Low temperature oxidation (L TO) has long been recognized as one of the dominant mechanisms controlling fuel availability in in-situ combustion. Its effect on the physical properties of crude oils is also well known. In spite of these fmdings, the prevailing conceptual model of in-situ combustion still hinges on thermal cracking (in isolation) ahead of the firefront, to provide sufficient fuel (coke) for propagation of the reaction zone. Previous simulation studies, which purported to include L TO as part of the reaction scheme, have unrealistically specified the reaction products as carbon oxides and water. Furthermore, oil compositional changes due to oxidation have been completely neglected.This paper describes a unified pseudo-mechanistic reaction model for mathematical modeling of in-situ combustion of Athabasca bitumen. The model represents a consolidation of individual experimental kinetic studies on thermal cracking and low temperature oxidation of Athabasca bitumen, and reported data for the high temperature oxidation of coke. The formulation is comprehensive in that it allows bitumen to undergo density and viscosity increases, as well as reduced reactivity to oxidation, with increased oxidation extent. Hydrocarbon bypassing due to quenching of the combustion front is also permitted with the proposed kinetic model.The paper includes application of the reaction model in numerical simulations of adiabatic combustion tube tests performed on Athabasca bitumen. A significant feature of the model is its ability to predict the dual oxidation uptake peaks associated with ramped temperature oxidation experiments.

Aquathermolysis experiments over the temperature range 360 to 422 ºC were performed on core samples taken from three large bitumen and heavy oil deposits found in Alberta: Athabasca, North Bodo, and Frisco Countess. The purpose of this work was to facilitate the development of comprehensive thermal cracking models for predicting gas and liquid phase product distributions under conditions anticipated during thermal recovery. Previous studies. have shown by material balance on oxygen that water is implicated in many of the chemical reactions leading to the formation of H2S and CO2, yet most of the reported thermal cracking studies have not included water. Additionally, experimental investigations in this area have, for the most part, not involved realistic time frames, and as such certain phenomena observed in this work have not been previously reported. The experiments conducted using Athabasca bitumen included runs with an initially previously oxidized oil sample (designed to simulate conditions preceding the arrival of the firefront during in situ combustion) and runs with a change in core mineralogy. Pre-oxidizing the oil was found to substantially increase the amount of H2 generated. Core mineralogy played an important role in the generation of CO2; and the amount of H2S produced was. dependent on oil composition, mineralogy, and time. Gas production was observed to be largely associated with the conversion of the heavy. oil and asphaltenes oil fractions. The cracking models developed in this work offer useful directional insight as to the effect of core mineralogy and oil composition on the kinetic parameters, and a much needed means of estimating the calorific value and acidic gas content of the produced gases during thermal recovery operations. Introduction The purpose of this work was to develop thermal cracking models capable of describing the liquid and gas phase compositional changes that occur during thermal recovery operations. Although rather extensive laboratory studies have been performed concerning the thermal cracking of heavy oils and bitumen, few in comparison have included water as part of the reactants. Laboratory studies(1, 2, 3) and field applications of thermal recovery processes(4) have demonstrated that appreciable amounts of gaseous environmental contaminants such as H2S and CO2 arecreated by the aquathermolysis (steam/oil reactions) of heavy oils. hese problems are all the more severe as the sulphur and oxygen content of the oil increases(5). It has also been demonstrated(2) that H2 and light saturated hydrocarbons are also produced by steam/oil reactions over the temperature range 200 to 300 ºC. Accordingly, casing gas produced from cyclic steam stimulation projects has sometimes been collected and condensed yielding between 0.015 and 1.5 m3 of condensate per well per day(6), with the noncondensible gas (which contains mostly methane) being used as a supplementary fuel for the steam generators. Thus, aside from the pollution aspect there is the potential to recover chemical energy from the effluent gases. In this paper we present thermal cracking models based on aquathermolysis experiments performed on core samples from three large bitumen and heavy oil deposits in Alberta: Athabasca, North Bodo, and Frisco Countess. The oils from these deposits have contrastingly different elemental compositions and API gravities. For the experiments involving Athabasca oil sands we report on three sets of tests: two involving significantly different core minera

Several processing options have been developed to accomplish near-well-bore in-situ upgrading of heavy crude oils. These processes are designed to pass oil over a fixed bed of catalyst prior to entering the production well, the catalyst being placed by conventional gravel pack methods. The presence of brine and the need to provide heat and reactant gases in a down-hole environment provide challenges not present in conventional processing. These issues were addressed and the processes demonstrated by use of a modified combustion tube apparatus. Middle-Eastern heavy crude oil and the corresponding brine were used at the appropriate reservoir conditions. In-situ combustion was used to generate reactive gases and to drive fluids over a heated sand or catalyst bed, simulating the catalyst contacting portion of the proposed processes. The heavy crude oil was found to be amenable to in-situ combustion at anticipated reservoir conditions, with a relatively low air requirement. Forcing the oil to flow over a heated zone prior to production results in some upgrading of the oil, as compared to the original oil, due to thermal effects. Passing the oil over a hydroprocessing catalyst located in the heated zone results in a product that is significantly upgraded as compared to either the original oil or thermally-processed oil. Catalytic upgrading is due to hydrogenation and results in about a 50% sulfur removal and an 8°API gravity increase. Additionally, the heated catalyst was found to be efficient at converting CO to additional H 2 . While all of the technologies needed for a successful field trial of in-situ catalytic upgrading exist, a demonstration has yet to be undertaken.

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Aquathermolysis experiments were performed on core samples taken from three large bitumen and heavy oil deposits found in Alberta, to investigate gas evolution over the temperature range 360 to 420°C. Experiments conducted on Athabasca included runs with an initially pre‐oxidized oil sample and runs with a change in core mineralogy. Pre‐oxidizing the oil was found to substantially increase the amount of carbon monoxide and molecular hydrogen generated. Core mineralogy played an important role in the generation of carbon dioxide, and the amount of hydrogen sulphide produced was dependent on oil composition, mineralogy and time. Although substantial amounts of gaseous products are produced by simple thermolysis reactions (i.e., without water present), the main thermal recovery methods, steam injection and in‐situ combustion, bring the oil phase and its host rock into direct contact with water. As water has been shown to take part in thermal cracking reactions, these experiments provide usful data for the estimation of produced gas composition during thermal recovery projects.