Abstract:
The invention relates to an improved bitumen recovery process. The process includes adding water to a bitumen-froth/solvent system containing asphaltenes and mineral solids. The addition of water in droplets increases the settling rate of asphaltenes and mineral solids to more effectively treat the bitumen for pipeline transport, further enhancement, refining, or any other application of reduced-solids bitumen.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of U.S. Provisional Patent Application 61/065,371 filed Feb. 11, 2008. 
    
    
     FIELD OF THE INVENTION 
     The present invention relates generally to producing hydrocarbons. More specifically, the invention relates to methods and systems for upgrading bitumen in a solvent based froth treatment process. 
     BACKGROUND OF THE INVENTION 
     The economic recovery and utilization of heavy hydrocarbons, including bitumen, is one of the world&#39;s toughest energy challenges. The demand for heavy crudes such as those extracted from oil sands has increased significantly in order to replace the dwindling reserves of conventional crude. These heavy hydrocarbons, however, are typically located in geographical regions far removed from existing refineries. Consequently, the heavy hydrocarbons are often transported via pipelines to the refineries. In order to transport the heavy crudes in pipelines they must meet pipeline quality specifications. 
     The extraction of bitumen from mined oil sands involves the liberation and separation of bitumen from the associated sands in a form that is suitable for further processing to produce a marketable product. Among several processes for bitumen extraction, the Clark Hot Water Extraction (CHWE) process represents an exemplary well-developed commercial recovery technique. In the CHWE process, mined oil sands are mixed with hot water to create slurry suitable for extraction as bitumen froth. 
     The addition of paraffinic solvent to bitumen froth and the resulting benefits are described in Canadian Patent Nos. 2,149,737 and 2,217,300. According to Canadian Patent No. 2,149,737, the contaminant settling rate and extent of removal of contaminants present in the bitumen froth generally increases as (i) the carbon number or molecular weight of the paraffinic solvent decreases, (ii) the solvent to froth ratio increases, and (iii) the amount of aromatic and napthene impurities in the paraffinic solvent decreases. Further, a temperature above about 30 degrees Celsius (° C.) during settling is preferred. 
     In many instances, it may be advantageous to observe the particle size distribution (PSD) in a particular bitumen-froth mixture. This may be done to ensure that the resulting heavy hydrocarbon product meets pipeline specifications and other requirements and lead to adjustments in the recovery process. Various techniques such as optical, laser diffraction, electrical counting, and ultrasonic techniques have been used to determine PSD. 
     One reason for processing the heavy hydrocarbon product in such a process is to eliminate enough of the solids to meet pipeline transport specifications and the specifications of the refining equipment. For example, the sediment specification of the bitumen product as measured by the filterable solids test (ASTM-D4807) may be used to determine if the product is acceptable. As such, a higher settling rate of solid particles including mineral solids and asphaltenes from the froth-treated bitumen is desirable. 
     Methods to improve the settling rate of the minerals can significantly impact the efficiency of heavy hydrocarbon (e.g. bitumen) recovery processes. There exists a need in the art for a low cost method to produce bitumen which meets various sediment specifications. 
     SUMMARY OF THE INVENTION 
     In one aspect of the invention, a method of recovering hydrocarbons is provided. The method includes providing a bitumen froth emulsion containing asphaltenes and mineral solids; adding a solvent to the bitumen froth emulsion to induce a rate of settling of at least a portion of the asphaltenes and mineral solids from the bitumen froth emulsion and generate a solvent bitumen-froth mixture; and adding water droplets to the solvent bitumen-froth mixture to increase the rate of settling of the at least a portion of the asphaltenes and mineral solids. In one aspect, the solvent may be a paraffinic solvent. 
     In another aspect of the invention, a system for recovering hydrocarbons is provided. The system includes a bitumen recovery plant configured to treat a froth-treated bitumen. The plant includes a froth separation unit having a bitumen froth inlet and a diluted bitumen outlet; and a water droplet production unit configured to add water droplets to the froth-treated bitumen. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The foregoing and other advantages of the present invention may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which: 
         FIG. 1  is a schematic of an exemplary prior art bitumen froth treatment plant layout; 
         FIG. 2  is a flow chart of an exemplary bitumen froth treatment process including at least one aspect of the present invention; 
         FIG. 3  is a schematic of an exemplary bitumen froth treatment plant layout including at least one aspect of the present invention; 
         FIG. 4  is a schematic illustration of the experimental apparatus utilized with the present invention as disclosed in  FIGS. 2 and 3 ; 
         FIG. 5  is an image of asphaltene-mineral aggregates obtained with a JM Canty Microflow Particle Sizing System; and 
         FIGS. 6A-6B  are images of asphaltene-mineral-water aggregates obtained after the addition of water to the bitumen-froth-solvent mixture. 
     
    
    
     DETAILED DESCRIPTION 
     In the following detailed description section, the specific embodiments of the present invention are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present invention, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. 
     The term “asphaltenes” as used herein refers to hydrocarbons, which are the n-heptane insoluble, toluene soluble component of a carbonaceous material such as crude oil, bitumen or coal. Generally, asphaltenes have a density of from about 0.8 grams per cubic centimeter (g/cc) to about 1.2 g/cc. Asphaltenes are primarily comprised of carbon, hydrogen, nitrogen, oxygen, and sulfur as well as trace vanadium and nickel. The carbon to hydrogen ratio is approximately 1:1.2, depending on the source. 
     The term “mineral solids” as used herein refers to “clumps” of non-volatile, non-hydrocarbon solid minerals. Depending on the deposit, these mineral solids may have a density of from about 2.0 g/cc to about 3.0 g/cc and may comprise silicon, aluminum (e.g. silicas and clays), iron, sulfur, and titanium and range in size from less than 1 micron (μm) to about 1,000 microns (in diameter). 
     The term “fine solids” as used herein refers to either or both of asphaltenes and mineral solids, but does not generally refer to sand and clumps of clay, rock and other solids larger than about one hundred (100) microns. 
     The term “aggregates” as used herein generally refers to a group of solids comprising “asphaltenes” and “mineral solids”. 
     The term “bitumen” as used herein refers to heavy oil having an API gravity of about 12° or lower. In its natural state as oil sands, bitumen generally includes fine solids such as mineral solids and asphaltenes, but as used herein, bitumen may refer to the natural state or a processed state in which the fine solids have been removed and the bitumen has been treated to a higher API gravity. 
     The term “paraffinic solvent” (also known as aliphatic) as used herein means solvents containing normal paraffins, isoparaffins and blends thereof in amounts greater than 50 weight percent (wt %). Presence of other components such as olefins, aromatics or naphthenes counteract the function of the paraffinic solvent and hence should not be present more than 1 to 20 wt % combined and preferably, no more than 3 wt % is present. The paraffinic solvent may be a C4 to C20 paraffinic hydrocarbon solvent or any combination of iso and normal components thereof. In one embodiment, the paraffinic solvent comprises pentane, iso-pentane, or a combination thereof. In one embodiment, the paraffinic solvent comprises about 60 wt % pentane and about 40 wt % iso-pentane, with none or less than 20 wt % of the counteracting components referred above. 
     The invention relates to processes and systems for recovering hydrocarbons. In one aspect, the invention is a process to partially upgrade a bitumen or heavy crude and is particularly suited for bitumen froth generated from oil sands which contain bitumen, water, asphaltenes and mineral solids. The process includes extracting bitumen having asphaltenes and mineral solids from a reservoir in the form of a bitumen froth, adding a solvent to the bitumen-froth, then adding water droplets to the solvent bitumen-froth mixture to enhance the settling rate of asphaltenes and mineral solids from the bitumen-froth. 
     In another aspect, the invention relates to a system for recovering hydrocarbons. The system may be a plant located at or near a bitumen (e.g. heavy hydrocarbon) mining or recovery site or zone. The plant may include at least one froth separation unit (FSU) having a bitumen froth inlet for receiving bitumen froth (or a solvent froth-treated bitumen mixture) and a diluted bitumen outlet for sending diluted bitumen from the FSU. The plant further includes a water droplet production unit configured to add water droplets to the solvent froth-treated bitumen mixture, one or more of the FSU&#39;s and/or the diluted bitumen from at least one of the FSU&#39;s. The plant may also include at least one tailings solvent recovery unit (TSRU), solvent storage unit, pumps, compressors, and other equipment for treating and handling the heavy hydrocarbons and byproducts of the recovery system. 
     Referring now to the figures,  FIG. 1  is a schematic of an exemplary prior art paraffinic froth treatment system. The plant  100  receives bitumen froth  102  from a heavy hydrocarbon recovery process (e.g., CHWE). The bitumen froth  102  is fed into a first froth separation unit (FSU)  104  and solvent-rich oil  120  is mixed with the bitumen froth  102 . A diluted bitumen stream  106  and a tailings stream  114  are produced from the FSU  104 . The diluted bitumen stream  106  is sent to a solvent recovery unit (SRU)  108 , which separates bitumen from solvent to produce a bitumen stream  110  that meets pipeline specifications. The SRU  108  also produces a solvent stream  112 , which is mixed with tailings  114  from the first FSU  104  and fed into a second froth separation unit  116 . The second FSU  116  produces a solvent rich oil stream  120  and a tailings stream  118 . The solvent rich oil stream  120  is mixed with the incoming bitumen froth  102  and the tailings stream is sent to a tailings solvent (TSRU) recovery unit  122 , which produces a tailings stream  124  and a solvent stream  126 . 
     In an exemplary embodiment of the process the bitumen froth  102  may be mixed with a solvent-rich oil stream  120  from FSU  116  in FSU  104 . The temperature of FSU  104  may be maintained at about 60 to 80 degrees Celsius (° C.), or about 70° C. and the target solvent to bitumen ratio is about 1.4:1 to 2.2:1 by weight or about 1.6:1 by weight. The overflow from FSU  104  is the diluted bitumen product  106  and the bottom stream  114  from FSU  104  is the tailings substantially comprising water, mineral solids, asphaltenes, and some residual bitumen. The residual bitumen from this bottom stream is further extracted in FSU  116  by contacting it with fresh solvent (from e.g.  112  or  126 ), for example in a 25:1 to 30:1 by weight solvent to bitumen ratio at, for instance, 80 to 100° C., or about 90° C. The solvent-rich overflow  120  from FSU  116  is mixed with the bitumen froth feed  102 . The bottom stream  118  from FSU  116  is the tailings substantially comprising solids, water, asphaltenes, and residual solvent. The bottom stream  118  is fed into a tailings solvent recovery unit (TSRU)  122 , a series of TSRUs or by another recovery method. In the TSRU  122 , residual solvent is recovered and recycled in stream  126  prior to the disposal of the tailings in the tailings ponds (not shown) via a tailings flow line  124 . Exemplary operating pressures of FSU  104  and FSU  116  are respectively 550 thousand Pascals gauge (kPag) and 600 kPag. FSUs  104  and  116  are typically made of carbon-steel but may be made of other materials. 
       FIG. 2  is an exemplary flow chart of a process for recovering hydrocarbons utilizing at least a portion of the equipment disclosed in  FIG. 1 . As such,  FIG. 2  may be best understood with reference to  FIG. 1 . The process  200  begins at block  202 , then includes extraction of a heavy hydrocarbon to form a bitumen froth emulsion or mixture  204 . After extraction, the mixture is added to a froth separation unit (FSU)  206 , solvent is added to the mixture  208 , and water droplets are added to the solvent bitumen-froth mixture  210 . Steps  206 ,  208 , and  210  may be done concurrently or in sequence in any order. This will promote precipitation and settling of asphaltenes and mineral solids (and aggregates thereof) out of the solvent bitumen-froth mixture  212  to produce a diluted bitumen  214 . Solvent is then recovered from the diluted bitumen  216  to produce bitumen  218 . The process  200  may be repeated as necessary or desired  220 . 
     Still referring to  FIGS. 1 and 2 , the step of extracting the heavy hydrocarbon (e.g. bitumen)  204  may include using a froth treatment resulting in a bitumen-froth mixture. An exemplary composition of the resulting bitumen froth  102  is about 60 wt % bitumen, 30 wt % water and 10 wt % solids, with some variations to account for the extraction processing conditions. In such an extraction process oil sands are mined, bitumen is extracted from the sands using water (e.g. the CHWE process or a cold water extraction process), and the bitumen is separated as a froth comprising bitumen, water, solids and air. In the extraction step  204  air is added to the bitumen/water/sand slurry to help separate bitumen from sand, clay and other mineral matter. The bitumen attaches to the air bubbles and rises to the top of the separator (not shown) to form a bitumen-rich froth  102  while the sand and other large particles settle to the bottom. Regardless of the type of water based oil sand extraction process employed, the extraction process  204  will typically result in the production of a bitumen froth product stream  102  comprising bitumen, water and fine solids (including asphaltenes, mineral solids) and a tailings stream  114  consisting essentially of water and mineral solids and some fine solids. 
     In one embodiment of the process  200  solvent  120  is added to the bitumen-froth  102  after extraction and the mixture is pumped to another separation vessel (froth separation unit or FSU  104 ). The addition of solvent  120  helps remove the remaining fine solids and water. Put another way, solvent addition increases the settling rate of the fine solids and water out of the bitumen mixture. In one embodiment of the recovery process  200  a paraffinic solvent is used to dilute the bitumen froth  102  before separating the product bitumen by gravity in a device such as FSU  104 . Where a paraffinic solvent is used (e.g. when the weight ratio of solvent to bitumen is greater than 0.8), a portion of the asphaltenes in the bitumen are rejected thus achieving solid and water levels that are lower than those in existing naphtha-based froth treatment (NFT) processes. In the NFT process, naphtha may also be used to dilute the bitumen froth  102  before separating the diluted bitumen by centrifugation (not shown), but not meeting pipeline quality specifications. 
     Adding water droplets  210  to the bitumen froth mixture  102  helps increase the settling rate of the fine solids including asphaltenes, making the process  200  more efficient and allowing higher throughputs of bitumen to be treated and recovered or permitting smaller FSU&#39;s  104  and  116  to be used. This result is counterintuitive because it calls for adding water to the bitumen froth solvent mixture  102  even though bitumen froth already contains large quantities of water (e.g., 30-40% or more depending on the extraction process). Note, the process calls for adding “droplets,” which may vary in size, but as used in this application, a droplet is generally a volume of water small enough to maintain droplet form when falling through air and does not included water “slugs.” 
     The water droplets may be added before mixing the froth treated bitumen with solvent, may be added in the first FSU  104  and/or the second FSU  116  (note, some plants  100  may include three or more FSU&#39;s, any of which may include water droplet addition, depending on the plant  100  and process  200  parameters). The water may also be added above or below a feed injection point in the first or second FSU  104 ,  116 . The water droplet addition increases the propensity of the mineral solids and asphaltenes to attach to each other to create larger particles. The larger particles then settle faster than smaller particles resulting in an increase in the settling rate of greater than a factor of two. The amount of water added can be optimized to enhance the settling rate of the minerals and asphaltenes. Higher settling rates may also permit reduction of the size and cost of the FSU vessels  104 ,  116  required to meet the pipeline sediment specification. For example, the vessels  104 ,  116  may have an eight to twelve meter diameter rather than an 18 to 22 meter diameter. The addition of water can also be used to optimize an existing paraffinic froth-treatment by increasing the production rate and/or improving the product quality. 
     As would be expected with any process, the optimum conditions would be preferred to produce the largest particle size distribution and subsequently the fastest settling time. Variables may be optimized include, but are not limited to; water-to-bitumen ratio (e.g. from 0.01 weight percent (wt %) to 10 wt %), mixing energy, water droplet size, temperature, solvent addition, and location of water addition. Water may be added either to the FSU feed streams  102 ,  114  and/or internally within the FSU vessels  104 ,  116 . Within the FSU vessels the water can be added either above and/or below the feed injection point. Further, the type of water used will depend on the available water sources, but is preferably one of fresh river water, distilled water from a solvent recovery unit  108 , recycled water, rain water, or aquifer water. 
       FIG. 3  is an exemplary schematic of a bitumen froth treatment plant layout utilizing the process of  FIG. 2 . As such,  FIG. 3  may be best understood with reference to  FIG. 2 . The plant  300  includes a bitumen froth input stream  302  input to a froth separation unit (FSU)  304 , which separates stream  302  into a diluted bitumen component  306  comprising bitumen and solvent and a froth treatment tailings component  312  substantially comprising water, mineral solids, precipitated asphaltenes (and aggregates thereof), solvent, and small amounts of unrecovered bitumen. The tailings stream  312  may be withdrawn from the bottom of FSU  304 , which may have a conical shape at the bottom. A water droplet production unit  303  is also included, which produces water droplets  305   a ,  305   b ,  305   c  and/or  305   d  for addition to, respectively, the bitumen froth input stream  302 , FSU  304 , tailings stream  312 , or FSU  320 . 
     In one embodiment, the water droplet production unit  303  may be a spray nozzle system. The unit  303  may produce droplets at a concentration of at least about 0.01 weight percent (wt %) relative to bitumen to at most about 10 wt % relative to bitumen depending on the composition of the bitumen, size of the handling units (e.g. FSU&#39;s) and other factors. Further, the droplets may be produced at a size of from at least about 5 microns (μm) in diameter to about 1,000 microns in diameter, although a range of from about 5 microns to about 500 microns is preferred. The added water may be fresh river water, distilled water from a solvent recovery unit  308 , recycled water, rain water or aquifer water. 
     The diluted bitumen component  306  is passed through a solvent recovery unit, SRU  308 , such as a conventional fractionation vessel or other suitable apparatus in which the solvent  314  is flashed off and condensed in a condenser  316  associated with the solvent flashing apparatus and recycled/reused in the process  300 . The solvent free bitumen product  310  is then stored or transported for further processing in a manner well known in the art. Froth treatment tailings component  312  may be passed directly to the tailings solvent recovery unit (TSRU)  330  or may first be passed to a second FSU  320 . 
     In one embodiment, FSU  304  operates at a temperature of about 60° C. to about 80° C., or about 70° C. In one embodiment, FSU  304  operates at a pressure of about 700 to about 900 kPa, or about 800 kPa. Diluted tailings component  312  may typically comprise approximately 50 to 70 wt % water, 15 to 25 wt % mineral solids, and 5 to 25 wt % hydrocarbons. The hydrocarbons comprise asphaltenes (for example 2.0 to 12 wt % or 9 wt % of the tailings), bitumen (for example about 7.0 wt % of the tailings), and solvent (for example about 8.0 wt % of the tailings). In additional embodiments, the tailings comprise greater than 1.0, greater than 2.0, greater than 3.0, greater than 4.0, greater than 5.0, greater than 10.0 wt % asphaltenes, or about 15.0 wt % asphaltenes. 
     Still referring to  FIG. 3 , FSU  320  performs generally the same function as FSU  304 , but is fed the tailings component  312  rather than a bitumen froth feed  302 . The operating temperature of FSU  320  may be higher than that of FSU  304  and may be between about 80° C. and about 100° C., or about 90° C. In one embodiment, FSU  320  operates at a pressure of about 700 to about 900 kPa, or about 800 kPa. A diluted bitumen component stream  322  comprising bitumen and solvent is removed from FSU  320  and is either sent to FSU  304  via feed  324  for use as solvent to induce asphaltene separation or is passed to SRU  308  via feed  325  or to an another SRU (not shown) for treatment in the same way as the diluted bitumen component  306 . The ratio of solvent:bitumen in diluted bitumen component  322  may be, for instance, 1.4 to 30:1, or about 20:1. Alternatively, diluted bitumen component  322  may be partially passed to FSU  304  via line  324  and partially passed to SRU  308  via line  325 , or to another SRU (not shown). Solvent  314  from SRU  308  may be combined with the diluted tailing stream  312  into FSU  320 , shown as stream  318 , or returned to a solvent storage tank (not shown) from where it is recycled to make the diluted bitumen froth stream  302 . Thus, streams  322  and  318  show recycling. In the art, solvent or diluted froth recycling steps are known such as described in U.S. Pat. No. 5,236,577. 
     In the exemplary system of  FIG. 3 , the froth treatment tailings  312  or tailings component  326  (with a composition similar to underflow stream  312  but having less bitumen and solvent), may be combined with dilution water  327  to form diluted tailings component  328  and is sent to TSRU  330 . Diluted tailings component  328  may be pumped from the FSU  320  or FSU  304  (for a single stage FSU configuration) to TSRU  330  at the same temperature and pressure in FSU  320  or FSU  304 . A backpressure control valve  329  may be used before an inlet into TSRU  330  to prevent solvent flashing prematurely in the transfer line between FSU  320  and TSRU  330 . 
     Flashed solvent vapor and steam (together 334) is sent from TSRU  330  to a condenser  336  for condensing both water  338  and solvent  340 . Recovered solvent  340  may be reused in the bitumen froth treatment plant  300 . Tailings component  332  may be sent directly from TSRU  330  to a tailings storage area (not shown) for future reclamation or sent to a second TSRU (not shown) or other devices for further treatment. Tailings component  332  contains mainly water, asphaltenes, mineral matter, and small amounts of solvent as well as unrecovered bitumen. A third TSRU (not shown) could also be used in series and, in each subsequent stage, the operating pressure may be lower than the previous one to achieve additional solvent recovery. In fact, more than three TSRU&#39;s could be used, depending on the quality of bitumen, pipeline specification, size of the units and other operating factors. 
     EXAMPLES 
     Experiments were conducted to test the effectiveness of water droplet addition to the bitumen froth streams. The experiments were designed to take small samples of bitumen froth streams, add some water droplets in accordance with the present invention and capture images of the bitumen froth streams before and after addition of the water droplets. 
       FIG. 4  is a schematic illustration of the experimental apparatus utilized with the present invention as disclosed in  FIGS. 2 and 3 . Hence,  FIG. 4  may be best understood with reference to  FIGS. 2 and 3 . The experimental setup  400  includes a vessel  402  with a stirrer  404  holding a sample of bitumen froth  405 . The vessel is connected to a particle size analyzer apparatus  406 , which includes a particle sizing computer system  408 , an image analyzer  410 , a variable width flow cell  412 , and a light source  414 . The particle size analyzer apparatus  406  is then connected to a pinch clamp  416  and a beaker  418  for receiving the analyzed samples  405 . 
     Example 1 
     In the first example, the bitumen froth sample  405  was 75 grams of Syncrude bitumen froth (60 wt % bitumen, 30 wt % water and 10 wt % mineral matter). The bitumen froth  405  was added to 400 ml of 60/40 pentane/iso-pentane solvent and stirred with the stirrer  404  in the vessel  402 . This particular bitumen froth  405  was chosen because its composition is representative of produced bitumen froth  102  or  302 . The stirrer  404  was used to mix the contents and keep the solids suspended in solution. The bitumen solvent mixture  405  was fed by gravity to the particle size analyzer apparatus  406 . In this case, a JM Canty Microflow Particle Size system (Model #MIC-LG2K11B11GZ) was used. The sample  405  was fed to the flow cell  412  at approximately 150 ml/min. The gap in the flow cell  412  was set at an optimum width of 300 micrometers (μm). Too large a gap did not provide enough light to resolve the particles while too small a gap restricted the flow of the particles. Images were taken by the image analyzer  410  and recorded by the computer system  408 . 
       FIG. 5  is an image of asphaltene-mineral aggregates obtained with the particle size analyzer apparatus  406  with no water addition to the bitumen-froth-solvent mixture  405 . The scale of the image  500  is shown on the image by a 100 micro-meter (micron or μm) line  502 . As can be seen, numerous particles less than 100 μm in size are observed. 
     Example 2 
     In a second test, the bitumen froth sample  405  was 75 grams of Syncrude bitumen froth (60 wt % bitumen, 30 wt % water and 10 wt % mineral matter). The bitumen froth  405  was added to 400 ml of 60/40 pentane/iso-pentane solvent and stirred with the stirrer  404  in the vessel  402 . The stirrer  404  was used to mix the contents and keep the solids suspended in solution for a few minutes. Then, about 50 grams of water was added to the bitumen froth-solvent mixture  405  while the stirrer  404  continued to mix the solution. The bitumen-solvent-water mixture was fed by gravity to the flow cell  412  at approximately 150 ml/min. The gap in the flow cell was set at an optimum width of 300 μm. Images were taken by the image analyzer  410  and recorded by the computer system  408 . 
       FIGS. 6A-6B  are images of asphaltene-mineral-water aggregates obtained after the addition of water to the bitumen-froth-solvent mixture  405 . In  FIG. 6A , the scale of the image  600  is shown by a 100 micron line  602 . As shown, particles significantly greater than 100 microns are generated. In comparison to the image  500 , there appear to be more large particles.  FIG. 6B  shows a magnified image  610  of the particulates bounded with water droplets  612 . The image  610  is magnified to show more clearly the presence and location of water droplets  612 . The scale of the image  610  is shown by a 100 micron line  614 . 
     While the present invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present invention includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.