INFLOW CONTROL DEVICES WITH MULTI-FLOW PORT CAPABILITIES

Abstract

A well system includes a wellbore penetrating a subterranean formation, production tubing extended into the wellbore and terminating at a completion string, and one or more inflow control devices forming part of the completion string. The inflow control device includes a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the first flow ports. A first flow regulation device is arranged within the base pipe and actuatable to expose or occlude the first flow ports, and a second flow regulation device is arranged within the base pipe and actuatable to expose or occlude the second flow ports. A downhole shifting device is operable to independently manipulate a position of the first and second flow regulation devices and thereby selectively expose or occlude the first or second flow ports.

Description

FIELD OF THE DISCLOSURE

The present disclosure relates generally to hydrocarbon production in the oil and gas industry and, more particularly, to inflow control devices with multiple flow port locations that allow the inflow control device to operate between fully open and fully closed.

BACKGROUND OF THE DISCLOSURE

Hydrocarbons (e.g., oil and gas) are recovered from subterranean formations via drilling and penetrating the same with a wellbore. In some cases the wellbore is completed by cementing a liner or “casing” along all or a portion of the wellbore and subsequently perforating the casing at particular production zones (hydrocarbon-bearing intervals) to extract formation fluids therefrom. In other cases, however, the wellbore may be un-cased or “open hole” and production zones may be defined by strategically deploying packers along the open hole wellbore to isolate specific production intervals.

Fluid from each production zone entering the wellbore is commonly drawn into production tubing extended within the wellbore from the well surface. It is desirable to have substantially even flow of fluid along the production zones, as uneven drainage may result in undesirable conditions such as water or gas coning. Water coning, for example, will cause an influx of water into the oil production flow, which reduces the amount and quality of the produced oil. Similarly, gas coning causes an influx of gas into the wellbore that also significantly reduces oil production.

Accordingly, it is beneficial to regulate the flow of formation fluids into the production tubing from the various production zones or intervals, and a number of devices are available to accomplish this. Some of these devices are non-discriminating for different types of formation fluids and can simply function as a “gatekeeper” for regulating access to the interior of the production tubing. Such gatekeeper devices, for example, can be simple on/off valves or passive inflow control devices (ICDs), such as sliding sleeve assemblies. ICDs are able to create multiple production zones in the same well, while isolating undesirable production zones. In horizontal wells for example, some production zones may be undesirable due to higher water rates or fractures, and such production zones can be isolated by installing a blank pipe in front of them and then completing the downhole completion with strategically placed wellbore packers. This arrangement ensures that the undesirable production zones are fully isolated and do not contribute to production.

ICDs typically have two positions: open and closed. As the well produces over time, some production zones develop higher water cut. One way to mitigate increased water influx is to access and close the particular ICD interval. In mature fields that employ water flooding as a recovery mechanism, production zones with higher water cut generally have better permeability and a high bottom hole pressure since they are well connected to the water injector wells. In the event these production zones become isolated, the well may cease to produce as the ICDs in the weaker production zones are unable to provide the required vertical lift performance to lift the production fluids to the surface. One common way to sustain production in such wells is to produce the well at high water rates, and the higher-pressure production zones thus overpower the weaker production zones and produce more water. This production scenario might not be the most optimum but at least it ensures well productivity.

What is needed are ICD designs that help ensure the required pressure support provided by high-pressure/high-watercut production zones without choking the low-pressure, oil-bearing production zones.

SUMMARY OF THE DISCLOSURE

Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an extensive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.

According to an embodiment consistent with the present disclosure, a well system may include a wellbore penetrating a subterranean formation, production tubing extended into the wellbore and terminating at a completion string, and one or more inflow control devices forming part of the completion string. Each inflow control device may include a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the one or more first flow ports, each flow port facilitating fluid communication between the subterranean formation and an interior of the base pipe, a first flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more first flow ports, a second flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more second flow ports, and a downhole shifting device operable to independently manipulate a position of the first and second flow regulation devices and thereby selectively expose or occlude the one or more first or second flow ports. The first flow regulation device can be positioned such that the one or more first flow ports are exposed, while simultaneously positioning the second flow regulation device such that the one or more second flow ports are occluded results in the inflow control device operating at 50% capacity.

According to one or more additional embodiments consistent with the present disclosure, a method of operating a well system can include receiving a formation fluid from a subterranean formation into an inflow control device, the inflow control device forming part of a completion string arranged within a wellbore penetrating the subterranean formation. The inflow control device can include a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the one or more first flow ports, each flow port facilitating fluid communication between the subterranean formation and an interior of the base pipe, a first flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more first flow ports, a second flow regulation device disposed within the base pipe and actuatable to expose or occlude the one or more second flow ports, and a downhole shifting device operable to independently manipulate a position of the first and second flow regulation devices. The method may further include operating the downhole shifting device to move the first flow regulation device from an open position, where the one or more first flow ports are exposed, to a closed position, where the one or more first flow ports are occluded by the first flow regulation device, and flowing the formation fluids into the interior of the base pipe via only the one or more second flow ports and thereby operating the inflow control device at 50% capacity.

Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an example well system that may employ one or more of the principles of the present disclosure, according to one or more embodiments.

FIG. 2 is an enlarged cross-sectional side view of an example inflow control device, according to one or more embodiments.

FIG. 3 is another enlarged cross-sectional side view of the inflow control device of FIG. 2 showing example operation, according to one or more embodiments.

FIG. 4 is another enlarged cross-sectional side view of the inflow control device of FIG. 2 showing additional example operation, according to one or more additional embodiments.

DETAILED DESCRIPTION

Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.

Embodiments in accordance with the present disclosure generally relate to multi-flow port inflow control devices that have at least two sets of flow ports and corresponding flow regulation devices that operate independently of each other. In embodiments with two sets, each set will contribute 50% of the flow area for the inflow control device. With one of the flow regulation devices moved to an open position, the inflow control device will contribute 50%, thus providing pressure support and lifting the well without over powering weaker inflow control devices included in the common completion string. In the event one of the flow regulation devices becomes stuck or blocked with debris, the production interval can still be produced using the second flow regulation device. Accordingly, the flow rates from each production interval in a downhole completion can be controlled to produce either at full capacity (100%) or half capacity (50%). The embodiments described herein provide greater flexibility as compared to conventional inflow control devices, and ensure built-in redundancy that allows multiple flow rates from the same production interval.

FIG. 1 is a schematic diagram of an example well system 100 that may employ one or more of the principles of the present disclosure, according to one or more embodiments. As depicted, the well system 100 includes a wellbore 102 that extends through various earth strata and has a substantially vertical section 104 that transitions into a substantially horizontal section 106. A portion of the vertical section 104 may have a string of casing 108 cemented therein, and the horizontal section 106 may extend through a hydrocarbon bearing subterranean formation 110. In some embodiments, the horizontal section 106 may be uncompleted and otherwise characterized as an “open hole” section of the wellbore 102. In other embodiments, however, the casing 108 may extend into the horizontal section 106, without departing from the scope of the disclosure.

A string of production tubing 112 may be positioned within the wellbore 102 and extend from a well surface location (not shown), such as the Earth's surface. The production tubing 112 provides a conduit for fluids extracted from the formation 110 to travel to the well surface location for production. A completion string 114 may be coupled to or otherwise form part of the lower end of the production tubing 112 and arranged within the horizontal section 106. The completion string 114 may be configured to divide the wellbore 102 into various production intervals or “zones” adjacent the subterranean formation 110. To accomplish this, as depicted, the completion string 114 may include a plurality of inflow control devices or “ICDs” 116 axially offset from each other along portions of the production tubing 112. In some embodiments, each inflow control device 116 may be positioned between a pair of wellbore packers 118 that provides a fluid seal between the completion string 114 and the inner wall of the wellbore 102, and thereby defining discrete production intervals or zones.

The inflow control devices 116 are operable to selectively regulate the flow of fluids 120 into the completion string 114 and, therefore, into the production tubing 112. In the illustrated embodiment, each inflow control device 116 includes a sand control screen assembly 122 that filters particulate matter out of the formation fluids 120 originating from the formation 110 such that particulates and other fines are not produced to the well surface location. After passing through the sand control screen assembly 122, the inflow control devices 116 may be operable to regulate the flow of the fluids 120 into the completion string 114. Regulating the flow of fluids 120 into the completion string 114 from each production interval may be advantageous in preventing water coning 124 or gas coning 126 in the subterranean formation 110. Other uses for flow regulation include, but are not limited to, balancing production from multiple production intervals, minimizing production of undesired fluids, maximizing production of desired fluids, etc.

As used herein, the term “fluid” or “fluids” (e.g., the fluids 120) includes liquids, gases, hydrocarbons, multi-phase fluids, mixtures of two of more fluids, water and fluids injected from the surface, such as water. Additionally, references to “water” includes fresh water but should also be construed to also include water-based fluids; e.g., brine or salt water. In accordance with embodiments of the present disclosure, the inflow control devices 116 may have a number of alternative structural features that provide selective operation and controlled fluid flow therethrough.

It should be noted that even though FIG. 1 depicts the inflow control devices 116 as being arranged in an open hole portion of the wellbore 102, embodiments are contemplated herein where one or more of the inflow control devices 116 is arranged within cased portions of the wellbore 102. Also, even though FIG. 1 depicts a single inflow control device 116 arranged in each production interval, any number of inflow control devices 116 may be deployed within a particular production interval without departing from the scope of the disclosure. In addition, even though FIG. 1 depicts multiple production intervals separated by the packers 118, any number of production intervals with a corresponding number of packers 118 may be used. In other embodiments, the packers 118 may be entirely omitted from the completion interval, without departing from the scope of the disclosure.

Furthermore, while FIG. 1 depicts the inflow control devices 116 as being arranged in the horizontal section 106 of the wellbore 102, the inflow control devices 116 are equally well suited for use in the vertical section 104 or portions of the wellbore 102 that are deviated, slanted, multilateral, or any combination thereof. The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

FIG. 2 is an enlarged cross-sectional side view of an example inflow control device 200, according to one or more embodiments. The inflow control device 200 or “ICD” may be the same as or replace one or more of the inflow control devices 116 of FIGS. 1, and may otherwise be used in the well system 100 (FIG. 1). As illustrated, the inflow control device 200 may include or otherwise be arranged about a base pipe 202, which may form part of the completion string 114 (FIG. 1). The base pipe 202 defines one or more first or “upper” flow ports 204a, and one or more second or “lower” flow ports 204b. The flow ports 204a,b may be configured to provide fluid communication between an interior 206 of the base pipe 202 and the surrounding subterranean formation 110 such that formation fluids 120 originating in the surrounding formation 110 are able to enter the base pipe 202 for production.

In the illustrated embodiment, each set of flow ports 204a,b includes a plurality of flow ports angularly offset from each other about the circumference of the base pipe 202 and equidistantly spaced from each other. Moreover, the flow ports of each set of flow ports 204a,b are axially aligned on the base pipe 202 at respective locations. In other embodiments, however, one or more of the flow ports in either of the sets of flow ports 204a,b may be axially offset from each other. In one or more further embodiments, one or both sets of the flow ports 204a,b may comprise a single flow port, without departing from the scope of the disclosure.

The inflow control device 200 may further include a sand control screen assembly 208 similar in some respects to the sand control screen assembly 122 of FIG. 1. As illustrated, the sand control screen assembly 208 includes a first or “upper” end ring 210a, a second or “lower” end ring 210b axially spaced (offset) from the upper end ring 210a, and a sand screen 212 that extends between the upper and lower end rings 210a,b. The end rings 210a,b and the sand screen 212 are each disposed about the exterior of the base pipe 202, and the end rings 210a,b provide a mechanical interface between the base pipe 202 and the sand screen 212. In some embodiments, for example, the sand screen 212 may be welded or brazed to the end rings 210a,b. In other embodiments, the sand screen 212 may be mechanically fastened to the end rings 210a,b using, for example, one or more mechanical fasteners (e.g., bolts, pins, rings, screws, etc.) or otherwise secured between the end rings 210a,b and a structural component of the end rings 210a,b, such as a shroud or crimp ring.

The end rings 210a,b may be made of a metal, such as 13 chrome, 304L stainless steel, 316L stainless steel, 420 stainless steel, 410 stainless steel, Incoloy 825, iron, brass, copper, bronze, tungsten, titanium, cobalt, nickel, combinations thereof, or the like. Moreover, the end rings 210a,b may be coupled or otherwise attached to the outer surface of base pipe 202 by being welded, brazed, threaded, mechanically fastened, shrink-fitted, or any combination thereof. In other embodiments, however, the end rings 210a,b may alternatively form an integral part of the sand screen 212.

The upper end ring 210a may be arranged about the base pipe 202 at or near the upper flow ports 204a, and the lower end ring 210b may be arranged about the base pipe 202 at or near the lower flow ports 204b. Each end ring 210a,b may further define a flow chamber 214 configured to receive formation fluids 120 from the surrounding formation 110 and convey (direct) the incoming formation fluids 120 to the corresponding flow ports 204a,b to be received within the interior 206 of the base pipe 202 during production operations.

The sand screen 212 may comprise a filter medium designed to allow fluids to flow therethrough but generally prevent the influx of particulate matter of a predetermined size. In some embodiments, the sand screen 212 may be a fluid-porous, particulate restricting device made from of a plurality of layers of a wire mesh that are diffusion bonded or sintered together to form a fluid porous wire mesh screen. In other embodiments, however, the sand screen 212 may have multiple layers of a weave mesh wire material having uniform pore structure and a controlled pore size that is determined based upon the properties of the formation 110. Suitable weave mesh screens may include, but are not limited to, a plain Dutch weave, a twilled Dutch weave, a reverse Dutch weave, combinations thereof, or the like. In yet other embodiments, the sand screen 212 may include a single layer of wire mesh, multiple layers of wire mesh that are not bonded together, a single layer of wire wrap, multiple layers of wire wrap, or the like. Those skilled in the art will readily recognize that several other mesh or wire wrap designs are equally suitable, without departing from the scope of the disclosure.

Accordingly, the sand screen 212 may comprise wire wrap screen, a swell screen, a sintered metal mesh screen, an expandable screen, a pre-packed screen, a treating screen, or any other type of sand control screen known to those of skill in the art. Moreover, while not depicted in FIG. 2, in some embodiments, the sand screen 212 may additionally include a drainage layer and/or an outer protective shroud. Furthermore, in some embodiments, the sand screen 212 may have an additional mesh layer disposed about the outer perimeter thereof.

As illustrated, the sand screen 212 may be radially offset from the base pipe 202, thereby defining a flow annulus 216 between the base pipe 202 and the sand screen 212. The radial offset may be caused by a plurality of ribs (not shown) that extend longitudinally between the end rings 210a,b and along the outer surface of the base pipe 202. The height or distance between the base pipe 202 and the sand screen 212 largely depends on the height of the ribs.

The inflow control device 200 may further include a first or “upper” flow regulation device 218a and a second or “lower” flow regulation device 218b. The upper flow regulation device 218a is movably disposed within the base pipe 202 at or near the upper flow ports 204a, and the lower flow regulation device 218b is movably disposed within the base pipe 202 at or near the lower flow ports 204a. The flow regulation devices 218a,b may comprise any type of device or mechanism actuatable or movable to selectively allow or prevent the flow of formation fluids 120 into the interior 206 of the base pipe 202 via the corresponding flow ports 204a,b. The upper flow regulation device 218a may be actuatable and otherwise movable to expose or occlude the upper flow ports 204a, and the lower flow regulation device 218b may be actuatable and otherwise movable to expose or occlude the lower flow ports 204b.

In the illustrated embodiment, the flow regulation devices 218a,b are depicted as sliding sleeves slidably received within corresponding recesses 220 defined in the inner radial surface of the base pipe 202. As shown, the recess 220 for the upper flow regulation device 218a encompasses the upper flow ports 204a, and the recess 220 for the lower flow regulation device 218b encompasses the lower flow ports 204b. The flow regulation devices 218a,b are axially movable within the corresponding recess 220 between a first position (i.e., the fully open position), where the flow regulation device 218a,b exposes the corresponding (adjacent) flow ports 204a,b, and a second position (i.e., the fully closed position), where the flow regulation device 218a,b occludes the corresponding (adjacent) flow ports 204a,b. The flow regulation devices 218a,b are shown in FIG. 2 in the first position.

In some embodiments, as illustrated, each recess 220 defines a first or “upper” shoulder 221a and a second or “lower” shoulder 221b axially spaced from the upper shoulder 221a. The upper shoulder 221a is configured to stop uphole movement of the corresponding flow regulation device 218a,b when moved to the closed position, and the lower shoulder 221b is configured to stop downhole movement of the corresponding flow regulation device 218a,b when moved to the open position. In other embodiments, however, the recesses 220 may be omitted and one or both of the flow regulation devices 218a,b may instead be arranged against the inner radial surface of the base pipe 202. In such embodiments, the sand control screen assembly 200 may further include a stop shoulder (not shown) defined on the inner radial surface and configured to stop the uphole movement of the corresponding flow regulation device 218a,b when moved to the closed position.

While the flow regulation devices 218a,b are depicted in FIG. 2 as sliding sleeves, those skilled in the art will readily appreciate that the flow regulation devices 218a,b may comprise any other device or mechanism capable of selectively exposing and occluding the flow ports 204a,b, without departing from the scope of the disclosure. Other examples of the flow regulation devices 218a,b include, but are not limited to, a rotating sleeve, a sliding plug, a rotating ball, an oscillating vane, an opening pocket, or an opening window.

In example operation, the formation fluids 120 are drawn into the flow annulus 216 and conveyed along the outer circumference of the base pipe 202 into the flow chambers 212 at either end of the sand control screen assembly 200. When both flow regulation devices 218a,b are in the open position, as shown in FIG. 2, the formation fluids 120 can flow into the interior 206 of the base pipe 202 via each set of exposed flow ports 204a,b. In such a scenario, the inflow control device 200 will operate at full capacity and otherwise provide 100% flow contribution from the adjacent production zone. In contrast, when one of the flow regulation devices 218a,b is moved to the closed position, the inflow control device 200 will still be able to operate but only at half capacity and otherwise provide 50% flow contribution from the adjacent production zone. Furthermore, when both flow regulation devices 218a,b are moved to the closed position, flow contribution from the inflow control device 200 will be 0%.

Conventional inflow control devices have only two positions or operation modes: open or closed. Consequently, the flowrate from conventional inflow control devices cannot be changed, and if a conventional inflow control device becomes blocked or plugged, the flow contribution from the corresponding production zone (interval) will go to zero (0%). Moreover, if a flow regulation device in a conventional inflow control device becomes stuck in the closed position, then the interval contribution will also go to zero (0%). In contrast, the inflow control device 200 of the present disclosure includes two sets of flow ports 204a,b with corresponding flow regulation devices 218a,b that operate independent of each other. When one flow regulation device 218a,b is shifted to the open position, while the other flow regulation device 218a,b is in the closed position, this is similar to producing the inflow control device 200 at 50% flow area. This may prove advantageous in providing 50% rate contribution from a dominant water-bearing production zone, for example. Accordingly, the inflow control device 200 may help ensure that the required pressure support is provided by inflow control devices in high-pressure, high-watercut production zones, without choking other inflow control devices located in low-pressure, oil-bearing production zones.

FIG. 3 is another enlarged cross-sectional side view of the inflow control device 200 showing example operation, according to one or more embodiments. The upper and lower flow ports 204a,b and corresponding flow regulation devices 218a,b may be separated by a predetermined distance or axial length 302. In some embodiments, for example, the axial length 302 may be between about 5 feet and about 10 feet, but could alternatively be shorter than 5 feet or longer than 10 feet, without departing from the scope of the disclosure. In some embodiments, it may be preferred that the inflow control device 200 consist of a single joint with specific screen length. In such embodiments, the axial length 302 may be within the 5-10 foot length. However, in other embodiments, the inflow control device 200 may be made up of two or more joints, and in such embodiments, the axial length 302 between the flow regulation devices 218a,b may be greater than 10 feet.

The flow regulation devices 218a,b may be selectively and independently actuatable between the open and closed positions using any type of suitable actuator, actuation system, or mechanism, such as, but not limited to, a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, or any combination thereof. In other embodiments, the flow regulation devices 218a,b may be configured to move between closed and open positions by being acted upon by one or more wellbore projectiles, such as wellbore darts or balls. In yet other embodiments, the flow regulation devices 218a,b may be selectively actuated from a remote location, such as a well surface location. In such embodiments, the actuation device or system that moves the flow regulation devices 218a,b may be located downhole and communicably coupled to the well surface location, and an operator may be able to send command signals to the actuation device to selectively move the flow regulation devices 218a,b between the fully open and closed positions as desired. In even further embodiments, the flow regulation devices 218a,b may be partially or fully automated.

In the illustrated embodiment, a downhole shifting device 304 (depicted in dashed lines) may be conveyed downhole within the base pipe 202 and may be configured to interact with the inflow control device 200 to selectively manipulate the flow regulation devices 218a,b between the open and closed positions. In some embodiments, the downhole shifting device 304 may be conveyed downhole as coupled to a conveyance 306, such as drill pipe, coiled tubing, or another type of conveyance that can transmit a downhole axial load. In other embodiments, however, the conveyance 306 may comprise wireline or slickline, and the downhole shifting device 304 may be pumped downhole to the inflow control device 200. The downhole shifting device 304 may include or otherwise provide one or more actuatable dogs 308 configured to locate and mate with corresponding profiles 310a and 310b defined on the upper and lower flow regulation devices 218a,b, respectively.

In some embodiments, the profiles 310a,b may comprise annular channels or grooves defined in the inner radial surface of the corresponding flow regulation devices 218a,b. In such embodiments, the profiles 310a,b may be distinct from each other and the dogs 308 may be designed to selectively locate and mate with the distinct profiles 310a,b. For example, each profile 310a,b may exhibit a unique geometry, depth, width, etc., which may prevent the downhole shifting device 304 from inadvertently mating with the wrong flow regulation device 218a,b. In at least one embodiment, the profiles 310a,b may differ in depth. In such embodiments, the dogs 308 may be hydraulically actuatable to a first depth sufficient to locate and mate with the lower flow regulation device 218b, and further hydraulically actuatable to a second depth greater than the first depth and sufficient to mate with the upper flow regulation device 218a.

The downhole shifting device 304 may be capable of moving the flow regulation devices 218a,b to the open or closed positions. To move the flow regulation devices 218a,b to the open position, the downhole shifting device 304 may selectively mate with each flow regulation device 218a,b. Once mated, a downhole axial load may be applied on the downhole shifting device 304, and the axial load may be transmitted to the corresponding flow regulation device 218a,b, resulting in the downhole sliding movement of the corresponding flow regulation device 218a,b. The flow regulation device 218a,b may be moved downhole until engaging the lower shoulder 221b of the corresponding recess 220, and thereby exposing the corresponding flow ports 204a,b. In some embodiments, the downhole axial load may be applied via the conveyance 306, but in other embodiments, the downhole axial load may be applied by pressurizing the wellbore uphole from the downhole shifting device 304. In yet other embodiments, the inflow control device 200 may be run-in-hole and otherwise installed downhole with the flow regulation devices 218a,b already in the open position.

In FIG. 3, the lower flow regulation device 218b has been moved to the closed position to thereby occlude the lower flow ports 204b. To accomplish this, in one or more embodiments, the downhole shifting device 304 may be run into the base pipe 202 and bypass the inflow control device 200 by a known distance. The known distance can be between about feet and about 100 feet, or another distance that ensures that the downhole shifting device 304 has in fact bypassed the inflow control device 200, taking into consideration any changes in the length of the conveyance 306 (e.g., coiled tubing) due to run length, temperature, pulling, pushing, any meter inaccuracies, etc. The downhole shifting device 304 may then be pulled in the uphole direction and the dogs 308 may be activated to locate and mate with the profile 310 of the lower flow regulation device 218b. In embodiments where the downhole shifting device 304 is hydraulically actuatable, activating the dogs 308 may comprise pumping a hydraulic fluid (e.g., through the conveyance 306 or from a reservoir in the device 304) to extend the dogs 308 radially outward. Once the dogs 308 locate the profile 310 of the lower flow regulation device 218b, the downhole shifting device 304 may then be pulled in the uphole direction using the conveyance 306, which transmits an uphole axial load that causes the lower flow regulation device 218b to move in the same direction. The lower flow regulation device 218b moves in the uphole direction until engaging the upper shoulder 221a of the corresponding recess 220, at which point the lower flow regulation device 218b will be in the closed position and the lower flow ports 204b will be occluded. At this point, the inflow control device 200 may be operable at 50% since the upper flow ports 204a remain open.

FIG. 4 is another enlarged cross-sectional side view of the inflow control device 200 showing additional example operation, according to one or more embodiments. In FIG. 4, the lower flow regulation device 218b is in the closed position, and the upper flow regulation device 218a has now been moved to the closed position to thereby occlude the upper flow ports 204a. To accomplish this, in one or more embodiments, the downhole shifting device 304 (shown in dashed lines) may locate and mate with the profile 310 of the upper flow regulation device 218a. In embodiments where the downhole shifting device 304 is hydraulically actuatable, the dogs 308 may be hydraulically activated to extend radially outward. Once the dogs 308 locate the profile 310 of the upper flow regulation device 218a, the downhole shifting device 304 may then be pulled in the uphole direction using the conveyance 306, which transmits an uphole axial load that causes the upper flow regulation device 218a to move in the same direction.

The upper flow regulation device 218a moves in the uphole direction until engaging the upper shoulder 221a of the corresponding recess 220, at which point the upper flow regulation device 218a will be in the closed position and the upper flow ports 204a will be occluded. At this point, the inflow control device 200 may be completely closed and otherwise operable at 0% with all flow ports 204a,b occluded.

Embodiments disclosed herein include:

• • A. A well system may include a wellbore penetrating a subterranean formation, production tubing extended into the wellbore and terminating at a completion string, and one or more inflow control devices forming part of the completion string. Each inflow control device may include a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the one or more first flow ports, each flow port facilitating fluid communication between the subterranean formation and an interior of the base pipe, a first flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more first flow ports, a second flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more second flow ports, and a downhole shifting device operable to independently manipulate a position of the first and second flow regulation devices and thereby selectively expose or occlude the one or more first or second flow ports. The first flow regulation device can be positioned such that the one or more first flow ports are exposed, while simultaneously positioning the second flow regulation device such that the one or more second flow ports are occluded results in the inflow control device operating at 50% capacity.

B. A method of operating a well system can include receiving a formation fluid from a subterranean formation into an inflow control device, the inflow control device forming part of a completion string arranged within a wellbore penetrating the subterranean formation. The inflow control device can include a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the one or more first flow ports, each flow port facilitating fluid communication between the subterranean formation and an interior of the base pipe, a first flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more first flow ports, a second flow regulation device disposed within the base pipe and actuatable to expose or occlude the one or more second flow ports, and a downhole shifting device operable to independently manipulate a position of the first and second flow regulation devices. The method may further include operating the downhole shifting device to move the first flow regulation device from an open position, where the one or more first flow ports are exposed, to a closed position, where the one or more first flow ports are occluded by the first flow regulation device, and flowing the formation fluids into the interior of the base pipe via only the one or more second flow ports and thereby operating the inflow control device at 50% capacity.

Each of embodiments A and B may have one or more of the following additional elements in any combination: Element 1: further comprising a sand control screen assembly disposed about an exterior of the base pipe and in fluid communication with the one or more first and second flow ports, the sand control screen assembly including first and second end rings axially spaced from each other on the exterior of the base pipe, and a sand screen that extends between the first and second end rings. Element 2: wherein the first flow regulation device comprises a first sliding sleeve movable between an open position, where the one or more first flow ports are exposed, and a closed position, where the one or more first flow ports are occluded by the first sliding sleeve, and wherein the second flow regulation device comprises a second sliding sleeve movable between an open position, where the one or more second flow ports are exposed, and a closed position, where the one or more second flow ports are occluded by the second sliding sleeve. Element 3: wherein each sliding sleeve is received within a corresponding recess defined in the inner radial surface, and wherein each recess defines a first shoulder configured to stop uphole movement of the first and second sliding sleeves and a second shoulder configured to stop downhole movement of the first and second sliding sleeves. Element 4: wherein the downhole shifting device is conveyable downhole to the base pipe using a conveyance. Element 5: wherein the downhole shifting device is pumped downhole to the base pipe. Element 6: wherein the downhole shifting device is selected from the group consisting of a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, and any combination thereof. Element 7: wherein the downhole shifting device provides one or more actuatable dogs configured to locate and mate with corresponding profiles defined by the first and second flow regulation devices. Element 8: wherein the profile of the first flow regulation device differs from the profile of the second flow regulation device. Element 9: wherein an axial load provided by the downhole shifting device is transferred to the first and second flow regulation devices upon mating the one or more actuatable dogs with the corresponding profiles of the first and second flow regulation devices. Element 10: wherein the one or more actuatable dogs are hydraulically actuatable to extend radially outward.

Element 11: wherein the first flow regulation device comprises a first sliding sleeve defining a first profile, and the downhole shifting device provides one or more actuatable dogs, and wherein operating the downhole shifting device comprises actuating the one or more actuatable dogs, locating the first profile with the one or more actuatable dogs and mating the one or more actuatable dogs with the first profile, and applying an axial load on the first sliding sleeve with the downhole shifting device and thereby moving the first sliding sleeve to the closed position. Element 12: wherein the second flow regulation device comprises a second sliding sleeve defining a second profile, and wherein operating the downhole shifting device further comprises actuating the one or more actuatable dogs, locating the second profile with the one or more actuatable dogs and mating the one or more actuatable dogs with the second profile, and applying an axial load on the second sliding sleeve with the downhole shifting device and thereby moving the second sliding sleeve to a closed position, where the one or more second flow ports are occluded by the second sliding sleeve. Element 13: wherein operating the downhole shifting device is preceded by conveying the downhole shifting device to the base pipe using a conveyance.

By way of non-limiting example, exemplary combinations applicable to A and B include: Element 2 with Element 3; Element 7 with Element 8; Element 7 with Element 9; Element 7 with Element 10; and Element 11 with Element 12.

The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “contains”, “containing”, “includes”, “including,” “comprises”, and/or “comprising,” and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

Terms of orientation are used herein merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of “third” does not imply there must be a corresponding “first” or “second.” Also, if used herein, the terms “coupled” or “coupled to” or “connected” or “connected to” or “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.

While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.

Claims

1. A well system, comprising:

a wellbore penetrating a subterranean formation;

production tubing extended into the wellbore and terminating at a completion string;

one or more inflow control devices forming part of the completion string, each inflow control device including: a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the one or more first flow ports, each flow port facilitating fluid communication between the subterranean formation and an interior of the base pipe; a first flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more first flow ports; a second flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more second flow ports; and a downhole shifting device operable to independently manipulate a position of the first and second flow regulation devices and thereby selectively expose or occlude the one or more first or second flow ports,

wherein positioning the first flow regulation device such that the one or more first flow ports are exposed, while simultaneously positioning the second flow regulation device such that the one or more second flow ports are occluded results in the inflow control device operating at 50% capacity.

2. The well system of claim 1, further comprising a sand control screen assembly disposed about an exterior of the base pipe and in fluid communication with the one or more first and second flow ports, the sand control screen assembly including:

first and second end rings axially spaced from each other on the exterior of the base pipe; and

a sand screen that extends between the first and second end rings.

3. The well system of claim 1, wherein the first flow regulation device comprises a first sliding sleeve movable between an open position, where the one or more first flow ports are exposed, and a closed position, where the one or more first flow ports are occluded by the first sliding sleeve, and

wherein the second flow regulation device comprises a second sliding sleeve movable between an open position, where the one or more second flow ports are exposed, and a closed position, where the one or more second flow ports are occluded by the second sliding sleeve.

4. The well system of claim 3, wherein each sliding sleeve is received within a corresponding recess defined in the inner radial surface, and wherein each recess defines a first shoulder configured to stop uphole movement of the first and second sliding sleeves and a second shoulder configured to stop downhole movement of the first and second sliding sleeves.

5. The well system of claim 1, wherein the downhole shifting device is conveyable downhole to the base pipe using a conveyance.

6. The well system of claim 1, wherein the downhole shifting device is pumped downhole to the base pipe.

7. The well system of claim 1, wherein the downhole shifting device is selected from the group consisting of a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, and any combination thereof.

8. The well system of claim 1, wherein the downhole shifting device provides one or more actuatable dogs configured to locate and mate with corresponding profiles defined by the first and second flow regulation devices.

9. The well system of claim 8, wherein the profile of the first flow regulation device differs from the profile of the second flow regulation device.

10. The well system of claim 8, wherein an axial load provided by the downhole shifting device is transferred to the first and second flow regulation devices upon mating the one or more actuatable dogs with the corresponding profiles of the first and second flow regulation devices.

11. The well system of claim 8, wherein the one or more actuatable dogs are hydraulically actuatable to extend radially outward.

12. A method of operating a well system, comprising:

receiving a formation fluid from a subterranean formation into an inflow control device, the inflow control device forming part of a completion string arranged within a wellbore penetrating the subterranean formation, wherein the inflow control device includes: a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the one or more first flow ports, each flow port facilitating fluid communication between the subterranean formation and an interior of the base pipe; a first flow regulation device arranged within the base pipe and actuatable to expose or occlude the one or more first flow ports; a second flow regulation device disposed within the base pipe and actuatable to expose or occlude the one or more second flow ports; and a downhole shifting device operable to independently manipulate a position of the first and second flow regulation devices;

operating the downhole shifting device to move the first flow regulation device from an open position, where the one or more first flow ports are exposed, to a closed position, where the one or more first flow ports are occluded by the first flow regulation device; and

flowing the formation fluids into the interior of the base pipe via only the one or more second flow ports and thereby operating the inflow control device at 50% capacity.

13. The method of claim 12, wherein the first flow regulation device comprises a first sliding sleeve defining a first profile, and the downhole shifting device provides one or more actuatable dogs, and wherein operating the downhole shifting device comprises:

actuating the one or more actuatable dogs;

locating the first profile with the one or more actuatable dogs and mating the one or more actuatable dogs with the first profile; and

applying an axial load on the first sliding sleeve with the downhole shifting device and thereby moving the first sliding sleeve to the closed position.

14. The method of claim 13, wherein the second flow regulation device comprises a second sliding sleeve defining a second profile, and wherein operating the downhole shifting device further comprises:

actuating the one or more actuatable dogs;

locating the second profile with the one or more actuatable dogs and mating the one or more actuatable dogs with the second profile; and

applying an axial load on the second sliding sleeve with the downhole shifting device and thereby moving the second sliding sleeve to a closed position, where the one or more second flow ports are occluded by the second sliding sleeve.

15. The method of claim 12, wherein operating the downhole shifting device is preceded by conveying the downhole shifting device to the base pipe using a conveyance.