Disclosed herein is a method of producing hydrocarbons from a subterranean reservoir, the method comprising: penetrating at least a portion of the subterranean reservoir with a first well and a second well, positioning an annulus-flow restrictor within the substantially-horizontal section of the first well at a distance, d.sub.1, from a produced-fluid inlet of the second well, injecting mobilizing fluid into the subterranean reservoir via a mobilizing-fluid injection outlet of the first well to mobilize hydrocarbons therewithin, and producing mobilized hydrocarbons from the subterranean reservoir via the produced-fluid inlet. The method further comprises positioning an annulus-flow restrictor within the substantially-horizontal section of the first well at a distance, d.sub.2, from the produced-fluid inlet such that d.sub.2<d.sub.1, injecting mobilizing fluid into the subterranean reservoir via the mobilizing-fluid injection outlet of the first well to mobilize hydrocarbons therewithin, and producing mobilized hydrocarbons from the subterranean reservoir via the produced-fluid inlet.

An aqueous wellbore fluid may include a surface active agent package in an amount ranging from 1 to 20 gpt, a thickener in an amount ranging from 0.01 to 0.3 wt. %, and an aqueous base fluid. The surface active agent package may include an α-olefin sulfonate, a terpenoid, and isopropyl alcohol. The thickener may include a biopolymer.

In accordance with one or more embodiments of the present disclosure, a foam suitable for use in hydrocarbon recovery includes a gas phase and a liquid phase. The liquid phase includes a foaming mixture, and the foaming mixture includes an aqueous solution, one or more surfactants, and an oil mixture. At least 2 wt. % of the liquid phase includes the oil mixture. Also described are methods of recovering hydrocarbons from a deposit reservoir using such a foam, as well as a hydrocarbon well including such a foam.

A resource exploration and recovery system includes a first system and a second system extending into a wellbore. The second system includes a completion having a casing defining a wellbore internal diameter. A chemical injection tubing extends from the first system into the completion. The chemical injection tubing includes a terminal end portion. A chemical introduction system is arranged at the first system and is fluidically connected to the chemical injection tubing. The chemical introduction system is operable to deliver a chemical into the chemical injection tubing. A chemical injector assembly is mounted to the terminal end portion. The chemical injection system includes an anchor and a chemical injector valve.

Described is a method for gas blend optimization. The method includes assigning a target rate for one or more parameters of interest in a desired gas blend. Data related to the parameters of interest is obtained for each well of a geographical region of interest. Based on the obtained data, an effect of each well's contribution to the parameters of interest in a total gas produced at a gas processing facility is determined. The parameters of interest in the total gas produced are optimized until the assigned target rate is met by determining an adjusted well gas rate for each well in a list of wells selected based on their effects on the total gas produced.

A method includes selecting a model for a simulation of hydrocarbon recovery from a reservoir having a plurality of fractures during injection of an injected gas into the plurality of fractures. Selecting the model includes determining a flux ratio of a convection rate to a diffusion rate for the reservoir, determining whether the flux ratio is less than a threshold, and in response to the flux ratio being less than the threshold, selecting the model that includes diffusion. Selecting the model includes performing the simulation of the hydrocarbon recovery from the reservoir based on the model.

Some methods of production hydrocarbons from a formation comprise drilling two or more horizontal wellbores in the formation, at least a portion of each extending in a direction that is within 20 degrees of parallel to a direction of maximum horizontal stress of the formation. The horizontal wellbores can include one or more producer wellbores and one or more injector wellbores, each of the producer wellbore(s) separated from at least one of the injector wellbore(s) by a formation-permeability-dependent well spacing. Some comprise comprising creating one or more longitudinal fractures that are in communication with the formation in each of the horizontal wellbores, injecting a recovery fluid comprising gas into at least one of the injector wellbore(s) such that the recovery fluid flows into the formation, and receiving hydrocarbons from the formation into at least one of the producer wellbore(s).

A method of underground storage of an injection gas containing CO.sub.2 gas and enhanced oil recovery includes: supplying injection water through a water flow path; jetting the injection water as a high-pressure water jet which is increased in velocity by narrowing a fluid flow through a fine bubble-generating device placed at a lower end of the water flow path; suctioning an injection gas through a gas flow path by a negative pressure generated by the Venturi effect downstream of the high-pressure water jet; jetting the injection gas as fine bubbles from the fine bubble-generating device placed at a lower end of the gas flow path; and performing underground storage of the injection gas by allowing a gas-liquid mixed fluid containing fine bubbles generated by mixing the injection water with the fine bubbles in the fine bubble-generating device to penetrate into a permeable formation such as an oil reservoir.

A flow control assembly including a subassembly including an annular safety valve, a shroud, a bushing connecting the shroud to the subassembly at one of two opposing ends of the shroud, and another bushing connecting the shroud to the subassembly at the other of the two opposing ends of the shroud. The method for operating a hydrogen storage and production system including pumping hydrogen into the salt cavern for storage through a borehole and producing hydrogen from the salt cavern through the same borehole.

Systems, methods, and computer program products can be used for determining the amount of oil removed by a miscible gas flood. One of the methods includes identifying locations of oil within a volume representing a reservoir rock sample. The method includes identifying locations of gas within the volume. The method also includes determining the amount of oil removed based on locations within the volume where oil is either coincident with the gas or is connected to the gas by a continuous oil path.