Patent Application
20200131852
In one aspect, the present invention relates to a rotary steerable drill string for directional drilling a borehole in an earth formation.
There is a significant interest in the oil and gas drilling industry in rotary steerable drilling systems that allow for directional drilling. Various systems and concepts have been developed to accomplish directional drilling.
US patent application publication US 2016/0084011 A1 describes systems and methods that accomplish deviated drilling by diverting circulating drilling fluid in a geostationary manner within the drill string, to selectively provide more drilling fluid to drilling fluid nozzles at a selected azimuthal segment around a predetermined geostationary azimuth compared to other drilling fluid nozzles that are not in said selected azimuthal segment. In such systems and methods, a drill string rotates in an azimuthal direction about a drill string longitudinal axis. A drill bit is connected to a lower end of the drill string in a rotation-locked configuration to rotate in unison with the drill string about the drill string longitudinal axis. Drilling fluid is circulated from an upper end of the drill string to the lower end of the drill string via a drilling fluid passage within the drill string, whereby a flow diverter is configured in a lower end of the drill string in the drilling fluid passage, which flow diverter is configured rotatable about the drill string longitudinal axis relative to the drill string. The flow diverter can direct the drilling fluid from the drilling fluid passage into an azimuth segment which is stationary relative to the flow diverter. As a result, the drilling fluid is expelled more through the nozzle(s) that by rotation of the drill string and drill bit move through the azimuth segment than through nozzles that are on an opposing side. This creates an underpressure resulting in a curve in the trajectory of the borehole being drilled. For drilling in a straight direction, the flow diverter can be allowed to rotate relative to the surrounding formation, and thus flush each side of the borehole.
The invention provides rotary steerable drill string, comprising:
a drill string rotatable in an azimuthal direction about a drill string longitudinal axis;
a drill bit connected to a lower end of the drill string in a rotation-locked configuration to rotate in unison with the drill string about the drill string longitudinal axis;
a drilling fluid passage within the drill string, to pass a drilling fluid from an upper end of the drill string to the lower end of the drill string via the drilling fluid passage;
a flow diverter configured in a lower end of the drill string in the drilling fluid passage, which flow diverter is configured rotatable about the drill string longitudinal axis relative to the drill string, to preferentially direct the drilling fluid from the drilling fluid passage into an azimuth segment which is stationary relative to the flow diverter. The drill bit has a base surface facing in a down-facing direction along the longitudinal axis, and a barrel surface circumferencing the longitudinal axis and facing radially outward perpendicular to the longitudinal axis. The drill bit further comprises at least two main blades protruding from the base surface and from the barrel surface, each of the two main blades having a leading face facing the azimuthal rotation direction and a trailing face looking away from the azimuthal rotation direction and an outer blade surface bridging the leading face and the trailing face, and a plurality of fixed cutter elements mounted on at least the leading face of each of the two main blades. Each sector of the bit face defined by and bound between two adjacent main blades is provided with at least one drilling fluid nozzle which co-rotates with the drill bit.
The drill bit may have a fully closed center at the intersection of bit face and the longitudinal axis, wherein the at least two main blades contact each other, whereby the leading face of one of the two main blades converges with the trailing face of another of the at least two main blades and the trailing face of said one of the two main blades converges with the leading face of said other of the at least two main blades.
Alternatively, or in addition thereof, at least one junk slot is provided on the barrel surface to provide a flow channel having an effective aperture for upward flow of drilling fluid that has been expelled from the at least one nozzle, which effective aperture decreases along the upward flow direction of the drilling fluid. Effective aperture means the cross sectional area of the window perpendicular to the flow direction which is available for drilling fluid to flow through. This may be accomplished, for instance, by converging the width of the flow channel and/or by reducing the depth of the flow channel when considered at successive locations along the upward flow direction.
The appended drawing, which is non-limiting, comprises the following figures:
The invention will be further illustrated hereinafter by way of example only, and with reference to the non-limiting drawing. The person skilled in the art will readily understand that, while the invention is illustrated making reference to one or more specific combinations of features and measures, many of those features and measures are functionally independent from other features and measures such that they can be equally or similarly applied independently in other embodiments or combinations.
The presently proposed rotary steerable drill string employs a drill bit selected to positively contribute to underpressure in preselected azimuthal segment of the borehole relative to an opposing azimuthal section. Generally, a high flow velocity of drilling fluid in the selected azimuthal segment relative to in other segments will result in a more pronounced underpressure in the selected azimuthal segment. Drill bit designs which locally enhance the drilling fluid flow velocity are proposed to be employed in the present rotary steerable drill string.
For example, the drill bit may have a fully closed center at the intersection of bit face and the longitudinal axis, wherein the at least two main blades contact each other, whereby the leading face of one of the two main blades converges with the trailing face of another of the at least two main blades and the trailing face of said one of the two main blades converges with the leading face of said other of the at least two main blades. Herewith, cross-over of drilling fluid being expelled from a drilling fluid nozzle in one sector of the bit face defined by and bound between two adjacent main blades to other sectors of the bit face is obstructed, causing a higher flow velocity in the sector.
In another example, which may be implemented independently or in combination with the previous example, the effective aperture for upward flow of drilling fluid that has been expelled from the at least one nozzle in the selected sector decreases along the upward flow direction of the drilling fluid. This causes the flow velocity of the drilling fluid to gradually increase along the upward flow direction of the drilling fluid, in order to preserve the (volumetric) flow rate.
The longitudinal axis of drill string 16 as well as drill bit 10 is indicated by dot-dashed line 18. The drill string 16 is rotatable about a drill string longitudinal axis 18. The direction of this rotation is azimuthal. The drill bit 10 is connected to the drill string 16 in a rotation-locked configuration. It rotates in unison with the drill string 16 about the longitudinal axis 18 at a drill string rotational frequency within the earth formation 5 (taking the earth formation 5 as the frame of reference).
A drilling fluid passage 46 is available within the drill string 16. A drilling fluid may be passed from an upper end of the drill string to the lower end of the drill string 16 via the drilling fluid passage 46. The drilling fluid passage 46 may be defined by a bore within the drill string 16.
The drill bit 10 is a fixed cutter drill bit, which comprises a bit body 20 provided with fixed cutter elements 24. These fixed cutter elements may be polycrystalline diamond compact cutters (PDC). The cutters at the downward-facing base surface of the drill bit form a bit face 26. During operation, said bit face is positioned near the borehole bottom 28 and facing said borehole bottom 28. Typically, the bit face 26 is in close contact with the borehole bottom 28.
A geostationary platform 42 may be arranged in the sub 14. The geostationary platform 42 is indicated very schematically, as the invention described herein is not limited to any specific embodiment of geostationary platform. Reference is made to US patent application publication US 2016/0084011 A1, which describes in detail some examples of such geostationary platforms suitable for use in combination with the present disclosure.
Generally, the geostationary platform 42 is rotatable within the drill string 16 about the longitudinal axis 18 at platform rotational frequency that differs from the drill string rotational frequency. By controlling the platform rotational frequency relative to the drill string rotational frequency, the geostationary platform 42 can rotate at any desired frequency relative to the earth formation 5. The geostationary platform 42 will typically comprise a counter-rotator 50 which rotates in a direction opposite to the drill string 16 rotation. The counter-rotator 50 may be coupled to a co-rotor 52 via a variable torque coupling. By regulating the variable torque, the platform rotational frequency can be controlled to any desired value.
The geostationary platform 42 may further comprise a flow diverter 30 which may be rigidly coupled to the counter-rotator 50 by means of for example an output shaft 48. The flow diverter 30 diverts the flow of drilling fluid to a preselected azimuthal segment within the drill bit 10. The flow diverter 30 typically may comprise an eccentric flow port 32, which can be maintained oriented at a selected azimuth to guide the flow of drilling fluid into the pre-selected azimuthal segment within the drill bit 10. The geostationary platform 42 is arranged in the sub 14 in such a way that drilling fluid can pass down the interior of the drill string 16 towards the flow diverter 30. The principle of the flow diverter 30, and some embodiments of flow diverters, have been described in US patent publication Nos. 2016/0061019, 2016/0076305, and 2016/0084011, to which reference is made herein.
The geostationary platform 42 may further comprise orientation sensors and/or a control unit adapted to obtain orientation data, such as from external, connected or integrated measurement devices, e.g. MWD devices, and/or via communication with an external data source, e.g. at surface. From actual and desired orientation data for the outlet member it may be determined, which relative rotation of the geostationary platform 42 with respect to the drill string 16 is needed.
The drill bit 10 is typically provided with a plurality of inlet channels to nozzles, for guiding drilling fluid from the drilling fluid passage 46 to the nozzles, via which the drilling fluid can be expelled into the borehole 3. In
In the example shown in
It will be appreciated that the manifold block 45 and the associated intermediate drilling fluid conduits 37 can be embodied in the form of an insert which can be slid inside a central bore in the drill bit 10. Alternatively, the manifold block 45 and/or the intermediate drilling fluid conduits 37 could be integral to the drill bit 10 (e.g. drilled bores, or channel structures in a cast bit body 20).
In the specific schematic example shown in
Obviously, if desired three or more nozzles and corresponding manifold channels 47 may be provided at smaller azimuthal intervals (e.g. 120 degrees or 90 degrees). Furthermore, it is conceived that groups of nozzles within an azimuthal segment on the bit face 26 may be connected to a single manifold channel 47 in parallel. In such a case, the bit face 26 could for example comprise two opposing groups of two or more nozzles, or three groups of two or more nozzles.
The system as described in reference to
The local, and potentially geostationary, area of underpressure causes a deviating force exercised by the drill bit to the earth formation. A benefit is that the force is generated locally at the drill bit surface and the side-ways (transversely) directed force does not have to be imposed to the drill bit from some location on the bottom hole assembly located uphole relative to the drill bit.
It has now been found that the local underpressure can be enhanced and/or tailored to needs by an appropriate drill bit design. In the drill bit 10 as shown in
The example drill bit 11 has bit body comprising a base surface 60 facing in a down-facing direction along the longitudinal axis 18. In a borehole, the bottom of the borehole is considered “down” and the surface end of the borehole is considered “up”, regardless of the actual trajectory of the borehole. The base surface 60 generally extends transverse to the longitudinal axis 18. The bit body further comprises a barrel surface 62, which circumferences the longitudinal axis 18. The barrel surface 62 generally faces radially outward perpendicular to the longitudinal axis 18 (the barrel surface 62 could for example be a cylindrical surface section). Usually, there may be a smooth transition zone 65 connecting the base surface 60 with the barrel surface 62 where the base surface 60 transitions into the barrel surface 62.
The drill bit 11 further comprises at least two main blades (71,72) protruding from the base surface 60 and from the barrel surface 62. These main blades may be oriented with a spacing of 180 degrees when there are exclusively two main blades. In the example shown in
The main blades 71,72,73 . . . divide the base surface 60, the barrel surface 62 and the transition zone 65 into sectors. In each sector at least drilling fluid nozzle 88 is provided in the base surface 60. These drilling fluid nozzles co-rotate with the drill bit, similar to first and second nozzles discussed in
The main blades 71,72,73 contact each other in the center on the longitudinal axis 18. This means that the leading face 81 of one of the main blades (e.g. the second main blade 72) converges with the trailing face 82 of another of the main blades (e.g. of the first main blade 71). Also, the trailing face 82 of said one of the main blades (e.g. the second main blade 72) converges with the leading face of another of the main blades. This can be the first main blade 71, in case there are two main blades, but it could also be a third main blade 73 in case there are more than two main blades. Converging in this context means that a continuous path can be envisaged that directly goes from the leading face of one of the main blades to the trailing face of an adjacent main blade without traversing the base surface or some other surface. Similarly, the outer blade surfaces 83 of all of the main blades converge at the center of the drill bit face, so that another continuous path can be envisaged that directly goes from the outer blade surface of one of the main blades to any other outer blade surface of any other main blade without traversing the base surface or some other surface of the drill bit 11.
As a result, the drill bit 11 has a fully closed center at the intersection of bit face and the longitudinal axis 18 so that cross flow of drilling fluid that has been expelled from one drilling fluid nozzle 88 in one of the sectors to another sector is hampered. Consequently, the drilling fluid that has been expelled from one drilling fluid nozzle can hardly redistribute itself over the other sectors and instead is forced to flow upward through the same sector as that it was expelled in, at a higher velocity than what would have been the case if the drilling fluid could distribute itself over the other sectors as well. The higher velocity will enhance the local underpressure in this sector.
The drill bit 11 may further comprises at least one auxiliary blade 90 arranged within each sector. The auxiliary blades 90 protrude at least from the barrel surface 62, and (similar to the main blades) each auxiliary blade has an auxiliary leading face 91 facing the azimuthal rotation direction 19; an auxiliary trailing face 92 looking away from the azimuthal rotation direction 19; and an auxiliary outer blade surface 93 bridging the auxiliary leading face 91 and the auxiliary trailing face 92. Preferably, fixed auxiliary cutting elements 34 are mounted at least on the auxiliary leading face 91 on each auxiliary blade 90. Similar to the cutting elements 24 on the main blades, these may be PDC cutters.
An auxiliary blade 90 distinguishes itself from a main blade in that a drilling fluid gap 89 is provided between the auxiliary blade 90 and the center. As a result, there can be fluid communication between the drilling fluid nozzle 88 and a first junk slot 95 defined between the trailing face 82 of one of the two main blades (e.g. the first main blade 71) and the auxiliary leading face 91, as well as fluid communication between the drilling fluid nozzle 88 and a second junk slot 96 defined between the auxiliary trailing face 92 and the leading face 81 of the neighboring main blades that defines the sector in which the auxiliary blade is located (e.g. the second main blade 72). The auxiliary main blade 90 thus further narrows the space available for the upward flow of the drilling fluid in the sector thereby further driving up the flow velocity.
Junk slots, such as first and second junk slots 95,96, are generally provided on the barrel surface 62 to provide a flow channel having an effective aperture for upward flow of drilling fluid that has been expelled from the drilling fluid nozzle 88. The underpressure can be further enhanced if the effective aperture decreases along the upward flow direction 33 of the drilling fluid, forcing the drilling fluid velocity to increase in order to pass the expelled volumetric rate. The junk slot may be shaped to converge, as opposed to conventional bit designs where the junk slot diverges. Additionally, or instead thereof, the depth of the junk slot may be reduced to contribute to maintaining the velocity and under pressure profile.
This can be achieved for instance by employing a slightly (frustro) conical barrel surface which is outwardly tapered (i.e. the outer diameter of the barrel surface increases along an upward direction), or, stated more generally, by a decreasing radial distance Δr between a selected outer blade surface 83 and/or auxiliary outer blade surface 93 on one hand and said barrel surface 62 on the other hand when comparing said radial distance in successive locations in the upward flow direction 33 of the drilling fluid.
Alternatively, or in addition thereto, the circumferential distance Δlt between the leading face 81 and the trailing face 82 of a selected main blade (e.g. 71) across the outer blade surface 83 may be diverging along the upward flow direction of the drilling fluid in the junk slots. In addition thereto, or instead thereof, the circumferential distance between the leading face 91 and the trailing face 92 of a selected auxiliary blade 90 across the auxiliary outer blade surface 93 may be diverging along the upward flow direction. Either way, it can be achieved that junk slots formed on the barrel surface 62 between two successively adjacent main and/or auxiliary blades converges in an upward flow direction of the drilling fluid.
In any of these examples, the shape of the junk slot is designed such that the flow velocity of drilling fluid through the junk slot remains high and sustained over a distance. Keeping the velocity high, and consequently the pressure low, may provide larger steering forces as the desired pressure acts over a larger area.
The junk slot profile may be optimized to maximize both the under pressure and exposed area. Computational fluid dynamics models have been made of the closed center of the drill bit, which clearly confirm the resulting effect of isolating the underpressure to the flow area within a single sector of the drill bit. When the drill bit engages into the formation, the closed area at the center of the drill bit effectively contains the underpressure at the point of flow. The models also shows the underpressure is reducing as the flow slows down in the transition zone between the base surface and the barrel surface.
A further benefit that can be drawn from the present disclosure, is that it offers a degree of control over how the deviating force that is exercised by the drill bit on the earth formation is directed from the drill bit to the earth formation. This can be achieved by tailoring the underpressure profile along the drill bit using the drilling fluid flow influencing methodologies described above. For example, if the underpressure profile shows the region of highest underpressure is underneath the bit face, then the deviating force is expected to be directed at an angle of generally less than 45°, or possibly even less than 30°, from the forward drilling direction along the longitudinal axis through the drill bit. However, if the region of highest underpressure is brought up more towards or onto the barrel surface, then the angle of the direction of the deviating force relative to the forward drilling direction will increase accordingly, and could even exceed 30° or preferably exceed 45°. Thus, the drill bit design can be tailored to a desired target build rate.
The computational fluid dynamics model used for the drill bit of
The person skilled in the art will understand that the teachings described in the present paper can be applied to advantageously modify any of the embodiments described in US patent publication Nos. 2016/0061019, 2016/0076305, and 2016/0084011; all of which are incorporated herein by reference.
The person skilled in the art will understand that the present invention can be carried out in many various ways without departing from the scope of the appended claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 17179027.2 | Jun 2017 | EP | regional |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/EP2018/067356 | 6/28/2018 | WO | 00 |
