Halliburton Energy Services, Inc.

Other

Landmark Graphics Corporation

Jeffrey James Miller

William Walter Shumway

Dale E Jamison

Preston Andrew May

Lance Everett Brothers

Jay Paul Deville

Nicholas Charles Braley

Donald R Siems

Patrick Baker

Miren Aranzazu Castanares

Andrew David Vos

Vikrant Bhavanishankar Wagle

Chesnee Lae Davis

Ketan Chimanlal Bhaidasna

Shadaab Syed Maghrabi

Catherine Martin Santos

Katerina V Newman

Sandeep Vasant Chavan

Jonathan Paul Walker

Nivika Rajendra Gupta

Lawrence Edward Miller

Sharad Bhimrao Gotmukle

Yerzhan Ayapbergenov

Diego Fernando Sanchez

Johannes Rygg

Chris L Bosch

Trevor Toppen

Ben Law

Henry Magne Hakstad

Patrick Chris Baker

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

Methods of treating a subterranean formation including shale include preparing a treatment fluid by mixing an aqueous base fluid and a dry polyvinyl pyrrolidone (PVP) in flake or powder form having a molecular weight between about 500,000 and about 2,000,000 and introducing the treatment fluid in the subterranean formation.

Compositions and methods for inhibiting shale and preventing shale accretion

Invert emulsions can be used in oil and gas operations. A fluid loss control additive (FLCA) is a component of the fluid that can be utilized to control or minimize fluid loss into a subterranean formation. The FLCA can be a chemically modified vegetable oil that is biodegradable. Vegetable oils having some or all of the functional groups sulfonated can be used as FLCA. A water-soluble salt that has been dissolved in the discontinuous phase of the invert emulsion can combine with the FLCA to form a wax-like, solid mass.

Modified vegetable oil as fluid loss control additive

A method of determining wettability may include: measuring an electrical property of a drilling fluid; and correlating the electrical property to wettability.

Using electrical signal as a measure of water wettability for direct emulsion fluids

Treatment fluids and methods of using a treatment fluid for minimizing fluid loss in a wellbore are disclosed. A method may comprise providing a drill-in fluid. The drill-in fluid may comprise an aqueous liquid, a base oil, a polyol, an emulsifying surfactant, and a solid bridging agent. The method may further comprise circulating the drill-in fluid through a drill-string and past a drill bit. The method may further comprise drilling in a reservoir section of a subterranean formation to extend a wellbore in the reservoir section the drill-in fluid is circulated therein.

Oil-based drill-in fluid with enhanced fluid loss properties

A method of reducing a density of a density of a stable emulsion drilling fluid may comprise providing a stable emulsion drilling fluid comprising: an aqueous liquid; a biopolymer; an emulsifier; solid particulates; and an oil; wherein the stable emulsion drilling fluid is capable of remaining in quiescent storage at approximately 70&#xb0; F. and atmospheric pressure without phase separation for about 8 hours or longer; circulating the stable emulsion drilling fluid though a drill string and annulus; adding additional oil to the stable emulsion drilling fluid to decrease the density of the stable emulsion drilling fluid and produce a reduced density stable emulsion drilling fluid; and circulating the reduced density stable emulsion drilling fluid though the drill string and the annulus.

Stable emulsion drilling fluids

Solid shale inhibitor additives and methods of using such additives to, for example, inhibit shale are provided. In some embodiments, such methods include providing an aqueous treatment fluid that includes an aqueous base fluid and a solid shale inhibitor additive, the solid shale inhibitor additive including carrier particles and a treatment composition that includes a shale inhibitor; and introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation.

Solid shale inhibitor additives

The embodiments of the present disclosure relate generally to subterranean formation operations and, more particularly, to milling oilfield particulates for use in subterranean formation operations. The embodiments provide systems and methods which may include jet mills that can be customized to grind desirably sized crude oilfield particulates, thereby creating operational oilfield particulates, and containerized for ease of use, movement, and shipping.

Milling oilfield particulates

Various embodiments disclosed relate to methods of cleaning invert emulsion drilling fluids. In various embodiments, the present invention provides a method of cleaning a drilling fluid. The method includes cleaning a used invert emulsion drilling fluid that includes drilled cuttings to form a cleaned invert emulsion drilling fluid. The cleaning includes processing the used invert emulsion drilling fluid in a separator to remove at least some of the drilled cuttings therefrom.

Methods of cleaning invert emulsion drilling fluids

A method for dynamically evaluating sag of a fluid by providing a test volume of the fluid into an angled sample chamber, wherein the angled sample chamber has a central axis, and wherein the central axis of the angled sample chamber is angled relative to horizontal, rotating the sample chamber about the central axis for a test period, and determining a sag density, wherein the sag density is a density of a fluid sample taken at a sample location within a stratum of the test volume of the fluid present in the angled sample chamber.

Inclined roller oven for dynamic sag evaluation/determination of settling velocity

The embodiments herein relate generally to subterranean formation operations and, more particularly, to enhancing aging testing to characterize settling of particulates in treatment fluids for use in subterranean formation operations. The embodiments use a test cell apparatus comprising a test cell body having an open end for receiving a treatment fluid into an interior of the test cell body, the interior having a floating piston for separating the treatment fluid from a pressurization fluid; a sampling port extending from the open end and having a sample valve for receiving samples of the treatment fluid from the sampling port; a pressure input for pressurizing the interior; and a sealing assembly adapted to be inserted into the test cell body in contact with the interior to fluidly seal the open end and through which the sampling port extends, the sealing assembly comprising a retainable test cell cap.

Aging testing apparatus and use thereof

A workflow management system that integrates well planning workflows with technical applications, audits change events, provides personnel authorizations, tracks and manages change events, and integrates best practice documentation and data at any point along the workflow.

Well planning workflow system, method and computer-program product

Combined fish cleaner grate and tray

Among the methods provided is a method of drilling a subterranean well with an invert emulsion fluid comprising: providing an invert emulsion fluid formed by combining components that comprise: an oil-based continuous phase; an aqueous discontinuous phase; and a polar hydrophobic additive that comprises a polar hydrophobe, wherein the polar hydrophobic additive may substantially increases the yield point, the low-shear yield point, or both of the invert emulsion fluid relative to a fluid without a polar hydrophobic additive while limiting the change in the plastic viscosity to no more than about 35% of the change in the property with the largest increase; and placing the invert emulsion fluid in a subterranean formation.

Growing community of inventors

Spring, TX, United States of America

Jeffrey James Miller