Oxidizers for carbon dioxide-based fracturing fluids

Information

  • Patent Grant
  • 11499090
  • Patent Number
    11,499,090
  • Date Filed
    Wednesday, July 22, 2020
    3 years ago
  • Date Issued
    Tuesday, November 15, 2022
    a year ago
Abstract
A method for treating kerogen in a subterranean zone which includes the use of supercritical carbon dioxide or emulsions of liquid carbon dioxide and an aqueous fluid. The carbon dioxide or emulsions can further include oxidizers. The oxidizers can include inorganic oxidizers or organic oxidizers, for example an oxidizer including an organic cation and an oxidizing anion. Additional additives such as polymers, crosslinkers, clay inhibitors, scale inhibitors and corrosion inhibitors can further enhance the efficiency of the kerogen-treating carbon dioxide or emulsion.
Description
TECHNICAL FIELD

This document relates to methods and compositions used in treating subterranean formations for enhancing hydrocarbon fluid recovery.


BACKGROUND

Unconventional source rock reservoirs differ from conventional reservoirs due to the presence of the hydrocarbon source material, that is, a Total Organic Content (TOC) including kerogen, bitumen and other organics. Kerogen is an irregular organic material that often represents 5 to 10 percent by weight (wt %) (10 to 20 percent by volume (vol %)) of a sedimentary source rock formation. In source rock formations, clay and non-clay minerals are woven and compacted together with the kerogen to form a complex hierarchical structure with mechanical and physical parameters similar to other porous natural materials. The polymeric nature of kerogen with its chemomechanical characteristics interwoven with the granular material results in a problematic role that these composite materials play, first in increasing the tensile strength resistance generated during hydraulic fracturing, and second in masking the capacity of the fracture faces to communicate with the main fracture. The interwoven polymer characteristics of kerogen present a challenge that needs to be addressed in optimizing hydraulic fracturing operations and the overall formation productivity.


Early developments in hydraulic fracturing have resulted in fracturing fluids with additives such as polymers or crosslinkers or both. These viscosified fracturing fluids were designed to move and evenly distribute proppant in the main fracture, while other additives, such as polymer breakers, biocides, clay swelling inhibitors, and scale inhibitors, were added to improve the hydraulic fracturing operations. Additionally, slickwater systems have been developed for stimulating unconventional formations. Slickwater incorporates a friction-reducing synthetic polymer, which increases the rate at which stimulation fluids may be pumped. Fracturing fluids incorporating gas or other components to reduce or eliminate water altogether are also used in fracturing operations.


SUMMARY

This disclosure describes organic and inorganic oxidizers for carbon dioxide (CO2)-based hydraulic fracturing fluids.


In some implementations, a method for treating kerogen or organic matter in a subterranean zone includes placing a composition in the subterranean zone. The composition includes carbon dioxide and a fluid including an oxidizer. The fluid is an aqueous fluid. The composition includes an emulsion of carbon dioxide and the aqueous fluid.


In some implementations, a composition for treating kerogen in a subterranean zone includes carbon dioxide and a fluid including an oxidizer. The fluid is an aqueous fluid. The composition includes an emulsion of carbon dioxide and the aqueous fluid.


In some implementations, a method of making a hydraulic fracturing fluid includes adding a quantity of a composition to a hydraulic fracturing fluid. The composition includes carbon dioxide and a fluid including an oxidizer. The fluid is an aqueous fluid. The composition includes an emulsion of carbon dioxide and aqueous fluid. The method further includes mixing the hydraulic fracturing fluid and the composition.


In some implementations, a method of making a kerogen breaking composition includes reacting two or more salts to form a composition with an organic cation and an oxidizing anion, and adding the composition to carbon dioxide (CO2).


The following units of measure have been mentioned in this disclosure:
















Unit of Measure
Full form









mL
milliliter



uL
microliter



mmol
millimole



g
gram



kDa
kilodalton



cm
centimeter



h
hour



° C.
degree Celsius



M.P.
melting point










The details of one or more implementations of the disclosure are set forth in the accompanying drawings and the description that follows. Other features, objects, and advantages of the disclosure will be apparent from the description and drawings, and from the claims.





DESCRIPTION OF DRAWINGS


FIG. 1 shows example structures of butylammonium cations.



FIG. 2 shows example structures of organic cations.



FIG. 3 shows an example of a fracture treatment for a well.



FIG. 4 is a flow chart of an example method for treating a well.





Like reference symbols in the various drawings indicate like elements.


DETAILED DESCRIPTION

Reference will now be made in detail to certain implementations of the disclosed subject matter, examples of which are illustrated in part in the accompanying drawings. While the disclosed subject matter will be described in conjunction with the enumerated claims, it will be understood that the exemplified subject matter is not intended to limit the claims to the disclosed subject matter.


Provided in this disclosure, in part, are methods, compositions, and systems for degrading organic matter, such as kerogen, in a subterranean formation. Implementations of the disclosure include reactive fluids that can break down the polymeric nature of the kerogen and other organic matter on the hydraulic fracture faces. Water-based fracturing fluids with a reactive nature, which were previously developed for source rock reservoirs, have now been extended to CO2-based systems. A synthetic strategy was developed where oxidizing anions are paired with organic cations that render the oxidizing compounds soluble or dispersible in CO2 while still being reactive towards kerogen. Implementing the strategy can enhance the hydraulic conductivity and formation communication with the main fracture. In this manner, implementations of the disclosure can optimize hydraulic fracturing and overall formation productivity in unconventional source rock reservoirs. Further, these methods, compositions, and systems allow for increased hydraulic fracturing efficiencies in subterranean formations, such as unconventional rock reservoirs.


In some implementations, hydraulic fracturing is performed using a hydraulic fracturing fluid that includes supercritical CO2 or liquid CO2.


This disclosure describes reactive compounds, for example, synthetic oxidizers, which are both soluble in supercritical CO2 or liquid CO2 and capable of degrading organic material such as kerogen. The oxidizers can be directly soluble in CO2 or dispersed in it as droplet or slurry. The oxidizers include both inorganic and organic oxidizers.


In some implementations, these oxidizers include chlorate or bromate which are known to degrade kerogen in combination with organic cations that render the compound soluble or dispersible in CO2.


In some implementations, oxidizers capable of degrading kerogen can be present in an emulsion of aqueous fluid with liquid CO2. The process of making an emulsion of a water-in-CO2 or CO2-in-water containing oxidizers involves dissolving the oxidizer in either water or CO2, providing an emulsifier/surfactant at 0.01 to 2 wt %, followed by introduction of the other solvent (water if the initial solvent was CO2). The oxidizer should be soluble or dispersible in the first phase of the mixing process (for example, sodium bromate in water).


Examples of surfactants suitable for creating emulsions include perfluoropolyethers, polysorbates, and other cationic and anionic surfactants. For example, water-in-CO2 emulsions can be formed by perfluoropolyether ammonium carboxylate surfactants with molecular weights of 500 to 10,000 Da, for example, compounds with the general formula CF3—(O—CF2—CF(CF3))n—(O—CF2)—COONH4+. These surfactants are highly soluble in CO2 (>5 wt %) and less soluble in water (<0.01 wt %).


In another example, beta-lactoglobulin can form CO2-in-water emulsions at pressures between 40-100 bar.


Polysorbates such as polysorbate 80 can be used to form CO2-in-water and water-in-CO2 emulsions. At pressures up to 250 bar and temperatures between 25-60° C., CO2-in-water emulsions are formed for water concentrations at or greater than 10%. On the addition of NaCl or other inorganic salts, the surfactant partitions away from water towards CO2 and water-in-CO2 emulsions are formed. Other cationic-anionic surfactants can be used to form water-in-CO2 emulsions, such as [C6F13methylimidazolium][C6F13S], [C5F11methylimidazolium][C5F11S], [C6F13methylimidazolium][(CF3)3S]. C6F13methylimidazolium, C5F11methylimidazolium, [C6F13S], [C5F11S] and [(CF3)3S] are shown in Table 1, where the abbreviation “mim” represents methylimidazolium.









TABLE 1





Chemical Structures of Surfactant Ions
















[C6F13S]


embedded image







[C5F11S]


embedded image







[(CF3)3S]


embedded image







[C6F13mim]


embedded image







[C5F11mim]


embedded image











Other surfactants that are used to form water-in supercritical CO2 microemulsions are sodium 1-oxo-1-[4-(perfluorohexyl)phenyl]hexane-2-sulfonate and 1-oxo-1-[4-(hexyl)phenyl]-2-hexanesulfonates.


In some implementations, an emulsion of aqueous fluid and liquid CO2 can include the aqueous fluid as the internal phase and the liquid CO2 as the external phase. The emulsion can include hydrophobic particles, including but not limited to particles of polytetrafluoroethylene, carbon black, or pulverized coal, where the hydrophobic particles stabilize the emulsion.


In some implementations, an emulsion of aqueous fluid and liquid CO2 can include the liquid CO2 as the internal phase and the aqueous fluid as the external phase. The emulsion can include hydrophilic particles including but not limited to limestone, silica, fly ash, shale, or magnesium silicate to stabilize the emulsion. The compositions described within this disclosure can be used as a kerogen control material to break down, dissolve, or remove all or parts of the kerogen in or near the areas to be hydraulically fractured in a subterranean formation. Using a composition described within this disclosure, the kerogen or other organic matter (or both) can be broken down by, for example, pumping the composition into a subterranean formation.


The compounds soluble in CO2 include oxidizers. The oxidizers can include organic cations and oxidizing anions. For example, organic cations include but are not limited to ammonium (NH4+) substituted with methyl, ethyl, propyl, hexadecyl and phenyl groups, and butylammonium cations, such as BuNH3+, Bu2NH2+, Bu3NH+ and Bu4N+. FIG. 1 shows some example structures from the butylammonium cations, including unsubstituted NH4+ (FIG. 1A), BuNH3+ (FIG. 1B), Bu2NH2+ (FIG. 1C), Bu3NH+ (FIG. 1D) and Bu4N+ (FIG. 1E). Other organic cations suitable for pairing with oxidizing anions include tetraphenylphosphinium [Ph4P]+, bis(triphenylphosphine)iminium [PPN]+, pyridinium [Pyr]+, pyrrolidinium [Pyrr]+, and imidazolium [Im]+. FIG. 2 shows some example structures of these organic cations, including tetraphenylphosphinium [Ph4P]+ (FIG. 2A), bis(triphenylphosphine)iminium [PPN]+ (FIG. 2B), pyridinium [Pyr]+ (FIG. 2C), pyrrolidinium [Pyrr]+ (FIG. 2D), and imidazolium [Im]+ (FIG. 2E). These organic cations can also be further substituted, with additional functional groups, for example, 1-butyl-3-methyl-imidazolium [BMIm]+. In addition, the organic cations can be partially or fully fluorinated. Suitable oxidizing anions include but are not limited to chlorate and bromate.


In addition, compounds soluble in CO2 include organic peroxides, such as hydroperoxides, peroxy acids and esters, diacyl peroxides, and dialkylperoxides.


The compounds soluble in water include aqueous oxidizers including, for example, sodium bromate, potassium bromate, sodium chlorate, potassium chlorate, sodium chlorite, potassium chlorite, sodium perchlorate, potassium perchlorate, sodium persulfate, ammonium persulfate, potassium persulfate, sodium perborate, potassium perborate, sodium percarbonate, potassium percarbonate, sodium hypochlorite, potassium hypochlorite, sodium nitrite, potassium nitrite, ammonium nitrite, sodium nitrate, potassium nitrate, ammonium nitrate, calcium peroxide, magnesium peroxide, hydrogen peroxide, or any combination of them.


In addition, organic oxidizers as described in any of the other implementations can also be used in an emulsion with liquid CO2. The organic oxidizers as described in any of the other implementations can also be dissolved or dispersed in CO2, or dissolved or dispersed in a fluid including CO2.


Depending on the exact nature of the cation and anions combined, the resulting salt can be either a solid or liquid at room temperature.


The concentration of the components of the composition (for example, the oxidizers, ions, fine particles, or a combination of the same) can depend on the quantity of kerogen or other organic matter in the reservoir rock. For example, the concentration of the oxidizer in the composition can be increased for formations in response to the quantity of organic matter to be removed or partially removed.


The composition can also include other fracturing fluid additives including but not limited to polymer, crosslinker, surfactant, clay inhibitor, scale inhibitor, corrosion inhibitor.


Polymers can be added to viscosify the CO2. Suitable polymers include fluorinated or oxygenated polymers which can self-assemble or are crosslinked. In some implementations, polymers can be added at a concentration of 0.1-10 wt %. Crosslinkers can optionally be added based on the specific polymer used, and can be used to crosslink polymers to add more viscosity.


Surfactants in the composition can enhance flowback of fluid from the reservoir to the surface. Suitable surfactants include zwitterionic/amphoteric surfactants, for example betaine, phosphobetaine, and sultaine. Suitable surfactants also include cationic surfactants, for example quaternary ammonium compounds, anionic surfactants, for example alkyl sarcosinate or alkyl sulfonate, or non-ionic surfactants, for example amido amino oxides. In some implementations, surfactants are added at 0.01-2 wt %.


Clay inhibitors in the composition can prevent clay swelling in the presence of water. Clay inhibitors include quaternary ammonium compounds. As some of the oxidizers used in the composition include quaternary ammonium compounds (for example, tetramethylammonium bromate and tetramethylammonium chloride), the organic component of the oxidizers can serve as a clay inhibitor. Alternatively, the clay inhibitor may consist of a polyamine, quaternary ammonium compound, or alkali metal salt. In some implementations, clay inhibitors are added to the composition at 0-5 wt %, preferably 0-1 wt %.


Scale inhibitors in the composition can prevent precipitation of minerals in the formation as a result of the composition interacting with the rock and its native brine. Scale inhibitors include polyphosphates, phosphate esters, polyacrylic acid derivatives, and chelating agents, for example, EDTA. In some implementations, scale inhibitors are added to the composition at 0-5 wt %, preferably 0-1 wt %.


Corrosion inhibitors in the composition can prevent corrosion of well tubulars by the composition components, for example the oxidizers. Corrosion inhibitors include amides, imidazolines, salts of nitrogenous bases, nitrogen quaternaries, polyoxylated amines, polyoxylated amides, polyoxylated imidazolines, mercaptan modified products, nitrogen heterocyclics, carbonyl compounds, silicate-based inhibitors, and thioacetals. In some implementations, corrosion inhibitors can be added to the composition at 0-5 wt %, for example, 0-1 wt %.


The composition can further include a fracturing fluid or a pad fluid and can be pumped into a subterranean formation before fracturing, during fracturing, or both. In some implementations, the release of the composition including oxidizers can be delayed from a carrier fluid. Delaying the release of the composition from a carrier fluid can be accomplished by encapsulating the composition. In some implementations, the composition can be encapsulated with coatings through which the composition can be slow-released, for example, where the coating slowly degrades so that the encapsulated composition is released a fraction at a time, rather than all at once. Alternatively, or in addition, the coatings can break during fracture closure to release the composition. The composition can be a solid or a powder that can be encapsulated. A delayed release of the composition can decrease corrosion issues (for example, in metal tubing in the wellbore through which the fluids are delivered to the formation) and polymer degradation in the treating fluid. The polymers subject to degradation include, for example, friction reducers.


In some implementations, one or more fluids are placed in the subterranean zone, for example alternating between placing the composition and placing a second fluid.



FIG. 3 illustrates an example of a fracture treatment 10 for a well 12. The well 12 can be a reservoir or formation 14, for example, an unconventional reservoir in which recovery operations in addition to conventional recovery operations are practiced to recover trapped hydrocarbons.


The well 12 can include a well bore 20, casing 22 and well head 24. The well bore 20 can be a vertical or deviated bore.


For the fracture treatment 10, a work string 30 can be disposed in the well bore 20. A fracturing tool 32 can be coupled to an end of the work string 30. Packers 36 can seal an annulus 38 of the well bore 20 above and below the formation 14.


One or more pump trucks 40 can be coupled to the work string 30 at the surface 25. The pump trucks 40 pump fracture fluid 58 down the work string 30 to perform the fracture treatment 10 and generate the fracture 60. The fracture fluid 58 can include a fluid pad, proppants and/or a flush fluid.


One or more instrument trucks 44 can also be provided at the surface 25. The instrument truck 44 can include a fracture control system 46 and a fracture simulator 47. The fracture control system 46 monitors and controls the fracture treatment 10.


A quantity of energy applied by the fracture control system 46 to generate the fractures 60 in the reservoir or formation 14 can be affected not only by the properties of the reservoir rock in the formation but also by the organic matter (for example, kerogen 75) intertwined within the rock matrix. As discussed within this disclosure, kerogen in a reservoir can increase the tensile strength of the rock, for example, by as much as 100-fold, resulting in a corresponding increase in the ultimate tensile strength of the rock. The high modulus of toughness of the rock-kerogen combination compared to the rock alone can require a large quantity of energy to generate fractures in such a reservoir. Moreover, the presence of kerogen in the reservoir can affect production as well. For example, the rubber-like properties of elastomeric kerogen has a high elasticity, which can prematurely close fractures resulting in a decrease in production. Accordingly, the presence of kerogen in a subterranean formation can decrease an efficiency of hydraulic fracturing treatments.


This specification describes compositions 81 to degrade the kerogen encountered in subterranean formations, such as at the openings of cracks in hydraulic fractures. The compositions can include hydraulic fracturing fluids (for example, the fracture fluid 58) that are flowed through the subterranean formation (for example, a reservoir). As or after the kerogen is degraded, a quantity of energy to generate and propagate fractures in the subterranean formation (for example, a reservoir) can decrease, thereby increasing an efficiency (for example, cost, time, long-term effect) of the fracturing process. In addition, fracture length and formation surface exposure after wellbore shut-in can be greater than corresponding parameters in reservoirs in which the kerogen has not been degraded. In addition, removing or partially removing the kerogen and other organic matter from the near fracture zone can decrease the propensity for the fractures to close (reheal) after the pressure is released from pumping the fracturing, thereby improving the overall productivity of the well.


This application describes the creation of synthetic organic oxidizers that are soluble or dispersible in CO2. The synthetic alkylammonium bromates and chlorates described in this application can be created by a double displacement reaction of [RR′3N]2SO4 with BaXO3 to yield [RR′3N]XO3 and BaSO4 (R=alkyl, R′═H, alkyl, X═Br, Cl).


Example 1, Preparation of Tetrabutylammonium Bromate ([Bu4N]BrO3)

In a 250 mL Erlenmeyer flask, 0.9 g (2.29 mmol) of barium bromate (Ba(BrO3)2) were added to 100 mL of deionized water (DI H2O) and the mixture was stirred. To this mixture was added 2.66 g of a 50 wt % tetrabutylammonium sulfate solution (2.29 mmol). The mixture instantly turned a milky white. The mixture was stirred for 3 hours. The mixture was then allowed to stand for 20 hours. The mixture was then filtered to remove barium sulfate (BaSO4). The reaction yield of the product, [Bu4N]BrO3, was 1.66 g (99% yield). Infrared spectroscopy of the product revealed the following spectrum: wavenumber (υ), cm−1=2950 (vs), 2905 (vs), 2840 (vs), 2740 (w), 2100 (w, br), 1650 (s), 1480 (vs), 1385 (s) 1290 (w), 1250 (w), 1170 (m), 1100 (s) 1060 (s) 1020 (m), 880 (s), 800 (vs). Melting point analysis of the product revealed a melting point of 54° C. In the previous sentence, “vs,” “s,” “m,” “w,” “sh,” and “br” stand for very strong, strong, moderate, weak, sharp and broad, respectively.


Example 2, Preparation of Tributylammonium Bromate ([Bu3NH]BrO3)

In a 125 mL Erlenmeyer flask, 0.5 mL (2.1 mmol) of tributylamine was added to 20 mL of DI H2O. Next, 57 μL of 98% sulfuric acid (H2SO4) (1.1 mmol) was added to the mixture. Then, the mixture was sonicated for 5 minutes. The result was a tributylammonium sulfate solution. Separately, 0.42 g (1.1 mmol) of Ba(BrO3)2 were added to 80 mL of DI H2O. This mixture was sonicated for 5 minutes. The tributylammonium sulfate solution was then added rapidly to the Ba(BrO3)2 solution. The resulting mixture was sonicated for 30 minutes. Then the mixture was vacuum filtered twice to give a clear solution. Water was then removed under vacuum. The product, [Bu3NH]BrO3, was a colorless liquid at room temperature. Infrared spectroscopy of the product revealed the following spectrum: υ (cm−1)=3430 (m, br), 2960 (st), 2935 (m), 2873 (m), 1722 (vw), 1628 (m), 1460 (m), 1381 (w), 1066 (w), 786 (vs, sh), 768 (vs), 740 (s, sh).


Example 3, Preparation of Dibutylammonium Bromate ([Bu2NH2]BrO3)

In a 125 mL Erlenmeyer flask, 0.5 mL (3.3 mmol) of dibutylamine was added to 20 mL of DI H2O. To this mixture was added 88 uL of 98% H2SO4 (1.6 mmol). The resulting mixture was sonicated for 5 minutes, resulting in a dibutylammonium sulfate solution. Separately, 0.64 g (1.6 mmol) of Ba(BrO3)2 were added to 80 mL of deionized H2O and sonicated for 5 minutes. Then, the dibutylammonium sulfate solution was added rapidly to the Ba(BrO3)2 solution. The resulting mixture was sonicated for 30 minutes. Next, the mixture was vacuum filtered twice to give a clear solution. Water was removed from the solution under vacuum. The resulting product, [Bu2NH2]BrO3, is a colorless liquid at room temperature. Infrared spectroscopy of the product revealed the following spectrum: υ (cm−1)=3430 (m, br), 2960 (st), 2935 (m), 2873 (m), 1722 (vw), 1628 (m), 1617 (m), 1460 (m), 1381 (w), 1066 (w), 915 (w), 780 (vs), 727 (vs). Melting point analysis of the product revealed a melting point of 4° C.


Example 4, Preparation of Butylammonium Bromate, [BuNH3]BrO3

In a 125 mL Erlenmeyer flask, 0.33 mL (3.3 mmol) of butylamine were added to 20 mL of DI H2O. To this mixture was added 88 uL of 98% H2SO4, (1.6 mmol). The resulting mixture was sonicated for 5 minutes, to yield a butylammonium sulfate solution. Separately, 0.64 g (1.6 mmol) of Ba(BrO3)2 were added to 80 mL of DI H2O and sonicated for 5 minutes. Then, the butylammonium sulfate solution was rapidly added to the Ba(BrO3)2 solution. The resulting mixture was sonicated for 30 minutes and vacuum filtered twice to give a clear solution. Water was removed from the solution under vacuum. The yield of the product, [BuNH3]BrO3, was 0.65 g (97% yield). Infrared spectroscopy of the product revealed the following spectrum: υ (cm−1)=3041 (st, br), 2960 (st), 2935 (m), 2875 (m), 1606 (m), 1600 (m), 1570 (s), 1174 (m), 1077 (m), 915 (m), 830 (s), 768 (vs), 757 (vs).


Example 5, Preparation of Tetrabutylammonium Chlorate ([Bu4N]ClO3)

In a 250 mL Erlenmeyer flask, 0.76 g (2.29 mmol) of barium chlorate (Ba(ClO3)2) was added to 100 mL of DI H2O and the mixture was stirred. To this mixture was added 2.66 g of a 50 wt % tetrabutylammonium sulfate solution (2.29 mmol). The mixture instantly turned a milky white. The mixture was stirred for 3 hours. Then, the mixture was allowed to stand for 20 hours. The mixture was then filtered to remove the BaSO4. The yield of the product, [Bu4N]ClO3, was 0.73 g (98% yield). Infrared spectroscopy of the product revealed the following spectrum: υ(cm−1)=2960 (m), 2935 (m), 2875 (m), 1476 (w), 1472 (w), 1381 (w), 1650 (s), 954 (vs), 930 (vs), 881 (m), 800 (w), 740 (m). Melting point analysis revealed a melting point of 116-118° C.


Example 6, Preparation of bis(Triphenylphosphine)iminium Bromate ([PPN]BrO3)

In a 120 mL glass tube, 4.0 g (26.5 mmol) of sodium bromate (NaBrO3) were dissolved in 30 mL of DI H2O. To this solution was added 1.0 g (1.86 mmol) of bis(triphenylphosphine)iminium chloride and the solution was heated at 100° C. for 15 minutes without stirring. Over the course of this time, a liquid formed and collected at the bottom of the tube. Upon cooling, this material crystallized and was isolated by filtration. Recrystallization of this material in 15 mL of DI H2O yielded 0.88 g of the product, [PPN]BrO3 (71% yield). Infrared spectroscopy of the product revealed the following spectrum: IR (cm−1), υ=3170 (w) 3150 (w) 3040 (s) 3010 (s), 2990 (s) 2700 (w) 2600 (w) 2230 (w) 2100 (w), 2080 (w), 2050 (w) 2000 (w), 1900 (w), 1830 (w), 1800 (w), 1780 (w) 1670 (w) 1600 (vs), 1480 (vs), 1420 (vs) 1300 (vs, br), 1190 (vs) 1100 (vs), 1020 (vs), 1000 (vs) 930 (w), 840 (vs), 790 (vs). Melting point analysis revealed a melting point of 236-238° C.


Example 7, Preparation of Pyridinium Bromate, ([PyrH]BrO3)

First, 0.5 mL (6.6 mmol) of pyridine was added to 10 mL of DI H2O. Next, 180 uL of concentrated H2SO4 (18.4 M) was added to the solution. The solution was stirred for two hours. This solution was then added to a second solution of 1.3 g (3.3 mmol) of Ba(BrO3)2 in 120 mL of water. The resulting mixture was sonicated for two hours. Then, the mixture was allowed to settle and was vacuum filtered. The water was removed with a rotary evaporator. The product, [PyrH]BrO3, was a colorless liquid. The yield of the product was 1.36 g (98% yield).



FIG. 4 is a flowchart of an example of a process 200 for degrading kerogen in a subterranean zone. The process can be implemented using different types of hydraulic fracturing fluids, for example, fracturing fluid including aqueous oxidizers, with or without proppant; fracturing fluids including organic oxidizers, with or without proppant; fracturing fluids including an emulsified oxidizer, with or without proppant; fracturing fluid including aqueous, organic, or emulsified oxidizers pumped with nanoproppant; or fracturing fluid including aqueous, organic, or emulsified oxidizers pumped with degradable nanoparticles such as poly(lactic acid) (PLA) or poly(glycolic acid) (PGA). At 201, a kerogen- and organic matter-degrading composition (for example, a composition including an oxidizer, such as an alkylammonium bromate) is mixed with a fluid. The fluid can be a hydraulic fracture fluid or a pad fluid that is flowed into the reservoir before the hydraulic fracture fluid (or both). At 205, the fluid (with the kerogen- and organic matter-degrading composition) is flowed into the reservoir as part of a hydraulic fracture treatment. As described previously, the kerogen and organic matter degrade upon reacting with the composition. At 203, an additive, such as polymer, crosslinker, breaker, surfactant, scale inhibitor, corrosion inhibitor, or flowback aid, can be added to the mixture of the composition and the fluid before pumping the fluid into the reservoir at 205. Other potential additives include any material that is compatible with the kerogen- and organic matter-degrading composition.


The term “about” as used in this disclosure can allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.


The term “substantially” as used in this disclosure refers to a majority of, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.


The term “solvent” as used in this disclosure refers to a liquid that can dissolve a solid, another liquid, or a gas to form a solution. Non-limiting examples of solvents are silicones, organic compounds, water, alcohols, hydrocarbons, ionic liquids, and supercritical fluids.


The term “room temperature” as used in this disclosure refers to a temperature of about 15 degrees Celsius (° C.) to about 28° C.


The term “downhole” as used in this disclosure refers to under the surface of the earth, such as a location within or fluidly connected to a wellbore.


As used in this disclosure, the term “fracturing fluid” refers to fluids or slurries used downhole during fracturing operations.


As used in this disclosure, the term “fluid” refers to liquids and gels, unless otherwise indicated.


As used in this disclosure, the term “subterranean material” or “subterranean zone” refers to any material under the surface of the earth, including under the surface of the bottom of the ocean. For example, a subterranean zone or material can be any section of a wellbore and any section of a subterranean petroleum- or water-producing formation or region in fluid contact with the wellbore. Placing a material in a subterranean zone can include contacting the material with any section of a wellbore or with any subterranean region in fluid contact the material. Subterranean materials can include any materials placed into the wellbore such as cement, drill shafts, liners, tubing, casing, or screens; placing a material in a subterranean zone can include contacting with such subterranean materials. In some examples, a subterranean zone or material can be any downhole region that can produce liquid or gaseous petroleum materials, water, or any downhole section in fluid contact with liquid or gaseous petroleum materials, or water. For example, a subterranean zone or material can be at least one of an area desired to be fractured, a fracture or an area surrounding a fracture, and a flow pathway or an area surrounding a flow pathway, in which a fracture or a flow pathway can be optionally fluidly connected to a subterranean petroleum- or water-producing region, directly or through one or more fractures or flow pathways.


In some implementations, a method for treating kerogen or organic matter in a subterranean zone includes placing a composition in the subterranean zone. The composition includes carbon dioxide and a fluid including an oxidizer. The fluid is an aqueous fluid. The composition includes an emulsion of carbon dioxide and the aqueous fluid.


This aspect, taken alone or combinable with any other aspect, can include the following features. The method further includes alternating placing the composition in the subterranean zone with placing a second fluid in the subterranean zone.


This aspect, taken alone or combinable with any other aspect, can include the following features. The oxidizer includes a cation and an anion.


This aspect, taken alone or combinable with any other aspect, can include the following features. The anion includes at least one of chlorate or bromate.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation includes at least one of an ammonium ion, a butylammonium ion, a dibutylammonium ion, a tributyl ammonium ion, or a tetrabutylammonium ion.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation includes at least one of an ammonium ion substituted with alkyl or phenyl groups, bis(triphenylphosphine)iminium, or tetraphenylphosphinium.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation includes a cationic heterocycle.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cationic heterocycle is at least one of pyridinium, pyrrolidinium, pyrazolium, or imidazolium.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation is partially or fully fluorinated.


This aspect, taken alone or combinable with any other aspect, can include the following features. The external phase of the emulsion includes aqueous fluid and the internal phase of the emulsion includes carbon dioxide.


This aspect, taken alone or combinable with any other aspect, can include the following features. The emulsion includes hydrophobic particles to stabilize the emulsion.


This aspect, taken alone or combinable with any other aspect, can include the following features. The external phase of the emulsion includes carbon dioxide and the internal phase of the emulsion includes aqueous fluid.


This aspect, taken alone or combinable with any other aspect, can include the following features. The aqueous fluid includes an inorganic oxidizer.


This aspect, taken alone or combinable with any other aspect, can include the following features. The inorganic oxidizer includes at least one of bromate, chlorate, chlorite, persulfate, perborate, percarbonate, hypochlorite, nitrite, nitrate, perchlorate, or peroxide.


This aspect, taken alone or combinable with any other aspect, can include the following features. The emulsion includes an organic oxidizer.


This aspect, taken alone or combinable with any other aspect, can include the following features. The emulsion is stabilized by surfactants or particles.


This aspect, taken alone or combinable with any other aspect, can include the following features. The method further includes flowing the composition into the subterranean zone with a fracturing fluid.


This aspect, taken alone or combinable with any other aspect, can include the following features. The fracturing fluid includes at least one of a polymer, a crosslinker, a breaker, a surfactant, a scale inhibitor, a corrosion inhibitor, or a flowback aid.


This aspect, taken alone or combinable with any other aspect, can include the following features. The method further includes flowing the composition and the fracturing fluid with proppants.


This aspect, taken alone or combinable with any other aspect, can include the following features. The subterranean zone includes carbonate rock or sandstone rock that includes organic matter.


In some implementations, a composition for treating kerogen in a subterranean zone includes carbon dioxide and a fluid including an oxidizer. The fluid is an aqueous fluid. The composition includes an emulsion of carbon dioxide and the aqueous fluid.


This aspect, taken alone or combinable with any other aspect, can include the following features. The oxidizer includes a cation and an anion.


This aspect, taken alone or combinable with any other aspect, can include the following features. The anion includes at least one of chlorate or bromate.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation includes at least one of an ammonium ion, a butylammonium ion, a dibutylammonium ion, a tributyl ammonium ion, or a tetrabutylammonium ion.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation includes at least one of an ammonium ion substituted with alkyl, phenyl, or other groups, for example, bis(triphenylphosphine)iminium or tetraphenylphosphinium.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation includes at least one of pyridinium, pyrrolidinium, pyrazolium or imidazolium.


This aspect, taken alone or combinable with any other aspect, can include the following features. The cation is partially or fully fluorinated.


This aspect, taken alone or combinable with any other aspect, can include the following features. The external phase of the emulsion includes an aqueous fluid and an internal phase of the emulsion includes carbon dioxide.


This aspect, taken alone or combinable with any other aspect, can include the following features. The emulsion includes hydrophilic particles to stabilize the emulsion.


This aspect, taken alone or combinable with any other aspect, can include the following features. The aqueous fluid includes an inorganic oxidizer.


This aspect, taken alone or combinable with any other aspect, can include the following features. The inorganic oxidizer includes at least one of bromate, chlorate, chlorite, persulfate, perborate, percarbonate, hypochlorite, nitrite, nitrate, perchlorate, or peroxide.


This aspect, taken alone or combinable with any other aspect, can include the following features. The emulsion includes an organic oxidizer.


This aspect, taken alone or combinable with any other aspect, can include the following features. The emulsion includes surfactants.


In some implementations, a method of making a hydraulic fracturing fluid includes adding a quantity of a composition to a hydraulic fracturing fluid. The composition includes carbon dioxide and a fluid including an oxidizer. The fluid is an aqueous fluid. The composition includes an emulsion of carbon dioxide and aqueous fluid. The method further includes mixing the hydraulic fracturing fluid and the composition.


In some implementations, a method of making a kerogen breaking composition includes reacting two or more salts to form a composition with an organic cation and an oxidizing anion, and adding the composition to carbon dioxide.


As used in this disclosure, “treatment of a subterranean zone” can include any activity directed to extraction of water or petroleum materials from a subterranean petroleum- or water-producing formation or region, for example, including drilling, stimulation, hydraulic fracturing, clean-up, acidizing, completion, cementing, remedial treatment, abandonment, aquifer remediation, and identifying oil rich regions via imaging techniques.


As used in this disclosure, a “flow pathway” downhole can include any suitable subterranean flow pathway through which two subterranean locations are in fluid connection. The flow pathway can be sufficient for petroleum or water to flow from one subterranean location to the wellbore or vice-versa. A flow pathway can include at least one of a hydraulic fracture, and a fluid connection across a screen, across gravel pack, across proppant, including across resin-bonded proppant or proppant deposited in a fracture, and across sand. A flow pathway can include a natural subterranean passageway through which fluids can flow. In some implementations, a flow pathway can be a water source and can include water. In some implementations, a flow pathway can be a petroleum source and can include petroleum. In some implementations, a flow pathway can be sufficient to divert water, a downhole fluid, or a produced hydrocarbon from a wellbore, fracture, or flow pathway connected to the pathway.


As used in this disclosure, “weight percent” (wt %) can be considered a mass fraction or a mass ratio of a substance to the total mixture or composition. Weight percent can be a weight-to-weight ratio or mass-to-mass ratio, unless indicated otherwise.


As used in this disclosure, “volume percent” (vol %) can be considered a volume fraction or a volume ratio of a substance to the total mixture or composition.


A number of implementations of the disclosure have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.

Claims
  • 1. A method for treating kerogen or organic matter in a subterranean zone, the method comprising placing a composition in the subterranean zone, the composition comprising: supercritical carbon dioxide (CO2); anda fluid comprising an oxidizer, wherein the fluid is an aqueous fluid, and wherein the composition comprises an emulsion of supercritical carbon dioxide and the aqueous fluid, wherein the supercritical carbon dioxide and the fluid comprising the oxidizer are mixed to form the emulsion before placing the composition in the subterranean zone,wherein the oxidizer comprises a cation and an anion, and the cation comprises a fluorinated organic cation.
  • 2. The method of claim 1, further comprising alternating placing the composition in the subterranean zone with placing a second fluid in the subterranean zone.
  • 3. The method of claim 1, wherein the anion comprises at least one of chlorate or bromate.
  • 4. The method of claim 1, wherein the cation comprises at least one of an ammonium ion, a butylammonium ion, a dibutylammonium ion, a tributyl ammonium ion, or a tetrabutylammonium ion.
  • 5. The method of claim 1, wherein the cation comprises at least one of: an ammonium ion substituted with alkyl or phenyl groups; bis(triphenylphosphine)iminium; or tetraphenylphosphinium.
  • 6. The method of claim 1, where the cation comprises a cationic heterocycle.
  • 7. The method of claim 6, wherein the cationic heterocycle is at least one of pyridinium, pyrrolidinium, pyrazolium, or imidazolium.
  • 8. The method of claim 1, wherein an external phase of the emulsion comprises the aqueous fluid and an internal phase of the emulsion comprises the supercritical CO2.
  • 9. The method of claim 1, wherein the emulsion comprises hydrophobic particles to stabilize the emulsion.
  • 10. The method of claim 1, wherein an external phase of the emulsion comprises the supercritical CO2 and an internal phase of the emulsion comprises the aqueous fluid.
  • 11. The method of claim 1, wherein the aqueous fluid comprises an inorganic oxidizer.
  • 12. The method of claim 11, wherein the inorganic oxidizer comprises at least one of bromate, chlorate, chlorite, persulfate, perborate, percarbonate, hypochlorite, nitrite, nitrate, perchlorate, or peroxide.
  • 13. The method of claim 1, wherein the emulsion comprises an organic oxidizer.
  • 14. The method of claim 1, wherein the emulsion is stabilized by surfactants or particles.
  • 15. The method of claim 1, further comprising flowing the composition into the subterranean zone with a fracturing fluid.
  • 16. The method of claim 15, wherein the fracturing fluid comprises at least one of a polymer, a crosslinker, a breaker, a surfactant, a scale inhibitor, a corrosion inhibitor, or a flowback aid.
  • 17. The method of claim 15, further comprising flowing the composition and the fracturing fluid with proppants.
  • 18. The method of claim 1, wherein the subterranean zone comprises carbonate rock or sandstone rock comprising organic matter.
  • 19. The method of claim 1, wherein: the cation comprises a member selected from the group consisting of tetrabutylammonium bromate, tributylammonium bromate, dibutylammonium bromate, butylammonium bromate, tetrabutylammonium chlorate, bis(triphenylphosphine)iminium bromate, pyridinium bromate; andthe cation is made by a double displacement reaction.
  • 20. A method for treating kerogen or organic matter in a subterranean zone, the method comprising placing a composition in the subterranean zone, the composition comprising: supercritical carbon dioxide (CO2); anda fluid comprising an oxidizer, wherein the fluid is an aqueous fluid, and wherein the composition comprises an emulsion of carbon dioxide and the aqueous fluid, wherein an external phase of the emulsion comprises the supercritical CO2 and an internal phase of the emulsion comprises the aqueous fluid, and wherein the supercritical carbon dioxide and the fluid comprising the oxidizer are mixed to form the emulsion before placing the composition in the subterranean zone, wherein:the oxidizer comprises a cation and an anion;the anion comprises at least one of chlorate or bromate;the cation comprises a member selected from the group consisting of tetrabutylammonium bromate, tributylammonium bromate, dibutylammonium bromate, butylammonium bromate, tetrabutylammonium chlorate, bis(triphenylphosphine)iminium bromate, pyridinium bromate; andthe cation is made by a double displacement reaction.
  • 21. A method for treating kerogen or organic matter in a subterranean zone, the method comprising placing a composition in the subterranean zone, the composition comprising: supercritical carbon dioxide (CO2); anda fluid comprising an oxidizer, wherein the fluid is an aqueous fluid, and wherein the composition comprises an emulsion of supercritical carbon dioxide and the aqueous fluid, wherein the supercritical carbon dioxide and the fluid comprising the oxidizer are mixed to form the emulsion before placing the composition in the subterranean zone,wherein: the oxidizer comprises a cation and an anion;the cation comprises a member selected from the group consisting of tetrabutylammonium bromate, tributylammonium bromate, dibutylammonium bromate, butylammonium bromate, tetrabutylammonium chlorate, bis(triphenylphosphine)iminium bromate, pyridinium bromate; andthe cation is made by a double displacement reaction.
CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser. No. 62/878,060 filed on Jul. 24, 2019, the entire contents of which are incorporated by reference in its entirety.

US Referenced Citations (406)
Number Name Date Kind
701154 Cole May 1902 A
830437 Humphrey Sep 1906 A
2900269 Bauman et al. Aug 1959 A
3284281 Thomas Nov 1966 A
3316965 Watanabe May 1967 A
3456183 Codrington et al. Jul 1969 A
3616855 Colgate Nov 1971 A
3690622 Brunner Sep 1972 A
3716387 Simmons et al. Feb 1973 A
3807557 Miller Apr 1974 A
3834122 Allison et al. Sep 1974 A
3912330 Carnahan et al. Oct 1975 A
3926575 Meyers Dec 1975 A
3977472 Graham et al. Aug 1976 A
3996062 Frost Dec 1976 A
4043599 Lingane Aug 1977 A
4043885 Yen et al. Aug 1977 A
4047988 Weill Sep 1977 A
4108965 Christe Aug 1978 A
4195010 Russell et al. Mar 1980 A
4220550 Frenier et al. Sep 1980 A
4223726 Cha Sep 1980 A
4252189 Bodine Feb 1981 A
4289639 Buske Sep 1981 A
4324560 Fonseca Apr 1982 A
4381950 Lawson May 1983 A
4444058 Ratigan Apr 1984 A
4480696 Almond et al. Nov 1984 A
4485071 Larter Nov 1984 A
4493875 Beck et al. Jan 1985 A
4587739 Holcomb May 1986 A
4594170 Brown et al. Jun 1986 A
4629702 Fan et al. Dec 1986 A
4640692 Audeh Feb 1987 A
4681914 Olson et al. Jul 1987 A
4708805 D'Muhala Nov 1987 A
4718489 Hallam et al. Jan 1988 A
4780223 Baranet et al. Oct 1988 A
4830773 Olson May 1989 A
4830779 Maeno et al. May 1989 A
4864472 Yoshimura Sep 1989 A
4882128 Hukvari et al. Nov 1989 A
4887670 Lord et al. Dec 1989 A
5031700 McDougall et al. Jul 1991 A
5180556 Nolte et al. Jan 1993 A
5193396 Gorski Mar 1993 A
5199490 Surles et al. Apr 1993 A
5213705 Olson May 1993 A
5224543 Watkins Jul 1993 A
5232490 Bender et al. Aug 1993 A
5251286 Wiener et al. Oct 1993 A
5302297 Barthrope Apr 1994 A
5390529 Ghiselli Feb 1995 A
5435187 Ewy Jul 1995 A
5604184 Ellis et al. Feb 1997 A
5757473 Kanduth et al. May 1998 A
5759964 Shuchart Jun 1998 A
5869750 Onan Feb 1999 A
5999887 Giannakopoulos et al. Dec 1999 A
6076046 Vassudevan Jun 2000 A
6095679 Hammiche et al. Aug 2000 A
6131661 Conner et al. Oct 2000 A
6138760 Lopez et al. Oct 2000 A
6140816 Heron et al. Oct 2000 A
6143698 Murphey et al. Nov 2000 A
6165295 Wagaman Dec 2000 A
6227295 Mitchell et al. May 2001 B1
6349595 Lorenzo et al. Feb 2002 B1
6411902 Wiltshire Jun 2002 B1
6488091 Weaver Dec 2002 B1
6491425 Hammiche et al. Dec 2002 B1
6494263 Todd Dec 2002 B2
6516080 Nur Feb 2003 B1
6579572 Espin et al. Jun 2003 B2
6652682 Fawls Nov 2003 B1
6694262 Rozak Feb 2004 B2
6705398 Weng Mar 2004 B2
6715553 Reddy et al. Apr 2004 B2
6729409 Gupta et al. May 2004 B1
6749022 Fredd Jun 2004 B1
6776235 England Aug 2004 B1
6832158 Mese Dec 2004 B2
6846420 Reddy et al. Jan 2005 B2
6866048 Mattox Mar 2005 B2
6884760 Brand et al. Apr 2005 B1
6947843 Fisher et al. Sep 2005 B2
6989391 Funkhouser Jan 2006 B2
7007752 Reddy et al. Mar 2006 B2
7011154 Maher et al. Mar 2006 B2
7044220 Nguyen et al. May 2006 B2
7086484 Smith Aug 2006 B2
7098663 Bader Aug 2006 B1
7210528 Brannon et al. May 2007 B1
7255169 Van Batenburg et al. Aug 2007 B2
7261158 Middaugh et al. Aug 2007 B2
7281580 Parker et al. Oct 2007 B2
7281581 Nyuyen et al. Oct 2007 B2
7326670 DiLullo et al. Feb 2008 B2
7334635 Nguyen Feb 2008 B2
7334636 Nguyen Feb 2008 B2
7344889 Kelemen et al. Mar 2008 B2
7369980 Deffenbaugh et al. May 2008 B2
7424911 McCarthy et al. Sep 2008 B2
7451812 Cooper et al. Nov 2008 B2
7472748 Gdanski et al. Jan 2009 B2
7472751 Brannon et al. Jan 2009 B2
7491444 Smith et al. Feb 2009 B2
7500517 Looney et al. Mar 2009 B2
7513306 Pfefferle et al. Apr 2009 B2
7526418 Pita et al. Apr 2009 B2
7527097 Patel May 2009 B2
7565831 Miyahara Jul 2009 B2
7571767 Parker et al. Aug 2009 B2
7581590 Lesko et al. Sep 2009 B2
7588085 Acock et al. Sep 2009 B2
7621173 Hsu Nov 2009 B2
7642223 Santra et al. Jan 2010 B2
7645883 Hawkins et al. Jan 2010 B1
7654159 Enoksson Feb 2010 B2
7678723 Duenckel et al. Mar 2010 B2
7703531 Huang Apr 2010 B2
7770647 Watson et al. Aug 2010 B2
7771549 Christe et al. Aug 2010 B1
7789164 Looney et al. Sep 2010 B2
7803740 Bicerano et al. Sep 2010 B2
7825053 Duenckel et al. Nov 2010 B2
7857055 Li Dec 2010 B2
7867613 Smith et al. Jan 2011 B2
7878248 Abad et al. Feb 2011 B2
7887918 Smith et al. Feb 2011 B2
7918277 Brannon et al. Apr 2011 B2
7921911 Fuller et al. Apr 2011 B2
7983845 Minh Jul 2011 B2
8003212 Smith et al. Aug 2011 B2
8003577 Li et al. Aug 2011 B2
8006760 Fleming et al. Aug 2011 B2
8047288 Skala et al. Nov 2011 B2
8061424 Willberg et al. Nov 2011 B2
8066068 Lesko et al. Nov 2011 B2
8081802 Dvorkin et al. Dec 2011 B2
8104536 Looney et al. Jan 2012 B2
8119576 Reyes et al. Feb 2012 B2
8127850 Brannon et al. Mar 2012 B2
8146416 Pisio et al. Apr 2012 B2
8165817 Betancourt et al. Apr 2012 B2
8177422 Kjoller et al. May 2012 B2
8205675 Brannon et al. Jun 2012 B2
8216675 Palamara et al. Jul 2012 B2
8225866 Rouffignac et al. Jul 2012 B2
8278931 Fang et al. Oct 2012 B2
8352228 Walters et al. Jan 2013 B2
8380437 Abousleiman et al. Feb 2013 B2
8408305 Brannon et al. Apr 2013 B2
8473213 Zhu et al. Jun 2013 B2
8490700 Lesko et al. Jul 2013 B2
8606524 Soliman et al. Dec 2013 B2
8614157 Pope et al. Dec 2013 B2
8614573 Minh Dec 2013 B2
8616294 Zubrin et al. Dec 2013 B2
8636065 Lesko et al. Jan 2014 B2
8701788 Wigand et al. Apr 2014 B2
8729903 Srnka et al. May 2014 B2
8731889 Du et al. May 2014 B2
8757259 Lesko et al. Jun 2014 B2
8763699 Medvedev et al. Jul 2014 B2
8763703 Saini et al. Jul 2014 B2
8796187 Reyes et al. Aug 2014 B2
8821806 Hersherwitz et al. Sep 2014 B2
8822386 Quintero et al. Sep 2014 B2
8835363 Amanullah et al. Sep 2014 B2
8839860 Wigand et al. Sep 2014 B2
8844366 Warren Sep 2014 B2
8851177 Wigand Oct 2014 B2
8865482 Wang et al. Oct 2014 B2
8868385 Fertig et al. Oct 2014 B2
8883693 Eldred et al. Nov 2014 B2
8936083 Nguyen Jan 2015 B2
8936089 Wigand Jan 2015 B2
8967249 Akkurt et al. Mar 2015 B2
9006151 Amanullah et al. Apr 2015 B2
9006153 Lin et al. Apr 2015 B2
9033033 Thomas et al. May 2015 B2
9033043 Hinkel May 2015 B2
9046509 Dvorkin et al. Jun 2015 B2
9057797 Omeragic et al. Jun 2015 B2
9080440 Panga et al. Jul 2015 B2
9085727 Litvinets et al. Jul 2015 B2
9097818 Hursan Aug 2015 B2
9128210 Pomerantz Sep 2015 B2
9133398 Wigand et al. Sep 2015 B2
9152745 Glinsky Oct 2015 B2
9297244 Mahoney et al. Mar 2016 B2
9523268 Potapenko et al. Dec 2016 B2
9644137 Dean et al. May 2017 B2
9664018 Vandeponseele et al. May 2017 B2
9670764 Lesko et al. Jun 2017 B2
9688904 Wang et al. Jun 2017 B2
9696270 Roy et al. Jul 2017 B1
9725645 Monastiriotis et al. Aug 2017 B2
9753016 Daugela Sep 2017 B1
9784882 Vinegar et al. Oct 2017 B2
9816365 Nguyen et al. Nov 2017 B2
9834721 Chang et al. Dec 2017 B2
9845670 Surjaatadja et al. Dec 2017 B2
9863211 Gamage et al. Jan 2018 B2
9863230 Litvinets et al. Jan 2018 B2
9863231 Hull et al. Jan 2018 B2
9869649 Hull et al. Jan 2018 B2
9885691 Daugela Feb 2018 B1
9895670 Anders et al. Feb 2018 B2
9896919 Chen Feb 2018 B1
9902898 Nelson et al. Feb 2018 B2
9909404 Hwang et al. Mar 2018 B2
9927344 Chertov Mar 2018 B2
9945220 Saini et al. Apr 2018 B2
9995125 Madasu et al. Jun 2018 B2
9995220 Hawie et al. Jun 2018 B2
10001769 Huang et al. Jun 2018 B2
10023782 Wang et al. Jul 2018 B2
10030495 Litvinets et al. Jul 2018 B2
10047281 Nguyen et al. Aug 2018 B2
10066149 Li et al. Sep 2018 B2
10077396 Nguyen et al. Sep 2018 B2
10087364 Kaufman et al. Oct 2018 B2
10113396 Nelson et al. Oct 2018 B2
10151715 Hull et al. Dec 2018 B2
10273398 Liu et al. Apr 2019 B2
10329478 Schnoor et al. Jun 2019 B2
10351758 Hull et al. Jul 2019 B2
10379068 Hull et al. Aug 2019 B2
10415367 Galford Sep 2019 B2
10421897 Skiba et al. Sep 2019 B2
10472555 Hutchins et al. Nov 2019 B2
10479927 Hull et al. Nov 2019 B2
10550314 Liang et al. Feb 2020 B2
10611967 Inan Apr 2020 B2
20020003115 Conaway et al. Jan 2002 A1
20030209248 Ward Nov 2003 A1
20030212465 Howard et al. Nov 2003 A1
20040101457 Pahlman et al. May 2004 A1
20040211567 Aud Oct 2004 A1
20050039919 Harris et al. Feb 2005 A1
20050059558 Blauch Mar 2005 A1
20050060130 Shapiro et al. Mar 2005 A1
20050103118 Workman May 2005 A1
20050274523 Brannon et al. Dec 2005 A1
20060047489 Scheidt et al. Mar 2006 A1
20060092766 Shelley et al. May 2006 A1
20060265204 Wallis et al. Nov 2006 A1
20070054054 Svoboda et al. Mar 2007 A1
20070087940 Qu et al. Apr 2007 A1
20070203677 Awwiller Aug 2007 A1
20070235181 Lecampion et al. Oct 2007 A1
20070298979 Perry et al. Dec 2007 A1
20080006410 Looney et al. Jan 2008 A1
20080059140 Salmon et al. Mar 2008 A1
20080070806 Lin et al. Mar 2008 A1
20080081771 Lin et al. Apr 2008 A1
20080093073 Bustos et al. Apr 2008 A1
20080217012 Delorey Sep 2008 A1
20080234147 Li et al. Sep 2008 A1
20090032252 Boney et al. Feb 2009 A1
20090044945 Wilberg et al. Feb 2009 A1
20090071239 Rojas et al. Mar 2009 A1
20090087912 Ramos et al. Apr 2009 A1
20090143252 Lehmann Jun 2009 A1
20090145607 Li et al. Jun 2009 A1
20090193881 Finnberg Aug 2009 A1
20090203557 Barnes et al. Aug 2009 A1
20090242196 Pao Oct 2009 A1
20090248309 Nelville et al. Oct 2009 A1
20090253595 Qu Oct 2009 A1
20090283257 Becker Nov 2009 A1
20090313772 Talley Dec 2009 A1
20100010106 Crews Jan 2010 A1
20100044049 Leshchyshyn Feb 2010 A1
20100049625 Biebesheimer et al. Feb 2010 A1
20100051511 Faerman Mar 2010 A1
20100121623 Yogeswaren May 2010 A1
20100126936 Jones May 2010 A1
20100128982 Dvorkin et al. May 2010 A1
20100186520 Wheeler Jul 2010 A1
20100213579 Henry Aug 2010 A1
20100224365 Abad Sep 2010 A1
20100243242 Boney et al. Sep 2010 A1
20100243248 Golomb Sep 2010 A1
20100258265 Karanikas et al. Oct 2010 A1
20100263867 Horton et al. Oct 2010 A1
20100276142 Skildum et al. Nov 2010 A1
20100279136 Bonucci Nov 2010 A1
20100323933 Fuller et al. Dec 2010 A1
20110005969 Giffin Jan 2011 A1
20110065612 Stokes et al. Mar 2011 A1
20110257944 Du et al. Oct 2011 A1
20110259588 Ali Oct 2011 A1
20120018159 Gulta et al. Jan 2012 A1
20120026037 Thomson et al. Feb 2012 A1
20120129737 Lesko et al. May 2012 A1
20120160486 Wigand Jun 2012 A1
20120179444 Ganguly et al. Jul 2012 A1
20120193578 Pan et al. Aug 2012 A1
20120247774 Li et al. Oct 2012 A1
20120261129 Becker Oct 2012 A1
20120261617 Pan et al. Oct 2012 A1
20120267102 Huang et al. Oct 2012 A1
20120305247 Chen et al. Dec 2012 A1
20120318498 Parsche Dec 2012 A1
20130013209 Zhu et al. Jan 2013 A1
20130056213 Medvedev et al. Mar 2013 A1
20130084643 Commarieu et al. Apr 2013 A1
20130137610 Huang May 2013 A1
20130160994 Alsop et al. Jun 2013 A1
20130161002 Wigand Jun 2013 A1
20130161003 Mikhailovich et al. Jun 2013 A1
20130213120 Lebedev Aug 2013 A1
20130213638 Keller Aug 2013 A1
20130228019 Meadows Sep 2013 A1
20130231908 Williams et al. Sep 2013 A1
20130233536 Alqam Sep 2013 A1
20130238304 Glinsky Sep 2013 A1
20130269933 Pomerantz et al. Oct 2013 A1
20130274149 Lafitte et al. Oct 2013 A1
20130275099 Frydman Oct 2013 A1
20130306321 Lanctot-Downs et al. Nov 2013 A1
20130341028 Christian et al. Dec 2013 A1
20140008305 Nichols et al. Jan 2014 A1
20140027109 Al-Baraik Jan 2014 A1
20140045732 Mazyar Feb 2014 A1
20140048694 Pomerantz Feb 2014 A1
20140090850 Benicewicz Apr 2014 A1
20140096964 Chakraborty et al. Apr 2014 A1
20140116710 Naser-El-Din et al. May 2014 A1
20140221257 Roddy Aug 2014 A1
20140231077 Rivero et al. Aug 2014 A1
20140243246 Hendrickson Aug 2014 A1
20140247997 Nishyama Sep 2014 A1
20140251605 Hera Sep 2014 A1
20140260694 Szlendak Sep 2014 A1
20140364343 Nelson et al. Dec 2014 A1
20140367100 Oliveria et al. Dec 2014 A1
20140374104 Kushal Dec 2014 A1
20150019183 Suzuki Jan 2015 A1
20150041136 Martin Feb 2015 A1
20150055438 Yan et al. Feb 2015 A1
20150057097 Cho Feb 2015 A1
20150057196 Debord Feb 2015 A1
20150065398 Gartland et al. Mar 2015 A1
20150068749 Wernimont Mar 2015 A1
20150071750 Foster Mar 2015 A1
20150072902 Lafitte et al. Mar 2015 A1
20150075782 Sharma Mar 2015 A1
20150083405 Dobroskok Mar 2015 A1
20150083420 Gupta Mar 2015 A1
20150152724 Amendt Jun 2015 A1
20150167440 Kasevich Jun 2015 A1
20150192005 Saeedfar Jul 2015 A1
20150259593 Kaufman et al. Sep 2015 A1
20150284625 Silveira Oct 2015 A1
20150293256 Dusterhoft Oct 2015 A1
20150300140 Eoff et al. Oct 2015 A1
20150322759 Okoniewski Nov 2015 A1
20150368541 Monclin et al. Dec 2015 A1
20160017202 Yang et al. Jan 2016 A1
20160061017 Nguyen et al. Mar 2016 A1
20160103047 Liu Apr 2016 A1
20160103049 Liu Apr 2016 A1
20160130496 Holtsclaw et al. May 2016 A1
20160137904 Drake May 2016 A1
20160177674 Shetty et al. Jun 2016 A1
20160208591 Weaver et al. Jul 2016 A1
20160215202 Weaver et al. Jul 2016 A1
20160215205 Nguyen Jul 2016 A1
20160256583 Yamada Sep 2016 A1
20160265331 Weng et al. Sep 2016 A1
20160289543 Chang et al. Oct 2016 A1
20160362965 Parlar et al. Dec 2016 A1
20170015895 Cox Jan 2017 A1
20170051598 Ouenes Feb 2017 A1
20170066959 Hull Mar 2017 A1
20170066962 Ravi et al. Mar 2017 A1
20170067836 Hull et al. Mar 2017 A1
20170137703 Leverson et al. May 2017 A1
20170145303 Fontenelle et al. May 2017 A1
20170145793 Ouenes May 2017 A1
20170176639 Mosse et al. Jun 2017 A1
20170198207 Li et al. Jul 2017 A1
20170247997 Kovalevsky Aug 2017 A1
20170248011 Craddock et al. Aug 2017 A1
20170275525 Koep et al. Sep 2017 A1
20170328179 Dykatra et al. Nov 2017 A1
20170336528 Badri et al. Nov 2017 A1
20170370197 Han et al. Dec 2017 A1
20180112126 Yang et al. Apr 2018 A1
20180155602 Zhang Jun 2018 A1
20180155615 Rahy et al. Jun 2018 A1
20180195982 Hull et al. Jul 2018 A1
20180305208 Mason Oct 2018 A1
20180321416 Freedman Nov 2018 A1
20180355707 Herrera et al. Dec 2018 A1
20190010795 Cascio et al. Jan 2019 A1
20190017203 Andoh et al. Jan 2019 A1
20190078424 Copeland et al. Mar 2019 A1
20190211658 Hull et al. Jul 2019 A1
20190292436 Mason et al. Sep 2019 A1
20190345377 Haque et al. Nov 2019 A1
20200048531 Hull et al. Feb 2020 A1
Foreign Referenced Citations (60)
Number Date Country
2322118 Dec 2007 CA
2635868 Dec 2008 CA
101819111 Dec 2011 CN
1621803 May 2012 CN
103387827 Nov 2013 CN
102183410 May 2014 CN
104727799 Jun 2015 CN
105445440 Mar 2016 CN
105567213 May 2016 CN
0247669 Dec 1987 EP
0460927 Nov 1991 EP
2480625 Apr 2013 EP
2480626 Apr 2013 EP
2161269 Aug 1988 GB
WO 1997028098 Aug 1997 WO
WO 2000060379 Oct 2000 WO
WO 2001094749 Dec 2001 WO
WO 2002064702 Aug 2002 WO
WO 2004005435 Jan 2004 WO
WO 2008001218 Jan 2008 WO
WO 2010138914 Dec 2010 WO
WO 2011035292 Mar 2011 WO
WO 2011035294 Mar 2011 WO
WO 2012051647 Apr 2012 WO
WO 2012057910 May 2012 WO
WO 2012087887 Jun 2012 WO
WO 2012087898 Jun 2012 WO
WO 2012104582 Aug 2012 WO
WO 2012122505 Sep 2012 WO
WO 2012171857 Dec 2012 WO
WO 2013052359 Apr 2013 WO
WO 2013112114 Aug 2013 WO
WO 2013149122 Oct 2013 WO
WO 2013154926 Oct 2013 WO
WO 2013155061 Oct 2013 WO
WO 2014008496 Jan 2014 WO
WO 2014008598 Jan 2014 WO
WO 2014123672 Aug 2014 WO
WO 2014178504 Nov 2014 WO
WO 2015041664 Mar 2015 WO
WO 2015041669 Mar 2015 WO
WO 2015071750 May 2015 WO
WO 2015097116 Jul 2015 WO
WO 2015126082 Aug 2015 WO
WO 2015163858 Oct 2015 WO
WO 2015181028 Dec 2015 WO
WO 2015200060 Dec 2015 WO
WO 2016089813 Jun 2016 WO
WO 2016094153 Jun 2016 WO
WO 2017035371 Mar 2017 WO
WO 2017040824 Mar 2017 WO
WO 2017040834 Mar 2017 WO
WO 2017065331 Apr 2017 WO
WO 2017086975 May 2017 WO
WO 2017136641 Aug 2017 WO
WO 2017161157 Sep 2017 WO
WO 2018025010 Feb 2018 WO
WO 2018045290 Mar 2018 WO
WO 2018118024 Jun 2018 WO
WO 2018170065 Sep 2018 WO
Non-Patent Literature Citations (280)
Entry
Kotai et al., Beliefs and Facts in Permanganate Chemistry—An Overview on the Synthesis and the Reactivity of Simple and Complex Permanganates, 2009, Trends in Inorganic Chemistry, vol. 11 (Year: 2009).
“Hydraulic Fracturing Fluid Product Component Information Disclosure,” 2012, 2 pages.
Abad et al., “Evaluation of the Material Properties of the Multilayered Oxides formed on HCM12A using New and Novel Techniques,” Manuscript Draft, Manuscript No. OXID-D-15-00019, 2015, 44 pages.
Abass et al., “Wellbore Instability of Shale Formation, Zuluf Field, Saudi Arabia,” Society of Petroleum Engineers (SPE), presented at the SPE Technical Symposium on Saudi Arabia Section, Dhahran, Saudi Arabia, May 21-23, 2006, 10 pages.
Abousleiman and Nguyen, “Poromechanics Response of Inclined Wellbore Geometry in Fractured Porous Media,” Journal of Engineering Mechanics, ASCE, Nov. 2005, 131:11, 14 pages.
Abousleiman et al, “A Micromechanically Consistent Poroviscoelasticity Theory for Rock Mechanics Applications,” Int. J. Rock Mech. Min. Sci. & Geomech. Abstr., 1993, 30:7 (1177-1180), 4 pages.
Abousleiman et al, “Anisotropic Porothermoelastic Solution and Hydro-Thermal Effects on Fracture Width in Hydraulic Fracturing,” International Journal for Numerical and Analytical Methods in Geomechanics, 2013, 25 pages.
Abousleiman et al, “Geomechanics Field and Laboratory Characterization of Woodford Shale: The Next Gas Play,” SPE 110120, Society of Petroleum Engineers (SPE), presented at the 2007 SPE Annual Technical Conference and Exhibition on Nov. 11-14, 2007, 14 pages.
Abousleiman et al, “Poroviscoelastic Analysis of Borehole and Cylinder Problems,” ACTA Mechanica, 1996, 119: 199-219, 21 pages.
Abousleiman et al, “The Granular and Polymer Nature of Kerogen Rich Shale,” Acta Geotechnica 2016, 11:3 (573-594), 24 pages.
Abousleiman et al., “GeoGenome Industry Consortium(G2IC),” JIP, 2004-2006, 6 pages.
Abousleiman et al., “GeoMechanics Field Characterization of the Two Prolific U.S. Mid-West Gas Plays with Advanced Wire-Line Logging Tools,” SPE 124428, Society of Petroleum Engineers (SPE), presented at the 2009 SPE Annual Technical Conference and Exhibition, Oct. 4-7, 2009, 19 pages.
Abousleiman et al., “Geomechanics Field Characterization of Woodford Shale and Barnett Shale with Advanced Logging Tools and Nano-indentation on Drill Cuttings,” The Leading Edge, Special Section: Borehole Geophysics, Jun. 2010, 6 pages.
Abousleiman et al., “Mandel's Problem Revisited,” Geotechnique, 1996, 46:2 (187-195), 9 pages.
Abousleiman et al., “Mechanical Characterization of Small Shale Samples subjected to Fluid Exposure using the Inclined Direct Shear Testing Device,” International Journal of Rock Mechanics and Mining Sciences, 2010, 47:3 (355-367), 13 pages.
Abousleiman et al., “Modeling Real-Time Wellbore Stability within the Theory of Poromechanics,” AADE-03-NTCE-11, American Association of Drilling Engineers (AADE), presented at the AADE 2003 National Technology Conference, Practical Solutions for Drilling Challenges, Texas, Apr. 1-3, 2003, 14 pages.
Abousleiman et al., “Poroelastic Solutions in Transversely Isotropic Media for Wellbore and Cylinder,” Int. J. Solids Structures, 1998, 35:34-35 (4905-4929), 25 pages.
Abousleiman et al., “Time-Dependent wellbore (in)stability predictions: theory and case study,” IADC/SPE 62796, International Association of Drilling Contactors (IADC), Society of Petroleum Engineers (SPE), presented at the 2000 IADC/SPE Asia Pacific Drilling Technology held in Kuala Lumur, Malaysia, Sep. 11-13, 2000, 8 pages.
Agenet et al., “Fluorescent Nanobeads: a First Step Toward Intelligent Water Tracers,” SPE 157019, Society of Petroleum Engineers (SPE), SPE International Oilfield Nanotechnology Conference, Jun. 12-14, 2012, 13 pages.
Agilent Technologies, “Field-Deployable Solution for Nanoporosity Measurements in Mud Logging Operations and a Novel Method for Fracability Analysis Using Mud Cuttings,” Gulf Coast Conference, Agilent Restricted, Oct. 2013, 44 pages.
Ahmed et al. “7.2.2 Information Required to Move to a Pilot Project,” Unconventional Resources Exploitation and Development, 2016, 1 page.
Allan et al., “A Multiscale Methodology for the Analysis of Velocity Anisotropy in Organic-Rich Shale,” Geophysics, Jul.-Aug. 2015, 80:4 (C73-C88), 16 pages.
Al-Munthasheri, “A Critical Review of Hydraulic Fracturing Fluids over the Last Decade,” SPE 169552, Society of Petroleum Engineers (SPE), presented at the SPE Western North American and Rocky Mountain Joint Regional Meeting, Apr. 16-18, 2014, 25 pages.
Altowairqi, “Shale elastic property relationships as a function of total organic carbon content using synthetic samples,” Journal of Petroleum Science and Engineering, Sep. 2015, 133: 392-400, 9 pages.
Ananthan et al., “Influence of Strain Softening on the Fracture of Plain Concrete Beams,” International Journal of Fracture, 1990, 45: 195-219, 25 pages.
Anisimov, “The Use of Tracers for Reservoir Characterization,” SPE 118862, Society of Petroleum Engineers (SPE), presented at SPE Middle East Oil and Gas Show and Conference, Mar. 15-18, 2009, 8 pages.
Arns et al., “Computation of linear elastic properties from microtomographic images: Methodology and agreement between theory and experiment,” Geophysics, Sep. 1, 2002, 67:5 (1396-1405), 10 pages.
Aslan et al., “Fluorescent Core—Shell AG@SiO2 Nanocomposites for Metal-Enhanced Fluorescence and Single Nanoparticle Sensing Platforms,” American Checmial Society (ACS), J. Am. Chem. Soc., JACS Communications, Jan. 19, 2007, 129: 1524-1525, 2 pages.
Atarita et al., “Predicting Distribution of Total Organic Carbon (TOC) and S2 with Δ Log Resistivity and Acoustic Impedance Inversion on Talang Akar Formation, Cipunegara Sub Basin, West Java,” Procedia Engineering, 2017, 170: 390-397, 8 pages.
Ballice, “Solvent Swelling Studies of Goynuk (Kerogen Type-I) and Beypazari Oil Shales (Kerogen Type-II),” Science Direct, 2003, Fuel 82: 1317-1321, 5 pages.
Barati and Liang, “A Review of Fracturing Fluid Systems Used for Hydraulic Fracturing of Oil and Gas Wells,” Journal of Applied Polymer Science, Aug. 15, 2014, 131:16, 11 pages.
Barenblatt et al., “Basic Concepts in the Theory of Seepage of Homogeneous Liquids in Fissured Rocks (Strata),” PMM 1960, 24:5 (852-864), 18 pages.
Bazant et al., “Deformation of Progressively Cracking Reinforced Concrete Beams,” ACI Materials Journal, Technical Paper, Title No. 81-26, May-Jun. 1984, 81:3, 11 pages.
Bazant et al., “Size Effect in Brazilian Split-Cylinder Tests: Measurements and Fracture Analysis,” ACI Materials Journal, Technical Paper, Title No. 88-M40, May 31, 1991, 88:3 (325-332), 8 pages.
Bazant et al., “Strain-Softening Bar and Beam: Exact Non-Local Solution,” Int. J. Solids Structures, 1988, 24:7 (659-673), 15 pages.
Bennett et al., “Instrumented Nanoindentation and 3D Mechanistic Modeling of a Shale at Multiple Scales,” Acta Geotechnica, 10:21, Jan. 9, 2015, 14 pages.
Berryman, “Extension of Poroelastic Analysis to Double-Porosity Materials: New Technique in Microgeomechanics,” Journal of Engineering Mechanics, 128:8 (840), Aug. 2002, 8 pages.
Bhandari et al., “Two-Dimensional DEM Analysis of Behavior of Geogrid-Reinforced Uniform Granular Bases under a Vertical Cyclic Load,” Acta Geotechnica, Research Paper, 2015, 10: 469-480, 12 pages.
Biot et al., “Temperature analysis in hydraulic fracturing,” Journal of Petroleum Technology, 39:11, Nov. 1987, 9 pages.
Biot, “General Theory of Three-Dimensional Consolidation,” the Ernest Kempton Adams Fund for Physical Research of Columbia University, Reprint Series, Journal of Applied Physics, 12:2 (155-164), Feb. 1941, 11 pages.
Bisnovat et al., “Mechanical and petrophysical behavior of organic-rich chalk from the Judea Plains, Israel,” Marine and Petroleum Geology, 64: 152-164, Jun. 2015, 13 pages.
Blanz et al., “Nuclear Magnetic Resonance Logging While Drilling (NMR-LWD): From an Experiment to a Day-to-Day Service for the Oil Industry,” Diffusion Fundamentals, 2010, 14(2), 5 pages.
Bobko et al., “The Nanogranular Origin of Friction and Cohesion in Shale—A Strength Homogenization Approach to Interpretation of Nanoindentation Results,” International Journal for Numerical and Analytical Methods in Geomechanics, 2010, 23 pages.
Boskey et al., “Perspective—Collagen and Bone Strength,” Journal of Bone and Mineral Research, 14:3, Nov. 3, 1999, 6 pages.
Bourbie and Zinszner, “Hydraulic and Acoustic Properties as a Function of Porosity in Fontainebleau Sandstone,” Journal of Geophysical Research, 90(B13):11,524-11,532, Nov. 1985, 9 pages.
Bratton et al., “The Nature of Naturally Fractured Reservoirs,” Oilfield Review, Jun. 2006, 21 pages.
Brochard et al., “Fracture Properties of Kerogen and Importance for Organic-Rich Shales,” Annual World Conference on Carbon (Carbon 2013), Jul. 2013, 5 pages.
Bunzil et al., “Taking Advantage of Luminescent Lanthanide Ions,” Chemical Society Reviews (CSR), Critical Review, 34: 1048-1077, Dec. 2005, 30 pages.
Caenn et al., “Chapter 9: Wellbore Stability,” p. 359, in Composition and Properties of Drilling and Completion Fluids, 7th Edition: Gulf Professional Publishing, 2016, 1 page.
Cahill et al., “Nanoscale Thermal Transport II,” Applied Physics Reviews 1.1:011305, 2014, 46 pages.
Cahill et al., “Nanoscale Thermal Transport,” Journal of Applied Physics 93:2, Jan. 15, 2003, 28 pages.
California Council on Science and Technology Lawrence Berkeley National Laboratory Pacific Institute, “Advanced Well Stimulation Technologies in California: An Independent Review of Scientific and Technical Information,” CCST, Jul. 2016, 400 pages.
Carcione and Avseth, “Rock-physics templates for clay-rich source rocks,” Geophysics 80:5 (D481-D500), Sep. 2015, 21 pages.
Carter and Hanson, “Fake Moon Dirt, HOOD Solar System Science,” UT Dallas Magazine, 6:2, Spring 2016, 1 page.
Chang et al., “Magnetic SERS Composite Nanoparticles for Microfluidic Detection,” abstract to 251st ACE National Meeting, Mar. 13-17, 2016, 1 page (abstract).
Chang, “In-Situ Formation of Proppant and Highly Permeable Blocks for Hydraulic Fracturing,” SPE-173328-MS, Society of Petroleum Engineers (SPE), SPE Hydraulic Fracturing Technology Conference Feb. 3-5, 2015, 11 pages.
Chen et al., “Size Effect in Micro-Scale Cantilever Beam Bending, ”Acta Mech., 219: 291-307, 2011, 17 pages.
Chen et al., “FITC functionalized magnetic core-shell Fe3O4/Ag hybrid nanoparticle for selective determination of molecular biothiols,” Sensors and Actuators B: Chemical, 193: 857-863, Dec. 2013, 7 pages.
Chern et al., “Deformation of Progressively Cracking Partially Prestressed Concrete Beams,” PCI Journal, 37:1 (74-84), 1992, 11 pages.
Cheshomi et al., “Determination of uniaxial compressive strength of microcystalline limestone using single particles load test,” Journal of Petroleum Science and Engineering, 111: 121-126, 2013, 6 pages.
Chuang et al., “Ultra-sensitive in-situ detection of novel near-infrared persistent luminescent tracer nanoagents in crude oil-water mixtures,” a natureresearch journal, Scientific Reports, Jun. 15, 2016, 5 pages.
Chupin et al., “Finite Strain Analysis of Nonuniform Deformation Inside Shear Bands in Sands,” International Journal for Numerical and Analytical Methods in Geomechanics, 36: 1651-1666, 2012, 16 pages.
Clough et al., “Characterization of Kerogen and Source Rock Maturation Using Solid-State NMR Spectroscopy,” Energy & Fuels, 2015, 29(10): 6370-6382, 42 pages.
Corapcioglu, “Fracturing Fluid Effects on Young's Modulus and Embedment in the Niobrara Formation,” Thesis for degree of Master of Science (Petroleum Engineering), Colorado School of Mines, 2014, 189 pages.
Cubillos et al., “The Value of Inter-well and Single Well Tracer Technology for De-Risking and Optimizing a CEOR Process—Caracara Field Case,” SPE 174394-MS, Society of Petroleum Engineers (SPE), presented at EUROPEC 2015, Jun. 1-4, 2015, 19 pages.
Cui et al., “Poroelastic solution for an inclined borehole,” Transactions of the ASME, Journal of Applied Mechanics, 64, Mar. 1997, 7 pages.
Custelcean et al., “Aqueous Sulfate Separation by Crystallization of Sulfate-Water Clusters,” Angewandte Chemie, International Edition, 2015, 54: 10525-10529, 5 pages.
Dagan, “Models of Groundwater Flow in Statistically Homogeneous Porous Formations,” Water Resource Search 15:1, Feb. 1979, 17 pages.
Daneshy, “Hydraulic Fracturing to Improve Production,” Tech 101, TheWayAhead, 6:3, Oct. 2010, 4 pages.
Das et al., “Molecular Fluorescence, Phosphorescence, and Chemiluminescence Spectrometry,” American Chemical Society Publications (ACS), Analytical Chemistry, 84: 597-625, Nov. 3, 2011, 29 pages.
De Block et al., “A New Solution for the Characterization of Unconventional Shale Resources Based on Analysis or Drill Cutting,” SPE-177601-MS, Society of Petroleum Engineers (SPE), presented at the Abu Dhabi International Petroleum Exhibition and Conference, Nov. 9-12, 2015, 6 pages.
De Rocha et al., “Concentrated CO2-in-Water Emulsions with Nonionic Polymeric Surfactants,” Journal of Colloid and Interface Science, 2001, 239:1 (241-253), 13 pages.
Deans, “Using Chemical Tracers to Measure Fractional Flow and Saturation In-Situ,” SPE 7076, Society of Petroleum Engineers (SPE) of AIME, presented at Fifth Symposium on Improved Methods for Oil Recovery of the Society of Petroleum Engineers of AIME, Apr. 16-19, 1978, 10 pages.
Deirieh et al., “Nanochemomechanical Assessment of Shale: A Coupled WDS-Indentation Analysis,” Acta Geotechnica, Research Paper, Sep. 2012, 25 pages.
Delafargue and Ulm, “Explicit approximations of the indentation modulus of elastically orthotropic solids for conical indenters,” International Jomnal of Solids and Structures 41:26 (7351-7360), Dec. 2004, 10 pages.
Detournay and Cheng, “Poroelastic Response of a Borehole in a Non-Hydrostatic Stress Field,” International Journal of Rock Mechanics, Min. Science and Geomech. Abstracts, 25:3, 1988, 12 pages.
Devarapalli et al., “Micro-CT and FIB-SEM imaging and pour structure characterization of dolomite rock at multiple scales,” Arabian Journal of Geosciences 10:361, Aug. 2017, 9 pages.
Du et al., “Interwell Tracer Tests: Lessons Learned from past Field Studies,” SPE 93140, Society of Petroleum Engineers (SPE), presented at SPE Asia Pacific Oil and Gas Conference and Exhibition, Apr. 5-7, 2005, 9 pages.
Ducros, “Source Rocks of the Middle East,” Source Rock Kinetics: Goal and Perspectives. AAPG Geosciences Technology Workshop, Jul. 2016, 30 pages.
Eastoe et al., “Water-in-CO2 Microemulsions Studied by Small-Angle Neutron Scattering,” Langmuir 1997, 13:26 (6980-6984), 5 pages.
Ehlig-Economides and Economides, “Water as Poppant,” SPE-147603, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Oct. 30-Nov. 2, 2011, 8 pages.
Ekbote et al., “Porochemoelastic Solution for an Inclined Borehole in a Transversely Isotropic Formation,” Journal of Engineering Mechanics, ASCE, Jul. 2006, 10 pages.
El-Aneed et al., “Mass Spectrometry, Review of the Basics: Electrospray, MALDI, and Commonly Used Mass Analyzers,” Applied Spectroscopy Reviews 44:3 (210-230), Mar. 16, 2009, 22 pages.
Elijah, “Numerical Modeling of Wellbore Instability (Tensile Failure) Using Fracture Mechanics Approach,” Thesis for the degree of Master of Science, African University of Science and Technology Abuja, May 2013, 77 pages.
Eliyahu et al., “Mechanical Properties of organic matter in shales mapped at the nanometer scale,” Marine and Petroleum Geology, 59:294-304, Sep. 18, 2014, 11 pages.
Ertas et al., “Petroleum Expulsion Part 1. Theory of Kerogen Swelling in Multicomponent Solvents,” Energy & Fuels, 20: 295-300, 2006, 6 pages.
Eseme et al., “Review of mechanical properties of oil shales: implications for exploitation and basin modeling,” Oil Shale 24:2 (159-174), Jan. 2007, 16 pages.
Esfahani et al., “Quantitative nanoscale mapping of three-phase thermal conductivities in filled skutterudites via scanning thermal microscopy,” Nature Science Review 5:1, Feb. 2017, 31 pages.
Ewy, “Shale Swelling/Shrinkage and Water Content Change due to Imposed Suction and Due to Direct Brine Contact,” Acta Geotechnica, 9: 869-886, 2014, 18 pages.
Ewy, “Wellbore-Stability Predictions by Use of a Modified Lade Criterion,” SPE Drill and Completion, 14:2, Jun. 1999, 7 pages.
Fekete.com [online], “Dual Porosity,” retrieved from URL <www.fekete.com/SAN/WebHelp/FeketeHarmony/Harmony_WebHelp/Content/HTML_Files/Reference_Material/General_Concepts/Dual_Porosity.htm>, available on or before 2014, retrieved on Nov. 11, 2019, 6 pages.
Finney, “Random packings and the structure of simple liquids I. The geometry of random close packing,” Proc. Roy. Soc. Lond. 319, 479-493, May 1970, 15 pages.
Fjaer et al., “Stresses around Boreholes. Borehole Failure Criteria,” in Petroleum Related Rock Mechanics, 2nd Edition, 2008, 156, 1 page.
Frazer et al., “Localized Mechanical Property Assessment of SiC/SiC Composite Materials,” Science Direct, Composites: Part A, 70: 93-101, 2015, 9 pages.
Gallegos and Varela, “Trends in Hydraulic Fracturing Distributions and Treatment Fluids, Additives, Proppants, Water Volumes Applied to Wells Drilled in the United States from 1947 through 2010—Data Analysis and Comparison to the Literature,” USGS, United States Geological Survey, 2015, 24 pages.
Gandossi and Estorff, “An overview of hydraulic fracturing and other formation stimulation technologies for shale gas production,” JRC Science for Policy Report, European Commission, EUR 26347 EN, Jan. 2013, 62 pages.
Ganjdanesh et al. “Treatment of Condensate and Water Blocks in Hydraulic-Fractured Shale-Gas/Condensate Reservoirs,” SPE-175145, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Sep. 28-30, 2015, SPE Journal, Apr. 2016, 10 pages.
Gao et al., “Materials Become Insensitive to Flaws at Nanoscale: Lessons from Nature,” PNAS, 100:10, May 13, 2003, 4 pages.
Gardiner et al., “Chapter 1: Introduction to Raman Scattering,” in Practical Raman Spectroscopy, Springer-Verlag, 1989, 9 pages.
Garnero, “The Contribution of Collagen Crosslinks to Bone Strength,” Int. Bone & Mineral Society, BoneKEy Reports 1:182, Sep. 2012, 8 pages.
George et al., “Approximate relationship between frequency-dependent skin depth resolved from geoelectronnagnetic pedotransfer function and depth of investigation resolved from geoelectrical measurements: A case study of coastal formation, southern Nigeria,” Journal of Earth Syst. Sci, 125:7 (1379-1390), Oct. 2016, 12 pages.
Georgi et al., “Physics and Chemistry in Nanoscale Rocks,” Society of Petroleum Engineers (SPE), SPE Forum Series, Frontiers of Technology, Mar. 22-26, 2015, 4 pages.
Glossary.oilfield.slb.com [online], “Oilfield Glossary: fluid-friction reducer,” available on or before Jun. 15, 2017, retrieved from URL< http://www.glossary.oilfield.slb.com/Terms/f/fluid-friction_reducer.aspx>, 1 page.
Glover et al., “The Use of Measurements Made on Drill Cuttings to Construct and Apply Geomechanical Well Profiles,” ARMA 16-0737, American Rock Mechanics Association (ARMA), presentation at the 50th US Rock Mechanics/Geomechanics Symposium, Jun. 26-29, 2016, 11 pages.
Golomb et al., “Macroemulsion of liquid and supercritical CO2-in-water and water-in-liquid CO2 stabilized with fine particles,” American Chemical Society (ACS), Ind. Eng. Chem. Res. 2006, 45:8 (2728-2733), 6 pages.
Goodman, “Chapter 3: Rock Strength and Failure Criteria,” in Introduction to Rock Mechanics, John Wiley & Sons, 1989, 21 pages.
Gu and Mohanty, “Effect of Foam Quality on Effectiveness of Hydraulic Fracturing in Shales,” International Journal of Roch Mechanics and Mining Sciences, 70: 273-285, 2014, 13 pages.
Han and Cundall, “LBM-DEM modeling of fluid-solid interaction in porous media,” International Journal for Numerical and Analytical Methods in Geomechanics, 37:10 (1391-1407), Jul. 2013, 17 pages.
Han et al., “Numerical and Experimental Studies of Kerogen Rich Shales on Millimeter-Scale Single-Edge Notched Beam,” ARMA-19-211, American Rock Mechanics Association (ARMA), prepared for presentation at the 53rd US Rock Mechanics and Geomechanics Symposium in New York, Jun. 23-26, 2019, 8 pages.
Han et al., “Numerical Modeling of Elastic Spherical Contact for Mohr-Coulomb Type Failures in Micro-Geomaterials,” Experimental Mechanics, 57: 1091-1105, Jun. 16, 2017, 15 pages.
Han et al., “Application of Silver-Coated Magnetic Microspheres to a SERS-Based Optofluidic Sensor,” American Chemical Society Publications (ACS), the Journal of Physical Chemistry C (JPCC), 115: 6290-6296, Mar. 7, 2011, 7 pages.
Harrison et al, “Water-in-Carbon Dioxide Microemulsions with a Fluorocarbon-Hydrocarbon Hybrid Surfactant,” Langmuir 1994, 10:10 (3536-3541), 6 pages.
Hiramatsu and Oka, “Stress around a shaft or level excavated in ground with a three-dimensional stress state,” Mem. Fra. Eng. Kyotu Univ. 24, 1962, 2 pages (Abstract).
Hoang et al., “Correspondence Principle Between Anisotropic Poroviscoelasticity and Poroelasticity using Micromechanics and Application to Compression of Orthotropic Rectangular Strips,” Journal of Applied Physics, American Institute of Physics, 112:044907, Aug. 30, 2012, 16 pages.
Hoek and Brown, “Empirical Strength Criterion for Rock Masses,” Journal of the Geotechnical Engineering Division, Sep. 1980, 20 pages.
Hornby et al., “Anisotropic Effective-Medium Modeling of the Elastic Properties of Shales,” Geophysics, 59:10 (1570-1583), Oct. 1994, 14 pages.
Hosemann et al., “Mechanical Characteristics of SiC Coating Layer in TRISO Fuel Particles,” Journal of Nuclear Materials, 442: 133-142, 2013, 10 pages.
Hosemann et al., “An Exploratory Study to Determine Applicability of Nano-Hardness and Micro-compression Measurements for Yield Stress Estimation,” Science Direct, Journal of Nuclear Materials, 375: 135-143, 2008, 9 pages.
Hu et al., “Smart Liquid SERS Substrates based on Fe3O4/Au Nanoparticles with Reversibility Tunable Enhancement Factor for Practical Quantitative Detection,” a natureresearch journal, Scientific Reports, 4:7204, Nov. 27, 2014, 10 pages.
Hull and Abousleiman, “Chapter 10: Insights of the Rev of Source Shale from Nano- and Micromechanics,” in New Frontiers in Oil and Gas Exploration, Springer International Publishing Switzerland, 2016, 29 pages.
Hull et al, “Nanomechanical Characterization of the Tensile Modulus of Rupture of Kerogen-Rich Shale,” SPE 177628, Society of Petroleum Engineers (SPE), presented at the Abu Dhabi International Petroleum Exhibition and Conference, Nov. 9-12, 2015, SPE Journal 2017, 22:4 (1024-1033), 10 pages.
Hull et al., “Oxidative Kerogen Degradation: A Potential Approach to Hydraulic Fracturing in Unconventionals,” Energy Fuels 2019, 33:6 (4758-4766), 9 pages.
Hull et al., “Recent Advances in Viscoelastic Surfactants for improved Production from Hydrocarbon Reservoirs,” SPE 173776, Society of Petroleum Engineers (SPE), presented at the SPE International Symposium on Oilfield Chemistry, Apr. 13-15, 2015, SPE Journal, 2016, 18 pages.
Huseby et al., “High Quality Flow Information from Tracer Data,” SPE-169183-MS, Society of Petroleum Engineers (SPE), presented at the SPE Bergen One Day Seminar, Apr. 2, 2014, 9 pages.
Hutchins et al., “Aqueous Tracers for Oilfield Applications,” SPE-21049, Society of Petroleum Engineers (SPE), presented at SPE International Symposium on Oilfield Chemistiy, Feb. 20-22, 1991, 9 pages.
Iqbal et al., “In situ micro-cantilver tests to study fracture properties of NiAl single crystals,” Acta Materialia, 60:3 (1193-1200), Feb. 2012, 8 pages.
Itascacg.com' [online], “Particle Flow Code, Version 5.0,” Itasca Consulting Group, Inc., available on or before Apr. 11, 2014, [retrieved on May 11, 2018], rettieved from URL: <https://www.itascacg.com/software/pfc>, 5 pages.
Itascacg.com [online], “Three-dimensional Fast Lagrangian Analysis of Continua (FLAC3D),” available on or before 2012, [retrieved on Jun. 7, 2018], retrieved from URL: <https://www.itascacg.com/software/flac3d>, 4 pages.
Iyengar et al., “Analysis of Crack Propagation in Strain-Softening Beams,” Engineering Fracture Mechanics 69: 761-778, 2002, 18 pages.
Jaeger et al., “Fundamentals of Rock Mechanics,” 4th Edition, Wiley, 2007, 486 pages.
Jia et al., “Highly Efficient Extraction of Sulfate Ions with a Tripodal Hexaurea Receptor,” Angew. Chem. Int. Ed., 2011, 50: 486-490, 5 pages.
Jianhong et al., “Estimation of the Tensile Elastic Modulus using Brazilian disc by Applying Diametrically Opposed Concentrated Loads,” International Journal of Rock Mechanics & Mining Sciences 46:3 (568-576), 2009, 9 pages.
Johnston et al, “Water-in-Carbon Dioxide Microemulsions: An Environment for Hydrophiles Including Proteins,” Science, 271:5249 (624-626), Feb. 2, 1996, 3 pages.
Jose et al., “Continuous multi cycle nanoindentation studies on compositionally graded Ti1-xAIxN multilayer thin films,” Materials Science and Engineering A, 528:21 (6438-6444), Apr. 20, 2011, 7 pages.
Jun et al., “Multifunctional Silver-Embedded Magnetic Nanoparticles as SERS Nanoprobes and Their Applications,” Nano Micro Small, Multifunctional Nanoparticles, 6:1 (119-125), Jan. 4, 2010, 7 pages.
Kang et al., “An experimental study on oxidizer treatment used to improve the seepage capacity of coal reservoirs,” Natural Gas Industry B, 6: 129-137, Sep. 25, 2018, 9 pages.
Kelemen et al., “Petroleum Expulsion Part 2. Organic Matter Type and Maturity Effects on Kerogen Swelling by Solvents and Thermodynamic Parameters for Kerogen from Regular Solution Theory,” Energy & Fuels 20: 310-308, 2006, 8 pages.
Kethireddy, “Quantifying the effect of kerogen on Electrical Resistivity Measurements in Organic Rich Source Rocks,” Thesis in partial fulfillment of the requirements for the degree of Master of Science, Dec. 2013, 78 pages.
Kim et al., “Numerical analysis of fracture propagation during hydraulic fracturing operations in shale gas systems,” International Journal of Rock and Mechanics Mining Sciences, 76: 127-137, 2015, 11 pages.
King, “Thirty Years of Gas Shale Fracturing: What Have We Learned?” SPE-133456, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Sep. 19-22, 2010, 50 pages.
Klapetek, “Chapter 11: Thermal Measurements,” in Quantitative Data Processing in Scanning Probe Microscopy: SPM Applications for Nanometrology, 2018, 26 pages.
Kneipp et al., “Single Molecule Detection Using Surface-Enhanced Raman Scattering (SERS),” Physical Review Letters, American Physical Society 78:9, Mar. 3, 1997, 4 pages.
Kolymbas, “Kinematics of Shear Bands,” Acta Geotechnica, 4:315-318, 2009, 4 pages.
Kumar et al., “Nano to Macro Mechanical Characterization of Shale,” SPE 159804, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Oct. 8-10, 2012, 23 pages.
Kuperkar et al., “Visoelastic micellar water/CTAB/NaNO3 Solutions: Reology, SANS and cyro-TEM Analysis,” Journal of Colloid and Interface Science, 323: 403-409, 2008, 7 pages.
Lam et al., “Experiments and Theory in Strain Gradient Elasticity,” Journal of Mechanics and Physics of Solids, 51: 1477-1508, 2003, 32 pages.
Larsen et al., “Changes in the Cross-Link Density of Paris Basin Toarcian Kerogen Dining Maturation,” Organic Geochemistry 33: 1143-1152, 2002, 10 pages.
Lee et al., “Water-in carbon dioxide emulsions: Formation and stability,” Langmuir, 1999, 15:20 (6781-6791), 11 pages.
Lewan, “Evaluation of petroleum generation by hydrous pyrolysis experimentation,” Phil. Trans. R. Soc. Lond. A, 1985, 315: 123-134, 13 pages.
Lewan, “Experiments on the role of water in petroleum formation,” Geochimica et Cosmochimica Acta, Pergamon, 1997, 61:17 (3691-3723), 33 pages.
Li et al., “A review of crosslinked fracturing fluids prepared with produced water,” KeAi Advanced Research Evolving Science, Southwest Petroleum University, Petroleum 2, 2:4 (313-323), Dec. 2016, 11 pages.
Li et al., “Differentiating Open Natural Fractures from Healed Fractures Using the New, High-Definition Oil-Based Mud Microelectrical Imager-Case Studies from Organic Rich Shales,” SPE-174923-MS, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Sep. 28-30, 2015, 16 pages.
Li et al., “High-Temperature Fracturing Fluids Using Produced Water with Extremely High TDS and Hardness,” IPTC-17797-MS, International Petroleum Technology Conference (IPTC), presented at the International Petroleum Technology Conference, Dec. 10-12, 2014, 13 pages.
Li et al., “Mechanical Characterization of Micro/Nanoscale Structures for MEMS/NEMS Applications using Nanoindentation Techniques,” Science Direct, Ultramicroscopy, 97: 481-494, 2003, 14 pages.
Li et al., “The Brazilian Disc Test for Rock Mechanics Applications: Review and New Insights,” Rock Mech Rock Eng, 2013, 46: 269-287, 19 pages.
Li et al., “Well Treatment Fluids Prepared With Oilfield Produced Water: Part II,” SPE-133379-MS, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Sep. 19-22, 2010, 7 pages.
Liang et al., “An Experimental Study on interactions between Imbibed Fractured Fluid and Organic-Rich Tight Carbonate Source Rocks,” SPE-188338-MS, Society of Petroleum Engineers (SPE), presented at the Abu Dhabi International Petroleum Exhibition and Conference, Nov. 13-16, 2017, 14 pages.
Liu and Abousleiman, “Multiporosity/Multipermeability Inclined-Wellbore Solutions with Mudcake Effects,” Society of Petroleum Engineers (SPE), SPE Journal 23:5, Oct. 2018, 25 pages.
Liu and Abousleiman, “N-Porosity and N-Permeability generalized wellbore stability analytical solutions and applications,” ARMA 16-417, America Rock Mechanics Association (ARMA), presented at the 50th US Rock Mechanics/Geomechanics Symposium held in Houston, Texas, Jun. 26-29, 2016, 10 pages.
Liu et al., “Applications of nano-indentation methods to estimate nanoscale mechanical properties of shale reservoir rocks,” Journal of Natural Gas Science and Engineering, 35: 1310-1319, Sep. 29, 2016, 10 pages.
Liu et al., “Microstructural and geomechanical analysis of Bakken shale at nanoscale,” Journal of Petroleum Science and Engineering, 153: 138-144, Mar. 23, 2017, 12 pages.
Liu et al., “Poroelastic Dual-Porosity/Dual-Permeability After-Closure Pressure-Curves Analysis in Hydraulic Fracturing,” SPE 181748, Society of Petroleum Engineers (SPE), SPE Journal 2016, 21 pages.
Liu et al., “Safe Drilling in Chemically Active and Naturally Fractured Source Rocks: Analytical Solution and Case Study,” IADC/SPE-189658-MS, Society of Petroleum Engineers (SPE), IADC, presented at the IADC/SPE Drilling Conference and Exhibition, Mar. 6-8, 2018, 13 pages.
Liu, “Dimension effect on mechanical behavior of silicon micro—cantilver beams,” Measurement, 41:8 (885-895), Oct. 2008, 11 pages.
Liu, “Elastic Constants Determination and Deformation Observation Using Brazilian Disk Geometry,” Experimental Mechanics, 2010, 50:1025-1039, 15 pages.
Liu, “Fracture Toughness Assessment of Shales by Nanoindentation,” Thesis for the degree of Master of Science in Civil Engineering, Geotechnical Engineering Masters Projects, University of Massachusetts Amherst, Sep. 2015, 80 pages.
Liu, “Micro-cantilver Testing to Evaluate the Mechanical Properties of Thermal Barrier Coatings,” presented at the 19th European Conference on Fracture (ECF19): Fractuie Mechanics for Durability, Reliability and Safety, Conference Proceedings, Aug. 26-31, 2012, 7 pages.
Long et al., “Chapter 2: Advanced Well Stimulation Technologies,” in an Independent Scientific Assessment of Well Stimulation in California, vol. I, Well Stimulation Technologies and their Past, Present and Potential Future Use in California, Jan. 2015, 62 pages.
Low, “Advances in Ceramics Matrix Composites,” Processing. Properties and applications of SiCl/SiC, 10-19, Nanoceramic Matric Composites, 30-41, 2014, 11 pages.
Low, “Ceramic-Matrix Composites: Microstructure, Properties and Applications,” Woodhead Publishing Limited, 11-19, 30-40, 2006, 11 pages.
Lu et al, “Fabrication and characterization of ceramic coatings with alumina-silica sol-incorporated a-alumina powder coated on woven quartz fiber fabrics,” Ceramics International 39:6 (6041-6050), Aug. 2013, 10 pages.
Lu et al., “Quantitative prediction of seismic rock physics of hybrid tight oil reservoirs of the Permian Lucaogou Formation, Junggar Basin, Northwest China,” Journal of Asian Earth Sciences, 2019, 178: 216-223, 8 pages.
Luan et al., “Creation of synthetic samples for physical modelling of natural shale,” European Association of Geoscientists and Engineers (EAGE), Geophysical Prospecting 64: 898-914, Jul. 2016, 17 pages.
Lyngra et al. “Heavy Oil Characterization: Lessons Learned During Placement of a Horizontal Injector at a Tar/Oil Interface,” SPE-172673-MS, Society of Petroleum Engineers (SPE), presented at the SPE Middle East Oil & Gas Show and Conference, Mar. 8-11, 2015, 20 pages.
Mahabadi et al., “A novel approach for micro-scale characterization and modeling of geomaterials incorporating actual material heterogeneity,” (XP002689941) Geophysical Research Letters 39:1 (L01303), Jan. 1, 2012, 6 pages.
Mahmoud et al., “Removal of Pyrite and Different Types of Iron Sulfide Scales in Oil and Gas Wells without H2S Generation,” IPTC-18279-MS, International Petroleum Technology Conferences (IPTC), presented at the International Petroleum Technology Conference, Dec. 6-9, 2015, 8 pages.
Maio et al., “Measuring Fracture Toughness of Coatings using Focused-ion-beam-machined Microbeams,” J. Mater. Res., 20:2, Feb. 2005, 4 pages.
Mao et al., “Chemical and nanometer-scale structure of kerogen and its change during thermal maturation investigated by advanced solid-state 13C NMR spectroscopy,” Geochimica et Cosmochimica Acta, 2010, 74(7): 2110-2127, 18 pages.
Marchetti et al., “Fluorous affinity chromatography for enrichment and determination of perfluoroalkyl substances,” American Chemical Society (ACS), Annual Review of Analytical Chemistry 84: 7138-7145, Jul. 19, 2012, 8 pages.
Maxwell, “Microseismic hydraulic fracture imaging: The path toward optimizing shale gas production,” The Leading Edge, Special Section: Shales, Mar. 2011, 6 pages.
McMahon et al., “First 100% Reuse of Bakken Produced Water in Hybrid Treatments Using Inexpensive Polysaccharide Gelling Agents,” SPE-173783-MS, Society of Petroleum Engineers (SPE), presented at the SPE International Symposium on Oilfield Chemistry, Apr. 13-15, 2015, 9 pages.
Mehrabian and Abousleiman, “Generalized Biot's Theory an Mandel's Problem of Multiple Porosity and Multiple-Permeability Poroelasticity,” American Geophysical Union (AGU), Journal of Geological Research: Solid Earth, 119:4 (2745-2763), 2014, 19 pages.
Mesa, “Spherical and rounded cone nano indenters,” Micro Star Technologies Inc., available on or before Jan. 23, 2018, 24 pages.
Meyer et al., “Identification of Source Rocks on Wireline Logs by Density/Resistivity and Sonic Transit Time/Resistivity Crossplots,” AAPG Bulletin, 1984, 68(2): 121-129, 9 pages.
Meyers et al., “Point load testing of drill cuttings from the determination of rock strength,” ARMA-05-712, presented at the 40th U.S. Symposium on Rock Mechanics (USRMS), Alaska Rocks 2005, American Rock Mechanics Association, Jun. 25-29, 2005, 2 pages, (Abstract).
Middleton et al., “Shale gas and non-aqueous fracturing fluids: Opportunities and challenges for supercritical CO 2,” Applied Energy, 147: 500-509, 2015, 10 pages.
Montgomery and Smith, “Hydraulic Fracturing: History of Enduring Technology,” Journal of Petroleum Technology, Dec. 2010, 7 pages.
Montgomery, “Chapter 1: Fracturing Fluids,” in Effective and Sustainable Hydraulic Fracturing, Intech, the proceedings of the International Conference for Effective and Sustainable Hydraulic Fracturing (HF2103) on May 20-22, 2013, 23 pages.
Montgomery, “Chapter 2: Fracturing Fluid Components,” in Effective and Sustainable Hydraulic Fracturing, Intech, 2013, 21 pages.
Moyer, “A Case for Molecular Recognition in Nuclear Separations: Sulfate Separation from Nuclear Wastes,” American Chemical Society (ACS), Inorganic Chemistry, 2012, 52: 3473-3490, 18 pages.
Moyner et al., “The Application of Flow Diagnostics for Reservoir Management,” SPE 171557, Society of Petroleum Engineers (SPE), SPE Journal, Apr. 2015, 18 pages.
Nguyen and Abousleiman, “Poromechanics Response of Inclined Wellbore Geometry in Chemically Active Fractured Porous Media,” Journal of Engineering Mechanics, 135:11, Nov. 2005, 14 pages.
Okiongbo et al., “Changes in Type II Kerogen Density as a Function of Maturity: Evidence from the Kimmeridge Clay Formation,” Energy Fuels, 2005, 19: 2495-2499, 5 pages.
Oliver and Pharr, “An improved technique for determining hardness and elastic modulus using load and displacement sensing indentation experiments,” Journal of Materials Research, 7:6, Jun. 1992, 20 pages.
Oliver and Pharr, “Measurement of hardness and elastic modulus by instrumented indentation: Advances in understanding and refinements to methodology,” Journal of Materials Research, 19:1, Jan. 2004, 18 pages.
Ortega et al., “The Effect of Particle Shape and Grain-Scale Properties of Shale: A Micromechanics Approach,” International Journal for Numerical and Analytical Methods in Geomechanics, 34: 1124-1156, 2010, 33 pages.
Ortega et al., “The Effect of the Nanogranular Nature of Shale on their Poroelastic Behavior,” Acta Geotechnica, 2: 155-182, 2007, 28 pages.
Ortega et al., “The Nanogranular Acoustic Signature of Shale,” Geophysics, 74:3 (D65-D84), May-Jun. 2009, 20 pages.
Osman and Pao, “Mud Weight Predition for Offshore Drilling,” 8 pages.
Ottesen, “Wellbore Stability in Fractured Rock,” IADC/SPE 128728, International Association of Drilling Contractors (IADC), Society of Petroleum Engineers (SPE), presented at the 2010 IADC/SPE Drilling Conference and Exhibition, Louisiana, Feb. 2-4, 2010, 8 pages.
Pant, “Nanoindentation characterization of clay minerals and clay-based hybrid bio-geomaterials,” dissertation for degree of Doctor of Philosophy in the Department of Civil and Environmental Engineering at the Louisiana State University and Agricultural and Medical College, Dec. 2013, 111 pages.
Passey et al., “From Oil-Prone Source Rock to Gas-Producing Shale Reservoir—Geologic and Petrophysical Characterization of Unconventional Shale-Gas Reservoirs,” SPE 131350, Society of Petroleum Engineers (SPE), presented at the CPS/SPE International Oil & Gas Conference and Exhibition, Jun. 8-10, 2010, 29 pages.
Patel et al., “Analysis of US Hydraulic Fracturing Fluid System and Proppant Trends,” SPE 168645, Society of Petroleum Engineers (SPE), presented at the SPE Hydraulic Fracturing Technology Conference, Feb. 4-6, 2014, 20 pages.
Petoud et al., “Brilliant SM, Eu, Tb, and Dy Chiral Lanthanide Complexes with Strong Circularly Polarized Luminescence,” Journal for the American Chemical Society (JACS), 129: 77-83, Dec. 15, 2006, 7 pages.
Petrowiki.org [online], “Fluid flow in naturally fractured reservoirs,” retrieved from URL <https://petrowiki.org/Fluid_flow_in_naturally_fractured_reservoirs>, available on or before Jul. 16, 2015, retrieved on Nov. 11, 2019, 12 pages.
Podio et al., “Dynamic Properties of Dry and Water-Saturated Green River Shale under Stress,” SPE 1825, Society of Petroleum Engineers (SPE), presented at the SPE 42nd Annual Fall Meeting, Oct. 1-4, 1967, Society of Petroleum Engineers Journal, Jun. 11, 1968, 16 pages.
Pollard et al., “Fundamentals of Structural Geology,” Cambridge University Press, Sep. 1, 2005, 291, 3 pages.
Pollock and Hammiche, “Micro-thermal analysis: techniques and applications,” Journal of Physics D: Applied Physics, 34.9 (R23-R53), 2001, 31 pages.
Poon et al., “An Analysis of Nanoindentation in Linearly Elastic Solids,” International Journal of Solids and Structures, 45:24 (6018-6033), Dec. 1, 2008, 16 pages.
Qin et al., “Applicability of nonionic surfactant alkyl poly glucoside in preparation of liquid CO2 emulsion,” Journal of CO2 Utilization, 2018, 26: 503-510, 8 pages.
Rajbanshi et al., “Sulfate Separation from Aqueous Alkaline Solutions by Selective Crystallization of Alkali Metal Coordination Capsules,” American Chemical Society Publications (ACS), Crystal Growth and Design, 2011, 11: 2702-2706, 5 pages.
Ribeiro and Sharma, “Fluid Selection for Energized Fracture Treatments,” SPE 163867, Society of Petroleum Engineers (SPE), presented at the SPE Hydraulic Fracturing Technology Conference, Feb. 4-6, 2013, 11 pages.
Richard et al, “Slow Relaxation and Compaction of Granular Systems,” Nature Materials, 4, Feb. 2005, 8 pages.
Rodriguez et al., “Imagining techniques for analyzing shale pores and minerals,” National Energy Technology Laboratory, Dec. 2, 2014, 44 pages.
Rostami et al., “DABCO tribromide immobilized on magnetic nanoparticle as a recyclable catalyst for the chemoselective oxidation of sulfide using H2O2 under metaland solvent-free condition,” Catal. Commun. 2014, 43: 16-20, 20 pages.
Rowan et al., “Dynamic Covalent Chemistry,” Angewante Chemie International Edition, 41: 898-952, Mar. 15, 2002, 55 pages.
Ryoo et al, “Water-in-Carbon Dioxide Microemulsions with Methylated Branched Hydrocarbon Surfactants,” Industrial & Engineering Chemistry Research 2003, 42:25 (6348-6358), 11 pages.
Sagisaka et al, “A New Class of Amphiphiles Designed for Use in Water-in-Supercritical CO2 Microemulsions,” Langmuir 2016, 32:47 (12413-12422), 44 pages.
Sagisaka et al, “Effect of Fluorocarbon and Hydrocarbon Chain Lengths in Hybrid Surfactants for Supercritical CO2,” Langmuir 2015, 31:27 (7479-7487), 36 pages.
Sagisaka et al, “Nanostructures in Water-in-CO2 Microemulsions Stabilized by Double-Chain Fluorocarbon Solubilizers,” Langmuir 2013, 29:25 (7618-7628), 11 pages.
Santarelli et al., “Drilling through Highly Fractured Formations: A Problem, a Model, and a Cure,” Society of Petroleum Engineers (SPE), presented at the 67th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Washington D.C., Oct. 4-7, 1992, 10 pages.
Sayed and Al-Muntasheri, “A Safer Generation of Wettability Alteration Chemical Treatments,” SPE-184566-MS, Society of Petroleum Engineers (SPE), presented at the SPE International Conference on Oilfield Chemistry, Apr. 3-5, 2017, 25 pages.
Selvin et al., “Principles and biophysical applications of lanthanide-based probes,” Annual Review of Biophysics and Biomolecular Structure, Jun. 2002, 31:275-302, 28 pages.
Sepulveda et al., “Oil-Based Foam and Proper Underbalanced-Drilling Practices Improve Drilling Efficiency in a Deep Gulf Coast Well,” SPE 115536, Society of Petroleum Engineers (SPE), presented at the 2008 SPE Annual Technical Conference and Exhibition in Denver, Colorado, Sep. 21-24, 2008, 8 pages.
Serra, “No Pressure Transient Analysis Methods for Naturally Fractured Reservoirs,” (includes assosciated papers 12940 and 13014), Journal of Petroleum Technology, Dec. 1983, 35:12, Society of Petroleum Engineers, 18 pages.
Serres-Piole et al., “Water tracers in oilfield applications: Guidelines,” Elsevier Ltd., Journal of Science and Engineering, Nov. 2012, 98-99:22-39, 18 pages.
Shahid et al., “Natural-fracture reactivation in shale gas reservoir and resulting microseismicity,” SPE 178437, Journal of Canadian Petroleum Technology, Nov. 2015, 54:06, 10 pages.
Shin et al., “Development and Testing of Microcompression for Post Irradiation Characterization of ODS Steels,” Journal of Nuclear Materials, 2014, 444:43-48, 6 pages.
Shook et al., “Determining Reservoir Properties and Flood Performance from Tracer Test Analysis,” SPE 124614, Society of Petroleum Engineers (SPE), presented at SPE Annual Technical Conference and Exhibition, Oct. 4-7, 2009, 19 pages.
Shukla et al., “Nanoindentation Studies on Shales,” ARMA 13-578, American Rock Mechanics Association (ARMA), presented at the 47th US Rock Mechanics/Geomechanics Symposium, Jun. 23-26, 2013, 10 pages.
Sierra et al., “Woodford Shale Mechanical Properties and the Impacts of Lithofacies,” ARMA 10-461, American Rock Mechanics Association (ARMA), presented at the 44th US Rock Mechanics Symposium and 5th US-Canada Rock Mechanics Symposium, Jun. 27-30, 2010, 10 pages.
Singh et al., “Facies classification based on seismic waveform,” presented at the 5th Conference & Exposition on Petroleum Geophysics, Jan. 15-17, 2004, 456-462, 7 pages.
Siskin et al., “Reactivity of organic compounds in hot water: geochemical and technological implications,” Science, Oct. 11, 1991, 254, 8 pages.
Slatt et al., “Merging Sequence Stratigraphy and Geomechanics for Unconventional Gas Shales,” The Leading Edge, Special Section: Shales, Mar. 2011, 8 pages.
Slatt et al., “Outcrop/Behind Outcrop (Quarry), Multiscale Characterization of the Woodford Gas Shale,” in Breyer, Shale Reservoirs—Giant Resources for the 21st Century: AAPG Memoir, 2011, 97: 1-21, 22 pages.
Sone et al., “Mechanical Properties of Shale-Gas Reservoir Rocks—Part 2: Ductile Creep, Brittle Strength, and Their Relation to the Elastic Modulus,” Geophysics, Sep.-Oct. 2013, 78:5 (D393-D402), 10 pages.
Sone et al., “Mechanical Properties of Shale-Gas Reservoir Rocks—Part 1: Static and Dynamic Elastic Properties and Anisotropy,” Geophysics, Sep.-Oct. 2013, 78:5 (D381-D392), 13 pages.
Song et al., “SERS-Encoded Nanogapped Plasmonic Nanoparticles: Growth of Metallic Nanoshell by Templating Redox-Active Polymer Brushes,” Journal of the American Chemical Society (JACS), Apr. 28, 2014, 136: 6838-6841, 4 pages.
Soni, “LPG-Based Fracturing: An Alternative Fracturing Technique in Shale Reservoirs,” IADC/SPE-170542-MS, Society of Petroleum Engineers (SPE), IADC/SPE Asia Pacific Drilling Technology Conference, Aug. 25-27, 2014, 7 pages.
Stiles et al., “Surface-enhanced Raman Spectroscopy,” Annual Review of Analytical Chemistry, Mar. 18, 2008, 1:601-26, 29 pages.
Tabatabaei et al., “Well performance diagnosis with temperature profile measurements,” SPE 147448, Society of Petroleum Engineers (SPE), in SPE Annual Technical Conference and Exhibition, Oct. 30-Nov. 2, 2011, published Jan. 2011, 16 pages.
Tathed et al., “Hydrocarbon saturation in Bakken Petroleum System based on joint inversion of resistivity and dielectric dispersion logs,” Fuel, Dec. 2018, 233: 45-55, 11 pages.
Tian et al., “Off-Resonant Gold Superstructures as Ultrabright Minimally Invasive Surface-Enhanced Raman Scattering (SERS) Probes,” American Chemical Society (ACS), Chemistry of Materials (CM), Jul. 2015, 27: 5678-5684, 7 pages.
Trippetta et al., “The seismic signature of heavy oil on carbonate reservoir through laboratory experiments and AVA modelling,” Journal of Petroleum Science and Engineering, 2019, 177: 849-860, 12 pages.
Ulboldi et al., “Rock strength measurement on cuttings as input data for optimizing drill bit selection,” SPE 56441, Society of Petroleum Engineers (SPE), presented at the 1999 SPE Annual Technical Conference and Exhibition, Oct. 3-6, 1999, 9 pages.
Uleberg and Kleppe, “Dual Porosity, Dual Permeability Formulation for Fractured Reservoir Simulation,” TPG4150, Reservoir Recovery Techniques, Combined Gas/Water Injection Subprogram, 1996, 12 pages.
Ulm et al., “Material Invariant Poromechanics Properties of Shales,” 2005, 8 pages.
Ulm et al., “The Nanogranular Nature of Shale,” Acta Geotechnica, Springer, Jun. 15, 2006, 1:2, 12 pages.
Vanlandingham, “Review of Instrumented Indentation,” Journal of Research of the National Institute of Standards and Technology, Jul.-Aug. 2003, 108:4 (249-265), 17 pages.
Vernik et al., “Ultrasonic Velocity and Anisotropy of Hydrocarbon Source Rocks,” Geophysics, May 1992, 57:5 (727-735), 9 pages.
Walters et al., “Kinetic rheology of hydraulic fracturing fluids,” SPE 71660, Society of Petroleum Engineers (SPE), SPE Annual Technical Conference and Exhibition, Sep. 30-Oct. 3, 2001, 12 pages.
Wang et al, “A Feasibility Analysis on Shale Gas Exploitation with Supercritical Carbon Dioxide,” Energy Sources, Part A: Recovery, Utilization, and Environmental Effects 2012, 34:15 (1426-1435), 11 pages.
Wang et al. “Iron Sulfide Scale Dissolvers: How Effective Are They?” SPE 168063, Society of Petroleum Engineers (SPE), presented at the SPE Saudi Arabia Section Annual Technical Symposium and Exhibition, May 19-22, 2013, 22 pages.
Wang et al., “A Numerical Study of Factors Affecting the Characterization of Nanoindentation on Silicon,” Materials Science and Engineering: A, Feb. 25, 2007, 447:1 (244-253), 10 pages.
Wang et al., “The Flattened Brazilian Disc Specimen Used for Testing Elastic Modulus, Tensile Strength and Fracture Toughness of Brittle Rocks: Analytical and Numerical Results,” International Journal of Rock Mechanics and Mining Sciences, 2004, 41:2 (245-253), 9 pages.
Warpinski, “Understanding Hydraulic Fracture Growth, Effectiveness, and Safety Through Microseismic Monitoring,” Chapter 6, in Effective and Sustainable Hydraulic Fracturing, Intech, May 17, 2013, 14 pages.
Warren and Root, “The Behavior of Naturally Fractured Reservoirs,” SPE 426, Society of Petroleum Engineers (SPE), SPE Journal, Sep. 1963, 3:3 (245-255), 11 pages.
Wegst et al., “Bioinspired Structural Materials,” Nature Materials, Jan. 2015, 14, 14 pages.
Wenk et al., “Preferred Orientation and Elastic Anisotropy of Illite-Rich Shale,” Geophysics, Mar.-Apr. 2007, 72:2 (E69-E75), 7 pages.
Wessels et al., “Identifying fault activation during hydraulic stimulation in the Barnett shale: source mechanisms, b values, and energy release analyses of microseismicity,” presented at the SEG San Antonio 2011 Annual Meeting, Sep. 18-23, 2011, 5 pages.
Wilson and Aifantis, “On the Theory of Consolidation with Double Porosity,” International Journal of Engineering Science, 1982, 20:9 (1009-1035), 27 pages.
Wilson et al., “Fracture Testing of Bulk Silicon Microcantilever Beams Subjected to a Side Load,” Journal of Microelectromechanical Systems, Sep. 1996, 5:3, 9 pages.
Wu et al., “A reusable biosensor chip for SERS-fluorescence dual mode immunoassay,” Proc. SPIE 9543:954317-1, Third International Symposium on Laser Interaction with Matter, LIMIS 2014, May 4, 2015, 6 pages.
Wu et al., “A SERS-Assisted 3D Barcode Chip for High-Throughput Biosensing,” Nano Micro Small Journal, Jun. 11, 2015, 11:23 (2798-2806), 9 pages.
Wu et al., “Extraction of kerogen from oil shale with supercritical carbon dioxide: Molecular dynamics simulations,” the Journal of Supercritical Fluids, 107: 499-506, Jan. 2016, 8 pages.
Wurster et al., “Characterization of the fracture toughness of microsized tungsten single crystal notched specimens,” Philosophical Magazine, May 2012, 92:14 (1803-1825), 23 pages.
Wurzenberger et al., “Nitrogen-Rich Copper(II) Bromate Complexes: an Exotic Class of Primary Explosives,” Journal of Inorganic Chemistry, 2018, 57: 7940-7949, 10 pages.
Xu et al., “Anisotropic elasticity of jarosite: A high-P synchrotron XRD study,” American Mineralogist, 2010, 95:1 (19-23), 5 pages.
Xu et al., “Measurement of two-photon excitation cross sections of molecular fluorophores with data from 690 to 1050 nm,” Journal of the Optical Society of America B, Mar. 1996, 13:3, 11 pages.
Yang et al., “Nanoscale geochemical and geomechanical characterization of organic matter in shale,” Nature Communcations, Dec. 19, 2017, 8:2179, 9 pages.
Yoldas, “Alumina gels that form porous transparent Al2O2,” Journal of Materials Science, 1975, 10: 1856-1860, 5 pages.
Zamberi et al., “Improved Reservoir Surveillance Through Injected Tracers in a Saudi Arabian Field: Case Study,” SPE 166005, Society of Petroleum Engineers (SPE), presented at SPE Reservoir Characterization and Simulation Conference and Exhibition, Sep. 16-18, 2013, 15 pages.
Zemel, “Chapter 3: Interwell Water Tracers,” Tracers in the Oil Field, 43:1, Elsevier Science, Jan. 13, 1995, 47 pages.
Zeszotarski et al., “Imaging and Mechanical Property Measurements of Kerogen via Nanoindentation,” Geochimica et Cosmochimica Acta, Oct. 15, 2004, 68:20 (4113-4119), 7 pages.
Zhou et al., “Upconversion luminescent materials: advances and applications,” American Chemical Society (ACS), Chemical Reviews, Jan. 14, 2015, 115: 395-465, 71 pages.
Zielinski et al, “A Small-Angle Neutron Scattering Study of Water in Carbon Dioxide Microemulsions,” Langmuir 1997, 13:15 (3934-3937), 4 pages.
Zimmerman and Bodvarsson, “Hydraulic Conductivity of Rock Fractures,” transport in Porous Media, Jan. 1996, 23: 1-30, 31 pages.
GCC Examination Report issued in Gulf Cooperation Council Appln. No. 2020-40155, dated Sep. 6, 2021, 4 pages.
PCT International Search Report and Written Opinion in International Appln. No. PCT/US2020/043380, dated Nov. 16, 2020, 12 pages.
AlDuailej et al., “CO 2 Emulsified Fracturing Fluid for Unconventional Applications,” SPE-177405, Society of Petroleum Engineers, Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, Nov. 9-12, 2015, 12 pages.
Related Publications (1)
Number Date Country
20210024814 A1 Jan 2021 US
Provisional Applications (1)
Number Date Country
62878060 Jul 2019 US