High Pressure Air Injection (HPAI) is an Improved Oil Recovery (IOR) technique in which compressed air is injected into light oil, high-pressure reservoirs. The objective of this process is the oxygen from the injected air reacts with a small fraction of the reservoir oil at an elevated temperature to produce a mixture of carbon dioxide and nitrogen. The produced gas flowing from the reaction region mobilizes the oil downstream of the reaction zone towards the production wells. Knowledge of the oil's oxidation behaviour is a key to the successful implementation of this process. However, information on oxidation behaviour of oils based on their compositions is limited, especially for light oils. An experimental study was designed to examine the oxidation behaviour of three crude oils (a light oil, a medium oil, and an Athabasca bitumen) by using the Pressurized Differential Scanning Calorimeter (PDSC) at pressures from 110 to 6,894 kPa. Pure hydrocarbon aromatics and paraffin samples were also selected for the current study. The study shows an increase of pressure results in an increase in the rate of oxidation reactions and heat released from the oxidation reactions. The PDSC heat flow curves also clearly demonstrate the effect of chemical structure of the samples on their oxidation behaviour. The extent of oxidation of hydrocarbon samples is strongly dependent on the nature of the hydrocarbon. Introduction Air injection continues to be an important oil recovery process, used to increase both the amount and the rate of oil recovered from a petroleum reservoir(1,2). When air is injected into a light oil reservoir, exothermic chemical reactions occur between the reservoir oil and the oxygen contained in the injected air. The reactions are mainly oxidation reactions resulting in heat generation and the production of carbon dioxide, carbon monoxide, and water corresponding to the consumption of oxygen. The heat of reactions results in a temperature elevation leading to vapourization of some lighter components and a decrease of viscosity of the oil, even though the heat effect is not very important for light or medium oil compared to heavy oil. Therefore, the driving gas, which can sweep the oil to production wells, is not the injected air but an in situ-generated flue gas, composed of CO, CO2, N2, and vapourized light hydrocarbon components. Air injection is a complex process involving simultaneous heat and mass transfer in a multiphase environment coupled with oxidation chemical reactions. Oxidation reactions play an important role in this process. In order to improve the efficiency of the air injection process, it is necessary to have additional knowledge of the factors influencing the process and how they affect the oxidation of oil. In recent years, the application of thermal analysis techniques, thermogravimetry (TG/DTG), and differential scanning calorimetry (DSC) have obtained wide acceptance in the study of combustion behaviour of oil. Attempts to use thermal analysis techniques to study crude oil combustion began with Tadema(3).
The research described in this paper was conducted in support of a more extensive study that has been ongoing at the University of Calgary to quantify the effect of the presence of low levels of oxygen in the unheated portions of an Athabasca Reservoir undergoing in situ combustion, and to evaluate if low temperature oxidation reactions could be used to achieve in situ upgrading. The objective of the overall program was to understand the compositional changes that might occur at temperatures ranging from those of the native reservoir to those experienced in a steam injection oil recovery process. The research program was originally started to quantify what were anticipated as detrimental compositional changes when oil is oxidized at native reservoir temperatures. The program was then extended to quantify the possible enhancement of the rate of cracking which might be achieved by oxidizing the oil at low temperatures, then heating it to temperatures typical of a steam injection operation. This paper will concentrate on the compositional changes of Athabasca bitumen in contact with nitrogen and air. The experiments were performed in an oscillating batch reactor with or without core and synthetic brine. The rate of oscillation was evaluated as a parameter to examine the role of mass transfer rates. Viscosity is reported in addition to the compositional data expressed in terms of the components: maltenes, asphaltenes, and coke. The data has direct applicability to recovery processes involving the injection of air or a gas containing oxygen as an impurity. Typical applications of this nature include in situ combustion, flue gas injection, and replacement of a gas cap with air or injection of CO2 containing oxygen as an impurity. Introduction Historically, the petroleum industry has tried to improve the recovery rate of heavy oils and oil sands that have reserves three times those of conventional oil reservoirs(1), but cannot be produced by conventional means. Current methods used to improve in situ bitumen production are cyclic steam stimulation and steam assisted gravity drainage. Steam injection increases the temperature in the reservoir, thereby reducing the bitumen viscosity and increasing its mobility. Sustained steam injection faces the obstacles of water availability, high natural gas costs, and air quality, hence air injection is again being considered as a method for in situ energy generation. In order to develop realistic designs for air injection or in situ combustion projects in bitumen reservoirs, it is necessary to understand the various reactions that are involved. Three major reactions have been reported when in situ combustion (ISC) is utilized:thermal cracking;liquid phase low temperature oxidation (LTO); and,high temperature oxidation (HTO) of vapour, liquid, and solid hydrocarbon fractions. Low temperature oxidation and thermal cracking reactions are associated with immobile fuel deposition during the in situ combustion process. Low temperature oxidation reaction (LTO) is the terminology used to describe the oxygen addition reactions that occur in the liquid phase of oils. The temperature range over which these reactions occur extends from the reservoir temperature up to a nominal limit of 300 °C. Low temperature oxygen addition reactions may occur simultaneously with bond scission reactions, which occur in the vapour phase at a temperature range of 150 to 300 °C. The transition between the temperatures where low temperature oxidation and high temperature oxidation are dominant is called the negative temperature gradient region (NTGR). This is the temperature range over which the global oxy
A light oil (API 30 º) reservoir is an excellent candidate for high pressure air injection, but the oil is not believed to be capable of self-ignition at the reservoir temperature. Several chemical additives and catalysts are studied to evaluate their effectiveness of ignition improvement for this light oil sample. Pressurized Differential Scanning Calorimetry (PDSC) and Accelerating Rate Calorimetry (ARC) experiments are examined in this study. The oil sample, which is mixed with certain catalysts and chemical additives, is subjected to a controlled heating schedule under a constant flow rate of air at 4.14 MPa (600 psig) and 13.8 MPa (2,000 psig) pressure for the PDSC and ARC tests, respectively. The amount and rate of heat released by the oxidation reactions is analyzed for those tests. In the presence of a metallic catalyst and chemical initiators, oxidation behaviour of the oil tested is dramatically improved. Also observed are a significant reduction in the onset temperature of significant exotherm and an increased rate for the release of heat. Introduction Air injection has been proven as a viable process in improving oil recovery from light oil reservoirs, and as a result, it has received much interest in recent years(1, 2). The concept of recovery increment is when air is injected into a light oil reservoir and exothermic chemical reactions occur. The desired reactions result in heat generation and the production of carbon dioxide. Downstream of the reaction zone, the combustion produced gas sweeps oil toward the production wells, combining with light hydrocarbon fractions vapourized by heat released from oxidation reactions. Therefore, incremental oil production is achieved. However, air injection for a light oil reservoir is a complex process involving simultaneous heat and mass transfer in a multiphase environment coupled with oxidation chemical reactions. Ignition is the first phase of this process and a satisfactory ignition is of prime importance in initiating a successful air injection process(2). In high temperature reservoirs, the air injection process is initiated by injecting air, which may spontaneously ignite the oil-in-place(1). However, in some cases, spontaneous ignition of the reservoir oil is not likely to occur so that several artificial means have been implemented(3), including down hole electrical heaters, a gas burner or injection of steam, but it is highly desirable to avoid having to run heaters or burners when air injection is to be applied in deep, high pressure reservoirs. As a result, chemical ignition is proposed(2). The concept of chemical ignition is where a slug of chemicals with reactive oxidation characteristics is injected into an oil bearing zone prior to the injection of air from an injector. If heat released from an oxidation reaction is continually generated at a rate greater than it is dissipated, starting at the native reservoir temperature, oil can be spontaneously ignited without the application of artificial means. The reactive nature of the base oil present in the ignition zone can be enhanced or stimulated. A spontaneous ignition may occur within the formation. Bednarski(4) reported on a chemical ignition improvement experiment.
High Pressure Air Injection (HPAI) is an improved oil recovery process in which compressed air is injected into typically deep, light oil reservoirs. Part of the oil reacts exothermically with the oxygen in the air to produce flue gas (mainly composed of nitrogen, carbon dioxide and water). Literature explaining the reaction mechanisms and phase interactions is available. Nevertheless, little effort has been devoted to describing gas, oil and water three-phase flow behaviour under HPAI reservoir conditions. Three coreflood experiments were conducted on Berea sandstone core. The first experiment consisted of injecting flue gas into core at initial oil and connate water saturations to obtain liquid-gas relative permeability data. The second experiment was designed to evaluate oil re-saturation, after gas sweep, simulating an HPAI thermal front. The third experiment consisted of gas displacing both oil and water completing the data necessary to plot the three-phase relative permeability curves. Reservoir simulation was used to adjust relative permeability curves and hysteresis parameters by matching the pressure drop and production data. Introduction It is well-known that the oil recovery mechanisms in HPAI are a combination of highly efficient displacement by the reaction front and light oil/flue gas compositional interactions, such as oil swelling and/or vapourization and near-miscible behaviour(1). However, the contribution of each of these recovery mechanisms has not been properly assessed(2). Although significant effort has been devoted to the characterization of oxidation kinetics(3–5) and flue gas/light oil compositional interactions(6, 7), the process remains challenging to simulate even under controlled and ideal conditions, i.e., a combustion tube test. Some of the difficulties include the limited availability of experimental data to feed the numerical simulators with the required parameters, as well as the interdependence of these parameters and their variation with temperature. Assuming that these difficulties can be overcome by carrying out a study that allows a judicious analysis of experimental information and a careful treatment of the matched parameters in a numerical simulator, there is still a piece of information that has a strong influence on the simulation results and cannot be defaulted or left as a final matching tool: relative permeability. In an earlier study(2), it was suggested that for a combustion tube match, the steps previous to air injection (waterflood and inert gas flood) could be used to find a full set of relative permeability curves for the run. It was also pointed out that the rock-fluid dataset should include a variation of relative permeability data with interfacial tension to account for changes in pressure, composition, and most importantly, temperature. While this being necessary, it is still insufficient to ensure a correct representation of the flow of phases in a porous medium subjected to HPAI. Ahead of the reaction front, the high mobility flue gas (mainly composed of nitrogen and carbon oxides) displaces oil and water at nearly reservoir temperature, while in the high temperature zone, oil and water are evapourated to later condense downstream. In both zones, three-phase flow is occurring.
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