Flexible collar for a rotary steerable system

A Rotary Steerable System (RSS) includes a flexible collar coupled therein that reduces the stiffness of the RSS and permits a tighter turning radius to be achieved. The positioning of the flexible collar between the steering section and the controller of the RSS further improves the turning radius, and may permit a push-the-bit system to operate similar to a point-the bit system. The flexible collar permits communication therethrough between controller and the steering sections of the RSS. The RSS may be arranged as a modular system to receive various configurations of a flexible collar and may operate with no flexible collar installed. The modularity enables tuning of the stiffness of an RSS to achieve different steering objectives.

BACKGROUND

The present disclosure relates generally to rotary steerable systems (RSS), e.g., drilling systems employed for directionally drilling wellbores in oil and gas exploration and production. More particularly, embodiments of the disclosure relate to rotary steerable systems having flexible collar therein for achieving tighter steering radii.

Directional drilling operations involve controlling the direction of a wellbore as it is being drilled. Usually the goal of directional drilling is to reach a target subterranean destination with a drill string, and often the drill string will need to be turned through a tight radius to reach the target destination. Generally, an RSS changes direction either by pushing against one side of a wellbore wall with steering pads to thereby cause the drill bit to push on the opposite side (in a push-the-bit system), or by bending a main shaft running through a non-rotating housing to point the drill bit in a particular direction with respect to the rest of the tool (in a point-the-bit system). In a push-the-bit system, the wellbore wall is generally in contact with the drill bit, the steering pads and a stabilizer. The steering capability of such a system is predominantly defined by a curve that can be fitted through each of the drill bit, steering pads and the stabilizer.

DETAILED DESCRIPTION

The present disclosure includes an RSS having a flexible collar coupled therein that reduces the stiffness of the RSS and permits a tighter turning radius to be achieved. The positioning of the flexible collar between the steering section and the controller of the RSS further improves the achievable turning radius. The flexible collar may be configured to permit communication therethrough between the controller and the steering section, and the RSS may be arranged as a modular system to receive various configurations of a flexible collar and may operate with no flexible collar installed.

FIG. 1is a partial cross-sectional side view of a directional wellbore drilled with a bottom hole assembly (BHA) including an RSS. An exemplary directional drilling system10is illustrated including a tower or “derrick”11that is buttressed by a derrick floor12. The derrick floor12supports a rotary table14that is driven at a desired rotational speed, for example, via a chain drive system through operation of a prime mover (not shown). The rotary table14, in turn, provides the necessary rotational force to a drill string20. The drill string20, which includes a drill pipe section24, extends downwardly from the rotary table14into a directional borehole26. The borehole26may exhibit a multi-dimensional path or “trajectory.” The three-dimensional direction of the bottom54of the borehole26ofFIG. 1is represented by arrow52.

A drill bit50is attached to the distal, downhole end of the drill string20. When rotated, e.g., via the rotary table14, the drill bit50operates to break up and generally disintegrate the geological formation46. The drill string20is coupled to a “drawworks” hoisting apparatus30, for example, via a kelly joint21, swivel28, and line29through a pulley system (not shown). During a drilling operation, the drawworks30can be operated, in some embodiments, to control the weight on drill bit50and the rate of penetration of the drill string20into the borehole26.

During drilling operations, a suitable drilling fluid or “mud”31can be circulated, under pressure, out from a mud pit32and into the borehole26through the drill string20by a hydraulic “mud pump”34. Mud31passes from the mud pump34into the drill string20via a fluid conduit (commonly referred to as a “mud line”)38and the kelly joint21. Drilling fluid31is discharged at the borehole bottom54through an opening or nozzle in the drill bit50, and circulates in an “uphole” direction towards the surface through an annular space27between the drill string20and the side56of the borehole26. As the drilling fluid31approaches the rotary table14, it is discharged via a return line35into the mud pit32. A variety of surface sensors48, which are appropriately deployed on the surface of the borehole26, operate alone or in conjunction with downhole sensors70,72deployed within the borehole26, to provide information about various drilling-related parameters, such as fluid flow rate, weight on bit, hook load, etc.

A surface control unit40may receive signals from surface and downhole sensors (e.g., sensors48,70,72) and devices via a sensor or transducer43, which can be placed on the fluid line38. The surface control unit40can be operable to process such signals according to programmed instructions provided to surface control unit40. Surface control unit40may present to an operator desired drilling parameters and other information via one or more output devices42, such as a display, a computer monitor, speakers, lights, etc., which may be used by the operator to control the drilling operations. Surface control unit40may contain a computer, memory for storing data, a data recorder, and other known and hereinafter developed peripherals. Surface control unit40may also include models and may process data according to programmed instructions, and respond to user commands entered through a suitable input device44, which may be in the nature of a keyboard, touchscreen, microphone, mouse, joystick, etc.

In some embodiments of the present disclosure, the rotatable drill bit50is attached at a distal end of a bottom hole assembly (BHA)22comprising a rotary steerable system (RSS)58. In the illustrated embodiment, the BHA22is coupled between the drill bit50and the drill pipe section24of the drill string20. The BHA22and or/the RSS58may comprise a Measurement While Drilling (MWD) System, with various sensors, e.g., sensors70,72, to provide information about the formation46and downhole drilling parameters. The MWD sensors in the BHA22may include, but are not limited to, a device for measuring the formation resistivity near the drill bit, a gamma ray device for measuring natural radioactivity of the formation, devices for determining the inclination and azimuth of the drill string20, and pressure sensors for measuring drilling fluid pressure downhole. The MWD sensors may also include additional/alternative sensing devices for measuring shock, vibration, weight on bit, torque, telemetry, etc. The above-noted devices may transmit data to a downhole communicator33, which in turn transmits the data uphole to the surface control unit40. In some embodiments, the BHA22may also include a Logging While Drilling (LWD) System.

A transducer43can be placed in the mud supply line38to detect mud pulses responsive to the data transmitted by the downhole communicator33. The transducer43in turn generates electrical signals, for example, in response to the mud pressure variations and transmits such signals to the surface control unit40. 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. A surface transmitter/receiver80communicates with downhole tools using, for example, any of the transmission techniques described, such as a mud pulse telemetry technique. This can enable two-way communication between the surface control unit40and the downhole communicator33and other downhole tools.

The BHA22and/or RSS58can provide some or all of the requisite force for the bit50to break through the formation46(known as “weight on bit”), and provide the necessary directional control for drilling the borehole26. The RSS58may include a steering section with steering pads60extendable in a lateral direction from a longitudinal axis AO of the RSS58to push against the geologic formation46. The steering pads60may comprise hinged pads, arms, fins, rods, energized stabilizer blades or any other element extendable from the RSS58to contact the side56of the borehole26. The steering pads60may be circumferentially spaced around the RSS58, and may be individually extended to contact the side56of the borehole26to apply an opposing side force to drill bit50laterally to the longitudinal axis of the RSS58with respect to the borehole26while drilling. The steering pads60may include a set of at least three externally mounted steering pads60to exert force in a controlled manner to deviate the drill bit50in the desired direction for steering. In some embodiments, the steering pads60are energized by a small percentage of the drilling fluid or mud31pumped through the drill string20and drill bit50for cuttings removal, cooling and well control. The RSS58is thereby using the “free” hydraulic energy of the drilling fluid or mud31for directional control. For traditional electrical servomotor/solenoid-type drive systems, the power requirement is in the order of 100-300 W. The steering pads60may provide an adjustable force to assist in controlling the direction of the borehole26. The RSS58also includes a stabilizer62coupled to a control section thereof.

FIG. 2is a schematic view of a bottom hole assembly100including a flexible collar102coupled to an up-hole end of an RSS104. The flexible collar102may include a structural connector106such as threads, latches, etc. at leading or downhole end thereof for selectively coupling to a trailing or uphole end of the RSS104. The RSS104includes a control section110, flow control section112and steering section114, each of which may be packaged in a single housing. Alternatively, structural connectors116may be provided between the control section110, the flow control section112and the steering section114. The flexible collar102may be constructed to exhibit a lower bending stiffness than the housing or housings of the control section110, flow control section112and the steering section114. may include a drill string coupler120at an uphole end thereof for coupling the BHA100to the drill pipe section24(FIG.1) of the drill string20. The bottom hole assembly100may then exhibit greater flexibility than the RSS104alone.

The drill bit50is coupled to the downhole end of the steering section114, which includes a plurality of steering pads60or other pushing devices for steering the drill bit50. The steering pads60may be constructed as hinged pad pushers, steering pistons or similar pistons such as those found on adjustable gauge stabilizers (not shown). The flow control section112is coupled above the steering section114(or comprises an uphole portion of the steering section114), and is operable to divert a portion of the total drilling fluid or mud31(FIG. 1) pumped through the BHA100. Typically, the flow control section112may include a valve set210(FIG. 3A) that deviates about 5-8% from the main mud flow. The diverted portion passes through a filter element before being directed to the respective steering pad60or pushing device through flow paths defined in the steering section114. The flow deviation is generally achieved using mechanically driven/controlled valve assemblies210, but other arrangements are also contemplated. In order to control and drive the mechanical valve assemblies210, servo motor, gearbox and/or bearing assemblies are traditionally employed. These gearbox and/or bearing assemblies can require volume compensation systems, if oil filling is required, and sealing solutions to prevent the ingress of drilling fluid or mud31.

The control section110houses an electronics assembly212(FIG. 3A) including Directional and Inclination (D&I) sensor packages, Gamma Ray (GR) sensor packages, and others types of MWD or LWD sensors. The control section110may also include a CPU, power conditioning, and communication device (e.g., the downhole communicator33). Power generation and/or power supply components are also generally located inside the Control Section110. The power generation and/or supply components need to be sufficiently sized to power the electronics assembly212, drive the mechanical valve assemblies and overcome any frictional losses created by seals, bearings, gearboxes, etc. The stabilizer62is coupled to an outer housing122of the control section110.

The theoretical steering capability of the BHA100is generally defined by a curve that can be fitted through the stabilizer62, steering pads60and drill bit50. These are the components that generally contact the geologic formation46(FIG. 1) when forming the wellbore26. Flexing of the control section110, flow control section112and steering sections114can increase the steering response of the BHA100in operation, but flexing of these sections110,112,114is typically limited in order to prevent damage or disruption of the internal components of these sections110,112,114, which could lead to a reduction in directional control accuracy (e.g., toolface control).

FIG. 3Ais a schematic view of an RSS200having the flexible collar102coupled therein, in accordance with the present disclosure. The flexible collar102is coupled between the steering section114and the control section110. As illustrated inFIG. 3A, the flow control section112is housed together with the steering section114in a housing206. The control section110includes a modular control and sensor electronics assembly212, and the flow control section112includes the valve assemblies210and other flow control devices. The valve assemblies210in the flow control section112may require an electrical connection to the electronics assembly212in the control section110for operation. Where the valve assemblies210include a battery or other power source (not shown) contained in the housing206of the steering section114, the valve assemblies210may only need instructions to be communicated across the flexible collar102. The instructions may be received by a communication reception unit218of the steering section114. Where the valve assemblies210do not include a power source, the valve assemblies210may need to receive instructions as well as power through the flexible collar102. Instructions and data may be transmitted through an electrical conductor such as a multi-conductor communication cable222, wire or other electrical conduit extending through the flexible collar102. A communication transmission unit224may be operatively coupled to the modular electronics assembly212to receive instructions therefrom, and may be operatively coupled to the communication cable222to transmit the instructions therethrough. Since only an electrical communication cable222needs to pass therethrough, the flexible collar102with reduced bending stiffness may be added very close to the drill bit50, i.e., directly above the steering pads60.

A leading stabilizer230is provided steering section114, and extends laterally from the housing206. The leading stabilizer230may prevent a portion of the bending stresses applied to a drill string20(FIG. 1) extending through a curved borehole from being applied to the steering pads60. These bending stresses have been found, in some instances, to cause the steering pads60to partially retract into the housing206, thereby preventing effective steering of the drill bit50. The leading stabilizer230may be disposed adjacent or above the steering pads60, and may protrude from the same housing206as the steering pads60.

A power section232is provided above the control section110. The power section232may include turbine blades (not shown) that extract energy from drilling mud31(FIG. 1) pumped down the drill string20(FIG. 1) to generate electrical power for the electronics assembly212, communication transmission unit224, communication reception unit218and the valve assemblies210. The valve assemblies210may rely on an electric motor (not shown) for selectively providing drilling mud to the steering pads60.

FIG. 3Bis a cross-sectional view of the flexible collar102. The flexible collar102generally defines a first outer diameter OD1at leading end240and a trailing end242thereof. The first outer diameter OD1may be similar to the outer diameters of the housings122(FIG. 2) and206(FIG. 3A) of the control section110and steering section114. A reduced diameter portion246between the leading and trailing ends240,242defines a second outer diameter OD2that is less than the first outer diameter OD1. The reduced diameter portion246provides a reduced bending stiffness to the flexible collar102. In some embodiments, the reduced diameter portion246may be gradually transitioned or necked down or from the leading and trailing ends240,242. In other embodiments, the flexible collar102can be implemented in forms other than a traditional necked down collar section, such as a fully articulated universal joint. The lower the bending stiffness of the flexible collar102or flex section, the more the tool RSS200(FIG. 3A) behaves like a point-the-bit rotary steerable system with the potential of achieving very high dogleg severities. The flexible collar102could be made replaceable to configure the RSS200based on required steering response. Detailed modeling may be required to determine if a particular flexible collar102or flex section is necessary to achieve the required dogleg severity for a particular project. In case flexing is not required, the flex collar102may be removed (seeFIG. 7).

In other embodiments, the reduced bending stiffness of the flexible collar102may be provided by other geometries. For example, a flexible collar may be constructed with a constant outer diameter OD1, but with a reduced wall thickness with respect to the control section110, flow control section112or the steering section114(FIG. 3A). Alternatively or additionally, notches or circumferential grooves may be defined in a wall of the flexible collar to provide a reduced bending stiffness. Also, a selection of materials may provide for the reduced bending stiffness. For example, where the control section110, flow control section112or the housing206of the steering section114is constructed of steel, a flexible collar may be s the flexible collar102may be constructed of titanium or another material more flexible than steel.

A wear band280may be provided or applied on the trailing end242of the flexible collar102. As illustrated inFIG. 3B, the wear band280may be disposed on a portion of the trailing end242that exhibits a reduced third diameter OD3that is less than the first outer diameter OD1and greater than the second outer diameter OD2. In other embodiments, (not shown) the wear band280may be applied on a portion of the leading240or trailing end242that defines the first outer diameter OD1or a larger diameter than OD1. The wear band280may protect the flexible collar102in case of contact with the side56of borehole26(FIG. 1). Wear band280may comprise a hardfacing material, such as tungsten carbide matrix. The wear band280may comprise a metal sleeve that is press fit or shrink fit to the leading or trailing ends240,242, e.g., about OD1or OD3.

Data and power transmission through the flexible collar102can be achieved in a variety of ways, e.g., a wired extender running through the Flex Section, electrical conductors attached to or integrated with the flexible collar102, or even wireless power/data transmission over short distance such as electromagnetic, RF, mud pulse, infrared, and/or optical transmissions. As illustrated inFIG. 3B, the flexible collar102includes electrical connectors250,252at the leading and trailing ends240,242to facilitate coupling the flexible collar102to other sections110,112,114,232of the RSS200. The connectors250,252may comprise rotary connectors, e.g., connectors that may engage corresponding connectors in other RSS sections110,112,114,232of by relative rotational movement therebetween. In some embodiments, structural connectors254,256such as threads may be provided for coupling the flexible collar102to other sections110,112,114,232, such that the relative rotational motion establishes both structural and electrical connections between the flexible collar102and the other sections110,112,114,232. In some embodiments, the connectors250,252may comprise 8-pin rotational connectors to accommodate the data and power transmission through the flexible collar102. Depending on the power requirements of the flow control section, a small battery or compact power generation module, e.g., vibration based could be included. In that case only data transmission would be required facilitating a wireless solution.

The connectors250,252may be operably coupled to one another with electrical cable222(FIG. 3A). In some embodiments, a gun-drilled longitudinal bore260may be provided through a wall262of the flexible collar102. The longitudinal bore260may be radially offset from a primary flow passage264extending through the flexible collar102. Primary flow passage264may also be radially offset from first diameters OD1and/or second diameter OD2and/or third diameter OD3.

FIG. 4is a partial, cross-sectional side view of the RSS200illustrating a flow path therethrough. The flow path extends through the flexible collar102, which is coupled between the flow control section112and the control section110. The RSS200includes structural connectors106for receiving a flexible collar102between the control section110and the flow control section112. As illustrated inFIG. 4, the power section232and the control section110are housed together in an outer housing122and the flow control section112steering section114are housed together in a housing206. In some embodiments, structural connectors106may be provided between the power section232and the control section110as well as between the flow control section112and the steering section114. The stabilizers62and230(FIG. 3A) associated with the housings122,206are not explicitly illustrated inFIG. 4.

Fluid or mud31enters the power section232from the drill string20(FIG. 1). The mud31passes through a turbine270, which extracts energy from the mud31to operate an electrical generator272. The mud31passes around the electrical generator272and the control components such as the communication transmission unit224. The mud31enters the primary flow passage264of the flexible collar102and passes into the flow control section112. A valve assembly210diverts a portion of the mud31to selectively drive or extend the steering pads60, and a remainder of the mud31continues to the drill bit50. The diverted portion of the mud31is expelled through the housing206and the remainder of the mud is expelled through the drill bit50.

In operation, the generator272provides electrical power to the electronics in the control section110including various sensors and circuitry that may provide instructions to the valve assembly210. The instructions and/or electrical power may be transmitted from the communication transmission unit224to communication reception unit218through the communication cable222. The valve210may then be operated according to the instructions received at the communication reception unit218.

As indicated above, the control section110features a modular electronics assembly212(FIG. 3A) including sensor packages for D&I (direction and inclination), GR (gamma ray), and others as well as CPU, power conditioning, and communication. The power generation/supply module section232is also generally located inside the control section110. In order to allow easy diagnostics and maintenance, a high degree of modularity is very desirable combined with onboard diagnostics and memory on each module232,110,112,114to allow fault finding, service life tracking and accumulative run history capture.

FIG. 5is a partial, cross-sectional side view of an RSS300having a controller302disposed within a flexible collar304thereof. The controller302may include any of the sensors and control components associated with the modular sensor and electronics assembly212(FIG. 3A). Where the controller302may withstand the flexing of the flexible collar302, the overall length of the RSS300may be reduced by taking advantage of available space in the flexible collar302. The flexible collar302may also be used to mount sensors to measure and record drilling parameters such as weight on bit (WOB), torque on bit (TOB), and bending moment and bending direction loads; important data that can be used as for directional control.

In some embodiments, a strain gauge (not shown) may be included in the controller302for measuring the bending of the flexible collar in operation. The controller302is illustrated as being disposed in a necked down or reduced diameter portion310between the leading and trailing ends312,314of the flexible collar304. In other embodiments, the controller302or portions of the controller302, may be disposed in the leading and trailing ends312,314. The controller302may be coupled to the communication reception unit218by the communication cable222, and may be coupled to the generator272by a power cable320.

FIG. 6is a cross-sectional side view of an RSS400having a dynamic survey sensor package402disposed below a flexible collar404thereof and a stationary survey sensor package406disposed above the flexible collar404. In order to improve the steerability and response of the RSS400, a selection of direction and inclination sensors may be placed in the dynamic survey sensor package402below the flexible collar404. Placement of the dynamic survey sensor package402below the flexible collar404, e.g., in a steering section410may provide an early indication of directional output. The flexible collar404within the RSS400will make the RSS400highly agile and will provide a high dogleg capability. Near bit direction; and/or inclination measurement data may be provided by the dynamic survey sensor package402in the steering section410(or in some embodiments, in the flexible collar404) for measurement of the inclination and/or direction of the drill bit50and/or other characteristics of a drilling operation. The stationary survey sensor package406may be provided in the control section412for providing MWD and/or LWD capabilities, and will allow the development of more sophisticated control system and paths for automation. The near bit measurements from the dynamic survey sensor package402may be of a lower quality and may be combined with the higher quality D&I data from the stationary survey sensor package406to make steering decisions. An additional dynamic survey sensor package403may be provided in the control section412for comparison to dynamic survey sensor package402in the steering section410while drilling. Such comparison may provide an early indication of local dogleg severity, local dogleg direction as well as bending magnitude and bending direction of the flexible collar404. The addition of dynamic survey sensor package403also provides redundancy to dynamic survey sensor package402for increased reliability during drilling operations.

Similar structural connectors416are provided at leading ends of the flexible collar404and a housing420of the control section412. Also similar electrical connectors424may be provided at the leading ends of the flexible collar404and the control section412.

FIG. 7is a cross-sectional side view of the RSS400having the flexible collar404removed therefrom. The similar structural connectors416and electrical connectors424in the RSS400permit a direct connection between the control section412and steering section410if the flexible collar404is removed.

FIG. 8is a schematic view of an RSS500disposed within a wellbore502. The RSS500includes a flexible collar504disposed between a steering section508and a control section510thereof. A valve motor512is disposed in the control section510and a valve motor shaft514extends through the flexible collar504between the valve motor512and a valve520. The valve520is operably coupled to a piston522, which is in turn operably coupled to a steering pad524for engaging a wall526of the borehole502to steer a drill bit530. A steering controller532may be operably coupled to a turbine534and generator536to receive electrical power therefrom. The steering controller532may control the valve motor512, which may in turn, communicate instructions to the valve520in the steering section508through mechanical motion of the motor shaft514. The steering controller532may include a stationary survey sensor540package therein.

FIG. 9is a schematic view of an RSS600disposed within a wellbore602. The RSS600includes a flexible collar604disposed between a steering section608and control section610thereof. A valve motor612is disposed in the steering section608and is coupled to a steering controller614via a power/control line616extending through the flexible collar604. The power/control line616may extend through a conduit618that isolates the power/control line616from drilling fluids31(FIG. 1). An orientation/survey sensor set or stationary survey sensor package620may be provided in the steering controller614and a secondary orientation/survey sensor set or dynamic survey sensor package622may be disposed on an opposite side of the flexible collar604in the steering section608. The secondary orientation/survey sensor set or dynamic survey sensor package622is optional and may be of higher dynamic range but lower accuracy than the upper orientation/survey sensor arrangement or stationary survey sensor package620in the control section610. Typically, the secondary orientation/survey sensor arrangement could be used while rotating the drill string20(FIG. 1) during drilling to make measurements below the flexible collar604. The data from the stationary and dynamic survey sensor packages620,622, including inclination and azimuth, may be compared to one another to determine amount of difference between the two, and to determine an amount of flex and thus curvature in the bore hole602.

A turbine634and generator636may be provided for supplying electrical power to the steering controller614, which may distribute power among the stationary and dynamic survey sensor packages620,622, and the valve motor612. The valve motor612is operably coupled to a valve640by a valve motor shaft642. The valve640may be coupled to a piston643, which is in turn operably coupled to a steering pad644for engaging a wall646of the borehole602to steer a drill bit650.

The aspects of the disclosure described below are provided to describe a selection of concepts in a simplified form that are described in greater detail above. This section is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter.

In one aspect, the disclosure is directed to a rotary steerable system. The rotary steerable system includes a steering section connectable to a drill bit. The steering section defines a longitudinal axis and includes at least one steering pad selectively extendable in a lateral direction from the longitudinal axis. The rotary steerable system also includes a control section that includes a steering controller. The steering controller is operable for generating instructions to selectively extend the at least one steering pad. The rotary steerable system also includes a flexible collar coupled between steering section and the control section. The flexible collar has a reduced bending stiffness with respect to the steering section and the control section.

In one or more example embodiments, the flexible collar includes a reduced diameter central portion between leading and trailing ends of the flexible collar. The reduced diameter central portion defines an outer diameter that is less than an outer diameter of the leading and trailing ends. The flexible collar may include a primary flow passage extending therethrough and a longitudinal bore radially offset from the primary flow passage. The longitudinal bore may extend through a wall of the reduced diameter portion. The flexible collar may include an electrical conductor extending through the longitudinal bore, the electrical conductor operably coupled between a communication transmission unit in the control section and the communication reception unit in the steering section.

In some embodiments, the control section and the flexible collar each include similar structural connectors at respective leading ends thereof for selectively coupling to the steering section. In some embodiments, the control section and the flexible collar each include similar electrical connectors at the respective leading ends thereof for selectively coupling to the communication reception unit.

In one or more example embodiments, the control section includes a stabilizer thereon extending radially from a housing of the control section. In some embodiments, the steering section also includes a leading stabilizer thereon extending radially from a housing of the steering section.

In some embodiments, the steering controller communicates wirelessly with a communication reception unit across the flexible collar through electromagnetic, RF, mud pulse, infrared, optical and/or other types of signals. In some embodiments the flexible collar includes an electronics package therein, and the electronics package may be operable for controlling the at least one steering pad in the steering section.

In one or more example embodiments, the control section includes a stationary survey sensor package therein for providing MWD and/or LWD capabilities, and the steering section includes a dynamic survey sensor package therein for measurement of the inclination of the drill bit and/or other characteristics of a drilling operation in use. The dynamic survey sensor package may be less accurate than the stationary survey sensor package.

In some embodiments, the steering section includes a plurality of steering pads circumferentially spaced therearound, and a valve set operable for diverting a portion of mudflow to the steering pads. In some example embodiments, the control section includes a valve motor therein operably coupled to the steering controller, and wherein the flexible collar includes a flexible mechanical shaft extending therethrough and operably coupled between the valve motor in the control section and the valve set in the steering section.

In another aspect, the disclosure is directed to a rotary drilling system. The rotary drilling system includes a drill string, a drill bit, and a control housing coupled to a leading end of the drill string. The rotary drilling system also includes a steering controller disposed within the control housing, and the steering controller operable to generate instructions for steering the drill bit. The rotary drilling system also includes a steering housing defining a longitudinal axis and coupled to an upper end of the drill bit and at least one steering pad selectively extendable from the steering housing in response to instructions from the steering controller. The rotary drilling system also includes a flexible collar coupled between control housing and the steering housing. The flexible collar has a reduced bending stiffness with respect to the control housing and steering housing.

In one or more example embodiments, the flexible collar includes leading and trailing ends defining a first outer diameter similar to an outer diameter of the steering and control housings, and the flexible collar includes a necked-down reduced diameter portion between the leading and trailing ends. The reduced diameter portion may define a second outer diameter less than the first outer diameter. In some embodiments, the flexible collar includes a primary flow passage in fluid communication with the drill string, and a longitudinal bore radially offset from the primary flow passage and having an electrically conductive cable extending therethrough for communicating the instructions from the steering controller through the flexible collar. In some embodiments, the rotary drilling system further includes a stationary survey sensor package disposed within the control housing, a dynamic survey sensor disposed within the steering housing, and a surface control unit operably coupled to the stationary and dynamic survey sensor packages for receiving measurements of the direction and inclination of the drill bit.

In another aspect, the disclosure is directed to a method for drilling a wellbore. The method includes (a) conveying a rotary steerable system into a wellbore, (b) generating instructions for steering a drill bit coupled to a lower end of the rotary steerable system with a steering controller disposed within a control housing of the rotary steerable system, (c) transmitting the instructions across a flexible collar of the rotary steerable system, the flexible collar having a reduced bending stiffness with respect to the control housing, and (d) extending at least one steering pad from a steering housing of the rotary steerable system coupled below the flexible collar in response to receiving the instructions from the steering controller below the flexible collar.

In some example embodiments, the method further includes removing the flexible collar from the rotary steerable system and coupling the control housing directly to the steering housing. In some embodiments, the method further includes comprising measuring a direction and inclination of the drill bit with a stationary survey sensor package disposed above the flexible collar, and measuring the direction and inclination of the drill bit with a dynamic survey sensor package disposed above the flexible collar. In some embodiments, the method further comprises measuring a direction and inclination of the drill bit with an additional dynamic survey sensor package disposed above the flexible collar and comparing measurements made above the flexible collar with measurements made below the flexible collar.

The Abstract of the disclosure is solely for providing the United States Patent and Trademark Office and the public at large with a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more examples.

While various examples have been illustrated in detail, the disclosure is not limited to the examples shown. Modifications and adaptations of the above examples may occur to those skilled in the art. Such modifications and adaptations are in the scope of the disclosure.