Halliburton Energy Services, Inc.

HsinChen Chung

Xiangnan Ye

Narongsak Tonmukayakul

Jason Maxey

Yuntao Thomas Hu

Shih-Ruey Tom Chen

Michael A McCabe

Kevin W Frederick

Randy J Loeffler

Dipti Singh

Prashant Dinkar Chopade

Aaron Gene Russell

Harvey Fitzpatrick

Systems and methods for controlling flow in downhole operations are described. Systems and methods may include a composition including a fracturing fluid base; one or more ionic compounds; a polymer; a crosslinking agent; and a pH modifier. A breaker may be provided in the composition. The composition may be provided to a formation to control flow, and syneresis may occur.

Controlling flow in downhole operations

A system and methods for breaking friction reducers in subterranean formations in-situ during hydraulic fracturing operations are disclosed. A method of fracturing a subterranean formation is disclosed, including providing a well treating fluid, adding a friction reducer into a water phase of an emulsion, adding a breaker into the water phase, and injecting the well treating fluid into the subterranean formation at a pressure sufficient to fracture the subterranean formation and invert the emulsion and double emulsion, thereby allowing the breaker to break the friction reducer. A friction reducer-breaker system for breaking a friction reducer polymer in-situ is also disclosed, including an oil phase, a water phase including friction reducer polymers and breakers in double emulsion dispersed throughout the water phase, wherein the emulsion and double emulsion are configured to invert under shear, thereby providing for mixing between the friction reducer polymers and the breakers.

Systems and methods for breaking friction reducers in-situ

Various embodiments disclosed relate to acidizing compositions including an ampholyte polymer. Various embodiments provide a method of treating a subterranean formation. The method can include placing in a subterranean formation an ampholyte polymer including an ethylene repeating unit including a &#x2014;C(O)NHgroup, an ethylene repeating unit including an &#x2014;S(O)ORgroup, and an ethylene repeating unit including an &#x2014;NRXgroup. At each occurrence, Rcan be independently selected from the group consisting of &#x2014;H and a counterion. At each occurrence, Rcan be independently substituted or unsubstituted (C-C)hydrocarbyl. At each occurrence, Xcan be independently a counterion.

Acidizing compositions including ampholyte polymers

Ampholyte polymeric compound that comprises at least one nonionic monomer, at least one sulfonic acid-containing monomer, and at least one cationic monomer may be useful in viscosifying treatment fluids for use in subterranean operations at a concentration of about 0.5 v/v % to about 30 v/v % of the treatment fluid. Such operations may involve introducing the treatment fluid into a wellbore penetrating a subterranean formation optionally at a pressure sufficient to create or extend at least one fracture in the subterranean formation.

Ampholyte polymeric compounds in subterranean applications

Various embodiments disclosed relate to a composition including a crosslinkable ampholyte polymer or a crosslinked product of the same, methods of making and using the composition, and systems including the composition. 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 crosslinkable ampholyte polymer. The crosslinkable ampholyte polymer can include an ethylene repeating unit including a &#x2014;C(O)NHgroup, an ethylene repeating unit including a &#x2014;S(O)ORgroup, and an ethylene repeating unit comprising an &#x2014;NRXgroup. At each occurrence, Rcan be independently selected from the group consisting of &#x2014;H and a counterion. At each occurrence, Rcan be independently substituted or unsubstituted (C-C)hydrocarbyl. At each occurrence, Xcan be independently a counterion. The composition can also include at least one crosslinker. The method can include placing the composition in a subterranean formation.

Ampholyte polymers and methods of treating subterranean formations with the same

Introducing a treatment fluid comprising proppant particulates into a subterranean formation, the treatment fluid comprising a high salt concentration base fluid, a charged polymeric gelling agent, and proppant particulates suspended therein, wherein the high salt concentration base fluid comprises a concentration of salt in the range of from about 0.5% to saturation, and wherein the treatment fluid has a bulk viscosity of from about 30 cP to about 150 cP at a shear rate of about 40 sec.

Methods for improved proppant suspension in high salinity, low viscosity subterranean treatment fluids

Ampholyte polymeric compounds that comprise at least one nonionic monomer, at least one sulfonic acid-containing monomer, and at least one cationic monomer may be useful as friction reducing agents in treatment fluids for use in subterranean operations at a concentration of about 0.001 v/v % to about 0.5 v/v % of the treatment fluid. Such operations may involve introducing the treatment fluid into a wellbore penetrating a subterranean formation optionally at a rate and/or a pressure sufficient to create or extend at least one fracture in the subterranean formation.

Computer-implemented methods, software, and systems for determining a property of a wellbore fluid are disclosed. In some implementations, a computing system receives an image of a first sample of the wellbore fluid filling a conduit to a threshold volume of the conduit. The computing system determines a first time duration of the first sample of the wellbore fluid filling the conduit to the threshold volume of the conduit based on the image of the first sample. The computing system receives an image of a second sample of the wellbore fluid filling the conduit to the threshold volume of the conduit. The computing system determines a second time duration of the second sample of the wellbore fluid filling the conduit to the threshold volume of the conduit based on the image of the second sample. A property of the wellbore fluid is determined based on a difference between the first and second time durations.

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Houston, TX, United States of America

HsinChen Chung