WO2009114146A2

WO2009114146A2 - In-situ low-temperature hydrocarbon recovery from tar sands

Info

Publication number: WO2009114146A2
Application number: PCT/US2009/001550
Authority: WO
Inventors: George E. Hoag; John Collins
Original assignee: Hoag George E; John Collins
Priority date: 2008-03-11
Filing date: 2009-03-11
Publication date: 2009-09-17
Also published as: WO2009114146A3

Abstract

A method for performing in-situ extraction of bitumen from tar sands using an injection fluid including hydrogen peroxide.

Description

IN-SITU LOW-TEMPERATURE HYDROCARBON RECOVERY FROM TAR SANDS

BACKGROUND OF THE INVENTION

[0001] Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about

10 percent of a reservoir's original oil in place is typically produced during primary recovery. Secondary recovery techniques to the field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.

[0002] However, with much of the easy-to-produce oil already recovered from U.S. oil fields, producers have attempted several tertiary, or enhanced oil recovery (EOR), techniques that offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original

011 in place. Two categories of EOR are:

[0003] - Thermal recovery, which involves the introduction of heat such as the injection of steam to lower the viscosity, or thin, the heavy viscous oil, and improve its ability to flow through the reservoir. Thermal techniques account for over 50 percent of U.S. EOR production, primarily in California.

[0004] - Gas injection, which uses gases such as natural gas, nitrogen, or carbon dioxide that expand in a reservoir to push additional oil to a production wellbore, or other gases that dissolve in the oil to lower its viscosity and improves its flow rate. Gas injection accounts for nearly 50 percent of EOR production in the United States. (U.S. Department of Energy) [0005] Thermal extraction processes utilize carbon fuels to generate heat and additionally add to the carbon footprint of this process. Thermal processes are not used in permafrost areas because the structural stability of the frozen ground is lost. Advanced oil recovery methods include microbially enhanced oil recovery (MEOR). While fundamental research has demonstrated the efficacy of using microbially generated surfactants (biosurfactants) in reservoirs, it has not been possible to widely use this technology because unsuitable environmental conditions exist in most reservoirs that are hostile to microbial stimulation. [0006] Carbon dioxide is the most common gas used to extract oil. Being a major greenhouse gas, this approach is not as desirable as other technologies and is very costly. Ongoing research is attempting to use oil reservoirs to sequester CO2 in the reservoirs, however, since the CO2 method is a bank-flood methods the injected CO2 is commonly designed to be removed from the subsurface along with the extracted oil.

[0007] 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.

[0008] 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. [0009] 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 of 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. [0010] 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 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.

[0011] 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 destroyed 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. [0012] 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.

[0013] 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 setlling-disposal of these sediments.

SUMMARY OF THE INVENTION

[0014] A method according to the invention for performing in-situ extraction of bitumen from tar sands includes providing an extraction well in the subsurface of the tar sands, injecting an injection fluid at an injection locus into the tar sands, the injection fluid comprising hydrogen peroxide, allowing the hydrogen peroxide to decompose to water and oxygen gas in the tar sands, and allowing the oxygen gas produced from decomposition of the hydrogen peroxide to impose pressure to force the bitumen through the tar sands toward the extraction well. The decomposition of the hydrogen peroxide can liberate heat that increases the temperature of the bitumen in the subsurface, thereby decreasing the viscosity of the bitumen. The hydrogen peroxide can partially oxidize the bitumen in the subsurface, thereby decreasing the viscosity of the bitumen.

[0015] In an embodiment according to the invention, the injection fluid flows from the injection locus through the subsurface to the extraction well at a mean velocity of at least about 0.1 cm/hour, at least about 0.2 cm/hour, at least about 0.3 cm/hour, at least about 0.5 cm/hour, at least about 1 cm/hour, at least about 2 cm/hour, at least about 3 cm/hour, at least about 5 cm/hour, at least about 10 cm/hour, at least about 20 cm/hour, at least about 30 cm/hour, at least about 50 cm/hour, at least about 100 cm/hour, at least about 200 cm/hour, or at least about 300 cm/hour. The injection fluid can be flowed through the subsurface for a period of time equal to at least about the mean time for a fluid element to flow from the injection locus to the injection well. The injection fluid can be flowed through the subsurface for a period of time equal to at least about 3 times, at least about 5 times, at least about 10 times, at least about 20 times, at least about 30 times, at least about 50 times, at least about 100 times, at least about 200 times, at least about 300 times, at least about 500 times, or at least about 1000 times the mean time for a fluid element to flow from the injection locus to the injection well. [0016] In an embodiment according to the invention, the hydrogen peroxide in the injection fluid is in the form of a solution of hydrogen peroxide in water, the hydrogen peroxide at a concentration in a range of from about 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.5 wt%, 1 wt%, 2 wt%, 3 wt%, 5 wt%, 8 wt%, 10 wt%, or 20 wt% to about 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.5 wt%, 1 wt%, 2 wt%, 3 wt%, 5 wt%, 8 wt%, 10 wt%, or 20 wt%.

[0017] In an embodiment according to the invention, the injection fluid can include a surfactant and/or cosolvent. For example, the surfactant and/or cosolvent can be 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, amidified, 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, 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, VeruSOL, VeruSOL-3, and combinations of these. The surfactant and/or cosolvent can be at a concentration of from about 1 g/L, 2 g/L, 3g/L, 5 g/L, 10 g/L, 20 g/L, 30 g/L, 50 g/L, or 100 g/L to about 1 g/L, 2 g/L, 3g/L, 5 g/L, 10 g/L, 20 g/L, 30 g/L, 50 g/L, or 100 g/L. [0018] In an embodiment according to the invention, the injection fluid can include sodium bicarbonate. For example, the sodium bicarbonate can be at a concentration in a range of from about 1 g/L, 2 g/L, 3 g/L, 5 g/L, 8 g/L, 10 g/L, 16 g/L, 20 g/L, 30 g/L, 50 g/L, 100 g/L, or 200 g/L to about 1 g/L, 2 g/L, 3 g/L, 5 g/L, 8 g/L, 10 g/L, 16 g/L, 20 g/L, 30 g/L, 50 g/L, 100 g/L, or 200 g/L.

[0019] In an embodiment according to the invention, the injection fluid can include Fe-

NTA. For example, the iron of the Fe-NTA can be at a concentration of from about 10 mg/L, 20 mg/L, 30 mg/L, 50 mg/L, 100 mg/L, 200 mg/L, 250 mg/L, 300 mg/L, 500 mg/L, 1000 mg/L, 2000 mg/L, 3000 mg/L, or 5000 mg/L to about 10 mg/L, 20 mg/L, 30 mg/L, 50 mg/L, 100 mg/L, 200 mg/L, 250 mg/L, 300 mg/L, 500 mg/L, 1000 mg/L, 2000 mg/L, 3000 mg/L, or 5000 mg/L.

[0020] A method according to the invention of recovering bitumen from tar sands can include injecting a hydrogen peroxide solution into the tar sands, reducing the viscosity of the bitumen, and extracting the bitumen from the tar sands. A method of producing petroleum can include one or more above methods, and further include processing the bitumen to remove any additives that interfere with refining the bitumen.

[0021] In an embodiment according to the invention, a tar sands extraction zone can include sand, bitumen, and hydrogen peroxide in a tar sands subsurface. The tar sands extraction zone can further include at least one of a surfactant and/or cosolvent (e.g., VeruSOL) and an alkali carbonate (e.g., sodium bicarbonate).

[0022] A method according to the invention of designing a bitumen recovery procedure can include obtaining a sample from a tar sand site of interest, for example, a core sample, or composing a simulated or analogous sample, testing the sample with various concentrations of hydrogen peroxide, other oxidants, and surfactants and/or co-solvents, e.g., VeruSOL, and under various conditions of temperature, flow rate, and pressure, determining the rate of mobilization of the bitumen under the various conditions, and selecting an optimum set of conditions for extracting bitumen from the tar sand site of interest. The method can further include extracting bitumen from the tar sand site of interest. The method can further include processing the bitumen into a petroleum product, e.g., synthetic crude oil, heating oil, diesel fuel, and/or gasoline.

BRIEF DESCRIPTION OF THE DRAWINGS

[0023] Figure IA depicts a bar graph presenting the final soil TPH (total petroleum hydrocarbons) concentrations in several columns through which various fluids (e.g., VeruSOL-

3, H2O2 (Hydrogen Peroxide), and nitrogen air are flowed.

[0024] Figures IB to IK present images of the columns for which final soil TPH concentrations are shown in Fig. 1 a before fluid is flowed through the column and after a period of flowing fluid through the column.

[0025] Figures 2A to 2F present images of columns that depict displacement of NAPL in several columns through which hydrogen peroxide (H2O2), sodium bicarbonate (NaHCCβ), and

Verusol are flowed at various concentrations.

[0026] Figures 3 A to 3F present images of columns that depict displacement of NAPL in columns through which hydrogen peroxide (H2O2) and Fe-NTA is flowed, with and without

Verusol.

DETAILED DESCRIPTION

[0027] A third category of enhanced oil recovery (EOR) technique is chemical injection, which can involve the use of long-chained molecules called polymers to increase the effectiveness of waterfloods, or the use of detergent-like surfactants to help lower the surface tension that often prevents oil droplets from moving through a reservoir. Chemical techniques account for less than one percent of U.S. EOR production. (U.S. Department of Energy) [0028] A surfactant or a mixture of surfactants and cosolvents can be simultaneously or sequentially be applied with a gas to a hydrocarbon containing subsurface formation. The gas can provide a hydraulic potential (pressure) to push the hydrocarbon to a recovery well. The surfactant and/or cosolvents can be applied first and then the gas pressure can be applied, or the surfactants and/or cosolvents can be applied simultaneously with the gas pressure. The gas can be created by injecting a liquid that upon contact with the subsurface materials decomposes into a gas (e.g., hydrogen peroxide solution). The gas phase can be created by pressurizing a gas phase into water (or another injected liquid) above ground or while injecting, so that upon release in the subsurface at lower pressure the dissolved gas comes out of solution and forms a gas phase. Additionally, the gas may be injected as a compressed gas or a supercritical fluid. The gas can include, for example, air, oxygen, nitrogen, carbon dioxide, or a noble (inert) gas, or a combination of gases. Carbon dioxide (CO2) may be useful as a gas; its use can serve the dual purpose of recovering subsurface hydrocarbons and sequestering the carbon dioxide, a greenhouse gas.

[0029] The composition of a surfactant and/or cosolvent liquid amendment for injection into a subsurface can include a natural surfactant or a surfactant derived from a natural product, such as a plant oil or plant extract. Mixtures of these natural surfactants or surfactants derived from natural products can be chosen to best emulsify the subsurface oil, tar, or bitumen such that a mobile phase emulsion is formed with greatly differing properties from the source oil, tar, or bitumen. The choice of surfactants and/or cosolvents can be based on the testing of the source oil, tar, or bitumen material. For example, a surfactant and/or cosolvent mixture can be selected to produce a low interfacial tension that enables the formation of either Winsor Type I, Winsor Type II, or Winsor Type III systems. A preferred formation of microemulsions is to form Winsor Type III microemulsions or Winsor Type I microemulsions. Frequently the preferred natural solvent such as those derived from plants are generally biodegrable, including terpenes. Terpenes are natural products extracted from conifer and citrus plants, as well as many other essential oil producing species. The combination of cosolvent and surfactants enhances the formation of microemulsions from highly viscous crude oils and tars. The specific choice of natural cosolvents and the ratio of cosolvent to surfactant can be based on laboratory tests conducted on the specific oil, tar, or bitumen to be emulsified. All of the above natural surfactants, surfactants derived from natural oils and natural cosolvents can be combined into formulations to form non- or low-toxicity macroemuslions and microemulsions, with crude oils, tars, and bitumens, enhancing their recovery from oil reservoirs or tar sands. Once emulsified, the petroleum oil-surfactant-cosolvent system or the tar(or bitumen)-surfactant-cosolvent system is formed, so that the hydrocarbon is amenable to become mobile in the reservoir, tar sand formation, or process reactor.

[0030] Compositions for use as surfactant and/or cosolvent liquid amendments for subsurface injection can include natural biodegradable surfactants and cosolvents. Natural biodegradable surfactants can include those that occur naturally, such as yucca extract, soapwood extract, and other natural plants that produce saponins, such as horse chestnuts (Aesculus), 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 known to exhibit excellent surfactant power, and are biodegradable and do not degrade into more toxic intermediary compounds. [0031] 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, 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, and ALFOTERRA L145-4S. [0032] 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, 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 (1 1) 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 (1 1) coconut amide, polyoxyethylene (20) coconut amide, polyoxyethylene (3) coconut amide, polyoxyethylene (5) coconut amide, polyoxyethylene (6) coconut amide, or polyoxyethylene (7) coconut amide.

[0033] Examples of surfactants derived from natural plant oils are ethoxylated coca oils, coconut oils, soybean oils, castor oils, corn oils and palm oils. Many of these natural plant oils are US FDA GRAS. The addition of biopolymers to the surfactant-cosolvent mixture may be used to thicken the emulsion to enhance hydrocarbon recovery efforts. Biopolymers can be useful in increasing the viscosity of the emulsion enabling the emulsified oil, tar, or bitumen to be pushed to an extraction well with a lower cost bulk liquid injectant such as a water or brine solution. Similarly, the microemulsion can be followed by an injection of a biopolymer to shield the microemulsion from the bulk liquid injectant used to push the microemulsion to an extraction well. If the oil or tar is particularly viscous then the addition of a chemical oxidant, such as hydrogen peroxide and/or sodium persulfate, can enhance the extraction of the oil, tar, or bitumen by the buildup of pressure (for example, oxygen and CO2 in the case of peroxide and CO2 in the case of persulfate). Additionally, the oxidants can used to pre-treat an oil or tar sands reservoir to condition the oil, tar, or bitumen (that is, the hydrocarbon) making the hydrocarbon more amenable to emulsification and/or transport. Mineral amendments may be added to optimize emulsification and/or transport of oils, tars, and bitumen. Mineral amendments include salts, such as sodium chloride (NaCl), bases, such as sodium hydroxide (NaOH), and acids. The addition of NaCl may be particularly useful in low salt conditions where the destabilization of clay colloids, that may impact efficient and effective oil, tar, and bitumen recovery, can be facilitated by the addition of salt. The addition of acids and bases may also be utilized under conditions where destabilization of clay colloids is desirable. Finally heat may be added to initially decrease the viscosity of the tar, oil, or bitumen to enhance emulsion formation.

[0034] The composition using natural surfactants and mixtures of natural surfactants, natural biopolymers, natural cosol vents to extract oil from reservoirs and tars from sand and/or shale deposits is novel and not practiced in the past. The combination of mixtures of natural surfactants, natural biopolymers, natural cosolvents with chemical oxidants to condition the oil and tar prior to treatment with of natural surfactants, natural biopolymers, natural cosolvents is 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.

[0035] Additional surfactants, cosolvents, and oxidants are presented in published PCT international application number WO2007/ 126779, which is hereby incorporated by reference. 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. 61/064,554, filed March 11, 2008, which is hereby incorporated by reference in its entirety.

EXAMPLES

[0036] In several columns discussed in the following Examples, MGP (Manufactured

Gas Plant) DNAPL (Dense Non-Aqueous Phase Liquid), that is the tarry residue generated as waste at MGP sites, was used as the hydrocarbon in assessing the ability of various fluids to extract the hydrocarbon. MGP DNAPL has a consistency similar to that of the bitumen found in tar sands.

[0037] In general, development and design of a process for recovery hydrocarbons from subsurface formations, such as oil reservoirs and tar sands, can make use of actual samples of the subsurface formation, for example, core samples, and/or can make use of simulated or analogous samples. For example, a simulated or analogous sample may be formed by mixing a sand similar to that present in the formation of interest with a hydrocarbon, e.g., bitumen, similar to that present in the formation of interest in proportions representative of those found in the formation of interest.

EXAMPLE 1

[0038] To measure the effect on final soil total petroleum hydrocarbon (TPH) of

VeruSOL-3, H2O2, heat, and nitrogen air, an experiment was set-up as follows. Ten columns were set-up, each column having a length of 30 cm and a diameter of 5 cm. Each column contained 950 g of sand. All columns were spiked with 8 g of MGP (Manufactured Gas Plant) DNAPL (Dense Non- Aqueous Phase Liquid), and a flow rate of about 0.5 ml/min was induced. Columns also contained varying amounts of VeruSOL-3, deionized water, hydrogen peroxide (H2O2), nitriloacetic acid chelated iron (Fe(NTA)), sodium bicarbonate (NaHCCβ), tar sands, and/or nitrogen air, as indicated on the x-axis of the chart in Figure IA. Figure IA shows that the columns with a mixture of VeruSOL-3, hydrogen peroxide and either Fe(NTA) or NaHCCβ have the lowest final soil TPH concentrations. VeruSOL-3 includes citrus terpenes and plant- derived surfactants.

[0039] A comparison of each of these experimental set-ups against a control is presented in Figs. IB- IK. It should be noted that the photos in Figs. IB- IK corresponded to experiments allowed to run for differing amounts of time. The columns shown in Fig. IB contained 950 g sand spiked with 8 g DNAPL, through which an aqueous solution of 10 g/L VeruSOL was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 14 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. 1C contained 95O g sand spiked with 8 g DNAPL, through which deionized water was flowed at a rate of 0.5 mL/min; the temperature was maintained at 50 °C, and the test was conducted for a duration of 8 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. ID contained 950 g sand spiked with 8 g DNAPL, through which an aqueous solution of 10 g/L VeruSOL, 8% H2O2, and Fe(II)-NTA with 250 mg/L as Fe was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 14 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. IE contained 95O g sand spiked with 8 g DNAPL, through which an aqueous solution of 8% H2O2 and Fe(II)-NTA with 250 mg/L as Fe was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 14 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. IF contained 950 g sand spiked with 8 g DNAPL, through which an aqueous solution of 10 g/L VeruSOL, 8% H2O2, and 8.4 g/L NaHCO3 was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 4 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. I G contained 950 g sand spiked with 8 g DNAPL, through which an aqueous solution of 10 g/L VeruSOL, 4% H2O2, and 4.2 g/L NaHCO3 was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 4 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. IH contained 950 g sand spiked with 8 g DNAPL, through which an aqueous solution of 10 g/L VeruSOL, 2% H2O2, and 4.2 g/L NaHCC-3 was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 4 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. II contained 100 g tar sands and 1050 g clean sand through which an aqueous solution of 10 g/L VeruSOL, 8% H2O2, and 8.4 g/L NaHCCβ was flowed at a rate of 0.5 mL/min; the test was conducted for a duration of 13 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. IJ contained 950 g sand spiked with 8 g DNAPL, through which an aqueous solution of 10 g/L VeruSOL was flowed at a rate of 0.5 mL/min and nitrogen gas was flowed at a rate of 4 mL/min; the test was conducted for a duration of 14 days, and photographs of the columns before and after the test are presented. The columns shown in Fig. IK contained 950 g sand spiked with 8 g DNAPL, through which deionized water was flowed at a rate of 0.5 mL/min and nitrogen gas was flowed at a rate of 4 mL/min; the test was conducted for a duration of 10 days, and photographs of the columns before and after the test are presented.

EXAMPLE 2

[0040] To measure the effects of H2O2 and NaHCO3 on NAPL displacement, an experiment was set-up as follows and as shown in Fig. 2A. 950 g of sand and 8 g of DNAPL (MPG) were placed in each of four columns of 30 cm length, 5 cm diameter, and 589 ml volume. Varying amounts of H2O2 and NaHCO3 were added to each column, along with 10 g/L of VeruSOL. A flow rate of 0.5 ml/min was induced. Column Cl is a control column. Column C2 had a solution of 8% H2O2, 10 g/L VeruSOL and 16.8 g/L NaHCO3 flowed through it at a rate of 0.5 mL/min. Column C3 had a solution of 4% H2O2, 10 g/L VeruSOL and 8.4 g/L NaHCO3 flowed through it at a rate of 0.5 mL/min. Column C4 had a solution of 2% H2O2, 10 g/L VeruSOL and 8.4 g/L NaHCO3 flowed through it at a rate of 0.5 mL/min. Figures 2b-2f are photos of the experimental set-up at varying time intervals over the course of 54 hours. That is, Figs. 2B, 2C, 2D, 2E, and 2F show the columns at times of 0, 3, 11, 33, and 54 hours, respectively. Figure 2f shows that after 54 hours of running the experiment, no DNAPL remained in any of the columns containing H2O2, VeruSOL, and NaHCO3. EXAMPLE 3

[0041] To measure the efficacy of VeruSOL on displacing NAPL, an experiment was set-up as follows and as shown in Fig. 3A. As in Example 2, columns were prepared containing sand and DNAPL (MGP). 950 g of sand and 8 g of DNAPL (MPG) were placed in each of two columns of 30 cm length, 5 cm diameter, and 589 ml volume. Each column also contained 8% H2O2 and Fe-NTA (250mg/L as Fe (iron)), and had a flow rate of 0.5 ml/min. Column Cl had a solution of 8% H2O2 and Fe-NTA with 250mg/L as Fe (iron), with no VeruSOL, flowed through it at a rate of 0.5 mL/min. Column C2 had a solution of 8% H2O2, Fe-NTA with 250mg/L as Fe (iron), and 10 g/L VeruSOL flowed through it at a rate of 0.5 mL/min. Figures 3b-3f are photos of the experimental set-up at varying time intervals over the course of 24 hours. That is, Figs. 3B, 3C, 3D, 3E, and 3F show the columns at times of 0, 1, 9, 12, and 24 hours, respectively. Figure 3 f shows that after 24 hours of running the experiment, there was greater DNAPL displacement in column C2.

EXAMPLE 4

[0042] An embodiment of this 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.

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

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

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

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

10) Shpakoff et al., (U.S. Patent 7,229,950) 1 l)House (U.S. Patent 6,127,319) 12) Olah (U.S. Patent 5,000,872)

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

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

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

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

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

Claims

WE CLAIM:

1. A method for performing in-situ extraction of bitumen from tar sands comprising: providing an extraction well in the subsurface of the tar sands; injecting an injection fluid at an injection locus into the tar sands, the injection fluid comprising hydrogen peroxide; allowing the hydrogen peroxide to decompose to water and oxygen gas in the tar sands; allowing the oxygen gas produced from decomposition of the hydrogen peroxide to impose pressure to force the bitumen through the tar sands toward the extraction well.

2. The method of claim 1, wherein the decomposition of the hydrogen peroxide liberates heat that increases the temperature of the bitumen in the subsurface, thereby decreasing the viscosity of the bitumen.

3. The method of claim 1, wherein the hydrogen peroxide partially oxidizes the bitumen in the subsurface, thereby decreasing the viscosity of the bitumen.

4. The method of claim 1, wherein the injection fluid flows from the injection locus through the subsurface to the extraction well at a mean velocity of at least about 0.1 cm/hour, at least about 1 cm/hour, at least about 3 cm/hour, at least about 10 cm/hour, at least about 30 cm/hour, at least about 100 cm/hour, or at least about 300 cm/hour.

5. The method of claim 1, wherein the injection fluid is flowed through the subsurface for a period of time equal to at least about the mean time for a fluid element to flow from the injection locus to the injection well.

6. The method of claim 1, wherein the injection fluid is flowed through the subsurface for a period of time equal to at least about 3 times, at least about 10 times, at least about 30 times, at least about 100 times, at least about 300 times, or at least about 1000 times the mean time for a fluid element to flow from the injection locus to the injection well.

7. The method of claim 1 , wherein the hydrogen peroxide in the injection fluid is in the form of a solution of hydrogen peroxide in water, the hydrogen peroxide at a concentration in a range of from about 0.5 wt% to about 20 wt%.

8. The method of claim 1 , wherein the hydrogen peroxide in the injection fluid is in the form of a solution of hydrogen peroxide in water, the hydrogen peroxide at a concentration in a range of from about 2 wt% to about 8 wt%.

9. The method of claim 1, wherein the injection fluid further comprises Verusol.

10. The method of claim 9, wherein the Verusol is at a concentration of from about 1 g/L to about 100 g/L.

11. The method of claim 9, wherein the Verusol is at a concentration of about 10 g/L.

12. The method of claim 1, wherein the injection fluid further comprises sodium bicarbonate.

13. The method of claim 12, sodium bicarbonate is at a concentration in a range of from about 1 g/L to about 200 g/L.

14. The method of claim 12, sodium bicarbonate is at a concentration in a range of from about 8 g/L to about 16 g/L.

15. The method of claim 1, wherein the injection fluid further comprises Fe-NTA.

16. The method of claim 15, wherein the iron of the Fe-NTA is at a concentration in the injection fluid of from about 10 mg/L to about 5000 mg/L.

17. The method of claim 15, wherein the iron of the Fe-NTA is at a concentration in the injection fluid of about 250 mg/L.

18. A method of recovering bitumen from tar sands comprising injecting a hydrogen peroxide solution into the tar sands, reducing the viscosity of the bitumen, and extracting the bitumen from the tar sands.

19. A method of producing petroleum comprising one of the previous methods, and further comprising processing the bitumen to remove any additives that interfere with refining the bitumen.

20. A tar sands extraction zone comprising sand, bitumen, and hydrogen peroxide in a tar sands subsurface.

21. The tar sands extraction zone of claim 20, further comprising at least one of a surfactant and/or cosolvent (e.g., VeruSOL) and an alkali carbonate (e.g., sodium bicarbonate).

22. A method of designing a bitumen recovery procedure, the method comprising obtaining a sample from a tar sand site of interest or composing a simulated or analogous sample, testing the sample with various concentrations of hydrogen peroxide, other oxidants, and surfactants and/or co-solvents, e.g., VeruSOL, and under various conditions of temperature, flow rate, and pressure, determining the rate of mobilization of the bitumen under the various conditions, and selecting an optimum set of conditions for extracting bitumen from the tar sand site of interest.

23. The method of the claim 22, further comprising extracting bitumen from the tar sand site of interest.

24. The method of the claim 23, further comprising processing the bitumen into a petroleum product, e.g., synthetic crude oil, heating oil, diesel fuel, and/or gasoline.

25. The method of claim 1, wherein the injection fluid further comprises a surfactant and/or cosolvent.

26. The method of claim 25, wherein the surfactant and/or cosolvent is selected from the group consisting of a carboxylate ester, a plant-based ester, a terpene, a citrus-derived terpene, limonene, d-limonene, and combinations of these.

27. The method of claim 25, wherein the surfactant and/or cosolvent is selected from the group consisting of castor oil, coca oil, coconut oil, soy oil, tallow oil, cotton seed oil, a naturally occurring plant oil, and combinations of these.

28. The method of claim 25, wherein the surfactant and/or cosolvent is selected from the group consisting of a nonionic surfactant, ethoxylated soybean oil, ethoxylated castor oil, ethoxylated coconut fatty acid, amidifϊed, ethoxylated coconut fatty acid, and combinations of these.

29. The method of claim 25, wherein the surfactant and/or cosolvent is selected from the group consisting of 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, 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, and combinations of these.

30. The method of claim 25, wherein the surfactant and/or cosolvent is at a concentration of from about 1 g/L to about 100 g/L.

31. The method of claim 25, wherein the surfactant and/or cosolvent is at a concentration of about 10 g/L.