The complex trajectories and multi-target oil wells require the directed placement of a borehole's path and the ability to continually to control or “steer” the direction or path of the borehole during the drilling operation. Preferably, the path can be rapidly controlled during the drilling operation at any depth and target as the borehole is advanced by the drilling operation.
Directional drilling is complicated by the necessity to operate a drill bit steering device within harsh borehole conditions. The steering device is typically disposed near the drill bit, which terminates a lower or “downhole” end of a drillstring. Many types of devices known in the prior art have been used to control the direction of a drill bit. Some devices use stabilizers having ribs or extensions for engaging the wall of a borehole and controlling the direction of the drill bit as it bores through the ground. Other devices may use rotational valve systems for employing fluid to steering pads, may use magnetic switches to control directional changes, or may use non-rotatable sleeves for applying lateral force to a borehole to adjust drilling trajectories. Examples of some devices used to direct the trajectory of a drill bit can be found in U.S. Pat. Nos. 4,319,649; 6,840,336; and 7,503,408.
Many of the devices known in the art either require stopping the drillstring and/or moving the drillstring in one or two specified positions to create lateral forces within a borehole. Also, some devices require the use of motors downhole for drilling in directions relative to specific positioning of the drill bit, or employ pistons, pads, or other mechanics for creating lateral forces in the borehole.
Unfortunately, there are problems associated with many of the directional drilling techniques mentioned above. Particularly, having to stop the drillstring during drilling for either positioning purposes or for using a downhole motor is inefficient. Besides the apparent inconvenience of having to stop and start the drill string and/or position the drillstring relative to preset positions of the non-rotating component, most systems also require sliding the drillstring, after having stopped, in the new drilling direction determined by the direction drilled using the downhole motor.
Because of the friction induced on the drillstring and tools downhole, these methods may be inefficient or even damaging to downhole components. Further, because of the complexity of using hydraulic valves to employ pistons, or other methods, a simpler method for achieving a similar goal may be preferred.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.
A method and apparatus for steering a drilling assembly during drilling operations for oil and gas. The steering assembly being disposed in a borehole and comprising a drill bit attached to a drill collar having an eccentric stabilizer disposed there upon. The eccentric stabilizer either in an engaged state whereupon rotating concentrically with the drill collar, or in a released state whereupon as the drill collar rotates the eccentric stabilizer is positioned eccentrically relative to the drill collar creating a lateral deflection in the borehole that may be used for changing the direction of the drilling assembly.
The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.
The drilling assembly 200 connected to the drillstring 110 is terminated by a drill bit 120. During drilling operations, the rotary table 26 imparts rotation to the drill bit 120 by rotating the drillstring 110 and the drilling assembly 200. For its part, the drill bit 120 of the drilling assembly 200 may be a polycrystalline diamond compact (PDC) bit, a rotary drilling bit rotated by a mud motor and shaft, or any other suitable type of drill bit 120.
In addition to the drill bit 120, the drilling assembly 200 can have one or more stabilizer components 220 that are used for both stabilizing the drilling assembly 200 within the borehole 10 during drilling operations and creating a lateral force in the borehole 10 for directing the drilling assembly 200 in a particular direction downhole.
As shown in more detail in
The stabilizer component 220 can have the form of a sleeve or the like disposed on the eccentric section 210 of the drilling assembly 200. The eccentric section 210 is offset from the central rotational axis C of the assembly 200 to that the stabilizer component 220 is eccentrically located on the assembly 200.
The engagement mechanism 230 is operated by the actuator and sensor section 114 to either engage or release the stabilizer component 220. When engaged by the mechanism 230, for example, the stabilizer component 220 rotates with the assembly 200 and the rotation imparted to it. When released by the mechanism 230, however, the stabilizer component 220 can rotate relative to the assembly 200. As discussed below, synchronizing the engagement and release of the eccentric stabilizer component 220 on the drilling assembly 200 during rotation can be used to direct drilling of the borehole 10.
Referring now to
As noted above, the stabilizer component 220 is disposed on the eccentric section 210, which passes through the stabilizer component 220. The eccentric section 210 may be an extension of the drilling assembly 200, having been machined with an inner diameter different than the diameter of the drilling assembly 200, or may be otherwise designed, or even be removably connectable to the drilling assembly 200.
One or more engagement mechanisms 230 may be disposed within the drilling assembly 200. In one embodiment, the engagement mechanism 230 serves to release or lock the stabilizer component 220. The engagement mechanism 230 may either release or lock the stabilizer component 220 at revolution intervals needed to maintain the desired drill path. The control parameters can be modified by communication from the surface and/or autonomously by directives preloaded into the downhole electronics either at the surface using an engagement control communicating with the engagement mechanism 230 downhole, or by programing a controller downhole.
The engagement mechanism 230 preferably takes a minimal amount of effort and uses as minimal electrical energy as possible to engage and re-engage the stabilizer component 220 with the drilling assembly 200. Some mechanisms that may be used include hydraulic systems with pistons and/or valves, a slip clutch mechanism, or any disposable object that can be used to lock the stabilizer component 220 to the drilling assembly 200.
Other mechanisms for locking and releasing the stabilizer component 220 may be used. For example, the engagement mechanism 230 may use a pin and spring mechanism for engaging the stabilizer component 220. The pin of the mechanism 230 can extend and retract relative to the stabilizer component 220 and may engage and disengaged from one or more slots 226, stops, locks or the like on the component 220. In another embodiment, the engagement mechanism 230 may be a multi-plate clutch mechanism, a ball/release mechanism, or any other suitable feature to lock and release the stabilizer component 220 relative to the drilling assembly 200.
When the engagement mechanism 230 is engaged (i.e., the engagement mechanism 230 has been configured to lock the stabilizer component 220 in an engaged state) the stabilizer component 220 will be disposed on the drilling assembly 200 being symmetrically aligned with the center of the drilling assembly 200 (i.e., in a concentric state). In this configuration, the stabilizer component 220 is connected to the drilling assembly 200. When the drilling assembly 200 is rotated as a result of rotating the connected drillstring 110, the stabilizer component 220 will likewise rotate. In this state, the stabilizer component 220 may help stabilize the downhole assembly 200, but will significantly direct drilling.
During drilling, the stabilizer component 220 can engage the borehole (10) using both friction and drag. Friction acting on the stabilizer component 220 in a neutral position concentric on the assembly 110 may assist in persuading the stabilizer component 220 to cam out from the eccentric section 210 once the engagement mechanism 230 has been released.
This camming action may be achieved by physical force (e.g., flow turbulence) upon the stabilizer 220, or by some mechanical, electrical, and/or magnetic inducement (e.g., using motors, or other such devices internal or external) to the drilling assembly 200. Moreover, once the stabilizer component 220 begins camming outward, additional drag may act on the stabilizer component 220 causing the stabilizer component 220 to eventually reach maximum eccentricity. Further, to increase friction and/or aid in creating the drag on the stabilizer component 220, the stabilizer component 220 may contain other friction inducing surfaces or mechanisms to increase the ability of the stabilizer component 220 to engage the borehole (10) once released.
As previously described, the external surface 222 serves to contact the inside of the borehole (10) when the stabilizer component 220 is in the released state. However, although regular re-latching of the stabilizer component 220 will minimize errors with the stabilizer component 220 slipping in the borehole (10), due to conditions in the borehole (10), additional friction generating substances or mechanisms may be used to increase the ability of the stabilizer component 220 to engage the borehole (10) when released.
As described above with reference to
Referring to the positioning of the eccentric section 210 relative to the drilling assembly 200 in
Referring now to
If the stabilizer component 220 is disposed near the drill bit 120 at a close distance D1 as shown, and the engagement mechanism 230 is released as shown, then the friction of the external surface 222 of the stabilizer component 220 against the borehole 10 will begin stalling the stabilizer component 220 relative to the position of the rotating drilling assembly 200. This stalling creates additional friction on the stabilizer component 220 because of the camming effect discussed above.
The stabilizer component 220 will be at maximum friction when it reaches maximum eccentricity (i.e., when the stabilizer component 220 rotates substantially near 180 degrees from its original concentric position). While approaching maximum eccentricity, the stabilizer component 220 is forced in the transverse direction (T) creating an opposite force or deflection in the opposite direction (B). In one embodiment, creating a force in the direction (B) due to the deflection created by the stabilizer component's eccentricity may preferentially direct the drill bit 120 of the drilling assembly 200 to drill on that side of the borehole 10 in that direction.
Further rotation of the drilling assembly 200 brings the stabilizer component 220 back into the concentric position where it may once again be arrested and locked by the engagement mechanism 230, and may continue rotating concentrically with the rest of the drilling assembly 200.
However, by disposing the stabilizer component 220 the distance D2 farther away from the drill bit 120, the lateral deflection created by the eccentricity of the stabilizer component 220 may actually be used to bend the drill collar of the drilling assembly 200. This bend in the drill collar may cause the drill bit 120 to be forced in a similar direction (T′) as the initial force in direction (T) created by the eccentricity of the stabilizer component 220. As a result, depending on the displacement D2 between the stabilizer component 220 and the drill bit 120, the resulting trajectory of the drilling assembly 200 may be different.
Although, as will be appreciated by those in the art, many different control techniques may be used to steer the drilling assembly 200 using the stabilizer component 220 and methods described above, one control technique is discussed below. In this technique, the engagement mechanism 230 may be activated every other rotation of the drilling assembly 200 so that the stabilizer component 220 is recaptured after each rotation to remain concentric. Recapture of the stabilizer component 220 may be necessary because, based on a plethora of mechanical and environmental variables downhole, the stabilizer component 220 may not necessarily remain synchronous with the rotation of the drilling assembly 200.
To obtain desired real-time directional control, the drilling assembly 200 preferably operates the steering remotely from the surface of the earth. Furthermore, the steering can be operated to maintain the desired path and direction while being deployed at possibly a great depth within the borehole and while maintaining practical drilling speeds. Finally, the steering can reliably operate under exceptional heat, pressure, and vibration conditions that can be encountered during the drilling operation.
Another control technique can release the engagement mechanism 230 when the desired “heading” of the drilling assembly 200 is directed to a calculated target. During the drilling operation, for example, control circuitry and sensors may monitor and record the toolface position when the sleeve of the stabilizer component 220 has reached maximum eccentricity. As an example, the sensing can be performed using a Hall Effect sensor or using torsional measurement. Once the stabilizer component 220 is in an eccentric position and the drillstring 110 is within a certain area of desired trajectory, locking the engagement mechanism 230 may be skipped so that the drilling may continue in the direction of the desired trajectory. Skipping activation of the mechanism 230 can be done for one revolution, which in reality may be only a partial revolution due to lag from the first activation. This re-synchronizes the stabilizer component 220 to the drilling assembly 200. This process is then repeated multiple times for a time cycle (e.g., 60 times if drilling at 120 rpm equating to one minute).
During the process, the activation toolface of the mechanism 230 is evaluated relative to the recorded position of the stabilizer component 220 at its peak eccentricity to determine any “slippage correction.” Thus, if the drillstring 110 has slipped off of the desired trajectory, the stabilizer component 220 may be reengaged or locked to adjust the heading while the mechanism 230 is activated to compensate for the measured slippage during the previous time cycle.
The entire process may be repeated many times, or modified to obtain the required trajectory. The stabilizer component 220 may be locked continuously within the borehole 10 if building an angle or changing direction of the drilling assembly 200 is not wanted.
For this embodiment having the eccentric sleeve of the stabilizer component 220 on the corresponding eccentric section 210, the drill bit 120 has an active “cutting” face that remains the same. The cutting face is determined by the random position of the bit 120 when it is put onto the assembly 200 and is the side of the bit 120 positioned opposite where the eccentric sleeve 220 reaches its maximum eccentricity. During operations, the active cutting face will take the brunt of the wear.
Turning now to
As before, this drilling assembly 300 includes a drill body or collar 310 with a drill bit 320 on its distal end. The drill collar 310 is coupled to an actuator assembly 330, which has a linear actuator 332, a torque clutch 334, and position sensors 336. The position sensors 336 in the assembly 330 determine the position of an actuator 350 so it can be coordinated to the toolface of the drilling assembly 300 and the eccentric offset that can be achieved with the stabilizer component 340.
The actuator assembly 330 is coupled to a control assembly 338 that houses control circuitry 339a and sensors 339b, such as near-bit inclination and azimuth sensors. The entire drilling assembly 300 extends from the drillstring 110, which imparts rotation to the assembly 300.
The eccentric stabilizer component 340 includes the actuator 350 disposed on the drill collar 310. As previously noted, the actuator 350 is operatively coupled to the actuator assembly 330, which can move the actuator 350 axially with the linear actuator 332 and can turn or torque the actuator 350 about the axis of the drill collar 310 with the clutch 334.
The stabilizer component 340 includes an inner eccentric sleeve 360 disposed on the drill collar 310, an outer eccentric sleeve 370 disposed on the inner sleeve 360, and a stabilizer body 380 disposed on the outer sleeve 370. As will be described in more detail below, the actuator 350 is engaged with the inner sleeve 360 and is selectively engageable in first and second conditions with the outer sleeve 370.
During one form of operation, for example, the actuator 350 moved to the first condition can selectively engage with the outer sleeve 370 and can orient the combined eccentricity E of the inner and outer sleeves 360, 370 concentrically on the drill collar 310. In this way, the stabilizer component 340 is concentric to the central rotational axis C of the drill collar 310. During another form of operation, however, the actuator 350 moved to the second condition can selectively engage with the outer sleeve 370 and can orient the combined eccentricity E of the inner and outer sleeves 360, 370 eccentrically on the drill collar 310. Controlling these states can achieve directional drilling.
In some situations during operation, the clutch (334) of the assembly 330 allows the actuator 350 to be driven by the rotation of the drill collar 310 with an amount of torque. In other situations during operation, the clutch (334) of the assembly 330 is operated so that there is less torque on the actuator 350. The assembly 330 can therefore use the clutch (334) to selectively control the extent that the actuator 350 is driven by the drill collar 310. The clutch (334) as disclosed herein may use static friction element(s) that will encourage the camming action of the external sleeve 370.
As disclosed herein, the actuator's slide bar 352 is travelling with the eccentric sleeves 360, 370, and the slide bar 352 can be activated in any relationship to the drill collar 310. Once the slide bar 352 is actuated, camming out the outer sleeve 370 can use a stalling force on the inner sleeve 360 relative to the drill collar 310 and can also use a stalling force on the outer sleeve 370 relative to the borehole to cause the sleeves 360, 370 to move differentially to each other. The outer sleeve 370 may have a spring-loaded wear pad to provide additional friction, even in an over-gauged borehole.
The inner sleeve 360 can be magnetically coupled to the drill collar 310 to produce constant drag, while still allowing the two pieces to constantly rotate. For example, the magnetic drag can be produced in the ring portion of the actuator 350, which is coupled with the inner sleeve 360. When the actuator 350 is slid by the linear actuator (332), magnetic elements between the ring of the actuator 350 and the drill collar 310 can overlap and create the desired drag between the actuator 350 (coupled to the inner sleeve 360) and the drill collar 310.
Alternatively, there also may be some other type of clutching mechanism in that same area. Overall, the actuator 350 may only need to be actuated linearly (and possibly use a spring return) for the required clutching to occur. All of the other needed forces can be generated by that one action. As will be appreciated, too much differential loading between the outer sleeve 370 and the inner sleeve 360 can make it more difficult for the actuator 350 to operate.
As best shown in
Depending on the axial and radial position of the slide bar 352 described below, its stops 354, 356 can selectively engage the outer sleeve's stops 374, 376. In general, the stops 374, 376 on the sleeve 370 can include tabs or the like extending from opposite ends of the sleeve 370. The slide bar's stops 354, 356 can be tabs extending upward from the surface of the bar 352. Other features for the stops 354, 356, 374, and 376 can be used.
Finally, as best shown in
It will be appreciated that the views of the stabilizer component 340 do not show many of the components required for the stabilizer component 340 to operated downhole during drilling operations. In other words, protective bodies, seals, bearings, etc. are not depicted for simplicity. With the benefit of the present disclosure, however, one skill in the art will recognize the use and necessity of these and other such features.
The drill collar 310, the inner sleeve 360, the outer sleeve 370, and the stabilizer body 380 can be oriented concentrically and eccentrically depending on operation of the actuator 350 by the actuator assembly 330, as described in more detail below. The concentric arrangement of these components is schematically illustrated in
The inner sleeve 360 can move (rotate) relative to the drill collar 310, and the outer sleeve 370 can move (rotate) relative to the inner sleeve 360. The stabilizer body 380 can be part of or connected to the outer sleeve 370 so that they move together, or the stabilizer body 380 can move (rotate) relative to the outer sleeve 370. Friction and torque may allow the various components to move (rotate) relative to one another, and various features, such as bearings, bushings, etc. found on rotary steerable system can allow for the relative rotation.
Having an understanding of the elements of the stabilizer component 340, its use in directional drilling will now be discussed. Turning to
The actuator 350 is retracted so that its distal stop 356 on the slide bar 352 engages the concentric stop 376 on the outer sleeve 370. Thus, the outer sleeve 370 along with the stabilizer body 380 is coupled for rotation with the actuator 350. Meanwhile, the inner sleeve 360 with the slide bar 352 passing there through is also coupled for rotation with the actuator 350. Because the stabilizer component 340 can move (rotate) relative to the drill collar 310, the component 340 may remain rotationally stationary in the advancing borehole. Alternatively, depending on the torque applied to the actuator 350 by the actuator assembly 330, the component 340 may be allowed to rotate relative to the drill collar 310. In any event, relative movement either positive or stationary for the component 340 is depicted as opposite rotation RB for illustrative purposes. In other words, if the component 340 is to be non-rotating in the borehole during concentric drilling, it remains stationary while the drill collar 310 rotates.
As expected, the concentric drilling arrangement in
When it is desired to use the stabilizer component 340 for directional drilling purposes, the actuator 350 is activated by operation of the actuator assembly 330. As shown in
Eventually, the proximal stop 354 on the actuator 350 rotates around to engage the eccentric stop 374 on the outer sleeve 370.
To directionally drill, the offset direction D can be oriented in the borehole so that the drill bit 320 advances toward a desired trajectory. Using the inclination, azimuth, toolface, and other information, the actuator assembly 330 can be controlled to orient the offset direction D as needed. As shown in
When a straight trajectory is again desired, the operational steps for activating the offset direction D can be reversed. For example,
From this point, the activation and deactivation processes can be repeated as necessary to drill the borehole along a trajectory. Overall, operation of the eccentric stabilizer component 340 of
The disclosed eccentric stabilizer components 200 and 340 can be used with any other directional drilling tool used on the drilling assembly 200 and 300. For example, the components 200 and 340 can be used with each other and/or with a directional drilling tool, such as a mud motor with a bent sub, a rotary steerable system, a point-the-bit system, a push-the-bit system, a targeted bit speed (TBS) tool, etc.
The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.
In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.
This application claims the benefit of U.S. Prov. Appl. 61/943,770, filed 24 Feb. 2014.
Filing Document | Filing Date | Country | Kind |
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PCT/US2015/017048 | 2/23/2015 | WO | 00 |
Number | Date | Country | |
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61943770 | Feb 2014 | US |