A self-adjusting gas lift system and corresponding self-adjusting gas lift valve (GLV) are described herein. The self-adjusting gas lift system includes a number of self-adjusting GLVs that fluidically couple an annulus of a well to an interior of a production tubing of the well. Each of the self-adjusting GLVs is configured to open to allow a compressed gas to flow from the annulus to the interior of the production tubing when a pressure differential between an injection pressure of the compressed gas within the annulus and a production pressure of fluids within the production tubing is within an engineered range. Each of the self-adjusting GLVs is also configured to close when the pressure differential is outside the engineered range.

Valve assemblies for reciprocating downhole pumps are provided. The valve assembly may comprise: a flow cage comprising a housing and a tubular insert; an annular valve seat positioned below the tubular insert; and an elongated sealing member positioned above the annular valve seat and at least partially received into the tubular insert. In some embodiments, the elongated sealing member may be more stable and may more securely engage the valve seat compared to spherical valve balls. Related methods are also provided.

A ball valve including a ball defining a bore therein, and a trunnion arm articulated with the ball via a trunnion, the trunnion arm disposed on a resilient member allowing resilient movement of the trunnion arm pursuant to load on the ball.

A valve assembly is installed within a wellhead such as a conventional tubing hanger or casing hanger used to suspend pipe or other tubular goods in a well. A seal bushing assembly is installed in a tubing head assembly or other wellhead component. A hanger valve assembly is stung into the seal bushing assembly and includes a valve that can be selectively opened or closed. In the open position, the valve does not restrict a central flow path diameter through the hanger and wellhead. In the closed position, the valve contains pressure and/or fluid flow and fully seals against wellbore pressure acting on the valve. A wellhead adapter covers the hanger valve assembly and provides an attachment point for a conventional Christmas tree or other wellhead equipment.

An actuation assembly positionable within a wellbore may comprise a primary piston coupled to a first spring. The primary piston may be positionable in a first position in which it is coupled to a release latch for restraining the release latch from actuating a ball valve mechanism. The actuation assembly may also include a locking piston coupled to a second spring and a locking mechanism positioned between the primary piston and the locking piston. The locking mechanism may be moveable between a restrained position and an unrestrained position, wherein in the restrained position the locking mechanism prevents the primary piston from moving a predetermined amount in a first direction in response to an application of pressure from a surface of the wellbore that is greater than a predetermined amount of pressure.

A wellbore system includes method of cutting a casing in a wellbore. A string is disposed in the casing, the string including a cutting tool and an activation sub coupled to the cutting tool. The cutting tool includes a ball seat and a cutter. The activation sub includes a control piston disposed therein. The control piston has a ball at an end thereof. The control piston is configured to move within the activation sub to engage the ball to the ball seat when a flow rate of a fluid through the control piston is above a flow rate activation threshold, wherein engaging the ball to the ball seat creates a pressure differential across the ball seat that moves the ball seat to extend the cutter from the cutting tool.

A valve seat for a ball valve. The valve seat having a valve seat body with a circumferential concave seating surface configured to mate with a curvature of the valve ball. A seal pocket formed within the valve seat body, the seal pocket having (i) an throat formed in the concave seating surface, (ii) an outer pocket sidewall, and (iii) an inner pocket sidewall. A retaining groove positioned below the throat on either the outer pocket sidewall or the inner pocket sidewall and a flexible seal element shaped for positioning in the seal pocket. The seal element includes (i) an extended lip configured to rest within the retaining groove when the seal element is seated in the seal pocket, and (ii) a sealing face with an upper end laying below the valve seat's concave seating surface and a mid-portion extending upward above a curvature path of the concave seating surface.

A standing valve assembly comprises a flow cage, a ball seat, and a valve ball. The flow cage includes a cage body defining an axial fluid passage therethrough, and a bridge extending across the fluid passage. The cage body and the bridge collectively define a plurality of openings to the fluid passage. The valve ball is received between the bridge and the ball seat and is axially movable within the flow cage. The bridge has an upper face and defines at least one guide ramp in the upper face. Each guide ramp extends at a downward angle to a respective one of the plurality of openings.

A managed pressure drilling (MPD) system including a work string including tubulars having an internal flow path. The work string supports a liner float. A liner hanger running tool is coupled to the work string uphole of the liner float. An MPD sub is coupled to the work string and is operable to close off the internal flow path to fluid pressure passing uphole from the liner float in a first position and opens the internal flow path to fluid pressure after the liner string reaches a target depth. The MPD sub includes a housing having a rotatable ball valve including a ball. A ball seat is arranged between the rotatable ball valve and the downhole end, and a ball engagement member arranged between the rotatable ball valve and the uphole end. The ball engagement member includes a seal component that engages the ball portion.

A downhole deployment and isolation system may be used to deploy a completion string, service the well, and isolate the lower completion string, optionally in a single trip. The lower completion string may be run into the well with a valve in an open condition, such as a ball valve propped open by a mandrel. The mandrel may be operable to both disconnect the work string from the lower completion string and to close the valve upon disconnecting such as by removing the mandrel from the ball. The valve may be remotely reopened with fluid pressure form surface.