Patent Grant
9016400
The present disclosure relates in general to systems and apparatus for directional drilling of wellbores, particularly for oil and gas wells.
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 desired 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. Most currently-used 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 (RSS) currently used for directional drilling focus on tools that sit above the drill bit and 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. As a matter of basic physics, the side force necessary to induce a given bit deflection (and, therefore, a given change in bit direction) will increase as the distance between the side force and the bit increases.
Examples of prior art 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 (Ban 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. 7,413,034 (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.
Currently-used 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 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 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 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 (alternatively 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 bit-pushing mechanism. As used in this patent specification, 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 demountable from the steering section.
The steering section of the drill bit houses one or more pistons, each having a radial stroke. The pistons are typically (but not necessarily) spaced uniformly around the circumference of 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 (alternatively referred to as a reaction pad) may be 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 drill bit's cutting structure. 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 its 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 will push or deflect the bit's cutting structure in a direction away from the extended piston, 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, in order to induce lateral displacement of the cutting structure relative to the wellbore when a given piston is actuated. The pistons may be biased toward 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 (such as drilling mud) can enter any given fluid channel to actuate the corresponding piston. The fluid channels typically 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, the lower end of which connects 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 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 adapted 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 will rotate with the drill string, but the control assembly is adapted 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 will be directed sequentially into each of the fluid inlets, thus actuating each piston to exert a force against the wall of the wellbore, thus pushing and deflecting the bit's cutting structure 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 will flow into that fluid inlet and actuate 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 will be subjected to a number of momentary pushes corresponding to the number of fluid inlets and pistons.
In a variant embodiment, the upper and lower sleeves are adapted and proportioned such that the upper sleeve is axially movable relative to the lower sleeve, from an upper position permitting fluid to flow into all fluid inlets simultaneously, to an intermediate position permitting fluid flow into only one fluid inlet at a time, and to 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).
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 one of the fluid inlets in the fixed lower plate, piston-actuating fluid can flow 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 will cause 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), thus pushing and deflecting the bit's cutting structure in the opposite direction.
Preferably, the steering section of the drill bit is demountable from the control assembly (such as by means of 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 will flow 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 will flow into that fluid inlet and actuate 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 will be 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 (as further discussed later herein).
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. The term “repeatability”, as used in this patent specification, is understood in the directional drilling industry 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. 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 will be reduced by virtue of the lower piston forces required for equal effectiveness when using push-the-bit systems in accordance with the present disclosure.
Push-the-bit rotary steerable drilling systems and apparatus in accordance with the present disclosure may be of modular design, such that any of the various components (e.g., pistons, reaction members, control assembly, and control assembly components) can be changed out in the field during bit changes. As previously noted, another advantageous feature of the apparatus 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 thus 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 present disclosure may be of any functionally suitable type. By way of one non-limiting example, the control assembly could 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 could rotate the rotating upper plate or sleeve using, for example, an electric motor or opposing turbines.
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:
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 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 a typical case, the piston-actuating fluid will be a portion of the drilling fluid diverted from the fluid flowing through axial channel 22 to cutting structure 90. However, 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 incorporates a fluid-metering assembly which in the embodiment shown in
Recesses 124 are formed into an upper region of lower sleeve 120 to provide fluid communication between each fluid inlet 122 and bore 121. Accordingly, and as best seen in
The assembly and operation of the fluid-metering assembly described above can be further understood with reference to
As may be understood with reference to
Drill bit stabilization with all pistons 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 will be blocked off, thus relieving the hydraulic force actuating piston 40A which will then be retracted into the body of steering section 80. Further rotation of tool 100 will cause 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 may then be continued without any transverse force acting to deflect cutting structure 90.
In variant 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.
Steerable rotary drilling systems in accordance with the present disclosure 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. RSS tools in accordance with the present disclosure will 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 12-¼″ (311 mm) wellbore, and subsequently be used to drill a 8-¾″ (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
RSS tools in accordance with the present disclosure 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.
It will be readily appreciated by those skilled in the art that various modifications of embodiments taught by the present disclosure may be devised without departing from the teaching and scope of the present disclosure, including modifications that use equivalent structures or materials hereafter conceived or developed. It is especially to be understood that the present disclosure is not intended to be limited to any described or illustrated embodiment, and that the substitution of a variant of a claimed element or feature, without any substantial resultant change in operation, will not constitute a departure from the scope of the present 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 different embodiments providing desired results.
Persons skilled in the art will also appreciate that components of disclosed embodiments that are described or illustrated herein as unitary components could also be built up from multiple subcomponents without material effect on function or operation, unless the context clearly requires such components to be of unitary construction. Similarly, components described or illustrated as being assembled from multiple subcomponents may be provided as unitary components unless the context requires otherwise.
In this patent document, any form of the word “comprise” is to be understood in its non-limiting sense to indicate 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 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.
Wherever used in this document, the terms “typical” and “typically” are to be interpreted in the sense of representative or common usage or practice, and are not to be understood as implying essentiality or invariability.
In this patent document, certain components of disclosed RSS tool embodiments are described 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. The proper and intended interpretation of the adjectives “inner”, “outer”, “upper”, and “lower” for specific purposes of illustrated piston assemblies and components thereof will be apparent from corresponding portions of the Detailed Description.
This application claims the benefit of U.S. Provisional Application No. 61/381,243 , filed on Sep. 9, 2010 , and U.S. Provisional Application No. 61/410,099 , filed on Nov. 4, 2010 , and said earlier applications are incorporated herein by reference in their entirety for continuity of disclosure.
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