Schlumberger Technology Corporation

Chevron U.s.a. Inc.

Chevron Australia Pty Ltd

Michael J Fuller

Trevor Lloyd Hughes

Jill F Geddes

Bruno Drochon

Evgeny Borisovich Barmatov

Sergey Makarychev-Mikhailov

Douglas Cory Arceneaux

Diankui Fu

John W Still

Mohan K R Panga

Syed Afaq Ali

Bruno Lecerf

Balkrishna Gadiyar

Wayne W Frenier

Murtaza Ziauddin

Anatoly Vladimirovich Medvedev

Raymond J Tibbles

Slaheddine Kefi

Ryan Hartman

Marieliz Garcia-Lopez De Victoria

Isabelle Couillet

Laurent Pirolli

Caleb Kimbrell Carroll

Zhijun Xiao

William Stephen Averill

John Bryan Trenery, Jr

Stephen Nigel Davies

Dana Earl Witt

Konstantin Viktorovich Vidma

William David Norman

Peter James Clark

Helene Bulte

Eduardo Martinez

Paul Michael Benet

George Nabil Farag

Benjamin James Krane

Maricel Marquez

William Dale Wood

Rodney Joseph Wetzel, Jr

Ivan Sergeyevich Glaznev

A method of deploying an expandable composition in a cement top job in a well system includes identifying evidence of actual or potential gas migration within an annulus cement of the well system. Once the evidence of gas migration is identified, a first component and a second component are mixed in a mixer to form the expandable composition and the expandable composition is pumped from the mixer through a conduit to a top of cement of the annulus cement. The expandable composition expands to form an expanded composition that seals the annulus above the top of cement of the annulus cement. Cement can be added onto the expanded composition.

Cement top jobs in wellbore annuli using expandable compositions

An open hole formation surface within a wellbore of a well system is sealed with a polymer seal. A deployment system is inserted into the wellbore to the location of the open hole formation surface. The open hole formation surface may be located at the bottom of the wellbore or at an interval between two casing strings. The deployment system delivers an expandable polymer grout system to the location of the open hole formation surface. The expandable polymer grout system cures to form the polymer seal on the open hole formation surface.

Expandable polymer grout for sealing subterranean formations

A deployment system for deploying a polymer grout system includes a first conduit line for conveying an isocyanate component, a second conduit line for conveying an organic polyol component, and a mixer for mixing the isocyanate component and the organic polyol component to form an expandable polymer grout system that is deployed to a target location associated with a wellbore. The deployment system can include a tailpipe and/or bridge plug for directing the expandable polymer grout system to the target location. The disclosure also includes methods of using the foregoing deployment system.

Deployment methods for expandable polymer grout for plug and abandonment applications

An annular blowout preventer includes a body, a piston disposed within the body, and a packing unit disposed adjacent the piston. The packing unit includes an packer body surrounding an opening. The packer body is fabricated from a first material. The packing unit further includes a second material disposed between the packer body and the opening, the second material being less rigid than the first material. The packer body and the second material constrict the opening when the annular blowout preventer is actuated. The second material creates a seal around a tool disposed within the opening. The second material fills in one or more crevices or recesses on an outer perimeter of the tool.

Annular blowout preventer (BOP) packing unit with integrated secondary sealing compound

A method includes placing a treatment fluid including a crosslinked gel in a wellbore penetrating a subterranean formation, the crosslinked gel including a gelling agent and a borate crosslinking agent, de-crosslinking a portion of the crosslinked gel, the de-crosslinking induced by a sufficient change in operating pressure, the de-crosslinking providing a release of active sites on the borate crosslinking agent and reducing the viscosity of the treatment fluid, and providing a borate-affinity agent to capture the released active sites on the borate crosslinking agent. A fracturing fluid includes a gelling agent, a borate crosslinking agent, a latent borate-affinity agent, and a proppant.

Methods for altering fluid rheology

A sand control screen assembly includes a base pipe, a mesh layer, and a sand screen layer. The base pipe includes a tubular surface and a plurality of perforations formed in the surface. The mesh layer is disposed around the base pipe. Additionally, the mesh layer comprises a plurality of functionalized fibers, wherein one or more of the plurality of functionalized fibers break off from the mesh layer when impacted by one or more particulates. In some embodiments, a sand control screen assembly includes a screen layer with a functionalized coating.

Sand control device and methods for identifying erosion

A technique includes completing a well, including installing a tubing string that includes a screen in the well and installing a fiber-based material outside of the screen. The technique further includes using the well as an injection well, including communicating a fluid into the tubing string to cause an injection flow to be communicated in a fluid flow path from an interior of the tubing string, through the screen and into a formation.

Gravel and fracture packing using fibers

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

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 method of treating a sandstone-containing formation penetrated by a wellbore is carried out by forming a treatment fluid comprising an aqueous fluid containing a hydrogen fluoride source and an amorphous silica precipitation inhibitor. The treatment fluid is introduced into the formation through the wellbore at a pressure below the fracture pressure of the formation to facilitate dissolution of formation materials, optionally as a single stage. The amorphous silica inhibitor may be a polycarboxylate and/or polycarboxylic acid, an organosilane or a phosphonate compound. The amorphous silica inhibitor may be capable of inhibiting precipitation of amorphous silica so that the treatment fluid contains at least about 500 ppm of silicon after at least about 100 minutes subsequent to the treatment fluid being introduced into the formation.

Method of treating sandstone formations with reduced precipitation of silica

Gravel packing a region of a wellbore is carried out using one or more hydrophobically-surfaced particulate materials as the gravel. Placing the gravel pack is carried out using an aqueous carrier liquid, with hydrophobic particulate material suspended in the liquid and a gas to wet the surface of the particles and bind them together as agglomerates. The presence of gas lowers the density of the agglomerates relative to the particulate material in them, so that transport of the particulates is improved. The invention enables the placing of longer, uniformly packed, gravel packs, especially in horizontal and near horizontal wellbores.

Method of gravel packing

A wellbore fluid is an aqueous carrier liquid with first and second hydrophobic particulate materials suspended therein. The first hydrophobic particles have a higher specific gravity than the second hydrophobic particles and the fluid also comprises a gas to wet the surface of the particles and bind them together as agglomerates. The fluid may be a fracturing fluid or gravel packing fluid and the first particulate material may be proppant or gravel. The lighter second particulate material and the gas both reduce the density of the agglomerates which form so that they settle more slowly from the fluid, or are buoyant and do not settle. This facilitates transport and placement in a hydraulic fracture or gravel pack. One application of this is when fracturing a gas-shale with slickwater. The benefit of reduced settling is better placement of proppant so that a greater amount of the fracture is propped open.

A method and apparatus for treating a subterranean formation with a fluid, including forming a fluid including a organosilane and a particulate and introducing the fluid into a subterranean formation with exposed surfaces, wherein the organosilane modifies the particulate or surfaces or both. Also, a method and apparatus for treating a subterranean formation with a fluid, including forming a fluid including an organosilane and introducing the fluid into a subterranean formation with exposed surfaces, wherein the organosilane modifies the surfaces with a first functional group.

Surface modification for cross-linking or breaking interactions with injected fluid

In a method of treating a sandstone-containing formation penetrated by a wellbore, a treatment fluid comprising an aqueous fluid containing a Bronsted acid, a hydrogen fluoride source and an organic acid or salt thereof that is substantially soluble in the aqueous fluid is formed. The treatment fluid contains less than about 2% of fluoride (F) by weight of the fluid and from 2% or less of sodium (Na) by weight of the fluid. The treatment fluid is introduced into the formation through the wellbore as a single-stage without introducing an acid-containing fluid preflush into the formation prior to introducing the treatment fluid.

Growing community of inventors

Houston, TX, United States of America

Michael J Fuller