Abstract: A method for measuring at least one property of a sample includes obtaining a sample of fluid including at least fines from a downhole environment, exposing the sample to a magnetic field, measuring a magnetic susceptibility of the fines in the sample in response to the magnetic field, and identifying at least one mineral present in the fines based at least partially on the magnetic susceptibility.

Abstract: 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.

Abstract: A wire includes a ferrous core. The ferrous core can be coated. The coatings can include nickel, molybdenum, zinc and Fe. A process of forming a wire can include placing a metal strip alongside a ferrous wire core, bending the strip around the core, and seam welding the strip to form a metal tube around the core. The process of forming a wire can include applying a metal layer to a ferrous metal rod to form a plated rod, placing a metal strip alongside the rod, bending the strip around the rod, and seam welding the strip to form a metal tube around the rod. The process of forming a wire can include coating a ferrous wire core with a layer of nickel, molybdenum or a nickel alloy that circumferentially surrounds the ferrous wire core.

Abstract: A wire includes a ferrous core. The ferrous core can be coated. The coatings can include nickel, molybdenum, zinc and Fe. A process of forming a wire can include placing a metal strip alongside a ferrous wire core, bending the strip around the core, and seam welding the strip to form a metal tube around the core. The process of forming a wire can include applying a metal layer to a ferrous metal rod to form a plated rod, placing a metal strip alongside the rod, bending the strip around the rod, and seam welding the strip to form a metal tube around the rod. The process of forming a wire can include coating a ferrous wire core with a layer of nickel, molybdenum or a nickel alloy that circumferentially surrounds the ferrous wire core.

Abstract: 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 particle size and/or minimum surface area: namely a volume median particle size d50 of not more than 200 micron, determined as median diameter of spheres of equivalent volume and/or a surface area of at least 30 m2 per litre (0.03 m2 per milliliter), determined as surface area of smooth spheres of equivalent volume. The agglomeration of the particles by gas leads to the formation of agglomerates which 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.

Abstract: A process of making observations of a subterranean reservoir penetrated by a wellbore uses distinguishable sets of tracer particles and comprises steps of: (i) delivering a plurality of sets of tracer particles to respective subterranean locations via the wellbore, the particles in each set comprising a tracer substance which distinguishes that set form the other sets; (ii) causing or allowing the tracer substances to flow out from the tracer particles whilst the particles are at the respective subterranean locations; (iii) causing or allowing production of fluid out of said reservoir via the wellbore; and (iv) detecting the presence or absence of the tracer substances in the produced fluid. The tracer substances are sufficiently distinguishable from each other to enable a tracer substance detected in the produced fluid to identify the set of tracer particles from which it has come and hence identify the location from which it has come.

Abstract: A wire includes a ferrous core. The ferrous core can be coated. The coatings can include nickel, molybdenum, zinc and Fe. A process of forming a wire can include placing a metal strip alongside a ferrous wire core, bending the strip around the core, and seam welding the strip to form a metal tube around the core. The process of forming a wire can include applying a metal layer to a ferrous metal rod to form a plated rod, placing a metal strip alongside the rod, bending the strip around the rod, and seam welding the strip to form a metal tube around the rod. The process of forming a wire can include coating a ferrous wire core with a layer of nickel, molybdenum or a nickel alloy that circumferentially surrounds the ferrous wire core.

Abstract: 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.

Abstract: 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 d50 of not more than 200 micron, and/or a minimum surface area of at least 30 m2 per 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.

Abstract: The recovery of oil from a reservoir is assisted by injecting a diluent into the reservoir formation to reduce the viscosity of the crude oil. This diluent is a mixture of a material which is an asphaltene precipitant, especially supercritical carbon dioxide, and a more polar material which comprises at least one aliphatic compound which includes at least one of a cycloaliphatic ring, an olefinic unsaturation, an ester or ether group. The inclusion of such an aliphatic compound which is more polar than the asphaltene precipitant reduces asphaltene precipitation and can enhance the efficiency of oil recovery when the precipitant is by supercritical carbon dioxide.

Abstract: A wellbore fluid contains a viscosifying polymer in which portions of the polymer are connected through formation of an inclusion complex involving cucurbituril 8 (i.e. CB[8]) as host molecule. The fluid contains guest molecules with first and second guest groups covalently attached wherein at least one of the guest molecules comprises a polymer chain. The CB[8] host and the guest molecules attach together through reception of first and second guest groups within CB[8] host cavities, thereby connecting polymer chains together as a larger, supramolecular polymer and enhancing viscosity of the fluid. Polymer molecules may be synthetic polymers and guest groups may be attached to monomers before polymerization. Alternatively guest groups may be attached to existing polymers which may be polysaccharide.

Abstract: 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.

Abstract: The magnitude of asphaltic precipitation when injecting a viscosity reducing diluent into a reservoir formation, notably to assist oil recovery therefrom, is forecast by (i) determining a relationship between asphaltic precipitation and a solubility parameter for the diluted oil, and then (ii) utilizing that relationship to forecast the magnitude of asphaltic precipitation when injecting a predetermined viscosity reducing diluent into the formation. Making this forecast may be followed by injecting a viscosity reducing diluent into the formation to assist oil recovery. The diluent may in particular be supercritical carbon dioxide or other asphaltene precipitant mixed with a more polar material in proportions designed by forecasting asphaltic precipitation by candidate materials in possible proportions.

Abstract: A treatment process for an aqueous phase which contains oil droplets, possibly of 10-50 nm diameter, in aqueous flow from a hydrocyclone separator, comprises bringing the water into contact with a surface subdivided into areas of differing surface energy and affinity for oil and such that when the surface is submerged in an aqueous phase, oil droplets adhere to it with an apparent contact angle in a range from 90 to 150 degrees. Areas of the surface may reduce their affinity for oil in response to an external stimulus causing controlled release of droplets adhering to the surface. The process may be used to remove oil droplets from water produced by an oil or gas well, after downhole oil water separation or after production at a at a well head, or used to coalesce droplets in such water to a larger size to enable conventional separation.

Abstract: A thickened aqueous composition is delivered to a subterranean location accessible via a wellbore by steps of i. providing a biphasic aqueous mixture comprising two aqueous solutions which, at surface temperature and pressure, are able to co-exist as separate aqueous phases in contact with each other, ii. pumping said biphasic aqueous system down the wellbore to the subterranean location, and iii. converting the biphasic mixture below ground so that its phases combine into a single aqueous phase which is more viscous than the biphasic mixture. The two phases of the aqueous biphasic mixture contain dissolved solutes which segregate between the two phases such that at least one first solute is present at a greater concentration in the first aqueous phase than in the second aqueous phase while at least one second solute is present at a greater concentration in the second aqueous phase than in the first aqueous phase.

Abstract: Embodiments of hydraulic fracturing methods disclosed herein use fine mesh proppant. In one embodiment the method is used to fracture a low permeability formation. In one embodiment the method uses flocculation to improve conductivity of a fracture. In one embodiment fluid flow through the fine mesh proppant in the fracture creates a network of connected channels to improve the fracture conductivity.

Abstract: 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.

Abstract: 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.

Abstract: A process for hydraulic fracturing of a subterranean reservoir formation penetrated by a wellbore includes pumping a fracturing fluid or other aqueous fluid from the surface via the wellbore and into the reservoir. This fluid is an aqueous suspension of particles which each comprise an oilfield chemical distributed within an encapsulating matrix of water-insoluble carrier material. The encapsulating matrix is chosen so as to provide a delayed release of the oilfield chemical from the particles into surrounding fluid, such that oilfield chemical is liberated from the particles after they have entered the fracture. The encapsulating matrix may be a polymer which is at least partially amorphous, with a glass transition temperature below the reservoir temperature.

Abstract: A wellbore fluid contains a viscosifying polymer in which portions of the polymer are connected through formation of an inclusion complex involving cucurbituril 8 (i.e. CB[8]) as host molecule. The fluid contains guest molecules with first and second guest groups covalently attached wherein at least one of the guest molecules comprises a polymer chain. The CB [8] host and the guest molecules attach together through reception of first and second guest groups within CB[8] host cavities, thereby connecting polymer chains together as a larger, supramolecular polymer and enhancing viscosity of the fluid. Polymer molecules may be synthetic polymers and guest groups may be attached to monomers before polymerization. Alternatively guest groups may be attached to existing polymers which may be polysaccharide.