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
To my mothers love which always encourages me
ii
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
3.1
15
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
iii
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
4.6
Instrument Calibration
38
4.5.1
TGA Calibration
38
4.5.2
DSC Calibration
39
Sample Description
43
4.6.1
Sample Assembly
43
4.6.2
Sample Preparation
44
Chapter 5: EXPERIMENTAL RESULTS
5.1
5.2
45
Physical Tests
45
5.1.1
Specific Gravity
45
5.1.2
Viscosity
45
5.1.3
Compositional Analysis
46
Thermal Tests
46
5.2.1
Kenmore Field
50
5.2.2
Field B
63
Chapter 6: ANALYSIS OF RESULTS AND DISCUSSIONS
6.1
76
Discussions on Physical Test Results
76
6.1.1
Specific Gravity & Viscosity
76
6.1.2
Compositional Analysis
76
iv
6.2
6.3
Discussions on Thermal Test Results
77
6.2.1
Kenmore Oils
77
6.2.2
Oils of Field B
78
Kinetic Parameters
80
Chapter 7: CONCLUSIONS AND RECOMMENDATIONS
82
7.1
Conclusions
83
7.2
Recommendations
84
REFERENCES
86
v
LIST OF TABLES
Table 2. 1
Table 2. 2
Reservoir Properties of Prospective Basins in Australia
Cooper-Eromanga Basin–Oil Reservoir Properties
12
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
vi
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
vii
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
viii
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
ix
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.
x
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.
xi
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
xii
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
xiii
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.
xiv
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.
xv
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, hightemperature (>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
1
Chapter 1: Introduction 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.
2
Chapter 1: Introduction 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
3
Chapter 1: Introduction 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.
4
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 insitu 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 repressurization are significant incremental recovery mechanisms (Clara et al., 2000;
Greaves et al., 1996; Hughes and Sarma, 2006; Turta and Singhal, 2001). However, in
5
Chapter 2: Research Background
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 oxygenatedhydrocarbon 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).
6 Chapter 2: Research Background
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 oilviscosity 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
7 Chapter 2: Research Background
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.
8 Chapter 2: Research Background
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.
9 Chapter 2: Research Background
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).
10 Chapter 2: Research Background
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 SuratBowen 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.
11 Chapter 2: Research Background
Table2.1: General Reservoir Properties of Prospective Basins for Air Injection in
Australia (Hughes and Sarma, 2006)
Basin
Screening
Carnarvon
Cooper
Suart-Bowen
Criteria
(Barrow Island)
Eromanga
(Moonie)
NOTE:
This table is included on page 12
of the print copy of the thesis held in
the University of Adelaide Library.
12 Chapter 2: Research Background
___________________________________________________________________
Table 2.2: Cooper-Eromanga Basin–Oil Reservoir Properties (Hughes and Sarma, 2006)
NOTE:
This table is included on page 13
of the print copy of the thesis held in
the University of Adelaide Library.
13
Chapter 2: Research Background
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.
14
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
15
Chapter 3: Theoretical Aspects of Air Injection
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.
16
Chapter 3: Theoretical Aspects of Air Injection
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):
17
Chapter 3: Theoretical Aspects of Air Injection
n
⎡ m n⎤
CH n + ⎢1 − + ⎥O2 → [1 − m]CO2 + mCO + H 2 O
2
⎣ 2 2⎦
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 insitu 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)
18
Chapter 3: Theoretical Aspects of Air Injection
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.
19
Chapter 3: Theoretical Aspects of Air Injection
NOTE:
This figure is included on page 20
of the print copy of the thesis held in
the University of Adelaide Library.
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 thermooxidative response. His study indicated that the thermal characteristic of oil is unique
20
Chapter 3: Theoretical Aspects of Air Injection
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 MendezKuppe 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.
21
Chapter 3: Theoretical Aspects of Air Injection
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
22
Chapter 3: Theoretical Aspects of Air Injection
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.
23
Chapter 3: Theoretical Aspects of Air Injection
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.
24
Chapter 3: Theoretical Aspects of Air Injection
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:
Rc = −
dC f
dt
= kPOm2 C nf ………………………………..………… (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)
⎛ E ⎞
k = Ar exp⎜ −
⎟ ………………………………………..………. (3.2)
⎝ RT ⎠
where:
Ar
= Arrhenius constant
E
= activation energy
R
= universal gas constant
Substituting Eq. (2) into Eq. (1) yields:
Rc = −
⎛ E ⎞
= Ar POm2 C nf exp⎜ −
⎟ ………………………….…….. (3.3)
dt
⎝ RT ⎠
dC f
25
Chapter 3: Theoretical Aspects of Air Injection
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:
⎡1 − (1 − α )1− n ⎤
⎡ AR ⎛ 2 RT ⎞⎤ E
…………..……………… (3.4)
ln ⎢
⎜1 −
⎟ −
⎥ = ln ⎢
2
E ⎠⎥⎦ RT
⎣ βE ⎝
⎣ (1 − n )T ⎦
By rearranging, integrating it is obtained the Coats and Redfern (1964) equation.
For all values of n ≠ 1
⎡1 − (1 − α )1− n ⎤
⎡ AR ⎛ 2 RT ⎞⎤ E
……………………………….. (3.5)
= ln ⎢
ln ⎢
⎜1 −
⎟ −
2 ⎥
E ⎠⎥⎦ RT
⎣ βE ⎝
⎣ (1 − n )T ⎦
For n = 1
(1 − α )⎤ = ln ⎡ AR ⎛1 − 2 RT ⎞⎤ − E ……………………………….. (3.6)
⎡
ln ⎢− ln
⎟
⎢ βE ⎜
T 2 ⎥⎦
E ⎠⎥⎦ RT
⎣
⎝
⎣
α
where,
α=
=fractional weight change of the sample
wo − wt
w0 − w∞
wo = initial sample weight
wt = sample weight @ time ‘t’
w∞ = final sample weight
t
= time
k = reaction rate
n = order of reaction
26
Chapter 3: Theoretical Aspects of Air Injection
β = temperature increasing rate ( β =
dT
)
dt
T = temperature at time‘t’
⎡1 − (1 − α )1− n ⎤
(1 − α )⎤ against
1
⎡
against
or, when n =1 ln ⎢− ln
Thus a plot of either ln ⎢
2 ⎥
T 2 ⎥⎦
T
⎣
⎣ (1 − n )T ⎦
1
E
should result in a straight line of slope for the correct value of n. The value of E
T
R
obtained graphically is substituted in Eq. 3.5 & Eq. 3.6 to calculate the pre-exponential
factor Ar.
27
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 (GCMS) 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.
28
Chapter 4: Experimental Technique and Apparatus
Fig. 4.1−Setup of Rheo meter Physica MCR 301
(Viscosity measurement apparatus)
Fig. 4.2−Clarus 500 GC–MS Apparatus Setup
29
Chapter 4: Experimental Technique and Apparatus
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
Thermosonimetry (emission)
TS
Acoustical properties
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.
30
Chapter 4: Experimental Technique and Apparatus
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)
31
Chapter 4: Experimental Technique and Apparatus
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 userspecified 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
32
Chapter 4: Experimental Technique and Apparatus
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)
33
Chapter 4: Experimental Technique and Apparatus
Fig. 4.7−View of the DSC 2920 with Pressure Cell
Fig. 4.8−View of the High Pressure Cell of DSC 2920
34
Chapter 4: Experimental Technique and Apparatus
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
35
Chapter 4: Experimental Technique and Apparatus
≈ 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.
1350
Heat Flow (mW)
1150
950
750
550
350
150
-50
0
100
200
300
400
500
Temperature
Temperature, °C
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
36
Chapter 4: Experimental Technique and Apparatus
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 oilwith-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.
37
Chapter 4: Experimental Technique and Apparatus
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.
0.5
100.5
100
Weight Change (%)
99.5
Weight (mg)
0.3
Deriv. Weight (%/_C)
99
98.5
0.2
98
0.1
97.5
0
97
96.5
0
50
100
150
200
250
300
350
400
-0.1
450
Temperature C °C
Temperature,
Fig. 4.10−Temperature Calibration of TGA Instrument by Nickel
38
Deriv. Weight (%/C)
0.4
Chapter 4: Experimental Technique and Apparatus
101
0.45
100
0.4
Weight Change (%)
Weight (mg)
98
0.3
Deriv. Weight (%/_C)
0.25
97
0.2
96
0.15
95
0.1
94
Deriv. Weight (%/C)
0.35
99
0.05
93
0
-0.05
92
0
50
100
150
Temperature
200
250
Temperature, °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.
39
Chapter 4: Experimental Technique and Apparatus
2.1
1.9
Heat Flow (mW)
1.7
1.5
1.3
1.1
0.9
0.7
0.5
0
100
200
300
400
500
Temperature
Temperature, °C
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.
40
Chapter 4: Experimental Technique and Apparatus
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.
41
Chapter 4: Experimental Technique and Apparatus
0
TGA of Test-2
TGA of Test-1
-1
DTG of Test-2
0.05
DTG of Test-1
-2
0.04
-3
0.03
-4
0.02
-5
Deriv. Weght (%/C)
Weight Change (%)
0.06
0.01
-6
-7
0
100
200
300
400
500
0
600
Temperature
Temperature,
°C
Fig. 4.14− Reproducibility of TGA and DTG curve (Kenmore Rock #31)
Weight Change
TGA of Test-1
0.14
-10
TGA of Test-2
-20
DTG of Test-1
-30
DTG of Test-2 0.1
-40
0.12
0.08
-50
0.06
-60
-70
0.04
Deriv. Weght (%/C)
0
-80
0.02
-90
-100
0
100
200
300
400
Temperature°C
Temperature,
500
0
600
Fig. 4.15−Reproducibility of TGA and DTG curve (Kenmore Oil #34 with Rock
Cutting)
42
Chapter 4: Experimental Technique and Apparatus
95
Test-1
Test-2
Heat Flow (mW)
70
45
20
-5
0
100
200
300
400
500
Temperature °C
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.
43
Chapter 4: Experimental Technique and Apparatus
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
Oil
Well Name
Kenmore #32
Kenmore #34
Kenmore
Production Tank-7
Kenmore #31
Kenmore
Cutting
Kenmore #34
Kenmore #36
Oil
Field B
W#3
W#5
E # 13
E # 40
Depth, m
Zone
n/a
n/a
1380
1383
1386
1389
1395
1401
1404
1390-1395
1395-1400
E # 22
E # 33
44
Hutton
Birkhead
n/a
n/a
n/a
P3-120/130
P3-230/250
P3-120/130
P3-120/130
E # 21
Cutting
Birkhead
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.
45
Chapter 5: Experimental Results
Table 5. 1−Specific Gravity and API-gravity
Kenmore Field
Run
Operating
Temperature
°C
Specific
Gravity
1
15.01
0.7857
2
15.00
0.7849
3
15.01
0.7851
Average
Specific
gravity
Field B
APIGravity
°API
Specific
Gravity
Average
Specific
gravity
APIGravity
°API
0.799
45.55
0.7986
0.785
48.70
0.7996
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.
46
Chapter 5: Experimental Results
3
2.75
2.5
Viscosity cP
2.25
2
1.75
1.5
1.25
1
0.75
0.5
10
20
30
40
50
60
Temperature °C
70
80
90
Fig. 5.1−Viscosity Temperature Profile of Kenmore Crude Oil
5.5
5
4.5
Viscosity, cP
4
3.5
3
2.5
2
1.5
1
10
30
50
70
90
Temperature,°C
Fig. 5.2−Viscosity Temperature Profile of Field B Crude Oil
47
100
Chapter 5: Experimental Results
16
14
12
Mole %
10
8
6
4
2
0
nC5
nC6
nC7
nC8
nC9
nnnnnnnnnnnnC2
C2
C1
C1
C1
C1
C1
C1
C1
C1
C1
C1
1
0
9
8
7
6
5
4
3
2
1
0
Carbon Number of Components
Fig. 5.3−Hydrocarbon Distribution of Kenmore Crude Oil
32
28
24
Mole %
20
16
12
8
4
0
28
C
n27
C
n- 6
2
C
n- 5
2
C
n24
C
n- 3
2
C
n22
C
n- 1
2
C
n20
C
n- 9
1
C
n18
C
n- 7
1
C
n- 6
1
C
n- 5
1
C
n- 4
1
C
n- 3
1
C
n- 2
1
C
n- 1
1
C
n10
C
n9
C
n8
C
n7
C
n6
C
n5
C
n4
C
n-
Carbon Number of Components
Fig. 5.4−Hydrocarbon Distribution of Crude Oil B
48
Chapter 5: Experimental Results
Table 5. 2−Thermal Tests Performed in this Study
TGA Test
Sample
DSC Test
Number
Sample Type
In Air
In N2
1000kPa
4500kPa
4500kPa
in Air
in Air
in O2
of Tests
Kenmore Samples
Oil (#32)
Oil (#34)
Oil (Prodn
Tank)
Oil-Only
√
√
-
√√
√
Cutting-Only
√
√
-
√
√√
Oil With Cuttings
√
√
-
√√
√
Oil-Only
√
√
-
√√
√
Cutting-Only
√
√
-
√
√
Oil With Cuttings
√
√
-
√√
√√
Oil-Only
√
√
-
-
√
Cutting-Only
-
-
-
-
-
Oil With Cuttings
-
-
-
-
-
15
15
3
Field B Samples
W-3
W-5
E-13
E-40
Oil-Only
√
√
√
√√
-
Cutting-Only
√
√
-
√
-
3
√
√
-
√√
-
Oil-Only
√
√
√
√√
-
Cutting-Only
√
√
-
√
-
Oil With Cuttings
√
√
-
√√
-
Oil-Only
√
√
√
√√
-
Cutting-Only
√
√
-
√
-
Oil With Cuttings
√
√
-
√√
-
Oil-Only
√
√
√
√
-
Cutting-Only
√
√
-
-
-
Oil With Cuttings
√
√
-
-
-
49
12
12
12
8
Chapter 5: Experimental Results
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.
10
0.06
-10
0.05
0.04
o
Mass Change (%)
-30
DTG (%/ C)
TGA of Rock 31 in air
TGA of Rock 31 in N2
DTG of Rock 31 in air
DTG of Rock 31 in N2
-50
0.03
-70
0.02
-90
0.01
-110
0
100
200
300
400
500
0
600
Temperature (OC)
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
50
Chapter 5: Experimental Results
provides energy, the cuttings material does not have any negative contact on oxidation
reaction.
0.6
Rock 34 in Air
Rock 31 in Air
Rock 36 in Air
Rock 31 in Oxygen
0.5
0.4
Heat Flow (W/g)
0.3
0.2
0.1
0
-0.1
-0.2
-0.3
0
100
200
300
400
500
O
Temperature ( C)
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.
51
Chapter 5: Experimental Results
0.5
TGA of oil 32 in Air
-10
TGA of oil 32 in N2
DTG of oil 32 in Air
0.4
DTG of oil 32 in N2
O
Mass Change (%)
0.3
Deriv. Weight (%/ C)
-30
-50
0.2
-70
0.1
-90
0
-110
0
100
200
300
400
500
-0.1
600
Temperature (OC)
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
52
Chapter 5: Experimental Results
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.
1
0.8
Heat Flow (W/g)
0.6
0.4
0.2
0
-0.2
0
50
100
150
200
250
300
350
O
Temperature ( C)
Fig. 5.8−DSC of Kenmore Oil #32 in Air at Atmospheric Pressure
53
400
Chapter 5: Experimental Results
58
Oil #32 in Air
Oil #32 in Oxygen
48
Heat Flow (W/g)
38
28
18
8
-2
0
100
200
300
400
500
Temperature ( OC)
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.
54
Chapter 5: Experimental Results
10
0.5
TGA of Oil 32 + Rock 31 inAir
TGA of oil 32 in air
DTG of oil 32 in air
-10
0.4
-30
0.3
-50
0.2
-70
0.1
-90
0
-110
Deriv. Weight (%/ oC)
Weight Change (%)
DTG of oil 32 + Rock 31 in Air
-0.1
0
100
200
300
400
500
600
Temperature (oC)
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.
55
Chapter 5: Experimental Results
22
In Air
20
In Oxygen
18
16
Heat Flow (W/g)
14
12
10
8
6
4
2
0
-2
0
100
200
300
400
500
Temperature (OC)
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.
56
Chapter 5: Experimental Results
0.09
10
0.08
-10
Weight Change (%)
-30
0.07
0.06
0.05
-50
0.04
0.03
-70
Deriv. Weight (%/ oC)
TGA of Rock 34 in Air
TGA of Rock 34 in Nitrogen
DTG of Rock 34 in Air
DTG of Rock 34 in Nitrogen
0.02
-90
0.01
-110
0
0
100
200
300
400
500
600
Temperature (oC)
Fig. 5.12−TGA of Kenmore Cutting #34 in Air and Nitrogen Environments
0.6
Rock 34 in Air
0.5
Heat Flow (W/g)
0.4
0.3
0.2
0.1
0
-0.1
-0.2
-0.3
0
100
200
300
400
Temperature (OC)
Fig. 5.13−PDSC of Kenmore Rock #34 in Air Environment
57
500
Chapter 5: Experimental Results
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°).
10
TGA in Air
0.5
TGA in Nitrogen
-10
DTG in Air
Mass Change (%)
-30
0.3
-50
0.2
-70
Deriv. Wight (%/OC)
0.4
DTG in Nitrogen
0.1
-90
0
-110
0
100
200
300
400
500
-0.1
600
O
Temperature ( C)
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.
58
Chapter 5: Experimental Results
0.7
0.6
0.5
Heat Flow (W/g)
0.4
0.3
0.2
0.1
0
-0.1
-0.2
0
50
100
150
200
250
300
350
O
Temperature ( C)
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.
59
Chapter 5: Experimental Results
22
In Air
In Oxygen
20
18
16
Heat Flow (W/g)
14
12
10
8
6
4
2
0
-2
0
100
200
300
400
500
Temperature (OC)
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.
60
Chapter 5: Experimental Results
0.16
10
TGA
TGA
DTG
DTG
Mass Change (% of total mass)
-10
in N2
in Air
in N2
in Air
0.14
O
-30
0.1
-50
Deriv. Weight (%/ C)
0.12
0.08
0.06
-70
0.04
-90
0.02
-110
0
100
200
300
400
0
600
500
Temperature (OC)
Fig. 5.17−TGA of Kenmore Oil #34 with Cutting #34 in Air and Nitrogen
Environments-Mass loss as a percentage of total mass
10
0.5
TGA of Oil 34+ Rock 34 in N2
TGA of Oil 34 in N2
DTG of Oil 34 + Rock 34 in N2
-10
0.4
-30
0.3
-50
0.2
-70
0.1
-90
0
-110
0
100
200
300
400
500
Deriv. Weight (%/OC)
Mass Change (%)
DTG of Oil 34 in N2
-0.1
600
Temperature (OC)
Fig. 5.18−TGA of Kenmore Oil #34 with Cutting #34 in Nitrogen Environment- Mass
loss as a percentage of mass of oil
61
Chapter 5: Experimental Results
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.
10
0.6
TGA of Oil 34 + Cutting 34 in Air
TGA of Oil 34 in Air
DTG of Oil 34 + Cutting 34 in Air
-10
0.5
DTG of Oil 34 in Air
O
Mass Change (%)
Deriv. Wight (%/ C)
0.4
-30
0.3
-50
0.2
-70
0.1
-90
0
-110
0
100
200
300
400
500
-0.1
600
Temperature (OC)
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
62
Chapter 5: Experimental Results
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.
22
In Air
20
In Oxygen
18
16
Heat Flow (W/g)
14
12
10
8
6
4
2
0
-2
0
100
200
300
400
500
O
Temperature ( C)
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
63
Chapter 5: Experimental Results
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.
0
Weight Change,%
0.025
EM#21-220/250
EM#22-120/130
EM#22-220/250
EM#33-120/130
DTG of EM#21
DTG of EM#23
DTG of EM#22-120/130
DTG of EM#22 -220/250
-1
0.02
0.015
-2
0.01
-3
Derriv. Weight, %/C
1
0.005
-4
-5
0
0
100
200
300
400
500
600
Temperature,°C
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.
64
Chapter 5: Experimental Results
2.5
2
Heat Flow, W/g
1.5
1
0.5
0
-0.5
0
50
100
150
200
250
300
350
400
450
500
Temperature, oC
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°).
65
Chapter 5: Experimental Results
10
TGA @ Air
0.45
TGA @ N2
0
DTG @ Air
0.4
DTG @ N2
-10
0.35
-20
0.3
-40
0.25
-50
0.2
-60
-70
Deriv. Weight, %/°C
Weight Change, %
-30
0.15
-80
0.1
-90
0.05
-100
-110
0
100
200
300
400
500
0
600
Temperature, °C
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 heatflow 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
66
Chapter 5: Experimental Results
55
WM-13 Oil Only @ 1000 kPa
WM-13 Oil Only @ 4500 kPa
45
WM-13 Oil + EM-22 Cutting
@ 4500 kPa
Heat Flow, W/g
35
25
15
5
-5
0
50
100
150
200
250
300
350
400
450
500
Temperature , °C
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 oilonly 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.
67
Chapter 5: Experimental Results
10
0.45
TGA of Oil Only
TGA of Oil+Rock
0
0.4
DTG of Oil Only
DTG of Oil with Rock
-10
0.35
-20
Weight Change, %
-40
0.25
-50
0.2
-60
Deriv. Weight, %/°C
0.3
-30
0.15
-70
-80
0.1
-90
0.05
-100
-110
0
100
200
300
400
500
0
600
Temperature ,°C
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.
68
Chapter 5: Experimental Results
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.
10
0.45
TGA @ Air
TGA @ N2
0
0.4
DTG @ Air
-10
DTG @ N2
0.35
-20
0.3
0.25
-40
0.2
-50
-60
0.15
-70
0.1
-80
0.05
-90
0
-100
-110
0
100
200
300
400
500
Temperature, oC
Fig. 5.26−TGA of W #3 Oil in Air and N2 Environments
69
-0.05
600
Deriv. Weight, %/oC
Weight Change, %
-30
Chapter 5: Experimental Results
10
0.45
TGA @ Air
TGA @ N2
DTG @ Air
DTG @ N2
0
-10
0.4
0.35
-20
Weight Change, %
-40
0.25
-50
0.2
-60
0.15
-70
0.1
-80
Deriv. Weight, %/°C
0.3
-30
0.05
-90
0
-100
-110
-0.05
0
100
200
300
400
Temperature,°C
500
600
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.
70
Chapter 5: Experimental Results
30
Oil Only @ 1000 kPa
Oil Only @ 4500 kPa
25
Heat Flow, W/g
20
15
10
5
0
-5
0
50
100
150
200
250
300
350
400
450
500
Temperature,°C
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.
71
Chapter 5: Experimental Results
30
DSC Oil Only @ 1000 kPa
DSC Oil Only @ 4500 kPa
25
Heat Flow, W/g
20
15
10
5
0
-5
0
100
200
300
400
500
Temperature,°C
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 oilonly 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.
72
Chapter 5: Experimental Results
10
0
-10
-20
Weight Change %
-30
Rock only
Oil+Rock -- (Total Wt)
Oil+Rock-- (Oil wt & after rock effect)
Oil+Rock-- (Oil Wt & Total effect)"
Oil Only
-40
-50
-60
-70
-80
-90
-100
-110
0
100
200
300
400
500
600
Temperature,°C
Fig. 5.30−Details of TGA of W #3 Oil in Air Environment
10
0.45
TGA @ Air
TGA @ Oil+Rock
0
DTG @ Air
-10
DTG @ Oil+Rock
0.4
0.35
-20
0.25
-40
0.2
-50
-60
0.15
Deriv. Weight, %/oC
Weight Change, %
0.3
-30
-70
0.1
-80
0.05
-90
0
-100
-0.05
-110
0
100
200
300
400
500
600
Temperature, oC
Fig. 5.31−TGA of W #3 Oil and Cutting E#22 in Air Environment—Mass loss as a
percentage of weight of oil
73
Chapter 5: Experimental Results
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.
10
0.45
TGA of Oil
TGA of Oil + Rock
0
0.4
DTG of Oil
-10
DTG of Oil+Rock
0.35
-20
0.3
0.25
-40
0.2
-50
-60
0.15
Deriv. Weight, %/°C
Weight Change, %
-30
-70
0.1
-80
0.05
-90
0
-100
-110
0
100
200
300
400
500
-0.05
600
Temperature,°C
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.
74
Chapter 5: Experimental Results
30
Oil Only @ 4500 kPa
25
Oil + Cutting @ 4500 kPa
Heat Flow, W/g
20
15
10
5
0
-5
0
100
200
300
400
500
Temperature,°C
Fig. 5.33−PDSC of W #3 with Rock Cuttings in Air Environment
30
DSC Oil Only @ 4500 kPa
DSC Oil + Rock @ 4500 kPa
25
Heat Flow, W/g
20
15
10
5
0
-5
0
50
100
150
200
250
300
350
400
450
Temperature,°C
Fig. 5.34−PDSC of W #5 with Rock Cuttings in Air Environment
75
500
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.
76
Chapter 6: Analysis of Results and Discussions
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
77
Chapter 6: Analysis of Results and Discussions
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-withcutting 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.
78
Chapter 6: Analysis of Results and Discussions
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
79
Chapter 6: Analysis of Results and Discussions
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.
80
Chapter 6: Analysis of Results and Discussions
Table 6.1−Kinetic Parameters
Reservoir
Sample
Well
Reaction
Peak
Range
Temperature
(°C)
(°C)
Kenmore
225-
Oil #32
280
Kenmore
200-
Oil #34
280
239
E (KJ/mole)
Calculated
Average
91.74
96
Oil only
219
101.14
264
71.36
Kenmore
Kenmore
Oil +
Oil #32
Rock
Kenmore
68
-
64.51
222
77.49
218
102.77
EM-13
234
105.08
WM-3
207
70.03
WM-5
210
82.49
205
99.76
Oil #34
WM-3
Oil only
Field B
Oil +
-
WM-5
Rock
EM-13
200240
200240
190250
81
95
84
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
82
Chapter 7: Conclusions and Recommendations
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
83
Chapter 7: Conclusions and Recommendations
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 180280ºC. 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
84
Chapter 7: Conclusions and Recommendations
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.
85
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