Patent Application
20150068811
Not applicable.
The present disclosure relates in general to bearing assemblies for downhole motors used in drilling of oil, gas, and water wells. The present disclosure also relates to drive systems incorporated in such downhole motors.
In drilling a 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 an assembly of drill pipe sections connected end-to-end (commonly referred to as a “drill string”), and then rotate the drill string so that the drill bit progresses downward into the earth to create the desired wellbore. In conventional vertical wellbore 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 wellbore (or, in offshore drilling operations, on a seabed-supported drilling platform or a suitably adapted floating vessel).
During the drilling process, a drilling fluid (also commonly referred to in the industry 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 between the drill string and the wellbore. The drilling fluid, which may be water-based or oil-based, is typically viscous to enhance its ability to carry wellbore cuttings to the surface. The drilling fluid can perform various other valuable functions, including enhancement of drill bit performance (e.g., by ejection of fluid under pressure through ports in the drill bit, creating mud jets that blast into and weaken the underlying formation in advance of the drill bit), drill bit cooling, and formation of a protective cake on the wellbore wall (to stabilize and seal the wellbore wall).
Particularly since the mid-1980s, it has become increasingly common and desirable in the oil and gas industry to use “directional drilling” techniques to drill horizontal and other non-vertical wellbores, to facilitate more efficient access to and production from larger regions of subsurface hydrocarbon-bearing formations than would be possible using only vertical wellbores. In directional drilling, specialized drill string components and “bottomhole assemblies” (BHAs) are used to induce, monitor, and control deviations in the path of the drill bit, so as to produce a wellbore of desired non-vertical configuration.
Directional drilling is typically carried out using a downhole motor (commonly referred to as a “mud motor”) incorporated into the drill string immediately above the drill bit. A typical prior art mud motor includes several primary components, as follows (in order, starting from the top of the motor assembly):
The mandrel is rotated by the drive shaft, which rotates in response to the flow of drilling fluid under pressure through the power section. The mandrel rotates relative to the cylindrical housing, which is connected to the drill string.
Conventional mud motors include power sections that use either a Moineau drive system or a turbine-type drive system. These types of power sections are relatively long, with typical lengths of 15-20 feet for Moineau-type power sections and 20-30 feet for turbines for motor sizes between 5″ and 8″ in diameter. For directional drilling with a bent motor assembly, it is optimal to position the bend within a few feet of the bit in order to achieve suitable levels of hole curvature and reasonable steerability of the assembly. Having the bend located above the power section or turbine would be too great a distance from the bit to be effective, so this requires the bend to be located below the power section or turbine. The bend is typically incorporated within the drive shaft housing. The driveshaft typically comprises universal joints to accommodate the angular misalignment between the power section and bearing assembly, as well as the eccentric operation in the case of a Moineau power section. The driveshaft U-joints and threaded connections are typically the weakest parts of the motor assembly and the most common locations for fractures to occur.
U.S. Pat. No. 6,280,169, No. 6,468,061, No. 6,939,117, and No. 6,976,832 (all of which are hereby incorporated by reference in their entirety) disclose similar types of fluid-powered rotary drive mechanisms. These mechanisms are capable of outputting levels of rotary speed and torque comparable to Moineau and turbine-type power sections, but in power sections as short as one to three feet in length. These mechanisms comprise a system of longitudinal lobes and gates, with intake and exhaust ports for directing fluid to build pressure between the lobes and gates to drive the rotation of the motor. The mechanisms operate with concentric rotation between the inner shaft and outer housing. The shorter length and concentric operation allow any of these drive systems to be incorporated directly within or attached to the mud motor bearing assembly, with no need for a driveshaft assembly with universal joints. The fixed or adjustable bent housing can be attached above the drive section while maintaining a bit-to-bend length that is as short as or shorter than in conventional downhole motors. The resulting overall length of the motor is dramatically shorter than in conventional assemblies.
These drive mechanisms do not require any elastomeric elements, in contrast to Moineau-type drive systems which incorporate elastomeric stator elements that limit the operational temperature for a Moineau-type system to a maximum of about 325-350° F. Additionally, the performance of Moineau-type drive systems tapers off sharply above 140° F. Therefore, these concentrically-operating drive systems are suitable for use in extremely high temperature and geothermal applications (500+ degrees F.) that are beyond the limits of Moineau-type systems, with little or no drop in performance.
The present disclosure teaches a downhole motor incorporating a drive system comprising a system of longitudinal lobes and gates, with intake and exhaust ports for directing fluid to build pressure between the lobes and gates to drive the rotation of the motor. Preferably, the drive system is connected concentrically to the bearing assembly while maintaining a short enough length to allow the bent housing to be located above the drive section, and negating the need for a driveshaft to connect the drive section to the bearing section as in prior art mud motors. Alternatively, the bend may be positioned below the drive section in combination with the use of a driveshaft assembly to connect the drive section to the bearing section, in order to position the bend as close as possible to the bit.
In a first aspect, the present disclosure teaches a rotary fluid drive system comprising:
In certain embodiments, each gate and its associated gate pocket are relatively configured to form at least one gate pocket flow path through which fluid can flow from between the gate pocket and the gate and into the working fluid space, when the gate has swung to a maximum extent into the gate pocket. In such embodiments, each gate (which will have a free longitudinal edge) and its associated gate pocket may be relatively configured so that when a gate has swung to the maximum extent into its associated gate pocket, the longitudinal edge will face and be spaced from a wall of the gate pocket so as to create a downstream portion of the gate pocket flow path.
In certain embodiments, a plurality of spaced projections may be formed on a surface of each gate surface facing its associated gate pocket, with the space or gap between adjacent projections creating an associated upstream portion of the pocket flow path. In such embodiments, the projections and the gate pockets may be relatively configured such that the projections can abut a surface of the gate pocket when the gate is swung to the maximum extent into its associated gate pocket. Preferably, though not necessarily, the projections will be evenly spaced along a length of a respective gate. The gaps between the projections may be sized such that the cumulative length of the gaps on each gate will correspond to at least 10% of the length of the gate. In alternative embodiments, the cumulative length of the gaps may correspond to at least 30% of the gate length, and in other embodiments it may correspond to up to 90% of the gate length.
Preferably, though not necessarily, each gate may have associated biasing means (such as a spring, by way of non-limiting example) to bias the gate to swing in a direction away from its associated gate pocket and toward the body provided with the at least one lobe. In embodiments provided with biasing means comprising a spring, the spring may extend along and within a longitudinal bore formed in the associated gate. In such embodiments, one end of each spring may be held rotationally fixed relative to the associated gate; optionally, that end of each spring may be keyed into a portion of the body provided with the gate pockets.
The inlet ports may be located upstream of the outlet ports, having reference to a direction of flow of the working fluid along the fluid path.
The rotary fluid drive may include a flow control mechanism disposed within the second body at a selected point between the inlet ports and the outlet ports.
In certain embodiments of the rotary fluid drive, the first body is disposed inside the second body. In alternative embodiments, the second body is disposed inside of the first body.
In a second aspect, the present disclosure teaches a rotary fluid drive system comprising:
In certain embodiments, each gate (which will have a free longitudinal edge) and its associated gate pocket may be relatively configured so that when a gate has swung to the maximum extent into its associated gate pocket, the longitudinal edge will face and be spaced from a wall of the gate pocket so as to create a downstream portion of the gate pocket flow path.
Preferably, though not necessarily, the projections will be evenly spaced along a length of a respective gate. The gaps between the projections may be sized such that the cumulative length of the gaps on each gate will correspond to at least 10% of the length of the gate. In alternative embodiments, the cumulative length of the gaps may correspond to at least 30% of the gate length, and in other embodiments it may correspond to up to 90% of the gate length.
Preferably, though not necessarily, each gate may have associated biasing means (such as a spring, by way of non-limiting example) to bias the gate to swing in a direction away from its associated gate pocket and toward the body provided with the at least one lobe. In embodiments provided with biasing means comprising a spring, the spring may extend along and within a longitudinal bore formed in the associated gate. In such embodiments, one end of each spring may be held rotationally fixed relative to the associated gate; optionally, that end of each spring may be keyed into a portion of the body provided with the gate pockets.
The inlet ports may be located upstream of the outlet ports, having reference to a direction of flow of the working fluid along the fluid path.
The rotary fluid drive may include a flow control mechanism disposed within the second body at a selected point between the inlet ports and the outlet ports.
In a third aspect, the present disclosure teaches a drilling motor including:
In some embodiments, the gates may be supported by the housing and pivotable about a pivot axis parallel to the rotational axis. In other embodiments, the gates may be supported by the rotor and pivotable about a pivot axis parallel to the rotational axis. In still other embodiments, the gates may be radially-actuating and supported by the housing or, alternatively, radially-actuating and supported by the rotor.
The drilling motor may include biasing means associated with the gates, for biasing the gates away from the component supporting the gates.
The drilling motor may be configured such that the mandrel engages the rotor so as to be coaxially rotatable therewith. Such coaxially rotatable engagement of the mandrel and the rotor may be effected by any functionally effective means, such as, without limitation:
The housing of the drilling motor may incorporate a bent sub, which optionally may be either a fixed bent sub or an adjustable bent sub. In certain embodiments the bent sub will be located above the rotor; generally speaking, however, the location of the bent sub, when provided, will be a matter of design choice having regard to operational parameters. For example, in some embodiments a bent sub may be positioned below the rotor. In embodiments incorporating a drive shaft coaxially engaging the rotor and engaging the mandrel by means of a universal joint, a bent sub may be positioned proximal to the universal joint. In embodiments incorporating a drive shaft having upper and lower universal joints, a bent sub may be positioned between the universal joints.
In certain embodiments, the radial bearing means may be adapted to transfer radial loads from the mandrel to the housing through the rotor, such as, by way of non-limiting example, by adapting the rotor to serve as a radial bearing.
Optionally, the drilling motor may comprise flow control means, for altering the characteristics of fluid flow through the motor to regulate the rotational speed of the motor. In certain embodiments, the flow control means may be configured to allow fluid to bypass the working fluid space when the pressure differential across the working fluid space exceeds a pre-set value. In other embodiments, the flow control means may comprise, by way of non-limiting example:
Embodiments in accordance with the present disclosure will now be described with reference to the accompanying Figures, in which numerical references denote like parts, and in which:
The Figures illustrate various embodiments of downhole motors in accordance with the present disclosure.
Bearing assembly 100 includes an elongate mandrel 10 coaxially disposed within a generally cylindrical housing 20 so as to be rotatable relative thereto, with the lower end 12 of mandrel 10 projecting from the lower end 22 of housing 20 and being adapted for connection to a drill bit or other BHA components below the motor. Mandrel 10 has a central bore 14 for passage of a working fluid such as a drilling fluid. The upper end 205 of bent housing 200 is adapted for connection to the drill string or to other BHA components above the motor.
The primary features of the bearing assembly 100 and rotary drive system 110 in
In the illustrated embodiment, rotor 120 is concentrically coupled to mandrel 10 by means of a splined connection as shown in
By way of non-limiting example,
As shown in
As shown in
As best seen in
The inner surface 24 of the bore of housing 20 is formed with elongate gate pockets 26 such that as lobed rotor 120 rotates within housing 20, rotor lobes 124 will sequentially engage gates 130 and deflect them into their associated gate pockets 26 in housing 20 so that rotor lobes 124 can pass by. Each gate 130 thus pivots between a lowered position (i.e., in contact with or closely adjacent to rotor 120) when located between adjacent rotor lobes 124, and a raised (or deflected) position when displaced into its associated gate pocket 26 by a passing rotor lobe 124.
Optionally, projections 136A and gate pockets 26 may be configured such that projections 136A of a given gate 130 will abut a surface of the associated gate pocket 26 when gate 130 is maximally deflected into gate pocket 26. Preferably, projections 136A are evenly spaced along the length of gate 130. In one embodiment, the cumulative length of gaps 136B, as measured along the length of gate 130, corresponds to at least 10% of the gate length. In an alternative embodiment, the cumulative length of gaps 136B corresponds to at least 30% of the gate length. In yet another embodiment, the cumulative length of gaps 136B corresponds to as much as 90% of the gate length.
In preferred embodiments, each gate pocket 26 incorporates a debris slot or chamber 27, to accommodate or receive large particulate matter that might be present in the drilling fluid and which might otherwise impede full deflection of the associated gate 130 into gate pocket 26 by the passing rotor lobes 124. This can be best appreciated with reference to
Preferably, each gate 130 and associated gate pocket 26 are relatively configured to form at least one gate pocket flow path (denoted by dotted line 141 in
As best understood with reference to
As may be appreciated with reference to
The pivotability of gates 130 may be enabled by any suitable means, and embodiments within the scope of the present disclosure are not limited or restricted to the use of any particular pivoting means. To provide one non-limiting example, each gate 130 may be provided with a longitudinal pin bore 133 generally as shown in
Preferably, gates 130 are provided with biasing means for biasing gates 130 away from housing 20 and into substantially sealing contact with rotor 120. Such biasing means could comprise torsion rod springs, torsion coil springs, cam bodies, fluid pressure, or any other suitable mechanical or hydraulic means. In one embodiment, and with particular reference to
In the embodiment shown in
However, as may be understood with reference to
The number of rotor lobes 124 and the number of gates 130 can vary. Preferably, however, there will always be at least one fluid inlet port 116 and at least one fluid outlet port 117 located between adjacent rotor lobes 124 at any given time, and at least one gate 130 sealing between adjacent fluid inlet and outlet ports at any given time.
Torque and speed outputs of rotary drive system 110 are dependent on the length and radial height (i.e., gate lift) of chambers 140. For a given drive system length, a smaller gate lift produces higher rotational speed and lower torque. Conversely, a larger gate lift produces higher torque and lower rotational speed. In preferred embodiments, different configurations of gates 130 and rotor lobes 124, with varying levels of gate lift, can be used to achieve broad torque and speed ranges as may be required for different drilling applications, from low-speed/high-torque performance drilling to high-speed turbine applications.
Bearing assembly 100 comprises multiple bearings for transferring the various axial and radial loads between mandrel 10 and housing 20 that occur during the drilling process. Thrust bearings 102 and 103 transfer on-bottom and off-bottom operating loads, respectively, while radial bearing 104 and 105 transfers radial loads between mandrel 10 and housing 20. In preferred embodiments, the thrust bearings and radial bearings are mud-lubricated PDC (polycrystalline diamond compact) insert bearings, and a small portion of the drilling fluid is diverted through the bearings to provide lubrication and cooling. In other embodiments, other types of mud-lubricated bearings may be used, or one or more of the bearings may be oil-sealed.
In the embodiment shown in
In the alternative embodiment shown in
In preferred embodiments, no elastomeric dynamic seals are used. Leakage is minimized by maintaining small amounts of clearance between components within drive system 110. Small amounts of leakage will reduce the overall efficiency of the drive system, but that is acceptable for this application. Efficiency will still equal or exceed that of a Moineau power section. Moreover, with no elastomeric dynamic seals being used, the motor will be suitable for high-temperature/geothermal applications that Moineau power sections cannot withstand.
Notwithstanding the foregoing discussion of thrust bearings and radial bearings in downhole motor bearing sections, it is to be noted that the particular types and arrangements of bearings that may be used in bearing assemblies incorporating rotary drive systems in accordance with the present disclosure are not directly relevant to such rotary drive systems, and do not form part of the broadest embodiments thereof.
Alternatively, a mechanism similar to the two-speed motor disclosed in U.S. Pat. No. 7,523,792 (which is hereby incorporated by reference in its entirety) could also be used to allow an operator two different speed ranges at a given flow rate using the same rotary drive geometry. This would be accomplished by turning fluid flow on and off. Alternatively, this could be accomplished by an electronically-controlled valve system. This valve system could react to drilling conditions such as vibration, bit whirl, and stick slip, and/or it could be communicated with, either from surface or from a downhole signal generator, to change the amount of fluid bypass through rotor 120 in the rotary drive system.
Notwithstanding the preceding discussion, it is not essential to limit differential pressure across rotary drive systems in accordance with the present disclosure. Alternative embodiments may use other forms of flow control such as, by way of non-limiting example, a solid plate (either integral with either the mandrel or the rotor, or a separately-sealed component) to separate flow between the fluid inlet and outlet ports. Alternative embodiments may use a nozzle to continuously bypass a portion of the flow through the rotor in order to reduce the rotary speed of the drive section. Alternative embodiments may also use a burst disc to separate flow between inlet and outlet ports. In the event that the burst disc capacity is exceeded and the disc ruptures, all or a portion of the flow would subsequently bypass through the rotor. Alternative embodiments may incorporate a flow diverter as described in U.S. Pat. No. 6,976,832 to evenly distribute fluid intake and outlet flow along all or a portion of the length of the drive section.
Alternative embodiments may relieve pressure by bypassing drilling fluid directly to the annulus between housing 20 and the wellbore, or, alternatively, between bent housing 200 and the wellbore.
Another optional feature, illustrated in
In an alternative embodiment, the design could be changed to allow rotation of the stator section (housing 20 with gates 130) relative to rotor 120 and mandrel 10. This could be achieved, for example, by modifying the embodiments shown in
Alternative embodiments may use rotary drive systems generally as disclosed in any of U.S. Pat. No. 6,280,169, No. 6,468,061, and No. 6,939,117, in combination with similar coupling means within the drilling motor, and similar arrangements of bearings. These systems utilize similar principles of operation, but with alternative forms of the gate/lobe system, such as radially-actuating gates as opposed to pivoting gates, or pivoting gates connected to the mandrel and engageable by lobes formed on the bearing section housing.
For example, referring to
Having regard to the preceding discussion, it is to be appreciated that concentric rotary drive systems in accordance with the present disclosure are not limited to embodiments in which the gates are mounted to the housing (and deflectable into gate pockets formed in the housing) and in which gate-actuating lobes are incorporated into a mandrel concentrically rotatable within the housing. The present disclosure also extends to alternative embodiments having gates mounted to the mandrel (and deflectable into gate pockets formed in the mandrel) and in which gate-actuating lobes are incorporated into the housing, and also to embodiments incorporating radially-actuating gates.
Accordingly, one category of concentric rotary drive systems in accordance with the present disclosure can be broadly described as comprising:
Therefore, the component referenced previously in this Detailed Description as “housing 20” could, in alternative embodiments, be characterized as either the “first body” or the “second body”, with the component referenced as rotor 120 being characterized as either the “second body” or the “first body”. It will also be appreciated that in certain alternative embodiments the rotary drive system could be configured such that the selected body coaxially disposed within the other body could be non-rotating relative to the drill string; i.e., the other (or outer) body would be rotatable relative to the “selected” (i.e., inner) body. Persons skilled in the art will appreciate that such alternative embodiments can be put in to practice on the basis of the present disclosure, modified as a given embodiment may require having reference to the information provided herein and common general knowledge in the art, and without need for specific illustration, significant experimentation, or inventive input.
Upper U-joint 615U engages an upper drive shaft housing 620U which in turn is connected rigidly and coaxially to lower end 120L of rotor 120. In the specific embodiment shown in
The embodiments of rotary drive system 110 illustrated in the Figures may be referred to as a single-stage drive system; i.e., having a single set of gates 130 associated with a lobed rotor 120. However, alternative embodiments of rotary drive system 110 may incorporate multiple-stage drives as necessary or desirable to achieve required performance.
For embodiments having multiple power sections aligned in series, the power sections can be coupled by means of a splined and/or threaded connection, such as, for example, the connection illustrated in
In further alternative embodiments, a gear box could be incorporated into the coupling between two power sections coupled in series.
For embodiments having multiple power sections arranged to be run in parallel, two power sections as disclosed herein could be run end to end and coupled by means of splined, threaded, or clutch-type engagement as stated above. A flow diverter would be needed to send a portion of the flow past the first stage to the second stage only and then on to the bit. This flow diverter would allow flow to enter either the first stage or the second stage only, and then exit to the bit without entering the other stage. This arrangement would allow increased torque output at the same differential pressure across the rotary drive system.
It will be readily appreciated by those skilled in the art that various modifications to embodiments in accordance with the present disclosure may be devised without departing from the scope and teaching of the present teachings, including modifications which may use equivalent structures or materials hereafter conceived or developed. It is to be especially understood that the scope of the present disclosure is not intended to be limited to described or illustrated embodiments, and that the substitution of a variant of a claimed element or feature, without any substantial resultant change in functionality, will not constitute a departure from the scope of the disclosure. It is also to be 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.
In this patent document, any form of the word “comprise” is to be understood in its non-limiting sense to mean that any item following such word is 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 subject elements, and may also include indirect interaction between the elements such as through secondary or intermediary structure.
Relational terms such as “parallel”, “concentric”, and “coaxial” are not intended to denote or require absolute mathematical or geometrical precision. Accordingly, such terms are to be understood as denoting or requiring substantial precision only (e.g., “substantially parallel”) unless the context clearly requires otherwise.
Wherever used in this document, the terms “typical” and “typically” are to be interpreted in the sense of representative of common usage or practice, and are not to be interpreted as implying essentiality or invariability.
This application is a 35 U.S.C. §371 national stage application of PCT International Application Serial No. PCT/US2013/038446 filed Apr. 26, 2013, and entitled “Downhole Motor with Concentric Rotary Drive System,” which further claims the benefit of U.S. provisional patent application Ser. No. 61/639,762 filed Apr. 27, 2012, and entitled “Downhole Motor with Concentric Rotary Drive System,” both of which are hereby incorporated by reference in their entirety.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2013/038446 | 4/26/2013 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 61639762 | Apr 2012 | US |
