Apparatus and method for mudcake removal

Abstract

Use of a drilling fluid during wellbore drilling operations may result in a layer of drilling fluid particles and other solids, that build up on a sidewall of a wellbore and penetrate radially into a near wellbore zone of the sidewall. Disclosed is an apparatus which includes a downhole tool operable to be conveyed within a wellbore and remove mudcake from a sandface of the wellbore when the downhole tool is being conveyed within the wellbore, where the downhole tool includes a body, a plurality of scrapers that contact the sandface and remove the mudcake from the sandface when the downhole tool is being conveyed within the wellbore, and a plurality of arms each carrying a corresponding one of the scrapers, wherein each arm is operable to extend away from the body such that the scraper contacts the sandface when the downhole tool is being conveyed within the wellbore.

Description

APPARATUS AND METHOD FOR MUDCAKE REMOVALCross-Reference to the Related Application

[0001] This application claims the benefit of U.S. Provisional Application No. 63 / 612,391, filed December 20, 2023.Background of the Disclosure

[0002] Wells are constructed at Earth’s surface or ocean bed and through subterranean geological formations to facilitate recovery of a reservoir fluid comprising oil and / or gas trapped within a subterranean reservoir. Well construction operations may be performed at a wellsite by a well construction system having various surface and subterranean well construction equipment operating in a coordinated manner. For example, a drive mechanism, such as a top drive located at a wellsite surface, may be utilized to rotate and advance a drill string into the subterranean formation to drill a wellbore. The drill string may include a plurality of drill pipes coupled together and terminating with a drill bit. Length of the drill string may be increased by adding additional drill pipes as depth of the wellbore increases. Drilling fluid may be pumped from the wellsite surface down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit and carries drill cuttings from the wellbore to the wellsite surface. The drilling fluid returning to the wellsite surface may then be cleaned and again pumped through the drill string. After the wellbore is drilled, various formation testing tools (e.g., wireline formation testers) may be conveyed within the wellbore to measure properties of the geological formation, such as to evaluate well productivity.

[0003] Using a drilling fluid during drilling operations results in a layer of mudcake (i.e., drilling fluid particles and other solids) building up or otherwise accumulating on a sandface (or a sidewall) of the wellbore and penetrating into the near wellbore zone of the sandface. Mudcake on the sandface and in the near wellbore zone will create positive skin and a corresponding additional pressure drop across the formation that can skew or otherwise negatively affect measurements of formation properties performed by the formation testing tools.Brief Description of the Drawings

[0004] The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standardpractice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

[0005] FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0006] FIG. 2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0007] FIG. 3 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0008] FIG. 4 is a schematic axial view of the apparatus shown in FIG. 3.

[0009] FIG. 5 is a schematic side view of the apparatus shown in FIG. 3 in a different stage of operations.

[0010] FIG. 6 is a schematic axial view of the apparatus shown in FIG. 5.

[0011] FIG. 7 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0012] FIG. 8 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0013] FIG. 9 is a schematic bottom view of the apparatus shown in FIG. 8.

[0014] FIG. 10 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

[0015] FIG. 11 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.Detailed Description

[0016] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for simplicity and clarity and does not in itself dictate a relationship between the various embodiments and / or configurations discussed. Moreover, the description of a first feature in contact with a second feature in the description that follows may include implementations in which the first and second features are in direct contact, and may also includeimplementations in which additional features may interpose the first and second features, such that the first and second features may not be in direct contact.

[0017] Furthermore, terms, such as upper, upward, above, lower, downward, and / or below are utilized herein to indicate relative positions and / or directions between apparatuses, tools, components, parts, portions, members and / or other elements described herein, as shown in the corresponding figures. Such terms do not necessarily indicate relative positions and / or directions when actually implemented. Such terms, however, may indicate relative positions and / or directions with respect to a wellbore when an apparatus according to one or more aspects of the present disclosure is utilized or otherwise disposed within the wellbore. For example, the terms upper and upward may mean in the uphole direction, and the terms lower and downward may mean in the downhole direction.

[0018] FIG. 1 is a schematic view of an example wellsite system 100 to which one or more aspects of the present disclosure may be applicable. The wellsite system 100 may be onshore or offshore. In the example wellsite system 100 shown in FIG. 1, a wellbore 102 is formed in one or more subterranean formations 106 by rotary drilling. Other example systems within the scope of the present disclosure may also or instead utilize directional drilling. Although some elements of the wellsite system 100 are depicted in FIG. 1 and described below, it is to be understood that the wellsite system 100 may include other components in addition to, or instead of, those presently illustrated and described.

[0019] As shown in FIG. 1, a drill string 112 suspended within the wellbore 102 comprises a bottom hole assembly (BHA) 140 that includes or is coupled with a drill bit 142 at its lower end. The surface system includes a platform and a support structure 110 (e.g., a mast, a derrick) positioned over the wellbore 102. The platform and support structure 110 may comprise a rotary table 114, a kelly 116, a hook 118, and a rotary swivel 120. The drill string 112 may be suspended from a lifting gear (not shown) via the hook 118, with the lifting gear being coupled to the support structure 110 rising above the wellsite surface 104. An example lifting gear includes a crown block affixed to the top of the mast, a vertically traveling block to which the hook 118 is attached, and a cable passing through the crown block and the vertically traveling block. In such an example, one end of the cable is affixed to an anchor point, whereas the other end is affixed to a winch to raise and lower the hook 118 and the drill string 112 coupled thereto. The drill string 112 comprises one or more types of tubular members, such as drill pipes, threadedly attached one to another, perhaps including wired drilled pipe.

[0020] The drill string 112 may be rotated by the rotary table 114, which engages the kelly 116 at the upper end of the drill string 112. The drill string 112 is suspended from the hook 118 in a manner permitting rotation of the drill string 112 relative to the hook 118. Other example wellsite systems within the scope of the present disclosure may utilize a top drive system to suspend and rotate the drill string 112, whether in addition to or instead of the illustrated rotary table system.

[0021] The surface system may further include drilling fluid or mud 126 stored in a pit or other container 128 formed at the wellsite. The drilling fluid 126 may be oil-based mud (OBM) or water-based mud (WBM). A pump 130 delivers the drilling fluid 126 to the interior of the drill string 112 via a hose or other conduit 122 coupled to a port in the rotary swivel 120, causing the drilling fluid to flow downward through the drill string 112, as indicated in FIG. 1 by directional arrow 132. The drilling fluid exits the drill string 112 via ports in the drill bit 142, and then circulates upward through the annulus region between the outside of the drill string 112 and a sandface (or sidewall) 103 of the wellbore 102, as indicated in FIG. 1 by directional arrows 134. In this manner, the drilling fluid 126 lubricates the drill bit 142 and carries formation cuttings up to the wellsite surface 104 as it is returned to the container 128 for recirculation.

[0022] The BHA 140 may comprise one or more specially made drill collars near the drill bit 142. Each such drill collar may comprise one or more devices permitting measurement of downhole drilling conditions and / or various characteristic properties of the subterranean formation 106 intersected by the wellbore 102. For example, the BHA 140 may comprise one or more logging-while-drilling (LWD) modules 144, one or more measurement -while-drilling (MWD) modules 146, a rotary-steerable system and motor 148, and perhaps the drill bit 142. Other BHA components, modules, and / or tools are also within the scope of the present disclosure, and such other BHA components, modules, and / or tools may be positioned differently in the BHA 140 than as depicted in FIG. 1.

[0023] The LWD modules 144 may comprise one or more devices for measuring characteristics of the formation 106, including for obtaining a sample of fluid from the formation 106. The MWD modules 146 may comprise one or more devices for measuring characteristics of the drill string 112 and / or the drill bit 142, such as for measuring weight-on-bit, torque, vibration, shock, stick slip, tool face direction, and / or inclination, among other examples.

[0024] The wellsite system 100 also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment 190, control devices andelectronics in one or more modules of the BHA 140 (such as a downhole controller 150), a remote computer system (not shown), communication equipment, and other equipment. The data processing system may include one or more computer systems or devices and / or may be a distributed computer system. For example, collected data or information may be stored, distributed, communicated to wellsite personnel, and / or processed locally or remotely.

[0025] The data processing system may, individually or in combination with other system components, perform the methods and / or processes described below, or portions thereof. Methods and / or processes within the scope of the present disclosure may be implemented by one or more computer programs that run in a processor located, for example, in one or more modules of the BHA 140 and / or the surface equipment 190. Such programs may utilize data received from the BHA 140 via mud-pulse telemetry and / or other telemetry means, and / or may transmit control signals to operative elements of the BHA 140. The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the BHA 140 and / or surface equipment 190, or may be stored on an external, tangible, non-transitory, computer-usable storage medium that is electronically coupled to such processor(s). The storage medium may be one or more known or future-developed storage media, such as a magnetic disk, an optically readable disk, flash memory, or a readable device of another kind, including a remote storage device coupled over a communication link, among other examples.

[0026] FIG. 2 is a schematic view of another example wellsite system 200 to which one or more aspects of the present disclosure may be applicable. The wellsite system 200 may be onshore or offshore. In the example wellsite system 200, a tool string 204 is conveyed into the wellbore 102 via a conveyance means 208, which may be or comprise a wireline, a slickline, or a fluid conduit, such as coiled tubing, completion tubing, a liner, or a casing. As with the wellsite system 100 shown in FIG. 1, the example wellsite system 200 may be utilized for evaluation of the wellbore 102 and / or the formation 106 penetrated by the wellbore 102.

[0027] The tool string 204 is suspended in the wellbore 102 from the lower end of the conveyance means 208, which may be a multi -conductor logging cable spooled on a surface winch (not shown). The conveyance means 208 may include at least one conductor that facilitates data communication between the tool string 204 and surface equipment 290 disposed on the wellsite surface 104. The surface equipment 290 may have one or more aspects in common with the surface equipment 190 shown in FIG. 1.

[0028] The tool string 204 and conveyance means 208 may be structured and arranged with respect to a service vehicle (not shown) at the wellsite. For example, the conveyance means 208 may be connected to a drum (not shown) at the wellsite surface 104, such that rotation of the drum may raise and lower the tool string 204. The drum may be disposed on a service vehicle or a stationary platform. The service vehicle or stationary platform may further contain the surface equipment 290.

[0029] The tool string 204 comprises one or more elongated housings encasing or otherwise carrying various electronic components and modules. For example, the illustrated tool string 204 includes several modules 212. Other implementations of the downhole tool string 204 within the scope of the present disclosure may include additional or fewer components or modules.

[0030] The wellsite system 200 also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment 290, control devices and electronics in one or more modules of the tool string 204 (such as a downhole controller 216), a remote computer system (not shown), communication equipment, and other equipment. The data processing system may include one or more computer systems or devices and / or may be a distributed computer system. For example, collected data or information may be stored, distributed, communicated to wellsite personnel, and / or processed locally or remotely.

[0031] The data processing system may, whether individually or in combination with other system components, perform the methods and / or processes described below, or portions thereof. Methods and / or processes within the scope of the present disclosure may be implemented by one or more computer programs that run in a processor located, for example, in one or more modules 212 of the tool string 204 and / or the surface equipment 290. Such programs may utilize data received from the downhole controller 216 and / or other modules 212 via the conveyance means 208, and may transmit control signals to operative elements of the tool string 204. The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the downhole controller 216, other modules 212 of the tool string 204, and / or the surface equipment 290, or may be stored on an external, tangible, non-transitory, computer-usable storage medium that is electronically coupled to such processor(s). The storage medium may be one or more known or future-developed storage media, such as a magnetic disk, an optically readable disk, flash memory, or a readable device of another kind, including a remote storage device coupled over a communication link, among other examples.

[0032] Although FIGS. 1 and 2 illustrate example wellsite systems 100 and 200, respectively, which convey a downhole tool / string into the wellbore 102, other example implementations consistent with the scope of this disclosure may utilize other conveyance means to convey tools / strings into the wellbore 102. Additionally, other downhole tools within the scope of the present disclosure may comprise components in a non-modular construction also consistent with the scope of this disclosure.

[0033] The use of a drilling fluid during wellbore drilling operations can result in a layer of drilling fluid particles and other solids, referred to as mudcake (or filtercake), to build up or otherwise accumulate on a sandface (or sidewall) of a wellbore and penetrate radially into a near wellbore zone of the sandface. FIGS. 3-6 are schematic views of at least a portion of an example implementation of a downhole string 300 configured to be conveyed within a wellbore 102 and to remove mudcake 105 from a sandface 103 of the wellbore 102 to form a clean zone (or segment) 107 along a predetermined portion of the wellbore 102. The downhole string 300 may then perform a formation test along the clean zone 107 to measure a property of a subterranean formation 106 penetrated by the wellbore 102. FIGS. 3 and 4 are schematic side and axial views of the downhole string 300 conveyed within the wellbore 102. FIGS. 5 and 6 are schematic side and axial views of the downhole string 300 conveyed within the wellbore 102 while performing downhole operations, including removing the mudcake 105 from the sandface 103 of the wellbore 102 to form the clean zone 107 and performing the formation test along the clean zone 107. The downhole string 300 may be an example implementation and may comprise one or more features of one or more of the BHA 140 shown in FIG. 1, and / or one or more of the tool string 204 shown in FIG. 2. The tools 306, 308, 310 may be example implementations and may comprise one or more features of one or more of the LWD modules 144 or MWD modules 146 shown in FIG. 1, and / or one or more of the modules 212 shown in FIG. 2. The downhole string 300 may thus be conveyed within the wellbore 102 via a conveyance means 302, such as a drill string, a liner, a casing string, coiled tubing, completion tubing, a wireline, and / or a slickline, among other examples. Accordingly, the following description refers to FIGS. 1-6, collectively.

[0034] The downhole string 300 may be conveyed within the wellbore 102 in a downhole (or downward) direction, as indicated by directional arrow 305, and in an uphole (or upward) direction, as indicated by directional arrow 307. The downhole string 300 may be conveyed within the wellbore 102 via the wellsite system 100 shown in FIG. 1 or the wellsite system 200 shown in FIG. 2. The downhole string 300 may comprise a plurality of downhole tools 306, 308,310, each configured to be conveyed within the wellbore 102 and operate together in a coordinated manner to form the clean zone 107 and then perform the formation test along the clean zone 107. The downhole string 300 (including each of the downhole tools 306, 308, 310) may comprise a longitudinal (e.g, central) axis 301. The downhole string 300 may be conveyed within the wellbore 102 along its axis 301.

[0035] The conveyance means 302 may comprise one or more insulated electrical and / or optical conductors 303 operable to transmit electrical energy (i.e., electrical power) and electrical and / or optical signals (e.g., sensor data, control data, etc.) between the downhole tools 306, 308, 310 of the downhole string 300 and one or more components of the surface equipment 190, 290. The conductors 303 may extend through and / or form a portion of each downhole tool 306, 308, 310 of the downhole string 300. The conductors 303 may facilitate communication between the downhole tools 306, 308, 310 and the surface equipment 190, 290. Thus, one or more of the downhole tools 306, 308, 310 of the downhole string 300 may be electrically connected with one or more components of the surface equipment 190, 290 via the conductors 303. For example, the conductors 303 may transmit and / or receive electrical power, sensor data, and / or control data between the surface equipment and one or more of the downhole tools 306, 308, 310. The conductors 303 may further facilitate (e.g, electrical and / or optical) communication between two or more of the downhole tools 306, 308, 310. The conductors 303 extending through the downhole tools 306, 308, 310 may be or comprise one or more electrical paths comprising a plurality of interconnected electrical conductors, connectors, and / or interfaces collectively forming the electrical path extending through the downhole string 300.

[0036] An upper portion (or end) of the downhole string 300 may comprise a connection sub (or tool) 304 configured to connect the conveyance means 302 with the downhole string 300 to facilitate downhole conveyance of the downhole string 300 via the conveyance means 302. The connection sub 304 may be configured to mechanically connect the conveyance means 302 with the downhole string 300 and facilitate electrical and / or communicative connection between the conductors 303 of the conveyance means 302 and the conductors 303 of the downhole string 302. For example, when the conveyance means 302 is implemented as a conveyance line, such as a wireline, a slickline, coiled tubing, and / or completion tubing, the connection sub 304 may be or comprise a cable head configured to connect with the conveyance line. When the conveyance means 302 is implemented as tubular joint string, such as a drill string or a casing string, theconnection sub 304 may be or comprise a crossover or other threaded connector head configured to connect with the tubular joint string.

[0037] The downhole tool 306 may be or comprise a telemetry / positioning tool 306, such as may facilitate communication between the downhole string 300 and the surface equipment 190, 290 and / or facilitate positioning (e.g, depth, orientation, etc.) of the downhole string 300. The telemetry / positioning tool 306 may comprise a downhole controller 312 communicatively connected with the surface equipment 190, 290 via the conductors 303 and with other downhole tools 308, 310 of the downhole string 300. The downhole controller 312 may be operable to receive, store, and / or process control commands from the surface equipment 190, 290 for controlling one or more of the downhole tools 308, 310, including to cause the downhole tools 308, 310 of the downhole string 300 to perform one or more example methods described herein. The downhole controller 312 may be further operable to store and / or communicate to the surface equipment 190, 290 sensor data generated by one or more sensors or instruments of the downhole string 300. Thus, one or more portions of the downhole string 300 may be automatically controlled by the surface equipment 190, 290 and / or downhole controller 312 and / or manually controlled by wellsite personnel from the wellsite surface 104 via the surface equipment 190, 290.

[0038] The telemetry / positioning tool 306 may further comprise inclination and / or orientation sensors 314, such as one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and / or other sensors for determining inclination and / or orientation of the downhole string 300 relative to the wellbore 102. The telemetry / positioning tool 306 may further comprise a depth correlation sensor (or tool) 316 (e.g., a gamma ray (GR) tool) for determining depth (e.g., true vertical depth, total depth, etc.) of the downhole string 300 or portions thereof within the wellbore 102. The sensors 314, 316 may be utilized to detect and / or log the inclination, orientation, and / or depth of the downhole string 300 within the wellbore 102, such as during conveyance within the wellbore 102 or other downhole operations. The sensors 314, 316 may be communicatively connected with the downhole controller 312 and / or the surface equipment 190, 290 via the conductors 303.

[0039] The downhole tool 308 may be or comprise a mudcake removal (or scraping) tool 308 configured to be conveyed within the wellbore 102 and remove the mudcake 105 from the sandface 103 of the wellbore 102 to form the clean zone 107 when the downhole string 300 (including the mudcake removal tool 308) is being conveyed within the wellbore 102. Themudcake removal tool 308 may comprise a body (or housing) 320 containing various actuators, sensors, mechanical components (e.g., gears, linkages, etc.), electrical components (e.g., switches, conductors, etc. , and other parts operating together in a coordinated manner to facilitate intended operations of the mudcake removal tool 308. The mudcake removal tool 308 may further comprise a plurality of scrapers 322 each configured to contact the sandface 103 of the wellbore 102 to remove the mudcake 105 from the sandface 103 when the downhole string 300 is being conveyed within the wellbore 102. Each scraper 322 may comprise an edge 325 configured to contact the sandface 103 and scrape the mudcake 105 off of the sandface 103 when the downhole string 300 is being conveyed within the wellbore 102. The edge 325 may be curved or comprise a curve configured to accommodate curvature of the sandface 103.

[0040] The mudcake removal tool 308 may further comprise a plurality of arms 324 each carrying a corresponding one of the scrapers 322 and an actuator 326 operatively connected with the arms 314. The actuator 326 may be operable to extend the arms 324 away from the body 320 in a radially outward direction with respect to the axis 301, as indicated by directional arrows 321, such that a corresponding one of the scrapers 322 is away from the body 320 and contacts the sandface 103. The actuator 326 may be further operable to retract the arms 324 toward the body 320 in a radially inward direction with respect to the axis 301, as indicated by directional arrows 323, such that the scraper 322 is adjacent the body 320 and away from the sandface 103. Thus, each arm 324 may be selectively operable to move between a retracted position (shown in FIGS. 3 and 4) in which the scrapers 322 are disposed against (or adjacent) the body 320 and away from the sandface 103, and an extended position (shown in FIGS. 5 and 6) in which the scrapers 322 are away from the body 320 and in contact with the sandface 103. The actuator 326 may comprise a hydraulic ram, a hydraulic motor, a linear electric actuator, and / or an electric motor, among other examples. Although FIGS. 4 and 6 show the mudcake removal tool 308 comprising four arms 324, the mudcake removal tool 308 may comprise two, three, four, five, six, or more arms 324, each carrying a corresponding scraper 322. In an example implementation, the mudcake removal tool 308 may be or comprise a caliper tool (e.g., a powered positioning device and caliper tool (PPC)) comprising arms or a centralizer tool comprising arms, each arm adapted to detachably connect with or otherwise carry a corresponding scraper 322 and move (i.e., extend and retract) as described herein.

[0041] The arms 324 of the mudcake removal tool 308 may be operable to apply (or impart) an intended (e.g., predetermined, selected, etc.) outward radially force against the sandface 103of the wellbore 102. The radial force may be selected based on several considerations. For example, the radial force may be selected based on structural properties or limits of the arms 324, such as may prevent bending or other damage to the arms 324. The radial force may be selected based on properties of the formation 106, such as to prevent damaging the sandface 103. The radial force may be selected based on downhole conditions (e.g., density, viscosity, and / or composition of wellbore fluid within the wellbore 102, friction properties of the sandface 103), such as to facilitate uninhibited axial movement of the downhole string 300 along the wellbore 102 (e.g., by preventing or inhibiting friction that may cause the downhole string 300 to stall within the wellbore 102). The mudcake removal tool 308 may be further operable to perform a sandface stress test, in which the scrapers 322 are used to induce damage to the sandface 103 to weaken the near wellbore zone and create imperfections on the sandface 103, such as to reduce breakdown pressure of the formation 106. Thus, the radial force applied by the mudcake removal tool 308 against the sandface 103 of the wellbore 102 may be selected based on predetermined parameters of the sandface stress test, such as to facilitate performance of the sandface stress test. The arms 324 may also be operable to maintain the intended radial force applied to the sandface 103 at a substantially constant level while the downhole string 300 is conveyed along the wellbore 102 and inner cross-sectional diameter of the wellbore 102 changes. For example, the arms 324 may apply substantially the same intended radial force against the sandface 103 while the mudcake removal tool 308 passes from a narrower section of the wellbore 102 to a wider section of the wellbore 102. The radial force applied by the mudcake removal tool 308 may be set e.g., implemented, programmed, calibrated) while the mudcake removal tool 308 is at the wellsite surface 104. The radial force applied by the mudcake removal tool 308 may be set while the mudcake removal tool 308 is conveyed within the wellbore 102 from the wellsite surface 104. The radial force applied by the mudcake removal tool 308 may be changed while the mudcake removal tool 308 is being conveyed within the wellbore 102, such as when downhole conditions change. In an example implementation of the mudcake removal tool 308, the radial force applied by the scrapers 322 of the mudcake removal tool 308 against the sandface 103 may range between about 140 kilograms force (kgf) and 190 kgf

[0042] The mudcake removal tool 308 may further comprise one or more sensors 327 operable to output sensor data indicative of a radial position (i.e., lateral position, extension, etc.) of the arms 324 and / or the radial force applied by the arms 324 to the sandface 103. The sensors 327 may thus output sensor data indicative of the radial position of the scrapers 322 and / or theradial force applied by the scrapers 322 to the sandface 103. The sensors 327 may be or comprise a linear encoder, a linear potentiometer, a capacitive sensor, an inductive sensor, a magnetic sensor, a linear variable-differential transformers (LVDT), a proximity sensor, a Hall effect sensor, and / or a reed switch, among other examples. The sensors 327 may also or instead be or comprise a force sensor, such as a load cell, a strain gauge, and / or a fluid pressure sensor, among other examples.

[0043] The mudcake removal tool 308 may further comprise a downhole controller 328 communicatively connected with the sensors 327 and the actuator 326 via the conductors 303. The downhole controller 328 may be communicatively connected with the surface equipment 190, 290 directly via the conductors 303 or indirectly via the downhole controller 312. The downhole controller 328 may be operable to store and / or communicate to the surface equipment sensor data generated by the sensors 327. The downhole controller 328 may be further operable to receive, store, and / or process control commands from the surface equipment 190, 290 for controlling the mudcake removal tool 308 to cause the mudcake removal tool 308 to perform one or more example methods described herein, including to cause the actuator 326 to move the arms 324 between the retracted and extended positions.

[0044] The downhole tool 310 may be or comprise a formation testing tool 310 (e.g., a wireline formation tester (WFT)) operable to perform a formation test to measure or otherwise facilitate measurement of a property of the formation 106 along the clean zone 107 of the wellbore 102. The formation testing tool 310 may comprise a body (or housing) 334 containing various actuators, sensors, mechanical components (e.g., gears, linkages, etc.), electrical components (e.g., switches, conductors, etc.), and other parts operating together in a coordinated manner to facilitate intended operations of the formation testing tool 310. The formation testing tool 310 may further comprise a dual-packer system, having an upper packer 330 and a lower packer 332. The packers 330, 332 may be operated between a retracted (e.g., a deflated) position (shown in FIGS. 3 and 4) in which the packers 330, 332 are disposed against (or adjacent) the body 334 of the formation testing tool 310 and away from the sandface 103 of the wellbore, and an expanded (e.g., an inflated) position (shown in FIG. 5) in which the packers 330, 332 extend away from the body 334 of the formation testing tool 310 and are in contact with the sandface 103 along the clean zone 107 of the wellbore 102. To permit axial view of the arms 324 and scrapers 322 in their extended positions, FIG. 6 does not show the packers 330, 332. When the packers 330, 332 are in the expanded position, the packers 330, 332 collectively isolate (or seal)an interval 108 of the wellbore 102 defined between the packers 330, 332. The formation testing tool 310 may further comprise a hydraulic pump 338 fluidly connected with the packers 330, 332 via a plurality of fluid conduits and operable to pump a hydraulic fluid into the packers 330, 332 via the fluid conduits to expand the packers 330, 332 in a radially outward direction with respect to the axis 301, as indicated by the arrows 321, from the retracted position to the expanded position. The hydraulic pump 338 may be further operable to pump the hydraulic fluid out of the packers 330, 332 to retract the packers 330, 332 in a radially inward direction with respect to the axis 301, as indicated by the arrows 323, from the expanded position to the retracted position. The formation testing tool 310 may further comprise a wellbore fluid pump 336 fluidly connected with the space (z.e., the wellbore 102) external to the formation testing tool 310 between the packers 330, 332 via a fluid conduit and operable to pump (or evacuate) wellbore fluid located within the interval 108 out of the interval 108 (and perhaps some formation fluid from the near wellbore zone of the formation 106) and into the wellbore 102 below the expanded lower packer 332 via another fluid conduit.

[0045] The formation testing tool 310 may further comprise a formation tester 340 operable perform the formation test, including to measure or facilitate the measurement of a property of the formation 106. For example, the formation tester 340 may be operable to measure formation pressure, formation mobility, and / or formation injectivity. The formation tester 340 may comprise a formation tester probe 342 (e.g., a radial probe or a focused radial probe) movable or otherwise operable between a retracted position (shown in FIGS. 3 and 4) in which the probe 342 is disposed against (or adjacent) the body 334 of the formation testing tool 310 and away from the sandface 103 of the wellbore 102, and an extended position (shown in FIGS. 5 and 6) in which the probe 342 extends away from the body 334 of the formation testing tool 310 and is in contact with the sandface 103 along the clean zone 107 of the wellbore 102. To permit axial view of the probe 342 in its extended positions, FIG. 6 does not show the packer 332.

[0046] Before the formation testing operations, the probe 342 may be moved in a radially outward direction with respect to the axis 301, as indicated by arrow 341, to the extended position. The formation tester 340 may then be used to facilitate measurements of the formation pressure, the formation mobility, and / or the formation injectivity. For example, during the formation testing operations, the formation tester 340 may receive formation fluid from the formation 106 via the probe 342 and / or inject a test fluid into the formation 106 via the probe 342 and generate sensor data indicative of a property of the formation 106, such as the formationpressure, the formation mobility, and / or the formation injectivity. After the formation testing operations, the probe 342 may be moved in a radially inward direction with respect to the axis 301, as indicated by arrow 343, to the retracted position.

[0047] The formation testing tool 310 may further comprise one or more sensors 344 operable to output sensor data indicative operational state or position of one or more of the probe 342, the wellbore fluid pump 336, the hydraulic pump 338, and / or the packers 330, 332. For example, the sensors 344 may be operable to output sensor data indicative of a radial position (i.e., lateral position, extension distance, etc.) of the probe 342, a flow rate, a volume, and / or a pressure of the wellbore fluid being pumped by the wellbore fluid pump 336, a flow rate, a volume, and / or a pressure of hydraulic fluid being pumped by the hydraulic pump 338, a flow rate, a volume, and / or a pressure of a fluid (c. ., formation fluid) being pumped (or injected) into or from the formation 106 by the formation tester 340 via the probe 342, and / or radial position of the packers 330, 332. The sensors 344 may be or comprise a linear encoder, a linear potentiometer, a capacitive sensor, an inductive sensor, a magnetic sensor, a LVDT, a proximity sensor, a Hall effect sensor, and / or a reed switch, among other examples. The sensors 344 may also or instead comprise a force sensor, such as a load cell, a strain gauge, and / or a fluid pressure sensor, among other examples. The sensors 344 may also or instead comprise a flow rate sensor and / or a pressure sensor.

[0048] The formation testing tool 310 may further comprise a downhole controller 346 communicatively connected with the sensors 344, the pumps 336, 338, and the formation tester 340 via the conductors 303. The downhole controller 346 may be communicatively connected with the surface equipment 190, 290 directly via the conductors 303 or indirectly via the downhole controller 312. The downhole controller 346 may be operable to receive, store, and / or process control commands from the surface equipment 190, 290 for controlling the formation testing tool 310 to cause the formation testing tool 310 to perform one or more example methods described herein, including to cause the hydraulic pump 338 to operate the packers 330, 332 between the retracted and expanded positions, to cause the wellbore fluid pump 336 to pump the wellbore fluid out of the interval 108 (and perhaps some formation fluid from the near wellbore zone of the formation 106), and to cause the formation tester 340 to extend the probe 342 and to perform the formation test. The downhole controller 346 may be operable to determine the formation pressure, the formation mobility, and / or the formation injectivity based on the sensor data generated by the formation tester 340. The downhole controller 346 may also or instead beoperable to store the sensor data generated by the sensors 344 and / or the formation tester 340 and / or transmit the sensor data to the surface equipment 190, 290 for further analysis, such as to determine operational state of the formation testing tool 310 and / or determine a property of the formation 106.

[0049] FIG. 7 is a schematic view of at least a portion of an example implementation of a processing device (or system) 400 according to one or more aspects of the present disclosure. The processing device 400 may be or form at least a portion of one or more equipment controllers and / or other electronic devices shown in one or more of the FIGS. 1-6. For example, the processing device 400 may be or form at least a portion of one or more of the surface equipment 190, 290 and downhole controllers 312, 328, 346. Accordingly, the following description refers to FIGS. 1-7, collectively.

[0050] The processing device 400 may be or comprise, for example, one or more processors, controllers, special -purpose computing devices, PCs (e.g., desktop, laptop, and / or tablet computers), personal digital assistants, smartphones, IPCs, PLCs, servers, internet appliances, and / or other types of computing devices. Although it is possible that the entirety of the processing device 400 is implemented within one device, it is also contemplated that one or more components or functions of the processing device 400 may be implemented across multiple devices, some or an entirety of which may be at the wellsite and / or remote from the wellsite.

[0051] The processing device 400 may comprise a processor 412, such as a general -purpose programmable processor. The processor 412 may comprise a local memory 414, and may execute machine-readable and executable program code instructions 432 (i.e., computer program code) present in the local memory 414 and / or other memory device. The processor 412 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general -purpose computers, special purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Examples of the processor 412 include one or more INTEL microprocessors, microcontrollers from the ARM and / or PICO families of microcontrollers, embedded soft / hard processors in one or more FPGAs.

[0052] The processor 412 may execute, among other things, the program code instructions (or computer program code) 432 and / or other instructions and / or programs to implement the example methods and / or operations described herein. For example, the program codeinstructions 432, when executed by the processor 412 of the processing device 400, may cause the processor 412 to receive and process (e.g., compare, analyze, etc.} sensor data (e.g., sensor measurements). The program code instructions 432, when executed by the processor 412 of the processing device 400, may also or instead output control data (i.e., control commands) to cause one or more portions or pieces of the downhole string 300 to perform the example methods and / or operations described herein. The program code instructions 432, when executed by the processor 412 of the processing device 400, may also or instead output information indicative of an event (e.g., abnormal event), a status (e.g., operational state, operational position, operational health, etc. , or a characteristic (e.g., size, length, height, etc.} of a portion of the downhole string 300 to an output device of the surface equipment 190, 290 for viewing by wellsite personnel.

[0053] The processor 412 may be in communication with a main memory 416, such as may include a volatile memory 418 and a non-volatile memory 420, perhaps via a bus 422 and / or other communication means. The volatile memory 418 may be, comprise, or be implemented by random-access memory (RAM), static RAM (SRAM), dynamic RAM (DRAM), synchronous DRAM (SDRAM), RAMBUS DRAM (RDRAM), and / or other types of RAM devices. The nonvolatile memory 420 may be, comprise, or be implemented by read-only memory, flash memory, and / or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 418 and / or non-volatile memory 420.

[0054] The processing device 400 may also comprise an interface circuit 424, which is in communication with the processor 412, such as via the bus 422. The interface circuit 424 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input / output (3GIO) interface, a wireless interface, a cellular interface, and / or a satellite interface, among others. The interface circuit 424 may comprise a graphics driver card. The interface circuit 424 may comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.}.

[0055] The processing device 400 may be in communication with various sensors, actuators, processing devices, equipment controllers, and other devices of the wellsite systems 100, 200 and / or the downhole string 300 via the interface circuit 424. The interface circuit 424 can facilitate communications between the processing device 400 and one or more devices by utilizing one or more communication protocols, such as an Ethernet-based network protocol(such as ProfiNET, OPC, OPC / UA, Modbus TCP / IP, EtherCAT, UDP multicast, Siemens S7 communication, or the like), a proprietary communication protocol, and / or other communication protocol.

[0056] One or more input devices 426 may also be connected to the interface circuit 424. The input devices 426 may permit a human user (e.g., wellsite personnel) to enter the program code instructions 432, which may be or comprise control data, operational parameters, and / or operational set-points. The program code instructions 432 may further comprise modeling or predictive routines, equations, algorithms, processes, applications, and / or other programs operable to perform example methods and / or operations described herein. The input devices 426 may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a trackpad, a trackball, an isopoint, and / or a voice recognition system, among other examples. One or more output devices 428 may also be connected to the interface circuit 424. The output devices 428 may permit visualization or other sensory perception of various data, such as sensor data, status data, and / or other example data. The output devices 428 may be, comprise, or be implemented by video output devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, a cathode ray tube (CRT) display, a touchscreen, etc.), printers, and / or speakers, among other examples. The one or more input devices 426 and the one or more output devices 428 connected to the interface circuit 424 may, at least in part, facilitate the HMIs described herein.

[0057] The processing device 400 may comprise a mass storage device 430 for storing data and program code instructions 432. The mass storage device 430 may be connected to the processor 412, such as via the bus 422. The mass storage device 430 may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and / or digital versatile disk (DVD) drive, among other examples. The processing device 400 may be communicatively connected with an external storage medium 434 via the interface circuit 424. The external storage medium 434 may be or comprise a removable storage medium (e.g., a CD or DVD), such as may be operable to store data and program code instructions 432.

[0058] As described above, the program code instructions 432 may be stored in the mass storage device 430, the main memory 416, the local memory 414, and / or the removable storage medium 434. Thus, the processing device 400 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as anASIC), or may be implemented as software or firmware for execution by the processor 412. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code instructions 432 (z.e., software or firmware) thereon for execution by the processor 412. The program code instructions 432 may include program instructions or computer program code that, when executed by the processor 412, may perform and / or cause performance of example methods, processes, and / or operations described herein.

[0059] The present disclosure is further directed to example methods (e.g., operations and / or processes) of operating a downhole string to remove mudcake 105 from a segment of a sandface 103 of a wellbore 102 and / or perform a formation test along the segment of the sandface 103. The methods may be performed by utilizing (or otherwise in conjunction with) at least a portion of one or more implementations of one or more instances of the apparatus shown in one or more of FIGS. 1-7, and / or otherwise within the scope of the present disclosure. The methods may be caused to be performed, at least partially, by a processing device (e.g., the processing device 400, the surface equipment 190, 290, the downhole controllers 312, 328, 346, etc.) executing computer program code according to one or more aspects of the present disclosure. Thus, the present disclosure is also directed to a non-transitory, computer-readable medium comprising computer program code that, when executed by the controller, may cause such controller to perform the example methods described herein. The methods may also or instead be caused to be performed, at least partially, by a human user (e.g., wellsite personnel) utilizing one or more instances of the apparatus shown in one or more of FIGS. 1-7, and / or otherwise within the scope of the present disclosure. Thus, the following description of example methods refer to apparatus shown in one or more of FIGS. 1-7. However, the methods may also be performed in conjunction with implementations of apparatus other than those depicted in FIGS. 1-7 that are also within the scope of the present disclosure.

[0060] An example method according to one or more aspects of the present disclosure may comprise operating the conveyance equipment of one of the wellsite systems 100, 200 via the surface equipment 190, 290, respectively, to convey the downhole string 300. As shown in FIGS. 3 and 4, the downhole string 300 may be conveyed in a downhole direction within the wellbore 102, as indicated by arrow 305, to a predetermined depth within the wellbore 102. As described above, the downhole string 300 may comprise the arms 324 each carrying a corresponding one of the scrapers 322. As shown in FIGS. 5 and 6, the method may furthercomprise extending the arms 324 in the radially outward direction, as indicated by arrows 321, toward the sandface 103 of the wellbore 102 until the scrapers 322 contact the sandface 103, and conveying the downhole string 300 a predetermined vertical distance in the uphole direction within the wellbore 102, as indicated by arrow 307, while the scrapers 322 contact the sandface 103 thereby causing the scrapers 322 to remove the mudcake 105 from the sandface 103 to form the clean zone 107 of the sandface 103. When the packers 330, 332 are used as part of the formation test, the predetermined vertical distance may range between about 1.1 meters and 1.5 meters. However, when the packers 330, 332 are not used as part of the formation test and just the formation tester 340 is used to perform the formation test, the predetermined vertical distance may range between about 0.3 meters and 0.5 meters.

[0061] The scraping operation described above may be repeated one, two, three, four, or more times to remove additional mudcake 105 for the sandface 103 of the wellbore 102. For example, the method may further comprise retracting the arms 324 away from the sandface 103 in the radially inward direction, as indicated by arrows 323, until the scrapers 322 are disposed away from the sandface 103, and conveying the downhole string 300 the predetermined distance in the downhole direction while the scrapers 322 are disposed away from the sandface 103. Thereafter, the method may include extending the arms 324 toward the sandface 103 in the radially outward direction until the scrapers 322 contact the sandface 103, and conveying the downhole string 300 the predetermined distance in the uphole direction while the scrapers 322 contact the sandface 103 thereby causing the scrapers 322 to remove additional mudcake 105 from the sandface 103 to form the clean zone 107 of the sandface 103.

[0062] As shown in FIGS. 3 and 4, the method may further comprise rotating the downhole string 300, as indicated by arrow 309, by a predetermined angle 311, between each of the scraping operations described above. For example, the method may further comprise retracting the arms 324 away from the sandface 103 in the radially inward direction until the scrapers 322 are disposed away from the sandface 103, and conveying the downhole string 300 the predetermined distance in the downhole direction while the scrapers 322 are disposed away from the sandface 103. Before or after conveying the downhole string 300 the predetermined distance in the downhole direction while the scrapers 322 are disposed away from the sandface 103, the method may further comprise rotating the downhole string 300, as indicated by the arrow 309, the predetermined angle 311. Rotation of the downhole string 300 may be performed by causing rotation of the drill string 112 conveying the downhole string 300 via the rotary table 114 or thetop drive. The predetermined angle 311 may range between about 30 degrees and 45 degrees. Thereafter, the method may include extending the arms 324 toward the sandface 103 in the radially outward direction until the scrapers 322 contact the sandface 103, and conveying the downhole string 300 the predetermined distance in the uphole direction while the scrapers 322 contact the sandface 103 thereby causing the scrapers 322 to remove additional mudcake 105 from the sandface 103 to form the clean zone 107 of the sandface 103. Such scraping operations may be repeated a predetermined number of times.

[0063] As described above, the downhole string 300 may further comprise an upper packer 330, a lower packer 332, and a wellbore fluid pump 336. Thus, the method may further comprise expanding the upper packer 330 and the lower packer 332 in the radially outward direction, as indicated by arrows 321, against the clean zone 107 of the sandface 103 to form an isolated interval 108 of the wellbore 102, and operating the wellbore fluid pump 336 to evacuate wellbore fluid from the isolated interval 108 (and perhaps some formation fluid from the near wellbore zone of the formation 106). Expanding the upper packer 330 and the lower packer 332 may comprise operating the hydraulic pump 338 of the downhole string 300 to pump a hydraulic fluid into the upper packer 330 and the lower packer 332.

[0064] As described above, the downhole string 300 may further comprise a formation tester 340 for performing a formation test to measure or otherwise facilitate measurement of the a property of the formation 106 through which the wellbore 102 extends. Thus, the method may further comprise operating the formation tester 340 to contact the sandface 103 along the clean zone 107 and perform the formation test. As described above, the formation tester 340 may comprise a probe 342 for performing or otherwise facilitating the formation test. Thus, the method may further comprise conveying the downhole string 300 such that the probe 342 is disposed within the clean zone 107 and operating the formation tester 340 to perform the formation test by: extending the probe 342 into contact with the sandface 103 within the clean zone 107; and injecting a fluid into the formation 106 via the probe 342 or receiving a fluid from the formation 106 via the probe 342 to measure the property of the formation 106.

[0065] The methods (or operations) described herein may be caused to be performed, at least partially, automatically by a processing device (e.g., the processing device 400, the surface equipment 190, 290, the downhole controllers 312, 328, 346, etc.) executing computer program code according to one or more aspects of the present disclosure. Such methods (or operations)may also or instead be caused to be performed, at least partially, manually by wellsite personnel utilizing the surface equipment 190, 290.

[0066] FIG. 8 is a schematic side view of an example implementation of a scraper 500 configured to contact a sandface 103 of a wellbore 102 and to remove mudcake 105 from the sandface 103 according to one or more aspects of the present disclosure. FIG. 9 is a schematic view of a bottom (or axial) view of the scraper 500 shown in FIG. 8. The scraper 500 may be configured to be connected to a downhole tool 308 (e.g., a mudcake removal tool) and remove the mudcake 105 from the sandface 103 when the downhole tool 308 is being conveyed within the wellbore 102. FIGS. 10 and 11 are perspective views of example implementations of scrapers 502, 504, respectively, each configured to contact a sandface 103 of a wellbore 102 and to remove mudcake 105 from the sandface 103 according to one or more aspects of the present disclosure. Each of the scrapers 502, 504 is shown connected to a corresponding arm 324 of a downhole tool 308. Each of the scrapers 502, 504 may be configured to remove the mudcake 105 from the sandface 103 when the downhole tool 308 is being conveyed within the wellbore 102. The downhole tool 308 may be conveyed within the wellbore 102 by itself or as part of a downhole string 300. The scrapers 500, 502, 504 may be an example implementations and may comprise one or more features of the scraper 322 shown in FIGS. 4-6. Accordingly, the following description refers to FIGS. 4-11, collectively.

[0067] Each scraper 500, 502, 504 may comprise a connection portion 510 configured to facilitate connection with the downhole tool 308, and an outer scraping surface 512 configured to contact the mudcake 105 and remove the mudcake 105 from the sandface 103 when the downhole tool 308 is being conveyed within the wellbore 102. The connection portion 510 may face or be directed toward the downhole tool 308 in a radially inward direction with respect to the axis 301 of the downhole tool 308 when the scraper 500, 502, 504 is connected to the downhole tool 308, and the scraping surface 512 may face or be directed away from the downhole tool 308 in a radially outward direction with respect to the axis 301 of the downhole tool 308 when the scraper 500, 502, 504 is connected to the downhole tool 308.

[0068] Each scraper 500, 502, 504 may comprise an upper end 501 and a lower end 503. The upper end 501 may be directed toward or be located closer to the upper (or uphole) end of the downhole tool 308 when the scraper 500, 502, 504 is connected to the downhole tool 308, and the lower end 503 may be directed toward or be located closer to the lower (or downhole) end of the downhole tool 308 when the scraper 500, 502, 504 is connected to the downhole tool308. The lower end 503 of the scraper 500, 502, 504 may be configured to contact the sandface 103. The fist end 501 of the scraper 500, 502, 504 may have a first width 536, and the second end of the scraper 500, 502, 504 may have a second width 538. The second width 538 may be greater than the first width 536. At least a portion of the scraper 500, 502, 504 may comprise a width 540 that progressively increases from the first end 501 to the second end 503.

[0069] The connection portion 510 may be configured to contact the arm 324 of the downhole tool 308 such that the scraper 500, 502, 504 can be detachably connected to the arm 324. The connection portion 510 may be or comprise a mounting surface configured to accommodate a portion of the arm 324 and facilitate connection with the arm 324. For example, the connection portion 510 may be or comprise a cavity configured to receive the arm 324. The scraper 500, 502, 504 may be fixedly connected to the arm 324 via a plurality of fasteners 534 (e.g, bolts) extending between the scraper 500, 502, 504 and the arm 324. The scraping surface 512 may be configured to contact the mudcake 105 and remove the mudcake 105 from the sandface 103 when the arm 324 is in the extended position and the downhole tool 308 is being conveyed within the wellbore 102.

[0070] The scraping surface 512 may be curved, such that a convex side of the curve faces in a radially outward direction with respect to the axis 301 of the downhole tool 308 when the scraper 500, 502, 504 is connected to the downhole tool 308. The scraping surface 512 may comprise a plurality of grooves 514, 516, 518 extending along the scraping surface 512. The grooves 514, 516, 518 may be configured (e.g, angled, sized, etc.) to direct flow of the mudcake 105 in an upward and side directions (or a lateral direction) along the scraping surface 512 and away from the center of the scraping surface 512, as indicated by arrows 513, such that the mudcake 105 that is removed from the sandface 103 falls off the sides of the scraping surface 512 and into the wellbore 102, thereby reducing the amount of mudcake 105 that is accumulated on the scraping surface 512. Each of the grooves 514, 516, 518 may have a V-shaped profile. Groove angle 530 of each of the grooves 514, 516, 518 may range between about 45 degrees and 120 degrees. Groove depth 532 of each of the grooves 514, 516, 518 may range between about 2 millimeters (mm) and 15 mm.

[0071] The grooves 514, 516, 518 may comprise a plurality of first grooves 514 and a plurality of second grooves 516. The first grooves 514 may be (or extend) parallel with respect to each other, and the second grooves 516 may be (or extend) parallel with respect to each other. The first grooves 514 extend diagonally along the scraping surface 512 and with respect to theaxis 301 of the downhole tool 308 when the scraper 500, 502, 504 is connected to the downhole tool 308. The second grooves 516 may extend diagonally along the scraping surface 512 and with respect to the axis 301, but in an opposing diagonal direction from the first grooves 514, when the scraper 500, 502, 504 is connected to the downhole tool 308. Thus, at least some of the first grooves 514 and at least some of the second grooves 516 intersect. The grooves 514, 516, 518 may further comprise a plurality of third grooves 518, wherein at least some of the third grooves 518 intersect with at least some of the first grooves 514 and the second grooves 516. The third grooves 518 may be or extend parallel with respect to each other. Spacing (or distances) 528 between adjacent instances of parallel grooves 514, 516, 518 may vary (or be different).

[0072] The grooves 514, 516, 518 may define a plurality of sharp cutting edges 520, 522 configured to cut into or shear the mudcake 105. For example, upwardly directed edges 520 of instances of the first grooves 514 and the second grooves 516 may be configured to shear the mudcake 105 during the scraping operations. Furthermore, side surfaces of the intersecting instances of the first grooves 514 and the second grooves 516 define upwardly directed edges 522 configured to cut into the mudcake 105 during the scraping operations. Furthermore, the first grooves 514 and second grooves 516 may define a plurality of cutting blocks 524 having the edges 520, 522. Also, each scraper 500, 502, 504 may comprise a contact edge 526 (e.g., at the lower end of the scraper 500, 502, 504 or the scraping surface 512) configured to contact the sandface 103 and remove (or scrape) the mudcake 105 from the sandface 103 during the scraping operations when the downhole tool 308 is being conveyed within the wellbore 102. The contact edge 526 may be curved to accommodate curvature of the sandface 103 during the scraping operations when the downhole tool 308 is being conveyed within the wellbore 102.

[0073] The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and / or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the scope of the present disclosure.

Claims

EXAMPLE CLAIMS, EMBODIMENTS, AND / OR IMPLEMENTATIONS WITHIN THE SCOPE OF THE PRESENT DISCLOSURE INCLUDE:

1. An apparatus comprising: a downhole tool operable to be conveyed within a wellbore and remove mudcake from a sandface of the wellbore when the downhole tool is being conveyed within the wellbore, wherein the downhole tool comprises: a body; a plurality of scrapers each configured to contact the sandface and remove the mudcake from the sandface when the downhole tool is being conveyed within the wellbore; and a plurality of arms each carrying a corresponding one of the scrapers, wherein each arm is operable to extend away from the body such that the scraper contacts the sandface when the downhole tool is being conveyed within the wellbore.

2. The apparatus of example 1 wherein each scraper comprises an edge configured to contact the sandface and remove the mudcake from the sandface when the downhole tool is being conveyed within the wellbore, and wherein the scraping surface is curved.

3. The apparatus of example 1 wherein the downhole tool further comprises an actuator operatively connected to the arms, and wherein the actuator is operable to extend the arms away from the body such that the scraper contacts the sandface and retract the arms toward the body such that the scraper is away from the sandface.

4. The apparatus of example 1 wherein the downhole tool comprises four arms.

5. The apparatus of example 1 wherein the downhole tool is a first downhole tool, wherein the apparatus further comprises a second downhole tool coupled to the first downhole tool, and wherein the second downhole tool comprises at least one of: a formation tester operable to measure at least one of formation pressure, formation mobility, and formation injectivity; and a dual packer assembly for isolating a wellbore interval.

6. A method comprising:conveying a downhole string downhole to a predetermined depth within a wellbore, wherein the downhole string comprises a plurality of arms each carrying a scraper; extending the arms toward a sandface of the wellbore until the scrapers contact the sandface; and conveying the downhole string uphole a predetermined distance while the scrapers contact the sandface thereby causing the scrapers to remove mudcake from the sandface to form a clean zone of the sandface.

7. The method of example 6 further comprising: retracting the arms away from the sandface until the scrapers are disposed away from the sandface; conveying the downhole string downhole the predetermined distance while the scrapers are disposed away from the sandface; extending the arms toward the sandface until the scrapers contact the sandface; and conveying the downhole string uphole the predetermined distance while the scrapers contact the sandface thereby causing the scrapers to remove additional mudcake from the sandface to form the clean zone of the sandface.

8. The method of example 6 further comprising: retracting the arms away from the sandface until the scrapers are disposed away from the sandface; conveying the downhole string downhole the predetermined distance while the scrapers are disposed away from the sandface; rotating the downhole string a predetermined angle; extending the arms toward the sandface until the scrapers contact the sandface; and conveying the downhole string uphole the predetermined distance while the scrapers contact the sandface thereby causing the scrapers to remove additional mudcake from the sandface to form the clean zone of the sandface.

9. The method of example 6 wherein the downhole string further comprises an upper packer, a lower packer, and a wellbore fluid pump; and wherein the method further comprises: expanding the upper packer and the lower packer against the clean zone of the sandface to form an isolated interval of the wellbore; andoperating the wellbore fluid pump to evacuate wellbore fluid from the isolated interval.

10. The method of example 6 wherein the downhole string further comprises a formation tester for performing a formation test to measure a property of a formation through which the wellbore extends, and wherein the method further comprises operating the formation tester to: contact the sandface along the clean zone; and perform the formation test.

11. The method of example 6 wherein the downhole string further comprises a formation tester with a probe for performing a formation test to measure a property of a formation through which the wellbore extends, and wherein the method further comprises: conveying the downhole string such that the probe is disposed within the clean zone; and operating the formation tester to perform the formation test by: extending the probe into contact with the sandface within the clean zone; and injecting a fluid into the formation via the probe or receiving a fluid from the formation via the probe to measure the property of the formation.

12. An apparatus comprising: a scraper configured to be connected to a downhole tool and remove mudcake from a sandface of a wellbore when the downhole tool is being conveyed within the wellbore, wherein the scraper comprises: a connection portion configured to facilitate connection with the downhole tool; and a scraping surface configured to contact the mudcake and remove the mudcake from the sandface when the downhole tool is being conveyed within the wellbore, wherein the scraping surface comprises a plurality of grooves defining a plurality of edges configured to cut into the mudcake.

13. The apparatus of example 12 wherein the grooves comprise a plurality of first grooves and a plurality of second grooves, and wherein at least some of the first grooves and at least some of the second grooves intersect.

14. The apparatus of example 13 wherein the first grooves are parallel with respect to each other, and wherein the second grooves are parallel with respect to each other.

15. The apparatus of example 13 wherein the first grooves extend diagonally along the scraping surface, and wherein the second grooves extend diagonally along the scraping surface.

16. The apparatus of example 13 wherein side surfaces of the intersecting instances of the first grooves and the second grooves define the edges.

17. The apparatus of example 16 wherein the first grooves and second grooves define cutting blocks having the edges.

18. The apparatus of example 16 wherein the scraping surface further comprises a plurality of third grooves, and wherein at least some of the third grooves intersect at least some of the first grooves and the second grooves.

19. The apparatus of example 18 wherein the third grooves are parallel with respect to each other.

20. The apparatus of example 12 wherein the scraper comprises an edge configured to contact the sandface and remove the mudcake from the sandface when the downhole tool is being conveyed within the wellbore, and wherein the edge is curved to accommodate curvature of the sandface.

21. The apparatus of example 12 wherein spacing between adjacent instances of the grooves varies.

22. The apparatus of example 12 wherein each of the grooves has a V-shaped profile.

23. The apparatus of example 12 wherein the groove angle of each of the grooves ranges between about 45 degrees and 120 degrees.

24. The apparatus of example 12 wherein the groove depth of each of the grooves ranges between about 2 millimeters (mm) and 15 mm.

25. The apparatus of example 12 wherein the scraping surface is curved.

26. The apparatus of example 12 wherein: the scraper comprises a fist end having a first width; the scraper comprises a second end having a second width; the second width is greater than the first width; and the second end is configured to contact the sandface.

27. The apparatus of example 12 wherein: the scraper comprises a first end; the scraper comprises a second end; at least a portion of the scraper comprises a width that progressively increases between the first end and the second end; and the second end is configured to contact the sandface.

28. The apparatus of example 12 wherein the connection portion is configured to contact an arm of the downhole tool such that the scraper can be detachably connected to the arm, and wherein the scraping surface is configured to contact the mudcake and remove the mudcake from the sandface when the arm is in an extended position and the downhole tool is being conveyed within the wellbore.

29. The apparatus of example 12 wherein the scraping surface is a single curved surface that extends partially around the downhole tool when the scraper is connected with the downhole tool.

30. A method according to one or more aspects explicitly described herein and / or inherently or otherwise within the scope of the present disclosure.

31. A workflow according to one or more aspects explicitly described herein and / or inherently or otherwise within the scope of the present disclosure.

32. A process according to one or more aspects explicitly described herein and / or inherently or otherwise within the scope of the present disclosure.

33. A computer program product comprising a non-transitory, computer-readable medium having code recorded thereon for causing a processor to perform at least a portion of a method, workflow, and / or process according to one or more aspects explicitly described herein and / or inherently or otherwise within the scope of the present disclosure.

34. An apparatus according to one or more aspects explicitly described herein and / or inherently or otherwise within the scope of the present disclosure.

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