BR112020005790B1 - METHOD FOR PERFORMING A DOWNWELL OPERATION AND DOWNLINK ACTIVATED SYSTEM FOR PERFORMING A DOWNWELL OPERATION - Google Patents

Abstract

The present invention relates to systems and methods for carrying out downhole operations in an exploration well comprising moving, with the use of surface equipment, an internal structure and an external structure within the exploration well, the external structure equipped with an interaction device and the inner structure configured to be moved relative to the outer structure in a direction parallel to the exploration well by the surface equipment; transmitting, by a transmitter, a downlink instruction to the internal structure; and executing an interaction routine with the interaction device in response to the downlink instruction, the interaction routine comprising an interaction at least partially outside the external structure to perform the downhole operation.

Description

CROSS REFERENCE TO RELATED DEPOSIT ORDERS

[0001] This application claims the benefit of application No. US 15/715298, filed on September 26, 2017, which is incorporated into the present invention by reference, in its entirety.

BACKGROUND 1. Field of invention

[0002] The present invention generally relates to downhole operations and downlink activation of components used in downhole operations.

2. Description of the related technique

[0003] Exploration wells are drilled deep into the earth for many applications such as carbon dioxide sequestration, geothermal production, and hydrocarbon exploration and production. In all applications, exploration wells are drilled so that they pass through or allow access to a material (e.g., a gas or fluid) contained in a formation lying below the surface of the earth. Different types of tools and instruments can be arranged in exploration wells to perform different tasks and measurements.

[0004] In general, completion equipment, such as liner hangers (casing pipes), are hydraulically activated within the exploration well. A work string containing a liner seating tool includes a pack-off well zone plug to isolate a liner hanger activation port and a ball seat. A ball is released until it reaches the bottom of the well and the pump pressure is transferred to the liner hanger activation piston. The activation piston thus engages the liner hanger with a liner. The present invention provides improvements to downhole activation components, such as activation of liner hangers.

SUMMARY

[0005] In the present disclosure, systems and methods are presented for carrying out downhole operations in an exploration well, the methods comprising the steps of: moving, with the use of surface equipment, an internal structure and an external structure within the exploration well, the external structure equipped with an interaction device and the internal structure configured to be moved relative to the external structure in a direction parallel to the exploration well by the surface equipment; transmitting, by a transmitter, a downlink instruction to the internal structure; and executing an interaction routine with the interaction device in response to the downlink instruction, the interaction routine comprising an interaction at least partially outside the external structure to perform the downhole operation.

BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The subject matter, which is considered to be the invention, is particularly described and distinctly claimed in the claims at the end of this specification. The foregoing and other features and advantages of the invention will be evident from the following detailed description taken in conjunction with the attached drawings, with similar elements being numbered in a similar manner, wherein:

[0007] Figure 1 is an example of a system for performing downhole operations that may employ embodiments of the present disclosure;

[0008] Figure 2 is a line diagram of an example drill string that includes an inner string and an outer string, wherein the inner string is connected to a first location of the outer string to drill a hole of a first size which may employ embodiments of the present disclosure;

[0009] Figure 3 is a schematic illustration of a downhole system that has an internal structure that is movable relative to an external structure that can employ embodiments of the present disclosure;

[0010] Figure 4A is a schematic illustration of a downhole system in accordance with an embodiment of the present disclosure;

[0011] Figure 4B is a schematic illustration of the system of Figure 4A that shows a first stage of operation of the system;

[0012] Figure 4C is a schematic illustration of the system of Figure 4A that shows a second stage of operation of the system;

[0013] Figure 4D is a schematic illustration of the system of Figure 4A that shows a third stage of operation of the system;

[0014] Figure 5A is a schematic illustration of an internal structure of a system according to an embodiment of the present disclosure;

[0015] Figure 5B is a schematic illustration of the internal structure shown in Figure 5A as being housed within an external structure, in accordance with an embodiment of the present disclosure;

[0016] Figure 6A is a schematic illustration of an activation section of an internal structure according to an embodiment of the present disclosure, in a disengaged state;

[0017] Figure 6B is a schematic illustration of the activation section of Figure 6A in an engaged state and illustrating a transition from the disengaged state to the engaged state;

[0018] Figure 6C is a schematic illustration of the activation section of Figure 6A in an engaged state and illustrating a transition from the engaged state to the disengaged state;

[0019] Figure 7A is a first view of a valve section of an internal structure according to an embodiment of the present disclosure;

[0020] Figure 7B is a second view of the valve section of Figure 7A; It is

[0021] Figure 8 is a flow process for performing a downhole operation in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

[0022] Figure 1 shows a schematic diagram of a system for performing downhole operations. As shown, the system is a drilling system 10 that includes a drill string 20 that has a drill assembly 90, also called a "bottom hole assembly" (BHA), carried in a exploration well 26 that penetrates an earth formation 60. The drilling system 10 includes a conventional drilling derrick 11 standing on a floor 12 that supports a turntable 14 that is rotated by a driving unit, such as an electric motor (not shown), at a desired rotational speed. The drill string 20 includes a drill tubular 22, such as a drill pipe, extending downwardly from the turntable 14 in the exploration well 26. A disintegration tool 50, such as a drill bit attached to the end of the drill string 20. BHA 90, disintegrates geological formations when it is rotated to drill the exploration well 26. The drill string 20 is coupled to surface equipment, such as lifting, rotating and/or pushing systems, including, but not limited to, , a winch 30 through a kelly joint 21, injection head 28 and cable 29 through a pulley 23. In some embodiments, the surface equipment may include a top drive (not shown). During drilling operations, the winch 30 is operated to control the weight on the bit, which affects the rate of penetration. The operation of winch 30 is well known in the art and will therefore not be described in detail here.

[0023] During drilling operations, a suitable drilling fluid 31 (also called "mud") supplied by a mud source or tank 32 is circulated under pressure through the drill string 20 by a mud pump 34. Drilling fluid 31 passes into drill string 20 through a pressure surge damper 36, fluid line 38 and kelly joint 21. Drilling fluid 31 is discharged into the bottom of the exploration well 51 through a opening in the disintegration tool 50. Drilling fluid 31 circulates uphole through the annulus 27 between the drill string 20 and the exploration well 26 and returns to the mud tank 32 through a return line 35. A sensor S1 in line 38 provides information about the fluid flow rate. A surface torque sensor S2 and a sensor S3 associated with the drill string 20 respectively provide information about the torque and rotational speed of the drill string. Additionally, one or more sensors (not shown) associated with cable 29 are used to provide the hook load of the drill string 20 and other desired parameters related to the drilling of the wellbore 26. The system may additionally include one or more sensors of downhole 70 located in drill string 20 and/or in BHA 90.

[0024] In some applications, the disintegration tool 50 is rotated solely by the rotation of the drill pipe 22. However, in other applications, a drill motor 55 (mud motor) disposed in the drill assembly 90 is used to rotate the disintegration tool 50 and/or to overlap or supplement the rotation of the drill string 20. In both cases, the rate of penetration (ROP) of the disintegration tool 50 in the exploration well 26 to a Given formation and drilling set largely depends on the weight on the drill bit and the rotational speed of the drill bit. In one aspect of the embodiment of Figure 1, the mud motor 55 is coupled to the disintegration tool 50 through a drive shaft (not shown) disposed in a bearing assembly 57. The mud motor 55 rotates the disintegration tool 50 when drilling fluid 31 passes through mud motor 55 under pressure. The bearing assembly 57 supports the radial and axial forces of the disintegration tool 50, the downward thrust of the motor, and the reactive upward load from the weight applied to the drill. Stabilizers 58 coupled to the bearing assembly 57 and other suitable locations act as centralizers for the lowermost portion of the mud motor assembly and other such suitable locations.

[0025] The surface control unit 40 receives signals from downhole sensors 70 and devices through a transducer 43, such as a pressure transducer, placed in the fluid line 38, as well as from sensors S1 , S2, S3, of hook load sensors, RPM sensors, torque sensors, and any other sensors used in the system and processes such signals in accordance with programmed instructions provided to the surface control unit 40. The surface control 40 displays desired drilling parameters and other information on a display/monitor 42 for use by an operator at the rig site to control drilling operations. The surface control unit 40 contains a computer, a memory for storing data, computer programs, models and algorithms accessible by a processor in the computer, a recorder such as a tape drive, memory unit, etc. to record data and other peripherals. The surface control unit 40 may also include simulation models for use by the computer to process data in accordance with programmed instructions. The control unit responds to user commands entered via a suitable device such as a keyboard. The control unit 40 is adapted to activate alarms 44 when certain unsafe or undesirable operating conditions occur.

[0026] The drilling assembly 90 also contains other sensors and devices or tools for providing a variety of measurements related to the formation surrounding the exploration well and for drilling the wellbore 26 and along a desired trajectory. Such devices may include a device for measuring formation resistivity near and/or in front of the drill bit, a gamma ray device for measuring formation gamma ray intensity, and devices for determining the inclination, azimuth and position of the drill string. drilling. A formation resistivity tool 64, produced in accordance with an embodiment described herein, may be coupled at any suitable location, including above a lower starting subassembly 62, to estimate or determine formation resistivity near or in front of the forming tool. disintegration 50 or in other suitable locations. An inclinometer 74 and a gamma ray device 76 can be suitably placed to respectively determine the inclination of the BHA and the forming gamma ray intensity. Any suitable inclinometer and gamma ray device can be used. Additionally, an azimuth device (not shown), such as a magnetometer or a gyroscopic device, can be used to determine the drill string azimuth. Such devices are known in the art and, therefore, will not be described in detail in the present invention. In the example configuration described above, the mud motor 55 transfers power to the disintegration tool 50 through a hollow drive shaft that also allows drilling fluid to pass from the mud motor 55 to the disintegration tool 50. In a alternative embodiment of the drill string 20, the mud motor 55 may be coupled below the formation resistivity tool 64 or in any other suitable location.

[0027] Still referring to Figure 1, other logging-while-drilling (LWD) devices (generally denoted in the present invention by reference number 77), such as devices for measuring formation porosity, permeability, density, rock properties, fluid properties etc. may be placed at suitable locations in the drilling assembly 90 to provide information useful for evaluating subsurface formations along the exploration well 26. Such devices may include, but are not limited to, temperature measuring tools, temperature measuring tools, pressure, wellbore diameter measuring tools (e.g., a gauge), acoustic tools, nuclear tools, nuclear magnetic resonance tools, and formation sampling and testing tools.

[0028] The devices noted above transmit data to a downhole telemetry system 72, which, in turn, transmits the data received uphole to the surface control unit 40. The downhole telemetry system 72 also receives signals and data from the surface control unit 40 which includes a transmitter and transmits such received signals and data to suitable downhole devices. In one aspect, a mud pulse telemetry system can be used for data communication between downhole sensors 70 and devices and surface equipment during drilling operations. A transducer 43 placed in the mud feed line 38 detects mud pulses responsive to data transmitted by the downhole telemetry system 72. The transducer 43 generates electrical signals in response to mud pressure variations and transmits such signals through a conductor 45 to the surface control unit 40. In other aspects, any other suitable telemetry system may be used for bidirectional data communication (e.g., downlink and uplink) between the surface and the BHA 90, including, but not limited to, an acoustic telemetry system, an electromagnetic telemetry system, an optical telemetry system, a wired pipeline telemetry system that may use wireless repeaters or couplers in the drill string or wellbore. Wired piping may be comprised of joining sections of drilling piping, where each section of piping includes a data communications link that runs along the piping. Data connection between piping sections may be made by any suitable method including, but not limited to, wired or optical electrical connections, induction, capacitive, resonant coupling, or directional coupling methods. In the case where a coiled tubing (spiral tubing) is used as the drill pipe 22, the data communication link may run along one side of the coiled tubing.

[0029] The drilling system described so far refers to those drilling systems that use a drill pipe to transport the drilling assembly 90 to the exploration well 26, in which the weight on the bit is controlled from the surface, typically by controlling the operation of the winch. However, a large number of current drilling systems, especially for drilling horizontal and highly deviated wellbores, use coiled tubing to transport the drill assembly down the well. In such an application, a thruster is sometimes installed on the drill string to provide the desired force on the drill bit. Furthermore, when coiled tubing is used, it is not rotated by a turntable, but preferably is injected into the wellbore by a suitable injector while the downhole motor, such as the mud motor 55, rotates the blasting tool 50. For offshore drilling, an offshore platform or vessel is used to support the drilling equipment, including the drill string.

[0030] Still referring to Figure 1, a forming resistivity tool 64 may be provided which includes, for example, a plurality of antennas including, for example, transmitters 66a or 66b and/or receivers 68a or 68b. Resistivity may be a formation property that is of interest in making drilling decisions. Those skilled in the art will recognize that other forming property tools can be employed with or in place of the forming resistivity tool 64.

[0031] Liner drilling can be a configuration or operation used to provide a disintegration device that is becoming increasingly attractive in the oil and gas industry as it has several advantages compared to conventional drilling. An example of such a configuration is shown and described in US Patent No. 9,004,195, entitled "Apparatus and Method for Drilling a Wellbore, Setting a Liner and Cementing the Wellbore During a Single Trip", which is incorporated herein. for reference, in its entirety. It is important to note that despite a relatively low penetration rate, the time to drive the liner to the target is reduced due to the fact that the liner is seated within the hole while the wellbore is simultaneously drilled. This can be beneficial in booming formations where contraction of the drilled well may make liner installation difficult later. Additionally, liner drilling in depleted and unstable reservoirs minimizes the risk of the pipe or drill string becoming stuck due to borehole collapse.

[0032] Although Figure 1 is shown and described in relation to a drilling operation, those skilled in the art will recognize that similar configurations, although with different components, can be used to perform different downhole operations. For example, steel cable, coiled tubing and/or other configurations may be used as known in the art. Additionally, production configurations can be employed to extract and/or inject materials from/into earth formations. Accordingly, the present disclosure should not be limited to drilling operations, but may be employed for any suitable or desired downhole operation.

[0033] Now referring to Figure 2, there is shown a schematic line diagram of an example of system 200 that includes an internal structure 210 disposed on an external structure 250. In this embodiment, the internal structure 210 is an internal column, including a downhole assembly as described below. Additionally, as illustrated, the outer structure 250 is an outer shell or column. The internal structure 210 includes various tools that are movable within and relative to the external structure 250. In accordance with embodiments of the present disclosure, the internal structure 210 and the external structure 250 may be moved by the surface equipment together or independently of each other. other. As described in the present invention, several of the tools of the internal structure 210 may act on and/or with portions of the external structure 250 to perform certain downhole operations. Additionally, several of the tools of the inner frame 210 may extend beyond the outer frame 250 to perform other downhole operations, such as drilling.

[0034] In this embodiment, the internal structure 210 is adapted to pass through the external structure 250 and connect to the internal side 250a of the external structure 250 at several separate locations (also referred to in the present invention as "settlements" or "seating locations" ). The shown embodiment of the outer frame 250 includes three seats, namely, a lower seat 252, a middle seat 254, and an upper seat 256. The inner frame 210 includes a drilling assembly or disintegration assembly 220 (also called a "squaring seat"). downhole") connected to a bottom end of a tubular member 201, such as a string of joined tubing or coiled tubing. The drilling assembly 220 includes a first disintegration device 202 (also called in the present invention a "pilot bit") at its bottom end for drilling a well of a first size 292a (also called in the present invention a "pilot hole"). . The drilling assembly 220 further includes a maneuvering device 204 which in some embodiments may include a plurality of force-applying members 205 configured to extend from the drilling assembly 220 to apply force to a wall 292a' of the pilot hole 292a drilled by the pilot drill 202 for driving the pilot drill 202 along a selected direction, such as for drilling an offset pilot hole. The drilling assembly 220 may also include a drilling motor 208 (also called a "mud motor") configured to rotate the pilot bit 202 when a pressurized fluid 207 is supplied to the internal structure 210.

[0035] In the configuration of Figure 2, the drill assembly 220 is also shown as including a reamer 212 that can be extended and retracted toward a body of the drill assembly 220, as desired, to enlarge the pilot hole 292a to form a wellbore 292b, up to at least the size of the outer column. In various embodiments, for example as shown, the drilling assembly 220 includes a plurality of sensors (collectively designated by reference numeral 209) to provide signals related to various downhole parameters, including, but not limited to, various properties or characteristics of a formation 295 and parameters related to the operation of the system 200. The drilling assembly 220 also includes a control circuit (also called a "controller") 224 that may include circuitry 225 for conditioning signals from the various sensors 209, a processor 226, such as a microprocessor, a data storage device 227, such as solid-state memory, and programs 228 accessible to the processor 226 to execute instructions contained in the programs 228. The controller 224 communicates with a surface controller (not shown) through a suitable telemetry device 229a that provides two-way communication between the internal structure 210 and the surface controller. The telemetry unit 229a may use any suitable data communication technique, including, but not limited to, mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, and wired piping. A power generating unit 229b in the internal structure 210 provides electrical power to the various components in the internal structure 210, including the sensors 209 and other components of the drilling assembly 220. The drilling assembly 220 may also include a second power generating device. energy 223 capable of providing electrical energy that is independent of the presence of energy generated using drilling fluid 207 (e.g., the third energy generating device 240b described below).

[0036] In various embodiments, such as the embodiment shown, the internal structure 210 may additionally include a sealing device 230 (also called a "seal sub") which may include a sealing element 232, such as an expandable "packer" and retractable, configured to provide a flow barrier or fluid seal between the inner structure 210 and the outer structure 250 when the sealing element 232 is activated to be in an expanded state. Additionally, the internal structure 210 may include a liner drive sub 236 that includes fastening devices 236a, 236b (e.g., locking elements, anchors, sliding elements, etc.) that may be removably connected to any of the locations of seating on the external structure 250. The fastening devices 236a, 236b are also referred to herein as "external engagement elements". The internal structure 210 may also include a lifter activation sub- or device 238, including an activation tool, which has sealing elements 238a, 238b configured to activate a rotatable hanger 270 in the outer frame 250. The internal structure 210 may include a third power generating device 240b, such as a turbine-driven device, operated by fluid 207 flowing through the internal column 210 configured to generate electrical power, and a second bidirectional telemetry device 240a, which includes a transmitter, which uses any suitable communications technique, including, but not limited to, mud pulse, acoustic, electromagnetic and wired pipe telemetry. The internal structure 210 may additionally include a fourth power generation device 241, which is independent of the presence of a power generation source using drilling fluid 207, such as batteries. The internal structure 210 may additionally include short tubes 244 and a rupture sub 246.

[0037] Still referring to Figure 2, the external structure 250 includes a liner 280 that can house or contain a second disintegration device 251 (for example, also called in the present invention a "reamer drill") at its lower end. The reamer 251 is configured to enlarge a remaining portion of the hole 292a drilled by the pilot drill 202. In certain aspects, the attachment of the inner column to the lower seating 252 allows the inner frame 210 to drill the pilot hole 292a and the reamer 212 to widen it. up to the size of the wellbore 292 which is at least as large as the outer structure 250. Attaching the inner structure 210 to the intermediate seating 254 allows the reamer bit 251 to enlarge the section of the hole 292a not enlarged by the reamer 212 (also called in the present invention of "remaining hole" or "remaining pilot hole"). Fixing the internal structure 210 in the upper settlement 256 allows cementing an annulus 287 between the liner 280 and the formation 295 without pulling the internal structure 210 to the surface, that is, in a single trip of the system 200 downhole. The lower seat 252 includes a female groove 252a and a locking groove 252b for securing the liner drive sub 236 attachment devices 236a and 236b. Similarly, the middle seat 254 includes a female groove 254a and a locking groove. 254b and the upper seating 256 includes a female groove 256a and a locking groove 256b. Any other suitable method of attachment and/or locking mechanisms for connecting the inner structure 210 to the outer structure 250 may be used for the purpose of this disclosure.

[0038] The outer structure 250 may also include a flow control device 262, such as a backflow prevention assembly or device, placed on the inner side 250a of the outer structure 250 adjacent to its lower end 253. In Figure 2, the flow control device 262 is in a deactivated or open position. In such a position, the flow control device 262 allows fluid communication between the wellbore 292 and the inner side 250a of the outer structure 250. In some embodiments, the flow control device 262 may be activated (i.e., closed ) when the pilot bit 202 is retrieved within the outer frame 250 to prevent fluid communication from the wellbore 292 to the inner side 250a of the outer frame 250. The flow control device 262 is deactivated (i.e., opened) when the pilot drill 202 is extended outward from the outer structure 250. In one aspect, force application members 205 or another suitable device may be configured to activate the flow control device 262.

[0039] The reverse flow control device 266, such as a flapper or other backflow prevention structure, may also be provided to prevent fluid communication from the internal side of the external structure 250 to locations below the flow device. reverse flow control 266. The outer structure 250 also includes a hanger 270 that can be activated by the hanger activation sub 238 to anchor the outer frame 250 to the host casing 290. The host casing 290 is installed in the wellbore 292 prior to drilling wellbore 292 with system 200. In one aspect, the outer frame 250 includes a sealing device 285 to provide a seal between the outer frame 250 and the host casing 290. The outer frame 250 further includes a receptacle 284 in its upper end which may include a protective sleeve 281 having a female groove 282a and a locking groove 282b. A debris barrier 283 may also be provided to prevent cuttings produced by the pilot drill 202, the reamer 212 and/or the reamer drill 251 from penetrating the space or annulus between the inner frame 210 and the outer frame 250.

[0040] To drill the wellbore 292, the internal structure 210 is placed within the external structure 250 and secured to the external structure 250 in the lower settlement 252 by activating the clamping devices 236a, 236b of the liner drive sub 236 as per shown. This liner drive sub 236, when activated, connects the clamping device 236a to the female grooves 252a and the clamping device 236b to the locking groove 252b in the lower seat 252. In this configuration, the pilot drill 202 and the reamer 212 extend in addition to reamer bit 251. In operation, drilling fluid 207 powers drilling motor 208 which rotates pilot bit 202 to cause it to drill pilot hole 292a while reamer 212 enlarges pilot hole 292a to the diameter of wellbore 292. The pilot bit 202 and the reamer 212 can also be rotated by the rotation of the drilling system 200, in addition to their rotation by the motor 208.

[0041] In general, there are three different configurations and/or operations that are performed with the system 200: drilling, reaming, and cementing. In a drilling position, the downhole assembly (BHA) completely exits the liner to allow full measurement and maneuverability (e.g., as shown in Figure 2). In a flared position, only the first disintegration device (e.g. pilot bit 202) is outside the liner to reduce the risk of stuck tubing or drill string in the event of a well collapse and the remainder of the BHA is housed within the outer frame 250. In a cementing position, the BHA is configured within the outer frame 250 at a certain distance from the second disintegration device (e.g., reamer drill 251) to ensure a suitable floating joint.

[0042] When carrying out downhole operations, the use of systems such as that shown and described above in Figures 1 and 2, it is advantageous to monitor what is occurring at the bottom of the well. Some such solutions include wired pipe (WP) where monitoring is performed using one or more sensors and/or devices and the collected data is transmitted through special drill pipes as a long cable. ". Another solution employs mud pulse telemetry (MPT) communication, where the borehole fluid is used as a communication channel. In such embodiments, downhole pressure pulses are generated (coded), and a pressure transducer converts the pressure pulses into electrical signals (coded). Mud pulse telemetry is, compared to wired piping, very slow (e.g. by a factor of a thousand). One specific piece of information is location. This is particularly true when it is desired for a downhole operation to be performed at a very specific point along a wellbore, such as, but not limited to, packer positioning, reaming, reaming, clamping, or connecting the inner string to the external column and/or extension stabilizers, anchors, blades, sliding or hanging elements, etc.

[0043] Embodiments of the present disclosure are directed to downlink-activated defining tools for liner piercing applications or other applications with one structure within another (e.g., wire rope application), wherein the one structure and the other structure may be moved by the surface equipment, either in conjunction (e.g., together as a single movement) or independently of each other (e.g., moving one while the other is held stationary). In the case of liner drilling applications, the liner and related completion equipment are transported downhole during the drilling operation (e.g., as shown in the arrangement in Figure 2). In the case of wireline or other similar application, the wireline tool or other internal structure may be inserted into and transported through an external structure to a location for a downhole operation to be performed.

[0044] In a non-limiting example, an internal structure has a hanger activation sub that is a drillstring component and is connected to a downhole assembly bus system for power supply and communication. In this example, once the liner drilling system reaches a target depth within the wellbore, the hanger activation sub is positioned next to and/or on a liner hanger. The hanger activation sub, including the activation tool, which may be part of the internal structure, contains at least one packing element (also called "internal engagement element") that generates a cavity within an annulus formed between the internal structure and the external structure and in a sensing element through at least one activation port in an interaction device on the liner hanger. To operate, the mud is circulated and a valve is opened to transfer a differential pressure from a central flow path, also called an "inner bore", from the hanger activation sub to the annulus and thus onto a sensing element. , as a pressure sensing element (e.g. pressure sensor or activation piston) of the interaction device on the liner hanger. Once the hanger is secured, at least one packing element (in some embodiments, two packing elements) can be decompressed and the drill string (inner structure) is released from the liner (outer structure). By way of non-limiting example, valve operation may be accomplished by alternative pressure transfer devices such as a piston or spindle valve that are mechanically, hydraulically and/or electrically driven. In the case of no mud flow within the exploration well, a pumping device within the internal structure can provide a differential pressure to activate the interaction device.

[0045] Now referring to Figure 3, a schematic illustration of a system 300 in accordance with an embodiment of the present disclosure is shown. In this embodiment, similar to that described above, an internal structure 310 is adapted to pass through an external structure 350 driven by surface equipment and connected to the internal side 350a of the external structure 350 at several separate locations (also referred to in the present invention as "seatings"). " or "places of settlement"). The shown embodiment of the external structure 350 includes three settlements, i.e., a lower settlement 352, an intermediate settlement 354 and an upper settlement 356. In yet another embodiment, there may be one, two, three or more settlements. The internal structure 310 includes a drill assembly 320 located at a lower end thereof, similar to that shown and described above.

[0046] As noted above, the internal structure 310 may interact with the external structure 350, such as through engagement between an internal downhole tool 358 such as a hanger activation sub, which is part of the internal structure 310 and a portion of the external structure 350, such as a hanger 370. In some embodiments, as noted, the internal downhole tool 358 is a downlinkable hanger activation sub that may extend and/or interact with a portion of the external structure 350. Although shown and described in the present invention in connection with a coupling between a lifter activation sub (of the internal structure) and a hanger (of the external structure), those skilled in the art will recognize that any type of downhole operation and/or tool arrangement may employ the embodiments of the present disclosure.

[0047] Now referring to Figures 4A to 4D, schematic illustrations of an operation in accordance with a non-limiting embodiment of the present disclosure are shown. Figures 4A to 4D depict a sequence for the operation of a lifter activation sub, including an activation tool 402, which operates under an interaction device 404. The activation tool 402 is part of an internal structure 406 that is movable. within and through an external structure 408 that includes the interacting device 404. One or more parts of the internal structure 406, including the activation tool 402, may be operated to act on, engage with, or otherwise interact with part of the external structure. 408, such as on an inner surface 408a of the outer structure 408 and/or the interaction device 404.

[0048] The interaction of the activation tool 402 with the interaction device 404 in the external structure 408 can be facilitated through a mechanical, electrical, acoustic and/or optical interaction. Activation tool 402 includes an internal engaging element. The internal engagement element includes at least one of an extensible element, an electrical element, an acoustic element and/or an optical element. The extensible element (or extensible elements) may be a packer, a snorkel, a piston, a claw, a blade, a rod and/or a rib. The electrical, acoustic and/or optical elements can transmit electrical, acoustic and/or optical signals, respectively. In the case of a mechanical activation of the interaction device 404, a sensor may be disposed within the interaction device 404 that is capable of detecting mechanical movement. Mechanical activation can be detected by a button-type sensor or other types of sensors of varying complexity, such as load sensors (e.g. pressure, torque, bending load, etc.). In the case of electrical, acoustic and/or optical activation of the interaction device 404, the electrical sensors (e.g., capacitive, inductive, galvanic, etc.), acoustic sensors (e.g., piezoelectric sensors, tuning forks, etc.) and/or or optical sensors (e.g., diodes, etc.) may be incorporated into the interaction device 404.

[0049] The inner structure 406 and the outer structure 408, as shown, are transported through a host casing 410 that is disposed within an exploration well 412 created in a formation 414. One or both of the inner structure 406 and the outer structure 408, in some embodiments, may include drill bits or other tools, as shown in Figures 2 to 3. A tool annulus 416 is formed between an outer portion of the inner frame 406 and the inner surface 408a of the outer frame 408. It may be advantageous to have the outer structure 408 secured relative to the host shell 410. However, at other times, the outer frame 408 needs to be movable relative to the host shell 410. As such, a hitch or gripping mechanism needs to be capable of being triggered only when desired, such as in specific locations. Accordingly, the system 400 includes the activation tool 402 as part of the internal structure 406 that is operative under the interaction device 404 of the external structure 408.

[0050] In this embodiment, the activation tool 402 includes a first engagement element 418 and a second internal engagement element 420. The interaction device 404 includes one or more external engagement elements 422. As shown in Figure 4A, the tool Activation port 402 is positioned in the interaction device 404 with the internal engagement elements 418, 420 positioned above and below the activation port of the sensing element of the interaction device 404 to allow isolation of a portion of the tool ring 416. In Generally, the one or more internal engagement elements 418, 420 are configured to isolate a portion of the tool ring around the activation port of the sensing element of the interaction device 202. The activation tool 402 may include electronic components and/or or be operatively connected to an electronics module that can send/receive communications along a communication line and thus can be in communication with surface equipment (e.g., control unit 40 in Figure 1). .

[0051] Although the embodiment of Figure 4A illustrates (and describes) an arrangement of two "packers" to isolate an annulus-shaped portion formed between the inner structure and the outer structure, various other shaped portions and/or shaped flow barriers can be used without departing from the scope of the present disclosure. For example, in a non-limiting embodiment, it may be sufficient to construct a flow barrier located between a valve on the activation tool of the inner structure and a flow port of the interaction device on the outer structure. Such a flow barrier may not span around an entire annulus, but instead may be implemented to employ only a portion of the annulus between the inner and outer structures, such as a channel-shaped connection (e.g., a cylinder). between the valve location on the inner frame activation tool and the activation tool portion of the outer frame interaction device. Such a channel-shaped connection can pass through the annulus.

[0052] In operation, activation tool 402 may receive instructions via a downlink. The instructions may be to perform an interacting operation, such as extending the outer engagement elements 422 to operatively connect the outer structure 408 to the host shell 410. Upon receipt of instructions, the inner engagement elements 418, 420 may be operated to isolating a portion of the tool annulus to form an insulated annulus or cavity 416a. The internal engagement elements 418, 420 may be packer-type elements that are expandable or compressible so that a portion of the internal engagement elements 418, 420 can engage with the internal surface 408a of the external structure 408 and form the insulated annulus or cavity. 416a. In a non-limiting example, the internal engagement elements 418, 420 are compressed or squeezed to expand outwardly in engagement with the internal surface 408a. Such engagement between the internal engagement elements 418, 420 and the internal surface 408a in the interacting device 404 is illustratively shown in Figure 4B, with the insulated annulus or cavity 416a defined between the activating tool 402 and the internal surface 408a in the interacting device. interaction 404.

[0053] As shown in Figure 4C, the isolated annulus or cavity 416a is filled with well fluid. The insulated annulus or cavity 416a, in this embodiment, is pressurized using higher pressure within the internal bore of the internal structure by transferring a fluid such as, but not limited to, mud, water, formation or production fluid, etc. supplied through an activation tool valve 402. Mud within a pressurized annulus or cavity 416b generates a differential pressure in the interaction device 404 and the one or more external engagement elements 422 will actuate. The differential pressure is in the interaction device 404. For example, a valve in the activation tool 402 allows fluid flow from an internal hole to an isolated annulus or cavity. Differential pressure is then present at the interaction device 404. The side of the interaction device 404 that faces the inner annulus experiences a different pressure than the side of the interaction device 404 that faces the outer annulus. In this case, the one or more expandable elements, also called external engagement elements 422, will extend outward from the interaction device 404 of the external structure 408 and in engagement with the host shell 410, as shown in Figure 4C. By way of non-limiting example, the external engagement element may be at least one of a sliding element, an anchor, a piston, a blade, a rib, a floating key and/or a claw. In some embodiments, the external structure may include a power source, such as a battery or alternative energy storage device, with such power source arranged to provide power to the external engagement elements if necessary.

[0054] In some embodiments of the present description, one or more of the external engagement elements may be arranged to interact with an external structure, such as an exploration well formation, a volume of cement, etc. The interaction in such embodiments may be at least one of formation evaluation (FE) measurements and/or cement bond measurements. The external engagement element (or elements) of such embodiments may include measurement sensors, for example, including at least one of a temperature sensor, a pressure sensor, a resistivity sensor, a gamma radiation sensor, a nuclear sensor , a nuclear magnetic resonance sensor and/or a formation sampling sensor. The acquired data can be stored in a non-volatile memory on the external structure for later retrieval and/or processing.

[0055] Once the one or more external engagement elements 422 are activated or actuated, the activation tool 402 may be operated to close the valve and/or may operate to disengage the internal engagement elements 418, 420 from the inner surface 408a, allowing the mud to disperse within the tool annulus 416. As shown in Figure 4D, the tool annulus 416 is re-formed without any interruptions or isolated sections and is continuous along the length of the inner and outer structures 406, 408. After this operation, the internal structure 406 can be moved relative to the external structure 408. Furthermore, the operation described above can be performed again at a second location with the activation tool 402 interacting with a second interaction device similar to the activation device. interaction 404, at a different location along the length of the external structure 408.

[0056] In accordance with embodiments of the present description, a downlink electronic activation of an activation tool is provided to enable and perform a downhole operation where the activation tool interacts with and/or operates an interaction device . For example, a liner installation operation can be initiated using electronic activation via a downlink and an activation tool (e.g., part of an internal drillstring, wireline tool) that is within an external structure (e.g., an external drill string, liner, etc.) may act or operate to cause an operation or action through the external structure to thereby engage and install with a liner. The activation tool acts in response to electronic instructions sent downlink from a surface controller to perform a downhole operation. Advantageously, embodiments of the present disclosure replace traditional drop-ball operations with faster downlink communication and thus improved operating times and/or repeatable operations can be performed at the bottom of the pit.

[0057] Downhole operations that are electronically initiated via a downlink are achieved with the use of an activation tool (e.g., internal drillstring, wireline tool, etc.) that acts on a interaction device (e.g., a portion of an external column, liner, casing, etc.). According to a non-limiting embodiment, an activation tool or part thereof of an internal structure is downlink activated to operate and perform a first action that induces a second action that is performed by an interaction device in an external structure that the internal structure is inside.

[0058] In a non-limiting example, a downlink instruction may be transmitted by a transmitter from the surface to perform a liner installation operation. In this case, the downlink is received by an internal structure, the internal structure having a valve section that includes a valve positioned between or near one or more optional internal engagement elements. The valve section may be arranged to be controllable in response to a downlink. Internal engagement elements can seal a volume (e.g. an annulus between the internal structure and the external structure). The valve is operated (in response to downlink instructions) to increase pressure near the internal engagement elements by transferring fluid and thereby perform downhole operation. In various embodiments, the valve may control, for example, hydraulic fluid or drilling mud. A changed pressure, such as increased or decreased pressure, between the activation tool and the interacting device acts to operate one or more features on/of the interacting device (e.g., liner hanger elements, clamping devices, sliding elements , etc.).

[0059] As will be appreciated by those skilled in the art, embodiments of the present disclosure can be used to perform any downhole tool activation operation and the present disclosure is not limited to packer/suspender arrangements. Embodiments of the present disclosure are directed to operations that are occurring on the external side or are external to the external structure or interaction device, as done by liner hanger subs, as described in the present invention. Additionally, embodiments may be used to perform activation operation (or operations) at multiple locations along an external structure with the use of a single activation tool of an internal structure.

[0060] As described in the present invention and in relation to a non-limiting embodiment below, apparatus and methods are provided for activating downlink of downhole equipment to perform a downhole operation. In general, embodiments are directed to positioning an activation tool of an internal structure within or near an activation port of an interaction device of an external structure, the activation device to be activated by operation of the activation tool. In one example, compression of two internal engaging elements (e.g., packing elements) generates an isolated annulus or cavity between the internal structure and the external structure, such as between the activation tool and the interaction device. An internal structure valve is operated to permit connection (e.g., hydraulic) between an inner diameter of the interacting device and an outer or outer component of the interacting device. The hydraulic connection enables the operation of the external component. For example, upon allowing fluid flow through the valve, a differential pressure is generated within the annulus or cavity. The differential pressure will then hydraulically activate a component or element of the interacting device so that an operation can be performed external to the interacting device.

[0061] In various embodiments, as described in the present invention, during downhole operations prior to activation of and/or interaction with the interaction device, the valve of the activation tool may be protected from debris and other contamination by means of the filling an annulus around the internal structure or any other geometric type of cavity associated with the internal structure with oil and sealing it with a rubber membrane, a piston, a bellows, or any other type of flexible barrier towards the annulus or cavity between internal and external structures. Additionally, in some embodiments, the differential pressure generated within the annulus or cavity between the internal and external structures to operate the interacting device may be supplemented by the operation of pulser valves that may be used as adjustable reducers to adjust the differential pressure within the annulus. or cavity. Additionally, an optional packing element can be used as a pressure seal for the annulus or cavity during a cementing operation. Furthermore, deactivation of provisions of the present disclosure, such as deactivation of the flow barrier, can be achieved by moving the internal structure relative to the external structure and, in this way, easy disengagement or deactivation can be obtained. Alternatively, deactivation can be achieved by using, again, differential pressure variations.

[0062] Now referring to Figures 5A to 5B, example illustrations of an internal structure 502 and an external structure 504 of a system 500 are shown in accordance with an embodiment of the present disclosure. Figure 5A illustrates various features and components of the internal structure 502 and Figure 5B illustrates a portion of the internal structure 502 within the external structure 504, which are all seated within an external feature or structure 505 (e.g., formation, wellbore , host coating, other liner, etc.). As shown in Figure 5B, the inner frame 502 may be seated within the outer frame 504, and in various arrangements, the inner frame 502 is movable within and relative to the outer frame 504.

[0063] The internal structure 502 has a control section 506, a valve section 508 and an activation section 510. Below the sections 506, 508, 510 may be one or more components of a downhole assembly 512 or other downhole component (or components). Although shown as three separate sections, those skilled in the art will recognize that several alternative arrangements are possible without departing from the scope of the present disclosure. For example, one or more of the control section 506, the valve section 508 and/or the activation section 510 may be integrally formed into a single structure or several of the functions may be incorporated into other parts of the internal structure 502 at locations many different. As shown, the activation section 510 includes an activation tool 514 that is positioned between the first and second internal engagement elements 516, 518.

[0064] As shown in Figure 5B, the internal structure 502 is positioned within the external structure 504. Additionally, the external structure 504 is disposed within the external feature 505, shown as a host coating. Although shown and described as a casing, those skilled in the art will recognize that the external structure 504 can pass into and through various other structures/features, such as an exploration well or wellbore, tubular, other liner, etc. The outer frame 504 includes an interaction device 520 that is part of and/or situated on an outer or outer side of the outer frame 504. When arranged as shown in Figure 5B, an inner annulus 522 is formed between the inner frame 502 and the outer frame 504. The inner ring 522 is similar to the tool ring 416 of Figures 4A to 4D. An outer annulus 524 is formed between the outer structure 504 and the outer feature 505.

[0065] In operation, a downlink command may be transmitted or communicated to the control section 506 of the internal structure 502. Transmission of the downlink instructions/command may be by mud pulse telemetry, electromagnetic telemetry, acoustic telemetry , wired piping communication or other downlink/downhole transmission technologies as known in the art. The control section 506 will then control the valve section 508 and/or the activation section 510 to perform a particular operation. In some embodiments, control by the control section 506 may include controlling the valve section 508 to act on the activation section 510. In a non-limiting example, the control section 506 controls the activation section 510 so that the elements internal engagement surfaces 516, 518 extend from the internal structure 502 in engagement with an internal surface of the external structure 504, thereby isolating the activation tool 514. The activation tool 514 may include one or more ports and may be in fluid communication with the valve section 508. When the portion of the inner annulus 522 around the activation tool 514 is isolated by the inner engagement elements 516, 518, the valve section 508 can control a flow of fluid (e.g., hydraulic fluid, mud, etc.) in the inner annulus 522. As a fluid enters or leaves the inner annulus 522, a fluid pressure and/or differential pressure changes within the inner annulus 522, e.g., the pressure increases or decreases.

[0066] As the differential pressure increases within the inner annulus 522, hydraulic force may be applied to the outer structure 504 and particularly to the interaction device 520 (or a portion thereof). Namely, upon operation of the activation tool 514, an interaction device 520 can be activated or operated to perform a downhole operation. In a non-limiting example, the interaction device 520 may include sliding elements or other types of extension members that can be extended due to differential pressure and thereby extend from the external structure 504 (and particularly the interaction device 520). in engagement with external resource 505.

[0067] According to a non-limiting embodiment, a function of the activation section 510 is to separate or block a hydraulic path between an upper area (above the activation section 510) and the lower area (below the activation section 510) of the inner annulus 522. Due to the existence of the two inner engaging elements 516, 518, it is possible to isolate a section of the inner annulus 522 and allow the activation section 510 (or activation tool 514) to connect a fluid or center hole pressure directly with the fluid or pressure level of the inner annulus 522 and/or the outer annulus 524 by opening a short circuit through the activation tool 514 and/or the interaction device 520 at a predefined location. This functionality can also be employed in an area where the internal structure 502 protrudes from the external structure 504 (for example, as shown in Figures 2 to 3) and can seal or isolate an area against a well wall.

[0068] As noted above, the internal structure can be divided into three main sections. The control section 506, the valve section 508, and the activation section 510. The control section 506 houses electronic components and, optionally, hydraulic fluids including a hydraulic fluid compensation reservoir. Valve section 508 consists of a plurality of pockets and/or elements, including, in some configurations, a mud valve. At the lower end of the valve section 508 is the activation section 510, shown as having the two internal engagement elements (e.g., rubber packing elements) that are responsible for sealing the inner annulus 522 between the inner and outer structures 502 , 504, as described in the present invention.

[0069] Control section 506 controls the activation and deactivation of the valve section 508 and the activation section 510 and/or subparts thereof. The control section 506 is a powered section of the internal structure 502 and may be powered by one or more power mechanisms. For example, in some configurations, the control section 506 is powered by electrical energy from a battery or a mudflow-driven alternator that is powered by a turbine, as will be appreciated by those skilled in the art. Electrical energy can be transformed into hydraulic power by an electric motor that drives a pump within the control section 506 (or located in another section of the internal structure 502). Additionally, electrical energy can be used to power electronic components, measuring devices and/or control valves of one or more sections of the internal structure 502.

[0070] The activation section 510, and particularly, the internal engagement elements 516, 518, is configured to allow sealing of the internal annulus 522 between the internal structure 502 and the external structure 504. The internal engagement elements 516, 518 of activation section 510 can be activated and deactivated separately or simultaneously. In some embodiments of the present disclosure, the internal engagement elements 516, 518 may be operated by respective pistons. These pistons can be individually controlled by associated activation lines as described below. Consequently, a creation of a simple mudflow barrier can be achieved if only one of the engagement elements 516, 518 is activated (e.g., compressed) or an isolated zone between both the inner and outer structures 502, 504 if both the internal engagement elements 516, 518 are activated (e.g. compressed) simultaneously. In some non-limiting embodiments, the internal coupling element may be a packer that may be hydraulically or pneumatically inflatable (inflatable packer) or may be a mechanically activated packer (mechanical packer).

[0071] Figures 6A to 6C are schematic illustrations of an activation section 610 in accordance with the present disclosure. More particularly, Figures 6A to 6C illustrate the operation and/or activation of internal engagement elements 616, 618 of an activation tool 614 of an activation section 610 forming part of an internal structure 602 in accordance with an embodiment of the present invention. revelation. In this embodiment, two internal engagement elements 616, 618 are activated with Figures 6A to 6C illustrating an activation sequence. Figure 6A illustrates the internal engagement elements 616, 618 in a deactivated position and Figures 6B to 6C illustrate the internal engagement elements 616, 618 in an activated position. The internal structure 602 and the activation tool 614 thereof may be disposed and movable within an external structure, as shown and described above. As described above, the activation tool 614 may be engageable with an external structure to form an isolated annulus or cavity. To achieve this, the activation tool 614 of Figures 6A to 6C includes internal engagement elements 616, 618. Extension and thereby engagement of internal engagement elements 616, 618 in this embodiment is accomplished by operating of a piston assembly 624 having a first piston 626 and a second piston 628.

[0072] Pistons 626, 628 are actuated by fluid pressure that is supplied through respective first and second fluid lines 630, 632. Fluid lines 630, 632 fluidly connect a fluid source (not shown), as a source of hydraulic fluid, with cavities that are formed between respective pistons 626, 628 and an intermediate locking element 634. The intermediate locking element 634, as shown, is a ring that is fixed to the internal structure 602 and the pistons 626, 628 are movable relative to the internal structure 602. A first fluid line 630 supplies fluid into a first activation chamber 636 which receives fluid to hydraulically actuate the first piston 626 away from the intermediate locking member 634 and toward the first internal engaging member 616. Similarly, a second fluid line 632 supplies fluid into a second actuating chamber 638 that receives fluid to hydraulically actuate the second piston 628 away from the intermediate locking member 634 and toward the second engaging member 616. internal engagement 618. The first internal engagement member 616 is compressible between the first piston 626 and an upper locking member 640. Similarly, the second internal engagement member 618 is compressible between the second piston 628 and a lower locking member 642. When fluid enters the first activation chamber 636, the fluid acts on the first piston 626 and impels the first piston 626 to the left in Figure 6A. When the fluid enters the second activation chamber 638, the fluid acts on the second piston 628 and drives the second piston 628 to the right in Figure 6A.

[0073] Accordingly, in some embodiments, the first piston 626 is moved to the left (e.g., well above) and the second piston 628 is moved to the right (e.g., bottom of the well) during an activation operation. In the present arrangement, self-reinforcement is obtained when external pressure is applied between both internal engagement elements 616, 618. However, in some embodiments, this may be altered if the pressure situation is different in any other application where the pressure of the outer side is larger than that between the inner engagement elements 616, 618.

[0074] As noted, located between the pistons 626, 628 is the intermediate locking element 634 which is fixed to the internal structure 602. The intermediate locking element 634 serves as a sealing support to divide both activation chambers 636, 638 and ensures a defined final position of the pistons 626, 628. The intermediate locking element 634 prevents an imbalance of the pistons 626, 628 during a deactivation operation of the internal engaging elements 616, 618. This is due to the fact that a piston 626 , 628 may remain at least partially activated while the respective other piston 626, 628 moves back to a deactivated position. Additionally, the end positions of the activated pistons 626, 628 are defined by the respective lower locking element 640 and upper locking element 642, which can be adjusted if necessary. The lower and upper locking elements 640, 642 can prevent excessive tension of the inner engaging elements 616, 618 when the inner engaging elements 616, 618 are compressed, as shown in Figures 6B to 6C.

[0075] As illustratively shown in Figure 6B, an activation operation is shown schematically. The fluid is transported to the first activation chamber 636 along the first activation fluid line 630. Similarly, the fluid is transported to the second activation chamber 638 along the second activation fluid line 632. The fluid may be provided from a control section of the internal structure 602 as described above. The fluid may be supplied in response to a downlink instruction received by the control section from a surface controller or control unit.

[0076] As fluid volume and/or pressure increases in the first and second activation chambers 636, 638, the first and second pistons 626, 628 are propelled away from the intermediate locking element 634. The first piston 626 is driven to the left and applies pressure to the first internal engagement member 616 which is joined by the upper locking member 640. Consequently, the first internal engagement member 616 is compressed and expands outward from the activation tool 614, and thus can engage with a surface of an external structure (e.g., external structure described above). The second piston 628 is driven to the right and applies pressure to the second internal engagement member 618 which is joined by the lower locking member 642. Consequently, the second internal engagement member 618 is compressed and expands outward from the tool. activation 614, and thus can engage with a surface of an external structure (e.g., external structure described above).

[0077] To disable the internal engagement elements 616, 618, a reverse operation can be performed, as shown in Figure 6C. As shown schematically, an optional deactivation fluid line 644 that can be fluidly connected to the first and second deactivation chambers 646, 648 is provided and can be supplied with fluid similar to that described above. In some embodiments, the internal engagement elements 616, 618 may be formed from rubber or other spring-like material (or include a mechanical tilting element) and naturally deactivate or retract due to mechanical behavior of the engagement elements. As such, the pistons 626, 628 are pushed back toward the deactivated (e.g., neutral) position once pressure from the activation fluid lines 630, 632 is released. However, as noted, optional deactivation chambers 646, 648 may provide additional forces to disable internal engagement elements 616, 618 and/or in the event of a failure within activation tool 614, such as stuck pistons. As shown schematically, a single deactivation fluid line 644 is fluidly connected to both the first and second deactivation chambers 646, 648. However, those skilled in the art will recognize that multiple fluid lines may be employed (similar to the first and to the second activation fluid lines 630, 632). As such, hydraulic deactivation can optionally be performed on one or both of the internal engagement elements 616, 618.

[0078] As noted, internal engagement elements 616, 618 can provide sealing functionality. For example, a pressure seal functionality provided by the first internal engagement member 616 (e.g., top engagement member or well above) may be used during a cementing operation. When a single engagement element is activated, deactivation may be achieved by a relative movement between the internal structure 602 and an external structure to which the engagement element may be engaged. This is advantageous due to the fact that communication with the activation tool 614 may not be possible upon completion of a cementing operation. In such a deactivation operation, when the first internal engagement member 616 is activated and the internal structure 602 is pulled upward relative to an external structure, the first internal engagement member 616 compresses any fluid in the respective first activation chamber 636 that leads to a pressure spike. The pressure peak can be detected by a pressure transducer in the activation tool 614 (e.g., a hydraulic unit) and a deactivation routine can be performed.

[0079] Now referring to Figures 7A to 7B, schematic illustrations of a valve section 708 are shown in accordance with an embodiment of the present disclosure. Figure 7A illustrates a first view of the valve section 708, illustrating an inlet arrangement of the valve section 708. Figure 7B illustrates a second view of the valve section 708, illustrating an outlet arrangement of the valve section 708.

[0080] Valve section 708 is part of an internal structure 702, for example, as shown and described above. The inner frame 702 is disposed within and movable along an outer frame 704 and a tool ring 716 is formed between the inner frame 702 and the outer frame 704. The inner frame 702 includes a central flow path 750. Central flow 750 can be used to transport drilling fluids, mud, hydraulic fluids, etc. from one location to another through the internal structure 702. As shown, the valve section 708 is situated next to an activation section 710 similar to that shown and described above. Valve section 708 includes a valve 752 that is fluidly connected to the central flow path 750.

[0081] Valve 752 is responsible for connecting the central flow path 750 of the internal structure 702 with the tool annulus 716 which is present between the internal structure 702 and the external structure 704. The valve 752 is configured to allow the transmission of fluid and/or pressure if one area has a higher pressure level than the other.

[0082] For example, the pressure within the central flow path 750 may be higher than the pressure within the tool annulus 716. This may be a normal condition when a mud flow is turned on and mud is circulated through the path. central flow flow 750 of the internal activation tool and then uphole through tool annulus 716 and/or uphole through an annulus formed between an outer part of the outer structure 704 and a wellbore wall 701 (i.e. , outer annulus 724). However, due to pressure losses at one or more restrictions and/or pressure losses due to frictional forces, a differential pressure may exist between the central flow path 750 and the tool annulus 716 and/or between the flow path central 750 and the outer annulus 724.

[0083] In another example, a pressure within the central flow path 750 may be equal to a pressure within the tool annulus 716. This situation occurs when circulation is turned off and there is also no movement of the internal structure 702, considering a homogeneous fluid throughout the fluid column.

[0084] In another example, a pressure within the central flow path 750 may be lower than a pressure within the tool annulus 716. This condition may be rare, but may occur if the fluid is inhomogeneous or during an operation maneuverability due to displacement forces if the inner structure 702 and/or the outer structure 704 are lowered too quickly into the exploration well.

[0085] To activate an external structure interaction device 704 (e.g., interaction device 404 of Figure 4), the first condition described above is employed and pressure is transmitted from the central flow path 750 to the annulus of tool 716 (when isolated as described above) at a predefined position of the outer structure interacting device 704. As shown, a valve inlet port 754a fluidly connects the central flow path 750 of the inner structure 702 to the valve 752 to the along an input line 754b. Valve outlet port 756a is on the outside of the internal structure (Figure 7B) with valve outlet port 756a fluidly connecting valve 752 and central flow path 750 to tool annulus 716 along a output line 756b. Both ports 754a, 756a are protected against sedimentation by a pre-filled fluid, grease or oil reservoir 758. Additionally, the valve inlet port 754a is equipped with a rubber bellows 760 that separates the sludge from the oil. In the event of a packing element leak, bellows 760 may be punctured to provide unlimited fluid supply (e.g., mud) through valve 752.

[0086] The valve outlet port 756a, as shown in Figure 7B, is situated on the outer diameter of the internal structure 702 (and particularly on the outer diameter of the valve section 708). Outlet port 756a and outlet line 756b are protected by oil against sedimentation. In a non-limiting configuration, the outlet port 756a features an insertion element that is equipped with a perforated membrane 774. The membrane 774 opens once a differential pressure is applied to the membrane 774 and closes automatically once the differential pressure is relieved.

[0087] In some non-limiting embodiments, a differential pressure used to interact with the interaction device may be generated by a mud pump and/or a piston within the internal structure. Additionally, in some embodiments, the rubber bellows can be replaced by a valve or piston. Such an arrangement can allow fluid to move directly from a central flow path to the tool annulus to change the pressure within the annulus between the inner structure and the outer structure.

[0088] Now referring to Figure 8, there is shown a flow process 800 for performing a downhole operation in accordance with the present disclosure. The flow process 800 can be carried out by downhole systems as shown and described in the present invention. Particularly, the flow process 800 is carried out downhole with an outer structure that has at least one interacting device and an inner structure that is movable within and relative to the outer structure, the inner structure having an activation. For example, in some embodiments, the outer structure may be an outer column and the inner structure may be an inner column, with the inner column being downlinkable and instructing to perform an action with the activation tool to cause an action by the interaction device. In other embodiments, the internal structure may be a wire rope tool that is carried within a liner or other covering. Various other configurations are possible without departing from the scope of the present disclosure.

[0089] In block 802, the internal structure is moved down the shaft together with an external structure or in relation to an external structure. The internal structure is moved so that the activation tool is aligned with the interaction device in a manner that enables operation as described in the present invention. In some embodiments, the internal structure includes a control section, a valve section, and an activation section, with the activation tool being part of the activation section.

[0090] In block 804, a downlink instruction is sent to the internal structure. Such downlink may be by any known means of communication. The internal structure may include electronic components for receiving downlink instructions.

[0091] In block 806, the internal structure performs an activation routine. The activation routine may be an operation of a valve, piston and/or motor to generate a pressure differential within the internal structure and/or between a central flow path and a tool annulus that is formed between the internal structure and the external structure. Alternatively, the differential pressure can be generated independently of the pressure in the central flow path by an electro-hydraulic system within the internal structure. Other activation routines may be electronic, mechanical, hydraulic and/or combinations thereof.

[0092] In block 808, the activation routine causes an interaction routine to be performed with the external structure. The interaction routine can be initiated by a pressure differential caused by the activation routine.

[0093] Process flow 800 can be used to perform isolation routines with the internal structure relative to the external structure, as described above, as an activation routine. Additionally, the interaction routine may be caused by pressure differentials formed within the tool annulus between the internal structure and the external structure within the isolated area. The interaction routine may be an extension of components or some other action that is external to or "outside" the external structure (e.g., within an exploration well and interaction with a host casing, another liner and/or formation wall). ).

[0094] Those skilled in the art will recognize that embodiments of the present disclosure can be used to perform a hanger activation operation. In such an embodiment, the external structure is or includes a liner hanger. The liner hanger, in some non-limiting embodiments, may be any liner size, including, but not limited to, 7 inches/#32 or 7 inches/#26.

[0095] In some embodiments, the activation section (e.g., activation section 610 of Figures 6A to 6C.) may include stabilizers to stabilize relative to the external structure. For example, with reference to Figures 6A to 6C, the upper locking member and the lower locking members may be equipped with stabilizing blocks. The stabilizing blocks can be secured to the activation section (and particularly the locking elements) with screws or other fasteners and can be replaced without dismantling the entire internal structure and/or complete sections thereof. In alternative embodiments, instead of the stabilizer blocks already discussed, the internal structure may be configured with thread stabilizers, which are simple sleeves with a thread, as will be appreciated by those skilled in the art. Furthermore, those skilled in the art will recognize that any number of engagement elements and/or internal structure tools can be configured along the length of the internal structure.

[0096] By way of non-limiting example, the internal coupling elements can be modular and/or interchangeable without dismantling the internal structure. Interchangeable internal coupling elements can allow installation of different packer sizes to suit different internal diameters of the external structure. Packers can be produced from various materials, including, but not limited to, natural rubber, different fluorinated elastomers (e.g. FKM, FFKM), nitrile butadiene rubbers (e.g. NBR, HNBR), etc. and can handle different drilling fluids, varying demand drilling conditions, and/or varying temperature and/or pressure regimes. Using different end lock positions can allow adjustment to different inflated packer diameters.

[0097] In some alternative non-limiting embodiments, internal engagement elements of the internal structure can be used to activate or deactivate part of an external structure directly, as compared to being used to generate a differential pressure. For example, the internal engagement elements may be expanded to engage and/or hold a sleeve (i.e., the outer structure) and push or pull the sleeve to another position. In some embodiments, the internal engagement elements may be mechanically extended (e.g., mechanical packer) rather than relying on a hydraulically operated piston configuration as described above. Additionally, in some embodiments, the radial force generated by internal engaging elements (e.g., a blade or lance) can be used to push a portion of an external structure directly, e.g., a key or release mechanism.

[0098] In some embodiments, the ability to isolate a section of the tool annulus (or an annulus external to the internal structure) may allow fluid sampling. For example, internal engagement elements can isolate an annulus in an open bore section or even in a perforated host casing to allow fluid sampling. The fluid sampling components and tools in such an embodiment would be part of the activation tool described herein. Additionally, such insulation can be used to isolate perforated areas or a simple hole, crack, etc. Another application for tools and arrangements in accordance with the present disclosure may be cleaning an external structure by rubbing an internal diameter of the external structure with the internal engagement elements of the internal structure.

[0099] Modality 1: A method for carrying out a downhole operation in an exploration well, wherein the method comprises: moving, with the use of surface equipment, an internal structure and an external structure within the exploration well , the outer structure equipped with an interaction device and the inner structure configured to be moved relative to the outer structure in a direction parallel to the wellbore by surface equipment, transmit, by a transmitter, a downlink instruction to the structure internal, and executing an interaction routine with the interaction device in response to the downlink instruction, the interaction routine comprising an interaction at least partially outside the external structure to perform the downhole operation.

[0100] Embodiment 2: The method, according to any of the embodiments described herein, wherein the internal structure comprises an activation tool, wherein the method comprises executing an activation routine that initiates the interaction routine in response to the command instruction. downlink.

[0101] Modality 3: The method, according to any of the modalities described herein, with the activation routine comprising creating a flow barrier in a portion formed between the internal structure and the external structure.

[0102] Modality 4: The method, according to any of the modalities described here, with the activation routine comprising changing a pressure within a portion formed between the internal structure and the external structure.

[0103] Modality 5: The method, according to any of the modalities described herein, with the activation routine comprising activating at least one internal engagement element.

[0104] Modality 6: The method, according to any of the modalities described herein, wherein activating the at least one internal engagement element comprises expanding a packer element.

[0105] Embodiment 7: The method, according to any of the embodiments described herein, wherein the at least one internal coupling element is at least one of an extensible element, an electrical element, an optical element and an acoustic element.

[0106] Modality 8: The method, according to any of the modalities described herein, with the interaction routine comprising activating at least one external engagement element.

[0107] Modality 9: The method, according to any of the modalities described herein, wherein the external structure is a first liner and the at least one external coupling element mechanically connects the first liner to at least one of the exploration well , a second liner and a coating.

[0108] Modality 10: The method, according to any of the modalities described herein, with the downlink instruction being transmitted by at least one of: mud pulse telemetry, electromagnetic telemetry, acoustic telemetry and a pipe telemetry with wire.

[0109] Embodiment 11: The method, according to any of the embodiments described herein, wherein the internal structure is at least (i) removed from the external structure after the interaction routine is performed, and (ii) moved within the structure external before the interaction routine is executed.

[0110] Embodiment 12: A system activated by downlink to perform a downhole operation, the system comprising: surface equipment to perform downhole operations; an external structure operatively connected to surface equipment; an internal structure operatively connected to the surface equipment and disposed within the external structure, wherein the internal structure and the external structure are movable within a wellbore by the operation of the surface equipment, the external structure including an interaction device and the internal structure is configured to be moved relative to the external structure in a direction parallel to the exploration well by surface equipment; wherein the internal structure is configured to receive downlink instructions; and the interaction device is configured to execute an interaction routine in response to the downlink instruction, the interaction routine comprising interacting at least partially with an external side of the external structure to perform the downhole operation.

[0111] Embodiment 13: The system, according to any of the embodiments described herein, the internal structure comprising an activation tool configured to execute an activation routine that initiates the interaction routine in response to the transmitted downlink instruction.

[0112] Modality 14: The system, according to any of the modalities described herein, with the activation routine comprising at least one of the actions of: creating a flow barrier in a portion formed between the internal structure and the external structure ; and changing a pressure within a portion formed between the inner structure and the outer structure.

[0113] Embodiment 15: The system, according to any of the embodiments described herein, wherein the external structure is a first liner and the at least one external coupling element mechanically connects the first liner to at least one of the exploration well , a second liner and a coating.

[0114] Embodiment 16: The system, according to any of the embodiments described herein, with the internal structure including a control section, a valve section and an activation section.

[0115] Embodiment 17: The system, according to any of the embodiments described herein, wherein the valve section includes a valve that is positioned between a central flow path within the internal structure and a portion formed between the internal structure and the external structure.

[0116] Embodiment 18: The system, according to any of the embodiments described herein, wherein the valve section is controllable to control at least one of a fluid pressure and a fluid fluid flow from the central flow path and the portion formed between the internal structure and the external structure.

[0117] Embodiment 19: The system, according to any of the embodiments described herein, with the activation section including at least one internal engagement element.

[0118] Modality 20: The system, according to any of the modalities described here, with the at least one internal coupling element being a packer or an extensible element.

[0119] In support of the teachings of the present invention, various analysis components can be used including a digital and/or analog system. For example, controllers, computer processing systems and/or geological targeting systems, as provided herein and/or used with the embodiments described herein, may include digital and/or analog systems. Systems may have components such as processors, storage media, memory, inputs, outputs, communication links (e.g., wired, wireless, optical, or others), user interfaces, software programs, signal processors (e.g. , digital or analog) and other such components (e.g., such as resistors, capacitors, inductors and the like) to provide operation and analysis of the apparatus and methods disclosed in the present invention in any of a number of ways well understood in the art. It is considered that these teachings can be, but need not be, implemented in combination with a set of computer-executable instructions stored on a non-transitory computer-readable medium, including memory (e.g., ROMs, RAMs), optical (e.g., CD -ROMs), or magnetic (e.g. disks, hard drives), or any other type that, when executed, causes a computer to implement the methods and/or processes described herein. These instructions may provide equipment operation, control, data collection, analysis, and other functions deemed relevant by a systems designer, owner, user, or other personnel, in addition to the functions described in this disclosure. The processed data as a result of an implemented method can be transmitted as a signal via a processor output interface to a signal receiving device. The signal receiving device may be a display monitor or printer for presenting the result to a user. Alternatively or additionally, the signal receiving device may be a memory or a storage medium. It will be noted that storing the result in memory or storage media may transform the memory or storage media into a new state (i.e., containing the result) from a previous state (i.e., not containing the result). ). Additionally, in some embodiments, an alert signal may be transmitted from the processor to a user interface if the result exceeds a threshold value.

[0120] Additionally, various other components may be included and called upon to provide aspects of the teachings of the present invention. For example, a sensor, transmitter, receiver, transceiver, antenna, controller, optical unit, electrical unit and/or electromechanical unit may be included in support of the various aspects discussed in the present invention or in support of functions other than this disclosure.

[0121] The use of the terms "a", "an", "the" and "the" and similar references in the context of describing the invention (especially in the context of the following claims) should be interpreted as encompassing both the singular and the plural, except where otherwise indicated in the present invention or clearly contradicted by the context. Additionally, it should be further considered that the terms "first", "second" and the like in the present invention do not denote any order, quantity or importance, but are instead used to distinguish one element from another. The modifier "about" used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (for example, it includes the degree of error associated with the measurement of the specific quantity).

[0122] The flow diagram (or diagrams) represented here is just an example. There may be several variations to this diagram or the steps (or operations) described therein without departing from the scope of the present disclosure. For example, steps can be performed in a different order, or steps can be added, removed, or modified. All such variations are considered a part of the present disclosure.

[0123] It will be recognized that the various components or technologies may provide certain necessary or beneficial features or functionality. Accordingly, such functions and features as may be necessary in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings of the present invention and a part of the present disclosure.

[0124] The teachings of the present disclosure can be used in a variety of well operations. These operations may involve the use of one or more treatment agents to treat a formation, the fluids residing in a formation, a well, and/or in-well equipment such as production piping. Treatment agents may be in the form of liquids, gases, solids, semisolids and mixtures thereof. Illustrative treating agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, flares, flow improvers, etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, flare injection, cleaning, acidizing, steam injection, water injection, cementing, etc.

[0125] Although the embodiments described in the present invention have been described with reference to several embodiments, it will be understood that various changes can be made and equivalents can be substituted for elements thereof without departing from the scope of the present disclosure. Additionally, many modifications will be observed to adapt a particular instrument, situation or material to the teachings of the present disclosure without departing from the scope thereof. Therefore, it is intended that the disclosure is not limited to the particular embodiments disclosed as the best contemplated mode for realizing the described features, but that the present disclosure includes all embodiments falling within the scope of the appended claims.

[0126] Consequently, the embodiments of the present disclosure should not be viewed as limited by the aforementioned description, but are only limited by the scope of the appended claims.

Claims (20)

1. Method for carrying out a downhole operation in an exploration well (26, 412), the method being characterized by comprising: moving, with the use of surface equipment, an internal structure (210, 310, 502, 602 , 702) and an external structure (250, 350, 406, 408, 502, 504, 704) within the exploration well (26, 412), the external structure (250, 350, 406, 408, 502, 504, 704 ) equipped with an interaction device (202, 404, 520) and the internal structure (210, 310, 406, 502, 602, 702) configured to be moved relative to the external structure (250, 350, 406, 408, 502 , 504, 704) in a direction parallel to the exploration well (26, 412) by the surface equipment, wherein the internal structure includes a control section, a valve section and an activation section; transmitting, by a transmitter (66a, 66b), a downlink instruction to the internal structure (210, 310, 406, 502, 602, 702); and executing an interaction routine with the interaction device (202, 404, 520) in response to the downlink instruction, the interaction routine comprising an interaction at least partially outside the external structure (250, 350, 406, 408 , 502, 504, 704) to perform the downhole operation. 2. Method according to claim 1, characterized by the fact that the activation section comprises an activation tool (402, 514, 614), the method comprising executing an activation routine, the activation routine starting the routine interaction in response to the downlink instruction. 3. Method according to claim 2, characterized by the fact that the activation routine comprises creating a flow barrier in at least a portion of an annular region formed between the internal structure (210, 310, 406, 502, 602 , 702) and the external structure (250, 350, 406, 408, 502, 504, 704). 4. Method according to claim 2, characterized by the fact that the activation routine comprises changing a pressure within at least a portion of an annular region formed between the internal structure (210, 310, 406, 502, 602, 702) and the external structure (250, 350, 406, 408, 502, 504, 704). 5. Method according to claim 2, characterized by the fact that the activation routine comprises activating at least one internal engagement element (418, 420, 516, 518, 616, 618). 6. Method according to claim 5, characterized in that activating at least one internal engagement element (418, 420, 516, 518, 616, 618) comprises expanding a packer element. 7. Method according to claim 5, characterized by the fact that the at least one internal engagement element (418, 420, 516, 518, 616, 618) is at least one of an extensible element, an electrical element, an optical element and an acoustic element. 8. Method according to claim 1, characterized in that the interaction routine comprises activating at least one external engagement element (422). 9. Method according to claim 8, characterized by the fact that the external structure (250, 350, 406, 408, 502, 504, 704) is a first liner (38) and the at least one external engagement element (422) mechanically connects the first liner (38) to at least one of the exploration well (26, 412), a second liner (38), and a casing. 10. Method according to claim 1, characterized in that the downlink instruction is transmitted by at least one of: mud pulse telemetry, electromagnetic telemetry, acoustic telemetry and wired pipe telemetry. 11. Method according to claim 1, characterized by the fact that the interaction device comprises a detection element. 12. System activated by downlink to perform a downhole operation, the system being characterized by comprising: surface equipment to perform downhole operations; an external structure (250, 350, 406, 408, 502, 504, 704) operatively connected to the surface equipment; and an internal structure (210, 310, 406, 502, 602, 702) operatively connected to the surface equipment and disposed within the external structure (250, 350, 406, 408, 502, 504, 704), the internal structure being (210, 310, 406, 502, 602, 702) and the external structure (250, 350, 406, 408, 502, 504, 704) are movable within an exploration well (26, 412) through the operation of the surface equipment, the outer structure (250, 350, 406, 408, 502, 504, 704) includes an interaction device (202, 404, 520) and the inner structure (210, 310, 406, 502, 602, 702 ) is configured to be moved relative to the external structure (250, 350, 406, 408, 502, 504, 704) in a direction parallel to the exploration well (26, 412) by the surface equipment; wherein the internal structure (210, 310, 406, 502, 602, 702) is configured to receive downlink instructions; and the interaction device (202, 404, 520) is configured to execute an interaction routine in response to the downlink instruction, the interaction routine comprising an interaction at least partially with an external side of the external structure (250, 350, 406, 408, 502, 504, 704) to perform the downhole operation; and wherein the internal structure includes a control section, a valve section, and an activation section. 13. Downlink activated system according to claim 12, characterized in that the activation section comprises an activation tool (402, 514, 614) configured to execute an activation routine, the activation routine initiating the interaction routine in response to the transmitted downlink instruction. 14. Downlink activated system according to claim 13, characterized by the fact that the activation routine comprises at least one of: creating a flow barrier in a portion formed between the internal structure (210, 310, 406 , 502, 602, 702) and the external structure (250, 350, 406, 408, 502, 504, 704); and changing a pressure within a portion formed between the inner structure (210, 310, 406, 502, 602, 702) and the outer structure (250, 350, 406, 408, 502, 504, 704). 15. Downlink activated system according to claim 14, characterized by the fact that the external structure (250, 350, 406, 408, 502, 504, 704) is a first liner (38) and at least one element external coupling (422) mechanically connects the first liner (38) to at least one of the exploration well (26, 412), a second liner (38) and a casing. 16. Downlink activated system according to claim 12, characterized in that the valve section (508, 708) includes a valve that is positioned between a central flow path (750) within the internal structure (210, 310, 406, 502, 602, 702) and at least a portion of an annular region formed between the inner structure (210, 310, 406, 502, 602, 702) and the outer structure (250, 350, 406, 408, 502, 504, 704). 17. Downlink activated system according to claim 16, characterized in that the valve section (508, 708) is controllable to control at least one of a fluid pressure in the portion of the annular region formed between the internal structure and the outer structure and a fluid flow of the fluid from the central flow path (750) to the portion of the annular region formed between the inner structure (210, 310, 406, 502, 602, 702) and the outer structure (250, 350, 406, 408, 502, 504, 704). 18. Downlink activated system according to claim 12, characterized in that the activation section (510, 610, 710) includes at least one internal engagement element (418, 420, 516, 518, 616, 618). 19. Downlink activated system according to claim 18, characterized in that the at least one internal engagement element (418, 420, 516, 518, 616, 618) is a packer or an extensible element. 20. Downlink activated system according to claim 12, characterized by the fact that it further comprises a detection element in the interaction device.