Halliburton Energy Services, Inc.

Sandip Prabhakar Patil

Rahul Chandrakant Patil

Krishna M Ravi

Ganesh Shriniwas Pangu

Sheetal Singh

Abhimanyu Pramod Deshpande

Samuel Jason Lewis

Ramesh Muthusamy

Siva Rama Krishna Jandhyala

Sohini Bose

Ashok K Santra

Tamal Kumar Sen

Kyriacos Agapiou

Trissa Joseph

Vaishali Mishra

Tushar Sureshgiri Gosavi

Jiten Chatterji

Craig Wayne Roddy

D Chad Brenneis

Krishna Babu Yerubandi

Ricky Layne Covington

Abhijit Tarafdar

Sairam K S Pindiprolu

Waseem Abdulrazzaq

Reem Mohammed Alburaikan

Dibyadarshani Senapati

Balasundaram Balaraman

Girish Dinkar Sarap

Marcus Allen Duffy

Keith Armstrong

Yogesh Barhate

Malharrao Hambirrao Jadhav

Maithili Ashok Dumbre

B Raghava Reddy

William Cecil Pearl, Jr

Rajender Salla

Sam Jason Lewis

Benjamin John Iverson

Sunita Sameer Kadam

Shoy George Chittattukara

Venkata Gopala Rao Palla

Crystal L Keys

Sairam Ks Pindiprolu

Remitha Ak

Anupom Sabhapondit

Shreya Mohan

William Cecil Pearl

Paul Michael Osborne

Sudhir Maruti Nimane

Ravinder Gahlawat

Faisal Saeed

Kameswara Sri Sairam Pindiprolu

Javier Urdaneta

Rahul Chandrakanth Patil

Rahul Chamdrakant Patil

Sourav Ghosh

Gauri Sudhir Bhide

Siva Rama Jandhyala

Kameswara Sri Pindiprolu

A method of servicing a wellbore penetrating a subterranean formation with a thixotropic cement composition is provided. The thixotropic cement composition includes a cementitious material, silica fume, graphene oxide, and an aqueous fluid, can have a 10-minute gel strength of from about 20 lbf/100 ftto about 300 lbf/100 ft, and can be used to service a wellbore (e.g., to reduce lost circulation in the wellbore). By incorporating graphene oxide into the thixotropic cement composition, the thixotropic cement composition can have a higher 10-minute gel strength than a reference composition absent the graphene oxide.

Thixotropic cement slurry with graphene oxide

Disclosed herein is a method of servicing a wellbore penetrating a subterranean formation with a thixotropic cement composition. The thixotropic cement composition comprises a cementitious material, maltodextrin, and an aqueous fluid, has a 10-minute gel strength of from about 30 lbf/100 ftto about 300 lbf/100 ft, and can be used to reduce lost circulation in the wellbore. By incorporating maltodextrin into the thixotropic cement composition as disclosed herein, the thixotropic cement composition can have a similar 10-minute gel strength and an increased thickening time when compared to a reference composition.

Methods of making and using a thixotropic cement composition

A thixotropic slurry material can be used in a wellbore during a wellbore operation. The wellbore operation can include a drilling operation, a cementing operation, or any other suitable operation that may include injecting a liquid material into the wellbore. The thixotropic slurry material can be a mixture of a cement, a clay mineral, and a suspending agent and can be injected into a wellbore during the wellbore operation.

Thixotropic slurry with enhanced reliability for use in a wellbore

A method may include: introducing a silane based aqueous soluble resin into a wellbore, wherein the silane based aqueous soluble resin comprises a glycidyl alkoxy silane containing resin and an amino alkoxy silane hardener. The silane based aqueous soluble resin may include 3-glycidoxypropyl trimethoxy silane and n-(3-(trimethoxysilyl)propyl)ethylenediamine.

In-situ aerogel type hydraulic cement composition for subterranean applications

The current method comprises producing a loss control blend by selecting blend ingredients that contribute to thixotropy of the blend, density of the blend, and compressive strength of the set blend, wherein at least one of the blend ingredients contributes positively to all three of these attributes.

Contribution based approach to increase the density and strength of current thixotropic loss control solutions

Provided are methods, compositions, and systems embodying cement compositions and the synergistic effect of lost circulation materials (LCMs) and fluid loss control additives (FLCAs) thereupon for cementing subterranean zones. A method of subterranean well cementing, comprising providing a cement composition comprising a hydraulic cement, a first FLCA, a LCM, and water, wherein the first FLCA comprises a water-soluble polymer with repeating units comprising a 5- to 6-membered cyclic amide; introducing the cement composition into a wellbore penetrating a subterranean formation, wherein inclusion of the first FLCA and the LCM in the cement composition fluid reduces fluid loss into the subterranean formation, wherein the subterranean formation has fractures with a width of from about 1 micron to about 800 microns, and wherein the subterranean formation has a permeability of about 1 millidarcy to about 300 Darcy; and allowing the cement composition to set in the subterranean formation.

Combination of fluid loss control additive and lost circulation materials to control losses in formation

A method of treating a subterranean formation can include: introducing a first fluid into a wellbore penetrating the subterranean formation; introducing a second fluid into the wellbore after introduction of the first fluid, wherein the second fluid comprises: a base fluid comprising water; a viscosifier; and a stabilizer, and wherein the second fluid has a rheological 3-rpm dial reading to 300-rpm dial reading ratio in the range of 1:1 to 1:3; and introducing a third fluid into the wellbore after introduction of the second fluid, wherein the second fluid inhibits or prevents the first fluid from mixing with the third fluid. The second fluid can be a liquid plug that substantially inhibits or prevents the first fluid from mixing with the third fluid. The first fluid can be a drilling mud or spacer fluid. The third fluid can be a spacer fluid or a cement composition.

Liquid plug for wellbore operations

A method of treating a well comprising introducing a well treatment fluid into the well, and a well treatment fluid, are provided. The well treatment fluid comprises an aqueous base fluid, sepiolite clay, and a polymer component selected from the group of an acryloylmorpholine polymer, a polyvinylpyrrolidone polymer, and mixtures thereof. In one embodiment, for example, the method is a method of drilling a well. In this embodiment, the well treatment fluid is a drilling fluid.

Downhole high temperature rheology control

A method of servicing a wellbore penetrating a subterranean formation, comprising placing into the wellbore a cementitious composition comprising a crosslinked polymeric microgel, a clay, a cementitious material, and water. By incorporating the crosslinked polymeric microgel and the clay as disclosed herein, the cementitious composition can be used at relatively high temperatures.

Methods of making and using a high temperature cementitious composition

A method of servicing a wellbore penetrating a subterranean formation, comprising placing a wellbore servicing fluid (WSF) into the wellbore proximate a permeable zone having an average fracture width of about W microns, wherein the WSF comprises a particulate blend and water, and wherein the particulate blend comprises (a) a type A particulate material characterized by a weight average particle size of equal to or greater than about W/3 microns, and (b) a type B particulate material characterized by a weight average particle size of less than about W/3 microns, wherein a weight ratio of the type A particulate material to the type B particulate material is from about 0.05 to about 5.

Methods of making and using a wellbore servicing fluid for controlling losses in permeable zones

Described herein are plugging materials with polysaccharides that can be used in wellbore operations. A plugging material can include hydraulic cement, amorphous silica, polysaccharides, a retarder, clay, and an aqueous base, where the material is injectable into a wellbore. The polysaccharides can be cross-linked with borate. The retarder can be at least one of an organo phosphoric acid, a modified sulfonated styrene-maleic anhydride polymer, lignosulfonate, or a polyacrylic acid.

Polysaccharide lost circulation materials for wellbore operations

A method of servicing a wellbore in a formation comprising circulating in the wellbore a wellbore servicing fluid wherein an equivalent circulating density of the wellbore servicing fluid is from about 1% to about 15% greater than a fracture pressure of the formation, and introducing to the wellbore a balloon-inhibiting tunable spacer (BITS) fluid wherein at least about 1 wt. % of the BITS fluid is retained by the formation.

Methods and compositions for mitigating fluid loss from well ballooning

The present disclosure provides methods, compositions, and systems embodying cement compositions and the synergistic effect of lost circulation materials (LCMs) and fluid loss control additives (FLCAs) thereupon for cementing subterranean zones. A method of subterranean well cementing, comprising providing a cement composition comprising a hydraulic cement, a first FLCA, an LCM, and water, wherein the first FLCA comprises a water-soluble polymer with repeating units comprising a 5- to 6-membered cyclic amide; introducing the cement composition into a wellbore penetrating a subterranean formation, wherein inclusion of the first FLCA and the LCM in the cement composition fluid reduces fluid loss into the subterranean formation, wherein the subterranean formation has fractures with a width of from about 1 micron to about 800 microns, and wherein the subterranean formation has a permeability of about 1 milliDarcy to about 300 Darcy; and allowing the cement composition to set in the subterranean formation.

A method of treating a well that includes introducing a well treatment fluid into the well, and a well treatment fluid, are provided. The well treatment fluid comprises an aqueous base fluid, a bridging agent, a viscosifying agent, and a water soluble, biodegradable graft copolymer. In one embodiment, for example, the method is a method of cementing a casing in a well. In this embodiment, the well treatment fluid is a cement spacer fluid.

Well treatment fluid having biodegradable fluid loss control agent

Methods of treating a subterranean formation including providing a spacer fluid including acrylamide/2-acrylamido-2-methylpropane sulfonic acid grafted copolymer (acrylamide copolymer), polyethylene glycol alkyl ether sulfate (PEGAES), and ethoxylated nonylphenol (ENP), and introducing the spacer fluid into a wellbore of the subterranean formation to displace at least a portion of a first fluid from the wellbore. The spacer fluid maintains its yield point for at least half an hour when subjected to a temperature of greater than 300&#xb0; F.

Spacer fluids with stability at high temperatures

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Pune, India

Sandip Prabhakar Patil