БУРОВЫЕ ТЕКУЧИЕ СРЕДЫ И СПОСОБЫ ИХ ПРИМЕНЕНИЯ

Группа изобретений относится к способам бурения с применением композиций буровых текучих сред. Технический результат - предотвращение потери текучей среды в пласте посредством водных буровых растворов, в которых регулирующее потери текучей среды вещество практически не набухает в воде, удерживание воды в водных буровых растворах, температура которых достигает или превышает уровень от 80°C до 200°C. Буровой раствор содержит источник воды, закупоривающий агент, нанокомпозит, содержащий структуру из ядра и оболочки. Ядро содержит наночастицу, имеющую средний размер частицы от примерно 5 нм до 500 нм. Наночастица выбрана из диоксида кремния, обработанного или частично обработанного пирогенного диоксида кремния, коллоидного диоксида кремния, композиционных частиц двойного оксида кремния и алюминия, или диоксида титана. Оболочка содержит поперечно-сшитый полимер, содержащий акриламидные повторяющиеся звенья, повторяющиеся звенья акриловой кислоты или ее соли, повторяющиеся звенья 2-акрилоиламино ...

КОМПОЗИЦИЯ И СПОСОБ ИЗВЛЕЧЕНИЯ УГЛЕВОДОРОДНЫХ ФЛЮИДОВ ИЗ ПОДЗЕМНОГО ПЛАСТА

Данное изобретение относится к композиции, включающей способные увеличиваться в объеме полимерные микрочастицы с высокой степенью сшивки, имеющие средний диаметр частиц до увеличения объема от около 0,05 до около 10 микрон и содержание сшивающего агента от 6000 млн.д. до 200000 млн.д. лабильных и от 0 до 300 млн.д. нелабильных сшивающих агентов, и к использованию этой композиции для изменения проницаемости подземных пластов и увеличения скорости мобилизации и/или извлечения углеводородных флюидов, присутствующих в пластах. Техническим результатом является изменение проницаемости подземных пластов и увеличение скорости мобилизации и/или скорости извлечения углеводородных флюидов, находящихся в пластах. 3 н. и 37 з.п. ф-лы, 11 табл.

СПОСОБ ОБРАБОТКИ СКВАЖИНЫ

Группа изобретений относится к способам, применимым к стволу скважины, проходящему через подземный пласт. Способ обработки подземного пласта из ствола скважины, в котором обеспечивают обрабатывающий флюид, содержащий неоднородные частицы, которые содержат разлагаемый материал и стабилизатор. Подают обрабатывающий флюид внутрь указанного отверстия. Формируют пробку в отверстии указанным обрабатывающим флюидом и удаляют пробку. При этом ствол скважины содержит обсадную колонну и по меньшей мере одно отверстие в указанной обсадной колонне, причем указанное отверстие имеет диаметр. При этом обрабатывающий флюид содержит смесь, которая содержит первое количество частиц, имеющих первый средний размер между около 3 мм и 2 см, и второе количество частиц, имеющих второй средний размер между около в 1,6-20 раз меньший, чем первый средний размер частиц, или второе количество чешуек, имеющих второй средний размер до 10 раз меньший, чем первый средний размер частиц. Техническим результатом является ...

СПОСОБ УЛУЧШЕНИЯ ЗАКУПОРИВАНИЯ ВОЛОКНАМИ

Изобретение относится к способу блокирования потока масляно-водной текучей среды с соотношением вода:масло, равным 70:30, через по меньшей мере один проход в подземной формации, через которую проходит ствол скважины, в котором осуществляют: (i) выбор композиций, концентраций и размеров жестких волокон, гибких волокон и твердых тампонирующих частиц; (ii) приготовление масляно-водной текучей среды, в которую добавляют волокна и частицы; и (iii) нагнетание блокирующей масляно-водной текучей среды в проход, при этом волокна образуют сетку поперек прохода, а твердые частицы тампонируют сетку, блокируя поток, причем жесткие волокна имеют диаметр от 20 мкм до 60 мкм и длину от 2 мм до 12 мм, при этом гибкие волокна имеют диаметр от 8 мкм до 19 мкм и длину от 2 мм до 12 мм. Изобретение также относится к интенсификации подземной формации. Изобретение развито в зависимых пунктах формулы изобретения. Технический результат - обеспечение перенаправления текучей среды для интенсификации скважины, что ...

НАБУХАЮЩЕЕ ИЗДЕЛИЕ

Группа изобретений относится к набухающему изделию, а также к способам его изготовления и применения. Технический результат заключается в облегчении набухания изделия под воздействием текучей среды. Набухающее изделие содержит материал матрицы, способный к расслоению материал на основе графена, расположенный в материале матрицы, и интеркалат, расположенный между слоями материала на основе графена. Способный к расслоению материал на основе графена функционально выполнен с возможностью расширения при приложении ультразвуковых частот к материалу на основе графена и с возможностью облегчения набухания набухающего изделия под воздействием выбранной текучей среды посредством сорбирования углеводородов в текучей среде. Набухание обеспечивает взаимодействие набухающего изделия со смежной структурой. 3 н. и 22 з.п. ф-лы, 2 ил.

ЗАТВЕРДЕВАЮЩИЕ КОМПОЗИЦИИ, СОДЕРЖАЩИЕ ЦЕМЕНТНУЮ ПЫЛЬ, И СПОСОБЫ ИХ ПРИМЕНЕНИЯ

Изобретение относится к применению алюминатов щелочных металлов и силикатов щелочных металлов с цементной пылью для получения затвердевающей композиции для применения в подземных операциях. В одном из вариантов реализации изобретения предложен способ, включающий введение в подземный пласт затвердевающей композиции, содержащей цементную пыль, алюминат щелочного металла, силикат щелочного металла и водную несущую текучую среду; и обеспечение возможности схватывания по крайней мере части затвердевающей композиции и тем самым снижения потока флюида через часть подземного пласта. Изобретение развито в зависимых пунктах формулы изобретения. Технический результат - эффективное предотвращение потери циркуляции флюида. 4 н. и 27 з.п. ф-лы, 1 табл., 3 ил.

СПОСОБ ОБРАБОТКИ ПРИЗАБОЙНОЙ ЗОНЫ ПЛАСТА

Изобретение относится к нефтедобывающей промышленности, а именно к технологии интенсификации добычи нефти. Технический результат - повышение стабильности эмульсионных растворов для комплексной технологии интенсификации добычи нефти, получение дополнительной добычи нефти, повышение эффективности на скважинах с высоким дебитом. Способ обработки призабойной зоны пласта - ПЗП, характеризующийся тем, что ПЗП обрабатывают последовательно эмульсионным раствором - ЭР, оторочкой нефти и кислотной композицией, состоящей из 15%-ной соляной кислоты, диэтиленгликоля, уксусной кислоты, гидрофобизатора на основе амидов, ингибитора коррозии и технической воды, причем предварительно определяют смачиваемость горных пород ПЗП продуктивного пласта и в случае гидрофильности горных пород продуктивного интервала применяют ЭР прямого типа следующего состава, мас.%: углеводородная фаза в виде дизельного топлива или подготовленной нефти с нефтесборного пункта 20-25, эмульгатор марки Синол-ЭМ или Синол ЭМИ 3-5, коллоидный ...

СПОСОБ ВРЕМЕННОЙ ИЗОЛЯЦИИ ИНТЕРВАЛА СКВАЖИНЫ, СПОСОБ ПОВТОРНОГО ГИДРОРАЗРЫВА ПЛАСТА И СПОСОБ ГЛУШЕНИЯ СКВАЖИНЫ

Группа изобретений относится к нефтегазовой промышленности и может найти применение при стимулировании подземного пласта с помощью операций гидравлического разрыва пласта, в частности при временной изоляции трещин гидравлического разрыва пласта, при повторном гидравлическом разрыве пласта, а также при глушении скважин. Способ временной изоляции интервала скважины включает закачивание в скважину первой суспензии, содержащей вязкую несущую жидкость, деградируемые частицы и деградируемые волокна, до формирования первого фильтрующего слоя. Закачивают в скважину вторую суспензию, содержащую вязкую несущую жидкость, недеградируемые частицы и деградируемые волокна, до формирования второго фильтрующего слоя. Первая и вторая суспензии не смешиваются при закачивании в скважину. Для оптимальной изоляции интервала объем первой суспензии относится к объему второй суспензии в пропорции от 1:5 до 2:1. Также предложены способ повторного гидроразрыва в интервале с несколькими трещинами ГРП и способ щадящего ...

БИТУМНЫЕ ЭМУЛЬСИИ ДЛЯ ПРИМЕНЕНИЯ В НЕФТЕДОБЫВАЮЩЕЙ ПРОМЫШЛЕННОСТИ

Изобретение относится к интенсификации притока в скважину для увеличения нефтегазодобычи. В способе борьбы с фильтрационными потерями в формации, содержащем закачивание водной жидкости, содержащей эмульсию, стабилизированную поверхностно-активным веществом и имеющую внутреннюю битумную фазу, в формации происходит обращение битумной эмульсии путем прибавления агента-инициатора обращения эмульсии. Изобретение развито в зависимых пунктах формулы. Технический результат – повышение эффективности обработки. 13 з.п. ф-лы, 3 пр., 5 ил.

ПАКЕТ ПОВТОРНО СШИВАЮЩИХСЯ ПОЛИМЕРНЫХ ЧАСТИЦ ДЛЯ КОНТРОЛЯ КОНФИГУРАЦИИ И ПОТЕРИ ЖИДКОСТИ

КОМПОЗИЦИЯ И СПОСОБ ИЗВЛЕЧЕНИЯ УГЛЕВОДОРОДНЫХ ФЛЮИДОВ ИЗ ПОДЗЕМНОГО МЕСТОРОЖДЕНИЯ

... 1. Композиция, включающая расширяемые полимерные микрочастицы, причем микрочастицы включают гидрофобные полимеры, содержащие лабильные боковые группы, где микрочастицы имеют средний диаметр частиц неувеличенного объема от примерно 0,05 до примерно 5000 мкм. ! 2. Композиция по п.1, в которой указанные гидрофобные полимеры включают один или более лабильных мономеров. ! 3. Композиция по п.1, в которой указанные гидрофобные полимеры включают сложный эфир акриловой кислоты и сомономеры, сополимеризованные со сложным эфиром акриловой кислоты. ! 4. Композиция по п.1, включающая эмульсию сложного эфира полиакриловой кислоты с непрерывной водной фазой. ! 5. Композиция по п.4, в которой сложный эфир полиакриловой кислоты включает первичный алкиловый сложный эфир полиакриловой кислоты. ! 6. Композиция по п.5, в которой первичный алкиловый сложный эфир выбран из группы метилового, этилового, пропилового, бутилового и амилового сложных эфиров. ! 7. Композиция по п.1, в которой лабильные боковые группы ...

КОМПОЗИЦИЯ И СПОСОБ ИЗВЛЕЧЕНИЯ УГЛЕВОДОРОДНЫХ ФЛЮИДОВ ИЗ ПОДЗЕМНОГО МЕСТОРОЖДЕНИЯ

... 1. Композиция, включающая по меньшей мере два различных типа сильносшитых расширяемых полимерных микрочастиц, имеющих различную химическую структуру и средний диаметр частиц неувеличенного объема от примерно 0,05 до примерно 5000 мкм, и содержание сшивающих агентов от примерно 100 до примерно 200000 млн-1 лабильных сшивающих агентов и от 0 до примерно 300 млн-1 нелабильных сшивающих агентов. ! 2. Композиция по п.1, в которой по меньшей мере один из типов сшитых полимерных микрочастиц включает лабильные сшивающие агенты, выбранные из диакрилатов и полифункциональных винильных производных полиспирта. ! 3. Композиция по п.1, в которой по меньшей мере один из типов сшитых полимерных микрочастиц выбран из группы, состоящей из сшитых анионных, амфотерных, содержащих ионную пару или бетаинсодержащих полимерных микрочастиц. !4. Композиция по п.3, которая находится в форме эмульсии или водной суспензии. ! 5. Композиция по п.4, в которой по меньшей мере один из типов сшитых полимерных микрочастиц ...

СПОСОБ ОБРАБОТКИ ПОДЗЕМНОЙ ФОРМАЦИИ

МАТЕРИАЛ ГРАВИЙНОГО ФИЛЬТРА (ВАРИАНТЫ) И СПОСОБ УСТАНОВКИ ГРАВИЙНОГО ФИЛЬТРА В СКВАЖИНЕ

... 1. Материал гравийного фильтра, содержащий смесь, содержащую первый объем гравия и второй объем гранул набухающего эластомерного материала, выбранного для расширения при воздействии заранее определенной скважинной текучей среды.2. Материал по п.1, в котором заранее определенная скважинная текучая среда представляет собой воду.3. Материал по п.1, в котором заранее определенная скважинная текучая среда представляет собой комбинацию углеводородов и воды.4. Материал по п.1, в котором гравий содержит частицы, имеющие первый средний размер и гранулы набухающего эластомерного материала имеют второй средний размер, соответствующий первому среднему размеру.5. Материал по п.4, в котором второй средний размер меньше первого среднего размера.6. Материал по п.1, в котором второй объем гранул набухающего эластомерного материала составляет, по меньшей мере, 25% от первого объем гравия.7. Материал по п.1, в котором гранулы набухающего эластомерного материала имеют неправильные формы.8. Материал гравийного ...

ПОКРЫТИЕ ГРАФИТОМ ДИСПЕРСНЫХ МАТЕРИАЛОВ

... 1. Дисперсный материал с импрегнированным графитом покрытием частиц, отличающийся тем, что он выбран из группы, включающей наполнитель для песчано-гравийного фильтра, гранулированный бентонит, размолотый гильсонит, карбонат кальция, стеклянные шарики, минеральную вату, измельченную бумагу, металлические шарики, керамические шарики, скорлупу ореха, перемолотую резину, пластмассовые шарики, белую слюду, обожженный нефтяной кокс и перлит. 2. Дисперсный материал по п.1, отличающийся тем, что покрытие содержит связующее из одной или более природной, синтетической, водорастворимой или органической смолы. 3. Дисперсный материал по п.1 или 2, отличающийся тем, что графит выбран из группы, включающей природный пластинчатый, синтетический и аморфный графит. 4. Дисперсный материал по п.3, отличающийся тем, что средний размер частицы распределяется от 0,001 до 850 мкм. 5. Дисперсный материал по п.1, отличающийся тем, что материал имеет средний размер частицы, который распределяется в пределах от 5 ...

ПРОЦЕСС ДЛЯ ЗАКУПОРИВАНИЯ ПОДЗЕМНЫХ ФОРМАЦИЙ

... 1. Процесс для закупоривания подземных формаций в процессе добычи нефти и/или газа, первый этап, который включает введение абсорбирующих воду частиц в жидкостно-несущие и пористые горные породы, указанными частицами могут быть набухаемые в воде, сшитые и не растворимые в воде полимеры, указанные частицы в водонесущих горных породах в конечном счете предотвращают поток жидкости через пласты пород посредством абсорбции воды, отличающийся тем, что абсорбирующие частицы содержат суперабсорбирующий полимер (САП) с анионными и/или катионными свойствами и действием замедленного набухания.2. Процесс по п.1, отличающийся тем, что САП приготовлен посредством полимеризации этиленненасыщенных виниловых соединений.3. Процесс по любому из пп.1 и 2, отличающийся тем, что он выполняется в водах формации, содержащих соль.4. Процесс по п.1, отличающийся тем, что набухание САП начинается не ранее чем через 5 мин и он приготовлен при помощи, по меньшей мере, одного варианта процесса, выбранного из группы:a ...

РАЗРУШАЕМЫЕ КОНТЕЙНЕРЫ ДЛЯ ДОСТАВКИ В СКВАЖИНУ МАТЕРИАЛОВ И ХИМИЧЕСКИХ ВЕЩЕСТВ

... 1. Способ обработки участка скважины, пересекаемого стволом, средством для обработки, в котором: к скважине доставляют средство для обработки, заключенное в один или более разрушаемых контейнеров, каждый из которых содержит оболочку, вводят один или более разрушаемых контейнеров в закачиваемую в скважину жидкость, и механически разрывают оболочку одного или более разрушаемых контейнеров в стволе скважины или в пласте для выпуска средства для обработки.2. Способ по п.1, в котором один или более разрушаемых контейнеров содержат один или более материалов.3. Способ по п.2, в котором по меньшей мере один из материалов, содержащихся в одном или более контейнеров, выполнен с возможностью разложения.4. Способ по п.1, в котором средство для обработки находится в виде суспензии внутри одного или более контейнеров.5. Способ по п.1, в котором ствол скважины имеет покрытие, причем покрытие перфорировано, наименьший размер одного или более разрушаемых контейнеров больше, чем диаметр перфораций, а один ...

СПОСОБ ФОРМИРОВАНИЯ ИЗОЛИРУЮЩЕЙ ПРОБКИ

... 1. Способ формирования изолирующей пробки, включающий закачку в скважину суспензии с диспергированными в ней волокнами и последующее формирование пробки, изолирующей нужный участок скважины и препятствующей прохождению жидкости, отличающийся тем, что в суспензию добавляют амфифильные вещества, а в качестве волокон используют волокна, обеспечивающие адсорбцию амфифильных веществ на своей поверхности. ! 2. Способ формирования изолирующей пробки по п.1. отличающийся тем, что материал волокна выбирают из группы, включающей ПЭТ-волокно, полимолочную кислоту, полигликолевую кислоту, полиэфир, хлопок, кварцевое стекловолокно, полиамид, протеин, фенолформальдегид, поликарбонат, полиангидрид, эпоксидную смолу. ! 3. Способ формирования изолирующей пробки по п.1, отличающийся тем, что амфифильные вещества добавляют в суспензию в процессе ее приготовления. ! 4. Способ формирования изолирующей пробки по п.1, отличающийся тем, что амфифильные вещества закачивают в скважину до закачки суспензии, или одновременно ...

Способ приготовления тампонажного материала

СПОСОБ ПРИГОТОВЛЕНИЯ ТАМПОНАЖНОГО МАТЕРИАЛА, включающий расплавление битума, введение минеральных добавок и поверхностно-активных веществ и перемешивание до однородной массы, отличающийся тем, что, с целью повыщения удоб(тва хранения, транспортирования и применения тампонажного материала , полученную однородную массу обращают в твердое порощкообразное состояние с удельной поверхностью 500-1500 см/г. (Л ...

Polymere, flüssige Erdverfestigungszusammensetzung und Verfahren zu deren Gebrauch

Swellable glass particles for reducing fluid flow in subterranean formations

Process

Smart filter cake for stengthening formations

Resilient carbon-based materials as lost circulation materials and related methods

Compositions and processes for oil field applications

Emulsifier-free wellbore fluid

Fracture filling drilling fluid comprising resilient polymeric granules

A drilling fluid additive comprises polymeric granules that will fill rock fractures in a well (fig 1A). As the granules fill a fracture the pressure at the end of the fracture reduces and the fracture closes, crushing or squashing the granules (fig 1B). As pressure in the well is raised the fracture will begin to open (fig 1C); the polymeric granules are sufficiently resilient that they expand as the fracture opens. The granules will have a maximum diameter distribution peak between 200 microns and 1000 microns and will have a rebound of at least 10 percent, but preferably 15 percent, after compression by a load of 200 Newtons. The granules can be polypropylene.

Well treating compositions for slow release of treatment agents and methods of using the same

Compositions and processes for oil field applications

Breaker fluids for wellbore fluids and methods of use

Compositions for controlling fluid loss may include an aqueous fluid, a viscosifier, a water soluble polar organic solvent, a delayed acid source, and a weighting agent. The composition may further comprise at least one selected from bridging solids, cleaning agent, dispersant, interfacial tension reducer, pH buffer, thinner, or surfactant. Such compositions may be used in producing a hydrocarbon from a formation by drilling the formation with a drill-in fluid to form a wellbore, emplacing the composition in the wellbore, and shutting the well for a predetermined time to allow the viscosity of the fluid loss composition to decrease.

WELL TREATING FLUID

Well treating fluid.

Shear thickening fluids which comprise a water-swellable material (clay), present in a sufficient concentration so as to be capable of forming a stiff paste upon interaction with the water used, and water wherein the clay and water are kept separated by an intervening hydrocarbon-surfactant composition. The intervening oil phase prevents the interaction between the water and the clay phases and results in a stable, nonreacting, pumpable composite until such time as the oil envelope is ruptured by application of a sufficiently high shear force. Upon such rupture, the materials interact rapidly forming a semi-rigid stiff paste. Various well-control problems, such as oil and gas with blowouts, can be controlled by use of the above described composite. The composite is pumped down the well pipe. Exiting the orifices of the drill bit or a nozzle supplies the shear force needed to rupture the oil envelope thereby permitting the interaction between the clay and the water resulting in the formation ...

Wellbore fluid containing granular hemicellulose material

Fluid loss additive for water based drilling fluids with improved thermal stability

A polymer microsphere for use as a fluid loss additive in drilling muds including a hydrophobic core of hydrophobic monomers and a hydrophilic shell of hydrophilic monomers wherein the hydrophilic shell surrounds the hydrophobic core. The polymer microsphere is capable of forming micelles or microgels in water without using surfactants and can be block, graft, and random copolymers. The hydrophilic shell is physically or chemically linked to the hydrophobic core. The polymer microsphere further includes crosslinkers, preferably where the crosslinkers are monomers containing at least two ethylenically unsaturated groups.

Improvements in treating fluid loss from a borehole

Oil field chemical delivery fluids, methods for their use in the targeted delivery of oil field chemicals to subterranean hydrocarbon reservoirs and methods

Fluid loss additive package for shallow well drilling fluids

Hydrobically treated particulates for improved return permeability

Compositions including a particulate bridging agent and fibers and methods of treating a subterranean formation with the same

Carbon dioxide foamed fluids.

Process of installation of a zone of particles consolidated in a well and composition used for this process.

Composition and method for recovering hydrocarbon fluids from a subterranean reservoir.

Synthetic polymer-based fluid loss pill

Die hier beschriebenen Zusammensetzungen können ein wässriges Fluid, ein vernetztes Polyvinylpyrrolidon (PVP) und ein Polymer auf Betainbasis beinhalten. Die hier beschriebenen Verfahren können Pumpen einer ausgewählten Menge einer Fluidverlustpille in eine Formation beinhalten, wobei die Fluidverlustpille ein vernetztes PVP und ein Polymer auf Betainbasis beinhaltet.

Date tree waste-based binary fibrous mix for moderate to severe loss control

A date tree fiber mix lost circulation material (LCM) is provided. The date tree fiber mix LCM may include includes date tree trunk fibers produced from date tree trunks and date tree leaf and leaf stem fibers produced from date tree leaves and leaf stems. The LCM include a mix of 30 % by weight date tree trunk fibers and 70 % date tree leaf and leaf stem fibers, 40 % by weight date tree trunk fibers and 60 % date tree leaf and leaf stem fibers, 50 % by weight date tree trunk fibers and 50 % date tree leaf and leaf stem fibers. Methods of lost circulation control using and manufacture of a date tree fiber mix LCM are also provided ...

Methods useful for controlling fluid loss in subterranean treatments

Improved drilling fluids

Methods for increase gas production and load recovery

Compositions and methods for recovering hydrocarbon fluids from a subterranean reservoir

The present disclosure is directed to compositions and methods for enhanced oil recovery, for modifying the permeability of subterranean formations and for increasing the mobilization and/or recovery rate of hydrocarbon fluids present in the formations. The compositions may include, for example, expandable cross-linked polymeric microparticles having unexpanded volume average particle size diameters of from about 0.05 to about 5,000 microns and cross linking agent contents of from about 100 to about 200,000 ppm of labile cross linkers and from 0 to about 300 ppm of non-labile cross linkers that may be used in combination with other components such as, for example, a second and different polymeric microparticle, a viscosified aqueous solution, a subterranean reservoir treatment, or combinations thereof.

Methods and compositions comprising a dual oil/water-swellable particle

Methods and compositions are provided that relate to well bore treatments that comprise swellable particles. An embodiment includes a method that comprises introducing a fluid comprising a dual oil/water-swellable particle into a subterranean formation. Another embodiment includes a method of cementing that comprises: introducing a cement composition comprising cement, water, and a dual oil/water-swellable particle into a space between a pipe string and a subterranean formation; and allowing the cement composition to set in the space. Another embodiment includes a well treatment composition comprising a dual oil/water-swellable particle.

An oil or gas treatment fluid containing a chelate or coordination complex that sets

A treatment fluid comprises: a metal oxide, wherein the metal oxide is capable of forming a chelate complex or coordination complex with a ligand, wherein the chelate complex or coordination complex has a setting time of less than 90 minutes at a temperature of 71 °F and a pressure of 1 atmosphere. A method of treating a portion of a subterranean formation comprises: introducing the treatment fluid into the subterranean formation; allowing or causing a chelate complex or coordination complex to form between the metal oxide and a ligand; and allowing or causing the chelate complex or coordination complex to set.

Swellable article

A swellable article, including a matrix material and an exfoliatable graphene-based material disposed in the matrix material. The exfoliatable graphene-based material is operatively arranged to facilitate swelling of the swellable article upon exposure to a selected fluid by sorbing particles in the fluid. The swelling enables the swellable article to engage an adjacent structure. Methods of making and using a swellable article are also included.

Curaua fibers as lost-circulation materials and fluid-loss additives in wellbore fluids

A method and wellbore fluid using Curaua fiber to prevent or cure loss circulation during well operations. The wellbore fluid includes a base fluid and a plurality of Curaua fibers. The wellbore fluid may include concentration up to 120 lb/bbl Curaua fibers. The base fluid may include at least one of water-based fluid, brine-based fluid, oil-based fluid, synthetic -based fluid, or Pneumatic-drilling fluid system. The water-based fluids may further include at least one of seawater, brine, saturated brine, or formate brine. The water-based fluid may include a dispersed system. The water-based fluid may further include a non-dispersed system. The oil- based fluid may include at least one of diesel, mineral oil, and low-toxicity linear olefins and paraffins. The synthetic -based fluid may include at least one of one of esters, internal olefins and linear paraffins. The oil-based and the synthetic -based fluids may further include lime.

Triggerable lost circulation material and method of use

Methods for preventing or alleviating the loss of drilling fluids and other well treatment fluids into a subterranean formation during drilling or construction of boreholes therein include a drilling fluid including a lost circulation material. The lost circulation material includes a suspension of swelled particles of a pH sensitive polymeric material, the swelled particles capable of reversibly attaching to other swelled particles of the polymeric material. The pH of the aqueous solution is such that each particle of the swelled pH sensitive polymeric material is not attached to other swelled particles, and wherein upon lowering the pH of the suspension, the swelled particles attach to each other.

Wellbore servicing compositions and methods of making and using same

A method of servicing a wellbore in a subterranean formation having one or more lost circulation zones comprising placing a wellbore servicing fluid comprising a sealing composition into the wellbore, wherein the sealing composition comprises a latex and an accelerator and wherein the latex, the accelerator or both are encapsulated with an encapsulation material. A wellbore servicing fluid comprising a latex and an accelerator wherein the latex, the accelerator, or both are encapsulated.

Well treatment

The following describes a novel and alternative mechanism in regards to releasing reactive chemicals. Namely, utilizing shells containing multiple emulsions that can be blended with the base fluids, and then react with said base fluid upon exposure to a trigger e.g. high shear and/or elongation flow, therefore plugging even large fractures. Such gelling lost circulation material allows to obtain a reliable carrier and fast reaction when triggered.

Cement compositions and methods utilizing nano-clay

The present invention includes well treatment fluids and methods utilizing nano- particles. An embodiment of a method of the present invention may comprise introducing a treatment fluid comprising nano-clay into a subterranean formation. The treatment fluid may be selected from the group consisting of a cement composition, a drilling fluid, a spacer fluid, and a lost circulation control composition. Another embodiment of the present invention may comprise a method of cementing. The method of cementing may comprise introducing a cement composition comprising a hydraulic cement, nano-clay, and water into a subterranean formation. The method further may comprise allowing the cement composition to set in the subterranean formation. Yet another embodiment of the present invention may comprise a treatment fluid, the treatment fluid comprising nano-clay. The treatment fluid may be selected from the group consisting of a cement composition, a drilling fluid, a spacer fluid, and a lost circulation ...

Protein-based fibrous bridging material and process and system for treating a wellbore

A bridging material for a well treatment fluid that comprises a protein-based fibrous material and at least one additional material is provided. For example, the protein-based fibrous material can be soy protein fiber (SPF). The additional material is a lost circulation material. A process for treating a wellbore penetrating a subterranean formation with minimal or no loss of treatment fluid into the formation is also provided. A system for drilling a wellbore from the surface into a subterranean formation with minimal or no loss of drilling fluid into the formation is also provided.

Enhancing complex fracture networks in subterranean formations

Methods of introducing into a subterranean formation a series of treatment fluids comprising one of micro-proppant particulates, micro-degradable particulates, branch-proppant particulates, branch-degradable particulates, main-proppant particulates, and main-degradable particulates and placing the particulates into portions of microfracture(s), branch fracture(s), and main fracture(s) to increase fracture complexity of a fracture network in the subterranean formation.

Loss circulation material for seepage to moderate loss control

A two-component lost circulation material (LCM) is provided. The two-component LCM includes a polymer component and a sodium hydroxide component. The polymer component may include may include a drilling fluid, a fibrous material such as polypropylene fibers, and an acrylic polymer, such as a 30% acrylic polymer solution. The sodium hydroxide component may include water and sodium hydroxide. The sodium hydroxide component is introduced to contact the polymer component to form the two-component LCM. Methods of lost circulation control and manufacture of a two-component LCM are also provided.

METHOD OF TEMPORARILY PLUGGING PORTIONS OF A SUBTERRANEAN FORMATION USING A DIVERTING AGENT

COLLOIDAL AND COLLOIDAL-LIKE SYSTEMS IN AQUEOUS, CLAY-BASED FLUIDS

The present invention generally relates to improved clay-based compositions comprising colloidal or colloidal-like phases (e.g., emulsions, aphrons) and methods of using those compositions. The compositions generally comprise an aqueous continuous phase, one or more palygorskite-sepiolite group clays, one or more surfactants, aphrons and optionally one or more Aphron Stabilizers. The compositions of the present invention are capable of being used in high-pressure applications.

CONTROLLING COAL FINES IN COAL BED OPERATIONS

The migration of coal fines within a bed is reduced, inhibited or constrained by contacting the fines with nanoparticles, such as magnesium oxide crystals having an average particle size of about 30 nm. These nanoparticles may coat a proppant during the fracturing of a subterranean formation to produce methane from a coal bed therein. The nanoparticles may also treat a proppant pack in a fractured coal bed. The nanoparticles cause the coal fines to thus bind to or associate with the proppants. Thus, most of the coal fines entering fractures away from the near-wellbore region will be restrained or controlled near their origin or source and the production of methane at a desired ievei will be maintained much longer than a similar situation than where the nanoparticies are not used.

NANO-SIZED PARTICLE-COATED PROPPANTS FOR FORMATION FINES FIXATION IN PROPPANT PACKS

A fracturing fluid, gravel pack fluid and/or frac pack fluid containing particles such as proppants, gravel and/.or sand, may contain an effective amount of a nano-sized particulate additive to fixate or reduce fines migration, where the particulate additive is an alkaline earth metal oxide, alkaline earth metal hydroxide, alkali metal oxides, alkali metal hydroxides transition metal oxides, transition metal hydroxides, post-transition metal oxides, post-transition metal hydroxides piezoelectric crystals and pyroelectric crystals. The nano-sized particulate additive is bound to the particles with a coating agent such as an oil. The particle size of the magnesium oxide or other agent may be nanometer scale, which scale may provide unique particle charges that help fixate the formation fines. The carrier fluid used in the treating fluid may be aqueous, brine, alcoholic or hydrocarbon- based.

THICKENER FROM WATER-SWELLABLE MATERIAL, OIL SURFACTANT AND WATER

WELL TREATING FLUID (C-845) The instant invention is directed to shear thickening fluids which comprise a water-swellable material (clay), present in a sufficient concentration so as to be capable of forming a stiff paste upon interaction with the water used, and water wherein the clay and water are kept separated by an intervening hydrocarbon-surfactant composition. The intervening oil phase prevents the interaction between the water and the clay phases and results in a stable, nonreacting, pumpable composite until such time as the oil envelope is ruptured by application of a sufficiently high shear force. Upon such rupture, the materials interact rapidly forming a semi-rigid stiff paste. Various well-control problems, such as oil and gas with blowouts, can be controlled by use of the above-described composite. The composite is pumped down the well pipe. Exiting the orifices of the drill bit or a nozzle supplies the shear force needed to rupture the oil envelope thereby permitting the ...

MULTI-COMPONENT GROUTING SYSTEM

METHOD OF CONSOLIDATING UNCONSOLIDATED OR INSUFFICIENTLY CONSOLIDATED FORMATIONS

METHOD AND COMPOSITION FOR SEALING A SUBSURFACE FORMATION

A method for plugging and sealing subsurface formations using alkaline nanosilica dispersion and a delayed activation chemistry is disclosed. In accordance with one embodiment of the present disclosure, the method includes introducing a mixture with a first pH into the subsurface formation. The mixture comprises an aqueous solution, an alkaline nanosilica dispersion and a water-insoluble hydrolyzable compound. The method further includes allowing the water-insoluble hydrolyzable compound to hydrolyze in the subsurface formation to form an acid at 70°C or greater, thereby acidizing the mixture to a reduced second pH and causing the alkaline nanosilica dispersion to gel into a solid and seal the subsurface formation. A composition for sealing a subsurface formation is also disclosed. The composition includes an aqueous mixture including water, an alkaline nanosilica dispersion, and a water-insoluble hydrolyzable compound.

SEALING APPARATUS WITH SWELLABLE METAL

A sealing apparatus is provided. The sealing apparatus includes a swellable metal. The swellable metal, when exposed to a fluid, is transitionable from an initial configuration having an initial volume to an expanded configuration having an increased volume. The swellable metal, upon transitioning to the expanded configuration in an annulus of a fluid channel, forms a seal against a surface of the fluid channel such that fluid communication across the swellable metal in the annulus is at least partially restricted.

POLYMER-BASED DRILLING FLUIDS CONTAINING NON-BIODEGRADABLE MATERIALS AND METHODS FOR USE THEREOF

MODIFIED BIOPOLYMERS FOR DIVERSION, CONFORMANCE, AND FLUID LOSS CONTROL

Well treatments that use modified biopolymers for diversion, conformance, fluid loss control, and/or other well treatments, including a method of providing conformance, fluid loss control, or diversion in a subterranean formation, comprising: providing a treatment fluid comprising a base fluid and hydrogel particles, wherein the hydrogel particles comprise modified biopolymers that are crosslinked, the modified biopolymers comprising a biopolymer backbone and a side chains derived from synthetic monomers; and introducing the treatment fluid into a subterranean formation penetrated by a wellbore.

RESIN PLUG FOR WELLBORE ABANDONMENT

A resin plug for wellbore abandonment includes: an amount of a heavier resin and an amount of a light weight resin, the heavier resin configured to have a faster setting rate than the light weight resin. The resin plug creates a seal for wellbore abandonment by the heavier resin setting first followed by setting of the light weight resin thereafter. Any void formed during setting of the heavier resin is filled by the light weight resin before the light weight resin sets ...

RE-ASSEMBLING POLYMER PARTICLE PACKAGE FOR CONFORMANCE CONTROL AND FLUID LOSS CONTROL

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

METHOD FOR MAKING A TREATMENT FLUID COMPRISING A DIVERTING AGENT IN FLAKE FORM, AND METHOD OF TREATING A WELL

A method of treating a subterranean formation penetrated by a well-bore, for example to facilitate fracturing of the formation, comprises the steps of: (i) selecting a treatment fluid comprising a diverting agent (A) in a flaked form, for example guar gum in a flaked form. (ii) introducing the treatment fluid into the subterranean formation via the well-bore to plug a region of the formation. Thereafter, the formation may be fractured or re-fractured.

STARCH-CONTAINING MICROSPHERE AND PREPARATION METHOD THEREFOR AND APPLICATION THEREOF

Disclosed is a starch-containing microsphere and a preparation method therefor and an application thereof. The particle size of the starch-containing microsphere exhibits polydispersity with uniform distribution in a particle size concentrated distribution interval, and the particle size distribution in the particle size concentrated distribution interval has the following features: equal division of the particle size concentrated distribution interval into n intervals, and a microsphere percentage in each interval is (I), where n is an integer greater than 1. The preparation method comprises: first reacting starch with a low concentration of epichlorohydrin, and then reacting the resultant product with a surfactant, followed by final crosslinking to give microspheres. The starch-containing microspheres prepared by the present invention are polydisperse starch-containing microspheres with a uniform particle size distribution, with the particle size being in a range of 0.1-500 µm.

OIL-SWELLABLE, DESOLVATED POLYMER GELS AND METHODS OF USING THE SAME FOR PREVENTING LOSS OF NON-AQUEOUS WELLBORE FLUIDS TO THE SUBTERRANEAN FORMATION

An oil-swellable gel lost circulation material (LCM) formed from an elastomeric polymer and a crosslinker amine is provided. The LCM may include gel pieces cut from gel strands formed from an elastomeric polymer and a crosslinker amine. The oil-swellable gel LCM composition may be formed by mixing an elastomeric polymer solution with a crosslinker amine and heating the mixture to form a crosslinked gel. The gel may be extruded through a die having orifices into a non-solvent and allowed to desolvate in the presence of the non-solvent. The gel strands may be dried and cut into gel pieces to form an LCM. The resulting LCM may swell when introduced to a loss circulation zone in the presence of a non-aqueous fluid such as a drilling mud or component of a drilling mud.

ENERGIZED FLUID FOR GENERATING SELF-CLEANING FILTER CAKE

A process for generating and subsequently breaking a filter cake, includi ng dissolving a non-reactive gas in a wellbore fluid to form an energized fl uid; pumping the energized fluid into a formation at a downhole pressure, wh erein the pumping is at overbalanced conditions; producing a filter cake; an d decreasing the down hole pressure to below a cut point of the dissolved ga s in the energized fluid to form a vapor phase, wherein the vapor phase comp romises the integrity of the filter cake is disclosed.

TREATMENT OF SUBTERRANEAN FORMATIONS USING A COMPOSITION INCLUDING A LINEAR TRIBLOCK COPOLYMER AND INORGANIC PARTICLES

The present invention relates to treatment of subterranean formations using compositions that experience an increase in viscosity as a result of the application of heat or shear. In various embodiments, the present invention provides a method of treating a subterranean formation. The method can include obtaining or providing a composition including a linear triblock copolymer and inorganic particles. The method can include at least one of shearing and heating the composition, to increase the viscosity thereof. The method can also include contacting the composition with a subterranean material downhole.

PROTEIN-BASED FIBROUS BRIDGING MATERIAL AND PROCESS AND SYSTEM FOR TREATING A WELLBORE

A bridging material for a well treatment fluid that comprises a protein-based fibrous material and at least one additional material is provided. For example, the protein-based fibrous material can be soy protein fiber (SPF). The additional material is a lost circulation material. A process for treating a wellbore penetrating a subterranean formation with minimal or no loss of treatment fluid into the formation is also provided. A system for drilling a wellbore from the surface into a subterranean formation with minimal or no loss of drilling fluid into the formation is also provided.

METHODS OF ZONAL ISOLATION AND TREATMENT DIVERSION WITH SHAPED PARTICLES

... ?Methods of treating a subterranean formation are disclosed that include introducing a treatment fluid including shaped particle and/or shaped uniform particles into a subterranean formation via a wellbore, and creating a plug including the shaped particle and/or shaped uniform particles of the treatment fluid.

COMPOSITION COMPRISING ULTRAFINE CELLULOSE FIBERS

The present invention addresses the problem of providing a salt water thickener which uniformly (favorably) disperses fine cellulose fibers even in a liquid in which salt (electrolyte) is present. By forming a salt water thickener that comprises fine cellulose fibers and a water soluble polymer, the fine cellulose fibers can be uniformly dispersed even in a liquid containing salt. This salt water thickener exhibits high viscosity since the thickener disperses uniformly even in a liquid containing salt. Additionally, this salt water thickener can be used as an additive to a fluid. For example, the thickener can be used for treatment of a subterranean formation.

LOST CIRCULATION MATERIAL FORMULATION AND METHOD OF USE

A lost circulation material and method for well treatment employing the material that is effective at sealing or plugging small fissures and large fractures and has utility over a wide range of temperatures, including high temperatures. The material has an optimized bimodal particle distribution and optionally has a polymer flocculant or water swellable polymer.

GRAPHITE COATING OF PARTICULATE MATERIALS

A coated particulate is provided with a graphite-impregnated resin coating. The oil field particulates may comprise any of gravel -pack sand, granular betonite, ground Gilsonite, calcium carbonate, glass beads, rock wool, shredded paper, metal spheres, ceramic beads, nut hulls, ground rubber, plastic beads, muscovite mica, calcined petroleum coke, and perlite. The resin may comprise as a binder one or more of a natural, synthetic, water-soluble, and organic resins. More specifically, the resins may comprise an organic film- forming resin such as an alkyd, polyurethane and epoxy. Alternatively, the resin may comprise a film-forming water-soluble polymer, such as a starch, carboxymethyl cellulose, hydroxyethyl cellulose, and xanthan gum. In a further alternative, the resin may comprise a resin-dispersed emulsion, such as a latex or acrylic .

WELL TREATMENT COMPOSITIONS AND METHODS UTILIZING NANO-PARTICLES

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

METHODS FOR MINIMIZING OVERDISPLACEMENT OF PROPPANT IN FRACTURE TREATMENTS

A method of treating a subterranean formation includes generating a fracture in the subterranean formation, introducing a predetermined amount of proppant into a treatment fluid, and subsequently introducing a plugging agent into the treatment fluid before the entire predetermined amount of proppant reaches the fracture, minimizing overdisplacement of the proppant from the fracture.

WELLBORE FLUIDS COMPRISING MINERAL PARTICLES AND METHODS RELATING THERETO

Mineral particles may provide for wellbore fluids with tailorable properties and capabilities, and methods relating thereto. Mineral particles may be utilized in methods that include introducing a wellbore fluid having a density of about 7 ppg to about 50 ppg into a wellbore penetrating a subterranean formation, the wellbore fluid comprising a base fluid and a plurality of mineral particles, and the wellbore fluid having a first viscosity; contacting at least some of the mineral particles with a linking agent so as to link the at least some of the mineral particles, thereby increasing the first viscosity to a second viscosity.

AN OIL OR GAS TREATMENT FLUID CONTAINING A CHELATE OR COORDINATION COMPLEX THAT SETS

A treatment fluid comprises: a metal oxide, wherein the metal oxide is capable of forming a chelate complex or coordination complex with a ligand, wherein the chelate complex or coordination complex has a setting time of less than 90 minutes at a temperature of 71 °F and a pressure of 1 atmosphere. A method of treating a portion of a subterranean formation comprises: introducing the treatment fluid into the subterranean formation; allowing or causing a chelate complex or coordination complex to form between the metal oxide and a ligand; and allowing or causing the chelate complex or coordination complex to set.

PROCESS AND FLUID FOR THE RECOVERY OF OIL IN RESERVOIRS WITH AQUIFER

PROCEDE ET FLUIDE POUR L'AMELIORATION DE LA RECUPERATION D'HUILE DANS LES RESERVOIRS COMPORTANT UN AQUIFERE La présente invention concerne un procédé pour améliorer la récupération d'huile dans un réservoir souterrain comportant un aquifère. Le procédé comporte l'injection dans l'aquifère d'un fluide comportant des produits gonflants au contact de l'huile, créant une barrière de perméabilité à l'interface huile-eau. Le fluide gonflant comporte une dispersion de très fines particules de polymère, par exemple un copolymère styrène-butadiène.

POLYMERIC EARTH SUPPORT FLUID COMPOSITIONS AND METHOD FOR THEIR USE

This invention relates to an earth stabilization fluid and to a method for using such an earth stabilization fluid. This invention uses a continuous phase that has been added to a borehole and a polymer material that forms gel masses having desired functional properties when added to the continuous phase.

METHOD FOR CONTROLLING FLUID LOSS IN HIGH PERMEABILITY FORMATIONS

The present invention provides a method of controlling fluid loss to a permeable formation penetrated by a wellbore. A novel fluid loss agent is prepared by forming a crosslinked polymer gel which then is sheared to break the gel into discrete particles. A slurry then is formed of the particles by dispersing the particles in an aqueous fluid having a density similar to that of the gel particles. The slurry then is introduced into contact with the permeable formation and a filter cake of the particles is formed upon contact with the formation and loss of the slurrying fluid to the formation. The filter cake provides further fluid loss control to the permeable formation.

[POLIELEKTROLITNYE] COMPLEXES FOR THE APPLICATION IN THE REGION OF OIL PRODUCTION AND GAS

COMPOSITIONS AND METHODS OF TREATMENT OF WELLS WITH USE OF NANOPARTICLES

METHOD OF TREATMENT OF UNDERGROUND BEDS

METHOD AND SUBSTANCE FOR CONSOLIDATION OF WELL AT UNDERGROUND OPERATIONS

СМЕСЬ ТЕРМОПЛАСТИКА И ЦЕЛЛЮЛОЗНЫХ ВОЛОКОН В КАЧЕСТВЕ ПЛАСТОЗАКУПОРИВАЮЩЕГО МАТЕРИАЛА

Предложен способ снижения ухода бурового раствора при бурении скважин, применяющий композитные материалы в качестве пластозакупоривающих материалов. Композиты включают термопластичный полимер и целлюлозные волокна. Композиты могут, необязательно, включать другие компоненты, такие как карбонат кальция, глина, масло и другие компоненты смеси.

ЗАМЕДЛЕННО НАБУХАЮЩИЕ В ВОДЕ МАТЕРИАЛЫ И СПОСОБЫ ИХ ИСПОЛЬЗОВАНИЯ

Состав, поглощающий воду, включает частицу, имеющую сердцевину из набухающего в воде материала. Покрытие, по существу, окружает сердцевину, что временно предотвращает контакт воды с набухающим в воде материалом. Покрытие может быть образовано из слоя разлагаемого в воде материала или не разлагаемого в воде, не поглощающего воду инкапсулирующего слоя. Количество частиц, включая замедленно набухающие в воде частицы, образованные, по меньшей мере частично, из набухающего в воде материала, и, возможно выбору, не набухающие в воде частицы тех же самых или других распределений по размерам, может быть использовано при обработке пласта, через который проходит ствол скважины. Суспензия из частиц образована с жидкостью-носителем. Суспензия из частиц вводится в ствол скважины пласта, чтобы облегчить обработку.

METHODS OF TREATMENT OF THE WELLBORE ZONE

Permeability blocking with stimuli-responsive microcomposites

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

Well Treatment Compositions and Methods Utilizing Nano-Particles

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

Methods for Initiating New Fractures in a Completed Wellbore Having Existing Fractures Present Therein

Fracturing operations can be problematic in completed wellbores containing at least one existing fracture, since it can be difficult to seal an existing fracture and initiate a new fracture within a reasonable timeframe due to the presence of particulate materials in the wellbore. Methods for fracturing a completed wellbore can comprise introducing a treatment fluid comprising a plurality of degradable sealing particulates into a completed wellbore penetrating a subterranean formation having an existing fracture therein; sealing the existing fracture with at least a portion of the degradable sealing particulates, thereby forming a degradable particulate seal; after sealing, allowing any degradable sealing particulates remaining in the treatment fluid to degrade, such that the treatment fluid becomes substantially particulate free; and after the treatment fluid becomes substantially particulate free, fracturing the subterranean formation so as to introduce at least one new fracture therein.

Lost Circulation Materials and Methods of Using the Same

A method of servicing a wellbore in contact with a subterranean formation, comprising placing a wellbore servicing fluid comprising a drilling fluid and lost circulation material into a lost circulation zone within the wellbore, wherein the lost circulation material comprises a polyelectrolyte multilayer material and a first counterion. A wellbore servicing fluid comprising a drilling fluid and a lost circulation material comprising a polyelectrolyte multilayer material and a counterion comprising a halide, wherein the LCM has a first state that is hydrophilic. A tunable lost circulation material comprising a base material, a polyelectrolyte multilayer on said base material, wherein the polyelectrolyte multilayer comprises a first electrolyte layer, a second electrolyte layer, and a charged surface, and a counterion, wherein wettability of the lost circulation material is a function of the counterion.

Method and system for sealing a void in an underground wellbore

Voids ( 14 ) in a underground wellbore ( 1 ) are sealed by:—inserting a corrosion prone object ( 10 A-C, 12 ) in the void injecting an oxidizing agent into the void ( 14 ); and—allowing the oxidizing agent to induce corrosion of the corrosion prone object and to thereby generate corrosion products ( 13 A-E) that are physically larger than the corrosion prone object ( 10 A-C, 12 ) and that seal the void ( 14 ).

Method For Reducing Permeability Of A Subterranean Reservoir

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

Date Palm Seed-Based Lost Circulation Material (LCM)

A date palm seed-based lost circulation material (LCM) is provided. A date palm seed LCM may be manufactured by drying date palm seeds and grinding the dried date palm seeds to create a plurality of particles. The particles may have sizes less than 4 mm, from 1 mm to 2 mm, or from 2 mm to 4 mm. The date palm seed LCM may have a volumetric swelling greater than an LCM formed from tree nuts and may have a volumetric swelling of at least 0.3 cubic centimeters per gram. The date palm seed LCM may have a D50 shift factor less than an LCM formed from calcium carbonate and may have a D50 shift factor of at least 0.38%. The date palm seed LCM may have a stability index of at least 0.95. Methods of lost circulation control and manufacture of a date palm seed LCM are also provided. 1. A method to control lost circulation in a lost circulation zone in a wellbore , comprising:introducing an altered drilling fluid into the well bore such that the altered drilling fluid contacts the lost circulation zone and reduces a rate of lost circulation into the lost circulation zone, where the altered drilling fluid comprises a drilling fluid and a lost circulation material (LCM), and where the LCM comprises a plurality of untreated particles comprising ground date palm seeds.2. The method of claim 1 , comprising adding the lost circulation material to the drilling fluid to create the altered drilling fluid.3. The method of claim 1 , wherein the untreated particles consist of ground date palm seeds.4. The method of claim 1 , wherein the LCM consists of a plurality of untreated particles consisting essentially of ground date palm seeds.5. The method of claim 1 , wherein the altered drilling fluid consists of the drilling fluid and the LCM claim 1 , where the LCM consists essentially of a plurality of untreated particles consisting essentially of ground date palm seeds.6. The method of claim 1 , wherein the reduced rate of lost circulation is at least 80% less by volume than before ...

METHODS OF CONTROLLING FINES MIGRATION IN A WELL

A method of treating a subterranean formation penetrated by a wellbore comprises: introducing into the subterranean formation a treatment fluid comprising coated polymeric particles having a polymeric core and a curable thermoset coating disposed on the polymeric core; allowing the curable thermoset coating to cure under downhole conditions; and forming a fluid-permeable pack from the coated polymeric particles, the fluid-permeable pack reducing or substantially preventing the passage of formation particles from the subterranean formation into the wellbore while allowing passage of formation fluids from the subterranean formation into the wellbore. 1. A method of treating a subterranean formation penetrated by a wellbore , the method comprising:introducing into the subterranean formation a treatment fluid comprising coated polymeric particles having a polymeric core and a curable thermoset coating disposed on the polymeric core, the polymeric core comprising a rubber, an epoxy, a phenolic resin, a thermoplastic polymer or a combination comprising at least one of the foregoing, the rubber comprising a nitrile rubber (NBR), a hydrogenated nitrile rubber (HNBR), a styrene-butadiene rubber (SBR), an ethylene propylene diene monomer rubber (EPDM), a natural rubber, a silicone rubber, a polybutadiene, polyisoprene, butyl rubber, or a combination comprising at least one of the foregoing, and the thermoplastic polymer comprising polyetheretherketone (PEEK), a polyimide, a polysulfone, a polyester or polycarbonate;allowing the curable thermoset coating to cure under downhole conditions; andforming a fluid-permeable pack from the coated polymeric particles, the fluid-permeable pack reducing or substantially preventing the passage of formation particles from the subterranean formation into the wellbore while allowing passage of formation fluids from the subterranean formation into the wellbore.2. The method of claim 1 , wherein the polymeric core is a recycled polymeric ...

Date Tree Waste-Based Compound Fibrous LCMs

An altered drilling fluid having a drilling fluid and a date tree waste-based lost circulation material (LCM). The date tree waste LCM may include includes date tree waste fibers produced from one or more of the following: date tree trunks, date tree rachis, date tree leaflets, date tree panicles, and date tree roots. The date tree waste LCM may include fibers having lengths in the range of 5 millimeters (5 mm) to 15 mm, diameters in the range of 0.5 mm to 0.8 mm, and having an aspect ratio range of 6 to 30. Methods of manufacture of a date tree waste LCM are also provided. 1. An altered drilling fluid , comprising:a water-based drilling fluid or an oil-based drilling fluid; anda lost circulation material (LCM), wherein the LCM comprises a plurality of date tree waste fibers produced from at least one of: date tree trunks, date tree rachis, date tree leaves, date tree leaflets, and date tree roots, wherein each of the plurality of date tree waste fibers has a length in the range of 5 millimeters (mm) to 15 mm and the plurality of date tree waste fibers have a moisture content of less than 3% by weight.2. The altered drilling fluid of claim 1 , wherein the water-based drilling fluid comprises water claim 1 , a clay claim 1 , a water hardness remover claim 1 , and a base.3. The altered drilling fluid of claim 2 , wherein the water comprises freshwater or seawater.4. The altered drilling fluid of claim 2 , wherein the water hardness remover comprises soda ash.5. The altered drilling fluid of claim 2 , wherein the base comprises sodium hydroxide.6. The altered drilling fluid of claim 1 , wherein the water-based drilling fluid has a pH of at least 10.7. The altered drilling fluid of claim 1 , wherein the oil-based drilling fluid comprises a base oil claim 1 , a primary emulsifier claim 1 , a secondary emulsifier claim 1 , a viscosifier and filtrate control additive.8. The oil-based drilling fluid of claim 7 , wherein the base oil comprises diesel or crude oil.9. The ...

RHEOLOGY MODIFIER

The composition provided herein includes an aqueous base fluid, a water-based polymer and glass microspheres comprising a metal cross-linking agent and where the water-based polymer cross-links in the presence of the glass microspheres. 1. A composition comprising:an aqueous base fluid, a water-based polymer and glass microspheres comprising a metal cross-linking agent, wherein the water-based polymer cross-links in the presence of the glass microspheres.2. The composition of claim 1 , wherein the composition is essentially free of any cross-linking agent other than the glass microspheres.3. The composition of claim 1 , wherein the glass microspheres are uncoated.4. The composition of claim 1 , wherein the water-based polymer only cross-links with surfaces of the glass microspheres.5. The composition of claim 1 , further comprising salt present in the amount of about 4% (w/v) to about 5% (w/v) of the aqueous base fluid and wherein the presence of salt increases the viscosity of the composition by at least 50 cP.6. The composition of claim 1 , wherein the glass microspheres are present in the amount of about 0.5% (w/v) to about 15% (w/v) based on the total volume of the aqueous base fluid.7. The composition of claim 1 , wherein the glass microspheres are present in the amount of at least about 3% (w/v) based on the total volume of the aqueous base fluid.8. The composition of claim 1 , wherein the glass microspheres are present in the amount of at least about 4% (w/v) based on the total volume of the aqueous base fluid.9. The composition of claim 1 , wherein crosslinks formed during the cross-linking of the water-based polymer in the presence of the glass microspheres are transient and self-degrade in about 1 to about 10 days.10. The composition of claim 1 , wherein the water-based polymer is carboxymethylhydroxyethylcellulose (CMHEC) present in the amount of about 25 lbs to about 50 lbs per about 1000 gallons of the aqueous base fluid.11. The composition of claim 1 , ...

THERMALLY ACTIVATED STRONG ACIDS

An acid-generating fluid includes a thermally activated strong acid precursor. The thermally activated strong acid precursor can include a component selected from aldehydes, ketones, and combinations thereof, in combination with a precursor of a compound adapted to react to liberate sulfur dioxide; or it can include sulfur dioxide in combination with a precursor of a compound adapted to react to liberate a component selected from aldehydes, ketones, and combinations thereof. 1. A method comprising: a precursor of a compound adapted to react to liberate sulfur dioxide, and', 'a component selected from aldehydes, ketones, and combinations thereof;, 'providing an acid-generating fluid that comprises water and a thermally activated strong acid precursor, the thermally activated strong acid precursor comprisingplacing the acid-generating fluid into a subterranean formation;thermally activating the precursor, thereby liberating sulfur dioxide; andreacting the sulfur dioxide and the component selected from aldehydes, ketones, and combinations thereof to form a thermally activated strong acid.2. The method of claim 1 , wherein the precursor is selected from the group consisting of a sulfone adduct of: butadiene claim 1 , a sulfone adduct of piperylene claim 1 , a sulfone adduct of isoprene claim 1 , a sulfite ester claim 1 , and combinations thereof.3. The method of claim 1 , wherein the first precursor is selected from the group consisting of: ethylene sulfite and dimethyl sulfite claim 1 , and combinations thereof.4. The method of claim 1 , wherein the acid-generating fluid further comprises a dienophile.5. The method of claim 4 , wherein the dieneophile and the thermally activated strong acid precursor are provided in a 1:1 molar ratio.6. The method of claim 1 , wherein the acid-generating fluid further comprises a base.7. The method of claim 6 , wherein the base is CaCO.8. The method of claim 1 , wherein the acid-generating fluid is an emulsion.9. The method of claim 1 ...

Lost Circulation Drilling Fluids Comprising Elastomeric Rubber Particles and a Method for Decreasing Whole Mud Loss Using Such Composition

The disclosed invention is a unique drilling fluid composition and method for reducing lost mud circulation in wellbores due to seepage loss into fluid permeable subterranean formations. The drilling fluid composition comprises a variety of shapes and sizes of distinctive unadulterated elastomeric rubber particles derived from the tire retreading (recapping) process. These elastomeric rubber particles are incorporated into an aqueous, hydrocarbon, or synthetic drilling fluid in sufficient amounts as to plug holes, fractures, and fissures, form a mud cake, and thus stem the loss of drilling fluids from the lost circulation zone.

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

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

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

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

SMART FILTRATE FOR STRENGTHENING FORMATIONS

A method of sealing a formation that includes drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising a first sealing component into the wellbore, wherein the non-aqueous based wellbore fluid filters into the formation as a filtrate and substantially thickens is disclosed. The substantially thickening may result from adding a second sealing component to the wellbore fluid, whereby the first sealing component initiates a reaction of the second sealing component. 1. A method of sealing a formation , comprising:drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising a first sealing component into the wellbore, wherein the non-aqueous based wellbore fluid filters into the formation as a filtrate and substantially thickens.2. The method of claim 1 , wherein the substantially thickening results from adding a second sealing component to the wellbore fluid claim 1 , whereby the first sealing component initiates a reaction of the second sealing component.3. The method of claim 2 , wherein the second sealing component is at least one of a peroxide claim 2 , modified persulfate claim 2 , metallocene claim 2 , dispersed silicon carbide claim 2 , or dispersed carbonaceous material chosen from the group including: graphite claim 2 , graphene claim 2 , graphene oxide claim 2 , glassy carbon claim 2 , carbon nanofoam claim 2 , buckminsterfullerene claim 2 , buckypaper claim 2 , nanofiber claim 2 , nanoplatelets claim 2 , nano-onions claim 2 , nanoribbons claim 2 , nanohorns claim 2 , single- or multi-walled carbon nanotubes claim 2 , carbon black claim 2 , carbon nanotubes claim 2 , and derivatives thereof.4. The method of claim 3 , wherein the second sealing component is encapsulated.5. The method of claim 4 , wherein the encapsulant is a composition comprising a dissolvable component.6. The method of claim 5 , wherein the dissolvable component is a high temperature wax.7. The method of ...

Hydrobically Treated Particulates For Improved Return Permeability

Compositions, methods, and systems for using particulates treated with one or more hydrophobizing agents in forming filter cakes during drilling to improve filter-cake removal. A method for drilling a wellbore may include circulating a drilling fluid in the wellbore, wherein the drilling fluid comprises particulates treated with one or more hydrophobizing agents; extending the wellbore while the drilling fluid is circulated in the wellbore; and forming a filter cake in the wellbore, wherein the filter cake comprises a portion of the particulates from the drilling fluid.

THERMALLY ACTIVATED STRONG ACIDS

An acid-generating fluid comprising a thermally activated strong acid precursor. 1. An acid-generating fluid comprising a thermally activated strong acid precursor.2. The acid-generating fluid of claim 1 , wherein the thermally active strong acid precursor comprises an SOprecursor.3. The acid-generating fluid of claim 1 , wherein the thermally active strong acid precursor comprises a sulfone adduct of butadiene claim 1 , a sulfone adduct of piperylene claim 1 , a sulfone adduct of isoprene claim 1 , a sulfite ester claim 1 , or any combination thereof.4. The acid-generating fluid of claim 1 , wherein the thermally active strong acid precursors comprises ethylene sulfite or dimethyl sulfite.5. The acid-generating fluid of claim 1 , wherein the thermally activated strong acid precursor comprises an aldehyde or ketone precursor.6. The acid-generating fluid of claim 1 , wherein the aldehyde or ketone precursor comprises paraformaldehyde claim 1 , polyoxymethylene claim 1 , metaldehyde claim 1 , trioxane claim 1 , formaldehyde claim 1 , acetaldehyde claim 1 , or any combination thereof.7. The acid-generating fluid of claim 1 , wherein the thermally activated strong acid precursor comprises SOand an aldehyde or ketone precursor in a ratio of 1:1.8. The acid-generating fluid of claim 1 , wherein the thermally activated strong acid precursor comprises an SOprecursor and aldehyde or ketone in an amount sufficient to generate a strong acid at a concentration of from 0.1% to 10% by weight of the acid-generating fluid.9. The acid-generating fluid of claim 1 , wherein the thermally activated strong acid precursor comprises an SOprecursor and an aldehyde or ketone precursor in an amount sufficient to generate a strong acid at a concentration of from 1% to 5% by weight of the acid-generating fluid.10. The acid-generating fluid of claim 1 , further comprising water.11. The acid-generating fluid of claim 1 , further comprising a dienophile.12. The acid-generating fluid of claim 10 , ...

PROPPANT-FIBER SCHEDULE FOR FAR FIELD DIVERSION

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

SMART FILTER CAKE FOR STRENGTHENING FORMATIONS

A method of sealing a formation that includes drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising an encapsulated first component into the wellbore, the non-aqueous based wellbore fluid forming a filter cake on the walls of the wellbore; and adding a second component to the wellbore fluid when fluid losses are registered during drilling, whereby the first and second components react to form a chemical sealing layer in the filter cake is disclosed. 1. A method of sealing a formation , comprising:drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising an encapsulated first component into the wellbore, the non-aqueous based wellbore fluid forming a filter cake on the walls of the wellbore; andadding a second component to the wellbore fluid when fluid losses are registered during drilling, wherebythe first and second components react to form a chemical sealing layer in the filter cake.2. The method of claim 1 , wherein the first component is encapsulated in a composition comprising a dissolvable component.3. The method of claim 2 , wherein the dissolvable component is a high temperature wax.4. The method of claim 3 , wherein the dissolvable component is carnauba wax.5. The method of claim 1 , wherein the first component is at least one of a sodium or potassium silicate in solid or solution form.6. The method of claim 5 , wherein the second component is at least one of an amine claim 5 , alcohol claim 5 , or ester/amide hydrolyzable in downhole conditions to produce an alcohol/amine.7. The method of claim 6 , wherein the alcohol or alcohol produced from the hydrolysis of the ester is at least one of ethanol claim 6 , glycerol claim 6 , or any two to ten carbon molecule containing at least one alcohol group.8. The method of claim 5 , wherein the second component is at least one of calcium chloride claim 5 , strontium chloride claim 5 , or aluminum sulfate.9. The method of claim ...

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

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

ENGINEERED LOSS CONTROL SLURRY WITH IMPROVED PERFORMANCE

Modified Drilling fluid compositions and methods for using drilling fluid compositions are provided with enhanced loss control properties where the modified drilling fluid may include a carrier fluid, one or more drilling fluid additives, and a loss control material blend. The loss control material blend may include a particle component of sized particulate comprising a plurality of a mixture of untreated date seed particles and a fibrous component comprising a mixture of hard date leaflet fibers and soft date tree fibers prepared from date tree waste materials. Methods to control lost circulation in a lost circulation zone in a wellbore may include introducing a modified drilling fluid into the wellbore such that the modified drilling fluid contacts the lost circulation zone. 1. A modified drilling fluid comprising:a carrier fluid;one or more drilling fluid additives; anda loss control material blend comprising:a particle component of sized particulate comprising a mixture of untreated date seed particles,and a fibrous component comprising a mixture of hard date leaflet fibers and soft date tree fibers prepared from date tree waste materials.2. The modified drilling fluid of claim 1 , further comprising one or more loss control additive materials.3. The modified drilling fluid of claim 1 , wherein the loss control material blend is comprised in an amount ranging from 180 to 200 ppb claim 1 , with respect to the modified drilling fluid.4. The modified drilling fluid of claim 1 , wherein the mixture of untreated date seed particles are comprised in an amount ranging from 20 to 50 ppb claim 1 , with respect to the modified drilling fluid.5. The modified drilling fluid of claim 1 , wherein the loss control composition comprises the mixture of hard date leaflet fibers and soft date tree fibers in an amount ranging from 20 to 50 ppb claim 1 , with respect to the modified drilling fluid.6. The modified drilling fluid of claim 1 , wherein each particle of the mixture of ...

Wellbore sealant using nanoparticles

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

Methods of treating oil and gas well fractures

Embodiments of the present disclosure provide for loss circulation materials, methods of making loss circulation materials, methods treating oil and gas well fractures using loss circulation materials, and the like.

KITS AND COMPOSITIONS CONTAINING VINYL ALCOHOL POLYMERS AND FIBERS

Disclosed are compositions and kits of fibers and acid-functional vinyl alcohol polymers, wherein such compositions and kits are useful for wellbore remediation as applied to a subterranean formation traversed by the borehole of an oil or gas well. 115-. (canceled)16. A composition comprising a blend of a particulate polyvinyl alcohol component and a fiber component , wherein the particulate polyvinyl alcohol component comprises a polyvinyl alcohol resin and a plasticizer , and the fiber component comprises one or more fibers.17. The composition of claim 16 , wherein the particulate polyvinyl alcohol component comprises one or more acid-functional polyvinyl alcohol resins.18. The composition of claim 17 , wherein the particulate polyvinyl alcohol component comprises an at least partially hydrolyzed copolymer of vinyl acetate with one or more acid-functional comonomers selected from the group consisting of (i) a monocarboxylic unsaturated acid claim 17 , (ii) a dicarboxylic unsaturated acid claim 17 , (iii) an alkyl ester of (i) claim 17 , (iv) an alkyl ester of (ii) claim 17 , (v) an alkali metal salt of (i) claim 17 , (vi) an alkali metal salt of (ii) claim 17 , (vii) an alkaline earth metal salt of (i) claim 17 , (viii) an alkaline earth metal salt of (ii) claim 17 , (ix) an anhydride of (i) claim 17 , and (x) an anhydride of (ii).19. The composition of claim 18 , wherein the acid-functional polyvinyl alcohol resin has (i) a degree of solubility in deionized water at a temperature in the range of about 50° C. to about 70° C. of at least about 3 wt % and yet not more than about 30 wt %; and (ii) a degree of solubility in deionized water at a temperature in the range of about 90° C. to about 110° C. of at least about 75 wt % and yet not more than about 100 wt %.20. The composition of claim 16 , wherein the fiber component comprises a fiber characterized by (i) a water dissolution temperature of about 60° C. or more and yet about 100° C. or less; and/or (ii) a fiber ...

WELLBORE SERVICING COMPOSITIONS AND METHODS OF MAKING AND USING SAME

A method of servicing a wellbore in a subterranean formation having one or more lost circulation zones comprising placing a wellbore servicing fluid comprising a sealing composition into the wellbore, wherein the sealing composition comprises a latex and an accelerator and wherein the latex, the accelerator or both are encapsulated with an encapsulation material. A wellbore servicing fluid comprising a latex and an accelerator wherein the latex, the accelerator, or both are encapsulated. 1. A method of servicing a wellbore in a subterranean formation having one or more lost circulation zones comprising:placing a wellbore servicing fluid in a wellbore, the wellbore servicing fluid comprising a latex and an accelerator;wherein the latex is selected from the group consisting of a solid latex or a latex emulsion;wherein the latex is encapsulated with a first encapsulation material;wherein the first encapsulation material deteriorates; andwherein in the absence of the first encapsulation material, the latex and the accelerator react to form a sealing composition.2. The method of claim 1 , wherein the sealing composition forms a mass on the surface of a subterranean formation or a mass within a lost circulation zone claim 1 , the mass being operable to reduce or eliminate the loss of material to a lost circulation zone.3. The method of claim 1 , wherein the first encapsulation material comprises at least two coatings claim 1 , each coating being selected from the group consisting of a first coating claim 1 , a second coating claim 1 , and an external coating.4. The method of claim 1 , wherein the latex is coated with a material that reacts with water to form the first encapsulation material.5. The method of claim 1 , wherein the accelerator is encapsulated with the first encapsulation material or a second encapsulation material.6. The method of claim 5 , wherein the first encapsulation material or the second encapsulation material comprise at least two coatings claim 5 , ...

Breaker Fluids for Wellbore Fluids and Methods of Use

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

COMPOSITIONS AND METHODS FOR SERVICING SUBTERRANEAN WELLS

Well treatment compositions comprise water, a polysaccharide and cellulose fibers. The cellulose fibers may have lengths between 100 nm and 10 mm, and diameters between 4 nm and 40 μm. The compositions may be used as spacer fluids during well cementing operations. The spacer fluids may prevent commingling of a cement slurry with a drilling fluid. The drilling fluid may be water-base, oil-base, synthetic-base or an emulsion. 1. A method for treating a subterranean well , comprising:(i) preparing a composition that comprises water, a water soluble polymer and cellulose fibers; and(ii) placing the composition in the well.2. The method of claim 1 , wherein the composition displaces and removes a drilling fluid from the subterranean well.3. The method of claim 1 , wherein the water soluble polymer comprises a polysaccharide or a synthetic polyelectrolyte or both.4. The method of claim 3 , wherein the polysaccharide comprises carboxymethyl cellulose claim 3 , the carboxymethyl cellulose having a molecular weight between 100 kDa and 2000 kDa claim 3 , and being present at a concentration between 0.001 wt % and 1 wt %.5. The method of claim 1 , wherein the cellulose fibers have lengths between 100 and 10 mm claim 1 , and diameters between 4 nm and 40 μm.6. The method of claim 1 , wherein the composition further comprises a halide salt.7. The method of claim 1 , wherein the composition further comprises a portland cement claim 1 , a weighting agent claim 1 , a surfactant claim 1 , a clay claim 1 , a solvent or an antifoam agent or a combination thereof.8. A method for cementing a subterranean well claim 1 , comprising:(i) preparing a composition that comprises water, a water soluble polymer and cellulose fibers;(ii) placing the composition in the well; and(iii) placing a cement slurry in the well,wherein the composition separates the cement slurry and a drilling fluid.9. The method of claim 8 , wherein the drilling fluid is water-base claim 8 , oil-base claim 8 , synthetic- ...

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

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

Nanoparticle-Based Shear-Thickening Materials

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

Fiber suspending agent for lost-circulation materials

A treatment fluid comprises: a base fluid; a lost-circulation material, wherein the lost-circulation material inhibits or prevents some or all of the treatment fluid from penetrating into a subterranean formation from a wellbore, wherein the wellbore penetrates the subterranean formation; and a suspending agent, wherein the suspending agent consists of a plurality of fibers, and wherein the suspending agent provides a lost-circulation material distribution of at least 30% for a test treatment fluid consisting essentially of the base fluid, the lost-circulation material, and the suspending agent at the temperature of a lost-circulation zone of the subterranean formation and static aging for at least 1 hour.

Date Tree Trunk-Based Fibrous Loss Circulation Materials

A date tree trunk-based lost circulation material (LCM) is provided. The date tree trunk LCM includes date tree trunk fibers produced from date tree trunks. The date tree trunks may be obtained from the date tree waste produced by the processing of date trees in the production of date fruits. The date tree trunk LCM may include fibers having lengths less than 8 millimeters (5 mm) and having an aspect ratio range of 10 to 15. Methods of lost circulation control using a date tree trunk LCM and manufacture of a date tree trunk LCM are also provided.

Diversion Using Solid Particulates

A method may comprise: introducing a treatment fluid into a wellbore penetrating a subterranean formation wherein the treatment fluid comprises a base fluid; a carbonate compound, wherein the carbonate compound at least partially plugs a zone in the subterranean formation; and an acid; and diverting at least a portion of the treatment fluid and/or a subsequently introduced fluid away from the zone. 1. A method comprising: a base fluid;', 'a carbonate compound, wherein the carbonate compound at least partially plugs a zone in the subterranean formation; and', 'an acid; and, 'introducing a treatment fluid into a wellbore penetrating a subterranean formation wherein the treatment fluid comprisesdiverting at least a portion of the treatment fluid and/or a subsequently introduced fluid away from the zone.2. The method of wherein the carbonate compound comprises magnesium carbonate claim 1 , calcium carbonate claim 1 , or combinations thereof.3. The method of wherein the acid is a solid acid with a solubility of less than about 5% by weight in water at 110° F. for one hour.4. The method of wherein the acid comprises a solid acid selected from the group consisting of ethylenediaminetetraacetic acid claim 1 , citric acid claim 1 , formic acid claim 1 , benzoic acid claim 1 , and combinations thereof.5. The method of wherein the treatment fluid further comprises a retarding agent comprising an oil-wetting surfactant claim 1 , polymers coating the carbonate compound claim 1 , or combinations thereof.6. The method of wherein the treatment fluid further comprises a retarding agent selected from the group consisting of sodium dodecylbenzenesulfonate claim 1 , emulsions of 2-ethylhexyl acrylate claim 1 , and combinations thereof.7. The method of wherein the retarding agent is present in an amount of about 0.1% to about 5% by weight of the carbonate compound.8. The method of further comprising introducing a fracturing fluid into the wellbore wherein the fracturing fluid comprises ...

Compositions and methods for diverting injected fluids to achieve improved hydrocarbon fluid recovery

The present disclosure is directed to compositions and methods that may be used for enhanced oil recovery, for modifying the permeability of subterranean formations and for increasing the mobilization and/or recovery rate of hydrocarbon fluids present in the formations. The compositions may include, for example, expandable cross linked polymeric microparticles having an unexpanded volume average particle size diameter of from about 0.05 to about 5,000 microns and a cross linking agent content of from about 100 to about 200,000 ppm of hydrolytically labile silyl ester or silyl ether crosslinkers and from 0 to about 300 ppm of non-labile crosslinkers.

COMPOSITE DIVERSION PARTICLE AGGLOMERATION

The present disclosure relates to material for use in oil and gas well completion activities. More particularly, the present disclosure relates to diversion particles, along with methods for making and using the diversion particles. In an embodiment, a composite diversion material includes a non-degradable component comprising two or more non-degradable particulates, wherein the non-degradable particulates have a long term permeability at 7,500 psi of at least about 20 D. The composite diversion material includes a degradable component surrounding at least a portion of the non-degradable component. In another embodiment, a method of making a composite diversion material includes mixing non-degradable proppant particles with an aqueous solution containing a first degradable material to provide a mixture having a proppant concentration of at least about 20 volume percent. The method includes drying the mixture at a temperature of from about 25° C. to about 200° C. to provide the composite diversion material. 1. A composite diversion material , comprising:a non-degradable component comprising two or more non-degradable particulates, wherein the non-degradable particulates have a long term permeability at 7,500 psi of at least about 20 D; anda degradable component surrounding at least a portion of the non-degradable component.2. The composite diversion material of claim 1 , wherein the non-degradable particulates comprise ceramic proppant.3. The composite diversion material of claim 2 , wherein the ceramic proppant has a bulk density of less than 3 g/cc.4. The composite diversion material of claim 3 , wherein the ceramic proppant has a silica concentration of about 0.1 wt % to about 70 wt %.5. The composite diversion material of claim 4 , wherein the ceramic proppant has size from about 20 mesh to about 150 mesh.6. The composite diversion material of claim 4 , wherein the ceramic proppant has size from about 5 mesh to about 14 mesh.7. The composite diversion material of ...

DEGRADABLE OBJECT

A degradable object including a shell comprising a degradable material, a substance disposed at least partially within the shell, the substance having a coefficient of thermal expansion greater than a coefficient of thermal expansion of the shell. 1. A degradable object comprising:a shell comprising a degradable material;a substance disposed at least partially within the shell, the substance having a coefficient of thermal expansion greater than a coefficient of thermal expansion of the shell.2. The object as claimed in wherein the substance is a fluid.3. The object as claimed in wherein the substance is a solid.4. The object as claimed in wherein the substance is a mixture.5. The object as claimed in wherein the substance comprises aluminum claim 1 , magnesium claim 1 , gallium claim 1 , copper claim 1 , lithium claim 1 , mercury claim 1 , polymer composites claim 1 , Polyvinyl Chloride (PVC) claim 1 , water claim 1 , salt water claim 1 , gasoline claim 1 , turpentine claim 1 , diesel claim 1 , glycerin claim 1 , ethanol claim 1 , rubber compounds claim 1 , rock salt claim 1 , epoxies claim 1 , thermoplastics claim 1 , natural waxes claim 1 , paraffin waxes claim 1 , polyethylene waxes and combinations and combinations including at least one of the foregoing.6. The object as claimed in wherein the degradable material is a controlled electrolytic metallic material.7. The object as claimed in wherein the shell includes a plurality of pieces.8. The object as claimed in wherein the pieces are hemispherical.9. The object as claimed in wherein the pieces are mechanically connectable to one another.10. The object as claimed in wherein the pieces are chemically connectable to one another.11. The object as claimed in wherein the shell includes a rupture panel.12. The object as claimed in wherein the rupture panel is a separate component attached to the shell.13. The object as claimed in wherein the rupture panel is a more easily degradable portion of the shell.14. The ...

Sphere-Shaped Lost Circulation Material (LCM) Having Straight Protrusions

A lost circulation material (LCM) that includes spheres having radially distributed and substantially-straight protrusions to facilitate engagement (such as interlocking and entanglement) of the spheres is provided. Each sphere has a plurality of protrusions to contact protrusions of adjacent spheres. The spheres may form plugs in channels, fractures, and other openings in a lost circulation zone. Additionally or alternatively, the spheres may form a bridge on which other LCMs may accumulate to seal openings in a lost circulation zone. Methods of preventing lost circulation using the spheres are also provided. 1. A method to control lost circulation in a lost circulation zone in a wellbore , comprising: a sphere body; and', 'a plurality of substantially-straight protrusions, each protrusion extending outward from a surface of the sphere body;', 'wherein a first protrusion of a sphere of the plurality of spheres is configured to contact a second protrusion of an adjacent sphere such that the plurality of spheres form a structure., 'introducing an altered carrier fluid into the wellbore such that the altered carrier fluid contacts the lost circulation zone, wherein the altered carrier fluid comprises a carrier fluid and a lost circulation material (LCM), wherein the LCM comprises a plurality of spheres, each sphere comprising2. The method of claim 1 , wherein the LCM consists of the plurality of spheres.3. The method of claim 1 , wherein the carrier fluid comprises an oil-based drilling mud or a water-based drilling mud.4. The method of claim 1 , wherein the LCM comprises a first LCM claim 1 , the method comprising:introducing an altered drilling fluid into the wellbore such that the altered drilling fluid contacts the lost circulation zone, wherein the altered drilling fluid comprises a drilling fluid and a second LCM, such that the second LCM accumulates on the structure.5. The method of claim 1 , wherein each sphere of the plurality of spheres has a diameter in the ...

RESERVOIR TREATMENTS

The present invention relates to the field of enhanced oil recovery and provides a method of establishing a plug in a hydrocarbon reservoir, the method comprising introducing into the reservoir a formulation comprising solid particles and a viscosifier and then reducing the viscosity of said viscosifier, thereby causing said solid particles to form a plug within said hydrocarbon reservoir. Also provided is a method of establishing a plug in a hydrocarbon reservoir, the method comprising introducing into the reservoir a formulation comprising: 121-. (canceled)22. A formulation comprising:(a) microorganisms or cell-free enzymes;(b) solid particles; and(c) a viscosifier which is a substrate for the microorganisms or cell-free enzymes of (a);wherein the solid particles (i) are substantially spherical, and (ii) have a core which is not deformable and an outer layer which is deformable.23. The formulation of claim 22 , further comprising growth medium.24. The formulation of claim 22 , wherein the microorganisms or cell-free enzymes are saccharolytic or lignocellulolytic.25Clostridium thermocellumAcidothermus cellulolyticus.. The formulation as claimed in claim 22 , wherein the microorganisms are claim 22 , or wherein the cell-free enzymes are from claim 22 , or26. The formulation of claim 22 , wherein the viscosifier comprises claim 22 , cellulose claim 22 , hemicellulose or a derivative thereof or a polysaccharide gum.27. The formulation of claim 26 , wherein the viscosifier comprises a polyanionic cellulose or a microfibrillated cellulose.28. The formulation of claim 27 , wherein the viscosifier comprises carboxymethyl cellulose.29. The formulation of claim 22 , wherein the solid particles have the same density as the rest of the formulation.30. The formulation of claim 22 , wherein the solid particles are substantially uniform in size.31. The formulation of claim 22 , wherein the formulation is made up of 25-70% by volume of the solid particles.32. The formulation of ...

Device for pressing in cellulose fiber nano-dispersion, method for pressing in cellulose fiber nano-dispersion using same, and hydrocarbon production method

A cellulose fiber nano-dispersion pressing-in device for pressing a liquid, in which a cellulose fiber of a conifer-derived pulp is nano-dispersed, into a stratum, includes a grinding means for grinding the conifer-derived pulp in water, a dilution means for diluting a cellulose fiber-containing liquid obtained in the grinding means and a pressing-in means for pressing a nano-dispersion of the cellulose fiber obtained in the dilution means into a well. Therefore, it is applicable to water-stopping operation in a civil engineering process or to a process of industrial production of hydrocarbons such as crude oil, gas and the like for improving the recovery rate thereof.

PARTICULATE POLYVINYL ALCOHOL COMPOSITIONS HAVING REDUCED DUST CONTENT

Provided are low dust-content particulate polyvinyl alcohol-based compositions suitable for a variety of end uses including for use in subterranean treatments and for manufacturing chemical materials, which are prepared by compacting a specified polyvinyl alcohol polymer resins, optionally with specified additives and/or other polyvinyl alcohols. 1. A particulate polyvinyl alcohol composition comprising compacted particles of a polyvinyl alcohol composition comprising a polyvinyl alcohol polymer , wherein (i) the polyvinyl alcohol polymer has a viscosity in the range of from about 10 to about 125 mPa·s , (ii) the particulate composition has a bulk density in the range of from about 0.30 to about 0.80 g/cm3 , and (iii) more than about 99 wt % of the particles have a particle size of 325 mesh or larger.2. The composition of claim 1 , which has a content of free dust fines of polyvinyl alcohol polymer in an amount of less than about 3%.3. The composition of claim 1 , wherein the polyvinyl alcohol polymer comprises a polyvinyl alcohol homopolymer.4. The composition of claim 1 , wherein the polyvinyl alcohol polymer comprises a copolymer prepared from a vinyl ester monomer and a monomer selected from the group consisting of an unsaturated acid or a derivative thereof claim 1 , an olefinic monomer claim 1 , and mixtures thereof.5. The composition of claim 1 , further comprising a second polyvinyl alcohol polymer selected from the group consisting of a (a) polyvinyl alcohol homopolymer claim 1 , and (b) a copolymer prepared from a vinyl ester monomer and a monomer selected from the group consisting of an unsaturated acid or a derivative thereof claim 1 , an olefinic monomer claim 1 , and mixtures thereof.6. The composition of claim 1 , wherein the polyvinyl alcohol polymer is a transition product.7. The composition of claim 1 , further comprising a plasticizer selected from the group consisting of water claim 1 , glycerol claim 1 , polyglycerol claim 1 , ethylene glycol ...

Well Treatment Fluid Having an Acidic Nanoparticle Based Dispersion and a Polyamine

A well treatment fluid having an acidic nanosilica dispersion and a polyamine activator and methods of reducing water production using the well treatment fluid. The acidic nanosilica dispersion and the polyamine activator may form a gelled solid after interaction over a period. 1. A method to reduce water production in a treatment zone in a wellbore , comprising:introducing a treatment fluid into the wellbore such that the treatment fluid contacts the treatment zone and reduces the water production in the treatment zone, wherein the treatment fluid comprises an acidic nanosilica dispersion and a polyethylene polyamine.2. The method of claim 1 , wherein the treatment fluid consists of the acidic nanosilica dispersion and the polyethylene polyamine.3. The method of claim 1 , wherein the polyethylene polyamine comprises at least one of diethylenetriamine claim 1 , ethylenediamine claim 1 , tetraethylenepetamine (TEPA) claim 1 , triethylentetramine claim 1 , pentaethylenehexamine (PEHA) claim 1 , and hexaethyleneheptamine (HEHA).4. The method of claim 1 , wherein the polyethylene polyamine comprises an amount in the range of 0.1 percent by volume of the total volume (v/v %) to 20 v/v %.5. The method of claim 1 , comprising maintaining the acidic nanosilica dispersion and the polyethylene polyamine in contact with the treatment zone for a period claim 1 , such that the acidic nanosilica dispersion and the polyethylene polyamine form a gelled solid.6. The method of claim 1 , wherein the period comprises a range of 0.5 hours to 24 hours.7. The method of claim 1 , comprising mixing the acidic nanosilica dispersion and the polyethylene polyamine to form the treatment fluid at the surface before introducing the treatment fluid into the wellbore.8. The method of claim 1 , wherein the treatment fluid comprises at least one of calcium carbonate particles claim 1 , fibers claim 1 , mica claim 1 , and graphite.9. The method of claim 8 , wherein the fibers comprise at least one of ...

Well Treatment Fluid Having an Acidic Nanoparticle Based Dispersion and a Polyamine

A well treatment fluid is provided having an acidic nanosilica dispersion and a polyamine activator. The acidic nanosilica dispersion and the polyamine activator may form a gelled solid after interaction over a period. Methods of reducing water production using the well treatment fluids are also provided.

Solids in borehold fluids

Solid polymer objects have size at least 0.5 mm in each of three orthogonal dimensions and shape such that each object has one or more edges, points or corners and/or has a plurality of projections which extend out from a core portion. Such objects may be included in a drilling fluid as a lost circulation additive intended to bridge fractures and mitigate fluid loss. Their angular shape features make it harder for them to slide over fracture faces or each other and helps them to bridge a fracture. A method of making these objects provides a travelling endless belt made of elastomer and defining mould cavities. The mould cavities are filled with a polyerisable liquid composition, which is cured in the mould as the belt advances, and the cured objects are ejected from a mould as the belt bends around a roller.

Polyglycolic acid resin short fibers for use in well treatment fluid

Polyglycolic acid resin short fibers for a well treatment fluid, the fibers having the following characteristics of (a) to (e): (a) an outside diameter of 5 to 300 μm; (b) a fiber length of 1 to 30 mm; (c) fineness of 0.1 to 25 D; (d) strength of 1 to 20 gf/D; and (e) a ratio of an area of the polyglycolic acid resin with respect to an area of a circle circumscribing a cross section of the fibers being from 10 to 95%; and a well treatment fluid containing the polyglycolic acid resin short fibers for a well treatment fluid.

High-Temperature Resistant, High-Strength, and Thixotropic Gel Plugging Agent and Its Preparation Method and Application

The invention provides a high-temperature resistant, high-strength, and thixotropic gel plugging agent and its preparation method and application. The said gel plugging agent is composed of raw materials in the following mass percent: 8-20% acrylamide monomer, 0.05-0.5% reactive polymer, 0.1-1.0% organic polymer cross-linker, 3.0-8.0% resin toughening agent, 1.0-5.0% flow pattern regulator, 0.01-0.5% cross-linking regulator, and water in the remaining percentage. The gel solution in the invention shows a low apparent viscosity during the shear flow and is easy to be pumped into the wellbore and then into the formation leakage layer; after the pumping stops, the gel solution shows rapidly increased viscosity and strong adhesive force, so it can stay in the leakage layers easily and form a high-strength barrier between the wellbore and the formation, preventing the drilling fluid from further leaking 1. A high-temperature resistant , high-strength , and thixotropic gel plugging agent , characterized in that it comprises raw materials in the following mass percent: 8-20% acrylamide monomer , 0.05-0.5% reactive polymer , 0.1-1.0% organic polymer cross-linker , 3.0-8.0% resin toughening agent , 1.0-5.0% flow pattern regulator , 0.01-0.5% cross-linking regulator , and water in the remaining percentage.2. The high-temperature resistant claim 1 , high-strength claim 1 , and thixotropic gel plugging agent according to claim 1 , characterized in that it comprises raw materials in the following mass percent: 12-18% acrylamide monomer claim 1 , 0.1-0.3% reactive polymer claim 1 , 0.3-0.8% organic polymer cross-linker claim 1 , 4.0-7.0% resin toughening agent claim 1 , 2.0-4.0% flow pattern regulator claim 1 , 0.05-0.2% cross-linking regulator claim 1 , and water in the remaining percentage.3. The high-temperature resistant claim 1 , high-strength claim 1 , and thixotropic gel plugging agent according to claim 1 , characterized in that the said reactive polymer is a ...

Date Tree Leaflet-Based Flaky Lost Circulation Material

A lost circulation material (LCM) having flakes formed from date tree leaflets is provided. The flakes of the date tree leaflet LCM may be formed by tearing and shredding date tree leaflets from date trees. The date tree leaflets may be obtained from date tree pruning performed by date tree farming industries. The date tree leaflet LCM may be added to o a drilling fluid to mitigate or prevent lost circulation in a well. Methods of lost circulation control with the date tree leaflets LCM are also provided. 1. A method to control lost circulation in a lost circulation zone in a wellbore , comprising:introducing an altered drilling fluid into the wellbore such that the altered drilling fluid contacts the lost circulation zone and reduces a rate of lost circulation into the lost circulation zone, where the altered drilling fluid comprises a drilling fluid and a lost circulation material (LCM), wherein the LCM comprises a plurality of processed date tree leaflets.2. The method of claim 1 , wherein the altered drilling fluid consists of the drilling fluid and the LCM.3. The method of claim 1 , wherein the LCM consists of the plurality of processed date tree leaflets.4. The method of claim 1 , wherein the plurality of processed date tree leaflets comprise a concentration of at least 10 pounds-per-barrel in the altered drilling fluid.5. The method of claim 1 , wherein the processed date tree leaflets comprise untreated date tree leaflets.6. The method of claim 1 , wherein the plurality of processed date tree leaflets comprises a plurality of flakes.7. The method of claim 6 , wherein the plurality of flakes comprises shredded date tree leaflets.8. The method of claim 6 , wherein each of the plurality of flakes has a length in the range of 5 millimeters (mm) to 8 mm.9. The method of claim 6 , wherein each of the plurality of flakes has a width in the range of 3 millimeters (mm) to 5 mm.10. The method of claim 6 , wherein each of the plurality of flakes has a thickness in the ...

SHAPE-ADAPTABLE LOST CIRCULATION MATERIAL FOR MODERATE AND SEVERE LOSS CONTROL

Modified Drilling fluid compositions, lost circulation material compositions and methods for using drilling fluid compositions are provided with enhanced loss control properties where the modified drilling fluid may include a carrier fluid, one or more drilling fluid additives, and a lost circulation shape-adaptable material. The loss lost circulation shape-adaptable material may include a plurality of oval shaped composite particles, wherein the plurality of oval shaped composite particles comprise a first component, a second component, and a high temperature, high pressure (HTHP) binding adhesive. Methods to control lost circulation in a lost circulation zone in a wellbore may include introducing a modified drilling fluid into the wellbore such that the modified drilling fluid contacts the lost circulation zone.

Silicon Dioxide Janus Nanosheets Relative Permeability Modifier (RPM) for Reducing Subterranean Formation Water Permeability in Carbonate and Sandstone Formations

A silicon oxide Janus nanosheets relatively permeability modifier (RPM) for carbonate and sandstone formations. The silicon oxide Janus nanosheets RPM may be used to treat a water and hydrocarbon producing carbonate or sandstone formation to reduce water permeability in the formation and increase the production of hydrocarbons. The silicon oxide Janus nanosheets RPM for carbonate formations includes a first side having negatively charged functional groups and a second side having alkyl groups. The silicon oxide Janus nanosheets RPM for sandstone formations includes a first side having positively charged functional groups and a second side having alkyl groups. The negatively charged functional groups may include a negatively charged oxygen group groups and hydroxyl groups. The positively charged functional groups may include amino groups and an amine. Methods of reducing water permeability using the silicon oxide Janus nanosheets RPM and methods of manufacturing the silicon oxide Janus nanosheets RPM are also provided.

CROSSLINKING FLUIDS, METHODS FOR DELAYING GEL CROSSLINKING OF SAID FLUIDS, AND APPLICATIONS OF SAID FLUIDS

Crosslinking fluids and methods configured for delaying gel crosslinking of the crosslinking fluid are provided. The crosslinking fluids and methods comprise mixtures of at least one crosslinking polymer, at least one crosslinker configured for crosslinking the at least one crosslinking polymer, at least one crosslink delay trigger configured for initiating crosslinking at a predetermined pH value and comprising at least one low reactivity magnesium oxide, and polar protic solvent. The at least one low reactivity magnesium oxide is produced by calcination of magnesium carbonate ore or magnesium hydroxide ore at a calcining temperature of at least 1,000° C.

Methods and apparatuses for controlling fines migration in a wellbore

A method of controlling fines migration in a wellbore penetrating a subterranean formation, the method comprising: introducing into the wellbore a screen mesh in an unexpanded form disposed of a first tubular member having a body with apertures, the screen mesh comprising a degradable material; expanding the screen mesh; injecting a cement slurry into the wellbore to fill open spaces within the expanded screen mesh; allowing the cement slurry to set forming a set cement that reduces or substantially preventing the passage of formation particles from migrating from the subterranean formation into the wellbore; and removing the degradable material of the screen mesh forming a fluid pathway in the set cement, which allows a formation fluid to flow from the subterranean formation into the wellbore.

Acid soluble flakes as lost circulation material

Compositions and methods for formulating lost circulation materials are provided. More particularly, in certain embodiments, the present disclosure relates to drilling fluids that comprise chitosan flakes as a lost circulation material. In one embodiment, the method comprises: introducing a drilling fluid into a wellbore penetrating at least a portion of a subterranean formation, wherein the drilling fluid comprises: a base fluid; and a lost circulation material comprising chitosan flakes; and forming a filter cake or LCM plug with the chitosan flakes in at least a portion of the subterranean formation.

METHOD FOR INHIBITING WATER PERMEATION IN AN EXTRACTION WELL OF A HYDROCARBON FLUID FROM AN UNDERGROUND RESERVOIR

A method for inhibiting water permeation in an extraction well of a hydrocarbon fluid from an underground reservoir containing: supplying a water-in-oil emulsion an oily continuous phase and an aqueous discontinuous phase containing a plurality of particles of at least one hydrogel containing a cationic polymer; and positioning the water-in-oil emulsion in contact with the underground reservoir. The present invention also concerns a treatment fluid for hydrocarbon fluid extraction wells containing the aforementioned water-in-oil emulsion and the related preparation process. 1. A method for inhibiting water permeation in an extraction well of a hydrocarbon fluid from an underground reservoir , the method comprising: an oily continuous phase, and', 'an aqueous discontinuous phase comprising a plurality of particles of at least one hydrogel comprising a cationic polymer; and, 'supplying a water-in-oil emulsion comprisingpositioning the water-in-oil emulsion in contact with the underground reservoir.2. The method according to claim 1 , wherein the cationic polymer comprises a monomeric unit having at least one cationic group.3. The method according to claim 2 , wherein the at least one cationic group is a —N—RRRgroup claim 2 , wherein R claim 2 , Rand Rare independently H or a C-Calkyl group.4. The method according to claim 1 , wherein the cationic polymer comprises at least one monomeric unit corresponding to a monomer selected from the group consisting of a water-soluble salt of [2-(methacryloyloxy)ethyl] trimethylammonium and a water-soluble salt of 2-(acryloyloxy) ethyl trimethyl ammonium.5. The method according to claim 4 , wherein the cationic polymer comprises a comonomeric unit corresponding to a monomer selected from the group consisting of: poly(ethylene glycol)methyl ether acrylate claim 4 , poly(ethylene glycol)methyl ether methacrylate claim 4 , acrylamide and methacrylamide.6. The method according to claim 5 , wherein a weight ratio of the comonomeric unit ...

SUSPENSION OF ASSOCIATIVE POLYMERS FOR THE TREATMENT OF UNDERGROUND FORMATIONS

This invention relates to the field of techniques for treating subterranean formations with gels during an oil or gas exploration or production operation, i.e., during drilling, completion, or hydraulic fracking processes. The invention relates in particular to a system making it possible to limit or even inhibit the phenomena known as loss of fluids (wager and/or gas) in an underground formation, particularly in a zone where the temperature is high. 1. A suspension (S) , comprising:an aqueous phase containing salts; andwithin said aqueous phase, associative polymer-based (p) particles (P).2. The suspension according to claim 1 , wherein the salts are selected from monovalent claim 1 , divalent claim 1 , and multivalent salts.3. The suspension according to claim 1 , wherein the salt content is at least 5% claim 1 , by mass of the total mass of the aqueous phase of the suspension (S).4. The suspension according to claim 1 , wherein the degree of hydration of the particles (p) is less than 50 g/g.5. The suspension according to claim 1 , wherein the associative polymer has a weight average molecular weight (Mw) greater than 500 claim 1 ,000 g/mol.6. The suspension according to claim 1 , wherein the associative polymer (P) comprises at least one chain (C) obtained by micellar polymerization.7. The suspension according to claim 6 , in which the chain (C) of the associative polymer (P) is obtained by a method comprising a step (E) of micellar radical polymerization in which the following is brought into contact within an aqueous medium (M):hydrophilic monomers (mh), dissolved or dispersed in said aqueous medium (M);hydrophobic monomers (mH) in the form of a micellar solution; andat least one radical polymerization initiator, wherein the initiator is water-soluble or water-dispersible; andat least one radical polymerization control agent.8. The suspension according to claim 7 , wherein the hydrophilic monomers (mh) are selected from (meth)acrylamide monomers including: ...

Hydrolyzable particle compositions, treatment fluids and methods

A composition, treatment fluid and method using hydrolyzable fines. A treatment fluid, which may optionally include a high solids content fluid (HSCF) and/or an Apollonianistic solids mixture, includes a fluid loss control agent comprising a dispersion of hydrolyzable fines, optionally with one or more of a surfactant, plasticizer, dispersant, degradable particles, reactive particles and/or submicron particles selected from silicates, γ-alumina, MgO, γ-Fe2O3, TiO2, and combinations thereof.

Fibrous barriers and deployment in subterranean wells

A fibrous plugging device for use in a subterranean well can include a body having fibers and a retainer material. The retainer material retains a shape of the body. A system for use with a well can include a fibrous plugging device conveyed by fluid flow in the well. The fibrous plugging device includes a body comprising multiple fibers. The fibrous plugging device engages an opening in the well, and thereby seals off the opening. A method for use with a well can include flowing a fluid through the well, thereby conveying at least one fibrous plugging device including a body having multiple fibers, and the fibrous plugging device sealingly engaging an opening in the well, thereby substantially preventing flow through the opening.

Mixing and Injecting Fiber-based Stimulation Fluids

An emulsion is mixed with fibers while the emulsion is moving through a surface tubing using a venturi. The fiber/emulsion mixture is injected into a pressurized tank and the pressurized fiber/emulsion mixture is injected from the pressurized tank into a desired location in a wellbore. Pumps and pressure boosters may be used to move the fluid.

FLUID DIVERSON COMPOSITION IN WELL STIMULATION

Described are methods and compositions for treating a subterranean formation. The method comprising introducing into the subterranean formation via a well-bore a diverter composition, the diverter composition comprising a combination of at least one deformable particle and at least one non-deformable particle; and allowing the diverter composition to block the flow of at least a portion of a treatment fluid from a first location within the well-bore to a second location. 1. A diverter composition comprising a combination of deformable particles and non-deformable particles.2. The diverter composition of claim 1 , wherein the deformable particles are present from about 1 wt % to about 99 wt % of the diverter composition.3. The diverter composition of claim 1 , wherein the deformable particles are swellable particles.4. The diverter composition of claim 1 , wherein the deformable particles comprise crosslinked polyacrylamide claim 1 , crosslinked polyacrylate claim 1 , crosslinked hydrolyzed polyacrylonitrile claim 1 , salts of carboxyalkyi starch claim 1 , salts of carboxymethyl starch claim 1 , salts of carboxyalkyi cellulose claim 1 , hydroxylethyl cellulose claim 1 , salts of crosslinked carboxyalkyi polysaccharide claim 1 , crosslinked copolymers of acrylamide and acrylate monomers claim 1 , starch grafted with acrylonitrile and acrylate monomers claim 1 , crosslinked polymers of two or more of allylsulfonates claim 1 , 2-acrylamido-2-methyl-1-propanesulfonic acid claim 1 , 3-allyloxy-2-hydroxy-1-propane-sulfonic acid claim 1 , diallyl-dimethylammonium salts claim 1 , benzyl-diallylmethylammonium salts claim 1 , methacrylamidopropyltrimethylammonium salts claim 1 , acrylamidopropyltrimethylammonium salts claim 1 , acrylamide claim 1 , acrylic acid claim 1 , acrylate monomers claim 1 , N-vinylformamide claim 1 , N-vinylpyrrolidone claim 1 , vinyl acetate claim 1 , and any combination thereof.5. The diverter composition of claim 1 , wherein the deformable particles ...

USED AUTOMOBILE TIRES AS LOSS CIRCULATION MATERIAL

An automobile tire that is unsuitable to carry an automobile is obtained. Tire chips are formed from the obtained automobile tire. The tire chips are mixed with a quantity of wellbore carrier fluid to form a mixture. The mixture is used as loss circulation material during a wellbore drilling operation. 1. A method comprising:flowing a mixture of tire chips and wellbore carrier fluid into a wellbore being drilled at a first pressure, wherein the tire chips are compressed by the first pressure; andflowing the mixture at a second pressure, less than the first pressure, wherein the tire chips expand in response to the second pressure, wherein tire chips at least partially seals loss circulation zones in a formation in which the wellbore is being drilled after the tire chips have expanded.2. The method of claim 1 , wherein the wellbore carrier fluid comprises water claim 1 , bentonite claim 1 , soda ash claim 1 , or sodium hydroxide.3. The method of claim 1 , further comprising claim 1 , obtaining a used vehicle tire and cleaning the obtained used vehicle tire.4. The method of claim 3 , further comprising forming the tire chips claim 3 , wherein forming the tire chips comprises shredding the cleaned used vehicle tire to form a plurality of tire pieces claim 3 , wherein at least some of the plurality of tire pieces are larger than at least some of the tire chips.5. The method of claim 4 , further comprising granulating the plurality of tire pieces into the tire chips.6. The method of claim 5 , wherein granulating the tire chips comprises removing steel and fiber in the used vehicle tire.7. The method of claim 6 , wherein the steel is removed magnetically.8. The method of claim 6 , wherein the fiber is removed using a combination of shaking screens and wind sifters.9. The method of claim 1 , wherein the tire chips range in size between 250 microns and 5 millimeters. This application is a continuation of and claims the benefit of priority to U.S. patent application Ser. No. ...

WELLBORE SERVICING COMPOSITIONS AND METHODS OF MAKING AND USING SAME

A method of servicing a wellbore in a subterranean formation having one or more lost circulation zones comprising placing a wellbore servicing fluid comprising a sealing composition into the wellbore, wherein the sealing composition comprises a latex and an accelerator and wherein the latex, the accelerator or both are encapsulated with an encapsulation material. A wellbore servicing fluid comprising a latex and an accelerator wherein the latex, the accelerator, or both are encapsulated. 1. A method of servicing a wellbore in a subterranean formation having one or more lost circulation zones comprising:placing a wellbore servicing fluid in a wellbore, the wellbore servicing fluid comprising a latex and an accelerator;wherein the latex is selected from the group consisting of a solid latex or a latex emulsion;wherein the latex is encapsulated with a first encapsulation material;wherein the first encapsulation material deteriorates; andwherein in the absence of the first encapsulation material, the latex and the accelerator react to form a sealing composition.2. The method of claim 1 , wherein the sealing composition forms a mass on the surface of a subterranean formation or a mass within a lost circulation zone claim 1 , the mass being operable to reduce or eliminate the loss of material to a lost circulation zone.3. The method of claim 1 , wherein the first encapsulation material comprises at least two coatings claim 1 , each coating being selected from the group consisting of a first coating claim 1 , a second coating claim 1 , and an external coating.4. The method of claim 1 , wherein the latex is coated with a material that reacts with water to form the first encapsulation material.5. The method of claim 1 , wherein the accelerator is encapsulated with the first encapsulation material or a second encapsulation material.6. The method of claim 5 , wherein the first encapsulation material or the second encapsulation material comprise at least two coatings claim 5 , ...

COMPOSITE DIVERSION PARTICLE AGGLOMERATION

The present disclosure relates to material for use in oil and gas well completion activities. More particularly, the present disclosure relates to diversion particles, along with methods for making and using the diversion particles. In an embodiment, a composite diversion material includes a non-degradable component comprising two or more non-degradable particulates, wherein the non-degradable particulates have a long term permeability at 7,500 psi of at least about 20 D. The composite diversion material includes a degradable component surrounding at least a portion of the non-degradable component. In another embodiment, a method of making a composite diversion material includes mixing non-degradable proppant particles with an aqueous solution containing a first degradable material to provide a mixture having a proppant concentration of at least about 20 volume percent. The method includes drying the mixture at a temperature of from about 25° C. to about 200° C. to provide the composite diversion material. 1. A composite diversion material , comprising: the non-degradable component comprises three or more non-degradable particulates, wherein the non-degradable particulates are configured to have a long term permeability at 7,500 psi of at least about 20 D; and', 'the degradable component is coated onto and encapsulates the non-degradable component, wherein a portion of the degradable component is disposed between at least two of the three or more non-degradable particulates;, 'an agglomeration of a non-degradable component and a degradable component, whereinwherein the degradable component comprises a tracer material.2. The composite diversion material of claim 1 , wherein the non-degradable particulates comprise sand or ceramic proppant.3. The composite diversion material of claim 2 , wherein the ceramic proppant has a bulk density of less than 3 g/cc.4. The composite diversion material of claim 3 , wherein the ceramic proppant has a silica concentration of about 0 ...

FLUID LOSS CONTROL PACKAGE FOR USE IN SUBTERRANEAN FORMATION OPERATIONS

Methods and systems including introducing a treatment fluid into a subterranean formation, wherein the treatment fluid comprises a base fluid and a fluid loss control package (FLCP). The FLCP comprises rigid non-degradable particulates and pliable degradable particulates. The FLCP forms a fluidic seal in the subterranean formation at a target interval, thereby providing fluid loss control therein. 1. A method comprising: 'wherein the treatment fluid comprises a base fluid and a fluid loss control package (FLCP), the FLCP comprising rigid non-degradable particulates and pliable degradable particulates; and', 'introducing a treatment fluid into a subterranean formation,'}forming a fluidic seal with the FLCP in the subterranean formation at a target interval, thereby providing fluid loss control therein.2. The method of claim 1 , wherein the fluidic seal has a permeability of less than about 0.1 darcies.3. The method of claim 1 , further comprising degrading the pliable degradable particulates to enhance the breakdown and removal of at least a portion of the fluidic seal.4. The method of claim 1 , further comprising flowing back the treatment fluid and producing a formation fluid from the subterranean formation claim 1 , and during flow back of the treatment fluid and the production of the formation fluid claim 1 , degrading the pliable degradable particulates to enhance the breakdown and removal of least a portion of the fluidic seal claim 1 ,wherein the degraded pliable degradable particulates are removed from the subterranean formations with the flow back of the treatment fluid and/or with the production of the formation fluid.5. The method of claim 1 , wherein the fluidic seal is a temporary filtercake formed on a surface selected from the group consisting of a packed proppant pack claim 1 , formation wall claim 1 , a fracture face claim 1 , and any combination thereof.6. The method of claim 1 , wherein the fluidic seal is formed in an opening selected from the ...

FLOW CONTROL IN SUBTERRANEAN WELLS

A method of restoring flow through an opening in a well, the opening being blocked by a plugging device, can include conveying a well tool into the well, contacting the plugging device with the well tool, and permitting flow through the opening as a result of the contacting step. Another method of restoring flow through an opening blocked by a plugging device in a well can include conveying a well tool into the well, reducing pressure in the well with the well tool, and permitting flow through the opening as a result of the pressure reducing step. 115-. (canceled)16. A method of restoring flow through an opening blocked by a plugging device in a well , the method comprising:conveying a well tool into the well;reducing pressure in the well with the well tool; andpermitting flow through the opening as a result of the pressure reducing.17. The method of claim 16 , wherein the plugging device comprises a body that prevents flow through the opening prior to the pressure reducing.18. The method of claim 17 , wherein the body comprises a knot.19. The method of claim 17 , wherein the body comprises a degradable material.20. The method of claim 19 , wherein the degradable material is selected from the group consisting of poly-vinyl alcohol claim 19 , poly-vinyl acetate claim 19 , poly-methacrylic acid claim 19 , poly-lactic acid and poly-glycolic acid.21. The method of claim 17 , wherein the plugging device further comprises claim 17 , extending outwardly from the body claim 17 , at least one of the group consisting of fibers and lines.22. The method of claim 21 , wherein the at least one of the group consisting of fibers and lines extends through the opening prior to the pressure reducing.23. The method of claim 17 , wherein the plugging device further comprises claim 17 , extending outwardly from the body claim 17 , at least one of the group consisting of film claim 17 , tube claim 17 , filament claim 17 , fabric and sheet material.24. The method of claim 23 , wherein the ...

MAGNETORHEOLOGICAL FLUIDS AND METHODS OF USING SAME

Described herein are methods of cementing at least a portion of a well comprising feeding a magnetorheological cementitious slurry to a well and applying a magnetic field to the magnetorheological cementitious slurry concurrent with at least a portion of said feeding step to cause a mechanical response in said magnetorheological cementitious slurry in the well. Also disclosed herein are methods of temporarily blocking at least a portion of a well comprising providing a magnetorheological fluid in a well, applying a magnetic field to cause a mechanical response in said magnetorheological fluid thereby blocking at least a portion of the well, and removing the magnetic field to unblock the portion of the well. Also disclosed herein is a magnetorheological cement. 1. A magnetorheological cement , comprising:a hydraulic cement; anda plurality of magnetic particles.2. The magnetorheological cement of claim 1 , wherein the plurality of magnetic particles comprises a mixture of spheroidal particles and rod-like particles.3. The magnetorheological cement of claim 1 , wherein a mean minimum dimension of the plurality of magnetic particles is from 2-200 micrometers.4. The magnetorheological cement of claim 1 , wherein the plurality of magnetic particles have a bimodal size distribution.5. The magnetorheological cement of claim 4 , wherein a first mode of the bimodal size distribution has a mean minimum dimension of from 2-50 micrometers claim 4 , and wherein a second mode of the bimodal size distribution has a mean minimum dimension of from 100-200 micrometers.6. The magnetorheological cement of claim 1 , wherein the hydraulic cement comprises a plurality of cement particles claim 1 , and wherein a mean particle size ratio between the plurality of magnetic particles and the plurality of cement particles is from 4:1 to 1:4.7. The magnetorheological cement of claim 6 , wherein the mean particle size of the plurality of magnetic particles is similar to the mean particle size of ...

Composition and Method of Manufacturing of Whole Date Palm Seed Lost Circulation Material (LCM)

A lost circulation material (LCM) that includes whole date palm seeds. The whole date palm seeds LCM includes date palm seeds having lengths greater than 22.6 millimeters (mm), date palm seeds having lengths in the range of 16 mm to 22.6 mm, and date palm seeds having lengths in the range of 1 mm to less than 16 mm. Method of manufacturing the whole date palm seeds LCM include washing and drying whole date palm seeds, such that the drying includes air-drying, hot rolling, and cooling. Methods of reducing lost circulation are also provided.

Method for temporary isolation of well interval, method for hydraulic refracturing, and method for well killing

A method for temporary isolation of a well interval is proposed, the method comprising: pumping a first slurry into the well, the slurry comprising a viscous carrier fluid, degradable particulates, and degradable fibers, until a first filter cake is formed; and pumping a second slurry into the well, the slurry comprising a viscous carrier fluid, non-degradable particulates, and degradable fibers, until a second filter cake is formed. The first and the second slurries are not mixed when pumped into the well. To ensure optimum interval isolation, the ratio of the volume of the first slurry to the volume of the second slurry should be in the range 1:5 to 2:1. A method for hydraulic refracturing within an interval with several hydraulic fractures and a non-damaging well killing method are also proposed. The technical result is manifested in no formation damage and degradation of the sealing layer formed.

DEGRADABLE BALLS FOR USE IN SUBTERRANEAN APPLICATIONS

Degradable balls for downhole use may include an incompliant degradable polymer and a compliant filler material, the incompliant degradable polymer having an elastic modulus of about 2 GPa or greater, and the compliant filler material having an elastic modulus of less than about 2 GPa. Such degradable balls may be useful in sealing segments of a wellbore and actuating wellbore tools. 1. A degradable ball for downhole use , the degradable ball comprising: an incompliant degradable polymer and a compliant filler material , the incompliant degradable polymer having an elastic modulus of about 2 GPa or greater , and the compliant filler material having an elastic modulus of less than about 2 GPa.2. The degradable ball of claim 1 , wherein the incompliant degradable polymer comprises at least one selected from the group consisting of poly(glycolic acid) claim 1 , crystalline poly(lactic acid) claim 1 , semi-crystalline poly(lactic acid) claim 1 , a polyhydroxyalkonate claim 1 , poly(hydroxybutyrate) claim 1 , an aliphatic polyester claim 1 , a polycarbonate claim 1 , an aliphatic polycarbonate claim 1 , a polyorthoester claim 1 , polyethylene terephthalate claim 1 , a copolymer thereof claim 1 , and a blend thereof.3. The degradable ball of claim 1 , wherein the compliant filler material comprises at least one selected from the group consisting of a vulcanized rubber particle claim 1 , a rubber fiber claim 1 , a thermoplastic particle claim 1 , a thermoplastic fiber claim 1 , a hollow glass sphere claim 1 , a hollow ceramic sphere claim 1 , a hollow metal sphere claim 1 , a hollow thermoplastic sphere claim 1 , a particulate of a compliant degradable polymer claim 1 , and any combination thereof.4. The degradable ball of claim 1 , wherein the compliant filler material comprises a plurality of particulates having an average diameter of about 50 nm to about 500 nm.5. The degradable ball of claim 1 , wherein the compliant filler material comprises a plurality of ...

COMPOSITIONS INCLUDING A PARTICULATE BRIDGING AGENT AND FIBERS AND METHODS OF TREATING A SUBTERRANEAN FORMATION WITH THE SAME

The present invention relates to compositions including a particulate bridging agent and fibers, and methods of treating a subterranean formation with the same. In various embodiments, the present invention provides a method of treating a subterranean formation that includes obtaining or providing a composition including a particulate bridging agent and fibers. The method includes placing the composition in a subterranean formation. The method includes forming within the formation a bridging agent-fiber diverter. The bridging agent-fiber diverter is formed from the composition including the bridging agent and the fibers. 1122-. (canceled)123. A method of treating a subterranean formation , the method comprising:placing in the subterranean formation a composition comprising a particulate bridging agent and fibers; andforming a bridging agent-fiber diverter from the composition within the subterranean formation.124. The method of claim 123 , wherein the composition is a hydraulic fracturing fluid.125. The method of claim 123 , wherein the composition further comprises a proppant.126. The method of claim 123 , further comprising degrading the bridging agent-fiber diverter.127. The method of claim 123 , further comprising using a fracturing fluid to hydraulically fracture the subterranean formation after forming the bridging agent-fiber diverter.128. The method of claim 123 , further comprising placing an acid treatment composition in the subterranean formation after forming the bridging agent-fiber diverter.129. The method of claim 123 , wherein the fibers comprise at least one of vegetable fibers claim 123 , wood fibers claim 123 , human fibers claim 123 , animal fibers claim 123 , mineral fibers claim 123 , metallic fibers claim 123 , carbon fibers claim 123 , silicon carbide fibers claim 123 , fiberglass fibers claim 123 , cellulose fibers claim 123 , and polymer fibers.130. The method of claim 123 , wherein the fibers comprise at least one of polyamide fibers claim ...

FLUID LOSS ADDITIVE FOR WATER BASED DRILLING FLUIDS WITH IMPROVED THERMAL STABILITY

A polymer microsphere for use as a fluid loss additive in drilling muds including a hydrophobic core of hydrophobic monomers and a hydrophilic shell of hydrophilic monomers wherein the hydrophilic shell surrounds the hydrophobic core. The polymer microsphere is capable of forming micelles or microgels in water without using surfactants and can be block, graft, and random copolymers. The hydrophilic shell is physically or chemically linked to the hydrophobic core. The polymer microsphere further includes crosslinkers, preferably where the crosslinkers are monomers containing at least two ethylenically unsaturated groups. 1. A method of using a plurality of self-dispersible polymer microspheres as fluid loss additives , which comprises the step of introducing the self-dispersible polymer microspheres into a drilling mud; where each self-dispersible polymer microsphere comprises:a hydrophobic core of hydrophobic monomers; anda hydrophilic shell of hydrophilic monomers;wherein the hydrophilic shell surrounds the hydrophobic core; andwherein the polymer microsphere is formed in water without addition of an emulsifier.2. The method of wherein the self-dispersible polymer microspheres are free of surfactants.3. The method of wherein the hydrophilic shell has a weight of between about 10% to about 90% by weight of the self-dispersible polymer microspheres.4. The method of wherein each self-dispersible polymer microsphere microsphere has a particle size of between about 0.01 to about 1000 microns.5. The method of wherein each self-dispersible polymer microsphere is selected from the group consisting of block claim 1 , graft claim 1 , and random copolymers.6. The method of wherein the hydrophilic shell is physically or chemically linked to the hydrophobic core of each self-dispersible polymer microsphere. This application for patent is a divisional of U.S. Non-Provisional Application No. 15/039,352, entitled “FLUID LOSS ADDITIVE FOR WATER BASED DRILLING FLUIDS WITH IMPROVED ...

Self-Pressurizing Soluble Alkali Silicate for use in Sealing Subterranean Spaces

The invention provides compositions and methods for sealing subterranean spaces such as natural or induced fractures, vugs or annular spaces. The composition is composed of a base fluid consisting of a soluble alkali silicate, a gas generating additive, solids and a setting agent. The gas generating additive may be coated or uncoated. The gas generating additive may also be in the form of a slurry. In the case of coated additives, the coating may act as a retarder or an accelerator to the expansion and setting agent of the soluble alkali silica. Similarly, the choice of carrier fluid in a slurry may retard or accelerate the expansion and setting of the alkali silicate-based plug.

LOST CIRCULATION MATERIAL

Fluid compositions including a base fluid and at least one granular hemicellulose material. The base fluid may be an oleaginous fluid or a non-oleaginous fluid. The granular hemicellulose material may have a cumulative particle size distribution D90 of about 4 mm or less and D10 of about 1 mm or greater, or D90 of 2.5 mm or less and D10 of about 1.5 mm or greater, or even D90 of about 3.8 mm or less, and D10 of about 2.4 mm or greater. The granular hemicellulose materials useful may have an average aspect ratio equal to or less than about 5:1, an average aspect ratio equal to or less than about 2:1, or even an average aspect ratio is about 1:1. The granular hemicellulose materials have hemicellulose in an amount from about 10% to about 50% by weight, cellulose in an amount from about 30% to about 50% by weight, and lignin in an amount from about 5% to about 35% by weight. The granular hemicellulose materials may be added to the base fluid in an amount from about 1 ppb to about 50 ppb, or even from about 4 ppb to about 40 ppb. The fluid compositions may be useful for sealing fractures in a subterranean formation, and reducing fluid loss in a subterranean formation. 1. A wellbore fluid composition comprising:a base fluid; and,at least one granular hemicellulose material.2. The wellbore fluid composition of claim 1 , wherein the base fluid is an oleaginous fluid.3. The wellbore fluid composition of claim 1 , wherein the base fluid is a non-oleaginous fluid.4. The wellbore fluid composition of claim 1 , wherein the at least one granular hemicellulose material has a particle size distribution D90 of about 10 mm or less claim 1 , and D10 of about 0.1 mm or greater.5. The wellbore fluid composition of claim 4 , wherein the at least one granular hemicellulose material has a particle size distribution Dof about 4 mm or less claim 4 , and Dof about 1 mm or greater.6. The wellbore fluid composition of claim 5 , wherein at least one granular hemicellulose material has a ...

PLASTICIZED POLYVINYL ALCOHOL DIVERTER MATERIALS

Methods for treating subterranean formations by diverting treatment fluids therein are provided. In one embodiment, the methods comprise: introducing a first diverter material comprising polyvinyl alcohol and a plasticizer into or adjacent to a permeable zone of a subterranean formation; introducing a second diverter material into or adjacent to the permeable zone of the subterranean formation, wherein at least a portion of the first diverter material comprises particles larger than particles of the second diverter material; and allowing the first diverter material and the second diverter material to at least partially divert at least a portion of a treatment fluid to a different portion of the subterranean formation. 1. A method comprising:introducing a first diverter material comprising polyvinyl alcohol and a plasticizer into or adjacent to a permeable zone of a subterranean formation;introducing a second diverter material into or adjacent to the permeable zone of the subterranean formation, wherein at least a portion of the first diverter material comprises particles larger than particles of the second diverter material; andallowing the first diverter material and the second diverter material to at least partially divert at least a portion of a treatment fluid to a different portion of the subterranean formation.2. The method of claim 1 , wherein the first diverter material is a composite material of the polyvinyl alcohol and the plasticizer.3. The method of claim 1 , wherein the second diverter material comprises polyvinyl alcohol.4. The method of claim 1 , wherein the first diverter material comprises particles sized 6 U.S. mesh or larger.5. The method of claim 1 , wherein the second diverter material comprises particles sized 8 U.S. mesh or smaller.6. The method of claim 1 , wherein the second diverter material comprises a plasticizer.7. The method of claim 1 , wherein the second diverter material does not comprise a substantial amount of a plasticizer.8. The ...

METHOD AND COMPOSITION OF MATTER FOR REDUCING LOST CIRCULATION

The present invention provides a method and a composition for eliminating or reducing the effects of loss of circulation events. In particular, the present invention provides a fiber-based loss of circulation material which seals fractures during drilling operations. 1. A method for eliminating or reducing lost circulation from a well , wherein the method comprises: a) a lost-circulation material;', 'b) wherein the lost-circulation material comprises cellulose;', 'c) wherein the lost-circulation material is made from bio-degradable products;', 'd) wherein the lost-circulation material has a specific gravity in a range from about 1.25 to about 1.5;', 'e) wherein the lost-circulation material has a median particle size in a range from about 80 US Mesh to 110 Mesh value (0.177 mm to 0.149 mm); and', 'f) wherein the bulk density varies from 0.4 to 0.55 gm/cc., 'introducing powder dissolved in water as a treatment fluid into at least a portion of the well, wherein the treatment fluid comprises2. The method according to claim 1 , wherein the lost-circulation material is comprised of at least 50% bast fiber cellulosic material.3. The method according to claim 1 , wherein the lost-circulation material comprises: cellulosic material claim 1 , a weighting agent and positive water solubility-maintained polysaccharides.4. The method according to claim 3 , wherein the cellulosic material is comprised of bast fiber obtained from the xylem portion of a plant.5. The method according to claim 1 , wherein the lost-circulation material has a median particle size in a range from 80 Mesh to 110 Mesh.6. The method according to claim 1 , wherein the lost-circulation material is in a concentration of at least 1:10 liquor ratio of the loss prevention fluid.7. The method according to claim 1 , wherein the lost-circulation material is in a concentration in a range of about 10% to 15% weight by volume of the loss prevention fluid.8. The method according to claim 1 , wherein the loss prevention ...

METHODS OF COMPLETING A WELL AND APPARATUS THEREFOR

A method can include conveying a dispensing tool through a wellbore, the dispensing tool including an enclosure containing plugging devices, and then opening the enclosure by cutting a material of the enclosure, thereby releasing the plugging devices from the enclosure into the wellbore at a downhole location. A dispensing tool can include a container having an enclosure therein, the enclosure including a flexible material that contains the plugging devices, and an end of the enclosure being secured to a member displaceable by an actuator. The enclosure material is cut in response to displacement of the member by the actuator. A plugging device can include at least one body configured to engage an opening in the well and block fluid flow through the opening, and multiple fibers including staple fibers or filaments formed into yarn. 19-. (canceled)10. A dispensing tool for dispensing plugging devices into a subterranean well , the dispensing tool comprising:a container having an enclosure therein, the enclosure comprising a flexible material that contains the plugging devices; andan end of the enclosure being secured to a member displaceable by an actuator, and in which the enclosure material is opened in response to displacement of the member by the actuator.11. The dispensing tool of claim 10 , in which an opposite end of the enclosure is secured against displacement relative to the container.12. The dispensing tool of claim 11 , in which a fastener extends through folds of the flexible material at the opposite end of the enclosure.13. The dispensing tool of claim 10 , in which the member comprises a closure member of a valve.14. The dispensing tool of claim 13 , in which the closure member comprises an inner sleeve claim 13 , and in which the valve comprises a sliding sleeve valve.15. The dispensing tool of claim 13 , in which the closure member has a closed position that prevents fluid communication between an exterior of the dispensing tool and an interior flow ...

Deploying Wellbore Patch for Mitigating Lost Circulation

Systems, methods, and apparatuses for deploying a lost circulation fabric (LCF) to seal a lost circulation zone during a drilling operation. The LCF may be contained within a lost circulation fabric deployment system (LCFDS) that is coupled to a tubular of a drilling string. The LCFDS may include a controller and sensors to detect the presence of a lost circulation zone and deploy the LCF upon detection of the lost circulation zone. In some implementations, a plurality of LCFDSs may be disposed on the tubular and work in cooperation to deploy a plurality of LCFs to form a seal along the lost circulation zone.

Expandable Coating for Solid Particles and Associated Methods of Use in Subterranean Treatments

A variety of methods and compositions are disclosed, including, in one embodiment, a method of treating a subterranean formation comprising: providing coated particles, wherein the coated particles comprise solid particles coated with an expandable coating; and introducing the coated particles into a permeable zone of the subterranean formation such that the coated particles form a barrier to fluid flow in the permeable zone. In another embodiment, a method of drilling a well bore may be provided, the method comprising: including coated particles in a drilling fluid, the coated particles comprising solid particles coated with an expandable coating; using a drill bit to enlarge the well bore; and circulating the drilling fluid past the drill bit. 1. A method of drilling a well bore comprising:including coated particles in a drilling fluid, the coated particles comprising solid particles coated with an expandable coating;using a drill bit to enlarge the well bore;circulating the drilling fluid past the drill bit; andallowing the expandable coating to expand, wherein an expansion of the expandable coating is controlled by divalent ions.2. The method of wherein the solid particles comprise a lost circulation material selected from the group consisting of a ground peanut shell claim 1 , mica claim 1 , cellophane claim 1 , ground walnut shell claim 1 , calcium carbonate claim 1 , plant fiber claim 1 , a cottonseed hull claim 1 , ground rubber claim 1 , polymeric material claim 1 , petroleum coke claim 1 , graphitic carbon claim 1 , and any combination thereof.3. The method of wherein the solid particles comprise a weighting agent selected from the group consisting of hematite claim 1 , hausmannite claim 1 , barite claim 1 , sand claim 1 , silica flour claim 1 , cement claim 1 , Illmanite claim 1 , calcium carbonate claim 1 , manganese oxide claim 1 , manganese tetraoxide claim 1 , and any combination thereof.4. The method of wherein the expandable coating comprises a ...

Polymer-Nanofiller Hydrogels

A polymer-nanofiller hydrogel including polymer hydrogel and nanofiller. The nanofiller is or includes nanosand. A method for forming the polymer-nanofiller hydrogel. A method of treating a wellbore in a subterranean formation, including applying a polymer-nanofiller hydrogel to the wellbore. 1. A method of treating a wellbore in a subterranean formation , comprising: polymer hydrogel comprising crosslinked polymer in water; and', 'nanofiller, wherein the nanofiller comprises nanosand., 'applying a polymer-nanofiller hydrogel to the wellbore, the polymer-nanofiller hydrogel comprising2. The method of claim 1 , wherein the crosslinked polymer and the nanofiller in combination are a polymer-nanofiller composite claim 1 , and wherein the nanofiller comprises hexagonal boron nitride in addition to the nanosand.3. The method of claim 1 , wherein the crosslinked polymer is reinforced with the nanofiller.4. The method of claim 1 , wherein the polymer-nanofiller hydrogel comprises a core-shell structure with the nanofiller as core and the polymer hydrogel as shell.5. The method of claim 1 , wherein the crosslinked polymer and the nanofiller comprise a core-shell structure with the nanofiller as core and the crosslinked polymer as shell.6. The method of claim 1 , wherein the crosslinked polymer comprises crosslinked polyacrylamide (PAM) claim 1 , and wherein the polymer hydrogel comprises PAM hydrogel comprising the crosslinked PAM in the water.7. The method of claim 1 , wherein the crosslinked polymer comprises crosslinked polystyrene-polymethylmethacrylate (PS-PMMA) copolymer claim 1 , and wherein the polymer hydrogel comprises PS-PMMA hydrogel comprising the crosslinked PS-PMMA copolymer in the water.8. The method of claim 1 , wherein applying the polymer-nanofiller hydrogel reduces water production from the subterranean formation into the wellbore.9. A method of forming a polymer-nanofiller hydrogel claim 1 , the method comprising:dispersing nanofiller in water, wherein ...

Loss Circulation Material for Seepage to Moderate Loss Control

A two-component lost circulation material (LCM) is provided. The two-component LCM includes a polymer component and a sodium hydroxide component. The polymer component may include may include a drilling fluid, a fibrous material such as polypropylene fibers, and an acrylic polymer, such as a 30% acrylic polymer solution. The sodium hydroxide component may include water and sodium hydroxide. The sodium hydroxide component is introduced to contact the polymer component to form the two-component LCM. Methods of lost circulation control and manufacture of a two-component LCM are also provided.

METHODS FOR INCREASING WELLBORE STRENGTH

Disclosed herein are compositions and methods for reducing fluid loss in a well bore. This invention relates to methods for wellbore strengthening and increasing the integrity of the borehole of an oil or gas well. In particular, the invention relates to methods for artificially increasing the temperature of a subsurface formation in the wellbore to increase the apparent wellbore strength. The mechanism for accomplishing this revolves around increasing fracture propagation pressure by actively manipulating thermal wellbore stresses. 145-. (canceled)46. A method for heating a fluid in a wellbore comprising contacting the fluid with a composition , thereby causing an exothermic event in the wellbore.47. The method according to claim 46 , wherein the exothermic event comprises at least one exothermic dissolution claim 46 , at least one exothermic reaction claim 46 , or a combination thereof.48. The method according to claim 46 , wherein the composition comprises at least one hygroscopic salt in an amount that is at least 15% by weight.49. The method according to any of claim 46 , wherein the composition comprises a calcium salt claim 46 , a magnesium salt claim 46 , a potassium salt claim 46 , an aluminum salt claim 46 , or a mixture thereof.50. The method according to claim 46 , wherein the exothermic event comprises a hydrolysis reaction.51. The method according to claim 46 , wherein the exothermic event comprises the hydrolysis of metal salt claim 46 , metal halide claim 46 , metal oxide claim 46 , metal hydroxide claim 46 , or a mixture thereof.52. The method according to claim 46 , wherein the exothermic event comprises a neutralization reaction between a strong acid and a strong base.53. The method according to claim 46 , wherein the exothermic event comprises a hydrolysis and neutralization cascade reaction.54. The method according to claim 46 , wherein the exothermic event comprises:{'sub': 2', '2', '2', '4', '2', '3', '3', '4', '2', '2', '5', '4', '10', '2', ' ...

FLOW CONTROL IN SUBTERRANEAN WELLS

A method of restoring flow through an opening in a well, the opening being blocked by a plugging device, can include conveying a well tool into the well, contacting the plugging device with the well tool, and permitting flow through the opening as a result of the contacting step. Another method of restoring flow through an opening blocked by a plugging device in a well can include conveying a well tool into the well, reducing pressure in the well with the well tool, and permitting flow through the opening as a result of the pressure reducing step. 1. A method of restoring flow through an opening blocked by a plugging device in a well , the method comprising:conveying a well tool into the well;contacting the plugging device with the well tool; andpermitting flow through the opening as a result of the contacting.2. The method of claim 1 , wherein the plugging device comprises a body that prevents flow through the opening prior to the contacting.3. The method of claim 2 , wherein the body comprises a knot.4. The method of claim 2 , wherein the body comprises a degradable material.5. The method of claim 2 , wherein the plugging device further comprises claim 2 , extending outwardly from the body claim 2 , at least one of the group consisting of fibers and lines.6. The method of claim 5 , wherein the at least one of the group consisting of fibers and lines extends through the opening prior to the contacting.7. The method of claim 5 , wherein the at least one of the group consisting of fibers and lines extends into a perforation prior to the contacting.8. The method of claim 2 , wherein the plugging device further comprises claim 2 , extending outwardly from the body claim 2 , at least one of the group consisting of film claim 2 , tube claim 2 , filament claim 2 , fabric and sheet material.9. The method of claim 8 , wherein the at least one of the group consisting of film claim 8 , tube claim 8 , filament claim 8 , fabric and sheet material extends through the opening ...

DUAL-FUNCTION NANO-SIZED PARTICLES

Dual-function nano-sized particles or nanoparticles may be effective at fixating or reducing fines migration and they may facilitate identification of a particular zone in a well having more than one zone. In some embodiments the dual-function nanoparticles are tagged with a detectable material that is distinguishable from the composition of the primary nanoparticle component. In these embodiments, the taggant material rather than the primary component of the nanoparticles may be used to enable identification of a particular zone. The nanoparticles (with or without taggant) may be added to a treatment fluid containing carrier particles such as proppant. The treatment fluid is pumped downhole to one of the zones; each zone receiving its own unique or uniquely-tagged nanoparticles. Should one of the zones fail, the composition of the nanoparticles (or its taggant) produced on the carrier particles may be correlated to the zone from which it was received, and hence produced. 1. A treatment fluid for reducing fines migration and comprising:a base fluid selected from the group consisting of water-based fluids, alcohol-based fluids and oil-based fluids, andcoated carrier particles consisting of: carrier particles, an effective amount of a particulate additive coated on the carrier particles to reduce fines migration and to facilitate identification of a zone in a well having more than one treatment-based zone, and taggants coated on the particulate additive; wherein the carrier particles are selected from the group consisting of sand, gravel, ceramic beads, glass beads, and combinations thereof; wherein the particulate additive has a mean particle size of 1000 nm or less and a primary component selected from the group consisting of alkaline earth metal oxides, alkaline earth metal hydroxides, transition metal oxides, transition metal hydroxides, post-transition metal oxides, post-transition metal hydroxides, piezoelectric crystals, pyroelectric crystals, and mixtures ...

Nano-Carbohydrate Composites as a Lost Circulation Materials - LCM Origami and Other Drilling Fluid Applications

A wellbore treatment fluid containing lost circulation materials and methods for using the treatment fluid, the fluid including a carrier fluid and nano-carbohydrate based sheets. The sheets may be folded or rolled into various cross-sectional surface area reducing configurations. The nano-carbohydrate based sheets may contain cellulose and or chitin materials. A method for utilizing the treatment fluid for creation or maintenance of a well includes forming or providing the treatment fluid and introducing the treatment fluid into a borehole. 1. A method of treating a formation comprising:forming or providing a well fluid including nano-carbohydrate based sheets; andintroducing the well fluid into a well.2. The method of claim 1 , wherein the well fluid is water-based.3. The method of claim 1 , wherein said forming or providing comprises forming the well fluid on-site near the well.4. The method of claim 3 , wherein said forming the well fluid includes dispersing the nano-carbohydrate based sheets in a tank or flow stream having a carrier fluid.5. The method of claim 4 , wherein before said dispersing claim 4 , the nano-carbohydrate based sheets are folded or rolled to reduce their cross-sectional areas by at least 50%.6. The method of claim 5 , wherein the folded or rolled nano-carbohydrate based sheets are folded with an accordion pleating configuration.7. The method of claim 5 , wherein the folded or rolled nano-carbohydrate based sheets have cross-sectional areas no more than about 1/16 of their unfolded cross-sections.8. The method of claim 5 , wherein the nano-carbohydrate based sheets are backed by a polymer that is configured to expand the nano-carbohydrate based sheets.9. The method of claim 8 , wherein the polymer is present as a coating on at least one portion of one side of the nano-carbohydrate based sheets.10. The method of claim 8 , wherein the polymer deforms when exposed to the carrier fluid.11. The method of claim 8 , wherein the polymer deforms ...

Clean Fluid Loss Control Additives

Methods of providing fluid loss control in a portion of a subterranean formation comprising: providing a treatment fluid comprising a base fluid and a plurality of seeds; introducing the treatment fluid into a portion of a subterranean formation penetrated by a well bore such that the seeds block openings in the subterranean formation to provide fluid loss control; and degrading the seeds over time within the subterranean formation. In some methods, the seeds are present in the treatment fluid in an amount of at least about 5 pounds per barrel. In addition, in some methods the seeds are preferably degradable.

Compositions and methods for fiber-containing grout

The invention relates to cementitious or grout compositions and drilling fluids including reinforcement fibers and methods relating thereto. The cementitious or grout compositions include dry blend material and reinforcement fibers. Each of the fibers can have one or more of a pre-selected mean length, denier, diameter and aspect ratio to improve dispersion in dry blending the cementitious or grout compositions.

SWELLABLE GLASS PARTICLES FOR REDUCING FLUID FLOW IN SUBTERRANEAN FORMATIONS

Methods, compositions, and systems that use swellable glass particles to reduce fluid flow in subterranean formations are included. An example method may comprise introducing swellable glass particles into a zone of a subterranean formation; contacting the swellable glass particles with a resin composition in the zone; and allowing the resin composition to harden in the zone whereby flow through the zone is reduced. 1. A well treatment method comprising:introducing swellable glass particles into a zone of a subterranean formation;contacting the swellable glass particles with a resin composition in the zone; andallowing the resin composition to harden in the zone whereby flow through the zone is reduced.2. The method of claim 1 , further comprising pumping a carrier fluid comprising the swellable glass particles through a well conduit and into the zone.3. The method of claim 2 , further comprising pumping the resin composition through a well conduit and into the zone to contact the swellable glass particles.4. The method of claim 1 , wherein at least a portion of the swellable glass particles swell upon contact with the resin composition to seal openings in the zone.5. The method of claim 4 , wherein the portion of the swellable glass particles swell to a volume of about 1.5 times or greater of a dry volume of the swellable glass particles.6. The method of claim 1 , wherein the swellable glass particles each comprise a plurality of interconnected organosilica nanoparticles.7. The method of claim 1 , wherein the swellable glass particles each comprise a bridged organosiloxane sol-gel comprising a plurality of alkylsiloxy substituents.8. The method of claim 1 , wherein the swellable glass particles are introduced into the subterranean formation in carrier fluid claim 1 , wherein the carrier fluid is aqueous based and comprises the swellable glass particles in an amount of about 0.001 to about 5 pounds per gallon of the carrier fluid.9. The method of claim 1 , wherein ...

METHODS AND COMPOSITIONS FOR USING TEMPORARY COMPACTED MATERIALS AS WELL SERVICING FLUIDS IN A SUBTERRANEAN FORMATION

Provided is a method of treating a subterranean formation comprising: preparing a well servicing fluid comprised of a base fluid, a temporary compacted material wherein the temporary compacted material is a compacted organic acid; placing the well servicing fluid into a subterranean formation; and allowing the temporary compacted material to gradually dissolve. 1. A method of treating a subterranean formation comprising: preparing a well servicing fluid comprised of a base fluid , a temporary compacted material wherein the temporary compacted material is a compacted organic acid and wherein the temporary compacted organic acid is compacted from powder or flake form to a larger particle at a pressure of approximately 500 psi to approximately 50 ,000 psi to alter solubility rate; placing the well servicing fluid into a subterranean formation; and allowing the temporary compacted material to gradually dissolve by an increase in temperature.2. A method of where the temporary compacted material is placed in the subterranean formation to influence the flow path of a wellbore or formation fluid.3. A method of where the temporary compacted material is placed in the subterranean formation such that the formation permeability is temporally altered.4. A method of where the temporary compacted material is placed in the subterranean formation where the wellbore configuration is altered.5. A method of where the organic acid is adipic acid6. A method of where the compacted material further comprises a solubility aide.7. A method of where the solubility aide is anhydrous sodium borate.8. A method of where the temporary compacted material is a particle in the size range of 100 microns to 25 mm.9. A method of where the shape of the temporary compacted material is a shape other than round.10. A method of where the shape of the temporary compacted material is a rod claim 9 , a cylinder claim 9 , a disk claim 9 , a plate claim 9 , a filament claim 9 , or has a cross section that is a ...

Method of Using Alginates in Subterranean Wellbores

Fluid loss from a wellbore into a subterranean formation may be reduced by forming a fluid barrier of a crosslinked alginate. 1. A method comprising:forming a fluid barrier from the wellbore into the formation with crosslinked alginate; andreducing fluid loss from a wellbore into a subterranean formation.2. The method of further comprising:reacting alginic acid or sodium alginate and an alkaline earth metal to form the crosslinked alginate.3. The method of wherein the reacting step occurs in the wellbore.4. The method of claim 2 , wherein the alkaline earth metal is encapsulated to delay formation of the crosslinked alginate.5. A method for prevent or reducing loss of fluids into flow passages of a subterranean formation penetrated by a well during drilling claim 2 , completion claim 2 , cementing or workover operations comprising:blocking the flow passages with a gel comprising crosslinked alginate.6. The method of claim 5 , wherein the crosslinked alginate is a reaction product of alginic acid or sodium alginate and an alkaline earth containing crosslinking agent.7. The method of claim 6 , wherein the alkaline earth of the alkaline earth containing crosslinking agent is calcium or magnesium.8. The method of claim 6 , wherein the crosslinked agent is lime or gypsum.9. The method of claim 5 , wherein the crosslinked alginate is formed by crosslinking sodium alginate with the calcium containing crosslinking agent.10. The method of claim 9 , wherein the molar ratio of calcium ions to sodium ions in the crosslinked sodium alginate is greater than 2:1.11. The method of claim 1 , wherein the crosslinked alginate is pumped into the well and further wherein the crosslinked alginate is viscosified in-situ to reduce the fluid loss.12. The method of claim 5 , further comprising:providing the crosslinked alginate to an oil-based or water-based fluid loss pill; andpumping the fluid loss pill with the crosslinked alginate the well.13. The method of claim 5 , further comprising: ...

Loss Circulation Compositions (LCM) Having Portland Cement Clinker

Portland cement clinker LCMs that include Portland cement clinker to mitigate or prevent lost circulation in a well are provided. A Portland cement clinker LCM may include Portland cement clinker, Portland cement, a carrier fluid, and an inorganic consolidation activator. Another Portland cement clinker LCM may include Portland cement clinker and a crosslinked fluid, such as a polyuronide crosslinked via calcium ions or a polysaccharide crosslinked via divinyl sulfone. Yet another Portland cement clinker LCM may include Portland cement clinker and polymer fibers or particulate glass. Methods of lost circulation control using a Portland cement clinker LCM are also provided. 1. A lost circulation material (LCM) composition , comprising:Portland cement clinker, wherein the Portland cement clinker consists of non-hydraulic, non-cementiceous unground Portland cement clinker particles;cement, wherein the cement comprises API Class G cement;a carrier fluid; andan inorganic consolidation activator selected to consolidate the clinker in the composition to form a plug when introduced into a lost circulation zone.2. The LCM composition of claim 1 , wherein the carrier fluid comprises an aqueous carrier fluid that includes at least one of diutan gum claim 1 , xanthan gum claim 1 , and welan gum.3. The LCM composition of claim 1 , wherein the Portland cement clinker comprises ASTM International Type I cement clinker claim 1 , ASTM International Type V cement clinker claim 1 , API Class A cement clinker claim 1 , or API Class G cement clinker.4. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises a silicate salt.5. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises at least one of sodium silicate claim 1 , calcium aluminate claim 1 , calcium chloride claim 1 , sodium aluminate claim 1 , and potassium silicate.6. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises an ...

Loss Circulation Compositions (LCM) Having Portland Cement Clinker

Portland cement clinker LCMs that include Portland cement clinker to mitigate or prevent lost circulation in a well are provided. A Portland cement clinker LCM may include Portland cement clinker, Portland cement, a carrier fluid, and an inorganic consolidation activator. Another Portland cement clinker LCM may include Portland cement clinker and a crosslinked fluid, such as a polyuronide crosslinked via calcium ions or a polysaccharide crosslinked via divinyl sulfone. Yet another Portland cement clinker LCM may include Portland cement clinker and polymer fibers or particulate glass. Methods of lost circulation control using a Portland cement clinker LCM are also provided. 1. A lost circulation material (LCM) composition , comprising:Portland cement clinker, wherein the Portland cement clinker consists of non-hydraulic, non-cementiceous unground Portland cement clinker particles;cement;a carrier fluid;a plurality of polymer fibers; andan inorganic consolidation activator selected to consolidate the clinker in the composition to form a plug when introduced into a lost circulation zone.2. The LCM composition of claim 1 , wherein the carrier fluid comprises an aqueous carrier fluid that includes at least one of diutan gum claim 1 , xanthan gum claim 1 , and welan gum.3. The LCM composition of claim 1 , wherein the Portland cement clinker comprises ASTM International Type I cement clinker claim 1 , ASTM International Type V cement clinker claim 1 , API Class A cement clinker claim 1 , or API Class G cement clinker.4. The LCM composition of claim 1 , wherein the cement comprises API Class G cement.5. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises a silicate salt.6. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises at least one of sodium silicate claim 1 , calcium aluminate claim 1 , calcium chloride claim 1 , sodium aluminate claim 1 , and potassium silicate.7. The LCM composition of claim 1 ...

Loss Circulation Compositions (LCM) Having Portland Cement Clinker

Portland cement clinker LCMs that include Portland cement clinker to mitigate or prevent lost circulation in a well are provided. A Portland cement clinker LCM may include Portland cement clinker, Portland cement, a carrier fluid, and an inorganic consolidation activator. Another Portland cement clinker LCM may include Portland cement clinker and a crosslinked fluid, such as a polyuronide crosslinked via calcium ions or a polysaccharide crosslinked via divinyl sulfone. Yet another Portland cement clinker LCM may include Portland cement clinker and polymer fibers or particulate glass. Methods of lost circulation control using a Portland cement clinker LCM are also provided. 1. A lost circulation material (LCM) composition , comprising:Portland cement clinker, wherein the Portland cement clinker consists of non-hydraulic, non-cementiceous unground Portland cement clinker particles;cement;a carrier fluid;particulate glass having an aspect ratio greater than or less than 1; andan inorganic consolidation activator selected to consolidate the clinker in the composition to form a plug when introduced into a lost circulation zone.2. The LCM composition of claim 1 , wherein the carrier fluid comprises an aqueous carrier fluid that includes at least one of diutan gum claim 1 , xanthan gum claim 1 , and welan gum.3. The LCM composition of claim 1 , wherein the Portland cement clinker comprises ASTM International Type I cement clinker claim 1 , ASTM International Type V cement clinker claim 1 , API Class A cement clinker claim 1 , or API Class G cement clinker.4. The LCM composition of claim 1 , wherein the cement comprises API Class G cement.5. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises a silicate salt.6. The LCM composition of claim 1 , wherein the inorganic consolidation activator comprises at least one of sodium silicate claim 1 , calcium aluminate claim 1 , calcium chloride claim 1 , sodium aluminate claim 1 , and potassium ...

Method of enhancing circulation during drill-out of a wellbore barrier using dissovable solid particulates

A fluid-impermeable barrier, used to isolate stimulated intervals in a reservoir during a multi-zone fracturing operation, may be removed from the wellbore which penetrates the reservoir using a circulating fluid containing dissolvable solid particulates. The dissolvable solid particulates bridge perforation clusters during clean-out of the wellbore and thus inhibit passage of the circulating fluid into the fracture network through the perforation clusters.

POLYMER-MONODISPERSED NANO-MICROSPHERES FOR DEEP PROFILE CONTROL AND FLOODING, AND PREPARATION METHOD THEREOF

A polymer-monodispersed nano-microspheres for deep profile control and flooding. The polymer-monodispersed nano-microspheres comprise (% wt.): 0.05˜2.5% of macromolecules A, 0.05˜2.5% of macromolecules B, 0.002˜0.05% of oxygen scavenger, and mineralized water. Macromolecules A are of a straight-chain water-soluble polymer with an ethyl ether or propyl ether structure. Macromolecules B are of a water-soluble polymer with a hydroxyl or polyphenolic structure. Macromolecules A and macromolecules B are intermolecularly assembled under the drive of extremely strong hydrogen bonds in aqueous solutions to rapidly construct monodispersed nano-microsphere dispersion glue with a controllable size. The monodispersed nano-microspheres have a good seepage in a porous medium and excellent deep profile control and flooding capabilities. 2. The polymer-monodispersed nano-microspheres for deep profile control and flooding according to claim 1 , wherein the macromolecules A are polypropylene glycol claim 1 , fatty alcohol polyoxyethylene ether claim 1 , methallyl alcohol polyoxyethylene ether or allyl alcohol polyoxyethylene ether.3. The polymer-monodispersed nano-microspheres for deep profile control and flooding according to claim 1 , wherein the macromolecules B are carboxymethyl-β-cyclodextrin claim 1 , tannin extract or tea polyphenol.4. The polymer-monodispersed nano-microspheres for deep profile control and flooding according to claim 1 , wherein the oxygen scavenger is thiourea.5. A preparation method for the polymer-monodispersed nano-microspheres for deep profile control and flooding according to claim 1 , sequentially comprising the following steps:adding a certain amount of oxygen scavenger to the mineralized water and stirring to dissolve for 10˜20 minutes, and then dividing the mixture into two parts;adding a certain mass concentration of macromolecules A to one part of mineralized water, and stirring to dissolve at room temperature for 10˜30 minutes;adding a certain ...

RESERVOIR TREATMENTS

The present invention relates to the field of enhanced oil recovery and provides a method of establishing a plug in a hydrocarbon reservoir, the method comprising introducing into the reservoir a formulation comprising solid particles and a viscosifier and then reducing the viscosity of said viscosifier, thereby causing said solid particles to form a plug within said hydrocarbon reservoir. Also provided is a method of establishing a plug in a hydrocarbon reservoir, the method comprising introducing into the reservoir a formulation comprising: (a) microorganisms or cell-free enzymes; (b) solid particles; and (c) a viscosifier which is a substrate for the microorganisms or cell-free enzymes of (a). Also provided is a formulation comprising: (a) microorganisms or cell-free enzymes; (b) solid particles made from wood or a wood derived product; and (c) a viscosifier which is a substrate for the microorganisms or cell-free enzymes of (a). 1. A method of establishing a plug in a hydrocarbon reservoir , the method comprising introducing into the reservoir a formulation comprising solid particles and a viscosifier and then reducing the viscosity of said viscosifier , thereby causing said solid particles to form a plug within said hydrocarbon reservoir.2. The method of establishing a plug in a hydrocarbon reservoir of claim 1 , wherein the formulation introduced into the reservoir further comprises:microorganisms or cell-free enzymes; andthe viscosifier is a substrate for the microorganisms or cell-free enzymes.3Clostridium thermocellumAcidothermus cellulolyticus.. A method as claimed in wherein the microorganisms or cell-free enzymes are saccharolytic or lignocellulolytic claim 2 , preferably are claim 2 , or are from claim 2 , or4. The method of claim 1 , wherein the viscosifier comprises claim 1 , cellulose claim 1 , hemicellulose or a derivative thereof or a polysaccharide gum.5. The method as claimed in wherein the viscosifier comprises a polyanionic cellulose or a ...

SPHEROID MAGNETIC POLYMERS FOR IMPROVING HYDROCARBON RECOVERY OR DRILLING PERFORMANCE

A wall of a subterranean reservoir wellbore may be at least partially coated with spheroid magnetic polymers. Alternatively, a downhole fluid having spheroid magnetic polymers may be circulated within the wellbore to at least partially coat the wall of the wellbore with the spheroid magnetic polymers. A magnetic field or electric field may be applied to the wall of the wellbore having the spheroid magnetic polymer coating forming a reversible pseudo-gel to improve hydrocarbon recovery and/or drilling performance by a method, such as but not limited to preventing or inhibiting lost circulation, improving or increasing rate of penetration (ROP), reducing frictional pressure during wellbore construction, preventing or inhibiting corrosion, and combinations thereof. 1. A method for producing hydrocarbons comprising improving a property selected from the group consisting of hydrocarbon recovery , drilling performance , and combinations thereof; wherein the method comprises:applying a magnetic field or electric field to the wall of a subterranean reservoir wellbore, wherein the wall has been at least partially coated with spheroid magnetic polymers in an effective amount to form a reversible pseudo-gel on the wall improve the property, whereby the reversible pseudo-gel improves the property by a process selected from the group consisting of preventing or inhibiting lost circulation, improving rate of penetration (ROP), reducing frictional pressure during wellbore construction, preventing or inhibiting corrosion, and combinations thereof.2. The method of where the spheroid magnetic polymers have an average diameter ranging from about 5 to about 1000 nm.3. The method of claim 1 , further comprising at least partially coating the wall of the subterranean reservoir wellbore with spheroid magnetic polymers prior to applying the magnetic field or electric field to the wall of the subterranean reservoir wellbore to form the reversible pseudo-gel.4. The method of where the ...

Metal-Organic Frameworks as Encapsulating Agents

Methods for treating subterranean formations are provided. The method includes contacting the formation with a fluid composition containing a porous metal-organic framework that contains at least one metal ion and an organic ligand. The organic ligand is at least bidentate and bonded to the metal ion. Pores in the framework are at least partially occupied by one or more additives.

Fluid diversion composition in well stimulation

Described are methods and compositions for treating a subterranean formation. The method comprising introducing into the subterranean formation via a well-bore a diverter composition, the diverter composition comprising a combination of at least one deformable particle and at least one non-deformable particle; and allowing the diverter composition to block the flow of at least a portion of a treatment fluid from a first location within the well-bore to a second location.

ARC Fiber Trio-Date Tree Waste-Based Trinary Fibrous Mix for Moderate to Severe Loss Control

A date tree fiber mix lost circulation material (LCM) is provided that includes a trinary mix of fibers produced from date trees. The date tree fiber mix LCM may include date tree trunk fibers produced from date tree trunks, date tree leaf and leaf stem fibers produced from date tree leaves and leaf stems, and date tree panicle fibers produced from date tree panicles. The LCM include a mix of 30% by weight date tree trunk fibers, 30% date tree leaf and leaf stem fibers, and 40% by weight date tree panicle fibers. Methods of lost circulation control using and manufacture of a date tree fiber mix LCM are also provided 1. A method to control lost circulation in a lost circulation zone in a wellbore , comprising:introducing an altered drilling fluid into the wellbore such that the altered drilling fluid contacts the lost circulation zone and reduces a rate of lost circulation into the lost circulation zone, where the altered drilling fluid comprises a drilling fluid and a lost circulation material (LCM), wherein the LCM comprises:a first plurality of fibers produced from date tree trunks;a second plurality of fibers produced from at least one of date tree leaves and date tree leaf stems; anda third plurality of fibers produced from date tree panicles.2. The method of claim 1 , wherein the altered drilling fluid consists of the drilling fluid and the LCM.3. The method of claim 1 , wherein the LCM consists of the first plurality of fibers produced from date tree trunks claim 1 , the second plurality of fibers produced from at least one of date tree leaves and date tree leaf stems claim 1 , and the third plurality of fibers produced from date tree panicles.4. The method of claim 1 , wherein the first plurality of fibers comprise 30% by weight of the LCM claim 1 , the second plurality of fibers comprise 30% by weight of the LCM claim 1 , and the third plurality of fibers comprise 40% by weight of the LCM.5. The method of claim 1 , wherein the LCM comprises a concentration ...

Date Seed-Based Multi-Modal Particulate Admixture for Moderate to Severe Loss Control

A date palm seed lost circulation material (LCM) is provided having a date palm seed admixture of date palm seed particles of various sizes. The date palm seed particles may have a size greater than about 2380 microns in a range of about 40% to about 42% by weight, particles having a size greater than about 595 microns and less than about 2381 microns in a range of about 46% to about 48% by weight, particles having a size greater than about 400 microns and less than about 596 microns in a range of about 4% to about 6% by weight, particles having a size less than about 210 microns in a range of about 4% to about 6% by weight, and particles having a size less than about 149 microns in a range of about 1% to about 3% by weight. Methods of lost circulation control using and manufacture of a date palm seed LCM are also provided. 1. A method to control lost circulation in a lost circulation zone in a wellbore comprising:introducing an altered drilling fluid into the well bore such that the altered drilling fluid contacts the lost circulation zone and reduces a rate of lost circulation into the lost circulation zone, where the altered drilling fluid comprises a drilling fluid and a lost circulation material (LCM), wherein the LCM comprises:a first plurality of untreated particles having a first particle size, wherein the first particle size comprises greater than 2380 microns;a second plurality of the untreated particles having a second particle size, wherein the second particle size comprises greater than 595 microns and less than 2381 microns;a third plurality of the untreated particles having a third particle size, wherein the third particle size comprises greater than 400 microns and less than 596 microns;a fourth plurality of the untreated particles having a fourth particle size, wherein the fourth particle size comprises less than 210 microns and greater than 148 microns;a fifth plurality of the untreated particles having a fifth particle size, wherein the fifth ...

Date Seed-Based Multi-Modal Particulate Admixture for Moderate to Severe Loss Control

A date palm seed lost circulation material (LCM) is provided having a date palm seed admixture of date palm seed particles of various sizes. The date palm seed particles may have a size greater than about 2380 microns in a range of about 40% to about 42% by weight, particles having a size greater than about 595 microns and less than about 2381 microns in a range of about 46% to about 48% by weight, particles having a size greater than about 400 microns and less than about 596 microns in a range of about 4% to about 6% by weight, particles having a size less than about 210 microns in a range of about 4% to about 6% by weight, and particles having a size less than about 149 microns in a range of about 1% to about 3% by weight. Methods of lost circulation control using and manufacture of a date palm seed LCM are also provided. 1. A method of forming an altered drilling fluid , comprising:drying a plurality of date palm seeds;grinding the plurality of date palm seeds to produce a plurality of untreated particles; a first group of the untreated particles having a first particle size; and', 'a second group of the untreated particles having a second particle size;, 'sifting the plurality of untreated particles into at least two groups of the untreated particles, the at least two groups comprisingmixing the first group and the second group of the untreated particles into a lost circulation material (LCM) composition; andblending the LCM composition into a drilling fluid to create an altered drilling fluid.2. (canceled)3. The method of claim 2 , wherein the drilling fluid is a water-based drilling fluid.4. The method of claim 1 , wherein the LCM composition consists essentially of the plurality of untreated particles.5. The method of claim 1 , wherein the plurality of untreated particles are not introduced to an alkali claim 1 , an acid claim 1 , a bleaching or an oxidation agent before mixing into the LCM composition.6. The method of claim 1 , wherein drying the plurality ...

Date Seed-Based Multi-Modal Particulate Admixture for Moderate to Severe Loss Control

A date palm seed lost circulation material (LCM) is provided having a date palm seed admixture of date palm seed particles of various sizes. The date palm seed particles may have a size greater than about 2380 microns in a range of about 40% to about 42% by weight, particles having a size greater than about 595 microns and less than about 2381 microns in a range of about 46% to about 48% by weight, particles having a size greater than about 400 microns and less than about 596 microns in a range of about 4% to about 6% by weight, particles having a size less than about 210 microns in a range of about 4% to about 6% by weight, and particles having a size less than about 149 microns in a range of about 1% to about 3% by weight. Methods of lost circulation control using and manufacture of a date palm seed LCM are also provided. 1. An altered drilling fluid , comprising:a drilling fluid; and a first plurality of untreated particles having a first particle size; and', 'a second plurality of the untreated particles having a second particle size,, 'a lost circulation material (LCM), wherein the LCM compriseswherein the untreated particles comprise ground date palm seeds.2. The altered drilling fluid of claim 2 , wherein the untreated particles consist of ground date palm seeds.3. The altered drilling fluid of claim 2 , wherein the first particle size comprises greater than 2380 microns and the second particle size comprises less than 210 microns.4. The altered drilling fluid of claim 2 , wherein the LCM comprises:a third plurality of the untreated particles having a third particle size;a fourth plurality of the untreated particles having a fourth particle size; anda fifth plurality of the untreated particles having a fifth particle size.5. The altered drilling fluid of claim 4 , wherein the first particle size comprises greater than 2380 microns.6. The altered drilling fluid of claim 5 , wherein the second particle size comprises greater than 595 microns and less than 2381 ...

ACID-SOLUBLE PLUG FORMING RAPIDLY DEHYDRATING LOSS CONTROL SLURRY

A rapidly dehydrating lost circulation material (LCM) composition that forms an acid-soluble plug is provided. The LCM composition may include a carrier fluid, an acid-soluble-particulate material, a viscosifier, and date tree rachis fibers. The carrier fluid may be water and the viscosifier may be a cellulosic microfiber. The LCM composition may alter a lost circulation zone by forming an acid-soluble plug in a fracture of the lost circulation zone. The acid-soluble plug may be removed via an acid solution, such as a hydrochloric acid solution. Methods of lost circulation control and manufacture of a rapidly dehydrating LCM are also provided. 1. A lost circulation material (LCM) composition , the composition comprising:a carrier fluid;an acid-soluble particulate material;a viscosifier; anda fibrous material comprising date tree rachis fibers.2. The LCM composition of claim 1 , wherein the carrier fluid claim 1 , the particulate material claim 1 , the viscosifier claim 1 , and the fibrous material form a homogenous mixture.3. The LCM composition of claim 1 , wherein the carrier fluid comprises water.4. The LCM composition of claim 1 , wherein the viscosifier comprises a cellulosic microfiber.5. The LCM composition of claim 1 , wherein the fibrous material consists of date tree rachis fibers.6. The LCM composition of claim 1 , wherein the acid-soluble particulate material comprises calcium carbonate.7. The LCM composition of claim 6 , wherein the calcium carbonate comprises at least 4% weight of the total weight (w/w %) of the LCM composition.8. The LCM composition of claim 1 , wherein the date tree rachis fibers comprise at least 4% weight of the total weight (w/w %) of the LCM composition.9. The LCM composition of claim 1 , wherein the LCM composition has a dehydration time of less than 3 minutes at 100 pounds-per-square inch differential (psid) pressure. This application is a divisional of and claims priority to U.S. Provisional application Ser. No. 15/649,242 ...

ACID-SOLUBLE PLUG FORMING RAPIDLY DEHYDRATING LOSS CONTROL SLURRY

A rapidly dehydrating lost circulation material (LCM) composition that forms an acid-soluble plug is provided. The LCM composition may include a carrier fluid, an acid-soluble-particulate material, a viscosifier, and date tree rachis fibers. The carrier fluid may be water and the viscosifier may be a cellulosic microfiber. The LCM composition may alter a lost circulation zone by forming an acid-soluble plug in a fracture of the lost circulation zone. The acid-soluble plug may be removed via an acid solution, such as a hydrochloric acid solution. Methods of lost circulation control and manufacture of a rapidly dehydrating LCM are also provided. 1. An altered drilling fluid , comprising:a drilling fluid; and a carrier fluid;', 'an acid-soluble particulate material;', 'a viscosifier; and', 'a fibrous material comprising date tree rachis fibers., 'a lost circulation material (LCM) composition, wherein the LCM composition comprises2. The altered drilling fluid of claim 1 , wherein the carrier fluid comprises water.3. The altered drilling fluid of claim 1 , wherein the viscosifier comprises a cellulosic microfiber.4. The altered drilling fluid of claim 1 , wherein the fibrous material consists of date tree rachis fibers.5. The altered drilling fluid of claim 1 , wherein the particulate material comprises calcium carbonate.6. The altered drilling fluid of claim 5 , wherein the calcium carbonate comprises at least 4% weight of the total weight (w/w %) of the LCM composition.7. The altered drilling fluid of claim 1 , wherein the date tree rachis fibers comprise at least 4% weight of the total weight (w/w %) of the LCM composition. This application is a divisional of and claims priority to U.S. Provisional application Ser. No. 15/649,242 filed Jul. 13, 2017, and titled “ACID-SOLUBLE PLUG FORMING RAPIDLY DEHYDRATING LOSS CONTROL SLURRY, which claims priority from U.S. Provisional Application No. 62/431,726 filed Dec. 8, 2016, and titled “ACID-SOLUBLE PLUG FORMING RAPIDLY ...