MXPA06008372A - Downhole drilling of a lateral hole - Google Patents

Abstract

A system for drilling a lateral hole departing from a main well. The system comprises a motor assembly (415) including a motor (412) to generate a rotating torque, an axial thruster (411) to generate an axial force, a blocking system (410) to fix the motor and the axial thruster downhole. The motor assembly further includes a drive shaft (414) to transmit the rotating torque. The system further comprises a first and second connector (402, 404) for transmitting the rotating torque and the axial force from the motor assembly to a drill string assembly. The first connector is connectable to the drill string assembly so as to transmit the axial force only to the drill pipe (401), and to transmit the rotating torque to a further drive (405) shaft positioned within the drill pipe. The second connector (402) is connectable to the drill stringassembly so as to transmit both the axial force and the rotating torque to the drill pipe (401).

Description

DRILLING THE BACKGROUND OF THE INVENTION BACKGROUND OF THE INVENTION Field of the Invention The invention relates generally to the drilling of a side hole of a main well.

Background of the Technique The lateral hole drilling has become a new method of drilling to build a well. With the lateral hole drilling allows access to an additional area of an underground reservoir, for example a hydrocarbon deposit, or an aquifer layer. The lateral hole drilling method is proven to be useful in the case of high hydrocarbon viscosity, low permeability reservoir, very stratified deposit, etc. The lateral hole drilling method also allows a deposit to be reached when the drilling grooves are limited, such as with a maritime platform. A drilling rig is usually used to drill the side hole of a main well diversion. A torque of rotation torque is generated on the surface and transmitted to a drill string at the bottom of the well. The torque of rotation can also be generated at the bottom of the hole by a hydraulic converter while a pump is used on the surface. An axial force that is applied in a hole in one end of the drill string can be generated by the weight of the drill string along a vertical or diagonal portion of the main well. A coiled tubing can also be used to drill the side hole. An injection head pushes a coiled tubing in the main well. Several tools, typically an auger collar, an orienting tool, a steerable motor and an auger, can be located at one end of the coiled tubing. A torque of rotation torque and an axial force are applied in the bit. The torque of rotation is generated by a steerable hydraulic motor converter while a pump is used on the surface. The axial force can be generated by the weight of the tools, or even the coiled tubing. The axial force can also be generated on the surface by the injection head. Several recent systems for drilling small side holes generate the torque of rotation at the bottom of the bore with an electric motor. In most cases, the lateral hole is drilled in two stages. During a first stage, a curved hole with a short radius is drilled using a first drilling system. When a desired direction is reached, the first drilling system is removed from the side hole and a second drilling system perforates the side hole substantially following the determined direction. The first drilling system can be a steerable motor that bends to allow drilling following a curve.

Airship Engine FIGURE. 1 illustrates a schematic part of a steerable engine according to the prior art. The steerable engine 101 comprises a piercing tube 105, a transmission shaft 103 to which an auger 107 is connected. The piercing tube 105 is bent to allow a curved pit to be drilled. During drilling, the steerable motor 101 is forced against a lower wall of the perforated hole: a direction radius of the curved hole is determined by the relative positions of the three contact points 102. In the case of a soft reservoir, it may happen that the steerable motor 101 drills a bore having a relatively long section. A resulting curved pit can therefore have an effective radius that is greater than the direction radius. In order to be able to control the effective radius, the contact points 102 can be provided in places corresponding to a relatively small steering radius. Steerable motor 101 can be employed with an angled mode or a straight mode.

In angled mode, a hydraulic converter 104, for example, a progressive cavity motor, located in the steerable motor, rotates the transmission shaft 103 using the circulation of a drilling fluid (not shown). The auger 107 is therefore rotated. The piercing tube 105 remains in an equal azimuthal position and transmits an axial force. The lower part of the transmission shaft 103 is supported by bearings 106 for transmitting axial force from the drill tube 105 to the bit 107. As a result, the resulting curved hole is bent with an effective radius greater than or equal to the direction radius. If the effective radius is less than a desired radius, the steerable motor 101 can be used in a straight mode, ie, the piercing tube 105 itself is rotated. The flexion angle does not point in a preferred direction and a large hole having a substantially straight direction is pierced. When combined with the angled mode, the straight mode allows to control the effective radius of the curved hole.

Control of a drilling direction During a drilling, an assembly located at the bottom of the drilling, such as the steerable engine, may comprise stabilizers. The stabilizers allow to place the drill pipe in the hole. The outriggers also allow drilling in an upward direction, or in a downward direction. FIGURE 2 illustrates a stabilizer of the prior art. The stabilizer 202 comprises vanes surrounding a drilling string 201 and is placed on an internal wall 204 of a perforated hole. Therefore, the stabilizer 202 maintains a center of the drilling string 201 substantially in a center of a section of the drilled hole. The weight of the drill string can cause a deformation of the drill string. The drilling string 201 thus allows drilling following a direction that is determined by the relative longitudinal positions of the stabilizers and by the weight of the drilling string 201. FIGURE 3A illustrates a straight configuration of an assembly located at the bottom of the bore to drill a side hole according to the prior art. An auger 303 is located at one end of a drilling string 301 of an assembly located at the bottom of the bore. Three stabilizers (302a, 302b, 302c) surround drill string 301 at different locations. The stabilizers (302a, 302b, 302c) maintain a center of the auger 303 at a center of a section of a hole 304 drilled to ensure a relatively straight bore. FIGURE 3B illustrates a dropping configuration of an assembly located at the bottom of the bore to drill a side hole according to the prior art. A first stabilizer 302a and a second stabilizer 302b surround a drilling string 301. When the first stabilizer 302a and the second stabilizer 302b are located at a relatively high distance from an auger 303 at one end of the drill string 301, the drill string 301 flexes under its own weight, thereby causing the auger 303 drill a hole 304 following a downward direction. FIGURE 3C illustrates an integrated configuration of an assembly located at the bottom of the bore to drill a side hole according to the prior art. A first stabilizer 302a and a second stabilizer 302c surround a drilling string 301. The first stabilizer 302a and the second stabilizer 302c are located at a relatively long distance from one another, and the second stabilizer 302c is relatively close to a bit 303 at one end of the drill string 301. The weight of a portion of the drill string 301 between the stabilizers (302a, 302c) causes the drill string 301 to flex elastically down between the stabilizers (302a, 302c). The auger 303 is therefore pushed up and drilled in an upward direction. When a change of direction is required, the drill string needs to be removed from the well to move the stabilizers. In order to avoid removing the drill string, a stabilizer of variable diameter can be established. The diameter of the variable diameter stabilizer can be changed from one position to the other. The change of position involves a mechanical system: only a simple different diameter of the variable diameter stabilizer can be established in an assembly located at the bottom of the borehole. The change of position can be ordered from the surface. A stabilizer adjustment of variable diameter is typically controlled by mechanical and flow events, for example, an application of an axial force, a removal of a torque from rotation, an application of a flow of a flow, a pressure drop due to the application of the flow, etc. A chronological order of the mechanical and flow events allows to establish a suitable stabilizer position. For example, the mechanical system typically comprises a key that can slide within an internal groove along a periphery of the assembly located at the bottom of the bore. The key can slide between an ascending position and a descending position depending on the chronological order of the mechanical and flow events. When the key is in the up position, a transmission system allows a variable diameter stabilizer blade to retract. When the key is in the down position, the drive system pushes the paddle against a wall of the drilled hole. The transmission system can be a tree connected indirectly to the pallet, or an inner pipe that is conical in shape. Therefore it is possible to decide from the surface if the perforation is carried out in a straight direction or in another direction. The other direction may be an upward direction, or a downward direction, depending on a relative longitudinal position of the variable diameter stabilizer. An assembly located at the bottom of the bore with a variable diameter stabilizer may comprise three outriggers as shown in FIGURE 3A, where one of the three stabilizers is the variable diameter stabilizer. The variable diameter stabilizer may be the nearest bit stabilizer. In this case, a retraction of the diameter of the variable diameter stabilizer provides a configuration that is similar to that shown in FIGURE 3B. Therefore, it is possible to drill in a straight direction or in a downward direction, depending on a diameter of the variable diameter stabilizer. Similarly, the diameter stabilizer can be located between the other stabilizers. In this case, a retraction of the diameter of the variable diameter stabilizer provides a configuration that is similar to that shown in FIGURE 3C. Therefore, it is possible to drill in a straight direction or in an upward direction, depending on a diameter of the variable diameter stabilizer.

Monitoring the drilling direction Controlling a drilling direction of a lateral hole also requires monitoring an auger drilling direction. Such monitoring is usually done by providing a Measurement While Drilling (MWD) tool in an assembly located at the bottom of the hole. The MWD tool may comprise an accelerometer system and a magnetometer system. The accelerometer system comprises at least one accelerometer. The accelerometer allows a measurement of a tilt of a drill pipe against the gravity vector of the Earth. The magnetometer system comprises at least one magnetometer that allows a measurement of an azimuth of the drill pipe against the magnetic field of the Earth. The accelerometer system can comprise three accelerometers that allow three different inclinations to be measured against the gravity vector of the Earth, to provide a three-dimensional measurement of a position of the drill pipe. The magnetometer system can comprise three magnetometers that measure three different azimuths against the Earth's magnetic field. The MWD tool can also comprise three accelerometers and three magnetometers. The MWD tool typically communicates with the surface using acoustic telemetry. The MWD tool is typically located at a relatively high distance from the bit, for example 25 meters. As a consequence of this distance, the MWD provides measurements that have a relatively low accuracy, since a curvature of the side hole under the MWD is not known.

Very short radius drilling In a case of a very short radius drilling, it is possible to use a motor that is locked inside a main well and a flexible shaft that can transmit a torque of rotation and an axial force to a bit. The flexible shaft bends substantially perpendicularly in an elbow between the main well and a perforated side hole. A guide system is provided inside the main well to allow the transmission of the torque of rotation and the axial force to the elbow.

The guide system can be lubricated to reduce the contact tensions between the flexible shaft and the diverting wedge. The guidance system is typically a deviating wedge. International application W099 / 29997 describes a system in which bushings are used within an elbow to cause a flexible shaft to flex and rotate while allowing rotation and axial movement therethrough.

Flow management and cuttings Hole drilling creates cuttings that need to be processed. For example, this can for example be done as described in the following. A pump on the surface injects a drilling fluid, for example, a drilling mud, through a hollow drilling tool. The drilling fluid reaches an auger of the drilling tool and is evacuated through an annular zone between the drilling tool and the drilled hole. The drilling fluid is viscous enough to carry the cuttings that are created in the auger to the surface. A vibrating shale sieve located on the surface allows to separate the cuttings from the drilling fluid.

SUMMARY OF THE INVENTION In a first aspect, the invention provides a system for drilling a lateral hole of diversion of a main well. The system comprises a motor assembly that includes a motor for generating a torque of rotation, an axial drive for generating an axial force, a locking system for fixing the motor and the axial drive at the bottom of the bore. The motor assembly further comprises a drive shaft for transmitting the torque of rotation. The system further comprises a connector for transmitting the torque of rotation and axial force from the motor assembly to a drill string assembly. The drill string assembly comprises a drill pipe and an auger. The connector provides a fluid communication channel between the motor assembly and the interior of the drill pipe. The connector is one of a first connector or a second connector. The first connector can be connected to the drill string assembly to transmit the axial force only to the drill pipe, and to transmit the torque of rotation to an additional transmission shaft placed inside the drill pipe. The second connector can be connected to the drill string assembly to transmit the axial force and the torque of rotation to the drill pipe.

In a first preferred embodiment, the engine is located inside the main well. In a second preferred embodiment, the system further comprises the drill string assembly. The drill string assembly is connected to the connector. The drill string assembly comprises the drill pipe to transmit the axial force and the additional drive shaft to transmit the torque of rotation. The additional drive shaft is placed inside the drill pipe. The system also includes the auger. In a third preferred embodiment, a portion of the side hole comprises a curved hole having a determined radius of curvature. The drill string assembly comprises three contact points to be in contact with a perforated side hole wall. The three points of contact define an angle of the drill pipe to allow the hole to be bent. In a fourth preferred embodiment, the system further comprises a thrust bearing for transmitting axial force from the drill pipe to the auger. The bit is located at one end of the additional drive shaft. The system further comprises a system of plain bearings to support a flexure of the additional drive shaft within the drill pipe.

In a fifth preferred embodiment, the motor is electric. In a sixth preferred embodiment, the system further comprises the drill string assembly. The drill string assembly is connected to the connector. The drill string assembly comprises the drill pipe to transmit the axial force and the torque of rotation. The system also includes the auger. In a seventh preferred embodiment, the system further comprises at least one variable diameter stabilizer for positioning the bit within a section of the side hole. The system further comprises control means for mechanically controlling from a remote location at least one parameter of the stabilizer between a set of parameters of the stabilizer. The set of parameters of the stabilizer comprises a diameter size of a stabilizer of a certain variable diameter, a distance between a first stabilizer and a marking device within the lateral hole, the marking device is either a different stabilizer or an auger, a coordinated retraction of at least two stabilizers of variable diameter, and an azimuthal radius of the stabilizer of a certain variable diameter. In an eighth preferred embodiment, the system further comprises an individual control unit for controlling at least one parameter of the stabilizer among the set of parameters of the stabilizer. In a ninth preferred embodiment, the system comprises a configuration slot and a configuration scheme that can be moved by the control means.

The configuration scheme makes it possible to select a desired adjustment position from a set of adjustment positions. The set of adjustment positions comprises at least three adjustment positions. Each adjustment position corresponds to a determined value of at least one parameter of the stabilizer. In a tenth preferred embodiment, the system further comprises two stabilizers of varying diameter that can be established in a coordinated manner. In a eleventh preferred embodiment, the system further comprises a Hall Effect sensor for measuring a diameter of one of the two variable diameter stabilizers. In a twelfth preferred embodiment, the system further comprises at least one micro-sensor in a vicinity of the bit. At least one micro-sensor allows a measurement of an orientation of the bit relative to a reference direction. In a thirteenth preferred embodiment, the drill pipe is flexible, to allow bending while transmitting the torque of rotation and the axial force. The system also comprises a bending guide with rotation supports to support the drill pipe in bending. In a fourteenth preferred modality, the rotation supports are bands that are supported by a pulley. In a fifteenth preferred embodiment, the system further comprises a pump located at the bottom of the borehole for pumping a drilling fluid. In a sixteenth preferred embodiment, the drilling fluid can flow from the main well to the auger through an annular zone between the perforated side hole and the drill string assembly. The drilling fluid can flow from the auger to the main well through the fluid communication channel. In a seventeenth preferred embodiment, the auger comprises an auger orifice that allows the cuttings generated in the auger to be evacuated through the auger. The auger comprises a main blade to ensure a cutting action. In a eighteenth preferred embodiment, the system further comprises a passage located at an exit from the side hole. The passage allows to guide a flow of drilling fluid from the side hole to the main well.

In a nineteenth preferred embodiment, the system further comprises a sealing device for forcing the drilling fluid to circulate through the passage. In a twentieth preferred embodiment, the passage is oriented downwards. In a twenty-first preferred embodiment, the system further comprises a filter device for separating the cutouts from the drilling fluid. The filter device is located at the bottom of the borehole. In a twenty-second preferred embodiment, the system further comprises a compactor within the filter device to regularly provide a compaction of the filtered cuttings. In a twenty-third preferred embodiment, the system further comprises an adaptive system within the filter device for sorting the filtered sediment depending on its size to prevent the filtered cuttings from clogging the filter device. In a twenty-fourth preferred embodiment, the system further comprises a container within the main well to collect the cuttings under the side hole. In a twenty-fifth preferred embodiment, the system further comprises a cutter collecting unit comprising a housing and a screw for extracting the cutouts in the housing. In a twenty-sixth preferred embodiment, the system further comprises a surface pump for generating a secondary circulation flow along a pipeline. The secondary circulation flow allows the cuttings generated in the auger to be brought to the surface and carried by a primary circulation flow from the auger to the secondary circulation flow. In a twenty-seventh preferred embodiment, the system further comprises a flow guide which allows the primary circulation flow to circulate at a relatively high flow rate between the side hole and the pipe to prevent settling of the cuttings. In a twenty-eighth preferred embodiment, the engine is located within the perforated side hole. In a second aspect, the invention provides a method for drilling a lateral hole of deviation from a main well. The method comprises blocking an axial motor and impeller located at the bottom of the borehole. The motor and the axial impeller respectively allow to generate a torque of rotation and an axial force. A connector for transmitting the torque of rotation and axial force from a motor assembly to a drill string assembly is provided. The motor assembly includes the motor, the axial impeller and a drive shaft. The drill string assembly includes a drill pipe and auger. The connector provides a fluid communication channel between the motor assembly and the interior of the drill pipe. The connector is either a first connector or a second connector. The first connector can be connected to the drill string assembly to transmit axial force only to the drill pipe, and to transmit the torque of rotation to an additional drive shaft positioned within the drill pipe. The second connector can be connected to the drill string assembly to transmit the axial force and torque of rotation to the drill pipe. In a twenty-ninth preferred embodiment, the drill pipe transmits the axial force and the additional drive shaft transmits the torque of rotation to the drill. In a preferred thirtieth embodiment, the method further comprises controlling an effective radius of a curved hole in the side pit. The control is done by combining an angled mode to a straight mode. During the angled mode, three contact points of the drill string assembly are in contact with a perforated side hole wall to allow drilling of the curved hole. During straight mode, the following steps are performed: rotating the drill pipe from a first angle, transmit the torque of rotation and axial force to the bit for a determined first duration, remove the drill string assembly at a certain distance, rotate the drill pipe from a second angle, transmit the torque of rotation and the axial force to the auger for a second determined duration. In a thirty-first preferred embodiment, the control is performed by combining the angled mode and the straight mode to a jet mode. The jet mode comprises providing a jet to preferentially erode a reservoir in a particular direction. In a thirty-second preferred embodiment, the drill pipe transmits the torque of rotation and the axial force to the drill. In a thirty-third preferred embodiment, the method further comprises mechanically controlling from a remote location at least one parameter of the stabilizer between a set of parameters of the stabilizer. The set of parameters of the stabilizer comprises a diameter size of a stabilizer of a certain variable diameter, a distance between a first stabilizer relative to a marking device, the marking device is either a different stabilizer or an auger, a retraction of at least two stabilizers of variable diameter, and an azimuthal radius of the stabilizer of a certain variable diameter. In a thirty-fourth preferred embodiment, the method further comprises displacing a configuration scheme within a configuration slot, to select a desired adjustment position from a set of adjustment positions comprising at least three adjustment positions. Each adjustment position corresponds to a determined value of at least one parameter of the stabilizer. In a thirty-fifth preferred embodiment, the drill pipe is flexible, to allow a bending while transmitting the torque of rotation and the axial force. The drill pipe is supported in bending by a bending guide comprising rotation supports. In a thirty-sixth preferred embodiment, the method further comprises monitoring an orientation of a bit relative to at least one reference direction with at least one micro-sensor located in a vicinity of the bit. In a thirty-seventh preferred embodiment, the method further comprises generating a circulation of a drilling fluid in the auger with a pump located at the bottom of the bore. In a preferred thirty-eighth embodiment, the drilling fluid flows into the auger through an annular zone between the perforated side hole and the drill string assembly. Drilling fluid circulates from the auger through the fluid communication channel. In a thirty-ninth preferred embodiment, the method further comprises guiding the drilling fluid to an exit from the side hole through a passage having a predetermined orientation. In a fortieth preferred embodiment, the drilling fluid is guided downwardly. In a forty-first preferred embodiment, the method further comprises filtering drilling fluid cut-outs at the bottom of the bore. In a forty-second preferred embodiment, the filtered cuttings are compacted within a filter device. In a forty-third preferred embodiment, the filtered clippings are classified according to their size to prevent filtered clippings from clogging the filter device. In a forty-fourth preferred embodiment, the method further comprises collecting the cutouts located at the bottom of the perforation at a location under the side hole.

In a forty-fifth preferred embodiment, a secondary circulation flow along a pipeline is generated. The secondary circulation flow allows the cuttings generated in the auger to be brought to the surface and carried by a primary circulation flow from the auger to the secondary circulation flow. Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

Brief Description of the Drawings FIGURE 1 shows an illustration of a schematic portion of a steerable engine according to the prior art. FIGURE 2 shows an illustration of a stabilizer according to the prior art. FIGURE 3A shows an illustration of a straight configuration of an assembly located at the bottom of the bore according to the prior art. FIGURE 3B shows an illustration of a drop configuration of an assembly located at the bottom of the bore according to the prior art. FIGURE 3C shows an illustration of an integrated configuration of an assembly located at the bottom of the bore according to the prior art.

FIGURE 4 shows an illustration of an example of a system for drilling a side hole according to a first embodiment of the present invention. FIGURE 5 shows an illustration of an example of a double transmission configuration of a system for drilling a side hole according to the present invention. FIGURE 6 shows an illustration of an example of a rotation transmission configuration of a system for drilling a side hole according to the present invention. FIGURE 7 shows an illustration of an example of a steerable device according to a second embodiment of the present invention. FIGURE 8A and FIGURE 8B show examples of a section of a hole drilled during a straight mode by a steerable device according to the present invention. FIGURE 9 illustrates an example of a first possible system according to a third embodiment of the present invention. FIGURE 10A illustrates a cross section of a third possible system according to a third embodiment of the present invention. FIGURE 10B illustrates an example of a ratchet system of a third possible system according to the third embodiment of the present invention. FIGURE 10C illustrates an example of a lower control sleeve of a third possible system according to the third embodiment of the present invention. FIGURE 10D illustrates an example of a top control sleeve of a third possible system according to the third embodiment of the present invention. FIGURE 10E illustrates a table of adjustments of a third possible system illustrated in FIGURE 10A. FIGURE 10F illustrates an example of a slot J of a third possible system according to the third embodiment of the present invention. FIGURE 11 shows an illustration of a fifth possible system according to the third embodiment of the present invention. FIGURE 12 shows an illustration of an assembly located at the bottom of the perforation according to a fourth embodiment of the present invention. FIGURE 13A illustrates an example of a drilling system according to a fifth embodiment of the present invention. FIGURE 13B shows an illustration of a first example of a bending system according to a fifth embodiment of the present invention.

FIGURE 14A and FIGURE 14B illustrate a second example of a flexure system according to the fifth embodiment of the present invention. FIGURE 15 illustrates an example of a drilling system according to a sixth embodiment of the present invention. FIGURE 16 illustrates an example of an auger according to a sixth embodiment of the present invention. FIGURE 17 illustrates an example of a drilling system in accordance with a seventh embodiment of the present invention. FIGURE 18 illustrates schematically an example of a drilling system according to an eighth embodiment of the present invention. FIGURE 19 shows an illustration of an example filter device according to a ninth embodiment of the present invention and a tenth embodiment of the present invention. FIGURE 20 shows an illustration of an example of a drilling system according to an eleventh embodiment of the present invention. FIGURE 21A shows an illustration of an example of a clip collecting unit according to a twelfth embodiment of the present invention. FIGURE 2IB illustrates an example of a drilling system according to the twelfth embodiment of the present invention. FIGURE 22 shows an illustration of an example of a flow circulation system according to a thirteenth embodiment of the present invention. FIGURE 23 shows an illustration of an example of a flow guide according to a fourteenth embodiment of the present invention.

Detailed Description FIGURE 4 illustrates an example of a system for drilling a side hole according to a first embodiment of the present invention. The system comprises a motor assembly 415, which describes a motor 412 for generating a torque of rotation, an axial drive 411 for generating an axial force, a locking system 410 for fixing the motor 412 and the axial drive 411 located at the bottom of the bore and a transmission shaft 414 to transmit the rotation torque. The system further comprises a connector (402, 404) for transmitting the torque of rotation and the axial force from the motor assembly 415 to a drill string assembly. The drill string assembly includes a drill pipe 401 and an auger 403. The connector provides a fluid communication channel 416 between the motor assembly 415 and the interior of the drill pipe 401. A fluid can be moved through the fluid communication channel 416 by a pump (not shown in FIGURE 4) driven by a second motor (not shown in FIGURE 4). The pump and the second motor are typically installed on the motor 412. In a first alternative, the connector can be a first connector 404 that can be connected to the drill string assembly to transmit axial force to the drill tube 401 only. When the first connector 404 is used, the torque of rotation generated in the motor 412 is transmitted to an additional transmission shaft 405 placed inside the drill pipe. The axial force can be transmitted to the bit 403 with axial bearings 406. The first connector 404 can be connected to a housing 409 of the motor assembly 415. A drilling fluid may circulate within the drill string assembly through an annular zone between the additional drive shaft 405 and the drill pipe 401. Such a double transmission configuration allows a curved hole to be drilled: the drilling tube 401 can withstand bending stresses relatively easily since the torque of rotation is transmitted by the additional drive shaft 405. In a second alternative, the connector can be a second connector 402 that can be connected to the drill string assembly. The second connector 402 allows the axial force and the rotational torque to be transmitted to the drilling tube 401. The transmission of the axial force to the drilling tube 401 can be carried out using axial bearings 407 and an intermediate tube 408. Such a rotary transmission configuration is particularly adapted for drilling in a straight direction: in a curved drilled hole, the rotary drilling tube can make contact with the walls of the drilled side hole or a main well, thereby reducing the efficiency of the perforation. The second connector 402 can be connected to a housing 409 of the motor assembly 415. With the rotation transmission configuration, the drilling fluid can circulate within the drill string assembly through the drilling tube 401 and through the intermediate tube 408. The system according to the invention comprises a motor 412 which is blocked at the bottom of the borehole. The transmission of the rotational torque and the axial force to the bit 403 can be adapted depending on a drilling target, typically a desired radius of the hole to be drilled. The system according to the invention can be configured to drill a curved hole or a straight hole. For a curved hole, the double transmission configuration is preferably used: the first connector 404 can be connected to the motor assembly 415. For a straight hole, the second connector 402 may be connected to the motor assembly 415. However, the first connector can be used to pierce the straight hole and the second connector 402 to pierce the curved hole. On this last case, or in a case in which the second connector 402 is used to pierce the straight hole after the curved hole, the rotating perforation tube 401 or the intermediate rotation tube 408 may be in contact with the walls of the hole. The rotary drilling tube 401 or the intermediate rotating tube 408 can be bent from the main well into the side hole, or into the side hole. A fifth embodiment of the present invention described in a further paragraph allows the curved pit to be punctured with a bent rotation drill pipe. Preferably, the motor is locked into the main well while the bit drills the side hole. Alternatively, the motor locks inside the side hole. A relatively short drill string can be used, which allows to avoid a rotation of the short drill string within a curved section of the drilled hole during additional drilling of the side hole. The transmission of the rotation torque comprises a transmission of a rotation combined with a transmission of a torque. The locking system may comprise a first set of side arms to allow locking of the impeller. The first set of side arms is located at one end of the impeller. A second set of side arms can be provided near the auger. When the bit has a relative displacement of sufficient amplitude, the second set of lateral arms blocks the bit. The first set of side arms is then closed, to unlock the impeller. The impeller can be operated to reduce a distance from the auger, the first set of open side arms to re-lock the impeller and the second set of closed side arms. This operation makes it possible to provide the axial force despite an axial displacement of the drill string. FIGURE 5 illustrates an example of a double transmission configuration of a system for drilling a side hole according to the invention. Only a portion of the system is represented. A first connector 504 connects a piercing tube 501 to a housing 509. The housing 509 transmits an axial force generated to an impeller (not shown). The piercing tube 504 therefore transmits the axial force to an auger (not shown) located at one end of the piercing tube 501. A torque of rotation torque generated in a motor (not shown) is transmitted by a transmission shaft 514 to a further transmission shaft 505 at one end of which the bit is attached. Both the transmission shaft 514 and the additional transmission shaft 505 are thus rotated. The drive shaft 514 can be guided with bearings (not shown in FIGURE 5) held in the housing 509. The first connector 504 provides a fluid communication channel 516 for the circulation of a drilling fluid. During a drilling operation, the drilling fluid can be pumped through the system. The drilling fluid can circulate through the fluid communication channel 516 to reach the auger and evacuate through an annular zone between the system and the drilled hole. The large arrows in FIGURE 5 represent a possible circulation of the drilling fluid. FIGURE 6 illustrates an example of a rotation transmission configuration of a system for drilling a side hole according to the invention. Only a portion of the system is represented. A second connector 602 connects a piercing tube 601 to a housing 609.

The housing 609 transmits an axial force generated in an impeller (not shown). The second connector 602 transmits the axial force to an intermediate tube 608 by means of axial bearings 607. The intermediate tube 608 transmits the axial force to the drilling tube 601 at one end of which a bit (not shown) is attached. A transmission shaft 614 transmits a torque of rotation torque generated in a motor (not shown) to the intermediate tube 608, and therefore to the drilling tube 601. The transmission shaft 614, the intermediate pipe 608 and the drill pipe are thus rotated. The drilling tube 601 transmits the axial force and the rotational torque to the auger. The second connector 602 provides a fluid communication channel 616 for a circulation of a drilling fluid. During a drilling operation, the drilling fluid can be pumped through the system. The drilling fluid can circulate through the fluid communication channel 616, reach the auger and evacuate through an annular zone between the system and the drilled hole. The large arrows in FIGURE 6 represent a possible circulation of the drilling fluid. Such a rotation transmission configuration is particularly well suited for drilling in a straight direction. The drilling system of the present invention can also be used in a lateral configuration (not shown), wherein the engine is locked within a lateral hole of a main well diversion. In the lateral configuration, the drill string may have a relatively short length. Both the double transmission configuration and the rotation transmission configuration can be used. However, the rotation transmission configuration is preferred. A system for locking the drilling system may comprise extension arms having pads. The pads allow to hold the drilling machine against the walls of the perforated side hole. The pads can have a relatively high surface area to lower contact stresses. The drilling system may further comprise a flow channel that allows a circular drilling fluid between an auger and the main well.

Dirigible Device A steerable engine as shown in FIGURE 1 comprises a hydraulic converter inside a drill pipe. The hydraulic converter generates a torque of rotation using a circulation of a drilling fluid and therefore is relatively long, for example, 3 meters. The hydraulic converter comprises relatively rigid parts that can not be bent without damage. The drilling tube of the steerable engine is also relatively long, which prohibits drilling a curved hole having a relatively short radius, for example less than 10 meters. There is a need for a steerable device that allows to drill a curved hole of short radius. FIGURE 7 illustrates an example of a steerable device according to a second embodiment of the invention. The steerable device 701 comprises a bending drill tube 705 and an auger 707 at one end of the drill tube 705. The bit 707 can be rotated by transmitting a torque of rotation. The torque of rotation is generated by a motor 704 that is located within the main well 709. As the rotational torsion moment in the main well 709 is generated, the steerable device 701 may have a length that is shorter than in the prior art, and therefore may allow a curved hole 710 to be drilled within a reservoir 713, the curved 710 hole has a shorter radius. The torque of rotation can be transmitted to the bit 707 by a drive shaft 703 that passes through the drill pipe 705. The drilling tube 705 can be used to transmit generated axial forces to an axial impeller 714. The axial forces can be transmitted either directly to the auger or, as represented in FIGURE 7, transmitted to the transmission shaft 703 by an axial bearing system 708, for example a thrust bearing system. The transmission shaft 703 has to support a fast rotation while it is bending. The transmission shaft 703 is therefore flexible with bending but allows the torque of rotation from the motor 704 to be transmitted to the bit 707. As the transmission shaft 703 is bent into the drill pipe 705, the tube 705 of The perforation may comprise low friction guide systems 711, for example, plain bearing systems. Typically, the bearings 711 are substantially and uniformly spaced along the drill pipe 705. The bearings 711 may include passages (not shown) that allow a circular drilling fluid between the drive shaft 703 and the drill pipe 705. The transmission shaft 703 can be formed of titanium and the bronze guide system 711. The drill tube 705 transmits the axial forces while bending. The perforation tube 705 has a shape corresponding to a curvature of the hole and is tangent to the perforated hole: a deformation can be achieved in a plastic domain.

Since the motor 704 is located within the main well, the motor 704 can be connected with electrical wires: the motor 704 can be electric. The steerable engine may preferably comprise a motor drive shaft (not shown) for transmitting the torque of rotation from the motor to the drive shaft by a first connector (not shown). In this case, the transmission shaft is an additional transmission shaft. The first connector can provide a fluid communication channel between a motor assembly to the inside of the drill pipe, the motor assembly comprises the motor, the axial driver, the locking system and the motor drive shaft. The first connector can be replaced by a second connector (not shown) which also provides a fluid communication channel between a motor assembly towards the interior of the drill pipe. The second connector can transmit the torque of rotation and the axial force to the drill pipe. However, the steerable engine 701 of Figure 7 comprises a simple transmission shaft 703 only for transmitting the torque of rotation from the engine 704 to the auger 707 and a simple drilling tube 705 for transmitting the axial force to the auger. 707. The steerable engine 701 may not allow a first connector or a second connector to be removably connected to adapt for the transmission of the rotational torque and the axial force to the bit 707 depending on a desired radius of the hole to be drilled. . The steerable device 701 makes it possible to drill a curved hole 710 having a short radius. The drill pipe 705 is bent and three contact points 702 are located in a drill string assembly comprising the drill pipe and the drive shaft. When the curved hole 710 is perforated, the contact points 702 are in contact with a wall of the perforated side hole. The three contact points 702 define an angle of the drill pipe to allow the curved hole 710 to be punctured. The positions of the contact points 702 determine a direction radius of the curved hole 710. However, in the case of a relatively soft reservoir, the auger can drill the larger gauge side hole compared to the auger. The perforated hole can therefore have a relatively large diameter: the perforated hole wall can therefore be located under an expected wall. As the steerable device 701 lies on the lower wall of the perforated hole, the perforated curved hole can have an effective radius of curvature having a value greater than the direction radius corresponding to the angle of the perforation tube.

An effective radio control can be realized by combining such an angled mode with a straight mode. During straight mode, the steerable device 701 is oriented by itself at a first angle. The torque of rotation generated in the motor 704 and the axial force are transmitted to the bit 707 according to a double transmission configuration for a first determined duration, which allows a perforation of a first hole on a first portion having a first direction. The steerable device 701 is removed over a certain distance, for example the first portion. The determined distance may also be greater or less than the length of the first portion. The steerable device 701 is then oriented by a second angle. The torque of rotation and the axial force are transmitted to the drill for a second determined duration, which allows reaming the first hole. Such steps can be performed in any order, for example, the rotation of the second angle can be performed before retraction. The rotation of the device steerable by a first angle can be performed with a first angle having a null value, that is, the steerable device can be rotated only once by a second angle during the execution of the steps. FIGURE 8A and FIGURE 8B illustrate examples of a section of a hole drilled during straight mode. The section of FIGURE 8A may have been perforated by performing the steps described in the foregoing. Typically, the second angle is substantially equal to 180 ° and the second determined duration is substantially equal to the first determined duration, which produces an oval hole 81. If the steps are repeated, the steerable device pierces the oval hole 81 over a certain length. The oval hole has a section larger than a diameter of the auger and has a relatively constant direction. FIGURE 8B illustrates a second example of a section of a hole drilled during straight mode. In this example, the transmission of the rotation torque and the axial force to the auger is carried out four times. For example, the second angle can be substantially equal to 180 ° and the second determined duration can be substantially equal to the first determined duration that produces an oval hole. Then, the steerable device is removed and rotated from a third angle, the third angle is substantially equal to 90 °. After a third perforation, the steerable device is removed and rotated by a fourth angle. The fourth angle is substantially equal to 180 °. The torque of rotation and axial force can be transmitted to the auger and a fourth bore is made. Such operations can be repeated. A resulting section 82 is larger than a diameter of the auger. The straight mode allows drilling in a relatively constant direction, which produces a perforated hole that is relatively straight over the determined distance. When combined with the angled mode, in the case of a direction radius smaller than a desired radius, the straight mode allows controlling an effective radius of the curved hole. Alternatively, the perforation tube can oscillate continuously from one direction to an opposite direction. The oscillations cause the drill pipe to be rotated over complete turns, thus allowing to drill a cylindrical hole having a diameter larger than a section of a drill bit. If the reservoir is soft, a jet mode can be combined with the angled mode or the angled mode already in combination with the straight mode. FIGURE 7 illustrates an example of such jet operation. A fluid jet 712 is provided to erode reservoir 713 in a certain direction. In the example of FIGURE 7, the bit is equipped with a non-symmetric jet configuration. The auger is not rotated, but the engine 704 can orient the drive shaft 703 to orient the fluid jet 712 in a preferred direction. An angle of displacement between an azimuthal direction of the fluid jet 712 and a reference direction of the motor 704 can be measured. The jet allows to drill a curved hole that follows a predefined trajectory even in the soft deposits, in a more precise direction than the perforation using a rotation of the bit 707.

Drill direction control In order to control an effective drilling direction, the stabilizers can be set to place an auger inside a section of a side hole. In particular, a stabilizer of variable diameter in an assembly located at the bottom of the drilling of a drilling system allows to decide from a remote location whether the drilling is to follow a straight direction or change direction. The change of direction may allow drilling in an upward or downward direction depending on a stabilizer configuration of varying diameter between the stabilizers of the assembly located at the bottom of the bore. When an operator decides to change the direction of drilling, a mechanical process allows to transmit and establish. When an operator decides to change the direction of drilling, a mechanical process allows to transmit and establish the decision in the stabilizer of variable diameter, thus allowing to select one of the two possible directions. However, a change of direction for a third different direction, for example, is required, an upward direction if the vertical direction is a downward direction, an assembly located at the bottom of the bore needs to be removed from the well. In this way there is a need for a more flexible steering control system. FIGURE 9 illustrates an example of a first possible system according to a third embodiment of the present invention. An auger 903 at one end of a drill string 901 of an assembly located at the bottom of the bore allows a side hole 904 to be drilled. The drill string 901 is surrounded by a plurality of stabilizers (902,905, 906), wherein at least one stabilizer is a variable diameter stabilizer (905,906). At least one stabilizer of variable diameter (905, 906) allows the bit 903 to be placed within a section of the side hole 904. The system according to the third embodiment of the present invention further comprises control means for mechanically controlling from a remote location at least one parameter of the stabilizer between a set of stabilizer parameters. The set of stabilizer parameters comprises a diameter size of a determined variable diameter stabilizer (not shown in FIGURE 9), a distance between a first stabilizer (not shown in FIGURE 9) and a marking device (not shown in FIG. FIGURE 9). The marking device may be a stabilizer other than an auger. The stabilizer parameter set further comprises a retraction of at least two stabilizers of varying diameter (905.906), and an azimuthal radius of the determined variable diameter stabilizer (not shown in FIGURE 9). The first possible system illustrated in FIGURE 9 allows to control from a remote location, for example, from the surface, a retraction of two stabilizers of variable diameter (905,906). The two stabilizers of variable diameter (905.906) can be put in a coordinated form. The first possible system illustrated in FIGURE 9 may allow drilling following more than two directions. The first possible system may comprise only two stabilizers having variable diameter. Alternatively, as shown in FIGURE 9, the first possible system may comprise three stabilizers, with two stabilizers of varying diameter therebetween. Typically, a first stabilizer 906 of variable diameter is located near the auger 903 and a second stabilizer 905 of variable diameter is located between the other two stabilizers (902.906). The first possible system comprises control means (not shown in FIGURE 9) which comprise more than two adjustment positions. Each adjustment position corresponds to an associated value of the stabilizer parameter. A configuration where three stabilizers (902,905, 906) are involved, as depicted in FIGURE 9, the stabilizer parameter can describe a retraction or expansion of at least two stabilizers of variable diameter (905.906). The corresponding control means therefore comprise at least three adjustment positions: a first adjustment position associated with a full gauge position of the first stabilizer 906 of variable diameter and of the second stabilizer 905 of variable diameter; - a second adjustment position associated with a lower caliber position of the first stabilizer 906 of variable diameter and a position of greater caliber of the second stabilizer 905 of variable diameter; - a third adjustment position associated with a large-caliber position of the first stabilizer 906 of variable diameter and to a lower caliber position of the second stabilizer 905 of variable diameter. A fourth adjustment position associated with a retraction of the variable diameter stabilizer 906 and the second variable diameter stabilizer 905 may also be comprised within the control means. If the first adjustment position is selected, the first stabilizer 906 of variable diameter and the second stabilizer 905 of variable diameter are in a position of large caliber. Consequently, the first stabilizer 906 of variable diameter and the second stabilizer 905 of variable diameter apply contact stresses on a wall of the side hole 904 and the perforation is performed in a relatively straight direction. If the second adjustment position is selected, only the first stabilizer 906 of variable diameter is retracted, which provides a configuration which is similar to that shown in FIGURE 3B. A center of bit 903 points in a downward direction due to the weight of drill string 901. The drilling is done in the downward direction. An adjustment for a smaller gauge position of the second variable diameter stabilizer 905 only, ie, only the second stabilizer 905 of variable diameter is retracted, provides a configuration which is similar to that shown in FIGURE 3C. A center of bit 903 points in an upward direction due to a weight of drill string 901. The drilling is done in the upward direction. A Hall Effect sensor 907 can be provided to measure a diameter of one of the two variable diameter stabilizers. The Hall Effect Sensor 907 can detect a retraction of a variable diameter stabilizer piston. Alternatively, the diameters of the two variable diameter stabilizers can be measured. The adjustment of both variable diameter stabilizers (905,906) is coordinated to achieve a desired configuration. If the hole to be drilled is relatively sticky, the two variable diameter stabilizers (905, 906) can be included in a single hole collar section (not shown in FIGURE 9) which allows to provide a single control unit to control at least one parameter of the stabilizer between the set of parameters of the stabilizers. A second possible system (not shown) according to the third embodiment of the present invention makes it possible to adjust a size of a diameter of at least one stabilizer of a determined variable diameter. The variable diameter stabilizer thus determined may have more than two positions. For example, the determined variable diameter stabilizer may be extended, retracted or be in a middle position. The second possible system comprises control means with at least three adjustment positions. Each adjustment position can be selected, for example, by means of a configuration key, for example, a key, placed inside a configuration slot, for example, a slot J. Each adjustment position corresponds to a position of the stabilizer of variable diameter determined. The second possible system allows to adjust a drilling direction with better precision than the prior art systems. FIGURE 10A illustrates a cross section of a third possible system according to a third embodiment of the present invention. Only half of the third possible system is represented. The third possible system allows to establish in a coordinated way two stabilizers of variable diameter (1001; 1002). Each of the variable diameter stabilizers (1001; 1002) may be in a retracted position, a middle position or an extended position. The third possible system therefore allows drilling following a higher direction or a lower direction, wherein a direction of drilling can be adjusted with a relatively high precision. The third possible system comprises control means with six adjustment positions (i, j,, 1, m, n,). Each adjustment position corresponds to an associated value of a stabilizer parameter, for example, a stabilizer 1001 of variable upper diameter is extended and a stabilizer 1002 of smaller variable diameter is retracted, as shown in FIGURE 10A. The control means allow to change from one setting position to another with a relative chronological order of a plurality of events, for example, a flow is applied before an axial force. The extension or retraction of each variable diameter stabilizer (1001; 1002) depends on an extension or a retraction of the associated pistons (1003; 1004). The control means allows a top piston 1003 and a bottom piston 1004 to be pushed out of a collar 1000, with respectively an upper control sleeve 1010 and a lower control sleeve 1007. When no thrust is applied to a given piston, the determined piston retracts. A ring 1005 mounted on each piston (1003; 1004) makes it possible to prevent the piston (1003; 1004) from being lost in a sounding. The lower piston 1004 can be pushed out of the collar 1000 by sliding in an inclination of the lower control sleeve 1007. The lower control sleeve can slide axially within the collar 1000. A pin 1008 prevents the lower control sleeve 1007 from rotating. A lower spring 1040 pushes the lower control sleeve 1007 upwardly. The lower control sleeve 1007 extends upwardly to a vicinity of the upper variable diameter stabilizer 1001. The lower control sleeve 1007 can therefore have a relatively high length, for example, several meters. The sliding of the lower control sleeve 1007 is controlled by a projection 1009 of the upper control sleeve 1010. The upper control sleeve 1010 can slide axially within the collar 1000 and can be rotated in a single direction: a tringuete system 1011 prevents a rearward rotation of the upper control sleeve 1010. FIGURE 10B illustrates an example of a trike system 1011 of a third possible system according to the third embodiment of the present invention. The trike system 1011 comprises slanted teeth 1042 in which a tab 1041 falls to allow effective movement in only one direction only. Referring again to FIGURE 10A, the trolley system 1011 allows a sliding of the upper control sleeve 1010 within the collar 1000. The projection 1009 pushes the lower control sleeve 1007 through different contact areas (1012, 1013, 1014, 1043). , 1044, 1045) depending on an azimuthal position of the upper control sleeve 1010.

FIGURE 10C illustrates an example of a sleeve 1010 of lower control of a third possible system according to the third embodiment of the present invention. The lower control sleeve comprises a plurality of contact areas (1012, 1013, 1014, 1043, 1044, 1045,). If the projection 1009 is aligned with the large-bore contact areas (1012, 1044, 1045), the upper control sleeve 1007 is pushed into the collar 1000. As a result, the lower piston 1004 is in the extended position. If the projection 1009 is aligned with medium-gauge contact areas (1013, 1043), the lower piston 1004 is in the middle position. If the projection 1009 is aligned with a smaller caliper contact area 1014, the lower piston 1004 is in the retracted position. The diameter of the lower stabilizer 1002 therefore depends on the contact area with which the projection 1009 is aligned. Referring now to FIGURE 10A, the sleeve The upper control 1010 comprises three inclinations (1015, 1016, 1017) on which the lower piston 1003 can lie. The inclinations have different azimuthal positions. FIGURE 10D illustrates an example of a top control sleeve 1010 of a third possible system according to the third embodiment of the present invention. The upper control sleeve 1010 comprises three inclinations (1015, 1016, 1017) having the same angle of inclination. The inclinations (1015, 1016, 1017) start at different axial positions in the upper control sleeve 1010. Referring again to FIGURE 10A, if the upper control sleeve 1010 has an axial position so that the upper piston 1003 lies at a first inclination 1017, the upper piston can be pushed out to the extended position. A second inclination 1016 allows the upper piston 1003 to be placed in a middle position, and the third inclination 1015 allows the upper piston 1003 to be retracted. The upper control sleeve 1010 comprises a projection 1009 which controls a size of the lower piston 1004. Each contact area is combined with a given height of the upper control sleeve 1010. Each adjustment position (i, j, k, 1, m, n,) is associated with a combination of a certain contact area (1012, 1013, 1014, 1043, 1044, 1045,) and a given inclination (1015).; 1016; 1017). FIGURE 10E illustrates a table of adjustment of a third possible system illustrated in FIGURE 10A. For example, the large-bore contact area 1012 is combined with the first inclination 1017. The combination is associated with a first adjustment position i corresponding to an extension of both pistons (1003; 1004), which allows drilling following a direction straight. A third adjustment position k is associated with a combination of the smaller caliber contact area 1014, ie, the lower piston 1004 retracts, towards the first inclination 1017, that is, the first upper piston 1003 extends. The third adjustment position k allows drilling in a downward direction. A second adjustment position j is associated with a combination of the half-bore contact area 1013, that is, the lower piston 1004 retracts, for the first inclination 1017, that is, the upper piston 1003 extends. The second adjustment position j allows drilling following an intermediate descending direction. Three other adjustment positions (1, m, n) are illustrated in the adjustment table of FIGURE 10E. Referring again to FIGURE 10A, the azimuthal position of the upper control sleeve 1010 is controlled by a position of a configuration key, for example, a key 1021 within a configuration slot, for example, a J 1025 slot. Slot J 1025 is located on a sleeve 1018 of slot J. Key 1021 is mounted on an extension 1022 of a top mandrel.

FIGURE 10F illustrates an example of a Slot J of a third possible system illustrated in FIGURE 10A. Slot J 1025 allows to change from one of the adjustment positions (i, j, k, 1, m, n) to another. If the flow of a remote pump (not shown) occurs before an application of the axial force, the sleeve 1018 of slot J is forced to descend by a pressure drop generated by the flow. During a downward stroke, the key 1021 moves within the groove J 1025, thereby inducing a rotation of the slot sleeve 1018. Referring now to FIGURE 10A, teeth 1019 allow the upper control sleeve 1010 to rotate in the rotation of the slot sleeve 1018. However, a free rotation of the slot sleeve 1018 relative to the upper control sleeve 1010 can also be allowed depending on a coupling of the teeth 1019. If the upper control sleeve 1010 is moving downwards, the upper piston 1003 can be pushed depending on the inclination (1015, 1016, 1017) on which the upper piston 1003 lies. The rotation of the upper control sleeve 1010 makes it possible to align the projection 1009 with a certain contact area (1012, 1013, 1014, 1043, 1044, 1045), thereby controlling the diameter of the stabilizer 1002 of lower variable diameter. If the axial force is applied before the flow, the upper mandrel 1023 moves downwardly until one end 1046 of the upper mandrel 1023 makes contact with a limb 1047 of a lower mandrel 1026. The extension 1022 of the upper mandrel pushes the slot sleeve 1018, so that no relative movement between the slot sleeve 1018 and the extension 1023 of the upper mandrel occurs. The sleeve 1018 of groove J is therefore not rotated. When the teeth 1019 are engaged so that the upper control sleeve 1010 is rotated with the rotation of the slot sleeve 1018, changing from one setting position (i, j, k, 1, m, n) to another provides when applying the flow before the axial force. If no change is desired, the axial force is applied before the flow. Under suitable conditions, a displacement of the key 1021 allows selecting a desired adjustment position among a set of adjustment positions (i, j, k, 1, m, n). The third possible system according to a third embodiment of the present invention may further comprise a position indicator 1028. When the mandrill 1023 is pushed downwardly on the lower mandrel 1026, the position indicator 1028 moves downwardly. A spring 1030 makes it possible to ensure the displacement of the position indicator 1028 is limited by a mechanical stop 1029 of the slot sleeve 1018. The mechanical stop 1029 has a length which depends on the azimuthal position of the slot sleeve 1018. As a consequence, the displacement of the position indicator 1028 depends on the azimuthal position of the slot sleeve 1018. When a pressure drop in a nozzle of the position indicator 1028 depends on the displacement of the position indicator, it is possible, by monitoring the pressure drop, for detecting the azimuthal position of the slot sleeve 1018. The possible free rotation of the slot sleeve 1018 relative to the top control sleeve 1010 can also be taken into consideration. Consequently, the diameters of the variable diameter stabilizers (1001, 1002) can be evaluated. Stretch marks and notches (not shown in FIGURE 10A) allow the upper mandrel 1023 to be prevented from rotating in relation to the lower mandrel 1026. The axial force on the other hand is transmitted from the upper mandrel 1023 to the lower mandrel 1026 by contacting the end 1046 of the upper mandrel 1023 and the end 1047 of the lower mandrel 1026. A rear contact 1033 allows an extension force to be transmitted from the upper mandrel 1023 to the lower mandrel 1026 when the system rises out of the drilled hole. A fourth possible system (not shown) according to the third embodiment of the present invention allows to control from a remote location an azimuth radius of a stabilizer of a certain variable diameter. The variable diameter stabilizer determined can in fact be an azimuthally adjustable stabilizer comprising a plurality of pistons, for example three pistons, as shown in FIGURE 2. Each piston has a determined azimuth direction. In the fourth possible system, each piston can be established independently of the others. The fourth possible system comprises control means with at least three adjustment positions, each adjustment position corresponding to a determined value of a stabilizer parameter, for example only a first piston extends. When a determined piston of the azimuthally adjustable stabilizer near the auger is pushed towards a wall of a drilled hole, the auger drills in a direction opposite to a given azimuthal direction of the determined piston. Particular care may be taken to synchronize the thrust of the determined piston with a possible rotation of a drill string of an assembly located at the bottom of the bore.

As each piston of the azimuthally adjustable stabilizer can be set independently, it is possible to order a perforation following any direction, for example, a horizontal direction. A possible system according to the third embodiment of the present invention allows control from a remote location, for example, from the surface, a longitudinal position of a first stabilizer relative to a marking device. The marking device may be mounted in an assembly located at the bottom of the perforation: for example, the marking device may be a different stabilizer or a bit. The first stabilizer may be a variable diameter stabilizer or any other device which allows a center of a drill string to be placed in a center of a section of a perforated hole, for example a stabilizer. An adjustment of the longitudinal position of the stabilizer relative to the auger can be made by adjusting a size of a section of the slide, or by moving the stabilizer along a drill string. The adjustment of the distance between two stabilizers allows to adjust a deformation of the drill string between the two stabilizers, and therefore to adjust a drilling direction. FIGURE 11 illustrates a possible system outline according to the third embodiment of the present invention. The possible system shroud allows an adjustment of a distance between a stabilizer 1102 and a bit 1101, and therefore an adjustment of a drilling direction. The system comprises a drilling string 1105 within which a sliding mandrel 1104 is located. The bit 1101 is located at one end of the sliding mandrel 1104. The direction of drilling depends on an elastic deformation of the sliding mandrel 1104 over a distance between the stabilizer 1102 and the bit 1101. A sealing-blogging system 1103 comprises means of blogging, for example, internal runners, to maintain the mandrel 1104 of Sliding in a certain position. The stamping-blogging system 1103 may also comprise a seal, eg, a rubber element, to secure a seal so that a circulation of a drilling fluid reaches the auger 1101 through an interior of the sliding mandrel 1104. The internal runners can be controlled by a physical parameter, for example, pressure, of a control shaft 1106. A transmission system 1107 allows the control shaft 1106 to communicate with the sliding mandrel 1104 and the sealed-blogging system 1103. The transmission system 1107 typically allows to establish the internal runners and transmit a displacement of the control shaft 1106. The transmission system 1107 comprises at least one hole to allow circulation of the drilling fluid through the sliding mandrel 1104. When the inner skids are dislodged, the sliding mandrel can move. A retraction on the control shaft 1106 makes it possible to reduce the distance between the stabilizer 1102 and the bit 1101. The distance between the stabilizer 1102 and the bit 1101 can also be increased, for example, by pushing on the control shaft 1106. The lock-lock system 1103 can also transmit a torque of rotation and an axial force from the drill string 105 to the sliding mandrel 1104. Alternatively, the rotational torque is transmitted from an alternative shaft (not shown) to the bit 1101. The steering control system according to the third embodiment of the present invention is interleaved in a drill string assembly of a drilling system. Preferably, the drill string assembly is removably connected to an engine assembly with a connector. The motor assembly can comprise a motor for generating a torque of rotation, an axial drive for generating an axial force, a locking system for fixing the motor and an axial drive located at the bottom of the bore, and a shaft for transmission to transmit the torque of rotation to the drill string assembly. The connector allows to transmit the torque of rotation and axial force from the motor assembly to the drill string assembly. The drill string assembly comprises an auger and a drill pipe. The connector provides a fluid communication channel between the motor assembly and the interior of the drill pipe. The connector comprises either a first connector or a second connector. The first connector can be connected to the drill string assembly to transmit the axial force only to the drill pipe and transmit the torque of rotation to an additional drive shaft placed inside the drill pipe. The auger is located at one end of the additional rotary transmission shaft located inside the drill pipe, the drill tube transmits the axial force. A plurality of stabilizers surrounds the transmission shaft. In particular, the fourth possible system of the third embodiment of the present invention can be employed with a drill pipe without rotation. Such a configuration of the double transmission is particularly suited for drilling following a curve.

The second connector can also be connected to the drill string assembly. The second connector allows to transmit the axial force and the torque of rotation to the drill pipe. The drill pipe transmits the torque of rotation and the axial force to the auger. Such a rotation transmission configuration is particularly adapted to pierce substantially in a straight direction. A plurality of stabilizers surrounds the drill pipe to ensure proper guidance of the drill string. Alternatively, the drilling system may also comprise a simple drive shaft for transmitting the torque of rotation from a motor to an auger, and a simple drill pipe for transmitting an axial force to the auger. The simple drill pipe may not be different from the simple drive shaft. The drilling system may not allow a first connector or a second connector to be removably connected to adapt the transmission of the rotational torque and the axial force to the auger depending on a desired radius of the hole to be drilled.

Monitoring the drilling direction Controlling a drilling trajectory requires monitoring an orientation of the drill bit. Monitoring is usually performed with an accelerometer system comprising at least one accelerometer that provides a measurement of a drilling string inclination relative to the Earth gravity vector. A magnetometer system comprises at least one magnetometer that allows an azimuth of the drill string to be measured against the magnetic field of the Earth. The accelerometer system can be associated with the magnetometer system. However, in the systems of the prior art, the magnetometer system and the accelerometer system are located at a relatively long distance from the auger, for example, 25 meters. There is a need for a system in which a more accurate measurement of the orientation of the bit can be provided. FIGURE 12 illustrates an assembly located at the bottom of the bore according to a fifth embodiment of the present invention. The assembly at the bottom of the borehole comprises an auger 1201 for drilling a hole. The assembly located at the bottom of the perforation further comprises at least one micro-sensor (1207, 1208) in an environment close to the bit 1201. At least one micro-sensor (1207, 1208) allows a measurement of one orientation of bit 1201 in relation to a reference direction. At least one micro-sensor can be a micro-magnetometer 1207 which allows a measurement of an orientation of the bit 1201 relative to the magnetic field of the Earth. Such a miero-magnetometer may belong to a family of Micro-Opto-electro-Mechanical Systems (MOEMS). Preferably, three micro-magnetometers are provided in the vicinity of the bit to measure three orientations of the bit relative to the Earth's magnetic field. A three-dimensional measurement of the orientation of the bit is therefore provided. The miero-magnetometer 1207 can also be a micro-accelerometer 1207. The micro-accelerometer 1207 allows a measurement and orientation of the bit 1201 relative to the gravity vector of the Earth. The micro-accelerometer can belong to the Micro Electro Mechanical Systems (MEMS) family. Preferably three micro-accelerometers are provided in the vicinity of the bit to measure three orientations of the bit relative to the gravity vector of the Earth. A three-dimensional measurement of the orientation of the bit is therefore provided. The system can also comprise both the three micro-accelerometers and the three micro-magnetometers. The micro-accelerometers and the micro-magnetometers themselves can provide respectively less accurate measurements than conventional accelerometers and conventional magnetometers. Nevertheless, the system thanks to the location of the micro-sensors in the vicinity of the auger, allows to provide a more precise mention of the orientation of the auger than the systems of the prior art. At least one micro-sensor allows to monitor the orientation of the bit 1201. The miero-magnetometer 1207 and the micro-accelerometer 1207 can be located within a sub-assembly 1206 near the bit 1201. An electric motor (not shown) can generating a torque of rotation that allows spinning the auger 1201. The electric motor has a length that is relatively less than the length of a hydraulic motor. The assembly located at the bottom of the perforation according to the present invention may comprise a small tube 1204 at a center of a drill string 1202. The small tube 1204 allows communication between a main substitute (not shown) and the micro-sensors (1207, 1208). The main substitute can be located inside a main well from which a lateral hole is being drilled using the assembly located at the bottom of the hole. The main substitute can also be a Measurement While Drilling tool located along a longitudinal axis of the assembly located at the bottom of the borehole at a relatively long distance from the bit 1201. The communication can be made by means of electric wires 1205 . The communication can also be performed by means of electrical signals transmitted to the micro-sensors (1207, 1208) through the tube 1204 stick and returned to the micro-sensors (1207, 1208) through the drill string 1202. The tube 1204 pegueño needs to be electrically isolated from drill string 1202. Preferably, the assembly located at the bottom of the perforation according to the present invention is part of a drilling system according to the first embodiment of the present invention. Alternatively, the micro-sensors are located in an environment close to an auger of an alternative drilling system, wherein the alternative drilling system does not allow to removably connect a first connector or a second connector to adapt the transmission of the rotation torque. and the axial force to the auger depending on a desired radius of the hole that is drilled. The alternative drilling system may be a steerable engine, a steerable device, a drilling rig system, a coiled pipe system or any other drilling system. In a case (not shown) of a steerable device, the micro-sensors can be located within a transmission shaft. In a case of an assembly located at the bottom of the borehole with an address control system (not shown), for example the micro-sensors can be located within a control unit (not shown).

Very short radius drilling A drilling system for drilling a side hole of deviation from a main well with a very short radius curve may comprise a flexible drill pipe that bends substantially perpendicularly in a bend between the main well and a perforated lateral hole. An engine and an axial impeller can be locked inside the main well and the flexible drill pipe transmits a torque of rotation and an axial force to a drill. The prior art drilling systems comprise either a diverting wedge or bushings, to allow the transmission of the rotational torque and the axial force at the elbow. However, in the case of a relatively long side pit, the transmission of the rotational torque and the axial force can be relatively delicate due to an intensity of the axial force along the flexible drill pipe. The diverting wedge has to support the axial force of the axial impeller and a compressive force from the auger. A reaction force acting on the diverting wedge can be calculated as a vector combination of the axial force and the compression force. In addition, the drill pipe slides on the deviating wedge during drilling as the perforated lateral well grows. However, when drilling is done, a tangential velocity of the drill pipe is greater than a slip speed. Typically, a relationship between the tangential velocity and the sliding speed is within a margin of one hundred. A combined velocity resulting from a vector sum of the tangential velocity and the sliding velocity, therefore, is substantially equal to the tangential velocity. The strength of the reaction and the combined speed can generate significant friction loss and wear. There is a risk that the diverting wedge, or a rocky deposit behind the diverting wedge, will explode due to stresses transmitted by the flexible shaft. There is a need for a system which allows a transmission of a torque of rotation and a relatively high axial force along a flexible shaft to flex the flexible shaft. FIGURE 13A illustrates an example of a drilling system according to a conventional embodiment of the present invention. An auger 1307 at one end of a drilling tube 1301 drills a side hole 1302 deviation from a main well 1303. The piercing tube 1301 transmits a torque of rotation and an axial force to the drill 1307. The piercing tube 1301 is flexible to allow a bending while transmitting the torque of rotation and the axial force. The drilling system further comprises a bending guide 1305 with rotation supports 1306 for supporting the drill pipe in bending. The side hole may deviate substantially perpendicular from the main well. The torque of rotation and the axial force can be generated respectively by a motor 1312 and an axial driver 1311. A 1310 blogging system can blog the 1312 motor and the axial 1311 driver into the main 1303 well. The 1312 motor can be electric. A guide mandrel 1304 can be provided to blog the bending guide 1305 into the main well. The guide mandrel may comprise an orientation substitute (not shown) which establishes and allows an azimuth direction of the bending guide to be measured to be drilled in a suitable azimuthal direction. The guide mandrel 1304 can communicate with a control substitute (not shown) located near the motor 1312 using an electrical wiring system (not shown). In this case, particular care must be taken to protect the electrical wiring system of the rotary drilling tube 1301. Alternatively, the guide mandrel 1304 can communicate with the control substitute using a wireless communication system (not shown), such as electromagnetic or acoustic telemetry. A pump (not shown) can ensure a circulation of a drilling fluid in the drilling strings 1301 and in an annular zone between the drilled lateral hole and the drilling string 1301. The bending guide 1305 allows to ensure the substantially perpendicular bending of drilling tube 1301 while transmitting the torque of rotation and the axial force. FIGURE 13B illustrates a cross section of a first example of a flexure system according to the fifth embodiment. A drilling tube 1301 transmits the torque of rotation and the axial force. The rotation supports 1306, for example rollers, allow a relatively easy rotation of the drilling tube 1301.

However, with the first example of a bending system, the piercing tube 1301 is supported by the relatively small contact areas of the rollers. 1306. In a case of a very high axial force, there is a risk that the drill string will deform locally. FIGURE 14A and FIGURE 14B illustrate a second example of a flexure system according to the fifth embodiment of the present invention. FIGURE 14A shows a cross section of the flexure system while FIGURE 14B shows a side view of the flexure system. A drilling tube 1401 is bent between two bending guides (not shown). The drill pipe is in contact with a network of rotation supports, for example bands 1406. The bands 1406 pass over the drilling tube 1401 and a flexible support, for example, a pulley 1407. Such a system of pulleys allows to ensure an orientation suitable for each band 1406. The bands 1406 have a movement following a rotation of the piercing tube 1401. The bands 1406 transmit a reaction force from the piercing tube 1401 to the pulley 1407. Bearings (not shown) can be provided at both ends of the flexible support 1407. The bearings allow the flexible support to be rotated with the rotation of the drill pipe. The bearings can be locked into the main well to withstand the reaction force of drilling tube 1401. The bands 1406 need to be relatively flexible. The webs 1406 may be strings or woven structures attached to the pulley 1407. The second example of the flexure system permits a support of the piercing tube 1401 over a relatively large surface area. Preferably, the drilling system according to the present invention comprises a motor assembly. The motor assembly comprises a motor to generate a torque of rotation, an axial impeller to generate an axial force, a locking system to fix the motor and the axial impeller inside the main well and a transmission shaft to transmit the moment of rotation torsion. The perforation system may allow to removably connect a first connector or a second connector to adapt the transmission of the rotational torque and the axial force for an auger that depends on a desired radius of the hole to be drilled. The first connector can provide a transmission of the axial force only to a drill pipe, the torque of rotation being transmitted to an additional drive shaft placed inside the drill pipe. On the contrary, the second connector can transmit the axial force and the torque of rotation to the drill pipe. Both the first connector and the second connector can provide a fluid communication channel for a circulation of a drilling fluid between the motor assembly and the interior of the drill pipe. The second connector can be located within the main well and the drill pipe can be flexible enough to allow a substantially perpendicular bending while transmitting the torque of rotation and the axial force. The perforation of the side hole can be done substantially substantially in a straight direction from the main well. Alternatively, as shown in FIGURE 13A, the drilling system according to the fifth embodiment of the present invention comprises a simple drilling tube 1301 which transmits a torque of rotation and an axial force from a motor and an axial impeller towards an auger. The motor and the axial impeller can be located inside the main well, or inside a side hole. The drilling system may not allow a first connector or a second connector to be removably connected to adapt the transmission of the rotational torque and the axial force to the auger depending on a desired radius of the side hole to be drilled.

Flow management and cuttings Hole drilling creates cuttings that need to be processed. The prior art systems involve a pump located on a surface that injects a drilling fluid, eg, a drilling mud, through a drilling tool. The drilling fluid reaches an auger of the drilling tool and is evacuated through an annular zone between the drilling tool and the drilled hole. The drilling fluid is viscous enough to carry the cuttings that are created in the auger to the surface. A shale vibratory sieve located on the surface allows to remove the cuttings from the drilling fluid. A metallic cable system, where the pump is located at the bottom of the bore to pump the drilling fluid, the cuts can not reach the surface. There is a need to process the drilling fluid flow and the cutouts in a case of a system with a pump located at the bottom of the borehole. FIGURE 15 illustrates an example of a drilling system according to a sixth embodiment of the present invention. A drilling system comprises a drill string assembly 1503. An auger 1507 drills a side hole 1501 deviation from a main well 1502. A drilling fluid flows into the auger 1507 through an annular zone 1504 between the perforated side hole 1501 and the drill string assembly 1503. The drilling fluid circulates from the auger 1507 to the main well through a fluid communication channel 1506, thereby carrying the cutouts generated in the auger 1507. When the drill string assembly 1503 has a smaller section that A coated tube (not shown) of the main well 1502, the drilling fluid can circulate relatively quickly through the fluid communication channel 1506, which allows to avoid sedimentation of the cuttings due to gravity. The transport of the cut-outs through the fluid communication channel 1506 requires less pumping power than in a conventional circulation where the cut-outs are carried through the annular zone 1504. Furthermore, the fluid communication channel 1506 allows to properly guide the cuts to an additional separation. The perforation of the lateral hole 1501 generates the cuts that are carried through the channel 1506 of fluid communication. It is therefore necessary that the bit 1507 comprises large holes to allow a passage of the cuttings. FIGURE 16 illustrates an example of an auger according to the sixth embodiment of the present invention. The bit 1607 can be in the form of a fishtail. The bit 1607 may comprise a main blade 1601 to ensure a cutting action. The cuttings generated during a drill through the drill 1607 can be evacuated by a circulation of a drilling fluid through a drill hole 1603. The hole 1603 of the bit having a relatively large section to allow the removal of the cuttings through the bit 1607. The bit may further comprise guide vanes 1602 to ensure a lateral guide in the drilled hole and stabilize a direction of the hole. drilling. The main vane 1601 and the guide vane 1602 may comprise cutters 1604. The main vane 1601 may be straight following a diameter of the spike 1607, as shown in FIG.

FIG. 16. Alternatively, the main vane has a curved shape passing through a center of a section of the bit 1607. Alternatively, the bit can comprise a plurality of vanes, where at least one vane crosses the section of the bit. The bit can comprise a central tip (not shown) to stabilize a drilling direction. Preferably, the drilling system according to the present invention comprises a motor assembly. The motor assembly comprises a motor to generate a torque of rotation, an axial impeller to generate an axial force, a locking system to fix the motor and the axial impeller inside the main well and a transmission shaft to transmit the torque of rotation. The drilling system may allow to removably connect a first connector or a second connector to adapt the transmission of the rotational torque and the axial force to a drill bit depending on a desired radius of the hole to be drilled. The first connector can provide a transmission of the axial force only to a drill pipe, the torque of rotation is transmitted to a further transmission shaft placed inside the drill pipe. On the contrary, the second connector can transmit the axial force and the torque of rotation to the drill pipe. Both the first connector and the second connector make it possible to provide the fluid communication channel between the motor assembly and the interior of the drill pipe. FIGURE 17 illustrates an example of a drilling system according to a seventh embodiment of the present invention. A drilling system comprises a drill string assembly 1701. An auger 1707 allows a side hole 1702 to be drilled from a main well 1703. A drilling fluid can flow into the bit 1707 through a fluid communication channel 1708 within the drill string assembly 1701. The drilling fluid is evacuated from the side hole 1702 through an annular zone 1709 between the assembly 1701 drill string and internal walls of the hole 1702 lateral perforated. The drilling fluid is guided in an outlet of the side hole 1702 by a passage 1704 having a predetermined orientation. A sealing device comprising shutters 1705 and sealing cups 1706 can be provided at the outlet of the side hole 1702 to force the drilling fluid to circulate through passage 1704. The passage allows to control the circulation of the drilling fluid once evacuated from the hole 1702 lateral. Typically, the passage 1704 can be oriented downward for further processing of the drilling fluid at the bottom of the well. The drilling fluid can in fact contain clippings generated in bit 1707. FIGURE 18 illustrates schematically an example of a drilling system according to an eighth embodiment of the present invention. A drilling system comprises a drill string assembly 1801. An auger 1807 allows a side hole 1802 to be drilled from a main well 1803. A drilling fluid may flow to the auger 1807 through a fluid communication channel 1808 within the drill string assembly 1801. The drilling fluid is evacuated from the lateral hole 1802 through an annular zone 1809 between the assembly 1801 drill string and internal walls of the hole 1802 lateral perforated. The system further comprises a filter device 1805 for separating cutouts from the drilling fluid. Preferably, the perforation system may comprise a passage 1810 having a predetermined orientation at an outlet of the lateral hole 1802, for guiding the drilling fluid to the filter device 1805. Sealing devices 1811 may be provided to force the drilling fluid through passage 1810. Alternatively, the piercing system does not comprise any sealing devices. The filter device 1805 makes it possible to separate the cuttings from the drilling fluid. The separate cut-outs 1806 can be stored within the filter device 1805, and the drilling fluid can be pumped by a pump 1804 located at the bottom of the bore. The filter device 1805 can be located within the main well, under the side hole, as shown in FIGURE 18 or in any other location located at the bottom of the hole. The filter device can also be located within a drilling machine: in FIGURE 18, an optional filter 1812 is located within the drilling machine 1813 which also comprises the pump 1804. FIGURE 19 illustrates an example of a filter device according to a ninth embodiment of the present invention. The filter device 1901 makes it possible to separate the cuttings from a drilling fluid. A compactor (1903, 1904) within the filter device 1901 makes it possible to regularly provide a compaction of the filtered cuttings (1906, 1905). The compactor (1903; 1904) allows an efficient filling of the filter device 1901. The filter device 1901 therefore needs to be replaced less frequently than a traditional filter device, which is particularly useful if the filter device 1901 is located at the bottom of the borehole. Replacing a filter device located at the bottom of the hole actually takes a lot of time. Furthermore, in the case of a filter device located at the bottom of the borehole, the filter device can have a longitudinal shape that adapts well to a well shape. The compactor can therefore be particularly useful since a natural filling of the cuttings in a longitudinal filter device may not be optimal. The drilling fluid can enter the filter device 1901 through an inlet 1907 of the filter device. The separation of the cuttings from the perforation can be provided by the centrifugation: the filter device can be rotated about a longitudinal axis. A filter device according to a tenth embodiment of the present invention allows the cuttings to be separated from a drilling fluid. FIGURE 19 illustrates such a filter device. An adaptable system (1902, 1909) within the filter device 1901 allows to classify the filtered cuttings (1905, 1906) depending on their size to prevent the filtered cuttings (1905, 1906) from plugging the filter device 1901. In fact it is well known that particles having a regular size distribution allow to provide a filling as efficient as possible in a given container. The adaptive system (1902, 1909) according to the present invention makes it possible to avoid a regular size distribution of the filtered cuttings (1905, 1906) and therefore a clogging of the filter device 1901. The drilling fluid can thus be circulated through the filtered cuttings (1905, 1906) when the filtered cuttings (1905, 1906) are classified as small cutouts 1905 and large cutouts 1906. The adaptive system (1902, 1909) may comprise at least a first static filter device 1902. At least one first static filter device 1902 makes it possible to classify the filtered cuttings (1905.1906): the large cut-outs 1906 are retained in a center of at least one first static filter device 1902. A second static filter device 1909 makes it possible to prevent small cuttings from escaping from the filter device 1901. The filter device illustrated in FIGURE 19 comprises the compactor (1903, 1904) and the static filter devices (1902, 1909). The compactor may therefore comprise a compactor 1904 of large cutouts and a compactor 1903 of small cuttings. The large cutter 1904 and the small cutter 1903 compactor can slide along the longitudinal axis of the filter device 1901. The filter device 1901 can be located within a main well, while the cutouts are generated from a drilling of a side hole diverting a main well. The filter device 1901 of the present invention can be part of a drilling system (not shown in FIGURE 19).

The perforation system may comprise a passage in an exit from the side hole. The passage has a predetermined orientation for forcing the drilling fluid to pass through the filter device 1901. Preferably, the systems according to the seventh embodiment, eighth embodiment, ninth embodiment and tenth embodiment of the present invention are used with or are part of a perforation system according to the first embodiment of the present invention. FIGURE 20 illustrates an example of a drilling system according to an eleventh embodiment of the present invention. The drilling system comprises a drill string 2003 and a 2007 drill bit to drill a 2001 side hole deviation from a 2002 main well. Drilling generates cuts at the 2007 drill. Cuttings are removed from the 2001 side hole. A 2005 container located inside the main well allows to collect the cuttings under the side hole. During a perforation of the lateral hole, the cuttings, when they are evacuated from the side hole, can be left inside the main well. Due to their weight, the cuttings can settle in the main well. The 2004 container allows to collect the abandoned cuttings. The black arrows in the figure represent a circulation of the cuts.

The container 2005 may have a long cylindrical shape to conform to a shape of the main well, or to a shape of a component of the main well, for example, a coated tube. The container may be a filter device according to the ninth embodiment of the present invention. The cuttings fall from the side hole towards the filter device. The container may also be a static filter device that classifies the cuttings of a drilling fluid flow passing through the static filter device. The container may comprise a cut-off collection unit (not shown in FIGURE 20) to ensure efficient filling of the container by the cut-outs. FIGURE 21A illustrates an example of a clip collecting unit according to a twelfth embodiment of the present invention. The scrap collecting unit 2100 comprises a compacting unit 2101 having the shape of a long screw that rotates to take out the cut-outs in a housing 2102. The scrap-collecting unit 2100 is typically used to clean up the cuttings from a well after of a sedimentation of the cuts. In a typical operation, the screw rotates slowly to remove the cuttings slowly and avoid thinning the cuttings. The 2100 pick-up unit can be used after a drilling operation. The 2100 scrap collector unit typically joins a drilling machine. The housing 2102 can be fixed to a non-rotating connection, for example an outer part of a first connector, of the drilling system, so that the drilling machine can push the cut-off collection unit. The screw can be attached to a rotating portion of the drilling machine, for example an internal part of the first connector. The 2100 scrap collector unit has a longitudinal shape to pass through a well pipe. The 2100 scrap collector unit allows the clippings to be collected, where the trimmings are sedimented in a container, as shown in FIGURE 20. The trimmings may alternatively lie directly in a lower part of the well. The screw may have a conical shape near the tip of the housing 2102 to ensure adequate compaction without blocking the rotation of the screw when an upper section of the housing 2102 is full of cutouts. FIGURE 2IB illustrates an example of a drilling system according to the twelfth embodiment of the present invention. The drilling system comprises a drilling machine 2115, a drilling string 2103 and a drill bit 2107 for drilling a side 2114 deviation hole from a main 2111 well. The perforation generates cuttings in the bit 2107. The cuttings are taken out of the side hole 2114 by a drilling fluid. A sealing device 2113 at an outlet of the side hole 2114 forces the drilling fluid to flow down through a passage 2110. The cuttings settle into the main well 2111 and form a bed 2112 of cut-outs. If the main 2111 well is tilted, as depicted in FIGURE 2IB, the bed 2112 of cutouts may lie on one side of the main well 2111. The drill 2115, the drill string 2103, the drill 2107, the sealing device 2113 and the passage 2110 can be removed from the main well 2111 after drilling. A scrap collector unit (not shown in FIGURE 2IB) may subsequently be attached to the 2115 drill bit. The drilling machine 2115 and the attached clip collection unit can be lowered into the main well 2111. The clip collecting unit comprises a compacting unit having the shape of a screw, as shown in FIGURE 21A. The compacting unit is rotated slowly to escape the pellets cut in the bed 2112 from cuttings out of the main well 2111. Preferably, the piercing system according to the twelfth embodiment comprises features of the first embodiment of the present invention, or features of any other embodiment of the present invention. FIGURE 22 illustrates an example of a flow circulation system according to a thirteenth embodiment of the present invention. An auger 2207 at one end of a drilling string 2203 allows drilling a lateral deviation hole 2201 from a main well 2202. A drilling machine 2212 located at the bottom of the bore comprises a pump 2205. The pump 2205 generates a primary circulation flow (represented by the arrows 2208). The flow of primary circulation allows to take the cuts generated in the drill 2207 towards the magneto 2212 of perforation. A surface pump 2204 makes it possible to generate a secondary circulation flow (represented by the arrows 2209) in an annular zone 2210 of the well between a pipe 2207 and the main well 2201. The flow of secondary circulation allows to bring to the surface the cuts carried by the flow of primary circulation. The flow circulation system according to the present invention allows a drilling fluid to be carried with the cuttings to the surface. The processing of the surface drilling fluid is well known from the prior art. The surface pump 2204 distributes a surface fluid in the annular zone 2210 of the well. The shutters 2206 may blog the annular zone at a lower end of the pipe 2207. The distributed surface fluid therefore escapes from the annular zone 2210 of the well through the slide gate valves 2211. The surface fluid of the secondary circulation flow may flow upwardly in line 2207. A large portion of the cutouts carried by the primary circulation flow are lifted by the secondary communication flow to the surface for further processing. The 2205 pump and other drilling tools (not shown) such as a motor can be located in line 2207, near the slide gate valves 2211. Preferably, the pump 2205 is located on the sliding door valve to ensure good mixing of the primary circulation flow and the secondary circulation flow. Alternatively, a hollow member (not shown in FIGURE 22) can extend the primary flow circulation to the sliding gate valves.

The sliding door valves require opening before starting the generation of secondary circulation flow which is typically performed by a sliding cable operation. The surface fluid may be a drilling mud, a determination fluid, a clean fluid, or a fluid having another composition. The surface fluid may have the same composition as the drilling fluid. The primary circulation flow ensures transportation of the cuttings from the auger 2207 to the sliding gate valves to ensure additional lift of the cuttings by the secondary circulation flow. However, the main well 2202 has a section that is usually much larger than a section of the lateral 2201 hole. A primary circulation flow velocity through the main well 2202 is therefore much smaller than a primary circulation flow velocity through the lateral hole 2201. There is a risk that the cuttings transported fall into the main well 2202 due to the effect of gravity. FIGURE 23 illustrates an example of a flow guide according to a fourteenth embodiment of the present invention. The flow guide 2301 allows the primary circulation flow to circulate at a relatively high speed between a side hole 2303 and a pipe 2304 to prevent settling of the cuttings. The cuts are generated in a drill bit of a drilling system (not shown). The flow guide 2301 may extend to a side hole 2303 to ensure that a drilling fluid is forced to flow through the flow guide. The flow guide can be supported by a diverting wedge (not shown), or any other support system. A drill string of the drilling system can pass through the flow guide 2301. The flow guide 2301 can be pushed towards a coated tube of the main well 2302 to limit lateral deformation due to a buckling effect of the drill string. The flow guide can also be sealed at one end, for example, an outlet from the side by a sealing device. The cut-outs can be carried by the primary circulation flow to the sliding door valves for additional lift to the surface by a secondary circulation flow. The secondary circulation flow can be generated by a surface pump located on the surface, as described above. The flow guide can be used within the flow circulation system according to the present invention. Both the flow guide and the flow circulation system can be used in combination with a drilling system to drill a side hole for diverting a main well. Preferably, the piercing system according to the fourteenth embodiment comprises features of the first embodiment of the present invention, or features of any other embodiment of the present invention. By "drilling fluid", any fluid flowing to the bottom of the borehole and allowing the transportation of cuttings is meant. The drilling fluid may contain clippings. The drilling fluid can also be clean. Although the invention has been described with respect to a limited number of embodiments, those skilled in the art, which have the benefit of this disclosure, will appreciate that other embodiments may be visualized which do not depart from the scope of the invention as described in the present. Those skilled in the art will also appreciate that the described modalities can be combined with each other. Accordingly, the scope of the invention should be limited only by the appended claims.

Claims (49)

1. CLAIMS 1. A system for drilling a lateral hole of deviation from a main well, the system comprises: an engine assembly that includes: a motor to generate a torque of rotation; an axial impeller to generate an axial force; a locking system to fix the motor and the axial impeller at the bottom of the hole; a drive shaft to transmit the torque of rotation; and a connector for transmitting the torque of rotation and axial force from the motor assembly to a drill string assembly, the drill string assembly comprises a drill pipe and a drill bit, the connector provides a communication channel of fluid between the motor assembly and the inside inside the drill pipe; where the connector is one of a first connector or a second connector, the first connector can be connected to the drill string assembly to transmit the axial force only to the drill pipe, and to transmit the torque of rotation to a drill shaft. Additional transmission placed inside the drill pipe, and the second connector can be connected to the drill string assembly to transmit the axial force and torque of rotation of the drill pipe.
2. 2. The system of claim 1, wherein the engine is located within the main well. The system of claim 2, further comprising: a drill string assembly, the drill string assembly is connected to the connector, the drill string assembly comprises the drill pipe apart to transmit the axial force; and the additional drive shaft for transmitting the torque of rotation, the additional drive shaft is placed inside the drill pipe; the auger The system of claim 3, wherein: a portion of the side pit comprises a curved pit having a determined radius of curvature; The drill string assembly comprises three contact points that are in contact with a perforated side hole wall, the three contact points define a perforation tube angle to allow the curved hole to be drilled. 5. The system of claim 4, further comprising a thrust bearing for transmitting axial force from the drill pipe to the auger, the auger is located at one end of the additional drive shaft; a plain bearing system to support a flexure of the additional drive shaft within the drill pipe. 6. The system of claim 5, wherein the motor is electric. The system of claim 2, further comprising: the drill string assembly, the drill string assembly is connected to the connector, the drill string assembly comprising the drill pipe apart to transmit the axial force and the torque of rotation; the auger The system of claims 1 or 2, further comprising: at least one stabilizer of variable diameter for positioning the auger within a section of the side hole; the control means for mechanically controlling from a remote location at least one parameter of the stabilizer between a set of stabilizer parameters, the set of stabilizer parameters comprising a diameter size of a stabilizer of determined variable diameter, a distance between a first stabilizer and a marking device within the lateral hole, the marking device is either a different stabilizer or an auger, a coordinated retraction of at least two stabilizers of variable diameter, and an azimuth radius of the stabilizer of a certain variable diameter. 9. The system of claim 8, further comprising a simple control unit for controlling at least one parameter of the stabilizer among the set of parameters of the stabilizer. 10. The system of claim 9, the system comprises: a configuration slot; a configuration key which can be moved by the control means, the configuration key allows to select from a set of adjustment positions (i, j, k, 1, m, n,) in a desired adjustment position; wherein: the set of adjustment positions comprises at least three adjustment positions; each adjustment position corresponds to a determined value of at least one parameter of the stabilizer. 11. The system of claim 10, the system comprises two stabilizers of variable diameter, where the two stabilizers of varying diameter can be established in a coordinated manner. 12. The system of claim 11, further comprising a Hall Effect sensor for measuring a diameter of one of two stabilizers of varying diameter. 13. The system according to any of claims 1 to 12, the system further comprises at least one micro-sensor in a vicinity of the auger, at least one micro-sensor allows a measurement of one orientation of the auger. in relation to a reference address. The system of claims 1,2 or 7, wherein the drill pipe is flexible, to allow flexing while transmitting the torque of rotation and the axial force; The system further comprises: a flexion guide with rotation supports to support the drill pipe in flexion. 15. The system of claim 14, wherein: the rotation supports are bands that are supported by a pulley. 16. The system of claim 2, further comprising: a pump located at the bottom of the bore to pump a drilling fluid. The system of claim 16, wherein: the drilling fluid can flow from the main well to the auger through an annular zone between the perforated side hole and the drill string assembly; The drilling fluid can circulate from the auger to the main well through the fluid communication channel. 18. The system of claim 17, wherein: the auger comprises a drill hole that allows evacuation of cuttings generated in the auger through the auger; the auger comprises a main blade to ensure a cutting action. 19. The system of claim 16, further comprising: a passage located at an outlet of the side hole, the passageway guiding a flow of drilling fluid from the side hole into the main well. 20. The system of claim 19, further comprising: a sealing device for forcing the drilling fluid to circulate through the passage. The system of claim 19 or claim 20, wherein the passage is oriented downwardly. 22. The system of any of claims 16, 19, 20 or 21, further comprising: a filter device for separating the cuttings from the drilling fluid, the filter device being located at the bottom of the drilling. 23. The system of claim 22, further comprising: a compactor within the filter device for regularly providing a compacting of the filtered cuttings. The system of claim 22 or claim 23, further comprising: an adaptive system within the filter device for sorting the filtered cuttings depending on their size to prevent the filtered cuttings from clogging the filter device. 25. The system of any one of claims 16, 19, 20 or 21, which further comprises: a container within the main well for collecting the cuttings under the side hole. 26. The system of any one of claims 16 or 25, further comprising: a clip collecting unit comprising a housing and a screw for removing the cutouts from the housing. 27. The system according to claim 16, which further comprises: a surface pump for generating a secondary circulation flow along a pipe, the secondary circulation flow allows to bring to the surface the cuts generated in the auger and carried by a flow of primary circulation from the auger to the secondary circulation flow. 28. The system according to claim 26, further comprising: a flow guide which allows the flow of primary circulating circulation at a relatively high flow rate between the side hole and the pipe to prevent sedimentation of the cuttings. 29. The system of claim 1, where the motor is located inside the perforated side hole. 30. A method for drilling a lateral hole of diversion of a main well, the method comprises: blogging a motor and an axial impeller at the bottom of the bore, the motor and the axial drives respectively allow to generate a torque of rotation and an axial force, - providing a connector for transmitting the torque of rotation and the axial force from a motor assembly to a drill string assembly, the motor assembly includes the motor, the axial driver and a drive shaft, The drill string assembly includes a drill pipe and auger; where: the connector provides a fluid communication channel between the motor assembly and the interior of the drill pipe; the connector is either a first connector or a second connector, the first connector can be connected to the drill string assembly to transmit the axial force only to the drill pipe, and transmit the torque of rotation to an additional transmission shaft placed inside the drill pipe, and the second connector can be connected to the drill string assembly to transmit the axial force and the torque of rotation to the drill pipe. 31. The method according to claim 30, wherein the motor is located within the main well. 32. The method of claim 31, wherein the drill pipe transmits the axial force and the additional drive shaft transmits the torque of rotation to the drill. 33. The method of claim 32, further comprising controlling an effective radius of a curved pit of the side pit, the control is performed by combining an angled mode with a straight mode, where: during the angled mode, three contact points of the assembly drill string are in contact with a perforated side hole wall to allow drilling the curved hole; and during the straight mode, the following steps are performed: rotating the drill pipe from a first angle; transmit the torque of rotation and the axial force to the bit for a first determined duration; remove the drill string assembly over a certain distance; rotating the drill pipe at a second angle; transmit the torque of rotation and the axial force to the auger for a second determined duration. 34. The method of claim 33, wherein the control is performed by combining the angled mode and the straight mode in a jet mode, the jet mode comprises: providing a jet of fluid to preferably erode a reservoir in a particular direction. 35. The method of claim 31, wherein the drill pipe transmits the torque of rotation and the axial force to the drill. 36. The method according to claim 30 or 31, further comprising: mechanically controlling from a remote location at least one parameter of the stabilizer between a set of stabilizer parameters, the set of stabilizer parameters comprise a diameter size of a stabilizer of a certain variable diameter, a distance between a first stabilizer relative to a marking device, the marking device is either a different stabilizer or an auger, a retraction of at least two stabilizers of variable diameter, and a radius azimuth of the variable diameter stabilizer determined. 37. The method according to claim 36, further comprising: moving a configuration key within a configuration slot, to select a desired adjustment position from a set of adjustment positions (i, j, k, 1, m, n,) which comprise at least three adjustment positions, each adjustment position corresponds to a determined value of at least one parameter of the stabilizer. 38. The method according to claim 30, 31 or 35, wherein: the drill pipe is flexible, to allow bending while transmitting the torque of rotation and the axial force; The drill pipe is supported in bending by a bending guide which comprises rotation supports. 39. The method according to any of claims 30 to 38, the method further comprising monitoring an orientation of the bit relative to at least one reference direction with at least one micro-sensor located in a close environment of the auger. 40. The method according to claim 31, further comprising: generating a circulation of a drilling fluid in the auger with a pump located at the bottom of the bore. 41. The method according to claim 40, wherein: the drilling fluid flows into the auger through an annular zone between the perforated side hole and a drill string assembly; the drilling fluid circulates from the auger through the fluid communication channel. 42. The method according to claim 40, the method further comprising guiding the drilling fluid at an exit from the side hole through a passage having a predetermined orientation. 43. The method according to claim 42, wherein the drilling fluid is guided downwardly. 44. The method according to claim 40, 41, 42 or 43, further comprising filtering drilling fluid cut-outs at the bottom of the bore. 45. The method according to claim 44, further comprising compacting the filtered cuttings within a filter device. 46. The method according to claim 44 or 45, which further comprises classifying the filtered cuttings according to their size to prevent the filtered cuttings from clogging the filter device. 47. The method according to any one of claims 40, 42 or 43, which further comprises collecting the cuttings from the bottom of the perforation at a location under the side hole. 48. The method according to claim 40, which further comprises: generating a secondary circulation flow along a pipeline, the secondary circulation flow allows the cuttings generated in the auger to be brought to the surface and carried by a flow of primary circulation from the auger to the secondary circulation flow. 49. The method of claim 30, wherein the motor is located within the perforated side hole.