FORMATION ELASTIC PROPERTY EVALUATION USING DRILLING DATA BASED ON A BIT-ROCK INTERACTION MODEL

Description

FIELD

The disclosure generally relates to drilling of wellbores and more particularly, to identifying rock elastic properties while drilling a wellbore.

BACKGROUND

A drill bit may be utilized to physically cut the rock to form a wellbore in a subsurface formation. Rock elastic properties along the wellbore offer vital insights for geological assessments during the drilling process and the stimulation optimization. These elastic properties, such as Young's modulus, Poisson's ratio, and elastic anisotropic parameters play pivotal roles in determining lithology, porosity, permeability, etc. of the subsurface formation. In drilling optimization, knowledge of rock elastic properties aids the approximation of rock strength, which can guide drill bit material selection and cutting structure design for enhanced efficiency. For well completion and stimulation, Young's Modulus and Poisson's ratio influence casing design and hydraulic fracturing. Generally, rock elastic properties are critical for informed wellbore drilling and reservoir production.

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-2B are schematics depicting an example drill bit, according to some implementations.

FIG. 3 is an illustration depicting a bit-rock interaction model, according to some implementations.

FIG. 4 is a flowchart depicting example operations to calibrate a bit-rock interaction model, according to some implementations.

FIG. 5 is a flowchart depicting example operations to determine one or more rock elastic properties while drilling a wellbore in a subsurface formation, according to some implementations.

FIG. 6 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 PDC drill bits in illustrative examples. Aspects of this disclosure can also be applied to any other types of drill bits or drilling tools. 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 rock elastic properties of a subsurface formation based on drilling data while drilling a wellbore in said subsurface formation. The elastic properties may include Young's modulus, Poisson's ratio, etc. Elastic properties of a subsurface formation may be utilized in hydrocarbon recovery operations such as determining reservoir properties for reservoir characterization, completion design, etc. Conventional operations may determine elastic properties via wireline logging and/or logging while drilling (LWD), with sonic logging being indispensable for measuring P-wave and S-wave slowness. Combined with neutron density logging, these tools may assess rock elastic properties, like Young's Modulus and Poisson's ratio. However, both wireline and LWD sonic logging face different challenges. For wireline logging, it may require a separate run after the wellbore is drilled, therefore involving additional costs and it may not provide guidance for real-time geosteering. LWD sonic logging, although performed while drilling a wellbore, may also introduce additional costs, and the tool may lead to an overall extension in the Bottom Hole Assembly (BHA) length. In addition, the LWD measurement point may not be exactly at-bit, but slightly behind the drill bit, which may cause delay for informed geosteering.

In some implementations, a bit-rock interaction model may be utilized to determine one or more rock elastic properties of a subsurface formation while drilling a wellbore with a drill bit. A bit-rock interaction model may utilize drilling data obtained while the drill bit drills the wellbore. The drilling data may include drill bit vibrations (which may be passively collected at the drill bit), rate of penetration (ROP) (which may be evaluated from measured depth), torque on bit (TOB), weight on bit (WOB), drill bit accelerations, rotations per minute (RPM), depth of cut (DOC), etc. The bit-rock interaction model may describe the rock stress and strain as the drill bit deforms and fails the rock during the drilling process. Accordingly, the bit-rock interaction model may establish a relationship between the drilling data and stress/strain of the subsurface formation, where the bit-rock interaction model may derive stress representatives from the drill bit vibrations, and the strain representatives from the ROP. In some implementations, the stress representatives and/or strain representatives may then be utilized to determine one or more rock elastic properties of the subsurface formation, such as Young's modulus, Poisson's ratio, etc., according to Hooke's law.

In comparison to conventional operations that may use sonic logs using wireline and/or LWD to determine rock elastic properties, the bit-rock interaction model may display significant advantages in terms of cost reduction, as it may only utilizes the passive data generated during drilling the wellbore, including the drill bit vibrations and ROP, whose acquisition cost may be neglectable compared with the data acquisition cost in wireline and LWD sonic logging. In addition, the proposed method may be more suitable for real-time geosteering, since its measurement point is at-bit, rather than on the BHA slightly behind the bit like the LWD sonic tool.

In comparison to conventional operations that may use drilling-data-based logging to determine rock elastic properties, the proposed method relies on a bit-rock interaction model, instead of pure rock fracturing theory without considering any drilling-related variables, such as ROP, revolution per minute (RPM) and depth of cut (DOC). This difference may result in different implementation regarding drilling data selection and processing, thus providing possible advantages for the drilling-data-based logging.

In some implementations, a drilling operation may be performed based on the rock elastic properties. Examples of drilling operations include tripping out the drill bit to be replaced, adjusting a drilling parameter, etc. For instance, the elastic rock properties may indicate unfavorable reservoir quality with respect to hydrocarbon recovery. Accordingly, drilling parameters such as weight on bit (WOB), rotations per minute (RPM), tool face orientation, etc. may be adjusted to steer the drill bit to more favorable rock.

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 drilling data may be obtained from and utilized by a bit-rock interaction model to determine elastic rock properties of the subsurface formation 108 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. 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 downhole drilling data as the drill bit 112 drills the subsurface formation 108. The drilling data obtained from the sensors may include downhole WOB, downhole TOB, downhole RPM, drill bit vibration, 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 embodiments, 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 bit-rock interaction model that may determine rock elastic properties based on drilling data obtained while the drill bit 112 drills the wellbore 180 in the subsurface formation 108. When drilling data is obtained and processed, the processor of the computer 170 may input the drilling data into the bit-rock interaction model to determine the rock elastic properties. In some implementations, the processor of the computer 170 may perform a drilling operation based on rock elastic properties. An example of the computer 170 is depicted in FIG. 6, which is further described below.

Example Drill Bit

FIGS. 2A-2B are schematics depicting an example drill bit, according to some implementations. In particular, FIGS. 2A-2B depict an example drill bit 200. The drill bit 200 can be an example of the drill bit 112 of FIG. 1. As shown in this example, the drill bit 200 includes six blades 202-207, which can be integrally formed and extend from a bit body 208. The blades 202-207 are separated by flow channels 209 that may include nozzles (i.e., orifices) where drilling mud can be ejected through the drill bit 200 and into the wellbore. Primary cutters 210, backup cutters 211, and depth of cut controllers (DOCCs) may be mounted on the blades 202-207. During drilling, the face of the primary cutters 210 and backup cutters 211 can be in contact with and cut and/or shear the rock of the subsurface formation to create and extend a wellbore. In some instances, the face of the primary cutters 210 may be extended a greater distance from the blades 202-207 than the backup cutters 211 such that only the primary cutters 210 can be in contact with the rock of the subsurface formation. During drilling, the primary cutters 210 may become worn or broken such that one or more of the backup cutters 211 can then be in contact with the rock of the subsurface formation. Many factors including orientation, shape, type, and density of the cutters may vary depending on the design of the drill bit 200. Other drill bit characteristics including the number of blades, the shape of the blades, etc. may vary depending on the subsurface formation environment that the drill bit 200 may drill. Pads 214 may extend from the side of the blades 202-207. The pads 214 may help maintain the size of the wellbore to a full gauge diameter, particularly when cutters become dull and become under gauge.

Example Bit-Rock Interaction Model

FIG. 3 is an illustration depicting a bit-rock interaction model, according to some implementations. In particular, FIG. 3 depicts a bit-rock interaction model 300 that includes a rock pie 302 being removed by a single cutter, the stress components along tangential and axial directions for the bit-rock interface, and the strain components along tangential and axial directions for the bit-rock interface.

Drilling data, such as drill bit vibrations and ROP, may be obtained from the drilling process. A rock-bit interaction model may derive stress representatives from the drill bit vibrations. Moreover, the rock-bit interaction model may derive strain representatives from the ROP. With the stress representatives and the strain representatives, the rock elastic properties may be determined based on Hooke's law. For example, the stress and strain, represented by σ and ε, respectively (using Equation 1 below), may be defined as follows:

[ σ y σ z ] = [ E ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) Ev ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) 2 ⁢ Ev ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) E ⁡ ( 1 - v ) ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) ] [ ε y ε z ] ( 1 )

• • where the subscripts y and z denote the tangential direction 306 and axial directions 308 of the drill bit rotation, respectively, and E and v are the Young's modulus and Poisson's ratio, respectively.

When drilling the wellbore, the bottom hole rocks are repeatedly compressed and failed by the forces applied through the drill bit cutters. Considering a bit-rock interaction model 300 where the drill bit is simplified as a single cutter. FIG. 3 depicts the illustration of the stress and strain along tangential direction 306 and axial direction 308. The example depicted in FIG. 3 includes a rock pie 302 being removed by the single cutter for one revolution, where x, y and z denote centripetal direction 304, tangential direction 306, and axial direction 308, respectively. r and DOC indicate the bit radius 310 and the depth of cut 312, respectively. The stress components include tangential stress components 316 and axial stress components 318 at the bit-rock interface 314. The strain components include tangential strain components 322 and axial strain components 325 at the bit-rock interface 320. F_(y/z) and d_(y/z) denote the forces and displacements along y/z directions, respectively. Per definition, stress should be proportional to the forces divided by the cutting area, which may be represented by DOC·r. Additionally, strain should be proportional to the displacement divided by the base length being compressed.

In some implementations, F_(y/z) and d_(y/z) may be derived from drilling data. For F_y and F_z, they may be directly measured by strain gauges at the drill bit, known as TOB and WOB. Alternatively, they may be represented by ρa_y and ρa_z, in which ρ is the rock density and a_y/z are the accelerations along y/z directions measured by accelerometers at the drill bit, known as bit vibrations (here denoted as VibeY and VibeZ). d_y and d_z may be represented by revolution per minute (RPM)·2πr and ROP, respectively. In some implementations, both the forces and the displacements may be statistically derived averages from different drilling data within a time range, whose corresponding depth bin size determines the final resolution of the rock property estimation. Depth bin size may be 1 foot, 10 feet, 100 feet, etc. Table 1 shows the corresponding relationship between the physical variables (F_(y/z) and d_(y/z)) and the drilling data.

TABLE 1
Physical variables	Fy	Fz	dy	dz
Drilling data	TOB	WOB	RPM · 2πr	ROP
	ρ · VibeY	ρ · VibeZ

In some implementations, the drilling data may be substituted into the stress components (tangential stress components 316 and axial stress components 318) and strain components (tangential strain components 322 and axial strain components 324). Moreover, the stress and strain components may be scaled by DOC, resulting in Equation 2 below:

[ A · TOB + A 0 B · WOB + B 0 ] = [ E ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) Ev ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) 2 ⁢ E ⁢ v ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) E ⁡ ( 1 - v ) ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) ] [ C · ROP + C 0 D · ROP + D 0 ] ( 2 )

Alternatively, the drilling data may be substituted into the stress components (tangential stress components 316 and axial stress components 318) and strain components (tangential strain components 322 and axial strain components 324). Moreover, the stress and strain components may be scaled by DOC/p, resulting in Equation 3 below:

[ A · VibeY + A 0 B · VibeZ + B 0 ] = [ E / ρ ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) E / ρ ⁢ v ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) 2 ⁢ E / ρ ⁢ v ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) E / ρ ⁡ ( 1 - v ) ( 1 - 2 ⁢ v ) ⁢ ( 1 + v ) ] [ C · ROP + C 0 D · ROP + D 0 ] ( 3 )

• • where, A, B, C, D and A₀, B₀, C₀, D₀ are the scales and biases (i.e., mapping parameters), respectively, to linearly map the drilling data into stress and strain representatives. Notice the bit radius, as a constant, has been absorbed into the scales and biases. The strain representatives for both equation 2 and 3 are ε_y DOC and ε_zDDOC, both of which are mapped from ROP, since RPM·DDOC=ROP. However, the stress representatives for equations 2 and 3 are different. In equation 2, the stress representatives are σ_yDOC and σ_zDOC, which are mapped from TOB and WOB, respectively. In Equation 3, the stress representatives are σ_yDOC/ρ and σ_zDOC/ρ, which are mapped from VibeY and VibeZ, respectively. Consequently, Equation 2 targets at E and v; whereas Equation 3 targets at E/ρ and v.

In some implementations, the bit-rock interaction model may be extended to anisotropic cases, including different transverse isotropic (TI) cases and/or orthorhombic case, by estimating more independent elastic constants using drilling data of all available directions, including centripetal, tangential, and axial directions. In some implementations, the stress/strain representatives may be extended to estimate rock confined compressive strength (CCS) based on the stress/strain representatives derived from drilling data. Instead of utilizing Hooke's law, we can estimate the CCS by locating the yielding point via fitting the whole stress-strain curve.

Example Operations

Example operations for determining rock elastic properties are now described in reference to FIG. 1, FIGS. 2A-2B, and FIG. 3. 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.

FIG. 4 is a flowchart depicting example operations to calibrate a bit-rock interaction model, according to some implementations. In particular, FIG. 4 includes a flowchart 400 of operations to calibrate a rock-bit interaction model to generate mapping parameters. The rock-bit interaction model is described in reference to the bit-rock interaction model 300 of FIG. 3. Additionally, the operations of the flowchart 400 are described in reference to the processor of the computer 170 of FIG. 1. Operations for the flowchart 400 begin at block 402.

At block 402, the processor of the computer 170 may obtain raw drilling data. The raw drilling data may include drill bit vibrations. In some implementations the drill bit vibrations may be obtained via strain gauges (such as torque on bit (TOB) and/or weight on bit (WOB) described in Table 1) positioned proximate the drill bit. In some implementations the drill bit vibrations may be obtained via accelerometers (such as VibeY and VibeZ described in Table 1). Additionally, the drill bit vibrations may be obtained by gyroscopes, magnetometers, or any other suitable sensor. Moreover, the raw drilling data may include rate of penetration (ROP). The ROP may be the hole depth variation over a period of time. The ROP may be the downhole ROP estimated and/or measured from other apparatus and/or methods. For example, a sensor positioned proximate the drill bit may be configured to obtain downhole ROP measurements while drilling. In some implementations, the ROP may be replaced with RPM·D if reliable RPM and D may be available.

At block 404. the processor of the computer 170 may process the raw drilling data to generate processed drilling data. For example, to process the drill bit vibration measurements, the power spectrum density (PSD) of the drill bit vibration measurements may be determined. The amplitudes of the PSDs may then be averaged for a selected frequency band within a temporal range or a corresponding depth bin to generate processed drill bit vibrations. The frequency band selected may be high enough to avoid influences from the bottom hole assembly (BHA) vibrations, such as the mud motor, and/or the drill string vibrations. In some implementations, the drill bit vibration measurements may be processed in time domain by calculating the windowed average of absolute measurements, by performing empirical mode decomposition (EMD), etc. To process the ROP, the hole depth variation along time within a temporal range and/or a corresponding depth bin may be averaged. Any suitable process may be used to process the drill bit vibrations and/or the ROP.

At block 406, the processor of the computer 170 may obtain reference rock clastic properties. Reference rock elastic properties may include Young's modulus, Poisson's ratio, etc. of a subsurface formation surrounding a wellbore. The reference rock elastic properties may correspond to the drilling data obtained from the drill bit utilized to drill the wellbore. The reference rock elastic properties may be obtained via sonic logs (wireline, LWD, etc.) from the same wellbore being drilled, from casing cement from which the properties are known, etc.

At block 408, the processor of the computer 170 may input processed drilling data and reference rock elastic properties into a bit-rock interaction mode to generate mapping parameters for the processed drilling data. To calibrate the bit-rock interaction model, the processed drilling data and the referenced elastic rock properties may be input into the bit-rock interaction model to generated mapping parameters for the different drilling data, i.e., the scales (A, B, C, D) and biases (A₀, B₀, C₀, D₀) as shown in Equation 2 and Equation 3.

For example, Equation 2 may be rearranged to estimate the scales and biases, as shown in Equation 4 below:

[ 0 0 ] = [ - TOB i 0 ( C 1 ⁢ 1 i + C 1 ⁢ 2 i ) · ROP i C 1 ⁢ 2 i · ROP i - 1 0 C 1 ⁢ 1 i + C 1 ⁢ 2 i C 1 ⁢ 2 i 0 - WOB i 2 ⁢ C 12 i · ROP i C 11 i · ROP i 0 - 1 2 ⁢ C 12 i C 1 ⁢ 1 i ] ⁢ P ( 4 )

• • where in which, P=[A, B, C, D, A₀, B₀, C₀, D₀] represents the target mapping parameters, C₁₁ and C₁₂ are the input elastic constants, which may be calculated by reference E and v as C₁₁=E(1−v)/((1−2v)(1+v)) and C₁₂=Ev/((1−2v)(1+v)). TOB, WOB and ROP are the input processed drilling data. The superscript i indicates sample index for the calibration data corresponding to a certain temporal range or depth bin. Using least-squares (LS), we may solve for P that may minimize the L2 residuals of Equation 4 for all available calibration data samples.

FIG. 5 is a flowchart depicting example operations to determine one or more rock elastic properties while drilling a wellbore in a subsurface formation, according to some implementations. In particular, FIG. 5 includes a flowchart 500 of operations to generate stress representatives and strain representatives via a rock-bit interaction model, and determine one or more rock elastic properties based on the stress representatives and strain representatives. The rock-bit interaction model is described in reference to FIG. 3. Additionally, the operations of the flowchart 500 are described in reference to the processor of the computer 170 of FIG. 1 and the mapping parameters of FIG. 4. The operations of the flowchart 500 may be continuously repeated as a drill bit drills a wellbore in a subsurface formation. Operations for the flowchart 500 begin at block 502.

At block 502, the processor of the computer 170 may obtain raw drilling data while drilling a wellbore with a drill bit. The raw drilling data may be measurements obtained from new rock drilled in the wellbore. The measurements may be similar to the measurements described in block 402 of FIG. 4. For example, the raw drilling data may include drill bit vibrations, ROP, etc. The drilling data may be obtained in depth intervals such as every foot, 10 feet, 100 feet, etc. and/or in time intervals such as every 30 seconds, every minute, every 10 minutes, etc. while drilling the wellbore.

At block 504, the processor of the computer 170 may process the raw drilling data to generate processed drilling data. Processing the raw drilling data may be similar to operations described in block 404 of FIG. 4. For example, the power spectrum density (PSD) of the drill bit vibration measurements may be determined. The amplitudes of the PSDs may then be averaged for a selected frequency band within a temporal range or a corresponding depth bin to generate processed drill bit vibrations. The frequency band selected may be high enough to avoid influences from the bottom hole assembly (BHA) vibrations, such as the mud motor, and/or the drill string vibrations. Moreover, to process the ROP, the hole depth variation along time within a temporal range and/or a corresponding depth bin may be averaged.

At block 506, the processor of the computer 170 may obtain mapping parameters. The mapping parameters may be the mapping parameters from the calibration of the bit-rock interaction model (as described in block 408 of FIG. 4). For example, the mapping parameters may include the scales (A, B, C, D) and biases (A₀, B₀, C₀, D₀) as shown in Equation 2 and Equation 3.

At block 508, the processor of the computer 170 may input the processed drilling data and mapping parameters into a bit-rock interaction model to generate stress representatives and strain representatives. The processed drilling data may be linearly mapped via the mapping parameters to generate the stress/strain representatives. For example, in Equation 2, the stress representatives are σ_yD and σ_zD, which may be mapped from TOB and WOB, respectively. In equation 3, the stress representatives are σ_yD/ρ and σ_zD/ρ, which may be mapped from VibeY and VibeZ, respectively. Additionally, the strain representatives for both equation 2 and 3 are ε_yD and ε_zD, both of which may be mapped from ROP, since RPM·D=ROP.

At block 510, the processor of the computer 170 may determine rock elastic properties based on the stress representatives and strain representatives. With the stress representatives and strain representatives, the rock elastic properties may be inverted according to Hooke's law. For example, Equation 2 may be rearranged to estimate E (Young's modulus) and v (Poisson's ration) as shown in Equation 5 below:

[ A · TOB + A 0 B · WOB + B 0 ] = [ C · ROP + C 0 ( C + D ) · ROP + C 0 + D 0 D · ROP + D 0 2 ⁢ ( C · ROP + C 0 ) ] [ C 1 ⁢ 1 C 1 ⁢ 2 ] ( 5 )

• • in which, [A, B, C, D, A₀, B₀, C₀, D₀] are the input mapping parameters, TOB, WOB and ROP are the input processed drilling data corresponding to certain temporal range or depth bin. Equation 5 may be directly solved for [C₁₁, C₁₂]. For example, utilized Equation 5, E and v may be determined for that specific temporal range or depth bin, by E=C₁₁−2C₁₂²/(C₁₁+C₁₂) and v=C₁₂/(C₁₁+C₁₂). In some implementations, Equation 3 may also be rearranged to generate E (Young's modulus) and v (Poisson's ration).

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 502-510 of flowchart 500 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. 6 is a block diagram depicting an example computer, according to some implementations. FIG. 6 depicts a computer 600 for determining rock elastic properties of a subsurface formation. The computer 600 includes a processor 601 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 600 includes memory 607. The memory 607 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 600 also includes a bus 603 and a network interface 605. The computer 600 can communicate via transmissions to and/or from remote devices via the network interface 605 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 600 also includes a signal processor 611 and a controller 615 which may perform the operations described herein. For example, the signal processor 611 may determine stress representatives and strain representatives based on drilling data. The signal processor 611 may also determine rock elastic properties based on the stress representatives and strain representatives. The controller 615 may execute one or more actions based on the cause of the change in the rock elastic properties. The signal processor 611 and the controller 615 can be in communication. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 601. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 601, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 6 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 601 and the network interface 605 are coupled to the bus 603. Although illustrated as being coupled to the bus 603, the memory 607 may be coupled to the processor 601.

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 rock elastic properties as 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 comprising: obtaining drilling data of a drill bit while drilling a wellbore in a formation with the drill bit; generating stress representatives and strain representatives via a bit-rock interaction model configured with parameters to map the drilling data; and determining one or more elastic properties of the formation based on the stress representatives and the strain representatives.

Implementation #2: The method of Implementation #1, wherein the drilling data includes any one or more of torque on bit, weight on bit, drill bit accelerations, rotations per minute, depth of cut, and rate of penetration.

Implementation #3: The method of Implementation #1 or 2, wherein the stress representatives are generated based on drill bit vibrations; and wherein the strain representatives are generated based on rate of penetration.

Implementation #4: The method of Implementation #3, wherein the drill bit vibrations are obtained via sensors proximate the drill bit including accelerometers, strain gauges, gyroscopes, magnetometers, or any combination thereof.

Implementation #5: The method of any one or more of Implementation #1-4, wherein the one or more elastic properties of the formation are determined based on Hooke's law.

Implementation #6: The method of any one or more of Implementation #1-5 further comprising; obtaining reference elastic properties of the formation to be drilled by the drill bit; calibrating the bit-rock interaction model with the reference elastic properties; and outputting the parameters for the drilling data.

Implementation #7: The method of Implementation #6 further comprising: inputting the drilling data and the parameters into the bit-rock interaction model to generate the stress representatives and the strain representatives.

Implementation #8: The method of any one or more of Implementation #1-7, wherein the one or more elastic properties includes Young's modulus and Poisson's ratio.

Implementation #9: A system comprising: a drill bit configured to drill a wellbore in a formation; a processor; and a computer-readable medium having instructions stored thereon that are executable by the processor to cause the processor to, obtain drilling data of the drill bit while drilling the wellbore; generate stress representatives and strain representatives via a bit-rock interaction model configured with parameters to map the drilling data; and determining one or more elastic properties of the formation based on the stress representatives and the strain representatives.

Implementation #10: The system of Implementation #9, wherein the drilling data includes any one or more of torque on bit, weight on bit, drill bit accelerations, rotations per minute, depth of cut, and rate of penetration.

Implementation #11: The system of Implementation #9 or 10, wherein the stress representatives are generated based on drill bit vibrations; and wherein the strain representatives are generated based on rate of penetration.

Implementation #12: The system of Implementation #11, wherein the drill bit vibrations are obtained via sensors at the drill bit including accelerometers, strain gauges, gyroscopes, magnetometers, or any combination thereof.

Implementation #13: The system of any one or more of Implementation #9-12, wherein the one or more elastic properties of the formation are determined based on Hooke's law.

Implementation #14: The system of any one or more of Implementation #9-13 further comprising; obtaining reference elastic properties of the formation to be drilled by the drill bit; calibrating the bit-rock interaction model with the reference elastic properties; and outputting, the parameters for the drilling data.

Implementation #15: A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor to perform operations comprising: obtaining drilling data of a drill bit while drilling a wellbore in a formation with the drill bit; generating stress representatives and strain representatives via a bit-rock interaction model configured with parameters to map the drilling data; and determining one or more elastic properties of the formation based on the stress representatives and the strain representatives.

Implementation #16: The non-transitory, computer-readable medium of Implementation #15, wherein the drilling data includes torque on bit, weight on bit, drill bit accelerations, rotations per minute, depth of cut, and rate of penetration.

Implementation #17: The non-transitory, computer-readable medium of Implementation #15 or 16, wherein the stress representatives are generated based on drill bit vibrations; and wherein the strain representatives are generated based on rate of penetration.

Implementation #18: The non-transitory, computer-readable medium of Implementation #17, wherein the drill bit vibrations are obtained via sensors at the drill bit including accelerometers, strain gauges, gyroscopes, magnetometers, or any combination thereof.

Implementation #19: The non-transitory, computer-readable medium of any one or more of Implementation #15-18 further comprising; obtaining reference elastic properties of the formation to be drilled by the drill bit; calibrating the bit-rock interaction model with the reference elastic properties; and outputting, the parameters for the drilling data.

Implementation #20: The non-transitory, computer-readable medium of Implementation #19 further comprising: inputting the drilling data and the parameters into the bit-rock interaction model to generate the stress representatives and the strain representatives.

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.