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EX-SITU LOW-TEMPERATURE HYDROCARBON SEPARATION

FROM TAR SANDS

BACKGROUND OF THE INVENTION

[0001] Tar sands are also known as bituminous sands or extra heavy oil sands. The properties of these sands include a mixture of very heavy crude oil and mineral sands, silts, clays and residual water. The very heavy oil present in tar sands is the residual left from biotic and abiotic weathering processes that have removed the lighter petroleum fractions typically associated with crude oil reservoirs. As a result of the tar-like consistency of these very heavy petroleum fraction associated with tar sands, the residual petroleum cannot be pumped from the subsurface using methods and processes typically associated with crude oil extraction. Viscosity reduction is a critical component of extracting the very heavy petroleum fractions from tar sands.

[0002] While, tar sand deposits are found in more than 70 countries in the world, including the United States and Russia, with the largest being in Canada and Venezuela. In Canada alone, there are reserves of 1.7 to 2.5 trillion barrels of heavy crude oil, associated with tar sands. In 2007, approximately 1.3 million barrels of oil sands product were produced per day. According to the Alberta Energy and Utilities Board (EUB), they are estimated to contain about 177 billion barrels of oil recoverable with current technology. Therefore, using current technology less than 10 percent of the tar sands in Canada are recoverable using existing technology. Among the issues associated with the extraction of heavy oil from tar sands is that is it very energy intensive and produces large quantities of carbon dioxide. [0003] The extraction of bitumen from tar sands in Canada began with G.C. Hoffman of the Geological Survey of Canada in 1883 as he attempted the separation using water. Dr. Karl Clark of the Alberta Research Council was granted a patent for the hot water extraction process in 1928. It should be noted that the present methods for extraction of bitumen from tar sands in Alberta are quite similar in theory to that developed by Dr. Clark in 1928. [0004] Current technology used to extract heavy petroleum involves removal of surficial tar sands, crushing , and slurrying them with hot water then pumped to an extraction plant. The hydrotransport of the hot water-tar sand slurry initiates the physical-chemical processes leading

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to the separation of bitumen from the mineral fraction of the tar sand. The mineral fraction in the Athabasca tar sands located in Alberta, Canada is water wet enabling a water-based extraction to be used as part of the extraction process. This connate water formed a boundary layer between the mineral fraction and the bitumen fraction of the tar sands. The hydrotransported slurry undergoes primary and secondary separation using dissolved air floatation-sedimentation extraction oil separation processes. Steam is added to heat the slurry prior to both the primary and secondary separation processes. In the primary separation process, the tar sand slurry is separated into three phases and floatable bitumen "froth", a heavy sand layer that is removed from the separation vessel in an underflow method and a supernatant or "middlings" which is a mixture of fine sands, silts, clays, bitumen and hot water that is decanted. The middlings supernantant undergoes a secondary separation process typically using dissolved air floatation processes to further extract bitumen not recovered in the primary separation vessel. The entire purpose heating the slurried tar sands in the primary and secondary separation processes is to release the bitumen from the tar sand mineral fraction and then to separate the bitumen from the mineral fraction using floatation and gravity separation processes. The bitumen froth is further treated to increase the bitumen content and reduce the water content. Typically, this processes includes the addition of naptha followed by either or both centrifugation or inclined plate and frame gravity-based oil separation processes. Following the inclined plate and frame settling process the mineral fraction left behind must have the naptha removed using distillation processing.

[0005] The majority of tar sands are below the existing capacity of surface mining techniques and require in situ methods. To date, only two in situ methods are commonly used to extract bitumen from tar sand deposits. High pressure and high temperature steam at 350oC is injected into the deeper tar sand deposits to fracture the media and then to propagate heat to reduce the viscosity of the bitumen enabling it to be extracted in wells. This process is generally repeated several times to extract the bitumen from the tar sands and consequently is called cyclic steam stimulation. A second in situ method utilizes directional drilling techniques to install parallel horizontal injection and extraction wells. The injection well in which high temperature steam iis injected into a tar sand formation is installed above the extraction well though which the reduced viscosity oil is extracted. Because this process destroys the structural integrity of the tar sands, water must be injected into the tar sands following this process to replace the removed water and bitumen to stabilize the deposit.

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[0006] The current use of hot water extraction process and an improvement to this process by adding NaOH to produce natural surfactants from tar sands is limited in effectiveness and requires large concentrations of NaOH to be effective in addition to steam requirements. This process is both chemical and energy intensive.

[0007] Improvements to the hot water extraction process by adding solvents such as naphtha, diesel oil, kerosene, chlorinated solvents have all be made to the basic hot water tar sand extraction process. In each case large concentrations of these added solvents are present in both the extracted bitumen phase, the supernatant phase and the solids phase. Because each of these compounds are quite toxic and hazardous to workers, as well as waterfowl and aquatic organisms, it is essential that the be removed from the clay-silt-sand fractions that result from the hot water tar sand extraction process. The presence of these above listed solvents requires expensive treatment to remove them and limits the reusability of the aqueous phase associated with lagoon type settling-disposal of these sediments.

[0008] After recovering oil from the reservoir, the extracted material undergoes further processing. Speight, et. al., of the Alberta Research Council conclude that the disposal of tailings from the hot water extraction process represents one the major problems facing commercial development. The surface active agents in the native bitumen, while having a beneficial effect of bitumen extraction, act as clay dispersants and adversely affect settling of particles in tailings ponds. This creates problems for recycling water needed in the slurrying and extraction processes and leads to large acreages need for the settling ponds. Further the presence of residual naphtha or other additives such as diesel in the sediments and unsettled particles in settling basins create problems discharging the highly contaminated water to rivers or groundwater.

SUMMARY OF THE INVENTION

[0009] A method according to the invention can include adding a surfactant and/or cosolvent (e.g., a plant-derived surfactant and/or cosolvent) and water to tar-sand ore to form a slurry, agitating the slurry, providing a settling time to allow the slurry to separate into a bitumen-rich layer, an aqueous layer, and a sand layer, and recovering bitumen from the bitumen-rich layer. One or more of these steps can be conducted at room temperature, e.g., at

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above the freezing point, for example, at above 0 ⁰ C or at least at about 5 ⁰ C, 10 ⁰ C, 15 ⁰ C,

20 ⁰ C, 25 ⁰ C, or 30 ⁰ C. One or more of these steps, e.g., agitating the slurry and providing a settling time to allow the slurry to separate can be conducted at less than about 75 ⁰ C, less than about 55 ⁰ C, less than about 40 ⁰ C, less than about 25 ⁰ C, less than about 20 ⁰ C, less than about

15 ⁰ C, less than about 10 ⁰ C, or less than about 5 ⁰ C.

[0010] A method according to the invention can include combining a plant-derived surfactant, water, and tar sand ore to form a mixture, agitating the mixture to form a slurry, allowing the slurry to separate into a bitumen-rich layer, an aqueous layer, and a sand layer, and recovering bitumen from the bitumen-rich layer. The aqueous layer can be clear upon recovery of the bitumen. The slurry can be allowed to separate into a bitumen-rich layer, an aqueous layer, and a sand layer in a vessel. For example, a vessel can be a container, a tank, a vat, or another structure for holding fluids and/or solids. After agitation, the slurry can be allowed to separate, without mixing, for a separation time. For example, this separation time can be less than or equal to about 10 minutes, less than or equal to about 30 minutes, less than or equal to about 1 hour, less than or equal to about 5 hours, less than or equal to about 12 hours, or less than or equal to about 1 day.

[0011] The term "clear" is to be understood to mean substantially clear. For example, a liquid that is substantially transparent can be considered to be clear, even though the liquid may be somewhat milky or hazy.

[0012] The slurry can include from about 5% to about 95% water, e.g., about 30% water, about 50% water, or about 60% water.

[0013] The bitumen can be processed into a petroleum product, e.g., synthetic crude oil, heating oil, diesel fuel, and gasoline.

[0014] In an embodiment no hydrocarbon other than the tar-sand ore is added to the slurry.

[0015] The surfactant and/or cosolvent can include a plant-derived surfactant and/or cosolvent. The surfactant and/or cosolvent can include a carboxylate ester, a plant-based ester, a terpene, a citrus-derived terpene, limonene, d-limonene, castor oil, coca oil, coconut oil, soy oil, tallow oil, cotton seed oil, a naturally occurring plant oil, a nonionic surfactant, ethoxylated soybean oil, ethoxylated castor oil, ethoxylated coconut fatty acid, amidifϊed, ethoxylated coconut fatty acid, ALFOTERRA 123-8S, ALFOTERRA 145-8S, ALFOTERRA L167-7S,

ETHOX HCO-5, ETHOX HCO-25, ETHOX CO-40, ETHOX ML-5, ETHAL LA-4, AG-6202,

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AG-6206, ETHOX CO-36, ETHOX CO-81, ETHOX CO-25, ETHOX T0-16, ETHSORBOX

L-20, ETHOX MO- 14, S-MAZ 8OK, T-MAZ 60 K 60, TERGITOL L-64, DOWFAX 8390,

ALFOTERRA L167-4S, ALFOTERRA L123-4S, ALFOTERRA L145-4S, Citrus Burst-1,

Citrus Burst-2, Citrus Burst-3, Citrus Burst-7, Natural Musle, and combinations of these. The surfactant and/or cosolvent can be added to result in a concentration in a range of from about 1 g/L, 5 g/L, 25 g/L, 50 g/L, or 250 g/L to about 1 g/L, 5 g/L, 25 g/L, 50 g/L, or 250 g/L.

[0016] A salt, for example, sodium chloride, can be added to the slurry. For example, the salt can be added to result in a concentration in a range of from about 0.1 g/L, 1 g/L, 2.5 g/L,

5 g/L, 50 g/L, or 250 g/L to about 0.1 g/L, 1 g/L, 2.5 g/L, 5 g/L, 50 g/L, or 250 g/L.

[0017] A polymer, for example, a cellulose derivative, such as carboxymethylcellulose can be added to the slurry. For example, the polymer can be added to result in a concentration in a range of from about 0.1 g/L, 1 g/L, 10 g/L, or 50 g/L to about 0.1 g/L, 1 g/L, 10 g/L, or 50 g/L.

[0018] The settling time can be at least about 10 minutes, at least about 30 minutes, or at least about 60 minutes.

[0019] The sand layer formed from the slurry can include no more than about 2 wt.% hydrocarbons, no more than about 1 wt.% hydrocarbons, or no more than about 0.5 wt.% hydrocarbons. The surface tension of the aqueous phase can be at least about 35 mN/m, at least about 50 mN/m, at least about 60 mN/m, or at least about 70 mN/m. The surface tension can be that corresponding to a temperature of the aqueous phase of 0, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ⁰ C, or another temperature. The surface tension of an aqueous solution is dependent on temperature. For example, the surface tension of pure water at a temperature of 0, 10, 20, 30,

40, 50, 60, 70, 80, 90, and 100 ⁰ C is 75.6, 74.2, 72.8, 71.2, 69.6, 67.9, 66.2, 64.5, 62.7, 60.8, and

58.9 mN/m, respectively. The turbidity of the aqueous layer can be no more than about 100

NTU, no more than about 75 NTU, or no more than about 50 NTU.

[0020] In this text, the terms "interfacial tension" and "surface tension" are used interchangably.

[0021] In an embodiment according to the invention, a composition includes tar sand ore, a surfactant and/or cosolvent, and water. The surfactant and/or cosolvent can include a plant-derived surfactant and/or cosolvent. The composition can be in the form of a slurry. The composition can be in the form of layers of a bitumen-rich layer, an aqueous layer, and a sand layer.

[0022] A method according to the invention includes designing a tar sands extraction

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protocol, which can include testing samples of tar sands with various concentrations and combinations including surfactant, salt, and polymer and identifying optimal conditions for separating bitumen from sand.

[0023] A method according to the invention includes the following. A plant-derived surfactant, water, and tar sand ore can be combined to form a slurry. The slurry can be transported over a distance with a pipeline or conveyor. At the end of the pipeline or conveyor, the slurry can be transferred to a settling tank. The slurry can be allowed to separate into a bitumen-rich layer, an aqueous layer, and a sand layer. Bitumen can be recovered from the bitumen-rich layer. The aqueous layer can be clear upon recovery of the bitumen. The volume of surfactant in the slurry can be less than about 0.15 mL per gram of tar sand ore. For example, the volume of surfactant in the slurry can be less than about 0.1, less than about 0.05, less than about 0.03, less than about 0.02, less than about 0.01, less than about 0.005, less than about 0.003, less than about 0.002, or less than about 0.001 mL per gram of tar sand ore.

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BRIEF DESCRIPTION OF THE DRAWINGS

[0024] Figure 1 presents a cartoon of a bitumen separation process for tar sands ore.

[0025] Figure 2 presents a cartoon of a primary separation and floatation process for tar sands ore.

[0026] Figure 3 presents a cartoon of a settling pond and flows into and out of the pond.

[0027] Figure 4 depicts the influence of VeruSOL-7, d-Limonene, and Carboxy Methyl

Celluose and Concentrations on Alberta Tar Sand extraction.

[0028] Figure 5 depicts the influence of VeruSOL-7 and d-Limonene Concentrations on interfacial tension (IFT) during Alberta Tar Sand extraction.

[0029] Figure 6 depicts the influence of VeruSOL-7 and d-Limonene concentrations on pH during Alberta Tar Sand extraction.

[0030] Figure 7 depicts the influence of VeruSOL-7 and d-Limonene concentrations on turbidity (NTU) during Alberta Tar Sand extraction.

[0031] Figure 8 A depicts the influence of VeruSOL-7, d-Limonene, and sodium chloride concentrations on soil residual TPH (total petroleum hydrocarbon) concentration.

[0032] Figure 8B depicts the influence of NaCl concentrations on TPH concentrations remaining in tar sands after extraction.

[0033] Figures 9A through 9F depict the influence of NaCl and Carboxy Methyl

Celluose concentrations on bitumen extraction and supernatant turbidity after settling periods of

0 minutes, 5 minutes, 10 minutes, 30 minutes, 1 hour, and 5 hours, respectively.

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DETAILED DESCRIPTION

[0034] Embodiments of the invention are discussed in detail below. In describing embodiments, specific terminology is employed for the sake of clarity. However, the invention is not intended to be limited to the specific terminology so selected. A person skilled in the relevant art will recognize that other equivalent components can be employed and other methods developed without parting from the spirit and scope of the invention. All references cited herein are incorporated by reference as if each had been individually incorporated. [0035] Compositions using natural surfactants and mixtures of natural surfactants, natural biopolymers, natural cosolvents to extract oil from reservoirs and tars from sand and/or shale deposits are novel and not practiced in the past. Combinations of mixtures of natural surfactants, natural biopolymers, natural cosolvents with chemical oxidants to condition oil and tar prior to treatment with natural surfactants, natural biopolymers, and/or natural cosolvents are novel. The use of salts, acids and bases with natural surfactants, natural biopolymers, natural cosolvents and oxidants is novel. These processes enable the use of renewable resources to extract oils and tars from otherwise unrecoverable sources.

[0036] Salts used can include inorganic salts, such as sodium bromide, and organic salts, such as potassium acetate. Salts used can include basic salts (such as calcium carbonate), acid salts (such as calcium phosphate), and neutral salts. Salts used can include can include compounds that upon dissolution yield monovalent anions (such as magnesium chloride), divalent anions (such as magnesium sulfate), or polyvalent anions. Salts used can include compounds that upon dissolution yield monovalent cations (such as sodium chloride (NaCl), sodium carbonate, and sodium bicarbonate), divalent cations (such as calcium chloride), or polyvalent cations. Examples of salts that can be used include alkali metal salts, such as sodium sulfate, alkali metal halides, such as potassium chloride, alkaline earth metal salts, such as calcium sulfate, alkaline earth metal halides, such as calcium bromide, metal salts, such as aluminum sulfate, metal halides, such as aluminum chloride, and others.

[0037] The compositions consist of natural biodegradable surfactants and cosolvents.

The compositions may also use synthetic surfactants and cosolvents with similar efficacy. Examples of natural biodegradable surfactants that can be used are yucca extract, soapwood extract, and other natural plants that produce saponins, such as horse chestnuts (Aesculus),

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climbing ivy (Hedera), peas (Pisum), cowslip, (Primula), soapbark (Quillaja), soapwort (Saponaria), sugar beet (Beta) and balanites (Balanites aegyptiaca). Many surfactants derived from natural plant oils are also known to exhibit excellent surfactant power, and are also biodegradable and do not degrade into more toxic intermediary compounds. [0038] Examples of surfactants and/or cosolvents that can be used include terpenes, citrus-derived terpenes, limonene, d-limonene, castor oil, coca oil, coconut oil, soy oil, tallow oil, cotton seed oil, or a naturally occurring plant oil. The surfactant and/or cosolvent can be a nonionic surfactant, such as ethoxylated soybean oil, ethoxylated castor oil, ethoxylated coconut fatty acid, and amidified, ethoxylated coconut fatty acid. The surfactant and/or cosolvent can be ALFOTERRA 123-8S, ALFOTERRA 145-8S, ALFOTERRA L167-7S, ETHOX HCO-5, ETHOX HCO-25, ETHOX CO-5, ETHOX CO-40, ETHOX ML-5, ETHAL LA-4, AG-6202, AG-6206, ETHOX CO-36, ETHOX CO-81, ETHOX CO-25, ETHOX TO-16, ETHSORBOX L-20, ETHOX MO-14, S-MAZ 8OK, T-MAZ 60 K 60, TERGITOL L-64, DOWFAX 8390, ALFOTERRA L167-4S, ALFOTERRA L123-4S, ALFOTERRA L145-4S, Citrus Burst-1, Citrus Burst-2, Citrus Burst-3, Citrus Burst-7, Natural Musle, or combinations of these. [0039] For example, a composition of surfactant and cosolvent can include at least one citrus terpene and at least one surfactant. A citrus terpene may be, for example, CAS No. 94266-47-4, citrus peels extract (citrus spp.), citrus extract, Curacao peel extract (Citrus aurantium L.), EINECS No. 304-454-3, FEMA No. 2318, or FEMA No. 2344. A surfactant may be a nonionic surfactant. For example, a surfactant may be an ethoxylated castor oil, an ethoxylated coconut fatty acid, or an amidified, ethoxylated coconut fatty acid. An ethoxylated castor oil can include, for example, a polyoxyethylene (20) castor oil, CAS No. 61791-12-6, PEG (polyethylene glycol)- 10 castor oil, PEG-20 castor oil, PEG-3 castor oil, PEG-40 castor oil, PEG-50 castor oil, PEG-60 castor oil, POE (polyoxyethylene) (10) castor oil, POE(20) castor oil, POE (20) castor oil (ether, ester), POE(3) castor oil, POE(40) castor oil, POE(50) castor oil, POE(60) castor oil, or polyoxyethylene (20) castor oil (ether, ester). An ethoxylated coconut fatty acid can include, for example, CAS No. 39287-84-8, CAS No. 61791-29-5, CAS No. 68921-12-0, CAS No. 8051-46-5, CAS No. 8051-92-1, ethyoxylated coconut fatty acid, polyethylene glycol ester of coconut fatty acid, ethoxylated coconut oil acid, polyethylene glycol monoester of coconut oil fatty acid, ethoxylated coco fatty acid, PEG- 15 cocoate, PEG-5 cocoate, PEG-8 cocoate, polyethylene glycol (15) monococoate, polyethylene glycol (5) monococoate, polyethylene glycol 400 monococoate, polyethylene glycol monococonut ester,

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monococonate polyethylene glycol, monococonut oil fatty acid ester of polyethylene glycol, polyoxyethylene (15) monococoate, polyoxyethylene (5) monococoate, or polyoxyethylene (8) monococoate. An amidified, ethoxylated coconut fatty acid can include, for example, CAS No. 61791-08-0, ethoxylated reaction products of coco fatty acids with ethanolamine, PEG-I l cocamide, PEG-20 cocamide, PEG-3 cocamide, PEG-5 cocamide, PEG-6 cocamide, PEG-7 cocamide, polyethylene glycol (11) coconut amide, polyethylene glycol (3) coconut amide, polyethylene glycol (5) coconut amide, polyethylene glycol (7) coconut amide, polyethylene glycol 1000 coconut amide, polyethylene glycol 300 coconut amide, polyoxyethylene (11) coconut amide, polyoxyethylene (20) coconut amide, polyoxyethylene (3) coconut amide, polyoxyethylene (5) coconut amide, polyoxyethylene (6) coconut amide, or polyoxyethylene (7) coconut amide.

[0040] Additional surfactants and cosolvents are presented in published PCT international application number WO2007/126779, which is hereby incorporated by reference. For example, the surfactant and/or cosolvent can be any combination of the above compounds. [0041] In this text, for brevity of terminology, unless otherwise stated, the term

"surfactant" is to be considered to include cosolvents as well as materials generally considered to be surfactants in the art within its definition.

[0042] In a method according to the invention, a surfactant and/or cosolvent (e.g., a plant-derived surfactant and/or cosolvent) and water can be added to tar sand ore to form a slurry. The slurry can be agitated and transferred to a settling tank. Alternatively, the slurry can be transported over a distance with a pipeline or conveyor, which can induce mixing of the components, before being transferred to a settling tank. A settling time can be provided to allow the slurry to separate into a bitumen-rich layer, an aqueous layer, and a sand layer. Bitumen can be recovered from the bitumen-rich layer.

[0043] For example, in a conventional process for separating bitumen from tar sands ore, such as the existing Clark extraction process, heat (thermal energy) and chemicals, such as sodium hydroxide (NaOH), diesel fuel, naphtha, and toluene, are added at several points. The added thermal energy, for example, in the form of hot water and/or steam, can be required to detach bitumen from tar sand particles and reduce the viscosity of the bitumen and tar sand ore. The heat added represents an added expense. Although the heat can be obtained from combustion of separated bitumen, this increases the pollution, for example, in terms of waste sand and emitted carbon dioxide and other gases, per unit of bitumen recovered for further

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hydrocarbon processing. In other words, obtaining the heat or thermal energy from the tar sands ore decreases the overall energy balance of the process. Added sodium hydroxide can serve to form surfactants from the bitumen. Added diesel fuel, naphtha, and toluene can serve to facilitate the flotation process. These added chemicals represent an additional expense. Moreover, a caustic chemical such as sodium hydroxide can result in an undesirable increase in pH of the surrounding environment. Toxic petroleum solvents and light distillates such as diesel fuel, naphtha, and toluene can cause harm when residual amounts are released into the environment. For example, in the process of preparing the tar sands ore, heat and chemicals are added after the ore has been crushed and before hot water is added to form a slurry. Heat and chemicals are added after pipeline conditioning of the slurry and before introduction of the slurry to a primary separation cell. The bitumen layer removed from the top of the separation cell is further heated to form the bitumen froth. Chemicals are added to sand removed from the bottom of the separation cell prior to placing the sand in a settling pond. In addition to the chemicals added during the process, which can include diesel fuel, naphtha, and toluene, the sand contains residual bitumen. These chemicals in the waste sand can have a deleterious effect on the environment, or can require further treatment, adding expense, before release into the environment. Moreover, the time for the sand and other fines, such as silt and clay, to settle in the ponds can be on the order of months or years, requiring considerable expenditure for maintenance of the ponds and the use of large areas of land, for example, hundreds of acres, for extended times. Residual tars resulting from incomplete bitumen detachment from sand during processing and incomplete floatation separation can float on the ponds. High toxicity chemicals from the process, such as diesel fuel, naphtha, toluene, and other chemicals can reside in the pond water. Because of the presence of residual chemical in the aqueous phase from the separation cell, recycling of water for reuse in the process or treatment prior to emission of the water to the environment can be difficult and costly.

[0044] Embodiments according to the present invention can simplify the process of separating bitumen from tar sands ore, reduce the amount of thermal energy input in the process, and eliminate or minimize the need for addition of chemicals such as sodium hydroxide, diesel fuel, naphtha, and toluene. Thus, the economics of the process of bitumen separation from tar sands ore can be improved and deleterious effects on the environment reduced. For example, the amount of steam required to be input in a process according to the present invention can be reduced by at least about 60% from the amount required for a conventional process. For

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example, the time required for settling of sand and fines such as silt and clay in a settling pond can be reduced. For example, the aqueous layer obtained from separation can be sufficiently clear that it can be directly discharged into the environment.

[0045] In an embodiment of the present invention, plant-derived surfactants and cosolvents, such as VeruSOL and d-limonene can be used to promote separation of the bitumen from the tar sands ore. Figure 1 illustrates steps in the preparation of the tar sands ore. Mined tar sands ore 122 is fed into the hopper 124 of a crusher system 126. The crushed tar sands ore can be temporarily stored 127 or can be directly fed into a pipeline 130 for pipeline conditioning and/or transport for further processing. A small amount of surfactant, such as the plant-derived surfactant VeruSOL or another biodegradable and/or environmentally-friendly surfactant can be introduced in an aqueous solution 128 into the crushed tar sands ore to form a slurry prior to pipeline conditioning. Microbubbles can be entrained in the aqueous solution 128. Such microbubbles can be introduced into the aqueous solution 128, for example, by adding hydrogen peroxide at a concentration of, for example, from about 1% to about 8%. Alternatively, microbubbles can be introduced into the aqueous solution 128 by introducing a compressed gas, such as nitrogen or air, into the aqueous solution 128 under pressure, so that microbubbles form when the pressure on the aqueous solution 128 is decreased, for example, when the aqueous solution 128 is exposed to ambient or atmospheric pressure. For example, the aqueous solution 128 introduced can include from about 2 g to about 25 g of VeruSOL surfactant per liter of water. The aqueous solution 128 need only be heated to a temperature sufficient to keep the solution from freezing. After conditioning in the pipeline 130, the conditioned tar sand slurry 132 can be fed to a subsequent separation process.

[0046] Figure 2 illustrates steps in a primary separation and flotation process according to the present invention. As needed, additional aqueous solution of a surfactant 148 can be introduced into the pipeline conditioned tar sand ore (slurry) 142. The surfactant can be a plant- derived surfactant. As needed, the additional aqueous solution of a surfactant 148 can be heated to prevent it from freezing and, as needed, microbubbles can be entrained into the solution. For example, microbubbles can be introduced into the solution through one of the techniques mentioned in the preceding paragraph. The pipeline conditioned tar sand ore (slurry) 142, with optional added surfactant, can be fed into a primary separation tank 144. From the primary separation tank 144, bitumen froth 150 can be separated and sent to a dearation unit 152. Once deaerated, the separated bitumen 154 can be stored. The separated bitumen 154 can, for

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example, be further processed into synthetic crude or other petrochemicals such as gasoline. [0047] Embodiments of the present invention, such as illustrated in Figs. 1 and 2, can be readily added, that is, "bolted-on", to existing bitumen separation processes. For example, an aqueous solution of surfactant 128 can be added to an existing stream of crushed tar sands ore 127 that is fed into a pipeline 130, as shown in Fig. 1. For example, an aqueous solution of surfactant 148 can be added to an existing stream of pipeline conditioned tar sand ore 142, prior to the pipeline conditioned tar sand ore 142 being fed into a primary separation tank 144, as shown in Fig. 2.

[0048] Figure 3 illustrates the flow of material into and out of a settling pond 170 bounded by containment walls 172 in an embodiment according to the present invention. Primary separation tailings 166, thickener fine tailings 164, and froth treatment sludge 162 can be introduced into the settling pond. Because of the addition of surfactant, such as a plant- derived surfactant, for example, VeruSOL or d-limonene, a greater fraction of bitumen can be separated from the tar sands ore than in a conventional process. As a result, for a given amount of useful hydrocarbon produced, less bitumen floats on the surface of the settling pond 170. Because no toxic chemicals are added, but rather only small amounts of surfactant and/or cosolvent, such as plant-derived surfactant, the contents of the settling pond 170 have little potential for environmental harm. Because of the absence of toxic chemicals and the promotion of settling of sand and fines such as silt and clay to form a clear aqueous layer, recycled water 168 can be removed from the settling pond 170 for reuse in the process at a much greater rate than in a conventional tar sands separation process.

[0049] Optimal conditions for separating bitumen from sand can be conditions under which the concentration of surfactant, salt, and polymer are selected, so that the monetary profit realized by separating the bitumen from the sand is maximized. For example, the concentration of surfactant, salt, and polymer can be selected to maximize the fraction of bitumen released from the sand, in order to maximize the yield of recovered bitumen and the value thereof. For example, by lowering the interfacial tension, for example, by increasing the concentration of surfactant, the fraction of bitumen released from the sand can be increased. For example, if the curve of residual TPH (total petroleum hydrocarbon) concentration as a function of surfactant concentration exhibits a minimum, the surfactant concentration at that minimum can be selected as an optimal condition. For example, the curves for VeruSOL-7 solution with salt and for d-Limonene solution with salt in Fig. 8A may exhibit such a minimum in residual TPH, for

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example, at a surfactant concentration of about 25 g/L. For example, the concentration of another component, such as a salt, can be selected to be the concentration at which a minimum residual TPH is observed in a residual TPH versus component concentration curve. For example, comparison of Fig. 8A and Fig. 8B may indicate that sodium chloride exhibits such a minimum at a concentration of about 25 g/L. Alternatively, if the surfactant, salt, and polymer materials used have different costs per unit mass, the concentrations can be selected to minimize the concentration of expensive material (for example, surfactant and/or polymer) by using more inexpensive material (for example, salt), while achieving an acceptable yield of recovered bitumen. The concentration of surfactant, salt, and polymer can be selected, so that the value of the recovered bitumen minus the cost of the added surfactant, salt, and polymer is maximized. [0050] Environmental factors can also be considered in identifying optimal conditions for separating bitumen from sand. For example, by selecting the concentrations of surfactant, salt, and polymer to maximize the yield of recovered bitumen, the amount of residual bitumen in the sand can be minimized. This can be advantageous, as the hydrocarbons in such residual bitumen can act as undesirable pollutants when disposing of the separated sand. The surfactant, salt, and polymer materials may differ in the environmental burden they impose or environmental damage they cause when released into the environment. For example, a given mass of biodegradable surfactant or polymer may cause little environmental harm when released, whereas the same mass of an inorganic salt may cause relatively large environmental harm when released. In such a case, a greater concentration of the material that causes little environmental harm can be used, so that the concentration of the material that causes greater environmental harm is minimized. The profit and the environmental impact can each be weighted and be used to determine a set of optimal conditions. For example, a given type and level of impact to the environment can be assigned a monetary value. The cost of environmental impact associated with operating under a certain set of conditions can be subtracted from the profit realized by the recovery of bitumen to obtain a net profit. The conditions, for example, the concentrations of surfactant, salt, and polymer can then be selected to maximize the net profit.

[0051] Operating costs can be considered in determining optimal conditions. For example, the amount of surfactant in the aqueous phase can affect the settling of clays and fines. Too great a concentration of surfactant may act to promote the suspension of clays and fines and delay their settling. The delay in settling may require a settling pond to be maintained for a

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longer period of time, with an associated cost. The cost associated with a longer settling time can be subtracted from the profit realized from the recovery of bitumen to obtain a net profit, and conditions, such as the concentrations of surfactant, salt, and polymer can be selected to maximize the net profit. Other operating and maintenance costs can similarly be considered, for example, the cost of heat required to maintain a certain temperature of the slurry, for example, the cost of heat required to maintain the slurry at a temperature above the freezing point. [0052] Additional surfactants, cosolvents, and oxidants are presented in published PCT international application number WO2007/ 126779, which is hereby incorporated by reference in its entirety. The surfactant and/or cosolvent can be any combination of the above compounds. The oxidant can be any combination of the above compounds. This application claims the benefit of U.S. Provisional Application No. 61/064,553, filed March 11, 2008, which is hereby incorporated by reference in its entirety.

EXAMPLES

EXAMPLE 1

[0053] Extraction of bitumen from Alberta Tar Sands purchased from the Alberta

Research Council was conducted using VeruSOL™-7 and d-limonene. VeruSOL™-7 includes terpene and plant-based esters. Tests were conducted using aliquots of tar sands as received. Tests were conducted with and without NaCl to evaluate effects on the rapid separation of the bitumen from the tar sands and quality of the supernatant "middlings" (i.e., aqueous layer) phase. Additionally, the effects of the VeruSOL™-7 and d-limonene concentration on extraction and quality of the supernatant were also evaluated.

[0054] Experimental conditions evaluated are presented in Table 1. Tests, identified by a number and letter, were conducted in 60 mL vials used as reactors. A 20 g mass of tar sand and 30 mL of deionized water were placed in each vial. As shown in the table, for vial sets 1-6, either the VeruSOL-7 or d-Limonene were added as the surfactant to a vial, in quantities of 0.015, 0.15, 0.75, 1.5, or 3 mL. That is, for vial sets 1-6, VeruSOL-7 was added to those vials labeled A or C, wherease d-limonene was added to those vials labeled B or D. For vial sets 1-6, a quantity of 1.5 g of sodium chloride (NaCl) was added to those vials labeled A or B; and no

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NaCl was added to those vials labeled C or D. 1 mL of carboxymethyl cellulose biopolymer was added to the vials of set 6 (that is, vials 6A, 6B, 6C, and 6D).

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Table 1. Tar Sand Extraction Batch Experimental Conditions

[0055] Figure 4 presents a photograph of the vials (reactors) following a first test. In the test, for mixing, the vials were placed on a shaker table operating at 300 rpm for 1 hour. Thereafter, the contents of the vials (reactors) were allowed to settle for 1 hour. For all concentrations of VeruSOL™-7 and d-limonene tested there was excellent separation of the bitumen from the sands with a clear supernatant when NaCl was used. When NaCl was not used

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the supernatant quality was poor. Because separation of the bitumen and clay from the supernatant is a critical performance factor and is problematic with existing hot water extraction processes, this represents an important improvement over existing applications for tar sand extraction and processing.

[0056] Figure 4 shows that carboxymethyl cellulose provided a clear supernatant

(aqueous layer) with and without the addition of NaCl. The lowest concentrations of VeruSOL™-7 or d-limonene of 0.015 mL per 20 g of tar sand provided a clear supernatant when NaCl was added (vials IA and IB, respectively). This concentration translates to approximately 0.75 g VeruSOL™-7 and d-limonene per kg of tar sands (approximately 0.075 percent on a weight basis).

[0057] Obtaining a clear aqueous layer of low turbidity is desirable for several reasons.

For example, an aqueous layer of low turbidity can be recycled to form a slurry with fresh tar sands ore or used in another industrial process. For example, an aqueous layer of turbidity less than an amount specified by a government regulatory agency can be discharged to surface waters as waste water without additional or with only minimal treatment, such as residence in a settling pond or filtering. For example, when an aqueous layer of initial low turbidity is placed in a settling pond, the time required for the turbidity to further decrease to a level at which the aqueous layer can be released into the environment can be less than that for an aqueous layer of initial higher turbidity. A clear separation of the removed bitumen from the supernatant minimizes oil carryover into settling ponds or other supernatatant treatment systems, improving performance of those supernatant treatment systems.

[0058] The effects of the addition of VeruSOL™-7 and d-limonene on Interfacial

Tension (IFT) measurements are shown in Figure 5. The IFT values decreased from the low 70's mN/m for the lowest dose of VeruSOL™-7 and d-limonene to from about 50 to about 55 mN/m for the highest VeruSOL™-7 and d-limonene dose. The lowest VeruSOL™-7 and d-limonene doses had the highest IFT values, close to that for pure water. The vials with the lowest VeruSOL™-7 and d-limonene doses also exhibited good separation of bitumen from the tar sands and the formation of a clear supernatant (aqueous layer), an unexpected result. The capability to separate bitumen from tar sands with a low concentration of surfactant is advantageous, in that economic savings can be realized and the environmental burden lessened in comparison with a process that requires a higher concentration of surfactant. [0059] Following the same experimental set-up as described above, the effects of the

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addition of VeruSOL™-7, d-limonene, and NaCl on Interfacial Tension (IFT) on pH and turbidity (NTU) were measured and are depicted in Figs. 6 and 7, respectively. For example, Fig. 7 shows that with addition of about 5 g/L of VeruSOL or d-Limonene, the turbidity is less than about 50 NTU. With the addition of about 50 g/L of VeruSOL, the turbidity is about 120 NTU, and with the addition of about 50 g/L of d-Limonene, the turbidity is about 90 NTU. [0060] Schramm et al. (U.S. Patent 5,009,773) and Schramm (2006) indicate that the natural surfactants present in tar sand bitumen as produced by the reaction of high concentrations of sodium hydroxide (NaOH) leads to IFT values as low as 20 mN/m and must be at the critical micelle concentration to be optimal.

[0061] Our observations using food grade natural surfactants are directly opposed to the findings of Schramm. Without intending to be bound by theory, this can lead to the conclusion that the operative mechanisms controlling the release of bitumen and quality of the supernatant (aqueous phase) in the presently presented findings is quite different from those of Schramm. The residual turbidity of the supernatant (aqueous phase) in the presence of NaCl is quite low, but increases with surfactant c oncentration at concentrations greater than about 50 g/L of VeruSOL™-7 or d-limonene.

[0062] Residual Total Petroleum Hydrocarbon (TPH) concentrations present in the sands are presented in Fig. 8A. After shaking, the vials containing the compositions reflected in Fig. 8A were allowed to settle for 24 hours before extraction to determine the amount of residual TPH. d-limonene was the more effective surfactant, as the lowest TPH values were present in the sand layer with its use. At a concentration of 5 g/L of d-limonene with NaCl in the water phase (0.75 g NaCl per kg soil) the residual TPH concentration in the sand was less than about 2 percent, or 20 g/kg. As the concentration of d-limonene was increased in the presence of NaCl, the residual concentration of TPH in the sand fell to less than 1 percent, or 10 g/kg. For example, with 25 g/L of d-Limonene and 50 g/L of NaCl, the residual TPH concentration in the sand was less than about 1 percent, or 10 g/kg. At higher concentrations of d-limonene alone (no NaCl), the residual TPH values in the sand were the lowest, however the quality of the supernatant with d-limonene alone was poor. For example, at a concentration of 100 g/L of d-Limonene, with no NaCl, the residual TPH concentration in the sand was less than about 0.5 percent, or 5 g/kg.

[0063] Figure 8B presents the TPH concentration in the sands for solutions that included

25 g/L of VeruSOL and that included NaCl at several different concentrations. To generate the

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results shown in Fig. 8B, after shaking, the vials containing the compositions were allowed to settle for 24 hours before extraction to determine the amount of residual TPH. [0064] The effects of NaCl concentration and carboxy methyl cellulose concentration were evaluated using time series photography to investigate the effect of varying concentrations of these chemicals on the quality of the supernatant (aqueous phase) using VeruSOL™-7. Time series photographs are shown in Figs. 9A-9F. Vials (reactors) 7A-7D and 8A-8D are shown in the photographs. The mixtures in the vials 7A-7D and 8A-8D were initially prepared by placing the vials with their contents on a shaker table operating at 300 rpm for 1 hour; thereafter, the contents of the vials were allowed to settle for 1 hour. Each of the vials in sets 7 and 8 contained 20 g tar sands and 30 mL deionized water, and a concentration of 25 g/L VeruSOL. In addition, vials 7A, 7B, 7C, and 7D contained a concentration of 1, 2.5, 5, and 25 g/L of NaCl, respectively, but contained no carboxymethyl cellulose polymer. In addition, vials 8A, 8B, 8C, and 8D contained a concentration of 0.05, 0.1, 0.25, and 0.5 mL of carboxymethyl cellulose polymer, respectively, but contained no NaCl. Each of the vials 7A-7D and 8A-8D were shaken for 1 hour at 300 rpm. After this period of shaking (extraction phase), the contents of the vials (reactors) were allowed to settle. The period of settling for the vials shown in Figs. 9A, 9B, 9C, 9D, 9E, and 9F, was 0 mins., 5 mins., 10 mins., 30 mins., 1 hour, and 5 hours, respectively. [0065] Figure 9C shows that after a 10 minute settling period, the supernatant (aqueous phase) was substantially clear. After 30 minutes of settling (Fig. 9D), the supernatant was even more clear, with increasing clarity up to 1 hour (Fig. 9E) of settling. This is in contrast to the months of settling required using existing processes to extract tar sands using the hot water or the hot water NaOH enhanced extraction method.

[0066] The effects of NaCl concentration on tar sand extraction was investigated to determine the minimum concentration that could be used for excellent bitumen extraction from the tar sands while maintaining high quality and clear supernatant. The vials depicted in Figs. 9A-9F were allowed to settle for additional time. After 24 hours of settling, the sands were extracted to determine the residual amount of TPH. It was observed that with the 2.5 g/L of NaCl in vial (reactor) 7B, less than 0.5 weight percent TPH remained in the tar sands.

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EXAMPLE 2

[0067] Another embodiment of the present invention is as follows:

1) Obtain a sample of the material to be extracted including oil or tar and the mineral matrix.

2) Test pretreatment of the materials using chemical oxidants to test viscosity, surface tension and density changes.

3) Conduct testing of various mixtures of surfactants and cosolvents of the optimal formation of emulsions. The optimal formation leads to the maximum mass of oil or tar extraction while still maintaining an emulsion system and minimizing the mass of surfactants and cosolvents needed for optimal emulsification.

4) Test the addition of salts, acids and bases on the destabilization of colloids and on the effectiveness of the surfactant-cosolvent properties.

5) Conduct testing on the effects of adding various concentrations of biopolymers on the viscosity and density of the emulsion. The optimum choice of biopolymer and dose is one which increases the viscosity to a desired point for transport through the reservoir (or reactor) and for extraction recovery.

6) Test the effects of added heat on each of the above properties.

7) Conduct a field test using a sequence of treatment, oxidation, surfactant-cosolvent extraction, biopolymer addition to the emulsion or immediately following the surfactant-cosolvent addition.

8) Push the emulsified oil or tar with water or brine into a zone of extraction removal.

[0068] The embodiments illustrated and discussed in this specification are intended only to teach those skilled in the art the best way known to the inventors to make and use the invention. Nothing in this specification should be considered as limiting the scope of the present invention. All examples presented are representative and non-limiting. The above-described embodiments of the invention may be modified or varied, without departing from the invention, as appreciated by those skilled in the art in light of the above teachings. It is therefore to be understood that, within the scope of the claims and their equivalents, the invention may be practiced otherwise than as specifically described.

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REFERENCES

1) Gregoli, et. al. (U.S. Patent 5,340,467)

2) Speight, et. al. Factors affecting Bitumen Recovery by the Hot Water Extraction Process. Alberta Research Council, 1978.

3) Redford, et. al. (U.S. Patent 3938590)

4) Needham et. al (U.S. Patent 4,068,717)

5) Rabbitts (U.S. Patent 4,101,172)

6) Alquist et al (U.S. Patent 4,229,281)

7) McCoy et al. (U.S. Patent 4,321,147)

8) Noelle (U.S. Patent 4,338,185)

9) Canter et al. (U.S. Patent 4,453,806)

10) Siefkin et al (U.S. Partent 4,368,111)

11) Miller et al. (U.S. Patent 4,470,899)

12)Mishra et al., (U.S. Patent 6,019,888)

13) Vinegar et. al., (U.S. Patent 7,066,254 B2)

14) House (U.S. Patent 6,127,319)

15) Guymon (US Patent 4,968,412)

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REFERENCES (cont'd)

16) Olah (U.S. Patent 5,000,872)

17) Schramm et al (U.S. Patent 5,009,773)

18) Graham et. al. (U.S. Patent 5,143,598)

19) Athabasca Regional Issues Working Group, Fact Sheet, December 2007

20) Ferguson, Barry Glen. Athabasca Oil Sands: Northern Resource Exploration 1875 - 1951. Canada: Gray's Publishing Ltd., 1978.

21) University of Alberta. An Introduction to Development in Alberta's Oilsand. Canada: Rob Engelhardt, Marius Todirescu, Feb. 2005

22) World Energy Council. Cost Analysis of Advanced Technology for the Production of Heavy Oil and Bitumen in Western Canada, 2005. www.worldenergy.org