Athabasca Oil Sands Bitumen Research Articles

Investigation of Unresolved Interface "Rag Layer" in Athabasca Oil Sand Bitumen In Situ Recovery.

Steam-assisted gravity drainage (SAGD), the leading commercial in situ bitumen recovery process, involves the underground injection of steam and produces at the well head a hot fluid containing water, hydrocarbons, and sand. This fluid is subjected to separation by diluent addition and gravity in several parallel treaters. Occasionally, the separation may be disrupted in one or few treaters by the occurrence of an unresolved interface or "rag layer" while continuing without disruption in the rest of the treaters. In the current study, we investigate "rag layer" occurrence based on the quantification of laboratory-scale and SAGD field tests and imaging of the "rag layer" morphology. The quantification results show that the formation and volume of the "rag layer" are affected by solids, mixing speed, and solvent addition. The microscopic images demonstrate the presence of both water-in-oil or oil-in water emulsions with a distinct transition between the continuous phases. The visual detection boundaries of the "rag layer" are defined as the threshold between the agglomerated and individual droplet layers. The extent of agglomeration increases in the proximity to the oil-water interface. The contribution of hydrophobic fine inorganic solids (less than 10 μm) to forming a "rag layer" is supported by their accumulation observed at the treaters' oil-water interface, compared to the feed. In well-controlled field operations, the perceived randomness of "rag layer" occurrence could be associated with the fluctuation of fine solid contents in the feed.

Optimization of iron-based catalyst for partial upgrading of Athabasca Bitumen: The role of Fe oxidation state, particle size, and concentration

The present investigation examines the prospective application of Fe-based catalysts for catalyzing the partial upgrading of Athabasca oil sand bitumen, aiming for developing an economically viable and environmentally sustainable process. The primary focus is to analyze the impact of the oxidation state of iron, catalyst particle size, and catalyst concentration on partial upgrading efficiency to optimize bitumen resource utilization without the need of an external source/supply of hydrogen gas using an autoclave reactor. The experimental results demonstrate that Fe-based catalysts, particularly those with lower oxidation states such as FeS, FeO, and Fe3O4, significantly improve the oil quality and reduce bitumen’s viscosity through increasing saturates and substantially reducing the asphaltene fractions. Furthermore, it is also identified that those catalysts can promote hydrogenation and cracking reactions that transform heavier fractions into lighter ones while achieving up to 59% vacuum residue conversion. A comprehensive screening process using Minitab statistical software was made to identify the best catalyst based on the catalyst’s oxidation state, concentration, and particle size range. As a result, Fe3O4 nanoparticles at a 0.5 wt% loading have been identified as the optimal catalyst combination for achieving the maximum liquid yield, while simultaneously producing the minimum asphaltene content, and maximum viscosity reduction. An assessment of the fresh and spent Fe3O4 catalyst yielded valuable insights concerning the catalytic partial upgrading of bitumen, unveiling a reaction mechanism involving iron catalyst sulfidation, desulfurization reactions, CH scission, and hydrocarbon cracking, in addition to the formation of coke. The potential role of various alloy materials employed in the fabrication of reactors for bitumen partial upgrading has also been studied and compared, discussing their unique advantages and limitations in terms of product quality and liquid yield. The findings presented in this study contribute significantly to the development of more efficient and sustainable upgrading processes, paving the way for optimizing catalyst properties for bitumen upgrading applications and providing a valuable perspective on the role of catalysts in the upgrading of heavy oils.

Virgin Heavy Gas Oil from Oil Sands Bitumen as FCC Feed

This study deals with a systematic investigation of the fluid catalytic cracking (FCC) performance of a bitumen-derived virgin heavy gas oil (HGO) in the presence of its counterpart from bitumen-derived synthetic crude oil (SCO). The objective is to determine the amelioration effect on yield and product slate by the addition of the premium SCO HGO. The 343–525 °C cut virgin bitumen HGO was obtained from distillation of a raw Athabasca oil sands bitumen. It was then blended with different amounts of the 343 °C+ fraction of commercial SCO. Four HGO blends were prepared containing 75, 64, 61, and 48 v% of SCO HGO. Each HGO blend, as well as 100% SCO HGO, were catalytically cracked at 500 and 520 °C using a bench-scale Advanced Cracking Evaluation (ACE) unit. The results show acceptable FCC performance of bitumen virgin HGO when an adequate amount of SCO HGO is added. However, the resulting liquid product may need some quality improvement before use. Several observations, including catalyst poisoning by feed nitrogen and the refractory nature of virgin HGO, are evident and help to explain some observed cracking phenomena.

Uncatalyzed Hydrogen Transfer during 100–250 °C Conversion of Asphaltenes

The reactivity and reactions of asphaltenes were explored over the temperature range 100–250 °C following reports of reactivity and meaningful free radical content in asphaltenes. This study employed industrial pentane precipitated asphaltenes from Athabasca oilsands bitumen. The presence of free radicals in the asphaltenes feed was confirmed. On heating the asphaltenes to 150 °C, the aromatic hydrogen content increased relative to the feed by a factor 1.12. It was also found that on heating the asphaltenes to 150 °C the n-heptane insoluble fraction increased from 67% to 75%. Almost no gas phase products were produced. The observed changes were ascribed to hydrogen transfer reactions and addition products formed by combination reactions. Direct evidence of hydrogen transfer reactions taking place in the asphaltenes was obtained through the use of the model systems, α-methylstyrene and cumene, as well as anthracene and 9,10-dihydroanthracene. The extent of hydrogen transfer was of the order 1.8 mg H/g asph...

Kinetic study on the nonisothermal pyrolysis of oil sand bitumen and its maltene and asphaltene fractions

Pyrolysis is an important conversion process which can produce high value-added light oils from unconventional oils such as oil sand bitumen and extra heavy oil, thus it is important to understand the characteristics and kinetics of pyrolysis for unconventional oils. In this study, the nonisothermal pyrolysis of Athabasca oil sand bitumen and its maltene and asphaltene fractions was analyzed using a thermogravimetric analyzer, and activation energies for pyrolysis were determined by the model-free isoconversional Friedman analysis. The analysis suggests that the pyrolysis of oil sand bitumen consists of reactions for volatilization of maltene fraction and cracking of maltene and asphaltene fractions. The pyrolysis behavior of oil sand bitumen was well described based on the kinetic parameters estimated by the distributed activation energy model for maltene and asphaltene fractions, which is beneficial to effective utilization and development of pyrolysis processes of oil sand bitumen.

Asphaltene adsorption on quartz sand in the presence of pre-adsorbed water

Background and hypothesisIn the oil industry, asphaltenes are known for their tendency to aggregate in solution and to deposit on surfaces, with both properties being connected with operational problems associated with recovery, production and refining. Interactions involving asphaltenes and other crude oil components have been a major aspect of investigation in attempting to understand the full nature of these problems. Water is implicated in asphaltene behavior in solution, for example, where it has been found to delay the deposition of asphaltene aggregates. At interfaces, there is evidence that water-in-crude oil emulsion stability is enhanced through asphaltene-water interactions, and there have been a few reports that asphaltene adsorption on mineral surfaces is reduced in the presence of water. We consider the latter aspect, because the instances of reduced adsorption to date have not attempted to quantify the effect. Previous studies showed that vapor-phase adsorption of organic molecules is reduced in the presence of pre-adsorbed water and we were interested to determine whether the same is true for liquid-phase adsorption of asphaltenes. ExperimentsThe surface of quartz sand was controlled by pre-adsorption of water from different relative humidity (RH) environments as the water adsorption isotherm is known from previous studies. These pre-conditioned sand samples were used as substrates for the adsorption from toluene solutions of n-heptane-precipitated asphaltenes (C7A) from an Athabasca oil sands bitumen. To supplement the adsorption behavior, atomic force microscopy (AFM) images were taken of the resultant sand grains at 0 and 80% RH, and low-field NMR was used to estimate the sand wettability. FindingsAsphaltene adsorption on sand is sensitive to surface-adsorbed water, with ∼4-fold reduction in adsorption when increasing the RH from 0 to 100%. This is in general agreement with previous vapor-phase adsorption of small organic molecules, and is therefore believed to be the first demonstration of the effect of pre-adsorbed water on adsorption from solution. Asphaltene adsorption as a function of RH is the converse of literature water adsorption isotherm data. Three asphaltene adsorption regions have been tentatively identified based on water adsorption behavior and the literature interpretation of water structure on quartz: the highest asphaltene adsorption occurs at very low RH, decreasing to a near-constant value in the range ∼40–80% RH, followed by a rapid decrease beyond 80% RH. Further analysis strongly suggests that asphaltene adsorption decreases linearly with the thickness of the adsorbed water film. The effects of RH on asphaltene adsorption are also reflected in AFM images and NMR wettability results.

Comparison of Thermal Cracking Processes for Athabasca Oil Sand Bitumen: Relationship between Conversion and Yield

This study compared various thermal cracking processes for Athabasca oil sand bitumen according to the relationship between vacuum residue (VR) conversion and the product yield for each process, using reported data. The conversion was defined as the fraction of VR that was converted to lighter products. The conventional processes examined were visbreaking, delayed coking, and fluid coking, and the developing processes were high conversion soaker cracking (HSC), heavy to light (HTL), IYQ, Eureka, and supercritical water cracking (SCWC). HSC and SCWC were higher severity visbreaking-type processes with conversions of 0.49 and 0.39–0.50, respectively. HTL and IYQ (recycle) were lower severity fluid coking-type processes with a conversion of 0.52. IYQ (once through) and Eureka showed the highest conversions (0.62–0.68). Supercritical water (SCW) upgrading was operated experimentally at higher severity, with a conversion of 0.64, and showed the highest yield of distillate product (DP) among all thermal cracking processes investigated. Analysis of the conversion–yield relationship revealed the thermal cracking behavior of Athabasca bitumen. The key for achieving higher conversions with lower coke yield was considered to be efficient mass transfer of the volatile fraction stripped away from the condensed phase, which is a liquid fraction at the experimental condition. The condensed-phase decomposition showed an upper limit of conversion of 0.55, and that with a high mass-transfer system exceeded 0.65.

On the Role of Water in Natural-Zeolite-Catalyzed Cracking of Athabasca Oilsands Bitumen

Water addition to natural-zeolite-catalyzed reactions significantly improves cracking of oilsands bitumen compared to analogous reactions in the absence of water. We report that the addition of 3% water to the catalyzed cracking reactions results in samples with lower viscosities and average molecular weights, less residue, olefin, and coke formation, and higher C2+ gas production compared to analogous reactions in the absence of water. Our study suggests that untreated natural zeolites undergo self-acidification by hydrolysis reactions in the presence of water. Fourier transform infrared spectroscopy and solid-state NMR analyses detected the presence of acid −OH groups on the raw untreated chabazite and clinoptilolite surfaces that are capable of supplying protons to initiate carbocation reactions. Stable isotopic mass spectrophotometric analyses on bitumen on D2O-doped catalytic reactions confirm up to ∼56% hydrogen incorporation from added water to the liquid products. Aromaticity and proton and deuter...

Froth Treatment in Athabasca Oil Sands Bitumen Recovery Process: A Review

Bitumen froth treatment is an integrated process step in the Athabasca oil sands bitumen recovery operations. Its objective is to separate mineral solids and water from the bitumen froth. The bitumen froth is diluted with naphthenic or paraffinic solvents to lower its viscosity to facilitate the separation; therefore, bitumen froth treatment is the removal of inorganics (mineral particles and water droplets) from a bitumen organic solvent solution. The micrometer sized mineral particles (mainly clays) and water-in-oil emulsion droplets are the most difficult to remove from the bitumen froth. Research has been carried out that has led to an understanding of the formation, stabilization and properties of the water-in-oil emulsions in the bitumen organic solvent solution. It is known that the water-in-oil emulsions are formed by water entrained into the bitumen froth during the water-based extraction process and stabilized by natural surfactants in bitumen (especially asphaltene) and fine mineral particles. ...

Viscosity Reduction and Upgrading of Athabasca Oilsands Bitumen by Natural Zeolite Cracking

Oilsands bitumen is an extremely important source of energy for North America. However, due to the presence of large molecules such as asphaltenes, the density and viscosity of the bitumen recovered from these sands are much higher than those of conventional crude oil. As a result the extracted bitumen has to be diluted with expensive solvents, or thermochemically upgraded in large, capital-intensive conventional upgrading facilities prior to pipeline transport. This study demonstrates that globally abundant natural zeolites such as clinoptilolite from Saint Clouds, New Mexico and Ca-chabazite from Bowie, Arizona can be used as very effective reagents for cracking and visbreaking of oilsands bitumen. Natural zeolite cracked oilsands bitumen products are highly recoverable (up to ~ 83%) using light hydrocarbons such as pentane, which indicates substantial conversion of heavier fractions to lighter components. The resultant liquid products are much less viscous, and have lighter product distribution compared to those produced from pure thermal treatment. These natural minerals impart similar effect on industrially extracted Athabasca bitumen.

Characterization of Sulfide Compounds in Petroleum: Selective Oxidation Followed by Positive-Ion Electrospray Fourier Transform Ion Cyclotron Resonance Mass Spectrometry

A novel analytical method for identifying sulfides in petroleum and its fractions was developed. Sulfides in petroleum were selectively oxidized into sulfoxides using tetrabutylammonium periodate (TBAPI) and identified by positive-ion electrospray ionization (ESI) Fourier transform-ion cyclotron resonance mass spectrometry (FT-ICR MS). A variety of model sulfur compounds were examined to evaluate the selective oxidization and ionization efficiencies for sulfur compounds in petroleum. Two fractions, straight-run diesel and saturates of Athabasca oilsands bitumen were investigated using this approach. The oxidization process was highly selective for sulfides from thiophenes and aromatic hydrocarbons. Oxidation generated sulfoxides were ionized by positive-ion ESI and analyzed by FT-ICR MS. Mass spectra revealed the composition characteristics of sulfides in the diesel by contrasting the double bond equivalence (DBE) and carbon number distribution of sulfur compounds before and after oxidation. The abundant sulfides in the straight run diesel and saturates fraction of oilsands bitumen had DBE values of 1-3 and 1-4, respectively.

Hindered diffusion of residue narrow cuts through polycarbonate membranes

AbstractHindered diffusion plays an important role in catalytic processing of residue and heavy oil because of large size molecules in these feedstocks. Vacuum residue of Athabasca oil sand bitumen was fractionated into 13 narrow fractions and an end‐cut by supercritical fluid extraction and fractionation (SFEF). Diffusion transport of five SFEF cuts through four polycarbonate membranes was investigated using a diaphragm cell at 308 K. The results showed that diffusion coefficients of the five SFEF cuts decreased as the experiment proceeded, which illustrates that these cuts are polydisperse in size. The effective diffusion coefficients varied with molecular size and pore size. Hindered diffusion of the five SFEF cuts is significant in the membranes with nominal pore diameter of 15 nm, which is around the average pore size of typical hydrotreating catalyst. Comparisons between experimental data and theoretical prediction revealed that the actual hindered degree for diffusion of the five SFEF cuts is higher than that calculated by the Renkin equation. There were slight differences in diffusivity among saturate, aromatic, and resin constituents. © 2010 American Institute of Chemical Engineers AIChE J, 2010

Stability of THAI ™ Process-Theoretical And Experimental Observations

Abstract The performance of the THAI ™ process has been investigated in numerous 3D experiments, using heavy crudes and Athabasca oil sands bitumen. The stability of the process is demonstrated by high combustion zone temperatures, absence of gas channelling, insensitivity to large changes in air injection rate, tolerance of an overlying gas cap, increased combustion temperature and faster upgrading response with increasing oil layer thickness, 'controlled gas override', own 'front tracking' capability and steady oil production rate. The most important parameters for upscaling of (stable) experimental scale performance to (stable) field scale operation are combustion front temperature and combustion front velocity. Early stage results from the WHITESANDS THAI ™ field pilot at Christina Lake, confirm high combustion zone temperatures (700 – 800 °C), high fluids production of up to 2,000 barrels per day of gross fluids (50 – 55% bitumen cut) and signs of significant partial upgrading (up to 8.2 °API). These measures of field pilot performance are consistent with the experimental findings from 3D physical experiments. They are very encouraging indicators for the future development of THAI ™on a commercial scale. Introduction There is a long and tortuous history concerning the in situ combustion (ISC) process as applied to heavy crude and oil sands reservoirs. Some parts of it were tremendously innovative and successful, but there were also many failures, often due to poorly chosen reservoirs. One of the main reasons why projects failed was lack of control of propagation of the in situ combustion front. In many cases, there was a lack of understanding of the part played by gravity, and hence gravity segregation. Since the first field test of the ISC process in 1951, more than 160 field pilots have been conducted; most of them in the period 1970 – 1990. This led to the development of both the dry and wet ISC processes. They were tested for normal heavy oil and for oil sands using air and enriched air. However, the commercial application of ISC was attained only for heavy crude reservoirs around 1970, using air injection. At that time, most operators started to realize that ISC was actually a gas displacement process, benefiting from oil viscosity reduction due to heat generated by ISC reactions. Therefore, as in any gas displacement process, the injectors should be located at the most updip position. As of April 1992, according to an Oil & Gas Journal report, the incremental daily production from ISC was approximately 4,700 BOPD (from eight projects) in the USA, 8,000 BOPD (from ten projects) in the former Soviet Union, 7,300 BOPD (from three projects) in Canada and 12,000 BOPD (from five projects) in Romania. Thus, the 1992 world incremental daily oil production due to ISC was about 32,000 BOPD (from 26 reported projects)(1, 2). This included nineteen commercial operations and seven semi-industrial projects. Currently, only four commercial heavy oil projects are active: Suplacu de Barcau (Romania), Balol and Santhal projects (India) and Bayou State Oil Corp. (BSOC) in Bellevue, Louisiana, USA.

Production of Activated Carbon from Athabasca Oilsands Bitumen

The carbonization process of the pentane insoluble (end-cut) fraction from Athabasca oilsands bitumen in the presence NaOH has been investigated. Chemical activation produced carbon with a well-developed mesoporous structure and a much reduced sulfur content. The yield of the activated carbon increased, whereas sulfur content decreased with an increase in the NaOH load. Physical activation with carbon dioxide resulted in significant improvement in surface area. The properties of an activated carbon produced from end-cut were compared with those for carbon derived from fluid coke. Compared to fluid coke, end-cut is more suitable in the preparation of the carbon with low sulfur content and high mesopore surface area.

Characterization of a coker gas oil fraction from athabasca oilsands bitumen

Bitumen derived gas oils have unique properties and are difficult to hydrotreat. These gas oils also significantly deactivate conventional catalysts; new, alternative catalysts have shown only limited improvements. The key for process and quality improvements is a better understanding of the molecular chemistry of gas oil. The approach applied in this work involves a combination of gas oil fractionation by high performance liquid chromatography (HPLC) and analysis of the resulting fractions by advanced spectroscopic methods. Results show that the HPLC saturate fraction is practically free of aromatic components. The nominal mono- and di-aromatics fractions differ in that the former has a higher molecular weight and H/C ratio but lower aromaticity and heteroatom content. The HPLC three poly-aromatic sub-fractions comprise molecules with an average of only two aromatic rings. Also, the H/C ratio and aromaticities of these samples are virtually the same. Regardless of their structural resemblances they differ substantially in their HPLC elution behaviour. This can be attributed to the differences in their oxygen and, especially, nitrogen contents. The asymmetric distribution of nitrogen may allow its selective removal thus opening the possibility for less expensive treatment, especially in terms of catalyst utilisation.

Diesel quality and molecular structure of bitumen-derived middle distillates

Six to seven narrow fractions from each of six light gas oils obtained from various upgrading processes of Athabasca oilsands bitumen were evaluated as diesel fuels. The relationships among the boiling range, cetane number (CN), and aromatics content were investigated. The correlation between CN and aromatic content of narrow-cut fractions showed three trends; i.e. (1) CN increases as aromatics increase; (2) CN decreases as aromatics increase; and (3) a mixed trend of both. In order to investigate such trends, the narrow-cut samples were separated into saturate and aromatic fractions using HPLC, and analyses of type distribution and average molecular structures were carried out. CN of narrow cuts was estimated from the type distribution and CN data for pure compounds. From the H/C atomic ratio, each narrow-cut sample was represented by six types of compounds, i.e. alkanes, mono- and dicycloalkanes, alkyl and naphthenic benzenes, and diaromatics. The average molecular structures for those types had 4–5 branches. The CN trend of the narrow-cuts were reproducible at a certain assumption from the CN of the average molecule structure by type estimated from the CNs of pure compounds. It was found that for the prediction of CN, not only aromatic content but also hydrocarbon types of saturates are important.

Studies of Athabasca asphaltene Langmuir films at air–water interface

Asphaltenes are present in heavy oils and bitumen. They are a mixture of hydrocarbons having complex structures of polyaromatic rings and short side chains. In general, the high-molecular-weight asphaltene is the most aromatic fraction with the highest number of side chains and the low-molecular-weight asphaltene contains the lowest number of side chains, while the number of side chains of the whole asphaltene fraction lies in between. In this study, asphaltenes were extracted and/or fractionated from Athabasca oil sand bitumen. Subfractions of high and low molecular weight and the whole asphaltenes were characterized using a Langmuir trough and complementary techniques such as VPO, FTIR, AFM, and contact angle measurements. At an air–water interface, amphiphilic asphaltene molecules can form a monolayer. Various fractions (high, low, and whole) of the asphaltene molecules behave similarly at the air–water interface, characterized by close resemblance of their surface pressure–area, hysteresis, and relaxation isotherms. The high-molecular-weight asphaltene is the most expanded fraction, while the low-molecular-weight asphaltene fraction is the most condensed, with the whole asphaltene lying in between. At the air–water interface a monolayer of the low-molecular-weight asphaltene relaxes at a faster rate than one of the high-molecular-weight asphaltene.

Catalyst Development for Hydrothermal Cracking of Heavy Oil. Effects of Support and Potassium Salt Additive.

Hydrothermal cracking of a Canadian Athabasca oil sand bitumen was conducted in a batch autoclave at 673 to 713K under 1.0 to 5.0MPa hydrogen to determine the most favorite reaction conditions. Various catalysts were prepared using MgO, activated carbon, SiO2 and Al2O3 as the support, and Ni as active metal, to investigate the catalytic activity for the hydrothermal cracking of the oil sand bitumen. The basic MgO and neutral activated carbon supported catalysts showed lower coke yields than the acidic SiO2 supported catalyst. Coke and gas yields were reduced when the Ni/SiO2 catalyst was doped by 1wt% potassium salt.

Combustion/Oxidation Behavior of Athabasca Oil Sands Bitumen

Summary Oils that are potential candidates for in situ combustion recovery processes are often screened by means of their oxidation characteristics: in particular, the kinetics of the ignition process and the transition from low-temperature to high-temperature oxidation through what is known as the "negative temperature gradient region." These characteristics are readily studied in ramped-temperature oxidation tests, which involve the controlled heating of recombined, oil-saturated cores in a one-dimensional plug flow reactor under a flowing stream of air (or oxygen-containing gas). The purpose of these tests is to study the global oxidation behavior and reaction kinetics under controlled conditions, with the end purpose of providing realistic data for incorporation into a numerical simulator which can be used to predict field performance. A ramped-temperature oxidation apparatus was used to conduct a detailed, two-year parametric study of the oxidation characteristics of Athabasca Oil Sands bitumen. The text matrix involved various levels of pressure, gas injection rate, oxygen content of the injected gas, and maximum ramp temperature. This paper details the principal findings for the 45-test study; especially the need to maintain high reaction temperatures (> 380° C) in order to mobilize and produce heavy oils under conditions of dry in situ combustion. Design considerations and operational guidelines for successful field projects arising from the results of this study are also discussed.

Ramped Temperature Oxidation Analysis of Athabasca Oil Sands Bitumen

Abstract Oils that are potential candidates for in situ combustion recovery processes are often screened by means of their oxidation characteristics; in particular, the kinetics of the ignition process and the transition from low temperature to high temperature oxidation through what is known as the "negative temperature gradient region." A ramped temperature oxidation apparatus, consisting of two identical tubular reactors mounted in a common heating block, was developed to observe these characteristics. The active reactor contained core which was saturated with oil and water, while the reference reactor contained only clean core. Inert gas was flowed through the reference reactor and an oxygen-containing gas was flowed through the active reactor while both were simultaneously heated at a fixed rate. Measured temperatures from the reactors, and produced gas composition and post test core analysis of the active reactor, allowed determination of the oxidation mode and transition behaviour. The apparatus was used to conduct a detailed parametric study of the oxidation characteristics of Athabasca Oil Sands bitumen. The test operating procedure matrix involved various levels of pressure, gas injection rate, oxygen content of the injected gas and maximum ramp temperature. The principal finding from the 45 test study was the need to maintain high reaction temperatures (>380 ° C) in order to mobilize and produce heavy oils and bitumens under conditions of dry in situ combustion. Introduction In order to successfully recover heavy oils and bitumens using the in situ combustion process, an accurate knowledge of the process kinetics is required; in particular, the reactions that can occur between the oxygen and the oil. Two different oxygen-oil reaction regimes are important when discussing in situ combustion. At one end of the spectrum is high temperature oxidation or combustion, which is characterized by fast, bond scission type reactions that produce carbon oxides, water, energy, and, in the case of laboratory in situ combustion experiments, temperatures in excess of 400 ° C. On the other extreme, low temperature oxidation reactions are not as easy to characterize, but generally involve relatively slower oxygen addition type reactions that produce variable amounts of carbon dioxide, with temperatures generally below 350 ° C. Researchers such as Martin et al.(1), Alexander et al.(2), Bousaid and Ramey(3), Burger and Sahuquet(4), Dabbous and Fulton(5), and Fassihi et al.(6) developed equipment which was used to evaluate both low and high temperature oxidation kinetics involving native oils and petroleum cokes. Differential thermal techniques such as DTA, TGA and PDSC were successfully applied for examining oxidation kinetics; however, as was pointed out by Nickle et al.,(7) care is required when translating these experiments to correlate with either combustion tube or field experiments. Despite the high quality of the research performed to date, two important deficiencies remain in the area of oxidation kinetics. The first is that nearly all of the existing numerical models of in situ combustion have focussed solely on the high temperature reactions and have not allowed for the possibility of operation in a low temperature mode.