Abstract: Oil-based drilling fluids can include an emulsifier to help stabilize the phases of the fluid. During repeated use, the amount of free emulsifier can become depleted. A field test can be used to determine the amount of free emulsifier in the fluid. Top oil from an aliquot from the fluid can be placed into a testing vial and mixed with an aqueous solution including a dye and optionally a pH adjuster or an acid or acidic buffer to facilitate dye transfer from the aqueous phase to the oil phase. The amount of dye transferred to the oil phase can be used to determine the amount of free emulsifier. Reference samples can be prepared with a known concentration of the emulsifier to visually compare the amount of dye transfer in the testing vial to the reference sample. Spectroscopy can also be used to compare the dye transfer in the test vial to the reference sample.

Abstract: A method includes contacting subterranean shale with a treatment fluid, wherein the treatment fluid comprises (i) a biopolymer, (ii) a polyamine, and (iii) an aqueous base fluid, and compositions relating thereof.

Abstract: A method of servicing a wellbore penetrating a subterranean formation, the method comprising: preparing a wellbore servicing composition comprising: (a) core-shell particles comprising a core and a shell, wherein the shell wholly or partially surrounds the core, and wherein: (i) the core of each of the core-shell particles comprises a particle selected from an inorganic particle or an organic particle; and (ii) the shell comprises a polymer that is a polymerization product of one or more monomers and optionally one or more cross-linkers, wherein the one or more monomers include a thermally stable monomer, the one or more cross-linkers include a thermally stable cross-linker, or wherein the one or more monomers include the thermally stable monomer and the one or more cross-linkers include the thermally stable cross-linker; and (b) a carrier fluid; and placing the wellbore servicing composition into the wellbore, the subterranean formation or both.

Abstract: A method of cooling at least a portion of a downhole tool located within a drilled wellbore using a fluid pill configured to transfer heat away from a heat-generating segment of the downhole tool. The downhole tool may be a wireline logging tool. The fluid pill can comprise at least one fluid coolant and may include other additives that enable the fluid pill to transfer heat away from a heat-generating segment of the downhole tool even in the presence of one or more fluids present in the drilled wellbore. The fluid pill can be introduced into residual drilling mud in the wellbore, and the downhole tool may thereafter be operated with the heat-generating segment thereof in fluid contact with the fluid pill, whereby heat generated by the heat-generating segment is transferred away from the downhole tool and toward a wall of the wellbore by the fluid pill.

Abstract: Methods and compositions comprising nanoparticle additives for use in drilling and treatment fluid compositions are provided. In some embodiments the present disclosure includes providing a treatment fluid including an aqueous base fluid, a nanoparticle additive, and a viscosifier; introducing the treatment fluid into at least a portion of a subterranean formation to contact at least a portion of the subterranean formation; and allowing the treatment fluid to reduce fluid loss into the subterranean formation.

Abstract: Drilling fluids for drilling a wellbore. An example drilling fluid includes an aqueous base fluid, a first fluid loss control additive that is a cross-linked polymer comprising N-vinylpyrrolidone as a monomer, and a second fluid loss control additive that is a cross-linked copolymer comprising a first comonomer of 2-acrylamido-2-methylpropanesulfonic acid in a first comonomer concentration of at least 50 mol % of the copolymer. The second fluid loss control additive additionally includes a second comonomer of an N-vinyl amine-containing monomer, a terminal double bound-containing monomer, or a combination of an N-vinyl amine-containing monomer and a terminal double bound-containing monomer. The second comonomer is present in a total second comonomer concentration of 50 mol % or less of the copolymer.

Abstract: A method and system for removing a filter cover. A system and method may comprise a downhole fluid sampling tool including a tool body; a flow port disposed on the tool body; a sample chamber disposed within the tool body and fluidly coupled to the flow port; a pump disposed within the tool body. In examples, the pump is configured to pump a fluid through the flow port into the sample chamber; a filter disposed on an inlet of the flow port, wherein the filter is configured to filter the fluid entering the flow port; and a removable filter cover configured to prevent fluid contact with the filter.

Abstract: A method of cooling at least a portion of a downhole tool located within a drilled wellbore using a fluid pill configured to transfer heat away from a heat-generating segment of the downhole tool. The downhole tool may be a wireline logging tool. The fluid pill can comprise at least one fluid coolant and may include other additives that enable the fluid pill to transfer heat away from a heat-generating segment of the downhole tool even in the presence of one or more fluids present in the drilled wellbore. The fluid pill can be introduced into residual drilling mud in the wellbore, and the downhole tool may thereafter be operated with the heat-generating segment thereof in fluid contact with the fluid pill, whereby heat generated by the heat-generating segment is transferred away from the downhole tool and toward a wall of the wellbore by the fluid pill.

Abstract: A treatment fluid can include a base fluid and a stabilizing additive. The stabilizing additive can include a plurality of environmentally acceptable nanoparticles. The particle size distribution of the plurality of nanoparticles can be selected such that the nanoparticles stabilize a wellbore wall of a subterranean formation or form a filtercake to inhibit or prevent fluid loss into permeable areas of the formation. The plurality of nanoparticles can have a particle size distribution of a d10 value in the range of 20 to 45 nanometers, a d50 value in the range of 40 to 80 nanometers, and a d90 value in the range of 80 to 140 nanometers. The plurality of nanoparticles can also be coated with a polymeric shell. The treatment fluid can be used in an oil and gas operation.

Abstract: Additives of wellbore fluids can be quantified using laser induced breakdown spectroscopy. For example, a method can involve acquiring a sample of wellbore fluid from a wellbore. The wellbore fluid can include an additive. The sample can be processed to separate the wellbore fluid into a liquid sample and a solid sample. A laser induced breakdown spectroscopy device can identify a chemical composition of the liquid sample or the solid sample. A concentration of the additive in the wellbore fluid can be determined based on the chemical composition of the liquid sample or the solid sample. An adjustment to a composition of the wellbore fluid can be performed based on the concentration of the additive in the wellbore fluid.

Abstract: Drilling fluids for drilling a wellbore. An example drilling fluid includes an aqueous base fluid, a first fluid loss control additive that comprises a cross-linked polymer comprising N-vinylpyrrolidone as a monomer, and a second fluid loss control additive that comprises a cloud point glycol.

Abstract: A method of cooling at least a portion of a downhole tool located within a drilled wellbore using a fluid pill configured to transfer heat away from a heat-generating segment of the downhole tool. The downhole tool may be a wireline logging tool. The fluid pill can comprise at least one fluid coolant and may include other additives such that the heat transfer properties of the fluid pill are superior to those of one or more fluids present in the drilled wellbore. The fluid pill can be introduced into residual drilling mud in the wellbore, and the downhole tool may thereafter be operated with the heat-generating segment thereof in fluid contact with the fluid pill, whereby heat generated by the heat-generating segment is transferred away from the downhole tool and toward a wall of the wellbore by the fluid pill.

Abstract: Apparatus for determining an amount of halide in a drilling fluid and methods of use. An example apparatus utilizes an analyzer configured to determine an amount of a halide precipitate in a substantially solids-free sample of a drilling fluid by measuring the amount of the precipitated halide produced upon contacting the substantially solids-free sample of drilling fluid with a cation. A solids removal device is configured to prepare the substantially solids-free sample by removing solids from a sample of the drilling fluid to produce the substantially solids-free sample fluid.

Abstract: A fluid monitoring system for monitoring a concentration of nanoparticle additives in wellbore treatment fluid using X-ray fluorescence (XRF) can include a preparation unit and an analysis unit. The preparation unit can generate a representative sample of the wellbore treatment fluid by performing a separation process with respect to a sample of the treatment fluid. The analysis unit can chemically analyze the subset of the treatment fluid sample using XRF to generate radiation intensity data of the representative sample. Based on the radiation intensity data, the fluid monitoring system can determine that the concentration of the nanoparticle additives is outside of a predefined range. In response to determining that the concentration of the nanoparticle additives in the representative sample is outside of the predefined range, the fluid monitoring system can perform a mitigation operation to modify the concentration of the plurality of nanoparticle additives to be within the predefined range.

Abstract: Techniques described herein can be used to quantify additives of wellbore fluids using laser induced breakdown spectroscopy. For example, a method can involve acquiring a sample of wellbore fluid from a wellbore. The wellbore fluid can include an additive. The sample can be processed to separate the wellbore fluid into a liquid sample and a solid sample. A laser induced breakdown spectroscopy device can identify a chemical composition of the liquid sample or the solid sample. A concentration of the additive in the wellbore fluid can be determined based on the chemical composition of the liquid sample or the solid sample. An adjustment to a composition of the wellbore fluid can be performed based on the concentration of the additive in the wellbore fluid.

Abstract: A method may include: introducing a treatment fluid into a production fluid disposed in a surface well system, the treatment fluid comprising: a base fluid; and a supramolecular host guest product comprising: a treatment fluid additive comprising a surfactant; and a supramolecular host molecule, wherein the supramolecular host molecule is not covalently bonded to the treatment fluid additive; introducing the production fluid containing the treatment fluid into a production facility separator; and separating, in the production facility separator, at least a portion of the production fluid to form a water stream.

Abstract: A treatment fluid can include a base fluid and a lost-circulation package. The lost-circulation package can include plurality of pieces of a first lost-circulation material and a second lost-circulation material. The plurality of pieces can be an open-cell, natural or biodegradable material, for example natural sponges such as loofah. The plurality of pieces can enter permeable areas of a subterranean formation and form a mesh-like matrix that the second lost-circulation material can be retained within. The second lost-circulation material can be insoluble particles such as ground walnut shells or include ingredients that form a cementitious substance. The first and second lost-circulation materials can form a plug and provide adequate fluid loss control. The treatment fluid can be used in an oil and gas operation.

Abstract: In general, in one aspect, embodiments relate to a method that includes circulating a water-based drilling fluid though a drill string to extend a wellbore through a subterranean formation, separating at least a portion of the water-based drilling fluid from the circulated water-based drilling fluid to form a separated portion of water-based drilling fluid, mixing a metal salt and a metal oxide into the separated portion of water-based drilling fluid to form a mixture and shearing the mixture to form a chemical sealing pill, where the chemical sealing pill includes the portion of the water-based drilling fluid, the metal salt, and the metal oxide, and after mixing and shearing, introducing the chemical sealing pill into the drill string as a single mixture and flowing the chemical sealing pill into a lost circulation zone in the subterranean formation.

Abstract: A treatment fluid can include a base fluid and a stabilizing additive. The stabilizing additive can include a plurality of environmentally acceptable nanoparticles. The particle size distribution of the plurality of nanoparticles can be selected such that the nanoparticles stabilize a wellbore wall of a subterranean formation or form a filtercake to inhibit or prevent fluid loss into permeable areas of the formation. The plurality of nanoparticles can have a particle size distribution of a d10 value in the range of 20 to 45 nanometers, a d50 value in the range of 40 to 80 nanometers, and a d90 value in the range of 80 to 140 nanometers. The plurality of nanoparticles can also be coated with a polymeric shell. The treatment fluid can be used in an oil and gas operation.

Abstract: Oil-based drilling fluids can include an emulsifier to help stabilize the phases of the fluid. During repeated use, the amount of free emulsifier can become depleted. A field test can be used to determine the amount of free emulsifier in the fluid. Top oil from an aliquot from the fluid can be placed into a testing vial and mixed with an aqueous solution including a dye and optionally a pH adjuster or an acid or acidic buffer to facilitate dye transfer from the aqueous phase to the oil phase. The amount of dye transferred to the oil phase can be used to determine the amount of free emulsifier. Reference samples can be prepared with a known concentration of the emulsifier to visually compare the amount of dye transfer in the testing vial to the reference sample. Spectroscopy can also be used to compare the dye transfer in the test vial to the reference sample.