ROTARY STEERABLE DRILLING SYSTEM AND METHOD |
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申请号 | EP11869401.7 | 申请日 | 2011-07-11 | 公开(公告)号 | EP2732119B1 | 公开(公告)日 | 2018-03-28 |
申请人 | Halliburton Energy Services, Inc.; | 发明人 | SAMUEL, Robello; | ||||
摘要 | A drilling system may include an outer sleeve, and a rotary steerable module including a shaft extending within the outer sleeve. The rotary steerable module may further include bearings disposed within the outer sleeve and through which the shaft extends, and cams positioned along the shaft between the bearings. Each cam may include an eccentric ring through which the shaft extends. Each extension of the shaft through one of the eccentric rings defines a bend in the shaft within the outer sleeve, the bend having a bend angle. A method of use and a drilling control apparatus are also provided. | ||||||
权利要求 | |||||||
说明书全文 | This disclosure generally relates to drilling systems and more particularly, to rotary steerable drilling systems for oil and gas exploration and production operations. A rotary steerable drilling system allows a drill string to rotate continuously while steering the drill string to a desired target location in a subterranean formation. A rotary steerable drilling system is limited by its maximum dogleg severity, that is, the maximum deflection rate of the drill string (in, for example, angle per linear length) that can be achieved during drilling. A more complete understanding of this disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying figures, wherein:
While this disclosure is susceptible to various modifications and alternative forms, specific exemplary embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the disclosure to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the scope of the disclosure as defined by the appended claims. This disclosure generally relates to drilling systems and more particularly, to rotary steerable drilling systems for oil and gas exploration and production operations. Rotary steerable drilling systems are provided herein that, among other functions, can be used to achieve greater maximum dogleg severities, that is, maximum drill string shaft deflection rates in, for example, angle per linear length. To facilitate a better understanding of this disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. For ease of reference, the terms "upper," "lower," "upward," and "downward" are used herein to refer to the spatial relationship of certain components. The terms "upper" and "upward" refer to components towards the surface (distal to the drill bit or proximal to the surface), whereas the terms "lower" and "downward" refer to components towards the drill bit (proximal to the drill bit or distal to the surface), regardless of the actual orientation or deviation of the wellbore or wellbores being drilled. In one exemplary embodiment, as illustrated in The rotary steerable module 14 includes a flexible lever arm or shaft 20 having a center axis 20a and extending within the outer sleeve 12. As shown in An upper cam 26 is disposed within the outer sleeve 12 and between the cantilever bearing 22 and the focal bearing 24. The upper cam 26 includes an inner eccentric ring 26a through which the shaft 20 extends, and an outer eccentric ring 26b extending about the inner eccentric ring 26a and connected to the outer sleeve 12. The inner eccentric ring 26a is engaged with the shaft 20 and may rotate therewith, relative to each of the outer eccentric ring 26b and the outer sleeve 12, under conditions to be described below. The control unit 16 is operably coupled to the upper cam 26 and controls the rotation of the upper cam 26 about the center axis 12a to any toolface setting and at least the inner eccentric ring 26a to varying degrees of offset from the center. More particularly, the control unit 16 causes at least one of the eccentric rings 26a and 26b to rotate about the center axis 12a to a predetermined angular position, relative to the outer sleeve 12, as shown in A lower cam 28 is disposed within the outer sleeve 12 and between the upper cam 26 and the focal bearing 24. The lower cam 28 includes an inner eccentric ring 28a through which the shaft 20 extends, and an outer eccentric ring 28b extending about the inner eccentric ring 28a and connected to the outer sleeve 12. The inner eccentric ring 28a is engaged with the shaft 20 and may rotate therewith, relative to each of the outer eccentric ring 28b and the outer sleeve 12, under conditions to be described below. The control unit 16 is operably coupled to the lower cam 28 and controls the rotation of the lower cam 28 about the center axis 12a to any toolface setting and at least the inner eccentric ring 28a to varying degrees of offset from the center. More particularly, the control unit 16 can cause at least one of the eccentric rings 28a and 28b to rotate about the center axis 12a to a predetermined angular position, relative to the outer sleeve 12, as shown in In several exemplary embodiments, the upper cam 26 and/or the lower cam 28 may be part of, include, or use, one or more of the annular rotational members and/or harmonic drive mechanisms described in one or more of In one exemplary embodiment, the drilling system 10 is a double bend point-the-bit rotary steerable system, which allows the drill bit 15 to tilt in any direction as indicated by the range of movement 30, under conditions to be described below (e.g., if the distal end portion of the drill string 21 extends horizontally, the drill bit 15 is allowed to tilt up, right, down or left). In operation, in one exemplary embodiment, the drilling system 10 drills or penetrates directionally into a subterranean ground formation for the purpose of recovering hydrocarbon fluids from the formation. As the drilling system 10 penetrates into the formation directionally, a wellbore is formed (the wellbore is not shown in During operation, in one exemplary embodiment, a control unit 16 positioned in the wellbore communicates with the surface control system 18, sending directional survey information to the surface control system 18 using a telemetry system. In one embodiment, the telemetry system utilizes mud-pulse telemetry. In any event, the control unit 16 may transmit to the surface control system 18 information about the direction, inclination and orientation of the drilling system 10. In one exemplary embodiment, the surface control system 18 controls the rotary steerable module 14 via the control unit 16. During operation, in one exemplary embodiment, the control unit 16 controls the rotary steerable module 14, controlling the rotation of the upper cam 26 and the lower cam 28 to any toolface setting, and controlling the offset of each of the inner eccentric rings 26a and 28a from the center. In one exemplary embodiment, one or both of the control unit 16 and the surface control system 18 are part of a downlink system that allows for automatic steering along a fixed or preprogrammed trajectory towards the desired target location in the formation. In one exemplary embodiment, to control the rotary steerable module 14 using the surface control system 18 and/or the control unit 16, the one or more processors 16a and/or the one or more processors 18a execute the plurality of instructions stored in the computer readable medium 16b and/or the plurality of instructions stored in the computer readable medium 18b. During operation, the shaft 20 can pivot at the upper cam 26, as well as at the lower cam 28. Due to the cams 26 and 28, and the accompanying pivot actions of the shaft 20 at the cams 26 and 28, wide ranges of dogleg severity (or deflection rate in, for example, angle per linear length) can be achieved. As a result, as shown in During operation, in one exemplary embodiment and referring to More particularly, the drill bit 15 (point 1 in Since the configuration shown in
In one exemplary embodiment, referring to During operation, in one exemplary embodiment, the bend angles β1 and β2 at the cams 28 and 26, respectively, are in the same plane and the rotary steerable module 14 is bent to the accordant direction, that is, placed in the accordant double bend configuration shown in In view of the foregoing, it is clear that the capability of the rotary steerable module 14 to be placed in a single composite double bend configuration, such as the reverse double bend configuration shown in Moreover, as noted above, due to the cams 26 and 28, and the accompanying respective pivot actions of the shaft 20 at the cams 26 and 28, wide ranges of dogleg severity can be achieved. In several exemplary embodiments, using equivalent input parameters, the double bend configuration(s) of the rotary steerable module 14 can achieve a dogleg severity (or deflection rate) that is greater than that of a single bend configuration. For example, a well needs a dogleg severity (or deflection rate) of 15.75 degrees per 100 ft. The available tool options are set forth below, each of which has a maximum bend of 1.5 degrees. The maximum deflection rate for each option in the accordant direction is determined as set forth below. Referring to In the example, for the tool option 36 having the single bend configuration as shown in Therefore, the maximum dogleg severity or deflection rate is 14.42 degrees per 100 ft for the tool option 36 having the single bend configuration as shown in In the example, for the rotary steerable module 14 having the accordant double bend configuration of Therefore, the maximum dogleg severity or deflection rate is 15.87 degrees per 100 ft for the rotary steerable module 14 having the accordant double bend configuration as shown in In one exemplary embodiment, as illustrated in In operation, in one exemplary embodiment, the drilling system 38 drills or penetrates into a subterranean ground formation for the purpose of recovering hydrocarbon fluids from the formation. As the drilling system 38 penetrates into the formation, a wellbore 44 is formed. During the drilling, the rotary steerable module 40 enables the drill string 21, and thus the flexible shaft 20 and the drill bit 15, to rotate continuously. The pad 42 interacts with the formation in which the wellbore 44 is being formed, thereby causing a side force to be generated, which side force deviates or pushes the drill bit 15 in a desired direction. In one exemplary embodiment, the pad 42 acts as a pivot for the deflection of the drill bit 15. The placement of the pad 42 and any additional pad(s), relative to the outer sleeve 12, enables the drill bit 15 to be steered in a controlled manner. In several exemplary embodiments, during operation, the drilling system 38 operates as a double bend push-the-bit rotary steerable system. During operation, the rotary steerable module 40 of the system 38 may be placed in a reverse double bend configuration, as shown in In one exemplary embodiment, as illustrated in In one exemplary embodiment, the drilling system 46 is a double bend push-the-bit rotary steerable system, which can be placed in either a reverse double bend configuration or an accordant double bend configuration. In several exemplary embodiments, the location of the pad 42, relative to the outer sleeve 12, may be varied. In several exemplary embodiments, the rotary steerable module 48 of the drilling system 38 may include one or more additional pads connected to the outer sleeve 12, each of which may be substantially identical to the pad 42. In operation, in one exemplary embodiment, the drilling system 46 drills or penetrates into a subterranean ground formation for the purpose of recovering hydrocarbon fluids from the formation. As the drilling system 46 penetrates into the formation, a wellbore 50 is formed. During the drilling, the rotary steerable module 48 enables the drill string 21, and thus the flexible shaft 20 and the drill bit 15, to rotate continuously. The pad 42 interacts with the formation in which the wellbore 50 is being formed, thereby causing a side force to be generated, which side force deviates or pushes the drill bit 15 in a desired direction. In one exemplary embodiment, the pad 42 acts as a pivot for the deflection of the drill bit 15. The placement of the pad 42 and any additional pad(s), relative to the outer sleeve 12, enables the drill bit 15 to be steered in a controlled manner. In several exemplary embodiments, during operation, the drilling system 46 operates as a double bend push-the-bit rotary steerable system. During operation, the rotary steerable module 48 of the system 46 may be placed in a reverse double bend configuration, as shown in In one exemplary embodiment, as illustrated in A connector 54 including an internal threaded connection (not shown) is connected to the upper end of the module 14. A connector 56 is connected to the lower end of the module 40. The connector 56 includes an external threaded connection (not shown), which is engaged with the internal threaded connection of the connector 54, thereby connecting the module 40 to the module 14. The sections 12a and 12b, the connector 54, and the connector 56 together form at least a portion of the outer sleeve 12. A connector 57 extends within at least the connectors 54 and 56, and connects the respective shafts 20 of the modules 14 and 40. The connector 57 and the respective shafts 20 of the modules 14 and 40 form at least a portion of the drill string 21, the lowermost end of which is connected to the drill bit 15. In operation, in one exemplary embodiment, the drilling system 52 operates as a double bend hybrid rotary steerable system. More particularly, the module 40 of the drilling system operates as a double bend push-the-bit rotary steerable system, while the module 14 operates as a double bend point-the-bit rotary steerable system. The overall coherence of the drilling system 52 achieves a desired toolface vector. During operation, in one exemplary embodiment, the module 14 is placed either in an accordant double bend configuration or in a reverse double bend configuration. Likewise, the module 40 is placed either in an accordant double bend configuration or in a reverse double bend configuration. In several exemplary embodiments, another module substantially identical to one of the modules 14, 40 and 48 is connected to the upper end of the module 40. In several exemplary embodiments, one or more modules, each of which is substantially identical to one of the modules 14, 40 and 48, are connected to each other end-to-end, with the lowermost module connected to the module 40. In several exemplary embodiments, in the drilling system 52, either the module 14 or the module 40 is replaced with the module 48. In one exemplary embodiment, as illustrated in The connector 54 is connected to the upper end of the module 40. The connector 56 is connected to the lower end of the module 14. The connector 56 is engaged with the connector 54, thereby connecting the module 14 to the module 40. The sections 12a and 12b, the connector 54, and the connector 56 together form at least a portion of the outer sleeve 12. The connector 57 extends within at least the connectors 54 and 56, and connects the respective shafts 20 of the modules 14 and 40. The connector 57 and the respective shafts 20 of the modules 14 and 40 together form at least a portion of the drill string 21, the lowermost end of which is connected to the drill bit 15. In operation, in one exemplary embodiment, the drilling system 58 operates as a double bend hybrid rotary steerable system. More particularly, the module 40 of the drilling system operates as a double bend push-the-bit rotary steerable system, while the module 14 operates as a double bend point-the-bit rotary steerable system. The overall coherence of the drilling system 58 achieves a desired toolface vector. During operation, in one exemplary embodiment, the module 14 is placed either in an accordant double bend configuration or in a reverse double bend configuration. Likewise, the module 40 is placed either in an accordant double bend configuration or in a reverse double bend configuration. In several exemplary embodiments, another module substantially identical to one of the modules 14, 40 and 48 is connected to the upper end of the module 14. In several exemplary embodiments, one or more modules, each of which is substantially identical to one of the modules 14, 40 and 48, are connected to each other in tandem end-to-end, with the lowermost module connected to the module 14. As a result, wider angles may be achieved. In several exemplary embodiments, in the drilling system 58, either the module 14 or the module 40 is replaced with the module 48. As shown in In several exemplary embodiments, with continuing reference to In one exemplary embodiment, as illustrated in In several exemplary embodiments, the method 60 may be implemented in whole or in part by a computer. In several exemplary embodiments, the plurality of instructions stored on the computer readable medium 16b, the plurality of instructions stored on the computer readable medium 18b, a plurality of instructions stored on another computer readable medium, and/or any combination thereof, may be executed by a processor to cause the processor to carry out or implement in whole or in part the method 60, and/or to carry out in whole or in part the above-described operation of one or more of the drilling systems 10, 38, 46, 52 and 58. In several exemplary embodiments, such a processor may include the one or more processors 16a, the one or more processors 18a, one or more additional processors, and/or any combination thereof. An example of a drilling system has been described that includes an outer sleeve; and a first rotary steerable module, comprising a first shaft extending within the outer sleeve; a first bearing disposed within the outer sleeve and through which the first shaft extends; a second bearing disposed within the outer sleeve and through which the first shaft extends, wherein the second bearing is spaced from the first bearing along the first shaft; a first cam disposed within the outer sleeve so that the first cam is positioned along the first shaft between the first and second bearings, the first cam comprising a first eccentric ring through which the first shaft extends; and a second eccentric ring extending about the first eccentric ring; wherein the extension of the first shaft through the first eccentric ring defines a first bend in the first shaft within the outer sleeve, the first bend having a first bend angle; and a second cam disposed within the outer sleeve so that the second cam is positioned along the first shaft between the first cam and the second bearing, the second cam comprising a third eccentric ring through which the first shaft extends; and a fourth eccentric ring extending about the third eccentric ring; wherein the extension of the first shaft through the second eccentric ring defines a second bend in the first shaft within the outer sleeve, the second bend having a second bend angle. An example of a drilling method has been described that includes extending a shaft within an outer sleeve, wherein the shaft and the outer sleeve have first and second center axes, respectively; placing a first bend in the shaft within the outer sleeve, the first bend having a first bend angle; placing a second bend in the shaft within the outer sleeve, the second bend having a second bend angle; and rotating, relative to the outer sleeve, the shaft about the first center axis while maintaining the first and second bends in the shaft within the outer sleeve. An example of a drilling control apparatus has been described that includes a computer readable medium; and a plurality of instructions stored on the computer readable medium and executable by a processor, the plurality of instructions comprising instructions that cause the processor to place a first bend in a shaft within an outer sleeve, wherein the first bend has a first bend angle, and wherein the shaft and the outer sleeve have first and second center axes, respectively; instructions that cause the processor to place a second bend in the shaft within the outer sleeve, wherein the second bend has a second bend angle; and instructions that cause the processor to rotate, relative to the outer sleeve, the shaft about the first center axis while maintaining the first and second bends in the shaft within the outer sleeve. Any spatial references such as, for example, "upper," "lower," "above," "below," "between," "bottom," "vertical," "horizontal," "angular," "upwards," "downwards," "side-to-side," "left-to-right," "left," "right," "right-to-left," "top-to-bottom," "bottom-to-top," "top," "bottom," "bottom-up," "top-down," etc., are for the purpose of illustration only and do not limit the specific orientation or location of the structure described above. |