Patent Application
20200095829
Underground drilling involves drilling a bore through a formation deep in the Earth using a drill bit connected to a drill string. Two common drilling methods, often used within the same hole, include rotary drilling and slide drilling. Rotary drilling typically includes rotating the drilling string, including the drill bit at the end of the drill string, and driving it forward through subterranean formations. This rotation often occurs via a top drive or other rotary drive means at the surface, and as such, the entire drill string rotates to drive the bit. This is often used during straight runs, where the objective is to advance the bit in a substantially straight direction through the formation.
Slide drilling is often used to steer the drill bit to effect a turn in the drilling path. For example, slide drilling may employ a drilling motor with a bent housing incorporated into the bottom-hole assembly (BHA) of the drill string. During typical slide drilling, the drill string is not rotated and the drill bit is rotated exclusively by the drilling motor. The bent housing steers the drill bit in the desired direction as the drill string slides through the bore, thereby effectuating directional drilling. Alternatively, the steerable system can be operated in a rotating mode in which the drill string is rotated while the drilling motor is running.
A problem with conventional slide drilling arises when the drill string is not rotated because much of the weight on the bit applied at the surface is countered by the friction of the drill pipe on the walls of the wellbore. This becomes particularly pronounced during long lengths of a horizontally drilled bore hole, which can cause the string to stick.
To reduce wellbore friction during slide drilling, a top drive may be used to oscillate or rotationally rock the drill string during slide drilling to reduce drag of the drill string in the wellbore. This oscillation can reduce friction in the borehole. However, too much oscillation can disrupt the direction of the drill bit by sending it off-course during the slide drilling process, and too little oscillation can minimize the benefits of the friction reduction, resulting in low weight-on-bit and overly slow and inefficient slide drilling.
The parameters relating to the top-drive oscillation, such as the number of oscillating rotations, are typically programmed into the top drive system by an operator, and may not be optimal for every drilling situation. For example, the same number of oscillation revolutions may be used regardless of whether the drill string is relatively long or relatively short, and regardless of the sub-geological structure. Drilling operators, concerned about turning the bit off-course during an oscillation procedure, may under-utilize the oscillation features, limiting its effectiveness. Because of this, in some instances, an optimal oscillation may not be achieved, resulting in relatively less efficient drilling and potentially less bit progression.
Thus, a system that can determine and recommend an effective slide drilling oscillation amount during a drilling process would be desirable and has been developed and described below. Thus, the present disclosure addresses one or more of the problems of the prior art.
The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.
It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
This disclosure provides apparatuses, systems, and methods for improved drilling efficiency by evaluating and determining an oscillation regime target, such as an oscillating revolution target, for a drilling assembly to reduce wellbore friction on a tubular string (e.g., often referred to herein as a drill string) while not disrupting a bit alignment during a slide drilling process. The apparatuses, systems, and methods allow a user (alternatively referred to herein as an “operator”) or a control system to determine a suitable number of revolutions (alternatively referred to herein as rotations or wraps) to oscillate a tubular string in a manner that improves the drilling operation. The term drill string is generally meant to include any tubular string. This improvement may manifest itself, for example, by increasing the slide drilling speed, slide penetration rate, the usable lifetime of components, and/or other improvements. In one aspect, the system sets the oscillation regime target, such as the target number of revolutions used in slide drilling, based on parameters detected during rotary drilling. These parameters may include, for example, vibration/motion, toolface orientation, and other parameters.
The disclosure provides a technique that can be performed using a drilling rig and a BHA where the mud pumps are stopped and later turned back on, such as would normally happen during the connection of an additional tubular or stand of drill pipe. The term drill pipe is exemplary and could refer to any type of tubular herein. The disclosed methods allow for the quantitative measurement of how many actual oscillation revolutions of the drill pipe are required before the toolface of the BHA is changed.
One of ordinary skill in the art understands that the number of oscillation revolutions should be kept low to maintain the desired position of the toolface, but the number of oscillation revolutions should be high enough to break the friction along the length of the drill string. Thus, finding the “correct” or optimum number of oscillation revolutions is important for an effective drilling process. Advantageously, the methods provide for the direct measurement of how much oscillation can be provided before changing the toolface of the BHA to obtain the most benefit from the pipe oscillation during slide drilling. In contrast to conventional oscillation methods, the methods described herein experimentally measure the number of oscillation revolutions that are applied to a drill string before affecting the direction of the BHA, instead of relying on models. Thus, instead of “guessing” what the oscillation regime target should be, the methods described herein actually determine a preferred oscillation regime target.
In one aspect, this disclosure is directed to apparatuses, systems, and methods that optimize an oscillation regime target, such as the number of revolutions of the tubular string, e.g., at the surface of the borehole, to provide more effective drilling. Drilling may be most effective when the drilling system oscillates the tubular string sufficiently to rotate the string even very deep within the borehole, while permitting the drilling bit to rotate only under the power of the motor. For example, a revolution setting that rotates only the upper half of the string will be less effective at reducing drag than a revolution setting that rotates nearly the entire string. Therefore, an optimal revolution setting may be one that rotates substantially the entire string without upsetting or rotating the BHA. Further, since excessive oscillating revolutions during a slide might rotate BHA and undesirably change the drilling direction, the optimal angular setting would not adversely affect the direction of drilling.
The apparatus and methods disclosed herein may be employed with any type of directional drilling system using a rocking technique with an adjustable target number of revolutions, including handheld oscillating drills, casing running tools, tunnel boring equipment, mining equipment, and oilfield-based equipment such as those including top drives. The apparatus is further discussed below in connection with oilfield-based equipment, but the oscillation revolution selecting systems, apparatuses, and devices of this disclosure may have applicability to a wide array of fields including those noted above.
Referring to
The apparatus 100 includes a mast 105 supporting lifting gear above a rig floor 110. The lifting gear includes a crown block 115 and a traveling block 120. The crown block 115 is coupled at or near the top of the mast 105, and the traveling block 120 hangs from the crown block 115 by a drilling line 125. One end of the drilling line 125 extends from the lifting gear to drawworks 130, which is configured to reel out and reel in the drilling line 125 to cause the traveling block 120 to be lowered and raised relative to the rig floor 110. The other end of the drilling line 125, known as a dead line anchor, is anchored to a fixed position, possibly near the drawworks 130 or elsewhere on the rig.
A hook 135 is attached to the bottom of the traveling block 120. A top drive 140 is suspended from the hook 135. A quill 145 extending from the top drive 140 is attached to a saver sub 150, which is attached to a drill string 155 suspended within a wellbore 160. Alternatively, the quill 145 may be attached to the drill string 155 directly. It should be understood that other conventional drilling techniques for arranging a rig do not require a drilling line, and these are included in the scope of this disclosure. In another aspect (not shown), no quill is present.
The drill string 155 includes interconnected sections of drill pipe 165, a BHA 170, and a drill bit 175. The BHA 170 may include stabilizers, drill collars, and/or measurement-while-drilling (MWD) or wireline conveyed instruments, among other components. The drill bit 175, is connected to the bottom of the BHA 170 or is otherwise attached to the drill string 155. One or more pumps 180 may deliver drilling fluid to the drill string 155 through a hose or other conduit 185, which may be fluidically and/or actually connected to the top drive 140.
As shown, the BHA 170 includes a telemetry system 172. The telemetry system 172 can be used to process signals from the MWD sensors and transmit the data to the surface to a controller. In one embodiment, the telemetry system 172 includes an electromagnetic (EM) telemetry system. EM telemetry involves the generation of electromagnetic waves which travel through the earth's surrounding formations from the wellbore, with detection of the waves at the surface. EM telemetry can be transmitted where there is no mud flowing through the drill string. In another embodiment, the telemetry system 172 includes a mud pulse (MP) telemetry system. MP telemetry involves creating pressure waves in the circulating drilling mud in the drill string. Information acquired by the downhole sensors is transmitted in specific time divisions by creating a series of pressure waves in the mud column. This is achieved by changing the flow area and/or path of the drilling fluid as it passes the BHA in a timed, coded sequence, thereby creating pressure differentials in the drilling fluid. MP telemetry systems require mud to be flowing for telemetry to be transmitted.
In the exemplary embodiment depicted in
The apparatus 100 also includes a control system 190 configured to control or assist in the control of one or more components of the apparatus 100. For example, the control system 190 may be configured to transmit operational control signals to the drawworks 130, the top drive 140, the BHA 170 and/or the pump 180. The control system 190 may be a stand-alone component installed near the mast 105 and/or other components of the apparatus 100. In some embodiments, the control system 190 is physically displaced at a location separate and apart from the drilling rig.
The control system 190 includes a user-interface 205 and a controller 210. Depending on the embodiment, these may be discrete components that are interconnected via wired or wireless means. Alternatively, the user-interface 205 and the controller 210 may be integral components of a single system.
The user-interface 205 may include an input mechanism 215 permitting a user to input a left oscillation revolution setting and a right oscillation revolution setting. These settings control the number of revolutions of the drill string as the system controls the top drive or other drive system to oscillate the top portion of the drill string. In some embodiments, the input mechanism 215 may be used to input additional drilling settings or parameters, such as acceleration, toolface set points, rotation settings, and other set points or input data. A user may input information relating to the drilling parameters of the drill string, such as BHA information or arrangement, drill pipe size, bit type, depth, formation information, among other parameters or data. The input mechanism 215 may include a keypad, voice-recognition apparatus, dial, button, switch, slide selector, toggle, joystick, mouse, data base and/or other available data input device. Such an input mechanism 215 may support data input from local and/or remote locations. Alternatively, or additionally, the input mechanism 215, when included, may permit user-selection of predetermined profiles, algorithms, set point values or ranges, such as via one or more drop-down menus. The data may also or alternatively be selected by the controller 210 via the execution of one or more database look-up procedures. In general, the input mechanism 215 and/or other components within the scope of the present disclosure support operation and/or monitoring from stations on the rig site as well as one or more remote locations with a communications link to the system, network, local area network (LAN), wide area network (WAN), Internet, satellite-link, and/or radio, among other means.
The user-interface 205 may also include a display 220 for visually presenting information to the user in textual, graphic, or video form. The display 220 may also be used, e.g., by the user, to input drilling parameters, limits, or set point data in conjunction with the input mechanism 215. For example, the input mechanism 215 may be integral to or otherwise communicably coupled with the display 220.
In one example, the controller 210 may include a plurality of pre-stored selectable oscillation profiles that may be used to control the top drive or other drive system. The pre-stored selectable profiles may include a right rotational revolution value and a left rotational revolution value. The profile may include, in one example, 5.0 rotations to the right and −3.3 rotations to the left. These values are typically measured from a central or neutral rotation.
In addition to having a plurality of oscillation profiles, the controller 210 includes a memory with instructions for performing a process to select the profile. In some embodiments, the profile is a simply one of either a right (i.e., clockwise) revolution setting and a left (i.e., counterclockwise) revolution setting. Accordingly, the controller 210 may include instructions and capability to select a pre-established profile including, for example, a right rotation value and a left rotation value. Because some rotational values may be more effective than others in particular drilling scenarios, the controller 210 may be arranged to identify the rotational values that provide a suitable level, and generally an optimal level, of drilling speed. The controller 210 may be arranged to receive data or information from the user, the BHA 170, and/or the drive system 140 and process the information to select or put in place an oscillation profile that might enable effective and efficient drilling.
The BHA 170 may include one or more sensors, typically a plurality of sensors, located and configured about the BHA to detect parameters relating to the drilling environment, the BHA condition and orientation, and other information. In the embodiment shown in
The BHA 170 may also include an MWD shock/vibration sensor 235 that is configured to detect shock and/or vibration in the MWD portion of the BHA 170. The shock/vibration data detected via the MWD shock/vibration sensor 235 may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The BHA 170 may also include a mud motor ΔP sensor 240 that is configured to detect a pressure differential value or range across the mud motor of the BHA 170. The pressure differential data detected via the mud motor ΔP sensor 240 may be sent via electronic signal to the controller 210 via wired or wireless transmission. The mud motor ΔP may be alternatively or additionally calculated, detected, or otherwise determined at the surface, such as by calculating the difference between the surface standpipe pressure just off-bottom and pressure once the bit touches bottom and starts drilling and experiencing torque.
The BHA 170 may also include a magnetic toolface sensor 245 and a gravity toolface sensor 250 that are cooperatively configured to detect the current toolface. The magnetic toolface sensor 245 may be or include any available (i.e., available used generally herein to refer to any current or future-developed component) magnetic toolface sensor that detects toolface orientation relative to magnetic north or true north. The gravity toolface sensor 250 may be or include a gravity toolface sensor which detects toolface orientation relative to the Earth's gravitational field. In an exemplary embodiment, the magnetic toolface sensor 245 may detect the current toolface when the end of the wellbore is less than about 7° from vertical, and the gravity toolface sensor 250 may detect the current toolface when the end of the wellbore is greater than about 7° from vertical. However, other toolface sensors may also be utilized within the scope of the present disclosure that may be more or less precise or have the same degree of precision, including non-magnetic toolface sensors and non-gravitational inclination sensors. In any case, the toolface orientation detected via the one or more toolface sensors (e.g., sensors 245 and/or 250) may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The BHA 170 may also include an MWD torque sensor 255 that is configured to detect a value or range of values for torque applied to the bit by the motor(s) of the BHA 170. The torque data detected via the MWD torque sensor 255 may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The BHA 170 may also include an MWD weight-on-bit (WOB) sensor 260 that is configured to detect a value or range of values for WOB at or near the BHA 170. The WOB data detected via the MWD WOB sensor 260 may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The top drive 140 may also or alternatively may include one or more sensors or detectors that provide information that may be considered by the controller 210 when it selects or sets the oscillation profile. In this embodiment, the top drive 140 includes a rotary torque sensor 265 that is configured to detect a value or range of the reactive torsion of the quill 145 or drill string 155. The top drive 140 also includes a quill position sensor 270 that is configured to detect a value or range of the rotational position of the quill, such as relative to true north or another stationary reference. The rotary torque and quill position data detected via sensors 265 and 270, respectively, may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The top drive 140 may also include a hook load sensor 275, a pump pressure sensor or gauge 280, a mechanical specific energy (MSE) sensor 285, and a rotary RPM sensor 290.
The hook load sensor 275 detects the load on the hook 135 as it suspends the top drive 140 and the drill string 155. The hook load detected via the hook load sensor 275 may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The pump pressure sensor or gauge 280 is configured to detect the pressure of the pump providing mud or otherwise powering the BHA from the surface. The pump pressure detected by the pump sensor pressure or gauge 280 may be sent via electronic signal to the controller 210 via wired or wireless transmission.
The mechanical specific energy (MSE) sensor 285 is configured to detect the MSE representing the amount of energy required per unit volume of drilled rock. In some embodiments, the MSE is not directly sensed, but is calculated based on sensed data at the controller 210 or other controller about the apparatus 100.
The rotary RPM sensor 290 is configured to detect the rotary RPM of the drill string. This may be measured at the top drive or elsewhere, such as at surface portion of the drill string. The RPM detected by the RPM sensor 290 may be sent via electronic signal to the controller 210 via wired or wireless transmission.
In
The controller 210 is configured to receive detected information (i.e., measured or calculated) from the user-interface 205, the BHA 170, and/or the top drive 140, and utilize such information to continuously, periodically, or otherwise operate to determine and identify an oscillation regime target, such as a target rotation parameter having improved effectiveness. The controller 210 may be further configured to generate a control signal, such as via intelligent adaptive control, and provide the control signal to the top drive 140 to set, adjust and/or maintain the oscillation profile in order to most effectively perform a drilling operation.
Moreover, as in the exemplary embodiment depicted in
In this example, the display 220 also conveys information relating to the torque settings that may be used as target torque settings to be used during an oscillation regime while slide drilling. Here, right torque and left torque may be entered in the regions identified by numerals 226 and 228 respectively.
In addition to showing the oscillation rotational or revolution values and target torque, the display 220 also includes a dial or target shape having a plurality of concentric nested rings. In this embodiment, the magnetic-based toolface orientation data is represented by the line 230 and the data 232, and the gravity-based toolface orientation data is represented by symbols 234 and the data 236. The symbols and information may also or alternatively be distinguished from one another via color, size, flashing, flashing rate, shape, and/or other graphic means.
In the exemplary display 220 shown in
The display 220 may also include a textual and/or other type of indicator 248 displaying the current or most recent inclination of the remote end of the drill string. The display 220 may also include a textual and/or other type of indicator 250 displaying the current or most recent azimuth orientation of the remote end of the drill string. Additional selectable buttons, icons, and information may be presented to the user as indicated in the exemplary display 220. Additional details that may be included or used, such as those disclosed in U.S. Pat. No. 8,528,663 to Boone, which is incorporated herein by express reference thereto.
In this method 400, however, rather than turning on the pumps 180 after the stand is connected, at step 406, the controller 210 instructs the drive system 140 to oscillate or rock the drill string 155 by a small amount for a few seconds until sufficient data is obtained. For example, the controller 210 may instruct the drive system 140 to oscillate the drill string 155 one revolution clockwise (+1) and one revolution counterclockwise (−1) for about 10 seconds. At step 408, the controller 210 starts or activates the pumps 180 to allow drilling fluid to once again flow through the drill string 155. After the vibration and/or motion from the starting of pumps 180 is detected by the MWD shock/vibration sensor 235, the MP telemetry system 172 waits a preprogrammed transmit delay time (e.g., 60 seconds) before the MP telemetry system 172 starts to transmit data to the surface. This can advantageously permit the pump pressure to build before data transmission begins. This data includes shock/vibration and motion data from MWD shock/vibration sensor 235, as well as toolface data from magnetic toolface sensor 245 and gravity toolface sensor 250. At step 410, the controller 210 receives the data and determines if the toolface was affected by the small amount of oscillation. In some embodiments, the controller 210 determines exactly when the toolface was affected. For example, the controller determines if motion was detected at the start of the pumps 180 or earlier but during oscillation. The tool typically will detect vibration either when the pumps 180 are activated or when oscillation causes a toolface change.
At step 412, the controller 210 instructs the drive system 140 to oscillate the drill string 155 by a larger amount than the small amount. For example, the drive system can oscillate the drill string 155 two revolutions clockwise (+2) and two revolutions counterclockwise (−2). In other embodiments, the oscillation revolution amount may be 1.5 instead of 2, or any other suitable amount in each direction. At step 414, the controller 210 receives data from MWD sensors 235, 245, and 250 to determine if the toolface was affected by the larger amount of oscillation. At step 416, the controller 210 increases (e.g., ramps up) the amount of oscillation in each direction until a change in toolface is detected.
At step 418, once the toolface is determined to be affected, the controller 210 determines the number of oscillation revolutions that caused the motion. This can be done, for example, by determining the time that motion was detected, and determining how many oscillation revolutions were applied at that time. At step 420, the controller 210 establishes the pipe oscillation set point at a slightly lower level than the determined number of oscillation revolutions for slide drilling. For example, if the number of oscillation revolutions that affect the toolface of the BHA is determined to be 4, the pipe oscillation set point could be set at 3.5 or 3. This set point amount can be a percentage of revolutions below the oscillation that caused toolface orientation change (e.g., about 0.1, 0.2, 0.3, 0.4, 0.5, 1, 2, 3, 4, 5, 10, 15, or 20 percent, etc.), a manually input set point, or the previously tested set point at which the toolface orientation did not change.
In various embodiments of this method 400, instead of slowly ramping up the number of oscillation revolutions over time (e.g., 1, 2, 3, 4, 5, etc.), the controller 210 instructs the drive system 140 to slowly step up the number of oscillation revolutions. For example, the drive system 140 may oscillate the drill string 155 one (1) revolution for a certain amount of time (e.g., 10 seconds), then two (2) revolutions for a certain amount of time (e.g., 20 seconds), before turning on pumps 180. Once a preprogrammed transmit delay time has passed, the controller 210 receives data from MP telemetry system 172, determines when motion was detected, and correlates the time with the number of oscillation revolutions. Thus, this embodiment permits calculation of the total number of wraps that occurred in the tubular string rather than simply detecting the binary determination of whether the toolface was effected or not.
The methods 400 and 500 may be repeated for every new connection of stand to the drill string 155, periodically for every nth selected number of connections, when a change in the geologic conditions is otherwise detected as a result of changes in drilling operations, or when manually triggered by the user to double-check the optimal oscillation is being used. As the length of the drill string 155 increases, its properties change and different oscillation target regimes are needed. In some embodiments, different oscillation amounts are applied at every other or at each new connection to ensure a more optimal oscillation is used.
The EM telemetry system 172 starts transmitting data a certain amount of time (e.g., 60 seconds) after the pumps 180 are turned off and before they are turned on again. This data typically includes shock/vibration and motion data from MWD shock/vibration sensor 235, as well as toolface data from magnetic toolface sensor 245 and gravity toolface sensor 250. At step 606, the controller 210 receives this data from EM telemetry system 172. At step 608, the controller 210 instructs the drive system 140 to oscillate or rock the drill string 155 by a small amount for a few seconds until sufficient data is obtained. Step 608 is similar to step 406 above. At step 610, the controller 210 starts or activates the pumps 180 to allow drilling fluid to once again flow through the drill string 155. At step 612, the controller 210 receives the data and determines if the toolface was affected by the small amount of oscillation. Step 612 is similar to step 410 above. In some embodiments step 610 may be performed at some point after step 620 or 622 instead of after step 608.
At step 614, the controller 210 instructs the drive system 140 to oscillate the drill string 155 by a larger amount than the small amount. Step 614 is similar to step 412 above. At step 616, the controller 210 receives data from MWD sensors 235, 245, and 250 to determine if the toolface of the BHA was affected by the larger oscillation amount. Step 616 is similar to step 414 above. At step 618, the controller 210 increases (e.g., ramps up) the amount of oscillation until a change in toolface is detected.
At step 620, the controller 210 determines the oscillation level (or number of oscillation revolutions) that was running at the time the toolface was affected. Step 620 is similar to step 418 above. In some embodiments, the EM telemetry system can be configured to transmit a parameter indicating a time delay after the telemetry started that motion was detected. This time delay can then be correlated with the number of oscillation revolutions that were applied at that time. In other embodiments, the received toolface measurements from the tool can be used directly to determine the time when the toolface is affected. At step 622, the controller 210 establishes the pipe oscillation set point at a slightly lower level than the determined oscillation level for slide drilling. Step 622 is similar to step 420 above.
Like method 400, in various embodiments of this method 600, instead of slowly ramping up the number of revolutions over time (e.g., 1, 2, 3, 4, 5, etc.), the controller 210 instructs the drive system 140 to step up the number of oscillation revolutions. Also like method 400, in some embodiments of this method 600, the pumps 180 are not started until the level of oscillation has reached a high enough level to ensure that toolface has been affected. Once this level of oscillation has been reached, the pumps 180 are turned on, and the controller 210 determines the oscillation level that affects the toolface of the BHA.
Like method 400, the method 600 is repeated for every new connection of stand to the drill string 155, or based on an alternate plan as disclosed above for method 400. In some embodiments, different oscillation amounts can be tried at every other or at each new connection.
As understood by one of ordinary skill in the art, variations of methods 400, 500, and 600 can be performed based on the available sensors and telemetry type of the BHA 170. For example, instead of the use of MP or EM telemetry systems, acoustic transmission through a drill string or electronic transmission through a wireline or wired pipe may be used.
By using the systems and method described herein, a rig operator can more easily operate the rig during slide drilling at a maximum efficiency to minimize the effects of frictional drag on the drill string during slide drilling, while still providing low or minimal risk of rotating the BHA off-course during a slide. This can increase drilling efficiency which saves time and reduces drilling costs.
According to a first aspect of the present disclosure, a system including a controller and a drive system is provided. The controller is configured to: (i) deactivate and activate one or more pumps that deliver drilling fluid through a tubular string, (ii) provide operational control signals to connect one or more tubulars to the tubular string, (iii) provide operational control signals to oscillate the connected one or more tubulars and tubular string while the one or more pumps are deactivated and activated, (iv) receive data from a telemetry system, (v) determine a number of oscillation revolutions of the tubular string required to affect toolface orientation based on the received telemetry data, and (vi) provide operational control signals to set a number of oscillation revolutions of the tubular string to less than the determined number of oscillation revolutions. The drive system is configured to: (i) receive the operational control signals from the controller, and (ii) oscillate the connected one or more tubulars and tubular string based on the set number of oscillation revolutions so that the connected one or more tubulars and tubular string oscillate while maintaining a desired toolface orientation while slide drilling.
According to a second aspect of the present disclosure, a method of oscillating a tubular string while slide drilling is provided. The method includes deactivating and activating one or more pumps that deliver drilling fluid through a tubular string; instructing a drive system to connect one or more tubulars to the tubular string while the one or more pumps are deactivated; instructing the drive system to oscillate the connected one or more tubulars and tubular string while the one or more pumps are deactivated and activated; receiving, from a telemetry system, data; determining, based on the received data, when the toolface orientation data was affected by oscillation; correlating a time that the toolface orientation data was affected with a number of oscillation revolutions applied by the drive system; and instructing the drive system to oscillate the connected one or more tubulars and tubular string at a number of oscillation revolutions less than the number of oscillation revolutions that affected the toolface orientation data so that the connected one or more tubulars and tubular string oscillate while maintaining desired toolface orientation while slide drilling.
According to a third aspect of the present disclosure, a non-transitory machine-readable medium having stored thereon machine-readable instructions executable to cause a machine to perform operations. The operations include deactivating and activating one or more pumps that deliver drilling fluid through a tubular string; instructing a top drive to connect one or more tubulars to the tubular string while the one or more pumps are deactivated; instructing the top drive to oscillate the connected one or more tubulars and tubular string a certain number of oscillation revolutions while the one or more pumps are deactivated and activated; instructing the top drive to oscillate the connected one or more tubulars and tubular string a number of oscillation revolutions greater than the certain number of oscillation revolutions while the one or more pumps are activated; receiving, from a telemetry system, data while the one or more pumps are activated; determining, based on the received data, how many oscillation revolutions are needed to affect the toolface orientation data; and instructing the top drive to oscillate the connected one or more tubulars and tubular string at a number of oscillation revolutions less than the determined number of oscillation revolutions so that the connected one or more tubulars and tubular string oscillate while maintaining desired toolface orientation while slide drilling.
Thus, various systems, apparatuses, methods, etc. have been described herein. Although embodiments have been described with reference to specific example embodiments, it will be evident that various modifications and changes may be made to these embodiments without departing from the broader spirit and scope of the system, apparatus, method, and any other embodiments described and/or claimed herein. Further, elements of different embodiments in the present disclosure may be combined in various different manners to disclose additional embodiments still within the scope of the present embodiments. Additionally, the specification and drawings are to be regarded in an illustrative rather than a restrictive sense.
The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.
Moreover, it is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the word “means” together with an associated function.
