Halliburton Energy Services, Inc.

Kushabhau Dagadu Teke

Dale E Jamison

Sandeep D Kulkarni

Dhanashree Gajanan Kulkarni

Vikrant Bhavanishankar Wagle

Shadaab Syed Maghrabi

Matthew Lynn Miller

Sharath Savari

Sandeep Kulkarni

John Adrian Hall

Pramod Dadasaheb Nikam

Robert J Murphy

Anita Gantepla

Don L Whitfill

Kunal Sharad Kulkarni

Kunai Sharad Kulkarni

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.

Fiber suspending agent for lost-circulation materials

Some embodiments described herein relate to methods comprising providing a proposed invert emulsion formulation, wherein the proposed invert emulsion formulation comprises an oil phase, an aqueous phase, and a particulates fraction comprising a first sub-fraction and a second sub-fraction, wherein the first sub-fraction comprises high-gravity particulates and the second sub-fraction comprises low-gravity particulates; calculating an initial associative stability value of the proposed invert emulsion based on the degree of association between the aqueous phase and the particulates fraction comprising both the first sub-fraction and the second sub-fraction; manipulating the proposed invert emulsion based on the initial associative stability value so as to produce an associatively stable invert emulsion having a final associative stability value in the range of between about 50% and about 100%; and introducing the associatively stable invert emulsion into a subterranean formation.

Methods of designing an invert emulsion fluid having high associative stability

An environmentally responsible iron chelating additive and method for removing hydrogen sulfide or sulfide ions from drilling and packer fluids and preventing settling of precipitates. Iron chelating agents selected from the group consisting of ferrous lactate, ferrous gluconate, ferrous bis glycinate, ferrous citrate, ferrous acetate, ferrous fumarate, ferrous succinate, ferrous sacchrate, ferrous tartarate, ferrous glycine sulfate, ferrous glutamate, ferrous ascorbate, ferrous polymaltose, or a combination thereof, may be used. When the fluids are oil based, the iron chelating agents are added to the water phase of an emulsion, and the emulsion is added to the fluid. Viscosifiers may also be added to the drilling fluid with the emulsion.

Compositions and method for treating out hydrogen sulfide and preventing settling of precipitate in an environmentally responsible drilling and packer fluid

A treatment fluid and method for simultaneously swelling an oil-swellable elastomer and breaking a filtercake in a well. The treatment fluid includes an emulsion comprising: (i) a continuous oil phase, wherein the oil phase comprises: (a) an oil; and (b) an emulsifier; and (ii) an internal aqueous phase, wherein the aqueous phase comprises: (a) water; and (b) a water-soluble hydrolyzable ester of a carboxylic acid; wherein the emulsion is stable to hydrolysis of the water-soluble hydrolyzable ester of the carboxylic acid. A method of treating a well includes the steps of: (A) forming the treatment fluid; and (B) introducing the treatment fluid into the portion of the wellbore, wherein: (i) a filtercake has been previously formed in the portion of the wellbore, wherein the filtercake comprises an acid-soluble or an acid-degradable material; and (ii) an oil-swellable elastomer has been previously deposited or positioned in the portion of the wellbore.

Invert emulsion for swelling elastomer and filtercake removal in a well

A method for quantitatively determining dynamic barite sag in drilling fluids includes measuring rheological properties with viscometers and/or rheometers, and introducing the parameters into an equation to obtain the sag rate.

Methods for predicting dynamic sag using viscometer/rheometer data

Methods of drilling or treating a well including the steps of: designing a fluid with high-gravity solids (e.g., barite); calculating the sagged fluid mud weight after allowing for sag according to formulas; forming a fluid according to the sagged fluid mud weight; and introducing the fluid into the well. The methods can be used to help control the well or to avoid excessive drilling torque or pressure, kick, or lost circulation due to sag of high-gravity solids such as barite.

Drilling a well with predicting sagged fluid composition and mud weight

A method of predictive modeling of a treatment fluid comprises: determining the value of properties of a base fluid and insoluble particulates; providing a proposed suspending agent; performing a first calculation of the suspendability of the proposed suspending agent as determined by a yield gravity function equation; evaluating if the result from the first calculation indicates a stable treatment fluid comprising the base fluid, the insoluble particulates, and the proposed suspending agent, or if the result does not indicate a stable treatment fluid, then: modifying the value of at least one of the properties of the proposed suspending agent, base fluid, and/or insoluble particulate; and performing a second calculation, wherein the same or different property values are continued to be modified and the calculation is continued to be performed until the result indicates a stable treatment fluid; and introducing the stable treatment fluid into a wellbore.

Modeling the suspendability of fibers in a treatment fluid using equations

An invert emulsion drilling fluid, and a method of drilling with such fluid, having improved rheology at low mud weights and high temperatures. The improved rheology is effected with addition of hydrophobic amines, most preferably dimer diamines.

Invert drilling fluids having enhanced rheology and methods of drilling boreholes

An apparatus and method for determining a formation/fluid interaction of a target formation and a target drilling fluid is described herein. The method may include training an artificial neural network using a training data set. The training data set may include a formation characteristic of a source formation and a fluid characteristic of a source drilling fluid and experimental data on source formation/fluid interaction. Once the artificial neural network is trained, a formation characteristic of the target formation and fluid characteristic of target drilling fluid may be input. The formation characteristic of the target formation may correspond to the formation characteristic of the source formation. The fluid characteristic of the target drilling fluid may correspond to the fluid characteristic of the source drilling fluid. A formation/fluid interaction of the target formation and the target drilling fluid may be determined using a value output by the artificial neural network.

Methods and apparatuses for modeling shale characteristics in wellbore servicing fluids using an artificial neural network

A method of servicing a wellbore comprises determining a cation exchange capacity of a sample of a shale, determining a swelling characteristic of the shale using the cation exchange capacity in an equation comprising a term of the form:(cation exchange capacity)where Ais a final swelling volume of the shale in the presence of an aqueous fluid having a salt concentration of z %, and x and y are empirical constants, determining a composition of a wellbore servicing fluid based on the determined swelling characteristic, and drilling the wellbore using the wellbore servicing fluid. The swelling characteristic of the shale can be determined using the cation exchange capacity of the shale and a salt concentration in an equation comprising a term of the form:()*()(cation exchange capacity)where Ais a final swelling volume of the shale in contact with an aqueous fluid having a salt concentration of m %, f(m,z) is a function based on the salt concentration of m % relative to salt concentration of z % in the aqueous fluid in contact with the shale, and x and y are empirical constants defining the relation A=x (cation exchange capacity).

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Kushabhau Dagadu Teke