Halliburton Energy Services, Inc.

Regeneron Pharmaceuticals, Inc.

Mitsubishi Electric Research Laboratories, Inc.

Mitsubishi Electric Research Labs.

Yiming Zhao

Jason Daniel Dykstra

Xingyong Song

Hunter Chen

Yebin Wang

Umut Zalluhoglu

Venkata Madhukanth Vadali

Fanping Bu

Stefano Di Cairano

Daniel Nikolaev Nikovski

Scott Bortoff

Robert Phillip Darbe

Julien Marck

Timothy Riehlman

Gabriel Carreau

Shao-Chun Wang

Ying Wang

The present invention provides methods for fabricating protein-encapsulating microgels using hydrocarbon-in-fluorocarbon emulsions. The non-aqueous emulsion-based microgel fabrication methods can be used for the encapsulation of a wide range of proteins and peptides, including antibodies and antibody-fusion proteins, for therapeutic use with ease of administration.

Fabrication of protein-encapsulating microgels

Non-aqueous membrane emulsion methods for producing polymeric and polymer-coated microparticles are provided. Some embodiments provide methods for producing a sustained release or controlled release microparticle by combining micronized protein powder and a polymer into a hydrocarbon solvent to form a non-aqueous first solution, agitating the first non-aqueous solution to form a suspension, feeding the suspension into a dispersion pump, wherein the suspension is infused through a porous membrane into a continuous phase comprising a fluorocarbon liquid and a fluorosurfactant to form a hydrocarbon-in-fluorocarbon emulsion. The hydrocarbon solvent, the fluorocarbon liquid, and the fluorosurfactant are removed, and the microparticles are collected.

Sustained release formulations using non-aqueous membrane emulsification

The disclosure relates to methods of analyzing a post-translationally modified protein of interest using electrophoresis, the methods comprising deglycosylating the protein of interest after labeling.

Deglycosylation methods for electrophoresis of glycosylated proteins

Non-aqueous emulsion methods for producing polymeric or polymer-coated microparticles are provided. One method produces a sustained release microparticle composition by combining protein powder and a polymer into a hydrocarbon solvent to form a non-aqueous first solution and adding the first solution to a second solution, wherein the second solution comprises a fluorocarbon liquid and a fluorosurfactant to form a non-aqueous emulsion comprising multiple emulsion hydrocarbon droplets in the fluorocarbon liquid. The subsequent microparticle hardening process includes the steps of removing the hydrocarbon solvent from the formed emulsion droplets, which can be achieved through evaporation the hydrocarbon at ambient condition under stirring, or accelerated hardening through vacuum, or through adding hydrofluoroester into the fluorocarbon as a cosolvent. Removing the fluorocarbon liquid and washing with extra fluorocarbon liquid to isolate the sustained release microparticles, wherein the sustained release microparticles comprise one or more cores of protein and a cortex of polymer.

Sustained release formulations using non-aqueous emulsions

A system includes different types of downhole sensing tools deployed in a borehole, wherein the different types of downhole sensing tools are optimized to identify a downhole condition based on a predetermined downhole evaluation plan that accounts for sensing tool availability and performance constraints. The system also includes at least one processing unit configured to analyze measurements collected by the different types of downhole sensing tools, wherein the collected measurements are analyzed together to identify the downhole condition. The system also includes at least one device that performs an operation in response to the identified downhole condition.

Methods and systems to optimize downhole condition identification and response using different types of downhole sensing tools

The disclosed embodiments include systems and methods to improve downhole drilling. In one embodiment, a method to improve downhole drilling includes receiving a well plan, where the well plan is indicative of a well path to form a borehole of a hydrocarbon well is provided. The method also includes receiving measurements indicative of a previously-drilled section of the borehole. The method further includes generating, based on the measurements, a trajectory of the borehole, where the trajectory is a function of a depth. The method further includes providing the trajectory of the borehole to a Model Predictive Controller. The method further includes steering a tool towards the well path based on an output of the Model Predictive Controller.

Systems and methods to improve directional drilling

Vibrational behavior of a wellbore operation can be characterized as a vibrational map relating a modeled or sensed vibration level of the operation's equipment to operational parameters of the wellbore operation. The operational parameters can be controllable by settings of the equipment. The map can include multiple contour lines, each representing a set of adjacent coordinates of operational parameters that have the same vibrational level. Tracing a contour line can include determining vibration at a pre-tracing coordinate, adjusting the operational parameters until the vibration level to be mapped is reached at a tracing origin coordinate, then varying the operational parameters while keeping the vibration level constant until the tracing origin or a bound of the operational parameters is reached. Vibration levels having multiple, non-intersecting contour lines can be found by repeating tracing from a different pre-tracing coordinate.

Downhole vibration characterization

A method includes generating a torsional wave that propagates in a drill string having a drill bit coupled at a first end of the drill string and a top drive coupled at a second end of the drill string, and determining first and second components of the torsional wave. The first component propagates from the drill bit to the top drive and the second component propagates from the top drive to the drill bit. The method further includes calculating a first control signal to mitigate the first component, calculating a second control signal to regulate the second component, and generating a torque command based on the first and second control signals to control the top drive to dampen the torsional wave.

Mitigating vibrations in a drilling system

A method includes generating k, (k+1), . . . , (k)control inputs for actuating flow control devices of a production well and/or an injection well of a well system during corresponding sampling steps k, (k+1), . . . , k, actuating the flow control devices during the kstep using the kcontrol input, measuring a position of a fluid front and a dynamic state of the well system during the kstep; predicting a dynamic state of the well system at each step (k+1), . . . , kusing a state predictor, updating the (k+1), . . . , (k)control inputs based on the predicted dynamic states, optimizing the (k+1), . . . , (k)control inputs using a desired cost function, actuating the flow control devices during the (k+1)step using the optimized value for the (k+1)step, and measuring the position of the fluid front and a dynamic state of the well system during the (k+1)step.

Real-time water flood optimal control with remote sensing

A method of evaluating a subterranean formation includes conveying a tool along a borehole. The tool includes a transmitter that transmits a drive pulse and a receiver that receives at least one formation response to the drive pulse. The method further includes calculating a signal-to-noise ratio of the at least one formation response and comparing the signal-to-noise ratio to a programmable threshold. The method further includes determining, based on the comparing, an adjusted drive pulse to transmit and transmitting the adjusted drive pulse. The method further includes and receiving at least one formation response to the adjusted drive pulse and deriving formation data from the at least one formation response to the adjusted drive pulse. The method further includes displaying a representation of the formation based on the formation data.

Using an adjusted drive pulse in formation evaluation

A method for directional drilling including defining, by a sliding mode controller, a sliding hypersurface for reducing a trajectory error in one or more error dimensions; determining a current trajectory error between a current trajectory of a directional drilling tool and a reference trajectory for a curved path, the current trajectory error corresponding to a current error position in the one or more error dimensions; calculating a sliding mode vector originating from the current error position and substantially conforming to the sliding hypersurface in the one or more error dimensions; determining a feedback control input for the directional drilling tool based on the sliding mode vector; instructing the directional drilling tool to generate a wellbore path according to the feedback control input; and updating the current trajectory error based on either a change in position or a change in attitude of the directional drilling tool.

Sliding mode control techniques for steerable systems

A method for generating a BHA design and component selection by creating a plurality of BHA configurations. A cost function, representative of each respective BHA configuration, is determined. Each cost function includes drilling process metrics. A final BHA configuration of the plurality of BHA configurations is selected having an optimal cost function value. The optimal cost function value may be defined as a cost function value that is less than cost function values of other respective cost functions for the plurality of BHA configurations.

Bottomhole assembly design and component selection

In accordance with some embodiments of the present disclosure, a method for vibration control for a wellbore logging tool is disclosed. The method may include measuring an initial output signal of the wellbore logging tool. Additionally, the method may include generating a first braking signal based on the initial output signal of the wellbore logging tool. The method may further include transmitting the first braking signal to the wellbore logging tool. The first braking signal may be designed to dampen the vibration of the wellbore logging tool.

Online active vibration control for a wellbore logging tool

A drilling system includes a top drive having a motor with a rotating shaft and an adjustable torque. The drilling system also includes a connector that couples the rotating shaft to a drillstring. The drillstring system also includes a controller that provides torque commands to the motor, wherein the torque commands are based at least in part on a dynamics model and operate to dampen vibrations due to torsional wave propagation along the drillstring.

Downhole drilling methods and systems with top drive motor torque commands based on a dynamics model

In accordance with some embodiments of the present disclosure a method of vibration control for a wellbore logging tool is disclosed. The method may include estimating one or more of an estimated position, an estimated velocity, and an estimated acceleration of the wellbore logging tool after the drive signal has been sent to the wellbore logging tool. The method may include generating an active dampening braking signal based, at least in part, on one or more of the estimated position, the estimated velocity, and the estimated acceleration of the wellbore logging tool.

Growing community of inventors

Katy, TX, United States of America

Yiming Zhao