CA2822327A1 - Directional drilling - Google Patents
Directional drilling Download PDFInfo
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- CA2822327A1 CA2822327A1 CA2822327A CA2822327A CA2822327A1 CA 2822327 A1 CA2822327 A1 CA 2822327A1 CA 2822327 A CA2822327 A CA 2822327A CA 2822327 A CA2822327 A CA 2822327A CA 2822327 A1 CA2822327 A1 CA 2822327A1
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- Canada
- Prior art keywords
- drill bit
- drilling fluid
- solids
- nozzles
- intermediate space
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- 238000005520 cutting process Methods 0.000 claims abstract description 9
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- 239000010432 diamond Substances 0.000 description 3
- 230000003628 erosive effect Effects 0.000 description 3
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- 238000005299 abrasion Methods 0.000 description 2
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/04—Directional drilling
- E21B7/06—Deflecting the direction of boreholes
- E21B7/065—Deflecting the direction of boreholes using oriented fluid jets
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/18—Drilling by liquid or gas jets, with or without entrained pellets
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
A method of controlling the direction of drilling comprising: providing a drill bit comprising mechanical cutting means forming a bit face and a plurality of nozzles for ejecting drilling fluid arranged at different azimuthal positions with respect to the bit face, and an intermediate space between an inlet port of the drill bit and the plurality of nozzles; rotating the drill bit while passing drilling fluid comprising solids through the intermediate space and the plurality of nozzles, so as to deepen the borehole; and modifying solids concentration of drilling fluid portions flowing through the plurality of nozzles while rotating the drill bit, so that the solids concentration, for the drilling fluid portion flowing through each of the nozzles, is relatively increased when the respective nozzle is in a selected first angular sector of the borehole bottom, as compared to a second angular sector.
Description
DIRECT IONAL DRILLING
The present invention relates to a method of controlling the direction of drilling a borehole in a subsurface formation, and to a system for directional drilling a borehole.
In the course of making a borehole, it is often desirable to control the drilling direction so as to provide a borehole along a predetermined trajectory. A
common technology of directional mechanical drilling uses equipment like bent subs, mud motors and rotating seals, to set only the lower part of the drill string with the drill bit to drill in a particular direction. Mechanical drilling uses drilling bits with mechanical cutters such as roller-cones or polycrystalline diamonds, which produce cuttings by crushing and/or scraping at the borehole bottom and at the sides.
More recently, rotary steerable systems (RSS) have been developed, which can operate with the entire drill string rotating. Known RSS methods point the mechanical drill bit into a desired direction using a complex bending mechanism, or push the drill bit to a particular side using expandable thrust pads. The side-cutting ability of the mechanical drill bits used for directional drilling then allows to deviate the borehole in the desired direction. For example, polycrystalline diamond compact (PDC) bits have cutters not only on the front end but also at the sides.
Some directional drilling systems and methods use drill bits wherein the nozzles are specially adapted so as to obtain a directional drilling effect.
In US 4211292 a roller cone drill bit is disclosed, which has, at a position normally occupied by a conventional wash nozzle, a nozzle extension with a fluid jet emitting nozzle. This extended jet nozzle emits pressurized fluid onto the gage corner of the borehole being drilled. Pressurized fluid is selectively conducted to the jet emitting nozzle during a predetermined partial interval of one drill bit rotation, so as to increase cutting of the gage corner in a certain azimuthal sector of the borehole, thereby deviating the borehole towards that sector.
GB 2 284 837 discloses another roller cone drill bit, in which one of three nozzles was modified to direct the flow into the corner of the workface, so that the flow of drilling fluid is asymmetric relative to the bit. The flow of drilling fluid is pulsed so that the flow is high in a certain azimuthal position and low for the remainder of the rotation, so as to preferentially drill in a selected direction.
US 4637479 discloses another roller cone drill bit, which is modified so that it sealingly co-operates with a fluid-direction means for sequentially discharging fluid streams through nozzles only into a selected sector of the borehole. During rotation of the drill string with drill bit, fluid communication through one or two nozzles outside the selected sector of the borehole is always blocked, and in this way it is achieved that the drill bit is diverted.
US-2006/0266554 discloses a method and system to modulate solids in a particular direction. The system comprises jet means for generating an abrasive jet of a mixture containing a fluid and a quantity of abrasive particles. The erosive power of the abrasive jet can be modulated by modulating the kinetic energy of the abrasive particles. This can be done by modulating the mass flow rate of the abrasive particles, for instance by modulating the quantity of the abrasive particles in the abrasive jet, or by modulating the velocity of the abrasive particles, which can be done for instance by modulating an acceleration pressure drop of the fluid in the jet means, or by a combination thereof.
The known methods require substantial modifications to conventional drill bits, such as nozzle modifications or implementation of rotating seals. Modifications are undesirable, as that reduces the choice of drill bit for the driller and requires use of such drill bit also for straight parts of the well trajectory. Modifying nozzles in conventional drill bits will moreover reduce overall drilling performance, as will the blocking nozzles.
Rotating seals are vulnerable and for that reason not a desired option in downhole equipment.
There is a need for a robust directional drilling method and system.
In accordance with the invention there is provided a method of controlling the direction of drilling a borehole in a subsurface formation, the method comprising - providing a tubular drill string;
- providing a drill bit connected to a lower end of the drill string, the drill bit comprising mechanical cutting means forming a bit face, and comprising a plurality of nozzles for ejecting drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between an inlet port of the drill bit and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space, from which consecutively one of the nozzle inlets extends during rotation of the drill bit;
- rotating the drill bit while passing drilling fluid comprising solids via the drill string through the plurality of nozzles, so as to deepen the borehole, - modifying solids concentration of drilling fluid portions flowing through the plurality of nozzles while rotating the drill bit, so that the solids concentration, for the drilling fluid portion flowing through each of the nozzles, is relatively increased when the respective nozzle is in a selected first angular sector of the borehole bottom, as compared to the solids concentration of the drilling fluid portion flowing through the respective nozzle when said nozzle is in a selected second angular sector of the borehole bottom.
The invention is based on the insight gained by applicant that solids concentration in fluid flow through each nozzle influences drilling performance, and that a distortion of an equal solids distribution of fluid ejected from the plurality of bit nozzles allows to achieve a directional drilling effect. Solids contribute to drilling progression by erosion, so an imbalance will lead to different erosion contributions to drilling progression in different sectors of the borehole bottom.
Merely a relatively small distortion from an equal solids concentration ejected through different nozzles can be sufficient to obtain a directional drilling effect of useful magnitude. Suitably therefore, simultaneous drilling fluid flow through the first and second nozzles is maintained during rotation. In this case, flow through a particular nozzle can be maintained throughout the rotation, and a modification such as a modulation of the flow with the frequency of rotation is sufficient. This eliminates the requirement for rotating seals, selectively blocking fluid flow through nozzles. It also allows the use of conventional drill bits without a modification of the nozzle configuration, i.e. the nozzles can still be optimally, such as symmetrically, arranged, as desired for a particular drill bit configuration.
The purpose of solids modulation in the context of the present invention is to enable higher abrasion and to generate instantaneous orientation dependant rate-of-penetration (ROP) changes and consequently differential hole making.
In one embodiment the drill bit comprises an intermediate space between an inlet port of the drill bit and the plurality of nozzles, each of the first and second nozzles having a nozzle inlet for fluid communication with the intermediate space, and wherein the step of modifying solids concentration comprises directing drilling fluid into a first area of the intermediate space from which consecutively one of the first and second nozzle inlets extends during rotation of the drill bit. This allows to vary or modify the solids concentration by using an inertia effect. In the intermediate space, the drilling fluid is distributed over the various nozzle inlets. Solids in the drilling fluid, having a higher density and therefore higher inertia, have a longer memory of the flow direction at which they were released into the intermediate space, and therefore the concentration in that direction and in the first area is relatively increased during redistribution of drilling fluid, as compared to other areas of the intermediate space.
Thus, at a particular first moment in time, say when the first nozzle has its inlet in the first area of the intermediate space, the directing of fluid towards the first area will cause transfer of drilling fluid with a higher concentration of solids to that nozzle, compared to the second nozzle that has its inlet in another area of the intermediate space. At a second, later moment in time, when the drill bit has rotated, the inlet of the second nozzle will be in the first area towards which fluid is preferentially directed, and now receives a higher solids concentration, both compared to the first nozzle at the second moment in time as well as to the second nozzle at the first moment in time. It shall be clear that the intermediate space is herein regarded as geostationary even though the drill bit rotates.
In one embodiment a flow directing means having an outlet member is provided for directing drilling fluid, and the method further comprises maintaining the outlet member in a geostationary position during at least one rotation of the drill bit. This is a particularly simple means of achieving an increased solids concentration towards consecutive nozzle inlets during rotation.
To maintain a geostationary position, a motor can be provided, controlled to orient the flow directing means as desired. In another embodiment, the flow directing means can be rotatably arranged in the drill string, and shaped so as to rotate in opposite direction with respect to the drill string when passing drilling fluid down the drill string. For example, shaping can include providing vanes, fins or similar. Moreover, in case rotation caused by the drilling fluid in this way is too fast, a brake means for the rotation of the flow directing means can be provided, and maintaining the flow directing means in a geostationary position then comprises operating the break means so as to slow the rotation of the flow directing means to compensate the opposite rotation of the drill string. The flow directing means can further include an electrical generator for converting hydraulic energy of the drilling fluid or rotational energy of the flow directing means into electricity, which can for example power a downhole measurement and/or control unit used for the directional drilling.
In one embodiment a solids concentration means is provided for increasing the concentration of solids in a drilling fluid portion. When at least part of the solids in the drilling fluid is deflectable in a magnetic field, wherein the solids concentration means can be arranged to apply a rotating magnetic field to the drilling fluid.
This can for example be a rotating magnet arrangement, e.g. a permanent magnet or an electromagnet. Such rotating magnet arrangement can for example be combined with a rotating flow diverter, to enhance the solids concentration effect. A rotating magnetic field can also be provided without moving parts, by arranging an electromagnet arrangement in and/or around the flow path of drilling fluid, comprising a plurality of electromagnetic poles in a plane or ring crossing the drilling fluid flow lines, and driving the electromagnetic arrangement such that an effective force is exerted on the particles, the vector characterizing this force rotating as desired.
Alternatively or in addition, the solids concentration means can comprise a curved flow path so as to effectuate a concentration due to centrifugal forces.
In some embodiments the flow directing means, solids concentration means and/or the flow guide (when present or desired) can be shaped so that they can be passed downwardly from surface and/or retrieved to surface in the course of drilling the borehole. This allows selective conducting of directional drilling only when it is desired, without the need to retrieve the drill string to exchange the drill bit or parts of the bottom hole assembly.
In one embodiment a flow guide is provided in the intermediate space, which is rotated together with the drill bit, the flow guide comprising first and second channels each co-operating during time periods of the rotation at an upstream end with the outlet member, depending on the relative rotational position the outlet member and the drill bit, and at a downstream end with the first and second nozzle inlets, respectively. This embodiment allows the outlet member directing the fluid to interface with the upstream end of the flow guide, which can be near the inlet port of the drill bit, which may be more convenient than interfacing directly with an area of nozzle inlets in the intermediate space some distance into the drill bit.
The invention moreover provides a system for directional drilling a borehole, the system comprising:
- a drill string element for passing drilling fluid comprising solids;
- a drill bit connected to the drill string element, the drill bit comprising a bit body, mechanical cutting means forming a bit face, an inlet port for receiving the drilling fluid from the drill string element, a plurality of nozzles for ejecting the drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between the inlet port and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space; and - a diverter for directing at least part of the solids to a first area of the intermediate space, from which first area consecutively one of the nozzle inlets extends during relative rotation of the drill bit with respect to the diverter, as compared with a second area of the intermediate space.
By directing fluid with relatively higher solids concentration towards the first area of the intermediate space, more solids are ejected through the nozzles that are consecutively extending from this area during rotation. This causes a small difference in drilling progression between the side of the first area and the opposite side. Controlling the diverter such that the area in which the solids concentration is relatively increased is kept geostationary, so that the first area of the intermediate space forms an azimuthal sector of the intermediate space, will result in a directional drilling action.
In one embodiment the diverter comprises - a flow directing means at least part of which being provided in the drill string element, the flow directing means comprising an outlet member in rotatable arrangement with respect to the drill bit, the outlet member being arranged to direct drilling fluid into a first area of the intermediate space from which consecutively one of the first and second nozzle inlets extends during a relative rotation of the outlet member with respect to the drill bit;
- a means for controlling relative rotation of the outlet member with respect to the drill bit.
In one embodiment the outlet member can in particular be a flow diverter.
In a particular embodiment the outlet member extends into the intermediate space, such as via the inlet port of the drill bit. That allows a direct interaction with the first area of the intermediate space. Possibly it is advantageous to adapt the outlet member to the geometry of the inlet port and/or intermediate space.
In one embodiment the system comprises a flow guide provided in the intermediate space in a rotatably locked configuration with the drill bit, the flow guide comprising first and second channels each adapted to co-operate, depending on the relative rotational position the outlet member and the drill bit, at an upstream end with the outlet member, and at a downstream end with the first and second nozzle inlets, respectively. In this embodiment the solids diverter can have a standardized interface co-operating with the upstream end of the flow guide, and adaptation to the geometry of the drill bit can be achieved by the flow guide, which can take the form of an adapter or insert.
The present invention relates to a method of controlling the direction of drilling a borehole in a subsurface formation, and to a system for directional drilling a borehole.
In the course of making a borehole, it is often desirable to control the drilling direction so as to provide a borehole along a predetermined trajectory. A
common technology of directional mechanical drilling uses equipment like bent subs, mud motors and rotating seals, to set only the lower part of the drill string with the drill bit to drill in a particular direction. Mechanical drilling uses drilling bits with mechanical cutters such as roller-cones or polycrystalline diamonds, which produce cuttings by crushing and/or scraping at the borehole bottom and at the sides.
More recently, rotary steerable systems (RSS) have been developed, which can operate with the entire drill string rotating. Known RSS methods point the mechanical drill bit into a desired direction using a complex bending mechanism, or push the drill bit to a particular side using expandable thrust pads. The side-cutting ability of the mechanical drill bits used for directional drilling then allows to deviate the borehole in the desired direction. For example, polycrystalline diamond compact (PDC) bits have cutters not only on the front end but also at the sides.
Some directional drilling systems and methods use drill bits wherein the nozzles are specially adapted so as to obtain a directional drilling effect.
In US 4211292 a roller cone drill bit is disclosed, which has, at a position normally occupied by a conventional wash nozzle, a nozzle extension with a fluid jet emitting nozzle. This extended jet nozzle emits pressurized fluid onto the gage corner of the borehole being drilled. Pressurized fluid is selectively conducted to the jet emitting nozzle during a predetermined partial interval of one drill bit rotation, so as to increase cutting of the gage corner in a certain azimuthal sector of the borehole, thereby deviating the borehole towards that sector.
GB 2 284 837 discloses another roller cone drill bit, in which one of three nozzles was modified to direct the flow into the corner of the workface, so that the flow of drilling fluid is asymmetric relative to the bit. The flow of drilling fluid is pulsed so that the flow is high in a certain azimuthal position and low for the remainder of the rotation, so as to preferentially drill in a selected direction.
US 4637479 discloses another roller cone drill bit, which is modified so that it sealingly co-operates with a fluid-direction means for sequentially discharging fluid streams through nozzles only into a selected sector of the borehole. During rotation of the drill string with drill bit, fluid communication through one or two nozzles outside the selected sector of the borehole is always blocked, and in this way it is achieved that the drill bit is diverted.
US-2006/0266554 discloses a method and system to modulate solids in a particular direction. The system comprises jet means for generating an abrasive jet of a mixture containing a fluid and a quantity of abrasive particles. The erosive power of the abrasive jet can be modulated by modulating the kinetic energy of the abrasive particles. This can be done by modulating the mass flow rate of the abrasive particles, for instance by modulating the quantity of the abrasive particles in the abrasive jet, or by modulating the velocity of the abrasive particles, which can be done for instance by modulating an acceleration pressure drop of the fluid in the jet means, or by a combination thereof.
The known methods require substantial modifications to conventional drill bits, such as nozzle modifications or implementation of rotating seals. Modifications are undesirable, as that reduces the choice of drill bit for the driller and requires use of such drill bit also for straight parts of the well trajectory. Modifying nozzles in conventional drill bits will moreover reduce overall drilling performance, as will the blocking nozzles.
Rotating seals are vulnerable and for that reason not a desired option in downhole equipment.
There is a need for a robust directional drilling method and system.
In accordance with the invention there is provided a method of controlling the direction of drilling a borehole in a subsurface formation, the method comprising - providing a tubular drill string;
- providing a drill bit connected to a lower end of the drill string, the drill bit comprising mechanical cutting means forming a bit face, and comprising a plurality of nozzles for ejecting drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between an inlet port of the drill bit and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space, from which consecutively one of the nozzle inlets extends during rotation of the drill bit;
- rotating the drill bit while passing drilling fluid comprising solids via the drill string through the plurality of nozzles, so as to deepen the borehole, - modifying solids concentration of drilling fluid portions flowing through the plurality of nozzles while rotating the drill bit, so that the solids concentration, for the drilling fluid portion flowing through each of the nozzles, is relatively increased when the respective nozzle is in a selected first angular sector of the borehole bottom, as compared to the solids concentration of the drilling fluid portion flowing through the respective nozzle when said nozzle is in a selected second angular sector of the borehole bottom.
The invention is based on the insight gained by applicant that solids concentration in fluid flow through each nozzle influences drilling performance, and that a distortion of an equal solids distribution of fluid ejected from the plurality of bit nozzles allows to achieve a directional drilling effect. Solids contribute to drilling progression by erosion, so an imbalance will lead to different erosion contributions to drilling progression in different sectors of the borehole bottom.
Merely a relatively small distortion from an equal solids concentration ejected through different nozzles can be sufficient to obtain a directional drilling effect of useful magnitude. Suitably therefore, simultaneous drilling fluid flow through the first and second nozzles is maintained during rotation. In this case, flow through a particular nozzle can be maintained throughout the rotation, and a modification such as a modulation of the flow with the frequency of rotation is sufficient. This eliminates the requirement for rotating seals, selectively blocking fluid flow through nozzles. It also allows the use of conventional drill bits without a modification of the nozzle configuration, i.e. the nozzles can still be optimally, such as symmetrically, arranged, as desired for a particular drill bit configuration.
The purpose of solids modulation in the context of the present invention is to enable higher abrasion and to generate instantaneous orientation dependant rate-of-penetration (ROP) changes and consequently differential hole making.
In one embodiment the drill bit comprises an intermediate space between an inlet port of the drill bit and the plurality of nozzles, each of the first and second nozzles having a nozzle inlet for fluid communication with the intermediate space, and wherein the step of modifying solids concentration comprises directing drilling fluid into a first area of the intermediate space from which consecutively one of the first and second nozzle inlets extends during rotation of the drill bit. This allows to vary or modify the solids concentration by using an inertia effect. In the intermediate space, the drilling fluid is distributed over the various nozzle inlets. Solids in the drilling fluid, having a higher density and therefore higher inertia, have a longer memory of the flow direction at which they were released into the intermediate space, and therefore the concentration in that direction and in the first area is relatively increased during redistribution of drilling fluid, as compared to other areas of the intermediate space.
Thus, at a particular first moment in time, say when the first nozzle has its inlet in the first area of the intermediate space, the directing of fluid towards the first area will cause transfer of drilling fluid with a higher concentration of solids to that nozzle, compared to the second nozzle that has its inlet in another area of the intermediate space. At a second, later moment in time, when the drill bit has rotated, the inlet of the second nozzle will be in the first area towards which fluid is preferentially directed, and now receives a higher solids concentration, both compared to the first nozzle at the second moment in time as well as to the second nozzle at the first moment in time. It shall be clear that the intermediate space is herein regarded as geostationary even though the drill bit rotates.
In one embodiment a flow directing means having an outlet member is provided for directing drilling fluid, and the method further comprises maintaining the outlet member in a geostationary position during at least one rotation of the drill bit. This is a particularly simple means of achieving an increased solids concentration towards consecutive nozzle inlets during rotation.
To maintain a geostationary position, a motor can be provided, controlled to orient the flow directing means as desired. In another embodiment, the flow directing means can be rotatably arranged in the drill string, and shaped so as to rotate in opposite direction with respect to the drill string when passing drilling fluid down the drill string. For example, shaping can include providing vanes, fins or similar. Moreover, in case rotation caused by the drilling fluid in this way is too fast, a brake means for the rotation of the flow directing means can be provided, and maintaining the flow directing means in a geostationary position then comprises operating the break means so as to slow the rotation of the flow directing means to compensate the opposite rotation of the drill string. The flow directing means can further include an electrical generator for converting hydraulic energy of the drilling fluid or rotational energy of the flow directing means into electricity, which can for example power a downhole measurement and/or control unit used for the directional drilling.
In one embodiment a solids concentration means is provided for increasing the concentration of solids in a drilling fluid portion. When at least part of the solids in the drilling fluid is deflectable in a magnetic field, wherein the solids concentration means can be arranged to apply a rotating magnetic field to the drilling fluid.
This can for example be a rotating magnet arrangement, e.g. a permanent magnet or an electromagnet. Such rotating magnet arrangement can for example be combined with a rotating flow diverter, to enhance the solids concentration effect. A rotating magnetic field can also be provided without moving parts, by arranging an electromagnet arrangement in and/or around the flow path of drilling fluid, comprising a plurality of electromagnetic poles in a plane or ring crossing the drilling fluid flow lines, and driving the electromagnetic arrangement such that an effective force is exerted on the particles, the vector characterizing this force rotating as desired.
Alternatively or in addition, the solids concentration means can comprise a curved flow path so as to effectuate a concentration due to centrifugal forces.
In some embodiments the flow directing means, solids concentration means and/or the flow guide (when present or desired) can be shaped so that they can be passed downwardly from surface and/or retrieved to surface in the course of drilling the borehole. This allows selective conducting of directional drilling only when it is desired, without the need to retrieve the drill string to exchange the drill bit or parts of the bottom hole assembly.
In one embodiment a flow guide is provided in the intermediate space, which is rotated together with the drill bit, the flow guide comprising first and second channels each co-operating during time periods of the rotation at an upstream end with the outlet member, depending on the relative rotational position the outlet member and the drill bit, and at a downstream end with the first and second nozzle inlets, respectively. This embodiment allows the outlet member directing the fluid to interface with the upstream end of the flow guide, which can be near the inlet port of the drill bit, which may be more convenient than interfacing directly with an area of nozzle inlets in the intermediate space some distance into the drill bit.
The invention moreover provides a system for directional drilling a borehole, the system comprising:
- a drill string element for passing drilling fluid comprising solids;
- a drill bit connected to the drill string element, the drill bit comprising a bit body, mechanical cutting means forming a bit face, an inlet port for receiving the drilling fluid from the drill string element, a plurality of nozzles for ejecting the drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between the inlet port and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space; and - a diverter for directing at least part of the solids to a first area of the intermediate space, from which first area consecutively one of the nozzle inlets extends during relative rotation of the drill bit with respect to the diverter, as compared with a second area of the intermediate space.
By directing fluid with relatively higher solids concentration towards the first area of the intermediate space, more solids are ejected through the nozzles that are consecutively extending from this area during rotation. This causes a small difference in drilling progression between the side of the first area and the opposite side. Controlling the diverter such that the area in which the solids concentration is relatively increased is kept geostationary, so that the first area of the intermediate space forms an azimuthal sector of the intermediate space, will result in a directional drilling action.
In one embodiment the diverter comprises - a flow directing means at least part of which being provided in the drill string element, the flow directing means comprising an outlet member in rotatable arrangement with respect to the drill bit, the outlet member being arranged to direct drilling fluid into a first area of the intermediate space from which consecutively one of the first and second nozzle inlets extends during a relative rotation of the outlet member with respect to the drill bit;
- a means for controlling relative rotation of the outlet member with respect to the drill bit.
In one embodiment the outlet member can in particular be a flow diverter.
In a particular embodiment the outlet member extends into the intermediate space, such as via the inlet port of the drill bit. That allows a direct interaction with the first area of the intermediate space. Possibly it is advantageous to adapt the outlet member to the geometry of the inlet port and/or intermediate space.
In one embodiment the system comprises a flow guide provided in the intermediate space in a rotatably locked configuration with the drill bit, the flow guide comprising first and second channels each adapted to co-operate, depending on the relative rotational position the outlet member and the drill bit, at an upstream end with the outlet member, and at a downstream end with the first and second nozzle inlets, respectively. In this embodiment the solids diverter can have a standardized interface co-operating with the upstream end of the flow guide, and adaptation to the geometry of the drill bit can be achieved by the flow guide, which can take the form of an adapter or insert.
In one embodiment, at least a part of the solids in the drilling fluid is magnetic, and the diverter comprises a magnet for diverting said part of the solids towards the first area of the intermediate space. The magnet can be a rotatable permanent magnet or an electromagnet with a driver unit capable of producing a rotating magnetic field.
In one embodiment the diverter can comprise a curved flow path.
In one embodiment at least part of the diverter and/or flow directing means and/or the flow guide can be retrievable through the drill string element. This makes it possible to conduct directional drilling only during certain periods of a drilling operation. By being retrievable, components are also insertable or re-insertable.
Suitably the system further comprises a controller means for controlling relative rotation of the outlet member with respect to the drill bit. In one embodiment the controller means can comprise a break means for slowing relative rotation of the outlet means with respect to the drill string.
The invention will be described hereinafter in more detail, and by way of example, with reference to the accompanying drawings in which:
Figure 1 schematically shows an embodiment of system for directional drilling a borehole in an earth formation in accordance with the invention;
Figure 2 schematically shows an electromagnetic brake arrangement;
Figure 3a and 3b show schematic views down the borehole as in Figure 1, for two moments in time;
Figure 4 schematically shows another embodiment of a system for directional drilling a borehole in an earth formation in accordance with the invention;
In one embodiment the diverter can comprise a curved flow path.
In one embodiment at least part of the diverter and/or flow directing means and/or the flow guide can be retrievable through the drill string element. This makes it possible to conduct directional drilling only during certain periods of a drilling operation. By being retrievable, components are also insertable or re-insertable.
Suitably the system further comprises a controller means for controlling relative rotation of the outlet member with respect to the drill bit. In one embodiment the controller means can comprise a break means for slowing relative rotation of the outlet means with respect to the drill string.
The invention will be described hereinafter in more detail, and by way of example, with reference to the accompanying drawings in which:
Figure 1 schematically shows an embodiment of system for directional drilling a borehole in an earth formation in accordance with the invention;
Figure 2 schematically shows an electromagnetic brake arrangement;
Figure 3a and 3b show schematic views down the borehole as in Figure 1, for two moments in time;
Figure 4 schematically shows another embodiment of a system for directional drilling a borehole in an earth formation in accordance with the invention;
Figure 5 schematically shows a cross-sectional view of the flow guide in Figure 4;
Figure 6 shows the result of a model calculation of drilling radius in dependence of a differential hole making (DHM) effect;
Figures 7a and 7b schematically show an embodiment of a deflection means alternative to outlet member 45 in Figures 1 and 4, in perspective and top view; and Figures 8a and 8b schematically show alternative methods and means for solids diversion.
In the Figures, like reference numerals relate to the same or similar components or objects.
Referring now to Figure 1 there is shown an embodiment of a method and system 1 for directional drilling a borehole 3 in an earth formation 5 in accordance with the invention. The system 1 comprises a drill bit 10 connected to a sub 14, which is a part of drill string 16 extending to the earth's surface. A drill collar 17 is shown connected to the upper end of sub 14 as a further part of the drill string 16. The longitudinal axis of drill string 16 as well as drill bit 10 is indicated as 18. A length of drill string above the drill bit 10 is referred to as a drill string element, and can be the entire drill string.
The drill bit 10 of shown in this embodiment is a polycrystalline diamond cutter (PDC) bit, but other drill bit types such for example a roller-cone it can also be used. The PDC bit of shown here comprises a bit body 20 provided with mechanical cutting means in the form of PDC
cutters 24. The cutters form a bit face 26, which is during normal operation near the borehole bottom 28. The drill bit 10 further is provided with an inlet port 30 for receiving drilling fluid from the drill string element, in this example from sub 14. The port 30 is the inlet to intermediate space 32, from which a plurality of inlet channels to nozzles for ejecting drilling fluid extend. In this example a first nozzle 35 with first inlet channel 36 and a second nozzle 38 with second inlet channel 39 are provided. The first and second nozzles are arranged at different azimuthal positions with respect to the bit face, in this example 180 degrees apart, as counted with respect to rotation of the drill string 16 along its longitudinal axis.
In the sub 14 a solids diverter is arranged. The solids diverter in this embodiment is a flow directing means 42 comprising an outlet member 45, connected via support member 46 and shaft 48 to a rotation means schematically shown as 50, and controlled by control unit 52 for controlling relative rotation of the outlet member with respect to the drill bit 10. The support member 46 is arranged such that it allows drilling fluid to pass down the interior of the drill string towards the inlet port 30. The outlet member 45 in this embodiment is a flow diverter, shown as a flat plate as seen from the side, but it can also have other shapes such as a curved lip or a channel. The outlet member 45 in this embodiment extends via the inlet port 30 into the intermediate space 32, and this way delivers drilling fluid in a direction towards a first area 55 of the intermediate space 32. As shown in Figure 1, the first inlet channel 36 to first nozzle 35 extends from the first area 55, and the second inlet channel 39 to second nozzle 38 extends from the second area 56 which second area is outside of the area towards which drilling fluid is directed. When the drill string 16 has rotated by 180 degrees, and the outlet member 45 remains geostationary, then the second inlet channel 39 to second nozzle 38 extends from the first area 55. Areas 55 and 56 are regarded as geostationary.
The control unit 52 is 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 is determined, which relative rotation of the outlet member with respect to the drill string is needed.
When the drill string 16 rotates, say right-handed, a left-handed rotation relative to the drill string would be required for the outlet member to remain geostationary. The rotation means 50 can for example be an active drive motor.
Another option is shaping a part of the flow direction means 42, such as the support member 46 or outlet member 45, such that it is driven by the flow of drilling fluid into an opposite rotation relative to the drill string. In the latter case, control over the direction of the flow diverter can be achieved by way of a controlled brake that slows the left hand rotation to such an extent that the right hand rotation of the drill string is compensated and the flow diverter points into a fixed direction relative to earth.
In Figure 2, a schematic electromagnetic brake arrangement for the rotation means is shown, in a view down the borehole 3 as in Figure 1. Within the sub 14 a stator 60 is arranged, which is rotatably locked to the sub 14. The stator can also be integrally formed with the sub. A rotor 64 is rotatably arranged with respect to the stator 60/sub 14. The rotor 64 comprises means , e.g. a vane, fin or rib, exerting a torque when fluid flows along and is deflected, so as to rotate the rotor relative to the stator 60 when drilling fluid flows down the sub 14. One option for such means is schematically indicated by lip 45a that is standing up from outlet member 45. This relative rotation of the rotor 64 is indicated by arrow 66. The rotation of the sub 14 in the borehole 3 during drilling operation, together with stator 60, is indicated by arrow 68. Stator 60 and rotor 64 together form an electromagnetic generator, in particular one of stator and rotor comprising a permanent magnet arrangement and the other comprising an electromagnetic coil arrangement. For example, the stator can comprise the permanent magnet arrangement, and the rotor the electromagnetic coil arrangement interacting with the permanent magnet arrangement during relative rotation so as to create a voltage over electrical poles of the electromagnetic coil arrangement, and thereby electrical energy. This energy can be dissipated in a load. The load can e.g. be a resistor. Instead of dissipating the energy as heat, it can also at least partly be used for powering other electrical equipment, directly or by loading a battery. By changing the load, such as a resistor connected to the electrical poles, the resistance to rotation can be controlled, and thereby the electromagnetic brake can be adjusted such that the rotations 64 and 68 compensate each other, so that the rotor 64 to which the outlet member 45 of the embodiment of Figure 1 is connected, remains geostationary. The outlet member causes a diversion of solids in the direction 70.
The flow directing means 42 in this embodiment can be retrieved to surface upwardly through the interior of the drill string 16. Also, the flow directing means 42 can be introduced through the drill string from surface, for instance to replace the flow directing means after retrieval thereof.
During directional drilling operation of the system 1, drilling fluid comprising solids is pumped down the interior of drill string 16.
The drilling fluid comprising solids suitably comprises at least 0.01 wt% solids, in particular at least 0.05 wt%. Suitably the drilling fluid comprises 10 wt% solids or less, in particular 5 wt% or less, such as 2 wt% or less. A suitable concentration of solids is in the range of from 0.02 wt% to 5 wt%, in particular from 0.05 wt% to 2 wt%.
The solids can be solids known to be used in drilling mud, e.g. barite, hematite and/or corundum.
Alternatively or in addition, solids can comprise solids that can be deflected in a magnetic field, e.g.
ferromagnetic, paramagnetic or dielectric solids. An example is steel.
Solids are preferably present as particles of a particle size that does not block passages or nozzles in the drill string and/or drill bit, but provides sufficient inertia effect. Suitably, at least 90 % of the particles, preferably substantially all particles, more preferably all particles, pass through a 1 mm sieve, in particular a 500 pm sieve, more in particular a 212 pm sieve, even more in particular a 150 pm sieve. Particles included in the drilling fluid for abrasive effect have suitably a minimum particle size. Suitably at least 90 %
of these particles, preferably substantially all of these particles, more preferably all of these particles, do not pass through a 20 pm sieve, in particular a 32 pm sieve, more in particular a 450 pm sieve. A suitable range of particle size is a sieve fraction between 45 and 150 pm sieves, such as a sieve fraction between 75 and 125 pm sieves. Sieves as used herein are specified in ASTM Ell, and a suitable sieving method is described in ASTM B214.
The specific density of the solids is higher than that of the liquid phase of the drilling fluid. Suitably the specific density is 2000 kg/m3 or more, in particular 3000 kg/m3 or more, and is typically less than 20000 kg/m3.
Figure 6 shows the result of a model calculation of drilling radius in dependence of a differential hole making (DHM) effect;
Figures 7a and 7b schematically show an embodiment of a deflection means alternative to outlet member 45 in Figures 1 and 4, in perspective and top view; and Figures 8a and 8b schematically show alternative methods and means for solids diversion.
In the Figures, like reference numerals relate to the same or similar components or objects.
Referring now to Figure 1 there is shown an embodiment of a method and system 1 for directional drilling a borehole 3 in an earth formation 5 in accordance with the invention. The system 1 comprises a drill bit 10 connected to a sub 14, which is a part of drill string 16 extending to the earth's surface. A drill collar 17 is shown connected to the upper end of sub 14 as a further part of the drill string 16. The longitudinal axis of drill string 16 as well as drill bit 10 is indicated as 18. A length of drill string above the drill bit 10 is referred to as a drill string element, and can be the entire drill string.
The drill bit 10 of shown in this embodiment is a polycrystalline diamond cutter (PDC) bit, but other drill bit types such for example a roller-cone it can also be used. The PDC bit of shown here comprises a bit body 20 provided with mechanical cutting means in the form of PDC
cutters 24. The cutters form a bit face 26, which is during normal operation near the borehole bottom 28. The drill bit 10 further is provided with an inlet port 30 for receiving drilling fluid from the drill string element, in this example from sub 14. The port 30 is the inlet to intermediate space 32, from which a plurality of inlet channels to nozzles for ejecting drilling fluid extend. In this example a first nozzle 35 with first inlet channel 36 and a second nozzle 38 with second inlet channel 39 are provided. The first and second nozzles are arranged at different azimuthal positions with respect to the bit face, in this example 180 degrees apart, as counted with respect to rotation of the drill string 16 along its longitudinal axis.
In the sub 14 a solids diverter is arranged. The solids diverter in this embodiment is a flow directing means 42 comprising an outlet member 45, connected via support member 46 and shaft 48 to a rotation means schematically shown as 50, and controlled by control unit 52 for controlling relative rotation of the outlet member with respect to the drill bit 10. The support member 46 is arranged such that it allows drilling fluid to pass down the interior of the drill string towards the inlet port 30. The outlet member 45 in this embodiment is a flow diverter, shown as a flat plate as seen from the side, but it can also have other shapes such as a curved lip or a channel. The outlet member 45 in this embodiment extends via the inlet port 30 into the intermediate space 32, and this way delivers drilling fluid in a direction towards a first area 55 of the intermediate space 32. As shown in Figure 1, the first inlet channel 36 to first nozzle 35 extends from the first area 55, and the second inlet channel 39 to second nozzle 38 extends from the second area 56 which second area is outside of the area towards which drilling fluid is directed. When the drill string 16 has rotated by 180 degrees, and the outlet member 45 remains geostationary, then the second inlet channel 39 to second nozzle 38 extends from the first area 55. Areas 55 and 56 are regarded as geostationary.
The control unit 52 is 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 is determined, which relative rotation of the outlet member with respect to the drill string is needed.
When the drill string 16 rotates, say right-handed, a left-handed rotation relative to the drill string would be required for the outlet member to remain geostationary. The rotation means 50 can for example be an active drive motor.
Another option is shaping a part of the flow direction means 42, such as the support member 46 or outlet member 45, such that it is driven by the flow of drilling fluid into an opposite rotation relative to the drill string. In the latter case, control over the direction of the flow diverter can be achieved by way of a controlled brake that slows the left hand rotation to such an extent that the right hand rotation of the drill string is compensated and the flow diverter points into a fixed direction relative to earth.
In Figure 2, a schematic electromagnetic brake arrangement for the rotation means is shown, in a view down the borehole 3 as in Figure 1. Within the sub 14 a stator 60 is arranged, which is rotatably locked to the sub 14. The stator can also be integrally formed with the sub. A rotor 64 is rotatably arranged with respect to the stator 60/sub 14. The rotor 64 comprises means , e.g. a vane, fin or rib, exerting a torque when fluid flows along and is deflected, so as to rotate the rotor relative to the stator 60 when drilling fluid flows down the sub 14. One option for such means is schematically indicated by lip 45a that is standing up from outlet member 45. This relative rotation of the rotor 64 is indicated by arrow 66. The rotation of the sub 14 in the borehole 3 during drilling operation, together with stator 60, is indicated by arrow 68. Stator 60 and rotor 64 together form an electromagnetic generator, in particular one of stator and rotor comprising a permanent magnet arrangement and the other comprising an electromagnetic coil arrangement. For example, the stator can comprise the permanent magnet arrangement, and the rotor the electromagnetic coil arrangement interacting with the permanent magnet arrangement during relative rotation so as to create a voltage over electrical poles of the electromagnetic coil arrangement, and thereby electrical energy. This energy can be dissipated in a load. The load can e.g. be a resistor. Instead of dissipating the energy as heat, it can also at least partly be used for powering other electrical equipment, directly or by loading a battery. By changing the load, such as a resistor connected to the electrical poles, the resistance to rotation can be controlled, and thereby the electromagnetic brake can be adjusted such that the rotations 64 and 68 compensate each other, so that the rotor 64 to which the outlet member 45 of the embodiment of Figure 1 is connected, remains geostationary. The outlet member causes a diversion of solids in the direction 70.
The flow directing means 42 in this embodiment can be retrieved to surface upwardly through the interior of the drill string 16. Also, the flow directing means 42 can be introduced through the drill string from surface, for instance to replace the flow directing means after retrieval thereof.
During directional drilling operation of the system 1, drilling fluid comprising solids is pumped down the interior of drill string 16.
The drilling fluid comprising solids suitably comprises at least 0.01 wt% solids, in particular at least 0.05 wt%. Suitably the drilling fluid comprises 10 wt% solids or less, in particular 5 wt% or less, such as 2 wt% or less. A suitable concentration of solids is in the range of from 0.02 wt% to 5 wt%, in particular from 0.05 wt% to 2 wt%.
The solids can be solids known to be used in drilling mud, e.g. barite, hematite and/or corundum.
Alternatively or in addition, solids can comprise solids that can be deflected in a magnetic field, e.g.
ferromagnetic, paramagnetic or dielectric solids. An example is steel.
Solids are preferably present as particles of a particle size that does not block passages or nozzles in the drill string and/or drill bit, but provides sufficient inertia effect. Suitably, at least 90 % of the particles, preferably substantially all particles, more preferably all particles, pass through a 1 mm sieve, in particular a 500 pm sieve, more in particular a 212 pm sieve, even more in particular a 150 pm sieve. Particles included in the drilling fluid for abrasive effect have suitably a minimum particle size. Suitably at least 90 %
of these particles, preferably substantially all of these particles, more preferably all of these particles, do not pass through a 20 pm sieve, in particular a 32 pm sieve, more in particular a 450 pm sieve. A suitable range of particle size is a sieve fraction between 45 and 150 pm sieves, such as a sieve fraction between 75 and 125 pm sieves. Sieves as used herein are specified in ASTM Ell, and a suitable sieving method is described in ASTM B214.
The specific density of the solids is higher than that of the liquid phase of the drilling fluid. Suitably the specific density is 2000 kg/m3 or more, in particular 3000 kg/m3 or more, and is typically less than 20000 kg/m3.
The flow diverter, outlet member 45, is kept geostationary by the operation of the control unit 52 and rotation means 50, so that drilling fluid is directed towards the first area 55 of the intermediate space 32.
In the intermediate space, the drilling fluid is distributed over the first and second nozzle inlets.
Solids in the drilling fluid, having a higher density and therefore higher inertia, have a longer memory of the flow direction at which they were released into the intermediate space, and therefore the concentration in fluid ejected through the respective nozzle having its inlet in the first area is relatively increased during redistribution as compared to the respective other nozzle.
In Figures 3a and 3b, schematic views down the borehole 3 as in Figure 1 are shown, for two different moments in time. The Figures show four sectors of the borehole bottom 28, including first sector 81 and second sector 82, separated by third sector 83 and fourth sector 84. At the first moment in time, see Figure 3a, a first nozzle 35 with first inlet channel 36 is located in first angular sector 81 of the borehole bottom near point A in the formation 5. For clarity, the direction of solids diversion 70 is shown instead of the flow diverter 45, or of any other means used for solids diversion. In this embodiment, the solids concentration towards first area 55 is increased by inertia, and from this area the first inlet channel 36 extends at this moment in time. The second nozzle 38 is located in second angular sector 82 opposite sector 81 of the borehole bottom and receives fluid from the second area 56 of the intermediate space, which in the area receiving a relatively lower solids concentration than the first area 55. Figure 3b shows a later moment in time, when the drill bit has turned so that the second nozzle 38 with inlet channel 39 is in the first sector 81 near point A, and receives drilling fluid with higher solids concentration from the area 55 of the intermediate space 32 that is considered to be geostationary. The first nozzle 35 now is in the second sector 82 and receives fluid from the second area 56.
Modulating the solids concentration provided to nozzles such that the solids concentration in the first sector 81 is relatively increased compared to the second sector 82 results in a higher abrasion effect in the first sector compared to the second sector. If other influences can be disregarded, that provides a directional drilling component towards the side of point A.
The angular sectors 81, 82, 83, 84 are shown in the Figure as quadrants of the borehole bottom 28, the first and second sectors forming opposite quadrants. It will be understood that the first and second sectors can be chosen differently; they can for example be opposite half circles, or can be two mutually exclusive sectors of different size (angle), together forming a full circle.
For an intermediate space having circular cross-sections, the first and second areas can be analogously defined with respect to such circular cross-section instead of the borehole bottom.
Referring now to Figure 4 there is showna further embodiment of a method and system 101 for directional drilling a borehole 3 in an earth formation 5 in accordance with the invention. Components that are substantially the same or similar to that of the embodiment of Figure 1 are given the same reference numerals and reference is made to their description hereinabove. By way of difference with Figure 1, the drill bit 110 is a roller-cone drill bit having three roller cones of which only two are shown with reference numerals 111,112. Roller cone 112 and its supporting leg are dashed, to indicate that this cone is behind the paper plane. The third roller cone (not shown) would be generally in front of roller cone 112. With each of the roller cones a nozzle is associated, first nozzle 35 with first roller cone 111, second nozzle 38 with second roller cone 112, and a third nozzle with the third roller cone (not shown). The nozzles communicate via inlet channels with the intermediate space 32 of the bit 110.
As a further difference with the embodiment of Figure 1, in the intermediate space 32 a flow guide 133 is arranged. The flow guide 133 in this embodiment is an insert that is adapted to and can be placed in a conventional roller-cone bit. The flow guide 133 is arranged such that it is rotatably locked to the bit, i.e. it rotates with the drill bit 110. The flow guide 133 comprises a first channel 134 co-operating at a downstream end 135 with the inlet to the first inlet channel 36, and a second channel 137 co-operating at its downstream end 138 with second inlet channel 39. A cross-sectional view of the flow guide 133 is shown in Figure 5, indicating a third channel 141 communicating with the third nozzle.
The flow guide 133 in this embodiment can be retrieved to surface upwardly through the interior of the drill string 16.
The flow directing means 42 of this embodiment comprises an outlet member 145 which, different from the outlet member 45 in Figure 1, does not extend into the intermediate space 32 of drill bit 110. Rather, it is arranged to deliver fluid towards the upstream end, e.g.
142, 143, of one of the flow channels 134,137 or 141 in turn, dependent on the relative rotational position of drill bit 110 and the outlet member 145.
Normal directional drilling operation is essentially as in the embodiment of Figure 1.
In the intermediate space, the drilling fluid is distributed over the first and second nozzle inlets.
Solids in the drilling fluid, having a higher density and therefore higher inertia, have a longer memory of the flow direction at which they were released into the intermediate space, and therefore the concentration in fluid ejected through the respective nozzle having its inlet in the first area is relatively increased during redistribution as compared to the respective other nozzle.
In Figures 3a and 3b, schematic views down the borehole 3 as in Figure 1 are shown, for two different moments in time. The Figures show four sectors of the borehole bottom 28, including first sector 81 and second sector 82, separated by third sector 83 and fourth sector 84. At the first moment in time, see Figure 3a, a first nozzle 35 with first inlet channel 36 is located in first angular sector 81 of the borehole bottom near point A in the formation 5. For clarity, the direction of solids diversion 70 is shown instead of the flow diverter 45, or of any other means used for solids diversion. In this embodiment, the solids concentration towards first area 55 is increased by inertia, and from this area the first inlet channel 36 extends at this moment in time. The second nozzle 38 is located in second angular sector 82 opposite sector 81 of the borehole bottom and receives fluid from the second area 56 of the intermediate space, which in the area receiving a relatively lower solids concentration than the first area 55. Figure 3b shows a later moment in time, when the drill bit has turned so that the second nozzle 38 with inlet channel 39 is in the first sector 81 near point A, and receives drilling fluid with higher solids concentration from the area 55 of the intermediate space 32 that is considered to be geostationary. The first nozzle 35 now is in the second sector 82 and receives fluid from the second area 56.
Modulating the solids concentration provided to nozzles such that the solids concentration in the first sector 81 is relatively increased compared to the second sector 82 results in a higher abrasion effect in the first sector compared to the second sector. If other influences can be disregarded, that provides a directional drilling component towards the side of point A.
The angular sectors 81, 82, 83, 84 are shown in the Figure as quadrants of the borehole bottom 28, the first and second sectors forming opposite quadrants. It will be understood that the first and second sectors can be chosen differently; they can for example be opposite half circles, or can be two mutually exclusive sectors of different size (angle), together forming a full circle.
For an intermediate space having circular cross-sections, the first and second areas can be analogously defined with respect to such circular cross-section instead of the borehole bottom.
Referring now to Figure 4 there is showna further embodiment of a method and system 101 for directional drilling a borehole 3 in an earth formation 5 in accordance with the invention. Components that are substantially the same or similar to that of the embodiment of Figure 1 are given the same reference numerals and reference is made to their description hereinabove. By way of difference with Figure 1, the drill bit 110 is a roller-cone drill bit having three roller cones of which only two are shown with reference numerals 111,112. Roller cone 112 and its supporting leg are dashed, to indicate that this cone is behind the paper plane. The third roller cone (not shown) would be generally in front of roller cone 112. With each of the roller cones a nozzle is associated, first nozzle 35 with first roller cone 111, second nozzle 38 with second roller cone 112, and a third nozzle with the third roller cone (not shown). The nozzles communicate via inlet channels with the intermediate space 32 of the bit 110.
As a further difference with the embodiment of Figure 1, in the intermediate space 32 a flow guide 133 is arranged. The flow guide 133 in this embodiment is an insert that is adapted to and can be placed in a conventional roller-cone bit. The flow guide 133 is arranged such that it is rotatably locked to the bit, i.e. it rotates with the drill bit 110. The flow guide 133 comprises a first channel 134 co-operating at a downstream end 135 with the inlet to the first inlet channel 36, and a second channel 137 co-operating at its downstream end 138 with second inlet channel 39. A cross-sectional view of the flow guide 133 is shown in Figure 5, indicating a third channel 141 communicating with the third nozzle.
The flow guide 133 in this embodiment can be retrieved to surface upwardly through the interior of the drill string 16.
The flow directing means 42 of this embodiment comprises an outlet member 145 which, different from the outlet member 45 in Figure 1, does not extend into the intermediate space 32 of drill bit 110. Rather, it is arranged to deliver fluid towards the upstream end, e.g.
142, 143, of one of the flow channels 134,137 or 141 in turn, dependent on the relative rotational position of drill bit 110 and the outlet member 145.
Normal directional drilling operation is essentially as in the embodiment of Figure 1.
Reference is made to Figures 7a and 7b, schematically showing an alternative flow direction means, in the form of deflection means 101, in perspective view and in top view. The deflection means can be arranged in principle instead of the outlet member 45 with lip 45a in the embodiments discussed hereinabove.
The deflection means acts as a solids diverter, due to the higher inertia of solids with higher density as discussed hereinabove. Deflection means 101 has an upstream end 103 for receiving fluid flowing along the drill string element, a downstream end 105 forming a non-axial outlet 106 for fluid, and a flow path 108 for fluid between the upstream and downstream ends. The direction of fluid flow is indicated by arrow 109. The deflection means is rotatable about the axis of the drill string element in which it is arranged during normal operation, which drill string element is not shown but for example similar to sub 14 discussed above. The axis of the drill string element 18 coincides with the axis 110 of the deflection means 101. The deflection means 101 of this embodiment comprises a deflection member 112 forming an at least partly helical flow channel 113 for fluid, coinciding with the flow 108 path. The flow path is arranged such that fluid flowing from the upstream end to the downstream end exerts a torque about the axis 110.
The torque is indicated by force vector 115 which does not cross the axis 110.
Reference is made to Figures 8a and 8b, showing schematically alternative methods and means for solids diversion, in cross-section through the drill string 3.
These methods can be applied when at least part of the solids can be deflected in magnetic field. Then, a geostationary magnetic field can be used to direct solids towards first area 55. One schematic embodiment for this is shown in Figure 8a, and is based on the electromagnetic brake of Figure 2. However, instead of the flow diverter with outlet member 45, a magnet 72 can be arranged. The operation of the brake is in principle as discussed with reference to Figure 2, but now the magnet diverts solids in the direction 70. The magnet 72 is suitably a permanent magnet so that no power is required.
In Figure 8b a further embodiment of a solids diverter is schematically shown. The solids diverter 80 of this embodiment comprises a plurality of electromagnetic coils 82, which are connected to a power source control unit, which energizes individual coils as a function of time such that an effective magnetic field is obtained that is rotating relatively opposite the rotation 68 of the sub 14, thereby also providing a geostationary solids deflection in the direction 70. An advantage of this embodiment is that it does not include mechanically rotating parts, but it requires an electric power source.
Reference is made to Figure 6, showing the result of a model calculation of drilling radius in dependence of a differential hole making (DHM) effect between two opposite sides at the borehole bottom. DHM can be defined as the difference, expressed in percent, between the rates of penetration at the opposite sides (diametrically opposite points). Calculations were performed for a 15,2 cm (6 inch) drill bit. Figure 6 shows, that a very small differential hole making effect is sufficient to achieve a practically useful directional drilling effect.
E.g. a differential hole making of only 0.1% is sufficient to obtain a radius of only 150 m. This model calculation does not take the stiffness of the bottom part of the drill string/bottom hole assembly (BHA) into account. In the practice of the invention this stiffness can determine the minimum radius that can be drilled; if the drill bit has a tendency for a smaller radius, it can set the drilling system into a mode to drill the minimum radius determined by the BHA.
Examples Experiments were conducted in lab drilling tests. A
15,2 cm drill bit of PDC type was used to drill into a limestone.
Drilling was performed at 60 rotations per minute (RPM), and at a downhole pressure of 10 MPa, with a pressure drop over the bit of 7 MPa and a flow rate of drilling fluid of 700 1/min. As drilling fluid water was used, as well as water to which corundum particles of 100 pm, and a particle density of 4 kg/1, were added in various solids concentrations (in volume% based on total drilling fluid). Concentrations are shown in Table 1.
Weight-on-Bit values (WOB) were also varied.
The ROP was measured with solids present in the drilling fluid (ROP solids). For comparison, ROP was also measured without solids, before and after the measurement with solids, and the average of these measurements is given as "ROP no solids" in Table 1 as well.
Table 1 Exp WOB ROP no solids ROP solids (tons) solids concentration (m/hr) (m/hr) (vol%) 1 2,8 1,60 1,49% 1,73 2 2,8 1,49 2,06% 1,75 3 2,2 0,47 1,07% 0,73 The experiments show that the rate of penetration significantly increases with solids in the drilling fluid. The relative increase of "ROP solids" compared to "ROP no solids" at the same WOB is larger with increasing solids concentration (18% increase in experiment 2 as compared to 8% in experiment 1). At very low WOB, where the normal drilling progression of the drill bit is small, the relative increase is much more pronounced.
Generally, the rate of penetration depends on weight-on-bit applied. This dependency is typically substantially linear for a range of WOB, and with the method of the invention it is preferred to operate in that linear regime.
The experiments demonstrate that providing higher solids concentration to nozzles in a first sector of the borehole bottom, as compared to nozzles in a second sector, provides a differential ROP and leads to a directional drilling effect.
When the solids concentration is increased by means of a flow directing means, for example as discussed with reference to Figures 1 and 4, a parameter of fluid flow through a particular nozzle is normally modulated together with the solids concentration. For example, the flow rate of drilling fluid through the nozzle receiving a higher solids concentration is increased at the same time. It has been found that for a PDC bit the increased flow rate also increases the rate of penetration, therefore the two effects both contribute to a directional drilling effect in the same direction. It was found for a roller-cone bit that the increase of flow rate through a nozzle leads to a decrease in instantaneous ROP (i.e. ROP at a time scale of one rotation or less), so to a directional drilling effect in the opposite direction. When solids are added to the drilling fluid, a certain minimum concentration may be required in case of solids diversion by means of flow diversion, before a directional drilling effect in the same direction as with a PDC bit is obtained. Clearly, these considerations do not apply if the solids concentration is modulated without influencing flow rate.
The deflection means acts as a solids diverter, due to the higher inertia of solids with higher density as discussed hereinabove. Deflection means 101 has an upstream end 103 for receiving fluid flowing along the drill string element, a downstream end 105 forming a non-axial outlet 106 for fluid, and a flow path 108 for fluid between the upstream and downstream ends. The direction of fluid flow is indicated by arrow 109. The deflection means is rotatable about the axis of the drill string element in which it is arranged during normal operation, which drill string element is not shown but for example similar to sub 14 discussed above. The axis of the drill string element 18 coincides with the axis 110 of the deflection means 101. The deflection means 101 of this embodiment comprises a deflection member 112 forming an at least partly helical flow channel 113 for fluid, coinciding with the flow 108 path. The flow path is arranged such that fluid flowing from the upstream end to the downstream end exerts a torque about the axis 110.
The torque is indicated by force vector 115 which does not cross the axis 110.
Reference is made to Figures 8a and 8b, showing schematically alternative methods and means for solids diversion, in cross-section through the drill string 3.
These methods can be applied when at least part of the solids can be deflected in magnetic field. Then, a geostationary magnetic field can be used to direct solids towards first area 55. One schematic embodiment for this is shown in Figure 8a, and is based on the electromagnetic brake of Figure 2. However, instead of the flow diverter with outlet member 45, a magnet 72 can be arranged. The operation of the brake is in principle as discussed with reference to Figure 2, but now the magnet diverts solids in the direction 70. The magnet 72 is suitably a permanent magnet so that no power is required.
In Figure 8b a further embodiment of a solids diverter is schematically shown. The solids diverter 80 of this embodiment comprises a plurality of electromagnetic coils 82, which are connected to a power source control unit, which energizes individual coils as a function of time such that an effective magnetic field is obtained that is rotating relatively opposite the rotation 68 of the sub 14, thereby also providing a geostationary solids deflection in the direction 70. An advantage of this embodiment is that it does not include mechanically rotating parts, but it requires an electric power source.
Reference is made to Figure 6, showing the result of a model calculation of drilling radius in dependence of a differential hole making (DHM) effect between two opposite sides at the borehole bottom. DHM can be defined as the difference, expressed in percent, between the rates of penetration at the opposite sides (diametrically opposite points). Calculations were performed for a 15,2 cm (6 inch) drill bit. Figure 6 shows, that a very small differential hole making effect is sufficient to achieve a practically useful directional drilling effect.
E.g. a differential hole making of only 0.1% is sufficient to obtain a radius of only 150 m. This model calculation does not take the stiffness of the bottom part of the drill string/bottom hole assembly (BHA) into account. In the practice of the invention this stiffness can determine the minimum radius that can be drilled; if the drill bit has a tendency for a smaller radius, it can set the drilling system into a mode to drill the minimum radius determined by the BHA.
Examples Experiments were conducted in lab drilling tests. A
15,2 cm drill bit of PDC type was used to drill into a limestone.
Drilling was performed at 60 rotations per minute (RPM), and at a downhole pressure of 10 MPa, with a pressure drop over the bit of 7 MPa and a flow rate of drilling fluid of 700 1/min. As drilling fluid water was used, as well as water to which corundum particles of 100 pm, and a particle density of 4 kg/1, were added in various solids concentrations (in volume% based on total drilling fluid). Concentrations are shown in Table 1.
Weight-on-Bit values (WOB) were also varied.
The ROP was measured with solids present in the drilling fluid (ROP solids). For comparison, ROP was also measured without solids, before and after the measurement with solids, and the average of these measurements is given as "ROP no solids" in Table 1 as well.
Table 1 Exp WOB ROP no solids ROP solids (tons) solids concentration (m/hr) (m/hr) (vol%) 1 2,8 1,60 1,49% 1,73 2 2,8 1,49 2,06% 1,75 3 2,2 0,47 1,07% 0,73 The experiments show that the rate of penetration significantly increases with solids in the drilling fluid. The relative increase of "ROP solids" compared to "ROP no solids" at the same WOB is larger with increasing solids concentration (18% increase in experiment 2 as compared to 8% in experiment 1). At very low WOB, where the normal drilling progression of the drill bit is small, the relative increase is much more pronounced.
Generally, the rate of penetration depends on weight-on-bit applied. This dependency is typically substantially linear for a range of WOB, and with the method of the invention it is preferred to operate in that linear regime.
The experiments demonstrate that providing higher solids concentration to nozzles in a first sector of the borehole bottom, as compared to nozzles in a second sector, provides a differential ROP and leads to a directional drilling effect.
When the solids concentration is increased by means of a flow directing means, for example as discussed with reference to Figures 1 and 4, a parameter of fluid flow through a particular nozzle is normally modulated together with the solids concentration. For example, the flow rate of drilling fluid through the nozzle receiving a higher solids concentration is increased at the same time. It has been found that for a PDC bit the increased flow rate also increases the rate of penetration, therefore the two effects both contribute to a directional drilling effect in the same direction. It was found for a roller-cone bit that the increase of flow rate through a nozzle leads to a decrease in instantaneous ROP (i.e. ROP at a time scale of one rotation or less), so to a directional drilling effect in the opposite direction. When solids are added to the drilling fluid, a certain minimum concentration may be required in case of solids diversion by means of flow diversion, before a directional drilling effect in the same direction as with a PDC bit is obtained. Clearly, these considerations do not apply if the solids concentration is modulated without influencing flow rate.
If no directional drilling is desired, this can be achieved by taking the solids diverter out of a geostationary position, or out of operation, such that a straight hole is drilled. This is for example the case if a rotating solids diverter such as a rotating flow diverter or a rotating permanent magnet rotates together with the drill bit.
The present invention is not limited to the embodiments thereof described above, wherein various modifications are conceivable within the scope of the appended claims. Features of embodiments may for instance be combined.
The present invention is not limited to the embodiments thereof described above, wherein various modifications are conceivable within the scope of the appended claims. Features of embodiments may for instance be combined.
Claims (15)
1. A method of controlling the direction of drilling a borehole in a subsurface formation, the method comprising - providing a tubular drill string;
- providing a drill bit connected to a lower end of the drill string, the drill bit comprising mechanical cutting means forming a bit face, and comprising a plurality of nozzles for ejecting drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between an inlet port of the drill bit and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space, from which consecutively one of the nozzle inlets extends during rotation of the drill bit;
- rotating the drill bit while passing drilling fluid comprising solids via the drill string through the plurality of nozzles, so as to deepen the borehole; and - modifying solids concentration of drilling fluid portions flowing through the plurality of nozzles while rotating the drill bit, so that the solids concentration, for the drilling fluid portion flowing through each of the nozzles, is relatively increased when the respective nozzle is in a selected first angular sector of the borehole bottom, as compared to the solids concentration of the drilling fluid portion flowing through the respective nozzle when said nozzle is in a selected second angular sector of the borehole bottom.
- providing a drill bit connected to a lower end of the drill string, the drill bit comprising mechanical cutting means forming a bit face, and comprising a plurality of nozzles for ejecting drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between an inlet port of the drill bit and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space, from which consecutively one of the nozzle inlets extends during rotation of the drill bit;
- rotating the drill bit while passing drilling fluid comprising solids via the drill string through the plurality of nozzles, so as to deepen the borehole; and - modifying solids concentration of drilling fluid portions flowing through the plurality of nozzles while rotating the drill bit, so that the solids concentration, for the drilling fluid portion flowing through each of the nozzles, is relatively increased when the respective nozzle is in a selected first angular sector of the borehole bottom, as compared to the solids concentration of the drilling fluid portion flowing through the respective nozzle when said nozzle is in a selected second angular sector of the borehole bottom.
2. The method of claim 1, wherein the step of modifying solids concentration comprises directing the drilling fluid into a first area of the intermediate space to increase the solids concentration by using an inertia effect, whereas in the intermediate space the drilling fluid is distributed over the various nozzle inlets.
3. The method according to claim 1, wherein simultaneous drilling fluid flow through the nozzles is maintained during rotation.
4. The method according to claim 2 or 3, wherein a flow directing means having an outlet member is provided for directing the drilling fluid, and wherein the method further comprises maintaining the outlet member in a geostationary position during at least one rotation of the drill bit.
5. The method according to claim 4, further comprising:
providing a flow guide in the intermediate space, and rotating the flow guide together with the drill bit, the flow guide comprising first and second channels each co-operating during time periods of the rotation at an upstream end with the outlet member, depending on the relative rotational position the outlet member and the drill bit, and at a downstream end with the first and second nozzle inlets, respectively.
providing a flow guide in the intermediate space, and rotating the flow guide together with the drill bit, the flow guide comprising first and second channels each co-operating during time periods of the rotation at an upstream end with the outlet member, depending on the relative rotational position the outlet member and the drill bit, and at a downstream end with the first and second nozzle inlets, respectively.
6. The method according to claim 1, wherein at least a part of the solids in the drilling fluid is magnetic, and wherein the step of modifying solids concentration comprises applying a rotating magnetic field to divert said part of the solids towards the first angular sector.
7. A system for directional drilling a borehole, the system comprising:
- a drill string element for passing drilling fluid comprising solids;
- a drill bit connected to the drill string element, the drill bit comprising a bit body, mechanical cutting means forming a bit face, an inlet port for receiving the drilling fluid from the drill string element, a plurality of nozzles for ejecting the drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between the inlet port and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space; and - a diverter for directing at least part of the solids to a first area of the intermediate space, from which first area consecutively one of the nozzle inlets extends during relative rotation of the drill bit with respect to the diverter, as compared with a second area of the intermediate space.
- a drill string element for passing drilling fluid comprising solids;
- a drill bit connected to the drill string element, the drill bit comprising a bit body, mechanical cutting means forming a bit face, an inlet port for receiving the drilling fluid from the drill string element, a plurality of nozzles for ejecting the drilling fluid, which nozzles are arranged at different azimuthal positions with respect to the bit face, and an intermediate space between the inlet port and the plurality of nozzles, each of the nozzles having a nozzle inlet for fluid communication with the intermediate space; and - a diverter for directing at least part of the solids to a first area of the intermediate space, from which first area consecutively one of the nozzle inlets extends during relative rotation of the drill bit with respect to the diverter, as compared with a second area of the intermediate space.
8. The system of claim 7, wherein the diverter is adapted to modify the solids concentration by directing the drilling fluid into the first area of the intermediate space to increase solids concentration by using an inertia effect, whereas in the intermediate space the drilling fluid is distributed over the various nozzle inlets.
9. The system according to claim 7 or 8, wherein the diverter comprises:
- a flow directing means at least part of which being provided in the drill string element, the flow directing means comprising the outlet member in rotatable arrangement with respect to the drill bit, the outlet member being arranged to direct the drilling fluid into the first area of the intermediate space; and - a means for controlling relative rotation of the outlet member with respect to the drill bit.
- a flow directing means at least part of which being provided in the drill string element, the flow directing means comprising the outlet member in rotatable arrangement with respect to the drill bit, the outlet member being arranged to direct the drilling fluid into the first area of the intermediate space; and - a means for controlling relative rotation of the outlet member with respect to the drill bit.
10. The system according to claim 9, wherein the outlet member extends into the intermediate space.
11. The system according to claim 9, further comprising a flow guide provided in the intermediate space in a rotatably locked configuration with the drill bit, the flow guide comprising first and second channels each adapted to co-operate, depending on the relative rotational position the outlet member and the drill bit, at an upstream end with the outlet member, and at a downstream end with the nozzle inlets, respectively.
12. The system according to claim 7, wherein at least a part of the solids in the drilling fluid is magnetic; and wherein the diverter comprises a magnet for diverting said part of the solids towards the first area of the intermediate space.
13. The system according to claim 12, wherein the magnet is a permanent magnet which is rotatable with respect to the drill bit or an electromagnet with a driver unit capable of producing a rotating magnetic field.
14. The system according to claim 7, wherein the diverter comprises a curved flow path.
15. The system of claim 7, wherein at least part of the diverter is retrievable or replaceable through the drill string element.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| EP10196484.9 | 2010-12-22 | ||
| EP10196484 | 2010-12-22 | ||
| PCT/EP2011/073386 WO2012084934A1 (en) | 2010-12-22 | 2011-12-20 | Directional drilling |
Publications (1)
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|---|---|
| CA2822327A1 true CA2822327A1 (en) | 2012-06-28 |
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| CA2822327A Abandoned CA2822327A1 (en) | 2010-12-22 | 2011-12-20 | Directional drilling |
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| EP (1) | EP2655782A1 (en) |
| CN (1) | CN103328755B (en) |
| AU (1) | AU2011347447B2 (en) |
| CA (1) | CA2822327A1 (en) |
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| CN105164367B (en) * | 2013-04-29 | 2018-12-14 | 国际壳牌研究有限公司 | Method and system for directed drilling |
| US10151150B2 (en) | 2013-04-29 | 2018-12-11 | Shell Oil Company | Insert and method for directional drilling |
| AU2014261524B2 (en) * | 2013-04-29 | 2016-07-21 | Shell Internationale Research Maatschappij B.V. | Method and system for directional drilling |
| US20150047911A1 (en) * | 2013-08-15 | 2015-02-19 | Smith International, Inc. | Using magnetic force/field for drill bits and other cutting tools |
| US9765618B2 (en) | 2015-01-28 | 2017-09-19 | Joy Mm Delaware, Inc. | Cutting bit assembly |
| MY185365A (en) | 2015-05-19 | 2021-05-11 | Halliburton Energy Services Inc | Down-hole communication across a mud motor |
| WO2019002436A1 (en) | 2017-06-30 | 2019-01-03 | Shell Internationale Research Maatschappij B.V. | Rotary steerable drill string |
| CA3080798C (en) * | 2017-10-31 | 2023-07-11 | Otto Torpedo Company | Radial conduit cutting system |
| NL2024001B1 (en) | 2019-10-11 | 2021-06-17 | Stichting Canopus Intellectueel Eigendom | Method and system for directional drilling |
| NL2026757B1 (en) | 2020-10-23 | 2022-06-17 | Stichting Canopus Intellectueel Eigendom | Device and method for concentrating particles within a stream |
| CN113338808A (en) * | 2021-07-13 | 2021-09-03 | 中国石油大学(北京) | Main power rotary cutting wheel drill bit |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US2075064A (en) * | 1936-05-26 | 1937-03-30 | James H Schumacher | Direction control mechanism for well drilling tools |
| US4211292A (en) | 1978-07-27 | 1980-07-08 | Evans Robert F | Borehole angle control by gage corner removal effects |
| US4619335A (en) * | 1984-08-16 | 1986-10-28 | Mccullough Doyle W | Enhanced circulation drill bit |
| US4637479A (en) | 1985-05-31 | 1987-01-20 | Schlumberger Technology Corporation | Methods and apparatus for controlled directional drilling of boreholes |
| GB2190411B (en) * | 1986-05-16 | 1990-02-21 | Shell Int Research | Apparatus for directional drilling. |
| US5314030A (en) * | 1992-08-12 | 1994-05-24 | Massachusetts Institute Of Technology | System for continuously guided drilling |
| GB2284837B (en) | 1993-12-17 | 1997-11-12 | Anadrill Int Sa | Directional drilling method and apparatus |
| AUPO062296A0 (en) * | 1996-06-25 | 1996-07-18 | Gray, Ian | A system for directional control of drilling |
| MY123696A (en) * | 1999-04-28 | 2006-05-31 | Shell Int Research | Abrasive jet drilling assembly |
| EP1997575B1 (en) * | 2001-12-05 | 2011-07-27 | Baker Hughes Incorporated | Consolidated hard material and applications |
| AR045022A1 (en) * | 2003-07-09 | 2005-10-12 | Shell Int Research | SYSTEM AND METHOD FOR PERFORATING AN OBJECT |
| US8795535B2 (en) * | 2009-07-23 | 2014-08-05 | National Oilwell Varco, L.P. | Apparatus and method for drilling fluid density separator utilizing rotating disks |
| BR112012015445A2 (en) * | 2009-12-23 | 2016-03-15 | Shell Int Research | method for punching an object, and, abrasive jet punching set |
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2011
- 2011-12-20 CN CN201180061667.7A patent/CN103328755B/en not_active Expired - Fee Related
- 2011-12-20 EA EA201300732A patent/EA201300732A1/en unknown
- 2011-12-20 EP EP11799098.6A patent/EP2655782A1/en not_active Withdrawn
- 2011-12-20 CA CA2822327A patent/CA2822327A1/en not_active Abandoned
- 2011-12-20 US US13/996,472 patent/US20130292181A1/en not_active Abandoned
- 2011-12-20 AU AU2011347447A patent/AU2011347447B2/en not_active Ceased
- 2011-12-20 WO PCT/EP2011/073386 patent/WO2012084934A1/en active Application Filing
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| EP2655782A1 (en) | 2013-10-30 |
| WO2012084934A1 (en) | 2012-06-28 |
| EA201300732A1 (en) | 2013-11-29 |
| AU2011347447B2 (en) | 2015-07-09 |
| US20130292181A1 (en) | 2013-11-07 |
| CN103328755A (en) | 2013-09-25 |
| AU2011347447A1 (en) | 2013-06-20 |
| CN103328755B (en) | 2015-11-25 |
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