Patent Application
20190353026
This application is a divisional of U.S. Patent Application Publication No. 2018/0058190, filed Aug. 25, 2016.
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.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
A downhole tool according to one or more embodiments of the present disclosure 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.
A method for determining a load on a downhole tool according to one or more embodiments of the present disclosure includes running the downhole tool into a wellbore, wherein 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, moving the downhole tool within the wellbore until the shifting device contacts a restriction in the wellbore, and measuring, with the load-monitoring sensor, a load on the downhole tool caused by the contact between the shifting device and the restriction.
The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings. In the figures:
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.
The downhole tool 100 may also include a tubular member (e.g., a wash pipe) 120. The tubular member 120 may be coupled to and positioned below the sand control device 110. The tubular member 120 may include a single joint or multiple joints that are coupled together. An axial bore 122 may extend through the tubular member 120 and at least partially through the sand control device 110.
The downhole tool 100 may also include a shifting device 130. The shifting device 130 may be coupled to the tubular member 120. More particularly, the shifting device 130 may be (or be part of) a separate sub that is coupled to one joint and/or positioned between two joints of the tubular member 120. The shifting device 130 may include one or more engagement members (e.g., collets) 132 that are used to open, close, and/or shift the position of downhole flow control or circulation devices (e.g., sleeves).
The downhole tool 100 may also include a load-monitoring sensor 140. The load-monitoring sensor 140 may be positioned axially-between the sand control device 110 and the shifting device 130. As shown, the load-monitoring sensor 140 may be positioned above and proximate to the shifting device 130. For example, a distance between the load-monitoring sensor 140 and the shifting device 130 may 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 sensor 140 within the downhole tool 100 and within the distance described above from the shifting device 130, the load-monitoring sensor 140 may yield more accurate results than if positioned above the downhole tool 100 (e.g., within the drill string 160). As shown, the load-monitoring sensor 140 may be coupled to and/or positioned within a separate sub that is coupled to the shifting device 130. In another example, the load-monitoring sensor 140 may be coupled to and/or positioned within a separate sub that is positioned between two joints of the tubular member 120. In yet another example, the load-monitoring sensor 140 may be positioned at least partially within one of the joints of the tubular member 120.
The load-monitoring sensor 140 may measure a load on the shifting device 130 and/or the downhole tool 100 when the shifting device 130 contacts or engages a restriction in the wellbore. More particularly, the load-monitoring sensor 140 may measure how much the load on the downhole tool 100 increases or decreases (i.e., a load differential) in response to the shifting device 130 contacting 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 sensor 140 may 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 tool 100 may also include a first physical property sensor 150. The first physical property sensor 150 may be positioned axially-between the sand control device 110 and the shifting device 130. As shown, the first physical property sensor 150 may be positioned axially-between the sand control device 110 and the load-monitoring sensor 140. The first physical property sensor 150 may be coupled to and/or positioned within a separate sub that is positioned between two joints of the tubular member 120. In another example, the first physical property sensor 150 may be coupled to and/or positioned within one of the joints of the tubular member 120. In yet another example, the first physical property sensor 150 may be positioned in the same joint or sub as the load-monitoring sensor 140. The first physical property sensor 150 may measure pressure, temperature, wellbore trajectory, or a combination thereof. In other embodiments, the first physical property sensor 150 may also measure formation properties such as resistivity, porosity, sonic velocity, and gamma ray.
The downhole tool 100 (e.g., the sand control device 110) may be coupled to a drill string 160. The drill string 160 may be used to raise and lower the downhole tool 100 within a wellbore. The drill string 160 may include a second physical property sensor 170 coupled thereto and/or positioned therein. For example, the second physical property sensor 170 may be coupled to and/or positioned within one of the joints of the drill string 160. In another example, the second physical property sensor 170 may be coupled to and/or positioned within a separate sub that is positioned between two joints of the drill string 160. As shown, the second physical property sensor 170 may be positioned above and proximate to the downhole tool 100. The second physical property sensor 170 may measure pressure, temperature, wellbore trajectory, or a combination thereof.
The completion assembly 200 may also include a fluid-loss device positioned below the gravel pack extension 220. 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 assembly 200 may also include one or more screens (seven are shown: 230). The screens 230 may 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 assembly 200 may also include one or more sleeves (one is shown: 240). The sleeve 240 may include an engagement member 242 that is configured to engage (e.g., receive) the engagement member 132 of the shifting device 130. The engagement member 242 of the sleeve 240 may be or include a groove. As described in greater detail below, when the engagement member 132 of the shifting device 130 is engaged with the engagement member 242 of the sleeve 240, axial movement of the downhole tool 100 with respect to the completion assembly 200 may cause the sleeve 240 to shift from a first position (e.g., closed) to a second position (e.g., open). In one example, when the sleeve 240 is in the first position, the sleeve 240 may allow fluid flow through an opening, and when the sleeve 240 is in the second position, the sleeve 240 may prevent fluid flow through the opening.
A gravel slurry may be pumped into the wellbore when the downhole tool 100 is positioned within the completion assembly 200. The gravel slurry may flow down the drill string 160, as shown by arrow 302. The gravel slurry may then flow out of the crossover in the sand control device 110 and into an annulus between the completion assembly 200 and the surrounding tubular (e.g., casing or wall of the wellbore), as shown by arrow 304. A portion of the gravel slurry (e.g., a carrier fluid) may flow from the annulus between the surrounding tubular and the completion assembly 200, through the screens 230, and into an annulus between the completion assembly and the downhole tool 100, as shown by arrows 306. Gravel particles from the gravel slurry may remain in the annulus between the surrounding tubular and the completion assembly 200 when the carrier fluid flows through the screens 230. The carrier fluid may then flow into the tubular member 120 through an end thereof, as shown by arrow 308. The carrier fluid may then flow through the crossover in the sand control device 110 and into an annulus between the drill string 160 and the surrounding tubular, as shown by arrow 310.
The sub 400 may include a body (also referred to as a mandrel) 410. In at least one embodiment, the body 410 may be eccentric. The body 410 may have an axial bore 412 formed therethrough. The axial bore 412 of the body 410 may be aligned, and in fluid communication, with the axial bore 122 of the tubular member 120. The carrier fluid may flow through the axial bore 412 of the body 410.
The body 410 may also define a recess 414 in an outer surface thereof. The load-monitoring sensor 140 may be or include a load cell that is positioned at least partially within the recess 414 formed in the outer surface of the body 410. When the shifting device 130 encounters a restriction (e.g., the sleeve 240) in the wellbore, the load-monitoring sensor 140 may measure the load induced by the engagement between the shifting device 130 and the restriction (e.g., the sleeve 240). A memory module 420 may also be positioned at least partially within the recess 414 formed in the outer surface of the body 410. The measurement from the load-monitoring sensor 140 may be recorded/stored in the memory module 420.
The load-monitoring sensors 140A, 140B may be or include strain gauges that are positioned at least partially within the recesses formed in the outer surface of the body 610. For example, the load-monitoring sensors 140A, 140B may be circumferentially-offset from one another. When the shifting device 130 encounters a restriction (e.g., the sleeve 240) in the wellbore, the load-monitoring sensors 140A, 140B may measure the load induced by the engagement between the shifting device 130 and the restriction (e.g., the sleeve 240). The measurement may be stored in the memory module 620.
One or more support members (three are shown: 614) may extend radially-between the body 610 and the memory module 620. The support members 614 may be coupled to or integral with the body 610. One or more axial flow channels (three are shown: 612) may be positioned radially-outward from the memory module 620. For example, each axial flow channel 612 may be positioned circumferentially-between two radial support members 614. The axial flow channels 612 may provide a path of fluid communication through the sub 600. For example, the carrier fluid may flow through the axial flow channels 612.
The method 800 may also include pumping a gravel slurry into the wellbore, as at 804. This is described in greater detail above with respect to
The method 800 may also include measuring, with the load-monitoring sensor 140, a load on the downhole tool 100 (e.g., on the shifting device 130) caused by the contact/engagement between the shifting device 130 and the restriction, as at 808. The method 800 may also include storing the measured load in a memory module 420, 620 in the downhole tool 100, as at 810. In at least one embodiment, the method 800 may also include storing a time that the load is measured (i.e., a time stamp) in the memory module 420, 620, as at 812.
The method 800 may also include recovering the measured load and the time from the memory module 420, 620, as at 814. In at least one embodiment, the downhole tool 100 may be pulled back to the surface to recover the measured load. In another embodiment, the downhole tool 100 may include a telemetry module (not shown) that may transmit the measured load up to the surface while the downhole tool 100 is in the wellbore. For example, the telemetry module may transmit the measured load using mud-pulse telemetry or electromagnetic (“EM”) telemetry.
The method 800 may also include determining a depth of the downhole tool 100 in the wellbore at a time that the load on the downhole tool 100 is measured, as at 816. The depth of the downhole tool 100 may 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 tool 100 versus time. The depth of the downhole tool 100 may be measured, for example, by adding up the length of the joints that make up the drill string 160.
The method 800 may also include determining whether the depth of the downhole tool 100 corresponds to a depth of the sleeve 240 in the wellbore, as at 818. The depth of the sleeve 240 in the wellbore may be known. Thus, the operator may compare the depth of the downhole tool 100 to the depth of the sleeve 240 to determine whether the depth of the downhole tool 100 corresponds to the depth of the sleeve 240. When the depth of the downhole tool 100 corresponds to the depth of the sleeve 240, and the measured load on the downhole tool 100 is greater than a predetermined threshold, indicating that the sleeve 240 is not functioning (e.g., shifting) properly, the method 800 may include pulling the downhole tool 100 out of the wellbore, and running a second downhole tool into the wellbore to repair or disable the sleeve 240, as at 820. When the depth of the downhole tool 100 does not correspond to the depth of the sleeve 240, this may indicate that the restriction is not the sleeve 240. Rather, the restriction may be or include debris in the wellbore. When the depth of the downhole tool 100 does not correspond to the depth of the sleeve 240, and the measured load on the downhole tool 100 is greater than a predetermined threshold, the method 800 may include pulling the downhole tool 100 out of the wellbore, and running a second downhole tool into the wellbore clear the restriction, as at 822.
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.”
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.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 15246916 | Aug 2016 | US |
| Child | 16531796 | US |
