CA2746987A1 - Treatment of bitumen froth with super critical water - Google Patents

Abstract

A method is provided to upgrade oil sand compositions that includes the steps of:
contacting an oil sand composition with water to form an oil sand slurry;
separating the oil sand slurry into a froth containing water and hydrocarbon mixture and a underflow stream comprising solids and water; heating the froth to a temperature above about 374°C, and increasing the pressure of the froth to a pressure above about 22.1 MP to form a reactant mixture;
permitting the reactant mixture to remain at a pressure above about 22.1MPa and a temperature above about 374°C for a period long enough for the hydrocarbons in the froth to be at least partially upgraded to become an upgraded froth; and separating the upgraded froth into an upgraded hydrocarbon stream and an stream containing water, solids and asphaltenes. The required temperature and pressure are the critical temperature and pressure for water.

Description

TREATMENT OF BITUMEN FROTH WITH SUPER CRITICAL WATER

This application claims priority to US Provisional Application number 61/367,061, filed on July 23, 2010, which is herein incorporated by reference.
Field of the Invention The invention relates to a method and apparatus for treatment of bitumen froth to upgrade and enhance separation of solids and water from hydrocarbons.
Background Oil sand is essentially a matrix of bitumen, mineral material and water, and possibly encapsulated air. The bitumen component of oil sand consists of viscous hydrocarbons which behave much like a solid at normal in situ temperatures and which act as a binder for the other components of the oil sand matrix. Oil sand will typically contain about 10% to 12% bitumen and about 3% to 6% water, with the remainder of the oil sand being made up of mineral matter. The mineral matter component in oil sand may contain about 14% to 20% fines, measured by weight of total mineral matter contained in the deposit, but the amount of fines may increase to about 30% or more for poorer quality deposits. Oil sand extracted from the Athabasca area near Fort McMurray, Alberta, Canada, averages about 11% bitumen, 5% water and 84% mineral matter, with about 15% to 20%
of the mineral matter being made up of fines. Oil sand deposits are mined for the purpose of extracting bitumen from them, which is then upgraded to synthetic crude oil.
A widely used process for extracting bitumen from oil sand is the "water process".
In this process, both aggressive thermal action and aggressive mechanical action are used to liberate and separate bitumen from the oil sand. An example of the water process is the hot water process. In the hot water process, oil sand is first conditioned by mixing it with hot water at about 95° Celsius and steam in a conditioning vessel which vigorously agitates the resulting slurry in order to disintegrate the oil sand. Once the disintegration of the oil sand is complete, the slurry is separated by allowing the sand and rock to settle out.
Bitumen, with air entrained in the bitumen, floats to the top of the slurry and is withdrawn as a bitumen froth. The remainder of the slurry is then treated further or scavenged by froth flotation techniques to recover bitumen that did not float to the top of the slurry during the separation step. The froth is further treated to separate solids and water from liquid hydrocarbons. Such a process is suggested in US patent no. 5,645,714, the disclosure of which is incorporated herein.

Canadian patent number 2,232,929, the disclosure of which is incorporated herein, discloses an improvement to the hot water process that utilizes a paraffinic solvent to extract bitumen from the bitumen froth.
Canadian patent number 2,316,084, the disclosure of which is incorporated herein, suggests extraction of oil from coal, oil shales, bitumens, heavy, and semi-heavy oils with supercritical water.
Further upgrading is accomplished by addition of carbon monoxide to the supercritical water-hydrocarbon mixture. It is suggested that bitumen may be contacted with supercritical water with or without the presence of carbon monoxide to further reduce the content of asphaltenes.
Application of this process to oil sands would require processing of the ore at high pressures and at high temperatures. This would be problematic because of material handling difficulty of the high solids content material at elevated pressures and temperatures. Further, increasing the temperature of the ore to the critical temperature of water would require heating a large mass of inert mineral matter along with the water and hydrocarbons, requiring more equipment and energy.

Summary of the Invention A method is provided to upgrade oil sand compositions comprising the steps of:
contacting an oil sand composition with water to form an oil sand slurry; separating the oil sand slurry into a froth containing water and hydrocarbon mixture and a underflow stream comprising solids and water; increasing the pressure of the froth to a pressure above about 22.1 MPa; heating the froth to a temperature above about 374 C; permitting the froth to remain at a pressure above about 22.1MPa and a temperature above about 374 C for a period long enough for the hydrocarbons in the froth to be at least partially upgraded to become an upgraded froth; and separating the upgraded froth into an upgraded hydrocarbon stream and an stream containing water, solids and asphaltenes.
The required temperature and pressure are the critical temperature and pressure for water.
Hydrocarbons in the froth become miscible in water when the water is at supercritical conditions.
The upgraded hydrocarbons may be transported by pipeline without further processing or addition of diluents. This process requires fewer steps than alternatives processing options and eliminates the need to transport the large volumes of diluents normally used to enable transportation of the hydrocarbons separated from the oil sands to facilities for further processing.
By applying the process to froth after initial separation of solids, materials handling is simplified and energy requirements are reduced when compared to contacting the total oil sand composition with supercritical water.
Compared to present processes to process oil sands, the process of the present invention is a much simplified process, and results in upgraded hydrocarbons. Capital costs should be considerably reduced. Existing solvent based methods to remove hydrocarbons from oil sand ore

2 are susceptible to operating problems caused by variations in the properties and composition of the oil sand ore. The process of the present invention may be considerably less sensitive to the properties of the froth and the oil sand ore.
An alternative application to the present invention is to contact the froth with a hydrocarbon solvent, then separate the froth and hydrocarbon solvent into a hydrocarbon phase product stream, and an underflow stream. The underflow stream may contain water, mineral solids, precipitated asphaltenes, and some solvent. Solvent in the underflow stream can then be removed by, for example, stripping with steam. The underflow stream, optionally after removal of at least a portion of the solvent, may be contacted with water at conditions wherein the water is at supercritical conditions. The hydrocarbon solvent may be a paraffinic solvent.
The invention also includes an apparatus for practicing the above described methods.
Brief Description of the Figures Figure 1 is a process flow drawing for the process of the present invention.
Figure 2 is a process flow drawing for an alternative embodiment of the present invention.
Detailed Description of the Invention Referring now to the Fig. 1, an oil sand ore stream, 101, is contacted with water 102 in a mixer 120, to form a water and oil sand slurry 103. The oil sand ore can be a mined bitumen ore from a formation such as oil sands found in the Athabasca area near Fort McMurray, Alberta, Canada. The ratio of oil sand ore to water may be, for example, in the range of 1 to 6 or 1 to 2. The oil sands may contain between 75 and 95 percent by weight of mineral solids, and may contain between 10 and 20 percent by weight hydrocarbons. The hydrocarbon portion of the oil sands may have a gravity of between 7 and 10 API and may contain from 10 to 25 percent by weight of ashpaltenes. Other components of the hydrocarbon portion of the oil sand ore may be 10 to 40 percent by weight aliphatics, 5 to 20 percent by weight aromatics, and 10 to 50 percent by weight polar compounds. The mixer may agitate the slurry to break up solids and to increase the area of contact between the solids and the water. The mixer may also heat the slurry to a temperature of, for example, between 40 and 90 C to enhance separation of the hydrocarbons from the solids. Air and chemicals such as caustic or surfactants maybe added to the slurry to further enhance separation of the hydrocarbons from the solids. Alternatively, liberation of hydrocarbon from mineral material may be accomplished in a slurry conditioning transportation line. The slurry

3 optionally may be screened in a screener 121 to remove larger solids from a remaining slurry stream 105.
Slurry stream 105 may be further processed to provide an initial solids separation in a first separator 126 producing a first underflow stream 114, containing solids and water with some bitumen, and a froth stream 113. The forth stream contains a majority of the hydrocarbons from the oil sands stream, along with entrained water and solids. Typically, the froth stream contains about 60 weight percent bitumen, about 30 weight percent water, and about 10 weight percent mineral solids. The first separator may include additional steps and equipment, such as, for example, flotation cells, to increase the bitumen recovery and de-aerators to remove excessive air.
Froth, 113, from the first separator may be pumped to a pressure in access of 22.1 MPa, the critical pressure of water, in a pump 122, to form a high pressure froth slurry 106. The high pressure froth slurry may then be heated to a temperature above the critical temperature of water, 374 C, in a heater 123 to form a reactant mixture 107, and then injected into a reactor 124. The heater may be, for example, a furnace, a heat exchanger, or a partial oxidation process or a mixture thereof. Further, the combination of heaters and pumps to increase the temperature and pressure of the reactants may be in various combinations and/or orders in the process.
Additional water 108 may be added to the reactant mixture if needed either at any point along the process from the initial mixer 120 to the reactor 124. Additional water is shown being added to the oil sand slurry prior to the heater 123. Above the critical point, the hydrocarbons and the water are miscible. Further, it has been found that contact super critical water upgrades the hydrocarbons.
The reactor may be a plug flow, or a stirred tank type of reactor, or a combination of the two.
Residence time in the reactor, or the total residence time for contact between the oil sand and water at supercritical conditions may be between about one minute and about three hours, or between about five minutes and about thirty minutes. Too long of contact time under these conditions may result in excessive coke generation, resulting in a loss of yield without a significant additional increase in quality of upgraded hydrocarbon product.
In one embodiment of the invention, carbon monoxide, hydrogen, or mixtures thereof (for example, a synthesis gas mixture of carbon dioxide, water vapor, carbon monoxide and hydrogen), 109, is also charged to the reactor. Addition of carbon monoxide and/or hydrogen may facilitate upgrading of bitumen and further improve stability and quality of the upgraded hydrocarbon. The amount of carbon monoxide and/or hydrogen may be, for example, from one to ten percent by weight of the water present in the supercritical mixture of water and oil sand 107, or a mole ratio of about 0.01 to about 0.1 of carbon monoxide and/or hydrogen to water.
The reactor effluent, 110, may be routed to a second separator, 125. The second separator 125 may be operated at a pressure and/or temperature lower than the critical pressure or

4 temperature of water such that the water will not be, at the conditions of the separator, miscible with the upgraded hydrocarbons. Further, the upgraded hydrocarbons may be considerably richer in paraffins than the original bitumen. Thus, further asphaltenes may be participated from the upgraded hydrocarbon stream 112 and rejected with the solids into an underflow stream 111 from the second separator 125. The upgraded hydrocarbons will also have a density that is lower than the hydrocarbons of the initial hydrocarbons in the oil sands, and therefore may tend to separate more easily from the water and solids than the hydrocarbons in the original oil sands.
The reactor effluent 110 may be cooled prior to the separator by, for example, heat exchange with the oil sand slurry stream, heat exchange with a heat recovery stream such as low pressure steam generation, or coolers such as air coolers. Cooling could also be accomplished by direct contact with additional water. Separation of the reactor effluent into the upgraded hydrocarbon stream 112 and the underflow stream 111 may be accomplished in a series of separators rather than one separator as shown in Fig. 1. For example, there may first be a high temperature separator vessel, and then the underflow of the high temperature separator may be cooled prior to another vessel, which may be at a lower pressure, to separate liquid hydrocarbons from solids and/or water. Separations may also be enhanced by addition of surfactants, hydrocarbons solvents, brines, or other components.
Referring now to Fig. 2, an alternative process to practice the present invention is shown.
An oil sand ore stream, 101, is contacted with water 102 in a mixer 120, to form a water and oil sand slurry 103. The mixer may agitate the slurry to break up solids and to increase the area of contact between the solids and the water. The slurry optionally may be screened in a screener 121 to remove larger solids from a remaining slurry stream 105.
Slurry stream 105 may be further processed to provide an initial solids separation in a first separator 126 producing a first underflow stream 114, containing solids and water with some bitumen, and a froth stream 113. The first separator may include additional steps and equipment, such as, for example, flotation cells, to increase the bitumen recovery and de-aerators to remove excessive air.
Froth, 113, from the first separator, in this embodiment, is mixed with solvent 206 in a solvent-froth mixer 220. The solvent may be a hydrocarbon solvent. The hydrocarbon solvent may be a paraffinic solvent. The paraffinic solvent tends to reject ashphaltenes into tailings, resulting in a higher quality hydrocarbon product from the subsequent physical separation, but a lower yield of product.
The solvent froth mixer product, 201, is separated into a solvent diluted bitumen 202 and tailings 207, in a hydrocarbon enrichment separator 221. The solvent diluted bitumen is then separated into a recycled solvent stream 204 and a bitumen product 203 in a solvent recovery unit.
Hydrocarbon enrichment separator 221 may comprise one to three stages of counter current

5 contacting of underflow from the separators with solvent such as taught in Canadian patent number 2,232,929.
Tailings 207 from the hydrocarbon enrichment separator 221 are then separated into a second recycled solvent stream 209 and a tailings solvent recovery unit underflow stream 208 in a tailings solvent recovery unit 223.
Tailings solvent recovery unit underflow stream 208 may be pumped to a pressure in access of 22.1 MPa in a pump 122 to increase the pressure of the tailings solvent recovery unit underflow to above the critical pressure of water to form a high pressure tailings solvent recovery unit underflow 210. The high pressure tailings solvent recovery unit underflow may then be heated in a heater 123 to form a reactant mixture 211 which is a supercritical mixture of water and pressure tailings solvent recovery unit underflow. The reactant mixture may then be injected into a reactor 124. The heater may be, for example, a furnace, a heat exchanger, or a partial oxidation process. Additional water 108 may be added to the reactant mixture if needed either at any point along the process from the initial mixer 120 to the reactor 124. Additional water is shown being added to the tailings solvent recovery unit underflow prior to the heater 123.
The supercritical mixture of water and oil sand may be at a temperature above about 374 C and a pressure 22.1 MPa.
The reactor may be a plug flow, or a stirred tank type of reactor, or a combination of the two.
Residence time in the reactor, or the total residence time for contact between the oil sand and water at supercritical conditions may be between about one minute and about three hours, or between about two minutes and about thirty minutes. In one embodiment, tailings solvent recovery unit underflow stream 208 could be combined with a froth slurry stream 106 and processed together in the reactor 124. In another embodiment, asphaltenes in the tailings solvent recovery unit underflow stream 208 could be concentrated prior to being processed in the reactor 124.
Carbon monoxide, hydrogen, or mixtures thereof (for example, a synthesis gas mixture of carbon dioxide, water vapor, carbon monoxide and hydrogen), 109, is also charged to the reactor as shown in Fig. 1 and described above.
The reactor effluent, 110, may be routed to a second separator, 125. The second separator 125 may be operated at a pressure and/or temperature significantly lower than the critical pressure or temperature of water such that the water will not be, at the conditions of the separator, miscible with the upgraded hydrocarbons. Further, the upgrades hydrocarbons may be considerably richer in paraffins than the original oil sand hydrocarbons. Thus, further asphaltenes may be participated from the upgraded hydrocarbon stream 112 and rejected with the solids into an underflow stream 111 from the second separator 125. The upgraded hydrocarbons will also have a density that is lower than the hydrocarbons of the hydrocarbons in the tailings solvent recovery unit underflow,

6 and therefore may tend to separate more easily from the water and solids than the hydrocarbons in the original tailings solvent recovery unit underflow.
The reactor effluent 110 may be cooled prior to the separator by, for example, heat exchange with another process stream, a heat recovery stream such as low pressure steam generation, or coolers such as air coolers. Separation of the reactor effluent into the upgraded hydrocarbon stream 112 and the underflow stream 111 may be accomplished in a series of separators rather than one separator as shown in Fig.2. Separations may also be enhanced by addition of surfactants, hydrocarbons solvents, brines, or other components.
The process as shown in Fig. 2 does not upgrade the whole bitumen stream, but could produce enough upgraded product to eliminate or significantly reduce any requirement for diluents for the combined product to meet specifications for pipeline transportation.
In the process as shown in Fig. 2, use of a paraffin solvent 206 will enhance rejection of asphaltenes into tailings 207 from the hydrocarbon enrichment separator 221, resulting in both an increased quality of produced bitumen 203 and a greater volume of upgraded hydrocarbons 112.
In the process shown in either Fig. 1 or Fig. 2, water in the underflow stream 111 may be separated from the solids and recycled, for example, to the slurry of oil sand and water 103.
Recycling the underflow stream water reduces the need to provide additional water 102. Recycling this water as hot water also provides additional heat to the front- end water extraction process and improves energy efficiency of the overall process. Because the upgraded hydrocarbon stream is rich in paraffins, a hydrocarbon phase containing ashpaltenes may be present in the underflow stream 111. This ashphaltene phase could be separated and used as fuel or marketed, or recycled back to, for example, the slurry of oil sand and water for another pass at upgrading by contact with supercritical water.
The invention also includes the apparatus capable of performing the method.
The upgraded hydrocarbon stream may be of pipelineable quality without further processing or addition of diluents. For example, the viscosity of the upgraded hydrocarbon stream may be lower than 800 cS, or below 400 cS and the density of the upgraded hydrocarbon stream may be below 0.98 gm/cm3 at 4 C or below 0.94 gm/cm3 at 4 C. The concentration of ashphaltenes in the upgraded hydrocarbon stream maybe below about 15 percent by volume, or below about 10 percent by volume. The yield of upgraded hydrocarbons may be between above about 80 or above about 90 percent by weight based on total hydrocarbons in the froth.

7

Claims (12)

We claim:

1. A method to upgrade oil sand compositions comprising the steps of:
contacting an oil sand composition with water to form a water and oil sand slurry;
separating the water and oil sand slurry into a froth containing water and hydrocarbon mixture and a underflow stream comprising solids water, and entrained hydrocarbons ;
increasing the pressure of the froth to a pressure above about 22.1 MPa and heating the froth to a temperature above about 374°C to form a reactant mixture;

permitting the reactant mixture to remain at a pressure above about 22.1MPa and a temperature above about 374°C for a period long enough for the hydrocarbons in the froth to be at least partially upgraded to become an upgraded froth; and separating the upgraded froth into an upgraded hydrocarbon stream and an stream containing water, solids and asphaltenes.

2. The method of claim 1 wherein additional water is added to the froth.

3. The method of claim 1 wherein the ratio of water to hydrocarbons present in the reactant mixture is between about 0.2 and about 5.

4. The method of claim 1 wherein after to permitting the froth to remain at a temperature above about 22.1 MPa and a temperature above about 374°C for a period between about one minute and about three hours.

5. The method of claim 1 wherein the upgraded bitumen has a density at 4°C of less than 0.98gm/cc and a viscosity at 25°C of less than 800 cSt.

6. The method of claim 1 wherein the period of time for which the froth is held at pressure above about 22.1 MPa and a temperature above about 374°C is between about two minutes and about three hours.

7. The method of claim 1 wherein at least some bitumen is removed from the froth by a solvent extraction process prior to the pressure of the remaining froth stream being increased to above about 22.1 MPa.

8. An apparatus for upgrading hydrocarbons of an oil sand composition comprising:
a mixer for contacting oil sands with water;
a first separator for separating the oil sands and water mixture into a froth and an first underflow stream:
a pump for increasing the pressure of the froth to a pressure above about 22.1

MPa;
a heat transfer means for increasing the temperature of the froth to a temperature above about 374 °c a second separator configured to receive froth after the froth has been processed by the pump and heat transfer means for separating the froth into an upgraded hydrocarbon composition and a second underflow stream.

10. The apparatus of claim 8 wherein the pump is a screw pump.

11. The apparatus of claim 8 further comprising a reactor for holding the froth after the froth has been processed by the pump and heat transfer means for a residence time of between two minutes and three hours.

12. The apparatus of claim 8 further comprising a second heat transfer means associated with the second separator effective to reduce the temperature of the froth prior to the froth entering the second separator.