Patent Grant
11795806
This application is directed to methods and systems for the creation of wells, such as oil or gas wells, and more particularly to the planning and drilling of such wells, such as using an apparatus and methods for uninterrupted drilling.
Drilling a borehole for the extraction of minerals has become an increasingly complicated operation due to the increased depth and complexity of many boreholes, including the complexity added by directional drilling. Drilling is an expensive operation and errors in drilling add to the cost and, in some cases, drilling errors may permanently lower the output of a well for years into the future. Conventional technologies and methods may not adequately address the complicated nature of drilling, and may not be capable of gathering and processing various information from downhole sensors and surface control systems in a timely manner, in order to improve drilling operations and minimize drilling errors.
In one aspect, a drilling rig system for automated slide drilling is disclosed. The drilling rig system may further include a drilling rig having at least one control system, a drill string coupled to the drilling rig, a drill bit coupled to a first end of the drill string, and a computer system in communication with and operable to control the at least one control system of the drilling rig. In the drilling rig system, the computer system may further include a processor, a memory, and instructions stored in the memory that are capable of execution by the processor. In the drilling rig system, the computer system may be adapted to receive at least one input during operation of the drilling rig, while the instructions may be adapted to perform the following operations: (i) determine that the drilling rig is to enter a slide drilling mode to perform a slide drilling operation in connection with drilling a wellbore, (ii) begin the slide drilling operation either from a rotary drilling mode or after a connection of a pipe or pipe stand to the drill string has been made, (iii) establish a torque value in the drill string, (iv) engage a bottom of the wellbore with the drill bit, (v) determine a target tool face for the slide drilling operation, (vi) maintain the target tool face within predetermined limits during the slide drilling operation, (vii) control the slide drilling mode until the computer system determines that the slide drilling operation is complete, (viii) resume rotary drilling mode or prepare for a survey at an upcoming end of a current drill pipe stand, and (ix) set at least one parameter associated with at least one of: an equipment parameter, a drilling parameter, and a formation parameter.
In any of the disclosed implementations of the drilling rig system, the computer system may be adapted to perform any one or more of the operations (i)-(ix) after first obtaining a user input to proceed.
In any of the disclosed implementations of the drilling rig system, the computer system may be adapted to perform any one or more of the operations (i)-(ix) after first providing a display of the operation or operations to be performed.
In any of the disclosed implementations of the drilling rig system, the at least one input may include at least one of: input from a surface sensor, input from a downhole sensor, and a user input.
In any of the disclosed implementations of the drilling rig system, the user input may be associated with at least one of: the equipment parameter, the drilling parameter, and the formation parameter.
In any of the disclosed implementations of the drilling rig system, the at least one equipment parameter may include information relating to at least one of: a type of drill bit, and a type of bottom hole assembly.
In any of the disclosed implementations of the drilling rig system, the at least one drilling parameter may include at least one of: weight on bit, rate of penetration, motor torque, motor speed, mechanical specific energy, and pressure differential.
In any of the disclosed implementations of the drilling rig system, the at least one formation parameter may include at least one of: a formation hardness, a formation structure, inclination, a current wellbore zone, a measured depth, a vertical section, and a formation identity.
In any of the disclosed implementations of the drilling rig system, the instructions adapted to perform (iii) may further include instructions for determining the torque value for the drill string for the slide drilling operation, and outputting a first control signal to the at least one control system to establish the torque value.
In any of the disclosed implementations of the drilling rig system, the instructions adapted to perform (v) may further include instructions for determining a target tool face for the slide drilling operation, and outputting a second control signal to the at least one control system to establish the target tool face.
In another aspect, an automated slide drilling system for drilling a well borehole is disclosed. The automated slide drilling system may include at least one processor, and at least one memory coupled to the at least one processor and storing instructions executable by the at least one processor. In the automated slide drilling system, the instructions may include instructions for receiving information from a measurement-while-drilling (MWD) system, at least one sensor, and at least one rig control system during drilling of a well borehole by a drilling rig. In the automated slide drilling system, the drilling rig may further include a drill string having a bottom hole assembly attached thereto at one end thereof. In the automated slide drilling system, the instructions may further include instructions for determining, responsive to the information received, whether a slide is to be performed and, when the slide is to be performed, determining a length and a direction of the slide, determining a current tool face, determining when a tool face adjustment is indicated for the slide and, when the tool face adjustment is indicated, determining an amount of the tool face adjustment, and sending a first control signal to the at least one drilling rig control system to adjust the tool face by the amount of the tool face adjustment. In the automated slide drilling system, the instructions may further include instructions for determining if oscillation of the drill string will assist the slide and, when the oscillation will assist the slide, identifying a magnitude and a frequency of the oscillation, and sending a second control signal to the at least one drilling rig control system to implement the magnitude and the frequency of the oscillation. In the automated slide drilling system, the instructions may further include instructions for sending a third control signal to the at least one drilling rig control system to rotate the drill bit, maintaining the tool face within a target range during the slide, and determining if the slide is complete and, when the slide is complete, sending a fourth control signal to the at least one drilling rig control system to stop the slide.
In any of the disclosed implementations, the automated slide drilling system may further include instructions for establishing a desired torque in the drill string.
In any of the disclosed implementations, the automated slide drilling system may further include comprising instructions for engaging a bottom of the well borehole with the drill bit.
In any of the disclosed implementations, the automated slide drilling system may further include instructions for resuming rotary drilling after the slide is complete.
In any of the disclosed implementations, the automated slide drilling system may further include instructions for returning control of drilling to another drilling control system or to an operator after the slide is complete.
In any of the disclosed implementations, the automated slide drilling system may further include instructions for displaying a status of the slide during the slide.
In any of the disclosed implementations, the automated slide drilling system may further include instructions for receiving updated information from the MWD system, the at least one sensor, and the at least one rig control systems during the slide, and determining whether at least one drilling parameter should be adjusted for the slide, and, when the at least one drilling parameter is to be adjusted, sending a fifth control signal to adjust the one or more drilling parameters.
In any of the disclosed implementations, the automated slide drilling system may further include instructions for receiving updated information from the MWD system, the at least one sensor, and the at least one rig control system during the slide, and, responsive to at least some of the updated information, displaying an updated status of the slide during the slide.
In any of the disclosed implementations the automated slide drilling system, the at least one sensor may include at least one of: a downhole sensor and a surface sensor.
In any of the disclosed implementations the automated slide drilling system, the instructions may further include instructions for providing a graphical user interface further including at least one of: a plot of current toolface versus a target toolface, a plot of toolface limits, and an indication of a confidence level of at least one toolface reading.
In any of the disclosed implementations the automated slide drilling system, the instructions may further include instructions for obtaining a confidence level from a decoder receiving information from a bottom hole assembly (BHA).
In any of the disclosed implementations the automated slide drilling system, the instructions may further include instructions for comparing a current toolface reading with a previous toolface reading and, based on a difference between the current toolface reading and the previous toolface reading, and the confidence level, determining whether to take an action to correct the toolface.
In another aspect of the disclosure, a computer software program may be provided, wherein the computer software program may comprise instructions in source code or in executable or interpretable form (or a combination of forms) for performing the steps described above with respect to the automated slide drilling system, and may exist as one or more files that may be stored on any type of computer readable media, including a CD, a DVD, a jump or pen drive, a USB drive, in volatile or non-volatile memory, or may be embedded in whole or in part on a semiconductor device.
In still a further aspect, a first method for drilling a well borehole is disclosed. The first method may include determining, by an automated slide drilling system, that a drilling rig should begin slide drilling. In the first method, the slide drilling may be controlled by the automated slide drilling system in communication with at least one control system of the drilling rig. The first method may further include determining, by the automated slide drilling system, whether an operator has indicated that the slide drilling is to be performed without further user input. When the slide drilling is to be performed without further user input, the first method may include determining, by the automated slide drilling system, whether at least one risk mitigation action is indicated. When at least one risk mitigation action is indicated, the first method may include identifying and performing the at least one risk mitigation action. The first method may also include determining, by the automated slide drilling system, a torque in the drill string, setting, by the automated slide drilling system, at least one drilling rig parameter to establish the torque in the drill string, controlling, by the automated slide drilling system, engagement of a drill bit with a bottom of the well borehole, including zeroing the weight on bit (WOB) and differential pressure (ΔP) values, determining, by the automated slide drilling system, a target range for a tool face orientation for the slide drilling, controlling, by the automated slide drilling system, an orientation of the drill bit within the target range for the tool face orientation, including sending a first control signal to the at least one control system to achieve the tool face orientation within the target range, controlling, by the automated slide drilling system, at least one rig operating parameter during the slide drilling, and determining, by the automated slide drilling system, whether the slide drilling has been completed. When the slide drilling has been completed, the first method may include ceasing the slide drilling by the automated slide drilling system and returning control of the drilling rig to the operator or another control system. When the slide drilling has not been completed, the first method may then include continuing the controlling, by the automated slide drilling system, of the at least one operating parameter until the slide drilling has been completed.
In any of the disclosed implementations, the first method may further include receiving, by the automated slide drilling system, input information from at least one surface sensor or at least one downhole sensor during the slide drilling.
In any of the disclosed implementations, the first method may further include querying, by the automated slide drilling system, updated data during the slide drilling from at least one of: a bit guidance system, a measurement-while-drilling directional system, and the at least one rig control systems.
In any of the disclosed implementations, the first method may further include determining, by the automated slide drilling system, if oscillation of the drill pipe is expected to improve the slide drilling. When oscillation of the drill pipe is expected to improve the slide drilling, the first method may include determining, by the automated slide drilling system, a magnitude and a frequency of oscillation of the drill pipe, and sending, by the automated slide drilling system without further user input, a second control signal to the at least one rig control system to set the magnitude and the frequency during the slide drilling.
In any of the disclosed implementations, the first method may further include stopping, by the automated slide drilling system, the slide drilling when user input corresponding to a stop command is received.
In any of the disclosed implementations, the first method may further include stopping, by the automated slide drilling system, the slide drilling when input information is not received within a predetermined period.
In any of the disclosed implementations of the first method, the risk mitigation action may further include waiting for an indication from an operator that the slide drilling is to proceed before allowing the slide drilling to be performed.
In any of the disclosed implementations of the first method, the at least one control system may further include a first control system for a top drive of the drilling rig, and a second control system for a draw works of the drilling rig. In the first method, the risk mitigation action may further include using the automated slide drilling system to communicate with the first control system and the second control system to control the top drive and the draw works, respectively, during the slide drilling.
In yet another aspect, a second method for maintaining tool face orientation during drilling is disclosed. The second method may include, determining, by a computer system, whether to modify a rate of penetration (ROP) of a drill bit in a borehole. Responsive to the determining, the second method may include sending, by a computer system, a first signal to at least one control system coupled to a drilling rig to modify at least one of a weight on bit (WOB) and a differential pressure (ΔP) of a drilling fluid in the borehole to respectively modify the ROP by an ROP offset determined by the computer system, and sending, by the computer system, a second signal to the at least one control system for adjusting an angular rotation of a top drive of the drilling rig to modify the ROP by the ROP offset, wherein a tool face orientation within a desired range of a target tool face orientation is maintained.
In any of the disclosed implementations of the second method, the second method may be performed by a processor executing computer software instructions, while the instructions may include instructions for maintaining the tool face orientation within the desired range by sending the second signal for adjusting the angular rotation of the top drive by an amount corresponding to the ROP offset.
In any of the disclosed implementations of the second method, the amount of angular rotation may be adjusted after a predetermined time interval after the WOB or ΔP is modified.
In any of the disclosed implementations of the second method, the predetermined time interval may be determined responsive to the length of a drill string in the borehole.
In yet another aspect, a control system for maintaining tool face orientation during drilling is disclosed. The control system may include a processor, a memory coupled to the processor. In the control system, the memory may store computer software instructions executable by the processor, while the instructions may include instructions for determining, by the control system when coupled to a drilling rig, whether to modify a rate of penetration (ROP) of a drill bit in a borehole drilled by the drilling rig, and, when modifying the ROP is indicated, determining an amount to modify the ROP, determining whether to modify at least one of a weight on bit (WOB) and a differential pressure (ΔP) of a drilling fluid in the borehole to modify the ROP, determining an amount of angular rotation of a top drive of the drilling rig that corresponds to the ROP when modified, adjusting an angular rotation of the top drive, respectively, corresponding to the ROP when modified, and modifying at least one of the WOB and the ΔP to achieve the amount to modify the ROP.
In any of the disclosed implementations of the control system, the instructions may further include instructions for maintaining, without further user input, a tool face orientation within a range of a target tool face orientation by adjusting the angular rotation of the top drive by an amount calculated to offset the amount to modify the ROP.
In any of the disclosed implementations of the control system, the instructions for modifying the at least one of the WOB and the ΔP may further include instructions for modifying at least one of the WOB and the ΔP after a time interval has elapsed after the angular rotation of the top drive has been adjusted.
In any of the disclosed implementations of the control system, the time interval may be determined responsive to the length of a drill string in the borehole.
In still a further aspect, a third method is disclosed for drilling a well borehole. The third method may include determining, by an automated slide drilling system, that a drilling rig should begin slide drilling, wherein the slide drilling is controlled by the automated slide drilling system in communication with at least one control system of the drilling rig, determining, by the automated slide drilling system, whether an operator has indicated that the slide drilling is to be performed without further user input, determining, by the automated slide drilling system, a torque in the drill string, setting, by the automated slide drilling system, at least one drilling rig parameter to establish the torque in the drill string, controlling, by the automated slide drilling system, engagement of a drill bit with a bottom of the well borehole, determining, by the automated slide drilling system, a target range for a tool face orientation for the slide drilling, controlling, by the automated slide drilling system, an orientation of the drill bit within the target range for the tool face orientation, including sending a first control signal to the at least one control system to achieve the tool face orientation within the target range, controlling, by the automated slide drilling system, at least one rig operating parameter during the slide drilling, and determining, by the automated slide drilling system, whether the slide drilling has been completed. When the slide drilling has been completed, the third method may include ceasing the slide drilling by the automated slide drilling system and returning control of the drilling rig to the operator or another control system. When the slide drilling has not been completed, the third method may then include continuing the controlling, by the automated slide drilling system, of the at least one operating parameter until the slide drilling has been completed.
In any of the disclosed implementations, the third method may further include receiving, by the automated slide drilling system, input information from at least one surface sensor or at least one downhole sensor during the slide drilling.
In any of the disclosed implementations, the third method may further include querying, by the automated slide drilling system, updated data during the slide drilling from at least one of: a bit guidance system, a measurement-while-drilling directional system, and the at least one rig control systems.
In any of the disclosed implementations, the third method may further include determining, by the automated slide drilling system, if oscillation of the drill pipe is expected to improve the slide drilling. When oscillation of the drill pipe is expected to improve the slide drilling, the third method may include determining, by the automated slide drilling system, a magnitude and a frequency of oscillation of the drill pipe, and sending, by the automated slide drilling system without further user input, a second control signal to the at least one rig control system to set the magnitude and the frequency during the slide drilling.
In any of the disclosed implementations, the third method may further include stopping, by the automated slide drilling system, the slide drilling when user input corresponding to a stop command is received.
In any of the disclosed implementations, the third method may further include stopping, by the automated slide drilling system, the slide drilling when input information is not received within a predetermined period.
In any of the disclosed implementations of the third method, the risk mitigation action may further include waiting for an indication from an operator that the slide drilling is to proceed before allowing the slide drilling to be performed.
In any of the disclosed implementations of the third method, the at least one control system may include a first control system for a top drive of the drilling rig, and a second control system for a draw works of the drilling rig, while the method may further include using the automated slide drilling system to communicate with the first control system and the second control system to control the top drive and the draw works, respectively, during the slide drilling.
In yet another aspect, a control system for controlling a drilling operation is disclosed. The control system may further include a database comprising a plurality of data relating to a plurality of drilling parameters. In the control system, the database may be updated during drilling of a borehole. The control system may further include a processor coupled to the database and a memory accessible to the processor and storing instructions executable by the processor. In the control system, the instructions may be executable for, during slide drilling, detecting an increase to a first differential pressure (ΔP) that is greater than a first threshold pressure and less than a second threshold pressure. Responsive to detecting the first ΔP, the instructions may further be executable for detecting a variance in a toolface angle error greater than a first threshold variance. In the control system, responsive to detecting the variance of the toolface angle, the instructions may further be executable for detecting within a first threshold period, a reduction in the variance greater than the first threshold variance. Responsive to detecting the reduction in the variance, the instructions may further be executable for generating an output to a user indicating that the variance of the toolface angle is not associated with interrupting the slide drilling.
In any of the disclosed embodiments of the control system, the instructions for detecting the reduction in the variance may further include instructions for detecting a decrease to a second ΔP that is less than the first threshold pressure.
In any of the disclosed embodiments of the control system, the plurality of drilling parameters may include at least one of: weight on bit, rate of penetration, differential pressure, mud flow rate, torque, and rate of oscillation.
In any of the disclosed embodiments of the control system, the database may further include information relating to equipment used for the drilling, and formation characteristics for one or more formations drilled, being drilled, or to be drilled.
In any of the disclosed embodiments of the control system, the instructions for detecting the increase to the first ΔP may further include instructions for determining that a top drive torque has not increased greater than a first threshold torque.
In still another aspect, a fourth method for controlling drilling operations is disclosed. The fourth method may include, during slide drilling under control of a steering control system enabled to monitor a plurality of drilling parameters, detecting an increase to a first differential pressure (ΔP) that is greater than a first threshold pressure and less than a second threshold pressure. Responsive to detecting the first ΔP, the fourth method may further include detecting a variance in a toolface angle error greater than a first threshold variance. Responsive to detecting the variance of the toolface angle, detecting within a first threshold period, a reduction in the variance greater than the first threshold variance. Responsive to detecting the reduction in the variance, the fourth method may further include displaying, by the steering control system, an output to a user indicating that the variance of the toolface angle is not associated with interrupting the slide drilling.
In any of the disclosed embodiments of the fourth method, detecting the reduction in the variance may further include detecting a decrease to a second ΔP that is less than the first threshold pressure.
In any of the disclosed embodiments of the fourth method, the plurality of drilling parameters may include at least one of: weight on bit, rate of penetration, differential pressure, mud flow rate, torque, and rate of oscillation.
In any of the disclosed embodiments of the fourth method, the database may further include information relating to equipment used for the drilling, and formation characteristics for one or more formations drilled, being drilled, or to be drilled.
In any of the disclosed embodiments of the fourth method, detecting the increase to the first ΔP may further include determining that a top drive torque has not increased greater than a first threshold torque.
In still another aspect, a fifth method for controlling drilling operations is disclosed. The fifth method may include, during drilling of a borehole, receiving, by a control system, a first differential pressure (ΔP) value, and receiving, by the control system, a second ΔP value. The fifth method may further include determining, by the control system, a variance between the first ΔP value and the second ΔP value. Responsive to the variance between the first ΔP value and the second ΔP value, the fifth method may further include determining, by the control system, if a correction of one or more drilling operations is indicated, and when the correction is indicated, the fifth method may further include sending, by the control system, one or more signals to initiate the correction of one or more drilling operations.
In any of the disclosed embodiments of the fifth method, the determining if a correction of one or more drilling operations is indicated may further include determining whether the variance between the first ΔP value and the second ΔP value exceeds a threshold for the variance.
In any of the disclosed embodiments of the fifth method, the determining if a correction of one or more drilling operations is indicated may further include determining whether the variance between the first ΔP value and the second ΔP value falls within an acceptable range for the variance.
In any of the disclosed embodiments, the fifth method may further include repeating at least some of the operations in the fifth method a plurality of times during drilling of the borehole.
In any of the disclosed embodiments, the fifth method may further include, during drilling of the borehole, receiving, by the control system, a first value associated with a toolface angle, determining, by the control system, if the first value associated with the toolface angle exceeds a first threshold for the toolface angle. In the fifth method, the determining, by the control system, if a correction of one or more drilling operations is indicated, may be responsive to the variance between the first ΔP value and the second ΔP value and to the determining if the first value associated with the toolface angle exceeds the threshold for the toolface angle.
In any of the disclosed embodiments, the fifth method may further include, receiving, by the control system, a second value associated with a toolface angle, determining, by the control system, a second variance between the first value associated with the toolface angle and the second value associated with the toolface angle, determining, by the control system, whether the second variance between the first value associated with the toolface angle and the second value associated with the toolface angle within a first threshold period is indicative of a correction of one or more drilling operations.
In any of the disclosed embodiments of the fifth method, the correction of one or more drilling operations may further include at least one of: ceasing drilling, adjusting one or more drilling parameters, wherein the drilling parameters comprise at least one of: weight on bit, rate of penetration, differential pressure, mud flow rate, torque, and rate of oscillation.
In any of the disclosed embodiments of the fifth method, the determining, by the control system, if the correction of one or more drilling operations is indicated may further include determining, by the control system, whether a top drive torque value increase within a first time period exceeds a threshold value for the top drive torque.
For a more complete understanding, reference is now made to the following description taken in conjunction with the accompanying drawings in which:
Referring now to the drawings, wherein like reference numbers are used herein to designate like elements throughout, the various views and embodiments of a system and method for surface steerable drilling are illustrated and described, and other possible embodiments are described. The figures are not necessarily drawn to scale, and in some instances the drawings have been exaggerated and/or simplified in places for illustrative purposes only. Many possible applications and variations may be based on the following examples of possible embodiments.
Referring to
It is understood the regions 112, 114, 116, and 118 may vary in size and shape depending on the characteristics by which they are identified. Furthermore, the regions 112, 114, 116, and 118 may be sub-regions of a larger region. Accordingly, the criteria by which the regions 112, 114, 116, and 118 are identified is less important for purposes of the present disclosure than the understanding that each region 112, 114, 116, and 118 includes geological characteristics that can be used to distinguish each region from the other regions from a drilling perspective. Such characteristics may be relatively major (e.g., the presence or absence of an entire rock layer in a given region) or may be relatively minor (e.g., variations in the thickness of a rock layer that extends through multiple regions).
Accordingly, drilling a well located in the same region as other wells, such as drilling a new well in the region 112 with already existing wells 102 and 104, means the drilling process is likely to face similar drilling issues as those faced when drilling the existing wells in the same region. For similar reasons, a drilling process performed in one region is likely to face issues different from a drilling process performed in another region. However, even the drilling processes that created the wells 102 and 104 may face different issues during actual drilling as variations in the formation are likely to occur even in a single region.
Drilling a well typically involves a substantial amount of human decision making during the drilling process. For example, geologists and drilling engineers use their knowledge, experience, and the available information to make decisions on how to plan the drilling operation, how to accomplish the plan, and how to handle issues that arise during drilling. However, even the best geologists and drilling engineers perform some guesswork due to the unique nature of each borehole. Furthermore, a directional driller directly responsible for the drilling may have drilled other boreholes in the same region and so may have some similar experience, but it is impossible for a human to mentally track all the possible inputs and factor those inputs into a decision. This can result in expensive mistakes, as errors in drilling can add hundreds of thousands or even millions of dollars to the drilling cost and, in some cases, drilling errors may permanently lower the output of a well, resulting in substantial long-term losses.
In the present example, to aid in the drilling process, each well 102, 104, 106, and 108 has corresponding collected data 120, 122, 124, and 126, respectively. The collected data may include the geological characteristics of a particular formation in which the corresponding well was formed, the attributes of a particular drilling rig, including the bottom hole assembly (BHA), and drilling information such as weight-on-bit (WOB), drilling speed, and/or other information pertinent to the formation of that particular borehole. The drilling information may be associated with a particular depth or other identifiable marker so that, for example, it is recorded that drilling of the well 102 from 1000 feet to 1200 feet occurred at a first ROP through a first rock layer with a first WOB, while drilling from 1200 feet to 1500 feet occurred at a second ROP through a second rock layer with a second WOB. The collected data may be used to recreate the drilling process used to create the corresponding well 102, 104, 106, or 108 in the particular formation. It is understood that the accuracy with which the drilling process can be recreated depends on the level of detail and accuracy of the collected data.
The collected data 120, 122, 124, and 126 may be stored in a centralized regional database 128 as indicated by lines 130, 132, 134, and 136, respectively, which may represent any wired and/or wireless communication channel(s). The regional database 128 may be located at a drilling hub (not shown) or elsewhere. Alternatively, the data may be stored on a removable storage medium that is later coupled to the regional database 128 in order to store the data. The collected data 120, 122, 124, and 126 may be stored in the regional database 128 as formation data 138, equipment data 140, and drilling data 142 for example. Formation data 138 may include any formation information, such as rock type, layer thickness, layer location (e.g., depth), porosity, gamma readings, etc. Equipment data 140 may include any equipment information, such as drilling rig configuration (e.g., rotary table or top drive), bit type, mud composition, etc. Drilling data 142 may include any drilling information, such as drilling speed, WOB, differential pressure, tool face orientation, etc. The collected data may also be identified by well, region, and other criteria, and may be sortable to enable the data to be searched and analyzed. It is understood that many different storage mechanisms may be used to store the collected data in the regional database 128.
With additional reference to
Current drilling techniques frequently involve directional drilling to reach a target, such as the target 180. The use of directional drilling generally increases the amount of reserves that can be obtained and also increases production rate, sometimes significantly. For example, the directional drilling used to provide the horizontal portion shown in
With additional reference to
The build rate depends on factors such as the formation through which the borehole 164 is to be drilled, the trajectory of the borehole 164, the particular pipe and drill collars/BHA components used (e.g., length, diameter, flexibility, strength, mud motor bend setting, and drill bit), the mud type and flow rate, the required horizontal displacement, stabilization, and inclination. An overly aggressive built rate can cause problems such as severe doglegs (e.g., sharp changes in direction in the borehole) that may make it difficult or impossible to run casing or perform other needed tasks in the borehole 164. Depending on the severity of the mistake, the borehole 164 may require enlarging or the bit may need to be backed out and a new passage formed. Such mistakes cost time and money. However, if the built rate is too cautious, significant additional time may be added to the drilling process as it is generally slower to drill a curve than to drill straight. Furthermore, drilling a curve is more complicated and the possibility of drilling errors increases (e.g., overshoot and undershoot that may occur trying to keep the bit on the planned path).
Two modes of drilling, known as rotating and sliding, are commonly used to form the borehole 164. Rotating, also called rotary drilling, uses a top drive or rotary table to rotate the drill string. Rotating is used when drilling is to occur along a straight path. Sliding, also called steering, uses a downhole mud motor with an adjustable bent housing and does not rotate the drill string. Instead, sliding uses hydraulic power to drive the downhole motor and bit. Sliding is used in order to control well direction.
The conventional approach to accomplish a slide can be briefly summarized as follows. First, the rotation of the drill string is stopped. Based on feedback from measuring equipment such as a MWD tool, adjustments are made to the drill string. These adjustments continue until the downhole tool face that indicates the direction of the bend of the mud motor is oriented to the direction of the desired deviation of the borehole. Once the desired orientation is accomplished, pressure is applied to the drill bit, which causes the drill bit to move in the direction of deviation. Once sufficient distance and angle have been built, a transition back to rotating mode is accomplished by rotating the drill string. This rotation of the drill string neutralizes the directional deviation caused by the bend in the mud motor as it continuously rotates around the centerline of the borehole.
Referring again to
The controller 144 may form all or part of a surface steerable system. The regional database 128 may also form part of the surface steerable system. As will be described in greater detail below, the surface steerable system may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. The surface steerable system may be used to perform such operations as receiving drilling data representing a drill path and other drilling parameters, calculating a drilling solution for the drill path based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at the drilling rig 110, monitoring the drilling process to gauge whether the drilling process is within a defined margin of error of the drill path, and/or calculating corrections for the drilling process if the drilling process is outside of the margin of error.
Referring to
The drilling rig 110 may also include a sensor system 214 for obtaining sensor data about the drilling operation and the drilling rig 110, including the downhole equipment. For example, the sensor system 214 may include measuring while drilling (MWD) and/or logging while drilling (LWD) components for obtaining information, such as tool face and/or formation logging information, that may be saved for later retrieval, transmitted with a delay or in real time using any of various communication means (e.g., wireless, wireline, or mud pulse telemetry), or otherwise transferred to the controller 144. Such information may include information related to hole depth, bit depth, inclination, azimuth, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotary rotations per minute (RPM), bit speed, ROP, WOB, and/or other information. It is understood that all or part of the sensor system 214 may be physically incorporated into one or more of the control systems 208, 210, and 212, and/or in the drilling equipment 218. As the drilling rig 110 may be configured in many different ways, it is understood that these control systems may be different in some embodiments, and may be combined or further divided into various subsystems.
The controller 144 receives input information 202. The input information 202 may include information that is pre-loaded, received, and/or updated in real time. The input information 202 may include a well plan, regional formation history, one or more drilling engineer parameters, MWD tool face/inclination information, LWD gamma/resistivity information, economic parameters, reliability parameters, and/or other decision guiding parameters. Some of the inputs, such as the regional formation history, may be available from a drilling hub 216, which may include the regional database 128 of
The controller 144 also provides output information 203. As will be described later in greater detail, the output information 203 may be stored in the controller 144 and/or sent offsite (e.g., to the regional database 128). The output information 203 may be used to provide updates to the regional database 128, as well as provide alerts, request decisions, and convey other data related to the drilling process.
Referring to
The user interface 250 provides visual indicators such as a hole depth indicator 252, a bit depth indicator 254, a GAMMA indicator 256, an inclination indicator 258, an azimuth indicator 260, and a TVD indicator 262. Other indicators may also be provided, including a ROP indicator 264, a mechanical specific energy (MSE) indicator 266, a differential pressure indicator 268, a standpipe pressure indicator 270, a flow rate indicator 272, a rotary RPM indicator 274, a bit speed indicator 276, and a WOB indicator 278.
Some or all of the indicators 264, 266, 268, 270, 272, 274, 276, and/or 278 may include a marker representing a target value. For purposes of example, markers are set as the following values, but it is understood that any desired target value may be representing. For example, the ROP indicator 264 may include a marker 265 indicating that the target value is fifty ft./hr. The MSE indicator 266 may include a marker 267 indicating that the target value is thirty-seven ksi. The differential pressure indicator 268 may include a marker 269 indicating that the target value is two hundred psi. The ROP indicator 264 may include a marker 265 indicating that the target value is fifty ft./hr. The standpipe pressure indicator 270 may have no marker in the present example. The flow rate indicator 272 may include a marker 273 indicating that the target value is five hundred gpm. The rotary RPM indicator 274 may include a marker 275 indicating that the target value is zero RPM (due to sliding). The bit speed indicator 276 may include a marker 277 indicating that the target value is one hundred and fifty RPM. The WOB indicator 278 may include a marker 279 indicating that the target value is ten klbs. Although only labeled with respect to the indicator 264, each indicator may include a colored band or another marking to indicate, for example, whether the respective gauge value is within a safe range (e.g., indicated by a green color), within a caution range (e.g., indicated by a yellow color), or within a danger range (e.g., indicated by a red color). Although not shown, in some embodiments, multiple markers may be present on a single indicator. The markers may vary in color and/or size.
A log chart 280 may visually indicate depth versus one or more measurements (e.g., may represent log inputs relative to a progressing depth chart). For example, the log chart 280 may have a y-axis representing depth and an x-axis representing a measurement such as GAMMA count 281 (as shown), ROP 283 (e.g., empirical ROP and normalized ROP), or resistivity. An autopilot button 282 and an oscillate button 284 may be used to control activity. For example, the autopilot button 282 may be used to engage or disengage an autopilot, while the oscillate button 284 may be used to directly control oscillation of the drill string or engage/disengage an external hardware device or controller via software and/or hardware.
A circular chart 286 may provide current and historical tool face orientation information (e.g., which way the bend is pointed). For purposes of illustration, the circular chart 286 represents three hundred and sixty degrees. A series of circles within the circular chart 286 may represent a timeline of tool face orientations, with the sizes of the circles indicating the temporal position of each circle. For example, larger circles may be more recent than smaller circles, so the largest circle 288 may be the newest reading and the smallest circle 286 may be the oldest reading. In other embodiments, the circles may represent the energy and/or progress made via size, color, shape, a number within a circle, etc. For example, the size of a particular circle may represent an accumulation of orientation and progress for the period of time represented by the circle. In other embodiments, concentric circles representing time (e.g., with the outside of the circular chart 286 being the most recent time and the center point being the oldest time) may be used to indicate the energy and/or progress (e.g., via color and/or patterning such as dashes or dots rather than a solid line).
The circular chart 286 may also be color coded, with the color coding existing in a band 290 around the circular chart 286 or positioned or represented in other ways. The color coding may use colors to indicate activity in a certain direction. For example, the color red may indicate the highest level of activity, while the color blue may indicate the lowest level of activity. Furthermore, the arc range in degrees of a color may indicate the amount of deviation. Accordingly, a relatively narrow (e.g., thirty degrees) arc of red with a relatively broad (e.g., three hundred degrees) arc of blue may indicate that most activity is occurring in a particular tool face orientation with little deviation. For purposes of illustration, the color blue extends from approximately 22-337 degrees, the color green extends from approximately 15-22 degrees and 337-345 degrees, the color yellow extends a few degrees around the 13 and 345 degree marks, and the color red extends from approximately 347-10 degrees. Transition colors or shades may be used with, for example, the color orange marking the transition between red and yellow and/or a light blue marking the transition between blue and green.
This color coding enables the user interface 250 to provide an intuitive summary of how narrow the standard deviation is and how much of the energy intensity is being expended in the proper direction. Furthermore, the center of energy may be viewed relative to the target. For example, the user interface 250 may clearly show that the target is at ninety degrees but the center of energy is at forty-five degrees.
Other indicators may be present, such as a slide indicator 292 to indicate how much time remains until a slide occurs and/or how much time remains for a current slide. For example, the slide indicator may represent a time, a percentage (e.g., current slide is fifty-six percent complete), a distance completed, and/or a distance remaining. The slide indicator 292 may graphically display information using, for example, a colored bar 293 that increases or decreases with the slide's progress. In some embodiments, the slide indicator may be built into the circular chart 286 (e.g., around the outer edge with an increasing/decreasing band), while in other embodiments the slide indicator may be a separate indicator such as a meter, a bar, a gauge, or another indicator type. In various implementations, slide indicator 292 may be refreshed by an automated slide drilling system.
An error indicator 294 may be present to indicate a magnitude and/or a direction of error. For example, the error indicator 294 may indicate that the estimated drill bit position is a certain distance from the planned path, with a location of the error indicator 294 around the circular chart 286 representing the heading. For example,
It is understood that the user interface 250 may be arranged in many different ways. For example, colors may be used to indicate normal operation, warnings, and problems. In such cases, the numerical indicators may display numbers in one color (e.g., green) for normal operation, may use another color (e.g., yellow) for warnings, and may use yet another color (e.g., red) if a serious problem occurs. The indicators may also flash or otherwise indicate an alert. The gauge indicators may include colors (e.g., green, yellow, and red) to indicate operational conditions and may also indicate the target value (e.g., an ROP of 100 ft./hr). For example, the ROP indicator 268 may have a green bar to indicate a normal level of operation (e.g., from 10-300 ft./hr), a yellow bar to indicate a warning level of operation (e.g., from 300-360 ft./hr), and a red bar to indicate a dangerous or otherwise out of parameter level of operation (e.g., from 360-390 ft./hr). The ROP indicator 268 may also display a marker at 100 ft./hr to indicate the desired target ROP.
Furthermore, the use of numeric indicators, gauges, and similar visual display indicators may be varied based on factors such as the information to be conveyed and the personal preference of the viewer. Accordingly, the user interface 250 may provide a customizable view of various drilling processes and information for a particular individual involved in the drilling process. For example, the surface steerable system 201 may enable a user to customize the user interface 250 as desired, although certain features (e.g., standpipe pressure) may be locked to prevent removal. This locking may prevent a user from intentionally or accidentally removing important drilling information from the display. Other features may be set by preference. Accordingly, the level of customization and the information shown by the user interface 250 may be controlled based on who is viewing the display and their role in the drilling process.
Referring again to
However, a newer or more sophisticated drilling rig 110, such as a rig that has electronic control systems, may have interfaces with which the controller 144 can interact for direct control. For example, an electronic control system may have a defined interface and the controller 144 may be configured to interact with that defined interface. It is understood that, in some embodiments, direct control may not be allowed even if possible. For example, the controller 144 may be configured to display the setting on a screen for approval, and may then send the setting to the appropriate control system only when the setting has been approved.
Referring to
The individuals involved in the drilling process may include a drilling engineer 302, a geologist 304, a directional driller 306, a tool pusher 308, a driller 310, and a rig floor crew 312. One or more company representatives (e.g., company men) 314 may also be involved. The individuals may be employed by different organizations, which can further complicate the communication process. For example, the drilling engineer 302, geologist 304, and company man 314 may work for an operator, the directional driller 306 may work for a directional drilling service provider, and the tool pusher 308, driller 310, and rig floor crew 312 may work for a rig service provider.
The drilling engineer 302 and geologist 304 are often located at a location remote from the drilling rig (e.g., in a home office/drilling hub). The drilling engineer 302 may develop a well plan 318 and may make drilling decisions based on drilling rig information. The geologist 304 may perform such tasks as formation analysis based on seismic, gamma, and other data. The directional driller 306 is generally located at the drilling rig and provides instructions to the driller 310 based on the current well plan and feedback from the drilling engineer 302. The driller 310 handles the actual drilling operations and may rely on the rig floor crew 312 for certain tasks. The tool pusher 308 may be in charge of managing the entire drilling rig and its operation.
The following is one possible example of a communication process within the environment 300, although it is understood that many communication processes may be used. The use of a particular communication process may depend on such factors as the level of control maintained by various groups within the process, how strictly communication channels are enforced, and similar factors. In the present example, the directional driller 306 uses the well plan 318 to provide drilling instructions to the driller 310. The driller 310 controls the drilling using control systems such as the control systems 208, 210, and 212 of
The drilling engineer 302/well planner (not shown), either alone or in conjunction with the geologist 306, may modify the well plan 318 or make other decisions based on the received information. The modified well plan and/or other decisions may or may not be passed through the company man 314 to the directional driller 306, who then tells the driller 310 how to drill. The driller 310 may modify equipment settings (e.g., tool face orientation) and, if needed, pass orders on to the rig floor crew 312. For example, a change in WOB may be performed by the driller 310 changing a setting, while a bit trip may require the involvement of the rig floor crew 312. Accordingly, the level of involvement of different individuals may vary depending on the nature of the decision to be made and the task to be performed. The proceeding example may be more complex than described. Multiple intermediate individuals may be involved and, depending on the communication chain, some instructions may be passed through the tool pusher 308.
The environment 300 presents many opportunities for communication breakdowns as information is passed through the various communication channels, particularly given the varying types of communication that may be used. For example, verbal communications via phone may be misunderstood and, unless recorded, provide no record of what was said. Furthermore, accountability may be difficult or impossible to enforce as someone may provide an authorization but deny it or claim that they meant something else. Without a record of the information passing through the various channels and the authorizations used to approve changes in the drilling process, communication breakdowns can be difficult to trace and address. As many of the communication channels illustrated in
Even if everyone involved does their part, drilling mistakes may be amplified while waiting for an answer. For example, a message may be sent to the geologist 306 that a formation layer seems to be higher than expected, but the geologist 306 may be asleep. Drilling may continue while waiting for the geologist 306 and the continued drilling may amplify the error. Such errors can cost hundreds of thousands or millions of dollars. However, the environment 300 provides no way to determine if the geologist 304 has received the message and no way to easily notify the geologist 304 or to contact someone else when there is no response within a defined period of time. Even if alternate contacts are available, such communications may be cumbersome and there may be difficulty in providing all the information that the alternate would need for a decision.
Referring to
The drilling hub 216 is remote from the controller 144, and various individuals associated with the drilling operation interact either through the drilling hub 216 or through the controller 144. In some embodiments, an individual may access the drilling project through both the drilling hub 216 and controller 144. For example, the directional driller 306 may use the drilling hub 216 when not at the drilling site or the controller 144 is remotely located and may use the controller 144 when at the drilling site when the controller 144 is located on-site.
The drilling engineer 302 and geologist 304 may access the surface steerable system 201 remotely via the portal 406 and set various parameters such as rig limit controls. Other actions may also be supported, such as granting approval to a request by the directional driller 306 to deviate from the well plan and evaluating the performance of the drilling operation. The directional driller 306 may be located either at the drilling rig 110 or off-site. Being off-site (e.g., at the drilling hub 216, remotely located controller or elsewhere) enables a single directional driller to monitor multiple drilling rigs. When off-site, the directional driller 306 may access the surface steerable system 201 via the portal 406. When on-site, the directional driller 306 may access the surface steerable system via the controller 144.
The driller 310 may get instructions via the controller 144, thereby lessening the possibly of miscommunication and ensuring that the instructions were received. Although the tool pusher 308, rig floor crew 312, and company man 314 are shown communicating via the driller 310, it is understood that they may also have access to the controller 144. Other individuals, such as a MWD hand 408, may access the surface steerable system 201 via the drilling hub 216, the controller 144, and/or an individual such as the driller 310.
As illustrated in
In some embodiments, documentation produced using the surface steerable system 201 may be synchronized and/or merged with other documentation, such as that produced by third party systems such as the WellView product produced by Peloton Computer Enterprises Ltd. of Calgary, Canada. In such embodiments, the documents, database files, and other information produced by the surface steerable system 201 is synchronized to avoid such issues as redundancy, mismatched file versions, and other complications that may occur in projects where large numbers of documents are produced, edited, and transmitted by a relatively large number of people.
The surface steerable system 201 may also impose mandatory information formats and other constraints to ensure that predefined criteria are met. For example, an electronic form provided by the surface steerable system 201 in response to a request for authorization may require that some fields are filled out prior to submission. This ensures that the decision maker has the relevant information prior to making the decision. If the information for a required field is not available, the surface steerable system 201 may require an explanation to be entered for why the information is not available (e.g., sensor failure). Accordingly, a level of uniformity may be imposed by the surface steerable system 201, while exceptions may be defined to enable the surface steerable system 201 to handle various scenarios.
The surface steerable system 201 may also send alerts (e.g., email or text alerts) to notify one or more individuals of a particular problem, and the recipient list may be customized based on the problem. Furthermore, contact information may be time-based, so the surface steerable system 201 may know when a particular individual is available. In such situations, the surface steerable system 201 may automatically attempt to communicate with an available contact rather than waiting for a response from a contact that is likely not available.
As described previously, the surface steerable system 201 may present a customizable display of various drilling processes and information for a particular individual involved in the drilling process. For example, the drilling engineer 302 may see a display that presents information relevant to the drilling engineer's tasks, and the geologist 304 may see a different display that includes additional and/or more detailed formation information. This customization enables each individual to receive information needed for their particular role in the drilling process while minimizing or eliminating unnecessary information.
Referring to
In block 504, a geological survey is performed. The survey results are reviewed by the geologist 304 and a formation report 506 is produced. The formation report 506 details formation layers, rock type, layer thickness, layer depth, and similar information that may be used to develop a well plan. In block 508, a well plan is developed by a well planner 524 and/or the drilling engineer 302 based on the formation report and information from the regional database 128 at the drilling hub 216. Block 508 may include selection of a BHA and the setting of control limits. The well plan is stored in the regional database 128. The drilling engineer 302 may also set drilling operation parameters in step 510 that are also stored in the regional database 128.
In the other branch, the drilling rig 110 is constructed in block 512. At this point, as illustrated by block 526, the well plan, BHA information, control limits, historical drilling data, and control commands may be sent from the regional database 128 to the local database 410. Using the receiving information, the directional driller 306 inputs actual BHA parameters in block 514. The company man 314 and/or the directional driller 306 may verify performance control limits in block 516, and the control limits are stored in the local database 410 of the controller 144. The performance control limits may include multiple levels such as a warning level and a critical level corresponding to no action taken within feet/minutes.
Once drilling begins, a diagnostic logger (described later in greater detail) 520 that is part of the controller 144 logs information related to the drilling such as sensor information and maneuvers and stores the information in the local database 410 in block 526. The information is sent to the regional database 128. Alerts are also sent from the controller 144 to the drilling hub 216. When an alert is received by the drilling hub 216, an alert notification 522 is sent to defined individuals, such as the drilling engineer 302, geologist 304, and company man 314. The actual recipient may vary based on the content of the alert message or other criteria. The alert notification 522 may result in the well plan and the BHA information and control limits being modified in block 508 and parameters being modified in block 510. These modifications are saved to the regional database 128 and transferred to the local database 410. The BHA may be modified by the directional driller 306 in block 518, and the changes propagated through blocks 514 and 516 with possible updated control limits. Accordingly, the surface steerable system 201 may provide a more controlled flow of information than may occur in an environment without such a system.
The flow charts described herein illustrate various exemplary functions and operations that may occur within various environments. Accordingly, these flow charts are not exhaustive and that various steps may be excluded to clarify the aspect being described. For example, it is understood that some actions, such as network authentication processes, notifications, and handshakes, may have been performed prior to the first step of a flow chart. Such actions may depend on the particular type and configuration of communications engaged in by the controller 144 and/or drilling hub 216. Furthermore, other communication actions may occur between illustrated steps or simultaneously with illustrated steps.
The surface steerable system 201 includes large amounts of data specifically related to various drilling operations as stored in databases such as the databases 128 and 410. As described with respect to
For example, in equipment comparison, data from different drilling operations (e.g., from drilling the wells 102, 104, 106, and 108) may be normalized and used to compare equipment wear, performance, and similar factors. For example, the same bit may have been used to drill the wells 102 and 106, but the drilling may have been accomplished using different parameters (e.g., rotation speed and WOB). By normalizing the data, the two bits can be compared more effectively. The normalized data may be further processed to improve drilling efficiency by identifying which bits are most effective for particular rock layers, which drilling parameters resulted in the best ROP for a particular formation, ROP versus reliability tradeoffs for various bits in various rock layers, and similar factors. Such comparisons may be used to select a bit for another drilling operation based on formation characteristics or other criteria. Accordingly, by mining and analyzing the data available via the surface steerable system 201, an optimal equipment profile may be developed for different drilling operations. The equipment profile may then be used when planning future wells or to increase the efficiency of a well currently being drilled. This type of drilling optimization may become increasingly accurate as more data is compiled and analyzed.
In drilling plan formulation, the data available via the surface steerable system 201 may be used to identify likely formation characteristics and to select an appropriate equipment profile. For example, the geologist 304 may use local data obtained from the planned location of the drilling rig 110 in conjunction with regional data from the regional database 128 to identify likely locations of the layers 168A-176A (
Referring to
In step 602, the on-site controller 144 receives inputs, such as a planned path for a borehole, formation information for the borehole, equipment information for the drilling rig, and a set of cost parameters. The cost parameters may be used to guide decisions made by the controller 144 as will be explained in greater detail below. The inputs may be received in many different ways, including receiving document (e.g., spreadsheet) uploads, accessing a database (e.g., the regional database 128 of
In step 604, the planned path, the formation information, the equipment information, and the set of cost parameters are processed to produce control parameters (e.g., the control information 204 of
In step 606, the control parameters are output for use by the drilling rig 110. In embodiments where the controller 144 is directly coupled to the drilling rig 110, outputting the control parameters may include sending the control parameters directly to one or more of the control systems of the drilling rig 110 (e.g., the control systems 210, 212, and 214). In other embodiments, outputting the control parameters may include displaying the control parameters on a screen, printing the control parameters, and/or copying them to a storage medium (e.g., a Universal Serial Bus (USB) drive) to be transferred manually.
In step 608, feedback information received from the drilling rig 110 (e.g., from one or more of the control systems 208, 210, and 212 and/or sensor system 214) is processed. The feedback information may provide the on-site controller 144 with the current state of the borehole (e.g., depth and inclination), the drilling rig equipment, and the drilling process, including an estimated position of the bit in the borehole. The processing may include extracting desired data from the feedback information, normalizing the data, comparing the data to desired or ideal parameters, determining whether the data is within a defined margin of error, and/or any other processing steps needed to make use of the feedback information.
In step 610, the controller 144 may take action based on the occurrence of one or more defined events. For example, an event may trigger a decision on how to proceed with drilling in the most cost effective manner. Events may be triggered by equipment malfunctions, path differences between the measured borehole and the planned borehole, upcoming maintenance periods, unexpected geological readings, and any other activity or non-activity that may affect drilling the borehole. It is understood that events may also be defined for occurrences that have a less direct impact on drilling, such as actual or predicted labor shortages, actual or potential licensing issues for mineral rights, actual or predicted political issues that may impact drilling, and similar actual or predicted occurrences. Step 610 may also result in no action being taken if, for example, drilling is occurring without any issues and the current control parameters are satisfactory.
An event may be defined in the received inputs of step 602 or defined later. Events may also be defined on site using the controller 144. For example, if the drilling rig 110 has a particular mechanical issue, one or more events may be defined to monitor that issue in more detail than might ordinarily occur. In some embodiments, an event chain may be implemented where the occurrence of one event triggers the monitoring of another related event. For example, a first event may trigger a notification about a potential problem with a piece of equipment and may also activate monitoring of a second event. In addition to activating the monitoring of the second event, the triggering of the first event may result in the activation of additional oversight that involves, for example, checking the piece of equipment more frequently or at a higher level of detail. If the second event occurs, the equipment may be shut down and an alarm sounded, or other actions may be taken. This enables different levels of monitoring and different levels of responses to be assigned independently if needed.
Referring to
Accordingly, in step 710, a determination is made as to whether an event has occurred based on the inputs of steps 702 and 708. If no event has occurred, the method 700 returns to step 708. If an event has occurred, the method 700 moves to step 712, where calculations are performed based on the information relating to the event and at least one cost parameter. It is understood that additional information may be obtained and/or processed prior to or as part of step 712 if needed. For example, certain information may be used to determine whether an event has occurred, and additional information may then be retrieved and processed to determine the particulars of the event.
In step 714, new control parameters may be produced based on the calculations of step 712. In step 716, a determination may be made as to whether changes are needed in the current control parameters. For example, the calculations of step 712 may result in a decision that the current control parameters are satisfactory (e.g., the event may not affect the control parameters). If no changes are needed, the method 700 returns to step 708. If changes are needed, the controller 144 outputs the new parameters in step 718. The method 700 may then return to step 708. In some embodiments, the determination of step 716 may occur before step 714. In such embodiments, step 714 may not be executed if the current control parameters are satisfactory.
In a more detailed example of the method 700, assume that the controller 144 is involved in drilling a borehole and that approximately six hundred feet remain to be drilled. An event has been defined that warns the controller 144 when the drill bit is predicted to reach a minimum level of efficiency due to wear and this event is triggered in step 710 at the six hundred foot mark. The event may be triggered because the drill bit is within a certain number of revolutions before reaching the minimum level of efficiency, within a certain distance remaining (based on strata type, thickness, etc.) that can be drilled before reaching the minimum level of efficiency, or may be based on some other factor or factors. Although the event of the current example is triggered prior to the predicted minimum level of efficiency being reached in order to proactively schedule drilling changes if needed, it is understood that the event may be triggered when the minimum level is actually reached.
The controller 144 may perform calculations in step 712 that account for various factors that may be analyzed to determine how the last six hundred feet is drilled. These factors may include the rock type and thickness of the remaining six hundred feet, the predicted wear of the drill bit based on similar drilling conditions, location of the bit (e.g., depth), how long it will take to change the bit, and a cost versus time analysis. Generally, faster drilling is more cost effective, but there are many tradeoffs. For example, increasing the WOB or differential pressure to increase the rate of penetration may reduce the time it takes to finish the borehole, but may also wear out the drill bit faster, which will decrease the drilling effectiveness and slow the drilling down. If this slowdown occurs too early, it may be less efficient than drilling more slowly. Therefore, there is a tradeoff that must be calculated. Too much WOB or differential pressure may also cause other problems, such as damaging downhole tools. Should one of these problems occur, taking the time to trip the bit or drill a sidetrack may result in more total time to finish the borehole than simply drilling more slowly, so faster may not be better. The tradeoffs may be relatively complex, with many factors to be considered.
In step 714, the controller 144 produces new control parameters based on the solution calculated in step 712. In step 716, a determination is made as to whether the current parameters should be replaced by the new parameters. For example, the new parameters may be compared to the current parameters. If the two sets of parameters are substantially similar (e.g., as calculated based on a percentage change or margin of error of the current path with a path that would be created using the new control parameters) or identical to the current parameters, no changes would be needed. However, if the new control parameters call for changes greater than the tolerated percentage change or outside of the margin of error, they are output in step 718. For example, the new control parameters may increase the WOB and also include the rate of mud flow significantly enough to override the previous control parameters. In other embodiments, the new control parameters may be output regardless of any differences, in which case step 716 may be omitted. In still other embodiments, the current path and the predicted path may be compared before the new parameters are produced, in which case step 714 may occur after step 716.
Referring to
In step 730, a comparison may be made to compare the estimated bit position and trajectory with a desired point (e.g., a desired bit position) along the planned path. The estimated bit position may be calculated based on information such as a survey reference point and/or represented as an output calculated by a borehole estimator (as will be described later) and may include a bit projection path and/or point that represents a predicted position of the bit if it continues its current trajectory from the estimated bit position. Such information may be included in the inputs of step 722 and feedback information of step 728 or may be obtained in other ways. It is understood that the estimated bit position and trajectory may not be calculated exactly, but may represent an estimate the current location of the drill bit based on the feedback information. As illustrated in
In step 732, a determination may be made as to whether the estimated bit position 743 is within a defined margin of error of the desired bit position. If the estimated bit position is within the margin of error, the method 720 returns to step 728. If the estimated bit position is not within the margin of error, the on-site controller 144 calculates a convergence plan in step 734. With reference to
In some embodiments, a projected bit position (not shown) may also be used. For example, the estimated bit position 743 may be extended via calculations to determine where the bit is projected to be after a certain amount of drilling (e.g., time and/or distance). This information may be used in several ways. If the estimated bit position 743 is outside the margin of error, the projected bit position 743 may indicate that the current bit path will bring the bit within the margin of error without any action being taken. In such a scenario, action may be taken only if it will take too long to reach the projected bit position when a more optimal path is available. If the estimated bit position is inside the margin of error, the projected bit position may be used to determine if the current path is directing the bit away from the planned path. In other words, the projected bit position may be used to proactively detect that the bit is off course before the margin of error is reached. In such a scenario, action may be taken to correct the current path before the margin of error is reached.
The convergence plan identifies a plan by which the bit can be moved from the estimated bit position 743 to the planned path 742. It is noted that the convergence plan may bypass the desired bit position 741 entirely, as the objective is to get the actual drilling path back to the planned path 742 in the most optimal manner. The most optimal manner may be defined by cost, which may represent a financial value, a reliability value, a time value, and/or other values that may be defined for a convergence path.
As illustrated in
A fourth path 756 may begin at a projected point or bit position 755 that lies along the projected path 752 and result in a convergence point 757, which represents a mid-range convergence point. The path 756 may be used by, for example, delaying a trajectory change until the bit reaches the position 755. Many additional convergence options may be opened up by using projected points for the basis of convergence plans as well as the estimated bit position.
A fifth path 758 may begin at a projected point or bit position 760 that lies along the projected path 750 and result in a convergence point 759. In such an embodiment, different convergence paths may include similar or identical path segments, such as the similar or identical path shared by the convergence points 751 and 759 to the point 760. For example, the point 760 may mark a position on the path 750 where a slide segment begins (or continues from a previous slide segment) for the path 758 and a straight line path segment begins (or continues) for the path 750. The controller 144 may calculate the paths 750 and 758 as two entirely separate paths or may calculate one of the paths as deviating from (e.g., being a child of) the other path. Accordingly, any path may have multiple paths deviating from that path based on, for example, different slide points and slide times.
Each of these paths 744, 746, 748, 750, 756, and 758 may present advantages and disadvantages from a drilling standpoint. For example, one path may be longer and may require more sliding in a relatively soft rock layer, while another path may be shorter but may require more sliding through a much harder rock layer. Accordingly, tradeoffs may be evaluated when selecting one of the convergence plans rather than simply selecting the most direct path for convergence. The tradeoffs may, for example, consider a balance between ROP, total cost, dogleg severity, and reliability. While the number of convergence plans may vary, there may be hundreds or thousands of convergence plans in some embodiments and the tradeoffs may be used to select one of those hundreds or thousands for implementation. The convergence plans from which the final convergence plan is selected may include plans calculated from the estimated bit position 743 as well as plans calculated from one or more projected points along the projected path.
In some embodiments, straight line projections of the convergence point vectors, after correction to the well plan 742, may be evaluated to predict the time and/or distance to the next correction requirement. This evaluation may be used when selecting the lowest total cost option by avoiding multiple corrections where a single more forward thinking option might be optimal. As an example, one of the solutions provided by the convergence planning may result in the most cost effective path to return to the well plan 742, but may result in an almost immediate need for a second correction due to a pending deviation within the well plan. Accordingly, a convergence path that merges the pending deviation with the correction by selecting a convergence point beyond the pending deviation might be selected when considering total well costs.
It is understood that the diagram 740 of
Referring again to
Referring to
In step 802, multiple solution vectors are calculated from the current position 743 to the planned path 742. These solution vectors may include the paths 744, 746, 748, and 750. Additional paths (not shown in
In step 804, any solution vectors that fall outside of defined limits are rejected, such as solution vectors that fall outside the lower limit 753 and the upper limit 754. For example, the path 744 would be rejected because the convergence point 745 falls outside of the lower limit 753. It is understood that the path 744 may be rejected for an engineering reason (e.g., the path would require a dogleg of greater than allowed severity) prior to cost considerations, or the engineering reason may be considered a cost.
In step 806, a cost is calculated for each remaining solution vector. As illustrated in
By weighting the costs, the cost matrix can be customized to handle many different cost scenarios and desired results. For example, if time is of primary importance, a time cost may be weighted over financial and reliability costs to ensure that a solution vector that is faster will be selected over other solution vectors that are substantially the same but somewhat slower, even though the other solution vectors may be more beneficial in terms of financial cost and reliability cost. In some embodiments, step 804 may be combined with step 808 and solution vectors falling outside of the limits may be given a cost that ensures they will not be selected. In step 810, the solution vector corresponding to the minimum cost is selected.
Referring to
In step 824, a reason for the error may be determined as the surface steerable system 201 and its data may provide an environment in which the prediction error can be evaluated. For example, if a bit did not drill as expected, the method 820 may examine many different factors, such as whether the rock formation was different than expected, whether the drilling parameters were correct, whether the drilling parameters were correctly entered by the driller, whether another error and/or failure occurred that caused the bit to drill poorly, and whether the bit simply failed to perform. By accessing and analyzing the available data, the reason for the failure may be determined.
In step 826, a solution may be determined for the error. For example, if the rock formation was different than expected, the regional database 128 may be updated with the correct rock information and new drilling parameters may be obtained for the drilling rig 110. Alternatively, the current bit may be tripped and replaced with another bit more suitable for the rock. In step 828, the current drilling predictions (e.g., well plan, build rate, slide estimates) may be updated based on the solution and the solution may be stored in the regional database 128 for use in future predictions. Accordingly, the method 820 may result in benefits for future wells as well as improving current well predictions.
Referring to
In step 834, a forecast may be made as to the impact of the event. For example, the surface steerable system 201 may determine whether the projected build rate needed to land the curve can be met based on the twenty foot difference. This determination may include examining the current location of the bit, the projected path, and similar information.
In step 836, modifications may be made based on the forecast. For example, if the projected build rate can be met, then modifications may be made to the drilling parameters to address the formation depth difference, but the modifications may be relatively minor. However, if the projected build rate cannot be met, the surface steerable system 201 may determine how to address the situation by, for example, planning a bit trip to replace the current BHA with a BHA capable of making a new and more aggressive curve.
Such decisions may be automated or may require input or approval by the drilling engineer 302, geologist 304, or other individuals. For example, depending on the distance to the kick off point, the surface steerable system 201 may first stop drilling and then send an alert to an authorized individual, such as the drilling engineer 302 and/or geologist 304. The drilling engineer 302 and geologist 304 may then become involved in planning a solution or may approve of a solution proposed by the surface steerable system 201 (see
It is understood that such recalibration forecasts may be performed based on many different factors and may be triggered by many different events. The forecasting portion of the process is directed to anticipating what changes may be needed due to the recalibration and calculating how such changes may be implemented. Such forecasting provides cost advantages because more options may be available when a problem is detected earlier rather than later. Using the previous example, the earlier the difference in the depth of the layer is identified, the more likely it is that the build rate can be met without changing the BHA.
Referring to
Accordingly, in step 842, one or more target parameters are identified. For example, the target parameter may be an MSE of 50 ksi or an ROP of 100 ft./hr that the controller 144 is to establish and maintain. In step 844, a plurality of control parameters are identified for use with the drilling operation. The control parameters are selected to meet the target MSE of 50 ksi or ROP of 100 ft./hr. The drilling operation is started with the control parameters, which may be used until the target MSE or ROP is reached. In step 846, feedback information is received from the drilling operation when the control parameters are being used, so the feedback represents the performance of the drilling operation as controlled by the control parameters. Historical information may also be used in step 846. In step 848, an operational baseline is established based on the feedback information.
In step 850, at least one of the control parameters is changed to modify the drilling operation, although the target MSE or ROP should be maintained. For example, some or all of the control parameters may be associated with a range of values and the value of one or more of the control parameters may be changed. In step 852, more feedback information is received, but this time the feedback reflects the performance of the drilling operation with the changed control parameter. In step 854, a performance impact of the change is determined with respect to the operational baseline. The performance impact may occur in various ways, such as a change in MSE or ROP and/or a change in vibration. In step 856, a determination is made as to whether the control parameters are optimized. If the control parameters are not optimized, the method 840 returns to step 850. If the control parameters are optimized, the method 840 moves to step 858. In step 858, the optimized control parameters are used for the current drilling operation with the target MSE or ROP and stored (e.g., in the regional database 128) for use in later drilling operations and operational analyses. This may include linking formation information to the control parameters in the regional database 128.
Referring to
It is understood that the controller 144 may perform certain computations to prevent errors or inaccuracies from accumulating and throwing off calculations. For example, as will be described later, the input driver 902 may receive Wellsite Information Transfer Specification (WITS) input representing absolute pressure, while the controller 144 needs differential pressure and needs an accurate zero point for the differential pressure. Generally, the driller will zero out the differential pressure when the drill string is positioned with the bit off bottom and full pump flow is occurring. However, this may be a relatively sporadic event. Accordingly, the controller 144 may recognize when the bit is off bottom and target flow rate has been achieved and zero out the differential pressure.
Another computation may involve block height, which needs to be calibrated properly. For example, block height may oscillate over a wide range, including distances that may not even be possible for a particular drilling rig. Accordingly, if the reported range is sixty feet to one hundred and fifty feet and there should only be one hundred feet, the controller 144 may assign a zero value to the reported sixty feet and a one hundred foot value to the reported one hundred and fifty feet. Furthermore, during drilling, error gradually accumulates as the cable is shifted and other events occur. The controller 144 may compute its own block height to predict when the next connection occurs and other related events, and may also take into account any error that may be introduced by cable issues.
Referring specifically to
The input driver 902 may receive various types of input, including rig sensor input (e.g., from the sensor system 214 of
The database query and update engine/diagnostic logger 910 receives input from the input driver 902, the GCL 914, and ACL 916, and provides output to the local database 912 and GUI 906. The database query and update engine/diagnostic logger 910 is configured to manage the archiving of data to the local database 912. The database query and update engine/diagnostic logger 910 may also manage some functional requirements of a remote synchronization server (RSS) via the remote synchronization interface 904 for archiving data that will be uploaded and synchronized with a remote database, such as the regional database 128 of
The local database 912 receives input from the database query and update engine/diagnostic logger 910 and the remote synchronization interface 904, and provides output to the GCL 914, the ACL 916, and the remote synchronization interface 904. It is understood that the local database 912 may be configured in many different ways. As described in previous embodiments, the local database 912 may store both current and historic information representing both the current drilling operation with which the controller 144 is engaged as well as regional information from the regional database 128.
The GCL 914 receives input from the input driver 902 and the local database 912, and provides output to the database query and update engine/diagnostic logger 910, the GUI 906, and the ACL 916. Although not shown, in some embodiments, the GCL 906 may provide output to the output driver 908, which enables the GCL 914 to directly control third party systems and/or interface with the drilling rig alone or with the ACL 916. An embodiment of the GCL 914 is discussed below with respect to
The ACL 916 receives input from the input driver 902, the local database 912, and the GCL 914, and provides output to the database query and update engine/diagnostic logger 910 and output driver 908. An embodiment of the ACL 916 is discussed below with respect to
The output interface 918 receives input from the input driver 902, the GCL 914, and the ACL 916. In the present example, the GUI 906 receives input from the input driver 902 and the GCL 914. The GUI 906 may display output on a monitor or other visual indicator. The output driver 908 receives input from the ACL 916 and is configured to provide an interface between the controller 144 and external control systems, such as the control systems 208, 210, and 212 of
It is understood that the system architecture 900 of
Referring to
The WITS parser 1006 in the system architecture 1000 may be configured in accordance with a specification such as WITS and/or using a standard such as Wellsite Information Transfer Standard Markup Language (WITSML). WITS is a specification for the transfer of drilling rig-related data and uses a binary file format. WITS may be replaced or supplemented in some embodiments by WITSML, which relies on extensible Markup Language (XML) for transferring such information. The WITS parser 1006 in input driver 1020 may feed into the database query and update engine/diagnostic logger 1022, which may be similar or analogous to logger 910. Accordingly, the WITS parser 1020 may also output various parameters, shown as block 1010, that may be available to and represent feedback to the GCL 914 and GUI 906 (see
Referring to
The build rate predictor 1102 may receive external input representing BHA and geological information, receives internal input from the borehole estimator 1106, and provides output to the geo modified well planner 1104, slide estimator 1108, slide planner 1114, and convergence planner 1116. The build rate predictor 1102 is configured to use the BHA and geological information to predict the drilling build rates of current and future sections of a well. For example, the build rate predictor 1102 may determine how aggressively the curve will be built for a given formation with given BHA and other equipment parameters.
The build rate predictor 1102 may use the orientation of the BHA to the formation to determine an angle of attack for formation transitions and build rates within a single layer of a formation. For example, if there is a layer of rock with a layer of sand above it, there is a formation transition from the sand layer to the rock layer. Approaching the rock layer at a ninety degree angle may provide a good face and a clean drill entry, while approaching the rock layer at a forty-five degree angle may build a curve relatively quickly. An angle of approach that is near parallel may cause the bit to skip off the upper surface of the rock layer. Accordingly, the build rate predictor 1102 may calculate BHA orientation to account for formation transitions. Within a single layer, the build rate predictor 1102 may use BHA orientation to account for internal layer characteristics (e.g., grain) to determine build rates for different parts of a layer.
The BHA information may include bit characteristics, mud motor bend setting, stabilization and mud motor bit to bend distance. The geological information may include formation data such as compressive strength, thicknesses, and depths for formations encountered in the specific drilling location. Such information enables a calculation-based prediction of the build rates and ROP that may be compared to both real-time results (e.g., obtained while drilling the well) and regional historical results (e.g., from the regional database 128) to improve the accuracy of predictions as the drilling progresses. Future formation build rate predictions may be used to plan convergence adjustments and confirm that targets can be achieved with current variables in advance.
The geo modified well planner 1104 may receive external input representing a well plan, internal input from the build rate predictor 1102 and the geo drift estimator 1112, and provides output to the slide planner 1114 and the error vector calculator 1110. The geo modified well planner 1104 uses the input to determine whether there is a more optimal path than that provided by the external well plan while staying within the original well plan error limits. More specifically, the geo modified well planner 1104 takes geological information (e.g., drift) and calculates whether another solution to the target may be more efficient in terms of cost and/or reliability. The outputs of the geo modified well planner 1104 to the slide planner 1114 and the error vector calculator 1110 may be used to calculate an error vector based on the current vector to the newly calculated path and to modify slide predictions.
In some embodiments, the geo modified well planner 1104 (or another module) may provide functionality needed to track a formation trend. For example, in horizontal wells, the geologist 304 may provide the controller 144, which may control surface steerable drilling, with a target inclination that the controller 144 is to attempt to hold. For example, the geologist 304 (see
In some embodiments, the geo modified well planner 1104 may be an optional module that is not used unless the well plan is to be modified. For example, if the well plan is marked in the surface steerable system 201 as non-modifiable, the geo modified well planner 1104 may be bypassed altogether or the geo modified well planner 1104 may be configured to pass the well plan through without any changes.
The borehole estimator 1106 may receive external inputs representing BHA information, measured depth information, survey information (e.g., azimuth and inclination), and may provide outputs to the build rate predictor 1102, the error vector calculator 1110, and the convergence planner 1116. The borehole estimator 1106 may be configured to provide a real time or near real time estimate of the actual borehole and drill bit position and trajectory angle. This estimate may use both straight line projections and projections that incorporate sliding. The borehole estimator 1106 may be used to compensate for the fact that a sensor is usually physically located some distance behind the bit (e.g., fifty feet), which makes sensor readings lag the actual bit location by fifty feet. The borehole estimator 1106 may also be used to compensate for the fact that sensor measurements may not be continuous (e.g., a sensor measurement may occur every one hundred feet).
The borehole estimator 1106 may use two techniques to accomplish this. First, the borehole estimator 1106 may provide the most accurate estimate from the surface to the last survey location based on the collection of all survey measurements. Second, the borehole estimator 1106 may take the slide estimate from the slide estimator 1108 (described below) and extend this estimation from the last survey point to the real time drill bit location. Using the combination of these two estimates, the borehole estimator 1106 may provide the on-site controller 144 with an estimate of the drill bit's location and trajectory angle from which guidance and steering solutions can be derived. An additional metric that can be derived from the borehole estimate is the effective build rate that is achieved throughout the drilling process. For example, the borehole estimator 1106 may calculate the current bit position and trajectory 743, as described above with respect to
The slide estimator 1108 may receive external inputs representing measured depth and differential pressure information, receives internal input from the build rate predictor 1102, and provides output to the borehole estimator 1106 and the geo modified well planner 1104. The slide estimator 1108, which may operate in real time or near real time, may be configured to sample tool face orientation, differential pressure, measured depth (MD) incremental movement, MSE, and other sensor feedback to quantify/estimate a deviation vector and progress while sliding.
Traditionally, deviation from the slide would be predicted by a human operator based on experience. The operator would, for example, use a long slide cycle to assess what likely was accomplished during the last slide. However, the results are generally not confirmed until the MWD survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by the distance of the sensor point from the drill bit tip (e.g., approximately fifty feet). This lag introduces inefficiencies in the slide cycles due to over/under correction of the actual path relative to the planned path.
With the slide estimator 1108, each tool face update may be algorithmically merged with the average differential pressure of the period between the previous and current tool faces, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during that period. As an example, the periodic rate may be between ten (10) and sixty (60) seconds per cycle depending on the tool face update rate of the MWD tool. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of the slide estimator 1108 may accordingly be periodically provided to the borehole estimator 1106 for accumulation of well deviation information, as well to the geo modified well planner 1104. Some or all of the output of the slide estimator 1108 may be output via a display, such as shown in the user interface 250 of
The error vector calculator 1110 may receive internal input from the geo modified well planner 1104 and the borehole estimator 1106. The error vector calculator 1110 may be configured to compare the planned well path to the actual borehole path and drill bit position estimate. The error vector calculator 1110 may provide the metrics used to determine the error (e.g., how far off) the current drill bit position and trajectory are from the plan. For example, the error vector calculator 1110 may calculate the error between the current bit position and trajectory 743 of
The geological drift estimator 1112 may receive external input representing geological information and provides outputs to the geo modified well planner 1104, slide planner 1114, and tactical solution planner 1118. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of drilling rate and BHA. The geological drift estimator 1112 is configured to provide a drift estimate as a vector. This vector can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution.
The slide planner 1114 may receive internal input from the build rate predictor 1102, the geo modified well planner 1104, the error vector calculator 1110, and the geological drift estimator 1112, and provides output to the convergence planner 1116 as well as an estimated time to the next slide. The slide planner 1114 may be configured to evaluate a slide/drill ahead cost equation and plan for sliding activity, which may include factoring in BHA wear, expected build rates of current and expected formations, and the well plan path. During drill ahead, the slide planner 1114 may attempt to forecast an estimated time of the next slide to aid with planning. For example, if additional lubricants (e.g., fluorinated beads) are needed for the next slide and pumping the lubricants into the drill string needs to begin thirty minutes before the slide, the estimated time of the next slide may be calculated and then used to schedule when to start pumping the lubricants.
Functionality for a loss circulation material (LCM) planner may be provided as part of the slide planner 1114 or elsewhere (e.g., as a stand-alone module or as part of another module described herein). The LCM planner functionality may be configured to determine whether additives need to be pumped into the borehole based on indications such as flow-in versus flow-back measurements. For example, if drilling through a porous rock formation, fluid being pumped into the borehole may get lost in the rock formation. To address this issue, the LCM planner may control pumping LCM into the borehole to clog up the holes in the porous rock surrounding the borehole to establish a more closed-loop control system for the fluid.
The slide planner 1114 may also look at the current position relative to the next connection. A connection may happen every ninety to one hundred feet (or some other distance or distance range based on the particulars of the drilling operation) and the slide planner 1114 may avoid planning a slide when close to a connection and/or when the slide would carry through the connection. For example, if the slide planner 1114 is planning a fifty foot slide but only twenty feet remain until the next connection, the slide planner 1114 may calculate the slide starting after the next connection and make any changes to the slide parameters that may be needed to accommodate waiting to slide until after the next connection. Such flexible implementation avoids inefficiencies that may be caused by starting the slide, stopping for the connection, and then having to reorient the tool face before finishing the slide. During slides, the slide planner 1114 may provide some feedback as to the progress of achieving the desired goal of the current slide.
In some embodiments, the slide planner 1114 may account for reactive torque in the drill string. More specifically, when rotating is occurring, there is a reactional torque wind up in the drill string. When the rotating is stopped, the drill string unwinds, which changes tool face orientation and other parameters. When rotating is started again, the drill string starts to wind back up. The slide planner 1114 may account for this reactional torque so that tool face references are maintained rather than stopping rotation and then trying to adjust to an optimal tool face orientation. While not all MWD tools may provide tool face orientation when rotating, using one that does supply such information for the GCL 1100 may significantly reduce the transition time from rotating to sliding.
The convergence planner 1116 receives internal inputs from the build rate predictor 1102, the borehole estimator 1106, and the slide planner 1114, and provides output to the tactical solution planner 1118. The convergence planner 1116 is configured to provide a convergence plan when the current drill bit position is not within a defined margin of error of the planned well path. The convergence plan represents a path from the current drill bit position to an achievable and optimal convergence target point along the planned path. The convergence plan may take account the amount of sliding/drilling ahead that has been planned to take place by the slide planner 1114. The convergence planner 1116 may also use BHA orientation information for angle of attack calculations when determining convergence plans as described above with respect to the build rate predictor 1102. The solution provided by the convergence planner 1116 defines a new trajectory solution for the current position of the drill bit. The solution may be real time, near real time, or future (e.g., planned for implementation at a future time). For example, the convergence planner 1116 may calculate a convergence plan as described previously with respect to
The tactical solution planner 1118 receives internal inputs from the geological drift estimator 1112 and the convergence planner 1116, and provides external outputs representing information such as tool face orientation, differential pressure, and mud flow rate. The tactical solution planner 1118 is configured to take the trajectory solution provided by the convergence planner 1116 and translate the solution into control parameters that can be used to control the drilling rig 110. For example, the tactical solution planner 1118 may take the solution and convert the solution into settings for the control systems 208, 210, and 212 to accomplish the actual drilling based on the solution. The tactical solution planner 1118 may also perform performance optimization as described previously. The performance optimization may apply to optimizing the overall drilling operation as well as optimizing the drilling itself (e.g., how to drill faster).
Other functionality may be provided by the GCL 1100 in additional modules or added to an existing module. For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole tool face. Accordingly, the GCL 1100 may receive information corresponding to the rotational position of the drill pipe on the surface. The GCL 1100 may use this surface positional information to calculate current and desired tool face orientations. These calculations may then be used to define control parameters for adjusting the top drive or Kelly drive (included in drilling equipment 218) to accomplish adjustments to the downhole tool face in order to steer the well.
For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with the GCL 1100 and/or other functionality provided by the controller 144. In the present embodiment, a drilling model class is defined to capture and define the drilling state throughout the drilling process. The class may include real-time information. This class may be based on the following components and sub-models: a drill bit model, a borehole model, a rig surface gear model, a mud pump model, a WOB/differential pressure model, a positional/rotary model, an MSE model, an active well plan, and control limits. The class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of the GCL 1100.
The drill bit model may represent the current position and state of the drill bit. This model includes a three dimensional position, a drill bit trajectory, BHA information, bit speed, and tool face (e.g., orientation information). The three dimensional position may be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The drill bit trajectory may be specified as an inclination and an azimuth angle. The BHA information may be a set of dimensions defining the active BHA. The borehole model may represent the current path and size of the active borehole. This model includes hole depth information, an array of survey points collected along the borehole path, a gamma log, and borehole diameters. The hole depth information is for the current drilling job. The borehole diameters may represent the diameters of the borehole as drilled over the current drill job.
The rig surface gear model may represent pipe length, block height, and other models, such as the mud pump model, WOB/differential pressure model, positional/rotary model, and MSE model. The mud pump model represents mud pump equipment and includes flow rate, standpipe pressure, and differential pressure. The WOB/differential pressure model represents draw works or other WOB/differential pressure controls and parameters, including WOB. The positional/rotary model represents top drive or other positional/rotary controls and parameters including rotary RPM and spindle position. The active well plan represents the target borehole path and may include an external well plan and a modified well plan. The control limits represent defined parameters that may be set as maximums and/or minimums. For example, control limits may be set for the rotary RPM in the top drive model to limit the maximum RPMs to the defined level. The control output solution may represent the control parameters for the drilling rig 110.
The main processing loop can be handled in many different ways. For example, the main processing loop can run as a single thread in a fixed time loop to handle rig sensor event changes and time propagation. If no rig sensor updates occur between fixed time intervals, a time only propagation may occur. In other embodiments, the main processing loop may be multi-threaded.
Each functional module of the GCL 1100 may have its behavior encapsulated within its own respective class definition. During its processing window, the individual units may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the modules may be in the sequence of geo modified well planner 1104, build rate predictor 1102, slide estimator 1108, borehole estimator 1106, error vector calculator 1110, slide planner 1114, convergence planner 1116, geological drift estimator 1112, and tactical solution planner 1118. It is understood that other sequences may be used in different implementations.
In
Referring to
One function of the ACL 1200 is to establish and maintain a target parameter (e.g., an ROP of a defined value of ft./hr), such as based on input from the GCL 1100. The regulation of the target parameter may be accomplished via control loops using at least one of the positional/rotary control logic block 1202, the WOB/differential pressure control logic block 1204, and the fluid circulation control logic block 1206. The positional/rotary control logic block 1202 may receive sensor feedback information from the input processor 1220 and set point information from the GCL 1100 (e.g., from the tactical solution planner 1118). The differential pressure control logic block 1204 may receive sensor feedback information from the input processor 1220 and set point information from the GCL 1100 (e.g., from the tactical solution planner 1118). The fluid circulation control logic block 1206 may receive sensor feedback information from the input processor 1220 and set point information from the GCL 1100 (e.g., from the tactical solution planner 1118).
The ACL 1200 may use the sensor feedback information and the set points from the GCL 1100 to attempt to maintain the established target parameter. More specifically, the ACL 1200 may have control over various parameters via the positional/rotary control logic block 1202, the WOB/differential pressure control logic block 1204, and the fluid circulation control logic block 1206, and may modulate the various parameters to achieve the target parameter. The ACL 1200 may also modulate the parameters in light of cost-driven and reliability-driven drilling goals, which may include parameters such as a trajectory goal, a cost goal, and/or a performance goal. It is understood that the parameters may be limited (e.g., by control limits set by the drilling engineer 306) and the ACL 1200 may vary the parameters to achieve the target parameter without exceeding the defined limits. If this is not possible, the ACL 1200 may notify the on-site controller 144 or otherwise indicate that the target parameter is currently unachievable.
In some embodiments, the ACL 1200 in
Another function of the ACL 1200 is error detection. Error detection is directed to identifying problems in the current drilling process and may monitor for sudden failures and gradual failures. In this capacity, the pattern recognition/error detection block 1208 may receive input from the input processor 1220. The input may include the sensor feedback received by the positional/rotary control logic block 1202, the WOB/differential pressure control logic block 1204, and the fluid circulation control logic block 1206. The pattern recognition/error detection block 1208 may monitor the input information for indications that a failure has occurred or for sudden changes that are illogical.
For example, a failure may be indicated by an ROP shift, a radical change in build rate, or any other significant changes. As an illustration, assume the drilling is occurring with an expected ROP of 100 ft./hr. If the ROP suddenly drops to 50 ft./hr with no change in parameters and remains there for some defined amount of time, the sudden change in ROP may be indicative of an equipment failure, formation shift, or another event. Another error may be indicated when MWD sensor feedback has been steadily indicating that drilling has been heading north for hours and the sensor feedback suddenly indicates that drilling has reversed in a few feet and is heading south. Such a change in sensor feedback may be an indication that a failure has occurred. Certain parameter or sensor value changes may be pre-defined, or the pattern recognition/error detection block 1208 may be configured to watch for deviations of a certain magnitude. The pattern recognition/error detection block 1208 may also be configured to detect deviations that occur over a period of time in order to catch more gradual failures or safety concerns, such as a slight drift of a given value.
When an error is identified based on a significant shift in input values, the controller 114 may send an alert. The alert may enable an individual to review the error and determine whether action needs to be taken. For example, if an error indicates that there is a significant loss of ROP and an intermittent change/rise in pressure, the individual may determine that mud motor chunking has likely occurred with rubber tearing off and plugging the bit. In this case, the BHA may be tripped and the damage repaired before more serious damage is done. Accordingly, the error detection may be used to identify potential issues that occur before the issues become more serious and more costly to repair.
Another function of the ACL 1200 in
Referring to
The computer system 1300 may include a central processing unit (“CPU”) 1302, a memory unit 1304, an input/output (“I/O”) device 1306, and a network interface 1308. The components 1302, 1304, 1306, and 1308 are interconnected by a transport system (e.g., a bus) 1310. A power supply (PS) 1312 may provide power to components of the computer system 1300, such as the CPU 1302 and memory unit 1304. It is understood that the computer system 1300 may be differently configured and that each of the listed components may actually represent several different components. For example, the CPU 1302 may actually represent a multi-processor or a distributed processing system; the memory unit 1304 may include different levels of cache memory, main memory, hard disks, and remote storage locations; the I/O device 1306 may include monitors, keyboards, and the like; and the network interface 1308 may include one or more network cards providing one or more wired and/or wireless connections to a network 1314. Therefore, a wide range of flexibility is anticipated in the configuration of the computer system 1300.
The computer system 1300 may use any operating system (or multiple operating systems), including various versions of operating systems provided by Microsoft (such as WINDOWS), Apple (such as Mac OS X), UNIX, and LINUX, and may include operating systems specifically developed for handheld devices, personal computers, and servers depending on the use of the computer system 1300. The operating system, as well as other instructions (e.g., software instructions for performing the functionality described in previous embodiments) may be stored in the memory unit 1304 and executed by the processor 1302. For example, if the computer system 1300 is the controller 144, the memory unit 1304 may include instructions (not shown in
Referring now to
Oil and gas wells may be drilled directionally for several purposes. An oil or gas well that is directional may follow a specific path that begins at the rotary table of the rig to intersect particular geological targets underground, and may be directional drilled for various use cases. Directional drilling may be used for drilling horizontally into shale or other formations (often referred to as an “unconventional well”). Directional drilling may be used for increasing an exposed section of a conventional reservoir by drilling through the reservoir at an angle. Directional drilling may enable drilling into the reservoir where vertical access is difficult or not possible (e.g., to reach an oilfield under a town, under a lake, or underneath a difficult-to-drill formation). Directional drilling may allow more wellheads to be grouped together on one surface location leading to fewer rig moves, less surface area disturbance, and wells that are easier and cheaper to complete and produce. For instance, on an oil platform or jack-up rig offshore, 40 or more wells can be grouped together. The wells paths may fan out from the platform into a subterranean reservoir. The use of multiple wellheads grouped together is being applied to land wells, allowing multiple subsurface locations to be reached from one pad, which can reduce costs. Directional drilling may be performed along the underside of a reservoir-constraining fault to allow multiple productive sands to be completed at the highest stratigraphic points. Directional drilling may be used for a so-called “relief well” to relieve the pressure of a well producing without restraint (i.e., a “blowout”), such as when the relief well is a second well that can be drilled starting from at a safe distance away from the blowout, in order to intersect the wellbore of the blowout well. Then, a heavy fluid (i.e., a kill fluid) may be pumped into the relief well to suppress the high pressure in the blowout wellbore.
As will be described in further detail below, an automated slide drilling system is disclosed that can perform directional drilling with little or no user input during drilling.
Oil and gas well drillers (referring to the role of a human operator) are typically provided with a well plan (also referred to as a well path, a drilling plan, a drilling path, or a steering plan) to follow that may be predetermined by engineers and geologists before drilling commences on a planned well. In many instances, the well plan may define individual zones or intervals along the planned well, and may include tracking information for drilling progress, such as formation targets, markers, survey data, and certain measurements. For example, during the drilling of the planned well, periodic surveys associated with a current drilling location may be taken with a downhole instrument to provide survey data (such as an inclination angle and an azimuth angle) of the well bore at various intervals. The intervals may be between 30-500 feet (10-150 meters) or at another distance, such as specified by federal and state regulations. A common survey interval during the drilling of curves and lateral sections may be 90 feet (30 meters), while distances of 200-300 feet (60-100 meters) may be typically used during the drilling of vertical portions of the planned well.
As the name implies, directional drilling is enabled by controlling a direction of (also referred to as “steering”) the drilling of the well. Directional drilling is enabled by a bottom hole assembly (BHA) that utilizes a downhole mud motor driven by the hydraulic power of drilling mud that is circulated down the drill string. The drill string may use a bent-sub to drill in a direction other than straight ahead. The use of the bent-sub and downhole mud motor allows a driller (also referred to as a “directional driller” when using the mud motor) to “steer” the wellbore trajectory to follow a specific well plan.
It should be noted that a well plan may change while the well is being drilled. In addition, the use of a bent-sub for slide drilling may allow for drilling in a particular direction, such as to correct an error, avoid a potential problem, or to mitigate an existing problem. For example, it may be that an unanticipated fault is encountered that places the target formation higher or lower than expected and as set forth in the original well plan. A correction to the wellbore trajectory may be desired to place the wellbore in the target formation. Similarly, it may be that drilling through a particular formation should be done at a higher or lower angle (relative to the formation) than initially planned in the well plan in order to avoid having a bit stuck in an undesired formation or to avoid missing a nearby target formation.
Drilling directionally (for example, by using a mud motor with a bent-sub or similar equipment) may involve occasionally stopping rotation of the drill pipe and then “slide drilling” (also referred to as “sliding”). Slide drilling may include orienting the bent-sub in a specific orientation and then drilling with the mud motor only (without rotation of the drill pipe driven by a top drive located at the surface). As the mud motor cuts a directional path in a specific orientation (usually given in degrees per 100 feet or in degrees per 30 meters), the wellbore trajectory deviates according to the curved path. Slide drilling can be difficult in some formations, and may often be slower and, therefore, more expensive than rotary drilling.
In conventional slide drilling, the role of the directional driller (referring to a human operator) typically includes analyzing data in order to make crucial and time-dependent decisions, such as when to rotationally drill and when to slide drill (including which tool face orientation to use when slide drilling), with an overall goal of hitting the specified targets in the well plan.
One important directional drilling problem that has been identified for unconventional wells is the inability to consistently follow a prescribed well path, and to hit targets while staying within the specified variances identified in the well plan. It has been observed that two primary limitations often contribute to the problem of consistent and accurate steering: in order to follow the prescribed path in the well plan, it is within the purview of the directional driller to determine a) when to begin slide drilling; and b) at which orientation to align the tool face for slide drilling. When making these decisions, directional drillers are faced with a wide array of parameters, variable factors and often unable to properly compensate for multiple parameters including variations in rotary walk and build, effective formation stresses, BHA dynamics, deflections, BHA potential, along with other factors such as hydrocarbon production potential related to drilling accuracy, lease boundaries, and tortuosity risks. In some cases, there may be so many rapidly changing variables for the directional driller to consider and react to in real-time, that the normal cognitive capabilities of a human operator become overstretched and are unable to keep up with the extensive information flow.
Once the decision has been made about when to slide and when to rotate, a driller performing conventional slide drilling may then control the drilling rig to execute the slide. Due to the lack of an industry standard of how to perform a slide, an inexperienced driller executing the slide may face a high risk of performing non-optimal slides, such as slides lacking in precision and in accuracy. The execution of non-optimal slides may lead to degraded borehole quality, longer durations in slide execution time, and poor accuracy. These errors may typically be due to the directional driller following one particular slide approach, or style, that may not be equally successful in each and every well. Over time and with more experience, directional drillers may adapt their approach, which may lead to higher quality boreholes and more consistent completion times, as the driller gains a blend of downhole knowledge and prior geographically-based experience with particular formations. The reasons for variances in the slide process can be attributed to at least some of the following factors: a) certain regions or formations may react differently when sliding through them; b) different BHAs may vary in their slide characteristics; c) physical forces and reactions while sliding may differ based on depth and well geometry; and d) an optimal approach may involve a challenging balance of ROP performance and directional control.
Even though experience with slide drilling may improve performance, even the most successful directional drillers are still a) working with limited information and b) have limited situational awareness during the course of slide drilling that may decrease the chances for optimal sliding.
At least some of these problems can be solved with the MOTIVE Directional Drilling Bit Guidance System (BGS), the industry's first use of cognitive computing to guide the directional drilling process, for example, to overcome the lack of information provided to the driller. The BGS has been successfully tested while guiding over three and a half million feet of directional and horizontal drilling to successfully determine rotate and slide start and stop depths along with setting and maintaining a targeted tool face orientation when sliding. When followed by a skilled driller, the algorithm-driven BGS system can improve the driller's ability to accurately position the bit, reduce the average drilling time, reduce tortuosity, and increase the hydrocarbon production potential of the completed well, which are desirable economic results.
As previously stated, due to the uncertainty of how to perform a slide, an inexperienced driller executing the slide may have a high risk of performing non-optimal slides (lacking in precision and in accuracy). Also, slides performed by an experienced driller may be subject to additional improvement.
In order to improve the consistency, accuracy, speed, and quality of sliding, an automated slide drilling system, as disclosed herein, may be used to perform slide drilling. The automated slide drilling system disclosed herein for drilling rigs may analyze a variety of data inputs and control the rig equipment (e.g., top drive, draw works, etc.) to continuously adjust the orientation, or tool face of the BHA before and during a slide.
The automated slide drilling system may be a dedicated sliding system which is operated separately and apart from any automated rotational drilling systems. Since the driller has responsibilities for both sliding and rotating intervals, keeping the automated slide drilling system contextually centered on sliding avoids confusion and responsibility overlap with rotational drilling that may introduce risk or confusion, which is undesirable.
It will be appreciated that the automated slide drilling systems and methods described and disclosed herein can be useful and can be implemented at various levels of automation, such as in accordance with various levels the Sheridan-Verplanck 10 levels of automation. In other words, at least the following levels of automation may be used in accordance with the present disclosure:
1. The automated slide drilling controller offers a set of alternatives which the human operator may ignore in making decision.
2. The automated slide drilling controller offers a restricted set of alternatives, and the human operator decides which to implement.
3. The automated slide drilling controller offers a restricted set of alternatives and suggests one, but the human operator still makes and implements final decision.
4. The automated slide drilling controller offers a restricted set of alternatives and suggests one, which it will implement if the human operator approves.
5. The automated slide drilling controller makes a decision but gives the human operator an option to veto prior to implementation.
6. The automated slide drilling controller makes and implements a decision, but must inform the human operator after the fact.
7. The automated slide drilling controller makes and implements a decision, and informs the human operator only when asked to.
8. The automated slide drilling controller makes and implements a decision, and sends a notice to the human operator only if the notice is determined to be warranted (i.e., only certain elevated alarms are reported).
9. The automated slide drilling controller makes and implements a decision if the decision is determined to be warranted, and sends a notice to the human operator only if the notice is determined to be warranted.
In one embodiment, an auto slide refers to the completion of some or all the following steps by a drilling rig system in drilling a well: (i) automatically (i.e., without further user input) determine that the drilling rig should enter slide mode; (ii) automatically enter slide mode directly from rotary drilling operations or after a connection of a pipe to the drill string has been made, based on a software recommendation; (iii) automatically establish the correct torque in the drill string based on a software recommendation; (iv) automatically engage the bottom of the wellbore with the drill bit; (v) automatically determine and achieve a target tool face; (vi) control the slide drilling until the slide is completed; and (vii) automatically resume rotary drilling or prepare for a survey at the end of the current drill pipe stand. Various embodiments of systems and methods useful for performing automated slide drilling of a well are described in more detail below.
In another embodiment, a drilling rig system may be provided, which is operable to provide auto slide drilling methods, and which may comprise: a drilling rig, a drill string coupled to said drilling rig, a drill bit coupled to a first end of said drill string, a computer system having a processor, memory, and instructions stored on said memory capable of execution with the processor, wherein said instructions comprise instructions for performing any one or more of the following steps: (i) automatically determining that a drilling rig should enter a slide drilling mode; (ii) automatically enter the slide drilling mode directly either from rotary drilling operations or after a connection to a pipe in the drill string has been made, based on a software recommendation; (iii) automatically establishing a determined torque value in a drill string coupled to the drilling rig based on a software recommendation; (iv) automatically engaging a bottom of the wellbore with a drill bit attached at one end of the drill string; (v) automatically determining and achieving a determined tool face for a slide drilling operation; (vi) controlling the slide drilling mode until the computer system determines that the determined slide is completed; (vii) automatically resuming rotary drilling mode or preparing for a survey at an upcoming end of a current drill pipe stand.
As noted above, during conventional slide drilling operations, the human operator performs the control and regulation and bases decisions on the system inputs and their own personal training, experience, and skill. Such persons are usually known as directional drillers. Due to human nature, manual control may result in somewhat of an inconsistent control result because of reliance on the level of personal experience and skill of the particular directional driller, which varies from person to person.
In one example, a general operational process for manual slide drilling is as follows: a directional driller is provided with a predefined well path to follow, and is tasked with following the well plan as closely as possible. The directional driller orients the drill bit tool face to the desired magnetic or gravity-referenced orientation and begins slide drilling (or sliding). While sliding, the downhole telemetry equipment may relay information regarding the position and orientation of the drill bit to the surface. If the drill bit varies away from the desired well path, the directional driller can make an adjustment of the tool face orientation to correct for the deviation. In addition to correcting for well path deviations, the directional driller can also implement a drill string oscillation routine that may help to reduce downhole friction in the wellbore. The directional driller can set the top drive to rotate a certain number of degrees in one direction, return to center, rotate a certain number of degrees the opposite direction, return to center, and repeat this process until the directional driller decides to stop. The directional driller may also utilize many other types of information to control conventional slide drilling operations, such as, but not limited to, rate of penetration (ROP), pressure differential (ΔP), weight on bit (WOB), pump strokes per minute, among others. All this information may be utilized to keep the drill bit as close to the desired well path as possible and to perform slide drilling as quickly and consistently as possible.
The automated slide drilling system disclosed herein may implement a hands off, closed-loop control system for slide drilling from when the automated slide drilling operation is initiated until when the automated slide drilling system hands drilling control back over to the driller (i.e. a human operator), for example, to re-initiate rotary drilling operations. Some or all of the downhole and rig-based telemetry measurements discussed above can be measured in real time and input or provided to the automated slide drilling system and can be utilized to calculate ideal outputs for other the rig control system set points, including set points for WOB, ROP, ΔP, pump strokes per minute, and tool face orientation, among others.
The automated slide drilling system at the surface can receive downhole telemetry information regarding actual bit position. The automated slide drilling system can compare the actual bit position information to the anticipated bit position and determine if there has been a deviation from the desired well path. When a deviation is calculated, the control system can determine a course correction route back to the desired well path and adjust the rig system set points, e.g. tool face orientation and WOB, to implement the desired course adjustment. The course adjustment can be implemented through the rig control system and the top drive by rotating the drill string in the desired direction to build torque. Once the torque overcomes the downhole friction and reaches the BHA, the tool face can be rotated to the new desired set point. It will be appreciated that the torque that overcomes the downhole friction can originate from the surface as noted above, but torque to obtain this result may also be obtained by increasing the WOB or the differential pressure to create downhole reactional torque to accomplish the same result.
The automated slide drilling system can also receive downhole telemetry information regarding tool face orientation. The automated slide drilling system can continuously monitor the received tool face orientation for comparison to the target tool face (i.e., the desired set point for the tool face orientation). If a deviation from the desired set point is identified, automated slide drilling system can calculate the required adjustment and output a new set point to reflect the desired change in tool face orientation. The automated slide drilling system also can implement a drill string oscillation routine to reduce the downhole friction between the wellbore and the drill string. For example, the automated slide drilling system can set the top drive to rotate a certain number of degrees in one direction, return to center, rotate a certain number of degrees in the opposite direction, return to center, and repeat this process until the automated slide drilling system indicates that the oscillation of the top drive is to stop.
In one embodiment, a tunable approach to automatic slide optimization can be used, and this tunable approach can also be used in conjunction with machine learning. The tunable approach can allow a variety of physical factors regarding the automated slide drilling system, the rig, the formation, the well, and the like to be considered, as well as allowing a variety of economic, performance, and risk-driven factors to be considered. The tunable approach can also allow an operator to set and reset, and otherwise adjust how the automated slide drilling system accounts for the various factors and preferences that might apply, which can be adjusted as the well is being drilled. Moreover, the tunable approach may allow such factors to be adjusted in real time and during drilling operations, as desired. For example, tunable approach may allow a human operator to adjust the manner in which the control system responds to various inputs by adjusting the inputs for various rigs, formations, or drilling preferences. In one example, the automated slide drilling system may dynamically handle slide drilling differently when the slide drilling occurs in different well zones.
Referring again now to the drawings,
It will be appreciated that automation of slide drilling with an automated slide drilling system can also be used to perform any one or more of the following:
(a) Preplan mud property slide enhancing efforts, and digitally time addition of lubricating beads in the mud to reach bottom for planned slides;
(b) Automate flow rate changes to change bit RPM and impact dogleg capacity of the BHA;
(c) Automate testing and calculation of break over torque;
(d) Automate BHA hang-up detection while sliding with visualization;
(e) Perform drill string variation prediction and simulation;
(f) Preplan and adjust automation approaches for different component changes such as drill pipe diameter; and
(g) Measure reactive torque and control the tool face as a method of formation evaluation. It should be appreciated that the methods and systems disclosed herein can be used to include some or all of the foregoing, as may be desired. For example, (d) Automate BHA hang-up detection while sliding with visualization may encompass various actions to successfully navigate a borehole transition from rotary drilling to slide drilling that may be associated with a discontinuity or contour irregularity along the inner surface of the wellbore. Firstly, the contour irregularity may be predicted based on information in the well plan, including formation information and predefined sliding zones that occur in between rotary drilling, along with information about the BHA being used. For example, a BHA having stabilizers protruding outward may be recognized as an indication of increased susceptibility to a hang up. In addition to prediction and avoidance or mitigation of the risk of a hang up, as well as the recognition of a hang up, the automated slide drilling system disclosed herein may be enabled for autonomous reaction and correction of a hang up condition, which may including stopping and starting drilling, increasing or decreasing WOB, moving the BHA forwards or backwards, setting a given tool face orientation, and other possible configurations of the BHA where available. The procedure for hang up detection and mitigation may be performed by the automated slide drilling system without user input or without user notification in real time or both, in various implementations, for example, to facilitate a rapid and cost-effective response to the hang up that does not negatively impact ROP.
As shown in
As shown in
In other implementations (not shown), the corrective action may be provided or communicated (by display, SMS message, email, or otherwise) to one or more human operators, who may then take appropriate action. In
Multiple approaches can be used to start a slide. The two most common approaches involve a) spending time orienting the off-bottom tool face to prepare for engagement in the ideal pre-compensated direction to account for reactional torque or b) to go directly to bottom and adjust on the fly to accomplish the desired tool face. Although the approaches a) and b) are historically driven by style of directional drillers, the automated slide drilling system can determine in real time which approach is better or ideal. The determination of the approach can change based on criteria of the well and downhole tools that might advantage either of these two example approaches. Additional variations of approaches throughout the well may also be evaluated in real-time by the automated slide drilling system. On a long lateral section of the well, it might make sense to go to bottom immediately for weight transfer concerns and the time involved with orienting off-bottom. By contrast, in a curved section of the well, where the build rate may be a higher priority to achieve, it might make sense to orient off-bottom to ensure an ideal tool face while sliding.
Multiple approaches can be used to adjust tool face targets during a slide. The two most common approaches involve a) rotating the drill string to cause the desired change or b) to increase or decrease the operating parameters of the bottom hole assembly (BHA) to create more or less reactive torque. Each approach has valid use cases but these can change based on operating limits or weight transfer capability during the drilling of well. In some cases the drilling operations may approach the limits of the BHA's operating parameters or the ability of the rock or bit to create the resistance needed to create the desired reactive torque. In other cases, the additional rotary torque delivered by the rig on the surface to adjust the downhole tool face may destabilize the rotational friction at the BHA that allows the tool face to remain stable. The system can determine which of these two approaches or other approaches can be used based on a variety of inputs in real time.
By using a known break over torque (where the surface torque is effectively being delivered to the downhole BHA), a transition from rotation to sliding can be accomplished without having the BHA coming off-bottom. This can make for a more efficient transition and avoid the static friction issues associated with going back to bottom. Additionally, pipe squat can be reduced or eliminated.
By using a known break over torque (where the surface torque is effectively being delivered to the downhole BHA), a transition from rotation to oscillation while sliding can be accomplished without coming off-bottom.
To determine ideal off-bottom tool face prior to going to bottom so that once engaged and reactive torque is present, the desired downhole tool face will be accomplished most efficiently.
To determine ideal off-bottom tool face prior to going to bottom so that once engaged and reactive torque is present, the desired downhole tool face will be accomplished most efficiently, the steps of
Steps shown in
To determine ideal bit torque that will accomplish optimized performance sliding, the steps of
To determine ideal bit torque that will accomplish optimized performance sliding, the steps of
Along with better rig operations alignment, an automated slide drilling system may be expected to abide by some or all of the following risk mitigation factors. As the first risk mitigation factor, prior to slide setup, the automated slide drilling system may be limited so that it cannot be initiated until the driller performs the necessary off-bottom actions to prepare for the slide. This can avoid the risk of moving the draw works while off-bottom, for instance, when trying to work the pipe to free trapped torque in the drill string from the previous rotate interval prior to setting up a slide. Therefore, the automated slide drilling system may be configured to have the driller control the draw works while off-bottom.
As the second risk mitigation factor, the automated slide drilling system may be configured to utilize only those controls that a driller would have access to. In this situation, the automated slide drilling system would use the rig's auto driller system exclusively to control the draw works as well as top drive orientation capabilities as provided by the existing rig controls. This approach allows the automated slide drilling system to include all safety measures that currently exist within the rig controls. The automated slide drilling system may be used with drilling rigs that do not have an auto drill control system. In such embodiments, the automated slide system may be coupled to one or more of the rig's drive works control system, the top drive control system, the oscillator control system, any combination thereof, and with other rig control systems, as indicated. The automated slide drilling system can be programmed to send one or more control signals as appropriate to any of such rig control systems to implement the automatic control and performance of the slide and related drilling rig operations described herein. For convenience, the following discussion focuses on exemplary embodiments that include a rig having an auto driller system. However, it will be understood that another control system, or a human operator, may replace the auto driller in different implementations.
On some drilling rigs, a primary human machine interface (HMI) is used that enables a driller to interact with various systems and controls on the rig. The HMI may include one or more touchscreens, for example. The automated slide drilling system can be programmed to expect or wait for a control handoff to occur explicitly from the driller, such as from this HMI. Additionally, the automated slide drilling system may have one or more separate displays presenting the status of the automated slide drilling system and drilling operations, as well as providing the ability to tune and adjust the slide process, before and during the slide.
When determining how best to control the tool face during a slide, the automated slide system may interface with one or more different control systems on the rig, such as the draw works control system, the top drive orientation control system, and the top drive oscillator control system.
The draw works control system may be the most impactful system to the progression of drilling due to its direct control of the rate at which drill string is lowered into the borehole, usually referred to as a “block velocity” or “block speed”. The draw works control system, through its direct control of the block speed, also has an indirect impact on tool face control during sliding from the forces applied, based on WOB and differential pressure changes. Rig manufacturers commonly utilize an automated control system that provides higher precision control within the performance limitations of the physical equipment while attempting to optimize ROP. In the case of some rigs, the auto driller is the dedicated system that provides the means of controlling the block speed by translating result-driven set point changes to surface torque, WOB, differential pressure, and ROP to changes in block speed. A set point is considered the intended resulting value that the connected equipment adjusts to and maintains when signaled by the automated slide drilling system. As each set point is entered into the automated slide drilling system, the auto driller (or a suitable alternative or a human operator) may attempt to adjust the draw works control system to meet that set point. Since there are usually multiple set points, the auto driller may attempt to meet all set points up to the first set point being reached at which time the auto driller may consider that particular set point as the active control driver, or primary limiting set point, of the auto driller. In a similar way that drillers change set points to adjust draw works, the automated slide drilling system may interface with the rig controls to provide set point values to the auto driller.
The top drive orientation control system provides the ability to change the orientation of the top drive and can have a direct impact on tool face control during a slide. When the orientation is adjusted, the rotational displacement of the top drive is transferred to the drill string at the surface and propagates from the surface down towards the BHA at the bottom of the hole as a result of a change in torsional force. If enough rotational displacement is applied to overcome frictional forces along the drill string, the amount of transferred torsional force will propagate to the bit. Once the propagation reaches the bit, the tool face downhole will change. The automated slide drilling system may interface with this control system in order to adjust the orientation of the top drive to affect the tool face downhole during the slide.
The top drive oscillator control system provides repeated alternating top drive orientation changes with the purpose of reducing the effect of frictional forces on the drill string during sliding. On some rigs, the oscillator control system allows the control of several set points; top drive speed, the amount of clockwise and counter-clockwise rotation, and the neutral position or offset where the oscillation movements are centered. The automated slide drilling system may interface with the top drive oscillator control system, which may be only after determining that oscillation is optimal for use, and provide set point values based on multiple factors including, but not limited to, borehole geometry, prior slide control precision, and drill string torque modeling.
Prior to executing a slide, it may be desirable that the tool face be aligned such that, after tagging bottom, the tool face is aligned with the target orientation. In order for the automated slide system to perform slide control properly, the driller may be required to pick up off-bottom from any previous on-bottom activity and perform multiple actions, while off-bottom, before the automated system is to be engaged.
The following actions may be performed or specified to be performed before the automated slide drilling system is considered ready to execute the slide.
The first action is the driller working the pipe to bring torque into an operationally ready state. The automated slide system can be programmed to calculate the torque threshold window and present this to the driller. The action of working the pipe can be performed by the driller and may involve alternating the raising and lowering of the block position, or elevation of the draw works. It may be considered necessary to release built up, or trapped, torque in the drill string such that, by releasing torque from the drill string, rotational displacement on the surface is better transferred to the BHA.
The second action is the automated slide system calculating the orientation of the tool face of the BHA while off-bottom. The off-bottom tool face offset calculation can be based on one or more BHA, formation, and torque characteristics, measurements or determinations, and may present an operational window within which the tool face is oriented.
The third action involves the driller orienting the top drive to bring the tool face of the BHA within the threshold window. Consequently, orienting the tool face is not mutually exclusive from the action of working the pipe. Working pipe before, during, and after orienting the tool face may give an indication to the driller that the effects of trapped torque on the alignment of the tool face are negligible, or neutral, and that alignment of the tool face at this neutral point increases the chance of successful control.
Following the slide setup actions above, the automated slide drilling system may then be engaged to begin executing the slide drilling operation.
Using the data recording from a driller setting up a slide and tagging bottom, the trace diagram provided as
The automated slide drilling system may then, at 3514, automatically control the draw works through the auto driller to lower the block until the bit is on-bottom, at 3518. In addition to lowering the block, the auto driller can automatically zero the WOB and differential pressure and transmit the zeroing event to the automated slide drilling system. WOB and differential pressure zeroing are useful for the automated slide system because it can set a reference point useful when later calculating appropriate adjustments.
Once the drill bit is on-bottom during slide control, the automated slide drilling system may apply continuous control system adjustments utilizing one or more data feeds from the surface or downhole sensors as well as from configuration and pre-planned data. The automated slide drilling system may determine the optimal control settings to adjust the drilling operations to maintain the tool face orientation at 3514 and optimize ROP. Additionally, the automated slide drilling system may determine whether use of the oscillator is optimal for slide control, set the appropriate oscillator set points, or enable the oscillator for use when needed. The automated slide drilling system may control top drive rotational adjustments, oscillator set points, and auto driller set points that include WOB, differential pressure, ROP, and surface torque parameters. Using this set of controls, the automated slide drilling system can be used to achieve and maintain tool face control with more consistent precision and improved accuracy throughout the slide. For example, the top drive may be adjusted by 0.89 wraps right to compensate for the reactive torque in the mud motor at 3516, also evident in the top drive torque at 3517.
Executing automated slide control can involve several steps that the automated slide system may perform. The automated slide drilling system may receive target tool face from the BGS and continuously receive the current downhole tool face. These data points can be used by the automated slide drilling system to maintain the orientation of the observed downhole tool face to the target orientation. The automated slide drilling system may also determine the differences between the downhole tool face and the target tool face orientation, in which direction that difference is occurring, and the impacts of that difference. In order to correct for such a difference, the automated slide drilling system may use various models and data inputs to evaluate the impact of control changes as each relates to performance. Once the automated slide drilling system determines the best corrective adjustments, it can apply those changes by interfacing with the rig controls to control one or components of the rig and their operation, as well as drilling operations. Following rig control adjustments by the automated slide drilling system, the automated slide drilling system may then continue to monitor the current downhole tool face orientation to the target tool face orientation and repeat the above steps as needed.
In order to accurately maintain control of the tool face orientation, the automated slide drilling system may use rig surface sensor data at a higher rate and fidelity than what is typically delivered by a conventional electronic data recorder (EDR) over serial communications. One efficient method is to integrate the automated slide drilling system with the rig so the automated slide drilling system can transfer data directly to and from the rig programmable logic controllers (PLCs).
Currently, conventional rig PLCs may be housed in the driller's cabin and communicate over the industry standard Click protocol. Surface sensor data may be transmitted from the PLCs to the EDR via a protocol translator device (such as supplied by Red Lion Controls, Inc., York, Pa., USA) which may be used to convert the data in real time from the Click protocol to other standard protocols. One of the available protocols is a Modbus protocol that provides a general transactional layer over Ethernet-based transmission control protocol (TCP). One advantage of using industry standard TCP-based communications is the ease of integration with various other common technologies and platforms used for modern applications. The Modbus TCP protocol provides both read and write transactions of a fixed set of data types including Boolean, integer (16-bit), and floating point (32-bit) values. Given the use of Modbus TCP from the protocol translator device to the EDR, the automated slide drilling system may also use the Modbus TCP protocol to send and receive sensor and control data between the automated slide drilling system and the rig PLCs.
In order to recognize tool face orientation variance and maintain accurate tool face control, the automated slide drilling system may receive downhole sensor data in addition to rig surface sensor data. Conventional measurement while drilling (MWD) systems may take the measurements from sensors downhole and communicate those data readings back to surface using various techniques. The downhole sensor data readings can then be distributed to user interfaces in the driller's cabin and to an EDR.
In one embodiment, the BGS may receive this data feed from an EDR via a serial communications link (e.g., RS-232), such as may be located in either the directional driller's cabin or the company man's cabin. The automated slide drilling system can be considered an active control system that performs tasks that the driller would otherwise perform through its interactions with and control of the rig controls and components. However, conventional EDR systems may add latency, thus delaying the MWD sensor data into the BGS and the automated slide drilling system. The EDR latency can be significant (e.g., anywhere from 5-15 seconds), such that the driller may be able respond to the directional user interface faster than the automated slide drilling system might respond using the EDR.
To avoid this latency, the automated slide drilling system can be integrated directly with the MWD directional systems. The MWD directional system may provide a data feed to the automated slide drilling system using an industry standard protocol, such as one based on Wellsite Information Transfer Specification (WITS), or possibly through another data transfer method.
The BGS and automated slide drilling system may comprise a single computer with at least one processor and memory, with computer software stored in memory that is executable by the processor to perform the steps and operations described in this disclosure for performing automated slide drilling operations. The BGS and automated slide drilling system also may comprise multiple computers, and processors and memories, which may be separate from one another, and may be any one of a number of conventional types of computer systems. The BGS and automated slide drilling system may be configured to receive and transmit information to and from the MWD directional system, a Modbus network system, and to provide a user interface to an operator or user.
The BGS software and the automated slide drilling software may be hosted on either a laptop workstation or on an industrial grade workstation with an integrated touchscreen display. These types of hosting machines are appropriate for mobile deployment between different rigs for multiple operators. However, when deploying an automation system on drilling rigs, a more streamlined approach may be desired by providing a fixed and integrated hosting system. Installed in most, if not all, driller's cabins on drilling rigs, is a half-rack sized server rack that allows for multiple servers and network switches to be mounted and connected to the rig and connected to dedicated touchscreen displays. The automated slide drilling system software may be deployed and executed by one or more such servers.
For the most effective experience utilizing the proposed automated slide drilling system, one potential deployment is for the software to be hosted on a server machine that is mounted and connected in the driller's cabin. This allows users on drilling rigs quick and simple access anywhere on rig-site using mobile device clients like a tablet, smartphone or laptop computer to monitor or interact with the automated slide drilling system.
The system architecture on some rigs is based upon a system-of-systems approach that aggregates and integrates many different individual systems. These systems typically provide standalone capabilities that when used or integrated together achieve desired operational behavior. The driller benefits from this approach through reduction in workload, greater situational awareness, and quicker response times to events that occur during the use of the rig. The automated slide drilling system may build upon this architecture by providing additional features and capabilities to handle the task of sliding. In order for the automated slide drilling system to perform its tasks, it may be integrated with one or more of such systems on the rig. These systems may include the rig controls (inclusive of the auto driller), BGS, and MWD directional systems.
The automated slide drilling system and BGS may be combined with or may be connected to various other rig systems via TCP or WITS communication protocols. In addition, the automated slide drilling system and BGS may be connected to a display, which may be located on the rig site or may be located elsewhere remote from the rig site. The automated slide drilling system and BGS may be connected with wired or wireless network connections, such as to a local Wi-Fi network, which may be secured, and to the Internet.
The BGS can output steering plans that consist of a series of sliding and rotating intervals (and tool face orientations) for the purposes of directing the best path to stay on the well plan. During drilling, the automated slide drilling system receives this information as inputs and responds to it when the driller engages the automated slide drilling system to follow one nor more slide sequences. A slide sequence controlled by the automated slide drilling system may be initiated by a direct command from the driller after completing the appropriate pre-slide tasks, if desired.
The MWD directional system may decode and distribute a feed of downhole sensor data to rig personnel as well as to other systems such as the EDR. The automated slide drilling system may receive this data feed and use it during slide control. The downhole sensor data may include, but is not limited to, trajectory station data, tool face orientation, and gamma resistivity (GR) data.
The rig control system is typically capable of outputting data from rig sensors and to accept control inputs from other systems, such as an automated slide drilling system of the present disclosure. A rig control system is usually made up of several different subsystems, such as PLCs, protocol translators, and an HMI.
The rig PLCs can be a set of devices that collect, interpret, and emit electrical signals to and from rig equipment. The rig PLCs may be programmable, specific devices that are dedicated to handling certain areas of control for the rig, such as safety checks for the draw works and the top drive. In order to communicate control signals to other systems, each rig PLC may be connected to a communications network using an industry standard protocol, such as the Click protocol. The automated slide drilling system may be connected to the rig PLCs over the protocol translator. The protocol translator provides a means of interfacing with the rig PLCs that connect over the Click protocol, which may be then translated to/from the Modbus protocol over TCP. The automated slide drilling system may communicate with the protocol translator over an Ethernet network using the Modbus protocol.
The primary interface for the driller to control and monitor rig equipment is usually the HMI. The HMI may be designed to handle touchscreen inputs from the driller and can be configured to support different capabilities. In one embodiment, the HMI can be used by the driller to engage the automated slide drilling system of the present disclosure.
Referring now to
In method 3600, after being prompted by the BGS to perform a slide, the automated slide drilling system presents the torque operational threshold and the tool face orientation operational window to use the automated slide drilling system to control the slide. Once the driller takes action to work the torque within the threshold as well as the tool face orientation downhole within the operational window, the driller may interact with the rig controls to communicate to the automated slide drilling system that it is now in control and can begin executing the slide. In some situations, or as configured for operation, the automated slide drilling system may take control without any input from the driller or another operator or user. The automated slide drilling system then actively adjusts the top drive rotational displacement and auto driller set points based on a tool face assessment. The adjustments are repeated as indicated to maintain on bottom slide control until the slide is completed when the automated slide drilling system hands control back to the driller.
Method 3600 may begin at step 3602 by working the top drive and tool face alignment by the driller. At step 3604, slide drilling control is engaged by rig controls in response to a driller request. At step 3606, information updates are queried. At step 3608, slide target information is received from bit guidance. At step 3610, downhole sensor information is received from MWD directional. At step 3612, rig sensor information is received. At step 3614, a torque model analysis is performed on a current data snapshot based on the received information. The current data snapshot may represent the newest information queried at step 3606. At step 3616, a decision is made whether the current steering target does indicate slide steering. When the result of step 3616 is NO, and the current steering target does not indicate slide steering, method 3600 loops back to step 3606. When the result of step 3616 is YES, and the current steering target does indicate slide steering, at step 3618, a further decision is made whether the slide length has been reached. When the result of step 3618 is YES, and the slide length has been reached, at step 3621, the auto driller is caused to be disabled, and method 3600 ends at step 3623. When the result of step 3618 is NO, and the slide length has not been reached, at step 3619, the tool face alignment is evaluated. At step 3620 a decision is made whether slide drilling is active. When the result of step 3620 is YES, and slide drilling is active, method 3600 proceeds to method 3601 (see
Referring now to
Referring now to
The method in
The automated slide drilling system software may be hosted on a server located in the driller's cabin with the desired connections to the rig controls and MWD Directional system. The software comprising the automated slide drilling system can also be co-hosted alongside or even integrated with the BGS software on the same server. The automated slide drilling system software may be implemented utilizing the Java programming language and may make use of object-oriented design practices. The automated slide drilling system software may include one or more software modules, each module representing a group of functionality that meets one or more requirements. The automated slide drilling system software design approach can be divided into two major groups of modules: data input/output modules 3902, and algorithm modules 3903. The data input/output modules may be focused on interfacing with other systems and provide data handling and storage. Additionally, the data input/output modules 3902 may also provide higher level control modules for more complicated control transactions (e.g., orient top drive, change oscillator offset, etc.). The algorithm modules 3903 may comprise the logical components that more directly relate to the automated slide drilling system.
Additionally, in
Additionally, in
The algorithm modules 3903 of
In one embodiment, an automated slide drilling system may be used to provide detailed instructions to an operator who may then control the rig components and operations. For example, once a slide is indicated (such as determined by the BGS), the automated slide drilling may receive the information about the upcoming slide from the BGS, obtain information about the BHA, its location, tool face orientation, etc., and then may provide either or both of (1) instructions or directions for an operator to control the rig and drilling operations to perform the slide, and (2) detailed parameters for operation of the rig components and operations for performance of the slide. Examples of the former (1) might include providing the operator with an appropriate target ROP and slide duration for a given tool face orientation. Examples of the latter (2) might include providing the operator with specific parameters for controlling the top drive, draw works, and the like. In the latter (2) case, the operator thus maintains control over the drilling operations, but the automated slide drilling system may provide specific parameters to be followed by the operator. In addition, the automated slide drilling system may obtain information from downhole and surface sensors during drilling, and use such information to compare the actual rig operations to those provided by the automated slide drilling system to the operator to determine if the drilling operations are within acceptable thresholds and provide an appropriate display or alert to the operator and one or more other systems or devices, such as by text message, email, or other alert.
In yet another embodiment, the automated slide drilling system may be configured to have a tutor mode of operation. In a tutor mode, the automated slide drilling system may be connected to a drilling rig or may be configured as a simulator, and may be used by operators to obtain training for control of various types of drilling operations, conditions, events, and the like.
Method 4000 may begin at step 4010 by ceasing rotary drilling, pulling off bottom to the latest pick-up weight, and deactivating the top drive grabber. At step 4012, the pipe is worked 15 feet (stop 3 feet off bottom), the pickup weight and the slack off weight are recorded, and the tool face orientation is recorded as TF value #1. At step 4014, the top drive grabber is activated, the pipe is scribe marked, the pipe is worked 15 feet (stop 3 feet off bottom), and the tool face orientation is recorded at TV value #2. At step 4016 a decision is made whether TF value #1 is significantly different from TF value #2. When the result of step 4016 is NO, and TF value #1 is not significantly different from TF value #2, method 4000 loops back to step 4014. When the result of step 4016 is YES, and TF value #1 is significantly different from TF value #2, at step 4018, a difference in the scribe offset to the planned slide heading is calculated, a right hand rotary turn with the top drive is added to match current tool face orientation to TF value #1, and the pipe is worked 15 feet (stop 3 feet off bottom).
With respect to step 4016, although not shown in
In addition, a toolface score (indicated by TF Score in
At step 4020, a decision is made whether the tool face orientation is near the desired slide heading. When the result of step 4020 is NO, and the tool face orientation is not near the desired slide heading, at step 4022, a lack of rotation at the bit is detected, and the pipe is worked 15 feet (stop 3 feet off bottom). At step 4024, a decision is made whether the tool face orientation is near the desired slide heading. When the result of step 4024 is NO, and the tool face orientation is not near the desired slide heading, method 4000 loops back to step 4018. When the result of step 4020 or step 4024 is YES, and the tool face orientation is near the desired slide heading, at step 4026, ready for automated sliding is confirmed. After step 4026, method 4000 proceeds to method 4001 in
In
A helpful and intuitive graphical user interface may be helpful for an operator using an Automated slide drilling system in accordance with the present disclosure. The automated slide drilling system may include software executable to provide one or more updated, real-time displays during drilling.
The user interface of the automated slide drilling system, as illustrated in
In general, it may be more cost effective to drill a well faster, and therefore it is generally desirable that a slide be performed quickly. However, increasing ROP during a slide can present problems with maintaining or controlling tool face orientation during the slide. As a general proposition, the automated slide drilling system, as well as a human operator, can on balance maintain more precise control over a slide, including the tool face orientation during the slide, with a slower optimal ROP than with the fastest ROP possible. In situations when it is important to precisely control the slide and the tool face orientation during the slide, it may be appropriate to decrease ROP. Conversely, if the slide to be performed is such that a wider margin is appropriate, it may be desirable to perform the slide with a faster ROP.
Increasing ROP or decreasing ROP for a slide can result in destabilizing the tool face orientation. For example, increasing ROP (such as by increasing WOB and/or differential pressure) may result in destabilizing the tool face orientation in a counterclockwise direction during a slide. Conversely, decreasing ROP during a slide (such as by decreasing WOB and/or differential pressure) may result in destabilizing the tool face orientation in a clockwise direction. For purposes of this discussion, destabilizing the tool face orientation may be considered a movement of the orientation away from the target or desired orientation. Similarly, stabilizing the tool face orientation can be considered as keeping the orientation on or close to the target or desired orientation, or within a desired range of the tool face orientation.
Adjustments to the angular position of the top drive can be made in angular increments, such as a move from 20 degrees to 30 degrees. The angular position may be defined and used in units of a “wrap”, which is a 360-degree movement of the top drive. Adding a wrap in a clockwise or counterclockwise direction may be done to control tool face orientation. However, increasing or decreasing wraps without corresponding changes to ROP can also destabilize the tool face orientation. For example, increasing wraps without an offsetting change to ROP will likely result in destabilizing the tool face orientation in a clockwise direction. Decreasing wraps without an offsetting change to ROP will likely result in destabilizing the tool face in a counterclockwise direction.
In order to reach an ideal ROP and still maintain appropriate control over a slide, it may be important to adjust various drilling parameters. For example, if it is desired to increase ROP while sliding, an operator or the automated slide system described above can increase WOB and/or differential pressure. The operator or automated slide drilling system can also make appropriate adjustments to the wraps in the appropriate direction in order to maintain tool face orientation and avoid destabilizing the tool face, such as by sending one or more control signals to the rig's auto driller. Such adjustments may be made in a desired sequence. For example, the automated slide drilling system can be programmed such that, when an increase in ROP is indicated or desired, the automated slide drilling system may first send one or more control signals to the auto driller (or to the rig's top drive control system) to increase the wraps by a value related to and based upon the changes to be made to WOB and/or differential pressure to increase the ROP. The automated slide drilling system may include or may use one or more databases which include data that correlates increases and/or decreases in WOB, differential pressure, wraps, and/or ROP with one another. The automated slide drilling system can also be programmed to either request or receive input from an operator before implementing any changes in WOB, differential pressure, ROP, and/or wraps during a slide. In addition, the data used to correlate changes in WOB, ROP, and/or differential pressure with corresponding changes in wraps can be based on empirical data, historical data (such as from other wells, from other operators, etc.), data input by an operator, other data sources, or combinations thereof.
Various control sequences may be used as either open or closed loop control of tool face. For example, the automated slide drilling system can be programmed to send appropriate control signals to the top drive control system, the draw works control system, the oscillator, and/or the mud pump control system to increase wraps first, then wait a predetermined amount of time, then increase either or both WOB and differential pressure to increase ROP by an appropriate amount corresponding to the amount of the increased wraps. The amount of time between sending the control signals for increasing wraps and the control signals for increasing ROP can be based on a number of factors, including the length of the drill string and the time needed for an increase in wraps to propagate down the drill string to the bit. Alternatively, the automated slide drilling system can be programmed so that the automated slide drilling system monitors data from one or more surface and/or downhole sensors after sending a control signal to increase wraps and, after determining from the data received from such sensors that the wraps have been propagated, then send appropriate control signals to increase WOB and/or differential pressure. In like fashion, the automated slide drilling system can be programmed to automatically, or upon input from an operator, decrease wraps, allow a time period to elapse, and then decrease WOB and/or differential pressure by amounts which correspond to the amount of the decrease in wraps in order to decrease ROP without destabilizing the tool face orientation. If desired, the automated slide drilling system can be programmed to increase or decrease ROP, such as by increasing or decreasing WOB and/or differential pressure, respectively, then increase or decrease wraps, respectively, by an amount corresponding to the amount by which the ROP has been increased or decreased.
In an alternative embodiment, the automated slide drilling system may be coupled to a database which may include historical data from other wells, data from earlier in the same well, and/or a combination thereof. The data in the database may include information such as measured depth of the well, most recent tool face orientation, and a target tool face orientation, and may also include additional information, including one or more control data elements. In one embodiment, the automated slide drilling system obtains measured depth for a wellbore while drilling, and then searches the database for a data set with the same or substantially similar (e.g., within +/−90 feet or so) measured depth value. The automated slide drilling system can also be programmed to search for and select a dataset with the closest measured depth value. In addition, the automated slide drilling system may be programmed to search the database and select the control data set for the entry at that measured depth with the same or substantially similar difference between the most recent tool face and the target tool face orientation as determined in the wellbore being drilled. The control data set corresponding to each measured depth may include any one or more of ROP, WOB, differential pressure, surface torque, spindle position, oscillation control, and the like. Likewise, information relating to formation characteristics, the bore hole assembly, and other parameters with historic information can be used as part of the control data set.
Once the appropriate control data set has been selected by the automated slide drilling system from the database, the automated slide drilling system can compare the control data set against various rules or limits to be sure that application of the control data set will not cause other problems. Such rules or limits may include parameters such as minimum and/or maximum ROP or WOB values, minimum or maximum differential pressure values, and/or maximum spindle or oscillation values. If the control data set does not violate such rules or limits, then the automated slide drilling system may send appropriate control signals to the rig control systems to implement appropriate adjustments to change from current ROP, WOB, differential pressure, and the like to the corresponding ROP, WOB, differential pressure, and the like, respectively, of the selected control data set. If the drilling rig has an auto driller, then the automated slide drilling system can be coupled to the auto driller and send appropriate control signals to the auto driller for implementation. If one or more of the data elements in the selected control data set violate one or more of the rules or limits, then the automated slide drilling system can be programmed to select the control data set with the next closest measured depth and/or difference between most recent tool face orientation and target tool face orientation. If the database contains a sufficiently large enough amount of data, then the automated slide drilling system may be programmed to select a control data set based on one or more algorithms, such as linear or polynomial regression based on one or more parameters of the data sets in the database.
A generalizable set of models can be used to help model and control downhole drill string dynamics. For example, in many situations the mud motor and drill bit relate translational weight or energy applied down the drill string controlled by the draw works. The reactional torque induced through the mud motor and drill bit drilling against the formation may create a corresponding force in the rotational axis. This force can be counterbalanced by the torsion in the drill string and can be controlled from the top drive at the top of the drill string. Two simple models such as a mass-spring-damper system representing translational effects from the drill string, and a mass-spring-damper system representing torsional effects on the drill string, can be used to estimate how to best balance or offset these forces. When these forces are in balance, a well controlled, steady state tool face can be maintained to allow for precise well bore steering. Furthermore, various sensors can be used for providing real-time information that can be used to assess the system dynamics of the model. For example, sensors can determine information such as: ROP, WOB, differential pressure, and downhole tool face, and this information can be used as measures of energy in the translational axis. Sensors can also determine information such as: top drive torque, net spindle wraps measured from surface induced into the drill string from a neutral state, differential pressure, and down hole tool face. This information can be used as measures of energy contributions in the rotational axis. More elaborate system models, like a larger system of ordinary differential equations, a set of stochastic differential equations, a neural network, and/or a finite element model could also be employed to improve the accuracy and precision of a system model.
A method for modeling drill string dynamics can be used to model energy induced into the drill string in steady state conditions or in conditions involving controlled dynamic movements of tool face. The model can also incorporate the non-linear effect of break over when the drill string moves from static to dynamic friction both in the translational and rotational axis. When attempting to control the tool face orientation, it may be important to overcome these break over forces before the desired control of drill string is achieved. Anticipating the necessary differential pressure, WOB in the translational axis, and the necessary torque or wraps required in the rotational axis, can be used in optimizing a controller to maintain tool face orientation as desired.
Using the state of the two system models described, the balance and intentioned imbalance of the models can be used to optimally control for both tool face orientation and drill string stability. For example, it is not uncommon for a formation of hard rock or other external influences to destabilize the drill string and/or tool face orientation. By monitoring the information obtained from sensors, the automated slide drilling system can observe the instability in system mismatches and oscillatory effects on sensors. Using the balance model, the automated slide drilling system can either delay additional control maneuvers to allow transient effects to subside, or it can automatically send appropriate control signals to induce the proper counter balancing effect, such as by sending control signals for increasing/decreasing ROP, WOB, differential pressure, and/or adding/removing spindle wraps, to have a stabilizing effect.
For a case involving moving the tool face orientation to a new tool face target, the intentional control of the draw works and top drive control to temporarily destabilize the drill string in a manner to steer the drill string in the desired direction to achieve the new target orientation can be an initial step. The subsequent step after some intentioned period of time or series of time steps which can be applied by either a prescribed amount of time, or by actively computing the error to target and feeding that to the system controller until the target is reached, can properly actuate the stabilizing effect of draw works and top drive control. The automated slide drilling system in such cases can be managed in a simple open loop control, state machine style control, a classical control style such as a proportional-derivate-integral controller, or LQR, or any number of modern control techniques.
As previously noted, the ability of a human being (even a very talented and knowledgeable human with extensive experience in directional drilling) to monitor and make sense of the vast amounts and types of data that are available during drilling operations and relate to many different drilling parameters (such as those described above) is fairly limited, at least as compared to the BGS and ASDS 4210 of the present disclosure. Among other things, when planning or performing a slide drilling operation, the ASDS 4210 can obtain, monitor, and analyze data that is updated in real-time during drilling and that relates to a substantial number and variety of drilling operations and parameters. For example, the ASDS 4210 can obtain, monitor, and consider the potential effects of formation information, such as the type of formation which is being drilled, the dip angle of the formation bed, the anticipated next formation to be drilled, the hardness and other physical characteristics of the formation(s) considered, and so forth. The ASDS 4210 can also obtain, monitor, and consider the potential effects of equipment information, such as the type and size of drill bit being used, the BHA type and configuration, the BHA stabilizers and their location, the bend in a mud motor, whether the tool is a push the bit or pull the bit type of tool, and so forth. The ASDS 4210 can obtain, monitor and consider the effects of information regarding the borehole, such as its measured depth, its true vertical depth, the tortuosity of one or more portions of the borehole (existing or planned), the severity of doglegs, relative placement with other wellbores or lease limits on placement of the borehole, and so forth. Moreover, the ASDS 4210 can obtain, monitor, and consider the potential effects of drilling parameters, such as weight on bit, rate of penetration, differential pressure, torque, pipe rotation, pipe oscillation, and so forth. The ASDS 4210 can be programmed to receive all of the information, updated as drilling progresses or there are changes (such as in the equipment used), as well as MWD information and LWD information, while the borehole is being drilled, such that the ASDS 4210 has available to it updated information from both downhole and surface sensors and updated information that represents a significant number of variables. In addition, the ASDS 4210 can be provided with access to data regarding the operational limits of each of the various equipment used for drilling, such as the top drive, mud pumps, BHA, and so forth.
In one embodiment, the ASDS 4210 may be programmed to access one or more databases containing such data in anticipation of an upcoming slide drilling operation, or may access the one or more databases repeatedly during drilling to monitor the data during a slide drilling operation and, depending on the data received, adjust a plurality of drilling parameters to adjust drilling operations, such as to adjust or control toolface during the slide, increase ROP, decrease ROP, reduce or increase torque, reduce or increase differential pressure, reduce or increase WOB, and so forth. Although physical limitations of computer processors mean that the ASDS 4210 cannot “simultaneously” adjust multiple drilling parameters at precisely the same exact point in time, it should be recognized that, as a practical matter and as apparent to any human observer, the ASDS 4210 can essentially adjust multiple drilling parameters simultaneously, such as adjusting two or more drilling parameters within the span of several microseconds. The ASDS 4210 of the present disclosure can effectively adjust any one or more of the drilling parameters previously described, including all of them, within a second or so of each other. For practical purposes for drilling operations, therefore, the ASDS 4210 can be considered as able to (1) obtain data from multiple sources that may affect drilling operations, (2) analyze the data from such multiple sources to determine if one or more adjustments are indicated and, if so, the adjustments to be made, and (3) simultaneously adjust the drilling parameters so indicated as in need of adjustment, such as by sending control signals to one or more pieces of drilling equipment and/or one or more control systems coupled to one or more pieces of drilling equipment.
It should be appreciated that, depending on the drilling parameters to be adjusted and on the adjustments to be made, the ASDS 4210 may send one or more first control signals to adjust one or more respective first parameters before sending one or more second control signals to adjust one or more respective second parameters. For example, the ASDS 4210 may determine that torque should increase, send the appropriate control signal to the top drive, then wait a determined amount of time before sending a second control signal (or set of signals) to adjust a second parameter (or set of parameters), wherein the time period may be determined by the length of the drill string and the time required for the increased torque to manifest itself at the drill bit.
The following example illustrates how the ASDS 4210 may adjust a plurality of drilling parameters simultaneously to control toolface orientation during a slide drilling operation. For example, when a reading for downhole toolface is reported to the surface at 58 degrees, and the desired target toolface defined by the BGS system is instead 12 degrees, a correction is needed to maintain the ideal trajectory. A human might use an input system to put a wrap to the left in to get the toolface and then wait a minute or two to see the result of the wrap while continuing to drill at the same ROP in the wrong direction. The human operator might then make a series of additional adjustments over a period of several minutes to acquire the desired toolface and then adjust parameters to increase performance, then repeat the targeting adjustment. Such an approach can often result in wasted time, increased tortuosity, and poor drilling performance.
With the ASDS 4210, the programming allows ASDS 4210 to determine that the ideal adjustment is to simultaneously increase the WOB and differential pressure targets, adjust the oscillator bias to the right by 0.83 wraps, and adjust the flowrate up by 10%. All of the adjustments can be made simultaneously. The net result is a faster acquisition of the toolface target, an increase in drilling performance and less unnecessary deviation of the well. The ability to make these simultaneous optimal adjustments is assisted by modeling the borehole and being able to simultaneously consider numerous variables, including the BHA, drill string, precise well path, historical trends, surface torque, reactive torque produced by the mud motor, and friction of the borehole from past evaluation, just to name a few things that can be considered. A human simply cannot make these simultaneous calculations at this resolution. Further, the continuous refinement of the adjustments based on feedback of updated information provided to the ASDS 4210, a database of previous adjustments available to the ASDS 4210, and knowledge of the variable feedback of the sensor information can be important. For example, the pressure increase caused by increasing WOB might happen well in advance of the downhole torque or toolface correction being visible at surface. With human operators it is common to make sequential adjustments without consideration of pending feedback due to this variable delay and this can lead to overcompensation causing efficiency losses. The ASDS 4210 can be used to control toolface to keep it within a target range or to correct toolface if it is determined that toolface exceeds a target threshold or falls below a target threshold, as the case may be.
In
Area 4170 of the GUI may include two lines 4105 and 4106 to the left and right, respectively, of the plot of actual tool face 4110 versus target tool face 4102, and each of the lines 4105 and 4106 may correspond to a tool face orientation that is 90 degrees in either direction from the target tool face orientation, such as minus 90 degrees on the left for line 4105 and plus 90 degrees on the right for line 4106. The lines 4105 and 4106 help provide a visual cue as to the relationship between the actual tool face and the target tool face.
The area 4135 may include a list of rig identifiers, and may indicate the rig that is currently drilling a well borehole, such as by shading, highlighting, or the like. As indicated in the GUI 4100 of
At the top of the GUI 4100, a highlighted area 4140 is provided, which indicates the current drilling operation. In this particular screen display example, the operation is shown as “Sliding 2.73 ft.” In addition, the control status area 4145 may display a current control status; in this particular example, the control status “Steering Left” is shown.
The area 4170 may also include a visual display of the actual tool face 4110 versus the target tool face orientation 4102 in an alternative configuration 4120. In the display area 4120, the current actual tool face of 195 degrees is identified in the middle of a circle with the degrees indicated around the circle. The actual tool face may be shown as a series of dots 4125 extending from the exterior of the circle to the interior of the circle to indicate the difference between the actual tool face and the target tool face at various points. Immediately below the circle may be an arrow or other indicator showing the target tool face orientation (in this example, the target tool face is 177 degrees). Below the circular display 4120, another display area 4130 may be provided. In the display area 4130, several different items of information may be provided. In this example, the target tool face of 177 degrees is listed, as is a tool face score, a value for AD stability, and a value for tool face mean. The series of dots 4125 and/or the dots 4110 can vary in size, color, shape, style, and so forth based on toolface confidence level values, although in
Still referring to
As drilling operations continue, the system may be programmed to provide and display updated information at selected intervals, such as every 10 seconds, 20 seconds, 30 seconds, or such longer or shorter intervals as may be desired. As updated information becomes available, the updated tool face information may be provided as an additional point in one or both of the displays of actual tool face 4110 and 4125 and older points may be deleted from the display. In addition, as drilling operations continue, the display of actual tool face 4110 versus target tool face 4102 may be adjusted to correspond to the time indicators in display field 4115. Moreover, as drilling operations continue, one or both of the displays 4115 and 4110 may scroll downward automatically, so that more recent information is provided at the top of display area 4170. In addition, the values for the current drilling parameters, such as those shown in data field 4160, may be automatically updated as new information is provided or may be updated at the same or different intervals as those for the tool face data plot updates.
The GUI 4100 thus provides an effective and simple display by which ongoing drilling operations can be monitored by visual inspection.
The following guide explains the use of various acronyms in the foregoing disclosure and/or the figures.
Referring now to
In ASDS control system architecture 4200 of
In ASDS control system architecture 4200 of
Referring now to
Method 4300 may begin at step 4310 by receiving a well plan and confirming that the drilling rig configuration is ready to drill. At step 4312, rotary drilling begins. At step 4314, the wellbore path is maintained according to the well plan during rotary drilling. As noted above, a well plan may change while the well is being drilled. For example, it may be that an unanticipated fault is encountered that places the target formation higher or lower than expected and as set forth in the original well plan. A correction to the wellbore trajectory and accompanying change in the well plan may be desired to help position the wellbore in the target formation. Similarly, it may be that drilling through a particular formation should be done at a higher or lower angle (relative to the formation) than initially planned in the well plan in order to avoid having a bit stuck in an undesired formation or to avoid missing a nearby target formation; a well plan may be updated to take account of such things. The well plan may be updated during the drilling of the wellbore for a variety of reasons, and the updated well plan may be provided, such as at step 4310. At step 4316, a decision is made whether a slide zone is approaching; e.g., a portion of the wellbore is to be drilled in a slide drilling mode according to the well plan, or a correction of the wellbore path should be made so the wellbore stays on plan. When the result of step 4316 is NO, and no slide zone is approaching, method 4300 loops back to step 4314. When the result of step 4316 is YES, and a slide zone is approaching, at step 4318, slide drilling (e.g., such as at the next slide zone in the well plan) is prepared for and the BHA is configured for slide drilling. At step 4320, slide drilling begins at the slide zone. At step 4322, the wellbore path is drilled using slide drilling. At step 4324, a decision is made whether the slide zone is complete. When the result of step 4324 is NO, and the slide zone is not complete, method 4300 loops back to step 4322. When the result of step 4324 is YES, and the slide zone is complete, at step 4326, rotary drilling is prepared for and the BHA may be configured for rotary drilling, or rotary drilling may begin.
As disclosed herein, an automated slide drilling system (ASDS) may be used with a surface steerable drilling system to control slide drilling. The ASDS may autonomously control slide drilling in a drilling rig without user input during the slide drilling. The ASDS may further support a transition from rotary drilling to slide drilling to rotary drilling without user input during the transitions. The ASDS may also support user input and user notifications for various steps to enable manual or semi-manual control of slide drilling by a driller or an operator.
In still further embodiments, certain transient signals may be detected and used to improve drilling performance during slide drilling. During slide drilling, various measurements, such as toolface angle or gamma ray emissions, may be transmitted to surface 104, such as by using mud pulse telemetry, in one non-limiting example. During slide drilling, a delay of 20-40 seconds or longer may typically be incurred before such MWD measurements are received from BHA 149. However, it has been observed that downhole pressure (and changes in downhole pressure) may propagate to surface 104 much faster than typical MWD measurements through the circulating mud. For example, differential pressure ΔP (or “DP”) may be defined as a difference between an initial mud pressure prior to begin of drilling and a current mud pressure during drilling. Thus, by recording the initial mud pressure, and measuring the current mud pressure during drilling at surface 104 (such as at standpipe 160 for example), values for differential pressure ΔP can be calculated without delay at surface 104 that are indicative of the downhole conditions during slide drilling.
Furthermore, it has been observed that, during slide drilling using a mud motor, certain transient signals in the differential pressure ΔP measured at surface 104 can be observed from time to time. Because differential pressure ΔP is indicative of the operation and performance of the mud motor, any change in differential pressure ΔP is normally a signal to the driller that conditions at BHA 149 have changed, which is undesirable during slide drilling because any downhole changes in drilling operation may alter the toolface angle, and thus affect the planned build rate and the planned drilling path.
Therefore, a driller (or autodriller 510 or autoslide 514) may observe and respond to the change in differential pressure ΔP, and may decide to adjust the toolface angle, or make another change to drilling parameters, such as WOB that can also affect the toolface angle. However, it has also been observed that certain transient signals in differential pressure ΔP represent temporary variances in differential pressure ΔP and result in the values for differential pressure ΔP returning to previous or expected values during slide drilling. Thus, such transient signals in differential pressure ΔP, while indicative of certain downhole conditions at BHA 149 and at the mud motor, may be false alarms for adjusting drilling parameters or changing the toolface angle, and any such adjustment or change to slide drilling in response to the transient signal would create another drilling error, which is undesirable. In some cases of slide drilling using a mud motor, a second transient signal that may be observed at surface 104 simultaneously with a transient differential pressure ΔP signal is a torque signal for drill string 146 measured by top drive 140. Although top drive 140 is not used for rotation during slide drilling, top drive 140 may be powered and may accordingly register changes in torque in drill string 146 that appear at surface 146 as transient signals that are indicative of forces acting within or on the mud motor, which may be propagated as torque along drill string 146 to surface 104 without delay.
Accordingly, a method and system for detecting transient downhole signals is disclosed. The method and system for detecting transient downhole signals disclosed herein may provide a human operator (e.g., a driller) or a software program module executing on a processor (e.g., autodriller 510 or autoslide 514 executing on a processor with steering control system 168 executing on processor 1001) with an indication that a certain measured value has been detected as a transient downhole signal, such as changes in differential pressure ΔP that are measured during drilling. The method and system for detecting transient downhole signals disclosed herein may enable early detection of one or more transient downhole signals at surface 104 without delay, such as differential pressure ΔP and drill string torque measured by top drive 140. The method and system for detecting transient downhole signals disclosed herein may indicate to a human operator or to autodriller 510 or to autoslide 514 that certain measured values, such as differential pressure ΔP or drill string torque measured by top drive 140, have been detected as transients and are expected to normalize in a short time, and may thereby prevent improper or unwarranted control action that may adversely affect drilling performance.
The method and system for detecting transient downhole signals disclosed herein may be enabled to operate with rig control systems 500, as described previously. Specifically, a software module for detecting transient downhole signals, as disclosed herein, may be used with steering control system 168 or with autodriller 510 or with autoslide 514, and may access WOB/ΔP control system 522 (or fluid circulation control system 526) to obtain ΔP measurements without delay, and may access positional/rotary control system 524 to obtain drill string torque measurements without delay. In this manner, the method and system for detecting transient downhole signals disclosed herein may be enabled to rapidly detect transient downhole signals at surface 104 without delay, and may accordingly be enable to respond with an indication of the transient downhole signals also without delay.
In one method of operation, the method and system for detecting transient downhole signals disclosed herein may determine whether a change in measured differential pressure ΔP is a transient downhole signal. The method for detecting the transient downhole signal based on ΔP may monitor a measured value of ΔP at surface 104 in a continuous manner, such as with a time resolution of 10 ms, 20 ms, 25 ms, 50 ms, 75 ms, or 100 ms, as examples. The measured value of ΔP may be measured using a pressure sensor (not shown) at surface 104 in fluid communication with standpipe 160, but yet may still be indicative of the transient downhole signal, as described previously. For example, the current pressure from the pressure sensor at standpipe 160 may be used to compute ΔP by subtracting an initial pressure value, such as a mud pressure prior to the start of drilling. In some embodiments, the initial pressure value may be reset or re-evaluated, such as when the mud motor is lifted off-bottom, to obtain a new baseline pressure. Then, a metric to determine the significance of an observed change in ΔP at surface 104 may be defined and used to identify the transient downhole signal. In one embodiment, a minimum threshold level for ΔP may be defined, such as a relative value to the normal operating value of ΔP for the particular mud motor being used, along with a minimum time duration that the minimum threshold level for ΔP is exceeded, in order to identify the transient downhole signal. In particular embodiments, Formula 1 below may be used to evaluate a threshold condition for the transient downhole signal based on ΔP.
In Formula 1, Δt may represent a time interval over which the evaluation is performed. In various embodiments, it is noted that other quantitative criteria may be used to evaluate the transient downhole signal, such as amplitude thresholds, slope thresholds, and a transient event history from previous drilling. It is noted that the change in values of ΔP that result in a positive identification of the transient downhole signal may involve values of ΔP that are nonetheless within normal operating values of ΔP for the mud motor, and that would not have otherwise resulted in an alert or an indication being generated, when only the range of normal operating values of ΔP is being monitored and controlled.
In addition to ΔP, a change in a drill string torque r, when observed to occur concurrently with a transient in ΔP as explained above, may further be used to positively identify the transient downhole signal. As noted with ΔP, or with the value of Formula 1, certain amplitude thresholds or duration thresholds or both may be applied as criteria to confirm detection of a transient signal that is expected to normalize in a relatively short time. For example, when the transient downhole signal results from the mud motor encountering a relatively small abnormality, such as a small (but much harder) inclusion in the formation being drilled through, it may be expected that drilling operations will return to normal for the formation once the small inclusion has been drilled through. Therefore, it would be a mistake or adverse to optimal drilling to make a change, such as a change in WOB or toolface, in response to observing the transient downhole signal, either ΔP or r, for example. Accordingly, the indication provided by the method and system for detecting transient downhole signals disclosed herein may indicate that the transient downhole signal should not be used for drilling parameter changes, and should be momentarily ignored by the human driller or by autodriller 510 or by autoslide 514, for example. Furthermore, when the transient downhole signal is not detected, steering control system 168 may be enabled to determine whether any drilling actions are indicated in order to rectify the change in measurement values observed, such as modifying WOB, ROP, toolface, or another drilling parameter.
In some implementations, various different criteria may be applied by the method and system for detecting transient downhole signals disclosed herein to positively identify the transient downhole signal. For example, the software algorithms for detecting transient downhole signals, as disclosed herein, may be enabled to calculate a confidence level for the identification of the transient signal, based on the evaluations described above. Thus, while detecting the transient downhole signals may be used to indicate when no control action should be performed, the confidence value may provide a further indication that the transient detected is actually temporary. The confidence level may evaluate a degree of certain differences between thresholds, instead of just a binary determination based on a threshold. For example, a minimum positive slope for the measured ΔP rising from a baseline value may be used to increase the confidence value, while a lower slope for the measured ΔP may lower the confidence value. Similarly, criteria may be applied to the measured value ΔP falling back to the baseline, such as a minimum negative slope, for example, to contribute to the confidence value.
Furthermore, the criteria applied by the method and system for detecting transient downhole signals disclosed herein to positively identify the transient downhole signal may be based on historical data collected for the same well or for other wells during slide drilling. Thus, instead of fixed threshold values, the threshold values may themselves be adaptively or historically determined. For example, to evaluate a threshold for the slope of ΔP, historical data of ΔP measurements, such as over a given recent past drilling history (e.g., over a recent window), may be accessed and used to determine a range of nominal slope values that have actually been observed for ΔP. Then, the threshold for the slope of ΔP may be based on the range of nominal slope values actually recorded for ΔP, such as a % of the range of nominal slope values, or 2.5 times a 65th percentile value of recent historical value of ΔP. Instead of, or in addition to, the slope of ΔP, nominal historical values for ΔP itself may be used, for given windows of drilling history. In some embodiments, the software algorithms for detecting transient downhole signals, as disclosed herein, may be enabled to store certain characteristic values from the drilling history in a local buffer to enable monitoring and evaluation of measured signals, such as ΔP and r, without delay during drilling.
Additionally, various different ‘training’ methods may be used to optimize or improve the software algorithms for detecting transient downhole signals, as disclosed herein. For example, historical data from drilled wells may be used to identify signals that are transient downhole signals, in order to evaluate the software algorithms against a known reference. In this manner, additional criteria for the live evaluation of the transient downhole signal may be defined and used during drilling. For example, certain formations, mud motor settings, well sections, or other drilling scenarios may be evaluated for propensity of transient downhole signals, and used as a match for the live evaluation of the transient downhole signal during drilling.
It is believed that transients and differential pressure spikes like those described can be the result of several inputs, including BHA performance and formation characteristics. Accordingly, these transients, particularly once confirmed, can be used as inputs to systems such as the BGS, ASDS 4210, and/or to geosteering systems, and can be used for correlation with historical formation characteristics or as part of a BHA health monitoring system to identify and take appropriate corrective action in the event of differential pressure spikes that may be the result of rubber damage in the stator tube or bearing disfunction.
Based on the evaluation of the transient downhole signal described above, different reactions may be generated for different outcomes that are evaluated. In one instance, when a timeout occurs during the detection of transient downhole signals disclosed herein, the detected event may end (or defined as ending) upon elapse of a timeout duration, and the software instructions may be enabled to resume searching for the next transient downhole signal. When an actual change in a measured value of ΔP or T or both is observed that does not return to normal, the transient downhole signal is not detected and no indication of the transient downhole signal is issued to the human driller or to autodriller 510 or to autoslide 514. For example, a relaxation time for evaluating the return to normal or to previous values may be defined as a parameter for the detection of transient downhole signals disclosed herein.
Additionally, another method may be used to evaluate the validity of MWD/LWD values received at the surface via mud pulse telemetry. The mud pulse telemetry uses a downhole transmitter to encode individual bits of each measurement value prior to transmission via mud pulse telemetry. Then, at surface 104, a receiver may decode the received bits back into a measurement value. When errors occur with the mud pulse telemetry transmission, incorrect values may be received and may be displayed to the user, such as on user interface 850, for example, or may be used by autodriller 510 or autoslide 514, which is undesirable for optimal drilling. In particular, the toolface angle is a measurement value that is determinative for the performance of slide drilling and any errors in the toolface angle received from downhole may lead to errors or delays that are not desired. In order to prevent erroneous values at surface 104 that are different from what is measured downhole from being used, a correlation of transient values from two or more downhole measurement values may be used. For example, if a transient, or discontinuous, value for gamma ray emission is received at surface 104 at the same time that a transient, or discontinuous, toolface angle is received at surface 104, a determination may be made that the decoding of the mud pulse telemetry signal has experienced an error, and that the next measurement value transmitted to surface 104 should be used for any subsequent control operations, either by the human driller or by autodriller 510 or by autoslide 514.
The transients can be used to evaluate the probability of MWD/LWD decode errors. Further, this evaluation can be done on a scale of proportional risk so that the system can react to the relative probability and/or expected impact of the error. This evaluation can also be displayed to the user by color, highlighting, numerical value or otherwise to indicate the probability of a decoding error, such as showing a particular value in red when the evaluation indicates a high probability of decode error, and in green when a value has an evaluation indicating a low probability of decode error. Time alignment can be compensated to align the pressure spike transient with the decoded data payload that has the potential disruption in stability of decode. Additionally, erroneous values of any decoded data payload can be used to enhance this probability determination of the decode error evaluation. For example, if a gamma count is reported to surface that is 10 time the normal range, the probability of that decoded data point being in error can further benefit from its occurrence in temporal proximity with a detected differential pressure transient. Additionally, if a gamma ray sample value is 10 time the normal value, the toolface angle reported prior or subsequent to the erroneous gamma sample might be deemed having a higher probability for error.
Referring now to
Referring now to
Referring now to
It will be appreciated by those skilled in the art having the benefit of this disclosure that this system and method for surface steerable drilling provides a way to plan a drilling process and to correct the drilling process when either the process deviates from the plan or the plan is modified. It should be understood that the drawings and detailed description herein are to be regarded in an illustrative rather than a restrictive manner, and are not intended to be limiting to the particular forms and examples disclosed. It will be understood that although specific values for different examples have been provided in the disclosure, such specific values are merely examples for descriptive purposes and are not limiting. On the contrary, included are any further modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments apparent to those of ordinary skill in the art, without departing from the spirit and scope hereof, as defined by the following claims. Thus, it is intended that the following claims be interpreted to embrace all such further modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments.
This application is a continuation and claims priority to and the benefit of U.S. non-provisional patent application Ser. No. 17/062,175 entitled “APPARATUS AND METHODS FOR UNINTERRUPTED DRILLING” filed Oct. 2, 2020, which is a continuation and claims priority to and the benefit of U.S. non-provisional patent application Ser. No. 16/591,387 entitled “APPARATUS AND METHODS FOR UNINTERRUPTED DRILLING” filed Oct. 2, 2019, which is a continuation-in-part application and claims priority to and the benefit of U.S. non-provisional patent application Ser. No. 16/101,161 entitled “APPARATUS AND METHODS FOR AUTOMATED SLIDE DRILLING” filed Aug. 10, 2018, which claims priority to and the benefit of U.S. provisional patent application Ser. No. 62/543,880, filed on Aug. 10, 2017, and U.S. provisional patent application Ser. No. 62/676,758, filed on May 25, 2018, each of which is hereby incorporated by reference in their entirety for all purposes.
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| Number | Date | Country | |
|---|---|---|---|
| 20220364457 A1 | Nov 2022 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62676758 | May 2018 | US | |
| 62543880 | Aug 2017 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 17062175 | Oct 2020 | US |
| Child | 17812850 | US | |
| Parent | 16591387 | Oct 2019 | US |
| Child | 17062175 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16101161 | Aug 2018 | US |
| Child | 16591387 | US |
