Halliburton Energy Services, Inc.

Multi-chem Group, LLC

Preston Andrew May

Jay Paul Deville

William Walter Shumway

Dale E Jamison

Hui Zhou

Ryan Patrick Collins

Jeffrey James Miller

Emily Cummings Hart

Miren Aranzazu Castanares

Eric Frantz

Kingsley Ihueze Nzeadibe

Thomas S Cortner

Jay DeVille

Frederick Thomas Brown

Michele Suzanne Brown

Troy Francis Davis

Sandeep Kumar Borra

Ayten Rady

Mohamed Metwally

Thomas Scott Cortner

Ryan P Collins

A treatment fluid can include a base fluid and a stabilizing additive. The stabilizing additive can include a plurality of environmentally acceptable nanoparticles. The particle size distribution of the plurality of nanoparticles can be selected such that the nanoparticles stabilize a wellbore wall of a subterranean formation or form a filtercake to inhibit or prevent fluid loss into permeable areas of the formation. The plurality of nanoparticles can have a particle size distribution of a d10 value in the range of 20 to 45 nanometers, a d50 value in the range of 40 to 80 nanometers, and a d90 value in the range of 80 to 140 nanometers. The plurality of nanoparticles can also be coated with a polymeric shell. The treatment fluid can be used in an oil and gas operation.

Environmentally acceptable wellbore stability additive

Additives of wellbore fluids can be quantified using laser induced breakdown spectroscopy. For example, a method can involve acquiring a sample of wellbore fluid from a wellbore. The wellbore fluid can include an additive. The sample can be processed to separate the wellbore fluid into a liquid sample and a solid sample. A laser induced breakdown spectroscopy device can identify a chemical composition of the liquid sample or the solid sample. A concentration of the additive in the wellbore fluid can be determined based on the chemical composition of the liquid sample or the solid sample. An adjustment to a composition of the wellbore fluid can be performed based on the concentration of the additive in the wellbore fluid.

Quantification of wellbore fluid additives by laser induced breakdown spectroscopy

Drilling fluids for drilling a wellbore. An example drilling fluid includes an aqueous base fluid, a first fluid loss control additive that comprises a cross-linked polymer comprising N-vinylpyrrolidone as a monomer, and a second fluid loss control additive that comprises a cloud point glycol.

Drilling fluid additives for high-density reservoir drilling fluids

Drilling fluids and methods for drilling a wellbore. An example drilling fluid is a divalent brine aqueous base fluid having at least one dissolved divalent zinc salt and also a polymeric additive that is a cross-linked copolymer comprising a first comonomer of 2-acrylamido-2-methylpropanesulfonic acid in a first comonomer concentration of at least 50 mol % of the copolymer; wherein the polymeric additive additionally comprises a second comonomer comprising a N-vinyl amine-containing monomer, a terminal double bound-containing monomer, or a combination of a N-vinyl amine-containing monomer and a terminal double bound-containing monomer; wherein the second comonomer is present in a total second comonomer concentration of 50 mol % or less of the copolymer. The drilling fluid further includes a zinc solid.

Divalent-brine-based high density drilling fluids

A variety of methods and systems are disclosed, including, in one embodiment, a method for emulsion breaking including: applying a trigger to an oilfield emulsion to facilitate breaking of the oilfield emulsion, wherein the oilfield emulsion includes an oleaginous phase, a non-oleaginous phase, and a breakable emulsifier, wherein the trigger breaks the breakable emulsifier into non-emulsifying byproducts; and separating at least a portion of the oleaginous phase from the non-oleaginous phase.

Breakable emulsifiers

Methods and compositions for improving the rheological properties of fluids including sepiolite are provided. In one or more embodiments, the compositions comprise a clay selected from the group consisting of: sepiolite, palygorskite, attapulgite, and a combination thereof; and an extender comprising sodium polyacrylate, wherein the extender is present in an amount from about 0.01 lbs/ton of the clay to about 10 lbs/ton of the clay. In one or more embodiments, the methods comprise introducing a treatment fluid into a wellbore penetrating at least a portion of a subterranean formation, wherein the treatment fluid comprises an aqueous base fluid, a clay selected from the group consisting of: sepiolite, palygorskite, attapulgite, and a combination thereof, and an extender comprising sodium polyacrylate.

Methods and compositions for enhancing clay viscosifiers

Methods for manufacturing lost circulation material particulates that may be for use in treating a subterranean formation are provided. In some embodiments, the methods include providing at a well-site a feed vessel that contains a liquid material, the liquid material including a monomer and an initiator; providing an injection device disposed underneath the feed vessel for directing at least a portion of the liquid material from the feed vessel to a reaction chamber, wherein the reaction chamber includes a fluid; discharging at least a portion of the liquid material from the feed vessel to the reaction chamber through an orifice disposed on the injection device; and forming LCM particulates at least in part by allowing at least a portion of the liquid material to polymerize in the fluid in the reaction chamber.

Methods of manufacturing lost circulation material at a well site

Methods and compositions including silicate shale inhibitor additives. In some embodiments, the methods include introducing a shale inhibitor additive comprising a silicate anion and a quaternary ammonium cation into a treatment fluid; introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation that comprises shale; and allowing the shale inhibitor additive to interact with the shale in the subterranean formation to at least partially inhibit the shale.

Silicate shale inhibitor additives

Described herein are methods to determine an amount of shale inhibitor in drilling fluids used in wellbore operations. In some cases, methods include receiving a sample of a drilling fluid, removing solids from the sample to produce a solids-free fluid, contacting the solids-free fluid with an anion to produce a precipitate in a test solution, and determining an amount of an amine-based shale inhibitor within the sample by measuring the amount of the precipitate in the test solution.

Detecting amine-based inhibitors in drilling fluids

The disclosure provides a method for determining a composition of a fluid. The method comprises diverting a sample of a portion of the fluid to a test chamber. The method further comprises actuating a heat source disposed around the test chamber to increase the temperature within the test chamber to produce vapors from the sample of the portion of the fluid and directing the vapors from the sample of the portion of the fluid to a chemical sensor array comprising one or more chemical sensors. The method further comprises determining a composition of the vapors from the sample of portion of the fluid, wherein the composition of the vapors is associated with the composition of the fluid.

Methods to use chemo-resistive sensors for wellbore production

Compositions and methods involving polyvalent cation reactive polymers for use as lost circulation materials in subterranean treatment operations are provided. In some embodiments, the methods include forming a treatment fluid including a base fluid, a source of a polyvalent cation, a polyvalent cation reactive polymer, and an acid precursor; introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation; and allowing the treatment fluid to at least partially set.

Reactive polymeric lost circulation materials

A fluid is provided. The fluid includes a base fluid and an additive. The additive has a marker functional group that absorbs infrared radiation having a wavelength in a predetermined range between about 2100 cmand about 2300 cm.

System and method to quantify fluid additives

Compositions and methods for using those compositions to at least partially stabilize subterranean formations are provided. In one embodiment, the methods include providing a treatment fluid including an aqueous base fluid and an additive including a low molecular mass organic gelator; introducing the treatment fluid into at least a portion of a subterranean formation to contact at least a portion of the subterranean formation that includes shale; and allowing the additive to interact with the shale to at least partially stabilize the shale.

Low molecular mass organic gelator wellbore stabilizers

A method of detecting an amine-based additive in a wellbore servicing fluid (WSF) comprising contacting an aliquot of WSF with an amine detector compound and an aqueous salt solution to form a detection solution; wherein the aqueous salt solution comprises an inorganic salt and organic carboxylate salt; wherein the WSF comprises the amine-based additive; and wherein the detection solution is characterized by at least one absorption peak wavelength in the range of 380-760 nm; detecting an absorption intensity for detection solution at a wavelength within about &#xb1;20% of the at least one absorption peak wavelength; comparing the absorption intensity of detection solution at the wavelength within about &#xb1;20% of the at least one absorption peak wavelength with a target absorption intensity of amine-based additive to determine the amount of amine-based additive in WSF; and comparing the amount of amine-based additive in WSF with a target amount of amine-based additive.

Growing community of inventors

Porter, TX, United States of America

Preston Andrew May