WO2013019332A1 - Procédé de traitement d'une matière première bitumineuse et d'eau contaminée - Google Patents

Procédé de traitement d'une matière première bitumineuse et d'eau contaminée Download PDF

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Publication number
WO2013019332A1
WO2013019332A1 PCT/US2012/043577 US2012043577W WO2013019332A1 WO 2013019332 A1 WO2013019332 A1 WO 2013019332A1 US 2012043577 W US2012043577 W US 2012043577W WO 2013019332 A1 WO2013019332 A1 WO 2013019332A1
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Prior art keywords
water
solvent
bitumen
solids
extraction
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PCT/US2012/043577
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English (en)
Inventor
Brian C. Speirs
James A. Dunn
Fritz PIERRE
David C. Rennard
Justin D. Pace
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ExxonMobil Upstream Research Co
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ExxonMobil Upstream Research Co
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    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/26—Treatment of water, waste water, or sewage by extraction
    • 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
    • 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
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
    • C02F2103/10—Nature of the water, waste water, sewage or sludge to be treated from quarries or from mining activities
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
    • C02F2103/34—Nature of the water, waste water, sewage or sludge to be treated from industrial activities not provided for in groups C02F2103/12 - C02F2103/32
    • C02F2103/36—Nature of the water, waste water, sewage or sludge to be treated from industrial activities not provided for in groups C02F2103/12 - C02F2103/32 from the manufacture of organic compounds
    • C02F2103/365—Nature of the water, waste water, sewage or sludge to be treated from industrial activities not provided for in groups C02F2103/12 - C02F2103/32 from the manufacture of organic compounds from petrochemical industry (e.g. refineries)
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/44—Solvents

Definitions

  • the present disclosure relates generally to the field of hydrocarbon extraction from mineable deposits, such as bitumen from oil sands.
  • Oil sands are sand deposits which in addition to sand, comprise clays, connate water, and bitumen. Depending on geographic location, bitumen may be recovered by mining methods or in-situ recovery methods. These recovery methods typically require the extensive use of heat and water. Additionally, the effectiveness of these processes depends heavily on the quality of the water used.
  • thermal oil recovery processes include, but are not limited to, steam-assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), and various derivatives thereof, such as solvent-assisted SAGD (SA-SAGD), steam and gas push (SAGP), combined vapor and steam extraction (SAVEX), expanding solvent SAGD (ES- SAGD), constant steam drainage (CSD), and liquid addition to steam for enhancing recovery (LASER), as well as water flooding and steam flooding processes.
  • SAGD steam-assisted gravity drainage
  • CSS cyclic steam stimulation
  • various derivatives thereof such as solvent-assisted SAGD (SA-SAGD), steam and gas push (SAGP), combined vapor and steam extraction (SAVEX), expanding solvent SAGD (ES- SAGD), constant steam drainage (CSD), and liquid addition to steam for enhancing recovery (LASER), as well as water flooding and steam flooding processes.
  • Evaporation-based water treatment plants have been used for the water treatment of produced water from thermal oil recovery.
  • An example is described by Heins in U.S. Patent No. 6,733,636. Heins describes an elaborate process to produce high quality water suitable for the production of 100% quality steam from packaged boilers.
  • Ikebe et al. in U.S. Patent Publication No. 2010/0264068, describe a simplified water treatment process comprised of membrane-based treatment followed by evaporation-based treatment to produce high quality water suitable for steam generation. Regardless of the method of water treatment, a concentrated wastewater stream is produced that must be properly disposed of.
  • Oil sands ore in a mining and extraction operation is typically processed using mechanical and chemical techniques to separate the bitumen from the sands.
  • water-based extraction and solvent-based extraction are the two processes that have been proposed or used to extract bitumen from mined oil sands.
  • water-based extraction water is the dominant liquid in the process and the extraction occurs by having water displace the bitumen on the surface of the solids.
  • solvent-based extraction the solvent is the dominant liquid and the extraction of the bitumen occurs by dissolving bitumen into the solvent.
  • bitumen froth flotation One of the most commonly employed water-based extraction processes is bitumen froth flotation.
  • hot water, air and typically process aids are agitated with the oil sands resulting in bitumen droplets that attach to or coat air bubbles.
  • the aerated bitumen rises under gravity to form a distinct hydrocarbon phase, known as bitumen froth, which can be separated from the aqueous layer.
  • the remaining aqueous phase comprised of sand, clay, water and un-recovered bitumen, is known as tailings.
  • a typical composition of the bitumen froth stream is about 60 wt% bitumen, 30 wt% water, and 10 wt% solids.
  • the water and solids in the froth are considered as contaminants and are reduced in a froth treatment process to a level suitable for feed to an oil refinery or an upgrading facility.
  • the water-based extraction of bitumen from oil sands poses numerous challenges, particularly since a large quantity of water is needed for the extraction process. In a typical extraction process, 6 to 8 barrels of water are used in a process that produces one barrel of bitumen. In fully mature extraction facilities, about 4 to 6 of those barrels of water are recycled from the tailings. However, the recycle water usually includes more solids and dissolved salts than that of fresh water.
  • the quality of the extraction water has a significant impact on the froth flotation process.
  • the presence of fine solids and dissolved solids within the extraction water increases the tendency of the fine solids to coat the bitumen droplets.
  • the solid coating then acts to impede the air bubbles from attaching to the bitumen droplets, which reduces bitumen flotation.
  • an increased presence of fine solids and dissolved solids within the extraction water increases the viscosity of the slurry. The increase in viscosity makes it difficult for aerated bitumen to rise under gravity to form the distinct hydrocarbon phase.
  • the amount of water recovered from tailings or other methods is typically in the range of 0 to 5%. This low water recovery is somewhat insignificant in comparison to overall water usage requirements for an oil sands mining operation for bitumen recovery and thus makes very little impact on the commercial process.
  • Solvent-based extraction processes for the recovery of bitumen from mined oil sands have been proposed as an alternative to water-based extraction since, among other benefits, solvent-based extraction processes have the potential to use much less water and water of lower quality than that used by water-based extraction processes.
  • the commercial application of a solvent-based extraction process has, for various reasons, eluded the oil sands industry.
  • a major challenge to the application of solvent-based extraction to oil sands is the tendency of fine particles within the oil sands to hamper the separation of solids from the bitumen extract.
  • Solvent extraction with solids agglomeration is a technique that has been proposed to deal with this challenge.
  • the original application of this technology was coined Solvent Extraction Spherical Agglomeration (SESA).
  • SESA Solvent Extraction Spherical Agglomeration
  • the SESA process involves mixing oil sands with a hydrocarbon solvent, adding a bridging liquid to the oil sands slurry, agitating the mixture in a slow and controlled manner to nucleate particles, and continuing such agitation to permit these nucleated particles to form larger multi-particle spherical agglomerates for removal.
  • the bridging liquid is preferably water or an aqueous solution since the solids of oil sands are mostly hydrophilic and water is immiscible with hydrocarbon solvents. It has been found that the bridging liquid used in the process can be water with both a high fines and dissolved solids content. In fact, in certain embodiments of the SESA process, it may be preferable to have aqueous bridging liquid with either high fines content and/or high dissolved solid content.
  • organic material is separated from oil sands by mixing the oil sands material with an organic solvent to form a slurry, after which an aqueous bridging liquid is added in the amount of 8 to 50 wt% of the feed mixture.
  • an aqueous bridging liquid is added in the amount of 8 to 50 wt% of the feed mixture.
  • solid particles from oil sands come into contact with the aqueous bridging liquid and adhere to each other to form macro-agglomerates of a mean diameter of 2 mm or greater.
  • the formed agglomerates are more easily separated from the organic extract compared to un-agglomerated solids.
  • the organic extract free agglomerates can be sintered at high temperatures to make useful construction material.
  • halide salts such as NaCI, KCI, and CaCI 2 can be dissolved in the aqueous bridging liquid to form agglomerates that, when sintered at elevated temperatures, produce very strong aggregates.
  • the macro-agglomeration process described by Meadus et al. may be suitable for oil sands feeds comprising greater than 15 wt% fines. For oil sands with a lesser amount of fines, it was found to be beneficial to have a water and fine particle slurry as the bridging liquid.
  • U.S. Patent No. 3,984,287 (Meadus et al.) describes that middlings of a primary separation vessel of a water-based extraction process or sludge from the water- based extraction tailings ponds may be used as the bridging liquids with high fines content.
  • the present disclosure relates to a method of processing a bituminous feed and contaminated water.
  • the bituminous feed is contacted with an extraction liquor and the contaminated water to form an initial slurry.
  • the initial slurry is solvent extracted to form an extracted slurry comprising solids, contaminated water, and a bitumen extract.
  • the solids are separated from the bitumen extract.
  • Solvent is recovered from the bitumen extract to form a bitumen product.
  • High quality water and solvent are recovered from the solids.
  • the method converts contaminated water into high quality water which can be used in water-based hydrocarbon extraction or in-situ thermal hydrocarbon recovery.
  • the present disclosure provides a method of processing a bituminous feed and contaminated water, the method comprising: a) contacting the bituminous feed with an extraction liquor and the contaminated water to form an initial slurry, wherein the extraction liquor comprises a solvent; b) solvent extracting the initial slurry to extract bitumen from the bituminous feed to form an extracted slurry comprising solids, the contaminated water, and a bitumen extract; c) separating the solids and the contaminated water from the bitumen extract; d) recovering solvent from the bitumen extract to form a bitumen product; e) recovering solvent and high quality water from the solids to form dry tailings; and f) separating the high quality water from the solvent.
  • Fig. 1 is a schematic illustrating a disclosed embodiment.
  • Fig. 2 is a schematic illustrating a disclosed embodiment.
  • Fig. 3 is a schematic illustrating a disclosed embodiment.
  • Fig. 4 is a schematic illustrating a disclosed embodiment.
  • Fig. 5 is a schematic illustrating a disclosed embodiment.
  • bituminous feed refers to a stream derived from oil sands that requires downstream processing in order to realize valuable bitumen products or fractions.
  • the bituminous feed is one that comprises bitumen along with undesirable components.
  • Such a bituminous feed may be derived directly from oil sands, and may be, for example, raw oil sands ore. Further, the bituminous feed may be a feed that has already realized some initial processing but nevertheless requires further processing. Also, recycled streams that comprise bitumen in combination with other components for removal as described herein can be included in the bituminous feed.
  • a bituminous feed need not be derived directly from oil sands, but may arise from other processes.
  • a waste product from other extraction processes which comprises bitumen that would otherwise not have been recovered, may be used as a bituminous feed.
  • Such a bituminous feed may be also derived directly from oil shale oil, bearing diatomite or oil saturated sandstones.
  • the term "agglomerate” refers to conditions that produce a cluster, aggregate, collection or mass, such as nucleation, coalescence, layering, sticking, clumping, fusing and sintering, as examples.
  • the term "high quality water” means water with a solids concentration of less than 1 wt.%, preferably less than 0.5 wt.%, and with a monovalent cation concentration of less than 2000 wppm, preferably less than 1000 wppm, and more preferably less than 100 wppm.
  • Monovalent cations may include, but are not limited to sodium cations.
  • the present disclosure relates to a method of processing a bituminous feed and contaminated water.
  • the bituminous feed is contacted with an extraction liquor and the contaminated water to form an initial slurry.
  • the initial slurry is solvent extracted to form an extracted slurry comprising solids, the contaminated water, and a bitumen extract.
  • the solids are separated from the bitumen extract.
  • Solvent is recovered from the bitumen extract to form a bitumen product.
  • High quality water and solvent are recovered from the solids.
  • the method converts contaminated water into high quality water which can be used in water- based hydrocarbon extraction or in-situ thermal hydrocarbon recovery.
  • Bituminous feed is dissolved and extracted via an extraction liquor and solid-liquid separation is assisted by the presence of the contaminated water.
  • the contaminated water comprises fine solids and/or dissolved solids.
  • the amount of fine solids and/or dissolved solids within the contaminated water is of a quantity such that the contaminated water is not suitable or not preferable for use within in-situ thermal hydrocarbon recovery or water-based hydrocarbon extraction processes.
  • the contaminated water does not meet the high-quality water specifications provided above.
  • Figure 1 illustrates one embodiment. As shown in Figure 1 , bituminous feed
  • Additional contaminated water (118) may be added to the TSRU (116) in order to maintain a specified level of water within the tailings (120), and to recover heat and additional high quality water.
  • Solvent and water vapor (together 121 ) from the TSRU (116) are condensed and then separated in order to recover high quality water (122) with reduced solids and dissolved solids content and solvent (123).
  • Solvent (124) is removed from the bitumen extract (114) using a solvent recovery unit (126) in order to form a bitumen product (128).
  • Suitable solvent-based extraction processes may include any solvent-based extraction process that uses an aqueous stream in the extraction process.
  • the solvent-based extraction process be a process that is not adversely or too adversely affected by the use of an aqueous stream with a significant amount of solids and/or dissolved solids.
  • Exemplary solvent-based extraction processes include, but are not limited to, those described in the background section, those described below, and those described in Canadian Patent Application Serial No. 2,724,806 ("Adeyinka et al.”), filed December 10, 2010 and entitled “Process and Systems for Solvent Extraction of Bitumen from Oil Sands”.
  • bitumen from oil sands in a manner that employs solvent extraction with solids agglomeration is described by Adeyinka et al.
  • a solvent is combined with a bituminous feed derived from oil sands to form an initial slurry. Separation of the initial slurry into a fine solids stream and a coarse solids stream may be followed by mixing a bridging liquid with the fine solid stream and agglomeration of solids from the fine solids stream to form an agglomerated slurry.
  • the agglomerated slurry can be separated into agglomerates and a low solids bitumen extract.
  • the coarse solids stream may be reintroduced and further extracted in the agglomerated slurry.
  • a low solids bitumen extract can be separated from the agglomerated slurry for further processing.
  • the mixing of a second solvent with the low solids bitumen extract to extract bitumen may take place, forming a solvent-bitumen low solids mixture, which can then be separated further into low grade and high grade bitumen extracts. Recovery of solvent from the low grade and/or high grade extracts is conducted, to produce bitumen products of commercial value.
  • Embodiments with Solvent Extraction with Solids Agglomeration [0035]
  • One embodiment relates to a method for using a solvent extraction with solids agglomeration process for extracting bitumen from mined oil sands and recovering high quality water from contaminated water.
  • Bituminous feed is dissolved and extracted via an extraction liquor and solids are agglomerated via contact with a bridging liquid and agitation.
  • contaminated water is used herein as the bridging liquid or as part of the bridging liquid.
  • the contaminated water may be, for instance, from a water-based hydrocarbon extraction process or from an in-situ thermal hydrocarbon recovery facility.
  • the contaminated water may comprise fine solids and/or dissolved solids. The amount of fine solids and/or dissolved solids within the water is of sufficient quantity such that said contaminated water is not suitable or not preferable for use within thermal oil recovery or water-based extraction processes.
  • Figure 2 illustrates one embodiment.
  • bituminous feed (202) is mixed with extraction liquor (204) in a mixing vessel (206) to form an initial slurry (208).
  • the initial slurry (208) is passed to an agglomerator (210) where contaminated water (212) is added, forming an agglomerated slurry (214).
  • the contaminated water (212) is used as a bridging liquid to assist solids agglomeration of the slurry (208) in order to improve subsequent solid-liquid separation.
  • agglomerated solids (216) are separated from the bitumen extract (218) in a solid-liquid separator (220) and then, if required, washed with a second solvent in order to remove any residual bitumen within the solids (not shown). Solvent and water vapor (together 221 ) are then evaporated from the agglomerates (216) in a tailings solvent recovery unit (TSRU) (220) in order to form environmentally acceptable dry tailings (222). Additional contaminated water (224) may be added to the TSRU (220) in order to maintain a specified level of water within the tailings.
  • TSRU tailings solvent recovery unit
  • Solvent and water vapor (together 221 ) from the TSRU (220) are condensed and then separated in order to recover high quality water (226) with reduced solids and dissolved solids content, and solvent (227).
  • Solvent (228) is removed from the bitumen extract (218) using a solvent recovery unit (229) in order to form a bitumen product (230).
  • the bituminous feed is oil sands.
  • the oil sands feed may be contacted with extraction liquor that is free of contaminated water or other bridging liquid in a slurry system to produce a pumpable slurry.
  • the oil sands feed may be heated to evaporate connate water from the oil sands in order to recover high quality water and to minimize feed variability due to water content.
  • the slurry may be well mixed in order to dissolve the bitumen.
  • the bitumen is first extracted from the oil sands prior to agglomeration in order to prevent (or limit) the agglomeration process from hampering the dissolution of bitumen into the extraction liquor and prevent (or limit) bitumen occlusion within the agglomerate.
  • the contaminated water may be directly mixed with the oil sands before or at the same time as the extraction liquor so that bitumen extraction and agglomeration occur simultaneously.
  • the contaminated water may be added before or at the same time as the extraction liquor in order to minimize the dispersion of fines, which may reduce the solids content of the bitumen extract after the agglomeration process.
  • the contaminated water may be added before or at the same time as the extraction liquor in order to minimize the adsorption of solvent onto the surface of the solids, which may reduce the energy required for tailings solvent recovery.
  • the solvent-based extraction facility is in proximity to a water-based extraction facility such that aqueous streams can be exchanged between the extraction facilities.
  • a portion of water-based extraction streams may be pumped to the solvent-based extraction facility for use in a solvent extraction with solids agglomeration process.
  • Suitable water-based extraction streams include, but are not limited to, middlings from primary separation, secondary and tertiary separation tailings, froth treatment tailings, mature fine tailings from a tailings pond, or a new stream resulting from passing any of these streams through a thickener, hydrocyclone, or other device.
  • middlings passed through a cyclone might generate an overflow stream and an underflow stream.
  • Either stream could be used in the solvent extraction with solids agglomeration process.
  • Particularly suitable streams are water-based extraction streams having high solids and/or dissolved solids contents because they are unsuitable, as is, for use in the recovery of additional bitumen within a water-based extraction process.
  • these water-based extraction streams are directed to a solvent-based extraction process to assist in the solvent extraction of additional bitumen from mined oil sands while simultaneously undergoing water treatment by evaporation that yields a high quality water with a reduced solids and dissolved solids content.
  • the higher quality water can be directed back to the water-based extraction process to provide improved bitumen recovery.
  • Figure 3 provides a process flow diagram of an embodiment of integrating solvent-based extraction with water-based extraction in order to extract bitumen from mined oil sands and recovering high quality water from contaminated water.
  • oil sand (302) is mixed with water (304) in a mix box (306) and passed to a primary separation vessel (PSV) (308).
  • PSD primary separation vessel
  • the bitumen froth (310) is sent to paraffinic froth treatment (PFT) (312).
  • PFT paraffinic froth treatment
  • Primary separation and paraffinic froth treatment are known and an example is described in Canadian Patent No. 2,587, 166 (Sury).
  • the PFT (312) illustrated in Figure 3 includes a first froth separation unit (FSU) (314), a second froth separation unit (FSU) (316), a solvent recovery unit (SRU) (318), and a tailings solvent recovery unit (TSRU) (320).
  • the PFT (312) yields a bitumen product (322) and PFT tailings (324).
  • the PFT tailings (324) may be sent to solvent-based extraction (326).
  • PSV tailings (328), from the PSV (308), may also be sent to solvent-based extraction (326).
  • the solvent-based extraction (326) produces a bitumen product (340), tailings (342), and high- quality water (344). As illustrated, the high-quality water (344) may be recycled into the water-based extraction process.
  • high quality water may not extract bitumen as well as process affected water. This may be mitigated in several ways; for example, by combining the high quality water with good quality process affected water, or by using the high quality water for a water wash within secondary recovery processes. In this way, certain water soluble organic compounds that are advantageous for extraction efficiency can be recovered to enhance bitumen recovery.
  • the aqueous stream from the water-based extraction process may undergo a water treatment process prior to being directed to the solvent-based extraction process.
  • the wastewater stream from the water treatment process, with concentrated solids and dissolved solids, is then directed to the solvent-based extraction process.
  • Exemplary tailings treatment processes include, but are not limited to, those described in the background section and those described in Canadian Patent No. 2,609,419 (Speirs and Dunn) and Canadian Patent Application No. 2,610,052 (Speirs and Dunn).
  • the solvent-based extraction facility is in proximity to a thermal oil recovery facility such that aqueous streams can be exchanged between these two facilities.
  • a portion of thermal oil recovery aqueous streams may be pumped to the solvent-based extraction facility for use in a solvent extraction with solids agglomeration process.
  • Suitable aqueous streams include, but are not limited to, produced water from the primary liquid-liquid separation vessels or other separation vessels downstream of the primary separation vessels, wastewater from the water treatment plants, and/or the blowdown streams from the steam generators.
  • Particularly suitable streams are aqueous streams from a thermal oil facility having high solids and/or dissolved solids contents because they are unsuitable, as is, for steam generation or other uses.
  • these aqueous streams are directed to the described solvent-based extraction process to assist in the solvent extraction of additional bitumen from mined oil sands while simultaneously undergoing water treatment by evaporation that yields a high quality water with reduced solids and dissolved solids content.
  • the higher quality water can be directed back to the thermal oil recovery facilities or released into the environment.
  • Figure 4 illustrates one embodiment.
  • a production well 402 produces bitumen and water (together 404), which is sent to a separator (406).
  • the separator produces bitumen (408) and water (410).
  • the water (410) is sent to a filter (412), which produces bitumen (414) and water (416).
  • the water (416) is sent to an evaporator (418), which produces wastewater (420) and high quality water with reduced solids and dissolved solids (422).
  • the recycling step (424) of the evaporator (418) is also illustrated.
  • the high quality water (422) is sent to a boiler (426), which produces steam (428) and a blowdown stream (430).
  • the wastewater stream (420) and blowdown stream (430) may be sent to solvent-based extraction (432) to produce a bitumen product (434), dry tailings (436), and high quality water (438).
  • the high quality water (438) may be recycled into the boiler (426).
  • Additional oil sand (440) may also be added to the solvent-based extraction (432).
  • the produced water from the primary separation vessel may comprise about
  • bitumen is recovered from the produced water using sequential skim tanks, gas flotation vessels, and oil removal filters.
  • a portion of the produced water from the primary separation vessel may bypass these bitumen recovery stages and instead be pumped to the solvent-based extraction facility in order to both recover the residual bitumen and produce high quality water.
  • the produced water after bitumen recovery, may be directed to a water treatment unit, such as an evaporator, as a means of producing high quality water with reduced dissolved solids.
  • a water treatment unit such as an evaporator
  • the wastewater stream from the water treatment unit is usually either disposed of by deep well injection, or is further concentrated to produce additional high quality water for steam generation and dry solids that can be buried.
  • a portion of the wastewater stream, concentrated with solids and dissolved solids, from the water treatment unit may be pumped to the solvent-based extraction facility to produce high quality water.
  • the dissolved solids of the wastewater stream will end up solidified with the tailings of the solvent-based extraction process.
  • a typical steam generator used in thermal oil recovery facilities is a once- through-type boiler which often operates with a feed water containing about 2,000 to 12,000 mg/L of dissolved solids. In these boilers, about 80% of the feed water is turned into steam with the remaining 20% of the feed water becoming the blowdown stream with five times the dissolved solids concentration.
  • the blowdown stream is of high pressure and thus can be flashed in a series of flash tanks to recovery lower pressures steam that can be used in other parts of the facilities. After the last flashing stage, the final blowdown stream is usually mixed with the wastewater stream from the water treatment unit and disposed of by the methods described above. In embodiments described herein, a portion of the blowdown streams from the steam generators may be pumped to the solvent-based extraction facility to produce high quality water.
  • Figure 5 is a schematic of solvent-based extraction method with agglomeration and additional steps including downstream solvent and water recovery.
  • the extraction liquor (502) is mixed with a bituminous feed (504) from oil sands in a slurry system (506) to form an initial slurry (508).
  • the extraction liquor (502) comprises a solvent and is used to extract bitumen from the bituminous feed (504).
  • Contaminated water (509) is also added to the slurry system (506) for use as the bridging liquid.
  • the initial slurry (508) is fed into an agglomerator (510).
  • Extraction may begin when the extraction liquor (502) is contacted with the bituminous feed (504) and a portion of the extraction may occur in the agglomerator (510). Agitation of the slurry is used to assist agglomeration. [0049]
  • the low solids bitumen extract (518) is sent to a solvent recovery unit (522) to recover solvent (524), which may be re-used to wash the agglomerates (520), leaving a bitumen product (526).
  • the agglomerates (520), along with contaminated water (534), are sent to a tailings solvent recovery unit (528) to recover solvent and water (together 530) leaving dry tailings (532).
  • liquid separator which produces solvent (538) and high quality water (540).
  • Exemplary liquid separators include vertical or horizontal settling tanks that are well known in the art.
  • the formed agglomerates are sized on the order of 0.1-1.0 mm, or on the order of 0.1-0.3 mm. In one embodiment, at least 80 wt.% of the formed agglomerates are less than 2mm, or 0.1-1.0 mm, or 0.1 to 0.3 mm in size.
  • the rate of agglomeration may be controlled by a balance between intensity of agitation within the agglomeration vessel, shear within the vessel which can be adjusted by for example changing the shape or size of the vessel, fines content of the slurry, bridging liquid addition, and residence time of the agglomeration process.
  • the agglomerated slurry may have a solids content of 20 to 70 wt%.
  • Agitation is assisted by some form of agitation.
  • the form of agitation may be mixing, shaking, rolling, or another known suitable method.
  • the agitation of the feed need only be severe enough and of sufficient duration to intimately contact the emulsion with the solids in the feed.
  • Exemplary rolling type vessels include rod mills and tumblers.
  • Exemplary mixing type vessels include mixing tanks, blenders, and attrition scrubbers. In the case of mixing type vessels, a sufficient amount of agitation is needed to keep the formed agglomerates in suspension.
  • the solids content of the feed is, in one embodiment, greater than 40 wt.% so that compaction forces assist agglomerate formation.
  • the agitation of the slurry has an impact on the growth of the agglomerates.
  • the mixing power can be increased in order to limit the growth of agglomerates by attrition of said agglomerates.
  • the fill volume and rotation rate of the vessel can be adjusted in order to increase the compaction forces used in the comminution of agglomerates. These agitation parameters can be adjusted in the control system described herein.
  • Extraction Liquor The extraction liquor comprises a solvent used to extract bitumen from the bituminous feed.
  • solvent as used herein should be understood to mean either a single solvent, or a combination of solvents.
  • the extraction liquor comprises a hydrocarbon solvent capable of dissolving the bitumen.
  • the extraction liquor may be a solution of a hydrocarbon solvent(s) and bitumen, where the bitumen content of the extraction liquor may range between 10 and 70 wt%, or 10 and 50 wt%. It may be desirable to have dissolved bitumen within the extraction liquor in order to increase the volume of the extraction liquor without an increase in the required inventory of hydrocarbon solvent(s). In cases where non-aromatic hydrocarbon solvents are used, the dissolved bitumen within the extraction liquor also increases the solubility of the extraction liquor towards dissolving additional bitumen.
  • the extraction liquor may be mixed with the bituminous feed to form a slurry where most or all of the bitumen from the oil sands is dissolved into the extraction liquor.
  • the solids content of the slurry is in the range of 10 wt% to 75 wt%, or 50 to 65 wt%.
  • a slurry with a higher solids content may be more suitable for agglomeration in a rolling type vessel, where the compressive forces aid in the formation of compact agglomerates.
  • the solvent used in the process may include low boiling point solvents such as low boiling point cycloalkanes, or a mixture of such cycloalkanes, which substantially dissolve asphaltenes.
  • the solvent may comprise a paraffinic solvent in which the solvent to bitumen ratio is maintained at a level to avoid or limit precipitation of asphaltenes.
  • a low boiling point solvent when it is used, there is the extra advantage that solvent recovery through an evaporative process proceeds at lower temperatures, and requires a lower energy consumption.
  • a low boiling point solvent when it is selected, it may be one having a boiling point of less than 100 °C.
  • the solvent selected according to certain embodiments may comprise an organic solvent or a mixture of organic solvents.
  • the solvent may comprise a paraffinic solvent, an open chain aliphatic hydrocarbon, a cyclic aliphatic hydrocarbon, or a mixture thereof.
  • a paraffinic solvent it may comprise an alkane, a natural gas condensate, a distillate from a fractionation unit (or diluent cut), or a combination of these containing more than 40% small chain paraffins of 5 to 10 carbon atoms. These embodiments would be considered primarily a small chain (or short chain) paraffin mixture.
  • the alkane may comprise a normal alkane, an iso-alkane, or a combination thereof.
  • the alkane may specifically comprise heptane, iso- heptane, hexane, iso-hexane, pentane, iso-pentane, or a combination thereof.
  • a cyclic aliphatic hydrocarbon be selected as the solvent, it may comprise a cycloalkane of 4 to 9 carbon atoms. A mixture of C 4 -C 9 cyclic and/or open chain aliphatic solvents would be appropriate.
  • Exemplary cycloalkanes include cyclohexane, cyclopentane, or a mixture thereof.
  • the solvent is selected as the distillate from a fractionation unit, it may for example be one having a final boiling point of less than 180 °C.
  • An exemplary upper limit of the final boiling point of the distillate may be less than 100 °C.
  • a mixture of C 4 -Ci 0 cyclic and/or open chain aliphatic solvents would also be appropriate.
  • it can be a mixture of C 4 -C 9 cyclic aliphatic hydrocarbons and paraffinic solvents where the percentage of the cyclic aliphatic hydrocarbons in the mixture is greater than 50%.
  • Extraction liquor may be recycled from a downstream step. For instance, as described below, solvent recovered in a solvent recovery unit, may be used to wash agglomerates, and the resulting stream may be used as extraction liquor.
  • the extraction liquor may comprise residual bitumen and residual solid fines. The residual bitumen increases the volume of the extraction liquor and it may increase the solubility of the extraction liquor for additional bitumen dissolution.
  • the solvent may also include additives. These additives may or may not be considered a solvent per se. Possible additives may be components such as de-emulsifying agents or solids aggregating agents. Having an agglomerating agent additive present in the bridging liquid and dispersed in the first solvent may be helpful in the subsequent agglomeration step.
  • Exemplary agglomerating agent additives include cements, fly ash, gypsum, lime, brine, water softening wastes (e.g. magnesium oxide and calcium carbonate), solids conditioning and anti-erosion aids such as polyvinyl acetate emulsion, commercial fertilizer, humic substances (e.g. fulvic acid), polyacrylamide based flocculants and others. Additives may also be added prior to gravity separation with the second solvent to enhance removal of suspended solids and prevent emulsification of the two solvents.
  • Exemplary additives include methanoic acid, ethylcellulose and polyoxyalkylate block polymers.
  • a bridging liquid is a liquid with affinity for the solids particles in the bituminous feed, and which is immiscible in the solvent.
  • Exemplary aqueous liquids may be recycled water from other aspects or steps of oil sands processing.
  • the aqueous liquid need not be pure water, and may indeed be water containing one or more salt, a waste product from conventional aqueous oil sand extraction processes which may include additives, aqueous solutions with a range of pH, or any other acceptable aqueous solution capable of adhering to solid particles within an agglomerator in such a way that permits fines to adhere to each other.
  • Contaminated water is used herein as the bridging liquid or as part of the bridging liquid.
  • the contaminated water may be, for instance, from a water-based hydrocarbon extraction process or from an in-situ thermal hydrocarbon recovery facility.
  • the contaminated water may include solids and/or dissolved solids.
  • Contaminated water requiring treatment prior to use within in-situ thermal hydrocarbon recovery and/or water- based extraction processes may be used.
  • Exemplary wastewaters are concentrated brine from water treatment plants and boilers of the in-situ thermal hydrocarbon recovery processes and tailings produced from water-based hydrocarbon extraction processes.
  • the total amount of bridging liquid added may be controlled in order to optimize bitumen recovery and the rate of solid-liquid separation, and may also be controlled with an account of the value provided by the upgrading of the contaminated water to high quality water.
  • the total amount of bridging liquid added may be such that a ratio of bridging liquid plus connate water from the bituminous feed to solids within the agglomerated slurry is in the range of 0.02 to 0.25, or in the range of 0.05 to 0.1 1.
  • the bridging liquid may be added in a concentration of less than 50 wt% of the oil sands feed, or less 25 wt%.
  • the bridging liquid may comprise fine particles (sized less than 44 ⁇ ) suspended therein. These fine particles may serve as seed particles for the agglomeration process. In one embodiment, the bridging liquid has a solids content of less than 40 wt%.
  • Ratio of Solvent to Bitumen for Agglomeration The process may be adjusted to render the ratio of the solvent to bitumen in the agglomerator at a level that avoids precipitation of asphaltenes during agglomeration. Some amount of asphaltene precipitation is unavoidable, but by adjusting the amount of solvent flowing into the system, with respect to the expected amount of bitumen in the bituminous feed, when taken together with the amount of bitumen that may be entrained in the extraction liquor used, can permit the control of a ratio of solvent to bitumen in the agglomerator.
  • An exemplary ratio of solvent to bitumen to be selected as a target ratio during agglomeration is less than 2:1. A ratio of 1.5:1 or less, and a ratio of 1 :1 or less, for example, a ratio of 0.75:1 , would also be considered acceptable target ratios for agglomeration.
  • ratios may be expressed herein using a colon between two values, such as “2:1 ", or may equally be expressed as a single number, such as "2", which carries the assumption that the denominator of the ratio is 1 and is expressed on a weight to weight basis.
  • Measurement of the solvent and bitumen content of the extraction liquor and/or bitumen extract could occur directly or by proxy.
  • Direct measurement of solvent and bitumen content could involve evaporating off the solvent and measuring the mass of both liquids, or use of a gas chromatograph, mass balance, spectrometer, or titration.
  • Indirect measurement of solvent and bitumen content could include measuring: density, the index of refraction, opacity, or other properties.
  • the slurry system may optionally be a mix box, a pump, or a combination of these.
  • the resulting slurry from the slurry system may have a solid content in the range of 20 to 65 wt%. In another embodiment, the slurry may have a solid content in the range of 20 to 50 wt%. In another embodiment, the slurry may have a solid content in the range of 40 to 65 wt%.
  • a lower solid content may be preferred since that will assist in the proper mixing of the bridging liquid and reduce the mixing energy needed to keep the slurry well mixed.
  • a higher solid content may be preferred since that will increase the compaction forces used in the comminution of agglomerates. Additionally, the increased compaction forces may reduce the amount of hydrocarbons that remain in the agglomerates and produce stronger agglomerates.
  • the preferred temperature of the slurry is in the range of 20-60 °C.
  • An elevated slurry temperature is desired in order to increase the bitumen dissolution rate and reduce the viscosity of the slurry to promote more effective sand digestion and agglomerate formation. Temperatures above 60 °C are generally avoided due to the complications resulting from high vapor pressures.
  • the residence time of the extraction process may be greater than 5 minutes, or may be greater than 10 minutes, or may be greater than 15 minutes, or may greater than 30 minutes. Depending on the desired level of agglomeration, the residence time of the agglomeration process may be in the range of 15 seconds to 10 minutes. In order to maximize bitumen recovery, the residence time of the agglomeration process may be in the range of 1 to 5 minutes.
  • Solid-Liquid Separator As described above, the agglomerated slurry may be separated into a low solids bitumen extract and agglomerates in a solid-liquid separator.
  • the solid-liquid separator may comprise any type of unit capable of separating solids from liquids, so as to remove agglomerates.
  • Exemplary types of units include a gravity separator, a clarifier, a cyclone, a screen, a belt filter or a combination thereof.
  • the system may contain a solid-liquid separator but may alternatively contain more than one. When more than one solid-liquid separation step is employed at this stage of the process, it may be said that both steps are conducted within one solid-liquid separator, or if such steps are dissimilar, or not proximal to each other, it may be said that a primary solid-liquid separator is employed together with a secondary solid-liquid separator. When a primary and secondary unit are both employed, generally, the primary unit separates agglomerates, while the secondary unit involves washing agglomerates.
  • Non-limiting methods of solid-liquid separation of an agglomerated slurry are described in Canadian Patent Application Serial No. 2,724,806 (Adeyinka et al.), filed December 10, 2010.
  • Secondary Stage of Solid-Liquid Separation to Wash Agglomerates As a component of the solid-liquid separator, a secondary stage of separation may be introduced for counter currently washing the agglomerates separated from the agglomerated slurry. The initial separation of agglomerates may be said to occur in a primary solid-liquid separator, while the secondary stage may occur within the primary unit, or may be conducted completely separately in a secondary solid-liquid separator.
  • counter currently washing it is meant that a progressively cleaner solvent is used to wash bitumen from the agglomerates.
  • Solvent involved in the final wash of agglomerates may be re-used for one or more upstream washes of agglomerates, so that the more bitumen entrained on the agglomerates, the less clean will be the solvent used to wash agglomerates at that stage. The result being that the cleanest wash of agglomerates is conducted using the cleanest solvent.
  • a secondary solid-liquid separator for counter currently washing agglomerates may be included in the system or may be included as a component of a system described herein.
  • the secondary solid-liquid separator may be separate or incorporated within the primary solid-liquid separator.
  • the secondary solid-liquid separator may optionally be a gravity separator, a cyclone, a screen or belt filter.
  • a secondary solvent recovery unit for recovering solvent arising from the solid-liquid separator can be included.
  • the secondary solvent recovery unit may be a conventional fractionation tower or a distillation unit.
  • the secondary stage for counter currently washing the agglomerates may comprise a gravity separator, a cyclone, a screen, a belt filter, or a combination thereof.
  • the solvent used for washing the agglomerates may be solvent recovered from the low solids bitumen extract, as described in Canadian Patent Application Serial No. 2,724,806 (Adeyinka et al.).
  • a second solvent may alternatively or additionally be used as described in Canadian Patent Application Serial No. 2,724,806 (Adeyinka et al.) for additional bitumen extraction downstream of the agglomerator.
  • Recycle and Recovery of Solvent The process may involve removal and recovery of solvent used in the process.
  • an exemplary solvent:bitumen ratio in the agglomerator may be 2:1 or lower, it is acceptable to use recycled solvent containing bitumen to achieve this ratio.
  • the amount of make-up solvent required for the process may depend solely on solvent losses, as there is no requirement to store and/or not re-use solvent that has been used in a previous extraction step. When solvent is said to be "removed”, or “recovered”, this does not require removal or recovery of all solvent, as it is understood that some solvent will be retained with the bitumen even when the majority of the solvent is removed.
  • the system may contain a single solvent recovery unit for recovering the solvent(s) arising from the gravity separator.
  • the system may alternatively contain more than one solvent recovery unit.
  • Solvent may be recovered by conventional means.
  • typical solvent recovery units may comprise a fractionation tower or a distillation unit.
  • the solvent recovered in this fashion will not contain bitumen entrained therein.
  • This clean solvent is preferably used in the last wash stage of the agglomerate washing process in order that the cleanest wash of the agglomerates is conducted using the cleanest solvent.
  • the solvent recovered in the process may comprise entrained bitumen therein, and can thus be re-used as the extraction liquor for combining with the bituminous feed.
  • Other optional steps of the process may incorporate the solvent having bitumen entrained therein, for example in countercurrent washing of agglomerates, or for adjusting the solvent and bitumen content prior to agglomeration to achieve the selected ratio within the agglomerator that avoids precipitation of asphaltenes.
  • This dilution can be carried out in a staged manner to pre-condition the primary solid-liquid separator feed to promote higher solids settling rates and lower solids content in the solid-liquid separator's overflow.
  • the solvent with which the slurry is diluted may be derived from recycled liquids from the liquid-solid separation stage or from other sources within the process.
  • the solvent to bitumen ratio of the feed into the agglomerator is set to obtain from about 10 to about 90 wt% bitumen in the discharge, and a workable viscosity at a given temperature. In certain cases, these viscosities may not be optimal for the solid-liquid separation (or settling) step. In such an instance, a dilution solvent of equal or lower viscosity may be added to enhance the separation of the agglomerated solids in the clarifier, while improving the quality of the clarifier overflow by reducing viscosity to permit more solids to settle.
  • dilution of agglomerator discharge may involve adding the solvent, or a separate dilution solvent, which may, for example, comprise an alkane.
  • the produced water of thermal oil recovery processes and the tailings of water-based extraction processes comprise residual bitumen that is desirable to recover.
  • the conventional method of recovering the residual bitumen is gravity separation. It is difficult to separate emulsified bitumen or bitumen of small droplet size by gravity. For this reason, a number of processing stages and pieces of equipment are required for the necessary oil-water separation, which results in a process that is both expensive in capital cost and operating cost. Similar limitations exist for the residual bitumen in the tailings produced from water-based extraction. In embodiments described herein, residual bitumen can be recovered and high quality water can be produced from the solvent- based extraction process.
  • Embodiments described herein may eliminate or reduce the need for the recycle loop.
  • the concentrated brine can mix with the solids of the solvent- based extraction process and the mixture can be dried in tailings solvent recovery unit such as a rotary dryer.
  • the wastewater from in-situ thermal water treatment plants is generally of a pH > 8.5.
  • For water based extraction it has been found that such a pH enhances recovery. Using contaminated water with a high pH as the bridging liquid in the solvent extraction process may enhance the separation of bitumen from the sand grains, reduce bitumen inclusion and thereby increase recovery.

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Abstract

La présente invention concerne un procédé de traitement d'une matière première bitumineuse et d'eau contaminée qui comprend la mise en contact de la matière première bitumineuse avec une liqueur d'extraction et l'eau contaminée pour former une pâte initiale. La pâte initiale est extraite par solvant pour former une pâte extraite comprenant des matières solides, de l'eau contaminée, et un extrait de bitume. Les matières solides sont séparées de l'extrait de bitume. Le solvant est récupéré à partir de l'extrait de bitume pour former un produit de bitume. De l'eau de haute qualité et du solvant sont récupérés à partir des matières solides. En plus de l'extraction de bitume, le procédé convertit l'eau contaminée en eau de haute qualité qui peut être utilisée dans l'extraction d'hydrocarbures à base d'eau ou récupération d'hydrocarbures thermique in situ.
PCT/US2012/043577 2011-08-02 2012-06-21 Procédé de traitement d'une matière première bitumineuse et d'eau contaminée Ceased WO2013019332A1 (fr)

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CA3016908A1 (fr) 2018-09-07 2020-03-07 Suncor Energy Inc. Extraction non aqueuse du bitume des sables bitumineux
CA3051955A1 (fr) 2019-08-14 2021-02-14 Suncor Energy Inc. Extraction et separation non aqueuses de bitume a partir de minerai de sables bitumineux a l'aide d'un solvant paraffinique et de bitume desasphaltee

Citations (5)

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US4225433A (en) * 1978-10-02 1980-09-30 Petro-Canada Exploration Inc. Filtration of hot water extraction process whole tailings
US4596651A (en) * 1980-02-20 1986-06-24 Standard Oil Company (Indiana) Two-stage tar sands extraction process
US4722782A (en) * 1983-10-31 1988-02-02 Standard Oil Company Method for solvent treating of tar sands with water displacement
US20110061610A1 (en) * 2009-09-16 2011-03-17 Speirs Brian C Heat and Water Recovery From Oil Sands Waste Streams
US20110180458A1 (en) * 2010-01-22 2011-07-28 Marathon Oil Canada Corporation Methods for extracting bitumen from bituminous material

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4225433A (en) * 1978-10-02 1980-09-30 Petro-Canada Exploration Inc. Filtration of hot water extraction process whole tailings
US4596651A (en) * 1980-02-20 1986-06-24 Standard Oil Company (Indiana) Two-stage tar sands extraction process
US4722782A (en) * 1983-10-31 1988-02-02 Standard Oil Company Method for solvent treating of tar sands with water displacement
US20110061610A1 (en) * 2009-09-16 2011-03-17 Speirs Brian C Heat and Water Recovery From Oil Sands Waste Streams
US20110180458A1 (en) * 2010-01-22 2011-07-28 Marathon Oil Canada Corporation Methods for extracting bitumen from bituminous material

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