US20030127252A1

US20030127252A1 - Motor Driven Hybrid Rotary Steerable System

Info

Publication number: US20030127252A1
Application number: US10/248,054
Authority: US
Inventors: Geoff Downton; Steven Hart; John Rowatt
Original assignee: Schlumberger WCP Ltd
Current assignee: Schlumberger UK Holdings Ltd
Priority date: 2001-12-19
Filing date: 2002-12-13
Publication date: 2003-07-10
Also published as: GB0412334D0; GB0514634D0; US7188685B2; GB2413346A; GB2406110B; GB0412333D0; WO2003052236A1; WO2003052237A1; GB2399121A; AU2002352414A1; GB2413346B; US20030121702A1; GB2399121B; AU2002352415A1; GB2406110A

Abstract

Abstract of Disclosure

A bottom hole assembly is rotatably adapted for drilling directional boreholes into an earthen formation. It has an upper stabilizer mounted to a collar, and a rotary steerable system. The rotary steerable system has integral drilling motor, an upper section connected to the collar, a steering section, and a drill bit arranged for drilling the borehole attached to the steering section. The steering section is joined at a swivel with the upper section. The steering section is actively tilted about the swivel. A lower stabilizer is mounted upon one of the upper section or the steering section such that the swivel is intermediate the drill bit and the lower stabilizer.

Description

Background of Invention

1. Field of the Invention.[0001]
This invention relates to a bottom hole assembly comprising a rotary steerable directional drilling tool with an integral drilling-motor, which is useful when drilling boreholes into the earth.[0002]
2. Description of the Related Art.[0003]
Rotary steerable drilling systems for drilling deviated boreholes into the earth may be generally classified as either "point-the-bit"systems or "push-the-bit"systems. In the point-the-bit system, the axis of rotation of the drill bit is deviated from the local axis of the bottom hole assembly (BHA) in the general direction of the new hole. The hole is propagated in accordance with the customary three point geometry defined by upper and lower stabilizer touch points and the drill bit. The angle of deviation of the drill bit axis coupled with a finite distance between the drill bit and lower stabilizer results in the non-collinear condition required for a curve to be generated. There are many ways in which this may be achieved including a fixed bend at a point in the BHA close to the lower stabilizer or a flexure of the drill bit drive shaft distributed between the upper and lower stabilizer. In its idealized form, the drill bit is not required to cut sideways because the bit axis is continually rotated in the direction of the curved hole. Examples of point-the-bit type rotary steerable systems, and how they operate are described in U.S. Patent Application Publication Nos. 2002/0011359; 2001/0052428 and U.S. Patent Nos. 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610; and 5,113,953 all herein incorporated by reference. [0004]
In the push-the-bit rotary steerable system there is usually no specially identified mechanism to deviate the bit axis from the local BHA axis; instead, the requisite non-collinear condition is achieved by causing either or both of the upper or lower stabilizers to apply an eccentric force or displacement in a direction that is preferentially orientated with respect to the direction of hole propagation. Again, there are many ways in which this may be achieved, including non-rotating (with respect to the hole) eccentric stabilizers (displacement based approaches) and eccentric actuators that apply force to the drill bit in the desired steering direction. Again, steering is achieved by creating non co-linearity between the drill bit and at least two other touch points. In its idealized form the drill bit is required to cut side ways in order to generate a curved hole. Examples of push-the-bit type rotary steerable systems, and how they operate are described in U.S. Patent Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763; 5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein incorporated by reference. [0005]
Although such distinctions between point-the-bit and push-the-bit are useful to broadly distinguish steering systems, a deeper analysis of their hole propagation properties leads one to recognize that facets of both are present in both types of deviated borehole steering systems. For example, a push-the-bit system will have a BHA that is not perfectly stiff, enabling the bit to be effectively pointed and so a proportion of hole curvature is due to the bit being pointed. Conversely, with point-the-bit systems that use a fixed bend offset, a change in hole curvature requires the bit to cut sideways until the new curvature is established. Changes in hole gauge and stabilizer wear effectively cause the bit to be pointed in a particular direction, which may or may not help the steering response, regardless of steering system type. In the extreme, push-the-bit systems that use drill bits with little or no side cutting ability may still achieve limited steering response by virtue of the aforementioned flexibility of the BHA or stabilizer/hole gauge effects.[0006]
An additional problem occurs when extremely small bend radiuses are included in the build. Mechanical fatigue in the drill pipe may occur as it is rotated in bending. When the bend is sharp and the drilling rate is slow, the fatigue life of the drill pipe may be exceeded, leading to either "tripping" the pipe to replace it, or failure of the pipe. Neither alternative is acceptable. One way to limit this problem is to drill with a drilling-motor. Since the drilling-motor supplies the majority of the rotation required for drilling, the drill pipe needs only to be rotated at a relative low RPM, just enough to prevent sticking.[0007]
Unfortunately, adding a drilling-motor to the BHA can cause the assembly to be too long to easily pass through the bend section to begin drilling. Adding a motor makes the assembly longer - and what ever is beneath the motor is subject to high cyclic bending forces when going through a tight bend. There are numerous other problems as well particularly when the minimum speed of the drilling-motor approaches the maximum speed of the rotary steerable tool. [0008]
It is into this broad classification of deviated borehole steering systems that the invention disclosed herein is launched. The hybrid steering system of the present invention incorporates an integral drilling-motor into the rotary steerable system, and combines the advantages of both the classical point-the-bit and push-the-bit systems by incorporating all into a single integral scheme.[0009]

Summary of Invention

Disclosed herein is a bottom hole assembly that is rotatably adapted for drilling directional boreholes into an earthen formation. It has an upper stabilizer mounted to a collar, and a rotary steerable system. The rotary steerable system has an upper section connected to the collar, a steering section, and a drill bit attached to the steering section. The rotary steerable system is adapted to transmit a torque from the collar to the drill bit. The upper section contains an integral drilling-motor. The steering section is joined at a swivel with the upper section. The steering section is actively tilted about the swivel and has a lower stabilizer. The lower stabilizer is mounted upon one of the upper section or the steering section such that the swivel is intermediate the drill bit and the lower stabilizer.

In this arrangement, the location of the contact between the drill bit and the formation is defined by the offset angle of the axis of the drill bit from the tool axis and the distance between the drill bit and the swivel. The theoretical build rate of the tool is then defined by the radius of curvature of a circle determined by this contact point and the two contact points between the formation and the upper stabilizer and lower stabilizer. The dogleg is also influenced by the side cutting characteristic of the bitA drilling fluid actuated motor system is used to point the portion of the steering section rigidly attached to the drill bit. Such a system utilizes the "free" hydraulic energy available in the drilling fluid as it is pumped through the tool to displace motors and/or pads to control the orientation of the tool while drilling. This minimizes the amount of electrical power that must be developed downhole for toolface control. Further, control of a motor system may be accomplished by numerous mechanical and electrical means, for example rotary disc valves to port drilling fluid to the requite actuators or similar arrangements utilizing solenoid actuated valves, affording great flexibility in implementation.

Brief Description of Drawings

Figure 1 is a perspective view of a bottom hole assembly within a borehole in the earth, as typically used in the practice of the present invention.[0012]
Figure 2 is a partial section view of one embodiment of the hybrid rotary steerable tool with an integral drilling-motor of the present invention.[0013]
Figure 3 is a partial section view of a second embodiment of the hybrid rotary steerable tool with an integral drilling-motor of the present invention.[0014]
Figure 4 is a partial section view of one arrangement of the integral drilling-motor of Figure 3.[0015]
Figure 5 is a partial section view of a second arrangement of the integral drilling-motor of Figure 3.[0016]

Detailed Description

Referring now to Figures 1-5, when drilling [0017] directional boreholes 4 into earthen formations 6, it is common practice to use a bottom hole assembly as shown in Figure 1. The bottom hole assembly (BHA), generally indicated as 10, is typically connected to the end of the tubular drill string 12 which is typically rotatably driven by a drilling rig 14 from the surface. In addition to providing at least a portion of the motive force for rotating the drill string 12, the drilling rig 14 also supplies a drilling fluid 8, under pressure, through the tubular drill string 12 to the bottom hole assembly 10. The drilling fluid 8 is typically laden with abrasive material, as it is repeatedly re-circulated through the borehole 4. In order to achieve directional control while drilling, components of the bottom hole assembly 10 may include one or more drill collars 16, one or more drill collar stabilizers 18 and a rotary steerable system 20. The rotary steerable system 20 is the lowest component of the BHA 10 and includes an upper section 22 having an integral drilling-motor 50 and also typically housing the electronics and other devices necessary for control of the rotary steerable system 20, and a steering section 24.
The [0018] upper section 22 is connected to the last of the drill collars 16 or to any other suitable downhole component. Other components suited for attachment of the rotary steerable system 20 include drilling motors, drill collars, measuring while drilling tools, tubular segments, data communication and control tools, cross-over subs, etc. For convenience in the present specification, all such suitable components will henceforth be referred to as collars 17. An upper stabilizer 26 is attached to one of the collars 17, preferably the one adjacent to the rotary steerable system 20 or to the upper section 22 of the rotary steerable system 20. The steering section 24 includes a drill bit 28. A lower stabilizer 30A may be attached to the upper section 22 or a lower stabilizer 30B may be attached to the steering section 24 but not to both.
A surface control system (not shown) is utilized to communicate steering commands to the electronics in the [0019] upper section 22, either directly or via a measuring while drilling module 29 included among the drill collars 16. The drill bit 28 is tilted about a swivel 31 (typically a universal joint 32) mounted in the steering section 24 (as shown in Figures 2 and 3). The swivel 31 itself may transmit the torque from the drill string 12 to the drill bit 28, or the torque may be separately transmitted via other arrangements. Suitable torque transmitting arrangements include many well-known devices such as splined couplings, gearing arrangements, universal joints, and recirculating ball arrangements. These devices may be either integral with the upper section 22 or the steering section 24, or they may be separately attached for ease of repair and/or replacement. The important function of the swivel 31, however, is to provide a 360 degree pivot point for the steering section 24.
The [0020] steering section 24 is intermittently actuated by one or more motors 39 about the swivel 31 with respect to the upper section 22 to actively maintain the bit axis 34 pointing in a particular direction while the drill bit 28 is rotated at drill string plus drilling-motor RPM. The term "actively tilted" is meant to differentiate how the rotary steerable system 20 is dynamically oriented as compared to the known fixed displacement units. "Actively tilted" means that the rotary steerable system 20 has no set fixed angular or offset linear displacement. Rather, both angular and offset displacements vary dynamically as the rotary steerable system 20 is operated.
The use of a universal joint 32 as a [0021] swivel 31 is desirable in that it may be fitted in a relatively small space and still allow the drill bit axis 34 to be tilted with respect to the rotary steerable system axis 38 such that the direction of drill bit 28 defines the direction of the wellbore 4. That is, the direction of the drill bit 28 leads the direction of the wellbore 4. This allows for the rotary steerable system 20 to drill with little or no side force once a curve is established and minimizes the amount of active control necessary for steering the wellbore 4. Further, the collar 17 can be used to transfer torque to the drill bit 28. This allows a dynamic point-the-bit rotary steerable system 20 to have a higher torque capacity than a static point-the-bit type tool of the same size that relies on a smaller inner structural member for transferring torque to the bit. Although the preferred way of providing a swivel 31 incorporates a torque transmitting device such as a universal joint 32, other devices such as flex connections, splined couplings, ball and socket joints, gearing arrangements, etc. may also be used as a swivel 31.
A particular advantage of this arrangement is that no external part of the [0022] bottom hole assembly 10 need ever be stationary with respect to the hole while drilling is in progress. This is important to avoid hang-up on obstructions, it being significantly easier to rotate over such obstructions while running in or out than a straight linear pull.
Referring now to Figures 2 and 3, are shown two embodiments of the rotary [0023] steerable system 20 with an integrated drilling-motor. Both embodiments reflect different placements of the lower stabilizer 30A and 30B. The lower stabilizer 30A may be placed on the upper section 22, or the lower stabilizer 30B may be placed on the periphery of the steering section 24, but only on one or the other. This slight difference in the placement of the lower stabilizer 30A, 30B has significant implications on the drilling mechanics of the tool as well as the range of angular deviation of the borehole 4, also known as dogleg capability.
Pistons 40 are the preferred motors 39 acting on the on the periphery of the [0024] steering section 24 apply a force to tilt the drill bit 28 with respect to the tool axis such that the direction of drill bit 28 broadly defines the direction of the well. The pistons 40 may be sequentially actuated as the steering section 24 rotates, so that the tilt of the drill bit is actively maintained in the desired direction with respect to the formation 6 being drilled. Alternately, the pistons 40 may be intermittently actuated in a random manner, or in a directionally-weighted semi-random manner to provide for less aggressive steering, as the steering section 24 rotates. There are also events during drilling when it may be desirable to activate either all or none of the pistons 40 simultaneously.
When the [0025] lower stabilizer 30A is located on the upper section 22, the rotary steerable system 20 steers in a manner similar to a classical point-the-bit system after a curve is established in the borehole 4. This arrangement relies primarily upon the end cutting action of the drill bit 28 for steering when drilling with an established curvature.
The mode is different, however, when the borehole curvature is changed or first being established. The force applied by the pistons 40 urges the drill bit so that it gradually tilts as it drills forward. It is the application of a force in this manner that provides the desirable push-the-bit mode when initially establishing, or consequently changing, the curvature of the [0026] borehole 4. Although this arrangement is an improvement over a pure point-the-bit system of the prior art, the steering mode during curvature changes is still partially point-the-bit, because both side cutting and end cutting of the bit are required.
Even so, this mode is clearly different than the traditional fixed bent-sub means for changing hole curvature. Therefore, this arrangement has advantages over the prior art because the drill bit is not forced into a set tilting displacement, as is common with similarly configured steerable systems of the prior art.[0027]
When the [0028] lower stabilizer 30A is located on the upper section 22, the location of the contact 42 between the drill bit 28 and the formation 6 is defined by the offset angle of the axis 44 of the drill bit 28 from the tool axis 38 and the distance between the drill bit 28 and the swivel 31.
When [0029] lower stabilizer 30B is placed on the periphery of the steering section 24, it provides a different steering topology. This arrangement defines two points of contact on the periphery of the steering section 24 and the formation 6 (i.e., contact at the drill bit 28 and the lower stabilizer 30B). As such, this arrangement steers like both a push-the-bit and point-the-bit system. Specifically, the periphery of the steering section 24 acts as a short rigid member with a drill bit 28 at its lower end and a nearly full gauge stabilizer 30B at its upper end. This geometry limits how much the periphery of the steering section 24 can tilt with respect to the tool axis 38. The periphery of the steering section 24 will tilt until the lower stabilizer 30B contacts the formation 6 at which point the motors 39 then act to push-the-bit through the formation 6, relying primarily on the side cutting action of the drill bit 28. As the formation 6 is removed by the side cutting action of the drill bit 28, the periphery of the steering section 24 is allowed to tilt further with respect to the tool axis 38 (i.e., the geometric constraint imposed by the formation 6 is removed) and the tool then begins to steer as a point-the-bit system, relying primarily on the end cutting action of the bit.
Analysis shows that by combining aspects of both push-the-bit and point-the-bit systems, this arrangement of the hybrid design affords a means of achieving higher build rates than a point-the-bit system with the same angular deflection of the [0030] steering section 24. The theoretical build rate of the tool is then defined by the radius of curvature of a circle determined by this contact point 42 and the two contact points 46, 48 between the formation and the upper stabilizer 26 and lower stabilizer 30B.
The dogleg response for the hybrid rotary [0031] steerable system 20 where the lower stabilizer 30B is mounted on the steering section 24 due to changes in actuator displacement (ecc) using consistent units is: $Dogleg (\deg / 30 m) = \frac{ecc * \frac{(d - a)}{(b - a)} (1 + K * c) - u * (1 + K * d) + w^{*} (1 + K * c)}{- c^{2 *} (1 + K * d) + d^{2} * (1 + K * c)}$
Where (displacement in meters):ecc= displacement of motors 39 contributing to deflection of the [0032] swivel 31.
u= the extent of under gauge at the [0033] touch point 48 at the lower stabilizer 30B on the steering section 24 of the rotary steerable system 20.
w = the extent of under gauge at the [0034] touch point 46 at upper stabilizer 26.
a= distance from bit to the [0035] swivel 31.
b= distance from bit to motor 39.[0036]
c= distance from [0037] bit 28 to lower stabilizer 30B on the rotary steerable system 20.
d= distance from [0038] bit 28 to upper stabilizer 26.
K = a factor depending on the bits ability to cut sideways, in units of per meter. (K=0 for a bit with no side cutting ability, K= infinity for a highly aggressive bit).[0039]
To this dogleg capability is added the effects of any BHA flexure, which according to sense may increase or reduce the effective response.[0040]
Both arrangements for the [0041] lower stabilizer 30A, 30B utilize an integrated drilling-motor 50 to provide rotary energy to effect drilling by the drill bit 28.
As shown in Figures 2-5, a drilling-[0042] motor 50 is integrated into the upper section. The drilling-motor 50 has a drive-shaft 52 which, as shown in figure 2, may be adapted to drive the lower stabilizer 30A, 30B whether mounted on either the upper section 22 or the steering section 24, in addition to the drill bit 28. In the embodiments shown in figures 3-5 the drive-shaft 52 may be extended to the steering section to drive just the steering section 24 and/or the drill bit 28. The drilling-motor 50 provides rotational energy in addition to that supplied by the drill rig 14 to the rotary steering system 20, as will be described.
The portion of the motive force for rotating the [0043] drill string 12 provided by the drilling rig 14 has a rate which is indicated by R1 in Figures 2 and 3. The addition of the integral drilling-motor 50 provides additional motive force for rotating the rotary steerable system 20, which is additive to that supplied by the drilling rig 14. The sum of the rate of this additional motive force and R1 is indicated by R2. For example, if the drilling rig 14 rotated the drill string 12 at say, 50 RPM, R1 would equal 50 RPM. If the drilling motor were simultaneously operated at say, 150 RPM, R2 would equal 200 RPM.
Because higher RPM"s tend to lead to faster wear and/or fatigue of the downhole components, it is desirable to rotate these wearable/fatigue-able components as slowly as possible. However, some rotation is often (although not necessarily always) supplied to the [0044] entire drill string 12 to help avoid sticking and other problems.
The different drive-[0045] shaft 52 arrangements of the drilling-motor 50 allow designers to trade-off differing levels of design complexity for differing arrangements of wear and fatigue prone components, to achieve varying degrees of improvement.
As illustrated in Figure 3, the drive-[0046] shaft 52 of the drilling-motor 50 may be arranged to drive the portion of the upper section 22 where the lower stabilizer 30A may be mounted. This would allow the drill string 14 to the collars 17 to be rotated at R1 and the working components of the rotary steerable system 20 to rotate at R2. This rather straightforward arrangement spares the majority of the BHA from the higher rates of wear and fatigue encountered if the entire drill string 12 were rotated fast enough for effective drilling. However, all the wearable/fatigue-able components of the rotary steerable system 20 are exposed to the higher rate R2.
In a second arrangement, shown in Figures 3 and 4, the drive-[0047] shaft 52 extends well beyond the drilling-motor 50 to a location on the upper section 22 beyond where the lower stabilizer 30A may be mounted. This allows the drill string 14 to the lower stabilizer 30A to be rotated at R1 and the other working components of the rotary steerable system 20 to rotate at R2. This more complex arrangement reduces wear of the lower stabilizer 30A. Bearings 54 are suitably located to allow the various sections of the upper section 22 to rotate with respect to each other. These bearings 54 may be arranged to accommodate axial push and pull loads as well as radial loads.
In a third arrangement, shown in Figure 5, the drive-[0048] shaft 52 extends all the way from the drilling-motor 50 to the center of the swivel 31. This allows the entire drill string 14 up to the drill bit 28 to be rotated at R1, and only the drill bit 28 to be rotated at R2. This arrangement requires a complex swivel 31 configuration with an inner swivel portion 56 to carry the power supplied by the drilling motor to be transmitted directly to the drill bit 28, and an outer swivel portion 58 to transmit the torque and tilt of the steering section 24 to the upper section 22. As previously described, flexible collars, joints, and other means may be used in the swivel arrangement and to transfer torque.
This is the most complex arrangement, but it also provides the greatest benefit for reduction of wear and fatigue, and also provides maximum operating flexibility.[0049]
The [0050] bottom hole assembly 10 of the preferred embodiment is therefore rotatably adapted for drilling directional boreholes 4 into an earthen formation 6. It has an upper stabilizer 26 mounted to a collar 17, and a rotary steerable system 20. The rotary steerable system 20 has an upper section 22 connected to the collar 17, a steering section 24, and a drill bit 28 arranged for drilling the borehole 4 attached to the steering section 24. The upper section 22 has an integral drilling-motor. The rotary steerable system 20 is adapted to transmit a torque from the collar 17 to the drill bit 28. The steering section 24 is joined at a swivel 31 with the upper section 22. The steering section 24 is actively tilted about the swivel 31. A lower stabilizer 30A, 30B is mounted upon one of the upper section 22 or the steering section 24 such that the swivel 31 is intermediate the drill bit 28 and the lower stabilizer 30B.
In the preferred embodiments, a drilling fluid 8 actuated piston 40 is the motor 39 system used to point the portion of the [0051] steering section 24 rigidly attached to the drill bit 28. Such a system utilizes the "free"hydraulic energy available in the drilling fluid as it is pumped through the tool to displace motors 39 and/or pads to control the orientation of the tool while drilling. This minimizes the amount of electrical power that must be developed downhole for toolface control. Further, control of a motor 39 system may be accomplished by numerous mechanical and electrical means, for example rotary disc valves to port drilling fluid 8 to the requite actuators or similar arrangements utilizing electrically or mechanically actuated valves, affording great flexibility in implementation.
There are numerous advantages to control with electrically controlled valve actuators. For example, rotary steerable systems are often rotated while the [0052] drill bit 28 is pulled back from the formation 6, and therefore not drilling. This may be necessary for hole cleaning, etc. During these times, the control system still causes the motors 39 to actuate, causing unnecessary wear. An actuator may be used to shut off the drilling fluid 8 flow to the rotary disc valve when the system is required to be in neutral. This arrangement would lower the wear experienced by the moving parts when the system is rotating.
In order to create a pressure drop to provide the "free" power, rotary [0053] steerable systems 20 typically use a choke which is intended to drop the pressure of the drilling fluid 8 supplied to the rotary valve in the case of operating conditions involving high drill bit pressures drops. By incorporating an actuator in the passage to shut off the supply of drilling fluid 8 to the rotary valve, the motors 39 may be shut down independently of the rotary valve.
Another condition where rotation is needed without actuation of the motors 39 is when a zero percentage dogleg condition is being demanded. Again, under these circumstances, the control system would activate the valve to shut off the drilling fluid 8 supply to the rotary valve. This effectively holds a neutral steering condition, minimizing wear of the moving parts and proportionality increase service life. As most of the drilling conditions involve low percentage steering conditions the life of the critical wear items would be considerably enhanced.[0054]
Suitable electrically controlled actuators for these various applications include solenoids, stepping motors, pilot controlled devices, mechanical or electrical direct activated bi-stable devices, and variants such as electro-magnetic ratcheting devices, thermally activated bi-stable devices, etc.[0055]
In a preferred embodiment, the [0056] swivel 31 is a universal joint 32. This may be a two-degree of freedom universal joint 32 that allows for rotation of the periphery of the steering section 24 around its axis 34, a variable offset angle, and also torque transfer. The maximum offset angle of the periphery of the steering section 24 is limited as will be described. The universal joint 32 transfers torque from the collar 17 to the periphery of the steering section 24.
Weight is transferred from the [0057] collar 17 to the periphery of the steering section 24. The universal joint 32 and other internal parts preferably operate in oil compensated to annulus drilling fluid 8 pressure. The offset of the periphery of the steering section 24 and the contact points 42, 46, and 48 between the well bore 4 and the drill bit 28, the lower stabilizer 30B and the upper stabilizer 26 define the geometry for three point bending and dictate the dog leg capability of the tool.
A set of internal drilling fluid 8 actuated motors 39, preferably pistons 40, is located within the periphery of the [0058] steering section 24. The drilling fluid 8 may act directly on the pistons 40, or it may act indirectly through a power transmitting device from the drilling fluid 8 to an isolated working fluid such as an oil. The pistons 40 are equally spaced and extended in the radial direction. The pistons 40 are housed within the steering section 24 and operate on differential pressure developed by the pressure drop across the drill bit 28. When actuated (synchronous with drill string rotation), these pistons 40 extend and exert forces on the periphery of the steering section 24 so as to actively maintain it in a geostationary orientation and thus a fixed toolface.
The control system governing the timing of the drilling fluid 8 actuator activation is typically housed in the [0059] upper section 22 and utilizes feedback data from onboard sensors and or an MWD system to determine tool face and tool face error.
Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.[0060]

Claims

1. What is claimed is:

1. A bottom hole assembly rotatably adapted for drilling directional boreholes into an earthen formation comprising an upper stabilizer mounted to a collar, and a rotary steerable system, the rotary steerable system comprising an upper section connected to the collar, a steering section, and a drill bit attached to the steering section, the rotary steerable system adapted to transmit a torque from the collar to the drill bit, the upper section comprising an integral drilling-motor, the steering section joined at a swivel with the upper section, the steering section actively tilted about the swivel and comprising a lower stabilizer, wherein the lower stabilizer is mounted upon one of the upper section or the steering section such that the swivel is intermediate the drill bit and the lower stabilizer.

2. The bottom hole assembly of claim 1 wherein the steering section is actively tilted by a plurality of activated motors to maintain a desired drilling direction as the bottom hole assembly rotates

3. The bottom hole assembly of claim 1 wherein no portion of the rotary steerable system exposed to the earthen formation is stationary with respect to the earthen formation while drilling.

3. 4. The bottom hole assembly of claim 1 wherein the rotary steerable system acts as a point-the-bit system after a curve is established in the borehole and as a push-the-bit system while establishing the curve.

4. 5. The bottom hole assembly of claim 2 wherein control of at least one of the motors is accomplished by porting a drilling fluid with a rotary disc valve or with an electrically actuated valve.

5. 6. The bottom hole assembly of claim 5 wherein the electrically actuated valve is selected from a group consisting of solenoids, stepping motors, direct activated bi-stable devices, electro-magnetic ratcheting devices, and thermally activated bi-stable devices.

6. 7. The bottom hole assembly of claim 2 wherein control of at least one of the motors is accomplished by porting a drilling fluid with a rotary disc valve and an electrically actuated valve.

7. 8. The bottom hole assembly of claim 7 wherein the electrically actuated valve is arranged in a passage to shut off the supply of the drilling fluid to the motor independently of the rotary valve.

8. 9. The bottom hole assembly of claim 8 wherein the supply of drilling fluid is shut off in response to a condition where rotation is needed without actuation of the motor.

9. 10. The bottom hole assembly of claim 9 wherein the rotary steerable system is effectively held in a neutral steering condition while drilling continues, minimizing wear of moving parts.

10. 11. The bottom hole assembly of claim 8 wherein the electrically actuated valve is selected from a group consisting of solenoids, stepping motors, direct activated bi-stable devices, electro-magnetic ratcheting devices, and thermally activated bi-stable devices.

11. 12. The bottom hole assembly of claim 1 wherein the swivel is a two-degree of freedom universal joint.

12. 13. The bottom hole assembly of claim 2 wherein at least one of the motors is a drilling fluid powered piston.