FORMULATIONS AND METHODS FOR REMOVING OIL-WET SOLIDS FROM AQUEOUS STREAMS

The invention encompasses methods for aggregating oil-wet solids in an aqueous suspension comprising providing an aqueous suspension containing oil-wet solids, and treating the aqueous suspension with an effective amount of a formulation comprising a tunable surfactant, thereby aggregating the oil-wet solids as removable aggregates. The invention also encompasses methods for extracting bitumen from oil sands ore and systems for separating bitumen from inorganic oil sands ore.

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Description
RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser. No. 61/661,584, filed Jun. 19, 2012, U.S. Provisional Application Ser. No. 61/695,751, filed Aug. 31, 2012, U.S. Provisional Application Ser. No. 61/711,811, filed Oct. 10, 2012, and U.S. Provisional Application Ser. No. 61/787,508 filed Mar. 15, 2013. The entire contents of the above applications are incorporated by reference herein.

FIELD OF APPLICATION

This application relates generally to recovering oil, removing oil, or removing oil-wet solids from aqueous streams using various surfactants.

BACKGROUND

Oil removal or oil recovery is advantageously pursued in a variety of settings. Oil as a contaminant is desirably removed from waste streams or process streams where it acts as a contaminant. In other settings, oil is desirably recovered as a valuable resource, for example bitumen from oil sands ore, or hydrocarbons from a petroleum reservoir.

In the process of drilling oil wells, aqueous streams such as salt-water-based drilling fluids can become contaminated with oil and suspended solids following drilling operations. Drilling fluid is generally held in an “active pit” tank or tanks, where it is drawn by a pump and circulated through the drill bit, then it returns to the surface and passes through a shale shaker to screen out coarse drill cutting particles or “cuttings”; finally, the fluid is returned to the active pit for reuse. When the drilling process penetrates an oil-bearing reservoir, hydrocarbon contaminants and fine particulates can become entrained into the drilling fluid, altering the properties of the fluid. The presence of these contaminants can render the drilling fluid unusable, especially when the contaminants accumulate during many passes through the underground drill bit; in some cases the oil contamination is significant enough that it alters the density of the drilling fluid so the fluid might not have sufficient mud weight to counterbalance the reservoir pressure. Removing oil from the drilling fluid stream along with removing other contaminating solids can allow the fluid to be reused as a drilling fluid or otherwise recycled or disposed of, decreasing the expense of disposal or perhaps eliminating disposal entirely. As another example, removing oil from oil-wet solids, tank bottoms, or waste sludges in the oilfield can offer the advantages of waste minimization, environmental compliance, hydrocarbon recovery, and cost savings. In certain oil production operations, a waste slurry containing oil, water, and insoluble solids is generated during the hot water or steamflood extraction of heavy oil. An effective means of separating the oil fraction from these wastes would allow for lower disposal costs of the waste slurry and allow the oil portion to be recovered for refining.

As another example, it is desirable to remove, extract or recover bitumen from oil sands. Bitumen in oil sands comprises roughly 30% of the world's oil reserves, with over 70% of the total oil sands reserves located in Canada and the United States. The oil producers in these regions face important economic and environmental challenges that limit the commercialization of these reserves. The environmental challenges include the emission of greenhouse gasses during extraction processes and the production of waste tailings, currently stored in tailings ponds.

Oil sands deposits consist of particulate solids, for example sand and clay, coated with bitumen. Bitumen is a heavy oil, with a high viscosity and density, rendering it difficult to separate from the particulate solids. Some oil sand deposits also have a hydration layer of water at the interface between the bitumen and the particulate solids, while others do not. Currently, a multi-stage process, the Clark hot water extraction process is used to separate the bitumen from the oil sands, a process most suitable for those deposits having a hydration layer. This process requires significant energy input to heat the hot water, it requires a significant amount of fresh water, and it produces a significant amount of waste water. Typically, the heating is accomplished by burning natural gas, with subsequent loss of heat to the environment and generation of greenhouse gases. The first stage of the hot water extraction process utilizes heated water in a hydro-transport pipe to separate out bitumen from the inorganic material to which it is bound. In the second, “froth flotation” step, small air bubbles are then passed through the slurry to lift naphtha-diluted bitumen to the surface for recovery.

Reducing the amount of heat needed for bitumen extraction would save money now spent on heating energy, and would lessen the environmental impact of these processes. In addition, current processes for extracting bitumen from oil sands consume a large amount of fresh water and produce a large amount of contaminated water. For every barrel of synthetic crude oil (SCO) produced in the oil sands extraction process, up to 10 barrels of contaminated water is produced. Discharging and storing this water in massive tailings ponds creates significant environmental liability for oil producers. There is a need in the art for an approach to extracting bitumen from oil sands that saves energy and that imposes less of a burden upon the environment. There is also a need in the art for extraction processes that are suitable for use in those oil sands without a hydration layer, where the traditional Clark hot water extraction process is not effective.

Currently, the froth treatment of bitumen recovered from oil sand extraction process utilizes solvents such as naphtha, a valuable fraction of purified petroleum, to dilute the bitumen and decrease the viscosity to the point of flowability. This allows solids and water to be removed by settling, froth flotation, and centrifugation methods. However, this step takes place after the initial, energy-demanding water extraction process, and serves only to provide a method of upgrading bitumen following its extraction. There remains a need in the art for bitumen extraction processes that can substitute for the hot water extraction processes and the costs that they entail.

SUMMARY

Disclosed herein, in embodiments, are methods for aggregating oil-wet solids in an aqueous suspension comprising providing an aqueous suspension containing oil-wet solids, and treating the aqueous suspension with an effective amount of a formulation comprising a tunable surfactant, thereby aggregating the oil-wet solids as removable aggregates. The methods can further comprise removing the removable aggregates. The methods can further comprise providing a flocculant and adding the flocculant to the aqueous suspension before, during or after the step of treating the aqueous suspension with the effective amount of the formulation comprising a tunable surfactant. The methods can further comprise providing a particulate formulation, and adding the particulate formulation to the aqueous suspension before, during or after the step of treating the aqueous suspension with the effective amount of the formulation comprising a tunable surfactant. Further disclosed herein, in embodiments, are methods for separating oil or solids from an aqueous slurry, comprising providing an aqueous slurry comprising oil and solids, treating the slurry with an effective amount of a formulation comprising a tunable surfactant, thereby segregating the oil or the solids from the slurry, and physically sequestering at least one of the oil and the solids, thereby separating the oil or the solids from the slurry. In embodiments, the slurry is derived from spent drilling fluid. In embodiments, the step of physically sequestering yields a reclaimable spent drilling fluid. In embodiments, the step of physically sequestering yields a brine solution. The methods can further comprise providing a particulate formulation comprising one or more solid particles, and adding the particulate formulation to the slurry before, during or after the step of treating the slurry with the effective amount of the formulation comprising a tunable surfactant. Also disclosed herein are methods for desorbing oil from oil-wet solids, comprising providing a sample of oil-wet solids, treating the sample with an effective amount of a formulation comprising a tunable surfactant to segregate the oil from the oil-wet solids, and sequestering the segregated oil, thereby desorbing the oil from the oil-wet solids. In embodiments, the method further comprises isolating the sequestered segregated oil, thereby recovering the oil. In embodiments, the method further comprises reusing the recovered oil. In embodiments, the desorbing of oil from the oil-wet solids reduces the amount of a waste material for disposal.

Disclosed herein, in additional embodiments, are methods for extracting bitumen from oil sands ore, comprising providing an oil sands ore containing bitumen; treating the oil sands ore with a hydrocarbon diluent to form a hydrocarbon-based slurry; treating the hydrocarbon-based slurry with at least one tunable surfactant to separate the bitumen from the oil sands ore, thereby forming a bitumen-containing portion and a separate inorganic-containing portion comprising the oil sands ore; and separating the bitumen-containing portion from the inorganic-containing portion, thereby extracting the bitumen from the oil sands ore; wherein each step takes place at a temperature within a lower temperature environment. In embodiments, the temperature is between 10 and 35 degrees Centigrade. In embodiments, the hydrocarbon diluent is diesel or naphtha. In embodiments, the at least one tunable surfactant is an aromatic surfactant or an aliphatic surfactant. In embodiments, the method further comprises treating the hydrocarbon-based slurry with a second tunable surfactant, wherein the second tunable surfactant is added to the hydrocarbon-based slurry with the at least one tunable surfactant to separate the bitumen from the oil sands ore. In embodiments, the at least one tunable surfactant is an aromatic surfactant and the second tunable surfactant is an aliphatic surfactant. In embodiments, the inorganic-containing portion comprises an aqueous phase containing suspended fines and a solid particulate phase containing sand. In embodiments, the method further comprises the step of mechanically agitating the hydrocarbon-based slurry before the step of treating the hydrocarbon-based slurry with the at least one tunable surfactant. In embodiments, the method further comprises the step of applying mechanical agitation after the step of treating the hydrocarbon-based slurry with the at least one tunable surfactant. In embodiments, the method further comprises the step of adding an acid after the step of treating the hydrocarbon-based slurry with the at least one tunable surfactant. In embodiments, the step of adding the acid adds the acid to the aqueous phase containing suspended fines.

Further disclosed herein are systems for separating bitumen from inorganic oil sands ore, comprising: a mixing chamber, whereby oil sands ore containing bitumen bound to inorganic oil sands ore is collectable in the mixing chamber; an introducer in fluid communication with the mixing chamber and in fluid communication with a reservoir containing a hydrocarbon diluent, wherein the hydrocarbon diluent is flowable from the reservoir through the introducer into the mixing chamber to contact the oil sands ore; a mechanical agitator disposed within the mixing chamber, wherein the agitation produced by the mechanical agitator mixes the hydrocarbon diluent and the oil sands to form a hydrocarbon-based slurry; a dispenser for a tunable surfactant in fluid communication with the hydrocarbon-based slurry, wherein the tunable surfactant is flowable at the ambient temperature into the hydrocarbon-based slurry to form a treated slurry, the treated slurry comprising a first phase containing bitumen and a second phase containing inorganic oil sands ore; and a separator adapted for separating the first phase from the second phase; wherein each component of the system operates at a temperature within a lower temperature environment. In embodiments, the temperature is between 10 and 35 degrees Centigrade. In embodiments, the system further comprises a mixer adapted for applying mechanical agitation to the treated slurry.

BRIEF DESCRIPTION OF THE FIGURES

The foregoing and other objects, features and advantages of the invention will be apparent from the following more particular description of preferred embodiments of the invention, as illustrated in the accompanying drawings in which like reference characters refer to the same parts throughout the different views. The drawings are not necessarily to scale, emphasis instead being placed upon illustrating the principles of the invention.

FIG. 1 shows 1 kilogram of high grade oil sands containing 12% bitumen.

FIG. 2 shows 1 kilogram of high grade oil sands dissolved in 250 grams of diesel.

FIG. 3 shows 1 kilogram of high grade oil sands dissolved in 250 grams of diesel and mixed with 800 mL of tunable surfactant solution for less than 1 minute.

FIG. 4 shows 1 kilogram of high grade oil sands dissolved in 250 grams of diesel and mixed with 800 mL of tunable surfactant solution for 240 minutes.

FIG. 5 shows two graduated cylinders, where the graduated cylinder on the left contains oil sands treated with diesel and water, and the graduated cylinder on the right contains oil sands treated with diesel and tunable surfactant solution.

FIG. 6 shows two vials, where the left vial shows the aqueous fines stream as recovered after treatment of oil sands with naphtha and tunable surfactants, and the vial in the right shows the same aqueous fines stream after the addition of mild acid to settle the fines from the solution.

FIG. 7 is a photograph of two jars, one containing an untreated sample of salt-water-based drilling fluid, and the other containing a treated sample.

FIG. 8 is a flow diagram depicting a process for treating samples of salt-water based drilling fluid.

FIG. 9 is a photograph of four vials of samples from Example 12 showing results from experiments as detailed below.

 DETAILED DESCRIPTION

Disclosed herein, in embodiments, are methods for separating oil and/or solid contaminants from aqueous streams using an aqueous tunable surfactant formulation.

As used herein, the term “tunable surfactant” includes compositions such as those described below and as set forth in U.S. patent application Ser. Nos. 12/481,072, 12/635,241, and 12/958,890 (U.S. Patent Application Publication No's. US 20090305933 A1, US 20110065612 A1 and US 20110309001 A1), the contents of which are incorporated herein by reference in their entireties. In embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the next formula (I):

wherein A is an alkyl, arylalkyl, alkenyl, alkadienyl, alkynyl, cycloalkyl, or cycloalkenyl, each optionally substituted; p is 1 or 2; preferably 2; each of m and n are independently 0, 1, 2, 3, 4, or 5; each of G1 and G2 are independently absent, O, S, NR2, (CO)O, O(CO), CO, CONR2, or NR2CO; each R2 is independently H or a lower alkyl; each G3 is independently absent, (CH2)q or G1; each q is independently 1, 2, 3, 4 or 5; each R is independently a hydrophilic group; and each R1 is independently a saturated or unsaturated hydrophobic aliphatic group. In certain aspects, each m is independently 1 or 2 and each n is independently 0 or 1. In some embodiments, at least one of G1 and G2 are present.

In embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the Formula (Ia):

wherein each t is independently 0 or 1; each G4 is independently O or NH; and A and R1 as defined above.

In additional embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the Formula (II):

wherein D is an aliphatic polymer; p is 1 or 2; preferably 2; each of m and n are independently 0, 1, 2, 3, 4, or 5; each of G1 and G2 are independently absent, O, S, NR2, (CO)O, O(CO), CO, CONR2, or NR2CO; each R2 is independently H or a lower alkyl; G3 is absent, (CH2)q or G1; each q is independently 1, 2, 3, 4 or 5; each R is independently a hydrophilic group; and each R1 is independently a saturated or unsaturated hydrophobic aliphatic group, or an aryl, heteroaryl, cycloalkyl, or cycloalkenyl group.

In certain embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the Formula (IIa):

wherein each t group is independently 0 or 1 or 2; each G4 is independently O or NH or is absent; and D and R1 are as defined above. In certain embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the Formula (IIb):

wherein each t is independently 0 or 1 or 2; each G4 is independently O or NH or is absent; each R2 is independently a COOH group, or salts of COO, or is absent, and D and R1 are as defined above. In an additional embodiment, the invention relates to a compound of Formula III:


EG5-D2)p;

wherein E is alkyl, alkenyl, alkadienyl, alkynyl, cycloalkyl, cycloalkenyl, aryl and heteroaryl; G5 is CONH; each D2 is independently a hydrophilic aliphatic polymer; and p is 1 or 2.

In other embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the Formula (IV):


D2-N(J)2;

wherein D2 is a hydrophilic aliphatic polymer; wherein each J is independently selected from the group consisting of hydrogen and the Fragment (A) having the structure shown below:

wherein each E in Fragment A is independently a hydrophobic group selected from the group consisting of alkyl, alkenyl, alkadienyl, alkynyl, cycloalkyl, cycloalkenyl, aryl and heteroaryl; and wherein at least one J is the Fragment (A).

In embodiments, the methods disclosed herein use surfactant formulations that comprise compounds having the Formula (V):


(J)2N-D2-N(J)2;

wherein D2 is a hydrophilic aliphatic polymer; each J is independently selected from the group consisting of H and the Fragment (A):

wherein each E in Fragment A is independently a hydrophobic group selected from the group consisting of alkyl, alkenyl, alkadienyl, alkynyl, cycloalkyl, cycloalkenyl, aryl and heteroaryl; and wherein at least two of J are Fragment (A). In one embodiment, compositions of particular use in these systems and methods can include at least one compound of the Formula (I), Formula (Ia), Formula (II), Formula (IIa), Formula (IIb), Formula (III), Formula (IV) or Formula (V) as described above.

In embodiments, the surfactant formulations disclosed herein comprise a compound that has the Formula (I), (Ia), (II), (IIa) or (IIb). In embodiments, the surfactant formulations encompass compounds having the Formula (I) or Formula (Ia), wherein A is an alkyl (e.g., a C3-C8 alkyl) or cycloalkyl, each optionally substituted. In another embodiment, A is an alkyl-substituted cyclopentyl or cyclohexyl. Examples of alkyl-substituted cyclohexyl are propylcyclohexyl and ethylcyclohexyl. In additional aspects, the surfactant formulations comprise a compound has the Formula (I), wherein each G1 is independently selected from the group consisting of O, S, NR2, C(O)O, OC(O), C(O), C(O)NR2 and NR2C(O). In yet additional aspects, the surfactant formulations comprise a compound that has the Formula (I), wherein each G1 is independently selected from the group consisting of C(O)O, OC(O), C(O), C(O)NR2 and NR2C(O). In yet further aspects, each G1 is independently selected from C(O)O and C(O)NR2. In additional aspects, the compound has the Formula (I), wherein p is 1. In yet additional aspects, the compound has the Formula (I) wherein p is 2. In a further aspect, the compound has the Formula (I) wherein m is 1 or 2. In yet additional aspects, the compound has the Formula (I), wherein n is 0 or 1. In yet another aspect, the compound has the Formula (I), wherein R is C(O)OH. In a further aspect, the compound has the Formula (I), wherein each R1 is independently selected from the group consisting of C5-C20 alkyl, C5-C20 alkenyl, and C5-C20 alkadienyl.

In other embodiments, the compound has the Formula (II) or (IIa) or (IIb), wherein D is selected from the group consisting of polyethylene glycol, poly(ethylene glycol)/poly(propylene glycol) copolymers, polyethylene glycol methyl ether, polyetheramine and ethylene oxide/propylene oxide block copolymer. In additional aspects, the compound has the Formula (II), wherein p is 1. In a further aspect, the compound has the Formula (II), wherein p is 2. In yet an additional aspect, the compound has the Formula (II), wherein m is 1 or 2, or n is independently 0 or 1, or a combination thereof. In another aspect, the compound has the Formula (II), wherein each G1 is independently OC(O), C(O)O, C(O), C(O)NR2 or NR2C(O). In an additional aspect, the compound has the Formula (II) wherein G2 is absent. In a further aspect, the compound has the Formula (II) wherein R is C(O)OH.

As described above, compounds of Formula (I), (Ia), (II), (IIa) and (IIb) comprise a hydrophilic portion (substituent R) and a hydrophobic group (substituent R1). In some embodiments, the hydrophobic groups include saturated or unsaturated carbon chains, preferably between five and twenty units in length, or five and eighteen units in length, or eight and twenty units in length, or hydrogen. In embodiments, the hydrophobic group comprises aryl or alkylaryl groups. The carbon chains can optionally be unsaturated and, when present, reside anywhere along the carbon chain. The hydrophilic portion of the inventive compounds can comprise one or more hydrophilic groups or substituents. Hydrophilic portions or groups can be ionizable groups, including, for example, amines and carboxylic acids. In certain aspects of the invention, the hydrophilic group is C(O)OH. Hydrophilic groups also include hydrophilic polymers, including, but not limited to, polyalkylamine, poly(ethylene glycol) or poly(ethylene glycol)/poly(propylene glycol) copolymers. Nonionic hydrophilic materials such as polyalkylamine, poly(ethylene glycol) or poly(ethylene glycol)/poly(propylene glycol) copolymers can be used to increase hydrophilicity or aid stability in salt solutions.

In some embodiments, the surfactant compound has the Formula (III). In certain aspects, D2 is a polymer or copolymer containing ether groups. Compounds having Formula (III) may be prepared by reacting an aliphatic or aromatic diacid with a polyetheramine. In an additional embodiment, the compound has the Formula (III), wherein each E is independently a C1-C6 alkyl.

In an additional embodiment, the surfactant compound has the Formula (IV) or Formula (V) as described above, wherein D2 is a polyether. In certain aspects, each E is independently a C5-C20 alkyl, C5-C20 alkadienyl or C5-C20 alkenyl.

In embodiments, the surfactant formulations disclosed herein further comprise dissolved additives that lower the freezing point of the formulation. Examples of the freezing point reducing additives include glycols, alcohols, salts, and urea.

In embodiments, the surfactants disclosed herein can be tunable surfactants. As used herein, the term “tunable” or “switchable” surfactants refers to a structural class of molecules whose surface active properties can be increased or decreased by application of a trigger. In embodiments, the trigger to change the properties of tunable surfactants is a change of environmental conditions like pH, temperature, ionic strength, and the like, or the presence of oil or a ‘breaker’ material. In embodiments, tunable surfactants can be selected for their ability to dissolve in an aqueous solution or form a stable dispersion in an aqueous solution, and upon the controlled application of a “trigger” the solubility of the tunable surfactant or stability of the tunable surfactant dispersion is reduced. The term “aqueous solution,” as used herein, refers to a water-containing solution where the total water content of the aqueous stream may range from as low as 10% to >99%, containing components in addition to water such as, but not limited to, any organic substance dissolved, dispersed, or emulsified in the aqueous phase, dissolved solids such as organic or inorganic salts, suspended solids such as clays, asphaltenes, silicates and the like. The tunable surfactant also has the surprising ability to cause the formation of aggregates of oil and solids or oil-wet solids in contaminated aqueous solutions. Once the aggregates are formed, the presence of the “trigger” will assist in the removal of the oil and/or solid aggregates formed by the tunable surfactant. In embodiments, the “trigger” can be provided before, after, or simultaneously with the formation of the aggregates. After the aggregates of oil and solids are formed, they can be removed from the solution by treatment with polymers and/or by mechanical separation techniques.

In embodiments, tunable surfactants can be selected for removing oil from aqueous solutions. The term “aqueous solution,” as used herein, refers to a water-containing solution where the total water content of the aqueous stream may range from as low as 10% to >99%, containing components in addition to water such as, but not limited to, any organic substance dissolved, dispersed, or emulsified in the aqueous phase, dissolved solids such as organic or inorganic salts, suspended solids such as clays, asphaltenes, silicates and the like. Additionally, the aqueous phase may be the non-continuous phase, either dispersed or emulsified in an organic liquid.

1. Bitumen Extraction from Oil Sands with Tunable Surfactants

Disclosed herein, in embodiments, are systems and methods for recovering bitumen from oil sands in a lower temperature environment, i.e., at a lower temperature. In embodiments, this process involves two steps: 1) treating the oil sands at a lower temperature with a hydrocarbon diluent; and 2) treating the resulting mixture with one or more “tunable surfactants” to extract the bitumen. The step of “treating,” as described herein, includes one or more processes of mixing and/or applying mechanical shear so that the tunable surfactant treatment material is able to interact adequately with the substrate being treated. Advantageously, the systems and methods disclosed herein are carried out a temperature that is lower than those currently employed in the art, although they are compatible with heating if desired. Such a temperature is termed a “lower temperature” herein. In embodiments, the systems and methods disclosed herein can be performed at temperatures of 10-35° C., advantageously at temperatures of 15-25° C. This contrasts favorably with oil sands extraction methods using continuous hot water processing where the processing temperatures are in the range of 35-55° C., or higher in older processes (e.g., up to 80° C.).

In embodiments, the first step of the process involves adding a diluent oil to the oil sands substrate and mechanically mixing these two components together. The diluent can prepare the oil sands substrate for interaction with the tunable surfactant(s) by lowering the viscosity of the bitumen adhering to the sands, thereby enhancing the ability of the tunable surfactant solution to separate the bitumen from the particulate solids. The diluent can also reduce the density of bitumen such that the density of the diluent/bitumen solution is less than that of the aqueous phase, thus allowing the diluent/bitumen solution to float above the aqueous phase, enabling easier recovery.

In embodiments, any hydrocarbon with a lower viscosity and density than bitumen can be used as a diluent. In embodiments, diesel, C5-C12 alkanes, or naphtha can be used as a diluent oil. It is desirable to use a minimal amount of diluent oil to reduce the cost associated with use and recovery of the diluent. In embodiments, the optimal diluent concentration is the minimum amount such that the density of the diluent/bitumen solution reduced below that of the aqueous phase, enabling the diluent/bitumen solution to float to the top of the aqueous phase for recovery. In embodiments, concentrations of naphtha comparable to what is used in the current extraction methods.

Following the combination of oil sands ore and the diluent oil, the mixture can be mechanically agitated, for example by applying mechanical shear. For example, a poly(tetrafluoroethylene) paddle at 200 rotations per minute can be used for mechanical agitation. In embodiments, a mixing head of any material, including ceramic, metal, and/or plastic materials can be used for mechanical agitation; specific examples of materials include stainless steel, poly(ethylene), silica glass, alumina, and similar materials. In embodiments, any geometry of mixing head can be used, such that the shear rate is in the range of 0.1 s−1 to 10,000 s−1. Agitation times of the oil sands ore and the diluent oil can range between less than 1 minute and several hours depending on the diluent oil concentration and the properties of the oil sands ore. Typically, longer mixing times can be required if the concentration of the diluent oil in the mixture is less. It is understood that other mixing devices and mixing protocols can be used, as would be appreciated by those having ordinary skill in the art.

As a second step, a dilute aqueous solution of one or more tunable surfactants can be added to the oil sands/diluent oil mixture. The tunable surfactants can function to liberate the bitumen from the oil sands solids. In an embodiment, a combination of two tunable surfactants, one with aromatic character and the other with aliphatic character can be used to liberate the oil-diluent-treated bitumen from the particulate solids. In embodiments, the tunable surfactants can comprise only one tunable surfactant, or two aliphatic tunable surfactants, or two aromatic surfactants; other combinations of multiple tunable surfactants can also be used. In embodiments, variations in the alkyl length of the tunable surfactant(s) can be made to enhance bitumen recovery. In embodiments, variations in the hydrophilic component of the tunable surfactant(s), changes in their molecular weight, changes in their composition, and the like, can be made to enhance recovery.

In embodiments, a tunable surfactant with aromatic character and a hydrophilic component consisting of poly(ethylene oxide) can be used to enhance recovery. In embodiments, a tunable surfactant, or combinations of tunable surfactants, with either aliphatic or aromatic character, and an additional component, or combination of components containing ethylene glycol, propylene glycol, ethylene oxide, propylene oxide, phenylene oxide, carboxylic acid, amine, amide, acrylic acid, acrylamide, aldehyde, ketone, imine, imide, ester, anhydride, glycol, and/or alcohol functional groups can be used to enhance recovery. In embodiments, the concentration of the tunable surfactant or combination of tunable surfactants is less than 1%, by weight, in water. In embodiments, the concentration of the tunable surfactant or combination of tunable surfactants is between 1% and 5%, by weight, in water. In embodiments, the concentration of the tunable surfactant or combination of tunable surfactants is between 5% and 20%, by weight, in water.

Following the combination of the tunable surfactant(s) and the diluent oil/oil sands mixture, the resulting mixture can be mechanically agitated, for example, by mechanical shear. For example, a poly(tetrafluoroethylene) paddle at 200 rotations per minute can be used for mechanical agitation. In embodiments, a mixing head of any material, including ceramic, metal, and/or plastic materials can be used for mechanical agitation; specific examples of materials include stainless steel, poly(ethylene), silica glass, alumina, and similar materials. In embodiments, the shear rate can range from 0.1 s−1 to 10,000 s−1. Other mixing methodologies known by those of ordinary skill are also compatible with the systems and methods disclosed herein. Mixing/agitation times of the diluted oil sands ore and the aqueous tunable surfactant solution can range between a few minutes and many hours depending on the diluent oil concentration used and the properties of the oil sands ore. Typically, longer mixing times are employed if the concentration of the diluent oil in the mixture is less. It is understood that other mixing devices and mixing protocols can be used, as would be appreciated by those having ordinary skill in the art. Mechanical mixing of the diluted oil sands ore and the aqueous tunable surfactant solution is carried out in a manner and to an extent that allows the tunable surfactants contact with the diluted bitumen in order to enhance separation from the solid particulates, and that allows a path for the diluted bitumen to rise to the surface of the aqueous phase. Without sufficient agitation the diluted bitumen, even after separation from the particulate solids, can become trapped below the solid particulates and not able to rise to the surface of the aqueous phase. However, mechanical agitation in a lower temperature environment can cause bitumen release from oil sands at a lower temperature, eliminating the need for “froth flotation,” which is typically used in the art.

Using the systems and methods described herein advantageously leads to other benefits, including reduction in the amount of diluent (naphtha) required for effective bitumen recovery, reduction in the amount of water required for effective bitumen recovery, and eliminating the need for heating of water for effective bitumen recovery.

In an embodiment, a vigorous mixing can be used initially to disperse the tunable surfactant in the oil sands. Gentle mixing thereafter helps the separation, as it allows diluted bitumen that may be trapped under the sand to find its way up to the aqueous phase, where it can float unimpeded to the surface. Also, the continued gentle mixing further disperses the tunable surfactant to allow access to all of the diluted bitumen that is on the sand, facilitating its removal. The actual removal will occur by skimming the oil layer off the top of the aqueous phase, or letting it flow out of a clarifying vessel as the overflow. This will be similar to the way the froth layer is recovered, except that the air bubbles were not needed.

Once the diluted bitumen is separated from the solids and aqueous solution, for example by froth flotation in a primary separation cell, a portion of the diluent oil can be recovered using a standard solvent recovery system, as is commonly used in current oil sands extraction processes. Without being bound by theory, it is understood that the density difference between the diluted oil (lowest), aqueous phase (middle), and solids (highest) can drive the separation. It is known in the art that it is helpful to allow for a portion of the diluent oil (7-30%, by weight) to remain in the bitumen, in order to control the viscosity of such recovered bitumen, enabling pipeline transport.

In embodiments, an acid such as hydrochloric acid can be added to the fines-laden aqueous stream, producing the middle layer shown in FIGS. 4 and 5 that results from treatment with diluent and tunable surfactants to remove the suspended fines from solution (see FIG. 6). In embodiments, any acid can be used to “switch” the tunable surfactants, where the term “switch” refers to changing the solubility or stabilizing/emulsifying behavior of the tunable surfactants, thereby altering their solubility in water and resulting in the settling of the fines from the aqueous solution. In embodiments, the acid can be added to the mixture of oil sands ore, diluent oil, and aqueous tunable surfactant solution before the removal of the diluent/bitumen oil phase. Adding the acid at this stage can enhance the phase separation between the oil, solid particulate, and aqueous phases. In embodiments, the acid can be introduced before the bitumen has been separated from the particulate solids.

Advantageously, the systems and methods disclosed herein allow for separation of bitumen from oil sands without requiring water, and in the lower temperature environment. In addition, the systems and methods disclosed herein can extract bitumen from oil sand ore that does not have a hydration layer. A hydration layer between the bitumen and the particulate solids is a requirement for the hot water extraction process currently used. Thus, those oil sands deposits lacking a hydration layer are presently not treatable using hot water extraction. Advantageously, the systems and methods disclosed herein are suitable for use with such deposits.

2. Tunable Surfactants for Contaminant Removal from Water-Based Drilling Fluid

In embodiments, tunable surfactant solutions can be used to consolidate oil and suspended solid contaminants from an aqueous solution, allowing for their removal. In the case of salt water based drilling fluids, the contamination of the fluid with oil and suspended solids results in a disruption of the desired fluid properties. Without removal of these contaminants, the fluid can no longer be used as a drilling fluid and will have to be disposed of. The consolidation of the oil and solid contaminants can be achieved by the treatment of the fluid with a tunable surfactant solution. In embodiments, the drilling fluids can be prepared with fresh water, or water containing relatively low salt content, such as 1000-20,000 ppm of total dissolved solids (TDS). In other embodiments, the drilling fluids can be prepared with brines such as salt water, seawater, KCl brine, zinc chloride brine, and the like; the TDS content of these brines can be in the range of 10,000-100,000 ppm and in some cases up to about 300,000 ppm.

In the treatment of water based drilling fluids, the conventional treatment is to remove large sized cuttings using a mechanical separation device known as a shale shaker. An additional component to the conventional treatments involves passing a portion of the fluid through a decanting centrifuge in an attempt to remove smaller cuttings and organic contaminants. The treatment with a high-speed centrifuge may be preceded by the injection of a water soluble flocculant and/or coagulant polymer. Often when the water based drilling fluid becomes contaminated with suspended solids that cannot be removed effectively by a shale shaker and/or high speed centrifuge, or contaminated with oil, the drilling fluid is considered a waste stream; this waste is either disposed of directly by landfill or slurry injection, or it is consolidated by sedimentation or centrifugation with the aid of water soluble polymer flocculants and/or solid particles. Water soluble polymers such as, but not limited to anionic, cationic, non-ionic, and amphoteric flocculants. The molecular weight of the polymer is typically greater than 100,000, and preferably greater than 1,000,000.

In the case of salt water or brine-based muds, for example with TDS content above 10,000 ppm, the effectiveness of consolidation processes with conventional flocculants is diminished. Also, as water based muds become contaminated with oil during drilling operations, the presence of oil, for example above 500 ppm oil, can cause the suspended solids to be less responsive to treatment by conventional flocculation processes. Some water based drilling fluids are known to become contaminated with much higher oil levels, such as 1-40% by volume. In these extreme conditions, the water based drilling fluid has become highly compromised in its suitability as an aqueous drilling fluid due to altered density, altered filtration or viscosity properties. The problem of oil contamination can lead to operational problems during drilling operations, since the density, or mud weight, of the fluid must be maintained within a well-defined range. When the density drops below a critical level, the pressure of the oil and gas containing reservoir can cause leakage or blowouts. The contaminated drilling fluid containing brine, solids, and oil can also have higher hazards for health and safety, and for environmental impact, resulting in higher transportation and disposal costs. In the case of either high brine content or high oil content, the treatability by conventional flocculation is compromised. It is an object of the invention to render these contaminated drilling fluids more treatable for the purpose of consolidation and minimization of the wastes generated. Another object of the invention is to enable the treatment of these contaminated drilling fluids during their use or after their use in drilling oil and gas wells. It is a further object of the invention to recover the water based fluid or brine from these drilling fluids. Although the treatment of the contaminated drilling fluids with water soluble polymer flocculants is often hindered by the presence of the contaminants, we have discovered that the tunable surfactants can improve the separation of contaminants from these fluids.

Tunable surfactants are selected according to compatibility with the components of the aqueous stream of interest, with factors including but not limited to solubility of the tunable surfactant in an aqueous phase, with solubility potentially being either desirable or undesirable, depending on the application. The ability to alter the solubility of the tunable surfactant as a function of pH and/or salt content can also be designed into the structure of the tunable surfactant. Other factors influencing the selection of a tunable surfactant including, affinity to an organic component of the aqueous stream of interest, for example by choosing a tunable surfactant structure containing either aliphatic and/or aromatic components, in order to provide affinity or compatibility to aromatic or aliphatic components in the aqueous stream of interest. Other factors influencing the selection of a tunable surfactant including, affinity to an inorganic component of the aqueous stream of interest, for example, but not limited to, an ethoxylated component may provide affinity to certain inorganic clays. It may be desirable to select multiple tunable surfactants to be used in combination with each other (in a blend) in order provide multiple of the characteristics described above. The tunable surfactants may be delivered to the solution of interest either in the neat form or dissolved, dispersed, or emulsified in a liquid, with the liquid being either aqueous or organic. Exemplary tunable surfactants include: Poly(ethyleneglycol)-block-poly(propyleneglycol)-block-poly(ethyeleneglycol)-bis(3-phenyl-succinic acid)ester, 2-(nonen-1-yl)succinic acid monobenzyl ester, 1-[methoxypoly(oxyethylene/oxypropylene)-2-propylamino]-3-phenoxy-2-propanol for aromatics; and Polyetherdiamine-bis-[3-(2-dedecen-1-yl succinic acid]amide, Poly(ethylene glycol)-bis-[octadecen-1-yl)succinic acid]ester, Poly(ethylene glycol)-bis[3-(2-nonen-1-yl)succinic acid]ester for aliphatics.

To treat an aqueous stream, the following method can be employed. The tunable surfactant can be added to the aqueous stream of interest either in the neat form, or dissolved, dispersed, or emulsified in a liquid, with the liquid being either aqueous or organic. In some cases it may be preferable to dissolve the tunable surfactant in a liquid, either organic or aqueous, in order to effectively deliver it homogeneously throughout the aqueous stream of interest. In some cases the solubility of the tunable surfactant in an aqueous solution can be controlled by adjusting the pH of the solution. In some cases it is desirable to dissolve the tunable surfactant in an aqueous solution to enable the homogeneous delivery of the tunable surfactant to the aqueous stream of interest, which the tunable surfactant may or may not be soluble in. In an exemplary example, the tunable surfactant is dissolved in an aqueous solution and mixed with an aqueous stream of interest that contains a high concentration of dissolved salts (above 10,000 ppm of dissolved salts), which the tunable surfactant is not soluble in. Delivering the tunable surfactant in an aqueous solution that it is soluble in, allows for the homogeneous distribution of the tunable surfactant throughout the aqueous phase of interest, before the tunable surfactant becomes insoluble in the aqueous phase of interest. This technique allows the tunable surfactant to be distributed more evenly throughout the aqueous stream of interest, increasing its efficacy. In some cases it is desirable to adjust the pH of the aqueous phase of interest after mixing with a tunable surfactant thus altering the solubility of the tunable surfactant, including but not limited to altering the pH in order to reduce the solubility of the tunable surfactant in order to remove contaminants from the aqueous stream of interest. The surfactant can be mixed with the aqueous stream by a variety of methods well-known in the art, such as in-line injection. In embodiments, the surfactant can be prepared preliminarily as a salt form in solution with its pH adjusted, for example, with a pH higher than about 5. Not to be bound by theory, in a specific application/example, the proposed mechanism for removing the oil and solid contaminants can involve delivering the tunable surfactant in a slightly basic aqueous solution, which the tunable surfactant is soluble in, to an aqueous stream of interest, which contains dissolved salts at concentrations higher than 10,000 ppm. A specific tunable surfactant (TS1 of Example 1) has decreasing solubility in aqueous streams as the dissolved solids concentration is increased. Upon mixing the tunable surfactant into the salt containing aqueous stream that is contaminated with oil and suspended solids the tunable surfactant associates with oil and suspended solids, which it has been designed to have an affinity for as described above, and simultaneously becomes insoluble in the aqueous stream due to the dissolved salt content. This proposed mechanism results in agglomerates or flocs of the oil and suspended solids that are not soluble in the aqueous stream of interest, enabling their removal from the aqueous stream through a number of methods, including but not limited to settling in ambient conditions, and separation by centrifugal force.

As an example, a tunable surfactant can be obtained by reaction of a polyethylene glycol with a hydrophobic succinic anhydride. This tunable surfactant compound can be dissolved in water along with alkali such as sodium hydroxide, where two moles of alkali are added per mole of the tunable surfactant. When sodium hydroxide is used as the alkali this yields a soluble tunable surfactant in the form of a sodium salt. The tunable surfactant can have a structure represented as follows, shown in the acid form:

In the specific example shown above, in embodiments, n can be between 2 and 100, preferably between 5 and 14, and each m can be, independently, between 11 and 15. As another example, the tunable surfactant can have a structure as shown above, but without the two —COOH functional groups. This chemical structure is shown below:

This solution can then be added to a contaminated drilling fluid, for example a contaminated salt-water-based drilling fluid, where the drilling fluid has a salinity of, for example, 1000-50,000 ppm total dissolved solids (TDS), or, for example, a salinity of up to about 300,000 ppm total dissolved solids. The exposure of the oil-containing aqueous stream with the tunable surfactant solution results in association of the oil and/or suspended solids with the tunable surfactant, yielding aggregates of oil and suspended solids. The observed effect is an aggregated suspension, resulting from the addition of a tunable surfactant solution to a salt-water-based mud slurry. This observation could be the result of converting oil-wet suspended solids into a water-wet condition, thereby enabling agglomeration by hydrostatic forces. In an exemplary embodiment, this process takes place in a mixing vessel and the aggregates are denser than the fluid in the vessel. Such dense aggregates can settle to the bottom or otherwise be removed. In certain embodiments, the aggregates will contain sufficient mineral or inorganic content such that their density exceeds the density of the brine carrier fluid and the aggregates will tend to sink. In other embodiments, the aggregates can contain sufficient oil or organic matter, or attached air bubbles, such that the aggregates have a lower density than the surrounding brine and the aggregates will tend to float. In either case, the addition of tunable surfactant can enable the formation of aggregates, and the appropriate separation equipment can be used to separate the aggregates from the fluid, whether by flotation or by sedimentation/sinking mechanisms. The density of the aggregates relative to the aqueous solution is influenced by a number of factors, including but not limited to, the dissolved solid content of the aqueous solution (increasing the density of the aqueous solution), the suspended solids component density and concentration within the aggregates, the organic component density and concentration within the aggregates, the tunable surfactant density and concentration within the aggregates, the potential entrapment of air or other gaseous component and concentration of entrained air or other gaseous component within the aggregates. Alternatively, if the aggregates formed are less dense than the fluid in the vessel, these aggregates can float to the top of the vessel and be removed there by, e.g., skimming or other removal techniques. The separation of aggregates either denser or less dense than the aqueous stream can be removed, for example, in either a stationary vessel or while the fluid stream is experiencing a non-turbulent flow. In embodiments, air bubbles can intentionally be introduced into the aggregates in order to reduce the aggregate density and result in aggregates that float to the top of the fluid. This can be accomplished through dissolved or induced air flotation techniques or other methods that are known to those skilled in the art. In embodiments, after mixing the tunable surfactant solution with the drilling fluid, the mixture can be introduced into a centrifuge to accelerate the consolidation of the oil and solids (which may either sink or float depending on the relative density of the oil and solid aggregates compared to the aqueous solution). The aqueous stream removed contains less than 0.5% oil and 0.5% suspended solids, by volume. The separation steps described herein can be accomplished with the aid of known separation processing equipment, such as clarifiers, settling basins or ponds, filters, skimming tanks, centrifuges, hydrocyclones, and the like. In embodiments, the oil and solid aggregates are allowed to sink to the bottom of a settling vessel by gravity or with the aid of centrifugal force and the aqueous fluid is recovered by decanting the brine, which comprises the top layer of the fluid, from the oil and solids aggregates in the bottom layer. In other embodiments, the oil and solid aggregates are allowed to float to the top of a flotation vessel or skimming tank, where the oil and solids can be separated by decanting or pumping; in this event the brine would be collected from the bottom of the separation vessel.

In embodiments a continuous settling process can be achieved by flowing the chemically treated fluid into a vessel (chemical treatments include treatments with tunable surfactants, with other surfactants, with flocculants, and/or with solids particles) and allowing the oil and solid aggregates to settle to the bottom of the vessel. In an embodiment, the aqueous stream recovered contains less than 0.5% oil and 0.5% suspended solids, by volume. In an embodiment, the sludge recovered at the bottom of the vessel contains ˜34% water, ˜36% oil, and ˜30% solids (measured as both dissolved and suspended solids), by volume. By metering the incoming fluid at a specified rate, such that the oil and solid aggregates have sufficient time to settle to the bottom of the vessel, a steady state process can be achieved, where the aqueous fluid, with the oil and solid contaminants removed, can flow over a weir into a collection vessel, and the oil and solids aggregates are concentrated at the bottom of the vessel where they are removed by a pumping. A series of such vessels can be used to ensure that oil and solid aggregates are completely removed and do not reach the output stream. Separation vessels useful for this purpose are familiar to those skilled in the art, such as clarifiers, dewatering vessels, thickening vessels and the like. A series of baffles and weirs can be used and adjusted to increase the efficacy of such vessels and systems.

In an exemplary embodiment, a vertical cone-bottom clarifier is used to achieve the desired throughput of the fluid stream. The clarifying vessel can concentrate the oil and solid aggregates to the bottom of the vessel, and prevent oil and solid aggregates from contaminating the aqueous overflow stream.

In embodiments the tunable surfactant can be used in combination with a flocculant solution, such as an acrylamide polymer or the like. In embodiments, the flocculant can be added after the mixing of the tunable surfactant with the contaminated fluid stream. In embodiments the tunable surfactant can be used in combination with chemicals that are commonly used for forming aggregates or flocs for the removal of particulates from aqueous streams, such as water soluble flocculants, including but not limited to high molecular weight polyacrylamides with either cationic or anionic charged groups. Representative flocculants are commercially available and familiar to artisans of ordinary skill; for example, charged polyacrylamides are commercially available from SNF Inc., under the trade name of FLOPAM®.

In embodiments the tunable surfactant can be used in combination with a solid particle, such as calcium carbonate or the like. As used herein, the term “particle” includes all known shapes of materials without limitation, such as spherical materials, elongate materials, polygonal materials, fibrous materials, irregular materials, and any mixture thereof. Suitable particles can include organic or inorganic materials, or mixtures thereof. In embodiments, inorganic particles can include one or more materials such as sand, graded sand, resin coated sand, bauxite, ceramic materials, glass materials, calcium carbonate, calcium silicate, dolomite, calcium sulfate, kaolin, talc, titanium dioxide, diatomaceous earth, aluminum hydroxide, fly ash, silica, alumina, fumed carbon, carbon black, graphite, mica, boron, zirconia, talc, other metal oxides, and combinations thereof and the like. Calcium carbonate is a preferred particle source for this application. Organic particles can include one or more materials such as starch, modified starch, cellulose, walnut hulls, polymeric materials, polymeric spheres (both solid and hollow), resinous materials, rubber materials, and the like. In embodiments, the particle substrates can include naturally occurring materials, for example nutshells that have been chipped, ground, pulverized or crushed to a suitable size (e.g., walnut, pecan, coconut, almond, ivory nut, brazil nut, and the like), or for example seed shells or fruit pits that have been chipped, ground, pulverized or crushed to a suitable size (e.g., plum, olive, peach, cherry, apricot, etc.), or for example chipped, ground, pulverized or crushed materials from other plants such as corn cobs. In embodiments, the particles can be derived from wood or processed wood, including but not limited to woods such as oak, hickory, walnut, mahogany, poplar, and the like. In embodiments, aggregates can be formed, using an inorganic material joined or bonded to an organic material. Particle sizes can range from a few nanometers to few hundred microns. In certain embodiments, macroscopic particles in the millimeter range may be suitable. Not to be bound by theory, solid particles can be used to aid in the formation of aggregates or flocs, and additionally provide an increase in the floc or aggregate density, rendering faster, more effective separation. The selected particle can be delivered in a solid form, for instance as a powder, and mixed into the fluid stream through a mixing hopper, such as a venture hopper.

The selected solid particle can be suspended in fluid to form a particulate formulation. One type of solid particle can be used for a particulate formulation, or more than one type may be used. In embodiments, for example, a particulate formulation can be prepared by adding the selected solid particle type(s) before or after the mixing of the tunable surfactant with the contaminated fluid stream. In embodiments, a particulate formulation can be prepared as a slurry by dispersing the solid particles in a aqueous medium, such as, but not limited to water, brine, salt water based drilling fluids, and salt water based drilling fluids contaminated with oil and or solids. In embodiments the particulate formulation can comprise a slurry containing less than 1% of the solid particles. In embodiments the formulation can comprise a slurry containing between 1% and 50% of the solid particles. In embodiments, if the particulate formulation comprises solid particles dispersed in salt water based drilling fluids contaminated with oil and or solids, this particulate formulation can be treated with tunable surfactant and additional chemicals, as disclosed herein.

In embodiments, the particulate formulations as disclosed herein can be mixed with the fluid stream to be treated, in order to control the amount of solid particles introduced in to the system in a controlled manner. In an exemplary embodiment, a particulate formulation comprises a 20% slurry of calcium carbonate in a salt water based drilling fluids contaminated with oil and or solids is prepared; this slurry is agitated to prevent settling, and introduced into the primary salt water based drilling fluids contaminated with oil and or solids in resulting in fluid stream with a final calcium carbonate concentration of 0.05-10% by weight. In embodiments, the fluid stream is then treated with tunable surfactant as described herein, followed by treatment with a water soluble flocculant, as described herein. An exemplary process is illustrated in FIG. 8.

In embodiments the tunable surfactant can be used in combination with chemicals that are commonly used to reduce foaming of fluids, such as fatty acids, fatty alcohols, silicone-containing materials and the like. Examples of these types of foam control agents include Dow Corning 5-7070 Emulsion, Dow 8194, oleic acid, lauric acid, lauryl alcohol, cetyl alcohol, and EO/PO copolymers.

In embodiments, the pH of the fluid stream can be adjusted and/or the pH of the solutions containing the treatment chemicals can be adjusted to increase the efficacy of the treatment process. In an embodiment, the pH of the oil and solids contaminated fluid stream is adjusted to less than 6.5, or less than 6.0, and aggregate formation occurs more rapidly, or requires a lower treatment dose, or the resulting aggregates are more suitable for flocculation and separation. Not to be bound by theory, lowering the pH can reduce the electrostatic interactions (i.e., electrostatic repulsion between similarly charged clay particles) between the clay particles, allowing for easier and more effective aggregation upon the introduction of the treatment chemicals. Similarly, the pH of the treatment chemical solutions can be adjusted to increase the efficacy of the treatment process. In embodiments, a solution containing treatment chemicals such as a tunable surfactant or polymer can have improved performance if the solution pH is lowered by addition of an acid. Also, not to be bound by theory, introducing a treatment chemical solution with an elevated pH can increase the undesirable electrostatic repulsions between the clay particles and hinder the treatment efficacy.

3. Treatment of Oil-Contaminated Slurries with Tunable Surfactants

In certain oil production operations, waste slurries containing oil, water, and insoluble solids are generated during waterflood or steamflood operations, from heavy oil production, from artificial lift oil production, and from cleanout of tanks, separators, and pipelines. Waterflood and steamflood operations are tertiary recovery methods practiced to enhance the recovery of oil from otherwise depleted reservoirs. When the oil is produced from these wells, it is often produced as a mixture with large volumes of produced water or condensate. The produced water, oil, and solids often present challenges in separation, and there is often a waste stream generated, containing oil-wet solids with water. In artificial lift operations, heavy oil is pumped to the surface using techniques and equipment such as positive displacement pumps that are capable of pumping viscous slurries containing oil, water, and solids. The oil production stream from artificial lift operations often is contaminated with insoluble solids and water; these materials are considered contaminants in the oil product, and they are removed by settling and other chemical and mechanical methods. In the cleanup of the produced solids from artificial lift operations, a waste slurry of oil, water, and insoluble solids is often generated. This waste stream contaminates the production site and new methods are needed to address these environmental concerns. Holding tanks, separator vessels, and pipelines that process crude oil often become laden with sludges that separate by gravitational settling. The equipment is cleaned out periodically to remove the sludges, and this presents a material handling and disposal challenge that would benefit from some kind of separation.

These waste slurries all contain a combination of oil, water, and insoluble solids. The goal of treatment process can be to remove the oil and solids from the slurry, or to remove the oil from the water and the insoluble solids. In certain embodiments, the tunable surfactants of the invention can be used to enhance the separation of oil and solids from a slurry, leaving behind a clarified water stream for recovery or disposal. This separation process with tunable surfactant can be aided by the use of a water soluble flocculant polymer. This treatment process applies the same approach as used for treatment of salt water based drilling fluids, described above, to other oilfield wastes such as oil/water/solids slurries. In other embodiments, the tunable surfactants of the invention can be used to release oil from oil-wet solids in the presence of water. In this treatment process, the oil is released in a form that contains less insoluble solids compared to the untreated slurry, and the oil can be recovered in a form that can be recovered for refining. Applications of the latter process include the treatment of waste sludges from steamflood, water flood, equipment cleanout, and artificial lift operations.

EXAMPLES Materials

    • Naphtha: a mixture of cyclohexane, nonane, octane, heptane, and pentane (obtained from Coleman lantern fuel)
    • Diesel: Purchased from Mobil gas station in Cambridge, Mass.
    • TS1: synthesized by Soane Energy as described in Example 1
    • TS2: synthesized by Soane Energy as described in Example 2
    • Sodium hydroxide (Sigma Aldrich)
    • High grade oil sands from Ft. McMurray region of Alberta, Canada
    • Water: from Cambridge Mass. municipal water supply
    • Alkylated succinic anhydride (Eka SA 210 brand)
    • Poly(ethylene glycol) (Fluka) (molecular weigh 380-420)
    • Phenyl succinic anhydride (Sigma Aldrich)
    • Pluronic L35 (BASF)
    • Salt-water based drilling fluid that has been contaminated with oil and solids during the drilling of an oil well (“SWBM”)
    • Calcium carbonate particles (Industrial Powder)

Example 1 Preparation of TS1 and TS1 Solution

A tunable surfactant TS1 was synthesized from alkenylsuccinic anhydride and polyethylene glycol in the following manner: a reactor was charged with Poly(ethylene glycol) (Fluka) (molecular weight 380-420) (12.82 g, 32 mmol) and Eka SA 210 brand alkylated succinic anhydride (22.58 g, 64 mmol). The mixture was stirred for about 3 hours at 130 degrees Celsius under nitrogen. The 1% weight solution of TS1 was created by combining 4.00 g of TS1, 0.29 g of sodium hydroxide, and 395.71 g of water. The TS1 solution was equilibrated at room temperature (about 20 degrees Centigrade) before use in the Examples below.

Example 2 Preparation of TS2 and TS2 solution

A tunable surfactant TS2 was synthesized from an ethylene oxide/propylene oxide block copolymer and phenyl succinic anhydride in the following manner: a reactor was charged with phenyl succinic anhydride (1.85 g, 10.52 mmol) and Pluronic L35 (10 g, 5.26 mmol). The mixture was stirred for about 4 hours at 130 degrees Celsius under nitrogen. The 1% weight solution of TS2 was created by combining 4.00 g of TS2, 0.14 g of sodium hydroxide, and 395.86 g of water. The TS2 solution was equilibrated at room temperature (about 20 degrees Centigrade) before use in the Examples below.

Example 3

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 1 kilogram of high grade oil sands (12%, by weight, bitumen) was combined with 250 g of diesel in a 4000 mL beaker and mixed with an overhead mixer at 250 rpm for 30 minutes. This slurry was then combined with 400 mL of a 1% weight solution of TS1 in water and 400 mL of a 1%, by weight, solution of TS2. TS1 was prepared in accordance with Example 1 and TS2 was prepared in accordance with Example 2. This slurry was then mixed at 300 rpm for 15 minutes. The slurry was then allowed to settle for 1 minute and the volume of the oil (bitumen and diesel) layer on the top was measured. This mixing and settling cycle was repeated several times with the oil volume being measured after total mixing times of 15, 30, 60, 120, and 240 minutes; the oil volumes measured were 270, 330, 420, 430, and 440 mL, respectively. FIG. 1 shows the oil sand sample before any treatment. FIG. 2 shows the oil sand sample of FIG. 1, following addition of 250 grams of diesel. FIG. 3 shows the oil sand sample of FIG. 1 dissolved in 250 grams of diesel and mixed with 800 mL of a 50/50 mixture of TS1 and TS2 solutions for less than 1 minute. No separation can be seen. FIG. 4 shows the oil sand sample of FIG. 1 dissolved in 250 grams of diesel and mixed with 800 mL of a 50/50 mixture of TS1 and TS2 solutions for 240 minutes. In FIG. 4, three layers can be seen, 402, 404 and 408. The top layer 402 consists of the diluent diesel and bitumen extracted from the oils sands. The middle layer 404 consists of fines suspended in an aqueous phase, without bitumen. The bottom layer 408 consists of the particulate solids at the bottom of the aqueous phase, which contains minimal bitumen.

Example 4

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 50 grams of high grade oil sands (12%, by weight, bitumen) was mixed with 10 g of diesel in a 250 mL round bottom flask and shaken for 12 hours. This slurry was then combined with 20 mL of a 1% weight solution of TS1 in water and 20 mL of a 1% weight solution of TS2 in water. TS1 was prepared in accordance with Example 1 and TS2 was prepared in accordance with Example 2. This slurry was then shaken for 3 hours. The resulting slurry was then transferred into a 100 mL graduated cylinder. A similar sample was prepared in the same manner with the only change being the two tunable surfactant solutions (TS1 and TS2) were replaced with 40 mL of water, with no added surfactants. The oil sands treated with diesel and the tunable surfactant solutions yielded a top layer with ˜18.5 mL of recovered oil (diesel and bitumen), compared to ˜9 mL of oil for the oil sands treated with diesel and water. Additionally, the particulate solids in the sample treated with tunable surfactant solution visibly contains less bitumen, compared to the sample treated with only naphtha and water. FIG. 5 shows two vials, 502 and 504. Vial 502 shows the sample treated with diesel and water as described above. Vial 504 shows the sample treated with diesel and the two tunable surfactants, as described above. The top layer in each vial (508, 510) contains the recovered diesel and oil. The middle layer in each vial (512, 514) is an aqueous phase. The aqueous phase 514 for vial 504 contains suspended fines. The bottom layer in each vial (518, 520) contains solids and oil. As seen in vial 504, all of the diluent diesel and more than 95% of the available bitumen was recovered in the top layer 510 for the oil sands treated with diesel and tunable surfactant solution. The treatment with diesel and water is visibly less effective, with significant amounts of bitumen remaining with the particulate solids at the bottom 518 of vial 502.

Example 5

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 50 grams of high grade oil sands (12%, by weight, bitumen) was mixed with 10 g of naphtha in a 250 mL round bottom flask and shaken for 12 hours. This slurry was then combined with 20 mL of a 1% weight solution of TS1 in water and 20 mL of a 1% weight solution of TS2 in water. TS1 was prepared in accordance with Example 1 and TS2 was prepared in accordance with Example 2. This slurry was then shaken for 3 hours. The resulting slurry was then transferred into a 100 mL graduated cylinder. A similar sample was prepared in the same manner with the only change being the two tunable surfactant solutions (TS1 and TS2) were replaced with 40 mL of water, with no added surfactants. The oil sands treated with naphtha and the tunable surfactant solutions yielded a top layer with ˜18 mL of recovered oil (naphtha and bitumen), compared to ˜10 mL of oil for the oil sands treated with naphtha and water. Additionally, the particulate solids in the sample treated with tunable surfactant solution visibly contained less bitumen, compared to the sample treated with only naphtha and water.

Example 6

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 100 grams of high grade oil sands (12%, by weight, bitumen) was mixed with 15 g of naphtha in a 250 mL round bottom flask and mixed with an overhead mixer at 100 rpm for 20 minutes. The oil sands ore contains 12% bitumen, by weight, representing a 125% dilution if the bitumen by naphtha, by weight. This slurry was then combined with 40 mL of a 1% weight solution of TS1 in water and 40 mL of a 1% weight solution of TS2 in water. TS1 was prepared in accordance with Example 1 and TS2 was prepared in accordance with Example 2. This slurry was then mixed with an overhead mixer at 500 rpm for 5 minutes, then at 100 rpm for 1 hour. The oil sands treated with naphtha and the tunable surfactant solutions yielded a top layer of oil, an aqueous layer containing dispersed fines, and a layer of particulate solids on the bottom that appears to have very little trapped bitumen. A similar sample was prepared in the same manner with the only change being the two tunable surfactant solutions (TS1 and TS2) were replaced with 80 mL of water, with no added surfactants. The sample treated with only naphtha and water yields a smaller oil layer on top and trapped bitumen trapped in the solid particulate layer can be seen at the bottom of the flask. A specimen of this sample is shown in the left-sided vial 602 in FIG. 6. Two 10 mL samples of the aqueous layer containing fines were removed from the sample treated with naphtha and tunable surfactant and put into 20 mL vials. 1 mL of 0.1 molar hydrochloric acid in water was added to one of the aqueous fines solutions. The addition of 1 mL of 0.1 molar hydrochloric acid results in the rapid (on the order of a few minutes) settling of the suspended fines.

A 10 mL sample of fluid was taken near the interface of the oil and aqueous phases from the sample treated with naphtha and tunable surfactant and put into 20 mL vial. The addition of 1 mL of 0.1 molar hydrochloric acid results in the rapid (on the order of a few minutes) settling of the suspended fines and the interface between the aqueous and oil phases appears sharper. Before the addition of acid, after gently shaking the sample the oil and aqueous phases would separate on the order of 5-10 minutes. After the addition of acid, after gently shaking the sample the oil and aqueous phases would separate on the order of 10-20 seconds. In this embodiment, after mixing with the aqueous tunable surfactant solution, separation of the bitumen from the particulate solids was observed and the dilution was sufficient to lower the density of the naphtha/bitumen solution below that of water. A specimen of this sample is shown in the right-sided vial 604 in FIG. 6. Subsequently the naphtha/bitumen was able to float to the surface of the aqueous layer, making it easy to remove.

Example 7

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 100 grams of high grade oil sands (12%, by weight, bitumen) was mixed with 2 g of naphtha in a 250 mL round bottom flask and mixed with an overhead mixer at 100 rpm for 16 hours. The oil sands ore contains 12% bitumen, by weight, representing a 16.7% dilution if the bitumen by naphtha, by weight. This slurry was then combined with 40 mL of a 1% weight solution of in water and 40 mL of a 1% weight solution of TS2 in water. TS1 was prepared in accordance with Example 1 and TS2 was prepared in accordance with Example 2. This slurry was then mixed with an overhead mixer at 500 rpm for 5 minutes, then at 100 rpm for 3 hours. The oil sands treated with naphtha and the tunable surfactant solutions yielded a layer of sand on the bottom that appears to have very little trapped bitumen, an aqueous layer with dispersed fines, and a viscous bitumen and naphtha layer in between the solids particulates and the aqueous layer. In this Example, after mixing with the aqueous tunable surfactant solution, separation of the bitumen from the particulate solids was observed; however, the dilution was not sufficient to lower the density of the naphtha/bitumen solution below that of water. Subsequently the naphtha/bitumen did not float to the surface of the aqueous layer, making it difficult to remove.

Example 8

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 150 mL of salt water based drilling fluid that has been contaminated with oil and solids during the drilling process was added to a glass jar. The contaminated salt water based drilling fluid contained ˜4% oil and ˜5% suspended solids. The Tunable surfactant solution designated as TS1 in Example 1 was prepared, and 7.5 mL of a 2% solution of this tunable surfactant in water was added to the contaminated salt water based drilling fluid and shaken for 10 seconds. The tunable surfactant solution was prepared by mixing 2 parts (by weight) of the tunable surfactant with 98 parts (by weight) water, and then adding 2 moles of sodium hydroxide for each mole of tunable surfactant. Within 10 seconds after the addition of the tunable surfactant to the oil and solid contaminated aqueous stream, visible aggregates formed and began to settle to the bottom of the jar, leaving a hazy aqueous solution behind. FIG. 7 shows a control jar containing a sample contaminated salt-water-based drilling fluid on the left (702), and a treated sample in the jar on the right (704), where the contaminated salt-water-based drilling fluid has been treated in accordance with this Example and has been allowed to settle for fifteen minutes. After it was allowed to sit for a period of one hour, the treated sample showed the recovered oil as a layer above the aqueous solution, with a viscous sludge consisting of solids and oil settled at the bottom; with increasing time, the amount of oil recovered in the layer above the aqueous solution increased. After a period of 1 hour the aqueous phase begins to decrease in turbidity, with the hazy aqueous phase becoming increasingly clear. In the absence of the tunable surfactant addition, the salt water based drilling fluid that has been contaminated with oil and solids remains as a stable mixture containing oil and solids impurities. The addition of tunable surfactant visibly increases the rate of separation.

Example 9

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 150 mL of salt water based drilling fluid that has been contaminated with oil and solids during the drilling process was added to a glass jar. The contaminated salt water based drilling fluid contained ˜4% oil and ˜5% suspended solids. The Tunable surfactant solution designated as TS1 in Example was prepared, and 7.5 mL of the 2% tunable surfactant in water was added to the contaminated salt water based drilling fluid and shaken for 10 seconds. The tunable surfactant solution was prepared by mixing 2 parts (by weight) of the tunable surfactant with 98 parts (by weight) water, and then adding 2 moles of sodium hydroxide for each mole of tunable surfactant. Within 10 seconds after the addition of the tunable surfactant to the oil and solid contaminated aqueous stream, visible aggregates formed and began to settle to the bottom of the jar, leaving a hazy aqueous solution behind. After a period of 30 seconds 1.5 mL of a 0.05% solution of a anionic flocculant (this solution was prepared by adding 5 parts by weight of an anionic polyacrylamide polymer powder to 9995 parts by weight water and mixing for a period of 2 hours) was added to the solution containing the aqueous stream of interest and the tunable surfactant solution previously added and shaken for 10 seconds. Nearly immediately visible aggregates form, larger and more resistant to disruptive turbulence than the aggregates formed with tunable surfactant alone, and begin to settle to the bottom of the jar, leaving a hazy aqueous solution behind. After letting sit for a period of one hour the treated sample shows the recovered oil as a layer above the aqueous solution, with a viscous sludge consisting of solids and oil settled at the bottom, with increasing time the amount of oil visible in the layer above the aqueous solution increases. After a period of 1 hour the aqueous phase begins to decrease in turbidity, with the hazy aqueous phase becoming increasingly clear.

Example 10

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 20 mL of salt water based drilling fluid that has been contaminated with oil and solids during the drilling process was added to a glass vial. The contaminated salt water based drilling fluid contained ˜4% oil and ˜5% suspended solids. 0.2 grams of calcium carbonate particles were added to the 20 mL of fluid to be treated. The Tunable surfactant solution designated as TS1 in Example 1 was prepared, and 1.0 mL of the 2% tunable surfactant in water was added to the contaminated salt water based drilling fluid and shaken for 10 seconds. The tunable surfactant solution was prepared by mixing 2 parts (by weight) of the tunable surfactant with 98 parts (by weight) water, and then adding 2 moles of sodium hydroxide for each mole of tunable surfactant. Within 10 seconds after the addition of the tunable surfactant to the oil and solid contaminated aqueous stream, visible aggregates formed and began to settle to the bottom of the jar, leaving a hazy aqueous solution behind. After a period of 30 seconds 0.5 mL of a 0.1% solution of a anionic flocculant (this solution was prepare by adding 10 parts by weight of an anionic polyacrylamide polymer powder to 9990 parts by weight water and mixing for a period of 2 hours) was added to the solution containing the aqueous stream of interest and the tunable surfactant solution previously added and shaken for 10 seconds. Nearly immediately, visible aggregates formed, larger and more resistant to disruptive turbulence than the aggregates formed with tunable surfactant alone, and began to settle to the bottom of the jar, leaving a hazy aqueous solution behind. After a period of 1 hour the aqueous phase began to decrease in turbidity, with the hazy aqueous phase becoming increasingly clear.

Example 11

FIG. 8 is a schematic diagram illustrating a process 100 for treating salt water based drilling fluid that has been contaminated with oil and solids, based on the systems and methods disclosed herein. As shown in the diagram, an active pit 102 can be used as a source of the contaminated fluid, e.g., the salt-water based drilling fluid that has been contaminated with oil and solids. Fluid to be treated can be withdrawn from the active pit 102 and pumped into the system through a pump 104 into a treatment manifold 108 where the fluid encounters a plurality of treatment chemicals. The pump 104 can be, for example, a centrifugal pump, a positive displacement pump, or the like. In one embodiment, a first treatment chemical 112 can be introduced through the manifold 108, for example, a particulate formulation comprising a 20% slurry of calcium carbonate that is premixed in a solution such as a sample of the salt water based drilling fluid contaminated with oil and solids, such as could be taken from the active drilling pit 102. A slurry employed as the first treatment chemical can be prepared, for example, by adding one part (by weight) of calcium carbonate to 4 parts of the contaminated salt water based drilling fluid. A second treatment chemical 114 can be introduced through the manifold 108, for example, a tunable surfactant solution prepared with between 0.1% and 22% of the tunable surfactant in water. A third treatment chemical 118 can be introduced through the manifold 108, for example a flocculant solution with a concentration between 0.005% and 1% in water. In embodiments, each of the three treatment chemicals 112, 114 and 118 are administered by in-line injection into the salt water based drilling fluid. The flow rates of each of the treatment chemicals are separately controlled. After chemical injection, a solid fraction bearing the various contaminants can be separated from the brine fluid in which the solids are suspended. Separation 120 may be carried out, for example, by a centrifuge or a clarifying vessel. A sludge fraction 122 of contaminated solids can be segregated for disposal after separation. A recovered brine fraction 124 can be reused in processing. The recovered brine fraction 124 can, for example, be recirculated 130 into the active pit 102 by a pump mechanism 128 or it may otherwise be repurposed.

Example 12

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. 500 mL of salt water based drilling fluid that has been contaminated with oil and solids during the drilling process was added to a plastic container. The contaminated salt water based drilling fluid contained ˜12% oil and ˜5% suspended solids by volume. The Tunable surfactant designated as TS1 in Example 1 was prepared, and 32 mL of a 4.4% solution of this tunable surfactant in water was added to the contaminated salt water based drilling fluid and shaken for 1 minute. The tunable surfactant solution was prepared by mixing 4.4 parts (by weight) of the tunable surfactant with 95.6 parts (by weight) water, and then adding 2 moles of sodium hydroxide for each mole of tunable surfactant. After a period of 30 seconds 0.75 mL of a 0.1% solution of an anionic flocculant (this solution was prepared by adding 1 parts by weight of an anionic polyacrylamide polymer powder to 999 parts by weight water and mixing for a period of 2 hours) was added to the solution. This solution was gently shaken and transferred into a 1 liter separation funnel. Within 10 seconds after the addition of the tunable surfactant to the oil and solid contaminated aqueous stream, visible aggregates formed and began to float to the top of the container, leaving a hazy aqueous solution behind. After it was allowed to sit for a period of one minute, the treated sample showed a layer of oil and solids above the aqueous solution, and 350 mL of the recovered clear brine was removed from the bottom of the separation funnel and the remaining fluid (a combination of the oil and solids sludge and clear brine) was transferred into a 200 mL container with at horizontal opening on one side. After a period of 45 minutes the oil and solids sludge had further consolidated at the top of the fluid. A portion of the brine recovered from the separation funnel was injected into the bottom of the 200 mL container, causing the fluid level to rise above the horizontal opening, and subsequently a portion of the oil and solids sludge spilled over the horizontal opening and was collected for analysis. The recovered sludge was found to contain ˜66% oil, ˜16% water, and ˜18% solids (dissolved and suspended), by volume.

Example 13

This Example was performed at 20 degrees Centigrade without addition of heating or cooling. Four experiments were performed where salt-water based drilling fluid that has been contaminated with oil and solids during the drilling of an oil well (“SWBM”) was treated with the Tunable surfactant solution designated TS1 in Example 1 and an anionic polyacrylamide flocculant solution. The same TS1 was used for all 4 experiments, where the pH was adjusted to 6.00 with 1 molar hydrogen chloride solution for the third and fourth experiments in this example. The SWBM had the following composition: 4% oil content, 12% solids content (dissolved and suspended), and 84% water content. In Experiment (A) 0.5 mL of a 4.4% Tunable surfactant solution with a pH of 7.96 was added to 20 mL of SWBM with a pH of 7.40 (not adjusted) and shaken vigorously for 1 minute in a 40 mL glass vial. 0.05 mL of a 0.10 weight percent flocculant solution was then added and shaken gently for 10 seconds. In Experiment (B) 0.5 mL of a 4.4% Tunable surfactant solution with a pH of 6.00 was added to 20 mL of SWBM with a pH of 7.40 (not adjusted) and shaken vigorously for 1 minute in a 40 mL glass vial. 0.05 mL of a 0.10 weight percent flocculant solution was then added and shaken gently for 10 seconds. In Experiment (C) 0.5 mL of a 4.4% Tunable surfactant solution with a pH of 7.96 was added to 20 mL of SWBM with a pH adjusted to 6.00 and shaken vigorously for 1 minute in a 40 mL glass vial. 0.05 mL of a 0.10 weight percent flocculant solution was then added and shaken gently for 10 seconds. In Experiment (D) 0.5 mL of a 4.4% Tunable surfactant solution with a pH of 6.00 was added to 20 mL of SWBM with a pH adjusted to 6.00 and shaken vigorously for 1 minute in a 40 mL glass vial. 0.05 mL of a 0.10 weight percent flocculant solution was then added and shaken gently for 10 seconds. After the addition of the flocculant solution and gently shaking, the 4 vials were left to settle. The sample from each Experiment is shown in FIG. 9 after five minutes of settling, with the sample vials being labeled A, B, C, and D, respectively. Experiment (D) showed large flocs that settled quickly to the bottom of the vial, with ˜70% of the fluid being a cloudy aqueous solution within 10 seconds, and the oil and solids flocs at the bottom of the vial. Experiments A, B, and C did not show significant settling after 30 seconds. After 5 minutes, all of the vials showed significant settling, with A, B, and C having a clear effluent and D having a cloudy effluent.

EQUIVALENTS

While this invention has been particularly shown and described with references to preferred embodiments thereof, it will be understood by those skilled in the art that various changes in form and details may be made therein without departing from the scope of the invention encompassed by the appended claims.

Claims

1. A method for aggregating oil-wet solids in an aqueous suspension, comprising:

providing an aqueous suspension containing oil-wet solids; and
treating the aqueous suspension with an effective amount of a formulation comprising a tunable surfactant, thereby aggregating the oil-wet solids as removable aggregates.

2. The method of claim 1, further comprising removing the removable aggregates.

3. The method of claim 1, further comprising providing a flocculant and adding the flocculant to the aqueous suspension before, during or after the step of treating the aqueous suspension with the effective amount of the formulation comprising a tunable surfactant.

4. The method of claim 1, further comprising providing a particulate formulation and adding the particulate formulation to the aqueous suspension, before, during or after the step of treating the aqueous suspension.

5. A method for separating oil or solids from an aqueous slurry, comprising:

providing an aqueous slurry comprising oil and solids;
treating the slurry with an effective amount of a formulation comprising a tunable surfactant, thereby segregating the oil or the solids from the slurry; and
physically sequestering at least one of the oil and the solids, thereby separating the oil or the solids from the slurry.

6. The method of claim 5, wherein the slurry is derived from spent drilling fluid.

7. The method of claim 6, wherein the step of physically sequestering yields a reclaimable spent drilling fluid.

8. The method of claim 6, wherein the step of physically sequestering yields a brine solution.

9. The method of claim 5, further comprising providing a particulate formulation and adding the particulate formulation to the slurry, before, during or after the step of treating the slurry.

10. A method for desorbing oil from oil-wet solids, comprising:

providing a sample comprising oil-wet solids;
treating the sample with an effective amount of a formulation comprising a tunable surfactant to segregate the oil from the oil-wet solids; and
sequestering the segregated oil, thereby separating the oil from the oil-wet solids.

11. The method of claim 10, further comprising isolating the sequestered segregated oil, thereby recovering the oil.

12. The method of claim 11, further comprising reusing the recovered oil.

13. The method of claim 10, wherein the desorbing of oil from the oil-wet solids reduces the amount of a waste material for disposal.

14. A method for extracting bitumen from oil sands ore, comprising:

providing an oil sands ore containing bitumen;
treating the oil sands ore with a hydrocarbon diluent to form a hydrocarbon-based slurry;
treating the hydrocarbon-based slurry with at least one tunable surfactant to separate the bitumen from the oil sands ore, thereby forming a bitumen-containing portion and a separate inorganic-containing portion comprising the oil sands ore; and
separating the bitumen-containing portion from the inorganic-containing portion, thereby extracting the bitumen from the oil sands ore,
wherein each step takes place at a process fluid temperature within in a lower temperature environment.

15. The method of claim 14, wherein the process fluid temperature is between 10 and 35 degrees Centigrade.

16. The method of claim 14, wherein the hydrocarbon diluent is diesel or naphtha.

17. The method of claim 14, wherein the at least one tunable surfactant is an aromatic surfactant.

18. The method of claim 14, wherein the at least one tunable surfactant is an aliphatic surfactant.

19. The method of claim 14, further comprising treating the hydrocarbon-based slurry with a second tunable surfactant, wherein the second tunable surfactant is added to the hydrocarbon-based slurry with the at least one tunable surfactant to separate the bitumen from the oil sands ore.

20. The method of claim 14, wherein the at least one tunable surfactant is an aromatic surfactant and the second tunable surfactant is an aliphatic surfactant.

21. The method of claim 14, wherein the inorganic-containing portion comprises an aqueous phase containing suspended fines and a solid particulate phase containing sand.

22. The method of claim 14, further comprising the step of mechanically agitating the hydrocarbon-based slurry before the step of treating the hydrocarbon-based slurry with the at least one tunable surfactant.

23. The method of claim 14, further comprising applying mechanical agitation after the step of treating the hydrocarbon-based slurry with the at least one tunable surfactant.

24. The method of claim 14, further comprising the step of adding an acid after the step of treating the hydrocarbon-based slurry with the at least one tunable surfactant.

25. The method of claim 24, wherein the step of adding the acid adds the acid to the aqueous phase containing suspended fines.

26. A system for separating bitumen from inorganic oil sands ore, comprising:

a mixing chamber, whereby oil sands ore containing bitumen bound to inorganic oil sands ore is collectable in the mixing chamber;
an introducer in fluid communication with the mixing chamber and in fluid communication with a reservoir containing a hydrocarbon diluent, wherein the hydrocarbon diluent is flowable from the reservoir through the introducer into the mixing chamber to contact the oil sands ore;
a mechanical agitator disposed within the mixing chamber, wherein the agitation produced by the mechanical agitator mixes the hydrocarbon diluent and the oil sands to form a hydrocarbon-based slurry;
a dispenser for a tunable surfactant in fluid communication with the hydrocarbon-based slurry, wherein the tunable surfactant is flowable at the ambient temperature into the hydrocarbon-based slurry to form a treated slurry, the treated slurry comprising a first phase containing bitumen and a second phase containing inorganic oil sands ore; and
a separator adapted for separating the first phase from the second phase,
wherein each component of the system operates at a temperature within a lower process fluid temperature environment.

27. The system of claim 26, wherein process fluid temperature is between 10 and 35 degrees Centigrade.

28. The system of claim 26, further comprising a mixer adapted for applying mechanical agitation to the treated slurry.

Patent History
Publication number: 20140151268
Type: Application
Filed: Jun 18, 2013
Publication Date: Jun 5, 2014
Inventors: David S. Soane (Chestnut Hill, MA), Robert P. Mahoney (Newbury, MA), Eric A. Verploegen (Cambridge, MA), Rosa Casado Portilla (Peabody, MA)
Application Number: 13/920,489
Classifications
Current U.S. Class: Tar Sand Treatment With Liquid (208/390); Solvent Extraction (196/14.52); With Added Organic Material (208/180)
International Classification: C10G 1/04 (20060101); C10G 21/14 (20060101);