СПОСОБ ГИДРОФОБНОЙ ОБРАБОТКИ ПРИЗАБОЙНОЙ ЗОНЫ ПРОДУКТИВНОГО ПЛАСТА

Изобретение относится к нефтегазодобывающей промышленности, в частности к способам повышения продуктивности скважин и ограничения притока пластовых вод для повышения нефтеотдачи и газоотдачи пластов с использованием физико-химических методов воздействия. Технический результат - повышение эффективности и надежности гидрофобизации призабойной зоны пласта за счет уменьшения и прекращения фильтрации воды, увеличения притока углеводородов и увеличения продолжительности эффекта гидрофобизации. В способе гидрофобной обработки призабойной зоны продуктивного пласта, включающем нагнетание в порово-трещинное пространство призабойной зоны пласта смеси поверхностно-активных веществ, выдержку скважины в покое для капиллярной пропитки и перевод в режим притока углеводородов, в качестве указанной смеси используют раствор, содержащий, мас.%: смесь многоатомных спиртов - побочный продукт при производстве моно-, ди- и триэтиленгликолей 75,0-96,0, концентрат головных примесей производства этилового спирта ...

СПОСОБ РАЗРАБОТКИ ОБВОДНЕННОЙ НЕФТЯНОЙ ЗАЛЕЖИ

Изобретение относится к нефтедобывающей промышленности и может быть использовано для регулирования разработки нефтяных месторождений, выравнивания профиля приемистости нагнетательных скважин и ограничения притока пластовых вод в нефтяных скважинах. Способ разработки обводненной нефтяной залежи включает отбор жидкости из добывающих скважин и периодическую закачку в нагнетательные скважины осадкообразующего реагента щелочного типа, при этом раствор указанного осадкообразующего реагента закачивают в две стадии, первоначально закачивают раствор с концентрацией реагента 0,1-5 мас.%, а затем раствор с концентрацией реагента 5-25 мас.%, после чего дополнительно закачивают раствор хлорида кальция, в качестве осадкообразующего реагента щелочного типа используют фосфат натрия, а соотношение фосфата натрия, закачиваемого на второй стадии, и хлорида кальция составляет 1:0,7-1,3. Технический результат - повышение эффективности разработки обводненной нефтяной залежи за счет увеличения коэффициента нефтевытеснения ...

Способ выравнивания профиля приемистости нагнетательных скважин и ограничения водопритока в добывающие скважины

Изобретение относится к нефтедобывающей промышленности и может найти применение для ограничения водопритоков в добывающие скважины либо для выравнивания профиля приемистости нагнетательных скважин. Технический результат - повышение эффективности вытеснения нефти из пласта гелеобразующими (вязкоупругими) составами за счет повышения прочности указанных составов и снижение энергетических затрат путем сокращения индукционного периода гелеобразования. В способе выравнивания профиля приемистости нагнетательных скважин и ограничения водопритока в добывающие скважины, включающем закачку в пласт гелеобразующего состава, содержащего силикат натрия, ацетат хрома и воду, установку индукционного периода гелеобразующего состава при пластовой температуре, продавливание указанного состава в пласт и технологическую паузу, по первому варианту в водный раствор вводят оксид цинка и в качестве наполнителя - древесную муку при следующем соотношении компонентов, мас.%: силикат натрия 0,5-10, ацетат хрома 0,3- ...

СОСТАВ ДЛЯ РЕГУЛИРОВАНИЯ ПРОНИЦАЕМОСТИ ПЛАСТА

Состав для регулирования проницаемости продуктивного пласта предназначен для повышения его нефтеотдачи. Состав содержит смесь хлорида алюминия и соляной кислоты в количестве до 33%, при этом объемное соотношение указанной смеси и щелочи равно 1:1. Технический результат: повышение эффективности вытеснения нефти за счет осадкообразования, происходящего в результате взаимодействия хлорида алюминия и щелочи в определенном диапазоне соотношений. 1 ил., 1 табл.

СПОСОБ РАЗРАБОТКИ НЕФТЯНОЙ ЗАЛЕЖИ С ОБВОДНЕННЫМИ ПРОПЛАСТКАМИ

Изобретение относится к нефтедобывающей промышленности, в частности к способам разработки нефтяной залежи с обводненными пропластками. Техническим результатом является повышение эффективности способа за счет увеличения охвата пласта заводнением. Закачивают закупоривающий материал на основе нефелина в нагнетательные скважины. Выдерживают рецептуру: 100 кг концентрата нефелина на 1 м3 6%-ного водного раствора соляной кислоты. В течение 3-х суток осуществляют выдержку образовавшегося геля в пласте. Потом нагнетательные скважины подключают к водоводам и пускают под закачку. Через определенное время ближайшие добывающие скважины к очагам закачки тампонирующего материала начнут реагировать на воздействие снижением обводненности добываемой продукции. После снижения обводненности на этих скважинах больше чем на 5% производят закачку этого же гелеобразующего состава в эти же добывающие скважины. В результате произойдет изоляция обводнившихся пропластков с двух сторон: со стороны зоны закачки и зоны ...

СОСТАВ ДЛЯ БЛОКИРОВАНИЯ ПРИЗАБОЙНОЙ ЗОНЫ ПЛАСТА ГАЗОВЫХ СКВАЖИН

Изобретение относится к нефтегазодобывающей промышленности, а именно к блокированию призабойной зоны пласта высокой проницаемости и трещин, образующихся в процессе гидравлического разрыва пласта и закрепленных проппантом, при проведении капитального ремонта скважин. Технический результат - повышение эффективности блокирования пласта высокой проницаемости или трещин, образующихся в процессе гидравлического разрыва пласта - ГРП и закрепленных проппантом, при сохранении фильтрационно-емкостных свойств пород-коллекторов и снижении стоимости проведения работ при капитальном ремонте скважин. Состав для блокирования призабойной зоны пласта газовых скважин содержит, мас.%: карбоксиметилцеллюлоза 1,5÷2,0, хлорид магния 12,0÷18,0, гидрооксид натрия 10,0÷16,0, вода остальное и дополнительно сверх 100%: микросферы 25,0÷40,0, мел 3,0÷5,0. 1 табл.

СПОСОБ РАЗРАБОТКИ ОБВОДНЕННОЙ НЕФТЯНОЙ ЗАЛЕЖИ С НЕОДНОРОДНЫМИ ПО ПРОНИЦАЕМОСТИ ПЛАСТАМИ

Изобретение относится к нефтедобывающей промышленности, в частности к повышению нефтеотдачи неоднородных по проницаемости заводненных пластов. Задача изобретения создать способ разработки обводненной нефтяной залежи с неоднородными по проницаемости пластами, включающий закачку в пласт водного раствора алюмосодержащего отхода процесса алкилирования бензола олефинами с последующим нагнетанием вытесняющего агента, причем водный раствор алюмосодержащего отхода закачивают с концентрацией 1 30% 1 табл.

СОСТАВ ДЛЯ ОБРАБОТКИ НЕФТЯНОГО ПЛАСТА

Изобретение относится к области нефтедобывающей промышленности, в частности к составам для обработки нефтяного пласта, и предназначено для ограничения водопритока в добывающую скважину и регулирования профиля приемистости нагнетательных скважин. Техническим результатом изобретения является повышение эффективности состава за счет улучшения реологических свойств и получения однородной, кинетически устойчивой системы, а также расширение технологических возможностей использования состава. Состав для обработки нефтяного пласта содержит, мас.%: полиэтиленоксид 0,01-0,5, наполнитель - глинопорошок или мел, или древесную муку, или сломель 16-30, гидроокись натрия или гидроокись калия, или каустическую соду 0,05-2,0, воду остальное. 1 табл.

Chemically induced stimulation of cleat formation in a subterranean coal formation

Water-based fluid for altering the wettability of a formation

A method of altering the wettability of a reservoir formation involves flowing a fluid into the reservoir so as to coat the reservoir. The fluid may contain organic and inorganic components of nanoparticle size. The organic components may include silanes, alkoxysilanes with fluorinated chains or alkylcarbonyl. The inorganic components are selected from the group consisting of silicon, aluminium, titanium and zirconium.

METHOD OF PROVIDING A STABLE SUSPENSION OF NON-SWELLING PARTICULATE MATTER

A solidified, thermally insulating composition

A thermally insulating composition comprises: (A) an aqueous liquid, wherein the aqueous liquid is the continuous phase of the composition; (B) a particulate, wherein the particulate is silica, and wherein the particulate is a dispersed phase of the composition; and (C) an activator, wherein the activator causes at least some of the particulate to aggregate and form a network of at least the particulate, wherein the formation of the network causes the insulating composition to become a gel, and wherein the gelled insulating composition inhibits or prevents heat loss from two areas having different temperatures. A method of thermally insulating a portion of an annulus comprises: introducing the insulating composition into a portion of an annulus, wherein the gelled insulating composition inhibits or prevents heat loss from the portion of the annulus to an area adjacent to the outside of a second object.

Colloidal dispersions (SOLS) for weighting agents in fluids

A sag-resistant fluid, such as a drilling fluid, a completion fluid, or a spacer fluid, including a colloidal suspension that includes a continuous liquid phase and a solid phase suspended in the continuous liquid phase. The solid phase includes a plurality of particles, having an average diameter of the plurality of particles less than about 1000 nm. The the sag-resistant fluid has a density of from about 7 to about 30 Ibm/gal, and exhibits a density variation of less than about 0.5 Ibm/gal over a time period of at least about 16 hours. A method including circulating the sag-resistant fluid through a well.

Additive for increasing the density of a fluid forcasing annulus pressure control.

MIXED METAL HYDROXIDES FOR THICKENING WATER OR HYDROPHILIC LIQUIDS.

Water soluble polymers for fiber dispersion

Methods of treating a subterranean formation include forming a treatment fluid including an aqueous base fluid, a proppant, a water soluble polymer; and hydrophilic fibers having a length of about 100 microns to 10 millimeters. Such methods include placing the treatment fluid in the subterranean formation.

Microemulsion containing oilfield chemicals useful for oil and gas field applications

Block polymers for fluid loss control

The present invention relates to the use of a block polymer as fluid loss control agent in a fluid injected under pressure into an oil-bearing rock, where: the fluid comprises solid particles and/or is brought into contact with solid particles within the oil-bearing rock following the injection thereof, the polymer comprises: - a first block which is absorbed onto at least one portion of the particles; and - a second block, having a composition different from that of the first, and having a weight-average molecular mass of greater than 10 000 g/mol, for example greater than 100 000 g/mol, and that is soluble in the fluid.

Compositions and method for breaking hydraulic fracturing fluids

Breaking compositions are disclosed for controlled breaking of borate cross-linked fracturing fluids, and to method for making and using same, where the composition includes an oxidative component and an ester component.

METHOD OF PROVIDING A STABLE SUSPENSION OF NON-SWELLING PARTICULATE MATTER

WATER-BASED SYSTEM FOR ALTERING WETTABILITY OF POROUS MEDIA

A method for altering wettability of a reservoir formation includes the steps of providing a water-based fluid containing a wettability altering coating system; and flowing the fluid into a reservoir so as to coat the reservoir with the coating system.

OIL RECOVERY PROCESS

HYDRAULIC FRACTURING FLUID

A fracturing fluid including an aqueous base fluid having total dissolved solids between 100,000 mg/L and 400,000 mg/L, a polymer, a crosslinker, and at least one of a free amine and an alkaline earth oxide. In one example, the fracturing fluid may include a hydroxypropyl guar, a Zr crosslinker, and either a free amine such as triethylamine, or an alkaline earth oxide such as magnesium oxide. Optionally, the fracturing fluid may include a nanomaterial. Suitable example of a nanomaterial includes comprises ZrO2 nanoparticles. The viscosity and viscosity lifetime of fracturing fluids with polymer, crosslinker, and either a free amine or an alkaline earth oxide are greater than the sum of the effects of the individual components taken separately. This synergistic effect offers significant, practical advantages, including the ability to reduce polymer loading to achieve a desired viscosity, and the ability to achieve better formation cleanup after the fracturing treatment.

ENHANCED OIL RECOVERY USING TREATMENT FLUIDS COMPRISING COLLOIDAL SILICA WITH A PROPPANT

A method of increasing production from a hydrocarbon containing formation by adding a proppant to the formation, wherein a treatment fluid comprising a colloidal silica nanoparticle is added to the formation before, during or after the time the proppant is added to the formation is described and claimed.

TRIGGERING AN EXOTHERMIC REACTION FOR RESERVOIRS USING MICROWAVES

Compositions and methods for triggering an exothermic reaction of an exothermic reaction component are provided. A method includes the steps of mixing the exothermic reaction component in an aqueous solution to achieve a pre-selected solution pH, where the aqueous solution operably delays triggering of the exothermic reaction upon reaching a pre-determined temperature of a hydrocarbon-bearing formation; disposing the exothermic reaction component within the hydrocarbon-bearing formation; applying microwaves to the exothermic reaction component, where the microwaves are operable to trigger the exothermic reaction of the exothermic reaction component; and generating heat and gas in situ by the exothermic reaction to increase pressure and temperature of the hydrocarbon-bearing formation proximate the exothermic reaction component.

STUCK DRILL PIPE ADDITIVE AND METHOD

An aqueous mixture of a non-toxic, low pH, antimicrobial, acidic composit ion having a pH between approximately 0.5 and approximately 3.5 is used in a drilling fluid and a stuck pipe additive. One embodiment of the stuck pipe additive composition includes an alkali metal halide salt in a range of appr oximately 10-35 weight %; a sequenching agent in a range between 2 - 8 weigh t %, a low pH, non toxic acid composition in a range of 0.5 - 20 weight perc ent and water in a range of 7 - 88.5 weight %. As a drilling fluid, it maint ains well control and removes drill cuttings from holes drilled into the ear th. As a spotting fluid, it frees a stuck drill stem in the annulus of a bor e hole in minutes.

COMPOSITIONS AND METHODS FOR INCREASING FRACTURE CONDUCTIVITY

A method for treating a subterranean formation penetrated by a wellbore, comprising: providing a treatment slurry comprising a carrying fluid, a solid particulate and an agglomerant; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the solid particulate and the agglomerant; and transforming the substantially uniform mixture into areas that are rich in solid particulate and areas that are substantially free of solid particulate, wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the fracture and wherein said transforming results from said substantially dissimilar velocities is provided.

WELL SERVICING FLUID

A nano-dispersion well servicing fluid is disclosed. The well servicing fluid is formulated with components comprising: nanoparticles comprising at least one material chosen from aluminum oxides, aluminum hydroxides, aluminum hydroxyoxides, zirconium oxides, zirconium hydroxides, zirconium hydroxyoxides, wherein the concentration of nanoparticles is greater than 0.5% by weight based on the total weight of the nano-dispersion well servicing fluid. The well servicing fluid also comprises an aqueous base continuous phase. Methods of employing the nano-dispersion to service a wellbore are also disclosed.

LIQUID ST AND METHODS

СПОСОБ ПОДАЧИ НЕФТЕПРОМЫСЛОВОГО ХИМИКАТА ВО ФЛЮИД

В изобретении описаны полезные микроэмульсии, содержащие ингибиторы коррозии в дисперсной фазе, диспергирующую фазу и по меньшей мере одно поверхностно-активное вещество, которое способствует образованию эмульсии. Значение рН самого ингибитора коррозии может быть установлено таким, чтобы он выступал в качестве поверхностно-активного вещества. Ингибиторы коррозии образуют микроэмульсии, содержащие частицы или капельки диаметром от примерно 10 до примерно 300 нм. Микроэмульсии могут являться микроэмульсиями масло-в-воде, вода-в-масле или бинепрерывными.

METHOD OF PRODUCTION OF NATURAL GAS AND NATURAL GAS CONDENSATE FROM UNDERGROUND GAS-CONDENSATE DEPOSIT, AND ALSO THE FLUID COMPOSITION FOR USE IN THIS METHOD

МИКРОЭМУЛЬСИЯ, СОДЕРЖАЩАЯ НЕФТЕПРОМЫСЛОВЫЕ ХИМИКАТЫ, ПРИГОДНАЯ ДЛЯ ПРИМЕНЕНИЯ НА МЕСТОРОЖДЕНИЯХ ГАЗА И НЕФТИ

В заявке описаны полезные микроэмульсии, содержащие ингибиторы коррозии в дисперсной фазе и диспергирующую фазу, и по меньшей мере одно поверхностно-активное вещество, которое способствует образованию эмульсии. Значение рН самого ингибитора коррозии может быть установлено таким, чтобы он выступал в качестве поверхностно-активного вещества. Ингибиторы коррозии образуют микроэмульсии, содержащие частицы или капельки диаметром от примерно 10 до примерно 300 нм. Микроэмульсии могут являться микроэмульсиями масло-в-воде, вода-в-масле или бинепрерывными.

СИСТЕМЫ И СПОСОБЫ МИКРОБИОЛОГИЧЕСКОГО ПОВЫШЕНИЯ НЕФТЕОТДАЧИ ПЛАСТОВ

Способ микробиологического повышения нефтеотдачи из нефтеносного пласта включает в себя обработку воды, предназначенной для закачки в нефтеносный пласт, для реализации микробиологической активности, и добавление кислорода, способствующего микробиологического активности. Обработка, применяемая для воды, базируется, по меньшей мере, частично, на создании в нефтеносном пласте, по меньшей мере, одного условия, благоприятного для микробиологической активности, которая увеличивает миграцию нефти из нефтеносного пласта.

Chemically induced stimulation of coal cleat formation

COMPOSITIONS OF ALKALINE SILICATES AND THEIR EMPLOYMENT

REVERSIBLE PROCESS OF FILLING OF UNDERGROUND FORMATIONS

METHOD OF TREATING A SUBTERRANEAN FORMATION PENETRATED BY A WELLBORE, COMPOSITION, METHOD, AND METHOD OF DESIGNING AN TREATMENT

METHOD OF ENHANCED OIL RECOVERY

The invention relates to a process for mineral oil production, in which an aqueous formulation comprising at least one polyethylene-oxide, at least one silica and optionally a surfactant is injected into a mineral oil deposit through at least one injection well and the crude oil is withdrawn from the deposit through at least one production well.

MITIGATING ANNULAR PRESSURE BUILDUP WITH NANOPOROUS METAL OXIDES

Methods and systems for mitigating annular pressure buildup in a wellbore are provided. An example method comprises introducing a treatment fluid into an annulus of the wellbore, wherein the annulus has an annular pressure, and wherein the treatment fluid comprises an aqueous base fluid and a nanoporous metal oxide. The method further comprises allowing or causing to allow at least a portion of the treatment fluid to remain in the annulus; and allowing or causing to allow the annular pressure to increase thereby inducing at least a portion of the aqueous base fluid to enter into an interior volume of the nanoporous metal oxide.

METHODS AND COMPOSITIONS FOR TREATING SUBTERRANEAN ZONES

Methods and compositions for breaking treatment fluids utilized in the stimulation of a subterranean formation.

Chemically induced stimulation of cleat formation in a subterranean coal formation

A method for increasing the production of methane from a subterranean coal formation by chemically stimulating the formation of cleats in the formation to increase the rate of methane production from the formation by injecting an aqueous oxidant solution into the formation to stimulate the formation of cleats in the formation; and thereafter producing methane from the formation at an increased rate. Suitable oxidants include chlorine dioxide, metallic salts of perchlorate, chlorate, persulfate, perborate, percarbonate, permanganate, nitrate and combinations thereof.

PICKERING EMULSIONS USED IN WELLBORE SERVICING FLUIDS AND METHODS

In wellbore servicing fluids and methods related thereto a Pickering emulsion is produced by mixing silica, an oleaginous fluid, an aqueous base fluid and an emulsifier. The silica can comprise a silica dust and larger proppant particles that work together to form a Pickering emulsion with the proppant particles suspended therein. In some embodiments, the proppant particles are a silica sand.

MONOVALENT BRINES FOR USE AS WELLBORE FLUIDS

The invention relates to a wellbore fluid, which is a monovalent brine comprising one or more alkali bromide salt(s) and one or more TCT-reducing additive(s) selected from the group consisting of alkali nitrates. A method of treating a subterranean formation, comprising placing the wellbore fluids of the invention in a wellbore in the subterranean formation is also provided.

Aqueous Based, Water-Soluble Polymer Slurry System

Systems and methods for forming aqueous based, water-soluble polymer slurry systems may include (1) a liquid phase which may be a suspension comprised of salt, water, and a water-soluble organic solvent and (2) a solid phase which may comprise a water-soluble polymer powder. The aqueous based, water-soluble polymer slurry systems may optimize processing of the suspension package so that it may slurry in low and high salt tolerance polymers, and the finished product can survive over 30 days at an approximately 120-degree Fahrenheit aging temperature, thereby overcoming economic performance and stability challenges through its high flash point, long shelf-life, high-temperature tolerance, and low cost.

СОСТАВ ДЛЯ ПОВЫШЕНИЯ НЕФТЕОТДАЧИ

Изобретение относится к нефтедобывающей промышленности, в частности к составам для проведения водоизоляционных работ, и может быть использовано для регулирования фильтрационных потоков нефтяных пластов. Техническим результатом является повышение эффективности состава путем регулирования его физико-химических характеристик (времени гелеобразования и вязкости), расширение области применения, а также снижение стоимости композиции и решение экологической проблемы - утилизации отходов нефтехимических производств. Состав для повышения нефтеотдачи, содержащий хлорид алюминия, карбамид и воду, дополнительно содержит хлорид цинка при следующем соотношении компонентов, мас. %: хлорид алюминия 10-15; хлорид цинка 10-15; карбамид 35-55; вода остальное. 2 табл.

СПОСОБ ИЗВЛЕЧЕНИЯ НЕФТИ ИЗ НЕОДНОРОДНОГО НЕФТЯНОГО ПЛАСТА

Способ извлечения нефти из неоднородного нефтяного пласта включает закачку загущающего агента . в качестве которого используют водную дисперсию осадков водоочистных станций, образующихся> при очистке воды коагуляцией сульфатами алюминия или железа .причем закачку загущающего агента производят до тех пор, пока давление закачки превысит первоначальное на 30-50%. Изобретение позволит повысить эффективность нефтеизвлечения из неоднородных по проницаемости пластов. 1 табл.

СПОСОБ РАЗРАБОТКИ НЕОДНОРОДНОГО НЕФТЯНОГО ПЛАСТА (ВАРИАНТЫ)

Предложение относится к нефтедобывающей промышленности, в частности к повышению нефтеотдачи пластов на поздней стадии разработки нефтяной залежи. Технический результат - увеличение нефтеотдачи пластов и снижение обводненности добывающих скважин, повышение эффективности охвата пласта воздействием, расширение технологических возможностей способа. В способе разработки неоднородного нефтяного пласта, включающем закачку в пласт через нагнетательную скважину соли алюминия и щелочного реагента и отбор нефти через добывающие скважины, предварительно до закачки в пласт на устье скважины получают коллоидно-дисперсную систему - КДС с концентрацией от 1,5 до 50,0 мас.% и рН 6,70-8,75 одновременным дозированием 0,5-10%-ного раствора соли алюминия и 1,0-20%-ного раствора щелочного реагента в воду при следующем соотношении компонентов, мас.%: соль алюминия - 0,05-3,0, щелочной реагент - 0,1-6,0, вода - остальное, перемешивают указанные растворы с водой в смесительной емкости в течение 10-30 мин, затем ...

СОСТАВ ДЛЯ ПРИГОТОВЛЕНИЯ ТЕХНОЛОГИЧЕСКОЙ ЖИДКОСТИ ДЛЯ ЗАКАНЧИВАНИЯ И РЕМОНТА НЕФТЯНЫХ И ГАЗОВЫХ СКВАЖИН

Изобретение относится к нефтегазодобывающей отрасли, предназначено для заканчивания и ремонта нефтяных и газовых скважин и может быть использовано в условиях аномально высоких пластовых давлений и высоких температур для первичного и вторичного вскрытия продуктивных пластов, для глушения и выполнения различных видов работ, в том числе в многопластовых скважинах, имеющих разное пластовое давление и проницаемость пластов, а также при наличии сероводорода в скважинной продукции. Технический результат - увеличение плотности технологических жидкостей, снижение фильтрационных показателей при температурах 120°С и выше, в том числе на месторождениях с сероводородсодержащей продукцией. Состав для приготовления технологических жидкостей для заканчивания и ремонта нефтяных и газовых скважин содержит, мас.%: хлорид кальция 13,3-21,9, нитрат кальция 13,3-21,9, хлорид цинка 52,55-72,1, хлорид натрия 0,5-2,35, бензоат натрия 0,80-1,30. 1 табл.

Способ изол ции водопритоков или зон поглощени в скважине

Изобретение относится к нефтяной промышленности и может найти применение при изоляции водопритоков или зон поглощения в скважине. В способе изоляции водопритоков или зон поглощения в скважине, включающем последовательную закачку в скважину гелеобразующего материала на основе нефелина, разделителя и водного раствора соляной кислоты 14-16%-ной концентрации, в качестве указанного гелеобразующего материала используют дисперсию концентрата сиенитового алюмощелочного в жидкости-носителе при их объемном соотношении соответственно 1:(1,9-2,1), и объемном соотношении указанной дисперсии и указанного водного раствора соляной кислоты соответственно (0,9-1,1):1. Технический результат повышение технологичности проведения работ и эффективности изоляции водопритоков или зон поглощения в скважине.

СПОСОБЫ И КОМПОЗИЦИИ ДЛЯ ОБРАБОТКИ ПОДЗЕМНЫХ УЧАСТКОВ

... 1. Способ обработки подземного участка, включающий получение композиции вязкой жидкости на водной основе для обработки пласта, которая содержит воду, повышающий вязкость полимер и растворимую в воде композицию для сильно замедленного разрушения полимеров, содержащую источник пероксида водорода, источник ионов двухвалентного железа и хелатообразующий агент, введение композиции вязкой жидкости для обработки пласта в подземный участок через ствол скважины, проникающий в подземный участок, и предоставление возможности композиции для сильно замедленного разрушения полимеров разрушить композицию вязкой жидкости для обработки пласта с образованием разбавленной жидкости, имеющей низкую вязкость. 2. Способ по п.1, где источник пероксида водорода выбирают из группы, состоящей из тетрагидрата пербората натрия и пероксида водорода. 3. Способ по п.1, где источник ионов двухвалентного железа выбирают из группы, состоящей из гептагидрата сульфата железа (II), хлорида железа (II) и глюконата железа (II ...

СОСТАВ ДЛЯ ОГРАНИЧЕНИЯ ПРИТОКА ПЛАСТОВЫХ ВОД

Состав для ограничения притока пластовых вод, содержит, мас.%: Карбонат натрия - 5 - 21 Растворимые или диспергируемые в воде соединения кремния - 0, 1 - 5,0 Вода - Остальное В качестве указанных соединений кремния могут быть использованы силикат натрия, этил- или метилсиликонат натрия, гексафторсиликат натрия, этилсиликат или силиконовая эмульсия. 1 з.п. ф-лы, 2 табл.

СПОСОБ ВЫРАВНИВАНИЯ ПРОФИЛЯ ПРИЕМИСТОСТИ НАГНЕТАТЕЛЬНЫХ СКВАЖИН И ОГРАНИЧЕНИЯ ВОДОПРИТОКА В ДОБЫВАЮЩИЕ СКВАЖИНЫ

Изобретение относится к нефтедобывающей промышленности. Технический результат - повышение эффективности вытеснения нефти из пласта за счет водоизоляции высокообводненных пластов в добывающих скважинах либо за счет выравнивания профиля приемистости нагнетательных скважин путем частичного или полного блокирования высокопромытых каналов или пропластков для движения нагнетаемой воды. В способе выравнивания профиля приемистости нагнетательных скважин и ограничения водопритока в добывающие скважины, включающем закачку в пласт гелеобразующего состава, содержащего, мас.%: силикат натрия 1-10, ацетат хрома 0,5-2, воду - остальное, продавливание указанного состава в пласт, технологическую паузу, перед закачкой указанного состава в скважины закачивают оторочку пресной воды, индукционный период гелеобразующего состава при пластовой температуре устанавливают равным 6-10 часам, а технологическую паузу выбирают продолжительностью 24-36 часов. 1 пр., 2 ил.

СПОСОБЫ РЕГУЛИРОВАНИЯ СВОЙСТВ ПОТЕРИ ТЕКУЧЕЙ СРЕДЫ ИЗ ТЕКУЧИХ СРЕД НА ОСНОВЕ ВЯЗКОУПРУГИХ ПОВЕРХНОСТНО-АКТВНЫХ ВЕЩЕСТВ

... 1. Способ обработки подземной формации, включающий стадии (a) обеспечения водной текучей среды, содержащей суспензию коллоидных частиц и загущающее количество вязкоупругого поверхностно-активного вещества и (b) закачивание текучей среды в хорошо проницаемую подземную формацию. 2. Способ обработки подземной формации, включающий стадии (a) обеспечения водной текучей среды, содержащей суспензию коллоидных частиц, вязкоупругое поверхностно-активное вещество и гидрофобно модифицированный полимер, причем гидрофобно модифицированный полимер присутствует при концентрации между приблизительно его концентрацией перекрывания, с* и приблизительно его концентрацией затруднения, Се и (b) закачивание текучей среды в хорошо проницаемую подземную формацию. 3. Способ по п.1 или 2, при котором проницаемость подземной формации находится между приблизительно 5 и приблизительно 100 мД. 4. Способ по п.3, при котором проницаемость подземной формации находится между приблизительно 10 и приблизительно 50 мД. 5.

Diverter composition including rheologically-modified invert emulsion

Oil well treatment

Chemically induced stimulation of coal cleat formation

Methane production from a subterranean carbonaceous formation using an aqueous oxidising solution to promote cleat formation

A method for increasing the production of methane from a subterranean carbonaceous formation containing clay minerals by injecting an aqueous oxidizing solution into said formation through an injection well. The oxidising agent contains at least one of the group comprising peroxide, ozone, oxygen, chlorine dioxide, sodium hypochlorite, water soluble metallic salts of hypochlorous acid, perchlorate, chlorate, persulfate, perborate, percarbonate, permanganate, nitrate and combinations thereof. The oxidising agent stimulates the formation of cleats or fractures by chemical reaction with the organic constituents of the formation and the rate of methane desorption from the formation increases as oxidation of carbonaceous material results in an increase in the free surface area of the cleats. Sodium or potassium salts are preferred. The methane may be recovered through the same well used for injecting the oxidising solution or through a separate recovery well. The oxidant is normally shut-in ...

Water-based system for altering wettability of porous media

OFF-SHORE CLEAN WATER SUPPLY

OFF-SHORE CLEAN WATER SUPPLY

ADDITIVE FOR THE INCREASE OF THE DENSITY OF A LIQUID FOR PRINTING CONTROL OF AN ANNULAR SPACE

ADDUCTS FROM LAMINATED MIXTURES METAL HYDROXIDES AND CLAY/TONE AS THICKENERS FOR WATER AND OTHER HYDROPHILIC LIQUIDS.

Compositions and methods for increasing fracture conductivity

Abstract A method for treating a subterranean formation penetrated by a wellbore, comprising: providing a treatment slurry comprising a carrying fluid, a solid particulate and an agglomerant; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the solid particulate and the agglomerant; and transforming the substantially uniform mixture into areas that are rich in solid particulate and areas that are substantially free of solid particulate, wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the fracture and wherein said transforming results from said substantially dissimilar velocities is provided.

PROCESS FOR SELECTIVELY TREATING A SUBTERRANEAN FORMATION USING COILED TUBING WITHOUT AFFECTING OR BEING AFFECTED BY THE TWO ADJACENT ZONES

Process for selectively treating a subterranean formation using coiled tubing without affecting or being affected by the two adjacent zones. The invention consists of a new process for selectively treating a subterranean formation without affecting or being affected by the two adjacent zones (above and below). Using the invented process, the treatment fluid is injected into the formation to be treated F, at the same time as two protection fluids, whether the same or different, are injected into the two adjacent zones (above ¢ZS! and below ¢ZI!). The process can be applied even in the presence of fractures, gravel-pack and thief zones.

PROCESS FOR RETARDING AND CONTROLLING THE FORMATION OF GELS OR PRECIPITATES DERIVED FROM ALUMINUM AND CORRESPONDING COMPOSITIONS, PLUS THE CORRESPONDING APPLICATIONS - IN PARTICULAR REGARDING OIL WELLS

The invention concerns the plugging of underground formations. The plugging agent used is aluminum hydroxychloride with hexamethylene tetramine, or a weak-base activator such as urea. The invention has applications in the treatment of oil wells and the traversed formations.

PROCEDE DE COLMATAGE REVERSIBLE DE FORMATIONS SOUTERRAINES

L'invention concerne un procédé de colmatage réversible dans une formation souterraine pénétrée par un puits de forage, caractérisé en ce que: - on injecte dans la formation une composition aqueuse comprenant un silicate de métal alcalin et un agent gélifiant; - on laisse gélifier la composition et on maintient le gel pendant le temps désire pour le colmatage; - puis on injecte une solution alcaline de manière à détruire le gel. Le procédé de l'invention permet donc le colmatage réversible de zones pétrolifères avec des durées de colmatage et de destruction du gel qui peuvent être parfaitement maîtrisées en un temps contrôlé, et l'obtention d'une perméabilité résiduelle sensiblement équivalente à la perméabilité initiale après un balayage limité en volume par l'agent destructeur.

WATER-BASED SYSTEM FOR ALTERING WETTABILITY OF POROUS MEDIA

A method for altering wettability of a reservoir formation includes the steps of providing a water-based fluid containing a wettability altering coating system; and flowing the fluid into a reservoir so as to coat the reservoir with the coating system.

COATED PARTICLES AND METHODS OF MAKING AND USING THE SAME

Provided herein are coated particles, such as, for example, proppants comprising a coating. A coated particle of the present invention may swell upon contact with a solution having a salinity in a range of about 50 ppm to about 100,000 ppm and/or having a hardness in a range of about 1 ppm to about 150,000 ppm. The amount of swelling may vary by less than 50% over a salinity concentration in a range of about 50 ppm to about 100,000 ppm and/or a hardness concentration in a range of about 1 ppm to about 150,000 ppm. Also provided herein are methods of making coated particles and methods of using the same.

NON-ACIDIC-EXOTHERMIC SANDSTONE STIMULATION FLUIDS

Provided is a method and composition for the in-situ generation of synthetic sweet spots in tight-gas formations. The composition can include nitrogen generating compounds, which upon activation, react to generate heat and nitrogen gas. The method of using the composition includes injecting the composition into a tight-gas formation such that upon activation, the heat and nitrogen gas generated ...

LAYERED MIXED METAL HYDROXIDES MADE IN NON-AQUEOUS MEDIA

Crystalline layered mixed metal hydroxides (LMMHs) which are substantially free of unbound water and which conform esentially to the generic formula LimDdT(OH)(3+m+d), where m represents an amount of Li of from 0 to 3, D represents a divalent metal cation, and d represents an amount of D of from 0 to 8.0, T represents a trivalent metal cation, and (3+m+d) represents an amount which essentially satifies the valence requirements of Li, D and T, and where m+d does not equal zero, are prepared, in an organic reaction medium which is essentially free of unbound water, by mixing predetermined metal organo compounds in predetermined ratios and reacting the metal organo compounds with at least one reagent which supplies OH- ions to replace the beginning anions in the mixture of metal compounds. A preferred LMMH is one which conforms essentially to the generic formula MgdAl(OH)(3+d), where d represents the amount of Mg per each unit of Al. Useful anhydrous gels are among the useful products.

CHEMICALLY INDUCED STIMULATION OF CLEAT FORMATION IN A SUBTERRANEAN COAL FORMATION

A method for increasing the production of methane from a subterranean coal formation by chemically stimulating the formation of cleats in the formation to increase the rate of methane production from the formation by injecting an aqueous oxidant solution into the formation to stimulate the formation of cleats in the formation; and thereafter producing methane from the formation at an increas ed rate. Suitable oxidants include chlorine dioxide, metallic salts of perchlorate, chlorate, persulfate, perborate, percarbonate, permanganate, nitrate and combinations thereof.

CHEMICALLY INDUCED AMPLIFICATION OF PERMEABILITY OF UNDERGROUND COAL DEPOSITS

CHEMICALLY INDUCED STIMULATION OF CLEAT FORMATIONS IN A SUBTERRANIEN COAL FORMATION

Chemically induced stimulation of coal cleat formation

Chemically induced stimulation of coal cleat formation

Process of treatment of water intended to be injected into geological formations

METHOD TO REDUCE RETENTION OF A DISPLACEMENT AGENT AND APPLYING THE ASSISTED RECOVERY OF HYDROCARBONS.

DRILLING FLUID ADDITIVES AND FRACTURING FLUID ADDITIVES CONTAINING CELLULOSE NANOFIBERS AND/OR NANOCRYSTALS

This disclosure provides drilling fluids and additives as well as fracturing fluids and additives that contain cellulose nanofibers and/or cellulose nanocrystals. In some embodiments, hydrophobic nanocellulose is provided which can be incorporated into oil-based fluids and additives. These water-based or oil-based fluids and additives may further include lignosulfonates and other biomass-derived components. Also, these water-based or oil-based fluids and additives may further include enzymes. The drilling and fracturing fluids and additives described herein may be produced using the AVAP® process technology to produce a nanocellulose precursor, followed by low-energy refining to produce nanocellulose for incorporation into a variety of drilling and fracturing fluids and additives.

TREATMENT FLUIDS CONTAINING A BORON TRIFLUORIDE COMPLEX AND METHODS FOR USE THEREOF

Treatment fluids for use in subterranean formations, particularly sandstone and other siliceous formations, may contain a source of fluoride ions to aid in mineral dissolution. In some cases, it is desirable to generate the fluoride ions from a fluoride ion precursor, particularly a hydrofluoric acid precursor, such as a boron trifluoride complex. Methods described herein comprise providing a treatment fluid that comprises an aqueous base fluid, a boron trifluoride complex, and a chelating agent composition, and introducing the treatment fluid into a subterranean formation.

FORMULATIONS COMPRISING RECOVERED WATER AND A VISCOSIFIER, AND ASSOCIATED METHODS

High viscosity fracturing fluids for fracturing a subterranean formulation are prepared by: (i)selecting recovered water; (ii)contacting said recovered water with a viscosifying agent,wherein said viscosifying agent is selected from fenugreek gum, tara gum, locust bean gum, guar gum and derivatives of the aforesaid; (iii)contacting said recovered water with one or more other additives for example with a cross-linking agent (A) for cross-linking said viscosifying agent, wherein contact of said recovered water with cross-linking agent (A) takes place when the pH of said recovered water is less than pH 6.5; (iv)adjusting the pH to pH 6.5-8.8.

WELL INSULATION METHOD

CHLORINE DIOXIDE PRECURSOR AND METHODS OF USING SAME

According to one aspect of the invention, a method of converting an oxy halide salt into a halide dioxide in a reaction zone under certain conditions is provided. More specifically, the method includes generating chlorine dioxide from a stable composition comprising an oxy halide salt by introducing said composition to a reducing agent and minimum temperature within the reaction zone. According to another aspect of the invention, a composition for a stable chlorine dioxide precursor comprising an oxy halide salt is provided.

METHOD OF FORMING A MIXTURE OF BARITE PARTICLES, CHELATING AGENT AND BENTONITE FOR FRACTURING

A drilling fluid composition that contains micronized barite particles with a particle size in the range of 1 to 5 μm, and also a method of fracturing a subterranean formation using the drilling fluid composition. Various embodiments of the micronized barite particles and the method of making thereof, the drilling fluid composition, and the method of fracturing a subterranean formation are also provided. 1. A method of making a barite composition and fracturing a subterranean formation , comprising:mixing micronized barite particles, a chelating agent and bentonite in water to form a drilling fluid composition,injecting the drilling fluid composition into the subterranean formation through a wellbore to fracture the subterranean formation and form fissures in the subterranean formation,wherein the micronized barite particles have a particle size in the range of 1 to 5 μm; andthe drilling fluid composition further comprises a viscosifier,wherein the micronized barite particles are present in the drilling fluid composition at a concentration in the range of 1 wt % to 50 wt %, relative to the total weight of the drilling fluid composition.2. The method of claim 1 , further comprising:injecting a proppant into the subterranean formation through the wellbore to deposit the proppant in the fissures.3. The method of claim 1 , further comprisingcirculating the drilling fluid composition within the wellbore after the injecting.4. The method of claim 1 , wherein the drilling fluid composition is injected at a pressure of at least 5 claim 1 ,000 psi to fracture the subterranean formation.5. (canceled)6. The method of claim 1 , wherein the drilling fluid composition has a plastic viscosity of 14 to 18 cP at a temperature of 80 to 90° F.7. (canceled)8. The method of claim 1 , wherein the drilling fluid composition has a density of 12 to 14 ppg at a temperature of 80 to 90° F.9. The method of claim 1 , wherein the drilling fluid composition has a yield point of 35 to 45 lb/100 ...

SALT-TOLERANT SELF-SUSPENDING PROPPANTS MADE WITH NEUTRAL STARCHES

A self-suspending proppant that resists the adverse effects of calcium and other cations on swelling comprises a proppant substrate particle and a gelatinized neutral starch coating on the proppant substrate particle.

Remediation of Rag Layer and Other Disposable Layers in Oil Tanks and Storage Equipment

The subject invention provides microbe-based products, as well as their use to improve oil production and refining efficiency by, for example, remediating the disposable layers in oil tanks and other oil storage units. In preferred embodiments, the microbe-based products comprise biochemical-producing yeast and growth by-products thereof, such as, e.g., biosurfactants. The subject invention can be used to remediate rag layer and/or other dissolved solid layers that form in water-oil emulsions. Furthermore, the subject invention can be used for remediating solid impurities, such as sand, scale, rust and clay, in produced water, flow-back, brine, and/or fracking fluids.

WELL SERVICING FLUID

PARTICLES CONTAINING ONE OR MORE CONTROLLED RELEASE CROSS-LINKED ACTIVE AGENTS

BLOCK POLYMERS FOR FILTRATE CONTROL

La présente invention concerne l'utilisation d'un polymère séquencé comme agent de contrôle du filtrat dans un fluide injecté sous pression dans une roche pétrolière, où : le fluide comprend des particules solides et/ou est mis en contact avec des particules solides au sein de la roche pétrolière suite à son injection, le polymère comprend : - un premier bloc qui s'adsorbe sur au moins une partie des particules ; et - un deuxième bloc, de composition distincte de celle du premier, et de masse moléculaire moyenne en poids supérieure à 10 000 g/mol, par exemple supérieure à 100 000 g/mol, et soluble dans le fluide.

СПОСОБ РЕГУЛИРОВАНИЯ РАЗРАБОТКИ НЕОДНОРОДНОГО НЕФТЯНОГО ПЛАСТА

Изобретение относится к нефтедобывающей промышленности и может найти применение при разработке нефтяной залежи на средней или поздней стадии. Техническим результатом изобретения является повышение нефтеотдачи пласта за счет повышения эффективности воздействия. В способе регулирования разработки неоднородного нефтяного пласта, включающем предварительное проведение геофизических исследований, закачку через нагнетательную скважину оторочек глинистой дисперсии, полимера и оторочки пресной воды, осуществляют закачку оторочек глинистой дисперсии и полимера в виде его водного раствора одновременно или последовательно, одновременно или после этого подают раствор щелочного реагента, осуществляют закачку оторочки пресной воды, затем - раствора солей двух- или трехвалентных металлов, или оторочки минерализованной сточной воды, затем все реагенты продавливают сточной водой, соотношение объема раствора щелочного реагента и объема глинистой дисперсии и водного раствора полимера подбирают по результатам ...

СОСТАВ ДЛЯ РЕГУЛИРОВАНИЯ ПРОНИЦАЕМОСТИ ОБВОДНЕННЫХ ПРОДУКТИВНЫХ ПЛАСТОВ

Изобретение относится к нефтедобывающей промышленности, в частности к осадкогелеобразующим составам, объектами использования которых являются многопластовые и слоистонеоднородные пласты на высокообводненных участках залежей нефти. Технический результат - регулирование процесса гелеобразования, получение максимально возможного объема геля в количестве, необходимом для заполнения осадком проницаемых участков пласта при взаимодействии с карбонатными породами. Состав содержит раствор хлорида алюминия и 15%-ный раствор соляной кислоты в соотношении 2 : 1. 1 ил.

СПОСОБ РАЗРАБОТКИ ПРОДУКТИВНОГО ПЛАСТА

Изобретение относится к области разработки нефтяных месторождений, в частности к повышению нефтеотдачи неоднородных по проницаемости, заводненных нефтяных пластов. Обеспечивает увеличение нефтеотдачи продуктивного пласта. Сущность изобретения: проводят закачку раствора силиката щелочного металла и минерализованной воды через нагнетательные скважины и отбирают нефть через добывающие скважины. Перед закачкой раствор силиката щелочного металла и минерализованной воды смешивают до коллоидного состояния. В качестве раствора силиката щелочного металла используют раствор этого силиката в воде с концентрацией 0,05-20 вес.%. В качестве минерализованной воды используют пластовые и сточные воды, содержащие неорганические соли, с минерализацией 2,5-15,0 вес.%.

МЕТАНОГЕННОЕ ПОЛУЧЕНИЕ IN SITU ИЗ ОТХОДОВ ПРОИЗВОДСТВА

ADDUKTE VON TON UND AKTIVIERTEN GEMISCHTEN METALLOXYDEN

Treatment of subterranean coal formation

Systems and methods of microbial enhanced oil recovery

A method of microbial enhanced oil recovery from an oil-bearing formation that involves treating the water that is to be injected into the oil-bearing formation to enable microbial activity and adding oxygen to aid microbial activity. The treatment applied to the water is based, at least in part, upon establishing at least one condition in the oil-bearing formation favorable to microbial activity that enhances movement of oil from the oil-bearing formation.

Methods for treatment of a subterranean formation

The present invention relates to methods of treating subterranean formations. In various embodiments, the present invention provides a method of treating a subterranean formation including placing a first aqueous composition and a second aqueous composition in a subterranean formation. The placing includes injecting the first aqueous composition through a tubular passage in a wellbore. The placing also includes injecting the second aqueous composition through an annular passage in the wellbore.

High performance water based fluid

A fluid may include an aqueous based continuous phase, a pH adjusting additive, wherein the pH adjusting additive is formic acid, and a clay hydration suppressant agent having the formula H2NCH(CH3)CH2(OCH(CH3)CH2)xNH2, wherein x is a value less than 15.

ADDUCTS OF CLAY/TONE AND ACTIVATED MIXTURE METAL OXIDES

Additive for increasing the density of a fluid for casing annulus pressure control

Method for Drilling Using a Drilling and Completion Fluid Comprising a Phosphate Based Blend

A method for for drilling through a producing zone in a subterranean formation or for completing a wellbore in a subterranean formation, using a drill-in and completion fluid comprising a blend of a phosphate brine and water. 113.-. (canceled)14. A method for drilling through a producing zone in a subterranean formation bearing hydrocarbons or for completing a wellbore in a subterranean formation , said method comprising using in said drilling or completion operation a clear , heavy brine fluid comprising a blend of phosphate based brine and water.15. The method of wherein the phosphate based brine is potassium phosphate brine.16. The method of wherein the fluid consists essentially of a blend of phosphate brine and water.17. The method of wherein the wellbore includes a packer and a tubing-casing annulus above the packer claim 14 , and the clear claim 14 , heavy brine fluid is positioned in and remains in the tubing-casing annulus above the packer.18. The method of wherein the fluid has an NTU less than about 20 and a density in the range of about 10 lb/gal to about 20 lb/gal.19. The method of wherein the fluid remains clear at temperatures in the range of about 50° F. to about 350° F.20. The method of wherein the fluid further comprises about 10% to about 60% by volume sodium bromide. 1. Field of the InventionThe present invention relates to compositions for heavy brines systems for use as drill-in and completion fluids.2. Description of Relevant ArtDrill-in fluids are drilling fluids used in drilling through a hydrocarbon producing zone (also called a pay zone) of a hydrocarbon bearing subterranean formation and completion fluids are fluids used in completing or recompleting or working over a well. Completion operations normally include perforating the casing and setting the tubing and pumps prior to, and to facilitate, initiation of production in hydrocarbon recovery operations. The various functions of drill-in, completion and workover fluids include ...

DELIVERY OF PARTICULATE MATERIAL BELOW GROUND

A wellbore fluid comprises an aqueous carrier liquid, hydrophobic fibers suspended therein, hydrophobic particulate material also suspended in the carrier liquid, and a gas to wet the surfaces of the particles and fibers and bind them together as agglomerates. The wellbore fluid may be a slickwater fracturing fluid and may be used for fracturing a tight gas reservoir. Using a combination of hydrophobic particulate material, hydrophobic fibers and gas inhibits settling out of the particulate material from an aqueous liquid. Because the gas acts to wet the surfaces of both materials and agglomerates them, the particulate material is made to adhere to the fibers; the fibers form a network which hinders settling of the particulate material adhering to them, and the agglomerates contain gas and so have a bulk density which is less than the specific gravity of the solids contained in the agglomerates. 1. A wellbore fluid comprising an aqueous carrier liquid , hydrophobic fibers suspended therein , hydrophobic particulate material also suspended in the carrier liquid , and a gas to wet the surfaces of the particles and fibers and bind them together as agglomerates.2. A fluid according to wherein the particles of the suspended particulate material have a specific gravity of at least 1.8 and a maximum dimension not larger than 1.0 mm.3. A fluid according to wherein 90% by volume of the particulate material has a largest particle dimension which is less than one fifth of the median length of the fibers.4. A fluid according to wherein the hydrophobic particulate material has a volume median particle size dof not more than 200 micron claim 3 , determined as median diameter of spheres of equivalent volume.5. A fluid according to wherein the fibers have a length of 3 mm or more.6. A fluid according to wherein the first particulate material has a hydrophobic surface coating and the fibers are glass fibers with a hydrophobic surface coating.7. A fluid according to wherein the ratio ...

Delivery of Particulate Material Below Ground

A wellbore fluid is an aqueous carrier liquid with first and second hydrophobic particulate materials suspended therein. The first hydrophobic particles have a higher specific gravity than the second hydrophobic particles and the fluid also comprises a gas to wet the surface of the particles and bind them together as agglomerates. The fluid may be a fracturing fluid or gravel packing fluid and the first particulate material may be proppant or gravel. The lighter second particulate material and the gas both reduce the density of the agglomerates which form so that they settle more slowly from the fluid, or are buoyant and do not settle. This facilitates transport and placement in a hydraulic fracture or gravel pack. One application of this is when fracturing a gas-shale with slickwater. The benefit of reduced settling is better placement of proppant so that a greater amount of the fracture is propped open. 1. A wellbore fluid comprising an aqueous carrier liquid and first and second hydrophobic particulate materials suspended therein , where the first hydrophobic particles have a higher specific gravity than the second hydrophobic particles , the fluid also comprising a gas to wet the surface of the particles and bind them together as agglomerates.2. A fluid according to wherein the first particles have a specific gravity of at least 1.8 and the second particles have a specific gravity of less than 1.5.3. A fluid according to wherein the second particles have a specific gravity of less than 1.0.4. A fluid according to wherein agglomerates of the first and second hydrophobic particles in the proportions present in the fluid claim 1 , containing the gas in the maximum amount which the agglomerates can retain claim 1 , have a density of 1.1 or less.5. A fluid according to wherein the ratio of the first and second particles lies in a range from 4:1 to 1:4 by volume.6. A fluid according to wherein the first hydrophobic particles have a higher strength to resist crushing ...

IN-SITU SELF DIVERTING WAG PROCESS

An aqueous viscoelastic solution for use in a modified water alternating gas (WAG) hydrocarbon production method includes a viscoelastic surfactant and a salt in an aqueous base solution. A modified water alternating gas (WAG) method for producing hydrocarbons from a hydrocarbon-bearing formation includes the step of introducing the aqueous viscoelastic solution into the hydrocarbon-bearing formation. The method also includes the step of introducing a service gas into the hydrocarbon-bearing formation. The aqueous viscoelastic solution and the service gas are introduced separately and sequentially into the hydrocarbon-bearing formation. The hydrocarbon-bearing formation produces a production fluid in response to each introduction. The production fluid contains both water and hydrocarbons. 2. The method of where the hydrocarbon-bearing formation is heterogeneous having a high permeability stratum and a low permeability stratum claim 1 , and a ratio of permeability between the high permeability stratum and the low permeability stratum in a range of from about 7:1 to about 8:1.3. The method of where the service gas comprises carbon dioxide.4. The method of where the service gas is introduced as a supercritical fluid.5. The method of where the aqueous viscoelastic fluid comprises calcium chloride.6. The method of where an amount of the aqueous viscoelastic solution introduced during the introducing the aqueous viscoelastic solution step and an amount of service gas introduced in the introducing the service gas step are similar in volume.7. The method of where an amount of the aqueous viscoelastic solution introduced during the introducing the aqueous viscoelastic solution step is about 20% of an estimated pore volume of the hydrocarbon-bearing formation to be treated.8. The method of where an amount of the service gas introduced during the introducing the service gas step is about 20% of an estimated pore volume of the hydrocarbon-bearing formation to be treated.9. The ...

Breakers for gelled fracturing fluids

A fracturing fluid for a downhole environment is disclosed, comprising a water-sensitive gel; and a hydrated breaker. A fracturing fluid for a downhole environment is also disclosed, the fracturing fluid comprising a water-sensitive carrier and a breaker, the breaker comprising one or more hydrates, and wherein water of the one or more hydrates is releasable so as to act with the water-sensitive carrier to reduce the viscosity of the fluid. A method of treating a downhole environment with a fracturing fluid is also disclosed, the method comprising: providing to the downhole environment a fluid comprising a water-sensitive carrier and a breaker, the breaker comprising one or more hydrates; and allowing water from the one or more hydrates to release so as to act with the carrier to reduce the viscosity of the fluid.

REDUCING SULFIDE IN OIL RESERVOIR PRODUCTION FLUIDS

Methods are provided for treating an oil reservoir to reduce the amount of sulfide in the production fluid obtained from a production well. The production fluid is treated with nitrate and/or nitrite ions, or another inorganic oxidizing agent, in an aqueous solution that is added to an injection well that is in contact with the production well. 2. The method of wherein the inorganic oxidizing agent has a reaction standard half-cell potential that is greater than −0.478 volts.3. The method of wherein the inorganic oxidizing agent is selected from the group consisting of permanganates claim 2 , persulfates claim 2 , inorganic peracids claim 2 , chromates claim 2 , bromates claim 2 , iodates claim 2 , chlorates claim 2 , perchlorates claim 2 , chlorites claim 2 , hypochlorites claim 2 , inorganic peroxides claim 2 , and oxides.4. The method of wherein the inorganic oxidizing agent is selected from the group consisting of chlorine dioxide claim 3 , hypochlorite claim 3 , persulfate claim 3 , and hydrogen peroxide.5. The method of wherein the inorganic oxidizing agent comprises nitrate ions claim 1 , nitrite ions claim 1 , or a mixture of nitrate and nitrite ions.6. The method of wherein the total molar concentration of nitrate ions claim 5 , nitrite ions claim 5 , or the mixture of nitrate and nitrite ions is at least about five-fold higher than the molar concentration of sulfide in production fluid of the production well measured prior to addition of the aqueous solution of (b).7. The method of wherein the total concentration of nitrate ions claim 5 , nitrite ions claim 5 , or the mixture of nitrate and nitrite ions in the aqueous solution of (b) is greater than about 3 claim 5 ,000 ppm.8. The method of wherein the total concentration of nitrate ions claim 7 , nitrite ions claim 7 , or the mixture of nitrate and nitrite ions in the aqueous solution of (b) is greater than about 10 claim 7 ,000 ppm.9. The method of wherein at least a portion of nitrate ions of (b) are ...

FRACTURING OPERATIONS EMPLOYING CHLORINE DIOXIDE

A method includes introducing a treatment fluid into a wellbore penetrating a subterranean formation, the treatment fluid including a polymer gel having a water-soluble polymer, a proppant, and a polymer gel-preserving amount of chlorine dioxide, the placing step includes applying the treatment fluid at a sufficient pressure and at a sufficient rate to fracture the subterranean formation. 1. A method comprising: a polymer gel comprising a water-soluble polymer;', 'a proppant; and', 'a polymer gel-preserving amount of chlorine dioxide;', 'wherein the placing step comprises applying the treatment fluid at a sufficient pressure and at a sufficient rate to fracture the subterranean formation., 'introducing a treatment fluid into a wellbore penetrating a subterranean formation, the treatment fluid comprising2. The method of claim 1 , wherein the treatment fluid comprises production water.3. The method of claim 1 , wherein the polymer gel-preserving amount of chlorine dioxide is an amount sufficient to substantially oxidize reducing species present in the treatment fluid.4. The method of claim 3 , wherein the reducing species comprises low oxidation state metal ions claim 3 , hydrogen sulfide claim 3 , and mixtures thereof.5. The method of claim 4 , wherein the low oxidations state metal ions comprise iron (II) ions.6. The method of claim 1 , wherein the polymer gel-preserving amount of chlorine dioxide is also a biocidally effective amount.7. The method of claim 6 , wherein the biocidally effective amount of chlorine dioxide comprises a range from about 1 to about 10 mg/L.8. The method of claim 1 , wherein the polymer gel-preserving amount of chlorine dioxide is further adjusted by estimating the amount of reducing species present in the subterranean formation being fractured.9. The method of claim 1 , wherein iron (III) ions are present in the treatment fluid and remain in the treatment fluid during the introducing step.10. A fracturing fluid comprising:a polymer gel ...

Enhanced Oil Recovery with Janus Nanoparticles

Enhanced oil recovery (EOR) including with a lamellar phase having Janus nanoparticles, petroleum surfactant, crude oil, and water and with additional water to give the flooding fluid that may be pumped through a wellbore into a subterranean formation to affect a property of hydrocarbon in the subterranean formation via contact of the flooding fluid with the hydrocarbon. 1. A method of enhanced oil recovery (EOR) , comprising:combining a lamellar phase comprising Janus nanoparticles, a petroleum surfactant, crude oil, and water with additional water to give a flooding fluid;pumping, via a centrifugal pump, the flooding fluid through a wellbore into a subterranean formation; andaffecting a property of hydrocarbon in the subterranean formation via contact of the flooding fluid with the hydrocarbon.2. The method of claim 1 , wherein the additional water is fresh water claim 1 , seawater claim 1 , or brine claim 1 , and wherein the petroleum surfactant comprises a petroleum sulfonate surfactant.3. The method of claim 1 , wherein the petroleum surfactant comprises a zwitterionic surfactant claim 1 , and wherein the Janus nanoparticles comprise Janus metal-oxide nanoparticles or Janus graphene-oxide nanosheets claim 1 , or a combination thereof.4. The method of claim 1 , wherein the petroleum surfactant comprises cocamidopropyl hydroxysultaine (CAHS) or cocamidopropyl betaine (CAPB) claim 1 , or a combination thereof.5. The method of claim 1 , wherein the Janus nanoparticles comprise Janus silicon-oxide (SiO) nanoparticles claim 1 , and wherein the Janus nanoparticles comprise less than 0.2 weight percent (wt %) of the flooding fluid.6. The method of claim 1 , wherein the EOR comprises:nanofluid flooding via the Janus nanoparticles; andsurfactant flooding via the petroleum surfactant, wherein the petroleum surfactant comprises less than 1 wt % of the flooding fluid, wherein the hydrocarbon comprises crude oil and the property comprises viscosity, and wherein affecting the ...

NOVEL VISCOUS FLUIDS SYSTEMS FROM PRODUCED AND FLOW BACK WATERS

In certain instances high levels of boron is present in produced or flowback water after it has been treated. The boron or borates tend to cause the guar to cross-link and become viscous too early which may cause undue wear or other problems with the surface equipment. It has been found that in the presence of low pH the viscosifier typically does not cross-link in the presence of a borate allowing the finished water to be used to hydrate the fluid. The fluid including the now hydrated linear gel is then subject to a chelating process so that the boron may be sequestered. Once the originally present borate is sequestered a slowly soluble borate is added to cause the linear gel to cross-link at the desired point in time. 1. A well treatment material method comprising:lowering a pH of a finished water,hydrating a viscosifier with the finished water,chelating a boron present in the finished water and the viscosifier,raising a pH of the finished water and the viscosifier, andadding a slowly soluble borate to the finished water and the viscosifier.2. The method of wherein claim 1 , the step of lowering the pH consists of lowering the pH to below 7.3. The method of wherein claim 1 , the step of lowering the pH consists of lowering the pH to between 6 and 6.5.4. The method of wherein claim 1 , the step of raising the pH consists of raising the pH to above 7.5. The method of wherein claim 1 , the step of raising the pH consists of raising the pH to between 9.5 and 12.6. The method of wherein claim 1 , the step of raising the pH consists of raising the pH to between 10 and 11.7. The method of wherein claim 1 , the slowly soluble borate is ulexite.8. The method of wherein claim 1 , a fast crosslinker is added with the slowly soluble borate.9. The method of wherein claim 8 , a fast crosslinker is a borax solution.10. The method of wherein claim 8 , a fast crosslinker is potassium borate. This application claims priority to U.S. Provisional Patent Application No. 62/023,113 ...

THERMALLY-STABLE, NON-PRECIPITATING, HIGH-DENISTY WELLBORE FLUIDS

A wellbore treatment fluid comprising: a base fluid; and a water-soluble salt, the salt comprising: a cation; and an anion, wherein the anion is selected from phosphotungstate, silicotungstate, phosphomolybdate, and silicomolybdate. The treatment fluid can have a density greater than or equal to 13 pounds per gallon. A method of treating a portion of a subterranean formation penetrated by a well comprising: introducing the treatment fluid into the well. 1. A system comprising:a wellbore that penetrates a subterranean formation; and (A) a base fluid; and', (i) a cation; and', '(ii) an anion, wherein the anion is selected from phosphotungstate, silicotungstate, phosphomolybdate, and silicomolybdate., '(B) a water-soluble salt, the salt comprising], 'a treatment fluid comprising2. The system of claim 1 , wherein the base fluid comprises water claim 1 , and wherein the water is selected from the group consisting of freshwater claim 1 , brackish water claim 1 , saltwater claim 1 , and any combination thereof.3. The system of claim 1 , wherein the cation is selected from ammonium claim 1 , phosphonium claim 1 , quaternary amines claim 1 , poly-quaternary amines claim 1 , alkaline earth metals claim 1 , transition metals claim 1 , and rare earth elements.4. The system of claim 1 , wherein the cation is organic or inorganic.5. The system of claim 1 , wherein the treatment fluid is thermally stable at temperatures greater than 212° F.6. The system of claim 1 , wherein the treatment fluid is a drilling fluid claim 1 , a drill-in fluid claim 1 , a packer fluid claim 1 , a completion fluid claim 1 , a spacer fluid claim 1 , a work-over fluid claim 1 , or an insulating fluid.7. The system of claim 1 , further comprising a mixer claim 1 , wherein the mixer is capable of mixing the treatment fluid.8. The system of claim 1 , further comprising a pump capable of pumping the treatment fluid into the subterranean formation.9. The system of claim 1 , wherein the treatment fluid further ...

Compositions And Methods For Treating Subterranean Formations

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.

BINDING COMPOSITION FOR PROPPANT

A downhole treatment fluid made up of a binding composition and a proppant, the binding composition including an aluminosilicate source, a metal silicate, an alkali metal activator. The binding composition may form a coated particulate or an aggregate with the proppant and provides strength-enhancing properties. The binding composition has easy handling properties facilitating on-the-fly preparation and downhole injection procedures. Furthermore, the binding composition has a low strength-hardening temperature and so may strength-harden in the presence of downhole temperatures. 1. A method comprising: an aqueous base fluid,', 'an aluminosilicate source,', 'a metal silicate, and', 'an alkali metal activator., 'injecting a treatment fluid into a borehole, the treatment fluid comprising a proppant and a binding composition, the binding composition having'}2. The method of wherein the binding composition coats the proppant to form a coated proppant particulate upon strength-hardening.3. The method of claim 1 , wherein the binding composition forms an aggregate with the proppant.4. The method of claim 1 , wherein the binding composition strength-hardens in the presence of heat within the borehole.5. The method of claim 4 , wherein the strength-hardened binding composition proppant withstands at least 8 claim 4 ,000 psi closure pressure.6. The method of claim 1 , wherein the aluminosilicate source is fly ash.7. The method of claim 1 , wherein the binding composition has a strength-hardening temperature of less than 400° F.8. The method of claim 1 , wherein the aluminosilicate source has an average particle size of less than 100 microns.9. The method of claim 1 , wherein the metal silicate is sodium metasilicate.10. The method of claim 1 , wherein alkali metal activator contains a metal selected from groups 1 or 2 of the periodic table.11. The method of claim 1 , wherein the alkali metal activator is an alkali metal carbonate or alkali metal hydroxide.12. The method of ...

SYSTEMS AND METHODS FOR REMOVING CONTAMINANTS FROM HIGH DENSITY COMPLETION FLUID

A system and method of decreasing contaminant concentration in an oilfield brine fluid, such as a high density completions fluid, that includes mixing the oilfield brine fluid with chlorine dioxide (ClO). The oilfield brine fluid includes dissolved contaminant, such as iron, and one or more dissolved salts, such as selected from the group consisting of NaCl, NaBr, CaCl, CaBr, and ZnBr. The mixing is for a time sufficient for the ClOto react with at least one component of the oilfield brine fluid to form precipitated contaminant without reacting to the one or more salts. 1. A method of decreasing contaminant concentration in a high density completions fluid , comprising:{'sub': 2', '2, 'mixing the completions fluid with chlorine dioxide (ClO), wherein the fluid comprises at least one dissolved contaminant and one or more dissolved salts, and wherein the mixing is for a time sufficient for the ClOto react with the at least one dissolved contaminant without reacting with the at least one dissolved salt.'}2. The method of claim 1 , wherein the at least one dissolved contaminant comprises dissolved iron.3. The method of claim 1 , wherein a concentration of the at least one dissolved contaminant is greater than about 50 ppm prior to the mixing.4. The method of claim 1 , wherein a concentration of the at least one dissolved contaminant is less than about 50 ppm after the mixing.5. The method of claim 1 , further comprising forming a precipitate of the at least one dissolved contaminant.6. The method of claim 5 , further comprising removing the precipitate from the fluid.7. The method of claim 1 , wherein the one or more salts is selected from the group consisting of formate salts claim 1 , NaCl claim 1 , NaBr claim 1 , CaCl claim 1 , CaBr claim 1 , and ZnBr.8. The method of claim 1 , wherein the fluid comprises a plurality of salts.9. The method of claim 1 , wherein the one or more salts comprises ZnBr.10. The method of claim 9 , wherein an amount of zinc remaining in the ...

Treatment fluids comprising anhydrous ammonia for use in subterranean formation operations

Methods including preparing a treatment fluid comprising a bulk amount of anhydrous ammonia, wherein the anhydrous ammonia is present in an amount greater than about 10 % by weight of a liquid portion of the treatment fluid, and wherein the anhydrous ammonia is in a phase selected from the group consisting of a liquid phase, a gaseous phase, supercritical phase, and any combination thereof; and introducing the treatment fluid into a subterranean formation.

METHOD OF PRODUCING MICRONIZED BARITE PARTICLES

A drilling fluid composition that contains micronized barite particles with a particle size in the range of 1 to 5 μm, and also a method of fracturing a subterranean formation using the drilling fluid composition. Various embodiments of the micronized barite particles and the method of making thereof, the drilling fluid composition, and the method of fracturing a subterranean formation are also provided. 114-. (canceled)15. A method of making micronized barite particles , comprising:stirring a suspension solution comprising a barite mixture and at least one chelating agent;filtering the suspension solution to form a filter cake comprising barite; andgrinding the filter cake to form the micronized barite particles each having a particle size in the range of 1 to 5 μm,wherein an amount of barite in the barite mixture is at least 80 wt %, andwherein an amount of said chelating agent in the suspension solution is in the range of 1 wt % to 20 wt %, relative to the total weight of the suspension solution.16. The method of claim 15 , further comprising:grinding the barite mixture prior to the stirring.17. The method of claim 15 , wherein the suspension solution is centrifugally stirred with a rotational speed of at least 500 rpm claim 15 , at a temperature in the range of 40 to 80° C.18. The method of claim 15 , wherein the amount of barite in the barite mixture is at least 95 wt % claim 15 , and wherein the amount of said chelating agent in the solution is in the range of 1 wt % to 10 wt %.19. The method of claim 15 , wherein said chelating agent is at least one selected from the group consisting of ethylenediamine tetraacetic acid claim 15 , glutamic diacetic acid claim 15 , hydroxyethylenediamine triacetic acid claim 15 , and salts thereof.20. The method of claim 15 , wherein the suspension solution has a pH in the range of 7 to 14. This application is based on, and claims the benefit of priority to, provisional application No. 62/274,423 filed Jan. 4, 2016, the entire ...

BUBBLE-ENHANCED PROPPANT FOR WELL FRACTURING

Stable, gas-filled bubbles on the surface of proppant particles are formed by placing proppant in selected organic solvent having a much greater solubility of a selected gas compared to water, pressurizing the solvent with the selected gas, e.g., nitrogen, at pressures equal of greater than the operating pressure for a set time period to achieve saturation, and then replacing the solvent with water before reducing the pressure back to operating pressure level to create a local supersaturation near the solvent-solid interface, which will result in gas-filled bubble formation on the surface of proppant particles. The pressurized mixture of bubble surrounded proppant particles and water can then be combined with a respective fracturing fluid, e.g., slick water or carbon dioxide and/or nitrogen foam or an emulsion, which can be used in oil or gas producing wells to improve efficiency of hydraulic fracturing thereof. 1. A method for forming gas-filled bubbles on a surface of a proppant particle comprising the steps of placing the proppant particle in water at an operating pressure , pressurizing the water with a gas to a pressure equal to or greater than the operating pressure to create saturation around or in the vicinity of the proppant particle and releasing the pressure from the water to the operating pressure level.2. The method as claimed in wherein the proppant particle is selected from the group consisting of sand claim 1 , resin-coated sand claim 1 , ceramic claim 1 , hollow ceramic and bauxite claim 1 , and mixtures of these.3. The method as claimed in wherein the gas is selected from the group consisting of nitrogen claim 1 , argon claim 1 , methane claim 1 , carbon dioxide claim 1 , hydrogen and helium and mixtures of these.4. The method as claimed in wherein the gas-filled bubbles are nanobubbles or microbubbles.5. The method as claimed in wherein the proppant particle is added to a well producing oil and/or gas to be fractured.6. The method as claimed in ...

NANOPARTICLE MODIFIED FLUIDS AND METHODS OF MANUFACTURE THEREOF

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 ...

PROCESS FOR REMOVAL OF ZINC, IRON AND NICKEL FROM SPENT COMPLETION BRINES AND PRODUCED WATER

Zinc, nickel and iron can be recovered from spent brines and produced water using a method that includes admixing an aqueous fluid with hydrazine to form a hydrazine complex and then filtering or otherwise removing the hydrazine complex from the aqueous fluid. Once treated, the aqueous fluid can then be recycled or at be the subject to an easier disposal. The isolated metal hydrazine complex may be recycled or discarded. 1. A method for recovering zinc metal , nickel metal , iron metal , zinc cations , nickel cations or iron cations from fluids produced from an oil well , the method comprising admixing an aqueous fluid produced from an oil well with hydrazine under conditions sufficient to produce an insoluble zinc or nickel hydrazine complex and removing the insoluble zinc or nickel hydrazine complex from the fluid.2. The method of wherein the hydrazine is employed as an aqueous solution having a hydrazine concentration of from about 10% to about 50%.3. The method of wherein the hydrazine is employed as an aqueous solution having a hydrazine concentration of from about 20% to about 40%.4. The method of wherein the hydrazine is employed as an aqueous solution having a hydrazine concentration of about 35%.5. The method of wherein the molar ratios of hydrazine to zinc claim 1 , nickel claim 1 , or iron necessary to form an insoluble complex is from about one to about three moles of hydrazine to about one mole of zinc claim 1 , nickel claim 1 , or iron.6. The method of wherein the molar ratios of hydrazine to zinc claim 5 , nickel claim 5 , or iron necessary to form an insoluble complex is from about one to about two moles of hydrazine to about one mole of zinc claim 5 , nickel claim 5 , or iron.7. The method of wherein the insoluble zinc claim 1 , nickel claim 1 , or iron hydrazine complex is removed from the fluid by filtering.8. The method of wherein the insoluble zinc claim 1 , nickel claim 1 , or iron hydrazine complex is removed from the fluid by centrifugation.9 ...

HYDROGEN PEROXIDE STEAM GENERATOR FOR OILFIELD APPLICATIONS

Exemplary apparatuses, systems, and methods are provided to produce steam for use in oil field applications. In some embodiments, a catalyst is provided that includes a plurality of ceramic bodies impregnated with an alkaline-promoted manganese oxide. In other embodiments, the catalyst includes a plurality of bodies formed of an active ceramic oxide in a consolidated state without an underlying ceramic body. The bodies are contacted with a liquid hydrogen peroxide having a strength, in one embodiment, between about 30 and about 70 weight percent to produce steam. The steam is directed to an oil field application, such as, but not limited to, a geologic formation to increase oil production from the geologic formation, an applicator to clean oilfield equipment, a heat exchanger to heat hydrogen peroxide, or a heat exchanger to heat living quarters. 1. A method for producing steam for use in stimulating a geologic formation , the method comprising:providing a catalyst that includes a plurality of ceramic bodies impregnated with manganese oxide;contacting the catalyst with a liquid hydrogen peroxide having a strength between about 30 and about 70 weight percent to produce steam; andinjecting the steam into a geologic formation.2. The method of claim 1 , wherein the liquid hydrogen peroxide has a strength of between about 50 and about 65 weight percent.3. The method of claim 1 , wherein the liquid hydrogen peroxide has a strength of about 60 weight percent.4. The method of claim 1 , wherein the liquid hydrogen peroxide has a strength below a self-heat strength of the liquid hydrogen peroxide.5. The method of claim 1 , wherein the ceramic bodies include spheres.6. The method of claim 5 , wherein the spherical ceramic bodies have a diameter of between about 0.0625 inches and about 0.25 inches.7. The method of claim 5 , wherein the spherical ceramic bodies have at least three distinct diameters.8. The method of claim 7 , wherein the at least three distinct diameters include ...

Buffered friction reducer for subterranean operations

Systems and methods having friction reducer compositions for use in subterranean treatment fluids are provided. An embodiment of the present disclosure is a method comprising: (A) forming a treatment fluid comprising: an aqueous base fluid, a friction reducer, and an alkaline buffering agent, wherein the treatment fluid has a pH in the range of about 7 to about 10; and (B) injecting the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation at a pressure sufficient to create or enhance one or more fractures within the subterranean formation.

METHODS FOR CONTROLLING CONDUCTIVE AGGREGATES

Provided are methods and systems for treating a subterranean formation. An example method comprises adding proppant particulates to a fluidized bed granulator; spraying a binding agent on the proppant particulates to at least partially coat the proppant particulates with the binding agent, wherein the coated proppant particulates form proto-aggregates; adding the proto-aggregates to a treatment fluid; and introducing the treatment fluid into a fracture within the subterranean formation. 1. A method of treating a subterranean formation comprising:adding proppant particulates to a fluidized bed granulator;spraying a binding agent on the proppant particulates to at least partially coat the proppant particulates with the binding agent, wherein the coated proppant particulates form proto-aggregates;adding the proto-aggregates to a treatment fluid; andintroducing the treatment fluid into a fracture within the subterranean formation.2. The method of claim 1 , further comprising activating the binding agent.3. The method of claim 1 , wherein the binding agent is a first binding agent and wherein the method further comprises adding a second binding agent to the treatment fluid after adding the proto-aggregates to the treatment fluid claim 1 , wherein the second binding agent may be the same or different from the first binding agent.4. The method of claim 1 , wherein the residence time of the proppant particulates in the fluidized bed granulator is controlled such that the average particle size distribution of the proto-aggregates is less than one fifth the diameter of the opening of the fracture.5. The method of claim 1 , wherein the treatment fluid is a treatment fluid selected from the group consisting of a fracturing fluid claim 1 , a spacer fluid claim 1 , a proppant-laden fluid claim 1 , and any combination thereof.6. The method of claim 1 , wherein the proppant particulates comprise a proppant particulate selected from the group consisting of sand claim 1 , natural ...

USING BRINE RESISTANT SILICON DIOXIDE NANOPARTICLE DISPERSIONS TO IMPROVE OIL RECOVERY

This invention describes and claims the stimulation of several Wolfcamp and Bone Springs targeted wells in the northern Delaware Basin using fracturing treatments and a new method employing relatively small pre-pad pill volumes of Brine Resistant Silicon Dioxide Nanoparticle Dispersions ahead of each stage of treatment have been successfully performed. The invention includes a method of extending an oil and gas system ESRV comprising the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion (“BRINE RESISTANT SDND”) to conventional oil well treatment fluids. The invention also includes a method of increasing initial production rates of an oil well by over 20.0% as compared to wells either not treated with the BRINE RESISTANT SDND technology or treated by conventional nano-emulsion surfactants. The Method focuses on the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion to conventional oil well treatment fluids. 1. A method of treatment of an oil and gas system , the method comprising adding an aqueous brine resistant silicon dioxide nanoparticle dispersion into the oil and gas system as a pre-pad pill , wherein the aqueous brine resistant silicon dioxide nanoparticle dispersion comprises silica nanoparticles surface modified with trimethoxy[3-(oxiranylmethoxy)propyl] silane , and wherein the aqueous brine resistant silicon dioxide nanoparticle dispersion is characterized by having a change in turbidity of less than about 100 NTU after API brine exposure according to an API brine resistance test by use of a turbidimeter.2. The method of claim 1 , further comprising adding a frac stage fluid into the oil and gas system after the pre-pad pill claim 1 , wherein the volume of the aqueous brine resistant silicon dioxide nanoparticle dispersion pre-pad pill is from about 500 to about 1 claim 1 ,000 U.S. gallons per about 3 claim 1 ,000 to about 6 claim 1 ,000 U.S. barrels of the frac stage fluid.3. The method of claim 1 , wherein ...

Chlorine dioxide generator for the efficient generation of chlorine dioxide in dilute solutions

Disclosed is a process for the safe and efficient generation of chlorine dioxide while achieving a variable chlorine dioxide mass flow rate, with a turn-down to turn-up ratio of at least 1 to 200. The process allows for a single chlorine dioxide generating system to safely provide variable mass flow rate of chlorine dioxide to applications that have wide ranging chlorine dioxide demand, like those experienced in oil and gas applications. 1. An automated process for the safe and efficient generation of a dilute aqueous solution of chlorine dioxide having a variable chlorine dioxide mass flow rate of at least 1 to 200 turn-down turn-up ratio , said aqueous solution is applied to oil and gas applications , the process comprising:a source of motive water in fluid contact with a variable mass flow rate chlorine dioxide generating system comprising: variable feed rate chemical pumps, chemicals for producing chlorine dioxide, flow meter, flow regulating valve, injection manifold, a reaction zone (reactor), pH sensor for monitoring the reactor effluent pH, and an optional optical sensor for measuring chlorine dioxide concentration exiting the reactor;{'sub': 2', '2, 'a control panel comprising a PLC programmed with turn-down turn-up logic and assigned a minimum ClOset-point and a maximum ClOset-point, the control panel in signal contact with the variable mass flow rate chlorine dioxide generating system and sensors for monitoring process conditions that influence the required mass flow rate of chlorine dioxide exiting the said chlorine dioxide generating system;'}the PLC applies turn-down turn-up logic to vary the mass flow rate of chlorine dioxide in the motive water to produce a dilute aqueous solution of chlorine dioxide by: (1) varying the concentration of chlorine dioxide by changing the feed rate of the chlorine dioxide generating system chemical pumps while controlling the motive water flow rate to target a predetermined value, and (2) changing the motive water flow ...

THERMO-GAS-GENERATING SYSTEMS AND METHODS FOR OIL AND GAS WELL STIMULATION

A method of treating a subterranean reservoir includes the steps of delivering a stabilized, non-explosive combustible oxidizing solution (COS) to a desired treatment area in the reservoir and activating the COS with an activator which reduces the pH of the COS. Upon activation, the COS reacts to produce sufficient heat and gas to stimulate the treatment area. 1. A method of treating a subterranean reservoir , comprising the steps of:(a) delivering a stabilized, non-explosive combustible oxidizing solution (COS) to a desired treatment area in the reservoir,(b) activating the COS with an activator which reduces the pH of the COS, wherein upon activation, the COS reacts to produce sufficient heat and gas to stimulate the treatment area.2. The method of wherein the activator is either consecutively injected after the COS claim 1 , or is encapsulated in an emulsion with the COS.3. The method of wherein the treatment zone is a near well-bore zone and/or a zone radially distal from the wellbore within the reservoir.4. The method of wherein the COS comprises an aqueous solution comprising:(a) a nitrate salt,(b) a nitrite salt, and(c) a stabilizer.5. The method of wherein the nitrate salt comprises ammonium nitrate.6. The method of wherein the nitrate salt comprises sodium nitrite.7. The method of wherein the weight percent composition (w:w) of the COS comprises ammonium nitrate of 15.0-50.0% claim 6 , sodium nitrite of 15.0-40.0% claim 6 , and stabilizer of 0-2.0%.8. The method of wherein the COS comprises an oil-in-water or water-in-oil emulsion claim 4 , and further comprises and oil and an emulsifier.9. The method of wherein the composition comprises oil in a weight percent of 10.0-25.0 claim 8 , and emulsifier in a weight percent of 0.1-2.0%.10. The method of wherein the COS further comprises a viscosifier.11. The method of wherein the viscosifier comprises guar or a polyacrylamide in a weight percent amount of 0.1-0.5%.12. The method of wherein the COS comprises a BSS ...

HEAVY FLUID AND METHOD OF MAKING IT

Heavy fluids are made from calcium bromide and at least one hydrogen bond donor such as a low molecular weight polyol or an organic acid. The combination of a hydrogen bond donor and calcium bromide as a hydrogen bond acceptor in an appropriate molar ratio forms a higher density clear completion fluid at a low temperature not otherwise obtainable with heavy aqueous solutions of calcium bromide such as are used in oilfield wells. A method of making the fluid comprises mixing calcium bromide with the polyol(s) in the presence of water and then reducing the water content, thus forming a heavy fluid. A crystallization inhibitor such as nitrilitriacetamide or a particulate silicate is included in the formulation. When the heavy fluid “freezes,” its physical form is somewhat amorphous and pumpable rather than crystalline. The heavy fluid is useful as a drilling fluid as well as a completion fluid and for other purposes in oil recovery processes where extreme density is beneficial. 1. Method of making a clear , zinc-free heavy fluid comprising (a) mixing (i) calcium bromide and 0% to 50% water by weight of the total of calcium bromide and water with (ii) at least one hydrogen donor in a mixture with up to 50% water by weight of the total of said hydrogen donor and water , (b) adding a small amount of crystallization inhibitor to the mixture of (a)(i) and (a)(ii) , and (c) removing water from said mixture to achieve a density of said mixture of at least 16 pounds per gallon.2. Method of wherein said at least one hydrogen donor comprises at least one polyol having from 2-6 carbon atoms and 2-6 hydroxyl groups or at least one organic acid.3. Method of wherein said calcium bromide in part (a)(i) is a saturated solution of calcium bromide in said water.4. Method of wherein said calcium bromide in part (a)(i) is solid calcium bromide.5. Method of wherein (1) step (a)(i) produces an aqueous solution of calcium bromide having a density of 13.9 to 14.5 pounds per gallon claim 1 , ( ...

Colored organic peroxide compositions and methods for breaking hydraulic fracturing fluids

A breaker composition for use in a fracturing fluid comprises at least one organic peroxide (e.g., tert-butyl hydroperoxide), at least one dye (e.g., an FD&C dye), and at least one alcohol (e.g., propylene glycol). A promoter composition for use in a fracturing fluid comprises at least one promoter (e.g., sodium thiosulfate), at least one dye (e.g., an FD&C dye). According to certain embodiments, the dye increases the efficiency of the promoter and/or the organic peroxide, so that the break time and the peak viscosity of the aqueous treatment fluid are reduced.

IN SITU RECOVERY FROM RESIDUALLY HEATED SECTIONS IN A HYDROCARBON CONTAINING FORMATION

Methods of treating a tar sands formation is described herein. The methods may include providing heat to a first section of a hydrocarbon layer in the formation from a plurality of heaters located in the first section of the formation. Heat is transferred from the heaters so that at least a first section of the formation reaches a selected temperature. At least a portion of residual heat from the first section transfers from the first section to a second section of the formation. At least a portion of hydrocarbons in the second section are mobilized by providing a solvation fluid and/or a pressurizing fluid to the second section of the formation. 11300-. (canceled)1301. A method of treating a tar sands formation , comprising:providing heat to at least part of the formation from a plurality of heaters located in the formation;allowing the heat to transfer from the heaters so that at least a portion of the formation reaches a selected temperature;allowing fluids to gravity drain to a bottom portion of the formation;producing a substantial portion of the drained fluids from one or more production wells located at or proximate the bottom portion of the formation, wherein at least a majority of the produced fluids are condensable hydrocarbons;reducing the pressure in the formation to a selected pressure after the portion of the formation reaches the selected temperature and after producing a majority of the condensable hydrocarbons in the portion of the formation;providing a solvation fluid and/or a pressurizing fluid to the portion of the formation, wherein the solvation fluid solvates at least a portion of remaining condensable hydrocarbons in the part of the formation to form a mixture of solvation fluid and condensable hydrocarbons; andmobilizing the mixture.1302. The method of claim 1301 , wherein the selected temperature is between 250° C. and 400° C.1303. The method of claim 1301 , wherein the solvation fluid comprises carbon disulfide claim 1301 , water claim ...

Synergistic blends of fluoro-inorganics and inorganic acids for removing deposits and stimulating geothermal wells

The present disclosure relates to the treatment of formation rock or scale. The rock or scale may be located in a geothermal well. The rock or scale may be treated with a stimulation fluid. The stimulation fluid includes a salt of a nitrogen base having a fluoro inorganic anion and an acid component. The rock may include quartz. The acid component may include hydrochloric acid.

ADDITIVES TO MINIMIZE VISCOSITY REDUCTION FOR GUAR/BORATE SYSTEM UNDER HIGH PRESSURE

A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer. 1. A method for preparing a pressure-tolerant fluid , the method comprising the steps of: a polymer, wherein the polymer comprises cis-hydroxyl groups,', 'a boron-containing crosslinker, wherein the boron-containing crosslinker is selected from the group consisting of borate salts, boric acid, and combinations of the same, and', 'a transition metal oxide additive, wherein the transition metal oxide is in the absence of a crosslinker appended to its surface, wherein the transition metal oxide additive is selected from the group consisting of transition metal oxide nanoparticles, transition metal oxide nanoparticle dispersions, polymeric material-stabilized transition metal oxides, transition metal oxide nanoparticles with other metal nanoparticles, and metal-organic polyhedra including transition metal oxides, wherein the transition metal oxide is operable to crosslink the cis-hydroxyl groups of the polymer at pressures greater than 2500 psi,', 'wherein the boron-containing crosslinker and the transition metal oxide additive are separately operable to crosslink the polymer; and, 'adding a pressure-tolerant dual-crosslinker gel to a fracturing fluid, the pressure-tolerant dual-crosslinker gel comprisesmixing the pressure-tolerant dual-crosslinker gel with the fracturing fluid to produce the pressure-tolerant fluid, wherein the pressure-tolerant dual-crosslinker gel is operable to viscosify the fracturing fluid, wherein the pressure-tolerant fluid has a viscosity of greater than 150 cP at 150 deg F. at a pressure of 8000 psi.2. The method of claim 1 , wherein the polymer is present in a ...

Internal Breaker for Fluid Loss Control Pills and Method

A method of treating a subterranean formation. The method may include providing a fluid-loss control pill that comprises an aqueous base fluid, a gelling agent, and an internal breaker that is selected from the group consisting of inorganic delayed acids or inorganic salts. The method can include introducing the fluid-loss control pill into a subterranean formation, allowing the internal breaker to reduce the viscosity of the pill after a delay period, and allowing the fluid-loss control pill to break. 1. A method of treating a subterranean formation comprising:providing a fluid-loss control pill that comprises an aqueous base fluid, a gelling agent, and an internal breaker that is selected from the group consisting of inorganic delayed acids and inorganic salts;introducing the fluid-loss control pill into a subterranean formation;allowing the internal breaker to reduce the viscosity of the pill after a delay period;allowing the fluid-loss control pill to break.2. The method of wherein the inorganic salts consist of alkali metal salts that are selected from a group consisting of bisulfite and bisulfate ions.3. The method of wherein the inorganic salts are encapsulated.4. The method of wherein the inorganic delayed acids are encapsulated.5. The method of wherein the inorganic delay acids are selected from the group consisting of sulfamic acid claim 1 , sulfonic acid and its derivatives claim 1 , toluensulfonic acid claim 1 , phosphonic acid and its derivatives claim 1 , and aluminum chloride.6. The method of wherein the inorganic delay acids are selected from the group consisting of sulfamic acid claim 4 , sulfonic acid and its derivatives claim 4 , toluensulfonic acid claim 4 , phosphonic acid and its derivatives claim 4 , and aluminum chloride.7. The method of wherein the gelling agent comprises at least one polymer selected from the group consisting of a natural polymer claim 1 , a synthetic polymer claim 1 , an xanthan claim 1 , an xanthan derivative claim 1 , a ...

FLOODING OPERATIONS EMPLOYING CHLORINE DIOXIDE

A method includes introducing a treatment fluid including a first polymer gel into a subterranean formation to generate a production fluid having an aqueous portion and a hydrocarbon portion, treating the aqueous portion of the production fluid with chlorine dioxide to separate additional hydrocarbons from the aqueous portion, and adjusting the viscosity of the treated aqueous portion prior to introducing the treated aqueous portion back into the subterranean formation. 1. A method comprising: a water-soluble polymer;', 'an amount of chlorine dioxide sufficient to increase the viscosity of the treatment fluid; and', 'an aqueous base fluid., 'introducing a polymer gel-containing treatment fluid into a subterranean formation, the polymer gel-containing treatment fluid comprising2. The method of claim 1 , wherein the amount of chlorine dioxide is at least about 5 ppm residual chlorine dioxide.3. The method of claim 1 , wherein the amount of chlorine dioxide comprises at least about 6 ppm residual chlorine dioxide.4. The method of claim 1 , wherein the amount of chlorine dioxide is in a range from about 5 ppm to about 20 ppm residual chlorine dioxide.5. The method of claim 1 , wherein an upper limit of the amount chlorine dioxide is an amount less than would substantially break the polymer gel claim 1 , as determined by viscosity measurement.6. The method of claim 1 , wherein the amount of chlorine dioxide is substantially greater than needed for biocidal activity.7. A method comprising: a polymer gel comprising a water-soluble polymer; and', 'an amount of chlorine dioxide substantially greater than needed for biocidal activity and also allowing an amount of water-soluble polymer to be used to form the polymer gel to be reduced by about 25% to about 75%, relative to a treatment fluid lacking chlorine dioxide; and', 'an aqueous base fluid., 'introducing a treatment fluid into a subterranean formation, the treatment fluid comprising8. The method of claim 7 , wherein the ...

Combo Hydraulic Fracturing Fluid Concentrate Having Both Drag Reduction and Sand-Carrying Properties

A combo hydraulic fracturing fluid concentrate, is characterized by 1) firstly preparing “water-in-water” dispersion polymer drag reducer A, which is synthesized via dispersion polymerization to obtain water-soluble macromolecular colloidal particles dispersed in an aqueous solution of inorganic salts; 2) secondly, adding a dispersion B, which is a polymeric viscosifier, having shear-thinning properties, dispersed in aqueous inorganic salt solution; wherein the percentage by weight of drag reducing agent to viscosifier dispersion B is 20-80:80-20. 1. A combo hydraulic fracturing fluid concentrate , characterized by 1) firstly preparing “water-in-water” dispersion polymer drag reducer A , which is synthesized via dispersion polymerization to obtain water-soluble macromolecular colloidal particles dispersed in an aqueous solution of inorganic salts; 2) secondly , adding a dispersion B , which is a polymeric viscosifier , having shear-thinning properties , dispersed in aqueous inorganic salt solution; wherein the percentage by weight of drag reducing agent to viscosifier dispersion B is 20-80:80-20;wherein, the drag reducing agent A is obtained by dispersion polymerization at elevated temperature with heating a homogenous solution containing water-soluble monomer A1, water-soluble dispersant A2, water-soluble free radical initiator A3, inorganic salt A4, and water A5, under mechanical agitation; wherein, the weight percentages of each component described above, with regard to the total weight of reactant mixture for preparing drag reducer A, are as the following: water-soluble monomers A1: 5.0-20.0%; water-soluble dispersant A2: 0.1-5.0%; water-soluble radical initiator A3: 0.000001-0.100%; inorganic salt A4: 15.0-40.0%; water A5: remainder;wherein the viscosifier dispersion B is composed of shear-thinning polymer B1, inorganic salt B2 and water B3; wherein the weight percentages of each component based on the total weight of the viscosifier dispersion B are: shear- ...

METHOD FOR MAKING A DRILLING FLUID COMPOSITION AND FRACTURING A SUBTERRANEAN FORMATION

A drilling fluid composition that contains micronized barite particles with a particle size in the range of 1 to 5 μm, and also a method of fracturing a subterranean formation using the drilling fluid composition. Various embodiments of the micronized barite particles and the method of making thereof, the drilling fluid composition, and the method of fracturing a subterranean formation are also provided. 1. A method of making a drilling fluid composition and fracturing a subterranean formation , comprising:suspending micronized barite particles in water to form the drilling fluid composition,injecting the drilling fluid composition into the subterranean formation through a wellbore to fracture the subterranean formation and form fissures in the subterranean formation, wherein the micronized barite particles have a particle size in the range of 1 to 5 μm; and the micronized barite particles;', 'an aqueous base fluid; and', 'a viscosifier,, 'the drilling fluid composition compriseswherein the micronized barite particles are present in the drilling fluid composition at a concentration in the range of 1 wt % to 50 wt %, relative to the total weight of the drilling fluid composition.2. The method of claim 1 , further comprising:injecting a proppant into the subterranean formation through the wellbore to deposit the proppant in the fissures.3. The method of claim 1 , further comprisingcirculating the drilling fluid composition within the wellbore after the injecting.4. The method of claim 1 , wherein the drilling fluid composition is injected at a pressure of at least 5 claim 1 ,000 psi to fracture the subterranean formation.5. The method of claim 1 , wherein the viscosifier is bentonite.6. The method of claim 1 , wherein the drilling fluid composition has a plastic viscosity of 14 to 18 cP at a temperature of 80 to 90° F.7. (canceled)8. The method of claim 1 , wherein the drilling fluid composition has a density of 12 to 14 ppg at a temperature of 80 to 90° F.9. The ...

Heavy Fluid and Method of Making It

Heavy fluids are made from calcium bromide and at least one hydrogen bond donor such as a low molecular weight polyol or an organic acid. The combination of a hydrogen bond donor and calcium bromide as a hydrogen bond acceptor in an appropriate molar ratio forms a higher density clear completion fluid at a low temperature not otherwise obtainable with heavy aqueous solutions of calcium bromide such as are used in oilfield wells. A method of making the fluid comprises mixing calcium bromide with the polyol(s) in the presence of water and then reducing the water content, thus forming a heavy fluid. A crystallization inhibitor such as nitrilitriacetamide or a particulate silicate is included in the formulation. When the heavy fluid “freezes,” its physical form is somewhat amorphous and pumpable rather than crystalline. The heavy fluid is useful as a drilling fluid as well as a completion fluid and for other purposes in oil recovery processes where extreme density is beneficial. 1. Method of making a clear , zinc-free heavy fluid comprising (a) mixing (i) calcium bromide and 0% to 50% water by weight of the total of calcium bromide and water with (ii) at least one hydrogen donor in a mixture with up to 50% water by weight of the total of said hydrogen donor and water , (b) adding a small amount of crystallization inhibitor to the mixture of (a)(i) and (a)(ii) , and (c) removing water from said mixture to achieve a density of said mixture of at least 16 pounds per gallon.2. Method of wherein said at least one hydrogen donor comprises at least one polyol having from 2-6 carbon atoms and 2-6 hydroxyl groups or at least one organic acid.3. Method of wherein said calcium bromide in part (a)(i) is a saturated solution of calcium bromide in said water.4. Method of wherein said calcium bromide in part (a)(i) is solid calcium bromide.5. Method of wherein (1) step (a)(i) produces an aqueous solution of calcium bromide having a density of 13.9 to 14.5 pounds per gallon claim 1 , ( ...

Nanotube Mediation of Degradative Chemicals for Oil-Field Application

Discrete, individualized carbon nanotubes having targeted, or selective, oxidation levels and/or content on the interior and exterior of the tube walls can be used for nanotube-mediated controlled delivery of degradative molecules, such as oxidizers and enzymes, for oil-field drilling applications. A manufacturing process using minimal acid oxidation for carbon nanotubes may also be used which provides higher levels of oxidation compared to other known manufacturing processes.

BRINE RESISTANT SILICA SOL

A brine resistant silica sol is described and claimed. This brine resistant silica sol comprises an aqueous colloidal silica mixture that has been surface functionalized with at least one moiety selected from the group consisting of a monomeric hydrophilic organosilane, a mixture of monomeric hydrophilic organosilane(s) and monomeric hydrophobic organosilane(s), or a polysiloxane oligomer, wherein the surface functionalized brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter. 110.-. (canceled)11. A fluid comprising a brine resistant aqueous silica sol , wherein the brine resistant aqueous silica sol comprises silica particles surface functionalized with: a monomeric unit of glycidoxypropyltrimethoxysilane and', 'a monomeric unit selected from the group consisting of phenyltrimethoxysilane, methacryloxypropyltrimethoxysilane, isobutyltrimethoxysilane, vinyltrimethoxysilane, 2-(7-oxabicyclo[4.1.0]hept-3-yl)ethyltrimethoxysilane, and hexamethyldisiloxane;, 'a polysiloxane oligomer comprising'}wherein the silica particles have an average diameter of between about 1 nm and about 100 nm, and 1) API Brine by Visual Observation,', '2) Artificial Seawater by Visual Observation, and', '3) API Brine Resistance Test by use of a Turbidimeter,, 'wherein the brine resistant aqueous silica sol is stable to brine exposure under at least two of the tests selected from the group consisting of'}wherein under the test of API Brine by Visual Observation or Artificial Seawater by Visual Observation, a stable aqueous silica sol does not become visibly hazy and opaque or undergo gelation at 10 minutes or 24 hours after brine exposure, andwherein under the test of API Brine Resistance Test by use of a Turbidimeter, a stable aqueous silica sol does not have a change in turbidity of more than 100 Nephelometric Turbidity Units at 24 hours after brine exposure compared to ...

METHODS AND COMPOSITIONS OF DISPERSIBLE FERROELECTRIC NANOPARTICLES, AND USES THEREOF

Methods of forming dispersible ferroelectric nanoparticles, including polyether-ylated barium titanate nanoparticles. Uses of the dispersible ferroelectric nanoparticles, including as a ferroelectric tracer material, optionally for detecting a presence and/or measuring a distribution of an oil or a hydrocarbon in a subsurface formation and/or flowback fluid. Compositions and methods involving an oil or hydrocarbon recovery fluid and the dispersible ferroelectric nanoparticles for detecting a presence, measuring a distribution, or both of an oil or a hydrocarbon in a subsurface formation and/or flowback fluid. 1. A method of forming dispersible ferroelectric nanoparticles , the method comprisingadding a barium precursor and a titanium precursor to a polyether to form a mixture;basifying the mixture;heating the mixture; andforming dispersible ferroelectric nanoparticles, the dispersible ferroelectric nanoparticles comprising polyether-ylated barium titanate nanoparticles.2. The method of claim 1 , wherein the barium precursor comprises a barium acetylacetonate (acac) complex; and/or the titanium precursor comprises a titanium acetylacetonate (acac) complex.3. The method of claim 2 , wherein the barium acetylacetonate (acac) complex is Ba(acac).xHO; and/or the titanium acetylacetonate (acac) complex is (O-i-Pr)Ti(acac).4. The method of claim 1 , wherein the polyether is a low-molecular weight polyethylene glycol (PEG).5. The method of claim 4 , wherein the low-molecular weight PEG is PEG claim 4 , or PEG claim 4 , or PEG claim 4 , or PEG claim 4 , or PEG claim 4 , or PEG.6. The method of claim 5 , wherein the low-molecular weight PEG is or PEG.7. The method of claim 1 , wherein basifying the mixture comprises:adding a base and adjusting the pH of the mixture to >9, >13, or about 14; oradding a base and adjusting the pH of the mixture to about 9 to about 13, or to about 13 to about 14.8. The method of claim 7 , wherein the base is an alkali metal hydroxide.9. The method ...

USING BRINE RESISTANT SILICON DIOXIDE NANOPARTICLE DISPERSIONS TO IMPROVE OIL RECOVERY

This invention describes and claims the stimulation of several Wolfcamp and Bone Springs targeted wells in the northern Delaware Basin using fracturing treatments and a new method employing relatively small pre-pad pill volumes of Brine Resistant Silicon Dioxide Nanoparticle Dispersions ahead of each stage of treatment have been successfully performed. The invention includes a method of extending an oil and gas system ESRV comprising the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion (“BRINE RESISTANT SDND”) to conventional oil well treatment fluids. The invention also includes a method of increasing initial production rates of an oil well by over 20.0% as compared to wells either not treated with the BRINE RESISTANT SDND technology or treated by conventional nano-emulsion surfactants. The Method focuses on the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion to conventional oil well treatment fluids. 1. A Method of extending an oil and gas system effective stimulated reservoir volume comprising the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion to conventional oil well treatment fluids.2. A Method of increasing initial production rates of an oil well by over 20.0% as compared to wells either not treated with the Brine Resistant Silicon Dioxide Nanoparticle Dispersion technology or treated by conventional nano-emulsion surfactants comprising the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion to conventional oil well treatment fluids.3. The Method of in which the pill volume is typically from about 500 to about 1 claim 1 ,000 U.S. gallons of Brine Resistant Silicon Dioxide Nanoparticle Dispersion per about 3 claim 1 ,000 to about 6 claim 1 ,000 barrels (U.S.) of frac stage fluid.4. The Method of in which the pill volume is typically from about 500 to about 1 claim 2 ,000 U.S. gallons of Brine Resistant Silicon Dioxide Nanoparticle Dispersion per about 3 claim 2 , ...

Sandstone stimulation using in-situ mud acid generation

A method for stimulating production of hydrocarbons from a sandstone formation includes the steps of injecting a stimulation fluid formed from a hydrofluoric acid generating precursor and an oxidizing agent, an ammonium containing compound, and a nitrite containing compound into the sandstone formation, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction and generate heat and nitrogen gas. Upon generation of heat and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid in-situ to dissolve silica and silicate minerals and stimulate the sandstone formation. A treatment fluid for use in stimulating sandstone formations includes the stimulation fluid, the ammonium containing compound, and the nitrite containing compound.

HIGH DENSITY BRINES

A method of treating a wellbore comprises injecting into the wellbore a high density brine comprising water; an inorganic salt; and a polyol having at least four hydroxyl groups per molecule, the polyol being present in an amount effective to cause the high density brine to have a density of about 14.2 pounds per gallon to about 22 pounds per gallon; and to suppress the true crystallization point of the brine to about −70° F. to about 70° F. at a pressure of about 0 to about 20000 psi determined according to API 13J. 1. A method of treating a wellbore , the method comprising injecting into the wellbore a high density brine comprising:water;an inorganic salt; anda polyol having at least four hydroxyl groups per molecule, the polyol being present in an amount effective to cause the high density to have a density of about 12.5 pounds per gallon to about 22 pounds per gallon; and to suppress the true crystallization point of the brine to about −70° C. to about 70° C. at a pressure of about 0 to about 20,000 psi determined according to API 13J.2. The method of claim 1 , wherein the polyol comprises glucose claim 1 , dextrose claim 1 , fructose claim 1 , maltose claim 1 , sorbitol claim 1 , or a combination comprising at least one of the foregoing.3. The method of claim 1 , wherein the polyol comprises sorbitol.4. The method of claim 1 , wherein the polyol is present in an amount of about 10 wt. % to about 50 wt. % claim 1 , based on the total weight of the high density brine.5. The method of claim 1 , further comprising optimizing the amount of the polyol by preparing two or more brine samples having a target brine density from water claim 1 , the inorganic salt claim 1 , and the polyol having at least four hydroxyl groups per molecule claim 1 , the two or more brine samples having increasing amounts of the polyol; measuring a rheological property and the true crystallization temperature at a predetermined pressure for each of the brine samples; establishing a ...

Self Propping Surfactant For Well Stimulation

A method of fracturing a subterranean formation may comprise: pumping a fracturing fluid into the subterranean formation, through a wellbore, at or above a fracture gradient of the subterranean formation, wherein the fracturing fluid comprises halloysite nanotubes. 1. A method of fracturing a subterranean formation , the method comprising:pumping a fracturing fluid into the subterranean formation, through a wellbore, at or above a fracture gradient of the subterranean formation, wherein the fracturing fluid comprises halloysite nanotubes, wherein in the fracturing fluid is a pad fluid or a pre-pad fluid.2. (canceled)3. The method of wherein the fracturing fluid comprises an aqueous fluid.4. The method of wherein the halloysite nanotubes further comprise a cargo.5. The method of wherein the cargo comprises at least one additive selected from the group consisting of a scale inhibitor claim 4 , a clay stabilizer claim 4 , a biocide claim 4 , a paraffin inhibitor claim 4 , a breaker claim 4 , a crosslinking agent claim 4 , a surfactant claim 4 , an in-situ acid generator claim 4 , a chelating agent claim 4 , a tracer claim 4 , a tagging agent claim 4 , and combinations thereof.6. The method of wherein the cargo comprises a surfactant.7. The method of wherein the halloysite nanotubes are present in the fracturing fluid in an amount ranging from about 0.05 pounds to about 0.5 pounds per gallon of the fracturing fluid.8. The method of further comprising pumping a proppant laden fluid into the subterranean formation.9. The method of further comprising depositing the halloysite nanotubes into one or more fractures in the subterranean formation such that the halloysite nanotubes form a partial proppant pack in the one or more fractures claim 1 , wherein the halloysite nanotubes comprise an anionic surfactant adsorbed in an interior of the halloysite nanotubes claim 1 , wherein the fractures are nano-fractures and/or micro-fractures claim 1 , wherein the fracturing fluid is a ...

DELAYED CROSSLINKING COMPOSITION OR REACTION PRODUCT THEREOF FOR TREATMENT OF A SUBTERRANEAN FORMATION

Various embodiments disclosed relate to delayed crosslinking compositions or reaction products thereof for treatment of a subterranean formation. In various embodiments, the present invention provides a method of treating a subterranean formation including placing in a subterranean formation a subterranean treatment composition including at least one of a delayed crosslinking composition and a reaction product thereof. The delayed crosslinking composition includes a crosslinker including a functionality chosen from —B(OH), —B(OH), —O—B(OH)—O—B(OH)—O—, —O—B(OH)—O—B(OH)(—O—), a salt thereof, an ester thereof, and a combination thereof. The delayed crosslinking composition also includes a glycol including at least one of a 1,2-diol and a 1,3-diol. 1. A method of treating a subterranean formation , the method comprising: [{'sub': 2', '2', '2, 'sup': −', '−, 'a crosslinker comprising a functionality chosen from —B(OH), —B(OH), —O—B(OH)—O—B(OH)—O—, —O—B(OH)—O—B(OH)(—O—), a salt thereof, an ester thereof, and a combination thereof; and'}, 'a glycol comprising at least one of a 1,2-diol and a 1,3-diol., 'placing in the subterranean formation a subterranean treatment composition comprising at least one of a delayed crosslinking composition and a reaction product thereof, the delayed crosslinking composition comprising'}2. The method of claim 1 , further comprising allowing the crosslinker and the glycol to react to provide the reaction product of the delayed crosslinking composition.3. The method of claim 1 , further comprising fracturing the subterranean formation.4. The method of claim 1 , wherein the subterranean treatment composition is preheated prior to placing the subterranean treatment composition in the subterranean formation.5. The method of claim 1 , wherein the subterranean treatment composition further comprises a carrier fluid.6. The method of claim 5 , wherein the carrier fluid comprises water.7. The method of claim 1 , wherein the subterranean treatment ...

Hydrocarbon formation treatment micellar solutions

A hydrocarbon formation treatment micellar solution fluid and its use in treating underperforming hydrocarbon formations is described and claimed. A hydrocarbon formation treatment micellar solution fluid wherein the micellar solution fluid comprises water, a non-terpene oil-based moiety, a brine resistant aqueous colloidal silica sol; and optionally a terpene or a terpenoid, wherein the brine resistant aqueous colloidal silica sol has silica particles with a surface that is functionalized with at least one moiety selected from the group consisting of a hydrophilic organosilane, a mixture of hydrophilic and hydrophobic organosilanes, or a polysiloxane oligomer, wherein the brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter, and wherein, when a terpene or terpenoid is present, the ratio of total water to terpene or terpenoid is at least about 15 to 1.

CHLORINE DIOXIDE PRECURSOR AND METHODS OF USING SAME

According to one aspect of the invention, a method of converting an oxy halide salt into a halide dioxide in a reaction zone under certain conditions is provided. More specifically, the method includes generating chlorine dioxide from a stable composition comprising an oxy halide salt by introducing said composition to a reducing agent and minimum temperature within the reaction zone. According to another aspect of the invention, a composition for a stable chlorine dioxide precursor comprising an oxy halide salt is provided. 146-. (canceled)47. A chlorine dioxide precursor composition comprising an aqueous solution of 5% to 40% by weight of a chlorate salt and 5% to 20% by weight of a weak acid , wherein the composition is stable at a temperature below about 90° F. and wherein the composition reacts to form chlorine dioxide when exposed to a reducing agent in combination with a temperature of about 110° F. or greater.48. The composition of claim 47 , wherein the chlorate salt comprises sodium chlorate and the weak acid comprises citric acid.49. The composition of claim 48 , wherein the composition does not comprise a strong acid.50. The composition of claim 48 , wherein the composition further comprises a strong acid at a concentration of about 0.1% to 2% by weight.51. The composition of claim 50 , wherein the strong acid is hydrochloric acid claim 50 , hydrofluoric acid claim 50 , or a mixture thereof.52. The composition of claim 47 , wherein the reducing agent is iron sulfide.53. A well fluid to which the precursor composition of is added at a concentration from about 100 to 10 claim 47 ,000 mg/l.54. A chlorine dioxide precursor composition comprising an aqueous solution of sodium chlorate at 5% to 40% by weight and citric acid at 5% to 20% by weight claim 47 , wherein the composition is stable at a temperature below about 90° F. and wherein the composition reacts to form chlorine dioxide when exposed to iron sulfide in combination with a temperature of about 115° ...

Method of monitoring a fluid, use of a tracer, and tracer composition

A method of monitoring a fluid is described comprising: introducing a tracer into the fluid and analysing the fluid to determine if the tracer is present in the fluid; characterised in that the tracer comprises luminescent carbon-based nanoparticles exhibiting a peak luminescence intensity at an emission wavelength of at least 500 nm. The method is in particular a method of monitoring a parameter of a hydrocarbon well, pipeline or formation. A use of a tracer and a tracer composition comprising carbon-based nanoparticles exhibiting a peak luminescence intensity at an emission wavelength of at least 500 nm are also described.

FLOODING OPERATIONS EMPLOYING CHLORINE DIOXIDE

A method includes introducing a treatment fluid including a first polymer gel into a subterranean formation to generate a production fluid having an aqueous portion and a hydrocarbon portion, treating the aqueous portion of the production fluid with chlorine dioxide to separate additional hydrocarbons from the aqueous portion, and adjusting the viscosity of the treated aqueous portion prior to introducing the treated aqueous portion back into the subterranean formation. 1. A composition comprising(i) an aqueous base fluid that contains a residual concentration of 6 ppm to 20 ppm chlorine dioxide, wherein the aqueous base fluid comprises a production fluid that has been treated with chlorine dioxide, or an aqueous portion of a production fluid that has been treated with chlorine dioxide, and 'wherein the composition is a gel.', '(ii) a water soluble polymer,'}2. The composition of claim 1 , wherein the production fluid is obtained from a well that has been subjected to polymer flooding.3. A composition comprising(i) an aqueous base fluid that contains a residual concentration of at least 6 ppm chlorine dioxide, wherein the aqueous base fluid comprises a production fluid that has been treated with chlorine dioxide, or an aqueous portion of a production fluid that has been treated with chlorine dioxide, and 'wherein the composition has a viscosity that is at least about 140% of the viscosity of a control composition formed by adding a corresponding water-soluble polymer to a control aqueous base fluid that comprises a corresponding production fluid, or aqueous portion thereof, that has not been treated with chlorine dioxide.', '(ii) a water soluble polymer,'}4. The composition of claim 3 , wherein the composition has a viscosity that is at least 160% of the viscosity of a control composition formed by adding a corresponding water-soluble polymer to a control aqueous base fluid that comprises a corresponding production fluid claim 3 , or aqueous portion thereof claim 3 ...

Formation Stabilizing Fracturing Fluid and Method of Use

A fracturing fluid comprises an aqueous base fluid and a cationic polymer combined with a salt. The fracturing fluid may be used to fracture a subterranean formation. The cationic polymer in combination with a salt provides for reduced clay swelling, while maintaining the granularity and porosity of the formation, which thereby promotes the flow of hydrocarbons from the formation. 1. A formation fracturing fluid comprising:an aqueous base fluid; anda cationic polymer combined with a salt.2. The fluid of claim 1 , wherein the salt is selected from potassium chloride claim 1 , calcium chloride claim 1 , sodium chloride claim 1 , ammonium chloride claim 1 , or combinations thereof.3. The fluid of further comprising about 0.001 to about 10 wt. % salt.4. The fluid of further comprising about 1.4 wt. % salt.5. The fluid of further comprising about 0.001 to about 1 wt. % cationic polymer.6. The fluid of further comprising about 0.6 wt. % cationic polymer.7. The fluid of claim 1 , wherein the cationic polymer comprises cationic hydroxyethyl cellulose.8. The fluid of claim 1 , wherein the cationic polymer comprises a combination of two or more cationic functional groups.9. The fluid of claim 8 , wherein the two or more cationic functional groups are selected from at least one of trimethylammonium chloride claim 8 , and quaternized vinylimidazole.10. The fluid of claim 1 , wherein the cationic polymer is water soluble.11. The fluid of claim 1 , wherein the cationic polymer is selected from quaternary hydroxyl alkyl cellulose claim 1 , cationic polygalactomannan gum claim 1 , and amine treated cationic starches.12. The fluid of claim 1 , wherein the cationic polymer includes at least one of guar claim 1 , xanthan claim 1 , synthetic polyacrylamide-based cationic polymers claim 1 , and combinations thereof.13. The fluid of claim 1 , wherein the molecular weight of the cationic polymer ranges from about 500 claim 1 ,000 to about 2.5 million.14. The fluid of further comprising at ...

BRINE RESISTANT SILICA SOL

A brine resistant silica sol is described and claimed. This brine resistant silica sol comprises an aqueous colloidal silica mixture that has been surface functionalized with at least one moiety selected from the group consisting of a monomeric hydrophilic organosilane, a mixture of monomeric hydrophilic organosilane(s) and monomeric hydrophobic organosilane(s), or a polysiloxane oligomer, wherein the surface functionalized brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter. 110.-. (canceled)11. A method of recovering hydrocarbon from subterranean formation , comprising introducing to the subterranean formation a fluid comprising a brine resistant aqueous silica sol , wherein the brine resistant aqueous silica sol comprises an aqueous colloidal silica mixture surface functionalized with:a polysiloxane oligomer comprising a monomeric unit of glycidoxypropyltrimethoxysilane anda monomeric unit selected from the group consisting of phenyltrimethoxysilane, methacryloxypropyltrimethoxysilane, isobutyltrimethoxysilane, vinyltrimethoxysilane, trimethoxy[2-(7-oxabicyclo[4.1.0]hept-3-yl)ethyltrimethoxysilane, and hexamethyldisiloxane; or trimethoxy[2-(7-oxabicyclo[4.1.0]hept-3-yl)ethyltrimethoxysilane,wherein the brine resistant aqueous silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter,wherein the monomeric unit of glycidoxypropyltrimethoxysilane and monomeric unit of phenyltrimethoxysilane,exhibit a critical surface tension in the range of from about 40 mN/m to about 50 mN/m; andwherein the methacryloxypropyl trimethoxysilane, isobutyl trimethoxy silane, vinyltrimethoxysilane, trimethoxy[2-(7-oxabicyclo[4.1.0]hept-3-yl)ethyltrimethoxysilane and hexamethyldisiloxane; exhibit a critical surface tension in the range of from about 15 mN/m to about 39.5 mN/m.12. The Method ...

Ves fluids having improved rheology at high temperature and high salinity

A viscoelastic surfactant treatment fluid comprises an aqueous base fluid an inorganic salt, the inorganic salt being present in an amount of greater than about 5 wt. % based on the total weight of the treatment fluid; a viscoelastic surfactant gelling agent effective to gel the aqueous base fluid by forming a plurality of micelles; and a cationic polymer additive associated with the micelles via electrostatic interactions.

HYDROGEN PEROXIDE STEAM GENERATOR FOR OILFIELD APPLICATIONS

Exemplary apparatuses, systems, and methods are provided to produce steam for use in oil field applications. In some embodiments, a catalyst is provided that includes a plurality of ceramic bodies impregnated with an alkaline-promoted manganese oxide. In other embodiments, the catalyst includes a plurality of bodies formed of an active ceramic oxide in a consolidated state without an underlying ceramic body. The bodies are contacted with a liquid hydrogen peroxide having a strength, in one embodiment, between about 30 and about 70 weight percent to produce steam. The steam is directed to an oil field application, such as, but not limited to, a geologic formation to increase oil production from the geologic formation, an applicator to clean oilfield equipment, a heat exchanger to heat hydrogen peroxide, or a heat exchanger to heat living quarters. 1. A method of manufacturing an apparatus for producing steam generated primarily by decomposition of a liquid hydrogen peroxide solution , the method comprising: providing one or more ceramic bodies in a catalytic solution,', 'drying the one or more ceramic bodies, and', 'calcining the one or more ceramic bodies;, 'providing a catalyst for decomposing the liquid hydrogen peroxide solution to produce the steam, wherein the steam is produced primarily by the decomposition of the liquid hydrogen peroxide solution, wherein providing a catalyst comprisesproviding a liquid hydrogen peroxide source;providing a first fluid communication pathway between the liquid hydrogen peroxide source and the catalyst; andproviding a second fluid communication pathway to conduct generated steam away from the catalyst.2. The method of claim 1 , wherein drying the one or more ceramic bodies comprises placing the one or more ceramic bodies in an oven above about 150 degrees Celsius.3. The method of claim 1 , wherein calcining the one or more ceramic bodies comprises heating the one or more ceramic bodies in an oven at between about 200 degrees ...

ENGINEERING FORMATION WETTABILITY CHARACTERISTICS

Methods and systems are provided to enhance recovery of hydrocarbons from a formation by altering wettability at a surface of the formation towards more water-wet. One method includes: providing a formation; providing an aqueous stream for injecting into the formation; adding a reducing agent to the aqueous stream; and injecting the aqueous stream with the reducing agent into the formation to alter a surface charge of the surface of the formation to become more water-wet to enhance recovery of hydrocarbons from the formation. The reducing agent is responsive to characteristics of the formation, characteristics of brine of the formation, and characteristics of hydrocarbons of the formation. Also provided is a method to select a brine composition to be injected into a formation to alter wettability at a surface of the formation towards more water-wet to enhance recovery of hydrocarbons from the formation. 1. A method to select a brine composition to be injected into a formation to alter wettability at a surface of the formation to enhance recovery of hydrocarbons from the formation , the method comprising:providing a plurality of substrates representative of the formation;providing a plurality of brine compositions;providing a plurality of reducing agents characterized as yielding oxyanions when added to the aqueous stream; andselecting a brine composition with at least one reducing agent based on interactions between the plurality of substrates, the plurality of brine compositions, and the plurality of reducing agents.2. The method of claim 1 , wherein the at least one reducing agent is selected from a salt of carbonate claim 1 , nitrate claim 1 , bisulfite claim 1 , meta bisulfite claim 1 , dithionite claim 1 , sulfate claim 1 , metaborate claim 1 , or any combination thereof.3. The method of claim 1 , further comprising:conducting an uncertainty analysis using various combinations of the plurality of the substrates, the plurality of the brine compositions, and the ...

MITIGATION OF CONDENSATE AND WATER BANKING USING FUNCTIONALIZED NANOPARTICLES

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 or water banking in the vicinity of a wellbore for a gas condensate reservoir , the method comprising a step of contacting a rock formation in the vicinity of a wellbore for a gas condensate reservoir with a particle suspension ,wherein the particle suspension comprises particles having a surface free energy lower than the rock formation before the contacting step, andwherein the particles are functionalized with a first chemical moiety (R) that reacts with a second chemical moiety (R′) on a surface of the rock formation to form at least one of a covalent bond, an electrostatic bond, or a Van der Waals bond, thereby reducing the surface energy of the rock formation.2. A method for mitigating condensate or water 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 particle suspension ,{'sup': '2', 'wherein the particle suspension comprises particles with a surface free energy less than 50 mJ/mwhich are functionalized with a first chemical moiety (R) that reacts with a second chemical moiety (R′) on a surface of the rock formation to form at least one of a covalent bond, an electrostatic bond, or a Van der Waals bond.'}3. The method of claim 1 , wherein the first chemical moiety (R) is selected from the group consisting of a silyl ether group claim 1 , an amine group claim 1 , an aromatic amine claim 1 , an ammonium group claim 1 , a quaternary amine group claim 1 , a polyamine claim 1 , a silanol claim 1 , an isocynate claim 1 , an epoxide claim 1 , a hydroxyl claim 1 , a phenol claim 1 , a halogen claim 1 , halosilanes claim 1 , a carboxyl group ...

Compositions And Methods For Treating Subterranean Formations

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. 1. An aqueous composition comprising:at least one carrier fluid;at least one populations of positively charged nanoparticles; andat least one populations of negatively charged nanoparticles,wherein the aqueous composition is not a drilling fluid, and is free of cement and foaming agents.2. The aqueous composition of claim 1 , further comprising:at least two populations of positively charged nanoparticles, wherein the at least two populations of positively charged nanoparticles have different sizes and/or are different materials; and/orat least two populations of negatively charged nanoparticles, wherein the at least two populations of negatively charged nanoparticles have different sizes and/or are different materials.3. The aqueous composition of claim 1 , further comprising:a detergent;a surface-active agent comprising a polymer or a surfactant;an alcohol; anda salt.4. The aqueous composition of claim 3 , wherein the surface-active agent is selected from the group consisting of polyvinylpyrrolidone claim 3 , fatty acid salts claim 3 , sulfates claim 3 , sulfonates claim 3 , phosphoric surfactants claim 3 , alkyl-ammoniums claim 3 , alkyl-amines claim 3 , fatty amine surfactants ...

INTERFACIAL TENSION REDUCTION AND WETTABILITY ALTERATION USING METAL OXIDE NANOPARTICLES TO REDUCE CONDENSATE BANKING

Treating a gas condensate reservoir having a porous formation material includes introducing a formation treatment fluid to the gas condensate reservoir and maintaining the formation treatment fluid in the gas condensate reservoir. The formation treatment fluid is a dispersion including metal oxide nanoparticles, and the gas condensate reservoir includes discrete portions of condensate in contact with the porous formation material. 1. A method of treating a gas condensate reservoir comprising a porous formation material , the method comprising:introducing a formation treatment fluid to the gas condensate reservoir, wherein the formation treatment fluid is a dispersion comprising metal oxide nanoparticles, and the gas condensate reservoir comprises discrete portions of condensate in contact with the porous formation material; andmaintaining the formation treatment fluid in the gas condensate reservoir, such that the discrete portions of condensate are displaced from the porous formation material to yield free condensate in the gas condensate reservoir.2. The method of claim 1 , wherein the formation treatment fluid is maintained in the gas condensate reservoir for sufficient time for the formation treatment fluid to form a wedge film between the discrete portions of condensate and the porous formation material.3. The method of claim 1 , further comprising removing the free condensate from the gas condensate reservoir.4. The method of claim 1 , wherein the metal oxide nanoparticles have a maximum dimension in a range of 1 nanometer (nm) to 100 nm.5. The method of claim 1 , wherein a concentration of the metal oxide nanoparticles in the formation treatment fluid is up to 1 weight percent (wt %).6. The method of claim 1 , wherein a particle volume fraction of the metal oxide nanoparticles in the formation treatment fluid is up to 0.25.7. The method of claim 1 , wherein the metal oxide nanoparticles comprise an oxide of silicon claim 1 , aluminum claim 1 , zinc claim 1 , ...

THERMALLY-STABLE, NON-PRECIPITATING, HIGH-DENISTY WELLBORE FLUIDS

A wellbore treatment fluid comprising: a base fluid; and a water-soluble salt, the salt comprising: a cation; and an anion, wherein the anion is selected from phosphotungstate, silicotungstate, phosphomolybdate, and silicomolybdate. The treatment fluid can have a density greater than or equal to 13 pounds per gallon. A method of treating a portion of a subterranean formation penetrated by a well comprising: introducing the treatment fluid into the well. 1. A method of treating a portion of a subterranean formation penetrated by a well comprising: (A) a base fluid; and', (i) a cation; and', '(ii) an anion, wherein the anion is selected from phosphotungstate, silicotungstate, phosphomolybdate, and silicomolybdate., '(B) a water-soluble salt, the salt comprising], 'introducing a treatment fluid into the well, wherein the treatment fluid comprises2. The method according to claim 1 , wherein the base fluid comprises water.3. The method according to claim 2 , wherein the water is selected from the group consisting of freshwater claim 2 , brackish water claim 2 , saltwater claim 2 , and any combination thereof.4. The method according to claim 1 , wherein the treatment fluid has a density greater than or equal to 13 pounds per gallon.5. The method according to claim 1 , wherein the treatment fluid is a drilling fluid claim 1 , a drill-in fluid claim 1 , a packer fluid claim 1 , a completion fluid claim 1 , a spacer fluid claim 1 , a work-over fluid claim 1 , or an insulating fluid.6. The method according to claim 1 , wherein the cation is organic or inorganic.7. The method according to claim 1 , wherein the cation is selected from ammonium claim 1 , phosphonium claim 1 , quaternary amines claim 1 , poly-quaternary amines claim 1 , alkaline earth metals claim 1 , transition metals claim 1 , and rare earth elements.8. The method according to claim 1 , wherein the type of salt and the concentration of the salt are selected claim 1 , based on the mass of the salt and the ...

Method of treating a high-temperature well with a fluid containing a viscosifier and a stabilizer package

A treatment fluid for treating a portion of a high-temperature subterranean formation comprises: a base fluid, wherein the base fluid comprises water; a viscosifier, wherein the viscosifier is a polymer, and wherein the viscosifier is thermally stable up to a temperature of 325° F.; and a stabilizer package, wherein the stabilizer package: (A) comprises a first stabilizer and a second stabilizer, wherein the first stabilizer is an oxygen scavenger and the second stabilizer is a pH adjustor; and (B) is capable of increasing the thermal stability of the viscosifier to a temperature greater than 350° F., wherein the portion of the subterranean formation has a bottomhole temperature greater than 350° F. A method of treating a high-temperature subterranean formation comprises introducing the treatment fluid into the portion of the subterranean formation.

ADDITIVES TO MINIMIZE VISCOSITY REDUCTION FOR GUAR/BORATE SYSTEM UNDER HIGH PRESSURE

A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer. 1. A composition for forming a pressure-tolerant dual-crosslinker gel in a fracturing fluid , the composition comprises:a polymer;a boron-containing crosslinker; and 'wherein the boron-containing crosslinker and the transition metal oxide additive are operable to crosslink the polymer to form the pressure-tolerant dual-crosslinker gel.', 'a transition metal oxide additive,'}2. The composition of claim 1 , wherein the polymer is present in a concentration of between 12 pptg and 100 pptg.3. The composition of claim 1 , wherein the polymer is selected from the group consisting of guar claim 1 , guar-derivatives claim 1 , polyvinyl alcohols claim 1 , mannose claim 1 , mannose-containing compounds claim 1 , and combinations of the same.4. The composition of claim 1 , wherein the boron-containing crosslinker is present at a concentration between 0.002% by weight and 2% by weight of the fracturing fluid.5. The composition of claim 1 , wherein the boron-containing crosslinker is selected from the group consisting of borate salts claim 1 , boric acid claim 1 , and combinations of the same.6. The composition of claim 5 , wherein the boron-containing crosslinker comprises a borate salt selected from the group consisting of sodium borate claim 5 , sodium pentaborate claim 5 , sodium tetraborate claim 5 , calcium borate claim 5 , magnesium borate claim 5 , and combinations of the same.7. The composition of claim 1 , wherein the transition metal oxide additive is present at a concentration between 0.0002% by weight and 2% by weight of the fracturing fluid.8. The composition of claim 1 , wherein the ...

POLYMER COMPOSITIONS

A composition contains an incompletely hydrated water soluble polymer suspended in a liquid medium. 161-. (canceled)62. A composition comprising , based on 100 parts by weight of the composition:water in an amount greater than or equal to about 10 pbw;at least one water-soluble polymer selected from non-derivatized guar polymers, derivatized guar polymers and mixtures thereof, in an amount greater than 2.5 to about 20 pbw;at least one suspending agent in an amount from about 0.1 to about 5 pbw and effective to impart shear thinning properties and yield strength to the composition;at least one surfactant in an amount from about 2 to about 40 pbw; andat least one hydration inhibitor selected from water-soluble non-surfactant salts in an amount from about 5 to about 60 pbw and water dispersible organic solvents in an amount from about 2 to about 30 pbw,wherein the combined amount of surfactant, water-soluble non-surfactant salt and water dispersible organic solvent is effective to inhibit hydration of the water soluble polymer in the water.63. The composition of wherein the suspending agent is selected from silica claim 62 , inorganic colloidal or colloid-forming particles claim 62 , rheology modifier polymers claim 62 , and mixtures thereof.64. The composition of wherein the suspending agent is fumed silica claim 63 , clay claim 63 , or a mixture thereof.65. The composition of wherein the suspending agent is Xanthan gum.66. The composition of wherein the derivatized guar polymer is selected from carboxymethyl guar claim 62 , carboxymethylhydroxypropyl guar claim 62 , cationic hydroxpropyl guar claim 62 , hydroxyethyl guar claim 62 , hydroxypropyl guar claim 62 , hydroxybutyl guar claim 62 , higher hydroxylalkyl guars claim 62 , carboxymethyl guar claim 62 , carboxylpropyl guar claim 62 , carboxybutyl guar claim 62 , and carboxyalkyl guars.67. The composition of claim 62 , wherein the water soluble polymer has a weight average molecular weight of from about 100 claim ...

ADDITIVES TO MINIMIZE VISCOSITY REDUCTION FOR GUAR/BORATE SYSTEM UNDER HIGH PRESSURE

A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer. 2. The method of claim 1 , wherein the polymer is present in a concentration of between 12 pptg and 100 pptg.3. The method of claim 1 , wherein the polymer is selected from the group consisting of guar claim 1 , guar-derivatives claim 1 , polyvinyl alcohols claim 1 , mannose claim 1 , mannose-containing compounds claim 1 , and combinations of the same.4. The method of claim 1 , wherein the boron-containing crosslinker is present at a concentration between 0.002% by weight and 2% by weight of the fracturing fluid.5. The method of claim 1 , wherein the boron-containing crosslinker comprises a borate salt selected from the group consisting of sodium borate claim 1 , sodium pentaborate claim 1 , sodium tetraborate claim 1 , calcium borate claim 1 , magnesium borate claim 1 , and combinations of the same.6. The method of claim 1 , wherein the transition metal oxide additive is present at a concentration between 0.0002% by weight and 2% by weight of the fracturing fluid.7. The method of claim 1 , wherein the transition metal oxide additive comprises a transition metal oxide nanoparticle selected from the group consisting of zirconium oxide nanoparticles claim 1 , titanium oxide nanoparticles claim 1 , cerium oxide nanoparticles claim 1 , and combinations of the same.8. The method of claim 1 , wherein the polymer comprises guar claim 1 , the boron-containing crosslinker comprises sodium borate and the transition metal oxide additive comprises CeOnanoparticles.9. The method of claim 1 , wherein a diameter of the transition metal oxide additive is in the range between 5 nm and 100 nm.10. The method of ...

Aqueous retarded acid solution and methods for use thereof

Methods include combining an amount of water and an acid retarding agent (RA), where the amount of water is present in an amount up to about 5 times the mass of the RA, inclusive, and wherein the RA includes at least one salt compound. An amount of acid is dissolved in the combined amount of water and RA to form a composition, where the amount of acid is a molar ratio of acid:RA of between 4.0 and 0.2, inclusive, and wherein the amount of acid is up to about 36% by weight of total weight of the composition. The composition is injected into a wellbore penetrating a subterranean formation at a pressure, which may be less than the fracture initiation pressure of the subterranean formation in some cases, while in other cases equal to or greater than the fracture initiation pressure.

NANOTUBE MEDIATION OF DEGRADATIVE CHEMICALS FOR OIL-FIELD APPLICATIONS

Discrete, individualized carbon nanotubes having targeted, or selective, oxidation levels and/or content on the interior and exterior of the tube walls can be used for nanotube-mediated controlled delivery of degradative molecules, such as oxidizers and enzymes, for oil-field drilling applications. A manufacturing process using minimal acid oxidation for carbon nanotubes may also be used which provides higher levels of oxidation compared to other known manufacturing processes. 1. A composition useful for treating hydraulic fracturing fluids comprising a plurality of discrete carbon nanotubes , wherein the discrete carbon nanotubes comprise an interior and exterior surface , the interior surface comprising an interior surface oxidized species content and the exterior surface comprising an exterior surface oxidized species content , and at least one degradative molecule that is attached on the interior or exterior surface of the plurality of discrete carbon nanotubes.2. The composition of claim 1 , wherein the hydraulic fracturing fluid comprises water.3. The composition of claim 1 , wherein the degradative molecule comprises at least one enzyme.4. The composition of claim 3 , wherein the enzyme is attached via Van der Waals claim 3 , ionic claim 3 , covalent bonding claim 3 , or a combination thereof.5. The composition of claim 1 , wherein the degradative molecule comprises an oxidizer.6. The composition of claim 5 , wherein the oxidizer is attached via Van der Waals claim 5 , ionic claim 5 , covalent bonding claim 5 , or combinations thereof.7. The composition of claim 3 , wherein the enzyme is selected from the group consisting of hemicellulases claim 3 , encapsulated enzyme breakers claim 3 , GBW-12CD claim 3 , LEB-H claim 3 , gammanase claim 3 , endo-mannanase claim 3 , P-mannanase claim 3 , pectinase claim 3 , and Econo Gelbreak-EL2X claim 3 , and mixtures thereof.8. The composition of claim 1 , wherein the degradative molecule comprises one or more types of ...

Synthetic Acid Compositions Alternatives to Conventional Acids in the Oil and Gas Industry

A synthetic acid composition for use in oil industry activities, said composition comprising: urea and hydrogen chloride in a molar ratio of not less than 0.1:1; and an alcohol or derivative thereof optionally, it may further comprise a phosphonic acid derivative. 128-. (canceled)29. A synthetic acid composition for use in oil industry activities , said composition comprising:urea and hydrogen chloride in a molar ratio of not less than 0.1:1;optionally, a phosphonic acid derivative; andan alcohol or derivative thereof.301. The synthetic acid composition according to claim , wherein the urea and hydrogen chloride are in a molar ratio of not less than 0.5:1.311. The synthetic acid composition according to claim , wherein the urea and hydrogen chloride are in a molar ratio of not less than 0.8:1.321. The synthetic acid composition according to claim , wherein the phosphonic acid derivative is aminoalkylphosphonic salt.331. The synthetic acid composition according to claim , wherein the phosphonic acid derivative is amino tris methylene phosphonic acid.341. The synthetic acid composition according to claim , wherein the alcohol or derivative thereof is an alkynyl alcohol or derivative thereof.351. The synthetic acid composition according to claim , wherein the alcohol or derivative thereof is an alkynyl alcohol or derivative thereof is propargyl alcohol or a derivative thereof.361. The synthetic acid composition according to claim , wherein the phosphonic acid derivative is present in a concentration ranging from 0.25 to 1.0% w/w.371. The synthetic acid composition according to claim , wherein the phosphonic acid derivative is present in a concentration of 0.5% w/w.381. The synthetic acid composition according to claim , wherein the alcohol is an alkynyl alcohol or derivative thereof present in a concentration ranging from 0.01 to 0.25% w/w.391. The synthetic acid composition according to claim , wherein the alcohol is an alkynyl alcohol or derivative thereof present in ...

Hydrocarbon formation treatment micellar solutions

A hydrocarbon formation treatment micellar solution fluid and its use in treating underperforming hydrocarbon formations is described and claimed. A hydrocarbon formation treatment micellar solution fluid wherein the micellar solution fluid comprises water, a non-terpene oil-based moiety, a brine resistant aqueous colloidal silica sol; and optionally a terpene or a terpenoid, wherein the brine resistant aqueous colloidal silica sol has silica particles with a surface that is functionalized with at least one moiety selected from the group consisting of a hydrophilic organosilane, a mixture of hydrophilic and hydrophobic organosilanes, or a polysiloxane oligomer, wherein the brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter, and wherein, when a terpene or terpenoid is present, the ratio of total water to terpene or terpenoid is at least about 15 to 1.

SELECTION OF OPTIMAL SURFACTANT BLENDS FOR WATERFLOOD ENHANCEMENT

A method of providing an optimal surfactant blend to improve waterflood efficiency comprises selecting candidate surfactant blends based on one or more of the following: a reservoir condition; information of a crude oil; information of an injection fluid; or information of a formation fluid, each candidate surfactant blends comprising at least two surfactants, one surfactant having a higher relative affinity for the crude oil than for the injection fluid and at least one surfactant having a higher affinity for the injection fluid than for the crude oil; evaluating phase behavior of the candidate surfactant blends to select surfactant blends that form a Winsor III system with the crude oil and the injection fluid at a reservoir temperature; and evaluating the selected surfactant blends in a porous media to select an optimal surfactant blend which achieves at least an additional 10% crude oil recovery after waterflood. 1. A method of providing an optimal surfactant blend to improve waterflood efficiency , the method comprising:selecting candidate surfactant blends based on one or more of the following: a reservoir condition; information of a crude oil; information of an injection fluid; or information of a formation fluid, each candidate surfactant blends comprising at least a first surfactant which has a higher relative affinity for the crude oil than for the injection fluid and at least a second surfactant which has a higher relative affinity for the injection fluid than for the crude oil;evaluating phase behavior of the candidate surfactant blends to select surfactant blends that form a Winsor III system with the crude oil and the injection fluid at a reservoir temperature; andevaluating the selected surfactant blends in a porous media to select an optimal surfactant blend which achieves at least an additional 10% crude oil recovery after waterflood.2. The method of claim 1 , further comprising simulating reservoir waterflood with the optimal surfactant blend.3. ...

Supercritical Carbon Dioxide Emulsified Acid

One aspect of an emulsion includes an internal phase including acid, an external phase including supercritical carbon dioxide, and multiple nanoparticles to stabilize the internal phase and the external phase. The acid can include hydrochloric acid. The hydrochloric acid can include 15% hydrochloric acid. The nanoparticles can include hydrophobic nanoparticles. A concentration of nanoparticles in the emulsion can be at least 0.1% by weight. The emulsion can include a corrosion inhibitor. A concentration of the corrosion inhibitor can be in a range of between 0.25% and 0.6% by volume. A ratio of a concentration of the acid to a concentration of the supercritical carbon dioxide can be in a range between 30% and 70%. 1. An emulsion comprising:an internal phase comprising acid;an external phase comprising supercritical carbon dioxide; anda plurality of nanoparticles to stabilize the internal phase and the external phase.2. The emulsion of claim 1 , wherein the acid comprises hydrochloric acid.3. The emulsion of claim 2 , wherein the hydrochloric acid comprises 15% hydrochloric acid.4. The emulsion of claim 1 , wherein the nanoparticles comprise hydrophobic nanoparticles.5. The emulsion of claim 1 , wherein a concentration of nanoparticles in the emulsion comprises at least 0.1% by weight.6. The emulsion of claim 1 , further comprising a corrosion inhibitor.7. The emulsion of claim 6 , wherein a concentration of the corrosion inhibitor is in a range of between 0.25% and 0.6% by volume.8. The emulsion of claim 1 , wherein a ratio of a concentration of the acid to a concentration of the supercritical carbon dioxide is in a range between 30% and 70%.9. A method of manufacturing an emulsion claim 1 , the method comprising:mixing a first quantity of nanoparticles and a second quantity of carbon dioxide; andmixing a third quantity of acid with the mixture of the first quantity and the second quantity at a temperature and a pressure sufficient to convert the carbon dioxide into ...

Hydrating Swellable Clays

A treatment fluid may comprise: a water having hardness at about 300 ppm or greater, a plurality of particulates, a swellable clay, a chelating agent at about 0.01% to about 5% by weight of the water (BWOW); and an alkali metal base at about 0.01% to about 5% BWOW, wherein the chelating agent and alkali metal base reduce the negative effect of the water on hydrating swellable clays. 1. A treatment fluid comprising:a water having hardness at about 300 ppm or greater;a plurality of particulates;a swellable clay;a chelating agent at about 0.01% to about 5% by weight of the water (BWOW); andan alkali metal base at about 0.01% to about 5% BWOW, wherein the chelating agent and alkali metal base reduce the negative effect of the water on hydrating swellable clays.2. The treatment fluid of claim 1 , wherein the treatment fluid is a drilling fluid and the plurality of particulates comprises weighting agents.3. The treatment fluid of claim 1 , wherein the treatment fluid is a fracturing fluid and the plurality of particulates comprises proppant.4. The treatment fluid of claim 1 , wherein the treatment fluid is a cement slurry and the plurality of particulates comprises a cement.5. The treatment fluid of claim 1 , wherein the treatment fluid is a gravel-packing fluid and the plurality of particulates comprises gravel.6. The treatment fluid of claim 1 , wherein the swellable clay comprises at least one selected from the group consisting of: beidellite claim 1 , montmorillonite claim 1 , bentonite claim 1 , nontronite claim 1 , saponite claim 1 , naturally occurring hectorite clay claim 1 , synthetic hectorite clay claim 1 , palygorskite claim 1 , and lasallite.7. The treatment fluid of claim 1 , wherein the swellable clay is present at about 0.1% to about 30% by weight of the treatment fluid.8. The treatment fluid of claim 1 , wherein the chelating agent comprises at least one selected from the group consisting of: ethylenediaminetetraacetic acid claim 1 , nitrilotriacetic acid ...

Chlorine Dioxide Containing Mixtures And Chlorine Dioxide Bulk Treatments For Enhancing Oil And Gas Recovery

The present disclosure provides a bulk treatment for introduction into a hydrocarbon bearing formation, the bulk treatment comprising a volume of a treatment fluid comprising chlorine dioxide, wherein the volume is such that when the treatment fluid is introduced into a wellbore that penetrates the hydrocarbon bearing formation, the fluid is expected to extend into the formation to a radius that goes beyond the near wellbore region. Such a bulk treatment can act to draw out hydrocarbons from a hydrocarbon-bearing formation, thereby enhancing recovery of oil and/or gas. Also provided herein are mixtures comprising chlorine dioxide, water, an organic non-polar solvent, and optionally one or more additional components (e.g., an acid or chelating agent and/or a surfactant or cosolvent). The mixtures are useful for enhancing recovery of oil and/or gas and for removing residues that contain hydrocarbons. Apparatus for making the mixtures, and methods of making and using the mixtures, e.g., to mitigate damage and/or enhance recovery of oil and/or gas from a petroleum well, are also disclosed. 1105-. (canceled)106. A mixture suitable for introduction into a wellbore of a petroleum production well , the mixture comprisinga) water,b) chlorine dioxide at a concentration of 100 to 10,000 ppm,c) 0.1 to 10% xylene,d) 0.1 to 10% citric acid, ande) 0.1 to 5% ethylene glycol monobutyl ether (EGMBE).107. The mixture of claim 106 , comprising chlorine dioxide at a concentration of at least 500 ppm.108. The mixture of claim 106 , comprising a salt at a concentration of 0.1 to 20%.109. The mixture of claim 106 , wherein the mixture is homogeneous.110. The mixture of claim 108 , wherein the mixture is homogeneous.111. The mixture of claim 106 , wherein the mixture comprises at least 95% liquid components.112. The mixture of claim 109 , wherein the mixture comprises at least 95% liquid components.113. The mixture of claim 110 , wherein the mixture comprises at least 95% liquid components. ...

WEIGHTED FLUIDS FOR TREATMENT OF SUBTERRANEAN FORMATIONS

Various embodiments disclosed relate to weighted fluids for treatment of subterranean formations. In various embodiments, the present invention provides a method of treating a subterranean formation. The method includes placing a weighted fluid in the subterranean formation. The weighted fluid includes calcium bromide. The weighted fluid includes one or more secondary salts that are each independently an inorganic bromide salt other than calcium bromide. The weighted fluid also includes water. The weighted fluid has a density at standard temperature and pressure of at least about 1.7 g/cm. 1. A method of treating a subterranean formation , the method comprising: calcium bromide;', 'one or more secondary salts that are each independently an inorganic bromide salt other than calcium bromide; and', 'water;', {'sup': '3', 'wherein the weighted fluid has a density at standard temperature and pressure of at least about 1.7 g/cm.'}], 'placing in the subterranean formation a weighted fluid comprising'}2. The method of claim 1 , wherein the weighted fluid is substantially free of elemental zinc and zinc salts.3. The method of claim 1 , wherein the method comprises using the weighted fluid to perform in the subterranean formation a completion operation claim 1 , a workover operation claim 1 , a drilling operation claim 1 , a perforating operation claim 1 , a displacement operation claim 1 , a gravel packing operation claim 1 , a well suspension operation claim 1 , a packing operation claim 1 , or a combination thereof.4. The method of claim 1 , wherein the weighted fluid is substantially free of solids.5. The method of claim 1 , wherein the weighted fluid has a density at standard temperature and pressure of about 1.7 g/cmto about 2.2 g/cm.6. The method of claim 1 , wherein the weighted fluid has a crystallization temperature at standard pressure of about −35° C. to about −7° C.7. The method of claim 1 , wherein the weighted fluid has a crystallization temperature at about 34 ...

CHLORINE DIOXIDE PRECURSOR AND METHODS OF USING SAME

According to one aspect of the invention, a method of converting an oxy halide salt into a halide dioxide in a reaction zone under certain conditions is provided. More specifically, the method includes generating chlorine dioxide from a stable composition comprising an oxy halide salt by introducing said composition to a reducing agent and minimum temperature within the reaction zone. According to another aspect of the invention, a composition for a stable chlorine dioxide precursor comprising an oxy halide salt is provided. 146-. (canceled)47. An aqueous chlorine dioxide precursor composition comprising 5% to 40% by weight of sodium chlorate and 5% to 20% by weight of citric acid , wherein the composition is stable at a temperature below about 90° F. and wherein the composition reacts to form chlorine dioxide when exposed to a reducing agent in combination with a temperature of about 110° F. or greater.48. A treatment fluid comprising a well fluid and an aqueous chlorine dioxide precursor composition , the aqueous chlorine dioxide precursor composition comprising 5% to 40% by weight of a chlorate salt and 5% to 20% by weight of a weak acid.49. A method comprising introducing a chlorine dioxide precursor composition into a well fluid to form a treatment fluid , the chlorine dioxide precursor composition being an aqueous solution comprising 5 to 40% by weight of a chlorate salt and 5 to 20% by weight of a weak acid , wherein the composition is stable at a temperature below about 90° F. , and wherein the composition reacts to form chlorine dioxide when exposed to a reducing agent in combination with a temperature of about50. The method of claim 49 , wherein the chlorine dioxide precursor composition does not comprise a strong acid.51. The method of claim 49 , wherein the weak acid is citric acid claim 49 , lactic acid claim 49 , formic acid claim 49 , oxalic acid claim 49 , ethanoic acid claim 49 , acetic acid claim 49 , propanoic acid claim 49 , or a mixture of two ...

NANOPARTICLE GEL SYSTEMS FOR TREATING CARBONATE FORMATIONS

Methods of treating a carbonate formation are provided. The methods include introducing a nanoparticle gel system into the carbonate formation at a rate and pressure sufficient to create or enhance at least one fracture in the carbonate formation. The nanoparticle gel system includes a gelling agent, a nanoparticle-size clay, and a proppant. The methods further include allowing a portion of the proppant to deposit in the at least one fracture, pumping an acidic fluid into the carbonate formation, and allowing a portion of the acidic fluid to at least partially reduce a viscosity of the nanoparticle gel system and to react with the carbonate formation. 1. A method of treating a carbonate formation comprising:introducing a nanoparticle gel system comprising a gelling agent, a nanoparticle-size clay, and a proppant into the carbonate formation at a rate and pressure sufficient to create or enhance at least one fracture in the carbonate formation;allowing a portion of the proppant to deposit in the at least one fracture;pumping an acidic fluid into the carbonate formation; andallowing a portion of the acidic fluid to at least partially reduce a viscosity of the nanoparticle gel system and to react with the carbonate formation.2. The method of claim 1 , wherein the gelling agent is present in the nanoparticle gel system in an amount of about 0.1 percent to about 2.0 percent by weight of the nanoparticle gel system.3. The method of claim 1 , wherein the nanoparticle-size clay is present in the nanoparticle gel system in an amount of about 0.05 percent to about 6.0 percent by weight of the nanoparticle gel system.4. The method of claim 1 , wherein the nanoparticle gel system further comprises a cross-linking agent claim 1 , and the gelling agent is cross-linked.5. The method of claim 4 , wherein the cross-linking agent comprises a metal cross-linking agent.6. The method of claim 1 , wherein the nanoparticle gel system further comprises an aqueous fluid.7. The method of ...

Treatment fluids containing a boron trifluoride complex and methods for use thereof

Treatment fluids for use in subterranean formations, particularly sandstone and other siliceous formations, may contain a source of fluoride ions to aid in mineral dissolution. In some cases, it may be desirable to generate the fluoride ions from a fluoride ion precursor, particularly a hydrofluoric acid precursor, such as a boron trifluoride complex. Methods described herein can comprise providing a treatment fluid that comprises an aqueous base fluid, a boron trifluoride complex, and a chelating agent composition, and introducing the treatment fluid into a subterranean formation.

DOWNHOLE HIGH TEMPERATURE RHEOLOGY CONTROL

A method of treating a well comprising introducing a well treatment fluid into the well, and a well treatment fluid, are provided. The well treatment fluid comprises an aqueous base fluid, sepiolite clay, and a polymer component selected from the group of an acryloylmorpholine polymer, a polyvinylpyrrolidone polymer, and mixtures thereof. In one embodiment, for example, the method is a method of drilling a well. In this embodiment, the well treatment fluid is a drilling fluid. 1. A method of treating a well , comprising: an aqueous base fluid;', 'sepiolite clay; and', 'a polymer component selected from the group of an acryloylmorpholine polymer, a polyvinylpyrrolidone polymer, and mixtures thereof., 'introducing a well treatment fluid into the well, said well treatment fluid including2. The method of claim 1 , wherein said aqueous base fluid is water.3. The method of claim 1 , wherein said sepiolite clay is present in the well treatment fluid in an amount in the range of from about 0.5 pounds to about 50 pounds per gallon of the aqueous base fluid.4. The method of claim 1 , wherein said polymer component includes one or more synthetic polymers.5. The method of claim 1 , wherein said polymer component is selected from the group of an acryloylmorpholine copolymer claim 1 , a polyvinylpyrrolidone copolymer claim 1 , and mixtures thereof.6. The method of claim 5 , wherein said acryloylmorpholine copolymer is selected from the group of an acrylic acid and acryloylmorpholine copolymer claim 5 , a methacrylic acid and acryloylmorpholine copolymer claim 5 , an acrylamide and acryloylmorpholine copolymer claim 5 , an N claim 5 ,N-dimethyl acrylamide and acryloylmorpholine copolymer claim 5 , a 2-acrylamido-2-methylpropane sulfonic acid and acryloylmorpholine copolymer claim 5 , and mixtures thereof.7. The method of claim 5 , wherein said polyvinylpyrrolidone copolymer is selected from the group of an acrylic acid and vinylpyrrolidone copolymer claim 5 , a methacrylic acid ...

HYDROCARBON STIMULATION BY ENERGETIC CHEMISTRY

Disclosed are methods and compositions for stimulating a hydrocarbon formation by generating heat and/or pressure in the formation, in either a fracturing or matrix treatment. This invention utilizes reactive fluids which comprise energetic chemistry that reacts in the formation to create heat and/or pressure. The heat may reduce the viscosity and increase the mobility of heavy oil, and/or the pressure may initiate or extend fractures in the hydrocarbon bearing formation. The reactive fluid may be buffered to slow the reaction and include an encapsulated activator to accelerate the reaction after suitable delay or when the fluid is placed in a zone of interest. Reactive fluids may be sequentially used, wherein each reactive fluid is successively less energetic than the preceding reactive fluid. 1. A method of stimulating a subterranean hydrocarbon formation penetrated by a wellbore , the formation having a proximal zone adjacent the wellbore , and a distal zone outside the proximal zone , the method comprising:(a) injecting a first reactive fluid comprising exothermic reactants into the proximal zone;(b) displacing the first reactive fluid into the distal zone with a second reactive fluid, which is less energetic than the first reactive fluid; and(c) activating the second reactive fluid such that heat generated by the second reactive fluid activates the first reactive fluid.2. The method of wherein the second reactive fluid is less energetic than the first reactive fluid as a result of a lower concentration or quantity of reactants claim 1 , or the absence of ammonium nitrate claim 1 , or both.3. The method of wherein the first reactive fluid comprises an ammonium compound and a nitrite compound.4. The method of wherein the first reactive fluid comprises ammonium nitrate in addition to the ammonium compound.5. The method of comprising the further step of displacing the first and second reactive fluids with at least one additional reactive fluid which is less ...

METHOD OF TREATING A SUBTERRANEAN FORMATION WITH A MORTAR SLURRY DESIGNED TO FORM A PERMEABLE MORTAR

A method of treating a subterranean formation may include preparing a mortar slurry, injecting the mortar slurry into the subterranean formation at a pressure sufficient to create a fracture in the subterranean formation, allowing the mortar slurry to set, forming a mortar in the fracture, and providing a pulse of pressure sufficient to reopen the fracture and thereby provide cracks in the set mortar. The mortar slurry may be designed to form a pervious mortar, to crack under fracture closure pressure, or both. 1. A method of treating a subterranean formation , comprising:preparing a mortar slurry designed to set to form a mortar with a compressive strength below a fracture closure pressure of the subterranean formation, the mortar slurry comprising a cementitious material and water;injecting the mortar slurry into the subterranean formation at a pressure sufficient to create a fracture in the subterranean formation;while maintaining a pressure higher than the fracture closure pressure, allowing the mortar slurry to set, forming the mortar in the fracture;reducing the pressure below the fracture closure pressure;allowing the mortar in the fracture to crack, forming a cracked mortar; andexposing the set mortar to a pulse of pressure sufficient to reopen the fracture and provide additional cracks and permeability in the set cracked mortar.2. The method of claim 1 , wherein the pulse of pressure is provided by a compressable gas.3. The method of wherein the pulse of pressure is provided by pumping a liquid into the wellbore.4. The method of wherein the mortar slurry is further designed to have a viscosity of less 5 claim 1 ,000 cP.5. The method of claim 1 , wherein the mortar slurry is further designed to set to form the mortar with a setting time in excess of 60 minutes after pump shut in claim 1 , and wherein allowing the mortar slurry to set comprises waiting at least 60 minutes after injecting stops.6. The method of claim 1 , wherein the mortar slurry is further ...

Supercritical Carbon Dioxide Emulsified Acid

One aspect of an emulsion includes an internal phase including acid, an external phase including supercritical carbon dioxide, and multiple nanoparticles to stabilize the internal phase and the external phase. The acid can include hydrochloric acid. The hydrochloric acid can include 15% hydrochloric acid. The nanoparticles can include hydrophobic nanoparticles. A concentration of nanoparticles in the emulsion can be at least 0.1% by weight. The emulsion can include a corrosion inhibitor. A concentration of the corrosion inhibitor can be in a range of between 0.25% and 0.6% by volume. A ratio of a concentration of the acid to a concentration of the supercritical carbon dioxide can be in a range between 30% and 70%. 120-. (canceled)21. An emulsion comprising:an internal phase comprising acid;an external phase comprising supercritical carbon dioxide; andnanoparticles that stabilize the internal phase and the external phase.22. The emulsion of claim 21 , wherein the acid comprises hydrochloric acid claim 21 , citric acid claim 21 , formic acid claim 21 , acetic acid claim 21 , hydrofluoric acid claim 21 , or a chelating agent claim 21 , or any combinations thereof23. The emulsion of claim 22 , wherein a ratio of a concentration of the acid to a concentration of the supercritical carbon dioxide is in a range between 30% and 70%.24. The emulsion of claim 21 , wherein the acid comprises hydrochloric acid.25. The emulsion of claim 21 , wherein the nanoparticles comprise hydrophobic nanoparticles claim 21 , and wherein a concentration of nanoparticles in the emulsion comprises at least 0.1% by weight.26. The emulsion of claim 21 , further comprising a corrosion inhibitor.27. The emulsion of claim 26 , wherein a concentration of the corrosion inhibitor in the emulsion is in a range of between 0.25% and 0.6% by volume.28. A method comprising: mixing nanoparticles and carbon dioxide at a temperature and a pressure sufficient to convert the carbon dioxide into supercritical ...

SALT-TOLERANT SELF-SUSPENDING PROPPANTS

A self-suspending proppant that resists the adverse effects of calcium and other cations on swelling comprises a proppant substrate particle and a gelatinized cationic starch coating on the proppant substrate particle. 1. A self-suspending proppant comprising a proppant substrate particle and a gelatinized cationic starch coating on the proppant substrate particle , wherein the self-suspending proppant exhibits a volumetric expansion as determined by its Settled Bed Height (SBH) of at least 1.5 in simulated hard water containing 80 ,000 ppm dissolved CaCOafter having been subjected to shear mixing at a shear rate of about 550 sfor 10 minutes.2. The self-suspending proppant of claim 1 , wherein the self-suspending proppant is dry.3. A self-suspending proppant which is both durable and especially resistant to the adverse effects of calcium and other cations on swelling claim 1 , this self-suspending proppant being made by mixing proppant substrate particles with a cationic starch which is at least partially gelatinized thereby forming discrete starch-coated substrate particles claim 1 , and then drying the starch-coated substrate particles so formed.4. The self-suspending proppant of claim 3 , wherein(a) the proppant substrate particle is treated with an adhesion promoter,(b) the cationic starch is crosslinked, or(c) both.5. The self-suspending proppant of claim 4 , wherein the cationic starch has a degree of substitution of 0.030 to 0.55 and contains about 5 to 30 wt. % of amylose units and about 70 to 95 wt. % of amylopectin.6. The self-suspending proppant of claim 3 , wherein the cationic starch is cationic due to the presence of quaternary ammonium groups.7. The self-suspending proppant of claim 3 , wherein the self-suspending proppant exhibits a volumetric expansion by a factor of ≧˜1.3 when exposed to a simulated hard water containing 80 claim 3 ,000 ppm CaCOfor 10 minutes.8. The self-suspending proppant of claim 7 , wherein the self-suspending proppant exhibits ...

Use of metal silicides in hydrocarbon production and transportation

A method of hydraulic fracturing is provided which uses metal silicides to generate significant pressure inside a wellbore. The method comprises injecting a fracturing fluid and an aqueous or reacting fluid into the wellbore to react with the fracturing fluid. The fracturing fluid comprises metal silicide, which may be uncoated or coated, and hydrocarbon fluid. The reacting fluid comprises water or a solvent. A method of removing buildup in pipelines such as subsea pipelines which uses metal silicides to generate heat and pressure inside the pipeline is also provided. The method comprises injecting an organic slug and an aqueous slug. The organic slug comprises metal silicide and hydrocarbon fluid. The aqueous slug comprises water. Alternatively, there is also provided a method for purifying flowback water produced from a hydraulic fracturing process comprising adding metal silicide to the flowback water produced from a hydraulic fracturing process.

COMPLETION FLUID

An aqueous well completion/workover fluid, including a surfactant, at least one salt and an alkaline material, wherein the surfactant comprises a mixture of a phosphate ester and a non ionic ethoxylated alcohol, wherein the fluid has a pH between 6 and 8, and wherein the fluid generates an interfacial tension with crude oil of less than or equal to 1 dyne/cm. The fluid is not harmful to a formation if it penetrates the formation, and further exhibits an excellent detergency which can be beneficial as well. 114-. (canceled)15. A method for completing a well , comprising the steps ofpumping an aqueous fluid comprising: a surfactant; at least one salt; and an alkaline material, wherein the surfactant comprises a mixture of a phosphate ester and a non ionic ethoxylated alcohol, wherein the fluid has a pH between 6 and 8, and wherein the fluid generates an interfacial tension with crude oil of less than or equal to 1 dyne/cm; andholding the fluid in the well during a completion process16. The method of claim 15 , wherein the at least one salt is selected from the group consisting of potassium chloride (KCl) claim 15 , potassium acetate (CHCOK) claim 15 , sodium chloride (NaCl) claim 15 , calcium chloride (CaCl) claim 15 , and a mixture thereof.17. The method of claim 15 , wherein the alkaline material is preferably an amino-alcohol.18. The method of claim 15 , wherein the fluid exhibits a detergency of at least 90%.19. The method of claim 15 , wherein the fluid contains the surfactant in an amount between 0.2 and 3.0 w/w with respect to weight of the fluid.20. The method of claim 15 , wherein the fluid contains the surfactant in an amount between 0.5 and 1% w/w with respect to weight of the fluid.21. The method of claim 15 , wherein the surfactant contains the phosphate ester in an amount between 20 and 60% w/w of the surfactant.22. The method of claim 21 , wherein the surfactant contains the non-ionic ethoxylated alcohol in an amount between 80 and 40% w/w of the ...

SYSTEMS AND METHODS FOR REMOVING CONTAMINANTS FROM HIGH DENSITY COMPLETION FLUID

A system and method of decreasing contaminant concentration in an oilfield brine fluid, such as a high density completions fluid, that includes mixing the oilfield brine fluid with chlorine dioxide (ClO). The oilfield brine fluid includes dissolved contaminant, such as iron, and one or more dissolved salts, such as selected from the group consisting of NaCl, NaBr, CaCl, CaBr, and ZnBr. The mixing is for a time sufficient for the ClOto react with at least one component of the oilfield brine fluid to form precipitated contaminant without reacting to the one or more salts. 1. A method of decreasing iron concentration in a high-density completions fluid , comprising:{'sub': '2', 'mixing a completions fluid with chlorine dioxide (ClO), wherein the completions fluid comprises dissolved iron and one or more dissolved salts, wherein the completions fluid comprises a manufactured brine with a density of at least 9 ppg and the one or more dissolved salts comprises at least zinc-bromide; and'}decreasing a concentration of the dissolved iron in the completions fluid without substantively removing the zinc-bromide.2. The method of claim 1 , wherein the density of the high-density completions fluid is at least 15 ppg.3. The method of claim 1 , wherein the density of the high-density completions fluid is at least 20 ppg.4. The method of claim 1 , wherein the completions fluid prior to mixing has an iron concentration greater than 50 ppm claim 1 , and wherein the completions fluid after mixing has an iron concentration less than 50 ppm.5. The method of claim 1 , further comprising forming a precipitate of the dissolved iron without forming a precipitate of the zinc bromide.6. The method of claim 1 , further comprising removing the iron from the high-density completions fluid without substantively removing the zinc bromide from the high-density completions fluid.7. The method of claim 1 , further comprising verifying that the zinc bromide substantially remains in the high-density ...

Method of Enhancing Fracture Complexity Using Far-Field Divert Systems

The flow of well treatment fluids may be diverted from a high permeability zone to a low permeability zone within a fracture network within a subterranean formation by use of a divert system comprising dissolvable diverter particulates and proppant. At least a portion of the high permeability zone is propped open with the proppant of the divert system and at least a portion of the high permeability zone is blocked with the diverter particulates. A fluid is pumped into the formation and into a lower permeability zone farther from the wellbore. The diverter particulates in the high permeability zones may then be dissolved at in-situ reservoir conditions and hydrocarbons produced from the high permeability propped zones of the fracture network. The divert system has particular applicability in the enhancement of production of hydrocarbons from high permeability zones in a fracture network located far field from the wellbore. 1. A method of stimulating the production of hydrocarbons from a subterranean formation penetrated by a wellbore , the method comprising:(a) pumping an aqueous fluid having minimum viscosity of 2 cP into a stimulated area within the subterranean formation and into a high permeability zone of a primary far field fracture within the stimulated area about 10 feet to about 3,000 feet from the wellbore, the aqueous fluid having a divert system comprising (i) dissolvable diverter particulates having a particle size from about 4 to 50 about mesh and (ii) proppant having a particle size range between from about 40 to about 325 mesh;(b) propping open at least a portion of the high permeability zone with at least a portion of the proppant of the divert system and blocking at least a portion of the high permeability zone with at least a portion of the diverter particulates, wherein the diverter particulates form a bridge within the primary far field fracture;(c) pumping a second fluid into the subterranean formation and diverting the flow of the second fluid ...

Compositions And Methods For Treating Subterranean Formations

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. 1. An aqueous composition comprising:at least one carrier fluid;at least one populations of positively charged nanoparticles; andat least one populations of negatively charged nanoparticles,wherein the aqueous composition is not a drilling fluid, and is free of cement and foaming agents.2. The aqueous composition of claim 1 , further comprising:at least two populations of positively charged nanoparticles, wherein the at least two populations of positively charged nanoparticles have different sizes and/or are different materials; and/orat least two populations of negatively charged nanoparticles, wherein the at least two populations of negatively charged nanoparticles have different sizes and/or are different materials.3. The aqueous composition of claim 1 , further comprising:a detergent;a surface-active agent comprising a polymer or a surfactant;an alcohol; anda salt.4. The aqueous composition of claim 3 , wherein the surface-active agent is selected from the group consisting of polyvinylpyrrolidone claim 3 , fatty acid salts claim 3 , sulfates claim 3 , sulfonates claim 3 , phosphoric surfactants claim 3 , alkyl-ammoniums claim 3 , alkyl-amines claim 3 , fatty amine surfactants ...

MULTI-FUNCTIONAL HYBRID FRACTURING FLUID SYSTEM

The present invention provides a multi-functional hybrid fracturing fluid system, comprising slick water and high viscosity sand carrying fluid, wherein the slick water contains 0.02%˜0.15% of friction-reducing agent by mass percentage, the high viscosity sand carrying fluid contains 0.2%˜0.75% of thickener by mass percentage; the friction-reducing agent and the thickener are the same associative polymer which is a modified natural associative polymer and/or an organic synthetic associative polymer. 1. Use of an associative polymer as friction-reducing agent and thickener , wherein the associative polymer is a modified natural associative polymer and/or organic synthetic associative polymer.2. A multi-functional hybrid fracturing fluid system , characterized in that , it comprises slick water and high viscosity sand carrying fluid ,wherein the slick water contains 0.02%˜0.15% of friction-reducing agent by mass percentage;the high viscosity sand carrying fluid contains 0.2%˜0.75% of thickener by mass percentage; andthe friction-reducing agent and the thickener are the same associative polymer which is a modified natural associative polymer and/or an organic synthetic associative polymer.3. The multi-functional hybrid fracturing fluid system of claim 2 , characterized in that claim 2 ,the modified natural associative polymer is one or more of hydrophobically modified cellulose polymers, hydrophobically modified starch polymers and hydrophobically modified xanthan gum; andthe organic synthetic associative polymer is hydrophobically modified polyacrylamide and/or derivatives thereof.4. The multi-functional hybrid fracturing fluid system of claim 2 , characterized in that claim 2 ,the slick water comprises 0.02%˜0.15% of friction-reducing agent, 0.05%˜0.3% of enhancer, 0.2%˜2% of clay stabilizer by mass percentage and water solvent as the balance;the high viscosity sand carrying fluid comprises 0.2%˜0.75% of thickener, 0.1%˜0.4% of enhancer, 0.3%˜2% of clay stabilizer, ...

Lowering The Crystallization Temperature Of Brines

Provided are compositions, methods, and systems that relate to use of crystallization temperature reduction additives in treatment fluids. A treatment fluid for use in subterranean operations, the treatment fluid comprising: a bromide brine having a first true crystallization temperature; a true crystallization temperature reduction additive, the first true crystallization temperature is the true crystallization temperature of the bromide brine without inclusion of the true crystallization temperature reduction additive; the treatment fluid has a second true crystallization temperature that is lower than the first true crystallization temperature. A method for treating a wellbore, wherein the method comprises: disposing a treatment fluid in the wellbore, wherein the treatment fluid comprises: a bromide brine and a first true crystallization temperature; a true crystallization temperature reduction additive, the treatment fluid has a second true crystallization temperature that is lower than the first true crystallization temperature. 1. A treatment fluid for use in subterranean operations , the treatment fluid comprising:a bromide brine having a first true crystallization temperature, wherein the bromide brine has a density of about 14.2 lbs/gal or greater; anda true crystallization temperature reduction additive;wherein the first true crystallization temperature is the true crystallization temperature of the bromide brine without inclusion of the true crystallization temperature reduction additive; andwherein the treatment fluid has a second true crystallization temperature that is lower than the first true crystallization temperature.2. The treatment fluid of claim 1 , wherein the second true crystallization temperature is less than the first true crystallization temperature by about 9° F. or more.3. The treatment fluid of claim 1 , wherein the bromide brine comprises at least one brine selected from the group consisting of a lithium bromide claim 1 , sodium ...

METHODS FOR TREATING FRACTURE FACES IN PROPPED FRACTURES USING FINE PARTICULATES

Methods and compositions for mitigating the embedment of proppant into fracture faces in subterranean formations are provided. In some embodiments, the methods comprise: introducing a treatment fluid into a subterranean formation at or above a pressure sufficient to create or enhance one or more fractures in the subterranean formation; introducing an anchoring agent into the subterranean formation to deposit the anchoring agent on a portion of a fracture face in the one or more fractures within the subterranean formation; introducing a first particulate material comprising fine particulates into the subterranean formation to attach to the anchoring agent on the portion of the fracture face, wherein said fine particulates have a mean particle size of up to about 50 μm; introducing a second particulate material comprising proppant into the one or more fractures in the subterranean formation. 1. A method comprising:introducing a treatment fluid into a subterranean formation at or above a pressure sufficient to create or enhance one or more fractures in the subterranean formation;introducing an anchoring agent into the subterranean formation to deposit the anchoring agent on a portion of a fracture face in the one or more fractures within the subterranean formation;introducing a first particulate material comprising fine particulates into the subterranean formation to attach to the anchoring agent on the portion of the fracture face, wherein said fine particulates have a mean particle size of up to about 50 μm; andintroducing a second particulate material comprising proppant into the one or more fractures in the subterranean formation.2. The method of wherein the treatment fluid comprises the anchoring agent.3. The method of wherein the treatment fluid comprises the proppant.4. The method of further comprising allowing the anchoring agent to consolidate at least a portion of unconsolidated particulates in the subterranean formation.5. The method of wherein the anchoring ...

HYDROCARBON FORMATION TREATMENT MICELLAR SOLUTIONS

A hydrocarbon formation treatment micellar solution fluid and its use in treating underperforming hydrocarbon formations is described and claimed. A hydrocarbon formation treatment micellar solution fluid wherein the micellar solution fluid comprises water, a non-terpene oil-based moiety, a brine resistant aqueous colloidal silica sol; and optionally a terpene or a terpenoid, wherein the brine resistant aqueous colloidal silica sol has silica particles with a surface that is functionalized with at least one moiety selected from the group consisting of a hydrophilic organosilane, a mixture of hydrophilic and hydrophobic organosilanes, or a polysiloxane oligomer, wherein the brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter, and wherein, when a terpene or terpenoid is present, the ratio of total water to terpene or terpenoid is at least about 15 to 1. 1. A method of treating a hydrocarbon-containing subterranean formation comprising introducing a micellar solution fluid into the hydrocarbon-containing subterranean , whereinthe micellar solution fluid comprisesa) waterb) a non-terpene oil-based moiety,c) a brine resistant aqueous colloidal silica sol; andd) optionally a terpene or a terpenoid,wherein the brine resistant aqueous colloidal silica sol has silica particles with a surface that is functionalized with at least one moiety selected from the group consisting of ai) hydrophilic organosilane,(ii) a mixture of hydrophilic and hydrophobic organosilanes, and(iii) polysiloxane oligomer,wherein the brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter, andwherein, when a terpene or terpenoid is present, the ratio of total water to terpene or terpenoid is at least about 15 to 1.2. The method of wherein when a terpene or terpenoid is ...

Composition And Method For Improving Performance Of Friction Reducing Polymers In High Dissolved Solids Water

Systems and methods include using a fracture fluid downhole for fracturing a formation. The method includes providing an aqueous solution comprising dissolved solids at a certain ionic strength, and adding a proppant to create a fracture fluid. The method continues by adding a polymeric additive and a surfactant to the fracture fluid, wherein the polymeric additive comprises friction reducing capabilities that can be decreased by the ionic strength present in the fracture fluid (i.e., ionic strength originally found in the water). The addition of the polymeric additive and the surfactant to the fracture fluid creates an enhanced fracture fluid, wherein the surfactant increases the performance of the friction reducing capabilities of the polymeric additive in the enhanced fracture fluid, which provides a more efficient fracturing operation. The method concludes by pumping the enhanced fracture fluid downhole for a more efficient fracture of the formation.

Fluid media for pre-treatment of formation, which contain peroxides, and methods referring to them

FIELD: oil and gas industry. SUBSTANCE: method involves production of cleaning fluid medium containing peroxide-forming compound and fluid medium on water basis; arrangement of cleaning fluid medium in an underground formation; removal of contaminants at least from some part of the underground formation for formation of a cleaned section of the formation; production of a consolidating agent; arrangement of the consolidating agent at least on some part of the cleaned formation section; and provision of conditions for sticking of the consolidating agent at least to some amount of non-consolidated particles in the cleaned formation section. As per the other version, the method involves the above, where the cleaned section includes at least some amount of cleaned flow movement routes. EFFECT: improvement of arrangement and operation of qualities of consolidating agents. 21 cl, 2 tbl РОССИЙСКАЯ ФЕДЕРАЦИЯ (19) RU (11) 2 501 942 (13) C1 (51) МПК E21B 43/267 (2006.01) E21B 33/138 (2006.01) E21B 37/00 (2006.01) ФЕДЕРАЛЬНАЯ СЛУЖБА ПО ИНТЕЛЛЕКТУАЛЬНОЙ СОБСТВЕННОСТИ (12) ОПИСАНИЕ ИЗОБРЕТЕНИЯ К ПАТЕНТУ Приоритет(ы): (30) Конвенционный приоритет: 17.12.2009 US 12/641,162 (73) Патентообладатель(и): ХАЛЛИБЁРТОН ЭНЕРДЖИ СЕРВИСИЗ, ИНК. (US) (45) Опубликовано: 20.12.2013 Бюл. № 35 2 5 0 1 9 4 2 (56) Список документов, цитированных в отчете о поиске: US 3858655 A, 07.01.1975. US 7392847 B2, 01.07.2008. US 7093658 B2, 22.08.2006. US 2007/0146976 A1, 27.06.2009. US 5853048 A, 29.12.1998. US 6439309 B1, 27.08.2002. RU 2344040 C2, 20.01.2009. 2 5 0 1 9 4 2 R U (86) Заявка PCT: US 2011/021579 (18.01.2011) C 1 C 1 (85) Дата начала рассмотрения заявки PCT на национальной фазе: 17.07.2012 (87) Публикация заявки РСТ: WO 2011/075750 (23.06.2011) Адрес для переписки: 109012, Москва, ул. Ильинка, 5/2, ООО "Союзпатент" (54) ТЕКУЧИЕ СРЕДЫ ДЛЯ ПРЕДВАРИТЕЛЬНОЙ ОБРАБОТКИ ПЛАСТА, СОДЕРЖАЩИЕ ПЕРОКСИДЫ, И СПОСОБЫ, ОТНОСЯЩИЕСЯ К НИМ (57) Реферат: Изобретение относится к добыче углеводородов из подземного ...

一种低固相高密度完井液制备方法

本发明公开了一种低固相高密度完井液制备方法，包括如下步骤：步骤1：完井液基液的配制，并将完井液基液密度调至1.8g/cm 3 ；步骤2：向完井液基液中加入加重剂，将完井液基液的密度从1.8g/cm 3 调至2.4g/cm 3 ；步骤1具体步骤如下：S1：将无固相加重剂与溴化钠或氯化钾按质量比为1‑2:1‑4放入搅拌机中搅拌混合，将其溶解在水中,搅拌时间为30‑50min,搅拌温度为40‑45℃；S2：降温后将碳酸氢钠和耐高温改性咪唑啉缓蚀剂加入搅拌机中搅拌溶解。本发明提供了低固相高密度完井液制备方法，通过该制备方法制备的低固相高密度完井液其密度能够达到2.4g/cm 3 ；其能够用于高温、高压的深井开发，具有较好的稳定性和低腐蚀性；且，低固相高密度完井液其密度达到2.4g/cm 3 后，其仍具有较好的稳定性。

使用远场转向体系增强裂缝复杂性的方法

通过使用包含可溶解转向剂微粒和支撑剂的转向体系，可以将井处理流体的流动从地下地层内的裂缝网络内的高渗透区带转向到低渗透区带。用所述转向体系的所述支撑剂将所述高渗透区带的至少一部分支撑敞开，并用所述转向剂微粒封堵所述高渗透区带的至少一部分。然后将流体泵入所述地下地层中并进入距离所述井筒更远的所述地层的较低渗透区带中。然后，可以将所述高渗透区带中的所述转向剂微粒在原位储层条件下溶解，并且从所述裂缝网络的所述高渗透支撑区域中开采烃类。所述转向体系特别适用于增强烃类从位于井筒远场的裂缝网络中的高渗透区带中的开采。

Compositions and methods for treating subterranean formations

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.

Preparation and use of gelable silicate solutions in oil field applications

A gelable silicate solution prepared by mixing fumed silica and an alkali metal hydroxide with water is provided. The silicate solution is used to form a seal or plug in one or more subterranean formations or in a well bore penetrating the formations by pumping the solution into a desired location in the well bore or formations and allowing the silicate solution to gel therein.

Compositions of and methods for using hydraulic fracturing fluid for petroleum production

A hydraulic fracturing fluid for use in oilfield applications, the hydraulic fracturing fluid includes a spherical bead-forming liquid composition, the spherical bead-forming liquid composition comprised of a primary liquid precursor and a secondary liquid precursor, the primary liquid precursor comprises a micellar forming surfactant, a bead-forming compound, and a non-solids bearing liquid solvent; and the secondary liquid precursor comprises one or more curing agents, and one or more co-curing agents.

Method of enhancing fracture complexity using far-field divert systems

The flow of well treatment fluids may be diverted from a high permeability zone to a low permeability zone within a fracture network within subterranean formation by use of divert system comprising dissolvable diverter particulates and proppant. At least a portion of the high permeability zone is propped open with the proppant of the divert system and at least a portion of the high permeability zone is blocked with the diverter particulates. A fluid is then pumped into the subterranean formation and into a lower permeability zone of the formation farther from the wellbore. The diverter particulates in the high permeability zones may be dissolved at in-situ reservoir conditions and hydrocarbons produced from the high permeability propped zones of the fracture network. The divert system has particular applicability in the enhancement of production or hydrocarbons from high permeability zones in a fracture network located far field from the wellbore.

Method of enhancing fracture complexity using far-field divert systems

The flow of well treatment fluids may be diverted from a high permeability zone to a low permeability zone within a fracture network within a subterranean formation by use of a divert system comprising dissolvable diverter particulates and proppant. At least a portion of the high permeability zone is propped open with the proppant of the divert system and at least a portion of the high permeability zone is blocked with the diverter particulates. A fluid is then pumped into the subterranean formation and into a lower permeability zone of the formation farther from the wellbore. The diverter particulates in the high permeability zones may then be dissolved at in-situ reservoir conditions and hydrocarbons produced from the high permeability propped zones of the fracture network. The divert system has particular applicability in the enhancement of production or hydrocarbons from high permeability zones in a fracture network located far field from the wellbore.

Hydrocarbon formation treatment micellar solutions

A hydrocarbon formation treatment micellar solution fluid and its use in treating underperforming hydrocarbon formations is described and claimed. A hydrocarbon formation treatment micellar solution fluid wherein the micellar solution fluid comprises water, a non-terpene oil-based moiety, a brine resistant aqueous colloidal silica sol; and optionally a terpene or a terpenoid, wherein the brine resistant aqueous colloidal silica sol has silica particles with a surface that is functionalized with at least one moiety selected from the group consisting of a hydrophilic organosilane, a mixture of hydrophilic and hydrophobic organosilanes, or a polysiloxane oligomer, wherein the brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter, and wherein, when a terpene or terpenoid is present, the ratio of total water to terpene or terpenoid is at least about 15 to 1.

Methods and viscosified compositions for treating wells

The present invention relates to methods of treating subterranean formations with viscosified aqueous well treating compositions which break into thin fluids at static temperatures in the range of from about 150° F. to about 200° F. A breaker system is included in the compositions comprised of an alkali metal or ammonium persulfate breaker and a breaker activity delaying agent comprised of an alkali metal chlorite or hypochlorite.

Clay Stabilization with Nanoparticles

A treating fluid may contain an effective amount of a particulate additive to stabilize clays, such as clays in a subterranean formation, by inhibiting or preventing them from swelling and/or migrating, where the particulate additive is an alkaline earth metal oxide, alkaline earth metal hydroxide, alkali metal oxide, alkali metal hydroxide, transition metal oxide, transition metal hydroxide, post-transition metal oxide, post-transition metal hydroxide, piezoelectric crystal, and/or pyroelectric crystal. The particle size of the magnesium oxide or other agent may be nanometer scale, which scale may provide unique particle charges that help stabilize the clays. These treating fluids may be used as treatment fluids for subterranean hydrocarbon formations, such as in hydraulic fracturing, completion fluids, gravel packing fluids and fluid loss pills. The carrier fluid used in the treating fluid may be aqueous, brine, alcoholic or hydrocarbon-based.

Alkaline silicate compounds, and their uses

L'invention concerne des compositions de silicates alcalins, caractérisées en ce qu'elles consistent en une microémulsion d'une solution aqueuse d'un silicate de métal alcalin, d'un agent gélifiant et d'au moins un agent tensioactif. Ces compositions trouvent notamment leur utilisation pour la consolidation des sols et pour le colmatage de formations géologiques souterraines.