RU2424430C2 - Automatic drilling machine on base of (mechanic specific energy) mse - Google Patents

Abstract

FIELD: oil and gas production.

SUBSTANCE: drilling procedure on base of mechanical specific energy (MSE) consists in drilling in first interval, using first workload on bore bit (WOB), in automatic determination of first MSE, corresponding to drilling, using first WOB, in drilling in second interval, using second WOB, different from first WOB, in automatic determination of second MSE, corresponding to drilling, using second WOB and drilling in third interval, using one of first WOB and second WOB chosen automatically on base of automatic comparison of first MSE and second MSE.

EFFECT: upgraded accuracy of determination of working characteristics of drilling machine.

13 cl, 8 dwg

Description

BACKGROUND OF THE INVENTION

Recent advances in drilling optimization use real-time analysis of energy consumption in a drilling system to optimize mechanical penetration rate (ROP). Such an optimization can provide instant ROP increases of 100-400% and increase the length of penetration per day. Similar results can be achieved in soft and hard rocks, steep and gentle inclined wells and with all types of drilling rigs.

However, it is difficult to objectively evaluate the work of operators in terms of drilling speed. In other words, drill bits are often estimated based on well displacement, but drilling speed is often limited by factors that the driller does not control and methods that cannot be recorded in the drill log. Therefore, the drilling speeds between two wells using the same bits can vary significantly. The technique used to evaluate the performance of a drill bit is often more important than evaluating the bit itself.

Drillers conduct many tests to optimize performance. The most common is the "drill test", which consists of simple experimentation with different weights applied to the bit (WOB), and adjusting the rotational speed of the drill bit (RPM), followed by summing up the results. The parameters that result in the highest ROP penetration rate are then used for subsequent operations. In a sense, a similar comparative analysis process is used in all optimization schemes. Thus, drillers seek to identify parameters that lead to better results relative to other established parameters.

One of the earliest designs is the “face-to-bottom bit rotation without recess” test, in which the driller applies a high WOB load and activates the brake to prevent the drill string from moving while continuing to rotate the drill string. As the bit advances, the drill string lengthens and the load on the bit decreases. ROP is calculated from the change in drill string elongation rate as weight decreases. The point at which the penetration rate ceases to correspond to a linear increase in WOB is defined as the point of the “exploratory trunk”. It is taken as the optimal WOB parameter. This process improves performance, but does not provide an objective assessment of the true potential drilling speed.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention can best be understood from the following detailed description with reference to the attached drawings.

Figure 1 is a diagram of a device in accordance with the objectives of the present invention.

Figure 2A is a flowchart of a method in accordance with the objectives of the present invention.

Figure 2B is a flowchart of a method in accordance with the objectives of the present invention.

Figure 3 is a diagram of a device in accordance with the objectives of the present invention.

Figure 4A is a diagram of a device in accordance with the objectives of the present invention.

Figure 4B is a diagram of a device in accordance with the objectives of the present invention.

5A is a flowchart of a method in accordance with the objectives of the present invention.

5B is a diagram of an apparatus in accordance with the objectives of the present invention.

5C is a flowchart of a method in accordance with the objectives of the present invention.

5D is a flowchart of a method in accordance with the objectives of the present invention.

6A is a flowchart of a method in accordance with the objectives of the present invention.

6B is a flowchart of a method in accordance with the objectives of the present invention.

6C is a flowchart of a method in accordance with the objectives of the present invention.

Figure 7 is a diagram of a device in accordance with the objectives of the present invention.

Figure 8 is a diagram of a device in accordance with the objectives of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

It should be understood that the present invention includes many different options or examples of its implementation with various features. A number of exemplary components and their location are described below in a simplified description. They, of course, are merely examples and do not limit the scope of the invention. In addition, in the present disclosure, numeric positions and / or letters may be repeated in various examples. This repetition is done for the purpose of simplicity and clarity of presentation, and does not in itself determine the relationship between the various embodiments and / or the configurations discussed. In addition, the formation of the first feature or the second feature of the invention in the following description may include embodiments in which the first and second features are formed in direct communication, and may also include embodiments in which additional features can be generated by inserting the first and second features in this way that they are no longer in direct communication with each other.

1 is a diagram of an apparatus 100 showing one or more aspects of the present invention. The device 100 is a surface rig or includes such a rig. However, one or more provisions of the present invention can be applied to any type of drilling rig, for example, self-elevating drilling rigs, semi-submersible drilling rigs, drilling ships, tubing strings, well repair facilities, wells adapted for drilling and / or re-entering well and casing of drilling rigs, among other uses within the scope of the present invention.

The device 100 includes a mast 105 for hoisting devices installed above the base of the drilling rig 110. The lifting mechanism includes a crown block 115 and a traveling block 120. The crown block 115 is attached near the top of the mast 105, and the traveling block 120 is suspended from the crown block 115 on the drilling cable 125. One end of the drilling the rope 125 extends from the lifting mechanism to the winches 130, which serve to wind the drill rope onto the drum 125 to raise or lower the traveling block 120 relative to the floor of the drilling rig 110. The other end of the drill rope 125, known as the fixed end mount is fixed in a stationary position, possibly near the winches 130 or elsewhere on the rig.

A hook 135 is attached to the bottom of the tackle block 120. The top drive 140 hangs on the hook 135. The hollow shaft 145 extends from the top drive 140 to the threaded sub 150, which is attached to the drill string 155 in the borehole 160. Alternatively, the hollow shaft 145 may be directly attached to the drill string 155.

The term "hollow shaft", as used here, is not limited to a component that extends directly from the top drive or which is traditionally referred to as a hollow shaft. For example, in the present invention, a “hollow shaft" may additionally or alternatively include a main shaft, a drive shaft, an output shaft and / or another component that transmits torque, position and / or rotation from the top drive or other rotating mechanism to the drill string, at least indirectly. However, just for the sake of clarity and brevity, these components may collectively be referred to herein as the “hollow shaft”.

Drill string 155 includes interconnected sections of drill pipe 165, bottom hole equipment (BHA) 170 and drill bit 175. BHA 170 equipment may include, among other components, stabilizers, weighted drill pipes and / or logging while drilling (MWD) or hanging tools. Drill bit 175, which is also referred to as a tool here, is connected to the bottom of the bottom hole casing equipment BHA 170 or is otherwise attached to drill string 155. One or more pumps 180 may supply flushing fluid to drill string 155 through a hose or other conduit 185, which may be coupled to top drive 140.

Downhole logging equipment (MWD) or tools mounted on a wireline can be used to evaluate physical properties, such as pressure, temperature, torque, bit load (WOB), vibration, tilt, bearing, borehole tool orientation in three-dimensional space, and / or other parameters of the well. These measurements can be made downhole, stored in solid state memory for some time, and transferred from the device (s) to the surface. Methods for transmitting data may include, for example, encoding data in digital format and transmitting encoded data to a surface, possibly as a pressure pulse in a flushing fluid or circulation system, transmitting an audio signal through a drill string 155, electronic transmission through a wire rope or wire pipe and / or transmission in the form of an electromagnetic pulse. The MWD tools and / or other parts of the BHA 170 may store the measured values for subsequent retrieval through the wireline and / or when the BHA 170 is removed from the borehole 160.

In one embodiment, the device 100 may also include a rotary ejection preventer (BOP) 158, which uses zero pressure differential drilling or pressure control methods to drill well 160. In such an embodiment, the drilling fluid in the annular space and drilling can be supported by surface pressure with the actual desired flow rate and pressure, with possible control by the nozzle system and with the fluid and pressure stored at the wellhead, directing the flow down to the nozzle by a rotating blowout preventer 158. The device 100 may also include an annular pressure sensor 159 used to measure pressure in an annular space defined, for example, between the borehole 160 (or casing pipes) and drill string 155.

In the embodiment shown in FIG. 1, top drive 140 is used to transmit rotational movement to drill string 155. However, the present invention is also applicable to other torque transmission systems such as hydraulic power swivel, rotor, and continuous well repair rigs. tubing, downhole motor and / or conventional rotary machine.

The device 100 also includes a controller 190, used to control or assist in controlling one or more components of the device 100. For example, the controller 190 can be used to transmit operational control signals to the winches 130, top drive 140, BHA 170 and / or pump 180. Controller 190 may be an autonomous unit installed near the mast 105 and / or next to other components of the device 100. In an example embodiment of the invention, the controller 190 includes one or more systems located in the control room, nearby from device 100, such as a universal shelter, often referred to as a "change house", serving as a tool storage room, office space, communications center and wardroom. Controller 190 may be used to transmit operational control signals to winches 130, top drive 140, BHA 170, and / or pump 180 via wired or wireless transmission media, which are not shown in FIG. 1 for simplicity.

A controller 190 is also used to receive electronic signals via wired or wireless data transmission devices (not shown in FIG. 1) from a variety of sensors, including sensors in a device 100, where each sensor is used to detect a process characteristic or parameter. One such sensor is the pressure sensor 159 described above for measuring pressure in an annular space at the surface of the earth. The device 100 may include a pressure sensor 170a for measuring pressure in the annular space of the borehole, coupled or otherwise connected to the BHA 170. The pressure sensor 170a can be used to determine the pressure 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 casing pressure, borehole pressure in the casing, MWD casing pressure, or annulus in the annulus .

Note that the meaning of the word "detection" in the context of the present invention may include the detection, determination, measurement, calculation and / or other procedure for obtaining data. Similarly, the meaning of the word “detect” in the context of the present invention may include the meaning of the verb detect, determine, measure, calculate and / or otherwise obtain data.

The device 100 may additionally or alternatively include a shock or vibration sensor 170b, which is used to detect shock and / or vibration in the BHA 170. The device 100 may additionally or alternatively include a differential pressure sensor (ΔP) 172a in the hydraulic downhole motor, which is used to detect the magnitude differential pressure or differential pressure range in the circuit of one or more motors 172 BHA 170. One or more motors 172 each may represent or include a volumetric downhole an engine that uses the hydraulic power of the flushing fluid to drive the drill bit 175. This engine is also called the hydraulic downhole motor. One or more torque sensors 172b may also be included in the BHA 170 to send data to the controller 190, which determines the torque applied to the drill bit 175 by one or more motors 172.

The device 100 may further or alternatively include a downhole tool sensor 170c used to determine the current orientation of the downhole tool. The downhole tool sensor 170c may be a conventional sensor or a future developed magnetic downhole tool sensor that detects the orientation of the downhole tool with respect to the magnetic north or true north pole. Alternatively or additionally, the downhole tool sensor 170c may be a conventional sensor or a future developed gravity sensor of a downhole tool that determines the orientation of the downhole tool relative to the Earth's gravitational field. The downhole tool sensor 170c can also be, or alternatively include, a conventional or future gyro sensor. The device 100 may additionally or alternatively include a WOB 170d sensor integrated in the BHA 170 equipment and used to detect the WOB load in or near the BHA 170.

The device 100 may further or alternatively include a torque sensor 140a coupled to or otherwise connected to the top drive 140. The torque sensor 140a may alternatively be located in or associated with the BHA 170. The torque sensor 140a may be used to detect the magnitude or range of the torque of the hollow shaft 145 and / or the drill string 155 (for example, in response to the force exerted on the drill string). Top drive 140 may additionally or alternatively include a speed sensor 140b used to determine the magnitude or range of speed of the hollow shaft 145.

Top drive 140, winch 130, drill bit or tackle block, drill rope or fixed end attachment mechanism may further include a bit load sensor (WOB) 140 s or be associated with this sensor (for example, one or more sensors installed anywhere on the way of the load-lifting mechanism for determining the WOB load, which can vary from one rig to another), different from the WOB 170d sensor. A load sensor 140c can be used to determine the WOB value or range where such a determination can be made on top drive 140, winch 130, or other component of device 100.

Detection performed by the sensors described herein may be performed once, performed continuously, periodically and / or at random intervals. Parameter determination can be performed manually by an operator or another person with access to a human machine interface (HMI), or carried out automatically, for example, by entering a characteristic or parameter that satisfies a predetermined condition (for example, after a period of time, according to the schedule of drilling operations, reaching a predetermined stage, the life of the drill bit, etc.). Such sensors and / or other means of determining parameters may include one or more interfaces, which may be local to the well / drilling site or located in another, remote location with a communication network with the system.

2A is a flowchart of a method 200a according to one or more aspects of the present invention. Method 200a may be performed in conjunction with one or more components of device 100 shown in FIG. 1 during operation of device 100. For example, method 200a may be performed to orient a downhole tool during a drilling operation performed by device 100.

Method 200a includes a step 210, during which the current orientation TF _{M of the} downhole tool is measured. The orientation of the TF _M can be measured using a conventional or future magnetic tool tool that detects the orientation of the tool with respect to the magnetic north pole or true north pole. Alternatively or additionally, the orientation of the TF _M can be measured using a conventional or future developed downhole tool gravity sensor that detects the orientation of the downhole tool relative to the Earth's gravitational field. In an embodiment of the invention, the orientation of TF _M can be measured using a magnetic downhole tool sensor when the end of the wellbore is deviated less than about 7 ° from the vertical, followed by a gravity sensor measurement of the downhole tool when the end of the wellbore deviates by no more than about 7 ° from the vertical. However, gyroscopic and / or other means for determining TF _M can also be used within the scope of the present invention.

In the next step 220, the orientation of TF _{M is} compared with the desired orientation of TF _{D of the} downhole tool. If TF _{M is} sufficiently equal to TF _D , as determined at decision stage 230, method 200a is resumed and step 210 is repeated. The expression "sufficiently equal" can mean basically equal values when the difference does not exceed a few percent, or can alternatively mean a change of no more than a predetermined angle, for example, about 5 °. In addition, the repetition of method 200a may be substantially immediate, or there may be a delay period before method 200a is resumed and step 210 is repeated.

If TF _{M is} “insufficient” equal to TF _D , as determined at decision stage 230, method 200a proceeds to step 240, during which the hollow shaft is rotated by the drive system, for example, by an amount equal to the difference between TF _M and TF _D. However, in the framework of the present invention, the shaft can also be rotated by another amount of rotational adjustment performed in step 240. After step 240 is completed, method 200a is resumed and step 210 is repeated. Such a repetition may be substantially immediate, or a delay period may occur before method 200a is resumed and step 210 is repeated.

FIG. 2B is a flowchart of another embodiment of the method 200a shown in FIG. 2A, defined herein by a numeral 200b. Method 200b may be performed in conjunction with one or more components of the device 100 shown in FIG. 1 during operation of the device 100. For example, method 200b may be used to orientate a downhole tool during a drilling operation performed by device 100.

Method 200b includes steps 210, 220, 230, and 240 described above with respect to method 200a and shown in FIG. 2A. However, method 200b also includes a step 233 where the current operating parameters are measured if TF _{M is} “sufficiently equal” to TF _D , as determined at decision stage 230. Alternatively or additionally, the current operating parameters may be measured periodically or at predetermined intervals or at depending on other events. The method 200b also includes a step 236, during which the operating parameters measured in step 233 are recorded. The operating parameters recorded in step 236 can be used in future calculations of the magnitude of the rotational moment of the hollow shaft performed in step 240, and these parameters can be determined by one or several intelligent adaptive controllers, programmable logic circuits, artificial neural networks and / or other adaptive and / or “trained” controllers or data processing devices.

Each of the steps of methods 200a and 200b can be performed automatically. For example, the controller 190 shown in FIG. 1 may be used to automatically perform a downhole tool comparison at step 230 periodically, at random intervals, or otherwise. The controller 190 can also be used to automatically generate and transmit control signals directing the rotation of the hollow shaft in step 240, for example, in response to a comparison of the downhole tool performed in steps 220 and 230.

3 is a block diagram of a device 300 according to one or more aspects of the present invention. The device 300 includes a user interface 305, BHA 310 equipment, a drive system 315, a winch 320, and a controller 325. The device 300 may be implemented within the environment and / or within the device shown in Figure 1. For example, the BHA 310 equipment may be basically, like the BHA 170 equipment shown in FIG. 1, the drive system 315 can be basically similar to the top drive 140 shown in FIG. 1, the winches 320 can be basically similar to the winches 130 shown in FIG. 1, and controller 325 maybe basically explicitly similar to the controller 190 shown in Figure 1. The device 300 may also be used in the method 200a shown in Figure 2A and / or in the method 200b shown in Figure 2B, among other methods described herein or otherwise in the framework of the present invention .

User interface 305 and controller 325 may be separate components that are connected through wired or wireless communications. Alternatively, the user interface 305 and controller 325 may be components of a single system or controller 327, as shown by a dotted line in FIG. 3.

The user interface 305 includes means 330 for the user to enter one or more predetermined points of the downhole tool, and may also include means for the user to enter other specified points, limits, and other input data. The input means 330 may include a keyboard, a voice device, a dial, a keyboard, a switch, a selector disconnector, a switch, a joystick, a mouse, a database, and / or other conventional or future data input device. Such data entry means may support data entry from local and / or remote nodes. Alternatively or additionally, the data input means 330 may include means for the user to select predefined temperature values of the downhole tool or ranges, for example, through one or more drop-down menus. Downhole tool temperature data may also or alternatively be selected by controller 325 by performing one or more database lookup procedures. In general, the data input means 330 and / or other components within the scope of the present invention support the operation and / or monitoring of stations in a drilling rig section, as well as in one or more remote sections through a communication line with the system and a local area network (local area network) , global network, Internet, satellite link and / or radio, among other possible means of communication.

User interface 305 may also include a display 335 used to visually present information to the user in the form of text, graphics, or video. The display 335 can also be used by the user to enter the target values of the downhole tool in combination with the data input means 330. For example, the input tool setpoints 330 of the downhole tool may be an integral part of the display 335 or otherwise associated with it.

The BHA 310 equipment may include a MWD casing pressure sensor 340, which is used to determine the annular pressure value or pressure range in the MWD BHA 310, and may be substantially similar to the pressure sensor 170a shown in Figure 1. Data casing pressure measured by the MWD 340 casing pressure sensor can be sent as an electronic signal to controller 325 via a wired or wireless communication line.

BHA 310 equipment may also include a shock or vibration detector MWD 345, which is used to detect shock and / or vibration in the MWD BHA 310 equipment, and it can basically be similar to the shock / vibration sensor 170b shown in Figure 1. Shock data / vibrations detected through the shock or vibration sensor 345 can be sent as an electronic signal to the controller 325 via a wired or wireless communication line.

BHA 310 equipment may also include a differential pressure sensor ΔP 350 through a downhole hydraulic motor, which is used to determine a differential pressure or a differential pressure range through a hydraulic downhole motor of a BHA 310 equipment, and it can basically be similar to a differential pressure detection ΔP sensor 172a through a hydraulic downhole motor. The differential pressure sensor 350 ΔP can send an electronic signal to the controller 325 via a wired or wireless communication line. The pressure drop ΔP of the hydraulic downhole motor can be alternatively or additionally calculated, detected, or otherwise determined on the surface by calculating the difference between the surface pressure of the riser above the bottom and the pressure at the moment the drill bit contacts the bottom of the bottom and begins to rotate when drilling.

BHA 310 equipment may also include a downhole tool magnetic sensor 355 and a downhole tool gravity sensor 360, which together determine the current downhole tool and which together can basically be similar to the downhole tool sensor 170c shown in FIG. 1. The downhole tool magnetic sensor 355 can be or include a conventional or future developed downhole tool magnetic sensor that detects the orientation of the downhole tool relative to magnetic north Whether the true North Pole. The gravity sensor of the downhole tool 360 may either include a conventional or future developed gravity sensor of the downhole tool that detects the orientation of the downhole tool relative to the Earth's gravitational field. In an example embodiment of the invention, the magnetic sensor of the downhole tool 355 can detect the current downhole tool when the end of the wellbore deviates no more than about 7 ° from the vertical, and the gravity sensor of the downhole tool 360 can detect the current downhole tool when the end of the wellbore deviates by more than than approximately 7 ° from the vertical. However, other downhole tool sensors may also be used within the scope of the present invention, including non-magnetic downhole tool sensors and non-gravity tilt sensors. In any case, the orientation of the downhole tool detected by one or more downhole tool sensors (e.g., sensors 355 and / or 360) can be sent as an electronic signal to the controller 325 via a wired or wireless communication line.

BHA 310 equipment may also include a MWD 365 torque sensor, which is used to determine the amount or range of torque applied to the drill bit by the engine (s) of the BHA 310 equipment, and it can basically be similar to the torque sensor 172b shown in the figure 1. The torque data detected by the MWD 365 torque sensor can be sent as an electronic signal to the controller 325 via a wired or wireless communication line.

The BHA 310 equipment may also include a MWD WOB sensor 370, which is used to determine the magnitude or range of values for the WOB near the BHA 310 equipment, and this sensor can basically be similar to the WOB sensor 170d shown in Figure 1. The WOB data detected by the 370 sensor The MWD WOB can be sent as an electronic signal to the controller 325 via a wired or wireless communication line.

Winches 320 include a controller 390 and / or other means for supplying a drill line (such as drill line 125 shown in FIG. 1). Such an operation may include directional feed (up and down) and feed rate control. However, embodiments of the invention also include those embodiments in which drill string winches with a drill string may alternatively have a hydraulic cylinder or a gear hoist, where the drill string is moved up and down through a system other than the winch. The drill string may also consist of flexible tubing, when the movement of the drill string into and out of the well is controlled by a wellhead that captures and feeds the pipe into and out of the well. However, embodiments of the invention may include a variant of the controller 390, and the controller 390 may be used to control the feed and / or extraction of the drill string.

The drive system 315 includes a surface torque sensor 375, which is used to determine the magnitude or range of the reactive torque of the hollow shaft or drill string, similar to the torque sensor 140a shown in figure 1. The drive system 315 also includes a sensor 380 of the position of the hollow shaft, which is used to determine the magnitude or range of the rotational position of the hollow shaft, for example, relative to the true north pole or other fixed point. Surface curl data and hollow shaft positions detected by sensors 375 and 380, respectively, can be sent as an electronic signal to controller 325 via a wired or wireless communication line. The drive system 315 also includes a controller 385 and / or other means for controlling the rotational position, speed and direction of the hollow shaft or other component of the drill string connected to the drive system 315 (for example, the hollow shaft 145 shown in FIG. 1).

In an example embodiment of the invention, the drive system 315, the controller 385, and / or other component of the device 300 may include means for accounting for friction between the drill string and the borehole. For example, such a friction meter can be used to detect the location and / or amount of friction, which can then be subtracted from the actual "reactive" torque, possibly by a controller 385 and / or other control component of the device 300.

The controller 325 is configured to receive one or more of the above parameters from the user interface 305, BHA equipment 310 and / or from the drive system 315, and uses such parameters continuously, periodically or otherwise to determine the current orientation of the downhole tool. The controller 325 can also be used to generate a control signal, for example, through a smart adaptive control circuit, and to generate a control signal for the drive system 315 and / or winch 320 to adjust or maintain the orientation of the downhole tool. For example, controller 325 may execute method 202 of FIG. 2B to transmit one or more signals to drive system 315 and / or winch 320 to increase or decrease WOB load and / or reposition hollow shaft in order to precisely “control” the operation drilling.

In addition, as in the embodiment of FIG. 3, the controller 385 of the drive system 315 and / or the controller 390 of the winches 320 can be used to generate and transmit a signal to the controller 325. Therefore, the controller 385 of the drive system 315 can be used to control BHA 310 and / or winch 320 equipment to help achieve and / or maintain the desired orientation of the downhole tool. Similarly, winch controller 390 320 can be used to control BHA 310 equipment and / or drive system 315 to help achieve and / or maintain the desired orientation of the downhole tool. Alternatively or additionally, the controller 385 of the drive system 315 and the controller 390 of the winch 320 can be used for direct communication, for example, as shown by the double arrow 392 in figure 3. Therefore, the controller 385 of the drive system 315 and the controller 390 of the winch 320 can be used together to receive and / or maintaining the desired orientation of the downhole tool. Such interaction may be independent of the control provided by the controller 325 and / or BHA 310 equipment.

4A is a diagram of at least a portion of a device 400a according to one aspect of the present invention. 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 an exemplary environment in which the method 200a shown in FIG. 2A and / or the method 200b shown in FIG. figure 2B. The device 400a includes a plurality of user inputs 410 and at least one processor 420. The user inputs 410 include a maximum torque limit of the hollow shaft 410a, a maximum torque limit of the hollow shaft 410b, a maximum speed limit of the hollow shaft 410c, and a speed limit of the hollow shaft the shaft 410d to a minimum, the maximum vibration limit of the hollow shaft 410a to the maximum, the maximum vibration limit of the hollow shaft 410f to the minimum, the neutral point of vibration of the hollow shaft 410g and the downhole tool orientation input 410h. However, other or alternative user inputs 410 may be used in other embodiments of the present invention. User inputs 410 can generally be similar to user inputs 330 or other components of user connections 305 shown in FIG. 3. At least one processor 420 may form at least a portion of the controller 325 of FIG. 3 and / or the controller 385 of the drive system 315 of FIG. 3 or to be formed of at least a portion of this controller.

In the embodiment of FIG. 4A, at least one processor 420 includes a downhole tool controller 420a and a winch controller 420b, and the device 400a also includes a plurality of sensors 430 or is otherwise associated with said sensors. The plurality of sensors 430 include a bit torque sensor 430a, a hollow shaft torque sensor 430b, a hollow shaft speed sensor 430c, a hollow shaft position sensor 430d, a hydraulic downhole motor ΔP sensor 430e, and a downhole tool orientation sensor 430f. In other embodiments of the present invention, additional or alternative sensors 430 may be used. In an example embodiment of the invention, each of the plurality of sensors 430 may be located on the surface of the wellbore rather than in the bottom near the drill bit, in the BHA equipment, and / or in any tool while logging while drilling. However, in other embodiments, one or more sensors 430 may not be located on the surface. For example, in one embodiment of the invention, the hollow shaft torque sensor 430b, the hollow shaft speed sensor 430c, and the hollow shaft position sensor 430d may be surface sensors, while the drill bit torque sensor 430a, the hydraulic downhole motor sensor 430e ΔP, and the downhole tool orientation sensor 430f may be downhole sensors (e.g., MWD sensors). In addition, the individual sensors 430 may be substantially similar to the respective sensors shown in FIG. 1 or FIG. 3.

The device 400a also includes or is associated with a hollow shaft motor 440. The hollow shaft motor 440 may form at least a portion of the top drive or other drive system, for example, the top drive 140 shown in FIG. 1 and / or the drive system 315 shown in FIG. 3. The hollow shaft motor 440 receives a control signal of the hollow motor shaft, at least one processor 420, if it is also not transmitted by other components of the device 400a. The control signal of the hollow shaft motor controls the position (for example, azimuth), direction of rotation, speed of rotation and / or oscillation of the hollow shaft. The downhole tool controller 420a is used to generate a control signal for the hollow shaft motor using data received from user inputs 410 and sensors 430.

The downhole tool controller 420a can compare the actual hollow shaft torque with the maximum hollow shaft torque value obtained from the corresponding user input 410a. The actual torque of the hollow shaft can be determined using data obtained from the torque sensor of the hollow shaft 430b. For example, if the actual torque of the hollow shaft exceeds the maximum torque of the hollow shaft, then the control signal of the hollow shaft motor can restore the working value of the torque of the hollow shaft 440. In an example embodiment of the invention, the downhole tool controller 420a can be used to optimize parameters during drilling operations in connection with the actual torque of the hollow shaft, for example, increasing the actual torque of the hollow shaft to a maximum value, without exceeding the limit maximum torque of the hollow shaft.

Alternatively or additionally, the downhole tool controller 420a may compare the actual hollow shaft torque with the minimum hollow shaft torque obtained from the corresponding user input 410b. For example, if the actual hollow shaft torque deviates below the minimum limit, the control signal of the hollow shaft motor can serve as a command to increase the torque of the hollow shaft 440. In an example embodiment of the invention, the downhole tool controller 420a can be used to optimize drilling operation parameters related to the actual the torque of the hollow shaft, for example, minimizing the actual torque of the hollow shaft, not reaching the point of limitation of the torque of the hollow shaft.

Alternatively or additionally, the downhole tool controller 420a may compare the actual speed of the hollow shaft with the maximum limit limit received from the corresponding user input 410c. The actual speed of the hollow shaft can be determined using data obtained from the speed sensor of the hollow shaft 430c. For example, if the actual speed of the hollow shaft exceeds the limit value of the speed of the hollow shaft, the control signal of the hollow shaft motor can restore the normal speed of the hollow shaft 440. In an example embodiment of the invention, the downhole tool controller 420a can be used to optimize drilling operation parameters related to the actual speed of the hollow shaft shaft, in particular, increasing the actual speed of the hollow shaft, not exceeding the maximum speed limit of the hollow shaft.

Alternatively or additionally, the downhole tool controller 420a may compare the actual speed of the hollow shaft with the limit of the speed of the hollow shaft obtained from the corresponding input by the user 410d. For example, if the actual speed of the hollow shaft deviates below the limit of the speed limit of the hollow shaft, the control signal of the hollow shaft motor may increase the speed of the hollow shaft 440. In an example embodiment of the invention, the downhole tool controller 420a may be used to optimize drilling operation parameters related to the actual speed hollow shaft, for example, minimizing the actual speed of the hollow shaft, not exceeding the maximum speed limit of the hollow shaft.

Alternatively or additionally, the downhole tool controller 420a may compare the actual orientation (azimuth) of the hollow shaft with the oscillation of the hollow shaft with a maximum limit obtained from the corresponding user input 410e. The actual orientation of the hollow shaft can be determined using data obtained from the position sensor of the hollow shaft 430d. For example, if the actual orientation of the hollow shaft exceeds the oscillation of the hollow shaft with a maximum limit, then the control signal of the motor of the hollow shaft can restore the oscillations of the hollow shaft 440 within the oscillation of the hollow shaft with a maximum limit or change the parameters of the oscillation of the hollow shaft so that the actual oscillation of the hollow shaft shaft in a positive direction (for example, clockwise) does not exceed the oscillation of the hollow shaft with a maximum limit. In an embodiment of the invention, the downhole tool controller 420a can be used to optimize drilling operation parameters associated with the actual vibration of the hollow shaft, for example, by increasing the value of the actual vibration of the hollow shaft in the positive direction without exceeding the maximum vibration limit of the hollow shaft.

Alternatively or additionally, the downhole tool controller 420a may compare the actual orientation of the hollow shaft with the minimum deflection limit of the hollow shaft obtained from the corresponding user input 410f. For example, if the actual orientation of the hollow shaft deviates below the limit of oscillation of the hollow shaft, the control signal of the hollow shaft motor can direct the rotation of the hollow shaft 440 to the limits of the oscillation of the hollow shaft or change the parameters of the oscillation of the hollow shaft so that the actual hollow shaft oscillates in a negative direction (for example counterclockwise) does not exceed the limit of the oscillations of the hollow shaft to a minimum. In an example embodiment of the invention, the downhole tool controller 420a can be used to optimize drilling operation parameters associated with the actual vibration of the hollow shaft, for example, by increasing the actual value of the vibration of the hollow shaft without exceeding the vibration limit of the hollow shaft to a minimum.

Alternatively or additionally, the downhole tool controller 420 a can compare the actual neutral point of the hollow shaft oscillation with the desired neutral point hollow oscillation of the neutral point input received from the corresponding user input 410g. The actual neutral point of oscillation of the hollow shaft can be determined using data obtained from the position sensor of the hollow shaft 430d. For example, if the actual neutral point of vibration of the hollow shaft changes from the desired value of the neutral point of vibration of the hollow shaft by a predetermined value or falls outside the desired range of vibration, then the control signal of the motor of the hollow shaft can change the vibration parameters of the hollow shaft 440 in order to carry out the corresponding correction.

Alternatively or additionally, the downhole tool controller 420a may compare the actual orientation of the downhole tool with a value of the downhole tool orientation obtained from the corresponding user input 410h. The downhole tool orientation input received from user input 410h may be the only value indicating the desired downhole tool orientation. For example, if the actual orientation of the downhole tool differs from the input value of the orientation of the downhole tool by a predetermined amount, then the control signal of the hollow shaft motor can cause the hollow shaft 440 to rotate by a value corresponding to correcting the orientation of the downhole tool. However, the input value of the downhole tool orientation obtained from the user input 410h may alternatively be a range within which the desired orientation of the downhole tool would be kept. For example, if the actual orientation of the downhole tool is outside the input orientation range of the downhole tool, the control signal of the hollow shaft motor can rotate the hollow shaft 440 by the amount necessary to correct the actual orientation of the downhole tool within the input range of the downhole tool orientation. In one embodiment, the actual orientation of the downhole tool is compared with the input orientation of the downhole tool automatically, possibly based on a predetermined and / or constantly updated well plan (for example, a “well service project”), possibly taking into account the error when drilling a well during drilling .

In each of the above comparisons and / or calculations made by the downhole tool controller, the actual pressure drop ΔP of the hydraulic downhole motor and / or the actual torque of the drill bit can also be used to generate the hollow shaft drive signal. The actual differential pressure ΔP of the hydraulic downhole motor can be determined using data obtained from the hydraulic downhole motor sensor 430e ΔP and / or by measuring the pressure of the pump before the drill bit reaches the bottom of the bottom and measuring this value and the actual torque of the drill bit can be determined using data obtained from the drill bit torque sensor 430a. Alternatively, the actual drill bit torque can be calculated using the differential pressure (ΔP) data obtained from the hydraulic downhole motor sensor 430e, because the actual drill bit torque and the actual ΔP of the hydraulic bottom hole motor are proportional.

One example is in which the actual ΔP of the hydraulic downhole motor and / or the actual torque of the drill bit can be used when the actual orientation of the downhole tool cannot be relied upon to get accurate or get fast enough. For example, this may occur during loss of circulation drilling or in other examples in which the driller no longer receives data from the orientation sensor of the downhole tool 430f. In such cases, the actual torque of the drill bit and / or the actual ΔP of the hydraulic downhole motor can be used to determine the actual orientation of the downhole tool. For example, if all other drilling parameters remain the same, a change in the torque of the actual drill bit and / or the actual hydraulic downhole motor ΔP may indicate a proportional rotation of the orientation of the downhole tool in the drilling direction or in the opposite direction. For example, an increasing bit torque or ΔP may indicate that the rotation of the downhole tool is changing in the opposite direction to the drilling direction, while a decreasing bit torque or falling ΔP may indicate that the downhole tool is rotating in the direction of drilling. Thus, the data obtained from the drill bit torque sensor 430a and / or from the hydraulic downhole motor sensor 430e ΔP can be used by the downhole tool controller 420 to generate a hollow shaft motor signal so that the hollow shaft can be rotated with correction or take into account any rotation of the drill bit, which is indicated by a change in the actual torque of the drill bit and / or the actual ΔP of the hydraulic downhole motor.

In addition, under certain operating conditions, data obtained by the downhole tool controller 420 from the downhole tool orientation sensor 430f may lag behind the actual orientation of the downhole tool. For example, the tool orientation sensor 430f may only periodically determine the actual orientation of the tool, or it may take a significant amount of time to transmit data from the tool to the surface. Typically, in prior art systems, such a delay is 30 seconds or more. Therefore, in some applications of the present invention, it may be more accurate or otherwise more beneficial for the downhole tool controller 420a to use the actual torque and pressure data obtained from the drill bit torque sensor 430a and the hydraulic downhole motor sensor 430e ΔP in addition to using the actual downhole motor downhole tool data obtained from an orientation tool 430f of the downhole tool.

As shown in FIG. 4A, user inputs 410 of device 400a may also include WOB 410i calibration, differential pressure calibration ΔP 410j of the hydraulic downhole motor, 410k ROP input, WOB input 410l, hydraulic downhole motor input 410m, and load limiter on hook 410n. At the same time, at least one processor 420 may also include a winch controller 420b. Many sensors 430 of device 400a may also include a hook load sensor 430g, a mud pump pressure sensor 430h, a bit depth sensor 430i, a casing pressure sensor 430j, and a ROP 430k sensor. Each of the plurality of sensors 430 may be located on the surface of the wellbore, in the bottom of the well (e.g., MWD), or in another space.

As described above, the downhole tool controller 420a is used to generate a hollow shaft control signal using data received from user inputs 410 and sensors 430, and then generates a control signal for the hollow shaft of the actuator 440, thereby controlling the orientation of the downhole tool by adjusting orientation and rotation speed of the hollow shaft. Thus, the control signal of the hollow shaft motor is used to control (at least partially) the orientation of the hollow shaft (for example, azimuth) as well as the speed and direction of rotation of the hollow shaft (if used).

The winch controller 420b is used to generate a control signal for the winch drum (or brake), also using data received from user inputs 410 and sensors 430. Then, the winch controller 420b provides a control signal to drive the winch 450, thereby controlling the feed direction and speed winches. The drive of the winches 450 may form at least part, or may be formed, at least part of the winch 130 shown in figure 1, and / or winch 320, shown in figure 3. The scope of the present invention also includes other means of regulation the vertical position of the drill string. For example, the winch controller 420b may be a winch controller, and the winch drive 450 may include means for raising the drill string instead of or in addition to a winch system (eg, rack and pinion hoist).

The device 400a also includes a comparator 420c, which compares the current data of the load on the hook with the WOB calibration to obtain the value of the current load on the bit. The current load data on the hook is transmitted by the load sensor on the hook 430g, and the WOB load is obtained from the corresponding user input 410i.

The winch controller 420b compares the current bit load with input bit load data. The current load on the bit is received from the comparator 420c, and input data on the load on the bit is obtained from the corresponding user input 410l. The bit load input received from user input 410l may be the only value indicating the desired load. For example, if the actual load on the bit differs from the input load by a predetermined value, then the control signal of the winch drive can initiate the movement of the winch rope 450 up or down to obtain a value corresponding to the required WOB correction. However, the bit load input received from user input 410l may alternatively be a range within which it is desirable to maintain the bit load. For example, if the actual load on the bit is outside the input range of the load on the bit, then the control signal of the winch drive can initiate the movement of the winch rope 450 up or down by the amount necessary to correct the actual load on the bit within the input range of the load on the bit. In an embodiment of the invention, the winch controller 420b may be used to optimize the parameters of the drilling operation associated with the WOB, for example, by increasing the actual load on the bit without exceeding the input WOB or range.

The device 400a also includes a comparator 420d, which compares the pressure of the mud pump with a calibration ΔP of the hydraulic downhole motor to form an "uncorrected" differential pressure ΔP of the hydraulic downhole motor. The mud pump pressure data is received from the mud pump pressure sensor 430h, and the calibration ΔP of the hydraulic downhole motor is received from the corresponding user input 410j.

The device 400a also includes a comparator 420e that uses the uncorrected hydraulic downhole motor data ΔP along with bit depth and casing pressure data to form a "corrected" or current differential pressure ΔP of the hydraulic downhole motor. Bit depth data is received from the bit depth sensor 430i, and casing pressure data is received from the casing pressure sensor 430j. The casing pressure sensor 430j may be a casing sensor, such as the sensor 159 shown in FIG. 1, and / or a downhole casing pressure sensor, for example, the 170A sensor shown in FIG. 1, and may detect annular pressure between the casing or borehole diameter and the drill string component.

The winch controller 420b compares the current differential pressure ΔP of the downhole motor with the input ΔP of the downhole motor. The current differential pressure ΔP of the hydraulic downhole motor is received from the comparator 420e, and the input data of the differential pressure ΔP of the hydraulic downhole motor is received from the corresponding user input 410m. The differential pressure input ΔP of the downhole motor obtained from the user input 410m may be the only value indicating the desired ΔP of the downhole motor. For example, if the current differential pressure ΔР of the hydraulic downhole motor differs from ΔР of the hydraulic downhole motor by a predetermined value, the control signal of the winch drive can initiate the movement of the winch rope 450 up or down by the value corresponding to the necessary correction ΔР. However, the input ΔP of the downhole motor obtained from the user input 410m may alternatively be a range within which it is desirable to maintain the ΔP of the downhole motor. For example, if the current differential pressure ΔP of the hydraulic downhole motor is outside this range, then the control signal of the winch drive can initiate the winch cable 450 moving up or down by the amount necessary to restore the current differential pressure ΔР within the input range. In an example embodiment of the invention, the winch controller 420b can be used to optimize drilling operation parameters associated with ΔP of the hydraulic downhole motor, for example, increasing ΔP of the hydraulic downhole motor without exceeding an input value or range.

The winch controller 420b can also compare actual ROP data with ROP input data. Actual ROP data is received from the ROP 430k sensor,

and ROP input is received from the corresponding 410k user input. The ROP input received from user input 410k may be the only value indicating the desired ROP value. For example, if the actual ROP speed differs from the input ROP by a predetermined value, then the control signal of the winch drive can initiate a movement of the winch rope 450 up or down by an amount corresponding to the necessary ROP correction. However, the ROP input received from user input 410k may alternatively be a range within which it is desirable to maintain a mechanical penetration rate. For example, if the actual ROP speed is outside the ROP input range, then the control signal of the winch drive can initiate a winch rope 450 moving up or down by the amount necessary to restore the actual ROP within the ROP input range. In an example embodiment of the invention, the winch controller 420b may be used to optimize the parameters of the drilling operation associated with the ROP, for example, increasing the actual ROP without exceeding the input ROP value or range.

The winch controller 420b may also use data received from the downhole tool controller 420a when a winch control signal is generated. Changes in the actual load on the bit can cause changes in the actual torque of the bit, the actual pressure drop ΔP of the hydraulic downhole motor, and the actual orientation of the downhole tool. For example, as the weight applied to the drill bit increases, the actual orientation of the downhole tool may rotate against the direction of drilling, and the actual torque of the drill bit and the pressure of the hydraulic downhole motor may increase proportionally. Therefore, the downhole tool controller 420a can provide data to the winch controller 420b indicating whether the winch drill wire should be fed up or down, and possibly the necessary feed rate, to bring the actual orientation of the downhole tool in accordance with the input orientation value or range provided by the corresponding input user 410h. In an example embodiment of the invention, the winch controller 420b may also provide data to the downhole tool controller 420a to rotate the hollow shaft clockwise or counterclockwise by an amount and / or at a speed sufficient to compensate for the increased or decreased WOB, bit depth or pressure in casing string.

As shown in FIG. 4A, user inputs 410 may also include traction limit input 410n. When the control signal of the winches is generated, the winch controller 420b can be used as a guarantee that the winches will not exceed the limit value of the pulling force by the amount received from the user input 410n. The limit value of the pulling force is also known as the load limiter on the hook and may depend on the specific configuration of the rig among other parameters.

In an example embodiment of the invention, the winch controller 420b may also provide data to the downhole tool controller 420a to initiate the downhole tool controller 420a to provide a signal to rotate the hollow shaft, for example, in magnitude, direction and / or speed sufficient to compensate for the traction limit reached. , or exceeding this limit. The downhole tool controller 420a may also provide data transmission to the winch controller 420b to force the winch controller 420b

increase or decrease the WOB, or adjust the drill string feed, for example, by an amount, direction, and / or speed sufficient to adjust the orientation of the downhole tool accordingly.

Figure 4B is a diagram of at least part of another embodiment of a device 400a, defined herein by numeral 400b. Like device 400a, device 400b is an exemplary embodiment of the device 100 shown in FIG. 1 and / or the device 300 shown in FIG. 3 and an exemplary environment in which the method 200a shown in FIG. 2A and / or the method can be implemented 200b shown in FIG. 2B.

Like device 400a, device 400b includes multiple user inputs 410 and at least one processor 420. At least one processor 420 includes a downhole tool controller 420a and a winch controller 420b described above, as well as a mud pump controller 420c. The device 400b also includes, or is otherwise connected to, a plurality of sensors 430, a hollow shaft drive 440, and a winch drive 450, similar to the device 400a. The device 400b also includes, or is otherwise connected to, a mud pump 460 that is used to operate the mud pump, such as the mud pump 180 shown in FIG. 1. In the embodiment of the invention, in the apparatus 400b shown in FIG. 4B, each of the plurality of sensors 430 may be located on the surface of the wellbore, in the bottom of the well (for example, as an element of MWD equipment), or in another space.

The mud pump controller 420c is used to generate a mud pump drive control signal using data received from a user input 410 and a sensor 430. Then, the mud pump controller 420c provides a mud pump drive signal 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 in part, of a controller 190 of FIG. 1 and / or a controller 325 of FIG. 3.

As described above, the pressure drop ΔP of the hydraulic downhole motor may be proportional or otherwise related to the orientation of the downhole tool, 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 ΔP value of the hydraulic downhole motor to help ensure the actual orientation of the downhole tool in accordance with the input orientation value of the downhole tool or the range set by the corresponding user input. Such an operation of the mud pump controller 420c may be performed independently of the operation of the downhole tool controller 420a and the winch controller 420b. Alternatively, as shown by the double arrows 462 in Figure 4B, the operation of the mud pump controller 420c to set the desired orientation of the downhole tool may be performed in conjunction with the downhole tool controller 420a and the winch controller 420b.

The controllers 420a, 420b, and 420c shown in FIGS. 4A and 4B may each either include intelligent or modelless adaptive controllers, such as those supplied by CyberSift, General Cybernation Group, Inc. All controllers 420a, 420b, and 420c can also be installed or independently implemented on any conventional or future computing device, such as one or more personal computers or servers, portable devices, PLC systems, and / or mainframes.

5A is a flowchart of a method 500a according to one or more aspects of the present invention. Method 500a may be implemented in conjunction with one or more components of the device 100 shown in FIG. 1 during operation of device 100. For example, method 500a may be performed to optimize drilling efficiency during a drilling operation performed by device 100.

Method 500a includes a step 502, during which the parameters for calculating the mechanical specific energy (MSE) are determined, collected, or otherwise obtained. These parameters may be referred to herein as MSE parameters. MSE parameters include static and dynamic parameters. Thus, some MSE parameters change mainly continuously. These MSE dynamic parameters include bit load (WOB), bit speed (RPM), drill string torque (TOR), and drill bit mechanical penetration rate (ROP) through the rock. Other MSE parameters rarely change, for example, when lifting a column from a well, when meeting a new type of rock, and when replacing a drill bit, among other events. These MSE static parameters include Maximum Effective Rate (MER) and Drill Bit Diameter (DIA).

MSE parameters can be obtained mainly or completely automatically without using user input. For example, during the first iteration of the steps of method 500a, the static parameters of the MSE can be recovered through an automatic database query. Therefore, during subsequent iterations, the static parameters of the MSE may not need to be searched again, for example, where the type of drill bit or formation data has not changed from the previous repetition of method 500a. Therefore, the execution of step 502, in many iterations, may require only the detection of dynamic parameters of the MSE. Dynamic parameter detection of the MSE can be performed in conjunction with a variety of sensors, such as the sensors shown in figures 1, 3, 4A and / or 4B.

Subsequent step 504 in method 500a involves calculating the MSE. In an embodiment of the invention, the MSE is calculated by the following formula:

MSE = MER × [(4 × WOB) / (n × DIA ² ) + (480 × RPM × TOR) / (ROP × DIA ² )]

Where:

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

MER = mechanical recoil (coefficient);

WOB = Chisel Load (lbs);

DIA = bit diameter (inches);

RPM = bit speed (RPM);

TOR = drill string torque (foot-pounds);

ROP = rate of penetration (feet per hour).

MER may also be referred to as drill bit efficiency. In an embodiment of the invention, the MER is 0.35. However, the MER may vary based on one or more different conditions, such as the type of drill bit, type of rock, and / or other factors.

Method 500a also includes a decision step 506, during which the MSE calculated during the previous step 504 is compared with the ideal MSE. The ideal MSE used for comparison at decision stage 506 may be the only value, such as 100%. Alternatively, the ideal MSE used for comparison at decision stage 506 may be a target range of values, for example, 90-100%. Alternatively, an ideal MSE may be a range of values obtained from a first analysis of a drilled formation, which consists of various rocks that have passed in the current operation.

If it is determined in step 506 that the MSE calculated in step 504 is equal to the ideal MSE, or falls within the ideal range of MSE, method 500a may be repeated again in step 502. However, if it is determined in step 506 that the calculated MSE is not equal to the ideal MSE , or does not fall within the ideal MSE range, additional step 508 is performed. At step 508, one or more operating parameters are configured with the intention of bringing the MSE closer to the ideal MSE or within the ideal MSE range. For example, in FIGS. 1 and 5A, all steps 508 performed together may include increasing or decreasing WOB, RPM, and / or TOR, transmitting a control signal from controller 190 to top drive 140 and / or to winch 130 to change rotation speed, TOR, and / or WOB. After step 508 is completed, method 500a can be resumed by repeating step 502.

Each of the steps of method 500a can be performed automatically. In particular, the automated determination of MSE dynamic parameters and the search for a static MSE parameter database have already been described above with respect to step 502. The controller 190 of FIG. 1 (and the other components described here) can be used to automatically calculate MSE in step 504, and can also used to perform automatic MSE comparisons at the decision stage 506, where MSE computation and comparison can be performed periodically, at random intervals, or otherwise. The controller can also be used to automatically generate and transmit control signals in step 508, for example, in response to an MSE comparison in step 506.

5B is a block diagram of a device 590 according to one or more aspects of the present invention. The device 590 includes a user interface 592, a winch 594, a drive system 596, and a controller 598. The device 590 may be implemented within the environment and / or device shown in Figures 1, 3, 4A, and / or 4B. For example, the winches 594 can be basically similar to the winches 130 shown in FIG. 1, the drive system 596 can basically be similar to the top drive 140 shown in FIG. 1 and / or the controller 598 can basically be similar the controller 190 shown in figure 1. The device 590 can also be used when performing the method 200a shown in figure 2A, the method 200b shown in figure 2B, and / or the method 500a shown in figure 5A.

User interface 592 and controller 598 may be separate components that are connected through wired or wireless communications. However, alternatively, the user interface 592 and controller 598 may be separate components of the same system 599, as shown in FIG. 5B.

User interface 592 includes means 592a for user input of one or more predetermined performance data (e.g., MER), values and / or ranges, and means 592b for user input of one or more predetermined drill bit diameters (e.g., DIA). Each of the data input means 592a and 592b may include a keyboard, voice recognition device, dial, keyboard, switch, joystick, mouse, database (for example, with deviation information) and / or other conventional or future data input device. Such data input means may support data input from local and / or remote terminals. Alternatively or additionally, the data input means 592a and / or 592b may include means for the user to select predetermined MER values and DIA values or ranges, for example, using one or more drop-down menus. MER and DIA data can also be selected by the 598 controller through one or more database lookups. In general, data input means and / or other components within the framework of the present invention can support system operations during execution and / or control from stations on a rig site, also from one or more remote terminals with a communication line to the system, network, local area network (LAN), regional area network (WAN) wide area network, Internet and / or radio among other means.

User interface 592 may also include a display 592c for visually presenting information to a user in text, graphic, or video format. Display 592c may also be used by the user to enter MER and DIA data in combination with data input means 592a and 592b. For example, data input means 592a and 592b about predetermined productivity and drill bit diameter may be an integral part of display 592c or devices connected thereto.

Winches 594 include an ROP sensor 594a, which is used to determine the magnitude or range of the ROP and basically can be similar to the ROP sensor 130a shown in Figure 1. The ROP data detected by the ROP sensor 594a can be sent as an electronic signal to the controller 598 via wired or wireless communication line. Winches 594 also include a control circuit 594b and / or other means for controlling the feed and / or retrieval of a drill wire (for example, drill wire 125 shown in FIG. 1).

The drive system 596 includes a torque sensor 596a, which is used to determine the magnitude or range of the reactive twisting of the drill string (eg, TOR), much like the torque sensor 140a of the drill string 155 shown in Figure 1. The drive system 596 also includes bit rotation sensor 596b, which is used to determine the magnitude or range of the rotation frequency of the drill bit in the borehole (for example, in revolutions per minute), almost the same as the rotation speed sensor 140b, drill bit 175 in the borehole 160 shown in FIG. 1. The drive system 596 also includes a load sensor 596c that is used to determine the magnitude or range of the WOB, much like the load sensor 140c shown in FIG. 1. Alternatively or additionally, the load sensor 596c may be located separately from the drive system 596 or in another component, as shown in figure 5B, or in another space. The drill string twist, bit speed, and bit load detected by sensors 596a, 596b, and 596c, respectively, can be sent as an electronic signal to controller 598 via a wired or wireless communication line. The drive system 596 also includes a control circuit 596d and / or other means for controlling the coordinates, speed and direction of rotation of the hollow shaft or other component of the drill string associated with the drive system 596 (for example, the hollow shaft 145 shown in figure 1). The control circuit 596d and / or other component of the drive system 596 may also include means for controlling the downhole hydraulic downhole motor (s). Thus, an RPM within the scope of the present invention may include mud pump flow data converted to an RPM of a downhole hydraulic motor that can be added to the RPM of the drill string to determine the total RPM of the drill bit.

The controller 598 is used to receive the specified MSE parameters from the user interface 592, the winch 594, and the drive system 596 and uses the MSE parameters continuously, periodically, or otherwise to calculate the MSE. Further, the controller 598 is used to signal the winches 594 and / or the drive system 596 based on the calculated MSE. For example, the controller 598 may execute the method 200a shown in FIG. 2A and / or the method 200b shown in FIG. 2B and thus generate one or more signals for the winches 594 and / or the drive system 596 to increase or decrease the WOB and / or bit speed to optimize drilling efficiency (based on MSE).

5C is a flowchart of a method 500b used to optimize a drilling operation based on online calculation of MSE energy according to one or more aspects of the present invention. Method 500b can be performed using the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, and / or the device 590 shown in FIG. 5B. Method 500b can also be performed in conjunction with the implementation of method 200a shown in FIG. 2A, method 200b shown in FIG. 2B, and / or method 500a shown in FIG. 5A. The method 500b shown in FIG. 5C may include or form at least part of the method 500a shown in FIG. 5A.

In step 512 of method 500b, a base MSE is determined to optimize performance drilling based on MSE by modifying the WOB. Since the base MSE determined in step 512 will be used for optimization by modifying the WOB, the MSE _BLWOB symbol will be used _here .

In the next step 514, the WOB parameter is changed. Such a change may include either an increase or decrease in WOB. Increasing or decreasing the WOB in step 514 may be performed within some predetermined WOB limits. For example, the change in WOB should not deviate by more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside of the predetermined WOB limits.

The WOB parameter can be manually changed by the operator, or the WOB can be automatically changed by signals transmitted by the controller, control system, and / or other component of the rig and the corresponding device. As described above, such signals may be transmitted via a remote control system from another terminal.

Then, at step 516, drilling continues with a modified WOB for a predetermined drilling time interval ΔWOB. The ΔWOB drilling interval may be a predetermined period of time, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the time interval ΔWOB may be a predetermined penetration depth. For example, step 516 may include continuing the drilling operation with the modified WOB until the existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The time interval ΔWOB may also include a time component and a depth component. For example, the ΔWOB time interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔWOB time interval may include drilling until the wellbore is extended twenty feet, but over a period of more than ninety minutes. Of course, the aforementioned time and depth values in the ΔWOB interval are merely examples, and many other values may also be included in the scope of the present invention.

After continuing the drilling operation in the ΔWOB interval with the changed WOB parameter, step 518 is performed to determine the MSE _ΔWOB resulting from working with the modified WOB parameter in the ΔWOB interval. In a subsequent decision step 520, the modified MSE _{ΔWOB is} compared with the base MSE _BLWOB . If the modified MSE _{ΔWOB is} more desirable with respect to the MSE _BLWOB , method 500b proceeds to step 522. However, if the modified MSE _{ΔWOB is} not desired with respect to the MSE _BLWOB , method 500b proceeds to step 524, in which the WOB will be restored to its previous value before it is executed step 514, and the method proceeds to step 522.

Determination at the decision-making stage 520 can be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The definition may comprise detecting that an MSE _{ΔWOB value is} desired if it is substantially equal to and / or less than the MSE _BLWOB . However, additional or alternative factors may also play a role in the determination made at block 520.

In step 522 of method 500b, a baseline MSE is determined to optimize MSE-based drilling performance by varying bit speed and RPM. Since the base MSE determined in step 522 will be used for optimization by changing the rotational speed (RPM), the symbol MSE _BLRPM will be used _here .

In the next step 526, the RPM is changed. Such a change may include an increase or decrease in RPM. An increase or decrease in RPM in step 526 can be performed within some predetermined RPM limits. For example, the change in RPM can be no more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside predetermined limits.

The RPM parameter can be changed manually by the operator, or the RPM can be changed automatically by signals transmitted by the controller, control system and / or other component of the rig and the corresponding device.

Then, at step 528, drilling continues at a modified RPM for a predetermined drilling time interval ΔRPM. The ΔRPM interval may be a predetermined time period, such as five minutes, ten minutes, thirty minutes, or some other time period. Alternatively, the ΔRPM interval may be a predetermined penetration depth. For example, step 528 may comprise a continuation of a drilling operation with a modified RPM parameter until the existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔRPM interval may include drilling until the wellbore is extended twenty feet, but over a period of no more than ninety minutes. Of course, the above time and depth values for the ΔRPM interval are merely examples, and the scope of the present invention includes many other values.

After continuing the drilling operation for a certain time ΔRPM with the changed parameter RPM 530, the step of determining the MSE _ΔRPM obtained as a result of working with the changed parameter RPM during the ΔRPM interval is performed. In a subsequent decision step 532, the changed MSE _{ΔRPM is} compared with the base MSE _BLRPM . If the modified MSE _{ΔRPM is} more desirable than the MSE _BLRPM , method 500b returns to step 512. However, if the modified MSE _{ΔRPM is} less desirable than the MSE _BLRPM , method 500b proceeds to step 534, where the RPM is restored to its previous value before it step 526 is completed, and the method proceeds to step 512.

Determination at the decision-making stage 532 can be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The definition may comprise detecting the desirability of using MSE _ΔRPM if it is substantially equal to and / or less than MSE _BLRPM . However, additional or alternative factors may also play an important role in the determination made in step 532.

In addition, after performing steps 532 and / or 534, the method 500b may immediately return to step 512 for subsequent repetition. For example, a subsequent repetition of method 500b may be delayed by a predetermined time or depth of penetration. Alternatively, method 500b may end after performing steps 532 and / or 534.

5D is a flowchart of a method 500c for optimizing a drilling operation based on real-time MSE calculation according to one or more objects of the present invention. Method 500c can be performed using the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, and / or the device 590 shown in FIG. 5B. Method 500c can also be performed in conjunction with method 200a shown in FIG. 2A, method 200b shown in FIG. 2B, method 500a shown in FIG. 5A, and / or method 500b shown in FIG. 5C. The method 500c shown in FIG. 5D may include or form at least a portion of the method 500a shown in FIG. 5A and / or the method 500b shown in FIG. 5C.

In step 540 of the method 500c, the baseline MSE is determined to optimize the efficiency of the MSE-based drilling by reducing WOB. Since the underlying MSE,

determined in step 540 will be used for optimization by reducing WOB, the symbol MSE _BL-WOB will be used here.

In the next step 542, the WOB parameter decreases. The decrease in WOB in step 542 may be within some predetermined limits of the WOB. For example, a decrease in WOB may be in the range of not more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside of the predetermined WOB limits. The WOB parameter can be manually reduced by the operator, or the WOB parameter can be automatically reduced by signals transmitted by the controller, control system and / or other component of the rig and the corresponding device.

Then, at step 544, drilling continues with a reduced WOB load for a predetermined time interval ΔWOB. Time interval ΔWOB

may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the time interval ΔWOB may be a predetermined penetration depth. For example, step 544 may include drilling continued with a reduced WOB until the existing wellbore is extended five feet, ten feet, fifty feet or some other depth. The time interval ΔWOB may also include components of time and depth. For example, the ΔWOB time interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔWOB time interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes. Of course, the above time and depth values for the ΔWOB time interval are merely examples, and many other values are also within the scope of the present invention.

After continuing the drilling operation in the ΔWOB interval with the reduced WOB load, step 546 is performed to determine the MSE _-ΔWOB resulting from the reduced WOB load in the ΔWOB interval. In a subsequent decision step 548, the reduced MSE _{-ΔWOB is} compared to the base MSE _BL-WOB . If the reduced MSE _{-ΔWOB is} more desirable than the MSE _BL-WOB , the method 500c proceeds to step 552. However, if the reduced MSE _{-ΔWOB is} not more desirable than the MSE _BL-WOB , the method 500c proceeds to step 550, where the WOB is restored to its the previous value before step 542 is completed, and the method proceeds to step 552.

Determination at the decision-making stage 548 can be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The definition may comprise detecting the desired value of MSE _-ΔWOB if it is substantially equal to and / or less than MSE _BL-WOB . However, additional or alternative factors may also play a role in the determination performed at step 548.

In step 552 of the method 500c, a baseline MSE is determined to optimize MSE-based drilling efficiency by increasing WOB. Since the base MSE determined in step 552 will be used for optimization with increasing WOB load, the designation MSE _{BL + WOB} will be used here.

In the next step 554, the WOB parameter is increased. An increase in WOB in step 554 may be performed within some predetermined WOB limits. For example, an increase in WOB may be in the range of not more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside of the predetermined WOB limits. The WOB parameter can be manually increased by the operator, or the WOB can be automatically increased by the signals transmitted by the controller, control system and / or other component of the rig and the corresponding device.

Then, at step 556, drilling continues with an increased WOB value for a predetermined drilling interval + ΔWOB. The time interval + ΔWOB may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the time interval + ΔWOB may be a predetermined penetration depth. For example, step 556 may include drilling continued with an increased WOB value until the existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The time interval + ΔWOB may also include components of time and depth. For example, the time span + ΔWOB may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the time interval + ΔWOB may include drilling until the wellbore is extended twenty feet, but over a period of no more than ninety minutes.

After continuing the drilling operation during the drilling interval + ΔWOB with the increased WOB value, step 558 is performed to determine the MSE _{+ ΔWOB} resulting from working with the increased WOB value during the drilling interval + ΔWOB. In the subsequent decision making phase 560 amended

MSE _{+ ΔWOB is} compared with the base MSE _{BL + WOB} . If the modified MSE _{+ ΔWOB is} more desirable than the MSE _{BL + WOB} , the method 500c proceeds to step 564. However, if the modified MSE _{+ ΔWOB is} not more desirable than the MSE _{BL + WOB} , the method 500c proceeds to step 562, where the WOB is restored to its the previous value before step 554 is completed, and the method proceeds to step 564.

Determination at the decision-making stage 560 may be performed manually by an operator or automatically by a controller, control system and / or other component of the rig and the corresponding device. The definition may comprise detecting MSE _{+ ΔWOB} as a desired value if it is substantially equal to and / or less than MSE _{BL + WOB} . However, additional or alternative factors may also play a role in the determination performed at block 560.

At step 564 of the method 500c, the base MSE is determined to optimize the drilling efficiency based on the MSE by reducing the RPM bit speed. Since the base MSE determined in step 564 will be used for optimization by reducing RPM, the designation MSE _BL-RPM will be used here.

In the next step, 566 decreases RPM. The reduction in RPM in step 566 may be performed within some predetermined RPM limits. For example, a decrease in RPM may be in the range of not more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside such RPM limits. RPM can be manually reduced by the operator, or RPM can be automatically reduced by signals transmitted by the controller, control system and / or other component of the rig and associated device.

Then, at step 568, drilling continues with a reduced RPM frequency 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 penetration depth. For example, step 568 may include drilling continued with a reduced RPM until the existing wellbore is extended five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔRPM interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes.

After continuing the drilling operation during the ΔRPM interval with reduced RPM, step 570 is performed to determine the MSE _-ΔRPM resulting from operating at a reduced RPM frequency during the ΔRPM interval. In a subsequent decision step 572, the reduced MSE _{-ΔRPM is} compared with the baseline MSE _BL-RPM . If the modified MSE _{-ΔRPM is} more desirable than the MSE _BL-RPM , the method 500c proceeds to step 576. However, if the modified MSE _{-ΔRPM is} not more desirable than the MSE _BL-RPM , the method 500c proceeds to step 574, where the RPM is restored to its the previous value before step 566 is completed, and the method proceeds to step 576.

Determination at the decision-making stage 572 may be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The definition may comprise detecting MSE _-ΔRPM as a desired value if it is substantially equal to and / or less than MSE _BL-RPM . However, additional or alternative factors may also play a role in the determination performed at step 572.

At step 576 of the method 500c, the base MSE is determined to optimize the drilling efficiency based on the MSE by increasing the RPM bit speed. Since the base MSE determined in step 576 will be used for optimization by increasing the RPM, here we will use the notation

MSE _{BL + RPM} .

In a next step 578, the RPM frequency is increased. An increase in RPM in step 578 may be performed within some predetermined RPM limits. For example, an increase in RPM may be within no more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside such RPM limits. The RPM frequency can be manually increased by the operator, or the RPM can be automatically increased by the signals transmitted by the controller, control system and / or other component of the rig and associated device.

Then, at step 580, drilling continues at an increased RPM 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 penetration depth. For example, step 580 may include drilling continued at an increased RPM until an existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔRPM interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes.

After continuing the drilling operation during the ΔRPM interval with the increased RPM, step 582 is performed to determine the MSE _{+ ΔRPM} resulting from the operation with the increased RPM in the ΔRPM interval. In a subsequent decision step 584, the increased MSE _{+ ΔRPM is} compared to the base MSE _{BL + RPM} . If the modified MSE _{+ ΔRPM is} more desirable than the MSE _{BL + RPM} , the method 500c proceeds to step 588. However, if the modified

MSE _{+ ΔRPM is} not more desirable with respect to MSE _{BL + RPM} , method 500c proceeds to step 586, where the RPM is restored to its previous value before step 578 is completed, and the method proceeds to step 588.

Determination at the decision-making stage 584 can be performed manually by an operator or automatically by a controller, control system and / or other component of the rig and the corresponding device. The definition may comprise detecting MSE _{+ ΔRPM} as a desired value if it is substantially equal to and / or less than MSE _{BL + RPM} . However, additional or alternative factors may also play a role in the determination performed at step 584.

Step 588 comprises waiting for a predetermined period or interval of drilling depth before repeating method 500c by returning to step 540. However, in one embodiment, this interval may be so small that it is 0 seconds or 0 feet, and the method returns to step 540, mainly immediately after performing steps 584 and / or 586. Alternatively, method 500c may not need to be repeated, and method 500c may generally end after performing steps 584 and / or 586.

In addition, the drilling intervals -ΔWOB, + ΔWOB, -ΔRPM and + ΔRPM can be basically identical within a single repetition of the method 500 s. Alternatively, one or more intervals may vary in duration or depth relative to other intervals. Similarly, the amount by which the WOB decreases and increases in steps 542 and 554 can basically be identical or can change relative to each other within a single repetition of method 500c. The values by which the RPM decreases and increases in steps 566 and 578 can basically be identical or can vary relative to each other within a single repetition of method 500c. WOB and RPM may also change or remain the same during subsequent repetitions of method 500c.

As described above, one or more of the objectives of the present invention can be achieved with a drilling or control operation based on MSE. However, one or more objectives of the present invention can additionally or alternatively be achieved with a ΔT-based drilling or control operation. Thus, as described above, during the drilling operation, torque is transmitted from the top drive or other rotary drive to the drill string. The torque required to drive the drill bit can be referred to as bit torque (TOB), and can be checked using a sensor, such as torque sensor 140a shown in FIG. 1, torque sensor 355 shown in FIG. 3, one or several sensors 430 shown in figures 4A and 4B, a torque sensor 596a shown in figure 5B, and / or one or more devices that respond to the torque of the VNA equipment.

During drilling, the drill string undergoes various types of vibration, including axial (longitudinal) vibrations, bending (lateral vibrations) and torsional (rotational) vibrations. Torsional vibrations are caused by non-linear interactions between the drill bit, drill string and borehole. As described above, such torsional vibration can include spasmodic vibration (SSA), characterized by alternating stops (during which the BHA equipment “sticks” to the wellbore) and the operation of the BHA equipment at a high angular velocity (during which the BHA equipment “slides” relative to the barrel wells).

Sudden motion of VNA equipment causes changes in TOV or ΔT in real time. This ΔT interval can be used to generate an abrupt motion alarm according to one or more objects of the present invention. For example, ΔТ or an alarm parameter can be visually indicated by a “stop signal” indicator, where green light can indicate an acceptable operating mode (for example, alarm parameter 0-15), amber light can indicate an abrupt movement (for example, an emergency parameter 16-25), and a red light may indicate an abrupt movement (for example, an alarm parameter above 25). However, these exemplary thresholds may be adjusted during operation, as they may vary depending on drilling conditions. ΔT or an alarm parameter can alternatively or additionally be shown graphically (for example, displaying current and historical data), in the form of an audio message (for example, through a speaker) and / or through the display of a measuring device or meter. Combinations of these display options are also included in the scope of the present invention. For example, the “stop signal” indicator described above can continuously indicate an alarm parameter regardless of its value, and an audible alarm can be turned on if the alarm parameter exceeds a predetermined value (for example, 25).

A drilling operation controller or other device of the present invention may perform one or more drilling control functions based on ΔT or alarm parameters, as described above. For example, the controller 190 shown in FIG. 1, the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A or 4B, and / or the controller 598 shown in FIG. 5B can be used to automatically control the RPM (RPM) drill string with pulse increased or decreased RPM (e.g. +/- 5 RPM) to break the harmonic of the spasmodic vibration before or after detecting spasmodic motion, and then return to normal RPM. The controller can be used to automatically increase or decrease the RPM by a predetermined or user-set value or percentage of a predetermined or user-set duration, in an attempt to remove the drilling operation from the wave state. Alternatively, the controller may be used to automatically continue to change the RPM up or down in increments of ΔT or to an alarm parameter indicating that the abrupt movement has been stopped.

In an exemplary embodiment, ΔT or an SSA responsive controller can also be used to automatically restore WOB if the jerky movement has reached a serious level, which could be due to an excessively high target WOB frequency. Such an automatic reduction in WOB may include one single adjustment or continuous adjustment until ΔT is reached or to an alarm parameter indicating that the abrupt movement has been stopped.

ΔT or an SSA-responsive controller can also be used to automatically increase the WOB, for example, to find the upper limit of the wobble of the WOB. For example, if all other possible drilling parameters are optimized or within the appropriate limits, the controller can automatically increase WOB in steps to ΔТ, or to the SSA parameter equal to its upper limit (for example, 25).

In an embodiment of the invention, a drilling or monitoring operation based on the ΔT parameter according to one or more objects of the present invention may function according to one or more aspects of the following pseudo-code:

where "moment" = torque; Process_Time - time starting from monitoring the ΔT or SSA parameter; Minimum_Torque - the minimum torque on the bit (TOV) that occurred in the interval Process_Time; Maximum_T moment - maximum TOV that occurred in the interval Process_Time; The real-time moment is the current TOV, Medium_T moment is the average TOV in the interval Process_Time, and SSA is the alarm parameter during abrupt movement.

As described above, ΔT or the SSA parameter can be used in the method 200a shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 500a shown in FIG. 5A, the method 500b shown in FIG. 5C, and / or the method 500c, shown in figure 5D. For example, as shown in FIG. 6A, the ΔT or SSA parameter can be replaced by the MSE parameter described above with reference to FIG. 5A. Alternatively, the ΔT or SSA parameter can be checked in addition to the MSE parameter described above with reference to Figure 5A to ensure that the drilling operation or control is based on both the MSE parameter and the ΔT or SSA parameter.

6A is a flowchart of a method 600a according to one or more objects of the present invention. Method 600a may be performed in conjunction with one or more components of the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, and / or device 590, shown in figure 5B, during their operation.

Method 600a includes a step 602, during which current ΔT parameters are measured. In the next step 604, ΔT is calculated. If ΔT is equal to the desired ΔT or otherwise approaches ideal, as determined at decision stage 606, method 600a is resumed and step 602 will be repeated. As described above, an “ideal” state may occur. The repetition of method 600a can generally be immediate, or delayed, so that method 600a is resumed, and step 602 is repeated. If ΔT is not ideal, as determined at decision stage 606, method 600a proceeds to step 608, during which one or more drilling parameters (e.g., WOB, RPM, etc.) are rebuilt in an attempt to improve ΔT. After step 608 is completed, method 600a is resumed and step 602 is repeated. Such a repetition may generally be immediate, or there may be a delay period before the method 600a is resumed and step 602 is repeated.

6B is a flowchart of a method 600b for monitoring ΔT and / or SSA according to one or more objects of the present invention. Method 600b can be performed using the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, and / or the device 590 shown in FIG. 5B. Method 600b can also be performed in conjunction with method 200a shown in FIG. 2A, method 200b shown in FIG. 2B, method 500a shown in FIG. 5A, method 500b shown in FIG. 5C, method 500c shown in FIG. 5D, and / or the method 600a shown in FIG. 6A. The method 600b shown in FIG. 6B may include or form at least a portion of the method 600a shown in FIG. 6A.

At step 612 of method 600b, a baseline parameter ΔT is determined for optimization based on ΔT by changing the WOB. Since the basic parameter ΔT determined in step 612 will be used for optimization by changing the WOB, the designation ΔT _BLWOB will be used _here .

In the next step 614, the WOB changes. Such a change may include an increase or decrease in WOB. Increasing or decreasing the WOB in step 614 may be performed within some predetermined WOB limits. For example, the change in WOB may be within no more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside of the predetermined WOB limits. The WOB parameter can be manually changed by the operator or the WOB parameter can be automatically changed by signals transmitted by the controller, control system and / or other component of the rig and the corresponding device. As described above, such signals may be transmitted via a remote control system from another terminal.

Then, at step 616, drilling continues with the modified WOB parameter for a predetermined time interval ΔWOB. The time interval ΔWOB may be a predetermined period of time, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the time interval ΔWOB may be a predetermined penetration depth. For example, step 616 may include drilling continued with a modified WOB parameter until the existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The time interval ΔWOB may also include components of time and depth. For example, the ΔWOB time interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔWOB time interval may include drilling until the wellbore is extended twenty feet, but over a period of no more than ninety minutes. Of course, the above values of time and depth for the time interval ΔWOB are merely examples, and many other values are also within the scope of the present invention.

After continuing the drilling operation in the ΔWOB interval with the changed WOB parameter, step 618 is performed to determine the ΔT _ΔWOB value obtained by working with the changed WOB parameter in the ΔWOB interval. In a subsequent decision step 620, the changed parameter ΔT _{ΔWOB is} compared with the base ΔT _BLWOB . If the changed parameter ΔT _{ΔWOB is} more desirable than ΔT _BLWOB , method 600b proceeds to step 622. However, if the changed parameter ΔT _{ΔWOB is} less desirable than ΔT _BLWOB , method 600b proceeds to step 624, where the WOB is restored to its previous value before stage 614 will be executed, and the method proceeds to step 622.

Determination at the decision-making stage 620 may be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The determination may include searching for a desired ΔT _ΔWOB value if it is substantially equal to and / or less than ΔT _BLWOB . However, additional or alternative factors may also play a role in the determination performed at block 620.

At step 622 of method 600b, a basic parameter ΔT is determined for optimization based on ΔT by changing the bit speed (parameter RPM). Since the basic parameter ΔT determined in step 622 will be used for optimization by changing the RPM, the designation ΔT _BLRPM will be used _here .

In the next step 626, the RPM parameter is changed. Such a change may include either an increase or decrease in RPM. An increase or decrease in RPM in step 626 may be implemented within certain predetermined RPM limits. For example, the change in RPM may be within no more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside such RPM limits. The RPM parameter can be changed manually by the operator, or the RPM can be automatically changed by signals transmitted by the controller, control system and / or other component of the rig and the corresponding device.

Then, at step 628, drilling continues with a modified RPM parameter for a predetermined drilling interval ΔRPM. The ΔRPM interval may be a predetermined period of time, such as five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the ΔRPM interval may be a predetermined penetration depth. For example, step 628 may include drilling continued with a modified RPM parameter until the existing wellbore is extended five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔRPM interval may include drilling until the wellbore is extended twenty feet, but over a period of no more than ninety minutes. Of course, the above time and depth values for the ΔRPM interval are merely examples, and many other values are also within the scope of the present invention.

After continuing the drilling operation for a certain time ΔRPM with the changed RPM parameter, step 630 is performed to determine the ΔT _ΔRPM value obtained by working with the changed RPM parameter during the ΔRPM interval. In a subsequent decision step 632, the changed parameter ΔT _{ΔRPM is} compared with the base ΔT _BLRPM . If the changed ΔT _ΔRPM parameter is more desirable than ΔT _BLRPM , method 600b returns to step 612. However, if the changed ΔT _ΔRPM parameter is less desirable than ΔT _BLRPM , method 600b proceeds to step 634, where the RPM is restored to its previous value before it step 626 is completed, and the method proceeds to step 612.

Determination at the decision-making stage 632 can be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The definition may comprise detecting the desirability of ΔT _ΔRPM if it is substantially equal to and / or less than ΔT _BLRPM . However, additional or alternative factors may also play a role in the determination performed at block 632.

In addition, after performing step 632 and / or 634, method 600b may immediately return to step 612 for subsequent repetition, or a subsequent repetition of method 600b may be delayed by a predetermined time interval or depth of penetration. Alternatively, method 600b may end after performing steps 632 and / or 634.

6C is a flowchart of a method 600c for optimizing a drilling operation based on a ΔT parameter calculated in real time according to one or more objects of the present invention. Method 600c can be performed using the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, and / or the device 590 shown in FIG. 5B. Method 600c can also be performed in conjunction with method 200a shown in FIG. 2A, method 200b shown in FIG. 2B, method 500a shown in FIG. 5A, method 500b shown in FIG. 5C, method 500c shown in FIG. 5D, method 600a shown in FIG. 6A and / or the method 600b shown in FIG. 6B. The method 600c shown in FIG. 6C may comprise or form at least a portion of the method 600a shown in FIG. 6A and / or the method 600b shown in FIG. 6B.

At step 640 of method 600c, a baseline parameter ΔT is determined for optimization based on ΔT by reducing WOB. Since the basic parameter ΔT determined in step 640 will be used for optimization by reducing WOB, the designation ΔT _BL-WOB will be used here.

In the next step 642, the WOB parameter is reduced. The reduction of WOB in step 642 may be performed within some predetermined limits of the WOB. For example, a decrease in WOB may be in the range of not more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside of the predetermined WOB limits. The WOB parameter can be manually reduced by the operator, or the WOB can be automatically reduced by signals transmitted by the controller, control system and / or other component of the rig and the corresponding device.

Then, at step 644, drilling continues with a reduced WOB parameter for a predetermined time interval ΔWOB. Time interval ΔWOB

may be a predetermined period of time, for example, five minutes, ten minutes, thirty minutes, or some other duration. Alternatively, the time interval ΔWOB may be a predetermined penetration depth. For example, step 644 may include drilling continued with a reduced WOB parameter until the existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The time interval ΔWOB may also include components of time and depth. For example, the ΔWOB time interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔWOB time interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes. Of course, the above time and depth values for the ΔWOB interval are merely examples, and many other values are also within the scope of the present invention.

After continuing the drilling operation in the ΔWOB interval with the reduced WOB parameter, step 646 is performed to determine the ΔT _{-ΔWOB value} . obtained as a result of working with a reduced parameter WOB in the interval ΔWOB. In a subsequent decision step 648, the reduced ΔT-ΔWOB interval is compared to the base ΔT _BL-WOB . If the reduced ΔT _{-ΔWOB is} more desirable than ΔT _BL-WOB , the method 600c proceeds to step 652. However, if the reduced ΔT _{-ΔWOB is} less desirable than ΔT _BL-WOB , the method 600c proceeds to step 650, where the WOB is restored to its former values before step 642 is completed, and the method proceeds to step 652.

Determination at the decision-making stage 648 can be performed manually by an operator or automatically by a controller, control system and / or other component of the rig and the corresponding device. The definition may comprise detecting ΔT _-ΔWOB as a desired value if it is substantially equal to and / or less than ΔT _BL-WOB . However, additional or alternative factors may also play a role in the determination performed at step 648.

At step 652 of method 600c, a baseline parameter ΔT is determined for optimization based on ΔT, increasing WOB. Since the basic parameter ΔT determined in step 652 will be used for optimization by increasing WOB, the designation ΔT _{BL + WOB} will be used here.

In the next step 654, the WOB parameter is increased. An increase in WOB in step 654 may be performed within some predetermined WOB limits. For example, an increase in WOB may be in the range of not more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside of the predetermined WOB limits. The WOB parameter can be manually increased by the operator, or the WOB can be automatically increased by the signals transmitted by the controller, control system and / or other component of the rig and the corresponding device.

Then, at step 656, drilling continues with an increased WOB value 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. Alternatively, the time interval + ΔWOB may be a predetermined penetration depth. For example, step 656 may include drilling continued with an increased WOB value until the existing wellbore is extended five feet, ten feet, fifty feet, or some other depth. The interval + ΔWOB may also include time and depth components. For example, the + ΔWOB interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the + ΔWOB interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes.

After continuing the drilling operation during the drilling interval + ΔWOB with the increased WOB value, step 658 is performed to determine the ΔT _{+ ΔWOB} value obtained by operating with the increased WOB value during the drilling interval + ΔWOB. In a subsequent decision step 660, the changed parameter ΔT _{+ ΔWOB is} compared with the base ΔT _{BL + WOB} . If the changed parameter ΔT _{+ ΔWOB is} more desirable than ΔT _{BL + WOB} , the method 600c proceeds to step 664. However, if the changed parameter ΔT _{+ ΔWOB is} less desirable than

ΔT _{BL + WOB} , the method 600c proceeds to step 662, where the WOB is restored to its previous value before step 654 is performed, and the method proceeds to step 664.

Determination at the decision-making stage 660 may be performed manually by an operator or automatically by a controller, a control system and / or other component of the rig and the corresponding device. The definition may comprise detecting ΔT _{+ ΔWOB} as a desired value if it is substantially equal to and / or less than ΔT _{BL + WOB} . However, additional or alternative factors may also play a role in the determination performed at block 660.

At step 664 of method 600c, a basic parameter ΔT is determined for optimization based on ΔT, reducing the RPM bit speed. Since the basic parameter ΔT determined in step 664 will be used for optimization by reducing RPM, the designation ΔT _BL-WOB will be used here.

In the next step 666, the RPM bit speed is reduced. RPM reduction

at 666, it may be performed within some predetermined RPM limits. For example, a decrease in RPM may be in the range of not more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside such RPM limits. RPM can be manually reduced by the operator, or RPM can be automatically reduced by signals transmitted by the controller, control system and / or other component of the rig and associated device.

Then, at step 668, drilling continues at a reduced RPM frequency 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 penetration depth. For example, step 668 may include drilling continued at a reduced RPM rate until the existing wellbore is extended five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔRPM interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes.

After continuing the drilling operation during the ΔRPM interval with the reduced RPM frequency, step 670 is performed to determine the ΔT _-ΔRPM value obtained by operating at the reduced RPM frequency during the ΔRPM interval. In a subsequent decision step 672, the reduced ΔT _-ΔRPM interval is compared to the baseline ΔT _BL-RPM . If the changed parameter ΔT _{-ΔRPM is} more desirable than ΔT _BL-RPM , the method 600c proceeds to step 676. However, if the changed parameter ΔT _{-ΔRPM is} less desirable than ΔT _BL-RPM , the method _600c proceeds to step 674, where the RPM is restored to its previous value before step 666 is completed, and the method proceeds to step 676.

Determination at the decision-making stage 672 can be performed manually by an operator or automatically by a controller, control system and / or other component of the drilling rig and the corresponding device. The definition may comprise detecting ΔT _-ΔRPM as a desired value if it is substantially equal to and / or less than ΔT _BL-RPM . However, additional or alternative factors may also play a role in the determination performed at block 672.

At step 676 of method 600c, a baseline parameter ΔT is determined for optimization based on ΔT of the RPM bit speed. Since the basic parameter ΔT determined in step 676 will be used for optimization by increasing the RPM, the designation ΔT _{BL + RPM} will be used here.

In the next step 678, the RPM increases. An increase in RPM in step 678 may be performed within some predetermined RPM limits. For example, an increase in RPM may be within no more than about 10%. However, the scope of the present invention may include other percentages, including the case where such percentages may be within or outside such RPM limits. The RPM can be manually increased by the operator or the RPM can be automatically increased by the signals transmitted by the controller, the control system and / or other component of the rig and the corresponding device.

Then, at step 680, drilling continues at an increased RPM 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 penetration depth. For example, step 680 may include drilling continued at an increased RPM until an existing wellbore is extended by five feet, ten feet, fifty feet, or some other depth. The ΔRPM interval may also include time and depth components. For example, the ΔRPM interval may include drilling for at least thirty minutes or until the wellbore is extended ten feet. In another example, the ΔRPM interval may include drilling until the wellbore is extended twenty feet, but for a period of no more than ninety minutes.

After continuing the drilling operation for the ΔRPM interval with the increased RPM speed, step 682 is performed to determine the values

_{ΔТ + ΔRPM} obtained as a result of operation with an increased RPM in the range ΔRPM. At the next decision stage 684, the increased parameter ΔT _{+ ΔRPM is} compared with the base ΔT _{BL + RPM} If the changed parameter

ΔT _{+ ΔRPM is} more desirable than ΔT _{BL + RPM} , method 600c proceeds to step 688. However, if the changed parameter ΔT _{+ ΔRPM is} less desirable than ΔT _{BL + RPM} , method 600c proceeds to step 686, where the RPM is restored to its previous value before than step 678 will be performed, and the method proceeds to step 688.

Determination at the decision-making stage 684 can be performed manually by an operator or automatically by a controller, control system and / or other component of the rig and the corresponding device. The definition may comprise detecting the desirability of ΔT _{+ ΔRPM} if it is substantially equal to and / or less than ΔT _{BL + RPM} . However, additional or alternative factors may also play a role in the determination performed at step 684.

Step 688 comprises waiting for a predetermined period or interval of drilling depth before repeating method 600c by returning to step 640. However, in an example embodiment, the interval may be so small that it is 0 seconds or 0 feet, and the method returns to step 640 mainly immediately after step 684 and / or 686. Alternatively, method 600c may not need to be repeated, and method 600c may generally end after step 684 and / or 686.

In addition, the drilling intervals: -ΔWOB, + ΔWOB, -ΔRPM and + ΔRPM each can be basically the same within one repetition of the method 600 s. Alternatively, one or more intervals may vary in duration or in depth relative to other intervals. Similarly, the amount by which the WOB decreases and increases in steps 642 and 654 can basically be the same or can vary relative to each other within a single repetition of method 600c. The amount by which the RPM decreases and increases in steps 666 and 678 can basically be the same or can vary relative to each other within the same repetition of method 600c. Deviations of WOB and RPM may also change or remain the same during subsequent repetitions of method 600c.

7 is a diagram of an apparatus 700 according to one or more aspects of the present invention. The device 700 may include or constitute at least a part of the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, and / or device 590, shown in figure 5B. Apparatus 700 is an embodiment of the invention in which one or more methods within the scope of the present invention may be performed or otherwise implemented, including method 200a shown in FIG. 2A, method 200b shown in FIG. 2B, method 500a shown in FIG. 5A, method 500b shown in FIG. 5C, method 500c shown in FIG. 5D, method 600a shown in FIG. 6A, method 600b shown in FIG. 6B, and / or method 600c shown in FIG. 6C.

The device 700 includes a plurality of data inputs, manually or automatically entered, all of which are collectively referred to herein as inputs 702. The device also includes many automatic controllers, computing devices, detectors and other processors, all collectively referred to as processors 704. Data from various inputs 702 are transmitted to various processors 704, as shown in FIG. 7 by arrow 703. Device 700 also includes a variety of sensors, encoders, drives, motors, and other sensory and -negative, and actuators, collectively referred to herein as devices 708. The various data and signals are collectively called data 706 are transmitted between processors 704 and various devices 708, as shown in Figure 7 by the arrows 705.

The device 700 may also include a display 710 or is connected to such a display with which you can conduct a dialogue or otherwise receive data from one or more processors 704, as well as from other components of the device 700. The display 710 may also be referred to as a human-machine interface (HMI), although such an HMI may also include one or more inputs 702 and / or processors 704.

In the example embodiment shown in FIG. 7, inputs 702 include means providing the following setpoints, limits, ranges, and other data:

bottomhole pressure 702a;

shutter position 702b;

limit ΔP 702s;

point ΔP 702;

the limit value of the pulling force of the winch 702e;

limit value MSE 702f;

target value MSE 702g;

drilling fluid setpoint 702h;

702i pump pressure calibration

negative amplitude of the hollow shaft 702j;

positive amplitude of the hollow shaft 702k;

drilling speed setpoint (ROP) 702l;

downhole tool position 702n;

top drive speed (RPM) 702o;

limit value of the torque of the upper drive 702r;

WOB value 702q; and

WOB 702r calibration

However, inputs 702 within the scope of the present invention may include means for providing additional or alternative setpoints, limits, ranges, and other data.

The bottomhole pressure 702a may indicate the value of the maximum desired pressure of the gaseous and / or other environment in the lower part of the wellbore. Alternative bottomhole pressure 702a may indicate a range within which it is desirable to maintain pressure at the base of the wellbore. Such pressure can be expressed as absolute pressure or gauge pressure (for example, relative to atmospheric pressure or some other predetermined pressure).

The designation of the position of the shutter 702b may be an operating point or a value indicating the desired position of the shutter. Alternatively, the designation of the position of the shutter 702b may indicate a range within which it is desired to maintain the position of the shutter. The damper may be a device having an opening or other means used to control fluid flow and / or pressure. The damper can be installed at the end of the wellhead piping, which is a high-pressure pipe extending from the outlet of the blowout preventer block, so that pressurized fluid in the wellbore can flow out of the wellbore through the wellhead line to the damper, thereby reducing fluid pressure (e.g. to atmospheric pressure). The designation of the position of the shutter 702b may be a double indicator expressing the position of the shutter, either as “open” or “closed”. Alternatively, the designation of the position of the shutter 702b may be expressed as a percentage indicating the degree of partial opening or closing of the shutter.

The limit ΔP 702c may be a value indicating the maximum or minimum pressure drop through the downhole hydraulic motor. Alternatively, the ΔP 702c limit may indicate a range within which it is desirable to maintain a pressure drop across the downhole hydraulic motor. The designation ΔP 702d may be an operating point or a value indicating the desired pressure drop through the downhole hydraulic motor. In an example embodiment, the limit ΔP 702c is a value indicating the maximum desired pressure drop across the downhole motor, and the designation ΔP 702d is a value indicating the nominal desired pressure drop across the downhole motor.

The limit value of the pulling force of the winches 702e may be a value indicating the maximum force that will be applied to the winches by the drill rope (for example, while maintaining the drill string above the bottom or when pulling equipment from the wellbore). For example, the limit value of the pulling force of the winches 702 may indicate the maximum load on the hook that must be provided by the winches during operation of the rig. The limit value of the pulling force of the winch 702e can be expressed as the maximum weight or interference fit of the drill rope, which can be carried by the winch without damaging the winch, drill rope and / or other equipment.

The limit value of MSE 702f may be a value indicative of the maximum or minimum energy MSE desired during drilling. Alternatively, the limit value of MSE 702f may be a range within which it is desirable to maintain MSE during drilling. As discussed above, the actual MSE value is at least partially dependent on WOB, drill bit diameter, bit speed, drill string torque, and mechanical drilling speed (ROP), each of which can be adjusted in accordance with the objectives of the present invention, to provide the desired MSE. The target MSE 702g may be a value indicating the desired MSE or the range within which it is desirable to maintain the MSE during drilling. In an exemplary embodiment, the limit value of MSE 702f is a value or range indicating a maximum and / or minimum MSE,

and the target MSE 702g is a value indicating the desired nominal MSE.

The predetermined amount of drilling fluid 702h may be a value indicating the maximum, minimum, or nominal desired flow rate of the drilling fluid provided by the mud pump. Alternatively, the predetermined amount of drilling fluid 702h may be a range within which it is desirable to maintain the flow rate of the drilling fluid. The calibration of the discharge pressure 702i may be a value indicating the current, desired, initial, or other pressure of the mud pump. The pressure calibration of the mud pump mainly takes into account the difference between the mud pressure and the casing or wellbore pressure when the drill string moves away from the bottom of the well.

The negative amplitude of the hollow shaft 702j may be a value indicating the desired maximum rotation of the hollow shaft from the neutral point of the hollow shaft in the first angular direction, while the positive amplitude of the hollow shaft 702k may be the value indicating the desired maximum rotation of the hollow shaft from the neutral point of the hollow shaft shaft in the opposite angular direction. For example, during operation of the top drive when the hollow shaft is oscillating, the negative amplitude of the hollow shaft 702j may indicate the desired maximum rotation of the hollow shaft to the right of the neutral oscillation point, and the positive amplitude of the hollow shaft 702k may indicate the desired maximum rotation of the hollow shaft to the left of the neutral oscillation point.

ROP 702l operating point may be a value indicating the maximum, minimum, or nominal desired ROP penetration rate. Alternatively, ROP 702l may be the range within which it is desired to maintain this speed.

The position of the downhole tool 702n may be a value indicating the desired orientation of the downhole tool. Alternatively, the position of the downhole tool 702n may be a range within which it is desirable to maintain the position of the downhole tool 702n. The position of the downhole tool can be expressed as one or more angles relative to a fixed or predetermined point. For example, the position of the downhole tool 702n may be represented by the desired orientation of the downhole tool in the form of an azimuth relative to the true north pole and / or the desired inclination of the downhole tool from the vertical.

The RPM of the top drive 702o may be a value indicating the maximum, minimum, or nominal desired speed of the top drive. Alternatively, the RPM of the top drive of the engine 702o may be a range within which it is desirable to maintain the drive speed. The torque limit of the top drive can be a value indicating the maximum torque that the top drive will create.

The designation WOB 702q may be a value indicating the maximum, minimum, or nominal desired WOB load resulting from the weight of the drill string acting on the drill bit, although it is also possible to take into account other forces acting on the WOB, for example, friction between the drill string and the borehole . Alternatively, the designation WOB 702q may be the range in which it is desirable to support WOB. Calibration of WOB 702r may be a value indicating a current, desired, initial, survey, or other WOB setup that takes into account the hook load and weight of the drill string when it is lifted from the bottom of the well.

One or more of the inputs 702 may include a keyboard, voice recognition device, dial, joystick, mouse, database, and / or other conventional or future data input device. One or more inputs 702 may support input from local and / or remote terminals. One or more inputs 702 may include means for the user to select predefined predetermined points, values, or ranges, for example, through one or more drop-down menus. One or more inputs 702 can also be or alternatively be used to automatically start one or more processors 704, for example, by performing one or more database lookup procedures. One or more inputs 702, possibly in combination with other components of device 700, are used to support operation and / or control from stations in a rig site, as well as one or more remote terminals. Each of the inputs 702 may have separate input means, although two or more inputs 702 may collectively have only one input means. One or more inputs 702 can be used for operator input, although one or more inputs 702 can alternatively be used to automatically enter data by a computer, program, input module, application, database search, algorithm, calculation, and / or otherwise. One or more inputs 702 can be used for such automatic data entry, but with a cancel function that the operator can apply or the operator can check the automatically entered data.

In the example embodiment shown in FIG. 7A, devices 708 include:

block position sensor 708a;

casing pressure sensor 708b;

shutter position sensor 708c;

load securing sensor at the fixed end 708d;

708e winch encoder;

drilling fluid pressure sensor 708f;

MWD 708g downhole tool gravity sensor;

MWD 708h magnetic downhole tool sensor;

return flow meter 708i;

return line drilling fluid density sensor 708j;

708k top drive encoder;

708l top drive torque sensor;

708m damper actuator;

708n winch drives;

engine winch 708o;

mud pump motor 708r;

708q top drive engine; and

708r top drive engine.

However, devices 708 may include additional or alternative components within the scope of the present invention. Devices 708 are designed to operate with appropriate mechanisms for winches, shutters, mud pump, top drive, block, drill string and / or other components of the rig. Alternatively, devices 708 also include one or more other components of the rig.

The position sensor of block 708a may include an optical sensor, a high-frequency sensor, an optical or other encoder, or other type of sensor used to determine the relative or absolute vertical position of the block. The position sensor of block 708a may be coupled to said block, drill bit, winches, and / or other component of device 700 or rig.

The casing pressure sensor 708b is used to detect pressure in the annulus between the drill string and the casing or wellbore, and may consist of or include one or more transducers, strain gauges, and / or other devices for detecting pressure changes or otherwise respond to pressure. The casing pressure sensor 708b may be coupled to the casing, drill string and / or other component of the device 700 or rig, and may be installed on or near the surface of the wellbore, bit below the surface, or in the depth of the wellbore.

The shutter position sensor 708c is used to detect whether the shutter is open or closed, and can also be used to determine the degree of partial opening or closing of the shutter. The damper position sensor 708c may be coupled or integral with the damper, damper actuator and / or other component of the device 700 or rig.

A load sensor 708d at the fixed end attachment point is used to detect drill cable tension near the fixed end. It may include one or more transducers, strain gauges, and / or other sensors connected to the drill string.

The winder coding device 708e is used to determine the rotational position of the winch drums on which the drill rope is wound. It may include one or more optical encoders, interferometers and / or other sensors designed to determine the angular position of the drum and / or any change in the angular position of the drum. The encoder of the winch 708e may include one or more components connected to or integrally with the drum and / or the fixed part of the winch.

The mud pressure sensor 708f is used to detect hydraulic fluid pressure generated by the hydraulic downhole motor and may include one or more transducers, strain gauges, and / or other devices for detecting fluid pressure. It can be connected to or be integral with the mud pump and, thus, located near the surface mouth of the wellbore.

The MWD downhole tool gravity sensor 708g is used to detect the orientation of the downhole tool based on gravity. The MWD downhole tool magnetic sensor 708h is used to detect the orientation of the downhole tool based on the magnetic field. These sensors 708g and 708h can be connected to or integrate with MWD equipment and are installed in the bottom of the well.

The return line flow sensor 708i is used to determine the flow rate of the return line drilling fluid and can be expressed in gallons / minute. The return line drilling fluid density sensor 708j is used to determine the weight of the drilling fluid flowing through the return line. These sensors 708i and 708j can be connected to a return line and, thus, can be installed at or near the wellhead.

The 708k top drive encoder is used to determine the rotational position of the hollow shaft. It may include one or more optical encoders, interferometers and / or other sensors designed to determine the angular position of the hollow shaft and / or any change in the angular position of the hollow shaft, the top drive relative to the true north pole, or some other fixed reference point. The top drive torque sensor 708l is used to determine the torque generated by the top drive or the torque required to rotate the hollow shaft or drill string in accordance with existing regulations. These sensors 708k and 708l can be connected to or integrate with the top drive.

The damper actuator 708m is used to rotate the damper to an open state, a closed state, and / or to one or more positions between a fully open and a fully closed state. The drive may be hydraulic, pneumatic, mechanical, electrical, or a combination thereof.

The winch motor 708n is used to provide an electrical signal to the winch motor 708o and drive them. The 708o winch motor is used to rotate the drum on which the drill rope is wound, thus raising or lowering the drill.

The mud pump motor 708p is used to provide an electrical signal to the mud pump, thereby controlling the flow rate and / or pressure from the outlet of the mud pump. The top drive of the engine 708q is used to provide an electrical signal to the top drive of the engine 708r to drive it. The top drive of the motor 708r is used to rotate the hollow shaft, thereby rotating the drill string attached to the hollow shaft.

In the example embodiment of FIG. 7, data 706 that is transmitted between devices 708 and processors 704 includes:

block position 706a;

casing pressure 706b;

damper position 706c;

hook load 706d;

drilling fluid pressure 706e;

stroke / phase of the mud pump 706f;

mud density 706g;

position of the hollow shaft 706h;

counterflow 706i;

downhole tool 706j;

top drive torque 706k;

signal 706l acting on the shutters;

706m signal acting on winches;

signal 706n acting on the mud pump;

signal 706o acting on the top drive; and

signal 706p limit torque of the upper drive.

However, data 706 transmitted between devices 708 and processors 704 may include additional or alternative data within the scope of the present invention.

In the example embodiment of FIG. 7, processors 704 include:

damper controller 704a;

drum controller 704b;

mud pump controller 704c;

oscillation controller 704d;

Hollow shaft position controller 704e;

downhole tool controller 704f;

MSE 704i calculator;

pressure calculator 704k;

ROP 704l calculator;

true well depth calculator 704m;

WOB 704n calculator;

704o step motion detector; and

logging magazine 704р.

However, processors 704 may include additional or alternative controllers, computing devices, detectors, data storage devices, and / or other processors within the scope of the present invention.

The damper controller 704a is used to control the bottomhole pressure from the inlet pressure sensor 702a, the pressure in the casing 706b from the pressure sensor 708b in the casing, the position of the damper 706c from the position sensor of the damper 708c and the density of the drilling fluid 706g from the density sensor of the drilling mud 708j return line. The damper controller 704a may also obtain bottomhole pressure data from the pressure transmitter 704k. Alternatively, processors 704 may include a comparator, adder or other device that performs an algorithm using the bottomhole pressure value obtained from the bottomhole pressure input 702a and the current bottomhole pressure obtained from the pressure calculator 704k with the result of such an algorithm transmitted to the damper controller 704a instead of the installed bottomhole pressure pressure and / or in addition to the current bottomhole pressure. The damper controller 704a is used to process the received data and generate a signal 706l acting on the damper, which is then transmitted to the damper actuator 708.

For example, if the current bottomhole pressure exceeds the set bottomhole pressure, then the signal 706l can act on the damper actuator 708m, opening the damper and thereby increasing the flow rate of the return flow and reducing the current bottomhole pressure. Similarly, if the current bottomhole pressure drops below the set bottomhole pressure, then a signal 706l acting on the actuator of the shutter 708m can close the shutter and, thus, reduce the flow rate of the return flow, increasing the current bottomhole pressure. The impact on the actuator of the shutter 708m can be increasing so that the signal 706l opens the shutter 708m several times, or opens the shutter a predetermined amount to the current bottomhole pressure, satisfactorily performing the task of setting the desired bottomhole pressure. Alternatively, the signal 706l acting on the shutters may act on the shutter actuator 708m

so as to open the shutter by a value proportional to the current difference between the current bottomhole pressure and the set value of the bottomhole pressure.

The damper controller 704a may comprise or constitute at least a portion, or otherwise be able to perform operations and / or have substantially similar inputs and outputs of data with respect to the controller 190 shown in FIG. 1, the controller 325 shown in FIG. 3, the controller 420 shown in figures 4A and 4B, and / or the controller 598 shown in figure 5B.

The drum controller 704b is used to receive the set ROP value from the input of the set ROP values 702l, as well as the current ROP value from the ROP 704l calculator. The drum controller 704b is also used to receive bit load data from a comparator, adder, or other device that performs the algorithm using the WOB control point from the input source of the WOB 702g and the current bit load from the WOB 704n calculator. This bit load data can be modified based on current MSE data. Alternatively, the drum controller 704b is used to receive the WOB control point from the input of the WOB 702g source and the current bit load directly from the WOB 704n calculator, and then performs a WOB comparison or an adder algorithm. The drum controller 704b is also used to receive ΔP data from a comparator, adder or other device that performs the algorithm using the reference value ΔP obtained from the input 702d of the reference value ΔP and the current value ΔP obtained from one of the processors 704, which is used to determine current ΔР. The current ΔP value may be adjusted to account for pressure in the casing 706b.

The drum controller 704b is used to process the received data and generate a signal 706m affecting the winch, which is then transmitted to the winch engine 708n. For example, if the value of the current load on the bit received from the WOB source calculator 704n is less than the specified WOB value received from the input of the WOB 702q source, then the signal acting on the winch 706m can initiate the winch 708n to drive the winch 708o engine in the direction of drilling the rope. If the current load on the bit deviates more than the specified value of WOB, then the signal acting on the winch 706m can initiate the drive of the winch 708n to operate the winch 708o engine in the direction of winding the drill rope onto the drum.

If the current mechanical driving speed (ROP) received from the ROP 704l calculator is less than the ROP received from the input of the ROP 702l setpoints, then the signal acting on the winch 706m can trigger the winch 708n to drive the winch motor 708o in the direction of the drill rope . If the current ROP is greater than the preset ROP value, then the signal acting on the winch 706m can initiate the winch 708n drive to operate the winch 708o engine to draw the drill rope.

If the current ΔP is less than the reference value ΔP received from the input 702d ΔP, then the signal acting on the winches 706m can initiate the drive of the winches 708n to operate the motor of the winches 708o in the direction of the drill rope bleeding. If the current ΔP is greater than the reference value ΔP, then the signal acting on the winches 706m can initiate the drive of the winches 708n to work the engine of the winches 708o to wind the drill rope.

The drum controller 704b may comprise or constitute at least a portion, or otherwise substantially be similar in principle to operation and / or have substantially similar data inputs and outputs with respect to the controller 190 shown in FIG. 1, the controller 325 shown in FIG. 3, the winch controller 420b shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

The mud pump controller 704c is used to receive the stroke / phase data of the mud pump 706f, the mud pressure 706e from the mud pressure sensor 708f, the current ΔP, the current MSE from the MSE 704i, the current ROP from the ROP 704l, and the jump indicator from the jump sensor 704o and the set value of the flow rate of the drilling fluid from the input 702h of the set values of the flow rate of the drilling fluid. The mud pump controller 704c then uses this data to generate a signal 706n affecting the mud pump, which is then transmitted to the mud pump 708p.

The mud pump controller 704c may comprise or comprise at least a portion, or otherwise, be substantially similar in principle and / or have substantially similar data inputs and outputs with respect to the controller 190 shown in FIG. 1, the controller 325 of FIG. 3, the controller 420 of FIG. 4A, the mud pump controller 420c of FIG. 4B and / or the controller 598 of FIG. 5B.

The oscillation controller 704d is used to receive the current position 706n of the hollow shaft, the current torque of the top drive 706k, the jump indicator from the jump sensor 704o, the current ROP from the ROP 704l and the limit amplitude of the oscillation of the hollow shaft from the inputs 702j and 702k. The oscillation controller 704d then uses this data to form an input to the position controller of the hollow shaft 704e to generate a signal 706o affecting the top drive. For example, if the jump indicator from the jump sensor 704o indicates that a jump is occurring, the signal generated by the vibration controller 704d may indicate that the amplitude of the oscillations begins to increase in amplitude.

Oscillation controller 704d may comprise or constitute at least a portion, or otherwise substantially be similar in principle to operation and / or have basically similar data inputs and outputs with respect to controller 190 shown in FIG. 1 , the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

The hollow shaft position controller 704e is used to receive a signal from the oscillation controller 704d, the setpoint RPM of the top drive, from the input RPM of the top drive 702o, the signal from the downhole tool controller 704f, the current bit load from the WOB 704n transmitter, and the current downhole tool 706j, at least one of the MWD sensors of the downhole tool 708g and 708h. The hollow shaft position controller 704e can also be used to receive the upper drive torque limit from the input of the upper drive torque limit 702p, although this predetermined value can be adjusted by a comparator, adder or other device to take into account the current MSE, and the value of the current MSE is received from the transmitter MSE 704i The position controller of the hollow shaft 704e can also be used to receive a step indicator from the step sensor 704 °. The position controller of the hollow shaft 704e then uses this data to generate a signal 706o acting on the top drive.

For example, a signal 706o acting on the top drive initiates the top drive of the motor 708q to turn on the motor 708r to rotate the hollow shaft at the speed indicated by the RPM input of the top drive 702o. However, this will only happen if other inputs do not cancel this action. For example, if the control signal from the vibration controller 704d acting on the upper drive 706o also causes the upper drive 708q to cause the hollow shaft to rotate the motor 708r. Additionally, the signal from the downhole tool controller 704d may cancel or otherwise affect the signal 706o acting on the top drive to rotationally orient the hollow shaft in a certain static position or establish a neutral point for vibrations.

The position controller of the hollow shaft 704e may comprise or constitute at least a portion, or otherwise, basically be similar in principle to operation and / or have basically similar data inputs and outputs with respect to the controller 190 shown in figure 1, the controller 325 shown in figure 3, the controller 420 shown in figures 4A and 4B, and / or the controller 598 shown in figure 5B.

The downhole tool controller 704f is used to receive a predetermined downhole tool position value from the downhole tool position input 702n, as well as the current position value of the downhole tool 706j from at least one of the MWD sensors of the downhole tool 708g and 708h. The downhole tool controller 704f may also be used to receive ΔP data. The downhole tool controller 704f then uses this data to generate a signal that is transmitted to the position controller of the hollow shaft 704e.

The downhole tool controller 704f may comprise or comprise at least a portion, or otherwise, be substantially similar in principle and / or have substantially similar data inputs and outputs with respect to the controller 190 shown in FIG. 1, the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

The MSE 704i is used to receive current RPM data from the main RPM input of the 702o engine, the torque of the top drive 706k from the torque sensor of the top drive 708l, and the current bit load from the WOB 704n. The MSE calculator 704i then uses this data to calculate the magnitude of the current MSE, which is then transmitted to the drum controller 704b, the hollow shaft position controller 704e, and the mud pump controller 704c. The MSE 704i can also be used to obtain MSE limit data from the input of the MSE 702f limit, and the MSE 704i can also be used to compare the current MSE with the specified MSE limit and give an alarm if the current MSE exceeds the set maximum MSE . The MSE 704i may also be used to receive the target MSE from the input of the MSE 702g, and the MSE 704i may also be used to generate a signal indicative of the difference between the current MSE and the target MSE. This signal can be used by one or more processors 704 to adjust various data values used in this way, for example, adjusting the current or reference WOB load data used by the drum controller 704b and / or the set upper limit torque limit of the upper drive used by the hollow position controller shaft 704e as described above.

The computer MSE 704i may contain or constitute at least part, or otherwise, basically be similar in principle and / or have basically similar data inputs and outputs, with respect to the controller 190 shown in figure 1 , the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

The pressure transmitter 704k is used to determine the pressure in the casing string 706b from the pressure sensor 708b in the casing string, the pressure of the drilling fluid 706e from the pressure transmitter 708f of the drilling fluid, the density of the drilling fluid from the density sensor of the drilling fluid 706g of the return line 708j and the actual vertical depth from the true depth calculator wells 704m. The pressure calculator 704k then uses this data to calculate the current bottomhole pressure, which is then transmitted to the throttle controller 704a. However, before transmitting to the controller of the shutter 704a, the current bottomhole pressure can be compared with a predetermined bottomhole pressure obtained from the bottomhole pressure inlet 702a, while the controller of the shutter 704a can only use the difference between the current bottomhole pressure and the predetermined bottomhole pressure to generate a signal 706l that affects flaps. This comparison between the current bottomhole pressure and a predetermined bottomhole pressure can be performed by a pressure calculator 704k, a damper controller 704a, or another processor 704.

The pressure calculator 704k may comprise or comprise at least a portion, or otherwise, basically be similar in principle to operation and / or have basically similar data inputs and outputs with respect to the controller 190 shown in FIG. 1 , the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

The ROP calculator 704l is used to receive position data of the block 706a from the position of the block 708a and then uses this data to calculate the current ROP. The current ROP is then transmitted to a true well depth calculator 704m, a drum controller 704b, a mud pump controller 704c, and an oscillation controller 704d. The computer ROP 704l may contain or constitute at least part, or otherwise, basically be similar in principle and / or have basically similar data inputs and outputs, with respect to the controller 190 shown in figure 1 , the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

A true well depth calculator 704m is used to receive data on the current downhole tool 706j from at least one of the MWD sensors 708g of the downhole tool and a current measured depth log 704p calculated from the current ROP speed obtained from the ROP 704l calculator. A true well depth calculator 704m then uses this data to calculate the actual vertical depth, which is then transmitted to the 704k pressure calculator. The true well depth calculator 704m may comprise or comprise at least a portion, or otherwise, be substantially similar in principle and / or have substantially similar data inputs and outputs with respect to the controller 190 shown in figure 1, the controller 325 shown in figure 3, the controller 420 shown in figures 4A and 4B, and / or the controller 598 shown in figure 5B.

The WOB calculator 704n is used to receive the jump indicator from the jump sensor 704 °, as well as the current load data on the hook 706d from the load sensor of the fixed end 708d. The WOB 704n can also be used to receive weight calibration data for the raised drill string, which may represent the difference between the WOB calibration received from the WOB calibration input 702r and the current load on hook 706d received from the load sensor attached to the fixed end 708d. In any case, the WOB 704n calculator is used to calculate the current load on the bit based on the current load on the hook, the current weight of the drill string, and a jump indicator. The current bit load is then transferred to the position controller of the hollow shaft 704e, the d-exponent calculator 704g, the d-exponent correction calculator 704h, the MSE calculator 704i, and the drum controller 704b.

The WOB 704n calculator may contain or constitute at least a part, or otherwise, basically be similar in principle to operation and / or have basically similar data inputs and outputs with respect to the controller 190 shown in FIG. 1 , the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

The discontinuous motion detector 704o is designed to receive data on the current torque of the top drive 706k and uses this data to generate a discontinuous motion indicator, which is then transmitted to the mud pump controller 704c, the oscillation controller 704d, and the position controller of the hollow shaft 704e. The jump detector 704o measures changes in the torque of the top drive 706k with respect to time, which is an indication of whether the drill bit shows a step-like movement, indicating that the torque of the top drive and / or WOB should be reduced, or the amplitude of the vibrations of the hollow shaft should be changed. The jump detector 704o may comprise or comprise at least a portion, or otherwise, basically be similar in principle to operation and / or have basically similar data inputs and outputs with respect to the controller 190 shown in the figure 1, the controller 325 shown in FIG. 3, the controller 420 shown in FIGS. 4A and 4B, and / or the controller 598 shown in FIG. 5B.

Processors 704 may be arranged in a single data processing unit or consist of many separate data processing devices. Each processor 704 may include one or more software modules or other software product modules, submodules, applications, routines, state machines, algorithms. Each processor 704 may further include one or more machine memory devices or other means for storing digital data. The objectives of one or more processors 704 may be substantially similar to those described herein with respect to any controller or other data processing device.

Figure 8 shows an exemplary system 800 for implementing one or more embodiments of the devices and / or methods described above or otherwise implemented within the scope of the present invention. System 800 includes a processor 802, an input device 804, a memory device 806, a video controller 808, a system memory 810, a display 814, and a communication device 816, all of which are connected by one or more buses 812. The memory device 806 may be a hard disk drive a disk, a CD, a DVD, an optical drive, or any other type of storage device. In addition, the storage device 806 may receive floppy disks, CDs, DVDs, or any other computer-readable medium that may contain computer-executable instructions. Communication device 816 may be a modem, network card, or any other device that allows system 800 to communicate with other systems, whether such communication is via a wired or wireless communication line.

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

The hardware mainly includes at least processor platforms, such as client machines (also known as personal computers or servers) and portable data processing devices (such as smartphones, personal assistants, and computing devices (e.g., personal communication devices) In addition, the hardware typically includes any physical device that is capable of storing machine-readable instructions, such as memory or other storage devices. include hardware subsystems, including drive devices such as modems, modem cards, punchers, and cards Hardware may also include at least the present invention multimodal technologies, for example, devices and / or systems that allow users to use multiple login forms and output, including voice input, keyboard, and stylus, used interchangeably in the same application or interface.

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

Hybrids (combinations of software and hardware) are becoming more widespread as devices that provide increased functionality and work in computer systems. A hybrid can be created when traditional software is directly integrated into the silicon chip - this is possible, since the software can be assembled and compiled into units and zeros, in the same way units and zeros can be represented directly in silicon. Typically, a hybrid (manufactured hardware) is designed to function without additional software. Accordingly, it should be understood that hybrids and other combinations of hardware and software are also included herein in the definitions of a computer system and are thus intended in the present invention as possible equivalent structures and equivalent methods.

Computer readable media may include passive storage of data, such as random access memory (RAM), as well as semi-permanent storage of data, such as a CD or DVD. In addition, an embodiment of the present invention can be embodied in computer RAM and effectively transform a standard computer into a new specific computer.

Data structures are defined by a data organization that can constitute an embodiment of the present invention. For example, a data structure may provide data organization or organization of executable code (executable program). In addition, data signals pass through a transmission medium that stores and transports various data structures, and thus can be used to transport an embodiment of the invention. It should be noted here that actions with the same name can be performed in the same way, unless specifically stated.

The controllers and / or systems of the present invention can be designed to control any specific architecture. For example, controllers and / or systems can be executed on one or more computers, local communication networks, local area networks, global Internet and Intranet networks, portable and other portable and wireless devices and networks.

Based on the foregoing and Figures 1-7, those skilled in the art will recognize that the present invention provides methods and devices based on MSE and / or optimization operations. In particular, one exemplary method includes detecting MSE parameters, using MSE parameters to calculate the MSE, and setting operational parameters as a function of the calculated MSE.

Another exemplary method within the scope of the present invention includes determining the baseline MSE value, changing the WOB, operating for a certain time or at a certain penetration depth, determining the updated MSE value resulting from the rig operation for a certain time, using the modified WOB and then supporting the modified WOB or reducing the previous WOB as a function of the updated MSE. This method may also include the determination of another main MSE, changing the RPM, the rig operation for a certain time or a certain depth, determining the updated MSE obtained as a result of working for a certain time or a certain depth, using a modified RPM, and then either supporting a modified RPM or lowering the previous RPM as a function of the updated MSE.

Another exemplary method within the scope of the present invention includes determining the base MSE, reducing WOB, working for a certain time or at a certain depth, determining an updated MSE value resulting from working for a certain time, using a modified WOB and then maintaining a changed WOB or reducing a previous WOB as a feature of the updated MSE. This method may further include determining another primary MSE, working for a certain time with a reduced RPM, and then either supporting the modified RPM or lowering the previous RPM as a function of the updated MSE. The method may also further include determining another base MSE, increasing the RPM, working for a certain time or at a certain depth, determining an updated MSE obtained as a result of working for a certain time at an increased RPM speed, and then either supporting the modified RPM or reducing the previous RPM as a feature of the updated MSE.

The present invention also provides an apparatus or system for operating on the basis of MSE and / or optimization, including means for detecting MSE parameters, means for using the detected MSE parameters for calculating the MSE, and means for setting operational parameters as a function of the calculated MSE.

Another exemplary device or system within the scope of the present invention comprises means for determining the base MSE, means for changing the WOB, means for working for a certain time or for a certain depth of penetration, means for determining the updated MSE as a result of working for a certain time, using the modified WOB , and a means to maintain the modified WOB or to restore the previous WOB as a function of the updated MSE. Such a device or system may further include means for determining another base MSE, means for changing the RPM, means for working for a certain time or for a certain depth of penetration, means for determining an updated MSE as a result of working for a certain time, using the changed RPM and means to maintain a modified RPM or to reduce a previous RPM as a function of an updated MSE.

Another exemplary device or system within the scope of the present invention comprises means for determining the base MSE, means for changing the WOB, means for working for a certain time or for a certain penetration depth, means for determining updated MSE as a result of working for a certain time, using reduced WOB, and a means to maintain a modified WOB or to restore a previous WOB as a function of an updated MSE. Such a device or system may further include means for determining another base MSE, means for increasing WOB, means for working for a certain time or for a certain depth of penetration, means for determining updated MSE as a result of working for a certain time, using an increased WOB, and a means to maintain an increased WOB or to restore a previous WOB as a function of an updated MSE. The device or system may further include means for determining another basic MSE, means for changing RPM, means for working for a certain time or for a certain depth of penetration, means for determining updated MSE as a result of working for a certain time using a reduced RPM, and means to maintain a reduced RPM or to restore a previous RPM as a function of the updated MSE. The device or system may further include means for determining another base MSE, means for increasing RPM, means for working for a certain time or for a certain depth of penetration, means for determining updated MSE as a result of working for a certain time using an increased RPM, and means to maintain an increased RPM or to restore a previous RPM as a function of an updated MSE.

One or more of the above-described exemplary devices or systems may include the device 100 shown in FIG. 1, the device 300 shown in FIG. 3, the device 400a shown in FIG. 4A, the device 400b shown in FIG. 4B, the device 590 shown in FIG. 5B , the device 700 shown in figure 7, and / or their components. One or more of the above-described exemplary devices or systems may be implemented as a software product. For example, one embodiment of such a software product may include a computer-readable medium and means written on a computer-readable medium to detect MSE parameters using MSE parameters to calculate the MSE and adjust operating parameters as a function of the calculated MSE.

Another exemplary software product within the scope of the present invention includes a computer-readable medium and means recorded on a computer-readable medium for determining the base MSE, changing the WOB, working for a certain time or at a certain depth of penetration, determining an updated MSE as a result of working for a certain time using a modified WOB and then supporting the modified WOB or restoring the previous WOB as a function of the updated MSE. Such a software product may also include means recorded on a computer-readable medium for determining another base MSE, changing RPM, working for a specific time or at a certain depth of penetration, determining an updated MSE as a result of working for a certain time using a modified RPM, and then maintaining Modified by RPM or restoration of a previous RPM as a function of the updated MSE.

Another exemplary software product within the scope of the present invention includes a computer-readable medium and means recorded on a computer-readable medium for determining the base MSE, reducing WOB, working for a specific time or at a certain depth of penetration, determining an updated MSE as a result of working for a certain time using reduced WOB, and maintaining a reduced WOB or restoring a previous WOB as a function of the updated MSE. Such a software product may also include means written on a computer-readable medium for determining another basic MSE, increasing WOB, working for a certain time or at a certain depth of penetration, determining an updated MSE as a result of working for a certain time using an increased WOB, and maintaining an increased WOB or restore the previous WOB as a function of the updated MSE. The software product may also include means written on a computer-readable medium to determine another base MSE by lowering RPM while working for a certain time or by a certain depth of penetration, determining updated MSE as a result of working for a certain time, using a reduced RPM, and maintaining a reduced RPM or restoring a previous RPM as a function of the updated MSE. The software product may also include means written on a computer-readable medium for determining another basic MSE, increasing RPM, working for a certain time or at a certain depth of penetration, determining an updated MSE as a result of working for a certain time using an increased RPM, and maintaining an increased RPM or restoring a previous RPM as a function of the updated MSE.

Furthermore, methods within the scope of the present invention may be local or remote in nature. For example, such methods may be deployed or performed through a PLC, PAC, PC, one or more servers, desktops, handheld computers, and / or any other type of computing device of appropriate performance.

The foregoing description provides several exemplary embodiments of the present invention so that those skilled in the art can better understand it. Skilled artisans understand that they can use the present invention as a basis for designing or modifying other processes and structures in order to achieve the same ends and / or advantages within the scope of the embodiments presented herein. Skilled artisans will also understand that such equivalent constructions do not depart from the scope of the present invention, and that they can make various changes, replacements and modifications without departing from the scope of the present invention.

Claims (13)

1. A drilling method based on mechanical specific energy (MSE), comprising:
drilling in a first interval using a first bit load (WOB);
Automatically detecting the first drilling MSE using the first WOB
drilling in a second interval using a second WOB that is different from the first WOB;
automatic detection of a second MSE corresponding to drilling using a second WOB; and
drilling in the third interval using one of the first WOB and the second WOB, selected automatically based on an automated comparison of the first MSE and the second MSE. 2. The method according to claim 1, additionally containing:
drilling in the fourth interval using the rotational speed per minute (RD-RPM) of the first rotation drive;
automatic detection of the third drilling MSE using the first RD-RPM;
drilling in the fifth interval using a second RD-RPM, which is different from the first RD-RPM;
automatic detection of the fourth drilling MSE using the second RD-RPM; and
drilling in the sixth interval using one of the first RD-RPM and the second RD-RPM, selected automatically based on an automated comparison of the third MSE and fourth MSE. 3. The method according to claim 1, in which the second WOB is smaller than the first WOB, and which further comprises:
drilling in the fourth interval using automatically selected one of the first WOB and the second WOB;
automatically detecting a third MSE corresponding to drilling in a fourth interval using the automatically selected one of the first WOB and the second WOB;
drilling in the fifth interval using a third WOB that is larger than the first WOB;
automatically detecting the fourth MSE corresponding to drilling in the fifth interval using the third WOB; and drilling in the sixth interval using the third WOB, and automatically selecting one of the first WOB and the second WOB based on an automated comparison of the third MSE and the fourth MSE. 4. The method according to claim 3, further comprising:
drilling in the seventh interval using the first rotation speed in revolutions per minute (RD-RPM) of the rotation drive;
Automatically detecting the fifth drilling MSE using the first RD-RPM
drilling in the eighth interval using a second RD-RPM that is smaller than the first RD-RPM;
automatic detection of the sixth MSE corresponding to drilling using a second RD-RPM;
drilling in the ninth interval using one of the first RD-RPM and second RD-RPM, selected automatically based on an automated comparison of the fifth MSE and sixth MSE;
drilling in the tenth interval using automatically selected one of the first RD-RPM and the second RD-RPM;
automatic determination of the seventh MSE corresponding to drilling in the tenth interval using the automatically selected one of the first RD-RPM and the second RD-RPM;
drilling in the eleventh interval using a third RD-RPM that is larger than the first RD-RPM;
automatically detecting the eighth MSE corresponding to drilling in the eleventh interval using the third RD-RPM; and
drilling in the twelfth interval using one of the third RD-RPM and automatically selected one of the first RD-RPM and second RD-RPM, selected automatically based on an automated comparison of the seventh MSE and eighth MSE. 5. Machine-readable medium containing:
machine readable medium; and
commands written in a machine-readable medium for:
drilling control in the first interval using the first bit load (WOB);
automatically detecting the first MSE corresponding to drilling in the first interval using the first WOB;
drilling control in the second interval using a second WOB that is different from the first WOB;
automatically detecting a second MSE corresponding to drilling in a second interval using a second WOB;
automatic comparison of the first MSE and the second MSE and automatic selection of one of the first WOB and second WOB as a function of the automated comparison of the first MSE and the second MSE; and drilling control in the third interval using the automatically selected one of the first WOB and the second WOB. 6. The machine-readable medium of claim 5, wherein the command further comprises instructions for:
drilling control in the fourth interval using the rotational speed per minute (RD-RPM) of the first rotation drive;
automatically detecting a third MSE corresponding to drilling using the first RD-RPM;
drilling control in the fifth interval using a second RD-RPM, which is different from the first RD-RPM;
automatically detecting the fourth MSE corresponding to drilling using the second RD-RPM;
automatic comparison of the third MSE and the fourth MSE and automatic selection of one of the first RD-RPM and the second RD-RPM as a function of the automated comparison of the third MSE and the fourth MSE; and drilling control in the sixth interval using the automatically selected one of the first RD-RPM and the second RD-RPM. 7. The computer-readable medium of claim 5, wherein the second WOB is smaller than the first WOB, and wherein the command further comprises instructions for:
drilling control in the fourth interval, using automatically selected one of the first WOB and the second WOB;
automatically detecting a third MSE corresponding to drilling in the fourth interval using the automatically selected one of the first WOB and the second WOB;
drilling control in the fifth interval using the third WOB, which is larger than the first WOB;
automatically detecting the fourth MSE corresponding to drilling in the fifth interval using the third WOB;
automatically comparing the third MSE and the fourth MSE and automatically selecting one of the third WOB and one of the first WOB and second WOB as a function of the automated comparison of the third MSE and fourth MSE; and
drilling control in the sixth interval, using automatically selected one of the third WOB and automatically selected one of the first WOB and second WOB. 8. The computer-readable medium of claim 7, wherein the command further comprises instructions for:
seventh interval drilling control using the first rotational speed per minute (RD-RPM) of the rotation drive;
automatically detecting the fifth MSE corresponding to drilling using the first RD-RPM;
drilling control in the eighth interval using a second RD-RPM that is smaller than the first RD-RPM;
automatically detecting the sixth MSE corresponding to drilling using a second RD-RPM;
automatic comparison of the fifth MSE and the sixth MSE and the automatic selection of one of the first RD-RPM and second RD-RPM as a function of the automated comparison of the fifth MSE and the sixth MSE;
drilling control in the ninth interval using automatically selected one of the first RD-RPM and the second RD-RPM;
drilling control in the tenth interval using automatically selected one of the first RD-RPM and the second RD-RPM;
automatically determining the seventh MSE corresponding to drilling in the tenth interval using the automatically selected one of the first RD-RPM and the second RD-RPM;
drilling control in the eleventh interval using the third RD-RPM, which is larger than the first RD-RPM;
automatically detecting the eighth MSE corresponding to drilling in the eleventh interval using the third RD-RPM;
automatically comparing the seventh MSE and the eighth MSE and automatically selecting one of the third and automatically selected one first RD-RPM and second RD-RPM as a function of automated comparison of the seventh MSE and eighth MSE; and
drilling control in the twelfth interval using the automatically selected third RD-RPM and to automatically select the first RD-RPM and second RD-RPM. 9. A device for drilling, including:
top drive used to rotate the drill string in the wellbore;
winches for vertical movement of the top drive to change the axial position of the drill string in the wellbore; and
a controller used to receive a plurality of MSE parameters, then to automatically detect the MSE and then to automatically generate and transmit one or more control signals to the top drive and winches to control the operation of the top drive and winches, in which the controller is used to automatically generate control signals, at least in part based on an automatically determined MSE. 10. The device according to claim 9, in which the controller is designed to:
controlling the operation of the top drive and winches during drilling in the first interval using the first bit load (WOB);
automatically detecting the first MSE corresponding to drilling in the first interval using the first WOB;
controlling the operation of the top drive and winches during drilling in the second interval using a second WOB that is different from the first WOB;
automatically detecting a second MSE corresponding to drilling in a second interval using a second WOB; and controlling the operation of the top drive and the winches during drilling in the third interval, using one of the first WOB and the second WOB, selected automatically based on an automated comparison of the first MSB and the second MSE. 11. The device according to claim 10, in which the controller is additionally designed for:
controlling the operation of the top drive and winches during drilling in the fourth interval using the first rotational speed in revolutions per minute of the top drive (TD-RPM);
automatically detecting a third MSE corresponding to drilling in a fourth interval using the first TD-RPM;
controlling the operation of the top drive and winches during drilling in the fifth interval using a second TD-RPM, which is different from the first TD-RPM;
automatically detecting a fourth MSE corresponding to drilling in a fifth interval using a second TD-RPM; and
controlling the operation of the top drive and winches during drilling in the fourth interval using one of the first TD-RPM and the second TD-RPM, selected automatically based on an automated comparison of the third MSE and fourth MSE. 12. The device according to claim 10, in which the second WOB is smaller than the first WOB, and in which the controller is further adapted to:
controlling the operation of the top drive and winches during drilling in the fourth interval using the automatically selected one of the first WOB and the second WOB;
automatically detecting a third MSE corresponding to drilling in the fourth interval using the automatically selected one of the first WOB and the second WOB;
controlling the operation of the top drive and winches during drilling in the fifth interval using a third WOB, which is larger than the first WOB;
automatically detecting the fourth MSE corresponding to drilling in the fifth interval using the third WOB; and
control the operation of the top drive and winches during drilling in the fourth interval using the third WOB, and to automatically select one of the first WOB and the second WOB, selected automatically based on an automated comparison of the third MSE and fourth MSE. 13. The device according to item 12, in which the controller is additionally designed for:
controlling the operation of the upper drive and winches during drilling in the seventh interval using the first rotational speed in revolutions per minute of the upper drive (TD-RPM);
automatically detecting the fifth MSE corresponding to drilling in the seventh interval using the first TD-RPM;
controlling the operation of the top drive and winches during drilling in the eighth interval using a second TD-RPM that is smaller than the first TD-RPM;
automatically detecting the sixth MSE corresponding to drilling in the eighth interval using the second TD-RPM;
controlling the operation of the top drive and winches during drilling in the ninth interval using one of the first TD-RPM and the second TD-RPM selected automatically based on an automated comparison of the fifth MSE and sixth MSE;
controlling the operation of the top drive and winches during drilling in the tenth interval using the automatically selected one of the first TD-RPM and the second TD-RPM;
automatically detecting a seventh MSE corresponding to drilling in a tenth interval using an automatically selected one of the first TD-RPM and the second TD-RPM;
controlling the operation of the top drive and winches during drilling in the eleventh interval using a third TD-RPM that is larger than the first TD-RPM;
automatically detecting the eighth MSB corresponding to drilling in the eleventh interval using the third TD-RPM; and
control the operation of the top drive and winches during drilling in the twelfth interval using one of the third TD-RPM and automatically selected one of the first TD-RPM and second TD-RPM, selected based on an automated comparison of the seventh MSE and eighth MSE.
Priority: from 12/07/2006, 09/21/2007, 11/06/2007 - all claims.

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