EP2497815A1 - Procédé d'amélioration du procédé d'extraction d'eau chaude des sables pétrolifères - Google Patents

Procédé d'amélioration du procédé d'extraction d'eau chaude des sables pétrolifères Download PDF

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Publication number
EP2497815A1
EP2497815A1 EP11170433A EP11170433A EP2497815A1 EP 2497815 A1 EP2497815 A1 EP 2497815A1 EP 11170433 A EP11170433 A EP 11170433A EP 11170433 A EP11170433 A EP 11170433A EP 2497815 A1 EP2497815 A1 EP 2497815A1
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Prior art keywords
carbon dioxide
pipeline
oil
oil sands
pressure
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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.)
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EP11170433A
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German (de)
English (en)
Inventor
Zhixiong Cha
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Linde GmbH
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Linde GmbH
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
    • C10G1/04—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by extraction
    • C10G1/047—Hot water or cold water extraction processes
    • 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 invention relates to a process for adding carbon dioxide in a hydrotransport pipeline through which oil sands slurry is transported to an extraction plant in order to improve bitumen recovery efficiency.
  • Hot water extraction process is the most frequently employed technique to recover bitumen from surface mined oil sands. Due to the high capacity and low operating cost of modern hot water extraction process for oil sands and other mined oil bearing formations, other alternative processes are not likely to replace this process in the near future.
  • a mixture of oil sand, hot process water, and extraction additive normally caustic reagent such as sodium hydroxide or sodium carbonate, is conditioned in a large tumbler or drum by intense mechanical agitation for a predetermined period to achieve a desired separation degree of bitumen from sand grains and entraining of air bubbles in the slurry.
  • This modern hot water extraction process which is developed from the conventional hot water process, transports oil sand, hot process water and extraction additives to a separation vessel in a pipeline wherein conditioning of oil sand is achieved during transportation.
  • hydrotransport is one of the most important developments in the oil sands surface mining industry since it greatly increases treatment capacity of the oil sands extraction plant and reduces energy cost.
  • Prior art document US 5 264 118 describes a pipeline conditioning process for mined oil sands wherein oil sands is transported with hot water and sodium hydroxide via a pipeline of sufficient length. During the conditioning process, with assistance of sodium hydroxide, bitumen is liberated from sand grains and entrained air facilitates subsequent aeration of the bitumen.
  • the conditioned oil sands slurry is fed to a gravity separation vessel, known as primary separation vessel (PSV), to settle into three layers, bitumen froth, middlings, and sand under quiescent conditions.
  • PSD primary separation vessel
  • the middlings which is normally processed in a secondary separation vessel, is a mixture of buoyant bitumen, clay and water.
  • the pipeline has a length of 2.5 kilometers to achieve a desired extraction efficiency for a mixture of fifty percent to seventy percent by weight of oil sands, fifty percent to thirty percent by weight of hot water, and less than 0.05% by weight of sodium hydroxide at a temperature between 40°C to 70°C.
  • the residence time of oil sands slurry in the pipeline is about fourteen minutes.
  • bitumen flecks tend to coalesce and attach or coat to the air bubbles entrained in the slurry. Because the amount of the entrained air is an important factor for oil sands conditioning in the hydrotransport pipeline, a more effective method of adding air into oil sands slurry can significantly improve the overall bitumen extraction efficiency.
  • the drawback of this process is that the extracted bitumen contains relatively high concentration of impurities due to bitumen's high viscosity at low temperature and incomplete separation of bitumen from sand grains.
  • the volume ratio of air to slurry can be up to 2.5:1 and the overall bitumen recovery efficiency can be as high as 98 percent.
  • This method can achieve more than ninety percent bitumen extraction efficiency for tar sands or oil sands from different countries without the assistant of caustic reagent and does not generate middlings.
  • the major drawback of this method is that the extraction capacity of a device is limited by the vessel size due to the high construction cost of a large pressure vessel.
  • prior art document WO 2005/123608 A1 teaches a method of adding hydrogen peroxide into a conditioned mixture of oil sands and hot water.
  • the oxygen bubbles generated through decomposition of hydrogen peroxide may accelerate separation and floatation of bitumen.
  • Caustic reagent is normally required to improve the conditioning effects in the hot water extraction process.
  • addition of caustic reagent such as sodium hydroxide has many drawbacks.
  • caustic reagent will cause emulsification of released bitumen in water and suspension of fine particles in the aqueous phase. Those effects greatly reduce the overall bitumen extraction efficiency and cause serious environmental problems when the process water is being disposed.
  • Another problem is generation of large amount of middlings in the separation vessel. Although most bitumen contained in the middlings and tailings can be recovered in the subsequent extraction processes, improving the primary separation vessel's froth production and quality is the most effective way to reduce the overall operating cost.
  • Prior art document CA 2 004 352 A1 has addressed these problems by replacing the caustic reagent by kerosene and methyl-isobutyl carbinol. This method also has a problem of high operating cost due to usage of large amount of chemicals.
  • prior art document CA 1 022 098 discloses a method to break the emulsion to recover additional bitumen and accelerate precipitation of the suspended solids through neutralizing the process water by addition of inorganic acids and carbon dioxide.
  • bitumen is separated from sand grains and bitumen droplets are formed with the help of the caustic reagent
  • the basic condition is not necessarily to be maintained in the separation vessel for formation of froth.
  • the caustic condition can cause emulsification of bitumen in hot water and generate large amount of middlings.
  • De-emulsification of the emulsion such as reducing pH of the process water or adding flocculent, can improve the total recovery ratio of bitumen in the primary separation vessel.
  • pressure drop in the primary separation vessel can significantly increase bitumen's buoyancy through expansion of the bitumen droplets. Also, reduction of emulsified bitumen in water and increase of bitumen's buoyancy can prevent generation of large amount of middlings.
  • pressurizing the primary separation vessel in a larger oil sands extraction plant is not practical because of the high construction cost of a large pressure vessel.
  • Injecting carbon dioxide in the hydrotransport pipeline is a more practical method for adjusting the oil sands slurry's pH.
  • an object of the present invention is to increase the bitumen extraction efficiency in a hot water oil sands extraction process; more particularly, the present invention aims to improve the bitumen recovery efficiency in a primary separation vessel by simultaneous improvement of the aeration effect and reduction of the bitumen emulsification degree.
  • a method for improving oil sands hot water extraction process, in particular for recovering bitumen comprising adding carbon dioxide to a pipeline containing an oil-bearing formation being transported is disclosed.
  • the bitumen extraction efficiency in a hot water oil sands extraction process is increased.
  • the oil-bearing formation is selected from the group consisting of an oil sands slurry, tar sands slurry and oil-contaminated soil slurry.
  • the volumetric flow rate ratio of the carbon dioxide to process water in the pipeline is controlled from 0.2:1 to 15:1.
  • the carbon dioxide injection pressure is maintained at a pressure from 1.2 bars to 21 bars.
  • the pressure in the pipeline behind the carbon dioxide injection point is maintained between 1.1 bars to twenty bars.
  • the pH of the oil sands slurry in the pipeline is adjusted to a level below 8.
  • the carbon dioxide is injected in the pipeline at a point where the oil-bearing formation has been conditioned to a degree higher than fifty percent.
  • the length of the pipeline is from one meter to two kilometers.
  • the oil-bearing formation flow is merged with a fresh water stream before it is fed to a separation vessel and the volumetric flow rate ratio of the fresh water to oil-bearing formation is from 0:1 to 3:1,
  • the carbon dioxide is directly injected into the oil-bearing formation through a device selected from the group consisting of nozzles and a venturi device.
  • carbon dioxide is mixed with a water stream before being injected in the pipeline, wherein the volumetric flow rate ratio of the carbon dioxide to the water can be from 1:0 to 20:1.
  • carbon dioxide is injected in the pipeline at several points.
  • a volume of gaseous carbon dioxide can be added into the oil sands slurry that is being transported through a hydrotransport pipeline from the oil sands mining site to the bitumen extraction plant at a position where the oil sands has been conditioned to a desired degree.
  • Carbon dioxide can be injected into the slurry under elevated pressure through a gas distribution device while the hydraulic pressure in the pipeline can be maintained at an elevated pressure. After the carbon dioxide-bearing oil sands slurry is fed into the separation vessel, a part of the carbon dioxide can be recovered for reinjection.
  • the present invention can be applied, but is not limited to, improving the oil extraction of oil sands and other oil bearing formation in a hot water extraction process.
  • the same method can be applied to remediation of contaminated soil, treatment of waste water, and mine floatation in order to improve treatment efficiency.
  • carbon dioxide is injected into the hydrotransport pipeline, through which oil sands slurry is conditioned when being transported from a mining site to an extraction plant, at a position where the oil sands have been conditioned to a desired degree.
  • the pH of the oil sand slurry after dissolving carbon dioxide in the process water which can be measured by a set of pH probes installed on the pipeline, is adjusted to a value below 8 and preferably below 7 by controlling the carbon dioxide's flow rate.
  • the hydraulic pressure in the pipeline is maintained at an elevated pressure to guarantee that a desired amount of carbon dioxide is dissolved in the process water. Also, some other aspects such as the salt concentration and alkalinity of water that can affect the equilibrant carbon dioxide concentration in the aqueous phase are taken into account.
  • the hydraulic pressure is maintained between 1.1 bars to twenty bars for the purpose of dissolving more carbon dioxide and a boosting pump is installed if necessary.
  • the pressure used in describing the present invention is absolute pressure.
  • bitumen extraction is also facilitated by other synergetic effects due to injection of carbon dioxide, such as aeration and gas bubble floatation effect in the separation vessel and higher buoyancy of the bitumen droplets. Therefore, by maintaining an elevated hydraulic pressure in the pipeline, the volumetric flow rate ratio of carbon dioxide to the process water in the hydrotransport pipeline is controlled from 0.2:1 to 15:1.
  • the gas volume used in the present invention is its volume under standard condition. Adding carbon dioxide into the hydrotransport pipeline can be achieved by one venturi device or other gas dissolving devices such as a set of nozzles.
  • the pressure of carbon dioxide is maintained at a pressure higher than the hydraulic pressure in the hydrotransport pipeline for the purpose of injection at a high gas flow rate, preferably between 1.5 bars to 21 bars.
  • a fresh water stream can be optionally mixed with the oil sands slurry flow prior to being fed into the primary separation tank.
  • the volumetric mixing ratio of the fresh water to the oil sands slurry is from 0:1 to 3:1.
  • the water's temperature can be controlled from 20°C to 120°C.
  • the present invention comprises a carbon dioxide recycling pipeline to recover the released carbon dioxide from the oil sands slurry in the primary separation vessel, in which the operating pressure is at ambient pressure or a pressure lower than the hydraulic pressure in the pipeline.
  • the recovered carbon dioxide can be stored in a carbon dioxide storage tank or be injected into another hydrotransport pipeline in parallel operation with or without treatment, depending on the insoluble gas concentration in it. Since a part of carbon dioxide that dissolved in the process water under ambient pressure is not recoverable, supplementary carbon dioxide is provided to maintain the carbon dioxide flow rate.
  • the process water recovered from the separation vessel is aerated by air or other inert gases such as nitrogen, methane, carbon monoxide and argon, or is heated to an elevated temperature by injection of steam.
  • the present invention also relates to a system, in particular to an apparatus, for conducting the method as described above.
  • the present invention finally relates to the use of a method as described above and/or of a system as mentioned above for increasing the bitumen extraction efficiency in the hot water oil sands extraction process.
  • carbon dioxide from carbon dioxide tank A is injected into the hydrotransport pipeline 3, which transports oil sands slurry to an extraction plant, through line 2, at a position where the oil sands slurry has been conditioned to a desired degree higher than fifty percent, preferably higher than eighty percent, and more preferably higher than ninety percent, that the basic condition is no longer required for liberation of bitumen from sand grains.
  • the carbon dioxide may be supplied to the carbon dioxide tank A through line 1 from a trailer or other ready source of carbon dioxide.
  • the hydrotransport pipeline 3 pressure for carbon dioxide injection is maintained at an elevated pressure from 1.2 bars to 21 bars, preferably from three bars to ten bars.
  • the pH of the oil sands slurry in the hydrotransport pipeline 3, which can be measured by a set of pH probes installed on the hydrotransport pipeline 3, is adjusted to a level below 8 and preferably below 7 by controlling the carbon dioxide flow rate.
  • Carbon dioxide can be directly injected in oil sand slurry through a set of nozzles or a gas disperser such as a venturi device. Although it is not necessary that all carbon dioxide be dissolved in the oil sands slurry since existence of gas bubbles in the slurry improves conditioning effect, an elevated pressure is maintained in the pipeline to keep as much as possible of carbon dioxide is dissolved in the oil sands slurry.
  • the pressure in the hydrotransport pipeline 3 behind the carbon dioxide injection point is maintained between 1.1 bars to twenty bars, preferably between two bars to ten bars.
  • the length of the hydrotransport pipeline 3 for dissolving carbon dioxide and the residence time of oil sands slurry in the hydrotransport pipeline 3 for breaking emulsion are decided by the hydraulic pressure, the slurry's pH, amount of impurities in water such as suspended fine particles, alkalinity of the process water and the emulsification degree of bitumen in water, preferably from one meter to two kilometers, more preferably from hundred meters to one kilometer.
  • the volumetric flow rate ratio of carbon dioxide to the process water in the hydrotransport pipeline 3 is controlled from 0.2:1 to 15:1, preferably from 0.5:1 to 10:1.
  • the oil sands slurry is fed into the hydrotransport pipeline 3 from mixer B through line 12.
  • the oil sands slurry is fed into mixer B through line 9; hot water is also fed into the mixer B through line 8 to line 11 and additives such as sodium hydroxide or sodium carbonate are also fed into the mixer B through line 10.
  • the mixer B is typically a cyclofeeder.
  • the hot water in line 8 can also be directed immediately or in addition to its transport into line 11 and mixer B, directly into the hydrotransport pipeline 3.
  • the oil sands slurry flow in hydrotransport pipeline 3 is merged with a fresh water stream through line 8 to adjust the volumetric ratio of gas to water for the purpose of optimizing the gas flotation effect for bitumen in the vessel.
  • the mixing volumetric flow rate ratio of the fresh water to oil sands slurry is controlled from 0:1 to 3:1, preferably from 0.1:1 to 1:1.
  • the water's temperature is controlled from 20°C to 120°C.
  • the oil sands slurry is fed into the separation vessel C though a pressure reducing device such as a nozzle or a valve.
  • the primary separation vessel C is operated under ambient pressure or a pressure lower than the hydraulic pressure in the hydrotransport pipeline 3. Therefore, a part of carbon dioxide dissolved in water and bitumen transforms into bubbles after pressure drop to provide additional bitumen separation and flotation effects in the separation vessel.
  • Gaseous carbon dioxide in the primary vessel's overhead space can be recycled through a carbon dioxide recovery pipeline 7 to a carbon dioxide storage tank A or be directly injected into another hydrotransport pipeline in parallel operation, not shown in Fig. 1 .
  • the recycled carbon dioxide may contain air entrained in oil sands during conditioning, so the carbon dioxide is diluted by fresh carbon dioxide or be treated by other measures to control the insoluble gas concentration in it if it is necessary.
  • the overall impurities concentration in carbon dioxide is controlled lower than twenty percent, preferably less than ten percent, and more preferably less than five percent by volume. Also, the recovered carbon can be used for other purposes.
  • the primary separation vessel C is typically a large, conical-bottomed, cylindrical vessel.
  • the primary separation vessel C will separate the oil sand slurry that is fed through hydrotransport pipeline 3 into three distinct components plus excess carbon dioxide that may be present in the oil sand slurry.
  • the sand and water will exit through the bottom of the primary separation vessel C through the bottom line 6 which can be treated and returned to where the oil sand was originally derived from or transported for other disposal means.
  • the middlings which are separated in the primary separation vessel C are removed through line 5 and froth is removed through line 4.
  • carbon dioxide is recovered and recycled through line 7 back to the carbon dioxide storage tank A where it can be used for injection into the hydrotransport pipeline 3.
  • the process water recovered through line 6 from the separation vessel C contains dissolved carbon dioxide, which may cause corrosion of the equipments and pipelines and require additional caustic reagent to condition the oil sands when the recovered water is to be reused
  • the process water is aerated by air or other inert gases such as nitrogen, methane, carbon monoxide and argon, or is heated to a higher temperature by injection of steam or other heating methods before reuse.
  • carbon dioxide is mixed with a fresh water stream before being added in the oil sands slurry.
  • the purpose of mixing the fresh water with carbon dioxide is to make carbon dioxide partially dissolved in water at a pressure higher than the pressure in the pipeline.
  • the fresh water's temperature can be higher or lower than the oil sands slurry's temperature transported in the pipeline.
  • the volumetric flow rate ratio of the carbon dioxide to fresh water is controlled from 1:0 to 20:1.
  • the water's temperature is controlled from 1°C to 100°C.
  • the carbon dioxide is injected into the hydrotransport pipeline at several points and the distance between two adjacent points is from one meter to 500 meters, more likely from ten meters to 200 meters.
  • the number of injection points is from two to twenty, and the carbon dioxide's injection rate at different injection points can be the same, close to or different at each injection point.
  • the flow rate ratio of the overall of carbon dioxide to the process water in the oil sands slurry is from 0.2:1 to 15:1, preferably from 0.5:1 to 10:1.
  • Fig. 1 also illustrates a corresponding system 100, in particular to a corresponding apparatus, for recovering bitumen, with such system 100 working according to the method of the present invention.

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Wood Science & Technology (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Extraction Or Liquid Replacement (AREA)
EP11170433A 2011-03-09 2011-06-17 Procédé d'amélioration du procédé d'extraction d'eau chaude des sables pétrolifères Withdrawn EP2497815A1 (fr)

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US13/044,044 US20120228195A1 (en) 2011-03-09 2011-03-09 Method for improving oil sands hot water extraction process

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EP2497815A1 true EP2497815A1 (fr) 2012-09-12

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Publication number Priority date Publication date Assignee Title
CA3052317A1 (fr) * 2017-02-03 2018-08-09 Adjacency Labs Corp. Deconstruction de materiaux en sable bitumineux a l'aide de liquides ioniques

Citations (12)

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CA1022098A (fr) 1973-10-12 1977-12-06 Dusan A. Vendrinsky Methode de traitement des effluents chauds issus du bitume des sables bitumineux au moyen d'anhydride carbonique
US4120777A (en) * 1976-07-13 1978-10-17 Guardian Chemical Corporation Process for recovery of bituminous material from tar sands
CA1237689A (fr) * 1985-09-26 1988-06-07 Moshe Greenfeld Flottation sur mousse pour la recuperation du bitume des suspensions aqueuses des sables bitumineux
US4968412A (en) * 1989-01-17 1990-11-06 Guymon E Park Solvent and water/surfactant process for removal of bitumen from tar sands contaminated with clay
CA2029795A1 (fr) 1989-11-10 1991-05-11 George J. Cymerman Procede de conditionnement de sables petroliferes pour le transport par canalisation
CA2004352A1 (fr) 1989-12-01 1991-06-01 Kohur N. Sury Appareil et methode d'extraction d'eau chaude
US5039227A (en) 1989-11-24 1991-08-13 Alberta Energy Company Ltd. Mixer circuit for oil sand
US5264118A (en) 1989-11-24 1993-11-23 Alberta Energy Company, Ltd. Pipeline conditioning process for mined oil-sand
US6004455A (en) * 1997-10-08 1999-12-21 Rendall; John S. Solvent-free method and apparatus for removing bituminous oil from oil sands
US6007708A (en) 1997-10-02 1999-12-28 Alberta Energy Company Ltd. Cold dense slurrying process for extracting bitumen from oil sand
WO2005123608A1 (fr) 2004-06-10 2005-12-29 Lawrence Conaway Procede pour l'utilisation de peroxyde et d'alcali pour la recuperation de bitume a partir de sables asphaltiques
CA2703835A1 (fr) 2007-11-02 2009-05-07 University Of Utah Research Foundation Compression/detente de gaz cylique pour l'extraction amelioree de sables bitumineux

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Patent Citations (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CA1022098A (fr) 1973-10-12 1977-12-06 Dusan A. Vendrinsky Methode de traitement des effluents chauds issus du bitume des sables bitumineux au moyen d'anhydride carbonique
US4120777A (en) * 1976-07-13 1978-10-17 Guardian Chemical Corporation Process for recovery of bituminous material from tar sands
CA1237689A (fr) * 1985-09-26 1988-06-07 Moshe Greenfeld Flottation sur mousse pour la recuperation du bitume des suspensions aqueuses des sables bitumineux
US4968412A (en) * 1989-01-17 1990-11-06 Guymon E Park Solvent and water/surfactant process for removal of bitumen from tar sands contaminated with clay
CA2029795A1 (fr) 1989-11-10 1991-05-11 George J. Cymerman Procede de conditionnement de sables petroliferes pour le transport par canalisation
US5039227A (en) 1989-11-24 1991-08-13 Alberta Energy Company Ltd. Mixer circuit for oil sand
US5264118A (en) 1989-11-24 1993-11-23 Alberta Energy Company, Ltd. Pipeline conditioning process for mined oil-sand
CA2004352A1 (fr) 1989-12-01 1991-06-01 Kohur N. Sury Appareil et methode d'extraction d'eau chaude
US6007708A (en) 1997-10-02 1999-12-28 Alberta Energy Company Ltd. Cold dense slurrying process for extracting bitumen from oil sand
US6004455A (en) * 1997-10-08 1999-12-21 Rendall; John S. Solvent-free method and apparatus for removing bituminous oil from oil sands
WO2005123608A1 (fr) 2004-06-10 2005-12-29 Lawrence Conaway Procede pour l'utilisation de peroxyde et d'alcali pour la recuperation de bitume a partir de sables asphaltiques
CA2703835A1 (fr) 2007-11-02 2009-05-07 University Of Utah Research Foundation Compression/detente de gaz cylique pour l'extraction amelioree de sables bitumineux

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WO2012121837A1 (fr) 2012-09-13

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