Patent Publication Number: US-10781650-B2

Title: Downhole tool with multi-stage anchoring

Description:
BACKGROUND 
     Oil and gas exploration and production generally involve drilling boreholes, where at least some of the boreholes are converted into permanent well installations such as production wells, injections wells, or monitoring wells. Before or after a borehole has been converted into a permanent well installation, the borehole or casing may be modified to update its purpose and/or to improve its performance. Such borehole or casing modifications are sometimes referred to as well interventions. Some examples of well interventions involve using a coiled tubing or wireline to deploy one or more tools for matrix and fracture stimulation, wellbore cleanout, logging, perforating, completion, casing, workover, nitrogen kickoff, sand control, drilling, cementing, well circulation, fishing services, sidetrack services, mechanical isolation, and/or plugging. Other examples of well interventions involve using a slickline to deploy a tool for completion, workover, and production intervention services. 
     Sometimes the tool performing a well intervention needs to be anchored against a borehole wall or a tubular (e.g., a casing). Existing anchors designs may suffer from one or more of the following shortcomings: a limited reach, insufficient anchoring force or grip, a large profile, lack of durability, and power loss/sticking issues. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Accordingly, there are disclosed in the drawings and the following description a downhole tool with multi-stage anchoring intended to address the at least some of the above-mentioned shortcomings. In the drawings: 
         FIG. 1  is schematic diagram showing a drilling environment. 
         FIGS. 2A and 2B  are schematic diagrams showing wireline tool string environments. 
         FIGS. 3A-3D  are a cross-sectional views showing part of a downhole tool with a multi-stage anchoring device. 
         FIGS. 4A-4C  are simplified views showing default anchoring device configurations. 
         FIGS. 5A-5C  are simplified views showing extended reach anchoring device configurations. 
         FIGS. 6A-6C  are simplified views showing set anchoring device configurations. 
         FIG. 7  is a flowchart showing a well intervention method. 
     
    
    
     It should be understood, however, that the specific embodiments given in the drawings and detailed description do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and modifications that are encompassed together with one or more of the given embodiments in the scope of the appended claims. 
     DETAILED DESCRIPTION 
     Disclosed herein is a multi-stage anchoring design to provide an adjustable anchoring reach on, for example, a downhole tool. The anchoring design may be replicated as needed to provide a plurality of adjustable anchoring contact points. As an example, a downhole tool may comprise a tool body and an anchoring device. In accordance with at least some embodiments, the anchoring device is integrated with the tool body such that when the anchoring device contacts a surface (e.g., a borehole wall or tubular), the downhole tool is anchored. Such integration of the anchoring device with the tool body may include positioning at least some components of the anchoring device within the tool body to apply a radial or outward force to a contact pad (e.g., a slip) that is positioned external to the tool body. Further, such integration of the anchoring device with the tool body may include shaping or machining the tool body for use with anchoring device components. Further, such integration of the anchoring device with the tool body may include at least some components of the anchoring device being bolted, strapped, or otherwise attached to the tool body. In at least some embodiments, the anchoring device includes a contact pad positioned along the outside of the tool body, the contact pad having multiple stages with different thicknesses. The anchoring device also includes a first linear actuator and a second linear actuator. Each linear actuator corresponds to a hydraulic or electromechanical device (e.g., a motor-based actuator) with a movable element (e.g., a piston, rod, etc.). The first linear actuator is configured to move the contact pad axially with respect to the tool body to align one of the multiple stages with the second linear actuator. In other words, the first linear actuator operates to adjust the reach of the anchoring device by aligning different contact pad stages with the second linear actuator and/or with a platform associated with the second linear actuator. To move the contact pad axially forward (e.g., to align a contact pad stage with increased thickness with the second linear actuator), the first linear actuator applies a force with at least some forward axial component to its moveable component. Meanwhile, to move the contact pad axially backwards (e.g., to align a contact pad stage with decreased thickness with the second linear actuator), the first linear actuator applies a force with at least some backwards axial component to its moveable component. In some embodiments, moving the contact pad axially backwards is the result of the first linear actuator not applying any force to its moveable component and/or triggering a contact pad position release mechanism. Thus, when anchoring is complete and/or should the downhole tool lose power, the contact pad may move axially to a default axial position that minimizes an anchoring device profile. Such movement of the contact pad to a default axial position can be controlled by the first linear actuator, a tension (spring) mechanism, and/or a slip position release mechanism. 
     Once a suitable contact pad stage is aligned with the second linear actuator (i.e., once a suitable preliminary anchoring device reach has been achieved), the second linear actuator is configured to apply a radial force to the contact pad to increase a reach and/or grip of the anchoring device. More specifically, to move the contact pad radially outward, the second linear actuator applies a force with at least some outward radial component to its moveable component. Meanwhile, to move the contact pad radially inward, the second linear actuator applies a force with at least some radially inward component to the moveable component. In some embodiments, moving the contact pad radially inward is the result of the second linear actuator not applying any force to its moveable component and/or triggering a contact pad tension release mechanism. Thus, when anchoring is complete and/or should the downhole tool lose power, the contact pad may move radially to a default radial position that minimizes an anchoring device profile. Such movement of the contact pad to a default radial position can be controlled by the second linear actuator, a tension (spring) mechanism, and/or a contact pad position release mechanism. It should be noted that contact pad may have a default axial position as well as a default radial position. Such default positions may be configured before the downhole tool is deployed based on expected clearance space in a borehole or tubular. As needed, the default positions can be updated to facilitate conveyance and expedited deployment of the multi-stage anchoring device. 
     The disclosed anchoring device designs may be used with various types of downhole tools. In particular, downhole tools configured to perform well intervention operations may employ the disclosed anchoring device. For example, an anchored downhole tool may perform one or more well intervention operations including, but not limited to, matrix and fracture stimulation, wellbore cleanout, logging, perforating, completion, casing, production intervention, workover, nitrogen kickoff, sand control, drilling, cementing, well circulation, fishing services, sidetrack services, mechanical isolation, and/or plugging. Depending on the downhole operations to be performed, the anchoring specifications for each downhole tool (e.g., the number of anchoring devices used, the orientation and position of each anchoring device along a tool body, the amount of force to be applied by each linear actuator, etc.) may be adjusted. The anchoring specifications may also be adjusted depending on the size of tool body relative to a borehole or tubular size. 
     The disclosed anchoring device designs are best understood when described in an illustrative usage context.  FIG. 1  shows an illustrative drilling environment  10 , where a drilling assembly  12  enables a drill string  31  to be lowered and raised in a borehole  16  that penetrates formations  19  of the earth  18 . The drill string  31  is formed, for example, from a modular set of drill pipe sections  32  and adaptors  33 . At the lower end of the drill string  31 , a bottomhole assembly  34  with a drill bit  40  removes material from the formation  18  using known drilling techniques. The bottomhole assembly  34  also includes one or more drill collars  37  and may include a logging tool  36  to collect measure-while-drilling (MWD) and/or logging-while-drilling (LWD) measurements. 
     In  FIG. 1 , an interface  14  at earth&#39;s surface receives the MWD and/or LWD measurements via mud-based telemetry or other wireless communication techniques (e.g., electromagnetic, acoustic). Additionally or alternatively, a cable (not shown) including electrical conductors and/or optical waveguides (e.g., fibers) may be used to enable transfer of power and/or communications between the bottomhole assembly  34  and the earth&#39;s surface. Such cables may be integrated with, attached to, or inside components of the drill string  31  (e.g., IntelliPipe sections may be used). 
     The interface  14  may perform various operations such as converting signals from one format to another, filtering, demodulation, digitization, and/or other operations. Further, the interface  14  conveys the MWD and/or LWD measurements or related data to a computer system  20  for storage, visualization, and/or analysis. In at least some embodiments, the computer system  20  includes a processing unit  22  that enables visualization and/or analysis of MWD and/or LWD measurements by executing software or instructions obtained from a local or remote non-transitory computer-readable medium  28 . The computer system  20  also may include input device(s)  26  (e.g., a keyboard, mouse, touchpad, etc.) and output device(s)  24  (e.g., a monitor, printer, etc.). Such input device(s)  26  and/or output device(s)  24  provide a user interface that enables an operator to interact with the logging tool  36  and/or software executed by the processing unit  22 . For example, the computer system  20  may enable an operator to select visualization and analysis options, to adjust drilling options, and/or to perform other tasks. Further, the MWD and/or LWD measurements collected during drilling operations may facilitate determining the location of subsequent well intervention operations and/or other downhole operations, where the downhole tool is anchored as described herein. 
     At various times during the drilling process, the drill string  31  shown in  FIG. 1  may be removed from the borehole  16 . With the drill string  31  removed, wireline logging and/or well intervention operations may be performed as shown in the wireline tool string environment  11 A of  FIG. 2A  (an “openhole” scenario). In environment  11 A, a wireline tool string  60  is suspended in borehole  16  that penetrates formations  19  of the earth  18 . For example, the wireline tool string  60  may be suspended by a cable  15  having electrical conductors and/or optical fibers for conveying power to the wireline tool string  60 . The cable  15  may also be used as a communication interface for uphole and/or downhole communications. In at least some embodiments, the cable  15  wraps and unwraps as needed around cable reel  54  when lowering or raising the wireline tool string  60 . As shown, the cable reel  54  may be part of a movable logging facility or vehicle  50  having a cable guide  52 . 
     In at least some embodiments, the wireline tool string  60  includes various sections including a power section  62 , control/electronics section  64 , actuator section  66 , anchor section  68 , and intervention tool section  70 . The anchor section  68 , for example, includes one or more anchor devices as described herein to contact the wall of borehole  16 , thereby maintaining the wireline tool string  60  in a fixed position during intervention tool operations and/or other operations. While not required, the wireline tool string  60  may also include one or more logging tool sections to collect sensor-based logs as a function of tool depth, tool orientation, etc. 
     At the earth&#39;s surface, an interface  14  receives sensor-based measurements and/or communications from wireline tool string  60  via the cable  15 , and conveys the sensor-based measurements and/or communications to computer system  20 . The interface  14  and/or computer system  20  (e.g., part of the movable logging facility or vehicle  50 ) may perform various operations such as data visualization and analysis, anchoring device control, intervention tool monitoring and control, and/or other operations. 
       FIG. 2B  shows another wireline tool string environment  11 B (a “completed well” or at partially completed well scenario). In environment  11 B, a drilling rig has been used to drill borehole  16  that penetrates formations  19  of the earth  18  in a typical manner (see  FIG. 1A ). Further, a casing string  72  is positioned in the borehole  16 . The casing string  72  of well  70  includes multiple tubular casing sections (usually about 30 feet long) connected end-to-end by couplings  76 . It should be noted that  FIG. 2B  is not to scale, and that casing string  72  typically includes many such couplings  76 . Further, the well  70  includes cement slurry  80  that has been injected into the annular space between the outer surface of the casing string  72  and the inner surface of the borehole  16  and allowed to set. Further, a production tubing string  84  has been positioned in the inner bore of the casing string  72 . 
     In at least some embodiments, the purpose of the well  70  is to guide a desired fluid (e.g., oil or gas) from a section of the borehole  16  to a surface of the earth  18 . In such case, perforations  82  may be formed at a section of the borehole  16  to facilitate the flow of a fluid  85  from a surrounding formation  19  into the borehole  16  and thence to earth&#39;s surface via an opening  86  at the bottom of the production tubing string  84 . Note that this well configuration is illustrative and not limiting on the scope of the disclosure. Other permanent well configurations may be configured as injection wells or monitoring wells. 
     In environment  11 B, a wireline tool string  78  may be deployed inside casing string  72  (e.g., before the production tubing string  84  has been positioned in an inner bore of the casing string  72 ) and/or production tubing string  84 . In accordance with at least some embodiments, the wireline tool string  78  has sections similar to those described for wireline tool string  60 , but may have a different outer diameter to facilitate deployment in a tubular rather than an openhole scenario. In particular, the wireline tool string  78  includes one or more anchoring devices as described herein to contact the inner bore of casing string  72  or production tubing string  84 , thereby maintaining the wireline tool string  78  in a fixed position during intervention tool operations and/or other operations. While not required, the wireline tool string  78  may include one or more logging tool sections to collect sensor-based logs as a function of tool depth, tool orientation, etc. 
     At earth&#39;s surface, a surface interface  14  receives sensor-based measurements and/or communications from wireline tool string  78  via a cable or other telemetry, and conveys the sensor-based measurements and/or communications to computer system  20 . The surface interface  14  and/or computer system  20  may perform various operations such as data visualization and analysis, anchoring device control, intervention tool monitoring and control, and/or other operations. While  FIGS. 2A and 2B  describe deployment of downhole tools using a wireline, it should be appreciated that coiled tubing is another option for such deployment. 
       FIGS. 3A-3D  show part of a downhole tool (e.g., tools  60  or  78 ) with an anchoring device  100 . The anchoring device  100  may, for example, be part of the anchor section  66  mentioned for wireline tool string  60 . More specifically,  FIGS. 3A and 3B  show the anchoring device  100  with a multi-stage contact pad  102  in a default position, said contact pad  102  alternatively having a curved outer surface with a radius to approximately correspond to the radius of the curved inner surface of the borehole  16 ; or a flat surface as shown in  FIGS. 4A-4C, 5A-5C, and 6A-6C .  FIGS. 3C and 3D  show the anchoring device  100  with multi-stage contact pad  102  in an extended reach position. For the embodiment of  FIGS. 3A-3D , multi-stage contact pad  102  has two stages  104 A and  104 B separated by sloped section  106 , where stages  104 A and  104 B have different thicknesses to enable an adjustable anchoring reach. 
     In  FIGS. 3A and 3B , stage  104 A of the multi-stage contact pad  102  is aligned with a contact component  126  associated with linear actuator  120 . The position of the contact pad  102  in  FIGS. 3A and 3B  corresponds to a default position, where the thinnest stage of multi-stage contact pad  102  is aligned with contact component  126 . In alternative embodiments, the default position for multi-stage contact pad  102  may be any predetermined stage rather than the thinnest stage. Further, the default position for multi-stage contact pad  102  could be such that none of its stages are aligned with contact component  126 . In such case, the contact component  126  associated with linear actuator  120  could be used to contact a surface (e.g., a borehole wall or tubular) directly. However, if the anchoring reach needs to be extended, the multi-stage contact pad  102  could be moved axially to align one of its stages with the contact component  126 . 
     In  FIGS. 3A-3D , the multi-stage contact pad  102  is connected to moving element  112  of linear actuator  110  to enable axial movement of the multi-stage contact pad  102 . As described herein, such axial movement enables different stages of the multi-stage contact pad  102  to be aligned with contact component  126 . In at least some embodiments, the multi-stage contact pad  102  connects to moving element  112  via coupler  114 , which may correspond to a spring. Additionally or alternatively, the coupler  114  may correspond to a rod or beam. Further, the coupler  114  may be rotatably coupled to each of the multi-stage contact pads  102  and the moving element  112  (e.g., via pins). Regardless of the particular coupling used between linear actuator  110  and multi-stage contact pad  102 , it should be appreciated that the amount of force needed to axially move multi-stage contact pad  102  may be small. Thus, the size of linear actuator  110  and related actuation components may likewise be small. Regardless of size, the linear actuator  110  may attach to tool body  90  via straps, bolts, or other fasteners. Further, it should be appreciated that the position and reach of the linear actuator  110  may vary. The reach for linear actuator  110  is based on the size of multi-stage contact pad  102  (i.e., the size of each stage and the number of stages). Regardless of its reach, the position of linear actuator  110  can be varied by adjusting the length of coupler  114 . Further, while the linear actuator  110  is shown to be entirely external to the tool body  90  in  FIGS. 3A-3D , other variations are possible. For example, in some embodiments, at least part of linear actuator  110  may be internal to and/or integrated with the tool body  90 . Further, the angle of the linear actuator  110  may vary. Any positioning or angle for linear actuator  110  is possible as long as movement of its moving element  112  can be converted to axial movement of the multi-stage contact pad  102 . 
     In  FIGS. 3A and 3B , stage  104 A of multi-stage contact pad  102  is aligned with the contact component  126  associated with linear actuator  120 . If stage  104 A provides a suitable anchoring reach for anchoring device  100 , the linear actuator  120  may apply a radial force  130  to moving element  122  as shown in  FIG. 3B . The determination of whether the anchoring reach associated with a particular stage is suitable depends on the clearance space  94 A between tool body  90  and surface  96 A (e.g., a borehole wall or tubular), and the reach of linear actuator  120 . In  FIG. 3B , at least part of the radial force  130  applied to moving element  122  is applied to contact component  126  (e.g., through coupler  124 ) and stage  104 A. The result of applying the radial force  130  is that the anchoring device  100  anchors a downhole tool associated with tool body  90  against surface  96 A. While the linear actuator  120  is shown to be entirely internal to the tool body  90  in  FIGS. 3A-3D , other variations are possible. For example, in some embodiments, at least part of linear actuator  120  may be external to and/or integrated with the tool body  90 . Further, the angle of the linear actuator  120  may vary. Any positioning or angle for linear actuator  120  is possible as long as movement of its moving element  122  can be converted to radial movement of the multi-stage contact pad  102 . 
     The amount of radial force  130  provided by linear actuator  120  may vary depending on the type of downhole operations to be performed while a downhole tool related with tool body  90  is anchored. Without limitation, some embodiments of linear actuator  120  may provide a radial force up to and exceeding 5000 psi to moving element  122 . If hydraulic actuation is used for linear actuator  120 , a predetermined ratio of diameters between a hydraulic feedline and a piston chamber associated with linear actuator  120  enables a suitable amount of force to be achieved. As an example (without limitation to other embodiments) one embodiment uses a hydraulic feedline with a 0.25 inch diameter and a piston chamber with a 1.0 inch diameter to be used in conjunction with linear actuator  120 . 
     In accordance with at least some embodiments, the reach of linear actuator  120  is preferably small to facilitate integrating the linear actuator  120  within tool body  90 . For example, in downhole tool embodiments that employ multiple anchoring devices  100  together at the same longitudinal position along a tool body  90 , the reach would be limited such that the linear actuator  120  does not occupy more than about half of the width of the tool body&#39;s interior space. Of course, if anchoring devices  100  are longitudinally offset from each along the tool body  90 , the position of the linear actuator  120  within tool body  90  and its reach could vary. 
     Further, the tool body  90  may include a raised portion  92  for use with the anchoring device  100 . More specifically, the raised portion  92  extends the outer profile of the tool body  90  to ensure anchoring reach and packaging criteria for linear actuator  120  are met. The raised portion  92  also may facilitate sealing the interior of tool body  90 . For example, one or more seals may be positioned between contact component  126  and the raised portion  92 , and/or between linear actuator  120  and the raised portion  92 . It should be appreciated that in different embodiments, the dimensions of raised portion  92  (e.g., its outward profile and slope) may vary. Regardless of its particular dimensions, the raised portion  92  may be part an integral tool body  90 , or may correspond to a separate component that is attached to tool body  90 . 
     In  FIG. 3C , the linear actuator  110  applies an axial force  140  to moving element  112  to move the multi-stage contact pad  102  axially. Again, the multi-stage contact pad  102  and the moving element  112  may be connected via coupler  114 . More specifically, application of the axial force  140  by the linear actuator  110  causes stage  104 B of the multi-stage contact pad  102  to be aligned with the contact component  126  associated with linear actuator  120  instead of stage  104 A. In accordance with at least some embodiments, transitions between stages  104 A and  104 B are facilitated using sloped section  106 . More specifically, when stage  104 A is aligned with contact component  126 , the sloped section  106  contacts or is close to raised portion  92  of tool body  90 . Thus, when axial force  140  is applied, the sloped section  106  contacts the raised portion  92  such that the transition between stages  104 A and  104 B does not involve sharp edges or corners that are susceptible to being snagged. For a multi-stage contact pad with additional stages (3 or more stages), additional sloped sections could be used to facilitate the transition between each stage as needed. Further, in at least some embodiments, slope sections such as section  106  may also serve to provide a detectable end to each stage. Thus, the amount of axial movement provided by linear actuator  110  may be preprogrammed using known stage sizes and/or may involve detecting that a particular stage is aligned using sensors or feedback. 
     Once stage  104 B of the multi-stage contact pad  102  is aligned with contact component  126 , the radial force  130  is applied to moving element  122 , contact component  126  (e.g., through coupler  124 ), and stage  104 B. The result of applying the radial force  130  is that the anchoring device  100  anchors a downhole tool associated with tool body  90  against surface  96 B. Again, the amount of radial force  130  provided by linear actuator  120  may vary depending on the type of downhole operations to be performed while a downhole tool related with tool body  90  is anchored. Compared to using stage  104 A for anchoring, stage  104 B provides an extended anchoring reach suitable for a clearance space  94 B between tool body  90  and surface  96 B (e.g., a borehole wall or tubular) that is larger than the clearance space  94 A between tool body  90  and surface  96 A represented in  FIG. 3B . 
       FIGS. 4A-4C  show various default anchoring device configurations  200 A- 200 C. In default anchoring device configuration  200 A, two multi-stage contact pads  102  are used with a tool body  90 A having two raised portions  92 . In default anchoring device configuration  200 B, three multi-stage contact pads  102  are used with a tool body  90 B having three raised portions  92 . In default anchoring device configuration  200 C, four multi-stage contact pads  102  are used with a tool body  90 C having four raised portions  92 . In each of the default anchoring device configurations  200 A- 200 C, each of the multi-stage contact pads  102  represented are associated with an anchoring device such as anchoring device  100 . For each of the default anchoring device configurations  200 A- 200 C, the outer profile of the multi-stage contact pads  102  and related anchoring device components is minimized. As previously discussed, an alternative default anchoring configuration may correspond to any predetermined stages of multi-stage contact pads  102  being used. Alternatively, the default axial position for the multi-stage contact pads  102  may be such that no stage is aligned with the raised portions  92 . In such case, the outer profile of the raised portions  92  may be larger than the outer profile of the multi-stage contact pads  102  in their default position. In at least some embodiments, the default anchoring device configurations  200 A- 200 C correspond to axial positions for the multi-stage contact pad  102 , where the clearance space  94  between the multi-stage contact pads  102  and surface  96  is maximized to facilitate positioning the downhole tool in a borehole or tubular. 
       FIGS. 5A-5C  show various extended anchoring device configurations  300 A- 300 C. In extended anchoring device configuration  300 A, the two multi-stage contact pads  102  mentioned for default anchoring device configuration  200 A have been moved axially to align thicker stages with the two raised portions  92 . In extended anchoring device configuration  300 B, the three multi-stage contact pads  102  mentioned for default anchoring device configuration  200 B have been moved axially to align thicker stages with the three raised portions  92 . In extended anchoring device configuration  300 C, the four multi-stage contact pads  102  mentioned for default anchoring device configuration  200 C have been moved axially to align thicker stages with the four raised portions  92 . In at least some embodiments, the extended anchoring device configurations  300 A- 300 C correspond to axial positions for the multi-stage contact pads  102 , where the clearance space  94  between the multi-stage contact pads  102  and surface  96  is minimized to facilitate anchoring the downhole tool in a borehole or tubular. However, it should be appreciated that minimizing the amount of clearance space  94  between each multi-stage contact pad  102  and surface  96  does not anchor the downhole tool corresponding to tool bodies  90 A- 90 C. 
       FIGS. 6A-6C  show various set anchoring device configurations  400 A- 400 C. In set anchoring device configuration  400 A, a radial force  130  is applied to the two multi-stage contact pads  102  mentioned for extended anchoring device configuration  300 A. When applied, the radial force  130  anchors a downhole tool corresponding to tool body  90 A by pushing the two multi-stage contact pads  102  against surface  96 . Application of the radial force  130  to the extended reach anchoring device configuration  300 A results in suitably strong two-sided anchoring even if the reach of radial force  130  is small. 
     In set anchoring device configuration  400 B, a radial force  130  is applied to the three multi-stage contact pads  102  mentioned for extended anchoring device configuration  300 B. When applied, the radial force  130  anchors a downhole tool corresponding to tool body  90 B by pushing the three multi-stage contact pads  102  against surface  96 . Application of the radial force  130  to the extended reach anchoring device configuration  300 B results in suitably strong three-sided anchoring even if the reach of radial force  130  is small. 
     In set anchoring device configuration  400 C, a radial force  130  is applied to the four multi-stage contact pads  102  mentioned for extended anchoring device configuration  300 C. When applied, the radial force  130  anchors a downhole tool corresponding to tool body  90 C by pushing the four multi-stage contact pads  102  against surface  96 . Application of the radial force  130  to the extended reach anchoring device configuration  300 C results in suitably strong four-sided anchoring even if the reach of radial force  130  is small. 
     While  FIGS. 4A-4C, 5A-5C, and 6A-6C  show anchoring device configurations, where axial and radial movement of multi-stage contact pads  102  occur together, it should be appreciated that individual multi-stage contact pads  102  can be axially or radially moved as needed. Further, each of the configurations  200 A- 200 C,  300 A- 300 C, and  400 A- 400 C of  FIGS. 4A-4C, 5A-5C, and 6A-6C  represents only one “layer” of anchoring. In practice, a downhole tool (e.g., tool  60  or  78 ) may have multiple layers of anchor units. For example, multiple anchoring devices  100  may be positioned along a downhole tool. The number of anchoring devices  100  for each layer may vary as noted herein. Further, the orientation of anchoring devices  100  for each layer may vary such that the contact point options vary with respect to azimuth (increasing stability of the anchor and providing selectable anchor options). Finally, other embodiments are possible as well including anchoring device configurations using five or more contact pads  102 . 
       FIG. 7  shows a well intervention method  500 . The method  500  may be performed, for example, by a downhole tool (e.g., part of wireline tool string  60  or  78 ). At block  502 , an anchor instruction is received. The anchor instruction may be received (e.g., by wireline tool string  60  or  78 ) from a surface computer (e.g., computer  70 ) with programming and/or an operator that selects when the downhole tool is to be anchored. Additionally or alternatively, the downhole tool may receive the anchor instruction from an embedded processing system (e.g., part of control/electronics section  64  of wireline tool string  60 ) that determines when the downhole tool is to be anchored using sensor-based data collected downhole. In at least some embodiments, the anchor instruction initiates a multi-stage contact pad procedure, where a multi-stage contact pad is first moved axially (e.g., using linear actuator  110 ) to align a particular stage with a linear actuator (e.g., linear actuator  120 ) at block  504 . After alignment, the multi-stage contact pad procedure operates the linear actuator (e.g., linear actuator  120 ) to apply a radial force to the multi-stage contact pad to anchor a corresponding downhole tool at block  506 . At block  508 , an operation is performed with the downhole tool is anchored. Example operations include, but are not limited to, setting or removing a plug (e.g., for hydraulic fracturing operations), shifting a sleeve (e.g., a filter or screening sleeve), and cutting or milling a damaged tubular. 
     Embodiments Disclosed Herein Include: 
     A: A downhole tool that comprises a tool body and an anchoring device integrated with the tool body. The anchoring device comprises a contact pad that is at least partially external to the tool body, the contact pad having multiple stages with different thicknesses. The anchoring device also includes a first linear actuator and a second linear actuator. The first linear actuator is configured to move the contact pad axially with respect to the tool body to align one of the multiple stages with the second linear actuator. The second linear actuator is configured to apply a radial force to the contact pad. 
     B: A method that comprises receiving, by a tool deployed in a downhole environment, an anchor instruction. The method also comprises, in response to receiving the anchor instruction, adjusting alignment of a contact pad relative to a linear actuator integrated with a tool body of the tool, wherein the contact pad has multiple stages with different thicknesses. The method also comprises operating the linear actuator to apply an outward force to the contact pad to anchor the tool against a borehole wall or tubular. The method also comprises performing an operation while the tool is anchored. 
     Each of the embodiments, A and B, may have one or more of the following additional elements in any combination. Element 1: the contact pad has an inclined surface between adjacent stages. Element 2: the anchoring device further comprises a shaft coupling the first linear actuator with the contact pad. Element 3: the shaft is rotatably-coupled at opposite ends to the first linear actuator and the contact pad. Element 4: the anchoring device further comprises a spring between the shaft and the first linear actuator. Element 5: the tool body comprises a raised portion, and wherein the contact pad passes over the raised portion when changing which of the multiple stages is aligned with the second linear actuator. Element 6: the second linear actuator comprises a hydraulic actuator. Element 7: the hydraulic actuator has a hydraulic feedline and piston chamber with a predetermined diameter relationship. Element 8: further comprising a well intervention component that is activated after the anchoring device anchors the tool against a borehole wall or tubular. Element 9: further comprising a plurality of said anchoring device to anchor the tool at different longitudinal or azimuthal positions against a borehole wall or tubular. Element 10: further comprising at least one controller to direct the first linear actuator and the second linear actuator in accordance with a multi-stage contact pad procedure. Element 11: the radial force is approximately perpendicular to a longitudinal axis of the tool body. 
     Element 12: adjusting alignment of the contact pad comprises operating another linear actuator to move the contact pad axially with respect to the tool body. Element 13: adjusting alignment of the contact pad comprises progressing from one stage thickness to another stage thickness until a thickest stage available for use is determined. Element 14: adjusting alignment of the contact pad comprises engaging at least one inclined surface of the contact pad with a raised portion of the tool body. Element 15: the linear actuator in a hydraulic actuator. Element 16: performing an operation while the tool is anchored comprises performing a well intervention operation. Element 17: further comprising adjusting alignment of at least one additional contact pad relative to corresponding linear actuators integrated with the tool body and operating the corresponding linear actuators to apply an outward force to each additional contact pad, where each additional contact pad has multiple stages with different thicknesses. Element 18: further comprising deploying the tool in the downhole environment using a wireline or coiled tubing. 
     Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.