WELLBORE TOOL POSITIONING SYSTEM AND METHOD

BACKGROUND
1. Field of Invention

This disclosure relates in general to oil and gas tools, and in particular, to systems and methods for positioning tools in a wellbore.

2. Description of the Prior Art

Hydrocarbons are typically produced from a well having a wellbore that intersects a hydrocarbon bearing subterranean reservoir. Various devices and types of tubulars are usually inserted into the wellbore during the operating life of the well. Casing that lines the sidewalls of the wellbore is one common type of tubular, as well as production tubing that inserts into the casing. Some tubulars are specially designed to be installed at a designated location in the wellbore, and sometimes come equipped with sliding valves and the like. Typical devices that are inserted downhole are imaging tools that log formation adjacent the wellbore, imaging tools that evaluate the efficacy of cement that bonds the casing to the wellbore walls, and perforating devices that form perforations into the formation from inside the wellbore. Frequently there is an attempt to centralize the devices or tubulars within the wellbore.

For example, it is important to symmetrically dispose casing in the wellbore so that cement is placed in the annular space between the casing and wellbore walls. Otherwise, cement bond integrity could be compromised, and zonal isolation may not be achieved. Many logging tools employ sensors that project radially outward from the body of the tool and against the sidewall of the wellbore, or inner surface of casing in a cased wellbore. If the tool body is not centered in the wellbore, the sensors may not be able to reach a portion of the wellbore sidewall distal from the tool body, or may not effectively image the target. Centralizers are generally employed when there is a need to center a tubular or device in a wellbore. The centralizers commonly include elongated elastic members oriented axially with the tool or tubular body, and that mount along an outer circumference of the tool or tubular body. Strategically positioning the centralizer members at designated angular locations causes each member to apply a radially inward force to the tool or tubular body, that when combined maintains the tubular or tool body centrally within the wellbore. One shortcoming of these passive centralizers becomes evident when wellbore diameter changes by an amount that either exceeds the outer diameter of the centralizer, or compresses the centralizer that in turn introduces an unacceptable drag force when attempting to pull the tool or tubular through the wellbore.

SUMMARY

Applicant recognized the problems noted above herein and conceived and developed embodiments of systems and methods, according to the present disclosure, for tool positioning systems.

In an embodiment, a system for performing downhole operations includes a tool string, a downhole tool forming at least a first portion of the tool string; and a positioning system forming at least a second portion of the tool string. The positioning system includes a plurality of adjustable arm devices (AADs), the AADs driving respective positioning components radially outward from an axis of a section of the tool string toward a wellbore wall. In embodiments, each AAD of the plurality of AADs is individually actuatable in response to a deployment command and driven radially outward by a respective external motive force.

In another embodiment, a system for positioning a section of a tool in a section of a wellbore includes a first arm coupled to a motor actuator at a first end and a positioning component at a second end. The system also includes a second arm coupled to a biasing member at a first end and the positioning component at a second end. In embodiments, the motor actuator drives rotation of the first end of the first arm about a rotation axis to change a radial position of the positioning component with respect to a tool axis at the section of the tool.

In an embodiment, a method for determining a position of a downhole tool includes receiving an instruction to position a portion of the downhole tool at a radial offset relative to a wellbore axis. The method also includes adjusting an adjustable arm device (AAD), based at least in part on the instruction, to change a radial position of a positioning device. The method further includes receiving a signal indicative of the radial position of the positioning device. The method also includes determining the radial offset, based at least in part on the radial position of the positioning device.

BRIEF DESCRIPTION OF THE DRAWINGS

The present technology will be better understood on reading the following detailed description of non-limiting embodiments thereof, and on examining the accompanying drawings, in which:

FIG. 1 is a side elevation view of an embodiment of a wellbore system, in accordance with embodiments of the present disclosure;

FIG. 2A is a schematic side view of an embodiment of a tool string within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 2B is a schematic side view of an embodiment of a tool string within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 2C is a schematic side view of an embodiment of a tool string within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 3 is a schematic top view of an embodiment of a body sheet, in accordance with embodiments of the present disclosure;

FIG. 4 is a schematic cross sectional view of an embodiment of an adjustable arm advice, in accordance with embodiments of the present disclosure;

FIG. 5A is a schematic cross sectional view of an embodiment of a tool string arranged within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 5B is a schematic cross sectional view of an embodiment of a tool string arranged within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 6 is a schematic side view of an embodiment of a tool string arranged within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 7A is a schematic side view of an embodiment of a tool string arranged within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 7B is a schematic side view of an embodiment of a tool string arranged within a wellbore, in accordance with embodiments of the present disclosure;

FIG. 8 is a schematic diagram of an embodiment of a control system, in accordance with embodiments of the present disclosure;

FIG. 9 is a flow chart of an embodiment of a method for using a positioning system, in accordance with embodiments of the present disclosure;

FIG. 10 is a flow chart of an embodiment of a method for using a positioning system, in accordance with embodiments of the present disclosure; and

FIG. 11 is a flow chart of an embodiment of a method for using a positioning system, in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION OF THE INVENTION

The foregoing aspects, features and advantages of the present technology will be further appreciated when considered with reference to the following description of preferred embodiments and accompanying drawings, wherein like reference numerals represent like elements. In describing the preferred embodiments of the technology illustrated in the appended drawings, specific terminology will be used for the sake of clarity. The present technology, however, is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.

When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Any examples of operating parameters and/or environmental conditions are not exclusive of other parameters/conditions of the disclosed embodiments. Additionally, it should be understood that references to “one embodiment”, “an embodiment”, “certain embodiments,” or “other embodiments” of the present invention are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, reference to terms such as “above,” “below,” “upper”, “lower”, “side”, “front,” “back,” or other terms regarding orientation are made with reference to the illustrated embodiments and are not intended to be limiting or exclude other orientations.

In various embodiments, like components may be referred to with the same reference numerals throughout the specification. However, in certain embodiments, different reference numerals may be used for clarity. Additionally, components of a similar nature may be referred to with a reference numeral and a letter, such as A and B, for clarity, and should not be construed as limiting. For example, while similar components may be referred to with reference numerals and an associated A and B, the components may have different sizes, shapes, or different operational mechanisms.

Embodiments of the present disclosure include systems and methods for arranging a downhole tool at a predetermined radial position within a wellbore. The radial position may be determined with respect to the wellbore axis. In various embodiments, the positioning system includes modular components that may be utilized with exiting tool strings to enable retrofitting and installation without specialty tools or fittings arranged on the tool string. Furthermore, the positioning systems may be adjustable to change a number of adjustable arm devices (AADs) that may be positioned on the tool string. In various embodiments, the adjust arm devices include arm assemblies that may drive an outward roller between different radial positions. The outward rollers may be driven radially outward from the positioning systems to engage a wall of the wellbore, thereby positioning the tool string at a desired radial location. The position of the outward roller may be controlled by a motor that adjusts the radial position of the outward roller based on one or more commands. For example, the command may be a surface instruction to position the outward roller at a predetermined radial position. Additionally, in various embodiments, the command may come from preloaded data regarding a diameter of the wellbore. Moreover, in embodiments, the command may be a feedback loop from sensors arranged on the outward roller, or another portion of the positioning system. Upon detection of contact with the wall, the motor may stop driving outward movement of the outward roller. Upon determination that the outward roller is not contacting the wall, the motor may drive the outward roller radially outward. In this manner, the tool string may be arranged at a predetermined radial position within the wellbore.

FIG. 1 is a schematic side view of an embodiment of a wellbore system 10 that includes a tool 12 (which may be part of a tool string) being lowered into a wellbore 14 formed in a formation 16 from a surface location 18. The illustrated wellbore system 10 may be referred to as a wireline system because the tool 12 is conveyed on a cable 20, such as an electric wireline. In various embodiments, the electric wireline may transmit electric signals and/or energy from the surface location 18 into the wellbore, for example to provide operational power for the tool 12 and/or to transmit data, such as data obtained from sensors arranged on the tool 12. In various embodiments, the tool 12 may be utilized to perform downhole logging operations, such as an imaging tool, a resistivity tool, a nuclear tool, or any other logging tool that may be used in a downhole environment. As will be described below, a position of the tool relative to an axis 22 of the wellbore 14 may impact the effectiveness of the tool 12. For example, the tool 12 may include one or more sensors that deploy outwardly to contact a wall 24 of the wellbore 14 (or a wall of the casing in instances of a cased wellbore). If the tool 12 is too far away from the wall 24 for the deployable sensors to make contact, the tool 12 will not obtain the desired measurements. As a result, the illustrated embodiment includes a plurality of positioning systems 26 coupled to the tool 12.

In the illustrated embodiment, the tool 12 includes the plurality of positioning systems 26 arranged on opposite sides of the tool 12. For clarity, the position system 26A will be referred to as being uphole of the tool 12 and the positioning system 26B will be referred to as being downhole of the tool 12. However, these designations are for illustrative purposes only and should not be construed as limiting a location of the position systems 26. Moreover, while the illustrated embodiment includes two positioning systems 26, in other embodiments there may be more or fewer positioning systems based on operating conditions.

The illustrated tool 12 includes arms 28 that extend outwardly from an axis 30 of the tool 12. In the embodiment illustrated in FIG. 1, the axis 22 of the wellbore 14 and the axis 30 of the tool 12 are substantially coaxial, or aligned. As such, the tool 12 may be described as being centered within the wellbore 14. As will be described in detail below, the positioning systems 26 may be utilized to drive one or more arms against the wellbore wall 24 to arrange the tool 12 in a predetermined position, which may be radially offset from the axis 22 of the wellbore 14. Accordingly, the arms 28 of the tool 12 may engage the wall 24 to obtain one or more logging measurements.

As described above, in various embodiments the tool 12 may be part of a tool string 32, which may include various components utilized for wellbore operations. For example, the tool string 32 may include various tools, sensors, measurement devices, communication devices, and the like, which will not all be described for clarity. In various embodiments, the tool string 32 may include one or more tools to enable at least one of a logging operation, a perforating operation, or a well intervention. For example, nuclear logging tools, fluid sampling tools, core sampling devices, and the like may be utilized in logging operations. Perforating operations may include ballistic devices being lowered into the wellbore to perforate casing or the formation. Furthermore, well interventions may include operations related to analyzing one or more features of the wellbore and proceeding with performing one or more tasks in response to those features, such as a data acquisition process, a cutting process, a cleaning process, and the like. Accordingly, in various embodiments, the tool string 32 may refer to tools that are lowered into the wellbore. Additionally, passive devices such as centralizers or stabilizers, tractors to facilitate movement of the tool string 32, and the like may also be incorporated into the tool string 32. Moreover, in the illustrated embodiment, the tool string 32 includes a commanding tool 34, which may be used to send and/or receive signals, such as control signals, from the surface 18. In various embodiments, the commanding tool 34 may include electrically conducting members, fiber optics, wireless transceivers, or combinations thereof to facilitate electrical transmissions, such as power transmission or data transmission. Moreover, as will be described below, in various embodiments, different power and/or data conducting tools may be utilized by embodiments of the present disclosure in order to send and receive signals and/or electrical power. As will be described below, in various embodiments sensors may be incorporated into various components of the tool string 32 and may communicate with the surface or other tool string components, for example via communication through the cable 20, mud pulse telemetry, wireless communications, wired drill pipe, and the like. Furthermore, it should be appreciated that while various embodiments include a wireline system, in other embodiments rigid drill pipe, coiled tubing, or any other downhole exploration and production methods may be utilized with embodiments of the present disclosure.

The wellbore system 10 include a wellhead assembly 36 shown at an opening of the wellbore 14 to provide pressure control of the wellbore and allow for passage of various equipment into the wellbore 14, such as the cable 20 and the tool string 32. In this example, the cable 20 is a wireline being spooled from a service truck 38. The illustrated cable 20 extends down to the end of the tool string 32. In operation, the cable 20 may be provided with slack as the tool string 32 is lowered into the wellbore 14, for example to a predetermined depth. In various embodiments, a fluid may be delivered into the wellbore 14 to drive movement of the tool string 32, for example where gravity may not be sufficient, such as in a deviated wellbore. For example a fluid pumping system (not illustrated) at the surface may pump a fluid from a source into the wellbore 14 via a supply line or conduit. To control the rate of travel of the downhole assembly, tension on the wireline 20 is controlled at a winch on the surface, which may be part of the service tuck 38. Thus, the combination of the fluid flow rate and the tension on the wireline may contribute to the travel rate or rate of penetration of the tool string 32 into the wellbore 14. The cable 20 may be an armored cable that includes conductors for supplying electrical energy (power) to downhole devices and communication links for providing two-way communication between the downhole tool and surface devices. Moreover, in various embodiments, tools such as tractors and the like may further be disposed along the tool string 32 to facilitate movement of the tool string 32 into the wellbore 14. Thereafter, in various embodiments, the tool string 32 may be retrieved from the wellbore 14 by reeling the cable 20 upwards via the service truck 38. In this manner, logging operations may be performed as the tool string 32 is brought to the surface 18.

FIGS. 2A.-C are schematic diagrams of embodiments of the tool string 32 within the wellbore 14. In the illustrated embodiments, the tool string 32 includes the tool 12 and a pair of positioning systems 26A, 26B. It should be appreciated that while the embodiments illustrated in FIGS. 2A-C include the tool 12 and the pair of positioning systems 26A, 26B, in various embodiments more tools 12 may be included, as well as more or fewer positioning systems 26. In other words, the number of tools 12 and/or positioning systems 26A, 26B may be particularly selected based on the downhole operation being performed. The illustrated wellbore 14 is a stepped wellbore that includes a transition 50 between a first diameter section 52 and a second diameter section 54. The illustrated first diameter section 52 is larger than the second diameter section 54. It should be appreciated that the arrangement is for illustrated purposes only and the uphole section (represented by an arrow 56 pointing in the uphole direction) that currently corresponds to the first diameter section 52 and a downhole portion (represented by an arrow 58 pointing in the downhole direction) that corresponds to the second diameter section 54 may be reversed in other embodiments. That is, the larger diameter section may be the downhole and the smaller diameter may be uphole.

In the illustrated embodiment, the tool string 32 is almost entirely positioned within the second diameter section 54 such that extensions 60 of the positioning tools 26A,26 B extend outwardly and contact the wall 24. In the illustrated embodiment, the positioning tools 26A, 26B substantially align the axis 30 with the axis 22, thereby centering the tool string 32 within the wellbore 14. Accordingly, the positioning tools 26A, 26B may facilitate arranging the tool 12 within the wellbore 14 to enable measurement and logging operations to commence.

FIG. 2B illustrates the tool string 32 extending between the first diameter section 52 and the second diameter section 54. As illustrated, the tool 12 is arranged substantially at the transition 50. Accordingly, it should be appreciated that fixed diameter centralizers would be insufficient in such an arrangement because a centralizer having a diameter equal to the second diameter section 54 would not be able to contact the walls of the first diameter section 52. Moreover, fixed diameter centralizers having a diameter equal to the first diameter section 52 would be too large to extend into the second diameter section 54. Accordingly, multiple runs would be performed within the wellbore 14, increasing costs and complexity at the wellsite.

In sharp contrast to the limitations of fixed diameter centralizers, the illustrated positioning system 26B is arranged to have a diameter corresponding to the second diameter portion 54 while the positioning system 26A has a diameter corresponding to the first diameter portion 52. That is, as will be described in detail below, the extensions 60 are adjustable to correspond to a variety of different wellbore diameters, thereby increasing their flexibility in use, and moreover, enabling the same positioning systems 26 to be utilized in wellbores having a variety of diameters. In the illustrated embodiment, the axis 30 is substantially aligned with the axis 22, which substantially centers the tool 12 within the wellbore 14.

FIG. 2C illustrates the tool 12 substantially arranged within the first diameter section 52. As illustrated, the extension 60 corresponding to the positioning system 26A remains in the position illustrated in FIG. 2B such that there is contact with the wall 24. However, the extension 60 corresponding to the positioning system 26B has been adjusted to expand outwardly to contact the wall 24. Accordingly, the arrangement of the tool 12 is maintained within the wellbore 14, relative to the radial offset between the axis 30 and the axis 22. In the illustrated embodiment, the tool 12 is substantially entered in the wellbore 14. However, as will be described below, the tool 12 may be arranged at any radial offset relative to the axis 22.

It should be appreciated that while the embodiments illustrated in FIGS. 2A-2C include a substantially straight tool string 32 and wellbore 14, in various embodiments the wellbore 14 may be a deviated wellbore that has an angle or curvature and the tool string 32 may include hinges or the link to form a multi-axis tool string 32. Accordingly, in various embodiments, the radial offset of the tool string axis 30 to the wellbore axis 22 may be described with reference to a section of the tool string 32. For example, the section of the tool string 32 may correspond to an area of the tool string 32 upstream or downstream of the positioning system 26.

FIG. 3 is a schematic top plan view of an embodiment of a body sheet 70 that may be utilized to couple the positioning system 26 to portions of the tool string 32. As will be described below, the body sheet 70 may facilitate retrofitting of existing tool strings 32 to accommodate the positioning systems 26. Furthermore, in various embodiments, the body sheet 70 enables modular application of the positioning system 26. As a result, the positioning system 26, using the body sheet 70, may be positioned on tool strings having a variety of different diameters. Moreover, the positioning system 26 may be used in wellbores having a variety of different diameters. Also, different ranges may be developed for different anticipated wellbore sizes to enable operators to quickly identify body sheet configurations. The body sheet 70 may enable coupling and uncoupling of various other devices, such as tools or sensors that may be mounted directly to the body sheet 70, as will be described below.

In various embodiments, the positioning system 26 may enable a tool string having a variety of different diameters to be utilized in wellbore, which may also have a variety of different diameters. For example, in various embodiments a portion of the tool string may have a diameter of approximately 4 inches while a different portion of the tool string may have a diameter of approximately 2 inches. In certain embodiments, the tool string may be positioned into a wellbore having a diameter of approximately 5 inches. Utilizing the body sheet 70, the positioning system 26 may be coupled to each section of the tool string, even though those sections have different diameters. Accordingly, the positioning system 26 enables modular configurations to accommodate a variety of different tool string and well bore diameters, thereby improving functionality and enabling operators to use and adjustment equipment on the fly. For example, as described above, centralizers may have a fixed position for use with a fixed diameter wellbore on a fixed diameter tool string. Accordingly, if the operator were using the centralizer and ran out of certain segments of piping to form the tool string, operations would cease until new pipe was delivered. In sharp contrast, embodiments of the present disclosure would enable different sized pipe to be coupled to the tool string and then use the positioning system 26 to adjust to the size of the wellbore. In this manner, operations are more flexible and equipment may be used in a wider variety of applications, thereby reducing costs for operators.

In the illustrated embodiment, the body sheet 70 includes a plurality of sheet sections 72. The separate sections 72 are delineated by the broken lines illustrated in FIG. 3, for clarity. In various embodiments, the sheet sections 72 are rotatably coupled together, for example via a hinge or pivot coupling 74. For example, in various embodiments, different numbers of sheet sections 72 may be coupled together for anticipated sizes of tool strings 32. For example, larger diameter tool strings 32 may use five sheet sections 72 while smaller diameter tool strings 32 may use two sheet sections 72. Accordingly, the body sheet 70, and therefore the positioning system 26, may be considered a modular system that can have various components easily added and/or removed for given downhole conditions. For example, a smaller diameter tool string 32 may not use as many positioning systems 26 (or as many extensions 60 as a portion of an overall positioning system 26) as a larger diameter tool string 32. Embodiments of the present disclosure enable rapid configuration of the positioning systems 26, which may be done at the well site to reduce downtown. As such, a variety of parts and components may be delivered to the well site to facilitate construction of and use of the positioning systems 26. Advantageously, shipping to well site may also be simplified because instead of shipping a large, configured component, the smaller modular sections may be delivered. However, it should be appreciated that fully assembled positioning systems 26 may also be shipped directly to the well site.

In various embodiments, the body sheet 70 includes attachment couplings 76 arranged along the various sheet sections 72. These attachment couplings 76 may include slots, clips, threaded components, and the like to facilitate coupling of one or more adjustable arm devices (described below) to assemble the positioning system 26. Moreover, in various embodiments, the same attachment couplings 76 may be configured to couple to the clasps 78 arranged along an edge of the body sheet 70. The clasps 78 are positioned to couple the body sheet 70 to the tool string 32 in a circumferential manner, as will be illustrated below. It should be appreciated that the clasps 78 are for illustrative purposes only and that a variety of other methods may be utilized to couple various portions of the body sheet 70 and/or the sheet sections 72 together, such as threaded fittings, bolts, clips, press fittings, hooks, and the like.

While the illustrated embodiment includes the attachment couplings 76 arranged substantially symmetrically along the body sheet 70, it should be appreciated that, in various embodiments, different arrangements may be utilized. For example, a width 80 of the body sheet 70, which may be defined by the sum of the respective widths 82 of the sheet sections 72. In various embodiments, the widths 82 may vary from sheet section 72 to sheet section 72. As a result, different sheet sections 72 may have different numbers of attachment couplings 76. While rows of 3×2 attachment couplings are illustrated, it should be appreciated that other configurations may also be utilized within the scope of the present disclosure. Moreover, a length 84 of the body sheet 70 may also be variable, which may impact the number of attachment couplings 76 arranged on the various sheet sections 72, and therefore the body sheet 70.

As will be described below, the body sheet 70 may be circumferentially positioned about the tool string 32. The sheet sections 72 may pivot about one another, for example with respect to pivot axes 86 formed by the couplings 74 between the sheet sections 72. As a result, in various embodiments, the body sheet 70 may conform to various different tool string diameters and may be adjusted based on the size of the tool string diameter. Moreover, it should be appreciated that, in other embodiments, various coupling members may be arranged on the tool string 32, which may also interact with components of the body sheet 70, for example the attachment couplings 76. Accordingly, the body sheet 70 may be secured to the tool string 32 for use in downhole wellbore operations. In various embodiments, the body sheet 70 may be formed from metallic components, such as steels, steel alloys, composite materials, and the like. It should be appreciated that the materials may be particularly selected for various downhole operations. For example, sour services (e.g., service with sulfur or sulfur compounds) may be formed from corrosion resistant materials. Moreover, high temperature applications may include nickel alloys. Additionally, high pressure or high stress applications may include various high strength steels or alloys.

In various embodiments, the body sheet 70 and/or sheet sections 72 may be provided as a portion of a kit along with at least one adjustable arm device (described below). For example, the number of sheet sections 72 may be determined, based at least in part, on an anticipated tool string diameter. Thereafter, a particularly selected number of adjustment arm devices may also be provided in order to enable operations in the wellbore. Such an arrangement illustrates the modular arrangement of the components of the system. That is, the body sheet 70 may be acquired for an anticipated tool string diameter, but then one or more sheet sections 72 may be removed or added to accommodate a different tool string diameter. Furthermore, in various embodiments, adjustment arm devices may be added, removed, or replaced based on certain operating conditions. In this manner, a collection of parts or components may be provided to the user in order to perform operations under a variety of conditions.

FIG. 4 is a schematic cross sectional view of an embodiment of an adjustment arm device (AAD) 100, which may form at least a portion of the positioning system 26 and/or the extensions 60. The illustrated AAD 100 includes an arm assembly 102 facilitates radial with respect to the tool axis 30. As will be described below, in various embodiments portions of the respective arms 104 may be driven longitudinally and substantially parallel to the tool axis 30, which may change a radial position of at least a portion of the arms 104. Such movement may be automatically controlled, for example by a surface or downhole controller, and may facilitate positioning the downhole tool 12 at a predetermined radial offset from the axis 22 of the wellbore. As noted above, the radial offset may be equal to substantially zero such that the axis 22 and the axis 30 are substantially co-axial.

Returning to the arm assembly 102, the respective arms 104A, 104B include respective first ends 106A, 106B coupled to rollers 108A, 108B and an outward roller 110 (e.g., positioning component) at respective second ends 112A, 112B. In various embodiments, the arms 104A, 104B are pivotally coupled to the rollers 108A, 108B, 110 such that the arms 104A, 104B may rotate about roller axes 114A, 114B, 116. For example, a pin coupling or the like may be utilized to couple the first ends 106A, 106B to the rollers 108A, 108B and facilitate rotational movement, which may be driven by the linear movement of the rollers 108A, 108B, as will be described below. It should be appreciated that while the illustrated embodiment includes the rollers 108, in various embodiments different mechanisms may be utilized within the scope of the present disclosure. For example, a sliding sleeve arrangement may be used in place, or in addition to, the rollers. Additionally, in various embodiments, pistons, tongue and groove sliding systems, guided track assemblies, and the like may also be utilized to facilitate translating linear motion of to the respective first ends 112A, 112B.

The respective second ends 112A, 112B are coupled to the same outward roller 110, in the illustrated embodiment. However, it should be appreciated that in other embodiments that may be a pair of outward rollers 110, which may be coupled together via a linkage or the like. As noted above, a pin coupling may be positioned at the second ends 112A, 112B to facilitate rotational movement about the roller axis 116. In various embodiments, a linkage 118 couples the second ends 112A, 112B together, thereby blocking separation from the outward roller 110. Furthermore, it should be appreciated that, in certain embodiments, the linkage 118 may include respective rotational axes 120A, 120B for the second ends 112A, 112B. That is, the pin couplings may couple the second ends 112A, 112B to the linkage 118. As will be described below, movement of the first ends 106A, 106B is transmitted to the second ends 112A, 112B to change a radial position of the outward roller 110, with respect to the tool axis 30. In certain embodiments, the outward roller 110 may be driven to contact the wall 24 to position the tool 12 at the predetermined radial offset from the wellbore axis 22. Furthermore, in certain embodiments, the outward roller 110 may include a sensor 122, which may be used to perform downhole measurements, such as logging measurements. Additionally, in certain embodiments, the sensor 122 may be a force sensor to determine whether the outward roller 110 is in contact with the wall 24. If the sensor 122 determines the outward roller 110 is not in contact with the wall 24, the radial position of the outward roller 110 may be adjusted. It should be appreciated that there may be more than one sensor 122. Additionally, in various embodiments, the outward roller 110 may not be a roller, but may be a pad for conducting measurements or the like. However, in embodiments where the outward roller 110 is a roller, the roller may facilitate movement of the tool 12 along the wellbore 14. For example, the outward roller 110 may be motorized to assist with removal of the tool string 32 from the wellbore 14. In various embodiments, friction forces may be large or an impediment when removing the tool string 32 from the wellbore 14. Even when the outward roller 110 is passive, the friction forces may be reduced due to the rotating nature of the outward roller 10. Furthermore, as discussed above, motoring the outward roller 110 may further reduce the friction as the tool string 32 is withdrawn, thereby improving logging operations. Moreover, to facilitate installation and removal, gripping sequencers may be deployed in place of the outward rollers 110. Additionally, in various embodiments, different AADs 100 of the positioning system 26 may have different configurations. For example, some may have rollers, some may have pads, some may have sensors, and the like. In various embodiments, the outward roller 110 may be replaced by a clamping pad that, upon activation, may apply a force to the wall to anchor or otherwise hold the tool 12 in place. This may be utilized, for example, in other systems such as with perforating guns, downhole cutters, and the like. It should be appreciated that various aspects of the disclosure discussed herein may be adapted for this application. For example, the force generated by the outward roller 110 against the wall 24 may be increased to act as a clamping pad. Furthermore, in various embodiments, one or more AAD 100 may be configured to act as a basket to block or otherwise restrict flow in the surrounding annulus. For example, in embodiments, a pair of AADs 100 may be coupled together via the basket and, upon deployment, may block flow along with wellbore 14. Accordingly, in various embodiments the outward roller 110 may be referred to as positioning component at least because various positioning and downhole tasks may be utilized via the positioning component and, in embodiments, the positioning component may not be a roller. Therefore, various configurations may be utilized depending on the downhole operations being conducted.

In various embodiments, the roller 108A may be referred to as a drive roller 124 and the roller 108B may be referred to as a passive or driven roller 126. That is, in the illustrated embodiment, the drive roller 124 is coupled to an actuator 128, which may include a motor 130, a drive arm 132, a gearbox 134, actuator sensors 136, and actuator electronics 138. The actuator 128 is configured to convert the linear movement of the drive roller 124 into rotational movement about the roller axis 114A for the arm 104A, thereby driving the outward roller 110 radially outward from the tool axis 30. In various embodiments, the motor 130 may be a linear motor, such as a screw motor or the like, that applies a force 140 to the drive roller 124, for example via a coupling to the drive arm 132. The force 140 moves in the drive roller 124 in the downhole direction 58 as the drive roller 124 rolls within a housing 142. It should be appreciated that the housing 142 may include an opening to facilitate coupling of the arms 104A, 104B to the rollers 108A, 108B while still maintaining at least a portion of the rollers 108A, 108B within the housing 142. In various embodiments, the gearbox 134 may be utilized to adjust the force 140, which may adjust the pressure applied to the wall 24 via the outward roller 110. As such, different forces 140 may be applied for different operational situations and/or different desired outcomes. For example, a reduced force may be applied in a cased wellbore, where the walls may be substantially smooth compared to an uncased wellbore.

The illustrated actuator electronics 138 may include a battery supplying an electric force to the motor 130. The battery may be rechargeable, for example via electrical energy transmitted downhole. Additionally, in various embodiments, the battery may be omitted in place of a direct electrical coupling to the motor, which may be transmitted downhole as described above. Furthermore, in various embodiments, the actuator electronics 138 may include a communication device, which may be a wired communication device or a wireless communication device. The communication device may send or receive signals to/from the surface 18 and/or other tools forming various portions of the tool string 32, such as the commanding tool 34. The communication device may be a portion of a controller that may include a memory and processor to transmit instructions to the motor 130, for example to drive movement of the drive roller 124 to adjust the radial position of the outward roller 110 with respect to the tool axis 30. For example, applying the force 140 in the downhole direction 58 may move the outward roller 110 radially outward while applying the force 140 in the uphole direction 56 may move the outward roller 110 radially inward. It should be appreciated that instructions may be preloaded on the memory and/or transmitted in real time or near-real time (e.g., without significant delay). For example, the wellbore profile may be known before logging begins and depth sensors may be arranged within the tool string 32 to facilitate instructions to deploy the positioning system 26 at various depths. Furthermore, in embodiments, logic may be programmed into the memory of the actuator 128 to receive signals from the sensor 122 to adjust positions of the outward roller 110 upon detection that the outward roller 110 is not touching the wall 24.

The illustrated embodiment further includes the actuator sensors 136, which may be utilized, at least in part, to determine the radial position of the outward roller 110 based on a position of one or more components of the actuator 128. For example, the actuator sensor 136A may determine a linear position of the motor 130, which may be correlated to a radial position of the outward roller 110. By way of example only, the actuator sensor 136A may count the number of rotations of a screw motor to determine the linear position of the motor 130. Additionally, or in the alternative, the actuator sensor 136B may be arranged on the drive arm 132 to determine the linear position of the drive arm 132. In various embodiments, the actuator sensor 136B may be a magnetic sensor, linear variable differential transformer, or the like to determine a linear position of the drive arm 132, which may correspond to a radial position of the outward roller 110. Furthermore, in certain embodiments, the actuator sensor 136C may measure the rotation of the second end 112A about the roller axis 114A. In this manner, the radial position of the outward roller 110 may be determined. It should be appreciated that various other methods may be utilized to determine the radial position of the outward roller 110 within the scope of the present disclosure.

Returning to the arm assembly 102, the arm 102B is coupled to the driven roller 126 at the second end 112B. As described above, a pin coupling may facilitate rotation of the second end 112B about the roller axis 114B. The illustrated embodiment includes a biasing member 144 arranged within the housing 142 and opposite the actuator 128. The biasing member 144 in the illustrated embodiment is a spring, which may be referred to as a compression spring. The illustrated spring may have a spring constant associated with the material and/or number of windings of the spring that resists compression via movement of the driven roller 126 in the downhole direction 58. As such, the force 140 applied to the driven roller 126 will compress the spring when it overcomes the spring constant. Additionally, the spring will apply an opposite force (e.g., a force in the opposite direction) to drive the roller 108B in the uphole direction 56 when the opposing force is insufficient to compress in the spring. In this manner, the radial movement of the outward roller 110 may be controlled, at least in part, by the force applied by the motor 130 and the opposing force provided by the biasing member 144. It should be appreciated that the biasing member 144 may not be a spring in all embodiments, and furthermore, may be an extension spring as opposed to a compression spring. Additionally, in various embodiments, a stop or the like may be incorporated into the housing 142 to restrict movement of the driven roller 126, thereby controlling or limiting radial movement of the outward roller 110.

As described above, in various embodiments a radial position 146 of the outward roller 110 may be determined with respect to the tool axis 30. The radial position 146 may be adjusted by rotation of the arms 104A, B about respective axes 114A, 114B, 116, 120A, 120B. As described above, the radial position 146 may be particularly selected to correspond to a diameter of the wellbore 14 and provide a force in a radially outward direction 148 against the wall 24 and/or casing.

FIGS. 5A and 5B are schematic cross-sectional views of embodiments of the positioning system 26, including a plurality of AADs 100, maintaining and adjusting a radial position of the tool 12 within the wellbore 14. In the embodiment illustrated in FIG. 5A, the tool axis 30 and the wellbore axis 22 are substantially aligned, and as a result, the tool 12 may be described as being centered within the wellbore 14. The illustrated AADs 100 are arranged circumferentially about the tool string 32 and spaced substantially equally about. As shown, the illustrated body sheet 70 extends circumferentially about the tool string 32, with the individual sheet sections 72 being coupled together and pivoted relative to one another. Each sheet section 72 includes a respective AAD 100, which includes the housing 142 and the arm assembly 102. In the embodiment illustrated in FIG. 5A, the radial position 146 of the outward rollers 110 are substantially equal for each arm assembly 102, thereby aligning the tool axis 30 with the wellbore axis 22. The outward rollers 110 are arranged to contact the wall 24 and may be applying the outward radial force 148 against the wall 24 to maintain the illustrated position of the tool 12. As described above, a radial offset 160 between the wellbore axis 22 and the tool axis 30 may be substantially zero in the illustrated embodiment.

FIG. 5B illustrates an arrangement where the radial offset 160 between the wellbore axis 22 and the tool axis 30 is not substantially zero. In the illustrated embodiment, the tool axis 30 is offset from the wellbore axis 22 such that a lower portion of the tool 12 is closer to the wall 24 than an upper portion of the tool 12. As illustrated, in various embodiments the individuals AADs 100 are independently actuatable. In other words, the respective radial positions 146 of the respective outward rollers 110 may not be equal. Accordingly, different radial positions of the tool 12 may be provided.

It should be appreciated that, while the illustrated embodiments include six AADs 100, that in other embodiments more or fewer AADs 100 may be included. For example, 2, 3, 4, 5, 7, 8, 9, 10 or any reasonable number of AADs 100 may be included. Moreover, individual sheet sections 72 may include more than one AAD 100 or no AADs 100. Additionally, while the illustrated AADs 100 are equally spaced about the circumference of the tool string 32, in other embodiments the AADs 100 may not be equally spaced. For example, there may be more AADs 100 proximate a lower portion of the tool string 32 where additional forces (for example, due to gravity) are expected.

FIG. 6 is a schematic side view of an embodiment of the tool string 32 arranged within the wellbore 14. In the illustrated embodiment, there is a radial offset 160 between the wellbore axis 22 and the tool axis 30. The illustrated radial offset 160 is not substantially zero such that, in the illustrated embodiment, the tool 12 is arranged closer to lower portion of the wellbore 14 than to an upper portion of the wellbore 14. As shown, the respective positioning systems 26 are arranged on the upstream 56 and downstream 58 sides of the tool 12. The AADs 100 on the upper sides of the positioning systems 26 are extended further out, such that the radial positions 146 for the outward rollers 110 on are farther from the tool axis 30 than the radial positions 146 for the outward rollers 110 on the lower side. Accordingly, FIG. 6 illustrates that the independently actuatable AADs 100 may be configured to arranged the tool 12 radially offset from the wellbore axis 22.

As described above, in various embodiments the tool string 32 may be a multi-axis tool string 32 that includes one or more hinges such that the positioning systems 26 position the tool string axis 30 of a section of the tool string 32 at the radial offset 160 with respect to the wellbore axis 22. Moreover, in various embodiments, the wellbore 14 may have multiple sections, such as a deviated wellbore, where the axis 22 is shifted or adjusted. Accordingly, while for simplicity the tool string 32 of the illustrated embodiments have been shown in a straight wellbore 14 with a single axis tool 32, in various embodiments the positioning system 26 may be utilized to arranged a section of the tool string 32 at the radial offset 160 to a section of the wellbore axis 14. Moreover, while the illustrated embodiment includes the tool string 32 having a substantially equal outer diameter, in various embodiment different portions of the tool string may have different diameters. However, through the use of the positioning system 26, the different diameter tool strings may be utilized together because the positioning system 26 may be used to arrange the various portions of the tool string to the desired radial offset.

FIGS. 7A and 7B are schematic side views of embodiments of the tool string 32 arranged within the wellbore 14 including the positioning systems 26. In the embodiment illustrated in FIG. 7A, communication cables 170 are illustrated coupled between the commanding tool 34 and the positioning systems 26A, 26B. As described above, in various embodiments the communications between components of the tool string 32, in whole or in part, may be provided via wireless or wired communication protocols. In the illustrated embodiment, the cable 20 (which may be a wireline cable) may be utilized to transmit data or electrical energy to and/or from the tool string 32. The illustrated communication cables 170 may further be utilized to transmit data or energy between components of the tool string 32. For example, data captured by various sensors may be transmitted to the commanding tool 34 via the communication cables 170. Additionally, a signal, such as a command to activate the positioning systems 26, may be transmitted along the cable 20 to the commanding tool 34, and thereafter further relayed to the positioning systems 26A, 26B via the communication cables 170. FIG. 7B illustrates an alternative embodiment utilizing wireless communication protocols between the commanding tool 34 and the positioning systems 26A, 26B. For example, each of the commanding tool 34 and the positioning systems 26A, 26B may include wireless transceivers to facilitate transmission and reception of wireless communication signals, such as data signals. Furthermore, it should be appreciated that the systems and methods described herein may utilize a combination of wired and wireless communication protocols. For example, there may be wireless communication between the positioning systems 26A, 26B with a wired connection to the commanding tool 34 and/or the cable 20. Accordingly, data and/or energy transmission is enabled in the downhole environment.

FIG. 8 is a schematic diagram of an embodiment of a control system 180, which may be utilized to control operation of one or more components of the positioning system 26 and/or transmit data to/from the positioning system 26. In the illustrated embodiment, a controller 182 includes one or more memory devices 184 and a processor 186. The memory devices 184 may be non-transitory machine readable memory devices, such as hard disks, optical disks, solid state devices, and the like. The processor 186 may be a microprocessor that, upon receipt of instructions, which may be stored on the memory devices 184, may execute one or more commands. The processor 186 may be configured to transmit instructions or receive data, for example over a communication protocol 188, which may be a wired or wireless communication protocol such as an electrical cable, wireless internet service, radio service, mud pulse telemetry service, or the like. Additionally, it should be appreciated that multiple communication protocols 188 may be utilized. For example, certain components of the drill string 32 may communicate via a wired communication protocol, such as a wireline, while other components may communicate via a wireless communication protocol.

The sensor 122 is communicatively coupled to the communication protocol 188 and may transmit information, such as a force reading between the sensor 122 arranged on the outward roller 110. Additionally, the sensor 122 may also be utilized for downhole logging and may transmit that information uphole, for example via the communication protocol 188. Information from the sensor 122 and/or the controller 182 may be transmitted to the actuator 128, for example to the motor 130 and/or the actuator sensor 136. For example, a command to activate the motor 130 may be transmitted downhole. Moreover, a position of the motor 130, which may be correlated to a radial position 146 of the outward roller 110, may be recorded via the actuator sensor 136 and transmitted to the controller 182. In this manner, various components may send and receive data and/or commands to facilitate operation of the positioning system 26.

FIG. 9 is a flow chart of an embodiment of a method 200 for utilizing the positioning system 26. It should be appreciated for this method and all methods described herein that the steps may be performed in any order, or in parallel, unless otherwise explicitly stated. Moreover, there may be more or fewer steps and certain steps may be omitted, in certain embodiments. In this example, the size of the tool string 32 is determined (block 202). For example, the outer diameter of the tool string 32 may be measured or determined based on an anticipated borehole size. The body sheet 70 may be formed (block 204), for example based on the size of the tool string 32. For example, the size of the tool string 32 may determine a number of sheet sections 72 to couple together to form the body sheet 70. The body sheet 70 may then be coupled to the tool string 32 (block 206). In various embodiments, the clasps 78 may be utilized to couple the body sheet 70 to the tool string 32. Additionally, in various embodiments, coupling members may be arranged on the tool string 32 to interface with the attachment couplings 76. One or more AADs 100 may be installed on to the body sheet 70 (block 208). For example, the attachment couplings 76 may interface with the AADs 100 to arrange the AADs 100 long the body sheet 70. The tool string 32 may be positioned within the wellbore 14 (block 210), for example during a wireline logging operation. Thereafter, the AADs 100 may be actuated (block 212). In various embodiments, the AADs 100 position the tool 12 at a predetermined radial offset 160 from the wellbore axis 22. Accordingly, logging operations may commence with the tool 12 at a known wellbore radial position. As described above, while embodiments of the method 200 are described with reference to logging operations, it should be appreciated that other wellbore operations, such as perforating operations, wellbore interventions, and the like may also be utilized with embodiments of the present disclosure.

FIG. 10 is a flow chart of an embodiment of a method 220 for adjusting the radial position of the tool 12. In this example, instructions are received regarding the tool position (block 222). For example, the instructions may be transmitted from an operator at the surface 18. Additionally, in various embodiments, the instructions may be preloaded instructions. For example, the instructions may be stored onto the memory 184 of the controller 182 based on previous logging data regarding the wellbore diameter. Moreover, in various embodiments, the instructions may be transmitted from the sensor 122 during logging operations in real or near-real time. Upon receipt of the instructions, the AAD 100 may be actuated (block 224). For example, the motor 130 may adjust or maintain a position of the outward roller 110, based at least in part on the instructions. Thereafter, the position of the tool 12 may be evaluated (block 226). For example, the radial offset 160 of the tool axis 30 may be checked with respect to the wellbore axis 22. In various embodiments, there may be a predetermined radial offset 160. Additionally, in embodiments, the position of the tool 12 may be determined by evaluating the radial positions 160 of the AADs 100. If the tool 12 is not in the proper position, additional actuation of the AAD 100 may be performed. If the tool 12 is in the proper position, the position may be recorded (block 228). For example, in certain embodiments the logging operation being performed may be determining the wellbore diameter at various locations. Thereafter, the logging operation may be evaluated for completion (block 230). If the operation is complete, the method ends (block 232). However, if the logging operation is incomplete, additional instructions may be received for further evaluation of the tool position. In this manner, various logging operations may be performed.

FIG. 11 is a flow chart of an embodiment of a method 240 for adjusting a position of at least a portion of a tool. In this embodiment, instructions are received indicative of a desired tool position (block 242). For example, as described above, the instructions may be received from an operator at a surface location, be preloaded onto onboard memory, or the like. By way of example only, the instructions may correspond to a particular location within the wellbore (e.g., centralize the tool) or to a desired radial offset (e.g., position the tool a predetermined number of inches offset from the wellbore axis). A signal may be received that is indicative of a positioning component of the AAD 100 (block 244). In various embodiments, the positioning component may correspond to the outward roller 110. The signal may be transmitted from the sensor 122 arranged on the outward roller 110 or from the actuator sensors 136, which may be used to correlate a position of the positioning component 110 to a position of the motor 130, or the like. The radial position of the tool may be determined, at least in part, on the radial position of the positioning component 110 (block 246). For example, the position of the motor 130 may be indicative of the radial position of the positioning component 110, which when combined with a known diameter of the tool string, may be utilized to determine the radial position of the tool string. In various embodiments, the diameter of the wellbore may be known, and as a result, the radial position of the tool may be determined based on the radial position of the positioning component 110, for example, when the positioning component 110 is in contact with the wellbore wall. The position of the tool is evaluated against the instructions (248). If the tool is not in the instructed position, the AAD 110 may be actuated (block 250), which may adjust the radial position of the tool. Thereafter, additional evaluation may be performed. If the tool is in the instructed position, the system may wait for or determine whether additional instructions have been received (block 252). If not, the method ends (block 254). It should be appreciated that the instructions provided initially, or at any time, may be continuous instructions that are followed until the downhole operation ends. For example, the instruction “keep the tool centered” may be continuously monitored, for example for changes in the wellbore diameter or for deviated portions of the wellbore, and continuously adjusted to verify compliance with the instructions.

Although the technology herein has been described with reference to particular embodiments, it is to be understood that these embodiments are merely illustrative of the principles and applications of the present technology. It is therefore to be understood that numerous modifications may be made to the illustrative embodiments and that other arrangements may be devised without departing from the spirit and scope of the present technology as defined by the appended claims.

WELLBORE TOOL POSITIONING SYSTEM AND METHOD

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