WO2012161855A1 - Procédé de traitement d'une charge bitumineuse à l'aide d'une agglomération dans un canalisation - Google Patents

Procédé de traitement d'une charge bitumineuse à l'aide d'une agglomération dans un canalisation Download PDF

Info

Publication number
WO2012161855A1
WO2012161855A1 PCT/US2012/028570 US2012028570W WO2012161855A1 WO 2012161855 A1 WO2012161855 A1 WO 2012161855A1 US 2012028570 W US2012028570 W US 2012028570W WO 2012161855 A1 WO2012161855 A1 WO 2012161855A1
Authority
WO
WIPO (PCT)
Prior art keywords
slurry
pipeline
agglomeration
solvent
agglomerates
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2012/028570
Other languages
English (en)
Inventor
Olusola B. Adeyinka
Brian C. Speirs
Fritz PIERRE
Payman Esmaeili
Thomas R. Palmer
Emilio Alvarez
Anjaneya S. Kovvali
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ExxonMobil Upstream Research Co
Original Assignee
ExxonMobil Upstream Research Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by ExxonMobil Upstream Research Co filed Critical ExxonMobil Upstream Research Co
Priority to US14/112,552 priority Critical patent/US20140054201A1/en
Publication of WO2012161855A1 publication Critical patent/WO2012161855A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

Classifications

    • 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
    • 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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/003—Solvent de-asphalting
    • 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
    • B01D21/01—Separation of suspended solid particles from liquids by sedimentation using flocculating agents
    • 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
    • B01D21/30—Control equipment
    • B01D21/32—Density control of clear liquid or sediment, e.g. optical control ; Control of physical properties
    • 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
    • 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
    • C10G2300/80—Additives
    • C10G2300/805—Water

Definitions

  • the present disclosure relates generally to the field of hydrocarbon extraction from mineable deposits, such as bitumen from oil sands.
  • Solvent extraction processes for the recovery of the hydrocarbons have been proposed as an alternative to water extraction of oil sands.
  • the commercial application of a solvent extraction process has, for various reasons, eluded the oil sands industry.
  • a major challenge to the application of solvent extraction to oil sands is the tendency of fine particles within the oil sands to hamper the separation of solids from the hydrocarbon extract. Solids agglomeration is a technique that can be used to deal with this challenge.
  • Solids agglomeration is a size enlargement technique that can be applied within a liquid suspension to assist solid-liquid separation.
  • the process involves agglomerating fine solids, which are difficult to separate from a liquid suspension, by the addition of a second liquid.
  • the second liquid preferentially wets the solids but is immiscible with the suspension liquid.
  • the second liquid displaces the suspension liquid on the surface of the solids.
  • the fines solids consolidate into larger, compact agglomerates that are more readily separated from the suspension liquid.
  • Solids agglomeration has been used in other applications to assist solid-liquid separation.
  • the process has been used in the coal industry to recover fine coal particles from the waste streams produced during wet cleaning treatments (see for example, U.S. Patent Nos. 3,856,668 (Shubert); 4, 153,419 (Clayfield); 4,209,301 (Nicol et al.); 4,415,445 (Hatem) and 4,726,810 (Ignasiak)).
  • Solids agglomeration has also been proposed for use in the solvent extraction of bitumen from oil sands. This application was coined Solvent Extraction Spherical Agglomeration (SESA). A more recent description of the SESA process can be found in Sparks et al., Fuel 1992 (71 ); pp 1349-1353.
  • SESA Previously described methodologies for SESA have not been commercially adopted.
  • 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.
  • the formed agglomerates are more easily separated from the organic solvent compared to un-agglomerated solids. This process permitted a significant decrease in water use, as compared with conventional water-based extraction processes.
  • the multi-phase mixture need only be agitated severely enough and for sufficient time to intimately contact the aqueous liquid with the fine solids.
  • the patent discloses that it is preferable that the type of agitation be a rolling or tumbling motion for at least the final stages of agglomeration. These types of motion should assist in forming compact and spherical agglomerates from which most of the hydrocarbons are excluded.
  • the formed agglomerates are referred to as macro-agglomerates because they result from the consolidation of both the fine particles (sized less than 44 ⁇ ) and the coarse particles (sized greater than 200 ⁇ ) found in the oil sands.
  • the additional solvent acts to wash the excess bitumen from the agglomerates.
  • the additional bridging liquid allows the agglomerates to grow by a layering mechanism and under the increasing compressive forces produced by the tapered rotating drum bed depth.
  • the compressive forces act to preferentially remove hydrocarbon liquid from the pores of the agglomerates such that, when optimal operating conditions are imposed, the pores of the agglomerates end up being filled with only the bridging liquid, and the solvent that remains on the surface of the agglomerates is easily recovered.
  • U.S. Patent No. 4,406,788 (Meadus et al.) describes a similar apparatus to that of U.S. Patent No. 3,984,287 (Measdus et al.), but where the extraction and agglomeration processes occurs within a single vessel. Within this vessel, the flow of solvent is counter-current to the flow of agglomerates which results in greater extraction efficiency.
  • U.S. Patent No. 4,719,008 (Sparks et al.) describes a process to address the agglomeration challenge posed by varying ore grades by means of a micro-agglomeration procedure in which the fine particles of the oil sands are consolidated to produce agglomerates with a similar particle size distribution to the coarser grained particles of the oil sands.
  • a micro-agglomeration procedure the solid-liquid separation behavior of the agglomerated oil sands will be similar regardless of ore grade.
  • the micro-agglomeration process is described as occurring within a slowly rotating horizontal vessel.
  • the conditions of the vessel favor the formation of large agglomerates; however, a light milling action is used to continuously break down the agglomerates.
  • the micro-agglomerates are formed by obtaining an eventual equilibrium between cohesive and destructive forces. Since rapid agglomeration and large agglomerates can lead to bitumen recovery losses owing to entrapment of extracted bitumen within the agglomerated solids, the level of bridging liquid is kept as low as possible commensurate with achieving economically viable solid-liquid separation.
  • the bridging liquid is either added directly to the dry oil sands or is added to the oil sands slurry comprising the oil sands and the hydrocarbon solvent.
  • bitumen extraction and particle agglomeration occurs simultaneously.
  • the growth of agglomerates may hamper the dissolution of the bitumen into the solvent, it may lead to trapping of bitumen within the agglomerates, and it may result in an overall increase in the required residence time for bitumen extraction.
  • excessive agglomeration may occur in the locations of bridging liquid injection.
  • agglomerates will tend to be larger than the desired agglomerate size and result in an increase in the viscosity of the slurry.
  • a higher slurry viscosity may hamper the mixing needed to uniformly distribute the bridging liquid throughout the remaining areas of the slurry. Poor bridging liquid dispersion may result in a large agglomerate size distribution, which is not preferred.
  • An important step in the agglomeration process is the distribution of the bridging liquid throughout the liquid suspension. Poor distribution of the bridging liquid may result in regions within the slurry of too low and too high binging liquid concentrations. Regions of low bridging liquid concentrations may have no or poor agglomeration of fine solids, which may result in poor solid-liquid separation. Regions of high bridging liquid concentration may have excess agglomeration of solids, which may result in the trapping of bitumen or bitumen extract within the large agglomerates. In the process described in U.S. Patent No.
  • U.S. Patent No. 3,925,189 (Wicks III) describes a process and apparatus for extracting hydrocarbons from oil-containing solids. Specifically, the process involves forming an oil-containing solid-solvent slurry and flowing the slurry within a pipeline at a relatively high flow velocity in order to extract the hydrocarbons from the solids.
  • the pipeline is positioned uphill at an angle of between 5 to 7 degrees to the horizontal, to increase solid holdup and residence time in the pipeline.
  • Wicks describes that it is preferable to use steam as the purge gas to remove oxygen from the oil sands, because it led to an improvement in the filtration rates.
  • Coal mining processes often produce aqueous slurries comprising fine coal particles.
  • Solids agglomeration has been proposed as a method of recovering these fine coal particles, which may constitute up to 30 wt% of the mined coal.
  • the hydrophobic coal particles are agglomerated within the aqueous slurry by adding an oil phase as the bridging liquid.
  • the coal particles become wetted with an oil layer and adhere to each other to form agglomerates.
  • the hydrophilic ash particles are not preferentially wetted by the oil phase and, as a result, remain un-agglomerated and suspended in the aqueous phase.
  • the agglomerated coal material, with reduced ash content, is readily separated from the aqueous slurry by mechanical methods such as screening.
  • U.S. Patent No. 4,153,419 (Clayfiled et al.) describes a process for the agglomeration of coal fines within an aqueous slurry by staged addition of a bridging liquid to the aqueous slurry.
  • Each agglomeration stage comprises the addition of a bridging liquid to the slurry, agitation of the mixture, and removal of agglomerates from the aqueous slurry.
  • U.S. Patent No. 4,415,445 (Van Hattem et al.) describes a process for the agglomeration of coal fines within an aqueous slurry by the addition of a bridging liquid and the addition of seed pellets that are substantially larger than the coal fines.
  • the presence of seed pellets induces agglomerate growth to occur predominately by a layering mechanism rather than by a coalescence mechanism. Since the rate of agglomeration occurs much faster by layering compared to coalescence, the process described therein allows agglomerates to form very quickly so that, for a given residence time, a higher throughput of agglomerates can be obtained compared to the throughput obtainable in the absence of seed pellets.
  • U.S. Patent No. 4,726,810 (Ignasiak) describes a process for the agglomeration of coal fines within an aqueous slurry by the addition of a bridging liquid comprising a low quality oil, such as bitumen, and a light hydrocarbon diluent, such as kerosene.
  • the aqueous slurry mixture is agitated by pumping it through a pipeline within which coal particles agglomerate and may later be separated from the slurry by screening.
  • the process allows for the selective agglomeration of low-rank coal using substantially a low quality oil.
  • the present disclosure relates to a method of processing a bituminous feed.
  • the bituminous feed is contacted with an extraction liquor to form a slurry.
  • the slurry is then flowed through a pipeline.
  • a bridging liquid is added to the slurry to assist agglomeration. Agitation is also used to assist agglomeration.
  • the result is an agglomerated slurry comprising agglomerates and a low solids bitumen extract.
  • the agglomerates are then separated from the low solids bitumen extract.
  • Performing the agglomeration in a pipeline as opposed to in a conventional agitating vessel may provide certain advantages, such as improved sealing in order to contain the potentially flammable mixture of oil sands slurry from the atmosphere, production of smaller and more uniform agglomerates due to improved mixing of the bridging liquid into the oil sands slurry, and the flexibility to have a long residence time for the extraction and agglomeration processes since the length of the pipeline can be readily increased to achieve the desired residence time. Additionally, the plug flow nature of processing within the pipeline may allow for greater observation and control of the agglomeration process. Furthermore, the pipeline may have the added advantage of providing a means of transporting the oil sands slurry to other locations within the mine site as the slurry is being processed within the pipeline.
  • the present disclosure provides a method of processing a bituminous feed, the method comprising: a) contacting the bituminous feed with an extraction liquor to form a slurry, wherein the extraction liquor comprises a solvent; b) flowing the slurry through a pipeline and adding a bridging liquid to the slurry before and/or within the pipeline, and agitating solids within the slurry within the pipeline to form an agglomerated slurry comprising agglomerates and a low solids bitumen extract; and c) separating the agglomerates from the low solids bitumen extract.
  • Fig. 1 is a flow chart 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 graph of bitumen recovery and initial filtration rate as a function of extraction time with the agglomeration time kept constant at 2 minutes.
  • Fig. 6 is a graph is a graph of bitumen recovery and initial filtration rate as a function of agglomeration time with the extraction time kept constant at 5 minutes.
  • Fig. 7a is a schematic illustrating a disclosed embodiment.
  • Fig. 7b is a schematic illustrating a disclosed embodiment.
  • Fig. 7c is a schematic illustrating a disclosed embodiment.
  • Fig. 7d is a schematic illustrating a disclosed embodiment.
  • Fig. 8 is a schematic illustrating a disclosed embodiment.
  • the present disclosure relates to a method of processing a bituminous feed using a pipeline to agglomerate solids. This method may be combined with aspects of other solvent extraction processes, including, but not limited to, those described above in the background section, and those described in Canadian Patent Application Serial No. 2,724,806 ("Adeyinka et al.”), filed December 10, 2010 and entitled “Processes and Systems for Solvent Extraction of Bitumen from Oil Sands”.
  • a solvent is combined with a bituminous feed derived from oil sand to form an initial slurry. Separation of the initial slurry into a fine solids stream and coarse solids stream may be followed by 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.
  • the present disclosure relates to a method of processing a bituminous feed.
  • the bituminous feed is contacted with an extraction liquor to form a slurry (102).
  • the slurry is then flowed through a pipeline and a bridging liquid is added to the slurry and agitation is provided to assist agglomeration (104).
  • the result is an agglomerated slurry comprising agglomerates and a low solids bitumen extract.
  • the agglomerates are then separated from the low solids bitumen extract (106).
  • 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.
  • bituminous feed may be used as a waste product from other extraction processes which comprises bitumen that would otherwise not have been recovered.
  • bituminous feed may be also derived directly from oil shale oil, bearing diatomite or oil saturated sandstones.
  • agglomerate refers to conditions that produce a cluster, aggregate, collection or mass, such as nucleation, coalescence, layering, sticking, clumping, fusing and sintering, as examples.
  • FIG 2 is a schematic of a disclosed embodiment with additional steps including downstream solvent recovery.
  • the extraction liquor (202) is mixed with a bituminous feed (204) from oil sands in a slurry system (206) to form a slurry (208).
  • the extraction liquor comprises a solvent and is used to extract bitumen from the bituminous feed.
  • the slurry is fed into a pipeline (210). Extraction may begin when the extraction liquor (202) is contacted with the bituminous feed (204) and a portion of the extraction may occur in the pipeline (210).
  • the slurry (208) is flowed in the pipeline (210), and at one or more points along the pipeline (210), a bridging liquid (212) is added to the pipeline to assist agglomeration of the slurry.
  • a bridging liquid may be added to the slurry prior to the pipeline.
  • Some form of agitation is also used to assist agglomeration as described below. In one embodiment, the agitation is provided by turbulent flow in the pipeline.
  • the low solids bitumen extract is sent to a solvent recovery unit (222) to recover solvent (224) leaving a bitumen product (226).
  • the agglomerates (220) are sent to a tailings solvent recovery unit (228) to recover solvent (230) leaving dry tailings (232).
  • the bituminous feed is dry oil sand, which is contacted with extraction liquor that free of bridging liquid in a slurry system to produce a pumpable slurry.
  • the slurry may be well mixed in order to dissolve the bitumen.
  • the bitumen is first extracted from the bituminous feed prior to agglomeration in order to prevent (or limit) the agglomeration process from hampering the dissolution of bitumen into the extraction liquor.
  • the bridging liquid may be directly mixed with the bituminous feed before or at the same time as the extraction liquor so that bitumen extraction and agglomeration occur simultaneously.
  • the bridging liquid is 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.
  • agglomerates may be produced that 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 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 velocity within the pipeline (i.e. flow turbulence), fines content of the slurry, bridging liquid addition, and residence time within the pipeline.
  • Figure 3 illustrates an exemplary pipeline that is segmented into three zones.
  • the slurry (308) comprising the bituminous feed and the extraction liquid, is fed into the pipeline (310).
  • bitumen extraction which began prior to delivering the slurry (308) to the pipeline (310), continues.
  • the extraction zone (350) is designed to provide enough residence time and agitation to dissolve the bitumen.
  • agglomeration does not occur, or is limited because bridging liquid is preferably not injected into the pipeline in the extraction zone of the pipeline.
  • bridging liquid (312a) is added to the pipeline (310). Adding a sufficient amount of bridging liquid (312a) assists agglomerate nucleation in the nucleation zone (352).
  • the amount of bridging liquid added within the nucleation zone may be less or much less than the total amount of bridging liquid needed for desired agglomeration. In one embodiment, the amount of bridging liquid added within the nucleation zone is 5 to 35% of the total amount of bridging liquid added within the pipeline. In another embodiment, the amount of bridging liquid added within the nucleation zone is 10 to 25% of the total amount of bridging liquid added within the pipeline.
  • the reduced amount of bridging liquid added within the nucleation zone may lower the rate of agglomerate growth and allow for rapid dispersion of the bridging liquid within the oil sands slurry.
  • additional bridging liquid (312b) is added to the pipeline (310) to assist agglomerate growth, in the agglomerate growth zone (354), to a desired size for subsequent solid-liquid separation.
  • the bridging liquid (312b) is added to the agglomerate growth zone (354) at several points to assist uniform mixing of the bridging liquid with the slurry.
  • the three zones are not necessarily discrete zones. For instance, extraction may continue after the extraction zone, and nucleation may continue after the nucleation zone.
  • the mixing energy within the comminution zone is increased significantly in order to comminute the undesirably large agglomerates that form in the agglomerate growth zone.
  • Methods for increasing the mixing energy include, but are not limited to, increasing the slurry velocity within the comminution zone and/or having internal structures within the comminution zone of the pipeline.
  • Figure 4 illustrates a pipeline (410) in more detail divided into three zones, the extraction zone (450), the nucleation zone (452), and the agglomerate growth zone (454).
  • the slurry (408), and bridging liquids (412a and 412b) are also shown.
  • Measurement (456) of one or more of the properties of the slurry at a point within the pipeline (410) can be used to control (458) the operation downstream of the measurement location.
  • One option is to adjust the amount of bridging liquid (412b) that is added.
  • Another option is to adjust the velocity of the slurry in the pipeline.
  • One possible measurement is agglomerate particle size distribution. This measurement can be accomplished by integrating an online particle size measurement device such as a Retsch Technology Camsizer.
  • a slip stream can be taken from the slurry, filtered to remove liquid, and then measured to analyze particle size distribution.
  • Another possible measurement is the filtration rate of the oil sands slurry. This measurement can be accomplished by integrating an online filtration device with the pipeline. A slip stream can be taken from the slurry and the rate of filtration of that slip stream can be measured. The filter medium should be similar to that which is used in the solid-liquid separator.
  • Another possible measurement is the solids content of the bitumen extract. One method for accomplishing this measurement may be the measurement of the density of an unfiltered and micro-filtered bitumen extract. The difference in density of these two streams can be correlated with solid content.
  • Yet another possible measurement is the power dissipation of the oil sands slurry at different points along the length of the pipeline. This measurement can be accomplished by measuring the static pressure along the length of the pipe.
  • Embodiments described herein may be used for the formation of macro-agglomerates or micro-agglomerates from the solids of the bituminous feed.
  • Macro-agglomerates are agglomerates that are predominantly greater than 2 mm in diameter. These agglomerates comprise both the fine particles (less than 44 ⁇ ) and sand grains of the oil sands.
  • Micro-agglomerates are agglomerates that are predominately less than 1 mm in diameter and they principally comprise fine particles of the oil sands. It has been found that for the SESA process described above, the formation of micro-agglomerates are more suitable for maximizing bitumen recovery for a range of oil sands grades.
  • the pipeline will comprise two zones, an extraction zone and an agglomeration zone.
  • the function of the extraction zone is to dissolve the bitumen from the oil sands into the extraction liquor.
  • bitumen is extracted from the oil sands prior to the agglomeration step in order to prevent (or limit) the agglomeration process from hampering the dissolution of bitumen into the extraction liquor.
  • the function of the agglomeration zone is to agglomerate the solids to the amount commensurate with achieving economically viable solid-liquid separation.
  • micro-agglomerates are preferred because they allow for good solid-liquid separation without entrapping a significant amount of the bitumen extract within the agglomerates.
  • the extraction of the bitumen prior to the agglomeration process has the effect of reducing the required residence time in the agglomeration zone, when compared to certain previously proposed processes which require extraction of bitumen and agglomeration to occur simultaneously.
  • the reduced residence time of the agglomeration zone allows for agglomerates of smaller particle size distribution to form.
  • the agglomeration zone may comprise a nucleation zone, an agglomerate growth zone, and a comminution zone.
  • the agglomeration process is initiated within the nucleation zone.
  • the amount of bridging liquid added within the nucleation zone may be less or much less than the total amount of bridging liquid needed for desired agglomeration.
  • the amount of bridging liquid added within the nucleation zone may be 5 to 35% of the total amount of bridging liquid added within the agglomeration zone.
  • the amount of bridging liquid added within the nucleation zone is 10 to 25% of the total amount of bridging liquid added within the agglomeration zone.
  • the reduced amount of bridging liquid added within the nucleation zone may lower the rate of agglomerate growth and allow for rapid dispersion of the bridging liquid within the oil sands slurry.
  • additional bridging liquid is added within the agglomeration growth zone in order to grow the agglomerates to the desired size and reduce the amount of fine solids dispersed within the bitumen extract.
  • the bridging liquid may be added to the agglomerate growth zone at several points to assist uniform mixing of the bridging liquid within the slurry.
  • a comminution zone may follow the agglomerate growth zone in order to comminute the undesirably large agglomerates that may form in the agglomerate growth zone. The comminution may be effected by, for example, increasing the velocity within the comminution zone or having internal structures within the comminution zone.
  • Velocity within Pipeline The nature of slurry flow within a horizontal pipeline depends on the ratio of the average flow velocity of the slurry within the pipeline to the limiting settling velocity of the slurry. When the average flow velocity is greater than the limiting settling velocity, the slurry flow within the pipeline is homogenous with no average concentration changes across the pipe. At any velocity below the limiting settling velocity, the slurry flow becomes heterogeneous with the concentration of the solids increasing towards the bottom of the pipe. For an average flow velocity that is heterogeneous but where the slurry velocity remains greater than 40% of the limiting settling velocity, the solids that are deposited at the bottom of the pipe can flow by bouncing and rolling along the pipe. This type of flow is called saltation flow. The average flow velocity that is below that which is needed for saltation flow is usually avoided since pipeline plugging will occur as solids are continuously injected into the pipeline.
  • the limiting settling velocity for a slurry is best determined by conducting tests with the slurry flowing within a pipeline test rig. In the absence of such tests, the limiting settling velocity, V L can be estimated using the following equation proposed by R Durand:
  • F L is a parameter that is dependent upon the particle size distribution and the solids volume concentration within the slurry. For a slurry with mixed particle size, such as that expected for oil sands slurries as described herein, F L has been measured to have values within the range of 0.5 to 1 .5.
  • the average flow velocity within the pipeline can be that needed for saltation flow or greater. It is preferable that the slurry flow be homogenous or mildly heterogeneous. However, this not necessary since the extraction liquor will digest the oil sands lumps even under low agitation conditions.
  • the average flow velocity within the extraction zone may be 1 to 5 m/sec. In another embodiment, the average flow velocity within the extraction zone may be 2 to 3 m/sec.
  • the slurry flow be a homogenous type slurry flow.
  • the homogenous flow will allow for proper mixing of the bridging liquid. Additionally, this type of flow will ensure that most, if not all, of the solids remain in the turbulent flow regime of slurry such that they are consistently exposed to the high shear forces needed to prevent (or limit) excessive growth of the agglomerates and non-uniformity of agglomerate size.
  • the average flow velocity within the agglomeration zone may be greater than 2 m/sec. In another embodiment, the average flow velocity within the agglomeration zone may be 3 to 6 m/sec.
  • the average flow velocity should not be too high a velocity so that the shear forces subject the agglomerates to severe attrition that prevents agglomerate growth.
  • severe attrition may be desired within the nucleation zone and in the comminution zone.
  • the severe attrition can be used to rapidly disperse the bridging liquid.
  • the severe attrition can be used to reduce the size of the larger agglomerates. Erosion of the pipeline and excessive pressure drop will limit the average flow velocity within all zones making up the agglomeration zone.
  • the residence time of the extraction zone 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.
  • the residence time of the agglomeration zone may be in the range of 30 seconds to 10 minutes. In one embodiment, the residence time of the agglomeration zone may be in the range of 1 to 5 minutes.
  • the residence time of the nucleation zone within the agglomeration zone may be less than 30 seconds.
  • the residence time within the agglomeration may be extended beyond 5 minutes to provide the required residence time for the comminution zone.
  • Pipeline Geometry of Pipeline. It is desirable to have the pipeline diameter of the extraction zone to be constant and as large as possible commensurate with keeping the slurry flow above the saltation velocity. Exemplary pipeline diameters are in the range of 0.5 to 1.5 m. These pipeline diameters are similar in size to those of the hydrotransport pipelines used in the water-based extraction process. Since the total pipeline length may comprise mostly the extraction zone, attempts should be made to minimize erosion within this portion of the pipeline.
  • the homogenous slurry flow can be accomplished by reducing the pipeline diameter of the agglomeration zone (as seen in Figure 7a) in order to increase the average flow velocity of the slurry and reduce the limiting settling velocity.
  • the slurry (708a), the extraction zone (750a), and the agglomeration zone (754a) are shown.
  • the pipeline diameter in the agglomeration zone may be 0.25 to 1 .5 m.
  • the homogenous slurry flow can be accomplished by incorporating a recycle loop with the agglomeration zone as shown in Figure 7b.
  • the slurry (708b), the extraction zone (750b), and the agglomeration zone (754b) are shown.
  • the recycle loop (755) would act to increase the average flow velocity within the agglomeration zone.
  • the pipeline of the agglomeration zone (754c) can be configured at angles to the horizontal. The configuration of the pipeline at angles will have the effect of reducing the limiting settling velocity of the slurry.
  • the pipeline may be angled 5° to 45° to horizontal.
  • the pipeline of the agglomeration zone may comprise internal structures to promote homogenous slurry flow.
  • Exemplary structures include intermittently spaced static mixers as shown in Figure 7d.
  • the static mixers (756) are shown within the agglomeration zone (754d). It is preferable that static mixers, or the like, be included in the pipeline in such a way that they can be readily replaced since such devices may be subject to high rates of erosion.
  • Other potential internal structures will be readily known by those skilled in the art.
  • the plug flow nature of processing the bituminous feed within the pipeline may allow for greater observation and control of the agglomeration process. For example, measurement of one or more of the properties of the slurry at a point or multiple points within the pipeline can be used to control the operation downstream of the measurement location.
  • One option is to adjust the amount of bridging liquid that is added.
  • Another option is to adjust the velocity of the slurry in the pipeline.
  • Another option is to adjust the solid content of the bridging liquid added to the slurry.
  • Another option is to adjust the methods and locations of the bridging liquid addition along the pipeline.
  • Yet another option is to reduce the solid content of the slurry.
  • One possible measurement is agglomerate particle size distribution.
  • This measurement can be accomplished by integrating an online particle size measurement device such as a Retsch Technology Camsizer.
  • a slip stream can be taken from the slurry, filtered to remove liquid, and then measured to analyze particle size distribution.
  • Another possible measurement is the filtration rate of the oil sands slurry.
  • This measurement can be accomplished by integrating an online filtration device with the pipeline.
  • a slip stream can be taken from the slurry and the rate of filtration of that slip stream can be measured.
  • the filter medium should be similar to that which is used in the solid-liquid separator.
  • Another possible measurement is the solids content of the bitumen extract.
  • One method for accomplishing this measurement may be the measurement of the density of an unfiltered and micro-filtered bitumen extract. The difference in density of these two streams can be correlated with solid content. Yet another possible measurement is the power dissipation of the slurry at different points along the length of the pipeline. This measurement can be accomplished by measuring the static pressure along the length of the pipe.
  • Extraction Liquor The extraction liquor comprises a solvent used to extract bitumen from the bituminous feed.
  • solvent used to extract bitumen from the bituminous feed.
  • solvent 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 to 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 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.
  • hydrocarbon solvents that preferentially precipitate asphaltenes from the bitumen.
  • the precipitated asphaltenes may agglomerate with the oileophilic solids within the slurry which can help to produce a bitumen extract with less entrained fine particles.
  • a low boiling point solvent While it is not necessary to use 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 a low boiling point solvent 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 hydrocarbon in the mixture is greater than 50%.
  • Extraction liquor may be recycled from a downstream step.
  • 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 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.
  • Bridging Liquid 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 salts, a waste product from conventional aqueous oil sand extraction processes which may include additives, aqueous solution with a range of pH, or any other acceptable aqueous solution capable of adhering to solid particles within the pipeline in such a way that permits fines to adhere to each other.
  • An exemplary bridging liquid is water.
  • the bridging liquid may be added to the slurry in a concentration of less than 20 wt% of the slurry. In another embodiment, the bridging liquid is added to the slurry in a concentration of less than 10 wt% of the slurry. In one embodiment, the bridging liquid is added in a concentration of between 1 wt% and 20 wt% or between 1 wt% and 10 wt%. In one embodiment, the bridging liquid comprises fine particles (for instance less than 44 ⁇ ) suspended therein. These fine particles may serve as seed particles for the agglomeration process. The bridging liquid may comprise less than 40 wt% solid fines. The agglomerated slurry may have a solids content of 20 to 70 wt%.
  • Ratio of Solvent to Bitumen for Agglomeration The process may be adjusted to render the ratio of the solvent to bitumen in the pipeline at a level that avoids or limits 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.
  • a solvent to bitumen ratio of at least 2:1 or greater is desired.
  • 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%.
  • the slurry may have a solid content in the range of 30 to 50 wt%.
  • 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.
  • Solvent Slurry Transport In the mining of oil sands, the distance that mined oil sands must travel from the mine to the extraction plant and subsequently to a disposal site necessitates significant energy expenditure and cost.
  • a similar benefit is realized within the hydrotransport lines of water-based extraction facilities. In the case of water-based extraction facilities, it is generally more cost effective and less energy intensive to transport oil sands by pipeline than by dry solid transport methods such as trucks and/or conveyors. Similar cost and energy saving may be realized in the case of solvent slurry transport.
  • Figure 8 illustrates a mine facilities layout where slurry systems (802a, 802b, and 802c) are located close to the mine face to receive oil sands (804a, 804b, and 804c) by trucks and/or conveyors. Pipelines (806a, 806b, and 806c) are then used to conduct the solvent extraction with solids agglomeration process while transporting the slurry to a central facility (808) where the remaining processes of solvent extraction, as outlined in Figure 2, may occur. As illustrated in Figure 8, optional equipment (808) such as a drum, a clarifier, and an inclined plate separator may also be used.
  • optional equipment such as a drum, a clarifier, and an inclined plate separator may also be used.
  • the central facility may include a solid- liquid separator (812) (such as a belt filter), a tailings solvent recover unit (814), and a clean solvent storage (816), the operations of which are described above.
  • the bitumen product (818) may be pipelined to a plant.
  • the coarse solids (820) may be sent to a pit.
  • the location of central facilities may be dictated by various factors such as the footprint of the facilities, tailings disposal requirements, and other considerations.
  • 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.
  • a solid-liquid separator 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.
  • 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.
  • 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 with reference to Figures 2 to 4.
  • 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 pipeline.
  • the process may involve removal and recovery of solvent used in the process.
  • 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 the process may comprise entrained bitumen therein, and can thus be re-used 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 pipeline.
  • Solvent may be added to the agglomerated slurry for dilution of the slurry before discharge into the primary solid-liquid separator, which may be for example a deep cone settler. 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 pipeline 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 pipeline discharge may involve adding the solvent, or a separate dilution solvent, which may, for example, comprise an alkane.
  • the pipeline has the added advantage of providing a means of transporting the oil sands slurry to other locations within the mine site as the slurry is being processed within the pipeline.
  • a pipeline may enable plug flow, or close to plug flow, behavior of the agglomeration process.
  • the pipeline may comprise different zones along the length of the pipe, each accomplishing a different result, as described above with reference to Figures 3 and 4.
  • the plug flow (or near plug flow) behavior of the agglomeration process within a pipeline may allow for greater flexibility in observing and controlling the agglomeration process itself. For example, measurement of one or more of the properties of the slurry at a point or multiple points within the pipeline can be used to control the operation downstream of the measurement location.
  • bitumen is extracted from the oil sands prior to the agglomeration step.
  • the decoupling of the extraction and agglomeration processes may yield certain advantages.
  • the experimental results plotted in Figures 5 and 6 suggest that the rate of bitumen recovery and solid-liquid separation can increase by extending the extraction residence time while keeping the agglomeration residence time low.
  • An advantage of the pipeline agglomeration process described herein is that such long residence time in the extraction zone of the pipeline is economically feasible since the length of the pipeline can be readily increased to achieve the desired residence time.
  • a Parr reactor (series 5100) (Parr Instrument Company, Moline, IL, USA) was used as the extractor and agglomerator.
  • the reactor vessel was made of glass that permits direct observation of the mixing process.
  • a turbine type impeller powered by an explosion proof motor of 0.25 hp was used.
  • the mixing and agglomeration speed of the impeller were set to 1500 rpm. This rotation speed allowed the slurry to remain fluidized at all conditions of the experiments.
  • the agglomeration experiments were conducted at room temperature (22 °C).
  • the agglomerated solids produced in these experiments were treated in a Soxhlet extractor combined with Dean-Stark azeotropic distillation, to determine the material contents of the agglomerated slurry.
  • Toluene was used as the extraction solvent.
  • the oil sand solids were dried overnight in an oven (100 °C) and then weighed to determine the solids content of the agglomerated slurry.
  • the water content was determined by measuring the volume of the collected water within the side arm of the Dean-Stark apparatus.
  • the bitumen content of the agglomerated slurry was determined by evaporating the toluene and residual cyclohexane from an aliquot of the hydrocarbon extract from the Soxhlet extractor.
  • the initial liquid drainage rate was calculated by measuring the time needed to drain 50 ml_ of bitumen extract above the bed of agglomerated solids.
  • Figure 5 plots the bitumen recovery and the initial liquid filtration rate as a function of the extraction residence time. The figure shows that the bitumen recovery and the initial liquid filtration rate increases as the extraction time increases for batch experiments conducted with the agglomeration time kept constant at 2 minutes.
  • the effects of agglomeration residence time on the solvent extraction with solids agglomeration process 350g of oil sands and 235.07g of extraction liquor were placed into the Parr reactor vessel. The solids and solvent were mixed at 1500 rpm for 5 minutes to fully homogenize the mixture and to fully extract the bitumen that was in the oil sands. After 5 minute of mixing, 16.8g of water was quickly pored into the vessel through a sample port. The mixture was then mixed at 1500 rpm for a given agglomeration residence time to agglomerate the solids. The agglomeration times tested were 0.5, 1 , 2, 5, 15, and 30 minutes.
  • Figure 6 plots the bitumen recovery and the initial liquid filtration rate as a function of the agglomeration residence time. The figure shows that the bitumen recovery reaches a maximum and then decreases as the agglomeration time increases for batch experiments conducted with the extraction time kept constant at 5 minutes. The decrease in recovery beyond the maximum recovery is most likely due to excessive agglomerate growth that lead to entrapment of the bitumen extract within the agglomerates. However, this growth of agglomerates does result in a continuous increase in the initial filtration rate as the agglomeration time increases,

Landscapes

  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Wood Science & Technology (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

La présente invention porte sur un procédé de traitement d'une charge bitumineuse. La charge bitumineuse est mise en contact avec une liqueur d'extraction pour former une bouillie. La bouillie est ensuite amenée à s'écouler à travers une canalisation. Un liquide de colmatage est ajouté à la bouillie pour aider l'agglomération. Une agitation est également utilisée pour aider l'agglomération. Le résultat est une bouillie agglomérée comprenant des agglomérats et un extrait de bitume à faible teneur en matières solides. Les agglomérats sont ensuite séparés de l'extrait de bitume à faible teneur en matières solides. Effectuer l'agglomération dans un canalisation par opposition à dans un récipient d'agitation classique peut fournir certains avantages, par exemple un scellement étanche amélioré afin de contenir le mélange potentiellement inflammable de bouillie de sables bitumineux hors de l'atmosphère, une production d'agglomérats plus petits et plus uniformes en raison d'un mélange amélioré du liquide de colmatage dans la bouillie de sables bitumineux, et la flexibilité d'avoir un long temps de séjour pour les procédés d'extraction et d'agglomération.
PCT/US2012/028570 2011-05-20 2012-03-09 Procédé de traitement d'une charge bitumineuse à l'aide d'une agglomération dans un canalisation Ceased WO2012161855A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
US14/112,552 US20140054201A1 (en) 2011-05-20 2012-03-09 Method of Processing a Bituminous Feed Using Agglomeration in a Pipeline

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
CA2740670 2011-05-20
CA2740670A CA2740670C (fr) 2011-05-20 2011-05-20 Methode de traitement d'un apport bitumineux faisant appel a l'agglomeration dans un pipeline

Publications (1)

Publication Number Publication Date
WO2012161855A1 true WO2012161855A1 (fr) 2012-11-29

Family

ID=47215840

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2012/028570 Ceased WO2012161855A1 (fr) 2011-05-20 2012-03-09 Procédé de traitement d'une charge bitumineuse à l'aide d'une agglomération dans un canalisation

Country Status (3)

Country Link
US (1) US20140054201A1 (fr)
CA (1) CA2740670C (fr)
WO (1) WO2012161855A1 (fr)

Families Citing this family (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9758733B2 (en) * 2014-11-18 2017-09-12 Exxonmobil Upstream Research Company Separation of asphaltenes
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
US11365356B2 (en) 2019-09-16 2022-06-21 Syncrude Canada Ltd. Process and process line for solvent extraction of bitumen from oil sands
CN112708436B (zh) * 2019-10-25 2022-09-02 国家能源投资集团有限责任公司 中间相沥青制备系统和中间相沥青制备方法
CA3169681C (fr) 2021-08-18 2025-12-23 Syncrude Canada Ltd. In Trust For The Owners Of The Syncrude Project As Such Owners Exist Now And In The Future Floculation/agglomeration de solides dans l'extraction de solvant du bitume de sable bitumineux

Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3560371A (en) * 1968-06-17 1971-02-02 Cities Service Athabasca Inc Recovery of bitumen from bituminous sand with control of bitumen particle size
US3925189A (en) * 1968-04-12 1975-12-09 Shell Oil Co Pipeline processing of oil-containing solids to recover hydrocarbons
US4057486A (en) * 1975-07-14 1977-11-08 Canadian Patents And Development Limited Separating organic material from tar sands or oil shale
US4153419A (en) * 1976-12-03 1979-05-08 Shell Oil Company Agglomeration of coal fines
US4719008A (en) * 1985-06-28 1988-01-12 Canadian Patents And Development Ltd. Solvent extraction spherical agglomeration of oil sands
US4726810A (en) * 1984-05-23 1988-02-23 Her Majesty The Queen In Right Of The Province Of Alberta As Represented By The Minister Of Energy And Natural Resources Process for the selective agglomeration of sub-bituminous coal fines
US5083613A (en) * 1989-02-14 1992-01-28 Canadian Occidental Petroleum, Ltd. Process for producing bitumen

Patent Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3925189A (en) * 1968-04-12 1975-12-09 Shell Oil Co Pipeline processing of oil-containing solids to recover hydrocarbons
US3560371A (en) * 1968-06-17 1971-02-02 Cities Service Athabasca Inc Recovery of bitumen from bituminous sand with control of bitumen particle size
US4057486A (en) * 1975-07-14 1977-11-08 Canadian Patents And Development Limited Separating organic material from tar sands or oil shale
US4153419A (en) * 1976-12-03 1979-05-08 Shell Oil Company Agglomeration of coal fines
US4726810A (en) * 1984-05-23 1988-02-23 Her Majesty The Queen In Right Of The Province Of Alberta As Represented By The Minister Of Energy And Natural Resources Process for the selective agglomeration of sub-bituminous coal fines
US4719008A (en) * 1985-06-28 1988-01-12 Canadian Patents And Development Ltd. Solvent extraction spherical agglomeration of oil sands
US5083613A (en) * 1989-02-14 1992-01-28 Canadian Occidental Petroleum, Ltd. Process for producing bitumen

Also Published As

Publication number Publication date
CA2740670A1 (fr) 2012-11-20
CA2740670C (fr) 2014-10-07
US20140054201A1 (en) 2014-02-27

Similar Documents

Publication Publication Date Title
CA2803977C (fr) Procede et systemes d'extraction au solvant de bitume a partir de sables bitumineux
CA2937235C (fr) Traitement de matiere premiere bitumineuse
CA2797513C (fr) Procedes integres pour la recuperation des hydrocarbures dans les sables bitumineux
CA2832931C (fr) Procedes integres pour la recuperation des hydrocarbures dans les sables bitumineux
CA2740670C (fr) Methode de traitement d'un apport bitumineux faisant appel a l'agglomeration dans un pipeline
CA2753811C (fr) Methode de traitement de residus de l'extraction d'hydrocarbures a base de solvant
CA2740468C (fr) Methode de traitement d'une charge bitumineuse par l'ajout progressif d'un liquide portant
CA2738194C (fr) Methode de traitement d'un circuit d'alimentation en bitume au moyen d'une emulsion
CA2741280C (fr) Procede de traitement de charge d'alimentation de bitume
CA2867357C (fr) Procede de traitement de matiere premiere bitumineuse
CA2744611C (fr) Systemes et processus relogeables pour recuperer le bitume des sables bitumineux
CA2916601C (fr) Procede d'agglomeration de boues de sables bitumineux a base de solvant

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12788849

Country of ref document: EP

Kind code of ref document: A1

WWE Wipo information: entry into national phase

Ref document number: 14112552

Country of ref document: US

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 12788849

Country of ref document: EP

Kind code of ref document: A1