Halliburton Energy Services, Inc.

Jesse Cale Porter

William Ellis Standridge

Matthew Todd Howell

Kendall Lee Pacey

Joel L Barlow

Kevin R Manke

Donald R Smith

Adam Kent Neer

Michael Linley Fripp

Zachary William Walton

Zachary R Murphree

Jimmie Robert Williamson

Matthew James Merron

Perry C Shy

Donald F Hushbeck

Roger Charles Watson

Matt T Howell

Brian Keith Wilkinson

Tyler Joseph Norman

Tracy Michael Martin

Robert Preston Clayton

Andrew John Eis

Zachery Ryan Olson

Aaron Jacob Miller

Donald Ray Smith

Matt Todd Howell

William Ellis Stanridge

Dissolvable pump down devices, dissolvable pump down assemblies, and methods to propel a bottomhole assembly through a lateral section are presented. A dissolvable pump down device includes an engageable portion, and one or more expandable pieces that are initially in a first position before the dissolvable pump down device is deployed in a wellbore, and configured to expand from the first position to a second position in response to a force generated by fluid flow of fluid through the wellbore. A diameter of the expandable pieces while the expandable pieces are in the first position is less than the diameter of the one or more expandable pieces while the one or more expandable pieces are in the second position. The engageable portion and the one or more expandable pieces are configured to dissolve after the dissolvable pump down device is positioned at the desired wellbore location.

Dissolvable pump down devices, dissolvable pump down assemblies, and methods to propel a bottomhole assembly through a lateral section of a wellbore

A downhole tool and process for introducing the downhole tool into a wellbore are provided wherein the downhole tool includes an occlusion-releasing tool. The occlusion-releasing tool contains an occlusion until such time as it is needed in a frac plug to prevent flow in one direction in the wellbore. The occlusion is released from the occlusion-releasing tool by fluid flow through the occlusion-releasing tool. The fluid flow acts directly on the occlusion to provide sufficient pressure to release the occlusion from a mechanical retainer.

Frac plug setting tool with triggered ball release capability

A wellbore isolation device comprising: one or more materials, wherein the one or more materials degrade after contact with a fluid; and a non-metallic coating, wherein the coating covers the one or more materials of the wellbore isolation device, and wherein the coating partially or wholly degrades after contact with a wellbore fluid. A method of removing the wellbore isolation device comprising: degrading the coating via contact with a wellbore fluid; and contacting the portion of the wellbore isolation device with a fluid, wherein the portion of the wellbore isolation device comprises one or more materials that degrade after contact with the fluid.

Coatings for a degradable wellbore isolation device

A wellbore servicing system, comprising a sleeve system comprising a ported case, a sliding sleeve within the case and movable between a first sleeve position in which the sleeve restricts fluid communication via the case and a second sleeve position in which the sleeve does not, a radially divided segmented seat movable between a first seat position in which the seat restricts movement of the sleeve and a second seat position in which the seat does not, and a sheath covering a portion of the seat, the sleeve system being transitionable from a first, to a second, to a third mode, in the first mode, the sleeve is in its first position and the seat in its first position, in the second mode, the sleeve is in its first position and the seat in its second position, and, in the third mode, the sleeve is in its second position.

System and method for servicing a wellbore

A wellbore servicing apparatus, comprising a housing defining an axial flowbore and comprising ports, a first sleeve, a second sleeve movable relative to the housing from (a) a first position in which the second sleeve obstructs fluid communication via the ports of the housing to (b) a second position in which the second sleeve allows fluid communication via the ports of the housing, and wherein the first sleeve is movable relative to the housing from (a) a first position in which the first sleeve does not allow a fluid pressure applied to the axial flowbore to move the second sleeve from the first position to the second position to (b) a second position in which the first sleeve allows a fluid pressure applied to the axial flowbore to move the second sleeve from the first position to the second position, and an expandable seat.

A downhole tool for use in a well is configurable as a frac plug, a caged ball frac plug or a bridge plug. The tool has a mandrel with a threaded neck. The mandrel has an expandable sealing element disposed thereabout. An adapter, which may be selected from multiple configurations of adapters, is threaded to the neck of the mandrel. The adapter may comprise a sleeve, or a cap with one open end and one closed end. The adapter has threads on an outer surface thereof to which a threaded setting mandrel may be attached. The setting mandrel when actuated will move the tool to a set position in the well and once the tool is moved to the set position the threads on the adapter will shear so that the setting mandrel may be retrieved. The tool will thus remain in the hole and will act as either a frac plug, a caged ball frac plug or a bridge plug depending upon the configuration of the selected adapter.

Composite reconfigurable tool

Disclosed herein is a wellbore servicing system, comprising a tubular string, a first sleeve system incorporated within the tubular string, the first sleeve system comprising a first sliding sleeve at least partially carried within a first ported case, the first sleeve system being selectively restricted from movement relative to the first ported case by a first restrictor while the first restrictor is enabled, and a first delay system configured to selectively restrict movement of the first sliding sleeve relative to the first ported case while the first restrictor is disabled; a second sleeve system incorporated within the tubular string, the second sleeve system comprising a second sliding sleeve at least partially carried within a second ported case, the second sleeve system being selectively restricted from movement relative to the second ported case by a second restrictor while the second restrictor is enabled.

A downhole tool for use in a well has a mandrel with an expandable sealing element disposed thereabout. The mandrel has a head portion threadedly connected thereto. A shoulder in the head portion and an upper end of the mandrel define an annular space. A sleeve with a bore therethrough may be positioned in the annular space. The head portion may be removed and a solid plug installed so that it fits within the annular space and so that the downhole tool will act as a bridge plug. The downhole tool has slip rings made up of a plurality of individual slip segments that are adhesively bonded to one another at the sides thereof.

Interchangeable drillable tool

A downhole tool has a mandrel with a sealing element disposed thereabout. The sealing element is movable from an unset position to a set position in which the sealing element engages the well. Extrusion limiters are positioned at the ends of the sealing element. The extrusion limiters have first and second layers and the first and second layers are different materials. The second layer may be made up of a plurality of discs. At least one of the discs may be a disc with an irregularly shaped outer peripheral edge and a generally circular inner peripheral edge. A plurality of the discs with the irregularly shaped outer edge may be stacked and may be stacked with a generally circular or ring-shaped segmented disc. The first and second layers are stacked and then molded into a final shape for placement at the ends of the sealing element.

Multiple layer extrusion limiter

A downhole tool has a mandrel with slip assemblies positioned thereon above and below a packer element. The slip assemblies are positioned in a manner to anchor the downhole tool in the well. The slip assemblies include a slip ring which has a plurality of slip segments. Each slip segment has inserts disposed in cavities therein. The cavities are oriented such that the longitudinal central axis of each cavity is parallel to the longitudinal central axis of each of the other cavities in the slip segment.

Slip segments for downhole tool

A downhole tool has a mandrel and an expandable packer element for sealingly engaging the well. A slip assembly is positioned on the mandrel and will anchor the downhole tool in the well. The slip assembly may include a slip ring that moves from an unset to a set position. A retaining ring is disposed about the slip ring and will hold the slip ring in the unset position until sufficient force is applied to break the retaining ring. The retaining ring may comprise a retaining band with a dampener to suppress the spring effect experienced by the retaining band when it breaks upon the application of force.

Downhole tool with multiple material retaining ring

A tool that is easily convertible from a frac plug to a bridge plug is disclosed. The tool comprises a mandrel with a mule shoe connected to the lower end thereof. A closing ball is disposed in a cavity defined by the mule shoe. The mandrel is threaded to receive a plug at or near the upper end thereof to convert the frac plug to a bridge plug.

Fracturing plug convertible to a bridge plug

A hydraulic setting tool for packers capable of mechanically setting the packer and opening a valve in the packer in one trip. The tool comprises an outer sleeve and an inner mandrel coaxially disposed within the outer sleeve and adapted to move axially relative to the outer sleeve. The tool further comprises three locking mechnisms that unlock under different fluid pressure loads. Two of the locking mechanisms lock the inner mandrel to the outer sleeve in a run-in position. Once a sufficient fluid pressure has been reached to unlock both of these locking mechanisms, the inner mandrel moves upward relative to the outer sleeve to set the packer. A spring forces the inner mandrel into a third position relative to the outer sleeve, which is maintained by the third locking mechanism. This third position is used to open the packer valve.

Growing community of inventors

Duncan, OK, United States of America

Jesse Cale Porter