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Небесная энциклопедия

Космические корабли и станции, автоматические КА и методы их проектирования, бортовые комплексы управления, системы и средства жизнеобеспечения, особенности технологии производства ракетно-космических систем

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Мониторинг СМИ

Мониторинг СМИ и социальных сетей. Сканирование интернета, новостных сайтов, специализированных контентных площадок на базе мессенджеров. Гибкие настройки фильтров и первоначальных источников.

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Поддерживает ввод нескольких поисковых фраз (по одной на строку). При поиске обеспечивает поддержку морфологии русского и английского языка
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Применить Всего найдено 6176. Отображено 100.
22-03-2012 дата публикации

Treatment of subterranean formations

Номер: US20120067585A1
Автор: Christopher B. Murphy, Jon O. Fabri, Phillip B. Reilly, Jr.
Принадлежит: Polymer Ventures Inc, WATER MARK Tech Inc

A method of preparing and using a subterranean formation stabilization agent. The stabilization agent includes a guanidyl copolymer and may be admixed with a fracturing fluid and optionally brine. The stabilization agent is effective in preventing and/or reducing, for example, clay swelling and fines migration from a subterranean formation contacted with the stabilization agent.

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Номер записи: 1
19-07-2012 дата публикации

Nanohybrid phase interfaces for foaming in oil field applications

Номер: US20120181033A1
Автор: Lewis R. Norman, Rajesh K. Saini
Принадлежит: Halliburton Energy Services Inc

Methods of using nanohybrid-containing fluids in a well are provided. The methods include the steps of: (a) forming or providing a well fluid comprising a nanohybrid; and (b) introducing the well fluid into a well. The methods can be used in various applications, such as in drilling, completion, or intervention operations.

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Номер записи: 2
26-07-2012 дата публикации

Permeability blocking with stimuli-responsive microcomposites

Номер: US20120190593A1
Автор: David S. Soane, Philip Wuthrich, Robert P. Mahoney, Rosa Casado Portilla
Принадлежит: Soane Energy LLC

Disclosed is a two-component fluid loss control system comprising a core substrate and a polymeric shell cooperating with each other to form a microcomposite, wherein the core substrate and the polymeric shell are formed from different materials. The system can demonstrate switchable behavior. The core substrate and the polymeric shell can be further modified, where modifications cooperate with each other to form the microcomposite. Also disclosed are formulations for fluid loss control and methods for controlling fluid loss in a well.

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Номер записи: 3
23-08-2012 дата публикации

Well Treatment Compositions and Methods Utilizing Nano-Particles

Номер: US20120211227A1
Автор: Carl J. Thaemlitz, Craig W. Roddy, D. Chad Brenneis, Jiten Chatterji, Ricky L. Covington
Принадлежит: Halliburton Energy Services Inc

Disclosed embodiments relate to well treatment fluids and methods that utilize nano-particles. Exemplary nano-particles are selected from the group consisting of particulate nano-silica, nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide, and combinations thereof. Embodiments also relate to methods of cementing that include the use of nano-particles. An exemplary method of cementing comprises introducing a cement composition into a subterranean formation, wherein the cement composition comprises cement, water and a particulate nano-silica. Embodiments also relate to use of nano-particles in drilling fluids, completion fluids, simulation fluids, and well clean-up fluids.

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Номер записи: 4
11-04-2013 дата публикации

System And Method Of Perforating A Well And Preparing A Perforating Fluid For The Same

Номер: US20130087336A1
Автор: David R. Underdown
Принадлежит: Chevron USA Inc

A perforation fluid is prepared having a solid material suspended in a liquid. The solid material includes particles having particle sizes that correspond to the pore throat sizes of one or more geological formations through which a well to be perforated runs. The solid material is self-degrading. Perforation of a well-casing of the well in the perforation fluid causes the solid material to instantaneously (or substantially so) form a self-degrading filter cake that facilitates setting of the final completions of the well.

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Номер записи: 5
09-05-2013 дата публикации

Consolidating Spacer Fluids and Methods of Use

Номер: US20130112405A1
Автор: Craig W. Roddy, Crystal L. Keys, D. Chad Brenneis, James R. Benkley, Jiten Chatterji, Rickey L. Morgan, Ronnie G. Morgan
Принадлежит: Halliburton Energy Services Inc

Disclosed are spacer fluids and methods of use in subterranean formations. Embodiments may include use of consolidating spacer fluids in displacement of drilling fluids from a well bore annulus.

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Номер записи: 6
16-05-2013 дата публикации

Use of polylysine as a shale inhibitor

Номер: US20130123148A1
Автор: Bernd Bruchmann, Marta Reinoso Garcia, Oscar Lafuente Cerda, Sophie Maitro-Vogel
Принадлежит: BASF SE

What is proposed is the use of hyperbranched polylysine in the development, exploitation and completion of underground mineral oil and natural gas deposits, and in deep wells, especially as a shale inhibitor in water-based drilling muds, completion fluids or stimulation fluids.

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Номер записи: 7
16-05-2013 дата публикации

Metallic particle induced saponification of fatty acids as breakers for viscoelastic surfactant-gelled fluids

Номер: US20130123150A1
Автор: James B. Crews
Принадлежит: Baker Hughes Inc

A method for affecting the viscosity of an aqueous fluid gelled with a VES includes providing an aqueous fluid and adding to the aqueous fluid, in any order: at least one VES comprising a non-ionic surfactant, cationic surfactant, amphoteric surfactant or zwitterionic surfactant, or a combination thereof, in an amount sufficient to form a gelled aqueous fluid comprising a plurality of elongated micelles, a glyceride oil comprising a fatty acid, and a plurality of metallic particles to produce a mixture comprising dispersed metallic particles. The method also includes dissolving at least a portion of the metallic particles in the aqueous fluid to provide a compound comprising a metallic base and forming in situ a soap reaction product of the fatty acid with the compound, wherein the soap reaction product is present in an amount effective to increase, decrease, or increase and then decrease a viscosity of the gelled aqueous fluid.

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Номер записи: 8
11-07-2013 дата публикации

Nanoparticle Kinetic Gas Hydrate Inhibitors

Номер: US20130175046A1
Автор: Alexandra Clare Morrison
Принадлежит: Halliburton Energy Services Inc

Inhibiting gas hydrate formation while transporting hydrocarbon fluids may include providing a kinetic gas hydrate inhibitor, adding the kinetic gas hydrate inhibitor to a fluid capable of producing gas hydrates, and transporting the fluid that comprises the kinetic gas hydrate inhibitor. Generally a kinetic gas hydrate inhibitor may include a heterocyclic compound comprising nitrogen, e.g., poly(vinyl pyrrolidone).

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Номер записи: 9
29-08-2013 дата публикации

Drilling fluid and method for drilling in coal-containing formations

Номер: US20130225457A1
Автор: Carl Keith Smith, Stefan Alexandru Stoian
Принадлежит: Tech Star Fluid Systems Inc

A drilling fluid and method for drilling in a coal containing formation. The method includes: providing a mixed metal-viscosified drilling fluid including at least 1% potassium salt; circulating the drilling fluid through the well; and drilling into a coal seam.

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Номер записи: 10
05-09-2013 дата публикации

Wellbore Servicing Compositions and Methods of Making and Using Same

Номер: US20130228333A1
Автор: Matthew Lynn Miller
Принадлежит: Halliburton Energy Services Inc

A method of servicing a wellbore comprising identifying lost circulation zone within a wellbore; and placing in the wellbore a composition comprising a wax and a water-based mud wherein placement of the composition reduces or prevents a loss of fluids to the lost circulation zone. A wellbore servicing fluid comprising a water-based mud, a sized calcium carbonate particle and a wax.

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Номер записи: 11
12-09-2013 дата публикации

Consolidation

Номер: US20130233623A1
Автор: Dana Aytkhozhina, Mark Shelton Aston
Принадлежит: BP Exploration Operating Co Ltd

A method of strengthening subterranean formation by drilling and completing a wellbore penetrating at least one unconsolidated or weakly consolidated formation, the method comprising: (a) drilling at least one interval of the wellbore that penetrates the unconsolidated or weakly consolidated formation using a drilling mud comprising a base fluid comprising an aqueous phase containing up to 25% weight by volume (% w/v) of a water soluble silicate, wherein the drilling mud has an acid-soluble particulate bridging solid suspended therein that is formed from a salt of a multivalent cation, wherein the salt of the multivalent cation is capable of providing dissolved multivalent cations when in the presence of an acid; (b) subsequently introducing a breaker fluid containing an acid and/or an acid precursor into the wellbore; (c) allowing the breaker fluid to soak in the interval that penetrates the unconsolidated or weakly consolidated formation for a predetermined period and strengthening formation by reacting with silicate now present in formation; and (d) removing the breaker fluid.

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Номер записи: 12
17-10-2013 дата публикации

Fluids and methods including nanocellulose

Номер: US20130274149A1
Автор: Jesse C. Lee, Philip F. Sullivan, Syed A. Ali, Valerie Lafitte
Принадлежит: Schlumberger Technology Corp

Treatment fluids and methods for treating a subterranean formation are disclosed that include introducing a treatment fluid into a subterranean formation, the treatment fluid containing a nanocrystalline cellulose.

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Номер записи: 13
26-12-2013 дата публикации

Methods of Using Nanoparticle Suspension Aids in Subterranean Operations

Номер: US20130341020A1
Автор: Jimmie D. Weaver, Philip D. Nguyen, Richard D. Rickman
Принадлежит: Halliburton Energy Services Inc

Methods of drilling wellbores, placing proppant packs in subterranean formations, and placing gravel packs in wellbores may involve fluids, optionally foamed fluids, comprising nanoparticle suspension aids. Methods may be advantageously employed in deviated wellbores. Some methods may involve introducing a treatment fluid into an injection wellbore penetrating a subterranean formation, the treatment fluid comprising a base fluid, a foaming agent, a gas, and a nanoparticle suspension aid; and producing hydrocarbons from the subterranean formation via a production wellbore proximal to the injection wellbore.

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Номер записи: 14
13-02-2014 дата публикации

Method For Reducing Permeability Of A Subterranean Reservoir

Номер: US20140041870A1
Автор: Mark Sanders, Russell Watson
Принадлежит: MI Drilling Fluids UK Ltd

The present invention provides a method of isolating a selected reservoir zone in a subterranean reservoir comprising at least the step of squeezing a treatment fluid into the selected reservoir zone, the treatment fluid comprising: a viscosifying agent; a fluid loss control agent; and a particulate material. The invention further provides a treatment fluid comprising a base fluid; a viscosifying agent; at least 20 kg/m 3 of a fluid loss control agent; and a particulate material.

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Номер записи: 15
20-03-2014 дата публикации

Thermally-Activated, High Temperature Particulate Suspending Agents and Methods Relating Thereto

Номер: US20140076565A1
Автор: Gary P. Funkhouser
Принадлежит: Halliburton Energy Services Inc

A particulate suspending agent may be useful for mitigating particulate settling in wellbore applications with high-temperature and/or at near-neutral and higher pH values. Methods of treating a wellbore may include providing a treatment fluid comprising an aqueous liquid, a plurality of particulates, and a particulate suspending agent, wherein the particulate suspending agent comprises a crosslinked polymer particulate formed by a reaction comprising a first monofunctional monomer and an orthoester crosslinker, the orthoester crosslinker comprising an orthoester linkage and at least two crosslinking moieties; and placing the treatment fluid in a wellbore penetrating a subterranean formation.

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Номер записи: 16
02-01-2020 дата публикации

ULTRASONIC BREAKING OF POLYMER-CONTAINING FLUIDS FOR USE IN SUBTERRANEAN FORMATIONS

Номер: US20200001206A1
Автор: MAY Preston Andrew, Nzeadibe Kingsley Ihueze, Shumway William Walter
Принадлежит:

Methods for breaking polymer-containing treatment fluids for use in subterranean formations are provided. In one or more embodiments, the methods comprise providing a treatment fluid comprising a base fluid and a polymer, wherein the treatment fluid was used to treat at least a portion of a subterranean formation; and sonicating at least a portion of the treatment fluid to at least partially reduce the viscosity of the treatment fluid. 1. A method comprising:providing a treatment fluid comprising a base fluid and a polymer, wherein the treatment fluid was used to treat at least a portion of a subterranean formation; andsonicating at least a portion of the treatment fluid to at least partially reduce the viscosity of the treatment fluid.2. The method of claim 1 , wherein the treatment fluid further comprises solids claim 1 , and wherein the method further comprises separating or removing at least a portion of the solids from the treatment fluid after sonicating at least the portion of the treatment fluid.3. The method of claim 2 , wherein the portion of the solids is separated or removed from the base fluid using a separation or removal technique selected from the group consisting of: settling claim 2 , decantation claim 2 , filtration claim 2 , centrifugation claim 2 , dissolving claim 2 , dissolution claim 2 , and any combination thereof.4. The method of further comprising:adding one or more additives to the base fluid after the portion of the solids has been separated or removed from the base fluid to form a second treatment fluid; andintroducing the second treatment fluid into at least a portion of the subterranean formation.5. The method of claim 1 , wherein the portion of the treatment fluid is sonicated using a sonication technique selected from the group consisting of: submersion of an ultrasonic probe claim 1 , submersion of an ultrasonic horn claim 1 , flow-through sonication claim 1 , indirect sonication claim 1 , and any combination thereof.6. The method ...

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Номер записи: 17
07-01-2016 дата публикации

DETERMINATION OF OIL SATURATION IN RESERVOIR ROCK USING PARAMAGNETIC NANOPARTICLES AND MAGNETIC FIELD

Номер: US20160002523A1
Автор: Bryant Steven L., Huh Chun, Johnston Keith P., Milner Thomas E.
Принадлежит: BOARD OF REGENTS, THE UNIVERSITY OF TEXAS SYSTEM

Methods for detection of the presence and distribution of oil in subsurface formation are described herein. The present invention involves injection of an aqueous dispersion of the nanoparticles into the potentially oil containing subsurface formation, followed by a remote detection of the oscillation responses of the nanoparticles in the oil/water interfaces in the reservoir rock by applying magnetic field. 1. A composition comprising:one or more coated paramagnetic nanoparticles, wherein the paramagnetic nanoparticles are coated with a polymer, a surfactant or any combinations thereof adapted for a downhole administration; anda fluid comprising the one or more coated paramagnetic nanoparticles, wherein the fluid is selected from the group consisting of water, hard water, brine, and any combinations thereof, wherein the composition is operable for detecting a presence, measuring a distribution or both of an oil or a hydrocarbon in a subsurface formation.2. The composition of claim 1 , wherein the coated paramagnetic nanoparticles comprise a metal oxide.3. The composition of claim 2 , wherein a metal in the metal oxide comprises at least one of iron claim 2 , magnesium claim 2 , molybdenum claim 2 , lithium claim 2 , cobalt claim 2 , nickel or tantalum.4. (canceled)5. The composition of claim 1 , wherein the nanoparticles are coated by adsorption of a thin polymer gel film or a coating material around the paramagnetic nanoparticles claim 1 , wherein the thin polymer gel film is wrapped around the paramagnetic nanoparticles to prevent a detachment of the coating during a transport of the nanoparticle in the subsurface formation.6. The composition of claim 5 , wherein the coating is configured to promote a high salinity tolerance to the nanoparticles for monovalent and divalent salts.7. The composition of claim 5 , wherein the detachment of the coating is prevented by a chemical bond of the polymer gel film or the coating material to itself or to another agent on the ...

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Номер записи: 18
05-01-2017 дата публикации

Methods and Compositions for In-Situ Polymerization Reaction to Improve Shale Inhibition

Номер: US20170002255A1
Автор: AL-OLAYAN Abeer Mohammad
Принадлежит:

A method of modifying an alteration zone of a formation near a wellbore using a non-Newtonian polymeric composition created from a reaction of a non-Newtonian combination comprises the steps of mixing an anhydrous tetraborate and a fluid to create a crosslinker solution, mixing a crosslinkable polyvinyl alcohol and water to create a polymer solution, where the crosslinker solution and the polymer solution form the non-Newtonian combination, pumping the non-Newtonian combination to a reaction zone in the wellbore, where pumping the non-Newtonian combination is configured to induce mixing of the polymer solution and the crosslinker solution, allowing the non-Newtonian combination to react to form the non-Newtonian polymeric composition, allowing the non-Newtonian polymeric composition to migrate to the alteration zone, where the non-Newtonian polymeric composition migrates due to gravity, and allowing the non-Newtonian polymeric composition to interact with the alteration zone to modify the alteration zone. 1. A method of modifying an alteration zone of a formation near a wellbore using a non-Newtonian polymeric composition created from a reaction of a non-Newtonian combination , the method comprising the steps of:mixing an anhydrous tetraborate and a fluid to create a crosslinker solution; 'wherein the crosslinker solution and the polymer solution form the non-Newtonian combination;', 'mixing a polyvinyl alcohol solution and a polyvinyl acetate solution to create a polymer solution,'} 'wherein a rate of dissolution of the polymer solution depends on the temperature in the reaction zone;', 'pumping the non-Newtonian combination to a reaction zone in the wellbore, wherein the pumping of the non-Newtonian combination is configured such that the crosslinker solution is isolated from the polymer solution until the reaction zone, the reaction zone being defined as a point which allows the reaction between the crosslinker solution and the polymer solution to proceed to a ...

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Номер записи: 19
05-01-2017 дата публикации

Chitin nanocrystal containing wellbore fluids

Номер: US20170002256A1
Автор: Lee Jeremy Hall
Принадлежит: Halliburton Energy Services Inc

The current invention relates to the use of chitin nanocrystals and chitin nanocrystal derivatives. More specifically, the present invention relates to the use of chitin nanocrystals and chitin nanocrystals used in oil and gas operations. The chitin nanocrystals and chitin nanocrystals derivatives can be used as additives to cement and wellbore fluids and can be used to inhibit corrosion in pipelines, on downhole tools and on other oil and gas related equipment.

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Номер записи: 20
04-01-2018 дата публикации

SYSTEMS AND METHODS FOR PRODUCING HYDROCARBONS FROM HYDOCARBON BEARING ROCK VIA COMBINED TREATMENT OF THE ROCK AND SUBSEQUENT WATERFLOODING

Номер: US20180002595A1
Автор: Boccardo Giovanna, Bullen John V., Collins Ian Ralph, Neil James, Peats Allan, Rees Andrew, Taylor Spencer, Zeng Huang
Принадлежит: BP CORPORATION NORTH AMERICA INC.

A method for producing hydrocarbons within a reservoir includes (a) injecting an aqueous solution into the reservoir. The aqueous solution includes water and a thermally activated chemical species. The thermally activated chemical species is urea, a urea derivative, or a carbamate. The thermally activated chemical agent is thermally activated at or above a threshold temperature less than 200 C. In addition, the method includes (b) thermally activating the thermally activated chemical species in the aqueous solution during or after (a) at a temperature equal to or greater than the threshold temperature to produce carbon-dioxide and at least one of ammonia, amine, and alkanolamine within the reservoir. Further, the method includes (c) increasing the water wettability of the subterranean formation in response to the thermally activation in (b). Still further, the method includes (d) waterflooding the reservoir with water after (a), (b) and (c). 1. A method for producing hydrocarbons within a reservoir in a subterranean formation , the reservoir having an ambient temperature and an ambient pressure , the method comprising:(a) injecting an aqueous solution into the reservoir with the reservoir at the ambient temperature, wherein the aqueous solution comprises water and a thermally activated chemical species, wherein the thermally activated chemical species is urea, a urea derivative, or a carbamate, wherein the thermally activated chemical agent is thermally activated at or above a threshold temperature less than 200° C.;(b) thermally activating the thermally activated chemical species in the aqueous solution during or after (a) at a temperature equal to or greater than the threshold temperature to produce carbon-dioxide and at least one of ammonia, amine, and alkanolamine within the reservoir;(c) increasing the water wettability of the subterranean formation in response to the thermally activation in (b); and(d) waterflooding the reservoir with water after (a), (b) and ...

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Номер записи: 21
07-01-2021 дата публикации

COLORIMETRIC DETECTION OF AMINE-BASED SHALE INHIBITORS

Номер: US20210003002A1
Автор: Deville Jay Paul, MAY Preston Andrew
Принадлежит:

A method of detecting an amine-based shale inhibitor in a wellbore servicing fluid (WSF) comprising contacting an aliquot of the WSF with an amine detector compound to form a detection solution; wherein the WSF comprises the amine-based shale inhibitor; and wherein the detection solution is characterized by at least one absorption peak wavelength in the range of from about 380 nm to about 760 nm; detecting an absorption intensity for the detection solution at a wavelength within about +20% of the at least one absorption peak wavelength; comparing the absorption intensity of the detection solution at the wavelength within about +20% of the at least one absorption peak wavelength with a target absorption intensity of the amine-based shale inhibitor to determine the amount of amine-based shale inhibitor in the WSF; and comparing the amount of amine-based shale inhibitor in the WSF with a target amount of the amine-based shale inhibitor. 1. A method of detecting an amine-based shale inhibitor in a wellbore servicing fluid (WSF) comprising:(a) contacting an aliquot of the WSF with an amine detector compound to form a detection solution; wherein the WSF comprises the amine-based shale inhibitor; and wherein the detection solution is characterized by at least one absorption peak wavelength in the range of from about 380 nanometers (nm) to about 760 nm;(b) detecting an absorption intensity for the detection solution at a wavelength within about +20% of the at least one absorption peak wavelength;(c) comparing the absorption intensity of the detection solution at the wavelength within about +20% of the at least one absorption peak wavelength with a target absorption intensity of the amine-based shale inhibitor to determine the amount of amine-based shale inhibitor in the WSF; and(d) comparing the amount of amine-based shale inhibitor in the WSF with a target amount of the amine-based shale inhibitor.2. The method of claim 1 , wherein (b) detecting an absorption intensity for ...

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Номер записи: 22
13-01-2022 дата публикации

Rheology Modifier With a Fatty Alcohol For Organoclay-Free Invert Emulsion Drilling Fluid Systems

Номер: US20220010189A1
Автор: Al-Yami Abdullah, Ramasamy Jothibasu, Wagle Vikrant
Принадлежит:

An invert emulsion drilling fluids having a combination of fatty acids derived from waste vegetable oil (WVO) and a fatty alcohol as a rheology modifier. An invert emulsion drilling fluid may include a water in oil emulsion, an invert emulsifier, a fatty alcohol having six to thirty carbon atoms, and a fatty acid having six to eighteen carbon atoms. The fatty acid is provided by esterifying a waste vegetable oil to produce a methyl ester of the waste vegetable oil and cleaving an ester group from the methyl ester of the waste vegetable oil. The invert emulsion drilling fluid may be formulated free of organoclay. Methods of drilling a wellbore using an invert emulsion drilling fluid are also provided. 1. An invert emulsion drilling fluid , comprisinga water in oil emulsion;an invert emulsifier to stabilize the water in oil emulsion in an amount operable to stabilize the water in oil emulsion;a fatty alcohol having six to thirty six carbons; esterifying a waste vegetable oil to produce a methyl ester of the waste vegetable oil; and', 'cleaving an ester group from the methyl ester of the waste vegetable oil., 'a fatty acid having six to eighteen carbons, the fatty acid produced by2. The invert emulsion drilling fluid of claim 1 , comprising a filtration control agent claim 1 , lime claim 1 , calcium chloride claim 1 , a bridging agent claim 1 , and a weighting agent.3. The invert emulsion drilling fluid of claim 2 , consisting of:the water in oil emulsion;the invert emulsifier to stabilize the water in oil emulsion in an amount operable to stabilize the water in oil emulsion;the fatty alcohol having six to thirty six carbons;the fatty acid having six to eighteen carbons;the filtration control agent;lime;calcium chloride;the bridging agent; andthe weighting agent.4. The invert emulsion drilling fluid of claim 2 , wherein the filtration control agent is an amount in the range of 0.1 pounds-per-barrel (ppb) to 15 ppb.5. The invert emulsion drilling fluid of claim 2 , ...

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Номер записи: 23
13-01-2022 дата публикации

COATED PROPPANTS AND NANITES AND METHODS OF MAKING AND USE OF COATED PROPPANTS AND NANITES

Номер: US20220010200A1
Автор: Arvanitakis Chrisanthos, Arvanitakis Nicholas, Rosado Diego
Принадлежит: GROUP HOLDINGS, LLC

Methods and compositions applied to proppants and/or nanites in order to reduce the microorganisms in fracking wells are disclosed. 1. A method for reducing bacteria using a coated proppant or nanite as described herein2. A coated proppant or nanite as described herein.3. A method for reducing bacteria using a coated proppant or nanite as described herein. The present application claims priority to the following co-pending United States provisional patent applications, all of which are incorporated herein by reference in their entireties:Decreasing the number of microorganisms in Fracking Wells by coating proppants with Quaternary ammonium organosilanes. By forming a bonded anti-microbial coating all around the proppant the use of biocides during the hydraulic fracking process is dramatically reduced. A proppant is a solid material, typically sand, man-made ceramic materials, aluminium oxide, zirconium dioxide, or sintered bauxite designed to keep an induced hydraulic fracture open, during or following a fracturing treatment. Hydraulic fracturing proppants hold open the small fractures once the deep rock achieves geologic equilibrium.The coated proppant reduces and eliminates microbial growth within the fracking wells, without the use of harmful biocides. The coated proppant does not allow micro-organisms to grow, which increases flow rates. With coated proppant, flow rates stay efficient and steady during the fracking process, making extraction quicker and more cost effective. Additionally, with coated proppant, the amount of biocides is dramatically decreased during the process reducing the cost of biocides and storage of biocides. Another great benefit of the coated proppant is to improve the safety of well sites for workers. Environmental risks are also decreased, as the number of biocides are reduced.Proppant coated with quaternary organosilane to form an antimicrobial coating, preferably bonded, on the proppant. The proppant may be any type of material used in ...

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Номер записи: 24
08-01-2015 дата публикации

Lubricating compositions for use with downhole fluids

Номер: US20150007995A1
Автор: John DELOREY, John Misselbrook, Silviu LIVESCU
Принадлежит: Baker Hughes Inc

An aqueous-based downhole fluid having a lubricant therein may be circulated within a subterranean reservoir wellbore where the downhole fluid may be or include a drilling fluid, a completion fluid, a fracturing fluid, a drill-in fluid, a workover fluid, and combinations thereof. The lubricant may include a clay stabilizer and a vegetable oil derivative, such as but not limited to, a sulfonated vegetable oil. The downhole fluid may include the lubricant in an effective amount for lubricating a first surface.

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Номер записи: 25
12-01-2017 дата публикации

METHODS FOR ENHANCING OIL RECOVERY USING COMPLEX NANO-FLUIDS

Номер: US20170009128A1
Автор: Towler Brian Francis
Принадлежит:

The inventions described herein relate generally to novel methods for increasing oil extraction using complex nano-fluids and, in at least one embodiment, to a method of increasing the recovery during oil extraction by injecting complex nano-fluids into an injection well in order to increase oil production yields. 1. A method to enhance or improve oil recovery during oil extraction , comprising administering an effective amount of a complex nano-fluid to an injection well.2. The method according to claim 1 , wherein the complex nano-fluid comprises a micro-emulsion of a non-ionic surfactant claim 1 , a solvent claim 1 , water claim 1 , and a co-solvent alcohol.3. The method of claim 1 , wherein the complex nano-fluid is biodegradeable and thermodynamically stable.4. The method of claim 1 , wherein the complex nano-fluid is administered at a concentration of at least 0.1 percent by weight.5. The method of claim 1 , wherein the complex nano-fluid is administered at a concentration within the range of 0.1 to 1.5 percent by weight.6. The method of claim 1 , wherein the complex nano-fluid is injected into one or more injection well.7. The method of claim 6 , wherein the one or more injection well comprises a material selected from the group containing oil-wet rocks.8. The method of claim 7 , wherein the oil-wet rock comprises sandstone and/or dolomite.9. The method of claim 1 , wherein the oil recovery is between 50 and 95 percent.10. The method of claim 1 , wherein the oil recovery is between 65 and 90 percent.11. A method for reducing capillary forces in oil-rock claim 1 , comprising administering an effective amount of a complex nano-fluid to an injection well.12. The method according to claim 11 , wherein the complex nano-fluid comprises a micro-emulsion of a non-ionic surfactant claim 11 , a solvent claim 11 , water claim 11 , and a co-solvent alcohol.13. The method of claim 11 , wherein the complex nano-fluid is biodegradeable and thermodynamically stable.14. The ...

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Номер записи: 26
27-01-2022 дата публикации

HYDROCARBON BASED CARRIER FLUID

Номер: US20220025246A1
Автор: BABCOCK John A., III Charles P., SIESS, WATTS Kevin G.
Принадлежит:

Y-grade NGL or L-grade is used as a carrier fluid to transport one or more chemical additives into a hydrocarbon bearing reservoir to treat the hydrocarbon bearing reservoir. The Y-grade NGL or L-grade and the chemical additives may be chilled and/or foamed. 1. A method of injecting a treatment fluid into a hydrocarbon bearing reservoir , comprising:mixing an unfractionated hydrocarbon liquid mixture and a chemical additive, wherein the unfractionated hydrocarbon liquid mixture is a by-product of a de-methanized hydrocarbon stream and comprises ethane, propane, butane, isobutane, pentane, and less than one percent methane by liquid volume, wherein the unfractionated hydrocarbon liquid mixture is sourced and transported from a separate processing facility that is located at a location remote from the hydrocarbon bearing reservoir, wherein the separate processing facility comprises at least one of a splitter facility, a gas plant, and a refinery, wherein the unfractionated hydrocarbon liquid mixture is transported via pressure storage vessels from the separate processing facility to the hydrocarbon bearing reservoir;pressurizing the unfractionated hydrocarbon liquid mixture and the chemical additive with a first pump;pressurizing a liquefied gas with a second pump;vaporizing the liquefied gas with a vaporizer;mixing the pressurized, vaporized gas with the pressurized, unfractionated hydrocarbon liquid mixture and chemical additive to form a treatment fluid; andpumping the treatment fluid into the hydrocarbon bearing reservoir at a pressure greater than a formation pressure of the hydrocarbon bearing reservoir.2. The method of claim 1 , further comprising mixing water with the unfractionated hydrocarbon liquid mixture and the chemical additive claim 1 , wherein the water comprises 5-10% inhibited water by volume.3. The method of claim 1 , wherein the chemical additive comprises a surfactant claim 1 , a non-ionic surfactant claim 1 , a polymer claim 1 , an acid claim 1 ...

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Номер записи: 27
14-01-2016 дата публикации

NOVEL NANOPARTICLE-CONTAINING DRILLING FLUIDS TO MITIGATE FLUID LOSS

Номер: US20160009979A1
Автор: "HUSEIN Maen Mohd", Hareland Geir, ZAKARIA Mohammad Ferdous
Принадлежит:

The present invention is directed to a well fluid, and in particular a drilling fluid having low amounts of nanoparticles which act as fluid loss material for reducing fluid loss in an underground formation. The fluid is a nanoparticle-containing well fluid comprising a base fluid and about 5 wt % or less nanoparticles, for preventing or reducing fluid loss to an underground formation, wherein the well fluid is a drilling fluid, kill fluid, completion fluid, or pre-stimulation fluid. The invention also includes in situ and ex situ methods of forming the nanoparticles. 1. A nanoparticle-containing well fluid comprising a base fluid and about 5 wt % or less nanoparticles , for preventing or reducing fluid loss to an underground formation , wherein the well fluid is a drilling fluid , kill fluid , completion fluid , or pre-stimulation fluid.2. The well fluid of wherein the well fluid is a drilling fluid.3. The well fluid of wherein the drilling fluid is an invert emulsion drilling fluid.4. The fluid of wherein the nanoparticles are present in an amount of less than about 4 wt % claim 1 , less than about 3 wt % claim 1 , or less than about 1%.5. (canceled)6. (canceled)7. The fluid of wherein the nanoparticles are present in an amount of between about 0.1 to about 1 wt %; between about 0.5 to about 1.0 wt %; between about 0.6 to 1 wt %; or between about 0.74 to about 1 wt %.8. (canceled)9. (canceled)10. (canceled)11. The fluid of wherein the nanoparticles have a particle size of between about 1 to about 120 nm or between about 1 to about 30 nm.12. (canceled)13. (canceled)14. The fluid of wherein substantially all of the nanoparticles have a particle size in the range of 1-30 nm.15. The fluid of wherein the nanoparticles are one or more of metal hydroxide claim 1 , metal oxide claim 1 , metal carbonate claim 1 , metal sulfide claim 1 , and metal sulfate.16. The fluid of wherein the nanoparticles are selected from the group consisting of iron hydroxide claim 15 , iron ...

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Номер записи: 28
14-01-2016 дата публикации

Gel compositions for hydraulic fracturing applications

Номер: US20160009983A1
Автор: JIANG LI, Roopa Tellakula
Принадлежит: KEMIRA OYJ

Gel compositions comprising an acrylamide polymer or copolymer crosslinked with dialdehyde, methods to produce the gel compositions, welibore treatment fluids comprising the gel compositions, and methods of treating a well bore comprising injecting the gel compositions, are provided. In the drilling, completion, and stimulation of oil and gas wells, well treatment fluids are often pumped into well bore holes under high pressure and at high flow rates causing the rock formation surrounding the well bore to fracture.

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Номер записи: 29
08-01-2015 дата публикации

THERMOSET NANOCOMPOSITE PARTICLES, PROCESSING FOR THIER PRODUCTION, AND THEIR USE IN OIL AND NATURAL GAS DRILLING APPLICATIONS

Номер: US20150011439A1
Автор: BICERANO Jozef
Принадлежит: SUN DRILLING PRODUCTS CORPORATION

Use of two different methods, either each by itself or in combination, to enhance the stiffness, strength, maximum possible use temperature, and environmental resistance of thermoset polymer particles is disclosed. One method is the application of post-polymerization process steps (and especially heat treatment) to advance the curing reaction and to thus obtain a more densely crosslinked polymer network. The other method is the incorporation of nanofillers, resulting in a heterogeneous “nanocomposite” morphology. Nanofiller incorporation and post-polymerization heat treatment can also be combined to obtain the benefits of both methods simultaneously. The present invention relates to the development of thermoset nanocomposite particles. Optional further improvement of the heat resistance and environmental resistance of said particles via post-polymerization heat treatment; processes for the manufacture of said particles; and use of said particles in the construction, drilling, completion and/or fracture stimulation of oil and natural gas wells are described. 189-. (canceled)90. A polymeric-nanocomposite spherical bead exhibiting at least one of enhanced resistance to deformation under load , enhanced retention of resistance at elevated temperature , and enhanced retention of resistance in acidic , basic , or hydrocarbon environments; comprising: a polymer matrix; and from 0.001 to 60 volume percent of nanofiller particles possessing a length that is less than 0.5 microns in at least one principal axis direction , wherein said nanofiller particles comprise at least one of fine particulate material , fibrous material , discoidal material , or a combination of such materials; and wherein said nanofiller particles are selected from the group consisting of natural nanoclays , synthetic nanoclays or mixtures thereof , said nanofiller particles being-dispersed throughout said polymeric nanocomposite spherical bead , wherein said spherical bead has diameter ranging from 0.1 ...

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Номер записи: 30
14-01-2021 дата публикации

Synergist for water-based drilling fluid and preparation method therefor, water-based drilling fluid and application thereof

Номер: US20210009887A1
Автор: Ang Li, Haiping FENG, Jianmin Chen, JING Yang, Junling Zhao, Wei Quan, Weizhi YOU, Xiaohu Quan, Yihu WANG, Yu Cao
Принадлежит: Beijing Shida Bocheng Technology Co Ltd

The present disclosure provides a synergist for a water-base drilling fluid and a preparation method therefor, a water-base drilling fluid and an application thereof, and belongs to the field of drilling fluid technologies. The synergist is prepared from raw materials comprising the following parts by weight: 15˜25 parts of sodium styrene sulfonate, 8˜15 parts of allyl trimethyl ammonium chloride, 2˜8 parts of didodecyldimethylammonium bromide, 1˜5 parts of n-octyl triethoxysilane, 1˜5 parts of propyltriethoxysilane, 1˜5 parts of disodium lauryl sulfosuccinate, 10˜20 parts of nano silica, 8˜15 parts of paraffin, and the like.

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Номер записи: 31
14-01-2021 дата публикации

Enzyme-Encapsulated Hydrogel Nanoparticles for Hydraulic Fracturing Fluid Cleanup

Номер: US20210009891A1
Автор: Hulli Guan, Jenn-Tai Liang
Принадлежит: Texas A&M University

Provided herein is a hydraulic fracturing fluid containing enzyme encapsulated hydrogel nanoparticles and a breaker composition of a viscosifier-degrading enzyme encapsulated in the hydrogel nanoparticle. Also provided are methods for hydraulic fracturing utilizing hydrogel nanoparticles encapsulating an enzyme as a breaker to prevent the premature degradation of the fracturing fluid, to improve transport and placement of the proppant and to facilitate subsequent cleaning of the fracturing fluid.

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Номер записи: 32
11-01-2018 дата публикации

SYSTEM AND METHOD FOR HYDRAULIC FRACTURING WITH NANOPARTICLES

Номер: US20180010435A1
Автор: Hampton Jesse Clay, Nguyen Philip D.
Принадлежит:

A method for controlling fluid loss into the pores of an underground formation during fracturing operations is provided. Nanoparticles are added to the fracturing fluid to plug the pore throats of pores in the underground formation. As a result, the fracturing fluid is inhibited from entering the pores. By minimizing fluid loss, higher fracturing fluid pressures are maintained, thereby resulting in more extensive fracture networks. Additionally, nanoparticles minimize the interaction between the fracturing fluid and the formation, especially in water sensitive formations. As a result, the nanoparticles help maintain the integrity and conductivity of the generated, propped fractures. 1. A method of hydraulically fracturing a tight formation having a fracturing pressure , comprising:a. providing a pad fluid, wherein said pad fluid comprises an aqueous based fluid and a plurality of nanoparticles;b. injecting said pad fluid into a well having a wellbore to interact with said formation at a pressure above said fracturing pressure of said formation to open a fracture therein such that a plurality of pores having pore throats are exposed, wherein a portion of said nanoparticles plug one or more of said pore throats of said foiniation to thus limit entry of said pad fluid into said formation through said pore throats;c. providing a proppant fluid, wherein said proppant fluid comprises an aqueous based fluid and a plurality of proppants; andd. injecting said proppant fluid through said wellbore and into said formation at a flow rate sufficient to place the proppant into said fracture and to extend the length of said fracture.2. The method of wherein a portion of said proppant fluid combines with a portion of said pad fluid in said formation to form a flowback fluid claim 1 , the method further comprising putting the well on production such that said flowback fluid flows out of said formation and such that at least a portion of said nanoparticles dislodge from said pore ...

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Номер записи: 33
10-01-2019 дата публикации

FUNCTIONALIZED NANOSILICA AS SHALE INHIBITOR IN WATER-BASED FLUIDS

Номер: US20190010377A1
Автор: Boul Peter J., Reddy B. Raghava, Thaemlitz Carl
Принадлежит: Saudi Arabian Oil Company

A nanosilica containing fluid system for shale stabilization in a shale formation. The nanosilica containing fluid system comprising a functionalized nanosilica composition operable to react with shale at the surface of the shale formation to form a barrier on the shale formation. The functionalized nanosilica composition comprising a nanosilica particle, the nanosilica particle having a mean diameter, and a functionalization compound, the functionalization compound appended to the surface of the nanosilica particle. And an aqueous-based fluid, the aqueous-based fluid operable to carry the functionalized nanosilica composition into the shale formation. The functionalization compound is an amino silane. The aqueous-based fluid is selected from the group consisting of water, deionized water, sea water, brine, and combinations thereof. 1. A method for shale stabilization in a shale formation , the method comprising the steps of: a functionalized nanosilica composition operable to inhibit shale erosion of the shale formation,', 'an aqueous-based fluid, the aqueous-based fluid operable to carry the functionalized nanosilica composition into the shale formation, and', 'a synergistic polymer additive;, 'introducing a nanosilica containing fluid into the shale formation, the nanosilica containing fluid comprisingallowing the nanosilica containing fluid to inhibit shale erosion of the shale formation, wherein the functionalized nanosilica composition and the synergistic polymer additive in the nanosilica containing fluid are operable to interact synergistically such that the synergy between the functionalized nanosilica composition and the synergistic polymer additive is operable to provide shale inhibition.2. The method of claim 1 , wherein the functionalized nanosilica composition comprises:a nanosilica particle; anda functionalization compound, the functionalization compound appended to the surface of the nanosilica particle.3. The method of claim 1 , wherein the ...

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Номер записи: 34
10-01-2019 дата публикации

METHODS OF RECOVERING A HYDROCARBON MATERIAL

Номер: US20190010382A1
Автор: Agrawal Devesh K., Darugar Qusai, Khabashesku Valery N., Kuznetsov Oleksandr V., Mazyar Oleg A., Suresh Radhika
Принадлежит:

A method of recovering hydrocarbons comprises introducing a suspension comprising nanoparticles to a material and contacting surfaces of the material with the suspension. After introducing the suspension comprising the nanoparticles to the material, the method further includes introducing at least one charged surfactant to the material and removing hydrocarbons from the material. Accordingly, in some embodiments, the nanoparticles may be introduced to the material prior to introduction of the surfactant to the material. Related methods of recovering hydrocarbons from a material are also disclosed. 1. A method of recovering hydrocarbons , the method comprising:introducing a suspension comprising nanoparticles to a material;contacting surfaces of the material with the suspension;after introducing the suspension comprising the nanoparticles to the material, introducing at least one charged surfactant to the material; andremoving hydrocarbons from the material.2. The method of claim 1 , wherein contacting surfaces of the material with the suspension comprises forming a layer of the nanoparticles on the surfaces of the material.3. The method of claim 1 , wherein introducing at least one charged surfactant to the material comprises introducing an anionic surfactant to the material.4. The method of claim 1 , wherein introducing a suspension comprising nanoparticles to a material comprises introducing at least a first type of silica nanoparticles and at least a second type of silica nanoparticles to the material.5. The method of claim 1 , wherein introducing at least one charged surfactant to the material comprises introducing the solution into a subterranean formation having a temperature greater than about 50° C.6. The method of claim 1 , wherein introducing a suspension comprising nanoparticles to a material comprises introducing a suspension including nanoparticles comprising aluminum atoms and silicon atoms to the material.7. The method of claim 1 , wherein introducing ...

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Номер записи: 35
03-02-2022 дата публикации

Re-assembling polymer particle package for conformance control and fluid loss control

Номер: US20220033703A1
Автор: Baojun Bai, Jingyang PU, Thomas Schuman
Принадлежит: University of Missouri System

This invention is broadly concerned with compositions and processes for oilfield applications. More specifically, this invention relates to novel polymer constructed packages that, when pumped into a petroleum well, provide tunable characteristics of transformation and delayed self-assembly with each other under reservoir conditions to yield strong, elastic, bulk gel materials. The compositions comprise a polymer, assembling agents, and optional additives used for the re-assembly stage are uniformly-distributed within the initial gel particles. The polymer particle packages absorb water and swell upon exposure to water, thus exposing the “assembling agents” that enable re-assembly. Both swelling and re-assembly are proportionally controlled via compositions to be tunable to allow functional dispersion and subsequent self-assembly under various reservoir conditions.

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Номер записи: 36
19-01-2017 дата публикации

POLYSACCHARIDE COATED NANOPARTICLE COMPOSITIONS COMPRISING IONS

Номер: US20170015895A1
Автор: Cox Jason R., Eichmann Shannon L., Ow Hooisweng, Schmidt Howard K.
Принадлежит:

A composition including a coated nanoparticle including a nanoparticle and a cross-linked carbohydrate-based coating and an ion selected from the group consisting of Li, Na, K, RbCs, Be, Mg, Ca, Sr, Ba, and mixtures thereof; methods of making and using the composition; and systems including the composition. 1. A method of treating a subterranean formation , the method comprising: a coated nanoparticle comprising a nanoparticle and a cross-linked carbohydrate-based coating; and', {'sup': +', '+', '+', '+,', '+', '2+', '2+', '2+', '2+', '2+, 'an ion selected from the group consisting of Li, Na, K, RbCs, Be, Mg, Ca, Sr, Ba, and mixtures thereof.'}], 'placing in a subterranean formation a nanoparticle composition comprising2. The method of claim 1 , wherein the composition further comprises an aqueous liquid.3. The method of claim 1 , wherein the nanoparticle is a metal oxide nanoparticle.4. The method of claim 3 , wherein the nanoparticle is an iron oxide nanoparticle claim 3 , a nickel oxide nanoparticle claim 3 , or a cobalt oxide nanoparticle.5. The method of claim 3 , wherein the nanoparticle comprises a metal oxide comprising an atom selected from the group consisting of Zn claim 3 , Cr claim 3 , Co claim 3 , Dy claim 3 , Er claim 3 , Eu claim 3 , Gd claim 3 , Gd claim 3 , Pr claim 3 , Nd claim 3 , In claim 3 , Pr claim 3 , Sm claim 3 , Tb claim 3 , Tm claim 3 , and combinations thereof.6. The method of claim 1 , wherein the nanoparticle is a superparamagnetic nanoparticle.7. The method of claim 1 , wherein the superparamagnetic nanoparticle comprises an iron oxide nanoparticle.8. The method of claim 1 , wherein the nanoparticle has an average particle size of about 10 nm to about 1 claim 1 ,000 nm.9. The method of claim 1 , wherein the cross-linked carbohydrate-based coating comprises a carbohydrate selected from the group consisting of a monosaccharide claim 1 , an oligosaccharide claim 1 , a polysaccharide claim 1 , and combinations thereof.10. The method of ...

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Номер записи: 37
19-01-2017 дата публикации

STABILIZED NANOPARTICLE COMPOSITIONS COMPRISING IONS

Номер: US20170015896A1
Автор: Cox Jason R., Kosynkin Dmitry, Ow Hooisweng
Принадлежит:

A composition including a coated nanoparticle and an ion, wherein the coated nanoparticle includes a nanoparticle, a linker, and a stabilizing group; methods of making and using the composition; and systems including the composition. The linker includes an anchoring group, a spacer, and a terminal group. The anchoring group is covalently bound to the nanoparticle and at least one of the terminal groups is covalently bound to at least one stabilizing group. A composition including a crosslinked-coated nanoparticle and an ion, wherein the crosslinked-coated nanoparticle includes a nanoparticle and a coating that includes a linker, a crosslinker, and a stabilizing group; methods of making and using the composition; and systems including the composition. 1. A method of treating a subterranean formation , the method comprising: [ a nanoparticle;', 'a linker comprising an anchoring group, a spacer, and a terminal group; and, 'a coated nanoparticle comprising, 'wherein the anchoring group is covalently bound to the nanoparticle and at least one of the terminal groups is covalently bound to a stabilizing group, and', 'an ion., 'placing in a subterranean formation a composition comprising2. The method of claim 1 , wherein the composition further comprises an aqueous liquid.3. The method of claim 2 , wherein the aqueous liquid comprises at least one of water claim 2 , brine claim 2 , produced water claim 2 , flowback water claim 2 , brackish water claim 2 , fresh water claim 2 , Arab-D-brine claim 2 , sea water claim 2 , mineral waters claim 2 , and other waters of varying salinity and mineral concentration.4. The method of claim 1 , wherein the coated nanoparticles have a lower critical solution temperature of greater than 90° C.5. The method of claim 1 , wherein the method further comprises obtaining or providing the composition claim 1 , wherein the obtaining or providing of the composition occurs above-surface.6. The method of claim 1 , wherein the nanoparticle is ...

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Номер записи: 38
21-01-2016 дата публикации

ELECTRICALLY CONDUCTIVE OIL-BASED FLUIDS

Номер: US20160017202A1
Автор: Arensdorf Joseph J., Clapper Dennis K., Darugar Qusai A, Garcia Alyssa Renee, Yang Jianzhong
Принадлежит: BAKER HUGHES INCORPORATED

Capped nanoparticles may be added to an oil-based fluid to improve the electrical conductivity of the oil-based fluid. The oil-based fluid may be a drilling fluid, a completion fluid, a drill-in fluid, a stimulation fluid, a servicing fluid, and combinations thereof. In a non-limiting embodiment, the oil-based fluid composition may be circulated in a subterranean reservoir wellbore.

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Номер записи: 39
21-01-2016 дата публикации

METHODS AND COMPOSITIONS COMPRISING PARTICLES FOR USE IN OIL AND/OR GAS WELLS

Номер: US20160017204A1
Автор: Germack David, Hill Randal M., Holcomb David L., Soeung Melinda
Принадлежит: CESI CHEMICAL, INC.

Methods and compositions comprising particles for use in various aspects of the life cycle of an oil and/or gas well are provided.

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Номер записи: 40
21-01-2016 дата публикации

ENCAPSULATION AND CONTROLLED DELIVERY OF STRONG MINERAL ACIDS

Номер: US20160017215A1
Автор: Al-Muntasheri Ghaithan, Johnson Leah M., Rothrock Ginger Denison, Shepherd Sarah
Принадлежит:

A polymer-encapsulated mineral acid solution and a method for forming the polymer-encapsulated mineral acid solution. Introducing a strong mineral acid solution to a monomer solution occurs such that a primary emulsion that is a water-in-oil type emulsion forms. Introducing the primary emulsion to a second aqueous solution forms a secondary emulsion that is a water-in-oil-in-water type double emulsion. The monomer in the secondary emulsion is cured such a polymerized shell forms that encapsulates the strong mineral acid solution and forms the capsule. The strong mineral acid solution has up to 30 wt. % strong mineral acid. A method of stimulating a hydrocarbon-bearing formation using the polymer-encapsulated mineral acid solution includes introducing a capsule suspension into a fissure in the hydrocarbon-bearing formation to be stimulated through a face in a well bore. The capsule is maintained within the fissure until the polymer shell degrades.

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Номер записи: 41
18-01-2018 дата публикации

COMPOSITIONS AND METHODS FOR DELAYED CROSSLINKING IN HYDRAULIC FRACTURING FLUIDS

Номер: US20180016488A1
Автор: Munoz Pablo, Tran Trinh, Waller Christopher, Wells Kirk E.
Принадлежит:

Disclosed herein are compositions and methods for delaying crosslinking of aqueous crosslinkable polymers such as polysaccharides in injectable compositions for hydraulic fracturing and related applications. The compositions and methods provide delayed crosslinking at high temperatures and pressures, such as those encountered by hydraulic fracturing compositions injected into subterranean environments. Compositions include injectable solutions comprising a competing agent that is a reaction product of a dialdehyde having 2 to 4 carbon atoms with a non-polymeric cis-hydroxyl compound. Provided are methods of making and using delayed-crosslinking compositions comprising crosslinker compositions containing zirconium complexes and the competing agents. 1. An injectable solution comprising:a crosslinkable polymer;a competing agent comprising a reaction product of a dialdehyde having 2 to 4 carbon atoms with a non-polymeric cis-hydroxyl compound;a crosslinker composition; andat least one water source.2. The injectable solution of claim 1 , wherein the crosslinker composition comprises a product obtained by mixing a solution of a zirconium (IV) compound and an alkanolamine composition comprising an alkanolamine claim 1 , wherein the molar ratio of the zirconium (IV) compound to the alkanolamine is between 1:5 and 1:10.3. The injectable solution of claim 2 , wherein the alkanolamine is triethanolamine.4. The injectable solution of claim 2 , wherein the zirconium (IV) compound is zirconium tetra(n-propoxide).5. The injectable solution of claim I claim 2 , wherein the at least one water source comprises a produced water claim 2 , tap water claim 2 , groundwater claim 2 , surface water claim 2 , seawater claim 2 , wastewater claim 2 , or any combination thereof.6. The injectable solution of claim 1 , wherein the dialdehyde is selected from glyoxal claim 1 , maleic dialdehyde claim 1 , fumaric dialdehyde claim 1 , glutaric dialdehyde claim 1 , the reaction product of glucose ...

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Номер записи: 42
17-01-2019 дата публикации

Surfactant for enhanced oil recovery

Номер: US20190016943A1
Автор: Dan Luo, Feng Wang, Zhifeng Ren
Принадлежит: UNIVERSITY OF HOUSTON SYSTEM

A Janus graphene nanosheet (JGN) surfactant formed from a two-dimensional graphene oxide sheet and functionalized to produce an amphiphilic graphene nanosheet. The JGN may be a component of a nanofluid utilized in nanofluid flooding for oil recovery. The JGN may also be used as solid surfactants to form emulsions for oil recovery.

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Номер записи: 43
17-01-2019 дата публикации

ORGANIC ACID FRACTURING FLUID COMPOSITION

Номер: US20190016945A1
Автор: ELKATATNY Salah El-Din, Mahmoud Mohamed Ahmed Nasr El-Din, MOHAMMAD Marwan Nagm Eldeen
Принадлежит: KING FAHD UNIVERSITY OF PETROLEUM AND MINERALS

A fracturing fluid composition that includes a chelating agent, e.g. GLDA, and a polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted in an aqueous base fluid, e.g. seawater, and a method of fracking a geological formation using the fracturing fluid composition. Various embodiments of the fracturing fluid composition and the method of fracking are also provided. 1: An organic acid fracturing fluid composition , comprising:an aqueous base fluid;a chelating agent comprising glutamic diacetic acid in an amount of 5-20 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition; anda polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and partially hydrolyzed polyacrylamide, in an amount of 0.45-1 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition, wherein the polymeric additive is present in the fracturing fluid composition at a concentration of no more than 1 wt % relative to the total weight of the fracturing fluid composition;wherein a weight percent of acrylamido-tert-butyl sulfonate in the copolymer is in the range of 5 to 20 wt %, and a weight percent of the partially hydrolyzed polyacrylamide in the copolymer is in the range of 80 to 95 wt %, each relative to the total weight of the copolymer.24-: (canceled)5: The fracturing fluid composition of claim 1 , wherein the aqueous base fluid is seawater.67-. (canceled)8: The fracturing fluid composition of claim 1 , which does not include claim 1 , other than the chelating agent and the polymeric additive claim 1 , additional additives selected from the group consisting of an antiscalant claim 1 , a deflocculant claim 1 , a crosslinker claim 1 , a breaker claim 1 , a fluid loss additive claim 1 , a buffer claim 1 , an interfacial tension reducer claim 1 , and a biocide.9: The fracturing fluid composition of claim 1 , which has a plastic viscosity of 2 to 8 cP at a ...

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Номер записи: 44
17-01-2019 дата публикации

High Temperature Crosslinked Fracturing Fluids

Номер: US20190016946A1
Автор: AL-MUNTASHERI GHAITHAN A., Li Leiming, Liang Feng, Reddy B. Raghava
Принадлежит: Saudi Arabian Oil Company

A fracturing fluid including a mixture of an aqueous copolymer composition including a copolymer, the copolymer having 2-acrylamido-2-methylpropanesulfonic acid, acrylamide, and acrylic acid monomer units, or a salt thereof, and a crosslinker. The crosslinker includes a metal, and the weight ratio of the metal to the copolymer is in a range of 0.01 to 0.08. Treating a subterranean formation includes introducing the fracturing fluid into a subterranean formation, and crosslinking the fracturing fluid in the subterranean formation to yield a crosslinked fracturing fluid. The crosslinked fracturing fluid has a viscosity of at least 500 cP for at least 80 minutes when the gel is subjected to a shear rate of 40 sat a temperature in a range of 300° F. to 400° F. 1. A fracturing fluid comprising a mixture of:an aqueous copolymer composition comprising a copolymer, the copolymer comprising 2-acrylamido-2-methylpropanesulfonic acid, acrylamide, and acrylic acid monomer units, or a salt thereof, wherein the copolymer comprises 1 mol % to 25 mol % of the 2-acrylamido-2-methylpropanesulfonic acid monomer units; anda crosslinker comprising a metal,wherein a weight ratio of the metal to the copolymer is in a range of 0.01 to 0.08 andwherein the fracturing fluid comprises 20 to 50 pounds of the copolymer per thousand gallons of the fracturing fluid.2. The fracturing fluid of claim 1 , wherein the weight ratio of the metal to the copolymer is in a range of 0.02 to 0.06.36-. (canceled)7. The fracturing fluid of claim 1 , comprising at least one of a gel stabilizer claim 1 , a clay stabilizer claim 1 , a viscosity breaker claim 1 , a proppant claim 1 , and a pH adjusting agent.8. The fracturing fluid of claim 7 , comprising the pH adjusting agent claim 7 , wherein a pH of the fracturing fluid is in a range of 2 to 7 or 3 to 6.5.9. The fracturing fluid of claim 1 , comprising between 50 mg/L and 50 claim 1 ,000 mg/L of total dissolved solids.10. The fracturing fluid of claim 1 , ...

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Номер записи: 45
17-01-2019 дата публикации

Structural Expandable Materials

Номер: US20190016951A1
Автор: Doud Brian, Sherman Andrew
Принадлежит:

A composite particle that incorporates a material and is designed to undergo a reaction and/or mechanical or chemical change with the environment to increase in volume. The composite particle can be combined with a constraining matrix to create an expandable particle upon reaction. These particles can be used in stimulating wells, including oil and gas reservoirs. 133-. (canceled)34. A force delivery device adapted for use in a subterranean formation , said force delivery device includes an expandable composite material that is configured to expand , said expandable composite material having a compressive strength after expansion of at least 2 ,000 psig , said expandable composite material is unreactive in ambient conditions , at least a portion of the expandable composite material when exposed to activating conditions undergoes a volumetric expansion of at least 2% in a period of 1 hour in a fluid environment that contains at least 2% KCl at 60-80° C. , said expandable composite material configured to release less than about 10% fines after exposure to crushing strengths of 5-7 ,000 psig , said expandable composite material formed of an expandable material and a polymer material , said polymer material forming a matrix or binder with said expandable material , said polymer material forming a coating about said expandable material , or combinations thereof , said polymer material selected from the group consisting of polyurea , epoxy , silane , carbosilane , silicone , polyarylate , polyimide , polyester , polyether , polyamine , polyamide , polyacetal , polyvinyl , polyureathane , epoxy , polysiloxane , polycarbosilane , polysilane , nylon , and polysulfone , said expandable composite material includes one or more materials selected from the group consisting of calcium , lithium , CaO , LiO , NaO , iron , aluminum , silicon , magnesium , KO and zinc35. The force delivery device as defined in claim 34 , wherein said expandable composite material retains a ...

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Номер записи: 46
16-01-2020 дата публикации

AMINATED DEXTRIN COMPOUNDS AND SUBTERRANEAN TREATMENT METHODS USING THE SAME

Номер: US20200017755A1
Автор: Gardner Christopher P., Landis Charles R., Madduri Ashoka V.R., Megahan Kristopher, Rodencal Curtis J.
Принадлежит: Integrity Bio-Chem, LLC

Interactions between aqueous fluids and clay-containing subterranean formations may be problematic due to issues associated with clay destabilization and migration. Functionalized dextrin compounds that are partially oxidized and bear at least one amine group at an oxidation site may promote clay stabilization for more effective treatment of a subterranean formation. Subterranean treatment methods may comprise: providing a clay stabilizing composition comprising an amine-functionalized dextrin compound, the amine-functionalized dextrin compound comprising 2 to about 20 glucose units linked together with α(1,4) glycosidic bonds, and a portion of the glucose units being oxidatively opened and functionalized with at least one amine group at a site of oxidative opening; introducing the clay stabilizing composition into a subterranean formation bearing a clay-containing mineral; and interacting the amine-functionalized dextrin compound with the clay-containing mineral to affect stabilization thereof. 1. A clay stabilizing composition comprising:an amine-functionalized dextrin compound, the amine-functionalized dextrin compound comprising 2 to about 20 glucose units linked together with α(1,4) glycosidic bonds, and a portion of the glucose units being oxidatively opened and functionalized with at least one amine group at a site of oxidative opening.2. The clay stabilizing composition of claim 1 , wherein the amine-functionalized dextrin compound is an amine-functionalized maltodextrin compound.3. The clay stabilizing composition of claim 2 , wherein the amine-functionalized maltodextrin compound is formed from a maltodextrin having a dextrose equivalent value of about 3 to about 20.4. The clay stabilizing composition of claim 3 , wherein the amine-functionalized maltodextrin compound is formed from a maltodextrin having a dextrose equivalent value of about 4.5-7.0.5. The clay stabilizing composition of claim 3 , wherein the amine-functionalized maltodextrin compound is ...

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Номер записи: 47
16-01-2020 дата публикации

Compositions And Methods For Treating Subterranean Formations

Номер: US20200017756A1
Автор: Amr Radwan, Dhiraj GUNDA, Khosrow NADERI, Mohamed TAREK, Mohammad Farid Ehtemam Haghighi, Parbatee JAGASSAR, Rui Zhang
Принадлежит: Preferred Technology LLC, Tenex Technologies LLC

The disclosure generally refers to compositions and methods for treating subterranean formations that improve the recovery of hydrocarbons from the subterranean formations. The compositions include positively and negatively charged nanoparticles suspended in a carrier fluid that is not a drilling fluid and is free of cement and foaming agents. The populations of nanoparticles may be of different sizes, different materials, and comprise different ratios. The composition may also include: surface-active agents, such as surfactants, polymers; detergents; crystal modifiers; stabilizers, or hydronium. In some embodiments, the surface-active agents may bind to the surface of the positively or negatively charged nanoparticles. A subterranean formation may then be injected with the composition.

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Номер записи: 48
16-01-2020 дата публикации

Methods for producing seawater based, high temperature viscoelastic surfactant fluids with low scaling tendency

Номер: US20200017758A1
Автор: FENG LIANG, Leiming Li, Tao Chen
Принадлежит: Saudi Arabian Oil Co

Embodiments of the present disclosure are directed to a method of producing a viscoelastic surfactant (VES) fluid, the VES fluid comprising desulfated seawater. The method of producing the VES fluid comprises adding an alkaline earth metal halide to seawater to produce a sulfate precipitate. The method further comprises removing the sulfate precipitate to produce the desulfated water. The method further comprises adding a VES and one or more of a nanoparticle viscosity modifier or a polymeric modifier to the desulfated seawater. Other embodiments are directed to VES fluids that maintain a viscosity greater than 10 cP at temperatures above 250° F.

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Номер записи: 49
21-01-2021 дата публикации

METHOD FOR KILLING OIL AND GAS WELLS

Номер: US20210017832A1
Автор: SERGEEV Vitalii Vyacheslavovich
Принадлежит: LIMITED LIABILITY COMPANY "GR PETROLEUM" [RU/RU]

The invention relates to the oil production industry. The present method includes consecutively pumping an active pack and a displacement fluid into the near-wellbore region of a formation. The active pack is an emulsion system containing: 15-30 vol % diesel fuel or treated oil from an oil preparation and pumping station, 2-3 vol % emulsifier, 0.5-1 vol % colloidal solution of hydrophobic silicon dioxide nanoparticles, and the remainder as an aqueous solution of calcium chloride or potassium chloride. The colloidal solution of hydrophobic silicon dioxide nanoparticles contains: 31-32.5 vol % amorphous silicon dioxide, 67-69 vol % propylene glycol monomethyl ether, and the remainder as water. The displacement fluid is an aqueous solution of calcium chloride or potassium chloride to which 1-2 vol % of IVV-1 or ChAS-M brand water repellent is added. The emulsifier is a composition having the following formulation: 40-42 vol % esters of higher unsaturated fatty acids (linoleic, oleic, linolenic) and resin acids, 0.7-1 vol % amine oxide, 0.5-1 vol % high molecular weight organic heat stabilizer, and the remainder as diesel fuel (summer diesel or winter diesel). The technical result of the invention is greater efficiency of geological and engineering operations involved in the killing of oil and gas wells, high heat stability and aggregate stability of the emulsion system for killing wells, and also the possibility of adjusting the viscosity properties of the emulsion system according to the porosity and permeability characteristics and the geological and physical characteristics of the near-wellbore region of a formation. 1the active pack is an emulsion system containing (vol. %):a diesel fuel or a treated oil from an oil preparation and pumping station—15-30, an emulsifier—2-3, a colloidal solution of hydrophobic silicon dioxide nanoparticles—0.5-1, an aqueous solution of calcium chloride or potassium chloride—the rest;the emulsifier contains (vol. %): esters of higher ...

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Номер записи: 50
25-01-2018 дата публикации

METHOD OF USING CATIONIC POLYMERS COMPRISING IMIDAZOLIUM GROUPS FOR PERMANENT CLAY STABILIZATION

Номер: US20180022985A1
Автор: Kaprinidis Nikolas, LINDNER Jean-Pierre Berkan, Rimassa Shawn, Siemer Michael
Принадлежит:

Method of inhibiting the swelling of clay in subterranean formations by introducing carrier fluid comprising at least one clay inhibitor into the formation, wherein at least one of the clay inhibitors is a cationic polymer comprising imidazolium groups having a high weight average 118.-. (canceled)20. The method according to claim 19 , wherein the weight average molecular weight Mis from 70 claim 19 ,000 g/mol to 1 claim 19 ,000 claim 19 ,000 g/mol.21. The method according to claim 19 , wherein the weight average molecular weight Mis from 80 claim 19 ,000 g/mol to 600 claim 19 ,000 g/mol.22. The method according to claim 19 , wherein R claim 19 , R claim 19 , Rcomprise 4 to 20 carbon atoms.23. The method according to claim 19 , wherein R claim 19 , R claim 19 , Rcomprise at least one group selected from the group of ether groups claim 19 , secondary amino groups or tertiary amino groups and apart from these no further functional groups.24. The method according to claim 19 , wherein R claim 19 , R claim 19 , Rare aliphatic groups.25. The method according to claim 19 , wherein Ris a Cto Calkylene group.26. The method according to claim 19 , wherein Ris a Cto Calkylene group.27. The method according to claim 19 , wherein the cationic polymer comprises repeating units (Ia).28. The method according to claim 27 , wherein the amount of repeating units (Ia) is at least 80 mol % relating to the total amount of all repeating units.29. The method according to claim 19 , wherein Yis an anion of a mono- or polycarboxylic acid.30. The method according to claim 29 , wherein Yis an acetate ion.31. The method according to claim 19 , wherein the cationic polymer is available by reacting at least an α-dicarbonyl compound claim 19 , an aldehyde claim 19 , at least one amino compound having 2 to 4 primary amino groups claim 19 , and a protic acid with one another.32. The method according to claim 19 , wherein the concentration of the cationic polymers in the carrier fluid is from 0.001% ...

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Номер записи: 51
10-02-2022 дата публикации

COMPOSITIONS AND METHODS FOR CONTROLLED DELIVERY OF ACID USING SULFONATE DERIVATIVES

Номер: US20220041921A1
Автор: Cairns Amy J., Hull Katherine L., Schipper Desmond E.
Принадлежит:

The present application relates to compositions and methods for controlled delivery of acid to a desired location, for instance to a subterranean formation. 1. A method for in situ acid stimulation of a subterranean formation that contains a hydrocarbon reservoir , the method comprising contacting the subterranean formation with (a) a sulfonate-based ammonium salt capable of being oxidized to produce acid; and (b) an oxidizing agent capable of oxidizing the sulfonate-based ammonium salt , where the sulfonate-based ammonium salt and the oxidizing agent react to produce an acid.2. The method of claim 1 , where the subterranean formation comprises carbonates claim 1 , sandstone claim 1 , and/or shale.34-. (canceled)5. The method of claim 1 , where the sulfonate-based ammonium salt comprises a salt selected from the group consisting of ammonium methanesulfonate claim 1 , ammonium perfluorobutanesulfonate claim 1 , ammonium trifluoromethanesulfonate claim 1 , and mixtures thereof.6. The method of claim 1 , where the sulfonate-based ammonium salt comprises ammonium methanesulfonate.7. The method of claim 1 , where the sulfonate-based ammonium salt comprises ammonium trifluoromethanesulfonate.8. The method of claim 1 , where the sulfonate-based ammonium salt comprises ammonium perfluorobutanesulfonate.9. The method of claim 1 , where the sulfonate-based ammonium salt is tethered to a nanoparticle to form a sulfonate based-ammonium salt-nanoparticle.10. The method of claim 9 , where the sulfonate-based ammonium salt is tethered to the nanoparticle through one or more metal salts.12. The method of claim 11 , where [NP] comprises a metal oxide nanoparticle of formula MO claim 11 , wherein x is selected from 1 to 3 and y is selected from 1 to 5.13. (canceled)14. The method of claim 11 , where B is a multifunctional Caliphatic claim 11 , wherein a Caliphatic group is selected from Calkyl claim 11 , Calkenyl claim 11 , Calkynyl claim 11 , and combinations thereof.15. (canceled) ...

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Номер записи: 52
24-01-2019 дата публикации

SHALE SWELLING INHIBITORS

Номер: US20190023972A1
Автор: Lei Cuiyue, Musa Osama M.
Принадлежит: ISP Investments LLC

The present invention provides amidic polymers, which exhibit shale swelling inhibitor activity having improved bio-degradability. The amidic polymers of the invention may be employed in a wide variety of compositions, particularly in subterranean drilling operations. Non-limiting generic structures of the amidic polymers are set out below: (1) wherein R-Rand integers m and n are defined herein. 113-. (canceled)14. An amidic polymer comprising a (a) polymer having a hydroxyl group reacted with a (c) vinyl amide to provide the amidic polymer.15. The amidic polymer according to claim 14 , wherein the (a) polymer having a hydroxyl group is selected from the group consisting of partially and fully hydrolyzed poly(vinyl alcohol)s claim 14 , polysaccharides claim 14 , and mixtures thereof.16. The amidic polymer according to claim 15 , wherein the polysaccharides are derived from celluloses claim 15 , hydroxyethyl celluloses claim 15 , carboxymethyl celluloses claim 15 , hydroxyethyl celluloses claim 15 , hydropropyl celluloses claim 15 , hydroxypropyl methyl celluloses claim 15 , ethyl celluloses claim 15 , carageenans claim 15 , chitosans claim 15 , chondroitin sulfates claim 15 , heparins claim 15 , hyaluronic acids claim 15 , starches claim 15 , chitins claim 15 , perctins claim 15 , guars claim 15 , xanthans claim 15 , dextrans claim 15 , welan gums claim 15 , gellan gums claim 15 , diutans claim 15 , pullulana claim 15 , and mixtures thereof.17. The amidic polymer according to claim 14 , wherein the (c) vinyl amide is selected from the group consisting of N-vinyl pyrrolidone; N-vinyl piperidone; N-vinyl caprolactam; N-vinyl-3-methyl pyrrolidone; N-vinyl-4-methyl pyrrolidone; N-vinyl-5-methyl pyrrolidone; N-vinyl-3-ethyl pyrrolidone; N-vinyl-3-butyl pyrrolidone; N-vinyl-3 claim 14 ,3-dimethyl pyrrolidone; N-vinyl-4 claim 14 ,5-dimethyl pyrrolidone; N-vinyl-5 claim 14 ,5-dimethyl pyrrolidone; N-vinyl-3 claim 14 ,3 claim 14 ,5-trimethyl pyrrolidone; N-vinyl-5-methyl-5- ...

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Номер записи: 53
24-01-2019 дата публикации

MITIGATION OF CONDENSATE BANKING USING SURFACE MODIFICATION

Номер: US20190023973A1
Автор: COX JASON, Liang Feng, Ow Hooisweng, Sayed Mohammed
Принадлежит:

The present application relates to methods and systems for mitigating condensate banking. In some embodiments, the methods and systems involve altering the wettability of a rock formation in the vicinity of a wellbore for a gas condensate reservoir. 1. A method for mitigating condensate banking in the vicinity of a wellbore for a gas condensate reservoir , the method comprising:contacting a rock formation in the vicinity of a wellbore for a gas condensate reservoir with a polymer solution, wherein the polymer solution comprises a charged polymer with a first net charge, thereby forming a modified rock formation; andcontacting the modified rock formation with a particle suspension, wherein the particle suspension comprises charged particles with a second net charge, wherein the first and second net charges are opposed.2. The method of claim 1 , wherein the charged polymer is positively charged in the polymer solution and the charged particles are negatively charged in the particle suspension.3. The method of claim 2 , wherein the charged polymer comprises a plurality of amine groups.4. The method of claim 2 , wherein the charged polymer comprises a plurality of quaternary ammonium groups.5. The method of claim 2 , wherein the charged polymer is a quaternizable polymer prepared by polymerization of vinylimidazole with a vinyl or acrylic claim 2 , or both monomer.6. The method of claim 2 , wherein the charged polymer is a polyquaternium.7. The method of claim 2 , wherein the charged polymer is a polyethylenimine.8. The method of claim 7 , wherein the charged polymer is a functionalized derivative of polyethylenimine.9. The method of claim 1 , wherein the polymer solution has a pH in the range of about 5 to about 10.10. The method of claim 1 , wherein the charged polymer has a number average molecular weight in the range of about 120 to about 800 claim 1 ,000 grams per mole.11. The method of claim 1 , wherein the charged polymer is present in the polymer solution in an ...

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Номер записи: 54
23-01-2020 дата публикации

MITIGATION OF CONDENSATE BANKING USING SURFACE MODIFICATION

Номер: US20200024505A1
Автор: COX JASON, Liang Feng, Ow Hooisweng, Sayed Mohammed
Принадлежит:

The present application relates to methods and systems for mitigating condensate banking. In some embodiments, the methods and systems involve altering the wettability of a rock formation in the vicinity of a wellbore for a gas condensate reservoir. 125-. (canceled)26. A system for mitigating condensate banking in the vicinity of a wellbore for a gas condensate reservoir , the system comprising:a first container or source of a polymer solution that comprises a charged polymer with a first net charge;a second container or source of a particle suspension that comprises charged particles with a second net charge, wherein the first and second net charges are opposed; andconduits for introducing the polymer solution and the particle suspension into a rock formation in the vicinity of a wellbore for a gas condensate reservoir.27. The system of claim 26 , wherein the charged polymer is positively charged in the polymer solution and the charged particles are negatively charged in the particle suspension.28. The system of claim 26 , wherein the charged polymer comprises a plurality of amine groups.29. The system of claim 26 , wherein the charged polymer comprises a plurality of quaternary ammonium groups.30. The system of claim 26 , wherein the charged polymer is a quaternizable polymer prepared by polymerization of vinylimidazole with a vinyl or acrylic claim 26 , or both monomer.31. The system of claim 26 , wherein the charged polymer is a polyquaternium.32. The system of claim 26 , wherein the charged polymer is a polyethylenimine.33. The system of claim 32 , wherein the charged polymer is a functionalized derivative of polyethylenimine.34. The system of claim 26 , wherein the polymer solution has a pH in the range of about 5 to about 10.35. The system of claim 26 , wherein the charged polymer has a number average molecular weight in the range of about 120 to about 800 claim 26 ,000 grams per mole.36. The system of claim 26 , wherein the charged polymer is present in the ...

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Номер записи: 55
23-01-2020 дата публикации

Methods and treatment fluids for microfracture creation and microproppant delivery in subterranean formations

Номер: US20200024508A1
Автор: Kai He, Liang Xin Xu, Paul David Lord, Philip Nguyen
Принадлежит: Multi Chem Group LLC

Systems, methods, and compositions for creating microfractures within subterranean formations and delivering micro-proppant particles into microfractures within subterranean formations are provided. In some embodiments, the methods include: providing a treatment fluid that comprises an aqueous base fluid, a surfactant, and a plurality of microproppant particles having a mean particle diameter of about 100 microns or less; introducing the treatment fluid into a subterranean formation at or above a pressure sufficient to initiate the formation of at least one microfracture within the subterranean formation; and allowing at least a portion of the microproppant particles to enter the at least one microfracture within the subterranean formation.

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Номер записи: 56
28-01-2021 дата публикации

PROPPANT-FIBER SCHEDULE FOR FAR FIELD DIVERSION

Номер: US20210024807A1
Автор: Dunaeva Anna, Godoy-Vargas Jazmin, KARIAMPALLY Jacob, MAYO John Thomas, PANGA Mohan Kanaka Raju, Usoltsev Dmitriy, VIDMA Konstantin, XIANG Changsheng
Принадлежит:

Methods include pumping a fracturing pad fluid into a subterranean formation under conditions of sufficient rate and pressure to create at least one fracture in the subterranean formation, the fracturing pad fluid including a carrier fluid and a plurality of bridging particles, the bridging particles forming a bridge in a fracture tip of a far field region of the formation. Methods further include pumping a first plurality of fibers into the subterranean formation to form a low permeability plug with the bridging particles, and pumping a proppant fluid comprising a plurality of proppant particles. 1. A method comprising:pumping a fracturing pad fluid into a subterranean formation under conditions of sufficient rate and pressure to create at least one fracture in the subterranean formation, the fracturing pad fluid comprising a carrier fluid and a plurality of bridging particles, the bridging particles forming a bridge in a fracture tip within a far field region of the formation;pumping a first plurality of fibers into the subterranean formation to form a low permeability plug with the bridging particles; andpumping a proppant fluid comprising a plurality of proppant particles.2. The method of claim 1 , wherein the bridging particles have a diameter ranging from 0.1 to 10 mm.3. The method of claim 2 , wherein the bridging particles have a monomodal or a multimodal distribution.4. The method of claim 1 , wherein the fracturing pad fluid comprises the first plurality of fibers such that the first plurality of fibers are intermingled with the bridging particles to form the bridge.5. The method of claim 1 , wherein the first plurality of fibers are pumped sequentially after the bridging particles such that the first plurality of fibers form a deposit on the bridge.6. The method of claim 5 , wherein the fracturing pad fluid further comprises a second plurality of fibers such that the second plurality of fibers are intermingled with the bridging particles to form the ...

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Номер записи: 57
28-01-2021 дата публикации

METHODS OF DETERMINING WELLBORE INTEGRITY

Номер: US20210025272A1
Автор: Boul Peter J., Santra Ashok
Принадлежит: Saudi Arabian Oil Company

Methods of determining the integrity of a well are provided. The methods include mixing conductive materials into a fluid, introducing the fluid into the well, and allowing the conductive materials to coat a surface of a subsurface formation, thereby forming an electrically conductive data conduit coating. The methods further include transmitting data through the electrically conductive data conduit coating to determine the integrity of the well. 1. A method of determining integrity of a well comprising:mixing conductive materials into a fluid;introducing the fluid into the well;allowing the conductive materials to coat a surface of a subsurface formation, thereby forming an electrically conductive data conduit coating; andtransmitting data through the electrically conductive data conduit coating to determine the integrity of the well.2. The method of claim 1 , in which transmitting data through the electrically conductive data conduit coating further comprises transmitting data to a surface of the well.3. The method of claim 1 , in which:the fluid comprises at least one of a drilling fluid, a spacer fluid, or a cement slurry; andthe conductive materials comprise at least one of carbon fibers, carbon nanofibers, carbon nanotubes, carbon nanosheets, or graphene, in which the conductive materials comprise carbon nanotubes selected from single-walled nanotubes, double-walled nanotubes, multi-walled carbon nanotubes, narrow-walled nanotubes, or combinations thereof.4. The method of claim 1 , further comprising cementing the well after allowing the conductive materials to coat the surface of the subsurface formation.5. The method of claim 1 , further comprising:mixing insulating materials into a drilling fluid;introducing the drilling fluid into the well;allowing the insulating materials to coat a surface of a subsurface formation, thereby forming an electrically insulating layer;introducing the fluid in the well, in which the fluid comprises a spacer fluid;allowing the ...

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Номер записи: 58
02-02-2017 дата публикации

THERMOSET NANOCOMPOSITE PARTICLES, PROCESSING FOR THEIR PRODUCTION, AND THEIR USE IN OIL AND NATURAL GAS DRILLING APPLICATIONS

Номер: US20170029330A1
Автор: BICERANO Jozef
Принадлежит: SUN DRILLING PRODUCTS CORPORATION

Use of two different methods, either each by itself or in combination, to enhance the stiffness, strength, maximum possible use temperature, and environmental resistance of thermoset polymer particles is disclosed. One method is the application of post-polymerization process steps (and especially heat treatment) to advance the curing reaction and to thus obtain a more densely crosslinked polymer network. The other method is the incorporation of nanofillers, resulting in a heterogeneous “nanocomposite” morphology. Nanofiller incorporation and post-polymerization heat treatment can also be combined to obtain the benefits of both methods simultaneously. The present invention relates to the development of thermoset nanocomposite particles. Optional further improvement of the heat resistance and environmental resistance of said particles via post-polymerization heat treatment; processes for the manufacture of said particles; and use of said particles in the construction, drilling, completion and/or fracture stimulation of oil and natural gas wells are described. 189.-. (canceled)90. A method for lightening a load of cement comprising: a polymer matrix; and', 'from 0.001 to 60 volume percent of nanofiller particles possessing a length that is less than 0.5 microns in at least one principal axis direction; said nanofiller particles comprising at least one of fine particulate material, fibrous material, discoidal material, or a combination of such materials, said nanofiller particles being selected from the group consisting of natural nanoclays, synthetic nanoclays or mixtures thereof wherein said nanofiller particles are substantially dispersed throughout said polymeric nanocomposite particles, wherein said polymeric nanocomposite particle has a diameter ranging from 0.1 mm to 4 mm; and, '(a) mixing an uncured cement composition with an effective amount of a polymeric nanocomposite bead comprising(b) placing the mixture in a selected location.91. The method of claim 90 , ...

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Номер записи: 59
02-02-2017 дата публикации

Organophilic Nanoparticles in Direct Emulsion Systems

Номер: US20170029687A1
Автор: Brunner Sara, Natalia Natalia
Принадлежит:

A direct emulsion fluid includes an aqueous continuous phase, an oleaginous discontinuous phase, calcium carbonate comprising an organophillic coating, and a surfactant. 1. A direct emulsion fluid comprising:an aqueous continuous phase;an oleaginous discontinuous phase;calcium carbonate comprising an organophillic coating; anda surfactant.2. The fluid of claim 1 , wherein the fluid is a single-phase fluid.3. The fluid of claim 1 , wherein the surfactant comprises an anionic surfactant claim 1 , an nonionic surfactant claim 1 , or a combination thereof.4. The fluid of claim 3 , wherein the nonionic surfactant comprises a phosphate group claim 3 , a phospholipid claim 3 , or a combination thereof.5. The fluid of further comprising a pH buffer.6. A method comprising: an aqueous continuous phase;', 'an oleaginous discontinuous phase;', 'calcium carbonate comprising an organophillic coating; and', 'a surfactant., 'emplacing into a formation a direct emulsion fluid comprising7. The method of claim 6 , wherein the fluid is a single-phase fluid.8. The method of claim 6 , wherein the surfactant comprises an anionic surfactant claim 6 , an nonionic surfactant claim 6 , or a combination thereof.9. The method of claim 8 , wherein the nonionic surfactant comprises a phosphate group claim 8 , a phospholipid claim 8 , or a combination thereof.10. The method of claim 6 , wherein the fluid further comprises a pH buffer.11. A method comprising: an aqueous continuous phase;', 'an oleaginous discontinuous phase;', 'calcium carbonate comprising an organophillic coating; and', 'a first surfactant; and, 'emplacing into a formation a direct emulsion fluid comprising a second surfactant;', 'a chelant; and', 'an enzyme;, 'pumping a breaker fluid comprisingwherein the breaker fluid degrades a filtercake formed by the direct emulsion fluid.12. The method of claim 11 , wherein the fluid is a single-phase fluid.13. The method of claim 11 , wherein the surfactant comprises an anionic surfactant ...

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Номер записи: 60
02-02-2017 дата публикации

ENCAPSULATED ACTIVATOR AND ITS USE TO TRIGGER A GELLING SYSTEM BY PHYSICAL MEANS

Номер: US20170029690A1
Автор: ARDAUD Pierre, CADIX Amaud, Rached Rabih
Принадлежит:

A process allowing the encapsulation of a polymerization accelerator comprising the steps of: a) providing an reverse emulsion containing, in an oil phase, a water solution/dispersion containing the polymerisation activator, the oil phase including a heat curable mixture of an isocyanate and a polyalkyldiene hydroxylated or polyol, b) pouring the reverse emulsion in a water phase to make a multiple emulsion water/oil/water, containing drops of activators as the internal water phase, and then, c) heating the multiple emulsion obtained in step b) to cure the polyisocyanate in polyurethane and obtain drops of activator enclosed in shells of polyurethane dispersed in water. The invention also relates to aqueous gelling systems comprising the encapsulated polymerization accelerator with water soluble or dispersable monomers and a polymerization initiator dispersed in said monomers, useful i.a. for sealing subterranean environments or consolidation of a soil or sealing of a subterranean structure. 16-. (canceled)7. The gelling system of claim 12 , wherein the polymerisation accelerator is an alkylamine claim 12 , polyalkyleneamine claim 12 , or polyalkylenimine.8. The gelling system of claim 12 , wherein the hydroxylated polyalkyldiene or polyol is a hydroxylated polybutadiene.9. The gelling system as claimed in claim 12 , wherein the isocyanate is a trimer form of alpha claim 12 , omega hexyldiisocynate.10. The gelling system of claim 9 , wherein the polymerisation accelerator is a polyethyleneimine (PEI).11. The gelling system of claim 12 , wherein a polymerization initiator is encapsulated with the polymerization accelerator claim 12 , wherein the polymerization initiator is selected from the group consisting of and water soluble persalts and/or peroxides.12. The aqueous gelling system of claim 25 , comprising:{'b': '1', 'i) the water soluble or dispersable monomers comprising acrylated or methacrylated polyoxyethylene and/or polyoxypropylene monomers p ii) the ...

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Номер записи: 61
04-02-2016 дата публикации

Methods and systems for infusing porous ceramic proppant with a chemical treatment agent

Номер: US20160032177A1
Автор: Chad Cannan, Steven C. Howe, Todd Roper
Принадлежит: Carbo Ceramics Inc

Methods and systems for infusing ceramic proppant and infused ceramic proppant obtained therefrom are provided. The method can include introducing ceramic proppant and a chemical treatment agent to a mixing vessel, mixing the ceramic proppant and the chemical treatment agent in the mixing vessel to provide a mixture, introducing microwave energy to the mixing vessel to heat the mixture to a temperature sufficient to produce infused ceramic proppant containing at least a portion of the chemical treatment agent, and withdrawing the infused ceramic proppant from the mixing vessel.

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Номер записи: 62
04-02-2016 дата публикации

Antimicrobial Resin Coated Proppants

Номер: US20160032180A1
Автор: Anoop Agrawal, Donald R. Uhlmann, Nicholas R. Krasnow
Принадлежит: Agienic Inc

The invention relates to polymeric coatings on proppants. These coatings have antimicrobial materials incorporated within these coatings. Preferably the antimicrobial materials have low water solubility. These antimicrobial agents are incorporated as particles whose surfaces are modified or these may also be incorporated within porous particles which are then added to the coating formulations. The antimicrobially active agents are incorporated in a fashion so that they can be released from these coatings in the environment of the proppants.

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Номер записи: 63
01-02-2018 дата публикации

NANOPARTICLE MODIFIED FLUIDS AND METHODS OF MANUFACTURE THEREOF

Номер: US20180030332A1
Автор: Chakraborty Soma, Johnson Michael H.
Принадлежит: Baker Hughes, a GE company, LLC

Disclosed herein is a nanoparticle modified fluid that includes nanoparticles that are surface modified to increase a viscosity of the nanoparticle modified fluid and that have at least one dimension that is less than or equal to about 50 nanometers; nanoparticles that are surface modified to increase a viscosity of the nanoparticle modified fluid and that have at least one dimension that is less than or equal to about 70 nanometers; and a liquid carrier; wherein the nanoparticle modified fluid exhibits a viscosity above that of a comparative nanoparticle modified fluid that contains the same nanoparticles but whose surfaces are not modified, when both nanoparticle modified fluids are tested at the same shear rate and temperature. 1. A nanoparticle modified fluid comprising:first nanoparticles that are surface modified to increase a viscosity of the nanoparticle modified fluid and that have at least one dimension that is less than or equal to about 100 nanometers;second nanoparticles that are surface modified to increase a viscosity of the nanoparticle modified fluid and that have at least one dimension that is less than or equal to about 100 nanometers, the first nanoparticles being different from the second nanoparticles; anda liquid carrier;whereinthe first and second nanoparticles each independently comprises carbonaceous nanoparticles, metal oxide nanoparticles, metal nanoparticles, polyhedral oligomeric silsesquioxane nanoparticles, clay nanoparticles, silica nanoparticles, boron nitride nanoparticles or a combination comprising at least one of the foregoing nanoparticles; andthe nanoparticle modified fluid exhibits a viscosity above that of a comparative nanoparticle modified fluid that contains the same nanoparticles but whose surfaces are not modified, when both nanoparticle modified fluids are tested at the same shear rate and temperature.2. The nanoparticle modified fluid of claim 1 , where the sum of the weight of the first and second nanoparticles is ...

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Номер записи: 64
01-02-2018 дата публикации

Methods of preparing treatment fluids comprising anhydrous ammonia for use in subterranean formation operations

Номер: US20180030340A1
Автор: Jim D. Weaver, Michael A. McCabe
Принадлежит: Halliburton Energy Services Inc

Methods comprising preparing a gelled fluid comprising a base fluid, a first gelling agent, and particulates; introducing the gelled fluid into a process stream, the process stream in fluid communication with a subterranean formation; introducing anhydrous ammonia into the gelled fluid at a downstream location in the process stream, thereby forming a particulate-containing treatment fluid; and introducing the particulate-containing treatment fluid into the subterranean formation from the process stream and through the wellhead.

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Номер записи: 65
17-02-2022 дата публикации

Clay Stabilization Composition

Номер: US20220049144A1
Автор: Kroh Franklin O.
Принадлежит:

A clay swelling inhibitor additive for oil and gas well treatment is disclosed. The additive comprises an aqueous solution of a water-soluble polymer and ammonium acetate. The additive composition synergistically retards water absorption by the down-hole clay formation. 1. A composition for clay stabilization consisting essentially of ammonium acetate , poly(diallyl dimethylammonium chloride) and water.2. The composition of wherein the ammonium acetate is in solution form prepared by dissolving an ammonium acetate powder in water or by reacting aqueous ammonia with acetic acid.3. The composition of wherein the ammonium acetate comprises from about 30 percent to about 70 percent by weight of the aqueous composition.4. The composition of wherein the ammonium acetate comprises from about 45 percent to about 55 percent by weight of the aqueous composition.5. The composition of wherein the ammonium acetate comprises from about 47 percent to about 50 percent by weight of the aqueous composition.6. The composition of wherein the poly(diallyl dimethylammonium chloride) or poly-DADMAC has a very low claim 1 , low claim 1 , medium or high molecular weight.7. The composition of wherein the poly(diallyl dimethylammonium chloride) has a medium molecular weight.8. The composition of wherein the poly-DADMAC has a molecular weight of <500 claim 6 ,000 daltons.9. The composition of wherein the poly-DADMAC has a molecular weight of <100 claim 8 ,000 daltons or the poly-DADMAC has a molecular weight of 100 claim 8 ,000-200 claim 8 ,000 daltons or the poly-DADMAC has a molecular weight of 200 claim 8 ,000-350 claim 8 ,000 daltons or the poly-DADMAC has a molecular weight of 400 claim 8 ,000-500 claim 8 ,000 daltons.10. The composition of wherein the poly-DADMAC has a molecular weight of 100 claim 9 ,000-350 claim 9 ,000 daltons.11. The composition of wherein the poly-DADMAC has a molecular weight of 200 claim 10 ,000-350 claim 10 ,000 daltons.12. The composition of wherein the poly- ...

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Номер записи: 66
17-02-2022 дата публикации

Sand Consolidation Compositions And Methods Of Use

Номер: US20220049153A1
Автор: Radwan Amr
Принадлежит:

The present disclosure provides hydraulic fracturing treatment fluid compositions and systems, and methods of controlling proppant flowback and/or controlling sand production in a hydrocarbon-bearing formation using the hydraulic fracturing treatment fluid compositions and systems. 1. A water-based hydraulic fracturing treatment fluid system comprising:an uncoated proppant;a metal particle having a size no larger than 20 mesh; andan oxidization promoter,wherein the metal particle and the oxidization promoter are capable of creating an in situ oxidation reaction to increase proppants bonding.2. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein the uncoated proppant is sand claim 1 , a ceramic claim 1 , or sintered bauxite claim 1 , or any combination thereof.3. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein the uncoated proppant is fracturing sand.4. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein one or both of the metal particle and oxidization promoter are suspended in an aqueous or non-aqueous solvent.5. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein one or both of the metal particle and oxidization promoter are suspended in a non-aqueous solvent.6. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein one or both of the metal particle and oxidization promoter are in a dry form.7. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein the metal particle is an aluminum particle claim 1 , a silicon particle claim 1 , or an iron particle claim 1 , or any combination thereof.8. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein the metal particle has a size no larger than mesh.912-. (canceled)13. The water-based hydraulic fracturing treatment fluid system according to claim 1 , wherein ...

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Номер записи: 67
17-02-2022 дата публикации

Nanoclay Assisted High Temperature Crosslinked Fracturing Fluids

Номер: US20220049155A1
Автор: Liang Feng
Принадлежит:

A fracturing fluid is provided including a mixture of an aqueous copolymer composition including a copolymer, the copolymer having acrylamide monomer units, or acrylic acid monomer units, or both, or salts thereof. The molar includes a crosslinker and a nanoclay. 1. A fracturing fluid comprising a mixture of:an aqueous copolymer composition comprising a copolymer, the copolymer comprising acrylamide monomer units, or acrylic acid monomer units, or both, or salts thereof;a crosslinker comprising a metal; anda friction reducing additive, wherein the friction reducing additive comprises a nanoclay.2. The fracturing fluid of claim 1 , wherein the copolymer comprises 2-acrylamido-2-methylpropane-sulfonic acid monomer units or salts thereof.3. The fracturing fluid of claim 1 , wherein the fracturing fluid comprises 1 to 20 pounds of the nanoclay per thousand gallons of the fracturing fluid (0.12 kg/kL to 2.4 kg/kL).4. The fracturing fluid of claim 1 , wherein the fracturing fluid comprises about 2 pounds of the nanoclay per thousand gallons of the fracturing fluid.5. The fracturing fluid of claim 1 , wherein the nanoclay comprises a phyllosilicate structure with a thickness of about 1 nanometer (nm).6. The fracturing fluid of claim 1 , wherein a weight ratio of the metal to the copolymer is in a range of 0.01 to 0.8.7. The fracturing fluid of claim 1 , wherein a weight ratio of the metal to the copolymer is in a range of 0.2 to 0.6.8. The fracturing fluid of claim 2 , wherein the copolymer comprises 1 mol % to 25 mol % of the 2-acrylamido-2-methylpropanesulfonic acid monomer units.9. The fracturing fluid of claim 8 , wherein the copolymer comprises about 15 mol % of the 2-acrylamido-2-methylpropanesulfonic acid monomer units.10. The fracturing fluid of claim 1 , comprising at least one of a gel stabilizer claim 1 , a clay stabilizer claim 1 , a viscosity breaker claim 1 , a proppant claim 1 , and a pH adjusting agent.11. The fracturing fluid of claim 10 , comprising the ...

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Номер записи: 68
17-02-2022 дата публикации

MAGNETIC EMULSIONS AS CONTRAST AGENTS FOR SUBSURFACE APPLICATIONS

Номер: US20220049599A1
Автор: Abdel-Fattah Amr I., Servin Jesus Manuel Felix, Shi Nan
Принадлежит: Saudi Arabian Oil Company

Provided is an injection fluid that may include a nanoemulsion having an oil phase dispersed in an aqueous phase, and non-superparamagnetic magnetic nanoparticles that are present in the dispersed oil phase. Further provided is a method for preparing an injection fluid that may include preparing a nanoemulsion from an aqueous phase and an oil phase having non-superparamagnetic magnetic nanoparticles therein, and may be used to form nanodroplets of the non-superparamagnetic magnetic nanoparticles. Further provided is a method for tracking movement of an injection fluid. The method may include introducing a tagged injection fluid into a hydrocarbon-containing reservoir, the tagged injection fluid may be a nanoemulsion that includes: an aqueous phase, an oil phase dispersed in the aqueous phase, and non-superparamagnetic nanoparticles that are present in the dispersed oil phase; and tracking the movement of the tagged injection fluid. 1. An injection fluid , comprising:a nanoemulsion comprising an oil phase dispersed in an aqueous phase; andnon-superparamagnetic magnetic nanoparticles encapsulated in the dispersed oil phase;{'sup': ['−5', '−6'], '#text': 'wherein an interfacial tension between the oil phase and the aqueous phase is in a range from about 10to 10N/m.'}2. The composition of claim 1 , wherein the salinity of the injection fluid is between 1 claim 1 ,000 ppm and 56 claim 1 ,000 ppm TDS.3. The composition of claim 1 , further comprising a surfactant stabilizing the dispersion of the oil phase in the aqueous phase.4. The composition of claim 1 , wherein the non-superparamagnetic magnetic nanoparticles range from 1 nm to 1000 nm in diameter.5. The composition of claim 5 , wherein the non-superparamagnetic magnetic nanoparticles range from 50 nm to 500 nm in diameter.6. The composition of claim 1 , wherein the non-superparamagnetic magnetic nanoparticles include one or more elements from the group consisting of iron claim 1 , nickel claim 1 , and cobalt.7. The ...

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Номер записи: 69
31-01-2019 дата публикации

Co-grinding slag with other material for hydraulic binders

Номер: US20190031942A1
Автор: Darrell Chad Brenneis, Gregory Robert Hundt, James Robert Benkley, Jiten Chatterji
Принадлежит: Halliburton Energy Services Inc

A variety of systems, methods and compositions are disclosed for cementing in subterranean formations. Embodiments may include the use of slag co-grind in well cementing operations.

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Номер записи: 70
31-01-2019 дата публикации

A PROCESS FOR DISSOCIATION OF HYDRATES IN PRESENCE OF ADDITIVES OR HYDRATE DISSOCIATION PROMOTERS

Номер: US20190031943A1
Автор: Bhattacharjee Gaurav, Choudhary Nilesh, Chugh Parivesh, Kashyap Raj Kumar, Kumar Asheesh, Kumar Rajnish, Pande Nawal Kishore, ROY Sudip
Принадлежит:

The present invention discloses a process for the dissociation of natural gas hydrates comprises injecting additives or hydrate dissociation promoters into the system at the hydrate dissociation temperatures ranging from 283-293 K in conjunction with or without first depressurizing the system to pressures (50%-75%) below the hydrate equilibrium pressure and such leading to the recovery of methane or natural gases. 1. A process for dissociation of natural gas hydrates in a reactor system using additive as hydrate dissociation promoter in the form of nanoparticles alone or in combination thereof , the additives and/or promoters being in the range of 0.01 weight % to 5 weight % of the water , the process comprising:i. injecting additives as hydrate dissociation promoters into the reactor system at a temperature ranging from 283-293 K;ii. optionally depressurizing the reactor system of (i) to pressures 50% to 75% below the hydrate equilibrium pressure; andiii. recovering of methane or natural gases from (i) and (ii).2. The process as claimed in claim 1 , wherein the additives are with or without the loading of hydrogen bond modifiers.3. The process as claimed in claim 2 , wherein the hydrogen bond modifiers are selected from synthetic polymers or chemical additives of inorganic or organic nature.4. The process as claimed in claim 1 , wherein the additives are selected from hydrophobic amino acids claim 1 , zwitterionic compounds claim 1 , silicone oils claim 1 , amines claim 1 , amine oxides claim 1 , phospholipids claim 1 , sophorolipids claim 1 , lipids in the form of liposomes claim 1 , allyl phenol claim 1 , terpineol claim 1 , terpinyl acetate claim 1 , hydrogen peroxide claim 1 , ionic liquids claim 1 , polysaccharides claim 1 , and hydrogen bond forming compounds.5. The process as claimed in claim 4 , wherein the liposomes are in the form of nanoparticles and the liposome nanoparticles are used alone or in conjunction with capping agents which are pegged as ...

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Номер записи: 71
31-01-2019 дата публикации

METHODS AND MATERIALS FOR CONTROLLED RELEASE OF DESIRED CHEMISTRIES

Номер: US20190031951A1
Автор: Huffman Nicolas Daniel, Johnson Leah Marie, Mecham Jeffrey Brent, Norton Chasity Antoninette, Rothrock Ginger Denison, Shepherd Sarah Dorothy
Принадлежит:

The present disclosure relates to delivery and release systems wherein a plurality of particles is provided, and the particles are formed of a vehicle component and a cargo component. The systems and methods particularly can be useful in delivery of various chemicals to a petroleum reservoir. The vehicle component can undergo a change in situ such that at least a portion of the cargo component is released. 1. A delivery system comprising a plurality of particles that each comprise a vehicle and a cargo that is retained by the vehicle , which vehicle is configured to controllably release at least a portion of the cargo , wherein one or more of the following conditions are met:the vehicle is in the form of a shell defining an interior space in which the cargo is retained;the vehicle is substantially in the form of a monolith;the vehicle is at least partially degradable;the particles have an average size of about 5 μm or less.2. The delivery system of claim 1 , wherein the vehicle is in the form of a shell defining an interior space in which the cargo is retained claim 1 , and the shell comprises a plurality of layers.3. The delivery system of claim 1 , wherein the vehicle is in the form of a shell defining an interior space in which the cargo is retained claim 1 , and the interior space comprises a core material with which the cargo is combined.4. The delivery system of claim 1 , wherein the vehicle is in the form of a shell defining an interior space in which the cargo is retained claim 1 , and the cargo is configured as a plurality of units within the interior space defined by the shell.5. The delivery system of claim 1 , wherein the vehicle is in the form of a shell defining an interior space in which the cargo is retained claim 1 , and the cargo is controllably diffusible through the shell.6. The delivery system of claim 1 , wherein the vehicle is at least partially degradable via a mechanism selected from the group consisting of thermal degradation claim 1 , ...

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Номер записи: 72
30-01-2020 дата публикации

METHODS OF CONTROLLING FINES MIGRATION IN A WELL

Номер: US20200032127A1
Автор: Kovalchuk Anton, Kumar Deepak, Ventura Darryl
Принадлежит: Baker Hughes, a GE company, LLC

A method of treating a subterranean formation penetrated by a wellbore comprises introducing into the subterranean formation a treatment fluid comprising encapsulated particles having a core of a crosslinking agent and a shell of a chitosan encapsulant disposed on the core; releasing the crosslinking agent from the encapsulated particles with an acid; reacting the released crosslinking agent with the chitosan encapsulant or a derivative thereof forming a polymerized chitosan; and consolidating a plurality of particles in the subterranean formation with the polymerized chitosan. 1. A method of treating a subterranean formation penetrated by a wellbore , the method comprising:introducing into the subterranean formation a treatment fluid comprising encapsulated particles having a core of a crosslinking agent and a shell of a chitosan encapsulant disposed on the core;releasing the crosslinking agent from the encapsulated particles with an acid;reacting the released crosslinking agent with the chitosan encapsulant or a derivative thereof forming a polymerized chitosan; andconsolidating a plurality of particles in the subterranean formation with the polymerized chitosan.2. The method of claim 1 , wherein the crosslinking agent comprises an oxycellulose claim 1 , a tripolyphosphate claim 1 , a sulfate claim 1 , a citrate claim 1 , or a combination comprising at least one of the foregoing.3. The method of claim 1 , wherein the acid breaks the shell of the chitosan encapsulant thus releasing the crosslinking agent.4. The method of claim 3 , wherein the acid is pumped downhole before the treatment fluid is introduced into the subterranean formation.5. The method of claim 3 , wherein the acid is pumped downhole after the treatment fluid is introduced into the subterranean formation.6. The method of claim 1 , wherein the acid comprises hydrochloric acid claim 1 , acetic acid claim 1 , formic acid claim 1 , lactic acid claim 1 , sulfuric acid claim 1 , nitric acid claim 1 , or a ...

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Номер записи: 73
04-02-2021 дата публикации

SPACER FLUIDS AND CEMENT SLURRIES THAT INCLUDE SURFACTANTS

Номер: US20210032525A1
Автор: Al-Yami Abdullah, AlBahrani Hussain, Wagle Vikrant
Принадлежит: Saudi Arabian Oil Company

According to at least one embodiment of the present disclosure, a well bore cementing system may comprise a spacer fluid and a cement slurry. The spacer fluid may be positioned within a well bore, and the spacer fluid may comprise a first surfactant package comprising one or more surfactants. The cement slurry may be positioned within the well bore, and the cement slurry may comprise a second surfactant package comprising one or more surfactants. 1. A well bore cementing system comprising: a base fluid that is an aqueous-based fluid; and', {'sub': 2', '4', 'x1, 'a first surfactant package consisting essentially of one or more surfactants having the chemical structure R1-(OCH)—OH, where R1 is a hydrocarbyl group having from 5 to 20 carbon atoms, and x1 is an integer from 5 to 15, where the one or more surfactants of the first surfactant package has a HLB of from 11 to 13.5; and'}], 'a spacer fluid positioned within a well bore, the spacer fluid comprising{'sub': 2', '4', 'x2, 'a cement slurry positioned within the well bore, the cement slurry comprising a second surfactant package consisting essentially of one or more surfactants having the chemical structure R2-(OCH)—OH, where R2 is a hydrocarbyl group having from 5 to 20 carbon atom, and x2 is an integer from 5 to 15, where the one or more surfactants of the second surfactant package has a HLB of from 11 to 13.5.'}2. The well bore cementing system of claim 1 , where the cement slurry is in contact with the spacer fluid.3. The well bore cementing system of claim 1 , where the spacer fluid is in contact with a drilling fluid and the cement slurry.4. The well bore cementing system of claim 1 , where the one or more surfactants of the first surfactant package has a HLB of from 12.5 to 13 claim 1 , the one or more surfactants of the second surfactant package has a HLB of from 12.5 to 13 claim 1 , or both.5. The well bore cementing system of claim 1 , where x1 is an integer from 5 to 10 claim 1 , x2 is an integer from 5 ...

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Номер записи: 74
08-02-2018 дата публикации

Downhole fluids and methods of use thereof

Номер: US20180037795A1
Автор: B. Raghava Reddy, Jay P. Deville, Lee J. Hall, Peter James Boul, Samuel J. Lewis, Trissa Joseph, Vivek S. Goel, Xiangnan YE, Xueyu Pang
Принадлежит: Halliburton Energy Services Inc

The present disclosure relates to downhole fluid additives including a clay, a hydroxylated polymer, a cation, and water. The disclosure further relates to downhole fluids, including drilling fluids, spaces, cements, and proppant delivery fluids containing such as downhole fluid additive and methods of using such fluids. The downhole fluid additive may have any of a variety of functions in the downhole fluid and may confer any of a variety of properties upon it, such as salt tolerance or desired viscosities even at high downhole temperatures.

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Номер записи: 75
08-02-2018 дата публикации

Wellbore sealant using nanoparticles

Номер: US20180037797A1
Автор: Dominic Joseph Brady, Mohan Kanaka Raju Panga, Wael Abdallah
Принадлежит: Schlumberger Technology Corp

A wellbore is internally sealed using nanoparticles. Permeability properties are determined for a particular formation, along with its pore throat size distribution. A wellbore internal sealant (nanoparticle treatment fluid) is designed based on the determined permeability properties and pore throat size distribution. The nanoparticle treatment fluid is introduced into the formation. Pore throats within the formation are plugged by nanoparticles in the nanoparticle treatment fluid. Internal sealing reduces leak-off from filtercake damage, and also eliminates build-up of surface filtercake. Sealing the pore-structure of a particular wellbore zone alleviates the need for additional lost circulation material, resulting in a very thin filtercake and significantly reducing the chance of differential sticking. Oil-based muds can be replaced with water-based equivalents. The nanoparticle treatment fluid results in a permanent reduction in formation permeability, and therefore is particularly suitable for wells that will be stimulated using perforations, matrix acidizing, or fracturing techniques.

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Номер записи: 76
08-02-2018 дата публикации

METHODS AND WORKING FLUIDS FOR RECOVERING A HYDROCARBON MATERIAL CONTAINED WITHIN A SUBTERRANEAN FORMATION

Номер: US20180037808A1
Автор: Chakraborty Soma, Johnson Michael H.
Принадлежит:

A method of recovering a hydrocarbon material from a subterranean formation comprises forming a working fluid comprising substantially solid particles and an at least partially gaseous base material, the substantially solid particles exhibiting a greater heat capacity than the at least partially gaseous base material. The working fluid is introduced into a subterranean formation containing a hydrocarbon material to heat and remove the hydrocarbon material from the subterranean formation. An additional method of recovering a hydrocarbon material from a subterranean formation, and a working fluid are also described. 1. A working fluid , comprising:carbon dioxide gas; andsubstantially solid particles dispersed and stabilized within the carbon dioxide gas, the substantially solid particles each formulated to remain substantially solid up to a temperature of at least about 350° C. and each independently having a heat capacity of greater than or equal to about 0.1 kJ/kg-K.2. (canceled)3. The working fluid of claim 1 , wherein the substantially solid particles each independently have a thermal conductivity of greater than or equal to about 50 W/m-K.4. The working fluid of claim 1 , wherein at least some of the substantially solid particles comprise functional groups attached to surfaces thereof.5. A method of recovering a hydrocarbon material from a subterranean formation claim 1 , comprising:forming nanoparticles comprising at least one of graphite, graphene, fullerenes, diamond, nanofibers, clay, inorganic material, an organo-silicon material, and metal;combining the nanoparticles with carbon dioxide to form a working fluid; andinjecting the working fluid into a subterranean formation at a temperature greater than or equal to about 100° C. to heat and remove a hydrocarbon material contained within the subterranean formation.6. The method of claim 5 , wherein forming nanoparticles comprises forming the nanoparticles to have a heat capacity of greater than or equal to ...

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Номер записи: 77
12-02-2015 дата публикации

NOVEL AGENT FOR INHIBITING THE SWELLING OF CLAYS, COMPOSITIONS COMPRISING SAID AGENT AND METHODS IMPLEMENTING SAID AGENT

Номер: US20150041138A1
Автор: Badel Thierry, Cadix Arnaud
Принадлежит:

The present invention concerns the use of a novel additive as an agent for inhibiting the swelling of clays, in particular in the field of boreholes. More specifically, the present invention concerns the use of a specific diamine and diacid salt as an agent for inhibiting the swelling of clays in an aqueous medium, and a drilling or hydraulic fracturing fluid composition comprising the salt according to the invention and methods for drilling or hydraulic fracturing implementing said salt. 1. A method for inhibiting swelling of clays in an aqueous medium , comprising adding to the aqueous medium a salt of a diamine and a dicarboxylic acid according to formula I:{'br': None, 'HOOC-A-COOH\u2003\u2003(I)'}wherein A is a covalent bond or a saturated or unsaturated, linear or branched divalent aliphatic hydrocarbon group that comprises a main linear chain that extends between the two COON end groups of the dicarboxylic acid and comprises from 1 to 3 carbon atoms.2. The method according to claim 1 , wherein the diacid is chosen from malonic acid claim 1 , succinic acid claim 1 , glutaric acid claim 1 , methylmalonic acid claim 1 , dimethylmalonic acid claim 1 , ethylmalonic acid claim 1 , mesaconic acid claim 1 , methylsuccinic acid claim 1 , ethylsuccinic acid claim 1 , maleic acid claim 1 , fumaric acid claim 1 , itaconic acid claim 1 , methylglutaric acid and glutaconic acid.3. The method according to claim 2 , wherein the diacid is chosen from malonic acid claim 2 , succinic acid claim 2 , glutaric acid claim 2 , methylmalonic acid claim 2 , dimethylmalonic acid claim 2 , ethylmalonic acid claim 2 , methylsuccinic acid claim 2 , ethylsuccinic acid and methylglutaric acid.4. The method according to claim 3 , wherein the diacid is chosen from succinic acid claim 3 , glutaric acid and methylglutaric acid.5. The method according to claim 1 , wherein the diamine is a primary diamine of following formula II:{'br': None, 'sub': 2', '2, 'HN—Z—NH\u2003\u2003(II)'}{'sub': '2', ' ...

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Номер записи: 78
12-02-2015 дата публикации

Ferrous Nanoparticle Oil Extraction

Номер: US20150041399A1
Автор: Duncan Mark Arthur Tennant
Принадлежит: Individual

Ferrous Nanoparticle Oil Extraction is the process of introducing ferrous nanoparticles coated in an oleophilic surfactant into oil reservoirs and implementing a magnetic force within the oil to supplement the traditional suctioning forces to extract oil. The nanoparticles, once in the oil, are allowed to disperse by Brownian motion and bind to the oil particles. The oil-nanoparticle solution is then magnetized and drawn out of the well. The magnetic force, originating at the mouth of the extraction pipe, supplements the traditional suctioning forces. Once collected, the oil-nanoparticle solution is passed through a high gradient magnetic separator, separating the oil from the nanoparticles. The nanoparticles are ready for reuse in the process of ferrous nanoparticle oil extraction.

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Номер записи: 79
24-02-2022 дата публикации

Fluorescent Dye Loaded Polymeric Taggants for Depth Determination in Drilling Wells

Номер: US20220056329A1
Автор: AlJabri Nouf, Antoniv Marta, Marsala Alberto F., Zhu Shitong Sherry
Принадлежит:

A method of surface logging a well includes adding each of multiple polymeric taggants to a circulating drilling fluid in an addition sequence while drilling the well. Each polymeric taggant includes a polymer and a respective fluorescent dye having an emission wavelength or excitation wavelength different from that of each other fluorescent dye. The method includes taking a sample of drill cuttings carried by a drilling fluid while drilling a well, wherein the sample of drill cuttings includes polymeric taggants attached to the drill cuttings. The method includes extracting the dyes from the sample of drill cuttings into an extract solution; determining an indication of the type of and the concentration of each of the dyes in the extract solution; and determining a depth associated with the sample of drill cuttings based on the indication of the concentration of each of the dyes and on the addition sequence. 1. A method of surface logging a well , the method comprising:adding each of multiple polymeric taggants to a circulating drilling fluid in an addition sequence while drilling the well, wherein each polymeric taggant comprises a polymer and a respective fluorescent dye, wherein each fluorescent dye has an emission wavelength different from the emission wavelength of each other fluorescent dye, an excitation wavelength different from the excitation wavelength of each other fluorescent dye, or both;taking a sample of drill cuttings carried by a drilling fluid while drilling a well in the presence of the drilling fluid, wherein the sample of drill cuttings includes polymeric taggants attached to the drill cuttings;extracting the dyes from the sample of drill cuttings into an extract solution;determining an indication of the type of and the concentration of each of the dyes in the extract solution; anddetermining a depth associated with the sample of drill cuttings based on the indication of the concentration of each of the dyes and on the addition sequence.2. The ...

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Номер записи: 80
06-02-2020 дата публикации

DEVELOPMENT OF ANTI-BIT BALLING FLUIDS

Номер: US20200040247A1
Автор: Al-Yami Abdullah, AlBahrani Hussain, AlHareth Nasser, Awadh Abdulla H., Ba Hamdan Abdulaziz A., Haidary Saleh A., Safran Ali, Wagle Vikrant
Принадлежит: Saudi Arabian Oil Company

Anti-bit balling drilling fluids and methods of making and using drilling fluids are provided. The anti-bit balling drilling fluid contains water, a clay-based component, and at least one of a surfactant having the formula: R—(OCH)—OH, where R is a hydrocarbyl group having from 10 to 20 carbon atoms and x is an integer from 1 and 10, or a polyethylene glycol having the formula: H—(O—CH—CH)—OH, where n is an integer from 1 to 50. Methods of making and using these drilling fluids are also provided. 2. The method of claim 1 , where the surfactant has an HLB of from 8 to 16.3. The method of claim 1 , where R is:an alkyl group comprising 12 to 15 carbons; oran alkenyl group comprising from 12 to 15 carbon atoms.4. The method of claim 1 , where x is from 5 to 10.5. The method of claim 1 , where the surfactant has an HLB of from 13 to 15.6. The method of claim 1 , where the surfactant comprises ethylene oxide condensate of branched isotridecyl alcohol.7. The method of claim 1 , where the polyethylene glycol has a weight average molecular weight of from 300 grams per mol (g/mol) to 500 g/mol claim 1 , as measured according to GPC.8. The method of claim 1 , where the drilling fluid comprises from 28 to 850 lb/bbl water based on total weight of the drilling fluid.9. The method of claim 1 , where the drilling fluid comprises from 28 to 720 lb/bbl of the clay-based component based on total weight of the drilling fluid.10. The method of claim 1 , where the drilling fluid comprises from 0.02 to 180 lb/bbl of the surfactant claim 1 , the polyethylene glycol claim 1 , or both claim 1 , based on total weight of the drilling fluid.11. The method of claim 1 , where the clay-based component comprises one or more components selected from the group consisting of lime (CaO) claim 1 , CaCO claim 1 , bentonite claim 1 , montmorillonite clay claim 1 , barium sulfate (barite) claim 1 , hematite (FeO) claim 1 , mullite (3AlO.2SiOor 2AlO.SiO) claim 1 , kaolin claim 1 , (AlSiO(OH)or kaolinite) ...

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Номер записи: 81
06-02-2020 дата публикации

Breaker Fluids for Wellbore Fluids and Methods of Use

Номер: US20200040248A1
Автор: Kippie David P.
Принадлежит:

Compositions and methods for producing a hydrocarbon from a formation include drilling the formation with a drill-in fluid to form a wellbore and emplacing a fluid loss composition in the wellbore. The fluid loss composition may include an aqueous fluid, a viscosifier, a water soluble polar organic solvent, a delayed acid source having a hydrolyzable ester configured to hydrolyze in situ, and a weighting agent. A viscosity of the fluid loss composition may be reduced by shutting the wellbore for a predetermined time and releasing an organic acid from a time-delayed hydrolysis of the hydrolyzable ester, wherein an amount of delay prior to the time-delayed hydrolysis of the hydrolyzable ester is greater than 1 hour. 1. A method of producing a hydrocarbon from a formation , the method comprising:drilling the formation with a drill-in fluid to form a wellbore; an aqueous fluid;', 'a viscosifier;', 'a water soluble polar organic solvent;', 'a delayed acid source; and', 'a weighting agent; and, 'emplacing a fluid loss composition in the wellbore, wherein the fluid loss composition comprisesshutting the well for a predetermined time to allow the viscosity of the fluid loss composition to decrease.2. The method of claim 1 , further comprising:allowing formation fluids to enter into the wellbore; andproducing fluids from the well.3. The method of claim 1 , wherein the emplacing the fluid loss composition in the wellbore occurs after producing fluids from the wellbore.4. The method of claim 1 , wherein the emplacing the fluid loss composition in the wellbore occurs simultaneous as performing an at least one completion operation.5. The method of claim 1 , further comprising:performing at least one completion operation after the emplacing.6. The method of claim 1 , wherein the emplacing the fluid loss composition in the wellbore occurs after performing an at least one completion operation.7. The method of claim 1 , wherein the wellbore contains at least one selected from the ...

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Номер записи: 82
18-02-2021 дата публикации

Methods of making cement slurries and cured cement and use thereof

Номер: US20210047556A1
Автор: Ashok Santra, Peter J. Boul
Принадлежит: Saudi Arabian Oil Co

Cured cements, cement slurries, and methods of making cured cement and methods of using cement slurries are provided. The method of making a modified cement slurry includes adding particles comprising carbon nanotube sponges disposed on sacrificial templates to a cement slurry to form the modified cement slurry and allowing the sacrificial templates to disintegrate, thereby leaving the carbon nanotube sponges dispersed throughout the modified cement slurry.

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Номер записи: 83
16-02-2017 дата публикации

METHODS OF DELIVERING CALCIUM CARBONATE PRODUCING MICROBES OR ENZYMES DOWNHOLE

Номер: US20170044420A1
Автор: Armstrong Charles David, Vorderbruggen Mark A., Wilson Michael B.
Принадлежит: BAKER HUGHES INCORPORATED

A method of delivering a microbe or enzyme to a selected location comprises conveying a coated aggregate to a selected location; wherein the coated aggregate comprises an aggregate and a coating disposed on the aggregate; the coating comprising a polymer matrix and a calcium carbonate producing agent comprising a microbe, an enzyme, or a combination comprising at least one of the foregoing. 1. A method of delivering a microbe or enzyme to a selected location , the method comprising:conveying a coated aggregate to a selected location; the coated aggregate comprising an aggregate and a coating disposed on the aggregate; the coating comprising a polymer matrix and a calcium carbonate producing agent comprising a microbe, an enzyme, or a combination comprising at least one of the foregoing.2. The method of claim 1 , wherein conveying the coated aggregate comprises pumping the coated aggregate into a wellbore penetrating a subterranean formation.3. The method of claim 2 , wherein conveying the coated aggregate comprises pumping a settable composition comprising the coated aggregate into the wellbore.4. The method of claim 3 , wherein the settable composition further comprises an uncoated aggregate.5. The method of claim 1 , wherein the weight ratio of the coated aggregate relative to the uncoated aggregate is about 1:99 to about 99:1.6. The method of claim 3 , further comprising allowing the settable composition to set.7. The method of claim 6 , wherein the calcium carbonate producing agent is present in an amount effective to set the settable composition in about 10 minutes to about 48 hours in the wellbore.8. The method of claim 1 , further comprising activating the calcium carbonate producing agent.9. The method of claim 8 , wherein activating the calcium carbonate producing agent comprisesreleasing the calcium carbonate producing agent from the coating; andcontacting the released calcium carbonate producing agent with urea, a calcium ion source, water, and a nutrient ...

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Номер записи: 84
16-02-2017 дата публикации

Solid-stabilized emulsion

Номер: US20170044421A1
Автор: Andrei-Nicolae Parvulescu, Lorenz Siggel, Riichiro Kimura, Roelf-Peter BAUMANN, Stefam MAURER, Ulrich Müller
Принадлежит: Wintershall Holding GmbH

The present invention relates to an emulsion comprising: a) water, b) at least one crude oil and c) at least one layered double hydroxide of general formula (I), whereby the layered double hydroxide of general formula (I) is present in the form of solid particles. The present invention further relates to a process for the preparation of the emulsion and the use of the same.

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Номер записи: 85
16-02-2017 дата публикации

STABILITY IMPROVEMENT OF CO2 FOAM FOR ENHANCED OIL RECOVERY APPLICATIONS USING POLYELECTROLYTES AND POLYELECTROLYTE COMPLEX NANOPARTICLES

Номер: US20170044425A1
Автор: BARATI GHAHFAROKHI REZA
Принадлежит:

Polyelectrolyte nanoparticles are generated to stabilize foam for use in enhanced oil recovery. Stability is further enhanced by optimizing pH and a ratio of polycationic and polyanioinic materials, resulting in stronger and longer lasting foams in the presence of crude oil. Use of these nanoparticles results in negligible damage to formation permeability. 1. In a foam including a non-liquid fluid phase and a liquid dispersion phase , the improvement comprising:the foam having a foam quality ranging from 60% to 90% determined as a percentage total foam volume occupied by the non-liquid fluid phase;the liquid dispersion phase being a dispersion of polyelectrolyte material and surfactant in water,the polyelectrolyte material and the surfactant being combined in a ratio of surfactant to polyelectrolyte material ranging from 3:1 to 9:1;the polyelectrolyte material forming nanoparticles by the action of cationic and anionic polyelectrolytes,the nanoparticles being located at lamellae of the liquid dispersion phase in an effective amount to stabilize the foam;the polyelectrolyte material being present in an amount ranging from 0.1% to 5% of the liquid phase by weight.2. The foam of claim 1 , further comprising a pH adjusting agent in an effective amount to reduce pH of the foam to a value ranging from 5 to 9.3. The foam of claim 1 , wherein the foam quality ranges from 60% to 90% of the non-liquid fluid phase by volume.4. The foam of claim 1 , wherein the foam quality is assessed as a matter of design to exist at conditions of pressure and temperature in an intended environment of use including a petroleum reservoir.5. The foam of claim 4 , wherein the non-liquid fluid phase comprises COin a supercritical state.6. The foam of claim 1 , wherein the surfactant is a nonionic surfactant.7. The foam of claim 1 , wherein the surfactant is an anionic surfactant.8. The foam of wherein the polycationic material is selected from the group consisting of polyethylenimine claim 1 , ...

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Номер записи: 86
15-02-2018 дата публикации

Stabilized pillars for hydraulic fracturing field of the disclosure

Номер: US20180044576A1
Автор: Danil Sergeevich PANTSURKIN, Geza Horvath Szabo, Mohan Kanaka Raju Panga
Принадлежит: Schlumberger Technology Corp

Methods of strengthening a proppant pack and resulting proppant pillar from both the inside and outside are described. Embodiments various additives to facilitate proppant/proppant interaction and modifying proppant surface to facilitate proppant interaction. Embodiments also include the use of protective coatings, some of which have embedded fibers or chemical moieties to divert flow from pillar.

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Номер записи: 87
15-02-2018 дата публикации

FORMING PROPPANT PACKS HAVING PROPPANT-FREE CHANNELS THEREIN IN SUBTERRANEAN FORMATION FRACTURES

Номер: US20180044577A1
Автор: BENOIT Denise, Lu Zheng, MONTENEGRO-GALINDO Gladys Rocio, Nguyen Philip D., Yang Yuming
Принадлежит:

Methods including pumping a fracturing fluid into a subterranean formation through an annulus between the subterranean formation and a pipe conveyance at a rate above a fracture gradient of the subterranean formation to create and/or open at least one fracture in the subterranean formation; continuously pumping a proppant-free fluid into the subterranean formation through the annulus at a first rate to extend the open fracture; continuously pumping a proppant fluid through an interior of the pipe conveyance and out the exit of the interior of the pipe conveyance at a second rate that is less than the first rate; and placing the proppant particulates into a portion of a fracture in the subterranean formation so as to form a proppant pack having proppant-free channels therein. 1. A method comprising:providing a fracturing fluid comprising a first base fluid and a first gelling agent;providing proppant-free fluid comprising a second base fluid and a second gelling agent; 'wherein the proppant-free fluid and the proppant fluid are substantially immiscible;', 'providing a proppant fluid comprising a third base fluid, a third gelling agent, and proppant particulates,'}pumping the fracturing fluid through an annulus formed between a subterranean formation and a pipe conveyance at a rate above a fracture gradient of the subterranean formation to create and/or open at least one fracture in the subterranean formation;continuously pumping the proppant-free fluid into the subterranean formation through the annulus at a first rate to extend the open fracture; 'wherein the proppant fluid and the proppant-free fluid are present simultaneously in a portion of the subterranean formation but remain substantially immiscible; and', 'continuously pumping the proppant fluid through an interior of the pipe conveyance and out an exit of the interior of the pipe conveyance at a second rate that is less than the first rate,'}placing the proppant particulates into a portion of a fracture in ...

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Номер записи: 88
03-03-2022 дата публикации

Cationic nitrogen-containing heterocycles and their application in wellbore stability

Номер: US20220064512A1
Автор: Carl Thaemlitz, Hasmukh A. Patel
Принадлежит: Saudi Arabian Oil Co

In accordance with one or more embodiments of the present disclosure, a method of inhibiting shale formation during water-based drilling of subterranean formations includes introducing a shale inhibitor to the subterranean formation during the water-based drilling, the shale inhibitor comprising a cationic polymer comprising repeating units of [A-B]. A is a substituted benzene or a substituted triazine of formula (2). B is a N-containing heterocycle. The cationic polymer and a method of making the cationic polymer are also described.

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Номер записи: 89
03-03-2022 дата публикации

Profile control and oil displacement agent for oil reservoir and preparation method thereof

Номер: US20220064517A1
Автор: Gaoshen Su, Huan Yang, Wei Wang, Xiaorong Yu
Принадлежит: Yangtze University

The present disclosure relates to a profile control and oil displacement agent for an oil reservoir and a preparation method thereof. The profile control and oil displacement agent is prepared by uniformly dispersing polymer microspheres, an activator and a solvent. The polymer microspheres are micron-sized dry-powdered microspheres, which are prepared by stirring and polymerizing a first monomer, a second monomer, an initiator, a hydrophobic nano-powder and water in a specific proportion. The profile control and oil displacement agent of the present disclosure can reduce the oil-water interfacial tension, has good long-term stability, simple preparation and low cost, avoids solvent waste, and can be applied to the deep profile control and oil displacement system of oil fields.

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Номер записи: 90
14-02-2019 дата публикации

SUSPENSIONS FOR REMOVING HYDROCARBONS FROM SUBTERRANEAN FORMATIONS AND RELATED METHODS

Номер: US20190048251A1
Автор: Agrawal Devesh Kumar, Khabashesku Valery N., Murugesan Sankaran
Принадлежит:

A suspension for removing hydrocarbons from a subterranean formation includes a fluid comprising at least one of water, brine, steam, carbon dioxide, a light hydrocarbon, and an organic solvent; and a plurality of nanoparticles dispersed with the fluid. Nanoparticles of the plurality comprise silica and carbon. A method includes forming a plurality of nanoparticles and dispersing the plurality of nanoparticles with a fluid to form a suspension comprising the nanoparticles. A method of recovering a hydrocarbon material includes introducing a suspension into a subterranean formation containing hydrocarbons, forming a stabilized emulsion of the suspension and the hydrocarbons within the subterranean formation; and removing the emulsion from the subterranean formation. The suspension comprises a plurality of nanoparticles, and at least some nanoparticles of the plurality comprise silica and carbon. 1. A suspension for removing hydrocarbons from a subterranean formation , the suspension comprising:a fluid comprising at least one of water, brine, steam, carbon dioxide, a light hydrocarbon, and an organic solvent; anda plurality of nanoparticles dispersed with the fluid, at least some nanoparticles of the plurality comprising both silica and carbon.2. The suspension of claim 1 , wherein the at least some nanoparticles of the plurality comprise a silica nanoparticle attached to at least one material selected from the group consisting of carbon nanodots claim 1 , graphene claim 1 , graphene oxide claim 1 , carbon nanotubes claim 1 , and functionalized carbon nanotubes.3. The suspension of claim 1 , wherein the at least some nanoparticles of the plurality of nanoparticles exhibit a mean diameter from about 5 nm to about 50 nm.4. The suspension of claim 1 , wherein the at least some nanoparticles of the plurality are hydrophilic.5. The suspension of claim 1 , wherein the at least some nanoparticles of the plurality comprise silica and carbon bonded by hydroxyl groups.6. The ...

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Номер записи: 91
25-02-2021 дата публикации

ACIDIZING SOLUTION FOR DISSOLUTION OF CLAY MINERAL AND PREPARATION METHOD THEREOF

Номер: US20210054261A1
Автор: CHEN Sirui, DONG Xiaofang, QIU Longwei, QU Xiyu, WANG GUANMIN, ZHANG Yangchen
Принадлежит:

The invention provides an acidizing solution for dissolution of a clay mineral and a preparation method thereof. The acidizing solution comprises hydrochloric acid, fluoboric acid, acetic acid, trifluoroacetic acid, hydrogen peroxide, ammonium chloride, dimethylamino-methylbenzotriazole, alkyl ammonium chloride, and polymethylacrylic acid. The acidizing solution provided by the invention can effectively dissolve organic matter, such as clay minerals and cements, in a high-temperature oil-gas reservoir over 160° C., inhibit swelling and migration of clay particles in the presence of water in the acidizing process, avoid secondary deposition of the reservoir, and improve the permeability of the reservoir. The acidizing solution can be prepared and used on the field conveniently and is safe and reliable. 1. An acidizing solution for dissolution of a clay mineral , comprising:hydrochloric acid, fluoboric acid, acetic acid, trifluoroacetic acid, hydrogen peroxide, and ammonium chloride; anddimethylamino-methylbenzotriazole, alkyl ammonium chloride, and polymethylacrylic acid.2. The acidizing solution for dissolution of a clay mineral according to claim 1 , wherein in the acidizing solution claim 1 , the mass concentration of hydrochloric acid is 10%-15% claim 1 , the mass concentration of fluoboric acid is 5%-15% claim 1 , the mass concentration of acetic acid is 0-3% claim 1 , the mass concentration of trifluoroacetic acid is 4%-9% claim 1 , the mass concentration of hydrogen peroxide is 15%-25% claim 1 , the mass concentration of ammonium chloride is 5% claim 1 , the mass concentration of dimethylamino-methylbenzotriazole is 1.5%-2% claim 1 , the mass concentration of alkyl ammonium chloride is 0.5%-2% claim 1 , the mass concentration of polymethylacrylic acid is 0.2%-1% claim 1 , and the balance is water.3. The acidizing solution for dissolution of a clay mineral according to claim 2 , wherein the alkyl ammonium chloride is at least one of N-octadecyl propylidene ...

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Номер записи: 92
25-02-2021 дата публикации

NANOPARTICLE COATED PROPPANTS AND METHODS OF MAKING AND USE THEREOF

Номер: US20210054263A1
Автор: Haque Mohammad Hamidul, Saini Rajesh Kumar, Sayed Mohammed
Принадлежит: Aramco Services Company

Methods for producing proppant with nanoparticle proppant coating are provided. The methods include coating the proppant particles with a strengthening agent, functionalized nanoparticles, and unfunctionalized organic resin to produce proppant with nanoparticle proppant coating. Additionally, a proppant comprising a proppant particle and a nanoparticle proppant coating is provided. The nanoparticle proppant coating includes a strengthening agent, functionalized nanoparticles, and unfunctionalized organic resin. The nanoparticle proppant coating coats the proppant particle. Additionally, a method for increasing a rate of hydrocarbon production from a subsurface formation through the use of the proppant is provided. 1. A nanoparticle coated proppant comprising:a proppant particle comprising sand, ceramic material, or combinations thereof; and unfunctionalized organic resin,', 'a strengthening agent comprising at least one of carbon nanotubes, silica, alumina, glass, mica, graphite, talc, nanoclay, graphene, carbon nanofibers, boron nitride nanotubes, vanadium pentoxide, zinc oxide, calcium carbonate, zirconium oxide, titanium oxide, silicon nitride, silicon carbide, or aramid fibers, and', 'functionalized nanoparticles adhered to the unfunctionalized organic resin, in which the functionalized nanoparticles comprise nanoparticles having at least one attached hydrophobic moiety, oleophobic moiety, or omniphobic moiety., 'a nanoparticle proppant coating coats the proppant particle, the nanoparticle proppant comprising'}2. The nanoparticle coated proppant of claim 1 , in which the at least one attached hydrophobic moiety claim 1 , oleophobic moiety claim 1 , or omniphobic moiety comprises organosilicon.3. The nanoparticle coated proppant of claim 1 , in which the at least one attached hydrophobic moiety claim 1 , oleophobic moiety claim 1 , or omniphobic moiety comprises a halogen.4. The nanoparticle coated proppant of claim 1 , in which the functionalized nanoparticles ...

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Номер записи: 93
13-02-2020 дата публикации

NANOSILICA DISPERSION WELL TREATMENT FLUID

Номер: US20200048526A1
Автор: Al-Yami Abdullah, Wagle Vikrant
Принадлежит:

A well treatment fluid is provided having an acidic nanosilica dispersion and an alkanolamine. The nanosilica dispersion and the alkanolamine may form a gelled solid after interaction over a period. Methods of reducing water production using the well treatment fluids are also provided. 1. A treatment fluid for reducing water production in a treatment zone in a wellbore , comprising:an acidic nanosilica dispersion; andan alkanolamine, the alkanolamine selected to form a gelled solid after interaction with the acidic nanosilica dispersion for a period.2. The treatment fluid of claim 1 , wherein the period comprises a range of 0.5 hours to 24 hours.3. The treatment fluid of claim 1 , consisting of the acidic nanosilica dispersion and the alkanolamine.4. The treatment fluid of claim 1 , wherein the acidic nanosilica dispersion comprises amorphous silicon dioxide in the range of 5% w/w to about 50% w/w.5. The treatment fluid of claim 4 , wherein the acidic nanosilica dispersion comprises water in the range of 50 w/w % to 95 w/w %.6. The treatment fluid of claim 1 , wherein the alkanolamine comprises monoethanolamine.7. A solid gelled material useful for reducing water production where the solid gelled material forms by introducing an acidic nanosilica dispersion and the alkanolamine to a treatment zone claim 1 , the acidic nanosilica dispersion comprising:amorphous silicon dioxide in the range of 5 weight percentage of the total weight (w/w %) to about 50 w/w %; andwater in the range of 50 w/w % to 95 w/w %;such that the acidic nanosilica dispersion and the alkanolamine contact the treatment zone having an elevated temperature for a period such that the solid gelled material forms.8. The solid gelled material of claim 7 , wherein the acidic nanosilica dispersion has a pH that is acidic.9. The solid gelled material of claim 7 , wherein the lost circulation zone is carbonate.10. The solid gelled material of claim 9 , wherein the acidic nanosilica dispersion has a pH value ...

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Номер записи: 94
13-02-2020 дата публикации

IN-SITU GENERATION OF GLASS-LIKE MATERIALS INSIDE SUBTERRANEAN FORMATION

Номер: US20200048527A1
Автор: AL-MOHSIN Ayman, BATAWEEL Mohammed, KARADKAR Prasad Baburao, OTHMAN Haitham A.
Принадлежит: Saudi Arabian Oil Company

Systems and methods for forming a permanent plug in a subterranean formation include providing a solution of colloidal silica and pumping the colloidal silica into a bore of a subterranean well so that the colloidal silica penetrates pores of the subterranean formation. The colloidal silica within the pores of the subterranean formation is dehydrated to form a glass-like material within the pores of the subterranean formation. 1. A method for forming a permanent plug in a subterranean formation , the method including:providing a solution of colloidal silica;pumping the colloidal silica into a bore of a subterranean well so that the colloidal silica penetrates pores of the subterranean formation;dehydrating the colloidal silica within pores of the subterranean formation to form a glass-like material within the pores of the subterranean formation.2. The method of claim 1 , further comprising before pumping the colloidal silica into the bore of the subterranean well claim 1 , mixing an activator with the colloidal silica so that the colloidal silica forms a gel within the pores of the subterranean formation.3. The method of claim 1 , wherein dehydrating the colloidal silica includes lowering a microwave system into the bore of the subterranean well and operating the microwave system to generate heat.4. The method of claim 3 , further including locating a microwave enabler within the subterranean well and heating the microwave enabler with the microwave system.5. A method for forming a permanent plug in a subterranean formation claim 3 , the method including:providing a solution of colloidal silica, the solution of colloidal silica including a stabilized mixture of silica particles suspended in a liquid;pumping the colloidal silica into a bore of a subterranean well so that the colloidal silica penetrates pores of the subterranean formation;providing for gelling-up of the solution of colloidal silica to provide a gel of colloidal silica within pores of the subterranean ...

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Номер записи: 95
13-02-2020 дата публикации

Frac Fluids for Far Field Diversion

Номер: US20200048532A1
Автор: Fu Diankui, Shen Lingjuan, Vigderman Leonid
Принадлежит: BJ Services, LLC

Aqueous well treatment fluids are provided especially for use in far field diversion in low viscosity carrier fluids. The fluids comprise water, a friction reducer, and a diverter. The diverter comprises dissolvable particulates and proppants. The dissolvable particulates have a specific gravity of from about 0.9 to about 1.6 and a particle size of about 50 mesh or less. The proppants have a specific gravity of from about 0.9 to about 1.4 and a particle size of from about 20 to about 100 mesh. The dissolvable particulates have a higher specific gravity and a smaller particle size than the proppant. 1. An aqueous well treatment fluid , said well treatment fluid comprising:(a) water;(b) a friction reducer; [ (1) a specific gravity of from about 0.9 to about 1.6; and', '(2) a particle size of about 50 mesh or less; and, 'i) dissolvable particulates having, (1) a specific gravity of from about 0.9 to about 1.4; and', '(2) a particle size of from about 20 to about 100 mesh; and, 'ii) proppants having, 'iii) wherein said dissolvable particulates have a higher specific gravity and a smaller particle size than said proppant., '(c) a diverter, said diverter comprising2. The fluid of claim 1 , where the ratio of said specific gravity of said dissolvable particulates to said specific gravity of said proppant is from about 1 to about 1.6.3. The fluid of claim 1 , where the ratio of said specific gravity of said dissolvable particulates to said specific gravity of said proppant is from about 1 to about 1.3.4. The fluid of claim 1 , wherein said fluid has a viscosity of about 12 cps or less.5. The fluid of claim 1 , wherein said fluid has a viscosity of about 8 cps or less.6. The fluid of claim 1 , wherein the ratio of the maximum particle size of said proppant to that of said dissolvable particulates is from about 1.5 to about 8.7. The fluid of claim 1 , wherein the ratio of the maximum particle size of said proppant to that of said dissolvable particulates is from about 2 to ...

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Номер записи: 96
22-02-2018 дата публикации

Liquid loaded powders made from hybrid calcium carbonate for oil and gas drilling fluids

Номер: US20180051200A1
Автор: Dennis K. Clapper
Принадлежит: Baker Hughes Inc

A method for introducing an organic drilling fluid additive into an aqueous drilling fluid in a subterranean formation, where the method includes introducing loaded microparticles into an aqueous drilling fluid. The loaded microparticles are made by absorbing at least one organic drilling fluid additive onto hybrid calcium carbonate microparticles to form loaded microparticles. The method further includes delivering the drilling fluid into a subterranean formation, and optionally shearing the loaded microparticles to release the absorbed drilling fluid additive(s) into the drilling fluid, such as by shearing them at the drill bit.

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Номер записи: 97
13-02-2020 дата публикации

Nanoparticle-Based Shear-Thickening Materials

Номер: US20200048984A1
Автор: Al-Olayan Abeer Mohammad Saleh, Alexander-Katz Alfredo, Cox Jason R.
Принадлежит:

A composition includes an aqueous colloidal dispersion of a nanomaterial. The nanomaterial includes, disposed on a surface of the nanomaterial, a first coupling agent including silane and a functional group including an amino acid. The nanomaterial includes, disposed on the surface of the nanomaterial, a second coupling agent including silane and a polymer with a molecular weight between 1,000 and 20,000. 1. A composition comprising an aqueous colloidal dispersion of a nanomaterial including , disposed on a surface thereof:a first coupling agent comprising silane and a functional group comprising an amino acid, anda second coupling agent comprising silane and a polymer with a molecular weight between 1,000 and 20,000.2. The composition of claim 1 , wherein the amino acid is a polar amino acid.3. The composition of claim 1 , wherein the polymer is polyethylene glycol or polyethylene oxide.4. The composition of claim 1 , wherein the aqueous colloidal dispersion is a shear-thickening material.5. The composition of claim 1 , wherein a potential of hydrogen (pH) of the aqueous colloidal dispersion is in a range of 9 to 10.6. The composition of claim 1 , wherein heating the aqueous colloidal dispersion to a temperature above 90 degrees Celsius (° C.) causes a viscosity of the aqueous colloidal dispersion to reversibly increase by a factor of 1.5 to 15.7. The composition of claim 1 , wherein applying a shear on the aqueous colloidal dispersion causes a viscosity of the aqueous colloidal dispersion to reversibly increase by a factor of 1.1 to 3.8. The composition of claim 1 , wherein a ratio between the first coupling agent and the second coupling agent disposed on the surface of the nanomaterial is between 1:1 and 20:1.9. The composition of claim 1 , wherein the nanomaterial comprises silica nanoparticles having an average particle size of equal to or less than approximately 1 micrometer (μm).10. The composition of claim 9 , wherein the silica nanoparticles have an average ...

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Номер записи: 98
26-02-2015 дата публикации

AQUEOUS DOWNHOLE FLUIDS HAVING CHARGED NANO-PARTICLES AND POLYMERS

Номер: US20150057196A1
Автор: Debord Saet B., Tanifum Christabel
Принадлежит: BAKER HUGHES INCORPORATED

Charged nanoparticles may be added to an aqueous downhole fluid having polymers therein where the charged nanoparticles may crosslink at least a portion of the polymers. The polymers may be or include, but are not limited to polyacrylamide, xanthan, guar, polyacrylic acid, poly 2-acrylamido-2-methyl-1-propane sulfonic acid (AMPS), polyethylene oxide, polypropylene oxide, or combinations thereof. The polymers may be homopolymers, copolymers, terpolymers, or combinations thereof. The charged nanoparticles may be or include, but are not limited to clay nanoparticles, modified nanoparticles, or combinations thereof. The aqueous downhole fluid may be or include, but is not limited to fracturing fluids, injection fluids, and combinations thereof for performing a fracturing operation, an injection operation, another enhanced oil recovery operation, and the like. 1. A fluid composition comprising:an aqueous downhole fluid selected from the group consisting of fracturing fluids, injection fluids, and combinations thereof;at least one polymer selected from the group consisting of polyacrylamide, xanthan gum, guar gum, polyacrylic acid, poly 2-acrylamido-2-methyl-1-propane sulfonic acid (AMPS), polyethylene oxide, polypropylene oxide, and combinations thereof; and wherein the polymers are selected from the group consisting of homopolymers, copolymers, terpolymers, and combinations thereof;charged nanoparticles in an amount effective to crosslink at least a portion of the polymers, where the charged nanoparticles are selected from the group consisting of clay nanoparticles, modified nanoparticles, and combinations thereof.2. The fluid composition of claim 1 , wherein the clay nanoparticles are selected from the group consisting of laponite claim 1 , bentonite claim 1 , and combinations thereof.3. The fluid composition of claim 1 , wherein the modified nanoparticles are selected from the group consisting of modified graphene nanoparticles claim 1 , modified graphene platelets ...

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Номер записи: 99
10-03-2022 дата публикации

INFUSED AND COATED PROPPANT CONTAINING CHEMICAL TREATMENT AGENTS AND METHODS OF USING SAME

Номер: US20220073813A1
Автор: Cady Daniel, Cannan Chad, CONNER Mark, Duenckel Robert, Leasure Joshua, LIENG Thu, Read Peter A., Roper Todd
Принадлежит:

Proppant compositions and methods for using same are disclosed herein. In particular, a proppant composition for use in hydraulic fracturing is disclosed herein. The proppant composition can contain a plurality of particulates and at least one particulate of the plurality of particulates containing a chemical treatment agent. The at least one particulate having a long term permeability measured in accordance with ISO 13503-5 at 7,500 psi of at least about 10 D. The at least one chemical treatment agent can separate from the at least one particulate when located inside a fracture of a subterranean formation after a period of time. 1. A proppant composition , the composition comprising:a proppant particulate;a non-degradable coating disposed onto the proppant particulate;a degradable shell encapsulating at least a portion of the non-degradable coating; anda chemical treatment agent, wherein a first portion of the chemical treatment agent is blended with the non-degradable coating; andwherein the chemical treatment agent is configured to separate from the proppant particulate upon degradation of the degradable shell.2. The composition of claim 1 , wherein the proppant particulate has an internal interconnected porosity of about 5% to about 75%.3. The composition of claim 1 , wherein the chemical treatment agent comprises a scale inhibitor claim 1 , a salt inhibitor claim 1 , a hydrogen sulfide scavenger claim 1 , an iron sulfide scavenger claim 1 , or any combination thereof.4. The composition of claim 3 , wherein the scale inhibitor comprises diethylenetriamine penta(methylene phosphonic acid) or one or more potassium salts of maleic acid copolymers.5. The composition of claim 3 , wherein the salt inhibitor comprises potassium ferricyanide.6. The composition of claim 1 , wherein the non-degradable coating is a phenolic novolac resin.7. The composition of claim 1 , wherein a second portion of the chemical treatment agent is blended with the degradable shell.8. The ...

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Номер записи: 100