Schlumberger Technology Corporation

Bruno Drochon

John W Still

Mohan K R Panga

Balkrishna Gadiyar

Ryan Hartman

Trevor Lloyd Hughes

Bryan Stamm

Philip F Sullivan

Simon James

Gregory Kubala

Carlos Abad

Gary John Tustin

Evgeny Borisovich Barmatov

Peter J Photos

Michael J Fuller

Sergey Makarychev-Mikhailov

Jill F Geddes

Michel Michaux

Yenny Christanti

Sylwia Komocki

Yiyan Chen

Marie Noelle Dessinges

Isabelle Couillet

Syed Afaq Ali

Lijun Lin

Anthony R H Goodwin

Paul R Howard

Alejandro Pena

Samuel Danican

Juan-Carlos Santamaria

Ramsey Buoy

Beilin Ding

Dinesh R Patel

Brian Oliver Clark

Julian J Pop

Reza Taherian

Jesse Lee

Mehmet Parlar

Christian Chouzenoux

Sylvaine Le Roy-Delage

Kevin W England

Nitin Y Vaidya

Pierre Maroy

Stephen Dyer

Marieliz Garcia-Lopez De Victoria

Yves Manin

Graham Watson

Valerie Lafitte

Véronique Barlet-Gouedard

Emmanuel Therond

Clara Carelli

Laura Schafer

Bernard Piot

Pierre J Daniel

Cecilia Nguyen

Gunnar Debruijn

Laurent Delabroy

Christelle Vatry

Laura Shafer

Isaac Aviles

Juan Carrasquilla

Frederic Thery

Caritey Jean-Philippe

An aqueous fluid, possibly a wellbore fracturing fluid, comprises an aqueous solution or dispersion of a first polymer, which may be polysaccharide, as a thickener and a cross linking agent to enhance the viscosity of the fluid by crosslinking the first polymer, wherein the crosslinking agent is a second polymer comprising at least one polymer chain with phenyl boronate groups distributed along the polymer chain and the phenyl boronic acid groups have nitrogen attached to the phenyl group at a position which is meta relative to the boronate group.

Thickening of fluids

Corrosion of steel by aqueous acidic solution when treating a wellbore with acid is inhibited by a procedure in which the steel is initially exposed to a first aqueous solution containing one or more corrosion inhibiting constituents which provide both corrosion inhibitor and hydrophobic liquid and deposit a corrosion inhibiting film on the steel surface and then exposed to an acidic second aqueous solution containing one or more such corrosion inhibiting constituents at a lower concentration. During this second period, the lower concentration of corrosion inhibiting constituents in the second aqueous solution maintains the film already established on the steel surface. Weight loss through corrosion in the second stage is lower than the weight loss which otherwise would be observed. Overall there can be reduction of both weight loss and consumption of corrosion inhibitor.

Corrosion inhibition

A storable composition for oilfield application including a slurry of a carrier fluid and a particulate blend made of proppant; the particulate blend comprising at least a first amount of particulates having a first average particle size between about 100 and 5000 &#x3bc;m and at least a second amount of particulates having a second average particle size between about three and twenty times smaller than the first average particle size; such that a packed volume fraction of the particulate blend exceeds 0.74 and the particulate blend volume is sufficient to substantially avoid settling of the particulate in the carrier fluid.

Methods to deliver fluids on a well site with variable solids concentration from solid slurries

Compositions that swell on contact with water contain a non-swellable thermoplastic or thermoset polymer and a swellable inorganic compound. In particular, the compositions are suitable for use in subterranean wells such as those used in the oil and gas industry. The polymer may be polypropylene and the inorganic compound may be magnesium oxide.

Swellable compositions for borehole applications

A method of cementing a well is disclosed. The method comprising pumping into the well a cement slurry comprising a solid blend including cement, water, and a fluid loss control agent, and allowing the cement slurry to set. The fluid loss control agent comprises a styrene-butadiene latex and a high molecular-weight water-soluble polymer such as a copolymer AMPS-Am. The addition of the water-soluble polymer allows drastic reduction of the quantity of latex required to achieve fluid loss control performance and even gas migration control.

Fluid loss control agents and compositions for cementing oil and gas wells comprising said fluid loss control agent

A wellbore fluid comprises an aqueous carrier liquid, hydrophobic fibers suspended therein, hydrophobic particulate material also suspended in the carrier liquid, and a gas to wet the surfaces of the particles and fibers and bind them together as agglomerates. The wellbore fluid may be a slickwater fracturing fluid and may be used for fracturing a tight gas reservoir. Using a combination of hydrophobic particulate material, hydrophobic fibers and gas inhibits settling out of the particulate material from an aqueous liquid. Because the gas acts to wet the surfaces of both materials and agglomerates them, the particulate material is made to adhere to the fibers; the fibers form a network which hinders settling of the particulate material adhering to them, and the agglomerates contain gas and so have a bulk density which is less than the specific gravity of the solids contained in the agglomerates.

Delivery of particulate material below ground

This invention relates to compositions and methods for treating subterranean formations, in particular, oilfield stimulation compositions and methods using water-in-water polymer emulsions to uniformly dissolve a rheologically active polymer, such as a thickener or friction reducer, in the treatment fluid. The emulsions have a low viscosity and are easily pumped for mixing into a treatment fluid, where upon dilution with an aqueous medium, the polymer is easily hydrated without forming fish-eyes. The partitioning agent in the water-in-water emulsion does not generally affect the rheology of the treatment fluid. The invention also relates to further processing of the emulsion by wet grinding, high shear mixing and/or heating to enhance the hydration rate in the preparation of the well treatment fluid.

Polymer delivery in well treatment applications

A thermoviscoelastic system (TVE) fluid useful in a well treatment method can include a hydrophobically-modified polymer and a viscoelastic surfactant (VES) in an aqueous medium, wherein the polymer has a lower critical solution temperature (LCST). The polymer can have water solubility for preparation below the LCST, and the TVE has a low viscosity for pumping down a well bore in communication with a subterranean formation. When the TVE is heated above the LCST, interaction between the hydrophobic groups of the polymer and the VES form a cross-linked network to increase the viscosity to transport proppant into a fracture. The thickened TVE can have a low leak-off rate, optionally including colloidal particles or other fluid loss control agent, and can be broken by contact with hydrocarbons as during flowback from the reservoir.

Thermoviscoelastic system fluid and well treatment method

A composition and method are disclosed. The composition includes a carrier fluid and a solids mixture combined to form a slurry, wherein the solids mixture comprises a plurality of volume-averaged particle size distribution (PSD) modes, wherein a first PSD mode comprises solids having a volume-average median size at least three times larger than the volume-average median size of a second PSD mode such that a packed volume fraction of the solids mixture exceeds 0.75, and wherein the solids mixture comprises a degradable material and includes a reactive solid. The method includes circulating the slurry through a wellbore to form a pack in a fracture and/or a screen-wellbore annulus; degrading the degradable material to increase porosity and permeability of the pack; and producing a reservoir fluid through the permeable pack.

High solids content methods and slurries

A wellbore fluid comprises an aqueous carrier liquid, hydrophobic particulate material suspended therein and a gas to wet the surface of the particles and bind them together as agglomerates. The hydrophobic particulate material has a specified maximum volume median particle size dof not more than 200 micron, and/or a minimum surface area of at least 30 mper liter. Agglomerates of the particles contain gas and so have a bulk density lower than the density of the particles. This reduces the rate of settling. The fluid is particularly envisaged as a slickwater fracturing fluid in which the suspended particles are proppant. The small particle size and/or substantial surface area increases the amount of gas which can be retained within agglomerates and so enhances the buoyancy of the agglomerates. The end result is that a greater proportion of a hydraulic fracture is propped open.

A spacer fluid comprises a fluid and a viscosity agent. The viscosity agent is a mixture of at least two polyvinylalcohol compositions. A first polyvinylalcohol composition comprises polyvinylalcohols having a first degree of hydrolysis and a second polyvinylalcohol composition comprises polyvinylalcohols having a second degree of hydrolysis. The first and second degrees of hydrolysis are substantially different such that the rheology of the spacer fluid is stable during temperatures changes.

Spacer fluid additive

A system and method for determining the asphaltene content of a downhole oil sample are provided. In one example, the method includes obtaining a hydrocarbon sample from a hydrocarbon formation of a reservoir at a given depth using a downhole tool. A liquid phase of the hydrocarbon sample is isolated within the downhole tool and the liquid phase is subjected to downhole analysis within the downhole tool to create a chromatography sample. The downhole analysis is based at least partially on size exclusion chromatography. A first property of the chromatography sample is measured to obtain a measured value, and a second property of the chromatography sample is estimated based on the measured value and known calibration curves.

Downhole determination of asphaltene content

It is proposed a new fluid loss control agent useful for the cementation of oil or gas wells. This fluid loss control agent consists of a mixture of a styrene-butadiene latex and a high molecular weight water-soluble polymer such as a copolymer AMPS-Am. The addition of the water-soluble polymer allows drastic reduction of the quantity of latex required to achieve fluid loss control performance and even gas migration control.

A method includes providing a slurry comprising a carrier fluid and a solids mixture, and injecting said slurry in a wellbore wherein the solids mixture comprises at least two volume-averaged particle size distribution (PSD) modes, wherein a first PSD mode comprises solids having a volume-average median size at least three times larger than the volume-average median size of a second PSD mode such that a packed volume fraction (PVF) of the solids mixture exceeds 0.75.

High solids content slurry systems and methods

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Cambridge, United Kingdom

Bruno Drochon