1. Field of the Disclosure
This disclosure relates generally to apparatus for use in wellbore operations that utilize progressive cavity power devices.
2. Background of the Art
To obtain hydrocarbons, such as oil and gas, boreholes or wellbores are drilled by rotating a drill bit attached to a drill string end. A large number of the current drilling activity involves drilling deviated and horizontal boreholes for hydrocarbon production. Current drilling systems utilized for drilling such wellbores generally employ a motor (commonly referred to as a “mud motor” or “drilling motor”) to rotate the drill bit. A typical mud motor includes a power section that includes a rotor having an outer lobed surface disposed inside a stator having a compatible inner lobed surface. The power section forms progressive cavities between the rotor and stator lobed surfaces. Also, certain pumps used in the oil industry utilize progressive cavity power sections. The rotor is typically made from a metal, such as steel, and includes helically contoured lobes on its outer surface. The stator typically includes a metal housing lined inside with an elastomeric material that forms helical contours or lobes on the inner surface of the stator. For high temperature applications, metal rotor and metal stator motors have been proposed. Pressurized fluid (commonly known as the “mud” or “drilling fluid”) is pumped into the progressive cavities formed between the rotor and stator lobes. The force of the pressurized fluid pumped into the cavities causes the rotor to turn in a planetary-type motion.
The disclosure herein provides progressive cavity devices, such a mud motors and pumps, that include serially coupled independent power sections or stages.
In one aspect, a drilling apparatus is disclosed that in one embodiment includes a progressive cavity device having a plurality of linearly coupled independent power sections, each such power section including a rotor disposed in a separate stator, wherein a coupling device between the independent power sections provides lateral or radial support to the adjoining rotors. In another aspect, the coupling device may also connect the adjoining stators. In another aspect, the coupled power sections may be placed in a common housing. In another aspect, the adjoining stators may be rigidly connected to each other.
In another aspect, a method of drilling a wellbore is disclosed that in one embodiment may include: deploying a drill string in the wellbore that includes a drilling motor coupled to a drill bit at an end of the drill string, wherein the drilling motor includes a plurality of linearly coupled power sections, wherein a coupling device between the power sections provides a lateral or radial support to the rotors; and supplying fluid under pressure to the drilling motor to drill the wellbore.
Examples of certain features of the apparatus and method disclosed herein are summarized rather broadly in order that the detailed description thereof that follows may be better understood. There are, of course, additional features of the apparatus and method disclosed hereinafter that will form the subject of the claims appended hereto.
The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which:
In one aspect, a suitable drilling fluid 131 (also referred to as the “mud”) from a source 132 thereof, such as a mud pit, is circulated under pressure through the drill string 120 by a mud pump 134. The drilling fluid 131 passes from the mud pump 134 into the drill string 120 via a desurger 136 and the fluid line 138. The drilling fluid 131a from the drilling tubular 122 discharges at the borehole bottom 151 through openings in the drill bit 150. The returning drilling fluid 131b circulates uphole through the annular space or annulus 127 between the drill string 120 and the borehole 126 and returns to the mud pit 132 via a return line 135 and a screen 185 that removes the drill cuttings from the returning drilling fluid 131b. A sensor S1 in line 138 provides information about the fluid flow rate of the fluid 131. Surface torque sensor S2 and a sensor S3 associated with the drill string 120 provide information about the torque and the rotational speed of the drill string 120. Rate of penetration of the drill string 120 may be determined from sensor S5, while the sensor S6 may provide the hook load of the drill string 120.
In some applications, the drill bit 150 is rotated by rotating the drill pipe 122. However, in other applications, a downhole motor 155 (mud motor) disposed in the drilling assembly 190 rotates the drill bit 150 alone or in addition to the drill string rotation.
A surface control unit or controller 140 receives signals from the downhole sensors and devices via a sensor 143 placed in the fluid line 138 and signals from sensors S1-S6 and other sensors used in the system 100 and processes such signals according to programmed instructions provided by a program to the surface control unit 140. The surface control unit 140 displays desired drilling parameters and other information on a display/monitor 141 that is utilized by an operator to control the drilling operations. The surface control unit 140 may be a computer-based unit that may include a processor 142 (such as a microprocessor), a storage device 144, such as a solid-state memory, tape or hard disc, and one or more computer programs 146 in the storage device 144 that are accessible to the processor 142 for executing instructions contained in such programs. The surface control unit 140 may further communicate with a remote control unit 148. The surface control unit 140 may process data relating to the drilling operations, data from the sensors and devices on the surface, data received from downhole devices and may control one or more operations of the
The drilling assembly 190 may also contain formation evaluation sensors or devices (also referred to as measurement-while-drilling, “MWD,” or logging-while-drilling, “LWD,” sensors) various properties of interest, such as resistivity, density, porosity, permeability, acoustic properties, nuclear-magnetic resonance properties, corrosive properties of the fluids or the formation, salt or saline content, and other selected properties of the formation 195 surrounding the drilling assembly 190. Such sensors are generally known in the art and for convenience are collectively denoted herein by numeral 165. The drilling assembly 190 may further include a variety of other sensors and communication devices 159 for controlling and/or determining one or more functions and properties of the drilling assembly 190 (such as velocity, vibration, bending moment, acceleration, oscillations, whirl, stick-slip, etc.) and drilling operating parameters, such as weight-on-bit, fluid flow rate, pressure, temperature, rate of penetration, azimuth, tool face, drill bit rotation, etc.
Still referring to
Still referring to
In another configuration, the stabilizing bearing may be made as a solid member. In one configuration, such a bearing may include no split members or screws but at least one key and an o-ring at each end. An exemplary solid bearing 600 is shown in
Referring to
In other aspects, two or more power stages may be axially coupled without a stabilizing bearing. In such a configuration, the adjoining stators alone may be keyed to one another or mechanically connected by another suitable mechanism, such as welding. Utilizing axially coupled independent stator stages permits making such stages short in length, which provides the ability to hold tighter tolerances, allows for a simpler overall machining process and the use of alternative manufacturing techniques. In other aspects, a stabilizing bearing may control the eccentric movement of the rotor during operations and control the gap between the rotor and the stator thereby reducing contact wear between the rotor and stator lobes. Such a design also does not prevent the rotor lobes from making solid contact with the stator lobes. In other aspects, a stabilizing bearing positioned between each power stage of the motor power section provides support for each of the rotors, which reduces the natural frequency of the rotors, which in turn decreases wear of the lobes, thus improving overall performance of the mud motor. Because the stabilizing bearing is relatively short in length, it allows the use of various anti-wear coating processes that often cannot be used on a rotor or stator. Such coatings result in extending the life of the entire mud motor power section. The power stages may include metal-metal rotor and stator stages or the stator lobes may be elastomeric.
While the foregoing disclosure is directed to the certain exemplary embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.
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Number | Date | Country | |
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20130175093 A1 | Jul 2013 | US |