CA2845983A1 - Lean froth process for oil sands processing - Google Patents
Lean froth process for oil sands processing Download PDFInfo
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- CA2845983A1 CA2845983A1 CA2845983A CA2845983A CA2845983A1 CA 2845983 A1 CA2845983 A1 CA 2845983A1 CA 2845983 A CA2845983 A CA 2845983A CA 2845983 A CA2845983 A CA 2845983A CA 2845983 A1 CA2845983 A1 CA 2845983A1
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B03—SEPARATION OF SOLID MATERIALS USING LIQUIDS OR USING PNEUMATIC TABLES OR JIGS; MAGNETIC OR ELECTROSTATIC SEPARATION OF SOLID MATERIALS FROM SOLID MATERIALS OR FLUIDS; SEPARATION BY HIGH-VOLTAGE ELECTRIC FIELDS
- B03B—SEPARATING SOLID MATERIALS USING LIQUIDS OR USING PNEUMATIC TABLES OR JIGS
- B03B9/00—General arrangement of separating plant, e.g. flow sheets
- B03B9/02—General arrangement of separating plant, e.g. flow sheets specially adapted for oil-sand, oil-chalk, oil-shales, ozokerite, bitumen, or the like
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
- C10G1/04—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by extraction
- C10G1/045—Separation of insoluble materials
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
- C10G1/04—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by extraction
- C10G1/047—Hot water or cold water extraction processes
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D21/00—Separation of suspended solid particles from liquids by sedimentation
- B01D21/02—Settling tanks with single outlets for the separated liquid
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D21/00—Separation of suspended solid particles from liquids by sedimentation
- B01D21/26—Separation of sediment aided by centrifugal force or centripetal force
- B01D21/267—Separation of sediment aided by centrifugal force or centripetal force by using a cyclone
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- Engineering & Computer Science (AREA)
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- Wood Science & Technology (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Geology (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
Described is a process for processing oil sands comprising: a) providing a slurry of oil sands, water, and a dispersant for reducing slurry viscosity to assist separation of solids from the slurry; b) breaking down lumps of the oil sands and effecting shear mixing, of the oil sands by the water, by mixing the slurry; c) producing a solids stream and a lean bitumen froth comprising bitumen after breaking down the lumps and effecting the shear mixing; d) passing the lean bitumen froth through a hydrotransport pipeline without the need for air injection;
and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d). The process is not dependent on air attachment.
and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d). The process is not dependent on air attachment.
Description
LEAN FROTH PROCESS FOR OIL SANDS PROCESSING
FIELD
[0001] The present disclosure relates generally to oil sands processing.
BACKGROUND
FIELD
[0001] The present disclosure relates generally to oil sands processing.
BACKGROUND
[0002] Water based extraction (WBE) is a commonly used process to extract bitumen from mined oil sands. In the WBE process, mined, crushed oil sands are mixed with hot water to form a slurry. Caustic, such as sodium hydroxide (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 droplets can be attached by air bubbles to aid separation, air is injected into the hydrotransport pipeline and into secondary flotation cells to assist bitumen recovery, thereby providing for bitumen to air attachment.
The injected air is in addition to air naturally interacts with the hydrotransport line and secondary flotation cells. 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.
Since the density of bitumen is similar to that of water and since bitumen droplets can be attached by air bubbles to aid separation, air is injected into the hydrotransport pipeline and into secondary flotation cells to assist bitumen recovery, thereby providing for bitumen to air attachment.
The injected air is in addition to air naturally interacts with the hydrotransport line and secondary flotation cells. 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.
[0003] The presence of fines (especially clays) in the oil sands makes bitumen to air attachment less efficient. Lower bitumen recovery is often the result of a large amount of fines in the oil sands. The lower bitumen recovery can even occur when there is a high bitumen content in the oil sands.
[0004] Air injection to the pipeline and a high solids content in the pipeline may enhance the erosion of the pipeline due to abrasion and oxidation. Due to the abrasion and oxidation, the pipeline is frequently rotated and replaced, contributing to lower plant utilization and higher operating costs.
[0005] Bitumen liberation from sand grains is a relatively fast process;
however, air attachment to bitumen droplets in the dense slurry is a relatively slow process and requires a very large vessel (for instance, on the order of 25 m in diameter and 30 m in height) to achieve the desired bitumen separation. In addition, secondary flotation cells are required to achieve a bitumen recovery of over 90%.
however, air attachment to bitumen droplets in the dense slurry is a relatively slow process and requires a very large vessel (for instance, on the order of 25 m in diameter and 30 m in height) to achieve the desired bitumen separation. In addition, secondary flotation cells are required to achieve a bitumen recovery of over 90%.
[0006] While the addition of caustic helps to liberate bitumen droplets from the sands and helps improve the efficiency of bitumen to air attachment in the pipeline, the addition of caustic may exacerbate the formation of mature fines tailings (MFTs). MFTs may take years to settle in tailings ponds. MFTs may delay water recycle. The high pH of tailings water, caused by having the MFTs, makes land reclamation more difficult.
[0007] It is desirable to provide an alternative process for processing oil sands.
SUMMARY
SUMMARY
[0008] It is an object of the present disclosure to provide a process for processing oil sands.
[0009] Described is a process for processing oil sands comprising: a) providing a slurry of oil sands, water, and a dispersant for reducing slurry viscosity to assist separation of solids from the slurry; b) breaking down lumps of the oil sands and effecting shear mixing, of the oil sands by the water, by mixing the slurry; c) producing a solids stream and a lean bitumen froth comprising bitumen after breaking down the lumps and effecting the shear mixing; d) passing the lean bitumen froth through a hydrotransport pipeline without the need for air injection; and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d). The process is not dependent on air attachment.
[0010] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood.
Additional features will also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
Additional features will also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.
[0012] Figure 1 is a flow chart of a process for processing oil sands into bitumen.
[0013] Figure 2 is a flow chart of a process for processing oil sands into bitumen.
[0014] Figure 3 is a flow chart of a process for processing oil sands into lean bitumen froth.
[0015] Figure 4 is a flow chart of a process for processing oil sands into lean bitumen froth.
[0016] Figure 5 is a graph showing bitumen recovery as a function of temperature.
[0017] Figure 6 is a graph showing bitumen recovery as a function of dispersant concentration.
[0018] Figure 7 is a graph showing bitumen recovery as a function of salts concentration.
[0019] Figure 8 is a graph showing bitumen recovery as a function of salts concentration.
[0020] Figure 9 is a graph showing bitumen recovery as a function of Na2SiO3 addition as a dispersant.
[0021] It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION
DETAILED DESCRIPTION
[0022] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features =
. .
that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.
100231 At the outset, for ease of reference, certain terms used in this application and their meaning as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.
[0024] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. However, the techniques described are not limited to heavy oils but may also be used with any number of other reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.
[0025] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range in excess of 7 wt. %).
In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can =
vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.
[0026] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluid by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.
[0027] Fines are generally defined as those solids having a size of less than about 44 micrometer ( m).
[0028] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
[0029] As described above, mined crushed oil sands are commonly treated with water and caustic, passed through a hydrotransport pipeline with air injection to attach air to the bitumen, separated from solids and water using primary and secondary flotation vessels, and treated with solvent to produce bitumen. In conventional processes, bitumen to air attachment = =
is considered a necessary bitumen extraction mechanism in the pipeline and in subsequent primary and secondary separation. Disadvantages of bitumen to air attachment are described above.
[0030] The process of the present disclosure is not dependent on bitumen to air attachment (i.e., air attachment).
[0031] Generally, the present disclosure relates to a process for processing oil sands comprising: a) providing a slurry of oil sands, water, and a dispersant for reducing slurry viscosity to assist separation of solids from the slurry; b) breaking down lumps of the oil sands and effecting shear mixing, of the oil sands by the water, by mixing the slurry; c) producing a solids stream and a lean bitumen froth comprising bitumen after breaking down the lumps and effecting the shear mixing; d) passing the lean bitumen froth through a hydrotransport pipeline without the need for air injection; and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d). The process is not dependent on air attachment.
[0032] Because the bitumen extraction described herein is not dependent on air attachment, bitumen recovery may be less sensitive to fines and clays content in the oil sands.
[0033] Because the bitumen extraction described herein may be less strict on process water quality in terms of salts and fines content, due to the addition of water and a dispersant and the use of shear mixing, recycle water management may be simplified.
[0034] Figure 1 [0035] As shown in Figure 1, at an ore preparation plant (100), a slurry of oil sands (102), water (106), and a dispersant (108) are mixed in a first mixer (104).
The slurry of oil sands (i.e., slurry) may be crushed, mined oil sands from a mined oil sands project. The slurry of oil sands may also be from production wells of a subsurface project that produces an oil sands and water slurry.
[0036] The dispersant may be used to reduce the viscosity of the slurry of oil sands to assist separation of solids from the slurry of oil sands. The dispersant may be, for instance, Na2SiO3 or NaOH where Na stands for sodium, Si stands for silicon, 0 stands for oxygen and H stands for hydrogen. The dosage of dispersant may be significantly smaller than caustic usage in commercial water based extraction processes. The dispersant may be added in an amount of, for instance, 100 to 400 ppm, or 100 to 300 ppm, based on oil sands weight, or any number between or inclusive of these ranges. Other suitable dispersants may include sodium citrate (Na3C6H507), ammonium hydroxide (NH4OH) or other chemicals that are capable of reducing carrier fluid viscosity to achieve the objectives of dispersing fines and clays in the slurry of oil sands, thereby allowing coarse sands to be separated from the slurry of oil sands.
C stands for carbon and N stands for nitrogen.
[0037] A ratio of, for instance, less than 1.2, between 0.6 and 1.2, or between 0.7 and 1.1 water, to 1.0 oil sands may be used, on a weight basis, or any number between or inclusive of these ranges. The water temperature should be high enough to provide a desired level of bitumen extraction and may be, for instance, between 40 C and 80 C, or any number between or inclusive of these ranges. C stands for degrees Celsius.
[0038] The water may have a relatively high salt content. Depending on such factors as, desired bitumen recovery, water to ore ratio (WOR), composition and amount of dispersant used, water with salt contents of up to 5,000 ppm (parts per million), up to 8,000 ppm, up to 10,000 ppm, or above 10,000 ppm may be used, or any number between or inclusive of these ranges. The ratio of dispersant to salts in the water may be at least at least 1:10, on a weight basis. The water may comprise at least one of brackish water, subsurface basal water, and river water. The water may have 200 ppm to 15,000 ppm salts, 100 and 10,000 ppm, 1000 and 10000ppm, 500 to 10,000 ppm salts, or any number between or inclusive of these ranges.
[0039] The first mixer (104) effects shear mixing of the oil sands by the water. The first mixer (104) breaks down lumps of the oil sands, to reduce bitumen loss in the solids stream (116). The lumps of oil sands may be broken down to, for instance, a d90 of less than 4 inches, or a d90 of less than 2 inches, or any number between or inclusive of these ranges.
Examples of the first mixer (104) are described below with reference to Figures 3 and 4.
Conventionally, lumps of oils sands have not been broken down to this extent, presumably because those in the art did not believe that the additional cost needed to break down the lumps provided sufficient benefit. As described herein, the benefit is not having to rely on air attachment.
[0040] Following mixing by the first mixer (104), the resultant slurry (110) may be fed into a separator (112). The separator (112) produces a lean bitumen froth (114) and a solids stream (116). The solids stream may have a bitumen content of less than 1.0 wt. % on a dry basis. The lean bitumen froth may comprise, for instance, 10-20% bitumen, 10-15% fines, 1-5% coarse sands, and 65-79% of water, all on a weight basis, or any number between or inclusive of these ranges. Bitumen droplets around sand grains are quickly released into the resultant slurry (110) when lump sizes of oil sands are reduced during the mixing. Coarse sands may be rapidly settled in the separator (112) (e.g. in a residence time of less than 3 minutes), when a sufficient amount of water, such as described in paragraphs [0036] and [0038] of the application, and dispersant are used. The lean bitumen froth (114) may comprise greater than 90% of the original bitumen in the oil sands. The solids stream (116) may be close to mining areas and may be landfilled by trucks, conveyer belts, or tailings pipeline.
[0041] The lean bitumen froth (114) may be transported through a hydrotransport pipeline (120), to a central processing plant (122). Because a limited quantity of coarse sands is presented in the lean bitumen froth (114), pipeline erosion may be reduced.
The hydrotransport pipeline may be able to operate longer before maintenance. In addition, air compression and feeding systems, used in conventional hydrotransport, may not be required, which may also reduce pipeline erosion. Air injection is not required since the bitumen extraction does not rely on bitumen to air attachment. The process may be carried out in the substantial absence of air injection for bitumen extraction, such that less than 10% of bitumen extraction is by air attachment. Air injection refers to the purposeful addition of air to the process and excludes the natural addition of air to the process. The natural addition of air occurs because the container where bitumen is extracted is open to the environment and is not within a vacuum. The process may be carried out in the substantial absence of air injection for bitumen extraction because the lumps of oil sands are broken down as discussed above. If the lumps of oil sands were not broken down as discussed above, it would not be possible to carry out the process in the substantial absence of air injection for bitumen extraction.
= =
[0042] Following hydrotransport, steam (124) may be used to deaerate (126) the lean bitumen froth (114). The lean bitumen froth (114) is deaerated from the natural addition of air entrained due to mixing the oil sands (102), water (106) and dispersant (108) in the first mixer (104) in the ore preparation plant (100).
[0043] Following dearation, a first solvent (128) may be added to a second mixer (130) to digest the bitumen and reduce the density (i.e. API gravity) of the bitumen. The first solvent (128) may be mixed with the lean bitumen froth (114) in the second mixer (130). The first solvent (128) may be a hydrocarbon solvent. The first solvent (128) may comprise one or more of the following: an n-paraffin, an iso-paraffin, a cyclic-paraffin, an olefin, and an aromatic hydrocarbon. The solvent may have a bromine number of less than 10 to stay within pipeline specification limits for the bromine number. The solvent may comprise natural gas liquid, light naphtha, or a blend of natural gas liquid and light naphtha. The solvent may comprise a C1-C6 hydrocarbon liquid. The solvent may be one that precipitates asphaltenes in order to assist fines recovery.
[0044] The first solvent (128) mixed with the lean bitumen froth (114) may be used in a weight fraction of 0.1 to 0.3 based on lean bitumen froth weight, 0.15 to 0.25 based on lean bitumen froth weight, or any number between or inclusive of these ranges. The amount of first solvent will depend on several factors including, but not limited to, oil sands grade and solvent composition. In particular, lower grade oil sands will require more solvent and/or a more effective first solvent, than will higher grade oil sands.
[0045] Bitumen extract (132) may be separated in a separator (134) from tailings (136). The bitumen extract (132) may be separated after the first solvent (128) is mixed with the lean bitumen froth (114). The bitumen extract (132) may be sent to product cleaning (138) to remove water and fines (140) after being separated from the tailings (136). The bitumen extract (132) may be sent to product cleaning (138) to remove water and fines (14) by using a second solvent (128) to produce a cleaned bitumen extract (142).
[0046] The second solvent (128) may comprise the same solvent as the first solvent (128). The second solvent (128) may come from the same source as the first solvent (128).
[0047]
Product cleaning (138) may be, for instance, paraffinic froth treatment, an electric treater process, or another process capable of producing a marketable bitumen product. Cleaned bitumen extract (142) may exit the product cleaning (138).
The cleaned bitumen extract (142) may have less than 300 ppm of fines, or any number between or inclusive of this range.
The product cleaning (138) may be any suitable cleaner. For example, the product cleaning (138) may be an electric treater or a froth treatment process.
[0048]
The cleaned bitumen extract (142) may undergo solvent recovery (144) to remove the first solvent (128) and the second solvent (128) as recovered solvent (128). Once the first solvent (128) and the second solvent (128) are removed, a bitumen product (146) may be produced. The bitumen product (146) may be suitable for pipeline transportation. The bitumen product (146) may have a fines content of less than 300 ppm. The recovered solvent (128) may be recycled back into the process. For example, the recovered solvent (128) may be recycled to enter the second mixer (130) and/or the product cleaning (138).
[0049]
Some amount of the first solvent (128) and the second solvent (128) may be retained in the bitumen product (146) in order to meet API gravity and viscosity specifications for crude transportation. In such a case, fresh solvent (not shown) may be required. The fresh solvent may be from a different source than the first solvent and the second solvent.
[0050]
The tailings (136) and fines and water (140) may be concentrated to produce thickened tailings with a solids content of approximately 50%, or 40-60%, or any number between or inclusive of these ranges. The thickened tailings may then be transported through a pipeline to a designated tailings area.
[0051] As shown in Figure 2, the lean bitumen froth may be deaerated in the ore preparation plant. The first solvent can then be injected into the hydrotransport pipeline, for instance at the front end of the hydrotransport pipeline, to digest bitumen droplets in the transportation process without the need for an additional mixing vessel at the central processing plant to achieve the bitumen mixing and digestion objective. The first solvent may also or alternatively be injected into the hydrotransport pipeline downstream of the front end and upstream of the back end.
=
[0052] As shown in Figure 2, and using like numbers as Figure 1, at an ore preparation plant (200), a slurry of oil sands (202), water (206), and a dispersant (208) may be mixed in a first mixer (204). Following sufficient mixing, the resultant slurry (210) may be fed into a separator (212) producing lean bitumen froth (214) and a solids stream (216). In addition to the mixing (204) at the first mixer and separation (212) at the separator, at the ore preparation plant (200), the lean bitumen froth (214) may be deaerated (226) using steam (224) then transported through a hydrotransport pipeline (220), together with a first solvent (228), to a central processing plant (222). The first solvent (228) may be added to the lean bitumen froth (214) in the pipeline (220) or before the lean bitumen froth is introduced into the pipeline.
[0053] Subsequent processing may be similar to Figure 1. In particular, bitumen extract (232) may be separated (234) from tailings (236) and sent to product cleaning (238) to remove water and fines (240), for instance using a second solvent (228), producing a cleaned bitumen extract (242). The cleaned bitumen extract (242) may undergo solvent recovery (244) to remove the first solvent (228) and the second solvent and produce a bitumen product (246) which may be suitable for pipeline transportation.
[0054] Production of the lean bitumen froth may be achieved in numerous ways, for instance using a commercially available attrition scrubber and pump box.
[0055] Figure 3 shows a two-stage scheme with an attrition scrubber (302) and a hydrocyclone (304) in a first stage. Oil sands (306) and water (308) (comprising a dispersant) may be passed through the attrition scrubber (302) and then into the hydrocyclone (304).
[0056] The hydrocyclone (304) may produce a first bottom stream (310). The first bottom stream (310) may be further diluted with water (312) and fed into a pump box (314) to aid mixing. After the pump box (314), the stream (310) may be fed into a hydrocyclone (316) to reject a second bottom stream (318) comprising coarse sands. First and second lean bitumen froths (320 and 322) from the first and second stages may be combined as the lean bitumen froth.
. .
. .
[0057] Instead of a pump box and hydrocyclones, a gravity based compact separator may be used downstream of an attrition scrubber. As seen in Figure 4, a slurry of oil sands (406) and water (408) (comprising a dispersant) may be passed through an attrition scrubber (402). Then, the slurry may be fed into a compact separator (410) with dilution water (412) injected at a bottom section of the compact separator (410). The compact separator (410) produces the lean bitumen froth (414) and a solids stream (416) comprising coarse sands. The process of Figure 4 is expected to achieve similar efficiency as Figure 3. The residence time in the compact separator may be less than 3 minutes.
[0058] Other means of breaking down lumps of oil sands and providing high shear mixing with water may be used.
[0059] EXAMPLES
[0060] A jacketed glass reactor from Parr Instruments (Moline, Illinois, United States) having an internal volume of one liter was used. It had a solid stirring shaft with two impellers (2 inch diameter). Oil sands and water, comprising a designated amount of salts and dispersant, were charged to the Parr cell. A circulating water bath heater was connected to the jacket of the Parr cell to heat up the internal slurry to the target temperature. Parr cell operation was carried out at atmospheric pressure. The mixture of oil sands and water occupied approximately 2/3 of the cell volume, the top empty space in the Parr cell being exposed to air. Even without air injection to the Parr cell, lean bitumen froth was produced due to natural air entrainment during mixing. After bitumen extraction was completed, the Parr cell was disassembled and froth and middling were collected. Coarse sands were dried in the fume hood for several days and a Dean Stark analysis was performed to determine residual bitumen content. Bitumen recovery (bitumen recovered in lean bitumen froth) was calculated based on weight and residual bitumen content of dried coarse sands.
[0061] Feed Oil Sands [0062] Several grades of crushed oil sands were homogenized into a large batch for all experimental work. Analyses showed the homogenized oil sands with 12.3%
(percent) bitumen, 2.9% water, and 84.8% solids. The solids contained 12% fines with particle size of =
less than44 urn. Approximately half of the fines were clays consisting of kaolinite, illite/mica, and illite/smectite.
[0063] In these examples, 400 grams of oil sands were charged to a Parr cell Salts and dispersant concentrations were measured on a ppm (parts per million) of oil sands weight.
Both salt components and dispersant were dissolved in water before being added to the Parr cell. After a designated amount of water, salts, and dispersant were added, these components were manually mixed with oil sands before assembly of the Parr cell. After assembly, the circulating heated water in the jacket of Parr cell brought the slurry to the target temperature.
The stirrer was then turned on and gradually brought to the speed of 1,000 rpm (revolutions per minute). A timer was used to control the mixing time period. After the target mixing time was reached, the stirrer was gradually turned off to allow coarse sands to settle. Coarse sands settling was quite rapid, and was usually completed within 1 minute. Then, the Parr cell was disassembled and froth and middling were collected. Additional designated amounts of water, salts, and dispersant were charged to the Parr cell. After assembly of Parr cell, bitumen extraction of coarse sands from first stage was repeated using the same procedure as in the first stage. After the second-stage extraction and removal of froth and middling, coarse sands were collected in a steel pan and dried in a fume hood for several days. The quantity of dried coarse sands was recorded and duplicated Dean Stark analyses were carried out.
Bitumen recovery (bitumen recovered in both froth and middling) was calculated based on the original bitumen in the feed oil sands and the residual bitumen in the dried coarse sands.
[0064] Salts and Dispersants [0065] A broad range of salt concentration in water was tested to examine the effectiveness of the extraction using various sources of water. Three components were mixed to mimic salts in process water for oil sands extraction. They were sodium chloride (NaC1), sodium sulfate (Na2SO4), and calcium chloride (CaC12).
[0066] To mimic extraction using river water and recycle water as sources a salt compositional blend of 52% sodium chloride, 32% sodium sulfate, and 16%
calcium chloride was used. The same salt compositional blend was extended to very high salts, up to 10,000 ppm (1 weight percent) of ore basis, to mimic brackish water. To mimic subsurface basal water, the salt compositional blend was 88% sodium chloride, 8% sodium sulfate, and 4%
calcium chloride.
[0067] Two types of dispersants were used, sodium silicate (Na2SiO3) and sodium hydroxide (NaOH).
[0068] Example Series 1 [0069] In this series of Parr cell extraction work, a salt compositional blend of 52%
sodium chloride, 32% sodium sulfate, and 16% calcium chloride was used. The total amount of salts used for both extraction stages was kept constant at 500 ppm on an ore basis. The total amount of water to oil sands (ore) ratio was kept constant at 1:1. Sixty percent of the total water was used in a first stage extraction; the rest (40%) was used in a second stage extraction. Sodium silicate was used as a dispersant and the total amount for both extraction stages was 200 ppm, proportionally distributed (60/40) between first and second stages.
[0070] The extraction residence time for each stage was 3 minutes under a stirrer agitation speed of 1000 rpm. Extraction temperature was the main process parameter in this series. Experimental data are plotted in Figure 5.
[0071] As shown in Figure 5, bitumen recovery decreased with a decrease in extraction temperature, from 55 to 45 C. When extraction temperature was above 50 C, bitumen recovery was greater than 90% for the two-stage extraction process.
[0072] Example Series 2 [0073] In this series of Parr cell tests, extraction temperature was kept constant at 55 C. On ore basis, the total amount of salts in water was 500 ppm and the total amount of water used was 1:1. Both water and salts were distributed 60/40 for the two-stage extraction work as in example series 1. The main process variable in this series was dispersant concentration, on ore basis. Sodium silicate was used as a dispersant and it was proportionally distributed (60/40) between the first and second stages.
[0074] As shown in Figure 6, sodium silicate had a very significant impact on bitumen recovery when the dispersant concentration was less than 200 ppm. With 500 ppm salts in the slurry, a sodium silicate concentration of 100 ppm was necessary to reduce slurry viscosity in order to achieve bitumen recovery of greater than 90%. At greater than 200 ppm sodium silicate concentration, its impact on bitumen recovery was relatively small.
At a sodium silicate concentration of 200 ppm and above, bitumen recovery was approximately 95%.
[0075] Example Series 3 [0076] The potential of using brackish water for oil sands extraction was tested with various salt concentrations up to 5000 ppm. This series was carried out in similar fashion as example series 1 and 2, at 55 C and with 3 minutes extraction for each of the two stages. For the two-stage extraction work, water, salts, and sodium silicate were proportionally distributed between the stages. For a WOR (water to ore ratio) of 1.0, the distribution ratio was 60/40. For a WOR of 1.2, the distribution ratio was 67/33 A salt compositional blend of 52% sodium chloride, 32% sodium sulfate, and 16% calcium chloride was used for this series.
The water comprised 5000 ppm salts comprising 381 ppm Ca, 2,038 ppm Nat, 2,761 ppm Cl-, and 1,431 ppm S042-.
[0077] The results are shown in Figure 7. As seen in Figure 7, bitumen recovery (approximately 95%) was relatively flat over a broad range of salt concentrations up to 5000 ppm when water/ore and salts/sodium silicate ratios were kept constant at 1.0 and 2.5, respectively. When the use of sodium silicate was reduced (salts/sodium silicate ratio of 4.0) along with increased use of total water for extraction (WOR of 1.2), bitumen recovery slightly reduced to approximately 92% but held the constant level within the salt level tested.
[0078] The data illustrated in Figure 7 showed that brackish water with high salts could be used in the extraction process to achieve high bitumen recovery from oil sands.
[0079] Example Series 4 [0080] Subsurface basal water has a very high salts content, mostly single-valent ions such as Na + and Cl- and much less divalent ions such as Ca++ and S042-. In this series, a salt compositional blend of 88% sodium chloride, 8% sodium sulfate, and 4% calcium chloride was used for total salts (on oil sands basis) of up to 10000 ppm. This single-valent blend is represented by solid (grey) diamond-shaped data points in Figure 8 and comprised 162 ppm = =
+, 4,185 ppm Nat, 6,291 ppm CY, and 609 ppm S042-. The salts to sodium silicate content was 2.5 and the WOR was 1Ø
[0081] Also, a compositional blend of 52% sodium chloride, 32% sodium sulfate, and 16% calcium chloride was tested to examine the impact of a large amount of divalent ions on bitumen recovery. This divalent blend is represented by solid (grey) square-shaped data points in Figure 8 and comprised 754 ppm Ca, 4,044 ppm Nat, 5,474 ppm Cl", and 2,840 ppm S042-. The salts to sodium silicate content was 2.5 and the WOR was 1Ø
[0082] These same two blends were used with a WOR of 1.2, and the same salts to sodium silicate content of 2.5. The data points are illustrated by empty (white) diamonds and squares in Figure 8.
[0083] The Parr extraction conditions were similar to example series 3.
As shown in Figure 8, the lower divalent ions of basal-like water had little impact on bitumen recovery (solid line with recovery of approximately 95%) with salts up to 10,000 ppm.
However, the high divalent ions salty water resulted in lower bitumen separation (dashed line) from the slurry under similar extraction conditions. Higher water and dispersant uses may improve bitumen recovery at conditions of high salts and divalent ions.
[0084] Example Series 5 [0085] From an economic standpoint, it would be desirable to lower the amount of dispersant used for extraction of bitumen from oil sands using subsurface basal water. In this series of Parr extraction tests, basal-like water (10,000 ppm salts on ore basis) with low divalent ions (88% sodium chloride, 8% sodium sulfate, and 4% calcium chloride) was used.
The water comprised 10,000 ppm salts comprising 162 ppm Ca, 4,185 ppm Nat, 6,291 ppm and 609 ppm S042-. Similar to example series' 2, 3, and 4, two-stage extractions were carried out in a Parr cell at 55 C with a residence time of 3 minutes for each stage. WOR was kept constant at 1.0 (60/40 proportionally for each stage) except for the one at lowest dispersant concentration, in which WOR was higher at 1.2. Sodium silicate was the dispersant for these tests.
=
[00861 As shown in Figure 9, bitumen recovery of approximately 93% was achieved even with sodium silicate use being reduced to a 2,000 ppm level. Below the 2,000 ppm level of sodium silicate, bitumen separation was less in the dense slurry. As a result, total water use was increased (WOR of 1.2) in order to achieve clear bitumen separation and maintain similar recovery.
[00871 Example Series 6 [0088] The effectiveness of sodium silicate (Na2SiO3) as a dispersant was compared to sodium hydroxide (NaOH) which is used in commercial oil sands processing. This series was carried out in similar fashion as example series 1 and 2, at 55 C and with 3 minutes extraction for each of the two stages. For the two-stage extraction work, water, salts, and dispersants were proportionally distributed (67% in the first stage and 33% in the second stage) between the stages. Water to ore ratios (WOR) of 0.9 and 1.0 were used for two sets of comparison.
Salts content in the water was 375 ppm and dispersant content in the water was 200 ppm, both concentrations were based on weight of oil sands.
10089] In the first set of comparison with WOR of 0.9, bitumen recovery was 94.9%
when sodium silicate was used as the dispersant. Bitumen recovery was lower, 91.2%, when NaOH was used as the dispersant. In the second set of comparison with WOR of 1.0, bitumen recovery was 94.7% when sodium silicate was used as the dispersant. Bitumen recovery was slightly lower, 92.8%, when NaOH was used as the dispersant. These two sets of comparison illustrated that both sodium silicate and sodium hydroxide are effective dispersants to achieve high bitumen recovery (e.g. greater than 90% recovery) and quick separation of coarse sands from the slurry. Sodium silicate may have slight advantage in effectiveness at the same concentration than sodium hydroxide.
100901 The examples above demonstrate the effectiveness of the process to achieve good bitumen recover, for instance greater than 90% bitumen recovery, by using an adequate amount of water and dispersant to reduce the impact of salts in the process water. A high salt tolerance allows flexibility of using river water, brackish water, subsurface basal water, or blending of various water sources for oil sands processing.
[0091] In addition, in this extraction, bitumen recovery is relatively insensitive to fines and clays. This may simplify the necessary mining process and the tailings management.
[0092] The scope of the claims should not be limited by particular embodiments set forth herein, but should be construed in a manner consistent with the specification as a whole.
It is contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.
[0093] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.
. .
that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.
100231 At the outset, for ease of reference, certain terms used in this application and their meaning as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.
[0024] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. However, the techniques described are not limited to heavy oils but may also be used with any number of other reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.
[0025] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range in excess of 7 wt. %).
In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can =
vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.
[0026] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluid by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.
[0027] Fines are generally defined as those solids having a size of less than about 44 micrometer ( m).
[0028] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
[0029] As described above, mined crushed oil sands are commonly treated with water and caustic, passed through a hydrotransport pipeline with air injection to attach air to the bitumen, separated from solids and water using primary and secondary flotation vessels, and treated with solvent to produce bitumen. In conventional processes, bitumen to air attachment = =
is considered a necessary bitumen extraction mechanism in the pipeline and in subsequent primary and secondary separation. Disadvantages of bitumen to air attachment are described above.
[0030] The process of the present disclosure is not dependent on bitumen to air attachment (i.e., air attachment).
[0031] Generally, the present disclosure relates to a process for processing oil sands comprising: a) providing a slurry of oil sands, water, and a dispersant for reducing slurry viscosity to assist separation of solids from the slurry; b) breaking down lumps of the oil sands and effecting shear mixing, of the oil sands by the water, by mixing the slurry; c) producing a solids stream and a lean bitumen froth comprising bitumen after breaking down the lumps and effecting the shear mixing; d) passing the lean bitumen froth through a hydrotransport pipeline without the need for air injection; and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d). The process is not dependent on air attachment.
[0032] Because the bitumen extraction described herein is not dependent on air attachment, bitumen recovery may be less sensitive to fines and clays content in the oil sands.
[0033] Because the bitumen extraction described herein may be less strict on process water quality in terms of salts and fines content, due to the addition of water and a dispersant and the use of shear mixing, recycle water management may be simplified.
[0034] Figure 1 [0035] As shown in Figure 1, at an ore preparation plant (100), a slurry of oil sands (102), water (106), and a dispersant (108) are mixed in a first mixer (104).
The slurry of oil sands (i.e., slurry) may be crushed, mined oil sands from a mined oil sands project. The slurry of oil sands may also be from production wells of a subsurface project that produces an oil sands and water slurry.
[0036] The dispersant may be used to reduce the viscosity of the slurry of oil sands to assist separation of solids from the slurry of oil sands. The dispersant may be, for instance, Na2SiO3 or NaOH where Na stands for sodium, Si stands for silicon, 0 stands for oxygen and H stands for hydrogen. The dosage of dispersant may be significantly smaller than caustic usage in commercial water based extraction processes. The dispersant may be added in an amount of, for instance, 100 to 400 ppm, or 100 to 300 ppm, based on oil sands weight, or any number between or inclusive of these ranges. Other suitable dispersants may include sodium citrate (Na3C6H507), ammonium hydroxide (NH4OH) or other chemicals that are capable of reducing carrier fluid viscosity to achieve the objectives of dispersing fines and clays in the slurry of oil sands, thereby allowing coarse sands to be separated from the slurry of oil sands.
C stands for carbon and N stands for nitrogen.
[0037] A ratio of, for instance, less than 1.2, between 0.6 and 1.2, or between 0.7 and 1.1 water, to 1.0 oil sands may be used, on a weight basis, or any number between or inclusive of these ranges. The water temperature should be high enough to provide a desired level of bitumen extraction and may be, for instance, between 40 C and 80 C, or any number between or inclusive of these ranges. C stands for degrees Celsius.
[0038] The water may have a relatively high salt content. Depending on such factors as, desired bitumen recovery, water to ore ratio (WOR), composition and amount of dispersant used, water with salt contents of up to 5,000 ppm (parts per million), up to 8,000 ppm, up to 10,000 ppm, or above 10,000 ppm may be used, or any number between or inclusive of these ranges. The ratio of dispersant to salts in the water may be at least at least 1:10, on a weight basis. The water may comprise at least one of brackish water, subsurface basal water, and river water. The water may have 200 ppm to 15,000 ppm salts, 100 and 10,000 ppm, 1000 and 10000ppm, 500 to 10,000 ppm salts, or any number between or inclusive of these ranges.
[0039] The first mixer (104) effects shear mixing of the oil sands by the water. The first mixer (104) breaks down lumps of the oil sands, to reduce bitumen loss in the solids stream (116). The lumps of oil sands may be broken down to, for instance, a d90 of less than 4 inches, or a d90 of less than 2 inches, or any number between or inclusive of these ranges.
Examples of the first mixer (104) are described below with reference to Figures 3 and 4.
Conventionally, lumps of oils sands have not been broken down to this extent, presumably because those in the art did not believe that the additional cost needed to break down the lumps provided sufficient benefit. As described herein, the benefit is not having to rely on air attachment.
[0040] Following mixing by the first mixer (104), the resultant slurry (110) may be fed into a separator (112). The separator (112) produces a lean bitumen froth (114) and a solids stream (116). The solids stream may have a bitumen content of less than 1.0 wt. % on a dry basis. The lean bitumen froth may comprise, for instance, 10-20% bitumen, 10-15% fines, 1-5% coarse sands, and 65-79% of water, all on a weight basis, or any number between or inclusive of these ranges. Bitumen droplets around sand grains are quickly released into the resultant slurry (110) when lump sizes of oil sands are reduced during the mixing. Coarse sands may be rapidly settled in the separator (112) (e.g. in a residence time of less than 3 minutes), when a sufficient amount of water, such as described in paragraphs [0036] and [0038] of the application, and dispersant are used. The lean bitumen froth (114) may comprise greater than 90% of the original bitumen in the oil sands. The solids stream (116) may be close to mining areas and may be landfilled by trucks, conveyer belts, or tailings pipeline.
[0041] The lean bitumen froth (114) may be transported through a hydrotransport pipeline (120), to a central processing plant (122). Because a limited quantity of coarse sands is presented in the lean bitumen froth (114), pipeline erosion may be reduced.
The hydrotransport pipeline may be able to operate longer before maintenance. In addition, air compression and feeding systems, used in conventional hydrotransport, may not be required, which may also reduce pipeline erosion. Air injection is not required since the bitumen extraction does not rely on bitumen to air attachment. The process may be carried out in the substantial absence of air injection for bitumen extraction, such that less than 10% of bitumen extraction is by air attachment. Air injection refers to the purposeful addition of air to the process and excludes the natural addition of air to the process. The natural addition of air occurs because the container where bitumen is extracted is open to the environment and is not within a vacuum. The process may be carried out in the substantial absence of air injection for bitumen extraction because the lumps of oil sands are broken down as discussed above. If the lumps of oil sands were not broken down as discussed above, it would not be possible to carry out the process in the substantial absence of air injection for bitumen extraction.
= =
[0042] Following hydrotransport, steam (124) may be used to deaerate (126) the lean bitumen froth (114). The lean bitumen froth (114) is deaerated from the natural addition of air entrained due to mixing the oil sands (102), water (106) and dispersant (108) in the first mixer (104) in the ore preparation plant (100).
[0043] Following dearation, a first solvent (128) may be added to a second mixer (130) to digest the bitumen and reduce the density (i.e. API gravity) of the bitumen. The first solvent (128) may be mixed with the lean bitumen froth (114) in the second mixer (130). The first solvent (128) may be a hydrocarbon solvent. The first solvent (128) may comprise one or more of the following: an n-paraffin, an iso-paraffin, a cyclic-paraffin, an olefin, and an aromatic hydrocarbon. The solvent may have a bromine number of less than 10 to stay within pipeline specification limits for the bromine number. The solvent may comprise natural gas liquid, light naphtha, or a blend of natural gas liquid and light naphtha. The solvent may comprise a C1-C6 hydrocarbon liquid. The solvent may be one that precipitates asphaltenes in order to assist fines recovery.
[0044] The first solvent (128) mixed with the lean bitumen froth (114) may be used in a weight fraction of 0.1 to 0.3 based on lean bitumen froth weight, 0.15 to 0.25 based on lean bitumen froth weight, or any number between or inclusive of these ranges. The amount of first solvent will depend on several factors including, but not limited to, oil sands grade and solvent composition. In particular, lower grade oil sands will require more solvent and/or a more effective first solvent, than will higher grade oil sands.
[0045] Bitumen extract (132) may be separated in a separator (134) from tailings (136). The bitumen extract (132) may be separated after the first solvent (128) is mixed with the lean bitumen froth (114). The bitumen extract (132) may be sent to product cleaning (138) to remove water and fines (140) after being separated from the tailings (136). The bitumen extract (132) may be sent to product cleaning (138) to remove water and fines (14) by using a second solvent (128) to produce a cleaned bitumen extract (142).
[0046] The second solvent (128) may comprise the same solvent as the first solvent (128). The second solvent (128) may come from the same source as the first solvent (128).
[0047]
Product cleaning (138) may be, for instance, paraffinic froth treatment, an electric treater process, or another process capable of producing a marketable bitumen product. Cleaned bitumen extract (142) may exit the product cleaning (138).
The cleaned bitumen extract (142) may have less than 300 ppm of fines, or any number between or inclusive of this range.
The product cleaning (138) may be any suitable cleaner. For example, the product cleaning (138) may be an electric treater or a froth treatment process.
[0048]
The cleaned bitumen extract (142) may undergo solvent recovery (144) to remove the first solvent (128) and the second solvent (128) as recovered solvent (128). Once the first solvent (128) and the second solvent (128) are removed, a bitumen product (146) may be produced. The bitumen product (146) may be suitable for pipeline transportation. The bitumen product (146) may have a fines content of less than 300 ppm. The recovered solvent (128) may be recycled back into the process. For example, the recovered solvent (128) may be recycled to enter the second mixer (130) and/or the product cleaning (138).
[0049]
Some amount of the first solvent (128) and the second solvent (128) may be retained in the bitumen product (146) in order to meet API gravity and viscosity specifications for crude transportation. In such a case, fresh solvent (not shown) may be required. The fresh solvent may be from a different source than the first solvent and the second solvent.
[0050]
The tailings (136) and fines and water (140) may be concentrated to produce thickened tailings with a solids content of approximately 50%, or 40-60%, or any number between or inclusive of these ranges. The thickened tailings may then be transported through a pipeline to a designated tailings area.
[0051] As shown in Figure 2, the lean bitumen froth may be deaerated in the ore preparation plant. The first solvent can then be injected into the hydrotransport pipeline, for instance at the front end of the hydrotransport pipeline, to digest bitumen droplets in the transportation process without the need for an additional mixing vessel at the central processing plant to achieve the bitumen mixing and digestion objective. The first solvent may also or alternatively be injected into the hydrotransport pipeline downstream of the front end and upstream of the back end.
=
[0052] As shown in Figure 2, and using like numbers as Figure 1, at an ore preparation plant (200), a slurry of oil sands (202), water (206), and a dispersant (208) may be mixed in a first mixer (204). Following sufficient mixing, the resultant slurry (210) may be fed into a separator (212) producing lean bitumen froth (214) and a solids stream (216). In addition to the mixing (204) at the first mixer and separation (212) at the separator, at the ore preparation plant (200), the lean bitumen froth (214) may be deaerated (226) using steam (224) then transported through a hydrotransport pipeline (220), together with a first solvent (228), to a central processing plant (222). The first solvent (228) may be added to the lean bitumen froth (214) in the pipeline (220) or before the lean bitumen froth is introduced into the pipeline.
[0053] Subsequent processing may be similar to Figure 1. In particular, bitumen extract (232) may be separated (234) from tailings (236) and sent to product cleaning (238) to remove water and fines (240), for instance using a second solvent (228), producing a cleaned bitumen extract (242). The cleaned bitumen extract (242) may undergo solvent recovery (244) to remove the first solvent (228) and the second solvent and produce a bitumen product (246) which may be suitable for pipeline transportation.
[0054] Production of the lean bitumen froth may be achieved in numerous ways, for instance using a commercially available attrition scrubber and pump box.
[0055] Figure 3 shows a two-stage scheme with an attrition scrubber (302) and a hydrocyclone (304) in a first stage. Oil sands (306) and water (308) (comprising a dispersant) may be passed through the attrition scrubber (302) and then into the hydrocyclone (304).
[0056] The hydrocyclone (304) may produce a first bottom stream (310). The first bottom stream (310) may be further diluted with water (312) and fed into a pump box (314) to aid mixing. After the pump box (314), the stream (310) may be fed into a hydrocyclone (316) to reject a second bottom stream (318) comprising coarse sands. First and second lean bitumen froths (320 and 322) from the first and second stages may be combined as the lean bitumen froth.
. .
. .
[0057] Instead of a pump box and hydrocyclones, a gravity based compact separator may be used downstream of an attrition scrubber. As seen in Figure 4, a slurry of oil sands (406) and water (408) (comprising a dispersant) may be passed through an attrition scrubber (402). Then, the slurry may be fed into a compact separator (410) with dilution water (412) injected at a bottom section of the compact separator (410). The compact separator (410) produces the lean bitumen froth (414) and a solids stream (416) comprising coarse sands. The process of Figure 4 is expected to achieve similar efficiency as Figure 3. The residence time in the compact separator may be less than 3 minutes.
[0058] Other means of breaking down lumps of oil sands and providing high shear mixing with water may be used.
[0059] EXAMPLES
[0060] A jacketed glass reactor from Parr Instruments (Moline, Illinois, United States) having an internal volume of one liter was used. It had a solid stirring shaft with two impellers (2 inch diameter). Oil sands and water, comprising a designated amount of salts and dispersant, were charged to the Parr cell. A circulating water bath heater was connected to the jacket of the Parr cell to heat up the internal slurry to the target temperature. Parr cell operation was carried out at atmospheric pressure. The mixture of oil sands and water occupied approximately 2/3 of the cell volume, the top empty space in the Parr cell being exposed to air. Even without air injection to the Parr cell, lean bitumen froth was produced due to natural air entrainment during mixing. After bitumen extraction was completed, the Parr cell was disassembled and froth and middling were collected. Coarse sands were dried in the fume hood for several days and a Dean Stark analysis was performed to determine residual bitumen content. Bitumen recovery (bitumen recovered in lean bitumen froth) was calculated based on weight and residual bitumen content of dried coarse sands.
[0061] Feed Oil Sands [0062] Several grades of crushed oil sands were homogenized into a large batch for all experimental work. Analyses showed the homogenized oil sands with 12.3%
(percent) bitumen, 2.9% water, and 84.8% solids. The solids contained 12% fines with particle size of =
less than44 urn. Approximately half of the fines were clays consisting of kaolinite, illite/mica, and illite/smectite.
[0063] In these examples, 400 grams of oil sands were charged to a Parr cell Salts and dispersant concentrations were measured on a ppm (parts per million) of oil sands weight.
Both salt components and dispersant were dissolved in water before being added to the Parr cell. After a designated amount of water, salts, and dispersant were added, these components were manually mixed with oil sands before assembly of the Parr cell. After assembly, the circulating heated water in the jacket of Parr cell brought the slurry to the target temperature.
The stirrer was then turned on and gradually brought to the speed of 1,000 rpm (revolutions per minute). A timer was used to control the mixing time period. After the target mixing time was reached, the stirrer was gradually turned off to allow coarse sands to settle. Coarse sands settling was quite rapid, and was usually completed within 1 minute. Then, the Parr cell was disassembled and froth and middling were collected. Additional designated amounts of water, salts, and dispersant were charged to the Parr cell. After assembly of Parr cell, bitumen extraction of coarse sands from first stage was repeated using the same procedure as in the first stage. After the second-stage extraction and removal of froth and middling, coarse sands were collected in a steel pan and dried in a fume hood for several days. The quantity of dried coarse sands was recorded and duplicated Dean Stark analyses were carried out.
Bitumen recovery (bitumen recovered in both froth and middling) was calculated based on the original bitumen in the feed oil sands and the residual bitumen in the dried coarse sands.
[0064] Salts and Dispersants [0065] A broad range of salt concentration in water was tested to examine the effectiveness of the extraction using various sources of water. Three components were mixed to mimic salts in process water for oil sands extraction. They were sodium chloride (NaC1), sodium sulfate (Na2SO4), and calcium chloride (CaC12).
[0066] To mimic extraction using river water and recycle water as sources a salt compositional blend of 52% sodium chloride, 32% sodium sulfate, and 16%
calcium chloride was used. The same salt compositional blend was extended to very high salts, up to 10,000 ppm (1 weight percent) of ore basis, to mimic brackish water. To mimic subsurface basal water, the salt compositional blend was 88% sodium chloride, 8% sodium sulfate, and 4%
calcium chloride.
[0067] Two types of dispersants were used, sodium silicate (Na2SiO3) and sodium hydroxide (NaOH).
[0068] Example Series 1 [0069] In this series of Parr cell extraction work, a salt compositional blend of 52%
sodium chloride, 32% sodium sulfate, and 16% calcium chloride was used. The total amount of salts used for both extraction stages was kept constant at 500 ppm on an ore basis. The total amount of water to oil sands (ore) ratio was kept constant at 1:1. Sixty percent of the total water was used in a first stage extraction; the rest (40%) was used in a second stage extraction. Sodium silicate was used as a dispersant and the total amount for both extraction stages was 200 ppm, proportionally distributed (60/40) between first and second stages.
[0070] The extraction residence time for each stage was 3 minutes under a stirrer agitation speed of 1000 rpm. Extraction temperature was the main process parameter in this series. Experimental data are plotted in Figure 5.
[0071] As shown in Figure 5, bitumen recovery decreased with a decrease in extraction temperature, from 55 to 45 C. When extraction temperature was above 50 C, bitumen recovery was greater than 90% for the two-stage extraction process.
[0072] Example Series 2 [0073] In this series of Parr cell tests, extraction temperature was kept constant at 55 C. On ore basis, the total amount of salts in water was 500 ppm and the total amount of water used was 1:1. Both water and salts were distributed 60/40 for the two-stage extraction work as in example series 1. The main process variable in this series was dispersant concentration, on ore basis. Sodium silicate was used as a dispersant and it was proportionally distributed (60/40) between the first and second stages.
[0074] As shown in Figure 6, sodium silicate had a very significant impact on bitumen recovery when the dispersant concentration was less than 200 ppm. With 500 ppm salts in the slurry, a sodium silicate concentration of 100 ppm was necessary to reduce slurry viscosity in order to achieve bitumen recovery of greater than 90%. At greater than 200 ppm sodium silicate concentration, its impact on bitumen recovery was relatively small.
At a sodium silicate concentration of 200 ppm and above, bitumen recovery was approximately 95%.
[0075] Example Series 3 [0076] The potential of using brackish water for oil sands extraction was tested with various salt concentrations up to 5000 ppm. This series was carried out in similar fashion as example series 1 and 2, at 55 C and with 3 minutes extraction for each of the two stages. For the two-stage extraction work, water, salts, and sodium silicate were proportionally distributed between the stages. For a WOR (water to ore ratio) of 1.0, the distribution ratio was 60/40. For a WOR of 1.2, the distribution ratio was 67/33 A salt compositional blend of 52% sodium chloride, 32% sodium sulfate, and 16% calcium chloride was used for this series.
The water comprised 5000 ppm salts comprising 381 ppm Ca, 2,038 ppm Nat, 2,761 ppm Cl-, and 1,431 ppm S042-.
[0077] The results are shown in Figure 7. As seen in Figure 7, bitumen recovery (approximately 95%) was relatively flat over a broad range of salt concentrations up to 5000 ppm when water/ore and salts/sodium silicate ratios were kept constant at 1.0 and 2.5, respectively. When the use of sodium silicate was reduced (salts/sodium silicate ratio of 4.0) along with increased use of total water for extraction (WOR of 1.2), bitumen recovery slightly reduced to approximately 92% but held the constant level within the salt level tested.
[0078] The data illustrated in Figure 7 showed that brackish water with high salts could be used in the extraction process to achieve high bitumen recovery from oil sands.
[0079] Example Series 4 [0080] Subsurface basal water has a very high salts content, mostly single-valent ions such as Na + and Cl- and much less divalent ions such as Ca++ and S042-. In this series, a salt compositional blend of 88% sodium chloride, 8% sodium sulfate, and 4% calcium chloride was used for total salts (on oil sands basis) of up to 10000 ppm. This single-valent blend is represented by solid (grey) diamond-shaped data points in Figure 8 and comprised 162 ppm = =
+, 4,185 ppm Nat, 6,291 ppm CY, and 609 ppm S042-. The salts to sodium silicate content was 2.5 and the WOR was 1Ø
[0081] Also, a compositional blend of 52% sodium chloride, 32% sodium sulfate, and 16% calcium chloride was tested to examine the impact of a large amount of divalent ions on bitumen recovery. This divalent blend is represented by solid (grey) square-shaped data points in Figure 8 and comprised 754 ppm Ca, 4,044 ppm Nat, 5,474 ppm Cl", and 2,840 ppm S042-. The salts to sodium silicate content was 2.5 and the WOR was 1Ø
[0082] These same two blends were used with a WOR of 1.2, and the same salts to sodium silicate content of 2.5. The data points are illustrated by empty (white) diamonds and squares in Figure 8.
[0083] The Parr extraction conditions were similar to example series 3.
As shown in Figure 8, the lower divalent ions of basal-like water had little impact on bitumen recovery (solid line with recovery of approximately 95%) with salts up to 10,000 ppm.
However, the high divalent ions salty water resulted in lower bitumen separation (dashed line) from the slurry under similar extraction conditions. Higher water and dispersant uses may improve bitumen recovery at conditions of high salts and divalent ions.
[0084] Example Series 5 [0085] From an economic standpoint, it would be desirable to lower the amount of dispersant used for extraction of bitumen from oil sands using subsurface basal water. In this series of Parr extraction tests, basal-like water (10,000 ppm salts on ore basis) with low divalent ions (88% sodium chloride, 8% sodium sulfate, and 4% calcium chloride) was used.
The water comprised 10,000 ppm salts comprising 162 ppm Ca, 4,185 ppm Nat, 6,291 ppm and 609 ppm S042-. Similar to example series' 2, 3, and 4, two-stage extractions were carried out in a Parr cell at 55 C with a residence time of 3 minutes for each stage. WOR was kept constant at 1.0 (60/40 proportionally for each stage) except for the one at lowest dispersant concentration, in which WOR was higher at 1.2. Sodium silicate was the dispersant for these tests.
=
[00861 As shown in Figure 9, bitumen recovery of approximately 93% was achieved even with sodium silicate use being reduced to a 2,000 ppm level. Below the 2,000 ppm level of sodium silicate, bitumen separation was less in the dense slurry. As a result, total water use was increased (WOR of 1.2) in order to achieve clear bitumen separation and maintain similar recovery.
[00871 Example Series 6 [0088] The effectiveness of sodium silicate (Na2SiO3) as a dispersant was compared to sodium hydroxide (NaOH) which is used in commercial oil sands processing. This series was carried out in similar fashion as example series 1 and 2, at 55 C and with 3 minutes extraction for each of the two stages. For the two-stage extraction work, water, salts, and dispersants were proportionally distributed (67% in the first stage and 33% in the second stage) between the stages. Water to ore ratios (WOR) of 0.9 and 1.0 were used for two sets of comparison.
Salts content in the water was 375 ppm and dispersant content in the water was 200 ppm, both concentrations were based on weight of oil sands.
10089] In the first set of comparison with WOR of 0.9, bitumen recovery was 94.9%
when sodium silicate was used as the dispersant. Bitumen recovery was lower, 91.2%, when NaOH was used as the dispersant. In the second set of comparison with WOR of 1.0, bitumen recovery was 94.7% when sodium silicate was used as the dispersant. Bitumen recovery was slightly lower, 92.8%, when NaOH was used as the dispersant. These two sets of comparison illustrated that both sodium silicate and sodium hydroxide are effective dispersants to achieve high bitumen recovery (e.g. greater than 90% recovery) and quick separation of coarse sands from the slurry. Sodium silicate may have slight advantage in effectiveness at the same concentration than sodium hydroxide.
100901 The examples above demonstrate the effectiveness of the process to achieve good bitumen recover, for instance greater than 90% bitumen recovery, by using an adequate amount of water and dispersant to reduce the impact of salts in the process water. A high salt tolerance allows flexibility of using river water, brackish water, subsurface basal water, or blending of various water sources for oil sands processing.
[0091] In addition, in this extraction, bitumen recovery is relatively insensitive to fines and clays. This may simplify the necessary mining process and the tailings management.
[0092] The scope of the claims should not be limited by particular embodiments set forth herein, but should be construed in a manner consistent with the specification as a whole.
It is contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.
[0093] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.
Claims (33)
1. A process for processing oil sands comprising:
a) providing a slurry of oil sands, water, and a dispersant for reducing slurry viscosity to assist separation of solids from the slurry;
b) breaking down lumps of the oil sands and effecting shear mixing, of the oil sands by the water, by mixing the slurry;
c) producing a solids stream and a lean bitumen froth comprising bitumen after breaking down the lumps and effecting the shear mixing;
d) passing the lean bitumen froth through a hydrotransport pipeline without a need for air injection; and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d).
a) providing a slurry of oil sands, water, and a dispersant for reducing slurry viscosity to assist separation of solids from the slurry;
b) breaking down lumps of the oil sands and effecting shear mixing, of the oil sands by the water, by mixing the slurry;
c) producing a solids stream and a lean bitumen froth comprising bitumen after breaking down the lumps and effecting the shear mixing;
d) passing the lean bitumen froth through a hydrotransport pipeline without a need for air injection; and e) using water in a weight ratio of the water to the oil sands of 1.5 or less throughout steps a) to d).
2. The process of claim 1, wherein providing the slurry comprises adding the dispersant to the slurry in an amount of 100 to 400 ppm, based on oil sands weight.
3. The process of claim 1 or 2, wherein a ratio of the dispersant to salts in the water is at least 1:10, on a weight basis.
4. The process of any one of claims 1 to 3, wherein step b) comprises breaking down the lumps of the oil sands to a d90 of less than 4 inches.
5. The process of any one of claims 1 to 3, wherein step b) comprises breaking down the lumps of the oil sands to a d90 of less than 2 inches.
6. The process of any one of claims 1 to 5, wherein the lean bitumen froth comprises 10-20% bitumen, 10-15% fines, 1-5% coarse sands, and 65-79% of water, all on a weight basis.
7. The process of any one of claims 1 to 6, wherein the water comprises between 100 and 10,000 ppm salts.
8. The process of any one of claims 1 to 6, wherein the water comprises between 1,000 and 5,000 ppm salts.
9. The process of any one of claims 1 to 8, wherein the weight ratio of the water to the oil sands is between 0.6 and 1.2.
10. The process of any one of claims 1 to 8, wherein the weight ratio of the water to the oil sands is between 0.7 and 1.1.
11. The process of any one of claims 1 to 9, wherein the lean bitumen froth comprises greater than 90 wt. % of bitumen in the oil sands.
12. The process of any one of claims 1 to 11, wherein the solids stream comprises less than 1.0 % bitumen on a dry weight basis.
13. The process of any one of claims 1 to 12, wherein step b) comprises:
passing the oil sands, the water, and the dispersant through an attrition scrubber and then through a first hydrocyclone to form a first lean bitumen froth and a first bottom stream;
passing the first bottom stream and additional water through a pump box, and then through a second hydrocyclone to form a second lean bitumen froth and the solids stream; and combining the first lean bitumen froth and the second lean bitumen froth to form the lean bitumen froth.
passing the oil sands, the water, and the dispersant through an attrition scrubber and then through a first hydrocyclone to form a first lean bitumen froth and a first bottom stream;
passing the first bottom stream and additional water through a pump box, and then through a second hydrocyclone to form a second lean bitumen froth and the solids stream; and combining the first lean bitumen froth and the second lean bitumen froth to form the lean bitumen froth.
14. The process of any one of claims 1 to 12, wherein producing the lean bitumen froth and the solids stream comprises passing the oil sands, the water, and the dispersant through an attrition scrubber, and then through a compact separator where additional water is added.
15. The process of claim 14, further comprising passing the oil sands, the water and the dispersant through the compact separator for less than 3 minutes.
16. The process of any one of claims 1 to 15, wherein the dispersant comprises one of Na2SiO3, NaOH, sodium citrate (Na3C6HSO7) and ammonium hydroxide (NH4OH)
17. The process of any one of claims 1 to 16, wherein the oil sands comprise crushed mined oil sands.
18. The process of any one of claims 1 to 17, further comprising mixing a solvent with the lean bitumen froth to digest the bitumen and reduce a density of the bitumen.
19. The process of claim 18, further comprising, prior to the solvent mixing, deaerating the lean bitumen froth using steam.
20. The process of claim 18, further comprising, after the solvent mixing, separating tailings from the lean bitumen froth to form a bitumen extract.
21. The process of claim 20, further comprising cleaning the bitumen extract by removing the water and fines to form a cleaned bitumen extract.
22. The process of claim 21, wherein the cleaned bitumen extract has less than 300 ppm of the fines.
23. The process of claim 21 or 22, wherein the cleaning comprises using an electric treater or using a froth treatment process.
24. The process of any one of claims 21 to 23, wherein the cleaning comprises mixing the bitumen extract with additional solvent.
25. The process of claim 24, further comprising recovering the solvent from the cleaned bitumen product to form a bitumen product.
26. The process of claim 25, further comprising recycling the solvent recovered from the cleaned bitumen product.
27. The process of any one of claims 18 to 26, wherein the solvent comprises at least one of an n-paraffin, an iso-paraffin, a cyclic-paraffin, an olefin, and an aromatic hydrocarbon, and wherein the solvent has a bromine number of less than 10.
28. The process of any one of claims 18 to 26, wherein the solvent comprises one of (i) natural gas liquid, (ii) light naphtha, and (iii) a blend of natural gas liquid and light naphtha.
29. The process of any one of claims 18 to 26, wherein the solvent comprises a hydrocarbon liquid.
30. The process of any one of claims 18 to 29, wherein the solvent is mixed with the lean bitumen froth in a weight fraction of 0.1 to 0.3 based on lean bitumen froth weight.
31. The process of claim 30, wherein the solvent is mixed with the lean bitumen froth in a weight fraction of 0.15 to 0.25 based on lean bitumen froth weight.
32. The process of any one of claims 1 to 31, wherein the water is at a temperature of between 40 and 80°C.
33.
The process of any one of claims 1 to 32, wherein the water comprises at least one of brackish water, subsurface basal water, and river water.
The process of any one of claims 1 to 32, wherein the water comprises at least one of brackish water, subsurface basal water, and river water.
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