CA2522031C - Method for treatment of oil sands tailings with lime or with lime and carbon dioxide - Google Patents
Method for treatment of oil sands tailings with lime or with lime and carbon dioxide Download PDFInfo
- Publication number
- CA2522031C CA2522031C CA2522031A CA2522031A CA2522031C CA 2522031 C CA2522031 C CA 2522031C CA 2522031 A CA2522031 A CA 2522031A CA 2522031 A CA2522031 A CA 2522031A CA 2522031 C CA2522031 C CA 2522031C
- Authority
- CA
- Canada
- Prior art keywords
- tailings
- oil sands
- water
- calcium oxide
- blended
- 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.)
- Active
Links
- 238000000034 method Methods 0.000 title claims description 45
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 title claims description 42
- 229910002092 carbon dioxide Inorganic materials 0.000 title claims description 24
- BRPQOXSCLDDYGP-UHFFFAOYSA-N calcium oxide Chemical compound [O-2].[Ca+2] BRPQOXSCLDDYGP-UHFFFAOYSA-N 0.000 title claims description 16
- 239000001569 carbon dioxide Substances 0.000 title claims description 7
- 235000008733 Citrus aurantifolia Nutrition 0.000 title abstract description 7
- 235000011941 Tilia x europaea Nutrition 0.000 title abstract description 7
- 239000004571 lime Substances 0.000 title abstract description 7
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 121
- 238000000605 extraction Methods 0.000 claims abstract description 35
- 239000007787 solid Substances 0.000 claims abstract description 28
- 239000002562 thickening agent Substances 0.000 claims abstract description 23
- 239000010426 asphalt Substances 0.000 claims abstract description 22
- AXCZMVOFGPJBDE-UHFFFAOYSA-L calcium dihydroxide Chemical compound [OH-].[OH-].[Ca+2] AXCZMVOFGPJBDE-UHFFFAOYSA-L 0.000 claims description 62
- 239000000920 calcium hydroxide Substances 0.000 claims description 62
- 229910001861 calcium hydroxide Inorganic materials 0.000 claims description 62
- 239000000292 calcium oxide Substances 0.000 claims description 29
- ODINCKMPIJJUCX-UHFFFAOYSA-N calcium oxide Inorganic materials [Ca]=O ODINCKMPIJJUCX-UHFFFAOYSA-N 0.000 claims description 18
- 239000004576 sand Substances 0.000 claims description 12
- 238000005204 segregation Methods 0.000 claims description 10
- 239000002002 slurry Substances 0.000 claims description 10
- 238000002156 mixing Methods 0.000 claims description 9
- 238000011144 upstream manufacturing Methods 0.000 claims 1
- 239000000203 mixture Substances 0.000 abstract description 18
- 239000000126 substance Substances 0.000 abstract description 13
- 229910001424 calcium ion Inorganic materials 0.000 abstract description 11
- 238000007596 consolidation process Methods 0.000 abstract description 11
- 238000004519 manufacturing process Methods 0.000 abstract description 8
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 abstract description 6
- 229910001425 magnesium ion Inorganic materials 0.000 abstract description 5
- JLVVSXFLKOJNIY-UHFFFAOYSA-N Magnesium ion Chemical compound [Mg+2] JLVVSXFLKOJNIY-UHFFFAOYSA-N 0.000 abstract description 4
- 235000011116 calcium hydroxide Nutrition 0.000 description 60
- 239000003921 oil Substances 0.000 description 48
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 35
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 26
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 21
- 238000006243 chemical reaction Methods 0.000 description 21
- 239000004927 clay Substances 0.000 description 19
- 229910000019 calcium carbonate Inorganic materials 0.000 description 18
- 230000008569 process Effects 0.000 description 15
- 229910000029 sodium carbonate Inorganic materials 0.000 description 14
- 239000011734 sodium Substances 0.000 description 13
- 235000017550 sodium carbonate Nutrition 0.000 description 13
- 150000002500 ions Chemical class 0.000 description 10
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 9
- 239000002253 acid Substances 0.000 description 9
- 229910000020 calcium bicarbonate Inorganic materials 0.000 description 9
- 150000007513 acids Chemical class 0.000 description 8
- 230000015572 biosynthetic process Effects 0.000 description 8
- 239000002245 particle Substances 0.000 description 8
- 230000009467 reduction Effects 0.000 description 8
- 239000013078 crystal Substances 0.000 description 7
- -1 hydrogen ions Chemical class 0.000 description 7
- 238000002347 injection Methods 0.000 description 7
- 239000007924 injection Substances 0.000 description 7
- 235000011121 sodium hydroxide Nutrition 0.000 description 7
- 239000007900 aqueous suspension Substances 0.000 description 5
- 230000008901 benefit Effects 0.000 description 5
- 230000003750 conditioning effect Effects 0.000 description 5
- 239000006185 dispersion Substances 0.000 description 5
- 238000005189 flocculation Methods 0.000 description 5
- 230000016615 flocculation Effects 0.000 description 5
- 239000000725 suspension Substances 0.000 description 5
- 239000003518 caustics Substances 0.000 description 4
- 239000003027 oil sand Substances 0.000 description 4
- JTJMJGYZQZDUJJ-UHFFFAOYSA-N phencyclidine Chemical class C1CCCCN1C1(C=2C=CC=CC=2)CCCCC1 JTJMJGYZQZDUJJ-UHFFFAOYSA-N 0.000 description 4
- 239000000654 additive Substances 0.000 description 3
- 239000011148 porous material Substances 0.000 description 3
- 239000002244 precipitate Substances 0.000 description 3
- 229910001415 sodium ion Inorganic materials 0.000 description 3
- 238000001179 sorption measurement Methods 0.000 description 3
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 description 2
- 238000009825 accumulation Methods 0.000 description 2
- 239000012736 aqueous medium Substances 0.000 description 2
- 239000008346 aqueous phase Substances 0.000 description 2
- 239000011575 calcium Substances 0.000 description 2
- NKWPZUCBCARRDP-UHFFFAOYSA-L calcium bicarbonate Chemical compound [Ca+2].OC([O-])=O.OC([O-])=O NKWPZUCBCARRDP-UHFFFAOYSA-L 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- 239000012530 fluid Substances 0.000 description 2
- 238000005342 ion exchange Methods 0.000 description 2
- 230000007774 longterm Effects 0.000 description 2
- 238000001556 precipitation Methods 0.000 description 2
- 238000011084 recovery Methods 0.000 description 2
- 239000004094 surface-active agent Substances 0.000 description 2
- 230000008719 thickening Effects 0.000 description 2
- 239000002351 wastewater Substances 0.000 description 2
- 238000003809 water extraction Methods 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 description 1
- 230000000996 additive effect Effects 0.000 description 1
- 229910052925 anhydrite Inorganic materials 0.000 description 1
- 150000001450 anions Chemical class 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 125000003118 aryl group Chemical group 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical group [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 159000000007 calcium salts Chemical class 0.000 description 1
- OSGAYBCDTDRGGQ-UHFFFAOYSA-L calcium sulfate Chemical compound [Ca+2].[O-]S([O-])(=O)=O OSGAYBCDTDRGGQ-UHFFFAOYSA-L 0.000 description 1
- 150000001768 cations Chemical class 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000013626 chemical specie Substances 0.000 description 1
- 230000002301 combined effect Effects 0.000 description 1
- 239000002131 composite material Substances 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 230000001627 detrimental effect Effects 0.000 description 1
- 239000002270 dispersing agent Substances 0.000 description 1
- 230000002708 enhancing effect Effects 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 238000005188 flotation Methods 0.000 description 1
- 229910052602 gypsum Inorganic materials 0.000 description 1
- 239000010440 gypsum Substances 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 238000006460 hydrolysis reaction Methods 0.000 description 1
- 239000011777 magnesium Substances 0.000 description 1
- VTHJTEIRLNZDEV-UHFFFAOYSA-L magnesium dihydroxide Chemical compound [OH-].[OH-].[Mg+2] VTHJTEIRLNZDEV-UHFFFAOYSA-L 0.000 description 1
- 239000000347 magnesium hydroxide Substances 0.000 description 1
- 235000012254 magnesium hydroxide Nutrition 0.000 description 1
- 229910001862 magnesium hydroxide Inorganic materials 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 238000005065 mining Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 150000002894 organic compounds Chemical class 0.000 description 1
- ISWSIDIOOBJBQZ-UHFFFAOYSA-N phenol group Chemical group C1(=CC=CC=C1)O ISWSIDIOOBJBQZ-UHFFFAOYSA-N 0.000 description 1
- 230000001376 precipitating effect Effects 0.000 description 1
- 230000001737 promoting effect Effects 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 238000000518 rheometry Methods 0.000 description 1
- 239000013049 sediment Substances 0.000 description 1
- 235000017557 sodium bicarbonate Nutrition 0.000 description 1
- 229910000030 sodium bicarbonate Inorganic materials 0.000 description 1
- 239000007762 w/o emulsion Substances 0.000 description 1
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
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B03—SEPARATION OF SOLID MATERIALS USING LIQUIDS OR USING PNEUMATIC TABLES OR JIGS; MAGNETIC OR ELECTROSTATIC SEPARATION OF SOLID MATERIALS FROM SOLID MATERIALS OR FLUIDS; SEPARATION BY HIGH-VOLTAGE ELECTRIC FIELDS
- B03B—SEPARATING SOLID MATERIALS USING LIQUIDS OR USING PNEUMATIC TABLES OR JIGS
- B03B9/00—General arrangement of separating plant, e.g. flow sheets
- B03B9/02—General arrangement of separating plant, e.g. flow sheets specially adapted for oil-sand, oil-chalk, oil-shales, ozokerite, bitumen, or the like
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B09—DISPOSAL OF SOLID WASTE; RECLAMATION OF CONTAMINATED SOIL
- B09B—DISPOSAL OF SOLID WASTE NOT OTHERWISE PROVIDED FOR
- B09B3/00—Destroying solid waste or transforming solid waste into something useful or harmless
- B09B3/20—Agglomeration, binding or encapsulation of solid waste
- B09B3/25—Agglomeration, binding or encapsulation of solid waste using mineral binders or matrix
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F1/00—Treatment of water, waste water, or sewage
- C02F1/52—Treatment of water, waste water, or sewage by flocculation or precipitation of suspended impurities
- C02F1/54—Treatment of water, waste water, or sewage by flocculation or precipitation of suspended impurities using organic material
- C02F1/56—Macromolecular compounds
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
- C10G1/04—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by extraction
- C10G1/047—Hot water or cold water extraction processes
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F11/00—Treatment of sludge; Devices therefor
- C02F11/12—Treatment of sludge; Devices therefor by de-watering, drying or thickening
- C02F11/14—Treatment of sludge; Devices therefor by de-watering, drying or thickening with addition of chemical agents
- C02F11/148—Combined use of inorganic and organic substances, being added in the same treatment step
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
- C02F2103/007—Contaminated open waterways, rivers, lakes or ponds
Landscapes
- Chemical & Material Sciences (AREA)
- Engineering & Computer Science (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Life Sciences & Earth Sciences (AREA)
- Organic Chemistry (AREA)
- General Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Wood Science & Technology (AREA)
- Environmental & Geological Engineering (AREA)
- Hydrology & Water Resources (AREA)
- Water Supply & Treatment (AREA)
- Geology (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
The present invention relates to the treatment of oil sands tailings with CaO lime or with CaO lime and CO2, to achieve improved non-segregating consolidation of the solids in the tailings, and to recover the release water with acceptable chemical properties for its use in the bitumen extraction process. Non-segregating tailings are produced from the blend of cyclone underflow and thickener underflow, or from the blend of cyclone underflow, thickener underflow, and mature fine tails, by treating the tailings mix with CaO or CaO and CO2 at proper dosages, with the resultant simultaneous production of release water having lower concentrations of Ca2+, Mg2+, Na+, Cl- ions, ultra fines, and color- making organic species concentrations.
Description
METHOD FOR TREATMENT OF OIL SANDS TAILINGS
WITH LIME OR WITH LIME AND CARBON DIOXIDE
FIELD OF THE INVENTION
The present invention is directed to methods for the treatment of oil sands tailings to achieve non-segregating consolidation of the solids in the tailings, and to recover the release water with acceptable chemical properties for its use in the bitumen extraction process.
BACKGROUND OF THE INVENTION
Over 700,000 barrels of synthetic crude oil are produced daily by commercial plants engaged in surface mining of Athabasca oil sands in Northern Alberta. At these plants, bitumen is extracted from oil sands using caustic and non-caustic water slurry-based extraction processes. An average sample of surface-mineable Athabasca oil sand ore contains about 11 % bitumen (by weight), 3-6% water, 12% fines (less than 44 microns) and 72% sand.
Water slurry-based extraction processes use large volumes of water: the production of each cubic meter of bitumen produced require about 7 to 9 cubic meters of water, of which about 70% is recycled from the surface zone of the tailings pond. In this process, about 0.3 cubic meters of water per ton of oil sands feed is withdrawn from the Athabasca River.
Commercial plants operating in the Athabasca oil sands must comply with regulatory requirements which stipulate no discharge of process-affected water. As a result of this "zero discharge" policy, waste water containment ponds are formed and waste water (including drainage and other sources) and tailings are discharged into these ponds.
During the extraction of bitumen from the oil sands by water slurry-based extraction processes, a coarse tailings stream is produced in the form of a slurry, containing about 55%
solids (by weight), of which about 82% is sand, about 17% is fines smaller than 44 microns in diameter, and about I% is unrecovered bitumen.
In early tailings disposal practice, the oil sands tailings discharged from the extraction plant were hydraulically transported and deposited in the tailings ponds. In this process, the coarse sand particles segregate quickly and form a beach. The remaining fine tails of 6 to 10 percent weight accumulate in the tailings ponds. Fine tails settle quickly, forming a suspension of 20 percent weight solids content and over a few years to 30 percent weight solids (85 percent water by volume) with a stable slurry structure, which is called mature fine tails (also called MFT). Mature fine tails remain in a fluid state for centuries because of their very slow consolidation rate. It is predicted that if the conventional tailings disposal practice is continued, the accumulated volume of mature fine tails will increase from the current level of 325 million cubic meters to over 1 billion cubic meters by the year 2020.
Accumulation of large volumes of mature fine tails with a very stable fluid structure creates environmental concerns and a long-term environmental liability.
To eliminate formation of the mature fine tails, or to reduce the inventory of the existing mature fine tails, a method was developed to produce a nonsegregating tailings mix (also called consolidated tailings or composite tailings or CT) for the disposal of the oil sands tailings. In this method, the coarse tailings are passed through cyclones, the sand-rich cyclone underflow (typically having at least about 90% sand) is blended with the mature fine tails (comprising about 30-33% solids, which in turn comprise about 98% fines) to produce a nonsegregating mix for final disposal. In this process, chemical additives such as gypsum (CaSO4) are used to prevent segregation. Also in this process, the fines-rich cyclone overflow (with about 20-30% solids, comprising about 50% fines) is discharged to a tailings pond. The fines in the cyclone overflow stream also form the mature fine tailings, which is a concern for long-term operations.
As low-temperature or low-energy bitumen extraction processes became adopted by commercial plants, it became desirable to achieve fast recovery of the process water from the tailings stream to save thermal energy. As a result, the cyclone overflow stream was thickened in thickeners, with the help of preferably polymeric flocculent.
Disposal of thickener underflow and cyclone underflow in an environmentally acceptable manner remains the challenge for the oil sands industry.
WITH LIME OR WITH LIME AND CARBON DIOXIDE
FIELD OF THE INVENTION
The present invention is directed to methods for the treatment of oil sands tailings to achieve non-segregating consolidation of the solids in the tailings, and to recover the release water with acceptable chemical properties for its use in the bitumen extraction process.
BACKGROUND OF THE INVENTION
Over 700,000 barrels of synthetic crude oil are produced daily by commercial plants engaged in surface mining of Athabasca oil sands in Northern Alberta. At these plants, bitumen is extracted from oil sands using caustic and non-caustic water slurry-based extraction processes. An average sample of surface-mineable Athabasca oil sand ore contains about 11 % bitumen (by weight), 3-6% water, 12% fines (less than 44 microns) and 72% sand.
Water slurry-based extraction processes use large volumes of water: the production of each cubic meter of bitumen produced require about 7 to 9 cubic meters of water, of which about 70% is recycled from the surface zone of the tailings pond. In this process, about 0.3 cubic meters of water per ton of oil sands feed is withdrawn from the Athabasca River.
Commercial plants operating in the Athabasca oil sands must comply with regulatory requirements which stipulate no discharge of process-affected water. As a result of this "zero discharge" policy, waste water containment ponds are formed and waste water (including drainage and other sources) and tailings are discharged into these ponds.
During the extraction of bitumen from the oil sands by water slurry-based extraction processes, a coarse tailings stream is produced in the form of a slurry, containing about 55%
solids (by weight), of which about 82% is sand, about 17% is fines smaller than 44 microns in diameter, and about I% is unrecovered bitumen.
In early tailings disposal practice, the oil sands tailings discharged from the extraction plant were hydraulically transported and deposited in the tailings ponds. In this process, the coarse sand particles segregate quickly and form a beach. The remaining fine tails of 6 to 10 percent weight accumulate in the tailings ponds. Fine tails settle quickly, forming a suspension of 20 percent weight solids content and over a few years to 30 percent weight solids (85 percent water by volume) with a stable slurry structure, which is called mature fine tails (also called MFT). Mature fine tails remain in a fluid state for centuries because of their very slow consolidation rate. It is predicted that if the conventional tailings disposal practice is continued, the accumulated volume of mature fine tails will increase from the current level of 325 million cubic meters to over 1 billion cubic meters by the year 2020.
Accumulation of large volumes of mature fine tails with a very stable fluid structure creates environmental concerns and a long-term environmental liability.
To eliminate formation of the mature fine tails, or to reduce the inventory of the existing mature fine tails, a method was developed to produce a nonsegregating tailings mix (also called consolidated tailings or composite tailings or CT) for the disposal of the oil sands tailings. In this method, the coarse tailings are passed through cyclones, the sand-rich cyclone underflow (typically having at least about 90% sand) is blended with the mature fine tails (comprising about 30-33% solids, which in turn comprise about 98% fines) to produce a nonsegregating mix for final disposal. In this process, chemical additives such as gypsum (CaSO4) are used to prevent segregation. Also in this process, the fines-rich cyclone overflow (with about 20-30% solids, comprising about 50% fines) is discharged to a tailings pond. The fines in the cyclone overflow stream also form the mature fine tailings, which is a concern for long-term operations.
As low-temperature or low-energy bitumen extraction processes became adopted by commercial plants, it became desirable to achieve fast recovery of the process water from the tailings stream to save thermal energy. As a result, the cyclone overflow stream was thickened in thickeners, with the help of preferably polymeric flocculent.
Disposal of thickener underflow and cyclone underflow in an environmentally acceptable manner remains the challenge for the oil sands industry.
SUMMARY OF THE INVENTION
The present invention is based on the treatment of oil sands tailings, produced from a process involving water slurry-based extraction of bitumen from oil sand, with lime (Ca(OH)2) or with lime and carbon dioxide (C02). By the treatment of oil sands tailings with Ca(OH)2 or with Ca(OH)2 and C02, the oil sands tailings become a non-segregating mix; i.e., the sand and the fines sediment and consolidate together. Also by the treatment of oil sands tailings with Ca(OH)2 or with Ca(OH)2 and CO2, the release water recovered from the settled and consolidated tailings would have acceptable water chemistry characteristics in terms of reduced concentrations of calcium ions (Ca2+) , magnesium ions (Mg2+), sodium ions (Na'), and chloride ions (Cl-).
When the oil sand tailings are treated with Ca(OH)2, the following ion exchange reaction takes place between the clay and the tailings pore water, which results in flocculation of the clay particles, mainly (but not necessarily only) by the following reaction:
Ca(OH)2+2Clay-Na-->(Clay)2Ca+2NaOH (1) resulting in increase in the viscosity of the fines-water suspension, and the consequent formation of the yield stress which holds the sand particles in the fines-water suspension matrix and prevents the segregation of the sand particles. Treatment of oil sands tailings with Ca(OH)2 also reduces the activity of the asphaltic acids in the aqueous solution because of the formation of the insoluble calcium salts of the asphaltic acids, which results in an increase in surface and interfacial tension of the water, which promotes the clay flocculation.
Both excess Ca(OH)2 and sodium hydroxide (NaOH) produced by the reaction expressed in Equation (1) act as a base. As a result, the suspension and the release water pH
are kept above 7 (pH being expressed as the minus of the logarithm of the hydrogen ions concentration [H+]; i.e., pH = -log [H+], a scale to express the acidity of the matter).
When the oil sand tailings are treated with Ca(OH)2, the bicarbonate hardness caused mainly by the water-soluble calcium bicarbonate (Ca(HCO3)2 of the tailings is also reduced, by converting Ca(HCO3)2) into water-insoluble calcium carbonate (CaCO3) by the following reactions:
The present invention is based on the treatment of oil sands tailings, produced from a process involving water slurry-based extraction of bitumen from oil sand, with lime (Ca(OH)2) or with lime and carbon dioxide (C02). By the treatment of oil sands tailings with Ca(OH)2 or with Ca(OH)2 and C02, the oil sands tailings become a non-segregating mix; i.e., the sand and the fines sediment and consolidate together. Also by the treatment of oil sands tailings with Ca(OH)2 or with Ca(OH)2 and CO2, the release water recovered from the settled and consolidated tailings would have acceptable water chemistry characteristics in terms of reduced concentrations of calcium ions (Ca2+) , magnesium ions (Mg2+), sodium ions (Na'), and chloride ions (Cl-).
When the oil sand tailings are treated with Ca(OH)2, the following ion exchange reaction takes place between the clay and the tailings pore water, which results in flocculation of the clay particles, mainly (but not necessarily only) by the following reaction:
Ca(OH)2+2Clay-Na-->(Clay)2Ca+2NaOH (1) resulting in increase in the viscosity of the fines-water suspension, and the consequent formation of the yield stress which holds the sand particles in the fines-water suspension matrix and prevents the segregation of the sand particles. Treatment of oil sands tailings with Ca(OH)2 also reduces the activity of the asphaltic acids in the aqueous solution because of the formation of the insoluble calcium salts of the asphaltic acids, which results in an increase in surface and interfacial tension of the water, which promotes the clay flocculation.
Both excess Ca(OH)2 and sodium hydroxide (NaOH) produced by the reaction expressed in Equation (1) act as a base. As a result, the suspension and the release water pH
are kept above 7 (pH being expressed as the minus of the logarithm of the hydrogen ions concentration [H+]; i.e., pH = -log [H+], a scale to express the acidity of the matter).
When the oil sand tailings are treated with Ca(OH)2, the bicarbonate hardness caused mainly by the water-soluble calcium bicarbonate (Ca(HCO3)2 of the tailings is also reduced, by converting Ca(HCO3)2) into water-insoluble calcium carbonate (CaCO3) by the following reactions:
Ca(HCO3)2 +Ca(OH)2 -+ 2CaCO3 + 2H20 (2) Ca(HCO3)2 +2NaOH --- CaCO3 +Na2CO3 + 2H20 (3) As an example, Ca2+ ions concentration in the release water recovered from the untreated tailings was at about 60 mg/L (milligram per liter), while Ca 2+
ions concentration in the release water recovered from the tailings treated with Ca(OH)2 was at about 30 mg/L.
Sodium carbonate (Na2CO3) produced by the chemical reaction expressed by Equation (3) also promotes the basic nature of the suspension and the release water; for example, it helps the pH to be greater than 7 by the hydrolysis reaction:
Na2CO3 + H2 0 -* NaHCO3 + Na + + OH- (4) When oil sands tailings are treated with Ca(OH)2, the release water recovered from the tailings contains the excess Ca(OH)2, NaOH, and Na2CO3 as a result of the chemical reactions expressed in Equations (1) and (3). If the release water is blended with the make-up water (e.g., river water, recycle water) or with any water with bicarbonate hardness for its use in the extraction process, the chemical species Ca(OH)2, NaOH, and Na2CO3 contained in the release water reduces the bicarbonate hardness by the chemical reactions expressed in Equation (2), Equation (3) as well as by the following chemical reactions:
Ca(HCO3 )2 + Na2CO3 -> CaCO3 + 2NaOH + 2CO2 (5) by which the water soluble Ca(HCO3)2 is converted to water insoluble CaCO3.
Also, because of the nature of the species produced by the chemical reactions expressed by Equations (1), (3), (4), and (5), the pH of the blended water would be basic; i.e., the pH of the blended water would be greater than 7. The pH of the blended water would be determined, however, by the dosage of Ca(OH)2 treatment, the solids content, the fines content or fines-to-sand ratio (SFP), or more specifically the clay content of the tailings and the exposure of the water (release water, recycle water or blended water, or the tailings) to the atmospheric C02, which could diffuse into the aqueous phase and acts as acid and reduces the pH by a reaction such as (but not limited to) the following:
Ca(OH)2 + CO2 -* CaCO3 + H2O (6) When Ca(OH)2 is used to treat oil sands tailings, the blended water (obtained from the blend of the release water with the make-up water, for its use in the extraction process) would have a pH higher than 7. Since the pH of the blended water is greater than 7, the bitumen extraction process would work better since the asphaltic acids contained in bitumen would be water soluble and would act as surfactants. Further, it would decrease surface tension and interfacial tension of the water, thus promoting clay dispersion and bitumen extraction efficiency. As a result, conditions favoring higher extraction efficiency by better dispersing the clays in the extraction process, however, would produce a tailings stream with difficult properties to handle since the fines and clay particles in the tailings would be more attractive to the water. This difficulty, however, could be overcome by treating the oil sands tailings with Ca(OH)2 in the first place.
If needed, the excess amount of Ca(OH)2 added into the oil sands tailings could be reduced by the controlled injection of CO2 into tailings after treating the tailings with Ca(OH)2 or by controlled injection of CO2 into the release water. When CO2 is injected in a controlled manner (i.e., by keeping the final pH of the tailings suspension or the release water preferably in the range of 11.0 < pH < 11.6), the Ca 2+ content in the aqueous media could be reduced to at about 30 mg/L range without causing any change in the segregating property of the tailings, by precipitating Ca(OH)2 in the form of CaCO3 by the chemical reaction expressed in Equation (6).
Uncontrolled or excessive injection of CO2 into the tailings after treating it with Ca(OH)2 or into the release water may cause the reduction of the pH in the range where water-soluble calcium bicarbonate would be formed by the following reaction:
CaCO3 +CO2 +H2O -> Ca(HCO3)2 (7) which causes an increase in the Ca 2+ ions concentration in the release water which could harm the bitumen extraction efficiency if the release water is recycled to the extraction plant.
Also, the chemical reaction expressed in Equation (7) would cause segregation of the tailings.
ions concentration in the release water recovered from the tailings treated with Ca(OH)2 was at about 30 mg/L.
Sodium carbonate (Na2CO3) produced by the chemical reaction expressed by Equation (3) also promotes the basic nature of the suspension and the release water; for example, it helps the pH to be greater than 7 by the hydrolysis reaction:
Na2CO3 + H2 0 -* NaHCO3 + Na + + OH- (4) When oil sands tailings are treated with Ca(OH)2, the release water recovered from the tailings contains the excess Ca(OH)2, NaOH, and Na2CO3 as a result of the chemical reactions expressed in Equations (1) and (3). If the release water is blended with the make-up water (e.g., river water, recycle water) or with any water with bicarbonate hardness for its use in the extraction process, the chemical species Ca(OH)2, NaOH, and Na2CO3 contained in the release water reduces the bicarbonate hardness by the chemical reactions expressed in Equation (2), Equation (3) as well as by the following chemical reactions:
Ca(HCO3 )2 + Na2CO3 -> CaCO3 + 2NaOH + 2CO2 (5) by which the water soluble Ca(HCO3)2 is converted to water insoluble CaCO3.
Also, because of the nature of the species produced by the chemical reactions expressed by Equations (1), (3), (4), and (5), the pH of the blended water would be basic; i.e., the pH of the blended water would be greater than 7. The pH of the blended water would be determined, however, by the dosage of Ca(OH)2 treatment, the solids content, the fines content or fines-to-sand ratio (SFP), or more specifically the clay content of the tailings and the exposure of the water (release water, recycle water or blended water, or the tailings) to the atmospheric C02, which could diffuse into the aqueous phase and acts as acid and reduces the pH by a reaction such as (but not limited to) the following:
Ca(OH)2 + CO2 -* CaCO3 + H2O (6) When Ca(OH)2 is used to treat oil sands tailings, the blended water (obtained from the blend of the release water with the make-up water, for its use in the extraction process) would have a pH higher than 7. Since the pH of the blended water is greater than 7, the bitumen extraction process would work better since the asphaltic acids contained in bitumen would be water soluble and would act as surfactants. Further, it would decrease surface tension and interfacial tension of the water, thus promoting clay dispersion and bitumen extraction efficiency. As a result, conditions favoring higher extraction efficiency by better dispersing the clays in the extraction process, however, would produce a tailings stream with difficult properties to handle since the fines and clay particles in the tailings would be more attractive to the water. This difficulty, however, could be overcome by treating the oil sands tailings with Ca(OH)2 in the first place.
If needed, the excess amount of Ca(OH)2 added into the oil sands tailings could be reduced by the controlled injection of CO2 into tailings after treating the tailings with Ca(OH)2 or by controlled injection of CO2 into the release water. When CO2 is injected in a controlled manner (i.e., by keeping the final pH of the tailings suspension or the release water preferably in the range of 11.0 < pH < 11.6), the Ca 2+ content in the aqueous media could be reduced to at about 30 mg/L range without causing any change in the segregating property of the tailings, by precipitating Ca(OH)2 in the form of CaCO3 by the chemical reaction expressed in Equation (6).
Uncontrolled or excessive injection of CO2 into the tailings after treating it with Ca(OH)2 or into the release water may cause the reduction of the pH in the range where water-soluble calcium bicarbonate would be formed by the following reaction:
CaCO3 +CO2 +H2O -> Ca(HCO3)2 (7) which causes an increase in the Ca 2+ ions concentration in the release water which could harm the bitumen extraction efficiency if the release water is recycled to the extraction plant.
Also, the chemical reaction expressed in Equation (7) would cause segregation of the tailings.
It has been observed experimentally by the inventor that the injection of CO2 into tailings appears to help flotation of the residual bitumen in the form of a water-in-oil emulsion.
Formation of the fresh CaCO3 crystals in the tailings as a result of the chemical reactions expressed in Equations (2), (3), (5), and (6) would result in the adsorption of the ultra fines (i.e., clay particles smaller than 0.2 m size) on the surface of newly formed CaCO3 crystal and precipitate them together with it, which results in reduction of the gel formation property of the tailings, since the ultra fines content of the tailings is partly responsible for the gel formation strength of the oil sands tailings. Also, the formation of the fresh CaCO3 crystals in the tailings would result in the adsorption of Na' and Cl- ions, on the surface of newly-formed CaCO3 crystals and precipitate them together with it, which results in the reduction of the Na' and Cl" ions in the release water recovered from the tailings. As an example, Na' ions concentration in the release water recovered from the untreated tailings was at about 130 mg/L, while Na' ions concentration in the release water recovered from the tailings treated with Ca(OH)2 was at about 115 mg/L.
Similarly, formation of the fresh CaCO3 crystals in the release water or any kind of blended water obtained by blending the release water with the make-up water, as a result of the chemical reactions expressed in Equations (2), (3), (5), and (6), would result in the adsorption of Na' and Cl- ions, and even the organic compounds responsible for the coloration of the water, on the surface of newly-formed CaCO3 crystal surface and precipitated together with it, which results in the reduction of the Na' and Cl- ions, and even in the reduction of the coloration of the water.
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments of the invention will now be described with reference to the accompanying figures, in which numerical references denote like parts, and in which:
FIGURE 1 is a schematic flow chart of a method of treating oil sands tailings in accordance with a first embodiment of the present invention.
Formation of the fresh CaCO3 crystals in the tailings as a result of the chemical reactions expressed in Equations (2), (3), (5), and (6) would result in the adsorption of the ultra fines (i.e., clay particles smaller than 0.2 m size) on the surface of newly formed CaCO3 crystal and precipitate them together with it, which results in reduction of the gel formation property of the tailings, since the ultra fines content of the tailings is partly responsible for the gel formation strength of the oil sands tailings. Also, the formation of the fresh CaCO3 crystals in the tailings would result in the adsorption of Na' and Cl- ions, on the surface of newly-formed CaCO3 crystals and precipitate them together with it, which results in the reduction of the Na' and Cl" ions in the release water recovered from the tailings. As an example, Na' ions concentration in the release water recovered from the untreated tailings was at about 130 mg/L, while Na' ions concentration in the release water recovered from the tailings treated with Ca(OH)2 was at about 115 mg/L.
Similarly, formation of the fresh CaCO3 crystals in the release water or any kind of blended water obtained by blending the release water with the make-up water, as a result of the chemical reactions expressed in Equations (2), (3), (5), and (6), would result in the adsorption of Na' and Cl- ions, and even the organic compounds responsible for the coloration of the water, on the surface of newly-formed CaCO3 crystal surface and precipitated together with it, which results in the reduction of the Na' and Cl- ions, and even in the reduction of the coloration of the water.
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments of the invention will now be described with reference to the accompanying figures, in which numerical references denote like parts, and in which:
FIGURE 1 is a schematic flow chart of a method of treating oil sands tailings in accordance with a first embodiment of the present invention.
FIGURE 2 is is a schematic flow chart of a method of treating oil sands tailings in accordance with a second embodiment of the invention.
DESCRIPTION OF THE PREFERRED EMBODIMENT
Experiments performed by the inventor have indicated that treatment of oil sands tailings with Ca(OH)2 improves the nonsegregating, settling and consolidation characteristics of the oil sands tailings. It is known that oil sands tailings have the tendency to become a nonsegregating mix as the solids content increases and as the fines content (i.e., fraction of the solids smaller than 325 mesh or 44 micron size) increases. Addition of Ca2+ ions into the oil sands tailings improves the nonsegregation behavior of the tailings; for example, it pushes the segregation boundary towards a lower solids content region.
It is important that segregation boundary lines (i.e., the lines of solids contents for various fines contents or SFRs, lower than which the tailings behave segregatingly, and higher than which the tailings behave non-segregatingly) for the tailings, both without any chemical additive and with different chemical additives, are parallel to the fixed fines-water ratio lines (the fines-water ratio being defined as the ratio of the fines/(fines + water) on mass basis), which is the indication that rheological characteristics of the fines-water suspension control the segregation behavior of the tailings. Addition of chemicals such as Ca(OH)2 into the oil sands tailings changes the rheology of the fines-water suspension;
i.e., forms sufficient yield stress and prevents segregation.
It is known that asphaltic acids present in oil sands bitumen become water soluble when the oil sands ore water suspension pH is kept slightly above 7. These asphaltic acids are partly aromatic in nature and contain oxygen functional groups of phenolic, carboxylic and sulphonic types. When the asphaltic acids become water soluble, they act as surfactants and reduce the surface and interfacial tension of the water (aqueous media);
as a result, they act as clay dispersants and promote the liberation of bitumen, thus enhancing the bitumen recovery efficiency of the extraction process. The conditions favoring clay dispersion in extraction process also favor production of oil sands tailings with difficult settling and consolidation characteristics.
DESCRIPTION OF THE PREFERRED EMBODIMENT
Experiments performed by the inventor have indicated that treatment of oil sands tailings with Ca(OH)2 improves the nonsegregating, settling and consolidation characteristics of the oil sands tailings. It is known that oil sands tailings have the tendency to become a nonsegregating mix as the solids content increases and as the fines content (i.e., fraction of the solids smaller than 325 mesh or 44 micron size) increases. Addition of Ca2+ ions into the oil sands tailings improves the nonsegregation behavior of the tailings; for example, it pushes the segregation boundary towards a lower solids content region.
It is important that segregation boundary lines (i.e., the lines of solids contents for various fines contents or SFRs, lower than which the tailings behave segregatingly, and higher than which the tailings behave non-segregatingly) for the tailings, both without any chemical additive and with different chemical additives, are parallel to the fixed fines-water ratio lines (the fines-water ratio being defined as the ratio of the fines/(fines + water) on mass basis), which is the indication that rheological characteristics of the fines-water suspension control the segregation behavior of the tailings. Addition of chemicals such as Ca(OH)2 into the oil sands tailings changes the rheology of the fines-water suspension;
i.e., forms sufficient yield stress and prevents segregation.
It is known that asphaltic acids present in oil sands bitumen become water soluble when the oil sands ore water suspension pH is kept slightly above 7. These asphaltic acids are partly aromatic in nature and contain oxygen functional groups of phenolic, carboxylic and sulphonic types. When the asphaltic acids become water soluble, they act as surfactants and reduce the surface and interfacial tension of the water (aqueous media);
as a result, they act as clay dispersants and promote the liberation of bitumen, thus enhancing the bitumen recovery efficiency of the extraction process. The conditions favoring clay dispersion in extraction process also favor production of oil sands tailings with difficult settling and consolidation characteristics.
As stated earlier, presence of water-soluble asphaltic acids in the tailings promote the clay dispersion. Addition of small quantities of Ca2+ ions into the tailings reduces the activity of asphaltic acids in the aqueous phase. This results in an increase in surface and interfacial tension, which promotes the clay (and fines) flocculation, in addition to the mechanism of clay bonding by Ca2+ ions as explained by the chemical reaction expressed in Equation (1). Therefore, addition of a small quantity of Ca2+ ions into the tailings suspension by treating the tailings with Ca(OH)2 would promote flocculation of clay and fines, and would promote the nonsegregating property of the tailings. Also, addition of small quantity of CaO, as small as 0.4 g/L CaO, into oil sands tailings increases the pH, which results in the precipitation of the Mg2+ ions in the form of Mg(OH)2, therefore resulting in the production of a release water with Mg2+ concentration less than 1.8 mg/L.
The Mg 2+ concentration of the release water produced from oil sands tailings without Ca(OH)2 treatment was about 24 mg/L.
Treatment of the tailings with Ca(OH)2 provides additional advantages as discussed in the "Summary of the Invention" section of the present patent application.
Treatment of oil sands tailings with Ca(OH)2 reduces bicarbonate hardness in the tailings by converting Ca(HCO3)2 to CaCO3. Also, Ca 2+ ions in the release water caused by excessive dosage of Ca(OH)2 could be reduced by controlled injection of CO2 into tailings or by controlled injection of CO2 into the release water. Furthermore, the release water could be treated, if needed, with soda ash (Na2C03) which precipitates excess Ca(OH)2 in form CaCO3 by the following reaction:
Ca(OH)2 + Na2CO3 -_> CaCO3 + 2NaOH (8) Production of caustic soda (NaOH) by the ion exchange reactions between the clay and Ca(OH)2 as explained by Equation (1) and by treating the release water containing excess Ca(OH)2 with Na2CO3 as explained by Equation (8) are additional advantages of using Ca(OH)2 for the treatment of oil sands tailings, because a valuable chemical NaOH, which costs about $1,000 per ton, could be produced from CaO time (when CaO is dissolved in water it forms Ca(OH)2 by the chemical reaction, CaO+H20---~Ca(OH)2), which costs about $50 per ton and Na2CO3 which costs about $100 per ton.
The Mg 2+ concentration of the release water produced from oil sands tailings without Ca(OH)2 treatment was about 24 mg/L.
Treatment of the tailings with Ca(OH)2 provides additional advantages as discussed in the "Summary of the Invention" section of the present patent application.
Treatment of oil sands tailings with Ca(OH)2 reduces bicarbonate hardness in the tailings by converting Ca(HCO3)2 to CaCO3. Also, Ca 2+ ions in the release water caused by excessive dosage of Ca(OH)2 could be reduced by controlled injection of CO2 into tailings or by controlled injection of CO2 into the release water. Furthermore, the release water could be treated, if needed, with soda ash (Na2C03) which precipitates excess Ca(OH)2 in form CaCO3 by the following reaction:
Ca(OH)2 + Na2CO3 -_> CaCO3 + 2NaOH (8) Production of caustic soda (NaOH) by the ion exchange reactions between the clay and Ca(OH)2 as explained by Equation (1) and by treating the release water containing excess Ca(OH)2 with Na2CO3 as explained by Equation (8) are additional advantages of using Ca(OH)2 for the treatment of oil sands tailings, because a valuable chemical NaOH, which costs about $1,000 per ton, could be produced from CaO time (when CaO is dissolved in water it forms Ca(OH)2 by the chemical reaction, CaO+H20---~Ca(OH)2), which costs about $50 per ton and Na2CO3 which costs about $100 per ton.
Precipitation of excess Ca 2, ions by the controlled injection of CO2 into oil sands tailings after its treatment with Ca(OH)2 provides another advantage. The ultra fine clay particles, cations and anions like Na' and Cl" and organic molecules causing color in the water are adsorbed on the freshly formed surfaces of the CaCO3 crystals and precipitated together with it, which results in faster water release rate and lower Na' ion concentration in the release water. Reduction of Na' in the release water would be another reason to use Ca(OH)2 for the treatment of oils ands tailings, since the accumulation of Na' in the recycle water over the years would have a detrimental effect on the extraction efficiency.
Based on the experimental evidence observed by the author of the present patent application, which are explained in "Summary of the Application" and "Description of the Preferred Embodiment" sections, oil sands tailings could be treated with CaO
or with CaO
and CO2 to improve its settling, consolidation and segregation characteristics and to produce a release water with acceptable water chemistry properties for its use in the extraction process, in the followings methods or their minor modifications could be used:
First Embodiment of the Method Figure 1 schematically illustrates a method of treating oil sands fines in accordance with a first embodiment of the invention. This method is suitable when the oil sands tailings discharged from the extraction plant are not of sufficiently high solids and fines contents to form a nonsegregating tailings even after treated with Ca(OH)2.
In this case, oil sands tailings are passed through cyclones, producing cyclone underflow and cyclone overflow streams. Depending on the plant operating conditions, cyclone underflow may be at about above 60% solids with 3% fines (i.e., 3% of the solids smaller than 44 micron size) and cyclone overflow could be at about above 15 percent solids with 50% fines (i.e., 50% of the solids smaller than 44 micron size). Cyclone overflow will be thickened in a thickener with the help of preferably polymeric flocculent to about over 40% solids content (fines content of the thickened tailings would be the same provided that all of the fines are flocculated and settled, and that the thickener overflow would not contain any fines).
Based on the experimental evidence observed by the author of the present patent application, which are explained in "Summary of the Application" and "Description of the Preferred Embodiment" sections, oil sands tailings could be treated with CaO
or with CaO
and CO2 to improve its settling, consolidation and segregation characteristics and to produce a release water with acceptable water chemistry properties for its use in the extraction process, in the followings methods or their minor modifications could be used:
First Embodiment of the Method Figure 1 schematically illustrates a method of treating oil sands fines in accordance with a first embodiment of the invention. This method is suitable when the oil sands tailings discharged from the extraction plant are not of sufficiently high solids and fines contents to form a nonsegregating tailings even after treated with Ca(OH)2.
In this case, oil sands tailings are passed through cyclones, producing cyclone underflow and cyclone overflow streams. Depending on the plant operating conditions, cyclone underflow may be at about above 60% solids with 3% fines (i.e., 3% of the solids smaller than 44 micron size) and cyclone overflow could be at about above 15 percent solids with 50% fines (i.e., 50% of the solids smaller than 44 micron size). Cyclone overflow will be thickened in a thickener with the help of preferably polymeric flocculent to about over 40% solids content (fines content of the thickened tailings would be the same provided that all of the fines are flocculated and settled, and that the thickener overflow would not contain any fines).
Then, the cyclone underflow and the thickener underflow will be blended at proper proportions and treated with Ca(OH)2 to produce a nonsegregating mix for its final disposal.
It is also possible to add existing mature fine tails (MFT, which is of about 33% solids and 98% fines, accumulated over the years as a result of the disposal of the hot water extraction process tailings) into the blend of cyclone underflow and thickener underflow, to improve the non-segregating characteristic of the tailings mix (although this may result in the reduction of settling and consolidation rates).
The dosage of Ca(OH)2 treatment could be as low as, but not limited to, the equivalent of 400 g/m3 (grams per cubic meter of tailings) of CaO, which would be the sufficient Ca(OH)2 dosage to produce a nonsegregating mix with acceptable settling and consolidation properties and to produce release water with acceptable water chemistry properties for its recycle to the extraction plant. The minimum dosage of Ca(OH)2 required in this process would be a function of the solids content, fines content (or sand-to-fines ratio, SFR, the ratio of the masses of sand to fines), and the extent of clay dispersion. The release water produced in accordance with this first embodiment of the method will contain reduced amounts of Cat+, Mgt+, Na+ and Cl" ions and lesser amount of ultra fines than the original tailings before the Ca(OH)2 treatment.
The Ca(OH)2 used for the treatment of the tailings would reduce the bicarbonate hardness of the tailings pore water. The remaining excess amount of the Ca(OH)2 and the chemicals produced by the chemical reactions as a result of the Ca(OH)2 treatment present in this release water could be used to reduce the bicarbonate hardness of the make-up water (which could be river water, recycle water, or water from any other suitable source). The thickener overflow, which is basically the process water recovered during the thickening of the cyclone overflow, could also be blended in any suitable proportions with the release water. A final water conditioning plant for the blended water (i.e., blend of the release water with fresh river water, thickener overflow, or water from another suitable source), by using CaO, CO2, Na2CO3 or another conventionally used water conditioning chemical, could be considered as an option.
It is also possible to add existing mature fine tails (MFT, which is of about 33% solids and 98% fines, accumulated over the years as a result of the disposal of the hot water extraction process tailings) into the blend of cyclone underflow and thickener underflow, to improve the non-segregating characteristic of the tailings mix (although this may result in the reduction of settling and consolidation rates).
The dosage of Ca(OH)2 treatment could be as low as, but not limited to, the equivalent of 400 g/m3 (grams per cubic meter of tailings) of CaO, which would be the sufficient Ca(OH)2 dosage to produce a nonsegregating mix with acceptable settling and consolidation properties and to produce release water with acceptable water chemistry properties for its recycle to the extraction plant. The minimum dosage of Ca(OH)2 required in this process would be a function of the solids content, fines content (or sand-to-fines ratio, SFR, the ratio of the masses of sand to fines), and the extent of clay dispersion. The release water produced in accordance with this first embodiment of the method will contain reduced amounts of Cat+, Mgt+, Na+ and Cl" ions and lesser amount of ultra fines than the original tailings before the Ca(OH)2 treatment.
The Ca(OH)2 used for the treatment of the tailings would reduce the bicarbonate hardness of the tailings pore water. The remaining excess amount of the Ca(OH)2 and the chemicals produced by the chemical reactions as a result of the Ca(OH)2 treatment present in this release water could be used to reduce the bicarbonate hardness of the make-up water (which could be river water, recycle water, or water from any other suitable source). The thickener overflow, which is basically the process water recovered during the thickening of the cyclone overflow, could also be blended in any suitable proportions with the release water. A final water conditioning plant for the blended water (i.e., blend of the release water with fresh river water, thickener overflow, or water from another suitable source), by using CaO, CO2, Na2CO3 or another conventionally used water conditioning chemical, could be considered as an option.
As indicated in Figure 1, the oil sands tailings optionally may also be treated with CaO lime (or Ca(OH)2) depending on the needs of the plant operation, preferably but not limited to (i) by adding CaO into the tailings before the cyclones, (ii) by adding CaO after blending the Thickener Underflow and Cyclone Underflow and Mature Fines Tailings (MFT) as optional, (iii) by adding CaO into the tailings before the cyclone, in the thickener, and after blending the Thickener Underflow and Cyclone Underflow and Mature Fines Tailings (MFT) as optional, or by any combination of these steps. Addition of CaO into the tailings before the cyclone or in the thickener provides a process option for the thickening process in the thickener due to the combined effects of polymeric flocculent and calcium ions (Ca2+) on the flocculation of clay size particles.
Second Embodiment of the Method Figure 2 schematically illustrates a method of treating oil sands fines in accordance with a second embodiment of the invention. This method is suitable when the oil sands tailings discharged from the extraction plant are of sufficiently high solids and fines contents to form a non-segregating tailings after being treated with Ca(OH)2.
In this case, the tailings treatment plant would not need to have cyclones and thickeners. Oil sands tailings treated with Ca(OH)2 would be of nonsegregating and of sufficiently fast-settling and consolidation properties. It is also possible to add existing mature fine tails (MFT, which is of about 33% solids and 98% fines, accumulated over the years as a result of the disposal of the hot water extraction process tailings) into the tailings discharged from the extraction plant, which would improve the nonsegregating characteristic of the tailings mix (although this may result in the reduction of settling and consolidation rates). The release water produced in accordance with this second embodiment of the method will contain reduced amounts of Ca2+, Mgt+, Na' and Cl- ions and lesser amount of ultra fines than the original tailings before the Ca(OH)2 treatment. The Ca(OH)2 used for the treatment of the tailings would reduce the bicarbonate hardness of the tailings pore water.
The remaining excess amount of the Ca(OH)2 and the chemicals produced by the chemical reactions as a result of the Ca(OH)2 treatment present in this release water could be used to reduce the bicarbonate hardness of the make-up water which could be the river water, the recycle water or water from any other suitable source. A final water conditioning plant for the blended water (i.e., blend of the release water with fresh river water, thickener overflow, or water from another suitable source) by using CaO, CO2, Na2CO3 or another conventionally used water conditioning chemical could be considered as an option.
Experimental studies performed by the inventor have indicated that the methods described herein could be used for the oil sands tailings produced by caustic or non-caustic, hot or cold water slurry-based extraction processes. The dosage of Ca(OH)2 treatment would be a function of the solids content and the sand-to-fines ratio of the tailings, the extent of clay dispersion in the extraction process (which is strongly dependent upon the pH
of the extraction process), and the composition of the make-up water to be blended with the release water produced from the tailings treated with Ca(OH)2.
Persons skilled in the field of the invention will appreciate that the present invention provides a variety of advantages and benefits, including the following:
1. Production of substantially non-segregating tailings with acceptable settling, consolidation and water release rate properties, with simultaneous production of release water with acceptable water chemistry characteristics for use in the bitumen extraction process.
2. Production of release water with lower concentrations of Cat+, Mgt+, Na+, ions, ultra fines, and color-making organic species concentrations.
3. Release water with excess Ca(OH)2 and other chemicals produced by treating the oil sands tailings with Ca(OH)2 may be used for the conditioning of the make-up water.
4. Existing inventories of mature fine tails (MFT) may be reduced by adding the MFT into the blend of cyclone underflow and thickener underflow, or into the whole tailings discharged from the extraction plant, depending on the composition of the tailings produced by the extraction process.
Second Embodiment of the Method Figure 2 schematically illustrates a method of treating oil sands fines in accordance with a second embodiment of the invention. This method is suitable when the oil sands tailings discharged from the extraction plant are of sufficiently high solids and fines contents to form a non-segregating tailings after being treated with Ca(OH)2.
In this case, the tailings treatment plant would not need to have cyclones and thickeners. Oil sands tailings treated with Ca(OH)2 would be of nonsegregating and of sufficiently fast-settling and consolidation properties. It is also possible to add existing mature fine tails (MFT, which is of about 33% solids and 98% fines, accumulated over the years as a result of the disposal of the hot water extraction process tailings) into the tailings discharged from the extraction plant, which would improve the nonsegregating characteristic of the tailings mix (although this may result in the reduction of settling and consolidation rates). The release water produced in accordance with this second embodiment of the method will contain reduced amounts of Ca2+, Mgt+, Na' and Cl- ions and lesser amount of ultra fines than the original tailings before the Ca(OH)2 treatment. The Ca(OH)2 used for the treatment of the tailings would reduce the bicarbonate hardness of the tailings pore water.
The remaining excess amount of the Ca(OH)2 and the chemicals produced by the chemical reactions as a result of the Ca(OH)2 treatment present in this release water could be used to reduce the bicarbonate hardness of the make-up water which could be the river water, the recycle water or water from any other suitable source. A final water conditioning plant for the blended water (i.e., blend of the release water with fresh river water, thickener overflow, or water from another suitable source) by using CaO, CO2, Na2CO3 or another conventionally used water conditioning chemical could be considered as an option.
Experimental studies performed by the inventor have indicated that the methods described herein could be used for the oil sands tailings produced by caustic or non-caustic, hot or cold water slurry-based extraction processes. The dosage of Ca(OH)2 treatment would be a function of the solids content and the sand-to-fines ratio of the tailings, the extent of clay dispersion in the extraction process (which is strongly dependent upon the pH
of the extraction process), and the composition of the make-up water to be blended with the release water produced from the tailings treated with Ca(OH)2.
Persons skilled in the field of the invention will appreciate that the present invention provides a variety of advantages and benefits, including the following:
1. Production of substantially non-segregating tailings with acceptable settling, consolidation and water release rate properties, with simultaneous production of release water with acceptable water chemistry characteristics for use in the bitumen extraction process.
2. Production of release water with lower concentrations of Cat+, Mgt+, Na+, ions, ultra fines, and color-making organic species concentrations.
3. Release water with excess Ca(OH)2 and other chemicals produced by treating the oil sands tailings with Ca(OH)2 may be used for the conditioning of the make-up water.
4. Existing inventories of mature fine tails (MFT) may be reduced by adding the MFT into the blend of cyclone underflow and thickener underflow, or into the whole tailings discharged from the extraction plant, depending on the composition of the tailings produced by the extraction process.
5. Cost-effective management of oil sands tailings produced by any kind of water slurry-based bitumen extraction process.
6. The process of the invention is simple to use in commercial environments and uses low-cost chemicals for the management of oil sands tailings.
7. The process can be smoothly integrated into existing bitumen extraction and oil sands tailings management processes.
In this patent document, the word "comprising" is used in its non-limiting sense to mean that items following that word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article "a" does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element.
6. The process of the invention is simple to use in commercial environments and uses low-cost chemicals for the management of oil sands tailings.
7. The process can be smoothly integrated into existing bitumen extraction and oil sands tailings management processes.
In this patent document, the word "comprising" is used in its non-limiting sense to mean that items following that word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article "a" does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element.
Claims (11)
1. A method for reducing segregation between sand and fines in oil sands tailings from water slurry-based bitumen extraction processes, said method comprising:
(a) passing coarse oil sands tailings through a cyclone so as to produce:
a.1 a cyclone underflow stream having a solids content of at least 60 percent by weight, with approximately 3 percent of said solids being fines; and a.2 a cyclone overflow stream having a solids content of at least 15 percent by weight, with approximately 50 percent of said solids being fines;
(b) passing the cyclone overflow stream through a thickener so as to produce a thickener underflow having a solids content of at least 40 percent by weight;
(c) blending the cyclone underflow stream and the thickener underflow stream to produce blended tailings;
(d) treating the blended tailings with calcium oxide at a dosage of at least grams of calcium oxide per cubic meter of blended tailings; and (e) injecting carbon dioxide into the blended tailings subsequent to treatment with calcium oxide, with the dosage of carbon dioxide being controlled to maintain the pH of the tailings within the range of 11.0 to 11.6.
(a) passing coarse oil sands tailings through a cyclone so as to produce:
a.1 a cyclone underflow stream having a solids content of at least 60 percent by weight, with approximately 3 percent of said solids being fines; and a.2 a cyclone overflow stream having a solids content of at least 15 percent by weight, with approximately 50 percent of said solids being fines;
(b) passing the cyclone overflow stream through a thickener so as to produce a thickener underflow having a solids content of at least 40 percent by weight;
(c) blending the cyclone underflow stream and the thickener underflow stream to produce blended tailings;
(d) treating the blended tailings with calcium oxide at a dosage of at least grams of calcium oxide per cubic meter of blended tailings; and (e) injecting carbon dioxide into the blended tailings subsequent to treatment with calcium oxide, with the dosage of carbon dioxide being controlled to maintain the pH of the tailings within the range of 11.0 to 11.6.
2. The method of Claim 1 wherein the calcium oxide is introduced into the blended tailings in the form of calcium hydroxide.
3. The method of Claim 1 or Claim 2 comprising the further step of adding calcium oxide to the coarse oil sands tailings upstream of the cyclone.
4. The method of any one of Claims 1-3 comprising the further step of mixing a polymeric flocculent with the cyclone overflow during the step of passing the cyclone overflow stream through a thickener.
5. The method of any one of Claims 1-4 comprising the further step of adding calcium oxide to the cyclone overflow during the step of passing the cyclone overflow stream through a thickener.
6. The method of any one of Claims 1-5 comprising the further step of mixing mature fine tails with the blended tailings prior to treatment of the blended tailings with calcium oxide.
7. The method of any one of Claims 1-6 comprising the further step of mixing mature fine tails with the blended tailings during treatment of the blended tailings with calcium oxide.
8. A method for reducing segregation between sand and fines in oil sands tailings from water slurry-based bitumen extraction processes, said method comprising:
(a) treating the oil sands tailings with calcium oxide at a dosage of at least grams of calcium oxide per cubic meter of tailings; and (b) injecting carbon dioxide into the oil sands tailings subsequent to treatment with calcium oxide, with the dosage of carbon dioxide being controlled to maintain the pH of the tailings within the range of 11.0 to 11.6.
(a) treating the oil sands tailings with calcium oxide at a dosage of at least grams of calcium oxide per cubic meter of tailings; and (b) injecting carbon dioxide into the oil sands tailings subsequent to treatment with calcium oxide, with the dosage of carbon dioxide being controlled to maintain the pH of the tailings within the range of 11.0 to 11.6.
9. The method of Claim 8 wherein the calcium oxide is introduced into the oil sands tailings in the form of calcium hydroxide.
10. The method of Claim 8 or Claim 9 comprising the further step of mixing mature fine tails with the oil sands tailings prior to the step of treating of the oil sands tailings with calcium oxide.
11. The method of any one of Claims 8-10 comprising the further step of mixing mature fine tails with the oil sands tailings during the step of treating of the oil sands tailings with calcium oxide.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2522031A CA2522031C (en) | 2004-10-05 | 2005-10-03 | Method for treatment of oil sands tailings with lime or with lime and carbon dioxide |
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2,481,597 | 2004-10-05 | ||
| CA2481597 | 2004-10-05 | ||
| CA2522031A CA2522031C (en) | 2004-10-05 | 2005-10-03 | Method for treatment of oil sands tailings with lime or with lime and carbon dioxide |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2522031A1 CA2522031A1 (en) | 2006-04-05 |
| CA2522031C true CA2522031C (en) | 2013-02-19 |
Family
ID=36141721
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2522031A Active CA2522031C (en) | 2004-10-05 | 2005-10-03 | Method for treatment of oil sands tailings with lime or with lime and carbon dioxide |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2522031C (en) |
Cited By (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8480908B2 (en) | 2005-11-09 | 2013-07-09 | Suncor Energy Inc. | Process, apparatus and system for treating a hydrocarbon feedstock |
| US8800784B2 (en) | 2005-11-09 | 2014-08-12 | Suncor Energy Inc. | System, apparatus and process for extraction of bitumen from oil sands |
| US8968580B2 (en) | 2009-12-23 | 2015-03-03 | Suncor Energy Inc. | Apparatus and method for regulating flow through a pumpbox |
| US9016799B2 (en) | 2005-11-09 | 2015-04-28 | Suncor Energy, Inc. | Mobile oil sands mining system |
| WO2019035954A1 (en) * | 2017-08-18 | 2019-02-21 | Graymont Western Canada Inc. | Treatment of oil sands tailings with lime at elevated ph levels |
| WO2019094620A3 (en) * | 2017-11-08 | 2019-07-11 | Graymont Western Canada Inc. | Treatment of tailings streams with one or more dosages of lime, and associated systems and methods |
Families Citing this family (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7736501B2 (en) | 2002-09-19 | 2010-06-15 | Suncor Energy Inc. | System and process for concentrating hydrocarbons in a bitumen feed |
| CA2471048C (en) | 2002-09-19 | 2006-04-25 | Suncor Energy Inc. | Bituminous froth hydrocarbon cyclone |
| US7931800B2 (en) | 2007-03-14 | 2011-04-26 | Apex Engineering Inc. | Method for extraction of bitumen from oil sands using lime |
| EP2644579A3 (en) | 2008-10-29 | 2016-06-08 | E. I. du Pont de Nemours and Company | Treatment of tailings streams |
| WO2013188982A1 (en) * | 2012-06-21 | 2013-12-27 | Suncor Energy Inc. | Enhanced techniques for dewatering thick fine tailings |
| US20150203385A1 (en) * | 2012-06-21 | 2015-07-23 | Suncore Energy Inc. | Dewatering of thick fine tailings with gas injection and flocculation |
| CA2825515C (en) * | 2012-10-26 | 2016-02-09 | Syncrude Canada Ltd. In Trust For The Owners Of The Syncrude Project | Use of multivalent inorganic additives |
| WO2020055893A1 (en) * | 2018-09-11 | 2020-03-19 | Graymont Western Canada Inc. | Improvement of geotechnical characteristics of tailings via lime addition |
-
2005
- 2005-10-03 CA CA2522031A patent/CA2522031C/en active Active
Cited By (12)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8480908B2 (en) | 2005-11-09 | 2013-07-09 | Suncor Energy Inc. | Process, apparatus and system for treating a hydrocarbon feedstock |
| US8800784B2 (en) | 2005-11-09 | 2014-08-12 | Suncor Energy Inc. | System, apparatus and process for extraction of bitumen from oil sands |
| US8968579B2 (en) | 2005-11-09 | 2015-03-03 | Suncor Energy Inc. | System, apparatus and process for extraction of bitumen from oil sands |
| US9016799B2 (en) | 2005-11-09 | 2015-04-28 | Suncor Energy, Inc. | Mobile oil sands mining system |
| US8968580B2 (en) | 2009-12-23 | 2015-03-03 | Suncor Energy Inc. | Apparatus and method for regulating flow through a pumpbox |
| WO2019035954A1 (en) * | 2017-08-18 | 2019-02-21 | Graymont Western Canada Inc. | Treatment of oil sands tailings with lime at elevated ph levels |
| US11390550B2 (en) | 2017-08-18 | 2022-07-19 | Graymont Western Canada Inc. | Treatment of oil sands tailings with lime at elevated PH levels |
| US11613485B2 (en) | 2017-08-18 | 2023-03-28 | Graymont Western Canada Inc. | Treatment of tailings with lime at elevated PH levels |
| WO2019094620A3 (en) * | 2017-11-08 | 2019-07-11 | Graymont Western Canada Inc. | Treatment of tailings streams with one or more dosages of lime, and associated systems and methods |
| US11027995B2 (en) | 2017-11-08 | 2021-06-08 | Graymont Western Canada Inc | Treatment of tailings streams with one or more dosages of lime, and associated systems and methods |
| US11618697B2 (en) | 2017-11-08 | 2023-04-04 | Graymont Western Canada Inc. | Treatment of tailings streams with one or more dosages of lime, and associated systems and methods |
| AU2018366144B2 (en) * | 2017-11-08 | 2024-05-09 | Graymont Western Canada Inc. | Treatment of tailings streams with one or more dosages of lime, and associated systems and methods |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2522031A1 (en) | 2006-04-05 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CA2522031C (en) | Method for treatment of oil sands tailings with lime or with lime and carbon dioxide | |
| CA2667933C (en) | Method for dispersing and aggregating components of mineral slurries | |
| CN103269995B (en) | Tailing stream treatment process | |
| AU2013239946B2 (en) | Method for removing calcium, barium, magnesium and strontium from frac flowback | |
| US11560323B2 (en) | Compositions of dry acid polymers and uses thereof | |
| CA2822091C (en) | Processes for flocculating tailings streams of the oil prospection | |
| AU2019316539B2 (en) | Improvement of geotechnical characteristics of tailings via lime addition | |
| MacKinnon et al. | Water quality issues associated with composite tailings (CT) technology for managing oil sands tailings | |
| CA2673981A1 (en) | Acidic filtration of bitumen froth tailings | |
| US7931800B2 (en) | Method for extraction of bitumen from oil sands using lime | |
| CA2188064C (en) | Oil sands tailings treatment process | |
| CA2871177C (en) | Method for treating mine waste | |
| CN103626367B (en) | A kind of method of floating the recycling of oil sludge resource utilization containing gather qi together | |
| CA3070408A1 (en) | Oil sands tailings treatment | |
| CA2840675A1 (en) | Method for destabilizing bitumen-water and oil-water emulsions using lime | |
| CA2823459C (en) | Method of using a silicate-containing stream from a hydrocarbon operation or from a geothermal source to treat fluid tailings by chemically-induced micro-agglomeration | |
| US20140116946A1 (en) | Use of multivalent inorganic additives | |
| CA2747913C (en) | Method of processing a bituminous feed and contaminated water | |
| Arnipally et al. | Reduction of Environmental Impacts of Oil Sands Plants by Implementing Bitumen Extraction and Tailings Disposal Processes using Lime (CaO) Additive | |
| CA3102651A1 (en) | Small-scale bitumen extraction processes and plants | |
| Ozum et al. | Reduction of Oil Sands Fine Tailings | |
| Ozum et al. | Methods to Reduce Production of Oil Sands Mature Fine Tailings | |
| CA2933892A1 (en) | Processing of oil sand streams via chemically-induced micro-agglomeration |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request |