RU2405099C2 - Drilling device and borehole sinking method - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: device includes heavy-weight drill pipe (HWDP) serving as carrying part of the main drilling assembly and having on one side the window open outwards, secondary drilling assembly including drill pipe one end of which is connected to HWDP, downhole drilling motor installed on drill pipe, drill bit arranged on the other end of drill pipe and operating from downhole drilling motor. Secondary drill assembly is arranged inside HWDP with possibility of being arranged between the first position when drill bit is left within the limits of window and the second position when drill bit protrudes sideward from the window provided in HWDP wall. Borehole sinking method by using drill device, during which there performed is the main hole, arrangement of drill device at the specified depth in the main hole, opening of secondary assembly; at that, drill bit leaves the first position and is sunken into the formation enveloping the main hole and drills the secondary offshoot with further return of secondary assembly to the second position.

EFFECT: effective drilling of offshoots without interruption of work in order to arrange small bottom hole assembly.

41 cl, 19 dwg

Description

The invention relates to devices and methods applicable to the drilling of side tables in the formation zone surrounding the main wellbore.

Multilateral wells (a collection of small shafts emanating from the main wellbore) are known in drilling practice in recent years and have been used in many fields. The main incentive for this technology is the desire to improve contact with the reservoir while minimizing the total cost of drilling. Also, the advancement of this technology may be motivated by the limited size of the base plate in the case of drilling from offshore platforms. In most cases, the drilling of multilateral wells requires complex work with many tripping operations, which increases the drilling time. The completion of multilateral operations is also a difficult operation, since the junctions of the secondary shafts to the main well determine the quality of side wells and production control methods.

Recently, small side well drilling techniques have been developed with less time loss and less support from the rig. For side-hole drilling, drilling systems using an auxiliary cable have been proposed. Based on these approaches, it is possible to drill a sidetrack without a drill string or coiled tubing as a means of communication with the surface. Examples of such drilling technology are given in patent EP 1559864, and patent applications WO 2004072437 and WO 2004011766. A tool for drilling sidetracks is also used for drilling long perforation holes (usually with a length of up to 1 meter and a diameter of several centimeters).

One example of an existing system is the SCORE 100 tool from Corpro Systems Ltd, which operates from the core assembly of the bottom of the drill string (BHA). The main BHA includes a modified version of the drill collar (UBT), which includes an integrated deflector (deflecting wedge). When the modified drill collar reaches the desired depth in the main trunk, the BHA of small diameter is lowered on the auxiliary cable inside the main drill string. This small BHA has a core sampler and a small drilling engine that drives this sampler, an anchor, a pusher system to provide longitudinal movement (the main parameters are the mechanical penetration speed (MSP) and spring-drill (VNB)), as well as an inflatable packer to direct the flow to the small hydraulic motor. The given system can fix itself inside the drill collar and move forward using the lift, which creates the WNB. Surface pumps create a mud stream that drives the small engine and cleans the small sidetrack. At the beginning of the axial displacement, the end of the small BHA is pushed out of the main BHA using the built-in diverter, and then the drill enters the open hole and into the formation rock. The axis of the sidetrack usually deviates from the axis of the main well by 3-6 degrees. Such a system is capable of drilling small holes up to 100 feet (30 meters) long. Typically, such a system is used to obtain cores. Auxiliary cable and tools provide underground process control, especially regarding regulation of SMEs and VNB. The cable also controls the anchoring of the system on the pipe to allow slow movement along the pipe. When a sidetracking or coring operation is completed, the small BHA is raised to the surface using a cable. Typically, the hole in the drill collar is sealed with an aluminum ball, which can be easily drilled using a small BHA. Patent EP 1247936 describes the remaining details of this technology.

The aim of this invention is to provide a method that can be used for efficient drilling of sidetracks, while avoiding significant interruptions in the work of the rig to accommodate a small BHA.

To achieve this goal, it is proposed to use a drilling device containing a weighted drill pipe (UBT), performing the function of the supporting part of the main assembly for drilling and having on one side a window open outward, a secondary assembly for drilling, including a drill string connected at one end to the UBT, downhole a drill motor mounted on a drill string, a drill bit located at the other end of the drill string and powered by a downhole drill motor, with the secondary drill the arrangement is placed inside the drill collar with the possibility of moving between the first position when the drill bit remains within the window and the second position when the drill bit exits sideways from the window existing in the drill collar wall. Preferably, the device comprises a secondary drill assembly comprising a piston mounted to move along the drill collar, with a drill pipe connected to one end of the piston and placed inside the drill collar, while moving between the first and second positions, the piston moves inside the drill collar. The specified window preferably has an inclined lower part, smoothly extending to the outer surface of the drill collar. Typically, a window is associated with a cutting edge of a drilling tool that is connected to the drill collar in such a way that the orientation of the working edge in the desired direction serves to suit the orientation of the window. The UBT may comprise a sliding cover that is movably mounted between a first position when the window is closed and a second position when the window is open. The device may further comprise an arrangement retraction system configured to move the secondary arrangement from a second position to a first position. The specified window preferably contains a moving seal, designed to pass the drill string when moving the secondary drilling composition in the second position. In addition, the device preferably further comprises a transmission shaft extending inside the drill string and connecting the drill bit to the drill motor. Typically, said drill bit comprises a spindle assembly that acts as a connector between the drill bit and the transmission shaft. Moreover, the specified spindle unit may contain a curved sub, as well as measuring devices. Typically, the piston comprises an exhaust valve that allows fluid to flow through the collar without moving the piston. In this case, the drilling engine may include a controller designed to control the opening of the bypass channel, taking into account the selected engine speed. Advantageously, the drill motor is additionally equipped with a siren connected to a piston and rotor mounted together with a stator and connected to a drill bit. The rotor can be connected to the drill bit by means of a torsion spring. The boring device may further comprise means for translating the rotor into an open position relative to the stator, and typically these means are magnets mounted on the rotor and stator. The drilling device may also further comprise a pressure detector for detecting pressure pulses arising from the operation of the siren and generating a signal, as well as a control system for controlling these secondary signals for drilling. The specified piston may additionally contain a bypass channel, which allows fluid to flow through the UBT without affecting the piston. The drilling device may also further comprise means for adjusting the angular relative position of the rotor and the stator during the movement of the secondary drilling assembly to the second position. Said tuning means are usually a groove on a wall of a drill collar representing a control surface, the groove being adapted to move the rotor finger as the secondary assembly for drilling moves. In addition, the drill collar may include a clamping device, which, when the secondary layout is connected to the drill collar, allows the secondary layout to move forward when the drill collar moves, and detaching the clamping device allows free independent movement of the primary and secondary layout when drilling. Typically, the clamping device comprises rotary clowns acting on the secondary assembly for drilling. The drilling device may also further comprise a means preventing the moment of rotation created during operation of the secondary drilling assembly. As the indicated means, an elongated finger installed with the possibility of exiting the drill string and entering the corresponding groove on the drill collar and / or an extension section mounted above the drilling engine can be used, and an elongated finger installed with the possibility of exiting the drill is placed on this section columns and entries into the corresponding groove on the drill collar, and / or a drill string with a non-circular cross section, installed with the possibility of movement along the seal of the corresponding shape. The boring device can be additionally equipped with a connection point for the secondary layout for drilling the device for attaching the extracting cable, made with the possibility of moving the secondary layout from the second position to the first position, and it may also contain a secondary bypass channel for the piston and a set of valves that allow directing the flow to the drill collar on the back of the piston and move the secondary layout from the second position to the first position. In addition, it may additionally contain a control mechanism that, when turned on, displays a secondary layout from a window in the drill collar. The secondary drilling arrangement is advantageously coupled to the drill collar through articulation. The drill string may be flexible. The secondary arrangement for drilling may include a self-propelled carriage located in the drill collar, while the drill string is connected to the self-propelled carriage at one end to allow the column to pass inside the drill collar, and when the layout moves from the first position to the second position, the carriage inside the drill collar is activated. The primary layout for drilling can be assembled with the possibility of making a window in a cased well to extend the secondary layout for drilling.

To achieve this goal, it is proposed to use the method of drilling a well using a drilling device according to any of the above embodiments, during which the main well is drilled, the drilling device is placed at a given depth in the main well, the secondary layout is opened, and the drill bit leaves the first position and deepens into the reservoir surrounding the main trunk and drills the secondary sidetrack with the subsequent return of the secondary layout to the second position. Typically, the main drilling arrangement is used to drill the main trunk. Most often, UBTs are pushed down, while the secondary layout continues to drill the formation. Typically, when implementing the method, the drill collars are alternately deepened and returned for short distances in the main shaft, while drilling using a secondary drilling arrangement. Preferably, the main well is reinforced with a cased casing followed by a hole in the casing using the main assembly before the secondary arrangement used to drill the formation through the created hole in the casing is put into operation. Typically, the secondary arrangement is used to drill S-shaped sidetracks or to drill spiral sidetracks.

This invention discloses a drilling device consisting of a weighted drill pipe, which is part of the primary drill assembly and having a groove open on one side of the pipe, a secondary drilling arrangement, which consists of a drill string connected at one end to a drill collar, a downhole motor on a drill string , the drill bit at the other end of the drill string, driven by the downhole motor, with the secondary arrangement for drilling mounted on the drill string so that it can t move between the first position when the drill bit remains inside the groove and the second position when the drill bit leaves the groove on one side of the drill collar.

In one preferred embodiment of the invention, the secondary drilling arrangement includes a piston that slides inside the drill collar, a drill string connected to one end of the piston and extending inside the drill collar, so that when the piston moves between the first and second positions, this piston slides inside the drill collar.

Preferably, the groove has a beveled portion that gradually extends to the outer surface of the drill collar. The position of the groove is aligned with the angular orientation of the drilling tool connected to the drill collar, so that the angular orientation of the drilling tool in the desired direction allows you to give the correct orientation of the groove in which the small layout is located. The drill collar may have a movable shutter (cover) that closes the groove in the first position of the system and opens the groove in the second position. The groove may also have a movable sealing element through which the drill string passes when the small bottomhole assembly moves to the second position.

The device may also have a system for diverting the secondary layout from the second to the first position. Preferably, said system has a transmission shaft (transmission shaft) that passes through the drill string and connects the downhole motor to the drill bit. The drill bit in this case has a spindle unit, possibly a curved sub, and an articulation device between the drill bit and the transmission shaft. Measuring instruments, such as sensors for logging while drilling (LWD) or measurements while drilling (MWD), can be placed in the spindle assembly.

The piston, in addition, has an exhaust valve to be able to pass the working fluid through the drill collar without driving the piston.

The downhole motor may have a regulator that controls the opening of the bypass channel according to the selected motor speed. In particular, it is preferable that the engine be equipped with a “siren” that has a stator connected to the piston and a twin rotor connected to the drill bit. In this case, the rotor can be connected to the drill bit through a torsion spring (torsion spring). It is also preferable to provide means, for example magnets, for holding the rotor relative to the stator in the open position.

To register pressure pulses (created by the operation of a hydraulic siren), a pressure detector is installed (as well as to create a signal) and an appropriate control system for directing the operation of the secondary drilling system using a hydraulic signal.

Preferably, the piston has a detour, and in this embodiment, the drilling fluid bypasses the drill collar and does not cause displacement of the piston.

In one embodiment of the invention, means are used to adjust the angular position of the rotor and stator as the secondary arrangement is advanced to a second position within the drill collar. Such tools can be represented by a groove in the body of the UBT, which defines a curved surface along which the rotor slides with a guide finger along the dimensions of the groove; this provides the necessary movement of the secondary layout for drilling.

A controlled clamping mechanism may be present on the drill collar, so that the actuation of the clamp mechanism ensures the joint movement of the drill collar and the secondary layout for drilling, and the release of this clamp allows independent advancement of the primary and secondary (small) layout for drilling. In one embodiment, the clamping mechanism is a pair of eccentric bodies connected to a secondary drilling assembly.

It is also useful to provide means to compensate for the moment of rotation that causes the secondary assembly to drill. Such a device may consist of the following elements: an elongated finger on the drill string, which is included in the corresponding groove on the drill collar; or this is achieved through the use of a drill string with a non-circular cross section; such a column passes through a suitably designed seal.

The secondary drilling arrangement may have a connection point for the guide wire in order to move the secondary drilling arrangement from the second position to the first position.

The bypass channel for the secondary piston and the valve device provides a direct flow of fluid into the drill string under the bottom of the piston to move the secondary assembly for drilling from the second to the first position.

In yet another embodiment, the drilling arrangement has a control mechanism through which the secondary arrangement can be brought out of the window. In this case, the secondary drilling arrangement may be coupled to the drill collar using a swivel joint and the drill string itself may be flexible.

In an alternative embodiment, the secondary arrangement includes a self-propelled carriage moving inside the drill string, a drill string attached to one end of the carriage and passing inside the drill collar; when the bottomhole assembly moves between the first and second positions, the carriage moves along the drill collar.

The secondary arrangement can be arranged as described above, but the main arrangement for drilling is constructed so that it can cut a window in the casing, through which the secondary arrangement for drilling will then be pulled out.

A method of drilling a borehole using a drilling device, as described above, includes drilling the main wellbore, placing the device in the right place on the main bore, the action of the secondary layout for drilling so that moving the drill bit from the first position causes its lateral displacement and penetration into the rock around the main trunk and sidetracking, return of the secondary drilling assembly to the second position (inside the drill collar). The basic drilling arrangement can be used to drill the main trunk. The method may also include advancing the drill collar while the secondary (small) layout is drilling the rock. In one case, this may represent alternate UBT movements back and forth over short distances in the main trunk, while the secondary layout continues to drill the rock.

If the main well has a shell in the form of a casing string, the method includes creating a hole in the casing using the main drilling assembly, even before it becomes necessary to drill using the secondary drilling assembly through this hole.

This invention is based on a combination of a small BHA (secondary downhole assembly) and a large BHA (primary downhole assembly). A large BHA is needed for the drilling operation in the usual way. The large BHA contains all conventional tools and devices, such as rotary-oriented systems or motors, measuring devices during drilling (MWD) or logging while drilling (LWD), etc. The large BHA includes a prepared drill collar with a small BHA inside. In particular, the prepared drill collar is equipped with a groove (window) through which the small BHA leaves the inner channel outside the large BHA. A part of such a groove is a modified deflector.

During sidetracking, a large BHA remains in a quasistatic state. The small BHA has an engine, preferably rotary deflected; while moving forward, formation drilling takes place. With the correct deviation, the small bore can be drilled outgoing from the main well. Drilling is usually carried out in progressive mode. When the lateral trunk is completed, the small BHA is removed inside the large BHA. After that, a large BHA resumes normal activities in the main well, for example, continues drilling to deepen the well.

In a preferred solution, the implementation of this method is based on a mechanical system.

A system with two BHA can also work in a cased well. In this case, the first drill is replaced with a cutter, which makes a window in the casing. After that, the small BHA creates a sidetrack without additional tripping.

There are partial modifications to the basic concept:

- a small BHA can be equipped so that the logging takes place outside the main well;

- various existing methods of working with the collector can be improved and developed through the use of double CBNC;

- various compounds can be used to transfer liquids from the main well to the side well, while the produced fluid flows first into the side well and then flows into the main well. This technique is especially interesting for the case of heavy oil and for special types of processing produced fluid directly in the reservoir.

The following is a description of the drawings used. Figure 1 and figure 2 shows the side wells drilled according to this invention, figure 3 and figure 4 shows a first embodiment of the device according to this invention, figure 5 and figure 6 shows the details of the device depicted in fig. 3 and 4, FIG. 7 shows a second embodiment of the device of this invention, FIG. 8 shows a top view for the siren of FIG. 7, FIG. 9 shows a graph of% of the open area as a function of rotation of the siren of FIG. 7 , figure 10 shows a graph of the% opening of the siren averaged over time as a function of speed rotated i (r / min) of the siren motor shown in FIG. 7, FIG. 11 shows a graph of the time-averaged pressure difference as a function of rotation speed (r / min) of the siren motor shown in FIG. 7, FIG. 12 shows a graph rotation speed as a function of the BSS for various operating curves of the engines, FIG. 13 shows a graph for a modulated signal from time to time for a siren for a third embodiment of the apparatus, FIG. 14 shows a part of a third embodiment of the apparatus, FIG. 15 shows a fourth embodiment of the apparatus as an open With the invention, FIG. 16 shows the operation of the invention according to a preferred method, FIG. 17 shows a fifth embodiment of an apparatus as disclosed in the invention; Fig.18 and Fig.19 show the trajectory drilled by the apparatus disclosed in the invention.

As mentioned earlier, the aim of the present invention is to provide a system for drilling a plurality of small sidetracks 10 from a main well 12 (see FIGS. 1 and 2) without carrying out tripping operations between successive stages of drilling (lateral and / or main).

The length of the lateral boreholes 10 usually lies in the range from 4.5 to 30 meters, while the diameter of the hole lies in the range from 3.8 to 9.0 cm, and the vertical separation 14 between the drilled shafts can be less than 1 m. the boreholes usually have a constant radius of curvature to achieve a direction almost perpendicular to the main well: in this case, the lateral curvature radius is usually from 3 to 15 meters, which leads to a penetration depth of 16 from the main well from 12 to 20 meters (see Figure 1). For other applications, the lateral trajectory may be straight (see Figure 2) with an axis that deviates by 2-7 degrees (18) from the main well 12.

The main (large) BHA is composed of conventional components, the set of which depends on the goal. If you start listing from below, then the BHA includes a drill bit. Further, the layout includes a controlled rotary drilling system or a controlled engine, stabilizers and movable articulation units. Drilling while measuring (MWD) and logging while drilling (LWD) devices can be added if required for drilling applications. A small BHA is placed in a prepared UBT, as shown in FIG. 3.

The double BHA includes the main BHA 20 and the small BHA 22. The main BHA 20 drills the main well 24, while the small BHA 22 drills the sidetracks. Some components of the double BHA already exist directly in the main BHA 20. In particular, the prepared UBT 26 with a side window 28 allows you to push the small BHA 22 out of the main BHA 20 and enter the open hole 24 and into the reservoir 30 away from the main well 24. UBT with window 26 has an external groove 32, which at the bottom of the pipe ends with an inclined surface (or diverter) 34. The orientation angle of the window 28 is usually tied to the MWD device in the main BHA 20, which allows you to get the window in the right direction before drilling shackles trunk.

The small BHA 22 is a continuously operating system that is moved inside the large BHA 20. At its lower point, it is located in the groove 32, which is made in the drill collar 26. The small layout leaves the inside of the large BHA outside through the sealing element 34, which is axially movable direction, and this seal is located in the upper part of the groove 32 made in the drill collar with the window 26. The small BHA 22 includes the following components, counting from the bottom up: the drill bit 36, the downhole motor 38, which drives the drill bit 36 through the extension transmission shaft 39, drill string 40, a system for extending the small BHA 22 from the UBT 26 (in this embodiment, it is a hydraulic piston 42 with a bypass channel 43, but mechanical systems can also be used), a control unit 44 for controlling the operation of the small BHA 22 (this there can be a mechanical or electromechanical control unit), a system that helps, if necessary, remove the small BHA 22 inside the large drill collar 26: for this, a fishing hook 46 is provided so that using the fishing tool it is possible to attach a hook to the logging cable and pull back the small layout (as shown below, other methods are also applicable for this operation), a locking mechanism (not shown) that allows you to close the small BHA 22 inside the large BHA 20 when it is not necessary to drill using the small BHA 22 .

In practice (see Figure 4), while the drilling fluid is pumped through the large BHA 20, the small BHA 22 is pushed forward by the movable piston 426 and the pressure on this piston creates weight on the drill for the small BHA 22. The drill bit 36 in the small BHA 22 is initially shifted from the axis due to the interaction with the inclined surface (diverter) 34. After some movement of the layout, the front end of the small BHA 22 is in the reservoir 30 and it works as a controlled downhole motor in the displacement mode. It moves at an angle and the lateral trajectory leaves the main well 24.

Small BHA 22 has a controllable downhole motor. A drill bit (usually with a diameter in the range of 3.8 to 8.9 cm) is attached via an adapter to a spindle unit 48, similar to that found in conventional small downhole motors. A curved sub is mounted above the spindle assembly 48, so that the engine allows the sidetrack 50 to be drilled in the desired direction. If the curved sub 48 is in the same plane with the main well 24, then a small side well 50 will be drilled in the same plane. With this orientation of the curved sub, the drilling operator should provide only the desired UBT azimuth with window 26 when placing the UBT in the well, then cut the lateral trunk 50 in the same plane.

Above the spindle unit 48 (combined with a curved sub), a drill string 40 is mounted between the motor section 38 and the shaft of the spindle unit 48. The length of this pipe can be up to 30 meters (or longer). Using this elongated pipe, the engine section 38 can remain inside the large BHA 20 and avoid bending loads in the side shaft 50. With this arrangement, the engine 38 is not sensitive to the curvature of the drilled shaft.

The flexible transmission shaft 39 is made flexible (bending) sufficiently to follow the curvature of the drilled hole. In addition, it thus replaces the universal joint between the rotor and the drive shaft of the drill. Such a flexible shaft can be made of a titanium pipe to give flexibility (but with the inevitable fatigue of the material during rotation), as well as to ensure the level of loads from the moment of drilling. The motor 38 also creates a downward force (due to the pressure drop across the downhole motor 38). This force is applied to the elongated flexible shaft 39, and it can lead to an undesirable longitudinal bending of the shaft, which is therefore strengthened using radial bearings (not shown) located along the shaft. A torsion damping system 52 (see FIG. 5) may be required to dampen the torsion resonance that may develop on an elongated flexible shaft 39.

In order to be able to drill along a path with a high curvature, the spindle assembly 48 is made rather short. However, it can accommodate a small housing 56 for accommodating measuring devices (if required).

With such a power system, the sidetrack 50 will be drilled in “sliding mode”. This provides an almost uniform drilling rate. In some cases, it becomes necessary to drill sidetracks 50 almost parallel to the main well 24 (within a deviation of several degrees). In this case, a direct version of the engine can be applied (without bending at node 48). Deviation is achieved due to the inclination angle of the built-in diverter 34.

The elongated motor has a drill pipe 40 between the spindle assembly 48 and the power section 38. The drill pipe 40 typically has a diameter of 3.0 to 6.4 cm. Such a pipe does not rotate, it only transfers weight to the drill (BSS) for the drill bit 36; torque is transmitted through the internal long shaft of the transmission 39. Such a drill string 40 is flexible enough to pass through a curved channel, while maintaining minimal contact with the formation 30. In some applications, such a pipe may be made of titanium or composite material (based on fibers and epoxy matrix) for greater flexibility. You can also consider pipes with an elliptical cross-section for the correct transfer of VLB, as well as to give greater flexibility in the curvature plane.

Obviously, the engine 38 and the drill pipe 40 must have diameters that allow easy movement within the main drill collar 26. If the large BHA 20 has a diameter of 17 cm (6 3/4 inches), then the drill pipe 40 may have a size of 2 3 / 8 to 2 7/8 inches. Other pipe sizes may also be suitable for this purpose.

As can be seen from FIG. 6, the dimensions of the UBT 26 allow the small BHA 22 to extend out of the large BHA 20. This UBT has an external groove 32 that ends at the bottom with an inclined surface (built-in diverter) 34. A small axial hole and a sealing element are made in the upper part of this groove 34, so that a small BHA can pass through them 22. The drill bit 36, the casing for the spindle and the curved sub 48 remain within the groove 32 if the formation 30 is not drilled; while the drill string 40 passes through the zone of the seal 34 UBT with the window 26. The seal 34 may have the simplest form of the holes with a tight fit. This allows the drilling fluid 58 to move inside the drill collar 26 in a lower direction towards a large drill bit (not shown). As an additional feature, a removable plug 60 may be installed in the sealing section 34.

The special surfaces of the spindle unit (or the body of the curved sub) 48 slide along the inclined surface 34, which allows you to push the node 48 out of the drill collar 26 (and also forces the drill bit 36 to enter the rock). Such a process has the advantage of minimal wear on the guide surface. This method of orienting the device is useful from the point of view of the drill for drilling, since the teeth of the drill will not break upon contact with the metal guide surface.

When the small BHA 22 is completely removed, the drill bit 36 remains in the groove 32 inside the drill collar 26, so that it can move in the radial direction. The drill bit is and remains inside the diameter of the main drill collar 26. Therefore, the drill bit has no contact in the rock while the large BHA 20 moves or rotates in the main well 24. The groove 32 on the drill collar has a length of several meters. If the drill string 40 has entered the side well 50, then the large BHA 20 has a margin for longitudinal movement in the main well 24 without the risk of pinching the drill string 40.

According to this concept, the weight on the drill for the small BHA is created through the pressure applied to the sliding piston 42. This piston moves in the bore of the drill collar 26 and is connected to the top of the small BHA 22. The piston 42 has a bypass channel 43 so that the flow of drilling fluid can pass down to a large BHA 20, and the pressure was applied to the piston 42. Depending on the device, the fluid pressure acting on the piston covers an area of 64 to 100 cm ² . Thus, up to 3.45 MPa can develop on the piston 42. This combination creates great power up to 22,000-33,000 Newtons (5,000 to 7,500 pounds per foot). This is quite a lot compared to the usual diameter of a small drill bit (6.3-8.9 cm), since in most cases lower pressure is required.

Estimates for the device described above show that typically about 30% of the total flow will pass through the engine 38 (during the drilling of the side well 50). If the engine 38 is braked, then the pressure drop on the small BHA 22 increases and the flow through the bypass channel 43 of the movable piston 42 increases: this means that the pressure increases and the weight on the drill increases accordingly. This makes controlling the small BHA 22 potentially difficult during braking, when the weight on the drill even increases slightly, further blocking the drill and maintaining the braking state. To avoid this situation, a flow control valve is installed on the movable piston to ensure that the weight on the drill is reduced when the engine speed drops (or in braking mode).

Figure 7 shows part of a particularly preferred embodiment of the power section according to this invention. The engine 38 is represented by a downhole screw motor, which is used in drilling. The rotor of this engine (not shown) rotates a rotary valve 62, consisting of a rotor 64 and a stator 66, which makes up a device like a siren, which is widely used to transmit information in telemetry systems during measurement during drilling. This rotary valve 62 is located in the bypass channel 70, which is connected to the valve 42 and on which the stator 66 is fixed. It controls the pressure drop across the valve 42 through flow control, which is allowed to pass through the bypass channel 70. The pressure applied to the surface of the movable piston 42, creates weight on the drill for the small BHA 22. The rotor 64 of the siren (valve) 62 is connected to the motor 38 through a torsion spring 68. Next, the rotor 64 and the stator 66 of the siren 62 are equipped with magnets 72, 74 (see Fig. 8), which help to hold siren more open - holding magnets the rotor blades 64 are in phase with the stator blades 66, and do not block the passage openings of the stator 66. When the motor 38 rotates at a constant speed, the siren rotor 64 has a non-uniform rotation (see Fig. 9), since it is mainly in the open position. In particular, when the engine 38 does not rotate, then the siren 62 is open (due to the torsion of the mating spring 68).

Due to this principle of operation, the average time through passage of the siren 62 is from 100% - when there is no rotation - to almost 50% at high rotation speeds (see Figure 10). The flow switching frequency is usually from 10 to 75 Hz. It is preferable to have a higher switching frequency of the flow in order to facilitate time averaging for the weight per drill (due to the inertia of the small BHA).

The “time-averaged” pressure drop across the siren 62 changes with the engine speed, as shown in FIG. 11. It can be adjusted using the mechanical parameters of siren 62 (spring stiffness 68, rotor mass 64, magnets strength, etc.). Figure 10 shows that a decrease in the average hole area (i.e., at a higher rotational speed of the motor and rotor) leads to a higher weight per drill (Figure 11).

To affect the weight on the drill, it is possible to reduce the rotational speed of the engine 38. If the revolutions are reduced, then the siren 62 will automatically lower the weight on the drill (Figs. 10 and 11) so as to achieve equilibrium at which the engine continues to operate at a suitable rotational speed. If the engine is close to the jam mode (full braking), then the rotation speed will be very low, and therefore the siren reopens and dramatically reduces the weight on the drill. In conclusion, the engine will have an operating point defined by a normal motor curve (rpm as a function of flow rate). The change in rotation speed will also depend on the characteristics of the drill and rock properties.

The combination of a motor curve and a control function is illustrated by two situations depicted in FIG. As you can see, the control curve shows that the weight on the drill still exists, even when the rotation speed drops to zero (at the point of slow rotation at high engine loads). This is due to the fact that the fluid pressure still acts on part of the movable sealing element in the drill collar, which pushes the downhole assembly forward. The control functional curve should be as horizontal as possible, since the controlled area of the siren should be large compared to the area of the movable seal. In addition, the pressure pulse generated by the siren 62 should be large compared to the pressure drop at the small BHA (where the small motor and small drill) 22. For example, if for the small BHA 22 the pressure drop is of the order of 3.5 MPa, then the pressure pulse the siren will be 7 MPa. The ratio of the working area of the siren to the area of the movable sealing element can be 2, which together provides a fourfold ratio of forces during operation of the device.

If the engine is blocked at the point of complete deceleration without being released using the weight control system on the drill, it is usually sufficient to withdraw the small BHA 22 from the bottom of the well and then engine 38 will restart as described below.

Another approach to control the drilling system is to use a centrifugal regulator. The motor 38 has a drive device for the centrifugal controller through the upper part, which is connected to the input of the bypass channel. At high speeds, the controller closes the flow through the bypass channel, which increases the pressure drop across the movable piston 42, thereby increasing the load on the drill, which has the effect of decreasing speed. The opposite effect occurs when the engine speed decreases: the centrifugal regulator opens the valve more, which reduces the pressure drop on the piston and thereby reduces the weight on the drill. Reducing the BSS allows you to raise the engine speed to reach an equilibrium point on the working curve.

Both variants of regulatory systems are self-adjusting and do not require human intervention.

The weight on the drill can also be adjusted using the clamping mechanism in the large BHA 20, which can command to clamp the small BHA 22. In this configuration, the large BHA 20 can push the small BHA 22 forward from 1 to 2 meters. This is achieved by the fact that the clamping mechanism only works when moving down, when the large BHA 20 moves down, it captures the small BHA 22, and both layouts 20 and 22 continue to move together. After a joint step of 1-2 meters (usually) the large BHA 20 moves upward by 1-2 meters, while on the way up the clamping device releases the small BHA 22. The small BHA 22 remains at a depth (usually with a drill in the lower part), thanks to fluid pressure in the engine. When the large BHA 20 is lifted to the desired distance (1 or 2 meters), it again moves downward already with the small BHA attached to it 22. With this arrangement, the large BHA 20 should move down and up in small steps (usually 1-2 meters). With each downward movement of such an arrangement, the small BHA 22 moves down.

The clamping system can be turned off through the control unit to allow the small BHA 22 to retract into the large BHA 20 at the end of the drilling operation.

The clamping system can be executed in the form of two eccentrics. Such eccentrics have a smoothed contact area to avoid local deformation.

When drilling is in displacement mode, it is important that the engine 38 operates at the correct speed. To solve this problem, it can apply modulation of the acoustic signal through the drilling fluid using sirens. The frequency of the modulated signal is directly proportional to the speed of the motor. This signal is read on the surface and its frequency is a measure of engine speed. If this signal indicates that the engine is not operating optimally, then the operator can take the necessary measures.

The siren used to control the weight on the drill can play the role of a signal generator on the surface, or an additional siren is installed for the entire stream or for part of the stream (for example, the stream through the engine).

It is also important to determine the penetration depth when drilling in a side well. Depending on the control system, such information may be obtained. For example, if the cable for downhole operations is connected to the top of the small BHA 22 during sidetracking, then the side penetration is determined through the movement of the cable. Another way is to change the angular position of the siren stator in the VNB control system by an angle corresponding to 180 ° signal modulation (this corresponds to half the angular distance between two adjacent blades). This shift will manifest itself as a sharp change in the shift of the signal X on the graph of the signal from time to time (Fig.13). This angular shift can be obtained by changing the path of the groove 76 in the main drill collar 26 along which the finger 78 slides, compensating for the force from the torque, and the groove 76 defines the control surface. The finger groove 76 is composed of straight segments, for example, 15 cm long, connected by angular segments that offset the groove by the desired distance 80 and provide the desired angular displacement of the stator, i.e. the signal (Fig. 14). Thus, peaks X will appear for every 15 cm (0.5 ft) of passage of the small BHA 22. There may be a need to make a mechanical phase shift, alternately to the right and left, to avoid large mechanical rotation of the system.

There is an additional way to note the fact when a small BHA reaches its final point of movement. The simplest method is to arrange in a certain place a gap between the piston and the hole through which the piston moves. When the piston reaches the gap, the pressure drop across the piston decreases sharply, this fact can be observed from the surface. Such a piston can be brought into operation by a small displacement of a large BHA (for example, 30 cm) in the lower direction, which should restore the working value of the pressure drop across the piston. Through the subsequent movement of the system, the operator on the surface knows about the end of the piston stroke length.

Depending on the device, the piston stroke length may be less than the length of the drill collar (for example, 10 m) or up to 30 meters or more.

The sliding piston 42 may contain a solid piston that moves along the inner channel of the main drill collar 26. It may have a rubber seal, such as an packing or packing ring, or the piston is inserted into a cylindrical channel with a small gap, such a small gap acts as a throttle flow (because the gap is a differential pressure). For greater flexibility, a rubber sleeve can be worn on the piston, which moves along a cylindrical bore. Such a rubber cuff should fit the narrowing of the diameter in the connecting section between the drill collars. Such a system provides better sealing and potentially greater weight on the drill, since the rubber cuff can be adjusted to the diameter of the large hole at a time when the cuff is outside the joint area of the drill collar.

The downhole motor 38 creates a torque for drilling using the small BHA 22. Therefore, it is obviously necessary to transfer the reactive torque to the main drill collar 26, while pursuing the goal of longitudinal movement of the small BHA 22 inside the large BHA 20. For this purpose, three main systems:

- The drill string 40 is equipped with a thumb, which moves along the groove of the guide system of the main drill collar 26.

- Above the downhole motor 38 attach a small pipe. This pipe has a length equivalent to the drill string 40 (or the maximum drilling depth of the small BHA 22). This additional pipe moves longitudinally together with the small BHA 22 inside the cylindrical hole of the main drill collar 26. This pipe has a guide groove for the finger along the entire length. The finger is attached to the main drill collar 26 in a place immediately above the engine 38 (when it is removed inside the main drill collar 26).

- Drill string 40 elliptical in shape. This elliptical shape slides along the equivalent guiding system of the main drill collar 26. This device allows you to transfer the moment from the small BHA 22 to the main drill collar 26. Sealing between the elements is possible because both ellipses are well defined.

When the small BHA 22 is completely removed, then the flow driving the motor 38 should be stopped. This is achieved using the sealing system at the top of the small BHA 22 — when the BHA is removed, the sealing block sits on top of the flow channel connected to the small BHA 22, locking the stream.

It is necessary that the small BHA 22 be completely removed inside the large BHA 20. For this, the use of several systems is possible.

One system is based on the use of a cable for downhole operations as a fishing tool. The cable for downhole operations is lowered into the drill string, the fishing tool captures the hook 46 located at the top of the movable piston 42 (see Figure 3). Then the cable is pulled upward, which allows the small BHA to be pulled inside the large BHA 20. After complete retraction, the fishing tool is released and the cable for downhole operations is removed from the drill string. The cable for downhole operations can be left connected to the small BHA 22 during the entire drilling of the small sidetrack.

Another solution for moving the BHA can be to use a pressure differential that creates vertical force and helps remove the small BHA 22. Such a system is shown in FIG. With this arrangement, the flow through the nozzle of the "weight per bit" 42 piston can be reversed depending on the position of the shutter 82. If the shutter 82 is open, then part of the drilling fluid flows through the cross section of the downhole motor 84 (and causes the drill bit 36 to rotate). The main flow goes to the large BHA 20 through the primary and secondary bypass ports 86, 88. This flow creates a pressure difference on the piston 42 (creating weight on the bit), and this piston moves forward (and pushes the bit 36 down). The damper 82 can open / close through the control unit 44. When the damper 82 is closed, a small flow will move upward through the connection 90. This flow then goes upward through the secondary bypass channel 88 and finally flows down through section 84 of the engine 38 and through the bit 36 ; however, such a flow is very small. Most of the flow creates a pressure drop across the large BHA 20. This pressure creates an upward force directed at the movable piston 42, so that the small BHA 22 is pulled inward by the large BHA 20.

The opposite effect can be even stronger if you use a double damper system - the second part of the damper (not shown) allows you to close the flow through the primary bypass 86. Two damper are always in opposite states (one open, the other closed).

In this invention, several approaches can be used for the control process. In one method, the wire rope for downhole operations is used to control the latch and the flap valve 82. At the beginning of the entire operation, the wire rope for downhole operations is pulled in the desired sequence to open the small BHA and switch the flap valve 82. At the end of the operation, the same cable is used to retract small BHA 22 and switch the flap valve 82 to the previous position, and also re-snap the small BHA 22 inside the large BHA 20.

In another embodiment, the control unit 44 can be built on hydraulic and mechanical commands. Various approaches can be applied:

- A sliding mandrel with a mechanism on a J-shaped slot, in which the up-down movement is conjugated in rotation.

- A sliding mandrel under pressure, and its movement does not require that the flow of drilling fluid is established first.

- Rotation in order to provide traction for the sleeve with support. Rotation is only achieved if the hydraulic fluid of the drilling fluid has transmitted control signals in the desired sequence.

- Settings for the operating mode of the bit through varying the flow rate. Typically, this scheme is used when starting a stream. For example, when switching from the “zero flow” mode to the “strong flow” mode and then “moderate flow” (or another sequence of flows) with a certain time frame, it is possible to transmit a signal to the system to start drilling a side well or stop drilling.

With such a control system, it is easy to find out about the state of the small BHA 22 — it is necessary to determine whether the layout is in the retracted and closed state or whether it is free for the drilling operation. The main advantage of the hydraulic-mechanical control system is simplicity in arrangement, maintenance and operation.

It is also possible to use electrical control systems. They can be based on two-way telemetry for installations and monitoring. The electrical control system is controlled through an electric wireline cable. This provides greater flexibility and a high data transfer rate, which is especially valuable when measurements are carried out in parallel with sidetrack drilling.

Sidetracking takes some time (from several minutes to 1 hour). At this time, a large BHA 20 may remain in static mode. This is quite dangerous, since the risk of sticking the drill pipe is quite high. To minimize this risk, the system is designed so that the large BHA 20 moves continuously in the main well 24. The large BHA 20 can move up to position 20A and down to 20 V for a short distance (usually several meters). This movement is possible due to the external window 32 on the UBT26. While the small BHA 22 does not need lateral extension by means of the deflecting plate 34 (when the rock 30 is fully inserted), the large BHA 20 can slowly continue to move downward, since the bit 36 has already received the direction of movement in the side well 50. Of course, the movement of the large BHA 20 in the lower direction it is limited by the upper end of the window 32. Note that if the side wall of the window in the drill collar 32 is made free, then the large BHA 20 can also slightly rotate left and right (usually 45 degrees). In this case, the drilling fluid flows through the bit of a large BHA (not shown), therefore, good circulation is provided along the entire length of the main well 24. It also plays a positive role in reducing the risk of pipe sticking in the side well. This circulation is also needed to raise the sludge generated during sidetracking.

As for the small sidetrack, there must be maintained at the right level the rate of circulation of drilling fluid in order to remove drill cuttings up to the point of entry into the main well. The small BHA can also move up and down to clean the bore and to reduce the risk of sticking a drill pipe in a side well.

If a small BHA is stuck in a side well, then a large BHA can be pulled up to rotate a small BHA at the junction of the main and side wells. This allows you to free up a large BHA and reduce the risk of losses.

The small BHA can be combined with various types of measurements (such as measuring the direction and inclination of the BHA, local rock resistance, cross-hole conductivity, sound measurements between wells, etc.).

For some modifications of the device, the small BHA can be raised using a cable passed through the main drill string. Fishing cap 60 (Fig.6) around the bottom of the small BHA allows you to catch all the components (from the bit to the valves). The ability to carry out fishing operations for a small BHA allows you to replace a broken layout or open a window for installing other tools in a side well. These optional tools may be mechanical or electrical. These tools are delivered using a cable or cable. Some of the standard tools allow for technical intervention in the sidetrack (placement of elements of a simplified completion option) or sidetracking using geophysical instruments of the desired diameter.

17 shows another embodiment of the invention with a simplified device. The small BHA 90 is embedded in the outer groove 92 of the UBT 94 and has a connection through the hinge device 96. The small BHA 90 is also a flexible design. When it becomes necessary to drill a sidetrack, the mechanical control mechanism 98 pushes the front part of the small BHA 90 to the side. At the same time, drilling fluid is fed to the small engine 100. As the small BHA 90 begins to enter the rock, the main BHA 102 continues to move forward slowly. which facilitates the penetration of small BHA 90 into the rock. If the small BHA 90 has a curved sub, then the lateral well goes deep into the main well.

Another embodiment of the invention is the use of a self-propelled carriage or tube tractor inside a large BHA to promote a small BHA. Such a system is controlled via a cable inside the main drill string. The control device is directed towards the small BHA. Such a system works in a wide range, since it provides movement over long distances. As an alternative to the electrical control unit, it can also work on MWD (combined with drilling) technologies or on directional drilling technologies. When a cable is used, the cable (and optionally the control unit) is lowered before drilling the side well and raised after completion of the operation.

The above options for dual BHA systems can also be used in cased wells. In this application, it is advisable to replace the bit in the large BHA with a cutter to create a window in the wall (a diverter is also needed).

Another embodiment of the invention is represented by two small BHAs, one bearing a milling cutter and the other carrying a drill bit. The installation of the control unit is somewhat more complicated, since it is necessary to provide a separate start for each small layout. In fact, such a system has potentially three different drills:

a) both small BHAs removed, drilling / milling with a large BHA;

b) the upper small BHA in drilling mode, and the lower is removed;

c) the upper small BHA is removed, the lower small BHA operates in the milling mode.

The lateral shaft may be drilled with a more complex shape than shown in FIG. 1 and FIG. 2. In this embodiment, this is achieved mechanically, for example, through a special shape of the groove, which guides the finger to work out the torque.

For some field applications, an S-shaped sidetrack may be required, as shown in FIG. Such geometry means that the lower end of the sidetrack will be practically parallel to the main well 106. To obtain such a trajectory, the working edge of the small BHA must be rotated 180 ° in the middle of the trajectory. The reaction of the downhole motor is transmitted to the drill collar through the upper torque transmission element and the finger groove makes a 180 ° spiral along the collar. When a finger from the “reaction” element reaches this position, this forces the small BHA to make a half turn. Preferably, the pitch of the spiral was extended to a distance of several meters to avoid unnecessarily twisting the curved sub in the other extreme position of the small BHA.

For other applications, it may be useful to drill a side well 108 in the form of a corkscrew around the main well 106, as shown in FIG. 19. To obtain such a geometry, the azimuth of the curved sub should be constantly adjusted to remove the engine from the current plane. To achieve such a setting on the cutting edge of the tool, the groove along which the finger slides to transmit the moment of “reaction” must have the desired spiral shape. For example, a side well may be drilled on a “cylindrical surface” with a radius of 5 meters and a pitch of 15 meters. This means that the lateral well is inclined to the main one by 45 degrees. Each complete rotation occurs after moving 21 meters and the side wells make two turns.

Claims (41)

1. A drilling device comprising a weighted drill pipe (UBT), performing the function of the bearing part of the main assembly for drilling and having on one side a window open to the outside, a secondary assembly for drilling, including a drill string, connected at one end to the drill collar, a downhole drill motor, mounted on the drill string, a drill bit located at the other end of the drill string and operating from a downhole drill motor, characterized in that the secondary drilling arrangement is placed inside the drill collar with possible awn movable between a first position where the drill bit is within the window, and a second position when the drill bit exits laterally from the window in the wall of the existing drill collar. 2. The drilling device according to claim 1, characterized in that it comprises a secondary drilling assembly comprising a piston mounted to move along the drill collar, with a drill pipe connected to one end of the piston and placed inside the drill collar, while moving between the first and In the second position, the piston moves inside the drill collar. 3. The drilling device according to claim 1, characterized in that the window has an inclined lower part that smoothly extends to the outer surface of the drill collar. 4. The drilling device according to claim 1, characterized in that the window corresponds to the cutting edge of the drilling tool, which is connected to the drill collar, so that the orientation of the working edge in the right direction serves for the corresponding orientation of the window. 5. The drilling device according to claim 1, characterized in that the drill collar contains a sliding cover that is mounted to move between the first position when the window is closed and the second position when the window is open. 6. The drilling device according to claim 1, characterized in that it further comprises a retraction arrangement arranged to move the secondary arrangement from a second position to a first position. 7. The drilling device according to claim 1, characterized in that the window contains a moving seal designed to pass the drill string when moving the secondary drilling assembly to a second position. 8. The drilling device according to claim 1, characterized in that it further comprises a gear shaft extending inside the drill string and connecting the drill bit to the drill motor. 9. The drill device according to claim 1, characterized in that said drill bit contains a spindle assembly that acts as a connector between the drill bit and the transmission shaft. 10. The drilling device according to claim 9, characterized in that the spindle assembly comprises a curved sub. 11. The drilling device according to claim 9, characterized in that the spindle assembly also includes measuring devices. 12. The drilling device according to claim 1, characterized in that the piston contains an exhaust valve that allows fluid to pass through the drill collar without moving the piston. 13. The drilling device according to claim 12, characterized in that the drilling motor comprises a regulator for controlling the opening of the bypass channel, taking into account the selected engine rotation speed. 14. The drilling device according to claim 1, characterized in that the drilling engine is additionally equipped with a siren connected to a piston and a rotor installed together with the stator and connected to the drill bit. 15. The drilling device according to 14, characterized in that the rotor is connected to the drill bit by means of a torsion spring. 16. The drilling device according to 14, characterized in that it further comprises means for translating the rotor into the open position relative to the stator. 17. The drilling device according to clause 16, characterized in that said means are magnets mounted on the rotor and stator. 18. The drilling device according to claim 14, characterized in that it further comprises a pressure detector for detecting pressure pulses arising from the operation of the siren and generating a signal, as well as a control system for controlling these secondary signals for drilling. 19. The drilling device according to claim 1, characterized in that the piston contains a bypass channel that allows fluid to flow through the drill collar without affecting the piston. 20. The drilling device according to 14, characterized in that it further comprises means for adjusting the angular mutual position of the rotor and stator in the process of moving the secondary layout for drilling to the second position. 21. The drilling device according to claim 20, characterized in that said means comprise a groove on the wall of the drill collar representing a control surface, wherein the groove is adapted to move the rotor finger as the secondary assembly for drilling moves. 22. The drill device according to claim 1, characterized in that the drill collar comprises a clamping device, which, when the secondary assembly is connected to the drill collar, allows the secondary assembly to move forward when the drill collar moves, and detaching the clamping device allows free independent movement of the primary and secondary assemblies during drilling. 23. The drilling device according to item 22, wherein the clamping device contains a rotary cam, acting on the secondary layout for drilling. 24. The drilling device according to claim 1, additionally containing a means that prevents the moment of rotation created by the secondary layout for drilling. 25. The drilling device according to paragraph 24, wherein said tool includes an elongated finger installed with the ability to exit the drill string and enter the corresponding groove on the drill collar. 26. The drilling device according to paragraph 24, wherein said tool is an extension section mounted above the drill motor, an extended finger mounted on this section that can exit the drill string and enter the corresponding groove on the drill collar. 27. The drilling device according to paragraph 24, wherein said tool comprises a drill string with a non-circular cross section, mounted to move along the seal of the corresponding shape. 28. The drilling device according to claim 1, characterized in that it is additionally equipped with a connection point to the secondary layout for drilling a device for attaching an extracting cable configured to move the secondary layout from the second position to the first position. 29. The drilling device according to claim 1, characterized in that it contains a secondary bypass channel for the piston and a set of valves that allows you to direct the flow to the drill collar from the back of the piston and moving the secondary layout from the second position to the first position. 30. The drilling device according to claim 1, characterized in that it further comprises a control mechanism that, when turned on, displays a secondary layout from a window in the drill collar. 31. The drilling device according to claim 30, characterized in that the secondary drilling arrangement is connected to the drill collar by means of a swivel joint. 32. The drilling device according to claim 30, wherein the drill string is flexible. 33. The drilling device according to claim 1, characterized in that the secondary arrangement for drilling comprises a self-propelled carriage located in the drill collar, while the drill string is connected to the self-propelled carriage at one end to allow the column to pass inside the drill collar, and when the layout is transferred from the first position in the second position, the carriage is activated inside the drill collar. 34. The drilling device according to claim 1, characterized in that the primary layout for drilling is assembled with the possibility of making a window in a cased well to extend the secondary layout for drilling. 35. The method of drilling a well using the drilling device according to claim 1, during which the main well is drilled, the drilling device is placed at a predetermined depth in the main well, the secondary assembly is opened, the drill bit leaving the first position and deepening into the formation surrounding the main trunk, and drills the secondary sidetrack, with the subsequent return of the secondary layout to the second position. 36. The method according to clause 35, wherein the main layout for drilling is used for drilling the main trunk. 37. The method according to clause 35, wherein the UBT advance downward and the secondary layout continues drilling the formation. 38. The method according to clause 37, wherein alternately deepening and returning movements of the drill collar over short distances in the main shaft are carried out while drilling using a secondary drilling arrangement. 39. The method according to clause 35, wherein the main well is reinforced with a cased casing, followed by creating a hole in the casing using the main layout before putting into operation the secondary layout used to drill the formation through the created hole in the casing. 40. The method according to clause 35, wherein the secondary layout is used for drilling S-shaped sidetracks. 41. The method according to p. 35, characterized in that they use the secondary layout for drilling lateral shafts of a spiral shape.

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