MULTISTAGE WELL SYSTEM AND TECHNIQUE

BACKGROUND

For purposes of preparing a well for the production of oil or gas, at least one perforating gun may be deployed into the well via a conveyance mechanism, such as a wireline or a coiled tubing string. The shaped charges of the perforating gun(s) are fired when the gun(s) are appropriately positioned to perforate a casing of the well and form perforating tunnels into the surrounding formation. Additional operations may be performed in the well to increase the well's permeability, such as well stimulation operations and operations that involve hydraulic fracturing. The above-described perforating and stimulation operations may be performed in multiple stages of the well.

SUMMARY

The summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In accordance with an example implementation, a technique that is usable with a well includes using untethered objects to operate a first plurality of tool of the string and using a string-conveyed tool to operate a second plurality of tools of the string.

In accordance with another example implementation, a technique that is usable with a well includes deploying untethered objects to selectively shift open valve assemblies of a string; performing stimulation operations in zones associated with the valve assemblies after the valve assemblies are opened by the shifting by the untethered objects; running a string-conveyed shifting tool into the string; using the string-conveyed shifting tool to selectively shift other valve assemblies of the string; and performing stimulation operations in additional zones associated with the other valve assemblies.

Advantages and other features will become apparent from the following drawings, description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic diagram of a multiple stage well illustrating the use of an untethered object to actuate one or more downhole tool assemblies according to an example implementation.

FIG. 1B is a schematic diagram of the multiple stage well illustrating the use of a string-conveyed tool assembly to actuate one more or more downhole tool assemblies according to an example implementation.

FIG. 2A is a flow diagram depicting a technique to use untethered objects and a string-conveyed shifting tool assembly to actuate downhole tool assemblies according to example implementations.

FIG. 2B is a flow diagram depicting a technique to use untethered objects and a string-conveyed tool shifting assembly to perform multiple stage stimulation operations according to example implementations.

FIG. 3 is a schematic diagram of a dart of FIG. 1 in a radially contracted state according to an example implementation.

FIG. 4 is a schematic diagram of the dart of FIG. 1 in a radially expanded state according to an example implementation.

FIGS. 5, 7B, 8 and 15 are flow diagrams depicting techniques using an untethered object to perform downhole operations according to example implementations.

FIG. 6 is a schematic diagram of a dart illustrating a magnetic field sensor of the dart of FIG. 1 according to an example implementation.

FIG. 7A is a schematic diagram of a dart illustrating a differential pressure sensor of the dart of FIG. 1 according to an example implementation.

FIGS. 9A and 9B are cross-sectional well views illustrating use of a dart to operate a valve assembly according to an example implementation.

FIGS. 10A and 10B are cross-sectional well views illustrating use of a dart to operate a valve assembly that has a mechanism to release the dart according to an example implementation.

FIG. 11 is a schematic diagram of a deployment mechanism of a dart according to an example implementation.

FIG. 12 is a perspective view of a deployment mechanism of a dart according to a further example implementation.

FIG. 13 is a schematic diagram of a dart illustrating an electromagnetic coupling sensor of the dart according to an example implementation.

FIG. 14 is an illustration of a signal generated by the sensor of FIG. 13 according to an example implementation.

FIG. 16 is a schematic diagram illustrating engagement of a valve assembly sleeve by a coiled tubing-conveyed shifting tool according to an example implementation.

DETAILED DESCRIPTION

Systems and techniques are disclosed herein for purposes of performing multiple stage stimulation operations (acidizing or hydraulic fracturing operations, for example) in a relatively long wellbore (a wellbore exceeding 5000 feet in length from its heel, as an example). More specifically, in accordance with example implementations, the stimulation operations are performed by deploying activation tools inside a tubing string that extends through multiple zones, or stages, of the wellbore. The tubing string contains valve assemblies (sleeve valve assemblies, for example) that are constructed to be selectively opened and closed to control fluid communication between the interior of the string and the region outside of the string. In this manner, a given valve assembly may be opened for purposes of allowing hydraulic communication between the central passageway of the string and the surrounding formation, and the valve assembly may be closed for purposes of isolating the central passageway from the formation.

As a more specific example, all of the valve assemblies of the tubing string may be initially closed when the tubing string is installed in the wellbore. Tools may then be deployed in the tubing string to sequentially perform stimulation operations along the tubing string. For the stimulation operation in a given stage, a fluid barrier may be formed in the central passageway of the string to divert the stimulation fluid, one or more valve assemblies of the stage may be opened, and stimulation fluid may be communicated through the open ports of the valve assembly(ies) into the surrounding formation. The valve assembly(ies) are then closed, and the operations may then be performed again in the next stage in the multistage sequence.

For relatively short well depths, or lengths (a length less than 5000 feet from the heel of the wellbore, for example), the valve assemblies may be operated by a string-conveyed shifting tool that is run downhole inside the outer tubing string. More specifically, a shifting tool assembly may be deployed on a coiled tubing string and run downhole inside the outer tubing string so that the shifting tool assembly may be positioned near a given valve assembly to be opened. The shifting tool assembly may then be activated (via tubing conveyed pressure or by predetermined mechanical movements, as examples) for purposes of an inner sleeve of expanding the shifting tool to cause the shifting tool to engage a mating profile of the targeted valve assembly. When engaged, the coiled tubing string may then be moved (pulled uphole, for example), for purposes of shifting the sleeve of the valve assembly to open radial fluid communication ports of the assembly. A fluid barrier (a bridge plug, for example) downhole of the valve assembly may also be set so that fracturing fluid may be pumped downhole into the well and out of the valve assembly's port for purposes of fracturing (as an example of a stimulation operation) the surrounding formation. The fluid barrier may then be removed and the shifting tool may subsequently be used to shift the valve assembly closed before the shifting tool assembly is repositioned, and another stimulation operation is performed in another stage.

A potential challenge in using a shifting tool assembly in a relatively long wellbore is that the assembly has a maximum length, or depth, at which the assembly is effective. In this manner, beyond a certain conveyance line length, the shifting tool may no longer be controlled with relatively sufficient precision.

Another way to open and close valve assemblies and set fluid barriers along a relatively long wellbore is through the use of untethered objects. In this manner, such untethered objects as darts, bars or balls, may be deployed into the central passageway of the tubing string and communicated downhole for purposes of concurrently hydraulically shifting a given valve assembly open and creating a fluid barrier to divert the fluid for the stimulation operation. As described herein, the objects may autonomously operate and may be selectively programmed to target different valve assemblies, thereby creating a relatively large pool of darts for a large number of multiple stage operations. Milling or other barrier removal operations may be used for purposes of removing untethered objects from the well passageway.

In accordance with examples and systems that are disclosed herein, a hybrid process is used, which employs the use of both untethered objects and a string-conveyed shifting tool assembly to perform multiple stage stimulation operations along a relatively long wellbore.

More specifically, referring to FIG. 1A, in accordance with example operations, untethered objects, such as example untethered object 100, are deployed in a passageway of a well and used for purposes of performing stimulation operations in a “far,” or distal, region 162 of a relatively long sleeve valve-containing outer tubing string 130 (a tubing string 130 extending for a distance greater than 5000 feet from the heel of the wellbore, for example). In this manner, the untethered objects are configured to target and operate valve assemblies 152 (valve assemblies 152-M to 152-P in FIG. 1A) that are located in the distal region 162 of the outer string 130, a region that extends at least a certain length (a length of at least 5000 feet from the heel of the wellbore, for example) from the Earth surface E of the well. Referring to FIG. 1B, for the “near,” or proximate, region 160 of the outer string 130 (region extending for a depth less than 5000 feet from the heel of the wellbore, for example), a shifting tool 102 is deployed on a tubing string 101 (a coiled or jointed tubing string, as examples) for purposes of operating valve assemblies 152 (valve assemblies 152-1 to 152-M) in the proximate region 160. Thus, for this hybrid approach to multistage stimulation operations, the total number of untethered objects is maintained within an acceptable range, while avoiding using the string-conveyed shifting tool assembly at depths at which the assembly may not be precisely controlled.

Referring to FIG. 2A, thus, in general, a technique 200 in accordance with example implementations, includes using (block 202) untethered objects to operate tool assemblies of an outer string that are located closer to a distal end of the outer string and using (block 204) a string-conveyed tool assembly to operate tools of the outer string that are located closer to a proximate end of the outer string.

Referring to FIG. 2B, in accordance with example implementations, a technique 220 includes deploying (block 224) an untethered object in a well to target a valve assembly in a distal region in which a stimulation operation is to be performed and determining (decision block 226) whether the untethered object has landed in the targeted valve assembly. If so, the landed untethered object has created a fluid obstruction, or barrier, in the well. This fluid barrier is used to pressurize the well uphole of the object to hydraulically shift the valve assembly open, and the fluid barrier is further used to divert fluid into the surrounding formation to perform the stimulation operation, pursuant to block 228. Afterwards, the object may be removed (via milling or self-removal, as described below, pursuant to block 229.

Pursuant to the technique 220, a determination is then made (decision block 230) whether the next zone in which stimulation operation is to be performed is still in the distal region of the well. If so, control returns to block 224 and proceeds with the deployment and use of another untethered object, as described above. It is noted that, as described below, in accordance with further example implementations, the same untethered object may release itself from one valve assembly, travel downhole to another valve assembly for purposes of performing another stimulation operation and so on. Thus, a single untethered object may be used to perform stimulation operations in multiple stages.

If a determination is made (decision block 230) that the next stimulation operation is within the proximate region, then a string-conveyed shifting tool assembly is run (block 232) into the well to the valve assembly in the next zone in the near region in which a stimulation operation is to be performed. The shifting tool assembly is then used to shift (block 234) the valve assembly open and form a fluid barrier. The fluid barrier is then used to divert fluid into the surrounding formation, pursuant to block 236. After the stimulation operation is complete, the valve assembly may then shifted closed using the shifting tool assembly, pursuant to block 238. If a subsequent determination is made (decision block 240) that a stimulation operation is to be performed in another zone in the proximate region, then control returns to block 232.

It is noted that in accordance with further example implementations, the shifting tool assembly may first be used in the proximate region before the untethered objects are used in the distal region of the wellbore.

In accordance with example implementations, the untethered object operates autonomously after being deployed in the well. In the context of the application, an “untethered object” refers to an object that travels at least some distance in a well passageway without being attached to a conveyance mechanism (a slickline, wireline, coiled tubing string, and so forth). As specific examples, the untethered object may be a dart, a ball or a bar. However, the untethered object may take on different forms, in accordance with further implementations. In accordance with some implementations, the untethered object may be pumped into the well (i.e., pushed into the well with fluid), although pumping may not be employed to move the object in the well, in accordance with further implementations.

In general, the untethered object may be used to perform a downhole operation that may or may not involve actuation of a downhole tool As just a few examples, the downhole operation may be a stimulation operation (a fracturing operation or an acidizing operation as examples); an operation performed by a downhole tool (the operation of a downhole valve, the operation of a single shot tool, or the operation of a perforating gun, as examples); the formation of a downhole obstruction; or the diversion of fluid (the diversion of fracturing fluid into a surrounding formation, for example). Moreover, in accordance with example implementations, a single untethered object may be used to perform multiple downhole operations in multiple zones, or stages, of the well, as further disclosed herein.

In accordance with example implementations, the untethered object is deployed in a passageway (a tubing string passageway, for example) of the well, autonomously senses its position as it travels in the passageway, and upon reaching a given targeted downhole position, autonomously operates to initiate a downhole operation.

The untethered object is initially radially contracted when the object is deployed into the passageway of the string. The object monitors its position as the object travels in the passageway, and upon determining that it has reached a predetermined location in the well, the object radially expands. The increased cross-section of the object due to its radial expansion may be used to effect any of a number of downhole operations, such as shifting a valve, forming a fluid obstruction, actuating a tool, and so forth. Moreover, because the object remains radially contracted before reaching the predetermined location, the object may pass through downhole restrictions (valve seats, for example) that may otherwise “catch” the object, thereby allowing the object to be used in, for example, multiple stage applications in which the object is used in conjunction with seats of the same size so that the object selects which seat catches the object.

In general, the untethered object is constructed to sense its downhole position as it travels in the well and autonomously respond based on this sensing. As disclosed herein, the untethered object may sense its position based on features of the string, markers, formation characteristics, and so forth, depending on the particular implementation. As a more specific example, for purposes of sensing its downhole location, the untethered object may be constructed to, during its travel, sense specific points in the well, called “markers” herein. Moreover, as disclosed herein, the untethered object may be constructed to detect the markers by sensing a property of the environment surrounding the object (a physical property of the string or formation, as examples).

The markers may be dedicated tags or materials installed in the well for location sensing by the object or may be formed from features (sleeve valves, casing valves, casing collars, and so forth) of the well, which are primarily associated with downhole functions, other than location sensing. Moreover, as disclosed herein, in accordance with example implementations, the untethered object may be constructed to sense its location in other and/or different ways that do not involve sensing a physical property of its environment, such as, for example, sensing a pressure for purposes of identifying valves or other downhole features that the object traverses during its travel.

As a more specific example, FIG. 1A depicts deployment of an untethered object, here a “dart 100,” into the passageway of a tubing string 130. The tubing string 130 is installed in a wellbore 120, which traverses one or more formations (hydrocarbon bearing formations, for example) of a multiple stage well. As a more specific example, the wellbore 120 may be lined, or supported, by the tubing string 130, as depicted in FIG. 1A. The tubing string 130 may be cemented to the wellbore 120 (such wellbores typically are referred to as “cased hole” wellbores); or the tubing string 130 may be secured to the formation by packers (such wellbores typically are referred to as “open hole” wellbores).

It is noted that although FIG. 1A depicts a laterally extending wellbore 120, the systems and techniques that are disclosed herein may likewise be applied to vertical wellbores. In accordance with example implementations, the well may contain multiple wellbores, which contain tubing strings that are similar to the illustrated tubing string 130. Moreover, depending on the particular implementation, the well may be an injection well or a production well. Thus, many variations are contemplated, which are within the scope of the appended claims.

In general, the downhole operations may be multiple stage operations that may be sequentially performed in the stages of the well in a particular direction (in a direction from a toe end 182 of the wellbore 120 to the heel end 180 of the wellbore 120, or vice versa, as examples) or may be performed in no particular direction or sequence, depending on the implementation.

Although not depicted in FIG. 1A, fluid communication with the surrounding reservoir may be enhanced in one or more of the stages through, for example, abrasive jetting operations, perforating operations, and so forth.

In accordance with example implementations, the well depicted in FIG. 1A includes downhole tool assemblies 152 (tool assemblies 152-1, 152-2, 152-3 and 152-4, being depicted in FIG. 1A as examples) that are located in the various stages of the well. Depending on the particular implementation, a given stage may have one or multiple tool assemblies 152. The tool assembly 152 may be any of a variety of downhole tools, such as a valve (a circulation valve assembly, a casing valve assembly, a sleeve valve assembly, and so forth), a seat assembly, a check valve, a plug assembly, and so forth, depending on the particular implementation. Moreover, the tool assembly 152 may be a mixture of different tool assemblies (a mixture of casing valves, plug assemblies, check valves, and so forth, for example).

A given tool assembly 152 may be selectively actuated by deploying an untethered object through the central passageway of the tubing string 130. In general, the untethered object has a radially contracted state to permit the object to pass relatively freely through the central passageway of the tubing string 130 (and thus, through tools of the string 130), and the object has a radially expanded state, which causes the object to land in, or, be “caught” by, a selected one of the tool assemblies 152 or otherwise secured at a selected downhole location, in general, for purposes of performing a given downhole operation. For example, a given downhole tool assembly 152 may catch the untethered object for purposes of forming a downhole obstruction to divert fluid (divert fluid in a fracturing or other stimulation operation, for example); pressurize a given stage; shift a sleeve of the tool assembly 152; actuate the tool assembly 152; install a check valve (part of the object) in the tool assembly 152; and so forth, depending on the particular implementation.

For the specific example of FIG. 1A, the dart 100 is used as the untethered object, which, as depicted in FIG. 1A, may be deployed (as an example) from the Earth surface E into the tubing string 130 and propagate along the central passageway of the string 130 until the dart 100 senses proximity of the targeted tool assembly 152 (as further disclosed herein), radially expands and engages the tool assembly 152. It is noted that the dart 100 may be deployed from a location other than the Earth surface E, in accordance with further implementations. For example, the dart 100 may be released by a downhole tool. As another example, the dart 100 may be run downhole on a conveyance mechanism and then released downhole to travel further downhole untethered.

In accordance with an example implementation, the tool assemblies 152 may be sleeve valve assemblies that may be initially closed when run into the well but subsequently shifted open when engaged by the dart 100 for purposes for performing fracturing operations from the heel 180 to the toe 182 of the wellbore 120. In this manner, for this example, before being deployed into the wellbore 120, the dart 100 is configured, or programmed, to sequentially target the tool assemblies 152 of the stages in the order in which the dart 100 encounters the tool assemblies 152.

As a more specific example, the tool assemblies 152 may be valve assemblies; and the dart 100 may be initially configured to target the tool assembly 152-N, which is the first tool assembly of a distal region 162 (a region extending beyond a wellbore length of 5000 feet from the heel 180, for example). The dart 100 is released into the central passageway of the tubing string 130 from the Earth surface E, travels downhole in the tubing string 130, and when the dart 100 senses proximity of the tool assembly 152-N along the dart's path, the dart 100 radially expands to engage a dart catching seat of the tool assembly 152-N. Using the resulting fluid barrier, or obstruction, that is created by the dart 100 landing in the tool assembly 152, fluid pressure may be applied uphole of the dart 100 (by pumping fluid into the tubing string 130, for example) for purposes of creating a force to shift the sleeve of the tool assembly 152 (a sleeve valve, for this example) to open radial fracturing ports of the tool assembly 152 with the surrounding formation.

In accordance with example implementations, the dart 100 is constructed to subsequently radially contract to release itself from the tool assembly 152-N (as further disclosed herein), travel further downhole through the tubing string 130, radially expand in response to sensing proximity of the tool assembly 152-(N+1) and land in the tool assembly 152-(N+1) to create another fluid obstruction. Using this fluid obstruction, the portion of the tubing string 130 uphole of the dart 100 may be pressurized for purposes of fracturing the corresponding stage and shifting the sleeve valve of the tool assembly 152-(N+1). Thus, the above-described process repeats in the downhole direction, in accordance with an example implementation, as the fracturing proceeds downhole until the stage associated with the tool assembly 152-P is fractured.

Although examples are disclosed herein in which the dart 100 is constructed to radially expand at the appropriate time so that a tool assembly 152 of the string 130 catches the dart 100, in accordance with other implementations disclosed herein, the dart 100 may be constructed to secure itself to an arbitrary position of the string 130, which is not part of a tool assembly 152. Thus, many variations are contemplated, which are within the scope of the appended claims.

For the example that is depicted in FIG. 1A, the dart 100 is deployed in the tubing string 130 from the Earth surface E for purposes of engaging one of the tool assemblies 152 (i.e., for purposes of engaging a “targeted tool assembly 152”). The dart 100 autonomously senses its downhole position, remains radially contracted to pass through tool assembly(ies) 152 (if any) uphole of the targeted tool assembly 152, and radially expands before reaching the targeted tool assembly 152. In accordance with some implementations, the dart 100 senses its downhole position by sensing the presence of markers 160 which may be spatially distributed along the length of the tubing string 130.

For the specific example of FIG. 1A, each marker 160 is embedded in a different tool assembly 152. The marker 160 may be a specific material, a specific downhole feature, a specific physical property, radio frequency (RF) identification (RFID), tag, and so forth, depending on the particular implementation.

It is noted that a given stage of a well may contain multiple markers 160; a given stage may not contain any markers 160; the markers 160 may be deployed along the tubing string 130 at positions that do not coincide with given tool assemblies 152; the markers 160 may not be evenly/regularly distributed as depicted in FIG. 1A; and so forth, depending on the particular implementation. Moreover, although FIG. 1A depicts the markers 160 as being deployed in the tool assemblies 152, the markers 160 may be deployed at defined distances with respect to the tool assemblies 152, depending on the particular implementation. For example, the markers 160 may be deployed between or at intermediate positions between respective tool assemblies 152, in accordance with further implementations. Thus, many variations are contemplated, which are within the scope of the appended claims.

In accordance with an example implementation, a given marker 160 may be a magnetic material-based marker, which may be formed, for example, by a ferromagnetic material that is embedded in or attached to the tubing string 130, embedded in or attached to a given tool housing, and so forth. By sensing the markers 160, the dart 100 may determine its downhole position and selectively radially expand accordingly. As further disclosed herein, in accordance with an example implementation, the dart 100 may maintain a count of detected markers. In this manner, the dart 100 may sense and log when the dart 100 passes a marker 160 such that the dart 100 may determine its downhole position based on the marker count.

Thus, the dart 100 may increment (as an example) a marker counter (an electronics-based counter, for example) as the dart 100 traverses the markers 160 in its travel through the tubing string 130; and when the dart 100 determines that a given number of markers 160 have been detected (via a threshold count that is programmed into the dart 100, for example), the dart 100 radially expands.

Referring to FIG. 3 in accordance with an example implementation, the dart 100 includes a body 304 having a section 300, which is initially radially contracted to a cross-sectional diameter D₁when the dart 100 is first deployed in the well 90. The dart 100 autonomously senses its downhole location and autonomously expands the section 300 to a radially larger cross-sectional diameter D₂(as depicted in FIG. 3) for purposes of causing the next encountered tool 352 to catch the dart 100.

As depicted in FIG. 3, in accordance with an example implementation, the dart 100 include a controller 324 (a microcontroller, microprocessor, field programmable gate array (FPGA), or central processing unit (CPU), as examples), which receives feedback as to the dart's position and generates the appropriate signal(s) to control the radial expansion of the dart 100. As depicted in FIG. 3, the controller 324 may maintain a count 325 of the detected markers, which may be stored in a memory (a volatile or a non-volatile memory, depending on the implementation) of the dart 100.

In this manner, in accordance with an example implementation, the sensor 330 provides one or more signals that indicate a physical property of the dart's environment (a magnetic permeability of the tubing string 330, a radioactivity emission of the surrounding formation, and so forth); the controller 324 use the signal(s) to determine a location of the dart 100; and the controller 324 correspondingly activates an actuator 320 to expand a deployment mechanism 310 of the dart 100 at the appropriate time to expand the cross-sectional dimension of the section 300 from the D₁diameter to the D₂diameter. As depicted in FIG. 4, among its other components, the dart 100 may have a stored energy source, such as a battery 340, and the dart 100 may have an interface (a wireless interface, for example), which is not shown in FIG. 3, for purposes of programming the dart 100 with a threshold marker count before the dart 100 is deployed in the well 90.

The dart 100 may, in accordance with example implementations, count specific markers, while ignoring other markers. In this manner, another dart may be subsequently launched into the tubing string 230 to count the previously-ignored markers (or count all of the markers, including the ignored markers, as another example) in a subsequent operation, such as a remedial action operation, a fracturing operation, and so forth. In this manner, using such an approach, specific portions of the well 90 may be selectively treated at different times. In accordance with some example implementations, the tubing string 230 may have more tools than are needed for current downhole operations, for purposes of allowing future refracturing or remedial operations to be performed.

In accordance with example implementations, the sensor 330 senses a magnetic field. In this manner, the tubing string 130 may contain embedded magnets, and sensor 330 may be an active or passive magnetic field sensor that provides one or more signals, which the controller 324 interprets to detect the magnets. However, in accordance with further implementations, the sensor 330 may sense an electromagnetic coupling path for purposes of allowing the dart 100 to electromagnetic coupling changes due to changing geometrical features of the string 130 (thicker metallic sections due to tools versus thinner metallic sections for regions of the string 130 where tools are not located, for example) that are not attributable to magnets. In other example implementations, the sensor 330 may be a gamma ray sensor that senses a radioactivity. Moreover, the sensed radioactivity may be the radioactivity of the surrounding formation. In this manner, a gamma ray log may be used to program a corresponding location radioactivity-based map into a memory of the dart 100.

Regardless of the particular sensor 430 or sensors 430 used by the dart 100 to sense its downhole position, in general, the dart 100 may perform a technique 500 that is depicted in FIG. 5. Referring to FIG. 5, in accordance with example implementations, the technique 400 includes deploying (block 504) an untethered object, such as a dart, through a passageway of a string and autonomously sensing (block 508) a property of an environment of the string as the object travels in the passageway of the string. The technique 500 includes autonomously controlling the object to perform a downhole function, which may include, for example, selectively radially expanding (block 512) the untethered object in response to the sensing.

Referring to FIG. 6 in conjunction with FIG. 3, in accordance with an example implementation, the sensor 330 of the dart 100 may include a coil 604 for purposes of sensing a magnetic field. In this manner, the coil 604 may be formed from an electrical conductor that has multiple windings about a central opening. When the dart passes in proximity to a ferromagnetic material 620, such as a magnetic marker 160 that contains the material 620, magnetic flux lines 610 of the material 620 pass through the coil 604. Thus, the magnetic field that is sensed by the coil 604 changes in strength due to the motion of the dart 100 (i.e., the influence of the material 620 on the sensed magnetic field changes as the dart 100 approaches the material 620, coincides in location with the material 620 and then moves past the material 620). The changing magnetic field, in turn, induces a current in the coil 604. The controller 324 (see FIG. 3) may therefore monitor the voltage across the coil 604 and/or the current in the coil 604 for purposes of detecting a given marker 160. The coil 604 may or may not be pre-energized with a current (i.e., the coil 604 may passively or actively sense the magnetic field), depending on the particular implementation.

It is noted that FIGS. 3 and 6 depict a simplified view of the sensor 330 and controller 324, as the skilled artisan would appreciate that numerous other components may be used, such as an analog-to-digital converter (ADC) to convert an analog signal from the coil 604 into a corresponding digital value, an analog amplifier, and so forth, depending on the particular implementation.

In accordance with example implementations, the dart 100 may sense a pressure to detect features of the tubing string 130 for purposes of determining the location/downhole position of the dart 100. For example, referring to FIG. 7A, in accordance with example implementations, the dart 100 includes a differential pressure sensor 720 that senses a pressure in a passageway 710 that is in communication with a region 760 uphole from the dart 100 and a passageway 714 that is in communication with a region 770 downhole of the dart 100. Due to this arrangement, the partial fluid seal/obstruction that is introduced by the dart 100 in its radially contracted state creates a pressure difference between the upstream and downstream ends of the dart 100 when the dart 100 passes through a valve.

For example, as shown in FIG. 7A, a given valve may contain radial ports 704. Therefore, for this example, the differential pressure sensor 720 may sense a pressure difference as the dart 100 travels due to a lower pressure below the dart 100 as compared to above the dart 100 due to a difference in pressure between the hydrostatic fluid above the dart 100 and the reduced pressure (due to the ports 704) below the dart 100. As depicted in FIG. 7A, the differential pressure sensor 720 may contain terminals 724 that, for example, electrically indicate the sensed differential pressure (provide a voltage representing the sensed pressure, for example), which may be communicated to the controller 224 (see FIG. 3). For these example implementations, valves of the tubing string 130 are effectively used as markers for purposes of allowing the dart 100 to sense its position along the tubing string 130.

Therefore, in accordance with example implementations, a technique 780 that is depicted in FIG. 7B may be used to autonomously operate the dart 100. Pursuant to the technique 780, an untethered object is deployed (block 782) in a passageway of the string; and the object is used (block 784) to sense pressure as the object travels in a passageway of the string. The technique 680 includes selectively autonomously operating (block 786) the untethered object in response to the sensing to perform a downhole operation.

In accordance with some implementations, the dart 100 may sense multiple indicators of its position as the dart 100 travels in the string. For example, in accordance with example implementations, the dart 100 may sense both a physical property and another downhole position indicator, such as a pressure (or another property), for purposes of determining its downhole position. Moreover, in accordance with some implementations, the markers 160 (see FIG. 1) may have alternating polarities, which may be another position indicator that the dart 100 uses to assess/corroborate its downhole position. In this regard, magnetic-based markers 160, in accordance with an example implementation, may be distributed and oriented in a fashion such that the polarities of adjacent magnets alternate. Thus, for example, one marker 160 may have its north pole uphole from its south pole, whereas the next marker 160 may have its south pole uphole from its north pole; and the next the marker 160 may have its north pole uphole from its south pole; and so forth. The dart 100 may use the knowledge of the alternating polarities as feedback to verify/assess its downhole position.

Thus, referring to FIG. 8, in accordance with an example implementation, a technique 800 for autonomously operating an untethered object in a well, such as the dart 100, includes determining (decision block 804) whether a marker has been detected. If so, the dart 100 updates a detected marker count and updates its position, pursuant to block 808. The dart 100 further determines (block 812) its position based on a sensed marker polarity pattern, and the dart 100 may determine (block 816) its position based on one or more other measures (a sensed pressure, for example). If the dart 100 determines (decision block 820) that the marker count is inconsistent with the other determined position(s), then the dart 100 adjusts (block 824) the count/position. Next, the dart 100 determines (decision block 828) whether the dart 100 should radially expand the dart based on determined position. If not, control returns to decision block 704 for purposes of detecting the next marker.

If the dart 100 determines (decision block 828) that its position triggers its radially expansion, then the dart 100 activates (block 832) its actuator for purposes of causing the dart 100 to radially expand to at least temporarily secure the dart 100 to a given location in the tubing string 130. At this location, the dart 100 may or may not be used to perform a downhole function, depending on the particular implementation.

In accordance with example implementations, the dart 100 may contain a self-release mechanism. In this regard, in accordance with example implementations, the technique 800 includes the dart 100 determining (decision block 836) whether it is time to release the dart 100, and if so, the dart 100 activates (block 840) its self-release mechanism. In this manner, in accordance with example implementations, activation of the self-release mechanism causes the dart's deployment mechanism 310 (see FIGS. 3 and 4) to radially contract to allow the dart 100 to travel further into the tubing string 130. Subsequently, after activating the self-release mechanism, the dart 100 may determine (decision block 844) whether the dart 100 is to expand again or whether the dart has reached its final position. In this manner, a single dart 100 may be used to perform multiple downhole operations in potentially multiple stages, in accordance with example implementations. If the dart 100 is to expand again (decision block 844), then control returns to decision block 804.

As a more specific example, FIGS. 9A and 9B depict engagement of the dart 100 with a valve assembly 910 of the tubing string 130. As an example, the valve assembly 910 may be a casing valve assembly, which is run into the well 90 closed and which may be opened by the dart 100 for purposes of opening fluid communication between the central passageway of the string 130 and the surrounding formation. For example, communication with the surrounding formation may be established/opened through the valve assembly 910 for purposes of performing a fracturing operation.

In general, the valve assembly 910 includes radial ports 912 that are formed in a housing of the valve assembly 910, which is constructed to be part of the tubing string 130 and generally circumscribe a longitudinal axis 900 of the assembly 910. The valve assembly 910 includes a radial pocket 922 to receive a corresponding sleeve 914 that may be moved along the longitudinal axis 900 for purposes of opening and closing fluid communication through the radial ports 912. In this manner, as depicted in FIG. 9A, in its closed state, the sleeve 914 blocks fluid communication between the central passageway of the valve assembly 910 and the radial ports 912. In this regard, the sleeve 914 closes off communication due to seals 916 and 918 (o-ring seals, for example) that are disposed between the sleeve 914 and the surrounding housing of the valve assembly 910.

As depicted in FIG. 9A, in general, the sleeve 914 has an inner diameter D2, which generally matches the expanded D2 diameter of the dart 100. Thus, referring to FIG. 8B, when the dart 100 is in proximity to the sleeve 914, the dart 100 radially expands the section 300 to close to or at the diameter D2 to cause a shoulder 300-A of the dart 100 to engage a shoulder 819 of the sleeve 914 so that the dart 100 becomes lodged, or caught in the sleeve 914, as depicted in FIG. 9B. Therefore, upon application of fluid pressure to the dart 100, the dart 100 translates along the longitudinal axis 900 to shift open the sleeve 914 to expose the radial ports 912 for purposes of transitioning the valve assembly 910 to the open state and allowing fluid communication through the radial ports 912.

In general, the valve assembly 910 depicted in FIGS. 9A and 9B is constructed to catch the dart 100 (assuming that the dart 100 expands before reaching the valve assembly 910) and subsequently retain the dart 100 until (and if) the dart 100 engages a self-release mechanism.

In accordance with some implementations, the valve assembly may contain a self-release mechanism, which is constructed to release the dart 100 after the dart 100 actuates the valve assembly. As an example, FIGS. 10A and 10B depict a valve assembly 1000 that also includes radial ports 1010 and a sleeve 1014 for purposes of selectively opening and closing communication through the radial ports 1010. In general, the sleeve 1014 resides inside a radially recessed pocket 1012 of the housing of the valve assembly 1000, and seals 1016 and 1018 provide fluid isolation between the sleeve 914 and the housing when the valve assembly 1000 is in its closed state. Referring to FIG. 9A, when the valve assembly 1010 is in its closed state, a collet 1030 of the assembly 1010 is attached to and disposed inside a corresponding recessed pocket 1040 of the sleeve 1014 for purposes of catching the dart 100 (assuming that the dart 100 is in its expanded D2 diameter state). Thus, as depicted in FIG. 10A, when entering the valve assembly 1000, the section 300 of the dart 100, when radially expanded, is sized to be captured inside the inner diameter of the collet 1030 via the shoulder 300-A seating against a stop shoulder 1013 of the pocket 1012.

The securement of the section 300 of the dart 100 to the collet 1030, in turn, shifts the sleeve 1014 to open the valve assembly 1000. Moreover, further translation of the dart 100 along the longitudinal axis 1002 moves the collet 1030 outside of the recessed pocket 1040 of the sleeve 1014 and into a corresponding recessed region 1050 further downhole of the recessed region 912 where a stop shoulder 1051 engages the collet 1030. This state is depicted in FIG. 10B, which shows the collet 1030 as being radially expanded inside the recess region 1040. For this radially expanded state of the collet 1030, the dart 100 is released, and allowed to travel further downhole.

Thus, in accordance with some implementations, for purposes of actuating, or operating, multiple valve assemblies, the tubing string 130 may contain a succession, or “stack,” of one or more of the valve assemblies 1000 (as depicted in FIGS. 10A and 10B) that have self-release mechanisms, with the very last valve assembly being a valve assembly, such as the valve assembly 900, which is constructed to retain the dart 100.

Referring to FIG. 11, in accordance with example implementations, the deployment mechanism 310 of the dart 100 may be formed from an atmospheric pressure chamber 1150 and a hydrostatic pressure chamber 1160. More specifically, in accordance with an example implementation, a mandrel 1180 resides inside the hydrostatic pressure chamber 1160 and controls the communication of hydrostatic pressure (received in a region 1190 of the dart 100) and radial ports 1152. As depicted in FIG. 11, the mandrel 1080 is sealed to the inner surface of the housing of the dart via (o-rings 1186, for example). Due to the chamber 1150 initially exerting atmospheric pressure, the mandrel 1180 blocks fluid communication through the radial ports 1152.

As depicted in FIG. 11, the deployment mechanism 310 includes a deployment element 1130 that is expanded in response to fluid at hydrostatic pressure being communicated through the radial ports 1152. As examples, the deployment element 1130 may be an inflatable bladder, a packer that is compressed in response to the hydrostatic pressure, and so forth. Thus, many implementations are contemplated, which are within the scope of the appended claims.

For purposes of radially expanding the deployment element 1130, in accordance with an example implementation, the dart 100 includes a valve, such as a rupture disc 1120, which controls fluid communication between the hydrostatic chamber 1160 and the atmospheric chamber 1150. In this regard, pressure inside the hydrostatic chamber 1160 may be derived by establishing communication with the chamber 1160 via one or more fluid communication ports (not shown in FIG. 11) with the region uphole of the dart 100. The controller 224 selectively actuates the actuator 220 for purposes of rupturing the rupture disc 1120 to establish communication between the hydrostatic 1160 and atmospheric 1150 chambers for purposes of causing the mandrel 1180 to translate to a position to allow communication of hydrostatic pressure through the radial ports 1152 and to the deployment element 1130 for purposes of radially expanding the element 1130.

As an example, in accordance with some implementations, the actuator 220 may include a linear actuator 1120, which when activated by the controller 224 controls a linearly operable member to puncture the rupture disc 1120 for purposes of establishing communication between the atmospheric 1150 and hydrostatic 1160 chambers. In further implementations, the actuator 220 may include an exploding foil initiator (EFI) to activate and a propellant that is initiated by the EFI for purposes of puncturing the rupture disc 1120. Thus, many implementations are contemplated, which are within the scope of the appended claims.

In accordance with some example implementations, the self-release mechanism of the dart 100 may be formed from a reservoir and a metering valve, where the metering valve serves as a timer. In this manner, in response to the dart radially expanding, a fluid begins flowing into a pressure relief chamber. For example, the metering valve may be constructed to communicate a metered fluid flow between the chambers 1150 and 1160 (see FIG. 11) for purposes of resetting the deployment element 1130 to a radially contracted state to allow the dart 100 to travel further into the well 90. As another example, in accordance with some implementations, one or more components of the dart, such as the deployment mechanism 1130 (FIG. 11) may be constructed of a dissolvable material, and the dart may release a solvent from a chamber at the time of its radial expansion to dissolve the mechanism 1130.

As yet another example, FIG. 12 depicts a portion of a dart 1200 in accordance with another example implementation. For this implementation, a deployment mechanism 1202 of the dart 1200 includes slips 1220, or hardened “teeth,” which are designed to be radially expanded for purposes of gripping the wall of the tubing string 130, without using a special seat or profile of the tubing string 130 to catch the dart 1200. In this manner, the deployment mechanism 1202 may contains sleeves, or cones, to slide toward each other along the longitudinal axis of the dart to force the slips 1220 radially outwardly to engage the tubing string 130 and stop the dart's travel. Thus, many variations are contemplated, which are within the scope of the appended claims.

Other variations of the dart are contemplated, which are within the scope of the appended claims. For example, FIG. 13 depicts a dart 1300 according to a further example implementation. In general, the dart 1300 includes an electromagnetic coupling sensor that is formed from two receiver coils 1314 and 1316, and a transmitter coil 1310 that resides between the receiver coils 1315 and 1316. As shown in FIG. 13, the receiver coils 1314 and 1316 have respective magnetic moments 1315 and 1317, respectively, which are opposite in direction. It is noted that the moments 1315 and 1317 that are depicted in FIG. 13 may be reversed, in accordance with further implementations. As also shown in FIG. 13, the transmitter 1310 has an associated magnetic moment 1211, which is pointed upwardly in FIG. 13, but may be pointed downwardly, in accordance with further implementations.

In general, the electromagnetic coupling sensor of the dart 1300 senses geometric changes in a tubing string 1304 in which the dart 1300 travels. More specifically, in accordance with some implementations, the controller (not shown in FIG. 13) of the dart 1300 algebraically adds, or combines, the signals from the two receiver coils 1314 and 1316, such that when both receiver coils 1314 and 1316 have the same effective electromagnetic coupling the signals are the same, thereby resulting in a net zero voltage signal. However, when the electromagnetic coupling sensor passes by a geometrically varying feature of the tubing string 1304 (a geometric discontinuity or a geometric dimension change, such as a wall thickness change, for example), the signals provided by the two receiver coils 1314 and 1316 differ. This difference, in turn, produces a non-zero voltage signal, thereby indicating to the controller that a geometric feature change of the tubing string 1304 has been detected.

Such geometric variations may be used, in accordance with example implementations, for purposes of detecting certain geometric features of the tubing string 1304, such as, for example, sleeves or sleeve valves of the tubing string 1304. Thus, by detecting and possibly counting sleeves (or other tools or features), the dart 1300 may determine its downhole position and actuate its deployment mechanism accordingly.

Referring to FIG. 14 in conjunction with FIG. 13, as a more specific example, an example signal is depicted in FIG. 14 illustrating a signature 1402 of the combined signal (called the“VD_IFF” signal in FIG. 14) when the electromagnetic coupling sensor passes in proximity to an illustrated geometric feature 1320, such as an annular notch for this example.

Thus, referring to FIG. 15, in accordance with example implementations, a technique 1500 includes deploying (block 1502) an untethered object and using (block 1504) the object to sense an electromagnetic coupling as the object travels in a passageway of the string. The technique 1500 includes selectively autonomously operating the untethered object in response to the sensing to perform a downhole operation, pursuant to block 1506.

Thus, in general, implementations are disclosed herein in which an untethered object may be deployed in a passageway of the string in a well. The deployed untethered object senses a position indicator as the object is being communicated through the passageway. The untethered object selectively autonomously operates in response to the sensing. As disclosed above, the property may be a physical property such as a magnetic marker, an electromagnetic coupling, a geometric discontinuity, a pressure or a radioactive source. In further implementations, the physical property may be a chemical property or may be an acoustic wave. Moreover, in accordance with some implementations, the physical property may be a conductivity. In yet further implementations, a given position indicator may be formed from an intentionally-placed marker, a response marker, a radioactive source, magnet, microelectromechanical system (MEMS), a pressure, and so forth. The untethered object has the appropriate sensor(s) to detect the position indicator(s), as can be appreciated by the skilled artisan in view of the disclosure contained herein.

Other implementations are contemplated and are within the scope of the appended claims. For example, in accordance with further example implementations, the dart may have a container that contains a chemical (a tracer, for example) that is carried into the fractures with the fracturing fluid. In this manner, when the dart is deployed into the well, the chemical is confined to the container. The dart may contain a rupture disc (as an example), or other such device, which is sensitive to the tubing string pressure such that the disc ruptures at fracturing pressures to allow the chemical to leave the container and be transported into the fractures. The use of the chemical in this manner allows the recovery of information during flowback regarding fracture efficiency, fracture locations, and so forth.

As another example of a further implementation, the dart may contain a telemetry interface that allows wireless communication with the dart. For example, a tube wave (an acoustic wave, for example) may be used to communicate with the dart from the Earth surface (as an example) for purposes of acquiring information (information about the dart's status, information acquired by the dart, and so forth) from the dart. The wireless communication may also be used, for example, to initiate an action of the dart, such as, for example, instructing the dart to radially expand, radially contract, acquire information, transmit information to the surface, and so forth.

Referring back to FIG. 1B, in accordance with example implementations, the string-conveyed shifting tool assembly 102 may be lowered downhole on the coiled tubing string 101 inside the tubing string 130 for purposes of operating the tool assemblies 152 that are disposed in the proximate region 160 of the wellbore (a region having an associated length less than 5000 feet from the heel 180, for example). Referring to FIG. 16, in general, shifting tool assembly 102 has a tubular housing 1652; and has selectively expandable, radially extending pistons 1654. As shown in FIG. 16, when the shifting tool 102 is in the appropriate position for a given valve assembly 152, a pressure P may be communicated into an open end 1660 of the housing 1652, which acts on the pistons 1654 to cause the pistons 1654 to radially expand and engage a corresponding mating profiles 1620 of an inner sleeve 1619 of the valve assembly 152.

When the pistons 1654 are engaged in the mating profiles 1620, an upward force may be applied to the string 101 to correspondingly move the shifting tool assembly 102 upwardly. This upward movement displaces collet fingers 1670 from a corresponding collet slot 1630 in the housing of the tubing string 130 to allow the inner sleeve 1619 of the valve assembly 152 to be shifted uphole.

At this point, ports 1624 of the inner sleeve 1619 align with corresponding ports 1600 of an outer housing 1621 of the valve assembly 152, thereby permitting fluid communication. It is noted that the collet fingers 1670 engage an upper annular slot 1634 in the housing 1621 to hold the valve assembly 152 in its open position.

Fluid may then be communicated via, for example, corresponding radial fluid communication ports 1690 of the shifting tool assembly 102 for purposes of performing the hydraulic fracturing operation. In accordance with example implementations, the shifting tool assembly 102 may include a valve 1690 that, upon application of a sufficient tubing pressure P, causes the valve 1693 to open to allow the fluid pressure to be communicated to the radially extending pistons 1654 for purposes of radially extending the pistons 1654.

The shifting tool assembly 102 may be further used to shift the valve assembly 152 closed. In this manner, downward movement of the tubing string may be used to shift the inner sleeve 1615 downwardly to close off fluid communication through the ports 1600. The collet fingers 1670 then engage an annular slot 1630 in the housing 1621 to lock the valve assembly 152 closed.

In accordance with example implementations, a given valve assembly 152 may be constructed to be independently operated by either a string-conveyed shifting tool or an untethered object.

Other implementations are contemplated, which are within the scope of the appended claims. For example, in accordance with further implementations, a given untethered object may be caught by a technique that does not involve expanding the object. In this manner, the untethered object may be caught in a seat of a tool assembly that is sized to catch the object; and seats that have different inner cross-sectional dimensions may be used to catch untethered objects that have correspondingly different outer dimensions. For example, valve assemblies may have progressively smaller seats as a function of distance from the heel of the wellbore. Untethered objects have a smaller cross-sectional size may be deployed first, so that the objects pass through the larger seats and are caught by the appropriate smaller seats.

As another example, untethered objects that have approximately the same size may be used, and the tool assemblies may be constructed to selectively constrict their seats for purposes of catching the objects, as described in U.S. Pat. No. 7,322,417, entitled, “TECHNIQUE AND APPARATUS FOR COMPLETING MULTIPLE ZONES,” which issued on Jan. 29, 2008.

While a limited number of examples have been disclosed herein, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations

MULTISTAGE WELL SYSTEM AND TECHNIQUE

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