Patent Grant
9476263
1. Field of the Disclosure
The present disclosure relates generally to systems and apparatus for directional drilling of wellbores, particularly for oil and gas wells.
2. Background of the Technology
Rotary steerable systems (RSS) currently used in drilling oil and gas wells into subsurface formations commonly use tools that operate above the drill bit as completely independent tools controlled from the surface. These tools are used to steer the drill string in a desired direction away from a vertical or other wellbore orientation, such as by means of steering pads or reaction members that exert lateral forces against the wellbore wall to deflect the drill bit relative to wellbore centerline. Most of these conventional systems are complex and expensive, and have limited run times due to battery and electronic limitations. They also require the entire tool to be transported from the well site to a repair and maintenance facility when parts of the tool break down. In addition, most conventional designs require large pressure drops across the tool for the tools to work well. Currently there is no easily separable interface between RSS control systems and formation-interfacing reaction members that would allow directional control directly at the bit.
There are two main categories of rotary steerable drilling systems used for directional drilling. In “point-the-bit” drilling systems, the orientation of the drill bit is varied relative to the centerline of the drill string to achieve a desired wellbore deviation. In “push-the-bit” systems, a lateral or side force is applied to the drill string (typically at a point several feet above the drill bit), thereby deflecting the bit away from the local axis of the wellbore to achieve a desired deviation.
Rotary steerable systems currently used for directional drilling focus on tools positioned uphole of the drill bit that either push the bit with a constant force several feet above the bit, or point the bit in order to steer the bit in the desired direction. Push-the-bit systems are simpler and more robust, but have limitations due to the applied side force being several feet from the bit and thus requiring the application of comparatively large forces to deflect the bit. Without being limited by this or any particular theory, the side force necessary to induce a given bit deflection (and, therefore, a given change in bit direction) increase as the distance between the side force and the bit increases.
Examples of conventional RSS systems may be found in U.S. Pat. No. 4,690,229 (Raney); U.S. Pat. No. 5,265,682 (Russell et al.); U.S. Pat. No. 5,513,713 (Groves); U.S. Pat. No. 5,520,255 (Barr et al.); U.S. Pat. No. 5,553,678 (Barr et al.); U.S. Pat. No. 5,582,260 (Murer et al.); U.S. Pat. No. 5,706,905 (Barr); U.S. Pat. No. 5,778,992 (Fuller); U.S. Pat. No. 5,803,185 (Barr et al.); U.S. Pat. No. 5,971,085 (Colebrook); U.S. Pat. No. 6,279,670 (Eddison et al.); U.S. Pat. No. 6,439,318 (Eddison et al.); U.S. Pat. No. 7,413,413,034 (Kirkhope et al.); U.S. Pat. No. 7,287,605 (Van Steenwyk et al.); U.S. Pat. No. 7,306,060 (Krueger et al.); U.S. Pat. No. 7,810,585 (Downton); and U.S. Pat. No. 7,931,098 (Aronstam et al.), and in Int'l Application No. PCT/US2008/068100 (Downton), published as Int'l Publication No. WO 2009/002996 A1.
Most conventional RSS designs typically require large pressure drops across the bit, thus limiting hydraulic capabilities in a given well due to increased pumping horsepower requirements for circulating drilling fluid through the apparatus. Point-the-bit systems may offer performance advantages over push-the-bit systems, but they require complex and expensive drill bit designs; moreover, they can be prone to bit stability problems in the wellbore, making them less consistent and harder to control, especially when drilling through soft formations.
A push-the-bit system typically requires the use of a filter sub run above the tool to keep debris out of critical areas of the apparatus. Should large debris (e.g., rocks) or large quantities of lost circulation material (e.g., drilling fluid) be allowed to enter the valve arrangements in current push-the-bit tool designs, valve failure is typically the result. However, filter subs are also prone to problems; should lost circulation material or rocks enter and plug up a filter sub, it may be necessary to remove (or “trip”) the drill string and bit from the wellbore in order to clean out the filter.
For the foregoing reasons, there is a need in the art for rotary steerable push-the-bit drilling systems and apparatus that can deflect the drill bit to a desired extent applying lower side forces to the drill string than in conventional push-the-bit systems, while producing less pressure drop across the tool than occurs using known systems. There is also a need for rotary steerable push-the-bit drilling systems and apparatus that can operate reliably without needing to be used in conjunction with filter subs.
Push-the-bit RSS designs currently in use typically incorporate an integral RSS control system or apparatus for controlling the operation of the RSS tool. It is therefore necessary to disconnect the entire RSS apparatus from the drill string and replace it with a new one whenever it is desired to change bit sizes. This results in increased costs and lost time associated with bit changes. Accordingly, there is also a need in the art for push-the-bit RSS designs in which the RSS control apparatus is easily separable from the steering mechanism and can be used with multiple drill bit sizes.
There is a further need in the art for push-the-bit RSS systems and apparatus that can be selectively operated in either a first mode for directional drilling, or a second mode in which the steering mechanism is turned off for purposes of straight, non-deviated drilling. Such operational mode selectability will increase service life of the apparatus as well as the time between tool change-outs in the field. In addition, there is a need for such systems and apparatus that use a field-serviceable modular design, allowing the control system and components of the pushing system to be changed out in the field, thereby providing increased reliability and flexibility to the field operator, and at lower cost.
In general terms, the present disclosure teaches embodiments of push-the-bit rotary steerable drilling apparatus, also referred to as an “RSS tool,” comprising a drill bit having a cutting structure, a pushing mechanism (or “steering section”) for laterally deflecting the cutting structure by applying a side force to the drill bit, and a control assembly for actuating the pushing mechanism. As used herein, the term “drill bit” is to be understood as including both the cutting structure and the steering section, with the cutting structure being connected to the lower end of the steering section. The cutting structure may be permanently connected to or integral with the steering section, or may be releasably connected to the steering section.
The steering section of the drill bit houses one or more pistons, each having a radial stroke. The pistons are preferably, but not necessarily, uniformly circumferentially spaced about the bit, and adapted for extension radially outward from the main body of the steering section. In some embodiments, the pistons are adapted for direct contact with the wall of a wellbore drilled into a subsurface formation. In other embodiments, a reaction member, also referred to as a “reaction pad,” is provided for each piston, with the outer surfaces of the reaction members lying in a circular pattern generally corresponding to the diameter (i.e., gauge) of the wellbore and the cutting structure of the drill bit. Each reaction member is mounted to the steering section so as to extend over at least a portion of the outer face of the associated piston, such that when a given piston is extended, it reacts against the inner surface of the corresponding reaction member. The outer surface of the reaction member in turn reacts against the wall of the wellbore, such that the side force induced by extension of the piston pushes or deflects the cutting structure in a direction away from the extended piston and toward the opposite side of the wellbore. The reaction members are mounted to the steering section in a non-rigid or resilient fashion so as to be outwardly deflectable relative to the steering section to induce lateral displacement of the cutting structure relative to the wellbore when a selected piston is actuated. The pistons may be biased to the retracted positions within the steering section, such as by means of biasing springs.
The steering section is formed with one or more fluid channels, corresponding in number to the number of pistons, and each extending between the radially-inward end of a corresponding piston to a fluid inlet at the upper end of the steering section, such that a piston-actuating fluid (e.g., drilling mud) can enter any given fluid channel to actuate the corresponding piston. The fluid channels continue downward past the pistons to allow fluid to exit into the wellbore through terminal bit jets.
The control assembly of the RSS tool is disposed within a housing having a lower end connected to the upper end of the steering section. A piston-actuating fluid such as drilling mud flows downward through the housing and around the steering section. The lower end of the control assembly engages and actuates a fluid-metering assembly (e.g., valve) for directing piston-actuating fluid to one (or more) of the pistons via the corresponding fluid channels in the steering section.
In one embodiment of the RSS tool, the fluid-metering assembly comprises a generally cylindrical upper sleeve member having an upper flange and a fluid-metering slot or opening in the sleeve below the flange. The fluid-metering assembly also comprises a lower sleeve having a center bore and defining the required number of fluid inlets, with each fluid inlet being open to the center bore via an associated recess in an upper region of the lower sleeve. The lower sleeve is mounted to or integral with the upper end of the steering section. The upper sleeve is disposable within the bore of the lower sleeve, with the slot in the upper sleeve at generally the same height as the recesses in the lower sleeve. The control assembly is configured to engage and rotate the upper sleeve within the lower sleeve, such that piston-actuating fluid will flow from the housing into the upper sleeve, and then will be directed via the slot in the upper sleeve into a recess with which the slot is aligned, and thence into the corresponding fluid inlet and downward within the corresponding fluid channel in the steering section to actuate (i.e., to radially extend) the corresponding piston.
The housing and the drill bit rotate with the drill string, but the control assembly is configured to control the rotation of the upper sleeve relative to the housing. To use the apparatus to deflect or deviate a wellbore in a specific direction, the control assembly controls the rotation of the upper sleeve to keep it in a desired angular orientation relative to the wellbore, irrespective of the rotation of the drill string. In this operational mode, the fluid-metering slot in the upper sleeve will remain oriented in a selected direction relative to the earth, i.e., opposite to the direction in which it is desired to deviate the wellbore. As the lower sleeve rotates below and relative to the upper sleeve, piston-actuating fluid is directed sequentially into each of the fluid inlets, thus actuating each piston to exert a force against the wall of the wellbore, thereby pushing and deflecting the cutting structure of the bit in the opposite direction relative to the wellbore. With each momentary alignment of the upper sleeve's fluid-metering slot with one of the fluid inlets, fluid flows into that fluid inlet and actuates the corresponding piston to deflect the cutting structure in the desired lateral direction (i.e., toward the side of the wellbore opposite the actuated piston). Accordingly, with each rotation of the drill string, the cutting structure is subjected to a number of momentary pushes corresponding to the number of fluid inlets and pistons.
In an alternative embodiment, the upper and lower sleeves are adapted and proportioned such that the upper sleeve is axially movable relative to the lower sleeve, between an upper position permitting fluid to flow into all fluid inlets simultaneously, an intermediate position permitting fluid flow into only one fluid inlet at a time, and a lower position preventing fluid flow into any of the fluid inlets (in which case all of the fluid simply continues to flow downward to the cutting structure through a central bore or channel in the steering section). When the apparatus is in this latter configuration, leakage of fluid to the pistons, if any, is generally insufficient to activate the pads even though the upper sleeve may be spinning.
During operation there can be a certain amount of constant fluid flow to each piston regardless of the relative positions of the upper and lower sleeves, as the fluid-metering assembly inherently provides a leak path to all pistons via their corresponding fluid channels in the steering section of the tool. The valve design may leaks due to the use of tight fits instead of sealing elements between the two mating sleeves. Any such leak path technically is between the two sleeve elements in the small annular space between the two mating sleeves. Fluid can flow from the downhole side up through the annular space due to pressure difference between the inside of the sleeve and the lower pressure in the inactive fluid channels (i.e., fluid channels not receiving fluid flow). There is also the possibility, albeit very slight, of leakage between the top mating faces. Slots or grooves may be provided on these mating sleeve areas to allow increased leakage to the fluid channels and related passages leading to the pistons to keep them clear of cuttings during operation.
However, fluid flow to the pistons is much less when the slot in the rotating upper sleeve is not aligned with the hole in the fixed lower sleeve. Optionally, grooved slots can be provided in the top face of the fixed lower sleeve to increase the minimum constant flow to the piston chambers regardless of the position of the rotating upper sleeve.
In another embodiment of the RSS tool, the fluid-metering assembly comprises an upper plate that is coaxially rotatable (by means of the control assembly) above a fixed lower plate incorporated into the upper end of the steering section, with the fixed lower plate defining the required number of fluid inlets, which are arrayed in a circular pattern concentric with the longitudinal axis (i.e., centerline) of the steering section, and aligned with corresponding fluid channels in the steering section. The upper and lower plates are preferably made from tungsten carbide or another wear-resistant material. The upper plate has a single fluid-metering opening extending through it, offset a radial distance generally corresponding to the radius of the fluid inlets in the fixed lower plate. As the tool housing and the drill bit rotate with the drill string, the control assembly controls the rotation of the upper plate to keep it in a desired angular orientation relative to the wellbore, irrespective of the rotation of the drill string.
The rotating upper plate lies immediately above and parallel to the fixed lower plate, such that when the fluid-metering opening in the upper plate is aligned with a given fluid inlet in the fixed lower plate, piston-actuating fluid flows through the fluid-metering opening in the upper plate and the aligned fluid inlet in the fixed lower plate, and into the corresponding fluid channel in the steering section. This fluid flow causes the corresponding piston to extend radially outward from the steering section such that it reacts against its reaction member (or reacts directly against the wellbore), thereby pushing and deflecting the cutting structure of the bit in the opposite direction.
The steering section of the drill bit is preferably releasably or removably connected to the control assembly (e.g., via a conventional pin-and-box threaded connection), with the rotating upper plate being incorporated into the control assembly. This facilitates field assembly of the components to complete the RSS tool at the drilling rig site, and facilitates quick drill bit changes at the rig site, either to use a different cutting structure, or to service the steering section, without having to remove the control assembly from the drill string.
To push the cutting structure in a desired direction relative to the wellbore, the control assembly is set to keep the fluid-metering opening oriented in the direction opposite to the desired pushing direction (i.e., direction of deflection). The drill bit is rotated within the wellbore, while the upper plate is non-rotating relative to the wellbore. With each rotation of the drill bit, the fluid-metering opening in the upper plate will pass over and be momentarily aligned with each of the fluid inlets in the fixed lower plate. Accordingly, when an actuating fluid is introduced into the interior of the tool housing above the upper plate, fluid flows into each fluid channel in turn during each rotation of the drill string.
With each momentary alignment of the upper plate's fluid-metering opening with one of the fluid inlets, fluid flows into that fluid inlet and actuates the corresponding piston to push (i.e., deflect) the cutting structure in the desired lateral direction (i.e., toward the side of the wellbore opposite the actuated piston). Accordingly, with each rotation of the drill string, the cutting structure is subjected to a number of momentary pushes corresponding to the number of fluid inlets and pistons.
By means of the control assembly, the direction in which the cutting structure is pushed can be changed by rotating the upper plate to give it a different fixed orientation relative to the wellbore. However, if it is desired to use the tool for straight (i.e., non-deviated) drilling, the tool can be put into a straight-drilling mode.
By having a side force applied directly at the drill bit, close to the cutting structure, rather than at a substantial distance above the bit as in conventional push-the-bit systems, bit steerability is enhanced, and the force needed to push the bit is reduced. Lower side forces at the bit, with a bit that is kept in line with the rest of the stabilized drill string behind, also increases stability and enhances repeatability in soft formations. As used herein, the term “repeatability” is understood as denoting the ability to repeatably achieve a consistent curve radius (or “build rate”) for the trajectory of a wellbore in a given subsurface formation, independent of the strength of the formation. Without being limited by this or any particular theory, the greater the magnitude of the force applied against the wall of a wellbore by a piston in a push-the-bit drilling system, the greater will be the tendency for the piston to cut into softer formations and reduce the curvature of the trajectory of the wellbore (as compared to the effect of similar forces in harder formations). Accordingly, this tendency in softer formations is reduced by virtue of the lower piston forces required for equal effectiveness when using push-the-bit systems in accordance with embodiments described herein.
Push-the-bit rotary steerable drilling systems and apparatus in accordance with the principles described herein can be of modular design, such that any of the various components (e.g., pistons, reaction members, control assembly, and control assembly components) may be changed out in the field during bit changes. As previously noted, another advantageous feature of the embodiments described herein is that the rotating upper plate (or sleeve) of the fluid-metering assembly can be deactivated such that the tool will drill straight when deviation of the wellbore is not required, thereby promoting longer battery life (e.g., for battery-powered control assembly components) and extending the length of time that the tool can operate without changing batteries.
The control assembly for rotary steerable drilling apparatus in accordance with the principles described herein can be of any functionally suitable type. By way of one non-limiting example, the control assembly can be similar to or adapted from a fluid-actuated control assembly of the type in accordance with the vertical drilling system disclosed in International Application No. PCT/US2009/040983 (published as International Publication No. WO 2009/151786). In other embodiments, the control assembly can rotate the rotating upper plate or sleeve using, for example, an electric motor or opposing turbines.
Embodiments Incorporating Filter Module
Embodiments of rotary steerable drilling apparatus described herein having fluid-metering assemblies incorporating upper and lower sleeves may include a generally cylindrical filter module coaxially mounted between the lower end of the control assembly and the upper sleeve of the fluid-metering assembly, such that the filter module rotates with the control assembly and the upper sleeve. The filter module has a fluid passage, preferably but not necessarily in the form of a cylindrical bore, extending between an upper end in fluid communication with the annular space between the control assembly and the cylindrical housing of the apparatus, and a lower end in fluid communication with the bore of the upper sleeve of the fluid-metering assembly.
The filter module is axially movable within the housing (along with the control assembly), with an upper portion of the cylindrical outer surface of the main body of the filter module having a close tolerance tight fit within the bore of the housing, allowing passage of only very small particles. Adjacent a lower portion of the filter module body, the bore of the housing is increased in diameter, forming an annular space (or “filter annulus”) between the cylindrical outer surface of the filter module body and the housing bore. Fluid ports are provided through the cylindrical wall of the filter module body, and one or more filter elements are provided within the fluid passage of the filter module to cover the fluid ports. In one embodiment, the fluid passage is a cylindrical bore, and the filter element is a cylindrical screen fitted against the cylindrical bore so as to cover all of the fluid ports.
In operation of the apparatus, drilling fluid flows from the housing annulus into the fluid passage of the filter module, with a portion of the fluid flow being diverted radially outward through fluid ports in the filter module body and into the filter annulus. The upper sleeve of the fluid-metering assembly is provided with a radial opening through which fluid can flow from the filter annulus sequentially into the recesses in the lower sleeve of the fluid-metering assembly as the upper sleeve/filter assembly rotates within the housing, and sequentially into the fluid channels in the steering section of the drill bit to sequentially actuate the pistons housed in the steering section. As with other embodiments not including a filter module, the upper sleeve is axially movable to selectively enable fluid flow to all or none of the pistons, as may be desired to suit operational requirements.
The filter module is effectively self-cleaning due to its geometry and due to the flow of fluid through the module's fluid passage. The majority of the fluid flow through the filter module is through the fluid passage, and any fluid containing particles larger than the filter screen mesh will flow into the main fluid channel in the steering section and onward to the bit nozzles. The high-velocity fluid flow through the fluid passage tends to remove any buildup on the filter element, such that it is carried into the steering section's main fluid channel. However, should the filter element nonetheless become plugged for some reason, a flow of fluid can still reach the filter annulus through the tolerance gap between the upper portion of the filter module and the housing bore. In this way, the tolerance gap serves as a secondary filter when the filter element is plugged.
The filter module is preferably connected to the upper sleeve of the fluid-metering assembly by means of a splined connection to provide torque transfer while also facilitating preloading or biasing in the downhole direction so that the upper and lower sleeves are kept in constant engagement. The preload can be provided by any functionally suitable means, such as but not limited to mechanical biasing means (such as a spring) or hydraulic biasing means.
The preloaded filter module accommodates significant misalignment during initial make-up of the bit pin with the box of the tool housing. The filter module moves upward until the upper and lower sleeves of the fluid-metering assembly become concentric as the pin continues to make up to the housing box. Once the parts are concentric, the spring (or other preload means) ensures that the upper sleeve is pushed into its properly seated position prior to initiation of fluid flow or rotation of the rotating sleeve. This arrangement reduces the risk of component damage during the procedure of stabbing the bit/lower sleeve assembly into the housing/upper sleeve assembly.
Embodiments Incorporating Auxiliary Cutting Elements
In other alternative embodiments, the pistons or piston pads of rotary steerable drilling apparatus may incorporate auxiliary cutting elements so as to provide the tool with near-bit reaming capability. The auxiliary cutting elements allow the tool to be used to open the borehole to a diameter larger than the effective bit diameter, by retracting the control assembly and upper sleeve of the fluid-metering assembly to allow fluid to actuate all of the pistons simultaneously, in situations where it is not desired or necessary to deviate the path of the borehole. This ability to increase the diameter of the borehole may be useful in situations where the drill bit has gone “under gauge” during drilling operations due to wear. In such a scenario, the operator could activate all of the pistons so that the cutting elements on the outer faces of the pistons (or on associated piston pads) will engage the wellbore to establish (or re-establish) a wellbore diameter equal to or greater than the as-new bit diameter.
Piston pads incorporating auxiliary cutting elements can be configured to both push or cut depending on the position of the rotating sleeve relative to the fixed sleeve valve. Through the use of non-aggressive cutting elements such as torque control components (TCCs) in the piston pads, the tool would still provide a side force when the control system and valve are in “steering mode” (i.e., activating one or a few pistons to push in a specific direction). When the control system and valve are retracted in the uphole direction, the cutters would be active to effectively ream the hole, as all the cutting elements would be active simultaneously. The auxiliary cutting elements may be provided in any functionally suitable form, such as (but not limited to) polycrystalline diamond compact (PDC) cutters, PDC buttons, or tungsten carbide buttons.
Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which numerical references denote like parts, and in which:
The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” A reference to an element by the indefinite article “a” does not exclude the possibility that more than one such 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 other terms describing an interaction between elements is not intended to limit such 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”, “perpendicular”, “coincident”, “intersecting”, “equal”, “coaxial”, and “equidistant” 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.
As used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Certain components of disclosed RSS tool embodiments are described herein using adjectives such as “upper” and “lower”. Such terms are used to establish a convenient frame of reference to facilitate explanation and enhance the reader's understanding of spatial relationships and relative locations of the various elements and features of the components in question. The use of such terms is not to be interpreted as implying that they will be technically applicable in all practical applications and usages of RSS tools in accordance with the present disclosure, or that such sub tools must be used in spatial orientations that are strictly consistent with the adjectives noted above. For example, RSS tools in accordance with the present disclosure may be used in drilling horizontal or angularly-oriented wellbores. For greater certainty, therefore, the adjectives “upper” and “lower”, when used with reference to an RSS tool, should be understood in the sense of “toward the upper (or lower) end of the drill string”, regardless of what the actual spatial orientation of the RSS tool and the drill string might be in a given practical usage.
Steering section 80 has one or more fluid channels 30 extending downward from the upper end of steering section 80. As seen in
Steering section 80 defines and incorporates a plurality of piston housings 28 protruding radially outward from steering section 80 (the main body of which will typically have a diameter matching or close to that of housing 10). The radial travel of each piston 40 is preferably restricted by any suitable means (indicated by way of example in
In this embodiment, the piston-actuating fluid is a portion of the drilling fluid diverted from the fluid flowing through axial channel 22 to cutting structure 90. However, in other embodiments, the piston-actuating fluid could alternatively be a fluid different from and/or from a different source than the drilling fluid flowing to cutting structure 90.
RSS tool 100 includes a fluid-metering assembly which, in the embodiment shown in
Recesses 124 are formed in an upper region of lower sleeve 120 to provide fluid communication between each fluid inlet 122 and bore 121. Accordingly, as best shown in
The assembly and operation of the fluid-metering assembly described above can be further understood with reference to
As best shown in
Drill bit stabilization with all pistons radially extended may also be desirable during “straight” drilling to mitigate “bit whirl,” which can result in poor wellbore quality when drilling through soft formations.
To operate a fluid-metering assembly incorporating upper and lower sleeves 210 and 220 as in
As tool 100 continues rotating, the flow of actuating fluid 70A into active fluid channel 30A is blocked off, thus relieving the hydraulic force actuating piston 40A which is then refracted into the body of steering section 80. Further rotation of tool 100 causees actuating fluid to flow into the next fluid channel 30 in steering section 80, thereby actuating and extending the next piston 40 in sequence, and exerting another transverse force in contact region WX of wellbore WB.
Accordingly, for each rotation of tool 100, a bit-deflecting transverse force will be exerted against wellbore WB, in contact region WX, the same number of times as the number of fluid channels 30 in steering section 80, thus maintaining an effectively constant deflection D of cutting structure 90 in a constant transverse direction relative to wellbore WB. As a result of this deflection, the angular orientation of wellbore WB will gradually change, creating a curved section in wellbore WB.
When a desired degree of wellbore curvature or deviation has been achieved, and it is desired to drill an undeviated section of wellbore, the operation of control assembly 50 is adjusted to rotate upper sleeve 110 such that fluid-metering slot 118 is in a neutral position between an adjacent pair of recesses 124 in lower sleeve 120, such that fluid 70 cannot be diverted into any of the fluid inlets 122 in lower sleeve 120. Control assembly 50 (or an associated metering assembly engagement means) then is either disengaged from upper sleeve 110, leaving upper sleeve 110 free to rotate with lower sleeve 120 and steering section 80, or alternatively is actuated to rotate at the same rate as tool 100, thereby in either case maintaining slot 118 in a neutral position relative to lower sleeve 120 such that fluid cannot flow to any of pistons 40. Drilling operations can then be continued without any transverse force acting to deflect cutting structure 90.
In other embodiments in which the fluid-metering assembly includes axially-movable upper sleeve 210 and lower sleeve 220 as shown in
The fluid-metering assembly shown in
To transition RSS tool 200 to undeviated drilling operations, control assembly 50 is actuated to rotate upper plate 60 to a neutral position relative to lower plate such that fluid-metering hole 62 is not in alignment with any of the fluid inlets 32 in lower plate 35, and upper plate 60 is then rotated at the same rate as steering section 80 to keep fluid-metering hole 62 in the neutral position relative to lower plate 35.
In an alternative embodiment of the apparatus (not shown), upper plate 60 can be selectively moved axially and upward away from lower plate 35, thus allowing fluid flow into all fluid channels 30 and causing outward extension of all pistons 40. This results in equal transverse forces being exerted all around the perimeter of steering section 80 and effectively causing cutting structure 90 to drill straight, without deviation, while also stabilizing cutting structure 90 within wellbore WB, similar to the case for previously-described embodiments incorporating upper and lower sleeves 210 and 220 when upper sleeve 210 is in its upper position relative to lower sleeve 220. Control system 50 can be deactivated or put into hibernation mode when upper plate 60 and lower plate 35 are not in contact, thus saving battery life and wear on the control system components.
In one embodiment, control assembly 50 comprises an electronically-controlled positive displacement (PD) motor that rotates upper plate 60 (or upper sleeve 110 or 210), but control assembly 50 is not limited to this or any other particular type of mechanism.
Embodiments of steerable rotary drilling systems in accordance with the principles described herein can be readily adapted to facilitate change-out of the highly-cycled pistons during bit changes. This ability to change out the pistons independently of the control system, in a design that provides a field-changeable interface, makes the system more compact, easier to service, more versatile, and more reliable than conventional steerable systems. In addition, embodiments of RSS tools in accordance with the principles described herein also allow multiple different sizes and types of drill bits and/or pistons to be used in conjunction with the same control system without having to change out anything other than the steering system and/or cutting structure. This means, for example, that the system can be used to drill a 12¼″ (311 mm) wellbore, and subsequently be used to drill a 8¾″ (222 mm) wellbore, without changing the control system housing size, thus saving time and requiring less equipment.
The system can also be adapted to allow use of the drill bit separately from the control system. Optionally, the control assembly can be of modular design to control not only drill bits but also other drilling tools that can make beneficial use of the rotating upper plate (or sleeve) of the tool to perform useful tasks.
As best appreciated with reference to the upper portion of
As best appreciated with reference to the upper portion of
Embodiments of RSS tools in accordance with the principles described herein may use pistons of any functionally suitable type and construction, and the disclosure is not limited to the use of any particular type of piston described or illustrated herein.
As shown in particular detail in
Extending downward from cylindrical sidewall 152 are a pair of spaced, curvilinear, and diametrically-opposed sidewall extensions 156, each having a lower portion 157 formed with a circumferentially-projecting lug or stop element 157A at each circumferential end of lower portion 157. Each sidewall extension 156 can thus be described as taking the general shape of an inverted “T”, with a pair of diametrically-opposed sidewall openings 156A being formed between the two sidewall extensions 156.
Inner member 160 of piston assembly 140 has a cylindrical sidewall 161 having an upper end 160U and a lower end 160L, and enclosing a cylindrical cavity 165 which is open at each end. A pair of diametrically-opposed retainer pin openings 162 are formed through sidewall 161 for receiving a retainer pin 145 for securing inner member 160 to and within steering section 80, such that the position of inner member 160 relative to steering section 80 will be radially fixed. A pair of diametrically-opposed fluid openings 168 (semi-circular or semi-ovate in the illustrated embodiment) are formed into sidewall 161 of inner member 160, intercepting lower end 160L of inner member 160 and at right angles to retainer pin openings 162, so as to be generally aligned with corresponding fluid channels 30 when piston 40 is installed in steering section 80, to permit passage of drilling fluid downward beyond inner member 160 and into a corresponding bit jet 34 in steering section 80. As best seen in
Extending upward from cylindrical sidewall 161 are a pair of spaced, curvilinear, and diametrically-opposed sidewall extensions 163, each having an upper portion 164 formed to define a circumferentially-projecting lug or stop element 164A at each circumferential end of upper portion 164. Each sidewall extension 163 can thus be described as being generally T-shaped, with a pair of diametrically-opposed sidewall openings 163A being formed between the two sidewall extensions 163. In combination, lugs 157A and 164A thus serve as travel-limiting means defining the maximum radial stroke of outer member 150 of piston assembly 140.
As may be best understood with reference to
Biasing spring 170, shown in isometric view in
The assembly of piston assembly 140 may be best understood with reference to
Thus assembled, piston 140 incorporates biasing spring 170 with its upper (outer) end securely retained within outer member 150 and with its lower (inner) end securely retained by inner member 160. Accordingly, when a piston-actuating fluid flows into the associated fluid channel 30 in steering section 80, fluid will flow into piston 140 and exert pressure against cap member 151 of outer member 150, so as to overcome the biasing force of biasing spring 170 and extend outer member 150 radially outward from steering section 80. When the fluid pressure is relieved, biasing spring 170 will return outer member 150 to its retracted position as shown in
The assembled piston(s) 140 can then be mounted into steering section 80 as shown in
The particular configuration of biasing spring 170 shown in the Figures, and the particular means used for assembling biasing spring 170 with outer member 150 and inner member 160, are by way of example only. Persons skilled in the art will appreciate that alternative configurations and assembly means may be devised in accordance with known techniques, and such alternative configurations and assembly means are intended to come within the scope of the present disclosure.
Piston assembly 140 provides significant benefits and advantages over existing piston designs. The design of piston assembly 140 facilitates a long piston stroke within a comparatively short piston assembly, with a high mechanical return force provided by the integrated biasing spring 170. This piston assembly is also less prone to debris causing pistons to bind within the steering section or limiting piston stroke when operating in dirty fluid environments. It also allows a spring-preloaded piston assembly to be assembled and secured in place within the steering section using a simple pin, without the need to preload the spring during insertion into the steering section, making the piston assembly easier to service or replace.
Embodiments Incorporating Filter Module
Filter module 410 is axially movable within housing 10 (along with control assembly 50), with an upper portion of the cylindrical outer surface of the main body 412 of filter module 410 having a close-tolerance fit within the bore of housing 10, allowing passage of only very small particles. Adjacent a lower portion of filter module body 412, the bore of housing 10 is increased in diameter, forming an annular space (or “filter annulus”) 425 between the cylindrical outer surface of filter module body 412 and the bore of housing 10. One or more fluid ports 418 are provided through the cylindrical wall 416 of filter module body 412, and one or more filter elements 430 are provided within fluid passage 420 to cover fluid ports 418. In one embodiment, fluid passage 420 is a cylindrical bore, and filter element 430 is a cylindrical screen fitted against the cylindrical bore so as to cover all of fluid ports 430.
As illustrated in detail in
In operation of the tool 400, drilling fluid flows from housing annulus 12 into the fluid passage 420 of filter module 410 (via fluid entry ports 414 in the illustrated embodiment), with a portion of the fluid flow being diverted radially outward through fluid ports 418 through wall 416 of filter module body 412 and into filter annulus 425. The fluid exits filter annulus 425 through fluid port 506 in skirt 504 and into each recess 558 in lower sleeve 550 in sequence as upper sleeve 500 rotates around lower sleeve 550. Fluid entering each recess 558 flows through its corresponding fluid inlet in lower sleeve 550 and then into the associated fluid channel 30 in steering section 80 to actuate the associated piston 40. As with embodiments not having the filter module, upper sleeve 500 is axially movable to selectively enable fluid flow to all or none of the pistons, as may be desired to suit operational requirements.
As illustrated by way of example in
Optionally, and as shown in
As shown in
As illustrated in detail in
The operation of RSS tool 450 is otherwise similar to the operation of RSS tool 400 as previously described, with fluid entering fluid annulus 425 entering the fluid-metering assembly through fluid entry port 606 in upper sleeve 600.
Optionally, and as shown in
As shown in
Embodiments Incorporating Auxiliary Cutting Elements
While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.
This application is a continuation of U.S. application Ser. No. 13/733,703 filed Jan. 3, 2013, entitled “Rotary Steerable Push-the-Bit Drilling Apparatus with Self-Cleaning Fluid Filter,” which is a continuation-in-part of U.S. application Ser. No. 13/229,643, filed Sep. 9, 2011, and entitled “Downhole Rotary Drilling Apparatus with Formation-Interfacing Members and Control System,” and further claims the benefit of U.S. provisional application Ser. No. 61/381,243 filed Sep. 9, 2010 and U.S. provisional application Ser. No. 61/410,099 filed Nov. 4, 2010, each of which is hereby incorporated herein by reference in its entirety. Not applicable.
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| Number | Date | Country | |
|---|---|---|---|
| 20150008043 A1 | Jan 2015 | US |
| Number | Date | Country | |
|---|---|---|---|
| 61381243 | Sep 2010 | US | |
| 61410099 | Nov 2010 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13733703 | Jan 2013 | US |
| Child | 14494696 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13229643 | Sep 2011 | US |
| Child | 13733703 | US |
