Halliburton Energy Services, Inc.

Xingyong Song

Jason Daniel Dykstra

Yiming Zhao

Venkata Madhukanth Vadali

Yuzhen Xue

Xiaoqing Ge

Fanping Bu

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

A system that includes a drillstring with a bottomhole assembly (BHA). The system also includes at least one stabilizer or reamer integrated with the BHA, wherein each of the at least one stabilizer or reamer includes a position adjustment assembly. The system also includes a processing unit that provides control signals to each position adjustment assembly, wherein the control signals are based on a cost function.

Bottomhole assembly (BHA) stabilizer or reamer position adjustment methods and systems employing a cost function

Methods and systems for enhancing workflow performance in the oil and gas industry may estimate the properties of drilling muds (e.g., density and/or viscosity) located downhole with methods that utilize real-time data, estimated drilling mud properties, and mathematical models. Further, the methods described herein may optionally account for the uncertainties induced by sensor readings and dynamic modeling. For example, a method may include circulating a drilling mud through a mud circulation system; performing a plurality of measurements from various sensors in a mud circulation system; modeling in real-time drilling mud flow dynamics in the drilling mud using a mathematical dynamics model; predicting physical states of the drilling mud with the mathematical dynamics model, thereby producing model physical state predictions; inputting the measurements into the mathematical dynamics model; and adjusting discrepancies between the model physical state predictions and the measurements using the mathematical dynamics model.

Real-time downhole drilling mud viscosity and density estimations

A method of estimating a state of a rotary steerable drilling system comprising applying a control input to a rotary steerable drilling system, sensing an actual output of the rotary steerable drilling system, inputting the control input into a mathematical model of the rotary steerable drilling system, receiving an estimated output of the rotary steerable drilling system from the mathematical model, generating an error compensation signal based on a difference between the actual output and the estimated output, and applying the error compensation signal to the mathematical model.

Systems and methods for sensorless state estimation, disturbance estimation, and model adaption for rotary steerable drilling systems

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 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

In accordance with some embodiments of the present disclosure, systems and methods for a nonlinear toolface control system for a rotary steerable drilling tool is disclosed. The method includes determining a desired toolface of a drilling tool, calculating a toolface error by determining a difference between a current toolface and the desired toolface, generating a model to describe the dynamics of the drilling tool, modify the model, based on at least one intermediate variable, to create a modified model, calculating a correction to reduce the toolface error, the correction based on the modified model, transmitting a signal to the drilling tool such that the signal adjusts the current toolface based on the correction, and drilling a wellbore with a drill bit oriented at the desired toolface.

Nonlinear toolface control system for a rotary steerable drilling tool

In accordance with some embodiments of the present disclosure, systems and methods for an advanced toolface control system for a rotary steerable drilling tool is disclosed. The method includes determining a desired toolface of a drilling tool, calculating a toolface error by determining a difference between a current toolface of the drilling tool and the desired toolface, decoupling a response of a first component of the drilling tool, calculating a correction to reduce the toolface error based on a model of the drilling tool containing information about a source of the toolface error, transmitting a signal to a second component of the drilling tool such that the signal adjusts the current toolface based on the correction, and drilling a wellbore with a drill bit oriented at the desired toolface.

Advanced toolface control system for a rotary steerable drilling tool

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, systems and methods for a gain scheduling based toolface control system for a rotary steerable drilling tool are disclosed. The method includes determining a desired toolface of a drilling tool, calculating a toolface error by determining a difference between a current toolface and the desired toolface, determining a plurality of operating points of the drilling tool, selecting one of the plurality of operating points based on a current operating point of the drilling tool, determining a model based on the selection, calculating a correction to correct the toolface error, the correction based on the model, transmitting a signal to the drilling tool such that the signal adjusts the current toolface based on the correction, and drilling a wellbore with a drill bit oriented at the desired toolface.

Gain scheduling based toolface control system for a rotary steerable drilling tool

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

In accordance with some embodiments of the present disclosure, systems and methods for a feedback based toolface control system for a rotary steerable drilling tool is disclosed. The method includes determining a desired toolface of a drilling tool, calculating a toolface error, calculating a correction to correct the toolface error by: estimating, using a model, an output of each of a plurality of states of the model based on an input to each of the states of the model and determining a desired input to each of the plurality of states, beginning at the toolface, based on a desired output of at least one of the plurality of states connected to a particular state, transmitting the signal to the input component of the drilling tool such that the signal adjusts the current toolface based on the correction, and drilling a wellbore with a drill bit oriented at the desired toolface.

Feedback based toolface control system for a rotary steerable drilling tool

Methods control systems for viscosity and density control may include a frequency loop shaping filter for shaping the frequency response in real-time for a multiple inputs multiple outputs (MIMO) system. For example, a method may include drilling a wellbore while circulating a drilling mud through a viscosity and density control system that includes one of: a mechanical separation system, a dilution system, a chemical additive regulation system, and any combination thereof; applying a frequency loop shaping filter to a desired mud viscosity and a desired mud density to produce control signals: a first control signal for the mechanical separation system, a second control signal for the dilution system, a third control signal for the chemical additive regulation system, and any combination thereof; and applying the control signals to the corresponding systems to alter the drilling mud to have a controlled viscosity value and a controlled density value.

Real-time frequency loop shaping for drilling mud viscosity and density measurements

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.

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Houston, TX, United States of America

Xingyong Song