Patent Application
20150240580
Not applicable.
The present disclosure relates generally to well-drilling methods and apparatus, and more particularly relates to methods and apparatus for controlling and adjusting the path of a wellbore.
In drilling a borehole (or wellbore) into the earth, such as for the recovery of hydrocarbons or minerals from a subsurface formation, it is conventional practice to connect a drill bit onto the lower end of a “drill string”, then rotate the drill string so that the drill bit progresses downward into the earth to create the desired borehole. A typical drill string is made up from an assembly of drill pipe sections connected end-to-end, plus a “bottomhole assembly” (“BHA”) disposed between the bottom of the drill pipe sections and the drill bit. The BHA is typically made up of sub-components such as drill collars, stabilizers, reamers and/or other drilling tools and accessories, selected to suit the particular requirements of the well being drilled.
In conventional vertical borehole drilling operations, the drill string and bit are rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig erected at the ground surface over the borehole (or in offshore drilling operations, on a seabed-supported drilling platform or suitably-adapted floating vessel). During the drilling process, a drilling fluid (commonly referred to as “drilling mud” or simply “mud”) is pumped under pressure downward from the surface through the drill string, out the drill bit into the wellbore, and then upward back to the surface through the annular space (“wellbore annulus”) between the drill string and the wellbore. The drilling fluid carries borehole cuttings to the surface, cools the drill bit, and forms a protective cake on the borehole wall (to stabilize and seal the borehole wall), as well as other beneficial functions.
As an alternative to rotation by a rotary table or a top drive, a drill bit can also be rotated using a “downhole motor” (alternatively referred to as a “drilling motor” or “mud motor”) incorporated into the drill string immediately above the drill bit. The technique of drilling by rotating the drill bit with a mud motor without rotating the drill string is commonly referred to as “slide” drilling. It is common in certain types of well-drilling operations to use both slide drilling and drill string rotation, at different stages of the operation.
One of the primary components of a downhole motor is the power section, which is commonly provided in the form of a progressive cavity motor (or “PC motor”) comprising an elongate and generally cylindrical stator plus an elongate rotor which is eccentrically rotatable within the stator. As is well known in the art, a PC motor is essentially the same thing as a positive displacement pump (or “Moineau pump”), but operated in reverse, and therefore could also be referred to as a positive displacement motor. Although all of these terms thus may be used interchangeably, for simplicity and consistency the term “PC motor” will be used throughout this patent document.
The rotor of the PC motor is formed with one or more helical vanes or lobes encircling a central shaft and extending along its length. The stator defines helical lobes of a configuration generally complementary to the rotor lobes, but numbering one more than the number of rotor lobes. In the typical operation of a downhole motor, drilling fluid flowing downward through the drill pipe assembly is diverted through the PC motor, causing the rotor to rotate within the stator, thus rotating a drive shaft and resulting in rotation of the drill bit (which is operably connected to the drive shaft through other components of the downhole motor and BHA).
A vertical wellbore (i.e., a wellbore that is intended to be vertical) can deviate from the desired vertical path during the drilling process by reason of the drill bit deflecting when encountering subsurface obstacles such as faults or discontinuities in the formation through which the well is being drilled. Such deviations must be corrected in order for the wellbore to achieve the desired end point, and it is known to correct a deviated wellbore path using an orientable steerable downhole motor in conjunction with directional drilling techniques. However, the wellbore may deviate from the desired corrective path when using a steerable downhole motor due to difficulty with controlling the orientation of the drill string and the necessity of using slide drilling techniques with this drill string configuration. Accordingly, there is a need for simpler, more reliable, and less expensive systems and associated control mechanisms for driving and steering rotating downhole tools to return a deviated vertical wellbore to a vertical path.
A directional wellbore (i.e., a wellbore or a portion of a wellbore that is intended to have a non-vertical path) requires steering during the drilling process to have the resulting wellbore reach the predetermined target. Known directional drilling techniques using an orientable, steerable downhole motor are commonly used to direct the wellbore along a desired three-dimensional path, and to correct wellbore path deviations caused by subsurface obstacles and irregularities. However, as in the previously-discussed case of deviated vertical wellbores, the use of an orientable, steerable downhole motor to correct deviated directional wellbores can be complicated or frustrated by difficulties with controlling the orientation of the drill string and the necessity of using slide drilling techniques with this drill string configuration. Accordingly, there is a further need for simpler, more reliable, and less expensive systems and associated control mechanisms for driving and steering rotating downhole tools to return a deviated directional wellbore to the intended path.
Provided in accordance with a first aspect of the present disclosure is a rotational rate control apparatus provided for use in association with a controlled device (such as, but not limited to, a deviation control assembly or, simply, “deviation assembly”) incorporated into the BHA of a drill string. Provided in accordance with a second aspect of the disclosure is a method for controlling the path of a wellbore, and for correcting deviations from a desired wellbore path, during the drilling of the wellbore.
In an embodiment, the rotational rate control apparatus of the disclosure comprises the following components in linear arrangement (beginning with the lowermost component): a progressive cavity (PC) motor; a driveshaft; a mud flow control valve; a control motor for operating the mud flow control valve; and a motor control assembly (alternatively referred to as the electronics section) for controlling the control motor.
Electric power for the apparatus is preferably provided by a battery pack disposed above the electronics section within the BHA. However, electrical power may alternatively be provided by other means such as but not limited to a power generation turbine incorporated into the BHA. The upper end of the rotational rate control apparatus as described above is connectable to the lower end of the drill pipe (or, more typically, to additional BHA sub-components which in turn connect to the drill pipe). The lower end of the rotational rate control apparatus is operably connectable to a controlled device which terminates with a drilling tool such as a drilling bit. The controlled device does not form part of the broadest embodiments of the present disclosure. In embodiments in which the controlled device comprises a deviation assembly, the deviation assembly may be of any suitable type known in the art (“point-the-bit” and “push-the-bit” systems and a steerable downhole motor being three non-limiting examples thereof).
One or more inlet ports in the lower end of the PC motor housing allow a portion of the drilling mud being pumped downward through the drill string to enter the lower end of the PC motor and to move upward therein, thus causing the PC motor to rotate in the direction opposite to its normal rotational direction (e.g., when being used to rotate a drill bit). In order for such upward mud flow to occur, one or more exit ports are provided at the upper end of the PC motor, whereby drilling mud exiting the upper end of the PC motor can flow into the well bore annulus. Mud flow through the exit ports is regulated by the mud flow control valve, which is actuated by a control motor in response to control inputs from a sensor assembly incorporated into the electronics section. The control motor preferably but not necessarily will be an electric motor. The sensor assembly may comprise one or more accelerometers, inclination sensors, pressure sensors, azimuth sensors, and/or rotational-rate sensors.
The electronics section senses the relative rotational rate of the rotational rate control apparatus and operates the control motor to actuate the mud flow control valve assembly as required to control and regulate the upward flow of drilling mud through the PC motor, as required to effect desired changes in the rate of rotation of the deviation assembly, in response to information from the sensor assembly. The PC motor drives the driveshaft and the deviation assembly (or other controlled device) at a specific zero or non-zero rotational rate. Using the mud flow control valve assembly and electronic control section, the speed of the PC motor is varied by controlled metering of the flow of drilling fluid that is directed through the PC motor.
In a first embodiment of the apparatus of the disclosure, a normally clockwise-rotating PC motor (as viewed from above) imparts a counterclockwise rotation to the deviation assembly by flowing drilling mud upward through the PC motor. An alternative second embodiment would have a normally counterclockwise-rotating PC motor delivering counterclockwise rotation to the deviation assembly by flowing drilling mud downward through the PC motor. In this embodiment, the mud inlet ports would be in an upper region of the PC motor and the mud exit ports and mud flow control valve would be at the lower end of the PC motor. A further alternative embodiment would have a PC motor configured such that clockwise rotational output is delivered to the controlled device or deviation assembly.
In accordance with the first embodiment described above, the rotor of the PC motor drives a coupling mandrel via a drive shaft, and the coupling mandrel is coupled to the controlled device (e.g., deviation assembly). By varying the relationship of the rotary speed of the PC motor compared to the rotational speed of the drill string, the tool face orientation (i.e., orientation of a drilling tool coupled to the controlled device) or non-zero rotational speed (in either direction) of the controlled device can be varied in a controlled manner. An electronically-controlled mud flow control valve assembly is used to meter the flow of drilling fluid through the PC motor, which controls the rotor's speed. In preferred embodiments, the mud flow control valve assembly comprises complementary tapered sliding sleeves which can be positioned with respect to one another to meter the flow of drilling fluid through the PC motor and into the wellbore annulus. The electronic control section and control motor are used to control the flow rate of drilling fluid through the valve assembly and to sense the orientation and direction of the tool (e.g., drilling bit), thus facilitating the return of a deviated wellbore to vertical, or the return of a directional wellbore to an intended path.
Embodiments of the disclosure will now be described with reference to the accompanying figures, in which numerical references denote like parts, and in which:
The
As illustrated in
PC motor 200 has an elongate rotor 210 disposed within the central bore 201 of an elongate stator 220, with the upper end of rotor 210 being connected to upper drive shaft 240, and with the lower end of rotor 210 being connected to a lower drive shaft 230. Rotor 210 is radially eccentrically supported within stator 220, and stator 220 is radially and axially supported within tool housing 10. Rotor 210 is connected to upper end 120 of deviation assembly 100 via lower drive shaft 230, allowing deviation assembly 100 to be rotationally driven by rotor 210. In the illustrated embodiment, PC motor 200 is configured such that rotor 210 will rotate clockwise (as viewed from above) in response to a downward flow of drilling mud through central bore 201.
A lower ported motor housing 250 having one or more inlet ports 251 (sized and positioned to suit specific requirements) is attached to the lower end of stator 220 and allows lower drive shaft 230 to pass through for operative engagement with deviation assembly 100. By virtue of inlet ports 251, central bore 201 of stator 220 is in fluid communication with inner annulus 20 of tool housing 10 such that a flow of drilling mud through inner annulus 20 may be partially diverted into and upward within central bore 201, thereby rotating rotor 210 counterclockwise (as viewed from above). In other words, a first flow path is established in the annulus 20 and a second, diverted or bypass flow path is established in the central bore 201 such that the two flow paths are overlapping. In some embodiments, the two flow paths are concentric. In this manner, the bypass flow path in the central bore 201 is a counter-flow path (i.e., in the other longitudinal direction through the tool housing 10) to the first flow path in the annulus 20, and the counter-flow path is used to drive the rotor 210. As a result, the counter-flow path driving the rotor 210 counter-rotates the rotor 210 relative to the stator 220 and tool housing 10.
Upper drive shaft 240 converts eccentric rotation of the rotor 210 within the PC motor 200 to concentric rotation of mud flow control valve assembly 300. Mud flow control valve assembly 300 includes a lower sleeve 310, an upper sleeve 320, at least one exit port sleeve 330 extending generally radially through the wall of tool housing 10, an inner valve housing 340, and an outer valve housing 350, with outer valve housing 350 being connected to or formed into the upper end of drive shaft housing 242. Upper sleeve 320 is sealingly attached to inner valve housing 340 while lower sleeve 310 is non-movingly secured to outer valve housing 350. Upper sleeve 320 is axially movable relative to lower sleeve 310, by means of a control motor 360 forming part of mud flow control valve assembly 300 and controlled by electronics section 400.
As best understood from
In preferred embodiments, inner surface 312 of lower sleeve 310 and outer surface 322 of upper sleeve 320 are in the form of mating tapered surfaces (specifically, frustoconical surfaces in the illustrated embodiments). However, persons of ordinary skill in the art will readily appreciate that lower sleeve 310 and upper sleeve 320 could be provide in other geometric configurations (including, without limitation, non-cylindrical and non-tapered sleeves) without departing from the scope and basic functionality of the present disclosure.
In an embodiment particularly suited for drilling directional wellbores, electronics section 400 comprises a computational electronic control assembly 420 and a sensor assembly 430 disposed within an electronics housing 410. Computational electronic control assembly 420 includes a microprocessor and associated memory, for receiving and processing data obtained by sensor assembly 430, as will be described. Sensor assembly 430 comprises one or more inclination sensors and/or one or more azimuth sensors (suitable types of which devices are known in the art). Electronics section 400, with the information gathered by sensor assembly 430, operates control motor 360 to regulate or stop the flow of drilling fluid through PC motor 200 and thence through drive shaft bore 244 and flow passage 375, as may be required to produce desired changes in rotational rate of the deviation assembly 100 to maintain or correct the path of a directional wellbore.
An alternative embodiment particularly suited for drilling vertical wellbores is largely similar to the embodiment described above for drilling directional wellbores, with the exception that sensor assembly 430 may but will not necessarily comprise one or more inclination sensors and/or one or more azimuth sensors. The system otherwise functions in a substantially analogous fashion to produce desired changes in rotational rate of the deviation assembly 100 to maintain or return the wellbore path to vertical.
The practical operation of the apparatus of the present disclosure may be readily understood with reference to the foregoing descriptions and to the Figures (particularly
Rotor 210 of PC motor 200 is powered by the uphole-flowing, or counter-flow, drilling mud within central bore 201 that flows at a higher pressure than the drilling mud in wellbore annulus due to the pressure drops caused by the downhole restrictions such as bit nozzles, and mud flow control valve assembly 300. The effect of drilling mud flowing through PC motor 200 in an uphole, or counter-flow, direction is to create a counterclockwise rotation of rotor 210 (as viewed from above). In typical downhole motor applications, the rotation of the drill string for purposes of drilling is clockwise. Similarly, in drilling operations using apparatus in accordance with the present disclosure, tool housing 10 rotates with the drill string in a clockwise direction, which is opposite to the rotation of rotor 210. The counterclockwise rotation, or counter-rotation, of rotor 210 is transferred to lower drive shaft 230 and deviation assembly 100, and results in a counterclockwise rotation supplied to the upper end of the deviation assembly 100 relative to the drill string. In other words, the counter-flow in the central bore 201 causes counterclockwise rotation of rotor 210, lower drive shaft 230, and deviation assembly 100 relative to the clockwise rotation of stator 220, tool housing 10, and the drill string. This may also be referred to as counter-rotation in the PC motor 200, wherein the lower components (the rotor 210, the lower drive shaft 230, and the deviation assembly 100) counter-rotate relative to the upper components (the stator 220, the tool housing 10, and the drill string).
Mud flow control valve assembly 300 is located uphole from PC motor 200 so that drilling mud exiting PC motor 200 enters into mud flow control valve assembly 300. Mud flow control valve assembly 300 is actuated by control motor 360, in response to control inputs from electronics section 400, to control the flow rate of drilling mud through PC motor 200 as required to rotate rotor 210 at an operationally appropriate rate. In this manner, the controllable valve assembly 300 receives the counter-flow diverted from the primary fluid flow M, and is controlled to adjust the flow rate of the counter-flow in the PC motor 200 and thereby adjust the rotation of the rotor 210 to a selected rate.
Electronics housing 410 rotates at the same speed as rotor 210 in PC motor 200 due to the connection of rotor 210 and electronics housing 410 via upper drive shaft 240 and mud flow control valve assembly 300. Because of the clockwise rotation of tool housing 10 and the counterclockwise rotatability of electronics housing 410, sensor assembly 430 can be kept close to geo-stationary so that it does not rotate at a significant speed or is kept at a non-zero controlled rotational rate relative to tool housing 10. The ability to maintain sensor assembly 430 close to geo-stationary or at a non-zero controlled rotational rate is controlled by the operation of mud flow control valve assembly 300. As tool housing 10 rotates with the rest of the drill string, upper sleeve 320 is adjusted in response to inputs from sensor assembly 430 to meter the flow of drilling mud upward through PC motor 200, thereby controlling the rotational rate of rotor 210 and electronics housing 410 with respect to tool housing 10 in order to keep sensor assembly 430 as close to geo-stationary as possible or rotating at a desired non-zero controlled rotational rate. The rotational rate of 430 is measured by sensors within electronics section 400, and the speed of rotation of electronics housing 410 is controlled with respect to tool housing 10 by controlling the rotational rate of rotor 210 until sensor assembly 430 is geo-stationary or rotating at a desired non-zero controlled rotational rate.
Sensor assembly 430 may comprise an inertial grade, three-axis accelerometer of a type commonly used in “measuring while drilling” (or “MWD”) operations, and functions to determine the direction, angular orientation, and speed at which to control the deviation assembly 100. In alternative embodiments, sensor assembly 430 may comprise two or three single-axis accelerometers. Sensor assembly 430 may also comprise one or more of any of the following sensors: inertial-grade azimuth sensors, rotational-rate sensors, temperature sensors, pressure sensors, gamma radiation sensors, and other sensors which would be familiar to persons skilled in the art.
Sensor assembly 430, in cooperation with other components of electronics section 400, helps to control the orientation and/or the rotational speed of deviation assembly 100 by sensing and determining the position and rotational rate, relative to the earth, of sensor assembly 430, which is coupled to deviation assembly 100. When upper sleeve 320 of flow control valve assembly 300 is in an open position, thus allowing fluid flow through PC motor 200, electronics section 400, upper sleeve 320, inner valve 340, control motor 360, and rotor 210 of PC motor 200 all rotate counterclockwise, or counter-rotate, relative to tool housing 10. Sensor assembly 430 takes readings to determine the rotational rate of sensor assembly 430 with respect to the immediate wellbore axis. The rotational rate sensed by sensor assembly 430 is conveyed to control motor 360, which correspondingly adjusts the axial position of upper sleeve 320 to change the speed of PC motor 200 as appropriate (e.g., such that the drilling tool is stationary and oriented in a desired direction, or such that the tool is rotating at a desired non-zero controlled rotational rate).
In one embodiment, the desired rotational rate is zero or geostationary, and accelerometers and/or magnetometers within sensor assembly 430 and electronics assembly 400 control the control motor 360 to orient sensor assembly 430 (which is coupled to deviation assembly 100) to a desired orientation with respect to the earth's gravitational field and/or the earth's magnetic field. Sensor assembly 430 periodically senses the orientation of the tool with respect to Earth to ensure that the tool is pointed in the desired direction and/or rotating at the desired rotational rate and to correct any deviations. When sensor assembly 430 senses that adjustment is needed, the rotational rate of rotor 210 of PC motor 200 is changed by moving upper sleeve 320, thus controlling the relative rotational speeds of rotor 210 of PC motor 200 and electronics housing 410 as appropriate to achieve a desired orientation of the tool. Once the tool is positioned as desired, the rotational rate of rotor 210 of PC motor 200 is controlled such that electronics section 400 and sensor assembly 430 remain geo-stationary.
While preferred embodiments have been shown and described herein, modifications thereof can be made by one skilled in the art without departing from the scope and teaching of the present disclosure, including modifications which may use equivalent structures or materials hereafter conceived or developed. The described and illustrated embodiments are exemplary only and are not limiting. It is to be especially understood that the substitution of a variant of a claimed element or feature, without any substantial resultant change in the working of the disclosure, will not constitute a departure from the scope of the disclosure. It is to also be fully appreciated that the different teachings of the embodiments described and discussed herein may be employed separately or in any suitable combination to produce desired results.
It should be noted in particular that the
Persons skilled in the art will also appreciate that alternative embodiments of the apparatus of the disclosure could incorporate known types of valves, adapted as appropriate, in lieu of a dual-sleeve mud flow valve assembly of the type illustrated in the Figures. To provide specific non-limiting examples, known types of ball valve, gate valve, globe valve, plug valve, needle valve, diaphragm valve, and/or butterfly valve could be adapted for use in lieu of a dual-sleeve valve assembly, without departing from the scope of the present disclosure.
For example, and with reference to
The lower mandrel 724 is coupled to a progressive cavity (PC) pump 760 via a shaft 740. In some embodiments, the shaft 740 is a flexible or flex shaft. The flex shaft 740 is coupled to a rotor 762 of the PC pump 760. The rotor 762 includes a central flow bore or passage 766. The rotor 762 is surrounded by a stator 764. The arrangement and operation of the rotor 762 and the stator 764 is consistent with the principles described elsewhere herein. Disposed between an upper end 763 of the rotor 762 and an inner surface 712 of the housing 710 is a flow control valve mechanism 790.
The flex shaft 740 includes upper flow channels or passages 748, 752 and lower flow channels or passages 742, 744. An outer surface 754 of the flex shaft 740 forms a cavity or chamber 746 with the inner tool housing surface 712. The chamber 746 is in fluid communication with the central flow passage 766 of the rotor 762 via the flow passages 748, 752. The chamber 746 is in fluid communication with the central flow passage 726 of the lower mandrel 724 via the flow passages 742, 744. In this manner, one flow path for the primary fluid flow 800 is through the central flow passage 766, the chamber 746, and the central flow passage 726.
During operation of the system 750, in some embodiments, the lower mandrel 724, the flex shaft 740, and the rotor 762 are not rotating or are rotating at the rate of the BHA. The lower mandrel 724 is coupled to the BHA, which may include a mud motor to drive the rotation of the drill bit. The remaining components of the system 750 are rotating at the rate of the drill string elements above the system 750 as coupled at the upper end 792. As torque is generated by the cutting action of the drill bit below the system 750, the torque is transmitted through the lower mandrel 724 into the rotor 762 of the PC pump 760. The torque is then transmitted to the stator 764 by pressurizing the drilling fluid between the rotor 762 and the stator 764 against the valve mechanism 790. As shown in
A portion of the diverted flow 804 is bypassed from the flow 808 at the lower end of the rotor 762 and travels upward as flow 806 through the PC pump 760 at the interface between the rotor 762 and the stator 764. The bypass flow 806 then flows to the valve mechanism 790. Consequently, the first or primary flow path 800, 802 is diverted at 804 into a second or bypass flow path 806 and a third or pass-through flow path 808. With the bypass flow path 806, the PC pump 760 achieves an overlapping counter-flow between fluid flows 802 and 806. In the embodiment shown, a portion of the system 750 includes the overlapping and opposing counter-flows 802 and 806 while another portion of the system 750 includes the pass-through flow 808. In other embodiments, the counter and pass-through flows can occupy various portions of the rotational rate control system, as is shown and consistent with the systems described elsewhere herein. In this manner, the PC pump 760 and the flex shaft 740 are configured in such a way as to pump the drilling fluid though the valve mechanism during operation of the system 750. In this embodiment, the bypass flow 806 flows in an upward direction. In other embodiments, the bypass flow 806 can flow downward, which results in the opposite directions of the counter-flows 802 and 806 being switched. In still other embodiments, the flows 802 and 806 are in the same direction, and thus not opposite counter-flows.
The rotational rate of the drilling tool or BHA below the system 750 can be controlled or set to zero by controlling the flow of the drilling fluid through the bypass flow path 806. The valve mechanism 790 can be controlled to adjust a flow passage 768 disposed at the valve mechanism and the upper end 763 of the rotor 762. As described elsewhere herein, such as with reference to control motor 360 and motor control assembly 400, electronics can be employed to control the position of the valve mechanism 790 to set the flow rate of the bypass flow 806 through the valve mechanism 790. The flow rate can be set or controlled to correlate the orientation or rotational rate of the drilling tool or BHA to a known sensor data, such as but not limited to accelerometer data to measure gravitational toolface, magnetometer data to measure magnetic toolface, or gyro data to measure rotational rate.
In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following that word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element. Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2629535 | Apr 2008 | CA | national |
This application is a continuation-in-part of U.S. application Ser. No. 12/988,274 filed Oct. 15, 2010, entitled “Method and Apparatus for Controlling Downhole Rotational Rate of a Drilling Tool,” which is the U.S. National Stage Under 35 U.S.C. §371 of International Patent Application No. PCT/US2009/040983 filed Apr. 17, 2009, which claims the benefit of Canadian Patent Application Serial No. 2,629,535 filed Apr. 18, 2008, entitled “Downhole Rotational Rate Control System.”
| Number | Date | Country | |
|---|---|---|---|
| Parent | 12988274 | Oct 2010 | US |
| Child | 14637122 | US |
