A method for recovering subsurface fluid from rock formations by adding an enzyme-based green solvent to a carrier fluid and injecting the enzyme-based green solvent and the carrier fluid into a production well. The enzyme-based green solvent and the carrier fluid are directed down a flow path of the production well. The solvent soaks in the production well before reversing the flow path of the production well. The enzyme-based green solvent and the carrier fluid travel up the flow path with a plurality of recovered deposits from the production well in the enzyme-based green solvent.

A method includes forming an ionic liquid-based product, the ionic liquid-based product including an ionic liquid and mixing the ionic-liquid based product with a fluid. The method also includes injecting the fluid mixed with the ionic-liquid based product into a formation as part of an Improved Oil Recovery (IOR) application.

A method includes forming an ionic liquid-based product, the ionic liquid-based product including an ionic liquid and mixing the ionic-liquid based product with a fluid. The method also includes injecting the fluid mixed with the ionic-liquid based product into a formation as part of an Improved Oil Recovery (IOR) application.

A method may include: introducing a treatment fluid into a stream, the treatment fluid comprising: a base fluid and a supramolecular host guest product, wherein the supramolecular host guest product comprises a treatment fluid additive and a supramolecular host molecule, wherein the supramolecular host molecule is not covalently bonded to the treatment fluid additive.

The subject invention provides microbe-based products, as well as their use to improve oil production and refining efficiency by, for example, remediating the disposable layers in oil tanks and other oil storage units. In preferred embodiments, the microbe-based products comprise biochemical-producing yeast and growth by-products thereof, such as, e.g., biosurfactants. The subject invention can be used to remediate rag layer and/or other dissolved solid layers that form in water-oil emulsions. Furthermore, the subject invention can be used for remediating solid impurities, such as sand, scale, rust and clay, in produced water, flow-back, brine, and/or fracking fluids.

The subject invention provides microbe-based products, as well as their use to improve oil production and refining efficiency by, for example, remediating the disposable layers in oil tanks and other oil storage units. In preferred embodiments, the microbe-based products comprise biochemical-producing yeast and growth by-products thereof, such as, e.g., biosurfactants. The subject invention can be used to remediate rag layer and/or other dissolved solid layers that form in water-oil emulsions. Furthermore, the subject invention can be used for remediating solid impurities, such as sand, scale, rust and clay, in produced water, flow-back, brine, and/or fracking fluids.

The present technology relates to a process for enhancing hydrocarbon production from a shale formation. In particular, the present technology relates to a process wherein a treatment fluid comprising a water soluble delayed release carbonate-dissolving agent is introduced into the shale formation after or as part of a hydraulic fracturing process. The present technology also relates to a treatment fluid that can be used in such a process.

During fracking processes, fluid is injected into the injection wells to cause micro-fractures in the shale. Contact between shale and water causes the development of micro-fractures. Given the deep location of the injection wells, the water is under high pressure that can build up over time and could potentially cause tremors. Based upon experiments on Pierre shale, it has been determined that the appearance of micro-fractures in shale begin with the saturation of capillaries, followed by ionic and diffusive transport of water into the shale clays. Using this discovery, a method for predicting the post-fracking pressure build-up in shale is disclosed.

The composition for enhanced oil recovery includes metal oxide or carbonate nanoparticles capped or encapsulated by a water soluble poly(ionic liquid) (PIL). The nanoparticles may be, e.g., CaCO.sub.3, TiO.sub.2, Cu.sub.2O.Fe.sub.3O.sub.4, or ZrO.sub.2. The poly(ionic liquid) may be a copolymer of 2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS) with N-isopropyl acrylamide, N-vinyl pyrrolidone, methacrylic acid, or acrylamide. The composition is made by synthesizing the metal oxide or carbonate nanoparticles in the presence of the PIL. The resulting nanocomposite or nanomaterial alters the wettability of carbonate rock in a carbonate reservoir, releasing asphaltenic crude oil from the surface of the carbonate rock and replacing oil in the pores of the rock, thereby enhancing secondary and tertiary oil recovery.

The composition for enhanced oil recovery includes metal oxide or carbonate nanoparticles capped or encapsulated by a water soluble poly(ionic liquid) (PIL). The nanoparticles may be, e.g., CaCO.sub.3, TiO.sub.2, Cu.sub.2O.Fe.sub.3O.sub.4, or ZrO.sub.2. The poly(ionic liquid) may be a copolymer of 2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS) with N-isopropyl acrylamide, N-vinyl pyrrolidone, methacrylic acid, or acrylamide. The composition is made by synthesizing the metal oxide or carbonate nanoparticles in the presence of the PIL. The resulting nanocomposite or nanomaterial alters the wettability of carbonate rock in a carbonate reservoir, releasing asphaltenic crude oil from the surface of the carbonate rock and replacing oil in the pores of the rock, thereby enhancing secondary and tertiary oil recovery.