Baker Hughes Corporation

Baker Hughes, a Ge Compnay, LLC

Baker Hughes Oilfield Operations LLC

National Oilwell Dht, L.p.

Nov Downhole Eurasia Limited

Turbo Drill Industries, Inc.

Mark Kendall Adam

Jeffrey Williams

Robert O'Brien

Michael A Carmody

Dennis G Jiral

Keven O'Connor

Harold E Payne

Robert S O'brien

Mathew J Jabs

Michael H Johnson

Bennett M Richard

Matthew J Jabs

Robert O'brien

Matthew Jay Jabs

Chee K Lee

Leopolodo S Gomez

Joerg Lehr

Jason Allen

Colin Patrick Andrew

Michael E McMahan

Jonathan Nicholas Croy

Lance M Rayne

Travis Treadway

Michael Barron

Brian Magnus

John Lindley Baugh

Edward T Wood

Richard YingQing Xu

Sean Gaudette

Christopher Ryan Hern

Nicholas J Clem

Chad Feddema

Chee Kong Yee

Todd Christophe Jackson

Graham E Farquhar

Alan B Emerson

Sheldon Ritchie

Matthias Moeller

Michael Ramon

Amy L Farrar

Leopoldo S Gomez

David Alan Garcia

Ines Gruetzmann

Bryan T Storey

Ricardo Arturo Gomez Barker

Mahmoud Marzouk

Eric J Curley

Carl Frederick Stockmeyer, Iii

James Sanchez

Sean L Gaudette

Matthias R Moeller

A method of conducting a plurality of downhole operations with a completion system, the method including performing a treatment through a port in a first sleeve assembly in a first stage of the completion system, using an object to slide a first sleeve in a second sleeve assembly, located uphole of the first sleeve assembly, in a second stage of the completion system to reveal a port, and then closing the port in the first sleeve assembly in the first stage using the object, performing a treatment through the port in the second sleeve assembly, closing the port in the second sleeve assembly, and opening at least one of the ports in the first sleeve assembly and the second sleeve assembly and producing fluids through the at least one of the ports. A completion system includes the sleeve assemblies and object for performing the method.

Sleeve device, method and system

A downhole vibration tool includes a body, a mandrel, a spring, and a balance piston. The body may be generally tubular and may have one or more helical slots formed on an inner surface thereof. The mandrel may be generally tubular, may have a bore, and may be positioned at least partially within the body. The mandrel may have one or more helical splines formed on an outer surface of the mandrel, the helical splines engaging the helical slots of the body such that the mandrel is translatable axially relative to the body. The spring may be positioned in an annular space formed between the mandrel and the body defined as a spring chamber. The balance piston may be in an annular space formed between the mandrel and the body, wherein the balance piston separates an oil-filled chamber from an internal pressure chamber.

Downhole vibration tool

A downhole system includes a lower completion having at least one tubular including a first end and a second end terminating at a shoe. The at least one tubular defining a flow path. A packer is arranged at the first end. A fluid loss control valve (FLCV) is arranged between the packer and the shoe. A screen system is arranged between the FLCV and the shoe. The screen system includes a screen and a non-mechanically operated flow control valve that selectively isolates the flow path from formation fluids passing through the screen. A wellbore clean out string is insertable into the lower completion. The wellbore clean out string includes a selectively activated casing cleaner and a setting tool. The selectively activated casing cleaner is spaced from the setting tool.

System for setting a lower completion and cleaning a casing above the lower completion

A method of performing an annular cementing operation after setting an integrated hanger and seal includes introducing a tubular including a flow passage having an inlet and an outlet into a wellbore, positioning and setting the integrated hanger and seal in the tubular, flowing cement between the tubular and the integrated hanger and seal into the inlet of the flow passage, passing the cement through the flow passage to the outlet, flowing the cement from the outlet, and closing the outlet.

Method and apparatus for setting an integrated hanger and annular seal before cementing

An apparatus for temporarily connecting a first tool part to a second tool part of a tool includes a plurality of frangible members connecting the first tool part to the second tool part. The frangible members break only after being subjected to a predetermined applied force. The frangible members cooperate to differentially resist loading applied to the tool.

Actuating force control for downhole tools

A liner is cemented bottom up and then top down followed by setting the simultaneously set liner hanger/packer and releasing the running tool. In one embodiment the ported sub for top down cementing has ports opened and then closed with multiple dropped or pumped balls one of which lands in the running tool to set the hanger packer with pressure before running tool removal. A dart with a leading ball can follow the top down cement to close the ported sub and thereafter land in the liner hanger/packer to set it with pressure. A dart can lead the top down cement and open the ported sub followed by a second dart behind the top down cement to close the ported sub and land in the liner hanger/packer to set it and to release the running tool. The ported sub can be operated in other ways such as motors responsive to a remote signal.

Combination bottom up and top down cementing with reduced time to set liner hanger/packer after top down cementing

Wall openings in a mandrel of a liner hanger/packer are eliminated and setting is accomplished with pressure against a landed object in a running tool. The wall of the running tool leads to a sealed annular space with a movable seal attached to a setting sleeve and the other end is a packer cup supported by the running tool. The setting sleeve sequentially sets the slips and releases the running tool followed by setting the packer seal. Optionally a dog sub can be used to set with set down weight on the setting sleeve. The set positions are locked in. The slips can be alternatively set with release of a contained spring force. The setting sleeve seal can be sheared out to allow removal of the running tool.

Pressure set liner hanger/packer without tubing wall port

In one aspect, a method of completing a wellbore is disclosed that in one non-limiting embodiment includes: placing a completion assembly in the wellbore, the completion assembly including a first link along an outside the completion; placing a second link between a surface location and a subsea location; placing a string having a third link between the first link and the second link; and connecting the third link to the first link and the second link to provide a continuous link between the completion assembly and the surface location.

Sandface liner with power, control and communication link via a tie back string

In a completion for producing methane the bottom hole assembly has a base pipe with porous media surrounding it for equalizing flow along the base pipe. A shape memory polymer foam surrounds the porous media. The borehole can be reamed to reduce produced methane velocities. Surrounding the shape memory polymer is an exterior layer of consolidated proppant or sand that can self-adhere and/or stick to the polymer foam. The proppant or sand can be circulated or squeezed into position although, circulation is preferred. The borehole may enlarge due to shifting sands in an unconsolidated formation as the methane is produced. The bottom hole assembly helps in fluid flow equalization and protects the foam and layers below from high fluid velocities during production.

Multi-layered wellbore completion for methane hydrate production

A downhole activation assembly includes a housing that is operatively connectable to a downhole tool and that has a passage for flow of fluid therethrough. An indexing assembly is positionable in the housing, includes a multiple position indexer and an indexing tube, and is operatively connectable to the downhole tool. A sleeve valve includes a fixed sleeve portion and a movable sleeve portion that is positionable in the housing passage and defines a ball passage therethrough. A valve seat in the sleeve valve is configured to receive the ball such that the flow of the fluid is selectively restricted through the ball passage. The movable sleeve is engagable with the indexing tube to selectively shift the indexer between multiple positions whereby the downhole tool is selectively activatable.

Downhole activation assembly with sleeve valve and method of using same

A downhole tool and associated methods. The downhole tool includes a body with a throughbore; at least one extendable cutting member; and an actuation member. The actuation member is operatively associated with the extendable cutting member and movable relative to the body to extend the cutting member laterally from the body along an extension axis. The extension axis is offset from a radius of the body.

Large gauge concentric underreamer

A method of inhibiting an undesirable fluid flow path, including pumping a flow of fluid downhole, the flow of fluid containing a plurality of shape-change particles; depositing the shape-change particles in an undesirable fluid flow path in a downhole structure; transitioning the shape-change particles from a first shape to a second shape; forming a plug with the shape-change particles when in the second shape; and inhibiting the undesirable fluid flow path from fluid flow therethrough with the plug of shape-change particles.

Shape-change particle plug system

A treatment system including a first tubular having at least one port therein. A valve member is disposed with the first tubular and operatively arranged to control fluid flow through the at least one port. A second tubular is disposed radially within the first tubular and terminates at an end opening into an interior passage of the first tubular for enabling a treatment media to be supplied through the second tubular into the first tubular, and through the at least one port when the at least one port is open. A seal assembly is disposed between the first and second tubulars for fluidly sealing an annulus formed between the first and second tubulars from the end of the second tubular. A tool is disposed with the second tubular for controlling operation of the valve member.

Formation treatment system

Growing community of inventors

Houston, TX, United States of America

Mark Kendall Adam