CLAIM OF PRIORITY

[0001] This application claims priority to U.S. Patent Application No. 17/656,331 filed on March 24, 2022, the entire contents of which are hereby incorporated by reference.

TECHNICAL FIELD

[0002] This disclosure relates to the production of oil, gas, or other resources from subterranean zones to the surface.

BACKGROUND

[0003] Hydrocarbons or other resources in subsurface reservoirs or locations below the Earth’s surface can be produced to the surface via wells drilled from the surface to the subsurface locations. After drilling, such wells are completed by installing one or more liners and production tubing to provide a pathway for such resources to flow to the surface. Liners can be cemented into the wellbore by introducing cement into the annular space between the wellbore and the liner or into the annular space between two successive liners. Liners can then be perforated at the downhole location or locations corresponding to the reservoirs or reservoir layers from which production is desired or expected. The produced liquids can flow to the surface via production tubing installed within the liner when completing the well.

[0004] To prevent or reduce the migration of sand or other particles from the reservoir to the production tubing, screens or other devices can be installed on the production tubing or on other suitable equipment or locations, as part of the well completion. Also as part of a well completion, inflow control devices or similar devices can be installed on the production tubing to control the flow of fluids into the production tubing. Such devices can be installed to equalizing reservoir inflow along the length of the product on tubing, or for other purposes.

SUMMARY

[0005] Certain aspects of the subject matter herein can be implemented as a system for selectively controlling flow from different subterranean intervals into a production tubing string positioned within a casing in a wellbore. The system includes a first interval inflow control device configured to be positioned on the production tubing string proximate to a first set of perforations through the casing at a first subterranean interval and a second interval inflow control device configured to be positioned on the production tubing string proximate to a second set of perforations through the casing at a second subterranean interval. The first interval inflow control device and the second interval inflow control device each include a substantially cylindrical sand screen surrounding an inner tube, the inner tube having a central bore fluidically connected to and coaxial with a central bore of the production tubing string. An annular space is fonned between an inner surface of the sand screen and an outer surface of the inner tube, and the annular space is fluidically connected to the central bore of the inner tube by a plurality of ports through the wall of the inner tube. A sliding sleeve is positioned within the inner bore and has a substantially cylindrical sleeve bore open to and coaxial with the central bore of the inner tube. The sliding sleeve is configured to translate axially from a first, open position in which the sliding sleeve does not prevent a flow of fluid through plurality of ports and a second, closed position in which the sliding sleeve prevents the flow of fluid through plurality of ports. The system also includes a first shifting tool configured to engage with and axially translate the sliding sleeve of the first interval inflow control device from the first, open position to the second, closed position, and a second shifting tool configured to engage with and axially translate the sliding sleeve of the second interval inflow control device from the first, open position to the second, closed position. The second shifting tool has an outer diameter less than an inner diameter of the sleeve bore of the sliding sleeve of the first interval inflow control device.

[0006] An aspect combinable with any of the other aspects can include the following features. The sliding sleeve of the first interval inflow control device can be locked in the first, open position by a shear pin.

[0007] An aspect combinable with any of the other aspects can include the following features. The system of claim 2, wherein the shear pin can be configured to be sheared by an application of force by the first shifting tool to the sliding sleeve of the first interval inflow control device. [0008] An aspect combinable with any of the other aspects can include the following features. The sliding sleeve of the second interval inflow control device can be locked in the first, open position by a shear pin.

[0009] An aspect combinable with any of the other aspects can include the following features. The shear pin can be configured to be sheared by an application of force by the second shifting tool to the sliding sleeve of the second interval inflow control device.

[0010] An aspect combinable with any of the other aspects can include the following features. The sliding sleeve of the first interval inflow control device can further include a shifting profile configured to selectively engage with a corresponding shifting key of the first shifting tool.

[0011] An aspect combinable with any of the other aspects can include the following features. The sliding sleeve of the second interval inflow control device can further include a shifting profile configured to selectively engage with a corresponding shifting key of the second shifting tool.

[0012] An aspect combinable with any of the other aspects can include the following features. A tubing-casing annulus can be formed by an inner surface of the casing and an outer surface of the production tubing string. The system can also include a first packer positioned on the production tubing string uphole of the first interval inflow control device and configured to selectively isolate the tubing-casing annulus uphole of the first packer from tubing-casing annulus downhole of the upper packer, and a second packer positioned on the production tubing string between the first interval inflow control device and the second interval inflow control device and configured to selectively isolate the tubing-casing annulus below the first packer and above the second packer from the tubing-casing annulus below the second packer.

[0013] An aspect combinable with any of the other aspects can include the following features. The second shifting tool can be configured to pass through the first interval control device without engaging with the sliding sleeve of the first inflow control device.

[0014] An aspect combinable with any of the other aspects can include the following features. The system can be configured prior to positioning the production tubing string in the wellbore such that, when the production tubing string is positioned in the wellbore, the first interval inflow control device is proximate to the first set of perforations and the second interval inflow control device is proximate to the second set of perforations.

[0015] Certain aspects of the subject matter herein can be implemented as a method for selectively controlling flow from different subterranean intervals into a production tubing string positioned within a casing in a wellbore. The method includes passing a shifting tool in a downhole direction through a sliding sleeve of a first interval inflow control device positioned on the production tubing string proximate to a first set of perforations through the casing at a first subterranean interval to engage with a sliding sleeve of a second interval inflow control device positioned on the production tubing string proximate to a second set of perforations through the casing at a second subterranean interval. The first interval inflow control device and the second interval inflow control device each include a substantially cylindrical sand screen surrounding an inner tube, the inner tube having a central bore fluidically connected to and coaxial with a central bore of the production tubing string. An annular space is formed between an inner surface of the sand screen and an outer surface of the inner tube. The annular space is fluidically connected to the central bore of the inner tube by a plurality of ports through the wall of the inner tube, and the sliding sleeve of the first interval inflow control device and the sliding sleeve of the second interval inflow control device each have a substantially cylindrical sleeve bore open to and coaxial with the central bore of the respective inner tube. The method further includes engaging the shifting tool with the sliding sleeve of the second interval inflow control device an axially translating, by the shifting tool, the sliding sleeve of the second interval inflow control device from a first, open position in which the sliding sleeve does not prevent a flow of fluid through the plurality of ports of the second interval inflow control device to a second, closed position in which the sliding sleeve prevents the flow of fluid through the plurality of ports of the second interval inflow control device.

[0016] An aspect combinable with any of the other aspects can include the following features. Engaging the shifting tool with the sliding sleeve of the second interval inflow control device can include engaging a shifting key of the shifting tool with a shifting profile of the sliding sleeve of the second inflow control device.

[0017] An aspect combinable with any of the other aspects can include the following features. The method can further include shearing, by an application of force to the shifting tool, a shear pin locking the sliding sleeve of the second interval inflow control device in the first, open position by a shear pin.

[0018] An aspect combinable with any of the other aspects can include the following features. A tubing-casing annulus can be formed by an inner surface of the casing and an outer surface of the production tubing string. A first packer can be positioned on the production tubing string uphole of the first interval inflow control device which isolates the tubing-casing annulus uphole of the first packer from the tubing-casing annulus downhole of the upper packer. The method can further include actuating a second packer positioned on the production tubing string between the first interval inflow control device and the second interval inflow control device and thereby isolating the tubing-casing annulus below the first packer and above the second packer from the tubing-casing annulus below the second packer.

[0019] An aspect combinable with any of the other aspects can include the following features. The passing of the shifting tool in the downhole direction through the sliding sleeve of a first interval inflow control device can be a first instance of an interval isolation sequence and wherein the shifting tool is a second shifting tool. The method can further include a second instance of the interval isolation sequence. The second instance of the interval isolation sequence method can include lowering a first shifting tool in a downhole direction to the sliding sleeve of the first interval inflow' control device, engaging the first shifting tool with the sliding sleeve of the first interval inflow control device, and axially translating, by the first shifting tool, the sliding sleeve of the first interval inflow control device from a first, open position in which the sliding sleeve does not prevent a flow of fluid through the plurality of ports of the first interval inflow control device to a second, closed position in which the sliding sleeve prevents the flow of fluid through the plurality of ports of the first interval inflow control device. [0020] An aspect combinable with any of the other aspects can include the following features. Engaging the first shifting tool with the sliding sleeve of the first interval inflow control device can include engaging a shifting key of the first shifting tool with a shifting profile of the sliding sleeve of the first inflow control device.

[0021] An aspect combinable with any of the other aspects can include the following features. A tubing-casing annulus is formed by an inner surface of the casing and an outer surface of the production tubing string and a first packer positioned on the production tubing string uphole of the first interval inflow control device can isolate the tubing-casing annulus uphole of the first packer from the tubing-casing annulus downhole of the upper packer. The method can further include actuating a second packer positioned on the production tubing string between the first interval inflow control device and the second interval inflow control device, thereby isolating the tubing-casing annulus below the first packer and above the second packer from the tubing-casing annulus below the second packer.

[0022] An aspect combinable with any of the other aspects can include the following features. The second shifting tool can be configured to pass through the first interval control device without engaging with the sliding sleeve of the first inflow control device.

[0023] An aspect combinable with any of the other aspects can include the following features. The method can further include, prior to positioning the production tubing string in the wellbore, configuring the production tubing string such that, when the production tubing string is positioned in the wellbore, the first interval inflow control device is proximate to the first set of perforations and the second interval inflow control device is proximate to the second set of perforations.

[0024] An aspect combinable with any of the other aspects can include the following features. Actuating the sliding sleeve can be in response to an indication that an amount of water relative to an amount of oil or gas produced from the second subterranean interval has increased.

[0025] The details of one or more embodiments are set forth in the accompanying drawings and the description below. Other features, objects, and advantages will be apparent from the description and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

[0026] Figure 1 is a schematic illustration of well system in accordance with an embodiment of the present disclosure.

[0027] Figures 2A and 2B are schematic illustrations of an inflow control device in accordance with certain embodiments of the present disclosure.

[0028] Figures 3A and 3B are schematic illustration of shifting tool and sliding sleeve pairs in accordance with certain embodiments of the present disclosure. [0029] Figures 4A - 4C are schematic illustrations of an operating sequence for selectively controlling flow from subterranean intervals into a production tubing string accordance with an embodiment of the present disclosure.

[0030] Figures 5A - 5C are schematic illustrations of an alternative operating sequence for selectively controlling flow from subterranean intervals into a production tubing string in accordance with an embodiment of the present disclosure.

[0031] Figure 6 is a process flow diagram of a method of selectively controlling flow from subterranean intervals into a production tubing string accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

[0032] The details of one or more implementations of the subject matter of this specification are set forth in this detailed description, the accompanying drawings, and the claims. Other features, aspects, and advantages of the subject matter will become apparent from this detailed description, the claims, and the accompanying drawings.

[0033] In accordance with embodiments of the present invention, inflow from different subterranean intervals into a production tubing string of a wellbore can be selectively controlled. In this way, one or more of the subterranean intervals can be selectively isolated and unwanted fluid flow from those subterranean intervals can be selectively reduced or eliminated. In certain circumstances, for example, one or more intervals may begin to produce a higher water content relative to the amount of oil or gas produced, making it desirable to partially or fully shut off fluid flow into the production string from such intervals, temporarily or permanently.

[0034] In accordance with some embodiments of the present disclosure, an improved method and system for controlling flow from specific intervals is disclosed. The system and method enable such control to be performed with respect to screened inflow control devices at different levels, simply and economically, thus reducing costly rig time and reducing or avoiding the need to run patches or isolation plugs, or to recomplete the well.

[0035] Figure 1 is a schematic illustration of well system 100 in accordance with an embodiment of the present disclosure. Referring to Figure 1, well system 100 that includes a substantially cylindrical wellbore 102 extending into the Earth into a subterranean zone 118. In the embodiment shown in Figure 1, wellbore 102 is drilled through two discrete intervals of subterranean zone 118: first interval 120a and second interval 120b. Second interval 120b in the illustrated embodiment is downhole in wellbore 102 relative to first interval 120a. First interval 120a and second interval 120b can be, for example, different geological formations or different stratigraphic layers within a formation or different hydrocarbon production zones other discrete or otherwise different zones of interest. While Figure 1 shows two such intervals, well system 100 can include more than two intervals. The intervals and the boundary between them can be substantially horizontal (as shown in Figure 1) or other than substantially horizontal (for example, closer to vertical than horizontal). Likewise, while wellbore 102 is shown as extending substantially vertically from the surface through first interval 120a and second interval 120b, the concepts described here can be applicable to many different configurations of wells, including vertical, horizontal, slanted, or wells that are otherwise non-horizontal, partially or fully, with respect to the surface and/or with respect to the intervals.

[0036] After some or all of the wellbore 102 is drilled, a portion of the wellbore 102 extending into first interval 120a and second interval 120b can be lined with lengths of tubing, called casing or liner. The wellbore 102 can be drilled in stages, the liners can be installed between stages, and cementing operations can be performed to inj ect cement in stages in the annulus between the liner and inner surface of the wellbore (and/or the annulus between the inner surface of an outer, larger-diameter liner into which the (smaller-diameter) liner has been positioned.

[0037] In some embodiments of the present disclosure, a well system (such as well system 100) can be constructed by lowering a first liner into place and then cementing the annulus by injecting a cement slurry downhole through central bore of the liner, such that the cement slurry then travels uphole within the annulus and hardens. After installation and cementing of the first liner, the second, smaller-diameter liner can be lowered within the first liner and the second liner cemented into place. Subsequent liners can likewise be installed in progressively lower sections. Accordingly, in the example well system 100 of Figure 1, the system 100 includes a first, outer liner 108, defined by lengths of tubing lining an upper portion of the wellbore 102 extending from the surface into the Earth. Outer liner 108 is shown as extending only partially down the wellbore 102. The example well system 100 also includes a second, inner liner 110 positioned radially inward from the outer liner 108 and defined by lengths of tubing that line a lower portion of the wellbore 102 that extends further downhole of the wellbore 102 than the portion of the wellbore into which first liner 108 has been positioned.

[0038] After installation of the casing or liner, production tubing string 112 can be installed in wellbore 102 within the liners. Production tubing string 112 can comprise lengths of tubing connected to each other and acts as the pri mary conduit through which fluids are produced to the surface. The outer surface of production tubing string 112 and the inner surface of the liners forms an annulus 114. In the illustrated embodiment, perforations 116a through liner 110 allow hydrocarbons or other fluids to enter wellbore 102 from first interval 120a, and perforations 116b allow hydrocarbons or other fluids to enter wellbore 102 from second interval 120b. In some embodiments, liner 110 (and/or other liners uphole or downhole of liner 110) can include additional or other perforations corresponding to intervals 120a or 120b or to different or additional subterranean intervals.

[0039] In the illustrated embodiment, inflow control devices (ICDs) 130a and 130b are installed on production tubing string 112 and provide a pathway for the fluids entering the wellbore via perforations 116a and 116b to enter production tubing string 112. In the illustrated embodiment, first interval ICD 130a is installed at a location on the tubing string proximate to perforations 116a, and thus is proximate to the flow of fluid 150a from first interval 120a. Second interval ICD 116b is installed at a location on the tubing string proximate to perforations 116b, and the is proximate to the flow of fluid 1 0b from second interval 120b. ICDs 130a and 130b are described in more detail in reference to Figures 2A and 2B. In some embodiments, the well system can include a greater number of ICDs for one or more single intervals and/or additional ICDs corresponding to additional subterranean zones, or more than one ICD per interval.

[0040] In the illustrated embodiment, packer 140 is installed on production tubing 112 and when activated, can seal and isolate the annulus 114 above packer 140 from annulus 114 below packer 140. Packer 142 is positioned between first interval ICD 130a and second interval ICD 130b and, when activated, isolate annulus 114 below packer 140 and above packer 142 from annulus 114 below packer 142. In some embodiments, packers 140 and 142 can be mechanical set packers. In some embodiments, packers 140 and/or 142 can be swellable packers or another suitable packer type. In some embodiments, instead of two packers, three or more packers can be installed on production tubing 112 to, for example, isolate the annulus above and below additional ICDs corresponding to additional subterranean intervals.

[0041] In accordance with some embodiments of the present invention, ICDs 130a and 130b can be selectively opened and closed, and packers 140 and 142 selectively activated, to selectively permit fluid flow into production tubing 112 from first interval 120a, or from second interval 120b, or from both intervals. Additional ICDs of similar design and configuration as ICDs 130a and 130b and additional packers can in some embodiments be installed on other portions of production tubing 112 to likewise selectively permit fluid flow from all or some of the plurality (for example, three or four or more ) subterranean intervals.

[0042] Figures 2A and 2B are schematic illustrations an ICD in accordance with certain embodiments of the present disclosure. Specifically, Figure 2A is an external schematic of first interval ICD 130a of Figure 1, and Figure 2B shows in internal crosssection of first interval ICD 130a. First interval ICD 130a comprises a main body 200, and can be connected to production tubing at an upper end 202 and a lower end 204. Screen 210 wraps circumferentially around ICD 130 and allows fluid flow into first interval ICD 130a while filtering out sand and other particulate matter. Within main body 200 is substantially cylindrical inner tube 220 having a central bore 222 which is open to and aligns axially with the central bore of the production tubing. The inner surface of screen 210 and the outer surface of inner tube 220 forms an annular space 224, and fluid entering through screen 210 can flow through the annular space and into central bore 222 via ports 226.

[0043] First interval ICD 130a further includes a sliding sleeve 250a which has a sleeve inner bore 252 open to and axially aligned with central bore 222. Sleeve 250a is configured to be translated axially (for example, by a shifting tool) from a first position in which ports 226 are not blocked by sleeve 250a to a second position in which ports 226 are blocked by sleeve 250a. Accordingly, in the first position, fluid can flow from annulus 224 to central bore 222, whereas in the second position, fluid cannot flow from annulus 224 to central bore 222. In the illustrated embodiment, sliding sleeve 250a further includes a shifting profile 254a which can selectively engage with a corresponding shifting key of a shifting tool (for example, a shifting tool shown in Figure 3A), thus locking sleeve 250a with the shifting tool such that sleeve 250a is axially translated by axial translation of the shifting tool. [0044] First interval ICD 130a further includes a shear pin 256a which locks sleeve 250a in the first position until the pin is sheared, for example, by the shifting tool applying sufficient force to shear the pin. In the illustrated embodiment, sleeve 250a further includes a locking ring 258a which can lock sleeve 250a in the second position by latching into recess 230 which extends circumferentially about the inner surface of inner tube 220. In other embodiments, other types of keys, locking profiles, other mechanisms can be used to lock or hold sleeve 250a in the first or second position or in other desired axial positions.

[0045] Second interval ICD 130b of Figure 1 can in some embodiments have the same or substantially the same elements, design and configuration as first interval ICD 130a as shown in Figures 2A and 2B. However, described in further detail in reference to Figures 3 A and 3B, in some embodiments, an inner bore diameter of the sliding sleeve of second interval ICD 130b can have a different (for example, smaller) diameter than inner bore 252A of sliding sleeve 250a of first interval ICD 130a.

[0046] Figures 3A and 3B are schematic illustration of shifting tool and sliding sleeve pairs in accordance with certain embodiments of the present disclosure. Sliding sleeve 250a of Figure 3A corresponds to sliding sleeve 250a of first interval ICD 130a of Figure 1. Sliding sleeve 250b of Figure 3B corresponds to a sliding sleeve which, in some embodiments, is positioned within second interval ICD 130b (in place of or instead of sliding sleeve 250a).

[0047] Referring to Figure 3 A, first interval shifting tool 310a has a lower locking section 312a having an external diameter 316a that is the same or less than the diameter 302A of inner bore 252A of sliding sleeve 250a. First interval shifting tool 310a further includes a shifting key 314a which corresponds to shifting profile 254a of sleeve 250a. Shifting key 314a can selectively engage and lock with shifting profile 254a such that sleeve 250a can be axially translated by axial translation of first interval shifting tool 310a.

[0048] Referring to Figure 3B, sliding sleeve 250b is substantially similar to sliding sleeve 250a except that inner bore 252b of sliding sleeve 250b has a smaller diameter 302b than inner bore 252 A of sliding sleeve 250a. Similar to first interval shifting tool 310a, second interval shifting tool 310b has a lower locking section 312b having an external diameter 316b the same or substantially the same as the diameter 302b of inner bore 252b of sliding sleeve 250b. Shifting tool 310b further includes a shifting key 314b which corresponds to shifting profile 254b of sleeve 250b. Shifting key 314b can selectively engage and lock with shifting profile 254b such that sleeve 250b can be axially translated by axial translation of second interval shifting tool 310b. [0049] In the illustrated embodiment, outer diameter 320b of second shifting tool 310b is less than the diameter 302A of sliding sleeve 250a. As described in greater detail in reference to the following figures, second shifting tool 310b can in some embodiments be run axially through sliding sleeve 250a and central bore 222A of first interval ICD 130a, to engage with sliding sleeve 250b of second interval ICD 130b without engaging with sliding sleeve 250a of first interval ICD 130a. Likewise, additional ICDs deployed on production tubing string 112 can be configured with sliding sleeves having progressively smaller diameters to allow for the passage therethrough of shifting tools for the operation of ICDs progressively further downhole.

[0050] Figures 4A - 4C are schematic illustrations of an operating sequence for selectively controlling flow from subterranean intervals into a production tubing string accordance with an embodiment of the present disclosure. In the sequence show n in Figures 4A-4C, production from the first interval (but not the second interval) is shut off. In the initial configuration show n in Figure 4A, sliding sleeve 250a of first interval ICD 130a and sliding sleeve 250b are both in the first, open position, such that produced fluid 150a from first interval 120a and produced fluid 150b from second interval 120b can both flow into production tubing string 112 through first interval ICD 130a and second interval ICD 130b, respectively. Packer 140 is activated (expanded) to the set configuration so as to isolate the tubing-casing annulus uphole of perforations 116a and 116b. Lower packer 142 is in an initial, inactivated (unset) configuration.

[0051] If the operator desires to reduce or stop flow into production tubing string 112 from first interval 120a then, as shown in Figure 4B, the operator can run first interval shifting tool 310a into first interval ICD 130a and lock shifting tool 310a into sliding sleeve 250a. By increasing the force applied to first interval shifting tool 310a, shear pin 256a can be sheared and sleeve 250a axially translated from the first (open) position to the second (closed) position, thereby blocking flow from first interval ICD 130a into production tubing 112 As shown in Figure 4C, shifting tool 310a can then be removed from the wellbore, allowing flow from downhole of first interval ICD 130a (for example, from second interval 120b via perforations 116b through second interval ICD 130b) to continue. In some embodiments, not shown in Figures 4A - 4C, subsequent to closing first interval ICD 130a or at another suitable time, lower packer 142 can be expanded (set) so as to seal and isolate that portion of the tubing-casing annulus below upper packer 140 and above packer 142 from that portion of the tubingcasing annulus below lower packer 142, thereby preventing or reducing inflow from interval 120a through second interval ICD 130b.

[0052] Figures 5A - 5C are schematic illustrations of an alternative operating sequence for selectively controlling flow from subterranean intervals into a production tubing string in accordance with an embodiment of the present disclosure. In the sequence shown in Figures 5 A-5C, production from the second interval (but not the first interval) is shut off. Similar to the sequence described in reference to Figures 4A-4C, in the initial configuration shown in Figure 5A, sliding sleeve 250a of first interval ICD 130a and sliding sleeve 250b are both in the first, open position, such that produced fluid 150a from first interval 120a and produced fluid 150b from second interval 120b can both flow into production tubing string 112 through first interval ICD 130a and second interval ICD 130b, respectively. Packer 140 can be activated (expanded) to the set configuration so as to isolate the tubing-casing annulus uphole of perforations 116a and 116b. Lower packer 142 is in an initial, inactivated (unset) configuration.

[0053] If the operator desires to reduce or stop flow into production tubing string 112 from second interval 120b then, as shown in Figure 5B, the operator can run shifting tool 310b through first interval ICD 130a and into second interval ICD 130b and lock shifting tool 310b into sliding sleeve 250b. By increasing the force applied to shifting tool 310b, shear pin 256b can be sheared and sleeve 250b axially translated from the first (open) position to the second (closed) position, thereby blocking flow from second interval ICD 130b into production tubing 112. As shown in Figure 5C, lower packer 142 can be expanded (set) so as to seal and isolate that portion of the tubing-casing annulus below upper packer 140 and above packer 142 from that portion of the tubingcasing annulus below lower packer 142. Such packer configuration isolates the tubingcasing annulus that includes first interval ICD 130a and isolates first interval ICD 130a from second interval ICD 130b. Shifting tool 310a can then be removed from the wellbore, thus allowing flow from the first interval 120a via perforations 11 a (through first interval ICD 130a) to continue.

[0054] Figure 6 is a process flow diagram of a method of selectively controlling flow from subterranean zones into a production tubing string accordance with embodiments of the present disclosure. The method begins at step 602 in which a production tubing string having a first interval inflow control device and a second interval inflow control device is configured such that, if the production tubing string is positioned in a wellbore within a subterranean zone, the first interval inflow control device is proximate to a first set of perforations corresponding to a first subterranean interval (such as an oil or gas producing interval) of the subterranean zone and the second interval inflow control device is proximate to a second set of perforations corresponding to a second subterranean interval of the subterranean zone downhole of the first subterranean interval. In some embodiments, such as, for example an embodiment wherein a greater number of subterranean intervals are present or a greater number of interval ICDs are desired per interval, more than two interval ICDs can be installed on the production tubing string and accordingly configured. In some embodiments, the production tubing string further includes with one or more packers separating the interval ICDs. In an initial configuration, in some embodiments, only an upper packer uphole of the interval ICDs is set, isolating the annulus uphole of the ICDs from the annulus downhole of the ICDs, and each of the ICDs is in the open position, allowing inflow into the production tubing string from each of the intervals. Other packers below the upper packer and between the interval ICDs can be in the unset (unsealed) position. Proceeding to step 604, the production tubing string is installed in the wellbore.

[0055] Proceeding to step 606, hydrocarbons or other resources are produced from the first and second subterranean intervals (and, if applicable, the other intervals) through the production tubing string to the surface. Proceeding to step 608, the operator makes a determination of whether to shut off flow from a subterranean interval and, if so, which interval to shut off. Such determination can be in response to, for example, an indication that water from the interval has increased relative to the production of oil or gas from the interval. If at step 608 the operator determines that such shut off is not desired or necessary, then the method returns to step 606 in which the resources continue to be produced from all of the intervals.

[0056] If at step 608 the operator determines that shut-off of the first interval is desired, then the method proceeds to step 610 in which a first interval shifting tool (that is, a shifting tool sized and configured to latch into the sliding sleeve of the first interval ICD) is run into the well and locked into the sliding sleeve of the first interval ICD using a shifting and key mechanism or other suitable mechanism. At step 612, by increasing the force applied to first interval shifting tool, a shear pin holding the sliding sleeve in the first (open) position in sheared and the sleeve axially translated from the first (open) position to the second (closed) position. Proceeding to step 614, the first interval shifting tool is removed from the wellbore, and, at step 616, inflow into the production tubing string continues from the second interval ICD but inflow into the production tubing string from the first interval ICD is shut off by the sliding sleeve of the first interval ICD

[0057] Returning to step 608, if the operator determines that shut-off of the second interval is desired, then the method proceeds to step 618 in which a second interval shifting tool (that is, a shifting tool sized and configured to freely pass through the first interval ICD and latch into the sliding sleeve of the second interval ICD downhole of the first interval ICD) is run into the well and locked into the sliding sleeve of the second interval ICD using a shifting and key mechanism or other suitable mechanism. At step 620, by increasing the force applied to second interval shifting tool, a shear pin holding the sliding sleeve in the first (open) position in sheared and the sleeve axially translated from the first (open) position to the second (closed) position. Proceeding to step 622, the packer between the first interval ICD and the second interval ICD is set (expanded) so as to seal and isolate that portion of the tubing-casing annulus below the second interval ICD from that portion of annulus above the second interval ICD and below the first interval. Proceeding to step 624, the second interval shifting tool is removed from the wellbore, and, at step 626, inflow into the production tubing string continues from the first interval ICD but inflow into the production tubing string from the second interval ICD is shut off by the sliding sleeve of the second interval ICD. [0058] Shear pins 256a and 256b provide a simple and cost-effective mechanism for holding the sliding sleeves in the open position until translation of the sleeves to the closed position is desired. In some embodiments, instead of or in addition to shear pins (which once sheared are not resettable), a resettable latch systems (such as a spring- loaded lock and key mechanism) could be used, thereby enabling multiple or repeated translation and locking/unlocking cycles between the first and second positions.

[0059] The term “uphole” as used herein means in the direction along the production tubing or the wellbore from its distal end towards the surface, and “downhole” as used herein means the direction along the production tubing or the wellbore from the surface towards its distal end. A downhole location means a location along the production tubing or wellbore downhole of the surface.

[0060] A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.