Patent Application
20150337598
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.
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.
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.
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.
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
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
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
With reference to
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
Referring now to
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.
