Enhancement of bitumen recovery from the oil sand in an alkaline solution using ultrasound irradiation and carbon dioxide

Oil sand is a mixture of bitumen, sand, and water. The separation and recovery of bitumen is the key to oil sand utilization. This study combined CO2-loaded amine solution and ultrasound utilization for high-efficiency bitumen recovery. Pretreatment of oil sand using an amine solution was applied before flotation to separate bitumen from sand. Ultrasound can enhance the separation of bitumen from sand by the physical effect in pretreatment and promote the contact of CO2 and bitumen in flotation by increasing the CO2 bubbles residence time and surface area. The effectiveness of ultrasound irradiation with different frequencies (28 kHz and 200 kHz) and stirring in pretreatment and flotation were studied. Both frequencies of ultrasound could enhance the bitumen separation and flotation more than stirring, and a high bitumen purity of 0.92 and a recovery ratio of 0.87 were achieved.

Athabasca oil sands: effect of organic coated solids on bitumen recovery and quality

Oil sand contains bitumen, which includes a high percentage of sulfur. Before using bitumen as a fuel, it must be recovered from oil sand and desulfurized. Currently, bitumen is recovered from oil sand using hot water (<100 °C), and sulfur is removed via hydrodesulfurization (>300 °C). Both of these processes consume significant amounts of energy. In this study, we demonstrate the simultaneous recovery and desulfurization of bitumen from oil sand using oxidative desulfurization with ultrasonic irradiation and tetrahydrofuran at 20 °C. We successfully recovered 88% of the bitumen from oil sand and removed 42% of the sulfur from the bitumen.

The need for alternative sources of energy has become even more acute in light of the recognition of the dwindling conventional world oil reserves. The interest in exploring other avenues of complimenting and/or eventually replacing this resource is growing quite rapidly. A ready alternative to conventional crude oil is oil sands which are abundant and vastly unexplored. The huge deposits of tar sand found in SouthWestern Nigeria remain untapped due to concerns about the environmental impact. The consequences of the methods in processing tar sand, ranging from water pollution to emission of greenhouse gases, especially in Canada bring in to sharp focus the urgent need for an alternative means of extracting oil from tar sand. A more effective and less environmentally damaging procedure could be the break through needed to open a new chapter in the exploitation of oil sands. The alternative recovery procedure is supercritical carbon dioxide extraction. Recent supercritical extractions use high temperatures and pressures. The upgrade in this research involves using high pressures and lower temperatures which saves energy and improves the process. The experimental study of the bitumen extraction from Nigerian tar sand by dense CO2 was carried out by high pressure extractor. The samples of tar sand were first heated in an oven at 120 °C to melt. A 50 g sample of melted tar sand with addition of 3 g of ethanol was placed into an extractor and heated to 80 °C to initiate the experiment. Carbon dioxide was injected in to the extractor to create 50 MPa of pressure in static mode for 20 min after which the extract was collected. In the presence of ethanol, the extract had a lighter colour than the usual black. Nigerian tar sand is known to be composed of 84 % sand, 17 % bitumen, 4 % water and 2 % mineral clay. Using this data, an extract of 19.47 % was calculated which makes the recovery achieved very encouraging. The experiment shows that recovery of bitumen from tar sand is possible under relatively low temperatures and can be possibly economically profitable.

ABSTRACTIndonesian bitumen and sands were thoroughly separated from Indonesian oil sands by introducing organic solvents and aqueous reagents into the system. The reaction mechanism of the double phase extraction system on the separation of oil sands was deeply analyzed. The effects of amount and pH of the aqueous reagents, amount of solvents and temperature on the bitumen recovery from oil sands were also investigated. The results showed that under the optimum operation conditions of m(aqueous reagents): m(oil sands) 0.4–0.6, pH of aqueous reagents 10–12, m(solvents): m(oil sands) 1.0 and temperature 70°C, bitumen recovery could be 94.5%. Bitumen recovery by double phase extraction was improved remarkably compared to single phase extraction.

The oil sands industry is moving away from tumbler conditioning at 80 °C to pipeline conditioning, often at significantly lower temperatures. This lower temperature conditioning can be less efficient, requiring longer conditioning times. Control of conditioning time in a pipeline is difficult and inadequate conditioning can result in either lower recoveries or higher froth densities, depending upon the operating conditions. A bench scale test was developed at CANMET to simulate the mechanical conditioning environment found in a stirred tank or in a pipeline. A small scale extraction test has been used at CANMET to investigate the relationship between the efficiency of oil sands conditioning and various process variables. A shift from relatively high temperature tumbler conditioning to pipeline or hydrotransport conditioning requires a slightly different approach to batch extraction testing. The CANMET test protocol has been compared to pipeline and stirred tank conditioning at a pilot scale and has been used to investigate the effect of several process variables in oil sands extraction. This technology brief discusses the preliminary findings and a potential link to operating experience.Introduction. Conditioning is conventionally considered to be the separation of bitumen from the mineral matrix, combined with air attachment. At low temperatures, bitumen separation may be complete, but inadequate air attachment can result in poor bitumen recovery. Oxidation or degradation of the bitumen can negatively impact the bitumen separation, but not necessarily reduce the efficiency of air attachment. This can result in poor bitumen froth quality, while maintaining high recovery. In cases where there is a combination of low temperatures and a degraded or oxidized bitumen component in the oil sand, recovery as well as froth quality can be drastically affected(1).Ordinarily, extraction experiments are carried out in a small scale unit where various stirring, aeration, and water additions are done in an attempt to mimic the commercial extraction process. The froth quality and bitumen recovery determined from these experiments allows for investigation of trends as a function of ore type, water chemistry, temperature, and other process variables. Previous studies have investigated the various factors that impact extraction performance, but limitations in the batch (or small scale) extraction protocol often limits the discussion to impacts on recovery only(2–6). Furthermore, it is often not possible to separate the effects of the bitumen liberation and air attachment, the two key points in conditioning of oil sands.Recent CANMET work has overcome some of these experimental difficulties and focused on the relationship between temperature, mechanical energy, and process chemicals in the conditioning step and the resulting impact on both recovery and froth quality(7). It was shown that to a certain extent, increasing mechanical energy can substitute for higher extraction temperatures and/or chemical process aids. By far the most important factor is process temperature, largely because of a change in the bitumen- air attachment mechanism as the temperature is reduced.

The oil sands industry is moving away from tumbler conditioning at 80 °C to pipeline conditioning, often at significantly lower temperatures. This lower temperature conditioning can be less efficient, requiring longer conditioning times. Control of conditioning time in a pipeline is difficult and inadequate conditioning can result in either lower recoveries or higher froth densities, depending upon the operating conditions. A bench scale test was developed at CANMET to simulate the mechanical conditioning environment found in a stirred tank or in a pipeline. A small scale extraction test has been used at CANMET to investigate the relationship between the efficiency of oil sands conditioning and various process variables. A shift from relatively high temperature tumbler conditioning to pipeline or hydrotransport conditioning requires a slightly different approach to batch extraction testing. The CANMET test protocol has been compared to pipeline and stirred tank conditioning at a pilot scale and has been used to investigate the effect of several process variables in oil sands extraction. This technology brief discusses the preliminary findings and a potential link to operating experience. Introduction Conditioning is conventionally considered to be the separation of bitumen from the mineral matrix, combined with air attachment. At low temperatures, bitumen separation may be complete, but inadequate air attachment can result in poor bitumen recovery. Oxidation or degradation of the bitumen can negatively impact the bitumen separation, but not necessarily reduce the efficiency of air attachment. This can result in poor bitumen froth quality, while maintaining high recovery. In cases where there is a combination of low temperatures and a degraded or oxidized bitumen component in the oil sand, recovery as well as froth quality can be drastically affected(1). Ordinarily, extraction experiments are carried out in a small scale unit where various stirring, aeration, and water additions are done in an attempt to mimic the commercial extraction process. The froth quality and bitumen recovery determined from these experiments allows for investigation of trends as a function of ore type, water chemistry, temperature, and other process variables. Previous studies have investigated the various factors that impact extraction performance, but limitations in the batch (or small scale) extraction protocol often limits the discussion to impacts on recovery only(2–6). Furthermore, it is often not possible to separate the effects of the bitumen liberation and air attachment, the two key points in conditioning of oil sands. Recent CANMET work has overcome some of these experimental difficulties and focused on the relationship between temperature, mechanical energy, and process chemicals in the conditioning step and the resulting impact on both recovery and froth quality(7). It was shown that to a certain extent, increasing mechanical energy can substitute for higher extraction temperatures and/or chemical process aids. By far the most important factor is process temperature, largely because of a change in the bitumen- air attachment mechanism as the temperature is reduced.

Summary form only given. Canadian oil sands are unconsolidated sand deposits that are impregnated with heavy, viscous petroleum, normally referred to as bitumen. The total bitumen in place in Alberta is estimated at 1.7 to 2.5 trillion barrels and is clearly massive by world standards. Presently, 25% of the Canadian energy needs are derived from upgraded bitumen from mined oil sands. The oil sands are a complex mixture containing bitumen, mineral solids, clays, connate water and salts. The bitumen recovery from the oil sands using water extraction processes involves bitumen separation from the sand grains and air-bitumen attachment for subsequent flotation. Colloidal, interfacial and electrokinetic phenomena play a major role in bitumen recovery from oil sands using water based extraction processes. Through the use of basic scientific tools at the micro and molecular scales, we were able to understand the working of what is considered to be a mega scale industrial process. Electrophoretic and atomic force balance measurements were used to establish the reasons for the observed low bitumen recovery in the presence of fine solids and divalent ions. As well, impinging jet deposition experiments were utilized to ascertain the ability of air-bitumen attachment under different physicochemical environment. The behavior of the bitumen-water interface was studied to better understand the formation of stable water-in-bitumen emulsions. Langmuir trough and micro-pipette techniques were employed to elucidate the fundamental role of deemulsifiers. The presentation will illustrate how one can within a University environment study a complex industrial process that is of great importance to the Canadian Energy Sector.

Further development of oil sand deposits requires processing poorer quality oil sands while maximizing bitumen recovery, minimizing the water and solids content of the product bitumen, and minimizing overall energy consumption. Bitumen recovery requires two stages: extraction and froth treatment. This work focuses on the effect of process conditions in the Clark Hot Water Bitumen Extraction Process on froth treatment effectiveness. Laboratory approximations are used to represent the two commercialized froth treatment processes in Alberta:the "Syncrude Process," which is dilution with an aromatic solvent followed by centrifugation; and,the "Albian Process," which is dilution with a paraffinic solvent followed by gravity settling. Parameters considered are oil sand quality, extraction shear, extraction temperature, NaOH addition during extraction, froth treatment temperature, and froth treatment residence time. It was found that reduced extraction temperature results in lower bitumen recovery at least for low quality oil sands. Higher shear extraction may improve bitumen recovery, but decreases froth treatment effectiveness. For paraffinic solvent-based froth treatments, the addition of NaOH during extraction may be required to obtain optimum froth treatment of low quality oil sands. Introduction The Canadian oil industry is producing about 1 million barrels of bitumen and synthetic crude oil per day from oil sands and the production is expected to rise to 2 million barrels per day by 2012(1). Currently, both in situ and surface mining operations contribute almost equally to the total production. However, the production of synthetic crude from surface-mined oil sands is expected to take the lead in the next decade(2). Expansions of existing oil sand facilities are already underway and the addition of new facilities are planned within the next decade. There are two main stages to oil sand processing: extraction and froth treatment. The most common extraction process is hot water bitumen extraction. The oil sand is conditioned with hot water, either in a process vessel (conditioning drum) usually with NaOH added, or more recently in a pipeline (hydrotransport) usually with a smaller amount of NaOH added. During conditioning, the slurry is aerated and, ideally, the bitumen separates from the sand, and attaches to and spreads on the air bubbles. Water is added to the slurry, which is subsequently sent to a separation vessel. The bitumen- coated air bubbles are carried upwards to form a froth that is rich in bitumen. The froth also contains free water, emulsified water, and suspended solids(3, 4). The froth is collected in two stages yielding a primary and a secondary froth. For high-quality oil sands, a typical primary froth composition is approximately 66 wt% oil, 25 wt% water, and 9 wt% solids. A typical secondary froth has lower oil content (approximately 24 wt%) and higher water and solids contents (59 wt% and 17 wt%, respectively). Poorer quality oil sand froths have lower oil content and higher water and solids contents(5).

Further development of oil sand deposits requires processing poorer quality oil sands while maximizing bitumen recovery, minimizing the water and solidscontent of the product bitumen, and minimizing overall energy consumption. Bitumen recovery requires two stages: extraction and froth treatment. This work focuses on the effect of process conditions in the Clark Hot Water Bitumen Extraction Process on froth treatment effectiveness. Laboratory approximations are used to represent the two commercialized froth treatment processes in Alberta:the ‘Syncrude’ process, dilution with an aromatic solvent followed by centrifugation; andthe ‘Albian’ process, dilution with a paraffinic solvent followed by gravity settling. Parameters considered are oil sand quality, extraction shear, extraction temperature, NaOH addition in extraction, froth treatment temperature, and froth treatment residence time. It was found that reduced extraction temperature results in lower bitumen recovery at least for low quality oil sands. Higher shear extraction may improve bitumen recovery, but decreases froth treatment effectiveness. For paraffinic solvent based froth treatments, the addition of NaOH in extraction may be required to obtain optimum froth treatment of low quality oil sands. Introduction The Canadian oil industry is producing about 1 million barrels of bitumen and synthetic crude oil per day from oil sands and the production is expected to rise to 2million barrels per day by 2012 [1]. Currently, both insitu and surface mining operations contribute almost equally to the total production. However, production of synthetic crude from surface-mined oil sands is expected to take the lead in the next decade [2]. Expansions of existing oil sand facilities are already underway and the addition of new facilities are planned within the next decade. There are two main stages to oil sand processing: extraction and froth treatment. The most commonextraction process is hot water bitumen extraction. The oil sand is conditioned with hot water, either in a process vessel (conditioning drum) usually with added NaOH, or more recently in a pipeline (hydrotransport) usually with less added NaOH. During conditioning, the slurry is aerated and, ideally, the bitumen separates from the sand, attaches to and spreads on the air bubbles. Water is added to the slurry, which is sent to a separation vessel. The bitumen coated air bubbles are carried upwards to form a froth that is rich in bitumen. The froth also contains free water, emulsified water and suspended solids [3,4]. The froth is collected in two stages yielding a primary and a secondary froth. For high-quality oil sands, a typical primary froth composition is approximately 66 wt% oil, 25 wt% water and 9 wt% solids. A typical secondary froth has lower oil content (approximately 24 wt%) and higher water and solids contents (59 wt% and 17 wt%, respectively). Poorer quality oil sand froths have lower oil content and higher water and solids contents [5]. Free water and coarse solids are relatively easily separated from the froth. However, the froth also contains fine solids and emulsified water droplets, which arecovered with surfactants including asphaltenes and nonsurfactants including ultra-fines (&amp;lt; 200 nm) [4,6,7].

Bitumen recovery and desulfurization from oil sand require high temperatures; low-temperature methods are desired to reduce energy consumption. We studied a process for the simultaneous recovery and desulfurization of bitumen in oil sand using hydrogen peroxide (H2O2), tetrahydrofuran (THF), and ultrasonic irradiation at 45 °C. THF reduces bitumen viscosity and it makes easy to separate bitumen from oil sand using ultrasound. The optimized conditions for simultaneous bitumen separation and desulfurization from oil sand using oxidant and ultrasound are 15 ml THF, 3 wt% H2O2, and 60 min ultrasonic irradiation after NaOH addition, resulting in 86% desulfurization ratio, 0.88 purity, and 93% recovery ratio.

Process modelling and simulation of bitumen mining and recovery from oil sands

Steam flooding oil sands requires some fluid communication path between injector and producer. This may be developed by exploiting reservoir zones with natural mobility, due to low bitumen saturation; or by artificial techniques such as fracturing. At the time of heat breakthrough to the producers, this communication path will generally be of limited volumetric extent, and have a fluid mobility thousands of times that of the virgin reservoir. A steam flood will there/ore fend to conform closely for this path, leading to early breakthrough and poor recovery. Bitumen recovery after breakthrough requires the steam front to advance into the reservoir in a direction essentially normal to the flow. One mechanism by which this can occur is steam drag, V1!here a thin layer of oil sand adjacent to the channel is heated, allowing the bitumen to be dragged away by the flowing steam. Although steam drag operates at low oil steam ratios, high bitumen production rates and recovery are possible. In this paper a simple analytical model of the steam drag effect is derived. A principal finding is that the rate of bitumen production should be proportional to the square root of the reservoir pressure gradient. Analytical predictions are found to be in reasonable agreement with numerical simulation results. The influences of reservoir quality and well geometry are discussed. Some practical recovery processes based on the steam drag concept are steam foam flooding, and bitumen recirculation. These appear to have the potential to recover a large fraction of the bitumen at acceptable oil/steam ratios. Introduction In a linear flood steam is well known to efficiently displace even extremely heavy bitumens from oil sand. In addition, much of Alberta's oil sand resource has excellent porosity, oil saturation and pay thickness, factors which are conducive to profitable steam flooding. The problem, of course, is that native high-grade reservoir generally has negligible mobility, making injection and production impossible at practical rates. To carry out a core flood in the laboratory, For example, it is usually necessary to preheat the core and/or to employ extremely high pressure gradients. In the field, it is necessary to create and maintain continuous heated channels between injectors and producers, before steam can be injected and bitumen produced on a continuous basis. This in itself is difficult enough, and is the subject of much current research. Some operators can exploit natural zones of low bitumen saturation, such as water sands(l), while others must resort to artificial means for example Fructuringt (2,3), or horizontal wells(4). A dilemma arises when the operator must now recover bitumen from the unheated remainder of the reservoir. After having deliberately created a communication channel having fluid mobilities thousands of times greater than the virgin reservoir. Bitumen behaves more like a solid than a fluid, with typical viscosities of 100,000 to 10,000,000 mPa's at reservoir conditions. Any practical pressure gradient is incapable of displacing it at a significant rate.

As the important unconventional energy source, oil sands have been paid more attention by the oil workers. The water-based separation method is widely applied to separate bitumen from oil sands. The water-based extraction bitumen has the advantages of large scale, extraction and separation without space restrictions, but the factors such as water temperature, and the ratio of water to oil sands can affect the recovery of bitumen. In this paper the influence factors of water-based separation of Urho's oil sands were studied. When the washing temperature was 85°C, the ratio of water to oil sands was 2, and the sodium hydroxide concentration was 0.1wt%, the recovery of bitumen was more than 85% in the experimental conditions.

Experimental results for bitumen recovery from oil sands by continuous and cyclic injection of several steam-flue gas combinations are presented in this paper. Steam, steam-CO2, steam-N2 and steam-CO2-N2 mixtures were injected (3.55 MPa and 100% steam quality into an oil sand test bed which contained a high permeability communications path between injection and production wells. The concentrations of flue gas (N2 + CO2) and carbon dioxide in steam were designed to simulate those which would be produced from a "down-hole " steam generator which uses either air or oxygen. The test results show that the addition of flue gas to steam substantially improves both rate and ultimate recovery of bitumen as compared to that obtained by steam-alone. The steam-CO2 mixture was superior to either steam-N2 or the steam-flue gas combinations. Introduction Oil sand is a complex mixture which contains mineral matter (primarily quartz and feldspar), organic materials (bitumen), gases and water with bitumen and water saturations up to 15% and 2% by weight, respectively. The oil sand has a permeability of about 3.0 µm2 and a porosity of about 32%. The viscosity of bitumen varies considerably and in some cases reaches values about 1000.0 Pa.s at reservoir conditions (15 °C). The technology of exploiting the oil sand deposits by surface mining has been proven in the last few years. However, the available oil sand resource which is surface-mineable accounts for only about 10% of the total available deposit, with the remaining 90% uneconomically mineable due to excessive overburden depth. For the deeper portions of the oil sand deposits, the technology of in-situ extraction has received considerable interest during recent years. In general, in-situ methods involve some means of reducing the viscosity of and then displacing bitumen to a production well. Injection of a hot fluid into the oil sands (most commonly steam) is normally used. Addition of solvents, gases or solvent-gas combinations may also be used in conjunction with steam. Two methods of steam injection have been employed: single well steam stimulation and steam drive. In this paper, the primary focus will be on the steam drive process. At reservoir conditions, most commonly, the first step in a steam drive process is establishment of communication between injection and production wells. Thereafter, the recovery process comprises of channeling of the steam, heating of the adjacent oil layer(s) by conduction and displacement of the heated oil by an entrainment process(1) in which healed oil is displaced toward the producing well by flowing steam and condensed water. Interaction between fluids flowing in the communication path and the surrounding formation is a very important part of the recovery process. There appears to be a dynamic balance between the rate of heat transfer from the steam zone to the adjacent oil layers and the flow displacement processes in the interface region between the steam zone and the oil zone. This balance can result in the occurrence of an optimum injection rate.