Baker Hughes Corporation

Halliburton Energy Services, Inc.

Stabil Drill Specialties, L.l.c.

Weatherford Technology Holdings, LLC

National Oilwell Varco, L.p.

Baker Hughes, a Ge Compnay, LLC

Baker Hughes Holdings LLC

Sorin Gabriel Teodorescu

Dale E Jamison

Lev Ring

Eric Charles Sullivan

Terry Hunt

Tarald Gudmestad

Hallvard Svadberg Hatloy

Donnie Williams

Robert J Murphy

Xiangnan Ye

Tu Tien Trinh

Xiaomin C Cheng

Matthew J Meiners

Daryl Pritchard

John Gerard Evans

Richard Earl Beggs

Keith Glasgow

Amir Shojaei

Robert Bradley Beggs

Lot William Short, Jr

Yildirim Hurmuzlu

Marius Raducanu

Dong P Phung

Amin Mehrabian

Lot William Short

Matthew Meiners

John G Evans

A downhole shock absorbing sub which includes a tubular main stem extending through a sub housing and a lateral shock absorbing assembly positioned within the sub housing. The lateral shock absorbing assembly includes an activator ring positioned around the main stem, the activator ring including a plurality of wedge inserts positioned around a perimeter of the activator ring. A reaction collar is positioned on each side of the activator ring with the reaction collars including ramp surfaces engaged by the wedge inserts. A spring system is positioned to resist movement of the reaction collars away from the activator ring, whereby lateral movement of the main stem causes the wedge inserts to move the reaction collars against the spring system.

Tri-axial shock absorber sub

A reaming tool for use in a wellbore has an elongated tubular body with an outer surface. There are at least first and second reamer sections formed on the tubular body, with the first and second reamer sections (i) being positioned circumferentially opposite one another, and (ii) each having at least two blades. The first reamer section includes at least one rounded dome insert and a majority of cutting tooth inserts, while the second reamer section includes a majority of rounded dome inserts.

Eccentric reaming tool

A method of managing bottom hole assembly vibrations while drilling a wellbore including obtaining data regarding drilling parameters related to one or more drilling operations, determining if the bottom hole assembly has vibration levels outside of the range of normal operation parameters, modifying the drilling mud formulation to alter at least one of its physical properties and rheological properties to keep or maintain the vibration levels of the bottom hole assembly within the range of normal operation parameters, and mitigating the vibrations.

Real time drilling fluid rheology modification to help manage and miniminze drill string vibrations

A filter sub which includes a tubular sub housing and a strainer insert. The strainer insert has (i) a tubular strainer body, (ii) a plurality of helical grooves formed through a sidewall of the strainer body, and (iii) at least one of the helical grooves extending at least 360&#xb0; around the strainer body.

Filter sub

A rheometer apparatus and methods of use are provided. In one embodiment, the rheometer includes a sleeve having an interior space; a cylindrical bob disposed within the interior space of the sleeve and coupled to a first end of a bob shaft; a cross-spring pivot coupled to a second end of the bob shaft; an arm coupled to and projecting radially from the cylindrical bob; and a linear actuator coupled to the arm. In some embodiments, the rheometer apparatus may facilitate more accurate gel shear strength measurements and/or may be correlated with existing rheometer measurements.

Gel shear strength measurement using a cross-spring pivot

Methods and systems for monitoring the oil to water ratio of a drilling fluid are disclosed. An example drilling fluid monitoring and handling system comprises a mud pit coupled to a fluid supply system and a fluid analysis system. The fluid supply system is coupled to the mud pit and the fluid analysis system. The fluid analysis system is coupled to the mud pit and the fluid supply system, wherein the fluid analysis system comprises a dielectric probe.

Monitoring of the oil to water ratio for drilling fluids

One system embodiment includes: an inlet sensor that measures a fluid quality of an input fluid stream; an arrangement of separation units operating to extract contaminants from the fluid stream; and a user interface (UI). Each separation unit produces a respective output fluid stream, exhibiting a performance that is impacted by a respective operating parameter, and has an outlet sensor that measures an output fluid stream quality. The UI receives fluid quality measurements from the inlet and the outlet sensors, responsively derives a performance value for each separation unit and an overall performance value for the arrangement, and displays each of the performance values. The UI may further set the operating parameter values to automate and optimize the operation of the arrangement for different drilling conditions. The fluid quality measurements may indicate contaminant concentrations, and the performance values may account for separation efficiency, energy consumption, reliability, and next service date.

Optimized recycling of drilling fluids by coordinating operation of separation units

Signal communications at a drilling system generally includes communicating upwards or downwards from the rig floor. For example, signal communications upwards may comprise the control of a cementing head operation (e.g., actuating cementing head). Signal communications downwards may comprise the activation of tools and their confirmation (e.g., hole opening tools, liner hangers, and packers). Actuation may be performed via umbilicals, for example, via pressure spikes or the dropping of balls, darts, or radio-frequency identification (RFID) tags. However, issues may arise wherein, for example, a ball may not properly land to close a circulation valve. As another example, a cementing head could be over 100 feet above the rig floor, which may make it difficult for signal communications via an umbilical. Accordingly, what is needed are techniques and apparatus for activation of tools and their confirmation by a remote communication system.

Method of incorporating remote communication with oilfield tubular handling apparatus

A managed pressure drilling (MPD) operation may use an inverse model in conjunction with a hydraulic model and real-time drilling conditions and parameters as inputs to determine a wellhead pressure set point corresponding to a desired bottomhole pressure. For example, while drilling a wellbore penetrating a subterranean formation with a drilling system, measured data including a wellhead pressure may be acquired. A model may then be executed that applies a hydraulic model to an a priori model estimate vector to produce predicted data; converts the measured data to a measured data vector; applies a randomized maximum likelihood algorithm to the a priori model estimate vector, the predicted data, and the measured data vector to produce an a posterioiri model estimates; and applies the hydraulic model to the a posterioiri model estimates to produce an a posteriori prediction and a calculated wellhead pressure set point corresponding to a desired bottomhole pressure.

Managed pressure drilling with hydraulic modeling that incorporates an inverse model

A drilling system includes a drillstring and a power section further including a stator having a stator axis and a rotor within the stator. The rotor rotates eccentrically within the stator in response to fluid flowing therebetween. Additionally, the system includes a coupling section including first, second, and third rotation members having a first, second, and third axes, respectively. The third rotation member is coupled to the first and second rotation members. The third rotation member is configured to move radially relative to the first and second rotation members as the first, second, and third rotation members rotate about the first, second, and third axes, respectively. Further, the system includes an input shaft coupled to the rotor and first rotation member. The input shaft and first rotation member rotate with the rotor eccentrically to the stator axis and the second rotation member rotates concentrically about the stator axis.

Downhole motor coupling systems and methods

A bit is assembled by forming the bit, including a bit body and a plurality of cutting components; embedding at least one electrical circuit into the bit, the circuit including a temperature sensor; and providing a module to monitor the circuits and generate an indication of bit wear. The electrical circuit may experience a change in resistance or conductivity due to wear of the bit and/or changes in an earth formation adjacent the bit. The bit wear and/or formation changes may be displayed for an operator.

Real time bit monitoring

Apparatus and corresponding method for remotely communicating with a device in a wellbore, comprising: an oilfield tubular handling apparatus (); partial toroidal coil sections () integrated with the oilfield tubular handling apparatus, wherein the partial toroidal coil sections form a toroidal coil upon a tubular member () with the handling apparatus; and a microcontroller for communicating with the device via at least one of signals transmitted or received through the tubular member using the toroidal coil.

The disclosure describes a system and a method for locating a cement plug within a wellbore. The system includes a signal transmitter mounted to the cement plug, a receiver at the opening to the wellbore, one clock positioned on the cement plug and in communication with the transmitter, a second clock which is synchronized to the first clock and in communication with the receiver, and a controller for triggering the transmittal of the signal.

Growing community of inventors

The Woodlands, TX, United States of America

Sorin Gabriel Teodorescu