Drilling rate drilling operation controller

Abstract

A method can include receiving a maximum depth of cut value for a drill bit that accounts for a bit body forming junction; receiving a total rotational rate value for the drill bit based at least in part on a differential pressure value for a mud motor; generating a rate of penetration value for the drill bit operatively coupled to the mud motor by multiplying the maximum depth of cut value and the total rotational rate value; and operating a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole with the drill bit operatively coupled to the mud motor.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of U.S. Nonprovisional Application No. 16 / 584,730, filed September 26, 2019, entitled “RATE OF PENETRATION DRILLING OPERATION CONTROLLER,” the disclosure of which is incorporated by reference herein. BACKGROUND

[0003] A resource field can be a collection, pool, or group of pools of one or more resources (e.g., oil, gas, petroleum, and natural gas) in a subterranean environment. A resource region can include at least one reservoir. A reservoir can be shaped in a manner that can trap hydrocarbons and can be covered by impermeable or sealed rock. A borehole can be drilled in the environment, in which a well can be formed using the borehole, which can be used to produce hydrocarbons from the reservoir.

[0004] A rig can be a system of components that are operable to form a borehole in an environment, to bring equipment into and out of a borehole in an environment, etc. As an example, a rig can include a system that can be used to drill a borehole and to acquire information about an environment, about a well, etc. A resource field can be a land field, an offshore field, or a land and offshore field. A rig can include components for performing land and / or offshore operations. A rig can be, for example, vessel-based, offshore platform-based, onshore, etc.

[0005] A field plan and / or development can be conducted in one or more phases, which can include an exploration phase (e.g., prospecting, scoping, etc.) that is intended to identify and evaluate an environment, which can include drilling one or more boreholes (e.g., one or more exploration wells, etc.). SUMMARY

[0006] A method can include receiving a maximum cut depth value for a drill bit that accounts for bit body formation engagement; receiving a total rotational rate value for the drill bit that is based at least in part on a differential pressure value for a mud motor; generating a rate of penetration value for the drill bit that is operatively coupled to the mud motor by multiplying the maximum cut depth value and the total rotational rate value; and operating a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit that is operatively coupled to the mud motor. A system can include a processor; a memory accessible to the processor; processor-executable instructions stored in the memory and executable to instruct the system to receive a maximum cut depth value for a drill bit that accounts for bit body formation engagement; receive a total rotational rate value for the drill bit that is based at least in part on a differential pressure value for a mud motor; generate a rate of penetration value for the drill bit that is operatively coupled to the mud motor by multiplying the maximum cut depth value and the total rotational rate value; and operate a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit that is operatively coupled to the mud motor. One or more computer-readable storage media can include processor-executable instructions to instruct a computing system to receive a maximum cut depth value for a drill bit that accounts for bit body formation engagement; receive a total rotational rate value for the drill bit that is based at least in part on a differential pressure value for a mud motor; generate a rate of penetration value for the drill bit that is operatively coupled to the mud motor by multiplying the maximum cut depth value and the total rotational rate value; and operate a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit that is operatively coupled to the mud motor. Various other apparatuses, systems, methods, etc. are also disclosed.

[0007] This Summary is provided to introduce some concepts of a selection of the concepts that will be further described in the detailed description below. This Summary does not intend to identify key or essential features of the claimed subject matter, nor is it intended for use in limiting the scope of the claimed subject matter. BRIEF DESCRIPTION OF DRAWINGS

[0008] The features and advantages of the described implementations can be better understood with reference to the following description and accompanying drawings.

[0009] Figure 1 An example of a device in a geological environment is shown;

[0010] Figure 2 An example of a device and an example of a hole type are shown;

[0011] Figure 3 An example of a system is shown;

[0012] Figure 4 An example of a wellsite system and an example of a computing system are shown;

[0013] Figure 5 An example of a device in a geological environment is shown;

[0014] Figure 6 An example of a graphical user interface is shown;

[0015] Figure 7 An example of a graphical user interface is shown;

[0016] Figure 8 An example of a graphical user interface is shown;

[0017] Figure 9 An example of a graphical user interface is shown;

[0018] Figure 10 An example of a drilling rate engine is shown;

[0019] Figure 11 An example of a graphical user interface is shown;

[0020] Figure 12 An example of a drill bit and an example of a computer aided design drill bit are shown;

[0021] Figure 13 An example of a graphical user interface is shown;

[0022] Figure 14 An example of a drill string in a geological environment and an example of a mud motor apparatus are shown;

[0023] Figure 15 An example of a graphical user interface is shown;

[0024] Figure 16 An example of a graphical user interface is shown;

[0025] Figure 17 An example of a graphical user interface is shown;

[0026] Figure 18 An example of a graphical user interface is shown;

[0027] Figure 19 An example of a graphical user interface is shown;

[0028] Figure 20 An example of a method is shown;

[0029] Figure 21 An example of a method is shown;

[0030] Figure 22 An example of a well construction ecosystem including one or more drilling rate engines is shown;

[0031] Figure 23 An example of a computing system is shown; and

[0032] Figure 24Example components of systems and networked systems are shown. DETAILED DESCRIPTION

[0033] The following description includes the best mode presently contemplated of carrying out the described embodiments. This description should not be taken as limiting the claimed embodiments to a single embodiment presented herein, but rather a general description of the general principles of the described embodiments. The scope of the described embodiments should be determined with reference to the claims.

[0034] Figure 1 Examples of a geological environment 120 are shown. In Figure 1 In particular, the geological environment 120 can be a sedimentary basin including layers (e.g., stratified) that include reservoirs 121 and can be traversed by a fault 123 (e.g., or multiple faults), for example. For example, the geological environment 120 can be equipped with any of a variety of sensors, detectors, actuators, etc. For example, the equipment 122 can include communication circuitry to receive and transmit information regarding one or more networks 125. Such information can include information associated with downhole equipment 124, which can be equipment to acquire information, assist resource recovery, etc. Other equipment 126 can be located away from the well site and include sensing, detecting, transmitting, or other circuitry. Such equipment can include storage and communication circuitry to store and communicate data, instructions, etc. As an example, one or more pieces of equipment can provide measured, collected, communicated, stored, analyzed, etc. data (e.g., for one or more produced resources, etc.). As an example, one or more satellites can be provided for communication, data acquisition, etc. purposes. For example, Figure 1 Satellites in communication with the network 125 are shown, which can be configured for communication, noting that the satellites can additionally or alternatively include circuitry for imaging (e.g., spatial, spectral, temporal, radiometric, etc.).

[0035] Figure 1Also shown is a geological environment 120, which optionally includes equipment 127 and 128 associated with a well, which includes a substantially horizontal portion (e.g., lateral portion) that can be traversed by one or more fractures 129. For example, consider a well in a shale formation, which can include natural fractures, artificial fractures (e.g., hydraulic fractures), or a combination of natural and artificial fractures. As an example, a well can be drilled for a laterally-extending reservoir. In such an example, lateral variations in properties, stresses, etc. can exist, where assessment of such variations can be helpful in planning, operations, etc. to develop the reservoir (e.g., through fracturing, injection, extraction, etc.). As an example, equipment 127 and / or 128 can include components, a system, multiple systems, etc. for fracturing, seismic sensing, seismic data analysis, assessment of one or more fractures, injection, production, etc. As an example, equipment 127 and / or 128 can provide for measurement, collection, communication, storage, analysis, etc. of data, such as production data (e.g., for one or more produced resources). As an example, one or more satellites can be provided for communication, data collection, etc. purposes.

[0036] Figure 1 Also shown are an example of equipment 170 and an example of equipment 180. Such equipment can be a component system, which can be suitable for geological environment 120. Although equipment 170 and 180 are illustrated as being land-based, various components can be suitable for offshore systems (e.g., offshore rigs, etc.).

[0037] Equipment 170 includes a platform 171, a derrick 172, a crown block 173, a rope 174, a traveling block assembly 175, a drawworks 176, and a landing 177 (e.g., catwalk). As an example, rope 174 can be controlled at least in part by drawworks 176, such that traveling block assembly 175 travels in a vertical direction relative to platform 171. For example, by taking in rope 174, drawworks 176 can cause rope 174 to pass through crown block 173, and raise traveling block assembly 175 away from platform 171 toward the sky; however, by allowing rope 174 to pay out, drawworks 176 can cause rope 174 to pass through crown block 173, and lower traveling block assembly 175 toward platform 171. Where traveling block assembly 175 carries pipe (e.g., casing, etc.), motion tracking of traveling block 175 can provide an indication of how much pipe has been deployed.

[0038] A derrick can be a structure used to support a crown block and a traveling block, which is operably coupled to the crown block at least in part by a rope. A derrick can be pyramid-shaped, and provide a suitable strength-to-weight ratio. A derrick can be movable as a unit or in pieces (e.g., assembled and disassembled).

[0039] As an example, a drawworks can include a reel, a brake, a power source, and a complement of auxiliary devices. The drawworks can controllably reel out and take in a rope. The rope can be wound on a crown block and coupled to a traveling block to obtain mechanical advantage in a "block and tackle" or "pulley" fashion. Reeling out and taking in the rope can cause the traveling block (and anything suspended from it) to be lowered into or raised out of a borehole. Reeling out the rope can be driven by gravity, and taking in can be driven by a motor, engine, etc. (e.g., electric motor, diesel engine, etc.).

[0040] As an example, a crown block can include a set of pulleys (e.g., sheaves) that can be located at or near the top of a derrick or mast through which a rope can pass. A traveling block can include a set of sheaves that can move up and down in the derrick or mast by the rope passing into the set of sheaves of the traveling block and the set of sheaves of the crown block. The crown block, the traveling block, and the rope can form a pulley system of the derrick or mast that can allow handling heavy loads (e.g., drill strings, pipe, casing, liner, etc.) to be brought out of or put into a borehole. For example, the rope can be about one centimeter to about five centimeters in diameter, such as a wireline. By using a set of sheaves, such a rope can carry a heavier load than the rope could support as a single strand.

[0041] As an example, a rigger can be a drilling crew member working on a platform attached to a derrick or mast. The derrick can include a platform on which the rigger can stand. As an example, such a platform can be about 10 meters or more above the rig floor. In an operation known as tripping out of hole (TOH), the rigger can wear a safety harness that enables reaching out from the working platform (e.g., catwalk) to reach pipe located at or near the center of the derrick or mast and throw a rope around the pipe and pull it back to its storage location (e.g., fingerboard), for example, until it can be desired to put the pipe back into the borehole. As an example, the rig can include automated pipe-handling equipment such that the rigger controls the machine rather than physically handling the pipe.

[0042] As an example, tripping can refer to the act of pulling equipment out of a borehole and / or putting equipment into a borehole. As an example, the equipment can include a drill string that can be pulled out of a well and / or placed or replaced in a well. As an example, pipe tripping can be performed in the case where a drill bit has become dull or has stopped drilling effectively and needs to be replaced. As an example, tripping equipment out of a borehole can be referred to as pulling out of hole (POOH), and tripping equipment into a borehole can be referred to as running in hole (RIH).

[0043] Figure 2An example of a wellsite system 200 (e.g., located onshore or offshore) is shown. As shown, the wellsite system 200 can include a mud tank 201 for holding mud and other materials (e.g., in the case that the mud can be a drilling fluid), a suction line 203 that serves as an inlet for a mud pump 204 to pump mud from the mud tank 201 to flow to a shaker hose 206, a drawworks 207 for pulling one or more drilling lines 212 with the drawworks, a standpipe 208 that receives mud from the shaker hose 206, a kelly hose 209 that receives mud from the standpipe 208, one or more kelly bushings 210, a traveling block 211, a crown block 213 (see, e.g., crown block 173 of Figure 1 ), a derrick 214 (see, e.g., derrick 172 of Figure 1 ), a kelly 218 or top drive 240, a kelly drive bushing 219, a rotary table 220, a drill floor 221, a swivel 222, one or more blowout preventers (BOPs) 223, a drill string 225, a drill bit 226, a casing head 227, and a flow line 228 that carries mud and other materials to, e.g., the mud tank 201.

[0044] In the example system of Figure 2 , a borehole 232 is formed in a subterranean formation 230 by rotary drilling; note that various example embodiments can also use one or more directional drilling techniques, equipment, etc.

[0045] As shown in the example of Figure 2 , the drill string 225 is suspended within the borehole 232 and has a drill string assembly 250 that includes the drill bit 226 at a lower end thereof. As an example, the drill string assembly 250 can be a bottom hole assembly (BHA).

[0046] The wellsite system 200 can provide for operation of the drill string 225 and other operations. As shown, the wellsite system 200 includes the traveling block 211 and the derrick 214 above the borehole 232. As noted above, the wellsite system 200 can include the rotary table 220, with the drill string 225 passing through an opening in the rotary table 220.

[0047] As shown in the example of Figure 2As shown by way of example, the wellsite system 200 can include a kelly 218 and associated components, or a top drive 240 and associated components. With respect to the kelly example, the kelly 218 can be a square or hexagonal metal / alloy rod with holes drilled therein that serve as a mud flow path. The kelly 218 can be used to transfer rotational motion from the rotary table 220 to the drill string 225 via a kelly drive bushing 219, while allowing the drill string 225 to be lowered or raised during rotation. The kelly 218 can pass through the kelly drive bushing 219, which can be driven by the rotary table 220. As an example, the rotary table 220 can include a main bushing that is operably coupled to the kelly drive bushing 219 such that rotation of the rotary table 220 can turn the kelly drive bushing 219 and thus the kelly 218. The kelly drive bushing 219 can include an interior profile that matches an exterior profile of the kelly 218 (e.g., square, hexagonal, etc.); however, the dimensions are slightly larger so that the kelly 218 can move freely up and down within the kelly drive bushing 219.

[0048] With respect to the top drive example, the top drive 240 can provide the functionality performed by the kelly and rotary table. The top drive 240 can turn the drill string 225. As an example, the top drive 240 can include one or more motors (e.g., electric and / or hydraulic motors) that are connected through appropriate gearing to a small section of pipe called a spool, which in turn can be screwed into a saver sub or the drill string 225 itself. The top drive 240 can be suspended from the traveling block 211, so the rotary mechanism can move freely up and down the derrick 214. As an example, the top drive 240 can allow drilling with more joints of pipe than the kelly / rotary table method.

[0049] In Figure 2 As an example, the mud tank 201 can hold mud, which can be one or more types of drilling fluid. As an example, a wellbore can be drilled to produce fluid, inject fluid, or both (e.g., hydrocarbons, minerals, water, etc.).

[0050] In Figure 2In the example of FIG. 2, drill string 225 (e.g., including one or more downhole tools) can be composed of a series of threaded together pipes to form a long pipe with drill bit 226 at the lower end of the long pipe. As drill string 225 is advanced into the borehole for the purpose of drilling a well, at some point in time prior to or concurrent with drilling, mud can be pumped by pump 204 from mud tank 201 (e.g., or other source) via lines 206, 208, and 209 to a port of kelly 218, or for example, to a port of top drive 240. The mud can then flow out of a port on drill bit 226 via a channel (e.g., multiple channels) in drill string 225 (see, e.g., directional arrows). As the mud exits drill string 225 via the port in drill bit 226, it can then circulate up the annulus between the outer surface of drill string 225 and the surrounding wall (e.g., open hole borehole, casing, etc.), as indicated by directional arrows. In this manner, the mud lubricates drill bit 226 and carries thermal energy (e.g., friction or other energy) and formation cuttings to the surface, where the mud (e.g., and cuttings) can be returned to mud tank 201, for example, for recirculation (e.g., for processing to remove cuttings, etc.).

[0051] The mud pumped into drill string 225 by pump 204, upon exiting drill string 225, can form a mud cake lining the borehole, which can reduce friction between drill string 225 and the surrounding wall (e.g., borehole, casing, etc.), among other functions. The reduction in friction can facilitate advancing or retracting drill string 225. During drilling operations, the entire drill string 225 can be pulled out of the borehole and optionally replaced with, for example, a new or sharp drill bit, a smaller diameter drill string, etc. As noted above, the act of pulling or lowering the drill string into the well is referred to as tripping. Depending on the direction of the trip, the trip can be referred to as a trip in or a trip out, or a trip down or a trip in.

[0052] As an example, consider a trip down, where mud is pumped to lubricate drill bit 226 for the purpose of drilling to enlarge the borehole when drill bit 226 of drill string 225 reaches the bottom of the borehole. As noted above, the mud can be pumped by pump 204 into the channel of drill string 225, and upon filling the channel, the mud can be used as a transmission medium to transmit energy, for example, energy that can encode information, as in mud pulse telemetry.

[0053] As an example, mud pulse telemetry equipment can include downhole equipment configured to affect a pressure change in the mud to produce a sound wave or wave that can modulate information. In such an example, information from the downhole equipment (e.g., one or more modules of drill string 225) can be transmitted up the well to a device uphole, which can relay such information to other equipment for processing, control, etc.

[0054] As an example, the telemetry device can operate via energy transfer via the drill string 225 itself. For example, consider a signal generator that imparts an encoded energy signal to the drill string 225 and a repeater that can receive such energy and relay it to further transmit the encoded energy signal (e.g., information, etc.).

[0055] As an example, the drill string 225 can mount a telemetry device 252 that includes a rotatable drive shaft; a turbine lobe mechanically coupled to the drive shaft such that mud can cause the turbine lobe to rotate; a regulator rotor mechanically coupled to the drive shaft such that rotation of the turbine lobe can cause the regulator rotor to rotate; a modulator stator mounted adjacent or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator generates pressure pulses in the mud; and a controllable brake to selectively brake rotation of the modulator rotor to modulate the pressure pulses. In such an example, an alternating current motor can be coupled to the aforementioned drive shaft, where the alternating current motor includes at least one stator winding that is electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternating current motor to selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.

[0056] In Figure 2 examples, the uphole control and / or data acquisition system 262 can include circuitry to sense the pressure pulses generated by the telemetry device 252, e.g., to transmit the sensed pressure pulses or information derived therefrom for processing, control, etc.

[0057] The components 250 of the illustrated example include a logging-while-drilling (LWD) module 254, a measuring-while-drilling (MWD) module 256, optional modules 258, a rotary steerable system (RSS) and / or motor 260, and a drill bit 226. Such components or modules can be referred to as tools, where the drill string can include multiple tools.

[0058] With respect to RSS, this involves techniques for directional drilling. Directional drilling includes drilling into the earth to form a borehole that is deviated such that the trajectory of the borehole is not vertical; rather, the trajectory deviates from vertical along one or more portions of the borehole. As an example, consider a target that is located at a lateral distance from a surface location where a rig platform can be stationed. In such an example, drilling can begin from a vertical portion, then deviate from vertical such that the borehole is aimed at the target and eventually reaches the target. Directional drilling can be implemented in situations where the target is inaccessible from a vertical position at the surface of the earth, where there are materials within the earth that can impede drilling or otherwise be detrimental (e.g., consider salt domes, etc.), where the strata extend laterally (e.g., consider a relatively thin but laterally-extending reservoir), where multiple boreholes are to be drilled from a single surface borehole, where a relief well is needed, etc.

[0059] One method of directional drilling involves a mud motor; however, mud motors can face challenges depending on factors such as rate of penetration (ROP), weight transfer to the bit due to friction (e.g., weight on bit, WOB), etc. The mud motor can be a positive displacement motor (PDM) that operates to drive a drill bit (e.g., during directional drilling, etc.). The PDM operates as drilling fluid is pumped through the PDM, where the PDM converts the hydraulic power of the drilling fluid into mechanical power to rotate the drill bit.

[0060] As an example, the PDM can operate in a combined rotary mode, where surface equipment is used to rotate the drill string bit by rotating the entire drill string (e.g., a rotary table, a top drive, and where the drill string bit is rotated with drilling fluid. In such an example, the surface RPM (SRPM) can be determined by using the surface equipment, and the downhole RPM of the mud motor can be determined using various factors related to the flow of drilling fluid, the type of mud motor, etc. As an example, in combined rotary mode, assuming the SRPM and the mud motor RPM are in the same direction, the bit RPM can be determined or estimated as the sum of the SRPM and the mud motor RPM.

[0061] As an example, the PDM mud motor can operate in a so-called sliding mode when the drill string is not rotated from the surface. In such an example, the bit RPM can be determined or estimated based on the RPM of the mud motor.

[0062] RSS can directionally drill where the drill string is continuously rotated from surface equipment, which can mitigate sliding of a steerable motor (e.g., PDM). RSS can be deployed while directionally drilling, such as deviated wells, horizontal wells, or extended reach wells. RSS can aim to minimize interaction with the wellbore, which helps to maintain hole quality. RSS can aim to apply a relatively consistent lateral force, similar to a stabilizer as the drill string rotates, or to orient the drill bit in a desired direction while continuously rotating at the same revolutions per minute as the drill string.

[0063] The LWD module 254 can be housed in a suitable type of drill collar and can contain one or more selected types of logging tools. It should also be understood that more than one LWD and / or MWD module can be employed, for example, as shown by module 256 of the drill string assembly 250. In referring to the location of a LWD module, it can refer to a module located at the location of the LWD module 254, module 256, etc., as an example. The LWD module can include capabilities for measuring, processing, and storing information, and for communicating with surface equipment. In the illustrated example, the LWD module 254 can include seismic measurement equipment.

[0064] The MWD module 256 can be housed in a suitable type of drill collar and can include one or more devices for measuring characteristics of the drill string 225 and drill bit 226. As an example, the MWD tool 254 can include a device for generating power, e.g., to power various components of the drill string 225. As an example, the MWD tool 254 can include a telemetry device 252, e.g., in which a turbine lobe can be powered by the flow of the mud; it should be appreciated that other power and / or battery systems can be employed to power the various components. As an example, the MWD module 256 can include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.

[0065] Figure 2 Some examples of the types of holes that can be drilled are also shown. For example, consider the deviated hole 272, the S-shaped hole 274, the extended reach hole 276, and the horizontal hole 278.

[0066] As an example, the drilling operation can include directional drilling, e.g., at least a portion of the well includes a curved axis. For example, consider a radius that defines a curvature, in which the angle of inclination with respect to the vertical can vary until an angle between about 30 degrees and about 60 degrees is reached, or for example, an angle of about 90 degrees or possibly greater than about 90 degrees is reached.

[0067] As an example, the directional well can include a variety of shapes, in which each shape can be intended to meet a particular operational need. As an example, the drilling process can be performed based on information that is relayed to the drilling engineer. As an example, the inclination and / or direction can be modified based on information received during the drilling process.

[0068] As an example, the deflection of the borehole can be achieved in part by using a downhole motor and / or turbine. For example, for a motor, the drill string can include a positive displacement motor (PDM).

[0069] As an example, the system can be a steerable system and include a device that performs a method such as geosteering. As noted above, the steerable system can be or include an RSS. As an example, the steerable system can include a PDM or turbine located in a lower portion of the drill string, which can have a curved sub installed just above the drill bit. As an example, above the PDM, MWD device, it can have installed a telemetry device 252 that provides real-time or near real-time data of interest (e.g., inclination, direction, pressure, temperature, actual weight on bit, torque stress, etc.) and / or a LWD device. For the latter, the LWD device can send various types of data of interest to the surface, including, for example, geologic data (e.g., gamma ray, resistivity, density, and sonic logs, etc.).

[0070] Coupling of sensors providing information in real-time or near real-time of the well trajectory process with one or more logging instruments, for example, characterizing the formation from a geological perspective, can allow for implementation of a geosteering method. Such a method can include navigating a subterranean environment, for example, along a desired route to a desired one or more targets.

[0071] As an example, the drill string can include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth, and shock; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bent subs; and a geosteering tool, which can include a motor and optionally equipment for measuring and / or responding to one or more of inclination, resistivity, and gamma ray related phenomena.

[0072] As an example, geosteering can include intentional directional control of a borehole based on downhole geologic logging measurements, aimed at keeping a directional borehole within a desired area, layer (e.g., pay zone), etc. As an example, geosteering can include directing a borehole to keep the borehole within a particular portion of a reservoir, for example, to minimize gas and / or water breakthrough, and for example, to maximize economic production from a well including the borehole.

[0073] Referring again to Figure 2 , the wellsite system 200 can include one or more sensors 264 operably coupled to the control and / or data acquisition system 262. As an example, the one or more sensors can be located at a surface location. As an example, the one or more sensors can be located at a downhole location. As an example, the one or more sensors can be located at one or more remote locations that are not within a distance on the order of about 100 meters from the wellsite system 200. As an example, the one or more sensors can be located at an offset wellsite, where the wellsite system 200 and the offset wellsite are located at a common oilfield (e.g., oil and / or gas field).

[0074] As an example, the one or more sensors 264 can be provided for tracking a tubular, tracking movement of at least a portion of a drill string, etc.

[0075] As an example, the system 200 can include one or more sensors 266 that can sense and / or transmit signals to a fluid conduit, such as a drilling fluid conduit (e.g., a drilling mud conduit). For example, in the system 200, the one or more sensors 266 can be operably coupled to a portion of the standpipe 208 through which mud flows. As an example, a downhole tool can generate a pulse that can travel through the mud and be sensed by one or more of the one or more sensors 266. In such an example, the downhole tool can include a related circuit, such as an encoding circuit, that can encode a signal, for example, to reduce a need for transmission. As an example, circuitry at the surface can include a decoding circuit to decode encoded information transmitted at least in part by mud pulse telemetry. As an example, circuitry at the surface can include an encoder circuit and / or a decoder circuit, and downhole circuitry can include an encoder circuit and / or a decoder circuit. As an example, the system 200 can include a transmitter capable of generating a signal that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

[0076] As an example, one or more portions of the drill string can be stuck. The term "stuck" can refer to one or more different degrees of inability to move or remove the drill string from the borehole. For example, in a stuck condition, it can be possible to rotate the drill pipe or lower it back into the borehole, or, for example, in a stuck condition, it can not be possible to move the drill string axially in the borehole, although there can be some degree of rotation. For example, in a stuck condition, it can not be possible to move at least a portion of the drill string axially and rotationally.

[0077] With respect to the term "stuck pipe," this can refer to a portion of the drill string that cannot be rotated or moved axially. As an example, a condition known as "differential sticking" can be a condition in which the drill string cannot be moved along the axis of the borehole (e.g., rotated or reciprocated). Differential sticking can occur when a high contact force, caused by a low reservoir pressure, a high wellbore pressure, or both, is exerted over a sufficiently large area of the drill string. Differential sticking can be time and cost intensive.

[0078] As an example, a stuck force can be the product of the differential pressure between the wellbore and the reservoir and the area over which the differential pressure acts. This means that exerting a relatively low differential pressure (Δp) over a large working area is as effective in stuck pipe as exerting a higher differential pressure over a small area.

[0079] As an example, a condition known as "mechanical sticking" can be a condition in which movement of the drill string is restricted or prevented by a mechanism other than differential sticking. Mechanical sticking can be caused by, for example, one or more pieces of junk in the well, borehole geometry anomalies, cement, buildup of cuttings in the keyseat or annulus.

[0080] Figure 3An example of a system 300 is shown that includes various equipment for evaluation 310, planning 320, engineering 330, and operations 340. For example, a drilling workflow framework 301, a seismic simulation framework 302, a technical data framework 303, and a drilling framework 304 can be implemented to perform one or more processes, such as evaluating formations 314, evaluating processes 318, generating trajectories 324, validating trajectories 328, formulating constraints 334, designing equipment and / or processes based at least in part on the constraints 338, performing drilling 344, and evaluating drilling and / or formations 348.

[0081] In Figure 3 In an example, the seismic simulation framework 302 can be, for example, the PETREL framework (Schlumberger, Houston, Texas), and the technical data framework 303 can be, for example, the TECHLOG framework (Schlumberger, Houston, Texas).

[0082] As an example, a framework can include entities, which can include earth entities, geological objects, or other objects, such as wells, surfaces, reservoirs, and the like. An entity can include a virtual representation of an actual physical entity that is reconstructed for one or more purposes of evaluation, planning, engineering, operations, and the like. An entity can include an entity that is based on data (e.g., seismic data and / or other information) obtained via sensing, observation, and the like. An entity can be characterized by one or more properties (e.g., a geometric columnar grid entity of an earth model can be characterized by a porosity property). Such properties can represent one or more measurements (e.g., acquired data), calculations, and the like.

[0083] A framework can be an object-based framework. In such a framework, entities can include entities that are based on predefined classes, for example, to facilitate modeling, analysis, simulation, and the like. An example of an object-based framework is the MICROSOFT.NET framework (Redmond, Washington), which provides a set of extensible object classes. In the.NET framework, an object class encapsulates a module of reusable code and related data structures. An object class can be used to instantiate object instances for use by a program, a script, and the like. For example, a borehole class can define an object for representing a borehole based on well data.

[0084] As an example, a framework can be implemented within or in operable coupling with the DELFI cognitive exploration and production (E&P) environment (Schlumberger, Houston, Texas), which is a secure, cognitive, cloud-based collaboration environment that integrates data and workflows with digital technologies like artificial intelligence and machine learning. As an example, such an environment can provide operations involving one or more frameworks.

[0085] As an example, the framework can include an analysis component that can allow interaction with models or model-based results (e.g., simulation results, etc.). As to simulations, the framework can be operatively linked to or include a simulator, such as the ECLIPSE reservoir simulator (Schlumberger, Houston Texas), the INTERSECT reservoir simulator (Schlumberger, Houston Texas), etc.

[0086] The foregoing PETREL framework provides components that allow for optimization of exploration and development operations. The PETREL framework includes a seismic simulation software component that can output information for improving reservoir performance, such as by improving the productivity of an asset team. By using such a framework, various professionals (e.g., geophysicists, geologists, well engineers, reservoir engineers, etc.) can develop collaborative workflows and integrate operations to streamline processes. Such a framework can be considered an application, and can be considered a data-driven application (e.g., where data is input for purposes of modeling, simulation, etc.).

[0087] As described with respect to the DELFI environment, one or more frameworks can interoperate and / or run on one or another framework. As an example, a framework environment marketed as the OCEAN framework environment (Schlumberger, Houston, Texas) can be used, which allows for integration of additional components (or plug-ins) into the PETREL framework workflow. In example embodiments, various components can be implemented as additional components (or plug-ins) that conform to and operate according to the specifications of the framework environment (e.g., according to application programming interface (API) specifications, etc.).

[0088] As an example, the framework can include a model simulation layer as well as a framework services layer, a framework core layer, and a module layer. In a framework environment (e.g., OCEAN, DELFI, etc.), the model simulation layer can include or be operatively linked to a model-centric framework. In example embodiments, the framework can be considered a data-driven application. For example, the PETREL framework can include features for model building and visualization. As an example, the model can include one or more grids, where the grids can be spatial grids that conform to the spatial locations of each acquisition data (e.g., satellite data, well logging data, seismic data, etc.).

[0089] As an example, the model simulation layer can provide domain objects, act as a data source, provide rendering, and provide various user interfaces. The rendering capability can provide a graphical environment in which applications can display their data, and the user interface can provide a common look and feel for application user interface components.

[0090] As an example, domain objects can include entity objects, property objects, and optionally other objects. Entity objects can be used to geometrically represent wells, surfaces, reservoirs, etc., while property objects can be used to provide property values as well as data versions and display parameters. For example, an entity object can represent a well, with property objects providing log information as well as version information and display information (e.g., showing the well as part of a model).

[0091] As an example, data can be stored in one or more data sources (or data stores, typically physical data storage devices), which can be located in the same or different physical locations, and can be accessed via one or more networks. As an example, the model simulation layer can be configured to model projects. As such, a particular project can be stored, with the stored project information including inputs, models, results, and cases. Thus, upon completion of a modeling session, a user can store a project. Later, the project can be accessed and restored using the model simulation layer, which can recreate instances of the relevant domain objects.

[0092] As an example, the system 300 can be used to execute one or more workflows. A workflow can be a process that includes a number of work steps. A work step can operate on data, e.g., creating new data, updating existing data, etc. As an example, a workflow can operate on one or more inputs and create one or more results, e.g., based on one or more algorithms. As an example, the system can include a workflow editor for creation, editing, execution, etc. of workflows. In such an example, the workflow editor can provide a selection of one or more predefined work steps, one or more custom work steps, etc. As an example, a workflow can be a workflow that is at least partially implementable in the PETREL framework, e.g., that operates on seismic data, seismic attributes, etc.

[0093] As an example, seismic data can be data obtained via seismic surveying, with sources and receivers located in a geological environment to emit and receive seismic energy, with at least a portion of such energy being reflected from subsurface structures. As an example, one or more seismic data analysis frameworks (e.g., consider the OMEGA framework sold by Schlumberger of Houston, Texas) can be used to determine depths, extents, properties, etc. of subsurface structures. As an example, seismic data analysis can include, e.g., forward modeling and / or inversion to iteratively build a model of a subsurface region of a geological environment. For example, a seismic data analysis framework can be part of or operably coupled to a seismic simulation framework (e.g., the PETREL framework, etc.).

[0094] As an example, a workflow can be a process implemented at least in part in a framework environment and by one or more frameworks. As an example, a workflow can include one or more work steps that access an instruction set such as a plug-in (e.g., external executable code, etc.). As an example, a framework environment can be cloud-based, where cloud resources are utilized that can be operatively coupled to one or more field devices such that using the features of the framework environment, data can be acquired, transmitted, stored, processed, analyzed, etc. As an example, a framework environment can employ various types of services, which can be backend, frontend, or both backend and frontend services. For example, consider a client-server type architecture, where communications can occur via one or more application programming interfaces (APIs), one or more microservices, etc.

[0095] As an example, a framework for modeling a petroleum system can be provided. For example, a modeling framework marketed as the PETROMOD framework (Schlumberger, Houston, Texas), which includes features for inputting various types of information (e.g., seismic, well, geology, etc.) to model the evolution of a sedimentary basin. The PETROMOD framework provides petroleum system modeling, such as modeling the evolution of a sedimentary basin, via input of various data such as seismic data, well data, and other geologic data. The PETROMOD framework can predict whether and how a reservoir is filled with hydrocarbons, including, for example, the origin and timing of hydrocarbon generation, migration pathways, quantities, pore pressure, and hydrocarbon types under subsurface or surface conditions. In conjunction with a framework such as the PETREL framework, a workflow can be constructed to provide a basin-to-prospect scale exploration solution. Data exchange between the frameworks can facilitate the construction of models, analysis of data (e.g., PETROMOD framework data analyzed using PETREL framework capabilities), and coupling of workflows.

[0096] As noted above, a drill string can include various tools that can take measurements. As an example, measurements can be taken with a wireline tool or another type of tool. As an example, a tool can be configured to acquire electrical borehole images. As an example, a Full Bore Formation Micro Imager (FMI) tool (Schlumberger, Houston, Texas) can acquire borehole image data. A data acquisition sequence for such a tool can include running the tool into a borehole with the acquisition pads closed, opening the acquisition pads and pressing them against the borehole wall, delivering electrical current into the material defining the borehole while translating the tool in the borehole, and remotely sensing the current, which is altered by its interaction with the material.

[0097] Analysis of the formation information can reveal features such as caverns, dissolution planes (e.g., dissolution along bedding planes), stress-related features, dip events, and the like. As an example, the tool(s) can acquire information that facilitates characterization of a reservoir (optionally, a fractured reservoir) in which fractures can be natural and / or artificial (e.g., hydraulic fractures). As an example, a framework such as the TECHLOG framework can be used to analyze information acquired by the tool(s). As an example, the TECHLOG framework can interoperate with one or more other frameworks (e.g., the PETREL framework).

[0098] As an example, various aspects of the workflow can be completed automatically, can be completed partially automatically, or can be completed manually, such as by a human user interacting with a software application executing using hardware (e.g., local and / or remote). As an example, the workflow can be cyclical and, as an example, can include four stages, such as an evaluation stage (e.g., see evaluation device 310), a planning stage (e.g., see planning device 320), an engineering stage (e.g., see engineering device 330), and an execution stage (e.g., see operations device 340). As an example, the workflow can begin at one or more stages, which can progress to one or more other stages (e.g., in a serial manner, a parallel manner, a cyclical manner, and the like).

[0099] As an example, the workflow can begin at an evaluation stage, which can include evaluation of the formation by a geoservices provider (e.g., see evaluation block 314). As an example, the geoservices provider can use a computing system executing a software package tailored for such activities to conduct the formation evaluation; or, for example, one or more other suitable geologic platforms can be employed (e.g., instead or in addition). For example, the geoservices provider can evaluate the formation using, for example, an earth model, a geophysical model, a basin model, a petroleum technology model, a combination thereof, and the like. Such models can take into account a variety of different inputs, including offset well data, seismic data, steerable well data, other geologic data, and the like. The models and / or inputs can be stored in a database maintained by a server and accessed by the geoservices provider.

[0100] As an example, the workflow can proceed to a geology and geophysics ("G&G") service provider, which can generate a well trajectory (e.g., see generation block 324), which can involve execution of one or more G&G software packages. Examples of such software packages include the PETREL framework. As an example, the G&G service provider can determine a well trajectory or a portion thereof based on, e.g., one or more models provided by a formation evaluation (e.g., according to evaluation block 314), and / or other data accessed, e.g., from one or more databases (e.g., maintained by one or more servers, etc.). As an example, the well trajectory can take into account various "basis of design" (BOD) constraints, such as general surface location, target (e.g., reservoir) location, etc. As an example, the trajectory can contain information about tools, bottom hole assembly, casing size, etc., that can be used for drilling the well. Determination of the well trajectory can take into account various other parameters, including risk tolerance, fluid weight and / or plan, bottom hole pressure, drilling time, etc.

[0101] As an example, the workflow can proceed to a first engineering service provider (e.g., one or more processing machines associated therewith), which can validate the well trajectory, e.g., a subsea well design (see, e.g., validation block 328). Such a validation process can include evaluation of physical properties, calculations, risk tolerance, integration with other aspects of the workflow, etc. As an example, one or more parameters used for such determinations can be maintained by the server and / or the first engineering service provider; note that one or more models, well trajectories, etc. can be maintained by the server and accessed by the first engineering service provider. For example, the first engineering service provider can include one or more computing systems that execute one or more software packages. As an example, in the event that the first engineering service provider rejects or otherwise recommends adjustment to the well trajectory, the well trajectory can be adjusted, or a message or other notification requesting such modification can be sent to the G&G service provider.

[0102] As an example, one or more engineering service providers (e.g., first, second, etc.) can provide casing design, bottom hole assembly (BHA) design, fluid design, and / or similar design to implement the well trajectory (e.g., see design block 338). In some embodiments, the second engineering service provider can use one or more software applications to perform such design. Such design can be stored in one or more databases maintained by one or more servers, which can employ, e.g., the STUDIO framework tool (Schlumberger, Houston, Texas), and can be accessed by one or more other service providers in the workflow.

[0103] As an example, the second engineering service provider can seek approval of one or more of the designs established along the well trajectory from a third engineering service provider. In such an example, the third engineering service provider can consider various factors regarding whether the well engineering plan is acceptable, such as economic variables (e.g., oil production forecasts, cost per barrel, risk, drilling time, etc.), and can request expenditure authorization, such as from a representative of the operating company, a representative of the oil well owner, etc. (e.g., see formulation block 334). As an example, at least some of the data upon which such a determination is based can be stored in one or more databases maintained by one or more servers. As an example, the first, second, and / or third engineering service providers can be provided by a single team of engineers or even a single engineer, and thus can or can not be separate entities.

[0104] As an example, in the event of unacceptability of economics or experiencing a denial of authorization, the engineering service provider can recommend changes to the casing, bottom hole assembly, and / or fluid designs, or otherwise notify and / or cede control to a different engineering service provider, such that the casing, bottom hole assembly, and / or fluid designs are adjusted. In the event that modifying one or more of such designs is not feasible within the well constraints, trajectory, etc., the engineering service provider can recommend adjustment of the well trajectory, and / or the workflow can return or otherwise notify the initial engineering service provider and / or the G&G service provider, such that either or both can modify the well trajectory.

[0105] As an example, the workflow can include consideration of the well trajectory, including the accepted well engineering plan and the formation evaluation. Such a workflow can then pass control to a drilling service provider, which can implement the well engineering plan, establish a safe and effective drilling, maintain well integrity, and report progress as well as operational parameters (e.g., see blocks 344 and 348). As an example, the operational parameters, encountered formations, data collected while drilling (e.g., using logging while drilling or measurement while drilling techniques), can be returned to the geology service provider for evaluation. As an example, the geology service provider can then reevaluate one or more other aspects of the well trajectory or well engineering plan, and in some cases, and possibly within predetermined constraints, the well engineering plan can be adjusted according to real drilling parameters (e.g., based on data obtained on-site, etc.).

[0106] According to particular embodiments, the workflow can be followed by a post check (e.g., see evaluation block 318), whether the well is drilled in its entirety or partially completed. As an example, the post check can include checking the drilling performance. As an example, the post check can also include reporting the drilling performance (e.g., to one or more of the relevant engineering, geology, or G&G service providers).

[0107] The various activities of the workflow can be executed in series and / or out of order (e.g., based in part on information from templates, nearby wells, etc. to fill in any gaps in information to be provided by another service provider). As an example, conducting one activity can affect the results or basis of another activity, thus can manually or automatically require one or more workflow activities, work products, etc. to change. As an example, the server can allow information to be stored on a central database accessible to the various service providers, where changes can be sought by communicating with the appropriate service provider, can be made automatically, or can otherwise appear as a recommendation to the relevant service provider. This approach can be considered a holistic approach to the well workflow as compared to a sequential, piecemeal approach.

[0108] As an example, various actions of the workflow can be repeated multiple times during the drilling of a borehole. For example, feedback from a drilling service provider can be provided in real-time or near real-time in one or more automated systems, and data acquired during drilling can be fed to one or more other service providers, which can adjust their segment of the workflow accordingly. Such adjustments can permeate the workflow, for example, in an automated manner, due to dependencies that can exist in other areas of the workflow. In some embodiments, the loop can additionally or alternatively be conducted after a certain drilling objective is reached, e.g., completion of a segment of a borehole, and / or after a whole borehole is drilled, or based on a daily, weekly, monthly, etc. basis.

[0109] A well plan can include determining a path (e.g., trajectory) of a well that can extend to a reservoir, e.g., to economically produce fluids, e.g., hydrocarbons, from the reservoir. The well plan can include selecting drilling and / or completion components that can be used to implement the well plan. As an example, various constraints can be imposed as part of the well plan that can affect the design of the well. As an example, such constraints can be imposed based at least in part on known geology about a subsurface region, information about the presence (e.g., actual and / or planned, etc.) of one or more other wells within a region (e.g., to consider collision avoidance). As an example, one or more constraints can be imposed based at least in part on characteristics of one or more tools, components, etc. As an example, one or more constraints can be based at least in part on factors associated with drilling time and / or risk tolerance.

[0110] As an example, a system can allow for reduction of waste, e.g., as can be defined in terms of LEAN. In the context of LEAN, consider one or more of the following types of waste: transportation (e.g., movement of unnecessary items, whether physical or data); inventory (e.g., components, whether physical or informational, as work-in-process, and unprocessed finished goods); motion (e.g., unnecessary movement or walking by people or equipment to perform desired processing); waiting (e.g., waiting for information, production interruptions during shift changes, etc.); overproduction (e.g., production of materials, information, equipment, etc. in anticipation of demand); overprocessing (e.g., resulting from inferior tools or product design creating activities); and defects (e.g., work involved in checking and repairing defects in information, equipment, etc.). As an example, a system that allows actions (e.g., methods, workflows, etc.) to be performed in a collaborative manner can help reduce one or more types of waste.

[0111] As an example, a system can be utilized to implement a method for facilitating distributed well engineering, planning, and / or drilling system design across multiple computing devices, where collaboration can be performed among various different users (e.g., some local users, some remote users, some mobile users, etc.). In such a system, various users of appropriate devices can be operatively coupled via one or more networks (e.g., local and / or wide area networks, public and / or private networks, land-based, sea-based, and / or regional networks, etc.).

[0112] As an example, a system can allow for well engineering, planning, and / or drilling system design via a subsystem approach, where a wellsite system is composed of various subsystems, which can include equipment subsystems and / or operational subsystems (e.g., control subsystems, etc.). As an example, computations can be performed using various computing platforms / devices that are operatively coupled via communication links (e.g., network links, etc.). As an example, one or more links can be operatively coupled to a common database (e.g., a server site, etc.). As an example, a particular server or servers can manage receiving notifications from and / or issuing notifications to one or more devices. As an example, a system can be implemented for a project, where the system can output a well plan, e.g., as a digital well plan, a paper well plan, a digital and paper well plan, etc. Such a well plan can be a complete well engineering plan or design for a particular project.

[0113] Figure 4 An example of a wellsite system 400 is shown, specifically, Figure 4 Approximate side and plan views of the wellsite system 400 are shown, as well as a block diagram of the system 470.

[0114] In Figure 4In the example, the well site system 400 may include a cabin 410, a rotary table 422, a winch 424, a mast 426 (e.g., optionally carrying a top drive, etc.), a mud tank 430 (e.g., having one or more pumps, one or more vibrators, etc.), one or more pump buildings 440, a boiler building 442, an HPU building 444 (e.g., with a rig fuel tank, etc.), a combination building 448 (e.g., having one or more generators, etc.), a tub 462, a catwalk 464, a bell mouth 468, etc. Such equipment may include one or more associated functions and / or one or more associated operational risks, which may be risks related to time, resources, and / or personnel.

[0115] like Figure 4 As illustrated in the example, well site system 400 may include system 470, which includes one or more processors 472, memory 474 operatively coupled to at least one of the processors 472, instructions 476, for example, that can be stored in memory 474, and one or more interfaces 478. As an example, system 470 may include one or more processor-readable media including processor-executable instructions executable by at least one of the processors 472 to cause system 470 to control one or more aspects of well site system 400. In such an example, memory 474 may be or include one or more processor-readable media, wherein processor-executable instructions may be or include instructions. As an example, processor-readable media may be a computer-readable storage medium that is neither a signal nor a carrier wave.

[0116] Figure 4 A battery 480 operatively connected to system 470 is also shown, for example, to power system 470. As an example, battery 480 may be a backup battery that operates when another power source is unavailable to power system 470. As an example, battery 480 may be operatively connected to a network, which may be a cloud network. As an example, battery 480 may include smart battery circuitry and may be operatively connected to one or more devices via SMBus or other types of bus.

[0117] exist Figure 4 In the example, service 490 is shown as available, for example, via a cloud platform. Such services may include data service 492, query service 494, and drilling service 496. As an example, service 490 could be such as Figure 3 It is part of system 300.

[0118] As an example, the system 470 can be used to generate one or more rate of penetration (ROP) values and / or receive one or more ROP values, which can be used to control one or more drilling operations, for example.

[0119] Figure 5 A diagram illustrating an example describing a drilling operation of a multi-segment directional well is shown. Figure 5 The illustrated drilling operation includes a wellsite drilling system 500 and a field management tool 520 for managing various operations related to drilling a borehole 550 of a directional well 517. The wellsite drilling system 500 includes various components (e.g., a drill string 512, an annulus 513, a bottom hole assembly (BHA) 514, a kelly 515, a mud pit 516, etc.). As Figure 5 As shown in the example, a target reservoir can be located away from a surface location of the well 517 (as opposed to being directly underneath). In such an example, special tools or techniques can be used to ensure reaching a particular location of the target reservoir along a path of the borehole 550.

[0120] For example, the BHA 514 can include a sensor 508, a rotary steerable system (RSS) 509, and a drill bit 510 to direct drilling toward a target guided by a predetermined survey program for measuring details of a location in the well. Moreover, a subterranean formation through which the directional well 517 is drilled can include multiple layers (not shown) having different compositions, geophysical characteristics, and geological conditions. Both a drilling plan during a well design phase and actual drilling according to the drilling plan in a drilling phase can be performed in multiple segments (see, e.g., segments 501, 502, 503, and 504), which can correspond to one or more of the multiple layers in the subterranean formation. For example, certain segments (e.g., segments 501 and 502) can use a casing 506 augmented with cement 507 due to particular formation compositions, geophysical characteristics, and geological conditions.

[0121] In Figure 5 In the example, a surface unit 511 can be operably linked to the wellsite drilling system 500 and the field management tool 520 via a communication link 518. The surface unit 511 can be configured with functionality to segmentally control and monitor drilling activities in real-time via the communication link 518. The field management tool 520 can be configured with functionality to store oilfield data (e.g., historical data, actual data, surface data, subterranean data, equipment data, geological data, geophysical data, target data, counter-target data, etc.) and determine relevant factors for configuring a drilling model and generating a drilling plan. The oilfield data, the drilling model, and the drilling plan can be transmitted via the communication link 518 according to a drilling operation workflow. The communication link 518 can include communication subcomponents.

[0122] During various operations at a wellsite, data can be acquired for analysis and / or monitoring of one or more operations. Such data can include, for example, subsurface formation, equipment, historical, and / or other data. Static data can relate to, for example, formation structure defining the geological structure of a subsurface formation and geologic formation. Static data can also include data regarding a borehole, such as an inner diameter, an outer diameter, and a depth. Dynamic data can relate to, for example, fluids flowing through the geological structure of a subsurface formation over time. Dynamic data can include, for example, pressure, fluid composition (e.g., gas-oil ratio, water cut, and / or other fluid composition information), and the status of various equipment, among other information.

[0123] Static and dynamic data collected via a borehole, formation, equipment, and / or the like can be used to create and / or update a three-dimensional model of one or more subsurface formations. As an example, static and dynamic data from one or more other boreholes, oilfields, and / or the like can be used to create and / or update a three-dimensional model. As an example, hardware sensors, core sampling, and logging techniques can be used to collect data. As an example, static measurements can be collected using downhole measurements, such as core sampling and logging techniques. Logging involves deploying a downhole tool into a wellbore to collect downhole measurements, such as density, resistivity, and / or the like, at various depths. Such logging can be performed using, for example, drilling tools and / or wireline tools, or sensors located on downhole production equipment. Once formed and completed, depending on the purpose of the well (e.g., injection and / or production), fluid can flow to the surface (e.g., and / or from the surface) using tubing and other completion equipment. As the fluid passes through, various dynamic measurements can be monitored, such as fluid flow, pressure, and composition. These parameters can be used to determine various characteristics of the subsurface formation, downhole equipment, downhole operations, and / or the like.

[0124] As an example, a system can include a framework that can acquire data, such as real-time data associated with one or more operations, such as one or more drilling operations. As an example, consider the PERFORM™ toolkit framework (Schlumberger Limited, Houston, Texas).

[0125] As an example, a service can be or include one or more of OPTIDRILL™, OPTILOG™, and / or other services marketed by Schlumberger Limited, Houston, Texas.

[0126] OPTIDRILL™ technology can help manage downhole conditions and BHA dynamics as a real-time drilling intelligence service. The service can incorporate rigsite displays (e.g., wellsite displays) that integrate downhole and surface data to provide actionable information to reduce risk and improve efficiency. As an example, such data can be stored to, for example, a database system (e.g., consider a database system associated with the STUDIO™ framework).

[0127] OPTILOG™ technology can help assess drilling system performance with single or multi-point measurements of drilling dynamics and internal temperature from a recorder. As an example, post-run data can be analyzed to provide input for future well planning.

[0128] As an example, information from a bit database can be accessed and utilized. For example, consider information from Smith Bit (Schlumberger Limited, Houston, Texas), which can include information from various operations (e.g., drilling operations) related to various bits, drilling conditions, formation types, etc.

[0129] As an example, one or more QTRAC services (Schlumberger Limited, Houston Texas) can be provided for one or more wellsite operations. In such an example, data can be acquired and stored, where such data can include time series data that can be received and analyzed, etc.

[0130] As an example, one or more M-I SWACO™ services (M-I L.L.C., Houston, Texas) can be provided for one or more wellsite operations. For example, consider services for value-added completion and reservoir drilling fluids, additives, cleanup tools, and engineering. In such an example, data can be acquired and stored, where such data can include time series data that can be received and analyzed, etc.

[0131] As an example, one or more ONE-TRAX™ services (e.g., via the ONE-TRAX software platform, M-I L.L.C., Houston, Texas) can be provided for one or more wellsite operations. In such an example, data can be acquired and stored, where such data can include time series data that can be received and analyzed, etc.

[0132] As an example, various operations can be defined with respect to WITS or WITSML, which is an acronym for Wellsite Information Transfer Specification or Standard (WITS) and a markup language (WITSML). WITS / WITSML specifies how a rig or offshore platform rig communicates data. For example, for a slip, which is a component that can be used to clamp and hang a drill string on a rotary table in a relatively non-damaging manner,

[0133] WITS / WITSML defines operations such as "bottom to slips" time as the time interval between the trip off bottom and setting the slips for the current connection; "in slips" as the time interval between setting the slips and then releasing the slips for the current connection; and "slips to bottom" as the time interval between releasing the slips and returning to bottom for the current connection (e.g., setting weight on bit).

[0134] Well construction can be performed according to various programs, which can be in various forms. As an example, a program can be specified digitally and can be, for example, a digital plan such as a digital well plan. A digital well plan can be an engineering plan for constructing a wellbore. As an example, a program can include information such as well geometry, casing program, mud considerations, well control issues, initial bit selection, offset well information, pore pressure estimates, economics, and special programs that can be used in the course of well construction, production, etc., although a drilling program can be carefully developed and specified, various situations can arise that require adjustment to the drilling program.

[0135] As an example, when the acquisition device obtains information about conditions, which can be conditions of the drilling equipment, conditions of the formation, conditions of the fluids, conditions about the environment (e.g., weather, sea, etc.), etc., can be adjusted at the rig site. Such adjustments can be made based on the personal knowledge of one or more individuals at the rig site. As an example, an operator can understand that the conditions require an increase in mud flow, a decrease in weight on bit, etc. Such an operator can evaluate data acquired via one or more sensors (e.g., torque, temperature, vibration, etc.). Such an operator can call for a trip out of hole sequence, which can be a test program to acquire additional data to better understand the actual physical conditions and physical phenomena that can be occurring or are occurring. The operator can be under one or more time constraints, which can be driven by physical phenomena such as fluid flow, fluid pressure, rock compaction, borehole stability, etc. In such an example, the decisions made by the operator can depend on the development of the conditions over time. For example, in an environment where fluid pressure is changing, a decision made at one fluid pressure can not be optimal at another fluid pressure. In such an example, the timing of the decision to implement as an adjustment to the program can have wide-ranging effects. An adjustment to a program made too late or too early can have adverse effects on other programs compared to an adjustment to a program made at an optimal time (e.g., implemented at an optimal time).

[0136] As an example, the system can include one or more automated assistance features. For example, consider a feature that can generate and / or receive one or more drilling rate of penetration (ROP) values that can be used to control a drilling operation. In such an example, a driller can utilize the generated ROP values to control one or more pieces of equipment to drill a borehole at or near the generated ROP values. As an example, where automation can signal one or more pieces of equipment, a controller can utilize the generated ROP values for automatic control. As explained, where a driller is involved in decision making and / or control, the generated ROP values can facilitate drilling as the driller can rely on the generated ROP values to make one or more adjustments to the drilling operation. Where one or more generated ROP values are received in advance and / or in real-time, drilling operations can be performed more effectively, for example, with respect to time to drill a section, a portion of a section, an entire borehole, etc., such an approach can account for equipment integrity (e.g., health, etc.), for example, such an approach can account for contact risk between a drill bit body and a formation and / or mud motor performance in which a mud motor can be used to drive a drill bit.

[0137] Figure 6 An example of a graphical user interface (GUI) 600 is shown that includes information associated with a well plan. Specifically, the GUI 600 includes a panel 610 in which surface representations 612 and 614 are presented along with a well trajectory, where a location 616 can represent a location of a drill string 617 along the well trajectory. The GUI 600 can include one or more editing features, such as a set of edit well plan features 630. The GUI 600 can include information about individuals of a team 640 that are involved, have been involved, and / or will be involved in one or more operations. The GUI 600 can include information about one or more activities 650.

[0138] As Figure 6 The GUI 600 can include a graphical control of a drill string 660, where, for example, individual portions of the drill string 660 can be selected to display one or more related parameters (e.g., type of equipment, equipment specifications, operational history, etc.), as shown in the example of FIG. 6B. In the example of FIG. 6B, the drill string graphical control 660 includes components such as drill pipe, heavy weight drill pipe (HWDP), subs, collars, jars, stabilizers, motors, and drill bits. A drill string can be a combination of drill pipe, a bottom hole assembly (BHA), and one or more other tools, which can include one or more tools that can help a drill bit spin and drill into a material (e.g., a formation). Figure 6 The GUI 600 can include a graphical control of a drill string 660, where, for example, individual portions of the drill string 660 can be selected to display one or more related parameters (e.g., type of equipment, equipment specifications, operational history, etc.), as shown in the example of FIG. 6B. In the example of FIG. 6B, the drill string graphical control 660 includes components such as drill pipe, heavy weight drill pipe (HWDP), subs, collars, jars, stabilizers, motors, and drill bits. A drill string can be a combination of drill pipe, a bottom hole assembly (BHA), and one or more other tools, which can include one or more tools that can help a drill bit spin and drill into a material (e.g., a formation).

[0139] As an example, the workflow can include utilizing the graphical controls of the drill string 660 to select and / or display information associated with one or more components, such as a drill bit and / or a mud motor. As an example, in response to selection of the drill bit and / or the mud motor (e.g., considering a combination of the drill bit and the mud motor), the computational framework (e.g., via an ROP engine, etc.) can generate one or more rates of penetration (ROP) values, which can be used as set points, for example, to perform one or more drilling operations. In Figure 6 As an example, a graphical control 665 is shown, which can be presented in response to interaction with the graphical controls of the drill string 660, for example, to select a type of component and / or to generate one or more ROP values, etc.

[0140] Figure 6 Also shown is an example of a table 670, which is a point spreadsheet, specifying information for a plurality of holes. As shown in the example table 670, coordinates such as “x” and “y” and “depth” can be specified for various features of a well, which can include pad parameters, spacing, toe height, stepout, initial inclination, kickoffs, etc. (see also, e.g., Figure 7 and various types of drilling operations with respect to the coordinate specification of the trajectory).

[0141] As noted above, a well can be a directional well, which is constructed using directional drilling. Directional wells have been a boon to oil and gas production, particularly in unconventional oil and gas fields, where horizontal and extended reach wells can help maximize wellbore exposure through the producing zone.

[0142] One or more of a variety of techniques can be used for directional drilling. For example, consider steerable mud motors, which can be used to achieve a desired well trajectory to and / or through one or more target regions. As an example, directional drilling operations can use downhole mud motors when kickoffs, building angles, drilling sections, and holding trajectories.

[0143] A mud motor can include a bend in the motor bearing housing that provides for steering the drill bit to a desired target. The bend can be surface adjustable (e.g., a surface adjustable bend (SAB)) and, for example, set at an angle within an operating angular range (e.g., consider 0 degrees to about 5 degrees, 0 degrees to about 4 degrees, 0 degrees to about 3 degrees, etc.). The bend can be intended to be sufficient to point the drill bit in a given direction while being small enough to allow the entire mud motor assembly to rotate during rotary drilling. The deflection caused by the bend can be a factor in determining the rate at which the mud motor can establish an angle to build a desired borehole. By orienting the bend to a particular direction (referred to as a tool face angle), drilling operations can change the inclination and azimuth of the well trajectory. To maintain the orientation of the bend, the drill string is operated in a sliding mode in which the entire drill string itself does not rotate in the borehole (e.g., via a top drive, rotary table, etc.) and the rotation of the drill bit for drilling is driven by the mud motor of the drill string.

[0144] A mud motor is a positive displacement motor (PDM) that is driven by drilling fluid. For example, a mud motor can include an eccentric helical rotor and stator assembly driver. As drilling fluid (e.g., mud) is pumped downhole, the drilling fluid flows through the stator and turns the rotor. The mud motor converts hydraulic power to mechanical power to turn a drive shaft that causes a drill bit operably coupled to the mud motor to rotate.

[0145] By using a mud motor, directional drilling operations can alternate between rotary and sliding drilling modes. In rotary mode, a rotary table or top drive is operated to rotate the entire drill string to deliver power to the drill bit. As noted above, rotary mode can include a combination of rotation via surface equipment and via the downhole mud motor. In rotary mode, rotation enables the bend in the motor bearing housing to point equally in different directions, thereby maintaining a straight borehole path. As an example, one or more measurement while drilling (MWD) tools integrated into the drill string can provide real-time inclination and azimuth measurements. Such measurements can be used to alert a driller, controller, etc. of one or more deviations from a desired trajectory (e.g., a planned trajectory, etc.). To adjust for the deviation or change the trajectory, drilling operations can switch from rotary mode to sliding mode. As noted above, in sliding mode, the drill string does not rotate; rather, the downhole motor turns the drill bit and the borehole is drilled in the direction the drill bit is pointed, which is controlled by the tool face orientation. In adjusting the course and reestablishing a desired trajectory intended to hit a target (or targets), drilling operations can switch from sliding mode to rotary mode, which, as noted above, can be a combination of surface and downhole rotary modes.

[0146] Of the two modes, the sliding mode tends to have lower sliding drilling efficiency; thus, lateral extension can come at the expense of rate of penetration. The rate of penetration (ROP) obtained using sliding techniques tends to be about 10-25% of the ROP that can be obtained using rotary techniques.

[0147] Various types of automation systems (e.g., automated driller) are designed to help drilling operations achieve gains in horizontal extent at significantly faster rates of penetration.

[0148] When transitioning from rotary mode to sliding mode, drilling operations can stop rotation of the drill string by orienting the drill bit, for example, aligning with the trajectory called for in the drilling plan, and initiate sliding. As to stopping rotation of the drill string, consider, as an example, drilling operations that pull the drill bit off the bottom and reciprocate the drill pipe to release the torque built up within the drill string. Drilling operations can then use real-time MWD toolface measurements to orient the downhole mud motor to ensure the specified hole deviation is obtained. After this relatively time-consuming orientation process, drilling operations can set the top drive brake to prevent further rotation from the surface. In such an example, sliding can begin when drilling operations release the drawworks brake to control the hook load, which in turn affects the magnitude of weight on bit (e.g., WOB) applied to the drill bit. As an example, small left and right torque adjustments (e.g., clockwise and counterclockwise) can be manually applied to appropriately steer the drill bit to keep the trajectory on course.

[0149] As the depth or lateral extent increases, the drill string tends to be subjected to greater friction and resistance. These forces in turn affect the ability to transfer weight to the drill bit (e.g., WOB) and the ability to control toolface orientation while sliding, which can make it more difficult to obtain sufficient ROP and maintain the desired trajectory to the target (or targets). These issues can result in increased drilling time, which can adversely affect the economics of the project and ultimately limit the length of the lateral portion of the borehole, and thus the length of the lateral portion of the well completion (e.g., production well).

[0150] The ability to transfer weight to the drill bit affects several aspects of directional drilling. As an example, drilling operations can transfer weight to the drill bit by releasing or unclamping the brake, which can transfer some of the hook load or drill string weight to the drill bit. The difference between the weight applied to the drill bit and the weight obtained by releasing the actuator at the surface is primarily caused by resistance. As the borehole deviates horizontally, the resistance along the longitudinal direction of the borehole tends to increase.

[0151] Drill string elasticity makes it more difficult to control bit weight throughout the slide mode, allowing the pipe to move disproportionately. This elasticity can cause one section of the drill string to move while other sections remain stationary or move at different speeds. Weight transfer can also be affected by conditions such as poor hole cleaning, for example. Hole cleaning efficiency tends to be lower in the slide mode due to the lack of pipe rotation; note that pipe rotation helps to create turbulence in the annulus between the pipe (drill string pipe or standpipe) and the borehole and / or casing section. Poor hole cleaning is related to the ability of the drilling fluid (such as mud) to carry solids (such as cuttings). As solids accumulate on the low side of the borehole due to gravity, the cross-sectional area of the borehole decreases and causes an increase in friction on the drill string (e.g., pipe or standpipe), which makes it more difficult to maintain a desired weight on bit (WOB), which can be a desired constant WOB. As an example, poor hole cleaning can increase the risk of a stuck pipe (such as a stuck pipe).

[0152] The difference in frictional forces between the drill string within the casing and the drill string within the open hole can cause a sudden release of weight, as can the suspension caused by the key seat and ledge. A sudden transfer of weight to the bit beyond the capacity of the downhole motor can cause a sudden stop in bit rotation and motor stalling. Frequent stalling can damage the stator assembly of the mud motor, depending on the weight transferred. Drilling operations can aim to operate the mud motor within a relatively narrow range of loads in an effort to maintain an acceptable ROP without stalling.

[0153] As an example, the system can include a console, which can include one or more displays, which can present one or more graphical user interfaces (GUIs) that include data from one or more sensors. As an example, an impending stall can be indicated by an increase in WOB presented to the GUI, for example, without a corresponding rise in downhole pressure to indicate that the increase in downhole WOB has actually occurred. In such an example, at some point, the WOB indicator can show a sudden drop, indicating a sudden transfer of force from the drill string to the bit. The increase in resistance hinders the ability to remove downhole torque, making it more difficult to set and maintain tool face orientation.

[0154] Tool face orientation can be affected by torque and WOB. When weight is applied to the bit, torque tends to increase at the bit. As described above, torque can be transmitted downhole through the drill string, which is typically oriented by drilling operations in a clockwise direction to the right. When weight is applied to the bit, a reactive torque is generated, acting in the opposite direction. This left-hand torque (counterclockwise direction) can be transmitted from the bit up to the lower portion of the drill string. The reactive torque increases as weight is increased, for example, reaching a maximum when the mud motor stalls. This reactive torque can also affect the orientation of the mud motor. When drilling operations attempt to orient the mud motor from the surface, the reactive torque can be considered. In practice, drilling operations can make minor changes to tool face orientation by changing the downhole WOB, thereby changing the reactive torque. To make larger changes, drilling operations can pull the bit off bottom and re-orient the tool face. However, even after a specified tool face orientation is reached, maintaining that orientation can sometimes be challenging. As described above, the longitudinal resistance tends to increase with lateral extension, and the weight transferred to the bit can become more unstable along the length of the horizontal section, thus generating a reactive torque that changes the tool face angle. The effort and time spent orienting the tool face can have a negative impact on the rig’s production time.

[0155] As previously described, directional drilling can include operating in a rotary mode and operating in a sliding mode, with multiple transitions between the two modes. As described above, drilling fluid can be used to drive a downhole mud motor to rotate the bit in the sliding mode, while surface equipment can be used to rotate the entire drill string in the rotary mode (e.g., rotary table, top drive, etc.), optionally in combination with the drilling fluid used to drive the downhole mud motor (e.g., combined rotary mode). Directional drilling operations can depend on various factors, including operational parameters that can be controlled at least to some extent. For example, one or more factors such as mode transition, lift, WOB, RPM, torque, and drilling fluid flow rate are controllable during drilling operations.

[0156] Figure 7 An example of a graphical user interface 700 is shown, including a graph of a system 710 and a graph of a trajectory 730, where the system 710 can be oriented for directional drilling according to the trajectory 730 to drill a borehole. As shown, the trajectory 730 includes a substantially vertical portion, a dogleg, and a substantially lateral portion (e.g., a substantially horizontal section). The system 710 can be operated in various operational modes, which can include, for example, rotary drilling and sliding.

[0157] In Figure 7In examples, the longitudinal resistance along the drill string can be reduced from the surface to a maximum swing depth, at which the friction and applied torque reach equilibrium. As an example, drilling operations can include manipulating the surface torque oscillation such that the maximum swing depth can be moved deep enough to create a significant reduction in resistance. As an example, the back torque from the drill bit creates a vibration that propagates up the well, disrupting the friction and longitudinal resistance through the drill string bottom until the point of interference, at which the torque is balanced by static friction. As Figure 7 As shown in examples, the middle region can remain relatively unaffected by the surface swing torque or back torque. In examples, the middle region can be a region of the drill string where the longitudinal resistance is relatively constant. As an example, the middle region can be a region of the drill string where the longitudinal resistance is relatively constant and the drill string is not being accelerated or decelerated. Figure 7 In examples, drilling operations can include monitoring torque, WOB, and ROP while sliding. As an example, such drilling operations can aim to minimize the length of the middle region, thereby reducing the longitudinal resistance.

[0158] Drilling operations in a slide mode that involve manual adjustments to change and / or maintain tool face orientation can be challenging. As an example, drilling operations in a slide mode can depend on the ability to transfer weight to the drill bit while stalling the mud motor, as well as the ability to sufficiently reduce the longitudinal resistance to achieve and maintain a desired tool face angle. As an example, drilling operations in a slide mode can aim to achieve an acceptable ROP while accounting for one or more various other factors (e.g., equipment capabilities, equipment conditions, trips, etc.).

[0159] For example, in drilling operations, the amount of surface torque provided by the top drive (e.g., STOR) can largely dictate the distance that downhole swing motion can be transmitted. As an example, the relationship between torque and swing depth can be modeled using a torque and drag framework (e.g., T&D framework). As an example, a system can include one or more T&D features.

[0160] As an example, a system can utilize input from surface hook load and standpipe pressure, as well as downhole MWD tool face angle. In such examples, the system can automatically determine an amount of surface torque suitable for transferring downhole weight to the drill bit, which can allow operations to not pull off bottom for tool face adjustments, which can result in more efficient drilling operations and reduced wear on downhole equipment. Such a system can be referred to as an automated assist system.

[0161] Figure 8An example of a graphical user interface 800 is shown that includes various tracks of different types of operations, including rotation according to the amount of surface torque provided, manual sliding, and automated assisted sliding. As shown in GUI 800, a comparison of the rotational and sliding drilling parameters for the rotation mode and sliding mode can be made. As shown, the rate of penetration (ROP) and tool face orientation control are largely dependent on the system’s ability to transfer weight to the bit and counteract the effects of torque and drag between the rotational and sliding modes. As shown, the best ROP is achieved when rotating; however, the tool face varies greatly because it is not being attempted to be controlled (track 3). The hook load (track 2) and weight on bit (WOB) remain fairly constant, while the differential pressure (track 1) increases slightly as the depth increases. To begin manual sliding, the drilling operation can be used to pull off bottom to release the trapped torque; during this time, the WOB (track 1) decreases while the hook load (track 2) increases. As drilling progresses, the inconsistency in differential pressure (e.g., when the bit is on bottom versus off bottom) indicates poor weight transfer to the bit (track 1). The peaks in rotational torque indicate the effort to orient and maintain the tool face (track 2). As shown, the tool face control can be poor due to the difficulty in transferring weight to the bit, which is also reflected in the poor ROP (track 3). Using an automated assisted sliding mode system, the directional driller can achieve tool face orientation more quickly. When the WOB is increased, the differential pressure is consistent, indicating good weight transfer (track 1). In Figure 8 the example, the weight on bit during sliding operations is lower than during manual sliding operations. The left and right swing of the drill pipe is relatively constant throughout the sliding track (track 2). The average ROP is much higher than that achieved during manual sliding, and the tool face orientation is more consistent (track 3).

[0162] Figure 9 An example of a graphical user interface 900 is shown that includes various types of well construction information, with the time of the respective actions presented. In Figure 9 the example, the time is shown as an estimated time (ET) in hours and a total time or cumulative time (TT) in days. Another time can be a clean time, which can be used to perform one or more actions without non-productive time (NPT), while the estimated time (ET) can include NPT, which can be determined using one or more databases, probabilistic analysis, etc. In Figure 9 the example, the total time (TT or cumulative time) can be a summation of the estimated time columns. As an example, during execution and / or re-planning, the GUI 900 can be presented and modified accordingly to reflect the changes. As Figure 9As shown by way of example, GUI 900 can include selectable elements and / or highlightable elements. As an example, elements can be highlighted in response to a signal indicating that an activity is currently being performed, is in progress, is about to be amended, etc. For example, a color coding scheme can be used to convey information to a user via GUI 900.

[0163] As an example, graphical user interface 900 can be operatively coupled to one or more systems that can assist and / or control one or more drilling operations. For example, consider the previously mentioned automated assisted sliding mode system that provides a large amount of surface torque. As another example, consider a system that generates a rate of penetration value, which can be, for example, a rate of penetration setpoint. Such a system can be an automated assistance system and / or a control system. For example, the system can present a GUI that displays one or more generated rate of penetration values, and / or the system can issue one or more commands to one or more pieces of equipment to cause it to operate at the generated rate of penetration.

[0164] As an example, automated assistance systems can be used in one or more oil and gas drilling operations to improve drilling efficiency and consistency. As an example, when such a system is enabled, a controller can include various setpoints and limits for one or more drilling parameters, which can include, for example, differential pressure, rate of penetration (ROP), weight on bit (WOB), surface rotational speed (surface RPM), etc. In a bottom hole assembly with a mud motor as a driver, differential pressure can be targeted as a drilling parameter for control. As an example, the system can provide for control of differential pressure to a desired setpoint, and can help to keep differential pressure relatively constant until the setpoint is changed.

[0165] For example, in an automated assistance system, if one drilling parameter reaches its setpoint or limit, one or more other parameters can stop tracking one or more corresponding setpoints and become reactive. As an example, if an ROP setpoint is too low such that ROP will reach the setpoint before differential pressure reaches its setpoint, then the drilling operation is not being performed at a level at which it is capable of achieving its potential efficiency. On the other hand, if the ROP setpoint is too high, when differential pressure reaches its setpoint, ROP can reach its physical limit, for example by bit design, which means that the bit body is engaged with the formation, causing the bit body to wear.

[0166] As an example, the system can generate one or more rate of penetration values. For example, consider a system that can generate ROP setpoints using various inputs. As an automated assistance system, one or more ROP setpoints can be generated and outputted to, for example, a GUI presented to a display, where, for example, a driller can evaluate one of the one or more ROP setpoints and take one or more actions aimed at achieving one of the one or more ROP setpoints. As an example, the system can implement control by generating and utilizing one or more ROP setpoints, where the system issues one or more signals to one or more devices in an effort to achieve one of the one or more ROP setpoints.

[0167] As an example, the system can include an ROP setpoint generation engine (e.g., an ROP engine), which can be a computational engine, which can be part of a computational framework. As an example, the ROP engine can generate ROP setpoint recommendations based on a combined drilling system including a bit and a mud motor. In such an example, for each candidate bit, the ROP engine can utilize a bit engine (e.g., a bit static engine, etc.) to calculate a depth of cut (DOC) limit before the bit body engages the formation; and, for each candidate mud motor, the ROP engine can utilize a mud motor engine that, based on a power portion characteristic curve, obtains motor RPMs for a specified differential pressure and flow rate. In such an example, the ROP engine can generate recommended ROP setpoints for one or more different flow rates, one or more different surface RPMs, and one or more differential pressures by combining the bit DOC limit and the motor RPMs.

[0168] As an example, the ROP engine can operate in one or more modes. For example, consider executing the ROP engine in a planning phase to generate a list of recommended ROP setpoints for different bit motor combinations, and consider executing the ROP engine in a drilling phase to recommend one or more ROP setpoints during one or more drilling operations, where the ROP engine can generate one or more ROP setpoints in real-time (e.g., on the order of ten minutes or less).

[0169] As an example, for each bit, a table or other data structure of ROP vs. RPM can be pre-generated using a computing framework, such as the IDEAS framework (Schlumberger Limited, Houston, Texas), when the bit body is in contact with (e.g., engaged with) the formation. As an example, such a data structure can then be used to automatically give ROP setpoints for one or more particular bit-motor combinations during the planning phase or during real-time drilling operations. As an example, the ROP engine can generate one or more ROP setpoints that help reduce the risk of damaging a bit and / or actually damaging a bit. As an example, the ROP engine can smooth drilling operations. As an example, smoother drilling operations can be characterized as being less reactive while still achieving acceptable ROP.

[0170] As described above, a damaged device (e.g., a damaged mud motor, a damaged bit, etc.) can result in a trip, resulting in an increase in non-productive time (NPT). As an example, the ROP engine can generate one or more ROP values that can smooth drilling operations and reduce the risk of having to perform an undesirable trip. As an example, the ROP engine can be operatively coupled to a system that can generate an output of data shown in GUI 900 such as Figure 9 As an example, consider a cycle that can provide an estimated time and a total time based at least in part on one or more generated ROP values that can be associated with one or more bit and / or mud motor combinations. In such an example, a GUI can present to a display a graph for selecting one or more bits and / or one or more mud motors, where upon selection of a bit and a mud motor, an ROP value is produced that can be used to determine an estimated time and / or a total time. In such an example, a user can select a desired combination of bits and mud motors and ROP values, for example, to use as one or more ROP setpoints for drilling one or more sections of a well (e.g., a portion of one or more sections of a well, etc.).

[0171] Figure 10 An example of a rate of penetration (ROP) engine 1000 is shown operatively coupled with a planner 1012 and a controller 1014, where the planner 1012 can be operatively coupled with the controller 1014. As an example, the ROP engine 1000, the planner 1012, and the controller 1014 can be separate, part of a common computing framework, or part of one or more computing frameworks. As an example, one or more features of the ROP engine 1000 can be implemented using a system of the system 470 such as Figure 4 As an example, the system 470 can be operatively coupled to the ROP engine 1000, and / or for example, the system 470 can be used to implement one or more features of the ROP engine 1000. Figure 10The controller 1014 can be part of the system 470. As an example, the ROP engine 1000 can be used in a system such as the system 300. Figure 4 Figure 3

[0172] As shown in the example of FIG. 10, the ROP engine 1000 includes a bit engine 1020 and a mud motor engine 1040. As explained, the bit engine 1020 can provide bit-related information, such as bit body engagement information regarding the formation, and the mud motor engine 1040 can provide mud motor information (e.g., RPM, etc.), such as regarding one or more operating parameters. As explained, the ROP engine 1000 can generate one or more ROP values, which can be used, for example, for one or more purposes, which can include planning one or more drilling operations (e.g., for a particular well or wells) and performing one or more drilling operations (e.g., for a particular well or wells). Figure 10

[0173] Figure 11 An example of a graphical user interface 1100 for a particular well is shown, which includes differential pressure (Diff. Press.), rate of penetration (ROP), and weight on bit (WOB) values, as well as limits and set points, relative to time.

[0174] The GUI 1100 is operatively coupled to a framework, such as a control framework that can be used to control one or more drilling operations. As shown, the GUI 1100 can include set points and limits for drilling parameters, such as one or more of differential pressure, ROP, WOB, and RPM.

[0175] As an example, the framework can push one or more drilling parameters to the respective set points, and operate to continuously maintain that set point until the parameter command changes.

[0176] As an example, if one of the drilling parameters reaches its set point or limit, then each of the other drilling parameters can stop tracking its set point, e.g., become reactive.

[0177] ​​​GUI 1100 includes two examples of possible scenarios, labeled A and B. In scenario A, the ROP reaches its setpoint (SP) while the differential pressure remains below its setpoint (SP); in scenario B, the differential pressure reaches its setpoint (SP), but the ROP does not reach its setpoint (SP) and becomes reactive (e.g., as long as it remains below its setpoint). As shown in GUI 1100, for scenario B, the relationship between ROP and time is unstable because it fluctuates relative to time by more than 25 feet per hour (e.g., approximately 10%). This fluctuation represents changing behavior that can be characterized as responsiveness, such as responsiveness to conditions, the drill bit's ability to break rock, the drilling fluid's ability to maintain motor parameters (e.g., RPM, torque, etc.).

[0178] As an example, a ROP engine can be used to generate one or more ROP values, where, for a specific depth range, one or more ROP values ​​can be used to set an appropriate ROP setpoint or limit, which helps, for example, improve drilling efficiency while reducing the risk of drill bit damage. As an example, the ROP engine can be part of a computational framework that can generate ROP setpoint and / or limit recommendations. In such an example, recommendations could be combinations of different drill bit power portions at different differential pressure setpoints.

[0179] Figure 12 An example of a drill bit 1210 is shown, which includes various cutting structures (e.g., cutters) numbered from 1 to N and represented in a cross-sectional view. This cross-sectional view is a view illustrating the cutter density and associated spatial information by rotating the placement of the cutting structures onto a single radial plane. The drill bit 1210 may be, for example, a polycrystalline diamond composite (PDC) drill bit, which may be a fixed-head drill bit that rotates as a single piece and does not include separate moving parts.

[0180] like Figure 12 As shown, the drill bit may include inserts 1212-1, 1212-2, ... 1212-N, which may include, for example, a main insert and auxiliary inserts. As an example, the inserts may be part of the drill body and therefore integral with it. As shown, the inserts may include insert tips for mounting multiple cutting structures (e.g., numbered 1 to N). As an example, a cutting structure may include a cutting face, wherein the cutting structure is mounted in a recess formed in the insert tip. The cutting structures may be arranged adjacent to each other in a radially extending row near the tip of the insert. As an example, the cutting face may have an outermost cutting tip, which may be furthest from the insert tip where the cutting structure is mounted. Figure 12As shown, the drill bit body may include various channels that allow drilling fluid to flow between the cutting blades 1212-1, 1212-2, ... 1212-N during drilling and to clean and cool the cutting blades 1212-1, 1212-2, ... 1212-N. As an example, the drill bit may be defined by a drill bit centerline and a drill bit face, with the cutting blades extending radially along the drill bit face. Figure 12 As shown, each blade 1212-1, 1212-2, ... 1212-N can extend outwards by a certain distance, thereby defining a channel between adjacent blades. As mentioned, each blade includes a blade tip, which can be defined by a blade height parameter. As described above, a cutting structure can be mounted on the blades, where drilling is to utilize the cutting structure to "cut" rock. As an example, the cutting structure can extend outwards beyond the blade tip to which it is mounted. The cutting structure (e.g., a cutting element) can be, for example, a PDC cutting structure, such that the drill bit can be called a PDC drill bit. Forming the PDC into a shape usable for the cutting structure may involve placing diamond grains together with its substrate in a pressure vessel and then sintering them under high temperature and pressure. As an example, the drill body can be considered as a carrier for the cutting structure.

[0181] As an example, the drill bit can be a matrix drill bit (MBB) or a steel-body drill bit (SBB). The matrix can be a hard but somewhat brittle composite material, which may include tungsten carbide grains metallurgically bonded to a softer, tougher metal binder. A matrix can be ideal as a drill bit material because its hardness provides wear resistance and corrosion resistance. Matrix drill bits may be able to withstand relatively high compressive loads, but may have relatively low resistance to impact loads compared to steel.

[0182] Because the matrix can be relatively inhomogeneous, as it is a composite material, and because the matrix can vary (e.g., through design and environment) due to the size and location of the tungsten carbide particles, its physical properties may be more difficult to predict than those of steel.

[0183] Matrix drill bits can be manufactured using a mold process. For example, tungsten carbide and binder material can be placed into a mold, which is then placed in a furnace for a period of time. The mold can then be cooled and released to remove the unfinished matrix drill bit.

[0184] For steel, it can withstand high impact loads but may be relatively soft and tends to fail rapidly due to wear and corrosion without protective features. High-quality steel tends to be homogeneous, and its structural constraints tend to be predictable. Steel bodies can be manufactured by processing reinforcing bars according to design.

[0185] Design features and manufacturing processes for different bit types differ in body construction because of the nature of the material from which they are made. The lower impact toughness of the matrix limits some matrix bit features, such as blade height. In contrast, steel has ductility, toughness, and is able to withstand greater impact loads. This allows steel body PDC bits to be relatively larger than matrix bits and integrate greater height into features such as blades.

[0186] Matrix body PDC bits tend to be suitable for environments where body corrosion can lead to bit failure. For diamond impregnated bits, a matrix body construction can be used. The strength and ductility of steel gives steel bit bodies a higher impact load capacity. Steel bodies tend to be more robust than matrix bodies. Because of the capabilities of steel, complex bit profiles and hydraulic designs can be built on multi-axis computer numerical control mills. Steel bits can be built to withstand multiple rebuilds to replace worn or damaged cutters, which can be beneficial to operators in low cost drilling environments.

[0187] Cutting structures or cutters of a bit can be expected to last the entire life of the bit. To perform properly, cutters can be given structural support and effective orientation from bit body features. Cutter orientation can be such that the cutters are loaded, during operation, largely (e.g., primarily) by compressive forces. To prevent loss (e.g., disengagement from the body), cutters can be held, for example, by brazing material that has sufficient structural capacity and is properly deposited during the manufacturing process.

[0188] Cutters can be properly placed on the bit face (e.g., mounted on blades) in an effort to ensure a desired amount of bottom hole coverage (e.g., full bottom hole coverage). The term “cutter density” refers, in part, to the number of cutters used in a particular bit design. For example, PDC bit cutter density can be a function of profile shape and length, as well as cutter size, type, and number. If there is cutter redundancy, the redundancy can generally increase from the center of the bit to the outer radius, as the demand for work increases as the radial distance from the centerline of the bit increases. Cutters closer to the gauge go farther, faster, and remove more rock than cutters closer to the centerline. As shown, cutter density can be illustrated by rotating the position of each cutter onto a single radial plane. Such an illustration can be referred to as a planar representation of cutter density, which is shown to increase as a function of radial position. Figure 12

[0189] Reducing the number of cutters on a bit face tends to result in the following: increased depth of cut (DOC); increased ROP; increased torque; and shortened bit life; however, increasing cutter density tends to result in: decreased ROP; decreased cutting structure cleaning efficiency; and increased bit life.

[0190] In​Figure 12 In the example of FIG. 12, for the depicted drill bit, the cutter density increases in a radial direction outward from the drill bit centerline, with the planar cutter impact pattern inscribing an image of the drill bit profile.

[0191] In Figure 12 In FIG. 12, a computer aided design (CAD) representation of a drill bit is shown along with a planar representation of the cutter density 1225, with an example of a blade tip 1226, a cutting structure 1227 (e.g., a cutter), and an example optional feature 1228 shown disposed on the blade tip 1226 (e.g., note that the drill bit can include multiple such features). As an example, a CAD file can be generated and utilized to determine one or more factors that are closely related to one or more drilling operations. For example, the CAD representation of the drill bit can be utilized to determine when the drill bit body can engage the formation. As previously mentioned, if the ROP setpoint is too high, when the differential pressure reaches its setpoint, the actual ROP can reach a physical limit through the drill bit design, which is characterized by the drill bit body engaging the formation resulting in drill bit body wear. As mentioned, the ROP engine 1000 can include a drill bit engine 1020 that can calculate a depth of cut (DOC) limit (e.g., a maximum DOC value) before the drill bit body engages the formation. As an example, the maximum DOC value can be a maximum desired DOC value, for example, defined in part by undesired, detrimental contact between the formation and one or more portions of the drill bit body (e.g., a blade tip, a blade tip, etc.). As mentioned, a data structure can include information about a plurality of drill bits organized with respect to ROP and RPM about when the drill bit body will come into contact with the formation (e.g., different types of formations). As mentioned, a framework such as the IDEAS framework can be utilized to generate such a data structure or a portion thereof.

[0192] As an example, a method can include designing or selecting a drill bit by running an IDEAS platform dynamics simulation (Schlumberger Limited, Houston, Texas), which allows options to be compared by looking at ROP performance versus impact and vibration. For a mud motor BHA, the simulation results for the drill bit are affected by the mud motor behavior. As an example, a framework can utilize one or more downhole power curves (e.g., from motor modeling, etc.) to output drill bit / motor combination results (e.g., for performance, stability, etc.).

[0193] The IDEAS integrated dynamic design and analysis platform provides 4D, time-based simulations that capture drill string and wellbore geometry for modeling cutting interface designs for rock drilling and metal milling applications. The IDEAS dynamic modeling platform includes a suite of solid mechanics and procedures that can model the interactions between the drill bit and rock, and between the mill and metal, in a virtual environment for real-time customized material design. The IDEAS platform can utilize theoretical calculations, numerical packages (e.g., finite element methods), in-house drilling rig testing, full-scale drilling rig testing, and field testing using MWD or downhole drilling dynamic sensors.

[0194] Figure 13 An example of a graphical user interface 1300 is shown, including example relationship diagrams 1310 and 1320 for the depth of cut (DOC) and weight on drill bit (WOB) for two different drill bits. Each of diagrams 1310 and 1320 includes a circle indicating the position where the top of the drill bit engages with the formation. Figure 13 As shown, the connection corresponds to a depth of cut (DOC) value (e.g., or range) and a weight on drill bit (WOB) value (e.g., or range). As shown in diagrams 1310 and 1320, the depth of cut (DOC) value is given as distance per revolution. As an example, the rate of drilling (ROP) can be determined by multiplying the drill bit's depth of cut (DOC) (distance per revolution) by the drill bit's rotational speed, which can be expressed as revolutions per unit time. For example, in the case where DOC is in inches per revolution and drill bit rotation is in revolutions per minute (RPM), ROP can be determined by multiplying DOC by RPM, resulting in ROP in inches per minute. Such values ​​can be expressed in various units, for example, Figure 19 The ROP value of 150.12 feet per hour is shown to standardize various ROP values. ROP values ​​can be given in terms of distance per unit time (e.g., feet per hour, meters per hour, etc.). As an example, such a graph can be generated using a framework such as the IDEAS framework.

[0195] As an example, a method can include determining a maximum depth of cut per revolution (DOC) when a bit tip top begins to engage the formation; determining a motor rotation rate (e.g., RPMs, etc.) from a differential pressure setpoint; determining a total bit rotation rate (e.g., it can be a function of motor RPMs and surface RPMs, etc.); and determining a rate of penetration (ROP) set limit by multiplying the depth of cut (DOC) by the total rotation rate (e.g., RPMs, etc.). Such a method can help reduce the risk of a bit tip top contacting the formation due to an improper ROP limit setting. As explained, such contact can result in bit damage, which can result in performing one or more operations, thereby introducing non-productive time (e.g., tripping out to replace the bit, replacing the bit, tripping in, etc.). As previously mentioned, there can be a variety of motivations to drill fast (e.g., high ROPs) to complete a well and begin producing fluid from the well. However, drilling fast without sufficient insight can result in bit damage and other issues. The method of providing ROP limit settings can be viewed as providing guidance, particularly where such ROP limit settings help reduce the risk of one or more issues while still aiming to drill efficiently such that a well can be completed and fluid can be produced from the well in a timely manner.

[0196] In Figure 13 In the relationship graphs 1310 and 1320, weight on bit (WOB) is used as a parameter that helps determine a maximum DOC for a given bit, where, for example, in a calculation, DOC increases with respect to WOB. As shown, the maximum DOC for a given bit is a defined value according to conditions (see, e.g., “top engagement”) that can use two types of calculations for a given bit. As explained, a wellsite installation can include a weight indicator that is operably coupled to a sensor, where the weight indicator can provide a reading that can be used to determine WOB. As previously mentioned, DOC increases with WOB; however, at certain times, depending on various factors, one or more portions of the bit can contact the formation (e.g., rock) in a manner that is damaging to the bit (e.g., to the bit body). Such damaging contact can result in damage, which can result in premature replacement of the bit (e.g., via tripping out, replacing the bit, and tripping in).

[0197] For example, the readings of the weight indicator can be used to monitor and improve operational efficiency of drilling operations. As an example, the weight indicator can be operably coupled to a hydraulic gauge (e.g., a hydraulic sensor) attached to a dead line of a drilling line. In such an example, as the tension in the drilling line increases, more hydraulic fluid is forced through the hydraulic gauge, which can cause a needle (or needles) of the weight indicator (e.g., a needle of a dial, etc.) to turn. As an example, the indicator and / or sensor can include digital circuitry, such as with a digital data output. During drilling operations, the measured weight can include various masses exerting tension on the wireline, including the traveling block and the cable itself. Thus, to accurately measure the weight of the drill string, the driller can first make a zero offset adjustment to account for the traveling block and items other than the drill string. The indicated weight will then more accurately represent the drill string (e.g., the drill pipe and bottom hole assembly). However, during drilling operations, the weight of interest is the weight exerted on the drill bit at the bottom of the well. As an example, the driller can take the rotational and hanging bottom weight (e.g., 300,000 lbf or 136,200 kgf) and subtract the rotational amount on the bottom weight (e.g., 250,000 lbf or 113,500 kgf) to obtain the drill bit weight (e.g., 50,000 lbf or 22,700 kgf). Various rigs can be equipped with a weight indicator with a second indicator dial that can be set to read zero (“zeroed”) with the drill string freely hanging, and work backward from the main indicator dial. After proper zeroing, the weight set at the bottom (e.g., weight taken off the main dial), has the effect of adding weight to this second dial, and thus, the driller can read the weight on bit (WOB) directly from the dial.

[0198] Referring again to the relationship graphs 1310 and 1320 of Figure 13 , one method can include performing the IDEAS framework bit analysis by applying different WOB values. In each relationship graph 1310 and 1320, two sets of data are presented, where the data in each set is for the same bit design; however, one curve is for data with a blade tip in the model, and another curve is for data without a blade tip in the model. In such a method, when there is a difference in DOC at the same WOB, it can be determined that the blade tip has contacted the formation to cause the difference in DOC (e.g., DOC difference). In such a method, the WOB that causes the blade tip to contact the rock can be different by simulating drilling of different rocks (e.g., different formation types, etc.). As an example, one method can include determining the maximum DOC value at which contact occurs (e.g., via a difference in calculated DOC values as shown in Figure 13 As an example, one method can or can not utilize the corresponding WOB number itself.

[0199] As referenced above,Figure 12 The blade top can have one or more different types of geometric features (e.g., see Figure 12 For example, consider a button-shaped tungsten carbide extrusion. As an example, a drill bit can include one or more such extrusions, which can act to avoid excessive DOC when one or more WOB spikes can occur due to drill bit bounce, etc. When the DOC is very small, these features can contact the top of the formation. As an example, a method can include performing an IDEAS framework analysis (e.g., or other analysis of DOC and WOB, etc.), where such contact can be allowed to occur (e.g., is acceptable). In such an example, a method can utilize a particular threshold of the difference in DOC between the two curves to determine the maximum DOC point at which blade top contact is effectively occurring. In the curve relationship graphs 1310 and 1320, the threshold can be seen in the circular area where the two curves diverge (e.g., diverge by an amount) in each curve relationship graph 1310 and 1320. As an example, a derivative type of analysis (e.g., slope) can be utilized and / or a model (e.g., linear, non-linear, etc.) can be utilized, where a difference in one or more model parameters can be analyzed, which can indicate the maximum DOC for a particular drill bit.

[0200] As described above, Figure 10 The ROP engine 1000 of FIG. 1 can include a mud motor engine 1040 as a computational engine to generate data for a particular mud motor. As described above, Figure 10 The ROP engine 1000 of FIG. 1 can utilize the mud motor engine 1040 and the drill bit engine 1020 to generate one or more ROP values.

[0201] Figure 14 An example of a drilling assembly 1400 in a geological environment 1401 is shown, the drilling assembly 1400 including a borehole 1403, where the drilling assembly 1400 (e.g., drill string) includes a drill bit 1404 and a motor portion 1410, where the motor portion 1410 includes a mud motor that can drive the drill bit 1404 (e.g., rotate the drill bit 1404 and deepen the borehole 1403).

[0202] As shown, the motor portion 1410 includes a dump 1412, a power section 1414, a surface adjustable bend housing 1416, a transmission assembly 1418, a bearing section 1420, and a drive shaft 1422, which are operably coupled to a drill bit, such as the drill bit 1404. Flow of drilling fluid through the power section 1414 can create a power that can rotate the drive shaft 1422, which can rotate the drill bit 1404.

[0203] With respect to power section 1414, two examples are shown as power section 1414-1 and power section 1414-2, each including a housing 1442, a rotor 1444, and a stator 1446. The rotor 1444 and stator 1446 can be characterized by a ratio. For example, power section 1414-1 can be a 5:6 ratio, while power section 1414-2 can be a 1:2 ratio, as seen in the cross-sectional view, which can involve lobes (e.g., rotor / stator lobe configurations). Figure 14 The motor section 1410 can be a POWERPAK series motor section (Schlumberger Limited, Houston, Texas) or another type of motor section. The POWERPAK series motor section can include 1:2, 2:3, 3:4, 4:5, 5:6, and 7:8 ratios and corresponding lobe configurations.

[0204] The power section can convert hydraulic energy from the drilling fluid into mechanical power to turn the drill bit. For example, consider a reverse application of the Moineau pump principle. During operation, drilling fluid can be pumped into the power section at a pressure that causes the rotor to spin within the stator, with the spinning force being transmitted to the drill bit through the drive shaft and drive axis.

[0205] The motor section can be partially manufactured from corrosion-resistant stainless steel, with a thin layer of chrome plating that can be present to reduce friction and wear. As an example, tungsten carbide can be used to coat the rotor, for example, to reduce wear and corrosion damage. As for the stator, it can be formed from a steel tube that can be a housing with an elastomeric material lined in the bore of the steel tube to define the stator. The elastomeric material can be referred to as a liner, or when assembled with the tube or housing, as a stator. As an example, the elastomeric material can be molded into the bore of the tube. The elastomeric material can be formulated to resist wear and hydrocarbon-induced degradation. Various types of elastomeric materials can be used for the power section, some of which can be proprietary. The properties of the elastomeric material can be tailored for a particular type of operation, which can take into account factors such as temperature, speed, rotor type, drilling fluid type, etc. The rotor and stator can be characterized by a helical profile, for example, a helix and / or lobes (see, for example, the cross-sectional view in Figure 14

[0206] ​During operation, the rotor and stator can form a continuous seal along a straight line at their point of contact, which creates multiple independent cavities. When fluid is forced through these progressive cavities, it causes the rotor to rotate within the stator. The motion of the rotor within the stator is called nutation. For each cycle of nutation, the rotor rotates a distance of one lobe width. Each lobe of the rotor nutates the stator one lobe width to complete a revolution of the bit box. For example, a motor section with a 7:8 rotor / stator lobe configuration and a bit box speed of 100 RPM will have a nutation speed of 700 revolutions per minute. Generally, torque output increases with the number of lobes, which corresponds to slower speeds. Torque also depends on the number of stages, where a stage is a complete spiral of the stator helix. Power is defined as speed times torque; however, having more lobes in a motor does not necessarily mean that the motor produces more power. Motors with more lobes tend to be less efficient because the sealing area between the rotor and stator increases with the number of blades.

[0207] The difference between the rotor average diameter (e.g., trough to lobe peak measurement) and the stator minor diameter (lobe wave peak to lobe peak) is defined as the rotor / stator interference fit. Under planned downhole conditions, various motors are fitted with rotors that are sized larger than the inner bore of the stator, which can create a strong positive interference seal called a positive fit. In the case of higher expected downhole temperatures, the positive fit can be reduced during motor assembly to allow the elastomeric material that forms the stator (e.g., stator liner) to expand. Mud weight and vertical depth can be considered as they affect the hydrostatic pressure on the stator liner. A calculation framework, such as the POWERFIT framework (Schlumberger Limited, Houston, Texas), can be used to calculate the desired interference fit.

[0208] As for some examples of elastomeric materials, consider nitrile rubber, which tends to be rated for about 138°C (280°F), and high-saturated nitrile rubber, which can be formulated to resist chemical attack and is rated for about 177°C (350°F).

[0209] The helical stage length of the stator is defined as the axial length of one lobe in the stator as it rotates 360 degrees along its helical path around the stator body. The stage length of the rotor is different than that of the stator because the stage length of the rotor is shorter than the corresponding stator. More stages can increase the number of fluid cavities in the power section, which can result in a greater total pressure drop. Under the same differential pressure conditions, power sections with more stages tend to hold speed higher because the smaller pressure drop per stage, the less leakage.

[0210] Drilling fluid temperature, which can be referred to as mud temperature or mud fluid temperature, can be a factor in determining the amount of interference in assembling the stator and rotor of the power section. As to interference, greater interference can result in the stator experiencing higher shear stresses, which can result in fatigue damage. Fatigue can result in premature chunking failure of the stator liner. As an example, chlorides or other such halides can damage the power section. For example, such halides can damage the rotor through corrosion, where the rough edges of the rotor can cut into the stator liner (e.g., cut the top off of the elastomeric liner). Such cuts can reduce the effectiveness of the rotor / stator seal and can result in the motor stalling at low differential pressure (e.g., chunking the stator). Coated rotors can be beneficial for oil-based muds (OBMs) and salt muds with supersaturated water phases.

[0211] As to differential pressure, as noted above, it is defined as the difference between the bottom hole drilling pressure and the exit bottom hole drilling pressure generated by the rotor / stator section (power section) of the motor. As noted previously, for greater differential pressures, there tends to be higher torque output and lower shaft speed. Motors that are run at greater than recommended differential pressures are more prone to premature chunking. Such chunking can follow a helical path or uniformly through the stator liner. The life of the power section can depend on factors that can result in chunking (e.g., damage to the stator), which can depend on the characteristics of the rotor (e.g., surface characteristics, etc.).

[0212] As to the trajectory of the wellbore to be drilled, it can be defined in part by one or more dogleg severities (DLSs). Rotating the motor in high DLS intervals of the well can increase the risk of damaging the stator. For example, the geometry of the wellbore can cause the motor section to bend and flex. The stator of the power section is relatively more flexible compared to other sections of the motor. Where the stator housing is bent, the elastomeric liner can be biased or pushed by the housing, which can cause the elastomeric liner to exert a force on the rotor. Such force can result in excessive compression of the stator lobes and result in chunking.

[0213] The motor can have a power curve. Testing can be performed in a laboratory using a dynamo meter, for example, using water at room temperature to determine the relationship between input (which is flow rate and differential pressure) and power output (in the form of RPM and torque). Such information can be available in the motor manual. However, due to various factors, the actual occurrences downhole can be different. For example, the output (e.g., motor power output) can be reduced due to the effects of downhole pressure and temperature. Such reduction can lead one to conclude that the motor is not working. In response, the driller can continue to push, causing the pressure to become too high, which can damage the elastomeric material (e.g., damage the stator) due to stalling.

[0214] Figure 15An example of a graphical user interface 1500 of a computing framework that can generate mud motor data, such as that shown in an RPM and torque versus differential pressure plot 1510, is shown. As shown, the GUI 1500 can include various fields for inputting mud motor parameters (e.g., eccentricity, maximum flow, minimum flow, stator major diameter, rotor major diameter, rotor minor diameter, lobe number, stator stage number, etc.) and can include various fields for inputting model parameters (e.g., power section type, elastomer type, fit profile type, fit adjustment, mud density, mud temperature, reference temperature, hydraulic, etc.). Figure 15

[0215] Figure 16 An example relationship plot 1610 of a mud motor having a 6 / 7 power section and an 8.0 stage is shown. In the relationship plot 1610, various points that can be considered for one or more drilling operations are shown. Specifically, in the example of Figure 16 the relationship plot 1610 includes the following points: ΔΡ of 800, 1000, and 1200 psi; flow of 250 and 350 GPM; and SRPM 40, 60, and 80.

[0216] Figure 17 An example of a graphical user interface 1700 that includes an example table 1710 and an example relationship plot 1720 of values for flow, SRPM (surface RPM provided by surface equipment), differential pressure, and ROP setpoint for a combination of a drill bit and a mud motor is shown.

[0217] Figure 18 An example of a graphical user interface 1800 that includes an example table 1810 and an example relationship plot 1820 of values for flow, SRPM (surface RPM provided by surface equipment), differential pressure, and ROP setpoint for another combination of a drill bit and a mud motor is shown.

[0218] Figure 19 An example of a graphical user interface 1900 that includes stabilized rate of penetration (ROP) sensitivity data that is encoded according to factors such as lateral vibration risk, axial vibration risk, and stick-slip risk, among others, is shown.

[0219] In the example of Figure 19 the GUI 1900 includes a sensitivity chart in which the data in the chart is generated via performing a drilling simulation. The chart can be considered a base that, for example, can be presented to a display in a cabin (e.g., doghouse, etc.) at a rig site at which a drilling operation is to occur, is occurring, etc. As explained, a well site can include various instrumentation, such as one or more weight indicators, pressure indicators, rotational rate indicators, flow indicators, etc. As noted above, such instrumentation can be analog and / or digital. ​

[0220] In Figure 19 examples, the base shows values that simulate drilling scenarios with indications about the impact and vibration response at the bit. In the base (within the thick black line), each cell is a drilling scenario with a given flow rate, surface RPM (SRPM), and WOB, where the differential pressure (DP) to output the given WOB is given.

[0221] During planning and / or execution, when one or more drilling parameters are selected, the method can include selecting one or more cells with less impact and vibration risk and higher machine ROP. For example, consider that running with a WOB over 20 klbf will result in higher impact and vibration risk (see, e.g., “Lat(3.0)”). As such, it can be indicated that it is recommended (see, e.g., “Stable”) to use a WOB below 20 klbf (e.g., greater than or equal to 15 klbf and less than 20 klbf). As an example, the operation can use differential pressure controlled drilling, where it can be recommended to run the motor with a differential pressure below about 389 psi (see, e.g., “Lat(3.0)” and “Stable”). For example, consider an automatic and / or semi-automatic drilling method that can utilize differential pressure controlled drilling. In such an example, the controller can be set to operate in a differential pressure controlled drilling mode, where the differential pressure setpoint is 350 psi (e.g., below 389 psi in the case of low impact and vibration risk), and where the ROP set limit can then be determined using a suitable example workflow (see, e.g., “Lat(3.0)”, “Stable”, and “Lat(3.0)”). As an example, the workflow can include determining the maximum DOC of the bit; determining the total RPM of the bit by adding the surface RPM (SRPM) and the motor RPM, where the motor RPM can be calculated using the differential pressure setpoint, the flow rate, and the motor characteristics; and determining the maximum ROP set limit of the controller. Such a method can include drilling using the maximum ROP set limit (e.g., the maximum ROP setpoint limit, etc.), where the drilling can be performed in an automatic manner, a semi-automatic manner, and / or a manual manner (e.g., via one or more human input devices (HIDs) operably coupled to the drilling equipment, etc.). Figure 13 、 Figure 20 、 Figure 21 etc.). As an example, the workflow can include determining the maximum DOC of the bit; determining the total RPM of the bit by adding the surface RPM (SRPM) and the motor RPM, where the motor RPM can be calculated using the differential pressure setpoint, the flow rate, and the motor characteristics; and determining the maximum ROP set limit of the controller. Such a method can include drilling using the maximum ROP set limit (e.g., the maximum ROP setpoint limit, etc.), where the drilling can be performed in an automatic manner, a semi-automatic manner, and / or a manual manner (e.g., via one or more human input devices (HIDs) operably coupled to the drilling equipment, etc.).

[0222] With respect to Figure 19Various vibration indications in examples, as an example, axial vibrations can cause the bit to bounce (e.g., consider the impact associated with bouncing), which can damage the bit cutters and bearings. Lateral vibrations are a destructive vibration that can create a large impact when the BHA hits the wellbore wall. In some cases, the interaction between the BHA and the point of contact of the drill string can cause the system to develop a reverse whirl. Reverse whirl tends to be the most severe form of vibration, creating high frequency, large amplitude bending moment fluctuations, which results in high fatigue rates of components and connections. Imbalances in the assembly can cause centrifugally induced drill string bending, which can create a forward whirl and cause one-sided wear of the assembly. Torsional vibrations can cause irregular downhole rotation. Stick-slip can be seen while drilling, and can be a severe form of torsional vibration of the drill string, where the bit will be stationary for a period of time. As the degree of stick-slip increases, the length of the sticking period tends to increase, as does the rotational acceleration upon break-out of the bit. Torsional fluctuations can fatigue the drill collar connections and can damage the bit. If the primary excitation source is from the bit, drilling operations using a mud motor can help to resolve stick-slip, but the presence of the mud motor itself does not prevent stick-slip. For example, even if the mud motor is turning the bit at a steady rate, the drill string and BHA above the mud motor can exhibit stick-slip motion.

[0223] In Figure 19 examples, the stable region of operating parameters is shown with respect to differential pressure (DP), WOB, SRPM (surface RPM as provided by surface equipment), and FLOW, where ROP is normalized by a factor of 150.12 feet per hour.

[0224] As an example, a trajectory can be defined in part by a measured depth (MD) metric, which can be, for example, 1000 meters or more. As an example, consider a trajectory of a well in the Permian Basin with a total measured depth of over 1000 meters, and a well plan that indicates three to ten trips to drill three sections. In such an example, an ROP engine can be utilized to generate one or more ROP values that can account for bit and / or mud motor conditions. In such an example, by performing one or more drilling operations in accordance with the one or more ROP values, the number of trips can be reduced or optimized to a minimum. The reduction in the number of trips can save a significant amount of time, as it can take several hours (e.g., over four hours) to drill from a 5000 meter MD hole. At times, a driller can drill as fast as possible based on personal knowledge, which can lead to uncertainty regarding equipment and the number of trips. The ROP engine can help reduce such uncertainty and reduce the requirement for the driller to drill fast, as the rig can drill in accordance with a recommended, generated ROP value (or values). Over the course of days (e.g., or weeks) of drilling, reducing the requirement for the driller can help the driller focus on one or more other activities, concerns, etc. (e.g., safety of workers, etc.).

[0225] As an example, consider a drilling operation in accordance with an output of an ROP engine, where, for example, drill cuttings carried to the surface by drilling fluid can be analyzed. In such an example, the drill cuttings can be compared to data input to the ROP engine, such as to a bit engine that can determine DOC data regarding the formation. In such an example, in the event of a mismatch between the input to the bit engine and the drill cuttings analysis output, the bit engine can be executed, and the ROP engine can generate one or more revised ROP values. In such an example, there can be a loop that can cause the ROP engine to produce one or more revised ROP values based on data regarding the formation being drilled.

[0226] As an example, in the event of a trip that is scheduled or otherwise required, the ROP engine can be executed to determine one or more bit types and / or mud motor types that can be suitable to continue drilling while tripping in. For example, consider a recommendation for a bit and mud motor combination for an unscheduled trip, where the current bit and mud motor can be replaced once the drill string is tripped out. Such an approach can provide one or more of fewer future trips, better ROP, reduction in total time, etc. As tripping out can take several hours, in the event of a decision to replace the bit and / or mud motor in accordance with a recommendation of the ROP engine, ground activities can occur to facilitate the replacement. For example, procuring the bit and / or mud motor (e.g., retrieving from inventory, shipping in, etc.) and preparing the bit and / or mud motor for replacement (e.g., positioning, preparing tools, etc.).

[0227] As explained, a ROP engine can help reduce the occurrence of accidental damage while providing the best ROP or a set of ROPs that may be associated with various types of risks (see, for example...). Figure 19 (GUI1900). In this method, the ROP engine can provide one or more ROP setpoints, which can facilitate scheduling (see, for example, GUI1900). Figure 9 The GUI 900) reduces the risk of scheduling changes. Figure 9 As shown in GUI 900, for an 8.5-inch well section, drilling to depth (3530 ft to 6530 ft or 1076 m to 1990 m) is estimated to take approximately 103 hours, or about 4.3 days. If unexpected (e.g., unplanned) tripping is required due to equipment conditions, this could extend the time by half a day, representing an increase of approximately 10% over the estimated time. If the equipment condition is due to the drill body engaging with the formation being drilled, this could indicate that modifying the ROP value (e.g., per drill bit motor) might be beneficial. In such an example, the ROP motor could use information (e.g., drill cuttings, drill bit condition, etc.) to generate one or more revised ROP values, thereby reducing the risk of recurring drill bit-related events and making the ROP acceptable for the same type of drill bit and / or for different types of drill bits and / or motors.

[0228] Figure 20 An example of method 2000 is shown, which includes a receiving box 2010 for receiving candidate drill bits, a generation box 2012 for generating cut depth (DOC) and engagement data, an output box 2014 for outputting DOC and engagement data, a receiving box 2030 for receiving drill bit motor range, a generation box 2032 for generating mud motor data, a generation box 2050 for generating one or more drilling rate of progress (ROP) values, a planning box 2052 for generating a drilling operation plan using one or more of the one or more ROP values, and a control box 2054 for controlling one or more drilling operations using one or more of the one or more ROP values. As an example, method 2000 can utilize... Figure 10 The ROP engine 1000 may include one or more features. For example, blocks 2010, 2012, and 2014 may utilize a drill engine 1020, while blocks 2030 and 2032 may utilize a mud motor engine 1040. As described above, the ROP engine 1000 may include one or more other features 1060.

[0229] exist Figure 20In the example, method 2000 can be implemented in real time, wherein, for example, data acquired via one or more technologies (e.g., sensors, etc.) is used as feedback to one or more boxes 2010, 2012, 2014, 2030, 2032 and 2050, which may result in the generation of one or more ROP values, and optionally, the generation of one or more modified ROP values.

[0230] exist Figure 20 In the example, box 2012 may output data, such as data from GUI 1300 for one or more drill bits, whereby the depth of cut (DOC) at the drill bit tip engaging the formation can be determined (e.g., regarding the risk of drill bit body damage). As an example, the drill bit tip may be defined by one or more portions of the cutting edge. In such an example, the DOC may be defined as the maximum depth of cut (e.g., maximum DOC). As an example, the maximum DOC may be defined as undesirable, harmful contact between one or more portions of the drill bit and the formation (e.g., rock), which could put the drill bit at risk of damage (e.g., reduced lifespan). As an example, box 2012 may utilize a computational framework, such as the IDEAS framework.

[0231] exist Figure 20 In the example, box 2030 may include receiving one or more recommended differential pressure ranges, one or more SRPM ranges, and one or more flow rate ranges, which may be associated with one or more drill bit and mud motor combinations. As an example, box 2030 may include receiving one or more of the aforementioned ranges from operational data and / or real-time data. For example, consider operational data for a drilled section, a portion of a drilled section, an off-center well, etc. As for real-time data, this data may be closely related to the equipment and / or operating conditions in the field. For example, mud pump data may be considered as being associated with one or more types of drilling fluid, which can provide indications about differential pressure ranges, flow rate ranges, and SRPM ranges (e.g., because RPM is related to drilling fluid flow rate). As for box 2032, it may include motor power part characteristics, which may be in the form of one or more motor power part characteristic curves (e.g., from specifications, mud motor engines, mud motor engine test data, etc.).

[0232] Regarding the generation box 2050, it can utilize various information to generate one or more ROP values, which can be output as limits (e.g., setpoints, etc.) to guide the driller, control drilling, etc. As an example, method 2000 may include determining the maximum DOC of the drill bit when the tip of the drill bit is in effective contact with the formation; determining the total RPM of the drill bit by adding the surface RPM and the motor RPM (e.g., the motor RPM can be determined by the differential pressure setpoint, flow rate, and motor characteristics); and generating the ROP setting limit by multiplying the maximum DOC (e.g., per revolution) by the total RPM.

[0233] As an example, the method 2000 can output one or more data structures including one or more ROP values, e.g., as shown in example GUIs 1700 and 1800 of Figure 17 and 18 As an example, the method 2000 can output ROP setpoint recommendations in the form of a lookup table or other type of data structure. In such examples, the data structure can include flow, SRPM, differential pressure information, which can be used to determine ROP setpoints given the flow, SRPM, and differential pressure.

[0234] Figure 20 The method 2000 of FIG. 2000 is shown as including various computer readable storage medium (CRM) blocks 2011, 2013, 2015, 2031, 2033, 2051, 2053, and 2055, which can include processor executable instructions that can direct a computing system (which can be a control system) to perform one or more actions described with respect to the method 2000. As an example, a system such as the system 470 of Figure 4 The system of the system 470 can be used to implement one or more portions of the method 2000, as an example. As an example, the instructions 476 can include instructions that are executable by at least one of the one or more processors 472.

[0235] Figure 21 An example of the method 2100 and an example of the system 2190 are shown. The method 2100 includes a receiving block 2110 for receiving a maximum depth of cut value for a drill bit that accounts for bit body formation engagement, a receiving block 2120 for receiving a total rate of rotation value for the drill bit based at least in part on a differential pressure value for a mud motor, a generating block 2130 for generating a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum depth of cut value with the total rate of rotation value, and an operating block 2140 for operating a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit operably coupled to the mud motor.

[0236] With respect to the generating block 2130, it can utilize methods as explained with respect to the generating block 2050 of Figure 20 As explained, one method can include determining a maximum ROP set limit as a function of the particular drill bit used, the motor used, and the differential pressure setpoint.

[0237] As an example, a method can include determining a maximum depth of cut value for a drill bit that accounts for bit body formation engagement; determining a total RPM value for the drill bit by adding a surface RPM value and a mud motor RPM value, where the mud motor RPM value is calculated using a differential pressure value (e.g., a differential pressure setpoint, etc.), a flow rate value, and one or more mud motor characteristics; and generating a maximum ROP limit (e.g., a setpoint limit) for drilling a well using the drill bit that is operably coupled to the mud motor. In such an example, the surface RPM value (SRPM) can be a zero or a non-zero value. As described above, drilling can be via the mud motor or via the mud motor and one or more surface motors (e.g., a rotary table, a top drive, etc.).

[0238] Method 2100 is shown to include various computer-readable storage media (CRM) blocks 2111, 2121, 2131, and 2141, which can include processor-executable instructions that can direct a computing system (which can be a control system) to perform one or more actions described with respect to method 2100.

[0239] In Figure 21 In an example, system 2190 includes one or more information storage devices 2191, one or more computers 2192, one or more networks 2195, and instructions 2196. With respect to one or more computers 2192, each computer can include one or more processors (e.g., or processing cores) 2193 and a memory 2194 (e.g., see blocks 2111, 2121, 2131, and 2141) to store instructions 2196 that are executable, for example, by at least one of the one or more processors 2193. As an example, a computer can include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), etc.

[0240] As an example, method 2100 can be a workflow that can be implemented using one or more frameworks within a framework environment. As an example, system 2190 can include local and / or remote resources. For example, a browser application executing on a client device is considered a local resource with respect to a user of the browser application, and a cloud-based computing device is considered a remote resource with respect to the user. In such an example, the user can interact with the client device via the browser application, where information is transmitted to the cloud-based computing device (or devices), and where information can be received and presented in response to the display operably coupled to the client device (e.g., via a service, an API, etc.).

[0241] Figure 22An example of system 2200 is shown, which could be a well construction ecosystem. As illustrated, system 2200 may include one or more instances of ROP engine 1000 and may include drilling rig infrastructure 2210 and drilling planning component 2220. Drilling planning component 2220 may generate or otherwise transmit information associated with a plan to be executed using drilling rig infrastructure 2210, for example via drilling operations layer 2240, which includes well site component 2242 and off-site component 2244. As illustrated, data acquired and / or generated by drilling operations layer 2240 may be transmitted to data archiving component 2250, which may be used for purposes such as planning one or more operations (e.g., according to drilling planning component 2220).

[0242] exist Figure 22 In the example, ROP engine 1000 is shown to be implemented for drilling planning component 2220, well site component 2242 and / or off-site component 2244.

[0243] As an example, the ROP engine 1000 can interact with one or more components in system 2200. As shown, the ROP engine 1000 can be used in conjunction with drilling planning component 2220. In such an example, data accessed from data archiving component 2250 can be used to evaluate the output of the ROP engine 1000, or, for example, can be used as input to the ROP engine 1000. As an example, data archiving component 2250 can include drilling data for one or more off-site wells and / or one or more current wells, relating to the specifications and / or operation of one or more types of drill bits, one or more types of mud motors, etc. In such an example, the drilling data can include bottom hole data, where the drill bit engages the formation at the bottom of the borehole to drill into the formation. As an example, such data can be used in conjunction with a framework such as the IDEAS framework. As an example, such data can be used with... Figure 10 This is used in conjunction with the drill bit engine 1020. As an example, this data can include mud motor operating data, which can be used, for example, in conjunction with the mud motor engine 1040. Figure 22As shown, various components of the drilling operations layer 2240 can utilize the ROP engine 1000 and / or a drilling digital plan output by the drilling plan component 2220. During drilling, performance data can be acquired, which the ROP engine 1000 can utilize to, for example, update one or more ROP values (e.g., ROP limits, etc.). Such performance data can be archived in the data archive component 2250, which can be archived during one or more drilling operations and can be obtained by the drilling plan component 2220, for example, for re-planning, etc. As an example, performance data can include going bottom data, as described above, which can be used by and / or in conjunction with the ROP engine 1000.

[0244] For example, going bottom data can include data related to a drill bit marking a bottom, which can include data such as weight on bit data, and can include data related to rotating the drill bit via a mud motor and / or surface equipment. As an example, the system 2200 can aim to optimize going bottom in a manner that complies with one or more ROP limits. For example, optimization can include reducing the risk of damaging a well, drill bit, and / or mud motor. As an example, optimization can take into account, for example, formation cuttings that can have migrated to the bottom of the well during a connection (e.g., adding pipe, etc.). As an example, one or more types of data can be used to determine whether a drill bit has marked a bottom, including, for example, a decrease in hook load corresponding to the drill bit being under weight, an increase in surface torque when the drill bit begins to engage with material at the bottom of the well, an increase in standpipe pressure when the drill bit nozzle flow begins to encounter more resistance, and / or whether a mud motor is running when the drill bit reaches material at the bottom of the well. As shown in the example GUI 1100, one or more ROP setpoints and / or one or more ROP limits can be utilized during drilling, which can be periodic (e.g., in a pipe-by-pipe or stand-by-stand manner, in a state-based manner, etc.).

[0245] As previously described, drilling can increase the depth of a bore. As an example, during non-drilling (e.g., a non-drilling state), the flow rate of fluid pumped into the drill string can increase and / or decrease, the rate of rotation of the drill string can increase and / or decrease, the drill bit can move upward and / or downward, or a combination thereof. Non-drilling activity can be or include a time when the drill bit is idle (e.g., not drilling) and the slip assembly is not engaged with the drill string.

[0246] As an example, pre-connection can refer to a state in which the drill bit has completed drilling operations for a current pipe segment, etc., but the slip assembly has not yet begun to move (e.g., radially inward) into engagement with the drill string. During pre-connection, the flow rate of fluid pumped into the drill string can increase and / or decrease, the rate of rotation of the drill string can increase and / or decrease, the drill bit can move upward and / or downward, or a combination thereof.

[0247] As an example, connection can refer to a state in which the slip assembly is engaged with and supporting the drill string (e.g., the drill string is “in the inner slips”). When a connection occurs, a section (e.g., pipe, stand, etc.) can be added to the drill string to increase the length of the drill string, or a section can be removed from the drill string to decrease the length of the drill string.

[0248] As an example, post-connection can refer to a state in which the slip assembly releases the drill string, the drill string with the drill bit descends to the bottom (e.g., the bottom hole or BOH). During post-connection, the flow rate of fluid pumped into the drill string can increase and / or decrease, the rate of rotation of the drill string can increase and / or decrease, the drill bit can move upward and / or downward, or a combination thereof.

[0249] As an example, a method can include drilling a well according to one or more generated ROP values, which can be one or more ROP setpoints and / or one or more ROP limits. In such an example, a drilling system can be categorized according to one or more operating states (e.g., drilling states, etc.). As an example, a transition to a drilling state can trigger the use of one or more ROP values (e.g., generated by ROP engine 1000). As explained with respect to GUI 1900 of Figure 19 Various factors can be considered in selecting an ROP value. As described above, an ROP value can be selected based at least in part on a vibration risk and / or a stick-slip risk.

[0250] As shown in method 2000 of Figure 20 One or more generated ROP values (e.g., generated by ROP engine 1000) can be used for planning (e.g., by planning block 2052) and / or can be used for control (e.g., by control block 2054). As an example, method 2000 of Figure 20 Method 2000 of and / or method 2100 of Figure 21 One or more actions of method 2000 of system 2200 can be utilized. Figure 22

[0251] As an example, a method can include receiving a drill bit maximum cut depth value that considers a drill bit body formation engagement; receiving a total rate of rotation value for the drill bit based at least in part on a differential pressure value for a mud motor; generating a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum cut depth value and the total rate of rotation value; and operating a wellsite system according to the rate of penetration value to drill a portion of a borehole with the drill bit operably coupled to the mud motor. In such an example, the rate of penetration (ROP) value can be a setpoint or limit (e.g., see GUI 1100, etc.). Figure 11

[0252] ​​As an example, a drilling rate value can be generated for the drilling fluid flow rate, as previously mentioned, where the drilling fluid can be used to drive a mud motor (e.g., see...). Figure 14 Motor part 1410).

[0253] As an example, drilling rate values ​​can be generated for the surface rotation rate values ​​of the surface equipment in a well site system, which rotates the drill string including the drill bit and mud motor.

[0254] As an example, the maximum cutting depth value could consider one or more button-shaped features that prevent the drill bit from bouncing off the formation. For instance, consider a tungsten carbide-type button-shaped feature that could be included in the drill bit.

[0255] As an example, one approach could include presenting drilling rate values ​​to a display of a controller operatively coupled to a well site system (see, for example, Figure 4 System 470 Figure 22 System 2200, etc.

[0256] As an example, one approach may include setting a drilling rate setpoint using a drilling rate value, and, for example, using the drilling rate setpoint to control equipment of the well site system (see, for example, Figure 11 (GUI1100).

[0257] As an example, drilling may include sliding mode drilling and / or rotary mode drilling (e.g., see...). Figure 7 The graphical user interface 700).

[0258] As an example, a method may include generating sensitivity information for multiple differential pressure values ​​having one or more corresponding drilling rate values, wherein the sensitivity information indicates vibration risk (e.g., see...). Figure 19 (GUI1900). In such an example, each of the plurality of differential pressure values ​​may include a corresponding surface rotation rate value, each of the plurality of differential pressure values ​​may include a corresponding drill pressure value, each of the plurality of differential pressure values ​​may include a corresponding surface rotation rate value and a corresponding flow rate value, and each of the plurality of differential pressure values ​​may include a corresponding drill pressure value, a corresponding surface rotation rate value, and a corresponding flow rate value. As an example, vibration risk may include at least one of lateral vibration risk and axial vibration risk. As an example, drilling may include using one or more corresponding drilling rate values ​​as a drilling rate setpoint (e.g., or limit) and using one of the plurality of differential pressure values ​​as a differential pressure setpoint (e.g., or limit).

[0259] As an example, a method can include generating sensitivity information for a plurality of weight on bit values having one or more respective rate of penetration values, where the sensitivity information indicates a vibration risk. In such an example, drilling can include utilizing one of the one or more respective rate of penetration values as a rate of penetration setpoint (e.g., or limit), and utilizing one of the plurality of weight on bit values as a weight on bit setpoint (e.g., or limit).

[0260] As an example, a method can include changing a rate of penetration setpoint in response to an analysis of drill cuttings generated by drilling. For example, consider analyzing drill cuttings for an indication that formation properties of a drilled formation do not match formation properties of bit body formation engagement data (e.g., used to determine a maximum depth of cut value). As an example, drill cuttings can be, for example, chips of rock brought to the surface by drilling fluid (e.g., mud).

[0261] As an example, a method can include evaluating one or more rate of penetration values to select a bit, a mud motor, or a combination of a bit and a mud motor for tripping in and subsequent drilling in response to a decision to pause drilling and tripping out.

[0262] As an example, bit body formation engagement data can include data for a matrix bit. For example, bit body formation engagement data can include data for one or more button features of a bit.

[0263] As an example, a method can include generating rate of penetration stability sensitivity data for at least one type of vibration. For example, consider axial vibrations and / or lateral vibrations.

[0264] As an example, drilling can include directional drilling. As an example, drilling can be performed according to a borehole trajectory that includes a dogleg.

[0265] As an example, drilling can be performed according to a digital plan that includes one or more generated ROP values that can be used as one or more setpoints and / or one or more limits during drilling (e.g., execution of the digital plan). As an example, one or more signals can trigger a change in setpoint and / or one or more limits using one or more generated ROP values. As an example, a system such as Figure 22 A system of system 2200, such as

[0266] As an example, a system can include a processor; a memory accessible to the processor; processor-executable instructions stored in the memory that are executable to instruct the system to: receive a maximum depth of cut value for a drill bit that accounts for bit body formation engagement; receive a total rotational rate value for the drill bit that is based at least in part on a differential pressure value for a mud motor; generate a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum depth of cut value and the total rotational rate value; and operate a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit operably coupled to the mud motor.

[0267] As an example, one or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: receive a maximum depth of cut value for a drill bit that accounts for bit body formation engagement; receive a total rotational rate value for the drill bit that is based at least in part on a differential pressure value for a mud motor; generate a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum depth of cut value and the total rotational rate value; and operate a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit operably coupled to the mud motor.

[0268] As an example, a method can be implemented, in part, using a computer-readable medium (CRM), for example, a module, a block, and the like, that includes information such as instructions suitable to cause one or more processors (or processor cores) to perform one or more actions. As an example, a single medium can be configured to contain instructions to permit, at least in part, performance of various actions of a method. As an example, a computer-readable medium (CRM) can be a computer-readable storage medium (e.g., a non-transitory medium) that is not a carrier wave.

[0269] According to an embodiment, one or more computer-readable media can include computer-executable instructions to instruct a computing system to output information for controlling a process. For example, such instructions can provide output to sense a process, inject a process, drill a well, extract a process, squeeze a process, pump a process, heat a process, and the like.

[0270] In some embodiments, a computing system can perform one or more methods. Figure 23 An example of a system 2300 that can include one or more computing systems 2301-1, 2301-2, 2301-3, and 2301-4 is shown, which can be operatively coupled via one or more networks 2309, which can include wired and / or wireless networks.

[0271] As an example, a system can include a single computer system or a distributed computer system arrangement. In Figure 23In the example of FIG. 23, computer system 2301-1 can include one or more modules 2302, which can be or include processor-executable instructions, for example, executable to perform various tasks (e.g., receive information, request information, process information, simulations, output information, etc.).

[0272] As an example, the modules can be executed independently or in coordination with one or more processors 2304, which can be operatively coupled to the one or more storage media 2306 (e.g., via wired, wireless, etc.). As an example, one or more of the one or more processors 2304 can be operatively coupled to at least one of the one or more network interfaces 2307. In such examples, computer system 2301-1 may, for example, send and / or receive information via one or more networks 2309 (e.g., consider one or more of the Internet, a private network, a cellular network, a satellite network, etc.).

[0273] As an example, computer system 2301-1 can receive information from and / or send information to one or more other devices, which can be or include, for example, one or more computer systems 2301-2, etc. The devices can be located at a physical location different from computer system 2301-1. As an example, the location can be, for example, a processing facility location, a data center location (e.g., a server farm, etc.), a drilling rig location, a wellsite location, a downhole location, etc.

[0274] As an example, a processor can be or include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or other control or computing device.

[0275] As an example, storage media 2306 can be implemented as one or more computer- or machine-readable storage media. As an example, storage can be distributed across multiple internal and / or external enclosures of a computing system and / or additional computing systems.

[0276] As an example, the one or more storage media can include one or more different forms of memory including semiconductor memory devices, such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), Blu-ray disks, or other types of optical storage, or other types of storage devices.

[0277] As an example, one or more storage media can reside with a machine that runs the machine- readable instructions, or one or more storage media can be remote from a machine that runs the machine-readable instructions, such as a cloud-based storage media.

[0278] As an example, various components of the system, such as computer system, can be implemented in hardware, software, or a combination of both hardware and software (e.g., including firmware), including one or more signal processing and / or application specific integrated circuits.

[0279] As an example, the system can include a processing device, which can be or include a general purpose processor or a special purpose chip (e.g., or chip set), such as an ASIC, FPGA, PLD, or other suitable device.

[0280] Figure 24 Components of computing system 2400 and network system 2410 are shown. The system 2400 includes one or more processors 2402, memory and / or storage components 2404, one or more input and / or output devices 2406, and a bus 2408. According to an embodiment, instructions can be stored in one or more computer-readable media (e.g., memory / storage component 2404). Such instructions can be read by one or more processors (e.g., processor(s) 2402) via a communication bus (e.g., bus 2408), which can be wired or wireless. The one or more processors can execute such instructions to implement (in whole or in part) one or more attributes (e.g., as part of a method). A user can view and interact with output from a process via an I / O device (e.g., device(s) 2406). According to an embodiment, a computer-readable medium can be a storage component, such as a physical memory storage device, e.g., a chip, chip on a package, memory card, etc.

[0281] According to an embodiment, components can be distributed, such as in network system 2410. Network system 2410 includes components 2422-1, 2422-2, 2422-3... 2422-N. For example, component 2422-1 can include processor(s) 2402, while component 2422-3 can include memory accessible by processor(s) 2402. Further, component 2422-2 can include an I / O device for display and optionally interaction with a method. The network can be or include the Internet, an intranet, a cellular network, a satellite network, etc.

[0282] For example, a device can be a mobile device that includes one or more network interfaces for communicating information. For example, a mobile device can include a wireless network interface (e.g., operable via IEEE 802.11, ETSI GSM, Bluetooth, satellite, etc.). As an example, a mobile device can include components such as a main processor, memory, display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), SIM slot, audio / video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery. As an example, a mobile device can be configured as a cell phone, tablet, etc. As an example, a method (e.g., in whole or in part) can be implemented using a mobile device. As an example, a system can include one or more mobile devices.

[0283] As an example, a system can be a distributed environment, e.g., a so-called "cloud" environment, in which various devices, components, etc. interact for data storage, communication, computation, etc. purposes. As an example, a device or system can include one or more components for communicating information via one or more of the Internet (e.g., where communication is via one or more Internet protocols), a cellular network, a satellite network, etc. As an example, a method can be implemented in a distributed environment (e.g., in whole or in part as a cloud-based service).

[0284] As an example, information can be input from a display (e.g., consider a touchscreen), output to a display, or both. As an example, information can be output to a projector, a laser device, a printer, etc. so that the information can be viewed. As an example, information can be output stereoscopically or holographically. As to a printer, consider a 2D or 3D printer. As an example, a 3D printer can include one or more substances that can be output to construct a 3D object. For example, data can be provided to a 3D printer to construct a 3D representation of a subsurface formation. As an example, layers can be constructed in 3D (e.g., stratigraphic layers, etc.), 3D constructs of geologic bodies, etc. As an example, holes, fractures, etc. can be constructed in 3D (e.g., as positive structures, as negative structures, etc.).

[0285] Although only a few examples have been described in detail above, those skilled in the art will readily comprehend many modifications. Accordingly, all such modifications are intended to be included within the scope of the present disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited functions and not only structural equivalents, but also equivalent structures. Thus although a nail and a screw can not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw can be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. 112, paragraph 6 for any limitations of any of the claims herein, except for where otherwise specifically recited in such claims.

Claims

1. A method for drilling a portion of a borehole, comprising: receiving a maximum depth of cut value for a drill bit that accounts for bit body formation engagement; receiving a total rate of rotation value for the drill bit that includes a rate of rotation value for a mud motor calculated from a differential pressure value for the mud motor; generating a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum depth of cut value and the total rate of rotation value; and operating a wellsite system in accordance with the rate of penetration value to drill a portion of a borehole using the drill bit operably coupled to the mud motor.

2. The method of claim 1, wherein, The rate of penetration value is generated for a flow rate of a drilling fluid.

3. The method of claim 1, wherein, The rate of penetration value is generated for a surface rate of rotation value for a surface device of the wellsite system that rotates a drill string that includes the drill bit and the mud motor.

4. The method of claim 1, wherein, The maximum depth of cut value accounts for one or more button features that protect the drill bit from bit-to-formation bounce.

5. The method of claim 1, comprising presenting the rate of penetration value to a display that is operably coupled to a controller of the wellsite system.

6. The method of claim 1, comprising setting a rate of penetration setpoint using the rate of penetration value.

7. The method of claim 6, comprising controlling a device of the wellsite system using the rate of penetration setpoint.

8. The method of claim 1, wherein, Drilling the borehole includes drilling the borehole in a sliding mode.

9. The method of claim 1, wherein, Drilling the borehole includes drilling the borehole in a rotary mode.

10. The method of claim 1, comprising generating sensitivity information for a plurality of differential pressure values having one or more corresponding rate of penetration values, wherein the sensitivity information indicates a vibration risk.

11. The method of claim 10, wherein, Each of the plurality of differential pressure values includes a corresponding surface rate of rotation value.

12. The method of claim 10, wherein, Each of the plurality of differential pressure values includes a corresponding weight on bit value.

13. The method of claim 10, wherein, Each of the plurality of differential pressure values includes a corresponding surface rate of rotation value and a corresponding flow rate value.

14. The method of claim 10, wherein, Each of the plurality of differential pressure values includes a corresponding weight on bit value, a corresponding surface rate of rotation value, and a corresponding flow rate value.

15. The method of claim 10, wherein, The vibration risk includes at least one of a lateral vibration risk and an axial vibration risk.

16. The method of claim 10, wherein, Drilling the borehole includes utilizing one of the one or more corresponding rate of penetration values as a rate of penetration setpoint and utilizing one of the plurality of differential pressure values as a differential pressure setpoint.

17. The method of claim 1, comprising generating sensitivity information for a plurality of weight on bit values having one or more corresponding rate of penetration values, wherein the sensitivity information indicates a vibration risk.

18. The method of claim 17, wherein, Drilling the borehole includes utilizing one of the one or more corresponding rate of penetration values as a rate of penetration setpoint and utilizing one of the plurality of weight on bit values as a weight on bit setpoint.

19. A system for drilling a portion of a borehole, comprising: a processor; a memory accessible by the processor; processor-executable instructions stored in the memory and executable to instruct the system to: receive a maximum depth of cut value for a drill bit that accounts for bit body formation engagement; receive a total rate of rotation value for the drill bit that includes a rate of rotation value for a mud motor calculated from a differential pressure value for the mud motor; generate a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum depth of cut value and the total rate of rotation value; and and The wellsite system is operated in accordance with the rate of penetration value to drill a portion of the borehole using the drill bit operably coupled to the mud motor.

20. One or more computer-readable storage media comprising processor-executable instructions to instruct a computing system to: receive a maximum depth of cut value for a drill bit that accounts for a formation engagement of a bit body; receive a total rate of rotation value for the drill bit that includes a rate of rotation value for the mud motor calculated from the differential pressure value of the mud motor; generate a rate of penetration value for the drill bit operably coupled to the mud motor by multiplying the maximum depth of cut value with the total rate of rotation value; and operate the wellsite system in accordance with the rate of penetration value to drill a portion of the borehole using the drill bit operably coupled to the mud motor.

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