US20160362608A1

US20160362608A1 - Dual-solvent extraction of oil sand bitumen

Info

Publication number: US20160362608A1
Application number: US14/739,409
Authority: US
Inventors: Xin Alex Wu; Sujit Bhattacharya
Original assignee: Syncrude Canada Ltd
Current assignee: Syncrude Canada Ltd
Priority date: 2015-06-15
Filing date: 2015-06-15
Publication date: 2016-12-15

Abstract

A process for extracting bitumen from oil sand is provided, comprising: contacting mined oil sand with a high-flash point heavy solvent (HS) to produce a dense oil sand slurry; mixing the dense slurry with a first light solvent (LS) stream and a second LS stream to give a heavy solvent to light solvent (HS/LS) mass ratio of about 75/25 to about 40/60; subjecting the HS/LS-diluted oil sand slurry to a first stage solid-liquid separation to produce a first liquids stream containing bitumen and a first solids stream; and washing the first solids stream with a mixed solvent having a HS/LS mass ratio of about 50/50 to about 20/80 and subjecting the solids and the mixed solvent to a second stage solid-liquid separation to produce a second liquids stream and a second solids stream.

Description

FIELD OF THE INVENTION

The present invention relates to a solvent extraction process which uses at least two different solvents for extracting bitumen from mined oil sands.

BACKGROUND OF THE INVENTION

The present commercial bitumen extraction process for mined oil sands is Clark hot water extraction technology or its variants that use large amounts of water and generate a great quantity of wet tailings. Part of the wet tailings becomes fluid fine tailings (FFT), which contain approximately 30% fine solids and are a great challenge for tailings treatment. In addition, certain “problem” oil sands, often having high fines content, yield low bitumen recoveries in the water-based extraction process. This leads to economic losses and environmental issues with bitumen in wet tailings.
An alternative to water-based extraction is solvent extraction of bitumen from mined oil sands, which uses little or no water, generates no wet tailings, and can potentially achieve higher bitumen recovery than the existing water-based extraction, especially for the aforementioned problem oil sands. Therefore, solvent extraction is potentially more robust and more environmentally friendly than water-based extraction.
The majority of solvent extraction processes taught in the prior art use a single solvent or a solvent mixture having a fixed composition throughout the process. This solvent may be a light solvent with a typical boiling range of 36-110° C., an intermediate solvent with a typical boiling range of 66-205° C., or a heavy solvent with a typical boiling range of 177-343° C. However, the use of any light or intermediate solvent poses a fire hazard during the initial contact of solvent with oil sands in a vessel that is not adequately purged or deoxygenated with an inert gas. Effectively purging such a vessel is a challenge due to the sticky nature of oil sands that may not allow effective use of air locks for the feed. If the oil sands are transported from a deoxygenation unit to a solvent contact unit through a semi-open port, solvent vapor may travel from the solvent contact unit to the deoxygenation unit and mix with air and/or the inert gas, thereby posing a fire hazard and causing solvent loss. Oil sands may be fed through a bath of liquid such as water to deoxygenate, as disclosed in Canadian Patent No. 2,815,132. However, this process may add excessive water which is problematic for solvent recovery. Further, the oil sand-volatile solvent mixture is fed through multiple slurry conditioning units which are not gas-tight, allowing leakage of solvent vapor.
Attempts to solve the above issues by using two solvents sequentially encounter solid/liquid separation problems and issues with higher solvent demand and operating costs. A non-volatile light gas oil and bitumen mixture for initial slurry preparation is disclosed in Canadian Patent No. 2,751,719. Inert gas blanketing is provided in the contact vessel in case light hydrocarbon contaminant is present in the mixture. Minimizing contaminant through proper operation of a distillation unit may decrease solvent vapor release in semi-sealed slurry conditioning units. However, this process requires a second light volatile solvent to facilitate solvent-diluted bitumen separation and solvent recovery from solids.
Processes for extracting oil sand bitumen using two solvents are disclosed in Canadian Patent Nos. 2,751,719 and 2,761,555 and U.S. Pat. Nos. 3,117,922 and 3,131,141. Such processes yield two hydrocarbon streams. The first stream is generated from the first separation of diluted bitumen from solids, and contains bitumen at a high concentration and one or two solvents. The second stream is generated from a subsequent separation of diluted bitumen and wash liquid from solids and contains bitumen at a lower concentration and two solvents at a different ratio compared to that in the first stream. The second stream cannot be directly recycled at the initial slurry preparation stage due to the presence of the second (volatile) solvent and the safety/solvent loss issues mentioned above. These two streams necessitates two separate flash/distillation units for separation, complicating the process and incurring greater operational costs compared to a single-solvent extraction process which allows direct recycling of low bitumen streams at the slurry preparation stage and requires only one flash/distillation unit for its product. Combining these two streams as in U.S. Pat. No. 3,117,922 reduces the bitumen concentration in the product and increases the size and cost of the flash/distillation unit to process the diluted product.
After slurry preparation and conditioning, diluted bitumen is typically separated from any solids through gravity settling, filtration, or other techniques. To speed up the separation rate, water may be added to bind fine solids and coarse sand to reach a total water to solids (W/S) mass ratio ranging between about 0.08 to 0.15 in slurry (i.e., “solids agglomeration” as disclosed in Canadian Patent Nos. 2,724,806, 2,740,468 and 2,740,481, and U.S. Pat. Nos. 4,057,486 and 4,719,008). In order to completely recover solvent from spent solids to meet the environmental requirements, the W/S ratio needs to be reduced to at least 0.02 and involves energy-intensive operations that increase greenhouse gas emissions. As an example, processing oil sands at 8000 t/h requires drying water at the rate of about 680 t/h in addition to solvent vaporization, assuming 85 wt % solids content in oil sands and W/S=0.12. Drying the relatively wet agglomerates using multiple dryers is an energy-intensive, uneconomical operation.
In summary, none of the prior art solvent extraction processes can resolve all of the following issues:

1. Fire hazard and solvent loss at initial contact of solvent with oil sands in an extraction process using a single volatile solvent;
2. Complicated flow sheet and greater operational costs for multiple flash/distillation units in an extraction process using two solvents; and
3. Conflicting requirements of water addition to satisfy fast solid-liquid separation and drying of spent solids for solvent recovery.

There is a need for a solvent extraction process that is safe, operable and economical.

SUMMARY OF THE INVENTION

The present invention relates to a solvent extraction process which uses at least two different solvents for extracting bitumen from mined oil sands. It was surprisingly discovered that by using the process of the present invention, one or more of the following benefits may be realized:
(1) The solvent extraction process of the present invention provides greater flexibility in the choices of heavy solvent (HS) and light solvent (LS), and the ranges of HS/LS mass ratios. The HS/LS mass ratio may vary from the first to the last separation stage within the process to optimize bitumen recovery and separation rate.
(2) The process improves safety and minimizes solvent vapor loss. After initial contact with a high-flash point HS to form dense slurry for oil sand deoxygenation and before mixing with LS and solids flocculation, the dense slurry is passed through an airlock to isolate oxygen-free and LS-containing atmosphere downstream from oxygen-containing and LS-free atmosphere upstream, thereby reducing fire hazard or solvent loss.
(3) Solids flocculation is achieved using a relatively intense mixer, e.g. an unconventionally designed baffled tank agitated with impellers, allowing for use of a relatively low water to solids (W/S) mass ratio. The W/S mass ratio in slurry may be less than about 0.1, preferably less than about 0.08,
(4) The process combines multiple LS streams into a second slurry preparation and conditioning unit, and recycles the LS for use in bitumen dissolution and solids flocculation. Recycling these LS streams does not reduce the bitumen concentration in the final product. A single hydrocarbon stream is thereby generated in the process so that a single distillation unit can be used for component separation without reducing the total solvent use efficiency. The process provides a less complex flow sheet and minimizes operational costs.
Use of the present invention achieves good bitumen recovery, good solvent recovery, and cleaner dry tailings. Thus, broadly stated, in one aspect of the present invention, a process for extracting bitumen from oil sand is provided, comprising:

- contacting mined oil sand with a high-flash point heavy solvent (HS) to produce a dense oil sand slurry;
- mixing the dense slurry with a first light solvent (LS) stream and a second LS stream to give a heavy solvent to light solvent (HS/LS) mass ratio of about 75/25 to about 40/60;
- subjecting the HS/LS-diluted oil sand slurry to a first stage solid-liquid separation to produce a first liquids stream containing bitumen and a first solids stream;
- washing the first solids stream with a mixed solvent having a HS/LS mass ratio of about 50/50 to about 20/80 and subjecting the solids and the mixed solvent to a second stage solid-liquid separation to produce a second liquids stream and a second solids stream.

In one embodiment, the process further comprises mixing the dense slurry and LS streams with a minimal amount of water to give a total water to solids (W/S) mass ratio less than about 0.1 to flocculate solids.
In one embodiment, the process further comprises passing the dense oil sand slurry for deoxygenation through an airlock after initial contact with the high-flash point HS to minimize the risks of fire hazard or solvent loss.
In one embodiment, the process further comprises mixing the second solids stream and LS in a repulper prior to being subjected to a third stage solid-liquid separation to produce a third liquids stream and a third solids stream. In one embodiment, the process further comprises washing the third solids stream with LS and subjecting the solids and LS stream to a fourth stage solid-liquid separation to produce a fourth liquids stream and a fourth solids stream. The fourth liquids stream is predominantly LS and is used in repulping. The fourth solids stream is dried in a solids dryer to produce dry tailings.
In another aspect of the invention, solids flocculation is conducted using a baffled tank agitated with one or more impellers while the dense slurry is being mixed with LS streams. Water is added into this tank to give a total water to solids (W/S) mass ratio less than about 0.1, In one embodiment, the one or more impellers comprise 45° pitched blade turbines having a diameter ranging from about 0.55 to about 0.7 of the tank diameter. In one embodiment, the bottom clearance ranges from about 0.01 to about 0.15 of the tank diameter. In one embodiment, the power input by the one or more impellers ranges from about 1 W/kg to about 15 W/kg of slurry.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will now be described by way of an exemplary embodiment with reference to the accompanying simplified, diagrammatic, not-to-scale drawings:

FIG. 1A (Prior Art) and FIG. 1B are graphs of heavy solvent to light solvent ratio (HS/LS) (from 0/100 to 100/0) versus bitumen concentration in hydrocarbons (from high to low).

FIG. 2 is a schematic process flow diagram of one embodiment of the solvent extraction process.

FIG. 3 is a schematic diagram which clarifies the structural differences among flocs, microagglomerates, and pellets as set out in the prior art (Meadus and Sparks, 1983).

FIG. 4A (Prior Art) and FIG. 4B are schematic diagrams of baffled tanks agitated with impellers.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The detailed description set forth below in connection with the appended drawings is intended as a description of various embodiments of the present invention and is not intended to represent the only embodiments contemplated by the inventors. The detailed description includes specific details for the purpose of providing a comprehensive understanding of the present invention. However, it will be apparent to those skilled in the art that the present invention may be practised without these specific details.
The present invention relates generally to a solvent extraction process which uses at least two different solvents for extracting bitumen from mined oil sands. A conventional process is disclosed in Canadian Patent No. 2,751,719 (CA '719) which uses a combination of a heavy solvent (HS) and a light solvent (LS). Compared to this prior art process, the present invention provides a greatly improved process.
Without being bound to theory, the principle behind using a combination of a heavy solvent (HS) and a light solvent (LS) is illustrated in FIGS. 1A (CA '719) and 1B which show plots of heavy solvent to light solvent ratios (HS/LS) from 0/100 to 100/0 on the Y axis versus bitumen concentration in hydrocarbons (from high to low) on the X-axis. The X-axis also represents the progression of extraction from left to right. The shaded area shows the region of asphaltene precipitation.
Each filled circle represents a stage of mixing and/or separation. The first circle represents the initial mixing of dry oil sand and heavy solvent to form a dense slurry. This stage is the same in both the CA '719 process and the process of the present invention.
The second circle represents the conditions in the first stage of the first solid-liquid separator. In the CA '719 process, the mass ratio of HS/LS is controlled to be in the range of about 70/30 to about 50/50, preferably 60/40, to ensure little to no asphaltene precipitation. Similarly, in the process of the present invention, the mass ratio of HS/LS is controlled to be in the range of about 75/25 to about 40/60 to ensure little to no asphaltene precipitation. Aside from the slight variation in the ranges for the mass ratio of HS/LS, this stage is essentially the same in both the CA '719 process and the process of the present invention.
The third circle represents the conditions in the second stage of the first solid-liquid separator. At this stage, there are significant differences between the CA '719 process and the process of the present invention. In the CA '719 process, the mass ratio of HS/LS is adjusted from being within a range of about 70/30 to about 50/50 (preferably about 60/40) to within a range of about 75/25 to about 55/45 (preferably about 65/35). The HS/LS mixture is thus adjusted to have a significant proportion of HS. The HS concentration is increased while the LS concentration is decreased to avoid asphaltene precipitation. At a HS/LS mass ratio ranging from about 75/25 to about 55/45, little asphaltene will precipitate out since the HS concentration is sufficiently high to dissolve any asphaltene precipitate. However, this causes higher HS loss to spent solids as the elevated HS concentration in liquid trapped in solids at the third circle must be brought down to a low value in the next two stages of washing/separation, which ideally should be zero. This is schematically shown by the fifth circle in FIG. 1A being substantially higher than the dashed base line, which is not the case with the fifth circle in FIG. 1B.
In the process of the present invention, the mass ratio of HS/LS is adjusted from being within a range of about 75/25 to about 40/60 to within a range of about 50/50 to about 20/80. The HS/LS mixture is thus adjusted to have a significant proportion of LS (in contrast to the greater proportion of HS in the CA '719 process). The HS/LS mixture has a decreased concentration of HS and an increased concentration of LS, but results in asphaltene precipitation. Despite the high LS concentration, this stream still contains some HS, which makes the asphaltene precipitate soft and non-sticky so that the chance of plugging and fouling is minimized. More importantly, the asphaltene precipitate is recycled back into a second slurry preparation and conditioning unit (represented by the second circle in FIG. 1B) where it is easily re-dissolved. The re-dissolution of asphaltene precipitate minimizes oil loss.
The increase of LS concentration at the third circle of FIG. 1B compared to the third circle of FIG. 1A (the CA '719 process) has two main advantages. First, the more gradual decrease of HS proportion shown in FIG. 1B allows a complete LS countercurrent wash scheme: 5^th(circle)->4^th->3^rd->2^ndwithout the need of a flash drum to process any of these streams. In comparison, the CA '719 process only allows two “broken” countercurrent wash schemes: 5^th(circle)->4^th->2^ndand 3^rd(circle)->flash drum->1^stdue to the requirement of high HS concentration at the third circle. Therefore, the present invention simplifies the flow sheet and increases the solvent use efficiency since the flash drum in the CA '719 process removes some HS and LS from the roles of bitumen dissolution and solids flocculation in the second slurry preparation and conditioning unit (second circle). The streams in the process of the present invention are thus predominantly LS streams which are ultimately directed into the second slurry preparation and conditioning unit. Second, because the HS concentration has been reduced at the third circle, the amount of HS loss to the spent solids has been reduced compared to that in the CA '719 process. This is schematically shown by the fifth circle touching the dashed base line in FIG. 1B, unlike in FIG. 1A (prior art).
The next stage is the same in both the CA '719 process and the process of the present invention. The solids produced in the first separator will have a low bitumen concentration and can be further treated with light solvent to reduce the heavy solvent present in the solids in a second separator to produce tailings having little or no bitumen and little or no heavy solvent (fourth and fifth circles). In the second separator, the amount of bitumen is low enough that the addition of light solvent will not result in a significant amount of asphaltene precipitation.
Compared to the CA '719 process, the solvent extraction process of the present invention provides greater flexibility in the choice of heavy and light solvents and the range of HS/LS ratios. Further, the process improves safety by minimizing fire hazard and solvent vapor release through inclusion of an airlock. Solids flocculation is achieved by ensuring optimal water to solids ratio in a baffled tank agitated with impellers. Surprisingly, by recycling multiple streams containing a light solvent into a second slurry preparation and conditioning unit for use in bitumen dissolution and solids flocculation, a single hydrocarbon product stream is thereby generated in the process for component separation in a single distillation unit without reducing the bitumen concentration in the product or the total solvent use efficiency. Overall, the process of the present invention achieves good bitumen recovery, good solvent recovery, and cleaner dry tailings.
The heavy solvent used in the present embodiment is a light gas oil stream, i.e. a distillation fraction of oil sand bitumen, of mixed C₉to C₃₂hydrocarbons with a boiling range within about 130-470° C. The light end boiling is below about 170° C. The contaminant content originating from a naphtha stream in the upgrader is less than about 5 wt %. It has a flash point of about 90° C. in air.
The light solvent is a hydrocarbon stream C₆-C₁₀with a boiling range of 69-170° C., which light solvent is available from bitumen upgrading units. The preferred LS is aliphatic C₆-C₇with a boiling range of 69-110° C.
Turning to the specific embodiment shown in FIG. 2, cold oil sand 10 is mixed with hot HS 12 with a temperature range of about 70-200° C. from conduit 14 and optionally, with water 16 from conduit 18, in a first slurry preparation and conditioning unit 20. The unit 20 may comprise a rotating tumbler followed by a two-stage sizer/crusher. Longitudinal lifters may be present in the tumbler to assist in the comminution of large oil sand lumps by lifting and dropping them on other oil sand lumps. The solids content in the dense slurry in the slurry preparation and conditioning unit 20 is about 60-75 wt %. The dense slurry temperature is preferably around 50° C., the source of heat being primarily from the hot HS 12 from conduit 14.
The bitumen concentration in the dense slurry in the slurry preparation and conditioning unit 20 is about 25-65 wt %. In one embodiment, the HS-dominant stream 12 contains about 70 wt % HS and about 30 wt % recycled bitumen. The bitumen concentration in the dense slurry is about 50 wt %. In one embodiment, the HS-dominant stream 12 is pure HS. The bitumen concentration in the dense slurry is about 30 wt %.
Preparation of the dense slurry in the unit 20 also deoxygenates the oil sand by filling its air pockets. An inert gas, e.g. nitrogen, may be used to continuously purge the unit 20. Some residual oxygen can be tolerated in the unit 20 since the HS and the bitumen are not flammable at the slurry temperature. The inert gas purge in the unit 20 acts as first-stage oxygen reduction that helps in maintaining a safe oxygen-free atmosphere downstream. Alternatively, air may be used to ventilate the unit 20 to reduce the hydrocarbon vapor concentration below its low flammable limit. The vented air may be used in combustion in solids dryer 22 to prevent the release of hydrocarbon vapor to the atmosphere. Inert gas purge may be limited to the area in vicinity to an airlock 28,
The dense slurry stream 24 exits the unit 20 via conduit 26, and passes through an airlock 28 and into a second slurry preparation and conditioning unit 30. In one embodiment, the dense slurry stream 24 flows by gravity from the unit 20, through the airlock 28, and into the unit 30. The airlock 28 provides an atmosphere substantially free of oxygen downstream of it. In one embodiment, the airlock 28 comprises a rotary valve and seals to separate the oxygen-containing atmosphere in the unit 20 from the inert atmosphere downstream. The hydrocarbons in the dense slurry provide additional sealing and prevent solids from sticking within the airlock 28.
Fines liberation into the hydrocarbons should be minimized to keep the solid-liquid separation rates sufficiently high. Addition of water to the oil sand causes aggregation of fines with sand grains that minimizes the fines liberation. According to Meadus and Sparks (1983; FIG. 3), the amount of water added can influence the type of aggregated solids. The types of aggregated solids are distinguished as “flocs”, “microagglomerates” or “pellets”. The process to form “flocs” is thus called “solids flocculation” and the process to form “microagglomerates” or “pellets” is called “solids agglomeration”.
With regard to solids flocculation, the aggregation of fines with sand grains forms “flocs” which are characterized as having a pendular structure with few water molecules filling the spaces among the solids, and loosely bridging the solids together. The percentage of pore filling by the bridging water ranges from about 0.5% to about 50%.
With regard to solids agglomeration, the aggregation of fines with sand grains forms “microagglomerates” which are characterized as having a funicular structure with a greater amount of water molecules filling the spaces among the solids, and more securely bridging the solids together. The percentage of pore filling by the bridging water ranges from about 45% to about 95%.
The second slurry conditioning unit 30 substantially completes bitumen dissolution and solid flocculation. Compared to solids agglomeration, solids flocculation requires much less water. For solids flocculation, the water to solids (W/S) ratio is typically less than about 0.1, preferably less than about 0.08 (refer to Examples 1-3). For solids agglomeration, the water to solids ratio is greater than 0.08 (U.S. Pat. No. 4,719,008) and typically greater than 0.1 to be functional (refer to Example 3). Solids flocculation is preferred over solids agglomeration since less water is required, enabling less heat duty in spent solids drying and better recovery of LS from solids, thereby saving energy and generating cleaner dry tailings.
The second slurry preparation and conditioning unit 30 may comprise a static or dynamic mixer. Preferably, the mixer is a baffled tank agitated with impellers. A conventional mixer has an impeller diameter of about 0.33-0.5 of the tank diameter and a bottom clearance of about 0.33 of the tank diameter (FIG. 4A; Paul et al. (ed.) “Handbook of Industrial Mixing—Science and Practice,” John-Wiley and Sons: Hoboken N.J. 2004, pp. 157), but it does not provide effective solids flocculation. In comparison, the mixer of the present invention with large diameter impellers placed at a low clearance is configured to induce solids flocculation (FIG. 4B). In one embodiment, the impellers are 45° pitched blade turbines having a diameter ranging from about 0.55 to about 0.7 of the tank diameter. The bottom clearance ranges from about 0.01 to about 0.15 of the tank diameter. In one embodiment, the bottom clearance ranges from about 1 cm to about 5 cm for any tank diameter. The power input by the impellers ranges from about 1 W/kg to about 15 W/kg of slurry.
In the second slurry preparation and conditioning unit 30, the slurry 24 is dosed with a minimal amount of water 16 or an aqueous solution (e.g., water from oil sands tailing ponds) having a pH of about 8-8.5 from conduit 32. Water or aqueous solution is added to yield a total water to solids mass ratio (W/S) of less than about 0.1, preferably less than about 0.08.
The slurry 24 is further mixed with a LS-rich stream 34 from conduit 36, and a LS-dominant stream 38 from conduit 40 in the slurry preparation and conditioning unit 30. The LS-rich stream 34 may contain LS in an amount ranging from about 45 wt % to about 65 wt %. The LS-dominant stream 38 may contain LS in a greater amount ranging from about 70 wt % to about 90 wt %.
The mass ratio of HS/LS in the LS-diluted slurry is controlled to be in the range of about 75/25 to about 40/60 by adjusting the flow rates in conduits 36 and 40 to ensure little to no asphaltene precipitation and to facilitate the subsequent solid-liquid separation. The solids content in the mixed slurry in the slurry preparation and conditioning unit 30 is about 45-60 wt %. The bitumen concentration in the mixed hydrocarbon phase in the slurry preparation and conditioning unit 30 is about 15-40 wt %.
In one embodiment wherein the HS-dominant stream 12 contains recycled bitumen, the HS/LS ratio ranges from about 55/45 to about 45/55 in LS-diluted slurry. The bitumen concentration in the mixed hydrocarbon phase in unit 30 is about 25-40 wt %.
In one embodiment wherein the HS-dominant stream 12 comprises pure HS, the HS/LS ratio ranges from about 72/28 to about 62/38 in LS-diluted slurry. The bitumen concentration in the mixed hydrocarbons in unit 30 is about 15-30 wt %.
All LS-containing streams in the process are combined into streams 34 and 38 and reused in the second slurry preparation and conditioning unit 30 to reduce the solids concentration in the dense slurry 24 to a suitable level for proper bitumen dissolution, floc formation and subsequent solid-liquid separation. The use of the “waste” LS-containing streams reduces the total HS and LS to oil sand bitumen mass ratios to about 1 and 3, respectively, for the process with bitumen recycle in stream 12. In comparison, the CA '719 process requires these ratios to be about 1.3 and 3.5, respectively, to achieve similar solids and bitumen concentrations in streams throughout the process. This improvement of solvent use efficiency is achieved by eliminating the flash drum in CA '719 process that removes some HS and LS from the process after merely one washing step.
The LS-diluted slurry 42 is then fed onto a first solid-liquid separator 44. In one embodiment, the first solid-liquid separator 44 may comprise a top-loading filter such as, for example, an enclosed pan filter. The first solid-liquid separator 44 contains at least two stages which are shown separated with a dashed line in FIG. 2. The first-stage separation generates a first liquids stream 46 and a first solids stream 48. The first liquids stream 46 is sent to a distillation unit 50 via conduit 52 to recover LS 54 and HS 56, removed via conduits 58 and 60, respectively, and to produce bitumen 62, which is removed via conduit 64. Recovered HS and LS flow into tank 66 and tank 68, respectively. Tank 68 receives another recycled LS stream 70 via conduit 72. Tank 68 also receives a LS makeup stream 132 via conduit 134. The HS makeup is produced internally by distilling the product bitumen in the unit 50 since the HS here is a fraction of bitumen. The HS makeup is included in the recovered HS stream 56 from conduit 60. In one embodiment, the distillation unit 50 includes multiple distillation columns. LS may be recovered in one column and HS in the next column. In one embodiment, the recovered HS stream 56 comprises about 20-40 wt % recycled bitumen and 60-80 wt % HS. In one embodiment, the recovered HS stream 56 is pure HS.
If the first liquids stream 46 is untreated, the bitumen 62 may contain about 1 wt % solids, similar to the product of naphtha-based froth treatment in a water-based extraction process. If the stream 46 is partially deasphalted, the bitumen 62 contains less than about 500 mg/kg solids.
After the first-stage separation, the first solids stream 48 from the separator 44 receives a LS-dominant stream 74 from conduit 76 for washing, and goes through a second-stage solid-liquid separation to generate a second liquids stream 34 and a second solids stream 78. The LS-dominant stream 74 contains about 70 wt % to about 90 wt % LS. The mass ratio of HS/LS in this washing liquid is maintained in the range of about 50/50 to about 20/80. This HS/LS ratio happens to be the value in a downstream liquids stream 96 that is partially recycled here. After using stream 74 for washing, the second liquids stream 34 also has a relatively high LS proportion compared to HS and can be recycled directly into a second slurry preparation and conditioning unit 30 without upsetting the HS/LS ratio in unit 30. The streams in the process of the present invention are thus predominantly LS streams which are ultimately directed into the second slurry preparation and conditioning unit 30. Compared to the prior art CA '719 process, the reduced HS/LS in the washing liquid stream 74 enables direct recycle of the stream 34 without the need of further processing with a flash drum and also reduces the HS concentrations in solids so that the HS loss to spent solids is reduced.
In one embodiment, the second solids stream 78 is a filter cake discharged from the pan filter. Some asphaltene may precipitate from the second liquids stream 34. Because of the presence of HS in the second liquids stream 34, the precipitated asphaltene is in the form of soft loose solids that can be pumped through a pipe without causing plugging. When the second liquids stream 34 arrives at the unit 30, the solvent chemistry there re-dissolves the precipitated asphaltene to minimize oil loss.
In one embodiment, the second solids stream 78 flows out of the first separator 44 into a repulper 80. In one embodiment, the repulper 80 is a baffled tank agitated with impellers. In one embodiment, the tank and impellers have an unconventional configuration shown in FIG. 4B. A LS-dominant stream 82 from conduit 84 is pumped into the repulper 80 as well. The repulper 80 provides vigorous mixing of the solids stream 78 and a predominantly LS stream 86 from conduit 88 to dissolve any trapped bitumen and HS. The predominantly LS stream 86 contains about 80 wt % to about 99 wt % LS. After repulping, the slurry 90 is fed via conduit 92 onto a second solid-liquid separator 94. The solids content in the slurry 90 in the repulper 80 is about 50-65 wt %.
The second solid-liquid separator 94 contains at least two stages (third and fourth stages) which are shown separated with a dashed line in FIG. 2. In one embodiment, the second solid-liquid separator 94 may comprise a top-loading filter such as, for example, an enclosed pan filter. The third-stage solid-liquid separation generates a third liquids stream 96 and a third solids stream 98. The third liquids stream 96, which comprises primarily light solvent, is removed via conduit 100 to be split through a splitter 110 into stream 38 for reuse in the second slurry preparation and conditioning unit 30; stream 74 for reuse in the separator 44; and stream 82 for reuse in the repulper 80. In one embodiment, the split ratio is about 33%, about 48% and about 19% for streams 38, 74, and 82, respectively.
After the third-stage separation, the third solids stream 98 in the separator 94 receives a pure LS stream 112 from conduit 114 for washing and goes through a fourth-stage solid-liquid separation to generate a fourth liquids stream 86 and a fourth solids stream 116. The fourth liquids stream 86, which comprises predominantly LS, is removed via conduit 88 for reuse in the repulper 80. In one embodiment, the solids stream 116 is a filter cake discharged from the pan filter.
The spent solids 116 from the separator 94 are removed via conduit 118 into the solids dryer 22. In one embodiment, the conduit 118 may be a jacketed screw conveyor to preheat the spent solids 116 with steam in the jacket. In one embodiment, the dryer 22 comprises a super-heated steam dryer. The solids are heated to about 100° C. and discharged as dry tailings 120. In one embodiment, the LS content in dry tailings 120 is less than about 300 mg/kg LS, equivalent to VOC emissions of less than 3.8 bbl/kbbl of bitumen produced. In one embodiment, the LS content is less than about 100 mg/kg, equivalent to VOC emissions of less than 1.3 bbl/kbbl of bitumen produced.
In one embodiment, the dry tailings 120 may be further mixed with fluid fine tailings (FFT) that are produced in water-based processes and typically contain about 30 wt % solids, at a mass ratio of about 1:0.25 to make a trafficable solids mixture containing about 85 wt % solids. This mixture, which is more consolidated and less dusty than loose dry solids, can be transported to a land reclamation site for disposal.
The recovered vapors (LS and H₂O) 122 flow via conduit 124 to a condenser/separator 126. The cooling medium used in condenser/separator 126 may be cold recycle cooling water. Condensed LS 70 flows out via conduit 72 to the LS tank 68. There may be a trace amount of HS condensed in the LS stream 70. Condensed water 128 flows out via conduit 130 and could be recycled for steam generation if needed. The bitumen and LS recoveries in this process are about 95% and about 99%, respectively. This bitumen recovery includes small loss of HS to spent solids that is deducted from the product bitumen in distillation as HS makeup. The HS recovery, if calculated separately, is about 99%.

EXAMPLE 1

Table 1 shows the relationship of water-to-solids mass ratios (W/S) in slurry and filtration rates for a test oil sand (#1) containing 9.3 wt % bitumen, 2.1 wt % water and 88.6 wt % solids. The fines (<44 μm) content in the solids was 21 wt %. This oil sand was relatively dry, so by varying the water dosage, the W/S could be adjusted in a wider range. The hydrocarbon phase in the slurry prior to the first filtration step comprised about 30 wt % bitumen, 35 wt % virgin light gas oil and 35 wt % heptane. The solids content in the slurry was about 58 wt %. The solids were flocculated in a baffled dished-bottom mixing tank of 13 cm in diameter (T) at 50° C. The impeller was a 6-blade 45° PBT of 7.6 cm in diameter (D). The bottom clearance (C) was about 1.5 cm. Thus, D/T=0.58 and C/T=0.12. The down-pumping axial impeller was operated at 600 rpm for 4 minutes, providing a power input of about 6 W/kg of slurry. The mixed slurry was transferred to a top-loading batch filter with about 70 kPa (absolute) pressure inside its filtrate receiver. The filter cake thickness was kept around 4.4 cm. One stage of drainage and one stage of washing were carried out on this filter. The filter cake was removed for repulping with a high-LS-content solution. One stage of drainage and one stage of washing were carried out on the same filter after repulping. The second filter cake was the spent solids for drying and solvent recovery. Filter process rate refers to the oil sand throughput per filter area (including both filters before and after repulping) per hour in a hypothetical continuous operation. Initial filtrate flux refers to the average flux of the first filtrate prior to air breakthrough.

TABLE 1

W/S Mass Ratio in Slurry	0.046	0.052	0.057	0.068
Filter Process Rate (t/m²h)	6.6	7.0	8.0	8.5
Initial Filtrate Flux (L/m²s)	4.9	5.9	8.5	10.2

Using a dual-solvent extraction process including solids flocculation and repulping, even the lowest filter process rate of 6.6 t/m²h is sufficient for a commercial pan filter to operate efficiently. The data indicate that with proper flocculation conditions and apparatuses, the filtration step may be scaled up to a commercial operation with a W/S ratio below about 0.07.

EXAMPLE 2

Two samples of oil sands #1 and #2 having 9.3 wt % and 9.7 wt % bitumen, 2.1 wt % and 6.2 wt % water and 21% and 28% fines in solids, respectively, were extracted with dual solvents under similar conditions as described in Example 1. The test for oil sand #2 had zero water addition. Oil sand connate water was the sole source of water for solids flocculation. Both samples went through four stages of filtration with repulping between stages 2 and 3. The filter cake thickness was kept around 4.3 cm. All wash liquids were prepared based on their compositions and flow rates in a continuous process. Table 2 shows the extraction performance.

TABLE 2

	Initial Filtrate	Filter Process	Bitumen	W/S Mass
	Flux	Rate	Recovery*	Ratio in
Oil sand	(L/m²s)	(t/m²h)	(%)	Slurry

#

1	5.9	7.0	96.9	0.052
#2	11.1	8.5	94.1	0.074

*Bitumen recovery here includes small loss of HS to spent solids that can be deducted from the product bitumen in distillation as HS makeup.

The bitumen recoveries for oil sands #1 and #2 in water-based extraction are 88% and 55%, respectively. The data indicate that using the dual-solvent extraction process including solids flocculation, filter process rates above 7 t/m²h, bitumen recovery around 95% and W/S below 0.08 can be achieved even for a relatively wet oil sand #2.

EXAMPLE 3

Tests were conducted to compare the filter process rates and bitumen recoveries achieved using a solids agglomeration method of the prior art which involved a drum agglomerator verses the solids flocculation method of the present invention which involved the mixing tank/impeller described in Example 1, The two solvents used in extraction and the slurry compositions were identical in these two tests and similar to those in Example 1. An oil sand (#3) used in both tests contained about 10 wt % bitumen, 5 wt % water and 85 wt % solids. The fines (<44 μm) content in the solids was 28 wt %. The solids contents in the slurry for the agglomeration and flocculation tests were about 45 wt % and 52 wt %, respectively. The filter cake thicknesses used in the agglomeration and flocculation tests were 10.2 cm and 4.7 cm, respectively. The agglomeration data have been converted based on a hypothetical filter cake thickness of 4.7 cm to be comparable with the flocculation data. Table 3 shows the comparison of extraction performance.

	TABLE 3

	Method

Flocculation

Agglomeration (Prior Art)

W/S in Slurry	0.07	0.08	0.08	0.095	0.11	0.12	0.14

Filter Process Rate	5.0	7.1	0	4.1	4.3	4.2	4.4
(t/m²h)
Initial Filtrate Flux	3.6	7.2	0	3.2	3.6	4.1	5.1
(L/m²s)
Bitumen Recovery*	93.0	92.4	N/A	91.0	91.4	91.3	87.2
(%)

*Bitumen recovery here includes small loss of HS to spent solids that can be deducted from the product bitumen in distillation as HS makeup.

The filter process rate and initial filtrate flux obtained from the solids flocculation method of the present invention ranged from 5.0 to 7.1 t/m²h and 3.6 to 7.2 L/m²s, respectively, with lower water content (W/S mass ratio between 0.07 to 0.08), compared to those from the solids agglomeration method of the prior art, 4.1 to 4.4 t/m²h and 3.2 to 5.1 L/m²s, respectively, with higher water content (W/S mass ratio between 0.095 to 0.14). At W/S=0.08, the solids agglomeration method caused filter plugging thus making the filter process rate zero. Filter plugging implies failure of the method to effectively bind fines with coarse sand grains.
Similarly, the bitumen recovery was higher for the flocculation method (over about 92%) at lower water content (W/S mass ratio between 0.07 to 0.08) compared to bitumen recovery for the agglomeration method (about 91%) at higher water content (W/S mass ratio between 0.095 to 0.12). Bitumen recovery plummeted to 87% at even higher water content (W/S mass ratio around 0.14). The bitumen recovery for oil sand #3 in water-based extraction is 81%.
In summary, the present invention involving solids flocculation was superior to the prior art involving solids agglomeration, yielding higher filter process rates and bitumen recovery in a low water content regime where the agglomeration method no longer functions. Lower water content is preferred in the process since higher water content interferes with downstream solvent recovery from spent solids.
The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims.

REFERENCES

All publications mentioned herein are incorporated herein by reference (where permitted) to disclose and describe the methods and/or materials in connection with which the publications are cited. The publications discussed herein are provided solely for their disclosure prior to the filing date of the present application. Nothing herein is to be construed as an admission that the present invention is not entitled to antedate such publication by virtue of prior invention. Further, the dates of publication provided may be different from the actual publication dates, which may need to be independently confirmed.

Adeyinka, O.; Speirs, B. C. and Esmaeili, P. Processes and systems for solvent extraction of bitumen from oil sands. Canadian Patent No. 2,724,806, issued Feb. 24, 2015.
Blackbourn, R. L.; Bott, R. A.; Giles, S. P.; Komishke, B. D.; Ling, Y.; Ploemen, I. H. J. and In'T Veen, B. C. M. Closed loop solvent extraction process for oil sands. Canadian Patent No. 2,715,301, issued Mar. 23, 2011.
Delude, S. G.; Giles, S. P. and Visser, C. M. A method for removing oxygen from an oil sand stream. Canadian Patent Application No. 2,815,132, published Nov. 9, 2013.
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Kift, J.; Joshi, M.; Thompson, W. C. and Hoffman, C. M. Process for extracting bitumen and drying the tailings. Canadian Patent Application No. 2,761,555, published Jun. 9, 2012.
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Pierre Jr., F.; Adenyinka, O. B.; Speirs, B. C.; Alvarez, E.; Esmaeli, P.; Myers, R. D.; Kaminsky, R. D.; Pace, J. D.; Palmer, T. R.; Rennard, D. C. and Ghosh, M. Integrated processes for recovery of hydrocarbon from oil sands. Canadian Patent No. 2,740,481, issued Feb. 12, 2013.
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Claims

What is claimed is:

1. A process for extracting bitumen from oil sand, comprising:

(a) contacting mined oil sand with a high-flash point heavy solvent (HS) to produce a dense oil sand slurry;

(b) mixing the dense slurry with a first light solvent (LS) stream and a second LS stream to give a heavy solvent to light solvent (HS/LS) mass ratio of about 75/25 to about 40/60;

(c) subjecting the HS/LS-diluted oil sand slurry to a first stage solid-liquid separation to produce a first liquids stream containing bitumen and a first solids stream; and

(d) washing the first solids stream with a mixed solvent having a HS/LS mass ratio of about 50/50 to about 20/80 and subjecting the solids and the mixed solvent to a second stage solid-liquid separation to produce a second liquids stream and a second solids stream.

2. The process of claim 1, further comprising in step (b), mixing the dense slurry with a minimal amount of water to give a water to solids (W/S) mass ratio less than about 0.1 to flocculate solids.

3. The process of claim 1, further comprising before step (b), preparing the dense oil sand slurry for oil sand deoxygenation and passing it through an airlock.

4. The process of claim 3, further comprising:

(e) mixing the second solids stream and two LS streams in a repulper prior to being subjected to a third stage solid-liquid separation to produce a third liquids stream and a third solids stream.

5. The process of claim 4, further comprising:

(f) washing the third solids stream with LS and subjecting the solids and LS stream to a fourth stage solid-liquid separation to produce a fourth liquids stream and a fourth solids stream.

6. The process of claim 1, wherein in step (b), the first LS stream comprises from about 70 wt % to about 90 wt % LS.

7. The process of claim 1, wherein in step (b), the W/S mass ratio is less than about 0.08.

8. The process of claim 5, wherein in step (c), the first liquids stream is treated in a distillation unit to recover bitumen, LS and HS.

9. The process of claim 8, wherein the recovered HS is the solvent used in step (a).

10. The process of claim 9, wherein the recovered HS comprises either pure HS, or about 70 wt % HS and about 30 wt % bitumen.

11. The process of claim 8, wherein the recovered LS is used for washing in step (f).

12. The process of claim 5, wherein the second liquids stream is used as the second LS stream in step (b).

13. The process of claim 12, wherein second LS stream comprises from about 45 wt % to about 65 wt % LS.

14. The process of claim 5, wherein the third liquids stream is passed through a splitter to produce LS for use in mixing in step (b) as the first LS stream; washing in step (d); and repulping in step (e).

15. The process of claim 5, wherein the fourth liquids stream is used for repulping in step (e).

16. The process of claim 5, wherein the LS present in the fourth solids stream is recovered by drying the fourth solids stream in a solids dryer to produce dry tailings.

17. The process of claim 16, wherein the fourth solids stream is pre-heated before drying.

18. The process of claim 17, wherein the fourth solids stream is pre-heated in a jacketed screw conveyor with steam before drying.

19. The process of claim 16, wherein the solids dryer removes and recovers greater than 99% LS from the fourth solids stream and leaves less than about 300 mg/kg of LS in solids.

20. The process of claim 16, wherein the dry tailings are mixed with fluid fine tailings to produce trafficable solids containing about 85 wt % solids.

21. The process of claim 16, wherein the recovered LS passes through a condenser to remove residual water before the LS is used for washing in step (f).

22. The process of claim 1, wherein the oil sand contains fines as high as 49% in solids and bitumen as low as 6%, the bitumen recovery is at least about 95%, and the HS and LS recoveries are at least about 99%.

23. The process of claim 1, wherein the HS is a non-volatile, high-flash point light gas oil stream, distilled from oil sand bitumen, and has a boiling range of about 130-470° C.

24. The process of claim 1, wherein the LS is a C₆-C₁₀hydrocarbon stream produced from an oil sand bitumen upgrading unit, and has a boiling range of about 69-170° C.

25. The process of claim 24, wherein the LS is aliphatic C₆-C₇and has a boiling range of about 69-110° C.

26. The process of claim 1, wherein in step (a), the dense oil sand slurry is produced in a first slurry preparation and conditioning unit.

27. The process of claim 26, wherein the first slurry preparation and conditioning unit comprises a rotatable tumbler.

28. The process of claim 1, wherein in step (b), the HS/LS-diluted oil sand slurry is produced in a second slurry preparation and conditioning unit.

29. The process of claim 28, wherein the second slurry preparation and conditioning unit comprises a baffled tank agitated with one or more impellers.

30. The process of claim 29, wherein the one or more impellers comprise 45° pitched blade turbines.

31. The process of claim 30, wherein the impellers have a diameter ranging from about 0.55 to about 0.7 of the tank diameter.

32. The process of claim 31, wherein the bottom clearance ranges from about 0.01 to about 0.15 of the tank diameter.

33. The process of claim 31, wherein the bottom clearance ranges from about 1 cm to about 5 cm for any tank diameter.

34. The process of claim 32, wherein the power input by the one or more impellers ranges from about 1 W/kg to about 15 W/kg of slurry.