Systems and methods include a method for optimizing maximum reservoir contact wells. For each lateral of a multi-lateral well and using input data for the lateral, a lateral flowrate is determined for each opening position for different combinations of internal control valve (ICV) sizes and target flowing bottomhole pressures. Using a numerical model, an estimated total flowrate is determined for each lateral based on the lateral's flowrate. Options are provided for presentation to a user in a user interface for changing ICV settings of the multi-lateral well. Each option includes a predicted added value to production of the multi-lateral well. The predicted added value includes one or more of an individual lateral production contribution, an enhanced sweep efficiency for one or more laterals, or a water rate reduction. A selection by the user of an option is received. The option is implemented during production of the multi-lateral well.

A downhole apparatus can include a first lateral tubing support that comprises: a body; a first passage extending through the body; and a second passage extending through the body. The first and second passage are spaced in parallel arrangement, and the body extends continuously and uninterruptedly in a direction transverse to the parallel directions of extension of the first and second passages, from the first passage to the second passage. The lateral tubing string can also include a first tubular and a second tubular spaced in parallel arrangement. The first passage is configured to at least partially encircle the first tubular and the second passage is configured to at least partially encircle the second tubular, with the first lateral tubing support increasing a radial and/or axial compressive load rating of the lateral tubing string.

A method of plugging a formation fracture includes drilling, with a drill string configured to flow drilling fluid, a wellbore, where, at a downhole location, the drilling fluid is lost through a formation fracture. The method also includes deploying, through the drill string, a plugging assembly to the downhole location of the wellbore. The plugging assembly includes a flexible fiber sheet releasably coupled to a pumpable dart such that when the plugging assembly reaches the downhole location, the flexible fiber sheet is released from the dart to flow, with the drilling fluid, to the formation fracture to at least partially overlay the formation fracture. The method also includes adding, to the drilling fluid, lost circulation material configured to accumulate on a portion of the flexible fiber sheet to at least partially fluidically plug the formation fracture.

Assemblies and methods are provided for positioning a sealing tool within a receptacle and pressure testing a seal between the sealing tool and the receptacle. The assembly may be coupled to the sealing tool for latching the sealing tool into the receptacle. The assembly may include a projection that is movable between a coupled position and an uncoupled position. In the coupled position, the projection may couple the assembly to the sealing tool. In the uncoupled position, the projection may be positioned such that the assembly is not coupled to the sealing tool. The projection may move from the coupled position to the uncoupled position in response to determining a seal is established between the sealing tool and the receptacle.

Methods and systems for producing hydrocarbons in a subterranean well with a completion system include landing an isolation valve completion within the subterranean well. The isolation valve completion is landed within an observation wellbore and downhole of a junction with a production wellbore. The isolation valve completion includes an isolation valve. A production tubing is delivered into the subterranean well. The production tubing has a downhole end located uphole of the junction with the production wellbore. An annulus defined between an outer diameter surface of the production tubing and an inner diameter surface of the subterranean well is sealed with a production packer that circumscribes the production tubing.

A multilateral junction comprising a y-block, lateral legs, and a transition sub for use in downhole well environments. The y-block includes a main bore and lateral bores with main bore and the lateral bores having threaded interfaces. The transition sub also includes lateral bores with threaded interfaces for receiving the lateral legs that also have threaded interfaces. The threaded interfaces of the lateral bore of the y-block has a less number of threads than the threaded interfaces of the lateral bores of the transition sub. The lateral leg includes another threaded interface that couples with the threaded interface of the lateral bore. Another end of each lateral leg includes an interface, e.g. a threaded interface, which couples with an interface of a transition sub. The main bore has an internal diameter that is greater than the internal diameter of the lateral bore.

Provided, in one aspect, are a downhole tool and a well system including a downhole tool. The downhole tool, in one aspect, includes a tubular, the tubular having an opening connecting an interior of the tubular and an exterior of the tubular. The downhole tool, in at least this aspect, includes first and second I-shaped seals on opposing sides of the opening, each of the first and second I-shaped seals including first and second opposing members, and a central member separating the first and second opposing members, the central member defining first and second fluid cavities.

Systems and methods for thru-tubing completion including a sub-surface completion unit (SCU) system including a SCU wireless transceiver for communicating with a surface control system of a well by way of wireless communication with a down-hole wireless transceiver disposed in a wellbore of the well, one or more SCU anchoring seals having an un-deployed position (enabling the SCU to pass through production tubing disposed in the wellbore of the well) and a deployed position (to seal against a wall of the target zone of the open-hole portion of the wellbore to provide zonal isolation between adjacent regions in the wellbore) and one or more SCU centralizers having an un-deployed position (enabling the SCU to pass through the production tubing disposed in the wellbore of the well) and a deployed position (to position the SCU in the target zone of the open-hole portion of the wellbore).

A lateral wellbore access system is used for moving an isolation sleeve relative to a window of a completion sleeve to adjust access through the window. The system includes an actuator having an isolation sleeve engagement mechanism and a driving mechanism. The isolation sleeve engagement mechanism is configured to engage with an isolation sleeve. The driving mechanism is configured to longitudinally reciprocate the isolation sleeve relative to the isolation sleeve engagement mechanism within a bore of a completion sleeve to longitudinally move an isolation sleeve within the bore relative to a window of the completion sleeve. Movement of the isolation sleeve adjusts a position of the isolation sleeve relative to the completion sleeve window for permitting or blocking access through the window into the bore.

A lateral wellbore access system is used for moving an isolation sleeve relative to a window of a completion sleeve to adjust access through the window. The system includes an actuator having an isolation sleeve coupling mechanism and a driving mechanism. The isolation sleeve coupling mechanism is configured to engage with an isolation sleeve. The driving mechanism is configured to longitudinally reciprocate the isolation sleeve coupling mechanism within a bore of a completion sleeve to longitudinally move an isolation sleeve coupled to the isolation sleeve coupling mechanism within the bore relative to a window of the completion sleeve. Movement of the isolation sleeve adjusts a position of the isolation sleeve relative to the completion sleeve window for permitting or blocking access through the window into the bore.