Patent Grant
10731453
At the outset of a drilling operation, drillers typically establish a drilling plan that includes a target location and a drilling path to the target location. Once drilling commences, the bottom hole assembly is directed or “steered” from a vertical drilling path in any number of directions, to follow the proposed drilling plan. For example, to recover an underground hydrocarbon deposit, a drilling plan might include a vertical well to a point above the reservoir, then a directional or horizontal well that penetrates the deposit. The operator may then steer the bit through both the vertical and horizontal aspects in accordance with the plan.
In some embodiments, such directional drilling requires accurate orientation of a bent segment of the downhole motor that drives the bit. In such embodiments, rotating the drill string changes the orientation of the bent segment and the toolface and can also cause torque to become trapped in the drill string. Thus, a transition from rotating drilling to slide drilling requires multiple steps to properly orient the bent segment and the toolface. This typically requires the operator to manipulate the drawworks brake, and rotate the rotary table or top drive quill to find the precise combinations of hook load, mud motor differential pressure, and drill string torque, to properly position the toolface. This can be difficult, time consuming, and complex. Each adjustment has different effects on the toolface orientation, and each must be considered in combination with other drilling requirements to drill the hole. Thus, transitioning from rotating drilling to slide drilling is very complex, labor intensive, and often inaccurate process. A more efficient, reliable method for executing sliding instructions is needed.
In one example aspect, the present disclosure is directed to a method of automating a slide drilling operation that includes a plurality of tasks, the method including presenting selectable indicators, on a graphical user interface, wherein each selectable indicator is associated with one task from the plurality of tasks related to the slide drilling operation; wherein the graphical user interface is operably coupled to a controller that is in communication with drilling equipment, wherein the controller is configured to: receive data from the drilling equipment; and control the operation of at least a portion of the drilling equipment using a predetermined workflow and task parameters; and wherein each task is associated with at least one predetermined workflow; receiving by the controller a first selection command associated with a first selectable indicator presented on the graphical user interface, a first task, and a first predetermined workflow; presenting on the graphical user interface, in response to the receipt of the first selection command, a first dialogue box for receiving a first plurality of task parameters associated with the first predetermined workflow; receiving, using the first dialogue box, the first plurality of task parameters; and executing, using the controller and at least a portion of the drilling equipment, the first task using the first predetermined workflow and the first plurality of task parameters. In some embodiments, the plurality of tasks includes one or more of: removing trapped torque from a drill string; auto-oscillating the drill string; tagging bottom using the drill string; obtaining a target toolface angle; maintaining the target toolface angle; and evaluating a slide drilling operation. In some embodiments, the method also includes: automatically presenting the selectable indicators on the graphical user interface during or after the execution of the first task; receiving by the controller a second selection command associated with: a second selectable indicator of the selectable indicators; a second task; and a second predetermined workflow; presenting on the graphical user interface, in response to the receipt of the second selection command, a second dialogue box configured to receive a second plurality of task parameters; receiving, using the second dialogue box, the second plurality of task parameters; and automatically executing, using the controller and at least a portion of the drilling equipment, the second task using the second predetermined workflow and the second plurality of task parameters. In some embodiments, the first task is removing trapped torque from a drill string that is coupled to a bottom hole assembly used in the slide drilling operation; the first task of removing trapped torque from the drill string is associated with a workflow to move the drill string vertically in first and second opposing directions, and with a workflow to rotate the drill string; wherein the method further includes: presenting, on the graphical user interface, a second dialogue box for receiving a second selection command selecting the workflow to move the drill string vertically as the first predetermined workflow or the workflow to rotate the drill string as the first predetermined workflow; and receiving, by the controller, the second selection command; wherein, when the workflow to move the drill string vertically in the first and second opposing directions is the first predetermined workflow, the first plurality of task parameters includes: a speed at which the drill string is to be moved vertically in the first and second opposing directions; a number of repetitions of moving the drill string vertically in the first and second opposing directions; or a vertical distance over which the drill string is to be moved vertically in the first and second opposing directions with each repetition; and wherein, when the workflow to rotate the drill string is the first predetermined workflow, the first plurality of task parameters includes a number of rotations of the drill string. In some embodiments, the second selection command selects the workflow to rotate the drill string as the first predetermined workflow; wherein the drilling equipment includes a top drive; and wherein executing the first task using the first predetermined workflow and the first plurality of task parameters includes automatically rotating, in response to the receipt of the second selection command and first plurality of task parameters, the drill string the number of rotations using the top drive. In some embodiments, the second selection command selects the workflow to move the drill string vertically as the first predetermined workflow; wherein the drilling equipment includes a drawworks; and wherein executing the first task using the first predetermined workflow and the first plurality of task parameters includes automatically lifting the drill string, in response to the receipt of the second selection command and the first plurality of task parameters, the vertical distance at the speed for the number of repetitions using the drawworks. In some embodiments, the drilling equipment further includes a top drive brake, wherein the workflow to move the drill string vertically as the first predetermined workflow also includes releasing the top drive brake; and wherein executing the first task using the first predetermined workflow and the first plurality of task parameters further includes automatically releasing the top drive brake. In some embodiments, the first task is auto-oscillating the drill string, wherein the drilling equipment includes: a top drive, and a weight on bit sensor; wherein the first plurality of task parameters includes measuring a minimum weight on bit threshold measurement; wherein the method further includes: receiving, by the controller, data from the weight on bit sensor; determining, using the data from the weight on bit sensor and the controller, an estimated weight on bit; and wherein executing the first task using the first predetermined workflow and the first plurality of task parameters includes automatically oscillating the drill string, using the top drive, upon the controller determining that the estimated weight on bit exceeds the minimum weight on bit threshold measurement. In some embodiments, the drilling equipment includes: a bottom hole assembly (“BHA”) coupled to a drill string that extends within a wellbore; a toolface sensor coupled to the BHA; and a top drive configured to rotate the drill string at the surface of the wellbore, wherein the first task is tagging bottom using the BHA; wherein the first plurality of task parameters includes a drill string rotation parameter; wherein executing the first task using the first predetermined workflow and the first plurality of task parameters includes: receiving, by the controller and from the toolface sensor, data associated with a first estimated toolface angle of the BHA while the BHA is off-bottom of the wellbore; determining, by the controller and based on the data associated with the first estimated toolface angle of the BHA, the first estimated toolface angle while the BHA is off-bottom; determining while the BHA is off-bottom, by the controller, a target toolface angle of the BHA; calculating, by the controller, a first difference measured in a clockwise direction between the target toolface angle and the first estimated toolface angle; when the first difference is greater than 180 degrees, calculating, by the controller, an adjusted drill string rotation parameter using a first rule and the drill string rotation parameter; when the first difference is equal to or less than 180 degrees, calculating, by the controller, the adjusted drill string rotation parameter using a second rule and the drill string rotation parameter; rotating, by the controller and using the top drive, the drill string by the adjusted drill string rotation parameter while the BHA is off-bottom; and tagging bottom, using the BHA, after rotating the drill string by the adjusted drill string rotation parameter. In some embodiments, the first rule includes adding the drill string rotation parameter to a second difference between 360 degrees and the first difference; and wherein the second rule includes subtracting the first difference from the drill string rotation parameter. In some embodiments, the drill string rotation parameter is defined by a number of rotations of the drill string in a first direction. In some embodiments, the drilling equipment further includes: a bottom hole assembly (“BHA”) coupled to a drill string that extends within a wellbore; a toolface sensor coupled to the BHA; and a top drive configured to rotate the drill string at the surface of the wellbore; wherein the first task is either obtaining a target toolface angle or maintaining toolface the target toolface angle during the slide drilling operation; wherein the first plurality of task parameters includes a selected period of time; wherein, executing, using the controller and the drilling equipment, the first task using the first predetermined workflow and the first plurality of task parameters includes: receiving, by the controller and from the toolface sensor, first drilling data from the BHA; determining, by the controller and using the first drilling data, a first estimated toolface angle of the BHA; determining, by the controller, if the first estimated toolface angle of the BHA is within a threshold deviation from the target toolface angle; when the first estimated toolface angle is not within the threshold deviation, then incrementing a count of a toolface counter from zero to one; receiving, by the controller and from the toolface sensor, second drilling data from the BHA; determining, by the controller and using the second drilling data, a second estimated toolface angle of the BHA; determining, by the controller, if the second estimated toolface angle of the BHA is within the threshold deviation from the target toolface angle; and when the second estimated toolface angle is not within the threshold deviation and the toolface counter is at one, then determining whether a difference between the first estimated toolface angle and the second estimated toolface angle, measured in a clockwise direction from the first estimated toolface angle is between 20 degrees and 180 degrees; when the difference is not between 20 degrees and 180 degrees, then pausing, using the controller and the top drive, rotation of the drill string for the selected period of time; and when the difference is between 20 degrees and 180 degrees, then resetting the count of the toolface counter to zero. In some embodiments, the threshold deviation includes: up to 60 degrees measured in the counterclockwise direction from the target toolface angle; and up to 120 degrees measured in a clockwise direction from the target toolface angle. In some embodiments, the selected period of time is about 10 seconds. In some embodiments, the drilling equipment further includes a mud pump; and wherein pausing drilling activities further includes ceasing operation of the mud pump. In some embodiments, pausing drilling activities reduces a downhole pressure differential In some embodiments, the plurality of tasks includes: a first task of removing trapped torque from a drill string; a second task of auto-oscillating the drill string; a third task of tagging bottom using the drill string; a fourth task of obtaining a target toolface angle; a fifth task of maintaining a toolface angle during the slide drilling operation; and a sixth task of evaluating a slide drilling operation; and wherein the method further includes automatically executing, using the controller and at least a portion of the drilling equipment: the fifth task after completion of the fourth task; the fourth task after completion of the third task; the third task after completion of the second task; or the second task after completion of the first task.
In one example aspect, the present disclosure is directed to a method of reducing stored torque within a drill string that extends within a wellbore of a well, the method including: storing, using a computing system, a first predetermined workflow to reduce stored torque within the drill string, and a second predetermined workflow to reduce stored torque within the drill string; wherein the first predetermined workflow includes instructions to vertically move the drill string in first and opposing second directions; and wherein the second predetermined workflow includes instructions to rotate the drill string in a first direction; presenting, using a graphical user interface operably coupled to the computing system, a first dialogue box configured to receive a selection command selecting the first predetermined workflow or the second predetermined workflow, and task parameters; receiving, by the controller, the selection command selecting the first predetermined workflow or the second predetermined workflow; further receiving, using the graphical user interface and when the selection command selects the first predetermined workflow, a first plurality of task parameters, the first plurality of task parameters including: a speed at which the drill string is to be moved vertically in the first and second opposing directions; a number of repetitions for moving the drill string vertically in the first and second opposing directions; and a vertical distance in which the drill string is to be moved vertically in the first and second opposing directions with each repetition; further receiving, using the graphical user interface and when the selection command selects the second predetermined workflow, a second plurality of task parameters, wherein the second plurality of task parameters includes a drill string rotation parameter; and automatically executing either the first predetermined workflow or the second predetermined workflow using drilling equipment operably coupled to a controller of the computing system, in response to the receipt of the selection command and either the first plurality of task parameters or the second plurality of task parameters. In some embodiments, the drilling equipment includes a top drive; and wherein the method further includes: receiving, using the graphical user interface, the selection command selecting the second predetermined workflow; and automatically executing the second predetermined workflow, wherein automatically executing the second predetermined workflow includes rotating, using the controller and the top drive, the drill string in accordance with the drill string rotation parameter. In some embodiments, the drill string rotation parameter is a number of rotations of the drill string at the surface of the well. In some embodiments, the drilling equipment includes a drawworks; and wherein the method further includes: receiving, using the graphical user interface, the selection command selecting the first predetermined workflow; and automatically executing the first predetermined workflow, wherein automatically executing the first predetermined workflow includes automatically lifting, using the controller and the drawworks, the drill string the vertical distance at the speed for the number of repetitions. In some embodiments, the drilling equipment further includes a top drive brake, wherein automatically executing the first predetermined workflow further includes releasing the top drive brake. In some embodiments, the drilling equipment further includes a travelling block coupled to the drill string and a crown block that is coupled to a mast that forms a portion of a drilling rig, wherein automatically executing the first predetermined workflow further includes controlling the drawworks to lift the drill string by the vertical distance while simultaneously monitoring a position of the travelling block relative to the crown block. In some embodiments, the drilling equipment further includes a bottom hole assembly; and wherein automatically executing the first predetermined workflow includes controlling the drawworks to lower the drill string by the vertical distance while simultaneously monitoring a position of the bottom hole assembly relative to a toe of the wellbore. In some embodiments, the drilling equipment includes a torque sensor configured to detect stored torque in the drill string; wherein the method further includes: receiving, by the controller and from the torque sensor, data relating to an amount of torque stored in the drill string; determining, by the controller and based on the data relating to the amount of torque stored in the drill string, an estimated amount of torque stored in the drill string; and determining, by the controller and based on the estimated amount of torque stored in the drill string, if the torque stored in the drill string should be reduced; wherein presenting the first dialogue box is in response to a determination by the controller that the torque stored in the drill string should be reduced. In some embodiments, automatically executing the selected predetermined workflow further includes controlling, by the controller, the drawworks to move the drill string at a speed that does not exceed a maximum speed limit.
In one example aspect, the present disclosure is directed to a method of tagging bottom using a bottom hole assembly (“BHA”) that extends within a wellbore during a slide drilling operation, the method including: storing, using a computing system including a graphical user interface and a controller, a first predetermined workflow to tag bottom using the BHA, and a second predetermined workflow to tag bottom using the BHA, wherein the first predetermined workflow is different from the second predetermined workflow; presenting, using the graphical user interface, a first dialogue box configured to receive a first selection command selecting the first predetermined workflow or the second predetermined workflow; wherein the graphical user interface is operably coupled to the controller that is in communication with drilling equipment, wherein the controller is configured to: receive data from the drilling equipment; and control the operation of at least a portion of the drilling equipment using the first and second predetermined workflows and task parameters; and receiving, by the controller, the first selection command selecting the first predetermined workflow or the second predetermined workflow; presenting, using the graphical user interface, a second dialogue box configured to receive task parameters; further receiving, using the graphical user interface and when the first selection command selects the first predetermined workflow, a first plurality of task parameters including a drill string rotation parameter; further receiving, using the graphical user interface and when the first selection command selects the second predetermined workflow, a second plurality of task parameters including a second selection command selecting a first rule or a second rule; and automatically executing either the first predetermined workflow or the second predetermined workflow using at least a portion of the drilling equipment, in response to the receipt of the first selection command and either the first plurality of task parameters or the second plurality of task parameters. In some embodiments, the drilling equipment includes: the BHA; a toolface sensor coupled to the BHA; and a top drive; wherein the method further includes: receiving, by the controller, the first selection command selecting the first predetermined workflow; and automatically executing the first predetermined workflow using at least a portion of the drilling in response to the receipt of the first selection command and the first plurality of task parameters, including: receiving, by the controller and from the toolface sensor, data associated with a first estimated toolface angle of the BHA while the BHA is off-bottom of the wellbore; determining while the BHA is off-bottom, by the controller and based on the data associated with the first estimated toolface angle of the BHA, the first estimated toolface angle; determining, by the controller, a first recommended toolface angle of the BHA while the BHA is on bottom; calculating, by the controller, a difference in a clockwise direction between the first recommended toolface angle and the first estimated toolface angle; causing, by the controller, when the difference is greater than 180 degrees, to calculate an adjusted drill string rotation parameter using a first rule; wherein the adjusted drill string rotation parameter is based on the drill string rotation parameter; causing, by the controller, when the difference is equal to or less than 180 degrees, to calculate the adjusted drill string rotation parameter using a second rule; rotating, by the controller and using the top drive, the drill string by the adjusted drill string rotation parameter while the BHA is off-bottom; and tagging bottom, using the BHA, after rotating the drill string by the drill string rotation parameter. In some embodiments, the first rule includes adding the drill string rotation parameter to the difference between 360 degrees and the difference; and wherein the second rule includes subtracting the difference from the drill string rotation parameter. In some embodiments, the first drill string rotation parameter is defined by a number of rotations of the drill string in a first direction. In some embodiments, the first plurality of task parameters further includes a predetermined speed; and wherein automatically executing the first predetermined workflow using at least a portion of the drilling equipment in response to the receipt of the first selection command and the first plurality of task parameters further includes lifting and then lowering the drill string at the surface of a well that includes the wellbore by at the predetermined speed. In some embodiments, the drilling equipment includes: the BHA; a toolface sensor coupled to the BHA; and a top drive; wherein the method further includes: receiving, by the controller, the first selection command selecting the second predetermined workflow; wherein the second selection command selects the first rule, wherein the first rule defines a threshold deviation between 30 degrees from a target toolface angle in a clockwise direction and 30 degrees from the target toolface angle in a counterclockwise direction; and automatically executing the second predetermined workflow using at least a portion of the drilling equipment in response to the receipt of the first selection command and the second plurality of task parameters, including: receiving, by the controller and from the toolface sensor, data associated with an estimated toolface angle of the BHA while the BHA is off-bottom of the wellbore; determining while the BHA is off-bottom of the wellbore, by the controller, and using the data associated with the estimated toolface angle of the BHA and the predetermined workflow, the estimated toolface angle of the BHA; determining, by the controller, if the estimated toolface angle of the BHA is within the threshold deviation from an target toolface angle; when the first estimated toolface angle is within the threshold deviation, then automatically lowering, using the controller, the BHA to tag the bottom of the wellbore; and when the first estimated toolface angle is not within the threshold deviation, then: rotating the drill string, using the controller and the top drive to adjust the BHA and repeating the steps a)-e). In some embodiments, the drilling equipment includes: the BHA; a toolface sensor coupled to the BHA; and a top drive; and wherein the method further includes: receiving, by the controller, the first selection command selecting the second predetermined workflow; wherein the second selection command selects the second rule, wherein the second rule defines a threshold deviation between 75 degrees in the clockwise direction from the target toolface angle to 105 degrees in a clockwise direction from the target toolface angle; and automatically executing the second predetermined workflow using at least a portion of the drilling equipment in response to the receipt of the first selection command and the second plurality of task parameters, including: receiving, by the controller and from the toolface sensor, data associated with an estimated toolface angle of the BHA while the BHA is off-bottom of the wellbore; determining while the BHA is off-bottom of the wellbore, by the controller, and using the data associated with the estimated toolface angle of the BHA and the predetermined workflow, the estimated toolface angle of the BHA; determining, by the controller, if the estimated toolface angle of the BHA is within the threshold deviation from an target toolface angle; when the estimated toolface angle is within the threshold deviation, then automatically lowering, using the controller, the BHA to tag the bottom of the wellbore; and when the estimated toolface angle is not within the threshold deviation, then: rotating the drill string, using the controller and the top drive to adjust the BHA and repeating the steps a)-e).
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 present 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.
The systems and methods disclosed herein automate the execution of sliding instructions, resulting in increased efficiently and speed during slide drilling compared to conventional systems that require significantly more manual input or pauses to provide for input. The invention can advantageously achieve this through the use of data feedback and location detection, processing received data, creating a stand-by-stand drilling plan, and executing automatically the stand-by-stand drilling plan. Prior to drilling, a target location is typically identified and an optimal wellbore profile or planned path is established. Such proposed drilling paths are generally based upon the most efficient or effective path to the target location or locations. As drilling proceeds, the systems and methods disclosed herein determine the position of the BHA, record and analyze results of surveys, create a plan for a next stand, and execute the plan for the next stand. Executing the plan for the next stand includes automatically executing, using the system, an automated slide sequence. Thus, the system and methods disclosed herein automate the execution of sliding instructions.
Referring to
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 drawworks 130 may include a ROP sensor 130a, which is configured for detecting an ROP value or range, and a controller to feed-out and/or feed-in of a drilling line 125. 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.
The term “quill” as used herein is not limited to a component which directly extends from the top drive, or which is otherwise conventionally referred to as a quill. For example, within the scope of the present disclosure, the “quill” may additionally or alternatively include a main shaft, a drive shaft, an output shaft, and/or another component which transfers torque, position, and/or rotation from the top drive or other rotary driving element to the drill string, at least indirectly. Nonetheless, albeit merely for the sake of clarity and conciseness, these components may be collectively referred to herein as the “quill.”
The drill string 155 includes interconnected sections of drill pipe 165, a bottom hole assembly (“BHA”) 170, and a drill bit 175. The bottom hole assembly 170 may include one or more motors 172, stabilizers, drill collars, and/or measurement-while-drilling (“MWD”) or wireline conveyed instruments, among other components. The drill bit 175, which may also be referred to herein as a tool, is connected to the bottom of the BHA 170, forms a portion 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 connected to the top drive 140.
The downhole MWD or wireline conveyed instruments may be configured for the evaluation of physical properties such as pressure, temperature, torque, weight-on-bit (“WOB”), vibration, inclination, azimuth, toolface orientation in three-dimensional space, and/or other downhole parameters. These measurements may be made downhole, stored in solid-state memory for some time, and downloaded from the instrument(s) at the surface and/or transmitted real-time to the surface. Data transmission methods may include, for example, digitally encoding data and transmitting the encoded data to the surface, possibly as pressure pulses in the drilling fluid or mud system, acoustic transmission through the drill string 155, electronic transmission through a wireline or wired pipe, and/or transmission as electromagnetic pulses. The MWD tools and/or other portions of the BHA 170 may have the ability to store measurements for later retrieval via wireline and/or when the BHA 170 is tripped out of the wellbore 160.
In an example embodiment, the apparatus 100 may also include a rotating blow-out preventer (“BOP”) 186, such as if the wellbore 160 is being drilled utilizing under-balanced or managed-pressure drilling methods. In such embodiment, the annulus mud and cuttings may be pressurized at the surface, with the actual desired flow and pressure possibly being controlled by a choke system, and the fluid and pressure being retained at the well head and directed down the flow line to the choke by the rotating BOP 186. The apparatus 100 may also include a surface casing annular pressure sensor 187 configured to detect the pressure in the annulus defined between, for example, the wellbore 160 (or casing therein) and the drill string 155. It is noted that the meaning of the word “detecting,” in the context of the present disclosure, may include detecting, sensing, measuring, calculating, and/or otherwise obtaining data. Similarly, the meaning of the word “detect” in the context of the present disclosure may include detect, sense, measure, calculate, and/or otherwise obtain data.
In the example embodiment depicted in
The apparatus 100 may include a downhole annular pressure sensor 170a coupled to or otherwise associated with the BHA 170. The downhole annular pressure sensor 170a may be configured to detect a pressure value or range in the annulus-shaped region defined between the external surface of the BHA 170 and the internal diameter of the wellbore 160, which may also be referred to as the casing pressure, downhole casing pressure, MWD casing pressure, or downhole annular pressure. These measurements may include both static annular pressure (pumps off) and active annular pressure (pumps on).
The apparatus 100 may additionally or alternatively include a shock/vibration sensor 170b that is configured for detecting shock and/or vibration in the BHA 170. The apparatus 100 may additionally or alternatively include a mud motor delta pressure (ΔP) sensor 172a that is configured to detect a pressure differential value or range across the one or more motors 172 of the BHA 170. In some embodiments, 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 one or more motors 172 may each be or include a positive displacement drilling motor that uses hydraulic power of the drilling fluid to drive the bit 175, also known as a mud motor. One or more torque sensors, such as a bit torque sensor 172b, may also be included in the BHA 170 for sending data to a controller 190 that is indicative of the torque applied to the bit 175 by the one or more motors 172.
The apparatus 100 may additionally or alternatively include a toolface sensor 170c configured to estimate or detect the current toolface orientation or toolface angle. For the purpose of slide drilling, bent housing drilling systems may include the motor 172 with a bent housing or other bend component operable to create an off-center departure of the bit 175 from the center line of the wellbore 160. The direction of this departure from the centerline in a plane normal to the centerline is referred to as the “toolface angle.” The toolface sensor 170c may be or include a conventional or future-developed gravity toolface sensor which detects toolface orientation relative to the Earth's gravitational field. Alternatively, or additionally, the toolface sensor 170c may be or include a conventional or future-developed magnetic toolface sensor which detects toolface orientation relative to magnetic north or true north. In an example embodiment, a magnetic toolface sensor may detect the current toolface when the end of the wellbore is less than about 7° from vertical, and a gravity toolface sensor 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, including non-magnetic toolface sensors and non-gravitational inclination sensors. The toolface sensor 170c may also, or alternatively, be or include a conventional or future-developed gyro sensor. The apparatus 100 may additionally or alternatively include a WOB sensor 170d integral to the BHA 170 and configured to detect WOB at or near the BHA 170. The apparatus 100 may additionally or alternatively include a torque sensor 140a coupled to or otherwise associated with the top drive 140. The torque sensor 140a may alternatively be located in or associated with the BHA 170. The torque sensor 140a may be configured to detect a value or range of the torsion of the quill 145 and/or the drill string 155 (e.g., in response to operational forces acting on the drill string). The top drive 140 may additionally or alternatively include or otherwise be associated with a speed sensor 140b configured to detect a value or range of the rotational speed of the quill 145.
The top drive 140, the drawworks 130, the crown block 115, the traveling block 120, drilling line or dead line anchor may additionally or alternatively include or otherwise be associated with a WOB or hook load sensor 140c (WOB calculated from the hook load sensor that can be based on active and static hook load) (e.g., one or more sensors installed somewhere in the load path mechanisms to detect and calculate WOB, which can vary from rig-to-rig) different from the WOB sensor 170d. The WOB sensor 140c may be configured to detect a WOB value or range, where such detection may be performed at the top drive 140, the drawworks 130, or other component of the apparatus 100. Generally, the hook load sensor 140c detects the load on the hook 135 as it suspends the top drive 140 and the drill string 155.
The detection performed by the sensors described herein may be performed once, continuously, periodically, and/or at random intervals. The detection may be manually triggered by an operator or other person accessing a human-machine interface (“HMI”) or GUI, or automatically triggered by, for example, a triggering characteristic or parameter satisfying a predetermined condition (e.g., expiration of a time period, drilling progress reaching a predetermined depth, drill bit usage reaching a predetermined amount, etc.). Such sensors and/or other detection means may include one or more interfaces which may be local at the well/rig site or located at another, remote location with a network link to the system.
The apparatus 100 also includes the controller 190 configured to control or assist in the control of one or more components of the apparatus 100. For example, the controller 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 controller 190 may be a stand-alone component installed near the mast 105 and/or other components of the apparatus 100. In an example embodiment, the controller 190 includes one or more systems located in a control room proximate the mast 105, such as the general purpose shelter often referred to as the “doghouse” serving as a combination tool shed, office, communications center, and general meeting place. The controller 190 may be configured to transmit the operational control signals to the drawworks 130, the top drive 140, the BHA 170, and/or the pump 180 via wired or wireless transmission means which, for the sake of clarity, are not depicted in
In some embodiments, the top drive control system 220 includes the top drive 140, the speed sensor 140b, the torque sensor 140a, and the hook load sensor 140c. The top drive control system 220 is not required to include the top drive 140, but instead may include other drive systems, such as a power swivel, a rotary table, a coiled tubing unit, a downhole motor, and/or a conventional rotary rig, among others.
In some embodiments, the mud pump control system 225 includes a mud pump controller and/or other means for controlling the flow rate and/or pressure of the output of the mud pump 180.
In some embodiments, the drawworks control system 230 includes the drawworks controller and/or other means for controlling the feed-out and/or feed-in of the drilling line 125. Such control may include rotational control of the drawworks (in v. out) to control the height or position of the hook 135, and may also include control of the rate the hook 135 ascends or descends. However, example embodiments within the scope of the present disclosure include those in which the drawworks-drill-string-feed-off system may alternatively be a hydraulic ram or rack and pinion type hoisting system rig, where the movement of the drill string 155 up and down is via something other than the drawworks 130. The drill string 155 may also take the form of coiled tubing, in which case the movement of the drill string 155 in and out of the hole is controlled by an injector head which grips and pushes/pulls the tubing in/out of the hole. Nonetheless, such embodiments may still include a version of the drawworks controller, which may still be configured to control feed-out and/or feed-in of the drill string.
As illustrated in
Generally, the hook position sensor 235 is configured to detect the vertical position of the hook 135, the top drive 140, and/or the travelling block 120. The hook position sensor 235 may be coupled to, or be included in, the top drive 140, the drawworks 130, the crown block 115, and/or the traveling block 120 (e.g., one or more sensors installed somewhere in the load path mechanisms to detect and calculate the vertical position of the top drive 140, the travelling block 120, and the hook 135, which can vary from rig-to-rig). The hook position sensor 235 is configured to detect the vertical distance the drill string 155 is raised and lowered, relative to the crown block 115. In some embodiments, the hook position sensor 235 is a drawworks encoder, which may be the ROP sensor 130a.
Generally, the rotary RPM sensor 240 is configured to detect the rotary RPM of the drill string 155. This may be measured at the top drive 140 or elsewhere, such as at surface portion of the drill string 155.
Generally, the quill position sensor 242 is configured to detect a value or range of the rotational position of the quill 145, such as relative to true north or another stationary reference.
Generally, the pump pressure sensor 245 is configured to detect the pressure of mud or fluid that powers the BHA 170 at the surface or near the surface.
Generally, the MSE sensor 246 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 190 or other controller.
Generally, the bit depth sensor 252 detects the depth of the bit 175.
In some embodiments the top drive control system 220 includes the torque sensor 140a, the quill position sensor 242, the hook load sensor 140c, the pump pressure sensor 245, the MSE sensor 246, and the rotary RPM sensor 240, and a controller and/or other means for controlling the rotational position, speed and direction of the quill or other drill string component coupled to the drive system (such as the quill 145 shown in
In some embodiments, the drawworks control system 230 comprises the hook position sensor 235, the ROP sensor 130a, and the drawworks controller and/or other means for controlling the length of drilling line 125 to be fed-out and/or fed-in and the speed at which the drilling line 125 is to be fed-out and/or fed-in.
In some embodiments, the mud pump control system 225 comprises the pump pressure sensor 245 and the motor delta pressure sensor 172a.
As illustrated in
Referring to
At the step 505, selectable indicators are presented on the GUI 195. For example and as illustrated in
Referring back to
At the step 515, in response to the receipt of the selection command, a dialogue box configured to receive a first plurality of task parameters is presented on the GUI 195.
At the step 520, the first plurality of task parameters is received using the dialogue box.
At the step 525, the first task associated with the selected button is executed using the first plurality of task parameters, the controller, and the drilling equipment.
In some instances, there are different methods of implementing the task associated with one of the buttons 605-630. For example, the trapped torque module 212a includes two sub modules. Often, when trapped torque is not worked out of the drill string 155, it can cause the toolface to move in unexpected and unpredictable ways, which increases the difficulty of applying a standard procedure or workflow for executing a slide. Generally, the majority of the trapped torque can be reliably reduced or removed by “working” the drill string up and down with the top drive brake off, or by removing wraps (turning the pipe left) a user defined number of turns before sliding. Thus, there are generally two methods of removing trapped torque in the drill string 155 from which a user can choose during the methods 400 and/or 500. The first is removing trapped torque using a “work pipe” module and the second is removing trapped torque using a “remove wraps” module.
At the step 510, the selection command received is associated with the selectable button 605, which is associated with the trapped torque task and the trapped torque module 212a.
At the step 705, another dialogue box is presented in the GUI 195. The dialogue box presented during the step 705 is configured to receive a selection command that selects a specific method of implementing the task of removing trapped torque from the drill string 155. For example, and as illustrated in
At the step 710, the selection command is received. For example, the selection command is received when the user selects one of the buttons 805 and 810. Selecting one of the buttons 805 and 810 selects one of the “remove wraps” workflow and the “work pipe” workflow to be implemented by the apparatus 100.
At the step 515, the input windows 805-835 are presented on the GUI 195. While the step 515 is illustrated as a separate step from the step 705, the steps 705 and 715 may occur simultaneously and involve one dialogue box, as illustrated by the dialogue box 800 of
At the step 520 and referring back to
At the step 525 during the method 700—and in response to the receipt of the selection command that selects the work pipe workflow and the inputs via the windows 815-825—the apparatus 100 automatically moves the drill string 155 by the vertical distance at the work pipe speed for the number of repetitions using the drawworks. Moreover, the trapped torque workflow 212a and thus the step 525 of the method 700 may also include releasing the top drive brake when the “work pipe” selectable indicator has been selected. Specifically, the trapped torque workflow 212a automatically sets the top drive brake to off or lowers the top drive torque in stages to allow torque to be released and works the drill pipe at the user defined speed up and down for the user defined number of times and length. In some embodiments, and during the step 525, the trapped torque workflow 212a stops the drilling operation if overpull/bridge protection limits set by the user are reached. The trapped torque workflow 212a also ensures that the work pipe length input parameter is not a distance that exceeds the crown saver, or controls the drawworks control system 230 such that the top drive 140 and/or the travelling block 120 is not lifted within a predetermined distance from the crown block 115. For example, the module 212a receives data from the hook position sensor 235 and determines the height of the travelling block 120 relative to the crown block 115 to ensure that the travelling block 120 is adequately spaced from the crown block 115 during the “work pipe” workflow. Thus, the trapped torque workflow 212a monitors the position of the travelling block relative to the crown block 120. In some embodiments, the trapped torque workflow 212a also monitors the position of the BHA 170 relative to a toe, or bottom, of the wellbore 160 to prevent the BHA 170 from to tagging bottom of the wellbore 160 during the “work pipe” workflow. In some embodiments, the trapped torque workflow 212a ensures that the BHA does not extend within 3 feet or 0.9 meters of the bottom of the wellbore 160. Generally, the maximum work pipe length input parameter has a maximum input value of 50 ft. or 15.2 meters. The trapped torque workflow 212a ensures that the work pipe speed does not exceed 5,000 ft./hr. or 1,524 m./hr., or controls the drawworks control system 230 such that the speed does not exceed 5,000 ft./hr. or 1,524 m./hr. or other predetermined safety limits. At the step 525 during the method 700—and in response to the receipt of the selection command that selects the remove wraps workflow and the input via the window 830—the apparatus 100 automatically rotates the drill string 155 the number of rotations using the top drive 140. The number of rotations is a drill string rotation parameter, which is not limited to a number of rotations of the drill string, but may also include a predetermined torque measurement within the drill string 155. Generally, the controller 190 controls or otherwise directs the top drive control system 220 and the drawworks control system 230 to implement the instructions stored within the trapped torque workflow during the step 525.
After the step 525 of the method 700, the apparatus 100 automatically begins to execute the oscillation module 212b or automatically presents the dialogue box 600 to the user.
At the step 510, the selection command is associated with the button 610.
At the step 515 of the method 1000, a dialogue box generally referred to by the numeral 1100 in
At the step 520 of the method 1000, the oscillation module 212b receives, using the input windows 1105-1140, one or more of the input parameters 215b.
At the step 1005, an estimated off-bottom rotary torque is calculated by the module 212b. In some instances, the off-bottom rotary torque is calculated by the controller 190 after the controller 190 receives data from the bit torque sensor 172b or other sensor. Generally, the estimated off-bottom rotary torque is used by the apparatus 100 to estimate the ideal number of wraps to rotate the drill string 155 during auto-oscillation of the drill string 155. Generally, the estimated off-bottom rotating torque is determined when the mud pump 180 is on and the drill string 155 is at full rotation, which generally corresponds to when the apparatus 100 zeros the WOB/DP before tagging bottom for a rotary period. Thus, when the WOB/DP has been zeroed and before the BHA 170 tags the bottom of the wellbore 160, the apparatus 100 calculates the estimated off-bottom rotary torque. After multiple estimated off-bottom rotary torques have been calculated, the apparatus 100 calculates an average off-bottom rotating torque. The estimated off-bottom rotary torque value or average estimated off-bottom rotary torque value is stored in the controller 190 to be used as an estimation of wraps required.
At the step 1010, the module 212b calculates an adjusted off-bottom rotary torque by multiplying the average estimated off-bottom rotating torque by the rotary torque percentage input parameter received via the window 1105. The average estimated off-bottom torque is generally the torque required to rotate the entire drill string 155 and BHA. However, the ideal amount of oscillating wraps is the number of wraps it takes to reach a percentage of this average off-bottom rotating torque. Thus, the ideal amount of oscillating wraps is the average estimated off-bottom torque multiplied by the rotary torque percentage input parameter.
At the step 1015, the module 212b receives data from the WOB sensor 170b.
At the step 1020, the module 212b determines an estimated WOB using the data from the WOB sensor 170b.
The step 525 of the method 1000 includes automatically tagging bottom upon the controller 190 determining that the estimated WOB exceeds the minimum WOB parameter at step 1025; automatically rotating the drill string 155 to the right until reaching and/or exceeding the adjusted off-bottom rotary torque to determine target number of right wraps at step 1030; automatically rotating the drill string 155 to the left until reaching and/or exceeding the adjusted off-bottom rotary torque or until reaching the maximum number of left wraps greater than right wraps number to determined target number of left wraps at step 1035; oscillating off-bottom while identifying the adjusted target number of wraps for oscillating off-bottom at step 1040; oscillating off-bottom using the adjusted target number of wraps and the oscillation RPM until reaching or exceeding the off-bottom cycles parameter at step 1045; and tagging bottom and continuing to oscillate the drill string 155 at the target number of right wraps and target number of left wraps at step 1050.
At the step 1025, the module 212b controls the apparatus 100 to automatically tag bottom of the wellbore 160 using the BHA 170 upon the controller 190 determining that the estimated WOB exceeds the minimum WOB parameter entered via the input window 1135. A certain amount of WOB is often required before oscillation the drill string 155 to avoid moving the BHA 170.
At the step 1030, the apparatus 100 automatically rotates the drill string 155 to the right until reaching and/or exceeding the adjusted off-bottom rotary torque to determine a target number of right wraps. In some instances, the drill string 155 is turned right at 20 rpms until the adjusted off-bottom rotary torque is detected and the apparatus 100 records that number of right turns required to reach the adjusted off-bottom rotary torque. The apparatus 100 then records that value as the right oscillation wraps to be used once the BHA 170 tags bottom to begin the sliding operation. After reaching and/or exceeding the adjusted off-bottom rotary torque, the system immediately begins rotating to the drill string 155 to left at 20 rpms.
At the step 1035, the apparatus 100 automatically rotates the drill string 155 to the left until reaching and/or exceeding the adjusted off-bottom rotary torque, or until reaching the maximum number of left wraps greater than the right wraps parameter received via the window 1110. The apparatus 100 records that number of left turns required to reach the adjusted off-bottom rotary torque.
At the step 1040, the apparatus 100 oscillates the drill string 155 off-bottom while the apparatus 100 identifies an adjusted target number of wraps for oscillating off-bottom by multiplying the target number of left wraps and the target number of right wraps by the off-bottom wraps percentage parameter received via the window 1120. At the step 1040, the apparatus 100 continues to oscillate the drill string 155 using the adjusted target number of wraps and the oscillation RPM received via the window 1115.
At the step 1045, the apparatus 100 continues oscillating the drill string 155 using the adjusted target number of wraps and the oscillation rpm received via the window 1115 until reaching or exceeding the off-bottom cycles parameter received via the window 1125.
At the step 1050, the apparatus 100 lowers the BHA 170 to tag the bottom of the wellbore 160 and continues to oscillate the drill string 155 at the target number of right wraps and the target number of left wraps.
When the user defined oscillation workflow is selected via the enable/disable button 1155 at the step 520, the step 525 includes the apparatus 100 starting oscillation of the drill string 155 using the off-bottom wrap percentage input received via the window 1130 for the number of cycles parameter received via the window 1135 before starting the tag bottom module 212c, during which the drill string 155 should be oscillated using a full user defined wrap parameter.
During the method 1000, input parameters relating to the oscillation regime, such as the oscillation module input parameters 215b, are input by the user thereby giving the apparatus 100 the ability to identify the optimal amount of wraps and begin oscillating before tagging bottom or execute the oscillation regime selected by the user.
After the step 525 of the method 1000, the apparatus 100 automatically begins to execute the oscillation module 212c or automatically presents the dialogue box 600 to the user.
At the step 510, the first indicator is the tag bottom indicator 615.
At the step 515, a dialogue box generally referred to by the numeral 1400 in
At the step 520 of the method 1300, the tag bottom module 212c receives the tag bottom workflow selection command via the button 1420 and one of more of the slide tag bottom module user inputs 215c via the windows 1405-1415. As illustrated in
At the step 1305, the apparatus 100 zeros the WOB and/or the differential pressure and slacks off at the slack of speed input parameter received via the window 1405 until 2 feet off-bottom.
Often, the off-bottom toolface is not already facing the direction the driller intends to slide so the offset wrap input parameter will need to be adjusted accordingly. Generally, the steps 1307-1320 adjust the offset wrap input parameter received via the window 1410 based on a current or estimated toolface position.
At the step 1307, the apparatus 100 receives, by the controller 190 and from the toolface sensor 170b, data associated with a first estimated toolface angle of the BHA while the BHA 170 is off-bottom of the wellbore.
At the step 1310, the system 10 determines while the BHA 170 is off-bottom, by the controller 190 and based on the data associated with the first estimated toolface angle of the BHA 170, the first estimated toolface angle. An illustration 1600 of the GUI 195 is illustrated in
At the step 1315, the apparatus 100 determines, by the controller 190, a first recommended on-bottom toolface angle of the BHA 170. In the example illustrated in
At the step 1320, the apparatus 100 determines an adjusted drill string rotation parameter, using a difference measured in the clockwise direction between the first recommended toolface angle and the first estimated toolface angle. In the example illustrated in
The step 525 of the method 1300 includes rotating, by the controller 190 and using the top drive control system 220, the drill string 155 by the adjusted drill string rotation parameter while the BHA 170 is off-bottom; and tagging bottom, using the BHA 170, after rotating the drill string 155 by the adjusted drill string rotation parameter.
At the step 520, the “line up toolface” enable selector is received via the window 1425 of
At the step 1705, the controller 190 or the module 212d determines whether the estimated toolface angle of the BHA 170 is within a threshold deviation from an advisory or target toolface angle. The threshold deviation used in the step 1705 is dependent upon the input parameter received via the window 1430. When the input parameter received via the window 1430 is “30 degree”, the threshold deviation includes 30 degrees from the advisory toolface angle in the clockwise direction and 30 degrees from the advisory toolface angle in the counterclockwise direction. When the input parameter received via the window 1430 is “90 right”, the threshold deviation includes 75 degrees in the clockwise direction from the advisory toolface angle to 105 degrees in the clockwise direction from the advisory toolface angle.
The step 525 of the method 1700 includes, when the first estimated toolface angle is within the threshold deviation, automatically lowering, using the controller 190 and the drawworks control system 230, the BHA 170 to tag the bottom of the wellbore 160. When the first estimated toolface angle is not within the threshold deviation, then the step 525 of the method 1700 includes rotating the drill string 155, using the controller 190 and the top drive control system 220, to adjust the toolface position of the BHA 170 and then repeating the method 1700 beginning at the step 1305.
After the step 525 of the method 1300 or 1700, the apparatus 100 automatically begins to execute the obtain target direction module 212d or automatically presents the dialogue box 600 to the user.
At the step 510, the first indicator is the obtain toolface position indicator 620.
At the step 515, a dialogue box 1900 illustrated in
At the step 520 of the method 1800, the apparatus 100 receives, via one or more of the input windows 1905-1965, the homing mode selection command via the window 1917 and one of more of the obtain target direction module user inputs 215d. As illustrated in
At the step 1805, the controller 190 receives from the toolface sensor 170b, data associated with an estimated toolface angle of the BHA 170.
At the step 1810, the apparatus 100 determines, by the controller 190 and based on the data associated with the first estimated toolface angle of the BHA 170, the estimated toolface angle.
At the step of 1815, the system determines based on the first estimated toolface angle, is within a first zone, a second zone, or a third zone. An illustration 2100 displayed on the GUI 195 is illustrated in
The step 525 of the method 1800 includes a sub-step of 1820 when the estimated toolface is in the first zone, a sub-step of 1825 when the estimated toolface is in the second zone, a sub-step of 1830 when the estimated toolface is in the third zone, and a sub-step of 1835 of ending the workflow.
At the step 1820 and when the estimated toolface is within the first zone, the step 525 of the method 1800 includes adding 0.5 right wraps after the minimum differential pressure has been reached; adding or removing left wraps based on the Table A entry 1965′ and changes in the differential pressure; and adding 0.5 right wraps when the next estimated toolface passes into or through the left 20 degree boundary or into/through the right 20 degree boundary.
At the step 1825 and when the estimated toolface is within the second zone, the step 525 of the method 1800 includes immediately adding 1.5 rights wraps; adding or removing left wraps based on the Table A entry 1965′ and changes in the differential pressure; adding 1 right wrap when the next estimated toolface is in the first zone then removing 1 right wrap when another next estimated toolface returns to the second zone; and immediately adding 1 left wrap when consecutive toolfaces are spaced more than 20 degrees apart and then cross into/through the right side 20 degree boundary.
At the step 1830 and when the estimated toolface is within the third zone, the step 525 of the method 1800 includes immediately adding 1 right wraps; adding or removing left wraps based on the Table A entry 1965′ and changes in the differential pressure; adding 1 right wrap when the next estimated toolface is in the 2nd zone then removing 1 right wrap once another next estimated toolface returns to the 3rd zone, and adding 0.5 right wraps when the yet another next estimated toolface passes through/into the left 20 degree boundary or the right 20 degree boundary.
At the step 1835, the apparatus 100 ends the workflow if any of the following three conditions are met: if consecutive toolfaces are within 20 degrees and both fall within +/−90 degrees of the target toolface; if 5 consecutive toolfaces fall within +/−90 degrees of the target toolface; and if the amount of time to move to next sequence received via the window 1955 is reached.
After the step 525 of the method 1800, the apparatus 100 automatically begins to execute the maintain target direction module 212e or automatically presents the dialogue box 600 to the user.
At the step 510, the first indicator is the maintain toolface position indicator 625.
At the step 515, a window 2300 illustrated in
At the step 520, the apparatus 100 receives, via one or more of the input windows 1905-1920, 1930-1940, 1960, 1965, and 2305-2330 one of more of the maintain target direction module user inputs 215e. As illustrated in
At the step 525 of the method 2200, the system increases and decreases the oscillation of the drill string 155 based on: a TF position, the maintain toolface position module input parameters 215e, and a plurality of rules to steer the BHA.
Before, during, or after the step 525 of the method 2200, the apparatus 100 automatically begins to execute the evaluation module 212f.
At the step 510, the first indicator is the evaluation toolface position indicator 630.
At the step 515, a dialogue box 2600 illustrated in
At the step 520 of the method 2500, the apparatus 100 receives, via one or more of the input windows 2605-2635 one of more of the evaluation module user inputs 215f. As illustrated in
The steps 1805 and 1810 of the method 2500 are identical or substantially identical to the steps 1805 and 1810 of the method 1800, and thus additional details will not be provided here.
The method 2500 also includes a step 1810 of determining, by the controller 190 and using the data associated with the actual toolface angle of the BHA, an actual toolface angle of the BHA.
At the step 2515, the controller 190 determines whether the first actual or estimated toolface angle is within a threshold deviation from an advisory toolface angle. In some embodiments, the threshold comprises: up to 60 degrees measured in a counterclockwise direction from the advisory toolface angle; and up to 120 degrees measured in a clockwise direction from the advisory toolface angle. If the first actual toolface angle is within the threshold deviation, then the next step is the step 1805. If the first actual toolface angle is not within the threshold deviation, then the next step is step 2520.
At the step 2520, the apparatus 100 increments a count of a toolface counter from zero to one.
At the step 2525, the controller 190 receives second drilling data from the BHA 170. The step 2525 is identical to the step 1805 except for that the data received at the step 2525 is subsequent to the data received at the step 1805.
At the step 2530, the controller 190 determines, using the second drilling data, a second actual toolface angle of the BHA 170.
At the step 2535, the controller 190 determines whether the 2nd actual toolface angle is within the threshold deviation from the advisory toolface angle. If the second actual toolface angle is within the threshold deviation, then the next step is a step 2537 in which the toolface counter is reset to zero and then the following step is the step 1805. If the second actual toolface angle is not within the threshold deviation, then the next step is step 2540.
At the step 2540, the apparatus 100 determines a difference, measured in a clockwise direction from the first actual toolface angle, between the first actual toolface angle and the second actual toolface.
At the step 2545, the controller 190 determines whether the difference is between 20 degrees and 180 degrees. If yes, then the next step is the step 2537 followed by the step 1805. If no, then the next step is the step 525.
At the step 525 of the method 2500, the module 215f pauses the drilling activities for the predetermined period of time or the wait time received via the window 2630. Pausing the drilling activities for the predetermined amount of time allows for the differential pressure to reduce, and thus prevents pushing the toolface further in a direction that is not desirable. The controller 190 may automatically pause the system by deactivating the top drive control system 220, the drawworks control system 230, and the mud pump drive 225.
The method 2500 may be executed simultaneously with each of the methods 1600, 1800, or similar method involving slide drilling.
Generally, the term “drilling equipment” refers to any combination of the lifting gear, the drawworks 130, the hook 135, the quill 145, the top drive 140, the saver sub 150, a portion or the entirety of the drill string 155, the BHA 170, the drill bit 17, the mud pump(s) 180, the BOP 186, the controller 190, and the plurality of sensors 210.
Each of the steps of the methods 300, 400, 500, 700, 1000, 1300, 1700, 1800, 2200, and 2500 may be performed automatically. The controller 190 of
In some instances, the parameters 215a-215f are provided by a user and thus are user inputs. In other instances, the parameters 215a-215f are generated by the apparatus 100 using historical user inputs, formation information, and historical results. Other inputs used by the sliding module 212 may include a quill torque positive limit, a quill torque negative limit, a quill speed positive limit, a quill speed negative limit, a quill oscillation positive limit, a quill oscillation negative limit, a quill oscillation neutral point input, and a toolface orientation input. Additional parameters of the apparatus 100 may also include a WOB tare, a mud motor ΔP tare, an ROP input, a WOB input, a mud motor ΔP input, and a hook load limit.
Some embodiments include a survey data input from prior surveys, a planned drilling path, or preferably both. These inputs may be used to derive the target toolface orientation input intended to maintain the BHA 170 on the planned drilling path. However, in other embodiments, the target toolface orientation is directly entered. Other embodiments within the scope of the present disclosure may utilize additional or alternative parameters. In some instances, the sliding module 212 and/or the controller 190 may access trend data stored from prior surveys.
The controller 190 may be, or include, intelligent or model-free adaptive controllers, such as those commercially available from Cyber Soft, General Cybernation Group, Inc. The controller 190 may also be collectively or independently implemented on any conventional or future-developed computing device, such as one or more personal computers or servers, hand-held devices, PLC systems, and/or mainframes, among others.
Referring to
Embodiments within the scope of the present disclosure may offer certain advantages over the prior art. For example, when automating a slide drilling operation using the methods 300, 400, 500, 700, 1000, 1300, 1700, 1800, 2200, and 2500, the slide drilling operation is more efficient. For example, determining whether a minimum WOB has been met prior to oscillating the drill string 155 prevents or reduces the amount of movement in the toolface.
A computer system typically includes at least hardware capable of executing machine readable instructions, as well as software for executing acts (typically machine-readable instructions) that produce a desired result. In addition, a computer system may include hybrids of hardware and software, as well as computer sub-systems.
Hardware generally includes at least processor-capable platforms, such as client-machines (also known as personal computers or servers), and hand-held processing devices (such as smart phones, PDAs, and personal computing devices (PCDs), for example). Furthermore, hardware typically includes any physical device that is capable of storing machine-readable instructions, such as memory or other data storage devices. Other forms of hardware include hardware sub-systems, including transfer devices such as modems, modem cards, ports, and port cards, for example. Hardware may also include, at least within the scope of the present disclosure, multi-modal technology, such as those devices and/or systems configured to allow users to utilize multiple forms of input and output—including voice, keypads, and stylus—interchangeably in the same interaction, application, or interface.
Software may include any machine code stored in any memory medium, such as RAM or ROM, machine code stored on other devices (such as floppy disks, CDs or DVDs, for example), and may include executable code, an operating system, as well as source or object code, for example. In addition, software may encompass any set of instructions capable of being executed in a client machine or server—and, in this form, is often called a program or executable code.
Hybrids (combinations of software and hardware) are becoming more common as devices for providing enhanced functionality and performance to computer systems. A hybrid may be created when what are traditionally software functions are directly manufactured into a silicon chip—this is possible since software may be assembled and compiled into ones and zeros, and, similarly, ones and zeros can be represented directly in silicon. Typically, the hybrid (manufactured hardware) functions are designed to operate seamlessly with software. Accordingly, it should be understood that hybrids and other combinations of hardware and software are also included within the definition of a computer system herein, and are thus envisioned by the present disclosure as possible equivalent structures and equivalent methods.
Computer-readable mediums may include passive data storage such as a random access memory (RAM), as well as semi-permanent data storage such as a compact disk or DVD. In addition, an embodiment of the present disclosure may be embodied in the RAM of a computer and effectively transform a standard computer into a new specific computing machine.
Data structures are defined organizations of data that may enable an embodiment of the present disclosure. For example, a data structure may provide an organization of data or an organization of executable code (executable software). Furthermore, data signals are carried across transmission mediums and store and transport various data structures, and, thus, may be used to transport an embodiment of the invention. It should be noted in the discussion herein that acts with like names may be performed in like manners, unless otherwise stated.
The controllers and/or systems of the present disclosure may be designed to work on any specific architecture. For example, the controllers and/or systems may be executed on one or more computers, Ethernet networks, local area networks, wide area networks, internets, intranets, hand-held and other portable and wireless devices and networks.
Moreover, methods within the scope of the present disclosure may be local or remote in nature. These methods, and any controllers discussed herein, may be achieved by one or more intelligent adaptive controllers, programmable logic controllers, artificial neural networks, and/or other adaptive and/or “learning” controllers or processing apparatus. For example, such methods may be deployed or performed via PLC, PAC, PC, one or more servers, desktops, handhelds, and/or any other form or type of computing device with appropriate capability.
As used herein, the term “substantially” means that a numerical amount is within about 20 percent, preferably within about 10 percent, and more preferably within about 5 percent of a stated value. In a preferred embodiment, these terms refer to amounts within about 1 percent, within about 0.5 percent, or even within about 0.1 percent, of a stated value.
The term “about,” as used herein, should generally be understood to refer to both numbers in a range of numerals. For example, “about 1 to 2” should be understood as “about 1 to about 2.” Moreover, all numerical ranges herein should be understood to include each whole integer, or 1/10 of an integer, within the range.
The present disclosure also incorporates herein in its entirety by express reference thereto each of the following references: U.S. Pat. No. 9,784,089 to Boone et al; and U.S. patent application Ser. No. 15/603,784 filed May 24, 2016.
The foregoing outlines features of several embodiments so that those of ordinary-skill in the art may better understand the aspects of the present disclosure. Those of ordinary-skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those of ordinary-skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.
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