Embed Size (px)
Citation preview
TO INVESTIGATE THE USE OF AIR INJECTION TO IMPROVE
OIL RECOVERY FROM LIGHT OIL RESERVOIRS
ABDUL HAQUE TUNIO
Doctor of Philosophy
In
Petroleum Engineering
MEHRAN UNIVERSITY OF ENGINEERING & TECHNOLOGY
JAMSHORO
2008
IN THE NAME OF
ALLAH,
THE MOST GRACIOUS
THE MOST MERCIFUL
WHO’S HELP WE SOLICIT
TO INVESTIGATE THE USE OF AIR INJECTION TO IMPROVE
OIL RECOVERY FROM LIGHT OIL RESERVOIRS
A thesis submitted by
ABDUL HAQUE TUNIO
In fulfillment of the requirement for the degree of
Doctor of Philosophy
In
Petroleum Engineering
Institute of Petroleum and Natural Gas Engineering
Mehran University of Engineering and Technology,
Jamshoro
2008
DEDICATION
THIS EFFORT OF MINE IS GREATFULLY DEDICATED
TO
MY PARENTS
&
MY FAMILY
WHO DID THEIR BEST TO UPLIFT ME TO THE
HEIGHTS OF AN IDEAL LIFE
ACKNOWLEDGEMENT
First of all, I wish to express my deepest gratitude to my supervisor, Professor Dr. Rafiq
Akhtar Kazi, who has been most generous with his precious time, provided many useful
ideas, valuable guidance, and encouragement.
Gratitude is extended to my co-supervisor and Director, Institute of Petroleum and
Natural Gas Engineering, Prof. Dr. Hafeez -Ur-Rahman Memon for his courageous
advice and guidance.
Sincere thanks to Prof. Dr. Ghous Bux Khaskheli, Director, Post Graduate Studies for his
timely response and help.
Finally, I would like to gratefully acknowledge the financial support of the Higher
Education Commission (HEC), Islamabad that made my research work possible.
TABLE OF CONTENTS PAGE
Chapter 1. INTRODUCTION 1
1. 1 Introduction 1
Chapter 2. GENERAL VIEW OF OIL RECOVERY 4
2.1 Introduction
2.2 Primary recovery methods
2.2.1 Solution gas drive reservoir
2.2.2 Gas Cap Drive Reservoir
2.2.3 Water Drive Reservoir
2.2.4 Combination Drive reservoir:
2.2.5 Gravity Drainage
2.3 Artificial lift methods
4
4
4
5
5
6
6
7
2.4 Secondary recovery method
2.5 Gas flooding
2.5.1 Immiscible gas injection
2.5.2 Miscible or high pressure gas injection
7
7
7
8
2.6 Water flooding 8
2.7 Enhanced oil recovery
2.8 Air injection
9
11
2.9 Thermal recovery processes
2.9.1 Cyclic steam stimulation
2.9.2 Steam flooding
2.9.3 In-situ combustion or fire flooding
12
12
12
13
2.10 Gas miscible recovery method
2.10.1 Cyclic carbon dioxide stimulation
2.10.2 Carbon dioxide flooding
2.10.3 Nitrogen flooding
15
15
16
17
2.11 Chemical flooding methods
i
18
2.11.1 Polymer flooding 18
2.11.2 Micellar-polymer flooding 18
2.11.3 Alkaline flooding 19
2.12 Microbial EOR methods
2.12.1 Cyclic microbial recovery method
2.12.2 Microbial flooding method
19
19
20
Chapter 3. LITERATURE REVIEW 21
3.1 Historic Performance of Air Injection Process 21
3.2 Recovery Processes at the CCA 22
3.3 Process Advantages 27
3.4 Difference between lights oil and heavy oils under
Air Injection
28
3.5 Observations from Field Projects 28
3.6 Oil Recovery 30
3.7 Reaction Kinetic Model 30
3.8 Air Injection Based Oil recovery Processes 33
3.9 Development of the MAF (HPAI) Processes 35
3.10 Status of Air Injection as an IOR Method. Field
Projects
36
13.10.1 Application to light oils 36
3.11 Air injection in a low temperature oxidation/
Immiscible air flooding mode
38
3.12 Air Injection in very Light, deep oil Reservoirs 39
3.13 Laboratory MAF Specific Tests 44
3.14 MAF Pilot Expansion to Commercial Operations 46
3.15 Screening Criteria 48
3.16 Low Temperature Oxidation (LTO) 49
3.17 Air Injection and Oxygen Consumption
ii
51
3.18 Spontaneous Ignition 52
3.19 Fuel Combustion 54
3.20 Fuel Deposition
3.21 Practical application of experimental results
55
56
Chapter 4. EXPERIMENTAL SET-UP AND PROCEDURE 57
4.1 Experimental Equipment 57
4.1.1 Air Injection Apparatus 57
4.1.2 Reactor Assembly 57
4.1.3 Reactor Heating System 64
4.1.4 Thermocouples 65
4.1.5 Pressure Transducer 65
4.1.6 Fluid separation 65
4.1.7 Recorder 67
4.1.8 Pressure Regulator 67
4.1.9 Flow metering 67
4.1.10 Gas Sampling system 68
4.1.11 Gas chromatograph 68
4.2 Properties of the crude oil 68
4.2.1 Oil Viscosity
4.2.2 Amount of Interstitial Water
4.2.3 Mineralogy
4.2.4 Geology
4.2.5 Reservoir Temperature
4.3 Properties of the sand pack
4.3.1 Oil mixing in unconsolidated sand
4.3.2 Preparation of the combustion cell
4.3.3 Preparation of Apparatus
4.4 Procedure
iii
68
70
71
71
71
71
72
73
73
74
4.5 Calibration of Alltech dual Concentric Column 75
Chapter 5 EXPERIMENTAL RESULTS 77
5.1 Presentation and discussion of Results
5.2 Effluent Gas Analysis
77
82
5.3 Effect of Porous Media Type 83
5.4 Oil Recovery 85
5.5 Effect of System Pressure 91
5.6 Effect of Air Flux 97
5.7 Oil and Water Saturation 103
5.8 Effect of Temperature / Heat Input 109
5.9 Comparison between Theoretical and
Experimental Results
110
5.10 Combustion Cell Temperature Profiles 117
5.10.1 Dry Combustion 117
5.10.2 Wet Combustion 119
Chapter 6. TREATMENT OF THE DATA 124
6.1 Treatment of the Data 124
6.2 Oxygen Consumption 124
6.3 m- Ratio 127
6.4 H/C Ratio 127
6.5 Carbon Balance 128
6.6 Kinetic Analysis by Direct Arrhenius Method 128
6.7 Analysis and Discussion of Results 131
6.8 Apparent H/C Ratio 131
6.9 m- Ratio 133
6.9.1 Effect of Heat input on H/C & m- Ratio. 140
6.9.2 Effect of Pressure on H/C & m- Ratio. 143
6.9.3 Effect of Air flux on H/C & m- Ratio. 144
iv
6.9.4 Comparison between Theoretical and
Experimental Results
146
6.10 Oxygen Balance 147
6.10.1 Oxygen Utilization 151
Chapter 7. ANALYSIS OF IN-SITU COMBUSTION REACTION
KINETICS
153
7.1 Analysis of In-Situ Combustion Kinetics 153
7.2 Interpretation of Kinetic Data 153
7.3 Kinetic parameters 161
7.3.1 Activation Energy 162
7.3.2 Activation Energy Effect 162
7.4 The Effect of Pressure 162
7.4.1 Total system pressure Effect 163
7.5 Kinetic parameters 163
7.6 Comparison of Kinetic Parameters 167
7.7 Repeatability and Accuracy of Experiments 169
Chapter 8. CONCLUSIONS AND RECOMMENDATIONS FOR
FUTURE WORK
171
8.1 Conclusions
8.2 Suggestions for Future Modification in
Experimental Set-up
8.2.1 Suggestions for Future work
171
172
173
REFRENCES 174
Appendix A: Photograph of Experimental set-up 188
v
FIG.
No
LIST OF FIGURES PAGE
3.1 Air Injection LTO Process 51
4.1 Air Injection Experimental Set-Up 58
4.2 High Pressure Reactor Assembly 63
4.3 Temperature Vs Time 66
4.4 Pressure Vs Current Relationship 66
4.5 Special Design For Gas Sampling System 69
4.6 Calibration of Alltech CTR1 Column by Calibration Gas Mixture 76
5.1 Gas Composition and Temperature Vs Time for Run-02 84
5.2 Gas Composition and Temperature Vs Time for Run-04 84
5.3 Gas Composition and Temperature Vs Time for Sand mix-01 87
5.4 Gas Composition and Temp. Vs Time for sand mix -02 87
5.5 Gas Composition and Temp. Vs Time for sand mix -03 88
5.6 Gas Composition and Temperature Vs Time for Sand mix-04 88
5.7 Oxygen Consumed vs Time with different sand pack properties for R-01
and R-10, R-15 & R-20
89
5.8 Production of CO2 vs Time with different sand pack properties for R-01
and R-10, R-15 & R-20
89
5.9 Production of CO vs Time with different sand pack properties for R-01
and R-10, R-15 & R-20
90
5.10 Cumulative oil Production with different sand pack 90
5.11 Gas Composition and Temperature Vs Time at 2069 KPa 93
5.12 Gas Composition and Temperature Vs Time at 3448 KPa 93
5.13 Gas Composition and Temperature Vs Time at 3585 KPa 94
5.14 Gas Composition and Temperature Vs Time at 6895 KPa 94
5.15 Oxygen Cons. vs Time with different Pressure for R-26, 27, 05 & -47 95
vi
5.16 Production of CO2 vs Time with diff. Pressure for R-26, 27, 05 & 47 95
5.17 Production of CO vs Time with different Pressure for R-26, 27, 05 & 47 96
5.18 Cumulative oil Production at different Pressure 96
5.19 Gas Composition and Temperature Vs Time at air flux 7.595 99
5.20 Gas Composition and Temperature Vs Time at air flux 22.78 99
5.21 Gas Composition and Temperature Vs Time at air flux 30.38 100
5.22 Oxygen Consumed vs Time with different air flux for R-50, 51& 53 100
5.23 Production of CO2 vs Time with different air flux for R-50, 51& 53 101
5.24 Production of CO vs Time with different air flux for R-50, R-51& 53 101
5.25 Cumulative oil Production at different Air fluxes 102
5.26 Gas Composition and Temperature Vs Time with So=55% & w=27.5% 102
5.27 Gas Composition and Temp. Vs Time with So=66% & Sw=16.5% 105
5.28 Gas Composition and Temperature Vs Time with So=41% & Sw=41% 105
5.29 Oxygen Consumed vs Time with different So & Sw for R-41, 42 & 46 106
5.30 Production of CO2 vs Time with different So & Sw for R-41, 42 & 46 106
5.31 Production of CO vs Time with different So & Sw for R-41, 42 & 46 107
5.32 Cumulative oil Production with different oil & water saturation 107
5.33 Oil Recovery with different oil & water saturation 108
5.34 Gas Composition and Temperature Vs Time with Single heater 108
5.35 Gas Composition and Temperature Vs Time with two heater 112
5.36 Gas Composition and Temperature Vs Time with three heater 112
5.37 Oxygen Consumed vs Time by increasing 1-3 heaters for R-22, 49 & 55 113
5.38 Production of CO2 vs Time by increasing 1-3 heaters for R-22, 49 & 55 113
5.39 Production of CO vs Time by increasing 1-3 heaters for R-22, 49 &55 114
5.40 Cumulative oil Production with different heat input 114
5.41 Pressure and Temperature Profiles VS Time for Run-01 121
5.42 Pressure and Temperature Profiles VS Time for Run-04 121
5.43 Pressure and Temperature Profiles VS Time for Run-05 122
vii
5.44 Pressure and Temperature Profiles VS Time for Run-41 122
5.45 Pressure and Temperature Profiles VS Time for Run-51 123
5.46 Pressure and Temperature Profiles VS Time for Run-54 123
6.1 Paths of oil oxidation 126
6.2 Apparent H/C Ratio vs Time for different type of rock formation 137
6.3 Apparent H/C Ratio vs Time for different system pressures 137
6.4 Apparent H/C Ratio vs Time for different Air fluxes 138
6.5 Apparent H/C Ratio vs Time for different Oil and Water Saturation 138
6.6 Apparent H/C Ratio vs Time for different Heat input 139
6.7 m-Ratio vs Time for different type of rock formation 139
6.8 m-Ratio vs Time for different System Pressures 141
6.9 m-Ratio vs Time for different air fluxes 141
6.10 m-Ratio vs Time for different oil and water saturations 142
6.11 m-Ratio vs Time for different Heat input 142
6.12 Oxygen consumed in Excess for Run-41 152
6.13 Oxygen consumed in Excess for Run-50 152
7.1 Direct Arrhenius plot with respect to Carbon Concentration for Run-05 156
7.2 Fuel Combustion Reaction for different type of Formation 156
7.3 Fuel Deposition Reaction for different type of Formation 157
7.4 Arrhenius Plot for LTO Reaction for different type of Formation 157
7.5 Arrhenius Plot for Fuel Combustion Reaction at different air fluxes 158
7.6 Arrhenius Plot for Fuel Deposition Reaction at different air fluxes 158
7.7 Arrhenius Plot for LTO Reaction for different at different air fluxes 159
7.8 Fuel Combustion Reaction at different System Pressure 159
7.9 Fuel Deposition Reaction at different System Pressure 164
7.10 LTO Reaction for different at different System Pressure 164
7.11 Fuel Combustion Reaction with different oil and water saturation 165
7.12 Fuel Deposition Reaction with different oil and water saturation 165
viii
7.13 LTO Reaction for different with different oil and water saturation 166
7.14 Arrhenius Plot for Fuel Combustion Reaction with different heat input 166
7.15 Arrhenius Plot for Fuel Deposition Reaction with different heat input 168
7.16 Arrhenius Plot for LTO Reaction for different with different heat input 168
ix
LIST OF TABLES
TABLE PAGE
4.1 Equipments used in the Research Rig 59
4.2 Specification of Apparatus, Installed in Air Injection Research Rig 60
4.3 Specification of Equipments used in the Research 62
4.4 Equipments used in the High pressure Reactor 62
4.5 Properties of the Crude Oil 70
4.6 Initial Pack conditions for the Combustion cell 72
4.7 Initial Sand Pack Properties 72
5.1 Summary of Sand Pack Parameters 79
5.2 Summary of Operating and Control Parameters 80
5.3 Summary of Combustion Cell Results 81
5.4 Summary of Sand Pack Properties with effect of sand pack 86
5.5 Summary of Operating and Control Parameters with effect of sand
pack
86
5.6 Summary of Combustion Cell Results with effect of Sand 86
5.7 Summary of Sand Pack Properties with effect of System Pressure 92
5.8 Summary of Operating and Control Parameters with effect of System
Pressure
92
5.9 Summary of Combustion Cell Results with effect of System Pressure 92
5.10 Summary of Sand Pack Properties with effect of Air flux 98
5.11 Summary of Operating and Control Parameters with effect of Air flux 98
5.12 Summary of Combustion Cell Results with effect of Air flux 98
5.13 Summary of Sand Pack Properties with effect of oil and water
saturation
104
5.14 Summary of Operating and Control Parameters with effect of oil and
water saturation
104
5.15 Summary of Combustion Cell Results with effect of oil and water
x
104
saturation
5.16 Summary of Sand Pack Properties with effect of heat input 111
5.17 Summary of Operating and Control Parameters with effect of heat
input
111
5.18 Summary of Combustion Cell Results with effect of heat input 111
5.19 Comparison between Theoretical and Experimental Results 115
6.1 Estimated averaged H/C ratio, m-Ratio, Peak temperature and carbon
burned for various runs
134
6.2 Estimated averaged H/C ratio, m-Ratio, Peak temperature and carbon
burned for various runs
135
6.3 Estimated averaged H/C ratio, m-Ratio, Peak temperature and carbon
burned for various runs
136
6.4 Kinetic experimental results 149
7.1 Summary of Kinetic data 155
7.2 Analysis of In-Situ Combustion reaction Kinetics 170
xi
ABSTRACT
Air injection into light oil reservoirs is now a proven field technique, because of the
unlimited availability and low access cost of the injectant. One of the key of a successful
air injection project is the evaluation of the process by carrying out representative
laboratory studies. In this research, experimental set up has been developed to understand
air injection process for improving oil recovery for depleted light oil reservoirs and the
parameters on the basis of different petrophysics and fluid sample properties.
In order to provide reliable experimental data, pressure and temperature experiments (up
to 11032 KPa and 600 °C), at non-Isothermal conditions ramp of 5 oC/ min., were
performed with unconsolidated cores (sand pack) and reservoir oils, at representative
conditions of the air injection process into light oil reservoirs. The effects of porous
media type, gas flux, heat input, water saturation and total pressure on the rates of the in-
situ oxidation reaction were measured. When air is injected, the oxygen contained in the
air (mainly of 79 % N2 and 21% O2) reacts with the hydrocarbons in place, by oxidation
reaction. The produced combustion gases consisting of CO2, CO, O2 and N2 depend on
the temperature conditions and the nature of the crude oil. The generation of a high
temperature oxidation zone is preferable for its higher oxygen uptake potential, it’s more
efficient carbon oxides generation and the creation of an oil bank downstream of the
thermal front, both of the latter factors contribute to the improvement of the recovery. In
both cases, the important point to assess is the oxygen consumption to prevent oxygen
arrival at the producers and to sustain the combustion front. This is one of the main
objectives of the air injection experiments.
By continuous analysis of the produced gases from the reactor, at linearly increased
temperature rate, it was found that combustion of crude oil in porous media follows a
complex series of reactions. These reactions can be divided into three sequences :( 1) low
temperature oxidation, (2) fuel deposition, and (3) fuel combustion.
A model is proposed to analyze and differentiate among these reactions. The method
developed is reasonably fast and can be used to measure the oxidation and deposition of
fuel for a given crude oil and porous medium.
The major conclusions are:
1. 100 percent utilization of oxygen was observed.
2. Significant oil recovery was achieved about 85 percent of original oil in place
(OOIP).
3. The generation of flue gases by oxidation process was very efficient in terms of
carbon oxides with an average percentage of gas composition of 10 % CO2 and
4 % of CO and balance unreacted oxygen.
4. The H/C ratio for the deposited fuel decreases when temperature increases.
5. Increasing the injection pressure of system decreases the m-ratio [(CO/
(CO+CO2)]
Expressions were obtained for low temperature oxidation rate of oil, the fuel deposition
rate and the burning rate of fuel as a function of fuel concentration
The relative reaction rate of carbon oxidation was used. The activation energy of each
reaction was different for most of the runs. A significant effect of the heat input on
activation energy was observed, a lower heat input producing larger activation energy.
The effect of total pressure up to 11032 KPa indicated kinetic control with 21 % Oxygen
partial pressure.
This research will contribute to the overall understanding of air injection process and
enable to be made of the most appropriate technique for a given reservoir. Use of less
expensive method in tertiary phase will encourage the producers for additional recovery
in this area.
CHAPTER 1
INTRODUCTION
1.1 INTRODUCTION
The demand for oil worldwide is rising at about 7 to 8 percent a year. This combined
with the increasing difficulty of finding new large reservoirs has put pressure on
major consuming countries. The increased rate in demand of energy through out the
world with a decreasing trend in conventional energy resources has led to the
consideration of unconventional sources of energy. The most conventional source of
energy today is crude oil but the limited resources have generated interest in new
methods of improved oil recovery.
Because of the early history of air injection most of the industry’s experience has been
with heavy oil applications. However, emphasis is currently shifting to light and
medium gravity oils because of their technical and economic advantages. Such change
in focus is slowly taking place in oil industry. This research addresses important
technical and economic aspects of air injection into light oil reservoirs.
Air injection into light oil reservoirs may be regarded as a new alternative enhanced
oil recovery (EOR) method for both secondary and tertiary EOR processes. When air
is injected into a light oil reservoir exothermic chemical reactions occur between the
oxygen and the reservoir oil.
These reactions in the case of light oil are mainly oxidation reactions resulting in heat
generation and in the production of Carbon oxides (mainly CO2 and CO) with
corresponding consumption of oxygen. These reactions are dependent on the oil
characteristics, rock/ fluid system, temperature and pressure. The later controls the
partial pressure of oxygen in the reservoir. The driving force is not the injectant air
but the in-situ generated flue gases, which are composed of CO2, CO, O2, N2, CH4 and
the vaporized lighter hydrocarbon components.
The mechanisms are numerous and complex. The reactive importance of each
individual effect will depend on the specific reservoir content. They include (a)
reservoir pressure maintenance.
1
2
(b) Gravity drainage process between flue gases and reservoir oil. (c) Vaporization of
reservoir oil by flue gases. (d) Oil displacement by gases. (e) Most of the beneficial
effects are enhanced with higher pressure and higher temperature. (f) Injection gas
substitution. (g) Spontaneous oil ignition. (h) Complete oxygen utilization.
Experimental equipment has been fully developed for understanding high- pressure
air injection Process (HPAI) into depleted light oil reservoirs.
The objective of this investigation is to (a) Acquire better understanding of the
mechanisms involved. (b) Identify critical process parameters. (c) Utilization of
oxygen during the combustion takes place at the elevated temperature. (d) Evaluating
the operating injection pressure. (e) Study the kinetics of light crude oil in an
unconsolidated rock formation. The experiments were conducted on various
unconsolidated rock formation with a linear temperature ramp of 5 oC / min. from
room temperature to 600 oC. Pressure levels ranging from of 689.5 to 11032 KPa
were investigated together with 21 % oxygen concentration. The effect of heating rate
on the oxidation of crude oil was also investigated. 100 % oxygen utilization was
observed on the basis of analysis of exhaust gases. CO2, CO, N2, O2 and CH4 gases
were also produced at the elevated temperature, which are analyzed by Gas
chromatograph.
This thesis consists of eight chapters. A brief introduction to oil recovery methods
with emphasis on enhanced oil recovery methods is presented in chapter 2. In chapter
3 general literature survey of the process together with the parameters involved in
high-pressure air injection (HPAI) process, are presented. While the chapter 4
describes the experimental equipment and the material / parts of other components
used in the experimental set- up and procedures along with the crude oil and sand
pack properties for the air injection process. Results of various experiments are
presented and discussed in chapter 5. In chapter 6 treatments of data is presented.
Analysis of In-Situ combustion is discussed in chapter 7. Chapter 8 deals with
conclusions and recommendations for future work.
3
The main objectives of this study are:
(1) To develop an experimental set-up for understanding air injection process
for depleted light oil reservoirs.
(2) To conduct series of experiments on the following parameters
(a) Effect of formation/ sand pack
(b) Effect of system pressure
(c) Effect of flow rate
(d) Effect of oil and water saturation
(e) Effect of heat input
This research will contribute to the overall understanding of air injection process and
enable to be made for most appropriate techniques for a given reservoirs. Use of less
expensive method in tertiary phase will encourage the operators to invest in additional
recovery in this area.
CHAPTER 2
GENERAL VIEW OF OIL RECOVERY
2.1 INTRODUCTION
Oil is an important resource of energy especially in Pakistan. For this purpose many
oil fields had been discovered and established. The capacity to produce oil from a
reservoir is dependent upon the reservoir pressure level that exists within reservoir.
Production of the reservoir fluids is dependent upon pressure draw down; therefore,
the pressure drop that is created between the reservoir pressure and the well bore
flowing pressure. Sources of reservoir energy are discussed below.
2.2 PRIMARY RECOVERY METHODS
The recovery of oil by natural production mechanisms is called “Primary Recovery”.
The term refers to the production of hydrocarbons from a reservoir without the use of
any process (such as fluid injection) to supplement the natural energy of the reservoir.
Primary recovery was the only method available during the early years of the oil
industry and it is still the only method used in many oil fields such as in Middle East.
The natural energy or reservoir drive that is used during primary production can be
visualized by considering that each unit volume of oil produced must be replaced by
something in the reservoir since a vacuum cannot exist. The primary reservoir energy
comes from five mechanisms. (a) Solution gas- drive reservoir (b) gas-cap drive
reservoir (c) water drive reservoir (d) combination drive reservoir (e) Gravity
drainage reservoir.
2.2.1 Solution gas drive reservoir
The mechanism of solution gas drive some times referred to as depletion drive may be
summarized as follows for an under saturated reservoir.
Oil is displaced from the reservoir to production wells by liquid expansion. Reservoir
pressure usually declines rapidly during this phase of the production process since oil
4
5
and water are only slightly compressible. Since, gas solubility decreases with
declining pressure. The reservoir that was initially under saturated becomes a
saturated oil reservoir when the pressure decreases to the bubble point pressure.
Liquid expansion is no longer effective in displacing oil from the reservoir since the
oil phase will shrink as gas is released from solution. Gas bubbles expand throughout
the reservoir as pressure decreases thus showing the decline in reservoir pressure. Oil
production rates are likely to decrease as wells are produced further. Since increase in
gas saturation decrease the relative permeability to oil.
The reservoir pressure continues to decline and gas saturation continues to increase
until a continuous gas phase is formed and the gas becomes mobile. The minimum
gas saturation at which gas can flow within the reservoir is called the critical gas
saturation. During this phase of the solution gas drive, the produced gas oil ratio will
increase substantially and oil production rate will continue to decline.
Oil recovery for this mechanism usually ranges from 7 to 18 % of oil initially within
the reservoir.
2.2.2 Gas cap drive reservoir
It is the presence of this free gas volume that exists initially in the reservoir at initial
reservoir pressure and temperature conditions substantially alters the performance
behavior of this system during the primary producing life of this type of reservoir.
The recovery efficiency of a gas cap drive reservoir can be expected to fall between
10 to 25 % of the initial oil in place.
2.2.3 Water drive reservoir
A water drive reservoir is one in which oil column is associated with a very large
underlying aquifer. The oil column can be either an under saturated oil or a saturated
oil having a gas cap. For the system to be specially water drive reservoir, however the
6
gas cap does not play a part in the energy drive mechanism. For a saturated oil
reservoir to be performing as a true water drive and not a combination drive,
therefore, the pressure would have to be maintained such that the gas does not expand.
Ultimate recovery by this type of primary production drive can most commonly be
expected to range between 40 to 55 % though higher recoveries have been observed.
The quality of performance of a water drive type reservoir can be significantly
influenced by the rate of water production. It would be possible to produce at such a
high rate that pressure in the reservoir is drawn down considerably or continues to
decline because water cannot encroach at the same rate as oil is produced. This could
be due to limited access for water to enter the oil column.
2.2.4 Combination drive reservoir
A combination drive reservoir having a saturated oil column associated with an
aquifer. In which both the gas cap and aquifer expand in to the oil column as oil is
produced. For this condition to exist, oil must be produced at rate greater than the
aquifer water can approach, such that the pressure decline occurs allowing the gas cap
to expand. As pressure is declining therefore this is saturated oil system, gas will be
coming out of solution in the oil column. Therefore, all three drive mechanisms are
solution gas drive; gas cap drive and water drive are contributing the total driving
energy of the system. Off course, it is desirable for the water drive to be dominant,
and this could be achieved by lowering the oil producing rate.
2.2.5 Gravity drainage
Gas bubbles that are evolved at a greater distance from the well will migrate up-dip
displacing oil downward towards the well. Under favorable conditions such as steeply
dipping beds, low oil viscosity, and high vertical permeability, oil recovery by
gravitational segregation can be on the order of 75 % of oil originally in place. Under
less favorable conditions the oil recovered by this mechanism may be negligible.
7
Maximum oil recovery by gravity drainage will occur if the production rate does not
exceed the rate at which the gravitational segregation occurs in the reservoir. If the
producing rate exceeds the gravity drainage rate oil recovery will be reduced.
2.3 ARTIFICIAL LIFT METHODS
When pressure in the oil reservoir has fallen to the point, where the well does not
produce at the economical rate by natural energy, some methods of artificial lift
should be used. The most common methods of artificial lift are:
(a) Sucker- Rod Pumping
(b) Gas Lift (Continuous and Intermittent)
(c) Electrical Submergible Pumping
(d) Hydraulic Pumping
2.4 SECONDARY RECOVERY METHOD
The natural pressure of the reservoir has decreased external energy is introduced to
the reservoir to stimulate the production of oil to the well bore from which it can be
produced. This is known as secondary recovery method. It is further divided in to two
categories:
2.5 GAS FLOODING
Gas injection method can be subdivided into two categories;
2.5.1 Immiscible gas injection
It is very inefficient fluid for additional oil recovery. The gas is non-wetting to
reservoir rocks.
The gas will move through the larger spaces of the reservoir rock by passing much of
the reservoir oil. Some gas saturation will be present.
8
Thus the initial gas may be displacing gas not oil. Due to low viscosity of gas its
mobility is quite high which results in excessive channeling and by passing of the oil.
2.5.2 Miscible or high-pressure gas injection
The displacement of oil by non aqueous injected of hydrocarbons solvent, lean
hydrocarbon gases, such as CO2, N2 or flue gases are generally described as miscible
fluids. The various conditions of pressure and temperature that are required for
miscibility whether on first multiple contact or normally dealt. An important factor in
oil recovery process is that the mass transfer between displaced and the displacing
factor/ phase.
In multiple contact system residual oil behind displace center may stripped of light
and intermediate fraction reducing substantially the residual oil saturation. This is
known as vaporization gas drive. Another mechanism called condensing gas drive
involves the transfer of intermediate components from the displacing gas to the
residual oil. The residual oil becomes of a lower viscosity and has increase oil
permeability. These volume effects can be significant even when full miscibility is not
attempt. In an ideal process the swelling and the mobilization dispersed the
discontinuous residual oil phase.
Leads to the formation of oil bank which, may then itself seam residual oil as it moves
through the formation. Tripping behind the oil bank is prevented by miscible
condition or by very large capillary number, where the formation is connected by the
miscible solvent it is expected that the oil recovery is complete.
2.6 WATER FLOODING
Water flooding is a secondary recovery method by which water is injected into a
reservoir to obtain additional oil recovery through movement of reservoir oil to a
producing well. After the reservoir has approached its economically productive limit
by primary recovery methods. Water flooding has currently been the most widely
accepted method of secondary recovery and as considered as reliable and economic
9
recovery technique. Almost every significant oil field that does not have strong
natural water drive has been is being or will be considered for water flooding. It is
dominant among fluid injection methods and is without question responsible for the
current high level of producing rate within not only U.S. and Canada but in the rest of
the world as well. Water pressure maintenance is a process where by water is injected
into an oil producing reservoir to supplement natural energy indigenous to the
reservoir and to improve oil producing characteristics of the field prior to the time that
economic productive limits have been reached.
In determining the suitability of a given reservoir to water flooding or pressure
maintenance the following factors must be considered:
(i) Reservoir geometry
(ii) Lithology
(iii) Reservoir depth
(iv) Porosity
(v) Permeability Magnitude and degree of variation
(vi) Fluid properties and relative permeability relationships
(vii) Continuity of reservoir rock properties
(viii) Magnitude and distribution of fluid saturation
Also of great interest is the initial saturation of connate water. Knowledge of this
quantity is essential in determining the initial oil saturation. Low water saturation
means relatively large amounts of oil remain un- recovered after primary production.
Leveret and Lewis and other investigators have experimentally shown that oil
recovery, as a fraction of pore volume by solution gas drive is essentially independent
of connate-water saturations. Connate-water content may be estimated from cores
obtained by using oil-base mud, electric-log information, laboratory oil floods or
capillary pressure tests.
2.7 ENHANCED OIL RECOVERY
“Enhanced oil recovery” in general, this describes oil recovery process other than
primary recovery.
10
EOR is generally considered as the third or last phase of useful oil production. The
first or primary phase of oil production begins with the discovery of an oil field using
the natural stored energy to move the oil to the wells by expansion of volatile
components and/or pumping of individual wells to assist the natural drive when this
energy is depleted, production declines and secondary phase of oil production begins,
when supplement energy added to the reservoir by injection of water and gas.
For the last two decades, the scientists have been searching for techniques to recover
more oil from depleted reservoir, which still contain as much as 50 % of original oil
in-place (OOIP).
During the next decade, world production capabilities by conventional means will not
meet energy demands. Therefore, oil prices will continue to soar. Some speculate that
the soaring oil prices could make EOR very economically, attractive and that could be
the beginning of era, when unconventional petroleum resources become economic.
Viewed from the perspective the future of the petroleum industry is indeed bright,
even in the face dwindling new discoveries. Although rising oil and gas prices could
improve the economic climate for EOR, they could also pave the way for massive
development of non-fossil energy resources, solar, nuclear and geothermal-especially
since operating costs for EOR increase will rising oil prices. EOR techniques must be
developed to their full potential in order to supply the energy demands.
The EOR is often synonymous with tertiary recovery. Although some times EOR
methods can be used earlier in the sequence. In some older discussions water flooding
was considered as EOR but now EOR is generally thought to follow water flooding.
EOR process have been subdivided into five major categories and presented as
follows:
(1) Air Injection method
(2) Thermal recovery methods.
(3) Gas miscible recovery methods
(4) Chemical flooding method
(5) Microbial enhanced oil recovery method
11
2.8 AIR INJECTION
Air Injection process is commonly used as a secondary recovery process in high
permeability heavy oil reservoirs and low permeability light oil reservoirs.
In the past, air injection has found a wide application as a recovery method of heavy
oil. In heavy oil operation, air injection has been used primarily as a viscosity
reducing agent. Air injection into light reservoirs is a different process than heavy oil
combustion. Significant increase in light oil production under air injection can be
achieved with enhancement to the economics.
The main agent of the process is air which can be regarded as an inexpensive and
easily available. The total consumption of 5 to 10 % of the remaining oil in place can
be expected to maintain a propagation of the in-situ oxidation process. The flue gas
and steam generated at the combustion front are stripping, swelling and heating
contacted oil. The light oil is displaced at near miscible condition with complete
utilization of injected oxygen. The process can lead to a high recovery within a
relatively short period of time. The process can potentially result in all remaining oil
in place being produced. The propagation of the combustion and displacement front in
the reservoir can sometime be uncertain. Monitoring and control of combustion front
movement is important.
The potential of air injection process for an offshore field in the North Sea was
evaluated. A simulation reservoir model accounting for chemical reactions,
stoichiometry and thermal aspects of the combustion process was used. History match
simulations of the combustion tube experiments calibrated the fluid description in the
simulation model. Application of air injection as primary, secondary and tertiary oil
recovery process was evaluated. The simulation results showed a high efficiency of
air injection if applied at a late stage of field production. Secondary air injection
potential to improve oil recovery after depletion was estimated at 10 % of STOOIP in
comparison with secondary water flooding. While tertiary air injection was estimated
to improve water flooding by additional 5 % of STOOIP. Air injection in the light oil
reservoirs at late are mature production stage will increase oil recovery at low extra
cost and extend the economic life of the fields.
12
2.9 THERMAL RECOVERY PROCESSES
Thermal methods account for about 70 % of the world’s EOR production. Their
applications to reservoirs having low gravity, high viscosity and high porosity have
become almost in routine. There is every indication that this segment of enhanced oil
technology will continue to grow. It is further divided into three categories:
2.9.1 Cyclic steam stimulation
This method is some times applied to heavy oil reservoirs to boost recovery during the
primary production phase. During this time it assists natural reservoir energy by
thinning the oil so it will move easily through the formation to the injection /
production wells. However, it can also be used as a single -well producer.
To utilize this EOR method, a predetermined amount of steam is injected into wells
that have been drilled or converted for injection purposes. These wells are then shut-in
to allow the steam to heat or “Soak” the producing formation around the well. After a
sufficient time has elapsed to allow adequate heating, the injection wells are placed
back in production until the heat is dissipated with the production fluids. This cycle of
soak and produce, or Huff and Puff” may be repeated until the response become
marginal due to declining natural reservoir pressure and increase water production. At
this stage, a continuous steam flooding is usually initiated for two reasons:
i. To continue the heating and thinning of the oil.
ii. To replace declining reservoir pressure so that production may
continue.
When steam flooding is started, some of the original injection wells will be converted
to production wells. These wells and others drilled or designed for that purpose will
be used for oil production.
2.9.2 Steam flooding
As with the cyclic steam stimulation, this EOR method is usually used in heavy oil
reservoirs containing oil whose viscosity is a limiting factor for achieving commercial
13
oil producing rates. It has also been considered, however, as a method for recovering
additional light oil. High temperature steam is generated on the surface then
continuously introduced into a reservoir through injection wells. As the steam losses
heat to the formation, it condenses into hot water which coupled with the continuous
supply of steam behind it, provides the drive to move the oil to production wells.
As the steam heats the formation, oil recovery is increased because of the following
effects:
i. The oil becomes less viscous, making it easier to move through the
formation toward production wells.
ii. Expansion or swelling of the oil aids in releasing it from the reservoir rock.
iii. Lighter fractions of the oil tend to vaporize, and as they move ahead into
the cooler information ahead of the steam they condense and form a
solvent or miscible bank.
iv. Finally, the condensed steam cools as it moves through the reservoir and
results in what amounts to an ordinary water flood ahead of the heated
zone.
An added bonus from the use of steam in both cyclic steam stimulation and steam
flooding is the flushing of liners and casing perforations, as well as the reduction of
deposits that may build up in the wells. Possible flow restrictions to oil production
through the wells are thus reduced.
2.9.3 In- Situ combustion or fire flooding
This method is sometimes applied to reservoirs containing oil too viscous or “heavy”
to be produced by conventional means. By burning some of the oil in situ (in place) a
combustion zone is created that moves through the formation toward production
wells. A steam drive together with an intense gas drive is thus provided for the
recovery of oil. Lowering a heater or igniter into an injection well sometimes starts
this process. Air is then injected down the well and the heater is operated until
ignition is accomplished.
14
After heating the surrounding rock, the heater is withdrawn but air injection is
continued to maintain the advancing combustion front. Water is sometimes injected
simultaneously or alternately with air, creating steam that contributes to better heat
utilization and reduced air requirements.
Many interactions occur in this process are mentioned as follows:
i. Zone is burned out as the combustion front advances.
ii. Any water formed or injected will turn to steam in this zone
due to the residual heat. This steam flows on into the unburned
area of the formation, helping to heat it.
iii. This shows the combustion zone, which advances through the
formation.
iv. High temperature just a head of the combustion zone causes
lighter fractions of the oil to vaporize, leaving a heavy residual
coke or carbon deposit as fuel for the advancing combustion
front.
v. A vaporizing zone that contains combustion products vaporized
light hydrocarbons.
vi. In this zone, owing to its distance from the combustion front,
cooling causes light hydrocarbons to condense and steam to
revert back to hot water. This action displaces oil miscibility,
condensed steam thins the oil, and combustion gases aid in
driving the oil to production wells.
vii. In this zone, an oil bank (an accumulation of displaced oil) is
formed. It contains oil, water and combustion gases.
viii. The oil bank will grow cooler as it moves toward production
wells, and temperatures will drop to that near initial reservoir
pressure.
When the oil bank reaches the production wells, oil, water, and gases will be brought
to the surface and separated. The oil to be sold and the water and gases sometimes re-
injected.
15
Stopping air injection when pre-designated areas are burned out or the burning front
reaches production wells will terminate the process.
Notice in the accompanying illustration that the lighter steam vapors and combustion
gases tend to rise into the upper portion of the producing zone lessening the
effectiveness of this method. Injection of water alternately or simultaneously with air
clean lessen the detrimental overriding effect.
2.10 GAS MISCIBLE RECOVERY METHOD
Inert gas miscible projects are on the increase in recent years, in contrast to
hydrocarbon miscible projects, which are declining because of the high cost and
limited supply of injected hydrocarbons. Recent reports state that CO2 miscible
flooding could potentially recover 40 % of the total project enhanced reserves in the
USA. The Gas miscible recovery methods are:
2.10.1 Cyclic carbon dioxide stimulation
Cyclic CO2 stimulation is a single well operation, which is developing as a method of
rapidly producing heavy oil. Cyclic CO2 stimulation is similar in operation to the
conventional cyclic or “huff and-puff” steam injection process. In other wards, CO2 is
injected into a well drilled into an oil reservoir, the well is then shut-in for a time
providing for a “soak period” then is opened allowing the oil and fluids to be
produced.
In this process some or all of the following mechanisms accomplishes the production
of additional oil produced:
i. CO2 dissolves in the oil, reducing its viscosity and allowing the oil to flow
more easily toward the well.
ii. Increased oil –phase saturation due to CO2 dissolving in the oil and
causing it to swell.
iii. Solution gas drive achieved by the evolution of CO2 and natural gas from
the oil phase at the lower pressures occurring during production.
16
iv. Hydrocarbon extraction by the supercritical CO2 gas.
This process is most applicable to viscous (heavy) oil reservoirs that have high oil
saturation and temperatures or pressures that preclude miscibility between oil and
CO2. The most important operating parameters are volume of CO2 injected per cycle,
number of cycles and degree of backpressure during production.
This process can be repeated several times, but efficiency decreases with the number
of cycles. Cyclic CO2 stimulation can be useful in recovering heavy oil in case where
thermal methods are not feasible.
2.10.2 Carbon dioxide flooding
Carbon dioxide is a common material normally used in the form of gas and can some
times be used to enhance the displacement of oil from a reservoir. It occurs naturally
in some reservoirs either with natural gas or as a nearly pure compound. It can also be
obtained as a by-product from chemical and fertilizer plants or it can be manufactured
or separated from power plant stack gas.
When pressure in a candidate reservoir has been depleted through primary production
and possibly water flooding, it must be restored before CO2 injection can be begin. To
do this water is pumped into the reservoir through injection wells until pressure
reaches a desired level then CO2 is introduced into the reservoir through the same
injection wells. Even though the CO2 is not miscible with oil on first contact when it
is forced into a reservoir. A gradual transfer of smaller, lighter hydrocarbon molecules
from the oil to the CO2 generates miscible front. This miscible front is in essence a
bank of enriched gas consisting of CO2 and light hydrocarbons. Under favorable
conditions of pressure and temperature, this front will be soluble with the oil making
it easier to move toward production wells.
This initial CO2 slug is followed by alternate water and CO2 injection the water
serving to improve sweep efficiency and to minimize the amount of CO2 required for
the flood. Production will be from an oil bank that forms ahead of the miscible front.
Reservoir fluids are produced through production wells, CO2 reverts to a gaseous
state and provides a “gas lift” similar to that of original reservoir natural gas pressure.
17
On the surface, the CO2 can be separated from the produced fluids and may be
reinjected helping to reduce the amount of new CO2 required for the project; thus, the
CO2 can be recycled. This procedure may be repeated until oil production drops
below a profitable level.
2.10.3 Nitrogen flooding
Nitrogen flooding can be viable EOR method if certain conditions exist in the
candidate reservoir. These conditions are as follows:
i. The reservoir oil must be rich in ethane through hexane (C2-C6) or lighter
hydrocarbons. These crudes are characterized as “light oils” having an API
gravity higher than 35o.
ii. The oil should have a high formation volume factor or the capability of
absorbing added gas under reservoir conditions.
iii. The oil should be undersaturated or low in methane (C1).
iv. The reservoir should be at least 5,000 feet deep to withstand the high
injection pressure (in excess of 5,000 psi) necessary for the oil to attain
miscibility with nitrogen withought fracturing the producing formation.
v. Gaseous nitrogen is attractive for flooding this type of reservoir because it
can be manufactured on site at less cost than other alternatives. Since it can
be extracted from air by cryogenic separation, there is an unlimited source
and being completely inert and non-corrosive.
In general when nitrogen is injected into a reservoir, it forms a miscible front by
vaporizing some of the lighter components from the oil. This gas now enriched to
some extent continues to move away from the injection wells contacting new oil and
vaporizing more components thereby enriching itself still further. As this action
continues the leading edge of this gas front becomes so enriched that it goes into
solution or becomes miscible with the reservoir oil. At this time the interface between
the oil and gas disappears and the fluids blend as one.
Continued injection of nitrogen pushes the miscible front (which continually renews
itself) through the reservoir moving a bank of displaced oil toward production wells.
18
Water slugs are injected alternately with the nitrogen to increase the sweep efficiency
and oil recovery.
At the surface the produced reservoir fluids may be separated not only for the oil but
also for natural gas liquids and injected nitrogen.
2.11 CHEMICAL FLOODING METHODS
The chemical processes for recovering additional oil account for less than 1 % of the
enhanced oil recovered in the USA. Although these processes have the best chance for
recovering oil from reservoirs that have been successfully water flooded (but still
contain considerable oil) development has been slow because of associated high costs,
high risk and complicated technology. Chemical Flooding methods are:
2.11.1 Polymer flooding
Reservoir conditions sometimes exist that cause a lowering of the efficiency of a
regular waterflood. Natural fractures or high permeability regions in the reservoir rock
sometimes will cause the injected water to channel or flow around much of the oil in
place by taking the path of least resistance.
The heavier or more viscous oil will also cause problems for a waterflood operation
because of their resistance to more mobile or free flowing water.
To help prevent injected water from by passing oil, water can be made more viscous
or thickened by the addition of a water soluble polymer. This effect allows the water
to move through more of the reservoir rock, resulting in a larger percentage of oil
recovery. Fresh water is usually injected behind the polymer solution to prevent it
from being contaminated by the final water drive that may produce brine.
2.11.2 Micellar-polymer flooding
This is an EOR method, which uses the injection of a micellar slug into a reservoir.
This slug is a solution containing mixture of surfactant, alcohol, brine and oil that acts
19
to release oil from the pores of the reservoir rock much as a dish washing detergent
releases grease from dishes so that it can be flushed away by flowing water.
As the micellar solution moves through the oil bearing formation in the reservoir, it
releases much of the oil trapped in the rock. To further ethane production polymer
thickened water for mobility control (as described in the polymer flooding process) is
injected behind the micellar slug. Here again a buffer of fresh water is injected
following the polymer and ahead of the drive water to prevent contamination of the
chemical solutions.
2.11.3 Alkaline flooding
This method of EOR requires the injection of alkaline chemicals (lye or caustic
solutions) into a reservoir. The reaction of these chemicals with petroleum acids in the
reservoir rock results in the in situ formation of surfactants. The surfactants help to
release the oil from the rock by one or more of the following mechanisms: reduction
of interfacial tension, spontaneous emulsification and wettability changes. Then oil
can be more easily moved through the reservoir to production wells.
As in the two preceding methods a polymer thickened water solution is introduced
after the chemicals are injected to aid in obtaining a more uniform movement or
“sweep” through the reservoir.
Fresh water is then injected behind the polymer solution to prevent contamination
from the final drive water, which may be salty or other wise incompatible with the
chemicals.
Alkaline flooding is usually more efficient if the acid content of the reservoir oil is
relatively high.
2.12 MICROBIAL ENHANCED OIL RECOVERY METHODS
Microbial EOR methods include:
2.12.1 Cyclic microbial recovery method
20
This is one of the newest EOR methods and requires the injection of microorganisms
and nutrients solution down a well into oil reservoir. This injection can usually be
performed in a matter of hours depending on the depth and permeability of the oil
bearing formation. Once injection is accomplished the injection well is shut-in for
days to weeks. This time known as an incubation or soak period the microorganisms
feed on the nutrients provided and multiply in number. These microorganisms
produce products metabolically that affect the oil in place in ways that make it easier
to produce products metabolically that effect the oil in place in ways that make it
easier to produce. Depending on the microorganisms used these products may be
acids, surfactants and certain gases most notably hydrogen and carbon dioxide. At the
end of this period the well is opened and the oil and products resulting from this
process are produced.
This method eliminates the need for continual injection but after the production phase
is completed a new supply of microorganisms and nutrients must be injected if the
process is to be repeated.
2.12.2 Microbial flooding method
Microbial flooding method is performed by injecting a solution of microorganisms
and a nutrient such as industrial molasses down injection wells drilled into an oil
bearing reservoir. As the microorganisms feed on the nutrient they metabolically
produce products ranging from acids and surfactants to certain gases such as hydrogen
and carbon dioxide. These products act upon the oil in place in a variety of ways
making it easier to move the oil through the reservoir to production wells. The
microbial and nutrient solution and the resulting bank of oil and products are moved
through the reservoir by means of water drive injected behind them.
CHAPTER 3
LITERATURE REVIEW
3.1 HISTORIC PERFORMANCE OF AIR INJECTION PROCESS
Air Injection (AI) has been applied successfully since the mid 1980’s in fields near
the coral creek anticline (CCA), such as Medicine pole hills unit (MPHU) and the
South buffalo red river unit (SBRRU) (1,2)
. These fields, owned and operated by
Continental Resources Inc., have not been water flooded and are undergoing AI in a
secondary mode. The oil and reservoir characteristics of those fields are typical for
those found in the CCA. However, because these fields are further down dip, their
initial oil saturations are in the 55 to 57 % range, significantly lower than Shell’s up
dip reservoirs (around 80 %). The average response in the South buffalo red river unit
resulted in production rates twice those initially achieved on primary. It took about
three years to achieve plateau production that was sustained for eight years. The field
is currently on a slow decline. As clearly shown in combustion tube experiments, (3, 4,
5) a minimum air flux (front propagation rate) is required to sustain combustion at
high pressure. Experimental minimum front propagation rates range between 3, 12
and 30 ft/day (5)
. In low permeability carbonates with radial outflow of air from
injection wells, these rates can be reached only in the vicinity of injectors. After more
than 15 years of air injection at the South Buffalo field HPAI project, no free oxygen
has been detected at all but one producer. As previously suggested, (6)
large field well
spacing provides the residence time required for complete oxygen removal. Due to the
low air rates in the field and the resulting combustion extinction a short distance from
the injectors, most of the oil displacement consists of a flue-gas drive with no
significant thermal effects. Moore (7)
has made the point that fire flooding of heavy oil
deposits is “much more a displacement process than a thermal process.
This is even more prevalent in the case of high-pressure air injection in light oil
reservoirs where a distributed low-temperature oxidation process takes place.
21
22
Consequently field air oil ratio (AOR) values currently observed for Medicine Pole
Hills and South Buffalo (7 and 14 Mscf/stb, respectively) are much lower than the
theoretical combustion AOR’s of 16 and 33 MSCF/STB.
The production performance of a typical pattern of South Buffalo was simulated with
a compositional isothermal model. A good historic match on oil production, gas oil
ratio (GOR) and AOR was obtained.
3.2 RECOVERY PROCESSES AT THE CORAL CREEK ANTICLINE
HPAI offers another tertiary alternative with the potential of profitably recovering an
additional 7 % to 15 % of the Original Oil in Place (OOIP). HPAI, a displacement
process for light oil deposits, does not require thermal effects for oil mobilization. It
depends on the reactivity of oxygen with crude oil components to generate flue-gas
[15 % CO2 + 85 % N2] flood. The reactivity of light oils described in the literature as
a low temperature oxidation (LTO) (8, 9)
phenomenon is the key for oxygen
scavenging by the oil. The mobility ratio is although not as high as with high viscosity
heavy oils is still unfavorable resulting in poor Buckley–Leverett displacement. Two
effects however contribute to improved performance: (a) A significant fraction of the
gas is dissolved in the oil phase resulting in oil swelling and reservoir re-
pressurization. (b) Oil is also transported in the gas phase by stripping this result in
peak production rates experienced after gas breakthrough in contrast to what is
observed in a heavy oil case.
The potential of air as a tertiary injectant was recognized more than 15 years ago by
Koch Oil Company, which started air injection in the Williston Basin (South Buffalo
Field) as a means to tackle the poor water injectivity of low-permeability porous
carbonates. Air injectivity grows with the growing extension of the gas cap, whereby
the resistance of the shrinking liquid bank is continuously reduced. When HPAI is
implemented after primary depletion the higher injectivity of air allows larger well
spacing than that required in water flood operations. The oil response to HPAI in
tertiary applications is a function of (a) Maturity of the water flood, i.e. the water-cut
at the beginning of air injection.
23
(b) Difference between the residual oil saturation to water and the residual oil
saturation to gas. The incremental response to HPAI is mainly a function of the latter.
However, another factor in relatively thick flow units (>20 ft) is gravity segregation.
Simulations show that top intervals of formations developed with large well spacing
experience poor water sweep and excellent sweep of a much lighter fluid like high-
pressure air. This segregation effect makes it possible for air to contact oil at the top
layers that has not been contacted by previously injected water.
Air injection for oil recovery from deep light oil reservoirs has been recommended for
the following reasons (11)
. First, a gas is needed to pressurize the reservoir or maintain
its pressure during depletion. Compared to other gases, air is a better choice for
injection because it also reacts with oil to form flue gas (85% N2, 15% CO2) in situ.
Compressing air is generally cheaper than injecting nitrogen or CO2. Also, because of
mass transfer between the oil and flue gas or air at reservoir conditions, the light
hydrocarbon components are stripped off the oil. These components appear as NGL in
the producing gas stream (12)
. Because of in situ combustion, part of the residual oil to
gas is mobilized and moves towards the producing well. Generally, the deeper and
warmer reservoirs are better candidates. Higher pressure enhances miscibility and
higher temperatures improve oxygen utilization. Finally, air is available in remote
locations so lack of solvents not a problem in this process.
When air is injected, upon ignition of the oil, a combustion front is created around the
injector. The mobilized oil by the combustion front is expected to add to the thickness
of the oil column created by gravity drainage.
The effect of injecting nitrogen instead of air was investigated. i.e., the nitrogen and
air response is virtually the same until much later when the thermal oil bank arrives at
the producers. Other injection schemes such as cyclic injection-production and an
injection period followed by a waiting-period before the start of production also were
modeled. These injection schemes generally had mixed oil response due to their
dependency on an optimum timing.
Experimental results indicate that combustion will occur at reservoir conditions.
However, the hot regions should be limited to the upper parts of the fault block sand
away from the producers during the injection period studied.
24
This project is designed on an environmentally sound basis. Compositional effects
play an important role in the stabilization of the gas displacement front. Based on the
advantages of air injection, this process might have worldwide application.
The Medicine pole hills unit (MPHU) EOR project is the deepest air injection/ in-situ-
combustion project in the Williston basin. A unit comprising 9,600 acres with 13
producing wells was formed in July 1985 and air-injection operations began in Oct.
1987. Laboratory combustion tests and detailed feasibility studies were completed
before starting the full-scale project. The combination of light oil (39 oAPI) carbonate
formation hot reservoir (230 oF) low permeability (1 to 30 md) makes this unique air-
injection project.
Air injection was considered to be a viable alternative primarily because of the
successful performance of the Buffalo field air-injection project 20 miles south of
Medicine Pole Hill field. Laboratory combustion tests, miscibility tests, reservoir fluid
studies, and detailed feasibility studies were completed before forming the unit.
High-pressure air-injection operations began in Oct. 1987 and cumulative air injection
into seven injectors was 12 BSCF as of Dec. 1993.
3.2.1. Reservoir fluid study
Samples of separator gas and liquid were collected to determine reservoir fluid
properties and phase behavior.
3.2.2. Combustion-tube tests
Three combustion tube runs were conducted to study the combustion characteristics
of the oil. The first run was terminated owing to extensive heat loss and lack of
sufficient fuel; an adiabatic test was conducted in the second run. Although the
burning front was stable in this run the oxygen utilization efficiency was only 49 %.
Two runs were conducted at initial conditions of 300 psig and 70 oF because of
equipment limitations of the commercial laboratory used. The higher reservoir
pressure and temperature at MPHU were expected to cause better oxygen utilization.
25
Air injection began in March 1986 but was suspended after 2 months of injection
because of the decline in oil price. Air injection was resumed in Oct. 1987 and has
continued to the present. Currently air is being injected into seven injectors at a rate of
9 MMSCF/D and a pressure of 4,400 Psi. The injection rates on most wells have been
fairly constant or have increased slightly over time. Gas production started to increase
after 5 months of continuous injection and is now 45 % of air injection.
Oil production has increased from 400 BOPD before unitization to the current rate of
950 BOPD. O2 utilization is 100 % on the basis of analysis of combustion gas
produced.
The ratio of injected air volume to produced oil, AOR, is generally used to measure
the performance of an air-injection project.
The MPHU reservoir is a deep, high temperature, Red River light oil reservoir proved
to be a suitable candidate for high-pressure air injection. Consistent laboratory results
indicated oil; rock and reservoir conditions were favorable to the implementation of
air injection.
NGL production is a significant component of liquids production in light oil HPAI
Projects. After 6 years of operations the MPHU air-injection project has achieved an
attractive air - (oil-plus-NGL) average ratio of 8 MSCF/STB.
In heavy oil operations air injection has been used primarily as a viscosity reducing
agent. Air injection / in-situ combustion has been shown to be technically feasible in
light oil reservoirs following water flooding but wide economic viability under
tertiary conditions have not been firmly established. Air is a low cost injectant and
unlike in the case of heavy oils the primary factor responsible for improved oil
recovery is not just the viscosity reduction. In fact depending on the circumstances air
injection into. A light reservoir can serve a multiplicity of functions. Air injection at
high temperature and pressure (deep reservoirs) could lead to unique economic and
technical opportunities for IOR in many candidate reservoirs under both secondary
and tertiary conditions, well beyond the traditional combustion applications.
Part of the oil remaining after implementation of conventional recovery methods can
in general be produced by suitable EOR methods. For a certain category of reservoirs
and fluids hydrocarbon gas injection has bean shown to be very promising.
26
Many mature fields have been identified as suitable candidates for lean gas injection
in tertiary conditions. For these reservoirs the additional tertiary reserves by gas
injection have been estimated between 8 and 15 % of the original oil in place
depending on the actual reservoir properties and the nature of the injected gas.
Air injection into light oil reservoirs may be regarded as a new alternative EOR
method for both secondary and tertiary EOR processes. The main mechanisms leading
to improved oil recovery concern both classical gas injection effects and additional
effects due to the presence of oxygen in the injectant. When air is injected into a light
oil reservoir exothermic chemical reactions occur between the oxygen and the
reservoir oil. These reactions in the case of light oil are mainly oxidation reactions
resulting in heat generation and in the production of the oxides of carbon (mainly CO
& CO2) with corresponding consumption of oxygen. These reactions are dependant on
the oil characteristics, rock / fluid, system, temperature and pressure. The latter
controls the partial pressure of oxygen in the reservoir. The heat of reactions results in
a temperature elevation leading to vaporization of the lighter components. The driving
gas therefore is not the injected air but the in-situ generated flue gas, which is
composed of CO, CO2, N2 and the vaporized light hydrocarbon components. The
mechanisms are numerous and complex (11)
. The relative importance of each
individual affect will depend on the specific reservoir context. They include the
following:
1. Reservoir pressure maintenance / pressurization.
2. Gravity drainage process between flue gas and reservoir oil.
3. Vaporization of reservoir oil by flue gas
4. Oil displacement by gases
5. Supercritical steam effects (high pressure temperature case)
6. Possibly development of miscibility between flue gas and reservoir oil
Most of these beneficial effects are enhanced with higher pressures and temperatures.
The laboratory experiments were designed with the following objectives:
1. Acquire a better understanding of the mechanisms involved.
2. Identify critical process parameters
3. Evaluate oxygen consumption
27
4. Provide Kinetic parameters / basic thermal parameters for core flood
simulation up- scaling and field simulations.
Historically experiments relating to in-situ combustion processes have been
performed with combustion tube (13)
. This consists of a metallic tube filled with
crushed rock and reservoir oil. An adiabatic conditions are achieved through heaters
and temperature recorders installed both inside and on the periphery of the crushed
core.
The oil oxidation reactions are triggered by pre heating the tube at the inlet (>200 oC).
In this study a consolidated core was used in each displacement. Specific equipment
was therefore developed to study air injection in consolidated porous medium with
light oil under reservoir conditions. Compared with the combustion tube the use of
consolidated reservoir core provides a significant improvement in simulating
representative reservoir flow conditions. However this equipment has been operating
under non-adiabatic conditions so far. The temperatures recorded during the
experiment are therefore lower than that would be obtained under truly adiabatic
conditions.
Several papers have been published (1, 9, 11, 14, 15)
discussing the process of air injection
for light oil recovery and describing the criteria for a successful project. The
performance of some light oil air injection field projects has also been discussed in
these papers (1, 15)
. However, the economics of this process have never been fully
addressed before. This paper discusses the economics of a successful on-going
project, the Medicine Pole Hills Unit (MPHU, ND), and a new project underway at
West Hackberry, LA. The economics of air injection in low-pressure fault blocks for
repositioning and producing the oil rim are discussed as well.
3. 3. PROCESS ADVANTAGES
Air injection can offer unique economic and technical opportunities for improved oil
recovery in many reservoirs. Advantages for the air injection process in light oil
reservoirs include: excellent displacement efficiency, near-miscibility and associated
enhanced hydrocarbon extraction capability of the flue gas, spontaneous oil ignition
28
with complete oxygen utilization and operation above the critical point of water with
possible super extraction benefits (16)
.
3. 4. DIFFERENCE BETWEEN LIGHT OILS AND HEAVY OILS UNDER
AIR INJECTION
The combustion process for displacement of light oils is fundamentally different than
the heavy oil combustion process. For heavier crude oils, heat and steam generation
and subsequent viscosity reduction is the primary oil displacement mechanism. For
this reason, in-situ combustion in a heavy oil reservoir should operate in the high
temperature oxidation reaction regime. For light oils, however, the heat generated is
of secondary value and flue gas generation is the primary factor in displacing oil.
Burning in a high temperature oxidation mode is of little consequence so long as the
Combustion front is self-sustaining and oxygen is consumed. Due to the early history
of air injection, most of the industry’s experience has been with heavy oil
applications. However, emphasis has been shifting to light and medium gravity oils,
due to technical and economic advantage.
3. 5 OBSERVATIONS FROM FIELD PROJECTS
Air injection into high-pressure reservoirs for light oil recovery is an emerging area of
technology application, a small number of successful light oil field air injection
projects have been documented in the technical literature (1, 15)
. Most have been
operated for many years, a fact which attests to their technical and economic success.
Selected financial information for onshore heavy oil projects can found in the
literature (17, 18)
. There has been no previously published economic analysis of a light
oil air injection field project, documenting the incremental revenues and costs of an
air injection project.
Air injection into light oil reservoirs can be divided in two principal modes: (a) the
conventional drive process, in which a combustion front displaces the oil horizontally,
and (b) a drainage process, in which the injection of air into a dipping reservoir causes
29
gravity drainage. MPHU is essentially a frontal displacement process, while West
Hackberry is based on the gravity drainage principle.
The feasibility of air injection into deep light oil reservoirs in the North Sea and
elsewhere has been investigated. The low temperature oxidation (LTO) process
removes oxygen in the injected air, to produce displacement gas (mainly nitrogen) in
the reservoir in order to achieve incremental IOR. Reaction and displacement studies
on four light oils have been carried out at reservoir conditions. This has involved the
high-pressure oxidation tube facility at Bath University as well as a small high-
pressure isothermal reactor.
The success of an air injection project for light oil reservoir application relies on two
important factors: removing oxygen and improving oil recovery. A number of studies
on gas injection (19, 20, 21)
has concluded that at least 6- 10 % incremental oil
production can be achieved by nitrogen, hydrocarbon gas or flue gas injection after
water-flooding. The primary concern of air injection in light oil reservoirs is to
consume all of the oxygen by low temperature oxidation (LTO) at reservoir
temperatures and to achieve at least nitrogen flooding. The thermal effect from the
reactions is not necessary in this case. It is therefore important to study the LTO
reaction scheme and the reaction products.
Laboratory studies of LTO have involved the use of isothermally controlled reactors
(22, 23, 24, 25, 26) and adiabatically controlled calorimeters (Accelerating-Rate
Calorimeter, ARC (9)
. Field experiences and project designs (2, 27, 28)
indicates that
spontaneous LTO reaction, leading to in-situ combustion, may occur in the fields with
relatively high reservoir temperatures 90 to 120 OC and pressures. However, this
process is restricted to those oil candidates, which exhibit a continuous adiabatic
exotherm, i.e. will progress to combustion at a temperature greater than 300 OC. On
the other hand, if the adiabatic exotherm is discontinuous, this means that the oil will
only undergo LTO at much lower temperatures.
Apart from Sakthikumar et al (29)
, there is very little reported data on the effect of
LTO in high-pressure light oil reservoirs, especially concerning the rate of oxygen
consumption and whether or not any thermal effect is generated in the reservoir.
30
3.6 OIL RECOVERY
Oil recovery is mainly affected by the characteristics of the core materials, such as
porosity, permeability and wettability as well as the oil properties namely
composition, viscosity and density. It is also affected by the residual oil saturation and
air injection rate. The oil recovery from the two oxidation tube tests was generally
high, and more than 70 % OOIP was recovered, leaving a residual oil saturation of
about 17 % in the sand pack. The latter is of course governed by the limited duration
time of the oxidation tube test compared with the in-situ combustion (HTO) tests
mentioned previously for the Australian light oil, which recovered 64 % OOIP after
thermal front had reached 90 % of the tube length (in 9 hours) the recovery rate for
the LTO Test-1 was higher. Less water was also produced (270 ml totally compared
to 750 ml) over 175 hours. The total quantity of air injected in the HTO test was 677
liters (standard condition), while in LTO test-1 it was 237 liters. For LTO Test-2,
even more oil was produced since it was operated without gas breakthrough.
3. 7 REACTION KINETICS MODEL
Oxidation of crude oils is a kinetically controlled process. The Arrhenius-type
equation is therefore used to describe the reaction rate as a function of oxygen partial
pressure and temperature. For a closed static system and assuming oil is in excess, the
reaction rate can be expressed in terms of reduction in oxygen partial pressure with
time, so that:
d (px)/dt= ko.e-E/RT.(px)n
Where,
Px = Oxygen partial pressure (bar)
ko = Pre exponential constant
E = Activation energy (J)
R = Gas constant
T = Absolute temperature (K)
31
n = Reaction order on oxygen partial pressure
Ko, E/R and n are so-called reaction parameters, which are dependent on oil
and reservoir rock properties and are usually determined by experiment using
specific techniques.
In previous kinetics studies of oil oxidation, most reactors have used an isothermal
ramp-controlled heat-up procedure with a relatively high heat rate 0.1 to 5 OC/min to
determine the relationship between oxygen consumption and temperature, in a gas
flow-through system. This is satisfactory for high temperature oxidation (in-situ
combustion), where the reaction rate is faster, or comparable to the heating rate. For
LTO reactions, where the reaction rate is very slow (less than 0.02 OC/min in terms of
heating rate for a 100 ml reactor volume), conventional ramped heating procedures
cannot be used to study the LTO reaction rate. An accelerating rate calorimeter (ARC)
with adiabatic temperature control has also been employed to study oil reactivity (9)
.
The small high-pressure isothermal reactor developed in this study has shown to be
suitable for LTO reaction kinetics studies at high pressure. Measurement of the rate of
pressure reduction under static conditions can be used to monitor the oxygen
consumption rate during reaction.
A modified oxidation /combustion tube facility has proved to be effective for
conducting LTO air injection experiments at near reservoir conditions. Using this
facility, it was possible to detect the gas breakthrough point to analyze the produced
gas composition and to measure the oil production rate at very low air injection rates.
The experimental results obtained from the small isothermal reactor and the oxidation
tube indicates that most of the light oils tested are sufficiently reactive at near-
reservoir conditions for air injection (LTO process) to be feasible. In most cases
nearly complete oxygen utilization equivalent to 200 % HCPV air injected was
achieved. This produced up to 9 % CO2 and some CO (around 1%). These first stage
experiments are a very positive indication of the potential viability of the air injection
LTO process. Further detailed study of the reaction rate and oxygen consumption
under different oil and water saturation using reservoir consolidated core is needed to
more precisely define the reaction model and displacement behavior.
32
High oil recovery was obtained under low rate LTO conditions (<120 oC) using both
crushed reservoir core and artificial sand packs. This recovery was found to be
comparable to that achieved for a light Australian crude oil (39 oAPI) under high air
injection rate and with a high temperature (250 oC) thermal front (HT process). The
overall economics for the LTO process is estimated to be similar to a conventional
nitrogen flood (exclude gas separation cost) and comparable also to a HT process for
light oil recovery.
Air injection processes (AIP) comprise those oil recovery processes, which occur
naturally when air is injected in an oil reservoir, the type of AIP occurring depends
mainly on reservoir temperature and pressure and on the oil and rock properties. In-
situ combustion (ISC) process is one variation of air injection and it has been applied
commercially for more than 30 years.
The main difference between AIP and ISC is due to the fact that the application of
ISC sometimes requires an ignition operation in order to initiate the process (create
the heat wave) while the application of AIP does not require any artificial means to
ignite the oil formation. The application of the ISC process is associated with the
existence of a high peak temperature 350 to 600 OC therefore formation of a vigorous
ISC front, which travels from the injection to the production wells. The application of
AIP does not necessarily assume the existence of a high peak temperature 350 to 600
OC. An ISC process is an AIP process but the reverse is not true; some of the AIP
processes cannot be considered as ISC processes at all.
The in-situ combustion does not appear feasible for extremely low porosity matrix
reservoirs; the porosity requirement is directly related to heat losses within the matrix.
However, if the intent of air injection is merely pressure maintenance (repositioning
of oil water contact) with a possible side effect of low temperature oxidation /high
temperature oxidation, the air injection should still be feasible if the injection of air as
a miscible or an immiscible gas displacement process is possible. So long as the
composition of air or a mixture of nitrogen with hydrocarbons is closer to that of
nitrogen, the miscibility of nitrogen should be the starting point in analyzing the
feasibility of air injection processes.
33
Generally if the miscibility with nitrogen cannot be achieved, only an immiscible gas
displacement needs to be evaluated, as this represents the application of air injection
as an immiscible gas flood.
3. 8 AIR INJECTION-BASED OIL RECOVERY PROCESSES
The air injection-based oil recovery processes can be evaluated based on the screening
criteria of the improved oil recovery processes. Basically the screening criteria for the
application of in-situ combustion gas miscible flooding and immiscible gas flooding
were utilized. When one injects air into an oil reservoir, two simultaneous phenomena
occur: displacement of oil and oxidation of the oil.
According to the efficiency of displacement and the intensity of oxidation, there are
four main types of processes can occur:
1. Immiscible air flooding (IAF) with intensive oxidation (IO)
2. Immiscible air flooding (IAF) without IO
3. Miscible air flooding (MAF) with IO
4. Miscible air flooding (MAF) without IO.
The last two processes are commonly known as high-pressure air injection (HPAI)
processes.
According to the intensity of oxidation, either the low temperature oxidation (LTO) or
the high temperature oxidation (HTO) reactions can dominate the development of the
process. Actually, when HTO takes place in the immiscible air flooding, the classic
in-situ combustion process is obtained, while if only LTO takes place, the process is
called LTO-IAF (LTO combined with immiscible air flooding).
Actually, the LTO-IAF was sometimes unintentionally obtained while applying ISC,
either when the ignition operation was not successful or the ignition operation was
successful but the ISC front did not sustain itself due to any of a variety of reasons.
Therefore, this kind of process has been applied only for relatively viscous and
viscous oils. So far the LTO-IAF process has not proved to be an effective IOR
process (as compared to ISC process). As a matter of fact, it seems to be the least
efficient one.
34
Stoichiometrically, the volume of air injected during HTO-MAF is roughly the same
as that of the gases produced, and hence, the oxidation reactions do not significantly
impact on pressure maintenance. For the LTO-MAF process, a part of oxygen is
consumed without releasing carbon oxides, leading to shrinkage of the injected gas
volume. Consequently the benefits of pressurization are somewhat less for this
process and some over-injection may be considered.
Air injection can be used in both horizontal and vertical flooding whether the target
reservoir is an unfractured or fractured formation. In a vertical flood, air is injected at
the top of the structure (which may be a reef) and oil is produced from lower
intervals, taking full advantage of the vertical relief within the pay zone and gravity
forces. This way, the volumetric sweep efficiency and displacement efficiency are
aided by natural forces and are usually extremely efficient. In the hydrocarbon
miscible flood, field experience has indicated incremental oil recovery using a vertical
flood to be of the order of 30 % OOIP, where as for horizontal floods, the incremental
oil recovery is typically 10% OOIP. This difference in the magnitude of oil recovery
is expected to remain the same for the application of air injection in these two modes.
Generally, the horizontal immiscible gas injection can increase the ultimate oil
recovery by up to 5 to 6 % OOIP. For a vertical immiscible flood this increment is
expected to be much higher.
As far as the potential of incremental oil recovery is concerned, air immiscible air
flooding process, may increase the ultimate oil recovery by at least as much as the
immiscible gas injection (nitrogen, flue gas or hydrocarbon gas injection). A special
case of these is pure oxygen injection. In this case only carbon dioxide will appear at
the production wells and the process could be analyzed as an either miscible or
immiscible carbon dioxide flooding; for both cases the incremental oil recovery is
higher, due to a less severe overriding phenomenon, because the density of the carbon
dioxide under reservoir conditions is higher than that of nitrogen or of mixtures of
nitrogen with other gases. For a successful air injection project the following
conditions should be met:
Oxygen utilization is practically 100 %
Spontaneous ignition is readily achieved.
35
In order to meet the frost condition additionally, two conditions should be satisfied:
Relatively homogeneous pay section (lack of pronounced heterogeneities) sufficient
fuel to sustain in-situ combustion or a very high reservoir temperature leading to 100
% oxygen utilization in an LTO mode.
3.9 DEVELOPMENT OF THE MAF (HPAI) PROCESSES
An oil reservoir can be ignited around a well bore by means of an artificial ignition
device (a gas burner or an electric heater) or by spontaneous ignition of the oil, upon
injecting air into the formation. A burning front (ISC front) moves outwards and the
combustion is sustained by continuous injection of air (dry combustion) or air/water
mixture (wet combustion). A small portion of the oil is burned generating heat
typically, peak temperatures of 350 to 600 °C are attained.
The continuous injection of air (or alternate slugs of air and water) provides an
efficient pressure maintenance in addition to other important heat displacement
mechanisms such as: oil viscosity reduction, generation of steam and hot water,
miscible effects due to the vaporized light oil ends flowing ahead of the ISC front, a
reduction in the effect of heterogeneities due to the heat conduction in the tighter
zones, etc.
Two main oxidation reactions can take place in the ISC process: high temperature
oxidation (HTO) and low temperature oxidation (LTO). HTO reactions are specific to
temperatures higher than 300 °C and are associated with the peak temperature of the
ISC front, while LTO reactions can take place downstream of the ISC front, when the
oxygen is not consumed completely in the HTO reactions. Also, the LTO reactions
are responsible for initiation of the ISC by spontaneous ignition. Artificial ignition, on
the other hand is time consuming, and expensive. Actually, the initiation of the ISC
by spontaneous ignition significantly simplifies application of the ISC process.
Until 1979, ISC process was commercially applied mainly in heavy oil, non-fractured
and non-carbonate reservoirs. The process was applied both using patterns (usually
five spot) and line drive (31,32,33)
.
36
The best result were obtained for the line drive application, when the process was
applied as a “top down” process, starting from the up most part of the structure.
The widespread acceptance of HPAI as an IOR process came in 1994, when the
results of commercial HPAI processes in the Williston Basin North and South Dakota,
USA were published at the forum on the ISC processes in Tulsa (34)
. It is interesting to
mention that these processes were reported after 15 and 7 years of commercial
operation, respectively.
It is important to mention the fact that these processes were developed directly in the
field without any laboratory support or reliable numerical simulation. The main
difficulty in the numerical simulation was a lack of understanding on the nature of
fuel consumed in the process.
The main drive behind the development of these processes was a pressing need for
finding an injection agent with acceptable infectivity, better than that of water. Water
injection process in these pools was only marginally attractive due to an extremely
low infectivity. Air injectivity was by far better than water injectivity.
Air injection projects in the Williston Basin are MAF projects and have enjoyed years
of successful field operations. However, laboratory combustion tube tests indicated
that an in-situ combustion process was not feasible due to insufficient fuel Deposition
(35). This clearly shows why laboratory tests encountered difficulties in simulating the
field processes.
3.10 STATUS OF AIR INJECTION AS AN IOR METHOD. FIELD
PROJECTS
The feasibility of air injection as an IOR method can be analyzed in the light of
experience from several field projects involving light and very light oils. For the
purpose of this work the light oils have viscosities in the range of 2 mpa.s to10 mpa.s,
while the very light oils have viscosities less than 2 mpa.s.
3.10.1 Application to lights
37
The extension of the ISC to lighter oil pools was very slow due to the misconception
about non-sufficiency of fuel deposited, which would not sustain the ISC front.
However, the ISC process appears feasible in reservoirs containing oil with a
viscosity of 2- 6 mpa.s under reservoir conditions. In all these projects, except in the
Heidelberg project, the ISC process was initiated using artificial ignition devices, and
the reservoir temperature was lower than 57 °C.
In these projects, the generation of a high peak temperature was realized but the
values of these peak temperatures were lower than those for heavy oil reservoirs,
where the amount of fuel deposited was significantly higher. Actually, for two
processes in Romania, Ochiuri and Babeni in which numerous bottom hole
temperature were measured in the producers, the maximum recorded temperature was
around 180 to190 °C implying relatively low peak temperatures (33)
. In the Countess B
project (36, 37)
a cored well drilled in the burned zone, 50 ft away from the injection
well indicated that the maximum peak temperature developed by ISC front did not
exceed 300- 400 OC. In three of the DOE cost-shared ISC projects (Bradford Sand
Project and two projects in Venango (38)
, important difficulties related to the ignition
and the self-sustaining capacity of the ISC front were reported. Difficulties related to
the ignition operations were also encountered in many other projects, although details
are lacking. In the Bradford Project after four ignition trials, finally an electrical
heater operated perfectly, yet the process was not working satisfactorily as seen from
a lack of appropriate amount of O2 in the effluent gases. Actually, in both Venango
and Bradford projects it was found that the self-sustained ISC could not be established
under the prevailing conditions (porosity, 14 % to 15 %, permeability, 24 to 70 mD,
reservoir temperature 15 OC, oil viscosity 4 MPa- s, and oil gravity 44 oAPI). In these
cases a combination, small amount of fuel deposited, and unfavorable reservoir
properties (such as porosity) prevented the normal development and propagation of
the ISC front.
It seems that the main mechanism of enhanced oil recovery for light oil reservoir
applications is not of the viscosity reduction, but an increase in volumetric sweep
efficiency. For instance, in the May Libby field ISC project (39)
the vertical sweep
efficiency of the burning front, as determined from coring wells, was 100 % (for a net
38
thickness of 3 m). In the Delaware Childers (40)
experimental project (oil viscosity 6
MPa- s and net thickness of 14 m) the vertical sweep efficiency was 65 %. The
conditions leading to this increase in volumetric sweep efficiency (as compared to that
for heavy oil reservoirs) are not fully understood.
3.11 AIR INJECTION IN A LOW TEMPERATURE OXIDATION/
IMMISCIBLE AIR FLOODING MODE
This process was often encountered during several in-situ combustion operations.
Sometimes, it resulted from the use of insufficient air flux. In such cases, due to the
dominance of the low temperature oxidations (LTO), there was no longer a
combustion front (high temperature wave) and the oxygen was consumed in LTO
reactions spread over a wide region increasing the viscosity of oil instead of
decreasing it. The LTO may occur even at the high air injection rates, especially when
the heterogeneity is very pronounced. However, in most reported cases, it was caused
by low air injection rates. Usually, causes for poor performance are seldom discussed
in the technical literature. In the open literature this cause was reported only for the
cases of heavy oil Kinsella field 20 and light oil Demjien-East (42)
ISC pilots. For
Kinsella, the values of apparent H/C ratios were higher than 5. These high steady
values for apparent H/C ratios corroborated with other data indicated the dominance
of LTO reactions. At Demjien East because air rates were only 6000 to 8000 Sm3/d,
the process remained mostly in the LTO regime, and the resultant combustion gases
contained 2 to 4 % O2 and 2 to 4 % CO2.
It is worth mentioning that at several other ISC projects, operated at low air injection
rates, such as in a light oil reservoir in Borislav, former Soviet Union (43)
and others, a
similar behavior was observed. At Borislav (air injection rate of 10,000 sm3/d, where
the reservoir temperature is about 50 OC, although the LTO process was not
recognized as such it was reported that the viscosity of produced oil increased 2 to 2.5
times (from 30 to 70 mpa.s) on a continuous basis, which again seems to confirm the
LTO character of the process. The combustion gases contained 9.5 % CO2 a year after
the initiation of combustion by artificial means.
39
Before the artificial ignition, air was injected for seven years. In all the three projects
described above, the oil production performance was not encouraging and the projects
were terminated.
For some air injection processes conducted in micro fractured sand stones containing
light oils (viscosity of 5-12 mpa.s), such as in Dofteana Oligocene and Solont Stanesti
(33) Romania it is believed that the process became mainly LTO dominated due to very
high heat losses in regions surrounding the channels through which ISC front
propagated. In both these cases, the air injection rate of 10,000 to 12,000 sm3/d was
too low for a pay thickness of 50 to 60 m, and the very low air injectivity contributed
to the reversion of the process into LTO. After 5 to 6 months following artificial
ignition, the percentage of CO2 in the produced gases decreased to 4 to 9 %, following
peak values of 9 to10 %. Both these projects were terminated due to poor oil
production performance.
To conclude, the causes for the occurrence of LTO dominated process are believed to
be:
High heterogeneity (including fracturing),
Low reservoir temperature, and pressure
Low air rates (low oxygen flux)
When LTO dominated performance occurred, the period of ISC testing had to be
prolonged in order to gather enough indications regarding projects success or failure.
All of the above projects were horizontal gas floods that resulted in a disappointing
performance. Therefore, it can be concluded that this kind of process has a low chance
of economic success in horizontal flooding. Potential disadvantages are an increase in
viscosity of oil, and shrinkage of the injected gas due to LTO (oxygen uptake in the
oil). However, the process may still have some potential in a vertical flooding mode.
3.12 AIR INJECTION IN VERY LIGHT, DEEP OIL RESERVOIRS
An important milestone in the advance of air injection processes was the
implementation of commercial scale air injection projects in the Williston Basin of
North and South Dakota, USA, starting in 1979, (15,1,2)
.
40
The process was applied in a dolomite reservoir with low porosity (11 % to 19 %),
low permeability (less than 20 mD), and very light oils (viscosity of less than 2 mpa.s
under reservoir conditions), where water injection encountered significant problems
due to extremely low injectivity. The dolomite contains some micro fractures but
extensive fracturing or faulting is not known to exist.
The most important feature of these projects is the high reservoir temperature, which
facilitates the initiation of the process by spontaneous ignition.
The fact that the Williston Basin projects involved miscible processes is supported by
the fact that the operator tried hard to inject air at sufficiently high air rates in order to
maintain a high-pressure level in the reservoirs (35)
. For the Wilson Basin HPAI
projects, it seems that the reservoir and operating conditions were conducive to the
generation of a true ISC front, or some kind of a power fid heat wave, although this is
not confirmed by bottom hole temperature in the producers or in the observation
wells, as proper measurements were not made. However, the fact that the CO2 in the
produced gases was around 12 % seems to suggest that a HTO-MAF process was
accomplished. The amount of natural gas liquids (NGL) was high in the produced
gases. Therefore, a gas processing plant was installed for recovering them; 30 m3/day
of light ends were recovered from one project, for a total oil rate of 140 m3/day. This
was the first commercial utilization of produced gases from a HPAI project, (15)
. The
feasibility of recovering the NGL from the produced gases was also considered in the
Sloss field and Heidelberg (44)
projects.
The most recent MAF project was started in November 1997 in Eagle springs field,
Nevada (46)
. A company representative maintained that “the heat really does not seven
spot pattern is used. After a few months of operations, spontaneous ignition and
complete oxygen utilization were confirmed.
Two new air injection projects are scheduled to start in USA: one in Louisiana and the
other one in Montana. A new air injection process is also due to start in Indonesia (29)
,
and another one in Argentina.
All the projects discussed in this and previous sections involved non-fractured
reservoirs. There are very few cases of air injection projects in fractured rocks. As
mentioned before, ISC was tested with negative results in two fractured reservoirs in
41
Romania (33)
where the reservoir temperatures were only 39 to 45°C. Actually, a more
complete testing of air injection in a fractured reservoir was conducted in the
extensively fractured CAPA Madison reservoir, North Dakota (34,15)
, where air was
injected in a horizontal flood mode, at the end of a water flood. After 1.5 years of
pattern flooding in this watered out reservoir, the air/oil ratio was twice that of other
Williston Basin MAF projects, and the project was terminated.
From these, the most important aspect to consider for the MAF application is
utilization of gravity and the kind of MAF process that will eventually develop an
HTO-MAF or a LTO-MAF. Laboratory investigations can only indicate whether an
HTO-MAF is possible, but the final, definitive response will come only from an MAF
pilot, conducted under typical operating conditions.
Kissler and Shallcross (47, 48)
performed ramped temperature oxidation tests using very
light oil (density 824 kg/m3). A sample of a mixture of sand, water and oil was
subjected to a linear heating schedule while air at constant rate was flowed through it
and the effluent gases were analyzed for their composition. The oxidation behavior of
light oil was substantially different from that of the heavy oil.
Unlike the heavy oils, the light oils display three oxidation reactions; low temperature
oxidation (LTO), medium temperature oxidation (MTO), and high temperature
oxidation (HTO). A different fuel is specific for each of these reactions: for LTO it is
the oil itself for MTO, it is the light hydrocarbons produced by cracking; and for HTO
it is the heavy oil deposited by cracking. The corresponding peak temperature for
these three classes are: <200 oC, 250
oC to 300
oC and >300
oC, respectively.
As compared to LTO in heavy oils, LTO in light oils produces more CO2. Bulighin
(49) showed that in LTO, out of all the oxygen consumed, 50 % forms water, 45 %
forms CO2 and 2 to 4 % forms oxygenated compounds (ethers 66 % aldehydes and
ketones 35 % and acids 11 %). It was also shown (49)
that the LTO leads to an increase
in viscosity. For instance, the viscosity increases 1.4 times after 11 hours of oxidation
at 52 OC, and 1.2 times after 23 hours of oxidation at 38 oC. The increase of viscosity
is a clear reality as caustic additives were tested in an attempt to combat this tendency
and reduce the viscosity of heavy oil submitted to LTO (50)
.
42
The LTO-IAF was also investigated by using ramped temperature oxidation and
combustion tube runs (51, 3)
. Using a very low air flux at a pressure of 20 - 22 MPa, in
a vertical combustion tube, a 70 % ultimate oil recovery was obtained, which
corresponded to 17% residual oil saturation. It may be noted that an operating
pressure of 20-22 MPa would ensure a miscible displacement for pure CO2 injection,
but not for nitrogen injection. Given the extremely low air flux, no high peak
temperatures were observed, but the oxygen was almost totally consumed by LTO.
Garon and Wyga1 (52)
tested very light oil (48 oAPI; viscosity 1.8 mpa.s) in the
combustion tube both in a dry and in a wet combustion mode at three pressures
(atmospheric, 7 MPa and 14 MPa). Although the distillation residue at 427 °C was
only 6%, they succeeded in propagating a wet ISC front at 14 MPa, while the dry ISC
front at this pressure and both dry and wet combustion fronts at lower pressures could
not be propagated.
Recently, the first in-depth investigation of the effect of pressures on the HTO-MAF
process was reported the temperature was 120 °C the pressure was varied in the range
1000 to 5400 psig (53)
. In this investigation, light oil has 866 kg/m3 density, and 1.5 to
2 MPa-s viscosity was used. Six runs were performed in a 6ft combustion tube, using
both a natural rock (reservoir rock) and a Torpedo rock (non-reservoir rock). At the
test temperature of 120°C, miscibility with nitrogen was obtained only at 5400 Psi
(but not at 2700 Psi or 1000 Psi). The main characteristics of these tests were very
high air flux (50-150 sm3/m
2-hr), resulting in very high displacement front velocity
and heat wave velocity. Previously, similar, high values for the air flux (60 sm3/m
2-hr)
and front velocity were used in the investigation of wet combustion in the combustion
tubes. The combustion tube was operated vertically with a downward flow of fluids,
and before the ignition, nitrogen was injected in order to simulate the flue gas
displacement during the MAF process. The main conclusions obtained from these
tests were:
A clear combustion front was propagated with a steady peak temperature of between
400 and 450 oC and it was higher for the natural reservoir rock. The oxygen utilization
was 80 to 95 %. The H/C apparent ratio was normal, with the exception of four tests
for which it was 2.25 to 3.1, showing more intensive LTO reactions downstream of
43
the combustion front. The higher-pressure tests tended to exhibit a more developed
steam plateau.
The major conclusion of this investigation was the need to operate the high-pressure
runs at high injection rates (high air flux). Attempts to run these tests at low rates
resulted in lower peak temperatures, early oxygen break-through and an inability to
propagate the in-situ combustion front (53)
. The need for high air flux is not easy to
explain. When the displacement front has a velocity greater than that of the ISC front,
one can speculate along the following lines. Usually, both for heavy and intermediate
viscosity oils (low pressure tests) an increase in pressure leads to the increased
deposition of fuel on rock due to the fact that the vaporization of light ends
immediately down stream of the combustion front is not so intense. This confirmed by
many investigators, including an in-depth investigation by Wilson et al (54)
. When the
operating pressure is increasing and a dynamic miscibility of oil with nitrogen can be
attained ahead of the combustion front a more effective displacement takes place and
the residual oil saturation (available for the formation of fuel) is smaller. In the
beginning this corresponds to the inlet portion of the tube and due to the pseudo-
miscible regime, it may still contain a certain amount of residual oil saturation.
However, as the minimum miscibility pressure (MMP) is attained the residual
saturation becomes very low. An example for determination of MMP using vertical
slim tubes (55)
. Thus for the range of high pressure there is interplay between two
opposite effects mainly less vaporization of light ends immediately downstream of the
combustion front and better displacement of the oil ahead of the combustion front.
Up to a certain level of pressure the two effects may offset each other. Then at higher
pressures the fuel deposited is small (but constant) and is practically determined by
the efficiency of dynamic miscible displacement of the oil ahead of the combustion
front. It is known from the operation of the wet in-situ combustion that smaller fuel
deposits need higher air fluxes corresponding to higher ISC front velocities in order
for the in-situ combustion to be sustained. For super wet combustion the ISC front can
survive even at a fuel deposit of 5 to 6 k.g/m3 if the air flux is increased up to 50-150
sm3/m
2 hr
(56, 57). This was exactly the case in the test #7, reported in
(53). For the
highest pressure (5400 Psi) the in-situ combustion front advanced normally in the
44
beginning; this period was necessary for the dynamic miscibility to develop as the
miscibility during nitrogen miscible displacement is developed at the displacement
front after several contacts; the region behind the displacement front still had oil
saturations higher than miscible residual oil saturation. Following the travel of the
ISC front in this region the ISC stumbled and the air flux had to be increased to
further sustain it. Because nitrogen achieves miscibility by vaporizing light
hydrocarbons a complete miscibility is seen only at the displacement front. So, in the
first period, until the nitrogen acquires enough light ends from the oil there is only
immiscible displacement. It is this kind of displacement that allows the normal
propagation of the ISC front at the beginning of the test.
A more vigorous judgment on the need for increasing the air flux when the pressure is
increasing may be correlated to the need to compensate for the accumulation of air
into the burned zone, which at high-pressure conditions may account for a
considerable part of the injected air. This can be demonstrated by comparing the
velocity of the miscible displacement front to that of the combustion front for a
typical situation in case of the ISC application to heavy oil and to light oil. For typical
heavy oil reservoir the displacement front was 8.4 times faster than the ISC front
while for light oil at high pressure reservoir conditions it was 1.46 times slower than
the ISC front. This simply means that the ISC front “encounters” the oil in its original
state without any previous miscible displacement downstream of the ISC front. In
other words a direct burning of the oil should occur. The miscible displacement does
not have any opportunity to reduce the oil saturation, which is reduced only due to
vaporization just ahead of the ISC front.
3.13 LABORATORY MISCIBLE AIR FLOODING SPECIFIC TESTS
Determining the kind of air-injection derived process that is feasible in a
specific situation.
1) Assessment of miscible or immiscible character of HPAI
Determine minimum miscibility pressure (MMP) of oil with mixtures of nitrogen with
up to 8 to 14 % CO2 and/or mixtures of nitrogen and solution gases.
45
i) Liquid phase oxidation of oil in order to determine the corrosively of
oxygenated products in the oil. This test is associated mainly with LTO
processes.
ii) Evaluation of sulphur content of the produced gases and sulphur
compound generation during air injection. This test is associated mainly
with HTO processes.
2) Assessment of LTO and HTO characteristics of oil / rock system
The following laboratory tests should be performed preferably in the
order presented below .
i) Exothermic of oil at low and high temperature as given by accelerating-
rate calorimeter (ARC); the ARC technique (9)
facilitates selection of oils
most suited to air injection although it does not provide any clues about
the reactivity of the rock. A large gap in the continuity of the exotherm
graph indicates the unsuitability of that oil for a HTO-HPAI process.
ii) The determination of the kerogen pyrobitumen content of the rock by
performing ramped oxidation tests on the oil free rock samples in a small
reactor. Most carbonate reservoirs have a significant amount of
pyrobitumen. (58).
iii) The determination of the increase in oil viscosity with temperature
during LTO reactions.
iv) Combustion tube tests in order to check the self-sustainability of the ISC
front. Two kinds of tests may be necessary: using crushed rock from oil
formation and consolidated rock, if available. Identifying the potential
operational problems related to corrosion and pollution
v) Iso-thermal oxidation of the oil/ rock system in order to determine the
variation of oxidation rate with temperature. From this variation the main
kinetic parameters, for use in mathematical modeling of the spontaneous
ignition can be derived. Use of mathematical models of spontaneous
ignition may be necessary in order to determine the ignition delay.
46
vi) Meta contents of the oil and rock as determined by direct analysis or
inferred indirectly from several ramped oxidation tests of the oil/ rock
system. These tests may also give some qualitative information on the
oxidability of the oil/rock system.
3.14 MAF PILOT AND EXPANSION TO COMMERCIAL OPERATIONS
A commercial scale implementation can occur only after some of the uncertainties
about feasibility of the proposed recovery process are resolved. Piloting would be
critical, specially because the proposed recovery process is yet unproved for the type
of specific applications such as those involving thick or thin oil column, highly
fractured and heterogeneous reservoir, entirely or partially water invaded reservoirs,
vertical mode of sweep, use of horizontal and slanted producers, etc. One way of
recognizing and resolving the above risks/ uncertainties is to conduct an air injection
pilot. A pilot can be designed with the objective of resolving the most critical of these
uncertainties, which can be divided into four categories as follows:
1. Extent of confinement of the injected air in view of numerous faults/ fractures
and uncertain integrity of cement around the older wells.
2. Potential problems related to corrosion/ oxygen production (Safety)/ Pollution
(emission of carbon oxides and/or hydrogen-sulphide).
3. Sub-fracture air Injectivity: This would help determine the completion of
injection wells (equipment needed, sizing of tubular and compressors, and the
required number of injectors).
4. Air-oil ratio and incremental oil recovery
There are two ways of applying air injection in well patterns and line drive well
configuration, the first system could be applied as continuous patterns or isolated
patterns. So far all three configurations have been tried but most of applications used
continuous patterns and peripheral line drive configurations. A line drive is feasible
only if started from the upper part of the reservoir. For this reason it is extremely
important to place the pilot up structure. In this way, after the test is finished one can
have both options (line drive or patterns) of developing to commercial phase.
47
Essentially the commercial line drive operation means that the first row of wells at the
uppermost part of the structure is to be used as air injection wells (combustion wells)
while producing the displaced oil via the off-setting 2-3 production well rows, which
are below the structural contour of injector row. Once the closest production row is
intercepted by the displacement front this row is converted into air injection, while the
former air injection row, behind the displacement front is shut off. Therefore, except
the first uppermost row of wells all other wells are utilized first as producers and
afterwards as injection wells. The only exception is the last or the lowest row on the
structure, which is used only for production. As a rule the displacement front should
be propagated as much as possible parallel to the structural contours.
The decision between a line drive and a pattern application is one of the most
important challenges for the designer. For a line drive, the rate of oil recovery is
limited by the length of structural contour at the row of injectors (limited by the
maximum total air injection rate achievable). Therefore, oil production corresponds to
the actual air injection rate at any given time, which also imposes time constraints on
the total life of the project.
Air injection, in principle is essentially a gas injection process, which may have
additional beneficial effects associated with the propagation of the heat wave.
Irrespective of the system one chooses for further development - a line drive or
patterns - it is very important that the pilot be located at the uppermost part of the
reservoir. Another reason behind this statement is that usually when a pilot is located
up structure it is easier to carry out a more vigorous evaluation of oil recovery. It
would be simpler to delineate the volume of reservoir located at the upper part of the
reservoir that is under the influence of the process and for which both air-oil ratio and
incremental oil recovery factor can be reliably estimated at different times.
Actually, for the four air injection projects conducted in this manner (starting from the
upper part of the reservoir) - May Libby Project, Gloriana field, Trix-Liz Field, Tx,
and Iola Field, Kansas, the ultimate oil recovery was more than 50 % (58)
and all of
them were economical; the AOR for all of them was under 1000 sm3/m
3.
Another positive aspect of locating the HTO-MAF pilot at the upper part of the
structure is that in case the test is inconclusive or deemed uneconomical although the
48
combustion was satisfactory or nearly so the operator can just stop the air injection
without any adverse consequences. Oil loss due to oil re saturation of the burning
zone in this case will be minimal. If the pilot is not located at the upper part in a
similar situation after the air injection stoppage, the burned zone may be
unintentionally transformed into a cracking reactor with the formation of large
quantity of coke.
Periodic production logs can be run in the producers to test the extent of
pressurization/ nitrogen encroachment. It is further recommended that pressure/
temperature/ sampling observation wells be placed to monitor communication within
the reservoir (extent of pressurization/ injected gas spread/ oil displacement/
temperatures attained). They can also be used to assess the spread of injected gases
horizontally. These wells could be relatively inexpensive slim holes.
For a proper operation/ interpretation of the pilot, it would be highly desirable that the
injector and the producer are logged with a cement bond logging (CBL) before air
injection to ensure their integrity.
Corrosion coupons in the producers can answer the questions about the severity and
extent of the problem. Monitoring of the produced gas two times a week can alert the
operator regarding any risks of oxygen, carbon monoxide or hydrogen sulphide
production. Detailed reservoir characterization followed by a numerical simulation of
pilot performance would help in interpreting the pilot performance and its scale-up to
subsequent commercial operations.
3.15 SCREENING CRITERIA
The LTO-IAF may be applied in reservoirs having an oil viscosity lower than 30
mpa.s and reservoir temperatures less than 45 °C; the same process is obtained at
reservoir temperatures higher than 45 °C if the reservoir is highly heterogeneous.
Also, oil saturation at the time of implementation of LTO-IAF should be higher than
50 %.
The HTO-IAF or in-situ combustion is applicable mainly for heavy oil reservoirs
(viscosity higher than 10 mpa.s)
49
The MAF, with or without intensive oxidation can be applied for the reservoirs having
an oil viscosity less than 10 mpa.s, usually under the conditions leading to a dynamic
miscibility with nitrogen. In the criteria developed the miscibility for nitrogen is taken
into account as the oxygen may be partially or totally converted to carbon dioxide but
it does not generate more than 14 % CO2.
The HTO-MAF can be applied in high temperature reservoirs (>80 oC) for a relatively
homogeneous reservoir while LTO-MAF may occur in relatively low temperature
reservoirs (<45 °C) and porosities lower than 12 % while for a heterogeneous
reservoir (especially fractured reservoirs) it may be applied at any values of reservoir
temperature and porosity.
The LTO-MAF conditions of applicability are the same as those for HTO-MAF
excepting the fact that miscibility is not achieved.
3.16 LOW TEMPERATURE OXIDATION (LTO)
LTO reactions are characterized either no carbon oxides or low levels of carbon
oxides in the effluent stream. In other words more oxygen reacts with the
hydrocarbons than can be found in produced gases. The air injection LTO process (59)
works by removing the oxygen from the injected air through low temperature
oxidation with oil in the reservoir. Unlike in-situ combustion, a stabilized high
temperature front, or combustion zone, is not necessary. The LTO reaction is
spontaneous and independent of oxygen partial pressure, so that complete oxygen
consumption can be achieved in the reservoir. A small amount of oxygen will be left
in the oil if there is an insufficient reactive component left to react with the oxygen.
The process is quite flexible regarding air injection rate. The only restriction on the air
injection rate is to ensure a sufficiently long residence time in the reservoir for
complete oxygen removal. This will not present any problem in reservoirs with a
fairly long well spacing. The process can therefore be applied in a variety of injection
schemes, such as water alternating gas (WAG), gravity stabilized gas injection
(GSGI) and pressure maintenance. In light oil reservoirs, the interwell distance
between injection and production wells will typically be several hundreds of meters.
50
Since the oxygen in the injected gas contacts oil over a long distance (compared to the
oxidation tube) reacting slowly with the oil at reservoir temperature the oil-oxygen
contact time is of the order of months or years not days. Thus the oxygen
concentration of the gas gradually decreases in a continuous manner with increasing
distance from the injector. The air injection LTO process is shown schematically in
Figure 3.1. Starting from the injector, the displacement gases produced by LTO
reactions are composed of CO2, CO, N2 and vaporized /stripped hydrocarbons. The oil
produced at the production wells, before gas breakthrough, is the un-reacted virgin
oil. In the reaction zone behind the displacement front, oil and water are displaced
/stripped by the "flue" gases. There is still a significant oil saturation (at least residual
to gas) left to react with injected oxygen. It is residual oil (Sorg) that is consumed in
the reaction. Compared with HTO or in-situ combustion, the reaction zone in the LTO
process is characterized by a steadily decreasing oxygen concentration profile,
possibly extending over a long reservoir distance. The displacement front is either a
nitrogen or flue gas depending on the rate at which CO2 is formed. Greaves et al (59,
51), on the time scale of the physical laboratory simulation of this process e.g. a few
days (or weeks) the process is simulated using an extremely low air injection flux, e.g.
a flux < 0.5 sm3/m
2-hr has been used in the oxidation tube studies. This flux reported
in field cases (2, 14, 28)
. In practice, low air or oxygen fluxes may be encountered in
field scale WAG and GSGI (gravity drainage) processes. Even for conventionally
operated in-situ combustion process (vertical injection and production), where the
interwell distance is fairly large, it will be difficult to maintain a stable combustion
front (4)
. Rather the oxygen flux will fall to a low level and only support slow LTO
reactions. In the small batch reactor case, the air is in an enclosed system with the oil,
in which a static condition prevailed. This represents an extreme case of very low air
injection rate. Although the economics of the process have not been thoroughly
investigated, we believe that air injection will be more economical than nitrogen
injection.
51
3.17 AIR INJECTION AND OXYGEN CONSUMPTION
Although various gases such as air, natural gas, CO2, N2 and flue gases are viable
candidates for gas injection, air combines the benefits of low cost with universal
accessibility. The singular greatest limitation to air injection is that the reservoir must
have sufficient temperature for the oxygen to be consumed by in – situ combustion (9).
Other wise the presence of oxygen in the reservoir could lead to bacterial growth and
emulsions. In addition, the presence of oxygen in production equipment could lead to
explosions and severe corrosion. During the design phase of the project, laboratory
tests discuss here in demonstrated that the waste Hackberry oil was sufficiently
52
reactive at reservoir temperature for the oxygen to be consumed by in-situ
combustion. Monitoring of the produced gas has confirmed that oxygen is being
consumed in the reservoir. Reservoir A on the north flank has experienced Nitrogen
production in several wells. Nitrogen content in the produced gas has ranged from just
a few percent to as high as 76 mole % in the producer closest to an injection well. In
the analysis from the well that measured 76 % Nitrogen, the oxygen content was only
1 %. The fact that the ratio of oxygen to Nitrogen in the produced gas is much less
than the ratio of oxygen to nitrogen in air indicates that much of the oxygen from the
injected air is being consumed in the reservoir.
Oxygen is consumed through spontaneous combustion in reservoir with temperatures
that range from 174 oF to 200
oF except for the two wells with greater than 50%
nitrogen content; only a minimal amount of CO2 has been detected in the produced
gas. Much of the CO2 is created in the combustion process dissolved in to the
reservoir oil before reaching the producing wells. The dissolution of CO2 in to the
reservoir oil lowers the oil viscosity thereby improving gravity drainage performance.
On several occasions, the air injector in fault block of the field experienced a dramatic
increase from (300 to 500 Psi) in injection pressure after three or four days of
continuously air injection. This pressure increase would gradually dissipate over time
or disappeared after injection was interrupted. The sharp in the injection pressure is
believed to be evidence of spontaneous high temperature combustion that occurred
after sufficient oxygen had been injected to fuel the process and after sufficient
induction time for the exothermic oxidation reactions to raise the combustion zone
temperature enough for vigorous combustion.
Additional evidence of in-situ combustion was observed in the west flank air injectors
in the form of elevated bottom hole temperatures measured 24 hrs after the injectors
were shut in. At that time the bottom hole temperatures were as much as 80 oF above
the normal reservoir temperatures.
3.18 SPONTANEOUS IGNITION
53
When air is injected in an oil reservoir, slow oxidation (LTO reactions) occurs at the
reservoir temperature and in some cases the heat given off can initiate the in-situ
combustion process. The ignition delay, tign is defined as the time required for the
temperature to exceed 210 oC around the air injection well
(35). It is expected that once
this temperature is reached, the oxidation rate is high enough to be sustained until the
peak temperature of the ISC front is attained.
Ignition occurs at a certain distance from the air injection well and this distance
increases with air flow rate used during ignition operation (35)
. During spontaneous
ignition process, the value of peak temperature increases and the location of the peak
temperature moves backwards towards the injection well before taking off in the
direction of the air- flow. During this period, there is a risk of damaging the casing of
the injection well. However, the experience with this technique and with chemical
ignition (which is similar to the spontaneous ignition in this respect) showed that such
occurrence is rare (60)
. Actually, most of the experience with spontaneous ignition was
gained during heavy oil exploitation using ISC process. In general, an ignition delay,
of 10-20 days is seen in oil reservoirs whose reservoir temperatures are 50-60 °C.
Spontaneous ignition can take place even at low reservoir temperatures as 30 °C, but
it can be as long as 100-150 days, and for light oil targets it becomes impractical for
various reasons, such as an increase in oil viscosity. Ignition delay also depends on
other oil and rock properties. In a field case, at 70 °C, the spontaneous ignition
occurred in 2- 3 weeks, for oil with viscosity of 100 m Pa .s (61,62, 63).
. In cases the t ign.
is higher than 10 days, a chemical ignition alternative can be utilized. This consists of
using a slug of linseed oil in order to speed up the oxidation reactions and reduce the t
ign.
On the other hand, where the reservoir temperature is higher than 70 to 80 oC, the
ignition take place very quickly, sometimes within hours. However, higher the
reservoir pressure, the more difficult it is to determine t ign. given the fact that the
gases produced by LTO (mainly CO2), are solubilized in oil, and may appear very late
in the produced gases. Thus, even if the ignition took place it is not possible to have a
firm confirmation.
54
Actually, in this case, maximum t ign., determined. Sometimes, a sharp increase in the
injection pressure occurs, and this is a clear sign that ignition occurred.
When the composition of the effluent gas (recovered from the surrounding producing
wells) is used to evaluate the ignition the most rigorous method of estimating the t ign
is one based on the variation of the apparent hydrogen-carbon (H/C) ratio during the
ignition operation (32)
, In order to help H/C interpretation, it is recommended to use a
relatively high air injection rate, and to keep it constant during ignition operation.
Although the existence of the high peak temperature may be of little consequence for
the displacement process in general (53)
, the control on the spontaneous ignition is very
important even in on case the ISC front does not sustain itself. This is so because this
helps achieve total oxygen utilization, which is paramount for an acceptable air
injection process (safety considerations). The operator must take contingency
measures at the air injection well, just for this reason
3.19 FUEL COMBUSTION
Fuel combustion occurs at the combustion front, investigators have used the data of
combustion tube experiments to define the combustion front and its characteristics.
Their goal was to obtain correlations to relating the combustion front velocity and
front temperature to experimental variables such as pressure and air flux. Given such
a correlation, the air requirement could than be easily assessed. In their pioneer work,
Martin (66)
found a direct relation ship between air flux and frontal velocity. they were
also able to correlate the frontal velocity with the rate of total oxygen consumption
(flux time O2 consumed).
This work supported by Penberthy and Ramey (63)
who used equation combined with
a material balance to get:
310109.141
12.
x
C
V
YU f
f
η
λ
λ
Where
U = Air Flux, scf h /ft2
Y = Fraction of Oxygen Consumed
55
Vf = Front Velocity, ft/ hr
Cf = Deposited fuel of formation, lb /ft 3
Of course, the above equation is another version of the general material balance
equation (Penberthy and Ramey, 63
):
)(AFRCf
UVf
Where
AFR = Air- Fuel Ratio, scf / lb
The same kind of correlation was reported by Moss et al (64)
, Showalter, (65)
, and
Wilson et al (54).
These relation ships could indicate that if the air flux drops below a certain limit in the
field, the burning front may extinguish.
On the contrary, field tests have indicated that the burning front could remain static
for long periods of time as well as move normal or counter current to the direction of
air flow [Ramey (67)
]. The front moves in the direction in which fuel, oxidant and
temperature were sufficient to permit the reaction to continue.
Wilson et al and others showed that front temperature increased with air flow but
became independent of air flux at sufficiently high pressure. Pressure was also found
not to affect front temperature and its velocity at high air flux, while at low flux
higher pressure increases the peak temperature and decrease the burning front velocity
[Martin (66)
, Wilson et al (54)
]. However pressure effect is minor.
3.20 FUEL DEPOSITION
The quantity of the fuel deposited and the reaction rate within the burning zone has
been the subject of the intensive study for number of reasons. First the maximum oil
recovery is the difference between the original oil in place at the start of the operation
and the oil consumed as fuel. Second, one of the most important factors in the
economic evaluation of any in-situ combustion project is the cost of air compression.
Excessive fuel deposition causes the burning front to advance slowly and this incurs
large air compression costs.
56
On the other hand, if the fuel concentration is too low, the heat of combustion will not
be sufficient to raise the temperature of the rock and the contained fluids to a level of
self sustained combustion. This may lead to combustion failure.
Using TGA thermo grams of 15 different crude oils in a wide gravity range in the
presence of both nitrogen and air, Bae (68)
showed that the oxidation of the crude oil
starts at higher temperatures and less heat is released as the pressure is lowered. For
most of the samples studied at 50 psig and up to 500 oF, the weight loss in the
presence of N2 or air was around 60 %. It was deduced that the distillation was the
dominant mechanism for fuel deposition. At higher pressures, less distillation would
occur and more fuel would be available for reaction. In Bae, s
(68) work, only a few
crude oils were reactive enough at low temperatures to generate the heat necessary to
sustain a low-temperature front.
3.21 PRACTICAL APPLICATION OF EXPERIMENTAL RESULTS
The experimental study of in-situ combustion regarding the potential application on
Sindh crude oil was considered. The reserves of Sindh crude are relatively small in
size and are depleting and almost reached to the abundant. Though these reservoirs
were natural water flooded but even sufficient quantity of oil is trapped. These
reservoirs need additional energy to mobilize the trapped oil from the reservoir to the
production wells. In compare to other enhanced oil projects, In-situ combustion
project is much inexpensive and very much viable for small pools with low
permeability reserves. In past at Pottohar division In-situ combustion process was
initiated to heavy crude oil, the project did not responded well and failure was
attributed to:
1. The reservoir was deep (8000 ft deep).
2. The permeability was high.
3. The laboratory studies were not conducted.
4. The parameters were not controlled effectively
CHAPTER 4
EXPERIMENTAL SET-UP AND PROCEDURE
4.1 EXPERIMENTAL EQUIPMENT
Experimental apparatus was designed in the Institute of Petroleum & Natural Gas
Engineering, Mehran University of Engineering and Technology, Jamshoro, Pakistan
for understanding air injection process for depleted light oil reservoirs. It consists
mainly of a linear (vertically downward Reactor), pressure shell, and combustion cell
which simulate the reservoir with the necessary heating device, PID temperature
processor controller, digital temperature indicator, product separation, recording
equipment, thermocouples, back-pressure regulator, gas chromatograph, flow system,
and high pressure air cylinder.
4.1.1 Air injection apparatus
Figure 4.1 shows a schematic diagram of the air injection apparatus. All the
accessories attached for controlling and recording the data are listed in table 4.1.
Table 4.2 presents the specification of the accessories attached to the reactor for data
gathering and recording.
Table 4.3 list the equipment with specifications used for evaluation of the properties
of core and oil used in this research work.
4.1.2 Reactor assembly
Reactor comprised of a thick wall autoclave made up of 316 stainless steel and has
flange at the bottom of the reactor. At the bottom part of the assembly, which holds
the combustion cell, is inserted in the autoclave, creates the leak proof seal with
autoclave and is tightened with 5.08 cm nuts is presented in Figure 4.2. Table 4.4
presents the reactor dimensions of 8.255 O.D cm, 5.715 cm I.D, 35.56 cm length, and
57
Figure
4.1-Air
injection experimental set-up
58
59
Table 4.1: Equipments installed in the research rig (Fig. 4.1)
S.NO ABBREVIATION DESCRIPTION
1 AC Air Cylinder
2 FCV Flow Control Valve
3 PG Pressure Gauge
4 D Dryer (filled with silica gel)
5 NV Needle Valve
6 SF Swagelok Fittings
7 HPA High Pressure Autoclave
8 HP Sep High Pressure Separator
9 P R Pressure Regulator
10 LP Sep Low Pressure Separator
11 DP Deflector Plates
12 FM Flow meter
13 S Scrubber (filled with wire mesh)
14 GT Glass Tubes (Absorbent)
15 GSP Gas Sampling Point
16 GC Gas Chromatograph
17 Re Recorder / Chromatocorder-12
18 HG Hydrogen Generator
19 PT Pressure Transducer
20 PID Temperature Processor
21 TI Temperature Indicator (Digital)
22 RE Recorder / Eco-Graph
(Six Pen Paper Less)
23 R Relay (On/ Off Switch)
60
Table 4.2: Specification of apparatus installed in air injection experimental
Set-up
DESCRIPTION SPECIFICATION Pressure Shell Type 316 Stainless Steel
8.255 cm O.D, 5.715 cm I. D, Wall Thickness 1.27 cm, and 35.56 cm Length
Combustion Cell Type 316 Stainless Steel
3.81 cm O.D, 3.175 cm I. D, Wall Thickness 0.3175 cm, 25.4 cm Length
Thermocouples Type K Iron Constant
I) 0.1016 cm O.D, length 30.48 cm II) 0.1016 cm O.D, length 30.48 cm III) 0.1016 cm O.D, length 30.48 cm
Flanges Type, Stainless Steel
13.97 cm O.D, 8.255 cm I. D, Flange Thickness 2.54 cm.
Mesh 200 Mesh Stainless Steel
(Bottom of the combustion Cell) PID Temperature Processor Controller
Honey Well DC 1040 CT-131-000-E S/N : SP 0208129068 INPUT : K, RANGE 0-600 OC
Temperature Indicator PUMA, Digital Panel Meter
For J, K, R, S. Thermo couple Gas Sampling Flow lines Plastic Tube, 0.635 cm O.D
(Low Pressure side at exhaust) Flow lines Type 316 Stainless Steel
0.635 cm O.D Pressure Transducer DONFOSS, DENMARK
MBS 3000, 060G1111 Pe : 0 - 250 BAR OUT : 4 - 20 Ma
Separator Type 304 Stainless Steel
61 Table 4.2 (continued)
DESCRIPTION SPECIFICATION Electric Heaters 1 KW , Each
Relay ON/ OFF, Switch
Thermowell Type 316 Stainless Steel 0.635 cm O.D
Pressure regulator GO, SANDIMAS CA USA
PR1 – 1A11A3C111 P/N : 102600 6/ 96 0 - 5000 PSIG (34475 KPa)
Recorder (Six Pen Paperless Recorder) ECO-GRAPH
ENDRESS + HAUSER 87487 GERMANY ECO-GRAPH SPEC: 30546554 / 0010 U : 110, 240 V, 50/ 60 HZ S : 22 VA S.NO. 3C00120410C
Needle valves Type 316 Stainless Steel Pressure gauges Range : 0 - 5000 PSIG (34475 KPa)
Range : 0 - 3000 PSIG (20685 KPa) Range : 0 - 1000 PSIG (6895 KPa)
Swagelok fitting Type 316 Stainless Steel
Glass Tube 1.27 cm Tube, 35.56 cm length, filled with silica
gel Gas Chromatograph Yanaco Gas Chromatograph
Model- G- 1880-T Thermal Conductivity Detector ( TCD)
Recorder/ Chromatocorder-12
Yanaco New Science, INC. No. of Peaks to be processed: Max. 900 No. of Peaks to be Identified: Max. 900 Peak processing Speed : 6 Peaks / sec Retention Time: Max. 7999 min.
Flow meter Model AK 1300
KOFLOK, KOJIMA RANGE : 0 - 500 ml / min.
62 Table 4.3: Specifications of equipments used in research work
DESCRIPTION
SPECIFICATION
Porosimeter Metec Corporation, Model, 2000 Carlo Erba Instruments
Sieve Shaker Metec Standard Sieve Hydro Meter Tokyo Yokota, Keiki Mfg, Co, Ltd Balance Shimadzu, Electronic Balance, Libor Eb-50 K Saybolt Viscometer Yoshida Kagaku Kikai Co, Ltd
Model Sfv ype- 2e, Power Source 220v / 1kw Temperature Range 0 -100 Deg. C
Table 4.4: Equipments installed in the high pressure autoclave (Fig. 4.2)
S.NO
ABBREVIATION DESCRIPTION
1 HPA High Pressure Autoclave
2 C.C Combustion Cell
3 EH Electric Heater/ Igniter
4 MS 200 Mesh Screen
5 PG/ RS Packing Gland / Rubber seals
6 Tw Thermowell
7 TC Thermocouple
8 F Flanges
9 N Nut
10 SF Swagelok Fittings
11 Bolt Stainless Steel Bolt
12 O+S Mixture of Oil and Sand
13 TC1 Thermocouple-1
14 TC2 Thermocouple-2
15 TC3 Thermocouple-3
63
64
1.27 cm wall thickness designed for a working pressure of 20685 KPa and
temperature up to 600 to 700 oC and reactor hydraulically tested up to the pressure of
34475 KPa.
A thin wall combustion cell (C. C) made up of stainless steel 316, having dimensions
of 3.81 cm O.D., 3.175 cm I.D, and length of 25.4 cm is placed inside the autoclave.
The volume of the combustion cell is 201 cm3. Reactor assembly was fabricated with
the help of local industry of Hyderabad, Sindh, Pakistan. Two stainless steel wire
screens of 200 meshes are placed at the bottom of the combustion cell to prevent the
sand entering in the production line and can create the blockage to the flow streams.
4.1.3 Reactor heating system
In the first series of experiments one electric heater (1.0 KW) was wrapped around the
top of the reactor to heat the autoclave to simulate reservoir temperature and to create
ignition in the sand pack. The heater is enclosed in a close muffled type and is
demountable, controlled by Honey well, PID temperature processor controller. A
ramp temperature of 5 oC/minute was set to a maximum temperature of 500 oC + 50.
Figure 4.3 presents the ramp behavior of the controller. The upper most thermocouple
used for control the temperature for the entire experiment. Initially it was thought that
once the combustion front develops would propagate to the downstream of the fire
front. This speculation did not work well due to the cold region ahead of the fire front.
The cold region was well below the actual reservoir temperature of 95 oC. It was
decided to install additional heaters downstream of the main heater to simulate the
reservoir temperature.
Therefore in the second series of experiments, one additional heaters of 1.0 KW was
installed, to the downstream of the main heater to maintain the temperature. Before
installing the 2nd heater, it was calibrated by variable controlled transformer (at 120
volt). This simulates the temperature of 95 oC ± 5 oC of the combustion cell.
In the final series of experiments, three heaters (1.0 KW each) were installed in a
series along with main heater for the entire length of the autoclave and set to simulate
the reservoir temperature mentioned above.
65
After stabilizing the required pressure all the heaters were switched “ON”. Ignition
could be observed on the temperature recorder by change of slope on the temperature
versus time. The igniter heater was switched “OFF” for obtaining constant and steady
temperature through out the reactor.
4.1.4 Thermocouples
The Temperature of the combustion cell (C.C) was measured by three chromel-
alumel K type thermocouples of 0.1 cm dia., located at the centre of the combustion
cell to measure the temperature of the reaction zones at the different depth.
Thermocouple -1 (T1) was placed in the upper most area of the C.C (2.54 cm to inlet),
Thermocouple -2 (T2) was placed at 12.7 cm from top of the C.C, and thermocouple-
3 (T3) was placed at 17.78 cm from top of the C.C. These thermocouples are
connected with recorder to record the temperatures i.e. Temperature (T1),
Temperature, (T2) and Temperature (T3) in oC. The upper most thermocouple placed
very close to the inlet of C.C was used to control the ramp temperature through PID
controller Figure 4.3.
4.1.5 Pressure Transducer
At the outlet of the reactor, the pressure transducer was installed, and connected to the
recorder to record the flowing pressure. Before installing, the pressure transducer into
the research rig, transmitter was calibrated as current (mA) out put response against
pressure (psig) applied as presented in figure 4.4.
4.1.6 Fluid Separation
High pressure and low-pressure separators are installed in series at the downstream of
autoclave; the separators are equipped with a deflector plate and contain three
perforated plates for better two phase separation. A back-pressure regulator was
installed upstream of the high pressure separator, this causes the difficulties in
66
0
100
200
300
400
500
0 60 120 180 240 300 360
TEMPERATURE (C)
TIME, MINUTES
Fig. 4.3 Temperature versus time. Non Iso-Thermal conditions ( Heating rate 5 oC / min) .
67
controlling the pressure of the autoclave due the oil blockage and hence some
experiments were terminated. A modification by moving the back pressure regulator
downstream of the high pressure separator solve this problem and oil separated in
high pressure separator was collected after experiments is over.
4.1.7 Recorder
A calibrated six pen paperless recorder was used to record the values of three
temperature and pressure and variation are recorded continuously during the
experiments. These values were than co-related with the effluent gases to obtain the
behavior of combustion front and its advancement.
4.1.8 Pressure Regulator
0
4
8
12
16
20
0 500 1000 1500 2000 2500 3000 3500
CURRENT,mA
PRESSURE,Psi
Fig. 4.4 Pressure versus current relationship
Initially pressure regulator was installed at the outlet of the reactor to control the
pressure of the autoclave. Different pressures were set for the different experiments.
Due to the flow of oil with effluent gas, the blockage of the regulator used to occur
and this causes the pressure of the autoclave to fluctuate. Even the regular cleaning of
the regulator doesn’t solve the problem. The relocation of the regulator to the
downstream of high pressure separator greatly reduces this problem. Further
downstream of this regulator the pressure further decreases which also help to bring
the flow of effluent gases close to atmosphere.
4.1.9 Flow metering
The air was supplied by high-pressure air cylinder (13652 KPa); the flow rate was
controlled by Needle valve installed at the inlet of the reactor. The flow of air metered
at the outlet by using a positive displacement flow meter for air, which indicate the
flow through the reactor.
68
4.1.10 Gas sampling system
As shown in Figure 4.5, realizing that the effluent gases may carries water vapours
which can damage the gas chromatograph column, a special set-up of extended dryers
of silica gel were installed prior to metering and sampling point. Downstream of the
metering and without disturbing the flow of effluent gas samples of 1 ml, with the
help of gas tight syringe was withdrawn with an interval of each 10 minutes.
4.1.11 Gas chromatograph
Gas Chromatograph (GC-1880) was connected with the experimental set-up for the
analysis of exhaust gases by injection of 1.0 ml sample with tight gas syringe at the
top of the column of injection port, after every 10 minutes, the various peaks of the
produced gases were recorded by recorder (chromatocorder-12) and integrated. A
column of (6ft length and dia 1/8 inch) packed with activated carbon was used to
determine the peaks of CO2, O2, CO, CH4 and N2 gases. Hydrogen gas used as a
carrier gas for analysis of above gases and response of thermal conductivity detector
(TCD) was recorded by recorder. The calibration of column is done using the standard
gas sample (i.e., CO2, and CO) recommended for the column, and atmospheric air,
oxygen, methane, nitrogen and synthetic air were also used for calibration purposes.
4.2.1. Properties of the crude oil
The crude oil used in these experiments was from the X oil field of Badin. Properties
of crude oil are presented in Table 4.5.
4.2.2 Oil Viscosity
The viscosity of oil can influence the process selection. Low viscosity oil may flow
naturally and recovery can be achieved by utilizing the natural formation pressure.
Figure 4.5: Special designs for gas sampling system
69
70
After depletion of natural formation pressure the characterization of the reservoir
change with decrease in reservoir pressure and the displacement of fluids. Some of the
reservoir and fluid properties change. The main changes are in the reservoir, oil
viscosity, density, surface tension and relative permeability. These changes in the
properties of reservoir must be considered prior to selecting the secondary/ tertiary
recovery. The density / API gravity of oil was measured by hydrometer.
Experimentally, measured gravity of different crude oil was 37.5, 39.5, and 41 oAPI.
The viscosity of the crude oil was determined at various temperatures using a Saybolt
viscometer.
4.2.3 Amount of Interstitial Water
The Interstitial water, which is present in the reservoir, is mostly associated with
mineral salts and has a significant effect on the recovery method. The concentration of
metal ions will affect the surface tension of the water and decrease the mobility of oil.
As the water saturation increases the relative permeability to oil decreases and relative
permeability to water increases. After depletion of the primary formation pressure,
and on switching to Secondary recovery the properties and amount of the interstitial
water must be considered, as the existing oil saturation of the reservoir is one of the
most critical factors.
Table 4.5: Properties of the crude oil
Oil Gravity 37.5 oAPI
Viscosity at 37.7 oC. 35 SUS
Weight Percent Carbon 85.87
Weight Percent Hydrogen 12.41
Weight Percent Nitrogen 0.76
Weight Percent Sulfur 0.21
Atomic H/ C Ratio 1.613
71
4.2.4 Mineralogy
The clays, which are associated with the Interstitial Water, can influence the process
selection for the EOR. Mono, di and trivalent ions are present in the clays, which may
react with the fluids used and hence reduce the effectiveness of the process,
decreasing the efficiency and productivity.
4.2.5 Geology
The nature of the reservoir rock can affect the successful application of the EOR
process. A fractured reservoir is difficult to handle, as there is a loss of energy to the
bulk of rock, with little or poor response to the injection. In addition to this other
problems may include resistance to flow by passing, channel formation and
inaccessible pore volume. These factors may result in poor mobility of the oil in the
reservoir.
4.2.6 Reservoir Temperature
The reservoir temperature is another environmental factor, which can have an
influence on process selection for EOR. The viscosity of oil is greatly affected by the
temperature, the lower the temperature the greater the viscosity. A high temperature
increases the reactivity of ions with the fluids used, decreasing the effectiveness of the
process, and affecting sweep efficiency. In Air injection process, reservoir
temperature plays an important role in the consumption of 100 percent oxygen.
4.3. PROPERTIES OF THE SAND PACK
Most of the experiments were conducted with a mixture of sand and oil. Table 4.6
shows the sieve analysis of the sand. Different size of sand mixed thoroughly with the
required amount of light oil and placed in a combustion cell. A uniform pressure was
applied to the packed tube. The components of the sand pack were mixed in pre-
72
determined proportions to represent a composition similar to reservoir conditions.
Further sand pack properties are summarized in Table 4.7.
.
Table 4.6: Initial sand pack conditions for the combustion cell
(Sieve analysis)
Sieve Size Percent by weight retained
50 60
100 40
Total 100
Table 4.7: Initial sand pack properties
Length of the Combustion Cell, cm CL 25.4
Length of the sand Pack, cm L 24.1
Radius of the Cell, cm rc 1.5875
Bulk volume, cm3 Vb 201
Sand density, gm/cc ρs 2.67
Oil density, gm/cc ρo 0.836
Oil saturation, % So 57.41 – 80
Weight of the sand in the Cell, gms Ws 170- 200
Weight of the oil in the Cell, gms Wo 50-66
Volume of the oil, cm3 Vo 60 – 80
Water Saturation, % Sw 20-41.25
4.3.1 Oil mixing in unconsolidated sand
Consolidated cores were ground into loose sand, crushing by hand or by pressing by
jaws of table vice so that the original shape of the sand particles were not destroyed.
A given weight of the sand was placed in a container and the required weight of the
oil added to the sand and mixed with the help of spatula, until the mixture becomes
73
homogenous. Unconsolidated sand equivalent to the weight of the consolidated core
was placed into the cell, when the experiments were conducted on unconsolidated
sand. The amount of oil was determined by weighing and the saturation was evaluated
using the following formula. (Cleo Griffith Rall and Taliaferro, 1946, and R.A.Kazi,
1995)
100,%
100,
,% ××=
PorosityccsampleofVolumeccsampleinoilofVolume
saturationOil
)/(
)(ccgoilofDensity
gmsoilofWeightoilofVolume =
4.3.2 Preparation of the combustion cell
The sand mixture was places into the combustion cell to its full length. A piston
slightly less in dia to the inside of the combustion cell attached to a steel rod used to
moderately press the sand mixture inside the cell. This moderately pressing should
have created a uniform sand pack with approximate porosity of 30 - 40%. This gives a
sand pack volume of 201 cm3 filled from bottom to top. Clean sand was packed up to
the level of the igniter in order to prevent premature cracking reactions with oil in the
sand pack
4.3.3 Preparations of apparatus
Packed combustion cell, secured in place in the bottom flange assembly was inserted
in the pressure shell and bolted. Placed on rack and connected with inlet and outlet
connections by using a Swagelok fittings. The reactor was pressurized to the required
pressure of experiment and held constant by isolating it for 30 minutes. With no
decline in pressure the experiment is than commenced.
The sequence of decline the pressure at the outlet of the reactor is:
1. Up to the high pressure separator the pressure kept same as to the experiment
pressure.
74
2. Downstream to the regulator and up to the scrubber, the pressure was kept to
34.5 KPa.
3. Downstream of the scrubber the pressure was let down to 6.895 KPa.
4. At the sample point the pressure was kept same to that of 6.895 KPa.
Samples were withdrawn with a gas tight syringe of 1.0 ml capacity.
4.4 PROCEDURE
A number of major modifications were made to facilitate the air injection experiments
on light oil reservoirs. A schematic diagram of the facility with the modified gas and
liquid sampling system is shown in Figure 4.1.
(1) The air was supplied by high-pressure (13652 KPa) cylinder of
compressed synthetic air by controlling the cylinder regulator.
(2) The injected flow rate of air was controlled by needle valve/ flow control
valve, installed at the inlet of the reactor.
(3) The inlet gas stream was admitted at the top of the reactor (Vertical),
while the exhaust gases were with drawn from the bottom of the reactor.
(4) Pressure regulator was used to control the pressure of the reactor
installed at the downstream of the high pressure separator.
(5) Down stream of the regulator, produced gases flow through the low-
pressure separator, scrubber and to the sample collection point.
(6) One electric heater/ igniter (1.0 KW) was wrapped around the top of the
reactor to heat the autoclave to simulate reservoir temperature and the
ignition to take place.
(7) Initially, the air at a pressure of 2069 to 4827 KPa with drawn through
dryer, combustion cell, high pressure separator, low pressure separator,
scrubber and series of three glass tubes filled with Silica gel, to remove
water vapors present in the effluent gas stream.
(8) After 30 minutes, the required pressure was maintained and stabilized.
The reactor was heated with a ramp of (5 oC/ min.) for the duration of
experiments and held constant to 500 oC + 50.
75
(9) Required airflow was established through the pack while the different
thermocouples were measuring the temperature at the sand face and also
at the different depth of the combustion cell. The ignition could be
observed on the temperature recorder from the change of slope on the
temperature versus time chart.
(10) Samples of exhaust gases were analyzed at every 10 minutes intervals
for the entire reaction time. For each oxidation run, the CO2, CO, O2 and
N2 concentration in the exhaust gas were determined as a function of
time.
(11) The liquid production from the high-pressure and low-pressure separator
was collected at the end of the experiment
.
4.5 CALIBRATION OF ALLTECH DUAL CONCENTRIC COLUMN
A dual concentric column (Alltech CTR1# 8700) with an inner dia (6ft Long x1/8
inch in diameter) tube packed with a porous polymer mixture and an outer dia (6ft
long x ¼ inch in diameter) tube packed with activated molecular sieve were used for
the analysis of CO2, CO, O2, N2, and CH4 gases under non isothermal conditions.
The column was calibrated with specified calibration gas mixture (Alltech # 9799)
recommended for the CTR1 column, as shown in figure 4.6.
This column is useful for the analysis of effluent gases during combustion. The other
experiments were conducted using this column (reported in chapter 5).
76
NO NAME RT A OR H CONCENTRATION %
1 COMP. 0.454 374476 37.6333 2 CO 2 0.774 36560 3.0674 3 O2 2.018 58707 5.8998 4 N2 3.008 459188 46.1465 5 CH4 5.192 22182 2.2292 6 CO 7.039 43952 4.4169 TOTAL 995067 100.0000
Fig. 4.6: Calibration of Alltech CTR1 column by calibration gas mixture
NAME RT A OR H CONCCOMP. 0.454 374476 37.6333
CHAPTER 5
EXPERIMENTAL RESULTS
5.1. PRESENTATION AND DISCUSSION OF RESULTS
In this chapter, the results of oxidation experiments will be presented and discussed. The
analysis is based on the effluent gas data obtained from the various experiments. The
analysis will be quantitative and qualitative description of the general trends observed.
Experiments were performed for obtaining useful kinetic data for in-situ combustion
process for the recovery of light oil.
These experiments were made, so that more reliable and comprehensive data could be
obtained for air injection process in the recovery of light oil reservoirs at high pressure
and high temperature. The unconsolidated core (sand pack) with different sand size
grains impregnated with light oil was used in this series of experiments. The properties of
light oil are presented in Table 4.5.
A total of 50 kinetics runs were made. The parameters that were varied from run to run-
included system pressure, rock formation / sand matrix, flow rate (Air flux), oxidation
temperature/ heat input, and oil and water saturation. However, oxygen concentration
remained constant for all runs. Three different types of light oils (37.5, 39.5, and 41.0
oAPI) were used in this study.
The effect of each parameter upon the oxygen conversion was determined from analysis
of the inlet oxygen and exist gases, oxygen and carbon oxides. The pressure was varied
from 690 KPa to 11032 KPa, gas flow rate from 50 to 500 ml/min measured at room
temperature and atmospheric pressure. These rates correspond to air fluxes ranging from
3.797 to 37.97 Sm3/m
2-hr. The oxygen content of the inlet gas remained constant for all
runs. At temperature below 100 oC, the oxygen conversion was too small to be
satisfactorily used in the quantitative analysis of the kinetic data. The data reported here
for oxidation temperature above 200 oC
77
78
A combustion cell filled with sand pack impregnated with light oil was placed in a high-
pressure reactor. Non-isothermal experiments were conducted at the temperature ramped
oxidation (RTO) 5 oC / min., from room temperature to 500
oC.
This impregnated unconsolidated core was placed in a combustion cell, which was heated
by one electric heater (1.0 KW) in the first series of experiments. Subsequently the
numbers of heaters were increased to three (each 1.0 kW).
In this set of experiments, 200 grams of loose sand impregnated with light oil was placed
in the reactor, and the reactor was pressurized with air to the required pressure using flow
control valve/ needle valve. The pressure regulator at the outlet of the reactor achieved at
the set pressure. The pressure regulator was then set to the required flow rate and
maintained constant to the end of the experiment. The samples of effluent gas were
analyzed at 10 minute intervals for the entire reaction time. For each oxidation run the
CO2, CO and O2 concentration in the effluent gas were determined as a function of
combustion time.
The results of successful runs are presented and discussed. The other series of
experiments were unsatisfactory in the sense that they failed due to operational problems
with the equipment or because complete analysis of the results were not possible. Typical
equipment problems that were experienced in particular experiments included leakage
from the top of the reactor, mostly loss of power during the peak analysis of the effluent
gas, and blockage of pressure regulator due to accumulation of oil and sand particles.
There were also unexpected small leaks in the experimental system, which led to shut
down of the equipment.
A summary of major experimental conditions employed for combustion runs are given in
Table 5.1, and 5.2. A summary of main results for these experiments is given in Table
5.3. However the experimental results compared with various runs by changing one
parameter are presented graphically.
79
Table 5.1: Summary of sand pack parameters
Run
No.
Percent by weight Total wt.,
%
Oil
API
Vol. of
Oil+Water
(ml)
So + Sw
%
Oil by
Wt. % 50
Mesh
80
Mesh
100
Mesh
200
Mesh
03
-
20
45
35
100
37.75
64
66.46
21.31
16
50
50
-
-
100
37.75
60
58.82
22.73
30
10
90
-
-
100
37.5
60
58.82
22.73
07
50
50
-
-
100
37.75
60
58.82
22.73
29
00
10
60
30
100
37.5
80
81.25
24.52
23
00
100
-
-
100
37.5
80
81.25
24.52
02
-
22
65
13
100
37.75
80
66.06
24.53
04
-
10
60
30
100
37.75
80
66.73
24.53
24
00
22
45
33
100
37.5
67
65.0
20.63
25
00
10
80
10
100
37.5
80
81.25
24.52
21
12.5
37.5
37.5
12.5
100
37.5
60
58.14
20.00
17
20
80
-
-
100
37.75
60
58.82
22.73
18
50
25
25
00
100
39.5
60
55.56
20.00
19
45
25
30
00
100
39.5
60
55.56
20.00
09
70
30
-
-
100
41.00
60
58.82
22.73
28
-
10
74
16
100
37.5
80
81.25
24.53
48
-
20
50
30
100
37.5
55+27
16.54
45
-
20
50
30
100
37.5
49
50
16.67
44
-
20
50
30
100
37.5
40+40
41+41
12.41
43
-
20
50
30
100
37.5
80
82.5
24.81
57
-
20
50
30
100
37.5
39+19
40+20
12.90
56
-
20
50
30
100
37.5
39+19
40+20
12.90
54
-
20
50
30
100
37.5
40+26.7
41+27.5
12.94
80
Table 5.2: Summary of operating and control parameters
Run
No.
Injected Gas Analysis
Mole %
Operating
Pressure
KPa
Temperature
Conditions
(C)
Flow rate
ml/min.
Air Flux
Sm3/m2-hr
O2 N2
03
21
79
2069
NON
ISOTHERMAL
HEATING RATE
(5 OC /MIN
100
7.595
16
21
79
2069
50
3.797
30
21
79
2069
50
3.797
07
21
79
2758
100
7.595
29
21
79
2758
100
7.595
23
21
79
3448
50-100
3.797 - 7.595
02
21
79
3448
100
7.595
04
21
79
3448
100
7.595
24
21
79
3448
100
7.595
25
21
79
3448
200
15.19
21
21
79
690
100
7.595
18
21
79
2069
100
7.595
19
21
79
2069
100
7.595
09
21
79
2069
75
5.696
17
21
79
2069
Igniter OFF, after
Ignition takes lace
100
7.595
28
21
79
2069
NON ISOTHERMAL
HEATING RATE
(5 OC /MIN.)
and another heater was
installed ( 120 Volt )
AT RESERVOIR
CONDITION
( 100 OC)
50
3.797
48
21
79
3550
200
15.19
45
21
79
3550
300
22.79
44
21
79
5310
100
7.595
43
21
79
6895
200
15.19
57
21
79
4482
Non Isothermal
Heating Rate
(5O C /Min.)
And Another
2 Heaters Were
Installed (80 Volt)
400
30.38
56
21
79
4482
500
37.97
54
21
79
9308
400
30.38
81
Table 5.3: Summary of combustion cell results
R.No.
Run
Time
Min.
NP+WP
ml
Oil
Recovery
% OOIP
Peak
Temp.
(O
C )
Max.
CO2(P)
Mole %
Max.
CO(P)
Mole %
Max.
O2(Con.)
Mole %
O2
(con.)
%
03 390 53
79.11
354
4.8761&
2.3098
2.3757
0.9745
13.5328
6.7160
100
16 240 40 66.67 326 2.1063 2.525 12.01 60.5
30 360 41 68.33 406 7.8 4.08 20.01 100
07 300 42 70.0 332 8.1615 4.4101 18.55 93
23 280 70
87.5
421
3.4269-
2.3732
1.439
&1.4354
11.9107
&5.057
100
02 460 65 81.25 372 7.1800 4.0519 19.2063 96.5
04 420 70
87.5
499
6.2841
2.4444
3.7943
1.1793
16.5501
7.6237
96.3
24 420 55 82.21 340 10.3141 4.7103
19.3005 97
25 360
65 81.25 368 6.8779 3.8699
17.7305
89
21 370
40 66.67 392 4.3037 2.6878
10.1546
51
17 240 40 66.67 383.5 6.273 5.5842 16.3956 82
18 180
40
66.67 328 2.3106 4.1399 14.0298 70.5
19 260
40
66.67
350 2.8642 4.1511 13.6784 68.5
09 670 40 66.67 427 4.4793 4.5643 9.9378 50
28 300 65 81.25 404 8.7784 5.5992 18.8976 95
48 200 42.5+26.6
79.55 406 4.9631 &
7.4049
3.8535 &
3.9809
15.0046 &
19.2698
100
45 200 44.9
92.5
335 7.3157 3.4323 18.1302 92
44 190 29+40
72.72
402 9.1242
3.0649 19.816 99.5
43 210 66.7 81.81
364 6.219 &
4.2195
3.0013 &
1.2127
17.4974
8.1243
100
57 150 31.5+19.4
87.5 405
5.2652 2.0676 14.0711 71
56 210 36.4+19.4
93.75 537 7.1758 4.0002 18.5525 93
54 160 31.5+26.6
78.78 403 7.4642
3.3448 18.4558 93
82
5.2 EFFLUENT GAS ANALYSIS
Figure 5.1 to 5.2, presents gas composition and temperature versus time for non-
isothermal experiments (heating rate 5 oC/ min) using light oil. In these figures, the
consumed oxygen and the produced carbon dioxide and carbon monoxide in mole percent
are plotted on Y1 ordinate, while the ordinate Y2 represents the temperature of the sand
pack in oC.
The abscissa represents the run time in minutes from the beginning of the air injection.
The air injection rate and effluent gas injection rate was held constant through the runs.
Figure 5.1 show that only one peak appears in the production of carbon oxides at
temperature of about 300 oC. In this peak amount of oxygen consumed exceeds that
recovered as carbon oxides gas. The decreasing mole fraction of oxygen in the produced
gas indicates that the produced reaction gases exhibiting an increase amount of CO2
generated gradually displaced the air saturation in the sand pack. The final O2 consumed
was less than 2 %. Figure 5.2 shows two apparent peaks in the production of carbon
oxides at different temperature. This result, as well as the result of differential thermal
analysis confirms the existence of at least two reactions. First peak appears at temperature
(around 300 oC); the amount of consumed oxygen is comparable to the amount of the
produced carbon oxides (i.e., CO2 + 0.5 CO). But the 2nd
peak at high temperature (about
425 oC), the O2 consumed is greater than the carbon oxides produced. At the temperature
below 100 oC, some O2 is consumed but no carbon oxides produced. The first peak in the
gas concentration graphs corresponds to the oil oxidation at low temperature, while the
second peak corresponds to the fuel combustion at high temperature. An observation was
made that the carbon monoxides production seems too early and greater than the
production of CO2 in these preliminary experiments conducted up to 3550 KPa and high
permeability sand pack as presented in Table 5.3. The rate of CO produced seems
unusual than to the rate predicted to this type of reaction scheme.
83
Comparing the results presented in Table 5.3, it is clear that the first peak is higher or
smaller than the second one, depending on the nature of the crude oil, and rock
properties. The light oil of Badin oil field due to its high reactivity with oxygen at low
temperature has a first peak, which is much higher than the second one. In contrast, for
the heavy viscous Wolf lake oil, the combustion peak is much higher than the low
temperature peak. [Kazi] (86)
, who used 10 oAPI wolf lake oil. This indicates the
propensity of this crude oil for fuel deposition. The produced carbon oxide gases can
account for almost all the oxygen consumed at high temperatures. Since the production of
carbon oxide gases represents the removal of carbon, the reaction associated with 2nd
peak is controlled by the simultaneous availability of fuel and O2 at high temperature. The
fuel is said to be burning when condition associated with the 2nd
peak prevail- i.e., the
amount of O2 consumed is eventually balanced by the amount of produced carbon oxide
gases. In this low temperature region the fuel is being oxygenated, rather than burned; a
smoldering rather than burning takes place.
5.3. EFFECT OF POROUS MEDIA TYPE
Various sets of non-isothermal experiments performed under similar operating conditions
with different sand pack properties are given in Table 5.4 and 5.5. The gas analysis
profiles and O2 consumption rates (for the Global reaction, the oxidation reaction and the
combustion reaction) were studied on different rock formations. The behavior of light oil
in unconsolidated rock formation with low permeability showed usual behavior, in that
small amount of oxygen was consumed below 100 oC temperature and no production of
carbon oxides was observed, but at temperature above 200 oC greater amount of O2 was
consumed with production of CO2 as presented in Figure 5.3 to 5.6. For better
observation oxygen consumption with different sand packs were drawn with time as an
abscissa. Figure 5.7 to 5.9 presents oxygen consumed and production of carbon oxides.
The appearance of LTO reactions in these experiments was attributed to the increased
bed thickness. To decrease the mesh size of the sand particles with low permeability gave
84
0
4
8
12
16
20
0 50 100 150 200 250 300 350 400 450 500
TIME, MINUTES
CO
NC
EN
TR
AT
ION
, M
OLE
%
0
100
200
300
400
500
TE
MP
ER
AT
UR
E,(
C)
CO2(PRODUCED) O2( CONSUMED)
CO ( PRODUCED) TEMPERATURE
RUN 02
P = 3516 KPa
A.F = 7.595
SAND PACK
80 M = 22 %
100 M = 65 %
200 M = 13 %
FIGURE 5.1 GAS COMPOSITION AND TEMPERATURE VS TIME FOR R-02
0
3
6
9
12
15
18
0 50 100 150 200 250 300 350 400 450
TIME, MINUTES
CO
NC
EN
TR
AT
ION
, M
OLE
%
0
100
200
300
400
500
600
TE
MP
ER
AT
UR
E,(
C)
CO2 ( PRODUCED) O2 (CONSUMED) CO(PRODUCED) TEMPERATURE
P = 3516 KPa
A. F = 7.595
SAND PACK
80 M = 10 %
100 M = 60 %
200 M = 30 %
RUN 04
FIGURE 5.2 GAS COMPOSITION AND TEMPERATURE VS TIME FOR R-04
85
better accessibility of oxygen to the oil and therefore favored the occurrence of LTO
reactions. Increasing the accessibility of oxygen to the residual oil and favoring LTO
attribute the appearance of LTO to the oil displacement over the dry portion of the
formation. Higher production rate of effluent gases were the result of LTO providing
more fuel to be burned. The broadening of the HTO peak was also attributed to the above
effect. The results revealed that the oil displacement and distillation could be one of the
main mechanisms of fuel deposition.
Additional experiments were conducted in order to verify the above result on different
arrangements of the sand pack. A summary of these porous media with the experimental
conditions employed for each run is given in Table 5.4 and 5.5. The results revealed that
the oil displacement and distillation could be one of the main mechanisms of fuel
deposition. At low permeability, the reaction between light components and O2 may be
high, producing CO and CO2. As CO could be the main source for the production of CO2;
therefore with increased combustion time CO reacts with O2 species to produce CO2. The
higher amount of the CO may indicate the deficiency of O2 to the reaction front, resulted
incomplete combustion. At high pressure the distillation effect may be low, therefore
more under saturated hydrocarbon molecules are produced to react with oxygen than with
the sand pack. This indicates an incomplete oxidation reaction, which may be attributed
to the low operating temperature used with the increased combustion time. The summary
of main results for these experiments is given in Table 5.6.
5.4 OIL RECOVERY
Oil recovery is mainly affected by the characteristics of the core materials, such as
porosity, permeability and wettability, as well as the oil properties, namely composition,
viscosity and density. It is also affected by the residual oil saturation and air injection
rate. The oil recovery from most of the oxidation tube tests was generally high, and more
than 75 % OOIP was recovered, leaving a residual oil saturation of about 15 % in the
86
Table 5.4: Summary of sand pack parameters
(Effect of sand pack)
Run
No.
Percent by weight Total wt.,
%
Oil
API
Vol. of
Oil, ml
So
%
Oil by
Wt. % 50 M* 80 M 100M 200M
01 - 25 45 30 100 37.5 70 64 22.5
10 30 70 - - 100 37.5 70 64 22.5
15 70 30 100 37.5 70 64 22.5
20 50 25 25 - 100 37.5 70 64 22.5
M = Mesh
50M = 300 Micrometer (μm)
100M = 150 Micrometer (μm)
Table 5.5: Summary of operating and control parameters
(Effect of sand pack)
Run
No.
Injected Gas Analysis
Mole %
Operating
Pressure
KPa
Temp.
Cond.
(C)
Flow rate
ml/min.
Air Flux
Sm3/m2-hr
O2 N2
01 21 79 2069 Non
Isothermal
5 (C/min.)
100 7.595
10 21 79 2069 100 7.595
15 21 79 2069 100 7.595
20 21 79 2069 100 7.595
Table 5.6: Summary of combustion cell results
(Effect of sand pack)
PARAMETERS R-01 R-10 R-15 R-20
RUN DURATION, (MINUTES) 300 240 240 300 CUMULATIVE OIL PRODUCTION, ML 57 49 48 53 FINAL OIL RECOVERY, (% OOIP) 81.25 70 68.75 76 AV. COMBUSTION FRONT PEAK TEMP. (C) 487 410 321 378 MAX. CON. OF PRODUCED CO2, MOLE % 7.1951 3.1936 2.9308 5.3703 MAX. CON.OF PRODUCED CO, MOLE % 4.6945 0.1999 4.8398 3.1181 MAX. CON. OF CONSUMED O2, MOLE % 19.1329 9.0272 9.4786 15.075 UTILIZATION OF O2, % 96.2 50 50 75.5
87
0
100
200
300
400
500
0 50 100 150 200 250 300
TIME. MINUTES
TE
MP
ER
AT
UR
E (
C)
0
4
8
12
16
20
GA
S C
OM
PO
SIT
ION
,%
TEMPERATURE,DEG.C CO2 ( Produced)
CO ( Produced) O2 ( Consumed)
RUN-01
P = 2069 KPa
A.F = 7.595
OIL = 37.5 API
SAND MIX- 01
80 M = 25
100 M = 45
200 M = 30
FIGURE 5.3 GAS COMPOSITION AND TEMPERATURE VS TIME FOR SAND MIX-01
0
2
4
6
8
10
0 40 80 120 160 200 240
TIME, MINUTES
GA
S C
OM
PO
SIT
ION
,( M
OLE
%
)
0
100
200
300
400
500
TE
MP
ER
AT
UR
E,(
C )
CO2( PRODUCED) O2 ( CONSUMED)
CO ( PRODUCED) TEMPERATURE
RUN 10
P = 2069 KPa
A. F = 7.595
Sand Pack
50 M = 30 %
100 M = 70 %
FIGURE 5.4 GAS COMPOSITION AND TEMPERATURE VS TIME WITH 50M=30% &100M=70%
88
0
3
6
9
12
15
0 30 60 90 120 150 180 210 240
TIME ( Minutes )
GA
S C
OM
PO
SIT
ION
(M
OLE
%
)
0
100
200
300
400
500
TE
MP
ER
AT
UR
E
( C
)
O2 CONS MOLE % CO2 PROD MOLE%
CO PROD MOLE % TEMP C
FIGURE 5.5 GAS COMPOSITION AND TEMPERATURE VS TIME WITH 50 M=70% &100 M=30%
RUN 15
P = 2069 KPa
A. F = 7.595
SAND PACK
50 M = 70 %
100 M = 30 %
0
4
8
12
16
20
0 60 120 180 240 300
TIME, MINUTES
GA
S C
OM
PO
SIT
ION
( M
ole
%)
0
100
200
300
400
500
TE
MP
ER
AT
UR
E (
C )
CO2 ( PRODUCED) O2( CONSUMED) CO(PRODUCED) TEMPERATURE
P = 2069 KPa
A. F = 7.595
SAND MIX-04
Sand Pack
50 M = 50 %
80 M = 25 %
100 M = 25 %
FIGURE 5.6 GAS COMPOSITION AND TEMPERATURE VS TIME FOR SAND MIX-04
RUN 20
89
EFFECT OF MATRIX ON THE CONSUMPTION OF OXYGEN
0
5
10
15
20
25
0 50 100 150 200 250 300
TIME ( MINUTES)
OX
YG
EN
CO
NS
UM
ED
(M
OLE
%)
R-1 O2 R-10 O2 R-15 O2 R-20 O2
FIGURE 5.7 OXYGEN CONSUMED VS TIME WITH DIFFERENT SAND PACK PROPERTIES
FOR R-1 , R-10, R-15 AND R-20
P = 2069 KPa
A.F = 7.595
So = 64 %
OIL = 37.5 API
EFFECT OF MATRIX ON THE PRODUCTION OF CO2
0
2
4
6
8
10
0 50 100 150 200 250 300
TIME ( MINUTES)
PR
OD
UC
TIO
N O
F C
O2
(M
OL
E %
)
R-1 CO2 R-10 CO2 R-15 CO2 R-20 CO2
FIGURE 5.8 PRODUCTION OF CO2 VS TIME WITH DIFFERENT SAND PACK PROPERTIES
FOR R-1 , R-10, R-15 AND R-20
P = 2069 KPa
A.F = 7.595
So = 64 %
OIL = 37.5 API
90
EFFECT OF MATRIX ON THE PRODUCTION OF CO
0
2
4
6
8
10
0 50 100 150 200 250 300
TIME (MINUTE)
PR
OD
UC
TIO
N O
F C
O (
MO
LE
%)
R-1 CO R-10 CO R-15 CO R-20 CO
P = 2069 KPa
A.F = 7.595
So = 64 %
OIL = 37.5 API
FIGURE 5.9 PRODUCTION OF CO VS TIME WITH DIFFERENT SAND PACK PROPERTIES
FOR R-1 , R-10, R-15 AND R-20
EFFECT OF SAND PACK ON CUMULATIVE OIL PRODUCTION
0
10
20
30
40
50
60
70
R-1 R-10 R-15 R-20
CU
MU
LA
TIV
E O
IL P
RO
DU
CT
ION
(ml)
FIG. 5.10 CUMULATIVE OIL PRODUCTION WITH DIFFERENT SAND PACK
91
sand pack, the latter is, of course, governed by the limited duration time of the oxidation
combustion cell test. Decreasing the permeability as presented in Figure 5.10 increased
cumulative oil production.
5.5 EFFECT OF SYSTEM PRESSURE
Figure 5.11 to5.14 presents the gas production rate with operating pressure as a parameter
is given in Table 5.7 and 5.8. For better observation oxygen consumption at different
pressures were drawn with time as an abscissa. Figure 5.1 5 presents oxygen consumed at
different pressure. This seems that increasing the pressure from 6895 KPa the reaction
rate has declined. Although comparing 2069 to 3448 KPa pressure has an identical
increase in reaction rate, but comparing to 3448 to 3585 KPa has almost an identical
behavior. Similar plots were drawn for carbon dioxide and carbon monoxide as presented
in Figure 5.16 to 5.17. An observation was made that the carbon monoxide production
seems too early in these experiments conducted up to 6895 KPa. The rate of CO
produced seems unusual than to the rate predicted to this type of reaction scheme. The
possible argument for the high rate of products at low temperature could be that the light
components are reacting with free oxygen available to large quantity, producing higher
amount of carbon oxide, where as in high pressure of 6895 KPa, the light components are
suppressed. The low level of products in 6895 KPa experiment may be due to dilution
effect, which is taking place by large number of moles present in the reactor on increased
pressure. One can conclude that the distribution of the products are inadequate and does
not behave ideal.
As the pressure increased from 2069 to 3448 KPa, cumulative oil production was
increased of about 15 percent, however at pressure 6895 KPa no significant effect was
observed as presented in Figure 5.18. The summary of main results for these experiments
is given in Table 5.9.
92
Table 5.7: Summary of sand pack parameters
(Effect of system pressure)
Run
No. Percent by weight Total wt.,
%
Oil
API
Vol. of
Oil, ml
So
%
Oil by
Wt. %
80 M 100M 200M
26 10 80 10 100 37.5 80 81 24.5
27 10 80 10 100 37.5 80 81 24.5
05 10 80 10 100 37.5 80 81 24.5
47 10 80 10 100 37.5 80 81 24.5
M = Mesh
80M = 225 Micrometer (μm)
200M = 75 Micrometer (μm)
Table 5.8: Summary of operating and control parameters
(Effect of system pressure)
Run
No.
Injected Gas Analysis
Mole %
Operating
Pressure
KPa
Temp.
Cond.
(C)
Flow rate
ml/min.
Air Flux
Sm3/m2-hr
O2 N2
26 21 79 2069 Non Isothermal
5 (C/min.) 2ND Heater
Installed @ 120 V to maintain
the reservoir
temp. (100 C)
100 7.595
27 21 79 3448 100 7.595
05 21 79 3585 100 7.595
47 21 79 6895 100 7.595
Table 5.9: Summary of combustion cell results
(Effect of system pressure)
PARAMETERS R-26 R-27 R-05 R-47
RUN DURATION, (MINUTES) 240 300 300 180 CUMULATIVE OIL PRODUCTION, ML 51 70 67 66 FINAL OIL RECOVERY, (% OOIP) 63.75 87.5 83.75 82.5 AV. COMBUSTION FRONT PEAK TEMP. (C) 353 451 489 403 MAX. CON. OF PRODUCED CO2, MOLE % 5.5428 9.2086 10.1433 5.692 MAX. CON.OF PRODUCED CO, MOLE % 4.9328 4.7947 5.4280 3.0925 MAX. CON. OF CONSUMED O2, MOLE % 13.7508 19.2457 19.1647 15.8466 UTILIZATION OF O2, % 69 97 97 80
93
0
3
6
9
12
15
0 30 60 90 120 150 180 210 240
TIME ( MINUTES )
GA
S C
OM
PO
SIT
ION
( M
OLE
%)
0
100
200
300
400
500
TE
MP
ER
AT
UR
E (
C )
CO2 PROD MOLE% O2 CONS MOLE %
CO PROD MOLE % Temp:CM ( C )
RUN 26
P = 2069 KPa
A.F = 7.595
FIGURE 5.11 GAS COMPOSITION AND TEMPERATURE VS TIME AT 2069 KPa
2ND HEATER @ 120 VOLT
IGNITER OF @ 80 MIN.
0
4
8
12
16
20
0 50 100 150 200 250 300
TIME ( MINUTES)
CO
NC
EN
TR
AT
ION
, M
OLE
%
0
100
200
300
400
500
TE
MP
ER
AT
UR
E (
C )
CO2 (PRODUCED) CO (PRODUCED)
O2 ( CONSUMED) TEMPERATURE
AT 60 MIN.
IGNITER OFF
2ND HEATER WAS SET AT 120 V
( 100 C ) FOR RES. COND.
RUN 27
FIGURE 5.12 GAS COMPOSITION AND TEMPERATURE VS TIME AT 3448 KPa
P = 3448 Kpa
A. F = 7.595
94
0
4
8
12
16
20
0 50 100 150 200 250 300
TIME, MINUTES
CO
NC
EN
TR
ATIO
N, M
OLE
%
0
100
200
300
400
500
TE
MP
ER
AT
UR
E(C
)
CO2 PRODUCED O2 CONSUMED CO PRODUCED TEMP. C
FIGURE 5.13 GAS COMPOSITION AND TEMPERATURE VS TIME AT 3585 KPa
STABILIZED
COMBUSTION
IGNITOR
ON
IGNITION IGNITOR
OFF
RUN 05
PRESSURE = 3585 KPa
AIR FLUX = 7.595
SAND PACK:
80 M = 10 %
100 M = 80 %
200 M = 10 %
0
4
8
12
16
20
0 30 60 90 120 150 180
Time ( Minutes )
Gas c
oncentr
ation (
Mole
% )
0
100
200
300
400
500
Tem
pera
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. Temp: ( C )
RUN 47
P = 6895 KPa
A F = 7.595
FIGURE 5.14 GAS CONCENTRATION AND TEMPERATURE VS TIME AT 6895 KPa
95
SYSTERM PRESSURE EFFECT
0
5
10
15
20
25
0 50 100 150 200 250 300
TIME (MINUTES)
OX
YG
EN
CO
NS
UM
ED
(M
OL
E%
)
2069KPa 3448KPa 3585KPa 6895 KPa
A.F = 7.595
OIL = 37.5 API
So = 81 %
SAND PACK
80 M =10%
100 M = 80 %
200 M = 10 %
FIGURE 5.15 OXYGEN CONSUMPTION WITH DIFFERENT SYSTEM PRESSURE VS
TIME FOR R-26,27,R-05 AND R-47
EFFECT OF SYSTEM PRESSURE ON THE PRODUCTION OF CO2
0
2
4
6
8
10
12
0 50 100 150 200 250
TIME (MINUTES)
PR
OD
UC
TIO
N O
F
CO
2(M
OLE
%)
2069KPa 3448KPa 3585 KPa 6895KPa
FIG. 5.16 PRODUCTION OF CO2 WITH DIFFERENT SYSTEM PRESSURE VS TIME FOR
R-26,27,05 AND 47
A.F = 7.595
OIL = 37.5 API
So = 81 %
SAND PACK
80 M =10%
100 M = 80 %
200 M = 10 %
96
EFFECT OF SYSTEM PRESSURE ON THE PRODUCTION OF CO
0
2
4
6
8
10
12
0 50 100 150 200 250
TIME (MINUTE)
PR
OD
UC
TIO
N O
F C
O (
MO
LE
%)
CO 2069KPa CO 3448KPa CO 3585 KPa CO 6895KPa
FIG.5.17 PRODUCTION OF CO WITH DIFFERENT SYSTEM PRESSURE VS TIME FOR R-
26,27,05 AND 47
A.F = 7.595
OIL = 37.5 API
So = 81.25
SAND PACK
80 M =10%
100 M = 80 %
200 M = 10 %
EFFECT OF PRESSURE ON CUMULATIVE OIL PRODUCTION
0
10
20
30
40
50
60
70
80
2069KPa 3448KPa 3585KPa 6895KPa
CU
MU
LA
TIV
E O
IL P
RO
DU
CT
ION
(ml)
FIG. 5.18 CUMULATIVE OIL PRODUCTION AT DIFFERENT PRESSURE
97
5.6 EFFECT OF AIR FLUX
Three different air fluxes are of 7.595, 22.78 and 30.38 Sm3/m
2-hr was used to investigate
the effect on the oxidation of light crude oil. Experiments were conducted on
unconsolidated core at pressure of 11032 KPa with a temperature ramp of 5 oC as
presented in Figure 5.19 to 5.21. The sand pack and control parameters are given in Table
5.10 to 5.11. For better observation oxygen consumption with different air fluxes were
drawn with time as an abscissa. Figure 5.22-5.24 presents oxygen consumed, production
of CO2 and CO with different air fluxes. By increasing air flux from 7.595- 30.38, the
maximum consumption of oxygen was observed at 30.38 air flux. However, at 7.595 to
22.78 air fluxes; the consumption of O2 was slightly lower than the higher fluxes, but at
lower flux the oxygen consumed for longer time as presented in figure 5.22. Increase of
air flux (airflow rate per unit area of the reacting bed) resulted in higher rates of oxygen
consumption over the temperature range under investigation: consequently the carbon
burned rate increased. The increased rate of cumulative carbon burned will affect the oil
production rate. One might expect that with increased flux distillation should also
decrease and less fuel be deposited but in contrast to this increased flux appears to have
decrease oil displacement from bed and more cumulative carbon is burned. A possible
explanation for this behavior is that at low flux less distillation occurs and thus lighter
residual oil is available for cracking or coking. The light oil is more susceptible to
visbreaking (87)
and therefore less fuel lay down may have resulted. At high flux with
more distillation, more effective visbreaking may have resulted in more fuel for
combustion.
Alexander et al (97)
observed the same behavior on increasing the air flux in the range of
1.52 to 6.10 m3/m
2-hr. fuel deposited was in the range of 1.25 to 1.6 gm/ 100gm of sand.
The low values of the fuel deposition were attributed to the low air flux used. Dabbous
(98) observed that the carbon-burning rate increases with increased flux in the region of
high carbon concentration (0.5 gm/100gm sand).
98
Table 5.10: Summary of sand pack parameters
(Effect of air flux)
Run
No.
Percent by weight Total
wt. ,
%
Vol. of
Oil, ml
Vol. of
Water,
ml
Oil
API
So
%
Sw
%
Oil by
Wt. % 80 M 100
M
200M
50 20 30 50 100 50 25 37.5 52 26 17.0
51 20 30 50 100 50 25 37.5 52 26 17.0
53 20 30 50 100 50 25 37.5 52 26 17.0
Table 5.11: Summary of operating and control parameters
(Effect of air flux)
Run
No.
Injected Gas Analysis
Mole %
Operating
Pressure
KPa
Temp.
Cond.
(C)
Flow rate
ml/min.
Air Flux
Sm3/m2-hr
O2 N2
50 21 79 11032 Non Isothermal
5 (C/min.) 2nd & 3rdND
Heater Installed
@ 80 V to
maintain the reservoir temp.
(100 C)
100 7.595
51 21 79 11032 300 22.78
53 21 79 11032 400 30.38
Table 5.12: Summary of combustion cell results
(Effect of air flux)
PARAMETERS R-50 R-51 R-53 RUN DURATION, (MINUTES) 210 210 210 CUMULATIVE OIL PRODUCTION, ML 38 42.5 43.5 CUMULATIVE WATER PRODUCTION, ML 25 25 25 FINAL OIL RECOVERY, (% OOIP) 76.00 85.00 87.0 AV. COMBUSTION FRONT PEAK TEMP. (C) 483 455 470 MAX. CON. OF PRODUCED CO2, MOLE % 8.10222 8.0337 8.866 MAX. CON.OF PRODUCED CO, MOLE % 3.4129 2.9889 3.1458 MAX. CON. OF CONSUMED O2, MOLE % 18.7451 18.5272 20.119 UTILIZATION OF O2, % 94 94 100
99
0
5
10
15
20
0 30 60 90 120 150 180 210
Time ( Minutes )
Gas c
oncentr
ation (
Mole
% )
0
100
200
300
400
500
Tem
pera
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. TEMP ( C )
P = 11032 KPa
A.F = 7.595
So = 52 %
Sw = 26 %
FIGURE 5.19 GAS CONCENTRATION AND TEMPERATURE VS TIME AT AIR FLUX 7.595
RUN 50
0
5
10
15
20
0 30 60 90 120 150 180 210
Time ( Minutes)
Gas C
oncentr
ation (
Mole
% )
0
100
200
300
400
500
Tem
pera
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. TEMP ( C )
RUN 51
P = 11032 KPa
A.F = 22.78
So = 52 %
Sw = 26 %
FIGURE 5.20 GAS COMPOSITION & TEMPERATURE VS TIME AT AIR FLUX 22.78 Sm3/m2-hr
100
0
5
10
15
20
25
0 30 60 90 120 150 180 210
Time ( Minutes )
Gas c
oncentr
ation (
Mole
% )
0
100
200
300
400
500
Tem
pera
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. Temp: ( C )
RUN 53
P = 11032 KPa
A.F = 30.38
So = 52%
Sw = 26%
FIGURE 5.21 GAS COMPOSITION & TEMPERATURE VS TIME AT AIR FLUX 30.38
EFFET OF AIR FLUX ON THE CONSUMPTION OF OXYGEN
0
5
10
15
20
25
0 30 60 90 120 150 180 210
TIME ( MINUTES)
O2
CO
NS
UM
ED
( M
OL
E %
)
7.595 O2 22.78 O2 30.38 O2
FIG. 5.22: Oxygen consumption versus time at differrent air fluxes for Run 50, 51& 53
P = 11032 KPa
OIL = 37.5 API
So = 52 %
Sw = 26 %
101
EFFECT OF AIR FLUX ON THE PRODUCTION OF CO2
0
2
4
6
8
10
0 30 60 90 120 150 180 210
TIME ( MINUTES )
CO
2 P
RO
DU
CE
D (
MO
LE %
)
7.595 CO2 22.78 CO2 30.38 CO2
FIG.5.23 CO2 PRODUCED VS TIME WITH DIFFERENT AIR FLUX FOR RUN 50, 51 & 53
P = 11032 KPa
OIL = 37.5 API
So = 52 %
Sw = 26 %
EFFECT OF AIR FLUX ON THE PRODUCTION OF CO
0
1
2
3
4
5
0 30 60 90 120 150 180 210
TIME ( MINUTES )
CO
PR
OD
UC
ED
( M
OLE
%)
7.595 CO 22.78 CO 30.38 CO
FIGURE 5.24 CO PRODUCED VS TIME WITH DIFFERENT AIR FLUX FOR RUN 50, 51 & 53
P = 11032 KPa
OIL = 37.5 API
So = 52 %
Sw = 26 %
102
EFFECT OF AIR FLUX ON THE PRODUCTION OF OIL
0
10
20
30
40
50
60
70
80
CU
MU
LA
TIV
E O
IL P
RO
DU
CT
ION
(m
l)
7.595 22.78 30.38
FIG. 5.25 CUMULATIVE OIL PRODUCTION WITH DIFFERENT AIR FLUXES
0
5
10
15
20
25
0 30 60 90 120 150 180 210
Time ( Minutes )
Gas C
om
positio
n (
Mole
% )
0
100
200
300
400
500T
em
pera
ture
( C
)
O2 CONS. CO2 PROD. CO PROD. TEMP: ( C )
FIGURE 5.26 GAS COMPOSITION AND TEMPERATURE VS TIME WITH So = 55% & Sw = 27.5%
RUN 41
P = 3550 KPa
A.F = 7.595
So = 55 %
Sw = 27.5 %
103
Peak temperature of the combustion marginally increased flux by 18 oC. As the air flux
increased, the cumulative oil production was also increased as presented in Figure 5.25.
The summary of main results for these experiments is given in Table 5.12.
5.7 OIL AND WATER SATURATION
In this series of experiments some amount of water was added into the cell impregnated
with light crude. The other sand pack and control parameters are given in Table 5.13 and
5.14. The effect of oil and water consequence production stream on the combustion
reaction is depicted in Figure 5.26 to 5.28. There is a slight variation in the consumption
of oxygen and production of oxides was observed by using different saturation of water,
16.5, 27 and 41.25 percent. Sand and water were thoroughly mixed; a weighed quantity
of oil was added with the sand and water until a homogenous mixture was obtained. The
relative amount of sand, water and oil used in the packed combustion cell, and porosity,
water and oil saturations were determined. Non-isothermal experiments were performed
with RTO 5 oC/minute using light oil. A sample of mixture was subjected to a linear
heating schedule while air was flowed through it and the effluent gases were analyzed for
their composition. It was found that unlike heavy oils, light oils displayed three oxidation
reaction classes: LTO, MTO, and HTO. A different fuel is specific for each reaction
class: for LTO, it is the oil itself; for MTO it is the light hydrocarbons produced by
cracking, and for HTO, it is heavy oil deposited by cracking. The corresponding peak
temperatures for these three classes are less than 200 oC, 250 to 300
oC and greater than
300 oC respectively. As compared to LTO in heavy oils, LTO in light oils produced more
CO2 Kissler and Shallcross (47, 48)
. It was also shown (49)
that the LTO leads to an increase
in viscosity. For instance, the viscosity increases 1.4 times after 11 hrs of oxidation at 52
oC and 1.2 times. Schematic profiles of O2 consumption along the combustion cell and
variation of the gas composition during the run are shown in Figure 5.26 to 5.28. As
shown in these figures, the O2 consumed 18 to 20 mole percent over an extended zone in
the reservoir, but around the injection well there still exists a narrow zone where the O2
104
Table 5.13: Summary of sand pack parameters
(Effect of oil and water saturation)
Run
No.
Percent by weight Total
wt.,
%
Vol. of
Oil, ml
Vol. of
Water,
ml
Oil
API
So
%
Sw
%
Oil by
Wt. % 80 M 100
M
200M
42 20 30 50 100 64 16 37.5 66 16.5 20.9
41 20 30 50 100 54 26 37.5 55 27 18.2
46 20 30 50 100 40 40 37.5 41 41 14.2
Table 5.14: Summary of operating and control parameters
(Effect of oil and water saturation)
Run
No.
Injected Gas Analysis
Mole %
Operating
Pressure
KPa
Temp.
Cond.
(C)
Flow
rate
ml/min.
Air Flux
Sm3/m2-hr
O2 N2
42 21 79 3550 Non Isothermal
5 (C/min.)
2nd Heater Installed @120 V to maintain
the reservoir temp.
(100 C)
100 7.595
41 21 79 3550 100 7.595
46 21 79 3550 100 7.595
Table 5.15: Summary of combustion cell results
(Effect of oil and water saturation)
PARAMETERS R-42 R-41 R-46 RUN DURATION, (MINUTES) 220 190 220 CUMULATIVE OIL PRODUCTION, ML 48 39 29.1 CUMULATIVE WATER PRODUCTION, ML 16 26 40 FINAL OIL RECOVERY, (% OOIP) 75.00 73 73 AV. COMBUSTION FRONT PEAK TEMP. (C) 401 388 398 MAX. CON. OF PRODUCED CO2, MOLE % 8.3364 9.6863 8.4029 MAX. CON.OF PRODUCED CO, MOLE % 3.7549 3.667 3.4996 MAX. CON. OF CONSUMED O2, MOLE % 17.6618 19.7665 20.0994 UTILIZATION OF O2, % 89 99 100
105
0
4
8
12
16
20
0 30 60 90 120 150 180 210 240
Time ( Minutes )
Ga
s C
om
po
sitio
n (
Mo
le %
)
0
100
200
300
400
500
Te
mp
era
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. Temp: ( C )
RUN 42
P = 3550 KPa
A.F = 7.595
So = 66.0 %
Sw = 16.5 %
FIGURE 5.27.30 GAS CONCENTRATION AND TEMPERATURE VS TIME WITH So=66 &
Sw=16.5%
0
5
10
15
20
25
0 30 60 90 120 150 180 210 240
Time ( Minutes )
Ga
s c
om
po
sitio
n (
Mo
le %
)
0
100
200
300
400
500
Te
mp
era
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. Temp: ( C )
RUN 46
FIGURE 5.28 GAS CONCENTRATION AND TEMPERATURE VS TIME WITH So=41% AND
Sw= 41%
P = 3550 KPa
A.F = 7.595
So = 41 %
Sw = 41%
106
EFFECT OF OIL AND WATER SATURATION ON THE CONSUMPTION OF O2
0
5
10
15
20
25
0 30 60 90 120 150 180 210 240
TIME ( MINUTES)
OX
YG
EN
CO
NS
UM
ED
( M
OL
E%
)
O2 So=66% Sw=16.5% O2 So=55% Sw=27.5%
O2 So=41.25% Sw=41.25%
FIGURE 5.29 OXYGEN CONSUMED VS TIME WITH DIFFERENT Sw FOR R -41,42, AND R-46.
P = 3550 KPa
A.F = 7.595
OIL = 37.5 API
SAND PACK
80 M = 20 %
100M = 50 %
200M = 30 %
EFECT OF OIL AND WATER SATURATION ON THE PRODUCTION OF
CO2
0
2
4
6
8
10
12
0 50 100 150 200 250
TIME (MINUTES)
PR
OD
UC
TIO
N O
F C
O2
(M
OL
E%
)
So=66% & Sw= 16.5% So=55%,Sw=27.5% So=41.25% & Sw=41.25%
FIG. 5.30 PRODUCTION OF CO2 VS TIME WITH DIFFERENT So AND Sw FOR R -41,42,
AND R-46.
P = 3550 KPa
A.F = 7.595
OIL = 37.5 API
SAND PACK
80 M = 20 %
100M = 50 %
200M = 30 %
107
EFFECT OF OIL AND WATER SATURATION ON THE PRODUCTION OF
CO
0
2
4
6
8
10
12
0 50 100 150 200 250
TIME (MINUTES)
PR
OD
UC
TIO
N O
F C
O (
MO
LE
%)
So=66 & Sw =16.5 So=55 & Sw=27.5% So=41.25% & Sw=41.25%
FIG. 7.31 PRODUCTION OF CO VS TIME WITH DIFFERENT So AND Sw FOR R -41,42,
AND R-46.
P = 3550 KPa
A.F = 7.595
OIL = 37.5 API
SAND PACK
80 M = 20 %
100M = 50 %
200M = 30 %
EFFECT OF OIL AND WATER SATURATION ON CUMULATIVE OIL
PRODUCTION
0
10
20
30
40
50
60
70
80
oil,ml water,ml OIL,ml Water,ml
Mixed Mixed Prod. Prod.
OIL
AN
D W
AT
ER
MIX
ED
AN
D C
UM
UL
AT
IVE
PR
OD
UC
TIO
N O
F O
IL A
ND
WA
TE
R (
ml)
R-42 R-41 R-46
FIG. 5.32 CUMULATIVE OIL PRODUCTION WITH DIFFERENT OIL AND WATER
SATURATION
108
60
64
68
72
76
80O
IL R
EC
OV
ER
Y (
%)
So=66%,Sw=16% So=55%,Sw=27% So=41%, Sw=41%
FIG. 5.33 OIL RECOVERY WITH DIFFERENT OIL AND WATER SATURATION
0
3
6
9
12
15
18
0 50 100 150 200 250 300 350 400 450
TIME, MINUTES
GA
S C
OM
PO
TIO
N,M
OL
E %
0
100
200
300
400
500
TE
MP
ER
AT
UR
E,
( C
)
CO(PRODUCED) O2(CONSUMED)
CO(PRODUCED TEMPERATURE, DEG.C
RUN 22
P = 3585 KPa
A.F = 7.595
OIL = 37.5 API
FIGURE 5.34 GAS CONCENTRATION AND TEMPERATURE VS TIME BY SINGLE
HEATER
109
from the air was not consumed owing the lack of fuel, this region had zero residual oil
saturation (3)
. Other laboratory investigations (80)
found that in this area, the residual oil
saturation is low, but it is not zero, the oil is partially oxidized and can no longer
consume oxygen. For better observation oxygen consumption with different oil and water
saturation were drawn with combustion time as an abscissa. Figure 5.29 presents oxygen
consumed with different oil and water saturation as a parameter. It seems that increasing
oil and water saturation from 16.5 to 27.5 percent, the slightly increases reaction rate .
But when Sw was increased from 27.5 to 41.5 the reaction rate decreased. Similar plot
was drawn for CO2 and CO as presented in Figure 5.30 and 5.31. The summary of main
results for these experiments is given in Table 5.15. As presented in Figure 5.32 and 5.33,
there was no any significant effect on the recovery of oil and cumulative oil production
respectively.
5.8 EFFECT OF TEMPERATURE/ HEAT INPUT
Increasing the number of heaters from one to three, increased the reaction rate. All other
parameters were kept constant and are given in Table 5.16 and 5.17. By installing one
electric heater on the top of the reactor as presented in Figure 5.34 resulted 75 percent
more oxygen consumption. Additional experiments were performed by installing one
heater by changing various parameters for most of the runs. 100 percent utilization of
oxygen was observed, but the oxidation reaction takes place for shorter time as compared
to two electric heaters. Two heaters were installed to cover the half of length of the
reactor to maintain reservoir conditions for the 2nd
zone (100 oC) as presented in Figure
5.35. Similarly by installing three heaters to cover the entire length of the reactor in order
to maintain the reservoir conditions (80 oC), the 100 percent oxygen was consumed and
the consumption took place for longer time as presented in Figure 5.36. For better
observation oxygen consumption at different heat input was drawn with time as an
abscissa. Figure 5.37, present oxygen consumed at different heat input. This seems that
increasing the number of heaters, the reaction rate has increased. Similar plots were
110
drawn for CO2 and CO as presented in Figure 5.38 and 5.39. The summary of main
results for these experiments is given in Table 5.18. The cumulative production of oil is
shown in Figure 5.40.
To investigate the reaction and chemical nature of the fuel burned by changing various
parameters and to see the importance of distribution and pyrolysis on these reactions, the
apparent Hydrogen-Carbon ratio and the molar carbon oxides ratio will be calculated.
The results of these calculations will be discussed in later chapter. For further
confirmation an Arrhenius plot was obtained by assuming fist order reaction rate with
respect to carbon concentration, which also confirmed, which will be discussed in later
chapter.
5.9 COMPARISON BETWEEN THEORETICAL AND EXPERIMENTAL
RESULTS
Comparisons of experimental with theoretical results are presented in Table 5.19.
However, results are not similar due to change of different parameters. However, these
results are consistent with other research studies.
111
Table 5.16: Summary of sand pack parameters
(Effect of heat input)
Run
No. Percent by weight Total wt.,
%
Oil
API
Vol. of
Oil, ml
So
%
Oil by
Wt. %
80 M 100M 200M
22 20 50 30 100 37.5 80 81 24.5
49 20 50 30 100 37.5 80 81 24.5
55 20 50 30 100 37.5 80 81 24.5
Table 5.17: Summary of operating and control parameters
(Effect of heat input)
Run
No.
Injected Gas
Analysis
Mole %
Operating
Pressure
KPa
Temperature conditions.
(C)
Flow rate
ml/min.
Air Flux
Sm3/m2-
hr
O2 N2
22 21 79 3585 Non Isothermal, Only one heater
was installed, Heating rate 5
(C/min.)
100 7.595
49 21 79 3585 Two heaters were installed one
for ignition & 2ND
Heater was
set @ 120 V to maintain the
reservoir temp. (100 C)
100 7.595
55 21 79 3585 Three heaters were installed one
for ignition & 2nd
and 3rd
Heater
were set @ 80 V to maintain the
reservoir temp. (100 oC)
100 7.595
Table 5.18: Summary of combustion cell results
(Effect of heat input)
PARAMETERS R-22 R-49 R-55 RUN DURATION, (MINUTES) 440 220 190 CUMULATIVE OIL PRODUCTION, ML 65 64 67 FINAL OIL RECOVERY, (% OOIP) 81.25 80.0 83.75 AV. COMBUSTION FRONT PEAK TEMP. (
OC) 337 401 432
MAX. CON. OF PRODUCED CO2, MOLE % 6.0854 8.3364 7.1106 MAX. CON.OF PRODUCED CO, MOLE % 2.9767 3.7549 3.5059 MAX. CON. OF CONSUMED O2, MOLE % 14.9117 17.6618 18.8122 UTILIZATION OF O2, % 75 89 95
112
0
4
8
12
16
20
0 30 60 90 120 150 180 210 240
Time ( Minutes )
Gas C
om
positio
n (
Mole
% )
0
100
200
300
400
500
Tem
pera
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. Temp: ( C )
RUN -49
P = 3585 KPa
A.F = 7.595
FIGURE 5.35 GAS CONCENTRATION AND TEMPERATURE VS TIME BY TWO HEATERS
0
4
8
12
16
20
0 30 60 90 120 150 180 210
Time ( Minutes )
Gas C
oncentr
ation (
Mole
% )
0
100
200
300
400
500
Tem
pera
ture
( C
)
CO2 PROD. O2 CONS. CO PROD. Temp: ( C )
P = 3585 KPa
A.F = 7.595
RUN 55
FIGURE 5.36 GAS CONCENTRATION AND TEMPERATURE VS TIME BY INSTALLING THREE HEATERS
IGNITOER OFF
@ 90 MIN.
Fig. 5.35: Gas concentration and temperature vs time heaters
Fig. 5.36: Gas concentration and temperature vs time by installing three
heaters
113
EFFECT OF HEAT INPUT ON THE CONSUMPTION OF OXYGEN
0
5
10
15
20
25
0 50 100 150 200 250 300
TIME (MINUTE)
OX
YG
EN
CO
NS
UM
ED
(MO
LE
%)
1H O2 2H O2 3H O2
FIG. 5.37 OXYGEN CONSUMED VS TIME BY INCREASING HEATERS FROM 1 TO 3 FOR R-22,49 &
55
P = 3585 KPa
A.F = 7.595
So = 81 %
OIL = 37.5 API
SAND PACK
80 M = 20 %
100 M = 50 %
200 M = 30 %
EFFECT OF HEAT INPUT ON THE PRODUCTION OF CO2
0
2
4
6
8
10
12
0 50 100 150 200 250 300
TIME ( MINUTE)
PR
OD
UC
TIO
N O
F C
O2
1H CO2 2H CO2 3H CO2
FIG.5.38 RODUCTION OF CO2 VS TIME BY INCREASING HEATERS FROM 1 TO 3 FOR R-22, 49 &
55
P = 3585 KPa
A.F = 7.595
So = 81 %
OIL = 37.5 API
SAND PACK
80 M = 20 %
100 M = 50 %
200 M = 30 %
114
EFFECT OF HEAT INPUT ON THE PRODUCTION OF CO
0
2
4
6
8
10
12
0 50 100 150 200 250 300
TIME (MINUTE)
PR
OD
UC
TIO
N O
N O
F C
O (
MO
LE
%)
1H CO 2H CO 3H CO
P = 3585 KPa
A.F = 7.595
So = 81 %
OIL = 37.5 API
SAND PACK
80 M = 20 %
100 M = 50 %
200 M = 30 %
FIG. 5. 39 PRODUCTION OF CO VS TIME BY INCREASING HEATERS FROM 1 TO 3 FOR R-22, 42
& 55
EFFECT OF HEAT INPUT ON THE PRODUCTION OF CUMULATIVE OIL
PRODUCTION
0
10
20
30
40
50
60
70
80
1
CU
MU
LA
TIV
E O
IL P
RO
DU
CT
ION
(mL)
1H 2H 3H
FIG. 5.40 CUMULATIVE OIL PRODUCTION WITH DIFFERENT HEAT INPUT
115
Table 5.19: Comparisons between theoretical and experimental results
Author/
Year
Equipment
Description
Oil
gravity
API
Pres.
KPa
Temp.
(0C)
Air flux
Sm3/m
2-
hr
CO2
PROD.
%
CO
PROD.
%
O2
CONS.
%
Sakthikumar et
al., 1995
Isothermal
Oxidation
Reactor
20-45 92-119 7.9 0.5 60
V.K.Kumar et
al, 1995
CT 39 7240
31027
280-428 8.0 49-100
M.Greaves et
al. 1996
SBR & CT 23 .0
31.0
176-352 375
15 3.5-12.8 1.5-6.9 52 - 90
P.Germain et
al., 1997
CT 32.2 4137-
4827
290 - - - 90
M.R.Fassihi et
al, 1997
CT/ Field 39
31
28407
24822
110 100
B.C.Watts et
al., 1997
CT/Field
32
32.2
39
13997
175-400 41.2-16.2 76 -
81.8
T.H.Gilham et
al., 1997
ARC/CT 36-37
39
24133 327 500 L/H 100
C.Clara et al.
1998
ARC / Field 32.2
39.0
30.0
26201
28270
300-400
13
2.0
100
A.T.Turta at
al., 1998,
CT / Field 48
44
37233
18616
6895
400-
450
50-150
9.5-12
-
80 -95
M.Pascual et
al. 1998
CT 31 19610 100 13 91
M.Greaves et
al. 1998
Oxidation
Tube/SBR
39.0 6206-
22754
111-118 8-16 0.4-1.8 100
Cedric Clara et
al., 1999
Isothermal
Oxidation
Reactor
33.5
17100
92-130
0.521
&
7.44
12
13
1.0
3.0
81.5
116 TABLE5.19 (CONTINUED)
Author/
Year
Equipment
Description
Oil
gravity.
API
Pres.
KPa
Temp.
(oC)
Air flux
Sm3/m
2-hr
CO2
PROD.
%
CO
PROD.
%
O2
CONS.
%
M.Greaves et
al., 1999
Oxidation
Tube & SBR
36
39
5999
17996
120-118
0.76-
0.08
0.58-
0.28
8
7
1.2
1.0
0.2-0.3
Final
C.A. Glandt et
al., 1999
ARC/ Field
31.6
31.7
33
34.5
7736
Pb
96.0
Cedric Clara et
al., 2000
Isothermal
Disk reactor
33.5
16879
400
12.5
&
2.5
13 3.0 81.5
M.Greaves et al.
2000
Oxidation
Tube
36
39
5999
17996
120-118
0.76-.08
0.58-.28
9
1.0 0.2-0.3
Final
A.T.Turta at al.,
2001
CT / Field
48
44
37233
18617
6895
400-450
50-150
9.5-12
80 -95
S.R.Ren &
M.Greaves
2002
SBR
&
Oxidation tube
36
37
39
23581-
24305
20685
100-130
0.34-
1.37
6.5 -2.6
0.8-1.9
Final
0.7 -2.4
Dembla Dhiraj
et al., 2004
ARC 41.7 20168 370 11.5 2.5 86
S.Stokka et al.,
2005
SBR/ ARC/
CT
31028 130-150
155-200
This Study
Combustion
Cell
37.5
39.5
41.0
6895-
11032
100-450
3.797-
37.97
6-10
0.19-4.0
70-100
117
5.9 COMBUSTION CELL TEMPERATURE PROFILES
The impregnated unconsolidated core sample was placed in a combustion cell which was
heated by installing one electric heater on the top of the reactor with a ramp of 5 o
C
/minute in the first series of experiments. Subsequently the number of heaters was
increased to three (1.0 KW each).
The temperature profiles during the combustion are shown in Figures 5.41 to 5.46. A
slight variation in peak temperatures is noticeable. This is due to the rate at which heat is
generated by the exothermic combustion reaction compared with heat losses from the
combustion. Heat losses from the combustion zone are the result of radial conduction
through the cell wall, combined with axial heat conduction and convection down stream
to the steam zone.
In these figures, temperature (CM1) and temperature (M2) and temperature (M3) profiles
of the sand pack (oC), are plotted on the left ordinate, while the ordinate on the right
represents the pressure (KPa). The abscissa represents the run time (minutes) from the
beginning of the air injection.
5.9.1 Dry combustion
Figure 5.41 to 5.42, a quick ignition was achieved and temperature increased
significantly of the 1st zone about 500
oC causing very little disturbance on the process.
The combustion front propagation stabilizes quickly for the set temperature of about 430
oC through out the test. Combustion front propagates in down ward direction and also
ignition takes place in 2nd
and 3rd
zone of the combustion cell, both the zones stabilized at
about the temperature of 350 oC and 200
oC respectively through out the run. The ignition
occurs in the 2nd
and 3rd
zone. The peak temperatures of these zones were about 400 oC
and 250 oC.
118
In the second series of experiments two heaters were installed one for ignition and
another for maintaining the reservoir temperature (100 oC). Igniter was installed at the top
of the reactor and 2nd
heater was installed at the mid of the reactor to cover the half of the
length of reactor. Both the heaters were switched “ON” after the pressure stabilized.
Figure 5.43 shows very quick ignition was achieved and caused very little disturbance on
the process. The combustion front propagation stabilized quickly after the igniter is
switched –OFF and there after continues at steady temperature of about 250 oC through
out the test. The ignition temperature of the 1st zone was reached at about 500
oC.
Combustion front propagates to the down ward direction and also ignition takes place in
2nd
and 3rd
zone of the combustion cell, both the zones stabilized at about 260 oC and 180
oC respectively through out the run. The ignition occurs in the 2
nd and 3
rd zone. The peak
temperatures of the 2nd
and 3rd
zones were about 380 oC and 280
oC.
The analysis was repeated in a similar manner for most of the runs. As reported in Table
5.2, run- 23, and 25 were performed with air at different total gas fluxes while runs -2, 4,
22, and 24 were performed at the same total air flux. These runs therefore demonstrate
the effect of oxygen flux on the magnitude of the heat loss. From a practical viewpoint of
operating forward combustion projects, oxygen fluxes greater than the minimum are
often used, in order to compensate for any excessive heat losses, other wise extinction of
the combustion front could occur. [Parrish et al., (119)
]
The heat loss as a percentage of the cumulative heat liberated for run-1-30 .It is apparent
that the heat generated and the heat losses are dependent on the combustion front
location.
According to Burger and Sahuquet (96)
, the heat released per unit mass of fuel burned at
the combustion zone is a function of the H/C ratio of the fuel and CO/CO2 ratio of
produced gas.
The heats of formation of CO2 and CO are respectively –94.052 and 26.416 cal /mole at
25 oC [Alderman et al.,
(120)] serving to illustrate that the amount of CO2 and CO
produced must significantly affect the heat generated.
119
Therefore, any variation of the H/C ratio or CO/CO2 ratio will produce a corresponding
change in the magnitude of heat generated as the combustion front propagates through
the sand pack. On the other hand, the heat loss is mainly a function of the temperature
gradient prevailing at the combustion front and also front velocity. For a fixed heat in put
by the wall heaters, the radial temperature gradient will depend on heat transfer processes
occurring in the vicinity of the combustion zone as well as the combustion reaction
kinetics. Hence, for a given front velocity, variation in the temperature gradient, give rise
to a corresponding change in heat loss over the combustion cell. The net effect is to
increase or decrease the observed peak temperature. The increasing trend of the average
peak temperature with oxygen concentration shown in Table 5.2 is consistent with the
findings of Hansel et al. (121)
and is believed to be due to the rate at which heat is
generated compared with the heat loss.
With air-assisted combustion, the peak temperature is not significantly affected by
increase in pressure, varying from 300 oC to 350
oC over the pressure range 2069 to 3448
KPa. One explanation for this is that at higher injection pressures, the distillation rate of
volatile components in the steam zone is lower. This means that more fuel is potentially
available for combustion. In consequence, a peak temperature would be expected but the
convective heat transport from the combustion cell, zone also increases due to larger
fraction of nitrogen in the combustion gases. Thus, when this is combined with the radial
heat loss by conduction, the net result is to suppress any increased temperature effect
arising from higher fuel concentration. Similar insensitivity of combustion front peak
temperature to air injection pressure has also been reported by Wilson (54, 66)
who
conducted experiments up to 11032 KPa with a near adiabatic combustion tube.
Greaves et al (51)
were also conducted at LTO experiments at high- pressure (200 bar) air
injection into light oil reservoirs.
5.9.2 Wet Combustion
The wet combustion results represented in Figure 5.44 shows that there is a lowering of
combustion front peak temperature, due to mainly the combined effect of external heat
120
losses and in-situ generated steam. Similar results reported by Burger et al. (96)
and Garon
et al. (52).
Figure 5.45 to 5.46 shows that there is a higher combustion front peak
temperature compared to dry combustion at low pressure (3550 KPa) and by installing
one to two heaters. This occurs by increasing the number of heaters to cover the entire
length of reactor and as well by increasing pressure up to 11032 KPa. Figure 5.45 to 5.46,
shows very quick ignition was achieved and causing very little disturbance on the
process. The combustion front propagation stabilizes quickly after the igniter is switched
–OFF and there after continues at steady temperature of about 250 oC through out the
test. The ignition temperature of the 1st zone was reached at about 450
oC. Combustion
front propagates to the down ward direction and also ignition takes place in 2nd
and 3rd
zone of the combustion cell, both the zones stabilized at about 260 oC and 180
oC
respectively through the run. The ignition occurs in the 2nd
and 3rd
zone. The peak
temperatures of the 2nd
and 3rd
zones were about 400 oC and 300
oC.
Ejiogu et al. (122)
however observed higher peak temperatures during wet combustion
compared with dry combustion. This was attributed to the additional heat input to the
combustion zone by superheated steam, which is produced when the added water
contacts the hot rock behind the combustion zone. They claimed that this increased the
size of the steam zone. The resulting preheating reduced the rate of heat loss by
decreasing the temperature gradient. In the normal wet combustion region to which
Ejiogu et al. results mainly apply, the superheated steam is always at a lower temperature
than the combustion peak temperature before it enters the combustion zone. Some
cooling effect is therefore expected to occur. As shown in Table 5.3, 5.6, 5.9, 5.12, 5.15
and 5.18, the average heat generation rate is higher for some wet combustion than for the
corresponding dry combustion. This is due mainly to the combined effect of the smaller
m-ratio and the H/C ratio of the burned fuel, both parameters being reaction kinetics
dependent. It seems more plausible therefore that if heat losses are minimized, than
higher peak temperature in wet combustion than in corresponding dry combustion could
be expected in such cases.
121
0
100
200
300
400
500
600
0 30 60 90 120 150 180 210 240 270 300
TIME. MINUTES
TE
MP
ER
AT
UR
E (
C)
0
400
800
1200
1600
2000
2400
PR
ES
SU
RE
,KP
a
TEMP:C/M1 TEMP:M2 TEMP:M3 PRESSURE
RUN 01AIR FLUX = 7.595
FIG. 5. 41 PRESSURE AND TEMPERATURE PROFILES VS TIME
SAND PACK
80 M = 25 %
100 M = 50 %
200 M = 25 %
0
100
200
300
400
500
600
0 50 100 150 200 250 300 350 400 450
TIME, MINUTES
TE
MP
ER
AT
UR
ES
, (C
)
0
700
1400
2100
2800
3500
4200
PR
ES
SU
RE
, K
Pa
TEMP:C/M1 TEMP:M2 TEMP:M3 PRESSURE
FIGURE 5.42 PRESSURE AND TEMPERATURE PROFILES VERSUS TIME FOR RUN-04.
SAND PACK
80 M = 10 %
100 M = 60 %
200 M = 30 %
RUN 04 AIR FLUX = 7.595
122
0
100
200
300
400
500
600
0 50 100 150 200 250 300
TIME (MINUTES)
TE
MP
ER
AT
UR
E,
( C
)
0
700
1400
2100
2800
3500
4200
PR
ES
SU
RE
(K
Pa
)
TEMP: C/M1 TEMP:M2 TEMP:M3 PRESSURE
FIGURE 5.43 PRESSURE AND TEMPRETURE PROFILES VS TIME
RUN 05SAND PACK
80 M = 10 %
100 M = 80 %
200 M = 10 %
A .F =7.595
0
100
200
300
400
500
0 30 60 90 120 150 180 210
TIME ( MINUTES )
TE
MP
ER
AT
UR
E (
C )
0
800
1600
2400
3200
4000
Pre
ssure
( K
Pa )
Temp:C/M1 °C Temp:M2 °C Temp:M3 °C Pressure Kpa
RUN 41
A. F = 7.595
FIGURE 5.44 TEMPERATURE PROFILES AND PRESSURE VS TIME
123
0
100
200
300
400
500
600
0 30 60 90 120 150 180 210
Time ( Minutes )
Te
mpera
ture
Pro
file
s (
C )
0
2000
4000
6000
8000
10000
12000
Pre
ssure
( K
Pa )
Temp:C/M1 Temp:M2 Temp:M3 Pressure
RUN 51
AIR FLUX =22.78
FIGURE 5.45 TEMPERATURE PROFILES AND PRESSURE VS TIME
0
100
200
300
400
500
0 30 60 90 120 150 180
Time ( Minutes )
Tem
pera
ture
Pro
file
s (
C )
0
2000
4000
6000
8000
10000
Pre
ssure
( K
Pa )
Temp:C/M1 Temp:M2 Temp:M3 Temp:M4 Pressure
RUN 54
AIR FLUX = 30.38
FIGURE 5.46 TEMPERATURE PROFILES AND PRESSURE VS TIME
CHAPTER 6
TREATMENT OF THE DATA
6.1 TREATMENT OF THE DATA
To investigate these reactions and the chemical nature of the fuel burned, and also to
determine the importance of distillation and pyrolysis on these reactions, the apparent
H/C ratio and the molar ratio of carbon monoxide to carbon oxides were calculated as:
2COCO
COm
As the bed length is short, few data points were available and averaged at the temperature
range, used to calculate the kinetic parameters such as rate, order of reaction and
activation energy. The fuel deposited was calculated by the method of Bousaid et al. (99)
.The results of these calculations are discussed in subsequent paragraph. To avoid the
error in calculating kinetic parameters the experimental data were smooth by using fourth
order polynomial regression. Some deviations were observed. These small deviations
were attributed to heat generation in the oxidation reactions.
Analysis of the over all rate expressions describing the rate of carbon conversion (Direct
Arrhenius plot) was used for reaction kinetics (123)
.
6.2 OXYGEN CONSUMPTION
The oxygen consumed in the reaction was estimated by assuming nitrogen as an inert gas
in the reaction and that oxygen and carbon oxides are present in the produced gas. The O2
consumed in excess is assumed to be form LTO products at low temperature and carbon
oxides and water in HTO reactions at high temperatures. From the balance of the N2 in
the exit gas:
PP OCOCON 222 100 (6.1)
124
125
Where CO2 = Carbon dioxide produced, mole %
CO = Carbon monoxide produced, mole %
O2 = Oxygen at outlet, mole %
The measured oxygen consumed was adjusted from the flow of gas at the exit and
calculated as:
PP
i
i
M ONN
OmeasuredO 22
2
2
2 )(
(6.2)
Where O2i = Oxygen at inlet, mole %
N2i = Nitrogen at inlet, mole %
N2P = Nitrogen at outlet, mole %
The true oxygen consumed by the process in production of carbon oxides is calculated
using Fassihi’s Method (42)
:
P
Pi
cOCOCO
OCOCOOTrueO
22
222
21
)1 (6.3)
The amount of oxygen consumed to form carbon dioxide, carbon monoxide and water,
then from stoichiometric (equation 6.5) and applying corresponds H/C ratio, the actual
amount of oxygen consumed is:
COCOCOCOX
OActual
5.04
222 (6.4)
By subtracting the actual amount of oxygen consumed O2 (Actual) in the production of
carbon oxides plus water formed, from the oxygen consumed in the process O2 C in low,
medium and high temperature range, a new curve is obtained. The obtained curve
represents the oxygen consumed in excess to the O2 consumed by carbon oxides and
water and believed that has been consumed by the oil in the production of hydrocarbons
during the oxidation.
The in-situ combustion process is an over lapping of several competing chemical
reactions occurring over different temperature ranges. To characterize the forward
combustion process, three processes are considered, namely LTO, then fuel lay down,
126
and finally combustion. (123)
. Some time difficulties arise in distinguishing between LTO
and MTO reaction.
This three step chain process can then be replaced by two processes, i.e. fuel lay down
and combustion. Experimentally it is difficult to calculate the concentration of
intermediate products of LTO before it is converted to coke. The intermediate products
are those oxygenated compounds, which are adsorbed by sand grains and react by
cracking reactions resulting in additional coke for combustion. The LTO and MTO
(coking) reactions are intimately related, the later rapidly coming on heals of the first,
thus one can not separately characterized them. Consequently two different paths for the
stoichiometry of HTO reaction may be considered in kinetic studies, Fig. 6.1 [Mamora &
Brigham. (102)
].
Path A
CHx CO2, CO, H2O
Path B Path C
CHx Oy
Figure 6.1 Paths of oil oxidation
In the absence of LTO reactions, it is assumed that little or no oxygenated compounds
are formed. Path A is therefore used for the calculation of oil oxidation.
Path A; represents the combustion of hydrocarbon fuel (CHx) which under goes
combustion according to stoichiometry:
127
OHx
mCOCOmOxm
CH x 2222
142
1
(6.5)
The mole percent of oxygen consumed may be calculated by equation (6.5)
6.3 m- RATIO
The m-ratio is defined as the ratio of carbon monoxide to that of carbon oxides present in
the effluent gas:
COCO
COm
2
(6.6)
6.4 H / C RATIO
For an oxygen balance, the apparent hydrogen – carbon ratio can be calculated:
COCO
COCOON
N
O
x
PP
i
i
2
222
2
2
24 (6.7)
Equation 6.7 assumes air injection and all oxygen not produced as free oxygen or carbon
oxides are used to oxidize hydrogen in the fuel.
Path B and C: as the temperature increases, the gases and light fractions are vaporized
leaving behind a residue of heavy oil fractions. Due to oxygen presence, the residue
undergoes low temperature oxidation and an oxygenated fuel is formed. On further
heating path C is followed and the oxygenated fuel is oxidized to form carbon oxides and
water. Due to the large surface area, fuel deposited on the grain surface is oxidized faster
than the fuel deposited at grain contacts. At some later combustion time, fuel is present
only at grain contacts. The stoichiometry for such oxygenated fuel could be written as:
128
OHx
mCOCOmOyxm
OCH yx 2222
1242
1
(6.8)
Where Y = Oxygen to carbon ratio (%)
6.5 CARBON BALANCE
Let CO and CO2 are the mole percent of produced carbon monoxide and carbon dioxide,
respectively and qo the effluent gas flow rate (ml/ min). One mole of the gas at standard
conditions occupies 22400 CC (24200 at 22 oC). Using the carbon balance, the number of
moles of fuel oxidized per minute may be expressed as qo (CO + CO2)/ 24200. The
molecular weight of the fuel CHx is equal to 12 + X. Therefore the mass of the fuel
consumed per minute at room temperature, dCf / dt, is:
24200
122 xCOCOq
dt
dCof
(6.9)
Equation 8.9 may be expressed in terms of oxygenated fuel consumed per minute dmf /
dt. as:
24200
16122 yxCOCOq
dt
dmof
(6.10)
6.6 KINETIC ANALYSIS BY DIRECT ARRHENIUS METHOD
Coke combustion in a porous bed may be described by a carbon-burning rate directly
proportional to the carbon concentration and oxygen partial pressure (25, 27, 68 and 86)
.
Mathematically this may be expressed as:
PfCkfdt
dCR f
f
c 21 (6.11)
129
Where Rc is the combustion rate; k is the reaction velocity; f 1 (C f ) is the dependence on
the fraction of carbonaceous material remaining unconverted and f 2 ( P) is dependent on
the concentration of oxidant.
Oxides of carbon produced during carbon combustion are CO and CO2. Therefore at any
instant, volume of carbon products produced Cp (t) will be,
tqotCOtCOtCP 2 (6.12)
qo ( t ) is gas flow rate at the exist of the reactor at the time t, ( cm3/ min.).
The total mass of carbon burnt after time t minutes = CB ( t ), CB ( t ) is gm C / 100 gm
sand , 24200 is the gm molecular volume of gases at the room temperature of 22 oC and
12 is the gram atom weight of carbon.
t
dttCpWs
tCB0
)(100
24200
12)( (6.13)
Equation 6.13 was integrated using Simpson’s rule, for the area under curve of CB ( t )
for the total reaction time . The sum of the CB ( t ) will yield the total carbon present in
the bed as a fuel at the start of the oxidation. This is the fuel present in the bed at the start
of oxidation, is the initial carbon concentration CI is expressed as:
endt
dttCpWs
CI0
)(100
24200
12 (6.14)
The quantity Cf ( t ) represents the carbon concentration of the reacting fuel at a particular
oxidation time.
Cf ( t ) = CI - CB ( t ) (6.15)
The amount of cumulative carbon steadily increases while the carbon concentration of the
reacting fuel correspondingly decreases with combustion time. Greaves et al. (68)
used the
instantaneous carbon concentration, which was obtained by subtracting the carbon,
burned from the initial carbon content of the sand pack in a dry and wet combustion tube
experiments on medium heavy oil.
Assuming that a power rate law provides adequate description of rate, from equation
6.11, the following equation may be obtained:
130
mn
f
fPoCk
dt
dCR 2 (6.16)
Where, n and m is order of reaction with respect to the unconverted fraction of
carbonaceous and oxygen partial pressure respectively.
In non-isothermal experiment, with a fixed heating rate
T = To + b t (6.17)
and
RT
EAK exp (6.18)
Where T is the absolute temperature, To is the initial temperature of the experiment, b is
the heating rate, t is the time, A is the Arrhenius constant, E is the activation energy and
R is the universal gas constant.
By substituting equation 6.17 and 6.18 in equation 6.16, the following equation may be
obtained:
n
f
mRT
E
rfCPo
b
A
dt
dC2
(6.19)
Taking natural logarithms, the equation becomes:
RT
EPo
b
Ar
C
dt
dC
m
n
f
f
2lnln (6.20)
The best-fit kinetic data on a straight line by assuming reaction orders m = 1 and linearize
n for best-fit line may be obtained. Shallcross et al. (103)
obtained the relative reaction rates
at higher temperature. They suggest that at temperature above 340 oC, the oxidation may
be expressed by a single reaction. In present study a single peak was obtained in a
temperature range 320 + 20 oC.
131
This suggest a single reaction for high temperature oxidation, a plot of n
ff CdtdC /ln
versus 1/ T , gives the activation energy, E as slope of this plot and an intercept of
m
r PobA 2/ln . By plotting intercepts mPobAr 2/ versus the oxygen partial pressure,
the true values of m can be obtained.
6.7 ANALYSES AND DISCUSSION OF RESULTS
The appearance of LTO reactions in porous medium alters the properties of fuel than to
the fuel formed in non-oxidizing atmosphere with no LTO. The fuel formed from oil field
of Badin crude of 37.5 oAPI gravity with no LTO was rich in Hydrogen and higher H/C
ratios were obtained with decrease in fuel deposition [22 % fuel decrease (88)
]. Also
distillation of crude oil at temperatures below 280 o
C changes the nature of fuel (89)
. The
hydrogen content of a fuel is unaltered up to 300 o
C and reduces as a temperature
increases, and around 2 was observed in dry combustion for the HTO zone alone (96).
On
comparing the results of unconsolidated rock formation, the appreciable LTO was
observed in most of the runs. As LTO characterizes the fuel from HTO, therefore the
nature of the fuel deposited in a formation with no LTO may differ substantially from the
fuel deposited in a formation with LTO reactions. For the determination of the nature of
the fuel being burned and also to determine the effect of distillation and pyrolysis on
these reactions, the apparent H/C ratio and m-ratio were evaluated.
6.8 APPARENT H/C RATIO
The H/C Ratio, which characterizes the oxidation and is indicative of the nature of the
fuel being burned, is a useful indicator for a process involving both simultaneously
hydrocarbon and a coke oxidation. The nature of the fuel changes as the hydrocarbons
and coke are oxidized simultaneously. In most of the runs LTO reactions were observed.
132
Therefore the calculations are based on the assumption that all the oxygen not observed
in the exit gas had reacted to form water and have been averaged to the temperature range
of interest (HTO zone).
The apparent atomic H/C ratios were calculated from gas composition data using
equation 6.7. The calculated H/C ratios for these runs are graphed in figure 6.2 –6.6. The
values of H/C at both very high and very low temperature should be discarded due to less
accurate measurement of the small concentration of gases produced. The most of the
runs, a general decrease in the apparent H/C ratio with an increase in temperature was
observed. The following observations were made:
The apparent H/C ratio increased to values ranging from about 15 to 40 at the
LTO peak temperature, indicating that a large amount of oxygen entered into the
LTO reactions, which did not produce carbon oxides.
Fairly constant apparent H/C ratios were observed following the first oxygen
consumption peak. The HTO reaction may be considered to be the oxidation of a
fuel consisting of a hydrocarbon with a particular H/C ratio.
The apparent hydrocarbon trends of these runs support the conclusion that there are two
main oxidation reaction mechanisms: oxygen addition to hydrocarbons with little carbon
oxide generation at low temperature followed by the high temperature oxidation of the
fuel. On the other hand H/C ratio trend indicates more gradual diminishing of stable polar
compounds in the oil when the temperature increases.
The H/C ratio is not constant, but varies as the combustion front progresses down the
combustion cell. This means that the chemical composition of the fuel must be changing.
The average H/C ratio values obtained at the different temperature steps. From
temperature 200 to 300 oC the production of Carbon oxides gases was too low to be
accurately measured. H/ C ratio decreased from about 10 at 300 oC to 2 at 350
oC. (This
characteristic value of 1.01 was measured in different runs at high temperature).
Table 6.1-6.3 presents the H/C ratio, and peak temperature and detailed results are
presented graphically.
133
Abu-Khamsin et al. (87)
found the distillation of crude plays an important role in shaping
the nature and extent of the cracking reactions. With extensive distillation they observed
less weight loss due to visbreaking, leaving a larger oil fraction transforming to coke.
They further elucidate that, the lighter the oil, the less is the visbreaking and greater the
coking. The heavier the oil, the more effective is the visbreaking, the higher the fuel
deposition and the lower the H/C ratio of the fuel burned.
When LTO occurs in unconsolidated formations a heavier residual oil is produced and
visbreaking is more effective leading to larger amount of coke and higher fuel deposition,
with a smaller H/C ratio of the fuel burned.
Dabous and Fulton (88)
observed similar H/C ratio in the presence and absence of LTO
reactions. A soft brown coke with a high H/C ratio was obtained in absence of LTO
reactions. In contrast a hard black coke with a low H/C ratio was obtained, in the
presence of LTO reactions. Ramey et al (67)
obtained oxidized residues at temperatures as
low as 149 oC.
6.9 m-RATIOS
The molar m-ratio was calculated by using equation 6.6 for the different type of
formation. The m-ratio indicates the transition between reactions at different temperature.
The trend of molar CO/ (CO+CO2) ratio under these conditions as a function of
combustion time is shown in figures 6.7-6.11. Both the level of CO and CO2 and the
molar ratio exhibit characteristics, which are attributable to change in fuel concentration
occurring at different combustion front locations.
From temperature 200 to 300 oC the, production of Carbon oxides gases was too low to
be accurately measured. From temperature 300 to 350 oC m- ratios decreased from about
0.6 to 0.15 and a fairly stable m-ratio of 0.15 was than measured from 350 oC to 370
oC.
Table 6.1- 6.3 presents the m-ratio, peak temperature and detailed of few results are
presented graphically.
134
Table 6.1: Estimated averaged H/C ratio, m- ratio, peak temperature
and C burnt for various runs
Run No
H/C
Ratio
m
Ratio
Peak Temp.
K
C
Burnt (%)
01 4.00
2.20
0.45
0.24
648
650
50.02
02 9.84
1.01
0.60
0.28
618
675
67.15
03 14.53
3.50
0.82
0.02
586
673
46.96
04 6.86
5.52
0.44
0.04
584
672
54.73
09 11.25
4.97
0.14
0.45
644
645
10 14.56
9.71
0.18
0.22
699
710
16.72
15 3.56
4.73
0.53
0.17
593
663
22.36
16 12.80
3.32
0.68
0.11
599
673
22.26
17 6.02
2.18
0.71
0.07
412
383
27.31
18 9.03 0.73 601 18.41
19
28.17
1.01
0.15
0.55
609
630
27.81
20 34.56
6.90
0.29
0.45
572
651
41.92
21
5.73
2.65
0.64
0.37
636
689
31.81
22 7.99
1.01
0.77
0.28
598
660
51.76
23 12.07
1.72
0.40
0.15
685
687
31.32
24 6.87
2.50
0.61
0.25
613
711
25 7.10
0.86
0.56
0.21
603
689
68.36
29 6.68
1.35
0.63
0.15
663
695
78.05
135
Table 6.2: Estimated averaged H/C ratio, m- ratio, Peak temperature
and C burnt for various runs
Run No
H/C
Ratio
m
Ratio
Peak Temp.
K
C
Burnt (%)
05 12.3
3.22
0.83
0.26
673
585
99.45
26 5.58
1.93
0.61
0.34
611
610
99
27 7.25
2.84
0.51
0.24
626
666
83.86
28 9.80
4.65
0.91
0.30
590
641
59.12
41 6.89
0.13
0.57
0.07
649
707
75.63
42 3.24
2.52
0.29
0.27
664
679
67.91
43 10.36
2.96
0.48
0.22
605
681
39.37
44 10.04
3.94
0.53
0.24
666
694
49.48
45 6.63
1.79
0.50
0.19
608
674
33.50
46 14.64
3.11
0.75
0.20
641
624
66.77
47 16.29
2.26
0.79
0.14
649
696
34.41
48 5.41
3.42
0.48
0.15
679
704
75.56
136
Table 6.3: Estimated averaged H/C ratio, m- ratio, Peak temperature
and C burnt for various runs
Run No
H/C
Ratio
m
Ratio
Peak Temp.
K
C
Burnt (%)
50 13.79
2.72
0.64
0.18
688
716
61.26
51 4.97
3.31
0.27
0.23
678
714
46.90
53 5.24
2.95
0.32
0.22
673
698
42.97
54 9.31
4.20
0.49
0.30
676
615
30.32
55 7.32
1.94
0.38
0.12
691
604
61.68
56 4.59
2.85
0.36
0.22
635
703
63.86
57 16.44
20.05
0.43
0.22
609
606
31.96
The m- ratio, fraction of the carbon converted to carbon monoxide decreased from 0.4 for
the LTO temperature range to about 0.2 for HTO. The m-ratio was fairly constant
through the temperature range of these experiments. From temperature 100-200 oC the
oxygen consumption was moderate and the production of carbon oxides gases was too
low to be accurately measured. Therefore the m-ratios were not reported over this
temperature interval. The m-ratio shows the dependence of the carbon oxides generation
process on the temperature.
137
0
10
20
30
40
50
50 70 90 110 130 150
TIME (MINUTES)
AP
PA
RE
NT
H/C
RA
TIO
R-1 R-10 R-15 R-20
Fig. 6.2: Apparent H/C ratio vs time for different type of rock formation
0
3
6
9
12
15
18
30 50 70 90 110 130 150 170
TIME (MINUTE)
H/C
RA
TIO
2069KPa 3448KPa 3585KPa 6895KPa
Fig. 6.3: Apparent H/C ratio V/s time for different system pressures
138
0
3
6
9
12
15
18
40 60 80 100 120 140
TIME (MINUTES)
H/C
RA
TIO
7.595 22.78 30.38
Fig. 6.4: Apparent H/C ratio vs time for different air fluxes
0
4
8
12
16
20
20 40 60 80 100 120 140 160
TIME (MINUTES)
H/C
RA
TIO
So=66% Sw=16 So=55% Sw=27% So=41% Sw=41%
Fig. 6.5: Apparent H/C ratio V/s time with different oil and water saturation
139
0
2
4
6
8
10
50 60 70 80 90 100 110 120 130
TIME (MINUTE)
H/C
RA
TIO
1H 2H 3H
F. 6.6: Apparent H/C ratio vs time with different heat input
0
0.4
0.8
1.2
1.6
2
60 70 80 90 100 110 120
TIME (MINUTES)
m -
RA
TIO
R-1 R-10 R-15 R-20
Fig. 6.7: m-ratio V/s time for different type of rock formation
140
Lewis et al. (89
reported that molar m-ratios for the combustion reaction for charcoal,
graphite, and coal in fluidized bed are around 0.25. The value of 0.25 is attributed to the
carbon oxidation or coke combustion; value different from this indicates that different
reactions are taking place. Fassihi et al (84)
has attributed values higher than that of 0.25 to
the fuel burned in the combustion reaction as a hydrocarbon reaction.
6.9.1 The effect of heat input on m-Ratio and H/C ratio
It appears that the value of m-ratio has two distinct regions, below 300 oC; m-ratio is
variable increasing from 0.55 to 0.333. At high temperatures, it is nearly constant at
around 0.333-0.2 depending on the pressure. The calculated m-ratios at very low and very
high temperatures were excluded because of the lower accuracy in measurement of small
concentration carbon oxides produced.
This fact that the m-ratio is almost constant at high temperatures indicates that carbon
oxides are being produced by the same reaction. By the same token, the reactions at low
temperatures must be numerous and non unique because of below 300 oC, m-ratio varies
with temperature. Lewis et al (89)
reported that the molar ratio for combustion reactions of
charcoal, graphite, and coal in fluidized bed is around 0.25.
This fact that this number is near the value of m-ratio obtained at high temperature,
indicates that the fuel burned in the combustion reaction is a heavy residue and is similar
to carbon in chemical characteristics.
The trend of both the H/C and the m-ratio in consolidated formation indicates that the
fuel burned in the HTO region may consist of a heavy residue plus coke in the
temperature range considered. The decrease of the H/C and m-ratio in unconsolidated
formations suggests that the fuel burned in the HTO region is more likely a coke.
Lewis et al (89)
reported the values of the m-ratio for different type of coke. They noted
that a value of 0.25 occurs for the most efficient combustion process and changes in the
m-ratio indicate a transition between reactions at different temperature.
141
0
0.4
0.8
1.2
1.6
2
30 50 70 90 110 130 150 170
TIME (MINUTES)
m-R
AT
IO
2069KPa 3448KPa 3585KPa 6895KPa
Fig. 6.8: m-ratio V/s time for different system pressure
0
0.2
0.4
0.6
0.8
1
40 50 60 70 80 90 100 110 120 130 140
TIME (MINUTES)
m-R
AT
IO
7.595 22.78 30.38
Fig. 6.9: m-ratio V/s time for different air fluxes
142
0
0.2
0.4
0.6
0.8
1
20 40 60 80 100 120 140 160
TIME (MINUTES)
m-R
AT
IO
So=66% Sw=16 So=55% Sw=27% So=41% Sw=41%
Fig. 6.10: m-ratio V/s time with diferent oil and water saturation
0
0.2
0.4
0.6
0.8
1
50 60 70 80 90 100 110 120 130
TIME (MINUTE)
m-R
AT
IO
1H 2H 3H
Fig. 6.11: m-ratio V/s time with different heat input
143
6.9.2 Effect of pressure on m-ratio and H/C ratio
Moore et al (90)
also found increased fuel requirement when the pressure was increased.
Abu-Khamsin et al (87)
found a marked increase in coke deposited with increase in
pressure and Showalter (65)
also observed increased fuel deposition with increased in
pressure. On further pressure, the amount of coke burned showed a decrease trend.
Another possibility may that due to the low injection gas flux (due to high pressure the
residence time of the gas is increased) the oxidation reaction may be mass transfer
controlled and hence flux dependent. Under such conditions, Moore et al (90)
has
suggested that the reduction in gas interstitial velocity at higher operating pressures
would be accompanied by a decrease in global oxygen uptake rate. Shahani et al (91)
observed a decrease in coke loading with increased pressure and oxygen enrichment for
heavy oil. Hansel et al (92)
observed a decreased coke loading on increasing the oxygen
concentration from 21 to 40% at 5200 KPa (754 Psig) pressure when using oil 31 o API.
Greaves et al (94, 93)
observed the fuel lay down was a function of oxygen mole fraction. A
summary of results presented in table 6.1-6.3 for carbon burnt as a percentage of the total
carbon present in the bed also confirms the effect of pressure on oxidation rate. As
presented in Figs. 6.3 by increasing the system pressure the H/C ratio decreases. A slight
decrease in H/C ratio was observed with increased pressure by Abu-Khamsin et al (87).
As
swelling of oil in CO2 may have resulted in viscosity reduction of the residual oil, more
light oils is present for coking, resulting in higher H/C ratio of fuel burned. Dug dale et al
(17) calculated the minimum miscibility pressure for the swelling of oil in CO2 and noted
that it was inversely related to the total amount of C5 through C30 hydrocarbons present in
the crude. The distribution of these hydrocarbons on the minimum miscibility pressure
was also investigated. A conclusion was aromatics lower the minimum miscibility
pressure. Moss et al (95)
observed a higher H/C ratio with oxygen injection than with air.
Burger et al (96)
reported a decrease in fuel deposition as the H/C ratio of the fuel
increases.
144
A decrease in m-ratio was observed from a maximum of 0.5 to a minimum of 0.15 for
that 21 % oxygen concentration on increasing the pressure as presented in figure 6.8.
However, apparent trend of this ratio with an increased system pressure was obtained.
6.9.3 Effect of air flux on m-ratio and H/C ratio
The increased rate of cumulative carbon burned will affect the oil production rate. One
might expect that with increased flux distillation should also decrease and less fuel be
deposited but in contrast to this increased flux appears to have decrease oil displacement
from bed and more cumulative carbon is burned. A possible explanation for this behavior
is that at low flux less distillation occurs and thus lighter residual oil is available for
cracking or coking. The light oil is more susceptible to visbreaking (87)
and therefore less
fuel lay down may have resulted. At high flux with more distillation, more effective
visbreaking may have resulted in more fuel for combustion. Table 6.1-6.3 presents a
summary of results for the cumulative percentage of carbon burned to that of total carbon
present in the bed.
Alexander et al (97)
observed the same behavior on increasing the air flux in the range of
1.52-to 6.10 m3/m
2-hr. fuel deposited was in the range of 1.25 to 1.6 gm/ 100gm of sand.
The low values of the fuel deposition were attributed to the low air flux used. Dabbous et
al (98)
observed that the carbon-burning rate increases with increased flux in the region of
high carbon concentration (0.5 gm/100gm sand). Peak temperature of the combustion
marginally increased flux by 18 oC. As shown in table 6.1-6.3, the low apparent H/C ratio
of the effluent gas would indicate that combustion is taking place on a coke like
substance. At low flux the high H/C ratio indicates that some heavy HCs are burning
simultaneously with the coke and the trend indicates a decline in H/C ratio with increased
flux indicating the burning of coke like substance.
With increase in air flux the m-ratio decrease, indicating more efficient combustion. The
increase in peak temperature also indicated better combustion. More detailed behavior of
H/C ratio and m-ratio for the temperature range of interest (300 - 350 oC) is presented in
145
figures 6.4 and 6.9. The results are in the agreement with those of Burger and Shaquet
(96) who studied the effect of H/C ratio of the fuel. They found that the carbon content of
the fuel was almost constant at all temperature, but the hydrogen content was only
constant up to around 300 oC, after which it decreased as the temperature was increased.
Bagci et al (118)
also observed the same effect on H/C ratio that which increases in
temperature H/C decreases, in all the three oils studied in a dry and wet combustion
experiments.
At the location of peak temperature the m-ratio approaches 0.25 for all fluxes. The same
observation made by Bousaid et al (99)
and Fassihi et al (100).
Alexander et al (97)
has
correlated the fuel availability with the apparent H/C ratio and concluded that fuel
availability decreases as H/C ratio increases. The present values of fuel deposited with
H/C ratio are in good agreement with this conclusion and follows same trend. Dabbous et
al (98)
has observed slight increase in CO2/CO ratio with increase in air flux on 19.9 o API
crude oil (decrease in m-ratio). Fassihi and Brigham (84)
concluded that in the high
temperature zone the molar ratio of the CO2/ CO is variable between 2 and 3, which is
equivalent to 0.333 to 0.25 in terms of the ratio CO/ (CO + CO2).
It was found that unlike heavy oils, light oils displayed three oxidation reaction classes:
LTO, MTO, and HTO. A different fuel is specific for each reaction class: for LTO, it is
the oil itself; for MTO it is the light hydrocarbons produced by cracking, and for HTO it
is heavy oil deposited by cracking. The corresponding peak temperatures for these three
classes are less than 200 C, 250 to 300 and greater than 300 oC respectively.
Kissler and Shallcross (26, 47, and 48)
as compared to LTO in heavy oils, LTO in light oils
produced more CO2. It was also shown (49)
that the LTO leads to an increase in viscosity.
For instance, the viscosity increases 1.4 times after 11 hrs of oxidation at 52 oC and 1.2
times. Using the same experimental techniques, Burger et al. (35)
and Fassihi (127)
also
found apparent H/C ratio between 0 and 1.0 for crude oil in the HTO range. Fassihi et al
(127) obtained the following apparent H/C ratio at the HTO peak: 0.3 (Huntington Beach
oil), 0.2 (Venzula Jobo crude oil) and 0.1 (Sand Ardo crude oil). Fassihi et al (127)
146
obtained the H/C ratio of distillation cuts of Huntington Beach oil based on elemental
analysis. The atomic H/C ratio decreased from 1.95 for a distillation cut at 150 oC (556
KPa) to 1.5 for a distillation cut at 550 oC compared to 1.64 for the original oil. Fassihi et
al (127)
results indicate that the fuel burned during combustion would have atomic H/C
ratios slightly lower than those of the original crude as typically observed in combustion
tube experiments.
6.9.4 Comparison between theoretical and experimental results
Comparison of theoretical with experimental results is presented in table 6.4. However,
results are not similar due change of different parameters.
Cedric et al (76, 80)
conducted various experiments on Isothermal Disk Reactor and
Isothermal Oxidation Reactor using 33.6 o
API at Pressure 17.1 MPa concluded that the
ratios = (CO/ CO2) 0.35 to 0.25 were obtained in temperature range investigated (134 to
400) 0C which is equivalent to 0.26 –0.20 in terms of m-ratio = CO/ (CO+CO2). By using
Isothermal Disk Reactor experiments B- ratios 0.5 to 0.15 were obtained in the
temperature range investigated (130-210 oC), which is equivalent to 0.33-0.13 in terms of
m-ratio. These values are marginally higher than for isothermal conditions. Apparent H/C
ratios measured in the considered temperature range from 7 to 0.8. The minimum H/C
value of 0.8 obtained at 400 o
C was consistent with the trend established during the
Isothermal Disk Reactor experiments. Moore et al. (72)
stated that the apparent H/C ratio
or the fraction of reacted oxygen converted to carbon oxides, both of which essentially
controlled by the CO2 / Nitrogen ratio provides a direct indication of the mean
temperature within the reaction zone. The projects involving air injection only should
have apparent H/C ratios of less than 3.0 and the reacted oxygen converted to carbon
oxides of greater than 50 percent, if the oxidation kinetics is operating in the proper
mode. Germain and Geyelin (27)
used medium light oil (32.2 oAPI) and calculated H/C
ratio1.65 at 290 oC and CO2 /CO = 9.1 which is equivalent to 0.09 in terms of m-ratio.
147
Greaves et al (75)
used heavy oil (19.8 o
API) and calculated H/C ratio 1.76 at a peak
temperature of 375 oC. Fassihi et al
(2) conducted various experiments by using two
different gravity of light oils (39 and 31) o API at pressure 28407 and 24822 KPa and
calculated the H/C ratio 1.73 and 1.24 at temperature 478 oC and 423
oC respectively.
lara et al (74)
used three types of oil having gravity 32.2, 39, and 30 oAPI. β-ratio is 0.15,
which is equivalent to 0.13 in terms of m-ratio temperature 400 o
C. Turta et al (55, 81)
used
two types of light oil having gravity (44 and 48) oAPI. H/C ratios were calculated 2.25
and 3.1 with a temperature range of 400 to 450 o
C. Glandt et al (77)
used four different
types of light oil having gravity 31.6, 31.7, 33.0 and 34.5 oAPI and calculated H/C ratio
1.73. Watt et al (28)
calculated the H/C ratio decreased from 1.93 at 300 oC (2030 psig) to
1.69 at 330 oC. The (CO2+CO)/ CO = 0.928 to 11.46 with variety of temperature range
400 oC to 175
oC which is equivalent to 0.11 to 0.087 in terms of m-ratio. Kumar et al
(1)
calculated 1.24 apparent H/C ratio at the peak temperature of 430 oC (2069 KPa) with air
flux 8 Sm3/m
2-hr. Pascual et al
(117) used 31
o API and calculated H/C ratio 1.74 at 19610
KPa with air flux 100 Sm3/m
2-hr.
6.10 OXYGEN BALANCE
The absence of LTO reaction in unconsolidated rock formation resulted only one peak.
Apparently this peak appeared in a temperature range considered for MTO and HTO
regions (300-400 oC). Material balance on oxygen indicates the higher consumption of
oxygen to that of oxygen consumption by carbon oxides plus the water formed.
By using equations 6.3 and 6.4 the oxygen consumed in excess of the actual oxygen
consumption was estimated. This excess oxygen consumption was estimated by
subtracting the oxygen consumed by the production of carbon oxide’s O 2 (carbon oxides) plus
that due to the water produced (eq.6.4) from the oxygen consumed by the process O 2c
(eq.6.3). The excess oxygen values are plotted against time together with the CO2 +
0.5CO production curves. Figure 6.12-6.13 present the oxygen distribution for R-41 and
148
R-50. The excess oxygen consumed when LTO reactions are present, peaks at around
300 oC, where as in most of the runs, when no LTO reaction occurs, the excess O2
consumed peaks at temperature above 350 oC. In R-41 the excess oxygen consumed is in
the mid temperature region where the cracking of the residual oil may have taken place.
The excess oxygen consumed is therefore believed to have reacted with the products of
the cracking reactions, and may have produced hydrocarbons products are absorbed by
the oil or sand matrix just in front of the combustion. Later these hydrocarbon products
may have combusted concurrently with heavy residue (coke) in HTO and thus produced
water, generating the negative peak n (Fig. 6.12- 6.13).
Abu-Khamsin et al. (87)
have observed substantial distillation of light ends of the crude at
low temperature and with rise in temperature resulted more distillation, triggering mild
pyrolysis of the oil. Finally the pyrolysis (cracking) of the trapped Hydrocarbons causes
fuel deposition just in front of the combustion.
Mamora et al. (104)
verified that the oxygen of oxygenated hydrocarbons took part in the
reactions of HTO. The experiment was conducted in a kinetic tube, where the oxygen
was injected until the end of LTO (310 oC). There after the N2 was injected. The result
was, during HTO even no oxygen was injected; CO2 and CO was present in the effluent
gas. Moore et al. (07)
stated the same phenomena in one of his paper on the strategies for
in-situ combustion. The excess oxygen consumed by the oxygenated components in
unconsolidated formation with an LTO peak around 300 oC has less attribution in HTO,
than to the consolidated formation. This suggests that the oxygenated hydrocarbons
produced in unconsolidated formation are more effectively cracked than to the
hydrocarbons produced in consolidated. In consolidated formation these trapped HC are
combusted concurrently with the coke in HTO, this also results in increase H/C ratio of
the fuel.
149
Table 6.4: Kinetic experimental results
Author/ Year Oil gravity
API
Temperature
(0C)
Atomic
H/C ratio
m-Ratio Oil
Recovery
%
Alexander et al,
1962
29.5
35.6
36.0
55
1.76
1.87
1.79
Wilson et al.,
1968
24.0
28.0
30.0
38 1.65
1.87
1.87
Bousaid and
Ramey, 1968
22.1 77 1.65
Greaves et al,
1989
22.8 85 1.54
V.K.Kumar et al,
1995
39.0 423 1.24
M.Greaves et al.
1996
23.0
31.0
19.8
1.76
59 –89
Germain &
Geyelin, 1997
32.2 290 1.65
0.09 -
M.R.Fassihi et al,
1997
39.0
30.0
110
100
1.73-1.24
2.0
T.H.Gilham et al.,
1997
36.0
37.0
39.0
426
88.0
B.C.Watts et al.,
1997
32.0
32.2
320-330 1.93-1.69
0.11-0.087 89.3-91.8
C.Clara et al.
1998
32.2
39.0
30.0
300-400 0.13 81.5
A.T.Turta at al.,
1998
48.0
44.0
400-450 2.25 –3.1
150
Table 6.4 (continued)
Author/ Year Oil gravity
API
Temperat
ure
(C)
Atomic
H/C ratio
m-Ratio Oil
recovery
%
M.Greaves et al.
1998
39.0 64-71
Cedric Clara et al.
1999
33.6
271
92-210
130
160-210
0.065
40-2.0
-
-
0.061
-
0.333
0.13
57.6
C.A. Glandt et al.,
1999
33.0
31.7
31.6
34.5
1.73
Cedric Clara et al.,
2000
33.5 134 -400 7 -0.8 0.26-0.20 57.6
M.Greaves et al.
2000
36.0
39.0
64-71
A.T.Turta at al.,
2001
48.0
44.0
400-450 2.25 –3.1
S.R.Ren et al.,
2002
36.0
37.0
39.0
110-130 57 -73.2
R.G. Moore et al.,
2002
Light oil 150-300 Less 3
Dembla Dhiraj,
2004
40.7 370 2.17 80
M.Pascual et al.,
2005
31 1.74
This Study
37.5
39.5
41.0
100-450
0.13-3.0
0.11-0.5
60-87
151
6.10.1 Oxygen utilization
Oxygen utilization is a measure of the efficiency of the combustion process. The Table
5.3, 5.6, 5.9. 5.12, 5.15 and 5.18 shows that approximately 75 -100 percent O2 utilization
was observed during the stabilized periods for the dry and wet runs at all operating
pressures and gas fluxes investigated. The value obtained for the majority of wet
combustion run is however, above 1.0 percent lower. A similar trend was reported by
Moss (95)
who obtained 97 percent oxygen utilization in wet combustion compared with
99 percent in dry forward combustion. With wet combustion, the steam, which is
produced, tends to restrict the diffusion path for the oxygen to the fuel surface. This will
inevitably lead to increased oxygen channeling.
152
-16
-8
0
8
16
24
0 25 50 75 100 125 150 175 200
TIME ( MINUTES)
CO
NC
EN
TR
AT
ION
(M
OL
E%
)
0
100
200
300
400
500
TE
MP
ER
AT
UR
E (
C )
O2 CONS. CO2+0.5CO O2 Cons. In Excess Temp: ( C )
FIG.6.12 Oxygen consumed in excess versus time for Run 41
Peak n
-14
-7
0
7
14
21
0 30 60 90 120 150 180 210
TIME (MINUTES)
CO
NC
EN
TR
AT
ION
(MO
LE
%)
0
100
200
300
400
500
TE
MP
ER
AT
UR
E (
C )
O2 CONS. CO2+0.5CO O2 CONS. IN EXCESS Temp: ( C )
RUN-50
FIG. 6.13 Oxygen consumed in excess versus time for Run 50
CHAPTER 7
ANALYSIS OF IN-SITU COMBUSTION REACTION KINETICS
7.1 ANALYSIS OF IN-SITU COMBUSTION REACTION KINETICS
The kinetic data obtained from (27) dry and (12) wet combustion runs are analyzed to
obtain over all rate expressions describing the rate of carbon combustion. The occurrence
of LTO reaction is significant due to mainly high O2 utilization (100 percent) at the
combustion zone.
The cracking reaction (fuel deposition) however, although very competitive with fuel
combustion reaction, has a greater influence on the over all process behavior and it is
therefore, as the LTO reaction has considered. The major influence of the combustion
reaction kinetics on the process behavior is through its effect on the combustion front
velocity and consumption of oxygen. In addition to this, the amount of fuel consumed
will also significantly effect on the ultimate recovery of oil.
In this investigation, the porous medium properties were essentially the same for most of
the runs except preliminary experiments of about 20 runs. The pressure was varied from
690 to 11032 KPa. The oxygen concentration was maintained constant for all runs. The
main objective of this study is to determine ultimate oil recovery of light oil from
depleted reservoirs and 100 percent utilization of oxygen under dry and wet combustion
conditions.
7.2 INTERPRETATION OF KINETIC DATA
Applying the Direct Arrhenius and using the relative reaction rate of carbon burned,
eq.5.20 was used for the calculation of the activation energy and pre exponential constant
by assuming the first order reaction with respect to the no oxidized carbon concentration
in the bed, Figure 7.1. A straight line was drawn through the high temperature data. From
153
154
the slope of that line activation energy, E = 35 KJ/ mole, is obtained. It was assumed that
this reaction also occurs at lower temperatures according to the extrapolation of the high
temperature data. From Figure 7.1, a calculation of the relative reaction rate as a function
of temperature (1/T). The results obtained by using this method are presented in Table
7.1. Figure 7.2 to 7.16 shows definite straight lines for HTO, MTO and LTO for various
runs. The data is not linear. However, a computation of an equivalent term for the carbon
oxides formed. The more consistent direct Arrhenius plot was used to compare the results
from the different types of formation, at 2069 KPa pressure. The activation energy was
found to be 72-154 KJ/ moles, with respect to carbon concentration (Figure 7.2). The
differences in activation energy may be attributed to LTO reactions, which are taking
place in the unconsolidated formation. Figure 7.3 shows definite straight lines.
Activation energy of E varies from run to run i.e. 37 to 88 KJ/mole were calculated from
the slope of this lines. In these figures, although data scatters considerably, it appears
reasonable to assume the oxygen consumption curve in the medium temperature range
follows the same slope as the CO2 curve. When the data from effluent gas data were
evaluated using the relative reaction rate and the results are presented in Figure 7.4, a
straight lines are formed which describes the low temperature oxidation reaction. The E
calculated from the slope of the lines is 24-109 KJ/mole. Using the computer
interactivity, this same analysis was applied to all other experiments. The results always
fit straight lines. However, for different crude oils / sand pack/ pressure/ temperature/ air
flux, the order of reaction with respect to fuel concentration, n, was different.
This is the basis of an analysis of the data for these separate reactions as described in
following paragraphs. The scatter in activation energies with respect to the Fassihi model
is due to the decoupling of oxygen consumption curve for HTO from the start end and
also the number of data points is insufficient. A general observation is that formations
that give LTO reactions have lower activation energies for HTO of around 20 KJ/mole.
Formations that do not show LTO reaction give higher values of the activation energy of
around 100 KJ/mole.
155
Table 7.1 Summary of kinetic data
RUN
NO
FUEL COMBUSTION FUEL DEPOSITION LTO REACTION
E
KJ/g-mole
n E
KJ/g-mole
n E
KJ/g-mole
N
01 101 1 76 1 109 1
02 84 1 102 2 43 1
04 84 1 88 1 131 1
07 220 1 157 1 110 1
10 99 1 37 1 24 1
15 72 1 45 1 259 1
16 32 1 50 1 13 1
18 220 3 31 3 47 3
19 200 3 264 3 40 1
20 154 1 88 1 87 1
21 204 1 60 1 23 1
22 153 1 112 1 91 1
23 110 1 26 1 18 1
24 57 1 213 1 50 1
25 55 1 43 1 9.5 0.5
29 231 1 97 1 63 1
30 63 1 - - 15 0.5
09 58 1 41 1 18 1
17 34 1 20 1 34 1
05 35 1 35 1 35 1
26 36 0.5 30.5 0.5 16 2
27 60 1 43.5 1.5 37 1.5
28 57 1 17 1 30 1
41 60 1 51 1 54 1
42 17 1.2 22 1.4 55 1
43 22 1 12 1 4 1
44 49 1.5 80 1 16 1.5
45 95 0.5 94 0.5 55 2
46 35 1 27 1 36 2
47 17 1 27 1 6 0.5
48 61 0.5 49 1 20 0.5
50 21 0.5 25 0.5 11 0.5
51 36 0.5 38 0.5 4 0.5
53 55 1 46 1 42 1.5
54 10 0.5 8 1 27 1
55 13 1 18 1 36.78 1
56 130 1 190 1 22 1
57 15 1 15 1 8 0.5
156
DIRECT ARRHENIUS PLOT
-5
-4
-3
-2
-1
0
1.7 1.8 1.9 2
1/Tx 1000
LN
[(D
C/D
T)/
(C
) n
] RUN -05
E1 = 35
n = 1.0
UNCONSOLIDATED
FORMATION
Fig. 7.1: Direct Arrhenius plot with respect to carbon concentration for Run-05
-6
-5
-4
-3
-2
-1
0 1.4 1.45 1.5 1.55 1.6 1.65 1.7
1/Tx1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
R-1 R-10 R-15 R-20
Linear (R-1) Linear (R-10) Linear (R-15) Linear (R-20)
Fig. 7.2: Arrhenius plot for fuel combustion reaction with different type of
Formation.
R.NO. n E 01 1.0 101 10 1.0 99 15 1.0 72 20 1.0 154
P = 2069 KPa
157
-6
-5
-4
-3
-2
-1
0 1.5 1.55 1.6 1.65 1.7 1.75 1.8 1.85 1.9 1.95 2
I/Tx1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
-6
-5
-4
-3
-2
-1
0
R-10 R-20 R-1 R-15
Linear (R-15) Linear (R-1) Linear (R-10) Linear (R-20)
FIG. 7.3: Arrhenius plot for fuel deposition reaction with different type of formation
R.NO n E 01 2.0 76 10 1.0 37 15 1.0 45 20 1.0 88
The activation energies with respect to carbon concentration show
-8
-6
-4
-2
0
2 2.4 2.8 3.2 3.6
1/Tx1000(1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN.)
R-1 R-10 R-20 R-15
Linear (R-1) Linear (R-10) Linear (R-20) Linear (R-15)
LTO
FIG.7.4 ARRHENIUS PLOT FOR LTO REACTION WITH DIFFERENT ROCK FORMATIONFig. 7.4: Arrhenius plot for LTO reaction with different rock formation.
158
-5
-4
-3
-2
-1
0
1.35 1.4 1.45 1.5 1.55 1.6
1/T*1000 ( 1/K)
Ln [
(dC
/dT
)/ C
n]
7.595 22.78 30.38 Linear (7.595) Linear (22.78) Linear (30.38)
FIG. 7.5 ARRHENIUS PLOT FOR FUEL COMBUSTION REACTION AT DIFFERRENT AIR FLUXES.
R.NO A.F n E
50 7.595 0.5 21
51 22.78 0.5 36
53 30.38 1.0 55
-8
-6
-4
-2
0
1.3 1.4 1.5 1.6 1.7 1.8 1.9
1/T x1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
-5
-4
-3
-2
-1
0
7.595 22.78 30.38 Linear (30.38) Linear (7.595) Linear (22.78)
FIG. 7. 6 ARRHENIUS PLOT FOR FUEL DEPOSITION AT DIFFERENT AIR FLUXES
R.NO A.F n E
50 7.595 0.5 25
51 22.78 0.5 38
53 30.38 1.0 46
Fig. 7.5: Arrhenius plot for fuel combustion reaction at different air fluxes.
Fig. 7.6: Arrhenius plot for fuel deposition for different air fluxes
159
-10
-8
-6
-4
-2
0
1.7 1.8 1.9 2 2.1 2.2 2.3 2.4 2.5
1/T *1000 ( 1/K)
Ln [
(dC
/dT
)/C
n]
-6
-5
-4
-3
-2
-1
0
22.78 30.38 7.595 Linear (22.78) Linear (30.38) Linear (7.595)
R.NO A.F n E
50 7.595 0.5 11
51 22.78 0.5 4.0
53 30.38 1.0 42
FIG. 7.7 ARRHENIUS PLOT FOR LTO REACTION WITH DIFFERENT AIR FLUXES AT PRESSURE
11032 KPa
-6
-5
-4
-3
-2
-1
0
1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2
1/Tx1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
-5
-4
-3
-2
3448 KPa 3585 KPa 6895KPa 2069 KPa
Linear (3448 KPa) Linear (3585 KPa) Linear (6895KPa) Linear (2069 KPa)
R.NO P n E
26 2069 0.5 36
27 3446 1.0 60
05 3585 1.0 35
FIG. 7.8 ARRHENIUS PLOT FOR FUEL COMBUSTION REACTION WITH DIFFERENT SYSTEM
PRESSURE
Fig. 7.7: Arrhenius plot for LTO reaction with different air fluxes at pressure 11032 KPa
Fig. 7.8: Arrhenius plot for fuel combustion reaction with different system pressure
160
The activation energies with respect to carbon concentration show fewer scatters. In
many formations the values are close, but the values in some formations vary
significantly. The reason for this is not clear. Lewis el al (89)
using a fluidized bed found
the activation energy of metallurgical coke was 121.4 KJ/mole and obtained first order
reaction rates for both carbon and oxygen concentration. Bousaid and Ramey (99)
used a
precooked crude of 13.9 oAPI in a packed bed using Berea sand and reported an
activation energy of 61.9 KJ/mole and a decreased activation energy of 48.4 KJ/mole by
adding 20 % clay to the sand. Dabous el al (98)
treated 19.9 oAPI precooked Berea sand of
60 mesh size and found an activation energy of 58.9 KJ/mole also obtained first and
second order reaction kinetics with respect to oxygen partial pressure and carbon
concentration respectively. Burger and Sahuquet (96)
reported values of the activation
energy ranging from 50.7 to 73.7 KJ/mole covering the range from 30 to 600 oC. Fassihi
Brigham (84)
used four different types of crudes; for 11.2 oAPI in sand pack activation
energy of 120 was obtained and by adding 5 % clay to the sand, this decreased to 61.0
KJ/mole. Philips et al. (105)
obtained an over all value of the activation energy of 80.0
KJ/mole, in an integral plug flow reactor by considering the ATS (Athabasca Tar Sand)
as the only reactant on oxidation. They observed first order reaction with respect to
oxygen concentration. Thomas et al. (106)
used cocked sand from the crude of density
0.971 cc/gm and observed activation energy in an air atmosphere of 87.0 KJ/mole. They
also obtained first order reaction with respect to carbon and oxygen concentration.
Kamath (107)
used heavy oil in a sand pack and found activation energy of 84 KJ/mole in
an air atmosphere. He also observed the activation energy decreased with increased
oxygen partial pressure. Vossoughi et al. (108)
used 19.3 API, crude oil mixed with sand in
thermogravimetric analysis, they obtained activation energy of 123.5 KJ/mole and they
suggested first order reactions with respect to surface area, oxygen partial pressure and
carbon concentration. Lin et al. (109)
analyzed tar sand (Utah) in a thermogravimetric
analyzer at different heating rate of 5 oC/min. Dubdub
(110) found the values of activation
energy of 110.2 KJ/ moles for ATS in tubular reactor, in a non-isothermal experiment by
161
using air. Reaction orders of 0.7 to 1.0 were found with respect to oxygen partial pressure
and carbon concentration respectively. In addition he also observed a decrease in
activation energy with increase in partial pressure. He obtained activation energy of 85.8
to 92.04 KJ/mole by using Direct Arrhenius plot and observed the reaction orders of 1.12
and 1.28 with respect to carbon concentration and oxygen Partial pressure respectively.
7.3 KINETIC PARAMETERS
The kinetic data obtained from the experiments conducted on different air fluxes were
analyzed to obtain over all rate parameters describing the rate of carbon combustion. The
temperature ranges for the calculation were selected by the analyzing oxygen utilization
peak temperature that commenced mainly at 200 + 20 oC continued up to 400 + 50
oC. In
this temperature range three competitive reactions; LTO, fuel deposition and fuel
combustion takes place. The major influence of the combustion reaction Kinetics on the
process behavior is through its effect on the nature of the fuel deposited. The oxygen
partial pressure remains the same in all four fluxes. The direct Arrhenius method, which
considers the relative combustion of carbon (eq .5.20), was used to calculate numerical
values of the reaction order n, and the activation energy “E” from the kinetic data. As the
oxygen partial pressure is constant for all experiments at different fluxes and if a first
order reaction is assumed, the reaction order with respect to oxygen partial pressure is
assumed constant and equal to one. By selecting suitable value of n, and using multi
linear regression analysis of the values of the left hand side of the equation 5.20 and
plotting against 1/ T, a straight line is obtained. The intercept of the line is equal to ln (Ar
/ b) PO2m
. Table 7.1 presents the evaluated values of activation energy with respect to
carbon burned rate, and the values of the reaction order n. The activation energies
reported in this study are in the agreement with the values reported in the literature for
burning various types of carbon, which ranges from 48.8 to 135 KJ/ mole.
162
7.3.1 Activation energy
Four representative combustion peak temperatures are chosen to calculate the reaction
rate constants from equations, which are written in the form. The values are given in
Table 7.1. A regression analysis was used to fit the computed values with relative
reaction rate versus reciprocal absolute temperature, according to the Arrhenius relation.
The activation energy “E” was calculated from the regression equation and the Arrhenius
plots are shown in Figure 7.2 to7.16
7.3.2 Activation energy effect
This important parameter controls the reaction rate and the associate thermal effects. The
lower the energy of activation, the higher the oxidation and heat production rates and
shorter the “reaction indication time” required for the reaction to speed up thanks to
increase of temperature. A fairly small E2 increases by less than 10 % above the second
value, leads to a large increase of this “indication time” because of the exponential form
of the kinetic function.
7.4 THE EFFECT OF SYSTEM PRESSURE
In this section the effect of differing pressures and oxygen concentration upon the
oxidation reaction kinetics is examined by comparing the effluent gas data and Arrhenius
graph from runs conducted on unconsolidated formation at different pressures. The H/C
and m-ratio is also discussed. The effect of pressure can be divided into two separate
categories. Firstly, total pressure effect by installed two electric heaters, secondly three
electric heaters. Experiments were conducted at four different pressures the selected
oxygen concentration in this study was 21 % (air). A summary of experimental
conditions employed for each pressure is given in Table 5.7. The effect of total pressure
with oxygen concentration is analyzed.
163
7.4.1 Total system pressure effect
Arrhenius plot was obtained by assuming fist order reaction rate with respect to carbon
concentration, which also confirmed that increased pressure (3446 KPa) has high
activation energy of 60 KJ/mole than to the experiments conducted at lower pressure
(2069 KPa), 36 KJ/mole for high temperature reaction zones. The possible argument for
the high rate of products at low temperature could be that the light components are
reacting with free oxygen available. To large quantity, producing higher amount of
Carbon oxide, where as in high pressure of 6895 KPa the light components are
suppressed. The low level of products in 6895 KPa experiment may be due to dilution
effect, which is taking place by large number of moles present in the reactor on increased
pressure. One can conclude that the distribution of the products are inadequate and does
not behave like ideal. This non-ideal behavior of the reactor could be attributed to the
mixing of the reactor. This is in depth investigation of the effect of pressure on this
process was conducted using 37.5 oAPI. .
7.5 KINETIC PARAMETERS
As mentioned earlier Arrhenius method for the analysis of kinetic data were used, for
considering the relative reaction rate of carbon burned in terms of carbon oxides
produced fluent gas.
As the reactant is the crude oil, or its residue, whatever the composition, the resultant
kinetic parameters are only accounted for over a limited temperature range.
Figure 7.8 shows the effect of system pressure for air 21 % O2. The plots did not behave
as expected. The high pressure line should lie above the low pressure line, where as no
such trend was observed. This phenomenon is not completely under stood. But up to the
pressure of 3585 KPa low pressure line lies above the high pressure line. Similar curves
were drawn for 21 % O2 concentrations inlet gas and the same mixed plots were obtained
164
-6
-5
-4
-3
-2
-1
0
1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 2.1
1/T x 1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN.)
-7
-6
-5
-4
-3
-2
3448 KPa 6895 KPa 2069 KPa
3585 KPa Linear (3448 KPa) Linear (6895 KPa)
Linear (2069 KPa) Linear (2069 KPa) Linear (3585 KPa)
FIG. 7.9 ARRHENIUS PLOT FOR FUEL DEPOSITION REACTION AT DIFFERENT SYSTEM PRESSURE
R.NO. P n E
26 2069 0.5 30.5
27 3448 1.5 43.5
05 3585 1.0 34.0
-8
-7
-6
-5
-4
-3
-2
-1
0
1.2 1.7 2.2 2.7 3.2 3.7 4.2 4.7 5.2
1/T x1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
-5
-4
-3
-2
-1
0
2069 KPa 3585 KPa 3448 KPa 6895KPa
Linear (3448 KPa) Linear (6895KPa) Linear (2069 KPa) Linear (3585 KPa)
FIG.7.10 ARRHENIUS PLOT FOR LTO REACTION WITH DIFFERENT SYSTEM PRESSURES
R.NO P n E
26 2069 2.0 16
27 3448 1.5 37
05 3585 1.0 33
47 6895 0.5 6.0
Fig. 7.9: Arrhenius plot for fuel deposition reaction at different system pressure
Fig. 7.10: Arrhenius plot for LTO reaction with different system pressures
165
-5
-4
-3
-2
-1
0
1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2
1/Tx1000 (1/K)R
ELA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
So=66% & Sw= 16% So = 55% & Sw = 27%
So=41% & Sw =41% Linear (So=66% & Sw= 16%)
Linear (So = 55% & Sw = 27%) Linear (So=41% & Sw =41%)
R.NO n E
41 1.0 60
42 1.2 17
46 1.0 35
FIG. 7.11 ARRHENIUS PLOT FOR FUEL COMBUSTION REACTION WITH DIFFERENT OIL AND
WATER SATURATION
-5
-4
-3
-2
-1
0
1.3 1.35 1.4 1.45 1.5 1.55 1.6 1.65 1.7 1.75 1.8
1/T x 1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/K
)
So = 66% & Sw =16% So=55% & Sw=27%
So=41% & Sw =41% Linear (So = 66% & Sw =16%)
Linear (So=55% & Sw=27%) Linear (So=41% & Sw =41%)
FIG. 7.12 ARRHENIUS PLOT FOR FUEL DEPOSITION REACTION WITH VARIOUS OIL AND GAS
SATRATION
R.NO. n E
41 1.0 51
42 1.4 22
46 1.0 27
Fig. 7.11: Arrhenius plot for fuel combustion reaction with different oil and water saturation
Fig. 7.12: Arrhenius plot for fuel deposition reaction with various oil and gas saturation
166
-8
-6
-4
-2
0
1.3 1.35 1.4 1.45 1.5 1.55 1.6 1.65 1.7
1/T x1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1
/MIN
.)
-8
-6
-4
-2
0
1H 3H 2H Linear (2H) Linear (1H) Linear (3H)
FIG. 7.14 ARRHENIUS PLOT FOR FUEL COMBUSTION WITH DIFFERENT HEAT
INPUT
R.No n E
22 1.0 153
49 1.2 17
55 1.0 13
-8
-7
-6
-5
-4
-3
-2
-1
0
1.5 1.7 1.9 2.1 2.3 2.5 2.7 2.9 3.1
1/Tx1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1/M
IN)
-8
-7
-6
-5
-4
-3
-2
-1
0
So=66% & Sw=16 % So=41% & Sw=41%
So=55% & Sw=27& Linear (So=55% & Sw=27&)
Linear (So=66% & Sw=16 %) Linear (So=41% & Sw=41%)
FIG.7.13 ARRHENIUS PLOT FOR LTO REACTION WITH DIFFERENT OIL AND WATER SATURATION
R.NO n E
41 1.0 54
42 1.0 55
46 2.0 36
Fig. 7.13: Arrhenius plot for LTO reaction with different oil and water Saturation.
46 2 36
167
for fuel deposition and LTO reactions as presented in Figure 7.9 to 7.10 respectively. The
kinetic parameters were calculated for each run. Table 7.1 present the kinetic data
evaluating by using Arrhenius method by considering the reaction order with respect to
fuel, n, is equal to one in most of the runs. Comparison in Table 7.1 of the kinetic
parameters for the various runs at different pressure, shows that the calculated activation
energies are similar, but not in complete agreement. Again, the discrepancy appears to be
an artifact of the data analysis procedure by which the temperature ranges were
decoupled. Irrespective, of small differences in activation energies these have been
plotted against the total pressure and for better observation, these values were linearized.
An Arrhenius plot was obtained by assuming first, 1.2, 1.4 and second order reaction
rates with respect to carbon concentration, for oil and water saturation were used for a
combustion reaction (Fig 7.11), the values of “E” varies from 17 to 60 KJ/mole. The
corresponding values for fuel deposition (Fig. 7.12) and LTO reaction (Fig. 7.13) were
about 22 to 51 and 36 to 55 respectively.
Similarly an Arrhenius plot was obtained by assuming first, 1.2, and 1.4 order reaction
rates with respect to carbon concentration, for different heat input were used for a
combustion reaction (Fig 7.14), the values of “E” varies from 13-153 KJ/mole. The
corresponding values for fuel deposition (Fig. 7.15) and LTO reaction (Fig. 7.16) were
about 118-112 and 37-91 respectively.
7.6 COMPARISON OF KINETIC PARAMETERS
The kinetic parameters obtained in this study are summarized in Table 7.1. The reaction
order n with respect to carbon concentration lie within the range of those reported by
other workers in Table 7.2, and the activation energies are also of the same order. The
difference in results in the numerical values of the kinetic parameters obtained in this
study compared with those reported in Table 7.1 are attributed to the different sand pack
properties and the operating parameters used. The presence of clay in the sand is known
to have catalytic effect, reducing the activation energy in addition to causing a fractional
168
-10
-8
-6
-4
-2
1.3 1.4 1.5 1.6 1.7 1.8 1.9
1/T X1000 (1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1
/MIN
)
-8
-6
-4
-2
0
3H 1H 2H Linear (3H) Linear (1H) Linear (2H)
FIG. 7.15 ARRHENIUS PLOT FOR FUEL DEPOSITION WITH DIFFERENT HEAT INPUT
R.No n E
22 1.0 112
49 1.2 22
55 1.0 18
-8
-6
-4
-2
0
1.5 1.7 1.9 2.1 2.3 2.5 2.7 2.9
1/TX1000(1/K)
RE
LA
TIV
E R
EA
CT
ION
RA
TE
(1
/MIN
)
1H 2H 3H Linear (1H) Linear (2H) Linear (3H)
FIG. 7.16 ARRHENIUS PLOT FOR LTO REACTION WITH DIFFERENT HEAT INPUT
R.No n E
22 1.0 91
49 1.2 55
55 1.0 37
Fig. 7.15: Arrhenius plot for fuel deposition with different heat input
Fig. 7.16: Arrhenius plot for LTO reaction with different heat input
169
order dependence of the reaction rate on the carbon concentration [Fassihi (84)
]. Also the
use of precoked oils in combustion kinetic studies does not simulate the flow and heat
transfer found in the in-situ combustion. Further more, the lower peak temperatures
obtained in this study has a reducing effect on kinetic parameters.
7.7 REPEATABILITY AND ACCURACY OF EXPERIMENTS
All runs were repeatable. Using same fuel in repeatable runs, which are not reported in
this thesis due to the similar results. The same procedure was followed in matching the
other results and the repeatability of the tests was confirmed.
To verify that the activation energies and the reaction orders derived from the analysis
were reasonable. The amount of oxygen consumed in the three reactions was super
imposed upon one another and the results were compared to the experimental oxygen
consumption curves. The match was good for these and other similar data.
The trapezoidal rule was used to integrate the area under the oxygen consumption curve.
This used some errors when there was a sharp change in gas composition. It also
introduced some errors into the calculations of curve fitting and extrapolation of the
reaction rates of lower temperatures. These calculations were especially sensitive to
choice the point at which the relative reaction rate curve would deviate from the straight
line. Thus in all runs using the same fuel except few runs; the calculated Activation
energy (E) was not the same. Therefore to normalize the data, first the E, which was quite
different from the average value, were discarded. Than using the average value of the
calculated E, straight lines of the slope were drawn through the experimental data points
on the Arrhenius plot (Fig 7.1-7.16). This was achieved by selecting an arbitrary data
points at the mid range of the abscissa as the focal point. For a combustion reaction (Fig
7.2, 7.5, 7.8, 7.11 and 7.14), this point was about 1.5 x10-3
k-1
. The corresponding points
for fuel deposition (Fig. 7.3, 7.6, 7.9, 7.12, and 7.15) and LTO reaction (Fig.7.4, 7.7,
7.10, 7.13, and 7.16) were about 1.6 x10-3
and 2.3 x10-3
k-1
respectively.
170
Table 7.2 Analysis of in-situ combustion reaction kinetics combustion reaction rate
Authors
Crude
type
API
Reactor
Bed
E
KJ /g-mole
n P
KPa
Combustion
Peak Temp.
(K)
Bousaid & Ramey,
1968
13.9
22.1
Beras sand
170-230
mesh
Beras sand
61.9
59.8
1.0
1.0
300
248
755
744
Dabbous & Fulton,
1974
19.90
Pre -
coked
Beras sand
60 mesh
58.90 1.0 200 713
Thomas et al.,
1979
27.0 Sand Quartz
Koalinite
(5%)
58.80
(1) 5
9997 n.a
Fassihi,
1981
11.2
10.1
18.5
Sand Pack
120
133
135
0.58
0.23
0.66
165
193
248
700
720
756
S.Sakthikumar et al
1995
98.74 365-392
T.H.Gilham et al.,
1997
95.39 24132 600
Cedric Clara et al.,
1999
33.5
70
23581-
24305
365 -403
M.Greaves et al.
1999
36
39
55.4 –62.7
6000
18000
363-413
393-391
M.Greaves et al.,
2000
36
39
55.4 –62.7
6000
18000
393-391
Cedric Clara et al.
2000
33.5
Sand Pack
E1=67,79,
4.5 & 60
E2= 103,
86, 109, 99
1.0
17100
673
Dembla Dhiraj,
2004
40.7 18.4-109
25-51.5
0.5 27063 643
S.Stokka et al.,
2005
30-40 20685
31027
428-473
This Study
37.5,39,
41
Sand pack
E1=4-130
E2=16-80
E3=4-55
0.5,1
1.5-2
690-
11032
585-711
CHAPTER 8
CONCLUSIONS AND RECOMMENDATIONS FOR
FUTURE WORK
8.1 CONCLUSIONS
1. A new slim and short combustion cell strategy was developed to assess the
recovery potential by air injection into depleted light oil reservoirs of Sindh crude,
Pakistan. All reported runs are performed with reservoir oils and unconsolidated
core (sand pack). Spontaneous ignition takes place in the combustion cell at
elevated temperatures. The generation of flue gas by oxidation process at high
temperature was very efficient in terms of carbon oxides with an average
percentage of gas composition of 10 % CO2, 4 % CO, and balance unreacted
oxygen.
2. Oxygen uptakes and characteristic combustion parameters were also calculated.
100 percent utilization of O2 was observed on the basis of analysis of flue gases.
3. Oil displacement observed by flue gases. Significant oil recovery varying between
65 to 87 % was obtained.
4. It was observed that by increasing pressure and heat input, oxidation reaction rate
increases.
5. By varying the sand pack it was concluded that trapped hydrocarbons in the
porous media create the LTO effect in the formation. The occurrence of LTO
reactions increases the fuel availability and decreases the H/C ratio of the fuel.
The excess oxygen consumption by hydrocarbons in unconsolidated formation
occurs in the temperature region.
6. Four different air fluxes of 7.595, 15.19, 30.38 and 37.97 Sm3/m
2-hr were used
to investigate the effect on the oxidation of crude oil. Increase of air flux, resulted
in slightly increasing rates of oxygen consumption over the temperature range
under investigation.
171
172
7. It was observed that, by increasing water saturation from 16.2 to 41.2 %, the
consumption of oxygen was slightly increased. How ever reaction time has
slightly decreased by increasing water saturation.
8. The H/C ratio and m-ratio of the fuel for these air injection experiments were
calculated at peak temperature of about 2 and 0.20 respectively.
9. Kinetic behavior of unconsolidated formation indicates a more reactive fuel
deposition. The activation energy with respect to rate of carbon burned correlated
well with the amount of carbon deposited on the sand grains. Activation energy
varying from 30 to 200 KJ/gmole at different pressure, air flux, heat input, water
saturation and sand pack.
10. The reaction order with respect to carbon concentration in the Direct Arrhenius
method was evaluated from 0.5 to 2.0 for all runs (HTO, MTO, and LTO).
The results obtained from the air injection experimental set-up, indicate that the most of
the light oils tested are sufficiently reactive at near reservoir conditions for air injection to
be feasible. These experimental results are very positive indication for the potential
viability of the air injection process.
8.2 SUGGESTIONS FOR FUTURE MODIFICATION IN EXPERIMENTAL
SET-UP
1. For the most accurate flow rate of air injection, a high-pressure mass flow
controller should be installed at the inlet of the reactor. This controller will work
directly on a cylinder pressure of 13652 KPa. This controller will not be
susceptible to damage by the differential pressure across the controller.
2. Safety gauge, pressure differential should be installed.
3. A loop type gas sample injection valve of 1.0 ml should be used and this will
inject a constant volumetric injection.
173
4. A simpler method for decomposition of the different reaction rates in non-
isothermal runs should be developed. Use of fully automatic computer program is
suggested.
5. An experimental model should be developed to analyze the gases produced at
different sections of a combustion tube and to directly measure the kinetic rates.
8.2.1 Suggestions for future work
1. Light oil were used in this work, future work should concentrate on medium and
heavy crude oils of Sindh.
2. Although unconsolidated reservoir core were used in this work, future work
should focus on natural cores. The whole suit of kinetic data should be obtained.
3. The effects of heat loss on the frontal temperature and frontal velocity should be
investigated.
4. Investigate the recovery at higher values of Sw greater than 50 percent.
174
REFRENCES
01 Kumar, V. K., Fassihi, M.R., Yannimaras, D.V. (1995), “Case History and
Appraisal of Medicine Pole Hills Unit Air – Injection Project,” SPE Paper
27792. SPE Reservoirs Engineering, August 1995.
02. Fassihi, M.R., Yannimaras, D.V, and Kumar, V. K, (1997) “Estimation of
Recovery Factor in Light Oil Air -Injection Projects” SPE Paper 28733. SPE
Reservoir Engineering, August, 1997
03 Greaves, M.; Mahgoub, O. (1996), “3D Physical Model Studies of Air Injection
into Light Oil Reservoir using Horizontal Wells,” SPE International Conference
on Horizontal Well Technology in Calgary, Canada.
04 Unpublished results of experimental work conducted as an industry consortium
supported by shell oil company.
05 Tiffin, D.L and Yannimaras, D.V. (1997) “In-Situ Combustion Performance of
light oils as a function of pressure (1000 to 6000 Psig),‟‟ In-Situ, 21 (1), pp. 47.
06 Greaves, M., Ren, S.R. Rathbone, R.R., Fishlock, T., and Ireland, R. (2000),
“Improved Residual Light Oil Recovery by Air Injection (LTO Process)”.
Presented at the 49th
Annual Technical Meeting, June 8-10, 1998, Calgary,
Alberta, V. 39, No.1, January, 2000
07 Moore, R.G., (1993) “New Strategies for In-Situ combustion,” J. Canadian
Petroleum Technology (1993) Vol. 32 No.10
08 Moore, R.G., Belgrade, J.D.M., Mehta, R., Ursenbach, M., and Laurenshen, C.J.
(1992), “Some Insights into the Low-Temperature and High-Temperature In-Situ
Combustion Kinetics,” Paper SPE/DOE 24174 presented at Eighth Symposium
on Enhanced Oil Recovery, Tulsa, Ok, April 22–24, 1992, pp.179-190.
09 Yannimaras, D.V, and Tiffin, D.L. (1995), “Screening of Oils for In-Situ
Combustion at Reservoir conditions by Accelerating–Rate calorimeter” SPE
Reservoir Engineering, February, 1995.
10 Carlson, L.O. (1988), “Performance of Hawkins Field Unit under Gas Drive
175
Pressure maintenance Operations and Development of an Enhanced Oil
Recovery Project” .SPE/DOE17324 paper presented at the 1988 Meeting held in
Tulsa, Ok. , April 17-20.
11 Yannimaras, D.V, Sufi, A.H., and Fassihi, M. R. (1991), “The Case for Air
Injection into Deep Light Oil Reservoirs,” Proceedings of Sixth European
Symposium on Improved Oil Recovery, Stavanger, Norway, 21-23 May 1991,
pp 55-63.
12 Fassihi, M. R. (1992), “Improved Phase Behavior representation for Simulation
of Thermal recovery of Light Oils” .SPE 24034, Paper presented at the 1992
California Regional Meeting, held in Bakers field, CA March 30 to April 1.
13 Lin, C.Y., Chin, W.H., Less, S.T. Gillham, W.E. (1984), “Numerical Simulation
of Combustion Tube Experiments and associated Kinetics of In-Situ combustion
process,” SPE – Dec. 1984.
14 Fassihi, M.R.; Gillham, T.H. (1993), “The Use of Air Injection to Improve the
Double Displacement Process,” .SPE Paper 26374, SPE 68th
Annual Technical
Conference and Exhibition, Houston, Texas, 3-6 October..
15 Erickson, A., Legerski, J.R., and Steece, F.V. (1994), “Appraisal of High
Pressure air Injection on In-Situ combustion results from deep high Temperature,
high gravity oil reservoirs,” Paper presented at the 15th
anniversary field
conference of the Wyoming geological association guide book.
16 Chekalyuk, E.B., Oganov, K.A and Onoprieko, V.P. (1979), “Oil In Water
solubility Thermal process to improve recovery” Proceedings of 10th
world
petroleum Congress, V. 3, Bucharest, Romania, pp. 405-412.
17 Dugdale, P.J. (1986), “Comparison of Recovery and Economics for O2 and Air
fire Flood in Canadian Heavy oil Areas,” SPE/DOE 14921. Paper presented at
the SPE/DOE meeting held in Tulsa, Ok. April 20-23.
18 Northrop, P.S., Willson, J.L., and Soustek, P.G., (1994), “Study of a Mature Fire
Flood: MOCO- T”, SPE 27889, Paper presented at the California Regional
176
meeting, held in long Beech, CA, March 23-25.
19 Oren, P.E, Billiotte, J, and Pinczewski, W, V, (1990), “Mobilization of Water
flood Residual Oil by Gas injection for water-Wet Conditions”, SPE/DOE
20185. Paper presented at the SPE/DOE seventh Symposium on Enhanced Oil
recovery in Tulsa, April 22-25.
20 Naylor, P., Sargent, N. C., Tilsed, A.P. and Frorup, M. D. (1991), “Oil Relative
Permeability for Gravity Drainage based on In-Situ Saturation Measurement”,
Paper SPE 23101, presented at Offshore Europe Conference in Aberdeen, 3-6
September.
21 Gregory, A. T. (1994), “DTI‟s improved Oil Recovery Strategy”, Trans I. Chem.
Part A, V. 72, pp-137
22 Fassihi, M.R, Meyers, K.0, and Basile, P.F. (1990), “Low temperature Oxidation
of Viscous Crude Oils”, SPE Reservoir Engineering, Nov. 1990, pp-609.
23 Burger, J. G. (1976),“Spontaneous Ignition in Oil Reservoirs,” SPE J, April
1976.
24 Tade, H. J., and Weijdema, J. (1970) “Spontaneous Ignition of Oil Sand”, Oil &
Gas J, Dec. 14, 1970, pp- 77.
25 Kazi, R. A., Oklany, J.S, Hughes, R. and Price, D. (1996), “Oxidation of heavy
oil in consolidated porous media; effect of oxidant flux and heating rate”, The
1996 I.Chem. E Research Event, pp-220-222
26 Kisler, J.P. and Shallcross, D, C. (1997), “Improved model for the oxidation
processes of light crude oil,” Trans IChemE. V. 75, Part A, May 1997.
27 Germain, P. and Geyelin, J.L. (1997), “ Air Injection into Light Oil Reservoirs:
The Horse Creek Project” SPE Paper 37782. Presented at the 1997 Middle East
Oil Show, Bahrain, 15-18 March.
28 Watts, B.C, Hall, T. F, and Petri, D.J. (1997), “The Horse Creek Air Injection
Project: An Over view,” SPE Paper 38359. Presented at the 1997, SPE Rocky
Mountain Regional Meeting, Casper, Wyoming, 18-21, May.
29
177
Sakthikumar, S.; Madaoui, K.; and Chastang, J. (1995), “An Investigation of the
Feasibility of Air Injection into a Water Flooded Light Oil Reservoir” SPE Paper
29806, the SPE Middle East Oil show, Bahrain 11-14 March.
30 Turta, A., Fisher, D, Wassmuth, F. (1997), “Addendum to PRJ.zem1.2-Technical
Report and user‟s Manual,” Petroleum Recovery Institute, Calgary, 1997.
31 Turta A., (1994), “In-Situ Combustion from Pilot to Commercial Application.”
Proceedings of the field Applications of In-Situ Combustion - Past
Performance/Future Application Symposium, Tulsa April 21-22, 1994.
32 Turta A. and Pantazi I. (1986), “Development of In-Situ Combustion on an
Industrial Scale at Vldele Field”, SPE Reservoir Engineering, November1986.
33 Carcoana, A., Machedon, V., Pantazi, I., Petcovici, V. and Turta A. (1983), “In-
Situ Combustion. An Effective Method to Enhance Oil Recovev in Romania”
Eleventh World Petroleum Congress, London, August, 28- Sept.2.
34 Miller, R. J. (1994), “Koch‟s Experience with Deep In Situ Combustion in
Williston Basin” Key Note Address at the Forum on Field Applications of In-
Situ Combustion- Past Performance/Future Application, Tulsa April21-22..
35 Burger, J., (1985), Sourieau, P. and Combamous, M. “Thermal Methods of Oil
Recovery “ Editions Tactile, Paris..
36 Metwally, M. (1989), “Experience with Fireflooding in Countess B Pool”,
Alberta - Reservoir Aspects”, CIM 89-40-50, Ba @ Canada.
37 Tilley, B.J. and Gunter, W.D. (1988), “Mineral and Water Chemistry of the
Burnt Zone from a Wet Combustion Pilot in Alberta”, Bulletin of Canadian
Petroleum Geology.
38 Sarathi, P.S. and Olsen, D.K. (1994), “DOE Cost-Shined In Situ Combustion
Projects Revisited” Proceedings of the Field Applications of In-Situ Combustion
-Past Performance/ future Application, Symposium, Tulsa, April 21-22.
39 Hardy, A., Fletcher, P.B. and Shepard, J.C. (1970), “In Situ Combustion
Performance in a thin high oil Gravity Reservoir May-Libby Reservoir, Delhi
178
Field” SPE 3053..
40 Grant, B. and Szasz, J. (1954), “Development of an Under ground Heat Wave for
Oil Recovery”, Trans AIME.
41 Byll, M., L., Moore, R., G., Ursenbach M., G. (1993), “Field Observations of In-
Situ Combustion in Water flooded Reservoir in the Kinsella Field,” Journ. of
Canadian Petr. Techn. September 1993.
42 Fassihi, M.R. and Gillham T.H., Yanimaras, D.V., and Hassan, D. (1996),
“ Field Tests Assess Novel Air Injection EOR Processes” Oil and Gas Journal,
May 20.
43 Oganov, K., A., Pavlov, B., M. (1970),“Opitno-promishlenoe Rsboti PO
Sozdaniiu fionta Gorenia v Borislavskom Pescianike,” Neftianoe Hoziaistvo, No
5, 1970, Russia.
44 Huffiman, G.A., Benton, JP. E1-Messidi A.E., and Riley K.M. (1983), “Pressure
Maintenance by In-Situ Combustion, West Heidelberg, Jasper County,
Mississippi”, Journ. of Petr. Techn. October 1983.
45 Buxton, T.S., Pollock, C.B., “The Sloss COFCAW Project Further Evaluation
of Performance during and After Air Injection”, SPE 4766, IOR Symposium
Tulsa, Oklahoma.
46 Anon., (1998), “Nevada Pilot Project Proving Efficiency of High Pressure Air
injection for Enhanced Recovery,” Improved Recovery week, January 19.
47 Kisler, J.P. and Shallcross, D. (1985), “Oxidation Kinetics of Very Light Crude
Oil”, Presented at the IEA Collaborative Project on EOR Workshop Symposium,
Tokyo, October 15-18.
48 Kisler, J.P. and Shallcross, D. (1997), “An Improved Model for the Oxidation
Processes of Light Crude Oil”, Trans IChemE, Vol. 75, Part A, May 1997.
49 Bulighin, M.G. (1971), “Chemical Reactions in the In-Situ Combustion Process
for the Oil Recovery”, Vol. NIL, Nedra, Moscow, 1971 (In Russian).
50 Wichert, G.C., Okazawa N.E., Moore, R.G. and Belgrave D.M. (1995), “In- situ
179
Upgrading of Heavy Oils by Low- Temperature Oxidation in Presence of
Caustic Additives”, International Heavy Oil Symposium, Calgary, 19-21 June .
51 Greaves, M, Ren, S.R and Rathbone, R.R., (1998), “Air Injection Technique
(LTO Process) for IOR from Light Oil Reservoirs: oxidation Rate and
Displacement Studies” SPE Paper 40062, Presented at the 1998 SPE/DOE IOR
Symposium, Tulsa, Oklahoma, 19-22 April.
52 Garon, A.M., Wygal R.J. (1974), “A Laboratory Investigation of Wet
Combustion Parameters” SPE 4762, IOR Symposium Tulsa 1974.
53 Tiffin, D.L. and Yanimaras, D.V. (1997), “The In-situ Combustion Performance
of Light Oils as a Function of Pressure”, In Situ, 21 (l), pp-47-64.
54 Wilson, L., Reed, R.L., Reed, D.W., and Clay, R. (1963), “Some Effects of
Pressure on Forward and Reverse Combustion”, Soc. of Petr. Engin. Journ. June
1963.
55 Turta, A.T.; Singhal, A.K. (1998), “Reservoir Engineering aspects of Oil
Recovery from Low Permeability Reservoirs by Air Injection” SPE Paper
48841, Presented at the 1998 SPE International Oil/Gas Conference &
Exhibition in China, Beijing, China, 2-6 November .
56 Dietz, D.N. and Weijdema J. (1968), “Wet and Partially Quenched Combustion”,
Journ. of Petr. Techn. April 1968.
57 Dietz, D.N. (1970), “Wet underground combustion. State of the Art”, Journal of
Petroleum Techn. May 1970
58 Shaw, J., and Leggitt, S. (1993), “Chemical and Physical Properties of Pyro
bitumen Key to Understanding Its Impact on Oil Recovery”, PRI Report April
1993.
59 Greaves, M, Ren, S.R and Xia, T.X. (1999), “New Air Injection Technology for
IOR Operations in Light and Heavy Oil Reservoirs” SPE Paper 57295. Presented
at the 1999 SPE Asia Pacific Improved Oil Recovery Conference, Kuala
Lumpur, Malaysia, and 25-26 October.
60
180
Machedon, V., Popescu, T and Paduraru, R. (1993), “Application of In- Situ
Combustion in Romania” Joint Canada / Romania Heavy Oil Symposium
Proceedings, Sinaia, Romania, March7-13.
x61 Roychaudhury, S. et al. (1995), “Experience with In-Situ Combustion Pilot in
Presence of Edge Water” Proceedings Sixth UNITAR international Conference
on Heavy Crude and Tar Sands ,Houston, Texas, February 12-17.
62 Turta A. (1996), „Review of the Balol and Lanwa In-Situ Combustion Field
Tests.” Four Technical Reports Prepared for the United Nations Development
Programs and Oil and Natural Gas Commission (ONGC) India, in the Period
September1991to March1996.
63 Penberthy, W.L., Ramey, H.J., Jr. (1966), “Design and operation of Laboratory
combustion tubes,” Soc. of Pet. Engg. J. June 1966.
64 Moss, J.T., white P.D., and Mc Niel, J.S. (1958), “In-Situ combustion process –
results of a Five –well field experiment in Southern Oklahoma,” Trans. AIME ,
V. 216, pp. 28-35
65
Showalter, W.E. (1963), “ Combustion Drive Tests,” Soc. of Pet. Engg. J.
,March 1963, pp. 53-58
66 Martin, W.L., Alexander, J.D., and Dew, J.N. (1958), “Process variables of in-
situ combustion”, Trans. AIME, V.213, pp.28-35
67 Ramey, H.J., Jr. (1971), “ In-Situ Combustion” Proceedings of the 8th
world
Petroleum congress, Moscow , pp. 253-262
68 Bae, J. H. (1977), “Characterizing of crude oil for fire flooding using Thermal
Analysis Methods”, Soc. of Pet. Engg. J., June 1977, pp. 211- 217
69 Fassihi, M.R.; Yannimaras, D.V., Westfall, E.E; Gillham, T.H. (1996)
“Economics of Light Oil Air Injection Projects” SPE Paper 3539, Presented at
the 1996 SPE/DOE Tenth Symposium on Improved Oil Recovery, Tulsa,
Oklahoma, U.S.A., 21-24 April.
70 Farim, M.L.; Moffitt, P.D.; Yannimaras, D.V. (1997), “Laboratory Testing
181
Simulation Results For High Pressure Air Injection In Water Flooded North
Sea Oil Reservoir” SPE Paper 38905, Presented at the 1997 SPE Annual
Technical Conference and Exhibition, San Antonio, Texas, USA, 5-8 October .
71 Kuhlman, M. I. (2000), “Simulation of Light Oil Air Injection into Viscous
Dominated and Gravity-Stable Reservoirs” SPE Paper 59331, Presented at the
2000 SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 3-
5 April.
72 Moore, R.G, Mehta, S.A, and Ursenbach, M.G. (2002), “ A Guide to High
Pressure Air Injection (HPAI) Based Oil Recovery” SPE Paper 75207, Presented
at the 2002, SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma,
USA, 13-17 April.
73 Gillham, T.H, Cerveny, B.W, Fornea, M.A, and Dr. Bassiouni, Z. (1998), “Low
Cost IOR: An Update on the W. Hackberry Air Injection Project” SPE Paper
39642, Presented at the 1998, SPE/DOE Improved Oil Recovery Symposium,
Tulsa, Oklahoma, USA, 19-22 April.
74 Clara, C., Zelenko, V., and Schirmer, P. (1998), “Appraisal of the Horse Creek
Air injection Project performance” SPE Paper 49519, Presented at the 1998 SPE
Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi,
United Arab Emirates, 11-14 October.
75 Greaves, M., Wilson, A., AL-Honi, M., & Lockett, A.D. (1996) “Improved
Recovery of Light/ Medium Heavy oils in Heterogeneous Reservoirs Using Air
Injection / In- Situ Combustion (ISC)” SPE Paper 35693, Presented at the 1996
SPE Western Regional Meeting, 22-24 May.
76 Cedric CLARA, Marc DURANDEAU, Gerard QUENAULT, and Tuyet Hang
NGUYEN. (1999), “Laboratory Studies for Light Oil Air injection Projects:
Potential Application in Handil Field” SPE Paper 54377, Presented at the 1999
SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, Indonesia, 20-
22 April.
77
182
Glandt, C.A., Pieterson, R., Dombrowski, A., Balzarini, M.A. (1999) “Coral
Creek Field Study: A Comprehensive Assessment of the Potential of High
Pressure Air Injection in a Mature Water flood Project” SPE Paper 52198,
Presented at the 1999, SPE Mid Continent Operations Symposium, Oklahoma
city, USA, 28-31 March.
78 Gillham, T.H, Cerveny, B.W., Turek, E.A., and Yannimaras, D.V. (1997), “Keys
to Increasing production Via Air Injection in Gulf Coast Light oil Reservoirs”
SPE Paper 38848, Presented at the 1997 SPE Annual Technical Conference And
Exhibition, San Antonio, Texas, USA, 5-8 October.
79 Leonid M., Yannimaras, D.V. (1999), “Air Injection – Cost Effective IOR
Method to Improve Oil Recovery from Depleted and Water Flooded Fields” SPE
Paper 57296, Presented at the 1999 SPE Asia Pacific Improved Oil Recovery
Conference (APIORC), 25-26 October.
80 Cedric Clara, Marc Durandeau and Gerard Quenault, and Tuyet – Hang Nguyen.
(1999), “Laboratory Studies for Light Oil Air injection Projects: Potential
Application in Handil Field” SPE Paper 64272, Presented at the 1999 SPE Asia
Pacific Oil & Gas Conference and Exhibition, Jakarta, Indonesia, 20-22 April.
SPE Reservoir Eval. & Engg. 3 (3), June 2000.
81 Turta, A.T.; Singhal, A.K. (1998), “Reservoir Engineering aspects of Light- Oil
Recovery by Air Injection”, SPE Paper 72503, 1998 SPE International Oil/Gas
Conference & Exhibition In China Held In Beijing, China, 2-6 November 1998.
August 2001 SPE Reservoir Evaluation and Engineering.
82 Ren, S.R., Greaves, M, and Rathbone, R.R. (2002), “ Air Injection LTO
Process: An IOR Technique for Light Oil Reservoirs”, SPE Paper 57005, March
2002 SPE, Journal
83 Abd Elsattar Elsaghir, Mohammad Moustafa, Elsayed Flayouty and Abdul
Razak Abro, “Comparative Investigation on Enhanced Oil Recovery Methods
with Special Reference to Hot Water Flooding and Alcohol Slug injection”,
183
Department of Petroleum Engineering, Bright Star University, Libya.
84 M. R. Fassihi, W.E. Brigham. (1982), “Analysis of Fuel Oxidation in In-Situ
Combustion Oil Recovery”, Topical Report, Stanford University Petroleum
research Institute Stanford, California.
85 K. K. Pande, (1985), “A study of the effect of Air Flux on process variables in
In-situ combustion”, M.S. Thesis, Stanford university. March, 1985
86 R.A. Kazi. (1985), “A high Pressure Kinetic study of the In- situ combustion
process for oil Recovery,” Ph.D. Thesis, University of Salford, 1995
87 Abu-Khamsin, William, E. Brigham and Ramey: (1988), “ Reaction Kinetics of
Fuel Formation for In-Situ Combustion,” Soc. Pet. Eng. Res. Nov., 1988. PP
1308-1316.
88 Dabbous M.K., and Fulton P.F. (1974), “ Low Temperature Oxidation Reaction
Kinetics and Effects of the In-Situ Combustion Process”, Soc. Pet. Eng. J. June,
1974, pp. 253-262
89 Lewis, W.K., Gilliland, E.R., Pakston, R.R. (1954), “ Low Temperature
Oxidation Of Carbon”, Ind. and Eng. Chem. Vol. 46. No.2, 1954, pp. 1327-1331.
90 Moore, R. G., Bennion, D.W., Belgrave, J. D. M., Gle, D.N., Ursenbach, M.G.
(1990), “ New Insights Into Enriched Air In-Situ Combustion”, J. Pet. Tech.
July, 1990, pp. 916-923
91 Shahani, G. H., Hansel, G.J. (1987), “ Oxygen Fire Flooding: Combustion Tube
Test With Light, Medium and Heavy Crude Oils”, Soc. Pet. Eng. Res. Nov.,
1987. pp. 591-595.
92 Hansel, G.J., Benning, M. A., Farbacher, J. M. (1984), “oxygen in-situ
combustion for oil recovery: combustion tube tests”, J. Pet. Tech. July 1984, pp.
1139-1144.
93 Greaves, M., Field, R.W., And Adewusi, V. A. (1988), “ In-Situ Combustion
Kinetic Studies of Medium Heavy Crude Oil”, Chem. Eng. Res. Des. Vol. 66 (4)
July 1988. pp. 328-338.
94
184
Greaves, M., and Dudley, J. W. O. (1990), “ In-Situ Combustion Process:
Reaction Rate Parameters from Combustion Tube Experiments”, Trans.
IChemE. . V. 68, Part A, July 1990. pp. 331-341.
95 Moss, T. Jon. (1982), “ Laboratory Investigation of the Oxygen Combustion
Process for Heavy Oil Recovery”, Paper SPE 10706 Presented at the California
Regional Meeting of the SPE, San Francisco, March, 24-26, 1982, pp. 55-68.
96 Burger, J.G., Sahquet, B. C. (1972), “Chemical Aspects of In- Situ Combustion
Heat of Combustion and Kinetics”, Soc. Pet. Eng. J. Oct., 1972. pp. 410-422.
97 Alexander, J.D., Martin, W. l., Dew, J. M. (1962), “ Factors Affecting Fuel
Availability and Composition during In-Situ Combustion”, J. Pet. Tech. Oct.
1962, pp. 1154-1164.
98 Dabbous, M. K., (1971), “ In-Situ Oxidation of Crude Oil in Porous Media”,
Ph.D Thesis University of Pittsburgh, USA.
99 Bousaid, I. S., Ramey, H. J. Jr. (1968), “Oxidation of Crude Oil in Porous
Media”, Soc. Pet. Eng. J. June, 1968, pp. 137-146.
100 Fassihi, M. R., Brigham, W.E., Ramey, H. J. Jr. (1984), “Reaction Kinetics of
In-Situ Combustion: Part 1- Observations”, Soc. Pet. Eng. J. August 1984, pp.
408-416.
101 Fassihi, M. R., Brigham, W.E. (1980), “ The Frontal behavior of In-Situ
combustion”, Paper SPE 8907 Presented at the 50th
Annual California Regional
Meeting, 9-10.
102 Mamora, D. D., and Brigham, W.E. (1994), “ The Effect Of LTO Oxidation on
the Fuel and Produced Oil during In-Situ Combustion”, Paper DOE/ NIPER NO.
ISC 7 Presented at the Symposium of In-Situ Combustion Practices Past, Present
and Future Application, Tulsa, Ok, April 21-22, 1994, pp. 65-76.
103
Shallcross, D. C., De Los Rio, C. F., Castaniar, L. M., and Brigham, W.E.
(1987), “Modifying In-Situ Combustion performance by the use of Water
Soluble Additives”, Soc. Pet. Eng. Res. August 1987. pp. 287-294.
104
185
Mamora, D. D. (1993), “Kinetics of In-Situ Combustion”, Ph.D Thesis,
Stanford University, CA, USA, May 1993.
105 Phillips, C. R., and Hsich, H. C. (1985), “ Oxidation Reaction Kinetics of
Athabasca bitumen”, Fuel, V. 64, July 1985, pp. 985-989.
106 Thomas, F. B., Moore, R. G., Bennion, D. W. (1985), “Kinetic Temperature for
the HTO of In-Situ Combustion Coke”, J. Can. Pet. Tech. Nov.-Dec., 1985, pp.
60-67.
107 Kamath, V. M. (1986), “ A Kinetic Study of In-Situ Combustion for oil
Recovery,” M.Sc. Thesis, University of Salford, 1986.
108 Vossoughi, S., and El-Shoubary. (1989), “Kinetics of crude oil Coke
Combustion”, Soc. Pet. Eng. Res. May 1989, pp. 201-206.
109 Lin, L. C., Deo, M. D., Hanson, F. V., and Oblad, O. G. (1990), “Kinetics of
Tar Sand Pyrolysis using a distribution of Activation Energy Model”, AIChE J.
Vol. 36,No. 10, Oct. 1990, pp 1585-1588.
110 Dubdub, I. J. (1993), “Kinetics of In-Situ Combustion of Athabasca Tar Sand”
Ph.D. Thesis, University of Salford, U.K
111 Dembla Dhiraj. (2004), “ Simulating Enhanced oil Recovery (EOR) By High
Pressure Air Injection (HPAI) in West Texas light oil Reservoir” M.S. Thesis
University Of Texas Austin, USA.
112 Greaves, M, Benther, A.H., and Rathbone, R.R. (2005), “ Air Injection into
Light Oil Reservoirs-Oxidation Kinetics and Simulation”, European Symposium
on Improved Oil Recovery, Budapest, April 2005.
113 Stoka, S, Rogaland, R.F, Oesthus, A. (2005), “ Evaluation Of Air Injection as
an Improved Oil Recovery Method for The Giant Ekofish Chalk Field”, SPE
International IOR Conference in Asia Pacific, Kuala Lumpur, Malaysia,
December, 2005.
114 Kumar, V.K., Gutierrez, D., Moore, R.G., and Mehta, S.A. (2006), “Air
Injection and Water Flooded Performance Comparison of two Adjacent Units in
186
Buffalo Field:Technical Analysis”, SPE Paper/ DOE Symposium on IOR, Tulsa,
Oklahoma, U.S.A, April, 2006.
115 E. Niz-Velas quez. (2006), “Numerical and Laboratory Assessment of the Oil
recovery Mechanisms in High Pressure Air Injection (HPAI) process” Paper
presented at the 2006 SPE International Student Paper contest at the SPE Annual
Technical Conference and Exhibition being held in San Antario, Texas, 24-27
September2006.
116 Zeeshan Mohiuddin, Anwar Raja, and Ismail Mohd Saaid. (2007), “ Utilizing
the effect of Nitrogen to Implement Light Oil Air Injection (LOAI) in Malaysian
oil Fields”. Paper presented at the 15th
SPE Middle East Oil and Gas Show and
Conference held in Bahrain International Exhibition Center, Kingdom of Bahrain
11-14 March 2007.
117 M.Pascual, D. Crosta and P. Lecentre. (2005), “Air Injection into a mature Water
flooded Light Oil reservoir. Laboratory and Simulation Results for Barrancass
Field, Argentina.” Paper presented at the SPE European / EAGE Annual
Conference held in Madrid Spain, 13-16 June 2005.
118 Bagci, A.S., Kok, M.V., Okandan, E., Middle East Technical U. (1987),
“Combustion Reaction Kinetics in Lime stones Containing Heavy Oils”, SPE
Paper no. 15737. Middle East Oil Show, 7-10 March 1987, Bahrain.
119 Parrish, David R., Pan American Petroleum Corp.; Craig Jr., F.F. (1969),
“Laboratory Study of a Combination of Forward Combustion and Water
flooding The COFCAW Process”, Journal of Petroleum Technology, Volume
21, Number 6, June 1969, PP 753-761.
120 Alderman, John H., Osoba, J.S., Texas A. and M U. (1971), “A Study of Oil
Recovery by In-Situ Combustion with the Addition of Water”, SPE California
Regional Meeting, 4-5 November 1971, Los Angeles, California.
121 Hansel J.G., Benning M.A., Fernbacher J.M. (1982), “Oxygen In-Situ
Combustion for oil recovery: Combustion tube tests”. Paper 11235 Presented at
187
the SPE Eastern Regional meeting, Washington DC, November 1982
122 G.C. Ejiogu, M. Fiori. (1987), “High-Pressure Saturated-Steam Correlations”,
SPE Paper No. 15405. Journal of Petroleum Technology, V. 39, No. 12,
December 1987, pp 1585-1590
123 Lin, L. C., Deo, M. D., Hanson, F. V., and Oblad, O. G. (1991), “Non-
Isothermal Analysis of Kinetics of the combustion of Coked Sand”, Ind. Eng.
Chem. Res. V. 30, No. 8, 1991. pp. 1795-1801.
124 Thomas, G. W., Buthod, A. P. and Allog, O. (1979), “ An Experimental Study
of the Kinetics of Dry Forward Combustion”, Fossil energy report no. BETC
1820-1, U.S. D. O. E. Feb., 1979.
125 Ambastha, A.K., Kumar, M. (1999), “ New Insights into In-Situ Combustion
Simulation for Heavy oil Reservoirs”, SPE Paper no. 56543 Presented at the SPE
Annual Technical conference and Exhibition, Houston, Texas, October 3-9.
126 Christopher, C.A., Spencer, M.F., Baker, M.A., (1999), “A Combustion Tube
Evaluation of the Air Injection Potential of Goldrus Producing Company Crude
oil and Core” Report.
127 Fassihi, Mohammad Reza, Abu-Khamsin, Sidqi, Brigham, William E., Williams,
Loretta A., Graham, Steve A., (1982), “A Preliminary Study of In-Situ
Combustion in Diatomite”, SPE Paper no. 10701. SPE Enhanced Oil Recovery
Symposium, 4-7 April 1982, Tulsa, Oklahoma, USA
128 Vossoughi, S., Willhite, G.P., Kritikos, W.P., (1982), “ Automation of In-Situ
Combustion Tube and Study of the effect of Clay on the In-Situ Combustion
process”, Paper SPE 10320 Presented at the 56th Annual Technical Conference
San Antario, Oct. 5-7, 1981. Published in SPE J. April, 1982. pp. 299-308
