Drilling parameter derivation workflow for autonomous directional drilling

1 . A method for performing autonomous directional drilling, the method comprising:

receiving input data, wherein the input data comprises:

a planned trajectory of a wellbore including a target;

a current position of a bottom of the wellbore;

a plurality of drilling parameters; and

a maximum dog leg severity (DLS) capability of a bottom hole assembly (BHA) drilling the wellbore;

determining an amount of DLS to reach the target from the current position of the bottom of the wellbore based upon the input data;

determining a modification to one or more of the drilling parameters based upon the amount of DLS to reach the target and the maximum DLS capability, wherein the modification is also based upon historical offset data from nearby wellbores having similar profiles, wherein the historical offset data comprises a comparison of maximum DLS capabilities of BHAs drilling the nearby wellbores with drilling parameters of the BHAs drilling the nearby wellbores, and wherein the maximum DLS capabilities of the BHAs drilling the nearby wellbores are defined by (1) a rate of penetration (ROP) of the BHAs drilling the nearby wellbores and (2) two numerical coefficients; and

performing directional drilling with the BHA while implementing the modification.

2 . The method of claim 1 , wherein the drilling parameters comprise a steering ratio of the BHA, a rate of penetration (ROP) of the BHA in the wellbore, an inclination of the wellbore, an azimuth of the wellbore, a tool face of the BHA, surface rotations per minute (SRPM), collar rotations per minute (CRPM), a flow rate through the BHA, surface weight-on-bit (WOB), a measured depth (MD) offset to run start, a true vertical depth (TVD) of the wellbore, a mud weight in the wellbore, or a combination thereof.

3 . The method of claim 2 , wherein the amount of DLS is determined using a single curvature to reach the target based upon the TVD of the wellbore, a North South (NS) of the wellbore, and an East West (EW) location of the wellbore.

4 . The method of claim 2 , wherein the amount of DLS is determined using a curvature to reach the target defined by the TVD, the inclination of the target, and the azimuth of the target.

5 . The method of claim 2 , wherein the amount of DLS is determined using a curvature to reach the target defined by a MD of the target, the inclination of the target, and the azimuth of the target.

6 . The method of claim 1 , wherein the amount of DLS is determined using a plurality of curvatures with varying DLS to reach the target.

7 . The method of claim 1 , wherein the amount of DLS is determined using a modified Lubinski curvature to reach the target.

8 . The method of claim 1 , further comprising determining a difference between the amount of DLS to reach the target and the maximum DLS capability, wherein the modification is also determined based upon the difference.

9 . The method of claim 1 , further comprising displaying an updated trajectory of the wellbore in response to the modification.

10 . The method of claim 1 , wherein the comparison is defined by Max DLS=a−b*ROP for a ROP range, where Max DLS represents the maximum DLS capabilities of BHAs drilling the similar nearby wellbores, and a and b represent numerical coefficients.

11 . A computing system, comprising:

one or more processors; and

a memory system comprising one or more non-transitory computer-readable media storing instructions that, when executed by at least one of the one or more processors, cause the computing system to perform operations, the operations comprising:

receiving input data, wherein the input data comprises:

a planned trajectory of a wellbore including a target;

a current position of a bottom of the wellbore;

a plurality of drilling parameters; and

a maximum dog leg severity (DLS) capability of a bottom hole assembly (BHA) drilling the wellbore;

determining an amount of DLS to reach the target from the current position of the bottom of the wellbore based upon the input data;

determining a modification to one or more of the drilling parameters based upon the amount of DLS to reach the target and the maximum DLS capability, wherein the modification is also based upon historical offset data from nearby wellbores having similar profiles, wherein the historical offset data comprises a comparison of maximum DLS capabilities of BHAs drilling the nearby wellbores with drilling parameters of the BHAs drilling the nearby wellbores, and wherein the maximum DLS capabilities of the BHAs drilling the nearby wellbores are defined by a flow rate into the nearby wellbores, the flow rate squared, and three numerical coefficients; and

causing the modification to be implemented while directional drilling is being performed with the BHA.

12 . The computing system of claim 11 , wherein the comparison is defined by Max DLS=x+y*Q+z*Q 2 , where Max DLS represents the maximum DLS capabilities of BHAs drilling the similar nearby wellbores, x, y, and z represent numerical coefficients, and Q represents flow rate.

13 . A non-transitory computer-readable medium storing instructions that, when executed by one or more processors of a computing system, cause the computing system to perform operations, the operations comprising:

receiving input data, wherein the input data comprises:

a planned trajectory of a wellbore including a target;

a current position of a bottom of the wellbore;

a plurality of drilling parameters; and

a maximum dog leg severity (DLS) capability of a bottom hole assembly (BHA) drilling the wellbore;

determining an amount of DLS to reach the target from the current position of the bottom of the wellbore based upon the input data;

determining a modification to one or more of the drilling parameters based upon the amount of DLS to reach the target and the maximum DLS capability, wherein the modification is also based upon historical offset data from nearby wellbores having similar profiles, wherein the historical offset data comprises a comparison of maximum DLS capabilities of BHAs drilling the nearby wellbores with drilling parameters of the BHAs drilling the nearby wellbores, and wherein the maximum DLS capabilities of the BHAs drilling the nearby wellbores are defined by a number of rotations per minute (RPM) of the BHAs drilling the nearby wellbores and three numerical coefficients, and

causing the modification to be implemented while directional drilling is being performed with the BHA.

14 . The non-transitory computer-readable medium of claim 13 , wherein the comparison is defined by Max DLS=x′+y′*RPM+z′*RPM 2 , where Max DLS represents the maximum DLS capabilities of BHAs drilling the similar nearby wellbores, and x, y, and z represent numerical coefficients.

15 . The non-transitory computer-readable medium of claim 13 , wherein the modification is determined by a machine learning (ML) model, an artificial intelligence (AI) model, or a generative AI (GenAI) model based upon a dependency between the maximum DLS capability and the drilling parameters.

16 . The non-transitory computer-readable medium of claim 13 , wherein the modification comprises a percentage of change to make to the one or more drilling parameters based on a difference between the amount of DLS to reach the target and the maximum DLS capability.

17 . The non-transitory computer-readable medium of claim 13 , wherein the operations further comprise generating or transmitting a signal that recommends, instructs, or causes the one or more drilling parameters to be physically modified.

18 . The non-transitory computer-readable medium of claim 13 , wherein the modification comprises a percentage of change to make to two or more of the drilling parameters simultaneously based upon a difference between the amount of DLS to reach the target and the maximum DLS capability.