Halliburton Energy Services, Inc.

Matthew Bradley Stokes

Borisa Lajesic

David Joe Steele

Wesley Paul Dietz

Srinivasa Prasanna Vemuri

Loc Phuc Lang

Christian Alexander Ramirez

Lester Barett Dupler

Michelle Brianne Henckel

A system for downhole separation of at least one of fluids or solids comprises a fluid flow diverter to be positioned downhole in a well. The fluid flow diverter is configured to receive a formation fluid in a multilayer flow structure that comprises a production fluid and a nonproduction fluid, wherein the fluid flow diverter is configured to separate the production fluid and the nonproduction fluid by being adjusted such that more of the production fluid is above the fluid flow diverter than below the fluid flow diverter and such that more of the nonproduction fluid is below the fluid flow diverter than above the fluid flow diverter.

Flow diverter and separator for downhole separation in a multi-bore well

Provided, in one aspect, is a whipstock. The whipstock may include a tubular having a longitudinal passageway extending along a length thereof, the tubular having a tapered face extending along at least a portion of the length; a support structure movably coupled to the tubular and extendable across the tapered face, wherein the support structure is operable to move from a first closed position closing the longitudinal passageway and a second open position exposing the longitudinal passageway; and a locking mechanism in the tubular for releasably holding the support structure in the first position.

Whipstock with hinged taperface

A sacrificial shroud is disposed over a packing element of a downhole packer to provide isolation from incompatible wellbore fluids and to minimize a tendency for swabbing or packer preset due to fluid flow past the packing element during run-in, thereby allowing for faster run-in speeds. The shroud may be depletive or consumable, such as by dissolution into a wellbore fluid or by melting at a predetermined downhole thermodynamic condition. The shroud may take the form of a sleeve or an applied coating.

Consumable packer element protection for improved run-in times

An apparatus includes a sleeve a sleeve having a slot defined by at least a first edge and a second edge of the sleeve. At least a portion of the first edge defines a left-handed helical portion of the slot. At least a portion of the second edge defines a right-handed helical portion of the slot. The left-handed helical portion and the right-handed helical portion are at different axial positions along the sleeve with respect to a center axis through the sleeve.

Helical alignment sleeve

Systems and methods are directed to aligning two subsequent pieces of equipment prior to disposing the pieces of equipment downhole. A method comprises providing the first tool piece to be disposed in a wellbore, wherein the first tool piece comprises: a first thread, wherein the first thread is disposed at a first end of the first tool piece; and a second thread, wherein the second thread is disposed at the first end of the first tool piece. The method further comprises disposing an alignment ring on the first tool piece, and coupling the first end of the first tool piece to a second end of the second tool piece. The method further comprises decoupling the first tool piece from the second tool piece; rotating the alignment ring; and coupling the first tool piece to the second tool piece after rotating the alignment ring to produce the tubular assembly.

Aligning two parts of a tubular assembly

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.

Lateral tubing support of a multi-lateral junction assembly

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 assemblies for running and testing tools

Certain shear bolts described herein provide failure bending resistance when torque is applied to members being connected by the bolts, while maintaining shearability. Certain other shear bolts described herein provide a shear region having different shear limits dependent upon the direction of force being applied to the shear region.

Torque resistant shear bolt having flat faces

A method includes conveying a washover whipstock coupled to an orienting latch anchor into a parent wellbore lined with casing and securing the orienting latch anchor to the casing. A washover tool couples to and removes the washover whipstock from the parent wellbore, and thereby exposes a releasable orienting coupling of the orienting latch anchor. A workover whipstock coupled to a junction isolation tool is then conveyed into the parent wellbore and the workover whipstock is coupled to the orienting latch anchor at the releasable orienting coupling. The junction isolation tool is separated from the workover whipstock and advanced into the lateral wellbore, following which the junction isolation tool is retracted back into the parent wellbore to be re-attached to the workover whipstock to remove the workover whipstock from the parent wellbore.

Reduced trip well system for multilateral wells

In accordance with presently disclosed embodiments, a system and method for rotationally orienting two wellbore tool components on a tool string relative to each other is provided. The system may include an alignment sub that is simple to operate and allows for quick adjustments to the relative orientations of downhole tool components. The disclosed alignment sub may include a first tubular component on one side and a second tubular component on the other side, and these tubular components are coupled together. The disclosed alignment sub utilizes an axially deformable and variable length sleeve attached to the first tubular component and adjacent to a tip of the second tubular component. The sleeve may provide an appropriate standoff distance between the opposing tubular components while enabling the components to be rotated relative to each other up to at least one full rotation about an axis of the alignment sub.

Alignment sub with deformable sleeve

Bolt having torque resistant shear region

A whipstock assembly includes a whipstock providing a ramped surface, and a mill releasably coupled to the whipstock with a shear bolt and providing a mill profile. A tension arm is pivotably coupled to the whipstock and movable between a stowed position, where the tension arm is received within a cavity defined in the ramped surface, and an engaged position, where an engagement head of the tension arm mates with the mill profile to assume at least a portion of a tensile load assumed by the shear bolt.

Whipstock assemblies with a retractable tension arm

An assembly and method for completion of lateral wellbores is disclosed. The completion assembly includes a junction fitting with main and lateral legs, and a lateral completion string and anchoring device connected to the downhole end of the lateral leg and the uphole end of the junction fitting, respectively. A working string, positioned within the lateral leg, anchoring device, and lateral completion string, includes a setting tool that is removably connected to the anchoring device and a completion tool assembly located within the lateral completion string. The completion assembly is run by the working string into the wellbore. After setting the anchoring device, the working string conveys the completion tool assembly within the lateral completion string for gravel packing, fracturing, frac-packing, acidizing, cementing, perforating, and inflating packers, for example. After wellbore completion, the completion tool assembly is removed through the lateral leg of the junction fitting.

Junction-conveyed completion tooling and operations

A diverter assembly can include a diverter having a deflection surface, and an annular seal device externally disposed and longitudinally displaceable on the assembly in response to a pressure differential being applied across the device. A well system can include a diverter assembly positioned in a casing, the assembly including a diverter and an annular seal device that seals off an annulus between the assembly and the casing, whereby a pressure differential across the device is reduced by movement of the device on the assembly. A method of sealing off an annulus formed between a diverter assembly and a casing can include positioning an annular seal device on a mandrel, the device being slidingly and sealingly engaged with an outer surface of the mandrel, connecting the mandrel to a diverter, and installing the assembly comprising the device, the mandrel and the diverter in the casing.

Well diverter assembly with substantially pressure balanced annular seal device

An example latch coupling assembly includes a latch coupling defining an inner latch profile and an expandable sleeve coupled to the latch coupling. A latch defining an outer latch profile is mateable with the inner latch profile, and a mandrel is at least partially extendable within the expandable sleeve. An expansion cone is moveable along the mandrel between a first position, where the expansion cone is positioned within the expandable sleeve, and a second position, where the expansion cone is moved into engagement with an inner radial surface of the expandable sleeve to radially expand the expandable sleeve into engagement with a casing string and thereby secure the latch coupling within the casing string.

Growing community of inventors

Keller, TX, United States of America

Matthew Bradley Stokes