CRITICAL DOWNHOLE TORQUE OF A DRILLING SYSTEM AND BIT DESIGN TO MITIGATE HFTO

Abstract

Disclosed herein are embodiments of a method and system for determining a critical torque on bit to reduce the occurrence of high frequency torsional oscillation (HFTO). In one embodiment, a method includes detecting at least one drilling parameter of an offset drill bit for a type of drilling system during an offset drilling operation using at least one in-bit sensor; determining a critical torque on bit (TOB) that is to excite HFTO of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system; measuring, for a current drilling operation, a current TOB and a current weight on bit (WOB) of a current drill bit having a same type of drilling system as the type of drilling system for the offset drilling operation; determining whether current TOB exceeds critical TOB; and mitigating the HFTO for the current drill bit.

Description

TECHNICAL FIELD

The disclosure generally relates to drill bit design and selection and, more particularly, to drill bit selection to mitigate high frequency torsional oscillations (HFTO) that occur during drilling operations.

BACKGROUND

Boreholes for oil and gas wells are typically drilled by a rotary drilling process. Drill bits are tools configured to produce a borehole through layers of earth by rotary drilling techniques. A drill bit is installed on the lower end of a drill string and rotated. A drill bit may be rotated by top drive control equipment that imparts rotation to the entire drill string, or alternatively, by a downhole mud motor or other device that selectively rotates the drill bit without rotation of the drill string (sliding mode). Subsurface layers may be mechanically removed by cutter elements (also referred to as “cutters”) on the drill bit that are positioned to grind, cut, or otherwise fracture solid material into cuttings that are circulated to the surface by drilling fluid.

Drill bits are frequently classified based in part on the type of cutters. Roller-cone bits utilize tooth-shaped cutter on two or more rollers that rotate across the end surface of the borehole as the bit rotates. Fixed-cutter bits utilize cutters in the form of blades with hard cutting element, typically natural or synthetic diamond, to dislodge formation material by grinding or scraping. Hybrid drill bits combine fixed-cutters and roller-cone cutters.

Any portion of the drill string including the drill bit and/or pipe components that degrades or fails during drilling must be extracted from the borehole and replaced. Since the drill string may weigh hundreds of tons and extend for thousands of feet in a frequently non-linear path, the extraction and replacement process can be very expensive and time consuming. Drill bit durability is therefore a significant factor for overall efficiency of a borehole drilling process. High frequency torsional oscillations (HFTO) occurs frequently in drilling and can damage downhole tools and affect drilling efficiency.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 is a partial cross-sectional view of an example wellbore system, according to some embodiments.

FIG. 2A-D are graphs illustrating data collected to illustrate that torque on bit may lead to HFTO.

FIG. 3A-3D are graphs illustrating data collected from on bit sensors from a drilling run, illustrating data points where HFTO occur.

FIG. 4 is a graph illustrating a stability map of downhole weight on bit and torque on bit based on the data shown in FIG. 3A-3D.

FIG. 5 is a graph illustrating a stability map of scaled WOB and TOB from the data shown in FIG. 3A-3D.

FIG. 6 is a graph illustrating scaled WOB versus TOB and bit response which may be used to determine bit design and selection to mitigate HFTO.

FIG. 7 is a graph illustrating data taken from a drilling run a lateral wellbore section at several drilling depths.

FIG. 8 is a graph illustrating data taken from a drilling run of a different wellbore section than FIG. 7 at several drilling depths.

FIG. 9 is a flowchart that illustrates a method for bit design and selection to mitigate HFTO according to some embodiments.

FIG. 10 is a flowchart that illustrates a method for real-time HFTO mitigation, according to some embodiments.

FIG. 11 is an example computer which may be used to implement certain aspects of the methods described herein, according to some embodiments.

DETAILED DESCRIPTION

The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to selecting and/or designing a drill bit to mitigate high frequency torsional oscillations (HFTO) which occur during drilling operations. Although various methods are currently available to mitigate/reduce HFTO, HFTO still causes several problems and disfunctions in drilling.

Drilling systems may be classified into groups according to various sections of a wellbore according to a length and placement of a downhole section, stabilizer placement, and pipe diameter of a wellbore section, such as a group used for a horizontal wellbore section, a group used for a curve section of a wellbore, and a group used for an intermediate system. Each BHA may include at least a drill bit, a stabilizer above the bit, and a motor and/or rotary steerable system above the stabilizer. For a given drilling system, there is generally a critical torque value and resonating frequency associated with the drilling system. For example, the drilling system for a horizontal section may have a different critical torque and resonating frequency than a drilling system for a curved section. HFTO is related primarily with a lower part of the BHA, such as parts positioned below a motor or motor system. HFTO occurs when a high enough reactive torque from a bit is applied to the drilling system. Any dynamic disturbance of a high bit reactive torque may lead to HFTO of the bottom hole assembly (BHA). To mitigate HFTO, traditional methods have included modifying the weight on bit (WOB) and bit rotational speed (RPM), but these traditional methods do not necessarily affect the torque on bit (TOB) and as such, are not always successful in mitigating HFTO.

Several factors influence the torque on bit, including depth and inclination of the well. For example, the torque increases with the depth of the wellbore and the inclination or angle at which the well is drilled. The increased weight of the drill string and the lateral forces exerted by gravity contribute to higher torque. Drilling parameters such as weight on bit (WOB) and the drilling fluid properties can also affect the torque on bit. Higher weight on bit or denser drilling fluid can increase the torque. Drill string properties such as the length, diameter, and type of drill pipe used in the drill string can influence the torque. Longer and larger-diameter drill pipes may result in higher torque. Formation characteristics such as the hardness, type of rock, and presence of any interbedded formations can affect the torque required to penetrate the formation. Harder formations generally require higher torque.

Controlling TOB may avoid excessive stress on the drill string and the downhole tools. Excessive torque can lead to equipment failure, including drill pipe twist-offs or damage to the drill bit. Monitoring and adjusting the drilling parameters, WOB, and using appropriate drilling fluids can help optimize the TOB and ensure efficient and safe drilling operations.

Disclosed herein is a method and system for designing and/or selecting a drill bit to mitigate HFTO that may occur during drilling operations. The method and system rely on determining HFTO, a torsional vibration that is induced by a torque generated at bit/rock interaction, and determining a critical TOB (TOBc) below which HFTO may be mitigated. The disclosed methods consider various factors and observations, including that downhole TOB, not WOB, acts as an on/off switch to trigger HFTO. For example, no HFTO is found to occur for certain bits, such a roller cone bit, where WOB is usually high. By mapping TOB versus rotations per unit of time, e.g. rotations per minute (RPM), there is a threshold above which HFTO occurs and below the threshold there is no HFTO. This will be shown and described herein. As a result of reviewing TOB versus RPM, studies show that a polycrystalline diamond compact (PDC) bit will have less TOB (and a higher drilling efficiency) will result in less HFTO.

In some studies, HFTO occurred in carbonate formations and not in shale formations, due to the stronger effective strength of carbonate than that of shale. Shale strength is usually more anisotropic than carbonate. Shale is much stronger in a direction perpendicular to bedding plane. but much weaker along bedding plane, so the effective shale strength may be much lower than continuous circulation system (CCS). In addition, if the shale was drilled with water based fluid and the shale is water reactive, the shale effective strength may be reduced because of the interaction between water and shale during shear failure process. In other words, it is the effective strength, not the UCS/CCS along, that trigger HFTO. In some single cutter tests, some 3D shaped cutters needed less cutting force than round plane cutter. Bits with such cutters will generate less TOB and therefore, less HFTO. As a result, testing indicated that certain cutter shapes helped to mitigate HFTO.

Disclosed herein are methods to mitigate HFTO by determining a critical torque on bit (TOBc) that excites HFTO. The critical TOB may be scaled or normalized by torsional stiffness of the system. Critical TOB or scaled critical TOB (TOBc) may be determined by measurements taken by in bit sensors, such as, e.g., cerebro-force in bit sensors, during drilling. Once scaled critical TOB is determined for a class or group of drilling systems, a drill bit may be selected and/or redesigned so that generated TOB is less than critical TOB in order to mitigate HFTO. In some embodiments, the on-bit sensors collect and relay data in real time. Certain design elements of the drill bit may be modified in real time while drilling to improve during real-time operations. In other embodiments, certain drilling factors, such as WOB, may be adjusted to mitigate HFTO in real-time. And in still other embodiments, a drill bit may be designed/redesigned and selected before beginning drilling or for use in subsequent drilling operations. As a result, dysfunctions caused by HFTO are reduced and the overall costs of drilling may be reduced, in addition to an improvement to drilling efficiency.

Example System

FIG. 1 depicts a partial cross-sectional view of an example wellbore system 100, according to some embodiments. The wellbore system 100 is configured to collect data during drilling operations. Wellbore system 100 includes a drilling rig 102 comprising various mechanical and electronic systems, subsystems, devices, and components configured to lower, rotate, and otherwise operate a drill string. The drill string includes, among other components, a section of drilling pipe 104 coupled at one end to a top drive (not depicted) within drilling rig 102. Drilling pipe 104 is coupled at the other end to a bottom hole assembly (BHA) 115 that includes a drill bit 110 on its lower/downhole end. BHA 115 further includes a steering actuator 116 configured either as a rotary steering system or motor driven device to determine the drilling direction by adjusting the direction of drill bit 110.

Drill bit 110 may be actuated by rotation imparted to the drill string by the top drive within drilling rig 102. A borehole 106 having a cylindrically contoured borehole wall 108 is formed as drill bit 110 is rotated within a subterranean region 140. As drill bit 110 rotates, a pump (not depicted) within drilling rig 102 pumps drilling fluid, sometimes referred to as “drilling mud,” downward through a drilling fluid conduit 114 that is formed within the various sections of the drill string. The drilling fluid cools and lubricates drill bit 110 as it exits drill bit 110.

BHA 115 in this embodiment further includes a drill collar 112 that provides downward weight force on drill bit 110 for drilling. Drill collar 112 comprises one or more thick-walled cylinders machined from various relatively high density metals or metallic alloys. While not expressly depicted in FIG. 1, drill collar 112 may comprise multiple distinct cylindrical members that are interconnected using releasable connections such as threaded connectors integral to the individual drill collar members.

Drill collar 112 is further configured to support a logging tool assembly 117 that includes at least one on bit sensor 120 for collecting data and taking measurements during the drilling operation within subterranean region 140. Tool assembly 117 further includes information processing and communication module 118 for transmitting the data and measurements via a telemetry link 125 to a data processing system 130. Telemetry link 125 may include transmission media and endpoint interface components configured to employ a variety of communication modes. The communication modes may comprise different signal and modulation types carried using one or more different transmission media such as acoustic, electromagnetic, and optical fiber media.

During drilling operations, information from the logging tool assembly 117 that includes the at least one on bit sensor 120 are processed by data processing system 130. Data may be collected for a group of drilling runs, including 1) runs using a rotary steerable system (RSS) or motor assisted RSS. 2) runs using a motor only, 3) vertical runs, 4) horizontal runs, and 5) curve runs.

The bit motion information collected during drilling operation and transmitted to data processing system 130. The rotational speed and acceleration information measured by sensors 119 and 121 may be recorded downhole such as by module 118 and transmitted continuously or intermittently to data processing system 130. As depicted and described in further detail with reference to FIGS. 2-9, the HFTO mitigation process includes determining critical torque for each type of drilling system and then making adjustments to the WOB or bit design to mitigate HFTO caused by torque exceeding the determined critical torque on bit (TOBc). Selecting a drill bit design may include adjustment or redesigning structural attributes such as bit size, number of blades, design pattern, cutter back rake angle, cutter chamfer size, etc. Structural attributes may be structures such as blades and cutters and numbers and/or other characteristics of the structures on a drill bit. Structural attributes may also be locations and orientations of structures on a drill bit including relative positioning among different structures on a drill bit.

Data processing system 130 may comprise processing components configured to process bit motion information collected from the sensors 119, 120 and 121 during drilling operation and calculate a critical torque on bit value (TOBc) for each of the group of runs. The data collected from a plurality of drilling runs is used to develop a general stability map to mitigate HFTO in operation. The stability map will then be used in embodiments for mitigating HFTO in real time operations and to develop a general design criterion to mitigate HFTO for subsequent drilling operations. The collected data may include at least (TOB, WOB, rotations per measure of time, such as RPM, and rate of penetration (ROP)). For each drilling system run, the following data is needed from the logging tool assembly 117 or from data collected from the logging tool assembly 117 and at least one on bit sensor 120 and sensors 119 and 121 when developing bit design criteria to mitigate HFTO. A drilling distance where HFTO is triggered is needed. The bit dull severity automated dull grade (ADG) file is then used to estimate bit wear. The effective critical depth of cut (DOC) is calculated considering cutter wear. The bit drilling efficiency is then calculated at the drilling distance where HFTO occurred. Also collected during each drilling run is gamma rays (GR, radioactivity emitted from the formation) and mechanical specific energy (MSE).

BHAs may vary in size. As a result, to eliminate any effect the bit size may have on the TOB and WOB data reviewed for selecting a drill bit design to mitigate HFTO, TOB and WOB may be scaled. TOB may be scaled using BHA's torsional stiffness to eliminate bit size effect, and the WOB is scaled using BHA's axial stiffness. Data from the plurality of drilling runs, including RPM, scaled TOB, and scaled WOB versus scaled TOB, is used to develop a stability map used in bit design/redesign and for determining adjustments needed to mitigate HFTO. For a BHA with outer diameter D and inner diameter d, and a length L, the axial stiffness (K_a) of the BHA is calculated according to Equation (1):

$\begin{array}{c}\mathrm{Eq}.\left(l\right)\end{array}$ $\mathrm{K\_a}=\mathrm{EA}/L\mathrm{where}E\mathrm{is}\mathrm{Young}\text{'}s\mathrm{module}\mathrm{and}A=0.25\pi \left(D\bigwedge 2-d\bigwedge 2\right)$

The torsional stiffness (K_t) of the BHA is calculated according to Equation (2):

$\begin{array}{c}\mathrm{Eq}.\left(2\right)\end{array}$ $\mathrm{K\_t}=\mathrm{GJ}/L=\mathrm{where}G\mathrm{is}\mathrm{shear}\mathrm{module}\mathrm{and}J=\pi /32\left(D\bigwedge 4-d\bigwedge 4\right)$

The scaled WOB (WOBs) and scaled TOB (TOBs) are then calculated according to Equations (3) and (4):

$\begin{array}{cc}\mathrm{WOBs}=\mathrm{WOB}/\mathrm{K\_a}& \mathrm{Eq}.\left(3\right)\end{array}$ $\begin{array}{cc}\mathrm{TOBs}=\mathrm{TOB}/\mathrm{K\_t}& \mathrm{Eq}.\left(4\right)\end{array}$

Because length L is usually different in different drilling systems, WOB and TOB can be scaled according to the following equations (5) and (6):

$\begin{array}{cc}\mathrm{WOBs}=\mathrm{WOB}/A& \mathrm{Eq}.\left(5\right)\end{array}$ $\begin{array}{cc}\mathrm{TOBs}=\mathrm{TOB}/J& \mathrm{Eq}.\left(6\right)\end{array}$

wherein WOB and TOB are measured by sensors on bit. A scaled TOB (TOBs) can be considered as a critical torque which may be applied to different drilling systems.

Once data is collected from a plurality of drilling runs, data output, such as stability map of FIG. 6, is generated and a bit for a future downhole drilling run may be designed, selected, and constructed based on a correlation between critical depth of cut (CDOC), drilling, and TOB, and the occurrence of HFTO, and a bit design criteria is developed to mitigate HFTO. In some examples, the at least one on bit sensor 120 collects data in real time, and the data and stability maps may be reviewed and adjustments may be made to mitigate HFTO for the current drilling process using the current drill bit without removing the current drill bit or drill string from the wellbore. In some examples, mitigating the HFTO may include reducing the current WOB until the current TOB is below the critical TOB in the current drilling operation. In other examples, mitigating the HFTO may include changing design features of the current drill but while downhole. This may include moving elements of the current drill bit to change a depth of cut (DOC) control elements or moving cutting elements that will move roughly axial to engage the formation more or less than the surrounding features to change overall cutting structure efficiency.

Examples of analysis of the data as part of embodiments of the method are shown and described in FIG. 2-3. This data and graphics are reviewed to develop stability map to mitigate HFTO in operation and bit design selection criteria.

FIG. 2A-D depict graphs illustrating how cutter impact torque may cause HFTO where a hard stone is located at the hole bottom. FIG. 2A illustrates torque versus time and illustrates data taken from an impact torque with a duration of about 0.01 seconds applied to a BHA. In this example, the impact torque may come from a cutter/rock interaction. FIG. 2B illustrates a frequency response up to 200 Hz for the impact torque with a duration of about 0.01 seconds shown in FIG. 2A. FIG. 2C illustrates 5 impact torques with a duration of about 0.01 seconds applied to the BHA. For a bit with 5 blades, 5 impact torques may be created in one bit revolution, where 5 cutters may hit a hard rock 5 times. FIG. 2D illustrates a frequency response up to 200 Hz for the 5 impact torques with a duration of about 0.01 seconds shown in FIG. 2C. High energy input to the BHA may be high enough to trigger HFTO.

FIG. 3A-3D depict graphs illustrating data collected from a logging tool and on bit sensor, such as logging tool assembly 117 and sensor 120. FIG. 3A illustrates a set of graphs 300 providing an overview of all data collected from all of the drilling runs, illustrating RPM versus drilling depth; WOB versus drilling depth; and TOB versus drilling depth. FIG. 3B illustrates a more detailed view at a first isolated portion of drilling depth. FIG. 3C illustrates a more detailed view at a second isolated portion of drilling depth. FIG. 3D illustrates a more detailed view at a third isolated portion of drilling depth.

FIGS. 4 and 5 depict graphs illustrating stability maps. The stability map of FIG. 4 illustrates non-scaled WOB versus TOB. A zone 402 illustrates an area where no HFTO is triggered by the TOB. Data points 406 illustrate points where HFTO is triggered. This stability map may be applied to a same drilling system with different types of drill bits. The stability map of FIG. 5 illustrates scaled WOB (WOBs) versus scaled TOB (TOBs) which eliminates any effect for bit size. A zone 502 illustrates an area where no HFTO is triggered by the TOB. Data points 506 illustrate points where HFTO is triggered. The map of FIG. 5 may be applied to different drilling systems with different types of drill bits. These stability maps may be reviewed in embodiments for mitigating HFTO in real time operations and to develop a general design criterion to mitigate HFTO.

FIG. 6 depicts a graph illustrating scaled WOB such as from the data represented in FIG. 3A-3D versus TOB. A zone 602 illustrates an area where no HFTO is triggered by the TOB. Zone 604 illustrates that an improved bit design extends an operating zone with no HFTO. Data points 606 illustrate points where HFTO is triggered. Line 610 represents bit response from calculations, such as from the data represented in FIG. 3A-3D, which can extend an operation zone and mitigating HFTO using a same drill bit by managing/reducing the current WOB until the current TOB is below the critical TOB in the current drilling.

FIG. 7 depicts a graph illustrating data taken from a lateral wellbore section at several drilling depths, including RPM, WOB, TOB, and Gamma. Data area 710 identifies the critical TOB at about 9000 ft-lbs. and in this example, the critical TOB is triggered by high rock strength of the formation.

FIG. 8 depicts a graph illustrating data taken at several drilling depths from another lateral wellbore section at several drilling depths from a different type of drilling system. The data includes RPM, WOB, TOB, and Gamma. Data area 810 identifies the critical TOB at about 6000 ft-lbs. in this example. This example illustrates how even though WOB stays relatively constant, the TOB is changing.

Example Operations

FIG. 9 depicts a flowchart of one example of a method 900 for mitigating HFTO during a drilling operation according to some embodiments. Operations of the method 900 can be performed by software, firmware, hardware, or a combination thereof. Operations of the method 900 are described in reference to the example wellbore system 100 of FIG. 1 The operations of method 900 start at block 902.

At block 902, a drill string having at least one bottom hole assembly (BHA) with at least one on-bit sensor is deployed within a wellbore. At a block 904, the at least one on-bit sensor collects data and at least one drilling parameter of an offset drill bit. The data may be collected in real time. The drilling parameter may be at least one of drilling depth, depth of cut, angle of cut, type of formation, bit dull severity, rotations per measure of time, WOB, TOB, bend on bit (BOB), and rate of penetration.

At a block 906, determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit is determined based on the at least one drilling parameter and based on the type of drilling system. Determining the critical TOB may include determining a drilling depth at which HFTO occurred, calculating a scaled WOB, and calculating a scaled TOB. The scaled WOB may be calculated by dividing the measured WOB by a calculated axial stiffness of the BHA. The scaled critical TOB may be calculated by dividing the determined critical TOB by a calculated torsional stiffness of the BHA. Considering the scaled WOB and scaled critical TOB may remove the effect of bit size on the drill bit design.

At a block 908, measurements for a current drilling operation are taken, including, a current TOB and a current weight on bit (WOB) of a current drill bit having a same type of drilling system as the type of drilling system for the offset drilling operation. At a block 910, the current TOB is compared with the critical TOB to determine whether the current TOB exceeds the critical TOB.

At a block 912, in response to determining that the current TOB exceeds the critical TOB, the current drilling operation is adjusted to mitigate the HFTO for the current drill bit for the current drilling operation. Adjusting the current drilling operation to mitigate the HFTO may include reducing the current WOB until the current TOB is below the critical TOB in the current drilling operation. Adjusting the current drilling operation to mitigate the HFTO may also include adjusting the drill bit design while the drill bit remains downhole in the wellbore. In some examples, certain elements of the bit design may be adjusted or moved, including bit height and angle settings, and other elements which may affect depth of cut (DOC) or affect axial movement to engage the formation.

FIG. 9 is annotated with a series of numbers 902-912. These numbers represent stages of operations. Although these stages are ordered for this example, the stages illustrate one example to aid in understanding this disclosure and should not be used to limit the claims. Subject matter falling within the scope of the claims can vary with respect to the order and some of the operations.

FIG. 10 depicts a flowchart of another example of a method 1000 for preparing bit design and selection to mitigate HFTO during a drilling operation according to some embodiments. Operations of the method 1000 can be performed by software, firmware, hardware, or a combination thereof. Operations of the method 1000 are described in reference to the example wellbore system 100 of FIG. 1 The operations of method 1000 start at block 1002.

At block 1002, a drill string having at least one bottom hole assembly (BHA) with at least one on-bit sensor is deployed within a wellbore for collecting data. At a block 1004, the at least one on-bit sensor detects at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit. The in-bit sensor may collect and transmit data to a processor, such as data processing system 130, in real time. Drilling parameters of the offset drill bit may include drilling depth, depth of cut, angle of cut, type of formation, bit dull severity, rotations per measure of time, WOB and TOB, and rate of penetration.

At a block 1006, data collected by the at least one on-bit sensor is reviewed to determine a critical TOB that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system. Determining the critical TOB includes determining a drilling depth at which HFTO occurred during the offset drilling operation.

At a block 1008, the WOB and rotations per unit of time (e.g., RPM) of the offset drill bit during the offset drilling operation is determined from data collected by the at least one in-bit sensor.

At a block 1010, a drill bit design is selected based on the determined critical TOB, WOB, and rotations per unit of time. In some embodiments, selecting a drill bit design includes considering scaled critical TOB and a scaled WOB. Selecting the drill bit design may include reviewing a stability map representing TOB versus WOB and including HFTO trigger points. In some examples, the stability map is plotted based on scaled TOB and scaled WOB, which eliminates the effect of drill bit size on the drill bit design.

At a block 1012, a drill bit for use in a drilling operation is constructed according to the selected drill bit design.

FIG. 10 is annotated with a series of numbers 1002-1012. These numbers represent stages of operations. Although these stages are ordered for this example, the stages illustrate one example to aid in understanding this disclosure and should not be used to limit the claims. Subject matter falling within the scope of the claims can vary with respect to the order and some of the operations.

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 of the methods 900 or 1000 may be performed in parallel or concurrently. 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.

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 block

Example Computer

FIG. 11 depicts an example computer 1100, according to some embodiments. The computer 1100 may be used to perform at least a part of the functions of the data processing system 130 shown in in FIG. 1. A computer 1100 includes a processor 1101 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 1100 includes a memory 1107. The memory 1107 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 1100 also includes a bus 1103 and a network interface 1105.

The system also includes a controller 1111. The controller 1111 may perform one or more operations depicted in FIG. 11. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 1101. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 1101, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 11 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 1101 and the network interface 1105 are coupled to the bus 1103. Although illustrated as being coupled to the bus 1103, the memory 1107 may be coupled to the processor 1101.

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.

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.

EXAMPLE EMBODIMENTS

Aspects disclosed herein include:

Aspect A: A method comprising: detecting at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit; determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system; measuring, for a current drilling operation, a current TOB and a current weight on bit (WOB) of a current drill bit having a same type of drilling system as the type of drilling system for the offset drilling operation; determining whether the current TOB exceeds the critical TOB; and in response to determining that the current TOB exceeds the critical TOB, mitigating the HFTO for the current drill bit for the current drilling operation.

Aspect B: A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor to perform operations comprising: detecting at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit; determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system; determining a weight on bit (WOB) and rotations per unit of time of the offset drill bit during the offset drilling operation; selecting a drill bit design based on the determined critical TOB, WOB, and rotations per unit of time; and constructing a drill bit for use in a drilling operation according to the selected drill bit design.

Aspect C: A system comprising: a processor; and a non-transitory computer-readable medium having instructions stored thereon that are executable by the processor to cause a drill bit design apparatus to: detect at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit; determine a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system; determine a weight on bit (WOB) and rotations per unit of time of the offset drill bit during the offset drilling operation; and select a drill bit design for construction of a drill for use in a drilling operation within a wellbore based on the determined critical TOB, WOB, and rotations per unit of time.

Aspect D: A method comprising: detecting at least one drilling parameter of a previous drill bit during a previous drilling operation of a wellbore using at least one in-bit sensor in the previous drill bit; determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation of the previous drill bit during drilling based on the at least one drilling parameter and based on a class of drilling; and developing a drill bit design criteria to mitigate high frequency torsional oscillations (HFTO), based at least in part on the determined critical bit on torque such that a torque of a subsequent drill bit during the subsequent drilling operation is less than the critical TOB; and constructing the subsequent drill bit for use in a subsequent drilling operation in a wellbore based on the developed drill bit design criteria.

Aspect E: measuring, for a drilling operation, a torque on bit (TOB) and weight on bit (WOB) of a drill bit in a drilling system; identifying whether high frequency torsional oscillations (HFTO) occurred at a first drilling depth; in response to identifying that HFTO occurred at the first drilling depth, recording the TOB as a critical TOB; and adjusting WOB and rotations per unit of time for the drilling operation to reduce TOB not exceeding the critical TOB at a second drilling depth.

Aspects A, B, C, D and E may have one or more of the following additional elements in combination:

Element 1: wherein mitigating the HFTO includes reducing the current WOB until the current TOB is below the critical TOB in the current drilling operation.

Element 2: wherein mitigating the HFTO includes adjusting a design of the current drill bit while the current drill bit remains downhole in the wellbore.

Element 3: wherein adjusting the drill bit design while the current drill bit remains downhole includes moving elements of the current drill bit to change a depth of cut.

Element 4: wherein moving elements of the current drill bit include moving cutting elements to affect axial movement of the current drill bit.

Element 5: wherein the at least one drilling parameter of an offset drill bit is one of drilling depth, depth of cut, angle of cut, type of formation, bit dull severity, rotations per measure of time, WOB, TOB, bend on bit (BOB) and rate of penetration.

Element 6: wherein determining the critical TOB comprises determining a drilling depth at which HFTO occurred, calculating a scaled WOB, and calculating a scaled TOB.

Element 7: wherein calculating the scaled WOB includes calculating an axial stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled WOB is a function of measure WOB and the axial stiffness of the bottom hole assembly.

Element 8: wherein calculating the scaled TOB includes calculating a torsional stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled TOB is a function of measure TOB and the torsional stiffness of the bottom hole assembly.

Element 9: wherein selecting a drill bit design includes reviewing a stability map representing critical TOB versus WOB and including HFTO trigger points.

Element 10: wherein the stability map represents scaled critical TOB and scaled WOB.

Element 11: wherein the instructions stored on the processor to cause the drill bit apparatus to determine the critical TOB include instructions to cause the drill bit apparatus to, determine a drilling depth at which HFTO occurred, calculate a scaled WOB, and calculate a scaled critical TOB.

Element 12: wherein the instructions to cause the drill bit design apparatus to calculate the scaled WOB includes instructions to cause the drill bit design apparatus to calculate an axial stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled WOB is a function of measure WOB and the axial stiffness of the bottom hole assembly, and wherein the instructions to cause the drill bit design apparatus to calculate the scaled critical TOB includes instructions to cause the drill bit design apparatus to calculate a torsional stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled critical TOB is a function of measure critical TOB and the torsional stiffness of the bottom hole assembly.

Element 13: wherein the drill bit design criteria to mitigate the HFTO includes adjusting the previous drill bit while the drill bit remains downhole based on the class of drilling such that a torque of the drill bit during the subsequent drilling operation is less than the critical TOB.

Element 14: wherein the drill bit design criteria to mitigate HFTO includes considering drilling efficiency of the previous drill bit.

Element 15: wherein developing a drill bit design criteria to mitigate the HFTO includes reviewing critical TOB versus WOB and data points representing HFTO trigger points.

Element 16: further comprising selecting and constructing a drill bit design for a future drilling operation based on at least the critical TOB.

Element 17: wherein the drilling system includes a processor and the processor is configured to identify whether the HFTO occurred at the first drilling depth, record the TOB as a critical TOB, and determine values for which to adjust the WOB and rotations per unit of time to reduce TOB to not exceed critical TOB at the second depth.

Claims

1. A method comprising: detecting at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit;determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system;measuring, for a current drilling operation, a current TOB and a current weight on bit (WOB) of a current drill bit having a same type of drilling system as the type of drilling system for the offset drilling operation;determining whether the current TOB exceeds the critical TOB; andin response to determining that the current TOB exceeds the critical TOB, mitigating the HFTO for the current drill bit for the current drilling operation.

2. The method according to claim 1, wherein mitigating the HFTO includes reducing the current WOB until the current TOB is below the critical TOB in the current drilling operation.

3. The method according to claim 1, wherein mitigating the HFTO includes adjusting a drill bit design of the current drill bit while the current drill bit remains downhole in the wellbore.

4. The method according to claim 3, wherein adjusting the drill bit design while the current drill bit remains downhole includes moving elements of the current drill bit to change a depth of cut.

5. The method according to claim 4, wherein moving elements of the current drill bit include moving cutting elements to affect axial movement of the current drill bit.

6. The method according to claim 1, wherein the at least one drilling parameter of an offset drill bit is one of drilling depth, depth of cut, angle of cut, type of formation, bit dull severity, rotations per measure of time, WOB, TOB, bend on bit (BOB) and rate of penetration.

7. The method according to claim 1, wherein determining the critical TOB comprises determining a drilling depth at which HFTO occurred, calculating a scaled WOB, and calculating a scaled TOB.

8. The method according to claim 7, wherein calculating the scaled WOB includes calculating an axial stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled WOB is a function of measure WOB and the axial stiffness of the bottom hole assembly.

9. The method according to claim 7, wherein calculating the scaled TOB includes calculating a torsional stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled TOB is a function of measure TOB and the torsional stiffness of the bottom hole assembly.

10. A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor to perform operations comprising: detecting at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit;determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system;determining a weight on bit (WOB) and rotations per unit of time of the offset drill bit during the offset drilling operation;selecting a drill bit design based on the determined critical TOB, WOB, and rotations per unit of time; andconstructing a drill bit for use in a drilling operation according to the selected drill bit design.

11. The non-transitory, computer-readable medium according to claim 10, wherein the at least one drilling parameter of an offset drill bit is one of drilling depth, depth of cut, angle of cut, type of formation, bit dull severity, rotations per measure of time, WOB, BOB, TOB, and rate of penetration.

12. The non-transitory, computer-readable medium according to claim 10, wherein determining the critical TOB comprises determining a drilling depth at which HFTO occurred, calculating a scaled WOB, and calculating a scaled critical TOB.

13. The non-transitory, computer-readable medium according to claim 12, wherein calculating the scaled WOB includes calculating an axial stiffness of a bottom hole assembly of a same type of drilling system as the type of drilling system for the offset drilling operation and the scaled WOB is a function of measure WOB and the axial stiffness of the bottom hole assembly.

14. The non-transitory, computer-readable medium according to claim 12, wherein calculating the scaled critical TOB includes calculating a torsional stiffness of a bottom hole assembly of a same type of drilling system as the type of drilling system for the offset drilling operation and the scaled critical TOB is a function of measure critical TOB and the torsional stiffness of the bottom hole assembly.

15. The non-transitory, computer-readable medium according to claim 10, wherein selecting a drill bit design includes reviewing a stability map representing critical TOB versus WOB and including HFTO trigger points.

16. The non-transitory, computer-readable medium according to claim 15, wherein the stability map represents scaled critical TOB and scaled WOB.

17. A system comprising: a processor; anda non-transitory computer-readable medium having instructions stored thereon that are executable by the processor to cause a drill bit design apparatus to: detect at least one drilling parameter of an offset drill bit for a type of drilling system of a number of drilling systems during an offset drilling operation of a wellbore using at least one in-bit sensor in the offset drill bit;determine a critical torque on bit (TOB) that is to excite a high frequency torque oscillation (HFTO) of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system;determine a weight on bit (WOB) and rotations per unit of time of the offset drill bit during the offset drilling operation; andselect a drill bit design for construction of a drill for use in a drilling operation within a wellbore based on the determined critical TOB, WOB, and rotations per unit of time.

18. The system according to claim 17, wherein the instructions stored on the processor to cause the drill bit design apparatus to determine the critical TOB include instructions to cause the drill bit design apparatus to, determine a drilling depth at which HFTO occurred,calculate a scaled WOB, andcalculate a scaled critical TOB.

19. The system according to claim 18, wherein the instructions to cause the drill bit design apparatus to calculate the scaled WOB includes instructions to cause the drill bit design apparatus to calculate an axial stiffness of a bottom hole assembly of a same type of drilling system as the type of drilling system for the offset drilling operation and the scaled WOB is a function of measure WOB and the axial stiffness of the bottom hole assembly, andwherein the instructions to cause the drill bit design apparatus to calculate the scaled critical TOB includes instructions to cause the drill bit design apparatus to calculate a torsional stiffness of a bottom hole assembly of the same type of drilling system as the type of drilling system for the offset drilling operation and the scaled critical TOB is a function of measure critical TOB and the torsional stiffness of the bottom hole assembly.

20. A method comprising: detecting at least one drilling parameter of a previous drill bit during a previous drilling operation of a wellbore using at least one in-bit sensor in the previous drill bit;determining a critical torque on bit (TOB) that is to excite a high frequency torque oscillation of the previous drill bit during drilling based on the at least one drilling parameter and based on a class of drilling; anddeveloping a drill bit design criteria to mitigate high frequency torsional oscillations (HFTO), based at least in part on the determined critical torque on bit such that a torque of a subsequent drill bit during the subsequent drilling operation is less than the critical TOB; andconstructing the subsequent drill bit for use in a subsequent drilling operation in a wellbore based on the developed drill bit design criteria.

21. The method according to claim 20, wherein the drill bit design criteria to mitigate the HFTO includes adjusting the previous drill bit while the previous drill bit remains downhole based on the class of drilling such that a torque of the previous drill bit during the subsequent drilling operation is less than the critical TOB.

22. The method according to claim 20, wherein the drill bit design criteria to mitigate HFTO includes considering drilling efficiency of the previous drill bit.

23. The method according to claim 20, wherein developing a drill bit design criteria to mitigate the HFTO includes reviewing critical TOB versus WOB and data points representing HFTO trigger points.

24. A method comprising: measuring, for a drilling operation, a torque on bit (TOB) and weight on bit (WOB) of a drill bit in a drilling system;identifying whether high frequency torsional oscillations (HFTO) occurred at a first drilling depth;in response to identifying that HFTO occurred at the first drilling depth, recording the TOB as a critical TOB; andadjusting WOB and rotations per unit of time for the drilling operation to reduce TOB not exceeding the critical TOB at a second drilling depth.

25. The method of claim 24, further comprising selecting and constructing a drill bit design for a future drilling operation based on at least the critical TOB.

26. The method according to claim 24, wherein the drilling system includes a processor and the processor is configured to identify whether the HFTO occurred at the first drilling depth, record the TOB as a critical TOB, and determine values for which to adjust the WOB and rotations per unit of time to reduce TOB to not exceed critical TOB at the second drilling depth.