US-12624627-B2 - Systems and methods for identifying friction forces in a wellbore

Abstract

A friction manager may receive time data for hookload, weight-on-bit (WOB), and torque for a wellbore. A friction manager may use the time data for the hookload, the WOB, and the torque, to identify a section of steady-state motion in the wellbore. A friction manager may generate friction forces for the section of steady-state motion based on the time data for the hookload, the WOB, and the torque. A friction manager may adjust drilling activities based on the friction forces.

Inventors

• James Philip Belaskie
• Nathaniel Wicks
• Xianxiang Huang
• Brennan Daniel Goodkey

Assignees

• SCHLUMBERGER TECHNOLOGY CORPORATION

Dates

Publication Date

20260512

Application Date

20230901

Claims (20)

1. 1 . A method, comprising: receiving, for a period of time while performing a drilling activity with a drill rig state, time data for hookload, weight-on-bit (WOB), and torque for a wellbore, wherein the period of time is based on a duration of time that it takes to adjust a total drill pipe length of a drill string, the drill string having a specification weight; using the time data for the hookload, the WOB, and the torque for the wellbore, identifying a section of steady-state motion in the wellbore over the period of time, wherein, in the section of steady-state motion, the drill string in the wellbore has reduced axial friction; generating friction forces for the section of steady-state motion by applying a friction model to the time data for the hookload, the WOB, and the torque; using the friction forces, the total drill pipe length, and the time data for the hookload over the period of time, identifying an adjusted linear weight of the drill string; calibrating the friction model based on the adjusted linear weight of the drill string, resulting in a calibrated friction model; generating adjusted friction forces by applying the calibrated friction model to the time data for the hookload, the WOB, and the torque; and adjusting the drilling activity based on the adjusted friction forces.
2. 2 . The method of claim 1 , further comprising identifying abnormal friction forces based on the time data for the hookload, the WOB, and the torque.
3. 3 . The method of claim 2 , wherein identifying the abnormal friction forces includes identifying a sticking event.
4. 4 . The method of claim 1 , wherein generating the friction forces includes generating a rotational friction force.
5. 5 . The method of claim 1 , wherein generating the friction forces includes generating the friction forces parallel to a longitudinal axis of the wellbore.
6. 6 . The method of claim 1 , wherein generating the friction forces includes generating a side force in a dogleg of the wellbore.
7. 7 . The method of claim 1 , wherein generating the friction forces includes generating the friction forces in real-time.
8. 8 . The method of claim 1 , further comprising generating a hookload plot of friction factors associated with the friction forces plotted against depth, and wherein identifying the section of steady-state motion includes identifying the section of steady-state motion based on a slope of the friction forces on the hookload plot.
9. 9 . The method of claim 1 , wherein determining the steady-state forces includes determining the steady-state forces based on a shape of the wellbore.
10. 10 . A method, comprising: receiving drilling data for a period for a drill string in a wellbore, wherein receiving the drilling data includes receiving the drilling data while performing a drilling activity with a drill rig state, the drilling data including hookload data, weight-on-bit (WOB) data, and torque data, the drill string having a drill pipe length and a specification weight; applying a friction model to the drilling data, the friction model resulting in a friction force for the drill string; using the friction force, the drill pipe length, and the drilling data over the period, identifying an adjusted linear weight of the drill string; generating a determined hookload using the friction model; and while performing drilling activities in a period of reduced axial friction, calibrating the friction model based on a hookload difference between the hookload data and the determined hookload, resulting in a calibrated friction model, wherein calibrating the friction model includes making iterative changes to inputs to the friction model until the hookload difference is below a calibration threshold, the inputs including the adjusted linear weight of the drill string and torque and drag factors.
11. 11 . The method of claim 10 , wherein calibrating the friction model includes comparing a weight of the drill string plus a first friction force to a first hookload data to determine the hookload difference.
12. 12 . The method of claim 10 , wherein applying the friction model includes generating a steady-state friction force over a first period by applying a filter to a first drilling data.
13. 13 . The method of claim 10 , further comprising: receiving third drilling data for a third period, the third drilling data including third hookload data, third WOB data, and third torque data; applying the calibrated friction model to the third drilling data, resulting in a third friction force; and based on the third friction force, identifying a sticking event for the drill string in the wellbore.
14. 14 . A system, comprising: a processor and memory, the memory including instructions that cause the processor to: receive, for a period of time while performing a drilling activity with a drill rig state, time data for hookload, weight-on-bit (WOB), and torque for a wellbore, wherein the period of time is based on a duration of time that it takes to adjust a total drill pipe length of a drill string, the drill string having a specification weight; using the time data for the hookload, the WOB, and the torque for the wellbore, identify a section of steady-state motion in the wellbore over the period of time, wherein, in the section of steady-state motion, the drill string in the wellbore has reduced axial friction; generate friction forces for the section of steady-state motion by applying a friction model to the time data for the hookload, the WOB, and the torque; use the friction forces, the total drill pipe length, and the time data for the hookload over the period of time, identifying an adjusted linear weight of the drill string; calibrate the friction model based on the adjusted linear weight of the drill string, resulting in a calibrated friction model; generate adjusted friction forces by applying the calibrated friction model to the time data for the hookload, the WOB, and the torque; and adjust the drilling activity based on the adjusted friction forces.
15. 15 . The system of claim 14 , wherein the memory further causes the processor to identify abnormal friction forces based on the time data for the hookload, the WOB, and the torque.
16. 16 . The system of claim 15 , wherein identifying the abnormal friction forces includes identifying a sticking event.
17. 17 . The system of claim 14 , wherein generating the friction forces includes generating a rotational friction force.
18. 18 . The system of claim 14 , wherein generating the friction forces includes generating the friction forces parallel to a longitudinal axis of the wellbore.
19. 19 . The system of claim 14 , wherein generating the friction forces includes generating a side force in a dogleg of the wellbore.
20. 20 . The system of claim 14 , wherein generating the friction forces includes determining a difference between the hookload and an in-situ weight of the drill string, the in-situ weight of the drill string based at least in part by a buoyancy of a drilling fluid.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63/506,171, filed on Jun. 5, 2023, which is hereby incorporated by reference in its entirety. BACKGROUND OF THE DISCLOSURE Drilling is used to access subterranean formations for exploration, the extraction of natural resources (e.g., oil, natural gas, water), power generation, other uses, and combinations thereof. A downhole drilling system includes a bit that is connected to a drill string and/or other downhole tools. During drilling activities, the drill string experiences forces based on the weight of the drill string, the upward force applied to the drill string, the torque applied to the drill string, and so forth. In some situations, the drill string may experience a sticking event that may increase the forces used to move the drill string. SUMMARY In some embodiments, the techniques described herein relate to a method. A friction manager receives time data for hookload, weight-on-bit (WOB), and torque for a wellbore. The friction manager, using the time data for the hookload, the WOB, and the torque, identifies a section of steady-state motion in the wellbore. The friction manager generates friction forces for the section of steady-state motion based on the time data for the hookload, the WOB, and the torque. The friction forces adjust drilling activities based on the friction forces. In some aspects, the techniques described herein relate to a method. A friction manager receives first drilling data for a period for a drill string in a wellbore. The drilling data includes hookload data, weight-on-bit (WOB) data, and torque data. The friction manager applies a friction model to the first drilling data, the friction model resulting in a friction force for the drill string. The friction manager generates a determined hookload using the friction model and the friction force. The friction manager calibrates the friction model based on a comparison between the hookload data and the determined hookload, resulting in a calibrated friction model. This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments. BRIEF DESCRIPTION OF THE DRAWINGS In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which: FIG. 1 is a representation of a drilling system for drilling an earth formation to form a wellbore, according to at least one embodiment of the present disclosure; FIG. 2-1 through FIG. 2-3 are representations of friction management systems illustrating various friction forces, according to at least one embodiment of the present disclosure; FIG. 3 is a representation of a friction manager, according to at least one embodiment of the present disclosure; FIG. 4 is a representation of a hookload plot, according to at least one embodiment of the present disclosure. FIG. 5-1 and FIG. 5-2 are representations of hookload plots, according to at least one embodiment of the present disclosure; FIG. 6 is a representation of a method for calibrating a friction model, according to at least one embodiment of the present disclosure; FIG. 7 is a representation of a method for determining wellbore friction, according to at least one embodiment of the present disclosure; FIG. 8 is a representation of a method for determining wellbore friction, according to at least one embodiment of the present disclosure; and FIG. 9 is a representation of a computing system, according to at least one embodiment of the present disclosure. DETAILED DESCRIPTION This disclosure generally relates to devices, systems, and methods for determining a friction force of a drilling system. A friction management system receives drilling data, including hookload data, weight-on-bit (WOB) data, and torque data. The friction manager may apply a friction model to the drilling data. The friction model may determine a friction force us