Baker Hughes Corporation

Bj Services Company

Baker Hughes, a Ge Compnay, LLC

Other

Nowsco Well Service Ltd.

Baker Hughes Imcorporated

Bj Services Company Canada

John Gordon Misselbrook

John E Ravensbergen

Silviu Livescu

Lyle Laun

Richard A Altman

Manfred Sach

Lance Nigel Portman

Alexander Raphael Crabtree

Jason Skufca

David E Sask

William Arthur Aitken

Harold Dean Brannon

Jeff Li

Lubos Vacik

William George Gavin

John Delorey

Darcy Allan Schultz

Craig Chabert

Alexander R Crabtree

Spencer J Fried

Trevor Gordon Hayes

Quentin Shane Stang

William Arthur Hutton Aitken

Russell Meyer

David Ross

Trevor Hayes

Darcy Schultz

Shane Stang

John Edward Ravensbergen

Lyle Erwin Laun

Harold Brannon

Barry Thomas Hlidek

Darcy A Schultz

A method of monitoring a coiled tubing operation includes positioning a bottom hole assembly (BHA) connected to a coiled tubing string within a horizontal wellbore. The method includes monitoring a plurality of sensors connected to the BHA via a communication line positioned within the coiled tubing string and determining an optimal injection speed of the coiled tubing string by monitoring the sensors in real-time. The injection speed of the coiled tubing may be changed based on the real-time determination of the optimal injection speed. The sensors may be monitored in real-time to determine an optimal amount of lubricant to be injected into a wellbore or whether the coiled tubing string is forming a helix. The BHA may include a tractor or a vibratory tool to aid in the movement of the BHA along a horizontal wellbore. The communication line may be used to power the sensors, tractor, and vibratory tool.

Real-time extended-reach monitoring and optimization method for coiled tubing operations

An aqueous-based downhole fluid having a lubricant therein may be circulated within a subterranean reservoir wellbore where the downhole fluid may be or include a drilling fluid, a completion fluid, a fracturing fluid, a drill-in fluid, a workover fluid, and combinations thereof. The lubricant may include a clay stabilizer and a vegetable oil derivative, such as but not limited to, a sulfonated vegetable oil. The downhole fluid may include the lubricant in an effective amount for lubricating a first surface.

Lubricating compositions for use with downhole fluids

A system and method for splicing a non-spoolable tool anywhere along a coiled tubing string. A removable tubing section may be connected along a coiled tubing string by two spoolable connectors. The coiled tubing string may be unspooled from a reel until the removable tubing section and connectors are positioned within a work window. The removable tubing section may be disconnected from the tubing string through the work window and a tool may be connected to the coiled tubing string via the two connectors. The tool may then be positioned within a wellbore by insertion of the coiled tubing string. The tool may aid in the insertion of the coiled tubing string into the wellbore. A portion of the wellhead may be disconnected and raised to expose the connectors to permit the removal of the removable tubing section and the connection of a non-spoolable tool.

System and method for splicing a non-spoolable tool anywhere along a coiled tubing string

A system of couplings and method of use of the couplings to locate a downhole tool connected to coiled tubing, such as a bottom hole assembly, within a selected segment of a casing string. The selected segment of casing may be a ported collar or ported housing that permits the treatment and/or stimulation of the adjacent well formation. The system of couplings may be two, three, or four couplings spaced apart at predetermined lengths. The predetermined lengths may be shorter than typical lengths of casing segments. The distance between the first and second coupling may be substantially identical to the distance between the third and fourth coupling. The use of distances between the couplings that are shorter than the length of conventional casing segments may provide surface indicators as to the location of the bottom hole assembly with a higher confidence than relying on a traditional tally sheet.

System and method for positioning a bottom hole assembly in a horizontal well

A wellbore completion is disclosed. The wellbore completion comprises a casing assembly comprising a plurality of casing lengths. At least one collar is positioned so as to couple the casing lengths. The at least one collar comprises a tubular body having an inner flow path and at least one fracture port configured to provide fluid communication between an outer surface of the collar and the inner flow path. A length of coiled tubing can be positioned in the casing assembly. The coiled tubing comprises an inner flow path, wherein an annulus is formed between the coiled tubing and the casing assembly. A bottom hole assembly is coupled to the coiled tubing. The bottom hole assembly comprises a fracturing aperture configured to provide fluid communication between the inner flow path of the coiled tubing and the annulus. A packer can be positioned to allow contact with the at least one collar when the packer is expanded. The packer is capable of isolating the annulus above the packer from the annulus below the packer so that fluid flowing down the coiled tubing can cause a pressure differential across the packer to thereby open the fracture port.

Multi-zone fracturing completion

A coiled tubing cutter assembly comprises a housing configured to be inserted in a length of coiled tubing. The housing forms a main bore and a first pathway through which cutting fluid can flow through the housing and be directed to impinge against an inner surface of the coiled tubing over which the housing is positioned so as to cut the coiled tubing. A sleeve is positioned in the main bore. The sleeve is movable between a first position and a second position within the main bore. The sleeve is configured so as to block the first pathway when in the first position and to allow cutting fluid to pass through the first pathway in the second position. A method of cutting coiled tubing is also disclosed.

Cutting assembly and method of cutting coiled tubing

A shear pig assembly and method of use for severing a linear conductor within a surrounding tubular. A shear pig assembly includes a main body and a nose that radially surround the linear conductor within the tubular. The main body and nose are axially moveable with respect to each other to cause a shear plug to move radially within a shearing chamber, thereby severing the linear conductor.

Devices and methods for severing a tube-wire

The present disclosure is directed to a cutting dart. The cutting dart comprises a dart body including a first pathway. The first pathway is configured to redirect cutting fluid flowing through a coiled tubing so that the cutting fluid flows radially to impinge against an inner surface of the coiled tubing. A seal is positioned around an outer circumference of the dart body. The present disclosure is also directed to an anchor dart. The anchor dart comprises a dart body and a swellable elastomer positioned around an outer circumference of the dart body. Methods of employing the cutting dart and anchor dart are also disclosed.

Cutting dart and method of using the cutting dart

A bottom hole assembly connected to coiled tubing to create an acid tunnel in a wellbore formation. High pressure acid is pumped down the coiled tubing and out a nozzle located at the end of the bottom hole assembly. The bottom hole assembly includes a first reversible knuckle joint and a second reversible knuckle joint to properly position the nozzle against the wellbore and to allow the assembly to adjust its angle as it initiates and moves through the lateral tunnel. The two reversible knuckle joints increases the radius of curvature of the bottom hole assembly while providing a sufficient attack angle for the nozzle against the wellbore. The two knuckle joints may be adjusted in response to loads applied on the assembly as the assembly moves through the lateral tunnel.

Acid tunneling bottom hole assembly and method utilizing reversible knuckle joints

A system used to remove multiple isolation plugs from a wellbore. The system is efficient in fluidizing and circulating proppant located below an upper plug resting on top of proppant settled above a lower plug. The system uses a central port of the mill that is in communication with coiled tubing to fluidize and circulate the proppant around the perimeter of the upper plug. Once the proppant has been circulated from underneath the upper plug, the upper plug may mate and rotationally lock with a lower plug set within the wellbore. Upon locking, the system is able to rapidly mill out the upper plug and the lower plug until the lower plug is no longer set within the wellbore. The system provides for the rapid removal of multiple plugs positioned within a wellbore where an amount of proppant is present between the plugs.

Mill and method for drilling composite bridge plugs

Methods for cleaning out horizontal wellbores using coiled tubing are provided for use during downhole operations. A coiled tubing having a bottom hole assembly is deployed into a horizontal wellbore. Fluid is circulated down the annulus of the wellbore and up the bottom hole assembly while the bottom hole assembly is moved upward at a selected rate and distance. This method may be used to remove downhole solids, such as formation sands and proppant.

Methods for cleaning out horizontal wellbores using coiled tubing

In some embodiments, a method of allowing a subterranean formation to be fractured from an open hole well bore section includes providing a removable coating across substantially the entire surface of the wall of the well bore section, selectively removing the coating at a desired first fracture initiation location and allowing the first fracture to be formed in the vicinity of the desired first fracture initiation location.

Methods for allowing multiple fractures to be formed in a subterranean formation from an open hole well

A production tubing comprising a liner is placed downhole in a wellbore. A fluid pill containing proppant is squeezed into the annulus between the formation and liner, thereby packing the proppant into the annulus, effectively isolating the annulus. The packed proppant is permeable to liquids but impermeable to fracturing proppants. After isolation of the annulus, the wellbore may be perforated using a resettable perforation assembly. Once perforating is complete, the wellbore is fractured. The presence of the packed proppant in the annulus generates resistance to the flow of fracturing fluid along the annulus, forcing the fracture to propagate down the perforation tunnels, while also allowing subsequent production fluids to be produced along the annulus.

Methods for placing multiple stage fractures in wellbores

An improved method for building a plug in a horizontal wellbore using a fluid pill pumped into the wellbore at the end of a fracturing treatment. The fluid pill includes a high concentration of an ultra lightweight proppant, such as a neutrally buoyant proppant or an ultra lightweight proppant mixture. The fluid pill is pumped down the wellbore until it almost reaches fractures within a zone of interest. The pumping is then ceased or reduced, allowing the fractures to partially close. The ultra lightweight proppant remains suspended within the fluid pill while stationary. The pumping is then resumed at a very slow rate or as a short pump burst, thus causing the proppant in the fluid pill to bridge off until a bridge plug is formed.

Method of isolating open perforations in horizontal wellbores using an ultra lightweight proppant

The invention is directed to controlling sand production in an oil and/or gas well. A preferred embodiment of the invention is directed to repairing a downhole screen by pumping neutrally buoyant resin coated material into a damaged portion of a gravel pack screen and also into any void behind the damaged portion of the screen. The neutrally buoyant resin provides for the repair of a portion of the screen even if the damaged portion is located on the uphole side of a deviated well. Any excess resin coated material may subsequently be removed from the central passageway of the screen and then circulated to the surface because the resin coated material is neutrally buoyant. Neutrally buoyant resin may be pumped into a well that does not have a sand control system. The porous neutrally buoyant resin allows production of hydrocarbons, but prevents production of sand into the well.

Growing community of inventors

Calgary, Canada

John Gordon Misselbrook