Patent Publication Number: US-2022235628-A1

Title: Controlling fluid flow through a wellbore tubular

Description:
TECHNICAL FIELD 
     The present disclosure describes apparatus, systems, and methods for controlling fluid flow through a wellbore tubular. 
     BACKGROUND 
     Inflow control devices are often used in hydrocarbon production operations. For example, inflow control devices can be positioned within a wellbore and operated to open and close to, for instance, limit an amount of water from a subterranean formation (along with one or more hydrocarbons) that is produced to the surface. 
     SUMMARY 
     In an example implementation, a wellbore flow control system includes a production tubular member configured to run into a wellbore formed from a terranean surface and into a subterranean formation; a plurality of autonomous inflow control valves (AICVs) positioned on the production tubular member, each of the plurality of AICVs controllable based at least in part on at least one of a density or a viscosity of a formation fluid; and a plurality of sliding sleeves mounted in the production tubular member, each of the plurality of sliding sleeves mounted near a set of AICVs of the plurality of AICVs, each of the plurality of sliding sleeves controllable based on a wellbore drawdown pressure to fluidly couple or fluidly decouple an inner volume of the production tubular member with the subterranean formation through the particular set of AICVs. 
     In an aspect combinable with the general implementation, the set of AICVs includes a single AICV or a pair of AICVs. 
     In another aspect combinable with any one of the previous aspects, each of the plurality of sliding sleeves is controllable based on the wellbore drawdown pressure to fluidly couple or fluidly decouple the inner volume of the production tubular member with the subterranean formation through one AICV of the pair of AICVs in the particular set of AICVs. 
     In another aspect combinable with any one of the previous aspects, the production tubular member includes a plurality of compartments, each compartment including a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves. 
     In another aspect combinable with any one of the previous aspects, a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs. 
     In another aspect combinable with any one of the previous aspects, the wellbore drawdown pressure includes a difference between the reservoir pressure and a flowing bottomhole pressure of the wellbore. 
     Another aspect combinable with any one of the previous aspects further includes one or more packers positioned on the production tubular member. 
     In another aspect combinable with any one of the previous aspects, adjacent compartments of the plurality of compartments are fluidly separated by at least one packer of the plurality of packers. 
     Another aspect combinable with any one of the previous aspects further includes a plurality of screens, each screen mounted across one or more AICVs of the plurality of AICVs. 
     In another general implementation, a wellbore fluid flow control method includes operating a production tubular member run into a wellbore formed from a terranean surface and into a subterranean formation, the production tubular member including a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves, at least one of the plurality of sliding sleeves in a closed position to fluidly decouple a first set of AICVs of the plurality of AICVs from the subterranean formation; determining a composition of a wellbore fluid flowing from the subterranean formation into the production tubular member through a second set of AICVs of the plurality of AICVs; based on the determined composition, autonomously modulating a second set of AICVs of the plurality of AICVs toward a closed position; determining a flowing bottomhole pressure; and based on the determined flowing bottomhole pressure being less than a desired value, adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards an open position to fluidly couple the production tubular member to the subterranean formation through the first set of AICVs. 
     In an aspect combinable with the general implementation, autonomously modulating the first set of AICVs of the plurality of AICVs toward the open position includes autonomously modulating one or two AICVs of the plurality of AICVs toward the open position. 
     In another aspect combinable with any one of the previous aspects, the production tubular member includes a plurality of compartments, each compartment including a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves. 
     In another aspect combinable with any one of the previous aspects, the first set of AICVS comprises a pair of AICVs. 
     In another aspect combinable with any one of the previous aspects, adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through the first set of AICVs includes adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through one AICV of the pair of AICVs of the first set of AICVs. 
     In another aspect combinable with any one of the previous aspects, the first set of AICVs is positioned in a first compartment and the second set of AICVs positioned in a second compartment. 
     In another aspect combinable with any one of the previous aspects, a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs. 
     Another aspect combinable with any one of the previous aspects further includes fluidly isolating the first compartment from the second compartment within an annulus between the production tubular member and the subterranean formation by at least one packer positioned on the production tubular member. 
     Another aspect combinable with any one of the previous aspects further includes hydraulically actuating the at least one packer positioned on the production tubular member to fluidly isolate the first compartment from the second compartment. 
     Another aspect combinable with any one of the previous aspects further includes re-determining the flowing bottomhole pressure; and based on the re-determined flowing bottomhole pressure being less than a desired value, adjusting at least another sliding sleeve of the plurality of sliding sleeves toward the open position to fluidly couple the production tubular member to the subterranean formation through a third set of AICVs of the plurality of AICVs. 
     Another aspect combinable with any one of the previous aspects further includes screening the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs with a plurality of screens, each screen mounted across one or more AICVs of the second set of AICVs. 
     Another aspect combinable with any one of the previous aspects further includes running the production tubular member into the wellbore; and maintaining the at least one sliding sleeve in the closed position during the running. 
     Another aspect combinable with any one of the previous aspects further includes determining the flowing bottomhole pressure with a pressure sensor positioned at or near an entry of the wellbore; and measuring a flow rate of the wellbore fluid with a flowmeter positioned at or near the entry of the wellbore. 
     In another aspect combinable with any one of the previous aspects, determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs includes determining the composition of the wellbore fluid based on at least one of the viscosity or density. 
     In another aspect combinable with any one of the previous aspects, determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs includes determining the composition of the wellbore fluid at the second set of AICVs. 
     Implementations of a tubular flow control system according to the present disclosure may include one or more of the following features. For example, a tubular flow control system according to the present disclosure can prolong a life of a hydrocarbon well. As another example, a tubular flow control system according to the present disclosure can maximize dry oil and/or gas production. As a further example, a tubular flow control system according to the present disclosure can reduce costs by enhancing well performance without requiring rig intervention. 
     The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic diagram of an example implementation of a downhole flow control system according to the present disclosure. 
         FIG. 2  is a schematic diagram of an example implementation of a downhole flow control tubular according to the present disclosure. 
         FIG. 3  is a flowchart of an example method performed with or by an example implementation of a downhole flow control system according to the present disclosure. 
         FIG. 4  is a schematic illustration of an example controller (or control system) for operating a downhole flow control system according to the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure describes example implementations of a downhole flow control system that includes autonomous inflow control valves (AICVs) and sliding sleeves that operate in combination to control a flow of a wellbore fluid from a subterranean formation (also called a reservoir) into a production tubular for production at a terranean surface. In some aspects, the downhole flow control system includes a tubular member or section that may be part of or coupled to a wellbore tubular, such as a production tubing or casing. The tubular member includes, in some aspects, one or more AICVs and at least one sliding sleeve in a particular compartment of the tubular member. In some aspects, the tubular member can include multiple compartments. 
       FIG. 1  is a schematic diagram of an example implementation of a downhole flow control system  100  according to the present disclosure. As illustrated, a wellbore  104  is formed (for example, drilled or otherwise) from a terranean surface  102  and into and through a subterranean formation  118 . Although the terranean surface  102  is illustrated as a land surface, terranean surface  102  may be a sub-sea or other underwater surface, such as a lake or an ocean floor or other surface under a body of water. Thus, the present disclosure contemplates that the wellbore  104  may be formed under a body of water from a drilling location on or proximate the body of water. 
     The illustrated wellbore  104 , in this example, is a directional wellbore. For instance, the wellbore  104  includes a substantially vertical portion  106  coupled to a radiused or curved portion  108 , which in turn is coupled to a substantially horizontal portion  110 . As used in the present disclosure, “substantially” in the context of a wellbore orientation, refers to wellbores that may not be exactly vertical (for example, exactly perpendicular to the terranean surface  102 ) or exactly horizontal (for example, exactly parallel to the terranean surface  102 ). In other words, those of ordinary skill in the drill arts would recognize that vertical wellbores often undulate offset from a true vertical direction, that they might be drilled at an angle that deviates from true vertical, and horizontal wellbores often undulate offset from a true horizontal direction. Further, the substantially horizontal portion  110 , in some aspects, may be a slant wellbore or other directional wellbore that is oriented between exactly vertical and exactly horizontal. Further, the substantially horizontal portion  110 , in some aspects, may be a slant wellbore or other directional well bore that is oriented to follow the slant of the formation  118 . As illustrated in this example, the three portions of the wellbore  104 —the vertical portion  106 , the radiused portion  108 , and the horizontal portion  110 —form a continuous wellbore  104  that extends into the Earth. 
     In this example, the illustrated wellbore  104  has a surface casing  120  positioned and set around the wellbore  104  from the terranean surface  102  into a particular depth in the Earth. For example, the surface casing  120  may be a relatively large-diameter tubular member (or string of members) set (for example, cemented) around the wellbore  104  in a shallow formation. As used herein, “tubular” may refer to a member that has a circular cross-section, elliptical cross-section, or other shaped cross-section. 
     As illustrated, a production casing  122  is positioned and set within the wellbore  104  downhole of the surface casing  120 . Although termed a “production” casing, in this example, the casing  122  may include any casing installed in the wellbore  104  that subject to hydrocarbon production operations, such as, for example, perforating operations, hydraulic fracturing operations, or production operations (or a combination thereof). Thus, the casing  122  refers to and includes any form of tubular member that is set (for example, cemented) in the wellbore  104  downhole of the surface casing  120 . In some examples, the production casing  122  may begin at an end of the radiused portion  108  and extend throughout the substantially horizontal portion  110 . The casing  122  could also extend into the radiused portion  108  and into the vertical portion  106 . 
     As shown, cement  130  is positioned (for example, pumped) around the casings  120  and  122  in an annulus between the casings  120  and  122  and the wellbore  104 . The cement  130 , for example, may secure the casings  120  and  122  (and any other casings or liners of the wellbore  104 ) through the subterranean formations (including subterranean formation  118 ) under the terranean surface  102 . In some aspects, the cement  130  may be installed along the entire length of the casings (for example, casings  120  and  122  and any other casings), or the cement  130  could be used along certain portions of the casings if adequate for a particular wellbore  104 . 
     The wellbore  104  and associated casings  120  and  122  may be formed with various example dimensions and at various example depths (for example, true vertical depth, or TVD). For instance, a conductor casing (not shown) may extend down to about 120 feet TVD, with a diameter of between about 28 in. and 60 in. The surface casing  120  may extend down to about 2500 feet TVD, with a diameter of between about 22 in. and 48 in. An intermediate casing (not shown) between the surface casing  120  and production casing  122  may extend down to about 8000 feet TVD, with a diameter of between about 16 in. and 36 in. The production casing  122  may extend substantially horizontally (for example, to case the substantially horizontal portion  110 ) with a diameter of between about 11 in. and 22 in. The foregoing dimensions are merely provided as examples and other dimensions (for example, diameters, TVDs, lengths) are contemplated by the present disclosure. For example, diameters and TVDs may depend on the particular geological composition of one or more of multiple subterranean formations (including formation  118 ), particular drilling techniques, or particular secondary operation techniques (for example, perforating, fracturing, acid jobs, fluid injection from other wellbores, and otherwise). 
     As shown in this example, the downhole flow control system  100  includes a wellbore tubular  124 , for example, a production tubing or otherwise, that extends into the wellbore  104  from the terranean surface  102 . Coupled to or part of the wellbore tubular  124  is a production tubular member (or section)  125 . In some aspects, the production tubular member  125  is a single-piece downhole tool (tubular) that includes one or more AICVs, one or more sliding sleeves, and one or more wellbore seals (for example, packers) as described herein and can be coupled (for example, threadingly or otherwise) to the wellbore tubular  124 . In some aspects, the production tubular member  125  comprises multiple tubular sections coupled together (for example, threadingly). Each tubular section of the tubular member  125  may comprise one or more AICVs, one or more sliding sleeves, and one or more wellbore seals (for example, packers) as described herein. 
     As shown in this example, the tubular member  125  includes or is separated into multiple compartments  138   a - 138   c  as shown in  FIG. 1 . Each compartment  138   a - 138   c  may include one or more AICVs and at least one sliding sleeve. In some aspects, each compartment  138   a - 138   c  is fluidly isolated (for example, within an annulus volume between the tubular member  125  and the casing  122 ) from other compartments  138   a - 138   c  by at least one wellbore seal  132 , such as a packer  132  (for example, hydraulically or mechanically actuated packer). For example, as shown in  FIG. 1 , the compartment  138   a  includes (two) AICVs  134   a  and the sliding sleeve  136   a ; the compartment  138   b  includes (two) AICVs  134   b  and the sliding sleeve  136   b ; and the compartment  138   c  includes (two) AICVs  134   c  and the sliding sleeve  136   c . Other example implementations of the tubular member  125  can include more or fewer compartments; further, other example implementations of each compartment  138   a - 138   c  can include more or fewer AICVs. 
     In some aspects, the tubular member  125  can control wellbore water production from the subterranean formation  118  into the wellbore tubular  124 , as well as wellbore drawdown, by operating (in combination) the illustrated AICVs with the illustrated sliding sleeves (for example, on a compartment-by-compartment basis). For example, each of the AICVs  134   a - 134   c  can be controlled (for example, to open, to close, or to be positioned between 100% open and 100% closed) autonomously. For example, the AICVs  134   a - 134   c  can operate to autonomously (for example, without direction or control external to the valves), distinguish between hydrocarbons and undesired fluids (for example, water) within a produced flow into the AICVs  134   a - 134   c . When the produced fluids are 100% hydrocarbons, the AICVs  134   a - 134   c  autonomously operate at 100% open. On the other hand, the AICVs  134   a - 134   c  are autonomously operated to close or partially close based on a particular percentage of undesired fluid/gas passing through the AICVs  134   a - 134   c . Thus, the tubular member  125  allows selective activation of each AICV (or set of AICVs in a compartment) based on watercut without a need for rig intervention. In some aspects, watercut is determined by a density, a viscosity, or both, of the wellbore fluid. 
     As one or more AICVs  134   a - 134   c  (or sets of AICVs for more than one AICV per compartment) are adjusted, wellbore drawdown can be changed. In some aspects according to the present disclosure, wellbore drawdown is a pressure difference in a reservoir pressure (for example, pressure of the subterranean formation  118 ) and a flowing bottomhole pressure (for example, a pressure within and at a downhole end of the wellbore  104  during production of the wellbore fluid). As watercut increases (and one or more AICVs  134   a - 134   c  or sets of AICVs are closed), an increasing amount of a wellbore fluid production flows through remaining open (or at least partially open) AICVs in particular compartments  138   a - 138   c  in the tubular member  125 . Such compartments  138   a - 138   c  may therefore being to be “dry” (in other words, with less and less watercut), which will increase wellbore drawdown in the dry compartments  138   a - 138   c . This can lower overall well production of hydrocarbons. 
     The example tubular member  125  can activate one or more of the sliding sleeves  136   a - 136   c  (for example, based on measurements from one or more sensors in a sensor system  146 ) to increase wellbore fluid production into the wellbore tubular  124  as the flowing bottom-hole pressure decreases below a particular threshold. Thus, well productivity can increase and wellbore drawdown can decrease in a rigless operation (in other words, rigless intervention) with the tubular member  125 . 
       FIG. 2  is a schematic diagram of an example implementation of a downhole flow control tubular  200  according to the present disclosure. In some aspects, the flow control tubular  200  can be used as or in place of the tubular member  125  shown in  FIG. 1 . As shown in  FIG. 2 , the flow control tubular  200  is positioned in a portion of a wellbore  201  that is formed in a reservoir  203 . In this example, the flow control tubular  200  a tubing  202  with an interior volume  206 . An annulus  204  is formed between the wellbore  201  and the tubing  202 . 
     As shown in this example, the flow control tubular  200  includes or is separated into multiple compartments  208   a - 208   c . Each compartment  208   a - 208   c  may include one or more AICVs and at least one sliding sleeve. As shown, each compartment  208   a - 208   c  is fluidly isolated (for example, within the annulus  204  between the tubing  202  and the wellbore  201 ) from other compartments  208   a - 208   c  by at least one packer  211  (for example, a hydraulically or mechanically actuated packer). In this example, each compartment  208   a - 208   c  includes two AICVs  210   a  and a sliding sleeve  212 . Other example implementations of the flow control tubular  200  can include more or fewer compartments; further, other example implementations of each compartment  208   a - 208   c  can include more or fewer AICVs  210  or more sliding sleeves  212 . 
     As further shown in  FIG. 2 , each compartment  208   a - 208   c  include a screen  214  that circumscribes the tubing  202  around each AICV  210 . The screen  214 , in some aspects, can filter fluid particulates in the wellbore fluid  215  from entering the interior volume  206  of the tubing  202  through the AICVs  210 . 
     In this example, each sliding sleeve  212  is moveable (for example, by coiled tubing) to fluidly decouple the annulus  204  from the interior volume  206  through one or both AICVs  210  of each compartment  208   a - 208   c  to prevent (or substantially prevent) a wellbore fluid (or production flow)  215  from entering the tubing  202  from one or more perforations or fractures in the reservoir  203  (and casing, not shown). In some aspects, each sliding sleeve  212  is moveable (to fully or partially cover or uncover one or more AICVs within a particular compartment), for example by coiled tubing. Independently of control of the sliding sleeves  212 , each AICV  210  is autonomously controllable to adjust to a fully open position, a fully closed position, or a partially open position. 
     In some aspects, the flow control tubular  200  can be installed initially with one or more of the sliding sleeves  212  in a closed position (fluidly decoupling one or more AICVs  210  from the reservoir  203 ). At an initial stage, production flow  215  is passing through the other AICVs (for fluidly decoupled) only. As production continues, the undesirable fluid/gas percentage passed through the AICVs  210  that are not fluidly decoupled by a sliding sleeve  112  can increase, resulting in autonomous closure (for example, partial or full) the open AICVs  210 . The flowing bottomhole pressure is thus lowered, thereby increasing drawdown due to less flow area into the flow control tubular  200 . This decrease in flowing bottomhole pressure can ultimately result in lowering the flowrate of the production fluid  215  into the flow control tubular  200 . Once this pressure decreases below a particular threshold, one or more of the sliding sleeves  112  can be mechanically opened (for example, riglessly using a coiled tubing unit). This intervention by opening one or more of the previously closed sliding sleeves  112  can therefore fluidly couple two or more AICVs  210  to the reservoir  203  to restore well productivity by increasing the flow area (leading to higher flowing bottomhole pressure and lower drawdown). 
       FIG. 3  is a flowchart of an example method  300  performed with or by an example implementation of a downhole flow control system according to the present disclosure. For example, method  300  may be executed with or by the downhole flow control system  100  (including the tubular member  125  or the flow control tubular  200 ). Method  300  can begin at step  302 , which includes operating a production tubular member (within a wellbore) that includes a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves. At least one of the sliding sleeves is positioned to fluidly decouple a first set (one or more) of AICVs of the plurality of AICVs from a reservoir. For example, a downhole tool (for example, tubular member  125  or flow control tubular  200 ) can be run into a wellbore as part of or coupled to a wellbore tubular, such as a production tubular. In some aspects, the wellbore can include a casing that has previously been perforated and, in some cases, fractured. Alternatively, the wellbore may be an open hole completion. The production tubular member can be defined by or include multiple compartments, where each of the compartments includes one or more (such as a set of) AICVs and a sliding sleeve (for example, mechanically operated). 
     In some aspects, one or more packers are included with or coupled to the production tubular member and actuated to fluidly separate the compartments in an annulus between the production tubular member and the subterranean formation (or casing). In some aspects, while the production tubular member is initially operating (or running into the wellbore), each of the AICVs can be open and one or more of the sliding sleeves is in a closed position. In some aspects, the number of AICVs, the number of compartments, or the number of AICVs per compartment (or a combination thereof) may be determined and designed into the production tubular member based on, for instance, an expected or measure reservoir pressure, an expected or desired inflow rate of the wellbore fluid, or a combination thereof. 
     Method  300  can continue at step  304 , which includes flowing a wellbore fluid from the reservoir through a second set of AICVs and into the production tubular. The second set of AICVs, therefore, is fluidly coupled to the reservoir without being closed by one or more of the sliding sleeves. For example, during a normal operation of the production tubular member, the AICVs in the second set (or sets other than the first set, with each set of AICVS positioned in a particular compartment of the production tubular member) are open (for example, 100% open) to allow a wellbore fluid (for example, a mixture of hydrocarbon fluids and water) to flow from the reservoir, into the annulus, through the set of open AICVs, and into an interior volume of the production tubular member. During step  304 , the sliding sleeves can be positioned so as to allow fluid flow through the second set of AICVs without impedance. In some aspects, a screen may be positioned in each compartment of the production tubular member to catch or filter particulates from the wellbore fluid as it enters the interior volume. 
     Method  300  can continue at step  306 , which includes determining a composition of the wellbore fluid. For example, in some aspects, one or more sensors (of the AICVs) can operate to determine one or more properties of the wellbore fluid to determine the composition. Also, there can be a pressure sensor to determine a flowing bottomhole pressure and a flowmeter to determine a flow rate of the produced fluids (included in the sensor system  146 ). In some aspects, such properties, such as viscosity, density, or both, can determine a composition, and therefore, a watercut of the wellbore fluid. 
     Method  300  can continue at step  308 , which includes a determination of whether the composition of the wellbore fluid indicates a high watercut. In some aspects, this step is performed autonomously by the AICVs on a valve-by-valve basis. For example, if the watercut (as determined by the composition) is low (below a threshold value), then step  308  may continue back to step  304  for normal operation (for example, with the second set of AICVs fully open). In some aspects, the property (and watercut) can be determined on a compartment-by-compartment basis. If the watercut is above a desired value (according to the composition) in one or more of the compartments, then the method can continue to step  310 . 
     Step  310  includes modulating the second set of AICVs of the plurality of AICVs toward a closed position. As in step  308 , this step is performed autonomously by the second set of AICVs, for example, on a valve-by-valve basis. For example, based on the determined watercut being too high in  308 , the second set (one or more) of AICVs in the production tubular member may be autonomously adjusted toward a closed position. In some aspects, only the set of AICVs within the particular compartment in which the watercut was determined to be too high is autonomously modulated toward or to the closed position. 
     Method  300  can continue at step  312 , which includes flowing a wellbore fluid from a reservoir through the modulated second set of AICVs and into the production tubular. For example, once the second set of AICVs is adjusted in step  310 , operation of the production tubular member to receive the wellbore fluid can continue. Wellbore fluid received into the production tubular through open AICVs (all or partially) can be circulated to the terranean surface. 
     Method  300  can continue at step  314 , which includes determining a Flowing bottomhole pressure. For example, one or more pressure sensors can determine a differential between the reservoir pressure and the bottomhole pressure in the wellbore (for example, during step  312 ). For example, after producing a wellbore fluid from a well for a time period (as in step  304 ), a percentage of undesired fluid can increase in some of the compartments of the production tubular member. Thus, some restriction or full closure of the second set of AICVs (as in step  310 ) can occur, which can minimize production from these compartments in which one or more AICVs were closed. Execution of step  310 , therefore, can result in creating a higher wellbore drawdown across the other compartments to meet a target wellbore fluid flowrate into the production tubular member. As a wellbore drawdown increases, the flowing bottom hole pressure can reach a minimum operating limit and the target rate will not be achieved. 
     Thus, method  300  can continue at step  316 , which includes a determination of whether the Flowing bottomhole pressure is less than a threshold value. For example, if the determination is no and the flowing bottomhole pressure is greater than the threshold value (thereby signifying an acceptable production rate of the wellbore fluid), then method  300  can revert back to step  312 . 
     If the determination in step  316  is yes, then method  300  can continue at step  318 , which includes adjusting the sliding sleeve toward an open position to fluidly couple the production tubular member from the subterranean formation through the first set of AICVs. For example, in a compartment in which the AICVs are fluidly decoupled from the reservoir due to position of the sliding sleeve, the sliding sleeve can be adjusted to increase or start flow of the wellbore fluid into that compartment by uncovering the set (one or more) of the AICVs in that compartment (in other words, fluidly coupling that compartment to the reservoir). 
     In some aspects, step  318  includes adjusting the sliding sleeve toward the open position to fluidly couple the production tubular member from the subterranean formation through a number of AICVs less than the full set of AICVs in the first set of AICVs. For example, the first set of AICVs can include a pair of AICVs. In some aspects, during the operation of the production tubular member (for example, in step  304 ), a first AICV of the pair of AICVs is fluidly decoupled (by the sliding sleeve) from the subterranean formation, while a second AICV of the pair of AICVs is fluidly coupled to the subterranean formation. Step  318  can include, therefore, adjusting the sliding sleeve to fluidly couple the first AICV to the subterranean formation, thereby facilitating flow of fluid through both the first and second AICVs of the first set of AICVs. 
     Method  300  can continue at step  320 , which includes flowing the wellbore fluid from the reservoir through the first set of AICVs (now uncovered by the adjusted sliding sleeve) and into the production tubular. For example, after adjusting the sliding sleeve in one or more compartments, operation of flowing the wellbore fluid into the production tubular member (at an increased flowing bottomhole pressure) can continue. 
     While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any inventions or of what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination. 
     Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described above should not be understood as requiring such separation in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products. 
     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.