CA1293464C - Recovery of heavy oil - Google Patents
Recovery of heavy oilInfo
- Publication number
- CA1293464C CA1293464C CA000544557A CA544557A CA1293464C CA 1293464 C CA1293464 C CA 1293464C CA 000544557 A CA000544557 A CA 000544557A CA 544557 A CA544557 A CA 544557A CA 1293464 C CA1293464 C CA 1293464C
- Authority
- CA
- Canada
- Prior art keywords
- recovery
- surfactant
- bitumen
- water
- range
- 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.)
- Expired - Fee Related
Links
- 238000011084 recovery Methods 0.000 title claims abstract description 27
- 239000000295 fuel oil Substances 0.000 title abstract description 3
- 239000004094 surface-active agent Substances 0.000 claims abstract description 17
- 239000010779 crude oil Substances 0.000 claims abstract description 11
- 229920003171 Poly (ethylene oxide) Polymers 0.000 claims abstract description 6
- -1 alkyl aryl sulphonate Chemical compound 0.000 claims abstract description 5
- 239000007864 aqueous solution Substances 0.000 claims abstract description 3
- 238000000034 method Methods 0.000 claims description 22
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 18
- 239000007787 solid Substances 0.000 claims description 6
- 239000003945 anionic surfactant Substances 0.000 claims description 5
- 239000000463 material Substances 0.000 claims description 5
- 239000000243 solution Substances 0.000 claims description 4
- 239000000126 substance Substances 0.000 claims description 2
- 229910021653 sulphate ion Inorganic materials 0.000 claims 1
- 229920000642 polymer Polymers 0.000 abstract description 10
- 125000002947 alkylene group Chemical group 0.000 abstract description 4
- 239000010426 asphalt Substances 0.000 description 20
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 15
- HFQQZARZPUDIFP-UHFFFAOYSA-M sodium;2-dodecylbenzenesulfonate Chemical compound [Na+].CCCCCCCCCCCCC1=CC=CC=C1S([O-])(=O)=O HFQQZARZPUDIFP-UHFFFAOYSA-M 0.000 description 9
- 230000000694 effects Effects 0.000 description 8
- 239000011269 tar Substances 0.000 description 8
- 239000011275 tar sand Substances 0.000 description 8
- 229920002594 Polyethylene Glycol 8000 Polymers 0.000 description 6
- 238000000605 extraction Methods 0.000 description 6
- 239000004576 sand Substances 0.000 description 6
- 239000008186 active pharmaceutical agent Substances 0.000 description 4
- 239000003921 oil Substances 0.000 description 4
- 230000003750 conditioning effect Effects 0.000 description 3
- 238000002386 leaching Methods 0.000 description 3
- 238000010794 Cyclic Steam Stimulation Methods 0.000 description 2
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 2
- 239000004927 clay Substances 0.000 description 2
- 230000007423 decrease Effects 0.000 description 2
- 238000002474 experimental method Methods 0.000 description 2
- 238000011065 in-situ storage Methods 0.000 description 2
- 229910052500 inorganic mineral Inorganic materials 0.000 description 2
- 239000011707 mineral Substances 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 239000002245 particle Substances 0.000 description 2
- 238000000926 separation method Methods 0.000 description 2
- 239000002002 slurry Substances 0.000 description 2
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- UOACKFBJUYNSLK-XRKIENNPSA-N Estradiol Cypionate Chemical compound O([C@H]1CC[C@H]2[C@H]3[C@@H](C4=CC=C(O)C=C4CC3)CC[C@@]21C)C(=O)CCC1CCCC1 UOACKFBJUYNSLK-XRKIENNPSA-N 0.000 description 1
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 1
- 206010024825 Loose associations Diseases 0.000 description 1
- XQCFHQBGMWUEMY-ZPUQHVIOSA-N Nitrovin Chemical compound C=1C=C([N+]([O-])=O)OC=1\C=C\C(=NNC(=N)N)\C=C\C1=CC=C([N+]([O-])=O)O1 XQCFHQBGMWUEMY-ZPUQHVIOSA-N 0.000 description 1
- 239000004614 Process Aid Substances 0.000 description 1
- 238000013019 agitation Methods 0.000 description 1
- 125000000129 anionic group Chemical group 0.000 description 1
- 238000001246 colloidal dispersion Methods 0.000 description 1
- 125000004122 cyclic group Chemical group 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 239000012154 double-distilled water Substances 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000003792 electrolyte Substances 0.000 description 1
- 239000000839 emulsion Substances 0.000 description 1
- 238000005188 flotation Methods 0.000 description 1
- 238000009291 froth flotation Methods 0.000 description 1
- ZZUFCTLCJUWOSV-UHFFFAOYSA-N furosemide Chemical compound C1=C(Cl)C(S(=O)(=O)N)=CC(C(O)=O)=C1NCC1=CC=CO1 ZZUFCTLCJUWOSV-UHFFFAOYSA-N 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 235000013882 gravy Nutrition 0.000 description 1
- 239000004615 ingredient Substances 0.000 description 1
- 239000002736 nonionic surfactant Substances 0.000 description 1
- 239000007764 o/w emulsion Substances 0.000 description 1
- 239000011148 porous material Substances 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 239000010453 quartz Substances 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N silicon dioxide Inorganic materials O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 229910052708 sodium Inorganic materials 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- 239000011885 synergistic combination 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
- C10G1/047—Hot water or cold water extraction processes
Landscapes
- 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)
- Working-Up Tar And Pitch (AREA)
Abstract
6461(2) ABSTRACT OF THE DISCLOSURE
RECOVERY OF HEAVY OIL
Heavy crude oil is recovered from tar sands by treatment with an aqueous solution containing a surfactant, e.g., an alkyl aryl sulphonate and a hydrophilic alkylene oxide polymer, e.g., polyethylene oxide.
Adding the alkylene oxide polymer enables the surfactant to be used in lower concentration and/or recovery to be increased.
RECOVERY OF HEAVY OIL
Heavy crude oil is recovered from tar sands by treatment with an aqueous solution containing a surfactant, e.g., an alkyl aryl sulphonate and a hydrophilic alkylene oxide polymer, e.g., polyethylene oxide.
Adding the alkylene oxide polymer enables the surfactant to be used in lower concentration and/or recovery to be increased.
Description
~3~6~
6461(2) RECOVERY OF HEAVY OIL
This invention relates to a method for the recovery of heavy crude oil, especially from tar sands.
As reserves of conventional crude oils (approximately 15 to 30 API) decline, increasing importance will be attached to efficient methods Eor recovering heavy crude oils (8~-12 API) and the even heavier bitumens (less than 8 API). Most bitumens are associated with minerals such as clays and quartz, and are known as tar sands.
;` The Alberta tar sands are among the largest deposits of theirkind in the world and are estimated to contain about one trillion barrels of bltumen in place. The Athabasca region alone has reserves of 250 billion barrels. About 0.7 million acres of the Athabasca deposit is overlain by 150 ft, or less, of overburden and is potentially capable o~ being mined from the surface. The remaining 16.6 million acres are at such depths that the bitumen can only be recovered by in-situ methods.
The crude bitu~en occurs in beds of sand and clay, usually partly connected together, and in porous carbonate rocks.
In high grade tar sand, the pore space is filled with bltumen (typically 15-20~ weight) and water.
In lower grade tar sands, i.e., containing less than 10% by weight bitumen, clusters of small parti~les exist within the framework formed by the coarse inorganic grains. These particles, known as fines, are saturated with water, Thus the amount of connate water in the tar sand increases with increasing fines ;; 1 ~ ' 6~
content.
The bitumen typically has an API gravi~y of 7 and is denser than water at room temperature but becomes lighter than water a~
elevated temperatures.
In the case of deposits near the surface the overburden may be removed and the tar sand recovered by open cast mlning.
Mined tar sands are refined by the hot water process. A
description of this procPss is given in USP 4 474 616.
In broad summary, this process comprises first conditioning the tar sand, to make it amenable to flotation separation of the bitumen from the solids. Conditioning involves feeding mined tar sands, hot water (80C), an alkaline process aid ~usually NaOH), and steam lnto a rotating horizontal drum wherein the ingredients are agitated together.
During conditioning, the mined tar sand in which the bitumen, connate water and solids are tightly bound together becomes an aqueous slurry of porridge-like consistency, wherein the components are in loose association.
The slurry leaving the drum is screened to remove oversize material and then flooded or diluted with additional hot water~
The bitumen is then recovered by primary and secondary froth flotation.
This process suffers from the disadvantages that bitumen/water emulsions are formed and``the separated water contains colloidal dispersions of clay, fines and oil which are extremely stable and present serious problems in their disposal.
For deposits at a greater depth, the technique of jet leaching can be employed. Jet leaching is a known technique for the extraction of tar sands which comprises drilling and fixing casing until the pay zone is reached. The mineral is then fragmented by directing high velocity ~ets of water onto it and the bitumen is pumped to the surface, leaving most of the solid particles downhole.
An alternative approach for deep depo~its is the use of cyclic steam stlmulation to recover the bitumen. Cyclic steam stimulation is otherwise Icnown as "huff and puff". In this process, steam is - 3~zg~3~6~
in~ected and the bitumen produced through the same well. The steam is injected down the well for several weeks. When it is turned off, bitumen flows freely up the well for about one week, after which it has to be pumped to the surface. Pumping can usually be continued for several months before more steam must be injected.
In all these methods, oil recovery is assisted when the sand is water wet and hindered when it is oil wet.
In the case of Athabascan tar sands~ most of the sand is water wet and therefore amenable to oil recovery.
The use of surfactants to improve recovery has also been reported, see CIM Bulletin, March 1979, pages 167-168, but the improvement compares unfavourably with that achieved by the use of sodium hydro~ide. ~ligher concentrations of surfactant are required to achieve approximately similar improvements in recovery.
We have now discovered that adding a hydrophilic alkylene oxide polymer to the surfactant enables the surfactant to be used in lower concentration and/or recovery to be increased.
Thus according to the present invention there is provided a method for the recovery of heavy crude oil from heavy crude oil associated with a solid inorganic substance (and optionally water) hereinafter referred to as the materal, which method comprises treating the ~aterial with an aqueous solution containing a surfactant and a hydrophilic alkylene oxide polymer and recovering the heavy crude oil.
Suitable surfactants include anionic and nonionic surfactants.
Anionic surfactants are preferred since the heavy crude oil is recovered as an oil in water emulsion which when separated ls substantially free from solids and water.
Suitable anionic surfactants include alkyl sulphates and alkyl aryl sulphonates.
Suitable polymers include polyethylene oxides of molecular weight in the range 1,000 to 1,000,000.
Suitable concentrations of surfactant and polymer are each in the range of 0.01% to 5%, preferably 0.1 to 2.0%~ by weight of the solution.
lZ93~
The treatment is suitable for both previously mined deposits and ~or in-situ recovery from a reservoir, for example jet leaching or cyclic steam stimulation as hereinbefore described.
For previously mined deposits treatment is preferably effected at a temperature in the range 40 to 90C.
The invention is illuætrated with raference to the following Examples, and related Figures attached.
Figure 1 is a graph representing the results of a first series of tests showing the relationship between polymer and surfactant concentration ~as the abscissa) and bitumen recovery (as the ordinate).
Figure 2 is a graph representing the results of a second series of tests showing the relationship between extraction time (as the abscissa) and bitumen recovery ~as the ordinate).
Figure 3 is a graph representiny the results oE a third series of tests showing the relationship between pH
(as the abscissa) and bitumen recovery (as the ordinate).
Examples The material studied was a high grade Athabasca tar sand containing approximately 16~ by weight bitumen homogeneously distributed throughout the sand mix.
A weighed sample of tar sand (typically 0.5g) and a measured quantity of the extraction medium (10 ml) were placed together in a round bottom flask which was immersed in a thermostatted bath. A water cooled condenser was fitted to minimize evaporative losses. Extractions were carried out without any agitation at 100C for 10 minutes, except where otherwise stated.
The amount of bitumen removed from the tar sand was quantified gravimetrically after separation from the extracting medium and the free bitumen. The extracted sand was washed with double distilled water until all ~ree bitumen had been removed. The sand was then filtered ,~' 1~3'~6~
through a sintered glass funnel and dried in an oven at 50C to constant weight.
Example 1 A series of tests were carried out using (a) a polyethylene oxide of average molecular weight 8,000, (PEG
8000), (b) sodium dodecyl benzene sulphonate, (SDBS), and (c) various combinations of (a) and (b).
The optimum concentration of PEG 8000 in conjunction with 5~ by wt SDBS was found to be 0.5%. Little increase in recovery was observed at higher concentrations of PEG
8000. Using this lower concentration of PEG 8000, the concentration of SDBS was optimised. The maximum recovery (96%) was measured at a concentration of SDBS of 1.5%.
Decreasing the concentration of 5DBS resulted in a marginal decrease in recovery at concentration as low as 0.5%.
.i~
:` ~.z93~6~
SDBS, 93% recovery was still achieved.
The results are set out graphlcally in the accompanylng Figure 1 and clearly show the syner~istic effect of the combination.
Example 2 A further series of tests was carried out to study the effect of extraction time on bitumen recovery using (a) a 5% solution of SDBS and (b) a solutlon containing 0.5~ SDBS and 0.5% PEG 8000.
The results are set out graphically in the accompanying Figure 2, The presence of the polymer has little effect on the rate of recovery over the first few minutes of the process. However, at time greater than about 2 minutes, recovery i9 increased considerably by the polymer/surfactant mixture compared to the surfactant alone.
Example 3 By way of comparison, a series of tests were carried out to show the effect of sodium hydroxide alone at various pH's and temperatures.
The effect of p~ on recovery was studied at 70~C and 100C over a pH range of 10-14. In the presence of NaOH at 70C, the maximum recovery, 53%, was found at pH 11.7. Increasing the temperature of the extraction to 100C had two effects: firstly, the recovery at the optimum pH increased to 61% and, secondly, the process became less sensitive to changes in pH, although still sensitive. At both temperatures, however, there was little observed recovery outside the pH range 10-13.
In order to investigate the effect of added electrolyte, the experiments at 70C were repeated in the presence of 0.1 M NaCl. As shown in Figure 3, this had little effect on the amount of bitumen outside the p~ range 10-13.
The results are shown graphically in the accompanying Figure 3 and cl arly show the inferiority of sodium hydroxide to either the surfactant or polymer and still more to the synergistic combination.
Thus the experiments show that not only is the combination of SDBS and PEG 8000 superior to either component alone or to NaOH, it 3L2a33~
iS al80 less sensitive to the concentrations of the co~ponents added. This is a considerable advantage in operations in the field.
- .
~'
6461(2) RECOVERY OF HEAVY OIL
This invention relates to a method for the recovery of heavy crude oil, especially from tar sands.
As reserves of conventional crude oils (approximately 15 to 30 API) decline, increasing importance will be attached to efficient methods Eor recovering heavy crude oils (8~-12 API) and the even heavier bitumens (less than 8 API). Most bitumens are associated with minerals such as clays and quartz, and are known as tar sands.
;` The Alberta tar sands are among the largest deposits of theirkind in the world and are estimated to contain about one trillion barrels of bltumen in place. The Athabasca region alone has reserves of 250 billion barrels. About 0.7 million acres of the Athabasca deposit is overlain by 150 ft, or less, of overburden and is potentially capable o~ being mined from the surface. The remaining 16.6 million acres are at such depths that the bitumen can only be recovered by in-situ methods.
The crude bitu~en occurs in beds of sand and clay, usually partly connected together, and in porous carbonate rocks.
In high grade tar sand, the pore space is filled with bltumen (typically 15-20~ weight) and water.
In lower grade tar sands, i.e., containing less than 10% by weight bitumen, clusters of small parti~les exist within the framework formed by the coarse inorganic grains. These particles, known as fines, are saturated with water, Thus the amount of connate water in the tar sand increases with increasing fines ;; 1 ~ ' 6~
content.
The bitumen typically has an API gravi~y of 7 and is denser than water at room temperature but becomes lighter than water a~
elevated temperatures.
In the case of deposits near the surface the overburden may be removed and the tar sand recovered by open cast mlning.
Mined tar sands are refined by the hot water process. A
description of this procPss is given in USP 4 474 616.
In broad summary, this process comprises first conditioning the tar sand, to make it amenable to flotation separation of the bitumen from the solids. Conditioning involves feeding mined tar sands, hot water (80C), an alkaline process aid ~usually NaOH), and steam lnto a rotating horizontal drum wherein the ingredients are agitated together.
During conditioning, the mined tar sand in which the bitumen, connate water and solids are tightly bound together becomes an aqueous slurry of porridge-like consistency, wherein the components are in loose association.
The slurry leaving the drum is screened to remove oversize material and then flooded or diluted with additional hot water~
The bitumen is then recovered by primary and secondary froth flotation.
This process suffers from the disadvantages that bitumen/water emulsions are formed and``the separated water contains colloidal dispersions of clay, fines and oil which are extremely stable and present serious problems in their disposal.
For deposits at a greater depth, the technique of jet leaching can be employed. Jet leaching is a known technique for the extraction of tar sands which comprises drilling and fixing casing until the pay zone is reached. The mineral is then fragmented by directing high velocity ~ets of water onto it and the bitumen is pumped to the surface, leaving most of the solid particles downhole.
An alternative approach for deep depo~its is the use of cyclic steam stlmulation to recover the bitumen. Cyclic steam stimulation is otherwise Icnown as "huff and puff". In this process, steam is - 3~zg~3~6~
in~ected and the bitumen produced through the same well. The steam is injected down the well for several weeks. When it is turned off, bitumen flows freely up the well for about one week, after which it has to be pumped to the surface. Pumping can usually be continued for several months before more steam must be injected.
In all these methods, oil recovery is assisted when the sand is water wet and hindered when it is oil wet.
In the case of Athabascan tar sands~ most of the sand is water wet and therefore amenable to oil recovery.
The use of surfactants to improve recovery has also been reported, see CIM Bulletin, March 1979, pages 167-168, but the improvement compares unfavourably with that achieved by the use of sodium hydro~ide. ~ligher concentrations of surfactant are required to achieve approximately similar improvements in recovery.
We have now discovered that adding a hydrophilic alkylene oxide polymer to the surfactant enables the surfactant to be used in lower concentration and/or recovery to be increased.
Thus according to the present invention there is provided a method for the recovery of heavy crude oil from heavy crude oil associated with a solid inorganic substance (and optionally water) hereinafter referred to as the materal, which method comprises treating the ~aterial with an aqueous solution containing a surfactant and a hydrophilic alkylene oxide polymer and recovering the heavy crude oil.
Suitable surfactants include anionic and nonionic surfactants.
Anionic surfactants are preferred since the heavy crude oil is recovered as an oil in water emulsion which when separated ls substantially free from solids and water.
Suitable anionic surfactants include alkyl sulphates and alkyl aryl sulphonates.
Suitable polymers include polyethylene oxides of molecular weight in the range 1,000 to 1,000,000.
Suitable concentrations of surfactant and polymer are each in the range of 0.01% to 5%, preferably 0.1 to 2.0%~ by weight of the solution.
lZ93~
The treatment is suitable for both previously mined deposits and ~or in-situ recovery from a reservoir, for example jet leaching or cyclic steam stimulation as hereinbefore described.
For previously mined deposits treatment is preferably effected at a temperature in the range 40 to 90C.
The invention is illuætrated with raference to the following Examples, and related Figures attached.
Figure 1 is a graph representing the results of a first series of tests showing the relationship between polymer and surfactant concentration ~as the abscissa) and bitumen recovery (as the ordinate).
Figure 2 is a graph representing the results of a second series of tests showing the relationship between extraction time (as the abscissa) and bitumen recovery ~as the ordinate).
Figure 3 is a graph representiny the results oE a third series of tests showing the relationship between pH
(as the abscissa) and bitumen recovery (as the ordinate).
Examples The material studied was a high grade Athabasca tar sand containing approximately 16~ by weight bitumen homogeneously distributed throughout the sand mix.
A weighed sample of tar sand (typically 0.5g) and a measured quantity of the extraction medium (10 ml) were placed together in a round bottom flask which was immersed in a thermostatted bath. A water cooled condenser was fitted to minimize evaporative losses. Extractions were carried out without any agitation at 100C for 10 minutes, except where otherwise stated.
The amount of bitumen removed from the tar sand was quantified gravimetrically after separation from the extracting medium and the free bitumen. The extracted sand was washed with double distilled water until all ~ree bitumen had been removed. The sand was then filtered ,~' 1~3'~6~
through a sintered glass funnel and dried in an oven at 50C to constant weight.
Example 1 A series of tests were carried out using (a) a polyethylene oxide of average molecular weight 8,000, (PEG
8000), (b) sodium dodecyl benzene sulphonate, (SDBS), and (c) various combinations of (a) and (b).
The optimum concentration of PEG 8000 in conjunction with 5~ by wt SDBS was found to be 0.5%. Little increase in recovery was observed at higher concentrations of PEG
8000. Using this lower concentration of PEG 8000, the concentration of SDBS was optimised. The maximum recovery (96%) was measured at a concentration of SDBS of 1.5%.
Decreasing the concentration of 5DBS resulted in a marginal decrease in recovery at concentration as low as 0.5%.
.i~
:` ~.z93~6~
SDBS, 93% recovery was still achieved.
The results are set out graphlcally in the accompanylng Figure 1 and clearly show the syner~istic effect of the combination.
Example 2 A further series of tests was carried out to study the effect of extraction time on bitumen recovery using (a) a 5% solution of SDBS and (b) a solutlon containing 0.5~ SDBS and 0.5% PEG 8000.
The results are set out graphically in the accompanying Figure 2, The presence of the polymer has little effect on the rate of recovery over the first few minutes of the process. However, at time greater than about 2 minutes, recovery i9 increased considerably by the polymer/surfactant mixture compared to the surfactant alone.
Example 3 By way of comparison, a series of tests were carried out to show the effect of sodium hydroxide alone at various pH's and temperatures.
The effect of p~ on recovery was studied at 70~C and 100C over a pH range of 10-14. In the presence of NaOH at 70C, the maximum recovery, 53%, was found at pH 11.7. Increasing the temperature of the extraction to 100C had two effects: firstly, the recovery at the optimum pH increased to 61% and, secondly, the process became less sensitive to changes in pH, although still sensitive. At both temperatures, however, there was little observed recovery outside the pH range 10-13.
In order to investigate the effect of added electrolyte, the experiments at 70C were repeated in the presence of 0.1 M NaCl. As shown in Figure 3, this had little effect on the amount of bitumen outside the p~ range 10-13.
The results are shown graphically in the accompanying Figure 3 and cl arly show the inferiority of sodium hydroxide to either the surfactant or polymer and still more to the synergistic combination.
Thus the experiments show that not only is the combination of SDBS and PEG 8000 superior to either component alone or to NaOH, it 3L2a33~
iS al80 less sensitive to the concentrations of the co~ponents added. This is a considerable advantage in operations in the field.
- .
~'
Claims (7)
1. A method for the recovery of heavy crude oil from heavy crude oil associated with a solid inorganic substance, the material, which method comprises treating the material with an aqueous solution containing a surfactant and a polyethylene oxide of molecular weight in the range 1,000 to 1,000,000 and recovering the heavy crude oil.
2. A method according to claim 1 wherein water is additionally present in the material.
3. A method according to claim 1 wherein the surfactant is an anionic surfactant.
4. A method according to claim 3 wherein the anionic surfactant is an alkyl sulphate or an alkyl aryl sulphonate.
5. A method according to claim 1 wherein the concentrations of surfactant and polyethylene oxide are each in the range 0.01 to 5% by weight of the solution.
6. A method according to claim 5 wherein the concentrations of surfactant and polyethylene oxide are each in the range 0.1 to 2.0% by weight of the solution.
7. A method according to claim 1 wherein the treatment is effected at a temperature in the range 40 to 90 C.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GB8620705 | 1986-08-27 | ||
| GB868620705A GB8620705D0 (en) | 1986-08-27 | 1986-08-27 | Recovery of heavy oil |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1293464C true CA1293464C (en) | 1991-12-24 |
Family
ID=10603254
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000544557A Expired - Fee Related CA1293464C (en) | 1986-08-27 | 1987-08-14 | Recovery of heavy oil |
Country Status (3)
| Country | Link |
|---|---|
| EP (1) | EP0261793A1 (en) |
| CA (1) | CA1293464C (en) |
| GB (1) | GB8620705D0 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9469813B2 (en) | 2013-04-18 | 2016-10-18 | S.P.C.M. Sa | Method for recovering bitumen from tar sands |
Families Citing this family (17)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5083613A (en) * | 1989-02-14 | 1992-01-28 | Canadian Occidental Petroleum, Ltd. | Process for producing bitumen |
| US5263848A (en) * | 1986-11-24 | 1993-11-23 | Canadian Occidental Petroleum, Ltd. | Preparation of oil-in-aqueous phase emulsion and removing contaminants by burning |
| US4978365A (en) * | 1986-11-24 | 1990-12-18 | Canadian Occidental Petroleum Ltd. | Preparation of improved stable crude oil transport emulsions |
| US5000872A (en) * | 1987-10-27 | 1991-03-19 | Canadian Occidental Petroleum, Ltd. | Surfactant requirements for the low-shear formation of water continuous emulsions from heavy crude oil |
| US4983319A (en) * | 1986-11-24 | 1991-01-08 | Canadian Occidental Petroleum Ltd. | Preparation of low-viscosity improved stable crude oil transport emulsions |
| US5156652A (en) * | 1986-12-05 | 1992-10-20 | Canadian Occidental Petroleum Ltd. | Low-temperature pipeline emulsion transportation enhancement |
| US4966235A (en) * | 1988-07-14 | 1990-10-30 | Canadian Occidental Petroleum Ltd. | In situ application of high temperature resistant surfactants to produce water continuous emulsions for improved crude recovery |
| US7640987B2 (en) | 2005-08-17 | 2010-01-05 | Halliburton Energy Services, Inc. | Communicating fluids with a heated-fluid generation system |
| US7809538B2 (en) | 2006-01-13 | 2010-10-05 | Halliburton Energy Services, Inc. | Real time monitoring and control of thermal recovery operations for heavy oil reservoirs |
| US7832482B2 (en) | 2006-10-10 | 2010-11-16 | Halliburton Energy Services, Inc. | Producing resources using steam injection |
| US7770643B2 (en) | 2006-10-10 | 2010-08-10 | Halliburton Energy Services, Inc. | Hydrocarbon recovery using fluids |
| WO2009061930A1 (en) * | 2007-11-09 | 2009-05-14 | Soane Energy, Llc | Systems and methods for oil sands processing |
| CA2972203C (en) | 2017-06-29 | 2018-07-17 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| CA2974712C (en) | 2017-07-27 | 2018-09-25 | Imperial Oil Resources Limited | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| CA2978157C (en) | 2017-08-31 | 2018-10-16 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| CA2983541C (en) | 2017-10-24 | 2019-01-22 | Exxonmobil Upstream Research Company | Systems and methods for dynamic liquid level monitoring and control |
| CN112980419B (en) * | 2019-12-13 | 2023-01-10 | 中国石油天然气股份有限公司 | A kind of thick oil foaming agent and its preparation method and application |
Family Cites Families (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| DE3004003C2 (en) * | 1980-02-04 | 1982-02-04 | Wintershall Ag, 3100 Celle | Process for the extraction of crude oil from oil sands |
| US4491514A (en) * | 1984-04-16 | 1985-01-01 | Exxon Research & Engineering Co. | Process for beneficiating oil-shale |
| US4571294A (en) * | 1984-07-02 | 1986-02-18 | Getty Oil Company | Process for extracting hydrocarbons from hydrocarbon bearing ores |
-
1986
- 1986-08-27 GB GB868620705A patent/GB8620705D0/en active Pending
-
1987
- 1987-08-14 CA CA000544557A patent/CA1293464C/en not_active Expired - Fee Related
- 1987-08-21 EP EP19870307419 patent/EP0261793A1/en not_active Withdrawn
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9469813B2 (en) | 2013-04-18 | 2016-10-18 | S.P.C.M. Sa | Method for recovering bitumen from tar sands |
Also Published As
| Publication number | Publication date |
|---|---|
| GB8620705D0 (en) | 1986-10-08 |
| EP0261793A1 (en) | 1988-03-30 |
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