Halliburton Energy Services, Inc.

Jody Ray McGlothen

David Joe Steele

Henry Louis Restarick

Bradley Leon Todd

Gary P Funkhouser

Robert S Taylor

Michael M Brezinski

Thomas Wayne Ray

Gregory B Chitwood

Ernest C Bailey

John C Gano

Cynthia Strickland Tuckness

Alex Procyk

Roger Lynn Schultz

Ralph Harvey Echols

William David Henderson

Michael Wayne Sanders

Marion Dewey Kilgore

Ronald J Powell

Robert T Brooks

Joseph DeWitt Parlin

Russell Irving Bayh

Dan Parnell Saurer

Richard Thomas Hay

Daniel Jon Themig

Travis Wayne Cavender

Michael Dale Ezell

Joe Eli Hess

Floyd Randolph Simonds

William Wallace Dancer

Paul I Herman

Christopher J Chalker

James W Scott

Gary Lorne Donison

Robert Kenneth Buckner

Radu Nicolae Nistor

Beauford Sean Mallory

Roderick Brand Falconer

Jeffery Richard Acker

Steven R Fipke

Michelle Brianne Henckel

Tommy L Stambaugh

Colin M MacRae

Denis C Desranleau

William Sloane Muscroft

Larry R Valentine

A system includes a valve housing with a port formed in a wall of the housing, a rotation sleeve disposed in the valve housing, an orienting sleeve with an orienting feature disposed in and fixed to the valve housing, and a shifter. The rotation sleeve is rotatable relative to the valve housing and includes a port formed therethrough. The shifter includes engagement features disposed a distance from each other along a length of the shifter and a rotational distance from each other about a circumference of the shifter. The engagement features are receivable into corresponding features of the orienting sleeve and the rotation sleeve to rotate the rotation sleeve relative to the valve housing as the shifter travels through the valve housing. The system may be used to selectively manipulate any number of valves in downhole equipment.

Manipulating a downhole rotational device

A retrievable Electrical Submersible Pump (ESP) and electrical motor for driving the ESP are positioned in a tubing string in the wellbore and, when desired, retrieved back to the surface. The ESP and motor are on an insertion string and can be lowered using wireline, coiled tubing, and standard running and setting tools. The method eliminates the need to retrieve the tubing string to repair, replace, or service the ESP and motor.

Retrievable electrical submersible pump

Passive completion optimization with fluid loss control. A completion string includes a set of well tools interconnected as a portion of the completion string, the well tools including a well screen assembly, at least one valve which controls fluid communication between an interior and exterior of the string, and two packer assemblies, each of the packer assemblies including at least one swellable seal element, and the packer assemblies longitudinally straddling the valve and the screen assembly. Another completion string includes a set of well tools interconnected as a portion of the completion string, the well tools including two packer assemblies, a well screen assembly, and the screen assembly including an inflow control device which restricts fluid flow through the screen assembly, each of the packer assemblies including a swellable seal element, and the packer assemblies longitudinally straddling the screen assembly.

Passive completion optimization with fluid loss control

A packer () for establishing sealing engagement with a surface disposed in a wellbore includes a packer mandrel () and a seal assembly () slidably disposed about the packer mandrel (). The seal assembly () has a running position and a radially expanded sealing position. A piston () is slidably disposed about the packer mandrel () and operably associated with the seal assembly (). A release assemblyis disposed about the packer mandrel () and is releasably coupled to the piston () such that actuation of the release assembly () decouples the release assembly () from the piston () allowing the piston () to shift longitudinally relative to the packer mandrel () to operate the seal assembly () from the running position to the radially expanded sealing position, thereby setting the packer ().

Interventionless set packer and setting method for same

Packer assemblies capable of providing desired load-bearing performance and of being retrieved from a bore in a subterranean formation are described. A packer assembly can include a wedge that can respond to a force in a downhole direction by un-supporting the slip. The unsupported slip is configured to disengage from a casing string, allowing the packer assembly to be removed from the bore. The wedge can include a collet to allow the wedge to separate from the slip to prevent slip re-setting.

Packer assembly

Diameter based tracking for a window milling system. A window cutting system includes a cutting assembly with multiple cutting faces for cutting the window; and a diverter for guiding displacement of the cutting assembly relative to the window, the diverter including multiple separate guide paths for the respective multiple cutting faces. A method of cutting a window includes the steps of: positioning a diverter in a tubular string, the diverter including multiple separate guide paths for respective multiple cutting faces of a cutting assembly; and then contacting the guide paths with the cutting faces to thereby form the window. Another method of cutting a window includes the step of: positioning a diverter in the tubular string, the diverter including multiple separate guide paths for respective multiple cutting faces of a cutting assembly, with each of the guide paths providing a separate wear surface for the respective cutting face.

Diameter based tracking for window milling system

An apparatus for separating a downhole tubular string into two parts. The apparatus includes a receptacle operably associated with a first part of the downhole tubular string and a mandrel operably associated with a second part of the downhole tubular string. First and second sleeves each having a profile are slidably positioned between the receptacle and the mandrel and are operable to be securably coupled to the mandrel in first and second positions relative to the mandrel. First and second rings are respectively positioned between the profiles of the first and second sleeves and the profiled surface of the receptacle. The first and second rings are operable to initially limit longitudinal movement of the receptacle relative to the mandrel, to prevent tubular string recoil during operation and to allow longitudinal movement of the receptacle relative to the mandrel after operation.

Apparatus and method for separating a downhole tubular string into two parts

A system for producing fluids from a subterranean zone comprises a tubing string disposed in a well bore, the tubing string adapted to communicate fluids from the subterranean zone to a ground surface. A downhole fluid lift system is operable to lift fluids towards the ground surface. A downhole fluid heater is disposed in the well bore and is operable to vaporize a liquid in the well bore. A seal between the downhole fluid lift system and the downhole fluid heater is operable to isolate a portion of the well bore containing the downhole fluid lift system from a portion of the well bore containing the downhole fluid heater. A method comprises: disposing a tubing string in a well bore; generating vapor in the well bore; and lifting fluids from the subterranean zone to a ground surface through the tubing string.

Producing resources using steam injection

A casing exit joint with an easily milled and low density barrier. A casing exit joint for use in drilling a lateral wellbore outwardly from a parent wellbore includes a generally tubular window structure having a window formed through a sidewall of the structure. An outer sleeve is disposed external to the window structure, so that the sleeve overlies the window. A hardenable substance supports the sleeve against deflection toward the window. A method of drilling a lateral wellbore extending outwardly from a parent wellbore includes the steps of: providing a casing exit joint including a hardenable substance positioned in a sidewall of the casing exit joint; then installing the casing exit joint in the parent wellbore; and then cutting through the hardenable substance in order to provide access for drilling the lateral wellbore.

Casing exit joint with easily milled, low density barrier

A surface controlled subsurface lateral branch safety valve provides flow control for each branch wellbore in a multilateral well. In a described embodiment, a completion system for a well having an intersection between parent and branch wellbores includes an apparatus having multiple passages formed therethrough. One passage provides fluid communication between opposite ends of the apparatus in the parent wellbore, and another passage provides guidance for drilling the branch wellbore. The apparatus further includes a flow control device, such as a surface controlled subsurface safety valve, which selectively controls fluid communication with the branch wellbore.

Surface controlled subsurface lateral branch safety valve

Systems and methods are provided for treating a wellbore using a loop system to heat oil in a subterranean formation contacted by the wellbore. The loop system comprises a loop that conveys a fluid (e.g., steam) down the wellbore via a injection conduit and returns fluid (e.g., condensate) from the wellbore via a return conduit. A portion of the fluid in the loop system may be injected into the subterranean formation using one or more valves disposed in the loop system. Alternatively, only heat and not fluid may be transferred from the loop system into the subterranean formation. The fluid returned from the wellbore may be re-heated and re-conveyed by the loop system into the wellbore. Heating the oil residing in the subterranean formation reduces the viscosity of the oil so that it may be recovered more easily.

Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore

The present disclosure addressed apparatus and methods for forming an annular isolator in a borehole after installation of production tubing. Annular seal means are carried in or on production tubing as it is run into a borehole. In conjunction with expansion of the tubing, the seal is deployed to form an annular isolator. An inflatable element carried on the tubing may be inflated with a fluid carried in the tubing and forced into the inflatable element during expansion of the tubing. Reactive chemicals may be carried in the tubing and injected into the annulus to react with each other and ambient fluids to increase in volume and harden into an annular seal. An elastomeric sleeve, ring or band carried on the tubing may be expanded into contact with a borehole wall and may have its radial dimension increased in conjunction with tubing expansion to form an annular isolator.

Annular isolators for expandable tubulars in wellbores

A system and method for assembly of downhole equipment in a subterranean well. In a described embodiment, a method of assembling an apparatus in a subterranean well includes the steps of: positioning an expandable shell in the well; expanding the shell in the well; and then interconnecting multiple portions of the apparatus to each other within the expanded shell.

Assembly of downhole equipment in a wellbore

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Waxahachie, TX, United States of America

Jody Ray McGlothen