Load-monitoring sensor proximate to a shifting device

A downhole tool includes a shifting device and a load-monitoring sensor positioned above the shifting device. A distance between the shifting device and the load-monitoring sensor is less than or equal to about 10 m.

BACKGROUND

A shifting device is a part of a downhole tool that may be used to shift one or more sleeves in a wellbore. For example, a completion assembly positioned within the wellbore may include a plurality of sleeves that are axially-offset from one another. The downhole tool may be run inside the completion assembly, and an engagement member (e.g., a collet) on the shifting device may be used to engage a first of the sleeves. Once engaged, the downhole tool is moved axially to shift the first sleeve from a first position (e.g., closed) to a second position (e.g., open). The engagement member may then disengage the first sleeve, and the downhole tool may be moved axially until the engagement member engages a second of the sleeves, where the process may be repeated. Rather than disengaging the first sleeve, the downhole tool may instead be moved axially to shift the first sleeve from the second position back to the first position, after which time the engagement member may disengage the first sleeve, and the downhole tool may be moved axially until the engagement member engages a second of the sleeves, where the process may be repeated.

It may be desirable to know the load on the shifting device when the shifting device engages and/or shifts the sleeves. For example, this knowledge may be used to identify sleeves that are not functioning (e.g., shifting) properly. The load on the shifting device may be determined by monitoring the hook load at the surface. However, monitoring the hook load may yield inaccurate results when the drill string is made up of multiple segments/joints that have different properties (e.g., inner diameter, outer diameter, material grade, etc.). Monitoring the hook load may also yield inaccurate results when the wellbore includes one or more deviated or horizontal sections or when there are restrictions in the wellbore. Currently, the load is determined in deviated and horizontal wellbores using one-time shear indicators. However, one-time shear indicators cannot measure the load for multiple sleeves.

SUMMARY

A downhole tool is disclosed. The downhole tool includes a shifting device and a load-monitoring sensor positioned above the shifting device. A distance between the shifting device and the load-monitoring sensor is less than or equal to about 10 m.

In another embodiment, the downhole tool includes a sand control device, a tubular member, a shifting device, and a load-monitoring sensor. The tubular member is coupled to and positioned below the sand control device. The shifting device is coupled to the tubular member. The load-monitoring sensor is coupled to the tubular member and positioned between the sand control device and the shifting device.

A method for determining a load on a downhole tool is also disclosed. The method includes running the downhole tool into a wellbore. The downhole tool includes a sand control device, a tubular member coupled to and positioned below the sand control device, a shifting device coupled to the tubular member, and a load-monitoring sensor coupled to the tubular member and positioned between the sand control device and the shifting device. The method also includes moving the downhole tool within the wellbore until the shifting device contacts a restriction in the wellbore. The method further includes measuring, with the load-monitoring sensor, a load on the downhole tool caused by the contact between the shifting device and the restriction.

DETAILED DESCRIPTION

Reference will now be made in detail to embodiments, examples of which are illustrated in the accompanying figures. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be apparent to one of ordinary skill in the art that the system and method disclosed herein may be practiced without these specific details.

FIG. 1illustrates a half-sectional side view of a downhole tool100, according to an embodiment. The downhole tool100may include a sand control device110. The sand control device110may include a setting module112, a crossover module114, and a locating collet116.

The downhole tool100may also include a tubular member (e.g., a wash pipe)120. The tubular member120may be coupled to and positioned below the sand control device110. The tubular member120may include a single joint or multiple joints that are coupled together. An axial bore122may extend through the tubular member120and at least partially through the sand control device110.

The downhole tool100may also include a shifting device130. The shifting device130may be coupled to the tubular member120. More particularly, the shifting device130may be (or be part of) a separate sub that is coupled to one joint and/or positioned between two joints of the tubular member120. The shifting device130may include one or more engagement members (e.g., collets)132that are used to open, close, and/or shift the position of downhole flow control or circulation devices (e.g., sleeves).

The downhole tool100may also include a load-monitoring sensor140. The load-monitoring sensor140may be positioned axially-between the sand control device110and the shifting device130. As shown, the load-monitoring sensor140may be positioned above and proximate to the shifting device130. For example, a distance between the load-monitoring sensor140and the shifting device130may be less than or equal to about 50 m, less than or equal to about 10 m, or less than or equal to about 3 m. By positioning the load-monitoring sensor140within the downhole tool100and within the distance described above from the shifting device130, the load-monitoring sensor140may yield more accurate results than if positioned above the downhole tool100(e.g., within the drill string160). As shown, the load-monitoring sensor140may be coupled to and/or positioned within a separate sub that is coupled to the shifting device130. In another example, the load-monitoring sensor140may be coupled to and/or positioned within a separate sub that is positioned between two joints of the tubular member120. In yet another example, the load-monitoring sensor140may be positioned at least partially within one of the joints of the tubular member120.

The load-monitoring sensor140may measure a load on the shifting device130and/or the downhole tool100when the shifting device130contacts or engages a restriction in the wellbore. More particularly, the load-monitoring sensor140may measure how much the load on the downhole tool100increases or decreases (i.e., a load differential) in response to the shifting device130contacting or engaging the restriction in the wellbore. The load may be an axial tension load, an axial compression load, a rotational load, or a combination thereof. The load-monitoring sensor140may be or include a strain gauge, a load cell, or the like. The restriction may be or include a sleeve, a reduced cross-sectional area (e.g., diameter) in the wellbore, a bend in the wellbore, debris in the wellbore, or the like.

The downhole tool100may also include a first physical property sensor150. The first physical property sensor150may be positioned axially-between the sand control device110and the shifting device130. As shown, the first physical property sensor150may be positioned axially-between the sand control device110and the load-monitoring sensor140. The first physical property sensor150may be coupled to and/or positioned within a separate sub that is positioned between two joints of the tubular member120. In another example, the first physical property sensor150may be coupled to and/or positioned within one of the joints of the tubular member120. In yet another example, the first physical property sensor150may be positioned in the same joint or sub as the load-monitoring sensor140. The first physical property sensor150may measure pressure, temperature, wellbore trajectory, or a combination thereof. In other embodiments, the first physical property sensor150may also measure formation properties such as resistivity, porosity, sonic velocity, and gamma ray.

The downhole tool100(e.g., the sand control device110) may be coupled to a drill string160. The drill string160may be used to raise and lower the downhole tool100within a wellbore. The drill string160may include a second physical property sensor170coupled thereto and/or positioned therein. For example, the second physical property sensor170may be coupled to and/or positioned within one of the joints of the drill string160. In another example, the second physical property sensor170may be coupled to and/or positioned within a separate sub that is positioned between two joints of the drill string160. As shown, the second physical property sensor170may be positioned above and proximate to the downhole tool100. The second physical property sensor170may measure pressure, temperature, wellbore trajectory, or a combination thereof.

FIG. 2illustrates a half-sectional side view of a completion assembly200, according to an embodiment. The completion assembly200may have a bore202formed axially-therethrough. The completion assembly200may include a packer210that is configured to expand radially-outward to engage a surrounding tubular member (e.g., a casing or the wall of the wellbore). The completion assembly200may also include a gravel pack extension220. The gravel pack extension220may include one or more ports. A sleeve may be configured to prevent flow through the ports in a first position and to allow flow through the ports in a second position. The gravel pack extension220may also include a locating/set-down collar. The sleeve and/or the locating/set-down collar may interact with the collet on the sand control device110.

The completion assembly200may also include a fluid-loss device positioned below the gravel pack extension220. The fluid-loss device may be or include a flapper that allows fluid to flow in one direction, but not the opposing direction. In another embodiment, the fluid-loss device may be or include a ball-type valve that prevents flow in both directions. In yet another embodiment, the fluid-loss device may be a sleeve that opens and closes.

The completion assembly200may also include one or more screens (seven are shown:230). The screens230may include a plurality of openings that are sized to allow fluid and particles having a cross-sectional length (e.g., diameter) less than a predetermined amount to pass therethrough, while preventing particles having a cross-sectional length (e.g., diameter) greater than a certain amount from passing therethrough.

The completion assembly200may also include one or more sleeves (one is shown:240). The sleeve240may include an engagement member242that is configured to engage (e.g., receive) the engagement member132of the shifting device130. The engagement member242of the sleeve240may be or include a groove. As described in greater detail below, when the engagement member132of the shifting device130is engaged with the engagement member242of the sleeve240, axial movement of the downhole tool100with respect to the completion assembly200may cause the sleeve240to shift from a first position (e.g., closed) to a second position (e.g., open). In one example, when the sleeve240is in the first position, the sleeve240may allow fluid flow through an opening, and when the sleeve240is in the second position, the sleeve240may prevent fluid flow through the opening.

FIG. 3illustrates a half-sectional side view of the downhole tool100positioned within the completion assembly200, according to an embodiment. As shown, the downhole tool100may be run into a wellbore and inserted at least partially into the completion assembly200. Although shown as axially-offset from the sleeve240inFIG. 3, as described in greater detail below, the downhole tool100may be moved (e.g., picked up) with respect to the completion assembly200to allow the engagement member132of the shifting device130to engage the engagement member242of the sleeve240.

A gravel slurry may be pumped into the wellbore when the downhole tool100is positioned within the completion assembly200. The gravel slurry may flow down the drill string160, as shown by arrow302. The gravel slurry may then flow out of the crossover in the sand control device110and into an annulus between the completion assembly200and the surrounding tubular (e.g., casing or wall of the wellbore), as shown by arrow304. A portion of the gravel slurry (e.g., a carrier fluid) may flow from the annulus between the surrounding tubular and the completion assembly200, through the screens230, and into an annulus between the completion assembly and the downhole tool100, as shown by arrows306. Gravel particles from the gravel slurry may remain in the annulus between the surrounding tubular and the completion assembly200when the carrier fluid flows through the screens230. The carrier fluid may then flow into the tubular member120through an end thereof, as shown by arrow308. The carrier fluid may then flow through the crossover in the sand control device110and into an annulus between the drill string160and the surrounding tubular, as shown by arrow310.

FIG. 4illustrates a side view of a sub400having the load-monitoring sensor140coupled thereto and/or positioned therein, andFIG. 5illustrates a cross-sectional side view (rotated 90° fromFIG. 4) of the sub400shown inFIG. 4, according to an embodiment. As mentioned above, the sub400may be coupled to the tubular member120and/or the shifting device130shown inFIG. 1.

The sub400may include a body (also referred to as a mandrel)410. In at least one embodiment, the body410may be eccentric. The body410may have an axial bore412formed therethrough. The axial bore412of the body410may be aligned, and in fluid communication, with the axial bore122of the tubular member120. The carrier fluid may flow through the axial bore412of the body410.

The body410may also define a recess414in an outer surface thereof. The load-monitoring sensor140may be or include a load cell that is positioned at least partially within the recess414formed in the outer surface of the body410. When the shifting device130encounters a restriction (e.g., the sleeve240) in the wellbore, the load-monitoring sensor140may measure the load induced by the engagement between the shifting device130and the restriction (e.g., the sleeve240). A memory module420may also be positioned at least partially within the recess414formed in the outer surface of the body410. The measurement from the load-monitoring sensor140may be recorded/stored in the memory module420.

FIG. 6illustrates a cross-sectional side view of another sub600having one or more load-monitoring sensors (two are shown:140A,140B) coupled thereto and/or positioned therein, according to an embodiment. As mentioned above, the sub600may be coupled to the tubular member120and/or the shifting device130shown inFIG. 1. The sub600may include a body (also referred to as a mandrel)610. The body610may define one or more recesses in an outer surface thereof. As shown, the recesses may be circumferentially-offset from one another.

The load-monitoring sensors140A,140B may be or include strain gauges that are positioned at least partially within the recesses formed in the outer surface of the body610. For example, the load-monitoring sensors140A,140B may be circumferentially-offset from one another. When the shifting device130encounters a restriction (e.g., the sleeve240) in the wellbore, the load-monitoring sensors140A,140B may measure the load induced by the engagement between the shifting device130and the restriction (e.g., the sleeve240). The measurement may be stored in the memory module620.

FIG. 7illustrates an end view of the sub600shown inFIG. 6, according to an embodiment. Referring toFIGS. 6 and 7, the memory module620may be positioned within the body610. For example, the memory module620may be positioned radially-inward from the body610such that a central longitudinal axis through the body610extends through the memory module620.

One or more support members (three are shown:614) may extend radially-between the body610and the memory module620. The support members614may be coupled to or integral with the body610. One or more axial flow channels (three are shown:612) may be positioned radially-outward from the memory module620. For example, each axial flow channel612may be positioned circumferentially-between two radial support members614. The axial flow channels612may provide a path of fluid communication through the sub600. For example, the carrier fluid may flow through the axial flow channels612.

FIG. 8illustrates a flowchart of a method800for determining a load on a shifting device130, according to an embodiment. The method800may include running the downhole tool100into a wellbore, as at802. In at least one embodiment, the downhole tool100may be run into a completion assembly200that is positioned within the wellbore, as shown inFIG. 3.

The method800may also include pumping a gravel slurry into the wellbore, as at804. This is described in greater detail above with respect toFIG. 3. Before or after the gravel slurry is pumped into the wellbore, the method800may also include moving the downhole tool100axially within the wellbore until the shifting device130contacts a restriction in the wellbore, as at806. As mentioned above, in at least one embodiment, the restriction may be the sleeve240in the completion assembly200, and contacting the restriction may include engaging the sleeve240with the shifting device130.

The method800may also include measuring, with the load-monitoring sensor140, a load on the downhole tool100(e.g., on the shifting device130) caused by the contact/engagement between the shifting device130and the restriction, as at808. The method800may also include storing the measured load in a memory module420,620in the downhole tool100, as at810. In at least one embodiment, the method800may also include storing a time that the load is measured (i.e., a time stamp) in the memory module420,620, as at812.

The method800may also include recovering the measured load and the time from the memory module420,620, as at814. In at least one embodiment, the downhole tool100may be pulled back to the surface to recover the measured load. In another embodiment, the downhole tool100may include a telemetry module (not shown) that may transmit the measured load up to the surface while the downhole tool100is in the wellbore. For example, the telemetry module may transmit the measured load using mud-pulse telemetry or electromagnetic (“EM”) telemetry.

The method800may also include determining a depth of the downhole tool100in the wellbore at a time that the load on the downhole tool100is measured, as at816. The depth of the downhole tool100may be determined by comparing the time that the load is measured (i.e., the time stamp) against a log maintained by an operator at the surface. The log may include the depth of the downhole tool100versus time. The depth of the downhole tool100may be measured, for example, by adding up the length of the joints that make up the drill string160.

The method800may also include determining whether the depth of the downhole tool100corresponds to a depth of the sleeve240in the wellbore, as at818. The depth of the sleeve240in the wellbore may be known. Thus, the operator may compare the depth of the downhole tool100to the depth of the sleeve240to determine whether the depth of the downhole tool100corresponds to the depth of the sleeve240. When the depth of the downhole tool100corresponds to the depth of the sleeve240, and the measured load on the downhole tool100is greater than a predetermined threshold, indicating that the sleeve240is not functioning (e.g., shifting) properly, the method800may include pulling the downhole tool100out of the wellbore, and running a second downhole tool into the wellbore to repair or disable the sleeve240, as at820. When the depth of the downhole tool100does not correspond to the depth of the sleeve240, this may indicate that the restriction is not the sleeve240. Rather, the restriction may be or include debris in the wellbore. When the depth of the downhole tool100does not correspond to the depth of the sleeve240, and the measured load on the downhole tool100is greater than a predetermined threshold, the method800may include pulling the downhole tool100out of the wellbore, and running a second downhole tool into the wellbore clear the restriction, as at822.

As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.” As used herein, “about,” “approximately,” “substantially,” and “significantly” will be understood by persons of ordinary skill in the art and will vary to some extent on the context in which they are used. If there are uses of the term which are not clear to persons of ordinary skill in the art given the context in which it is used, “about” and “approximately” will mean plus or minus 10% of the particular term and “substantially” and “significantly” will mean plus or minus 10% of the particular term.

The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principals of the invention and its practical applications, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.