Patent Grant
10358913
Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. The formations through which the wellbore passes can be evaluated for a variety of properties, including the presence of hydrocarbon reservoirs in the formation, and the direction of the wellbore may be altered to optimize the location of the well in the formation. Wellbores may be drilled using a drill bit attached to the downhole end of a string of drill pipe. A directional drilling assembly may steer the drill bit through the formations based on information collected from the surrounding formations and measurements regarding the position and/or performance of the drilling system collected at the surface or below the surface.
For example, a bottomhole assembly may include one or more sensors at or near the drill bit, the directional drilling assembly, or other components of the bottomhole assembly. The sensors may monitor the performance of the bottomhole assembly and provide information regarding the navigation of the drill bit and bottomhole assembly through the formations. The information may be received by a computing device or by an operator that may interpret the information to steer the drill bit to form the wellbore.
The one or more sensors may be part of a measurements-while-drilling (“MWD”) tool. The MWD tool may be a component of the bottomhole assembly and may be connected in series with other components of the bottomhole assembly including a motor, a logging-while-drilling (“LWD”) tool, the drill bit, the directional drilling assembly, a communications module, or other components. Each additional component included in the bottomhole assembly increases the length of the bottomhole assembly and introduces a connection that may be a potential failure point. The length of the bottomhole assembly affects the ability of the drilling system to navigate the formations and drill the wellbore.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify specific features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In a first non-limiting embodiment, a motor includes a stator with an opening therethrough. A rotor is positioned within the opening and configured to rotate relative to the stator. The rotor has a central bore therethrough with an MWD tool located in the central bore. The MWD includes an orientation measurement device, a power supply, and a communication module.
In a second non-limiting embodiment, a motor includes a stator with an opening and a longitudinal axis therethrough with a rotor positioned in the opening. The rotor is configured to rotate relative to the stator. The rotor has a central bore extending through a length of the rotor and the central bore has a front end and a second end. The motor has a first alignment member fixed relative to the stator and a second alignment member fixed relative to the rotor. An MWD tool is located in the central bore of the rotor and includes an orientation measurement device, a power supply, and a first communication module proximate the first end of the central bore. The first communication module is in data communication with at least one of the first alignment member and the second alignment member. The motor may also include a second communication module located proximate the second end of the central bore. The second communication module may be in data communication with the first communication module.
In a third non-limiting embodiment, a method of measuring physical properties in a downhole environment includes tripping a motor into a wellbore. The motor has a stator, a rotor, an MWD tool located within a central bore of the rotor. The method also includes flowing a drilling fluid through the motor to rotate the rotor relative to the stator. The flow of the drilling fluid is then stopped or reduced to stop rotational movement of the rotor relative to the stator, data is collected using the MWD tool, and the flow of drilling fluid is then increased through the motor to increase rotational movement of the rotor relative to the stator.
Additional features of embodiments of the disclosure will be set forth in the description which follows. These and other features will become more fully apparent from the following description and appended claims, or may be learned by the practice of such embodiments as set forth hereinafter.
In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, these embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:
One or more embodiments of the present disclosure will be described below. In an effort to provide a concise description of these embodiments, some features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual embodiment, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. It should further be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
One or more embodiments of the present disclosure may generally relate to devices, systems, and/or methods for collecting drilling information and/or data using a measurements-while-drilling (“MWD”) tool located inside a motor. Further, one or more embodiments disclosed herein may relate to the calibration and/or orientation of an MWD tool within a motor in a downhole environment. Further still, one or more embodiments disclosed herein may relate to devices, systems, and/or methods of collecting drilling information and/or data regarding bit speed, bottomhole assembly (“BHA”) orientation, fluid pressure, differential fluid pressure, other information, or combinations thereof during drilling fluid flow or no-flow conditions. In at least some embodiments, drilling information and/or data may be collected using an MWD tool within a motor during both drilling fluid flow and no-flow conditions. As used herein, “flow condition” may be understood to refer to a state in which drilling fluid circulates within a drilling system to provide energy to and operate a motor. “No-flow condition” may be understood to refer to a state in which drilling fluid does not circulate or circulates at a low enough rate and/or pressure that a motor does not operate (i.e., the rotor does not rotate). For example, the drilling fluid may have little or no force applied, e.g., via pump, to flow, or the drilling fluid may circulate too slowly or at too low pressure, or there is a fluid bypass in and/or around the motor that diverts fluid from the motor, each such that the motor does not operate.
A motor 102 may be positioned in the primary wellbore 120 as part of, for example, a drill string 124. The drill string 124 may include the tubular 116 and the BHA 104. The tubular 116 may include a number of components such as segmented drill pipe, coiled tubing, drill collars, transition pipe (e.g., HEVI-WATE® drill pipe), drill pipe, or similar components. The tubular 116 may transmit torque and/or longitudinal force through the primary wellbore 120 to the BHA 104. The BHA 104 may include the bit 106 configured to remove material from the formation 122 and/or to drill a lateral borehole extending from the primary wellbore 120. According to at least some embodiments, the BHA 104 may include a steerable portion 110 located on, near, or adjacent to the bit 106. In some embodiments, the steerable portion 110 may direct (i.e., guide) the bit 106. For example, the steerable portion 110 may direct the bit through the primary wellbore, a lateral borehole, or other borehole. A steerable portion 110 may be used in situations where the desired bit path is not straight or is entirely or at least partially straight. In some embodiments, the steerable portion 110 may direct both the bit 106 and the bit drive assembly 108. The bit drive assembly 108 may control rotational movement of the bit 106 relative to the BHA 104 and/or drill string 124. The BHA 104 may include a variety of sensors or data collection modules including the MWD tool. The data collection modules may collect information regarding the state of the fluid present in the formation 122, the state of the drilling system 100, other information, or combinations thereof.
The drill string 124 may transmit torque from, for example, a kelly 126 mated to a rotary table 128 at the surface. The rotary table 128 may have a kelly bushing (not shown) which may have an inside profile that may complimentarily mate with an outside profile of the kelly 126, such as a square, hexagon, or other polygonal shape that allows for the transmission of torque. The kelly 126 may move longitudinally freely relative to the rotary table 128 in order to transmit longitudinal force to the drill string 124. In other embodiments, the drill string 124 may be rotated by another torque transmitting device. For instance, a top drive (not shown) may be used to rotate the drill string 124.
The rotation and/or longitudinal movement of the drill string 124 may be controlled via a control system. The control system may receive information from, for example, the data collection modules and/or may send instructions to control the placement and/or rotational speed of the drill string 124. Where the data collection modules provide information used to direct the bit 106 within the primary wellbore 120 or drill a lateral borehole, the information may be used in a closed loop control system. For instance, pre-programmed software, hardware, firmware, or the like may enable the data collection modules to automatically steer the BHA 104 including the bit 106, when drilling the primary wellbore 120 and/or creating a lateral borehole. In other embodiments, however, the control system may be an open loop control system.
Information may be provided from the data collection modules to a controller (e.g., at the surface or in the BHA 104) or operator (e.g., at the surface). The controller or operator may review and/or process data signals received from the data collection modules and/or may provide instructions or control signals to the control system to direct drilling of the primary wellbore 120 and/or creating a lateral borehole. The data collection modules may include controllers positioned downhole and/or at the surface that may vary the operation of (e.g., steer or orient) the bit 106 or other portions of the bottomhole assembly 104. Mud pulse telemetry, wired drill pipe, fiber optic coiled tubing, wireless signal propagation, other information transmission techniques, or combinations thereof may be used to send information to or from the surface.
As shown in
The rotor 236 may rotate relative to the stator 234. The relative movement of the rotor 236 and stator 234 may provide mechanical or electrical energy to at least a portion of a BHA. For example, the relative movement of the rotor 236 and the stator 234 may provide mechanical energy to operate a bit. In another example, the relative movement of the rotor 236 and stator 234 may provide electrical energy, e.g., via a generator, to operate one or more sensors or data collection modules. In the depicted embodiment, the relative movement of the rotor 236 and the stator 234 may provide electrical energy to operate the MWD tool 232 located in the central bore 238 of the rotor 236.
The MWD tool 332 may include one or more sensors to evaluate physical properties, such as pressure, temperature, and wellbore trajectory in three-dimensional space. An incorporated MWD tool 332 may measure differential properties above and below the motor 302. For example, an incorporated MWD tool 332 may have a proximal (uphole) end 354 and a distal (downhole) end 356. The incorporated MWD tool 332 may have one or more pressure sensors at the proximal end 354 and one or more pressure sensors at the distal end 356, i.e., a pressure measurement device. The pressure sensors at the proximal end 354 may allow the incorporated MWD tool 332 to monitor the input column pressure of the drilling fluid 348 applied to the motor 302, while the pressure sensors at the distal end 356 may allow the incorporated MWD tool 332 to monitor the output pressure of the drilling fluid 348 passing through the motor 302. For example, differential pressure data may allow software or an operator to evaluate the operating efficiency of the motor 302 during operation in a downhole environment. The MWD tool 332 may have one or more sensors located adjacent the fluid bypass 352. One or more sensors adjacent the fluid bypass 352 may allow the incorporated MWD tool 332 to monitor properties independent of the drilling fluid 348 passing through the motor 302. In some embodiments, the MWD tool 332 may include geological surveying equipment, such as a gamma sensor.
The incorporated MWD tool 332 may include one or more magnetometers and/or gyroscopes to measure the orientation of the MWD tool 332 in three-dimensional space.
The one or more first alignment members 458 and one or more second alignment members 460 may be in electromagnetic communication with one another. For example, at least one of the first alignment members 458 or at least one of the second alignment members 460 may include a magnet. In some embodiments, at least one of the first alignment members 458 and/or at least one of the second alignment members 460 may be or include an electromagnet. The electromagnet may be selectively magnetized by an electrical current applied to the electromagnet. An electromagnet may selectively or continuously monitor the relative position of one or more first alignment members 458 or/and one or more second alignment members 460. In other embodiments, at least one of the first alignment members 458 and/or at least one of the second alignment members 460 may be or include a permanent magnet, such as a rare-earth magnet housed in the stator 434 or a stator tube (not shown). In yet other embodiments, at least one of the first alignment members 458 and/or at least one of the second alignment members 460 may be or include a radio frequency identification (“RFID”) device. The one or more first alignment members 458 or/and one or more second alignment members 460 may be configured to continuously monitor a position relative to one another or may selectively monitor a position, such as when the motor 402 is not operating (i.e., the drilling system is in a no-flow state). In yet further embodiments, the first alignment members 458 and/or second alignment members 460 may use mud pulse telemetry and/or electromagnetic telemetry to communicate position data to the surface.
A magnetic (e.g., ferromagnetic) stator 434 and/or rotor 436 may interfere with the positional measurements of the one or more magnetic first alignment members 458 and/or one or more magnetic second alignment members 460. The stator 434 and/or rotor 436 may be made of or include a non-magnetic material. For example, the stator 434 and/or rotor 436 may be made of or include non-magnetic stainless steel, titanium alloy, beryllium copper, aluminum alloy, other non-magnetic materials, or combinations thereof. In some embodiments, the MWD tool 432 may include one or more magnetometers and/or other orientation measurement devices. The one or more magnetometers and/or other orientation measurement devices may collect information regarding the orientation and/or position of the MWD tool 432 in three-dimensions relative to the Earth's magnetic field.
The relative rotation of the rotor 536 and stator 534 may generate electrical energy. The motor 502 may include an energy generation device 566 that generates electrical energy as a portion fixed to the rotor 536 passes a portion fixed relative to the stator 534. In some embodiments, the energy generation device 566 may be or include a dynamo. In other embodiments, the energy generation device 566 may be or include an alternator.
As shown in
Another embodiment of an MWD tool 732 that may be incorporated in a motor according to the present disclosure is depicted in
In some embodiments, the MWD tool 732 may have a first communication module 770. The first communication module 770 may be in data communication with one or more sensors, e.g., a first alignment member 458 or a second alignment member 460 of
In other embodiments, the MWD tool 732 may having a first communication module 770 and a second communication module 772. The first communication module 770 may be in data communication with one or more sensors in the MWD tool 732 and with the second communication module 772. For example, the second communication module 772 may receive data from one or more components connected to a BHA (such as BHA 104 in
The method 876 may further include transmitting the data to a remote computing device (e.g., at the surface) by either a wireless transmission, a wired transmission, direct transmission (i.e., removal of a data storage device from the MWD after removal from the wellbore), or combinations thereof. The method 876 may also include calibrating the MWD at least partially based upon the relative orientation of the rotor and stator. For example, position and/or orientation measurements may be collected by the MWD when stationary after stopping operation of the motor. The accuracy of the position and/or orientation measurements may be increased by determining the position of the rotor relative to the stator after stopping operation of the motor. In other examples, the MWD tool may collect data regarding position, orientation, pressure, temperature, rate of rotor rotation, other physical properties, or combinations thereof while the rotor is moving/rotating. The data collected while the motor is rotating may be averaged (e.g., a continuous rolling average) to reduce variations that may be imparted at least partially by the operation of the motor.
The method 876 may include receiving data from a component downhole from the motor, such as a bit, a bit drive assembly, or other component of a BHA. For example, the MWD tool may include a second communication module positioned at or near the distal (downhole) end of the MWD tool, as described in relation to
While embodiments of MWD tools have been primarily described with reference to wellbore drilling operations, the MWD tools described herein may be used in applications other than the drilling of a wellbore. In other embodiments, MWD tools according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, MWD tools of the present disclosure may be used in a borehole used for placement of utility lines, for tunneling underneath rivers, mountains and other surface features, etc. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.
The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.
Those having ordinary skill in the art will realize, in view of the present disclosure, that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. It should be understood that “proximal,” “distal,” “uphole,” and “downhole” are relative directions. As used herein, “proximal” and “uphole” should be understood to refer to a direction toward the surface, rig, operator, or the like. “Distal” or “downhole” should be understood to refer to a direction away from the surface, rig, operator, or the like.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the disclosure. The embodiments described above, therefore, are to be considered as illustrative and not restrictive. Further, the scope of the disclosure is not limited by the appended claims or the foregoing description. Accordingly, all such modifications are intended to be included within the scope of the disclosure.
The present application claims the benefit of, and priority to, U.S. Provisional Patent Application No. 62/095,172, filed Dec. 22, 2014, which is hereby incorporated by reference in its entirety.
| Number | Name | Date | Kind |
|---|---|---|---|
| 7708086 | Witte | May 2010 | B2 |
| 20020122722 | Bertin | Sep 2002 | A1 |
| 20050150689 | Jogi | Jul 2005 | A1 |
| 20060243493 | El-Rayes | Nov 2006 | A1 |
| 20130184995 | Sinclair | Jul 2013 | A1 |
| 20170051560 | Slaughter, Jr. | Feb 2017 | A1 |
| Number | Date | Country | |
|---|---|---|---|
| 20160177703 A1 | Jun 2016 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62095172 | Dec 2014 | US |
