Abstract: The present disclosure relates to biocide compositions, formulations and methods for using formulations. In particular the present disclosure relates to biocide compositions and their use in effecting biocidal activity in subterranean oil and gas wells being drilled, completed, worked over or produced.

Abstract: A method for enhanced oil recovery in a tilted reservoir includes the steps of: providing an injection well and at least one production well, the at least one production well provided at a greater depth in the tilted reservoir than the injection well; injecting carbon dioxide or nitrogen gas into the injection well; injecting enriched air into the injection well so as to cause ignition in the tilted reservoir; reducing production by the at least one production well; draining fluid from an area in the tilted reservoir up-dip of the injection well; and recovering the drained fluid by the at least one production well.

Abstract: Methods for installing soil and sand stabilization columns using a chemical polymer are provided. The chemical polymer can be a liquid acrylic base chemical polymer or a liquid vinyl acetate base chemical polymer. In the methods, a dilution rate of a chemical polymer is determined based on at least one of: a moisture content of the soil at a selected soil location, a particle size distribution of the soil at the selected soil location, a shear strength of the soil at the selected soil location, a target strength of the soil stabilization column, and a target stiffness of the soil stabilization column. The chemical polymer is then diluted based on the determined dilution rate. The diluted chemical polymer is inserted into a selected soil location and mixed with in-situ soil or with sand to form a stabilization column.

Abstract: A method of oil production after water flooding includes the steps of: forming at least one injection well and at least one production well in a reservoir; pumping enriched air (at least 30-100 mole-% oxygen with fogged water droplets) into the injection well, so as to maximize gravity segregation of gas/steam and gravity drainage of oil from an attic and/or pinch-out volume of the reservoir; and recycling produced carbon dioxide by injection into a man-made gas cap created around the at least one injection well. The enriched air preferably includes a mixture of 30-100 mole-% oxygen, 0-4 mole-% argon, 0-67 mole-% nitrogen and 0-70 mole-carbon dioxide gas.

Abstract: The present disclosure relates to the generation of food grade sugar modified 1-MCP nanobubbles ranging in size from 50 to 600 nm. These nanobubbles have a high degree of stability while in aqueous solution and can inhibit the action of ethylene in different biological processes. In addition, they can reduce the action of ethylene in plant metabolism, making the plant less susceptible to water stress, low temperature stress, and stress from soil conditions, among others. This disclosure also relates to the method of preparing sugar modified 1-MCP nanobubbles, their different uses and applications.

Abstract: Wellbore synthesis techniques are disclosed suitable for use in geothermal applications. Embodiments are provided where open hole drilled wellbores are sealed while drilling to form an impervious layer at the wellbore/formation interface. The techniques may be chemical, thermal, mechanical, biological and are fully intended to irreversibly damage the formation in terms of the permeability thereof. With the permeability negated, the wellbore may be used to create a closed loop surface to surface geothermal well operable in the absence of well casing for maximizing thermal transfer to a circulating working fluid. Formulations for the working and drilling fluids are disclosed.

Abstract: Formation treatment fluid compositions and methods are provided that include an aqueous base fluid, where the aqueous base fluid comprises one or more salts; and sago. The profile modification fluid may include sago in an amount in the range from 50,000 ppm to 100,000 ppm. Formation treatment fluid compositions may also include an aqueous base fluid, where the aqueous base fluid comprises one or more salts, and sago, where the formation treatment fluid may include sago in an amount in the range from 10,000 ppm to 50,000 ppm. Methods for using the formation treatment fluid may include introducing into a targeted stratum of a subterranean formation a treatment fluid. The subterranean treatment fluid may include an aqueous base fluid, where the aqueous base fluid includes one or more salts, sago, and the treatment fluid may include sago in an amount in the range from 10,000 ppm to 100,000 ppm.

Abstract: A treatment system comprises a treatment bladder associated with a volume of a tubing-casing annulus of a wellhead system to be treated. The treatment bladder contains a treatment fluid and is at an elevated pressure. The treatment bladder is coupled to the tubing-casing annulus utilizing a fluid conduit through a lower fluid junction. The fluid conduit permits two-way fluid communication between the treatment bladder and the tubing-casing annulus. A method for treating the tubing-casing annulus includes coupling the treatment bladder containing the treatment fluid of the treatment system to the tubing-casing annulus of the wellhead system using the fluid conduit, establishing two-way fluid communication between the tubing-casing annulus and the treatment bladder though the fluid conduit, halting fluid communication though the fluid conduit, and decoupling the treatment bladder from the tubing-casing annulus.

Abstract: Embodiments relate to cementing operations and, in certain embodiments, to passivated cement accelerators and methods of using passivated cement accelerators in subterranean formations. An embodiment may comprise a method of cementing comprising: providing a cement composition comprising cement, water, and a passivated cement accelerator; and allowing the cement composition to set.

Abstract: A drilling fluid comprises an aqueous solution; a clay-based component comprising layered silicate; and a viscosifier additive comprising poly(acrylamide-co-diallyldimethylammonium chloride) (poly(AAm-co-DMAC)) polymer. The polymer comprises a number average molecular weight of from 10,000 g/mol to 2,000,000 g/mol. The layered silicate and poly(AAm-co-DMAC) reacts to form a silicate-poly(AAm-co-DMAC) complex within the aqueous solution. A mass ratio of the poly(AAm-co-DMAC) to the layered silicate is 1 to 8.

Abstract: A downhole tool for controlling the flow of a fluid in a wellbore includes a component that comprises: a cementitious material; an aggregate; and a ductility modifying agent comprising one or more of the following: an ionomer; a functionalized filler; the functionalized filler comprising one or more of the following: functionalized carbon; functionalized clay; functionalized silica; functionalized alumina; functionalized zirconia; functionalized titanium dioxide; functionalized silsesquioxane; functionalized halloysite; or functionalized boron nitride; a metallic fiber; or a polymeric fiber.

Abstract: An apparatus for continuously generating and controlling the density of foam has a fluid in-flow manifold in communication with a source of liquid and comprising a pressure sensor. A plurality of branch lines are in fluid communication with the in-flow manifold a foam out-flow manifold. Each branch line has a flow control valve, a Venturi tube and in fluid communication with a throat of each Venturi tube an air induction control valve. The foam out-flow manifold has a pressure sensor. At least one in-flow control valve is disposed between the source and the in-flow manifold and at least one out-flow control valve is in communication with the out-flow manifold. The branch valves, air valves, the in-flow control valve and the out-flow control valve are operable to provide a chosen flow rate of the liquid and a selected foam product flow rate at a selected density of the foam product.

Abstract: A well cementing method is described for improving cementing quality by controlling the hydration heat of cement slurry. By controlling the degree and/or rate of hydration heat release from cement slurry, the method improves the hydration heat release during formation of cement with curing of cement slurry, improves the binding quality between the cement and the interfaces, and in turn improves the cementing quality at the open hole section and/or the overlap section. The cementing method improves cementing quality of oil and gas wells and reduces the risk of annular pressure.

Abstract: Provided are wellbore treatment fluids and methods to introduce these treatment fluids in a subterranean formation. The treatment fluids include a diverter material and an aqueous carrier fluid. Further, the diverter material comprises a composite material of a polyvinyl alcohol and a plasticizer. The diverter material includes particles having a particle size distribution of about 2 to about 10 U.S. mesh and an aspect ratio of 20:1 or less. The treatment fluid is introduced into a permeable zone of a subterranean formation, wherein the permeable zone is part of a wellbore that is permeated or penetrated by fractures and fissures. The diverter material diverts at least partially the treatment fluid to a different portion of the subterranean formation.

Abstract: A production well system includes a main wellbore extending from a wellhead and penetrating a subterranean hydrocarbon-bearing formation, a lateral wellbore extending from the main wellbore, production tubing arranged within the main wellbore and in fluid communication with a production fluid present in the subterranean hydrocarbon-bearing formation, a separator arranged within the production tubing and operable to separate the production fluid into a hydrocarbon stream and a water stream, wherein the hydrocarbon stream is conveyed to the wellhead within the production tubing and the water stream is conveyed to the lateral wellbore, and a pump arranged uphole from the separator and operable to receive and convey the water stream into downhole portions of a lateral wellbore, thus creating a multi-purpose well which may reduce operating and capital expenditures while increasing production of existing and dead wells.

Abstract: The present invention discloses a novel aqueous composition for use in removing petroleum-contaminated barium sulfate scale from a surface contaminated with such, said composition comprising: a chelating agent and a counterion component selected from the group consisting of: Li5DTPA; Na5DTPA; K5DTPA; Cs5DTPA; Na4EDTA; K4EDTA; TEAH4DTPA; and TBAH5DTPA; a scale removal enhancer; a non-ionic surfactant; and a hydrotrope. There is also disclosed methods to use such compositions.

Abstract: A preparation method of the starch-containing microsphere includes the steps of first reacting starch with a low concentration of epichlorohydrin, and then reacting the resultant product with a surfactant, followed by final crosslinking to give microspheres. The starch-containing microspheres thus prepared are polydisperse starch-containing microspheres with a uniform particle size distribution, with the particle size being in a range of 0.1-500 ?m.

Abstract: A stable water based nanofluid of graphene-based amphiphilic Janus nanosheets, where the nanofluid has a high salt-content while retaining the interfacial activities of the nanosheets. Such a nanofluid of amphiphilic Janus nanosheets may be used for enhanced oil recovery.

Abstract: A method of preparing a solid surfactant composite may include: coating a liquid water-wetting surfactant on a solid carrier; and drying the solid carrier to produce the solid surfactant composite. A method may include: introducing a spacer fluid into a wellbore, the spacer fluid comprising a solid surfactant composite; and displacing a fluid in the wellbore using the spacer fluid.

Abstract: Methods are disclosed for emplacing a gel-form material in a porous subterranean formation, such as a hydrocarbon reservoir. The material is formed by admixing solid nanoparticles with gelation supporting amounts of surfactants or ionic species, such as ionic species of the kind that form ionic liquids. The nanoparticle to ion ratio may be selected, in combination with selecting the components of the gel-form material, so that the rheological and gelation properties of the gel-form material are adapted for a particular use, for example forming a fluid flow barrier in a reservoir.