.5−Schematic Diagram of a Heat Flux DSC Cell

Fig. 4.6−View of the DSC 2920 (TA Instruments)


34

Fig. 4.7−View of the DSC 2920 with Pressure Cell

Fig. 4.8−View of the High Pressure Cell of DSC 2920


35

4.3 Thermal Analysis Test Conditions The sensitivity of TG and DSC tests to heating rate, purge gas flow and sample size was

evaluated to determine the validity of the experimental results.

Heating Rate Selection The heating rate for TGA and DSC can be varied from 1°C to 20°C/min. Higher heating

rates increase the sensitivity and reduce its resolution. Before conduct of this study a

series of experiments was done to evaluate the accurate heating rate. It was observed

that above 10°C/min DSC gives overlapping exothermic regions in the heat flow curves,

which was an indication of declining resolution. Thus, 10°C/min was the selected

heating rate up to 350°C for DSC. In order to maintain the similar environment of this

study, 10°C/min heating rate was also selected for TGA up to 600°C. The similar heating

rate was maintained in PDSC tests up to 500°C.

Purge Gas Flow Rate and Test Pressure The TGA curves of tested samples are influenced by mass transfer limitations, i.e.,

diffusion of oxygen into the sample. TGA tests were performed in the normal

atmosphere but the flow rate through the chamber was specified. The purge gas flow

rate was kept constant at 50 mL/min by flow controller.

The normal DSC was performed at atmospheric pressure and PDSC was performed at

high pressure (4500kPa). PDSC tests were run in closed cell in a temperature range

ambient to 500°C. Due to the operational safety the PDSC working initial pressure was

set on 4500 kPa, which was increased with temperature up to 6000kPa.

Sample Size Sample size affects the sensitivity and resolution of TGA and DSC tests. Some

preliminary tests were performed to determine the appropriate sample size use in these

thermal studies. Increasing sample size improves thermal contact between sample and

thermocouple; however, the resolution of the heat signals decreases. Also larger sample

size reduces the contact between crude oil and flow gas stream. The acceptable mass

range for the TGA instrument was more or less 20mg. Thus, based on better sensitivity

and resolution in the TGA test sample size was roughly 15 mg. Moreover, sample sizes

of the oil-only, cutting only, and oil-with-cutting combined test, were ≈ 5 mg, ≈ 10 mg and


36

≈ 15 mg, respectively. These amounts of sample were used to maximise exposure of

the oil to the surrounding gas environments.

In the DSC test of oil with rock cuttings, more than 30% mass of oil sample, which gave

super heated result. Fig. 4.9 shows the superheated result of Kenmore oil #34 with rock

cutting at high pressure. For better results, the oil percentage was reduced to 10% by

mass. In this study, DSC sample sizes were 1±0.1 mg for the oil-only test and 3−4 mg

for the cutting-only test. In the combination test (i.e., oil and rock cutting) the oil weight

was 1±0.1 mg. In this case, cutting was weighed out in a sample holder and the required

amount of oil was added by a syringe. Then, a small amount of mixed sample was

weighed on a DSC pan and placed in the cell.

-50

150

350

550

750

950

1150

1350

0 100 200 300 400 500

Temperature

Hea

t Flo

w (m

W)

Fig. 4.9−Super Heated Result of Kenmore Oil #34 with Rock #34

4.4 Thermal Test Procedure

4.4.1 TGA Test

TGA tests on Kenmore crude oil and crude oil of Reservoir B, and their rock cuttings,

were conducted at atmospheric pressure in the temperature range of room temperature

Temperature, °C


37

to 600°C. The heat rate was held constant at a rate of 10°C/min. TGA tests of crude oil

samples were conducted separately with oil-only, with cutting-only and combined oil-

with-cuttings. Each test was carried out in contact with both air and nitrogen at

atmospheric pressure.

The initial test temperature of the TGA instrument was set to 25°C and purge gas (air or

N2) was set constant to 50mL/min. The platinum crucible was hung on the alumina wire

and then an aluminium pan was put into the platinum crucible. The balance was tared

after the temperature and weight signals were stabilized. Then, the sample was loaded

into aluminium pan and put back on the platinum crucible. To maintain the sample size,

the test sample was weighed into an aluminium sample pan using an electric balance.

Once the system was stable, the test was started. The mass change information was

recorded as a function of temperature and time. When the temperature reached 600°C,

the experiment was terminated and the unit was cooled down to ambient temperature by

air cooler.

4.4.2 DSC Test

The differential scanning calorimetry test was carried using the DSC−2920 (supplied by

TA Instruments), shown in Fig 4.6 and Fig 4.7. In this study, the normal DSC tests were

conducted at atmospheric pressure and temperature range was 25°C to 350°C with the

heating 10°C/min. A constant mass flow of air/oxygen at the rate of 50 mL/min was set

for each test. To perform a test, the sample was weighed into a special aluminium

sample pan using an electric balance. After the sample was spread evenly across the

flat portion of the sample pan, it was placed on the front platform in the cell. An empty

pan was placed as a reference on the rear platform. As soon as the temperature and

flow rate were stable, the test was started and when the temperature reached 350°C

test was completed.

Pressurized differential scanning calorimetry (PDSC) tests were conducted at 4500kPa

in a high-pressure cell. The pressure cell is shown in Fig. 4.8. These tests were

performed in oxygen and air environments over a temperature range from ambient to

500°C. The pans were maintained under controlled gas environment and were

subjected to a specified 10°C/min heating profile. After placing both sample pan and

reference pan, the cell was pressurised very slowly to 4500kPa. Once the system

became stable, the process was started.


38

4.5 Instrument Calibration

4.5.1 TGA Calibration

In the present study, a TA−2950 Thermogravimetric Analyzer (TA Instruments) was

used for all TGA analyses. The instrumental temperature was calibrated by observing

the mass change at the Curie temperature of nickel and alumel at 358.28°C and

154.16°C, respectively under the effect of a magnet. The time-temperature and time

dependence of Curie temperature was determined for nickel and alumel with a 10°C/min

heating rate. Fig. 4.10 and Fig. 4.11 show temperature calibration results of nickel and

alumel for TA 2950. Fig. 4.10 shows that nickel melted at 358°C, and Fig. 4.11 shows

alumel melted at 153.2°C. The experiments were conducted for both nickel and alumel

TGA had a fixed heating rate 10°C/min. Since the melting point matches with the actual

values, these results give validity to the heating rate chosen for this study; also validate

the TGA instrument results.

96.5

97

97.5

98

98.5

99

99.5

100

100.5

0 50 100 150 200 250 300 350 400 450

Temperature C

Wei

ght C

hang

e (%

)

-0.1

0

0.1

0.2

0.3

0.4

0.5

Der

iv. W

eigh

t (%

/C)Weight (mg)

Deriv. Weight (%/_C)

Fig. 4.10−Temperature Calibration of TGA Instrument by Nickel

Temperature, °C


39

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

92

93

94

95

96

97

98

99

100

101

0 50 100 150 200 250

Der

iv. W

eigh

t (%

/C)

Wei

ght C

hang

e (%

)

Temperature

Weight (mg)

Deriv. Weight (%/_C)

Fig. 4.11−Temperature Calibration of TGA by Alumel

4.5.2 DSC Calibration

Baseline Test Several baseline tests were performed without crucible or pan both sample and

reference side to obtain a baseline for both DSC and PDSC tests. Test conditions were

identical to the test performed on the samples. Fig. 4.12 shows the PDSC baseline

result heating from ambient to 500°C at a programmed heating rate of 10°C/min.

Baseline results were subtracted from tests sample outcomes in order to get the correct

result.

Temperature, °C


40

0.5

0.7

0.9

1.1

1.3

1.5

1.7

1.9

2.1

0 100 200 300 400 500

Temperature

Hea

t Flo

w (m

W)

Fig. 4.12−DSC Baseline of DSC−2920 at 4500kPa in Air Environment

Test on Standard Material Temperature was calibrated based on a run in which a temperature slandered, e.g.,

indium was heated through its melting transition using the same conditions to be used in

the sample test program (heating rate and pressure). The recorded melting point of

indium was compared to the known melting point and the difference was calculated for

temperature calibration. Indium was heated from 100 to 180°C at a programmed heating

rate of 10°C/min. The actual melting temperature is 156.6±0.5°C. Fig. 4.13 shows the

Indium test results that were melted at 156.8°C. This result confirms the validity of

temperature measurement for DSC apparatus.

Temperature, °C


41

Fig. 4.13−Temperature Calibration Result for PDSC using Standard Material (Indium) at 4500kPa

Reproducibility of Thermal Analysis Experiments Several runs were repeated to assess the reproducibility of thermal test results (showing

Fig. 4.14 to 4.16). Tests were repeated in the different verity of test conditions. Fig. 5.14

shows the reproducibility of TGA and DTG curves of Kenmore rock cutting, and Fig.

4.15 shows another pair of TGA runs of Kenmore oil and rock cutting combined tests at

atmospheric pressure. Also, Fig. 4.16 shows the reproducible PDSC test results of oil

E#13 in the air environment. The PDSC tests were performed at high pressure

(4500kPa) and heating rate was 10°C/min for ambient to 500°C. This figure shows the

reproducibility of this run is very good; one result matches with the other as predicted.

These all figures demonstrate an acceptable reproducibility of TGA and DSC test

results.


42

-7

-6

-5

-4

-3

-2

-1

0

0 100 200 300 400 500 600

Temperature

Wei

ght C

hang

e (%

)

0

0.01

0.02

0.03

0.04

0.05

0.06

Der

iv. W

eght

(%/C

)

TGA of Test-2TGA of Test-1DTG of Test-2DTG of Test-1

Fig. 4.14− Reproducibility of TGA and DTG curve (Kenmore Rock #31)

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

0 100 200 300 400 500 600Temperature

Wei

ght C

hang

e

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

Der

iv. W

eght

(%/C

)

TGA of Test-1TGA of Test-2DTG of Test-1DTG of Test-2

Fig. 4.15−Reproducibility of TGA and DTG curve (Kenmore Oil #34 with Rock

Cutting)

Temperature, °C

Temperature, °C


43

-5

20

45

70

95

0 100 200 300 400 500

Temperature °C

Hea

t Flo

w (m

W)

Test-1

Test-2

Fig. 4.16− Reproducibility of Heat-flow Curve (E-13 in Air Environment)

4.6 Sample Description

4.6.1 Sample Assembly

Two Australian light-oil reservoirs samples were used in this study. One of these

reservoirs is Kenmore Oilfield, Eromanga Basin; which is operated by Beach Petroleum

Limited. Another reservoir is field ‘B’ an onshore oil and gas field, operated by Santos

Limited. Details of the crude oil samples and their corresponding rock cutting samples

obtained from these reservoirs along with their respective depths and rock zone are

presented in Table 4.2. Kenmore crude oil samples were received from well #32, well

#34 and production tank-7, and the rock cuttings samples were received from well #31,

well #34, and well #36. Crude oil samples were received from field ‘B’ of well E #13, E

#40, W #3, and W #5, and the rock cuttings samples were received from well E #21, E

#22, and E #33.


44

4.6.2 Sample Preparation

Crude oil samples were first cleaned by the sedimentation and filtration process. A

uniform mixture of crude oil was placed in several covered 10mL tube for sedimentation.

These tubes were vertically set more than 24 hours for sedimentation and the clean

sample was collected from top portion of the tubes. These samples were used in

specific gravity and viscosity measurements and for the purpose of compositional

analysis sample was diluted to 40% (v/v) by hexane.

In the thermal test, homogeneous mixture of crude oil sample was used. As the cutting

samples came from the same reservoir, the original cutting and oil were used in all

thermal tests. In the case of oil and cutting combined samples, the cutting was weighed

first and then oil was added using microsyringe. Both the masses of oil and cuttings

were recorded.

Table 4. 2−Oil and Cutting Samples

Reservoir Sample Well Name Depth, m Zone

Kenmore

Oil

Kenmore #32

n/a n/a Kenmore #34 Kenmore Production Tank-7

Cutting

Kenmore #31

1380

Birkhead 1383 1386 1389

Kenmore #34 1395

Hutton 1401 1404

Kenmore #36 1390-1395

Birkhead 1395-1400

Field B

Oil

W # 3

n/a n/a W # 5 E # 13 E # 40

Cutting E # 21

n/a

P3-120/130 P3-230/250

E # 22 P3-120/130 E # 33 P3-120/130

45

Chapter 5 EXPERIMENTAL RESULTS

The results of the physical and thermal analyses experiments carried out on the crude

oil and rock cuttings samples from Kenmore and Field B reservoirs are presented in this

chapter. It begins with the presentation of results of the physical tests followed by the

thermal tests for the samples from both the reservoirs. The physical properties

determined in the laboratory are the specific gravity, viscosity and the petroleum

fractionations through GCMS based compositional analysis. Thermal properties

measurement using TGA/DSC techniques provided the important information on the

mass loss behaviour over the wide range of temperature in air and nitrogen

environments, and type of oxidation reactions occurring during air injection process.

After the presentation of the individual results for each of reservoirs oil, the effect of

pressure and presence of core materials during the air injection process are presented.

5.1 Physical Tests 5.1.1 Specific Gravity

One of the most important characteristic properties of crude oil is its specific gravity. It

was directly measured by apparatus DMA-4000 at a temperature of 15°C (shown in

Table 5.1).The specific gravity based of Kenmore oil on three runs of crude oil sample is

0.785 and the crude oil of Field B is 0.799. The resultant API gravity of is 48.7° and

45.55 for Kenmore and Field B, respectively.

5.1.2 Viscosity

Viscosity was measured in the temperature range between 15°C to 100°C. The viscosity

temperature profiles are shown in Fig. 5.1 and Fig. 5.2. The resulting viscosities of

Kenmore field at different temperatures were 3.87cP at 15.4ºC and 2.48cP at 25.4ºC

and 0.75cP at the reservoir temperature; Field B crude oil viscosities at different

temperature were 5.34cP at 15ºC and 4.48cP at 25.4ºC and at the reservoir temperature

2.3cP.

Chapter 5: Experimental Results

46

Table 5. 1−Specific Gravity and API-gravity

Run Operating

Temperature °C

Kenmore Field Field B

Specific Gravity

Average Specific gravity

API-Gravity

°API

Specific Gravity

Average Specific gravity

API-Gravity

°API

1 15.01 0.7857

0.785 48.70

0.7986

0.799 45.55 2 15.00 0.7849 0.7996

3 15.01 0.7851 0.7995

5.1.3 Compositional Analysis

The mass spectrum fingerprints were used to identify the compounds in crude oil. The

mass spectrum from the crude component was compared to mass spectra in the

computer-dedicated library of spectra. This library was used to identify the unknown

compound in the sample crude oil. Fig. 5.3 shows the composition of Kenmore crude

oil. It is evident that more than 84 mole% of compounds fall in the group C5 to C13, with

C9 being the most abundant group with ~16 mole %.

Fig. 5.4 presents crude oil composition of Field B. It is observed that more than ~95

mole% of compounds fall in the group C4 to C19, with C9 being the most abundant group

with ~19 mole%. Compositional analysis result supported light nature of Field B crude

oils.

5.2 Thermal Tests In this study, a series of thermal tests was performed on selected Kenmore and Field B

reservoir samples. TGA tests were performed in air and nitrogen environments in a

temperature range of ambient to 600°C. DSC tests were performed in air and oxygen

environments at three different pressures. The overview of all performed thermal

experiments is presented in Table-5.2.


47

0.5

0.75

1

1.25

1.5

1.75

2

2.25

2.5

2.75

3

10 20 30 40 50 60 70 80 90 100

Visc

osity

cP

Temperature °C

Fig. 5.1−Viscosity Temperature Profile of Kenmore Crude Oil

1

1.5

2

2.5

3

3.5

4

4.5

5

5.5

10 30 50 70 90

Visc

osity

, cP

Temperature,°C

Fig. 5.2−Viscosity Temperature Profile of Field B Crude Oil


48

0

2

4

6

8

10

12

14

16

n-C5n-C6

n-C7n-C8

n-C9n-C10

n-C11n-C12

n-C13n-C14

n-C15n-C16

n-C17n-C18

n-C19n-C20

n-C21

Carbon Number of Components

Mol

e %

Fig. 5.3−Hydrocarbon Distribution of Kenmore Crude Oil

0

4

8

12

16

20

24

28

32

n-C4n-C5

n-C6n-C7

n-C8n-C9

n-C10n-C11

n-C12n-C13

n-C14n-C15

n-C16n-C17

n-C18n-C19

n-C20n-C21

n-C22n-C23

n-C24n-C25

n-C26n-C27

n-C28

Carbon Number of Components

Mol

e %

Fig. 5.4−Hydrocarbon Distribution of Crude Oil B


49

Table 5. 2−Thermal Tests Performed in this Study

Sample Sample Type

TGA Test DSC Test Number

of Tests In Air In N2 1000kPa

in Air

4500kPa

in Air

4500kPa

in O2

Kenmore Samples

Oil (#32)

Oil-Only √ √ - √√ √

15 Cutting-Only √ √ - √ √√

Oil With Cuttings √ √ - √√ √

Oil (#34)

Oil-Only √ √ - √√ √

15 Cutting-Only √ √ - √ √

Oil With Cuttings √ √ - √√ √√

Oil (Prodn

Tank)

Oil-Only √ √ - - √

3 Cutting-Only - - - - -

Oil With Cuttings - - - - -

Field B Samples

W-3

Oil-Only √ √ √ √√ -

12 Cutting-Only √ √ - √ -

3 √ √ - √√ -

W-5

Oil-Only √ √ √ √√ -


Oil With Cuttings √ √ - √√ -

E-13

Oil-Only √ √ √ √√ -


Oil With Cuttings √ √ - √√ -

E-40

Oil-Only √ √ √ √ -

8 Cutting-Only √ √ - - -

Oil With Cuttings √ √ - - -


50

5.2.1 Kenmore Field

5.2.1.1 Kenmore #32 Oil sample

Cutting-only

Fig. 5.5 shows the TGA and DTG profile of air and nitrogen tests on rock cuttings from

Kenmore #31. DTG showing mass loss was started from 400°C and both tests showed

that mass was lost over the temperature range, up to ≈ 6% of the original mass when

600ºC was reached. The mass loss was likely due to a small amount of bound water

present in the sample. The TGA results indicate that Kenmore #31 cutting is inert in air

and nitrogen environments.

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600

Temperature (OC)

Mas

s C

hang

e (%

)

0

0.01

0.02

0.03

0.04

0.05

0.06

DTG

(%/o C

)

TGA of Rock 31 in airTGA of Rock 31 in N2DTG of Rock 31 in airDTG of Rock 31 in N2

Fig. 5.5−TGA of Kenmore Cutting #31 in Air and Nitrogen Environments

According to the heat-flow curves, as seen in Fig. 5.6, there are two distinct regions of

exothermic activity of Kenmore rock cuttings in air and oxygen environments. The first

peak is broad, occurring between 200 and 350ºC with an evolved heat of 190 J/g

(approx). The higher temperature exotherm occurred between 350ºC and 400ºC with an

evolved heat of 40 J/g (approx). However, above 400ºC the heat flow is endothermic,

i.e., absorbing heat, in this temperature zone rock cuttings mass loss likely due to bound

water. These results indicate that Kenmore rock has a minor oxidation characteristic up

to 400ºC under air environment and then endothermic outcomes. As the exotherm


51

provides energy, the cuttings material does not have any negative contact on oxidation

reaction.

-0.3

-0.2

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

0 100 200 300 400 500

Temperature (OC)

Hea

t Flo

w (W

/g)

Rock 34 in AirRock 31 in AirRock 36 in AirRock 31 in Oxygen

Fig. 5.6−PDSC of Kenmore Cutting in Air and Oxygen Environments

Oil-Only

Fig. 5.7 shows the TGA comparison of Kenmore oil #32 in air and nitrogen

environments. In the presence of air, mass was lost more or less consistently over the

full heating program and at the end of the experiment 99.9% of it disappeared. This is

due to the very light nature of the Kenmore oil. Due to the evaporative nature of crude oil

and apparatus constraint, it was difficult to take more DSC tests in the air environment at

the atmospheric pressure with DSC-2920. DSC curve of Kenmore oil #32 in air at

atmospheric pressure is shown in Fig. 5.8. It shows two peaks around 250ºC and 350ºC.


52

-110

-90

-70

-50

-30

-10

0 100 200 300 400 500 600

Temperature (OC)

Mas

s C

hang

e (%

)

-0.1

0

0.1

0.2

0.3

0.4

0.5

Der

iv. W

eigh

t (%

/OC

)

TGA of oil 32 in AirTGA of oil 32 in N2DTG of oil 32 in AirDTG of oil 32 in N2

Fig. 5.7−TGA of Kenmore Oil #32 in Air and Nitrogen Environments

In the nitrogen environment, the mass was lost consistently throughout the temperature

programme until it reached 290ºC by which time more than 98% oil had evaporated (Fig.

5.7). The final 2% of the sample was evaporated by 600ºC and this plot resembles that

of the baseline.

The heat-flow curve (Fig. 5.8) indicates the reaction character of oil #32. In the first part

of the DSC curve, endothermic activity was present, which indicated that vaporisation

and oxygen addition reactions were dominating the process. Bond scission reactions

could be occurring at lower temperature levels but they do not become significant until

the temperature reaches approximately 240ºC when the process becomes exothermic. It

was evident that exothermic activity in pressurised DSC was shifted to the lower

temperature range. The heat-flow diagram of Kenmore oil #32 reveals one big

exotherm peaking at 210-280°C in oxygen and 225-280°C in air. Also, two consecutive

small exotherms were observed in oxygen in the temperature range of 280-350ºC and

380-450ºC where as one peak in the range of 300-460°C was shown in the air

environment. These are illustrated in Fig. 5.9. In the oxygen environment the maximum

peak temperature of the first exotherm was 229ºC with 2692 J/g heat evolution and the

second exotherm appeared at 294ºC and the evolved heat was 19 J/g. Finally, the third


53

exotherm peaked maximum at 406ºC and evolved heat was 35 J/g. Compare to oxygen,

in the air environment exothermicity shifted towards higher temperature where maximum

peak temperature was 239ºC and the exothermicity was continued up to 470ºC with the

total evolved heat 2278 J/g. All of these exothermic peaks are due to the oxidation of

Kenmore oil #32. Without effluent gas analysis, it is difficult to state that the types of

reactions are occurring in each exothermic region however, they are likely all bond

scission reactions due to the temperature involved.

-0.2

0

0.2

0.4

0.6

0.8

1

0 50 100 150 200 250 300 350 400

Temperature (OC)

Hea

t Flo

w (W

/g)

Fig. 5.8−DSC of Kenmore Oil #32 in Air at Atmospheric Pressure


54

-2

8

18

28

38

48

58

0 100 200 300 400 500

Temperature ( OC)

Hea

t Flo

w (W

/g)

Oil #32 in Air

Oil #32 in Oxygen

Fig. 5.9−PDSC of Kenmore Oil #32 in Air and Oxygen Environments Oil-with-Cuttings

Fig. 5.10 compares the profiles of oil-only and oil-with-cuttings TGA-DTG tests

performed in the presence of air. In the oil-with-cuttings combined test, the percentage

of weight change is plotted against temperature as a percentage of the original mass of

oil. Also the data from corresponding the cutting-only test has been subtracted from the

data from the oil-with-cutting combined test so that the observed trends reflect only the

behaviour of oils. Both sets of curves show continuous mass loss until 260ºC -- 97% of

oil in oil-only test and 87% of oil in the oil-with-cutting combined test evaporated. At the

end of test (i.e., at 600°C), 9% of oil was remaining in the oil-with-cutting combined test

while 1% of the oil was present in the oil-only test. It is possible that the oil gets

adsorbed on the surface of the cutting material and thus the oil in the oil with cutting

combined test evaporates more slowly.


55

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600

Temperature (oC)

Wei

ght C

hang

e (%

)

-0.1

0

0.1

0.2

0.3

0.4

0.5

Der

iv. W

eigh

t (%

/o C)

TGA of Oil 32 + Rock 31 inAir

TGA of oil 32 in air

DTG of oil 32 in air

DTG of oil 32 + Rock 31 in Air

Fig. 5.10−TGA of Kenmore Oil #32 and Cutting #31 in Air Environment – Mass loss as a percentage of mass of oil

Fig. 5.11 shows the pressurised heat-flow curve in both oxygen and air environments of

oil #32 with rock cutting #31 where oil was ≈10% (by mass). Two regions, endothermic

and exothermic were seen in the plot. Endothermic region was observed up to 200ºC.

This is likely due to evaporation or distillation of lighter components in the oil. Two

exothermic regions, arising from bond scissions reaction indicate the heat flow in the

process. In oxygen, the maximum peak temperatures are 237ºC and 395ºC and the heat

evolved by these exotherms are 4045 J/g and 169 J/g, respectively. In air, exothermicity

was shifted to the higher temperature with higher heat evaluation. The maximum peak

temperatures were 264ºC and 411ºC, and evolved heat were 4673 J/g and 135 J/g,

respectively. In the air environment, it is possible that some of the fraction of crude oil

has oxidised slowly and gave more heat in high exothermic regions. This would account

for the increased exothermicity of higher temperature regions.


56

-2

0

2

4

6

8

10

12

14

16

18

20

22

0 100 200 300 400 500

Temperature (OC)

Hea

t Flo

w (W

/g)

In AirIn Oxygen

Fig. 5.11−PDSC of Kenmore Oil #32 and Cutting #31 in Air and Oxygen Environments

5.2.1.2 Kenmore #34 Oil sample

Cutting-Only

The mass loss profile for air and nitrogen tests on Kenmore cutting #34 is shown in Fig.

5.12. The air and nitrogen environments gave similar thermal results, as shown in Fig.

12. DTG curves confirmed that in both environments mass was lost mainly in 400-500ºC

region and TGA curves revealed the loss was ≈ 5% of its original mass. This mass loss

in the air and nitrogen environments was likely due to the loss of bound water from core

material. The heat flow activity of Kenmore cutting #34 in the air environment is similar

to Kenmore cutting #31 (Fig. 5.13). A small heat flow was evident up to 400ºC and after

this temperature region, the process was endothermic, likely due to the loss of bound

water.


57

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600

Temperature (oC)

Wei

ght C

hang

e (%

)

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

Der

iv. W

eigh

t (%

/o C)

TGA of Rock 34 in AirTGA of Rock 34 in NitrogenDTG of Rock 34 in AirDTG of Rock 34 in Nitrogen

Fig. 5.12−TGA of Kenmore Cutting #34 in Air and Nitrogen Environments

-0.3

-0.2

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

0 100 200 300 400 500

Temperature (OC)

Hea

t Flo

w (W

/g)

Rock 34 in Air

Fig. 5.13−PDSC of Kenmore Rock #34 in Air Environment


58

Oil-Only

The TGA of Kenmore oil #34 in both air and nitrogen is shown in Fig. 5.14. As the result

evident from this figure, in the test of air environment, the mass drops steadily until only

2% remains by about 300°C and at the end (i.e., at 600ºC), 1% oil sample remains. The

DTG values are similar in air and nitrogen environments and they touch the baseline at

300°C. This is likely due to very light nature of Kenmore oil (high API gravity 48.7°).

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600

Temperature (OC)

Mas

s C

hang

e (%

)

-0.1

0

0.1

0.2

0.3

0.4

0.5

Der

iv. W

ight

(%/O

C)

TGA in Air

TGA in Nitrogen

DTG in Air

DTG in Nitrogen

Fig. 5.14−TGA of Kenmore Oil #34 in Air and Nitrogen Environments

The heat-flow profile of Kenmore oil #34 at atmospheric pressure with air illustrates in

Fig. 5.15.The first part of this heat-flow curve demonstrates endothermic activity,

indicating that vaporisation and oxygen addition reactions could have taken place. Bond

scission reactions appear between approximately 240º–290ºC when the process

becomes exothermic. The second peak starts at 290°C continuing up to the final test

temperature of 350ºC.


59

-0.2

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 50 100 150 200 250 300 350

Temperature (OC)

Hea

t Flo

w (W

/g)

Fig. 5.15−DSC of Kenmore Oil #34 in Air at Atmospheric Pressure

However, at high pressure, exotherm peaks were shifted to the lower temperature range

where oil gave three exotherms. These PDSC results of Kenmore oil #34 in air and

oxygen environments are shown in Fig. 5.16. The first exotherm in oxygen environment

was shown between 200°C and 280°C. The maximum peak temperature was 219°C

with evolved heat value 1763 J/g. This observation indicates that pressure accelerates

the oxidation (bond scission) reactions. Other two exothermic regions were seen at

306°C and 343°C and these peaks gave heat values of 8.6 J/g and 144.6 J/g,

respectively. In contact with air, the maximum temperature appears at 240°C and

evolved heat was 1635 J/g. Air has 79% nitrogen and this nitrogen may have shifted

exothermicity towards higher temperature. In the air environment at high pressure, the

exotherm was revealed over base line up to 470°C and the total evolved heat was 2398

J/g. The shifting of these peaks to lower temperatures indicates that the high pressure

accelerates bond scission reactions.


60

-2

0

2

4

6

8

10

12

14

16

18

20

22

0 100 200 300 400 500

Temperature (OC)

Hea

t Flo

w (W

/g)

In AirIn Oxygen

Fig. 5.16−PDSC of Kenmore Oil #34 in Air and Oxygen Environments

Oil-with-Cuttings

As in the case of oil #32 tests, the mass change curve of the cutting-only test was

subtracted from the oil-with-cutting combined test. Both tests were performed in the

same conditions. This ensures that the profiles shown here represent only the

hydrocarbon portion of the sample. A comparison of the TGA profile, mass loss as

percentage of the total mass of the oil #34 with the cutting #34 in air and nitrogen

environments, is presented in Fig. 5.17. Mass loss was higher in air and it is possible

that oxidation occurred in the air environment.


61

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600Temperature (OC)

Mas

s C

hang

e (%

of t

otal

mas

s)

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

0.16

Der

iv. W

eigh

t (%

/OC

)

TGA in N2TGA in AirDTG in N2DTG in Air

Fig. 5.17−TGA of Kenmore Oil #34 with Cutting #34 in Air and Nitrogen Environments-Mass loss as a percentage of total mass

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600

Temperature (OC)

Mas

s C

hang

e (%

)

-0.1

0

0.1

0.2

0.3

0.4

0.5

Der

iv. W

eigh

t (%

/OC

)

TGA of Oil 34+ Rock 34 in N2TGA of Oil 34 in N2DTG of Oil 34 + Rock 34 in N2DTG of Oil 34 in N2

Fig. 5.18−TGA of Kenmore Oil #34 with Cutting #34 in Nitrogen Environment- Mass

loss as a percentage of mass of oil


62

Fig. 5.18 and Fig. 5.19 show the TGA of Kenmore oil #34 with rock cutting #34 in

nitrogen and air environments, respectively. In both tests, the oil-only shows higher DTG

values than those from oil-with-cutting combined test. In the nitrogen environment (Fig.

5.18) oil-with-cutting, 90% mass of the oil sample disappears at 275°C. At the same

temperature, in the oil-only test, the loss is more than 96% of the oil sample. This is

likely due to crude oil adsorbed in the surface of cutting material and liberated slowly.

This observation indicates that cutting material has a lower the weight loss which is a

positive indication for continuous oxidation during air injection.

-110

-90

-70

-50

-30

-10

10

0 100 200 300 400 500 600

Temperature (OC)

Mas

s C

hang

e (%

)

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

Der

iv. W

ight

(%/O

C)

TGA of Oil 34 + Cutting 34 in AirTGA of Oil 34 in AirDTG of Oil 34 + Cutting 34 in Air DTG of Oil 34 in Air

Fig. 5.19−TGA of Kenmore Oil #34 with Cutting #34 in Air- Mass loss as a percentage of mass of oil

In an air environment, as seen in Fig 5.20, the oil loses its mass steadily up to 250°C

and at 600°C, that is, at the end of the test all samples disappears in both oil-only and

oil-with-cutting combined tests. The high-pressure DSC curve pointed out that the

process is endothermic up to approximately 210ºC (as Fig. 5.20). This endothermic

behaviour indicates evaporation and oxygen addition reactions. The bond scission

reaction started from 210ºC and overlaps one peak with other. It is difficult to distinguish


63

these peaks and calculate their individual heat values. However, the total heat evolved

in the oxygen environment is calculated at 5655 J/g. In contact with air, the exothermic

peak was broader than the oxygen environment. Exothermicity in air was at 210-450ºC

and in oxygen; it was 210-420ºC. In the air environment, peaks are overlapped and it is

difficult to distinguish them. The calculated total heat value in air environment is

5775J/g.

-2

0

2

4

6

8

10

12

14

16

18

20

22

0 100 200 300 400 500

Temperature (OC)

Hea

t Flo

w (W

/g)

In Air

In Oxygen

Fig. 5.20−PDSC of Kenmore Oil #34 and Cutting #34 in Air and Oxygen

Environments

5.2.2 Field B

5.2.2.1 Field B East Part

Cutting-only

The TGA profile of supplied rock cutting samples of Field B at air environment is

represented in Fig. 5.21. The test showed that mass was lost over the temperature

range, up to ≈ 4% of the original mass when 600ºC was reached. The mass loss was


64

likely due to a small amount of bound water present in the sample. The results indicate

that cuttings of Field B are inert in both air and nitrogen environments.

-5

-4

-3

-2

-1

0

1

0 100 200 300 400 500 600

Temperature,°C

Wei

ght C

hang

e,%

0

0.005

0.01

0.015

0.02

0.025

Der

riv. W

eigh

t, %

/C

EM#21-220/250EM#22-120/130EM#22-220/250EM#33-120/130DTG of EM#21DTG of EM#23DTG of EM#22-120/130DTG of EM#22 -220/250

Fig. 5.21−TGA of Cutting Samples of Field B in Air Environment

Fig. 5.22 shows the PDSC result of East portion rock cutting in air environment.

According to this heat-flow curve, the distinct region of exothermic activity of E-22 rock

cutting in air environment, occurring between 180 and 250ºC with an evolved heat of 43

J/g and maximum peak temperature was 212 ºC. This result indicated that the Field B

rock cutting itself has exothermic effects that may be an advantage for oil oxidation at air

injection.


65

-0.5

0

0.5

1

1.5

2

2.5

0 50 100 150 200 250 300 350 400 450 500

Temperature, oC

Hea

t Flo

w, W

/g

Fig. 5.22−PDSC of E-22 Rock Cutting in Air Environment

Oil-Only

Fig. 5.23 presents the TGA results of E#13 oil in air and nitrogen environments. In the

presence of air, mass was lost more or less consistently over the full heating program

and at the end of the experiment 99.9% of it disappeared. In the nitrogen environment,

mass was lost consistently throughout the temperature programme until 400ºC by which

temperature rang more than 99% of oil has evaporated. The final 1% of the sample was

evaporated by 600ºC and this plot resembles that of the baseline. This is due to the very

light nature of the Field B oil (API gravity 45.5°).


66

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Temperature, °C

Wei

ght C

hang

e, %

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Der

iv. W

eigh

t, %

/°C

TGA @ AirTGA @ N2DTG @ AirDTG @ N2

Fig. 5.23−TGA of E #13 Oil in Air and Nitrogen Environments

Due to the evaporative nature of crude oil and apparatus restrictions, it was not possible

to take the normal DSC test in air environment at the atmospheric pressure, thus

pressurised DSC test was done at 1000kPa and 4500kPa. Fig. 5.24 shows the heat flow

profile of E #13 at the pressure of 1000kPa and 4500 kPa in air environment. The heat-

flow curve indicates the reaction character of Field B oil. In the first part of the heat-flow

curve, endothermic activity is present indicating that vaporisation and oxygen addition

reactions are dominating. Bond scission reactions could be occurring at low levels but

they do not become significant until the temperature reaches approximately 200ºC when

the process becomes exothermic. Maximum peak temperature of the exotherm was

234ºC with 2825 J/g heat evolution


67

-5

5

15

25

35

45

55

0 50 100 150 200 250 300 350 400 450 500

Temperature , °C

Hea

t Flo

w, W

/g

WM-13 Oil Only @ 1000 kPa

WM-13 Oil Only @ 4500 kPa

WM-13 Oil + EM-22 Cutting@ 4500 kPa

Fig. 5.24−PDSC of E #13 in Air Environment

Oil-with-Cuttings

Fig. 5.25 compares the oil-only and the oil-with-cutting TGA profiles of the Field B oil in a

flowing nitrogen and air atmosphere at atmospheric pressure. As in the oil E #13 test,

the mass change curve of the cutting-only test was subtracted from oil-with-cutting

combined test. Both tests were performed in the same conditions. This ensures that the

profiles shown here represent only the hydrocarbon portion of the sample. In the test oil-

only shows higher DTG values than those from oil-with-cutting combined test. The figure

shows that the presence of core resulted in a lower mass loss of the oil portion (cutting

only results had already been subtracted from data). This may be due to the increased

surface area of the cutting facilitating slower vaporization of the oil which occurred in

these tests. During the oil-with-cutting test 82% weight of the oil sample disappears at

330°C, where as at the same temperature, in the oil-only test, the loss is more than 95%

of the oil sample. At 600°C, that is, at the end of test all sample disappears in oil-only

test and near 9% weight is remained at the oil-with-cutting combined tests.


68

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Temperature ,°C

Wei

ght C

hang

e, %

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Der

iv. W

eigh

t, %

/°C

TGA of Oil Only TGA of Oil+RockDTG of Oil OnlyDTG of Oil with Rock

Fig. 5.25−TGA of E #13 Oil and Cutting E#22 in Air Environment—Mass loss as a

percentage of weight of oil

High pressure (4500 kPa) DSC analysis of the east part of Field B oil with cutting

showed that at approximately 170ºC, the process becomes exothermic (heat

generating). This temperature is significantly less than the onset temperature of 200ºC

observed in the same atmosphere in oil-only tests. Thus, the cutting materials

accelerate the bond scission reactions occurring at low temperature and leads to earlier

onset of exothermicity. PDSC curve pointed out that the process is endothermic up to

approximately 170ºC (as Fig. 5.24). This endothermic behaviour indicates evaporation

and oxygen addition reactions. Bond scission reaction started from 200ºC up to 250ºC.

The heat evolved in air environment is calculated at 4251 J/g and peak temperature is

205ºC.


69

5.2.2.2 Field B West Region

Oil-Only

The mass change profile of W#3 and W#5 is shown in Fig. 5.26 and 5.27, respectively.

As evident from Fig. 26, the test of W #3 in the air environment, the mass drops steadily

until only 2% remains by about 330°C and at the end (i.e., at 600ºC), 1% oil sample

remains. The similar type of result in air and nitrogen environments was obtained in

W#5, as seen in Fig. 27. The DTG values are similar in air and nitrogen environments

and they touch the baseline at 300°C.

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Temperature, oC

Wei

ght C

hang

e, %

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Der

iv. W

eigh

t, %

/oC


Fig. 5.26−TGA of W #3 Oil in Air and N2 Environments


70

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Der

iv. W

eigh

t, %

/°C

Wei

ght C

hang

e, %

Temperature,°C


Fig. 5.27−TGA of W #5 Oil in Air and N2 Environments

The heat-flow profile of the oil W #3 at pressure 1000 kPa and 4500 kPa with air is

illustrated in Fig. 5.28. The first part of this heat-flow curve demonstrates endothermic

activity, indicating that vaporisation and oxygen addition reactions could have taken

place. Bond scission reactions appear between approximately 210º–250ºC when the

process becomes exothermic. The maximum peak temperature at 1000 kPa was 229°C

with evolved heat value 1400 J/g. At high pressure (4500kPa), exotherm peaks were

shifted to lower temperature range; the exotherm was shown between 200°C and 240°C

where maximum peak temperature was 222°C with evolved heat value 2144J/g.


71

-5

0

5

10

15

20

25

30

0 50 100 150 200 250 300 350 400 450 500

Temperature,°C

Hea

t Flo

w, W

/g

Oil Only @ 1000 kPaOil Only @ 4500 kPa

Fig. 5.28−DSC of W #3 Oil in Air Environment

The heat-flow profile of the oil W #5 at pressure 1000 kPa and 4500 kPa with air

illustrate similar type of result of W #3 (see Fig. 5.29). At low pressure (1000 kPa), the

heat-flow curve exhibits endothermic activity and then bond scission reactions appear

between approximately 210º–250ºC when process becomes exothermic. At this

pressure maximum peak temperature was 230°C with evolved heat 1429J/g. At high

pressure (4500kPa), exotherm peaks were shifted to lower temperature range; the

exotherm was shown between 200°C and 240°C. The maximum peak temperature was

218°C with evolved heat value 2118J/g. This shifting of temperature indicates that

pressure accelerates the bond scission reactions. At high pressure, the heat evolution

of the lower temperature region is greatly increased while the higher temperature region

was decreased. It is possible that some of the higher temperature reactions are now

occurring in the lower temperature region.


72

-5

0

5

10

15

20

25

30

0 100 200 300 400 500Temperature,°C

Hea

t Flo

w, W

/g

DSC Oil Only @ 1000 kPa


Fig. 5.29−PDSC of W #5 in Air Environment

Oil-with-Cuttings

The percentage of mass change is plotted against temperature as a percentage of

original mass of oil. Also the data from the corresponding cutting-only test have been

subtracted from the data from oil-with-cutting combined test so that the observed trends

reflect only the behaviour of oils (details on Fig. 5.30). Fig. 5.31 & Fig. 5.32 compare the

profiles of the oil-only and oil-with-cuttings TGA tests performed on W #3 and W #5 in

the presence of air. Both sets of curves show continuous mass loss until 300ºC -- 90%

of oil in the oil-only test, and 85% of W #3 oil and 80% in W #5 oil in the oil-with-cutting

combined test evaporated. At the end of test (i.e., at 600°C), 10-12% of oil was

remained in the oil-with-cutting combined test while 0.5-1% of oil was present in the oil-

only test. It is possible that the oil gets adsorbed on the surface of the cutting material

and thus the oil in the oil with cutting combined test evaporates more slowly.


73

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Temperature,°C

Wei

ght C

hang

e %

Rock onlyOil+Rock -- (Total Wt)Oil+Rock-- (Oil wt & after rock effect)Oil+Rock-- (Oil Wt & Total effect)"Oil Only

Fig. 5.30−Details of TGA of W #3 Oil in Air Environment

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Der

iv. W

eigh

t, %/o

C

Wei

ght C

hang

e, %

Temperature, oC

TGA @ AirTGA @ Oil+RockDTG @ AirDTG @ Oil+Rock

Fig. 5.31−TGA of W #3 Oil and Cutting E#22 in Air Environment—Mass loss as a

percentage of weight of oil


74

Fig. 5.33 & Fig. 5.34 show the pressurised heat-flow curve in air environment of W #3 &

W #5 oil only, and oil with rock cutting where oil was ≈10 mass%. Two regions,

endothermic and exothermic were seen in the plot. Endothermic region was observed

up to 200ºC. This is likely due to distillation or evaporation of lighter components in the

oil. Two exothermic regions, arising from bond scissions reaction indicate the heat flow

in the process. In W #3, the maximum peak temperatures are 207ºC and the heat

evolved was 1668J/g. In W #5, the maximum peak temperature is 210ºC and evolved

heat was1573J/g.

-110

-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

0

10

0 100 200 300 400 500 600

Temperature,°C

Wei

ght C

hang

e, %

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Der

iv. W

eigh

t, %

/°C

TGA of Oil

TGA of Oil + Rock

DTG of Oil

DTG of Oil+Rock

Fig. 5.32−TGA of W #5 Oil and Cutting E#22 in Air Environment—Mass loss as a percentage of weight of oil

In both the W #3 and W #5 the heat-flow curve of oil with cutting combined tests,

exothermicity shifts to the lower temperature range. Also, these exothermic peaks are

broader than oil-only tests. This is due to bond scission reactions likely occurring at

lower temperature level. Also, it is possible that some of higher temperature reactions

were accelerated so much they lower temperatures and were accelerated so much they

shifted to lower temperatures.


75

-5

0

5

10

15

20

25

30

0 100 200 300 400 500

Temperature,°C

Hea

t Flo

w, W

/g

Oil Only @ 4500 kPa

Oil + Cutting @ 4500 kPa

Fig. 5.33−PDSC of W #3 with Rock Cuttings in Air Environment

-5

0

5

10

15

20

25

30

0 50 100 150 200 250 300 350 400 450 500

Temperature,°C

Hea

t Flo

w, W

/g


DSC Oil + Rock @ 4500 kPa

Fig. 5.34−PDSC of W #5 with Rock Cuttings in Air Environment

76

Chapter 6 ANALYSIS OF RESULTS AND DISCUSSIONS

The results of experimental investigations conducted on Kenmore and Field B reservoir

samples are discussed in this chapter. After presentation of individual results for each

oil, the physical and thermal analysis experimental results, followed by the effects of

rock cutting and operating pressure on the oxidation process are presented. Based on

the respective thermograms obtained in the experiments, kinetic parameters are

calculated and presented.

6.1 Discussions on Physical Test Results

6.1.1 Specific Gravity & Viscosity The specific gravity of the Kenmore crude oil sample is 0.78 and Field B crude oil’ is

0.79. The resultant API gravity of Kenmore oil is 48.7° and Field B is 45.5°. Also, both

reservoirs are high temperature (Kenmore, 92ºC; Field B, 63ºC) and the TGA tests

shown that the crude oils start to evaporate from temperature 40-50ºC. Therefore, at the

higher temperature in the reservoir condition, the actual viscosity will be lower than

instrument measured viscosity. Viscosity and API gravity results indicate the light nature

of these two oils. Due to this light nature, these reservoirs could be potential candidate

for the implementation of air injection.

6.1.2 Compositional Analysis The hydrocarbon distribution of Kenmore crude oil indicates a substantial amount (i.e.,

84mole %) of compounds in the lower carbon numbers of n-C5 to n-C13. Reservoir B

crude oil indicates 95mole% of lower carbon number (n-C4 to n-C19) compounds. These

lighter components may contribute favourably towards efficient oxidation. However, it is

also to be borne in mind that a too high content of lighter ends in the oil may also result

in a lower fuel load. Generally, low molecular weight oil gives the fastest mass loss from

heavy crude oil. The thermo-oxidative characteristic of paraffinic oils has a strong

correlation with their molecular weight or carbon number; the extent of exothermic

reactions increases in low and high temperature range. Therefore, one must carefully

weigh and balance the benefits of oil compositions.

Chapter 6: Analysis of Results and Discussions

77

6.2 Discussions on Thermal Test Results In light of the objective of this study, mass loss and heat generation are the two main

measured parameters. Mass loss characteristics are discussed in this section which is

supported by the TGA plots measured from the tested samples. Heat generation

analysis is also discussed in the DSC profile of tested samples. This discussion helps to

better understand the oxidation behaviours of Kenmore and Field B reservoirs crude

oils.

6.2.1 Kenmore Oils

6.2.1.1 Cuttings-Only

The cuttings exhibit minimal thermal properties, both in air and nitrogen environments.

During the heating programme Kenmore cuttings #31, #34 and #36 give similar results;

the sample loses 5-6% of its mass in air or nitrogen most likely due to loss of bound

water from the sample. The high-pressure DSC test on cutting samples in air and

oxygen indicates two distinct exothermic regions. The dominant region peaks at around

260ºC and the minor region peaks around 400 ºC. These results indicate that the cutting

material does not undergo a significant oxidation process under these conditions.

However, as the exothermic oxidation reactions provide energy the cutting materials

may have a positive impact on the oxidation reactions.

6.2.1.2 Oil-only

In air and nitrogen environments, it is seen that most of the mass of the sample has left

the pan once temperature rises to 265ºC; hence the fuel remains for reactions in the

high temperature range is limited. This is due to the light nature of Kenmore crude oil.

In atmospheric pressure, normal DSC tests are conducted up to 350ºC. The first part of

this DSC curve indicates endothermic nature of the process which is the indication of

evaporation and distillations. Exothermic activity is observed approximately at 240ºC,

from where the bond scission reactions significantly continued until the temperature

reaches 290ºC. In the endothermic region a significant amount of mass is lost. Thus,

from the TGA and DSC curve it is concluded that evaporation/distillation is a dominant

physical phenomenon in the low temperature range.

At an elevated pressure, this exothermicity is shifted to a lower temperature range.

There are three peaks of oxidation in an oxygen environment at the high pressure, in the


78

temperature ranges of about 200-280ºC, about 300-340ºC and about 350-450ºC. The

first peak dominates the energy liberation evolving more than 95% of the heat, while the

remaining heat is liberated at the higher temperature peaks. The heat release is higher

in the low temperature range, the result of not enough fuel left for the reaction in the high

temperature range. In high-pressure air environment, compare to oxygen environment,

exothermicity is shifted to higher temperature. However, at high pressure, the

exothermic behaviour appears at a lower temperature than normal pressure

environment. The shifting of the peak to lower temperature indicates that the pressure

accelerates the oxidation reactions.

6.2.1.3 Oil-with-Cuttings

In both the presence and absence of cutting, the oil appears to undergo evaporation. In

the presence of rock cutting the mass loss occurs more slowly than in the absence of

cutting. It is possible that the oil gets adsorbed on the surface of the cutting materials

and thus evaporates more slowly. The heat-flow curve of oil-with-cuttings combined test

shows different behaviours to those without the cuttings. The oil-with-cuttings test gives

two indistinct exothermic heat-flow regions. The first peak appears at about 200-280ºC

temperature zone but it is wider than the peak observed in the oil-only test. It is possible

that the oil adsorbed on cutting surface gets desorbed in this temperature range. Also,

the desorbed oil may get oxidised and increase the exothermic activity. The oil-with-

cutting exotherms evolved more heat compared to the oil-only exotherms. These

observations indicate that cutting material accelerates oxidation reactions because of

availability more surface area.

Bond session reactions in the air environment are shifted towards a higher temperature

and exothermic peaks are wider than oxygen environments. It is possibly, air has 79%

nitrogen; this nitrogen may absorb heat and shift exothermicity to a higher temperature.

6.2.2 Oils of Field B

6.2.2.1 Cuttings-Only

The cuttings exhibit negligible thermal properties, in both air and nitrogen environments.

During the heating programme cuttings #21, #22 and #33 give similar results; the

sample loses 4-5% of its original mass in air or nitrogen, it is probably due to loss of

moisture from the sample.


79

The high-pressure DSC test on cutting samples in air indicates a distinct exothermic

region, which peaks at around 200ºC. As these exothermic oxidation reactions provide

energy, the cutting materials may have a positive impact on the oxidation reaction.

6.2.2.2 Oil-only

In air and nitrogen environments, 90-95% mass is lost by the temperature 330ºC. This

is due to the light nature of Field B crude oil. Pressurised DSC tests are conducted up

to 500ºC. The first part of these heat-flow curves indicates the endothermic nature of the

process which is indicates the occurrence of the evaporation, distillation or oxygen

addition reactions. The exothermic activity is observed approximately at 180-200ºC,

from where the bond scission reactions significantly continued until 290ºC. By the

endothermic temperature range more than 60% mass is lost. It is evident that

evaporation/distillation is the dominant physical mechanism at the low temperature

range. This is due to the Field B oil’s paraffinic nature.

Pressure largely affects the oxidation reactions. The effect of pressure has marked an

influence on the heat generation in the low temperature range. With increasing pressure,

a faster rate of heat generation and a greater amount of heat generation are observed in

the low temperature range. At the elevated pressure the exothermicity is shifted to a

lower temperature range. The shifting of the peak to lower temperature indicates that

pressure accelerates the oxidation reactions. The elevated exothermic activity in the

low temperature range due to the increase in pressure is possibly associated with bond

scission reactions or combustion reactions of the distilled fraction in the vapour phase.

6.2.2.3 Oil-with-Cuttings

In both the presence and absence of cutting, the oil seems to be undergoing

evaporation. In the presence of rock cutting the mass loss occurs more slowly than in

the absence of cutting. It could be because of slow evaporation of adsorbed on the

surface of the cutting materials. The heat-flow curve of oil-with-cuttings combined test

shows different behaviours to those without the cuttings.

The oil-with-cuttings gives two indistinct heat-flow regions. The first part of the heat-flow

curve indicates endothermic activity due to vaporisation and oxygen addition reactions.

The exothermic peak appears at about 180ºC but the peak is observed at 200ºC in the


80

oil-only test. It is possible that the oil was adsorbed on cutting surface previously which

is desorbed in this temperature range. Also, the desorbed oil may get oxidised and

increase the exothermic activity. The oil-with-cutting exotherms evolved more heat

compared to oil-only exotherms. These observations indicate that cutting material

accelerates oxidation reactions. Lower activation energy in oil with cutting combined test

is also another indication that rock cutting has considerable positive impact on ignition

process.

6.3 Kinetic Parameters Mass loss kinetics during combustion reactions is a complex phenomenon. Both

reservoirs, the Kenmore and Field B have shown strong trends of distillation in low

temperature range wherein evaporation or distillation is an important factor in regarded

to mass loss characteristics for light oil. These distillate fractions may not participate in

the oxidation reactions. Therefore, it is a challenge to obtain kinetic parameters

accurately from the TGA results. In this study, Coats and Redfern method is used to

calculate kinetic parameters (i.e., activation energy and order of reaction) of combustion

reactions, which is applied to TGA data, assuming the order of reactions. The correct

order is presumed to lead to the best linear plot, from which the activation energy is

determined.

The reaction temperature range, peak temperature and calculated activation energy of

Kenmore and Field B reservoirs samples are resembled in Table 6.1. Reaction

temperature range and peak temperatures are obtained from DSC tests; activation

energy is calculated by trail on error to match the experimental TGA data. Calculated

activation energy for Kenmore oil-only test is 96 KJ/mole and in oil with cutting test is 68

KJ/mole. In the Field B samples activation energy of combustion reactions in oil only test

is 95 KJ/mole and oil with cutting tests show 84 KJ/mole to activate the reactions.

Adding rock cuttings decrease the activation energy. This observation indicates that

cutting material accelerates combustion reactions.


81

Table 6.1−Kinetic Parameters

Reservoir Sample Well Reaction

Range (°C)

Peak Temperature

(°C)

E (KJ/mole)

Calculated Average

Kenmore

Oil only

Kenmore

Oil #32

225-

280 239 91.74

96 Kenmore

Oil #34

200-

280 219 101.14

Oil +

Rock

Kenmore

Oil #32 - 264 71.36

68 Kenmore

Oil #34 - - 64.51

Field B

Oil only

WM-3 200-

240 222 77.49

95 WM-5

200-

240 218 102.77

EM-13 234 105.08

Oil +

Rock

WM-3 207 70.03

84 WM-5 210 82.49

EM-13 190-

250 205 99.76

82

Chapter 7 CONCLUSIONS AND RECOMMENDATIONS

This chapter summarizes the conclusions based on the experiments in this work. Also,

some recommendations are listed with this study for future work.

7.1 Conclusions In the light of the objectives studied, the thermal behaviour of two Australian light oil

reservoirs is established in air and nitrogen environments at different pressures. The key

findings are discussed below:

1. The oxidation behaviours of light oils were tested using TGA/DSC; the

important information is given below.

i. In the low temperature range, the vaporization of light oil is a

dominant physical phenomenon. The maximum rate of heat

generation and amount of heat generated occurs in the low

temperature range, and the majority of the fuel was consumed in

the low temperature range.

ii. In the high temperature range, the combustion reactions are very

weak due to insufficient fuel is available for oxidation reactions.

2. The addition of rock cuttings to the crude oil sample was shown to decrease

the reaction temperatures of the bond scission reaction region.

3. The elevated pressure accelerated bond scission reactions, as evidenced

by the shifting of exothermicity to lower temperatures was compared to

what was experienced at the atmospheric pressure. This pressure effect

has a noticeable influence at the low temperature range.

4. The chemical and physical processes involved in the oxidation of crude oils

are very complex. Interpretation of the results from this test suggests the

possibility of different groups of chemical reactions occurring in the two

temperature regions. Reactions in the endothermic zone are attributed to

Chapter 7: Conclusions and Recommendations

83

evaporation, distillation and thermolysis and in the exothermic zone to low

temperature oxidation, pyrolysis and high temperature oxidation.

5. The heat flow and mass loss profiles of crude oil samples showed that the

bond scission reactions did not cause a sudden increase in the rate of mass

loss. Also, mass loss profiles in air and nitrogen atmosphere were very

similar. Therefore, it is concluded that bond session reaction may occur in

the vapour phase as well.

6. The physical analysis indicated that Kenmore and Reservoir B crude oils

are light oils. Kenmore crude oil contains n-C5 to n-C21 compounds where

n-C5 to n-C13 compounds together contain about 84 mole% of its

composition. Reservoir B crude oil has n-C4 to n-C28 compounds with n-C4

to n-C19 compounds of 95 mole% of its composition.

7. TGA tests on reservoirs rock cutting samples showed little reactivity in air

environment over the temperature range from ambient to 600ºC. There was

an evidence of moisture loss at high temperature.

8. Kenmore and Reservoir B are high temperature and the light oil reservoir

could be the potential candidate for implementation of air injection. Both

reservoirs demonstrated favourable exothermic behaviour at a temperature

less than 300°C. The presence of rock cutting has resulted in an exothermic

response relatively at the low temperature and it may carry on having a

lower ignition temperature. With regard to mass loss characteristics, it was

noted that:

Kenmore Reservoir: • TGA tests on oil only samples in air and nitrogen environments

showed 95% mass loss within temperature range of 260-265ºC

while in the same temperature range oil with rock cutting

combined tests showed 85-90% mass loss. Possibly, it is

because of the oil adsorption on the surface of the cutting

material resulting in a slow evaporation.

• Heat flow and mass loss profiles of Kenmore crude oil samples

showed that the bond scission reactions did not cause a sudden

increase in the rate of mass loss. Also, mass loss profiles in air


84

and nitrogen atmosphere were very similar. Therefore, it is

concluded that bond session reaction may occur in the vapour

phase as well.

Reservoir B:

• Heat flow profiles of Reservoir B crude oil samples showed

that the bond scission reactions occur in 200-300ºC where

as in the same environment, oil with cutting tests bond

scission reactions occur in at lower temperature range 180-

280ºC. Therefore, it is concluded that the cutting material

accelerated bond scission reactions.

• The oil only TGA tests of Reservoir B oil in air and nitrogen

environments showed 95% mass loss within the temperature

range of 320-330ºC while at the same temperature range oil

with rock cutting combined tests showed 80-85% mass loss.

Oil was adsorbed on the surface of the cutting material

resulting in a slow evaporation.

7.2 Recommendations In order to further understand the oxidation behaviour of reservoir fluids, further

investigations are necessary. Recommendations based on the research carried out under

the present study are summarized below.

1. In this study, high-pressure thermal tests were performed at the maximum

pressure of 4500kPa to study the application of these tests to the target

reservoir. It is recommended to investigate the oxidation behaviour at

reservoir temperature and pressure conditions.

2. In order to screen the properties of these two reservoirs for air injection

implementation, further studies should be conducted to determine a number

of important parameters/characteristics notably, spontaneous ignition

capability of the candidate oil with high-pressure air (O2), critical design


85

parameters such as Arrhenius activation energy, air flux requirements

(compressor rating), and stoichiometric coefficients.

3. It is recommended to carry out the thermal analysis tests in combination

with effluent gas stream analysis, which can provide the information for a

better understanding of the nature of oxidation reactions. Gas analysis in

association with mass change and heat release information would

significantly help to identify the temperatures at which oxygen addition,

bond scission reaction, thermal cracking reaction and high temperature

reaction occur.

4. In the current study, all thermal analysis tests were performed using

TGA/DSC. To characterize in-situ combustion potential of crude oil, and to

determine the spontaneous ignition in the reservoir upon air injection the

Accelerating Rate Calorimeter (ARC) test is recommended. Also, the

design parameters (pre-exponential factor, Ea in particular) can be

estimated through these tests for simulation studies.

5. The combustion tube test is recommended for the propagation of a

combustion front under a given air injection flux and it would determine the

amount of injected air needed to process a unit volume of the reservoir. The

combustion tube test mimics the operation of in-situ combustion in the

reservoir. This test also determines other important process parameters

such as atomic H/C ratio of burned fuel, peak temperature; fuel lay down,

overall combustion stoichiometry, air-fuel ratio, and oxygen utilization in

terms of O2-fuel and O2-sand ratios, liquid HC (oil) recovery and

characteristics of produced fluids/emulsions.

6. To conduct a performance prediction study, incorporating field history and

laboratory test data generation through the aforementioned tests, a

simulation study is recommended. Simulation studies will aid in project

design and development, and will also provide insight into its economic

evaluation.

86

References

Adetunji, L.A., Teigland, R. and Kleppe, J., 2005. Light-Oil Air-Injection Performance:

Sensitivity to Critical Parameters. Paper SPE 96844 presented at the SPE Annual

Technical Conference and Exhibition, Dallas, Texas, U.S.A.., October 9-12.

Alexander, J.D., Martin, W.L. and Dew, J.N., 1962. Factors Affecting Fuel Availability and

Combustion During In situ Combustion. JPT: 1154-1162. SPE-296.

Awan, A.R., Teigland, R. and Kleppe, J., 2006. EOR Survey in the North Sea. Paper SPE

99546 presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa,

Oklahoma, U.S.A..: April 22-26.

Bae, J.H., 1977. Characterization of Crude Oil for Fireflooding Using Thermal Analysis

Methods. SPEJ (June): 211-218. SPE-6173.

Benham, A.L. and Poettmann, F.H., 1958. The Thermal Recovery Process-An Analysis of

Laboratory Combustion Data. JPT: 83-85 SPE-1022.

Bousaid, I.S. and Ramey Jr, H.J., 1968. Oxidation of Crude Oil in Porous Media. SPEJ

(June): 137-148. SPE-1937.

Burger, J.G., 1976. Spontaneous ignition in Oil Reservoirs. SPEJ (April): 73-81. SPE-

5455.

Burger, J.G. and Sahuquet, B.C., 1972. Chemical Aspect of In-situ Combustion - Heat of

Combustion and Kinetics. Paper SPE-3599 presented at the SPE 46th Annual Fall

Meeting, New Orleans, October 3-6.

Ciajolo, A. and Barbella, R., 1984. Pyrolysis and Oxidation of Heavy Fuel Oils and Their

Fractions in a Thermogravimetric Apparatus. Fuel, 63(May): 657661.

Clara, C., Durandeau, M., Quenault, G. and Nguyen, T.H., 2000. Laboratory Studies for

Light Oil Air Injection Projects: Potential Application in Handil Field. SPEREE, 3(3):

239-248. SPE -64272.

Clara, C., Zelenko, V., P. Schirmer and Wolter, T., 1998. Appraisal of the Horse Creek Air

Injection Project Performance Paper SPE 49519 presented at the 8th Abu Dhabi

International Petroleum Exhibition & Conference, Abu Dhabi, United Arab

Emirates, October 11-14.

Coats, A.W. and Redfern, J.P., 1964. Kinetic Parameters from Thermo Gravimetric Data.

Nature, 201(January): 68-69.

Dabbous, M.K. and Fulton, P.F., 1974. Low-Temperature-Oxidation Reaction Kinetics and

Effects on the In-situ Combustion Process. SPEJ (June) 253-262. SPE-4143.

Reference

87

Dharwadkar, S.R., Chandrasekharaiah, M.S. and Karkhanavala, M.D., 1978. Evaluation of

Kinetic Parameters from Thermogravimetric Curves. Thermochimica Acta, 25: 372-

375.

Drici, O. and Vossoughi, S., 1985. Study of the Surface Area Effect on Crude Oil

Combustion by Thermal Analysis Techniques. SPEJ: 731-735. SPE 13389.

Fassihi, M.R., 1992. Improved Phase Behaviour Representation for Simulation of Thermal

Recovery of Light Oils, Paper SPE 24034 presented at the Western Regional

Meeting, Bakersfield, California, March 30-April 1.

Fassihi, M.R., Brigham, W.E. and Ramey Jr., H.J., 1984. Reaction Kinetics of In-situ

Combustion: Part 2-Modeling. Paper SPE-9454 presented at the SPE Annual

Technical Conference and Exhibition, Dallas, Texas, September 21-24.

Fassihi, M.R., Brigham, W.E. and Ramey Jr., H.J., 1983. Reaction Kinetics of In-situ

Combustion: Part 1-Observations. Paper SPE-8907 presented at the California

Regional Meeting, Los Angeles, April 9-11.

Fassihi, M.R. and Gillham, T.H., 1993. The Use of Air Injection to Improve the Double

Displacement Processes. Paper SPE-26374 presented at the 68th Annual

Technical Conference and Exhibition of the Society of Petroleum Engineers,

Houston, Texas, October 3-8.

Fassihi, M.R., Gillham, T.H., Yannimaras, D.V. and Hasan, D., 1996. Field Tests Assess

Novel Air-Injection EOR Processes. Oil & Gas J. (May 20): 69-72.

Fassihi, M.R., Yannimaras, D.V. and Kumar, V.K., 1997. Estimation of Recovery Factor in

Light-Oil Air-Injection Projects. SPERE (August): 173 - 178. SPE-28733.

Fassihi, M.R., Yannimaras, D.V., Westfall, E.E. and Gillham, T.H., 1996. Economics of

Light Oil Air Injection Projects. Paper SPE/DOE-35393 presented at the SPE/DOE

Tenth Symposium on Improved Oil Recovery, Tulsa, Oklahoma, April 21-24.

Ferguson, H.A., Mehta, S.A., Moore, R.G., Okazawa, N.E. and Ursenbach, M.G., 2003.

Oxidation Characteristics of Light Hydrocarbons for Underbalanced Drilling

Applications. Journal of Energy Resources Technology, 125: 177-182.

Fraim, M.L., Moffitt, P.D. and Yannimaras, D.V., 1997. Laboratory Testing and Simulation

Results for High Pressure Air Injection in a Waterflooded North Sea Oil Reservoir,

Paper SPE 38905 presented at the SPE Annual Technical Conference &

Exhibition, San Antonio, U.S.A., October 5-8.

Freeman, E.S. and Carroll, B., 1958. The Application of Thermoanalytical Techniques to

Reaction Kinetics; The Thermogravimetric Evaluation of the Kinetics of the

Decomposition of Calcium Oxalate Monohydrate. Journal of Physical Chemistry,

62: 394-397.

Reference

88

Gallagher, P.K., 1997. Thermoanalytical Instrumentation, Techniques, and Methodology.

In: E.A. Turi (Editor), Thermal Characterization of Polymeric Materials. Academic

Press, Inc., California, pp. 1-203.

Gates, C.F. and Ramey Jr., H.J., 1978. A Method for Engineering In-situ Combustion Oil

Recovery Projects. Paper SPE-7149 presented at the SPE 48th Annual California

Regional Meeting, San Francisco, April 12-14.

Germain, P. and Geyelin, J.L., 1997. Air Injection into a Light Oil Reservoir: The Horse

Creek Project, Paper SPE 37782 presented at the SPE Meddle East Oil Show,

Bahrain, March 15-18.

Gillham, T.H., Cerveny, B.W., Fornea, M.A. and Bassiouni, D.Z., 1998. Low Cost IOR: An

Update on the W. Hackberry Air Injection Project. Paper SPE-39642 presented at

the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April 19-22.

Gillham, T.H., Cerveny, B.W., Turek, E.A. and Yannimaras, D.V., 1997. Keys to Increasing

Production via Air Injection in Gulf Coast Light Oil Reservoirs. Paper SPE-38848

presented at the SPE Annual Technical Conference and Exhibition, San Antonio,

Texas, October 5-8.

Greaves, M., Ren, S.R. and Rathbone, R.R., 1998. Air Injection Technique (LTO Process)

for IOR from Light Oil Reservoirs: Oxidation Rate and Displacement Studies. Paper

SPE-40062 presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa,

Oklahoma, April 19-22.

Greaves, M., Ren, S.R., Rathbone, R.R., Fishlock, T. and Ireland, R., 2000. Improved

Residual Light Oil Recovery by Air Injection (LTO Process). J. Cdn. Pet. Tech.,

39(1): 57-61.

Greaves, M., Wilson, A., Al-Honi, M. and Lockett, A.D., 1996. Improved Recovery of Light /

Medium Heavy Oils in Heterogeneous Reservoirs Using Air Injection / In-situ

Combustion (ISC). Paper SPE-35693 presented at the Western Regional Meeting

held in Amhorage, Alaska, May 22-24.

Gutierrez, D., Taylor A.R., Kumar V.K., Ursenbach M.G., Moore R.G., Mehta S.A., 2007.

Recovery Factor in High-Pressure Air Injection Projects Revisited, Paper SPE

108429 presented at the SPE Annual Technical Conference and Exhibition,

Anaheim, California, U.S.A., November 11-14.

He, B., Chen, Q., Castanier, L.M. and Kovscek, A.R. Improved In-Situ Combustion

Performance With Metallic Salt Additives. Paper SPE 93901 presented at the SPE

Western Regional Meeting, Irvine, CA, U.S.A., March 30-April 1.

Reference

89

Huffman, G.A., Benton, J.P., El-Messidi, A.E. and Riley, K.M., 1983. Pressure

Maintenance by In-situ Combustion, West Heidelberg Unit, Jasper County,

Mississippi. JPT (October): 1877-1883. SPE 10247.

Hughes, B.L. and Sarma, H.K., 2006. Burning Reserves For Greater Recovery? Air

Injection Potential In Australian Light Oil Reservoirs. Paper SPE-101099 presented

at the SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia,

September 11-13.

Indrijarso, S., Oklany, J.S., Millington, A., Price, D. and Hughes, R., 1996.

Thermogravimetric Studies of Systems Pertinent to In-situ Combustion Process for

Enhanced Oil Recovery. Part-1. Development of a High-Pressure Thermobalance.

Thermochimica Acta, 277: 41-52.

Kharrat, R. and Vossoughi, S., 1985. Feasibility Study of the In-situ Combustion Process

Using TGA/DSC Techniques. JPT (August): 1441-1445.SPE 12678.

Kok, M.V., 2002. Combustion Kinetics of Crude Oils. Energy Sources, Part A: Recovery,

Utilization and Environmental, 24: 1-7.

Kok, M.V. and C.O. Karacan, 2000. Behaviour and Effect of SARA fractions of Oil During

Combustion. SPEREE, 3(5): 380-385. SPE 66021.

Kok, M.V., Hughes, R. and Price, D., 1997. Combustion Characteristics of Crude Oil-

Limestone Mixtures High pressure Thermogravimetric Analysis and Their

Relevance to In-situ Combustion. Journal of Thermal Analysis, 49: 609-615.

Kok, M.V. and Karacan, O., 1998. Pyrolysis Analysis and Kinetics of Crude Oils. Journal of

Thermal Analysis, 52: 781-788.

Kok, M.V. and Keskin, C., 2001. Comparative Combustion Kinetics for In situ Combustion

Process. Thermochimica Acta, 369: 143-147.

Kumar, V.K., Fassihi, M.R. and Yannimaras, D.V., 1995. Case History and Appraisal of the

Medicine Pole Hills Unit Air-Injection Project. SPERE (August): 198-202. SPE-

27792.

Kumar, V.K., Gutierrez, D. and Mehta, S.A., 2007. Case History and Appraisal of the West

Buffalo Red River Unit High-Pressure Air Injection Project. Paper SPE-107715

presented at the SPE Hydrocarbon Economics and Evaluation Symposium, Dallas,

Texas, USA, April 1-3.

Kumar, V.K., Gutierrez, D., Moore, R.G. and Mehta, S.A., 2008. Air Injection and

Waterflood Performance Comparison of Two Adjacent Units in the Buffalo Field.

SPEREE (October): 848-857.

Li, J. Mehta S.A., Moore R.G., Ursenbach M.G., .Ferguson H., Zalewski E., Okazawa N. E., 2002.

The Research of Oxidation and Ignition Behaviour of Saturated Hydrocarbon

Sample With Crude Oils Using TG/DTG and DTA Thermal Analysis Technique.

Reference

90

Paper presented at the Petroleum Society's Canadian International Petroleum

Conference, Calgary, Alberta, Canada, June 11-13.

Mamora, D.D., Ramey Jr, H.J., Brigham, W.E. and Castanier, L.M., 1993. Kinetics of In

situ Combustion SUPRI TR 91, Stanford, CA.

Mendez-Kuppe, G.J., Mehta, S.A., Moore, R.G., Ursenbach, M.G. and Zalewski, E., 2008.

Heats of Combustion of selected Crude Oils and Their SARA Fractions. J. Cdn.

Pet. Tech., 47(1): 38-42.

Mickelson, R.W. and Einhorn, I.N., 1970. The Kinetics of Polymer Decomposition Through

Thermogravimetric Analysis. Thermochimica Acta, 1: 147-157.

Montes, A.R., Moore, R.G., Mehta, S.A., Ursenbach, M.G. and Gutierrez, D., 2008. Is

High-Pressure Air Injection (HPAI) Simply a Flue-Gas Flood? Paper presented at

the Canadian International Petroleum Conference/SPE Gas Technology

Symposium, Calgary, Alberta, Canada, June 17-19.

Moore, R.G., Mehta, S.A. and Ursenbach, M.G., 2002. A Guide to High Pressure Air

Injection (HPAI) Based Oil Recovery. Paper SPE-75207 presented at the

SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 13-17.

Moore, R.G., Mehta, S.A. and Ursenbach, M.G., 2004. Air Injection-Based IOR for Light

Oil Reservoirs. Technology Platform: Reservoir Engineering, 4(1): 11-17.

Moore, R.G., Mehta, S.A.R., Matthew G. Ursenbach and Laureshen, C.J., 1998.

Strategies for Successful Air Injection-Based IOR Processes. Paper presented at

the 7th UNITAR International Conference for Heavy Crude and Tar Sands, Beijing,

China October 27-30.

Nickle, S.K., Meyers, K.O. and Nash, L.J., 1987. Shortcoming in the Use of TGA/DSC

Techniques to Evaluate In-situ Combustion. Paper SPE-16867 presented at the

62nd Annual Technical Conference and Exhibition of the Society of Petroleum

Engineers, Dallas, TX; USA, September 27-30.

Parrish, D.R., Pollock, C.B. and Craig Jr., F.F., 1974a. Evaluation of COFCAW as a

Tertiary Recovery Method, Sloss Field, Nebraska. JPT (June): 676-686. SPE-3777.

Parrish, D.R., Pollock, C.B., Ness, N.L. and Craig Jr., F.F., 1974b. A Tertiary COFCAW

Pilot Test In the Sloss Field, Nebraska. JPT (June): 667-675. SPE-3839.

Reich, L. and Stivala, S.S., 1978. Kinetic Parameters fro Thermogravimetric Curves.


Ren, S.R., Greaves, M. and Rathbone, R.R., 2002. Air Injection LTO Process: An IOR

Technique for Light-Oil Reservoirs. SPEJ: 90-99. SPE-57005.

Rock, R., 1978. Determination of Kinetic Parameters from Thermogravimetric Data.


Reference

91

Sarathi, P.S., 1998. In-situ Combustion Handbook - Principles and Practices, BDM

Petroleum Technologies Bartlesville, Oklahoma.

Sarma, H.K., Yazawa N., Moore R. G., Methta S. A., Okazawa N. E., Ferguson H., Ursenbach M.

G., 2002. Screening of Three Light-Oil Reservoirs for Application of Air Injection

Process by Accelerating Rate Calorimetric and TG/PDSC Tests. J. Cdn. Pet.

Tech., 41(3): 50-61.

Shallcross, D.C., De Ios Rios, C.F., Castanier, L.M. and Brigham, W.E., 1991. Modifying

In-situ Combustion Performance by the Use of Water-Soluble Additives. SPERE,

August. SPE 19485

Smith, J.M., 1981. Chemical Engineering Kinetics. McGraw-Hill Book Company.

Surguchev, L.M., Koundin, A. and Yannimaras, D., 1999. Air Injection-Cost Effective IOR

Method to Improve Oil Recovery from Depleted and Waterflooded Fields, Paper

SPE 57296 presented at the Asia Pacific Improved Oil Recovery Conference,

October 25-26.

Taber, J.J. and Martin, F.D., 1983. Technical Screening Guides for the Enhanced

Recovery of Oil, Paper SPE 12069 presented at the 58th Annual Technical

Conference and Exhibition San Francisco, CA, October 5-8.

Taber, J.J., Martin, F.D. and Seright, R.S., 1997a. EOR Screening Criteria Revisited-Part

1: Introduction to Screening Criteria and Enhanced Recovery Field Projects.

SPERE (August): 189-198. SPE 35385.

Taber, J.J., Martin, F.D. and Seright, R.S., 1997b. EOR Screening Criteria Revisited-Part

2: Applications and Impact of Oil Prices. SPERE (August): 199-205. SPE 39234.

Takabayashi, K. Onishi T., Okatsu K., Maeda H., Moore R. G., Methta S. A., Ursenbach M. G.,

2008. Study on Minimum Air Flux for In-situ Combustion into Light Oil Reservoir,

Paper SPE 116530 presented at the SPE Asia Pacific Oil & gas Conference and

Exhibition, Perth, Australia, October 20-22.

Turta, A.T. and Singhal, A.K., 2001. Reservoir Engineering Aspects of Light-Oil Recovery

by Air Injection. SPEREE: 336-344. SPE-72503.

Verkoczy, B. and Freitag, N.P., 1997. Oxidation of Heavy Oils and Their SARA Fractions -

Its Role in Modelling In-situ Combustion, Paper presented at the 7th Petroleum

Conference of South Saskatchewan Section, The Petroleum Society of CIM,

Regina, October 19-22.

Verkoczy, B. and Jha, K.N., 1986. TGA/DSC investigations of Saskatchewan heavy oils

and cores. J. Cdn. Pet. Tech. (May-June): 47-54.

Vossoughi, S. and El-Shoubary, Y., 1989. Kinetics of Crude-Oil Coke Combustion.

SPERE, May: 201-205. SPE 16268.

Reference

92

Vossoughi, S., Willhite, G., El-Shoubary, Y. and Bartlett, G., 1983. Study of the Clay Effect

on Crude Oil Combustion by Thermogravimetry and Differential Scanning

Calorimetry. Journal of Thermal Analysis, 27: 17-36.

Vossoughi, S., Willhite, G., Kritikos, W.P. and El-Shoubary, Y., 1982. Development of a

Kinetic Model for In-situ Combustion and Prediction of the Process Variables Using

TGA/DSC Techniques, Paper SPE 11073 presented at the 57th Annual Technical

Conference and Exhibition New Orleans, Louisiana, September 26-29.

Watts, B.C., Hall, T.F. and Petri, D.J., 1997. The Horse Creek Air Injection Project: An

Overview. Paper SPE-38359 presented at the SPE Rocky Mountain Regional

Meeting, Casper, Wyoming: May 18-21.

Yannimaras, D.V. and Tiffin, D.L., 1995. Screening of Oils for In-situ Combustion at

Reservoir Conditions by Accelerating-Rate Calorimetry. SPERE (February): 36-39.

SPE-27791.

Yoshiki, K.S. and Phillips, C.R., 1985. Kinetics of Thermo-oxidative and thermal cracking

reactions of Athabasca bitumen. FUEL, 64(November): 1591-1597.

a study of oxidation reaction kinetics during an air ...€¦ · table 4. 2 oil and cutting samples...

Documents