Halliburton Energy Services, Inc.

Halliburton Company

Chevron U.s.a. Inc.

Sdg LLC

Halliburton Services

Lonnie Carl Helms

Frank Vinicio Acosta

Min Mark Yuan

Rajesh Parameshwaraiah

Ishwar Dilip Patil

Mayur Narain Ahuja

Paul Joseph Jones

Nicholas Frederick Budler

Bo Gao

Gary Joe Makowiecki

Aniruddha Gadre

Yuzhu Hu

Jinhua Cao

Stephen Allen Yeldell

Handoko Tirto Santoso

John Key

Frank Vinicia Acosta Villarreal

Kevin Wendell Ardoin

Avinash Gopal Dharne

Michael Linley Fripp

Samuel Jason Lewis

William Cecil Pearl, Jr

Ricky Layne Covington

Saul Emmanuel Vazquez Niebla

Luke Christopher Downey

Tor Sigve Saetre

Priyanshkumar Prashantkumar Desai

John Laureto Maida, Jr

John Paul Bir Singh

James R Longbottom

Timothy Rather Tips

Christopher Lee Stokely

Byong Jun Kim

Todd Anthony Stair

Venkata Gopala Rao Palla

Shobeir P Gar

Ernst Rudolf Man Schnell

Maithri Muddasani

Reena Thomas

Frank Vinicio Acosta Villarreal

Frank Vinicia Acosta VIllarreal

Clayton Reed Bonn

Neal Gregory Skinner

Songhua Chen

Henry Eugene Rogers

Jeffery Dwane Karcher

William M Moeny

Robert Phillip Darbe

Sam Jason Lewis

Simon David Turton

John P Singh

Xiaoguang Allan Zhong

Tamal Kumar Sen

Christopher James Mericas

Michael Malave

Carlos Alejandro Valdez

Saul Emmanuel Vazquez

Julio Alberto Cornejo

Thomas Zachary Vonk

Payton Dally

Misty Dawn Rowe

Grant Andruss

Connor Faulk

Luke Smith

Brian Nguyen

Gavin Graff

Arturo Lopez

Nathan Barrett Wyatt

Benny E Dawsey

Rafael Hernandez

David Li

John Roland Key

Steven Daniel Southwell

Saul Emmanuel Vazquez-Niebla

Brittany Helene Spivey

A sealing element for wellbore operations can include an energizing end with a sloped surface and a perpendicular surface, a stationary end with a sloped surface and a perpendicular surface, and an engagement surface located between the energizing end and the stationary end. An energizing sleeve can include a sloped surface that engages with and moves along the sloped surface of the energizing end to cause the engagement surface to engage with the inside of a tool housing, casing, or tubing string to create a seal. A stationary tool component can about the stationary end, so the sealing element is energized. The sealing element can be used in a packer assembly, as an anchoring device, in lieu of O-rings, to allow opening or closing of flow ports, or in other downhole tools.

Sealing element with sloped ends

A downhole tool has a tool body with a tool body outer diameter. A liner with a liner outer diameter is connected to the tool body. The tool body has a plurality of diverter ports defined in a wall thereof. A closing sleeve is movable in the tool body to close the diverter ports. A closing seat attached to the closing sleeve is a frangible closing seat.

Apparatus and method of reducing surge when running casing

A puddle job can be performed in a wellbore to secure a liner within an open-hole wellbore. A resin in liquid form can be spotted at the bottom of the wellbore. The liner can be lowered into the wellbore to displace the resin up into an annulus between the outside of the liner and the wellbore wall. The resin can be contacted with a solid or liquid initiator to cause the resin to set. The resin can be contacted with the initiator as the liner is being lowered or afterwards. The resin/initiator can be used instead of a cement composition.

Puddle job with delayed setting of resin

A puddle job can be performed in a wellbore to secure a liner within an open-hole wellbore. A resin in liquid form can be spotted at the bottom of the wellbore. The liner can be lowered into the wellbore to displace the resin up into an annulus between the outside of the liner and the wellbore wall. The resin can be contacted with a solid or liquid activator to cause the resin to set. The activator can cause the resin to set via a polymerization reaction such as ROMP, FRP, or step polymerization. The resin can be contacted with the activator as the liner is being lowered or afterwards. The resin/activator can be used instead of a cement composition.

Puddle job with delayed setting of resin via a polymerization reaction with an activator

A wellbore fluid inductance monitor is disclosed, which operates at an end of a tubular in a wellbore. The wellbore fluid inductance monitor comprises an inductor in an electrical circuit. A magnetically doped portion of wellbore fluid, which may be a hydraulic fluid or cement slurry, is introduced into the wellbore during a reverse cementing or other cementing operation. The magnetically doped portion of wellbore fluid contains a dopant that alters at least one of a magnetic permeability and conductivity. The wellbore fluid inductance monitor detects the proximity magnetically doped portion of wellbore fluid based on altered electrical characteristics of the inductor. Based on the detection, the wellbore fluid inductance monitor triggers a wellbore operation which is detectable at a cementing controller and the cementing operation can be stopped or otherwise completed based on the determination that the cement slurry has reached the end of the tubular.

Induction loop cementing progress detection

A wiper dart having a bi-diameter wiper cup can be used to help track the location of the dart in a pipe string. As the wiper dart is pumped through the pipe string, a first mean pump pressure will exist as the wiper cup travels through drill pipe sections having a larger inner diameter than a tool joint and a second mean pump pressure will exist as the wiper cup travels through the tool joints. The wiper cup can have a geometric shape selected such that a detectable pressure spike can be observed when the wiper cup reaches a transition section located between one end of a pipe section and the tool joint. By counting the number of pressure spikes, an operator can accurately track the location of the wiper dart as it is being pumped through the pipe string.

Tracking a wiper dart having a bi-diameter wiper cup in a wellbore using pressure spikes

A wiper dart can be used in an oil and gas operation. The wiper dart can have at least two different outer diameters. A first outer diameter can be less than a second outer diameter and used to wipe the insides of tool joints of a tubing string. The second outer diameter can be used to wipe the insides of pipe sections of the tubing string that have a larger inner diameter than the tool joints. The single, bi-diameter wiper cup can be used in lieu of two or more current, conical-shaped wiper cups to accomplish the same functionality. The wiper cup can include a protruding ring located circumferentially around the wiper cup at the first outer diameter. A plurality of buttons or splines can be spaced apart around the wiper cup at the second outer diameter.

Wiper dart having a bi-diameter wiper cup with protruding ring

A wiper dart can be used in an oil and gas operation. The wiper dart can have at least two different outer diameters. A first outer diameter can be less than a second outer diameter and used to wipe the insides of tool joints of a tubing string. The second outer diameter can be used to wipe the insides of pipe sections of the tubing string that have a larger inner diameter than the tool joints. The single, bi-diameter wiper cup can be used in lieu of two or more current, conical-shaped wiper cups to accomplish the same functionality. The wiper cup can be generally bell shaped and have a variety of first and second outer diameters.

Wiper dart having a bi-diameter wiper cup

Provided, in one aspect, is a cementing apparatus. The cementing apparatus, in one embodiment comprising a housing; a fixed member coupled with the housing, the fixed member having at least one fixed member fluid opening therein; and a moving member positioned downhole of the fixed member and movable between a circulating position and a cemented position, the moving member having at least one moving member fluid opening therein, the at least one moving member fluid opening linearly offset from the at least one fixed member fluid opening.

Cementing apparatus for reverse cementing

A valve housing has a first flapper moveable from an open position in the housing in which two-way flow is allowed to a closed position in which only one-way flow is permitted. A first collet sleeve is moveable from a first position to a second position in the valve housing. The first collet sleeve in the first position retains the flapper valve in the open position. The collet sleeve is moveable from a first position to a second position which allows the flapper to move to a closed position.

Differential fill valve with collet sleeve

Systems and methods are provided for determining the end of a reverse cementing operation based on one or more pressure measurements. In some aspects, a cement composition can be delivered to an annulus formed between a casing and a wellbore for reverse cementing the casing. In some cases, a determination that the cement composition has reached a shoe joint at a bottom portion of the casing can be based on a threshold change in a pressure measurement obtained while delivering the cement composition. In some instances, a trigger can be initiated for closing the shoe joint after determining that the cement composition has reached the shoe joint.

Managed pressure reverse cementing and valve closure

Float collar equipment can be bonded to an inside of a casing string via an adhesive. An annulus can be located around an outside of a float collar housing and the inside of the casing string where the adhesive can be injected. The float collar housing does not require external threads or packers to secure the housing to the inside of the casing string. An injection sub can be used to inject the adhesive into the annulus. After curing or drying, the adhesive bonds the housing to the casing string. A seat, seat housing, or float shoe nose can be attached to the float collar housing via an adhesive or threads. The float collar housing can house one or more float assemblies. The float collar equipment can be bonded to the casing string at a wellsite or remote location prior to use in a cementing operation.

Externally threadless float equipment for cementing operations

A downhole apparatus has a sleeve body sleeve body defining a sleeve body inner surface. The sleeve body has an internal thread on at least a portion thereof. The internal thread defining having a thread minor diameter. A plug seat is pressed into the threaded portion of the sleeve body. The plug seat has an unthreaded outer surface defining a plug seat outer diameter. The plug seat outer diameter is greater than the thread minor diameter.

Operating sleeve

A flow diverter having a first conical section, a second conical section, and support legs. The first conical section comprises an outside surface tapering from a first end to a second end. The first end of the first conical section comprises a rounded nose. The second conical section comprises an outside surface tapering from a first end to a second end. The first end of the second conical section comprises a rounded nose. The second end of the first section can contact or be integrated with the second end of the second section, or an intermediate section can be positioned therebetween. The intermediate section can comprise a substantially cylindrical outer surface extending from the second end of the first conical section to the second end of the second conical section. The support legs are configured to fixedly couple the flow diverter to a tubular.

Fluid particulate concentrator for enhanced sensing in a wellbore fluid

A downhole tool for use in a well comprising a mandrel and an outer sleeve slidably disposed about the mandrel. An inner sleeve is slidably disposed in the mandrel. A drive pin comprising a drive pin bushing connected to the outer sleeve and a shear pin connected to the inner sleeve connects the inner sleeve to the outer sleeve.

Shearable drive pin assembly

Growing community of inventors

Humble, TX, United States of America

Lonnie Carl Helms