Schlumberger Technology Corporation

Jill F Geddes

Trevor Lloyd Hughes

Evgeny Borisovich Barmatov

Michael J Fuller

Bruno Drochon

Sergey Makarychev-Mikhailov

Lynne Patricia Crawford

Man Yi Ho

Dean Michael Willberg

Paul Barnes

Bruce Alexander Mackay

Michaela Nagl-Vogel

A method for measuring average thickness of a metal or alloy coating on a metal or alloy substrate using an X-ray fluorescence (XRF) spectrometer is used when the coating has an uneven surface at different distances from a measurement window of the XRF spectrometer. The method includes measuring elemental composition of the coating or substrate using the XRF spectrometer and obtaining the average thickness of the coating using a calibration relationship between coating thickness and elemental composition of the coating or substrate. The metal or alloy coating may be a metal or alloy coating of a plurality of outer armor wires wrapped around a cable. The method may be used to analyze coating thickness changes over time or along the length of the cable, or to analyze a corrosive environment in order to choose optimal material for a metal or alloy coating.

Measurement of metal or alloy coating

A method for measuring a thickness of a deposit layer on a metal or alloy substrate using an X-ray fluorescence (XRF) spectrometer, where the deposit layer includes scale deposits or corrosion products. As part of the method, an elemental composition of the deposit layer or the metal or alloy substrate is measured using the XRF spectrometer. The thickness of the deposit layer is obtained from the elemental composition using a calibration relationship between deposit layer thicknesses and corresponding elemental compositions of the deposit layer or the metal/alloy substrate. The method can be applied to determine the rate of deposit layer formation and evaluate the effectiveness of a treatment.

Measurement of thickness of scale or corrosion

An aqueous acid composition that may be used, for example, in a matrix acidizing treatment can include an acid, a polymeric acid corrosion inhibitor, and an acid corrosion inhibitor intensifier. The acid corrosion inhibitor can include iodide ions and metal ions, with the metal ions being one or more of copper, silver, bismuth, or antimony. The molar ratio of metal ions to iodide ions can be 1:X, where X is greater than or equal to 2. The polymer of the polymeric acid corrosion inhibitor can have a molecular weight less than 100,000 g/mol.

Aqueous acidic compositions with a corrosion inhibitor

A method of inhibiting corrosion of duplex stainless steel by aqueous acidic solution, comprises carrying out a preliminary treatment which is passivation of the steel while exposing the steel to a first aqueous acidic solution containing at least one organic corrosion inhibitor able to adsorb to a steel surface, so as to deposit a passivating and corrosion inhibiting film on the steel surface; and thereafter during a second period of time exposing the steel to a second aqueous acidic solution different from the first aqueous acidic solution and also containing at least one organic corrosion inhibitor able to adsorb to a steel. The second aqueous acidic solution maintains the film on the steel surface, such that weight loss through corrosion in the second period of time is lower than the weight loss which would be observed with the same second aqueous acidic solution but without carrying out the preliminary treatment.

Corrosion inhibition

A corrosion inhibiting composition which is a liquid carrier in which is dissolved or dispersed a corrosion inhibitor compound comprising at least one moiety (A) which is an aliphatic, aromatic or mixed aliphatic/aromatic structure containing one or more hetero atoms which are nitrogen, oxygen, phosphorus or sulphur, and also at least one moiety (B) which contains one or more polymerisable groups containing double or triple bonded carbon, with the moieties (A) and (B) directly or indirectly covalently connected together.

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.

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

Solid material required at a subterranean location is supplied from the surface suspended in a carrier liquid and agglomerated below ground by means of a binding liquid. To achieve agglomeration, the binding liquid and the particulate solid are similar to each other but opposite to the carrier liquid in hydrophilic/hydrophobic character. The solid and the binding liquid may both be hydrophobic while the carrier liquid is hydrophilic, or vice versa. The solid may be hydrophobically surface modified to render it hydrophobic. The binding liquid may be provided as a precursor which converts to the binding liquid below ground to trigger agglomeration after arrival at the subterranean location. The agglomerates may function as proppant heterogeneously placed in a fracture of a reservoir, or may serve to block an unwanted path of flow. The binding liquid may polymerise after agglomeration so as to stabilise and strengthen the agglomerates.

Manipulation of flow underground

A method and composition for treating a subterranean formation with a fluid, including forming a fluid including a particulate and an organosilane with the chemical formula RSiX, wherein n is equal to 1, 2, or 3, R is an organic functional group, and X is a halogen, alkoxy, or acetoxy group, introducing the fluid into a subterranean formation with exposed surfaces, and modifying the wettability of a surface of the particulate or subterranean formation or both. A method and composition for treating a subterranean formation with a fluid including forming a fluid comprising a particulate and an organosilane, introducing the fluid into a subterranean formation with exposed surfaces, and modifying the wettability of the proppant or surfaces or both, wherein the wettability modification degrades.

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Cambridge, United Kingdom

Jill F Geddes