Undesirable water-in-oil emulsions often form during oil processes. Chemical treatment with demulsifiers (surfactants) is a common method for breaking down these emulsions; however, this technique is not always effective. In order to improve the chemical treatment for emulsions, it is useful to have an understanding of the factors that contribute to emulsion stability.

Surface pressure isotherms were measured in a drop shape analyzer for droplets of asphaltenes, toluene, and heptane surrounded by a solution of water and the surfactant. The experimental variables were: heptane content (0, 25, and 50 vol%), asphaltene concentration (0, 5, and 10 kg/m³), surfactant concentration (0, 0.1, and 0.5 wt% for NA; 0, 0.01, and 0.001 wt% for DDBS), and aging time (10 minutes to 4 hours). The compressibilities of the interfacial films were determined from the slope of the surface pressure isotherms. Water-in-oil emulsions were prepared from the same solutions. Emulsion stability was assessed in terms of the free water evolved after a treatment of centrifugation and heating.

[1]        Yarranton, H.W., Urrutia, P., Sztukowski, D.M., J. Colloid Interface Sci, 310, 2007, 253-259.

 The stability of water-in-crude oil emulsion has been speculated to arise from a visco-elastic film on the water-oil interface. In previous work, a correlation was observed between the stability of water-in-toluene/heptane emulsions stabilized by asphaltenes and the compressibility of asphaltene films. Naphthenic acids, which occur naturally in processes such as bitumen extraction, are believed to influence emulsion stability. In this work, naphthenic acids are used to determine if the correlation for emulsion stability is more generally applicable.

It has long been speculated that the stability of water-in-crude oil emulsions arises from a visco-elastic film on the water-oil interface. In previous work involving water-in-toluene/heptane emulsions stabilized by asphaltenes, a correlation was observed between emulsion stability and the compressibility of interfacial asphaltene films [1]. The next step in this work is to assess the effect of other crude oil constituents on the film properties and to determine if the correlation for emulsion stability is more generally applicable. Here, naphthenic acids are considered because they are believed to influence emulsion stability, for example, during bitumen extraction.

 [1]        Yarranton, H.W., Sztukowski, D.M., Urrutia, P., “Dynamic Surface Pressure Isotherms from Drop Shape Analysis of Water-Oil Interfaces”, 7^th International Conference on Petroleum Phase Behavior and Fouling, Ashville, June 25-29, 2006.

Hot water bitumen extraction produces a froth consisting of bitumen, water, and inorganic solids.  The froth must be treated to separate the bitumen.  There are two commercialized processes in Alberta to recover the bitumen from the froth: 1) the 'Syncrude' process, dilution with naphtha solvent followed by centrifugation; and 2) the 'Albian' process, dilution with a paraffinic solvent followed by gravity settling.

This work summarizes laboratory observations on froth treatment effectiveness for a variety of oil sand qualities.  Extractions were performed using a Batch Extraction Unit (low shear) and a Denver Cell (high shear).  Extraction parameters considered were oil sand quality, shear rate, temperature, and NaOH addition during extraction.  Froth treatment experiments were performed using laboratory approximations of the commercial processes; the Aromatic Solvent and the Paraffinic Solvent Methods.  Froth treatment temperatures of 23 and 60°C and residence times from 5 minutes to 8 hours were evaluated.  Froth treatment effectiveness was assessed primarily in terms of the water content in the product bitumen as a function of dilution ratio.
 

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:  1) the 'Syncrude' process, dilution with an aromatic solvent followed by centrifugation; and 2) the '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.
 

Bench-scale process tests show that, for Athabasca oil sands, the water-based conditioning/flotation process can be adjusted from 80 to 50°C without losing recovery efficiency, as measured by either standard batch extraction unit (BEU, low shear) or Denver cell extraction (high shear) techniques. Detailed processibility evaluations, together with trends in interfacial tension and surface charge confirmed this conclusion. For further temperature reduction to 25°C, various chemical process aids are needed to achieve good bitumen separation and flotation. These are needed, in part, to overcome a bitumen viscosity threshold when the BEU is used. In Denver cell processing, mechanical energy input provides an alternative means of overcoming the viscosity threshold and, when alkaline process aid was optimized, no further chemical additives were required for good oil recovery. Under optimized processing conditions, good oil recoveries could be obtained from either kind of extraction cell over the full temperature range from 25 through 80°C. Studies of the key interfacial properties are underway to identify key mechanisms to good oil recovery.
   

We have used a highly reduced gravity environment to remove the masking influence of normal gravity and examine capillary flow in porous media by combining experiments from high altitude parabolic aircraft flights and from the STS-91 space shuttle flight, with simulations performed using a simple finite-difference numerical model. These studies involved a range of gravitational accelerations, surface tensions, viscosities, wetting preferences, permeabilities, and pore radii on capillary flow. Throughout enhanced to terrestrial to highly reduced gravitational accelerations, bead-pack experiments and numerical simulation results provided quite good agreement when the constraining cell walls were not preferentially wetted by the liquid. When the walls were wetted by the liquid the simulations provided severe underestimates of the experimental capillary flow results, apparently due to pronounced fluid flow along the inner cell walls under highly reduced gravity conditions. For sand-pack 1g experiments the numerical simulations provided reasonable predictions; for near-zero gravity experiments some simulations provided underestimates of the experimental capillary rise results, apparently due to poor conformance on the part of the advancing liquid front through the porous media. This effect was not observable in the shorter time-duration reduced gravity experiments. This work demonstrates the ability of normal gravity to mask remarkable interfacial phenomena and shows the potential value of conducting such experiments in on highly reduced gravity platforms such as high altitude aircraft parabolic flights and the space shuttle.
 

Batch extraction tests show that, for Athabasca oil sands, the water-based conditioning/flotation process can be adjusted from 80 to 50°C conditions without substantial changes in optimal process aid addition level or primary oil recovery obtained.  When the process temperature is further reduced to 25°C, however, an order of magnitude reduction in primary oil recovery is obtained, suggesting that one or more key process variables have undergone a substantial change.  Our studies with process additives suggest that several key physical properties undergo major changes, including bitumen viscosity, interfacial tension, and interfacial charge.  If these are addressed then comparable optimum primary oil recoveries can be achieved under all of 25, 50, or 80°C conditions.  This is a significant result in terms of identifying the key mechanism(s) by which good primary froth recovery can be achieved.  It is shown that the interfacial property changes in particular are consistent with the expected thermodynamic conditions necessary for efficient bitumen separation and flotation.
 

Batch extraction tests show that, for Athabasca oil sands, the water-based conditioning/flotation process can be adjusted from 80 to 50°C conditions without substantial changes in optimal process aid addition level or primary oil recovery obtained.  When the process temperature is further reduced to 25°C, however, an order of magnitude reduction in primary oil recovery is obtained, suggesting that one or more key process variables have undergone a substantial change.  Our studies with process additives suggest that several key physical properties undergo major changes, including bitumen viscosity, interfacial tension, and interfacial charge.  If these are addressed then comparable optimum primary oil recoveries can be achieved under all of 25, 50, or 80°C conditions.  This is a significant result in terms of identifying the key mechanism(s) by which good primary froth recovery can be achieved.  It is shown that the interfacial property changes in particular are consistent with the expected thermodynamic conditions necessary for efficient bitumen separation and flotation.
 
 

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