US20150337598A1

US20150337598A1 - Pressure Booster for Rotary Steerable System Tool

Info

Publication number: US20150337598A1
Application number: US14/287,044
Authority: US
Inventors: Guy Rushton; Jonathan James
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2014-05-25
Filing date: 2014-05-25
Publication date: 2015-11-26

Abstract

Aspects of the disclosure can relate to a drill assembly that includes a body for receiving a flow of drilling fluid. The body includes a crushing implement and/or a cutting implement and defines a nozzle that allows the drilling fluid to exit the body proximate to the crushing implement and/or the cutting implement. The drill assembly also includes an extendable displacement mechanism coupled with the body and powered by the flow of the drilling fluid. The drill assembly further includes a drive mechanism for driving a pump mechanism disposed in the body. The pump mechanism increases the pressure of a fraction of the flow of the drilling fluid, and the fraction of the flow of the drilling fluid is furnished to the extendable displacement mechanism.

Description

BACKGROUND

Oil wells are created by drilling a hole into the earth using a drilling rig that rotates a drill string (e.g., drill pipe) having a drill bit attached thereto. The drill bit, aided by the weight of pipes (e.g., drill collars) cuts into rock within the earth. Drilling fluid (e.g., mud) is pumped into the drill pipe and exits at the drill bit. The drilling fluid may be used to cool the bit, lift rock cuttings to the surface, at least partially prevent destabilization of the rock in the wellbore, and/or at least partially overcome the pressure of fluids inside the rock so that the fluids do not enter the wellbore. Rotary steerable systems (RSS) can be used for directional drilling. These systems employ down hole equipment that responds to commands (e.g., from surface equipment) and steers into a desired direction. For example, pistons may be used to generate force against a borehole wall or to cause angular displacement of one steerable system component with respect to another to cause a drill bit to move in the desired direction of deviation.

SUMMARY

Aspects of the disclosure can relate to a drill assembly that includes a body for receiving a flow of drilling fluid. The body includes a crushing implement and/or a cutting implement and defines a nozzle that allows the drilling fluid to exit the body proximate to the crushing implement and/or the cutting implement. The drill assembly also includes an extendable displacement mechanism coupled with the body and powered by the flow of the drilling fluid. The drill assembly further includes a drive mechanism for driving a pump mechanism disposed in the body. The pump mechanism increases the pressure of a fraction of the flow of the drilling fluid, and the fraction of the flow of the drilling fluid is furnished to the extendable displacement mechanism.
Other aspects of the disclosure can relate to a drill assembly that includes a body for receiving a flow of drilling fluid. The body includes a crushing implement and/or a cutting implement and defines a nozzle that allows the drilling fluid to exit the body proximate to the crushing implement and/or the cutting implement. The drill assembly also includes an extendable displacement mechanism coupled with the body and powered by the flow of the drilling fluid. The drill assembly further includes a pressure booster disposed in the body. The pressure booster increases the pressure of a fraction of the flow of the drilling fluid, and the fraction of the flow of the drilling fluid is furnished to the extendable displacement mechanism.
Also, aspects of the disclosure can relate to a method that includes supplying a portion of a flow of drilling fluid to a nozzle proximate to a crushing implement and/or a cutting implement. The method also includes receiving the flow of drilling fluid at a drive mechanism for driving a pump mechanism to increase the pressure of a fraction of the flow of the drilling fluid. The method further includes furnishing the fraction of the flow of the drilling fluid to an extendable displacement mechanism powered by the flow of the drilling fluid.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

FIGURES

Embodiments of a pressure booster for a rotary steerable system tool are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components.

FIG. 1 illustrates an example system in which embodiments of a pressure booster for a rotary steerable system tool can be implemented;

FIG. 2 illustrates an example rotary steerable system tool with a pressure booster in accordance with one or more embodiments;

FIG. 3 illustrates an example pressure booster for a rotary steerable system tool, such as the rotary system tool illustrated in FIG. 1, in accordance with one or more embodiments;

FIG. 4 illustrates an example pump mechanism for a pressure booster for a rotary steerable system tool, such as the rotary system tool illustrated in FIG. 1, in accordance with one or more embodiments; and

FIG. 5 illustrates example method(s) for pressure boosting for a rotary steerable system tool in accordance with one or more embodiments.

DETAILED DESCRIPTION

FIG. 1 depicts a wellsite system 100 in accordance with one or more embodiments of the present disclosure. The wellsite can be onshore or offshore. A borehole 102 is formed in subsurface formations by directional drilling. A drill string 104 extends from a drill rig 106 and is suspended within the borehole 102. In some embodiments, the wellsite system 100 implements directional drilling using a rotary steerable system (RSS). For instance, the drill string 104 is rotated from the surface, and down hole devices move the end of the drill string 104 in a desired direction. The drill rig 106 includes a platform and derrick assembly positioned over the borehole 102. In some embodiments, the drill rig 106 includes a rotary table 108, kelly 110, hook 112, rotary swivel 114, and so forth. For example, the drill string 104 is rotated by the rotary table 108, which engages the kelly 110 at the upper end of the drill string 104. The drill string 104 is suspended from the hook 112 using the rotary swivel 114, which permits rotation of the drill string 104 relative to the hook 112. However, this configuration is provided by way of example only and is not meant to limit the present disclosure. For instance, in other embodiments a top drive system is used.
A bottom hole assembly (BHA) 116 is suspended at the end of the drill string 104. The bottom hole assembly 116 includes a drill bit 118 at its lower end. In embodiments of the disclosure, the drill string 104 includes a number of drill pipes 120 that extend the bottom hole assembly 116 and the drill bit 118 into subterranean formations. Drilling fluid (e.g., mud) 122 is stored in a tank and/or a pit 124 formed at the wellsite. The drilling fluid can be water-based, oil-based, and so on. A pump 126 displaces the drilling fluid 122 to an interior passage of the drill string 104 via, for example, a port in the rotary swivel 114, causing the drilling fluid 122 to flow downwardly through the drill string 104 as indicated by directional arrow 128. The drilling fluid 122 exits the drill string 104 via ports (e.g., courses, nozzles) in the drill bit 118, and then circulates upwardly through the annulus region between the outside of the drill string 104 and the wall of the borehole 102, as indicated by directional arrows 130. In this manner, the drilling fluid 122 cools and lubricates the drill bit 118 and carries drill cuttings generated by the drill bit 118 up to the surface (e.g., as the drilling fluid 122 is returned to the pit 124 for recirculation).
In some embodiments, the bottom hole assembly 116 includes a logging-while-drilling (LWD) module 132, a measuring-while-drilling (MWD) module 134, a rotary steerable system 136, a motor, and so forth (e.g., in addition to the drill bit 118). The logging-while-drilling module 132 can be housed in a drill collar and can contain one or a number of logging tools. It should also be noted that more than one LWD module and/or MWD module can be employed (e.g. as represented by another logging-while-drilling module 138). In embodiments of the disclosure, the logging-while drilling modules 132 and/or 138 include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment, and so forth.
The measuring-while-drilling module 134 can also be housed in a drill collar, and can contain one or more devices for measuring characteristics of the drill string 104 and drill bit 118. The measuring-while-drilling module 134 can also include components for generating electrical power for the down hole equipment. This can include a mud turbine generator (also referred to as a “mud motor”) powered by the flow of the drilling fluid 122. However, this configuration is provided by way of example only and is not meant to limit the present disclosure. In other embodiments, other power and/or battery systems can be employed. The measuring-while-drilling module 134 can include one or more of the following measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, an inclination measuring device, and so on.
In embodiments of the disclosure, the wellsite system 100 is used with controlled steering or directional drilling. For example, the rotary steerable system 136 is used for directional drilling. As used herein, the term “directional drilling” describes intentional deviation of the wellbore from the path it would naturally take. Thus, directional drilling refers to steering the drill string 104 so that it travels in a desired direction. In some embodiments, directional drilling is used for offshore drilling (e.g., where multiple wells are drilled from a single platform). In other embodiments, directional drilling enables horizontal drilling through a reservoir, which enables a longer length of the wellbore to traverse the reservoir, increasing the production rate from the well. Further, directional drilling may be used in vertical drilling operations. For example, the drill bit 118 may veer off of a planned drilling trajectory because of the unpredictable nature of the formations being penetrated or the varying forces that the drill bit 118 experiences. When such deviation occurs, the wellsite system 100 may be used to guide the drill bit 118 back on course.
FIG. 2 depicts a drill assembly 200 that can be used with, for example, a wellsite system (e.g., the wellsite system 100 described with reference to FIG. 1). For instance, the drill assembly 200 can comprise a bottom hole assembly suspended at the end of a drill string (e.g., in the manner of the bottom hole assembly 116 suspended from the drill string 104 depicted in FIG. 1). In some embodiments, the drill assembly 200 is implemented using a drill bit. However, this configuration is provided by way of example only and is not meant to limit the present disclosure. In other embodiments, different working implement configurations are used. Further, use of drill assemblies 200 in accordance with the present disclosure is not limited to wellsite systems described herein. Drill assemblies 200 can be used in other various cutting and/or crushing applications, including earth boring applications employing rock scraping, crushing, cutting, and so forth.
The drill assembly 200 includes a body 202 for receiving a flow of drilling fluid. The body 202 comprises one or more crushing and/or cutting implements, such as conical cutters and/or bit cones having spiked teeth (e.g., in the manner of a roller-cone bit). In this configuration, as the drill string is rotated, the bit cones roll along the bottom of the borehole in a circular motion. As they roll, new teeth come in contact with the bottom of the borehole, crushing the rock immediately below and around the bit tooth. As the cone continues to roll, the tooth then lifts off the bottom of the hole and a high-velocity drilling fluid jet strikes the crushed rock chips to remove them from the bottom of the borehole and up the annulus. As this occurs, another tooth makes contact with the bottom of the borehole and creates new rock chips. In this manner, the process of chipping the rock and removing the small rock chips with the fluid jets is continuous. The teeth intermesh on the cones, which helps clean the cones and enables larger teeth to be used. A drill assembly 200 comprising a conical cutter can be implemented as a steel milled-tooth bit, a carbide insert bit, and so forth. However, roller-cone bits are provided by way of example only and are not meant to limit the present disclosure. In other embodiments, a drill assembly 200 is configured differently. For example, the body 202 of the bit comprises one or more polycrystalline diamond compact (PDC) cutters that shear rock with a continuous scraping motion.
In embodiments of the disclosure, the body 202 of the drill assembly 200 defines one or more nozzles 204 that allow the drilling fluid to exit the body 202 (e.g., proximate to the crushing and/or cutting implements). The nozzles 204 allow drilling fluid pumped through, for example, a drill string to exit the body 202. For example, as discussed with reference to FIG. 1, drilling fluid 122 is furnished to an interior passage of drill string 104 by pump 126 and flows downwardly through drill string 104 to drill bit 118 of bottom hole assembly 116, which can be implemented using a drill assembly 200. Drilling fluid 122 then exits drill string 104 via nozzles in drill bit 118 (e.g., via nozzles 204), and circulates upwardly through the annulus region between the outside of drill string 104 and the wall of borehole 102. In this manner, rock cuttings can be lifted to the surface, destabilization of the rock in the wellbore can be at least partially prevented, the pressure of fluids inside the rock can be at least partially overcome so that the fluids do not enter the wellbore, and so forth.
The drill assembly 200 also includes one or more extendable displacement mechanisms 206, such as a piston mechanism that can be selectively actuated by an actuator 208 to displace a pad 210 toward, for instance, a borehole wall to cause the drill assembly 200 to move in a desired direction of deviation. In embodiments of the disclosure, the displacement mechanism 206 is actuated by drilling fluid routed through the body 202 of the drill assembly 200. For example, as discussed with reference to FIG. 1, drilling fluid 122 is used to move a piston, which changes the orientation of the drill bit 118 (e.g., changing the drilling axis orientation with respect to a longitudinal axis of the bottom hole assembly 116). The displacement mechanism 206 may be employed to control a directional bias and/or an axial orientation of the drill assembly 200. Displacement mechanisms 206 may be arranged, for example, to point the drill assembly 200 or to push the drill assembly 200. In some embodiments, the drill assembly 200 is deployed by a drilling system using a rotary steerable system that rotates with a number of displacement mechanisms 206 (e.g., the rotary steerable system 136 described with reference to FIG. 1). It should be noted that such a rotary steerable system can be used in conjunction with stabilizers, such as non-rotating stabilizers, and so on.
Increased steering from the drill assembly 200 can in part be achieved if there is more force available from the actuator 208 to drive the bit in the desired direction. However, the force available to a down hole hydraulic actuator may be constrained by the pressure available at the end of the drill string, the area of an active piston, and so forth. Thus, in an application of limited physical size (e.g., where the size of a piston may not be increased) for example, the working fluid pressure can be raised to increase the available force from the actuator 208. As described herein, pressure boosting (e.g., using a large volume of working fluid to increase the pressure of a much smaller volume of working fluid) is used to increase the available force provided by the actuator 208. For example, in some embodiments, the flow of the majority of the drilling fluid through the body 202 of the drill assembly 200 and to the nozzles 204 is used to drive a pressure booster 212 that increases the pressure of a fraction of the flow of the drilling fluid. For instance, a high pressure flow of drilling fluid is furnished to an RSS tool (e.g., to displace the pad 210 of the drill assembly 200). In this manner, more force can be generated on the pad 210 because of the higher pressure of the drilling fluid (e.g., with respect to using the pressure of the drilling fluid on the pad 210 without a pressure booster 212). In some embodiments, one or more valves are used to distribute the flow of the drilling fluid to the actuator 208. For example, a valve can be coupled with a controller (e.g., via wired connection, a wireless connection, and so forth) to selectively actuate the displacement mechanism 206.
In embodiments of the disclosure, the pressure booster 212 comprises a drive mechanism 214 for driving a pump mechanism 216. For example, as shown in FIG. 2, the drive mechanism 214 comprises an axial flow turbine 218 (e.g., employing a turbine stator 220 and a turbine rotor 222). The turbine rotor 222 is coupled with the pump mechanism 216, which can be implemented using a compressor (e.g., a centrifugal compressor 224). In this example, at least substantially the entire flow of drilling fluid through the body 202 (e.g., to the nozzles 204) passes through the turbine 218, driving the centrifugal compressor 224. This flow of drilling fluid is indicated by directional arrows 226. The centrifugal compressor 224 is positioned upstream from the turbine 218 with respect to the flow of the drilling fluid and takes its inlet charge (e.g., a small percentage of the total flow of drilling fluid) from before the turbine 218. The inlet charge is represented by directional arrows 228. However, this configuration is provided by way of example only and is not meant to limit the present disclosure. In other embodiments, the pump mechanism 216 is positioned behind the drive mechanism 214 (e.g., downstream from the drive mechanism 214 with respect to the flow of the drilling fluid). It should be noted that in such a configuration, the pump mechanism 216 may use a higher pressure ratio and the volume of high pressure fluid may be less.
With reference to FIG. 3, in some embodiments the drive mechanism 214 employs a multi-stage turbine 230. For example, two or more turbines 218 are used to drive the pump mechanism 216 (e.g., using multiple, concentric turbine shafts, and so forth). In some embodiments, one or more of the turbines 218 comprises an axial turbine 232. In other embodiments, one or more of the turbines comprises a radial turbine 234. However, these turbine configurations are provided by way of example only and are not meant to limit the present disclosure. In other embodiments, different turbine configurations are used with the drill assembly 200. It should be noted that other pump mechanisms 216 can also be used with the drill assembly 200, including positive displacement pumps for higher pressure ratios, and so forth. For example, with reference to FIG. 4, the pump mechanism 216 can include a roots blower pump 236, a piston pump 238, a screw feed pump 240, a vane pump 242, and so forth. Further, the pump mechanism 216 can employ multiple stages (e.g., using multiple compressor stages, and so on).
In some embodiments, a force maintainer is used to maintain the pressure of the drilling fluid to the drill assembly 200 (e.g., for long drill strings). In some embodiments, multiple pistons are used for the displacement mechanism 206. For example, a smaller piston is used to generate force on a larger piston, which in turn is used to displace the pad 210. It should be noted that while the pressure booster and displacement mechanism 206 are shown proximate to the bit of the drill assembly 200 in FIG. 2, one or more of the displacement mechanism 206, the drive mechanism 214, the pump mechanism 216, and so forth, can be positioned at various locations along a drill string, a bottom hole assembly, and so on. For example, in some embodiments, the displacement mechanism 206 is positioned in the rotary steerable system 136, while in other embodiments, the displacement mechanism 206 is positioned at or near the end of the bottom hole assembly 116 (e.g., proximate to the drill bit 118). In some embodiments, the drill assembly 200 includes one or more filters that filter the drilling fluid (e.g., upstream of the drive mechanism 214 and/or the pump mechanism 216 with respect to the flow of the drilling fluid).
Referring now to FIG. 5, a procedure 500 is described in an example embodiment in which pressure to a displacement mechanism of a tool is boosted. At block 510, at least a portion of a flow of drilling fluid, such as drilling fluid 122, is supplied to a nozzle, such as nozzle 204, proximate to at least one of a crushing implement or a cutting implement, such as a conical cutter, a bit cone, and so forth, of a drill bit 118. At block 520, the flow of drilling fluid is received at a drive mechanism, such as the drive mechanism 214, for driving a pump mechanism, such as the pump mechanism 216, to increase the pressure of a fraction of the flow of the drilling fluid, such as the flow of drilling fluid indicated by directional arrows 228. At block 530, the fraction of the flow of the drilling fluid is furnished to a displacement mechanism, such as the extendable displacement mechanism 206, powered by the flow of the drilling fluid.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from PRESSURE BOOSTER FOR ROTARY STEERABLE SYSTEM TOOL. Features shown in individual embodiments referred to above may be used together in combinations other than those which have been shown and described specifically. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

What is claimed is:

1. A drill assembly comprising:

a body for receiving a flow of drilling fluid and comprising at least one of a crushing implement or a cutting implement, the body defining a nozzle allowing the drilling fluid to exit the body proximate to the at least one of the crushing implement or the cutting implement;

an extendable displacement mechanism coupled with the body and powered by the flow of the drilling fluid; and

a drive mechanism for driving a pump mechanism disposed in the body for increasing the pressure of a fraction of the flow of the drilling fluid, where the fraction of the flow of the drilling fluid is furnished to the extendable displacement mechanism.

2. The drill assembly as recited in claim 1, wherein the drive mechanism comprises a turbine.

3. The drill assembly as recited in claim 2, wherein the turbine comprises a multi-stage turbine.

4. The drill assembly as recited in claim 2, wherein the turbine comprises at least one of an axial turbine or a radial turbine.

5. The drill assembly as recited in claim 1, wherein the pump mechanism comprises a compressor.

6. The drill assembly as recited in claim 1, wherein the pump mechanism comprises at least one of a roots blower pump, a piston pump, a screw feed pump, or a vane pump.

7. The drill assembly as recited in claim 1, wherein the pump mechanism is positioned upstream from the drive mechanism.

8. The drill assembly as recited in claim 1, wherein at least substantially the entire flow of drilling fluid through the body passes through the drive mechanism.

9. A drill assembly comprising:

a pressure booster disposed in the body for increasing the pressure of a fraction of the flow of the drilling fluid, where the fraction of the flow of the drilling fluid is furnished to the extendable displacement mechanism.

10. The drill assembly as recited in claim 9, wherein the pressure booster comprises a drive mechanism for driving a pump mechanism.

11. The drill assembly as recited in claim 10, wherein the drive mechanism comprises a turbine.

12. The drill assembly as recited in claim 11, wherein the turbine comprises a multi-stage turbine.

13. The drill assembly as recited in claim 11, wherein the turbine comprises at least one of an axial turbine or a radial turbine.

14. The drill assembly as recited in claim 10, wherein the pump mechanism comprises a compressor.

15. The drill assembly as recited in claim 10, wherein the pump mechanism comprises at least one of a roots blower pump, a piston pump, a screw feed pump, or a vane pump.

16. The drill assembly as recited in claim 9, wherein the pump mechanism is positioned upstream from the drive mechanism.

17. The drill assembly as recited in claim 9, wherein at least substantially the entire flow of drilling fluid through the body passes through the drive mechanism.

18. A method comprising:

supplying at least a portion of a flow of drilling fluid to a nozzle proximate to at least one of a crushing implement or a cutting implement;

receiving the flow of drilling fluid at a drive mechanism for driving a pump mechanism to increase the pressure of a fraction of the flow of the drilling fluid;

furnishing the fraction of the flow of the drilling fluid to an extendable displacement mechanism powered by the flow of the drilling fluid.

19. The method as recited in claim 18, wherein the drive mechanism comprises a turbine.

20. The method as recited in claim 18, wherein the pump mechanism comprises a compressor.