METHODS OF INCREASING A THERMAL CONDUCTIVITY AND TRANSFERRING HEAT WITHIN A SUBTERRANEAN FORMATION, AND METHODS OF EXTRACTING HYDROCARBONS FROM THE SUBTERRANEAN FORMATION
A method of increasing a thermal conductivity of a subterranean formation and a hydrocarbon-containing material comprises introducing nanoparticles having a high thermal conductivity into the subterranean formation. The nanoparticles adhere to surfaces of the hydrocarbon-containing material and increase the thermal conductivity of the hydrocarbon-containing material. A heating fluid is injected into the subterranean formation and contacts the nanoparticles. Heat is transferred to hydrocarbons of the hydrocarbon-containing material and reduces a viscosity of the hydrocarbons. Methods of transferring heat to a hydrocarbon-containing material, as well as methods of recovering hydrocarbons from a subterranean formation are also disclosed.
Embodiments of the disclosure relate generally to methods of increasing the thermal conductivity of subterranean formations. More particularly, embodiments of the disclosure relate to methods of increasing a thermal conductivity of a hydrocarbon-containing material within a subterranean formation with nanoparticle materials, and to methods of enhancing hydrocarbon recovery using the nanoparticles.
BACKGROUNDEnhanced oil recovery includes processes for increasing the amount of hydrocarbon material (e.g., crude oil, natural gas, etc.) recovered from a subterranean formation. Methods of enhanced oil recovery include water flooding, steam assisted gravity drainage (SAGD), steam flooding (e.g., cyclic steam stimulation (CSS)), and related methods. In these processes, a carrier fluid (e.g., water, brine, steam, etc.) is injected into a subterranean formation through injection wells to heat and/or sweep a hydrocarbon material contained within interstitial spaces (e.g., pores, cracks, fractures, channels, etc.) of the subterranean formation toward production wells offset from the injection wells.
However, heavy hydrocarbon materials (e.g., hydrocarbons having an API gravity of about 22 (specific gravity of about 0.92) or lower), or bitumen (e.g., bituminous sands including oil sands and tar sands) often exhibit a high viscosity and, therefore, are often difficult to produce. The high viscosity of such heavy hydrocarbons makes them difficult to mobilize and transport from a subterranean formation to the surface to be produced. Reducing the viscosity of such heavy hydrocarbons and bitumen is often a goal of hydrocarbon recovery processes.
Methods for enhancing the recovery of hydrocarbons and bitumen often include thermal stimulation methods, with the goal of decreasing the viscosity of the hydrocarbons. One thermal process of lowering the viscosity of hydrocarbons in subterranean formations is to flood the formation with a heating medium (e.g., steam). Steam increases the temperature of the hydrocarbons in the formation, which lowers the viscosity of the hydrocarbons and allows the hydrocarbons to drain or be swept towards an oil well to be produced. The steam may also sweep the hydrocarbon-containing regions of the subterranean formation (e.g., the reservoir) and physically displace any hydrocarbons within the reservoir and push the hydrocarbons towards producing wells. Steam can also condense into water, which can then act as a low viscosity carrier phase for an emulsion of the hydrocarbon and the water, allowing heavy hydrocarbons to be more easily produced. In other conventional thermal stimulation processes, steam may be injected into the formation through wormholes, fissures, or fractures within the subterranean formation to create a steam chamber. In some methods, such as CSS, steam may be injected into the subterranean formation and allowed to soak within the subterranean formation for a period of days or weeks. As the steam soaks within the hydrocarbon-containing formation, at least a portion of the hydrocarbons are heated and the viscosity of the heated hydrocarbons is reduced. The heated hydrocarbons may be swept or drain to a production well and be produced. Another method of thermal stimulation is steam assisted gravity drainage wherein two horizontal wells are drilled. Steam is injected into an upper well and heat from the steam transfers to bitumen, reducing the viscosity and mobilizing the bitumen. The bitumen may drain to a lower well, where it may be produced.
However, the aforementioned methods of thermal stimulation may not effectively heat large portions of hydrocarbon-containing materials within a subterranean formation. For example, a large portion of the hydrocarbons may be isolated from the steam. The hydrocarbons may be surrounded by a formation with a substantially low porosity (e.g., having very small pores and throat openings), reducing the accessibility of the steam to the hydrocarbons. Pore throat sizes may be as low as 1 μm in sandstones and shale formations and may be as low as about 10 nm in tight-gas sandstones, reducing the accessibility of the heating medium to major portions of the hydrocarbons within such formations. Thus, heat transfer to the hydrocarbons within such formations may be limited by the thermal conductivity of the formation surrounding entrapped hydrocarbons.
BRIEF SUMMARYEmbodiments disclosed herein include methods of increasing a thermal conductivity of a subterranean formation as methods of recovering hydrocarbons from a hydrocarbon-containing material within the formation. For example, in accordance with one embodiment, a method for increasing a thermal conductivity of a subterranean formation comprises combining nanoparticles with a carrier fluid to form a suspension, injecting the suspension into a subterranean formation, adhering the nanoparticles to surfaces and within pores of the subterranean formation, and heating hydrocarbon-containing material within the subterranean formation and at least a portion of the nanoparticles with a heating fluid.
In additional embodiments, a method of recovering hydrocarbons from a subterranean formation comprises introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation, contacting surfaces of the subterranean formation and a hydrocarbon-containing material with the suspension and adhering at least some of the nanoparticles to surfaces of the subterranean formation and the hydrocarbon-containing material, contacting at least some of the nanoparticles with steam, transferring heat from at least some of the nanoparticles to the subterranean formation and the hydrocarbon-containing material to reduce a viscosity of hydrocarbons within the hydrocarbon-containing material, and transferring the hydrocarbons to a surface of the subterranean formation.
In further embodiments, a method of transferring heat to a hydrocarbon-containing material comprises introducing a suspension comprising nanoparticles having an average thermal conductivity greater than about 2,000 W/m-K into a formation containing hydrocarbons, contacting at least a portion of the formation having a lower thermal conductivity than surrounding portions of the formation with the suspension to adhere nanoparticles of the suspension to the hydrocarbons of the at least a portion of the formation, contacting the nanoparticles and the formation with steam, and extracting hydrocarbons from the formation.
The following description provides specific details, such as material types, compositions, material thicknesses, and processing conditions in order to provide a thorough description of embodiments of the disclosure. However, a person of ordinary skill in the art will understand that the embodiments of the disclosure may be practiced without employing these specific details. Indeed, the embodiments of the disclosure may be practiced in conjunction with conventional techniques employed in the industry. In addition, the description provided below does not form a complete process flow for heating and recovering hydrocarbons from a hydrocarbon-containing subterranean formation. Only those process acts and structures necessary to understand the embodiments of the disclosure are described in detail below. A person of ordinary skill in the art will understand that some process components (e.g., pipelines, line filters, valves, temperature detectors, flow detectors, pressure detectors, and the like) are inherently disclosed herein and that adding various conventional process components and acts would be in accord with the disclosure. Additional acts or materials to heat and extract a hydrocarbon material from a subterranean formation or from bitumen may be performed by conventional techniques.
A rate of hydrocarbon recovery from a subterranean formation may be increased by increasing a thermal conductivity of a subterranean formation including hydrocarbons. For example, the transfer of heat to desired portions of a hydrocarbon-containing material within a subterranean formation may be increased by increasing the thermal conductivity of the subterranean formation and the hydrocarbon-containing material. In some embodiments, the thermal conductivity of the subterranean formation or hydrocarbon-containing material may be increased by increasing the thermal conductivity of the subterranean formation and hydrocarbon-containing material exhibiting a lower thermal conductivity than other portions of the formation and hydrocarbon-containing material. Accordingly, by increasing the thermal conductivity of the subterranean formation and hydrocarbon-containing material, hydrocarbons from a subterranean formation may be recovered with less steam and energy than in conventional thermal stimulation methods.
According to embodiments disclosed herein, a suspension including nanoparticles exhibiting a high thermal conductivity suspended in a carrier fluid is introduced into a subterranean formation to increase the thermal conductivity of the subterranean formation. The nanoparticles are configured to adhere to the surfaces of hydrocarbon-containing material within the subterranean formation and to organic surfaces (e.g., hydrocarbons) of the hydrocarbon-containing material. The nanoparticles may travel through interfaces of the host rock and surfaces of the hydrocarbon-containing material and disperse throughout the hydrocarbon-containing material, including regions within tightly packed formations (e.g., tight-gas sandstones, small pore shales, etc.). The nanoparticles may be configured (e.g. due to their size and shape) to travel through hydrocarbon-containing materials with reduced pore throat sizes and regions of reduced porosity (e.g., reduced pore sizes). As the nanoparticles travel through and adhere to the hydrocarbon-containing material, the they conductivity of the hydrocarbon-containing material increases. The hydrocarbon-containing material, including the high thermal conductivity nanoparticles attached thereto, may be exposed to a heating medium (e.g., a heating fluid), such as high temperature water or brine, high pressure steam, and combinations thereof. The heating fluid may contact at least a portion of the hydrocarbon-containing material and at least a portion of the attached nanoparticles. Trapped hydrocarbons may be heated at an accelerated rate because of the increased overall thermal conductivity of the hydrocarbon-containing material. Heat transfer through the subterranean formation and the hydrocarbon-containing material may be directed by a heat flow path defined by locations of the nanoparticles adhered to surfaces of the hydrocarbon-containing material. Accordingly, a heat transfer rate through the hydrocarbon-containing material is increased, reducing overall steam consumption and the time required to heat a given volume of the hydrocarbon-containing material. The methods described herein may require less steam, produce less waste water, and emit less carbon dioxide than conventional recovery methods. Accordingly, economical hydrocarbon production rates may be achieved in less time than in conventional thermal stimulation methods.
As used herein, the “nanoparticle” means and includes particles having an average particle size of less than about 1,000 nm. The nanoparticles may have an average particle size of less than about 1,000 nm. The nanoparticles may include materials exhibiting a high thermal conductivity, such as a thermal conductivity above about 2,000 W/m-K.
As used herein, the term “pore throat” means and includes an opening at a point where two grains of material (e.g., formation, sand, etc.) meet, which connects larger pore volumes between the grains. Generally, the pore throat decreases with a decreasing grain size.
As used herein, the term “hydrocarbon-containing material” means and includes materials that include hydrocarbons and may include materials that surround the hydrocarbons. For example, a hydrocarbon-containing material may include bitumen and may also include bitumen and surrounding host rock formations, such as sandstones and shale formations.
Referring to
The subterranean formation may be stimulated to create flow channels from a wellbore to hydrocarbon-containing materials located within the subterranean formation. In some embodiments, channels may be formed in the subterranean formation during drilling operations or during a cold heavy oil production with sand process (known in the industry as “CHOPS”). The channels may be referred to in the art as “wormholes” and may create fluid conductivity paths between the wellbore and the subterranean formation, such as between the wellbore and hydrocarbon-containing regions of the subterranean formation.
In other embodiments, fractures within the subterranean formation may be forming by hydraulic fracturing. Hydraulic or propellant-based fracturing may create fractures in the subterranean formation in zones adjacent hydrocarbon-containing materials to create channels through which hydrocarbons may flow to the wellbore, through a production string, and to the surface. A hydraulic fracturing process may include injecting a fracturing fluid (e.g., water, a high velocity propellant gas, etc.) into a wellbore at high pressures. The fracturing fluid may be directed to a hydrocarbon-containing material within the subterranean formation. The high pressure fracturing fluid creates fractures in the subterranean formation. Proppant suspended in fracturing fluids may be introduced (e.g., injected) into the formation to prop open the fluid channels created during the fracturing process at pressures below the pressure at which the fractures are created. The fractures, when open, may provide a flow path for hydrocarbon-containing materials within the formation to flow from the formation to the production string and to the surface. The fractures may also provide a flow path for materials including the nanoparticles to travel from the wellbore, through the fractures, and to the hydrocarbon-containing material. In some embodiments, at least a portion of the proppants may be coated with the nanoparticles.
Prior to heating the hydrocarbon-containing material, the hydrocarbon-containing material may be contacted with a suspension including nanoparticles having a high thermal conductivity. The nanoparticles may be mixed with a carrier fluid and suspended within the carrier fluid in a suspension formation process 100. The suspension formation process 100 includes suspending the nanoparticles in a carrier fluid to form a suspension of nanoparticles. The nanoparticles may be insoluble in the carrier fluid and suspended throughout the carrier fluid. In some embodiments, the carrier fluid is a colloidal suspension including colloidal nanoparticles. The colloidal nanoparticles may be a dispersed phase in a continuous carrier fluid phase and may be uniformly dispersed within the carrier fluid.
The carrier fluid may be an aqueous-based fluid with solid nanoparticles suspended in a continuous phase of the carrier fluid. The carrier fluid may be an aqueous fluid, such as a water or a brine solution. In other embodiments, the carrier fluid is a non-aqueous fluid, such as a hydrocarbon fluid, a brine-in-oil emulsion, or a water-in-oil emulsion. In some embodiments, the nanoparticles may be suspended in a high pressure steam carrier fluid. The steam may heat the subterranean formation and the hydrocarbon-containing material at the same time that the nanoparticles are introduced to the hydrocarbon-containing material. In other embodiments, the carrier fluid is a solvent. The solvent may include a mixture of one or more types of nanoparticles. The solvent may include materials such as methane, ethane, propane, isobutane, n-butane, pentanes, hexanes, heptanes, CO2, surfactants, aromatics such as benzene, xylene, and toluene, refined products such as gasoline and diesel, and combinations thereof.
The nanoparticles may include nanoparticles exhibiting a high thermal conductivity, such as a thermal conductivity higher than about 2,000 watts per meter kelvin (W/m-K). Non-limiting examples of suitable nanoparticles include single walled carbon nanotubes (SWCNTs) (about 6,000 W/m-K), multi-walled carbon nanotubes (MWCNTs) (about 3,000 W/m-K), graphene (about 5,000 W/m-K), and nanodiamonds (about 2,300 W/m-K). Thus, nanoparticles including SWCNTs, MWCNTs, graphene, nanodiamonds, and combinations thereof, may be mixed into a carrier fluid to form a suspension including the nanoparticles. The suspension may include SWCNTs, MWCNTs, graphene, nanodiamonds, and combinations thereof. In some embodiments, the suspension may include one or more of SWCNTs, MWCNTs, graphene, and nanodiamonds, and at least another of SWCNTs, MWCNTs, graphene, and nanodiamonds.
The nanoparticles may have a diameter between about 5 nm and about 1,000 nm, such as between about 5 nm and about 10 nm, between about 10 nm and about 20 nm, between about 20 nm and about 50 nm, between about 50 nm and about 100 nm, between about 100 nm and about 500 nm, or between about 500 nm and about 1,000 nm. The nanoparticles may have a length that is substantially larger than a diameter of the nanoparticles. For example, a length of the nanoparticles may be up to about 25,000 nm, such as between about 5 nm and about 50 nm, between about 50 nm and about 500 nm, between about 500 nm and about 1,000 nm, between about 1,000 nm and about 5,000 nm, between about 5,000 nm and about 10,000 nm, or between about 10,000 nm and about 25,000 nm.
The nanoparticles may be monodisperse wherein each of the nanoparticles has substantially the same size, shape, and material composition, or may be polydisperse, wherein the nanoparticles include a range of sizes, shapes, and/or material composition. In some embodiments, each of the nanoparticles has substantially the same size and the same shape as each of the other nanoparticles.
The carrier fluid may include between about 0.0001 weight percent (wt. %) to about 15 weight percent, such as between about 0.001 weight percent and about 1.0 weight percent, between about 1.0 weight percent and about 5.0 weight percent, or between about 5.0 weight percent and about 15 weight percent of the nanoparticles. In some embodiments, the suspension may include a first type of nanoparticle suspended within the carrier fluid and a second, different type of nanoparticle suspended within the carrier fluid. For example, the carrier fluid may include at least one of single walled carbon nanotubes, multi-walled carbon nanotubes, graphene, and nanodiamonds and at least another of single walled carbon nanotubes, multi-walled carbon nanotubes, graphene, and nanodiamonds suspended within the carrier fluid.
The thermal conductivity of the suspension including the nanoparticles may be between about 2.0 W/m-K and about 100 W/m-K, such as between about 2.0 W/m-K and about 20 W/m-K, between about 20 W/m-K and about 50 W/m-K, between about 50 W/m-K and about 75 W/m-K, or between about 75 W/m-K and about 100 W/m-K.
The nanoparticles may include one or more functional groups. The functional groups may increase a dispersibility of the nanoparticles in the carrier fluid. By way of non-limiting example, at least one edge, surface, or end of the nanoparticles may be modified to include at least one functional group. In some embodiments, the nanoparticles are functionalized only at a surface thereof. Functionalized nanoparticles may prevent flocculation or agglomeration of the nanoparticles within the suspension. In some embodiments, at least a portion of the nanoparticles are functionalized and at least another portion of the nanoparticles are unfunctionalized. Functionalization of at least a portion of the nanoparticles may increase the dispersibility of the nanoparticles within the carrier fluid, but may, undesirably, reduce the overall thermal conductivity of the nanoparticle suspension. In some embodiments, a minimal portion of the nanoparticles are functionalized to suspend a desired amount of nanoparticles within the suspension. In some embodiments, one type of nanoparticle may be functionalized and other types of nanoparticles may be unfunctionalized and suspended within the same carrier fluid. In some embodiments, at least a portion of the nanoparticles are functionalized with at least one of a hydroxyl group (OH), a carboxyl group (—COOH), an amine group ((NRR′R″), wherein R, R′, and R″ may include hydrogen, another functional group, or an organic group), an alkyl group, and polyethylene glycol functional groups.
The nanoparticles may also include one or more functional groups configured to adhere the nanoparticles to the formation surrounding the hydrocarbon-containing material, or to organic surfaces of the hydrocarbon-containing material (e.g., bitumen). Thus, at least a first portion of the nanoparticles may include one functional group to increase the dispersibility of the nanoparticles in the carrier fluid and at least a second portion of the nanoparticles may include another functional group configured to adhere the nanoparticles to the hydrocarbon-containing material or increase a dispersibility of the nanoparticles within hydrocarbons of the hydrocarbon-containing material. The carrier fluid may include at least a first portion of nanoparticles including a first functional group, a second portion of nanoparticles including a second functional group different than the first functional group, and a third portion of nanoparticles that are unfunctionalized. Each of the first portion of nanoparticles, the second portion of nanoparticles, and the third portion of nanoparticles may include the same type of nanoparticle or may include different types of nanoparticles. For example, a suspension may include at least one of single walled carbon nanotubes, multi-walled carbon nanotubes, graphene, and nanodiamonds functionalized with a first functional group, at least another of single walled carbon nanotubes, multi-walled carbon nanotubes, graphene, and nanodiamonds functionalized with a second functional group, and at least another of unfunctionalized single walled carbon nanotubes, multi-walled carbon nanotubes, graphene, and nanodiamonds. In some embodiments, the nanoparticles may include at least one hydroxyl group for increasing the dispersibility of the nanoparticles within an aqueous carrier fluid and may also include one or more carbonyl, carboxyl, hydroxyl, and amine groups configured to attach the nanoparticles to the hydrocarbon-containing material. In other embodiments, at least a portion of the nanoparticles may be functionalized with a hydrophobic functional group and at least another portion of the nanoparticles may be functionalized with a hydrophilic functional group. In some embodiments, nanoparticles may be functionalized with both hydrophilic functional groups and hydrophilic functional groups.
Non-limiting examples of functional groups include, but are not limited to, hydroxyl (OH) groups, carboxyl (—COOH) groups, carbonyl groups (a compound including a carbon-oxygen double bond (C═O)), such as a ketone, an aldehyde, a carboxylate group (RCOO), an ester group, and an alkoxy group (an alkyl group with a carbon-oxygen single bond (R—O—R′)), an alkyl group, an alkenyl group (C═C), an alkynyl group (C≡C), an organohalide group (R—X, wherein R is a hydrocarbon and X is a halide, such as F, Cl, Br, or I), a halide group, an amine group (primary amine, secondary amine, tertiary amine), an amide group (organic amides (—NHCO—), a sulfanoamide, a phosphoroamide), an organosulfur group, an epoxy group, a polyamine group, a sulfonate group (RSO2O−), a sulfate group (SO42−), a succinate group (HOOC—(CH2)2—COO−), a sulfosuccinate group (HOOC—CH2—SO3—COOH), a thiosulfate group (S2O32−), a glucoside group (C6H12O6—O), an ethoxylate group (R—(OC2H4)nOH), a propoxylate group (R—(OC3H6)nOH), a phosphate group (PO43−), an ether group (R—O—R′), an ethoxylatepropoxylate group, a phenyl group (R—C6H5), a benzyl group (C6H5—CH2), perfluro compounds, a thiol group (R—SH), an epoxy group, a lactone, a metal, an organo-metallic group, an oligomer (e.g., a dimer, a trimer, a tetramer, etc.), a polymer, an acid chloride group (RCOCl), and combinations thereof. By way of non-limiting example, where the hydrocarbon-containing material includes carboxylic acids, a portion of the nanoparticles may be functionalized with one or more of amine groups, hydroxyl groups, and combinations thereof to attach the nanoparticles to carboxylic acid groups within the hydrocarbon-containing material.
In some embodiments, between about 0 weight percent (0 wt. %) and about 20 weight percent, such as between about 0 weight percent and about 5 weight percent, between about 5 weight percent and about 10 weight percent, or between about 10 weight percent and about 20 weight percent of the nanoparticles are functionalized while the remaining nanoparticles are unfunctionalized.
The nanoparticles may be configured to adhere to the subterranean formation, to the hydrocarbon-containing material, and to combinations thereof. In some embodiments, at least a portion of the nanoparticles are configured to adhere to the subterranean formation and at least another portion of the nanoparticles are configured to adhere to the hydrocarbon-containing material (e.g., bitumen). As the nanoparticles adhere to surfaces of the formation, the thermal conductivity of the subterranean formation may increase. Similarly, as the nanoparticles adhere to surfaces of the hydrocarbon-containing material, the thermal conductivity of the hydrocarbon-containing material may increase. As the thermal conductivity of the subterranean formation and the hydrocarbon-containing material increase, the hydrocarbons within the subterranean formation may be stimulated to elevated temperatures with less steam and in less time than conventional heat stimulation methods. The nanoparticles may be configured to travel to deeper portions (e.g., shale rich portions) of the hydrocarbon-containing material and increase a thermal conductivity of the deeper portions of the hydrocarbon-containing material, increasing the rate at which heat is transferred to the hydrocarbons trapped within the hydrocarbon-containing material.
The carrier fluid may further include one or more surfactants to increase the dispersibility of the nanoparticles within the carrier fluid. For example, the surfactants may comprise between about 0.01 weight percent and about 15 weight percent of the carrier fluid, such as between about 0.01 weight percent and about 5 weight percent of the carrier fluid. The surfactants may be non-ionic, anionic, cationic, amphoteric, zwitterionic, janus, and combinations thereof. Non-limiting examples of suitable non-ionic surfactants include alkyl polyglycosides, sorbitan esters, methyl glucoside esters, amine ethoxylates, diamine ethoxylates, polyglycerol esters, alkyl ethoxylates, and alcohols that have been polypropoxylated and/or polyethoxylated or both. Anionic surfactants may include alkali metal alkyl sulfates, alkyl ether sulfonates, alkyl sulfonates, alkyl aryl sulfonates, linear and branched alkyl ether sulfates and sulfonates, alcohol polypropoxylated sulfates, alcohol polyethoxylated sulfates, alcohol polypropoxylated polyethoxylated sulfates, alkyl disulfonates, alkylaryl disulfonates, alkyl disulfates, alkyl sulfosuccinates, alkyl ether sulfates, linear and branched ether sulfates, alkali metal carboxylates, fatty acid carboxylates, and phosphate esters. Cationic surfactants may include, but are not necessarily limited to, arginine methyl esters, alkanolamines and alkylenediamides. Other surfactants may include dimeric or gemini surfactants, cleavable surfactants, janus surfactants, and extended surfactants (also called extended chain surfactants).
The nanoparticles in the suspension may be introduced to the hydrocarbon-containing material and adhere to the hydrocarbon-containing material in the injection process 102. The nanoparticles may be introduced into the subterranean formation with stimulation fluids, such as thermal treating fluids, hydraulic fracturing fluids, or any other suitable fluid for transporting the nanoparticles to the subterranean formation.
The injection process 102 may include introducing the nanoparticles to the subterranean formation at high pressures. Injecting the nanoparticle suspension into the subterranean formation at high pressures may create fractures within the subterranean formation. The fractures may form conduits through which the nanoparticles may travel through the formation and to the hydrocarbon-containing material. In other embodiments, the nanoparticles may be suspended within a fracturing fluid and introduced to the subterranean formation during a hydraulic fracturing process. The fracturing fluid may include a mixture of proppants for holding fractures created by the fracturing fluid open. The fracturing fluid may also include nanoparticles that may travel through the fractures and adhere to the subterranean formation within the fractures. The nanoparticles may also travel to the hydrocarbon-containing material beyond the fractures and travel through the hydrocarbon-containing material.
In yet other embodiments, the nanoparticles may be introduced into the subterranean formation after creating hydraulic fractures in the subterranean formation and prior to heat stimulation of the hydrocarbon-containing material. For example, after hydraulic fracturing is complete, a carrier fluid including the nanoparticles may be introduced into the subterranean formation. The nanoparticles may adhere to the subterranean formation within the fractures and may also travel across the hydrocarbon-containing material beyond the fractures. For example, the nanoparticles may travel within pores of the hydrocarbon-containing material as small as about 1,000 nm. The nanoparticles may adhere to the hydrocarbon-containing material at regions with small domains (e.g., pore throat sizes and pores) and regions of reduced porosity that may not be sufficiently stimulated during conventional heat stimulation techniques.
In yet other embodiments, the nanoparticles may be introduced into the hydrocarbon-containing material through wormholes within the subterranean formation. For example, wormholes may be created by removing sand filters from the well and producing sand with produced hydrocarbons, such as in cold heavy oil production with sand (known in the industry as “CHOPS”). In some embodiments, an initial stage of hydrocarbons may be recovered by CHOPS. Wormholes may be formed within the subterranean formation during the CHOPS production stage and prior to introducing the nanoparticles into the subterranean formation. The nanoparticles may be introduced into the subterranean formation through the wormholes formed during the initial CHOPS production stage.
In some embodiments, the suspension may be heated to a temperature below a boiling point of the carrier fluid prior to introducing the suspension into the hydrocarbon-containing material. Where the carrier fluid includes an aqueous-based fluid (e.g., water or brine), the carrier fluid may be heated to a temperature between about 90° C. and about 100° C. and introduced into the subterranean formation.
The hydrocarbon-containing material may include oil sands having an average pore throat diameter of about 1 μm or less. The number, size, and distribution of the pore throats may control the flow, capillary pressure, and the resistivity of flow through the formation. In some embodiments, the nanoparticles travel between pores and throats of a hydrocarbon-containing material having at least some pores and throats smaller than about one micrometer (1 μm). In some embodiments, pore throat diameters may be as low as between about 5 nm and about 1,000 nm, such as between about 5 nm and about 10 nm, between about 10 nm and about 100 nm, between about 100 nm and about 500 nm, or between about 500 nm and about 1,000 nm. For example, tight gas sandstones and shales may have pore throat diameters as low as about 5 nm. The nanoparticles may have an average size that is less than the average pore throat diameter or of the smallest pore throats in the hydrocarbon-containing material.
The thermal conductivity of the hydrocarbon-containing material (e.g., oil sands) may range from between about 1.5 W/m-K to about 2.5 W/m-K. The nanoparticles may exhibit a thermal conductivity that is about three orders of magnitude higher (i.e., about 1,000 times higher) than the thermal conductivity of the hydrocarbon-containing material. Therefore, a relatively low amount of nanoparticles in the hydrocarbon-containing material may significantly increase the average thermal conductivity of the hydrocarbon-containing material.
In some embodiments, the nanoparticles may be directed to portions of the hydrocarbon-containing material having a lower thermal conductivity than other portions of the hydrocarbon-containing material. By way of example, regions of the hydrocarbon-containing material having a lower porosity (e.g., sandstone and shale rich regions) may have a lower thermal conductivity than other regions of the hydrocarbon-containing material. Low thermal conductivity portions of the hydrocarbon-containing material may create non-uniform heat distribution in the hydrocarbon-containing material during thermal stimulation processes. For example, as steam is injected into the hydrocarbon-containing material, non-uniform heat distribution may result in a non-homogeneous steam chamber, wherein portions of the hydrocarbon-containing material remain unaffected by the steam, resulting in a lower than optimal volumetric sweep efficiency and hydrocarbon recovery rate. Contacting portions of the hydrocarbon-containing material having a lower natural thermal conductivity than other portions of the hydrocarbon-containing material with a higher concentration of nanoparticles than the other portions of the hydrocarbon-containing material may improve the uniformity of heat distribution within the hydrocarbon-containing material (e.g., increase a rate at which heat is transferred to the low thermal conductivity regions). Thus, heat transfer may be increased throughout the hydrocarbon-containing material as the thermal conductivity of at least portions of the subterranean formation and the hydrocarbon-containing material is increased. In some embodiments, the suspension of nanoparticles is directed at only the hydrocarbon-containing material without contacting other regions of the subterranean formation to improve the homogeneity of the thermal conductivity of the subterranean formation and the hydrocarbon-containing material.
In some embodiments, the nanoparticles are directed to shale-rich portions of the hydrocarbon-containing material including regions of hydrocarbons isolated by the tight spacing (e.g., small pore throats and pore diameters) of the hydrocarbon-containing material. By way of example, a thermal conductivity of shale rich portions of a hydrocarbon-containing material may be lower than a thermal conductivity of other portions of the hydrocarbon-containing material. In some embodiments, a first portion of nanoparticles may be directed to the hydrocarbon-containing material and a second portion of nanoparticles having a smaller average particle size may be directed to the hydrocarbon-containing material to contact deeper portions of the hydrocarbon-containing material than the first portion of nanoparticles. The first portion of nanoparticles and the second portion of nanoparticles may be suspended in the same carrier fluid. In other embodiments, a first portion of nanoparticles having a first thermal conductivity may be directed to a first portion of the hydrocarbon-containing material having a lower thermal conductivity than a second portion of the hydrocarbon-containing material. A second portion of nanoparticles having a second thermal conductivity lower than the first thermal conductivity may be directed to the second portion of the hydrocarbon-containing material.
After the suspension of nanoparticles has circulated through the hydrocarbon-containing material and adhered to at least portions of the hydrocarbon-containing material, the carrier fluid may be cycled out of the subterranean formation and back to the surface. A solution of hot water or hot brine may be introduced into the subterranean formation and hydrocarbon-containing material in an optional heating process 104. The hot water or hot brine solution may be circulated within the hydrocarbon-containing material and contact at least a portion of the nanoparticles adhered to surfaces of the hydrocarbon-containing material. The nanoparticles may accelerate the rate at which heat from the hot water or hot brine solution is transferred to the hydrocarbons of the hydrocarbon-containing material. The hot solution may reduce the viscosity and increase the permeability of the hydrocarbons contacted by the nanoparticles.
After the optional heating process 104, high pressure steam may be introduced to the hydrocarbon-containing material to further transfer heat to the hydrocarbons contained therein in the steam injection process 106. Heat from the high pressure steam may transfer to the hydrocarbon-containing material through the nanoparticles and reduce the viscosity of the hydrocarbons. As the hydrocarbons are heated and the viscosity is reduced, the porosity of the hydrocarbon-containing material may increase and the hydrocarbons may flow from the hydrocarbon-containing material to expose more portions of the hydrocarbons within the hydrocarbon-containing material than were exposed during the injection process 102 or the optional heating process 104.
In some embodiments, after a sufficient amount of time, heated hydrocarbons may be recovered from the hydrocarbon-containing material in the extraction process 110. If a sufficient amount of hydrocarbons have been contacted by the nanoparticles and heated during the steam injection process 106, the hydrocarbons may flow to a production well and be produced at the surface.
In other embodiments, after the steam injection process 106, an optional cycle process 108 may include repeating at least one of the injection process 102, the optional heating process 104, and the steam injection process 106. The optional cycle process 108 may include introducing nanoparticles into the hydrocarbon-containing material at various stages of heat stimulation or production. Nanoparticles may be introduced into the subterranean and adhere to the hydrocarbon-containing material during the injection process 102. A concentration of nanoparticles within the suspension may be less than, the same as, or greater than a concentration of nanoparticles in a suspension of a previous cycle. The carrier fluid may be the same or different than carrier fluids used in previous cycles. The nanoparticles suspended in the carrier fluid may contact surfaces of the hydrocarbon-containing material that were initially unexposed or inaccessible during previous cycles and were not previously contacted by nanoparticles. For example, during the optional heating process 104 and the steam injection process 106, hydrocarbon-bearing surfaces may become exposed as the hydrocarbon-containing material is heated and a viscosity of the hydrocarbons is reduced. Trapped hydrocarbons may become exposed as the hydrocarbon-containing material is heated and the pore size and pore throats of the hydrocarbon-containing material may increase, exposing more hydrocarbons of the hydrocarbon-containing material. Accordingly, each injection process 102 may contact more hydrocarbons of the hydrocarbon-containing material with nanoparticles than previous injection processes 102 because the optional heating process 104 and the steam injection process 106 of previous cycles may expose more regions of the hydrocarbon-containing material. Thus, the nanoparticles of an injection process 102 may adhere to the hydrocarbon-containing material at locations that were not contacted by the nanoparticles during a previous injection process 102.
In some embodiments, the optional cycle process 108 includes introducing a first suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into the subterranean formation in a first injection process 102 and contacting at least some of the nanoparticles of the first suspension with steam in a first steam injection process 106. The optional cycle process 108 further includes introducing a second suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation in a second injection process 102 and contacting at least some of the nanoparticles of the second suspension with steam in a second steam injection process 106. The first suspension and the second suspension may include the same or different types, concentrations, and functional groups on the nanoparticles. Steam from the first steam injection process 106 may expose hydrocarbons that were not contacted by nanoparticles of the first suspension in the first injection process 106. Nanoparticles of the second suspension may contact hydrocarbons that were not contacted by nanoparticles of the first suspension.
The optional cycle process 108 may be repeated any number of times. In some embodiments, only one cycle is required and the thermal conductivity of the hydrocarbon-containing material is sufficiently increased such that hydrocarbons may be economically recovered with one cycle. In other embodiments, the hydrocarbon-containing material may be tightly packed (e.g., shale, sandstone) such that pore sizes of the hydrocarbon-containing material are less than about 5 nm. Repeating the cycles may advantageously expose deeper portions of the hydrocarbon-containing material and enhance oil recovery beyond conventional thermal stimulation methods.
In some embodiments, hydrocarbons may be recovered from the subterranean formation in between each cycle. In other embodiments, hydrocarbons may be recovered from the subterranean formation after repeating two, three, four, etc., cycles. After hydrocarbons are recovered from the hydrocarbon-containing material, the hydrocarbon-containing material may be further stimulated by repeating the injection process 102, the optional heating process 104, the steam injection process 106, the optional cycle process 108. Hydrocarbons may be recovered by repeating the extraction process 110.
Accordingly, recovery of hydrocarbons may be increased in formations including heavy hydrocarbons with reduced water, energy consumption, and CO2 emissions. Nanoparticles adhered to the hydrocarbon-containing material may increase the rate of thermal transfer across the hydrocarbon-containing material as at least portions of the hydrocarbon-containing material and nanoparticles are contacted with a heating fluid.
While the disclosure is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the scope of the disclosure as defined by the following appended claims and their legal equivalents.
Claims
1. A method for increasing a thermal conductivity of a subterranean formation, the method comprising:
- combining nanoparticles with a carrier fluid to form a suspension;
- injecting the suspension into a subterranean formation;
- adhering the nanoparticles to surfaces and within pores of the subterranean formation; and
- heating hydrocarbon-containing material within the subterranean formation and at least a portion of the nanoparticles with a heating fluid.
2. The method of claim 1, further comprising forming fractures within the subterranean formation prior to injecting the suspension into a subterranean formation.
3. The method of claim 1, wherein combining nanoparticles with a carrier fluid to form a suspension comprises forming a suspension comprising between about 0.0001 weight percent and about 15 weight percent of the nanoparticles.
4. The method of claim 1, wherein adhering the nanoparticles to surfaces and within pores of the subterranean formation comprises attaching nanoparticles having an average size of between about 5 nm and about 1,000 nm to the surfaces and within pores of the subterranean formation.
5. The method of claim 1, wherein adhering the nanoparticles to surfaces and within pores of the subterranean formation comprises contacting the hydrocarbon-containing material with nanoparticles comprising at least one of single walled carbon nanotubes, multi-walled carbon nanotubes, graphene, and nanodiamonds.
6. The method of claim 1, wherein combining nanoparticles with a carrier fluid to form a suspension comprises combining at least some nanoparticles having at least one functional group configured to increase a dispersibility of the nanoparticles with the carrier fluid.
7. The method of claim 1, wherein heating hydrocarbon-containing material within the subterranean formation and at least a portion of the nanoparticles with a heating fluid comprises contacting the hydrocarbon-containing material and at least a portion of the nanoparticles with at least one of a hot water or a hot brine solution.
8. The method of claim 1, wherein heating hydrocarbon-containing material within the subterranean formation and at least a portion of the nanoparticles with a heating fluid comprises heating the hydrocarbon-containing material with steam.
9. The method of claim 1, wherein heating hydrocarbon-containing material within the subterranean formation and at least a portion of the nanoparticles with a heating fluid comprises contacting the nanoparticles adhered to the surfaces and within pores of the subterranean formation with the heating fluid and transferring heat through the nanoparticles to the hydrocarbon-containing material.
10. The method of claim 1, wherein heating hydrocarbon-containing material within the subterranean formation and at least a portion of the nanoparticles with a heating fluid comprises reducing a viscosity of hydrocarbons of the hydrocarbon-containing material.
11. A method of recovering hydrocarbons from a subterranean formation, the method comprising:
- introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation;
- contacting surfaces of the subterranean formation and a hydrocarbon-containing material with the suspension and adhering at least some of the nanoparticles to surfaces of the subterranean formation and the hydrocarbon-containing material;
- contacting at least some of the nanoparticles with steam;
- transferring heat from at least some of the nanoparticles to the subterranean formation and the hydrocarbon-containing material to reduce a viscosity of hydrocarbons within the hydrocarbon-containing material; and
- transferring the hydrocarbons to a surface of the subterranean formation.
12. The method of claim 11, wherein introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation comprises introducing a suspension comprising at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles and at least another of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into the subterranean formation.
13. The method of claim 11, wherein introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation comprises introducing the suspension into a portion of the subterranean formation having a lower thermal conductivity than other portions of the subterranean formation.
14. The method of claim 11, wherein introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation comprises introducing a suspension comprising a first portion of nanoparticles having a first functional group and a second portion of nanoparticles having a second functional group into the subterranean formation.
15. The method of claim 11, wherein introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation and contacting at least some of the nanoparticles with steam comprises:
- introducing a first suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into the subterranean formation;
- contacting at least some of the nanoparticles of the first suspension with steam;
- introducing a second suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation; and
- contacting at least some of the nanoparticles of the second suspension with steam.
16. The method of claim 15, wherein introducing a second suspension into the subterranean formation comprises contacting hydrocarbons that were not contacted by nanoparticles of the first suspension.
17. The method of claim 11, wherein introducing a suspension into a subterranean formation comprises introducing an aqueous-based suspension into the subterranean formation at a temperature of between about 90° C. and about 100° C.
18. The method of claim 11, further comprising introducing another suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into the subterranean formation after transferring the hydrocarbons to the surface of the subterranean formation.
19. The method of claim 11, wherein introducing a suspension including at least one of single wall carbon nanotube nanoparticles, multi-walled carbon nanotube nanoparticles, graphene nanoparticles, and nanodiamond nanoparticles into a subterranean formation comprises introducing the suspension into the subterranean formation during a hydraulic fracturing process.
20. A method of transferring heat to a hydrocarbon-containing material, the method comprising:
- introducing a suspension comprising nanoparticles having an average thermal conductivity greater than about 2,000 W/m-K into a formation containing hydrocarbons;
- contacting at least a portion of the formation having a lower thermal conductivity than surrounding portions of the formation with the suspension to adhere nanoparticles of the suspension to the hydrocarbons of the at least a portion of the formation;
- contacting the nanoparticles and the formation with steam; and
- extracting hydrocarbons from the formation.
Type: Application
Filed: Sep 12, 2014
Publication Date: Mar 17, 2016
Inventors: Fermin Fernandez-Ibanez (Houston, TX), Ashley L. Christian (San Antonio, TX), Chun Lan (Katy, TX), Jeffrey J. Krimmel (Houston, TX), Jacob D. Gibson (Calgary), Bernhard Meyer-Heye (Bremen)
Application Number: 14/484,686
