Compositions, systems, and methods for degrading shale using siderophores

Abstract

Provided herein are methods, systems, and compositions for degrading shale material. The methods, systems, and compositions provided herein generally involve the use of siderophores to degrade shale materials. The methods, systems, and compositions provided herein may be used to release metal from shale materials. The methods, systems, and compositions provided herein may be used to release hydrocarbons from shale materials. The methods, systems, and compositions provided herein may further involve collecting, extracting, and / or purifying the metal released from the shale material.

Description

Attorney Docket No. 66122-711.601COMPOSITIONS, SYSTEMS, AND METHODS FOR DEGRADING SHALE USING SIDEROPHORES CROSS-REFERENCE

[0001] This application claims the benefit of U.S. Provisional Application No. 63 / 762,568, filed on February 24, 2025, which is hereby incorporated by reference in its entirety.BACKGROUND

[0002] Oil-bearing shale are underground rock formations that contain trapped hydrocarbons. Hydrocarbons must be extracted and liberated from the shale prior to utilization. Current methods for extracting hydrocarbons from oil-bearing shale is expensive, inefficient, and harmful to the environment. For example, current methods of extracting oil release large quantities of greenhouse gases and are a major contributor to climate change.SUMMARY

[0003] There is a significant unmet need for compositions, methods, and systems that facilitate access to existing sources of hydrocarbons and / or metals, such as to extract and / or collect the hydrocarbons and / or metals from their sources and make them available for use in various industrial applications and / or products, in a manner that is industrially scalable, efficient, and inexpensive. The compositions, methods, and systems of the present disclosure address the aforementioned needs and shortcomings, in some aspects, by providing compositions, methods, and systems for extracting, separating, and / or collecting hydrocarbons (e.g., in the form of crude oil) and / or metals from shale in an efficient, inexpensive, and scalable manner. In some cases, the disclosure provides methods for further processing hydrocarbons extracted from shale using the compositions and methods disclosed herein into products such as fuels (e.g., gasoline, diesel, kerosene, jet fuel), asphalt, lubricants, chemical reagents used to make plastics, solvents, textiles, refrigerants, paint, synthetic rubbers, fertilizers, pesticides, pharmaceuticals, and more. In some cases, the disclosure further provides compositions, methods, and systems for processing extracted metals (e.g., from shale) and using them in a product (e.g., rechargeable batteries). The extracted metal may be processed and turned into an industrial grade metal, battery grade metal, pharmaceutical grade metal, or other useful forms of metals.

[0004] In one aspect, provided herein is a method of degrading a shale material, the method comprising: contacting the siderophore with the shale material under conditions sufficient for the siderophore to degrade at least a portion of the shale material. In some cases, theAttorney Docket No. 66122-711.601siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal. In some cases, the siderophore is in a solution. In some cases, the shale material is located in an oil well. In some cases, the shale material is located in a subsurface oil well. In some cases, the shale material is located in a surface oil well. In some cases, the method further comprises, prior to the contacting, treating the shale material with an acid. In some cases, the acid comprises hydrochloric acid (HC1), hydrofluoric acid (HF), acetic acid, or citric acid, or any combination thereof. In some cases, the acid comprises HC1. In some cases, the acid comprises HF. In some cases, the acid comprises acetic acid. In some cases, the acid comprises citric acid. In some cases, the acid is present in a solution at a concentration of at least about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, or 20% (w / v) acid. In some cases, the contacting comprises injecting the siderophore. In some cases, the siderophore is contacted with the shale material in the presence of at least one surfactant. In some cases, the at least one surfactant comprises dodecylbenzene sulfonic acid (DDB SA), a-Olefin sulfonate (AOS), betaine, NHance 52, NHance 1101, NHance 920 A, NHance 2101, XPerse®, Super SF 1001, Tween 80, sodium lauryl ether sulfate (SLES), sophorolipid, or any combination thereof. In some cases, the at least one surfactant comprises DDB SA. In some cases, the at least one surfactant comprises AOS. In some cases, the at least one surfactant comprises betaine. In some cases, the at least one surfactant comprises NHance52. In some cases, the at least one surfactant comprises NHance 1101. In some cases, the at least one surfactant comprises NHance 920A. In some cases, the at least one surfactant comprises NHance 2101. In some cases, the at least one surfactant comprises XPerse. In some cases, the at least one surfactant comprises Super SF 1001. In some cases, the at least one surfactant comprises Tween 80. In some cases, the at least one surfactant comprises SLES. In some cases, the at least one surfactant comprises sophorolipid. In some cases, the shale material comprises a hydrocarbon. In some cases, degradation of the shale material results in liberation of at least a portion of the hydrocarbon from the shale material. In some cases, at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, or at least about 99.5% of the hydrocarbon in the shale material is liberated after the contacting. In some cases, an amount of the hydrocarbon released from the shale material is greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in a solution at a concentration from about 5% (w / v) toAttorney Docket No. 66122-711.601about 25% (w / v). In some cases, an amount of the hydrocarbon released from the shale material is at least 1% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v). In some cases, an amount of the hydrocarbon released from the shale material is from about 1% to about 400% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v). In some cases, at least a portion of the hydrocarbon is released. In some cases, the contacting changes a fluid property of the shale material. In some cases, the fluid property comprises intrafacial tension (IFT), density, viscosity, or any combination thereof. In some cases, the contacting decreases the IFT, density, viscosity, or any combination thereof of the shale material. In some cases, the contacting decreases the IFT of the shale material. In some cases, the contacting decreases the IFT from about 10% to about 50% of the shale material. In some cases, the contacting decreases the density of the shale material. In some cases, the contacting decreases the density from about 1% to about 5% of the shale material. In some cases, the contacting decreases the viscosity of the shale material. In some cases, contacting decreases the viscosity of the shale material from about 10% to about 40%. In some cases, the contacting increases permeability, porosity, pore throat size, fluid flow, or any combination thereof of the shale material. In some cases, the contacting increases the permeability of the shale material from about 10% to about 500%. In some cases, the contacting decreases water absorption or water content of the shale material. In some cases, the contacting destabilizes the shale material. In some cases, the contacting forms a silica gel. In some cases, the shale material comprises one or more metals. In some cases, the one or more metals comprise iron, aluminum, chromium, vanadium, or uranium, or any combination thereof. In some cases, the one or more metals comprise aluminum, phosphorous, silicone, sulfur, potassium, calcium, manganese, nickel, copper, zinc, arsenic, selenium, strontium, rubidium, chromium, zirconium, niobium, molybdenum, barium, tin, lead, antimony, tantalum, tungsten, mercury, bismuth, thorium, titanium, cobalt, vanadium, yttrium, or uranium, or any combination thereof. In some cases, the method further comprises extracting a metal of the one or more metals from the shale material. In some cases, the method further comprises recovering a metal of the one or more metals from the shale material. In some cases, the method further comprises separating a metal of the one or more metals from the shale material. In some cases, the method further comprises purifying a metal of the one or more metals from the shale material, thereby obtaining a purified metal.Attorney Docket No. 66122-711.601In some cases, the purified metal has a purity of at least about 80%. In some cases, the purified metal has a purity of at least about 90%. In some cases, the purified metal has a purity of at least about 95%. In some cases, the purified metal has a purity of at least about 99%. In some cases, the purified metal has a purity of at least about 99.99%. In some cases, the purified metal has a purity of at least about 99.999%. In some cases, the method further comprises liberating at least a portion of the one or more metals from the shale material. In some cases, at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, or at least about 99.5% of the one or more metals in the shale material are liberated. In some cases, an amount of the one or more metals released from the shale material is greater than an amount of one or more metals released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v). In some cases, an amount of the one or more metals released from the shale material is at least 1% greater than an amount of one or more metals released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v). In some cases, an amount of the one or more metals released from the shale material is from about 1% to about 400% greater than an amount of one or more metals released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v). In some cases, at least a portion of the one or more metals are released. In some cases, the contacting comprises contacting the shale material with the siderophore in the presence of a salt. In some cases, the salt comprises citrate, oxalate, phosphate-buffered saline (PBS), bicarbonate, or any combination thereof. In some cases, the salt comprises citrate. In some cases, the salt comprises oxalate. In some cases, the salt comprises PBS. In some cases, the salt comprises bicarbonate. In some cases, the salt is at a concentration in a range from about 0.01 M to 1.0 M. In some cases, the salt is at a concentration of about 0.01 M, 0.05 M, 0.1 M, 0.5 M, or 1.0 M. In some cases, the salt is at a concentration of about 0.1 M. In some cases, the conditions comprise a pH from about 2 to about 8. In some cases, the conditions comprise a pH from about 4 to about 6. In some cases, the conditions comprise a pH of about 5. In some cases, the contacting occurs at a temperature of about -10 °C to about 150 °C. In some cases, the contacting occurs at a temperature of about average surface temperature. In some cases, the contacting occurs at a temperature of about 15 °C. In some cases, the contacting occurs at a temperature of about 20 °C. In some cases, the contacting occurs at aAttorney Docket No. 66122-711.601temperature of about 25 °C. In some cases, the contacting occurs at a temperature of about 125 °C. In some cases, the contacting occurs at a temperature of about 150 °C. In some cases, the conditions comprise a salinity of about 250,000 ppm to about 300,000 ppm. In some cases, the conditions comprise a salinity of about 250,000 ppm. In some cases, the conditions comprise a salinity of about 300,000 ppm. In some cases, the contacting occurs at a pressure of about surface pressure. In some cases, the contacting occurs at a pressure of about 15 psi. In some cases, the contacting occurs at a pressure of about 100 psi to about 8,000 psi. In some cases, the contacting occurs at a pressure of about 100 psi. In some cases, the contacting occurs at a pressure of at least about 100 psi. In some cases, the contacting occurs at a pressure of about 8,000 psi. In some cases, the contacting occurs at a pressure of at most about 8,000 psi. In some cases, the contacting occurs for a time period. In some cases, the time period is from about 1 day to about 7 days. In some cases, the time period is about 7 days. In some cases, the time period is at most about 7 days. In some cases, the contacting is performed without agitation. In some cases, the contacting is performed with agitation. In some cases, the siderophore is derived from an organism selected from the group comprising Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotoformans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter,Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus,Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof. In some cases, the siderophore is selected from the group consisting of: aerobactin, agrobactin, aminochelin, azotobactin, azotochelin, bacillibactin, deferoxamine B, deferoxamine E, desferrioxamine B, desferrioxamine E, enterobactin, ferrichrome, fusarinine C, micacocidin, mycobactin, ornibactin, protochelin, pseudobactin, pyochelin, pyoverdine, pyoverdine or a derivative of pyoverdine, PyoPpC-3B, pyridine-2,6-dithiocarboxylate, rhizobactin 1021, rhodotorulic acid, salmochelin, schizokinen, vibrioferrin, vibriobactin, vicibactin, yersiniabactin, and any combination thereof. In some cases, the siderophore comprises pyoverdine, pyochelin, ornibactin, or any combination thereof. In some cases, the siderophore comprises pyoverdine. In some cases, the siderophore comprises pyoverdine or a derivative of pyoverdine. In some cases, the siderophore comprises PyoPpC-3B. In someAttorney Docket No. 66122-711.601cases, the siderophore comprises pyochelin. In some cases, the siderophore comprises ornibactin. In some cases, the siderophore is purified from an organism. In some cases, the organism is selected from the group consisting of Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotof ormans, Pseudomonas BIO, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof. In some cases, the siderophore is produced in a host cell or in a cell-free production system. In some cases, the host cell comprises a bacterial cell. In some cases, the bacterial cell comprises Burkholderia bacteria. In some cases, the Burkholderia bacteria is selected from the group consisting of Burkholderia cenocepacia and Burkholderia cepacia. In some cases, the bacterial cell comprises a Pseudomonas bacteria. In some cases, the Pseudomonas bacteria is selected from the group consisting of Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa. In some cases, the shale material comprises clay, carbonaceous shale, black shale, or any combination thereof. In some cases, the clay is a swelling clay. In some cases, the shale material comprises kaolinite, montmorillonite, illite, feldspar, quartz or any combination thereof. In some cases, the shale material has low-permeability. In some cases, the method is performed in situ or ex situ. In some cases, the siderophore has a hydrocarbon extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore has a maximum hydrocarbon extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore has a metal extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore has a maximum metal extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least aboutAttomey Docket No. 66122-711.60192%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof, prior to the contacting. In some cases, the siderophore is bound to Fe(II) prior to the contacting. In some cases, the contacting comprises contacting the siderophore with the shale material in the presence of an oxidizing agent. In some cases, the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin. In some cases, the oxidizing agent comprises sodium hypochlorite. In some cases, the oxidizing agent comprises hydrogen peroxide. In some cases, the oxidizing agent comprises pyocyanin.

[0005] In another aspect, provided herein is a reaction mixture comprising: a siderophore and a shale material. In some cases, the reaction mixture further comprises a solution. In some cases, the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a prechelated metal. In some cases, the shale material is located in a surface oil well. In some cases, the shale material is located in a subsurface oil well. In some cases, the shale material is shale material that has been pre-treated with an acid. In some cases, the acid comprises hydrochloric acid (HC1), hydrofluoric acid (HF), acetic acid, or citric acid, or any combination thereof. In some cases, the acid comprises HC1. In some cases, the acid comprises HF. In some cases, the acid comprises acetic acid. In some cases, the acid comprises citric acid. In some cases, the acid comprises a solution comprising a concentration of at least about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, or 20% (w / v) acid. In some cases, the reaction mixture comprises at least one surfactant. In some cases, the at least one surfactant comprises dodecylbenzene sulfonic acid (DDBSA), a-Olefin sulfonate (AOS), betaine, NHance 52, NHance 1101, NHance 920 A, NHance 2101, XPerse®, Super SF 1001, Tween 80, sodium lauryl ether sulfate (SLES), sophorolipid, or any combination thereof. In some cases, the at least one surfactant comprises DDBSA. In some cases, the at least one surfactant comprises AOS. In some cases, the at least one surfactant comprises betaine. In some cases, the at least one surfactant comprises NHance52. In some cases, the at least one surfactant comprises NHance 1101. In some cases, the at least one surfactant comprises NHance 920A. In some cases, the at least one surfactant comprises NHance 2101. In some cases, the at least one surfactant comprises XPerse. In some cases, the at least one surfactant comprises Super SF 1001. In some cases, the at least one surfactant comprises Tween 80. In some cases, the at least one surfactant comprises SLES. In some cases, the at least oneAttorney Docket No. 66122-711.601surfactant comprises sophorolipid. In some cases, the reaction mixture comprises a salt. In some cases, the salt comprises citrate, oxalate, phosphate-buffered saline (PBS), bicarbonate, or any combination thereof. In some cases, the salt comprises citrate. In some cases, the salt comprises oxalate. In some cases, the salt comprises PBS. In some cases, the salt comprises bicarbonate. In some cases, the salt is at a concentration in a range from about 0.01 M to 1.0 M. In some cases, the salt is at a concentration of about 0.01 M, 0.05 M, 0.1 M, 0.5 M, or 1.0 M. In some cases, the salt is at a concentration of about 0.1 M. In some cases, the reaction mixture comprises a pH from about 2 to about 8. In some cases, the reaction mixture comprises a pH from about 4 to about 6. In some cases, the reaction mixture comprises a pH of about 5. In some cases, the reaction mixture is at a temperature of about -10 °C to about 150 °C. In some cases, the reaction mixture is at a temperature of about average surface temperature. In some cases, the reaction mixture is at a temperature of about 15 °C. In some cases, the reaction mixture is at a temperature of about 20 °C. In some cases, the reaction mixture is at a temperature of about 25 °C. In some cases, the reaction mixture is at a temperature of about 125 °C. In some cases, the reaction mixture is at a temperature of about 150 °C. In some cases, the reaction mixture comprises a salinity of about 250,000 ppm to about 300,000 ppm. In some cases, the reaction mixture comprises a salinity of about 250,000 ppm. In some cases, the reaction mixture comprises a salinity of about 300,000 ppm. In some cases, the reaction mixture is at a pressure of about surface pressure. In some cases, the reaction mixture is at a pressure of about 15 psi. In some cases, the reaction mixture is at a pressure of about 100 psi to about 8,000 psi. In some cases, the reaction mixture is at a pressure of at least about 100 psi. In some cases, the reaction mixture is at a pressure of about 8,000 psi. In some cases, the reaction mixture is at a pressure of at most 8,000 psi. In some cases, the reaction mixture is incubated for a time period. In some cases, the time period is from about 1 hour to about 7 days. In some cases, the time period is from about 7 days. In some cases, the time period is from at most about 7 days. In some cases, the reaction mixture is not agitated. In some cases, the reaction mixture is agitated. In some cases, the siderophore is derived from an organism selected from the group comprising Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotof ormans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum,Attorney Docket No. 66122-711.601Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof. In some cases, the siderophore is selected from the group consisting of: aerobactin, agrobactin, aminochelin, azotobactin, azotochelin, bacillibactin, deferoxamine B, deferoxamine E, desferrioxamine B, desferrioxamine E, enterobactin, ferrichrome, fusarinine C, micacocidin, mycobactin, ornibactin, protochelin, pseudobactin, pyochelin, pyoverdine, pyoverdine or a derivative of py overdine, PyoPpC-3B, pyridine-2,6-dithiocarboxylate, rhizobactin 1021, rhodotorulic acid, salmochelin, schizokinen, vibrioferrin, vibriobactin, vicibactin, yersiniabactin, and any combination thereof. In some cases, the siderophore comprises pyoverdine, pyochelin, ornibactin, or any combination thereof. In some cases, the siderophore comprises pyoverdine. In some cases, the siderophore comprises pyoverdine or a derivative of pyoverdine. In some cases, the siderophore comprises PyoPpC-3B. In some cases, the siderophore comprises pyochelin. In some cases, the siderophore comprises ornibactin. In some cases, the siderophore is purified from an organism prior to the contacting. In some cases, the organism is selected from the group consisting of: Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotoformans, Pseudomonas BIO, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof. In some cases, the siderophore is produced in a host cell or in a cell-free production system. In some cases, the host cell comprises a bacterial cell. In some cases, the bacterial cell comprises Burkholderia bacteria. In some cases, the Burkholderia bacteria is selected from the group consisting of: Burkholderia cenocepacia and Burkholderia cepacia. In some cases, the bacterial cell comprises a Pseudomonas bacteria. In some cases, the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa. In some cases, the shale material comprises clay, carbonaceous shale, black shale, or any combination thereof. In some cases, the clay is a swelling clay. In some cases, the shale material comprises kaolinite, montmorillonite, illite, feldspar, quartz or any combinationAttorney Docket No. 66122-711.601thereof. In some cases, the shale material has low-permeability. In some cases, the reaction mixture is in situ or ex situ. In some cases, the siderophore has a hydrocarbon extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore has a maximum hydrocarbon extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore has a metal extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore has a maximum metal extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher. In some cases, the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof. In some cases, the siderophore is bound to Fe(II). In some cases, the reaction mixture comprises an oxidizing agent. In some cases, the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin. In some cases, the oxidizing agent comprises sodium hypochlorite. In some cases, the oxidizing agent comprises hydrogen peroxide. In some cases, the oxidizing agent comprises pyocyanin.

[0006] In another aspect, provided herein is a method of degrading a shale material in a surface oil well, the method comprising: contacting the shale material with the siderophore under conditions sufficient for the siderophore to degrade at least a portion of the shale material. In some cases, the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal. In some cases, the siderophore is in a solution. In some cases, the siderophore comprises pyoverdine. In some cases, the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to the contacting. In some cases, the siderophore is bound to Fe(II) prior to the contacting. In some cases, the siderophore is contacted with the shale material in the presence of an oxidizing agent. In some cases, the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin. In some cases, the oxidizing agent comprises sodium hypochlorite. In some cases, the oxidizing agent comprises hydrogen peroxide. In someAttorney Docket No. 66122-711.601cases, the oxidizing agent comprises pyocyanin. In some cases, the contacting occurs at a temperature of about average surface temperature. In some cases, the contacting in (b) occurs at a temperature of about 15 °C. In some cases, the contacting in (b) occurs at a temperature of about 20 °C. In some cases, the contacting in (b) occurs at a temperature of about 25 °C. In some cases, the contacting in (b) occurs at a pressure of about surface pressure. In some cases, the contacting in (b) occurs at a pressure of about 15 psi. In some cases, the contacting in (b) occurs at a pressure of at most about 15 psi. In some cases, the contacting in (b) occurs for a time period. In some cases, the time period is from about 1 hour to about 7 days. In some cases, the time period is about 7 days. In some cases, the time period is at most about 7 days. In some cases, the siderophore is purified from an organism prior to the contacting. In some cases, the host cell comprises a bacterial cell. In some cases, the bacterial cell comprises a Pseudomonas bacteria. In some cases, the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa.

[0007] In yet another aspect, provided herein is a method of degrading a shale material in a subsurface oil well, the method comprising: contacting the siderophore with the shale material under conditions sufficient for the siderophore to degrade at least a portion of the shale material. In some cases, the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal. In some cases, the siderophore is in a solution. In some cases, the siderophore comprises pyoverdine. In some cases, the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to the contacting. In some cases, the siderophore is bound to Fe(II) prior to the contacting. In some cases, the siderophore is contacted with the shale material in the presence of an oxidizing agent. In some cases, the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin. In some cases, the oxidizing agent comprises sodium hypochlorite. In some cases, the oxidizing agent comprises hydrogen peroxide. In some cases, the oxidizing agent comprises pyocyanin. In some cases, the contacting occurs at a temperature of about -10 °C to about 150 °C. In some cases, the contacting occurs at a temperature of about 125 °C. In some cases, the contacting occurs at a temperature of about 150 °C. In some cases, the contacting occurs at a pressure of about 100 psi to about 8,000 psi. In some cases, the contacting occurs at a pressure of at least about 100 psi. In some cases, the contacting occurs at a pressure of about 8,000 psi. In some cases, the contacting occurs at a pressure of at most about 8,000 psi. In some cases, the contacting occurs for aAttorney Docket No. 66122-711.601time period. In some cases, the time period is from about 1 hour to about 7 days. In some cases, the time period is about 7 days. In some cases, the time period is at most about 7 days. In some cases, the siderophore is purified from an organism prior to the contacting. In some cases, the host cell comprises a bacterial cell. In some cases, the bacterial cell comprises a Pseudomonas bacteria. In some cases, the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa.

[0008] In yet another aspect, provided herein is a stabilized siderophore comprising the siderophore bound to at least one of Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), or Zn(II).

[0009] In another aspect, provided herein are methods for mitigating excessive swelling and preserving structural integrity of a swelling clay, the method comprising contacting the swelling clay with a siderophore. In some cases, the siderophore is pyoverdine. In some cases, the method further comprises contacting the reactive clay mineral with potassium chloride. In some cases, the swelling clay comprises smectite or montmorillonite.

[0010] In another aspect, provided herein are compositions comprising a siderophore and potassium chloride. In some cases, the siderophore is pyoverdine. In some cases, the potassium chloride is an amount of about 3.5%. In some cases, the composition is a solution.INCORPORATION BY REFERENCE

[0011] All publications, patents, and patent applications mentioned in this specification are herein incorporated by reference to the same extent as if each individual publication, patent, or patent application was specifically and individually indicated to be incorporated by reference.BRIEF DESCRIPTION OF THE DRAWINGS

[0012] The novel features of the present disclosure are set forth with particularity in the appended claims. A better understanding of the features and advantages of the present disclosure will be obtained by reference to the following detailed description that sets forth illustrative embodiments, in which the principles described herein are utilized, and the accompanying drawings of which:

[0013] FIG. 1 shows an example workflow according to the methods of the present disclosure.

[0014] FIGs. 2A-2B show Fourier-transform infrared spectroscopy (FTIR) scans of hydrocarbons released from solid shale material. FIG. 2A shows a FTIR scan of the totalAttorney Docket No. 66122-711.601hydrocarbons released from a solid shale material under Conditions 1, 4, 5, 7, 11, and 15 with a siderophore. FIG. 2B shows a FTIR scan of the total hydrocarbons released from a solid shale material under Conditions 1, 2, and 3, which compared hydrocarbon release by the inclusion of buffer in the reaction conditions with the siderophore. The higher the absorbance, the higher total amount of hydrocarbons, indicating more efficient release under that condition.

[0015] FIGs. 3A-3B show a FTIR scans of hydrocarbons remaining in the solid shale material after release under various reaction conditions. FIG.3A shows a FTIR scan of the total hydrocarbons remaining in the solid shale material after treatment with the siderophore under Conditions 1 and 4-15. FIG. 3B shows a relevant area for hydrocarbon zoomed in for clarity of the differences. The lower the absorbance, the lower total amount of remaining hydrocarbons, indicating more efficient release under that condition.

[0016] FIGs. 4A-4B show a FTIR scans of hydrocarbons remaining in the solid shale material after release under various reaction conditions. FIG. 4A is replotted Conditions 3, 7, and 15 from FIG. 3A for additional clarity. FIG. 4B shows a relevant area for hydrocarbon zoomed in for clarity of the differences. The lower the absorbance, the lower total amount of remaining hydrocarbons, indicating more efficient release under that condition.

[0017] FIGs. 5A-5B show FTIR scans of hydrocarbons remaining from solid shale material after release under various conditions. FIG. 5A shows a FTIR scan of the total hydrocarbons remaining in the solid shale material after treatment with Conditions 1, 2, and 3, which compared hydrocarbon release by the inclusion of buffer in the reaction conditions with the siderophore. FIG. 5B shows a relevant area for hydrocarbon zoomed in for clarity of the differences. The lower the absorbance, the lower total amount of remaining hydrocarbons, indicating more efficient release under that condition.

[0018] FIG. 6 shows a FTIR scan of the total hydrocarbons released in a liquid fraction from a shale material under using Groups 1-4 conditions.DETAILED DESCRIPTION

[0019] There is a significant unmet need for compositions, methods, and systems that facilitate access to existing sources of hydrocarbons and / or metals, such as to extract and / or collect the hydrocarbons and / or metals from their sources (e.g., shale) and make them available for use in various industrial applications and / or products, in a manner that is industrially scalable, efficient, and inexpensive. Current methods for extracting hydrocarbons (e.g., oil) from oil wells are damaging to the environment, and are a major source ofAttorney Docket No. 66122-711.601greenhouse gases. Old or underperforming oil wells are often characterized with low permeability and difficulty in extracting additional hydrocarbons, and there is an unmet need for efficient technologies to facilitate access to the hydrocarbons in these oil wells.

[0020] Siderophores are small compounds secreted by fungi and microorganisms that chelate iron and other metals with high affinity. In shale materials, the removal of metals may weaken the crystal lattice, causing structural destabilization. The structural destabilization and transformation may decrease the swelling potential of the clays, increase pore size and connectivity, and in turn increase the reservoir’s permeability and thus access to hydrocarbons. Methods and compositions described herein can thereby enhance oil recovery from shale.

[0021] In addition, metals such as lithium, aluminum, iron, nickel, cobalt, copper, manganese, magnesium, zinc, and rare earth elements have vast applications across various industries and in different products. The demand for such metals continues to increase, and there is an unmet need for efficient technologies to facilitate access to metal sources, and to extract and collect the metals for use in products and industries in need thereof and to meet demand. As an example, lithium is highly in demand for rechargeable batteries which can be used in a variety of products such as electronics, electric motors and electric vehicles, clean energy industry, solar panels, and beyond. As these industries advance and become more prominent in global markets, so does the demand for lithium. Lithium can be found in a number of sources, including in brine, for example, in brine deposits generated as a result of accumulations of saline groundwater enriched in dissolved lithium. However, brine sources of lithium are limited in abundance and can only be found in limited geographical locations, mostly located in South America. Metals released by the siderophores in the shale material can be an additional source of these important metals.

[0022] Provided herein are compositions, methods, and systems that can extract hydrocarbons and metals from shale in an efficient, industrially scalable, inexpensive, and environmentally friendly fashion. For example, in some cases, the methods may avoid reaction conditions requiring harmful substances (e.g., highly acidic solvents), high temperatures and pressures, and the like, which may cause harm to the environment and / or increase the cost, energy demands, and / or environmental footprint of the process. In some cases, this is accomplished by contacting shale with a siderophore under conditions suitable for the siderophore to degrade the shale, e.g., to extract and separate a metal (e.g., metal ion / atom) therefrom. The methods, compositions, and systems provided herein may be industrially scaled and implemented. For example, in some cases, the reaction may notAttorney Docket No. 66122-711.601require temperatures that are significantly higher than room temperature, may not require pressures that are significantly higher than atmospheric pressure, may not require conditions that are highly acidic or highly basic, and may not require other conditions that are environmentally harmful and costly. Instead, in many cases, the reactions of the present disclosure may be efficiently performed in near-ambient temperature, near-atmospheric pressure, and / or near-neutral pH conditions, reducing their cost, energy demand, and environmental footprint. The details of such reaction conditions are further elaborated on herein. In some cases, the compositions, methods, and systems provided herein may be used on surface shale.

[0023] In some cases, the compositions, methods, and systems provided herein may be used to degrade shale in subsurface oil wells. In some cases, the compositions, methods, and systems provided herein may be used to degrade shale in old, underperforming, and / or low-permeability oil wells. In some cases, the compositions, methods, and systems provided herein can increase oil production from low-permeability oil wells without the use of invasive methods such as fracturing. In some cases, the compositions, methods, and systems provided herein involve the use of siderophores that can degrade shale under the conditions of a subsurface oil well (e.g., temperature, pressure, salinity).

[0024] In some cases, the methods involve contacting a shale material with a siderophore under reaction conditions suitable for the siderophore to degrade the shale (or a portion thereof). In some cases, degradation of the shale material may facilitate the extraction of hydrocarbons from the shale material. In some cases, degradation of the shale material may facilitate the extraction of metals from the shale material. The siderophores provided herein can be used to degrade, dissolve, and / or depolymerize shale material, and liberate hydrocarbons and / or metals (e.g., metal ions) therefrom. In some cases, the methods may be performed at near-ambient temperatures without the need for an energy -intensive, high temperature acid separation process. This process can significantly decrease the environmental impact of refining metals deposited in shale. In some cases, the methods may be performed in situ in a subsurface oil well. In such cases, the methods involve the use of siderophores that can withstand the conditions of a subsurface oil well, such as the temperatures, pressures, and salinity encountered therein. Provided herein are siderophores capable for performing such reactions.

[0025] The term “subsurface” refers to geologic strata occurring below the earth's surface.

[0026] As used herein, the term “formation” refers to any definable subsurface region regardless of size. The formation may contain one or more hydrocarbon-containing layers,Attorney Docket No. 66122-711.601one or more non-hydrocarbon containing layers, an overburden, and / or an underburden of any geologic formation. A formation can refer to a single set of related geologic strata of a specific rock type, or to a set of geologic strata of different rock types that contribute to or are encountered in, for example, without limitation, (i) the creation, generation and / or entrapment of hydrocarbons or minerals, and (ii) the execution of processes used to extract hydrocarbons or minerals from the subsurface.

[0027] As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

[0028] The term “sequence identity” as used herein generally refers to an exact nucleotide-to-nucleotide or amino acid-to-amino acid correspondence of two polynucleotides or polypeptide sequences, respectively. Typically, techniques for determining sequence identity include determining the nucleotide sequence of a polynucleotide and / or determining the amino acid sequence encoded thereby, and comparing these sequences to a second nucleotide or amino acid sequence. Two or more sequences (polynucleotide or amino acid) can be compared by determining their percentage (%) of “sequence identity”. The % of sequence identity of two sequences, whether nucleic acid or amino acid sequences, is the number of exact matches between two aligned sequences divided by the length of the longer sequence and multiplied by 100. Percent sequence identity may also be determined, for example, by comparing sequence information using the advanced BLAST computer program, including version 2.2.9, available from the National Institutes of Health. The BLAST program is based on the alignment method of Karlin and Altschul, Proc. Natl. Acad. Sci. USA, 87:2264-2268 (1990) and as discussed in Altschul, et al., J. Mol. Biol., 215:403-410 (1990); Karlin And Altschul, Proc. Natl. Acad. Sci. USA, 90:5873-5877 (1993); and Altschul et al., Nucleic Acids Res., 25:3389-3402 (1997). The program may be used to determine percent sequence identity over the entire length of the proteins being compared. Default parameters are provided to optimize searches with short query sequences in, for example, with the blastp program. The program also allows use of an SEG filter to mask-off segments of the query sequences as determined by the SEG program of Wootton and Federhen, Computers and Chemistry 17:149-163 (1993). Ranges of desired degrees of sequence identity are approximately 50% to 100% and integer values therebetween. In general, this disclosure encompasses sequences with at least 50%, at least 55%, at least 60%, at least 65%, at leastAttorney Docket No. 66122-711.60170%, at least 75%, at least 80%, at least 85%, at least 90%, at least 95%, or at least 98% sequence identity with any sequence provided herein.

[0029] The term “about” or “approximately” generally means within an acceptable error range for the particular value as determined by one of ordinary skill in the art, which will depend in part on how the value is measured or determined, i.e., the limitations of the measurement system. For example, “about” can mean within 1 or more than 1 standard deviation, per the practice in the art. Alternatively, “about” can mean a range of up to 20%, up to 10%, up to 5%, or up to 1% of a given value. Alternatively, particularly with respect to biological systems or processes, the term can mean within an order of magnitude, preferably within 5-fold, and more preferably within 2- fold, of a value. Where particular values are described in the application and claims, unless otherwise stated, the term “about” meaning within an acceptable error range for the particular value should be assumed.

[0030] In an aspect, provided herein is a method of degrading a shale material. In some embodiments, the method comprises directing a siderophore (e.g., in an solution (e.g., an aqueous solution) to a location comprising a shale material and contacting the siderophore with the shale material under reaction conditions suitable for the siderophore to degrade at least a portion of the shale material. In some embodiments, the location comprising the shale material is an oil well. In some embodiments, the location comprising the shale material is an underground reservoir. In some embodiments, the location comprising the shale material is a surface oil well. In some embodiments, the location comprising the shale material is a subsurface oil well. In some cases, the directing comprises injecting the aqueous solution. In some embodiments, the shale material comprises a hydrocarbon. In some embodiments, the shale material comprises a metal. The method may comprise contacting the shale mineral with a siderophore under reaction conditions such that the hydrocarbon and / or metal contained within the shale material is released.

[0031] In an aspect, the method further includes extracting a hydrocarbon(s) and / or metal(s) from the shale material. The method may further comprise collecting the released hydrocarbon(s) and / or metal(s), thereby extracting the hydrocarbon(s) and / or metal(s) from the shale material. In some cases, the shale material comprises or is a rock, an ore, or a clay. In some cases, the clay is a swelling clay. In some cases, the metal is a metal ion or metal atom. FIG. 1 shows an example workflow according to the embodiments of the present disclosure.

[0032] In some embodiments, provided herein is a method of degrading a shale material in a subsurface oil well. In some cases, the method comprises contacting the subsurface oil wellAttorney Docket No. 66122-711.601comprising a shale material with a siderophore. In some cases, the method comprises directing the siderophore to the subsurface oil well comprising the shale material. In some cases, the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a prechelated metal. In some cases, the siderophore further comprises a solution. In some cases, the method involves the use of a siderophore that can degrade shale material under the conditions encountered in a subsurface oil well (e.g., temperature, pressure, salinity). The siderophore used under such conditions generally is a siderophore that is capable of degrading shale material under subsurface oil well conditions. In some cases, the siderophore is thermostabilized to withstand the high temperatures encountered in subsurface oil wells. In some cases, the siderophore is pyoverdine. In some cases, the siderophore (e.g., pyoverdine) is thermostabilized (e.g., for subsurface oil well use) by, e.g., binding it to ferrous iron (Fe(II)) or other 2+ ions. In some cases, the siderophore (e.g., pyoverdine) may be thermostabilized by binding it to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to contacting the siderophore with the shale material. In some cases, the siderophore (e.g., pyoverdine) may be thermostabilized by binding it to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to contacting the siderophore with the shale material. In other cases, the subsurface oil well may be contacted with or coated with Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to adding in non-chelated siderophore (e.g., pyoverdine) into the subsurface oil well (at which point the non-chelated siderophore can bind Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II)). Without wishing to be bound by theory, upon contact of the thermostabilized siderophore (e.g., siderophore bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), or Zn(II)) with mineral -bound Fe(III) (e.g., found in subsurface oil wells), the Fe(III) may replace the metal ion (e.g., Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II)) initially bound to the siderophore (e.g., pyoverdine) and begin destabilizing the crystal structure of the shale material.

[0033] In some cases, the siderophore is stabilized by binding the siderophore with a metal ion (e.g., prior to contacting the siderophore with the shale material) that has lower affinity for the siderophore than a metal ion found in the shale material. For example, the siderophore may be bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any other metal ion that has lower affinity for the siderophore than a metal ion found in the shale material (e.g., Fe(III), Al (III)), which may allow for the preferential exchange with Fe(III), Al(III) or other metal ions found in the shale material, upon contact with the shale material. ThisAttorney Docket No. 66122-711.601controlled chelation process may ensure that the siderophore remains stable during injection but effectively disrupts the shale matrix, facilitating the release of hydrocarbons and metals.

[0034] In some embodiments, provided herein is a method of degrading a shale material in a surface oil well. In some cases, the method comprises contacting the surface oil well comprising a shale material with a siderophore under conditions suitable to degrade the shale material or a portion thereof. In some cases, the method involves a siderophore to the surface oil well comprising the shale material. In some cases, the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal. In some cases, the siderophore further comprises a solution.

[0035] In some cases, the method further comprises, prior to contacting the shale material with the siderophore, treating the shale material with an acid. In some cases, the shale material has been, prior to contacting the shale material with the siderophore, treated with an acid. In some cases, is the shale material has been wasted or pre-treated with an acid. In some cases, the acid comprises hydrochloric acid (HC1), hydrofluoric acid (HF), acetic acid, citric acid, or any combination thereof. In some cases, the acid comprises HC1. In some cases, the acid comprises HF. In some cases, the acid comprises acetic acid. In some cases, the acid comprises citric acid. In some cases, the acid comprises an acid solution comprising a concentration of at least about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, or 20% (w / v) acid. In some cases, the solution comprises about 15% (w / v) acid. In some cases, the shale material is contacted with an about 15% (w / v) solution of hydrochloric acid prior to the contacting with the siderophore under a reaction condition. In some cases, the solution comprises from about 5% to about 25% (w / v) acid. In some cases, the shale material is contacted with an from about 5% to about 25% solution of hydrochloric acid prior to the contacting with the siderophore under a reaction condition.

[0036] In some embodiments, the (e.g., aqueous) solution comprises a surfactant. In some embodiments, the surfactant comprises dodecylbenzene sulfonic acid (DDBSA), a-Olefin sulfonate (AOS), betaine, NHance 52, NHance 1101, NHance 920A, NHance 2101, XPerse®, Super SF 1001, Tween 80, sodium lauryl ether sulfate (SLES), sophorolipid, or any combination thereof. In some embodiments, the surfactant comprises dodecylbenzene sulfonic acid (DDBSA). In some embodiments, the surfactant comprises a-Olefin sulfonate (AOS). In some embodiments, the surfactant comprises betaine. In some embodiments, the surfactant comprises NHance 52. In some embodiments, the surfactant comprises NHanceAttorney Docket No. 66122-711.6011101. In some embodiments, the surfactant comprises NHance 920A. In some embodiments, the surfactant comprises NHance 2101. In some embodiments, the surfactant comprises Super SF 1001. In some embodiments, the surfactant comprises Tween 80. In some embodiments, the surfactant comprises sodium lauryl ether sulfate (SLES). In some embodiments, the surfactant comprises sophorolipid. In some embodiments, the surfactant comprises XPerse®. In some embodiments, the surfactant is at an amount of about 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9%, 1.0%, 1.1%, 1.2%, 1.3%, 1.4%, 1.5%, 1.6%, 1.7%, 1.8%, 1.9%, or 2.0% of the reaction condition.

[0037] In some cases, oxidizing agents may be used to enhance the oxidation of metal ions and subsequent chelation to the siderophore. In some cases, the shale material may be contacted with the siderophore and the oxidizing agent in the same solution. In other cases, the shale material may be contacted with the oxidizing agent first, and then subsequently contacted with the siderophore. Vice versa, the shale material may be contacted with the siderophore first, and then subsequently contacted with the oxidizing agent. Any suitable oxidizing agent may be used. In some cases, the oxidizing agent comprises pyocyanin and oxygen. In some cases, the oxidizing agent comprises sodium hypochlorite. In some cases, the oxidizing agent comprises hydrogen peroxide (H2O2). The oxidizing agent may be used in a range from about 50 ppm to about 1,000 ppm.

[0038] In some cases, treating the shale material with the acid liberates a hydrocarbon from the shale material. In some cases, the hydrocarbon is released into a (e.g., aqueous) solution. In some cases, the hydrocarbon is collected from the (e.g., aqueous) solution. In some cases, the contacting with the acid releases about 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 93%, 95%, 96%, 97%, 98%, 99%, or 99.9% of the hydrocarbon from the shale material. In some cases, the contacting with the acid releases at most about 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 93%, 95%, 96%, 97%, 98%, 99%, or 99.9% of the hydrocarbon from the shale material. In some cases, the contacting with the acid releases at least about 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 93%, 95%, 96%, 97%, 98%, 99%, or 99.9% of the hydrocarbon from the shale material. In some cases, the contacting with a siderophore liberates a volume of a hydrocarbon.

[0039] In some cases, the contacting liberates at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, or at least about 99.5% of the hydrocarbon in the shale material. In some cases, the contacting liberates at most about 80%, at most about 85%, at most about 90%, at most about 91%, at most about 92%, at most aboutAttorney Docket No. 66122-711.60193%, at most about 94%, at most about 95%, at most about 98%, at most about 99%, or at most about 99.5% of the hydrocarbon in the shale material. In some cases, the contacting liberates about 80%, about 85%, about 90%, about 91%, about 92%, about 93%, about 94%, about 95%, about 98%, about 99%, or about 99.5% of the hydrocarbon in the shale material.

[0040] In some cases, an amount of the hydrocarbon released from the shale material is greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, an amount of the hydrocarbon released from the shale material is at least about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, 20%, 21%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 50%, 100%, 150%, 200%, 250%, 300%, 350%, or 400% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, an amount of the hydrocarbon released from the shale material is at most about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, 20%, 21%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 50%, 100%, 150%, 200%, 250%, 300%, 350%, or 400% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, an amount of the hydrocarbon released from the shale material is about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, 20%, 21%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 50%, 100%, 150%, 200%, 250%, 300%, 350%, or 400% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, an amount of the hydrocarbon released from the shale material is from about 1% to about 400% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in an solution at a concentration of about 15% (w / v). In some cases, the acid comprises HC1 in an solution at a concentration from about 5% (w / v) to about 25% (w / v). In some cases, at least a portion of the hydrocarbon is released into the solution. In some cases, the siderophore has a hydrocarbon extraction efficiency rate of at least about 10%, 20%, 30%, 40%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, 99%, or 99.5%. In some cases, the siderophore has a maximum hydrocarbon extraction rate of at least about 10%, 20%, 30%, 40%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, 99%, or 99.5%.

[0041] In some cases, the contacting changes a fluid property of the shale material. In some cases the fluid property comprises intrafacial tension (IFT), density, viscosity, or any combination thereof. In some cases, the fluid property comprises intrafacial tension (IFT). In some cases, the fluid property comprises density. In some cases, the fluid property comprisesAttorney Docket No. 66122-711.601viscosity. In some cases, the siderophore changes the fluid property of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%. In some cases, the siderophore increases the fluid property of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%. In some cases, the siderophore decreases the fluid property of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%.

[0042] In some cases, the IFT is measured by spinning drop tensiometer (SDT), pendant drop method, Wilhelmy plate / Du Nouy ring tensiometry, or a combination of two or more thereof. In some cases, the IFT is measured by spinning drop tensiometer (SDT). In some cases, the IFT is measured by pendant drop method. In some cases, the IFT is measured by Wilhelmy plate / Du Nouy ring tensiometry. In some cases, the siderophore decreases the IFT of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%. In some cases, the siderophore decreases the IFT of the shale material from about 5% to about 60%. In some cases, the siderophore decreases the IFT of the shale material from about 5% to about 55%. In some cases, the siderophore decreases the IFT of the shale material from about 5% to about 50%. In some cases, the siderophore decreases the IFT of the shale material from about 10% to about 60%. In some cases, the siderophore decreases the IFT of the shale material from about 10% to about 55%. In some cases, the siderophore decreases the IFT of the shale material from about 10% to about 50%.

[0043] In some cases, the density is measured by digital densitometers (oscillating U-tube method), gravimetric analysis, or a combination of two or more thereof. In some cases, the density is measured by digital densitometers (oscillating U-tube method). In some cases, the density is measured by gravimetric analysis. In some cases, the siderophore decreases the density of the shale material by about 0.1%, 0.5%, 1%, 1.5%, 2%, 2.5%, 3%, 3.5%, 4%, 4.5%, 5%, 6%, 7%, 8%, 9%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%. In some cases, the siderophore decreases the density of the shale material from about 0.1% to about 10%. In some cases, the siderophore decreases the density of the shale material from about 0.1% to about 7%. In some cases, the siderophore decreases the density of the shale material from about 0.1% to about 5%. In some cases, the siderophore decreases the density of the shale material from about 0.5% to about 10%. In some cases, the siderophore decreases the density of the shale material from about 0.5% to about 7%. In some cases, the siderophore decreases the density of the shale materialAttorney Docket No. 66122-711.601from about 0.5% to about 5%. In some cases, the siderophore decreases the density of the shale material from about 1% to about 10%. In some cases, the siderophore decreases the density of the shale material from about 1% to about 7%. In some cases, the siderophore decreases the density of the shale material from about 1% to about 5%.

[0044] In some embodiments, the viscosity is measured by rotational rheometers (Brookfield, Anton Paar MCR series) and capillary / falling ball viscometers, or a combination of two or more thereof. In some embodiments, the viscosity is measured by rotational rheometers (Brookfield, Anton Paar MCR series). In some embodiments, the viscosity is measured by capillary / falling ball viscometers. In some cases, the siderophore decreases the viscosity of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%. In some cases, the siderophore decreases the viscosity of the shale material from about 5% to about 60%. In some cases, the siderophore decreases the viscosity of the shale material from about 5% to about 55%. In some cases, the siderophore decreases the viscosity of the shale material from about 5% to about 50%. In some cases, the siderophore decreases the viscosity of the shale material from about 5% to about 45%. In some cases, the siderophore decreases the viscosity of the shale material from about 5% to about 40%. In some cases, the siderophore decreases the viscosity of the shale material from about 10% to about 60%. In some cases, the siderophore decreases the viscosity of the shale material from about 10% to about 55%. In some cases, the siderophore decreases the viscosity of the shale material from about 10% to about 50%. In some cases, the siderophore decreases the viscosity of the shale material from about 10% to about 45%. In some cases, the siderophore decreases the viscosity of the shale material from about 10% to about 40%.

[0045] In some cases, the contacting with a siderophore increases permeability, porosity, pore throat size, fluid flow, or any combination thereof of the shale material. In some cases, the contacting with a siderophore increases permeability of the shale material. In some cases, the contacting with a siderophore increases porosity of the shale material. In some cases, the contacting with a siderophore increases pore throat size of the shale material. In some cases, the contacting with a siderophore increases fluid flow of the shale material.

[0046] In some cases, the permeability is measured by steady-state flow (Darcy’s Law) for fluid permeability, pulse decay gas permeametry for ultra-low permeability, mercury intrusion porosimetry (MIP) to assess pore connectivity, NMR / X-ray CT imaging, or any combination of two or more thereof. In some cases, faster pressure decay, higher fluid flow, and increased pore throat diameters indicate improved permeability. In some cases, theAttorney Docket No. 66122-711.601contacting with a siderophore increases permeability of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 95%, 100%, 125%, 150%, 275%, 200%, 250%, 300%, 400%, 500%, 600%, 700%, 800%, 900%, or 1000%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 1% to about 1000%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 1% to about 600%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 1% to about 500%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 1% to about 300%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 1% to about 100%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 10% to about 1000%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 10% to about 600%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 10% to about 500%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 10% to about 300%. In some cases, the contacting with a siderophore increases permeability of the shale material from about 10% to about 100%.

[0047] In some cases, the contacting with a siderophore increases porosity of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 95%, 100%, 125%, 150%, 275%, 200%, 250%, 300%, 400%, 500%, 600%, 700%, 800%, 900%, or 1000%. In some cases, the contacting with a siderophore increases pore throat size of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 95%, 100%, 125%, 150%, 275%, 200%, 250%, 300%, 400%, 500%, 600%, 700%, 800%, 900%, or 1000%. In some cases, the contacting with a siderophore increases fluid flow of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, 95%, 100%, 125%, 150%, 275%, 200%, 250%, 300%, 400500%, 600%, 700%, 800%, 900%, or 1000%.

[0048] In some cases, the contacting with a siderophore decreases water absorption, water content, or any combination thereof of the shale material. In some cases, the contacting with a siderophore decreases water content of the shale material. In some cases, the contacting with a siderophore decreases water absorption of the shale material. In some cases, the contacting with a siderophore decreases water absorption of the shale material by about 5%, 10%, 15%,Attorney Docket No. 66122-711.60120%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%. In some cases, the contacting with a siderophore decreases water content of the shale material by about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%.

[0049] In some cases, the contacting destabilizes the shale material. In some cases, the contacting forms a silica gel. In some cases, the destabilized shale material forms a silica gel.

[0050] In some cases, the siderophore may degrade, digest, and / or disintegrate the shale material. As a result, metals, such as in the form of metal ions, metal atoms, or metal precipitates, may be released from the shale mineral material (e.g., into a solution). In some cases, the method may comprise collecting the metal or the solution containing the metal. In some cases, the method may comprise separating the metal from the solution. In some cases, the metal may be water soluble. Alternatively or in addition, the metal may precipitate in the solution. The solution may be an aqueous solution comprising water and / or a buffer described anywhere herein.

[0051] In some cases, the methods of the present disclosure are performed on a shale material. The method may be according to the embodiments described anywhere herein. According to the embodiments described anywhere in the present disclosure, in some cases, the siderophore acts on the shale material. In some embodiments, the shale material comprises one or more metals. In some embodiments, the shale material comprises a metal. The siderophore and the method of the present disclosure may degrade, digest, or disintegrate the shale material and extract a hydrocarbon and / or metal therefrom. The shale may be a source of valuable metals such as lithium, aluminum, iron, nickel, cobalt, copper, manganese, magnesium, zinc, rare earth elements, uranium, and other metals with vast industrial use and applications. The methods and siderophores of the present disclosure facilitate access to such sources. In some embodiments, the shale material is selected from the group consisting of: clay, carbonaceous shale, black shale, kaolinite, montmorillonite, illite, feldspar, and quartz. In embodiments, the shale material has low-permeability. In some cases, the clay is a swelling clay.

[0052] In some embodiments, the contacting comprising extracting one or more metals from the shale material. In some embodiments, the contacting comprising recovering one or more metals from the shale material. In some embodiments, the contacting comprising separating one or more metals from the shale material. In some embodiments, the contacting comprising liberating one or more metals from the shale material. In some embodiments, at least a portion of the one or more metals are released into the solution. In some embodiments, theAttorney Docket No. 66122-711.601shale material is contacted with the siderophore which facilitates extraction by acidolysis. In some embodiments, the shale material is contacted with the siderophore which facilitates extraction by compl exolysis. In some embodiments, the shale material is contacted with the siderophore which facilitates extraction by redoxolysis.

[0053] In some cases, the method further comprises purifying a metal from the shale material. In some cases, the purified metal has a purity of at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 95%, at least about 99%, at least about 99.9%, at least about 99.99%, at least about 99.999%, at least about 99.9999%, or higher purity.

[0054] In some cases, the contacting comprising purifying one or more metals from the shale material. In some cases, at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, or at least about 99.5% of the one or more metals in the shale material are liberated.

[0055] In some cases, an amount of the one or more metals released from the shale material is at least 1% greater than an amount of one or more metals released from the shale material upon treatment with an acid. In some cases, an amount of the one or more metals released from the shale material is from about 1% to about 400% greater than an amount of one or more metals released from the shale material upon treatment with an acid. In some cases, the acid comprises HC1 in an solution at a concentration of about 15% (w / v). In some cases, the acid comprises HC1 in an solution at a concentration from about 5% (w / v) to about 25% (w / v).

[0056] In some cases, the purified metal is aluminum, phosphorous, silicone, sulfur, potassium, calcium, manganese, nickel, copper, zinc, arsenic, selenium, strontium, rubidium, chromium, zirconium, niobium, molybdenum, barium, tin, lead, antimony, tantalum, tungsten, mercury, bismuth, thorium, titanium, cobalt, vanadium, yttrium, uranium, and / or a rare earth metal. In some cases, the purified metal is industry-grade, battery-grade, and / or pharmaceutical grade.

[0057] In some cases the hydrocarbon and the metal is extracted from the shale material. In some cases, a metal is extracted. In some cases, the metal is aluminum, phosphorous, silicone, sulfur, potassium, calcium, manganese, nickel, copper, zinc, arsenic, selenium, strontium, rubidium, chromium, zirconium, niobium, molybdenum, barium, tin, lead, antimony, tantalum, tungsten, mercury, bismuth, thorium, titanium, cobalt, vanadium, yttrium, uranium, and / or a rare earth element. In some cases, the metal is silicone. In someAttorney Docket No. 66122-711.601cases, the metal is aluminum. In some cases, the metal is vanadium. In some cases, the metal is chromium. As a result of degradation and / or disintegration of the shale material, the metal may be released and extracted from the shale material, in some cases, in a solution, in some cases in the form of a metal ion or a metal atom. The solution may be an aqueous solution.

[0058] In some embodiments, the siderophore has a metal extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5% or higher. In some embodiments, the siderophore has a maximum metal extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5% or higher.

[0059] In some embodiments, the solution comprises a salt. In some embodiments, the salt is a buffer. In some embodiments, the salt comprises citrate, oxalate, phosphate-buffered saline (PBS), bicarbonate, or any combination thereof. In some embodiments, the salt comprises citrate. In some embodiments, the salt comprises oxalate. In some embodiments, the salt comprises phosphate-buffered saline (PBS). In some embodiments, the salt is at a concentration in a range from about 0.01 M to 1.0 M. In some embodiments, the salt comprises bicarbonate. In some embodiments, the salt is at a concentration of about 0.01, 0.05, 0.1, 0.15, 0.2, 0.3, 0.4, 0.5, or 1.0 M. In some embodiments, the salt is at a concentration of about 0.01 M. In some embodiments, the salt is at a concentration of about 0.05 M. In some embodiments, the salt is at a concentration of about 0.1 M. In some embodiments, the salt is at a concentration of about 0.2 M. In some embodiments, the salt is at a concentration of about 0.3 M. In some embodiments, the salt is at a concentration of about 0.4 M. In some embodiments, the salt is at a concentration of about 0.5 M. In some embodiments, the salt is at a concentration of about 1.0 M.

[0060] In some cases, the solution comprises a pH from about, 2 to 3, 2 to 4, 2 to 5, 2 to 6, 2 to 7, 2 to 8, 2 to 9, 2 to 10, 2 to 11, 2 to 12, 3 to 4, 3 to 5, 3 to 6, 3 to 7, 3 to 8, 3 to 9, 3 to 10, 3 to 11, 3 to 12, 4 to 5, 4 to 6, 4 to 7, 4 to 8, 4 to 9, 4 to 10, 4 to 10, 4 to 11, 4 to 12, 5 to 6, 5 to 7, 5 to 8, 5 to 9, 5 to 10, 5 to 11, 5 to 12, 6 to 7, 6 to 8, 6 to 9, 6 to 10, 6 to 11, 6 to 12, 7 to 8, 7 to 9, 7 to 10, 7 to 11, 7 to 12, 8 to 9, 8 to 10, 8 to 11, 8 to 12, or 9 to 10. In some cases, the solution comprises a pH from about 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12. In some cases, the solution comprises a pH from about at least 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12. In some cases, the solution comprises a pH of about at most 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12. In some cases, the solution comprises a pH of about 2. In some cases, the reaction conditions comprise a pHAttorney Docket No. 66122-711.601of about 3. In some cases, the solution comprises a pH from about 4. In some cases, the solution comprises a pH of about 5. In some cases, the solution comprises a pH of about 6. In some cases, the solution comprises a pH of about 7. In some cases, the solution comprises a pH of about 8. In some cases, the solution comprises a pH of about 9. In some cases, the solution comprises a pH from of 10. In some cases, the solution comprises a pH of about 11. In some cases, the solution comprises a pH of about 12. In some cases, the methods of the present disclosure are performed in pH ranges that are substantially neutral, or in other words, not highly / strongly acidic or highly / strongly basic. In some cases, the method of the present disclosure does not comprise a strong acid, such as is used in acid leaching. In some cases, the method of the present disclosure comprises a weak acid. In some cases, the method of the present disclosure comprises a weak organic acid. In some embodiments, the weak acid comprises acetic acid, ascorbic acid, benzoic acid, butyric acid, citric acid, fumaric acid, formic acid, glycolic acid, hydrofluoric acid, lactic acid, malic acid, nitrous acid, oxalic acid, phosphoric acid, propionic acid, pyruvic acid, succinic acid, sulphurous acid, tartaric acid, or any combination thereof.

[0061] In some cases, the contacting occurs at a temperature (e.g., a temperature under which the extraction, or a portion thereof, is performed). In some cases, the temperature is from about -10 to about 150 degrees Celsius (°C). In some cases, the temperature is from about -10 to about 125 °C. In some cases, the temperature is from about -10 to about 100 °C. In some cases, the temperature is about -10 to about 90 °C. In some cases, the temperature is from about -10 to about 80 °C. In some cases, the temperature is from about -10 to about 70 °C. In some cases, the temperature is from about -10 to about 60 °C. In some cases, the temperature is from about -10 to about 50 °C. In some cases, the temperature is from about -10 to about 35 °C. In some cases, the temperature is from about -10 to about 30 °C. In some cases, the temperature is from about 0 to about 110 °C. In some cases, the temperature is from about 0 to about 100 °C. In some cases, the temperature is from about 0 to about 90 °C. In some cases, the temperature is from about 0 to about 80 °C. In some cases, the temperature is from about 0 to about 70 °C. In some cases, the temperature is from about 0 to about 60 °C. In some cases, the temperature is from about 0 to about 50 °C. In some cases, the temperature is from about 0 to about 35 °C. In some cases, the temperature is from about 0 to about 30 °C. In some cases, the temperature is from about 10 to about 120 °C. In some cases, the temperature is from about 10 to about 100 °C. In some cases, the temperature is from about 10 to about 90 °C. In some cases, the temperature is from about 10 to about 80 °C. In some cases, the temperature is from about 10 to about 70 °C. In some cases, the temperature isAttorney Docket No. 66122-711.601from about 10 to about 60 °C. In some cases, the temperature is from about 10 to about 50 °C. In some cases, the temperature is from about 10 to about 35 °C. In some cases, the temperature is from about 10 to about 30 °C. In some cases, the temperature is from about 20 to about 80 °C. In some cases, the temperature is from about 20 to about 70 °C. In some cases, the temperature is from about 20 to about 60 °C. In some cases, the temperature is from about 20 to about 50 °C. In some cases, the temperature is from about 20 to about 35 °C. In some cases, the temperature is from about 20 to about 30 °C. In some cases, the temperature is from about 30 to about 80 °C. In some cases, the temperature is from about 30 to about 70 °C. In some cases, the temperature is from about 30 to about 60 °C. In some cases, the temperature is from about 30 to about 50 °C. In some cases, the temperature is from about 30 to about 40 °C. In some cases, the temperature is from about 30 to about 35 °C. In some cases, the temperature is from about 45 to about 50 °C. In some cases, the temperature is from about 20 to about 250 °F. In some cases, the methods of the present disclosure may be performed in near-ambient temperatures and / or pressures In some cases, the temperature ranges of the methods of the present disclosure may be significantly lower than temperatures required in acid roasting, (e.g., 200 °C and above). This may reduce the energy requirements of the process performed using the methods of the present disclosure. In some cases, the temperature is about 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48, 49, 50, 51, 52, 53, 54, 55, 56, 57, 58, 59, or 60 °C. In some cases, the temperature is about 15 °C. In some cases, the temperature is about 20 °C. In some cases, the temperature is about 25 °C. In some cases, the temperature is about 125 °C. In some cases, the temperature is about 150 °C.

[0062] In some embodiments, the solution comprises a salinity. In some embodiments, the salinity is about 200,000, 225,000, 250,000, 275,000, 300,000, 325,000, or 350,000 ppm. In some embodiments, the salinity is about 200,000 ppm. In some embodiments, the salinity is about 225,000 ppm. In some embodiments, the salinity is about 250,000 ppm. In some embodiments, the salinity is about 275,000 ppm. In some embodiments, the salinity is about 300,000 ppm. In some embodiments, the salinity is about 325,000 ppm. In some embodiments, the salinity is about 350,000 ppm. In some embodiments, the salinity is about 250,000 to about 300,000 ppm.

[0063] In some embodiments, the contacting occurs at a pressure. In some embodiments, the pressure is about 100, 300, 500, 1,000, 15,00, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, 5,500, 6,000, 6,500, 7,000, 7,500, or 8,000 psi. In some embodiments, the pressure is at mostAttorney Docket No. 66122-711.601about 100, 300, 500, 1,000, 15,00, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, 5,500, 6,000, 6,500, 7,000, 7,500, or 8,000 psi. In some embodiments, the pressure is at least about 100, 300, 500, 1,000, 15,00, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, 5,500, 6,000, 6,500, 7,000, 7,500, or 8,000 psi. In some embodiments, the pressure is about 100 psi. In some embodiments, the pressure is about 300 psi. In some embodiments, the pressure is about 100 psi. In some embodiments, the pressure is about 500 psi. In some embodiments, the pressure is about 1,000 psi. In some embodiments, the pressure is about 2,000 psi. In some embodiments, the pressure is about 3,000 psi. In some embodiments, the pressure is about 4,000 psi. In some embodiments, the pressure is about 5,000 psi. In some embodiments, the pressure is about 6,000 psi. In some embodiments, the pressure is about 7,000 psi. In some embodiments, the pressure is about 8,000 psi. In some embodiments, the pressure is at most about 1,000 psi. In some embodiments, the pressure is at most about 2,000 psi. In some embodiments, the pressure is at most about 3,000 psi. In some embodiments, the pressure is at most about 4,000 psi. In some embodiments, the pressure is at most about 5,000 psi. In some embodiments, the pressure is at most about 6,000 psi. In some embodiments, the pressure is at most about 7,000 psi. In some embodiments, the pressure is at most about 8,000 psi. In some embodiments, the pressure is about surface pressure. In some embodiments, the pressure is about 15 psi. In some embodiments, the pressure is about 100 psi. In some embodiments, the pressure is at least about 100 psi.

[0064] In some embodiments, the methods of the present disclosure are performed with agitation. In some embodiments, the methods of the present disclosure are performed without agitation.In some embodiments, contacting occurs for a period of time. In some embodiments, the period of time is about 1, 2, 3, 4, 5, 6, 7, 8, 12, 16, 20, 24, 28, 32, 36, 40, 44, 48, 52, 56, 60, 64, 68, or 72 hours. In some embodiments, contacting the shale material with a siderophore under reaction conditions is for about at least 1, 2, 3, 4, 5, 6, 7, 8, 12, 16, 20, 24, 28, 32, 36, 40, 44, 48, 52, 56, 60, 64, 68, or 72 hours. In some embodiments, the period of time is about at most 1, 2, 3, 4, 5, 6, 7, 8, 12, 16, 20, 24, 28, 32, 36, 40, 44, 48, 52, 56, 60, 64, 68, or 72 hours. In some embodiments, the period of time is about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, or 25 days. In some embodiments, the period of time is about at least 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, or 25 days. In some embodiments, the period of time is about at most about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, or 25 days. In some embodiments, the period of time is about 8 hours. In some embodiments, the period of time isAttorney Docket No. 66122-711.601about 12 hours. In some embodiments, the period of time is about 16 hours. In some embodiments, the period of time is about 20 hours. In some embodiments, the period of time is about 24 hours. In some embodiments, the period of time is about 28 hours. In some embodiments, the period of time is about 32 hours. In some embodiments, the period of time is about 36 hours. In some embodiments, the period of time is about 40 hours. In some embodiments, the period of time is about 44 hours. In some embodiments, the period of time is about 48 hours. In some embodiments, the period of time is about 52 hours. In some embodiments, the period of time is about 56 hours. In some embodiments, the period of time is about 60 hours. In some embodiments, the period of time is about 64 hours. In some embodiments, the period of time is about 68 hours. In some embodiments, the period of time is about 72 hours. In some embodiments, the period of time is about 1 day. In some embodiments, the period of time is about 2 days. In some embodiments, the period of time is about 3 days. In some embodiments, the period of time is about 4 days. In some embodiments, the period of time is about 5 days. In some embodiments, the period of time is about 6 days. In some embodiments, the period of time is about 7 days. In some embodiments, the period of time is about 8 days. In some embodiments, the period of time is about 9 days. In some embodiments, the period of time is about 10 days. In some embodiments, the period of time is about 11 days. In some embodiments, the period of time is about 12 days. In some embodiments, the period of time is about 13 days. In some embodiments, the period of time is about 14 days. In some embodiments, the period of time is about 15 days. In some embodiments, the period of time is about 16 days. In some embodiments, the period of time is about 17 days. In some embodiments, the period of time is about 18 days. In some embodiments, the period of time is about 19 days. In some embodiments, the period of time is about 20 days. In some embodiments, the period of time is about 21 days. In some embodiments, the period of time is about 22 days. In some embodiments, the period of time is about 23 days. In some embodiments, the period of time is about 24 days. In some embodiments, the period of time is about 25 days. In some embodiments, the period of time is at most about 1 day. In some embodiments, the period of time is at most about 2 days. In some embodiments, the period of time is at most about 3 days. In some embodiments, the period of time is at most about 4 days. In some embodiments, the period of time is at most about 5 days. In some embodiments, the period of time is at most about 6 days. In some embodiments, the period of time is at most about 7 days. In some embodiments, the period of time is at most about 8 days. In some embodiments, the period of time is at most about 9 days. In some embodiments, the period ofAttorney Docket No. 66122-711.601time is at most about 10 days. In some embodiments, the period of time is at most about 11 days. In some embodiments, the period of time is at most about 12 days. In some embodiments, the period of time is at most about 13 days. In some embodiments, the period of time is at most about 14 days. In some embodiments, the period of time is at most about 15 days. In some embodiments, the period of time is at most about 16 days. In some embodiments, the period of time is at most about 17 days. In some embodiments, the period of time is at most about 18 days. In some embodiments, the period of time is at most about 19 days. In some embodiments, the period of time is at most about 20 days. In some embodiments, the period of time is at most about 21 days. In some embodiments, the period of time is at most about 22 days. In some embodiments, the period of time is at most about 23 days. In some embodiments, the period of time is at most about 24 days. In some embodiments, the period of time is at most about 25 days. In some embodiments, the period of time is from about 1 hour to about 25 days. In some embodiments, the period of time is from about 1 hour to about 10 days. In some embodiments, the period of time is from about 1 hour to about 7 days. In some embodiments, the period of time is from about 1 hour to about 1 day. In some embodiments, the period of time is from about 12 hours to about 25 days. In some embodiments, the period of time is from about 12 hours to about 10 days. In some embodiments, the period of time is from about 12 hours to about 7 days. In some embodiments, the period of time is from about 12 hours to about 1 day. In some embodiments, the period of time is from about 1 day to about 25 days. In some embodiments, the period of time is from about 1 day to about 10 days. In some embodiments, the period of time is from about 1 day to about 7 days. In some embodiments, the period of time is from about 1 hour to about 2 days.

[0065] In some cases, the siderophore comprises activity such as the capability to digest or degrade a shale mineral. In some cases, the shale mineral material (e.g., rock / ore / clay) comprises a clay, carbonaceous shale, black shale, kaolinite, montmorillonite, illite, feldspar, quartz, or any combination thereof. In some cases, the clay is a swelling clay.

[0066] In some cases, the siderophore is derived from an organism selected from the group comprising: Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cenocepacia, Burkholderia cepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotoformans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, PseudomonasAttorney Docket No. 66122-711.601aeruginosa, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus,Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof.

[0067] In some cases, the siderophore is selected from the group comprising: aerobactin, agrobactin, aminochelin, azotobactin, azotochelin, bacillibactin, deferoxamine B, deferoxamine E, desferrioxamine B, desferrioxamine E, enterobactin, ferrichrome, fusarinine C, micacocidin, mycobactin, ornibactin, protochelin, pseudobactin, pyochelin, pyoverdine, pyoverdine or a derivative of pyoverdine, PyoPpC-3B, pyridine-2,6-dithiocarboxylate, rhizobactin 1021, rhodotorulic acid, salmochelin, schizokinen, vibrioferrin, vibriobactin, vicibactin, yersiniabactin, and any combination thereof. In some embodiments, the siderophore comprises pyoverdine. In some embodiments, the siderophore comprises pyoverdine or a derivative of pyoverdine. In some embodiments, the siderophore comprises PyoPpC-3B. In some embodiments, the siderophore comprises pyochelin. In some embodiments, the siderophore comprises ornibactin. In some embodiments, the siderophore is purified from an organism prior to the contacting.

[0068] In some aspects, the siderophore produced prior to the directing in a host cell or in a cell-free production system. In some cases, the host cell is a bacterial cell or yeast cell. In some embodiments, the bacterial cell comprises a Pseudomonas bacteria. In some embodiments, the bacterial cell comprises a Burkholderia bacteria. In some cases, the bacterial cell comprises Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotoformans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas aeruginosa, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, or Yersinia pestis. In some embodiments, the bacterial cell comprises Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas aeruginosa, or Pseudomonas azotoformans. In some embodiments, the bacterial cell comprises Burkholderia cenocepacia or Burkholderia cepacia.Attorney Docket No. 66122-711.601

[0069] In some embodiments, the siderophore is purified from an organism prior to the directing. In some embodiments, the siderophore is derived from an organism. In some embodiments, the siderophore is purified from an organism. In some embodiments, the organism comprises Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotoformans, Pseudomonas BIO, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas aeruginosa, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, or Yersinia pestis. In some embodiments, the organism is Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas aeruginosa, or Pseudomonas azotoformans. In some embodiments, the organism is Burkholderia cenocepacia or Burkholderia cepacia. In some embodiments, the siderophore is purified from the host cell or in the cell-free production system prior to the contacting.

[0070] In some cases, the siderophore may extract a hydrocarbon from the shale material. As a result, hydrocarbons, may be released from the shale mineral material (e.g., into a solution). In some cases, the method may comprise collecting the hydrocarbon or the solution containing the hydrocarbon. In some cases, the method may comprise separating the hydrocarbon from the solution. In some cases, the hydrocarbon may be water soluble. The solution may be an aqueous solution comprising water and / or a buffer described anywhere herein.

[0071] In some aspects, provided herein is a reaction mixture comprising a siderophore, a shale material, and a solution, as described throughout the disclosure. In some embodiments, the siderophore comprises a siderophore disclosed herein. In some embodiments, the shale material comprises a shale material disclosed herein. In some embodiments, the solution comprises an aqueous solution. In some embodiments, the siderophore, the shale material, and the solution are contacted at a location. In some embodiments, the location comprises a location disclosed herein. In some embodiments, prior to the contacting, the shale material is treated with an acid. In some embodiments, the acid comprises an acid disclosed herein. In some embodiments, the shale material comprises a hydrocarbon. In some embodiments, the shale material comprises a metal. In some embodiments, the contacting liberates at least a portion of the hydrocarbon and / or metal from the shale material.Attorney Docket No. 66122-711.601

[0072] In some embodiments, the solution is inside any suitable container. In some cases, the shale material comprises a rock or ore. In some cases, the shale material may be placed inside a container and added to a solution comprising the siderophore, water, a buffer, and / or potential other reagents for performing a contacting. In some cases, the contacting may be performed in one or more of a container, a dish, a beaker, a device, a tank, a reactor, and / or any combination thereof. The containers (e.g., one or more reactors and / or tanks) may be connected to one another to perform one or more reactions according to the embodiments of the present disclosure. The containers may also be reaction units and / or process units each of which may serve a function as part of the method and / or in combination with the method. For example, one or more tanks, reactors, and / or processing units, may be connected to each other with any configuration, such as in series, in parallel, or any combination thereof to perform the method steps such as delivering and / or contacting the siderophore with the shale material, extracting the hydrocarbon and / or metal, separating the hydrocarbon and / or metal from the solution, purifying the hydrocarbon and / or metal, processing the hydrocarbon and / or metal, and / or converting the metal into an industry-grade, battery -grade, or pharmaceuticalgrade metal. In some cases, the method further comprises grinding the shale material (e.g., rock / ore) prior to performing the reaction (e.g., the degradation). In some cases, the method further comprises using a filtration / chelating system, a precipitation system, a recycle system, or any combination thereof.

[0073] Further provided herein are methods for mitigating excessive swelling and preserving structural integrity of a swelling clay, the method comprising contacting the swelling clay with a siderophore. In some cases, the siderophore is pyoverdine. In some cases, the method further comprises contacting the reactive clay mineral with potassium chloride. In some cases, the swelling clay comprises smectite or montmorillonite.

[0074] Further provided herein are compositions comprising a siderophore and potassium chloride. In some cases, the siderophore is pyoverdine. In some cases, the potassium chloride is an amount of about 3.5%. In some cases, the composition is a solution.

[0075] In some aspects, provided herein is a kit comprising a siderophore, a shale material, and a reaction condition, as described throughout the disclosure. Kit may include a siderophore such as pyoverdine described herein. In some cases, the siderophore may be purified and dried to a powder. In some cases, reaction condition comprises components described herein. In some cases, the reaction condition is dried to a powder.Attorney Docket No. 66122-711.601EXAMPLESExample 1: Extraction of shale material with py overdine

[0076] Oil-bearing shale material was extracted from an old oil well. 1 gram samples were pretreated with 15 % HC1 until the mixture stopped effervescing, taken as a sign of maximal dissolution of carbonates. HC1 treatment is a standard treatment of shale to extract hydrocarbons. After HC1 treatment, 10 mL of the working solution was added to each sample, 10% (w / v). Py overdine was produced and isolated to 99+% purity and dried for preservation. A total of 15 samples were tested under conditions shown in Table 1.Pyoverdine was used at a concentration of 60 pM. All experiments were run at 32°C and 250 rpm for 36 hours. After completion of the experiments, the tubes were allowed to gravity settle and the liquid fraction was decanted from the solid fraction. The liquid fraction was passed through a 22-micron filter to remove particulates that could affect the readings and separated for analysis. The solid samples were put to dry under moderate vacuum at 70°C. Both the fractions, the liquid fraction containing extracted metals and hydrocarbons and the solid fraction containing the remaining shale material of metals and hydrocarbons, were analyzed as described below.Table 1.Attorney Docket No. 66122-711.601

[0077] Samples were prepared as described above and analyzed using Fourier-transform infrared spectroscopy (FTIR). FTIR detected types and quantities of hydrocarbons from the samples via absorption of infrared light. The FTIR was run with a KBr detector with a diamond crystal and a total of 16 sample scans. FTIR scan of hydrocarbons showed IR absorption peaks between 2800 and 3300 cm’1due to C-H stretching vibrations. A CO2 peak at 2350 cm’1was identified and was possibly due to desorption of CO2 from the solid into the liquid and the decomposition of other functional groups inside the samples. IR absorption peaks at lower wavenumbers (1000-1500 cm’1) were due to C-H bending and C-0 stretching vibrations. A water peak usually centered at 3000 cm’1was due to O-H stretching (water). A more detailed description of the bonds and compounds found at different wavenumbers are shown in Table 2. The results demonstrated the extraction of hydrocarbons under the various conditions.Table 2.

[0078] FIGs. 2A-2B shows a FTIR scan of the liquid sample. The FTIR scan showed hydrocarbons were released during the treatment with Conditions 1, 4, 5, 7, 11, and 15 (FIG.2A). The top five samples were plotted with the water control sample to highlight the differences relevant to hydrocarbon release on the regions mentioned. The area under the curve was quantified to determine the total amount of hydrocarbons released from the solidAttorney Docket No. 66122-711.601sample into the liquid fraction as compared to a negative control. The higher the absorbance, the higher total amount of hydrocarbons, indicating more efficient release under that condition. The results showed Condition 3 had the highest amount of additional hydrocarbon liberation into the liquid fraction as compared to the other conditions.

[0079] The FTIR scan showed hydrocarbons were released during the treatment with Conditions 1, 2, and 3 (FIG. 2B) The negative control water (Condition 1), py overdine + water (Condition 2), and pyoverdine + water + buffer (Condition 3) were plotted together to highlight the difference between the use of the buffer and water. The higher the absorbance, the higher total amount of hydrocarbons, indicating more efficient release under that condition. The results showed Condition 3 had the highest amount of additional hydrocarbon liberation into the liquid fraction as compared to the other conditions.

[0080] The area under the curve was quantified to determine the total amount of hydrocarbons released from the solid sample into the liquid fraction as compared to the negative control (Condition 1). The calculated area and percentage of hydrocarbons released after treatment with Conditions 1-15 is shown in Table 3. The results showed that the reaction conditions of Condition 3 resulted in the highest percentage release of hydrocarbons from the shale material.Table 3.Attorney Docket No. 66122-711.601

[0081] FIGs. 3A-3B shows a FTIR scan of the hydrocarbons remaining in the shale samples after treatment with the various conditions. In these figures, a higher amount of hydrocarbons seen in FTIR scans demonstrate that there were additional hydrocarbons that could have been liberated, but had not been by the treatments. Therefore, the lower the absorbance, the lower total amount of hydrocarbons remaining in the shale sample, indicating more efficient release under that condition.

[0082] FIG. 3A shows a FTIR scan of the hydrocarbons in the solid shale under Conditions 3-15. FIG. 3B shows a relevant area for hydrocarbon is shown zoomed in for clarity of the differences. This figure demonstrated the differences in extraction of hydrocarbons between the various conditions tested by indicating which samples had remaining hydrocarbons within the shale. The lower the absorbance, the lower total amount of remaining hydrocarbons, indicating more efficient release under that condition. The amount of hydrocarbon detected on the solid sample was Condition 3 (pyoverdine in salt buffer without the addition of any surfactant) was the lowest in the study, indicating that Condition 3 had extracted the most amount hydrocarbons. These results are consistent to those seen in the liquid fraction described above.

[0083] The best condition from FIG. 3A, Condition 3, was also graphed against Condition 7 and Condition 15, the next best conditions from FIG. 4A to further highlight the comparison of extraction efficiencies between conditions. FIG. 4B shows a relevant area for hydrocarbon is shown zoomed in for clarity of the differences. The lower the absorbance, the lower total amount of remaining hydrocarbons, indicating more efficient release under that condition. Condition 7 and condition 15 were the surfactant samples (Conditions 4-15) and had a significantly lower amount of hydrocarbon measured via FTIR in the solid samples than all the other surfactant samples tested. However, Condition 3 still had the lowest measured hydrocarbons in the FTIR scan even compared to the best conditions with added surfactants, Conditions 7 and Condition 15.

[0084] FIG. 5A shows the FTIR scan showed hydrocarbons remaining in the solid sample after treatment with Conditions 1, 2, and 3. FIG. 5B shows a relevant area for hydrocarbon is shown zoomed in for clarity of the differences. The negative control water (Condition 1),Atorney Docket No. 66122-711.601pyoverdine + water (Condition 2), and pyoverdine + water + buffer (Condition 3) were plotted together to highlight the difference between the use of the buffer and water. The lower the absorbance, the lower total amount of remaining hydrocarbons, indicating more efficient release under that condition. The results showed Condition 3 had the lowest amount of hydrocarbon remaining in the solid sample as compared to the other conditions. These results are consistent with the liquid sample results described above in which higher amounts of hydrocarbons extracted in Condition 3 than Condition 2 or Condition 1.

[0085] In addition, metals were extracted and collected in the liquid solution using the above described protocol. Metals such, as aluminum, present in the shale material were released when contacted with the siderophore under the various reaction conditions. Liquid samples of produced water obtained from the tests were stored as received at room temperature. Solid fractions of the samples were separated by centrifugation and due to the oil contained in some of them, the samples were filtered using a 0.45 pm PTFE filter. A 1 ml sample was taken from the liquid that was previously filtered. Each 1 mL sample was then diluted with 9 mL of 2% nitric acid solution to be analyzed on the iCAP PRO XP Duo ICP-OES, with 10 ppm Yttrium as the internal standard. Lithium concentrations were measured at 610.362 nm and 670.784 nm, silicon was measured at 221.667 nm and 251.611 nm, uranium concentrations were measured at 367.007 nm and 409.014nm, while thorium was measured at 318.09 nm and 283.23 nm and yttrium was measured at 360.073 nm and 224.306 nm. Each sample was measured three times, and the reported values represent the average of these three independent measurements.

[0086] The results of the experiments are reported below. The results for Conditions 1-15 for various metals are shown in Tables 4, 5, 6, and 7. The calibrated data was calculated using the calibration curve determined by the individual standards solution and the semiquant data was measured automatically by the software using the semiquant feature.Table 4.Atorney Docket No. 66122-711.601Table 5.Atorney Docket No. 66122-711.601Table 6.Attorney Docket No. 66122-711.601Table 7.

[0087] The results shown in Tables 4, 5, 6, and 7 demonstrate the capability of the siderophore to extract metals from the shale material.Attorney Docket No. 66122-711.601Example 2: Siderophores for Enhanced Permeability and Metal Recovery in Surface Oil Wells

[0088] A siderophore was tested on a surface oil well to measure the amount of hydrocarbon liberation compared to other treatment methods.

[0089] Shale cuttings from a shale deposit were tested at a saltwater disposal site. The shale was tested comparing four different groups. Group 1: pyoverdine; Group 2: Solugen Verza360™ XT (a chemical approach leveraging bioengineered and synthetic components for oil field applications); Group 3: Locus SW101 (a biosurfactant-based technology targeting enhanced hydrocarbon release); and Group 4: saltwater standard. Group 2 and 3 serve as a comparison of commonly used technologies to Group 1. Group 5 serves as a control standard to establish baseline hydrocarbon concentrations in the liquid fraction.

[0090] Each Group was tested under surface conditions, average surface temperature and average surface pressure, with the shale cuttings. The components of each Group were added to the shale in aqueous conditions for a period of time. After incubation, the liquid fraction was collected. The liquid fraction samples were subjected to a FTIR spectroscopy scan, as described in Example 1. FTIR spectroscopy was used to detect and quantify hydrocarbon presence in the liquid fraction. Specific nanometer ranges provided insight into the types of hydrocarbons liberated: 0-1790 nm: Near-Infrared (NIR) region associated with overtones of C-H stretching, indicative of alkanes and aromatic hydrocarbons; 2300-2400 nm: Shortwave Infrared (SWIR) region linked to C-H stretching and bending combinations, often corresponding to methane and heavier alkanes; and 2750-3780 nm: Mid-Infrared (MIR) region identifying fundamental C-H stretching vibrations in all hydrocarbons, including aromatics, alkanes, and potential oxidation products. The resulting scan was shown in FIG. 6.

[0091] As shown in FIG. 6 and Table 8, the Group 1 pyoverdine delivered the highest increase in hydrocarbon concentration across all tests, making it the most effective technology. Group 2 and 3 also showed an increased in hydrocarbon liberation, as compared to Group 4, but did not increase as much as Group 1 showed. Group 1 released the most hydrocarbons across all spectral ranges, especially in the mid-infrared region, showing it worked well with a variety of hydrocarbon types. Group 2 and 3 showed moderate improvements but targeted specific types of hydrocarbons more effectively. The results showed a more than 4 times increase in hydrocarbons released in Group 1 compared to Group 4 control.Attorney Docket No. 66122-711.601Table 8.Example 3: Siderophores for Enhanced Permeability and Metal Recovery in Subsurface Old Oil Wells

[0092] Siderophores, such as pyoverdine, can be used to increase permeability in aging, low-permeability subsurface oil wells. Subsurface oil wells require additional consideration than surface oil wells. Subsurface oil wells comprise conditions of high temperatures, high pressures, and salinity. Methods to increase hydrocarbon liberation should be able to withstand extreme conditions.

[0093] Pyoverdine binds Fe(III) with high affinity, stripping it from mineral lattices. In iron-bearing clays and shale materials, such as montmorillonite or illite, the removal of Fe(III) weakens the crystal lattice, causing structural destabilization. Pyoverdine can be primed with Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof to stabilize the pyoverdine structure. Pyoverdine can be primed with Fe(II) to stabilize the pyoverdine structure. Pyoverdine primed with Fe(II) in the presence of Fe(III) will swap out the Fe(II) in favor of the Fe(III). In this way, a stabilized version of pyoverdine prepared with Fe(II) can be delivered to subsurface oil wells and be stable under said extreme conditions. In some cases, pyoverdine can be primed with Cr(III) to stabilize the pyoverdine structure. In some cases, pyoverdine can be primed with Ti(IV) to stabilize the pyoverdine structure. In some cases, pyoverdine can be primed with Cu(II) to stabilize the pyoverdine structure. In some cases, pyoverdine can be primed with Ni(II) to stabilize the pyoverdine structure. In some cases, pyoverdine can be primed with Zn(II) to stabilize the pyoverdine structure.

[0094] The structural destabilization causes swelling clays, such as montmorillonite, to transform into more stable, non-swelling secondary minerals such as illite. This transformation decreases the swelling potential of the clays, which in turn increases the reservoir’s permeability. The structural destabilization also causes an increase in pore size and connectivity. Pore throats expands and facilitates the flow of fluids through the reservoir. This improves permeability and significantly enhanced oil recovery in aging wells.Attorney Docket No. 66122-711.601

[0095] Pyoverdine binds Fe(III) and other metals present in the reservoir, such as aluminum (Al), chromium (Cr), vanadium (V), and even uranium (U). These metals are present in small quantities in oil reservoirs, particularly in association with Fe-rich minerals. Once pyoverdine binds these metals, they are extracted from the reservoir along with the chelated Fe(III), providing an opportunity for the recovery of valuable metals from the oil well.

[0096] An old, underperforming well with known low permeability and high clay content is selected for the trial. The mineral composition of the reservoir will be analyzed to confirm the presence of Fe(III)-bearing clays or shale materials, such as montmorillonite or illite, and the concentrations of other potentially valuable metals.

[0097] A solution containing pyoverdine and Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof is injected into the well. In some cases, a solution containing pyoverdine and Fe(II) is injected into the well. The concentration of pyoverdine is adjusted based on the estimated Fe(III) content of the reservoir and the desired depth of chelation. The solution is allowed to penetrate the reservoir for a period of 1-3 days to maximize the interaction between pyoverdine and Fe(III) in the mineral structures. Over time, pyoverdine chelates Fe(III), destabilizing the mineral structure, reducing swelling, and enhancing pore throat size.

[0098] As pyoverdine chelates Fe(III) and other metals, the produced water from the well is analyzed for metal content. Iron, aluminum, chromium, vanadium, and other metals are quantified. Metal-rich pyoverdine complexes are separated using standard filtration or extraction processes, and the extracted metals are recovered. With reduced clay swelling and improved permeability, the well’s oil production will increase. This extends the productive life of the well and reduces the need for more invasive methods such as fracturing. In addition to increased oil flow, the recovered metals (such as iron, aluminum, chromium, and vanadium) from the reservoir are processed as a byproduct of the oil recovery process.Example 4: Evaluating the interaction between pyoverdine, clay-rich reservoir rock, and potassium chloride (KC1) under elevated temperature and pressure conditions.

[0099] This example presents the results of swelling core experiments conducted to evaluate the interaction between pyoverdine, clay-rich reservoir rock, and potassium chloride (KC1) under elevated temperature and pressure conditions. Seven core sections from an Olmos Sand swelling-prone formation were tested under controlled laboratory conditions, using combinations of pyoverdine, 3.5% KC1, and 15% HC1 pre-treatment. Physical measurements and Inductively Coupled Plasma Optical Emission Spectrometry (ICP-OES) analysis wereAttorney Docket No. 66122-711.601used to quantify mineral dissolution behavior, mechanical stability, and ion release into solution. Cores exposed to pyoverdine only demonstrated significant degradation and density reduction, indicating substantial mineral matrix disruption. Similarly, treatment with KC1 alone led to measurable structural breakdown. However, cores treated with pyoverdine combined with KC1 exhibited reduced disintegration and increased final density, suggesting that the presence of the mixture of chemicals play a stabilizing role in mitigating excessive swelling and preserving structural integrity. ICP-OES data showed consistent release of Al, Ca, Fe, S, and Si into solution after pyoverdine exposure, confirming targeted mineral interaction expected in swelling clays. Acid pre-treatment removed carbonates and contributed to additional metal release but did not prevent disintegration unless paired with the pyoverdine + KC1 system. Overall, the results indicate that pyoverdine drives mineral modification within reactive shales, but co-treatment with KC1 is necessary to stabilize the rock and prevent excessive structural failure.

[0100] Liquid samples from the reaction of clay swelling core samples with pyoverdine were conducted. A total of seven core pieces were tested in this study. Each core piece was derived from one large core that was roughly cut into 2 inches by 1 inch slices using a wet tile saw. Core pieces were placed to dry in a ventilated oven under small vacuum at 90 °C overnight for 22 hours. Each core slice was weighed and measured (length, height, and volume) carefully before each step of the experiment. Volume was experimentally measured using water displacement. Post water displacement measurements cores were placed to dry in a ventilated oven under small vacuum at 90 °C for 4 hours.

[0101] One core slice (labeled Swelling 1) was kept as a total negative control and placed into a sealed container without any treatment. The remaining core slices were pre-treated as follows: three of them without pretreatment (labeled Swelling 3, 5, and 7) and three were pretreated using a 15 % HC1 solution (labeled Swelling 2, 4, and 6). The acid pretreated pieces were placed in 125 mL of the acid solution under negative pressure (-25inHg) for 30 minutes. Then, they were rinsed using DI water to remove any excess acid and placed to dry in a ventilated oven under small vacuum at 90 °C overnight for 17 hours.

[0102] All six cores were each placed in a mason jar with 150 mL of a solution of pyoverdine, pyoverdine with 3.5% KC1, or 3.5% KC1 in DI water. The pyoverdine samples that were tested in this study were in the same growth media and containing cells, without any pretreatment or purification process: pyoverdine (1.2 mM). Prior to sealing, the jars wereAttorney Docket No. 66122-711.601placed into a negative pressure chamber (-25inHg) for 1 hour. The mason jars were then tightly closed and sealed before being placed in a ventilated oven at 121.1 °C.

[0103] After 89 hours, the experiment fully stopped, and each of the respective solutions were decanted from the jars. Due to partial or full evaporation of the solutions, all jars were normalized back to 150 mL using DI water and stored for further analysis. The cores were then placed in separate beakers with DI water and sonicated for 5 minutes and then placed in a ventilated oven under small vacuum at 90 °C. After being dried overnight for 22 hours, the cores were measured again (length, height, and volume) to detect any differences from the values before the experiments.

[0104] From each of the liquid samples, a 2 mL aliquot of the sample was taken after the experiment. A 1 mL sample was diluted with 9 mL of 2% nitric acid solution and filtered using a 0.45 pm PTFE filter. A control solution of each solution (pyoverdine, pyoverdine + KC1, and KC1) was also diluted to be run on ICP to serve as blank for the results. The remaining liquids of the acid wash and sonication steps were kept to detect any metals in solution via ICP.

[0105] The ICP diluted samples were analyzed on an iCAP PRO XP Duo ICP-OES (Thermofisher), with 10 ppm Yttrium or 10 ppm Osmium as the internal standard (any value above the reference of 10 ppm is attributed to the sample). Each sample was measured three times, and the reported values represent the average of these three independent measurements. The results of the experiments are reported below. The calibrated data was calculated using the calibration curve determined by the individual standards solution. In the calibrated data, a change above 2 ppm of 50% more is underlined.Table 9. Data calibrated for elements with known standards. Data in Table 9 was measured for the samples to serve as a blank.Atorney Docket No. 66122-711.601Attorney Docket No. 66122-711.601attributed to the sample

[0106] Tables 10-12 highlight ICP data from pre and post experimental washes.Table 10. Data calibrated for elements with known standards. Data in Table 10 measures solutions during the pre-treatment.Atorney Docket No. 66122-711.601Attorney Docket No. 66122-711.601*Osmium was fed at 10 ppm as internal standard. Any value above the reference of 10 ppm is attributed to the sample

[0107] The acid treated cores exhibited significant release of Ca and Mg into solution, mainly removing the carbonates from the matrix. Additionally, Ag, Al, Fe, Na, and S were detected in relevant quantities in the acid solution.Table 11. Data calibrated for elements with known standards. Data in Table 11 measures the post experiment wash for cores 2-4.Atorney Docket No. 66122-711.601Attorney Docket No. 66122-711.601* Yttrium was fed at 10 ppm as internal standard. Any value above the reference of 10 ppm is attributed to the sample.Table 12. Data calibrated for elements with known standards. Data in Table 12 measures the post experiment wash for cores 5-7.Atorney Docket No. 66122-711.601Attorney Docket No. 66122-711.601* Yttrium was fed at 10 ppm as internal standard. Any value above the reference of 10 ppm is attributed to the sample.

[0108] In the ICP results shown in Table 13 and Table 14, the metals detected in the blank solutions (pyoverdine, pyoverdine + KC1, and KC1) were subtracted from the values reported by the ICP.Table 13. Data calibrated for elements with known standards. Data in Table 13 was measured for the pyoverdine solutions after experiment.Atorney Docket No. 66122-711.601Attorney Docket No. 66122-711.601Table 14. Data calibrated for elements with known standards. Data in Table 14 was measured for the pyoverdine solutions after experiment.Attorney Docket No. 66122-711.601

[0109] After the pyoverdine treatment, several metals were detected in solution, more significantly Al, Ca, Fe, S and Si.

[0110] The measurements and weight of each core at every step of experimentation was recorded and are reported in Table 15 to highlight any changes.Attorney Docket No. 66122-711.601Table 15. Initial data obtained from cores pre-experimentation.[OHl] Cores 2, 4, and 6 were pre-treated with a HC1 solution, rinsed with DI water, and dried overnight prior to pyoverdine or KC1 treatment. Minor degradation can be seen after the pre-treatment step, most notably in core 4. Table 16 highlights the physical changes in the acid pre-treated cores.Table 16. Post pre-treatment data from core pieces.

[0112] Significant visual differences were observed in the cores when comparing pre and post experimental photos. No change was observed from the control. Cores tested solely with pyoverdine or KC1 showed degradation / disintegration regardless of HC1 pre-treatment. Cores treated using both pyoverdine and KC1 solutions exhibited signs of wear / cracks along theAttorney Docket No. 66122-711.601surface but minimal degradation during the experimental process regardless of the pretreatment.

[0113] Table 17 highlights the physical changes of each of the cores after experimentation. The density of cores that degraded was taken by crushing the remaining core large pieces into a fine powder and measuring using a graduated volumetric cylinder. For the cores that didn’t disintegrate, the volume was measured by water displacement.Table 17. Post experiment data from core pieces.

[0114] The pyoverdine + KC1 treated cores that did not disintegrate were the only ones in which an increase in density was measured. In contrast, all the other core samples that were treated exhibited a reduction in the overall density, most likely caused by the disintegration of the core samples.Example 5: Integrated Evaluation of Porosity, Permeability, and Flow Capacity Under Acid and Siderophore Treatments

[0115] The following evaluation is based on independent, third-party laboratory testing. All capillary pressure mercury injection, porosity, and permeability measurements were performed under controlled conditions using industry-standard methodologies. The use of an independent laboratory ensures that the results presented here reflect unbiased, reproducible measurements and provides confidence that the observed changes in porosity, permeability, and flow capacity are technically sound and representative of reservoir-relevant behavior.Attorney Docket No. 66122-711.601

[0116] This study evaluated the impact of acid and siderophore-based stimulation treatments on porosity, permeability, and resulting flow capacity using two independent but complementary datasets: mercury intrusion porosimetry and sidewall core permeability measurements conducted under a confining pressure of 3,229 psi. Permeability values from the sidewall core analysis are Klinkenberg-corrected and therefore representative of gas flow behavior under stress, making them appropriate for reservoir-relevant assessment of transmissibility. Because core thickness is unchanged across all treatments, changes in permeability may be interpreted directly as proportional changes in flow capacity, expressed in reservoir terms as changes in effective k h.

[0117] Across all treated cores, permeability responds more strongly than porosity, regardless of measurement method. This observation is consistent across Hg-derived pore-scale metrics and stress-conditioned flow measurements, indicating that the dominant effect of treatment is enhancement of pore connectivity and throat conductance rather than simple creation of additional pore volume. From a reservoir engineering perspective, this distinction is critical, as hydrocarbon deliverability is governed primarily by transmissibility rather than storage.

[0118] One acid-treated core in the original dataset, Core 1, was observed to be cracked prior to testing. In this sample, porosity decreases by 5.25 % while permeability increases by 656.25 %, corresponding to a 6.56-fold increase in effective permeability and k h. While this result demonstrates the ability of acid to generate very high conductivity pathways, the decoupling of permeability gain from porosity loss indicates a channelized, fracture-dominated response rather than uniform matrix alteration. As such, this cracked core is not considered representative of intrinsic matrix stimulation and is treated as a boundary case illustrating the upper limit of conductivity enhancement under fracture-influenced conditions.

[0119] To establish an appropriate matrix-based comparison for acid treatment, an intact acid-treated core tested under identical confining pressure conditions was evaluated. In this intact sample, acid treatment produces a 5.24 % increase in porosity and a 162 % increase in permeability, corresponding to a 2.62-fold increase in effective k h. This response reflects distributed pore throat enlargement and improved connectivity across the matrix, without evidence of fracture-dominated flow. The intact acid core, therefore defines the representative baseline performance of acid stimulation for comparative evaluation.

[0120] Core 2, treated with pyoverdine alone, exhibited a 9.60 % increase in porosity and an 82.91 % increase in permeability, corresponding to a 1.83-fold increase in k h. This response indicates a controlled enhancement of pore connectivity, where added storage is accompanied by proportionate improvements in transmissibility. The permeability gain per unit porosityAttorney Docket No. 66122-711.601increase is modest relative to other treatments, but the response is uniform and stable, consistent with distributed pore-network restructuring rather than aggressive dissolution or localized channel formation. Under reservoir conditions, this behavior would be expected to improve flow efficiency while preserving rock integrity.

[0121] Core 3, treated with a combination of acid and py overdine, showed an 8.90 % increase in porosity and a 506.42 % increase in permeability, corresponding to a 6.06-fold increase in effective k h. Importantly, this permeability increase substantially exceeds that observed in the intact acid-treated core, demonstrating that the combined treatment produces a synergistic effect beyond acid-driven matrix dissolution alone. Both Hg porosimetry and Klinkenberg-corrected measurements indicate that this combined treatment disproportionately enhances connected flow pathways relative to added pore volume, representing the most effective conversion of contacted rock into producing rock in the dataset.

[0122] Core 4, treated with omibactin, exhibited a 7.80 % increase in porosity and a 215.82 % increase in permeability, corresponding to a 3.16-fold increase in flow capacity. This response reflects substantial improvement in pore throat conductance and connectivity, yielding a meaningful reduction in pressure drop for a given production rate. The permeability gain per unit porosity increase is significantly higher than pyoverdine alone and exceeds that of intact acid treatment, indicating a stronger pore-throat opening effect while maintaining a positive porosity response.

[0123] Mercury intrusion porosimetry provides a pore-scale view of these effects and reveals that permeability changes inferred from pore throat restructuring are directionally and quantitatively consistent with permeability measured under confining stress. Across all treatments, Hg-derived porosity and permeability changes align closely with Klinkenberg-corrected measurements at 3,229 psi. This agreement demonstrates that the pore-scale restructuring inferred from Hg intrusion translates into real, stress-sustaining improvements in transmissibility and is not a low-stress laboratory artifact.

[0124] When permeability gain is normalized by porosity change, clear mechanistic distinctions emerge. Intact acid treatment produces moderate permeability gains associated with distributed matrix dissolution. Pyoverdine alone produces controlled, efficient permeability gains per unit porosity, indicative of uniform connectivity enhancement.Ornibactin produces a stronger permeability response per unit porosity increase, suggesting more effective pore throat opening. The combination of acid and pyoverdine produces the highest permeability gain per unit porosity by a wide margin, reflecting a synergisticAttorney Docket No. 66122-711.601mechanism in which acid weakens mineral bonding or removes constraining phases, enabling pyoverdine to restructure the pore network into highly connected and conductive pathways. The cracked acid core represents a fracture-dominated upper bound and is not representative of matrix stimulation performance.

[0125] Taken together, these results demonstrate that siderophore-based treatments, particularly when used in combination with acid, preferentially enhance permeability and flow capacity relative to porosity under reservoir-relevant confining stress. This behavior aligns with a stimulation mechanism that improves pore connectivity and throat efficiency rather than relying on bulk dissolution or indiscriminate pore creation. Under reservoir conditions, such responses translate directly into higher effective k h, improved transmissibility, and increased deliverability from existing rock volume, which is the central objective of effective reservoir stimulation.

[0126] An important aspect of this evaluation is the stability of the observed permeability gains under elevated confining pressure. All sidewall core permeability measurements were conducted at a confining pressure of 3,229 psi, specifically to assess whether treatment-induced flow improvements persist under stress conditions representative of the subsurface. This is a critical distinction, as permeability enhancements that collapse under compression have limited reservoir relevance.

[0127] The intact acid-treated core demonstrates that acid-driven matrix permeability gains are stress-sustaining but moderate. In this sample, permeability increases from 0.29 mD in the control to 0.76 mD after treatment at 3,229 psi, corresponding to a 2.62-fold increase in effective permeability and k h. This confirms that acid treatment can produce real, measurable improvements in matrix transmissibility that remain open under confining stress, though the magnitude of the response is bounded.

[0128] Siderophore-based treatments exhibit similarly stable behavior under elevated pressure, with permeability gains that persist at 3,229 psi and exceed those observed for intact acid treatment. Pyoverdine alone maintained an approximately 1.83-fold increase in permeability under confining stress, while omibactin maintained an approximately 3.16-fold increase. Most notably, the combination of acid and pyoverdine maintained an approximately 6.06-fold increase in permeability at elevated pressure, demonstrating that the enhanced flow pathways created by this treatment are mechanically robust and not prone to stress-induced closure.

[0129] The pressure stability of these permeability gains is further supported by the close agreement between Hg porosimetry-derived permeability trends and Klinkenberg-correctedAttorney Docket No. 66122-711.601permeability measurements under confining stress. Hg intrusion indicates pore throat enlargement and improved connectivity consistent with the stress-conditioned flow data, suggesting that the treatments generate structurally stable pore-network modifications rather than compliant or transient features.

[0130] From a reservoir-engineering perspective, the persistence of permeability gains under elevated confining pressure indicates that the observed improvements in flow capacity are structural and durable. This provides confidence that the laboratory -measured enhancements in transmissibility will translate into sustained deliverability improvements under field conditions, reinforcing the commercial relevance of siderophore-based stimulation treatments.

[0131] Based on the combined Hg porosimetry and stress-conditioned sidewall core data, and using intact acid-treated cores as the appropriate baseline for matrix comparison, the acid plus pyoverdine treatment is an effective stimulation strategy for maximizing reservoir deliverability. This treatment consistently produces permeability and flow capacity increases that substantially exceed those achievable with acid alone, while maintaining stresssustaining connectivity improvements indicative of true pore-network restructuring.Ornibactin may be used where acid use is constrained, offering transmissibility gains that exceed intact acid treatment with positive porosity response. Pyoverdine alone provides controlled, lower-risk improvements suitable for applications prioritizing rock integrity and uniform stimulation. Acid-only treatment, while capable of high conductivity in fracture-influenced cases, should be evaluated cautiously for matrix stimulation and is best deployed in combination with siderophores to ensure stable, reservoir-relevant performance.

[0132] The second-generation plug analysis evaluates the effects of acid stimulation, pyoverdine, ornibactin, and sequential acid plus siderophore treatment on porosity and permeability under reservoir-relevant confining stress. The results show that conventional acid stimulation produces large apparent permeability gains at low stress that degrade significantly at higher stress, while siderophore formulations generate smaller but more mechanically stable improvements. Ornibactin and pyoverdine exhibit distinct behaviors, with ornibactin producing greater absolute permeability uplift and pyoverdine delivering highly stress-stable matrix modification. When applied sequentially after acid, pyoverdine converts stress-sensitive acid gains into durable matrix conductivity. Across all siderophore-treated samples, porosity increases without measurable loss of grain density, indicating selective pore network restructuring rather than bulk mineral dissolution. Collectively, theAttorney Docket No. 66122-711.601data support siderophore as a matrix-reactive stimulation chemistry that enhances reservoir connectivity in a mechanically persistent manner.

[0133] Air permeability results

[0134] Air permeability measurements showed clear differentiation between treatment mechanisms when evaluated across confining pressure. Acid-treated plugs exhibited very large permeability increases at low stress, consistent with aggressive enlargement of existing conductive features. However, these gains diminished sharply at higher confining pressure, indicating that a significant portion of the flow improvement is stress-sensitive.

[0135] It is important to note that the acid-treated sample contained a visible fracture aligned with the flow direction. This feature likely exaggerated low-stress air permeability by providing a preferential flow conduit that partially closes or loses effectiveness as confining pressure increases. As a result, the acid air-permeability response should be interpreted as an upper-bound case rather than a conservative representation of matrix stimulation.

[0136] Pyoverdine-treated plugs showed modest air permeability uplift, but with minimal change between low and high confining pressure. This behavior is consistent with controlled modification of pore-scale connectivity rather than fracture-dominated flow. Omibactin produced a larger air permeability response than pyoverdine, while retaining similar stress stability, suggesting a stronger interaction with iron- and aluminum-bound silicate structures that increases effective pore linkage without introducing mechanically weak features.

[0137] Sequential acid plus pyoverdine treatment produced intermediate air permeability uplift that remained largely intact under higher stress, indicating that pyoverdine stabilizes acid-accessible flow paths and reduces their stress sensitivity.

[0138] Klinkenberg Permeability Results

[0139] Klinkenberg-corrected permeability provides the most reservoir-relevant measure of matrix conductivity. In the acid-only case, Klinkenberg permeability increased dramatically at low confining pressure but declined substantially at higher pressure, mirroring the airpermeability trend and reinforcing the interpretation that acid primarily enhances pre-existing flow features.

[0140] Pyoverdine exhibited smaller Klinkenberg permeability gains, but these gains remained consistent across confining pressures, indicating genuine improvement in matrix conductivity rather than gas-slip or fracture-controlled effects. Ornibactin delivered larger Klinkenberg permeability increases than pyoverdine, again with strong stress stability, confirming that its higher absolute uplift reflects more extensive pore network restructuring rather than mechanical artifacts.Attorney Docket No. 66122-711.601

[0141] The sequential acid plus pyoverdine treatment yielded the most balanced response, with Klinkenberg permeability gains that are both meaningful in magnitude and largely insensitive to increased confining pressure. This indicates conversion of acid-accessible porosity into structurally supported matrix flow rather than transient enhancement.

[0142] Porosity

[0143] Porosity measurements showed consistent increases in siderophore-treated plugs relative to their paired controls, typically on the order of 0.6-0.8 absolute percentage points. In the context of tight reservoirs, this represents a meaningful increase in connected pore volume rather than measurement noise.

[0144] The acid-only sample showed comparatively small porosity change, consistent with surface etching or enlargement of existing pores rather than creation of new pore space. In contrast, the porosity gains observed with siderophore treatments indicate formation of additional connected void space through selective restructuring of the aluminosilicate framework.

[0145] Grain Density

[0146] Grain density remained effectively constant across all treatments, including pyoverdine, ornibactin, and sequential acid plus siderophore. This observation is critical for mechanistic interpretation. It demonstrates that the observed permeability and porosity increases are not driven by bulk mineral removal or dissolution of heavy phases.

[0147] Instead, the stable grain density supports a mechanism in which siderophores selectively disrupt iron- and aluminum-mediated silicate binding points, allowing the pore network to reorganize without stripping mineral mass. This selective restructuring explains both the porosity gains and the strong stress stability of permeability improvements observed in siderophore-treated samples.

[0148] Mechanistic Implications for EOR

[0149] The results indicate that siderophores operate through a matrix-reactive mechanism that is distinct from both conventional acid stimulation and fluid-focused chemical EOR. Rather than enlarging existing flow paths or relying on fracture-dominated conductivity, siderophores selectively disrupt iron- and aluminum-coordinated aluminosilicate structures that constrain pore connectivity in tight reservoirs. This disruption leads to controlled microscale restructuring of the pore network, increasing effective permeability while preserving mechanical stability under reservoir stress.

[0150] The exposure of fresh silicate surfaces during this restructuring introduces hydroxylterminated interfaces that favor water-wet conditions, reducing oil adhesion and residual oilAttorney Docket No. 66122-711.601saturation at the pore scale. As a result, siderophores simultaneously increase hydraulic connectivity and improves wettability, enabling previously immobile hydrocarbons to participate in flow without reliance on high-pressure mechanical stimulation.

[0151] When applied after acid, siderophores convert stress-sensitive, acid-accessible features into mechanically supported matrix pathways, mitigating permeability collapse and extending the productive contribution of treated intervals. In an EOR context, this behavior expands the effective drainage volume of the well and improves the durability of stimulation outcomes, positioning siderophores as a complementary tool that bridges the gap between chemical EOR and matrix stimulation in silicate-dominated reservoirs.Example 6: Proof of Concept Field Trial

[0152] A field-scale pyoverdine EOR chemical stimulation was executed on the Fowler #1 well, a severely impaired asset with no production for several months and negligible historical output. The treatment was successfully placed and displaced into the formation under field conditions. Post-treatment fluids showed clear evidence of iron chelation, clay-associated mineral disruption, and renewed hydrocarbon mobility. Incremental oil was recovered from a formation previously considered non-productive. The trial confirmed pyoverdine’ s ability to penetrate swelling, clay -rich systems, mobilize iron-stabilized mineral phases, and restore fluid communication without damaging fracture integrity.

[0153] Results from this deployment validate pyoverdine’ s core mechanism and provide actionable guidance for optimizing formulations for soft and clay-dominated reservoirs.

[0154] Fowler #1 had produced approximately five barrels of oil over a 15-month period and recorded zero production in the three months immediately preceding treatment. A prior hydraulic fracturing campaign five years earlier, including 15% HC1 acid stimulation, large-volume water injection, and proppant placement, failed to establish sustained production. The well was operationally classified as non-commercial. Subsequent produced-water flushing further degraded performance, consistent with swelling clay behavior in the Olmos formation and progressive loss of permeability.

[0155] Field Operations and Treatment Execution

[0156] Pre-Treatment Activities

[0157] A site reconnaissance was conducted and representative produced water and crude oil samples were collected. These samples were submitted for ICP and FTIR analysis to establish a chemical baseline prior to treatment.

[0158] Treatment Day OperationsAttorney Docket No. 66122-711.601

[0159] The pyoverdine EOR treatment was executed under stable weather conditions with ambient temperatures of approximately 65°F and an initial well pressure of 0 psi. An echometer survey confirmed a fluid level at approximately 1,530 feet, corresponding to pump depth. A pre-flush consisting of one tote (1,000 liters) of produced water was injected using a triplex pump rated to 2,500 psi. During this stage, suction pressure increased steadily, reaching approximately 400 psi at discharge, indicating active fluid movement into the formation.

[0160] The main pyoverdine EOR treatment followed, with a total of five totes injected at a concentration of 460 micro molar. During displacement of the first two totes, pumping was temporarily suspended due to a leak at the pump packing. This mechanical issue was corrected on site, and pumping resumed without further incident.

[0161] A post-flush consisting of seven barrels of crude oil was then pumped to displace the treatment into the formation. Final displacement pressure reached approximately 580 psi. The well was shut in at 580 psi to allow for soak time.

[0162] Post-Treatment Monitoring and Early Response

[0163] A complete pressure drop overnight was reported, with both casing and flowline pressures at 0 psi. While this indicated pressure communication with the formation, the well was intentionally left shut in to allow continued chemical interaction during the soak period.

[0164] Production Response and Fluid Observations

[0165] The well was returned to production. Approximately nine barrels of fluid were recovered, consisting predominantly of oil with minimal associated water. Gravity separation revealed clear phase partitioning.

[0166] Notably, the first barrel recovered exhibited a reddish-brown coloration, consistent with iron chelation and solubilization. Subsequent barrels showed normal crude oil with clear water and minimal basic sediment and water (BS&W). A small amount of fine, non-viscous sediment was observed floating in the water phase. This material appeared neither consolidated nor tacky and exhibited mixed hydrophilic and hydrophobic characteristics, consistent with partiallyhydroxylated silicate fines liberated during treatment.

[0167] Importantly, no proppant was observed to be mobilized or produced, indicating that pyoverdine selectively altered mineral binding phases without mechanically destabilizing the fracture pack.

[0168] The well was operated intermittently in six-hour production cycles to accumulate sufficient fluid volume for evaluation. Total recovered oil increased to approximately 9.5Attorney Docket No. 66122-711.601barrels, representing an incremental gain of roughly 2.5 barrels relative to the pre-treatment baseline under highly impaired conditions.

[0169] Following the trial, the well has continued to produce crude oil at a sustained rate of approximately 2-3 gallons per day with basic sediment and water (BS&W) consistently below 5%. This production remains ongoing at the time of this report, confirming continued hydrocarbon mobility and stable phase behavior post-treatment.

[0170] Interpretation and Technical Assessment

[0171] The Fowler #1 well is dominated by swelling clay mineralogy that historically suppressed permeability and pore connectivity. Field observations demonstrate that py overdine effectively disrupted iron- and aluminum-stabilized clay structures, enabling deeper chemical penetration and reopening of previously inaccessible pore pathways.

[0172] Initial post-treatment flow behavior reflects the dynamic response of soft clay systems to ion chemistry rather than loss of treatment effectiveness. Importantly, continued low-rate oil production with stable fluid quality confirms that pyoverdine-established flow paths remained active beyond the initial recovery period.

[0173] The sustained presence of chelated iron in early produced fluids, liberation of fine silicate material, and complete absence of proppant mobilization collectively validate py overdine’ s intended mechanism of action. The treatment selectively altered mineral binding phases and clay structure without aggressive dissolution, fines migration, or mechanical destabilization of the fracture network.

[0174] Operational Learnings and Recommended Improvements

[0175] Both laboratory data and field response support the inclusion of potassium chloride at approximately 3.5% weight per volume to further suppress clay re-swelling and stabilize permeability gains in clay-rich formations.

[0176] Field observations also support deploying pyoverdine in combination with proppant in mechanically weak or “soft” formations to preserve chemically accessed pore throats following treatment. This positions pyoverdine not only as an effective standalone remedial chemistry, but also as a complementary additive or carrier fluid during initial fracturing or refracturing operations.

[0177] Based on these findings, two optimized pyoverdine EOR formulations are recommended for future deployments: Pyoverdine incorporating 3.5% potassium chloride, with optional proppant compatibility.Attorney Docket No. 66122-711.601

[0178] While preferred embodiments of the present invention have been shown and described herein, it will be obvious to those skilled in the art that such embodiments are provided by way of example only. Numerous variations, changes, and substitutions will now occur to those skilled in the art without departing from the invention. It should be understood that various alternatives to the embodiments of the invention described herein may be employed in practicing the invention. It is intended that the following claims define the scope of the invention and that methods and structures within the scope of these claims and their equivalents be covered thereby.

Claims

1. Attorney Docket No. 66122-711.601CLAIMS WHAT IS CLAIMED IS:

1. A method of degrading a shale material, the method comprising:contacting the siderophore with the shale material under conditions sufficient for the siderophore to degrade at least a portion of the shale material.

2. The method of claim 1, wherein the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal.

3. The method of claim 1, wherein the siderophore is in a solution.

4. The method of any one of claims 1-3, wherein the shale material is located in an oil well.

5. The method of any one of claims 1-4, wherein the shale material is located in a subsurface oil well.

6. The method of any one of claims 1-4, wherein the shale material is located in a surface oil well.

7. The method of any one of claims 1-6, further comprising, prior to the contacting, treating the shale material with an acid.

8. The method of claim 7, wherein the acid comprises hydrochloric acid (HC1), hydrofluoric acid (HF), acetic acid, or citric acid, or any combination thereof.

9. The method of claim 7, wherein the acid comprises HC1.

10. The method of claim 7, wherein the acid comprises HF.

11. The method of claim 7, wherein the acid comprises acetic acid.

12. The method of claim 7, wherein the acid comprises citric acid.

13. The method of any one of claims 7-12, wherein the acid is present in a solution at a concentration of at least about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, or 20% (w / v) acid.

14. The method of any one of claims 1-13, wherein the contacting comprises injecting the siderophore.

15. The method of any one of claims 1-14, wherein the siderophore is contacted with the shale material in the presence of at least one surfactant.

16. The method of claim 15, wherein the at least one surfactant comprises dodecylbenzene sulfonic acid (DDBSA), a-Olefin sulfonate (AOS), betaine, NHance 52, NHance 1101, NHance 920 A, NHance 2101, XPerse®, Super SF 1001, Tween 80, sodium lauryl ether sulfate (SLES), sophorolipid, or any combination thereof.Attorney Docket No. 66122-711.60117. The method of claim 15, wherein the at least one surfactant comprises DDB SA.

18. The method of claim 15, wherein the at least one surfactant comprises AOS.

19. The method of claim 15, wherein the at least one surfactant comprises betaine.

20. The method of claim 15, wherein the at least one surfactant comprises NHance52.

21. The method of claim 15, wherein the at least one surfactant comprises NHance 1101.

22. The method of claim 15, wherein the at least one surfactant comprises NHance 920A.

23. The method of claim 15, wherein the at least one surfactant comprises NHance 2101.

24. The method of claim 15, wherein the at least one surfactant comprises XPerse.

25. The method of claim 15, wherein the at least one surfactant comprises Super SF 1001.

26. The method of claim 15, wherein the at least one surfactant comprises Tween 80 27. The method of claim 15, wherein the at least one surfactant comprises SLES.

28. The method of claim 15, wherein the at least one surfactant comprises sophorolipid.

29. The method of any one of claims 1-28, wherein the shale material comprises a hydrocarbon.

30. The method of claim 29, wherein degradation of the shale material results in liberation of at least a portion of the hydrocarbon from the shale material.

31. The method of claim 30, wherein at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, or at least about 99.5% of the hydrocarbon in the shale material is liberated after the contacting.

32. The method of claim 30 or 31, wherein an amount of the hydrocarbon released from the shale material is greater than an amount of hydrocarbon released from the shale material upon treatment with an acid.

33. The method of claim 32, wherein the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v).

34. The method of any one of claims 29-33, wherein an amount of the hydrocarbon released from the shale material is at least 1% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid.

35. The method of claim 34, wherein the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v).

36. The method of any one of claims 29-35, wherein an amount of the hydrocarbon released from the shale material is from about 1% to about 400% greater than an amount of hydrocarbon released from the shale material upon treatment with an acid.Attorney Docket No. 66122-711.60137. The method of claim 36, wherein the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v).

38. The method of any one of claims 29-37, wherein at least a portion of the hydrocarbon is released.

39. The method of any one of claims 1-38, wherein the contacting changes a fluid property of the shale material.

40. The method of claim 39, wherein the fluid property comprises intrafacial tension (IFT), density, viscosity, or any combination thereof.

41. The method of claim 40, wherein the contacting decreases the IFT, density, viscosity, or any combination thereof of the shale material.

42. The method of claim 40, wherein the contacting decreases the IFT of the shale material.

43. The method of claims 40 or 42, wherein the contacting decreases the IFT from about 10% to about 50% of the shale material.

44. The method of claim 40, wherein the contacting decreases the density of the shale material.

45. The method of claims 40 or 44, wherein the contacting decreases the density from about 1% to about 5% of the shale material.

46. The method of claim 40, wherein the contacting decreases the viscosity of the shale material.

47. The method of claims 40 or 46, wherein the contacting decreases the viscosity of the shale material from about 10% to about 40%.

48. The method of any one of claims 1-47, wherein the contacting increases permeability, porosity, pore throat size, fluid flow, or any combination thereof of the shale material.

49. The method of any one of claims 1-48, wherein the contacting increases the permeability of the shale material from about 10% to about 500%.

50. The method of any one of claims 1-49, wherein the contacting decreases water absorption or water content of the shale material.

51. The method of any one of claims 1-50, wherein the contacting destabilizes the shale material.

52. The method of any one of claims 1-51, wherein the contacting forms a silica gel.

53. The method of any one of claims 1-52, wherein the shale material comprises one or more metals.Attorney Docket No. 66122-711.60154. The method of claim 53, wherein the one or more metals comprise iron, aluminum, chromium, vanadium, or uranium, or any combination thereof.

55. The method of claim 53 or 54, wherein the one or more metals comprise aluminum, phosphorous, silicone, sulfur, potassium, calcium, manganese, nickel, copper, zinc, arsenic, selenium, strontium, rubidium, chromium, zirconium, niobium, molybdenum, barium, tin, lead, antimony, tantalum, tungsten, mercury, bismuth, thorium, titanium, cobalt, vanadium, yttrium, or uranium, or any combination thereof.

56. The method of any one of claims 53-55, wherein the method further comprises extracting a metal of the one or more metals from the shale material.

57. The method of any one of claims 53-56, wherein the method further comprises recovering a metal of the one or more metals from the shale material.

58. The method of any one of claims 53-57, wherein the method further comprises separating a metal of the one or more metals from the shale material.

59. The method of any one of claims 53-58, wherein the method further comprises purifying a metal of the one or more metals from the shale material, thereby obtaining a purified metal60. The method of claim 59, wherein the purified metal has a purity of at least about 80%.

61. The method of claim 59, wherein the purified metal has a purity of at least about 90%.

62. The method of claim 59, wherein the purified metal has a purity of at least about 95%.

63. The method of claim 59, wherein the purified metal has a purity of at least about 99%.

64. The method of claim 59, wherein the purified metal has a purity of at least about 99.99%.

65. The method of claim 59, wherein the purified metal has a purity of at least about 99.999%.

66. The method of any one of claims 53-65, wherein the method further comprises liberating at least a portion of the one or more metals from the shale material.

67. The method of claim 66, wherein at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, or at least about 99.5% of the one or more metals in the shale material are liberated.

68. The method of claim 66 or 67, wherein an amount of the one or more metals released from the shale material is greater than an amount of one or more metals released from the shale material upon treatment with an acid.Attorney Docket No. 66122-711.60169. The method of claim 68, wherein the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v).

70. The method of any one of claims 66-69, wherein an amount of the one or more metals released from the shale material is at least 1% greater than an amount of one or more metals released from the shale material upon treatment with an acid.

71. The method of claim 70, wherein the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v).

72. The method of any one of claims 66-71, wherein an amount of the one or more metals released from the shale material is from about 1% to about 400% greater than an amount of one or more metals released from the shale material upon treatment with an acid.

73. The method of claim 72, wherein the acid comprises HC1 in a solution at a concentration from about 5% (w / v) to about 25% (w / v).

74. The method of any one of claims 53-73, wherein at least a portion of the one or more metals are released.

75. The method of any one of claims 1-74, wherein the contacting comprises contacting the shale material with the siderophore in the presence of a salt.

76. The method of claim 75, wherein the salt comprises citrate, oxalate, phosphate- buffered saline (PBS), bicarbonate, or any combination thereof.

77. The method of claim 75, wherein the salt comprises citrate.

78. The method of claim 75, wherein the salt comprises oxalate.

79. The method of claim 75, wherein the salt comprises PBS.

80. The method of claim 75, wherein the salt comprises bicarbonate.

81. The method of any one of claims 75-80, wherein the salt is at a concentration in a range from about 0.01 M to 1.0 M.

82. The method of any one of claims 75-80, wherein the salt is at a concentration of about 0.01 M, 0.05 M, 0.1 M, 0.5 M, or 1.0 M.

83. The method of any one of claims 75-80, wherein the salt is at a concentration of about 0.1 M.

84. The method of any one of claims 1-83, wherein conditions comprise a pH from about 2 to about 8.

85. The method of any one of claims 1-83, wherein the conditions comprise a pH from about 4 to about 6.Attorney Docket No. 66122-711.60186. The method of any one of claims 1-83, wherein the conditions comprise a pH of about 5.

87. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about -10 °C to about 150 °C.

88. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about average surface temperature.

89. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about 15 °C.

90. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about 20 °C.

91. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about 25 °C.

92. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about 125 °C.

93. The method of any one of claims 1-83, wherein the contacting occurs at a temperature of about 150 °C.

94. The method of any one of claims 1-93, wherein the conditions comprise a salinity of about 250,000 ppm to about 300,000 ppm.

95. The method of any one of claims 1-93, wherein the conditions comprise a salinity of about 250,000 ppm.

96. The method of any one of claims 1-93, wherein the conditions comprise a salinity of about 300,000 ppm.

97. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of about surface pressure.

98. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of about 15 psi.

99. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of about 100 psi to about 8,000 psi.

100. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of about 100 psi.

101. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of at least about 100 psi.

102. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of about 8,000 psi.Attorney Docket No. 66122-711.601103. The method of any one of claims 1-96, wherein the contacting occurs at a pressure of at most about 8,000 psi.

104. The method of any one of claims 1-103, wherein the contacting occurs for a time period.

105. The method of claim 104, wherein the time period is from about 1 day to about 7 days.

106. The method of claim 104, wherein the time period is about 7 days.

107. The method of claim 104, wherein the time period is at most about 7 days.

108. The method of any one of claims 1-107, wherein the contacting is performed without agitation.

109. The method of any one of claims 1-107, wherein the contacting is performed with agitation.

110. The method of any one of claims 1-109, wherein the siderophore is derived from an organism selected from the group comprising Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotof ormans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof.

111. The method of any one of claims 1-110, wherein the siderophore is selected from the group consisting of: aerobactin, agrobactin, aminochelin, azotobactin, azotochelin, bacillibactin, deferoxamine B, deferoxamine E, desferrioxamine B, desferrioxamine E, enterobactin, ferrichrome, fusarinine C, micacocidin, mycobactin, ornibactin, protochelin, pseudobactin, pyochelin, pyoverdine, pyoverdine or a derivative of py overdine, PyoPpC-3B, pyridine-2,6-dithiocarboxylate, rhizobactin 1021, rhodotorulic acid, salmochelin, schizokinen, vibrioferrin, vibriobactin, vicibactin, yersiniabactin, and any combination thereof.

112. The method of any one of claims 1-111, wherein the siderophore comprises pyoverdine, pyochelin, ornibactin, or any combination thereof.Attorney Docket No. 66122-711.601113. The method of any one of claims 1-111, wherein the siderophore comprises pyoverdine.

114. The method of any one of claims 1-111, wherein the siderophore comprises pyoverdine or a derivative of pyoverdine.

115. The method of any one of claims 1-111, wherein the siderophore comprises PyoPpC-3B.

116. The method of any one of claims 1-111, wherein the siderophore comprises pyochelin.

117. The method of any one of claims 1-111, wherein the siderophore comprises ornibactin.

118. The method of any one of claims 1-117, wherein the siderophore is purified from an organism.

119. The method of claim 118, wherein the organism is selected from the group consisting of: Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotof ormans, Pseudomonas BIO, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof.

120. The method of any one of claims 1-119, wherein the siderophore is produced in a host cell or in a cell-free production system.

121. The method of claim 120, wherein the host cell comprises a bacterial cell.

122. The method of claim 121, wherein the bacterial cell comprises Burkholderia bacteria.

123. The method of claim 122, wherein the Burkholderia bacteria is selected from the group consisting of: Burkholderia cenocepacia and Burkholderia cepacia.

124. The method of claim 123, wherein the bacterial cell comprises a Pseudomonas bacteria.Attorney Docket No. 66122-711.601125. The method of claim 124, wherein the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa.

126. The method of any one of claims 1-125, wherein the shale material comprises clay, carbonaceous shale, black shale, or any combination thereof.

127. The method of any one of claims 1-126, wherein the shale material comprises kaolinite, montmorillonite, illite, feldspar, quartz or any combination thereof.

128. The method of any one of claims 1-127, wherein the shale material has low- permeability.

129. The method of any one of claims 1-128, wherein the method is performed in situ or ex situ.

130. The method of any one of claims 1-129, wherein the siderophore has a hydrocarbon extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

131. The method of any one of claims 1-130, wherein the siderophore has a maximum hydrocarbon extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

132. The method of any one of claims 1-131, wherein the siderophore has a metal extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

133. The method of any one of claims 1-132, wherein the siderophore has a maximum metal extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

134. The method of any one of claims 1-133, wherein the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof, prior to the contacting.

135. The method of any one of claims 1-134, wherein the siderophore is bound to Fe(II) prior to the contacting.Attorney Docket No. 66122-711.601136. The method of any one of claims 1-135, wherein the contacting comprises contacting the siderophore with the shale material in the presence of an oxidizing agent.

137. The method of claim 136, wherein the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin.

138. The method of claim 136, wherein the oxidizing agent comprises sodium hypochlorite.

139. The method of claim 136, wherein the oxidizing agent comprises hydrogen peroxide.

140. The method of claim 136, wherein the oxidizing agent comprises pyocyanin.

141. A reaction mixture comprising: a siderophore and a shale material.

142. The reaction mixture of claim 141, wherein the reaction mixture further comprises a solution.

143. The reaction mixture of claim 141 or 142, wherein the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal.

144. The reaction mixture of any one of claims 141-143, wherein the shale material is located in a surface oil well.

145. The reaction mixture of any one of claims 141-143, wherein the shale material is located in a subsurface oil well.

146. The reaction mixture of any one of claims 141-145, wherein the shale material is shale material that has been pre-treated with an acid.

147. The reaction mixture of claim 146, wherein the acid comprises hydrochloric acid (HC1), hydrofluoric acid (HF), acetic acid, or citric acid, or any combination thereof.

148. The reaction mixture of claim 146, wherein the acid comprises HC1.

149. The reaction mixture of claim 146, wherein the acid comprises HF.

150. The reaction mixture of claim 146, wherein the acid comprises acetic acid.

151. The reaction mixture of claim 146, wherein the acid comprises citric acid.

152. The reaction mixture of any one of claims 146-151, wherein the acid comprises a solution comprising a concentration of at least about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, or 20% (w / v) acid.

153. The reaction mixture of any one of claims 141-152, wherein the reaction mixture comprises at least one surfactant.Attorney Docket No. 66122-711.601154. The reaction mixture of claim 153, wherein the at least one surfactant comprises dodecylbenzene sulfonic acid (DDBSA), a-Olefin sulfonate (AOS), betaine, NHance 52, NHance 1101, NHance 920 A, NHance 2101, XPerse®, Super SF 1001, Tween 80, sodium lauryl ether sulfate (SLES), sophorolipid, or any combination thereof.

155. The reaction mixture of claim 153, wherein the at least one surfactant comprises DDBSA.

156. The reaction mixture of claim 153, wherein the at least one surfactant comprises AOS.

157. The reaction mixture of claim 153, wherein the at least one surfactant comprises betaine.

158. The reaction mixture of claim 153, wherein the at least one surfactant comprises NHance52.

159. The reaction mixture of claim 153, wherein the at least one surfactant comprises NHance 1101.

160. The reaction mixture of claim 153, wherein the at least one surfactant comprises NHance 920A.

161. The reaction mixture of claim 153, wherein the at least one surfactant comprises NHance 2101.

162. The reaction mixture of claim 153, wherein the at least one surfactant comprises XPerse.

163. The reaction mixture of claim 153, wherein the at least one surfactant comprises Super SF 1001.

164. The reaction mixture of claim 153, wherein the at least one surfactant comprises Tween 80165. The reaction mixture of claim 153, wherein the at least one surfactant comprises SLES.

166. The reaction mixture of claim 153, wherein the at least one surfactant comprises sophorolipid.

167. The reaction mixture of any one of claims 141-166, wherein the reaction mixture comprises a salt.

168. The reaction mixture of claim 167, wherein the salt comprises citrate, oxalate, phosphate-buffered saline (PBS), bicarbonate, or any combination thereof.

169. The reaction mixture of claim 168, wherein the salt comprises citrate.

170. The reaction mixture of claim 168, wherein the salt comprises oxalate.Attorney Docket No. 66122-711.601171. The reaction mixture of claim 168, wherein the salt comprises PBS.

172. The reaction mixture of claim 168, wherein the salt comprises bicarbonate.

173. The reaction mixture of any one of claims 167-172, wherein the salt is at a concentration in a range from about 0.01 M to 1.0 M.

174. The reaction mixture of any one of claims 167-173, wherein the salt is at a concentration of about 0.01 M, 0.05 M, 0.1 M, 0.5 M, or 1.0 M.

175. The reaction mixture of any one of claims 167-174, wherein the salt is at a concentration of about 0.1 M.

176. The reaction mixture of any one of claims 141-175, wherein the reaction mixture comprises a pH from about 2 to about 8.

177. The reaction mixture of any one of claims 141-176, wherein the reaction mixture comprises a pH from about 4 to about 6.

178. The reaction mixture of any one of claims 141-177, wherein the reaction mixture comprises a pH of about 5.

179. The reaction mixture of any one of claims 141-178, wherein the reaction mixture is at a temperature of about -10 °C to about 150 °C.

180. The reaction mixture of any one of claims 141-179, wherein the reaction mixture is at a temperature of about average surface temperature.

181. The reaction mixture of any one of claims 141-180, wherein the reaction mixture is at a temperature of about 15 °C.

182. The reaction mixture of any one of claims 141-180, wherein the reaction mixture is at a temperature of about 20 °C.

183. The reaction mixture of any one of claims 141-180, wherein the reaction mixture is at a temperature of about 25 °C.

184. The reaction mixture of any one of claims 141-180, wherein the reaction mixture is at a temperature of about 125 °C.

185. The reaction mixture of any one of claims 141-180, wherein the reaction mixture is at a temperature of about 150 °C.

186. The reaction mixture of any one of claims 141-185, wherein the reaction mixture comprises a salinity of about 250,000 ppm to about 300,000 ppm.

187. The reaction mixture of any one of claims 141-186, wherein the reaction mixture comprises a salinity of about 250,000 ppm.

188. The reaction mixture of any one of claims 141-186, wherein the reaction mixture comprises a salinity of about 300,000 ppm.Attorney Docket No. 66122-711.601189. The reaction mixture of any one of claims 141-188, wherein the reaction mixture is at a pressure of about surface pressure.

190. The reaction mixture of any one of claims 141-188, wherein the reaction mixture is at a pressure of about 15 psi.

191. The reaction mixture of any one of claims 141-188, wherein the reaction mixture is at a pressure of about 100 psi to about 8,000 psi.

192. The reaction mixture of any one of claims 141-188, wherein the reaction mixture at a pressure of at least about 100 psi.

193. The reaction mixture of any one of claims 141-188, wherein the reaction mixture is at a pressure of about 8,000 psi.

194. The reaction mixture of any one of claims 141-188, wherein the reaction mixture is at a pressure of at most 8,000 psi.

195. The reaction mixture of any one of claims 141-194, wherein the reaction mixture is incubated for a time period.

196. The reaction mixture of claim 195, wherein the time period is from about 1 hour to about 7 days.

197. The reaction mixture of claim 196, wherein the time period is from about 7 days.

198. The reaction mixture of claim 197, wherein the time period is from at most about 7 days.

199. The reaction mixture of any one of claims 141-198, wherein the reaction mixture is not agitated.

200. The reaction mixture of any one of claims 141-198, wherein the reaction mixture is agitated.

201. The reaction mixture of any one of claims 141-200, wherein the siderophore is derived from an organism selected from the group comprising Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotof ormans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof.Attorney Docket No. 66122-711.601202. The reaction mixture of any one of claims 141-201, wherein the siderophore is selected from the group consisting of: aerobactin, agrobactin, aminochelin, azotobactin, azotochelin, bacillibactin, deferoxamine B, deferoxamine E, desferrioxamine B, desferrioxamine E, enterobactin, ferrichrome, fusarinine C, micacocidin, mycobactin, ornibactin, protochelin, pseudobactin, pyochelin, pyoverdine, pyoverdine or a derivative of pyoverdine, PyoPpC-3B, pyridine-2,6-dithiocarboxylate, rhizobactin 1021, rhodotorulic acid, salmochelin, schizokinen, vibrioferrin, vibriobactin, vicibactin, yersiniabactin, and any combination thereof.

203. The reaction mixture of any one of claims 141-202, wherein the siderophore comprises pyoverdine, pyochelin, ornibactin, or any combination thereof.

204. The reaction mixture of any one of claims 141-203, wherein the siderophore comprises pyoverdine.

205. The reaction mixture of any one of claims 141-204, wherein the siderophore comprises pyoverdine or a derivative of pyoverdine.

206. The reaction mixture of any one of claims 141-203, wherein the siderophore comprises PyoPpC-3B.

207. The reaction mixture of any one of claims 141-203, wherein the siderophore comprises pyochelin.

208. The reaction mixture of any one of claims 141-203, wherein the siderophore comprises ornibactin.

209. The reaction mixture of any one of claims 141-208, wherein the siderophore is purified from an organism prior to the contacting.

210. The reaction mixture of claim 209, wherein the organism is selected from the group consisting of: Acinetobacter baumannii, Azotobacter vinelandii, Bacillus anthracis, Bacillus megaterium, Bacillus subtilis, Bacillus thuringiensis, Burkholderia cepacia, Burkholderia cenocepacia, Escherichia coli, Fusarium roseum, Klebsiella pneumonia, Mycobacterium smegmatis, Mycobacterium tuberculosis, Pantoea eucalypti M91, Pantoea vagans C9-1, Pseudomonas aeruginosa, Pseudomonas azotof ormans, Pseudomonas B10, Pseudomonas fluorescens, Pseudomonas putida, Pseudomonas sp., Pseudomonas syringae, Rhizobium leguminosarum, Rhizobium meliloti, Rhizobium radiobacter, Rhodotorula pilimanae, Streptomyces coelicolor, Streptomyces pilosus, Streptomyces coelicolor, Ustilago sphaerogena, Vibrio cholerae, Yersinia pestis, and any combination thereof.Attorney Docket No. 66122-711.601211. The reaction mixture of any one of claims 141-210, wherein the siderophore is produced in a host cell or in a cell-free production system.

212. The reaction mixture of claim 211, wherein the host cell comprises a bacterial cell.

213. The reaction mixture of claim 212, wherein the bacterial cell comprises Burkholderia bacteria.

214. The reaction mixture of claim 213, wherein the Burkholderia bacteria is selected from the group consisting of: Burkholderia cenocepacia and Burkholderia cepacia.

215. The reaction mixture of claim 212, wherein the bacterial cell comprises a Pseudomonas bacteria.

216. The reaction mixture of claim 215, wherein the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa.

217. The reaction mixture of any one of claims 141-216, wherein the shale material comprises clay, carbonaceous shale, black shale, or any combination thereof.

218. The reaction mixture of any one of claims 141-217, wherein the shale material comprises kaolinite, montmorillonite, illite, feldspar, quartz or any combination thereof.

219. The reaction mixture of any one of claims 141-218, wherein the shale material has low-permeability.

220. The reaction mixture of any one of claims 141-219, wherein the reaction mixture is in situ or ex situ.

221. The reaction mixture of any one of claims 141-220, wherein the siderophore has a hydrocarbon extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

222. The reaction mixture of any one of claims 139-221, wherein the siderophore has a maximum hydrocarbon extraction rate of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

223. The reaction mixture of any one of claims 141-222, wherein the siderophore has a metal extraction efficiency of at least about 80%, at least about 85%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

224. The reaction mixture of any one of claims 141-223, wherein the siderophore has a maximum metal extraction rate of at least about 80%, at least about 85%, at least aboutAttorney Docket No. 66122-711.60190%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 98%, at least about 99%, at least about 99.5%, or higher.

225. The reaction mixture of any one of claims 141-224, wherein the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof.

226. The reaction mixture of any one of claims 141-225, wherein the siderophore is bound to Fe(II).

227. The reaction mixture of any one of claims 141-226, wherein the reaction mixture comprises an oxidizing agent.

228. The reaction mixture of claim 227, wherein the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin.

229. The reaction mixture of claim 227, wherein the oxidizing agent comprises sodium hypochlorite.

230. The reaction mixture of claim 227, wherein the oxidizing agent comprises hydrogen peroxide.

231. The reaction mixture of claim 227, wherein the oxidizing agent comprises pyocyanin.

232. A method of degrading a shale material in a surface oil well, the method comprising:contacting the shale material with the siderophore under conditions sufficient for the siderophore to degrade at least a portion of the shale material.

233. The method of claim 232, wherein the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal.

234. The method of claim 232 or 233, wherein the siderophore is in a solution.

235. The method of any one of claims 232-234, wherein the siderophore comprises pyoverdine.

236. The method of any one of claims 232-235, wherein the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to the contacting.

237. The method of any one of claims 232-236, wherein the siderophore is bound to Fe(II) prior to the contacting.

238. The method of any one of claims 232-237, wherein the siderophore is contacted with the shale material in the presence of an oxidizing agent.Attorney Docket No. 66122-711.601239. The method of claim 238, wherein the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin.

240. The method of claim 238, wherein the oxidizing agent comprises sodium hypochlorite.

241. The method of claim 238, wherein the oxidizing agent comprises hydrogen peroxide.

242. The method of claim 238, wherein the oxidizing agent comprises pyocyanin.

243. The method of any one of claims 232-242, wherein the contacting occurs at a temperature of about average surface temperature.

244. The method of any one of claims 232-243, wherein the contacting in (b) occurs at a temperature of about 15 °C.

245. The method of any one of claims 232-243, wherein the contacting in (b) occurs at a temperature of about 20 °C.

246. The method of any one of claims 232-243, wherein the contacting in (b) occurs at a temperature of about 25 °C.

247. The method of any one of claims 232-246, wherein the contacting in (b) occurs at a pressure of about surface pressure.

248. The method of any one of claims 232-247, wherein the contacting in (b) occurs at a pressure of about 15 psi.

249. The method of any one of claims 232-247, wherein the contacting in (b) occurs at a pressure of at most about 15 psi.

250. The method of any one of claims 232-247, wherein the contacting in (b) occurs for a time period.

251. The method of claim 250, wherein the time period is from about 1 hour to about 7 days.

252. The method of claim 250, wherein the time period is about 7 days.

253. The method of claim 250, wherein the time period is at most about 7 days.

254. The method of any one of claims 232-253, wherein the siderophore is purified from an organism prior to the contacting.

255. The method of claim 254, wherein the host cell comprises a bacterial cell.

256. The method of claim 255, wherein the bacterial cell comprises a Pseudomonas bacteria.Attorney Docket No. 66122-711.601257. The method of claim 256, wherein the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa.

258. A method of degrading a shale material in a subsurface oil well, the method comprising:contacting the siderophore with the shale material under conditions sufficient for the siderophore to degrade at least a portion of the shale material.

259. The method of claim 258, wherein the siderophore is lyophilized, in a powder form, in suspension in a solution, dissolved in an organic solvent, dissolved in an inorganic solve, natural, or stabilized with a pre-chelated metal.

260. The method of claim 258 or 259, wherein the siderophore is in a solution.

261. The method of any one of claims 258-260, wherein the siderophore comprises pyoverdine.

262. The method of any one of claims 258-261, wherein the siderophore is bound to Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), Zn(II), or any combination of two or more thereof prior to the contacting.

263. The method of any one of claims 258-262, wherein the siderophore is bound to Fe(II) prior to the contacting.

264. The method of any one of claims 258-263, wherein the siderophore is contacted with the shale material in the presence of an oxidizing agent.

265. The method of claim 264, wherein the oxidizing agent comprises sodium hypochlorite, hydrogen peroxide, or pyocyanin.

266. The method of claim 264, wherein the oxidizing agent comprises sodium hypochlorite.

267. The method of claim 264, wherein the oxidizing agent comprises hydrogen peroxide.

268. The method of claim 264, wherein the oxidizing agent comprises pyocyanin.

269. The method of any one of claims 258-268, wherein the contacting occurs at a temperature of about -10 °C to about 150 °C.

270. The method of any one of claims 258-269, wherein the contacting occurs at a temperature of about 125 °C.

271. The method of any one of claims 258-270, wherein the contacting occurs at a temperature of about 150 °C.Attorney Docket No. 66122-711.601272. The method of any one of claims 258-271, wherein the contacting occurs at a pressure of about 100 psi to about 8,000 psi.

273. The method of any one of claims 258-272, wherein the contacting occurs at a pressure of at least about 100 psi.

274. The method of any one of claims 258-273, wherein the contacting occurs at a pressure of about 8,000 psi.

275. The method of any one of claims 258-274, wherein the contacting occurs at a pressure of at most about 8,000 psi.

276. The method of any one of claims 258-275, wherein the contacting occurs for a time period.

277. The method of claim 276, wherein the time period is from about 1 hour to about 7 days.

278. The method of claim 277, wherein the time period is about 7 days.

279. The method of claim 278, wherein the time period is at most about 7 days.

280. The method of any one of claims 258-279, wherein the siderophore is purified from an organism prior to the contacting.

281. The method of claim 280, wherein the host cell comprises a bacterial cell.

282. The method of claim 281, wherein the bacterial cell comprises a Pseudomonas bacteria.

283. The method of claim 282, wherein the Pseudomonas bacteria is selected from the group consisting of: Pseudomonas putida, Pseudomonas fluorescens, Pseudomonas azotoformans, and Pseudomonas aeruginosa.

284. A stabilized siderophore comprising the siderophore bound to at least one of Fe(II), Cr(III), Ti(IV), Cu(II), Ni(II), or Zn(II).

285. A method of mitigating excessive swelling and preserving structural integrity of a swelling clay, the method comprising contacting the swelling clay with a siderophore.

286. The method of claim 285, wherein the siderophore is pyoverdine.

287. The method of claim 285 or 286, further comprising contacting the reactive clay mineral with potassium chloride.

288. The method of any one of claims 285-287, wherein the swelling clay comprises smectite or montmorillonite.

289. A composition comprising a siderophore and potassium chloride.

290. The composition of claim 289, wherein the siderophore is pyoverdine.Attorney Docket No. 66122-711.601291. The composition of claim 289 or 290, wherein the potassium chloride is an amount of about 3.5%.

292. The composition of any one of claims 289-291, wherein the composition is a solution.

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