DRILLING SYSTEMS AND METHODS WITH ITERATIVE DRILLING PARAMETER TESTING

Description

BACKGROUND

Drilling a borehole for the extraction of minerals has become an increasingly complicated operation due to the increased depth and complexity of many boreholes, including the complexity added by directional drilling. Drilling is an expensive operation and errors in drilling add to the cost and, in some cases, drilling errors may permanently lower the output of a well for years into the future. Conventional technologies and methods may not adequately address the complicated nature of drilling and may not be capable of gathering and processing various information from downhole sensors and surface control systems in a timely manner, in order to improve drilling operations and minimize drilling errors.

BRIEF SUMMARY

The following presents a simplified summary of some embodiments of the invention in order to provide a basic understanding of the invention. This summary is not an extensive overview of the invention. It is not intended to identify key/critical elements of the invention or to delineate the scope of the invention. Its sole purpose is to present some embodiments of the invention in a simplified form as a prelude to the more detailed description that is presented later.

Operating a drill rig to drill a borehole is a complicated task involving coordinated operation of multiple subsystems of the drill rig. In embodiments, a drill rig includes a top drive, a top drive motor control system, a hoisting system (e.g., a drawworks), and a drilling mud system. Drilling of a borehole can be accomplished by rotating a bottom hole assembly (BHA) that includes a drill bit that forms the borehole. The top drive rotates the BHA via a drill string attached to the BHA and coupled with the top drive. The top drive can include a top drive motor that drives rotation of the drill string. The top drive motor control system can be configured to control operation of the top drive motor to rotate the drill string at a specified rotational rate. Additionally, as described herein, the top drive motor control system can be controlled to provide a specified torsional spring rate and a specified amount of torsional damping to inhibit occurrence of detrimental stick/slip of the drill string. The hoisting system is operable to lower the top drive to lower the drill string and BHA into the borehole during drilling of the borehole and to raise the top drive to lift the drill string relative to the borehole. The drilling mud system pumps a flow of drilling mud down through the drill string to the BHA for removing borehole cuttings, suspending and releasing borehole cuttings, controlling geological formation pressures, sealing permeable geological formations, maintaining stability of the borehole, minimizing geological formation damage, cooling the drill bit and the drilling assembly, lubricating the drill bit and the drilling assembly, and powering a mud motor for rotation of the drill bit during slide drilling.

In embodiments, one or more control parameters of a drilling system are controllably varied to conduct a parameter sweep to induce one or more responses of the drilling system that are measured for use in optimizing drilling operations. By controlled varying of one or more parameters, and monitoring one or more other parameters, an optional or preferable set of drilling parameters can be determined and then used for better drilling operations. In embodiments, some control parameters that can be varied include one or more of the following: (a) rate of rotation of the proximal end of the drill string by the top drive, (b) rate of descent of the proximal end of the drill string, (c) hook load applied to the top drive, (d) flow rate and/or pressure of drilling mud pumped through the drill string to the BHA, (e) effective torsional spring rate of the top drive, (f) oscillations of the drill pipe, (g) travelling block velocity and movement, and (h) effective torsional damping of the drill string provided by the top drive. Responses of the drilling system that can be measured for use in optimizing drilling operations include: (a) reactive torque applied to the top drive by the proximal end of the drill string, (b) vertical support load (aka “hook load”) applied to the top drive via the hoisting system of the drill rig, (c) torsional oscillations of the drill string, (d) rotational rates of the BHA, and (d) differential pressure of the drilling mud. Operational parameters of the drilling system that may be optimized include weight-on-bit (via optimization of hook load), rate of penetration (ROP), flow rate of drilling mud, differential pressure of the drilling mud, rate of rotation of the proximal end of the drill string by the top drive, effective torsional spring rate of the top drive, toolface, and effective torsional damping of the drill string provided by the top drive. In general, just about any drilling parameter and/or combination of drilling parameters (including but not limited to the foregoing examples) can be controlled to sweep through a desired range of values, with one or more downhole and/or surface sensors used to measure the resulting effects on drilling operations. Such a “parameter sweep” can be performed a plurality of times during a well, can be performed at predetermined intervals or at varying intervals, and the results can be used to modify one or more drilling parameters to more efficiently and/or more effectively drill the well.

In some embodiments, one or more drilling parameters may have their values varied (or “swept) through a range of values even though the drilling rig is not currently drilling the well. For example, there are often numerous times during drilling of a well when drilling is paused to allow other operations to occur. These may include when the bit is off bottom, when tripping out, when a new drill pipe or stand is added to or removed from the drill string, and so on. For example, the drill string may be oscillated through a range of wraps, and/or with a range of speeds, while the bit is off bottom, and in such situations, the varying of the wraps and/or velocity of oscillations may be used to determine inflection points in torsional forces or friction that the drill string is subject to. The use of parameter sweeps in accordance with this disclosure thus includes sweeps of drilling parameter values both during drilling and during transitions (such as lifting a bit off bottom or lowering the bit back to the bottom of well before actual drilling of the rock commences).

Parameter sweeps in accordance with the present disclosure may be performed at regular intervals, which time intervales may vary depending on the section of the well being drilled, the particular formation(s) being drilled, the expected formation(s) to be drilled, and the like. Parameter sweeps also may be performed at irregular intervals, such as if problems are encountered or are expected. Some drilling parameter sweeps may be performed at regular time intervals while others occur at irregular intervals. In some cases, particular drilling parameters may be swept through a range of values and/or the time intervals between parameter sweeps may vary depending on the rig state, which may include states such as rotary drilling, slide drilling (with or without) oscillations, tripping, back to bottom, rotating off bottom, reaming up/down, circulating or not, and so forth. It may also be desirable to have one or more drilling parameters as the subject of one or more parameter sweeps for each one of a defined rig state for a number of different rig states, such as those just mentioned.

Thus, in one aspect, a first drilling system includes a computer system configured to conduct a parameter sweep to identify an operational set point for use in drilling a borehole. In embodiments of the first drilling system, the computer system is configured to: (a) control a top drive and a hoisting system to operate at a first operational set point in which the top drive rotates a drill string at a first rotational rate and the hoisting system applies a first support force to the top drive to drill a first portion of a borehole, (b) control the top drive and the hoisting system to perform a parameter sweep in which the top drive rotates the drill string through a parameter sweep range of rotational rates and/or the hoisting system applies a parameter sweep range of support forces to the top drive, (c) monitor one or more other parameters during the parameter sweep, (d) select a second operational set point based on the parameter sweep and the parameter values measure during the parameter-sweep, and (e) control the top drive and the hoisting system to operate at the second operational set point to drill a second portion of the borehole, wherein the top drive rotates the drill string at a second rotational rate and the hoisting system applies a second support force to the top drive at the second operational set point. In embodiments of the first drilling system, the second rotational rate is different than the first rotational rate and/or the second support force is different than the first support force.

The optimal or preferable set of parameters for drilling performance can be determined based on any suitable drilling parameter values. For example, in embodiments of the first drilling system, the at least one resulting drilling parameter value can include one or more of: (a) a rate of penetration, (b) a reactive torque oscillation value indicative of a level of oscillation of a reactive torque applied to the top drive by the drill string, (c) a tracking accuracy value indicative of a magnitude of deviation of a measured track of the borehole relative to a planned track of the borehole, (d) toolface and/or toolface variations, and/or (e) a drill bit wear value estimate of a rate of wear of a drill bit used to drill the borehole.

In embodiments of the first drilling system, the computer system is further configured to conduct a parameter sweep on a drilling mud system. For example, the computer system can be further configured to: (a) control a drilling mud system to pump drilling mud through the drill string at a first flow rate at the first operational set point, (b) control the drilling mud system to pump drilling mud through the drill string through a parameter sweep range of flow rates during the parameter sweep, and (c) control the drilling mud system to pump drilling mud through the drill string at a second flow rate at the second operational set point, wherein the second flow rate is different than the first flow rate. Similarly, the computer system may be configured to sweep through a set of differential pressures.

In embodiments of the first drilling system, the computer system is configured to conduct one or more additional parameter sweeps for identifying drilling parameters for enhancing drilling performance. For example, in embodiments of the first drilling system, the computer system is configured to: (a) control the top drive and the hoisting system to perform a parameter sweep in which the top drive rotates the drill string through a parameter sweep range of rotational rates and/or the hoisting system applies a parameter sweep range of support forces to the top drive, (b) determine parameter-sweep drilling performances based on parameter-sweep value sets for the parameter sweep, wherein each of the parameter-sweep value sets includes the at least one resulting drilling parameter value measured during the parameter sweep; (c) select an operational set point based on the parameter sweep and the parameter-sweep drilling performances, and (d) control the top drive and the hoisting system to operate at the operational set point to drill a portion of the borehole, wherein the top drive rotates the drill string at a rotational rate and the hoisting system applies a support force to the top drive at the operational set point.

In another aspect, a drilling system includes a computer system configured to apply a rotational impulse to the drill string and measure a resulting torsional oscillation of the drill string for use in optimizing hook load to maximize rate of penetration without incurring detrimental stick/slip oscillations of the drill string. In embodiments, the drilling system includes a computer system configured to: (a) measure a first support load applied to a top drive by a hoisting system during drilling of a first portion of a borehole via rotation of a drill string by the top drive, (b) control the top drive to induce one or more predetermined rotational accelerations of a proximal end portion of the drill string, (c) measure a response of the drill string to the one or more predetermined rotational accelerations of the proximal end portion of the drill string, (d) process the response of the drill string to determine a second support load for application to the top drive by the hoisting system, and (e) control operation of the hoisting system to apply the second support load to the top drive to drill a second portion of the borehole.

The response of the drill string to the one or more predetermined rotational accelerations of the proximal end portion of the drill string may include a reactive torque applied to the top drive by the drill string. In embodiments of the drilling system, the computer system is configured to: (a) process the reactive torque applied to the top drive by the drill string to quantify torsional oscillations of the drill string, and (b) update a weight-on-bit limit based on the torsional oscillations of the drill string.

In embodiments of the drilling system, the one or more predetermined rotational accelerations of the proximal end portion of the drill string include one or more cycles of sinusoidal angular accelerations of the proximal end portion of the drill string. In embodiments of the drilling system, the one or more cycles of sinusoidal angular accelerations of the proximal end portion of the drill string include a plurality of cycles covering a range of cycle frequencies.

In embodiments of the drilling system, rotational rates of a bottom hole assembly are measured for use in quantifying the torsional oscillations of the drill string. For example, in embodiments of the second drilling system: (a) the drill string includes a bottom hole assembly (BHA) that includes one or more BHA sensors that generates a BHA sensor output indicative of a rotational rate of the BHA, and (b) the response of the drill string to the one or more predetermined rotational accelerations of the proximal end portion of the drill string include rotational rates of the BHA.

In another aspect, a drilling system may include a computer system configured to conduct a parameter sweep to identify a flow rate for a drilling mud system. In embodiments, the drilling system includes a computer system configured to: (a) control a drilling mud system during drilling of a first portion of a borehole to operate at a first operational set point in which the drilling mud system pumps drilling mud through a drill string at a first flow rate, (b) control the drilling mud system to perform a parameter sweep in which the drilling mud system pumps drilling mud through the drill string through a parameter sweep range of flow rates, (c) determine parameter-sweep drilling performance value sets for the parameter sweep, wherein each of the parameter-sweep drilling performance value sets includes at least one resulting drilling parameter value measured during the parameter sweep, (d) select a second operational set point based on the parameter sweep and the parameter-sweep drilling performance value sets, and (e) control the drilling mud system to operate at the second operational set point to drill a second portion of the borehole, wherein the drilling mud system pumps drilling mud through the drill string at a second flow rate at the second operational set point. In some embodiments of the drilling system, the computer system is further configured to assess variation in a differential pressure of the drilling mud produced during the parameter sweep, such as to determine whether there is a buildup of cuttings within the borehole. In some embodiments of the drilling system, the computer system is further configured to assess a variation in a differential pressure of the drilling mud.

In another aspect, a drilling system includes a computer system configured to assess a response of a drill string to an increase and/or decrease in WOB and adjust a WOB based on the response of the drill string to the changes in WOB. For example, in embodiments, the drilling system includes a computer system configured to: (a) control a hoisting system to decrease vertical support of a top drive by a predefined amount to increase weight-on-bit (WOB), (b) measure a response of a drill string to the increased WOB, (c) process the response to quantify a level of torsional oscillations of the drill string, (d) increase a WOB limit in response to the level of torsional oscillations of the drill string being equal to or less than an acceptable level, and (e) maintain or decrease the WOB limit in response to the level of torsional oscillations of the drill string being greater than the acceptable level. The response of the drill string to the increased WOB may include reactive torsion applied to the top drive by the drill string. In some embodiments of the drilling system: (a) the drill string includes a bottom hole assembly (BHA) that includes one or more BHA sensors that generates a BHA sensor output indicative of a rotational rate of the BHA, (b) the computer system is configured to process the BHA sensor output to determine a rotational rate of the BHA, and (c) the response of the drill string to the increased WOB includes rotational rates of the BHA.

Another drilling system includes a computer system configured to conduct a parameter sweep to identify a torsional spring rate for a top drive for use in controlling the top drive to provide the torsional spring rate. In embodiments, the drilling system includes a computer system configured to: (a) control a top drive, a top drive electronic control system, and a hoisting system to operate at a first operational set point to drill a first portion of a borehole, wherein the top drive electronic control system controls operation of the top drive to provide a first torsional spring rate at the first operational set point, (b) control the top drive electronic control system to perform a parameter sweep in which the top drive provides a parameter sweep range of torsional spring rates, (c) determine parameter sweep torsional oscillation levels of the drill string for the parameter sweep, (d) select a second torsional spring rate to be provided by the top drive based on the parameter sweep torsional oscillation levels of the drill string for the parameter sweep; and (e) control the top drive, the top drive electronic control system, and the hoisting system to operate at a second operational set point to drill a second portion of the borehole, wherein the top drive electronic control system controls operation of the top drive to provide a second torsional spring rate at the second operational set point. In embodiments of the drilling system, the computer system is configured to determine the parameter sweep torsional oscillation levels of the drill string based on reactive torsion applied to the top drive by the drill string. In embodiments of the drilling system: (a) the drill string includes a bottom hole assembly (BHA) that includes one or more BHA sensors that generates a BHA sensor output indicative of a rotational rate of the BHA; (b) the computer system is configured to process the BHA sensor output to determine a rotational rate of the BHA, and (c) the computer system is configured to determine the parameter sweep torsional oscillation levels of the drill string based on rotational rates of the BHA.

In addition, another drilling system includes a computer system configured to conduct a parameter sweep to identify a torsional damping coefficient for a top drive for use in controlling the top drive to provide torsional damping. In embodiments, the drilling system includes a computer system configured to: (a) control a top drive, a top drive electronic control system, and a hoisting system to operate at a first operational set point to drill a first portion of a borehole, wherein the top drive electronic control system controls operation of the top drive to provide torsional damping corresponding to a first torsional damping coefficient, (b) control the top drive electronic control system to perform a parameter sweep in which the top drive provides torsional damping corresponding to a parameter sweep range of torsional dampening coefficients, (c) determine parameter sweep torsional oscillation levels of the drill string for the parameter sweep, (d) select a second torsional damping coefficient for the top drive based on the parameter sweep torsional oscillation levels of the drill string for the parameter sweep, and (e) control the top drive, the top drive electronic control system, and the hoisting system to operate at a second operational set point to drill a second portion of the borehole, wherein the top drive electronic control system controls operation of the top drive to provide torsional damping corresponding to a second torsional damping coefficient. In embodiments of the drilling system, the computer system is configured to determine the parameter sweep torsional oscillation levels of the drill string based on reactive torsion applied to the top drive by the drill string. In embodiments of the drilling system: (a) the drill string includes a bottom hole assembly (BHA) that includes one or more BHA sensors that generates a BHA sensor output indicative of a rotational rate of the BHA, (b) the computer system is configured to process the BHA sensor output to determine a rotational rate of the BHA, and (c) the computer system is configured to determine the parameter sweep torsional oscillation levels of the drill string based on rotational rates of the BHA.

For a fuller understanding of the nature and advantages of the present invention, reference should be made to the ensuing detailed description and accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

FIG. 1 illustrates a drilling system for drilling a borehole, in accordance with embodiments;

FIG. 2 illustrates a drilling environment that includes the drilling system of FIG. 1;

FIG. 3 illustrates a portion of a borehole generated in the drilling environment of FIG. 2;

FIG. 4 illustrates a drilling architecture that includes the drilling environment of FIG. 2;

FIG. 5 shows drilling rig control systems of the drilling system of FIG. 1;

FIG. 6 shows control algorithm modules of the rig control systems of FIG. 5;

FIG. 7 schematically illustrates a steering control process used by the rig control systems of FIG. 5;

FIG. 8 illustrates a graphical user interface of the rig control systems of FIG. 5;

FIG. 9 is a simplified schematic flow chart of a method of controlling operation of the drilling system of FIG. 1 in which a parameter sweep is used to select an operational set point, in accordance with embodiments;

FIG. 10A illustrates an example envelope parameter sweep that can be employed in the method of FIG. 9, in accordance with embodiments;

FIG. 10B illustrates another example of an envelope parameter sweep that can be employed in the method of FIG. 9, in accordance with embodiments.

FIG. 10C illustrates another example of parameter sweeps that can be made responsive to a determination of rig state.

FIG. 11 shows a plot of relative drilling performance for the example envelope parameter sweep of FIG. 10;

FIG. 12 illustrates an example linear parameter sweep that can be employed in conjunction with the example envelope parameter sweep of FIG. 10 in the method of FIG. 9, in accordance with embodiments.

FIG. 13 shows a plot of relative drilling performance for the example linear parameter sweep of FIG. 12;

FIG. 14 is a simplified schematic flow chart of a method of controlling operation of the drilling system of FIG. 1, in accordance with embodiments;

FIG. 15 is a plot of an example predetermined variation of drill string rotation rate over a predetermined time span that can be used to generate a response of the drilling system of FIG. 1, in accordance with embodiments;

FIG. 16 is a plot of an example predetermined variation of drill string translation rate over a predetermined time span that can be used to generate a response of the drilling system of FIG. 1, in accordance with embodiments;

FIG. 17 is a plot of another example predetermined variation of drill string rotation rate over a predetermined time span that can be used to generate a response of the drilling system of FIG. 1, in accordance with embodiments;

FIG. 18 is a plot of another example predetermined variation of drill string translation rate over a predetermined time span that can be used to generate a response of the drilling system of FIG. 1, in accordance with embodiments;

FIG. 19 is a simplified schematic flow chart of a method of controlling operation of the drilling system of FIG. 1 in which a parameter sweep is used to select flow rate for a drilling mud system, in accordance with embodiments;

FIG. 20 shows plots of simulated, predicted, and measured bottom hole assembly (BHA) rotational speeds during example stick slip oscillations of the down-hole assembly of the drilling system of FIG. 1;

FIG. 21 shows plots of simulated and measured reactive torsion applied to a top drive by the proximal end portion of the drill string of the drilling system FIG. 1 during the example stick slip oscillations of FIG. 20;

FIG. 22 illustrates variation of coefficient of friction during a stick slip rotational oscillation of a bottom hole assembly of the drilling system of FIG. 1;

FIG. 23 schematically illustrates a rotational model representing a top-drive motor and a down-hole assembly of the drilling system of FIG. 1;

FIG. 24 is a simplified schematic flow chart of a method of assessing/updating a weight on bottom limit for avoiding stick slip oscillations of the drill string in the drilling system of FIG. 1, in accordance with embodiments;

FIG. 25 is a plot of an example predetermined variation of hook load of the drilling system of FIG. 1 to practice the method of FIG. 24, in accordance with embodiments;

FIG. 26 is a simplified schematic flow chart of a method of controlling operation of the drilling system of FIG. 1 in which a parameter sweep is used to select a torsional spring rate to be provided via control of a top drive motor, in accordance with embodiments; and

FIG. 27 is a simplified schematic flow chart of a method of controlling operation of the drilling system of FIG. 1 in which a parameter sweep is used to select a torsional damping coefficient to be provided via control of a top drive motor, in accordance with embodiments.

DETAILED DESCRIPTION

In the following description, details are set forth by way of example to facilitate discussion of the disclosed subject matter. It should be apparent to a person of ordinary skill in the field, however, that the disclosed embodiments are exemplary and not exhaustive of all possible embodiments.

Throughout this disclosure, a hyphenated form of a reference numeral refers to a specific instance of an element and the un-hyphenated form of the reference numeral refers to the element generically or collectively. Thus, as an example (not shown in the drawings), device “12-1” refers to an instance of a device class, which may be referred to collectively as devices “12” and any one of which may be referred to generically as a device “12”. In the figures and the description, like numerals are intended to represent like elements.

Referring now to the drawings, FIG. 1 illustrate a drilling system 100, in accordance with embodiments. The drilling system 100 is one example of a top drive drilling system. The drilling system 100 includes a derrick 132 disposed on a ground surface 104. The drilling system 100 is configured for drilling a borehole 106 into the earth. Typically the drilling system 100 is used to drill the borehole 106 into a geological formation of interest.

The derrick 132 includes a crown block 134, a traveling block 136, and a drilling line 138. The traveling block 136 is supported from the crown block 134 by the drilling line 138. The drilling system 100 includes a top drive 140, a saver sub 142, and a drill pipe 144, which is part of a drill string 146. The top drive 140 is coupled to the traveling block 136. The top drive 140 is configured to rotate the drill pipe 144 to rotate the drill string 146. In the illustrated embodiment, the saver sub 142 is disposed between the top drive 140 and the drill pipe 144. The top drive 140 may rotate the drill string 146 via the saver sub 142. The drill string 146 is attached to a bottom hole assembly (BHA) 149. The BHA 149 includes a drill bit 148. Rotation of the drill string 146 by the top drive 140 rotates the BHA 149 and the drill bit 148, which can be used to drill a borehole 106 through a geological formation 102. The drilling system 100 includes a rotary table 162 that may be fitted with a master bushing 164 to hold the drill string 146 when not rotating.

The drilling system includes a mud pump 152 that is operable to direct a fluid mixture (e.g., drilling mud 153) from a mud pit 154 into the drill string 146. The mud pit 154 is shown schematically as a container, but it is noted that various receptacles, tanks, pits, or other containers may be used. The drilling mud 153 may flow from mud pump 152 into a discharge line 156 that is coupled to a rotary hose 158 by a standpipe 160. The rotary hose 158 may then be coupled to the top drive 140, which includes a passage for the drilling mud 153 to flow into the borehole 106 via the drill string 146 from which the drilling mud 153 may emerge at the drill bit 148. The drilling mud 153 may lubricate the drill bit 148 during drilling and, due to the pressure supplied by the mud pump 152, the drilling mud 153 may return via the borehole 106 to the surface 104.

In the drilling system 100, drilling equipment (see also FIG. 5) is used to perform the drilling of the borehole 106, such as the top drive 140 (or rotary drive equipment) that couples to the drill string 146 and the BHA 149 and is configured to rotate the drill string 146 and apply pressure to the drill bit 148. The drilling system 100 may include control systems such as a weight on bit (WOB)/differential pressure control system 522, a positional/rotary control system 524, a fluid circulation control system 526, and a sensor system 528, as further described below with respect to FIG. 5. The control systems may be used to monitor and change drilling rig settings, such as the WOB or differential pressure to alter the rate of penetration (ROP) or the radial orientation of the toolface, change the flow rate of drilling mud, and perform other operations. The sensor system 528 may be for obtaining sensor data about the drilling operation and drilling system 100, including the downhole equipment. For example, the sensor system 528 may include measurement while drilling (MWD) tools and/or logging while drilling (LWD) tools for acquiring information, such as toolface orientation and formation logging information, that may be saved for later retrieval, transmitted with or without a delay using any of various communication means (e.g., wireless, wireline, or mud pulse telemetry), or otherwise transferred to a steering control system 168 of the drilling system 100. As used herein, an MWD tool is enabled to communicate downhole measurements without substantial delay to the surface 104, such as using mud pulse telemetry, while a LWD tool is equipped with an internal memory that stores measurements when downhole and can be used to download a stored log of measurements when the LWD tool is at the surface 104. The internal memory in the LWD tool may be a removable memory, such as a universal serial bus (USB) memory device or another removable memory device. Certain downhole tools may have both MWD and LWD capabilities. Information acquired by the sensor system 528 may include information related to hole depth, bit depth, inclination angle, azimuth angle, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotations per minute (RPM), bit speed, ROP, WOB, among other information. All or part of the sensor system 528 may be incorporated into a control system, or in another component of the drilling equipment. The drilling system 100 can be configured in many different implementations in which different control systems and subsystems may be used.

Sensing, detection, measurement, evaluation, storage, alarm, and other functionality may be incorporated into a downhole tool 166 or the BHA 149 or elsewhere along the drill string 146 to provide downhole surveys of the borehole 106. Accordingly, the downhole tool 166 may be an MWD tool or a LWD tool or both, and may accordingly utilize connectivity to the surface 104, local storage, or both. In different implementations, gamma radiation sensors, magnetometers, accelerometers, and other types of sensors may be used for the downhole surveys. Although the downhole tool 166 is shown in singular in the drilling system 100, it is noted that multiple instances (not shown) of the downhole tool 166 may be located at one or more locations along the drill string 146.

In some embodiments, formation detection and evaluation functionality may be provided via the steering control system 168 on the surface 104. The steering control system 168 may be located in proximity to the derrick 132 or may be otherwise included with the drilling system 100. In other embodiments, the steering control system 168 may be remote from the actual location of the borehole 106 (see also FIG. 4). For example, the steering control system 168 may be a stand-alone system or may be incorporated into other systems included with the drilling system 100.

In operation, the steering control system 168 may be accessible via a communication network and may accordingly receive formation information via the communication network. In some embodiments, the steering control system 168 may use the evaluation functionality to provide corrective measures, such as a convergence plan to overcome an error in the well trajectory of borehole 106 with respect to a reference, or a planned well trajectory. The convergence plans or other corrective measures may depend on a determination of the well trajectory, and therefore, may be improved in accuracy using certain methods and systems for improved drilling performance.

In particular embodiments, at least a portion of the steering control system 168 may be located in the downhole tool 166 (not shown). In some embodiments, the steering control system 168 may communicate with a separate controller (not shown) located in the downhole tool 166. In particular, the steering control system 168 may receive and process measurements received from downhole surveys and may perform the calculations using the downhole surveys and other information referenced herein.

In the drilling system 100, to aid in the drilling process, data is collected from within the borehole 106, such as from sensors in the BHA 149, sensors in the downhole tool 166, or both. The collected data may include geological characteristics of the formation 102 in which the borehole 106 was formed, attributes of the drilling system 100, including the BHA 149, and drilling information such as weight-on-bit (WOB), drilling speed, and other information pertinent to the formation of the borehole 106. The drilling information may be associated with a particular depth or another identifiable marker to index the collected data. For example, the collected data for the borehole 106 may capture drilling information indicating that drilling of the well from 1,000 feet to 1,200 feet occurred at a first rate of penetration (ROP) through a first rock layer with a first WOB, while drilling from 1,200 feet to 1,500 feet occurred at a second ROP through a second rock layer with a second WOB (see also FIG. 2). In some applications, the collected data may be used to virtually recreate the drilling process that created the borehole 106 in the formation 102, such as by displaying a computer simulation of the drilling process. The accuracy with which the drilling process can be recreated depends on a level of detail and accuracy of the collected data, including collected data from a downhole survey of the well trajectory.

The collected data may be stored in a database that is accessible via a communication network for example. In some embodiments, the database storing the collected data for the borehole 106 may be located locally at the drilling system 100, at a drilling hub that supports a plurality of the drilling systems 100 in a region, or at a database server accessible over a communication network that provides access to the database (see also FIG. 4). At the drilling system 100, the collected data may be stored at the surface 104 or downhole in the drill string 146, such as in a memory device included with the BHA 149. Alternatively, at least a portion of the collected data may be stored on a removable storage medium, such as at the steering control system 168 or the BHA 149, which is later coupled to the database in order to transfer the collected data to the database, which may be manually performed at certain intervals, for example.

In FIG. 1, the steering control system 168 is located at or near the surface 104 from where borehole 106 is being drilled. The steering control system 168 may be coupled to equipment used in drilling system 100 and may also be coupled to the database, whether the database is physically located locally, regionally, or centrally (see also FIG. 4 and FIG. 5). Accordingly, the steering control system 168 may collect and record various inputs, such as measurement data from a magnetometer and an accelerometer that may also be included with the BHA 149.

The steering control system 168 may further be used as a surface steerable system, along with the database, as described above. The surface steerable system may enable an operator to plan and control drilling operations while drilling is being performed. The surface steerable system may itself also be used to perform certain drilling operations, such as controlling certain control systems that, in turn, control the actual equipment in drilling system 100 (see also FIG. 5). The control of drilling equipment and drilling operations by the steering control system 168 may be manual, manual-assisted, semi-automatic, or automatic, in different embodiments.

Manual control may involve direct control of the drilling rig equipment, albeit with certain safety limits to prevent unsafe or undesired actions or collisions of different equipment. To enable manual-assisted control, the steering control system 168 may present various information, such as using a graphical user interface (GUI) displayed on a display device (see FIG. 8), to a human operator, and may provide controls that enable the human operator to perform a control operation. The information presented to the user may include live measurements and feedback from the drilling rig and the steering control system 168, or the drilling rig itself, and may further include limits and safety-related elements to prevent unwanted actions or equipment states, in response to a manual control command entered by the user using the GUI.

To implement semi-automatic control, the steering control system 168 may itself propose or indicate to the user, such as via the GUI, that a certain control operation, or a sequence of control operations, should be performed at a given time. Then, the steering control system 168 may enable the user to initiate the indicated control operation or sequence of control operations, such that once manually started, the indicated control operation or sequence of control operations is automatically completed. The limits and safety features mentioned above for manual control would still apply for semi-automatic control. The steering control system 168 may execute semi-automatic control using a secondary processor, such as an embedded controller that executes under a real-time operating system (RTOS), that is under the control and command of the steering control system 168. To implement automatic control, the step of manual starting the indicated control operation or sequence of operations is eliminated, and the steering control system 168 may proceed with only a passive notification to the user of the actions taken.

In order to implement various control operations, the steering control system 168 may perform (or may cause to be performed) various input operations, processing operations, and output operations. The input operations performed by the steering control system 168 may result in measurements or other input information being made available for use in any subsequent operations, such as processing or output operations. The input operations may accordingly provide the input information, including feedback from the drilling process itself, to the steering control system 168. The processing operations performed by the steering control system 168 may be any processing operation, as disclosed herein. The output operations performed by the steering control system 168 may involve generating output information for use by external entities, or for output to a user, such as in the form of updated elements in the GUI, for example. The output information may include at least some of the input information, enabling the steering control system 168 to distribute information among various entities and processors. In particular, the operations performed by the steering control system 168 may include operations such as receiving drilling data representing a drill path, receiving other drilling parameters, calculating a drilling solution for the drill path based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at the drilling rig, monitoring the drilling process to gauge whether the drilling process is within a defined margin of error of the drill path, and calculating corrections for the drilling process if the drilling process is outside of the margin of error.

The steering control system 168 may receive input information either before drilling, during drilling, or after drilling of the borehole 106. The input information may include measurements from one or more sensors, as well as survey information collected while drilling the borehole 106. The input information may also include a drill plan, a regional formation history, drilling engineer parameters, downhole toolface/inclination information, downhole tool gamma/resistivity information, economic parameters, and reliability parameters, among various other parameters. Some of the input information, such as the regional formation history, may be available from a drilling hub 410, which may have respective access to a regional drilling database (DB) 412 (see FIG. 4). Other input information may be accessed or uploaded from other sources to the steering control system 168. For example, a web interface may be used to interact directly with the steering control system 168 to upload the drill plan or drilling parameters.

As noted, the input information may be provided to the steering control system 168. After processing by the steering control system 168, the steering control system 168 may generate control information that may be output to the drilling rig 210 (e.g., to rig controls 520 that control the drilling equipment 530, see also FIG. 2 and FIG. 5). The drilling rig 210 may provide feedback information using the rig controls 520 to the steering control system 168. The feedback information may then serve as input information to the steering control system 168, thereby enabling the steering control system 168 to perform feedback loop control and validation. Accordingly, the steering control system 168 may be configured to modify its output information to the drilling rig, in order to achieve the desired results, which are indicated in the feedback information. The output information generated by the steering control system 168 may include indications to modify one or more drilling parameters, the direction of drilling, and the drilling mode, among others. In certain operational modes, such as semi-automatic or automatic, the steering control system 168 may generate output information indicative of instructions to the rig controls 520 to enable automatic drilling using the latest location of the BHA 149. Therefore, an improved accuracy in the determination of the location of the BHA 149 may be provided using the steering control system 168.

Referring now to FIG. 2, a drilling environment 200 is depicted schematically and is not drawn to scale or perspective. In particular, the drilling environment 200 may illustrate additional details with respect to the formation 102 below the surface 104 in the drilling system 100 shown in FIG. 1. In FIG. 2, the drilling rig 210 may represent various equipment discussed above with respect to drilling system 100 in FIG. 1 that is located at the surface 104.

In drilling environment 200, it may be assumed that a drill plan (also referred to as a well plan) has been formulated to drill the borehole 106 extending into the ground to a true vertical depth (TVD) 266 and penetrating several subterranean strata layers. The borehole 106 is shown in FIG. 2 extending through strata layers 268-1 and 270-1, and terminating in strata layer 272-1. Accordingly, as shown, the borehole 106 does not extend or reach underlying strata layers 274-1 and 276-1. An example target area 280 specified in the drill plan is located in strata layer 272-1 as shown in FIG. 2. The target area 280 may represent a desired endpoint of the borehole 106, such as a hydrocarbon producing area within the strata layer 272-1. The target area 280 may be of any shape and size and may be defined using various different methods and information in different embodiments. In some instances, the target area 280 may be specified in the drill plan using subsurface coordinates, or references to certain markers, that indicate where the borehole 106 is to be terminated. In other instances, the target area may be specified in the drill plan using a depth range within which the borehole 106 is to remain. For example, the depth range may correspond to the strata layer 272-1. In other examples, the target area 280 may extend as far as can be realistically drilled. For example, when the borehole 106 is specified to have a horizontal section with a goal to extend into the strata layer 172 as far as possible, the target area 280 may be defined as the strata layer 272-1 itself and drilling may continue until some other physical limit is reached, such as a property boundary or a physical limitation on the length of the drill string.

Also visible in FIG. 2 is a fault line 278 that has resulted in a subterranean discontinuity in the fault structure. Specifically, strata layers 268, 270, 272, 274, and 276 have portions on either side of the fault line 278. On one side of the fault line 278, where the borehole 106 is located, strata layers 268-1, 270-1, 272-1, 274-1, and 276-1 are unshifted by the fault line 278. On the other side of fault line 278, strata layers 268-2, 270-3, 272-3, 274-3, and 276-3 are shifted downwards by the fault line 278.

Current drilling operations frequently include directional drilling to reach a target, such as the target area 280. The use of directional drilling has been found to generally increase an overall amount of production volume per well, but also may lead to significantly higher production rates per well, which are both economically desirable. As shown in FIG. 2, directional drilling may be used to drill the horizontal portion of the borehole 106, which increases an exposed length of the borehole 106 within the strata layer 272-1, and which may accordingly be beneficial for hydrocarbon extraction from the strata layer 272-1. Directional drilling may also be used alter an angle of the borehole 106 to accommodate subterranean faults, such as indicated by fault line 278 in FIG. 2. Other benefits that may be achieved using directional drilling include sidetracking off of an existing well to reach a different target area or a missed target area, drilling around abandoned drilling equipment, drilling into otherwise inaccessible or difficult to reach locations (e.g., under populated areas or bodies of water), providing a relief well for an existing well, and increasing the capacity of a well by branching off and having multiple boreholes extending in different directions or at different vertical positions for the same well. Directional drilling is often not limited to a straight horizontal borehole 106 but may involve staying within a strata layer that varies in depth and thickness as illustrated by strata layer 272. As such, directional drilling may involve multiple vertical adjustments that complicate the trajectory of the borehole 106.

Referring now to FIG. 3, one embodiment of a portion of the borehole 106 is shown in further detail. Using directional drilling for horizontal drilling may introduce certain challenges or difficulties that may not be observed during vertical drilling of the borehole 106. For example, a horizontal portion 318 of borehole 106 may be started from a vertical portion 310. In order to make the transition from vertical to horizontal, a curve may be defined that specifies a so-called “build section” 316. The build section 316 may begin at a kickoff point 312 in the vertical portion 310 and may end at a begin point 314 of the horizontal portion 318. The change in inclination in the build section 316 per measured length drilled is referred to herein as a “build rate” and may be defined in degrees per one hundred feet drilled. For example, the build rate may have a value of 6°/100 ft., indicating that there is a six degree change in inclination for everyone hundred feet drilled. The build rate for a particular build section may remain relatively constant or may vary.

The build rate used for any given build section may depend on various factors, such as properties of the formation (i.e., strata layers) through which the borehole 106 is to be drilled, the trajectory of the borehole 106, the particular pipe and drill collars/BHA components used (e.g., length, diameter, flexibility, strength, mud motor bend setting, and drill bit), the mud type and flow rate, the specified horizontal displacement, stabilization, and inclination, among other factors. An overly aggressive built rate can cause problems such as severe doglegs (e.g., sharp changes in direction in the borehole) that may make it difficult or impossible to run casing or perform other operations in the borehole 106. Depending on the severity of any mistakes made during directional drilling, the borehole 106 may be enlarged or the drill bit 146 may be backed out of a portion of the borehole 106 and redrilled along a different path. Such mistakes may be undesirable due to the additional time and expense involved. If, however, the build rate is too cautious, additional time may be added to the drilling process because directional drilling generally involves a lower ROP than straight drilling. Furthermore, directional drilling for a curve is more complicated than vertical drilling and the possibility of drilling errors increases with directional drilling (e.g., overshoot and undershoot that may occur while trying to keep the drill bit 148 on the planned trajectory).

Two modes of drilling, referred to herein as “rotating” and “sliding,” are commonly used to form a borehole. Rotating, also called “rotary drilling,” uses the top drive 140 or rotary table 162 to rotate the drill string 146. Rotating may be used when drilling occurs along a straight trajectory, such as for the vertical portion 310 of the borehole 106. Sliding, also called “steering” or “directional drilling” as noted above, typically uses a mud motor located downhole at the BHA 149. The mud motor may have an adjustable bent housing and is not powered by rotation of the drill string 146. Instead, the mud motor uses hydraulic power derived from the pressurized drilling mud pumped through the drill string 146 to directionally drill the borehole 106 in build section 316.

Sliding is used in order to control the direction of the well trajectory during directional drilling. A method to perform a slide may include the following operations. First, during vertical or straight drilling, the rotation of the drill string 146 is stopped. Based on feedback from measuring equipment, such as from the downhole tool 166, adjustments may be made to the drill string 146, such as using the top drive 140 to apply various combinations of torque, WOB, and vibration, among other adjustments. The adjustments may continue until a toolface is confirmed that indicates a direction of the bend of the mud motor is oriented to a direction of a desired deviation (i.e., build rate) of the borehole 106. Once the desired orientation of the mud motor is attained, WOB is increased, which causes the drill bit 148 to move in the desired direction of deviation. Once sufficient distance and angle have been built up in the curved trajectory, a transition back to rotating mode can be accomplished by restarting rotation of the drill string 146. The rotation of the drill string 146 after sliding may neutralize the directional deviation caused by the bend in the mud motor due to the continuous rotation around a centerline of the borehole 106.

Referring now to FIG. 4, a drilling architecture 400 is illustrated in diagram form. As shown, the drilling architecture 400 depicts a hierarchical arrangement of drilling hubs 410 and a central command 414, to support the operation of a plurality of drilling rigs 210 in different regions 402. Specifically, as described above with respect to FIG. 1 and FIG. 2, the drilling rig 210 includes the steering control system 168 that is enabled to perform various drilling control operations locally to the drilling rig 210. When the steering control system 168 is enabled with network connectivity, certain control operations or processing may be requested or queried by the steering control system 168 from a remote processing resource. As shown in FIG. 4, the drilling hubs 410 represent a remote processing resource for the steering control system 168 located at respective regions 402, while the central command 414 may represent a remote processing resource for both the drilling hub 410 and the steering control system 168.

Specifically, in a region 401-1, a drilling hub 410-1 may serve as a remote processing resource for the drilling rigs 210 located in region 401-1, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, the drilling hub 410-1 may have access to a regional drilling DB 412-1, which may be local to drilling hub 410-1. Additionally, in a region 401-2, a drilling hub 410-2 may serve as a remote processing resource for the drilling rigs 210 located in the region 401-2, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, the drilling hub 410-2 may have access to a regional drilling DB 412-2, which may be local to drilling hub 410-2.

In FIG. 4, respective regions 402 may exhibit the same or similar geological formations. Thus, reference wells, or offset wells, may exist in a vicinity of a given drilling rig 210 in the region 402, or where a new well is planned in the region 402. Furthermore, multiple drilling rigs 210 may be actively drilling concurrently in the region 402 and may be in different stages of drilling through the depths of formation strata layers at the region 402. Thus, for any given well being drilled by a drilling rig 210 in a region 402, survey data from the reference wells or offset wells may be used to create the drill plan and may be used for improved drilling performance. In some implementations, survey data or reference data from a plurality of reference wells may be used to improve drilling performance, such as by reducing an error in estimating true vertical depth (TVD) or a position of the BHA 149 relative to one or more strata layers, as will be described in further detail herein. Additionally, survey data from recently drilled wells, or wells still currently being drilled, including the same well, may be used for reducing an error in estimating TVD or a position of the BHA 149 relative to one or more strata layers.

Also shown in FIG. 4 is central command 414, which has access to a central drilling database (DB) 416, and may be located at a centralized command center that is in communication with drilling hubs 410 and drilling rigs 210 in the various regions 402. The centralized command center may have the ability to monitor drilling and equipment activity at any one or more of the drilling rigs 210. In some embodiments, the central command 414 and the drilling hubs 412 may be operated by a commercial operator of the drilling rigs 210 as a service to customers who have hired the commercial operator to drill wells and provide other drilling-related services.

In FIG. 4, the central drilling DB 416 may be a central repository that is accessible to the drilling hubs 410 and the drilling rigs 210. Accordingly, the central drilling DB 416 may store information for the various drilling rigs 210 in the different regions 402. In some embodiments, the central drilling DB 416 may serve as a backup for at least one regional drilling DB 412 or may otherwise redundantly store information that is also stored on at least one regional drilling DB 412. Likewise, the regional drilling DB 412 may serve as a backup or redundant storage for at least one drilling rig 210 in the region 402. For example, the regional drilling DB 412 may store information collected by the steering control system 168 from the drilling rig 210.

In some embodiments, the formulation of a drill plan for a drilling rig 210 may include processing and analyzing the collected data in the regional drilling DB 412 to create a more effective drill plan. Furthermore, once drilling has begun, the collected data may be used in conjunction with current data from the drilling rig 210 to improve drilling decisions. As noted, the functionality of the steering control system 168 may be provided at the drilling rig 210, or may be provided, at least in part, at a remote processing resource, such as the drilling hub 410 or the central command 414.

As noted, the steering control system 168 may provide functionality as a surface steerable system for controlling the drilling rig 210. The steering control system 168 may have access to the regional drilling DB 412 and the central drilling DB 416 to provide the surface steerable system functionality. As will be described in greater detail below, the steering control system 168 may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. The steering control system 168 may be used to perform operations such as receiving drilling data representing a drill trajectory and other drilling parameters, calculating a drilling solution for the drill trajectory based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at the drilling rig 210, monitoring the drilling process to gauge whether the drilling process is within a margin of error that is defined for the drill trajectory, or calculating corrections for the drilling process if the drilling process is outside of the margin of error.

Referring now to FIG. 5, an example of rig control systems 500 is illustrated in schematic form. The rig control systems 500 may include fewer or more elements than shown in FIG. 5 in different embodiments. In the illustrated embodiment, the rig control systems 500 include the steering control system 168 and the drilling rig 210. Specifically, the steering control system 168 is shown with logical functionality including an autodriller 510, a bit guidance 512, and an autoslide 514. The drilling rig 210 is hierarchically shown including rig controls 520, which provide secure control logic and processing capability, along with drilling equipment 530, which represents the physical equipment used for drilling via the drilling rig 210. As shown, the rig controls 520 include a WOB/differential pressure control system 522, a positional/rotary control system 524, a fluid circulation control system 526, and a sensor system 528, while the drilling equipment 530 includes a draw works/snub 532, the top drive 140, mud pumping equipment 536, and MWD/wireline equipment 538.

The steering control system 168 can include one or more processors and one or more tangible memory devices storing non-transient instructions executable by the one or more processors to cause the one or more processors to accomplish the functionality described herein with respect to the steering control system 168. Likewise, each of the WOB/differential pressure control system 522, the positional/rotary control system 524, and the fluid circulation control system 526 can include one or more processors and one or more tangible memory devices storing non-transient instructions executable by the one or more processors to cause the one or more processors to accomplish the functionality described herein with respect to the respective control system. In alternate embodiments, one or more programmable logic controllers (PLCs) may be employed to provide the functionality described herein with respect to the respective control system. Accordingly, each of the systems included in rig controls 520 may be a separate controller, such as a PLC, and may autonomously operate, at least to a degree. The steering control system 168 may represent hardware that executes instructions to implement a surface steerable system that provides feedback and automation capability to an operator, such as a driller. For example, the steering control system 168 may cause the autodriller 510, the bit guidance 512 (also referred to as a bit guidance system (BGS)), and the autoslide 514 (among others, not shown) to be activated and executed at an appropriate time during drilling. In particular implementations, the steering control system 168 may be enabled to provide a user interface during drilling, such as the user interface 850 depicted and described below with respect to FIG. 8. Accordingly, the steering control system 168 may interface with the rig controls 520 to facilitate manual, assisted manual, semi-automatic, and automatic operation of the drilling equipment 530 included in the drilling rig 210. The rig controls 520 may also accordingly be enabled for manual or user-controlled operation of drilling and may include certain levels of automation with respect to the drilling equipment 530.

In the rig control systems 500 of FIG. 5, the WOB/differential pressure control system 522 may be interfaced with the draw works/snubbing unit 532 to control WOB. The positional/rotary control system 524 may be interfaced with the top drive 140 to control rotation of the drill string 146. The fluid circulation control system 526 may be interfaced with the mud pumping equipment 536 to control mud flow and may also receive and decode mud telemetry signals. The sensor system 528 may be interfaced with the MWD/wireline equipment 538, which may represent various BHA sensors and instrumentation equipment, among other sensors that may be downhole or at the surface.

In the rig control systems 500, the autodriller 510 may represent an automated rotary drilling system and may be used for controlling rotary drilling. Accordingly, the autodriller 510 may enable automatic operation of the rig controls 520 during rotary drilling, as indicated in the drill plan. The bit guidance 512 may represent an automated control system to monitor and control performance and operation of the drill bit 148.

In the rig control systems 500, the autoslide 514 may represent an automated slide drilling system and may be used for controlling slide drilling. Accordingly, the autoslide 514 may enable automatic operation of the rig controls 520 during a slide and may return control to the steering control system 168 for rotary drilling at an appropriate time, as indicated in the drill plan. In particular implementations, the autoslide 514 may be enabled to provide a user interface during slide drilling to specifically monitor and control the slide. For example, autoslide 514 may rely on the bit guidance 512 for orienting a toolface and on the autodriller 510 to set WOB or control rotation or vibration of the drill string 146.

FIG. 6 shows a collection of control algorithm modules 600 used with the steering control system 168. The control algorithm modules 600 include a slide control executor 650, a slide control configuration provider 652, a BHA and pipe specification provider 654, a borehole geometry model 656, a top drive orientation impact model 658, a top drive oscillator impact model 660, a ROP impact model 662, a WOB impact model 664, a differential pressure impact model 666, a torque model 668, a tool face projection module 670, a tool face control evaluator 672, a top drive adjustment calculator module 674, an oscillator adjustment calculator 676, and an auto driller adjustment calculator 678. The slide control executor 650 is responsible for managing execution of the slide control algorithms. The slide control configuration provider 652 is responsible for validating, maintaining, and providing configuration parameters for the other control algorithm modules 600. The BHA & pipe specification provider 654 is responsible for managing and providing details of the BHA 149 and the drill string 146 characteristics. The borehole geometry model 656 is responsible for keeping track of the borehole geometry and providing a representation of the borehole geometry to other software modules. The top drive orientation impact model 658 is responsible for modeling the impact that changes to the angular orientation of the top drive 140 have had on the toolface control. The top drive oscillator impact model 660 is responsible for modeling the impact that oscillations of the top drive 140 has had on the toolface control. The ROP impact model 662 is responsible for modeling the effect on the toolface control of a change in ROP or a corresponding ROP set point. The WOB impact model 664 is responsible for modeling the effect on the toolface control of a change in WOB or a corresponding WOB set point. The differential pressure impact model 666 is responsible for modeling the effect on the toolface control of a change in differential pressure (DP) or a corresponding DP set point. The torque model 668 is responsible for modeling the comprehensive representation of torque for surface, downhole, break over, and reactive torque, modeling impact of those torque values on toolface control, and determining torque operational thresholds. The toolface control evaluator 672 is responsible for evaluating all factors impacting toolface control and whether adjustments need to be projected, determining whether re-alignment off-bottom is indicated, and determining off-bottom toolface operational threshold windows. The toolface projection 670 is responsible for projecting toolface behavior for top drive 140, the top drive oscillator, and auto driller adjustments. The top drive adjustment calculator 674 is responsible for calculating top drive adjustments resultant to toolface projections. The oscillator adjustment calculator 676 is responsible for calculating oscillator adjustments resultant to toolface projections. The autodriller adjustment calculator 678 is responsible for calculating adjustments to autodriller 510 resultant to toolface projections.

FIG. 7 illustrates a steering control process 700 for determining an optimal corrective action for drilling. The steering control process 700 may be used for rotary drilling or slide drilling in different embodiments.

The steering control process 700 employs a variety of inputs that can be used to determine an optimum corrective action. The inputs include formation hardness/unconfined compressive strength (UCS) 710, formation structure 712, inclination/azimuth 714, current zone 716, measured depth 718, vertical section 720, bit factor 722, mud motor torque 724, reference trajectory 730, and angular velocity 726. The reference trajectory 730 of borehole 106 is determined to calculate a trajectory misfit in act 732. Act 732 may output the trajectory misfit to determine an optimal corrective action to minimize the misfit at act 734, which may be performed using the other inputs described above. Then, at act 736, the drilling rig is caused to perform the optimal corrective action.

In some implementations, at least certain portions of the steering control process 700 may be automated or performed without user intervention, such as operating the rig control systems 500. In other implementations, the accomplishment of the optimal corrective action in act 736 may be provided or communicated (by display, SMS message, email, or otherwise) to one or more human operators, who may then take appropriate action. The one or more human operators may be members of a rig crew, which may be located at or near the drilling rig 210 or may be located remotely from the drilling rig 210.

Referring to FIG. 8, a user interface 850 that may be generated by the steering control system 168 for monitoring and operation by a human operator is illustrated. The user interface 850 provides many different types of information in an easily accessible format. The user interface 850 may be shown on a computer monitor, a television, a viewing screen (e.g., a display device) associated with the steering control system 168. In some embodiments, at least certain portions of user interface 850 may be displayed to and operated by a user of the steering control system 168 on a mobile device, such as a tablet or a smartphone. For example, the steering control system 168 may support mobile applications that enable the user interface 850, or other user interfaces, to be used on a mobile device, for example, within a vicinity of the drilling rig 210.

As shown in FIG. 8, the user interface 850 includes a hole depth indicator 852, a bit depth indicator 854, a gamma ray indicator 856, an inclination indicator 858, an azimuth indicator 860, and a TVD indicator 862 distributed across the top of the user interface 850. The user interface 850 further includes a rate of penetration (ROP) indicator 864, a mechanical specific energy (MSE) indicator 866, a differential pressure indicator 868, a standpipe pressure indicator 870, a flow rate indicator 872, a rotary RPM (angular velocity) indicator 874, a bit speed indicator 876, and a WOB indicator 878.

In the user interface 850, each of the indicators 864, 866, 868, 872, 874, 876, and 878 includes a marker representing a target value. While each of the markers in FIG. 8 is set to a particular target value, the marker can be set to any suitable target value. Although not shown in FIG. 8, multiple markers may be present on a single indicator. The markers may vary in color or size. The ROP indicator 864 includes a marker 865 indicating that the target value is 50 feet/hour (or 15 m/hour). The MSE indicator 866 includes a marker 867 indicating that the target value is 37 kilograms per square inch (ksi) (or 255 MPa). The differential pressure indicator 868 includes a marker 869 indicating that the target value is 200 pounds per square inch (psi) (or 1,380 kilo Pascal (kPa)). The flow rate indicator 872 includes a marker 873 indicating that the target value is 500 gallons per minute (gpm) (or 31.5 liters per second (L/s)). The rotary RPM indicator 874 includes a marker 875 indicating that the target value is 0 RPM (e.g., due to sliding). The bit speed indicator 876 includes a marker 877 indicating that the target value is 150 RPM. The WOB indicator 878 includes a marker 879 indicating that the target value is 10 kips (or 4,500 kg). Each indicator may also include a colored band, or another marking, to indicate, for example, whether the respective gauge value is within a safe range (e.g., indicated by a green color), within a caution range (e.g., indicated by a yellow color), or within a danger range (e.g., indicated by a red color).

The user interface 850 includes a log chart 880 that can display depth versus one or more measurements (e.g., may represent log inputs relative to a progressing depth chart). For example, the log chart 880 may have a Y-axis representing depth and an X-axis representing a measurement such as gamma ray count 881 (as shown), a ROP 883 (e.g., empirical ROP and normalized ROP), or resistivity. The user interface 850 includes an autopilot button 882 and an oscillate button 884. The autopilot button 882 may be used to engage or disengage the autodriller 510. The oscillate button 884 may be used to directly control oscillation of the drill string 146 or to engage/disengage an external hardware device or controller.

The user interface 850 includes a circular chart 886 for displaying current and historical toolface orientation information (e.g., which way the bend is pointed). The circular chart 886 represents three hundred and sixty degrees. A series of circles displayed within the circular chart 886 represent a timeline of toolface orientations, with the sizes of the circles indicating the temporal position of each circle. For example, larger circles may be more recent than smaller circles, so a largest circle 888 may be the newest reading and a smallest circle 889 may be the oldest reading. In other embodiments, circles 889, 888 may represent the energy or progress made via size, color, shape, a number within a circle, etc. For example, a size of a particular circle may represent an accumulation of orientation and progress for the period of time represented by the circle. In other embodiments, concentric circles representing time (e.g., with the outside of the circular chart 886 being the most recent time and the center point being the oldest time) may be used to indicate the energy or progress (e.g., via color or patterning such as dashes or dots rather than a solid line).

In the user interface 850, the circular chart 886 may also be color coded, with the color coding existing in a band 890 around the circular chart 886 or positioned or represented in other ways. The color coding may use colors to indicate activity in a certain direction. For example, the color red may indicate the highest level of activity, while the color blue may indicate the lowest level of activity. Furthermore, the arc range in degrees of a color may indicate the amount of deviation. Accordingly, a relatively narrow (e.g., thirty degrees) arc of red with a relatively broad (e.g., three hundred degrees) arc of blue may indicate that most activity is occurring in a particular toolface orientation with little deviation. As shown in user interface 850, the color blue may extend from approximately 22-337 degrees, the color green may extend from approximately 15-22 degrees and 337-345 degrees, the color yellow may extend a few degrees around the 13-and 345-degree marks, while the color red may extend from approximately 347-10 degrees. Transition colors or shades may be used with, for example, the color orange marking the transition between red and yellow or a light blue marking the transition between blue and green. This color coding may enable the user interface 850 to provide an intuitive summary of how narrow the standard deviation is and how much of the energy intensity is being expended in the proper direction. Furthermore, the center of energy may be viewed relative to the target. For example, the user interface 850 may clearly show that the target is at 90 degrees, but the center of energy is at 45 degrees.

The user interface 850 further includes a slide indicator 892. The slide indicator 892 indicates how much time remains until a slide occurs or how much time remains for a current slide. For example, the slide indicator 892 may represent a time, a percentage (e.g., as shown, a current slide may be 56% complete), a distance completed, or a distance remaining. The slide indicator 892 may graphically display information using, for example, a colored bar 893 that increases or decreases with slide progress. In some embodiments, the slide indicator 892 may be built into the circular chart 886 (e.g., around the outer edge with an increasing/decreasing band), while in other embodiments the slide indicator 892 may be a separate indicator such as a meter, a bar, a gauge, or another indicator type. In various implementations, the slide indicator 892 may be refreshed by the autoslide 514.

The user interface 850 further includes an error indicator 894 that indicates a magnitude and a direction of error. For example, the error indicator 894 may indicate that an estimated drill bit position is a certain distance from the planned trajectory, with a location of the error indicator 894 around the circular chart 886 representing the heading. For example, the error indicator 894 in FIG. 8 illustrates an error magnitude of 15 feet and an error direction of 15 degrees. The error indicator 894 may be any color but may be red for purposes of example. The error indicator 894 may display a zero if there is no error. The error indicator may represent that the drill bit 148 is on the planned trajectory using other means, such as being a green color. Transition colors, such as yellow, may be used to indicate varying amounts of error. In some embodiments, the error indicator 894 may not appear unless there is an error in magnitude or direction. The user interface 850 further includes a marker 896 that indicates an ideal slide direction. Although not shown, other indicators may be present, such as a bit life indicator to indicate an estimated lifetime for the current bit based on a value such as time or distance.

The user interface 850 may be arranged in many different ways. For example, colors may be used to indicate normal operation, warnings, and problems. In such cases, the numerical indicators may display numbers in one color (e.g., green) for normal operation, may use another color (e.g., yellow) for warnings, and may use yet another color (e.g., red) when a serious problem occurs. The indicators may also flash or otherwise indicate an alert. The gauge indicators may include colors (e.g., green, yellow, and red) to indicate operational conditions and may also indicate the target value (e.g., an ROP of 100 feet/hour). For example, the ROP indicator 864 may have a green bar to indicate a normal level of operation (e.g., from 10-300 feet/hour), a yellow bar to indicate a warning level of operation (e.g., from 300-360 feet/hour), and a red bar to indicate a dangerous or otherwise out of parameter level of operation (e.g., from 360-390 feet/hour). The ROP indicator 864 may also display a marker at 100 feet/hour to indicate the desired target ROP.

Furthermore, the use of numeric indicators, gauges, and similar visual display indicators may be varied based on factors such as the information to be conveyed and the personal preference of the viewer. Accordingly, the user interface 850 may provide a customizable view of various drilling processes and information for a particular individual involved in the drilling process. For example, the steering control system 168 may enable a user to customize the user interface 850 as desired, although certain features (e.g., standpipe pressure) may be locked to prevent a user from intentionally or accidentally removing important drilling information from the user interface 850. Other features and attributes of the user interface 850 may be set by user preference. Accordingly, the level of customization and the information shown by the user interface 850 may be controlled based on who is viewing the user interface 850 and their role in the drilling process.

Parameter Sweep

FIG. 9 is a simplified schematic flow chart of a method 900 of controlling operation of a drilling system to perform a parameter sweep to identify an operational set point for the drilling system based on drilling performances measured or monitored during the parameter sweep, in accordance with embodiments. The method 900 can be practiced in any suitable drilling system, such as the drilling system 100.

It is to be noted that one or more models may be used to better determine which parameter values to sweep through a range, what drilling parameter combinations may be used for sweeping, and the ranges of values to be included in a sweep in order to optimize drilling performance. Such models may include physics-informed neural networks, artificial intelligence and/or machine learning models, physics-based models, and the like. For example, suppose one wants to test the block velocity for tripping speed optimization. The parameter sweep can start from 250 ft/hr and go to 500 ft/hr though various increments, measuring hook load at each increment, provide that information to one or more of the models mentioned, and then determine from the model output that perhaps the sweep should extend to 600 ft/hr because that speed still falls within a range of acceptable values based on safety considerations. Thus, the model can be used to optimize the range of the parameter values to be examined and give directions about what values to test for sweeping parameters (arrows 1006 or 1010 in FIG. 10 for example).

At step 902, a drilling system is controlled to operate at a first operational set point, which in this example can be a designated rotational rate of a drill string and a designated block velocity value. For example, FIG. 10A illustrates an example first operational set point 1002 and an example envelope parameter sweep 1004 that can be employed in the method 900. At the example first operational set point 1002, the top drive is operated to rotate the drill string at 100 RPMs and the hoisting system is operated to apply a 220,000 lbs. hook load to the top drive. These values can be varied by the control system by incrementing or decrementing the hook load and/or RPMs through a desired range therefor. While the parameter values are being varied (i.e., swept), one or more other parameters can be monitored so that the effects of different values for hook load and/or RPMs can be better observed and an optimal or otherwise desired value or combination of values can be determined and then implemented by the control system for drilling the well.

An alternative parameter sweep is shown in FIG. 10B. In FIG. 10B, a drilling system is controlled to operate at a first set point, which in FIG. 10B is still revolutions per minute of the drill string, and a designated block velocity value. For example, FIG. 10B illustrates an example first set point 1002 and an example envelope parameter sweep 1004 that can be employed with method 900. At the example first operational set point 1002 in FIG. 10B, the top drive is operated to rotate the drill string at 80 RPMs and the traveling block is operated to run at a velocity of 10 feet per minute. These values can be controllably varied through a desired range of RPMs and feet/minute. For example, during drilling, block velocity typically ranges from 1 foot/hour to around 300 feet/hour, often depending on the hardness of the formation being drilled. Rotational speed of the drill string at the surface typically varies from 60 to 200 RPMs or so. For tripping operations, generally block velocity varies from 50ft/minute to 80 ft/minute and at RPMs at surface would vary from 0 to 100 RPMs.

At step 904, the drilling system is controlled to perform a parameter sweep, which in this example is one in which the top drive rotates the drill string through a parameter sweep range of rotational rates and/or the hoisting system applies a parameter sweep range of support forces to the top drive. The parameter sweep range of rotational rates and/or the parameter sweep range of support forces can have any suitable configurations. FIGS. 10A and 10B show examples of parameter sweeps 1004. Each parameter sweep 1004 includes a first segment 1006, a second segment 1008, and a third segment 1010. In the first segment 1006, the rotational rate of the drill string is increased from 240 rpm to 251 rpm and the hook load (in FIG. 10A) or the block velocity (in FIG. 10B) is held constant at 250,000 lbs to transition from the first operational set point 1002 to a sweep perimeter operational set point 1012. In the second segment 1008, the rotational rate of the drill string and the hook load and block velocity, respectively, are varied so that the second segment 1008 encircles the first operational set point 1002 and returns back to the sweep perimeter operational set point 1012. The third segment 1010 transitions back to the first operational set point 1002 from the sweep perimeter operational set point 1012. As shown, the example parameter sweep 1004 sweeps the rotational rate of the drill string and the hook load or block velocity, respectively, through operational set points that envelope and surround the first operational set point 1002.

At step 906, parameter-sweep drilling performances are determined (such as by monitoring or measuring sensor values) based on parameter sweep value sets for the parameter sweep. Each of the parameter sweep value sets can include any suitable combination of performance related drilling parameters of interest such as, but not limited to, rate of penetration (ROP), level of oscillation of a reactive torque applied to the top drive by the drill string, level of rotational rate oscillations of the BHA, a tracking accuracy value indicative of a magnitude of deviation of a measure track of the borehole from a planned track of the borehole, a drill bit wear rate estimate of wear of a drill bit used to drill the borehole and/or toolface. In embodiments, the parameter sweep 1004 in FIGS. 10A and 10B is illustrated as a series of parameter sweep operational set points and the each of the parameter sweep value sets can be measured or otherwise determined for a respective one of the parameter sweep operational set points. A respective one of the parameter-sweep drilling performance can be determined for each of the parameter sweep operational set points via a suitable function of the performance related drilling performance values such as, for example, a function employing a suitable cost function that accounts for costs associated with drilling the borehole and future performance related costs associated with deviations of the borehole track from a planned borehole track.

In some embodiments, one or more drilling parameters may have their values varied (or “swept) through a range of values even though the drilling rig is not currently drilling the well. For example, there are often numerous times during drilling of a well when drilling is paused to allow other operations to occur. These may include when the bit is off bottom, when tripping out, when a new drill pipe or stand is added to or removed from the drill string, and so on. For example, the drill string may be oscillated through a range of wraps, and/or with a range of speeds, while the bit is off bottom, and in such situations, the varying of the wraps and/or velocity of oscillations may be used to determine inflection points in torsional forces or friction that the drill string is subject to. The use of parameter sweeps in accordance with this disclosure thus includes sweeps of drilling parameter values both during drilling and during transitions (such as lifting a bit off bottom or lowering the bit back to the bottom of well before actual drilling of the rock commences).

Parameter sweeps in accordance with the present disclosure may be performed at regular intervals, which time intervals may vary depending on the section of the well being drilled, the particular formation(s) being drilled, the expected formation(s) to be drilled, and the like. Parameter sweeps also may be performed at irregular intervals, such as if problems are encountered or are expected. Some drilling parameter sweeps may be performed at regular time intervals while others occur at irregular intervals. In some cases, particular drilling parameters may be swept through a range of values and/or the time intervals between parameter sweeps may vary depending on the rig state, which may include states such as rotary drilling, slide drilling (with or without) oscillations, tripping, back to bottom, rotating off bottom, reaming up/down, circulating or not, and so forth. It may also be desirable to have one or more drilling parameters as the subject of one or more parameter sweeps for each one of a defined rig state for a number of different rig states, such as those just mentioned.

In some embodiments, the rig state may be used to determine the timing of a number of parameter sweeps, as well as the parameter(s) to be swept, and/or the range of values through which the parameter(s) is/are to be swept. Referring now to FIG. 10C, a diagram showing the parameter value ranges for block velocity and rotation speed to be swept for various rig states is provided. A control system may determine or may be provided with a current rig state and an indication that a sweep is to be performed. The control system may then perform a sweep of block velocity and rotation speed that may be determined based on the current rig state. For example, if the rig state is tripping down, the block velocity can be varied from 1000 to 3000 feet/hour, while the drill string is held steady and not rotated (i.e., the drill string rotational speed is zero). If the rig state is tripping up, then the block velocity can be varied from −1000 to −3000 feet/hour (with a rotational speed of zero). In other words, the sweep may vary the block velocity values in the opposite direction for the two tripping states. If the rig state is back to bottom, the block velocity may be varied in increments or decrements ranging from 300 to 750 feet/hour, while the drill string rotational speed is varied in increments or decrements from 30-80 RPMs. FIG. 10C provides additional examples of ranges for parameter sweeps of block velocity and drill string rotational speed for other rig states, including slide drilling without oscillations, reaming up or down, and rotary drilling. Those skilled in the art will understand that the foregoing ranges of values are exemplary, and may vary from those set forth in FIG. 10C. Those skilled in the art will further understand that the parameters shown in FIG. 10C (block velocity and rotational speed) are not the only parameters that may be swept based on rig state, and that the list of rig states in FIG. 10C is exemplary and may include others, such as, for example, slide drilling with oscillation, rotating off bottom, whether drilling mud is circulating or not, and so forth. A number of approaches may be used to determine rig state, including the use of a computer vision system, such as described in U.S. Pat. No. 10,997,412, issued on May 4, 2021 to Torrione, which is hereby incorporated by reference as if fully set forth herein.

FIG. 11 shows a plot 1100 of example relative drilling performance for the example envelope parameter sweep 1004. While in some embodiments, overall drilling performance might be considered for optimization, it is anticipated that in many situations, it will instead be desirable to optimize particular drilling parameters, especially in order to avoid potential problems. For example, one might try to optimize ROP, or one might instead try to optimize block velocity and RPMs in a manner that avoids vibrations, stick-slip, whirling, and other potential problems or anomalous conditions. In some embodiments, other measures might be optimized, such as maximizing production percentage probability or minimizing time to target as described in U.S. Pat. No. 11,313,217 B2, issued on Apr. 26, 2022, and titled “Systems and Methods of Iterative Well Planning for Optimized Results”, which is hereby incorporated in its entirety by reference herein. As shown, the example relative drilling performance varies from 0.93 at operational set point 1012, reduces to a minimum of about 0.84 at 120 degrees around the second segment 1008 from operational set point 1012, then increases to a maximum of about 0.96 at operational set point 1014 (which is at 300 degrees around the second segment 1008 from the operational set point 1012), and then reduces back down to 0.93 back at operational set point 1012.

FIG. 12 illustrates an example linear parameter sweep 1200 that can be employed in conjunction with the example envelope parameter sweep 1004 at step 906. FIG. 13 shows a plot 1300 of relative drilling performance for the example linear parameter sweep 1200. As illustrated in FIG. 12, the example linear parameter sweep 1200 extends from the first operational set point 1002 through operational set point 1014 (which has the maximum relative drilling performance of about 0.96 for the envelope parameter sweep 1004. As shown in FIG. 13, the example relative drilling performance reaches a maximum at operational set point 1202 (at rotational rate 250 rpm and hook load 8400 lbs). In embodiments, the linear parameter sweep 1200 is continued as long as the relative drilling performance is increasing and can be terminated once the relative drilling performance drops below the maximum relative drilling performance by a suitable threshold.

At step 908, a second operational set point is selected based on the parameter sweep and the resulting parameter-sweep drilling performance. For example, the second operational set point can be set to be operational set point 1202 (which is found to provide the highest relative drilling performance using the combination of the example envelope parameter sweep 1004 and the associated example linear parameter sweep 1200). In step 910, the drilling system is controlled to operate at the second operational set point (e.g., operational set point 1202, which has a relative drilling performance of 1.0 at 250 rpm rotational rate of the drill string and an lbs hook load).

Impulse Input

In embodiments, one or more drilling parameters for use in drilling a wellbore are determined and/or updated during the drilling of a borehole with the drilling system based on a measured response of the drilling system to an induced impulse. FIG. 14 shows a simplified schematical flow chart of a method 1400 of controlling operation of a drilling system, in accordance with such embodiments. The method 1400 can be practiced in conjunction with any suitable drilling system, such as the drilling system 100.

At step 1402, a first support load applied to a top drive by a hoisting system is measured during drilling of a first portion of a borehole via rotation of a drill string by the top drive. In embodiments, the support load is measured via generation of sensor output (by one or more sensors) indicative of the support load and processing of the sensor output by a computer system to determine the magnitude of the support load.

At step 1404, the top drive is controlled to induce one or more predetermined rotational accelerations of a proximal end portion of a drill string. FIG. 10 shows a plot 1502 of an example predetermined variation of rotation rate of the proximal end portion of the drill string 146. In the example predetermined variation of rotation rate, the rotation rate of the proximal end portion of the drill string 146 is transitioned from a first rotation rate (R₁) to a second rotation rate (R₂) over a predetermined time span (t₂−t₁) in a predetermined manner. In the illustrated example, the angular acceleration of the proximal end portion of the drill string 146 increases from zero at t₁ to a maximum at t=t₁+0.5(t₂−t₁) and then decrease back to zero at t₂. Any suitable predetermined variation in the rotation rate of the proximal end portion of the drill string 146 can be employed to produce a corresponding one or more predetermined rotational accelerations of the proximal end portion of the drill string 146 whenever a change in rotation rate of the proximal end portion of the drill string 146 is accomplished as part of operation of the drilling system 100. Likewise, any suitable predetermined variation in the vertical translation rate of the proximal end portion of the drill string 146 (and therefore a corresponding variation in the vertical acceleration of the proximal end of the drill string 146) can be produced by controlling a hoisting system motor of the drilling system 100 to produce a matching variation in the vertical translation rate of the traveling block 136, which supports the top drive 140 and is supported by the drilling line 138.

FIG. 16 shows a plot 1602 of an example predetermined variation of vertical translation rate of the proximal end portion of the drill string 146. In the example predetermined variation of vertical translation rate, the translation rate of the proximal end portion of the drill string 146 is transitioned from a first velocity (V₁) to a second velocity rate (V₂) over a predetermined time span (t₂−t₁) in a predetermined manner. In the illustrated example, the axial acceleration of the proximal end portion of the drill string 146 increases from zero at t₁ to a maximum at t=t₁+0.5(t₂−t₁) and then decrease back to zero at t₂. Any suitable predetermined variation in the axial translation rate of the proximal end portion of the drill string 146 can be employed to produce a corresponding one or more predetermined axial accelerations of the proximal end portion of the drill string 146 whenever a change in translation rate of the proximal end portion of the drill string 146 is accomplished as part of operation of the drilling system 100. Any suitable time span (t₂−t₁) and any suitable velocity profile can be employed to produce a suitable one or more predetermined accelerations of the proximal end portion of the drill string 146 to induce a response of the drilling system 100.

FIG. 17 shows a plot 1702 of another example predetermined variation of the rotation rate of the proximal end portion of the drill string 146 over a predetermined time span (t₂−t₁) that can be used to generate a response of the drilling system 100. In the example predetermined variation of rotation rate, the rotation rate of the proximal end portion of the drill string 146 is varied sinusoidally from (R) up to a maximum (R+deltaR), and then down to a minimum (R−deltaR), and then back to (R) over a predetermined time span (t₂−t₁) in a predetermined manner, which produces corresponding sinusoidally varying accelerations of the proximal end portion of the drill string 146. While one sinusoidal cycle is shown in which the rotational rate of the proximal end portion of the drill string 146 varies by plus and minus (deltaR) over the predetermined time span (t₂−t₁), any suitable number of cycles, amplitudes, and frequencies can be employed to induce a response from the drilling system 100.

Likewise, any suitable predetermined variation in the vertical velocity of the proximal end portion of the drill string 146 (and therefore a corresponding variation in the vertical acceleration of the proximal end of the drill string 146) can be produced by controlling a hoisting system motor of the drilling system 100 to produce a matching variation in the vertical velocity of the traveling block 136, which supports the top drive 140 and is supported by the drilling line 138. For example, FIG. 18 shows a plot 1802 of another example predetermined variation of the vertical translation rate of the proximal end portion of the drill string 146 over a predetermined time span (t₂−t₁) that can be used to generate a response of the drilling system 100. In the example predetermined variation of translation rate, the translation rate of the proximal end portion of the drill string 146 is varied sinusoidally from (V) up to a maximum (V+deltaV), and then down to a minimum (V−deltaV), and then back to (V) over a predetermined time span (t₂−t₁) in a predetermined manner, which produces corresponding sinusoidally varying axial accelerations of the proximal end portion of the drill string 146. While one sinusoidal cycle is shown in which the translation rate of the proximal end portion of the drill string 146 varies by plus and minus (deltaV) over the predetermined time span (t₂−t₁), any suitable number of cycles, amplitudes, and frequencies can be employed to induce a response from the drilling system 100.

At step 1406, a response of the drill string to the one or more predetermined rotational accelerations of the proximal end portion of the drill string 146 is measured. For example, one or more predetermined rotational accelerations of the proximal end portion of the drill string 146 may produce transient rotational oscillation of the drill string 146 that can be measured by measuring corresponding reactive torsions applied to the top drive 140 by the proximal end portion of the drill string 146 and/or can be measured by measuring corresponding rotational oscillations of the BHA 149.

At step 1408, a measured response of the drill string to the one or more predetermined rotational accelerations of the proximal end portion of the drill string 146 is processed to determine a second support load for application to the top drive by the hoisting system. For example, the response of the drill string can include resulting reactive torsions applied to the top drive by the drill string. When the resulting reactive torsions are below an acceptable threshold by a suitable margin, the hook load may be decreased to increase WOB without incurring detrimental stick/slip oscillations of the drill string. In contrast, when the resulting reactive torsions are not below an acceptable margin by a suitable margin, the hook load may be maintained or increased to maintain or decrease WOB to provide a suitable operational margin for avoiding detrimental stick/slip oscillations. At step 1410, the hoisting system is controlled to apply the second support load to the top drive to drill a second portion of the borehole.

Drilling Mud System Parameter Sweep

FIG. 19 is a simplified schematic flow chart of a method 1900 of controlling operation of a drilling mud system, in accordance with embodiments. The method 1900 can be practiced in conjunction with any suitable drilling system, such as the drilling system 100. At step 1902, a drilling mud system is controlled during drilling of a first portion of a borehole to pump drilling mud through a drill string at a first flow rate. At step 1904, the drilling mud system is controlled to perform a parameter sweep in which the drilling mud system pumps drilling mud through the drill string over a range of flow rates. At step 1906, parameter-sweep drilling performance value sets (e.g., ROP, toolface, differential pressure, bit wear, etc.) are determined for the parameter sweep of drilling mud flow rates. At step 1908, a second drilling mud flow rate is selected based on the parameter sweep and the parameter-sweep drilling performances. At step 1910, the drilling mud system is controlled to pump drilling mud through the drill string at the second drilling mud flow rate. In embodiments, a variation in a differential pressure of the drilling mud produced during the parameter sweep such as to determine whether there is a buildup of cuttings within the borehole. In embodiments, a variation in a differential pressure of the drilling mud produced during the parameter sweep to estimate rheological properties for the drilling mud within the borehole with the help of a model (physics-based, AI/ML, or a combination of these (PINN)

Stick/Slip Based WOB Limit

Detrimental stick slip oscillations during rotary drilling may occur when the WOB exceeds a WOB threshold for avoiding detrimental stick slip at a given rate of rotation of the drill string by the top drive. The length of the drill string can be on the order of 3000 meters or more. When the drill bit is rotationally engaged with a rock formation, the drill bit can transfer varying levels of torsion from the rock formation to the BHA. When the torsion transferred to the BHA from the drill bit varies by more than an applicable threshold, the drill string can be subjected to considerable elastic twisting around its longitudinal axis, which can lead to considerable variations in the rotation rate of the drill bit. For example, FIG. 20 shows plots of simulated 2002, predicted 2004, and measured 2006 bottom hole assembly (BHA) rotational speeds during example stick slip oscillations of a drill string. The average rotational rate of the BHA (approximately 160 rpm) is equal to the rate at which the proximal end portion of the drill string is rotated by the top drive. In some instances, the rotation rate of the BHA varies between 0 rpm and approximately double the rotation rate of the proximal end portion of the drill string.

FIG. 21 shows plots of simulated reactive torsion 2102 and measured reactive torsion 2104 applied to a top drive of a drilling system by a proximal end portion of a drill string of the drilling system. As illustrated in FIG. 22, the coefficient of static friction (μ_s) between the borehole and the drill string is higher than the coefficient of dynamic friction (μ_d), which increases the magnitude of the torsion transferred to the BHA from the drill bit for rotation rates of the drill bit close to zero, thereby increasing the tendency for the rotation rate of the drill bit to be zero over brief periodically recurring time periods.

There are various existing approaches for reducing exposure to detrimental stick slip oscillations. For example, FIG. 23 illustrates a drilling system 2301 with reduced stick slip tendency. The drilling assembly 2301 is described in U.S. Pat. No. 6,166,654, which is incorporated by reference herein. The drilling system 2301 includes a drill string 2303 (represented as a torsional spring), a BHA 2305, a motor 2311, and a rotary table 2314. The motor 2311 rotates the rotary table 2314, which rotates the proximal end portion of the drill string 2313. The BHA 2305 includes a drill bit (not shown) that is subjected to frictional forces that apply a torsional moment 2318 to the BHA 2305. The drilling system 2301 employs an electronic control system (not shown) that regulates the rotation rate of the motor 2311. The electronic control system is configured to control the rotation rate of the motor 2311 so as to provide torsional flexibility and torsional damping equivalent to a torsional spring 2307 (which has a torsional spring constant K_f) and a torsional viscous damper 2309 (which has a damping ratio C_f). As discussed in U.S. Pat. No. 6,166,654, K_f and C_f can be selected to minimize the threshold rotational rate for a given WOB at which stick slip oscillations may occur when using the approach described in U.S. Pat. No. 6,166,654.

While approaches (such as the approach described in U.S. Pat. No. 6,166,654) can be used to decrease the threshold rotation rate below which detrimental stick slip oscillations may occur for a specific WOB, the threshold rotation rate will typically increase with increasing WOB. Increased rate of penetration (ROP) can often be achieved using increased WOB. As a result, the maximum achievable ROP at a given rotation rate may be effectively limited by the maximum WOB that can be employed at the given rotation rate without inducing detrimental stick slip oscillations, which may be dependent on a number of factors such as the stick slip oscillation mitigating approaches employed, the length of the drill string, the torsional stiffness of the drill string, the borehole trajectory, the down-hole coefficient of friction, and the properties of the formation being drilled.

In view of the desirability of maximizing ROP, it may be desirable to maximize WOB without inducing detrimental slip stick oscillations of the drill string. Accordingly, it may be desirable to determined and provide a maximum WOB limit applicable to a particular drill string configuration (e.g., length, bending stiffness, torsional stiffness), borehole configuration (e.g., trajectory), and formation properties.

FIG. 24 is a simplified schematic flow chart of a method 2400 of determining a WOB limit for avoiding stick slip oscillations of a drill string, in accordance with embodiments. The method 2400 can be practiced using any suitable drilling system, such as the drilling system 100.

At step 2402, a hoisting system is controlled to decrease vertical support of a top drive by a predefined amount to thereby increase WOB. For example, FIG. 25 shows a plot 2502 of an example predetermined variation of hook load that can be used to decrease the vertical support of the top drive to increase WOB. Any suitable predetermined reduction in vertical support of the top drive can be employed.

In step 2404, a response of the drill string to the increased WOB is measured. For example, in some embodiments, the reactive torsion applied to the top drive by the proximal end portion of the drill string is measured. In some embodiments, the BHA assembly includes one or more BHA sensors (e.g., a 6 axis accelerometer) that generates sensor output indicative of torsional accelerations of the BHA and the sensor output is processed to determine the torsional accelerations of the BHA.

In step 2406, the response of the drill string to the increased WOB is processed to quantify the level of the torsional oscillations of the drill string. For example, when the reactive torsion applied to the top drive by the proximal end portion of the drill string is measured, the torsional oscillations of the drill string can be quantified by processing the measure reactive torsions. When the torsional accelerations of the BHA are measured, the torsional accelerations can be integrated to quantify the range of variation in the rotation rate of the BHA.

At step 2408, the level of the torsional oscillations of the drill string is compared to an acceptance threshold to assess acceptability. For example, when oscillations of the reactive torsion are measured, the reactive torsions can be compared to a corresponding acceptance threshold, which can be established to provide a suitable operational margin between the measured reactive torsions at the acceptance threshold and the occurrence of detrimental torsional oscillations of the drill string. When the torsional accelerations of the BHA are measured, the range of variation in the rotation rate of the BHA can be compared to an acceptance threshold, which can be established to provide a suitable operational margin between the measured rotational rate range and the occurrence of detrimental torsional oscillations of the drill string. If the level of measured torsional oscillations of the drill string is acceptable, the WOB limit can be increased based on the amount by which the vertical support of the down-hole assembly was decreased (step 2510). If the level of measured torsional oscillations of the drill string is unacceptable, the WOB limit can be maintained or decreased based on the measured torsional oscillations of the drill string and/or on the amount by which the vertical support of the down-hole assembly was decreased (step 2512).

Top Drive Motor Controller Parameter Sweep

FIG. 26 is a simplified schematic flow chart of a method 2600 of controlling operation of a drilling system in which a parameter sweep is used to select a torsional spring rate to be provided via control of a top drive motor. The method 2600 can be practiced in conjunction with any suitable drilling system, such as the drilling system 100.

At step 2602, a top drive, a top drive control system, and a hoisting system are controlled to operate at a first operational set point to drill a first portion of a borehole. At the first operational set point, the top drive control system controls operation of the top drive to provide a first torsional spring rate in series with the torsional spring rate of the drill string.

At step 2604, the top drive control system is controlled to perform a parameter sweep in which the top drive provides a parameter sweep range of torsional spring rates. The parameter sweep range of torsional spring rates can cover any suitable range, which may include the first torsional spring rate. At step 2606, torsional oscillation levels of the drill string are determined during the parameter sweep. In embodiments, the torsional oscillation levels are based on reactive torsion applied to the top drive by the drill string.

In embodiments, the drill string includes a bottom hole assembly (BHA) that includes one or more BHA sensors that generates a BHA sensor output indicative of a rotational rate of the BHA. The BHA sensor output can be processed to determine rotational rates of the BHA. The parameter sweep torsional oscillation levels of the drill string based on rotational rates of the BHA.

At step 2608, a second torsional spring rate to be provided by the top drive is selected based on the torsional oscillation levels of the drill string for the parameter sweep. For example, the second torsional spring rate can be selected to be the torsional spring rate from the parameter sweep range of torsional spring rates that minimizes the torsional oscillation levels of the drill string.

At step 2610, the top drive, the top drive control system, and the hoisting system are controlled to operate at a second operational set point to drill a second portion of the borehole. The top drive control system controls operation of the top drive to provide the second torsional spring rate at the second operational set point.

FIG. 27 is a simplified schematic flow chart of a method 2700 of controlling operation of a drilling system in which a parameter sweep is used to select a torsional damping coefficient to be provided via control of a top drive motor. The method 2700 can be practiced in conjunction with any suitable drilling system, such as the drilling system 100.

At step 2702, a top drive, a top drive control system, and a hoisting system are controlled to operate at a first operational set point to drill a first portion of a borehole. At the first operational set point, the top drive control system controls operation of the top drive to provide torsional damping corresponding to a first torsional damping coefficient.

At step 2704, the top drive control system is controlled to perform a parameter sweep in which the top drive provides torsional damping corresponding to a parameter sweep range of torsional damping coefficients. The parameter sweep range of torsional damping coefficients can cover any suitable range, which may include the first torsional damping coefficient.

At step 2706, torsional oscillation levels of the drill string are determined for the parameter sweep. In embodiments, the torsional oscillation levels are based on reactive torsion applied to the top drive by the drill string. In embodiments, the drill string includes a bottom hole assembly (BHA) that includes one or more BHA sensors that generates a BHA sensor output indicative of a rotational rate of the BHA. The BHA sensor output can be processed to determine rotational rates of the BHA. The parameter sweep torsional oscillation levels of the drill string based on rotational rates of the BHA.

At step 2708, a second torsional damping coefficient to be provided by the top drive is selected based on the torsional oscillation levels of the drill string from the parameter sweep. For example, the second torsional damping coefficient can be selected to be the torsional damping coefficient from the parameter sweep range of torsional damping coefficients that minimizes the torsional oscillation levels of the drill string.

At step 2710, the top drive, the top drive control system, and the hoisting system are controlled to operate at a second operational set point to drill a second portion of the borehole. The top drive control system controls operation of the top drive to provide torsional damping corresponding to the second torsional damping coefficient at the second operational set point.

Other variations are within the spirit of the present invention. Thus, while the invention is susceptible to various modifications and alternative constructions, certain illustrated embodiments thereof are shown in the drawings and have been described above in detail. It should be understood, however, that there is no intention to limit the invention to the specific form or forms disclosed, but on the contrary, the intention is to cover all modifications, alternative constructions, and equivalents falling within the spirit and scope of the invention, as defined in the appended claims. Although not shown in the Figures, for example, a parameter sweep of the rotational wraps of a pipe in the drill string might be performed after the pipe has been added to the drill string. While doing the sweep of the wraps, the control system can monitor the amount of torque in the drill string; when the torque value changes, that indicates that movement of the drill string has occurred downhole and could provide valuable information about conditions downhole, which can be used in connection with modeling such conditions and adjusting drilling parameters accordingly. For example, the inflection point at which rotation downhole begins is important information about the friction downhole. During a sweep, multiple friction releases might be observed, and these can be mapped to locations in the borehole using the spring constant for the drill string and the torque or wraps applied to achieve the observed torque inflections or drill string movements. In publication IADC/SPE-208708-MS, presented March 2022, by Mahjoub, Dao, Nguyen, and Menand, titled “Combining Downhole Axial and Surface Oscillation Tools, What Are the Consequences on Tool Face Control Performance?” which is hereby incorporated by reference herein in its entirety, simulations with different wraps and attendant effects on tool face are provided. It is believed that a parameter sweep of wraps can be used to provide effects on tool face and thus provide an optimal number, amplified, and/or velocity of wraps to better control tool face. One example is that, once the inflection point in the number of wraps that corresponds to movement of the drill string downhole is known, that number of wraps might be used for the next slide drilling operation to be performed in drilling the well.

The range of values for a parameter sweep, and/or the rate at which the parameters are swept, may vary for different parameters, different portions of the wellbore, different measured depths of the wellbore, different geology (e.g., the length and trajectory of the drill string in a given formation), the bottom hole assembly or other equipment downhole, and the like. Moreover, the parameter sweeps may be performed at the same or different intervals during drilling of the wellbore, again depending on factors such as the parameters involved, the portion of the wellbore involved, the measured depth of the wellbore, the geology involved, and/or the BHA and/or other downhole equipment. In addition, one or more parameters can be swept almost continuously if desired, or the time between parameter sweeps may be decreased when more control and/or optimization is desired. For example, if a drilling event or condition is detected (including situations in which an event or condition is predicted), such as sticking, a stall, bit wear, a cave in, a kick, or the like, the control system may be programmed to automatically respond by doing parameter sweeps of one or more parameters in response to the detected or predicted condition or event. Moreover, it should be noted that the time during which a parameter sweep is performed may vary, such that some parameter sweeps may be performed more quickly than others. In some situations, the time for which a particular value of a drilling parameter is held during a parameter sweep may be varied during that parameter sweep or from one parameter sweep to another.

One or more tuning algorithms and systems and methods may be used together with the systems and methods of the present disclosure above. For example, an autotuning system and/or method such as described in U.S. Published Patent Application No. 2023/0151696 A1, published on May 18, 2023, and titled “Apparatus and Methods for Controlling Drilling” which is hereby incorporated by reference herein in its entirety, may be used together with the systems and methods described herein for optimizing drilling operations using sweeps of drilling parameters. An autotuning algorithm such as that described in the foregoing patent application may be improved with the sweeping of drilling parameters, such as torsional stiffness/damping and the rock-drill bit interaction. Normally the Kf and Cf variables are dependent on the geometry and length of the drill string. Using a parameter sweep like those described herein during drilling operations with a drilling rig would allow for the inclusion of friction and rock related parameters that can only be effectively measured on a rig and can be measured using drilling parameter sweeps like those described herein. Additional parameters that may be improved with the use of drilling parameter sweeps include determining the origin of stick-slip=off bottom friction with the string and the on-bottom rock-bit interaction, off bottom sweeping parameters and on-bottom sweeping parameters comparisons, and the like. The results of such drilling parameter sweeps may be provided to an autotuning system to provide more accurate inputs and therefore obtain better and more effective estimates of one or more drilling parameters, which can be modified to more effectively drill the wellbore.

In drilling, it may be desirable to minimize and mitigate stick/slip of the drill string, as well as other potential problems such as whirling, excessive vibrations, buckling, failure, and the like. The use of PID and other control systems to autotune drilling parameters is described in U.S. Published Patent Application No. 2023/0151696 A1, mentioned above. Using stick/slip as an example, drilling parameters such as rotational speed and block velocity (as well as any of the others mentioned in this disclosure) could be varied in a parameter sweep, with the results used to autotune inputs in a PID control system such as Kf and Cf (which provide coefficients for drill string stiffness and damping, respectively). In one example, a control system could determine (e.g., from ROP, MSE, etc.) or receive input information relating to (e.g., from a well plan) a measure of the hardness of a formation being drilled. In addition, the control system could sweep through a series of values for RPMs and monitor the corresponding observed torque values. The information on RPMs, torque, and rock hardness could be provided to an autotuning control system (like a PID system) that can then use that information to iteratively modify the Kf and Cf coefficient values to obtain an autotuned algorithm, which in turn can be used to determine a desired rotational rate and/or torque values that can be implemented by the drilling system to mitigate stick/slip in the formation being drilled. It will be appreciated that rock hardness can be indirectly calculated in a number of ways, such as based on observed ROP, MSE, WOB, and the like. It should also be appreciated that, although the foregoing example focuses on stick/slip mitigation and the use of parameter sweeps of RPMs, other drilling parameter values may be similarly swept and other drilling parameters may be monitored during such sweeps in order to minimize and mitigate against other potential problems.

It should be noted that the incremental and/or decremental changes made to the parameters as described herein may be relatively large relatively small, and the size of the increments and/or decremental amounts may be varied. In some situations, the changes may be noticeable to a human observer as they occur (e.g., faster or slower rotation of drill pipe, movement up or down of a traveling block, etc.). In some situations the changes may not be noticeable because they are made in relatively smaller amounts than normal human perception would notice. This is important because, with a computer control system used to implement the parameter sweeps as described herein, and with the sensors available, a computer control system can implement small changes in drilling parameters that a human could not perceive or execute and the computer control system can observe the measured effects of even these small, otherwise imperceptible by a human changes.

The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. The terms “comprising,” “having,” “including,” and “containing” are to be construed as open-ended terms (i.e., meaning “including, but not limited to,”) unless otherwise noted. The term “connected” is to be construed as partly or wholly contained within, attached to, or joined together, even if there is something intervening. Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein, and each separate value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g., “such as”) provided herein, is intended merely to better illuminate embodiments of the invention and does not pose a limitation on the scope of the invention unless otherwise claimed. No language in the specification should be construed as indicating any non-claimed element as essential to the practice of the invention.

Preferred embodiments of this invention are described herein, including the best mode known to the inventors for carrying out the invention. Variations of those preferred embodiments may become apparent to those of ordinary skill in the art upon reading the foregoing description. The inventors expect skilled artisans to employ such variations as appropriate, and the inventors intend for the invention to be practiced otherwise than as specifically described herein. Accordingly, this invention includes all modifications and equivalents of the subject matter recited in the claims appended hereto as permitted by applicable law. Moreover, any combination of the above-described elements in all possible variations thereof is encompassed by the invention unless otherwise indicated herein or otherwise clearly contradicted by context.

All references, including publications, patent applications, and patents, cited herein are hereby incorporated by reference to the same extent as if each reference were individually and specifically indicated to be incorporated by reference and were set forth in its entirety herein.