DRILLING ASSEMBLY SYSTEMS AND METHODS

Abstract

An apparatus can include a drilling tool having a proximate and distal end. The drilling tool can include an internal threaded section proximal the distal end of the drilling tool, a gripper apparatus affixed to an exterior surface of a portion of the drilling tool. The gripper apparatus can be configured to selectively extend and increase an outer diameter of the portion of the drilling tool and to selectively retract and decrease the outer diameter of the portion of the drilling tool. The drilling tool can include a cylindrical sleeve having external threads extending from at least a portion of an outer surface of the cylindrical sleeve, the cylindrical sleeve configured to travel inside the drilling tool and have the external threads engage with the internal threaded section. The drilling tool can include an inner and outer bearing sections. Methods of using the tool for drilling are also disclosed.

Description

BACKGROUND

Field of the Disclosure

The present disclosure relates generally to systems and methods for drilling of wells, such as for oil and gas production and, more particularly, to systems and methods for drilling wells.

Description of the Related Art

Some of the biggest challenges in conventional motor drilling in a lateral section of a directional well are toolface control, rate of penetration control, and cost. The reactive torque on the drill face can cause swinging of the drill bit and therefore make precise control of the toolface difficult during drilling operations. In addition, long lateral sections (e.g., 20,000 feet-40,000 feet) during drilling operations can make it difficult to maintain weight-on-bit to push the drill pipe laterally when extending the wellbore.

BRIEF SUMMARY

Certain embodiments of the present disclosure can provide methods, systems, and apparatuses for drilling wells.

A downhole drilling tool can allow for both accurate toolface control and maintaining weight on bit even in long lateral sections. A downhole kelly according to the present disclosure may not require as much weight, and therefore drill pipe, and may therefore exhibit less friction, resulting in faster drilling. The downhole kelly may maintain a set toolface when sliding regardless of weight on bit and may maintain a set rate of penetration (ROP) when sliding or rotating.

When sliding, a downhole drilling tool according to the present technology may contain grippers, which may expand to engage with the inside wall of the borehole. After the downhole kelly tool is fixed in position, such as by utilizing one or more grippers, a section of the drill string, which may be hexagonal in embodiments, can advance through rollers like a traditional kelly when sliding, allowing the bit to stay in constant contact with the drilling surface. The downhole kelly tool can perform an “inchworm” or “corkscrew” type function, as discussed in greater detail below, that can maintain force on the bit through long lateral sections of the well.

A locking mechanism, activated electronically or by pressure, can be used to lock the splines and the kelly section or the splines and/or the Helix section of the downhole kelly tool to selectively lock and unlock from each other. The indexer can be activated by pressure cycling that would allow the downhole assembly to sequence by 5-20 degrees to set the tool face without rotating the drill string.

In an aspect of the disclosure, an apparatus can include a drilling tool having a proximate and distal end. The drilling tool can include an internal threaded section proximal the distal end of the drilling tool, a gripper apparatus affixed to an exterior surface of a portion of the drilling tool. The gripper apparatus can be configured to selectively extend and increase an outer diameter of the portion of the drilling tool and to selectively retract and decrease the outer diameter of the portion of the drilling tool. The drilling tool can include a cylindrical sleeve having external threads extending from at least a portion of an outer surface of the cylindrical sleeve, the cylindrical sleeve configured to travel inside the drilling tool and have the external threads engage with the internal threaded section.

In various embodiments, the drilling tool can include an inner bearing section inside a portion of the cylindrical sleeve.

In various embodiments, the drilling tool can include an outer bearing section inside a portion of the drilling tool between an inside surface of the drilling tool and an outside surface of the cylindrical sleeve.

In various embodiments, the drilling tool can include a kelly section configured to connect a drill pipe at a proximate end of the drilling tool.

In various embodiments, the gripper apparatus can include a plurality of gripper pads configured to engage with an interior surface of a borehole.

In various embodiments, the gripper apparatus comprises a plurality of teeth configured to engage with an interior surface of a borehole.

In various embodiments, the drilling tool can include a drill bit attached to the cylindrical sleeve.

In various embodiments, the gripper apparatus can be configured to extend outwardly from a longitudinal axis of the drilling tool when drilling mud flows through the drilling tool.

In various embodiments, the gripper apparatus can be configured to retract inwardly towards a longitudinal axis of the drilling tool when drilling mud is not flowing through the drilling tool.

In an aspect of the disclosure a method of drilling a wellbore can include providing a drilling tool located in a wellbore to be drilled, wherein the drilling tool comprises a first section having a gripper apparatus configured to selectively extend outwardly from a longitudinal axis of the drilling tool when a drilling fluid flows through the drilling tool, and wherein the drilling tool further comprises a second section having a sleeve having external threads extending from at least a portion of an outer surface of the sleeve. The sleeve can be configured to travel along the longitudinal axis of the drilling tool inside the drilling tool. The sleeve can have the external threads engage with the internal threaded section. A drill bit can couple to a first end of the drilling tool and a drill string can be coupled to a second end of the drilling tool.

The method can include obtaining a desired toolface or confirming that a current toolface is within a target range therefor or is within a margin of error thereof.

The method can include adjusting toolface, if necessary, so that the current toolface is within a target range therefor or is within a margin of error thereof.

Responsive to a flow of drilling fluid through the drilling tool, the method can include extending the gripper apparatus to thereby engage with an interior surface of the wellbore. The method can include drilling a first portion of the wellbore.

In various embodiments, during drilling of the first portion of the wellbore, the sleeve travels along the longitudinal axis of the drilling tool until stopped by threading of the external threads with the internal threads.

In various embodiments, the engagement of the gripper apparatus with the interior surface of the wellbore maintains a toolface within a target range.

In various embodiments, the drilling comprises a slide drilling operation.

In various embodiments, the drilling comprises one or more slide drilling operations and/or one or more rotary drilling operations.

In various embodiments, the drill string does not include heavy weight drill pipe.

In various embodiments, the first portion of the wellbore drilled extends vertically towards the surface.

In various embodiments, the drilling comprises a plurality of alternating slide drilling operations and rotary drilling operations.

In various embodiments, the drill string comprises casing for a portion of the wellbore.

In various embodiments, at least a portion of the drill string comprises one or more pipes comprising a composite material.

In various embodiments, the method can include ceasing flow of the drilling fluid once the first portion of the wellbore has been drilled to thereby retract the grippers. The method can include allowing the sleeve to reset to its initial position before the drilling of the first portion of the wellbore. The method can include causing the drilling fluid to flow, thereby extending the grippers to engage with an interior surface of the wellbore. The method can include drilling a second portion of the wellbore. Any one or more methods discussed herein can include repeating the drilling operation(s) a plurality of times.

The downhole kelly can achieve desired WOB with minimal heavy weight drill pipe (HWDP) and accurate anchoring during a slide.

Reference to the remaining portions of the specification, including the drawings and claims, will realize other features and advantages of embodiments of the present disclosure. Further features and advantages, as well as the structure and operation of various embodiments of the present disclosure, are described in detail below with respect to the accompanying drawings. In the drawings, like reference numbers can indicate identical or functionally similar elements.

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 is a depiction of a drilling system for drilling a borehole;

FIG. 2 is a depiction of a drilling environment including the drilling system for drilling a borehole;

FIG. 3 is a depiction of a borehole generated in the drilling environment;

FIG. 4 is a depiction of a drilling architecture including the drilling environment;

FIG. 5 is a depiction of rig control systems included in the drilling system;

FIG. 6 is a depiction of algorithm modules used by the rig control systems;

FIG. 7 is a depiction of a steering control process used by the rig control systems;

FIG. 8 is a depiction of a graphical user interface provided by the rig control systems;

FIG. 9 is a depiction of a guidance control loop performed by the rig control systems;

FIG. 10 is a depiction of a controller usable by the rig control systems;

FIG. 11 illustrates a profile cutaway view of a downhole drilling tool that is a drilling tool having a proximal end and distal end;

FIG. 12A illustrates a cutaway view of the gripper apparatus of FIG. 11 in which the mud pumps for the drilling assembly are operating;

FIG. 12B illustrates a cutaway view of the gripper apparatus of FIG. 11 in which the mud pumps for the drilling assembly are not operating;

FIG. 13 illustrates an exemplary threaded section and an exemplary threaded sleeve of the downhole drilling tool;

FIG. 14 illustrates the exemplary threaded sleeve inside the exemplary threaded section of the downhole kelly tool;

FIG. 15 illustrates an exemplary kelly section of the downhole drilling tool;

FIGS. 16A and 16B illustrates a first state of the gripping mechanism;

FIG. 17 illustrates a portion of a drill string employing a downhole drilling tool with a ball screw system; and

FIGS. 18A and 18B illustrates a portion of a toolface anchor according to embodiments of the present technology;

FIG. 19 is a flow chart of a process for drilling using a downhole drilling tool, according to an example of the present disclosure.

DESCRIPTION OF PARTICULAR EMBODIMENT(S)

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.

Drilling a well typically involves a substantial amount of human decision-making during the drilling process. For example, geologists and drilling engineers use their knowledge, experience, and the available information to make decisions on how to plan the drilling operation, how to accomplish the drill plan, and how to handle issues that arise during drilling. However, even the best geologists and drilling engineers perform some guesswork due to the unique nature of each borehole. Furthermore, a directional human driller performing the drilling may have drilled other boreholes in the same region and so may have some similar experience. However, during drilling operations, a multitude of input information and other factors may affect a drilling decision being made by a human operator or specialist, such that the amount of information may overwhelm the cognitive ability of the human to properly consider and factor into the drilling decision. Furthermore, the quality or the error involved with the drilling decision may improve with larger amounts of input data being considered, for example, such as formation data from a large number of offset wells. For these reasons, human specialists may be unable to achieve optimal drilling decisions, particularly when such drilling decisions are made under time constraints, such as during drilling operations when continuation of drilling is dependent on the drilling decision and, thus, the entire drilling rig waits idly for the next drilling decision. Furthermore, human decision-making for drilling decisions can result in expensive mistakes because drilling errors can add significant cost to drilling operations. In some cases, drilling errors may permanently lower the output of a well, resulting in substantial long term economic losses due to the lost output of the well.

The systems and methods used to drill oil and gas wells are complex and sophisticated. Methods and systems developed for oil and gas wells can be adapted for use in planning, drilling, and creating wells for geothermal energy. The following discussion provides a description of systems and techniques for drilling wells that can be useful for drilling geothermal wells, as well as generating electricity therefrom.

Referring now to the drawings, Referring to FIG. 1, a drilling system 100 is illustrated in one embodiment as atop drive system. As shown, the drilling system 100 includes a derrick 132 on the surface 104 of the earth and is used to drill a borehole 106 into the earth. Typically, drilling system 100 is used at a location corresponding to a geographic formation 102 in the earth that is known.

In FIG. 1, derrick 132 includes a crown block 134 to which a traveling block 136 is coupled via a drilling line 138. In drilling system 100, a top drive 140 is coupled to traveling block 136 and may provide rotational force for drilling. A saver sub 142 may sit between the top drive 140 and a drill pipe 144 that is part of a drill string 146. Top drive 140 may rotate drill string 146 via the saver sub 142, which in turn may rotate a drill bit 148 of a bottom hole assembly (BHA) 149 in borehole 106 passing through formation 102. Also visible in drilling system 100 is a rotary table 162 that may be fitted with a master bushing 164 to hold drill string 146 when not rotating.

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

In drilling system 100, drilling equipment (see also FIG. 5) is used to perform the drilling of borehole 106, such as top drive 140 (or rotary drive equipment) that couples to drill string 146 and BHA 149 and is configured to rotate drill string 146 and apply pressure to drill bit 148. Drilling system 100 may include control systems such as a 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 ROP or the radial orientation of the toolface, change the flow rate of drilling mud, and perform other operations. Sensor system 528 may be for obtaining sensor data about the drilling operation and drilling system 100, including the downhole equipment. For example, sensor system 528 may include MWD or logging while drilling (LWD) tools for acquiring information, such as toolface and formation logging information, which 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 steering control system 168. 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. It is noted that certain downhole tools may have both MWD and LWD capabilities. Such information acquired by 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, rotary rotations per minute (RPM), bit speed, ROP, WOB, among other information. It is noted that all or part of sensor system 528 may be incorporated into a control system, or in another component of the drilling equipment. As drilling system 100 can be configured in many different implementations, it is noted that 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 BHA 149 or elsewhere along drill string 146 to provide downhole surveys of borehole 106. Accordingly, 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 downhole tool 166 is shown in singular in drilling system 100, it is noted that multiple instances (not shown) of downhole tool 166 may be located at one or more locations along drill string 146.

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

In operation, steering control system 168 may be accessible via a communication network (see also FIG. 10) and may accordingly receive formation information via the communication network. In some embodiments, 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 steering control system 168 may be located in downhole tool 166 (not shown). In some embodiments, steering control system 168 may communicate with a separate controller (not shown) located in downhole tool 166. In particular, steering control system 168 may receive and process measurements received from downhole surveys and may perform the calculations described herein using the downhole surveys and other information referenced herein.

In drilling system 100, to aid in the drilling process, data is collected from borehole 106, such as from sensors in BHA 149, downhole tool 166, or both. The collected data may include the geological characteristics of formation 102 in which borehole 106 was formed, the attributes of drilling system 100, including BHA 149, and drilling information such as weight-on-bit (WOB), drilling speed, and other information pertinent to the formation of borehole 106. The drilling information may be associated with a particular depth or another identifiable marker to index collected data. For example, the collected data for 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 borehole 106 in 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 borehole 106 may be located locally at drilling system 100, at a drilling hub that supports a plurality of drilling systems 100 in a region, or at a database server accessible over the communication network that provides access to the database (see also FIG. 4). At drilling system 100, the collected data may be stored at the surface 104 or downhole in drill string 146, such as in a memory device included with BHA 149 (see also FIG. 10). Alternatively, at least a portion of the collected data may be stored on a removable storage medium, such as using steering control system 168 or 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, steering control system 168 is located at or near the surface 104 where borehole 106 is being drilled. 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 FIGS. 4 and 5). Accordingly, 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 BHA 149.

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 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, 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 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, 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, steering control system 168 may enable the user to imitate 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. It is noted that 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 steering control system 168. To implement automatic control, the step of manual starting the indicated control operation or sequence of operations is eliminated, and 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, 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 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 steering control system 168. The processing operations performed by steering control system 168 may be any processing operation, as disclosed herein. The output operations performed by 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 steering control system 168 to distribute information among various entities and processors.

In particular, the operations performed by 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.

Accordingly, steering control system 168 may receive input information either before drilling, during drilling, or after drilling of borehole 106. The input information may comprise measurements from one or more sensors, as well as survey information collected while drilling 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 steering control system 168. For example, a web interface may be used to interact directly with steering control system 168 to upload the drill plan or drilling parameters.

As noted, the input information may be provided to steering control system 168. After processing by steering control system 168, steering control system 168 may generate control information that may be output to drilling rig 210 (e.g., to rig controls 520 that control drilling equipment 530, see also FIGS. 2 and 5). Drilling rig 210 may provide feedback information using rig controls 520 to steering control system 168. The feedback information may then serve as input information to steering control system 168, thereby enabling steering control system 168 to perform feedback loop control and validation. Accordingly, 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 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, steering control system 168 may generate output information indicative of instructions to rig controls 520 to enable automatic drilling using the latest location of BHA 149. Therefore, an improved accuracy in the determination of the location of BHA 149 may be provided using 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, drilling environment 200 may illustrate additional details with respect to formation 102 below the surface 104 in drilling system 100 shown in FIG. 1. In FIG. 2, 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 borehole 106 extending into the ground to a true vertical depth (TVD) 266 and penetrating several subterranean strata layers. Borehole 106 is shown in FIG. 2 extending through strata layers 268-1 and 270-1, while terminating in strata layer 272-1. Accordingly, as shown, borehole 106 does not extend or reach underlying strata layers 274-1 and 276-1. A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1. It is noted that 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, target area 280 may be specified in the drill plan using subsurface coordinates, or references to certain markers, which indicate where borehole 106 is to be terminated. In other instances, target area may be specified in the drill plan using a depth range within which borehole 106 is to remain. For example, the depth range may correspond to strata layer 272-1. In other examples, target area 280 may extend as far as can be realistically drilled. For example, when borehole 106 is specified to have a horizontal section with a goal to extend into strata layer 172 as far as possible, target area 280 may be defined as 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 to 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 fault line 278. On one side of fault line 278, where borehole 106 is located, strata layers 268-1, 270-1, 272-1, 274-1, and 276-1 are unshifted by 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 fault line 278.

Current drilling operations frequently include directional drilling to reach a target, such as 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 borehole 106, which increases an exposed length of borehole 106 within strata layer 272-1, and which may accordingly be beneficial for hydrocarbon extraction from strata layer 272-1. Directional drilling may also be used alter an angle of 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 172. As such, directional drilling may involve multiple vertical adjustments that complicate the trajectory of borehole 106.

Referring now to FIG. 3, one embodiment of a portion of 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 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 up” section 316. Build up section 316 may begin at a kickoff point 312 in vertical portion 310 and may end at a begin point 314 of horizontal portion 318. The change in inclination in buildup 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 every one hundred feet drilled. The build rate for a particular build up section may remain relatively constant or may vary.

The build rate used for any given build up section may depend on various factors, such as properties of the formation (i.e., strata layers) through which borehole 106 is to be drilled, the trajectory of 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 borehole 106. Depending on the severity of any mistakes made during directional drilling, borehole 106 may be enlarged or drill bit 146 may be backed out of a portion of borehole 106 and redrilled along a different path. Such mistakes may be undesirable due to the additional time and expense involved. However, if the built rate is too cautious, additional overall 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 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 106. Rotating, also called “rotary drilling,” uses top drive 140 or rotary table 162 to rotate drill string 146. Rotating may be used when drilling occurs along a straight trajectory, such as for vertical portion 310 of borehole 106. Sliding, also called “steering” or “directional drilling” as noted above, typically uses a mud motor located downhole at BHA 149. The mud motor may have an adjustable bent housing and is not powered by rotation of the drill string. Instead, the mud motor uses hydraulic power derived from the pressurized drilling mud that circulates along borehole 106 to and from the surface 104 to directionally drill borehole 106 in buildup section 316.

Thus, 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 drill string 146 is stopped. Based on feedback from measuring equipment, such as from downhole tool 166, adjustments may be made to drill string 146, such as using 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 borehole 106. Once the desired orientation of the mud motor is attained, WOB to the drill bit is increased, which causes the drill bit 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 rotating the drill string again. The rotation of the drill string after sliding may neutralize the directional deviation caused by the bend in the mud motor due to the continuous rotation around a centerline of borehole 106.

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

Specifically, in a region 401-1, a drilling hub 410-1 may serve as a remote processing resource for 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, 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 drilling rigs 210 located in region 401-2, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, 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 region 402, or where a new well is planned in region 402. Furthermore, multiple drilling rigs 210 may be actively drilling concurrently in region 402 and may be in different stages of drilling through the depths of formation strata layers at region 402. Thus, for any given well being drilled by 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 TVD or a position of 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 BHA 149 relative to one or more strata layers.

Also shown in FIG. 4 is central command 414, which has access to central drilling DB 416, and may be located at a centralized command center that is in communication with drilling hubs 410 and drilling rigs 210 in various regions 402. The centralized command center may have the ability to monitor drilling and equipment activity at any one or more drilling rigs 210. In some embodiments, central command 414 and drilling hubs 412 may be operated by a commercial operator of 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, it is particularly noted that central drilling DB 416 may be a central repository that is accessible to drilling hubs 410 and drilling rigs 210. Accordingly, central drilling DB 416 may store information for various drilling rigs 210 in different regions 402. In some embodiments, 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. In turn, regional drilling DB 412 may serve as a backup or redundant storage for at least one drilling rig 210 in region 402. For example, regional drilling DB 412 may store information collected by steering control system 168 from drilling rig 210.

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

As noted, steering control system 168 may provide functionality as a surface steerable system for controlling drilling rig 210. Steering control system 168 may have access to regional drilling DB 412 and central drilling DB 416 to provide the surface steerable system functionality. As will be described in greater detail below, steering control system 168 may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. 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 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. It is noted that rig control systems 500 may include fewer or more elements than shown in FIG. 5 in different embodiments. As shown, rig control systems 500 includes steering control system 168 and drilling rig 210. Specifically, steering control system 168 is shown with logical functionality including an autodriller 510, a bit guidance 512, and an autoslide 514. 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 at drilling rig 210. As shown, rig controls 520 include WOB/differential pressure control system 522, positional/rotary control system 524, fluid circulation control system 526, and sensor system 528, while drilling equipment 530 includes a draw works/snub 532, top drive 140, mud pumping equipment 536, and MWD/wireline equipment 538.

Steering control system 168 represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in FIG. 10. Also, WOB/differential pressure control system 522, positional/rotary control system 524, and fluid circulation control system 526 may each represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in FIG. 10, but for example, in a configuration as a programmable logic controller (PLC) that may not include a user interface but may be used as an embedded controller. Accordingly, it is noted that 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. 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, steering control system 168 may cause autodriller 510, bit guidance 512 (also referred to as a bit guidance system (BGS)), and autoslide 514 (among others, not shown) to be activated and executed at an appropriate time during drilling. In particular implementations, 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, steering control system 168 may interface with rig controls 520 to facilitate manual, assisted manual, semi-automatic, and automatic operation of drilling equipment 530 included in drilling rig 210. It is noted that 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 drilling equipment 530.

In rig control systems 500 of FIG. 5, WOB/differential pressure control system 522 may be interfaced with draw works/snubbing unit 532 to control WOB of drill string 146. Positional/rotary control system 524 may be interfaced with top drive 140 to control rotation of drill string 146. Fluid circulation control system 526 may be interfaced with mud pumping equipment 536 to control mud flow and may also receive and decode mud telemetry signals. Sensor system 528 may be interfaced with 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 rig control systems 500, autodriller 510 may represent an automated rotary drilling system and may be used for controlling rotary drilling. Accordingly, autodriller 510 may enable automate operation of rig controls 520 during rotary drilling, as indicated in the drill plan. Bit guidance 512 may represent an automated control system to monitor and control performance and operation drilling bit 148.

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

FIG. 6 illustrates one embodiment of control algorithm modules 600 used with steering control system 168. The control algorithm modules 600 of FIG. 6 include: a slide control executor 650 that is responsible for managing the execution of the slide control algorithms; a slide control configuration provider 652 that is responsible for validating, maintaining, and providing configuration parameters for the other software modules; a BHA & pipe specification provider 654 that is responsible for managing and providing details of BHA 149 and drill string 146 characteristics; a borehole geometry model 656 that is responsible for keeping track of the borehole geometry and providing a representation to other software modules; a top drive orientation impact model 658 that is responsible for modeling the impact that changes to the angular orientation of top drive 140 have had on the toolface control; a top drive oscillator impact model 660 that is responsible for modeling the impact that oscillations of top drive 140 has had on the toolface control; an ROP impact model 662 that is responsible for modeling the effect on the toolface control of a change in ROP or a corresponding ROP set point; a WOB impact model 664 that is responsible for modeling the effect on the toolface control of a change in WOB or a corresponding WOB set point; a differential pressure impact model 666 that is responsible for modeling the effect on the toolface control of a change in differential pressure (DP) or a corresponding DP set point; a torque model 668 that 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; a toolface control evaluator 672 that 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; a toolface projection 670 that is responsible for projecting toolface behavior for top drive 140, the top drive oscillator, and auto driller adjustments; a top drive adjustment calculator 674 that is responsible for calculating top drive adjustments resultant to toolface projections; an oscillator adjustment calculator 676 that is responsible for calculating oscillator adjustments resultant to toolface projections; and an autodriller adjustment calculator 678 that is responsible for calculating adjustments to autodriller 510 resultant to toolface projections.

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

Steering control process 700 in FIG. 7 illustrates a variety of inputs that can be used to determine an optimum corrective action. As shown in FIG. 7, the inputs include formation hardness/unconfined compressive strength (UCS) 710, formation structure 712, inclination/azimuth 714, current zone 716, measured depth 718, desired toolface 730, vertical section 720, bit factor 722, mud motor torque 724, reference trajectory 730, and angular velocity 726. In FIG. 7, reference trajectory 730 of borehole 106 is determined to calculate a trajectory misfit in a step 732. Step 732 may output the trajectory misfit to determine an optimal corrective action to minimize the misfit at step 734, which may be performed using the other inputs described above. Then, at step 736, the drilling rig is caused to perform the optimal corrective action.

It is noted that in some implementations, at least certain portions of steering control process 700 may be automated or performed without user intervention, such as using rig control systems 700 (see FIG. 7). In other implementations, the optimal corrective action in step 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 human operators may be members of a rig crew, which may be located at or near drilling rig 210 or may be located remotely from drilling rig 210.

Referring to FIG. 8, one embodiment of a user interface 850 that may be generated by steering control system 168 for monitoring and operation by a human operator is illustrated. User interface 850 may provide many different types of information in an easily accessible format. For example, user interface 850 may be shown on a computer monitor, a television, a viewing screen (e.g., a display device) associated with 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 steering control system 168 on a mobile device, such as a tablet or a smartphone (see also FIG. 10). For example, steering control system 168 may support mobile applications that enable user interface 850, or other user interfaces, to be used on the mobile device, for example, within a vicinity of drilling rig 210.

As shown in FIG. 8, a user interface 850 provides visual indicators such as a hole depth indicator 852, a bit depth indicator 854, a GAMMA indicator 856, an inclination indicator 858, an azimuth indicator 860, and a TVD indicator 862. Other indicators may also be provided, including a 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 FIG. 8, at least some of indicators 864, 866, 868, 870, 872, 874, 876, and 878 may include a marker representing a target value. For example, markers may be set as certain given values, but it is noted that any desired target value may be used. Although not shown, in some embodiments, multiple markers may be present on a single indicator. The markers may vary in color or size. For example, ROP indicator 864 may include a marker 865 indicating that the target value is 50 feet/hour (or 15 m/h). MSE indicator 866 may include a marker 867 indicating that the target value is 37 ksi (or 255 MPa). Differential pressure indicator 868 may include a marker 869 indicating that the target value is 200 psi (or 1,380 kPa). ROP indicator 864 may include a marker 865 indicating that the target value is 50 feet/hour (or 15 m/h). Standpipe pressure indicator 870 may have no marker in the present example. Flow rate indicator 872 may include a marker 873 indicating that the target value is 500 gpm (or 31.5 L/s). Rotary RPM indicator 874 may include a marker 875 indicating that the target value is 0 RPM (e.g., due to sliding). Bit speed indicator 876 may include a marker 877 indicating that the target value is 150 RPM. WOB indicator 878 may include a marker 879 indicating that the target value is 10 klbs (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).

In FIG. 8, a log chart 880 may visually indicate depth versus one or more measurements (e.g., may represent log inputs relative to a progressing depth chart). For example, log chart 880 may have a Y-axis representing depth and an X-axis representing a measurement such as GAMMA count 881 (as shown), ROP 883 (e.g., empirical ROP and normalized ROP), or resistivity. An autopilot button 882 and an oscillate button 884 may be used to control activity. For example, autopilot button 882 may be used to engage or disengage autodriller 510, while oscillate button 884 may be used to directly control oscillation of drill string 146 or to engage/disengage an external hardware device or controller.

In FIG. 8, a circular chart 886 may provide current and historical toolface orientation information (e.g., which way the bend is pointed). For purposes of illustration, circular chart 886 represents three hundred and sixty degrees. A series of circles within circular chart 886 may 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 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 user interface 850, circular chart 886 may also be color coded, with the color coding existing in a band 890 around 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 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, user interface 850 may clearly show that the target is at 90 degrees, but the center of energy is at 45 degrees.

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

In user interface 850, an error indicator 894 may indicate a magnitude and a direction of error. For example, error indicator 894 may indicate that an estimated drill bit position is a certain distance from the planned trajectory, with a location of error indicator 894 around the circular chart 886 representing the heading. For example, FIG. 8 illustrates an error magnitude of 15 feet and an error direction of 15 degrees. Error indicator 894 may be any color but may be red for purposes of example. It is noted that error indicator 894 may present a zero if there is no error. Error indicator may represent that 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, error indicator 894 may not appear unless there is an error in magnitude or direction. A marker 896 may indicate 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.

It is noted that 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, 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). 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, 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, 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 user interface 850. Other features and attributes of 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 user interface 850 and their role in the drilling process.

Referring to FIG. 9, one embodiment of a guidance control loop (GCL) 900 is shown in further detail GCL 900 may represent one example of a control loop or control algorithm executed under the control of steering control system 168. GCL 900 may include various functional modules, including a build rate predictor 902, a geo modified well planner 904, a borehole estimator 906, a slide estimator 908, an error vector calculator 910, a geological drift estimator 912, a slide planner 914, a convergence planner 916, and a tactical solution planner 918. In the following description of GCL 900, the term “external input” refers to input received from outside GCL 900, while “internal input” refers to input exchanged between functional modules of GCL 900.

In FIG. 9, build rate predictor 902 receives external input representing BHA information and geological information, receives internal input from the borehole estimator 906, and provides output to geo modified well planner 904, slide estimator 908, slide planner 914, and convergence planner 916. Build rate predictor 902 is configured to use the BHA information and geological information to predict drilling build rates of current and future sections of borehole 106. For example, build rate predictor 902 may determine how aggressively a curve will be built for a given formation with BHA 149 and other equipment parameters.

In FIG. 9, build rate predictor 902 may use the orientation of BHA 149 to the formation to determine an angle of attack for formation transitions and build rates within a single layer of a formation. For example, if a strata layer of rock is below a strata layer of sand, a formation transition exists between the strata layer of sand and the strata layer of rock. Approaching the strata layer of rock at a 90 degree angle may provide a good toolface and a clean drill entry, while approaching the rock layer at a 45 degree angle may build a curve relatively quickly. An angle of approach that is near parallel may cause drill bit 148 to skip off the upper surface of the strata layer of rock. Accordingly, build rate predictor 902 may calculate BHA orientation to account for formation transitions. Within a single strata layer, build rate predictor 902 may use the BHA orientation to account for internal layer characteristics (e.g., grain) to determine build rates for different parts of a strata layer. The BHA information may include bit characteristics, mud motor bend setting, stabilization, and mud motor bit to bend distance. The geological information may include formation data such as compressive strength, thicknesses, and depths for formations encountered in the specific drilling location. Such information may enable a calculation-based prediction of the build rates and ROP that may be compared to both results obtained while drilling borehole 106 and regional historical results (e.g., from the regional drilling DB 412) to improve the accuracy of predictions as drilling progresses. Build rate predictor 902 may also be used to plan convergence adjustments and confirm in advance of drilling that targets can be achieved with current parameters.

In FIG. 9, geo modified well planner 904 receives external input representing a drill plan, internal input from build rate predictor 902 and geo drift estimator 912 and provides output to slide planner 914 and error vector calculator 910. Geo modified well planner 904 uses the input to determine whether there is a more optimal trajectory than that provided by the drill plan, while staying within specified error limits. More specifically, geo modified well planner 904 takes geological information (e.g., drift) and calculates whether another trajectory solution to the target may be more efficient in terms of cost or reliability. The outputs of geo modified well planner 904 to slide planner 914 and error vector calculator 910 may be used to calculate an error vector based on the current vector to the newly calculated trajectory and to modify slide predictions. In some embodiments, geo modified well planner 904 (or another module) may provide functionality needed to track a formation trend. For example, in horizontal wells, a geologist may provide steering control system 168 with a target inclination as a set point for steering control system 168 to control. For example, the geologist may enter a target to steering control system 168 of 90.5-91.0 degrees of inclination for a section of borehole 106. Geo modified well planner 904 may then treat the target as a vector target, while remaining within the error limits of the original drill plan. In some embodiments, geo modified well planner 904 may be an optional module that is not used unless the drill plan is to be modified. For example, if the drill plan is marked in steering control system 168 as non-modifiable, geo modified well planner 904 may be bypassed altogether or geo modified well planner 904 may be configured to pass the drill plan through without any changes.

In FIG. 9, borehole estimator 906 may receive external inputs representing BHA information, measured depth information, survey information (e.g., azimuth and inclination), and may provide outputs to build rate predictor 902, error vector calculator 910, and convergence planner 916. Borehole estimator 906 may be configured to provide an estimate of the actual borehole and drill bit position and trajectory angle without delay, based on either straight line projections or projections that incorporate sliding. Borehole estimator 906 may be used to compensate for a sensor being physically located some distance behind drill bit 148 (e.g., 50 feet) in drill string 146, which makes sensor readings lag the actual bit location by 50 feet. Borehole estimator 906 may also be used to compensate for sensor measurements that may not be continuous (e.g., a sensor measurement may occur every 100 feet). Borehole estimator 906 may provide the most accurate estimate from the surface to the last survey location based on the collection of survey measurements. Also, borehole estimator 906 may take the slide estimate from slide estimator 908 (described below) and extend the slide estimate from the last survey point to a current location of drill bit 148. Using the combination of these two estimates, borehole estimator 906 may provide steering control system 168 with an estimate of the drill bit's location and trajectory angle from which guidance and steering solutions can be derived. An additional metric that can be derived from the borehole estimate is the effective build rate that is achieved throughout the drilling process.

In FIG. 9, slide estimator 908 receives external inputs representing measured depth and differential pressure information, receives internal input from build rate predictor 902, and provides output to borehole estimator 906 and geo modified well planner 904. Slide estimator 908 may be configured to sample toolface orientation, differential pressure, measured depth (MD) incremental movement, MSE, and other sensor feedback to quantify/estimate a deviation vector and progress while sliding.

Traditionally, deviation from the slide would be predicted by a human operator based on experience. The operator would, for example, use a long slide cycle to assess what likely was accomplished during the last slide. However, the results are generally not confirmed until the downhole survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by a distance of the sensor point from the drill bit tip (e.g., approximately 50 feet). Such a response lag may introduce inefficiencies in the slide cycles due to over/under correction of the actual trajectory relative to the planned trajectory.

In GCL 900, using slide estimator 908, each toolface update may be algorithmically merged with the average differential pressure of the period between the previous and current toolface readings, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during the period. As an example, the periodic rate may be between 10 and 60 seconds per cycle depending on the toolface update rate of downhole tool 166. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of slide estimator 908 may accordingly be periodically provided to borehole estimator 906 for accumulation of well deviation information, as well to geo modified well planner 904. Some or all of the output of the slide estimator 908 may be output to an operator, such as shown in the user interface 850 of FIG. 8.

In FIG. 9, error vector calculator 910 may receive internal input from geo modified well planner 904 and borehole estimator 906. Error vector calculator 910 may be configured to compare the planned well trajectory to an actual borehole trajectory and drill bit position estimate. Error vector calculator 910 may provide the metrics used to determine the error (e.g., how far off) the current drill bit position and trajectory are from the drill plan. For example, error vector calculator 910 may calculate the error between the current bit position and trajectory to the planned trajectory and the desired bit position. Error vector calculator 910 may also calculate a projected bit position/projected trajectory representing the future result of a current error.

In FIG. 9, geological drift estimator 912 receives external input representing geological information and provides outputs to geo modified well planner 904, slide planner 914, and tactical solution planner 918. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of ROP and BHA 149. Geological drift estimator 912 is configured to provide a drift estimate as a vector that can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution.

In FIG. 9, slide planner 914 receives internal input from build rate predictor 902, geo modified well planner 904, error vector calculator 910, and geological drift estimator 912, and provides output to convergence planner 916 as well as an estimated time to the next slide. Slide planner 914 may be configured to evaluate a slide/drill ahead cost equation and plan for sliding activity, which may include factoring in BHA wear, expected build rates of current and expected formations, and the drill plan trajectory. During drill ahead, slide planner 914 may attempt to forecast an estimated time of the next slide to aid with planning. For example, if additional lubricants (e.g., fluorinated beads) are indicated for the next slide, and pumping the lubricants into drill string 146 has a lead time of 30 minutes before the slide, the estimated time of the next slide may be calculated and then used to schedule when to start pumping the lubricants. Functionality for a loss circulation material (LCM) planner may be provided as part of slide planner 914 or elsewhere (e.g., as a stand-alone module or as part of another module described herein). The LCM planner functionality may be configured to determine whether additives should be pumped into the borehole based on indications such as flow-in versus flow-back measurements. For example, if drilling through a porous rock formation, fluid being pumped into the borehole may get lost in the rock formation. To address this issue, the LCM planner may control pumping LCM into the borehole to clog up the holes in the porous rock surrounding the borehole to establish a more closed-loop control system for the fluid.

In FIG. 9, slide planner 914 may also look at the current position relative to the next connection. A passageway may happen every 90 to 100 feet (or some other distance or distance range based on the particulars of the drilling operation) and slide planner 914 may avoid planning a slide when close to a passageway or when the slide would carry through the connection. For example, if the slide planner 914 is planning a 50 foot slide but only 20 feet remain until the next connection, slide planner 914 may calculate the slide starting after the next passageway and make any changes to the slide parameters to accommodate waiting to slide until after the next connection. Such flexible implementation avoids inefficiencies that may be caused by starting the slide, stopping for the connection, and then having to reorient the drilling assembly before finishing the slide. During slides, slide planner 914 may provide some feedback as to the progress of achieving the desired goal of the current slide. In some embodiments, slide planner 914 may account for reactive torque in the drill string. More specifically, when rotating is occurring, there is a reactional torque wind up in drill string 146. When the rotating is stopped, drill string 146 unwinds, which changes toolface orientation and other parameters. When rotating is started again, drill string 146 starts to wind back up. Slide planner 914 may account for the reactional torque so that toolface references are maintained, rather than stopping rotation and then trying to adjust to an optimal toolface orientation. While not all downhole tools may provide toolface orientation when rotating, using one that does supply such information for GCL 900 may significantly reduce the transition time from rotating to sliding.

In FIG. 9, convergence planner 916 receives internal inputs from build rate predictor 902, borehole estimator 906, and slide planner 914, and provides output to tactical solution planner 918. Convergence planner 916 is configured to provide a convergence plan when the current drill bit position is not within a defined margin of error of the planned well trajectory. The convergence plan represents a path from the current drill bit position to an achievable and optimal convergence target point along the planned trajectory. The convergence plan may take account the amount of sliding/drilling ahead that has been planned to take place by slide planner 914. Convergence planner 916 may also use BHA orientation information for angle of attack calculations when determining convergence plans as described above with respect to build rate predictor 902. The solution provided by convergence planner 916 defines a new trajectory solution for the current position of drill bit 148. The solution may be immediate without delay, or planned for implementation at a future time that is specified in advance.

In FIG. 9, tactical solution planner 918 receives internal inputs from geological drift estimator 912 and convergence planner 916 and provides external outputs representing information such as toolface orientation, differential pressure, and mud flow rate. Tactical solution planner 918 is configured to take the trajectory solution provided by convergence planner 916 and translate the solution into control parameters that can be used to control drilling rig 210. For example, tactical solution planner 918 may convert the solution into settings for control systems 522, 524, and 526 to accomplish the actual drilling based on the solution. Tactical solution planner 918 may also perform performance optimization to optimizing the overall drilling operation as well as optimizing the drilling itself (e.g., how to drill faster).

Other functionality may be provided by GCL 900 in additional modules or added to an existing module. For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole toolface. Accordingly, GCL 900 may receive information corresponding to the rotational position of the drill pipe on the surface. GCL 900 may use this surface positional information to calculate current and desired toolface orientations. These calculations may then be used to define control parameters for adjusting the top drive 140 to accomplish adjustments to the downhole toolface in order to steer the trajectory of borehole 106.

For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with GCL 900, or other functionality provided by steering control system 168. In GCL 900, a drilling model class may be defined to capture and define the drilling state throughout the drilling process. The drilling model class may include information obtained without delay. The drilling model class may be based on the following components and sub-models: a drill bit model, a borehole model, a rig surface gear model, a mud pump model, a/differential pressure model, a positional/rotary model, an MSE model, an active drill plan, and control limits. The drilling model class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of GCL 900. The drill bit model may represent the current position and state of drill bit 148. The drill bit model may include a three dimensional (3D) position, a drill bit trajectory, BHA information, bit speed, and toolface (e.g., orientation information). The 3D position may be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The drill bit trajectory may be specified as an inclination angle and an azimuth angle. The BHA information may be a set of dimensions defining the active BHA. The borehole model may represent the current path and size of the active borehole. The borehole model may include hole depth information, an array of survey points collected along the borehole path, a gamma log, and borehole diameters. The hole depth information is for current drilling of borehole 106. The borehole diameters may represent the diameters of borehole 106 as drilled over current drilling. The rig surface gear model may represent pipe length, block height, and other models, such as the mud pump model, WOB/differential pressure model, positional/rotary model, and MSE model. The mud pump model represents mud pump equipment and includes flow rate, standpipe pressure, and differential pressure. The WOB/differential pressure model represents draw works or other WOB/differential pressure controls and parameters, including WOB. The positional/rotary model represents top drive or other positional/rotary controls and parameters including rotary RPM and spindle position. The active drill plan represents the target borehole path and may include an external drill plan and a modified drill plan. The control limits represent defined parameters that may be set as maximums and/or minimums. For example, control limits may be set for the rotary RPM in the top drive model to limit the maximum RPMs to the defined level. The control output solution may represent the control parameters for drilling rig 210.

Each functional module of GCL 900 may have behavior encapsulated within a respective class definition. During a processing window, the individual functional modules may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the functional modules may be in the sequence of geo modified well planner 904, build rate predictor 902, slide estimator 908, borehole estimator 906, error vector calculator 910, slide planner 914, convergence planner 916, geological drift estimator 912, and tactical solution planner 918. It is noted that other sequences may be used in different implementations.

In FIG. 9, GCL 900 may rely on a programmable timer module that provides a timing mechanism to provide timer event signals to drive the main processing loop. While steering control system 168 may rely on timer and date calls driven by the programming environment, timing may be obtained from other sources than system time. In situations where it may be advantageous to manipulate the clock (e.g., for evaluation and testing), a programmable timer module may be used to alter the system time. For example, the programmable timer module may enable a default time set to the system time and a time scale of 1.0, may enable the system time of steering control system 168 to be manually set, may enable the time scale relative to the system time to be modified, or may enable periodic event time requests scaled to a requested time scale.

Referring now to FIG. 10, a block diagram illustrating selected elements of an embodiment of a controller 1000 for performing steering methods and systems for improved drilling performance according to the present disclosure. In various embodiments, controller 1000 may represent an implementation of steering control system 168. In other embodiments, at least certain portions of controller 1000 may be used for control systems 510, 512, 514, 522, 524, and 526 (see FIG. 5).

In the embodiment depicted in FIG. 10, controller 1000 includes processor 1001 coupled via shared bus 1002 to storage media collectively identified as memory media 1010.

Controller 1000, as depicted in FIG. 10, further includes network adapter 1020 that interfaces controller 1000 to a network (not shown in FIG. 10). In embodiments suitable for use with user interfaces, controller 1000, as depicted in FIG. 10, may include peripheral adapter 1006, which provides connectivity for the use of input device 1008 and output device 1009. Input device 1008 may represent a device for user input, such as a keyboard or a mouse, or even a video camera. Output device 1009 may represent a device for providing signals or indications to a user, such as loudspeakers for generating audio signals.

Controller 1000 is shown in FIG. 10 including display adapter 1004 and further includes a display device 1005. Display adapter 1004 may interface shared bus 1002, or another bus, with an output port for one or more display devices, such as display device 1005. Display device 1005 may be implemented as a liquid crystal display screen, a computer monitor, a television, or the like. Display device 1005 may comply with a display standard for the corresponding type of display. Standards for computer monitors include analog standards such as video graphics array (VGA), extended graphics array (XGA), etc., or digital standards such as digital visual interface (DVI), definition multimedia interface (HDMI), among others. A television display may comply with standards such as NTSC (National Television System Committee), PAL (Phase Alternating Line), or another suitable standard. Display device 1005 may include an output device 1009, such as one or more integrated speakers to play audio content, or may include an input device 1008, such as a microphone or video camera.

In FIG. 10, memory media 1010 encompasses persistent and volatile media, fixed and removable media, and magnetic and semiconductor media. Memory media 1010 is operable to store instructions, data, or both. Memory media 1010 as shown includes sets or sequences of instructions 1024-2, namely, an operating system 1012 and steering control 1014. Operating system 1012 may be a UNIX or UNIX-like operating system, a Windows® family operating system, or another suitable operating system. Instructions 1024 may also reside, completely or at least partially, within processor 1001 during execution thereof. It is further noted that processor 1001 may be configured to receive instructions 1024-1 from instructions 1024-2 via shared bus 1002. In some embodiments, memory media 1010 is configured to store and provide executable instructions for executing GCL 900, as mentioned previously, among other methods and operations disclosed herein.

As noted previously, steering control system 168 may support the display and operation of various user interfaces, such as in a client/server architecture. For example, steering control 1014 may be enabled to support a web server for providing the user interface to a web browser client, such as on a mobile device or on a personal computer device. In another example, steering control 1014 may be enabled to support an app server for providing the user interface to a client app, such as on a mobile device or on a personal computer device. It is noted that in the web server or the app server architecture, surface steering control 1014 may handle various communications to rig controls 520 while simultaneously supporting the web browser client or the client app with the user interface.

Downhole Kelly and Toolface Anchor

Some of the biggest challenges in conventional drilling in a lateral section of a directional well include toolface control, rate of penetration (ROP) control, and cost. A downhole drilling tool according to the present technology and/or toolface anchor may address all three issues. A downhole kelly and/or toolface anchor according to the present technology may not require a heavy weight, such as a heavy drill pipe, and may also exhibit less friction, resulting in faster drilling. A downhole kelly and/or toolface anchor according to the present technology may maintain a set toolface when sliding, regardless of weight on bit, and may maintain a set ROP when sliding or rotating. In traditional assemblies, reactional torque on the drill face can cause swinging of the drill bit, and therefore challenging or limited toolface control during drilling operation. In addition, long lateral sections (e.g., 20,000 feet-40,000 feet) can be challenging to maintain sufficient weight-on-bit to push the drill pipe laterally.

In embodiments, a downhole kelly and/or toolface anchor according to the present technology may allow for grippers to expand to grip the borehole inside wall when sliding. In embodiments of a downhole kelly, when a section of the drill string advances through rollers, during sliding, the toolface may be forced to stay constant. In embodiments, a downhole kelly and/or toolface anchor according to the present technology may perform an “inchworm” or “corkscrew” type function that can maintain force on the bit through long lateral sections of the well, or even when drilling uphill. Conversely, typical kelly tools may be merely utilized to provide rotary motion, and force on bit may only be provided by the weight on bit, such as the drill pipe. This is advantageous, as deep drilling operations may exhibit increased friction due to excessive drill pipe weight and length, reducing the torque provided and causing vibrations that reduce the accuracy and economy of drilling. In addition, as existing methods are reliant upon weight on bit, uphill drilling has thus far been problematic. Thus, the present technology may address one or more of these issues by providing a low friction and/or low vibration solution that is uniquely situated for lateral or uphill drilling.

In embodiments, a locking mechanism, which may be activated electronically or by pressure, can be used to lock one or more splines and the kelly section or one or more splines and/or the helix section of the downhole kelly tool according to the present technology. Such an orientation may allow the downhole kelly tool sections to selectively lock and unlock from each other. An indexer can be activated by pressure cycling. For instance, pressure cycling may provide for the downhole kelly assembly to sequence by 5-20 degrees, as an example, to set the tool face without rotating the drill string.

As discussed above, the downhole kelly assembly and/or toolface anchor discussed herein may achieve excellent weight on bit with minimal or no heavy weight drill pipe. Furthermore, assemblies discussed herein may accurately and securely anchor a toolface during a slide.

FIG. 11 illustrates a profile cutaway view of a drilling tool 1100, which may be a downhole kelly in embodiments, according to embodiments of the present technology. While a drilling tool 1100 may be incorporated in any one or more of the drilling systems discussed above in a variety of locations, in embodiments, the drilling tool 1100 may be disposed on a drill string, such as drill string 146, between a surface of the ground and the drill bit, such as drill bit 148 (e.g., may be attached to drill string 146 and to drill bit 148). In embodiments, the drilling tool 1100 may be disposed on or around a portion of the drill string adjacent to the downhole tool, allowing compressive force to be applied to the drill bit 148. The drilling tool 1100 has a proximal end 1102 and distal end 1104. A sleeve 1106, which may be cylindrical in embodiments, is disposed within an inner volume defined by opposed interior surfaces 1109 of the drilling tool 1100, allowing the sleeve 1106 to travel linearly inside the inner volume of drilling tool 1100. The drilling tool 1100 can include an internal threaded section 1108 proximal the distal end 1104 of the drilling tool 1100. However, in embodiments, other linear movement mechanisms may be utilized, such as ball bearings, and the like. Alternatively, the drilling tool 1100 may be attached to BHA 149 at one end and to drill bit 148 at a second end, and/or to drill string 146 at one end and to BHA 149 at the other end. While not shown in the figures, it should be understood that, in embodiments, one or more of the drilling tools discussed herein may be disposed between the drill bit and the BHA.

The exterior surface 1110 of the drilling tool 1100 can include a gripper apparatus 1112. The gripper apparatus 1112 may be affixed to the exterior surface 1110 of a portion of the drilling tool 1100 or may be unitarily formed with a portion of the exterior surface 1110 of the drilling tool 1100. The gripper apparatus 1112 can be configured to selectively extend outward of the exterior surface (e.g. laterally away from a longitudinal axis of the drilling tool, which may be a radial direction if the interior volume is cylindrical), increasing an outer diameter of the portion of the drilling tool 1100, and to selectively retract to a position flush with, or recessed into, exterior surface 1110, decreasing the outer diameter of the portion of the drilling tool 1100. The gripper apparatus 1112 can include a plurality of gripper pads 1113 that protrude from the outer surface of the gripper apparatus 1112 and engage with an inner surface of the borehole during drilling. In various embodiments, the gripper apparatus 1112 can include a plurality of teeth 1114 (e.g., spikes) mounted on, or formed unitarily with gripper pads 1113, that may engage with an interior surface of a borehole during drilling.

In embodiments, gripper apparatus 1112 may extend outwardly from a longitudinal axis of the drilling tool 1100 when pressure increases within drilling tool 1100, such as when drilling mud flows through the drilling tool 1100. In embodiments, the gripper apparatus 1112 may retract inwardly towards a longitudinal axis of the drilling tool 1100 when pressure decreases, such as when drilling mud is not flowing through the drilling tool 1100. However, it should be clear that other methods of changing pressure may be utilized to extend and retract gripper apparatus 1112. The gripper apparatus 1112 can set (e.g. engage an inner surface of the borehole), retract (e.g. disengage from an inner surface of the borehole), and reset as the drill bit makes progress drilling the well. This function can allow both accurate toolface control and consistent weight on bit when drilling lateral sections. Furthermore, the drilling tool 1100 according to the present technology may provide for increased control and consistent weight on bit when drilling downhole or laterally, even when the weight of the drill pipe is maintained or decreased from conventional methods.

In embodiments, sleeve 1106 may contain one or more external threads 1107 extending from at least a portion of an outer surface of the cylindrical sleeve 1106. External threads 1107 may engage with the internal threaded section 1108, allowing linear movement of sleeve 1106 within drilling tool 1100. However, in embodiments, as discussed above, the internal threaded section and/or threads may instead be other mated movement mechanisms, such as a ball bearing, or the like.

In embodiments, drilling tool 1100 can include an inner bearing section 1116 inside a portion of the cylindrical sleeve 1106. In the context of a drill pipe tool, an inner bearing section 1116 typically refers to a component or components used to support and facilitate the rotational movement of the drill pipe. The inner bearing may serve to disconnect the rotary action of the drill string above from the drilling assembly below. When the inner bearing is clear of the outer bearing (such as outer bearing 1118 discussed below), the kelly section can be engaged and the drill bit locked to provide a thread driven equivalent of slide drilling. When the inner bearing sits within the outer bearing section 1118, the drill string and the drilling assembly rotate together and the kelly is clear of its rollers to provide a thread driven equivalent of rotary drilling. The engaged position and rotating position can be alternately set, such as by a helical index, as well as other engagement mechanisms as known in the art.

The inner bearing section 1116 can be designed to reduce friction and wear between the rotating components of the tool, allowing smooth rotation and transfer of torque from the drill string to the drilling bit. The inner bearing section 1116 can perform various functions, including load distribution, friction reduction, smooth rotation of the tool, and axial support for the cylindrical sleeve 1106. The inner bearing section 1116 can help distribute the load and torque applied to the drill pipe evenly throughout the drilling tool 1100, reducing stress concentration and potential damage to the drilling tool 1100. Furthermore, inner bearing section 1116 may also allow for forces from the drill pipe and/or drill sting to be transmitted efficiently through the drilling tool 1100.

In embodiments, inner bearing section 1116 may include rolling element bearings, such as ball bearings or roller bearings as examples. Rolling element bearings may allow the inner bearing to minimize friction between the rotating components. This can help to reduce heat generation and wear, thus improving the overall efficiency and lifespan of the drilling tool 1100.

Regardless of the type of bearing selected, inner bearing section 1116 can provide a low-friction surface that allows the drill pipe to rotate smoothly within the tool. This smooth rotational movement allows for improved, efficient, and effective drilling operations, as it provides for the transfer of torque from the drilling rig to the drill bit. In addition to supporting the rotational movement, the inner bearing section 1116 may also provide axial support to the drill pipe. For instance, the inner bearing section 1116 may aid in maintaining proper alignment of the drilling tool 1100 in relation to the drill string and/or drill pipe and prevents excessive axial movement of the pipe, improving stability during drilling operations. In embodiments, an inner bearing section 1116 in a drill pipe tool may facilitating smooth rotation, reducing friction, and supporting the drill pipe. Thus, an inner bearing section 116 may contribute to the efficiency, durability, and reliability of the drilling equipment, improving effective drilling operations in various applications, such as oil and gas exploration, mining, and construction.

In various embodiments, the drilling tool 1100 can include an outer bearing section 1118. The outer bearing section 1118 can be permanently or releasably affixed between the exterior surface 1110 and an interior surface 1109 of the drilling tool 1100. The outer bearing section 1118 can lock an upper portion of the drill string to a lower portion of the drill string. The outer bearing section 1118 can perform many of the same functions as the inner bearing section 1116 to include load distribution, friction reduction, smooth rotation of the tool, and axial support as described above, for the sleeve 1106. In embodiments, a drill bit can be attached to internal threaded section 1108 at proximal end 1104 the cylindrical sleeve 1106.

In embodiments, the drilling tool 1100 can include a kelly section 1120. In embodiments, kelly section 1120 may connect to a drill pipe at a proximal end 1102 of the drilling tool. In traditional drilling operations, a kelly typically refers to a square or hexagonal steel pipe that is used to transmit rotational motion from the rotary table to the drill string during drilling. The kelly section 1120 according to the present technology can be connected to the top drive or rotary table and may be responsible for transferring torque to the drill string, allowing the drilling bit to rotate and penetrate the earth's surface.

The illustrated drilling tool 1100 in FIG. 11 includes five main sections, but may include more or less based upon the desired application or drilling circumstances. The sections can include a internal threaded section, an inner bearing section, a gripper section, and outer bearing section, and a kelly section. These sections can be various lengths.

In various embodiments, the drilling tool 1100 can include a threaded section that is from about 2 feet to about 12 feet in length (e.g., moving from a proximal end towards a distal end of the respective section), such as greater than or about 3 feet, such as greater than or about 4 feet, such as greater than or about 5 feet, such as greater than or about 6 feet, such as greater than or about 7 feet, such as greater than or about 8 feet, such as greater than or about 9 feet, such as greater than or about 10 feet, such as less than or about 12 feet, such as less than or about 11 feet, such as less than or about 10 feet, such as less than or about 9 feet, such as less than or about 8 feet, or any ranges or values therebetween. However, it should be acknowledged that the length of any section or of the drilling tool 1100 may vary based upon the desired drilling application, length of borehole, and the like.

Nonetheless, in embodiments, a gripper section is from about 2 feet to about 12 feet in length (e.g., moving from a proximal end towards a distal end of the respective section), such as greater than or about 3 feet, such as greater than or about 4 feet, such as greater than or about 5 feet, such as greater than or about 6 feet, such as greater than or about 7 feet, such as greater than or about 8 feet, such as greater than or about 9 feet, such as greater than or about 10 feet, such as less than or about 12 feet, such as less than or about 11 feet, such as less than or about 10 feet, such as less than or about 9 feet, such as less than or about 8 feet, or any ranges or values therebetween.

In embodiments, an inner bearing section may be from about 1 foot to about 8 feet in length (e.g., moving from a proximal end towards a distal end of the respective section), such as greater than or about 2 feet, such as greater than or about 3 feet, such as greater than or about 4 feet, such as greater than or about 5 feet, such as greater than or about 6 feet, such as less than or about 8 feet, such as less than or about 7 feet, such as less than or about 6 feet, such as less than or about 5 feet, such as less than or about 4 feet, or any ranges or values therebetween.

An outer bearing section may be from about 1 foot to about 8 feet in length (e.g., moving from a proximal end towards a distal end of the respective section), such as greater than or about 2 feet, such as greater than or about 3 feet, such as greater than or about 4 feet, such as greater than or about 5 feet, such as greater than or about 6 feet, such as less than or about 8 feet, such as less than or about 7 feet, such as less than or about 6 feet, such as less than or about 5 feet, such as less than or about 4 feet, or any ranges or values therebetween.

Furthermore, in embodiments, a kelly section may be from about 1 foot to about 8 feet in length (e.g., moving from a proximal end towards a distal end of the respective section), such as greater than or about 2 feet, such as greater than or about 3 feet, such as greater than or about 4 feet, such as greater than or about 5 feet, such as greater than or about 6 feet, such as less than or about 8 feet, such as less than or about 7 feet, such as less than or about 6 feet, such as less than or about 5 feet, such as less than or about 4 feet, or any ranges or values therebetween.

In embodiments, an overall length of drilling tool 1100 may be from about 20 feet to about 60 feet in length (e.g., from the proximal end to the distal end), such as greater than or about 22 feet, such as greater than or about 24 feet, such as greater than or about 26 feet, such as greater than or about 28 feet, such as greater than or about 30 feet, such as greater than or about 32 feet, such as greater than or about 34 feet, such as greater than or about 36 feet, such as less than or about 55 feet, such as less than or about 50 feet, such as less than or about 45 feet, such as less than or about 40 feet, such as less than or about 35 feet, such as less than or about 30 feet, or any ranges or values therebetween. However, it should be acknowledged that the length of any section or of the drilling tool 1100 may vary based upon the desired drilling application, length of borehole, and the like.

In embodiments, while the gripper section 1112 of the inner sleeve 1106 may have various cross-sectional shapes, such as hexagonal, square, triangular, and the like, the gripper section 1112 may be generally hexagonal. Furthermore, the remaining sections may have various cross-sectional shapes, such as hexagonal, square, triangular, circular, and the like, but the exterior surface 1110 of the remaining sections may have a generally circular cross-sectional shape.

FIGS. 12A and 12B illustrates a cutaway view of a gripper apparatus 1112 according to one or more embodiments of the present technology. In embodiments, the gripper apparatus 1112 may correspond to a gripper apparatus 1112 of FIG. 11, but should be understood that the gripper apparatus of FIGS. 12A and 12B may be utilized with other drilling tools discussed herein.

As shown in FIG. 12A the gripper apparatus 1112 can include a plurality of gripper pads 1113. The gripper apparatus 1112 can include a frame 1202 that encloses a diffuser ring 1208 and seats each of the gripper pads 1113. The gripper pads 1113 can have a plurality of teeth 1114 that can hold the gripper apparatus 1112 in place in the borehole. When pumps are operating during drilling, drilling mud can travel down through the drill pipe and through a diffuser ring 1208. The drilling mud may apply pressure on the interior surface of the gripper pads 1113. However, as discussed above, pressure may be increased or decreased within the gripper apparatus 112 by various methods as known in the art. The pressure within the gripper apparatus 1112 can cause the gripper pads 1113 to extend outwards from the longitudinal axis of drilling tool 1100 and engage with an inside surface of the borehole. This allows the gripper apparatus 1112 to anchor the drilling tool to the borehole, which may reduce effects (e.g., swinging) of the bit due to reactional torque from drilling. Cycling the mud pump motor in a particular sequence can be used to change mode (e.g., anchored or not) of the downhole drilling tool.

For instance, FIG. 12B illustrates a cutaway view of the gripper apparatus 1112 of FIG. 11 in a released orientation (e.g. reduced or low pressure within the apparatus). When the mud pumps are not running, the pressure relaxes on the interior surface of the gripper pads 1113. In various embodiments, springs 1115 can cause the gripper pads 1113 to retract thereby reducing the outer diameter of the gripper apparatus 1112. However, other release mechanisms in the art may be utilized, such pressure release and the like. In embodiments, the released orientation may seat the gripper pads 1113 below a shoulder 1204 of frame 1202. Thus, the gripper pads 1113 may reduce an overall diameter of the gripper apparatus 1112, and instead allow a smooth shoulder 1204 to contact the inside surface of the borehole, or slide past. By repeating the process of anchoring, drilling, releasing forward, and anchoring again, the drilling tool 1100 can travel down the borehole (e.g. by drilling and extending), until a new location is selected to impart weight on bit.

FIG. 13 illustrates an exemplary threaded section 1108 and an exemplary threaded sleeve 1106 according to one or more embodiments of the present technology. In embodiments, the threaded section 1108 may correspond to a threaded section 1108 of FIG. 11, but should be understood that the threaded section of FIG. 13 may be utilized with other drilling tools discussed herein The threaded sleeve 1106 can fit within the threaded section 1108 and can extend through the threaded section 1108 by turning the threaded sleeve 1106. Various sizes threads can be used.

The threaded sleeve 1106 can include pressure plates 1302. Pressure plates 1302 may be utilized to distribute and exert pressure on the threaded sleeve 1106. Threaded sleeves 1106, also known as threaded inserts or threaded bushings, are cylindrical metal fasteners with internal threads or external threads. Pressure plates 1302 for threaded sleeves 1106 may be utilized to apply compressive force onto the sleeve, securing it firmly in place within the drilling tool. Pressure plates 1302 may aid in securing proper engagement of the internal threads of the sleeve with the external threads of a mating fastener, such as a bolt or screw (e.g. threaded section of a drilling tool). The pressure plates 1302 may be formed from metal, such as steel or brass, to provide strength and durability, but may be formed from other durable materials as known in the art. When utilized, sidewalls of pressure plates 1302 may be flat or slightly curved with a central diameter that matches the outer diameter of the threaded sleeve. Thus, in embodiments, pressure plates 1302 for threaded sleeves may aid in the secure installation and retention of threaded sleeves by applying pressure and distributing forces evenly.

FIG. 14 illustrates an exemplary threaded sleeve disposed within an exemplary threaded section of a drilling tool, such as drilling tool 1100 as discussed above, but may be utilized in other drilling tools discussed herein. As shown in FIG. 11, the cylindrical threaded sleeve 1106 can be connected to the drill string at the elly section 1120 providing the drill string with the freedom to rotate independently. A drill bit can be attached to a distal end 1104 of the threaded sleeve 1106. The rotation of the drill string allows for advancement of the threaded sleeve 1106, such as by rotating the threaded section through the threaded sleeve. In various embodiments, this can allow the drill bit to maintain weight on bit for an extended reach well (e.g. a well with one or more sections, lateral, uphill, or otherwise, of 10,000 feet or more, 20,000 feet or more, 30,000 feet or more, 40,000 feet or more, or any ranges or values therebetween) including lateral drilling. As the threaded sleeve 1106 with drill bit attached approaches the distal end, the gripper apparatus 1112 can release the pressure on the gripper pads, such as by releasing the pressure within the internal volume as discussed herein, and the entire drilling tool 1100 can advance in the borehole (e.g. towards the distal end/drill bit). For instance, the compressed spring, may urge the assembly forward as, or after, the grippers and threads retract to a relaxed first state, due at least in part to the decrease in pressure, as discussed in greater detail below. When no pressure is present, such as due to not rotation from the drill string or mud flowing, the assembly may be in a fully retracted orientation, such that the entire assembly may be withdrawn from the wellbore.

FIG. 15 illustrates an exemplary kelly section 1120 of a drilling tool 1100 according to the present technology. In embodiments, the kelly section may be utilized, such as in drilling tool 1100, or with any other drilling tools discussed herein. The kelly section 1120 can include a plurality of rollers 1502 along the outside of the kelly structure 1504. The kelly structure may be hexagon shaped in some embodiments, but may have any one or more of the cross-sectional shapes discussed above.

FIGS. 16A and 16B illustrate a gripping mechanism 1600 that can be used in addition to, or alternatively to, a threaded section, such as threaded section 1108 of a drilling tool according to the present technology, such as drilling tool 1100. The gripping mechanism 1600 can include an outer casing 1602 and an inner casing 1604. A spring 1606 may be disposed within outer casing 1602 with a proximal end 1601 of the spring 1606 attached to or disposed against an inside surface of the outer casing 1602 and the distal end 1603 of the spring 1606 attached to or disposed against an outside surface of the inner casing 1604. The spring 1606 can apply a force against the inner casing 1604 sliding or otherwise moving the inner casing inside the outer casing 1602 towards a distal end 1605 of the outer casing 1602.

The inner casing 1604 can include a plurality of inner recesses 1608 and a plurality of exterior recesses 1609. The inner recesses 1608 may be located along an interior side of the inner casing 1604, and the exterior recesses 1609 may be located on an exterior side of the inner casing 1604. The outer casing can include outer recesses 1610 that may be located along an exterior side of the outer casing 1602, and interior recesses 1611 that may be located along an interior side of the outer casing 1602. The inner recesses 1608 and the interior recesses 1611, and the outer recesses 1610 and the exterior recesses 1609 may align when in a compressed orientation, to allow a spring-loaded locking pin 1612 to pass through the inner recess 1608 and interior recess 1611, and the outer recess 1610 and exterior recesses 1609. The spring-loaded locking pin 1612 may allow the spring force to engage the locking-pin 1612 such that the locking pin 1612 may exit the inner casing 1604, and extend through one or more recesses in outer casing 1602. The inner casing 1604 can include a plurality of spring-loaded locking pins 1612.

FIG. 16A illustrates an expanded or relaxed first state of the gripping mechanism 1600. In a first state of the gripping mechanism 1600, the spring-loaded locking pin 1612 can pass through an inner recess 1608 but does not pass through an outer recess 1610, as the inner recess 1608 and the outer recess 1610 are not aligned. Therefore, for the first state the spring-loaded locking pins 1612 do not exit the outer casing 1602, and allow the drilling tool to move in the direction of drilling.

FIG. 16B illustrates a compressed or pressurized second state of the gripping mechanism 1600. In the second state, the inner recess 1608 and outer recess 1610 may be aligned such that the spring-loaded locking pin 1612 can pass through the inner recess 1608 and the interior recess 1611 and engage with the teeth of the threaded section 1108. In addition, spring-loaded locking pin 1612 may also pass through exterior recess 1609 and outer recesses 1610, allowing the spring-loaded locking pins to engage the interior surface of the bore hole. Thus, the gripping mechanism 1600 may provide for locking the threaded sleeve and fixing the gripping mechanism 1600 in a position in the borehole. When sufficient pressure is applied, within the interior volume 1614 of inner casing 1604, such as by drilling mud, or other applied pressure, such as rotation from the drilling string, release valves 1616 and 1618 may align, releasing the pressure in the interior volume 1614. When the pressure is released, the spring-loaded locking pins may disengage, and re-set to the first state, allowing the inner casing 1604 to slide relative to the outer casing 1602, and move the drilling tool down borehole.

Other techniques can be employed to fix the gripper assembly and/or drilling tool assembly in place during drilling, as may be discussed in greater detail below. For example, a ball race, cylinder roller race, or elliptical roller race may all be used for to fix the gripper assembly in place when engaged. Linear bearings are mechanical components designed to provide smooth, low-friction motion along a linear path while supporting and holding a device stationary. They can be used in various applications, such as in industrial machinery, automation systems, 3D printers, CNC machines, and more. Linear bearings can be used for ensuring precision, stability, and durability in these systems.

Linear bearings generally include two main parts: the outer housing and the inner carriage. The inner carriage is the moving part that carries the load, while the housing provides the support and guidance for the carriage. Both parts have smooth, flat surfaces that come into contact with each other. Linear bearings incorporate rolling elements that facilitate smooth motion and reduce friction. The most common types of rolling elements used in linear bearings are balls or rollers. These elements are located between the sliding surfaces of the carriage and housing, allowing the carriage to move smoothly along the linear path. To further reduce friction and ensure smooth movement, linear bearings are often lubricated. Lubrication helps in minimizing wear and prolonging the life of the bearing. Linear bearings usually have a retaining mechanism to keep the rolling elements in place. This prevents the balls or rollers from falling out of position, ensuring stability during operation.

When a linear bearing is used to hold a device stationary, it relies on the principle of static friction. Static friction is the force that opposes the motion of an object at rest relative to another surface. In this case, the device resting on the carriage creates a static frictional force between the carriage's sliding surfaces and the device itself. As long as the applied force or load on the device is within the static frictional limit, the device will remain stationary, and the carriage won't move. Linear bearings are designed to handle both radial and axial loads, which means they can support forces applied in both vertical and horizontal directions. Proper selection of linear bearings based on the load, speed, and environmental conditions is essential to ensure the device's stability and efficient operation. Additionally, regular maintenance, including lubrication and periodic inspections, can help maintain the performance and longevity of the linear bearing system.

A ball race, commonly known as a ball bearing, is a type of rolling element bearing that facilitates smooth motion and reduces friction between moving parts. While ball bearings are often used to enable rotational motion, they can also be used to hold a device stationary. The principle behind how a ball bearing holds a device stationary is similar to that of a linear bearing but applied to rotational motion. A ball bearing generally includes an outer ring (also called the outer race), an inner ring (inner race), a set of steel balls, and a cage (retainer) that keeps the balls separated and evenly spaced. The inner and outer rings have smooth surfaces that allow them to rotate relative to each other. The steel balls inside the ball bearing serve as the rolling elements. These balls have very low friction when they come into contact with the smooth raceways (grooves) of the inner and outer rings.

When a radial load (a force applied perpendicular to the axis of rotation) is applied to the inner ring of the ball bearing, the balls in the raceways roll smoothly along the grooves. This rolling action distributes the load evenly across the balls and the raceways, reducing the friction between the moving parts. Just like in linear bearings, ball bearings rely on static friction to hold a device stationary. If the applied radial load is within the static frictional limit, the device will remain stationary, and the inner ring will not rotate. If the device's applied force exceeds the static frictional limit or the rotational speed becomes too high, known as limiting speed, the ball bearing may start to overcome the static friction and initiate rotation. Ball bearings are widely used in various applications where rotational motion is required, such as in machinery, motors, wheels, and more. When used to hold a device stationary, the load-bearing capacity and static frictional limits of the ball bearing need to be considered to ensure the device remains in a fixed position. If a device requires both rotational and axial (thrust) motion while maintaining stability, a combination of different bearing types, such as thrust bearings, may be used to meet the specific requirements of the application.

FIG. 17 illustrates an alternative to internal threaded section 1108, which may include a ball screw system 1702. It should be understood that the internal threaded section 1108 may therefore include any one or more bearings or linear drive mechanisms discussed herein, as the internal threaded section 1108 and ball screw system 1702 may be illustrative examples. A ball screw system 1702 is a mechanical component used in various applications to convert rotary motion into linear motion or vice versa with high precision and efficiency. The ball screw system 1702 can include three main components: a threaded shaft (screw), a nut with ball bearings, and the supporting bearings or guides.

The threaded shaft may contain helical grooves cut into its surface, creating a spiral path. These grooves are designed to match the profile of the ball bearings in the nut. The nut may contain a set of ball bearings that fit into the helical grooves of the threaded shaft. These ball bearings serve as the rolling elements, enabling smooth and low-friction movement along the screw when the screw rotates. The ball screw assembly may typically be supported by bearings or guides on both ends. These bearings ensure stability and proper alignment, allowing the screw and nut to move smoothly without excessive play.

When the threaded shaft (screw) is rotated using a motor or any other source of rotational motion (such as rotation of the drill string herein), the ball bearings in the nut move along the helical grooves, causing the nut to move linearly along the length of the screw. This linear motion is highly precise and can be controlled accurately, making ball screw systems suitable for applications where precision and repeatability are essential.

Ball screw systems can be used in various industrial and manufacturing applications, including CNC (Computer Numerical Control) machinery, robotics, aerospace equipment, semiconductor manufacturing, medical devices, and more. They offer advantages such as high efficiency, low friction, reduced backlash (play), and the ability to handle heavy loads while maintaining accurate positioning.

A ball screw system 1702 can include a ball return tube 1706 that is configured to recirculate balls 1708 above ball nut outside diameter. The ball screw system 1702 can include a ball screw 1710 that the ball nut 1712 can travel on. The ball screw system 1702 can include integral lead shift 1714. The ball screw system 1702 can include a ball wiper 1716 that can remove drilling fluids and rocks sediment from the ball screw system 1702.

FIG. 18 illustrates a toolface anchor 1800 that can be used in addition to, or alternatively to, a threaded section, such as threaded section 1108 of a drilling tool according to the present technology, such as drilling tool 1100. However, in embodiments, the toolface anchor 1800 may not require the use of a downhole kelly, and may form all or a part of a drilling tool. The toolface anchor 1800 can include an outer casing 1802 and an inner casing 1804. A spring 1806 may be disposed within outer casing 1802 with a proximal end 1801 of the spring 1806 attached to or disposed against an inside surface of a proximal end 1826 of the outer casing 1802 and the distal end 1803 of the spring 1806 attached to or disposed against an outside surface of the inner casing 1804. The spring 1806 can apply a force against the inner casing 1804 sliding or otherwise moving the inner casing inside the outer casing 1802 towards a distal end 1805 of the outer casing 1802.

The inner casing 1804 can include a plurality of inner recesses 1808 and a plurality of exterior recesses 1809. The inner recesses 1808 may be located along an interior side of the inner casing 1804, and the exterior recesses 1809 may be located on an exterior side of the inner casing 1804. The outer casing can include outer recesses 1810 that may be located along an exterior side of the outer casing 1802, and interior recesses 1811 that may be located along an interior side of the outer casing 1602. The inner recesses 1808 and the interior recesses 1811, may align when in a compressed orientation, to allow an engagement section (e.g. ball bearings 1813 in the illustrated embodiment) of engagement mechanism 1812 to engage with a complementary engagement track 1815, on sleeve 1108.

In embodiments, the engagement mechanism may have a first arm 1821 adjacent to inner recesses 1808, and a second arm 1820 extending through outer recesses 1810 and exterior recesses 1809. In embodiments, the first arm 1821 may engage, or cause an engagement section, to engage with the complementary engagement track 1815, by urging the engagement section (illustrated as a ball bearing in the illustrated embodiment), through outer recess 1810 and into engagement with the complementary engagement track 1815. It should be understood that the engagement mechanism and/or engagement track may include any one or more linear bearings discussed above, as well as other fixture mechanisms. In embodiments, the first arm may include a first arm spring 1821a and the second arm may include a second arm spring 1820a, which may aid in return of the engagement section and/or gripper foot to a first orientation. In the illustrated embodiment, an engagement mechanism may include a spring engaged ball bearing and a complementary ball track or return, such that ball bearings 1813 to engage bearing track 1815. However, it should be clear that engagement mechanism 1812 may also include one or more of the alternative linear movement mechanisms discussed herein. The engagement mechanism 1812 may allow the spring force to engage the ball 1813 in the illustrated embodiment, such that ball 1813 may access ball track 1815, providing for movement of the inner casing 1804 relative to outer casing 1802.

FIG. 18A illustrates an expanded or relaxed first state of the toolface anchor 1800. In a first state of the toolface anchor 1800, the engagement mechanism can pass through an inner recess 1808 but does not pass through an outer recess 1810, as the inner recess 1808 and the outer recess 1810 are not aligned. Therefore, for the first state the engagement mechanism does not exit the outer casing 1802 and therefore does not engage the ball track 1815, and allow the drilling tool to move in the direction of drilling.

FIG. 18B illustrates a compressed or pressurized second state of the toolface anchor 1800. In the second state, the inner recess 1808 and outer recess 1810 may be aligned such that the engagement mechanism 1812 can pass through the inner recess 1808 and the interior recess 1811 and engage with the ball race or return 1815 of a threaded section, such as the threaded section 1108, in embodiments used in conjunction with a drilling tool 1100.

In addition, the engagement mechanism may also extend laterally outward, engaging second arms 1820, and extending second arms 1820 through exterior recess 1809 and outer recesses 1810. In such a manner, second arms 1820 may extend gripper foot 1822 laterally outward, engaging gripper foot 1822 with the interior surface of the bore hole. Thus, the toolface anchor 1800 may provide for locking the threaded sleeve and fixing the gripping mechanism 1812 in a position in the borehole, which may be simultaneous or sequential. When sufficient pressure is applied within the interior volume 1814 of inner casing 1804, such as by rotation from the drilling string, or other methods discussed herein, release valves 1816 and 1818 may align, releasing the pressure in the interior volume 1814. When the pressure is released, the engagement mechanism may disengage, and re-set to the first state, allowing the inner casing 1804 to slide relative to the outer casing 1802, and move the drilling tool down borehole. In embodiments, the toolface anchor 1800 may be formed as a unitary body, or may be formed from one or more components.

While FIGS. 18A and 18B are shown in a longitudinal cross-section, it should be clear that the cross-sectional shape of the toolface anchor 1800 may include any one or more cross-sectional shapes as discussed above, and may have a similar cross-sectional shape, and shoulder orientation, to gripper apparatus 1112, as an example only. Thus, in embodiments, toolface anchor 1800 may include two or more gripper feet 1822 extended around toolface anchor 1800 (which may be circumferentially disposed if a circular or hexagonal cross-sectional shape is utilized), such as three or more feet, such as four or more feet, such as five or more feet, or more. In addition, while gripper foot 1822 is shown as being a continuous piece, it should be understood that gripper foot 1822 may be two or more pieces when extending from the proximate end 1826 to distal end 1805 of toolface anchor 1800. For instance, there may be one gripper foot 1822 for each second arm 1820, for every two second arms 1820, or the like.

Surprisingly, the pressure, and therefore weight on bit and drill speed may be controlled by rotation of the drill string, in embodiments. For instance, by increasing the revolutions per minute of the drill string, pressure may be transferred through a drill pipe, which may be in fluid contact with outer casing 1602/1802, to the toolface anchor 1800 (or one or more grippers as discussed above) and increased more quickly, applying increased pressure and movement speed. Thus, the present technology may provide for increased drilling speeds, even when drilling laterally or uphill. Namely, in embodiments, a proximal end 1826 of the outer casing may be disposed within or adjacent to a drill pipe. Thus, the proximal end 1826 may be exposed to an internal pressure of the drill pipe. A pressure is increased within the drill pipe, such as by increasing the rotation of the drill string, the spring 1806 may be compressed, increasing the pressure with internal volume 1814. Therefore, pressure may be increased and decreased quickly, without excessive vibrational or frictional forces.

Thus, in embodiments, the present technology may provide for drilling at greater than or about 50 feet per hour, such as greater than or about 60 feed per hour, such as greater than or about 70 feet per hour, such as greater than or about 80 feet per hour, such as greater than or about 90 feet per hour, such as greater than or about 100 feet per hour, such as greater than or about 110 feet per hour, such as greater than or about 120 feet per hour, such as greater than or about 130 feet per hour, such as greater than or about 140 feet per hour, such as greater than or about 150 feet per hour, or greater, or any ranges or values therebetween.

While only two engagement mechanisms 1812 and one gripper foot 1822 are illustrated, it should be clear that more or less engagement mechanisms or gripper feet may be utilized based upon the overall size of the toolface anchor. Furthermore, it should be clear that toolface anchor 1800, gripper mechanism 1600, and combinations thereof, may be utilized alone or in combination with the downhole kelly discussed above. Moreover, toolface anchor 1800, gripper mechanism 1600, and combinations thereof may have any one or more of the above discussed sizes and cross-sectional shapes, such as discussed in regards to gripper section 1112 above.

Regardless of the orientation, the present technology has surprisingly found that the toolface anchor 1800, gripper mechanism 1600, downhole kelly 1120 and combinations thereof may allow for greatly improved drilling speed, even in lateral or uphill toolface orientations, and may also exhibit reduced vibration, friction, and wear on the assembly. Furthermore, the assemblies discussed herein may provide for uphill drilling, such as an angle that is greater than or about 1° above a lateral elevation (which may be parallel or coplanar with a ground surface in embodiments, such as a direction from a lower depth towards a surface), such as greater than or about 2°, such as greater than or bout 3°, such as greater than or about 4°, such as greater than or about 5°, such as greater than or about 6°, such as greater than or about 7°, such as greater than or about 8°, such as greater than or about 9°, such as greater than or about 10°, such as greater than or about 11°, such as greater than or about 12°, such as greater than or about 13°, such as greater than or about 14°, such as greater than or about 15°, or any ranges or values therebetween.

Furthermore, the present technology may allow for extensive compressive force to be placed on a bit without requiring an increase in drill pipe weight. For instance, the present technology may provide a compressive force on bit of greater than or about 1,000 pounds, such as greater than or about 5,000 pounds, such as greater than or about 10,000 pounds, such as greater than or about 15,000 pounds, such as greater than or about 20,000 pounds, such as greater than or about 25,000 pounds, such as greater than or about 30,000 pounds, such as greater than or about 35,000 pounds, such as greater than or about 40,000 pounds, such as greater than or about 45,000 pounds, such as greater than or about 50,000 pounds or greater, or such as less than or about 100,000 pounds, such as less than or about 90,000 pounds, such as less than or 80,000 pounds, such as less than or about 70,000 pounds, such as less than or about 60,000 pounds, or any ranges or values therebetween.

As discussed above, the present disclosure may provide for drilling with lighter weight pipe for the drill string. In embodiments, the entire drill string could be neutrally buoyant as the drilling tool(s) of the present disclosure may not require any weight on bit from the drill pipe or drill string. Moreover, it is believed that drilling in accordance with the present disclosure may be possible with lighter drill pipe, which may also reduce friction and drag, providing for faster drilling.

FIG. 19 is a flow chart of a process 1900 for drilling using a drilling tool, according to an example of the present disclosure. According to an example, one or more process blocks of FIG. 19 may be performed by one or more drilling tools discussed herein.

At block 1905, process 1900 may include providing a drilling tool to a wellbore to be drilled. In embodiments, the drilling tool may include any one or more of the embodiments discussed above, such as a toolface anchor, a downhole kelly, or a combination thereof. In embodiments, the drilling tool may include at least a first section having a gripper apparatus configured to selectively extend outwardly from a longitudinal axis of the drilling tool when a drilling fluid flows through the drilling tool or when pressure is otherwise applied. The drilling tool further may include a second section having a sleeve having external threads extending from at least a portion of an outer surface of the sleeve, where the sleeve may be configured to travel along the longitudinal axis of the drilling tool inside the drilling tool and have the external threads engage with the internal threaded section. A drill bit may be coupled to a first end of the drilling tool and a drill string may be coupled to a second end of the drilling tool.

At block 1910, process 1900 may include optionally obtaining a desired toolface or confirming that a current toolface is within a target range or is within a margin of error thereof.

At block 1915, process 1900 may include optionally adjusting the toolface if necessary so that the current toolface is within a target range or is within a margin of error thereof. For example, the device may adjust the toolface, if necessary, so that the current toolface is within a target range or is within a margin of error thereof, as described above.

At block 1920, process 1900 may, extending the gripper apparatus to engage with an interior surface of the wellbore. As discussed above, the gripper and/or toolface anchor may extend due to increased pressure within the device, such as due to rotation from the drill string, pressure from drilling mud, combinations thereof, or the like.

At block 1925, process 1900 may include drilling a first portion of the wellbore. For example, device may drill a first portion of the wellbore, as described above.

At block 1930, process 1900 may include retracting the gripper apparatus to disengage with an interior surface of the wellbore. As discussed above, the gripper and/or toolface anchor may retract or disengage due to decreased pressure within the device, such as due to the release of accumulated pressure in the interior volume.

Process 1900 may include additional implementations, such as any single implementation or any combination of implementations described below and/or in connection with one or more other processes described elsewhere herein. In a first implementation, during drilling of the first portion of the wellbore, the sleeve travels along the longitudinal axis of the drilling tool until stopped by threading of the external threads with the internal threads.

As the drilling assembly described and disclosed herein does not require conventional weight on bit (e.g. weight from the drill string), it is believed that the drilling assembly of the present disclosure can be used with lighter weight drill string, or even in the absence of heavy weight drill pipe. With a drilling assembly according to the present technology and a lighter drill string, it is believed that a wellbore may be drilled from a lower depth towards the surface (and therefore an upper depth), in addition to the benefits discussed above. This capability for “uphill” drilling can be useful for a number of reasons. For example, older wells may be considered depleted, such as after water injection methods (or other enhanced oil recovery methods) have been used to enhance recovery from such wells. In fact, the reservoirs of such wells may not be depleted of oil and/or gas. By using the drilling assembly of the present disclosure, it is considered possible to drill upwards through the water injector of a previously drilled well (or otherwise drill into the reservoir of such a well) and then determine whether oil and/or gas remains in that well, such as by testing the drilling mud for hydrocarbons. If oil remains in the reservoir of the well, the wellbore drilled with the drilling assembly (or another wellbore) can be used to inject a gas into the reservoir to force the oil and/or natural gas remaining downward so it can be recovered and thereby obtain additional recovery of oil and/or natural gas from a well previously considered depleted. It is also believed that many older wells drilled without more modern geosteering techniques were like drilled to an excessive depth, and thus may yield additional recovery of oil and gas even though currently thought to be depleted.

The drilling assembly disclosed herein may also be used in other ways. For example, the drilling assembly may be used to drill some or all of the portions of a wellbore drilled to provide goods to one or more urban locations, such as described in U.S. Provisional Patent Application Ser. No. 63/494,126, filed with the United States Patent and Trademark Office on Apr. 4, 2023, and entitled “Systems and Methods for Delivery of Goods,” which is hereby incorporated by reference as if fully set forth herein. Additionally, the drilling assembly disclosed herein may be used to drill one or more portions of one or more lateral wellbore extensions from a wellbore, such as if the wellbore has been drilled to a target formation (or portion of a formation) and additional lateral wellbores are to be drilled in that same formation (or portion of a formation) to obtain additional recovery.

In various embodiments, the engagement of the gripper apparatus with the interior surface of the wellbore maintains a toolface within a target range therefor.

In various embodiments, the drilling may include a slide drilling operation.

In various embodiments, the drilling may include a slide drilling operation and a rotary drilling operation.

In various embodiments, the drill string does not include heavy weight drill pipe.

In various embodiments, the first portion of the wellbore drilled extends towards the surface.

In various embodiments, the drilling may include a plurality of alternating slide drilling operations and rotary drilling operations.

In various embodiments, the drill string may include casing for a portion of the wellbore.

In various embodiments, at least a portion of the drill string may include one or more pipes formed from a composite material. It should be noted that while FIG. 19 shows example blocks of process 1900, in some implementations, process 1900 may include additional blocks, fewer blocks, different blocks, or differently arranged blocks than those depicted in FIG. 19. Additionally, or alternatively, two or more of the blocks of process 1900 may be performed in parallel.

The above disclosed subject matter is to be considered illustrative, and not restrictive, and the appended claims are intended to cover all such modifications, enhancements, and other embodiments which fall within the true spirit and scope of the present disclosure. Thus, to the maximum extent allowed by law, the scope of the present disclosure is to be determined by the broadest permissible interpretation of the following claims and their equivalents and shall not be restricted or limited by the foregoing detailed description.

Claims

1. An apparatus, comprising: a drilling tool having a proximal end and a distal end;an internal threaded section proximal the distal end of the drilling tool;a gripper apparatus affixed to an exterior surface of a portion of the drilling tool, the gripper apparatus having a first extended orientation and a second retracted orientation, wherein in the extended orientation an outer diameter of a gripper apparatus comprises an outer diameter greater than an outer diameter of an external wall of the drilling tool and the retracted orientation comprises an outer diameter of the gripper apparatus of less than the outer diameter of the external wall; anda cylindrical sleeve having external threads extending from at least a portion of an outer surface of the cylindrical sleeve, the cylindrical sleeve having a first orientation, and a second linearly extended orientation wherein the external threads engage with the internal threaded section.

2. The apparatus of claim 1, wherein the gripper apparatus comprises a plurality of gripper pads configured to engage with an interior surface of a borehole.

3. The apparatus of claim 2, wherein the plurality of gripper pads comprise a plurality of teeth configured to engage with an interior surface of a borehole.

4. The apparatus of claim 1, further comprising a drill bit attached to the cylindrical sleeve.

5. The apparatus of claim 1, wherein the gripper apparatus extends outwardly away from a longitudinal axis of the drilling tool from the retracted orientation to the extended orientation when an internal pressure of the gripper apparatus is increased.

6. The apparatus of claim 1, wherein the gripper apparatus retracts inwardly towards a longitudinal axis of the drilling tool from the extended orientation to the retracted orientation when an internal pressure of the gripper apparatus is decreased.

7. A method of drilling a wellbore, the method comprising: providing a drilling tool located in a wellbore to be drilled, wherein the drilling tool comprises a first section having a gripper apparatus configured to selectively extend outwardly from a longitudinal axis of the drilling tool when a drilling fluid flows through the drilling tool, and wherein the drilling tool further comprises a second section having a sleeve having external threads extending from at least a portion of an outer surface of the sleeve, the sleeve configured to travel along the longitudinal axis of the drilling tool inside the drilling tool and have the external threads engage with an internal threaded section, and wherein a drill bit is coupled to a first end of the drilling tool and a drill string is coupled to a second end of the drilling tool;obtaining a desired toolface or confirming that a current toolface is within a target range therefor or is within a margin of error therefor;adjusting toolface if necessary so that the current toolface is within a target range therefor or is within a margin of error therefor;responsive to a flow of drilling fluid through the drilling tool, extending the gripper apparatus to thereby engage with an interior surface of the wellbore; anddrilling a first portion of the wellbore.

8. The method according to claim 7, wherein during drilling of the first portion of the wellbore, the sleeve travels along the longitudinal axis of the drilling tool until stopped by threading of the external threads with the internal threads.

9. The method according to claim 8, wherein the engagement of the gripper apparatus with the interior surface of the wellbore maintains the toolface within a target range.

10. The method according to claim 7, wherein the drilling comprises a slide drilling operation and a rotary drilling operation.

11. The method according to claim 7, wherein the first portion of the wellbore drilled extends towards the surface.

12. The method according to claim 7 wherein the drilling comprises one or more slide drilling operations and one or more rotary drilling operations.

13. The method according to claim 7, wherein at least a portion of the drill string comprises one or more pipes comprising a composite material.

14. The method according to claim 7, further comprising: ceasing flow of the drilling fluid, retracting the grippers;resetting the sleeve to its initial position before the drilling of the first portion of the wellbore;flowing drilling fluid and extending the grippers to engage with an interior surface of the wellbore;drilling a second portion of the wellbore.

15. A drilling tool, comprising: a drilling tool having a proximal end and a distal end;a gripper section having an external wall, an engagement mechanism having one or more gripper feet, a first extended orientation and a second retracted orientation, wherein in the extended orientation an outer diameter of the gripper section comprises an outer diameter greater than an outer diameter of the external wall of the drilling tool and the retracted orientation comprises an outer diameter of the gripper section of less than the outer diameter of the external wall; anda sleeve having a complementary engagement track extending from at least a portion of an outer surface of the sleeve, the sleeve having a first orientation, and a second linearly extended orientation wherein the complementary engagement track engages with the engagement mechanism when the gripper is in the first extended orientation.

16. The drilling tool of claim 15, wherein the engagement mechanism comprises one or more ball bearings, and the engagement track comprises one or more ball returns.

17. The drilling tool of claim 15, wherein the engagement mechanism comprises one or more locking pins, and the engagement track comprises one or more recesses.

18. The drilling tool of claim 15, further comprising an inner casing and an outer casing, wherein the gripper section is disposed within the inner casing.

19. The drilling tool of claim 18, further comprising a spring disposed between a proximal end of the outer casing and a proximal end of the inner casing.

20. The drilling tool of claim 18, wherein the inner casing comprises an inner pressure release valve and the outer casing comprises an outer pressure release valve, wherein the inner pressure release valve and the outer pressure release valve are aligned in a fully extended orientation.

21. The drilling tool of claim 18, wherein the outer casing comprises one or more shoulder regions, wherein the one or more gripper feet are seated within the one or more shoulder regions in a retracted orientation.

22. The drilling tool of claim 15, wherein the engagement mechanism comprises a first arm in contact with an engagement section, and a second arm in contact with the one or more gripper feet.

23. A method of drilling a wellbore, the method comprising: disposing a drilling tool in a wellbore to be drilled, the drilling tool comprising a gripper section and a drill bit attached to the gripper section;increasing pressure in an internal volume of the drilling tool, increasing an outer diameter of the gripper section to thereby engage with an interior surface of the wellbore;applying a compressive force of greater than or about 1000 pounds to the drill bit; anddrilling a first portion of the wellbore.

24. The method according to claim 23, wherein the drilling tool is disposed in an uphill portion of the wellbore prior to drilling the first portion.

25. The method according to claim 24, wherein the uphill portion has a slope of greater than or about 1° relative to a horizontal plane.

26. The method according to claim 23, wherein the gripper section comprises an external wall, an engagement mechanism having one or more gripper feet, a first extended orientation and a second retracted orientation, wherein in the extended orientation an outer diameter of the gripper section comprises an outer diameter greater than an outer diameter of the external wall of the drilling tool and the retracted orientation comprises an outer diameter of the gripper section of less than the outer diameter of the external wall; anda sleeve having a complementary engagement track extending from at least a portion of an outer surface of the sleeve, the sleeve having a first orientation, and a second linearly extended orientation wherein the complementary engagement track engages with the engagement mechanism when the gripper is in the first extended orientation;wherein the increase in pressure transitions the gripper section from the retracted orientation to the extended orientation.

27. The method according to claim 26, wherein the engagement mechanism is extended outward from a longitudinal axis of the sleeve when the pressure is increased, increasing the diameter of the gripper section.

28. The method according to claim 27, further comprising releasing the pressure after drilling the first portion, reducing the outer diameter of the gripper section.

29. The method according to claim 26, wherein the engagement mechanism comprises one or more ball bearings, and the engagement track comprises one or more ball returns, wherein the engagement mechanism engages the engagement track, stopping linear movement of the sleeve when the pressure is increased.

30. The method according to claim 29, further comprising releasing the pressure, disengaging the engagement mechanism from the engagement track.

31. The method according to claim 26, wherein the gripper section further comprises an inner casing and an outer casing, wherein the gripper section is disposed within the inner casing and a spring is disposed between a proximal end of the outer casing and a proximal end of the inner casing,a drill pipe in fluid communication with the proximal end of the outer casing,wherein the spring is compressed as pressure increases in the drill pipe.