Apparatus, systems, and methods for efficiently communicating a geosteering trajectory adjustment

Apparatus, systems, and methods according to which a geosteering trajectory change is efficiently communicated by presenting, on a first human-machine interface, a plurality of selectable trajectory types, each of the trajectory types representing a potential trajectory of a wellbore, selecting, via the first human-machine interface, the selectable trajectory type most closely representing a desired trajectory of the wellbore, the selected trajectory type including one or more data fields adapted to receive one or more task parameters needed to drill the wellbore along the desired trajectory, entering, via the first human-machine interface, the one or more task parameters into the one or more data fields of the selected trajectory type, and pushing the selected trajectory type and/or the one or more entered task parameters to a control system adapted to control drilling equipment to drill the wellbore along the desired trajectory.

TECHNICAL FIELD

The present disclosure relates generally to oil and gas drilling and production operations, and, more particularly, to a geosteering trajectory change communication apparatus, system, and method.

BACKGROUND

At the outset of a drilling operation, drillers typically establish a well plan that includes a steering objective location (or target location) and a drilling path to the steering objective location. The well plan may be based on a subsurface model developed from surface testing (e.g., seismic or otherwise) and/or data gathered from wells adjacent to the drilling location. Once drilling commences, a bottom-hole assembly (BHA) may be directed or “steered” from a vertical drilling path (in any number of directions) to follow the proposed well plan. For example, to recover an underground hydrocarbon deposit, a well plan might include a vertical bore to the side of a reservoir containing a deposit, then a directional or horizontal bore that penetrates the deposit. The operator may then follow the plan by steering the BHA through the vertical and horizontal aspects in accordance with the plan.

Due to the difficulty in measuring subsurface lithology prior to the drilling of a well, the well plan may need to be adjusted as the well is drilled closer to the target location—such adjustments may be made based on data received from measurement-while-drilling (MWD) tool(s) and/or logging-while-drilling (LWD) tool(s) of the BHA. The MWD and LWD tool(s) take periodic surveys allowing operators to assess whether the BHA (and therefore the drill-bore itself) is substantially following the well plan. The process of “geosteering” involves making trajectory adjustments by analyzing data from the MWD and LWD tool(s) to determine where the preferred zone of the formation is actually located. If the geosteerer determines that the well trajectory needs to be changed, the recommended change must be effectively communicated to the rig personnel or operator(s) at the well site so the target location can be changed accordingly. Therefore, what is needed is an apparatus, system, and/or method that addresses one or more of the foregoing issues, and/or one or more other issues.

DETAILED DESCRIPTION

The present disclosure aims to facilitate the effective communication of a desired well trajectory from a geosteerer (e.g., a geosteering system user, such as a geologist located remote from drilling equipment) to a control system of the drilling equipment, a driller at or near the drilling equipment, and/or any combination thereof. While conventional systems relay well trajectory changes through a complex and tedious review and approval process before implementation (often by word of mouth, email, or telephone communications among rig personnel, the geosteerer, and others), the apparatus, systems, and methods herein allow for much faster and more efficient implementation of a desired well trajectory by facilitating communication of said trajectory directly between the geosteerer and the control system of the drilling equipment, the driller tasked with operating the drilling equipment (e.g., via the control system), and/or any combination thereof. To this end, a systematic approach is disclosed for optimizing the manner in which the desired well trajectory is communicated from the geosteerer (or another person having authority over well trajectory changes) to the drilling equipment's control system and/or the driller.

Referring toFIG. 1, an embodiment of a drilling rig (a.k.a., drilling equipment) for implementing the aims of the present disclosure is schematically illustrated and generally referred to by the reference numeral10. The drilling rig10is or includes a land-based drilling rig—however, one or more aspects of the present disclosure are applicable or readily adaptable to any type of drilling rig (e.g., a jack-up rig, a semisubmersible, a drill ship, a coiled tubing rig, a well service rig adapted for drilling and/or re-entry operations, and a casing drilling rig, among others). The drilling rig10includes a mast12that supports lifting gear above a rig floor14, which lifting gear includes a crown block16and a traveling block18. The crown block16is coupled to the mast12at or near the top of the mast12. The traveling block18hangs from the crown block16by a drilling line20. The drilling line20extends at one end from the lifting gear to drawworks22, which drawworks22are configured to reel out and reel in the drilling line20to cause the traveling block18to be lowered and raised relative to the rig floor14. The other end of the drilling line20(known as a dead line anchor) is anchored to a fixed position, possibly near the drawworks22(or elsewhere on the rig).

The drilling rig10further includes a top drive24, a hook26, a quill28, a saver sub30, and a drill string32. The top drive24is suspended from the hook26, which hook is attached to the bottom of the traveling block18. The quill28extends from the top drive24and is attached to a saver sub30, which saver sub is attached to the drill string32. The drill string32is thus suspended within a wellbore34. The quill28may instead be attached directly to the drill string32. The term “quill” as used herein is not limited to a component which directly extends from the top drive24, or which is otherwise conventionally referred to as a quill28. For example, within the scope of the present disclosure, the “quill” may additionally (or alternatively) include a main shaft, a drive shaft, an output shaft, and/or another component which transfers torque, position, and/or rotation from the top drive24or other rotary driving element to the drill string32, at least indirectly. Nonetheless, albeit merely for the sake of clarity and conciseness, these components may be collectively referred to herein as the “quill.”

The drill string32includes interconnected sections of drill pipe36, a bottom-hole assembly (“BHA”)38, and a drill bit40. The BHA38may include stabilizers, drill collars, and/or measurement-while-drilling (“MWD”) or wireline conveyed instruments, among other components. The drill bit40is connected to the bottom of the BHA38or is otherwise attached to the drill string32. One or more mud pumps42deliver drilling fluid to the drill string32through a hose or other conduit44, which conduit may be connected to the top drive24. The downhole MWD or wireline conveyed instruments may be configured for the evaluation of physical properties such as pressure, temperature, torque, weight-on-bit (“WOB”), vibration, inclination, azimuth, toolface orientation in three-dimensional space, and/or other downhole parameters. These measurements may be made downhole, stored in solid-state memory for some time, and downloaded from the instrument(s) at the surface and/or transmitted in real-time or delayed time to the surface. Data transmission methods may include, for example, digitally encoding data and transmitting the encoded data to the surface as pressure pulses in the drilling fluid or mud system. The MWD tools and/or other portions of the BHA38may have the ability to store measurements for later retrieval via wireline and/or when the BHA38is tripped out of the wellbore34.

The drilling rig10may also include a rotating blow-out preventer (“BOP”)46, such as if the wellbore34is being drilled utilizing under-balanced or managed-pressure drilling methods. In such an embodiment, the annulus mud and cuttings may be pressurized at the surface, with the actual desired flow and pressure possibly being controlled by a choke system, and the fluid and pressure being retained at the well head and directed down the flow line to the choke system by the rotating BOP46. The drilling rig10may also include a surface casing annular pressure sensor48configured to detect the pressure in the annulus defined between, for example, the wellbore34(or casing therein) and the drill string32. In the embodiment ofFIG. 1, the top drive24is utilized to impart rotary motion to the drill string32. However, aspects of the present disclosure are also applicable or readily adaptable to embodiments utilizing other drive systems, such as a power swivel, a rotary table, a coiled tubing unit, a downhole motor, and/or a conventional rotary rig, among others.

The drilling rig10also includes a control system50configured to control or assist in the control of one or more components of the drilling rig10—for example, the control system50may be configured to transmit operational control signals to the drawworks22, the top drive24, the BHA38and/or the mud pump(s)42. The control system50may be a stand-alone component installed near the mast12and/or other components of the drilling rig10. In some embodiments, the control system50includes one or more systems located in a control room proximate the drilling rig10, such as the general purpose shelter often referred to as the “doghouse” serving as a combination tool shed, office, communications center, and general meeting place. The control system50may be configured to transmit the operational control signals to the drawworks22, the top drive24, the BHA38, and/or the mud pump(s)42via wired or wireless transmission (not shown). The control system50may also be configured to receive electronic signals via wired or wireless transmission (also not shown) from a variety of sensors included in the drilling rig10, where each sensor is configured to detect an operational characteristic or parameter. The sensors from which the control system50is configured to receive electronic signals via wired or wireless transmission (not shown) may include one or more of the following: a torque sensor24a, a speed sensor24b, a WOB sensor24c, a downhole annular pressure sensor38a, a shock/vibration sensor38b, a toolface sensor38c, a WOB sensor38d, the surface casing annular pressure sensor48, a mud motor delta pressure (“ΔP”) sensor52a, and one or more torque sensors52b.

It is noted that the meaning of the word “detecting,” in the context of the present disclosure, may include detecting, sensing, measuring, calculating, and/or otherwise obtaining data. Similarly, the meaning of the word “detect” in the context of the present disclosure may include detect, sense, measure, calculate, and/or otherwise obtain data. The detection performed by the sensors described herein may be performed once, continuously, periodically, and/or at random intervals. The detection may be manually triggered by an operator or other person accessing a human-machine interface (HMI), or automatically triggered by, for example, a triggering characteristic or parameter satisfying a predetermined condition (e.g., expiration of a time period, drilling progress reaching a predetermined depth, drill bit usage reaching a predetermined amount, etc.). Such sensors and/or other detection means may include one or more interfaces which may be local at the well/rig site or located at another, remote location with a network link to the drilling rig10.

The drilling rig10may include any combination of the following: the torque sensor24a, the speed sensor24b, and the WOB sensor24c. The torque sensor24ais coupled to or otherwise associated with the top drive24—however, the torque sensor24amay alternatively be located in or associated with the BHA38. The torque sensor24ais configured to detect a value (or range) of the torsion of the quill28and/or the drill string32in response to, for example, operational forces acting on the drill string32. The speed sensor24bis configured to detect a value (or range) of the rotational speed of the quill28. The WOB sensor24cis coupled to or otherwise associated with the top drive24, the drawworks22, the crown block16, the traveling block18, the drilling line20(which includes the dead line anchor), or another component in the load path mechanisms of the drilling rig10. More particularly, the WOB sensor24cincludes one or more sensors different from the WOB sensor38dthat detect and calculate weight-on-bit, which can vary from rig to rig (e.g., calculated from a hook load sensor based on active and static hook load).

Further, the drilling rig10may additionally (or alternatively) include any combination of the following: the downhole annular pressure sensor38a, the shock/vibration sensor38b, the toolface sensor38c, and the WOB sensor38d. The downhole annular pressure sensor38ais coupled to or otherwise associated with the BHA38, and may be configured to detect a pressure value or range in the annulus-shaped region defined between the external surface of the BHA38and the internal diameter of the wellbore34(also referred to as the casing pressure, downhole casing pressure, MWD casing pressure, or downhole annular pressure). Such measurements may include both static annular pressure (i.e., when the mud pump(s)42are off) and active annular pressure (i.e., when the mud pump(s)42are on). The shock/vibration sensor38bis configured for detecting shock and/or vibration in the BHA38. The toolface sensor38cis configured to detect the current toolface orientation of the drill bit40, and may be or include a magnetic toolface sensor which detects toolface orientation relative to magnetic north or true north. In addition, or instead, the toolface sensor38cmay be or include a gravity toolface sensor which detects toolface orientation relative to the Earth's gravitational field. In addition, or instead, the toolface sensor38cmay be or include a gyro sensor. The WOB sensor38dmay be integral to the BHA38and is configured to detect WOB at or near the BHA38.

Further still, the drilling rig10may additionally (or alternatively) include a MWD survey tool38eat or near the BHA38. In some embodiments, the MWD survey tool38eincludes any of the sensors38a-38das well as combinations of these sensors. The BHA38and the MWD portion of the BHA38(which portion includes the sensors38a-dand the MWD survey tool38e) may be collectively referred to as a “downhole tool.” Alternatively, the BHA38and the MWD portion of the BHA38may each be individually referred to as a “downhole tool.” The MWD survey tool38emay be configured to perform surveys along length of a wellbore, such as during drilling and tripping operations. The data from these surveys may be transmitted by the MWD survey tool38eto the control system50through various telemetry methods, such as mud pulses. In addition, or instead, the data from the surveys may be stored within the MWD survey tool38eor an associated memory. In this case, the survey data may be downloaded to the control system50when the MWD survey tool38eis removed from the wellbore or at a maintenance facility at a later time. The MWD survey tool38eis discussed further below with reference toFIG. 2.

Finally, the drilling rig10may additionally (or alternatively) include any combination of the following: the mud motor ΔP sensor52aand the torque sensor(s)52b. The mud motor ΔP sensor52ais configured to detect a pressure differential value or range across one or more motors52of the BHA38and may comprise one or more individual pressure sensors and/or a comparison tool. The motor(s)52may each be or include a positive displacement drilling motor that uses hydraulic power of the drilling fluid to drive the drill bit40(also known as a mud motor). The torque sensor(s)52bmay also be included in the BHA38for sending data to the control system50that is indicative of the torque applied to the drill bit40by the motor(s)52.

Referring toFIG. 2, an apparatus is diagrammatically shown and generally referred to by the reference numeral54. The apparatus54includes at least respective parts of the drilling rig10, including, but not limited to, the control system50, the drawworks22, the top drive24(identified as a “drive system”), the BHA38, and the mud pump(s)42. The apparatus54may be implemented within the environment and/or the drilling rig10ofFIG. 1. The drilling rig10and the apparatus54may be collectively referred to as a “drilling system.” As shown inFIG. 2, the control system50includes a user-interface56and a controller58—depending on the embodiment, these may be discrete components that are interconnected via a wired or wireless link. The user-interface56and the controller58may additionally (or alternatively) be integral components of a single system. The user-interface56may include an input mechanism60that permits a user to input drilling settings or parameters such as, for example, left and right oscillation revolution settings (these settings control the drive system to oscillate a portion of the drill string32), acceleration, toolface setpoints, rotation settings, a torque target value (such as a previously calculated torque target value that may determine the limits of oscillation), information relating to the drilling parameters of the drill string32(such as BHA information or arrangement, drill pipe size, bit type, depth, and formation information), and/or other setpoints and input data.

The input mechanism60may include a keypad, voice-recognition apparatus, dial, button, switch, slide selector, toggle, joystick, mouse, database, and/or any other suitable data input device. The input mechanism60may support data input from local and/or remote locations. In addition, or instead, the input mechanism60, when included, may permit user-selection of predetermined profiles, algorithms, setpoint values or ranges, such as via one or more drop-down menus—this data may instead (or in addition) be selected by the controller58via the execution of one or more database look-up procedures. In general, the input mechanism60and/or other components within the scope of the present disclosure support operation and/or monitoring from stations on the rig site as well as one or more remote locations with a communications link to the system, network, local area network (“LAN”), wide area network (“WAN”), Internet, satellite-link, and/or radio, among other suitable techniques or systems. The user-interface56may also include a display62for visually presenting information to the user in textual, graphic, or video form. The display62may be utilized by the user to input drilling parameters, limits, or setpoint data in conjunction with the input mechanism60—for example, the input mechanism60may be integral to or otherwise communicably coupled with the display62. The controller58may be configured to receive data or information from the user, the drawworks22, the top drive24, the BHA38, and/or the mud pump(s)42—the controller58processes such data or information to enable effective and efficient drilling.

The BHA38includes one or more sensors (typically a plurality of sensors) located and configured about the BHA38to detect parameters relating to the drilling environment, the condition and orientation of the BHA38, and/or other information. For example, the BHA38may include an MWD casing pressure sensor64, an MWD shock/vibration sensor66, a mud motor ΔP sensor68, a magnetic toolface sensor70, a gravity toolface sensor72, an MWD torque sensor74, and an MWD weight-on-bit (“WOB”) sensor76—in some embodiments, one or more of these sensors is, includes, or is part of the following sensor(s) shown inFIG. 1: the downhole annular pressure sensor38a, the shock/vibration sensor38b, the toolface sensor38c, the WOB sensor38d, the mud motor ΔP sensor52a, and/or the torque sensor(s)52b.

The MWD casing pressure sensor64is configured to detect an annular pressure value or range at or near the MWD portion of the BHA38. The MWD shock/vibration sensor66is configured to detect shock and/or vibration in the MWD portion of the BHA38. The mud motor ΔP sensor68is configured to detect a pressure differential value or range across the mud motor of the BHA38. The magnetic toolface sensor70and the gravity toolface sensor72are cooperatively configured to detect the current toolface. In some embodiments, the magnetic toolface sensor70is or includes a magnetic toolface sensor that detects toolface orientation relative to magnetic north or true north. In some embodiments, the gravity toolface sensor72is or includes a gravity toolface sensor that detects toolface orientation relative to the Earth's gravitational field. In some embodiments, the magnetic toolface sensor70detects the current toolface when the end of the wellbore34is less than about 7° from vertical, and the gravity toolface sensor72detects the current toolface when the end of the wellbore34is greater than about 7° from vertical. Other toolface sensors may also be utilized within the scope of the present disclosure that may be more or less precise (or have the same degree of precision), including non-magnetic toolface sensors and non-gravitational inclination sensors. The MWD torque sensor74is configured to detect a value or range of values for torque applied to the bit by the motor(s) of the BHA38. The MWD weight-on-bit (“WOB”) sensor76is configured to detect a value (or range of values) for WOB at or near the BHA38.

The following data may be sent to the controller58via one or more signals, such as, for example, electronic signal via wired or wireless transmission, mud-pulse telemetry, another signal, or any combination thereof: the casing pressure data detected by the MWD casing pressure sensor64, the shock/vibration data detected by the MWD shock/vibration sensor66, the pressure differential data detected by the mud motor ΔP sensor68, the toolface orientation data detected by the toolface sensors70and72, the torque data detected by the MWD torque sensor74, and/or the WOB data detected by the MWD WOB sensor76. The pressure differential data detected by the mud motor ΔP sensor68may alternatively (or additionally) be calculated, detected, or otherwise determined at the surface, such as by calculating the difference between the surface standpipe pressure just off-bottom and the pressure measured once the bit touches bottom and starts drilling and experiencing torque.

The BHA38may also include a MWD survey tool78—in some embodiments, the MWD survey tool78is, includes, or is part of the MWD survey tool38eshown inFIG. 1. The MWD survey tool78may be configured to perform surveys at intervals along the wellbore34, such as during drilling and tripping operations. The MWD survey tool78may include one or more gamma ray sensors that detect gamma data. The data from these surveys may be transmitted by the MWD survey tool78to the controller58through various telemetry methods, such as mud pulses. In other embodiments, survey data is collected and stored by the MWD survey tool78in an associated memory80. This data may be uploaded to the controller58at a later time, such as when the MWD survey tool78is removed from the wellbore34or during maintenance. Some embodiments use alternative data gathering sensors or obtain information from other sources. For example, the BHA38may include sensors for making additional measurements, including, for example and without limitation, azimuthal gamma data, neutron density, porosity, and resistivity of surrounding formations. In some embodiments, such information may be obtained from third parties or may be measured by systems other than the BHA38.

The BHA38may include a memory80and a transmitter82. In some embodiments, the memory80and transmitter82are integral parts of the MWD survey tool78, while in other embodiments, the memory80and transmitter82are separate and distinct modules. The memory80may be any type of memory device, such as a cache memory (e.g., a cache memory of the processor), random access memory (RAM), magnetoresistive RAM (MRAM), read-only memory (ROM), programmable read-only memory (PROM), erasable programmable read only memory (EPROM), electrically erasable programmable read only memory (EEPROM), flash memory, solid state memory device, hard disk drives, or other forms of volatile and non-volatile memory. The memory80may be configured to store readings and measurements for some period of time. In some embodiments, the memory80is configured to store the results of surveys performed by the MWD survey tool78for some period of time, such as the time between drilling connections, or until the memory80may be downloaded after a tripping out operation. The transmitter82may be any type of device to transmit data from the BHA38to the controller58, and may include a mud pulse transmitter. In some embodiments, the MWD survey tool78is configured to transmit survey results in real-time to the surface through the transmitter82. In other embodiments, the MWD survey tool78is configured to store survey results in the memory80for a period of time, access the survey results from the memory80, and transmit the results to the controller58through the transmitter82.

The top drive24includes one or more sensors (typically a plurality of sensors) located and configured about the top drive24to detect parameters relating to the condition and orientation of the drill string32, and/or other information. For example, the top drive24may include a rotary torque sensor84, a quill position sensor86, a hook load sensor88, a pump pressure sensor90, a mechanical specific energy (“MSE”) sensor92, and a rotary RPM sensor94—in some embodiments, one or more of these sensors is, includes, or is part of the following sensor shown inFIG. 1: the torque sensor24a, the speed sensor24b, the WOB sensor24c, and/or the casing annular pressure sensor48. The top drive24also includes a controller96for controlling the rotational position, speed, and direction of the quill28and/or another component of the drill string32coupled to the top drive24—in some embodiments, the controller96is, includes, or is part of the controller58.

The rotary torque sensor84is configured to detect a value (or range of values) for the reactive torsion of the quill28or the drill string32. The quill position sensor86is configured to detect a value (or range of values) for the rotational position of the quill28(e.g., relative to true north or another stationary reference). The hook load sensor88is configured to detect the load on the hook26as it suspends the top drive24and the drill string32. The pump pressure sensor90is configured to detect the pressure of the mud pump(s)42providing mud or otherwise powering the BHA38from the surface. In some embodiments, rather than being included as part of the top drive24, the pump pressure sensor90may be incorporated into, or included as part of, the mud pump(s)42. The MSE sensor92is configured to detect the MSE representing the amount of energy required per unit volume of drilled rock—in some embodiments, the MSE is not directly detected, but is instead calculated at the controller58(or another controller) based on sensed data. The rotary RPM sensor94is configured to detect the rotary RPM of the drill string32—this may be measured at the top drive24or elsewhere (e.g., at surface portion of the drill string32). The following data may be sent to the controller58via one or more signals, such as, for example, electronic signal via wired or wireless transmission: the rotary torque data detected by the rotary torque sensor84, the quill position data detected by the quill position sensor86, the hook load data detected by the hook load sensor88, the pump pressure data detected by the pump pressure sensor90, the MSE data detected (or calculated) by the MSE sensor92, and/or the RPM data detected by the RPM sensor88.

The mud pump(s)42include a controller98and/or other means for controlling the pressure and flow rate of the drilling mud produced by the mud pump(s)42—such control may include torque and speed control of the mud pump(s)42to manipulate the pressure and flow rate of the drilling mud and the ramp-up or ramp-down rates of the mud pump(s)42. In some embodiments, the controller98is, includes, or is part of the controller58.

The drawworks22include a controller100and/or other means for controlling feed-out and/or feed-in of the drilling line20(shown inFIG. 1)—such control may include rotational control of the drawworks to manipulate the height or position of the hook and the rate at which the hook ascends or descends. The drill string feed-off system of the drawworks22may instead be a hydraulic ram or rack and pinion type hoisting system rig, where the movement of the drill string32up and down is facilitated by something other than a drawworks. The drill string32may also take the form of coiled tubing, in which case the movement of the drill string32in and out of the wellbore34is controlled by an injector head which grips and pushes/pulls the tubing in/out of the wellbore34. Such embodiments still include a version of the controller100configured to control feed-out and/or feed-in of the drill string32. In some embodiments, the controller100is, includes, or is part of the controller58.

The controller58may be configured to receive data or information relating to one or more of the above-described parameters from the user-interface56, the BHA38(including the MWD survey tool78), the top drive24, the mud pump(s)42, and/or the drawworks22, as described above, and to utilize such information to enable effective and efficient drilling. In some embodiments, the parameters are transmitted to the controller58by one or more data channels. In some embodiments, each data channel may carry data or information relating to a particular sensor. The controller58may be further configured to generate a control signal, such as via intelligent adaptive control, and provide the control signal to the top drive24, the mud pump(s)42, and/or the drawworks22to adjust and/or maintain one or more of the following: the rotational position, speed, and direction of the quill28and/or another component of the drill string32coupled to the top drive24, the pressure and flow rate of the drilling mud produced by the mud pump(s)42, and the feed-out and/or feed-in of the drilling line20. Moreover, the controller96of the top drive24, the controller98of the mud pump(s)42, and/or the controller100of the drawworks22may be configured to generate and transmit a signal to the controller58—these signal(s) influence the control of the top drive24, the mud pump(s)42, and/or the drawworks22. In addition, or instead, any one of the controllers96,98, and100may be configured to generate and transmit a signal to another one of the controllers96,98, or100, whether directly or via the controller58—as a result, any combination of the controllers96,98, and100may be configured to cooperate in controlling the top drive24, the mud pump(s)42, and/or the drawworks22.

In operation, the drilling rig10and/or the apparatus54are utilized to drill stands down one after the other in order to advance the drill string32and the wellbore34in accordance with the well plan. To begin the process of drilling down a particular stand, the stand is connected at the top of the drill string32on the rig floor14. Moreover, the top drive24is connected to an upper end portion of the made-up stand. The mud pump(s)42are started to initiate the flow of drilling mud into the made-up stand and the drill string32. Before, during, or after the starting of the mud pump(s)42, the drawworks22are used to reel in the drilling line20so that the drill string32is lifted out of slips—thereafter, the drilling line20is reeled out to lower the BHA38to the bottom of the wellbore34. Before, during, or after the lowering of the BHA38to the bottom of the wellbore34, the mud pump(s)42are ramped up (e.g., in one or more stages) to circulate drilling mud downhole through the drill string32to the BHA38and uphole in an annulus between the drill string32and the wellbore34to the surface. In some embodiments, the drilling mud is instead circulated downhole in the annulus between the drill string32and the wellbore34to the BHA38and uphole through the drill string32to the surface. During or after the ramping up of the mud pump(s)42, drilling is initiated by rotating the top drive24(for rotary drilling) and/or rotating the motor(s)52of the BHA38(for slide drilling) to thereby rotate the drill bit40.

Surveys are conducted at each drill pipe or stand connection—these periodic surveys are transmitted from the BHA38to the surface via the transmitter82the MWD survey tool (e.g.,38eor78) so that a geosteerer (or directional driller), may assess whether the BHA38(and thus the wellbore34) is substantially following the well plan (or whether the well plan needs adjustment). If the geosteerer determines that the wellbore34's trajectory needs to be changed, the recommended change must be effectively communicated to the control system and/or a driller at or near the rig floor14.

Referring toFIG. 3, effective communication of a desired wellbore34trajectory is facilitated by a system generally referred to by the reference numeral102. The system102enables the trajectory of the wellbore34to be adjusted periodically to ensure compliance with the well plan. In addition, or instead, the system102enables adjustment of the well plan itself in view of differences between measurements of the subsurface lithology (taken prior to the drilling of the wellbore34) and real-time or delayed time data received from the downhole MWD or wireline conveyed instruments described herein. The system102includes drilling equipment104for drilling down stands to advance the wellbore34, a control system106connected to the drilling equipment104and adapted to control the operation thereof to drill the wellbore34, and a monitoring system108connected to the drilling equipment104and adapted to monitor the drilling of the wellbore34. The control system106includes, is associated with, or is adapted to execute, a software program110and is operable by a driller112to control the drilling equipment104. The control system106may include, for example, the control system50, the controller58, the controller96, the controller98, the controller100, another computing device (not shown) or any combination thereof. The drilling equipment104may include, for example, the drawworks22, the top drive24, the BHA38, the mud pump(s)42, another component of the drilling rig10, the apparatus54, or the system102, or any combination thereof. The monitoring system108includes, is associated with, or is adapted to execute, a software program114that is operable by a geosteerer116to determine a desired trajectory of the wellbore34relative to the well plan and/or a current trajectory of the wellbore34. Upon determining the desired trajectory of the wellbore34, the geosteerer116enters the desired trajectory into a human-machine interface (“HMI”)118.

In some embodiments, the monitoring system108includes the MWD survey tool38eor78—the monitoring system108may additionally (or alternatively) include, for example, the torque sensor24a, the speed sensor24b, the WOB sensor24c, the downhole annular pressure sensor38a, the shock/vibration sensor38b, the toolface sensor38c, the WOB sensor38d, the surface casing annular pressure sensor48, mud motor ΔP sensor52a, the torque sensor(s)52b, the MWD casing pressure sensor64, the MWD shock/vibration sensor66, the mud motor ΔP sensor68, the magnetic toolface sensor70, the gravity toolface sensor72, the MWD torque sensor74, the MWD WOB sensor76, the rotary torque sensor84, quill position sensor86, the hook load sensor88, the pump pressure sensor90, the MSE sensor92, the rotary RPM sensor94, or any combination thereof. In some embodiments, the monitoring system108additionally (or alternatively) includes a computing device (not shown) operable by the geosteerer116to execute the software program114. Moreover, although shown as part of the monitoring system108, in some embodiments, the software program114is operable by the geosteerer116(after the geosteerer116obtains the necessary information from the monitoring system108) on a separate computing device (not shown) to determine the desired trajectory of the wellbore34relative to the well plan and/or the current trajectory of the wellbore34. Thereafter, the geosteerer enters the desired trajectory into the HMI118, as will be described in further detail below.

Turning toFIG. 4, in an embodiment, selectable trajectory types120(a)-(d) are presented to the geosteerer116on the HMI118, each of the trajectory types120(a)-(d) representing a potential trajectory of the wellbore34and including one or more data fields into which one or more task parameters needed to drill the wellbore34along the desired trajectory are enterable. To initiate the process of adjusting the trajectory of the wellbore34, the geosteerer116selects the trajectory type120(a)-(d) most closely representing the desired trajectory of the wellbore34and enters the one or more corresponding task parameters into the one or more data fields. The geosteerer116then pushes (by selecting a “push trajectory” button122on the HMI118) the selected trajectory type (i.e.,120(a),120(b),120(c), or120(d)) and the one or more entered task parameters to one or both of a human-machine interface (“HMI”)124and the control system106(shown inFIG. 3), as will be described in further detail below.

As shown inFIGS. 4 and 5(a), the selectable trajectory type120(a) may be referred to as a “plan line shift” trajectory type and represents a potential trajectory in which the wellbore34is shifted relative to the well plan and/or the current trajectory of the wellbore34—the plan line shift trajectory type120(a) includes data fields in which the following task parameters are adapted to be entered by the geosteerer116: a first distance126(a), a second distance126(b), a third distance126(c), and a fourth distance126(d) by which the trajectory of the wellbore34is adapted to be shifted up, down, left, and right, respectively, relative to the well plan and/or the current trajectory of the wellbore34. InFIG. 5(a), the well plan and/or the current trajectory of the wellbore34is represented by reference numeral128, and the potential trajectory in which the wellbore34is shifted is represented by reference numeral130.

Further, as shown inFIGS. 4 and 5(b), the selectable trajectory type120(b) may be referred to as a “dip hold” trajectory type and represents a potential trajectory in which the wellbore34has a constant inclination—the dip hold trajectory type120(b) includes a data filed in which the following task parameter is adapted to be entered by the geosteerer116: an inclination132of the wellbore34. InFIG. 5(b), the well plan and/or the current trajectory of the wellbore34is represented by reference numeral134, and the potential trajectory in which the wellbore34has a constant inclination is represented by reference numeral136.

Further still, as shown inFIGS. 4 and 5(c), the selectable trajectory type120(c) may be referred to as a “target point” trajectory type and represents a potential trajectory in which the wellbore34is directed to a target point—the target point trajectory type120(c) includes data fields in which the following task parameters are adapted to be entered by the geosteerer116: an estimate138of the measured depth of the wellbore34at the target point, and an estimate140of the true vertical depth of the wellbore34at the target point. InFIG. 5(c), the well plan and/or the current trajectory of the wellbore34is represented by reference numeral142, and the potential trajectory in which the wellbore34is directed to the target point is represented by reference numeral144.

Finally, as shown inFIGS. 4 and 5(d), the selectable trajectory type120(d) may be referred to as a “plan change” trajectory type and represents a potential trajectory in which the wellbore34includes one or more inflection points that are each followed by a corresponding wellbore34segment with constant azimuth and inclination—the plan change trajectory type120(d) includes data fields in which the following task parameters are adapted to be entered by the geosteerer116: a measured depth146for each of the one or more inflection points, azimuth148and inclination150values for the one or more corresponding wellbore34segments, and a total depth152of the wellbore34at which the plan change is meant to terminate. Moreover, the plan change trajectory type120(d) includes an “add inflection” button154that, when selected, adds an inflection point and a corresponding wellbore34segment with constant azimuth and inclination to the plan change trajectory type120(d)—as a result, the geosteerer116can enter any desired number of inflection points into the plan change trajectory type120(d). InFIG. 5(c), the well plan and/or the current trajectory of the wellbore34is represented by reference numeral156, and the potential trajectory in which the wellbore34includes one or more inflection points followed by corresponding wellbore34segments with constant azimuth and inclination is represented by reference numeral158.

Referring still toFIG. 4, in an embodiment, another data field is presented on the HMI118, where a user may enter an intended effective depth160at which the control system106is intended to initiate control of the drilling equipment104to drill the wellbore34along the desired trajectory. In some embodiments, the intended effective depth is pushed to the control system106along with the selected trajectory type (i.e.,120(a), (b), (c), or (d)) and the one or more entered task parameters. The control system106is thus capable of controlling the drilling equipment104, based on the pushed trajectory type (i.e.,120(a), (b), (c), or (d)), the one or more pushed task parameters, and the pushed intended effective depth160, to drill the wellbore34along the desired trajectory. In some embodiments, an actual effective depth162is presented on the HMI118, at which actual effective depth162the control system106initiates control of the drilling equipment104to drill the wellbore34along the desired trajectory. In addition, the geosteerer116may select a “view log” button164presented on the HMI118to view a trajectory log166(shown inFIG. 6) in which at least the pushed trajectory type (i.e.,120(a), (b), (c), or (d)), the one or more pushed task parameters, the pushed intended effective depth160, and the actual effective depth162at which the control system106initiates control of the drilling equipment104to drill the wellbore34along the desired trajectory are stored.

Turning again toFIG. 3, the geosteerer116pushes (by selecting the “push trajectory” button122on the HMI118) the selected trajectory type (120(a),120(b),120(c), or120(c)) and the one or more entered task parameters to one or both of the HMI124and the control system106. More particularly, the geosteerer116pushes the selected trajectory type (120(a),120(b),120(c), or120(c)) and the one or more entered task parameters to a network168that is communicatively connected to the HMI124and/or the control system106. The selected trajectory type (120(a),120(b),120(c), or120(c)) and the one or more entered task parameters are then communicated from the network168to the HMI124. In some embodiments, the HMI124is located at or near the drilling equipment104and the HMI118is located remote from the drilling equipment104. In some embodiments, step-by-step instructions for drilling the wellbore34along the desired trajectory are presented on the HMI124so as to be ascertainable by the driller112(e.g., visually, audibly, etc.) at or near the rig floor14. The step-by-step instructions are determined based on the selected trajectory type (120(a),120(b),120(c), or120(c)) and/or the one or more task parameters.

Upon receipt, the driller112is able to operate the control system106in accordance with the step-by-step instructions to drill the wellbore34along the desired trajectory. More particularly, the control system106includes, is associated with, or is adapted to execute, the software program110, which software program is operable by the driller112to control the drilling equipment104. In some embodiments, the software program110is different from the software program114. In addition, or instead, the selected trajectory type (120(a),120(b),120(c), or120(c)) and the one or more entered task parameters may be communicated from the network168to the control system106(as indicated by the dashed-line arrow inFIG. 3). In some embodiments, the control system106additionally (or alternatively) includes a computing device (not shown) operable by the driller112to execute the software program110. Moreover, although shown as part of the control system106, in some embodiments, the software program110is operable by the driller112(upon receipt of the necessary step-by-step instructions from the HMI124) on a separate computing device (not shown) to control the drilling equipment104to drill the wellbore34along the desired trajectory.

Referring toFIG. 7(a), a method is diagrammatically illustrated and generally referred to by the reference numeral200—in relation to the method200, the term “drilling equipment” may refer to any combination of the drawworks22, the top drive24, the BHA38, the mud pump(s)42, the control system50, and one or more other components of the drilling rig10, the apparatus54, or the system102. In some embodiments, the method200includes presenting, on the HMI118, the selectable trajectory types120(a)-(d), each of the trajectory types120(a)-(d) representing a potential trajectory of the wellbore34at a step202; selecting, via the HMI118, the selectable trajectory type (i.e.,120(a), (b), (c), or (d)) most closely representing a desired trajectory of the wellbore34, the selected trajectory type (120(a), (b), (c), or (d)) including one or more data fields into which one or more task parameters needed to drill the wellbore34along the desired trajectory are adapted to be entered at a step204; entering, via the HMI118, the one or more task parameters into the one or more data fields of the selected trajectory type (120(a), (b), (c), or (d)) at a step206; and pushing the selected trajectory type (120(a), (b), (c), or (d)) and the one or more entered task parameters to the control system106adapted to control the drilling equipment104to drill the wellbore34along the desired trajectory at a step208.

In some embodiments of the method200, the potential trajectory of the wellbore34represented by the selected trajectory type (120(a), (b), (c), or (d)) is shifted relative to a current trajectory of the wellbore34, and the one or more task parameters needed to drill the wellbore34along the desired trajectory include first, second, third, and fourth distances by which the trajectory of the wellbore34is shifted up, down, left, and right, respectively, relative to the current trajectory. In some embodiments of the method200, the potential trajectory of the wellbore34represented by the selected trajectory type (120(a), (b), (c), or (d)) has a constant inclination, and the one or more task parameters needed to drill the wellbore34along the desired trajectory include an inclination of the wellbore34. In some embodiments of the method200, the potential trajectory of the wellbore34represented by the selected trajectory type (120(a), (b), (c), or (d)) is directed to a target point, and the one or more task parameters needed to drill the wellbore34along the desired trajectory include estimates of a measured depth and a true vertical depth of the wellbore34at the target point. In some embodiments of the method200, the potential trajectory of the wellbore34represented by the selected trajectory type (120(a), (b), (c), or (d)) includes one or more inflection points that are each followed by a corresponding wellbore34segment with constant azimuth and inclination, and the one or more task parameters needed to drill the wellbore34along the desired trajectory include a measured depth for each of the one or more inflection points, and azimuth and inclination values for the one or more corresponding wellbore34segments.

Further, turning toFIG. 7(b), in an embodiment, the method200further includes one or more of the following steps: determining, based on the pushed trajectory type (i.e.,120(a), (b), (c), or (d)) and the one or more pushed task parameters, step-by-step instructions for drilling the wellbore34along the desired trajectory at a step210; presenting, on the HMI124, the step-by-step instructions for drilling the wellbore34along the desired trajectory at a step212; and controlling, using the control system106and based on the presented step-by-step instructions, the drilling equipment104to drill the wellbore34along the desired trajectory at a step214. In some embodiments of the method200, the HMI124is located at or near the drilling equipment104and the wellbore34, and the HMI118is located remotely from the drilling equipment104and the wellbore34.

Further still, turning toFIG. 7(c), in an embodiment, the method200further includes one or more of the following steps: communicating the selected trajectory type (120(a), (b), (c), or (d)) and the one or more entered task parameters to the control system106in a format compatible with the software program110at a step216; executing, using the control system106and based on the pushed trajectory type (i.e.,120(a), (b), (c), or (d)) and the one or more pushed task parameters, the software program110to control the drilling equipment104to drill the wellbore34along the desired trajectory at a step218; and determining the desired trajectory using the software program114at a step220.

Finally, turning toFIG. 7(d), in an embodiment, the method200further includes one or more of the following steps: presenting, on the HMI118, another data field into which the intended effective depth160at which the control system106is intended to initiate control of the drilling equipment104to drill the wellbore34along the desired trajectory is adapted to be entered at a step222; entering, via the HMI118, the intended effective depth160into the another data field at a step224; pushing the intended effective depth160to the control system106at a step226; controlling, using the control system106and based on the pushed trajectory type (i.e.,120(a), (b), (c), or (d)), the one or more pushed task parameters, and the pushed intended effective depth160, the drilling equipment104to drill the wellbore34along the desired trajectory at a step228; presenting, on the HMI118, the actual effective depth162at which the control system106initiates control of the drilling equipment104to drill the wellbore34along the desired trajectory at a step230; and logging, in the trajectory log166, the pushed trajectory type (i.e.,120(a), (b), (c), or (d)), the one or more pushed task parameters, the pushed intended effective depth160, and the actual effective depth162at which the control system106initiates control of the drilling equipment104to drill the wellbore34along the desired trajectory at a step232.

Referring toFIG. 8, an embodiment of a computing device300for implementing one or more embodiments of one or more of the above-described controllers (e.g.,58,96,98, or100), control systems (e.g.,50or106), monitoring systems (e.g.,108), software programs (e.g.,110, or114), human-machine interfaces (e.g., HMI118or124), methods (e.g.,200), and/or steps (e.g.,202,204,206,208,210,212,214,216,218,220,222,224,226,228,230, or232), and/or any combination thereof, is depicted. The computing device300includes a microprocessor300a, an input device300b, a storage device300c, a video controller300d, a system memory300e, a display300f, and a communication device300gall interconnected by one or more buses300h. In some embodiments, the storage device300cmay include a floppy drive, hard drive, CD-ROM, optical drive, any other form of storage device and/or any combination thereof. In some embodiments, the storage device300cmay include, and/or be capable of receiving, a floppy disk, CD-ROM, DVD-ROM, or any other form of computer-readable medium that may contain executable instructions. In some embodiments, the communication device300gmay include a modem, network card, or any other device to enable the computing device to communicate with other computing devices. In some embodiments, any computing device represents a plurality of interconnected (whether by intranet or Internet) computer systems, including without limitation, personal computers, mainframes, PDAs, smartphones and cell phones.

The computing device can send a network message using proprietary protocol instructions to render 3D models and/or medical data. The link between the computing device and the display unit and the synchronization between the programmed state of physical manikin and the rendering data/3D model on the display unit of the present invention facilitate enhanced learning experiences for users. In this regard, multiple display units can be used simultaneously by multiple users to show the same 3D models/data from different points of view of the same manikin(s) to facilitate uniform teaching and learning, including team training aspects.

In some embodiments, one or more of the components of the above-described embodiments include at least the computing device300and/or components thereof, and/or one or more computing devices that are substantially similar to the computing device300and/or components thereof. In some embodiments, one or more of the above-described components of the computing device300include respective pluralities of same components.

In some embodiments, a computer system typically includes at least hardware capable of executing machine readable instructions, as well as the software for executing acts (typically machine-readable instructions) that produce a desired result. In some embodiments, a computer system may include hybrids of hardware and software, as well as computer sub-systems.

In some embodiments, hardware generally includes at least processor-capable platforms, such as client-machines (also known as personal computers or servers), and hand-held processing devices (such as smart phones, tablet computers, personal digital assistants (PDAs), or personal computing devices (PCDs), for example). In some embodiments, hardware may include any physical device that is capable of storing machine-readable instructions, such as memory or other data storage devices. In some embodiments, other forms of hardware include hardware sub-systems, including transfer devices such as modems, modem cards, ports, and port cards, for example.

In some embodiments, software includes any machine code stored in any memory medium, such as RAM or ROM, and machine code stored on other devices (such as floppy disks, flash memory, or a CD ROM, for example). In some embodiments, software may include source or object code. In some embodiments, software encompasses any set of instructions capable of being executed on a computing device such as, for example, on a client machine or server.

In some embodiments, combinations of software and hardware could also be used for providing enhanced functionality and performance for certain embodiments of the present disclosure. In an embodiment, software functions may be directly manufactured into a silicon chip. Accordingly, it should be understood that combinations of hardware and software are also included within the definition of a computer system and are thus envisioned by the present disclosure as possible equivalent structures and equivalent methods.

In some embodiments, computer readable mediums include, for example, passive data storage, such as a random access memory (RAM) as well as semi-permanent data storage such as a compact disk read only memory (CD-ROM). One or more embodiments of the present disclosure may be embodied in the RAM of a computer to transform a standard computer into a new specific computing machine. In some embodiments, data structures are defined organizations of data that may enable an embodiment of the present disclosure. In an embodiment, a data structure may provide an organization of data, or an organization of executable code.

In some embodiments, any networks and/or one or more portions thereof, may be designed to work on any specific architecture. In an embodiment, one or more portions of any networks may be executed on a single computer, local area networks, client-server networks, wide area networks, internets, hand-held and other portable and wireless devices and networks.

In some embodiments, a database may be any standard or proprietary database software. In some embodiments, the database may have fields, records, data, and other database elements that may be associated through database specific software. In some embodiments, data may be mapped. In some embodiments, mapping is the process of associating one data entry with another data entry. In an embodiment, the data contained in the location of a character file can be mapped to a field in a second table. In some embodiments, the physical location of the database is not limiting, and the database may be distributed. In an embodiment, the database may exist remotely from the server, and run on a separate platform. In an embodiment, the database may be accessible across the Internet. In some embodiments, more than one database may be implemented.

In some embodiments, a plurality of instructions stored on a non-transitory computer readable medium may be executed by one or more processors to cause the one or more processors to carry out or implement in whole or in part the above-described operation of each of the above-described embodiments of the drilling rig10, the apparatus54, the system102, and/or any combination thereof. In some embodiments, such a processor may include the microprocessor300a, and such a non-transitory computer readable medium may include the storage device300c, the system memory300e, or a combination thereof. Moreover, the computer readable medium may be distributed among one or more components of the drilling rig10, the apparatus54, and/or the system102, and/or any combination thereof. In some embodiments, such a processor may execute the plurality of instructions in connection with a virtual computer system. In some embodiments, such a plurality of instructions may communicate directly with the one or more processors, and/or may interact with one or more operating systems, middleware, firmware, other applications, and/or any combination thereof, to cause the one or more processors to execute the instructions.

The present disclosure introduces a system including a first human-machine interface on which a plurality of trajectory types are presented, each of the trajectory types representing a potential trajectory of a wellbore, the trajectory type most closely representing a desired trajectory of the wellbore being selectable via the first human-machine interface, wherein, once so selected, one or more task parameters needed to drill the wellbore along the desired trajectory are enterable into one or more data fields associated with the selected trajectory type; and a control system adapted to control drilling equipment to drill the wellbore along the desired trajectory, wherein, once entered into the one or more data fields, the one or more task parameters are pushable to the control system. In some embodiments, the system further includes a second human-machine interface connected to the control system and on which step-by-step instructions for drilling the wellbore along the desired trajectory are presented, the step-by-step instructions being determined based on the one or more task parameters once the one or more task parameters are pushed to the control system; wherein the second human-machine interface is different from the first human machine interface; and wherein the control system is operable by a user, based on the presented step-by-step instructions, to control the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, the second human-machine interface is located at or near the drilling equipment and the wellbore, and the first human-machine interface is located remotely from the drilling equipment and the wellbore. In some embodiments, an intended effective depth, at which the control system is intended to initiate control of the drilling equipment to drill the wellbore along the desired trajectory, is enterable into another data field presented on the first human-machine interface; and, once entered into the another data field, the intended effective depth is pushable to the control system. In some embodiments, the system further includes a second human-machine interface connected to the control system and on which step-by-step instructions for drilling the wellbore along the desired trajectory are presented, the step-by-step instructions being determined based on the one or more task parameters and the intended effective depth once the one or more task parameters and the intended effective depth are pushed to the control system; wherein the second human-machine interface is different from the first human machine interface; and wherein the control system is operable by a user, based on the presented step-by-step instructions, to control the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, once the one or more task parameters and the intended effective depth are pushed to the control system, the one or more task parameters, the intended effective depth, and an actual effective depth at which the control system initiates control of the drilling equipment to drill the wellbore along the desired trajectory are loggable into a trajectory log.

The present disclosure also introduces a method including presenting, on a first human-machine interface, a plurality of selectable trajectory types, each of the trajectory types representing a potential trajectory of a wellbore; receiving a selection, via the first human-machine interface, of a selectable trajectory type of the plurality of selectable trajectory types that most closely represents a desired trajectory of the wellbore, the selected trajectory type including one or more data fields into which one or more task parameters needed to drill the wellbore along the desired trajectory are adapted to be entered; receiving an input, via the first human-machine interface, of the one or more task parameters into the one or more data fields of the selected trajectory type; and pushing the selected trajectory type and the one or more input task parameters to a control system adapted to control drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, the method further includes determining, based on the pushed trajectory type and the one or more pushed task parameters, step-by-step instructions for drilling the wellbore along the desired trajectory; and presenting, on a second human-machine interface, the step-by-step instructions for drilling the wellbore along the desired trajectory, wherein the second human-machine interface is different from the first human-machine interface. In some embodiments, the second human-machine interface is located at or near the drilling equipment and the wellbore, and wherein the first human-machine interface is located remotely from the drilling equipment and the wellbore. In some embodiments, the method further includes controlling, using the control system and based on the presented step-by-step instructions, the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, pushing the selected trajectory type and the one or more input task parameters to the control system includes communicating the selected trajectory type and the one or more input task parameters to the control system in a format compatible with a first software program; and the method further includes executing, using the control system and based on the pushed trajectory type and the one or more pushed task parameters, the first software program to control the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, the method further includes determining the desired trajectory using a second software program that is different from the first software program. In some embodiments, the method further includes presenting, on the first human-machine interface, another data field into which an intended effective depth at which the control system is intended to initiate control of the drilling equipment to drill the wellbore along the desired trajectory is adapted to be entered; entering, via the first human-machine interface, the intended effective depth into the another data field; and pushing the intended effective depth to the control system. In some embodiments, the method further includes controlling, using the control system and based on the pushed trajectory type, the one or more pushed task parameters, and the pushed intended effective depth, the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, the method further includes presenting, on the first human machine interface, an actual effective depth at which the control system initiates control of the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, the method further includes logging, in a trajectory log, the pushed trajectory type, the one or more pushed task parameters, the pushed intended effective depth, and an actual effective depth at which the control system initiates control of the drilling equipment to drill the wellbore along the desired trajectory. In some embodiments, the potential trajectory of the wellbore represented by the selected trajectory type is shifted relative to a current trajectory of the wellbore, and the one or more task parameters needed to drill the wellbore along the desired trajectory include first, second, third, and fourth distances by which the trajectory of the wellbore is shifted up, down, left, and right, respectively, relative to the current trajectory; the potential trajectory of the wellbore represented by the selected trajectory type has a constant inclination, and the one or more task parameters needed to drill the wellbore along the desired trajectory include an inclination of the wellbore; the potential trajectory of the wellbore represented by the selected trajectory type is directed to a target point, and the one or more task parameters needed to drill the wellbore along the desired trajectory include estimates of a measured depth and a true vertical depth of the wellbore at the target point; or the potential trajectory of the wellbore represented by the selected trajectory type includes one or more inflection points that are each followed by a corresponding wellbore segment with constant azimuth and inclination, and the one or more task parameters needed to drill the wellbore along the desired trajectory include a measured depth for each of the one or more inflection points, and azimuth and inclination values for the one or more corresponding wellbore segments.

The present disclosure also introduces a method including presenting, on a first human-machine interface, a plurality of selectable trajectory types, each of the trajectory types representing a potential trajectory of a wellbore; receiving a selection, via the first human-machine interface, of a selectable trajectory type of the plurality of selectable trajectory types that most closely represents a desired trajectory of the wellbore; pushing the selected trajectory type to a control system adapted to control drilling equipment to drill the wellbore along the desired trajectory; and based on the pushed selected trajectory type, modifying the input of at least one of a top drive, a bottom hole assembly (BHA), a drawworks, and a mud pump to change the trajectory of the wellbore from a current trajectory to the desired trajectory. In some embodiments, the method further includes tracking the pushed selected trajectory type and outputting a table identifying parameters of a drilled wellbore at the time of modifying the input of at least one of the top drive, the bottom hole assembly (BHA), the drawworks, and the mud pump. In some embodiments, the method further includes receiving an input, via the first human-machine interface, of one or more task parameters into one or more data fields of a task parameter needed to drill the wellbore along the desired trajectory, the input including at least one of: a shift distance, an inclination, a depth, and inflection data.

It is understood that variations may be made in the foregoing without departing from the scope of the present disclosure.

In some embodiments, the elements and teachings of the various embodiments may be combined in whole or in part in some or all of the embodiments. In addition, one or more of the elements and teachings of the various embodiments may be omitted, at least in part, and/or combined, at least in part, with one or more of the other elements and teachings of the various embodiments.

Although some embodiments have been described in detail above, the embodiments described are illustrative only and are not limiting, and those skilled in the art will readily appreciate that many other modifications, changes and/or substitutions are possible in the embodiments without materially departing from the novel teachings and advantages of the present disclosure. Accordingly, all such modifications, changes, and/or substitutions are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, any means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Moreover, 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 those in which the claim expressly uses the word “means” together with an associated function.