At least a portion of a wellbore isolation device consists essentially of: a metal alloy, wherein the metal alloy: (A) comprises magnesium at a concentration of at least 50% by volume of the metal alloy; and (B) at least partially dissolves in the presence of an electrolyte. A method of removing the wellbore isolation device comprises: contacting or allowing the wellbore isolation device to come in contact with an electrolyte; and allowing at least a portion of the metal alloy to dissolve.

A perforating gun has shaped charges that can generate a high-pressure gas. A valve sub connects to the perforating gun and a reservoir sub connects to the valve sub. The valve sub has an enclosure with a port. A mandrel in the enclosure has a piston head and a fluid path extending at least partially through the mandrel. A sleeve is slidably mounted on the mandrel and selectively blocks fluid flow through the port. A pressure chamber in the sleeve receives the generated high-pressure gas via the fluid path. The sleeve slides toward the perforating gun after a predetermined pressure is created by the generated high-pressure gas in the pressure chamber. The reservoir sub may have at least one chamber in fluid communication with the interior of the valve sub.

An inflow control device (ICD) that may include a piston located in a flow passage, a barrier that prevents fluid flow through the ICD, and a shear device that prevents movement of the piston. A method of actuating one or more ICDs may include Preventing actuation of the devices by maintaining a pressure in an interior of a well tool (or tubing string) below an actuation pressure of the devices, where each device may include a piston located within a flow passage, a barrier that prevents fluid flow through the ICD, and a shear device that initially prevents movement of the piston. The method may include increasing the pressure in the well tool (or tubing string) to be greater than or equal to the actuation pressure, thereby shearing the shear device and moving the piston.

A dual coiled tubing head has an outer coiled tubing connector, an inner coiled tubing connector, a central housing, a first piston and a bottom housing. The outer coiled tubing connector and inner coil connect to the outer coil and inner coil of dual coiled tubing. The inner coiled tubing connector fits within the outer coiled tubing connector such that a passage is created between an outer surface of the inner coiled tubing connector and an inner surface of the outer coiled tubing connector to allow for the passage of fluid through the outer coiled tubing connector. A central housing is connected to the outer coiled tubing connector and inner coiled tubing connector. The central housing has a central passage, at least one peripheral downhole passage and at least one outlet. The peripheral downhole passages are in fluid communication with the outer coiled tubing connector. A piston is housed within the central passage of the central housing. The piston has an inlet end, a sealed bottom end, at least one orifice and a hollow interior. The inlet end is in fluid communication with the inner coiled tubing connector and the hollow interior. The hollow interior houses a one-way valve that permits downward flow. The orifice is in fluid communication with the outlets of the central housing. The bottom housing connects to the central housing. The bottom housing has a central passage, a bottom end and a top end. The central passage is in fluid communication with the peripheral downhole passages and houses a one-way valve for permitting downhole flow of fluid from the exterior coiled tubing connector.

Embodiments described herein relate to injecting steam into a wellbore using a device. The device includes a body having a bore configured to communicate steam through the body. The device also includes a sleeve movable in the bore of the body between a first position and a second position, wherein the sleeve in the first position blocks steam from exiting an opening of the body and the sleeve in the second position allows steam to exit the opening of the body. The device can be activated by an activation device conveyed down a tubing string and can include a seat on which the activation device. The seat is expandable to allow the activation device to pass.

A plug assembly for opening a subterranean wellbore comprises a tubular housing and a first frangible element comprising an activation component. The first frangible element has a first orifice in an uphole side that extends at least partially through the first frangible element. The activation component initially seals the first orifice to prevent fluid communication from the uphole side of the first frangible element with the first orifice. After the activation component is activated, fluid communication is enabled from the uphole side of the first frangible element with the first orifice.

A wellbore assembly includes a cable configured to be disposed within a wellbore. The wellbore assembly also includes a housing attached to a downhole end of the cable. The housing defines a fluid outlet at a downhole end of the housing. The housing includes an anchor and a collapsible gate. The anchor engages a wall of the wellbore under increased tension in the cable, thereby anchoring the housing to the wellbore. The collapsible gate is disposed inside the housing between an uphole end of the housing and the fluid outlet. The housing temporarily stores a treatment fluid configured to treat an obstruction in the wellbore. The collapsible gate is configured to break, with the anchor engaged, under further tension applied by the cable, inside the housing to allow the treatment fluid to flow out of the housing through the fluid outlet toward the obstruction.

A downhole sleeve tool is provided that includes a lower sub defining a bore and one or more sleeve ports therethrough. There is a piston valve movably positionable within the lower sub to selectively block communication between the bore and the one or more sleeve ports. There is an upper sub connectable to the lower sub and sharing another bore therewith. The upper sub has an inlet port, one or more communication ports, and an outlet port. There is an at least one cartridge assembly disposed in a cartridge bore formed in a wall of the upper sub.

Acid stimulation operations in a wellbore may be conducted using frac plugs constructed of a hydrolytically degradable polymer. The frac plugs may be constructed of an aliphatic polyester such as PGA and may be readily pumped into position in the wellbore due in part to their relatively low density. Once perforations have been created in the wellbore and a first frac plug is set in place, an acid solution may be pumped at a high-pressure acid against the frac plug and into the geologic formation. A second and/or any number of subsequent frac plugs may be pumped behind the acid, e.g., in brine solution, to be used in subsequent acid stimulation operations. After completing acid stimulation operations, the frac plugs may degrade in the wellbore to permit production within two weeks.

A downhole assembly includes a float tool configured to be connected to a casing string and including one or more one-way valves configured to permit fluid flow in a downhole direction and to prevent fluid flow in an uphole direction, and a first wiper plug configured to be deployed into a well via the casing string and engage the float tool. The first wiper plug comprises a valve element that is configured to prevent fluid flow through the first wiper plug at least in the uphole direction.