WELLBORE HOLE PROFILE DETERMINATION

Description

FIELD

The disclosure generally relates to drilling of wellbores and more particularly, to determining the wellbore diameter while drilling the wellbore.

BACKGROUND

The hole diameter of a wellbore may be a critical aspect in hydrocarbon recovery operations. The size of the hole may vary depending on several factors including drill bit size and other equipment on the drill string, type of formation the wellbore is formed in, future completion and production operations, etc. The hole profile may be planned to optimize drilling operations (e.g., mud weights, cementing operations, etc.) and knowledge of the current hole profile while drilling may assist in adjusting current drilling operations to account for differing wellbore conditions. Factors such as wellbore inclination, azimuth, formation type encountered, etc. may influence the hole profile, thus altering wellbore conditions.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of the disclosure may be better understood by referencing the accompanying drawings.

FIG. 1 is a schematic depicting an example well system, according to some implementations.

FIGS. 2A-2D are illustrations depicting example hole profiles, according to some implementation.

FIGS. 3A-3B are schematics depicting example wellbores, according to some implementations.

FIGS. 4-5 are flowcharts depicting example operations to generate a hole profile at measured depth layers of a wellbore being drilled in a subsurface formation, according to some implementations.

FIGS. 6A-6B are charts depicting example hole profiles of wellbores drilled in subsurface formations with different lithologies, according to some implementations.

FIG. 7 is a schematic depicting a depth interval, according to some implementations.

FIG. 8 is a schematic of an axial layer, according to some implementations.

FIG. 9 is a chart depicting a hole profile log, according to some implementations.

FIG. 10 is a block diagram depicting an example computer, according to some implementations.

DESCRIPTION

The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to inclination and azimuth as wellbore properties. Aspects of this disclosure can also be applied to any other types of wellbore properties. In other instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description.

Example implementations relate to determining the hole profile of a wellbore while drilling the wellbore in a subsurface formation. The diameter of the wellbore may play a crucial role in hydrocarbon recovery operations, with implications in well design, production operations, etc. For example, the hole diameter may be crucial in determining calculations while drilling the wellbore such as drill string buckling (stable regions versus unstable regions), torque and drag calculations (such as limits, overpull, etc.), hydraulic calculations (pressure losses, flow regime, etc.), hole cleaning (packoff of the drill string, preparation for cementing operations), stuck pipe (due to mud cake), etc. While drilling a wellbore in a subsurface formation, it may be assumed that the diameter of the wellbore may be approximately uniform and approximately similar to the diameter of the drill bit (or other drilling component on the drill string, such as a reamer). However, the diameter of the wellbore may fluctuate from the assumed diameter depending on a number of factors such as wellbore inclination and/or azimuth, subsurface formation properties (i.e., lithology, principal stresses, etc.), etc. The fluctuation in wellbore diameter may result in a varying hole profile throughout the depth of the wellbore. For example, if there are no issues the hole profile may be a gauge hole (e.g., the hole diameter is approximately uniform and approximately similar to the drill bit diameter or within a tolerance of the expected hole diameter). Alternatively, a breakout, washout, key seat, or any other hole profile variation may occur, resulting in a hole profile that differs from a gauge hole profile.

When the hole profile differs from the assumed hole profile, drilling failures such as buckling of the drill string, pressure losses, packoff of the drill string, stuck pipe, etc. may occur. Conventional operations may assume the hole profile based on the drill bit size (as mentioned above) and in some instances may include a safety factor (such as 5% above drill bit diameter). However, this assumption may not capture the hole profile along the depth of the wellbore, resulting in misleading drilling calculations while drilling (as mentioned above) and thus potential drilling failures. In some implementations, the hole profile may be generated via logging while drilling (LWD) tools implemented on the drill string, such as a caliper log. However, in some instances the caliper log may not be available, or the data from a caliper log may not be able to be communicated to the surface while drilling the wellbore, but instead may only be available with the LWD tools are returned to surface when the drill string is tripped out of the wellbore. The addition of an LWD caliper log in a drill sting assembly may also increase drilling costs.

In some implementations, a hole profile generator may be configured to determine and/or update the hole profile of a wellbore, layer-by-layer, without a caliper log, while drilling a wellbore. The hole profile generator may be a “virtual three dimensional (3D) caliper log” in the absence of electronic LWD caliper logs on the drill string assembly. Prior to and/or during drilling operations, the properties of the subsurface formation including principal stresses, lithology of the subsurface formation layers (such as composition, grain size, etc.), etc. may be obtained. Additionally, the wellbore properties of a wellbore such as inclination, azimuth, etc. may be obtained while drilling the wellbore. For example, a drill string assembly may be configured to drill a wellbore in a subsurface formation. The drill string assembly may include a mud motor, MWD tools, LWD tools, etc. that may be utilized to assist in drilling the wellbore such as steer the drill bit, determine the drill bit location in the subsurface formation, etc. In some implementations, the drill string assembly may include one or more sensors. The one or more sensors may be configured to obtain and communicate the wellbore properties while drilling the wellbore with a drill bit in a subsurface formation. In some implementations, the hole profile generator may select a failure criteria for a depth interval of the wellbore. The failure criteria may be selected based on the subsurface formation properties corresponding to the depth interval. For example, failure criterion such as Mogi-Coulomb, Mohr-Coulomb, or other failure criteria may be selected based on the lithology of the subsurface formation for the corresponding depth interval. The mineral content, chemical composition, grain size, and other lithological properties may affect how the rock structure withstands stresses when the stresses are altered (such as when rock is removed to form a wellbore). Accordingly, the proper failure criteria may be selected to account for the lithology of the subsurface formation when determining the hole profile of the wellbore. In some implementations, the depth interval may include n number of axial layers. The hole profile generator may iteratively determine the layer failure volume of each radial layer within an axial layer (based on the wellbore properties and the failure criteria) until the breakout angle of the interval layer is approximately zero. The hole profile generator may then determine the layer failure volume of the axial layer based on the layer failure volumes of each radial layer before proceeding to the subsequent axial layer of the depth interval to determine the respective layer failure volume. Moreover, the radial distance of the wellbore at the depth interval may be determined based on the layer failure volumes of the n number of axial layers within the depth interval.

In some implementations, the hole profile generator may verify the radial distance of the depth interval. For example, the hole profile generator may determine hydraulic calculations (such as standpipe pressure (SPP), equivalent circulating density (ECD), etc.) and use the hydraulic calculations to verify the radial distance for the current depth interval. Once verified, the hole profile generator may generate a hole profile of the wellbore for the corresponding depth interval. In some implementations, the hole profile of the depth interval may be added to a hole profile log to update the hole profile log. The hole profile generator may continuously determine and update the hole profile log for subsequent depth intervals as the wellbore is drilled.

In some implementations, the hole profile across depths of the wellbore may be utilized to fingerprint the hole profile type at certain depths. For example, the hole profile may indicate the wellbore at a measured depth and/or over a measured depth interval is an in gauge hole (no issues), or may have experienced a breakout, washout, key seat, etc.

In some implementations, the hole profile generator may utilize caliper measurements (such as when an electronic LWD caliper log is a part of the drill string assembly). The caliper measurements may be utilized to adjust the radial distance, verify the radial distance, update the hole profile generator, etc. For example, the caliper measurements may be utilized to train and/or update the hole profile generator if the hole profile generator is configured with a learning machine, such as a neural network.

In some implementations, a drilling operation may be performed based on the hole profile. The drilling operations may prevent and/or address drilling failures such as lost circulation, stuck pipe, buckling of the drill pipe, etc. Examples of drilling operations include adjusting the mud weight, adjusting one or more drilling parameters (such as weight-on-bit (WOB), torque-on-bit (TOB), etc.), adjusting cementing operations, performing procedures to release stuck drill pipe, etc. For instance, the hole profile may indicate a washout across a depth interval. Accordingly, the mud weight (i.e., drilling fluid) and/or the pump speed may be adjusted to maintain returns to efficiently remove drill cuttings from the wellbore, manage ECD to prevent lost circulation and/or a kick, prevent packoff of the drilling string, etc.

Example Well System

FIG. 1 is a schematic depicting an example well system, according to some implementations. In particular, FIG. 1 is a schematic diagram of a well system 100 that includes a drill string 106 having a drill bit 112 disposed in a wellbore 180 for drilling the wellbore 180 in the subsurface formation 108. While depicted for a land-based well system, example embodiments can be used in subsea operations that employ floating or sea-based platforms and rigs. The drill bit 112 forming the wellbore 180 is an example for which wellbore properties may be obtained from and utilized by a hole profile generator to determine the hole profile at measured depths of the wellbore 180 as described herein can be performed.

The well system 100 may further include a drilling platform 110 that supports a derrick 152 having a traveling block 114 for raising and lowering the drill string 106. The drill string 106 may include, but is not limited to, drill pipe, drill collars, and downhole tools 116 (such as a drill string assembly). The downhole tools 116 may comprise any of a number of different types of tools including measurement while drilling (MWD) tools, logging while drilling (LWD) tools, mud motors, and others. A kelly 115 may support the drill string 106 as it may be lowered through a rotary table 118. While FIG. 1 is described relative to a drill bit 112, aspects of the disclosure may be applied to any downhole cutting structure or multiple downhole cutting structures. For instance, the drill bit 112 may include roller cone bits, polycrystalline diamond compact (PDC) bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As the drill bit 112 rotates, it may crush or cut rock to create and extend a wellbore 180 that penetrates various subterranean formations. The drill bit 112 may be rotated by various methods including rotation by a downhole mud motor and/or via rotation of the drill string 106 from the surface 120 by the rotary table 118. A pump 122 may circulate drilling fluid through a feed pipe 124 to the kelly 116, downhole through interior of the drill string 106, through orifices in the drill bit 112, back to the surface 120 via an annulus surrounding the drill string 106, and into a retention pit 128. Parameters of drilling the wellbore 180 may be adjusted to increase, decrease, and/or maintain the rate of penetration (ROP) of the drill bit 112 through the subsurface formation 108. Drilling parameters may include parameters measured at the surface 120 including weight-on-bit (WOB), torque-on-bit (TOB), rotations-per-minute (RPM) of the drill string 106, etc. In some implementations, the downhole tools 116 may include sensors to obtain drilling parameters and/or wellbore properties as the drill bit 112 drills the subsurface formation 108. The drilling parameters obtained from the sensors may include downhole WOB, downhole TOB, downhole RPM, drill bit vibration, etc. The wellbore properties may include inclination, azimuth, etc. In some implementations, the sensors may obtain subsurface formation properties such as lithology, permeability, etc.

The well system 100 includes a computer 170 that may be communicatively coupled to other parts of the well system 100. The computer 170 can be local or remote to the drilling platform 110. A processor of the computer 170 may perform simulations (as further described below). In some implementations, the processor of the computer 170 may control drilling operations of the well system 100 or subsequent drilling operations of other wellbores. For instance, the processor of the computer 170 may include a hole profile generator that may be configured to generate and/or update a hole profile of a wellbore, without the use of a caliper log, while the drill bit 112 drills the wellbore 180 in the subsurface formation 108. The a hole profile generator may utilize one or more wellbore properties (such as inclination, azimuth, etc.) obtained from one or more sensors on the downhole tools 116, such as LWD tools. In some implementations, the hole profile generator may be utilized for automation in the drilling process. For example, a drilling rig may be configured with automation to drill a wellbore. The hole profile generator may be utilized by the automated drilling rig to drill the wellbore, update and/or modify drilling operations, etc. An example of the computer 170 is depicted in FIG. 10, which is further described below.

Example Hole Profiles

FIGS. 2A-2D are illustrations depicting example hole profiles, according to some implementation. The hole profiles described in FIGS. 2A-2D are example hole profiles, and the operations described herein may be applicable to any other suitable hole profile. FIG. 2A includes a cross-sectional view of an in-gauge hole profile 200 of a wellbore 202. When a wellbore 202 is in-gauge, the radii of the wellbore 202 may be approximately equidistant about the central axis 250. For example, the diameter 204 may be approximately similar to the diameter 206. The diameters 204, 206 may be approximately similar to the diameter of the drill bit, underreamer, etc. utilized to drill the wellbore 202.

FIG. 2B includes a cross-sectional view of a breakout hole profile 201 of a wellbore 202. A breakout may be an elongation and/or enlargement of a portion of the wellbore 202 cross section. A breakout, such as breakouts 220, 222 may occur when the stress concentration of the subsurface formation surrounding the wellbore exceeds the strength of the rock. The breakouts 220, 222 may occur in the direction of the minimum horizontal stress (σ_h) of the subsurface formation, perpendicular to the to the direction of the maximum horizontal stress (σ_H). For example, the wellbore 202 may have an intended profile 208 (e.g., the drill bit diameter). However, a breakout 220, 222 may occur in the direction of the diameter 204 (i.e., the direction of the minimum horizontal stress). Thus, the diameter 204 may be greater than the diameter 206 and the profile of the wellbore 202 differs from the intended profile 208. This may result in drilling failures such as an increase in drill cuttings that may pack off the drill string, loss of pressure of the drilling fluid due to an increase in wellbore cross-sectional area (which may result in failure to clean the wellbore of drill cutting, thus packing off the drill string), increase in torque and drag on the drill string, etc.

FIG. 2C includes a cross-sectional view of a washout hole profile 203. A washout of a wellbore 202 may be when the diameter of the wellbore 202 may become larger than the intended profile 208. For example, both the diameter 204 and diameter 206 (i.e., the diameter in both the minimum and maximum horizontal stress direction) may become larger than the diameter of the intended profile 208 (e.g., the drill bit diameter). A washout may occur in various scenarios such as inadequate drilling fluid properties, high formation pressure, formation instability, mechanical factors (such as excessive RPM, WOB, etc.), chemical reactions (between drilling fluid and the subsurface formation), etc. The washout may result in an increased cross-sectional area of the wellbore, resulting in drilling failures such as pressure losses, packing off of the drill string, etc. For example, when drilling a horizontal well, drill cutting may accumulate on the low side of the wellbore (in the direction of gravity). One of the functions of drilling fluid is to transport the drill cuttings to the surface to maintain a clean wellbore and prevent the drill cuttings from packing in the drill string. When a washout occurs, there may be an excess of drill cuttings and the flow rate of the drilling fluid may decrease (due to the increased cross-sectional area of the wellbore). Thus, drill cuttings may accumulate in the wellbore, increasing the risk of packing in the drill string.

FIG. 2D includes a cross-sectional view of a key seat profile 205. A key seat profile 205 of a wellbore 202 may occur when a drill string rubs against one side of the wellbore 202, resulting in a channel forming in the wellbore wall. A key seat 230 may occur when a wellbore is inclined and/or deviated (i.e., the inclination of a wellbore may be greater than 0 degrees). Thus, the drill string may be in contact with a side of the wellbore 202 when the drill string rotates and moves through the wellbore. This contact may result in the formation of a key seat 230. For example, a portion of the wellbore 202 may include a key seat such that the diameter 204 may be greater than the diameter 206, resulting in the portions of the wellbore 202 having a diameter greater than the diameter of the intended profile 208.

To help illustrate, FIGS. 3A-3B are schematics depicting example wellbores, according to some implementations. FIG. 3A includes a partial cross-sectional side view 300 of a wellbore 302. A drill string 304 is positioned in the wellbore 302 and may be drilling the wellbore 302 through a subsurface formation. The wellbore 302 may have an inclination 306, a, measured in degrees deviated from vertical. When drilling, forces 310 may be applied along the central axis of the wellbore (z-axis 316) to the drill string 304 to drill the wellbore 302 such as forces applied by the traveling block, the weight of the drill string, etc. Forces 308 may also be applied along the z-axis 316 in the opposite direction, such as friction force. The inclination 306 of the wellbore and the forces 308 may result in the drill string to contact the wall of the wellbore 302, resulting in the formation of a key seat profile. A partial cross-sectional view 301 includes a hole profile view of the wellbore 302 with a drill string 304 contacting the wall of the wellbore 302 relative to the x-axis 312 and y-axis 314 of the wellbore. The position of the contact on the wellbore 302 wall may be defined as the angle 318 from the x-axis 312 of the wellbore 302. A normal force 320 may be applied to the drill string 304 when the drill string 304 contacts the wellbore 302 wall, resulting in potential buckling of the drill string 304.

FIG. 3B includes a partial cross-sectional side view 303 of an inclined section of a wellbore 340. The depths of the wellbore 340 location in the subsurface formation may be defined by the x-axis 330, y-axis, 332, and z-axis 334. The angle 338 may define the drilling direction relative to the maximum horizontal stress. The angle 336 may define the angle, measured clockwise, from the x-axis 330. Axis 344, 346, and 348 may define the axes of the wellbore 340, similar to the x-axis 312, y-axis 314, and z-axis 316 of FIG. 3A. When the wellbore 340 is curved, the drill string 342, may contact the wall of the wellbore 340, resulting in a key seat hole profile and potential buckling of the drill string 342 or increased friction force on the drill string 342.

Example Operations

Example operations for generating and/or updating a hole profile are now described. This section describes operations associated with some implementations of the invention. In the discussion below, the flow diagrams may be described with reference to the example system presented above. In certain implementations, the operations are performed by executing instructions residing on machine-readable media (e.g., software), while in other implementations, the operations are performed by hardware and/or other logic (e.g., firmware). In some implementations, the operations are performed in series, while in other implementations, one or more of the operations can be performed in parallel. Moreover, some implementations perform less than all the operations shown in the flow diagrams.

The operations described in FIGS. 4-5 utilize the term “breakout” when describing when rock is removed from a wellbore wall, resulting in the radius of the wellbore in at least a portion of the wellbore being greater than the intended radius. The term “breakout” may also refer to the hole profile type, as described in FIG. 2B.

FIGS. 4-5 are flowcharts depicting example operations to generate a hole profile at measured depth layers of a wellbore being drilled in a subsurface formation, according to some implementations. Flowcharts 400-500 of FIGS. 4-5, respectively, are described in reference to the hole profile generator on the processor of the computer 170 of FIG. 1. Additionally, the flowcharts 400-500 are described in reference to FIGS. 2A-2D and FIGS. 3A-3B. However, other systems and components can be used to perform the operations now described. The operations described in the flowchart 400-500 may be performed while drilling the wellbore and/or after the wellbore has been drilled. For example, the hole profile log may be updated in real time during the drilling of the wellbore. Operations of the flowcharts 400-500 continue between each other through transition points A and B. Operations of the flowchart 400 start at block 402.

At block 402, the processor of the computer 170 may determine a depth interval for a wellbore being drilled in a subsurface formation. The depth interval may be 50 feet measured depth (MD), 200 feet MD, 1000 feet MD, etc. of the wellbore that has been drilled. In some implementations, the length of the depth interval may depend on the wellbore environment. For example, if the surrounding rock is stable (i.e., no breakouts may be occurring), then the length interval may be longer relative to a region where breakouts may be occurring and/or are known to occur and thus, finer depth intervals may be desired for increased accuracy of identifying hole profile types, as described below.

At block 404, the processor of the computer 170 may obtain wellbore properties and subsurface formation properties for the depth interval. The wellbore properties may include the inclination, azimuth, etc. of the wellbore for the corresponding depth interval. The wellbore properties may be obtained from one or more sensors positioned on the drill string assembly proximate the drill bit, such as the LWD tool.

The subsurface formation properties may include lithology of the subsurface formation, in-situ stresses of the subsurface formation, etc. Lithology (and any other suitable rock properties) may be obtained from sources such as well logs of the subsurface formation (from the current wellbore, offset wellbore, etc.). For example, one or more logging tools may be positioned in an offset wellbore to obtain subsurface formation properties. Alternatively, or in addition to, one or more sensors may be positioned on the drill string assembly and configured to obtain subsurface formation properties while drilling the wellbore. The in-situ stresses (the stresses present in the subsurface formation prior to drilling) may include the maximum horizontal principal stress, the minimum horizontal principal stress, the vertical principal stress, etc. In some implementations, the principal stresses may be obtained prior to drilling the wellbore.

Operations of the flowchart 400 now proceed to blocks 406 and 408. The operations of blocks 406 and 408 may be performed in series or in parallel.

At block 406, the processor of the computer 170 may transform the stresses based on the wellbore properties and the subsurface formation properties. When a wellbore is drilled, the in-situ stresses may be altered due to the removal of material, resulting in a redistribution of stresses around the wellbore. Transformation of the stresses may indicate the updated status of the stresses surrounding the wellbore at the corresponding depth interval, given the current orientation of the wellbore (e.g., inclination, azimuth, etc.). For example, the stresses for a depth interval may be transformed as follows (using Equations 1-6 below):

σ x = ( σ H ⁢ cos 2 ⁢ α + σ h ⁢ cos 2 ⁢ α ) ⁢ cos 2 ⁢ i + σ v ⁢ sin 2 ⁢ i ( 1 ) σ y = σ H ⁢ sin 2 ⁢ α + σ h ⁢ cos 2 ⁢ α ( 2 ) σ z = ( σ H ⁢ cos 2 ⁢ α + σ h ⁢ sin 2 ⁢ α ) ⁢ sin 2 ⁢ i + σ v ⁢ cos 2 ⁢ i ( 3 ) σ xy = 1 2 ⁢ ( σ h - σ H ) ⁢ sin ⁢ 2 ⁢ α · cos ⁢ i ( 4 ) σ yz = 1 2 ⁢ ( σ h - σ H ) ⁢ sin ⁢ 2 ⁢ α · sin ⁢ i ( 5 ) σ xz = 1 2 ⁢ ( σ H ⁢ cos 2 ⁢ α + σ h * sin 2 ⁢ α - σ v ) ⁢ sin ⁢ 2 ⁢ i ( 6 )

where σ_H is the maximum horizontal principal stress, σ_h is the minimum horizontal principal stress, σ_ν is the vertical principal stress, σ_x is the normal stress along the x-axis, σ_y is the normal stress along the y-axis, σ_z is the normal stress along the z-axis, σ_xy is the shear stress on the x-plane along the y-direction, σ_yz is the shear stress on the y-plane along the z-direction, σ_xz is the shear stress on the x-plane along the z-direction, α is the drilling direction with respect to σ_H, and i is the well inclination angle.

In some implementations, the stresses in the subsurface formation extending past the wellbore wall may be determined. For example, stresses 2, 3, etc. times the radii away from the center point of the wellbore may be transformed. The in-situ stresses at various radial distances away from the center point of the wellbore for the depth interval may be transformed as follows (using Equations 7-12 as follows):

σ r = σ x + σ y 2 ⁢ ( 1 - R 2 r 2 ) + σ x - σ y 2 ⁢ ( 1 - 4 ⁢ R 2 r 2 + 3 ⁢ R 4 r 4 ) ⁢ cos ⁢ 2 ⁢ θ + σ xy ( 1 - 4 ⁢ R 2 r 2 + 3 ⁢ R 4 r 4 ) ⁢ sin ⁢ 2 ⁢ θ + P w ⁢ R 2 r 2 ( 7 ) σ θ = σ x + σ y 2 ⁢ ( 1 + R 2 r 2 ) - σ x - σ y 2 ⁢ ( 1 + 3 ⁢ R 4 r 4 ) ⁢ cos ⁢ 2 ⁢ θ - σ xy ( 1 + 3 ⁢ R 4 r 4 ) ⁢ sin ⁢ 2 ⁢ θ - P w ⁢ R 2 r 2 ( 8 ) σ z = σ z 0 - 2 ⁢ v ⁡ ( σ x - σ y ) ⁢ R 2 r 2 ⁢ cos ⁢ 2 ⁢ θ - 4 ⁢ v ⁢ σ xy ⁢ R 2 r 2 ⁢ sin ⁢ 2 ⁢ θ ( 9 ) τ r ⁢ θ = ( σ x - σ y 2 ⁢ sin ⁢ 2 ⁢ θ + σ xy ⁢ cos ⁢ 2 ⁢ θ ) ⁢ ( 1 + 2 ⁢ R 2 r 2 - 3 ⁢ R 4 r 4 ) ( 10 ) τ rz = ( σ yz ⁢ sin ⁢ θ + σ xz ⁢ cos ⁢ θ ) ⁢ ( 1 - R 2 r 2 ) ( 11 ) τ θ ⁢ z = ( - σ xz ⁢ sin ⁢ θ + σ yz ⁢ cos ⁢ θ ) ⁢ ( 1 + R 2 r 2 ) ( 12 )

where σ_r is the radial stress in the near field, σ_θ is the tangential stress in the near field, σ_z is the axial stress in the near field along the well axis, τ_rθ is the shear stress on the r-plane along the θ-direction, τ_rz is the shear stress on the r-plane along the z-direction, τ_θz is the shear stress on the θ-plane along the z-direction, σ_x is the normal stress along the x-axis, θ_y is the normal stress along the y-axis, σ_z⁰ is the normal stress along the z-axis, σ_xy is the shear stress on the x-plane along the y-direction, σ_yz is the shear stress on the y-plane along the z-direction, σ_xz is the shear stress on the x-plane along the z-direction, R is the radius of the borehole, r is the radial distance in the near field from the well center, θ is the angle measured clockwise from the x-axis, P_w is the pressure in the borehole, and ν is Poisson's ratio. To calculate the in-situ stresses from the borehole wall (1 radius from the center of the wellbore) to the specified radial distance into the subterranean formation (n times the radius of the wellbore, such as 3, 4, or 5), the iteration can change the radial distance analyzed into the subterranean formation by the distance increment, for example, 0.2 of the radius each iteration.

The transformation of stresses at the depth interval may be performed at each theta (θ) angle of the wellbore and/or up to a specified maximum radial distance from the center point of the wellbore. In some implementations, the stress transformation may be performed for theta angles 0 degrees to 180 degrees (i.e., half of the wellbore) and direct symmetry may be applied to the opposite side of the wellbore to transform the stresses for the remaining half of the wellbore.

At block 408, the processor of the computer 170 may select a failure criteria based on the subsurface formation properties. In some implementations, failure criteria may be lithology specific. For example, lithological properties such as mineral content, grain size, chemical composition, etc. may influence how stress affects said rock when the stresses in the subsurface formation may be altered (such as when a wellbore is formed in the subsurface formation. Accordingly, failure criteria may be tailored for specific lithologies. Thus, the failure criteria may be selected based on the lithology of the subsurface formation for the corresponding depth interval. For example, a Mogi-Coulomb failure criteria may be selected for a carbonate lithology or a Mohr-Coulomb failure criteria may be selected for a sandstone and/or shale lithology. Other criteria such as Lade criteria, Drucker-Prager criteria, etc. may be selected. The utilization of the selected failure criteria for the depth interval is described below.

To help illustrate, FIGS. 6A-6B are charts depicting example hole profiles of wellbores drilled in subsurface formations with different lithologies, according to some implementations. FIG. 6A includes a chart 600 of a hole profile of a wellbore drilled in a shale formation. In the example implementation the shale formation may have a uniaxial compressive strength (UCS) of 35 megapascals (MPa) and the wellbore is drilled at a 30 degree inclination. The chart 600 includes an x-axis 602 and a y-axis 604. The x-axis is the caliper of the wellbore having units in inches (in). The y-axis 604 is the depth of the wellbore having unites in feet (ft). At a depth 606, and depth 610, there is approximately no breakout, depicted by the respective hole profiles 608, 612. At the depths 614, 618, the respective hole profiles 616, 620 indicate breakouts. Thus, the caving volume for the depths between approximately 1400 ft and 5400 ft for the wellbore depicted in the chart 600 total to be approximately 2569.66 cubic inches (in3).

FIG. 6B includes a chart 601 of a hole profile of a wellbore drilled in a carbonate formation. In the example implementation the shale formation may have an unconfined compressive strength (UCS) of 35 megapascals (MPa) and the wellbore is drilled at a 30 degree inclination (similar to the wellbore of FIG. 6A, for comparative purposes). The chart 601 includes an x-axis 602 and a y-axis 604. The x-axis is the caliper of the wellbore having units in inches (in). The y-axis 604 is the depth of the wellbore having unites in feet (ft). At a depth 622, and depth 626, there is approximately no breakout, depicted by the respective hole profiles 624, 628. At the depths 630, 634, the respective hole profiles 632, 636 indicate breakouts. Thus, the caving volume for the depths between approximately 1400 ft and 5400 ft for the wellbore depicted in the chart 601 total to be approximately 130.46 in3.

As shown, the wellbore drilled in the carbonate formation yields less caving volume than the wellbore drilled in the shale formation in similar drilling conditions. Thus, selection of the failure criteria based on the lithology of the formation may impact the determination of the radial distance of the depth intervals, as described below.

At block 410, the processor of the computer 170 may determine the layer failure volume for a radial layer of an axial layer in the depth interval. A depth interval may be divided into one or more axial layers, where each axial layer may have one or more radial layers at and/or extending beyond the wellbore wall.

To help illustrate, FIG. 7 is a schematic depicting a depth interval, according to some implementations. In particular, FIG. 7 includes a depth interval 700 with a wellbore 710. The depth interval 700 includes two axial layers along the axis 737 of the wellbore 710; the axial layer 740 and the axial layer 745. Each axial layer 740, 745 in the depth interval may have a length of 1 inch, 1 foot, 10 feet, etc. Moreover, each axial layer 740, 745 may have uniform length or different lengths. Each axial layer 740, 745 may include one or more radial layers that extend into the subsurface formation along the axis 735 of the wellbore 710, such as radial layer 755 and radial layer 757 that are at the wellbore wall 750 or extend beyond the wellbore wall 750, respectively. Each radial layer may be n radii away from the center point of the wellbore 710. For example, radial layers 755, 757 may be 0.1 times the radius into the subsurface formation. In some implementations, the depth interval 700 may be configured with a maximum radial distance 758 in which the layer failure volume may be calculated for (as described below).

Returning to the flowchart of FIG. 4, the layer failure volume may first be determined for the radial layer nearest the wellbore wall, such as the radial layer 755 of FIG. 7. The failure criteria (selected in block 408) may first be applied to each theta (θ) angle of the wellbore (i.e., every degree, 10 degrees, 45 degrees, etc.) to determine if breakout has occurred and, if so, at what orientation in the wellbore. The failure criteria may be applied with respect to the transformed stresses at each theta (θ) angle of the wellbore determined in block 406. For example, if the depth interval was a carbonate formation and the Mogi-Coulomb failure criterion were selected, the stability analysis for each theta (θ) angle may be determined as follows (using Equations 13-18 below):

τ oct = a + b * σ m ⁢ 2 ( 13 ) τ oct = 1 3 ⁢ ( σ 1 - σ 2 ) 2 + ( σ 2 - σ 3 ) 2 + ( σ 1 - σ 3 ) 2 ( 14 ) σ m ⁢ 2 = ( σ 1 + σ 3 ) 2 ( 15 ) a = 2 ⁢ 2 * UCS 3 * ( q + 1 ) ⁢ and ⁢ b = 2 ⁢ 2 * ( q - 1 ) 3 * ( q + 1 ) ( 16 ) q = 1 + sin ⁡ ( friction ⁢ angle ) 1 - sin ⁡ ( friction ⁢ angle ) ( 17 ) Failure ⁢ eqn ⁢ ( F ) = a + b ⁢ σ m ⁢ 2 - τ oct ( 18 )

where τ_oct is the octahedral shear stress, σ_m2 is the effective mean stress,

σ₁ is the maximum principal stress at theta (θ), σ₂ is the intermedia principal stress theta (θ), σ₃ is the minimum principal stress theta (θ), q is the slope of the line relating to σ₁ and σ₃, a is the Mogi parameter, and b is the Mogi parameter.

Alternatively, if the depth interval was a sandstone or shale formation and the Mohr-Coulomb failure criterion were selected, the stability analysis for each theta (θ) angle may be determined as follows (using Equations 13-17 above and 19-20 below):

σ 1 = q * σ 3 + UCS ( 19 ) Failure ⁢ eqn ⁢ ( F ) = q * σ 3 + UCS - σ 1 ( 20 )

where UCS is the Uniaxial compressive strength of the subsurface formation. For both Equations 18 and 20, if F is less than or equal to 0, then shear failure may occur at the respective theta (θ), indicating breakout of the subsurface formation at the respective theta (θ). In some implementations, the failure criteria may be applied for each theta (θ) between 0 degrees and 180 degrees. Accordingly, direct symmetry may be applied to the opposite side of the wellbore to determine if failure criteria is present around wellbore at the axial layer.

With the orientation of the breakouts in the wellbore wall for the radial layer, the breakout angle of the breakout (if present) may be determined. This may be determined by taking the difference in theta (θ) between the edges of the breakout. For example, if it is determined that there is a breakout between 35 degrees and 75 degrees in the radial layer, then the breakout angle may be 40 degrees. Moreover, given the breakout angle, the width of the radial layer, and the length of the axial layer, the layer failure volume for said radial layer may be determined. For example, the axial layer length multiplied by the radial layer width multiplied by the width of the breakout (derived from the breakout angle) may provide the layer failure volume.

In some implementations, the Carr classification may be utilized to determine the orientation of the breakout to account for the azimuthal direction of the wellbore. For example, the angle of repose, represented by gamma, may be determined as follows ((using Equation 20 below):

Sin ⁡ ( 90 - α ) = γ - ( 90 - φ ) ( 20 )

where α is the inclination and φ is the azimuthal direction. An angle of repose less than 30 degrees indicates very free flowing, between 30 degrees and 38 degrees indicates free flowing, 38 degrees to 45 degrees indicates fair to passable flow, 45 degrees to 55 degrees indicates cohesive, and greater than 55 degrees indicates very cohesive (non-flowing). By determined the angle of repose, factors may be implemented into the failure criteria to determine and/or adjust the orientation of the breakout.

To help illustrate, FIG. 8 is a schematic of an axial layer, according to some implementations. In particular, FIG. 8 includes a partial cross section of an axial layer 800 that includes multiple radial layers. A failure criteria indicates breakout has occurred in radial layer n from approximately 35 degrees to 100 degrees. Accordingly, the breakout angle for layer n is θ_n 885. Moreover, given the breakout angle, the depth of the radial layer n, and the length of the axial layer, the layer failure volume 890 may be determined for the radial layer n.

At block 412, the processor of the computer 170 may determine if the breakout angle is zero. A breakout angle of zero may indicate there is no more breakout occurring at the current radial layer. In some implementations, the breakout angle may be greater than zero but a maximum specified radial distance into the subsurface formation has been reached. If the breakout angle is greater than zero, then operations proceed to block 414. Otherwise, operations proceed to block 416.

At block 414, the processor of the computer 170 may increase the radial size. For example, with reference to FIG. 7, the radial size may be increased to determine the layer failure volume 792, and thus the breakout angle α_n+1 786, of the radial layer n+1. The radial size may be increased by any distance increment, such as 0.25 of the wellbore radius. For example, each radial layer may have width of 2 inches, and therefore the radial size may be increased by 2 inches in block 414. The distance increment for each radial layer may be uniform or vary. Operations may return to block 410 for the aforementioned operations. The processor of the computer 170 may iteratively determine the breakout angle of the current axial layer, via subsequent radial layers, until the breakout angle is zero (or a maximum radial distance is reached).

At block 416, the processor of the computer 170 may determine if there are additional axial layers. For example, with reference to FIG. 7, the depth interval 700 includes an axial layer 745. The layer failure volumes and corresponding breakout angles may need to be determined for the axial layer 745 after axial layer 740 is complete. If there are additional axial layers, operations may return to block 410. Otherwise, operations proceed to block 418.

At block 418, the processor of the computer 170 may determine the radial distance of the depth interval. The radial distance may be where the largest distance the breakout is from the wellbore wall, i.e., the radial layer where the breakout angle reaches zero. The radial distance of the radial layer in which the breakout angle is zero may provide the radial distance for the corresponding axial layer. Thus, the radial distance of the depth interval may include the radial distances of each axial layer. In some implementations, the radial distance of the depth interval may be the average of the radial distances of the axial layers, the maximum radial distance of the axial layers, the minimum radial distance of the axial layers, the median radial distance of the axial layers, etc.

For example, a wellbore may have a radius of 4 inches. If the radial layers in blocks 410-414 used increments of 0.25 of the wellbore radius (i.e., each radial layer is 1 inch wide), and a breakout angle of zero occurred at the second radial layer, n+1, (2 radial layers deep, or 2 inches into the formation), the radial distance of the wellbore for the corresponding axial interval may be 2 inches into the formation from the wellbore wall. For example, with reference to FIG. 2B, it may be determined that the breakouts 220, 222 may be 2 inches past the wellbore wall (intended profile 208). In some implementations, the average of the radial distances of each axial layer may be averaged to determine the radial distance for the depth interval. In some implementations, the radial distance may be derived from the layer failure volume of the axial layers. For example, the layer failure volumes for radial layers where the breakout angle is greater than zero may be determined, as described above. The radial distance from the wellbore wall may be generated based on the accumulated area of the layer failure volumes for the radial layers given the breakout angle for each radial layer.

Operations of the flowchart 400 continue at transition point A, which continues at transition point A of FIG. 5. From transition point A of FIG. 5, operations continue at block 502.

At block 502, the processor of the computer 170 may determine if the depth interval length is greater than a length threshold. For example, a length threshold may be any suitable length such as 50 feet, 200 feet, 1000 feet, etc. If the depth interval has a length greater than or equal to the length threshold, then operations proceed to block 504. Otherwise, operations proceed to block 510.

At block 504, the processor of the computer 170 may determine the hydraulics of the wellbore. The hydraulics may include the equivalent circulating density (ECD), stand pipe pressure (SPP), etc. In addition to the depth, drill string dimensions, mud properties (such as density), bottom hole pressure, etc., the hydraulics may be affected by the area of the wellbore. For example, a change in the annular area may affect the friction factor of the annulus when drilling fluid is being circulated to the surface, resulting in a change in ECD, SPP, etc. In some implementations, the hydraulics may be determined by utilizing the radial distance of the current depth interval and/or the failure layer volume. For example, the friction factor of the annulus may be adjusted to accommodate the increased area of the wellbore profile as a result of a breakout in the wellbore. Accordingly, the hydraulics may be determined based on the radial distance of the depth interval.

At block 506, the processor of the computer 170 may determine if the hydraulics match the measured data. The measured data may include the measured SPP and the measured ECD. The measurements may be obtained from one or more sensors positioned downhole (i.e., in the drill string assembly) and/or at the surface. The actual measurements may be indicative of the actual wellbore conditions. If the hydraulics match the actual measurements, then the radial distance of the depth interval may be valid, and operations may proceed to block 510. In some implementations, the data may match if within a certain threshold. For example, the hydraulics may need to be with 95% or greater to be considered matching. If the hydraulics do not match the measured data, then operations may proceed to block 508.

At block 508, the processor of the computer 170 may adjust the radial distance. The radial distance may be adjusted by any amount in attempts to match the actual measurements. For example, if the calculated ECD is less than the actual ECD, the radial distance may be increased by a specified amount to attempt to match the actual measurements. Operations return to block 504 to determine the hydraulics with the updated radial distance and determine if the updated hydraulics match the measured data.

At block 510, the processor of the computer 170 may update the hole profile log of the wellbore based on the radial distance for the depth interval. The depth interval with the corresponding radial distance may be added to the hole profile log of the wellbore to update the hole profile log. To help illustrate, FIG. 9 is a chart depicting a hole profile log, according to some implementations. FIG. 9 includes a chart 900 of a hole profile log with an x-axis 902 and a y-axis 904. The x-axis 902 is the caliper of the wellbore having units in inches (in.) The y-axis 904 is the measured depth of the wellbore having units in feet (ft). The caliper 906 may represent assumed wellbore radial distance (based on the diameter of the drill bit and any other safety factor included in the assumed radial diameter). The maximum radial distance 908 (determined and validated above) of the wellbore at each measured depth may represent the deepest distance from the wellbore wall at the corresponding depth. When a radial distance of a depth interval is determined (as described above), the radial distance and corresponding measured depths may be added to the hole profile log to update the hole profile log. In some implementations, if a hole profile log has not yet been generated, a hole profile log may be generated from radial distances and corresponding depths of a depth interval.

At block 512, the processor of the computer 170 may identify the hole profile type. For each measured depth (or depth interval), the hole profile type may be identified based on the radial distance. For example, the radial distance (and orientation on the wellbore wall) may indicate the hole profile is in gauge, a breakout, a washout, a key seat, etc. (as described in FIGS. 2A-2D). In some implementations, forces such as forces on the drill string, pumps, etc. may be utilized to validate the hole profile type. For example, a key seat profile may indicate additional friction force on the drill string, resulting in sticking. The overpull of the drill string may validate a key seat profile may be present in the wellbore.

At block 514, the processor of the computer 170 may perform a drilling operation based on the hole profile type. The hole profile type may indicate a drilling failure may occur or has occurred such as a stuck pipe, lost circulation, packoff, etc. Accordingly, a drilling operations may be performed and/or one or more drilling properties may be modified based on the hole profile.

At block 516, the processor of the computer 170 may determine if there are additional depth intervals. For example, if the wellbore is still being drilled, then more depth intervals may be required to update the hole profile log. If there are additional depth intervals, then operations of the flowchart 500 may continue at transition point B, which continues at transition point B of FIG. 4. From transition point B of FIG. 4, operations return to operations at block 402. In some implementations, the subsequent depth interval may have a length similar or different to the previous depth interval. For example, if the current depth interval indicates an increasing radial distance in one or more directions of the wellbore, then the next depth interval may be shorter than the current depth interval to improve the accuracy of the hole profile generator. If there are no additional depth intervals (i.e., drilling of the wellbore is complete), the operations of flowchart 500 are complete.

The flowcharts are provided to aid in understanding the illustrations and are not to be used to limit the scope of the claims. The flowcharts depict example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. For example, the operations depicted in blocks 302-308 of flowchart 300 can be performed in a different order. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus.

As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

Any combination of one or more machine-readable medium(s) may be utilized. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random-access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.

A machine-readable signal medium may include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.

Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.

Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine.

The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.

Example Computer

FIG. 10 is a block diagram depicting an example computer, according to some implementations. FIG. 10 depicts a computer 1000 for determining rock elastic properties of subsurface formations with transferrable mapping parameters. The computer 1000 includes a processor 1001 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 1000 includes memory 1007. The memory 1007 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 1000 also includes a bus 1003 and a network interface 1005. The computer 1000 can communicate via transmissions to and/or from remote devices via the network interface 1005 in accordance with a network protocol corresponding to the type of network interface, whether wired or wireless and depending upon the carrying medium. In addition, a communication or transmission can involve other layers of a communication protocol and or communication protocol suites (e.g., transmission control protocol, Internet Protocol, user datagram protocol, virtual private network protocols, etc.).

The computer 1000 also includes a hole profile generator 1011 and a controller 1015 which may perform the operations described herein. For example, the hole profile generator 1011 may determine where a breakout has occurred on a wellbore wall of a depth interval in a wellbore and determine the radial distance of the breakout. The hole profile generator 1011 may also verify the radial distance and determine the hole profile type at the measured depth layer. The controller 1015 may execute one or more actions based on the hole profile type. The hole profile generator 1011 and the controller 1015 can be in communication. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 1001. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 1001, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 10 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 1001 and the network interface 1005 are coupled to the bus 1003. Although illustrated as being coupled to the bus 1003, the memory 1007 may be coupled to the processor 1001.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for determining the hole profile of a wellbore at different measured depth layers described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

Various modifications to the implementations described in this disclosure may be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other implementations without departing from the spirit or scope of this disclosure. Thus, the claims are not intended to be limited to the implementations shown herein but are to be accorded the widest scope consistent with this disclosure, the principles and the novel features disclosed herein.

Certain features that are described in this specification in the context of separate implementations also may be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation also may be implemented in multiple implementations separately or in any suitable sub combination. Moreover, although features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination may in some cases be excised from the combination, and the claimed combination may be directed to a sub combination or variation of a sub combination.

Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. Further, the drawings may schematically depict one more example process in the form of a flow diagram. However, some operations may be omitted and/or other operations that are not depicted may be incorporated in the example processes that are schematically illustrated. For example, one or more additional operations may be performed before, after, simultaneously, or between any of the illustrated operations. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and the described program components and systems may generally be integrated together in a single software product or packaged into multiple software products. Additionally, other implementations are within the scope of the following claims. In some cases, the actions recited in the claims may be performed in a different order and still achieve desirable results.

Example Implementations

Implementation #1: A method performed while drilling a wellbore with a drill string assembly in a subsurface formation comprising: obtaining subsurface formation properties of the subsurface formation; obtaining, via one or more sensors on the drill string assembly, wellbore properties corresponding to a first depth interval of the wellbore, wherein the first depth interval comprises one or more axial layers; selecting, via a hole profile generator, a failure criteria of the subsurface formation corresponding to the first depth interval; determining, via the hole profile generator, a layer failure volume for each axial layer of the first depth interval based on the wellbore properties and the failure criteria; determining, via the hole profile generator, a radial distance of the wellbore for the first depth interval based on the layer failure volumes; and identifying, via the hole profile generator, a hole profile type for the wellbore based on the radial distance of the first depth interval.

Implementation #2: The method of claim Implementation #1 further comprising: updating a hole profile log based on the radial distance of the first depth interval.

Implementation #3: The method of claim Implementation #1 or 2, wherein the failure criteria is selected based on lithology of the subsurface formation corresponding to the first depth interval.

Implementation #4: The method of any one or more of Implementations #1-3, wherein the subsurface formation properties include principal stresses of the subsurface formation and lithology, and wherein the wellbore properties include inclination and azimuth.

Implementation #5: The method of any one or more of Implementations #1-4, further comprising: determining the layer failure volume of each radial layer of a first axial layer until a breakout angle is zero; and determining the layer failure volume of the first axial layer based on the layer failure volume of the radial layers.

Implementation #6: The method of any one or more of Implementations #1-5 further comprising; determining hydraulic properties, wherein the hydraulic properties include standpipe pressure and equivalent circulating density; and confirming the radial distance of the wellbore for the first depth interval based on the hydraulic properties.

Implementation #7: The method of any one or more of Implementations #1-6 further comprising: performing a drilling operation based on the hole profile type.

Implementation #8: The method of any one or more of Implementations #1-7, wherein the hole profile type includes a gauge hole, a breakout, a washout, and a key seat.

Implementation #9: A system comprising: a drill string assembly configured to drill a wellbore in a subsurface formation; a processor; and a computer-readable medium having instructions stored thereon that are executable by the processor, the instructions including, instructions to obtain subsurface formation properties of the subsurface formation; instructions to obtain, via one or more sensors on the drill string assembly, wellbore properties corresponding to a first depth interval of the wellbore, wherein the first depth interval comprises one or more axial layers; instructions to select, via a hole profile generator, a failure criteria of the subsurface formation corresponding to the first depth interval; instructions to determine, via the hole profile generator, a layer failure volume for each axial layer of the first depth interval based on the wellbore properties and the failure criteria; instructions to determine, via the hole profile generator, a radial distance of the wellbore for the first depth interval based on the layer failure volumes; and instructions to identify, via the hole profile generator, a hole profile type for the wellbore based on the radial distance of the first depth interval.

Implementation #10: The system of Implementation #9 further comprising: instructions to determine the radial distance of the wellbore of a second depth interval, wherein the second depth interval is at a depth greater than the first depth interval; and instructions to update a hole profile log based on the radial distance of the second depth interval.

Implementation #11: The system of Implementation #9 or 10, wherein the failure criteria is selected based on lithology of the subsurface formation corresponding to the first depth interval.

Implementation #12: The system of any one or more of Implementations #9-11, wherein the subsurface formation properties include principal stresses of the subsurface formation and lithology, and wherein the wellbore properties include inclination and azimuth.

Implementation #13: The system of any one or more of Implementations #9-12, further comprising: instructions to determine the layer failure volume of each radial layer of a first axial layer until a breakout angle is zero; and instructions to determine the layer failure volume of the first axial layer based on the layer failure volume of the radial layers.

Implementation #14: The system of any one or more of Implementations #9-13 further comprising; instructions to determine hydraulic properties, wherein the hydraulic properties include standpipe pressure and equivalent circulating density; and instructions to confirm the radial distance of the wellbore for the first depth interval based on the hydraulic properties.

Implementation #15: The system of any one or more of Implementations #9-14 further comprising: instructions to perform a drilling operation based on the hole profile type.

Implementation #16: The system of any one or more of Implementations #9-15, wherein the hole profile type includes a gauge hole, a breakout, a washout, and a key seat.

Implementation #17: A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor, the instructions comprising: instructions to obtain subsurface formation properties of a subsurface formation, wherein a wellbore is drilled, via a drill string assembly, in the subsurface formation; instructions to obtain, via one or more sensors on the drill string assembly, wellbore properties corresponding to a first depth interval of the wellbore, wherein the first depth interval comprises one or more axial layers; instructions to select, via a hole profile generator, a failure criteria of the subsurface formation corresponding to the first depth interval; instructions to determine, via the hole profile generator, a layer failure volume for each axial layer of the first depth interval based on the wellbore properties and the failure criteria; instructions to determine, via the hole profile generator, a radial distance of the wellbore for the first depth interval based on the layer failure volumes; and instructions to identify, via the hole profile generator, a hole profile type for the wellbore based on the radial distance of the first depth interval.

Implementation #18: The non-transitory, computer-readable medium of Implementation #17 further comprising: instructions to determine the radial distance of the wellbore of a second depth interval, wherein the second depth interval is at a depth greater than the first depth interval; and instructions to update a hole profile log based on the radial distance of the second depth interval.

Implementation #19: The non-transitory, computer-readable medium of Implementation #17 or 18, further comprising: instructions to determine the layer failure volume of each radial layer of a first axial layer until a breakout angle is zero; and instructions to determine the layer failure volume of the first axial layer based on the layer failure volume of the radial layers.

Implementation #20: The non-transitory, computer-readable medium of any one or more of Implementations #17-19 further comprising: instructions to determine hydraulic properties, wherein the hydraulic properties include standpipe pressure and equivalent circulating density; and instructions to confirm the radial distance of the wellbore for the first depth interval based on the hydraulic properties.

Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.

As used herein, the term “or” is inclusive unless otherwise explicitly noted. Thus, the phrase “at least one of A, B, or C” is satisfied by any element from the set {A, B, C} or any combination thereof, including multiples of any element.