Patent Grant
9016401
This application is a U.S. national stage of International Patent Application No. PCT/US2012/042069, filed Jun. 12, 2012, the contents of which are incorporated herein by reference in its entirety.
The present disclosure relates generally to the drilling of boreholes, for example, during hydrocarbon exploration and excavation. More particularly, the present disclosure relates to steering apparatuses and steering actuators for directing drilling assemblies.
Boreholes, which are also commonly referred to as “wellbores” and “drill holes,” are created for a variety of purposes, including exploratory drilling for locating underground deposits of different natural resources, mining operations for extracting such deposits, and construction projects for installing underground utilities. A common misconception is that all boreholes are vertically aligned with the drilling rig; however, many applications require the drilling of boreholes with vertically deviated and horizontal geometries. A well-known technique employed for drilling horizontal, vertically deviated, and other complex boreholes is directional drilling. Directional drilling is generally typified as a process of boring a hole which is characterized in that at least a portion of the course of the bore hole in the earth is in a direction other than strictly vertical—i.e., the axes make an angle with a vertical plane (known as “vertical deviation”), and are directed in an azimuth plane.
Conventional directional boring techniques traditionally operate from a boring device that pushes or steers a series of connected drill pipes with a directable drill bit at the distal end thereof to achieve the borehole geometry. In the exploration and recovery of subsurface hydrocarbon deposits, such as petroleum and natural gas, the directional borehole is typically drilled with a rotatable drill bit that is attached to one end of a bottom hole assembly or “BHA.” A steerable BHA can include, for example, a positive displacement motor (PDM) or “mud motor,” drill collars, reamers, shocks, and underreaming tools to enlarge the wellbore. A stabilizer may be attached to the BHA to control the bending of the BHA to direct the bit in the desired direction (inclination and azimuth). The BHA, in turn, is attached to the bottom of a tubing assembly, often comprising jointed pipe or relatively flexible “spoolable” tubing, also known as “coiled tubing.” This directional drilling system—i.e., the operatively interconnected tubing, drill bit, and BHA—can be referred to as a “drill string.” When jointed pipe is utilized in the drill string, the drill bit can be rotated by rotating the jointed pipe from the surface, through the operation of the mud motor contained in the BHA, or both. In contrast, drill strings which employ coiled tubing generally rotate the drill bit via the mud motor in the BHA.
Directional drilling typically requires controlling and varying the direction of the wellbore as it is being drilled. Oftentimes the goal of directional drilling is to reach a position within a target subterranean destination or formation with the drill string. For instance, the drilling direction may be controlled to direct the wellbore towards a desired target destination, to control the wellbore horizontally to maintain it within a desired payzone, or to correct for unwanted or undesired deviations from a desired or predetermined path. Frequent adjustments to the direction of the wellbore are often necessary during a drilling operation, either to accommodate a planned change in direction or to compensate for unintended or unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottomhole drilling assembly, and the manner in which the wellbore is being drilled, as some non-limiting examples.
Various options are available for providing steering capabilities to a drilling tool for controlling and varying the direction of the wellbore. In directional drilling applications, for example, one option is to attach a bent-housing or a bent-sub downhole drilling motor to the end of the drilling string as a steering tool. When steering is required, the drill-pipe section of the drilling string can be restrained against rotation and the drilling motor can be pointed in a desired direction and operated for both drilling and steering in a “sliding drilling” mode. When steering is not required, the drilling string and the drilling motor can be rotated together in a “rotary drilling” mode. An advantage to this option is its relative simplicity. One disadvantage to this option, however, is that steering is typically limited to the sliding drilling mode. In addition, the straightness of the borehole in rotary drilling mode may be compromised by the presence of the bent drilling motor. Furthermore, since the drill pipe string is not rotated during sliding drilling, it is more susceptible to sticking in the wellbore, particularly as the angle of deflection of the wellbore from the vertical increases, resulting in reduced rates of penetration.
Directional drilling may also be accomplished with a “rotary steerable” drilling system wherein the entire drill pipe string is rotated from the surface, which in turn rotates the bottomhole assembly, including the drilling bit, connected to the end of the drill pipe string. In a rotary steerable drilling system, the drilling string may be rotated while the drilling tool is being steered either by being pointed or pushed in a desired direction (directly or indirectly) by a steering device. Some rotary steerable drilling systems include a component which is non-rotating relative to the drilling string in order to provide a reference point for the desired direction and a mounting location for the steering device(s). Alternatively, a rotary steerable drilling system may be “fully rotating”. Some advantages to rotary steerable drilling systems are that they can provide relatively high steering accuracy and they need not be operated in a sliding drilling mode to provide steering capabilities. In addition, the rate of penetration tends to be greater, while the wear of the drilling bit and casing are often reduced. However, rotary steerable drilling systems are relatively complex apparatuses and tend to be more expensive than their conventional counterparts.
As a third option, directional drilling may be accomplished using a combination of both rotary steerable drilling and sliding drilling. Rotary steerable drilling will typically be performed until such time that a variation or change in the direction of the wellbore is desired. At this point, rotation of the drill pipe string is stopped and sliding drilling, through use of the downhole motor, is commenced. Although the use of a combination of sliding and rotary drilling may permit satisfactory control over the direction of the wellbore, many of the problems and disadvantages associated with sliding drilling are still encountered.
Various attempts have been made to provide rotary steerable drilling systems which address these problems. Numerous examples of prior art rotary steerable drilling apparatuses are disclosed in U.S. Pat. No. 6,769,499, to Edward J. Cargill et al., and U.S. Pat. No. 7,413,034, to Kennedy Kirkhope, both of which are incorporated herein by reference in their respective entireties and for all purposes. In many of these disclosed configurations, however, servicing the individual actuators often requires opening the steering tool, which is typically a very complicated and time consuming process. Exposing the internal hydraulics of the steering system is also generally not desirable due to environmental corrosion and other deleterious effects. In addition, once replaced, each of the actuators must then be tested at the rig site to ensure proper functionality, which adds to downtime and repair costs. There remains a need for improved and simplified rotary steerable drilling configurations which reduce servicing costs and down time, simplify installment and testing, and minimize environmental exposure of the tool.
Aspects of the present disclosure are directed to modular rotary steerable actuators which package all of the components necessary to provide the functionality of a steering actuator into a single cartridge that is mounted to the exterior of the steering tool. In some configurations, the modular actuator is a self-contained apparatus with a pump, a fluid reservoir, a pressure compensator piston, a solenoid control valve, and an actuator piston, all of which are packaged in a common housing. By limiting external connections to electrical control logic, the modular actuator can reduce leak points and permits oil filling and verification of “on the shelf” cartridges. The foregoing configuration also allows for ease of replacement of the individual actuators from outside the steering tool with only electrical control and positional feedback connections. The modular actuator also provides the benefits and capabilities of a hydraulic actuator without the “at rig” servicing complications often associated with prior art directional steering systems. Another advantage is the ability to stock complete replacement actuator cartridges that quickly and easily replace onboard cartridges to rapidly return the steering tool to downhole readiness. Isolating the hydraulic circuits also help to simplify differing system pressures. Another advantage is the ability to use more of the common cartridges to scale into larger tools.
Some embodiments of the present disclosure are directed to a steering tool for use in drilling a borehole. The steering tool may be used, for example, for drilling vertical and/or non-vertical boreholes. The steering tool is a hydro-mechanical tool with a plurality of self-contained, separately actuable, circumferentially spaced modular actuators. The steering tool is intended to be incorporated into a drill string. The steering tool may be incorporated into a drill string in several different configurations depending, for example, on the intended drilling application. In some configurations, the steering tool is configured as a component of a drilling motor. The steering tool can also be adapted as a component of a rotary steerable drilling system. In some configurations, the steering tool is adapted as a component of a fully rotating rotary steerable drilling system.
Aspects of the present disclosure are directed to a modular actuator for use in directing a drill string, which includes a housing and a drive shaft. The modular actuator includes a cartridge that is configured to couple to the outer periphery of the drill string housing. A fluid reservoir is contained within the cartridge. A hydraulically actuated actuator piston, which is slidably disposed at least partially inside the cartridge, is movable between first and second positions. A hydraulic control system is also contained within the cartridge, fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate movement of the actuator piston between the first and second positions such that the actuator piston selectively moves the drive shaft and thereby changes the direction of the drill string.
According to other aspects of the present disclosure, a steering tool is presented for use in directing a drill string when drilling a borehole in an earth formation. The drill string includes a drive shaft and a swash plate. The steering tool includes a tubular housing with an exterior surface and a housing bore configured to receive therethrough the drive shaft. The steering tool also includes a plurality of modular actuators circumferentially spaced about the exterior surface of the housing. Each of the modular actuators includes: a cartridge coupled to the exterior surface of the housing; a fluid reservoir sealed within the cartridge; a hydraulically actuated actuator piston slidably disposed at least partially inside the cartridge, the actuator piston being movable between deactivated and activated positions; and, a hydraulic control system sealed within the cartridge and fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate the movement of the actuator piston between the deactivated and activated positions such that the actuator piston selectively moves the drive shaft and thereby changes the direction of the drill string.
A rotary steerable drilling system is also featured in accordance with aspects of this disclosure. The rotary steerable drilling system includes a drill-pipe string and a tubular housing operatively coupled to a distal end of the drill-pipe string. The tubular housing has an exterior surface and a housing bore. A drive shaft, which extends through the tubular housing, includes a plurality of ramped surfaces. A drill bit is rotatably coupled to the tubular housing via the drive shaft. The rotary steerable drilling system also includes a steering controller and a plurality of modular actuators circumferentially spaced about the exterior surface of the housing. Each of the modular actuators includes: a cartridge coupled to the exterior surface of the housing; an electrical connector electrically connecting the modular actuator with the steering controller; a fluid reservoir sealed within the cartridge; a hydraulically actuated actuator piston slidably disposed at least partially inside the cartridge, the piston being movable between deactivated and activated positions; and, a hydraulic control system sealed within the cartridge and fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate movement of the actuator piston from the deactivated position to the activated position such that the actuator piston selectively presses against one of the ramped surfaces of the drive shaft and thereby changes the direction of the drill string.
The above summary is not intended to represent each embodiment or every aspect of the present disclosure. Rather, the foregoing summary merely provides an exemplification of some of the novel aspects and features set forth herein. The above features and advantages, and other features and advantages of the present disclosure, will be readily apparent from the following detailed description of the exemplary embodiments and modes for carrying out the present invention when taken in connection with the accompanying drawings and appended claims.
While the present disclosure is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. It should be understood, however, that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.
While this invention is susceptible of embodiment in many different forms, there are shown in the drawings and will herein be described in detail embodiments of the invention with the understanding that the present disclosure is to be considered as an exemplification of the principles of the invention and is not intended to limit the broad aspects of the invention to the embodiments illustrated. To that extent, elements and limitations that are disclosed, for example, in the Abstract, Summary, and Detailed Description sections, but not explicitly set forth in the claims, should not be incorporated into the claims, singly or collectively, by implication, inference or otherwise. For purposes of the present detailed description, unless specifically disclaimed, the singular includes the plural and vice versa; the words “and” and “or” shall be both conjunctive and disjunctive; the word “all” means “any and all”; the word “any” means “any and all”; and the word “including” means “including without limitation.” Moreover, words of approximation, such as “about,” “almost,” “substantially,” “approximately,” and the like, can be used herein in the sense of “at, near, or nearly at,” or “within 3-5% of;” or “within acceptable manufacturing tolerances,” or any logical combination thereof, for example.
Referring now to the drawings, wherein like reference numerals refer to like components throughout the several views,
The directional drilling system 10 exemplified in
A drill bit 50 is attached to the distal, downhole end of the drill string 20. When rotated, e.g., via the rotary table 14, the drill bit 50 operates to break up and generally disintegrate the geological formation 46. The drill string 20 is coupled to a “drawworks” hoisting apparatus 30, for example, via a kelly joint 21, swivel 28, and line 29 through a pulley system (not shown). The drawworks 30 may comprise various components, including a drum, one or more motors, a reduction gear, a main brake, and an auxiliary brake. During a drilling operation, the drawworks 30 can be operated, in some embodiments, to control the weight on bit 50 and the rate of penetration of the drill string 20 into the borehole 26. The operation of drawworks 30 is generally known and is thus not described in detail herein.
During drilling operations, a suitable drilling fluid (commonly referred to in the art as “mud”) 31 can be circulated, under pressure, out from a mud pit 32 and into the borehole 26 through the drill string 20 by a hydraulic “mud pump” 34. The drilling fluid 31 may comprise, for example, water-based muds (WBM), which typically comprise a water-and-clay based composition, oil-based muds (OBM), where the base fluid is a petroleum product, such as diesel fuel, synthetic-based muds (SBM), where the base fluid is a synthetic oil, as well as gaseous drilling fluids. Drilling fluid 31 passes from the mud pump 34 into the drill string 20 via a fluid conduit (commonly referred to as a “mud line”) 38 and the kelly joint 21. Drilling fluid 31 is discharged at the borehole bottom 54 through an opening or nozzle in the drill bit 50, and circulates in an “uphole” direction towards the surface through an annular space 27 between the drill string 20 and the side 56 of the borehole 26. As the drilling fluid 31 approaches the rotary table 14, it is discharged via a return line 35 into the mud pit 32. A variety of surface sensors 48, which are appropriately deployed on the surface of the borehole 26, operate alone or in conjunction with downhole sensors 70, 72 deployed within the borehole 26, to provide information about various drilling-related parameters, such as fluid flow rate, weight on bit, hook load, etc., which will be explained in further detail below.
A surface control unit 40 may receive signals from surface and downhole sensors and devices via a sensor or transducer 43, which can be placed on the fluid line 38. The surface control unit 40 can be operable to process such signals according to programmed instructions provided to surface control unit 40. Surface control unit 40 may present to an operator desired drilling parameters and other information via one or more output devices 42, such as a display, a computer monitor, speakers, lights, etc., which may be used by the operator to control the drilling operations. Surface control unit 40 may contain a computer, memory for storing data, a data recorder, and other known and hereinafter developed peripherals. Surface control unit 40 may also include models and may process data according to programmed instructions, and respond to user commands entered through a suitable input device 44, which may be in the nature of a keyboard, touchscreen, microphone, mouse, joystick, etc.
In some embodiments of the present disclosure, the rotatable drill bit 50 is attached at a distal end of a steerable drilling bottom hole assembly (BHA) 22. In the illustrated embodiment, the BHA 22 is coupled between the drill bit 50 and the drill pipe section 24 of the drill string 20. The BHA 22 may comprise a Measurement While Drilling (MWD) System, designated generally at 58 in
In some embodiments, a mud pulse telemetry technique may be used to communicate data from downhole sensors and devices during drilling operations. Exemplary methods and apparatuses for mud pulse telemetry are described in U.S. Pat. No. 7,106,210 B2, to Christopher A. Golla et al., which is incorporated herein by reference in its entirety. Other known methods of telemetry which may be used without departing from the intended scope of this disclosure include electromagnetic telemetry, acoustic telemetry, and wired drill pipe telemetry, among others.
A transducer 43 can be placed in the mud supply line 38 to detect the mud pulses responsive to the data transmitted by the downhole transmitter 33. The transducer 43 in turn generates electrical signals, for example, in response to the mud pressure variations and transmits such signals to the surface control unit 40. Alternatively, other telemetry techniques such as electromagnetic and/or acoustic techniques or any other suitable techniques known or hereinafter developed may be utilized. By way of example, hard wired drill pipe may be used to communicate between the surface and downhole devices. In another example, combinations of the techniques described may be used. As illustrated in
According to aspects of this disclosure, the BHA 22 can provide some or all of the requisite force for the bit 50 to break through the formation 46 (known as “weight on bit”), and provide the necessary directional control for drilling the borehole 26. In the embodiments illustrated in
As shown in the embodiment of
In the embodiment illustrated in
A rotatable drill bit (e.g., drill bit 50 of
The motor assembly 114 of
The distal end of the rotor is coupled to the rotatable drill bit via the drive shaft 118 and bit sub 120 such that the eccentric power from the rotor is transmitted as concentric power to the bit. In this manner, the PDM motor assembly 114 can provide a drive mechanism for the drill bit which is at least partially and, in some instances, completely independent of any rotational motion of the drill string generated, for example, via rotation of a top drive in the derrick mast and/or the rotary table 14 on the derrick floor 12 of
An external surface 117 of the housing 116 shown in
Each modular actuator 124A-D includes a respective cartridge 128A, 128B, 128C and 128D that is configured to couple to the outer periphery of the housing 116. As seen in
In the illustrated example, the first piston 132 faces “uphole” and translates generally rectilinearly along a common axis with the second piston 134, which faces and translates generally rectilinearly “downhole.” The pistons 132, 134 are movable from respective first “deactivated” positions (e.g., 132′ and 134′ in
In applications where larger forces are required (e.g., for larger tools), the drill string system 100 can employ additional and/or larger modular actuators 124. For instance, larger forces can be acquired by use of additional modular actuators 124 that are slightly out of plane with the primary modular actuators 124 (e.g., the four shown in
A first return spring 136 biases the first piston 132 towards the deactivated position 132′, whereas a second return spring 138 biases the second piston 134 towards the deactivated position 134′. The rotary steering tool assembly 112 can be a “normally open” design. By way of non-limiting example, the second return spring 138 biases the actuator piston 134 towards the deactivated position 134″. In this optional configuration, when one of the modular actuators 124 is deactivated or otherwise rendered inoperable, the corresponding actuator piston 134 is biased away from the shaft ramp 140 and toward the deactivated position 134′ via the return spring 138, and the ramped surface of the actuator piston 134 does not apply a steering force to the drive shaft 118 via the shaft ramp 140. With all of the deactivated modular actuators 128 being biased out of steering engagement with the drive shaft 118, the rotary steering tool assembly 112 is a normally open “fail safe” configuration, which helps to ensure that the steering system defaults into a straight ahead condition, for example, on failure of the steering electronics. The first return spring 136 is shown loaded into a side window 144 of the cartridge 128 installed outside of an internal oil environment 146 to maximize useable oil space inside the cartridge 128.
In accordance with aspects of the disclosed concepts, the individual modular actuators 124 each contains all the mechanical and hydraulic components necessary to operate as a hydraulic rotary steerable actuator, e.g., in a single plane. Turning to
Hydraulic control systems, each of which is respectively designated at 150A, 150B, 150C and 150D in
The hydraulic control systems 150A-150D are configured to regulate or otherwise control movement of the actuator pistons 134A-D between respective deactivated and activated positions to thereby change the direction of the drill string 100, for example, as described above with respect to
The drill string system 100 further comprises an actuator steering mechanism and electronics packages, schematically represented herein by the steering controller (or “brain”) 160 of
Packaging each of the components necessary to effect a complete actuator into a single cartridge and utilizing an external “brain” to electrically control the status of the actuator provides a number of benefits over prior art rotary steerable systems. For instance, at least some of the configurations disclosed herein permit service of the hydraulic steering system at the rig site without having to expose the actuator hydraulics to the environment. The introduction of a new/replacement cartridge can quickly and easily return the function of the steering tool to “as new” condition. In addition, standardization of the cartridge can provide the opportunity for reduced inventory variety, optimization of the cartridge design, and the potential for a complete vendor-provided sealed package that is oil filled, tested, and ready to install.
While particular embodiments and applications of the present disclosure have been illustrated and described, it is to be understood that the present disclosure is not limited to the precise construction and compositions disclosed herein and that various modifications, changes, and variations can be apparent from the foregoing descriptions without departing from the spirit and scope of the invention as defined in the appended claims.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US2012/042069 | 6/12/2012 | WO | 00 | 1/2/2014 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2013/187885 | 12/19/2013 | WO | A |
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| Entry |
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| International Search Report and Written Opinion mailed Jul. 24, 2013 which issued in corresponding International Patent Application No. PCT/US2012/042069 (10 pages). |
| Number | Date | Country | |
|---|---|---|---|
| 20140110178 A1 | Apr 2014 | US |
