Systems and processes for enhanced oil recovery and well discarding

Abstract

The present disclosure relates to methods and systems for injecting and / or sequestering carbonaceous materials in subterranean wells, and in some examples, for using carbonaceous materials to improve oil recovery and well waste. An example method includes obtaining a material comprising a carbonaceous liquid; optionally testing the compatibility of the material with a subterranean well; optionally adjusting the properties of the material to improve compatibility; and providing a material for injection into the subterranean well.

Description

[0001] Cross-reference to related applications

[0002] This application claims priority to U.S. Patent Application No. 18 / 360,317, filed July 27, 2023, the entire contents of which are incorporated herein by reference. Technical Field

[0003] In various examples, this disclosure relates to the field of atmospheric carbon removal and negative carbon dioxide emissions, and more specifically, to systems and processes for the geological sequestration of carbonaceous materials. Background Technology

[0004] Human burning of fossil fuels has increased atmospheric carbon dioxide concentrations from an average of 280 ppm in the 19th century to 415 ppm in May 2019. This is now considered a major cause of global climate change. Numerous global efforts are underway to reduce dependence on fossil fuels and develop alternative energy sources. However, there is a growing consensus that removing anthropogenic carbon from the atmosphere is necessary to limit the associated rise in global temperatures.

[0005] Biomass is a sink for atmospheric carbon. Existing biomass carbon sequestration projects convert biomass into sequesterable solids (such as biochar plowed into fields) or sequesterable gases (such as CO2 in underground geological formations). The persistence of carbon sequestration in soil remains an active area of ​​research. New categories have been developed in this field and are known as biomass carbon removal and storage (BiCRS).

[0006] Injecting CO2 into underground geological formations, addressing storage issues on a geological timescale, is also commonly used to enhance oil recovery. However, CO2 geological storage is typically expensive due to the high energy costs associated with gas separation, compression, transportation, and monitoring.

[0007] Improved systems and methods are needed for carbon sequestration, CO2 emission reduction, and enhanced oil recovery. Summary of the Invention

[0008] In some examples, this disclosure relates to systems and methods for injecting and / or storing carbon-containing liquids and / or other carbon-containing materials in underground wells. The carbon-containing liquids can be produced using a variety of chemical processes, including, for example, pyrolysis, hydrothermal liquefaction, transesterification, and fermentation. The carbon-containing liquids can be, or include, suspensions of, for example, bio-oil, biocrude oil, glycerol, biodiesel, ethanol, other carbon-containing materials, carbon-containing particles (e.g., biochar particles and / or biomass particles), or any combination thereof. The carbon-containing liquids can be tested to ensure compatibility with one or more underground wells. If desired, one or more properties of the carbon-containing liquids (e.g., pH, solids content, viscosity, etc.) can be modified to improve compatibility with the underground wells. Finally, the carbon-containing liquids can be injected into the underground wells for storage and / or enhanced oil recovery.

[0009] The systems and methods described herein for carbon-containing liquid sequestration offer several significant advantages over previous carbon sequestration methods. For example, the infrastructure required for the manufacture, transport, and placement of carbon-containing liquids is significantly reduced or simplified compared to previous methods involving carbon-containing gases (e.g., CO2) or solids. Standard hardware, similar to that used in the oil and gas industry, can be used to pump, store, and move the liquid injection. Furthermore, unlike gaseous injections such as CO2, liquid injections typically do not require compression and / or sequestration at sufficiently high pressures to maintain the material at a depth of compression or liquid (e.g., for CO2, at a depth of at least approximately 800 m). This avoids or significantly reduces the capital and operating costs associated with compression processes and equipment. The disposal, pumping, and / or delivery of liquid injections are also more reliable compared to solid injections such as soil or biochar. As described herein, in some cases, conventional pumps can be used to mix the liquid injection with solids to achieve the injection of a liquid-solid mixture into the well.

[0010] Generally speaking, in one aspect, the subject matter of this disclosure relates to a method for sealing carbon-containing liquids. The method includes: obtaining a material comprising a carbon-containing liquid, wherein the properties of the material have been modified to improve compatibility with an underground well; and providing the material for injection into the underground well.

[0011] In another aspect, the subject matter of this disclosure relates to the use of bio-oil or other (one or more) carbon-containing fluids for enhanced oil recovery. One example method includes: injecting bio-oil into a subsurface well at an injection point; and obtaining crude oil from the subsurface well at a production point. Advantageously, bio-oil can act as a production-enhancing fluid (e.g., due to its acidity) and / or can drive crude oil from the injection point through the subsurface well to the production point. For example, when used in combination with water, bio-oil can improve the scavenging efficiency of water injection in the well (e.g., by 10%, 20%, 50%, or more).

[0012] In another aspect, the subject matter of this disclosure relates to methods for abandoning underground wells. One example method includes: injecting bio-oil into the underground well; and plugging at least a portion of a casing extending from a surface location into the underground well. The plug may be formed of cement.

[0013] In another aspect, the subject matter of this disclosure relates to compositions obtained from underground wells. These compositions comprise a mixture of crude oil and bio-oil.

[0014] These and other objects, advantages, and features of the embodiments of the invention disclosed herein will become more apparent from the following description, drawings, and claims. Furthermore, it should be understood that the features of the various embodiments described herein are not mutually exclusive and can exist in various combinations and arrangements. Attached Figure Description

[0015] In the accompanying drawings, the same reference numerals in different views generally refer to the same parts. Furthermore, the drawings are not necessarily drawn to scale; rather, the emphasis is usually on illustrating the principles of the invention. In the following description, various embodiments of the invention are described with reference to the following drawings, in which: Figure 1 This is a schematic diagram of a system for forming and encapsulating carbon-containing materials according to certain embodiments; Figure 2 This is a schematic diagram of a system for preparing carbon-containing liquids from biomass according to certain embodiments; Figure 3 This is a schematic diagram of a system for producing biodiesel and glycerol from one or more fats and alcohols in a transesterification process, according to certain embodiments. Figure 4A This is a schematic diagram of a system for producing ethanol from one or more sugars in a fermentation process according to certain embodiments; Figure 4B This is a schematic diagram of a system for producing dispersions of biomass pellets and / or biochar pellets in a liquid, according to certain embodiments. Figure 5 This is a schematic diagram of a process for testing and / or conditioning carbon-containing liquids according to certain embodiments; Figure 6 This is a schematic diagram of a process for injecting carbonaceous material into one or more underground wells according to certain embodiments; Figure 7 This is a flowchart of a method for sealing carbonaceous materials in an underground well according to certain embodiments; Figure 8 This is a schematic diagram of a system for performing enhanced oil recovery according to certain embodiments; Figure 9 A flowchart of a method for enhancing oil recovery according to certain embodiments; and Figure 10 This is a flowchart of a method for abandoning underground wells according to certain embodiments. Detailed Implementation

[0016] The apparatus, system, method, and process of the present invention intended for protection include variations and adaptations developed using the information from the embodiments described herein. Those skilled in the art can adapt and / or modify the apparatus, system, method, and process described herein.

[0017] It should be understood that the order of steps or the sequence of certain actions is not important as long as the invention remains operable. Furthermore, two or more steps or actions can be performed simultaneously.

[0018] In various examples, "biomass" is or includes organic material derived from living organisms, such as plants or animals. Biomass can be or includes, for example, agricultural waste (e.g., corn stalks), forestry residues (e.g., branches, leaves, etc.), woody biomass (e.g., trees, shrubs, thickets, etc.), non-woody biomass (e.g., sugarcane, cereal straw, seaweed, algae, cotton, grass, kelp, soil, etc.), and / or processing waste (e.g., grain husks and cobs, bagasse, nut shells, vegetable oil cake, sawmill waste, food waste, human excrement, animal excrement, animal fat, etc.).

[0019] In various examples, “carbon-containing material” can be or includes solids, liquids, or gases having one or more carbon atoms. Some carbon-containing materials may be referred to herein as “bio-derived.” As described herein, such bio-derived carbon-containing materials can be produced directly from living organisms (e.g., biomass such as wood, grass, or animal fat) or can be derived from materials produced free from living organisms (e.g., biochar, biocrude oil, glycerin, or gasoline).

[0020] In various examples, "carbon-containing liquid" can be or includes liquids having one or more carbon-containing materials, including carbon-containing materials that are liquid or solid (e.g., solid particles suspended in a liquid). Carbon-containing liquids can include, for example, bio-oils, glycerol, biodiesel, ethanol, other alcohols, used cooking oils, vegetable oils, vegetable oils, solutions containing microorganisms or algae, bio-crude oil, bio-crude oil byproducts, dispersions of biomass particles and / or biochar particles in water or other liquids, and / or fuels such as petroleum, crude oil, gasoline, kerosene, or diesel. In some implementations, the carbon-containing liquids described herein are liquid at or near atmospheric pressure and / or at temperatures ranging from about -20°C to about 50°C, more typically from about 10°C to about 25°C, or at and around the well injection point at other ambient temperatures. Carbon-containing liquids are typically liquid at normal atmospheric temperatures and pressures and do not require a phase change from gaseous form (e.g., before or during injection into the well).

[0021] In various examples, an underground “well” (which may be alternatively referred to as an “injection well”) can be or includes underground strata, caverns, mine shafts, caverns, reservoirs, or other spaces beneath the surface that may contain or receive material for sequestration or storage. Underground wells may include, for example, salt caverns, natural caverns, mine shafts (such as abandoned mine shafts and / or leaching mine shafts), porous rock formations, commercial disposal wells, and injection wells or caverns classified as Class I, II, III, V, or VI by the U.S. Environmental Protection Agency (EPA).

[0022] Figure 1 This is a schematic diagram of a system 100 for forming and sequestering carbonaceous materials (e.g., achieving negative carbon emissions), according to certain examples. System 100 includes a source of carbonaceous material 102, such as, for example, biomass (e.g., agricultural waste and / or forestry residues). The carbonaceous material 102 may undergo a chemical process 104 to produce a carbonaceous liquid 106. The carbonaceous liquid 106 may undergo a preparation process 108 in which the compatibility of the carbonaceous liquid 106 with sequestration in an underground well is tested. If it is determined that the carbonaceous liquid 106 is incompatible with the underground well, one or more properties of the carbonaceous liquid 106 may be modified to improve compatibility. The carbonaceous liquid 106 or modified carbonaceous liquid 106 may then be used as an injection material 110, which may be injected into deep underground wells 112 (e.g., hundreds or thousands of meters below the surface). The underground well 112 may be, or include, for example, salt caverns or abandoned mine shafts. In the depicted example, the underground well 112 is located below a block 114 and below several layers 116 of ground, rock, sediment or other confined strata.

[0023] In various examples, chemical process 104 may utilize or include a variety of techniques for producing carbon-containing liquid 106 from carbon-containing material 102. Chemical processes may be, for example: rapid pyrolysis to produce bio-oil and / or biochar from biomass; transesterification to produce crude glycerol and biodiesel; hydrothermal liquefaction to produce bio-crude oil and its aqueous byproducts; fermentation to produce dilute ethanol; mechanical or solvent extraction to produce vegetable oils, such as soybean oil or rapeseed oil; and / or processes for producing biomass mixed or suspended in solution. In some examples, carbon-containing liquid 106 or a portion thereof may be obtained (e.g., purchased) without performing chemical process 104. For example, an entity preparing injection material 110 or injecting injection material 110 into a subsurface well 112 may obtain cooking oil, one or more fuels (e.g., petroleum, gasoline, diesel, and / or crude oil), or other carbon-containing liquid 106 without using chemical process 104 to obtain such liquids.

[0024] For carbon accounting purposes (e.g., utilizing low-carbon fuel standards or LCFS), System 100 and related methods can be used and accounted for in conjunction with the production of fuels such as biocrude oil or hydrogen, where the carbon intensity of the fuel takes into account the negative carbon impacts of System 100 and the methods. Additionally or alternatively, System 100 and the methods can be used and considered as voluntary negative emissions or voluntary offsetting. In some examples, System 100 and the methods may be officially recognized for cap-and-trade or federal and / or state carbon credits, such as tax credits (e.g., 45Q) and / or LCFS-based carbon accounting. System 100 and the methods can be used in some cases to enhance oil recovery and / or can replace CO2 geological sequestration. Advantageously, for the purpose of sequestering carbon from the atmosphere, System 100 can provide a complete process for the production, analysis, preparation, and injection of carbon-containing liquids.

[0025] Carbon-containing liquid production

[0026] Figure 2This is a schematic diagram of a system 200 for preparing a carbon-containing liquid from biomass 202 according to certain embodiments. In one example, a pyrolysis process 204 is used to produce bio-oil 206 from biomass 202. The pyrolysis process 204 can use a variety of pyrolysis techniques to produce bio-oil and / or biochar (e.g., in the range of 400°C to 800°C), wherein the heating rate and residence time range from less than one second to many minutes. In some examples, the highest yield of bio-oil can be obtained using fast or flash pyrolysis techniques. A fast pyrolysis process may include heating the feedstock biomass 202 to about 500°C at extremely high heating rates (e.g., from about 20°C to about 500°C in less than 1 second, 10 seconds, or 1 minute). Alternatively or additionally, slow or medium pyrolysis processes may be used. Compared to fast pyrolysis, slow or medium pyrolysis processes may have slower heating rates and / or wider temperature ranges (e.g., for the final temperature), and in some examples, may result in lower bio-oil yields. The resulting bio-oil 206 can possess properties similar to crude oil extracted from geological formations millions of years later. However, compared to crude oil, bio-oil 206 can be highly oxidized (e.g., on a dry weight basis, bio-oil 206 typically has 30%-40% oxygen compared to 1% oxygen in crude oil). This can reduce the value of bio-oil 206 as a fuel or chemical, but it can still be rich in carbon for sequestration (e.g., typically 40%-60% carbon on a dry weight basis). The pyrolysis process 204 can utilize rapid pyrolysis equipment and / or systems used and / or available from ENSYN or ABRI-TECH in Canada, BTG in the Netherlands, or Iowa State University, Charmindustrial, Frontline Bioenergy, or Mainstrea Engineering in the United States. Methods for performing biomass pyrolysis are described in U.S. Patent No. 10,457,882, published October 29, 2019, and U.S. Patent No. 10,851,037, published December 1, 2020, the entire disclosure of which is incorporated herein by reference.

[0027] In another example, a hydrothermal liquefaction process 208 is used to produce biocrude oil 210 from biomass 202. The hydrothermal liquefaction process 208 can be or includes a thermochemical conversion process that converts biomass 202 and water into biocrude oil 210 (oil component), aqueous byproducts, solid hydrothermal coke byproducts, and a syngas mixture typically at least 90% CO2. Biomass 202 can be milled biomass with varying moisture content. The hydrothermal liquefaction process 208 can be performed in a reactor using subcritical or supercritical water (e.g., at 300°C to 350°C and approximately 3000 psi). The residence time in the reactor is typically about a few minutes. Biocrude oil 210 and byproducts can be upgraded to sustainable jet fuel, road fuel, or marine fuel; however, this may be prohibitively expensive depending on the quality of the biocrude oil 210. The hydrothermal liquefaction process 208 may utilize hydrothermal liquefaction equipment and / or systems used and / or available for purchase from Pacific Northwest National Laboratory (PACIFIC NORTHWEST NATIONAL LABORATORY) or GENIFUEL, Steeperenergy of Denmark and Canada, Liquella of Australia or Altaka Energy of Turkey.

[0028] refer to Figure 3 In some examples, system 300 can be used in transesterification process 306 to produce biodiesel and glycerol 302 (or other carbon-containing liquids) from one or more fats 304. Transesterification process 306 may involve a reaction in which fat 304 reacts with one or more alcohols 308 in the presence of a catalyst to produce biodiesel and glycerol 302. Fat 304 may be derived from agricultural waste, vegetable oil, used cooking oil, or animal sources. In some examples, glycerol may be further refined to produce food-grade consumer products, incinerated, or provided as a feed additive to dairy cows or other livestock. Transesterification process 306 may utilize equipment and / or systems used by and / or available from Cargill Inc. and / or AG Processing, both companies located in the United States.

[0029] refer to Figure 4AIn some examples, system 400 can be used in fermentation process 406 to produce ethanol 402 (or other alcohols or carbon-containing liquids) from one or more sugars 404 (e.g., sugars derived from cellulosic biomass, direct biogenic sugars, or other carbohydrates), wherein bacteria consume sugar 404 and discharge ethanol 402 in a diluted form (e.g., a mixture of ethanol and water). Ethanol 402 can be distilled and dehydrated to a low water concentration (e.g., about 0 to 5% water); however, in typical examples, distillation and / or dehydration steps can be reduced or eliminated to lower production costs. In some cases, for example, the ethanol concentration of ethanol 402 can be less than or equal to 24% (e.g., more than 76% water). Solutions with an ethanol concentration higher than 24% can be considered hazardous waste. Fermentation process 406 can utilize equipment and / or systems used and / or available for purchase from Archer Daniel Midland Co., Cargill, or Marquis Energy LLC, each of which is located in the United States.

[0030] refer to Figure 4B In some examples, system 450 can be used to produce a carbon-containing liquid, which is or includes a biomass dispersion 452, wherein biomass particles and / or biochar particles (e.g., produced by pyrolysis or hydrothermal liquefaction) are mixed or suspended in the liquid. A shredding and mixing process 454 can be used to shred the biomass 456 and / or biochar into small particles, and then mix the particles with the liquid 458 to form the biomass dispersion 452. The shredding and mixing process 454 can utilize one or more mechanical devices to form the particles, such as a shredder, pulverizer, and / or grinder. The particle size (e.g., diameter) can be, for example, less than about 200 mm, less than about 50 mm, less than about 2 mm, or less than about 0.1 mm. In some cases, the particle size may depend on the type of well used for storage. For example, for Class V wells or salt caverns, the particle size (average or maximum) can be up to 200 mm, or in some examples, it can be in the range of about 2 mm to about 50 mm. For Class I or Class II wells, the particle size can be less than about 0.1 mm. Generally speaking, smaller particle size makes the biomass dispersion 452 easier to pump and / or less likely to clog pumping equipment. It is desirable for the particle size to be small enough to fit wellbore and / or underground pores.

[0031] Generally, the shredding and mixing process 454 can form biomass pellets without altering the chemical composition of the original biomass 456. For example, the biomass pellets may have the same or similar chemical composition as the original biomass 456. Various mixing devices (e.g., including tanks and agitators) can be used to mix the pellets with a liquid 458, which may be or include, for example, water, carbon-containing liquids (e.g., bio-oil or glycerol), and / or other suitable liquids. One or more surfactants may be added to improve dispersion stability. Additionally or alternatively, biocides may be added to prevent or limit microbial growth. As described herein, biocides may be added during conditioning steps to improve compatibility with underground wells. In some examples, in addition to or instead of biomass pellets, the biomass dispersion 452 may include biochar pellets.

[0032] In various examples, multiple biomass sources (e.g., biomass 202 or biomass 456) can be used to produce the carbon-containing liquid described herein. Biomass sources can be, or include, for example, waste sawdust (e.g., which would otherwise rot) and / or waste agricultural residues (e.g., from the immediate vicinity of a fast pyrolysis plant). In the United States, corn stalks (e.g., corn leaves, stalks, and cobs) are an example of a large-scale agricultural waste product with virtually no value. Rice straw and bagasse are similar low-value wastes in other countries. Such waste products are typically burned in the field, left to decompose, or used as animal feed. These three crops alone generate 1.7 billion tons of waste biomass annually, of which rice straw accounts for 580 million metric tons annually (e.g., 3.7 tons / hectare out of 158 million hectares), bagasse for 300 million metric tons annually, and corn stalks for 860 million metric tons annually (e.g., 43 billion bushels if 2 tons are recycled per 100 bushels).

[0033] A variety of other biomass sources or wastes can be used to generate the carbonaceous liquids described herein. For example, biomass sources can be or include materials from forest thinning or power line maintenance operations. Additionally or alternatively, some chemical processes may use only a portion of the biomass in their specific processes and may end up as a less useful byproduct that can be used as a biomass source. For example, lignin pulp produced by paper mills can be used as a biomass source. In another example, STORA ENSO Louisiana utilizes a process that absorbs unprocessed bagasse and produces mature bagasse byproducts that can be used as a biomass source rich in cellulose and lignin but lacking hemicellulose.

[0034] Another option for biomass sources or feedstocks is the acquisition of biomass for cultivation or soil remediation (e.g., at US Superfund sites), where the soil may contain high levels of strictly regulated toxic metals. Such waste can be difficult to treat, but as described herein, converting it into a bio-carbonaceous liquid containing strictly regulated toxic metals and then injecting it into a hazardous waste treatment well deep underground may be an efficient and effective remediation method, especially considering that deep well injection may have special permit exemptions for Superfund site waste. Additionally or alternatively, the systems and methods described herein can use biomass grown for conversion into materials for sequestration. Examples of such biomass materials can include energy crops such as Giant King Grass or other fast-growing biomass.

[0035] Injection preparation

[0036] Carbon-containing liquids (e.g., carbon-containing liquid 106) produced or obtained using the techniques described herein (e.g., rapid pyrolysis, transesterification, fermentation, or hydrothermal liquefaction) may possess one or more properties that are undesirable or incompatible with subsurface injection. Such properties may include, for example: a low pH (e.g., in the range of 1.5 to 5.5) that may be corrosive to equipment, well casing, and some rock formations; a significant particulate content that may block pore space and / or lead to instability in storage and transport; high viscosity or a tendency to self-aggregate, which may require high injection pressures or block the injection well; a low flash point (e.g., below 60°C), which may pose a fire or explosion hazard; a high specific gravity (e.g., greater than 1.2), which may exceed the density limits of some well suppliers; and / or the potential for microbial growth or interaction. In some examples, microbial growth or interaction may be problematic because reactions that may generate gases could release carbon dioxide, methane, or other gaseous products. Such reactions may increase pressure in the well, which could lead to well leakage and / or affect the ultimate durability of carbon sequestration.

[0037] refer to Figure 5In some examples, method 500 is used to test and / or condition one or more properties of the carbon-containing liquid 502 prior to underground injection. For example, various tests (step 504) can be performed on the carbon-containing liquid 502 to confirm its suitability for underground injection and / or compatibility with a particular underground well. For example, a series of laboratory tests can be performed to check compatibility with various well types. In some cases, tests can be used to measure or determine pH, corrosivity, particulate / solid content, viscosity, self-agglomeration tendency, flash point, density or specific gravity, likelihood of microbial growth (e.g., presence of sugars), total carbon content (e.g., to verify carbon sequestration), and / or heavy metal content. In some cases, toxicity characterization leaching procedures (e.g., SW-846 Test Method 1311 as defined by the Environmental Protection Agency) can be performed to determine the migration rate of analytes present in solid, liquid, or multiphase waste. The tendency to self-agglomerate can be detected by measuring the increase in viscosity and / or diameter growth of any suspended solids or micelles. For example, polymerization testing may be necessary or beneficial when carbon-containing liquid 502 (i) is mixed with other solutions or substances, (ii) is stored for a long period of time (e.g., more than one month), and / or (iii) is heated to temperatures above 100°C (e.g., before or during injection into a well). Portable microbial culture medium test kits (e.g., sold by INTERTEK) can be used to assess microbial growth potential.

[0038] Additionally or alternatively, core samples from the subsurface formation can be used to perform tests on carbon-containing liquid 502 to ensure compatibility. Such tests can be used to confirm that carbon-containing liquid 502 will not clog pore spaces, induce gas generation reactions, damage the formation, or produce undesirable reactions with formation materials. In some cases, carbon-containing liquid 502 can be tested in mixtures with downhole substrates, fluids, or other well materials to ensure compatibility with such materials. This avoids potential problems associated with premature polymerization, self-polymerization, phase separation, gas generation, and / or solid precipitation.

[0039] Still referencing Figure 5 If necessary, one or more properties of the carbon-containing liquid 502 can be adjusted (step 506) to produce injection material 508 for injection into underground wells. Typically, injection material 508 may be or include a modified version of the carbon-containing liquid 502. One or more tests may be performed on injection material 508 prior to the injection process (e.g., as described above with respect to step 504).

[0040] In some cases, such as, the injection material 508 can be produced by adding one or more pH adjusters to the carbon-containing liquid 502 to adjust the pH to a desired level (e.g., greater than 2, 3, 4, or 5), depending on the specific well or subsurface formation. The pH adjuster can be or includes, for example, a diluent (e.g., water), a buffer, or a blending additive such as vegetable oil, sunflower oil, corrosive materials, or processing materials such as molasses or petrochemical products.

[0041] Additionally or alternatively, injection material 508 can be produced by reducing the viscosity of the carbon-containing liquid 502 to a practical level for pumping or storage through preheating or dilution. In some examples, one or more of the pH adjusters described above can be added to achieve viscosity reduction through dilution. The desired or target viscosity of injection material 508 may depend on the specific well geology; for example, some injection wells can accept high-viscosity materials such as bitumen. Lower viscosity injection material 508 can be obtained by blending the carbon-containing liquid 502 with water, lower viscosity oil, and / or solvents such as methanol or other alcohols.

[0042] In some examples, depending on the characteristics of the target well, the injection material 508 can be produced by adding a polymerization inhibitor or polymerization promoter to the carbon-containing liquid 502. For wells where polymerization is undesirable, polymerization inhibitors, such as hydroquinone, can be added. For wells where autopolymerization may be beneficial (e.g., to help stabilize subsurface caverns), biochar or ash products can be added to the carbon-containing liquid 502 to increase the polymerization rate. Possible polymerization reactions involving the carbon-containing liquid 502 can include, for example, homopolymerization of aldehydes, condensation reactions of furfuryl alcohol and / or other furan derivatives, and polymerization of olefins (e.g., in the presence of free radicals from peroxides in the carbon-containing liquid 502).

[0043] Additionally or alternatively, in some cases, temperature regulation may be necessary to maintain the stability of the injected material 508 and / or achieve the desired material properties or flow characteristics during pumping or injection. For example, for bio-oils, a temperature of approximately 40°C may be targeted for injection to maintain low viscosity and / or prevent or accelerate polymerization. For some injected materials 508, such as glycerol, little or no temperature modification or control may be required.

[0044] In some examples, conditioning step 506 may include using mechanical stirring, for example, to blend layers caused by phase separation, reduce the overall viscosity, and / or to blend high-viscosity materials (e.g., oils) with low-viscosity materials. Various mechanical mixers (e.g., available from JONGIA) can be used. Mechanical stirring can occur within train tank cars, tank car trailers, and / or storage tanks (e.g., near the injection point). Additionally or alternatively, mechanical stirring may be used to blend in additives such as water (e.g., to reduce the specific gravity of bulk liquids), other carbon-containing liquids and solids (e.g., to increase carbon content), and / or biocides to reduce or eliminate the generation, growth, or interaction of microorganisms.

[0045] In various implementations, the conditioning step 506 may include increasing the flash point of the injected material 508 (e.g., above 60°C). The flash point can be increased by distillation (e.g., partial or vacuum distillation) and / or blending with a non-volatile or high-flash-point liquid (e.g., vegetable oil, sunflower oil, or water). Partial or vacuum distillation equipment and systems are available from KOCH MODULAR.

[0046] To reduce solid load, conditioning step 506 may utilize or include filtration or separation processes, such as mechanical filtration or centrifugal filtration, depending on the specific injection well geology. Mechanical filtration may utilize mechanical filters, which are available from HY-PROFILTRATION. Centrifugal filtration or separation may be performed using equipment purchased from DOLPHIN CENTRIFUGE. In some cases, solids (e.g., biochar, wood, etc.) may be ground into fine particles (e.g., less than 10 mm, less than 5 mm, or less than 1 mm in diameter) to ensure that any solids present in the injection material 508 do not clog the channels or pores during the injection process.

[0047] underground injection

[0048] In the United States and other countries, several types of injection wells are available for injecting carbonaceous liquids (e.g., injection material 508). Carbonaceous liquids with a high particulate content and / or considered unstable are best injected into salt caverns as part of a slurry or dispersion (e.g., a liquid with suspended solids or liquid particles). In the United States, these types of wells are considered EPAV-type injection wells. In such cases, excess biochar can be added to the slurry to increase its carbon content and / or promote polymerization. Advantageously, while polymerization is generally considered to have negative consequences, in some cases it can help stabilize salt caverns and / or other types of underground wells. Permanently solidifying the carbonaceous liquid (e.g., via polymerization) can reduce the risk of well-associated sinkholes or other instabilities. The carbonaceous liquid can be analyzed prior to injection to ensure it is immiscible with brine solutions and does not interact with the salt layer of the cavern walls.

[0049] According to one embodiment, carbonaceous liquids with low particulate content, miscible with brine, and / or interacting with salt cavern walls may be more suitable for injection into deep, porous rock formations (e.g., rather than salt caverns). In the United States, these types of wells can be classified as EPA-regulated deep subsurface injection wells, such as Class II wells. These wells are available throughout the United States and safely receive millions of gallons of harmless waste annually.

[0050] refer to Figure 6 Injection material 508 and / or other carbonaceous liquids or materials can be injected into various underground injection wells. Among various examples, a suitable type of underground injection well is the commercial disposal well 602, such as a Class I injection well at the Mid-Way Environmental outside Davenport, Oklahoma. Other Class I injection wells (e.g., associated with Class V wells) are suitable for placing displacement brine solutions, such as those previously used for natural gas storage near Hutchinson, Kansas.

[0051] Additionally or alternatively, in some cases, a suitable type of underground injection well is a salt cavern 604, such as the salt cavern operated by Underground Cavern Stabilization LLC at the former EMPIRE GAS propane storage site near Crupper's Corner, Kansas. Other examples of suitable salt caverns are operated by ONEOK, a company near Hutchinson, Kansas.

[0052] In some examples, a suitable type of subsurface injection well is a Class II cavity 606 previously used for oil and gas. Care should be taken to ensure the compatibility of the materials and geology with the injected material, and / or to prevent leakage through any open wellheads that may have been used and / or abandoned. In some examples, Class II cavity 606 may be used in conjunction with enhanced oil recovery systems and methods described herein. For example, carbonaceous liquids (e.g., injected material 508) may be injected into the subsurface well in an effort to enhance the well's oil recovery.

[0053] Additionally or alternatively, depleted, abandoned, or specially constructed mine shafts and / or natural caverns are excellent candidates for the underground injection wells described herein. Solution mining operations and mechanical mining can generate large caverns that can be used as placement or injection facilities with minimal effort compared to new construction. Preparation of such caverns for injection may include, for example, sealing ventilation shafts, installing baffles, and performing a series of integrity tests to ensure both chemical compatibility and formation suitability of the injection material. In the case of lean solution mining, given that the geological differences between Class V wells and solution mining caverns may be small, conversion to a suitable injection facility may simply be a permissible change.

[0054] Figure 7 This is a flowchart of an example method 700 for sealing carbon-containing materials. A material comprising a carbon-containing liquid is obtained (step 702). Optionally, the material (step 704) is tested for compatibility with the underground well. Optionally, the properties of the material are adjusted (step 706) to improve compatibility. The material is provided (step 708) for injection into the underground well. Injection operation hardware may include, but is not limited to, storage and blending tanks or containers, pumps, mechanical filtration devices, process piping, thermal conditioning equipment, sensors, and / or control hardware.

[0055] Enhanced oil recovery

[0056] refer to Figure 8 In various circumstances, the bio-oil and / or other carbonaceous liquids described herein can be used to enhance oil recovery in a subsurface well 810, which may be located below or between layers 812 of surface, rock, sediment, or other confined formations. Bio-oil may be injected into the subsurface well 810 at an injection point 814, and crude oil may be pumped from the subsurface well 810 at a production point 816. The injection point 814 may include a supply tank 818 or other bio-oil source, a pump 820, and a conduit or casing 822 located in the borehole and extending from a surface location 823 to the well 810. The pump 820 receives bio-oil from the supply tank 818 and pumps it down to the bottom portion of the casing 822, where the bio-oil may enter the well 810 through perforations, holes, or channels in the casing 822. The bio-oil may sweep or facilitate the flow of crude oil through the well 810 to the conduit or casing 824 at the production point 816. Crude oil may enter the casing 824 through perforations, holes, or channels in the bottom portion of the casing 824. Pump 826 at production point 816 can pump crude oil from the bottom part of casing 824 to storage tank 828 at surface location 823, where the crude oil can be stored for transportation or processing.

[0057] In some implementations, the material obtained from well 810 at production point 816 may include crude oil and a mixture of one or more enhanced oil recovery (EOR) materials, including, for example, bio-oil and / or water. In some cases, for example, a composition containing crude oil and bio-oil may be obtained from well 810. This composition may contain bio-oil in an amount less than about 20%, less than about 10%, less than about 5%, less than about 2%, or less than about 1% by weight. The remainder of the composition may include crude oil or a mixture of crude oil and other EOR materials (e.g., water and / or dispersants). Crude oil may be separated from the recovered fluid at production point 816 or other locations. Various separation techniques may be used, including, for example, filtration, centrifugation, distillation, chromatography, and / or evaporation. Any bio-oil separated from the crude oil may be provided to supply tank 818 and injected back into well 810 to further enhance oil recovery. Crude oil may be processed at a refinery to produce petroleum products such as gasoline, diesel, heating oil, wax, lubricating oil, and / or bitumen.

[0058] In some examples, bio-oil can be used to enhance oil recovery by improving flowability and / or modifying surface tension within well 810. For example, bio-oil with or without additives (e.g., water) can have properties and / or characteristics (e.g., viscosity, flow properties, or surfactant properties) similar to those of enhanced oil recovery polymers (e.g., lignin-derived biopolymers) mixed with water or other compounds, chemicals, or mixtures thereof. For example, when bio-oil is mixed with water and injected into well 810, it can increase the scavenging efficiency of water injection (e.g., in mature wells) by 10%, 20%, 50%, or more.

[0059] Additionally or alternatively, the bio-oil may be acidic (e.g., pH of about 2-3) and / or may act as a production-enhancing fluid to improve permeability (e.g., increase pore space in well 810), dissolve mineral complexes, or reverse the effects of scaling (e.g., limescale or calcium carbonate) around perforated sections of well 810 (e.g., in or around perforations in casings 822 and 824). For example, the acidic components of the bio-oil (e.g., formic acid and / or acetic acid components) may have a stimulating or dissolving effect in well 810, which may create or open pathways through areas of lower permeability, thereby enabling the recovery of crude oil from such areas. The acidity of the bio-oil may improve the injection capacity or productivity of well 810.

[0060] In some cases, when bio-oil is first injected into well 810, it may flow through the largest or most permeable channels (and scavenge crude oil from them). As the bio-oil remains in the well for an extended period, it may solidify or become more viscous, potentially clogging large or highly permeable channels. With the addition of more bio-oil, it may be forced to flow through lower permeability paths (and scavenge crude oil from them), thereby reducing the permeability of well 810 and / or creating a lower permeability reservoir. In some examples, as described herein, bio-oil may solidify more quickly when mixed with cement accelerators or curing accelerators.

[0061] Additionally or alternatively, in some examples, injecting bio-oil can alter the wettability of well 810. For example, the geological formations in well 810 may be preferably wetted by bio-oil rather than crude oil. This may result in the bio-oil displacing or separating the crude oil from solid materials in the geological formations or from the surface. The separated crude oil is then freely flushed away by the bio-oil, water, or other recovery fluids. In general, by modifying the wettability of well 810, bio-oil can improve the ability of production fluids to stably scaveng and / or propel crude oil through well 810 to casing 824 and / or production point 816.

[0062] In various examples, enhanced oil recovery can be achieved by injecting bio-oil into well 810 along with other materials or chemicals. For example, bio-oil can be injected with: water, salt solutions, polymers (e.g., to increase viscosity), surfactants (e.g., to reduce interfacial tension at the oil-water interface), dispersants (e.g., to reduce viscosity or pressure requirements for pumping or injection), curing accelerators (e.g., cement accelerators, sodium thiocyanate, triethanolamine, sulfates, nitrates, formates, or other materials that accelerate bio-oil curing), pH adjusters, corrosive materials (e.g., sodium hydroxide), low-salinity nanofluids (e.g., including nanoparticles, nanoparticles, nanocatalysts, and / or nanoemulsions), microorganisms (e.g., for microbial injection), liquid carbon dioxide (e.g., dissolved in crude oil), or any combination thereof.

[0063] Additionally or alternatively, bio-oil can be used in conjunction with other technologies for enhancing oil recovery. Such other technologies may include, for example, gas injection (e.g., injection of carbon dioxide, natural gas, and / or nitrogen), thermal injection (e.g., steam drive or fire drive), and / or plasma pulse technology.

[0064] Figure 9This is a flowchart of a method 900 for enhancing oil recovery according to certain examples. Bio-oil is injected (step 902) into a subsurface well (e.g., well 810) at an injection point (e.g., injection point 814). The injection point may include a bio-oil source (e.g., supply tank 818), a first pump (e.g., pump 820), and a first casing (e.g., casing 822) extending from a surface location at the injection point into the subsurface well. As described herein, the bio-oil can sweep crude oil through the subsurface well, act as a production-enhancing fluid, reduce scale buildup, and / or modify wettability in the well. Crude oil is obtained from the subsurface well at a production point (e.g., production point 816) (step 904). Production may include a second pump (e.g., pump 826) and a second casing (e.g., casing 824) extending from a surface location at the production point into the subsurface well.

[0065] Abandoned dry well

[0066] In some implementations, bio-oil can be injected into depleted wells or reservoirs as a sealing fluid or stabilizing material. For example, see again... Figure 8 Once the crude oil (or natural gas) in well 810 is depleted, a specified volume of bio-oil can be injected into well 810 through perforated casing 822 (e.g., based on the available volume or capacity of well 810 and / or other parameters, such as the pressure in well 810). Once the bio-oil has been injected, a plug can be formed by cement or other material in casing 822 (e.g., at the top of the perforated area of ​​casing 822) to abandon the completion interval associated with casing 822. This process can be repeated for (i) any other casing (e.g., casing 824) that is penetrated and completed into well 810 and / or (ii) shallower depleted reservoirs within the same casing 822 (e.g., by plugging other perforated areas of casing 822) until plugged well 810 is plugged and abandoned in accordance with management guidelines.

[0067] Advantageously, using bio-oil as a sealing fluid can eliminate pathways for gas (e.g., carbon dioxide and / or hydrocarbon gases) to leak from depleted wells. Besides long-term natural degradation, such leaks can also lead to the brittleness or corrosion of wellbore construction materials. For example, bio-oil used as a sealing fluid can mitigate the risk of leakage from supercritical carbon dioxide plumes, which can be mobile and corrosive in the presence of water and can migrate through weakened or degraded subsurface wells even if the well is clogged. The suitability of bio-oil as a sealing fluid can be enhanced by its tendency to solidify over time, which can further reduce well permeability. As described herein, this solidification tendency can be promoted by adding solidification accelerators to the bio-oil.

[0068] Figure 10This is a flowchart of a method 1000 for an abandoned underground well according to some examples. Bio-oil is injected into the underground well (e.g., well 810) (step 1002). Injection can be performed using a pump (e.g., pump 820) that receives bio-oil from a source (e.g., supply tank 818) and pumps it into a casing (e.g., casing 822) extending from a surface location into the underground well. At least a portion of the casing is then plugged (step 1004). For example, the pump (e.g., pump 820) can receive cement from a cement source and pump the cement into the casing to form a plug.

[0069] Example

[0070] Configuration 1

[0071] Carbon-containing liquids (such as bio-oils, glycerin, biodiesel, ethanol, used cooking oils, vegetable oils, other vegetable oils, solutions containing microorganisms or algae, bio-crude oil, bio-crude oil byproducts, petroleum, crude oil, gasoline, kerosene, diesel, or any combination thereof) can be obtained or purchased from suppliers. The compatibility and injection suitability of the carbon-containing liquids can be tested to confirm that the liquid meets the compatibility criteria of one of the well options. The carbon-containing liquids can be transported to facilities near or above the appropriate type of well and injected into the well.

[0072] Configuration 2

[0073] Biomass can be collected in various forms and from a variety of locations, such as agricultural waste from farms or secondary processing facilities (e.g., corn stalks from farms, almond shells from hulling facilities, or kelp from kelp farms), forestry residues from thinning or fire prevention operations, and / or sawdust, pulp, bagasse, or other byproducts from factories, manufacturing plants, or chemical plants. Biomass can be dried and milled as needed to produce fine particles (e.g., an average particle size of 0.5 mm to 5 mm) with low moisture content (e.g., less than 15%). Biomass can be injected into pyrolysis systems (e.g., fluidized bed pyrolysis reactors provided by MAINSTREAM ENGINEERING, rapid pyrolysis, or RTP provided by ENSYN). ® The bio-oil and / or biochar are produced using a process (such as the EMPYRO process provided by BTG or this rapid pyrolysis process). Measurements can be performed using standard procedures and equipment to determine the corrosivity, viscosity, and flash point of the bio-oil. The compatibility and injection suitability of the bio-oil can be tested to confirm that it meets the compatibility criteria of one of the well options. pH, viscosity, specific gravity, microbial growth potential, solids loading, and / or flash point can be adjusted as needed, for example, by blending the bio-oil with another material to meet the compatibility requirements of one of the well options. The bio-oil and / or biochar can be injected into the injection well.

[0074] Configuration 3

[0075] Carbon-containing liquids (e.g., including bio-oils, glycerol, biodiesel, ethanol, used cooking oils, vegetable oils, other vegetable oils, solutions containing microorganisms or algae, bio-crude oil, bio-crude oil byproducts, petroleum, crude oil, gasoline, kerosene, diesel, or any combination thereof) can be obtained or purchased from suppliers. The compatibility and suitability for placement of the liquid can be tested, and it can be determined that the liquid does not meet some of the well's requirements. Properties such as pH, viscosity, specific gravity, microbial growth potential, solids loading, and / or flash point can be adjusted as needed, for example, by filtering the liquid and / or blending the bio-oil with another material, to meet the requirements of one of the well options. The adjusted carbon-containing liquid can be injected into a suitable well.

[0076] Configuration 4

[0077] Biomass can be collected in various forms from various locations, such as agricultural waste from farms or secondary processing facilities (e.g., corn stalks from farms, or almond shells from hulling facilities), forestry residues from thinning or fire prevention operations, and / or sawdust, pulp, bagasse, or other byproducts from factories, manufacturing plants, or chemical plants. Biomass can be ground as needed to produce fine particles (e.g., an average particle size of 0.5 mm to 5 mm). Biomass can be injected into hydrothermal liquefaction units (e.g., provided or used by GENIFUEL, STEEPER ENERGY, or CHARM INDUSTRIAL, or catalytic hydrothermal reactors provided by LICELLA) to produce biocrude oil, aqueous byproducts, and solid byproducts. Measurements can be performed using standard procedures and equipment to determine the corrosivity, viscosity, and flash point of the biocrude oil. The compatibility and injection suitability of the biocrude oil can be tested to confirm that it meets the compatibility criteria for a well option. pH, viscosity, specific gravity, microbial growth potential, solids loading, and / or flash point can be adjusted as needed, for example, by blending bio-oil with another material, to meet the compatibility requirements of one well option. Bio-oil, aqueous byproducts, and / or hydrothermal carbon byproducts can be injected into the injection well.

[0078] Configuration 5

[0079] Bio-based materials in the form of vegetable oils, other vegetable oils, used cooking oils, animal fats, other fats, fatty acids, lipids, or any combination thereof can be obtained or purchased from suppliers. In the presence of a catalyst, the bio-based materials are reacted with one or more alcohols (e.g., ethanol or methanol) in a transesterification process to produce biodiesel and crude glycerol. Measurements are performed using standard procedures and equipment to determine the corrosivity, viscosity, and flash point of the biodiesel and / or crude glycerol. The compatibility and injection suitability of the biodiesel and / or glycerol can be tested to confirm that the biodiesel and / or glycerol meet the compatibility criteria of one of the well options. pH, viscosity, specific gravity, microbial growth potential, and / or flash point can be adjusted as needed, for example, by blending the biodiesel and / or glycerol with another material to meet the compatibility requirements of one of the well options. Glycerol and / or biodiesel can be injected into injection wells.

[0080] Configuration 6

[0081] Corn kernels, sugar beets, other direct biosaccharides, or cellulosic biomass-derived sugars can be obtained or purchased from suppliers. The sugars can be used in fermentation processes to produce diluted ethanol products. Measurements can be performed using standard procedures and equipment to determine the corrosivity, viscosity, and / or flash point of the bioethanol product. The compatibility and placement suitability of the ethanol product can be tested to confirm that it meets the compatibility criteria of one of the well options. pH, viscosity, specific gravity, microbial growth potential, and / or flash point can be adjusted as needed, for example, by blending the ethanol product with another material, to meet the compatibility requirements of one of the well options. The ethanol product can be injected into injection wells.

[0082] Configuration 7

[0083] Carbon-containing liquids (e.g., including bio-oils, glycerin, biodiesel, ethanol, used cooking oils, vegetable oils, other vegetable oils, solutions containing microorganisms or algae, bio-crude oil, bio-crude oil byproducts, petroleum, crude oil, gasoline, kerosene, diesel, or any combination thereof) can be obtained or purchased from suppliers. The compatibility and injection suitability of the liquids can be tested to confirm whether the liquids meet the compatibility criteria of one of the well options. If necessary, the liquids can be modified to improve compatibility. For the purpose of enhancing oil recovery and / or geological carbon sequestration, the liquids can be transported to facilities for injection into appropriate types of wells.

[0084] Specific embodiments of the subject matter have been described. Other embodiments are also within the scope of this disclosure. For example, the actions described in the claims can be performed in a different order and the desired result can still be obtained. As an example, the process depicted in the drawings does not necessarily require the specific or sequential order shown to achieve the desired result. In some implementations, multitasking and parallel processing may be advantageous. Additional steps or stages may be provided, or steps or stages may be removed from the described process. Therefore, other implementations are also within the scope of the following claims.

[0085] The wording and terminology used in this article are for descriptive purposes and should not be considered as limiting.

[0086] The terms “approximately,” “approximately equal to,” and other similar phrases (e.g., “X has a value of approximately Y” or “X is approximately equal to Y”) used in the specification and claims should be understood as a value (X) within a predetermined range of another value (Y). Unless otherwise specified, the predetermined range may be plus or minus 20%, 10%, 5%, 3%, 1%, 0.1%, or less than 0.1%.

[0087] The indefinite articles “a” and “an” used in the specification and claims shall be understood as “at least one” unless expressly stated otherwise. The phrase “and / or” used in the specification and claims shall be understood to mean “one or two” of the elements so combined, i.e., elements that exist together in some cases and separately in others. Multiple elements listed with “and / or” shall be interpreted in the same way, i.e., “one or more” of the elements so combined. In addition to the elements specifically indicated by the “and / or” clause, other elements may optionally be present, whether or not they are related to those specifically indicated. Thus, as a non-limiting example, in one embodiment, when used in conjunction with open-ended language such as “comprising,” a reference to “A and / or B” may refer only to A (which may alternatively include elements other than B); in another embodiment, only to B (which may optionally include elements other than A); in yet another embodiment, it applies to both A and B (which may optionally include other elements); and so on.

[0088] The word “or” as used in the specification and claims should be understood to have the same meaning as “and / or” as defined above. For example, when separating items in a list, “or” or “and / or” should be interpreted as inclusive, meaning including at least one, but also including multiple elements or lists of elements, and optionally, additional unlisted items. Only terms that explicitly indicate the opposite, such as “only one of…” or “exact one of…”, or when used in a claim, “consisting of…” will refer to including multiple elements or exactly one element from a list of elements. Generally, the term “or” when preceded by an exclusive term, such as “any,” “one of…,” “only one of…,” or “exact one of…”, should be interpreted only as indicating an exclusive choice (i.e., “one or the other, but not both”). When used in a claim, “consisting substantially of…” should have the ordinary meaning used in the field of patent law.

[0089] As used in the specification and claims, the phrase “at least one” refers to a list of one or more elements and should be understood as at least one element selected from any one or more elements in the element list, but does not necessarily include at least one of each element specifically listed in the element list, nor exclude any combination of elements in the element list. This definition also allows for the optional presence of elements other than those specifically identified in the element list referred to by the phrase “at least one,” regardless of their relation to those specifically identified elements. Thus, as a non-limiting example, “at least one of A and B” (or equivalently, “at least one of A or B,” or equivalently, “at least one of A and / or B”) in one embodiment may refer to at least one, optionally including more than one A, with no B (and optionally including elements other than B); in another embodiment, at least one, optionally including more than one B, with no A (and optionally including elements other than A); in yet another embodiment, at least one, optionally including more than one A, and at least one, optionally including more than one B (and optionally including other elements); and so on. The use of “including,” “comprising,” “having,” “containing,” “involving,” and their variations means to include the items listed after it and any additional items.

[0090] The use of ordinal terms in claims, such as "first," "second," "third," etc., does not imply any priority, order of precedence, or sequence of one claim element relative to another, or the chronological order in which the actions of the method are performed. Ordinal terms are used only as labels to distinguish one claim element with a certain name from another element with the same name (but the use of ordinal terms is to differentiate claim elements).

[0091] Each numerical value presented herein, for example in tables, graphs, or line graphs, is intended to represent a minimum or maximum value within a range for the corresponding parameter. Therefore, based on the teachings herein, when added to a claim, the numerical value provides explicit support for the scope of the claim, which may be higher or lower than that value. Where not included in a claim, each numerical value given herein should not be considered limiting in any way.

Claims

1. A method for enhancing oil recovery, the method comprising: The bio-oil is injected into the underground well at the injection point; as well as Crude oil is obtained from the underground well at the production site.

2. The method of claim 1, wherein injecting the bio-oil comprises pumping the bio-oil into a casing extending from a surface location into the underground well.

3. The method of claim 1, wherein injecting the bio-oil further comprises injecting at least one of water, a dispersant, or a curing accelerator into the underground well.

4. The method according to claim 1, wherein the injected bio-oil drives the crude oil through the underground well.

5. The method of claim 1, wherein the bio-oil acts as a production-enhancing fluid in the well.

6. The method of claim 1, wherein the bio-oil contains an acidic component that reduces scale buildup in or around the casing associated with the injection point or the production point.

7. The method according to claim 1, wherein the bio-oil modifies the wettability of the underground well.

8. The method of claim 1, wherein the bio-oil blocks highly permeable pathways in the underground well.

9. The method of claim 1, wherein obtaining the crude oil comprises pumping the crude oil into a casing extending from the underground well to a surface location.

10. A system for enhancing oil recovery, the system comprising: An injection point for injecting bio-oil into an underground well, the injection point comprising a bio-oil source, a first pump, and a first casing extending from a surface location at the injection point into the underground well; as well as A production point for obtaining crude oil from the underground well, the production point comprising a second pump and a second casing extending from a surface location at the production point to the underground well.

11. The system of claim 10, wherein the injection point further comprises at least one of water, a dispersant, or a curing accelerator for injection together with the bio-oil into the underground well.

12. The system of claim 10, wherein the injected bio-oil scours the crude oil through the underground well.

13. The system of claim 10, wherein the bio-oil serves as a production-enhancing fluid in the well.

14. The system of claim 10, wherein the bio-oil contains an acidic component that reduces scale buildup in or around the first or second casing.

15. The system of claim 10, wherein the bio-oil modifies the wettability of the underground well.

16. The system of claim 10, wherein the bio-oil blocks highly permeable pathways in the underground well.

17. A method for abandoning an underground well, the method comprising: Inject bio-oil into underground wells; as well as At least a portion of the casing extending from the surface location into the underground well is blocked.

18. The method of claim 17, wherein injecting the bio-oil comprises pumping the bio-oil into the casing.

19. The method of claim 17, wherein plugging the at least portion of the sleeve comprises forming a plug with cement.

20. A system for abandoned underground wells, the system comprising: Bio-oil source; cement source; Casing extending from the surface location into the underground well; as well as At least one pump is configured to (i) receive bio-oil from the bio-oil source and inject the bio-oil through the casing and into the underground well, and (ii) receive cement from the cement source and pump the cement into the casing.

21. The system of claim 20, wherein the cement forms a plug in the sleeve.

22. A composition obtained from an underground well, the composition comprising a mixture of crude oil and bio-oil.

23. The composition of claim 22, wherein the composition comprises less than about 20% by weight of the bio-oil.

Images