RU2471980C2 - Automated device, and methods for controlled directional drilling - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: method involves the following stages: obtaining the entry including the specified drilling trajectory to target location; determination of predicted location of equipment of drilling string bottom of drilling system at continuous drilling; comparison of predicted location of equipment of drilling string bottom with the specified drilling trajectory for determination of deviation value; creation of the changed drilling trajectory to target location, which is chosen based on deviation value from the specified drilling trajectory; automatic and electronic creation of one or several control signals of drilling device on the well surface to direct the equipment of drilling string bottom of drilling system to target location as per the changed drilling trajectory.

EFFECT: improved control of equipment of drilling string bottom, which leads to improved response of equipment of drilling string bottom and quicker operation of equipment of drilling string bottom.

21 cl, 11 dwg

Description

BACKGROUND OF THE INVENTION

At the beginning of the drilling process, drillers typically develop a drilling plan that includes the target location and the drilling path to the target location. After the start of drilling, the equipment of the bottom of the drill string is directed or "deviated" from the vertical drilling course in any direction, following the proposed drilling plan. For example, to extract oil or gas from an underground field, a drilling plan may include a vertical well at a point above the reservoir, then a directional or horizontal well that penetrates the field. Then the operator can direct the drilling both vertically and horizontally, in accordance with the plan.

In some embodiments, the implementation of such directional drilling requires accurate orientation of the curved segment of the downhole motor, which drives the drill bit. In such embodiments, the rotation of the drill string changes the orientation of the curved segment and the end of the bit. For effective control of the unit, the operator must first determine the current orientation of the bit face, for example, using the device for "measurements during drilling" (IPB). After that, if the drilling direction needs to be adjusted, the operator must rotate the drill string to change the orientation of the end face of the drill bit. In other embodiments, for example, in rotary controlled systems, the operator still needs to determine the current orientation of the bit end.

In the process of drilling, inclinometric measurements identifying data on the position and direction of the bottom of the drill string (BHA) equipment in the well are obtained at different time intervals. Each inclinometry measurement gives the slope and azimuth (or compass heading) of the position in the well (usually the total depth during the measurement). In directional wellbores, in particular, the position of the wellbore must be known with sufficient accuracy to ensure the correct path of the wellbore. Measurements themselves include deviation from the vertical and the azimuth of the wellbore. In addition to data on the end face of the bit, as well as the slope and azimuth, the data obtained during each inclinometry measurement can also include, for example, data on the depth of the well, data on the rotation of the column, data on the load on the hook, data on the pressure drop (through downhole motor), as well as simulated bend data.

These measurements can be made at individual points in the well, and the approximate path of the wellbore can be determined based on these individual points. Typically, standard inclinometry measurements are taken at each drill pipe joint to obtain an accurate dip and azimuth measurement for a new inclinometer position. However, if directional drilling operations require one or more transitions between movement and rotation within the interval of one link or drill pipe lock, the driller cannot rely on new inclinometry measurements to accurately assess the progress or effectiveness of the operation. For example, a driller cannot use new inclinometry data to evaluate the effectiveness or accuracy of rotary-free drilling, which began after inclinometer data were obtained. The usual application of inclinometry measurements does not provide the directional drilling technologist with any feedback on the advancement or effectiveness of the operations performed after new inclinometric data are received.

When there is a deviation from the planned drilling path, drillers should study the factors available to them in order to try to return the direction of drilling to the original path. This typically requires the operator to control the drawworks brake and rotate the rotor table or top drive spindle to find the exact combinations of hook load, downhole differential pressure and torque on the drill string to properly position the bit face. This can be a difficult, time consuming and complex process. Each regulation produces different effects regarding the orientation of the bit face, and each needs to be considered in combination with other drilling standards when drilling a well. Thus, the reorientation of the end face of the bit in the well is very complex, time-consuming and often inaccurate. Therefore, a more efficient, reliable way to control the BHA is necessary.

SUMMARY OF THE INVENTION

In one embodiment, the present description is directed to a method of drilling to a target location, which includes obtaining baseline data including a planned drilling path to a target location, and determining the predicted position of the bottom of the drill string equipment in the drilling system. The predicted location of the bottom hole equipment is compared with the planned drilling path and a modified drilling path is created to the target location. Drilling rig control signals are generated, typically on the surface of the well, that direct the bottom of the drill string to the target location along a modified drilling path.

In one embodiment, creating a modified drilling path to the target location involves calculating curves from the predicted location of the bottom of the drill string that intersects the planned drilling path. In another embodiment, creating a modified drilling path to the target location involves calculating a new planned drilling path that does not intersect the planned drilling path and which is directed from the predicted position of the bottom of the drill string to the target location, the method also includes re-determining the predicted position of the bottom of the drill system of the drilling system . The predicted position of the bottom of the drill string is compared with the new modified drilling path and creating a second modified drilling path to the target location. One or more control signals of the drilling rig are automatically and electronically generated on the surface of the well, which direct the equipment of the bottom of the drill string of the drilling system along a second altered drilling path to the target location.

In one embodiment, determining the predicted position of the bottom of the drill string includes determining the predicted position of the drill bit of the bottom of the drill and determining the predicted position of the drill includes reviewing data from one or more results of the inclinometry measurements.

In one embodiment, creating a modified drilling path based on whether the deviation from the planned path exceeds a threshold, includes creating a modified drilling path that intersects the predetermined drilling path if the deviation from the predetermined path exceeds the first deviation threshold, and creating a modified drilling path which does not cross the predetermined drilling path if the deviation from the predetermined path exceeds the second deviation threshold I am. The method may include receiving user-initiated input indicating whether to create a new predetermined path to the target that does not intersect the predetermined drilling path when the deviation of the bottom of the drill string exceeds a second threshold deviation from the predetermined path.

In one embodiment, a predetermined drilling path includes a tolerance zone, and a modified drilling path is created when the predicted position of the bottom hole equipment crosses the boundary of the tolerance zone, and is not implemented when the predicted position of the bottom hole equipment is within the tolerance zone. In another embodiment, the method includes calculating the inclinometric value of the end face of the bit and the measured depth required to direct the equipment of the bottom of the drill string to the target location.

In one embodiment, creating a modified drilling path to a target location includes calculating a first three-dimensional curve, calculating a held section, and optionally calculating a second three-dimensional curve. The first and optional second three-dimensional curves may be part of an altered drilling path. An optional second three-dimensional curve may connect the altered path to the original, predetermined drilling path in a position in front of the target location. In a preferred embodiment of the present invention, all curve calculations are performed electronically, for example, using a computer or other suitable logic device, as described herein.

In one embodiment, the method includes determining a tolerance zone, a threshold zone, and a correction zone near a predetermined drilling path. Comparison of the predicted position of the bottom of the drill string equipment with a given drilling path includes determining which zone contains the particular predicted position of the bottom of the drill string equipment. After creating a modified drilling path to the target location, a new tolerance zone, a new threshold zone, and a new correction near the modified drilling path are determined.

In one embodiment, determining the predicted position of the bottom of the drill string includes using real-time inclinometric projection as a guide. The real-time projection is performed using a method including at least one of a curve of minimum radius, guide orientations and a straight line. Real-time projection may include entering the bit face orientation.

In one embodiment, the method includes creating a modified drilling path to a target location, which includes calculating a first three-dimensional curve, a retained section, and an optional second three-dimensional curve that guides the bottom of the drill string along a predetermined drilling path. The first and optional second three-dimensional curves can be calculated, preferably electronically, by calculating any curves required to intersect a predetermined drilling path at a target location, computing any curves required to intersect a predetermined drilling path in a first position in front of the target location. Each curve may have an acceptable level of curvature for the BHA. The curves can also be calculated, preferably electronically, by calculating any curves required to intersect a predetermined drilling path in a second position before the first position, all curves having an acceptable level of curvature, the first and second positions are separated by a selected measurement distance, and selecting design curves that cross a predetermined path in a first position before reaching a target location.

In another embodiment, the present invention provides a system for drilling to a target location, comprising a receiver for receiving input data including a predetermined drilling path to a target location, a sensor device for determining a predicted position of the bottom of the drill string of the drilling system, a first logical device for comparing the predicted the position of the equipment of the bottom of the drill string with a given drilling path to determine the amount of deviation from the back of a given trajectory, a second logical device for creating a modified drilling path to the target location, selected on the basis of the deviation from a given drilling path, a drilling rig control signal generator for automatically and electronically generating one or more drilling rig control signals on the surface of the well that direct the bottom equipment the drill string of the drilling system to the target location along the altered drilling path.

In one embodiment, the system includes a drawworks drive, a top drive, and a mud pump. The control signal generator transmits one or more signals to control the winch, top drive and mud pump in order to change the direction of the equipment of the bottom of the drill string during drilling. In one embodiment, the second logic device creates a modified drilling path based on whether the deviation from the predetermined path exceeds a threshold value, and includes a tool for creating a modified drilling path that intersects the predetermined drilling path if the deviation from the predetermined path exceeds the first deviation threshold from a given trajectory, and a device for creating a modified drilling trajectory that does not intersect a given drilling trajectory, if the deviation from the predetermined path exceeds the second threshold value of the deviation from the predetermined path.

In another embodiment, the present invention provides a method for directionally controlling the equipment of the bottom of the drill string while drilling from the rig to the underground target location, comprising the following steps: developing a drilling plan including a drilling path and an allowable error as an tolerance zone; obtaining data characterizing one or more guiding orientations and the predicted bit depth; determining the actual location of the equipment of the bottom of the drill string based on one or more guiding orientations and the projection of the depth of the bit; determining whether the drill bit is within the tolerance zone, comparing the actual location of the bottom of the drill string equipment with a given drilling path to determine the deviation from the given trajectory of the bottom of the drill string, the actual drilling path and creating a modified drilling path based on the amount of deviation from the given path includes creating a modified drilling path that intersects a given drilling path if the deviation from the given the path exceeds the first threshold deviation from a given path, and creating a modified drilling path to a target location that does not intersect the predetermined drilling path if the deviation from the given path exceeds a second threshold deviation from the predetermined path. The method also includes determining the desired orientation of the end of the bit in order to direct the equipment of the bottom of the drill string along the changed drilling path, automatically and electronically generating one or more control signals of the drilling rig on the surface of the well in the control unit and supplying one or more control signals of the drilling rig to the drawworks and top drive for guiding the bottom of the drill string along an altered drilling path.

BRIEF DESCRIPTION OF THE DRAWINGS

The present description can best be understood from the following detailed description, taken in conjunction with the accompanying figures. It should be emphasized that in accordance with generally accepted industry practice, various details are not shown to scale. In fact, the dimensions of the various parts may optionally be increased or decreased for clarity of description.

FIG. 1 is a schematic illustration of a drilling rig in accordance with one or more aspects of the present description.

FIG. 2A and 2B are flowcharts of methods according to one or more aspects of the present description.

FIG. 3 is a diagram of an apparatus according to one or more aspects of the present description.

FIG. 4A-4C are plant diagrams according to one or more aspects of the present description.

FIG. 5A is a flowchart of a method according to one or more aspects of the present description.

FIG. 5B is a depiction of a cylindrical tolerance zone around a drilling path.

FIG. 6A is a flowchart of a method according to one or more aspects of the present description.

FIG. 6B is a diagram of an apparatus according to one or more aspects of the present description.

FIG. 6C-6D are flowcharts of methods according to one or more aspects of the present description.

FIG. 7A-7C are flowcharts of methods according to one or more aspects of the present description.

FIG. 8A-8B is an installation diagram in accordance with one or more aspects of the present description.

FIG. 8C is a flowchart of a method according to one or more aspects of the present description.

FIG. 9A-9B are flowcharts of methods according to one or more aspects of the present description.

FIG. 10A-10B are diagrams of an indication device according to one or more aspects of the present description.

FIG. 11 is a diagram of an apparatus according to one or more aspects of the present description.

DETAILED DESCRIPTION

It should be understood that the present description provides many different embodiments or examples of various features of various embodiments. Specific examples of elements and configurations are described below to simplify the present description. Of course, they are only examples and do not limit the present invention. In addition, in the present description may be repeated the numbers and / or letters of the positions in various examples. This repetition is used for simplicity and clarity and does not in itself determine the relationship between the various described embodiments and / or configurations. In addition, the formation of the first feature or the second feature in the description below may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features including the first and second features may be generated, wherein the first and second signs may not be in direct contact.

The systems and methods disclosed in this application provide improved control of the BHA, which leads to an improved response of the BHA and faster operation of the BHA compared to conventional systems, which significantly more often require manual data entry or stops to complete data entry. The invention can preferably provide this through feedback and location detection, processing the acquired data, and optimizing the drilling path based on the predicted, actual position of the bit. Before drilling, the target location is usually identified and the optimal profile of the wellbore or a predetermined trajectory is established. Such prospective drilling paths are in most cases based on the most efficient path leading to the target location or locations. When drilling begins, the BHA may begin to deviate from the optimal predetermined drilling path due to one or more different factors. The systems and methods disclosed in this application are designed to detect deviations from a predetermined path and introduce adjustments to return the BHA to the drilling path or, if more efficiently, to develop an alternative drilling path leading to the target location, preferably using the most efficient method, preferably avoiding excessive adjustments.

In FIG. 1 schematically illustrates an apparatus 100 in accordance with one or more aspects of the present disclosure. The device 100 is or includes a surface drilling rig. However, one or more aspects of the present description are applicable or can be easily adapted to any type of drilling rig, for example, a self-lifting drilling rig, semi-submersible drilling rigs, drilling ships, drilling rigs with flexible tubing, and underground well repair rigs adapted to drilling and / or repair operations, as well as casing drilling rigs, which, among others, are included in the scope of the present description.

The device 100 includes a support 105 supporting a lifting mechanism above the floor of the drilling rig 110. The lifting mechanism includes a crown block 115 and a movable block 120. The crown block 115 is mounted on or near the upper part of the support 105, and the movable block 120 is suspended through the crown block 115 on the drill cable 125. One the end of the drill cable 125 extends from the lifting mechanism to the drawworks 130, which unwinds and reels the drill cable 125, which causes the sliding block 120 to lower and rise relative to the floor of the drilling rig 110. The other end of the drill cable 125, known as to the fixed end mount, fixed in a stationary position, possibly near the drawworks 130 or elsewhere on the rig.

A hook 135 is attached to the bottom of the movable unit 120. The top drive 140 is suspended from the hook 135. A shaft 145 that extends from the top drive 140 is attached to a safety sub 150 that is attached to a drill string 155 suspended in the borehole 160. Alternatively, the shaft 145 may be attached to drill string 155 directly.

The term “shaft” as used in this application is not limited to an element that extends directly from the top drive or that is otherwise commonly referred to as a shaft. For example, as used herein, a “shaft” may additionally or alternatively include a main shaft, a drive shaft, an output shaft, and / or another element that transmits torque, position, and / or rotation from the top drive to the drill string, at least indirectly , or other rotatable drive element. However, although only for the sake of clarity and brevity, these elements may be collectively referred to herein as a “shaft”.

Drill string 155 includes connected sections of drill pipe 165, bottom hole equipment (BHA) 170, and drill bit 175. Downhole equipment 170 may include stabilizers, weighted drill pipes, and / or wireline measuring equipment (IPB) or run on a cable , among other elements. A drill bit 175, which may also be referred to as a tool in this application, is attached to the bottom of the BHA 170 or attached to the drill string 155 in another way. One or more pumps 180 may supply drilling fluid to the drill string 155 through a flexible pipe or other conduit 185, which may be coupled to the top drive 140.

Downhole IPB or tools supplied on the cable can be used to evaluate physical parameters, such as pressure, temperature, torque, bit load (WOB), vibration, tilt, azimuth, orientation of the bit face in three-dimensional space and / or other parameters in the well . These measurements can be performed in the well, the data is stored in the solid state memory for some time and downloaded from the tool (s) to the surface and / or transmitted to the surface in real time. Data transmission methods may include, for example, digitizing data and transmitting encoded data to the surface, possibly in the form of pressure pulses in a drilling fluid or drilling fluid circulation system, transmitting audio signals through a drill string 155, electronic transmission through a cable or flexible pipe and / or transmission in the form of electromagnetic pulses. IPB tools and / or other parts of the BHA 170 may have the ability to store measurement data for subsequent retrieval through the cable and / or when the BHA 170 is lifted from the well bore 160.

In an exemplary embodiment, device 100 may also include a rotary blowout preventer 158, for example, if well 160 is drilled using negative depression or controlled pressure drilling techniques. In such an embodiment, the drilling fluid and sludge from the annulus can be supplied to the surface under pressure, while the actual required flow rate and pressure are possibly controlled by the nozzle system, and the fluid and pressure are held at the wellhead and are directed downstream of the injection pipe into the nozzle by means of a rotary BOP 158. The device 100 may also include a pressure sensor in the annular space of the technical column 159, designed to measure pressure in the annular space between for example, a borehole 160 (or a casing therein) and a drillstring 155.

In the embodiment shown in FIG. 1, the top drive 140 is used to transmit rotational movement to the drill string 155. However, aspects of the present description can also be applied or easily adapted to commissioning using other drive systems, such as a swivel drive, a rotary table, a continuous string installation, a downhole an engine and / or a conventional rotary drilling rig, among others.

The device 100 also includes a controller 190 for controlling or assisting in the management of one or more elements of the device 100. For example, the controller 190 may serve to transmit operational control signals to the drawworks 130, top drive 140, BHA 170 and / or pump 180. The controller 190 may be an autonomous element installed near the support 105 and / or other elements of the device 100. In an example implementation, the controller 190 includes one or more systems located in the controller located next to it device 100, such as a universal stall, often called "booth," which serves as a storage area for various equipment, office communication center and place for overall assembly. The controller 190 may be used to transmit operational control signals to the drawworks 130, the top drive 140, the BHA 170 and / or the pump 180 via wired or wireless transmission means, which, for clarity, are not shown in FIG. one.

The controller 190 is also designed to receive electronic signals via wired or wireless transmission media (also not shown in FIG. 1) from various sensors in the device 100, where each sensor serves to measure an operating characteristic or parameter. One such sensor is a pressure sensor in the annular space of the technical column 159 described above. The device 100 may include a downhole pressure sensor in the annular space 170a connected to or otherwise associated with the BHA 170. The downhole pressure sensor in the annular space 170a can measure the value or range of pressure in the annular space between the outer surface of the BHA 170 and the inner diameter of the borehole 160 , which may also be referred to as annular pressure, bottomhole annular pressure, IPB annular pressure or pressure in the annular space of the well. These measurements may include static pressure in the annular space (pumps off) and active annular pressure (pumps on).

It should be noted that the meaning of the word "detection", in the context of the present description, may include the detection, determination, measurement, calculation and / or receipt of data in any other way. Similarly, the meaning of the word “detect”, in the context of the present description, may include detecting, determining, measuring, computing and / or receiving data in some other way.

The device 100 may additionally or alternatively include a shock / vibration sensor 170b, which is designed to detect shock and / or vibration in the BHA 170. The device 100 may additionally or alternatively include a differential pressure sensor (ΔP) in the downhole motor 172a, which is designed to measure the value or the differential pressure range in one or more motors 172 ONBC 170. One or more motors 172 may be or include a hydraulic drilling motor, also known as a turbopump downhole motor, otorrhea uses hydraulic power to rotate the mud bit 175. One or more torque sensors 172b may also be included in the BHA 170, the controller 190 so as to transmit data, which characterize the torque applied to bit 175 by one or more engines 172.

The device 100 may further or alternatively include a bit end sensor 170c for detecting the current orientation of the bit end. The bit end sensor 170c may be either a standard or perspective magnetic bit end sensor that detects the orientation of the front end of the bit relative to magnetic north or geographic north. Alternatively, or additionally, the bit face sensor 170c may be, or include a standard or prospective gravitational bit face sensor, which determines the orientation of the bit end relative to the Earth's gravitational field. The bit end sensor 170c may additionally, or alternatively, be, or include a standard or forward gyro sensor. The device 100 may additionally or alternatively include a bit load sensor 170d, which is part of the BHA 170 and is designed to detect the load on the bit in, or near, the BHA 170.

The device 100 may additionally or alternatively include a torque sensor 140a connected or otherwise connected to the top drive 140. The torque sensor 140a can alternatively be located in or connected to the BHA 170. The torque sensor 140a can serve to determine the value or range of torsion of the shaft 145 and / or drill string 155 (for example, in response to labor forces acting on the drill string). Top drive 140 may additionally or alternatively include, or may be otherwise associated with, a speed sensor 140b that is configured to measure a value or range of shaft speed 145.

Top drive 140, drawworks 130, crown block or movable unit, drill cable or fixed end mount may additionally or alternatively be included, or may be otherwise associated with bit load sensor 140c (bit load is calculated based on readings from the hook load sensor, which can be based on the dynamic and static load on the hook) (for example, one or more sensors are installed somewhere on the mechanisms located on the path of the load to measure and calculate the load ki-on-bit, which can vary depending on the rig) differing from the sensor 170d WOB. The bit load sensor 140c may serve to measure the value or range of the bit load, where such a measurement may be performed in the top drive 140, the drawworks 130, or other element of the device 100.

The measurement performed by the sensors described in this application can be performed once, continuously, periodically and / or at arbitrary time intervals. A measurement can be manually started by an operator or another person with access to the operator interface, or started automatically, for example, by synchronizing a characteristic or parameter that satisfies a given condition (for example, the expiration of a period of time, reaching a given depth during drilling, wear of a drill bit reaching set level, etc.). Such sensors and / or other means of detection may include one or more interfaces, which can be located on the drilling site or in another, remote position with connection to the system via a network.

In FIG. 2A is a flowchart of a method 200a for guiding a bit face orientation to a desired position in accordance with one or more aspects of the present disclosure. Method 200a may be performed in conjunction with one or more elements of the device 100 shown in FIG. 1 during operation of the device 100. For example, method 200a may be performed to control the orientation of the bit face during drilling operations performed by the device 100.

The method 200a includes an operation 210, during which the current orientation of the bit face TF _M is determined. TF _M can be determined using a standard or prospective magnetic bit end sensor that detects the orientation of the bit end relative to magnetic north or geographic north. Alternatively, or additionally, TF _M can be determined using a standard or prospective gravitational bit face sensor that detects the orientation of the bit face relative to the Earth's gravitational field. In an exemplary embodiment, TF _M can be determined using a magnetic bitface sensor when the end of the wellbore is less than about 7 ° deviated from the vertical, and then determined using a gravitational bitface sensor when the end of the wellbore is more than about 7 ° deviated from the vertical. However, gyro sensors and / or other devices for determining TF _{M are} also included in the scope of the present description.

In the next step 220, TF _{M is} compared with the desired bit face orientation TF _D. If TF _M is sufficiently equal to TF _D , as determined during decision operation 230, method 200a is iterated and operation 210 is repeated. “Sufficiently equal” may mean substantially equal, for example, differing by no more than a few percent, or, alternatively, may mean differing by no more than a predetermined angle, for example, approximately 5 °. In addition, the iteration of method 200a may be substantially instantaneous, or there may be a delay period before iteration of method 200a, after which operation 210 is repeated.

If TF _{M is} not sufficiently equal to TF _D as determined during decision operation 230, method 200a is continued until operation 240, during which the shaft is rotated by the drive system, for example, by an amount approximately equal to the difference between TF _M and TF _D. However, other values of the rotational control performed during operation 240 are also included in the scope of the present description. After performing operation 240, method 200a is iterated, and operation 210 is repeated. Such a repetition may be substantially instantaneous, or there may be a delay period before the repetition of method 200a, after which operation 210 is repeated.

In FIG. 2B is a flowchart of another embodiment of the method 200a shown in FIG. 2A, indicated in the present description by the number 200b. The method 200b includes an operation of collecting information when the orientation of the end face of the bit is in the desired orientation, and can be performed in conjunction with one or more elements of the device 100 shown in FIG. 1 during operation of the device 100. For example, method 200b may be performed to control the orientation of the bit face during drilling operations performed by the device 100.

Method 200b includes operations 210, 220, 230, 240 described above for method 200a and shown in FIG. 2A. However, method 200b also includes operation 233, during which the current operating parameters are determined if TF _M is sufficiently equal to TF _D , as determined during decision operation 230. Alternatively, or additionally, the current operating parameters may be determined in periodic or predetermined intervals, or after the occurrence of other events. The method 200b also includes operation 236, during which the operating parameters measured in operation 233 are recorded. The operating parameters recorded in operation 236 can be used in future calculations of the shaft rotation performed during operation 240, and they can be determined by one or several programmable adaptive controllers, programmable logic controllers, artificial neural networks and / or other adaptive and / or “learning” controllers or processing devices.

Each operation of methods 200a and 200b may be performed automatically. For example, the controller 190 of FIG. 1 may serve to automatically perform a comparison of the bit face of operation 230, either periodically, at arbitrary intervals, or otherwise. The controller 190 may also serve to automatically generate and transmit control signals directing the rotation of the shaft in operation 240, such as in response to a comparison of the end face of the bit performed during operations 220 and 230.

In FIG. 3 is a block diagram of an apparatus 300 according to one or more aspects of the present description. The device 300 includes a user interface 305, BHA 310, a drive system 315, a drawworks 320 and a controller 325. The device 300 may operate in an environment and / or in the installation shown in FIG. 1. For example, the BHA 310 may be substantially similar to the BHA 170 shown in FIG. 1, the drive system 315 may be substantially similar to the top drive 140 shown in FIG. 1, the drawworks 320 may be substantially similar to the drawworks 130 shown in FIG. 1 and / or the controller 325 may be substantially similar to the controller 190 shown in FIG. 1. The device 300 may also be used in the method 200a shown in FIG. 2A and / or the method 200b shown in FIG. 2B, among other methods described in this application or included in the scope of the present description.

User interface 305 and controller 325 may be separate elements that are connected through wired or wireless means. Alternatively, user interface 305 and controller 325 may be constituent elements of a single system or controller 327, as indicated by dashed lines in FIG. 3.

The user interface 305 includes a device 330 for the user to enter one or more control points of the bit end, and may also include a device for user input of other control points, limits, and other input data. The data entry device 330 may include a keyboard, a speech identification device, a disk, a button, a switch, a slide selector, a switch, a joystick, a mouse, a database, and / or other standard or advanced input device. Such data entry devices may support data entry from local and / or remote locations. Alternatively, or additionally, the data entry device 330 may include a device for the user to select setpoint values or ranges of control points for the bit face, for example, via one or more drop-down menus. The data of the control points of the end face of the bit can be additionally or alternatively selected by the controller 325 by performing one or more search procedures in the database. Typically, the data entry device 330 and / or other elements within the framework of the present description support operation and / or monitoring from stations at the rig site, as well as from one or more remote locations, through a communication link with the system, network, local area network, wide area network, Internet, satellite communications and / or radio, among other means.

User interface 305 may also include a display 335 for displaying information to a user in text, graphic, or video form. The display 335 can also be used by the user to enter the data of the control points of the bit end in connection with the device for inputting data 330. For example, the device for entering the data of the control points of the end face of the bit 330 may be an integral part of the display 335 or may be connected to it.

BHA 310 may include an annular pressure annular pressure sensor 340, which is designed to detect a value or range of pressure in the annular space, in or near the LSI portion of the annular pressure sensor 310, and may be substantially similar to the pressure sensor 170a shown in FIG. 1. The pressure data in the annular space, obtained using the IPB of the pressure sensor in the annular space 340, can be sent by electronic signal to the controller 325 using a wired or wireless transmission.

The BHA 310 may also include an IPB shock / vibration sensor 345, which is designed to detect shock and / or vibration in the IPB part of the BHA 310, and may be substantially similar to the shock / vibration sensor 170b shown in FIG. 1. Impact / vibration data obtained using the IPB of the impact / vibration sensor 345 may be sent by electronic signal to the controller 325 via wired or wireless transmission.

The BHA 310 may also include a differential pressure sensor for the hydraulic downhole motor 350, which is designed to detect the value or range of the differential pressure in the bottomhole motor of the BHA 310, and may be substantially similar to the differential pressure sensor 172a of the downhole motor shown in FIG. 1. The differential pressure data obtained using the differential pressure sensor of the hydraulic downhole motor 350 can be sent by electronic signal to the controller 325 via wired or wireless transmission. The pressure drop of the hydraulic downhole motor can alternatively or additionally be calculated, detected or otherwise determined on the surface, for example, by calculating the difference between the surface pressure in the riser, not reaching the bottom, and the pressure when the bit contacts the face when the drilling starts and the torque acts .

The BHA 310 may also include a magnetic bit end sensor 355 and a gravitational bit end sensor 360, which together serve to determine the current position of the bit end and which together can be substantially similar to the bit end sensor 170c shown in FIG. 1. The magnetic bit end sensor 355 may be either a conventional or prospective magnetic bit end sensor that detects the orientation of the bit end relative to magnetic north or geographic north. The gravitational end face sensor 360 may be either a standard or prospective gravitational end face sensor that detects the orientation of the end face relative to the Earth’s gravitational field. In an exemplary embodiment, the magnetic end face sensor 355 can detect the current position of the end face of the bit when the end of the wellbore is deviated from the vertical by less than about 7 °, and the gravity sensor of the end face 360 can determine the current position of the end of the bit when the end of the wellbore is deviated from more than than about 7 °. However, other bit end sensors may also be used within the scope of the present description, including non-magnetic bit end sensors and non-gravity tilt sensors. In any case, the orientation of the bit face, determined using one or more sensors of the bit end (for example, sensors 355 and / or 360), can be sent by electronic signal to the controller 325 using a wired or wireless transmission.

The BHA 310 may also include an IPB torque sensor 365, which is designed to detect a value or range of torque values applied to the bit by the BHA 310 engine (s), and may be substantially similar to the torque sensor 172b shown in FIG. 1. The torque data obtained using the 365 torque sensor IPB can be sent via electronic signal to the controller 325 via wired or wireless transmission.

The BHA 310 may also include an IPB bit load sensor 370, which is designed to detect a value or a range of bit load values in or near the BHA 310, and may be substantially similar to the bit load sensor 170d shown in FIG. 1. The bit load data obtained by the bit load sensor 370 can be sent by electronic signal to the controller 325 via wired or wireless transmission.

The drawworks 320 includes a controller 390 and / or another device for controlling the unwinding and / or reeling of the drill cable (such as drill cable 125 shown in FIG. 1). Such control may include controlling the rotation of the drawworks (to or from) to adjust the height or position of the hook, and may also include adjusting the speed at which the hook rises or lowers. However, exemplary embodiments within the framework of the present disclosure also include those in which the drill string feed system through the drawworks can alternatively be a hydraulic hoist or rack-and-pinion hoist of a drilling rig lifting system in which the drill string is moved up and down with using a mechanism other than a drawworks. The drill string may also be in the form of a flexible pipe, wherein the movement of the drill string into and out of the well is controlled by a wellhead that grips and pushes / lifts the continuous string into / out of the well. However, such embodiments may also include a variant of the controller 390, wherein the controller 390 may also serve to control the feed and / or rise of the drill string.

The drive system 315 includes a surface torque sensor 375, which is designed to detect the value or range of reactive torsion of a hollow shaft or drill string, much like the torque sensor 140a shown in FIG. 1. The drive system 315 also includes a position sensor for the hollow shaft 380, which is designed to determine the value or range of the angular position of the hollow shaft, for example, relative to geographic north or other fixed point. Surface torsion data and shaft positions obtained using sensors 375 and 380, respectively, can be sent via electronic signal to controller 325 using wired or wireless transmission. The drive system 315 also includes a controller 385 and / or other device for controlling the angular position, speed, and direction of the shaft or other drill string member connected to the drive system 315 (for example, shaft 145 shown in FIG. 1).

In an exemplary embodiment, the drive system 315, controller 385, and / or other element of device 300 may include a device for determining friction between the drill string and the borehole. For example, such a device for determining friction can serve to detect the occurrence and / or intensity of friction, which can then be subtracted from the actual "reactive" torque, possibly by a controller 385 and / or other control element of the device 300.

The controller 325 is designed to receive one or more of the above parameters from the user interface 305, ONBC 310 and / or the drive system 315, as well as to use such parameters to continuously, periodically, or otherwise determine the current orientation of the bit face. The controller 325 may also serve to generate a control signal, for example, through programmable adaptive control, and supply a control signal to the drive system 315 and / or drawworks 320 to adjust and / or maintain the orientation of the bit end. For example, the controller 325 may execute the method 202 shown in FIG. 2B by supplying one or more signals to drive system 315 and / or drawworks 320 to increase or decrease the load on the bit and / or shaft position, which may be required to accurately “control” the drilling process.

In addition, as in the embodiment shown in FIG. 3, the controller 385 of the drive system 315 and / or the controller 390 of the drawworks 320 may serve to generate and transmit a signal to the controller 325. Therefore, the controller 385 of the drive system 315 may be designed to influence the control of the BHA 310 and / or the drawworks 320 to facilitate achieving and / or maintaining the desired orientation of the bit end. Similarly, drawworks controller 390 320 may be designed to influence the control of the BHA 310 and / or the drive system 315 to help achieve and / or maintain the desired bit face orientation. Alternatively, or additionally, the controller 385 of the drive system 315 and the controller 390 of the drawworks 320 can communicate directly, as indicated by the double arrow 392 shown in FIG. 3. Thus, the controller 385 of the drive system 315 and the controller 390 of the drawworks 320 can cooperate when reaching and / or maintaining the desired orientation of the bit end. Such interaction may be independent of the control carried out in relation to or through the controller 325 and / or the BHA 310.

In FIG. 4A is a schematic illustration of at least a portion of an apparatus 400a according to one or more aspects of the present disclosure. The device 400a is an exemplary embodiment of the device 100 shown in FIG. 1 and / or the device 300 shown in FIG. 3, and serves as an example of an environment in which the method 200a shown in FIG. 2A and / or the method 200b shown in FIG. 2B. Apparatus 400a includes a group of user inputs 410 and at least one main control module 420, which may include one or more processors. User inputs 410 include a positive shaft torque limit 410a, a negative shaft torque limit 410b, a positive shaft speed limit 410c, a negative shaft speed limit 410d, a positive shaft vibration limit 410e, a negative shaft vibration limit 410f, a shaft vibration neutral point 410g and input 410h bit face orientation. Some embodiments include inputting data from previous inclinometry measurements 410p, a predetermined drilling path 410q, or preferably both. The specified input data can be used to obtain input 410h orientation of the end face of the bit required to hold the BHA on a given drilling path. However, in other embodiments, the implementation of the orientation of the end face of the bit is introduced directly. In other embodiments, additional or alternative user inputs 410 may be used within the scope of the present description. User input 410 may be substantially similar to user input 330 or other user interface elements 305 shown in FIG. 3. At least one control module 420 may form at least a portion, or may itself be formed with at least a portion of the controller 325 shown in FIG. 3, and / or the controller 385 of the drive system 315 shown in FIG. 3. In the embodiment shown in FIG. 4A, at least one control module 420 includes a bit face controller 420a and a drawworks controller 420b. In some embodiments, it also includes a mud pump controller.

The device 400a also includes or is otherwise combined with a group of sensors 430. A group of sensors 430 includes a bit torque sensor 430a, a shaft torque sensor 430b, a shaft speed sensor 430c, a shaft position sensor 430d, a differential pressure sensor for the hydraulic downhole motor 430e and an orientation sensor 430f end face of the bit. In other embodiments, additional or alternative sensors 430 may, however, be used within the scope of the present description. In an exemplary embodiment, each group of sensors 430 may be located on the surface of the wellbore and may not be located in the well near the bit, the bottom of the drill string and / or any devices " for measurement while drilling. " In other embodiments, however, one or more sensors 430 may not be surface sensors. For example, in an embodiment, the shaft torque sensor 430b, the shaft speed sensor 430c, and the shaft position sensor 430d may be surface sensors, while the bit torque sensor 430a, the differential pressure sensor 430e and the bit face orientation sensor 430f may be downhole sensors (e.g. IPB sensors). In addition, some of the sensors 430 may be substantially similar to the corresponding sensors shown in FIG. 1 or FIG. 3.

The device 400a also includes or is coupled to a shaft drive 440. The shaft drive 440 may form at least a portion of a top drive or other drive rotation system, such as top drive 140 shown in FIG. 1 and / or drive system 315 shown in FIG. 3. The shaft drive 440 is used to receive a control signal of the shaft drive from at least one control module 420, or from other elements of the device 400a. The shaft drive control signal sets the position (for example, azimuth), direction of rotation, speed of rotation and / or vibration of the shaft. The bit end controller 420a is designed to generate a shaft drive control signal using data received from user input 410 and sensors 430.

The bit face controller 420a can compare the actual shaft torque with the positive shaft torsion limit obtained from the corresponding user input 410a. The actual shaft torque can be determined using data obtained from the shaft torque sensor 430b. For example, if the actual shaft torque exceeds a positive shaft torque limit, the shaft drive control signal may indicate that the shaft drive 440 reduces the torque applied to the shaft. In an embodiment, the bit face controller 420a may serve to optimize drilling process parameters related to the actual shaft torque, for example, maximizing the actual shaft torque without exceeding the positive shaft torsion limit.

The bit face controller 420a, alternatively or additionally, can compare the actual shaft torque with the negative shaft torsion limit obtained from the corresponding user input 410b. For example, if the actual shaft torque is less than the negative shaft torque limit, the shaft drive control signal may indicate that the shaft drive 440 will increase the torque applied to the shaft. In an embodiment, the bit end controller 420a may serve to optimize drilling process parameters associated with the actual shaft torque, for example, minimizing the actual shaft torque, but not exceeding the negative shaft torsion limit.

The bit end controller 420a, alternatively or additionally, can compare the actual shaft speed with the positive shaft speed limit obtained from the corresponding user input 410c. The actual shaft speed can be determined using data obtained from the shaft speed sensor 430c. For example, if the actual shaft speed exceeds a positive shaft speed limit, then the shaft drive control signal may indicate that the shaft drive 440 will reduce the shaft speed. In an embodiment, the bit face controller 420a may serve to optimize drilling process parameters related to the actual shaft speed, for example, maximizing the actual shaft speed without exceeding the positive shaft speed limit.

The bit face controller 420a, alternatively or additionally, can compare the actual shaft speed with the negative shaft speed limit obtained from the corresponding user input 410d. For example, if the actual shaft speed is less than the negative shaft speed limit, then the shaft drive control signal may indicate that the shaft drive 440 will increase the shaft speed. In an embodiment, the bit end controller 420a may serve to optimize drilling process parameters related to the actual shaft speed, for example, minimizing the actual shaft speed as much as possible without exceeding the negative shaft speed limit.

The bit face controller 420a, alternatively or additionally, can compare the actual shaft orientation (azimuth) with the positive shaft vibration limit obtained from the corresponding user input 410e. The actual shaft orientation can be determined using data obtained from the shaft position sensor 430d. For example, if the actual shaft orientation exceeds the positive limit of the shaft oscillation, the shaft drive control signal may indicate that the shaft drive 440 rotates the shaft to a positive limit of the shaft oscillation, or change the parameters of the shaft oscillation so that the actual shaft oscillation in the positive direction (for example, clockwise) did not exceed the positive limit of the shaft oscillation. In an embodiment, the bit end controller 420a may serve to optimize the parameters of the drilling process associated with the actual shaft oscillation, for example, maximizing the actual shaft oscillation in the positive direction without exceeding the positive limit of the shaft oscillation.

The bit end controller 420a, alternatively or additionally, can compare the actual shaft orientation with the negative shaft vibration limit obtained from the corresponding user input 410f. For example, if the actual shaft orientation is less than the negative limit of the shaft oscillation, the shaft drive control signal may indicate that the shaft drive 440 rotates the shaft to a negative limit of the shaft oscillation, or change the parameters of the shaft oscillation so that the actual shaft oscillation in the negative direction ( for example, counterclockwise) does not exceed the negative limit of the shaft oscillation. In an embodiment, the bit end controller 420a may serve to optimize drilling process parameters associated with the actual shaft oscillation, for example, maximizing the actual value of the shaft oscillation in the negative direction without exceeding the negative limit of the shaft oscillation.

The bitface controller 420a, alternatively or additionally, can compare the actual neutral shaft vibration point with the input of the desired shaft shaft neutral point obtained from the corresponding user input 410g. The actual neutral vibration point of the shaft can be determined using data obtained from the shaft position sensor 430d. For example, if the neutral point of the actual vibration of the shaft differs from the desired neutral point of vibration of the shaft by a predetermined amount or falls outside the desired range of the neutral point of vibration, the control signal of the shaft drive may indicate that the shaft drive 440 has changed the parameters of the shaft vibration to make a corresponding correction.

The bit face controller 420a, alternatively or additionally, can compare the actual bit face orientation with the bit face orientation input obtained from the corresponding user input 410h. The input of the end face orientation obtained from the user input 410h may be a separate value characterizing the desired orientation of the end face of the bit. It can be directly entered or obtained from the inclinometry data files 410p and the predetermined drilling path 410q using, for example, the method described in FIG. 4C, 5A and 5B. If the actual orientation of the end face of the bit differs from the input value of the orientation of the end face of the bit by a predetermined value, the control signal of the shaft drive may indicate that the shaft drive 440 rotates the shaft at a level corresponding to the necessary correction of the orientation of the bit end. However, the input of the end face orientation obtained from the user input 410h may alternatively be a range within which the end face orientation is desired. For example, if the actual orientation of the bit face is outside the input range of the bit face orientation, the shaft drive control signal may indicate that the shaft drive 440 rotates the shaft at a level necessary to restore the actual bit face orientation within the bit end orientation input range. In an embodiment, the actual orientation of the bit face is compared with the input of the bit face orientation that is directly entered or obtained from the inclinometry data files 410p and the predetermined drilling path 410q using an automated process. In some embodiments, this is based on a predetermined and / or constantly updated drilling plan (for example, “well design”), if possible taking into account the error of progress along the drilling path.

In each of the above comparisons and / or calculations performed by the bit face controller, the actual differential pressure of the hydraulic downhole motor and / or the actual bit torque can also be used to generate the shaft drive signal. The actual differential pressure of the hydraulic downhole motor can be determined using data obtained from the differential pressure sensor 430e of the hydraulic downhole motor and / or by measuring the pressure of the pump before the bit comes into contact with the face plane and abruptly changes this value, and the actual torque bits can be determined using data obtained from the torque sensor bit 430a. Alternatively, the actual bit torque can be calculated using data obtained from the differential pressure sensor of the hydraulic downhole motor 430e, since the actual bit torque and the actual differential pressure of the hydraulic downhole motor are proportional.

One example in which the actual differential pressure of the hydraulic downhole motor and / or the actual torque of the bit can be used is when it is impossible to proceed from the actual orientation of the end face of the bit when obtaining accurate or reasonably fast data. For example, such a case may occur during blind drilling (with complete absorption of drilling fluid) or other cases in which the driller does not receive data from the bit face orientation sensor 430f. In such cases, the actual bit torque and / or the actual differential pressure of the hydraulic downhole motor can be used to determine the actual orientation of the bit face. For example, if all other drilling parameters remain unchanged, a change in the actual bit torque and / or the actual differential pressure of the hydraulic downhole motor may indicate a proportional rotation of the bit face orientation in the same or in the opposite direction of drilling. For example, an increase in torque or differential pressure may indicate that the end of the bit is changing in the opposite direction of drilling, while a decrease in torque or differential pressure may indicate that the end of the bit is moving in the direction of drilling. Thus, the data obtained from the bit torque sensor 430a and / or the differential pressure sensor 430e of the hydraulic downhole motor can be used by the bit face controller 420 to generate the shaft drive signal, whereby the shaft can rotate in such a way that it is corrected or otherwise taken into account any change in the position of the end face of the bit, which is characterized by a change in the actual torque of the bit and / or with the actual pressure drop of the hydraulic downhole motor.

In addition, in some modes of operation, the data obtained by the bit face controller 420 from the bit face orientation sensor 430f may be delayed from the actual bit face orientation. For example, the bit face orientation sensor 430f may only determine the actual position of the bit face periodically, or a significant period of time may be required to transfer data from the bit face to the surface. In fact, in prior art systems, such a delay can often be 30 seconds or more. Therefore, in some implementations within the framework of the present description, it may be more accurate or otherwise beneficial that the bit face controller 420a uses the actual torque and pressure data obtained from the bit torque sensor 430a and the differential pressure sensor 430e of the hydraulic downhole motor, in addition, if not in the alternative, to using the actual bit-end position data obtained from the bit-end orientation sensor 430f. However, in some embodiments of the present description, real-time inclinometric measurements can be applied, as disclosed in FIG. 9A and 9B to obtain data regarding the direction of the BHA and the orientation of the end face of the bit.

As shown in FIG. 4A, the user inputs 410 of the device 400a may also include the nominal bit load 410i, the nominal differential pressure of the hydraulic downhole motor 410j, the input 410k of the penetration speed, the input 410l of the load on the bit, the input 410m of the differential pressure of the hydraulic bottom hole motor and the ultimate load 410n on the hook, and also, at least one control module 420 may also include a drawworks controller 420b. The sensor group 430 of the device 400a may also include a hook load sensor 430g, a mud pump pressure sensor 430h, a bit depth sensor 430i, an annular pressure sensor 430j, and a penetration rate sensor 410k. Each group of sensors 430 may be located on the surface of the wellbore, in the well (e.g., IPB), or elsewhere.

As described above, the bit face controller 420a is designed to generate a shaft drive control signal using data obtained from user inputs 410 and from sensors 430, followed by a shaft drive control signal to the shaft drive 440, thereby controlling the orientation of the bit end by adjust the orientation and speed of the shaft. Thus, the control signal of the shaft drive serves to control (at least partially) the orientation of the shaft (for example, azimuth), as well as the speed and direction of rotation of the shaft (if any).

A drawworks controller 420b is provided for generating a control signal for a drawworks drum drive (or brake) also using data received from a user input 410 and from sensors 430. After that, a drawworks controller 420b provides a control signal for a drawworks drive to a drawworks drive 450, thus controlling the feed direction and speed of the drawworks. The drawworks drive 450 may form at least a portion of, or may be formed, at least a portion of the drawworks 130 shown in FIG. 1 and / or drawworks 320 shown in FIG. 3. The scope of the present description can also be applied or easily adapted to other devices for adjusting the vertical position of the drill string. For example, the drawworks controller 420b may be a lift controller, and the drawworks drive 450 may comprise or include a drill string lifting device other than or additional to the drawworks (e.g., rack and pinion lifting device).

The device 400a also includes a comparison device 420c that compares the current hook load data with the nominal bit load, obtaining the current bit load. The current hook load data is obtained from the hook load sensor 430g, and the nominal bit load is obtained from the corresponding user input 410i.

The drawworks controller 420b compares the current bit load with the input bit load data. The current bit load is obtained from the comparison device 420c, and the entered bit load data is obtained from the corresponding user input 410i. The entered bit load data obtained from user input 410i may be a separate value characterizing the required bit load. For example, if the actual bit load is different from the bit load entered with a predetermined value, then the winch drive control signal may indicate that the winch drive 450 feed or reel the cable to a length corresponding to the necessary correction of the bit load. However, the entered bit load data obtained from user input 410i may alternatively be a range within which the bit load is desired. For example, if the actual bit load is outside the input range of the bit load, the control signal of the drawworks drive may indicate that the drawworks drive 450 feed or reel the cable to the length necessary to restore the actual load on the bit within the load input range to bit. In an embodiment, a drawworks controller 420b may serve to optimize drilling process parameters associated with a bit load, for example, maximizing the actual bit load while not exceeding the value or input range of the bit load.

The device 400a also includes a comparison device 420d that compares the pressure of the mud pump with the nominal differential pressure of the hydraulic downhole motor to obtain an “uncorrected” differential pressure value of the hydraulic downhole motor. The mud pump pressure data is obtained from the mud pump pressure sensor 430h, and the nominal differential pressure of the hydraulic downhole motor is obtained from the corresponding user input 410j.

The device 400a also includes a comparison device 420e that uses the uncorrected differential pressure of the hydraulic downhole motor along with bit depth data and pressure data in the annulus to obtain a “corrected” or current differential pressure of the hydraulic downhole motor. The bit depth data is obtained from the bit depth sensor 430i, and the annular pressure data is obtained from the annular pressure sensor 430j. The annular pressure sensor 430j may be a surface annular pressure sensor, such as the sensor 159 shown in FIG. 1 and / or a downhole annular pressure sensor, such as sensor 170a shown in FIG. 1, both in that and in the other case, it can measure the pressure in the annular space between the casing or borehole diameter and the drill string element.

The drawworks controller 420b compares the current value of the differential pressure of the downhole motor with the entered differential pressure of the hydraulic downhole motor. The current differential pressure of the downhole motor is obtained from the comparison device 420e, and the entered differential pressure of the hydraulic downhole motor is obtained from the corresponding user input 410m. The entered differential pressure of the hydraulic downhole motor obtained from the input 410m of the user can be a separate value characterizing the desired value of the differential pressure of the hydraulic downhole motor. For example, if the current value of the differential pressure of the hydraulic downhole motor differs from the entered differential pressure of the hydraulic downhole motor by a predetermined value, then the winch drive control signal may indicate that the winch drive 450 feed or reel the cable to a length corresponding to the necessary correction of the differential pressure of the hydraulic bottomhole engine. However, the inputted differential pressure of the downhole motor obtained from the user input 410m may alternatively be a range within which the differential pressure of the downhole motor is desired. For example, if the current value of the differential pressure of the hydraulic downhole motor is outside this range, then the control signal of the drive of the drawworks can indicate that the drive 450 of the drawworks feed or reel the cable to the length necessary to restore the current value of the differential pressure of the hydraulic downhole motor within the entered range. In an exemplary embodiment, the drawworks controller 420b may serve to optimize drilling process parameters associated with the differential pressure of the downhole motor, for example, maximizing the pressure drop of the hydraulic downhole motor without exceeding the entered value or range.

The drawworks controller 420b may additionally or alternatively compare the actual penetration rate data with the entered penetration rate data. The actual penetration rate data is obtained from the penetration rate sensor 430k, and the entered penetration rate data is obtained from the corresponding user input 410k. Entered penetration rate data obtained from user input 410k may be a single value characterizing a desired penetration rate. For example, if the actual penetration rate differs from the entered penetration rate by a predetermined amount, then the winch drive control signal may indicate that the winch drive 450 feed or reel the cable to a length corresponding to the necessary correction of the penetration rate. However, the entered penetration rate data obtained from the user input 410k may alternatively be a range within which the penetration rate is desired. For example, if the actual penetration rate is outside the entered range of the penetration rate, then the winch drive control signal may indicate that the winch drive 450 feed or reel the cable to the length necessary to restore the actual penetration rate within the entered penetration rate range. In an exemplary embodiment, the drawworks controller 420b may serve to optimize drilling process parameters related to the penetration rate, for example, maximizing the actual penetration rate without exceeding the entered value or the penetration rate range.

The drawworks controller 420b may also use data received from the bit end controller 420a to generate a control signal for the drawworks drive. Changes in the actual load on the bit can cause changes in the actual torque of the bit, the actual differential pressure of the hydraulic downhole motor, and the actual orientation of the end of the bit. For example, as the load applied to the bit increases, the actual orientation of the bit end may rotate in the opposite direction to the bit rotation (due to reactive torque), while the actual bit torque and downhole hydraulic pressure may increase proportionally. Therefore, the bit face controller 420a may send data to the drawworks controller 420b indicating whether it is necessary to feed the winch cable or reel, and possibly the appropriate feed rate necessary to bring the actual bit face orientation into line with the entered value or bit face orientation range provided corresponding user input 410h. In an embodiment, the drawworks controller 420b may also provide data to the bit face controller 420a to rotate the shaft clockwise or counterclockwise by an amount and / or at a speed sufficient to compensate for the increased or decreased load on the bit, bit depth or pressure in annular space.

As shown in FIG. 4A, user input 410 may also include input of tension limit 410n. When generating a control signal for the drawworks drive, the drawworks controller 420b can ensure that the drawworks do not pull the cable beyond the tension limit obtained from the user input 410n. The tension limit is also known as the ultimate load on the hook and, among other parameters, may depend on the specific configuration of the rig.

In an exemplary embodiment, the drawworks controller 420b may also forward data to the bit face controller 420a so that the bit face controller 420a rotates the shaft, for example, an amount in the direction and / or at a speed sufficient to compensate for reaching or exceeding the tension limit. The bit face controller 420a may also forward data to the drawworks controller 420b so that the drawworks controller 420b increases or decreases the load on the bit, or adjusts the feed of the drill string, for example, by an amount, in the direction and / or at a speed sufficient to properly adjust bit end orientation.

Next, in FIG. 4B shows a generalized schematic representation of at least part of another embodiment of an apparatus 400b. Like device 400a, device 400b is an exemplary embodiment of device 100 shown in FIG. 1 and / or the device 300 shown in FIG. 3, and serves as an example of an environment in which the method 200a shown in FIG. 2A and / or the method 200b shown in FIG. 2B.

Like device 400a, device 400b includes a group of user inputs 410 and at least one control module 420. At least one control module 420 includes a bit end controller 420a and a drawworks controller 420b described above, as well as a mud pump controller 420c. The device 400b also includes or is otherwise connected to a group of sensors 430, a shaft drive 440 and a drawworks drive 450, as is the device 400a. The device 400b also includes, or is otherwise connected to, a mud pump actuator 460 that is designed to control the operation of the mud pump, such as the mud pump 180 shown in FIG. 1. In the exemplary embodiment of the device 400b shown in FIG. 4B, each group of sensors 430 may be located on the surface of the wellbore, in the well (e.g., IPB), or elsewhere.

The mud pump controller 420c is designed to generate a mud pump drive control signal using data received from user inputs 410 and sensors 430. Thereafter, the mud pump controller 420c provides a mud pump drive control signal to the mud pump actuator 460, thereby controlling speed, flow rate and / or mud pump pressure. The mud pump controller 420c may form at least a portion, or may be formed, at least a portion of the controller 190 shown in FIG. 1 and / or the controller 325 shown in FIG. 3.

As described above, the differential pressure of the hydraulic downhole motor may be proportionally or otherwise related to the orientation of the bit face, the load on the bit and / or the torque of the bit. Therefore, the mud pump controller 420c can be used to influence the actual differential pressure of the hydraulic downhole motor, helping to bring the actual orientation of the bit face into line with the entered value or range of bit face orientation that is provided by the corresponding user input. Such operation of the mud pump controller 420c may be independent of the operation of the bit face controller 420a and the drawworks controller 420b. Alternatively, as indicated by the double arrows 462 shown in FIG. 4B, the operation of the mud pump controller 420c to provide or maintain the desired bit face orientation can be performed in conjunction with or in conjunction with the bit face controller 420a and the drawworks controller 420b.

The controllers 420a, 420b and 420c shown in FIG. 4A and 4B may or may include programmable or model-independent adaptive controllers, such as those supplied by CyberSoft, General Cybernation Group. The controllers 420a, 420b and 420c can also, collectively or independently, be used on any standard or advanced computing device, such as one or more personal computers or servers, portable devices, PLC systems and / or mainframes, among others.

FIG. 4C is another generalized block diagram identifying exemplary elements of another alternative drilling control system 400c (located at the wellsite) of the device 100 shown in FIG. 1. In this embodiment, the block diagram includes a main controller 402 including a bit face computer 404, a control module 420 including a bit face controller 420a, a drawworks controller 420b, and a mud pump controller 420f. In addition, the control system includes a user input device 470 that can receive inputs 410 shown in FIG. 4A, an output display 472, as well as sensors 430 connected to the main controller 402. In the shown embodiment, the bit end computing machine 404 and the control module 420 are devices that can share the same processor or operate using separate processors, performing various but collaborative functions. Accordingly, a main controller 402 is shown, which includes controllers for a drawworks, a bit face and a mud pump, as well as a bit face computer 404. However, in other embodiments, the bit end computing machine 404 operates using a separate processor to calculate and determine the path. User input device 470 and display 472 may include at least a portion of a user interface, such as user interface 305 shown in FIG. 3. The user interface and controller may be separate elements that are connected using wired or wireless means. However, alternatively they can, for example, be components of a separate system.

As indicated above, the drilling plan includes a wellbore profile or a predetermined drilling path. A drilling plan is a preselected trajectory of a drilled wellbore, usually before conditions require changes to the drilling plan. Typically, it identifies key bending points of the wellbore and the optimal degrees of bending that are used to achieve the positional goal or goals of the wellbore, called target locations. To the extent possible, the main controller 402 controls the rig, directing the BHA to the target location along a predetermined drilling path within the specified tolerance zone.

Computing machine 404 is a controller or part of a controller for calculating a control drilling path for a BHA. This path follows a predetermined path of wellbore drilling within the margin of error known as the tolerance zone (also referred to herein as the “tolerance cylinder” as an example). Based on positional and other responses, as well as on the basis of the initial, predetermined drilling path, the bit face computer 404 either sets the recommended angular settings of the bit end within 0-360 degrees and the drilling distance in feet or meters with this setting of the bit end parameters, or gives recommendation to continue drilling in rotary drilling mode. Preferably, the angular settings as little as possible differ from the drilled section in order to minimize sharp bends, which can complicate the installation of the casing. These recommendations provide the BHA in the right direction with the effective achievement of the target location.

The end face calculator 404 introduces recommendations based on a number of factors. For example, a bit face calculator 404 examines an initial control drilling path, estimates guide orientations, and estimates the predicted bit depth in real time. In some embodiments, said machine 404 evaluates additional information that helps to identify the location and direction of the BHA. In other embodiments, machine 404 only evaluates guiding orientations and the original drilling path.

The initial control drilling path can be directly entered by the user or can be calculated by the end face computing machine 404 based on the parameters entered by the user. Guiding orientations can be determined on the basis of previous or existing coordinate data from the results of periodic or operational geophysical surveys to theoretically determine the position of the bit. This may include, for example, bending parameters or borehole deviation rate obtained at user defined drilling intervals to a predetermined depth. These parameters can be used as starting points for the next drilled control curve and can be obtained from an analysis of the current nature of drilling, taking into account previous drilling parameters. The calculation of the distance in a straight line to a given target location can be performed based on the predicted bit position in real time. The indicated real-time predicted bit position can be calculated by the bit face computer 404 or the control module 420 based on static and / or dynamic data received from the sensors 430. If the values are calculated by the control module 420, they can be sent to the bit face computer 404 for additional processing. The indicated values of the predicted bit depth can be calculated using any number of methods, including, for example, the minimum arc method, the guide orientation method and the linear method. After calculating the position, it is used as a starting point for calculating the normal clearance and any subsequent reference path, or for calculating the refined path.

Using these inputs, the bit face calculator 404 determines where the actual drilling path coincides with a predetermined or reference drilling path. Based on the obtained data, the bit end end computer 404 generates control commands that help to keep the actual drilling path on a given drilling path, that is, within the tolerance zone. These commands can be output as bit face orientation commands, which can be used in input 410h in FIG. 4A. In some embodiments, the generated control commands are based on the degree of deviation of the actual drilling path relative to a given drilling path, as further described below. An exemplary method 500, implemented by a bit end face 404 computer to determine the level of deviation from the desired path and to determine the updated path, is shown in FIG. 5A.

In FIG. 5A, method 500 may begin with operation 502, in which the bit end end computer 404 receives a user-entered control or predetermined drilling path. A reference or predetermined drilling path is a desired path that can be based on a number of factors, but is usually the most efficient path leading from the rig to the target location.

In operation 504, the bit face calculator 404 estimates the current desired drilling path, guiding orientations, and the predicted bit depth. As described above, the guiding orientations are based on previous inclinometry and predicted bit depths, or the position of the bit is determined by the bit end end computer 404, the control module 420, or another controller or module in the main controller 402. The received data is transmitted from the computational element to the computer 404 the end face of the bit and include the value of the intensity of the deviation of the wellbore, which is used to calculate correction curves, if necessary, as described below. In this case, as a first iteration, the current desired drilling path may correspond to a control or predetermined drilling path defined in the drilling plan adopted in operation 502.

In operation 506, the bit face calculator 404 determines the actual drilling path based on the guiding orientations and the predicted bit depth. As indicated above, additional data may be used to determine the actual drilling path, and in some embodiments, guidance may be used to estimate the actual drilling path if determining the actual drilling path is uncertain or the touch input required for calculation is limited. In operation 508, the bit face calculator 404 determines whether the actual path is within the tolerance zone determined by the current desired drilling path. The tolerance zone or the continued drilling zone is shown and described in FIG. 5B.

In FIG. 5B shows an example of a predetermined wellbore drilling path 530, indicated by a dashed line. A predetermined wellbore path 530 forms the axis of the proposed tolerance cylinder 532, threshold zone 534, and correction zone 536. As long as the actual drilling path is within the tolerance cylinder 532, the actual drilling path is within an acceptable range of deviation from the predetermined drilling path, and drilling can be continued without control adjustment. The tolerance cylinder can be determined within certain percentages of the distance from the desired trajectory or from the diameter of the well, and may partially depend on factors that differ for each proposed well. For example, alternatively, a correction zone can be set at about 50% deviation or about 20% deviation from a given path, while a threshold zone can be set at about 25% or about 10% deviation from a given path. Thus, returning to FIG. 5A, if the bit face calculator 404 determines that the actual path is within the tolerance zone around the predetermined drilling path in step 508, then the process may simply return to step 504, awaiting confirmation of the next guide orientation and / or predicted bit depth.

If, at step 508, the bit end calculator 404 decides that the actual drilling path is outside the tolerance cylinder 532 shown in FIG. 5B, then the bit-end computing machine 404 determines whether the actual path is within the threshold zone 534, and the control unit 420 can generate one or more control signals that enable the BHA to be held in the desired direction. The threshold zone 534 in FIG. 5B is concentrically located around tolerance cylinder 532. It includes an inner boundary defined by tolerance cylinder 532 and an outer boundary defined by correction zone 536. If the actual drilling path was in the threshold zone 534, then the actual drilling path can be estimated as moderately deviating from the given drilling path 530. In this embodiment, the correction zone 536 is concentrically located around the threshold zone 534 and defines the entire area outside the threshold zone 534. If the actual drilling path was in the correction zone 536, then the actual drilling path can be estimated as significantly deviating from the specified drilling path 530.

Next, returning to FIG. 5A, if the actual drilling path is within the threshold zone 534 in step 510, then the bit face calculator 404 can calculate a three-dimensional curved sectional path from the predicted bit position in the direction of the given drilling path 530 in step 512. As indicated above, this calculation may be based on data obtained from current or previous inclinometry files and may include a prediction of bit depth or bit position and the value of the deviation intensity of the wellbore. The calculated curved path preferably includes the orientation of the bit end required to move along the curved section and the measured drilling depth in feet or meters, required, for example, to return the BHA to the tolerance zone with the highest possible efficiency, but with minimizing any excessive correction.

The specified corrected guide path, as one or more control signals, is supplied to the control unit 420 in operation 514. Thus, one or more controllers 420a, b, f in FIG. 4C receives data on the desired bit face orientation and other advisory information that allows the controller to generate one or more control signals that direct the BHA. From a predetermined drilling path, the control module 420 and / or other elements of the drilling control system 400c located at the drilling site can control the winch, top drive and mud pump by adjusting the direction of the BHA according to the adjusted path.

From here, the process returns to operation 504, in which the bit face calculator 404 estimates the current predetermined path, guiding orientations, and the predicted bit depth. In this case, the current predetermined path is changed using the curved section of the path calculated in step 512. Accordingly, during the next iteration, the drilling path, evaluated as a “predetermined” drilling path, becomes the corrected path.

If in operation 510 the actual drilling path was not within the threshold zone 534, then the bit face computer 404 determines that the actual drilling path should be in the correction zone 536 and determines whether the predetermined path is a critical drilling path in operation 516. Critical a drilling path is usually a path in which there are factors that limit the appropriateness of creating a new predetermined drilling path to the target location. For example, a critical drilling path may be a path selected to bypass underground rock formations, with areas outside of threshold zone 534 including a rock formation. Of course, the definition of a given drilling path as a critical path can be made for any reason.

If the predetermined drilling path is not defined as a critical path in operation 516, then the bit face calculator 404 generates a new predetermined path based on the predicted current location of the bit relative to the target location. The specified new predetermined path may be independent, or may even not intersect with the original planned path, and may be generated based, for example, on the most efficient path to the target location from the current one. For example, a new path may include the minimum amount of bend required from the predicted current location of the bit to the target. The new predetermined path may indicate the measured depth, inclination, azimuth, north-south and east-west, the end face of the bit and the intensity of the deviation of the wellbore or bend at equal distances between the observation points, for example, after about 100 feet or 30 meters. The trajectory, bit face orientation data, as well as other data can be sent to the control module 420, while the control module 420 can adjust the BHA to follow the new path with the greatest possible accuracy. The indicated output may include the estimated recommended bit end angle and the remaining drilling distance. The process returns to operation 504, in which the bit end end computer 404 estimates the current predetermined path, guiding orientations, and the predicted bit depth. Now, the current predetermined flow path is the new predetermined path calculated in step 518.

If a predetermined path is defined as a critical path in step 516, then the bit face end computer 404 creates a path, following which the bit intersects the original predetermined path in continuous drilling. To this end, as indicated in step 520, the bit face calculator 404 calculates at least a first three-dimensional curved sectional path (“cross path”) from the predicted bit position to a predetermined drilling path or to a target. Optionally, the bit end calculator 404 may further calculate a second three-dimensional curved sectional path to combine the BHA on a given path from the cross path before reaching the target. These curved sectional paths can be divided into a held or a straight section, depending on how far the BHA deviated into the correction zone. Of course, if the intersection path is defined without a second three-dimensional curvilinear sectional path, then the refined plan will be held, or a direct section, from deviation to a new target, final destination or location on the original given path.

The bit face calculator 404 provides an updated guide path including the newly generated curve (s) in the form of one or more control signals to the control module 420 in step 514. As indicated above, the specified target path may include the measured depth, inclination, azimuth, north -yug and east-west, the end face of the bit and the intensity of the deviation of the wellbore through equal distances between the observation points, for example, after about 100 feet or 30 meters. During the next iteration, the bit face calculator 404 estimates the current predetermined path, the guiding orientations and the predicted bit depth, the current predetermined path being the adjusted predetermined path in operation 504.

The method 500 is re-performed during the drilling process in order to maintain the actual drilling path on a given path and changing the given path, as the case may be. In some embodiments, the process is ongoing in real time. This can successfully provide accelerated drilling without the need for shutdowns, so that the technologist consults the drilling plan or evaluates the inclinometry data. In other embodiments, the process is repeated after a predetermined drilling period or interval, such as, for example, approximately 90 seconds, approximately five minutes, approximately ten minutes, approximately thirty minutes, or any other duration. Alternatively, iteration may be performed while driving to a predetermined drilling depth. For example, the process can be repeated when an existing wellbore extends approximately five feet (≈1.5 m), approximately ten feet (≈3 m), approximately fifty feet (≈15 m), or some other depth . The process interval may also include both time and depth components. For example, the process may include drilling for at least about thirty minutes, or until the wellbore extends by about ten feet. In another example, the interval may include drilling until the wellbore extends about twenty feet, but no longer than about ninety minutes. Of course, the above time and depth values for the interval are merely examples, and many other values are also included in the scope of the present description.

After the end face of the bit is calculated by the computer 404, usually electronically, the corrected path for the original drilling plan and the adjusted path to the target location are passed to the controls of the rig site control system. After calculating the correction, the bit face calculator 404 or other well site control element, including the control module 420, introduces bit end recommendations or instructions that can be executed on the rig.

In some embodiments, the user can selectively control whether the bit face calculator 404 creates a new predetermined path to the target, or creates an adjusted predetermined path to the original plan when the actual drilling path is in correction zone 536. For example, the user may select a default function that instructs the correction option to calculate the path to the “target” or “source plan”. In some embodiments, the default setting may be active for only certain parts of the original drilling path.

Since trajectory control decisions are based on the deviation of the borehole from a given trajectory, after each inclinometric measurement, a normal scheduled non-contact scan of a given well can be performed. If the drilling position is in the threshold zone, then a shift of the borehole back to the plan is usually recommended. If the well continues to deviate from the plan and enters the correction zone, then usually a modified predetermined trajectory to the target is calculated as correction or correction of the initial plan is performed.

In some embodiments, one or more variables are evaluated in addition to or instead of online prediction of bit depth or guiding orientations. Input variables may vary in each calculation. In addition, the intensity of the deviation of the wellbore or curvature can be used to calculate a suitable curve that limits the amount of oscillation and prevents going beyond the drilling path. The borehole deviation rate or curvature can be obtained by analysis using the current drilling parameters of the BHA based on previous drilling parameters or a combination thereof.

When creating a modified drilling plan that returns the BHA to the original path of the drill bit, when, for example, the predicted position of the bit is within the threshold zone 534 or when the specified drilling path deviates significantly and is a critical path, the task is to return to the original, predetermined drilling path to reach the target location. The curve profile, however, is still under consideration, since the curve profile can affect friction, vibration and other factors. The value of the deviation intensity of the wellbore can be used to calculate one or both calculations of the curve, as before, with the first curve turning the bit along the original given path or towards the target, and the optional second curve allows the BHA to more quickly align and follow a given path with a limited value , or without going beyond or excessive correction. One way to determine the profile of a curve involves calculating a curve-straight or curve-straight-curve profile to an endpoint or a target location in the original plan, and then recalculating at the target-minus-1 endpoint, measurement period inclinometry or distance calculation, or another period. The calculation is preferably carried out electronically. It continues, reaching the goal-minus-2 point, and so on, until the calculation stops. The last successful profile calculation can be used to obtain one or two arcs having the smallest permissible curvature with the corresponding drilling length. The indicated values determine the recommended bit face information for the first correction curve, which is used to generate a new drilling path and to guide the BHA. When the actual drilling path reaches the final curve intersecting the original drilling plan, in a further embodiment, using a second, final curve returning to the original drilling plan, the specified final curve is drilled with a second estimated drilling length and degree of curvature.

It should be noted that although the tolerance cylinder 532 and the threshold zone 534 are shown as cylinders without a circular cross-section, they may have a different shape, including but not limited to oval, conical, parabolic or other, for example, or may not be concentric around a given path 530 drilling. Alternative forms may, for example, allow the bit to deviate from a given trajectory in one direction more than in the other, depending, for example, on geological deposits on one side of a given trajectory. In addition, although the described example includes three zones (tolerance zone, threshold zone, and correction zone), this is only necessary for explanation. In other embodiments, additional zones may be included, and additional factors may be assessed when deciding whether to create a path that intersects the original predetermined path, whether to create a path that goes directly to the target location without intersecting the original predetermined drilling path, or how much DLS can be gentle on the correction curve (s).

In some embodiments, the driller may increase or decrease the tolerance during drilling by entering data into the bit end end computer 404. This can help minimize or prevent over-adjustment or over-fluctuations in the drilling path.

After calculation, the output of data from the end face computer 404 may act as input to the control unit 420 of FIG. 4C, or control module 420 of FIG. 4A. For example, data output from a bit end computer 404 may include, but is not limited to, bit end orientation suitable as input 410h in FIG. 4A. In this figure, the bit face orientation serves as input to the device 400a and is used by the bit face controller 420a to control the shaft drive 440. An additional data output from the end face computer 404 may be used as inputs to the device 400a. Using these inputs, the bit end controller 420a, the drawworks controller 420b and the mud pump controller 420f can control the rig or BHA directly by guiding the BHA along the desired drilling path.

In some embodiments, a warning module may be used to warn drillers and / or well monitoring stations of the deviation of the bit from a given drilling path, of any potential problem with the drilling system, or to report other information that needs attention. When drillers are not present on the rig, that is, the driller (s) is away from the rig, the alert module may be coupled to the bit face calculator 404 so that when the bit end calculator 404 detects a bit deviation from the predetermined drilling path, the notification module warns the driller and, in some cases, can wait for manual user intervention, for example, confirmation, before the bit is guided along a new path. This warning may be carried out at the rig using any suitable means and may be displayed on the display 472 in the form of a visual alarm. Alternatively, the warning may be an audible alarm or may cause an alarm to be transmitted via a radio signal sent to specific locations or to specific individuals.

In addition to transmitting an alarm to a display 472 or to another location near the rig, the emergency module can transmit an alarm to adjacent objects (outside the rig site). This may allow external monitoring and may allow the driller to perform remote control. These alarms may be transmitted using any suitable communication line. For example, in some embodiments, when the alert module sends an alarm to a remote location, the alarm may go through a satellite communications system. More specifically, one or more orbital (usually in a fixed position) satellites can be used to transmit communication signals (potentially bi-directional) between the well monitoring station and the warning module on the offshore drilling platform. In the alternative, radio, cellular, optical, or fixed wired signal transmission systems may be used to communicate between the alert module and drillers or a well monitoring station. In situations where the location of the oil well is an offshore platform, a satellite communications system may be used, since communications systems such as cellular, wireline and ship-to-shore are in some situations impractical or unreliable. It should be noted that external control and regulation can be performed without specific alarms, but using the described remote access systems.

A central monitoring station for monitoring wells in most cases can be a computer or server, which is connected to many warning modules, each of which is placed on different drilling platforms. A well monitoring station can receive various types of signals (for example, satellite, radio, cellular, wired, optical, ship-shore and telephone) from several drilling sites on which the warning module is installed. The well monitoring station may also transmit selective information from the alert module to a specific remote user terminal of a group of remote user terminals associated with the alert module. A well monitoring station may also receive information or commands from a remote user terminal. The remote user terminal, through the well monitoring station and the alert module, displays the drilling or production parameters for the well associated with the alert module.

In most cases, a monitoring station for monitoring wells can be located in a central data terminal and can be connected to a warning module at a drilling site, for example, via a satellite communication line. A monitoring monitoring station can allow users to identify alarms based on information and data collected at a drilling site (s) using various replication and synchronization methods. For this reason, the received data may not be substantially operational in each embodiment of the invention, since the alarms depend on the data that was transmitted from the drilling site to the central data terminal by radio or satellite (which, by definition, takes some time).

In one embodiment, an example alert module monitors one, two, or more specific processes or parameters. The working section and the actual values on which the alarm is set also usually comes from the database and metadata, and therefore, when the parameter refers to a specific data type, the corresponding operations can be selected by the user.

In FIG. 6A is a flowchart of a method 600a according to one or more aspects of the present description. The method 600a may be performed in conjunction with one or more elements of the device 100 shown in FIG. 1, during operation of device 100. For example, method 600a may be performed to optimize drilling efficiency during drilling operations performed by device 100, any of the control systems disclosed in any of the figures in this application may be performed, including, among others, FIG. 3 and 4A-C.

Method 600a includes operation 602, during which parameters for calculating specific mechanical energy are detected, collected, or otherwise obtained. These parameters may be referred to in this application as specific mechanical energy parameters and may be used as input in FIG. 4A-C and others. Specific mechanical energy parameters include static and dynamic parameters. Thus, some of these parameters change essentially continuously. The indicated dynamic parameters of the specific mechanical energy include the load on the bit, the rotational speed of the drill bit, the torque of the drill string and the speed of penetration of the drill bit through the formation. Other parameters of specific mechanical energy rarely change, for example, after raising a drill string, reaching a new type of rock and changing the type of bit, among other events. Specified static parameters of specific mechanical energy include mechanical efficiency and drill bit diameter.

The specific mechanical energy parameters can be essentially or completely obtained automatically, with little or no user input. For example, during the first iteration, during the operations of method 600a, the static parameters of the specific mechanical energy can be obtained through an automatic query from the database. Thus, during subsequent iterations, the static parameters of the specific mechanical energy may not require re-production, for example, if the type of drill bit or the characteristics of the formation have not changed after the previous repetition of method 600a. Therefore, the execution of operation 602 in many iterations may require the determination of only dynamic parameters of specific mechanical energy. The determination of the dynamic parameters of the specific mechanical energy can be carried out by means of or in other interaction with various sensors, such as the sensors shown in FIG. 1, 3, 4A and / or 4B.

Subsequent operation 604 in method 600a involves calculating the specific mechanical energy. In an embodiment, the specific mechanical energy is calculated according to the following formula:

MSE = MEP × [(4 × WOB) / (π × DIA ² ) + (480 × RPM × TOR) / (ROP × DIA ² )],

wherein:

MSE = specific mechanical energy (pounds per square inch);

MER = mechanical efficiency (ratio);

WOB = Chisel Load (lbs);

DIAMETER = drill bit diameter (inches);

RPM = bit rotation frequency (rpm);

TOR = drill string torque (foot-pounds); and

ROP = rate of penetration (feet per hour).

MEP may also be referred to as the efficiency of the drill bit. In an embodiment, MEP is 0.35. However, MEP may vary depending on one or more different factors, such as, for example, bit type, reservoir type and / or other factors.

The method 600a also includes a decision operation 606, during which the specific mechanical energy calculated in the previous step 604 is compared with the ideal specific mechanical energy. The ideal specific mechanical energy used for comparison in the decision operation 606 may be a single value, such as 100%. Alternatively, the ideal specific mechanical energy used for comparison in the decision operation 606 may be a target range of values, such as 90-100%. In the alternative, the ideal specific mechanical energy may be a range of values derived from an advanced analysis of the area to be drilled, taking into account the various formations drilled in the current operation.

If it is determined in step 606 that the specific mechanical energy calculated in step 604 is equal to the ideal specific mechanical energy or is within the ideal range of the specific mechanical energy, method 600a may be repeated to repeat step 602. However, if it is determined in step 606, that the calculated specific mechanical energy is not equal to the ideal specific mechanical energy or is not within the ideal range of specific mechanical energy, then perform additional operation 608. B during operation 608, one or more operating parameters are adjusted to approximate the specific mechanical energy to an ideal value of the specific mechanical energy or a value within an ideal range of specific mechanical energy. For example, while referring to FIG. 1 and 6A, operation 608 may include increasing or decreasing the load on the bit, the rotational speed of the drill bit and / or the torque of the drill string, transmitting a control signal from the controller 190 to the upper drive 140 and / or the winch 130, in order to change the rotational speed of the drill drill bit, drill string torque and / or bit load. After performing operation 608, method 600a may be repeated with repeating operation 602.

Each of the operations of method 600a may be performed automatically. For example, automated determination of the dynamic parameters of specific mechanical energy and a search in the database of static parameters of specific mechanical energy have already been described above with respect to operation 602. The controller 190 in FIG. 1 (as well as others described in this application) can serve to automatically perform the calculation of specific mechanical energy in operation 604, and can also serve to automatically perform a comparison of specific mechanical energy in the operation of solution 606, in which both calculation and comparison of specific mechanical energy may be performed periodically, at random intervals, or otherwise. The controller may also serve to automatically generate and transmit control signals in operation 608, for example, in response to a comparison of specific mechanical energy in operation 606.

In FIG. 6B is a block diagram of an apparatus 690 in accordance with one or more aspects of the present disclosure. The device 690 includes a user interface 692, a drawworks 694, a drive system 696 and a controller 698. The device 690 can be used within the environment and / or device shown in FIG. 1, 3 and 4A-4C. For example, drawworks 694 may be substantially similar to drawworks 130 shown in FIG. 1, the drive system 696 may be substantially similar to the top drive 140 shown in FIG. 1, and / or the controller 698 may be substantially similar to the controller 190 shown in FIG. 1. Device 690 may also be used in the method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, method 500, in FIG. 5A and / or the method 600a shown in FIG. 6A.

User interface 692 and controller 698 may be separate elements that are connected through wired or wireless means. However, user interface 692 and controller 698 may alternatively be constituent elements of a separate system 699, as indicated by dashed lines in FIG. 6B.

User interface 692 includes devices 692a for user input of one or more setpoints and / or performance ranges (e.g., MER) and devices 692b for user input of one or more setpoints and / or bit diameter ranges. Each of the data entry devices 692a, 692b may include a keyboard, a speech identification device, a disk, a button, a switch, a slide selector, a switch, a joystick, a mouse, a database (for example, with offset information) and / or another standard or advanced device data entry. Such data entry devices may support data entry from local and / or remote locations. Alternatively, or additionally, data entry devices 692a and / or 692b may include a device for the user to select MER values or ranges and drill bit diameters, for example, via one or more drop-down menus. The MER and DIA data, optionally or alternatively, can be selected by the 698 controller when performing one or more database searches. Typically, a data entry device and / or other elements within the scope of the present description may support the operation and / or control of the system from stations at the drilling site, as well as from one or more remote locations associated with the system via a communication line, network, local area network, global networks, the Internet and / or radio, among other means.

User interface 692 may also include a display 692c for visually displaying information to a user in text, graphic, or video form. Display 692c may also be used by a user to enter MER and DIA data in conjunction with data entry devices 692a and 692b. For example, devices for entering predetermined efficiency data and bit diameters 692a and 692b may be included in or otherwise connected to a display 692c.

Winch 694 includes a penetration rate sensor 694a that is designed to detect a value or range of penetration rate, and may be substantially similar to the penetration rate sensor 130a shown in FIG. 1. The penetration rate data obtained by the penetration rate sensor 694a may be sent by electronic signal to the controller 698 via wired or wireless transmission. The drawworks 694 also includes a control loop 694b and / or other means for controlling the feed and / or reeling of the drill cable (such as drill cable 125 shown in FIG. 1).

The drive system 696 includes a torque sensor 696a that is designed to detect the value or range of the reactive torque of the drill string, almost the same as the torque sensor 140a and drill string 155 shown in FIG. 1. The drive system 696 also includes a bit speed sensor 696b that is designed to detect a value or a range of a bit’s rotational speed in the wellbore (eg, rotational speed of the drill bit), almost the same as the bit speed sensor 140b, the drill bit 175 and the barrel wells 160 shown in FIG. 1. The drive system 696 also includes a bit load sensor 696c that is designed to detect a value or range of a bit load, almost the same as the bit load sensor 140c shown in FIG. 1. Alternatively, or in addition, the load sensor on the bit 696c may be located separately from the drive system 696, in any other element shown in FIG. 6B, or elsewhere. The drill string torque, drill bit rotation speed, and bit load data obtained using sensors 696a, 696b, 696c, respectively, can be sent via electronic signal to controller 698 via wired or wireless transmission. The drive system 696 also includes a control loop 696d and / or other means for controlling the angular position, speed and direction of the shaft or other element of the drill string connected to the drive system 696 (such as shaft 145 shown in FIG. 1). The control loop 696d and / or other element of the drive system 696 may also include means for controlling the hydraulic downhole motor (s). Thus, the bit rotational speed, as used herein, may include mud pump flow data converted to the rotational speed of the drill bit of the hydraulic downhole motor, which can be added to the rotational speed of the column to determine the total value of the rotational speed of the bit.

The controller 698 is designed to receive the above-mentioned specific mechanical energy parameters from the user interface 692, a hoist 694 and a drive system 696, and to use the specific mechanical energy parameters for continuous, periodic or other calculation of the specific mechanical energy. The controller 698 is also designed to provide a signal to the drawworks 694 and / or the drive system 696 based on the calculated specific mechanical energy. For example, the controller 6980 may execute the method 200a shown in FIG. 2A and / or the method 200b shown in FIG. 2B, and therefore, provide one or more signals to the drawworks 694 and / or drive system 696 to increase or decrease the load on the bit and / or the rotation speed of the drill bit, which may be required to optimize drilling efficiency (based on specific mechanical energy).

In FIG. 6C is a flowchart of a drilling process optimization method 600b based on an operatively calculated specific mechanical energy according to one or more aspects of the present disclosure. The data obtained can be used in conjunction with any of the systems disclosed in the present description. Method 600b may be performed using device 100 shown in FIG. 1, of the device 300 shown in FIG. 3, the apparatus 400a shown in FIG. 4A, the apparatus 400b of FIG. 4B and / or the device 690 shown in FIG. 6B. Method 600b may also be performed in conjunction with method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B and / or the method 600a shown in FIG. 6A. The method 600b shown in FIG. 6C may include or form at least a portion of the method 600a shown in FIG. 6A.

In operation 612 of method 600b, the base specific mechanical energy is determined to optimize drilling efficiency based on the specific mechanical energy by changing the load on the bit. Since the base specific mechanical energy determined in step 612 is used for optimization by changing the load on the bit, the symbol MSE _{BLWOB is} used in the present description.

In the next operation 614, the load on the bit is changed. Such a change may include either an increase or decrease in the load on the bit. An increase or decrease in the load on the bit during operation 614 can occur within certain specified threshold values of the load on the bit. For example, the change in the load on the bit can be no more than approximately 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the load on the bit. The load on the bit can be changed manually, by entering the operator, or the load on the bit can be changed automatically, through signals transmitted by the controller, the control system and / or other element of the rig and the associated device. As indicated above, such signals may be provided by remote control from another location.

After that, during operation 616, drilling continues with a modified bit load for a predetermined drilling interval ΔWOB. The ΔWOB interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the ΔWOB interval may be a predetermined drilling penetration depth. For example, operation 616 may include continuing drilling with a modified bit load until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The ΔWOB interval may also include both time and depth components. For example, the ΔWOB interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the ΔWOB interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes. Of course, the above-described time and depth values for the ΔWOB interval are only examples, and many other values are also included in the scope of the present description.

After continuing drilling during the ΔWOB interval with the modified bit load, step 618 is performed to determine the MSE _ΔWOB resulting from working with the modified bit load during the ΔWOB interval. In the next _{step of} decision 620, the modified MSE _{ΔWOB is} compared with the base MSE _BLWOB . If the modified MSE _ΔWOB is preferred over MSE _BLWOB , method 600b is continued until operation 622. And if the modified MSE _{ΔWOB is} not preferred compared to MSE _BLWOB , method 600b is continued until operation 624, in which the bit load is restored to its value before how operation 614 was performed, and then the method continues to operation 622.

The determination made during the operation of decision 620 may be performed manually or automatically by a controller, a control system, and / or another element of the rig and the associated device. The determination may include determining the value of MSE _ΔWOB as preferred if it is less and / or substantially equal to MSE _BLWOB . However, additional or alternative factors may also play a role in the determination made during operation 620.

In step 622 of method 600b, a baseline specific energy is determined to optimize drilling efficiency based on specific mechanical energy by varying the bit speed. Since the base specific mechanical energy determined in step 622 is used for optimization by changing the rotational speed of the drill bit, the designation MSE _{BLRPM is} used in the present description.

In a next step 626, the rotational speed of the drill bit is changed. Such a change may include either an increase or decrease in the rotational speed of the drill bit. An increase or decrease in the rotational speed of the drill bit during operation 626 may occur within certain, predetermined limit values for the rotational speed of the drill bit. For example, the change in rotational speed of the drill bit may be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the rotational speed of the drill bit. The rotational speed of the drill bit can be changed manually, by entering the operator, or the rotational speed of the drill bit can be changed automatically, by signals transmitted by the controller, control system and / or other element of the drilling rig and the associated device.

Thereafter, during operation 628, drilling is continued at a modified rotational speed of the drill bit for a predetermined drilling interval ΔRPM. The ΔRPM interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the ΔRPM interval may be a predetermined drilling penetration depth. For example, operation 628 may include continuing drilling at a modified rotational speed of the drill bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include both time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the ΔRPM interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes. Of course, the above time and depth values for the ΔRPM interval are only examples, and many other values are also included in the scope of the present description.

After continuing the drilling process for the ΔRPM interval with the changed drill bit rotation speed, operation 630 is performed to determine the MSE _ΔRPM obtained as a result of working with the changed drill bit rotation speed during the ΔRPM interval. In the next decision operation 632, the modified MSE _{ΔRPM is} compared with the base MSE _BLRPM . If the altered MSE _ΔRPM is preferred over the MSE _BLRPM , method 600b returns to step 612. And if the altered MSE _{ΔRPM is} not preferred over MSE _BLRPM , the method 600b continues to step 634, in which the rotational speed of the drill bit is restored to its value before step 626 was performed, and then the method continues to step 612.

The determination made during decision 632 may be performed manually or automatically by the controller, control system and / or other element of the rig and associated device. The determination may include determining the value of MSE _ΔRPM as preferred if it is smaller and / or substantially equal to MSE _BLRPM . However, additional or alternative factors may also play a role in the determination made during operation 632.

Furthermore, after performing operations 632 and / or 634, method 600b should not immediately return to operation 612 at the next iteration. For example, the next iteration of method 600b may be delayed by a predetermined period of time or until sinking to a predetermined depth. Alternatively, method 600b may end after performing operations 632 and / or 634.

In FIG. 6D is a flowchart of a drilling process optimization method 600c based on an operatively calculated specific mechanical energy according to one or more aspects of the present disclosure. Method 600c may be performed using device 100 shown in FIG. 1, of the device 300 shown in FIG. 3, of the device 400a shown in FIG. 4A, of the device 400b shown in FIG. 4B and / or the device 690 shown in FIG. 6B. Method 600c may also be performed in conjunction with the execution of method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 600a shown in FIG. 6A and / or the method 600b shown in FIG. 6C. The method 600c shown in FIG. 6D may include or form at least part of the method 600a shown in FIG. 6A and / or the method 600b shown in FIG. 6C.

In operation 640 of method 600c, the baseline specific mechanical energy is determined to optimize drilling efficiency based on the specific mechanical energy by reducing the load on the bit. Since the base specific mechanical energy determined in step 640 is used for optimization by reducing the load on the bit, the designation MSE _{BL-WOB is} used in the present description.

In a next step, 642 reduces the load on the bit. The decrease in the load on the bit during operation 642 can occur within certain specified threshold values of the load on the bit. For example, a reduction in the load on the bit may be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the load on the bit. The load on the bit can be manually reduced by entering the operator, or the load on the bit can be automatically reduced by signals transmitted by the controller, the control system and / or another element of the rig and the associated device.

Thereafter, during operation 644, drilling is continued with a reduced bit load for a predetermined drilling interval of -ΔWOB. The -ΔWOB interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the -ΔWOB interval may be a predetermined drilling penetration depth. For example, operation 644 may include continuing the drilling process with a reduced bit load until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The -ΔWOB interval may also include both time and depth component. For example, the -ΔWOB interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the -ΔWOB interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes. Of course, the above-described values of time and depth for the interval -ΔWOB are only examples, and many other values are also included in the scope of the present description.

After continuing the drilling process for the −ΔWOB interval with a reduced bit load, step 646 is performed to determine the MSE _−ΔWOB resulting from the reduced bit load during the −ΔWOB interval. In the next decision operation 648, the reduced MSE _{-ΔWOB is} compared with the base MSE _BL-WOB . If the reduced MSE- _ΔWOB is preferred over the MSE _BL-WOB , then the method 600c is continued until operation 652. And if the reduced MSE- _{ΔWOB is} not preferred compared to the MSE _BL-WOB , the method 600c is continued until operation 650, in which the load the bit is restored to its value before operation 642 was performed, and then the method continues to operation 652.

The determination made during the operation of decision 648 can be performed manually or automatically, by the controller, the control system and / or another element of the rig and the associated device. The determination may include determining the value of MSE- _ΔWOB as preferred if it is less and / or substantially equal to MSE _BL-WOB . However, additional or alternative factors may also play a role in the determination made during operation 648.

In operation 652 of method 600c, the base specific mechanical energy is determined to optimize drilling efficiency based on the specific mechanical energy by increasing the load on the bit. Since the base specific mechanical energy determined in step 652 is used for optimization by increasing the load on the bit, the designation MSE _{BL + WOB is} used in the present description.

In the next operation 654 increase the load on the bit. The increase in the load on the bit during operation 654 can occur within certain specified threshold values of the load on the bit. For example, an increase in the load on the bit can be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the load on the bit. The load on the bit can be manually increased by operator input, or the load on the bit can be automatically increased by signals transmitted by the controller, control system and / or other element of the rig and the associated device.

After that, during operation 656, drilling is continued with an increased load on the bit for a predetermined drilling interval + ΔWOB. The interval + ΔWOB may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternative interval

+ ΔWOB may be a given depth of penetration during drilling. For example, operation 656 may include continuing the drilling process with an increased load on the bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The interval + ΔWOB may also include both time and depth components. For example, the + ΔWOB interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the + ΔWOB interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes.

After continuing the drilling process during the + ΔWOB interval with an increased bit load, step 658 is performed to determine the MSE _{+ ΔWOB} resulting from working with the increased bit load during the + ΔWOB interval. In the next _{step of} decision 660, the modified MSE _{+ ΔWOB is} compared with the base MSE _{BL + WOB} . If the modified MSE _{+ ΔWOB} is preferred over MSE _{BL + WOB} , the method 600c is continued until operation 664. And if the modified MSE _{+ ΔWOB is} not preferred compared to MSE _{BL + WOB} , the method 600c is continued until operation 662, in which the bit is restored to its value before operation 654 was performed, and then the method continues to operation 664.

The determination made during decision 660 may be performed manually or automatically by the controller, control system and / or other element of the rig and associated device. The determination may include determining the value of MSE _{+ ΔWOB} as preferred if it is less and / or substantially equal to MSE _{BL + WOB} . However, additional or alternative factors may also play a role in the determination made during operation 660.

In step 664 of method 600c, the baseline specific mechanical energy is determined to optimize drilling efficiency based on the specific mechanical energy by reducing the bit rotation frequency and the drill bit rotation frequency. Since the base specific mechanical energy determined in step 664 is used for optimization by reducing the rotational speed of the drill bit, the designation MSE _{BL-RPM is} used in the present description.

In a next step 666, the rotational speed of the drill bit is reduced. A decrease in the rotational speed of the drill bit during operation 666 may occur within certain predetermined limit values for the rotational speed of the drill bit. For example, a decrease in drill bit rotation speed may be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the rotational speed of the drill bit. The rotational speed of the drill bit can be manually reduced by operator input, or the rotational speed of the drill bit can be automatically reduced by signals transmitted by the controller, control system and / or other element of the rig and the associated device.

Thereafter, during operation 668, drilling is continued at a reduced drill bit rotational speed for a predetermined drilling interval −ΔRPM. The -ΔRPM interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the -ΔRPM interval may be a predetermined drilling penetration depth. For example, operation 668 may include continuing the drilling process at a reduced rotational speed of the drill bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The -ΔRPM interval may also include both time and depth components. For example, the -ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the -ΔRPM interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes.

After continuing the drilling process during the −ΔRPM interval with a reduced drill bit _speed , _step 670 is performed to determine the MSE _-ΔRPM resulting from operating at a reduced drill bit speed during the −ΔRPM interval. In the next decision _step 672, the reduced MSE _{-ΔRPM is} compared with the base MSE _BL-RPM . If the modified MSE _-ΔRPM is preferred over the MSE _BL-RPM , the method 600c is continued until step 676. And if the modified MSE _{-ΔRPM is} not preferred compared to the MSE _BL-RPM , the method 600c is continued until step 674, in which the speed the drill bit is restored to its value before operation 666 was performed, and then the method continues to operation 676.

The determination made during decision 672 may be performed manually or automatically by the controller, control system and / or other element of the rig and the associated device. The determination may include determining the value of MSE _-ΔRPM as preferred if it is less and / or substantially equal to MSE _BL-RPM . However, additional or alternative factors may also play a role in the determination made during operation 672.

In step 676 of method 600c, the base specific mechanical energy is determined to optimize drilling efficiency based on the specific mechanical energy by increasing the rotational speed of the bit, the rotational speed of the drill bit. Since the base specific mechanical energy determined in step 676 is used for optimization by increasing the rotational speed of the drill bit, the designation MSE _{BL + RPM is} used in the present description.

In a subsequent operation 678, the rotational speed of the drill bit is increased. An increase in the rotational speed of the drill bit during operation 678 can occur within certain, predetermined limit values for the rotational speed of the drill bit. For example, an increase in the rotational speed of the drill bit can be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the rotational speed of the drill bit. The rotational speed of the drill bit can be increased manually, by entering the operator, or the rotational speed of the drill bit can be increased automatically, through signals transmitted by the controller, the control system and / or other element of the drilling rig and the associated device.

Thereafter, during operation 680, drilling is continued at an increased rotational speed of the drill bit for a predetermined drilling interval + ΔRPM. The interval + ΔRPM may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the + ΔRPM interval may be a predetermined drilling penetration depth. For example, operation 680 may include continuing the drilling process at an increased rotational speed of the drill bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The interval + ΔRPM may also include both time and depth components. For example, the + ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the + ΔRPM interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes.

After continuing the drilling process during the + ΔRPM interval with an increased drill bit rotation speed, operation 682 is performed to determine the MSE _{+ ΔRPM} resulting from operating at an increased drill bit rotation speed during the + ΔRPM interval. In the next decision _step 684, the increased MSE _{+ ΔRPM is} compared with the base MSE _{BL + RPM} . If the modified MSE _{+ ΔRPM} is preferred over MSE _{BL + RPM} , the method 600c is continued until operation 688. And if the modified MSE _{+ ΔRPM is} not preferred compared to MSE _{BL + RPM} , the method 600c is continued until operation 686, in which the speed the drill bit is restored to its value before operation 678 was performed, and then the method continues to operation 688.

The determination made during the operation of decision 684 may be performed manually or automatically by the controller, control system and / or other element of the rig and the associated device. The determination may include determining the value of MSE _{+ ΔRPM} as preferred if it is less and / or substantially equal to MSE _{BL + RPM} . However, additional or alternative factors may also play a role in the determination made during operation 684.

Operation 688 includes waiting for a predetermined period of time or an interval of drilling depth before repeating method 600c, returning to operation 640. In this embodiment, the interval may be up to 0 seconds or 0 feet, and the method returns to operation 640 essentially immediately after operations 684 and / or 686. Alternatively, the method 600c may not require iteration, while the method 600c may essentially end after operations 684 and / or 686.

In addition, the drilling intervals ΔWOB, + ΔWOB, - ΔRPM and + ΔROM can be substantially identical within the same iteration of method 600c. In the alternative, one or more intervals may vary in duration or depth compared to other intervals. Similarly, the amount by which the load on the bit decreases and increases in operations 642 and 654 may be substantially identical or may vary with respect to each other within the same iteration of method 600c. The amount by which the rotational speed of the drill bit decreases and increases in operations 666 and 678 may be substantially identical or may vary with respect to each other within the same iteration of method 600c. Changes in the bit load and rotational speed of the drill bit may also change or remain the same with respect to subsequent iterations of method 600c.

As described above, one or more aspects of the present description can be used in the drilling process or for its control based on specific mechanical energy. However, one or more aspects of the present description, additionally or alternatively, can be used in the drilling process or for its control based on ΔT. Thus, as described above, during drilling, torque is transmitted from the top drive or other rotation drive to the drill string. The torque required to rotate the bit can be referred to as the torque on the bit, and can be monitored using a sensor, such as the torque sensor 140a shown in FIG. 1, the torque sensor 355 shown in FIG. 3, one or more sensors 430 shown in FIG. 4A and 4B, the torque sensor 696a shown in FIG. 6B, and / or one or more devices for measuring the torque of the BHA.

During drilling, the drill string undergoes various types of vibrations, including axial (longitudinal) vibrations, bending (transverse) vibrations and torsional (rotational) vibrations. Torsional vibrations are caused by non-linear interaction between the bit, drill string and borehole. As described above, said torsional vibration may include intermittent vibrations characterized by intermittent shutdowns (during which the BHA “sticks” to the wellbore) and intervals with a high angular velocity of the BHA (during which the BHA “slides” relative to the wellbore).

Intermittent movement of the BHA causes operational changes in the torque on the bit or ΔT. This ΔT may be used to provide Intermittent Motion Alarm (STD) in accordance with one or more aspects of the present disclosure. For example, the ΔT parameter or SPD can be visually displayed using the “Stop Light” indicator, the green light of which can indicate an acceptable mode of operation (for example, the SPD parameter is 0-15), yellow light can indicate that it is inevitable intermittent movement (for example, the SPD parameter is 16-25), and a red light may indicate that intermittent motion is probably already occurring (for example, the SPD parameter is greater than 25). However, these approximate threshold values can be adjusted during operation, as they can vary depending on the drilling conditions. The parameter ΔT or SPD, alternatively or additionally, can be displayed graphically (for example, by showing current and previous data), acoustically (for example, using an alarm) and / or by means of the dashboard or indicator of the device. Combinations of these display options are also included in the scope of the present description. For example, the “Stop Light” indicator described above can continuously show the SPD parameter regardless of its value, and an acoustic alarm can be triggered if the SPD parameter exceeds a preset value (for example, 25).

A drilling process controller or other device within the scope of the present description may include one or more aspects of a drilling process or control based on a ΔT or SPD parameter, as described above. For example, a controller such as controller 190 shown in FIG. 1, the controller 325 shown in FIG. 3, the controller 420 shown in FIG. 4A or 4B, and / or the controller 698 shown in FIG. 6B can automatically adjust the rotational speed of the drill bit of the drill string with a short pulse to increase or decrease the rotational speed of the drill bit (for example, +/- 5 rotational speed of the drill bit), interrupting harmonious intermittent vibration either before or at the moment of detecting intermittent movement, and then return to normal drill bit speed. The controller can be used to automatically increase or decrease the speed of the drill bit by a predetermined or user-adjustable value or percentage for a specified or user-controlled duration, in an attempt to bring the drilling process out of harmonic state. Alternatively, the controller may automatically continue to increase or decrease the rotational speed of the drill bit in increments until the ΔT or SPD parameter indicates that intermittent operation has been stopped.

In an embodiment, a controller with ΔT or SPD support can additionally automatically reduce the load on the bit if the intermittent movement is intense, which may be due to an excessively high target load on the bit. Such automatic reduction of the load on the bit may include one adjustment or step-by-step adjustment, short-term or long-term, and can be continued until the ΔT or SPD parameter indicates that intermittent operation has been stopped.

A controller with ΔT or SPD support can additionally automatically increase the load on the bit, for example, to find the upper limit of the load on the bit during intermittent movement. For example, if all other possible drilling parameters are optimized or adjusted within the respective ranges, the controller can automatically increase the load on the bit incrementally until the ΔT or SPD parameter approaches or reaches its upper limit (for example, 25).

In an embodiment, a ΔT-based drilling process or control, in accordance with one or more aspects of the present description, may operate in accordance with one or more aspects of the following pseudo-code:

IF (counter <= Process_Time)

IF (counter = = 1)

Minimum_Torque = Realtime_Torque

PRINT ("Minimum", Minimum_Torque)

Maximum_Torque = Realtime_Torque

PRINT ("Maximum", Maximum_Torque)

End

IF (Realtime_Torque <Minimum_Torque)

Minimum_Torque = Realtime_Torque

End

IF (Maximum_Torque <Realtime_Torque)

Maximum_Torque = Realtime_Torque

End

Torque_counter = (Torque_counter + Realtime_Torque)

Average_Torque = (Torque_counter / counter)

counter = counter + 1

PRINT ("Process_Time", Process_Time)

ELSE

SSA = ((Maximum_Torque - Minimum_Torque) / Average_Torque) * 100

where Process_Time is the time elapsed since the start of monitoring the ΔT or SPD parameter, Minimum_Torque is the minimum torque on the bit that is present during Process_Time, Maximum_Torque is the maximum torque on the bit that is present during Process_Time, Realtime_Torque is the current torque on the bit, Average_Torque is the average torque on the bit during Process_Time and SPD is the Intermittent Alarm parameter.

As described above, the ΔT or DPS parameter can be applied to, or otherwise, according to the method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 600a shown in FIG. 6A, the method 600b shown in FIG. 6C, and / or the method 600c shown in FIG. 6D. For example, as shown in FIG. 7A, the parameter ΔT or SPD can be replaced by the specific mechanical energy parameter described above with respect to FIG. 6A. Alternatively, the ΔT or SPD parameter may be monitored in addition to the specific mechanical energy parameter described above with respect to FIG. 6A, wherein the drilling process or control is based on both specific mechanical energy and ΔT or SPD.

In FIG. 7A is a flowchart of a method 700a according to one or more aspects of the present description. The method 700a may be performed in conjunction with one or more elements of the device 100 shown in FIG. 1, of the device 300 shown in FIG. 3, of the device 400a shown in FIG. 4A, of the device 400b shown in FIG. 4B and / or the device 690 shown in FIG. 6B, in the course of their work.

Method 700a includes an operation 702 during which current ΔT parameters are measured. In the next operation 704, ΔT is calculated. If ΔT is sufficiently equal to the desired ΔT or otherwise ideal, as determined during decision operation 706, the method 700a is repeated and operation 702 is repeated. "Ideal" may be as described above. The iteration of method 700a can be carried out essentially immediately, or before the iteration of method 700a there may be a delay period after which operation 702 is repeated. If ΔT is not ideal, as determined during decision operation 706, method 700a continues until operation 708, during which or several drilling parameters (e.g., bit load, drill bit speed, etc.) are adjusted to improve ΔT. After operation 708 is completed, method 700a is repeated, and operation 702 is repeated. Such an iteration can be carried out essentially immediately, or a delay period may be present before the iteration of method 700a, after which operation 702 is repeated.

In FIG. 7B is a flow chart of a method 700b for monitoring ΔT and / or SPD according to one or more aspects of the present description. Method 700b may be performed using device 100 shown in FIG. 1, of the device 300 shown in FIG. 3, of the device 400a shown in FIG. 4A, of the device 400b shown in FIG. 4B and / or the device 690 shown in FIG. 6B. Method 700b may also be performed in conjunction with the execution of method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 600a shown in FIG. 6A, the method 600b shown in FIG. 6C, the method 600c shown in FIG. 6D and / or the method 700a shown in FIG. 7A. The method 700b shown in FIG. 7B may include or form at least part of the method 700a shown in FIG. 7A.

In operation 712 of method 700b, a baseline ΔT is determined for optimization based on ΔT by changing the bit load. Since the base ΔT determined in step 712 is used for optimization by changing the load on the bit, the designation ΔT _{BLWOB is} used in the present description.

In the next operation 714, the load on the bit is changed. Such a change may include either an increase or decrease in the load on the bit. An increase or decrease in the load on the bit during operation 714 can occur within certain specified limit values of the load on the bit. For example, the change in the load on the bit can be no more than approximately 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the load on the bit. The load on the bit can be changed manually, by entering the operator, or the load on the bit can be changed automatically, through signals transmitted by the controller, the control system and / or other element of the rig and the associated device. As indicated above, such signals may be provided by remote control from another location.

Thereafter, during operation 716, drilling is continued with a modified bit load for a predetermined drilling interval ΔWOB. The ΔWOB interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the ΔWOB interval may be a predetermined drilling penetration depth. For example, operation 716 may include continuing the drilling process with a modified bit load until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The ΔWOB interval may also include both time and depth components. For example, the interval ΔWOB

may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the ΔWOB interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes. Of course, the above-described time and depth values for the ΔWOB interval are only examples, and many other values are also included in the scope of the present description.

After continuing the drilling process during the ΔWOB interval with the modified bit load, step 718 is performed to determine the ΔT _ΔWOB resulting from working with the modified bit load during the ΔWOB interval. In the next decision operation 720, the changed ΔT _{ΔWOB is} compared with the base ΔT _BLWOB . If the altered ΔT _ΔWOB is preferred over ΔT _BLWOB , the method 700b is continued until operation 722. And if the altered ΔT _{ΔWOB is} not preferred compared to ΔT _BLWOB , the method 700b is continued until operation 724, in which the load on the bit is restored to its value before how operation 714 was performed, and then the method continues to operation 722.

The determination made during decision 720 may be performed manually or automatically by the controller, control system and / or other element of the rig and associated device. The determination may include determining the value of ΔT _ΔWOB as preferred if it is less and / or substantially equal to ΔT _BLWOB . However, additional or alternative factors may also play a role in the determination made during operation 720.

In operation 722 of method 700b, a baseline ΔT is determined for optimization based on ΔT by changing the bit speed. Since the baseline ΔT determined in step 722 is used for optimization by changing the rotational speed of the drill bit, the designation ΔT _{BLRPM is} used in the present description.

In a subsequent operation 726, the rotational speed of the drill bit is changed. Such a change may include either an increase or decrease in the rotational speed of the drill bit. An increase or decrease in the rotational speed of the drill bit during operation 726 may occur within certain predetermined limit values for the rotational speed of the drill bit. For example, the change in rotational speed of the drill bit may be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the rotational speed of the drill bit. The rotational speed of the drill bit can be manually changed by operator input, or the rotational speed of the drill bit can be changed automatically by signals transmitted by the controller, control system and / or other element of the rig and the associated device.

Thereafter, during operation 728, drilling is continued at a modified rotational speed of the drill bit for a predetermined drilling interval ΔRPM. The ΔRPM interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the ΔRPM interval may be a predetermined drilling penetration depth. For example, operation 728 may include continuing the drilling process at a modified rotational speed of the drill bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include both time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the ΔRPM interval may include drilling until the wellbore is recessed twenty feet, but more than ninety minutes. Of course, the above time and depth values for the ΔRPM interval are only examples, and many other values are also included in the scope of the present description.

After continuing the drilling process for the ΔRPM interval with the changed drill bit rotation speed, operation 730 is performed to determine the ΔT _ΔRPM obtained as a result of working with the changed drill bit rotation speed during the ΔRPM interval. In the next decision operation 732, the changed ΔT _{ΔRPM is} compared with the base ΔT _BLRPM . If the changed ΔT _ΔRPM is preferred over ΔT _BLRPM , method 700b is returned to operation 712. And if the changed ΔT _{ΔRPM is} not preferred compared to ΔT _BLRPM , method 700b is continued until operation 734, in which the drill bit speed is restored to its value before operation 726 was performed, and then the method continues to operation 712.

The determination made during the operation of decision 732 may be performed manually or automatically by the controller, control system and / or other element of the rig and the associated device. The determination may include determining the ΔT _{ΔRPM value} as preferred if it is less and / or substantially equal to ΔT _BLRPM . However, additional or alternative factors may also play a role in the determination made during operation 732.

In addition, after performing operations 732 and / or 734, method 700b may not immediately return to operation 712 in the next iteration. For example, the next iteration of method 700b may be delayed by a predetermined period of time or to a predetermined drilling depth. Alternatively, method 700b may end after step 732 and / or 734.

In FIG. 7C is a flowchart of a drilling process optimization method 700c based on an operatively calculated ΔT according to one or more aspects of the present disclosure. Method 700c may be performed using device 100 shown in FIG. 1, of the device 300 shown in FIG. 3, of the device 400a shown in FIG. 4A, of the device 400b shown in FIG. 4B and / or the device 690 shown in FIG. 6B. The method 700c may also be performed in conjunction with the execution of the method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 600a shown in FIG. 6A, the method 600b shown in FIG. 6C, the method 600c shown in FIG. 6D, the method 700a shown in FIG. 7A and / or the method 700b shown in FIG. 7B. The method 700c shown in FIG. 7C may include or form at least part of the method 700a shown in FIG. 7A and / or the method 700b shown in FIG. 7B.

In operation 740 of method 700c, a baseline ΔT is determined for optimization based on ΔT by reducing the load on the bit. Since the base ΔT determined in step 740 is used for optimization by reducing the load on the bit, the designation ΔT _{BL-WOB is} used in the present description.

In a subsequent operation 742, the load on the bit is reduced. The decrease in the load on the bit during operation 742 can occur within certain specified threshold values of the load on the bit. For example, a reduction in the load on the bit may be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the load on the bit. The load on the bit can be reduced manually, by entering the operator or automatically by signals transmitted by the controller, control system and / or other element of the rig and the associated device.

Thereafter, during operation 744, drilling is continued with a reduced bit load for a predetermined drilling interval of −ΔWOB. The -ΔWOB interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the -ΔWOB interval may be a predetermined drilling penetration depth. For example, operation 744 may include continuing the drilling process with a reduced bit load until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The -ΔWOB interval may also include both time and depth components. For example, the -ΔWOB interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the -ΔWOB interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes. Of course, the above-described values of time and depth for the interval -ΔWOB are only examples, and many other values are also included in the scope of the present description.

After continuing the drilling process during the −ΔWOB interval with the reduced WOB, step 746 is performed to determine the ΔT _-ΔWOB value obtained by operating with the reduced bit load during the −ΔWOB interval. In the next _step , solutions 748 reduce ΔT _-ΔWOB , compared with the base ΔT _BL-WOB . If a reduced ΔT _-ΔWOB is preferred over ΔT _BL-WOB , the method 700c is continued until operation 752. And if a reduced ΔT _{-ΔWOB is} not preferred compared to ΔT _BL-WOB , the method 700c is continued until operation 750, in which the load the bit is restored to its value before operation 742 was performed, and then the method continues to 752.

The determination made during decision 748 may be performed manually or automatically by the controller, control system and / or other element of the rig and associated device. The determination may include determining the value of ΔT _-ΔWOB as preferred if it is less and / or substantially equal to ΔT _BL-WOB . However, additional or alternative factors may also play a role in the determination made during operation 748.

In operation 752 of method 700c, a baseline ΔT is determined for optimization based on ΔT by increasing the load on the bit. Since the base ΔT determined in step 752 is used for optimization by increasing the load on the bit, the designation ΔT _{BL + WOB is} used in the present description.

In the next operation 754 increase the load on the bit. The increase in the load on the bit during operation 754 can occur within certain specified limit values of the load on the bit. For example, an increase in the load on the bit can be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the load on the bit. The load on the bit can be increased manually, by entering the operator, or the load on the bit can be increased automatically, through signals transmitted by the controller, control system and / or other element of the rig and the associated device.

Thereafter, during operation 756, drilling is continued with an increased load on the bit for a predetermined drilling interval + ΔWOB. The interval + ΔWOB may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. In the alternative, the + ΔWOB interval may be a predetermined drilling penetration depth. For example, operation 756 may include continuing the drilling process with an increased load on the bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The interval + ΔWOB may also include both time and depth components. For example, the + ΔWOB interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the + ΔWOB interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes.

After continuing the drilling process during the + ΔWOB interval with an increased bit load, step 758 is performed to determine the ΔT _{+ ΔWOB} resulting from working with the increased bit load during the + ΔWOB interval. In the next decision operation 760, the changed ΔT _{+ ΔWOB is} compared with the base ΔT _{BL + WOB} . If the altered ΔT _{+ ΔWOB} is preferred over ΔT _{BL + WOB} , the method 700c is continued until operation 764. And if the altered ΔT _{+ ΔWOB is} not preferred compared to ΔT _{BL + WOB} , the method 700c is continued until operation 762, in which the load the bit is restored to its value before operation 754 was performed, and then the method continues to operation 764.

The determination made during decision 760 may be performed manually or automatically by the controller, control system and / or other element of the rig and the associated device. The determination may include determining the value of ΔT _{+ ΔWOB} as preferred if it is less and / or substantially equal to ΔT _{RL + WOB} . However, additional or alternative factors may also play a role in the determination made during operation 760.

In operation 764 of method 700c, a baseline ΔT is determined for optimization based on ΔT by reducing the bit speed. Since the baseline ΔT determined in step 764 is used for optimization by reducing the rotational speed of the drill bit, the notation ΔT _{BL-RPM is} used in the present description.

In a subsequent operation 766, the rotational speed of the drill bit is reduced. A decrease in the rotational speed of the drill bit during operation 766 may occur within certain predetermined limit values for the rotational speed of the drill bit. For example, a decrease in drill bit rotation speed may be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the rotational speed of the drill bit. The rotational speed of the drill bit can be manually reduced by operator input, or the rotational speed of the drill bit can be automatically reduced by signals transmitted by the controller, control system and / or other element of the rig and the associated device.

Thereafter, during operation 768, drilling is continued at a reduced rotational speed of the drill bit for a predetermined drilling interval of −ΔRPM. The -ΔRPM interval may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the -ΔRPM interval may be a predetermined drilling penetration depth. For example, operation 768 may include continuing the drilling process at a reduced rotational speed of the drill bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The -ΔRPM interval may also include both time and depth components. For example, the -ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the -ΔRPM interval may include drilling until the wellbore is recessed twenty feet, but for more than ninety minutes.

After continuing the drilling process during the −ΔRPM interval with a reduced drill bit _speed , _step 770 is performed to determine the ΔT _-ΔRPM value obtained by operating at a reduced drill bit speed during the −ΔRPM interval. In the next decision _step 772, the reduced ΔT _{-ΔRPM is} compared with the base ΔT _BL-RPM . If the modified ΔT _-ΔRPM is preferred over ΔT _BL-RPM , the method 700c is continued until step 776. And if the modified ΔT _{-ΔRPM is} not preferred compared to ΔT _BL-RPM , method 700c is continued until step 774, in which the speed the drill bit is restored to its value before operation 766 was performed, and then the method continues to operation 776.

The determination made during decision 772 may be performed manually or automatically by the controller, control system and / or other element of the rig and the associated device. The determination may include determining the value of ΔT _-ΔRPM as preferred if it is less and / or substantially equal to ΔT _BL-RPM . However, additional or alternative factors may also play a role in the determination made during operation 772.

In operation 776 of method 700c, a baseline ΔT is determined for optimization based on ΔT by increasing the bit speed. Since the baseline ΔT determined in step 776 is used for optimization by increasing the rotational speed of the drill bit, the notation ΔT _{BL + RPM is} used in the present description.

In a next operation 778, the rotational speed of the drill bit is increased. An increase in the rotational speed of the drill bit during operation 778 may occur within certain predetermined limit values for the rotational speed of the drill bit. For example, an increase in the rotational speed of the drill bit can be no more than about 10%. However, other percentages are also included in the scope of the present description, where such percentages are within or outside the specified limits of the rotational speed of the drill bit. The rotational speed of the drill bit can be increased manually, by entering the operator, or the rotational speed of the drill bit can be increased automatically, through signals transmitted by the controller, the control system and / or other element of the drilling rig and the associated device.

Thereafter, during operation 780, drilling is continued at an increased rotational speed of the drill bit for a predetermined drilling interval + ΔRPM. The interval + ΔRPM may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the + ΔRPM interval may be a predetermined drilling penetration depth. For example, operation 780 may include continuing the drilling process at an increased rotational speed of the drill bit until the existing wellbore is deepened by five feet, ten feet, fifty feet, or some other depth. The interval + ΔRPM may also include both time and depth components. For example, the + ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is ten feet deep. In another example, the + ΔRPM interval may include drilling until the wellbore is recessed twenty feet, but not more than ninety minutes.

After continuing the drilling process during the + ΔRPM interval with an increased drill bit rotation speed, operation 782 is performed to determine ΔT _{+ ΔRPM} obtained as a result of operating with an increased drill bit rotation speed during the + ΔRPM interval. In the next _{step of} decision 784, the increased ΔT _{+ ΔRPM is} compared with the base ΔT _{BL + RPM} . If the modified ΔT _{+ ΔRPM} is preferred over ΔT _{BL + RPM} , method 700c is continued until operation 788. And if the changed ΔT _{+ ΔRPM is} not preferred compared to ΔT _{BL + RPM} , method 700c is continued until operation 786, in which the speed the drill bit is restored to its value before operation 778 was performed, and then the method continues to operation 788.

The determination made during decision 784 may be performed manually or automatically by the controller, control system and / or other element of the rig and the associated device. The determination may include determining the value of ΔT _{+ ΔRPM} as preferred if it is less and / or substantially equal to ΔT _{BL + RPM} . However, additional or alternative factors may also play a role in the determination made during operation 784.

Step 788 includes waiting for a predetermined period of time or drilling to a predetermined depth interval before repeating method 700c, returning to step 740. In this embodiment, the interval may be as little as 0 seconds or 0 feet, and the method returns to step 740 essentially immediately after performing operations 784 and / or 786. Alternatively, the method 700c may not require iteration, while the method 700c may essentially end after performing operations 784 and / or 786.

In addition, the drilling intervals -ΔWOB, + ΔWOB, -ΔRPM and + ΔROM can be substantially identical within the same iteration of method 700c. Alternatively, one or more intervals may vary in duration or depth relative to other intervals. Similarly, the amount by which the load on the bit decreases and increases in operations 742 and 754 may be substantially identical or may vary with respect to each other within the same iteration of method 700c. The amount by which the rotational speed of the drill bit decreases and increases in operations 766 and 778 may be substantially identical or may vary with respect to each other within the same iteration of method 700c. Changes in the load on the bit and the rotational speed of the drill bit may also change or remain the same relative to subsequent iterations of the method 700c.

In FIG. 8A is a schematic illustration of an apparatus 800 according to one or more aspects of the present description. The device 800 may include or constitute at least a portion of the device 100 shown in FIG. 1, of the device 300 shown in FIG. 3, of the device 400a shown in FIG. 4A, of the device 400b shown in FIG. 4B, the device 400c shown in FIG. 4C, and / or the device 690 shown in FIG. 6B. Apparatus 800 is an exemplary embodiment in which one or more of the methods described herein may be performed or otherwise implemented, including the method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 500 shown in FIG. 5A, the method 600a shown in FIG. 6A, the method 600b shown in FIG. 6C, the method 600c shown in FIG. 6D, the method 700a shown in FIG. 7A, the method 700b shown in FIG. 7B and / or the method 700c shown in FIG. 7C.

Apparatus 800 includes a variety of manual or automated data inputs, collectively referred to herein as inputs 802. The apparatus also includes multiple controllers, computing devices, sensors, and other processors, collectively referred to herein as processors 804. Data from various inputs 802 transmitted to various processors 804, as shown in FIG. 8A by arrow 803. Device 800 also includes a plurality of sensors, encoder encoders, control mechanisms, actuators, motors, and other sensory, measuring, and driving devices, collectively referred to herein as devices 808. Various data and signals, collectively referred to herein description as data 806 are transmitted between various processors 804 and various devices 808, as shown in FIG. 8A arrows 805.

The device 800 may also include, be connected to, or otherwise connected to, a display 810, which may be controlled or receive data in another way from one or more processors 804, if not also from other elements of the device 800. Display 810 may also be referred to herein description as an operator interface, which may further include one or more inputs 802 and / or processors 804.

In the embodiment shown in FIG. 8A, inputs 802 include devices for inputting the following setpoints, limit values, ranges, and other data:

bottomhole pressure input 802a;

input 802b control position fitting;

enter 802c differential pressure limit value;

differential pressure input 802d;

input of the 802e limit of drawworks cable tension;

input 802f specific mechanical energy limit value;

input 802g target value of specific mechanical energy;

input 802h of the set value of the flow rate of the drilling fluid;

input of 802i nominal pressure of the pump;

input 802j negative shaft amplitude;

input 802k positive shaft amplitude;

enter 802l setpoint rate of penetration;

input of 802m pump;

bit end position input 802n;

input of the rotational speed of the drill bit of the top drive;

input of 802p top drive torque limit;

input of 802q control value of the load on the bit; and

input of 802r nominal value of loading on a bit.

However, inputs 802 may include devices for introducing additional or alternative setpoints, limit values, ranges, and other data as part of the present description.

The bottomhole pressure input 802a may indicate the value of the maximum required pressure of the gaseous and / or other medium at the lower end of the wellbore. In the alternative, bottomhole pressure input 802a may indicate a range within which bottomhole pressure is desirably maintained. Such pressure can be expressed as absolute pressure or gauge pressure (for example, relative to atmospheric pressure or some other predetermined pressure).

Entering the nozzle reference position 802b may be a set point or value that indicates the desired nozzle position. In the alternative, input 802b of the control position of the fitting may indicate a range within which the position of the choke coil is desirably maintained. The fitting may be a device having a bore or other means that allow you to adjust the flow rate of the fluid and / or pressure. The fitting can be installed at the end of the nozzle line, which is a high pressure pipe extending from the outlet on the blowout preventer block, through which liquid under pressure in the wellbore can flow from the well through the nozzle line to the nozzle, thereby lowering the pressure of the fluid (for example, to atmospheric pressure). Entering the nozzle reference position 802b may be a dual indicator reflecting the nozzle position as “open” or “closed”. Alternatively, input 802b of the control position of the nozzle may be indicated as a percentage indicating the extent to which the nozzle is partially open or closed.

Entering the 802c differential pressure limit value may be a value indicating a maximum or minimum pressure differential in a downhole hydraulic motor. Alternatively, entering an 802c differential pressure limit value may indicate a range within which a differential pressure in the downhole hydraulic motor is desirably maintained. The input of the 802d differential pressure reference can be a set point or a value indicating the desired differential pressure in the downhole hydraulic motor. In an embodiment, the input 802c of the differential pressure limit value is a value indicating the maximum required differential pressure in the downhole motor, and the input 802 of the reference differential pressure control value is a value indicating the nominal required differential pressure in the hydraulic downhole motor.

Entering 802e of the maximum drawbar tension can be a value indicating the maximum force applied to the drill winch by the drill cable (for example, while maintaining the drill string over the bottom or when lifting equipment installed in the wellbore). For example, entering the limit tension of the 802e winch cable may indicate the maximum hook load that the winch must support during operation. Entering the limit tension of the 802e drawworks cable can be expressed as the maximum weight or drawbar tension that the drawworks can withstand without damaging the drawworks, drill cable and / or other equipment.

Entering the 802f specific mechanical energy limit value may be a value indicating the maximum or minimum specific mechanical energy required during drilling. Alternatively, inputting 802f of the specific mechanical energy limit value may be a range within which the specific mechanical energy is desirably maintained during drilling. As described above, the actual value of the specific mechanical energy is at least partially dependent on the load on the bit, the diameter of the bit, the rotational speed of the drill bit, the torque of the drill string and the penetration rate, each of which can be adjusted according to aspects of the present description while maintaining the desired specific mechanical energy. Entering 802g of the target specific mechanical energy value may be a value indicating the desired specific mechanical energy, or a range within which the specific mechanical energy is desirably maintained during drilling. In an embodiment, the input 802f of the specific mechanical energy limit value is a value or range indicating the maximum and / or minimum specific mechanical energy, and the 802g input of the specific mechanical energy specific value is a value indicating the desired nominal specific mechanical energy.

Entering a predetermined mud flow rate 802h may be a value indicating a maximum, minimum, or nominal required mud flow rate at the outlet of the mud pump. Alternatively, entering a predetermined flow rate of the 802h drilling fluid may be a range within which a drilling fluid flow is desirably maintained. Entering the 802i nominal pump pressure may be a value indicating the current, required, initial, measured, or other nominal pressure of the mud pump. The nominal pressure of the mud pump is usually the difference between the mud pressure and the pressure in the annular space or in the borehole when the drill string is held above the bottom.

Negative shaft amplitude input 802j may be a value indicating the maximum required shaft rotation from the neutral shaft oscillation point in the first angular direction, while positive shaft amplitude input 802j may be the value indicating the maximum required shaft rotation from the neutral shaft oscillation point in the opposite angular direction. For example, during operation of the top drive that causes the shaft to oscillate, inputting negative shaft amplitude 802j may indicate the maximum required rotation of the shaft clockwise in the direction of the neutral point of vibration, and entering 802k positive amplitude of the shaft may indicate the maximum required rotation of the shaft counterclockwise neutral point of oscillation.

Entering the 802l setpoint rate of the penetration rate may be a value indicating the maximum, minimum, or nominal required penetration rate. Alternatively, entering a predetermined value of the 802l penetration rate may be a range within which the penetration rate is desirably maintained.

The input of the 802m pump may be a value indicating the maximum, minimum, or nominal required flow rate, power, speed (e.g., number of strokes per minute) and / or other operating parameter associated with the operation of the mud pump. For example, a mud pump may actually include more than one pump, with an 802m pump inlet may indicate the required maximum or nominal total pressure, flow rate, or other parameters at the outlet of several mud pumps, or the pump system works in conjunction with several mud pumps.

The bit end position input 802n may be a value indicating a desired bit end orientation. In an alternative, bit end position input 802n may be a range within which a bit end is desirably maintained. The bit end position input 802n may be expressed as one or more angles with respect to a fixed or predetermined coordinate point. For example, inputting the bit end position 802n may represent the desired azimuthal orientation of the bit end relative to geographic north and / or the desired inclination of the bit end relative to the vertical. As described above, in some embodiments, it is administered directly, or it can be based on a predetermined drilling path. During drilling using the method of FIG. 5A, the bit face orientation can be calculated based on other data, such as inclinometry data or directional data and the amount of deviation from a given drilling path. This may be the value that is estimated for the direction of the BHA along an altered drilling path.

The input of the 802o speed of the top drive may be a value indicating the maximum, minimum, or nominal required speed of the top drive. Alternatively, the 802o input may be a range within which the top drive rotational speed is desirably maintained. The input of the upper drive limit torque 802p may be a value indicating the maximum torque developed by the upper drive.

Entering the 802q drill bit reference value may be a value indicating the maximum, minimum, or nominal required bit load resulting from the action of the weight of the drill string on the drill bit, although other forces affecting the bit load, such as friction between drill string and borehole. Alternatively, entering an 802q bit load reference value may be a range in which a bit load is desirably maintained. Entering the 802r nominal bit load value may be a value indicating the current, required, initial, measured, or other nominal bit load value, which takes into account the hook load and drill string weight when the drill string is held above the bottom.

One or more of the inputs 802 may include a keyboard, a speech identification device, a disk, a joystick, a mouse, a database, and / or another standard or prospective input device. One or more inputs 802 may support data input from local and / or remote locations. One or more entries 802 may include means for the user to select preset control points, values, or ranges, for example, using one or more drop-down menus. One or more inputs 802, additionally or alternatively, can provide automated input by one or more processors 804, for example, by performing one or more database searches. One or more of the inputs 802, possibly in conjunction with other elements of the device 800, may support operation and / or monitoring from stations at the wellsite, as well as from one or more remote locations. Each of the inputs 802 may have individual input devices, although two or more of the inputs 802 may together have one input device. One or more of the inputs 802 may allow input to the operator, although one or more of the inputs 802 may alternatively provide automatic input of data by a computer, software, module, subroutine, by searching the database, algorithm, calculation, and / or otherwise. One or more inputs 802 may serve for such automatic data entry, but with an overridden function by which a human operator can approve or adjust automatically entered data.

In the embodiment shown in FIG. 8A, devices 808 include the following elements:

block position sensor 808a;

annular pressure sensor 808b;

fitting 808c;

a fixed load cable end load sensor 808d;

winch position encoder 808e;

drilling fluid pressure sensor 808f;

Gravity sensor 808g IPB bit end face;

magnetic bit sensor 808h IPB;

return line flow sensor 808i;

return line weight sensor 808j;

top drive encoder 808k;

top drive torque sensor 808l;

fitting drive 808m;

drawworks drive 808n;

drawworks engine 808o;

mud pump drive 808p;

top drive 808q drive; and

top drive engine 808r.

However, devices 808 may include additional or alternative devices as part of the present description. Devices 808 are designed to work in conjunction with a suitable drawworks, fitting, mud pump, top drive, block, drill string, and / or other elements of the rig. In an alternative, devices 808 also include one or more of the other elements of a rig out of these.

The block position sensor 808a may be or include an optical sensor, a radio sensor, an optical or other encoder position sensor, or another type of sensor for detecting the relative or absolute vertical position of the block. The position sensor of block 808a may be connected, or may be integral, with the block, crown block, drawworks and / or other element of device 800 or drilling rig.

The annular pressure sensor 808b is designed to detect annular pressure defined between the drill string and the casing or borehole, and may comprise or include one or more transducers, strain gauges, and / or other devices for detecting pressure changes or other pressure detection way. The annulus pressure sensor 808b may be coupled to the casing, drill string and / or other element of the device 800 or rig, and may be mounted on or near the surface of the wellbore, slightly lower than the surface, or much deeper in the wellbore.

The fitting position sensor 808c is for determining whether the fitting is open or closed, and may also serve to determine the extent to which the fitting is partially open or closed. The nozzle position sensor 808c may be coupled, or may be integral, with the nozzle, the nozzle drive, and / or another element of the device 800 or of the drilling rig. The fitting can alternatively maintain the set pressure or stabilize the mass flow, for example, depending on the pressure in the annular space. This can be measured using an optional 808s mass flow meter.

The fixed-end mount load sensor 808d is for detecting drill cable tension at or near the fixed-end mount. It may include one or more transducers, strain gauges, and / or other sensors attached to the drill cable.

The winch position encoder 808e is designed to determine the angular position of the winch pulleys on which the drill cable rests. It may include one or more optical encoder encoders, interferometers and / or other sensors designed to determine the angular position of the pulley and / or any change in the angular position of the pulley. The drawworks position encoder 808e may include one or more elements connected to or integrally with a pulley and / or stationary part of the drawworks.

The mud pressure sensor 808f is designed to measure the pressure of the working fluid at the outlet of the downhole motor and may comprise or include one or more transducers, strain gauges and / or other devices for determining fluid pressure. It can be connected, or can be a single unit, with a mud pump and, thus, placed on the surface or near the wellhead.

Gravity sensor 808g IPB of the end face of the bit is designed to determine the orientation of the end face of the bit based on gravity. The magnetic end face sensor 808h IPB is designed to determine the orientation of the end face of the bit based on the magnetic field. These sensors 808g and 808h can be connected, or can be a single unit, with the IPB node and, thus, are placed in the well.

The return line flow sensor 808i is for detecting the flow rate of the drilling fluid in the return line, which can be expressed in gallons / min. The mud weight sensor in the return line 808j is designed to measure the weight of the drilling fluid flowing along the return line. Said sensors 808i and 808j can be connected to a return line and thus can be placed on the surface or near the wellhead.

The encoder 808k position of the top drive is designed to determine the angular position of the shaft. It may include one or more optical encoders, interferometers and / or other sensors designed to determine the angular position of the shaft and / or any change in the angular position of the shaft relative to the top drive, geographic north, or some other fixed coordinate point. The top drive torque sensor 808l is for measuring the torque applied by the top engine or the torque needed to rotate the shaft or drill string at the current speed. These sensors 808k and 808l can be connected, or can be a single unit, with top drive.

Choke actuator 808m is designed to actuate a choke to move the choke to an open, closed position and / or one or more positions between a fully open and a fully closed position. The fitting drive may be hydraulic, pneumatic, mechanical, electrical, or a combination of the above.

The drawworks drive 808n is designed to provide an electrical signal to the drawworks motor 808o to drive it. The drawworks drive 808o is designed to rotate the pulley on which the drill cable rests, fed or wound in this way.

The mud pump drive 808p is designed to provide an electrical signal to the mud pump and thereby control the flow rate and / or pressure of the mud pump at the outlet. The top drive 808q is intended to provide an electrical signal to the top drive 808r to drive it. The top drive motor 808r is designed to rotate the shaft and thus rotate the drill string connected to the shaft.

In the embodiment shown in FIG. 8A, data 806 transmitted between devices 808 and processors 804 includes the following:

block position 806a;

pressure 806b in the annular space;

fitting position 806c;

load 806d per hook;

drilling fluid pressure 806e;

mud pump stroke / phase 806f;

weight 806g of drilling fluid;

shaft position 806h;

return flow 806i;

end face 806j bits;

806k top drive torque;

connection signal 806l;

winch enable signal 806m;

mud pump turn-on signal 806n;

top drive enable signal 806o; and

top drive torque limit signal 806p.

However, data 806 transmitted between devices 808 and processors 804 may include additional or alternative data as part of the present description.

In the embodiment shown in FIG. 8A, processors 804 include the following elements:

fitting controller 804a;

a drum controller 804b;

mud pump controller 804c;

oscillation controller 804d;

shaft position controller 804e;

bit end controller 804f;

a device 804g for calculating the d-exponent;

a device 804h for calculating the adjusted d-exponent;

device 804i for calculating specific mechanical energy;

a device 804l for calculating the rate of penetration;

a device 804m for calculating the actual depth;

a device 804n for calculating the load on the bit;

jamming / slipping sensor 804o; and

chart 804p results of measurements of inclinometry.

However, processors 804 may include additional or alternative controllers, computing devices, sensors, data storage devices and / or other processors as part of the present description.

The nozzle controller 804a is designed to obtain a bottomhole pressure set by the bottomhole pressure input 802a, the annular pressure 806b from the annular pressure sensor 808b, the nozzle position 806c from the nozzle position sensor 808c, and the mud weight 806g from the mud weight sensor in the return lines 808j. The union controller 804a may also receive bottomhole pressure data from a pressure calculating device 804k. Alternatively, processors 804 may include a comparison device, an adder or other device that performs an algorithm that uses the bottomhole pressure settings obtained from the bottomhole pressure input 802a and the current bottomhole pressure obtained from the pressure calculator 804k, the result of a similar algorithm enters the fitting controller 804a instead of or in addition to the bottomhole pressure settings and / or the current bottomhole pressure. A choke controller 804a is designed to process the received data and generate a choke on signal 806l, which is then transmitted to the choke actuator 808.

For example, if the current bottom-hole pressure exceeds the set bottom-hole pressure, then the enable signal of the nozzle 806l may indicate that the drive of the nozzle 808m opens the nozzle more, thereby increasing the return flow and decreasing the current bottom-hole pressure. Similarly, if the current bottomhole pressure is less than the set bottomhole pressure, then the enable signal of the fitting 806l may indicate that the actuator 808m

the nozzle closed the nozzle more, thus reducing the return flow and increasing the current bottomhole pressure. The choke actuator 808m can be turned on step by step, while the choke enable signal 806l repeatedly indicates that the choke actuator 808m opens or closes by a predetermined amount until the current bottom-hole pressure matches the set bottom-hole pressure parameters. Alternatively, the choke enable signal 806l may indicate that the choke actuator 808m opens or closes proportionally to the current difference between the current bottomhole pressure and the set bottomhole pressure.

The drum controller 804b is designed to obtain a predetermined rate of penetration from an input 802l of a predetermined rate of penetration, as well as the current penetration rate from the device 804l to calculate the penetration rate. The drum controller 804b is also designed to receive bit load data from a comparator, summarizer or other device that performs an algorithm that uses a bit load reference value from an 802g input of the bit load reference value and a current bit load from the 804n device to calculate the load on the chisel. The indicated bit load data can be changed based on current specific mechanical energy data. Alternatively, the drum controller 804b is designed to obtain a bit load reference value from input 802g of a bit load reference value and a current bit load value from the device 804n to directly calculate the bit load, and then perform a bit load comparison or a summing algorithm directly. The drum controller 804b is also designed to receive differential pressure data from a comparison device, a summing device, or another device that implements an algorithm that uses a differential pressure reference value obtained from an 802d input of a differential pressure control and a current differential pressure value received from one of the processors 804 , which is designed to determine the current value of the differential pressure. The current differential pressure value can be adjusted to account for the pressure 806b in the annular space.

The drum controller 804b is designed to process the received data and to generate a winch enable signal 806m, which is then transmitted to the winch drive 808n. For example, if the current value of the load on the bit received from the device for calculating the load on the bit is less than the control value of the load on the bit obtained from the input 802q of the control value of the load on the bit, then the winch enable signal 806m may indicate the winch drive 808n, so that he drives the winch motor, which in turn feeds the drill cable. If the current value of the bit load is less than the reference value of the bit load, then the winch enable signal 806m may indicate the winch drive 808n to drive the winch motor 808o, which in turn wraps the drill cable.

If the current penetration rate value received from the penetration rate calculator 804l is less than the predetermined penetration rate value obtained from the 802l input of the predetermined penetration rate, then the winch enable signal 806m may indicate the winch drive 808n to drive the winch motor , which in turn feeds the drill cable. If the current penetration rate exceeds a predetermined penetration rate, then the winch enable signal 806m may indicate the winch drive 808n to drive the winch motor 808o, which in turn wraps the drill cable.

If the current differential pressure value is less than the differential pressure control value obtained from input 802d of the differential pressure control value, then the winch enable signal 806m can indicate the winch drive 808n to drive the winch motor 808o, which in turn feeds the drill cable . If the current differential pressure value exceeds the differential pressure reference value, then the winch enable signal 806m may indicate the winch drive 808n to drive the winch motor 808o, which in turn wraps the drill cable.

The mud pump controller 804c is designed to receive mud pump stroke / phase data 806f, mud pressure 806e from the mud pressure sensor 808f, the current differential pressure value, the current value of the specific mechanical energy from the device 804i for calculating the specific mechanical energy, the current value of the penetration rate from devices 804l for calculating the penetration rate, the index of jamming / slipping from the sensor 804o jamming / slipping, the specified flow rate of the drilling fluid from the input 802h rear The mud flow rate as well as the pump data from the 802m pump input. The mud pump controller 804c then uses the indicated data to generate a mud pump enable signal 806n, which is transmitted to the mud pump 808p.

The oscillation controller 804d is designed to obtain the current position of the shaft 806h, the current top drive torque 806k, the jamming / slipping index from the jamming / slipping sensor 804o, the current penetration rate from the device 804l to calculate the penetration rate, and the limit values of the amplitude of the oscillation of the shaft from inputs 802j and 802k. Then, the vibration controller 804d uses the specified data to generate an input to the shaft position controller 804e for use in generating the top drive enable signal 806o. For example, if the jamming / slipping index from the jamming / slipping sensor 804o indicates that jamming / slipping is occurring, then the signal generated by the oscillation controller 804d indicates that the oscillation should be started or its amplitude should be increased.

The shaft position controller 804e is designed to receive a signal from the oscillation controller 804d, a predetermined top drive drill bit rotation speed from input of a top drive 802o drill bit rotation frequency, a signal from the bit end controller 804f, the current value of the bit load from the device 804n to calculate the bit load as well as the current position of the bit end face 806j from at least one of the bit end face sensors 808g and 808h. The shaft position controller 804e can also be used to obtain the upper drive limit torque setpoint from the upper drive limit input 802p, although the specified target value can be adjusted by a comparison device, a summing device or other device taking into account the current value of the specific mechanical energy, where the current value specific mechanical energy received from the device 804i for calculating specific mechanical energy. The shaft position controller 804e may also be designed to obtain a jamming / slipping index from the jamming / slipping sensor 804o. The shaft position controller 804e then uses the specified data to generate an enable signal for the top drive 806o.

For example, the top drive enable signal 806o instructs the top drive 808q to drive the top drive motor 808r, which in turn rotates the shaft at the speed indicated by the top drive rotational speed input 802o. However, this can only happen when other entries do not cancel this task. For example, if the enable signal of the top drive 806o is directed by a signal from the oscillation controller 804d, it also tells the top drive 808q to drive the top drive motor 808r that rotates the shaft with the oscillation. In addition, the signal from the bit end controller 804d may cancel or otherwise affect the top drive enable signal 806o by rotationally orienting the shaft in a certain static position or by setting a neutral oscillation point.

The bit face controller 804f is designed to obtain a bit face position set by inputting the bit end position 802n, as well as the bit end current position 806j, from at least one of the bit end face sensors 808g and 808h. The bitface controller 804f may also be used to receive differential pressure data. Then, the bit end controller 804f uses the specified data to generate a signal that is supplied to the shaft position controller 804e. The device 804g for calculating the d-exponent is designed to obtain the current value of the penetration rate from the device 804l to calculate the penetration rate, the current value of the pressure drop and / or other pressure data, the diameter of the bit, the current value of the load on the bit from the device 804n to calculate the load on the bit, as well as the current mud weight 806g from the mud weight sensor 808j in the return line. Then, the d-exponent calculator 804g uses the indicated data to calculate the d-exponent, which is a factor in estimating the penetration rate and detecting or predicting zones of abnormal pore pressure. Acceptance of all other parameters is constant, while the d-exponent should increase with depth when drilling in formations with normal pressure, while the reversal of this dynamics is a sign of drilling in formations with potential anomalously high pressure. The signal from the device for calculating the d-exponent 804g is optionally displayed on the display 810, and also fed to the end face bit calculator 404. Therefore, the control unit 420 can stop drilling or correct a predetermined path, considering the region causing the increase in the value received from the device for calculating the d-exponent 804g as a deviation from the predetermined path outside the tolerance zone. This may advantageously allow the main controller to be automatically instructed to direct the drilling in the other direction to prevent drilling in areas of potential abnormally high pressure. The device for calculating the d-exponent is just another suitable method or algorithm for analyzing the penetration rate, and it is also another calculation that can be performed similar to calculating the specific mechanical energy.

The adjusted d-exponent calculator 804h may be designed to obtain substantially the same data as the d-exponent calculator 804g. Alternatively, the adjusted d-exponent calculator 804h is for obtaining the current d-exponent calculated by the 804g calculator for the d-exponent. Then, the corrected d-exponent calculator 804h uses the indicated data to calculate the corrected d-exponent, which corrects the d-exponent based on the weight of the drilling fluid and which may be directly related to formation pressure rather than differential pressure. The signal from the device 804g for calculating the d-exponent is displayed, for example, on the display 810.

The specific mechanical energy calculation device 804i is for obtaining current drill bit speed data from the top drive rotational speed input 802o, the top drive torque 806k from the top drive torque sensor 808l, and the current bit load value from the load calculation device 804n on the chisel. Then, the specific mechanical energy calculator 804i uses the data to calculate the current specific mechanical energy value that is transmitted to the drum controller 804b, the shaft position controller 804e, and the mud pump controller 804c. The specific mechanical energy calculation device 804i may also serve to obtain a specific mechanical energy limit set by inputting the specific mechanical energy limit value 802f, while the 804i specific mechanical energy calculation device may also be used to compare the current specific mechanical energy value with a predetermined limit value specific mechanical energy and initiating a warning if the current value of specific mechanical energy exceeds a predetermined redelnoe a value of the mechanical energy. The specific mechanical energy calculator 804i may also serve to obtain a target specific mechanical energy value set by inputting the target specific mechanical energy value 802g, while the specific mechanical energy calculator 804i may also generate a signal indicative of a difference between the current specific mechanical specific value energy and the target value of specific mechanical energy. This signal may be used by one or more processors 804 to adjust various data values used in this way, for example, to adjust the current or control value of the bit load used by the drum controller 804b and / or a predetermined upper drive torque limit used by the controller 804e shaft position as described above.

The pressure calculating device 804k is configured to receive annular pressure 806b from the annular pressure sensor 808b, drilling fluid pressure 806e from the mud pressure sensor 808f, drilling fluid weight 806g from the mud weight sensor 808j in the return line, and also the actual vertical depths from the 804m device to calculate the actual depth. The pressure calculating device 804k then uses the indicated data to calculate the current bottomhole pressure, which is transmitted to the nozzle controller 804a. However, before sending the choke to the controller 804a, the current bottomhole pressure can be compared with a bottomhole pressure value obtained from the bottomhole pressure input 802a, while the choke controller 804a can only use the difference between the current bottomhole pressure and the bottomhole pressure setpoint when generating the choke on signal 806l. The specified comparison between the current bottomhole pressure and the target bottomhole pressure can be performed by a pressure calculating device 804k, a choke controller 804a, or other processors 804.

The driving speed calculator 804l is intended to obtain the position of the block 806a from the position of the block 808a and then using the obtained data to calculate the current value of the driving speed. Then, the current penetration rate value is transmitted to the device 804m for calculating the actual depth, the drum controller 804b, the mud pump controller 804c, and the vibration controller 804d.

The device 804m for calculating the actual depth is designed to obtain the current position of the end face of the bit 806j from at least one of the sensors of the end face of the bit 808g and 808h, diagram 804p of the results of measurements of inclinometry and the current measured depth calculated from the current value of the penetration rate received from the device 804l to calculate the rate of penetration. Then, the device 804m for calculating the actual depth uses the specified data to calculate the actual vertical depth, which is transmitted to the device 804k for calculating the pressure.

The bit load calculator 804n is designed to obtain a jamming / slipping index from the jamming / slipping sensor 804o, as well as the current load on the hook 806d from the load sensor 808d for attaching the fixed end of the cable. The bit load calculator 804n may also serve to obtain the nominal weight of the column held over the face, which may differ from the nominal bit load obtained from the input 802r of the nominal bit load and the current load on the hook 806d received from the load sensor 808d on fixing the fixed end. In any case, the bit load calculator 804n is for calculating the current bit load based on the current hook load, the current column weight and the jamming / slipping index. Then, the current value of the bit load is transmitted to the shaft position controller 804e, the device 804g for calculating the d-exponent, the device 804h for calculating the adjusted d-exponent, the device 804i for calculating the specific mechanical energy and the drum controller 804b.

The jamming / slipping sensor 804o is designed to obtain the current top drive torque 806k and using the acquired data to generate a jamming / slipping index, which is then supplied to the mud pump controller 804c, the vibration controller 804d and the shaft position controller 804e. The jamming / slipping sensor 804o measures the top drive torque 806k in time, which is an indication of whether the bit may show intermittent movement (jamming / slipping), which indicates that the upper drive torque and / or bit load need to be reduced , or it is necessary to change the amplitude of the shaft oscillations.

Processors 804 may be implemented together as a single processing device or as a plurality of processing devices. Each processor 804 may include one or more programs or other program modules, submodules, subroutines, standard subroutines, state machines, algorithms. Each processor 804 may further include one or more computer storage devices or other means for storing digital data. Aspects of one or more processors 804 may be substantially similar to those described herein with respect to any controller or other data processing device. Accordingly, processors 804 may include or consist of at least a portion of controller 190 in FIG. 1, the controller 325 in FIG. 3, the controller 420 of FIG. 4A-C and controller 698 in FIG. 6B, for example.

In FIG. 8B shows a control module of a system 812 in accordance with one or more aspects of the present description. The system control module 812 is one possible embodiment of the device 800 shown in FIG. 8A, and may be used in conjunction with or may be housed in the device 100 shown in FIG. 1, as well as in any of the devices 300, 400a, 400b, 400c and 790 shown in FIG. 3, 4A-C and 7B, respectively. System control module 812 may also be used to implement one or more aspects of the methods shown in any of FIGs. 2A, 2B, 5A, 6A, 6C, 7A, 7B and 7C.

The system control module 812 includes an interface module 814, a data communication module 816, and a drilling process control master module 818. Module 814 includes a manual data input module 814b 814a and an image output module. The master drilling process control module 818 includes sensor data module 818a, a control signal transmission module 818b, a BHA control module 818c, a drawworks control module 420b, a top drive control module 420a, a mud pump control module 420f, a penetration rate optimization module 818g, a 818h module bit life optimization, specific mechanical energy optimization module 818i, d-exponent optimization module 818j, adjusted d-exponent optimization module 818k, and optimization module 818m tion BHA.

Manual data entry module 814a is intended to facilitate user input of various control values, operating ranges, formation conditions, equipment parameters and / or other data including a drilling plan or data for determining a drilling plan. For example, manual data input module 814a may provide inputs 802 shown in FIG. 8A, among others. Such data can be obtained by the manual data input module 814a through the data transmission module 816, which may include or support one or more connectors, ports and / or other means for receiving data from various data input devices. The image output module 814b is intended to display an indication that the user has successfully made partial or full input, which is facilitated by the manual data input module 814a. Such an indication may include some type of visual indication, for example, an indication by outputting text or graphic characters, or other information, by turning on one or more light indicators or LEDs, or by changing the color of the light indicators, LEDs, graphic sign or symbol, among others.

The master drilling process control module 818 is designed to receive user input from an interface module 814, which in some embodiments is coupled via a data transfer module 816, as in the embodiment shown in FIG. 8B.

The data module 818a from the sensors of the host drilling process control module 818 also receives sensory or measured data from various sensors, sensors, code sensors and other similar devices associated with various equipment and elements of the drilling rig. Examples of such sensory and information-receiving devices include devices 430 shown in FIG. 4A, and devices 806 in FIG. 8A, among other figures included in the present application. Said sensor data may also be obtained by the sensor data module 818a from the sensors via the data transmission module 816.

The control signal transmission module 718b serves as an interface between the control modules of the master drilling process control module 818 and the actual operating systems. For example, it sends and receives control signals 130 for drawworks, top drive 140, mud pump 180, and, in some embodiments, BHA 170 in FIG. 1. The BHA control module 718c may be used when the BHA is controlled in the well.

Winch control module 420b, top drive control module 420a and mud pump control module 420f are used to generate control signals sent through the control signal transmission module 718b of the drawworks, top drive and mud pump. They may correspond to the controllers shown in FIG. 4C.

In some embodiments, the leading drilling process control module 818 may not include all of the optimization modules 818g-m shown, with each of the optimization modules being separately ordered by the user. Accordingly, some embodiments may include only one of the optimization modules, while other embodiments include more than one optimization module. Thus, the leading drilling process control module 818 can be configured in such a way that the available modules cooperate to achieve optimization values, taking into account all optimization modules available in the drilling drilling process control module. This is further discussed below with reference to FIG. 8C.

Shown in FIG. 8B, the penetration rate optimization module 818g determines methods or process adjustments that improve the BHA penetration rate. The sinking speed optimization module 818g receives data from the sensor data module 430, as well as other data, including data regarding the orientation of the bit end, among others, in order to determine the most efficient way to maximize the sinking speed. After evaluating these and / or other factors, the penetration rate optimization module 818g is coupled to the control modules 818c, 420a, 420b, and 420f so that the control modules can determine if the control changes can optimize the penetration rate in a way that maximizes productivity and efficiency.

The bit life optimization module 818h can evaluate the data received from the sensor data module 430, as well as the bit face orientation data, including azimuth, bit face orientation deviation data, and drilling duration, to determine the most efficient way to maintain bit life without sacrificing performance or performance. After evaluating these or other factors, the bit life optimization module interacts with the control modules 818c, 420a, 420b, 420f so that the control modules can determine whether the regulatory changes have preserved the bit life in a way that maximizes productivity and efficiency.

The specific mechanical energy optimization module 818i performs the specific mechanical energy optimization processes described above with respect to FIG. 6A, 6C and 6D. The conclusions 818i of the optimization module may be connected to the control modules 818c, 420a, 420b, 420f in order to actually implement changes that lead to increased efficiency.

The d-exponent-based optimization module 818j may include a d-exponent calculator 804g, which is designed to determine the d-exponent and estimate the penetration rate, which makes it possible to detect or predict zones with abnormal pore pressure. Thus, since the d-exponent module determines the difference at normal pressure, the d-exponent module can interact with the control modules 818c, 420a, 420b, 420f in the evaluation, which makes any control changes necessary for efficient drilling.

The adjusted d-exponent optimization module 818k may include a device 804h for calculating the adjusted d-exponent. Using the data, the optimization module 818k corrects the d-exponent value taking into account the weight of the drilling fluid, which can be associated directly with reservoir pressure, and not with differential pressure. The indicated corrected value may also go to the control units 818c, 420a, 420b, 420f during evaluation, which makes any control changes necessary for efficient drilling.

The BHA optimization module 818m may evaluate data received from the sensor data module 430, data input in the manual data input module 714a, as well as other available data, in order to determine optimization profiles for the BHA. In some embodiments, the BHA optimization module 818m processes the information received from other modules in the drilling process control master module 718. Using this information, the BHA optimization module 818m provides data to the control modules 818c, 420a, 420b, 420f during evaluation, which makes any changes to the BHA control necessary during the optimization of the BHA.

Like the drawworks control module 420b, the top drive control module 420a and the mud pump control module 420f receive information from the optimization modules, they process the data to determine how, positively or negatively, the interaction of the recommended changes affects the overall productivity of the well system and generate control signals instructing the drawworks 130, top drive 140 and mud pump 180 shown in FIG. 1, implementing changes with maximum efficiency.

In FIG. 8C shows an example method 830 performed by a leading drilling process control module 818 to optimize an overall drilling process in a drilling rig. As described above, some embodiments of the host drilling process control module 818 do not include all of the optimization modules shown in FIG. 8B. Thus, method 830 considers circumstances in which a leading drilling process control module includes one, more than one, or not all of the optimization modules shown. It is assumed that these modules are exemplary and that other optimization modules may be included in them.

Method 830 includes operations that are performed in parallel, and may not be performed in sequence. In some embodiments, the indicated parallel paths of the method are alternative paths and can be implemented based on the configuration of the host drilling process control module and / or the availability of optimization modules. For example, from operation 832, method 830 continues to operations 834, 840, 846, 852, 858. They are all described below.

In FIG. 8C, in operation 832, the drilling process master module 718 receives manual inputs and / or sensor data from the manual data input module 814a and / or data module 430 from the sensors (input or sensor data not shown). In some cases, the leading drilling process control module 718 can access the dynamics data stored in previous inclinometry measurements.

Using the specified information and data, the optimization modules in the host drilling process control module 818 calculate or otherwise process the data using algorithms to determine the optimization value for any number of factors affecting drilling efficiency or productivity, including drilling speed. In some embodiments, alternative paths in FIG. 8C depend on the availability of optimization modules. For example, from operation 832, method 830 continues to operation 834 if the leading drilling process control module 818 from the optimization modules includes only the penetration rate optimization module 818g. Alternatively, from operation 832, method 830 continues to operation 840 if the lead drilling process control module 818 includes only one of the specific mechanical energy optimization module 818i, the d-exponent optimization module 818j, and the adjusted d- optimization module 818k Exponent and BHA optimization module 818m. Again, in an alternative, starting from operation 832, method 830 continues to operation 846 if the master drilling process control module 818 includes more than one optimization module. Method 832 continues to operation 852 if the leading drilling process control module 818 includes penetration rate optimization module 818g and one of the specific mechanical energy optimization module 818i, the d-exponent optimization module 818j, and the d-exponent adjusted optimization module 818k and BHA optimization module 818m. Method 832 continues to operation 858 if the host drilling process control module 818 includes a penetration rate optimization module 818g and more than one optimization module 818i, 818j, 818k, 818l, 818m.

In alternative embodiments, the leading drilling process control module 818 performs all the operations of the method instead of processing them as alternative operations, as described above. Thus, although the leading drilling process control module includes many optimization modules, it still evaluates the penetration rate optimization module 818g independently in operation 834, evaluates one of the other optimization modules independently in operation 840, and in the same way with operations 846, 852 and 858 .

In circumstances where only the penetration rate optimization module 818g is included in the drilling process control master module 818 or the control master module 818 is designed to evaluate only the penetration rate optimization module 818g, in operation 834, the penetration rate optimization module 818g determines changes in drilling parameters that optimize the process drilling based on penetration rate using manual inputs and / or sensor data. These drilling parameter changes are transmitted to the BHA control module 818c, the drawworks control module 420b, the top drive control module 420a and / or the mud pump control module 420f. In operation 836, said control modules modify one or more control signals sent by the BHA to the drawworks, top drive and / or mud pump to change the drilling parameter (s) needed to optimize the drilling process based on the penetration rate.

In circumstances where only one optimization module is included in the drilling process control master module 818, or the control master module 818 is designed to evaluate only one optimization module 840, in operation, using the specific mechanical energy optimization module 818i, the optimization module 818j based on d-exponent, optimization module 818k based on the adjusted d-exponent and BHA optimization module 818m, the leading drilling process control module 818 can calculate one of the specific mechanical energy, d-exposure nt, adjusted d-exponent, and BHA optimization values based on data received from a data module from sensors or a manual data input module 814a. Based on these data, in operation 842, the drilling process control module 818 can determine the drilling parameter changes needed to optimize the drilling process based on one calculated value from the specific mechanical energy, d-exponent, adjusted d-exponent, and BHA optimization values. These drilling parameter changes are provided to the BHA control module 818c, the drawworks control module 420b, the top drive control module 420a and / or the mud pump control module 420f. In operation 844, said control modules alter control signals sent to the BHA, drawworks, top drive and / or mud pump to change the drilling parameters necessary to optimize the drilling process based on the calculated value.

In circumstances where more than one optimization module is included in the leading drilling process control module, in operation 846, using the optimization modules 818i, 818j, 818k, 8181, 818m, the leading drilling process control module 818 preferably calculates more than one (usually at least two ) a parameter from specific mechanical energy, d-exponent, adjusted d-exponent, and BHA optimization values based on data received from a data module from sensors or a manual data input module 814a. Based on the above data, in operation 848, the leading drilling process control module 818 can determine changes in the drilling parameter necessary to optimize the drilling process based on a number of calculated values. These drilling parameter changes are provided to the BHA control module 818c, the drawworks control module 420b, the top drive control module 420a and / or the mud pump control module 420f, and in operation 850, these control modules change the control signals sent to the BHA, the drawworks to the top drive and / or a mud pump in order to change the drilling parameters necessary to optimize the drilling process based on a series of calculated values.

In circumstances where a penetration rate optimization module 818g is included in the drilling process control master module 818 and only one other optimization module or the control master module 818 is designed to evaluate only the penetration rate optimization module 818g and only one other optimization module, in operation 854, the master module 818, the drilling process control preferably determines the drilling parameter changes necessary to optimize the drilling process based on one calculated value and the optimization value c orosti penetration. The indicated values are supplied to the control modules and, in operation 856, these control modules can change the control signals sent to the BHA, the drawworks, the top drive and / or the mud pump to change the drilling parameters necessary to optimize the drilling process based on the calculated value.

In circumstances where a driving speed optimization module and more than one additional optimization module are included in the leading drilling process control module, in operation 858, using the optimization modules 818i, 818j, 818k, 8181, 818m, the leading drilling process control module 818 calculates more than one parameter from d-exponent, adjusted d-exponent, and BHA optimization values based on data received from the data module from the sensors and / or manual data input module 814a. In this case, the leading drilling process control module 818 estimates the penetration rate by determining changes in the drilling parameter necessary to optimize the drilling process. Thus, the leading drilling process control module 818 can evaluate a plurality of calculated values received from optimization modules, including sinking speed, to determine optimized changes in the drilling parameter. Indicated changes in the drilling parameter are provided to the control modules 818c, 420b, 420a and / or 420f, and in operation 862, said control modules change the control signals sent to the BHA, the drawworks, the top drive and / or the mud pump to change the drilling parameters necessary for optimization of the drilling process based on a variety of calculated values.

No matter which path is used, after sending the modified control signals from the master drilling process control module, the image output module 814b preferably updates the additional, but preferred interface display in operation 838, displaying the indicated new changed control signals. An interface display is further discussed and incorporated herein.

In some cases, the drilling control module 818 performs all or some of the operations 834, 840, 846, 852, 858 at the same time, or in a fairly fast sequence, almost simultaneously, and the control signals change based on multiple inputs from the system .

In FIG. 9A and 9B are flowcharts detailing methods for optimizing the accuracy of directional drilling during drilling operations performed by the apparatus 100 in FIG. 1. In the implementation of the methods of FIG. 9A and 9B, any of the control systems disclosed herein may be used, including FIG. 1, 3, 4A-C, 6B, 8A and 8B. Real-time data in these methods can be configured as inputs in FIG. 4A in order to optimize the drilling process and calculate the position of the bit to identify and correct any deviations of the bit from a given drilling path during drilling operations.

In FIG. 9A shows a flowchart of a method 900 in accordance with one or more aspects of the present description. The method 900 may be performed in conjunction with one or more elements of the device 100 shown in FIG. 1, during operation of the device 100. For example, method 900 may be performed to optimize the accuracy of directional drilling during drilling operations performed using the device 100.

The method 900 includes an operation 910, in which the position of the end face of the bit in real time, the depth of the well, the rotation of the pipe, the load on the hook, pressure drop and / or other data are fed to a controller or other device for processing data (for example, any controller 190, 325 , 420, 402, 698, 804, 812 or others described in this application). Data can be obtained from various instruments on the rig and / or sensors designed for such measurements (such as the sensors shown in Figs. 1, 4A, 8 A, and others). Operation 910 may also include obtaining simulated sharp bending of the trunk and / or other drilling plan data taken from inclinometric measurements or otherwise obtained. In the next operation 920, operational and / or simulated data obtained during operation 910 are used to calculate the real-time inclinometric projections before the last result of standard inclinometry. The real-time inclinometric projection calculated in step 920 may then optionally be temporarily used as the next standard inclinometry point in subsequent step 930. The method 900 may also include step 940, performed after step 920 and / or step 930, in which the real-time inclinometric projection calculated in step 920 is compared with the drilling plan at the corresponding depth of the well. Operation 950 may be performed after operation 930 and / or prior to operation 940, while during it the directional drilling technologist receives an in-line projection in real time calculated during operation 920 and / or the results of the comparison performed during operation 940. Therefore, the directional drilling technologist can more accurately evaluate the progress of the current drilling operation even in the absence of any direct inclination and azimuth measurements at the depth of the well.

In an exemplary embodiment, as part of the present description, method 900 is then repeated so that the process flow returns to operation 910 and starts again. An iteration of method 900 can be used to evaluate the bottom of the drill string. In addition, the iteration may allow the real-time inclinometry projection calculation model to be updated each time the inclinometry data is received. The application of method 900, in at least some embodiments, can help a directional drilling technologist during drilling by applying the radius of curvature set and the angular velocity of rotation to rotor-free intervals and projections along the intervals traversed by rotary drilling.

As described above, a conventional approach involves performing standard inclinometry at each joint of the drill pipe to obtain a tilt and azimuth measurement for the new inclinometer position. Thus, in the prior art, measurements are taken after a well has been drilled. In contrast, using method 900 and other methods, within the scope of the present description, real-time measurements are taken before the last standard inclinometry, which can provide the directional drilling technologist with information regarding the progress and effectiveness of the rotary or rotary drilling operation.

In FIG. 9B is a flowchart of a simplified version of the method 900 shown in FIG. 9A, which is designated as 900a. Method 900a includes operation 910, during which data from the position of the end face of the bit and the measurements of the depth of the well are obtained from devices on the rig. Step 910 may also include obtaining model data or a drilling plan corresponding to operational data received from instruments at the drilling rig. Such reception of operational and / or simulated data may occur in one or more controllers, data processing devices, and / or other devices, such as the controller 190 shown in FIG. one.

In a next operation 960, these measurements are used together with simulated or calculated data obtained from previous inclinometry measurements (for example, including the rate of set of curvature of the wellbore, sharp curvature of the wellbore, etc.) in order to track well penetration by calculating the projection of real-time inclinometry , followed by a comparison of the projection with the drilling plan. Operations 910 and 960 are then repeated, if possible at rates or intervals that give a high degree of resolution. Operation 960 may also include averaging the received data over depth intervals (for example, averaging the latest received data with previously received data). Thus, the data obtained during operation 910 and processed during operation 960 can provide accurate resolution, possibly based on foot-by-foot during the rotary drilling operation, and can demonstrate how a particular drilling operation can be affected or affected by how accurately a specific end face is supported.

A high-resolution survey of the current well in comparison with the drilling plan is often key in determining the effectiveness of the rotary drilling operation. For example, within a lap span, a directional drilling technologist may need to (for example, according to a drilling plan) perform rotary-free drilling on a 20-foot, 50-foot rotary drilling segment, and then again 20-foot rotary drilling. Typically, the driller will not know the effectiveness of this section until he receives the data of the next inclinometry measurement performed after trying to perform the “rotary-rotor-rotorless” drilling operation. However, according to one or more aspects of the present description, a driller can calculate, using real-time inclinometry projections during a rotary-rotor-rotorless drilling operation, the predicted bit path in the well. Thus, the accuracy with which the rotary-rotor-rotorless drilling operation is performed can be significantly increased, and if the method of FIG. 5A provides more accurate directional correction than conventional systems. In addition, methods 900 and 900a may include updating the radius of curvature of the set and the model for each inclinometry measurement in real time, thereby improving the accuracy of each subsequent measurement, projection of inclinometry and / or the drilling stage.

FIG. 10A and 10B are exemplary images of user displays transmitting bit location information to a user. The display in the Figures may be any display described in this application, including displays 335, 472, 692c and 810. In FIG. 10A is a schematic diagram of an operator interface 1000 in accordance with one or more aspects of the present description. The interface 100 can be used by a human operator during directional drilling and / or other drilling operations to control the relationship between the orientation of the end face of the bit and the position of the shaft. In an embodiment, the interface 1000 is one of several displays selected by the user during drilling operations, and may be included as or within the operator interfaces, drilling operations and / or drilling devices described in the systems in this application and systems included by links, the interface 100 may also be executed as a series of instructions recorded on a computer-readable medium, such as described in one or more of these links.

The interface 100 is used by the directional drilling technologist during the drilling process to control the BHA in three-dimensional space. A control system or a computer that controls one or more other operator interfaces during the drilling process may also provide an interface 1000. Alternatively, the interface 1000 may be controlled or displayed by a separate control system or computer, and may be displayed on a computer display (monitor), different from that to which the remaining images of the drilling process are displayed.

The control system or computer that controls the interface 1000 includes an "inclinometric" or other data channel, or other means for receiving and / or reading data from sensors transmitted from the BHA, "measuring while drilling" equipment and / or other parameter measuring tools drilling, where such a transmission can be performed using the Protocol of data exchange with the drilling, markup language and / or other data transfer protocol. Such electronic data may include data on the orientation of the bit end face based on gravity, data on the orientation of the bit end based on the magnetic field, data on the orientation of the azimuth of the bit end and / or data on the orientation of the bit end, among others. In an exemplary embodiment, electronic data includes data on the orientation of the bit face based on the magnetic field when the orientation of the bit end is less than about 7 ° relative to the vertical, and alternatively includes data on the orientation of the bit end based on gravity when the orientation of the bit end is greater than about 7 ° relative verticals. However, in other embodiments, electronic data may include bit face orientation based on both gravity and magnetic field. Bit azimuth orientation data may relate to the azimuthal direction of the distal end of the drill string relative to geographic north, the upper side of the wellbore and / or other specified orientation. The bit end inclination orientation data may relate to the inclination of the distal end of the drill string relative to the vertical.

As shown in FIG. 10A, the interface 1000 may be depicted as essentially resembling a disk or target shape having a plurality of concentric nested rings 1005. The magnetic field orientation information for the bit end is represented in the interface 1000 by 1010, and the gravity bit end orientation data is presented characters 1015. The interface 1000 also includes characters 1020 indicating shaft positions. In the embodiment shown in FIG. 10A, bitface magnetic data symbols 1010 are circular, bitface gravity data symbols 1015 are rectangular, and shaft position data symbols 1020 are triangular, thereby distinguishing different types of data from each other. Of course, other forms may be used within the framework of the present description. Symbols 1010, 1015, 1020 may additionally or alternatively differ from each other in color, size, backlight, flicker frequency and / or other graphic means.

Symbols 1010, 1015, 1020 may indicate only the most recent measurements of the position of the end face of the bit (symbols 1010, 1015) and the shaft of the symbol (120). However, as in the embodiment shown in FIG. 10A and 10B, the interface 1000 may include a representation of previous measurements of the position of the end face of the bit and shaft, with the last measurement and several previous measurements being shown. Thus, for example, each ring 1005 in the interface 1000 may represent a measurement iteration or count, or a predetermined time interval, or otherwise indicate the dynamics between the new measurement (s) and the previous measurement (s). In the embodiment shown in FIG. 10A, five such rings 1005 are present in the disk (an outer ring is used to indicate other data), each ring 1005 representing data measurements or transmission iteration, or counting. The bit end symbols 1010, 1015 may include a number indicating the relative age of each measurement. In other embodiments, the implementation of the color, shape and / or other signs can graphically display the relative duration of the measurement. Although in FIG. 10A is not shown, this concept can also be used to display previous shaft position data.

The interface 1000 may also include an explanation of the data symbols 1025 associated with the shape, color and / or other parameters of the data symbols 1010, 1015, 1020 for the corresponding data represented by symbols. The interface 1000 may also include a text and / or other type of indicator 1030 of the current setting mode of the end face of the bit. For example, the end face mode can be set to display only gravitational end face data, only magnetic end face data, or a combination thereof (possibly based on the current tilt of the end face and / or the end of the drill string). Indicator 1030 may also indicate the current system time. Indicator 1030 may also identify a secondary channel or a monitored parameter or parameter otherwise displayed by the interface 1000. For example, in the embodiment shown in FIG. 10A, the indicator 1030 indicates that the combination (“Combo”) of the bit face mode is currently selected by the user, that the bit depth is controlled by the secondary channel and that the current system time is 13:09:04.

The interface 1000 may also include a textual and / or other type of indicator 1035 showing the current or last orientation of the bit end. Indicator 1035 may also show the current mode of measurement of the end face of the bit (for example, gravitational or magnetic). Indicator 1035 can also show the time at which the last measurement of the end face of the bit was made or received, as well as the value of any parameter that was being monitored at that moment by the second channel. For example, in the embodiment shown in FIG. 10A, the last measurement of the end face of the bit was carried out by the gravitational sensor of the end face of the bit and showed that the orientation of the end of the bit was -75 °, that the measurement was performed at 13:00:13 according to the system’s clock, and that the last bit depth measured at the indicated time was 1830 ft.

Interface 1000 may also include a text and / or other type of indicator 1040 showing the current or last tilt of the distal end of the drill string. Indicator 1040 can also show the time at which the last tilt measurement was taken or received, as well as the value of any parameter that was being tracked by the second channel at that time. For example, in the embodiment shown in FIG. 10A, the last inclination of the end of the drill string was 8 °, and this measurement was taken at 13:00:04 hours of the system, and the last bit depth measured at the indicated time was 1830 feet. The interface 1000 may also include an additional graphical or other type of indicator 1040a showing the current or last tilt. Thus, for example, the interface 1000 can display the current or last tilt value using both a text indicator (e.g., indicator 1040) and a graphic indicator (e.g., indicator 1040a). In the embodiment shown in FIG. 10A, a tilt graph indicator 1040a represents the current or last tilt value in the form of an arcuate strip, the length of which indicates the degree to which the tilt deviates relative to the vertical, and where the direction in which the strip extends (for example, clockwise or counterclockwise) indicate the direction of inclination (e.g. north or south).

The interface 1000 may also include a textual and / or other type of indicator 1045 showing the current or last azimuth orientation of the distal end of the drill string. Indicator 1045 can also show the time at which the last azimuth measurement was made or received, as well as the value of any parameter that was being tracked by the second channel at that time. For example, in the embodiment shown in FIG. 10A, the last azimuth of the end of the drill string was 67 °, and this measurement was taken at 12:59:55 hours of the system, and the last bit depth measured at the indicated time was 1830 feet. The interface 1000 may also include an additional graphical or other type of indicator 1045a showing the current or latest tilt value. Thus, for example, the interface 1000 can display the current or last slope using both a text indicator (e.g., indicator 1045) and a graphic indicator (e.g., indicator 1045a). In the embodiment shown in FIG. 10A, an azimuth graph indicator 1045a represents the current or last azimuth measurement in the form of an arc strip, the length of which indicates the degree to which the azimuth orientation deviates from geographic north or some other predetermined position, and where the direction in which the strip stretches (e.g., clockwise or counterclockwise), may indicate the direction of the azimuth (for example, northeast or northwest).

In some embodiments, the interface 1000 includes data corresponding to a predetermined drilling path and an actual drilling path described in FIG. 4C and 5A. These data can provide the driller with a visual indicator of the location of the BHA bit relative to a given drilling path and / or target location. In addition, the data recorded in the dynamics displayed in the interface 1000 in FIG. 10A can be estimated in calculating the position of the BHA, regardless of whether the BHA deviates from a given drilling path and in which zone shown in FIG. 5B, BHA located.

In FIG. 10B is an enlarged view of a portion of the interface 1000 shown in FIG. 10A. In embodiments in which the interface 1000 is depicted in the form of a disk or a target, the latest measurements of the position of the end face of the bit and shaft may be located closer to the edge of the disk, and previous readings may recede to the middle of the disk. For example, in the embodiment shown in FIG. 2, the last reading was received 8 minutes before the system currently displayed, the next reading was received 7 minutes before the first, and the oldest reading was received 6 minutes earlier than the others, for a total of 21 minutes of registration. Readings taken hours or seconds ago may indicate the duration / unit of time with the characters “h” or “s”.

As also shown in FIG. 10B, hovering the mouse cursor of a user or other graphical input means of the user on one of the position symbols of the end face of the bit or shaft 1010, 1015, 1020, the time mark of the symbol can be shown, as well as a secondary indicator (if present) in the window 1050. Time marks can depend on the device settings at the actual time the measurement was recorded. Symbols 1010, 1015 of the end face of the bit may indicate the time elapsed after the measurement was recorded by the touch device (for example, relative to the current time of the system). Secondary channels configured to show a timestamp can show a timestamp corresponding to the device registering the measurement.

In the embodiment shown in FIG. 10A and 10B, the interface 1000 shows the absolute position of the top drive shaft oriented to geographic north, the top of the well, or some other predetermined direction. The interface 1000 also displays current and previous bitface data received from downhole tools. An interface 1000, other operator interfaces within the framework of the present description and / or other devices within the framework of the present description may have, provide and / or demonstrate a simplified understanding of the effect of reactive torque on the measurements of the end face of the bit, accurately controlling and simultaneously displaying measurements of the position and end face of the bit, and shaft to the user.

In view of the foregoing, as well as the figures and references included in this application, it will be obvious to those of ordinary skill in the art that the present description provides a method for visually demonstrating the relationship between the orientation of the end face of the bit and the orientation of the shaft, this method including: obtaining electronic data on permanent basis, which includes data on the orientation of the shaft and at least one of the data on the orientation of the end face of the bit based on gravity and data on the orientation of the end face of the bit based on the magnetic field and output electrons to the display data that is available for user review, in the historic format that displays data from the last measurement and a plurality of previous measurements. Electronic data may also include bit face azimuth data relating the drill string azimuth orientation near the bit. Electronic data may further include the bit-end inclination data, linking the drill string propensity near the bit. These shaft positions can relate the orientation of the shaft, top drive, lead pipe and / or other rotary engine devices to the bit and / or end face of the bit. Electronic data can be obtained from IPB and / or other sensory / measuring downhole devices.

The method may also include combining electronic data with time indications based on specific points at which measurements were taken to produce electronic data. In an embodiment, the most recent data can be displayed in text form, and previous data can be displayed graphically, for example, as an indication in the form of a disk or a target. The graphic display may include time-dependent or time-specific characters or other images that, in a user-accessible mode, may temporarily display data related to a specified time (e.g., pop-up data). Icons can have a numerical, text, color or other indication by prescription relative to other icons. Icons can correspond to the time, the last at the edge of the disc, the first in the center of the disc. Icons can display a change in time from the measurement recorded by the corresponding touch device to the current time of the computer system. The display can also display the current system time.

The present disclosure also provides a device comprising devices for receiving electronic data on an ongoing basis, where the electronic data includes data on the orientation of the shaft and at least one of the data on the orientation of the bit end based on gravity and the data on the orientation of the bit end based on magnetic fields and devices for outputting electronic data to a display accessible for user review in a historical format displaying data obtained in the last measurement and many previous measurements.

Embodiments within the scope of the present disclosure may provide certain advantages over the prior art. For example, when these positions of the end face of the bit and the shaft are combined on one display, this can help the operator or other worker to understand the relationship between the position of the shaft and the end of the bit. Combining bit end and shaft position data on a single display can additionally or alternatively help to understand the relationships by which reactive torque is associated with the bit and / or shaft end position.

In FIG. 11 shows an exemplary system 1100 for implementing one or more embodiments of at least a portion of the device and / or methods described herein. System 1100 includes a processor 1102, an input device 1104, a data storage device 1106, a video controller 1108, a system memory 1110, a display 1114, and a communication device 1116 connected to one or more buses 1112. The data storage device 1106 may be a floppy disk, a hard disk, or a compact disk , DVD, optical disc drive or any other form of storage device. In addition, the storage device 1106 may be capable of receiving a floppy disk, CD, DVD, or any other form of computer-readable medium that may contain computer-executable instructions. Communication device 1116 may be a modem, network card, or any other device by which system 1100 can communicate with other systems.

A computer system typically includes at least hardware capable of executing machine-readable instructions, as well as software for performing actions (usually machine-readable instructions) that produce the desired result. In addition, a computer system may include hybrids of hardware and software, as well as computer subsystems.

Hardware typically includes at least processor platforms, such as user machines (also known as personal computers or servers), as well as handheld data processing devices (such as smartphones, PDAs, as well as personal computing devices). In addition, hardware typically includes any physical device that is capable of storing machine-readable instructions, such as memory or other storage devices. Other forms of hardware include hardware subsystems, including transmission devices such as modems, modem cards, ports, and port cards, for example. Hardware may also include, at least as part of the present description, multimodal technology, such as devices and / or systems, allowing users to use multiple forms of input and output, including voice, keyboards and a pen, alternately in the same interaction, application or interface.

The software may include any machine code stored on any medium, such as RAM or ROM, machine code stored on other devices (such as floppy disks, CDs or DVDs, for example), and may include executable code, an operating system, as well as the source or object code, for example. In addition, the software may encompass any set of instructions executed on a user machine or server and, in this form, often referred to as a program or executable code.

Hybrids (combinations of software and hardware) are becoming more common as devices to provide enhanced functionality and efficiency to computer systems. A hybrid can be created when what is traditionally a software function is directly sewn into a silicon crystal during the manufacturing process - this is possible, since the software can be assembled and converted into binary code, and, in the same way, binary code can be represented directly in silicon. As a rule, the functions of a hybrid (manufactured hardware) are designed to work without firmware firmware. Accordingly, it must be understood that hybrids and other combinations of hardware and software are also included in the definition of a computer system in this application and are thus provided by this description as equivalent structures and equivalent methods as possible.

Computer-readable media may include a passive storage device, such as random access memory (RAM), as well as a semi-permanent storage device, such as a CD or DVD. In addition, an embodiment of the present description may be embodied in the form of a computer RAM and can efficiently convert a standard computer into a new dedicated computing machine.

Data structures are defined data organizations that can provide an embodiment of the present description. For example, a data structure may provide data organization or organization of executable code (executable software). In addition, data signals are carried in a transmission medium and stored, as well as transporting various data structures and, thus, can be used for transporting an embodiment of the invention. In the present description, it should be noted that processes with similar names can be performed in a similar manner, unless otherwise indicated.

The controllers and / or systems of the present description can be designed to work on any specific architecture. For example, controllers and / or systems can run on one or more computers, Ethernet networks, local area networks, wide area networks, the Internet, intranets, handheld devices, and other portable and wireless devices and networks.

In view of the foregoing, as well as FIG. 1-11, it will be apparent to those of ordinary skill in the art that the present disclosure provides a method for guiding the bottom of a drill string during a drilling process from a rig to an underground target location. The method includes developing a drilling plan, including a drilling path and an acceptable margin of error in the form of a tolerance zone; obtaining data characterizing the orientation and projection of the depth of the bit; determination of the actual location of the equipment of the bottom of the drill string based on the orientation and projection of the depth of the bit; determining if the bit is within the tolerance zone; comparing the actual location of the equipment of the bottom of the drill string with a given drilling path to determine the level of deviation of the equipment of the bottom of the drill string from the actual path of drilling; creating a modified drilling path based on the amount of the identified deviation from the given path, including: creating a modified drilling path that intersects the given drilling path if the level of deviation from the given path is less than the threshold deviation level, and creating a modified drilling path to the target location, which does not cross a predetermined drilling path if the level of deviation from a given path exceeds a threshold level of deviation; determination of the required orientation of the end face of the bit in order to direct the equipment of the bottom of the drill string along the changed drilling path; automatic and electronic generation of drilling rig control signals in the motion control controller; and outputting control signals of the drilling rig to the drawworks and top drive in order to direct the equipment of the bottom of the drill string along the altered drilling path.

The present disclosure also provides a method of using a shaft to adjust a hydraulic motor while driving a wellbore in a direction having a horizontal component, where the shaft and hydraulic motor are connected at opposite ends of the drill string, the method including: monitoring the actual orientation of the end face of the bit driven by the hydraulic engine, by controlling the parameter of the drilling process, characterizing the difference between the actual orientation of the bit end and the required orientation it toolface; and adjusting the position of the shaft by an amount that depends on the controlled parameter of the drilling process. The amount of adjustment of the shaft position may be sufficient to compensate for the difference between the actual and the required orientation of the bit end. Adjusting the shaft position may include adjusting the angular position of the shaft relative to the wellbore, the vertical position of the shaft relative to the wellbore, or both. Monitoring a drilling process parameter characterizing the difference between the actual and required orientation of the bit end may include controlling a plurality of drilling process parameters characterizing the differences between the actual and desired orientation of the bit end, and the amount of shaft position control may also depend on each set of drilling process parameters.

Monitoring a drilling process parameter may include monitoring data received from the bit face orientation sensor, and the amount of shaft position control may depend on the bit face orientation sensor data. The bit end sensor may include a gravitational bit end sensor and / or a magnetic bit end sensor.

The parameter of the drilling process may include the axial load on the bit, the depth of the bit in the wellbore and / or the rate of penetration of the bit into the wellbore. The parameter of the drilling process may include the differential pressure of the hydraulic motor, which can be adjusted to take into account the controlled pressure of the fluid present in the annular space defined between the wellbore and the drill string.

In an exemplary embodiment, monitoring a drilling process parameter characterizing the difference between the actual and desired bit face orientation includes monitoring data received from the bit face orientation sensor, monitoring the load on the bit, monitoring the depth of the bit in the wellbore, monitoring the penetration rate (penetration of the bit into the wellbore ), and control of the differential pressure in the hydraulic motor. Adjusting the position of the shaft may include adjusting the position of the shaft by an amount that depends on the monitored data of the bit face orientation sensor, the monitored load on the bit, the monitored bit depth in the wellbore, the monitored penetration rate and the specified monitored differential pressure in the hydraulic motor.

The control of the drilling process parameter and the adjustment of the shaft position can be performed simultaneously with the operation of the hydraulic motor. Adjusting the position of the shaft may include controlling the winch, which adjusts the load on the bit by an amount that depends on the controlled parameter of the drilling process. Adjusting the shaft position may include adjusting the neutral angular position of the shaft, the method may further include oscillating the shaft, rotating the shaft by a predetermined angle from the neutral position in a clockwise and counterclockwise direction.

The present disclosure also provides a system for applying a shaft to adjust a hydraulic motor while sinking a wellbore in a direction having a horizontal component, where the shaft and hydraulic motor are connected at opposite ends of the drill string. In an embodiment, the system includes devices for monitoring the actual orientation of the bit end, which is driven by a hydraulic motor, includes devices for monitoring a drilling process parameter characterizing the difference between the actual orientation of the bit ends and the required orientation of the bit ends, and devices for adjusting the shaft position by which depends on the controlled parameter of the drilling process.

The present disclosure also provides a device for applying a shaft to adjust a hydraulic motor while driving a wellbore in a direction having a horizontal component, where the shaft and hydraulic motor are connected at opposite ends of the drill string. In an embodiment, the device includes a sensor for detecting a parameter of a drilling process characterizing the difference between the actual orientation of the bit end that is driven by the hydraulic motor and the desired orientation of the bit end; and a bit face controller for adjusting the actual orientation of the bit face by generating a shaft drive control signal regulating the shaft drive to adjust the angular position of the shaft depending on the controlled parameter of the drilling process.

The present disclosure also provides a method of using a shaft to adjust a hydraulic motor while driving a wellbore in a direction having a horizontal component, where the shaft and hydraulic motor are connected at opposite ends of the drill string. In an exemplary embodiment, the method includes controlling the differential pressure of the hydraulic motor while simultaneously controlling the hydraulic motor, as well as adjusting the orientation of the end face of the hydraulic motor bit by adjusting the angular position of the shaft depending on the controlled differential pressure. The controlled pressure drop may be a corrected pressure drop calculated using the controlled pressure of the fluid present in the annular space defined between the wellbore and the drill string. The method may further include monitoring the current orientation of the end face of the motor bit while controlling the hydraulic motor and adjusting the angular position of the shaft depending on the controlled orientation of the end face of the bit. The method may further include monitoring the load on the bit of the hydraulic motor while simultaneously controlling the hydraulic motor and adjusting the angular position of the shaft depending on the controlled load on the bit. The method may further include controlling the depth of the bit of the hydraulic motor in the wellbore while controlling the hydraulic motor and adjusting the angular position of the shaft depending on the controlled bit depth. The method may further include controlling the penetration rate of the hydraulic motor into the wellbore while simultaneously controlling the hydraulic motor and adjusting the angular position of the shaft depending on the controlled penetration rate. Adjusting the face orientation of the bit may include adjusting the angular position of the shaft depending on the controlled load on the bit and the controlled speed of penetration. Alternatively, adjusting the face orientation of the bit may include adjusting the angular position of the shaft depending on the controlled load on the bit, the controlled speed of penetration, and the current orientation of the face of the bit. Adjusting the orientation of the end face of the hydraulic motor bit may further include controlling a drawworks that adjusts the load on the hydraulic motor bit depending on the controlled differential pressure. The angular position of the shaft may be a neutral position, the method may further include oscillating the shaft, rotating the shaft by a predetermined angle from the neutral position in a clockwise and counterclockwise direction.

The present disclosure also provides a system for applying a shaft to adjust a hydraulic motor while sinking a wellbore in a direction having a horizontal component, where the shaft and hydraulic motor are connected at opposite ends of the drill string. In an embodiment, the system includes a device for measuring a differential pressure of a hydraulic motor while simultaneously controlling a hydraulic motor and a device for adjusting the orientation of the end face of the hydraulic motor, where the device for adjusting the orientation of the end face of the bit includes a device for adjusting the angular position of the shaft depending on the measured differential pressure. The system may further include a device for determining the current orientation of the end face of the motor bit while controlling the hydraulic motor, where the device for adjusting the angular position of the shaft can also serve to adjust the angular position of the shaft depending on the controlled orientation of the end face of the bit. The system may further include a device for measuring the load on the bit of the hydraulic motor while controlling the hydraulic motor, where the device for adjusting the angular position of the shaft can also serve to adjust the angular position of the shaft depending on the controlled load on the bit. The system may further include a device for determining the depth of the bit of the hydraulic motor in the wellbore while controlling the hydraulic motor, where the device for adjusting the angular position of the shaft can also serve to adjust the angular position of the shaft depending on the determined depth of the bit. The system may further include a device for measuring the penetration rate of the hydraulic motor into the wellbore while controlling the hydraulic motor, where the device for adjusting the angular position of the shaft can also serve to adjust the angular position of the shaft depending on the controlled penetration rate. The tool for adjusting the orientation of the bit end may further include a device for controlling the drawworks, which adjusts the load on the bit of the hydraulic motor depending on the measured pressure drop.

The present disclosure also provides a device for applying a shaft to adjust a hydraulic motor while driving a wellbore in a direction having a horizontal component, where the shaft and hydraulic motor are connected at opposite ends of the drill string. In an embodiment, the apparatus includes a pressure sensor for measuring a differential pressure of a hydraulic motor during operation of the hydraulic motor, and a bit face controller for adjusting the orientation of the bit end of the hydraulic motor by generating a shaft drive control signal that causes the shaft motor to adjust the angular position shaft depending on the measured differential pressure. The device may further include a bit face orientation sensor for detecting the current bit face orientation, where the bit face controller may serve to generate a shaft drive control signal also based on the detected current bit face orientation. The device may further include a bit load sensor for detecting data characterizing the amount of load on the hydraulic motor bit, as well as a drawworks controller for interacting with the bit face controller when adjusting the bit face orientation by generating a drill winding control signal that indicates the drill the winch to control the winch, where the control signal of the winch can be based on the measured load on the bit. The device may further include a penetration rate sensor for detecting a borehole penetration rate, where a winch control signal may also be based on a detectable penetration rate.

Methods and apparatus within the framework of the present description include methods and apparatus aimed at automatically obtaining and / or maintaining the required orientation of the bit face by controlling parameters of the drilling process that were not previously used for automatic orientation of the bit face and include one or more of the actual hydraulic bottomhole pressure period engine, the actual orientation of the end face of the bit, the actual load on the bit, the actual depth of the bit, the actual speed of penetration, the actual count fucking shaft. Examples of combinations of these drilling process parameters that can be used according to one or more aspects of the present description to obtain and / or maintain the desired orientation of the bit end include the following

ΔP and TF;

ΔP, TF and WOB;

ΔP, TF, WOB and DEPTH;

ΔP and WOB;

ΔP, TF and DEPTH;

ΔP, TF, WOB and ROP;

ΔP and ROP;

ΔP, TF and ROP;

ΔP, TF, WOB and OSC;

ΔP and DEPTH;

ΔP, TF and OSC;

ΔP, TF, DEPTH and ROP;

ΔP and OSC;

ΔP, WOB and DEPTH;

ΔP, TF, DEP and OSC;

TF and ROP;

ΔP, WOB and ROP;

ΔP, WOB, DEPTH and ROP;

TF and DEPTH;

ΔP, WOB and OSC;

ΔP, WOB, DEP and OSC;

TF and OSC;

ΔP, DEPTH and ROP;

ΔP, DEPTH, ROP and OSC;

WOB and DEPTH;

ΔP, DEP and OSC;

ΔP, TF, WOB, DEPTH and ROP;

WOB and OSC;

ΔP, ROP and OSC;

ΔP, TF, WOB, DEP and OSC;

ROP and OSC;

ΔP, TF, WOB, ROP and OSC;

ROP and DEPTH; and

ΔP, TF, WOB, DEP, ROP and OSC;

where ΔP represents the actual differential pressure of the hydraulic downhole motor, TF represents the actual orientation of the bit face, the load on the bit represents the actual load on the bit, the depth represents the actual depth of the bit, the penetration rate represents the actual penetration rate and the OSC represents the actual oscillation frequency shaft, speed, amplitude, neutral point and / or torque.

In the embodiment, the desired orientation of the bit end is provided (for example, by a user, computer or computer program), and the device according to one or more aspects of the present description then monitors and controls the actual orientation of the bit end, as described above. However, when tracking and controlling the actual orientation of the bit face, the data of the drilling operation parameter can be monitored in order to record and then update in real time the relationship between the differential pressure of the hydraulic downhole motor and the bit torque, changes in the bit load and bit torque and changes in the position of the shaft and the actual orientation of the end of the bit, among other possible relationships within the framework of the present description. Then, the obtained information can be used to control the actual orientation of the bit face by changing one or more controlled parameters of the drilling process.

Thus, for example, the desired bit face orientation can be entered by the user, while the rotary drive system according to aspects of the present description can rotate the drill string until the controlled bit face orientation and / or other drilling process parameter data detects movement of the downhole tool. Then, the automated device of the present description continues to control the rotary engine until the desired orientation of the bit face is obtained. Then, directional drilling is performed. If the actual orientation of the end of the bit moves away from the desired orientation of the end of the bit, which can be indicated by the controlled parameter data of the drilling process, the rotary drive can respond by rotating the shaft and / or drill string in a clockwise or counterclockwise direction, according to the relationship between the controlled drilling parameter data and bit face orientation. If an oscillation mode is used, the device can change the amplitude of the oscillation (for example, increasing or decreasing part of the oscillations clockwise), bringing the actual orientation of the end face of the bit in accordance with the plan. Alternatively or additionally, the winch system may respond to a deviation in the orientation of the bit end by feeding or reeling up the drill cable, and / or the mud pump system may respond by increasing or decreasing the differential pressure of the hydraulic downhole motor. If the actual orientation of the end face of the bit deviates from the desired orientation in excess of the specified (user-adjustable) limit for a period longer than the specified (user-adjustable) duration, the device may give an audible and / or visual warning signal. The operator can then allow continued automatic control or accept manual control.

This approach can also be used to control the orientation of the bit face with a known shaft orientation before and after the connection, which reduces the time required for connection. For example, the orientation of the shaft can be controlled in the face with a known orientation of the end of the bit, the load on the bit and / or the pressure drop of the downhole motor. Then, clamps can be set, and the shaft orientation can be recorded and then compared with the above ratio (s). Then a connection can be made, and the orientation of the shaft can be recorded only before removing the clamps. At this point, the shaft orientation can be returned to the one before the connection. Then the operator on the rig or the automated controller can begin the "auto-orientation" procedure, while the device can rotate the shaft to a certain position, and then return to the bottom. Thus, the operator may not need to wait to determine the orientation of the bit end and may not need to return to the face at random. Therefore, aspects of the present description can provide significant time savings during connections.

In addition, the methods within the framework of the present description may be local or remote in nature. These methods, as well as any controllers described in this application, can be provided by one or more intelligent adaptive controllers, programmable logic controllers, artificial neural networks and / or other adaptive, and / or “learning” controllers or data processing devices. For example, such methods can be applied or performed by means of a PLC, PKA, PC, one or more servers, desktop stations, laptop computers and / or any other form or type of computing device with the corresponding ability.

Used in the present description, the term "essentially" means that the numerical amount is in the range of about 20 percent, preferably in the range of about 10 percent, and more preferably in the range of about 5 percent of the specified value. In a preferred embodiment, these terms refer to amounts in the range of about 1 percent, in the range of about 0.5 percent, or even in the range of about 0.1 percent of the specified value.

The term “approximately” as used herein is generally understood to refer to both numbers in a numerical range. For example, “about 1-2” should be understood as “from about 1 to about 2”. In addition, it should be understood that all numerical ranges in the present description include each integer, or 1/10 of an integer, within the range.

Also in the present description by reference, each of the following documents is fully incorporated:

U.S. Patent 6,050,348 (Richarson et al.)

U.S. Patent 5,474,142 (Bowden);

U.S. Patent 5,713,422 (Dhindsa);

U.S. Patent 6,192,998 (Pinckard);

U.S. Patent 6,026,912 (King et al.);

U.S. Patent 7,059,427 (Power et al.);

U.S. Patent 6,029,951 (Guggari);

"A Real-Time Implementation of MSE", AADE-05-NTCE-66;

"Maximizing Drill Rates with Real-Time Surveillance of Mechanical Specific Energy", SPE 92194;

"Comprehensive Drill-Rate Management Process to Maximize Rate of Penetration", SPE 102210; and

"Maximizing ROP with Real-Time Analysis of Digital Data and MSE", IPTC 10607.

The features of several embodiments are set forth above so that those of ordinary skill in the art can better understand aspects of the present description. Those of ordinary skill in the art should understand that they can readily apply the present description as a basis for developing or modifying other methods and structures in order to fulfill the same purpose and / or achieve the same advantages of the embodiments proposed herein. Those of ordinary skill in the art should also understand that such equivalent interpretations do not depart from the essence and scope of the present description, into which they can make various modifications, replacements, or changes without departing from the essence and scope of the present description.

Claims (21)

1. A method of continuous drilling to a target location, comprising the following steps:
obtaining an input including a predetermined drilling path to a target location;
determination of the predicted location of the bottom hole equipment of the continuous drilling system;
comparing the predicted location of the equipment of the bottom of the drill string with a given drilling path to determine the magnitude of the deviation;
creating a modified drilling path to a target location selected based on a deviation from a predetermined drilling path;
automatic and electronic creation of one or more control signals of the drilling rig on the surface of the well to direct the equipment of the bottom of the drill string of the drilling system to the target location along the changed drilling path. 2. The method according to claim 1, in which the target location is a reservoir containing natural oil and / or gas. 3. The method according to claim 1 or 2, in which the creation of a modified drilling path to the target location includes the electronic calculation of at least one curve from the predicted location of the equipment of the bottom of the drill string intersecting a given drilling path, or electronic calculation of a new specified path drilling, which does not cross a predetermined drilling path and is directed from the predicted location of the bottom of the drill string equipment to the target location, or both. 4. The method according to claim 2, which further comprises the following stages:
re-determining the predicted position of the bottom of the drill string of the drilling system;
comparing the predicted location of the bottom of the drill string with a new modified drilling path;
electronically creating a second modified drilling path to the target location;
automatic and electronic creation of one or more control signals of the drilling rig to direct the equipment of the bottom of the drill string of the drilling system along the second modified drilling path to the target location. 5. The method according to any one of claims 1 to 4, in which the determination of the predicted position of the bottom of the drill string includes determining the predicted location of the drill bit of the equipment of the bottom of the drill string, and the determination of the predicted location of the drill bit includes evaluating the data of one or more inclinometry measurements. 6. The method according to claim 1, in which the creation of a modified drilling path is carried out on the basis of whether the deviation from the given path exceeds a threshold value. 7. The method according to claim 6, in which the creation of a modified drilling path based on whether the deviation exceeds the threshold value, and which includes the creation of a modified drilling path crossing the predetermined drilling path if the level of deviation from the given path exceeds the first threshold value deviations, and the creation of a modified drilling path that does not intersect a predetermined drilling path if the level of deviation exceeds the second threshold value of the deviation. 8. The method according to claim 1, in which the predetermined drilling path includes a tolerance zone, and a modified drilling path is created when the predicted position of the bottom hole equipment crosses the boundary of the tolerance zone, and is not carried out when the predicted position of the bottom hole is within the tolerance zone. 9. The method according to claim 7, which further comprises receiving user-initiated input indicating whether to create a new predetermined path to the target that does not intersect the predetermined drilling path when the deviation of the equipment of the bottom of the drill string exceeds a second threshold value of deviation from the given trajectory. 10. The method according to claim 1, which further comprises computing electronically the values of the orientation of the bit end and the measured depth required to direct the equipment of the bottom of the drill string to the target location. 11. The method according to claim 1, in which the creation of a modified path of drilling to the target location includes the following stages:
electronically calculating the first three-dimensional curve;
electronic calculation of the holding section;
optional electronically calculating a second three-dimensional curve, wherein the first and optional second three-dimensional curves are part of a modified drilling path, an optional second three-dimensional curve connects the modified path to the original predetermined drilling path at a location located in front of the target location. 12. The method according to claim 1, which comprises determining a tolerance zone, a threshold zone, and a correction zone around a predetermined drilling path, wherein comparing a predicted position of the bottom of the drill string with a predetermined drilling path includes determining a zone containing a specific projection of the bottom of the drill string , and after creating the changed drilling path to the target location, a new tolerance zone, a new threshold zone and a new correction zone around the changed drilling path are determined. 13. The method according to claim 1, in which the determination of the predicted position of the equipment of the bottom of the drill string includes the use of real-time inclinometry forecast as a guide orientation. 14. The method according to item 13, in which the real-time forecast is performed using the method that includes at least one of the minimum curvature arc, guiding orientations or a straight line, or the real-time forecast includes entering the orientation of the bit end. 15. The method according to claim 1, in which the creation of a modified path of drilling to the target location includes calculating electronically the first three-dimensional curve, the holding section and the optional second three-dimensional curve, which directs the equipment of the bottom of the drill string along a predetermined drilling path, each from the first and optional second three-dimensional curves calculated by electronically calculating any curves required to intersect a given drilling path at the target location, subtracting electronically tracking any curves required to intersect a predetermined drilling path at a first location in front of the target location, each curve having a curvature value acceptable for the bottom of the drill string; electronically calculating any curves required to intersect a predetermined drilling path at a second location in front of the first location, the curves having an unacceptable curvature, the first and second locations are separated by the selected measured distance, and selecting the calculated curves that intersect the predetermined path in the first location before reaching the target location. 16. A system for continuous drilling to a target location, comprising a receiver for receiving an input including a predetermined drilling path to a target location, a sensor device for determining a predicted position of the bottom hole equipment of the drilling system, a first logic device for comparing the predicted position of the bottom hole equipment with a predetermined drilling path to determine the level of deviation, the second logical device for creating a modified path drilling to a target location selected based on a deviation from a predetermined drilling path, and a drilling rig control signal generator for automatically and electronically generating one or more drilling rig control signals that direct the bottom of the drillstring of the drilling system to the target location along a modified drilling path. 17. The system of claim 16, wherein the target location is a formation containing natural oil and / or gas. 18. The system of claim 17, comprising a drawworks drive, a top drive and a mud pump, wherein the control signal generator is capable of supplying one or more control signals to the drawworks, top drive and a mud pump to change the direction of movement of the bottom of the drill string when resuming drilling . 19. The system according to 17 or 18, in which the second logic device provides the creation of a modified drilling path based on whether the deviation from a given path exceeds a threshold value, and contains a device for creating a modified drilling path that intersects a given drilling path, if the deviation level exceeds the first deviation threshold value and the device for creating a modified drilling path that does not intersect the predetermined drilling path if the deviation level p Raises the second deviation threshold. 20. A method for continuously guiding downhole equipment during a drilling process from a drilling rig to an underground target location, comprising the following steps:
development of a drilling plan, which includes a drilling path and an acceptable margin of error in the form of a tolerance zone for continuous drilling;
obtaining data characterizing one or more guiding orientations and prediction of bit depth;
determining the actual location of the bottom of the drill string equipment based on one or more guiding orientations and prediction of bit depth;
determining the location of the drill bit within the tolerance zone;
comparing the actual location of the equipment of the bottom of the drill string with a given drilling path to determine the level of deviation of the equipment of the bottom of the drill string from the actual path of drilling;
creating a modified drilling path based on a deviation amount, including creating a modified drilling path that intersects a predetermined drilling path if the deviation level exceeds a first deviation threshold value, and creating a modified drilling path to a target location that does not intersect a predetermined drilling path if level the deviation exceeds the second threshold deviation;
determination of the required orientation of the end face of the bit for the direction of the equipment of the bottom of the drill string along the changed drilling path;
automatic and electronic generation of one or more drilling rig control signals in a motion control controller;
supplying one or more control signals to the drawworks and top drive for guiding the bottom of the drill string along an altered drilling path. 21. The method according to claim 20, in which the target location is a reservoir containing natural oil and / or gas.

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