Bitumen Froth Research Articles

Hydrothermal Treatment of Oilsands Bitumen Froth at 400 °C: Influence of Minerals and Water on Hydrogen Transfer, Cracking, and Addition Reactions

Hydrothermal Treatment of Oilsands Bitumen Froth at 400 °C: Influence of Minerals and Water on Hydrogen Transfer, Cracking, and Addition Reactions

Effect of simulated flue gas on pentane-induced asphaltene precipitation in bitumen froth

In paraffinic bitumen froth treatment, a paraffinic solvent such as n-pentane is mixed with bitumen froth at a high solvent/bitumen ratio of 1.5 to 2.0. The purpose of the high solvent/bitumen ratio is to induce asphaltene precipitation which helps clean the bitumen so that it can be processed directly by a high-conversion refinery without the need of an upgrader. However, the high solvent/bitumen ratio inevitably increases the complexity and costs of the paraffinic froth treatment process. In this study, we have attempted to reduce the solvent/bitumen ratio without affecting asphaltene precipitation by replacing part of the solvent with simulated flue gas (CO2/N2 mixture at 200 °C). The n-pentane/bitumen ratio was varied from 0.8 to 2.2, CO2 concentration in the gas mixtures from 0 to 100 vol%, gas pressure from 0.1 to 1.7 MPa, and temperature at 21 °C and 90℃. Asphaltene contents in the bitumen products were measured following ASTM D4055, and the contents of water, solids, C, H, N, S in the products were measured by Karl Fischer titration, ashing and hot filtration, and CHNS elemental analysis. It was found that at the asphaltene precipitation onset n-pentane/bitumen ratio of 1.4 at 90 °C, the amount of precipitated asphaltenes was linearly correlated to the partial pressure of CO2; at the CO2 pressure of 1.7 MPa, about 50 % of the asphaltenes were precipitated, corresponding to an n-pentane/bitumen ratio of 2.2 when no CO2 was used. A solvent saving of about 36 % could therefore be achieved under these conditions without changing the quantity of asphaltene precipitation. The bitumen product quality was not affected when CO2 was used. This work provided useful information on the function of CO2 gas in assisting asphaltene precipitation, so that a lower n-pentane/bitumen ratio could be used, reducing process complexity and cost without affecting performance.

Investigation of Moisture Sensitivity and Cracking Resistance of Granular Base Course Comprised of Tailing Solvent Recovery Unit Materials and Bitumen Froth Derived from Alberta Oil Sands

Investigation of Moisture Sensitivity and Cracking Resistance of Granular Base Course Comprised of Tailing Solvent Recovery Unit Materials and Bitumen Froth Derived from Alberta Oil Sands

Visbreaking of Bitumen Froth: Influence of Minerals, Water, and Solvent on the Physicochemical Changes in the Bitumen Phase

Visbreaking of Bitumen Froth: Influence of Minerals, Water, and Solvent on the Physicochemical Changes in the Bitumen Phase

Performance evaluation of stabilized base courses comprising TSRU materials and bitumen froth derived from Alberta oil sands

In this research, the properties of two tailings solvent recovery unit (TSRU) samples, one bitumen froth sample and two aggregates, are evaluated using various laboratory tests. The TSRU-modified mixtures are prepared at different concentrations of bitumen froth (0%–6% of weight of mixture increasing in 1% intervals) where TSRU materials were added based on optimum moisture content of the mixture. The properties of the mixtures are investigated using indirect tensile strength and Marshall stability tests. The results show that TSRU modification results in a higher tensile strength. The granular layer thickness can be reduced by 42% and 60% for modified samples made with both aggregates. It should be noted that the modified samples fail to meet the soaked indirect tensile strength requirement. A potential solution to improve the indirect tensile strength of the soaked mixture is using cementitious additives such as Portland cement.

Free Radical and Cationic Addition due to Clay Minerals Found in Bitumen Froth at 250 °C Probed with Use of α-Methylstyrene and 1-Octene

Following previous evidence that hydrothermal treatment of bitumen froth does not lead to bitumen upgrading at 250 °C and promotes viscosity increase, the current study explores the free radical and cationic reactivity of clay minerals found in bitumen froth in promoting heavier material formation through addition reactions. The current investigation employed α-methylstyrene (AMS) and 1-octene as probe molecules instead of bitumen froth, and their conversion at 250 °C in the presence of clay minerals kaolinite and illite was studied in batch reactors. Thermal conversion of AMS and 1-octene at 250 °C in the absence of minerals was observed to be low. In the presence of clay minerals, not only the conversion of AMS and 1-octene was increased but also reactions such as dimerization of AMS and alkylation of 1-octene and toluene (used as solvents) were mainly promoted, leading to heavier product formation. Double-bond isomerization of 1-octene and cumene formation from AMS was side reactions that were also promoted by the clay minerals. Suppression of mineral-related conversion by pyridine and selectivity to different reaction products that enabled differentiation between free radical and cationic reaction pathways indicated that the mineral-related conversion was predominantly cationic in nature. Using the reactions in the presence of minerals and pyridine as surrogates for alkaline bitumen froth, it was concluded that even under alkaline conditions, minerals could promote heavier material formation through cationic addition.

Emulsions in Bitumen Froth Treatment and Methods for Demulsification and Fines Removal in Naphthenic Froth Treatment: Review and Perspectives

Petroleum refining and downstream facilities cannot handle excessive water, solids, and salts as they increase the refining operational costs and damage the equipment through various interfacial phenomena such as fouling, corrosion, and catalyst poisoning. Thus, producers must dehydrate the crude and remove the fine solids in the extraction and treatment processes. However, the presence of interfacially active species in the bitumen composition such as asphaltenes, resins, and fine solids results in the formation of stable emulsions that are difficult to treat. This phenomenon is indeed the case in the bitumen froth treatment, where asphaltenes and fine solids found in abundance in the bitumen composition hinder the oil/water/solid phase separation, particularly in the naphthenic froth treatment (NFT). This work systematically reviews the progress in the bitumen froth treatment in the oil sands surface mining process, influential factors in stabilizing/destabilizing the emulsions in these operations, the conventional emulsion treatment methods, and their effectiveness in the ultimate oil–water phase separation in the NFT process. The review attempts to summarize the up-to-date understanding of the origins of emulsion stability in the NFT and specify the research gaps in this area and also discusses overlooked technologies, methods, and future research perspectives which may be useful in implementing improved demulsification and fine solids removal strategies.

Understanding the Properties of Bitumen Froth from Oil Sands Surface Mining and Treatment of Water-in-Oil Emulsions

Bitumen froth, as the crude product from the surface mining of oil sands, requires the efficient removal of water and solids for further processing. This work has systematically characterized the p...

Coalescence inhibition and agglomeration initiation near the critical dilution of asphaltene precipitation

In bitumen recovery from oil sands, solvent addition is used to destabilize the water-in-diluted bitumen emulsions and separate the valuable oil product from water and solids. For each solvent, a critical solvent-to-bitumen ratio or critical dilution can be determined that coincides with the onset of bulk asphaltene precipitation, at which the system properties change abruptly. Above the critical dilution, solvent addition promotes bulk asphaltene precipitation and separation by the agglomeration of water droplets, solids and precipitated asphaltenes. Below the critical dilution, separation occurs by the coalescence of water droplets. The properties of the water-diluted bitumen interface could be key to improving the mechanistic understanding of water-in-diluted bitumen emulsions and bitumen recovery. In this work, we explore the behavior of water-in-diluted bitumen emulsions at macro- and microscopic scales, and provide novel insights at conditions below critical dilution. Bench scale bitumen froth treatment settling experiments highlight the possibility to attain effective water and solids separation based on agglomeration, without any noticeable bulk asphaltene precipitation. Light microscopy images reveal the inhibition of water droplet coalescence and the initiation of agglomeration due to the transformation of the oil continuous phase into a gel-like structure in the contact zone between water droplets. Thin liquid film observations show drastic changes in the continuous oil phase properties in the contact zone between water droplets at similar conditions that are attributed to the formation of both asphaltene aggregates at the interface and an oil gel-like structure that expands around them. These findings lead to the proposal that agglomeration can occur below critical dilution by surface asphaltene precipitation at the water-oil interface, without bulk asphaltene precipitation. The multiscale insights highlight opportunities to improve further not only bitumen froth treatment but also other oil-water-solids separation processes.

Hydrothermal Treatment of Bitumen Froth: Impact of Mineral Solids and Water on Bitumen Properties

Hydrothermal Treatment of Bitumen Froth: Impact of Mineral Solids and Water on Bitumen Properties

Vapour–liquid–liquid and vapour–liquid equilibrium of paraffinic aromatic synthetic naphtha/water blends: Prediction of the number of phases

AbstractBitumen is extracted from oil sands using warm water and additives. The resulting bitumen froth is diluted with naphtha in a froth treatment process. Residual naphtha in the aqueous tailings of the froth treatment unit is recovered in a naphtha recovery unit (NRU). It is imperative to maximize the naphtha recovery process to minimize the plant's environmental and economic impact. It is, in this respect, that NRU vapour–liquid–liquid equilibrium data is of significant value. In this work, a paraffinic‐aromatic synthetic naphtha (PASN) with a true boiling point (TBP) similar to that of froth treatment naphtha is used. Water/PASN mixtures are studied using the Soave‐Redlich‐Kwong equation of state with a Kabadi‐Danner modification. The tangent plane distance (TPD) is evaluated as a possible criterion to calculate the number of phases, with its significant shortcomings being established. As well, experimental data obtained in a CREC‐VL‐Cell is observed to display higher solubilities of PASN in water than the ones obtained by HYSYS‐Aspen Plus V9 simulation. To address these issues, a machine learning (ML)‐based phase classification methodology was considered, predicting the number of phases with a 99% recall. This anticipates that ML will be of significant value for faster convergence of the flash split calculations for the naphtha hydrocarbon‐water systems under consideration.

A Deep Look into the Microbiology and Chemistry of Froth Treatment Tailings: A Review.

In Alberta’s Athabasca oil sands region (AOSR), over 1.25 billion m3 of tailings waste from the bitumen extraction process are stored in tailings ponds. Fugitive emissions associated with residual hydrocarbons in tailings ponds pose an environmental concern and include greenhouse gases (GHGs), reduced sulphur compounds (RSCs), and volatile organic compounds (VOCs). Froth treatment tailings (FTT) are a specific type of tailings waste stream from the bitumen froth treatment process that contains bioavailable diluent: either naphtha or paraffins. Tailings ponds that receive FTT are associated with the highest levels of biogenic gas production, as diverse microbial communities biodegrade the residual diluent. In this review, current literature regarding the composition, chemical analysis, and microbial degradation of FTT and its constituents is presented in order to provide a more complete understanding of the complex chemistry and biological processes related to fugitive emissions from tailings ponds receiving FTT. Characterizing the composition and biodegradation of FTT is important from an environmental perspective to better predict emissions from tailings ponds and guide tailings pond management decisions.

Effect of Carbon Dioxide on Paraffinic Bitumen Froth Treatment: Asphaltene Precipitation from a Commercial Bitumen Froth Sample.

In this study, the effect of carbon dioxide in assisting paraffinic bitumen froth treatment was investigated. The work was divided into two parts, the effect of water addition on CO2-assisted asphaltene precipitation from a dry and clean bitumen sample by n-heptane and the effect of CO2 injection to a mixture of n-heptane and a commercial bitumen froth sample. It was found that water addition to the dry and clean bitumen improved the beneficial effect of CO2 on promoting asphaltene precipitation by n-heptane, where asphaltene precipitation increased by 2.5 percentage points (or 19%) with the presence of water and CO2. The asphaltene precipitation enhancement may be due to chemical reactions between injected CO2 and water in the formation of carbonic acid in the aqueous phase, which destabilized asphaltene. On the other hand, no improvement was detected under the control tests (N2). Similar results were observed in the case of CO2 injection to paraffinic solvent (n-heptane) treatment of the commercial bitumen froth sample. The results indicated that when the commercial bitumen froth sample was mixed with n-heptane at a solvent/bitumen ratio of 1.08, the injection of 1.7 MPa CO2 increased the amount of precipitated asphaltene from 10.0 ± 0.1% (without CO2) to 15.2 ± 0.2% (with 1.7 MPa CO2) at 90 °C, indicating a potential reduction of solvent usage by about 66%.

Structure and Mineralogy of Hydrophilic and Biwettable Sub-2 µm Clay Aggregates in Oil Sands Bitumen Froth

A primary concern of commercial mined oil sands operations is the extent to which one can minimize the content of water and solids contaminants in the solvent-diluted bitumen products resulting from the bitumen production processes. During bitumen production, particles of about 2 µm or less may be responsible for the stabilization of water-in-bitumen emulsions that form during aqueous extraction of bitumen and purification of bitumen froth subsequently during the froth treatment processes, thus leading to the presence of those contaminants in solvent-diluted bitumen products. In this study, we separate and analyze sub-2 µm clay solids isolated from typical bitumen froth fed to a froth treatment plant at a commercial mined oil sands operation. Analytical transmission electron microscopy (TEM) with spatially-resolved energy-dispersive X-ray spectroscopy (EDX) and electron energy-loss spectroscopy (EELS) demonstrate key differences in morphology and composition between sub-2 µm clay aggregates with two distinct wettability characteristics: hydrophilic vs. biwettable particle surfaces. In particular, clay platelets with <200 nm lateral dimensions and thicknesses of a few atomic layers, which are intermixed within coarser sub-2 µm clay aggregates, are found to confer clear differences in morphological characteristics and wettability behaviors to the sub-2 µm clay aggregates. The <200 nm clay platelets found within sub-2 µm biwettable clays tend to arrange themselves with random orientations, whereas <200 nm clay platelets within sub-2 µm hydrophilic clays typically form well-ordered face-to-face stacks. Moreover, in biwettable sub-2 µm clay aggregates, <200 nm clay platelets often cover the surfaces of ~1–2 µm sized mineral particles, whereas similarly sized mineral particles in hydrophilic sub-2 µm clay aggregates, in contrast, generally have exposed surfaces without clay platelet coverage. These biwettable vs. hydrophilic behaviors are attributed to a difference in the surface characteristics of the <200 nm clay platelets caused by toluene-unextractable organic carbon coatings. Nanometer-scale carbon mapping reveals an inhomogeneous toluene-unextractable organic carbon coating on the surfaces of <200 nm platelets in biwettable clays. In contrast, hydrophilic clays have a significantly lower amount of toluene-unextractable organic carbon, which tends to be concentrated at steps or near metal oxide nanoparticles on clay particle surfaces. Mixing surface-active organic species, such as asphaltene, resin, or carboxylic organic acids of various types with inorganic solids can lead to a dramatically enhanced emulsion stability. Consequently, understanding the origin and characteristics of sub-2 µm clay solids in bitumen froth is important to (i) clarify their potential role in the formation of stable water-in-oil emulsions during bitumen production and (ii) improve froth treatment process performance to further reduce contaminant solids in solvent-diluted bitumen products. We discuss the implications of our results from these two perspectives.

Bitumen froth treatment in the transition region between paraffinic and naphthenic process conditions

Bitumen froth treatment is an important process step of the bitumen recovery from oil sands by surface mining. In bitumen froth treatment, water and mineral solids are separated from the target organic bitumen product by using hydrocarbon solvents. Residual water and mineral solids in the bitumen product are detrimental to pipeline transport and downstream processes. Depending on the solvent composition, the commercial naphthenic and paraffinic bitumen froth treatment processes proceed via the oil-water separation mechanisms of coalescence and agglomeration, respectively. This study presents an experimental proof-of-concept for the existence of a transition region at ambient conditions and solvent-to-bitumen ratio of 1.6, where the advantages of the two commercial froth treatment processes may be combined and the drawbacks essentially eliminated. The bitumen product obtained in the transition region is virtually free from residual water and solids (<0.1 wt%), using gravity settling alone, as in the paraffinic process, and the asphaltenes are retained, as in the naphthenic process. The transition region range is determined at 2.2–4.5(±0.2) wt% aromatic or 70–80(±10) wt% paraffinic content of the solvent. Bitumen froth treatment in the transition region recovers a sufficient amount of oil product with gravity settling alone. These findings suggest that conducting bitumen froth treatment in the transition region could increase both hydrocarbon recovery and product quality. This approach may be valuable not only for bitumen froth treatment but also for other oil-water separation processes, such as in situ bitumen recovery.

Dewatering of Naphthenic Bitumen Froth

Bitumen froth is a water-in-bitumen emulsion (~ 30 wt% water, 60 wt% bitumen, and 10 wt% of solids) stream obtained during the water-based extraction process of mined oil sands. The separation of w...

Waste Containment Ponds Are a Major Source of Secondary Organic Aerosol Precursors from Oil Sands Operations.

The surface mining and bitumen extraction of oil sands (OS) generates over one million barrels of heavy oil each day in the Alberta Oil Sands Region of Canada. Recent observations suggest that emissions from OS development contribute to secondary organic aerosol (SOA) formation, but the chemical composition, mass fluxes, and sources of those emissions are poorly delineated. Here, we simulated OS extraction and used comprehensive two-dimensional gas chromatography to quantify and characterize direct air emissions, bitumen froth, residual wastewater, and tailings components, ultimately enabling fate modeling of over 1500 chromatographic features simultaneously. During the non-ice cover season, tailings ponds emissions contributed 15 000-72 000 metric tonnes of hydrocarbon SOA precursors, translating to 3000-13 000 tonnes of SOA, whereas direct emissions during the extraction process itself were notably smaller (960 ± 500 tonnes SOA yr-1). These results suggest that tailings pond waste management practices should be targeted to reduce environmental emissions.

Comprehensive study on cleaner production of heavy oil from Athabasca oil sands using chemical additives in biodiesel-assisted ambient-aqueous bitumen extraction process

The massive unconventional petroleum resources of Athabasca oil sands in Alberta, Canada are currently being excavated and processed using the hot water bitumen extraction (HWBE) process and steam-assisted gravity drainage (SAGD) technology. A major challenge associated with HWBE process is high energy intensity for maintaining an operation temperature of 40–55 °C. Solvent-assisted ambient aqueous bitumen extraction processes, in which a portion of solvent is added for oil sands pretreatment prior to extraction process, have been reported to be capable of reducing the energy intensity via ambient temperature oil sands extraction operations. However, there is still a gap between the current solvent-assisted process and industrial expectations. This study focuses on optimization of biodiesel-assisted ambient aqueous bitumen extraction, an example of the solvent-assisted process, by incorporating methyl isobutyl carbinol (MIBC) and ethylene oxide-propylene oxide (EO-PO) copolymer in oil sands pretreatment. The idea is to take advantage of such chemicals and demulsifiers used downstream of heavy oil (known as bitumen) extraction process by their addition upfront as in the case of biodiesel-assisted hybrid extraction process. With the incorporation of these chemicals and demulsifiers in the improved biodiesel-assisted process, both bitumen liberation and bitumen flotation efficiency were improved significantly with the addition of biodiesel/MIBC mixture at 10 wt% of bitumen. The results from bench-scale experiments revealed a higher bitumen recovery and a cleaner bitumen froth by the improved biodiesel-assisted process at ambient temperature as compared with the traditional biodiesel-assisted process, as well as current industrial HWBE process, featuring a cleaner production of heavy oil from Athabasca oil sands and other heavy oil resources.

Effect of Carbon Dioxide on Asphaltene Precipitation from Bitumen–Heptane Mixtures

Bitumen froth generated from water-based extraction of Alberta oil sands typically consists of 60 wt % bitumen, 30 wt % water, and 10 wt % mineral solids. The froth has to be cleaned by removing th...

Reducing energy consumption during bitumen separation from oil sand

Oil sands, found in Canada, Venezuela, USA and Russia, contain bitumen, water, clay and some metals. Two different methods of producing oil from oil sands exist: open-pit mining and in situ. Approximately 20% of oil sands are recoverable through open-pit mining.After oil sand is mined, bitumen is separated from solids and water within the bitumen production facilities. The process of bitumen separation consists of 3 main steps. (1) Hot/warm water is added to the oil sands producing a slurry that can be pumped to the processing plant through hydrotransport pipelines which connect ore preparation to the main extraction facility. These large-diameter pipelines can be several kilometers long, providing the additional time and shear required to break down the lumps of mined oil sands. (2) After hydrotransport pipeline oil sand slurry enters flotation facility where bitumen is gravity separated from the coarse solids producing an intermediate bitumen froth product. (3) Then solvent is added to the froth, to reduce the bitumen viscosity and to remove remaining water and fine solids.In addition to efficiency concerns, this separation process suffers from high operating cost due to a number of factors such as the energy needed for heating the water, the energy consumed by the cyclofeeder and the energy consumed by hydrotransport. The other problem of hydrotransport is extensive wear since the slurry contains quartz sand particles which are extremely abrasive.In the present study, an alternative technology based on cavitation jets is suggested. It is found that jets can separate bitumen at low temperatures (5–6 °C) and cavitation jet technologies have the potential to replace hydrotransport.A series of nozzles were designed for low intensity cavitation at high cavitation numbers (σ=0.37 - 0.46) to test different types of cavitation generators. It was shown that selfresonating nozzle shows significantly better results than conventional nozzles and conventional nozzles with passive control.