Patent ID: 12188332

DETAILED DESCRIPTION

It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.

As used herein, orientation terms “uphole,” “downhole,” “up,” and “down” are defined relative to the location of the earth's surface relative to the subterranean formation. “Down” and “downhole” are directed opposite of or away from the earth's surface, towards the subterranean formation. “Up” and “uphole” are directed in the direction of the earth's surface, away from the subterranean formation or a source of well fluid. “Fluidically coupled” means that two or more components have communicating internal passageways through which fluid, if present, can flow. A first component and a second component may be “fluidically coupled” via a third component located between the first component and the second component if the first component has internal passageway(s) that communicates with internal passageway(s) of the third component, and if the same internal passageway(s) of the third component communicates with internal passageway(s) of the second component.

Hydrocarbons, such as oil and gas, are produced or obtained from subterranean reservoir formations that may be located onshore or offshore. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation typically involve a number of construction steps such as drilling a wellbore at a desired well site, isolating the wellbore with a barrier material, completing the wellbore with various production equipment, treating the wellbore to optimize production of hydrocarbons, and providing surface production equipment for the recovery of hydrocarbons from the wellhead.

Prior to the completion operations, a cleanout operation can remove drilling mud and debris from a wellbore. The cleanout operation may include a cleanout string, e.g., one or more cleanout tools, conveyed into a wellbore to a target depth, for example, the bottom or toe of the wellbore. The cleanout string can include one or more cleanout tools configured to remove debris, for example, a casing scraper, a circulating tool, a downhole fluid filter, a magnet tool, a junk basket, or combinations thereof. The cleanout string can be conveyed on a workstring configured to circulate fluid into the wellbore to clean and/or replace the wellbore fluids.

Typically, a casing scraper comprises a set of scraper blades extending from a housing to contact an inner surface of the casing. Each scraper blade can have a generally rectangular cross-section with an outer arc shape configured to contact or scrape the inner surface of the casing. The scraper blades can be fixed or spring loaded. The set of scraper blades can be located or positioned around the circumference of a mandrel to contact or scrape all 360 degrees of the inner surface. The casing scraper is typically conveyed into the wellbore on drill pipe, tubing, coil tubing, or any other suitable tubular.

The cleanout operation may target a portion of the wellbore for cleaning, for example, adjacent to a formation. The cleanout string may be disabled, or configured to not clean, during the conveyance to the target cleaning location. In some embodiments, the cleanout string can include a casing scraper configured in a run-in position or disabled position. In the run-in position, the scraper blades of the casing scraper can be retained away from the inner surface of the casing. The scraper blades can be activated, or configured to scrape, by a signal from the surface, e.g., applied pressure. The casing scraper can clean the inner surface of the wellbore along the target zone or portion of the wellbore. In some embodiments, the casing scraper can be transitioned from the activated position back to the run-in position. For example, the casing scraper can retract or return the scraper blades to the run-in position.

In some scenarios, the cleanout operation may utilize a casing scraper during a drilling operation. For example, a casing scraper may be placed proximate to a drill bit or milling shoe. The casing scraper may allow for rotation of the drilling string during the drilling operation while not rotating the scraper blades. In some embodiments, the mandrel of the casing scraper can rotate independently of the set of scraper blades. For example, the casing scraper may be configured in an active position with the scraper blades contacting or cleaning the wellbore. The scraper blades may remain stationary while the mandrel of the casing scraper rotates with the workstring.

In some scenarios, the cleanout operation may utilize a casing scraper to remove obstructions from the inner surface of the casing. For example, hardened material such as cement, scale, paraffin, or perforation burrs may adhere and/or protrude from the inner surface of the casing to obstruct the flow path of the casing. In some embodiments, the casing blades can be configured to rotate with the mandrel of the casing scraper while contacting the inner surface of the wellbore. The contact or cleaning of the inner surface while rotating can remove hardened substances, e.g., cement, mud, and paraffin, and can remove casing or completion equipment material protruding into flow path, e.g., perforation burrs, portions of downhole tools, and deformation of the casing. In this configuration, the scraper blades may be keyed to and rotate with the mandrel of the casing scraper as the casing scraper rotates with the workstring.

The cleanout operation may determine that a different type of casing scraper is desirable during a portion of the cleanout operation. For example, the casing scraper may be conveyed into the wellbore in a non-rotating configuration, e.g., the scraper blades move independent from the mandrel, and service personnel determine a need for a rotating configuration, e.g., a tight spot. Typically, the workstring must be tripped out, e.g., conveyed back to surface, to exchange or reconfigure the casing scraper to a rotating configuration. A casing scraper that is configurable downhole is desirable.

A casing scraper with a surface activated selective configuration can provide a solution to configuring the casing scraper in the wellbore. In some embodiments, a selective casing scraper can comprise extendable and retractable scraper blades. For example, the selective casing scraper can be configured in a run-in position with the set of scraper blades retracted or away from the inner surface of the casing. An activation mechanism can reconfigure the casing scraper to an activated configuration by deploying the set of scraper blades to contact the inner surface of the casing. The selective casing scraper can be activated in a first configuration, e.g., non-rotating configuration. A surface signal, e.g., pressure or flowrate, can activate or initiate the activation method. In some embodiments, the selective casing scraper can be reconfigured from a first configuration to a second configuration. For example, the selective casing scraper can be reconfigured from a non-rotating configuration to a rotating configuration. The selective scraper can include a control mechanism that can reconfigure the selective casing scraper from a first configuration to a second configuration. In some embodiments, the control mechanism can reconfigure the selective casing scraper from a first configuration, to a second configuration, and/or to a third configuration.

Turning now toFIG.1, an exemplary wellsite environment100for a cleanout operation is illustrated. In some embodiments, wellsite environment100comprises a wellbore102extending from a surface location to a permeable subterranean formation110. The wellbore102can be drilled through a subterranean formation130from surface location128using any suitable drilling technique. The wellbore102can include a substantially vertical portion104that transitions to a deviated portion and into a substantially horizontal portion106. In some embodiments, the wellbore102may comprise a nonconventional, horizontal, deviated, multilateral, or any other type of wellbore. Wellbore102may be defined in part by a casing string108that may extend from a surface location to a selected downhole location. The casing string108may be isolated from the wellbore102by cement114. Portions of wellbore102that do not comprise the casing string108may be referred to as open hole. Although the horizontal portion106is illustrated with a liner string116, e.g., secondary casing and cement118, it is understood that the horizontal section can include an open hole section, an open hole completion, a liner string, a cement section, or combinations thereof. While the wellsite environment100illustrates a land-based subterranean environment, the present disclosure contemplates any wellsite environment including a subsea environment. In one or more embodiments, any one or more components or elements may be used with subterranean operations with equipment located on service platforms126, offshore platforms, drill ships, semi-submersibles, drilling barges, and land-based rigs.

A cleanout string124may be conveyed into the wellbore102by a workstring122extending from a service platform126. The workstring122can be any piping, tubular, or fluid conduit including, but not limited to, drill pipe, workover tubing, production tubing, casing, coiled tubing, and any combination thereof. The workstring122can provide a conduit for the cleaning operation to deliver fluids to the cleanout string124or extract fluids from the interior of the casing string108as will be described further herein.

In some embodiments, the cleanout string124can include a drill bit132, milling shoe, or other suitable drilling device. The cleanout string124can be conveyed into the wellbore102and/or casing string108to drill out or remove one or more completion tools, for example, a frac plug. The drill bit132can locate and/or contact the completion tool and the workstring122can be rotated to drill out or remove the completion tool. Drilling fluid or completion fluid can be pumped down the workstring122during the drilling operation to lift out or remove the cuttings from the interior of the casing string108.

In some embodiments, the cleanout string124comprises a selective casing scraper136. The selective casing scraper136can be conveyed into the wellbore102and/or casing string108on the workstring122alone or as a portion of the cleanout string124. Said another way, the cleanout string124can comprise the selective casing scraper136alone or with other downhole tools, e.g., a junk basket. In some embodiments, the selective casing scraper can be configured in a run-in position with a set of scraper blades retracted or away from the inner surface112of the casing string108. An activation process can reconfigure the selective casing scraper136to an activated configuration by deploying the set of scraper blades to contact the inner surface112of the casing string108. In some embodiments, the selective casing scraper136can be reconfigured from a first configuration, e.g., a run-in configuration, to a second configuration, e.g., an active configuration, and returned to the first configuration. For example, the cleanout string124can be conveyed into the casing string108to locate, e.g., contact, a completion tool or cementing tool within the wellbore102. The selective casing scraper136can be activated from surface by reconfiguring the selective casing scraper136from a run-in position to an active position, e.g., scraper blades in contact with the inner surface112of the casing string108.

Turning now toFIG.2, a partial cross-sectional view of a selective casing scraper tool can be described. In some embodiments, a selective casing scraper tool200can be an embodiment of the selective casing scraper136shown inFIG.1. The selective casing scraper tool200, also referred to as a selective tool, comprises a blade assembly210, a position control device212, and a scraper actuator214. The blade assembly210can extend and retract one or more scraper blades220, alternatively referred to as scraper heads, in response to the position control device212. The scraper actuator214can direct the position control device212to change positions. A downhole end236of the blade assembly210can couple to the workstring122. An uphole end sub296of the second mandrel254can couple to the workstring122.

In some embodiments, the blade assembly210comprises a first stabilizer222, a first mandrel224, a housing226, one or more scraper blades220, a second stabilizer228, and a wedge230. The first stabilizer222can be generally cylinder in shape with an outer surface232, an inner surface234, and a downhole end236. The outer surface232of the first stabilizer222can centralize or position the blade assembly210a predetermined distance from the inner surface112of the casing string108. The inner surface234can define a fluid passage through the blade assembly210. The downhole end236can be releasably coupled to a workstring, e.g., workstring122. The first stabilizer222can be coupled to a first mandrel224. The first mandrel224can be generally cylinder shape with an outer surface238and an inner surface that can be a continuation of inner surface234. The first mandrel224can be coupled to the second stabilizer228. The second stabilizer228can be generally cylinder in shape with an outer surface240, an inner surface, and one or more rod ports242. The outer surface240of the second stabilizer228can be the same general size or circumference as the outer surface232of the first stabilizer222. The housing226can be generally cylinder shape with an outer surface244, an inner surface246, and one or more windows248. The inner surface246of the housing226can have a sliding fit onto an outer surface250on the first stabilizer222and an outer surface252on the second stabilizer228. In some embodiments, the housing226can be configured to rotate about the first stabilizer222and the second stabilizer228. One or more scraper blades220, alternatively referred to as scraper heads, can be a generally cubic shape with an outer surface256and an inner surface258. The outer surface256can be generally arc shape and configured with curvature to generally fit, conform, or mate with the curvature of the inner surface112of the casing string108. The sides of the scraper blades220can be configured with an allowance fit inside the one or more windows248of the housing226. In a first configuration, e.g., a run-in configuration, the inner surface258of the one or more blades220can abut or contact a lower surface260of the wedge230. In some embodiments, a housing spring324can bias the wedge230to the first configuration. In a second configuration, e.g., extended configuration, the one or more scraper blades220can abut or contact an upper surface262of the wedge230as will be described further herein.

In some embodiments, the position control device212can be generally cylinder in shape with an outer surface and an inner surface266with an allowance fit with an outer surface268of a second mandrel254. A control pattern270, e.g., one or more slots, can be located along the inner surface266of the position control device212. A lug272can travel within the control pattern270as will be described further herein. The lug272can be coupled to a lug ring274. In some embodiments, the lug272and lug ring274can rotate within a ring groove277on the outer surface268of the second mandrel254. In some embodiments, the lug272and lug ring274can be coupled to the ring groove277, e.g., non-rotatable. An actuator cover264can be a generally cylinder shape with an outer surface, an inner surface, and releasably coupled to the second stabilizer228and the uphole end sub296.

In some embodiments, the scraper actuator214comprises a piston assembly208abutting a metering assembly206. The piston assembly208comprises a piston cylinder276sealingly coupled to a piston boss278and a seal surface280of the second mandrel254. The piston cylinder276can be generally cylinder in shape with a seal284located within a circumferential groove on an inner surface282. A fluid chamber288can be formed by an inner surface290and a front face292of the piston cylinder, the seal surface280of the second mandrel254, and an end face294of the piston boss278. A fluid port298can fluidically couple the fluid chamber288to the fluid passage234of the selective tool200. In some embodiments, a flowrate of wellbore fluids302pumped through the fluid passage234via the workstring122can generate an increase in fluid pressure at a restriction304located proximate to the fluid port298. The fluid pressure within the fluid chamber288can activate the piston assembly208as will be described further herein.

In some embodiments, the metering assembly206comprises a first metering chamber316, a second metering chamber318, and a metering device314. The first metering chamber316can be defined by a first end sub306, a housing308, a piston boss312, and the seal surface280of the second mandrel254. The second metering chamber318can be defined by a second end sub310, the housing308, the piston boss312, and the outer surface268of the second mandrel254. Although the metering assembly206is illustrated as a separate assembly from the piston assembly208, it is understood that the metering assembly206and piston assembly208can be combined. For example, the piston cylinder276of the piston assembly208can be couple to or combined with the first end sub306of the metering assembly206. The metering device314can be an orifice, a nozzle, a jet, a check valve, a pressure relief valve, or any other suitable metering device and fluidically couple the first metering chamber316with the second metering chamber318. Although a single unit of the metering device314is illustrated, it is understood that there may be 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more metering devices314and the metering devices may be of different types, e.g., two nozzles and one check valve. In a context, the metering device314can be referred to as a nozzle314. The metering assembly206can be filled with a volume of substantively incompressible fluid, such as hydraulic fluid, transmission fluid, dielectric fluid, water, other similar fluid. The metering assembly can be configured to transfer a volume of fluid from one fluid chamber to another fluid chamber via the nozzle314. For example, a linear force, e.g., force parallel to the central axis of the selective tool200, can generate an increase in fluid pressure within first chamber316and the transfer of fluid at a designated flowrate through the nozzle314and into the second chamber318. The nozzle314can transfer fluid at a predetermined flowrate and thus, within a predetermined time period for the volume of fluid. In some embodiments, the metering assembly206can be configured to apply a predetermined activation force for a predetermined amount of time as will be disclosed further herein.

Although the selective tool200inFIG.2Ais illustrated with one scraper blade220inside a window248of the housing226, it is understood that the blade assembly210can have a plurality of scraper blades220and/or multiple rows of scraper blades220along the housing226. Turning now toFIG.2B, an exemplary blade assembly with multiple scraper blades220A-L can be described. In some embodiments, the blade assembly210′ can include three or more scraper blades220within corresponding windows248angularly distributed about the housing226′ in three rows. Each of the rows of scraper blades220can be configured, e.g., angularly distributed about a central axis of the blade assembly210′, to provide 360 degrees of contact along the inner surface112of the casing string108. As illustrated with the exemplary blade assembly210′ ofFIG.2B, a first row of windows248can comprise four blades220A-D evenly distributed at 90 degrees about the centerline of the blade assembly210′. A second row of windows can comprise four blades220E-H evenly distributed at 90 degrees and rotated an angle of “R” from the first row. A third row of windows can comprise four blades220I-L evenly distributed at 90 degrees and rotated an angle of “T” from the first row. In the exemplary blade assembly210′, the second row of four blades220E-H can be rotated 60 degrees from the first row and the third row of four blades220I-L can be rotated 30 degrees from the first row to provide 360 degrees contact between the outer surface256of the scraper blade220and the inner surface112of the casing string108. Although the blade assembly210′ is illustrated with 3 rows of four blades220, it is understood that any combinations of rows and rotational spacing of blades can provide 360 degrees of contact. For example, the blade assembly210′ can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, or any number of scraper blades220angularly distributed in each row with 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of rows of scraper blades220to provide a combination configured for 360 degrees of outer surface256contact with the inner surface112of the casing108.

The selective tool200can be activated or cycled to one of three different functions by applying a predetermined pressure during a predetermined time interval. In some embodiments, the selective tool200can be cycled to a position, e.g., a second position, by a continuous flowrate of wellbore fluids302, e.g., drilling fluid, through the fluid passage234via the workstring122. The term pumping pressure “P” can be defined as the fluid pressure within the fluid passage234of the selective tool200can be increased proximate or adjacent to the fluid port298as a result of the flowrate of wellbore fluids302passing through the restriction304. Turning now toFIG.2C, the selective tool200can cycle from a first position, e.g., run-in position, to a second position, e.g., non-active position. The pumping pressure “P” can create a differential pressure within chamber288, e.g., higher pressure inside fluid chamber288compared to pressure outside of the piston assembly208. An activation force “F”, e.g., axial force parallel to the longitudinal axis, can be generated from the cross-sectional area “A1” of the inner surface290and the seal surface280. The piston cylinder276can move or axially translate to contact the first end sub306of the metering assembly206in response to the activation force. The activation force “F” can transfer from the as piston208to the metering assembly206and to the control device212by direct contact if separate assemblies or via a coupled connection. The activation force “F1” can initiate a transfer of fluid from the first chamber316to the second chamber318via the nozzle314. The activation force “F1” can increase the pressure of the volume of fluid in the first chamber316by bias or moving the first end sub306towards the piston boss312which decreases the volume of the first chamber316and increases the volume of the second chamber318. The volume of fluid can be defined as the volume of the first chamber316, the volume of the second chamber318, and a volume of fluid located within the nozzle314. The volume of the first chamber316can be defined as a cross-sectional area A2, e.g., inner surface of the housing308to the seal surface280of the second mandrel254, and a linear distance “D,” e.g., axial distance from the end face of the sub306to an end face of the piston boss312. The change in the volumes of the chambers316,318can generate a pressure differential across the nozzle314which initiates the transfer of fluid through the nozzle314at a predetermined flowrate. The flowrate through the nozzle314can be i) dependent or ii) independent on the pressure differential depending on the type of nozzle utilized.

A metering time “T” for the metering206to transfer a volume of fluid can be predetermined based on the nozzle314, e.g., metering device. In some embodiments, the metering time “T” can be a function of volume, force “F,” and the characteristics of the nozzle314. For example, a metering time “T1” can be determined for a first force “F1”, e.g., activation force “F,” a distance “D,” and the nozzle314. Likewise, a metering time “T2” can be determined for a second force “F2,” e.g., return force, a distance “D” and the nozzle314. In some embodiments, the force “F1” is the activation force, e.g., force generated by the piston assembly208. In some embodiments, the force “F2” is a biasing force of one or more return springs320. In some embodiments, the metering time “T1” and “T2” can be equivalent or nearly equivalent based on the forces “F1” and “F2” and the nozzles314. In some embodiments, the metering time “T1” and “T2” can be different based on the forces “F1” and “F2” and the nozzles314. In one scenario, the forces “F1” and “F2” are equivalent and the nozzle314may comprise a set of metering devices configured to restrict fluid transfer in one direction and allow fluid transfer in another direction, for example the nozzle314comprises an orifice and a check valve. In a second scenario, the forces “F1” and “F2” are different, e.g., “F1” is greater than “F2,” and the nozzle314can comprise two or more nozzles and/or orifices configured restrict fluid transfer in both directions. In a third scenario, the forces “F1” and “F2” can be different and the nozzle314can be configured to restrict fluid transfer in one direction and allow fluid transfer in the opposite direction, e.g., one or more orifices, a pressure relief valve, a flow metering valve, a check valve, or combinations thereof.

The distance “D” can be limited by the control pattern270within the inner surface266of the position control device212. A first distance “D1” can be the axial distance for the lug272to travel within the pattern270to a first position “P1.” A second distance “D2” can be the axial distance for the lug272to travel within the pattern270to a second position “P2.” A third distance “D3” can be the axial distance for the lug272to travel within the pattern270to a third position “P3.” The time interval for the lug272to travel the first distance “D1” to position “P1” can be “TID1.” The time interval for the lug272to travel back or return along the first distance “D1” can be “T2D1.” Similarly, the time interval for the lug272to travel the second distance “D2” to position “P2” can be “TID2” and the time interval to return can be “T2D2.” The time interval for the lug272to travel the third distance “D3” to position “P3” can be “TID3” and the time interval to return can be “T2D3.”

The lug272can be guided through the pattern270by the placement of one or more angled sides. Turning now toFIG.3A, an unrolled view of an inner surface of a control device can be described. In some embodiments, the position control device212can be a cylinder with a series of slots and/or grooves formed along the inner surface266. The lug272can be positioned in a first slot350for conveying the selective tool200into the string of casing108. The first slot350, e.g., groove, can be aligned with the first position “P1” by the pattern270. A force “F2” applied to the control device212from the one or more return springs320can retain or position the lug272in a first reset position352, e.g., end of the first slot350. As shown inFIG.2A, the one or more scraper blades220can be retained in an inactive position, e.g., positioned on the lower surface260of the wedge230in response to the lug272being located in the first reset position352.

The lug272can travel along a lug path to the first position “P1” in response to the first force “F1”, e.g., activation force, being greater than the second force “F2”, e.g., reset force. The lug path can comprise a set path354and a reset path362for each of the positions. The first force “F1” can be the activation force via the piston assembly208. In some embodiments, a flowrate of wellbore fluids302through the fluid passage234can generate a first force “F1” to axially translate the control device212over the lug272. For example, a wellbore servicing operation can deliver a flowrate of the wellbore fluids302at a predetermined flowrate for a predetermined time interval to axially translate the lug272along the first set path354A to the first position “P1.” The lug272can travel, e.g., axially translate, along the first slot350from the first reset position352to contact a first angle surface356. The contact with the first angle surface356can rotationally translate and axially translate the lug272along the first set path354A until the lug272is no longer in contact with the angle surface356. The lug272can travel, e.g., axially translate, along the first set path354A until the lug272contacts the second angle surface358. The contact with the second angle surface358can rotationally translate and axially translate the lug272along the first set path354A until the lug272enters a configuration slot360. The time interval for the lug272to travel a first set path354A to the first position “P1” can be “T1D1.” Although the lug272is described as following the lug path through the pattern270, it is understood that the motion is relative and thus, the control device212can axially and rotationally translate about a static embodiment of the lug272or the lug272can axially and rotationally translate through the pattern270of the static embodiment of the control device212.

Continuing withFIG.3A, the lug272can be located in the first position “P1” in response to the first force “F1” and the pattern270directing the lug272though the first set path354A. As shown inFIG.2C, the first position “P1” in the control pattern270can restrain and/or prevent the control device212from axially translating the wedge230under the one or more scraper blades220to deploy or extend the one or more blades220from the housing226. In some embodiments, the wellbore servicing operation can perform a portion of the servicing operation without the selective tool200active, e.g., the one or more scraper blades deployed. For example, the portion of the servicing operation can include pumping wellbore servicing fluids through the workstring122, conveying the workstring122through the casing string108, rotating the workstring122, or combinations thereof.

The lug272can return to the first reset position352by the removal of the first force “F1,” e.g., the activation force. In some embodiments, the servicing operation can stop pumping wellbore fluids down the workstring122. The reset force “F2,” e.g., spring320, can bias the control device212to axially translate and return the piston276of the device208to the run-in position or first position. The reset force “F2” can axially translate the control device212, the metering device206, and the device208to the run-in position. The lug272can exit the first position “P1,” travel along the configuration slot360A to contact a third angled surface364A. The contact with the third angle surface364A can rotationally translate and axially translate the lug272along the reset path362until the lug272is no longer in contact with the surface364A. The lug272can travel, e.g., axially translate, along the reset path362A until the lug272contacts a fourth angled surface366A. The contact with the fourth angle surface366A can rotationally translate and axially translate the lug272along the reset path362A until the lug272enters the first slot350A. The time interval for the lug272to travel a first reset path362A to the first reset position can be “T2D1.”

In some scenarios, the wellbore servicing operation can convey the selective tool200into the casing string108with the selective tool200in the run-in position, e.g., the first reset position352. In a scenario, the wellbore servicing operation can include a pumping operation for a time interval longer than “TID1” to locate the lug272into the first position “P1.” For example, the wellbore operation can circulate fluids down the workstring122, through the cleanout string124, out the drill bit132, and return fluids to surface for a time period greater than “TID1” as part of a wellbore servicing operation. In a scenario, the wellbore servicing operation may stop pumping fluid for a time period greater than “T2D1” to allow the selective tool200to return to the first reset position352.

The wellbore servicing operation may determine a need to position the tool into a second position “P2.” Turning now toFIG.3B, an unrolled view of an inner surface of a cylinder with the second position can be described. In a scenario, the wellbore servicing operation may begin a first pumping operation for a predetermined time, e.g., “T1D1,” to place the lug272into the first position “P1.” The wellbore servicing operation my stop pumping for a predetermined time to allow the lug272to travel along a portion of the first reset path362A. Before the lug272enters slot350A, the wellbore servicing operation may begin a second pumping operation to generate the force “F1” and the lug272may travel along a second set path354B for a predetermined time to reach the second position “P2.” The second set path364B can be identical to first set path364A with a second angle surface358B that directs the lug272into a slot360B with the position “P2.”

The pattern270within the control device212can be a repeating pattern with identical or substantively identical set paths354A-C, and reset paths362A-C. Turning now toFIG.3C, the unrolled view of an inner surface of a cylinder with the second position can be described. A second set path354B can comprise identical or near identical angled surfaces, e.g., surface356B, to direct the lug272along the lug path. For example, the lug272can travel, e.g., axially translate, along the second slot350B from the second reset position352B to contact a first angled surface356B, rotationally and axially translate the lug272along the second set path354B until the lug272is no longer in contact with the surface356B and the lug272contacts the second angle surface358B. The contact with the second angle surface358B can rotationally and axially translate the lug272along the second set path354B until the lug272enters a second slot360and contacts the second position P2. The time interval for the lug272to travel a second set path354B to the second position can be “TID2.”

The lug272can return from the second position “P2” to the second reset position352B along the second reset path362B. As previously described, the reset force “F2,” e.g., spring320, can bias the control device212to axially translate so that the lug272can exit the second position “P2,” travel along the slot360B to contact a third angled surface364B and rotationally and axially translate the lug272along the second reset path362B until the lug272is no longer in contact with the angled surface364B. The lug272can travel along the second reset path362B until the lug272contacts a fourth angled surface366B and rotationally and axially translate until the lug272enters the second slot350B. The time interval for the lug272to travel a second reset path362B to the second reset position352B can be “T2D2.”

Returning toFIG.2D, the selective tool200may be configured in a non-rotating scraper mode in response to the lug272being located in the second position “P2.” In some embodiments, the wellbore servicing operation can include a pumping operation that retains the lug272in the second position “P2.” The second position “P2” can compress the one or more return springs320and the housing spring324to axially translate the wedge230via one or more control rods322coupled to the wedge230. The one or more control rods322can include a sliding fit within the corresponding one or more rod ports242. The one or more scraper blades220can extend radially outward from the housing226as the inner surface258of the blade220moves from the lower surface260to the upper surface262of the wedge230. The outer surface256of the one or more blades220may be in contact with the inner surface112of the casing string108. AlthoughFIG.2Dillustrates a portion of the inner surface258engaged with or in contact with the upper surface262, it is understood that 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 100%, or any fraction therebetween of the inner surface258of the blade220may be supported by the wedge230.

The wellbore servicing operation can perform a wellbore cleaning operation with the selective tool200configured in the non-rotating scraper mode. For example, the one or more scraper blades220and the housing226may remain rotationally stationary, e.g., non-rotating, as the workstring122coupled to the chassis of the selective tool200, e.g., the first stabilizer222, the first mandrel224, second stabilizer228, and second mandrel254, rotates during the wellbore cleaning operation. In some embodiments, the inner surface246of the housing226can rotate about the outer surface250of the first stabilizer222and the outer surface252of the second stabilizer228.

In some embodiments, the wellbore cleaning operation may reconfigure the selective tool200from the non-rotating scraper mode to a rotating scraper mode. Referring back toFIG.3C, the wellbore cleaning operation cycle or reconfigure the selective tool200by stopping the pumping operation for a predetermined time interval to allow the lug272to travel a portion of the reset path362B. The pumping operation may begin again after the predetermined time interval to place the lug272within the path354C and (after a predetermined time period) located the lug272within the third position “P3.”

A third set path354C can comprise identical or near identical angled surfaces, e.g., surface356C, to direct the lug272along the lug path. For example, the lug272can travel, e.g., axially translate, along the third slot350C from the third reset position352C to contact a first angled surface356C, rotationally and axially translate the lug272along the third set path354C until the lug272is no longer in contact with the surface356C and the lug272contacts the second angle surface358C. The contact with the second angle surface358C can rotationally and axially translate the lug272along the third set path354C until the lug272enters a third slot360C and contacts the third position P3. The time interval for the lug272to travel a third set path354C to the third position “P3” can be “TID3.”

The lug272can return from the third position “P3” to the third reset position352C along the third reset path362C. As previously described, the reset force “F2,” e.g., spring320, can bias the control device212to axially translate so that the lug272can exit the third position “P3,” travel along the third slot360C to contact a third angled surface364C and rotationally and axially translate the lug272along the third reset path362C until the lug272is no longer in contact with the surface364C. The lug272can travel along the third reset path362C until the lug272contacts a fourth angled surface366C and rotationally and axially translate until the lug272enters the third slot350C. The time interval for the lug272to travel a third reset path362C to the third reset position352C can be “T2D3.”

Although the position control device212is described with the pattern270located about the inner surface266, it is understood that the position control device212can be an assembly of two or more parts, e.g., a body and a housing, coupled together. In some embodiments, the control device212and the lug272can swap places with the pattern270located on the outer surface268of the second mandrel254and the lug272and lug ring274can be located on the control device212.

Turning toFIG.2E, the selective tool200may be configured in a rotating scraper mode in response to the lug272being located in the third position “P3.” In some embodiments, the wellbore servicing operation can include a pumping operation that retains the lug272in the second position “P2.” The third position “P3” can compress the one or more return springs320and the housing spring324to axially translate the wedge230via one or more control rods322to couple a mandrel clutch326and/or a housing clutch328. The mandrel clutch326can comprise a set of mandrel castellations330engaged with a set of axial wedge castellations332. The housing clutch328can comprise a set of housing castellations334engaged with radial wedge castellations336. The mandrel clutch326and/or housing clutch328can rotationally couple the housing226to the wedge230and/or the first mandrel224so that the housing226and one or more scraper blades220within the windows248rotate with the first mandrel224. Although the mandrel clutch326and housing clutch328are described as comprising castellations, it is understood that the mandrel clutch326and housing clutch328can be formed by any shape that can engage or mesh or couple together, for example, gear teeth, spines, serrations, key way, or any other suitable coupling mechanism. The one or more scraper blades220can remain radially extended from the housing226and the inner surface258of the blade220can be engaged with the upper surface262of the wedge230. The outer surface256of the one or more scraper blades220may be in contact with the inner surface112of the casing string108.

The wellbore servicing operation can perform a wellbore cleaning operation with the selective tool200configured in the rotating scraper mode. For example, the one or more scraper blades220and the housing226may be rotationally coupled to the chassis of the selective tool200, e.g., mandrel224, rotate in response to rotation of the workstring122during the wellbore cleaning operation.

Although the selective tool200is described as operating in a second configuration after being reconfigured from a first configuration, it is understood that the selective tool200can be reconfigured from a first configuration, to a second configuration, and then to a third configuration before a wellbore servicing operation begins.

Although the scraper actuator214is described as generating the activation force “F1” via a piston assembly208and the metering assembly206, it is understood that the activation device can be any type of actuator configured to axially move or allow axial movement of distance “D3.” In an embodiment, the scraper actuator214can be i) a hydraulic system with a volume of fluid and a pump, ii) a single pressure source with a manifold, iii) a gas generator with a manifold, iv) a motor driving a gear system, v) a motor turning a threaded extension, or vi) an electromagnetic extend-retract actuator. In an embodiment, a pump actuator214comprises a first chamber and a second chamber fluidically connected to a battery powered or surface powered downhole pump that moves the sleeve actuator214to a second position by transferring a volume of fluid from a first chamber to a second chamber. In an embodiment, pressure actuator214comprises a pressure source fluidically coupled to a first chamber by a manifold that moves the sleeve actuator214to a second position by transferring a volume of fluid or gas to the first chamber. In an embodiment, a gear actuator214comprises a motor rotationally coupled to a gear system engaged to a threaded surface on a mandrel or extension rod that moves the gear actuator214to a second position by moving the gear system along the threaded surface. In an embodiment, the electromagnet actuator214comprises a plurality of electromagnets magnetically coupled to a plurality of permanent magnets on a mandrel that move the electromagnet actuator214to a second position by moving the permanent magnets relative to the electromagnets.

The selective tool200may comprise a unit controller coupled to the scraper actuator214to control the position of the lug272within the pattern270of the control device212. In an embodiment, the unit controller can comprise a processor, non-transitory memory, one or more sensors, and a communication device. The one or more sensors can include a pressure sensor fluidically coupled to the fluid passage234and one or more positional sensors coupled to the control device212. The pressure sensor can determine a pumping pressure value within the fluid passage234in response to a pumping operation. The unit controller can receive signals from the surface, for example, pressure applied to the fluid passage234of the selective tool200. The unit controller can direct the scraper actuator214to position the lug272into a first position “F1,” a second position “F2,” and/or a third position “F3.” The unit controller may direct one or more components of the scraper actuator214, for example, the pump, the manifold, the motor, or the plurality of electromagnets.

Turning now toFIG.7, a computer system700suitable for implementing one or more embodiments of the unit controller including without limitation any aspect of the computing system associated with the scraper actuator ofFIG.2. The computer system700includes one or more processors702(which may be referred to as a central processor unit or CPU) that is in communication with memory704, secondary storage706, input output devices710, and network devices. The computer system700may continuously monitor the state of the input devices and change the state of the output devices based on a plurality of programmed instructions. The programming instructions may comprise one or more applications retrieved from memory704for executing by the processor702in non-transitory memory within memory704. The input output devices may comprise a Human Machine Interface with a display screen and the ability to receive conventional inputs from the service personnel such as push button, touch screen, keyboard, mouse, or any other such device or element that a service personnel may utilize to input a command to the computer system700. The secondary storage706may comprise a solid state memory, a hard drive, or any other type of memory suitable for data storage. The secondary storage706may comprise removable memory storage devices such as solid state memory or removable memory media such as magnetic media and optical media, i.e., CD disks. The computer system700can communicate with various networks with the network devices714comprising wired networks, e.g., Ethernet or fiber optic communication, and short range wireless networks such as Wi-Fi (i.e., IEEE 802.11), Bluetooth, or other low power wireless signals such as ZigBee, Z-Wave, 6LoWPan, Thread, and WiFi-ah. The computer system700may include a transceiver218for communicating wirelessly.

In some embodiments, the computer system700may comprise a DAQ card716for communication with one or more sensors. The DAQ card716may be a standalone system with a microprocessor, memory, and one or more applications executing in memory. The DAQ card716may be a card or a device within the computer system700. In some embodiments, the DAQ card716may be combined with the input output device710. The DAQ card716may receive one or more analog inputs, one or more frequency inputs, and one or more Modbus inputs. For example, the analog input may include a positional sensor, e.g., a linear sensor. For example, the frequency input may include a flow meter, i.e., a fluid system flowrate sensor. For example, the Modbus input may include a pressure transducer. The DAQ card716may convert the signals received via the analog input, the frequency input, and the Modbus input into the corresponding sensor data. For example, the DAQ card716may convert a frequency input from the flowrate sensor into flowrate data measured in gallons per minute (GPM).

ADDITIONAL DISCLOSURE

The following are non-limiting, specific embodiments in accordance and with the present disclosure.

A first embodiment, which is a wellbore cleaning tool configurable for cleaning an inner surface of a downhole tubular, comprising: a tool mandrel generally cylinder in shape with an outer surface, an inner fluid passage, one or more fluid ports, and a mandrel clutch; a scraper actuator located on the tool mandrel configured to generate an activation force, wherein the scraper actuator is fluidically coupled to the one or more fluid ports; a blade assembly located on the tool mandrel proximate the mandrel clutch comprising one or more scraper blades located in corresponding windows in a housing; and a control device located on the tool mandrel between the scraper actuator and the blade assembly comprising at least one lug located within a control pattern; wherein an outer surface of each of the one or more scraper blades is configured to contact the inner surface of the downhole tubular in the extended position.

A second embodiment, which is the wellbore cleaning tool of the first embodiment, wherein: the one or more fluid ports are fluidically coupled to the fluid passage within the tool mandrel; wherein fluid pressure within the fluid passage is generated in response to a pumping operation; and wherein fluid pressure applied to one or more fluid ports generates the activation force via the scraper actuator.

A third embodiment, which is the wellbore cleaning tool of the second embodiment, wherein the scraper actuator comprises i) a piston comprising a fluid chamber coupled to the one or more fluid ports, ii) a hydraulic system with a volume of fluid and a pump, iii) a single pressure source with a manifold, iv) a gas generator with a manifold, v) a motor driving a gear system, vi) a motor turning a threaded extension, vii) an electromagnetic actuator, or ix) combinations thereof.

A fourth embodiment, which is the wellbore cleaning tool of the third embodiment, wherein the scraper actuator further comprises a metering assembly configured to i) travel a first distance in a first direction within a first time interval and ii) travel a second distance in a second direction within a second time interval.

A fifth embodiment, which is the wellbore cleaning tool of the fourth embodiment, wherein: the metering assembly comprises a volume of fluid within a first chamber fluidically coupled to a second chamber by one or more metering devices; wherein the fluid is substantially incompressible; and wherein the one or more metering devices regulate a flowrate of fluid from the first chamber to the second chamber in the first direction and from the second chamber to the first chamber in the second direction.

A sixth embodiment, which is the wellbore cleaning tool of the first embodiment, wherein the control pattern comprises a first position and a second position, wherein the lug located in the first position configures the blade assembly in a retracted position, and wherein the lug located in the second position configures the blade assembly in an extended position.

A seventh embodiment, which is the wellbore cleaning tool of the first embodiment, wherein: the control device comprises at least two set positions selected from a group of i) a retracted position, ii) a non-rotating scraper position, and iii) a rotating scraper position; where the control pattern comprises a set path for directing the lug from a reset position to one of the at least two set positions; wherein the set path comprises one or more angled surfaces and a configuration slot with the at least two set positions a distance of i) D1, ii) D2, or iii) D3 from the reset position; and wherein the control pattern comprises a reset path for directing the lug from each of the set position to the reset position.

A eighth embodiment, which is the wellbore cleaning tool of the seventh embodiment, wherein: the lug travels along the set path in response to the scraper actuator applying an activation force; wherein the lug travels along the reset path in response to a biasing force from one or more reset springs; wherein the set path for the second position is coincident with the reset path of the first position; wherein the set path for a third position is coincident with the reset path of the second position; and wherein the set path for the first position is coincident with the reset path of the third position.

A ninth embodiment, which is the wellbore cleaning tool of the eighth embodiment, wherein: the lug travels from a first set position to a second set position in response to ending the activation force for a predetermined time period and reapplying the activation force at the end of the predetermined time period.

A tenth embodiment, which is the wellbore cleaning tool of the first embodiment, wherein: the one or more scraper blades are radially extended from a run-in retracted position to an extended position in response to a wedge axially translating from a first position to a second position; wherein the run-in position is the first position within the control device; wherein the extended position is the second position or a third position within the control device; wherein the control device axially translates the wedge via one or more control rods; and wherein a housing spring is configured to bias the wedge to return to the first position.

An eleventh embodiment, which is the wellbore cleaning tool of the tenth embodiment, further comprising: a housing clutch comprising a set of housing castellations on the inner surface of the housing and a set of radial castellations on the outer surface of the wedge; wherein the housing clutch is configured to allow rotation of the housing in response to not being engaged; and wherein the housing clutch is not engaged in the first and second position.

A twelfth embodiment, which is the wellbore cleaning tool of the eleventh embodiment, wherein: the housing clutch is engaged in the third position; wherein the set of housing castellations engage with the set of radial castellations; and wherein the housing clutch is configured to stop rotation of the housing in response to being engaged.

A thirteenth embodiment, which is a method of cleaning debris from a portion of a wellbore with one or more selective scraper tools, comprising: conveying one or more selective scraper tools, via a workstring, from a surface location to a target depth within the wellbore; pumping a wellbore fluid through a fluid passage within the selective scraper tool via the workstring; extending one or more scraper blades from a housing by axially translating a wedge from a first position to a second position or a third position; conveying the selective scraper tool within a target zone within the wellbore; and returning the one or more selective scraper tools to a surface location.

A fourteenth embodiment, which is the method of thirteenth embodiment, further comprising: signaling a scraper actuator from the surface location to actuate a blade assembly by directing a lug within a control pattern to travel from the first position to the second position or the third position.

A fifteenth embodiment, which is the method of thirteenth or fourteenth embodiment, further comprising: axially translating the wedge from a first position to the second position or the third position in response to an activation force axially and rotationally translating a control device slidingly coupled with a lug; directing the lug within a control pattern of the control device to travel along a lug path from a reset location to a set position, wherein the lug path comprises one or more angled surfaces, wherein the lug path comprises a set path and a reset path, wherein the lug travels along the set path in response to the activation force, and wherein the lug travels along the reset path in response to a biasing force from a return spring; directing the lug from the first position within the control pattern to a subsequent position by stopping an actuation force for a predetermined time period and reapplying the actuation force after the predetermined time period, wherein the lug travels along the reset path in response to the biasing force of the return spring during the predetermined time period, and wherein the lug travels along a set path for the subsequent position in response to the activation force after the predetermined time period, and wherein the set path for the subsequent position is aligned with the reset path of the first position; and wherein the subsequent position is the second position or the third position.

A sixteenth embodiment, which is the method of any of the thirteenth through fifteenth embodiments, wherein the selective scraper is configured in a non-rotating scraper mode in the second position.

A seventeenth embodiment, which is the method of any of the thirteenth through sixteenth embodiments, wherein the selective scraper is configured in a rotating scraper mode in the third position.

An eighteenth embodiment, which is the method of any of the thirteenth through seventeenth embodiments, wherein: the one or more selective scraper tools are configured with the one or more scraper blades in contact with an inner surface of the wellbore a first target depth at a beginning the target zone; wherein the one or more selective scraper tools are conveyed to a second target depth at an end of the target zone with the one or more scraper blades in contact with the wellbore; and wherein the workstring is rotated in response to the one or more scrapers being configured in a rotating scraper mode.

A nineteenth embodiment, which is a downhole wellbore cleaning system, comprising: a selective scraper tool coupled to a workstring; and a debris removal tool coupled to the workstring proximate to the selective scraper tool, wherein the debris removal tool is i) a service packer, ii) a circulation valve, iii) a junk basket, iv) a casing scraper, v) a casing brush, vi) a well screen, vii) a milling shoe, viii) a drill bit, or ix) combinations thereof, wherein the selective scraper tool and debris removal tool are conveyed into a wellbore to a target depth via the workstring; wherein the selective scraper tool comprises one or more scraper blades located within corresponding windows in a housing, wherein the scraper blades are retracted in a first position, wherein the scraper blades are extended radially from the housing in a second position or a third position, wherein the scraper blades contact an inner surface of a wellbore in response to being extended radially; wherein the selective scraper tool is configured in a first position for conveyance into the wellbore; wherein the selective scraper tool is configured in a second position in response to a first wellbore cleaning operation utilizing a debris removal tool; and wherein the selective scraper tool is configured in the third position in response to a completion of the first wellbore cleaning operation.

A twentieth embodiment, which is the downhole wellbore cleaning system of the nineteenth embodiment, wherein: the second position of the selective scraper tool is a non-rotating scraper mode with the one or more scraper blades in contact with the inner surface of the wellbore; wherein a wedge is axially moved from a first position or a third position to a second position to radially extend the one or more scraper blades in the second position; and wherein the wedge is axially translated by a scraper actuator via a lug engaged in a control pattern, wherein an actuation force from the scraper actuator urges the wedge into the second position by placement of the lug into the second position of the control pattern.

A twenty-first embodiment, which is the downhole wellbore cleaning system of the nineteenth or twentieth embodiment, wherein: the third position of the selective scraper tool is a rotating scraper mode with the one or more scraper blades in contact with the inner surface of the wellbore; wherein a wedge is axially moved from either a first position or a second position to a third position to radially extend the one or more scraper blades in the third position; wherein a set of radial wedge castellations engage a set of radial housing castellations; wherein the housing is rotationally coupled to the wedge by the engagement of the castellations; and wherein the wedge is axially translated by a scraper actuator via a lug engaged in a control pattern, wherein an actuation force from the scraper actuator urges the wedge into the third position by placement of the lug into the third position of the control pattern.

While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−Rl), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.