US20120145604A1

US20120145604A1 - Solvent Assisted Water Extraction of Oil Sands

Info

Publication number: US20120145604A1
Application number: US13/273,683
Authority: US
Inventors: Michael Y. Wen
Original assignee: Individual
Current assignee: Individual
Priority date: 2010-12-08
Filing date: 2011-10-14
Publication date: 2012-06-14
Also published as: CA2757603A1; CA2757603C

Abstract

Described is a process for extracting bitumen from oil sands. Water is mixed with oil sands to form a slurry. The slurry and a hydrocarbon solvent are passed through a hydrotransport pipeline to form an extracted slurry. Dilution water is added to the extracted slurry to form a diluted extracted slurry to reduce the viscosity of the slurry to assist in subsequent bitumen separation. A flocculant may be added to assist subsequent separation or to reduce dilution water requirements.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. Provisional Patent Application 61/421,029 filed Dec. 8, 2010, entitled SOLVENT ASSISTED WATER EXTRACTION OF OIL SANDS, the entirety of which is incorporated by reference herein.

FIELD

The present disclosure relates generally to the extraction of hydrocarbons from mineable deposits, for instance the extraction of bitumen from mined oil sands.

BACKGROUND

Hot water extraction (HWE) is a commonly used process to extract bitumen from mined oil sands. In the HWE process, mined crushed oil sands are mixed with hot water to form a slurry. Caustic, such as NaOH, is added to the water to improve bitumen extraction. The slurry is transported in a hydrotransport pipeline to a primary separation vessel, which uses flotation to produce a bitumen froth. Since the density of bitumen is similar to that of water and since bitumen prefers air to water, air is injected into the hydrotransport pipeline and into secondary flotation cells to assist in the recovery of bitumen. The produced bitumen froth (for instance, 60% bitumen, 30% water, and 10% fines) requires additional processing steps, such as naphtha froth treatment (NFT) or paraffin froth treatment (PFT), to produce bitumen.
The HWE process works well for high quality oil sands, however it can provide poor bitumen recovery where the oil sands have a high clay content. The addition of caustic helps to liberate bitumen droplets from the sands, but it exacerbates the formation of mature fines tailings (MFTs) that may take years to settle. MFTs may delay water recycle and the high pH of tailings water makes land reclamation more difficult. Furthermore, the addition of air to the hydrotransport pipeline enhances the erosion of the pipeline due to continuous abrasion and oxidation.
The use of hydrocarbon solvents for oil sands extraction has previously been studied. The main advantage of adding the solvent is its strong ability to dissolve bitumen and the low density of the resulting bitumen/solvent product, which facilitates separation from water and sands.
Certain references are discussed briefly below. These discussions do not, of course, necessarily highlight the most relevant portions of the references. Anyone wishing to appreciate what is described in these references is recommended to read the references themselves.
Wolff V. T. in Canadian Patent Application No. 2,520,943 describes, according to the Abstract, “ . . . a method comprising: a) preparing a slurry having a temperature of between about 5° C. and about 85° C. by mining an oil sand deposit to produce a mined oil sand and mixing the mined oil sand with water; b) mixing the slurry with at least one hydrocarbon solvent thereby producing a solvent-slurry mixture; c) agitating the solvent-slurry mixture by transporting the solvent-slurry mixture along a pipeline, thereby producing an emulsion; and d) providing the emulsion to a primary separation facility”. However, without intending to be bound by theory, it is believed that because of the strength of the resultant emulsion, separation of such an emulsion by gravity separation alone may be inefficient and may result in low bitumen recovery. Wolff describes the option of using a high velocity hydrocyclone to achieve the separation. However, the potential high erosion rate of sands in a hydrocyclone may pose operational challenges.
Davis and Paul in U.S. Pat. No. 5,690,811 describe the use of a vertical acoustic chamber to extract oil from hydrocarbon containing soil. The hydrocarbon containing soil and solvent slurry is introduced into the top of chamber and is flowed downward. Additional solvent is introduced through a lower port of the chamber and is flowed upward. Water is introduced through the bottom of the chamber to carry away cleaned soil.
Graham et al. in U.S. Pat. No. 5,143,598 describe a wet grinding process where a specific amount of solvent and water are introduced. Mixing power, residence time, and the amount of water/solvent of the milling step were found to be important for bitumen recovery.
Rendall in U.S. Pat. No. 4,875,998 describes a process using solvent and water to extract bitumen from tar sands. Part of the bitumen extract is recycled along with solvent to improve extraction efficiency. Options of product utilization and heat integration are described.
Graham et al. in U.S. Pat. No. 4,722,782 describe first treating tar sands with solvent and then adding water to separate a bitumen rich extract from residual sands without the formation of a stable emulsion.
Hsieh and Clifford in U.S. Pat. No. 4,676,889 describe a specially designed extractor. Tar sands, solvent, and water are fed into the top of the extractor. Bitumen extract is withdrawn from the side and residual sands and water slurry is withdrawn from the bottom.
Sparks, et al. in U.S. Pat. No. 4,719,008 describe the use of specific ratios of solvent and water to extract bitumen and agglomerate oil sands. Following the solvent recovery step, dry tailings are suitable for disposal.
Taylor in European Patent Application No. 261794 describes a tar sands extraction process using less than 15% of halogenated solvent-in-water emulsions as an extraction agent.
Guymon in U.S. Pat. No. 4,968,412 describes a process to extract bitumen from tar sands contaminated with clay. Solvent extraction is followed by a water wash including a surfactant and gas stripping to recover residual bitumen and solvent.
Although certain hydrocarbon solvents have the advantage of high bitumen solvency, the direct contact of solvent with oil sands results in high equipment costs and added energy costs for recovering solvent from residual sands. Many previous efforts in this area use specially designed extraction systems to achieve the objective of high bitumen recovery; nevertheless the reliability of such equipment may have a negative impact on operability.
It is, therefore, desirable to provide an alternative process for extracting bitumen from oil sands.

SUMMARY

It is an object of the present disclosure to obviate or mitigate at least one disadvantage of previous processes.
Described is a process for extracting bitumen from oil sands. Water is mixed with oil sands to form a slurry. The slurry and a hydrocarbon solvent are passed through a hydrotransport pipeline to form an extracted slurry. Dilution water is added to the extracted slurry to form a diluted extracted slurry to reduce the viscosity of the slurry to assist in subsequent bitumen separation. A flocculant may be added to assist subsequent separation or to reduce dilution water requirements.
Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way of example only, with reference to the attached Figures.

FIG. 1 is a flow chart of a process of an embodiment described herein;

FIG. 2 is a diagram of a process of an embodiment described herein;

FIG. 3 is a diagram of a process of an embodiment described herein;

FIG. 4 is a diagram of a process of an embodiment described herein; and

FIG. 5 is a graph of bitumen recovery by weight percent, using an embodiment of a process described herein.

DETAILED DESCRIPTION

Generally, the present disclosure relates to a process for extracting bitumen from oil sands. FIG. 1 is a flow chart of a process of an embodiment described herein. Water is mixed with oil sands to form a slurry (102). The slurry and a hydrocarbon solvent are passed through a hydrotransport pipeline to form an extracted slurry (104). Dilution water is added to the extracted slurry to form a diluted extracted slurry to reduce the viscosity of the slurry to assist in subsequent bitumen separation (106). A flocculant may also be added to assist subsequent separation and/or to reduce dilution water requirements.
Bitumen is classified as an extra heavy oil, with an API gravity of about 10° or less, as measured in degrees on the American Petroleum Institute (API) Scale.
In one embodiment, the solvent assisted water extraction (SAWE) processes have certain features in common with the HWE process. Similar to the HWE process, SAWE processes may have three main steps, 1) mining and slurry preparation, 2) hydrotransport and extraction, and 3) separation. However, the SAWE processes include enhancements on the conventional HWE processes, with certain of these enhancements being made to one or more of the basic process steps described above.
In the mining and slurry preparation step, SAWE may use the same or similar processing equipment as HWE. While the equipment itself may be conventional, the methods of operating the equipment and the inputs and outputs of the equipment are notably different in the present SAWE processes. As shown in FIG. 2, mined oil sands (202) are crushed (204) and mixed with water (206) in a slurry mixer (208) to form a slurry (209). For example, the water may be between 20 and 70° C. The amount of water used to prepare the slurry may be in the range of 40 to 60% by weight of oil sands, or 40-50%, or 40-45%.
A low concentration, for instance less than 50 parts per million weight (ppmw), of flocculant (210) (or 1-50 ppmw, or less than 15 ppmw, or 5-15 ppmw) may be added to assist bitumen liberation and bitumen extract separation from the slurry in subsequent separation. The flocculant may be a polymer flocculant and may be a nonionic, anionic, or cationic polymer or copolymer with different molecular weights and with various functional groups, such as acrylamide, acrylic acid, amine, acrylate, ethylene imine, ethylene oxide, etc. In some implementations of the SAWE processes, the flocculant is an anionic high molecular weight polymer flocculant, with high molecular weight referring to a molecular weight above about 500,000 or above about 1,000,000.
Caustic is not required in the presently described SAWE processes, which allows water to be more easily recovered from the tailings. In some implementations minor amounts of caustic may be added or may be found in the slurry through other means, in which case the slurry may include less than 100 ppmw of caustic.
Once the slurry is prepared, it is pumped into a hydrotransport pipeline (212). In the hydrotransport pipeline (212), the high velocity of flow creates strong turbulence to assist further breakdown of lumps of oil sands and liberation of bitumen droplets from the surface of the sands. Hydrocarbon solvent (214) is injected into a front section (or solvent injection zone) (216) of the hydrotransport pipeline (212). Due to high turbulence, high solid content and high viscosity of the slurry, both hydrocarbon solvent and bitumen droplets stay small throughout the bitumen extraction zone (218), and this greatly increases the chance of digestion of bitumen droplets by solvent droplets. The hydrocarbon solvent may be a natural gas liquid, light naphtha, a C1-C6 hydrocarbon, an n-paraffin, an iso-paraffin, a cyclic-paraffin, or an aromatic hydrocarbon, or a combination thereof. A liquid olefin hydrocarbon could also be used but one would have to consider pipeline specification limits for the bromine number; for instance, the bromine number could be kept under 10. Other hydrocarbon solvents that are effective could also be used. Examples of the weight fraction of solvent use are 0.1 to 0.3, or 0.15 to 0.25 based on oil sands weight. The amount of solvent will depend on several factors including oil sands grade and solvent composition.
In order to reduce the viscosity of the extracted slurry to allow bitumen extract droplets to be separated in the separation vessel, additional dilution water (220) may be desired to achieve desirable efficiency and/or separation speed. Dilution water (for instance 30 to 160% by weight of oil sands) is injected into a later section (or water dilution zone) (222) of the hydrotransport pipeline to form a diluted extracted slurry (228). In another embodiment (not shown), the dilution water may be added to the extracted slurry after the extracted slurry exits the pipeline. The diluted extracted slurry may have a water to oil sands ratio of less than 2:1, or less than 1.5:1, or less than 1:1, and at least 0.5:1, or at least 0.7:1.
In a separation step (224), a gravity separation vessel may be used to separate bitumen extract (226) from the diluted extracted slurry (228).
The amount of dilution water and the concentration of flocculant have a great impact on the residence time requirement and the recovery of bitumen extract. As shown in the examples below, bitumen recovery of more than 90% by weight was achieved using a limited amount of dilution water and with a flocculant amount of less than 15 ppmw of oil sands.
As shown in FIG. 2, it may be beneficial to pass the bitumen extract (226) to a product cleaning step (or bitumen extract solids removal) (230) to remove fines (232) as well as a small amount of entrained water. The product cleaning step may be performed, for instance by an electric treater or other system to achieve crude specifications for pipeline transportation. Solvent in the cleaned bitumen extract (234) is recovered (236), for instance in a solvent recovery unit, and is recycled (238) to the front section of hydrotransport pipeline to assist in bitumen extraction. Some amount of hydrocarbon solvent may be retained in the diluted bitumen product (239) in order to meet API gravity and viscosity specifications for crude transportation. In such a case, additional fresh solvent (238) may be required in the solvent injection zone to make up any shortfall.
The tailings (240) from the bottom of the separation vessel may include a significant amount of hydrocarbon solvent. Tailings solvent recovery (TSR) (242) may be used to reduce solvent concentration to a level acceptable for tailings pond storage. Solvent (243) from the TSR (242) may be passed to solvent recovery (236). Solvent recovery may involve a stripping tower or other solvent recovery system. Steam may be used to increase the stripping tower temperature to assist solvent recovery. Solvent reduced tailings (244) and the fines (232) (together 246) are then pipelined in a hydrotransport pipeline (250) to a tailings pond (248) for storage and for recycle of water (252) either for the slurry (254) or for the dilution (220). Optionally, additional flocculant (258) in a proper concentration (for instance 50 to 500 ppmw of oil sands) may be injected into the hydrotransport pipeline (250) to assist the precipitation of fines in the tailing pond and speed-up the recycle of water.
In conventional primary separation vessels, it is necessary to withdraw a middling product for further bitumen recovery in the flotation cells. On the other hand, in an embodiment of the instant process, a high bitumen recovery may be achieved with gravity separation. Therefore, there is no need to withdraw a middling product for additional bitumen recovery. A middling stream is formed along with the coarse sands slurry at the bottom of the primary separation vessel. For tailings management, at least two options are available, both of which are considered part of the present inventions. One option is to withdraw both streams and send them to tailing hydrotransport where additional flocculants may be added, or where additional flocculants are added in the tailing ponds to speed up separation of sands and water recycle. Another option is to withdraw the middling stream and add flocculants to separate fines and recycle water. The concentrated fines slurry may then be mixed with coarse sands and sent to tailing ponds for disposal and water recycle. The Figures show the first option; one of ordinary skill will be readily able to visualize the latter option by way of the description herein.
In another embodiment, as shown in FIG. 3, some cleaned bitumen extract (358) may be recycled directly to the front section of the hydrotransport to reduce the requirement of make-up solvent. The remainder of FIG. 3, including the reference numerals, is the same as FIG. 2.
In another embodiment, as shown in FIG. 4, a solvent mixing vessel (460) is used before the hydrotransport pipeline to achieve the same objective of dispersion of solvent droplets to assist the digestion of bitumen droplets. In this embodiment, recycle solvent and make-up solvent are fed to the solvent mixer (460) instead of hydrotransport pipeline. The remainder of FIG. 4, including the reference numerals, is the same as FIG. 2.
FIGS. 3 and 4 illustrate two of the many modifications to the equipment used to implement the SAWE processes described herein. It will be understood that the present disclosure is directed to methods of extracting bitumen using the SAWE processes and also to systems that are adapted for the implementation of the SAWE processes described herein. FIGS. 2-4 have been provided as exemplary, non-limiting illustrations of equipment arrangements that may be used to provide a SAWE system. Those of ordinary skill in the art will recognize variations on the themes presented in FIGS. 2-4. All systems adapted to operate according to the SAWE process described herein are considered to be within the scope of the present disclosure.
In one embodiment, bitumen recovery is higher than 90% by weight from middle grade oil sands (middle grade oils sands having 10-12 wt. % bitumen). In one embodiment, bitumen recovery is higher than 95% from high grade oil sands (high grade oil sands having 12-15 wt. % bitumen). In one embodiment, total hydrocarbons, including asphaltenes, in the tailings is less than 10% by weight of original bitumen in the oil sands feed.

EXAMPLES

Testing of solvent assisted water extraction (SAWE) processes was carried out in a 1500 ml glass vessel made by Parr Instrument (Moline, Ill., United States). The glass vessel had a jacketed layer allowing circulation of heating fluid to control extraction temperature. The glass vessel was equipped with dual level turbo blades to ensure good slurry mixing.
Two feed samples of oil sands were used. Feed sample #1 was middle grade with 11.03% bitumen, 3.77% water, and 85.20% sands. Feed sample #2 was high grade with 13.04% bitumen, 2.95% water, and 84.01% sands. Both feed samples were homogenized in advance and stored under frozen condition to ensure uniform feed quality.
The hydrocarbon solvent used in the test processes comprised a mixture of cyclohexane, n-heptane, and toluene. The volume content of n-heptane was in the range of 50-60%, cyclohexane was in the range of 30-35%, and toluene was in range of 10-15%. In some examples, bitumen was mixed with other solvents to form the hydrocarbon solvent. In such implementations, the hydrocarbon solvent included 10-15% of bitumen. Unless specifically stated otherwise, all content measurements are in weight percent based on weight of the oil sands.
For each testing run, 300-600 grams of oil sands were charged to the Parr glass vessel along with 40-50% of water based on the weight of oil sands. The glass vessel was assembled and purged with nitrogen to remove air in the system. The fluid circulation system was turned on to raise the vessel content to a target extraction temperature, typically between 20 and 50° C. A stirrer was then turned on to agitate the slurry to a homogeneous mixture. Typically, the stirrer speed was kept around 1000 rpm. After initial mixing of 3-5 minutes, hydrocarbon solvent was fed to the vessel and the slurry was further agitated for another 10 minutes. Dilution water was then added to the vessel and the slurry was further agitated for 5 minutes. The sequential injection of solvent and dilution water was to simulate continuous operation of the hydrotransport pipeline.
After that, the stirrer was turned off and the slurry mixture was allowed to settle for 10-30 minutes. The top layer bitumen extract was collected and the residual sands and water mixture was filtered to get wet residual sands. The wet residual sands were placed in a flat pan and allowed to dry in a vent hood for a couple of days. In some experiments, a fixed concentration of flocculant was added to the initial slurry or to the dilution water to understand its impact. In certain cases, a higher concentration of flocculant was added to the residual sands-water mixture to speed up the filtration process.
Dean Stark analysis was carried out on dried samples of residual sands. Water content was obtained from the analysis and extracted sands were further dried in an oven to obtain the solid content. Bitumen content of the residual sands was determined by dispersing Dean Stark aliquot sample on glass-fiber filter paper followed by air drying. Raw data of bitumen, water, and solid contents were normalized and bitumen recovery was calculated based on residual bitumen content in the dried sands.
Various flocculants may be effective to aid liberation of bitumen from sands surface and to reduce the amount of dilution water requirement. Two types of flocculants were used: hydrated solid flocculant Floccin™-1106 provided by Integrated Engineers Inc. (Oakhurst, Calif., United States) and anionic ultra high molecular weight polymer flocculant Magnafloc™ 1011 produced by BASF (Ludwigshafen, Germany), to demonstrate the process concept. However, the process is not limited to the use of such flocculants. Various nonionic, anionic, and cationic polymers or copolymers with different molecular weight and with acrylamide, acrylic acid, amine, acrylate, ethylene imine, ethylene oxide, and other functional groups may be suited as flocculants. Other inorganic flocculants such as aluminum sulfate, polyaluminum chloride, polysilicate, sodium hydroxide, magnesium oxide, hydroxylated ferric sulfate, acidified sodium silicate, etc. may be suited to be used alone or in combination with polymer flocculants.

Example 1

Feed sample #1 was used to measure the impact of dilution water on bitumen extract separation. Water to oil sands ratio of 40% was used for all four experiments to form the initial slurry. Solvent used in this study was a blend of 15% bitumen with 85% of hydrocarbon solvent mentioned above. Solvent to oil sands ratio was kept at 20%. Different amount of dilution water was added after solvent extraction to reduce bitumen-water-fines emulsion. Total amount of water usage for the four experiments ranged from 0.6 to 2.0 by weight of oil sands. Hydrated solid flocculant, Floccin™-1106, was used in experiment No. 2. Results are listed in Table 1.

	TABLE 1

	Experiment No.

	1	2	3	4

Oil Sands charge	gram	600	600	300	400
Extraction	° C.	50	30	30	30
temperature
Water added to	gram	240	240	120	160
form slurry
Flocculant added	ppmw of	0	0	0	0
	ore
Agitation speed	rpm	1000	1100	1100	1100
Water slurry	min	3	3	3	3
agitation time
Solvent added	gram	120	120	60	80
Solvent slurry	min		10	10	10	10
agitation time
Dilution water	gram	120	420	480	560
added
Flocculant added	ppmw of	0	2500	0	0
	ore
Additional	min	5	5	5	5
agitation time
Slurry settling	min		30	30	30	30
time
Solvent/Ore ratio	w/w	0.2	0.2	0.2	0.2
Total Water/Ore	w/w	0.6	1.1	2.0	1.8
ratio
Emulsion		Yes	Yes	No	No
Formation
Bitumen extract		No	No	Clear	Clear
separation		separation	separation	sepa-	sepa-
				ration	ration

As shown in Table 1, a stable bitumen-water-fines emulsion was formed when the total amount of water usage in the slurry was 0.6 of ore. Floccin™-1106 at 2500 ppmw level did not help to break the emulsion even where the total amount of water increased to 1.1 of ore. When the total amount of water to ore ratio was increased to the range of 1.8-2.0, the stable bitumen-water-fines emulsion was broken and clear separation of bitumen extract from water-fines middling layer was seen. This is evidence that gravity separation of bitumen extract can be achieved with an adequate amount of dilution water without the use of flocculant.

Example 2

Feed sample #1 was used to measure the impact of temperature on bitumen extraction. Solvent used was a mixture of 87.5% hydrocarbon solvent blended with 12.5% bitumen. Three temperatures, 20, 30 and 40° C. were tested. Total water to oil sands ratio was kept at 2.0. Each condition was duplicated to improve data reliability. Bitumen recovery was calculated from the amount of bitumen left in residual sands from Dean Stark analysis. Results are listed in Table 2.

	TABLE 2

	Experimental No.

	5/6	7/8	9/10

Oil Sands charge	gram	350	350	350
Extraction temperature	° C.	20	30	40
Water added to form	gram	140	150	150
slurry
Flocculant added	ppmw of	0	0	0
	ore
Agitation speed	rpm	1000	1000	1000
Water slurry agitation	min	3	3	3
time
Solvent added	gram	70	70	70
Solvent slurry agitation	min		10	10	10
time
Dilution water added	gram	550	540	540
Flocculant added	ppmw of	0	0	0
	ore
Additional agitation	min	5	5	5
time
Slurry settling time	min		10	10	10
Solvent/Ore ratio	w/w	0.2	0.2	0.2
Total Water/Ore ratio	w/w	2.0	2.0	2.0
Emulsion Formation		No	No	No
Bitumen extract		Clear	Clear	Clear
separation		separation	separation	separation
Bitumen Recovery	wt %	91.2	92.5	92.7

As seen from Table 2, bitumen recovery increased slightly from 91.2 to 92.7 wt % with an increase of temperature from 20 to 40° C. This showed temperature in the range of the study had only a minor impact on bitumen extraction. This data also showed that bitumen recovery of higher than 90% can be achieved.

Example 3

Feed sample #1 was used for this study. Pure hydrocarbon solvent without bitumen blend was used. The solvent had a volume composition of 15% toluene, 35% cyclohexane, and 50% n-heptane. Temperatures of 20 to 50° C. were tested. Total water to oil sands ratio was kept at 2.0. Some conditions were repeated to improve data reliability. Results are listed in Table 3.

	TABLE 3

	Experimental No.

	11/12/13	14/15	16/17	18

Oil Sands charge	gram	350	350	350	350
Extraction	° C.	20	30	40	50
temperature
Water added to form	gram	140	150	150	150
slurry
Flocculant added	ppmw of	0	0	0	0
	ore
Agitation speed	rpm	1000	1000	1000	1000
Water slurry	min	3	3	3	3
agitation time
Solvent added	gram	70	70	70	70
Solvent slurry	min		10	10	10	10
agitation time
Dilution water	gram	550	540	540	540
added
Flocculant added	ppmw of	0	0	0	0
	ore
Additional agitation	min	5	5	5	5
time
Slurry settling time	min		10	10	10	10
Solvent/Ore ratio	w/w	0.2	0.2	0.2	0.2
Total Water/Ore	w/w	2.0	2.0	2.0	2.0
ratio
Emulsion Formation		No	No	No	No
Bitumen extract		Clear	Clear	Clear	Clear
separation		separation	sepa-	sepa-	sepa-
			ration	ration	ration
Bitumen Recovery	wt %	92.9	93.2	94.5	93.1

Compared to the data of Table 2, the pure hydrocarbon solvent provided similar or higher bitumen recovery than the solvent with bitumen blend. Data further showed that temperature, in the range of 20 to 50° C., did not have strong impact on bitumen recovery. Solvent extraction time of 10 minutes was enough to achieve higher than 90% bitumen recovery and a dilution water mixing time of 5 minutes was enough to achieve clear separation of bitumen extract.

Example 4

Feed sample #1 was used for this study. Pure hydrocarbon solvent as in example 3 was used. The solvent to oil sands ratio changed from 0.10 to 0.30 while temperature was kept constant at 30° C. Total water to oil sands ratio was kept constant at 2.0 as well.

	TABLE 4

	Experimental No.

	19/20	21/22	23	24/25	26/27

Oil Sands charge	gram	350	350	350	350	350
Extraction	° C.	30	30	30	30	30
temperature
Water added to	gram	150	150	150	150	150
form slurry
Flocculant	ppmw
	0	0	0	0	0
added	of ore
Agitation	rpm	1000	1000	1000	1000	1000
speed
Water slurry	min	3	3	3	3	3
agitation time
Solvent added	gram	35.0	52.5	70.0	87.5	105.0
Solvent slurry	min		10	10	10	10	10
agitation time
Dilution water	gram	540	540	540	540	540
added
Flocculant	ppmw		0	0	0	0	0
added	of ore
Additional	min	5	5	5	5	5
agitation time
Slurry settling	min		20	20	20	20	20
time
Solvent/Ore	w/w	0.10	0.15	0.20	0.25	0.30
ratio
Total	w/w	2.0	2.0	2.0	2.0	2.0
Water/Ore
ratio
Emulsion		No	No	No	No	No
Formation
Bitumen		Clear	Clear	Clear	Clear	Clear
extract		separation	separation	separation	separation	separation
separation
Bitumen	wt %	88.8	88.7	90.3	90.2	93.5
Recovery

Bitumen extracts in this study were all clearly separated from water-fines middling streams. As with examples 2 & 3, separation was relatively fast and completed within 10 minutes. Bitumen recovery data showed significant impact of solvent to oil sands ratio with higher bitumen recovery at a high ratio. Data of Examples 2, 3 and 4 showed that solvent to oil sands ratio of 0.2 was adequate to provide bitumen recovery of higher than 90%.

Example 5

Data of examples 1 to 4 showed that bitumen-water-fines emulsion could be avoided and clear bitumen extract separation could be achieved with total water use in the range of 1.8-2.0 of oil sands. However, it is desirable to reduce the total water use for bitumen extraction. Feed sample #1 was used and an anionic ultra high molecular weight polymer flocculant, Magnafloc™ 1011, was used to study its impact on viscosity of water-fines middling stream. The concentration of flocculant was in the range of 10 to 90 ppmw based on oil sands. Flocculant was added either in the initial water slurry or in the dilution water, or added to both of them. Total water usage was gradually reduced in the study to understand the impact of flocculant. Temperature of extraction was kept at 30° C. and the solvent to oil sands ratio was kept constant at 0.20. The same type of hydrocarbon solvent was used as in examples 3 and 4. Results are shown in Table 5.

	TABLE 5

	Experiment No.

	28	29	30	31	32	33	34

Oil Sands	gram	350	350	350	350	350	350	350
charge
Extraction	° C.	30	30	30	30	30	30	30
temperature
Water	gram	175	175	175	175	175	175	175
added to
form
slurry
Flocculant	ppmw
	0	15	15	15	0	15	10
added	of
	ore
Agitation	rpm	1000	1000	1000	1000	1000	1000	1000
speed
Water	min	5	5	5	5	5	5	5
slurry
agitation
time
Solvent	gram	70.0	70.0	70.0	70.0	70.0	70.0	70.0
added
Solvent	min		10	10	10	10	10	10	10
slurry
agitation
time
Dilution	gram	525	525	350	350	350	250	175
water
added
Flocculant	ppmw		90	30	15	0	15	0	0
added	of
	ore
Additional	min	5	5	5	5	5	5	5
agitation
time
Slurry	min
	20	20	20	20	20	20	20
settling
time
Solvent/Ore	w/w	0.20	0.20	0.20	0.20	0.20	0.20	0.20
ratio
Total	w/w	2.0	2.0	1.5	1.5	1.5	1.2	1.0
Water/Ore
ratio
Emulsion		Some	Moderate	Minor	No	No	No	No
Formation
Bitumen		Bitumen	Bitumen	Bitumen	Clear	Clear	Clear sep.	Clear sep.
extract		trapped	trapped	trapped	sep.	sep.
separation		in sands	in sands	in
				sands
Bitumen	wt %	85.1	78.8	89.5	94.3	92.2	93.1	92.0
Recovery

As shown in Table 5, flocculant concentration at 90 and 45 ppmw levels (experiment No. 28 & 29) increased slurry viscosity and resulted in some bitumen droplets trapped in sands. Low bitumen recovery resulted due to poor bitumen extract separation. When the flocculant concentration was reduced to 10-15 ppmw range (experimental No. 31-34), the total amount of water use could be reduced to 1.0 of oil sands (experimental No. 34) and yet clear bitumen extract separation and high bitumen recovery (>90%) was achieved.
The use of a low concentration of polymer flocculant to reduce total water usage from 2.0 to 1.0 of oil sands, the clear bitumen extract separation by gravity, and high bitumen recovery, demonstrated the effectiveness of this process.

Example 6

A higher grade oil sands sample, feed sample #2, was used to understand the impact of a low concentration of flocculant, Magnafloc™ 1011, on water usage and bitumen recovery. Extraction temperature was kept constant at 30° C. and solvent to oil sands ratio was kept at 0.20. Results are listed in Table 6.

	TABLE 6

	Experimental No.

	35	36

Oil Sands charge	gram	350	350
Extraction temperature	° C.	30	30
Water added to form slurry	gram	175	175
Flocculant added	ppmw of	10	10
	ore
Agitation speed	rpm	1000	1000
Water slurry agitation time	min	5	5
Solvent added	gram	70	70
Solvent slurry agitation time	min		10	10
Dilution water added	gram	250	175
Flocculant added	ppmw of	0	0
	ore
Additional agitation time	min	5	5
Slurry settling time	min		20	20
Solvent/Ore ratio	w/w	0.2	0.2
Total Water/Ore ratio	w/w	1.2	1.0
Emulsion Formation		No	No
Bitumen extract separation		Clear	Clear separation
		separation
Bitumen Recovery	wt %	95.6	96.5

Data of Table 6 showed that clear bitumen extract separation was achieved by gravity at a total water ratio of 1.0-1.2 to oil sands. This is accomplished at a flocculant concentration of 10 ppmw. Very high bitumen recovery, around 96%, was achieved at these conditions. Also, bitumen extract separation was quite fast, generally completed in less than 10 minutes.
Examples 1 to 6 demonstrated that the process is capable achieving high bitumen recovery (>90%) with conventional gravity separation, yet the process does not require the aid of caustic to liberate bitumen from oil sands. The use of a low concentration of polymer flocculant reduces the total water usage, and the water reuse from tailings is greatly improved due to the absence of caustic. In addition, the absence of a bitumen-water-fines emulsion and air usage, eliminates (or mitigates the need for) the secondary separation system such as flotation cells and associated devices. The present processes may simplify the separation process and may reduce both capital and operating costs.
FIG. 5 illustrates bitumen recovery data between normal oil sands and highly weathered oil sands using the SAWE processes described herein. Bitumen recovery graph 500 includes oil sands bitumen content 502 as a function of weight percent, on the x-axis, and bitumen recovery percentage 504 on the y-axis. Curve 506 illustrates the Energy Resources Conservation Board of Alberta, Canada, mandatory bitumen recovery on the basis of bitumen ore content. Line 508 illustrates bitumen recovery obtained from normal oil sands 510 and from highly weathered oil sands 512, using the SAWE processes described herein. Typically, highly weathered oil sands give very low bitumen recovery, generally under 50 percent, using standard commercial bitumen recovery processes. The high bitumen recovery obtained using SAWE, even for low quality oil sands such as the highly weathered oil sands, makes the SAWE process valuable for commercial application of a broad range of oil sands resources.
In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments. However, it will be apparent to one skilled in the art that these specific details are not required.
The above-described embodiments are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope, which is defined solely by the claims appended hereto.

Claims

1. A process for extracting bitumen from oil sands comprising:

adding water to the oil sands to form a slurry;

passing the slurry and a hydrocarbon solvent through a hydrotransport pipeline to form an extracted slurry; and

adding dilution water to the extracted slurry to form a diluted extracted slurry to reduce slurry viscosity to assist in subsequent separation.

2. The process of claim 1, further comprising adding a flocculant to assist subsequent separation or to reduce dilution water requirements.

3. The process of claim 2, wherein 1 to 50 ppmw of the flocculant is used based on oil sands weight.

4. The process of claim 3, wherein 5 to 15 ppmw of the flocculant is used based on oil sands weight.

5. The process of claim 2, wherein the flocculant is a polymer flocculant.

6. The process of claim 5, wherein the flocculant is an anionic polymer flocculant with molecular weight above 500,000.

7. The process of claim 5, wherein the flocculant is an anionic polymer flocculant with a molecular weight of above 1,000,000.

8. The process of claim 1, wherein the solvent is added to the slurry in the hydrotransport pipeline.

9. The process of claim 1, wherein the solvent is mixed with the slurry before the slurry is introduced into the hydrotransport pipeline.

10. The process of claim 1, wherein the dilution water is added to the extracted slurry in the hydrotransport pipeline.

11. The process of claim 1, wherein the dilution water is added to the extracted slurry after the extracted slurry exits the hydrotransport pipeline.

12. The process of claim 1, further comprising separating the diluted extracted slurry into a bitumen extract and tailings.

13. The process of claim 12, wherein the separation is effected by gravity separation.

14. The process of claim 12, further comprising passing the bitumen extract to a product cleaning system to remove fines and water and to produce a cleaned bitumen extract.

15. The process of claim 14, wherein the product cleaning system is an electric treater.

16. The process of claim 14, wherein a portion of the cleaned bitumen extract is recycled back into the hydrotransport pipeline.

17. The process of claim 12, further comprising recovering a portion of the solvent from the cleaned bitumen extract to form a diluted bitumen product.

18. The process of claim 17, further comprising recycling the portion of the solvent recovered from the cleaned bitumen extract back into the hydrotransport pipeline.

19. The process of claim 12, further comprising recovering a portion of the solvent from the tailings.

20. The process of claim 19, wherein the recovering of the portion of the solvent comprises the use of steam or a hot gas stripping tower to raise the temperature of the tailings to assist solvent recovery.

21. The process of claim 12, further comprising passing the tailings through tailings hydrotransport.

22. The process of claim 21, further comprising adding a flocculant into the tailings hydrotransport to assist fines settling.

23. The process of claim 22, wherein 50 to 500 ppmw of the flocculant is added into the tailings hydrotransport.

24. The process of claim 17, wherein an amount of the solvent is retained in the diluted bitumen product to meet pipeline transportation specifications.

25. The process of claim 12, further comprising withdrawing a middling stream from the diluted extracted slurry.

26. The process of claim 25, further comprising adding a flocculant to the middling stream to separate fines and recycle water to form a concentrated fines slurry.

27. The process of claim 1, wherein the solvent comprises one or more of the following: an n-paraffin, an iso-paraffin, a cyclic-paraffin, an olefin, and an aromatic hydrocarbon, wherein the solvent has a bromine number of less than 10.

28. The process of claim 1, wherein the solvent comprises natural gas liquid, light naphtha, or a blend of natural gas liquid and light naphtha.

29. The process of claim 1, wherein the solvent comprises a C₁-C₆hydrocarbon liquid.

30. The process of claim 1, wherein the solvent is used in a weight fraction of 0.1 to 0.3 based on oil sands weight.

31. The process of claim 1, wherein the solvent is used in a weight fraction of 0.15 to 0.25 based on oil sands weight.

32. The process of claim 1, wherein the extraction is effected with less than 100 ppmw caustic based on oil sands weight.

33. The process of claim 1, wherein the extraction is effected in the absence of caustic as a means to assist extraction.

34. The process of claim 1, wherein the extraction is effected in the absence of air as a means to separate bitumen droplets from the slurry.

35. The process of claim 1, wherein a weight ratio of water to oil sands in the diluted extracted slurry is less than 2:1.

36. The process of claim 1, wherein a weight ratio of water to oil sands in the diluted extracted slurry is less than 1.5:1.

37. The process of claim 1, wherein a weight ratio of water to oil sands in the diluted extracted slurry is less than 1:1.

38. The process of claim 1, wherein a weight ratio of water to oil sands in the diluted extracted slurry is at least 0.5:1.

39. The process of claim 1, wherein a weight ratio of water to oil sands in the diluted extracted slurry is at least 0.7:1.

40. The process of claim 1, wherein extraction is effected at a temperature of 10 to 50° C.

41. The process of claim 1, wherein extraction is effected at a temperature of 25 to 35° C.

42. The process of claim 1, wherein a solvent extraction residence time is at least 5 minutes.

43. The process of claim 1, wherein a solvent extraction residence time is at least 10 minutes.

44. The process of claim 1, wherein a water dilution residence time is at least 10 minutes.

45. The process of claim 1, wherein a water dilution residence time is between 1 and 10 minutes.

46. The process of claim 1, wherein a water dilution residence time is between 1 and 5 minutes.

47. The process of claim 1, wherein the solvent is a solvent that will not precipitate asphaltenes.

48. The process of claim 1, wherein the oil sands are mined oil sands that have been crushed.

49. The process of claim 1, wherein the diluted bitumen extract is a non-emulsion.