Patent Publication Number: US-8985215-B2

Title: Single trip multi-zone completion systems and methods

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 13/896,887 filed on May 17, 2013, which is a continuation of U.S. patent application Ser. No. 13/988,139 filed on May 17, 2013, which claims priority to and is a National Stage entry of International App. No. PCT/US2012/057241 filed on Sep. 26, 2012. 
    
    
     BACKGROUND 
     The present invention relates to the treatment of subterranean production intervals and, more particularly, to gravel packing, fracturing, and production of multiple production intervals with a single trip multi-zone completion system. 
     In the production of oil and gas, recently drilled deep wells reach as much as 31,000 feet or more below the ground or subsea surface. Offshore wells may be drilled in water exhibiting depths of as much as 10,000 feet or more. The total depth from an offshore platform to the bottom of a drilled wellbore can be as much as eight miles. Such extraordinary distances in modern well construction cause significant challenges in equipment, drilling, and servicing operations. 
     For example, tubular strings can be introduced into a well in a variety of different ways. It may take many days for a wellbore service string to make a “trip” into a wellbore, which may be due in part to the time consuming practice of making and breaking pipe joints to reach the desired depth. Moreover, the time required to assemble and deploy any service tool assembly downhole for such a long distance is very time consuming and costly. Since the cost per hour to operate a drilling or production rig is very expensive, saving time and steps can be hugely beneficial in terms of cost-savings in well service operations. Each trip into the wellbore adds expense and increases the possibility that tools may become lost in the wellbore, thereby requiring still further operations for their retrieval. Moreover, each additional trip into the wellbore oftentimes has the effect of reducing the inner diameter of the wellbore, which restricts the size of tools that are able to be introduced into the wellbore past such points. 
     To enable the fracturing and/or gravel packing of multiple hydrocarbon-producing zones in reduced timelines, some oil service providers have developed “single trip” multi-zone systems. The single trip multi-zone completion technology enables operators to perforate a large wellbore interval at one time, then make a clean-out trip and run all of the screens and packers at one time, thereby minimizing the number of trips into the wellbore and rig days required to complete conventional fracture and gravel packing operations in multiple pay zones. It is estimated that such technology can save in the realm of $20 million per well. Since rig costs are so high in the deepwater environment, more efficient and economical means of carrying out single trip multi-zone completion operations is an ongoing effort. 
     SUMMARY OF THE INVENTION 
     The present invention relates to the treatment of subterranean production intervals and, more particularly, to gravel packing, fracturing, and production of multiple production intervals with a single trip multi-zone completion system. 
     In some embodiments of the disclosure, a single trip multi-zone completion system is disclosed. The system may include an outer completion string having at least one sand screen arranged thereabout and a flow control device movably disposed within the at least one sand screen between an open position and a closed position, and an insert string arranged within the outer completion string and having at least one control and data acquisition module disposed thereon having one or more coupling mechanisms and configured to locate and move the flow control device. 
     In other embodiments of the disclosure, a single trip multi-zone completion system for producing from one or more formation zones is disclosed. The system may include an outer completion string having at least one sand screen arranged thereabout adjacent the one or more formation zones, a flow control device disposed within the at least one sand screen and movable between an open position and a closed position, wherein, when in the open position, fluids may communicate from the one or more formation zones, through the at least one sand screen, and into the outer completion string, an insert string arranged within the outer completion string and being communicably coupled to the outer completion string at a crossover coupling, the crossover coupling having one or more control lines coupled thereto, and at least one control and data acquisition module disposed on the insert string and having one or more mechanical coupling mechanisms. 
     In yet other embodiments of the disclosure, a method of producing from one or more formation zones is disclosed. The method may include arranging an outer completion string within a wellbore adjacent the one or more formation zones, the outer completion string having at least one sand screen arranged thereabout and a flow control device movably disposed within the at least one sand screen, locating an insert string within the outer completion string, the insert string having at least one control and data acquisition module disposed thereon having one or more mechanical coupling mechanisms extending therefrom, locating the flow control device, and moving the flow control device between a closed position and an open position, wherein, when in the open position, fluids may communicate from the one or more formation zones, through the at least one sand screen, and into the outer completion string. 
     In even further aspects of the disclosure, a method of deploying a single trip multi-zone completion system is disclosed. The method may include arranging an outer completion string within a wellbore that penetrates one or more formation zones, the outer completion string having at least one sand screen arranged thereabout and a flow control device movably disposed within the at least one sand screen, locating an inner service tool within the outer completion string, treating the one or more formation zones with the inner service tool, retrieving the inner service tool from within the outer completion string, locating an insert string within the outer completion string, the insert string having at least one control and data acquisition module arranged therein, and locating and moving the flow control device with the at least one control and data acquisition module and thereby regulating a fluid flow through the at least one sand screen. 
     The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure. 
         FIG. 1  is an exemplary single trip multi-zone system, according to one or more embodiments. 
         FIG. 2  is a partial cross-sectional view of the single trip multi-zone system of  FIG. 1 , having an exemplary insert string arranged therein, according to one or more embodiments disclosed. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention relates to the treatment of subterranean production intervals and, more particularly, to gravel packing, fracturing, and production of multiple production intervals with a single trip multi-zone completion system. 
     The exemplary single trip multi-zone systems and methods disclosed herein allow multiple zones of a wellbore to be gravel packed and fractured in the same run-in trip into the wellbore. An exemplary insert string is subsequently extended into the wellbore in order to regulate and monitor production from each zone. Control lines located within the insert string and also along the sand face allow operators to monitor production operations, including measuring fluid and well environment parameters at each point within the system. The insert string may include one or more control and data acquisition modules that include mechanical coupling mechanisms used to locate and move corresponding flow control devices arranged within respective sand screens adjacent each zone. Adjusting the position of the flow control device with a corresponding control and data acquisition module serves to choke or otherwise regulate the production flow rate through the sand screen, thereby allowing for the intelligent production of hydrocarbons from each zone. In the event a control and data acquisition module fails or otherwise malfunctions, the insert string may be returned to the surface without requiring the removal of the remaining portions of the system. Once proper repairs or modifications have been completed, the insert string may once again be run into the wellbore to resume production. 
     Referring to  FIG. 1 , illustrated is an exemplary single trip multi-zone completion system  100 , according to one or more embodiments. As illustrated, the system  100  may include an outer completion string  101  coupled to a work string or production tubing  103  that extends longitudinally within a wellbore  102 . The wellbore  102  may penetrate multiple formation zones  104   a ,  104   b , and  104   c , and the outer completion string  101  may be extended into the wellbore  102  until being arranged or otherwise disposed adjacent the formation zones  104   a - c . The formation zones  104   a - c  may be portions of a common subterranean formation or hydrocarbon-bearing reservoir. Alternatively, one or more of the formation zones  104   a - c  may be portion(s) of separate subterranean formations or hydrocarbon-bearing reservoirs. The term “zone” as used herein, however, is not limited to one type of rock formation or type, but may include several types, without departing from the scope of the disclosure. 
     As will be discussed in greater detail below, the system  100  may be deployed within the wellbore  102  in a single trip and used to hydraulically fracture and gravel pack the various formation zones  104   a - c , and subsequently regulate hydrocarbon production therefrom. Although only three formation zones  104   a - c  are depicted in  FIG. 1 , it will be appreciated that any number of formation zones  104   a - c  (including one) may be treated or otherwise serviced using the system  100 , without departing from the scope of the disclosure. 
     As is depicted in  FIG. 1 , the wellbore  102  may be lined with a string of casing  106  and properly cemented therein, as known in the art. In at least one embodiment, a cement plug  108  may be formed at the bottom of the casing  106 . In other embodiments, however, the system  100  may be deployed or otherwise operated in an open-hole section of the wellbore  102 , without departing from the scope of the disclosure. One or more perforations  110  may be formed in the casing  106  at each formation zone  104   a - c  and configured to provide fluid communication between each respective formation zone  104   a - c  and the annulus formed between the outer completion string  101  and the casing  102 . 
     The system  100  may include a safety valve  112  and a crossover coupling  114  arranged in or otherwise forming part of the production tubing  103 . In some embodiments, the safety valve  112  may be a tubing-retrievable safety valve, such as the DEPTHSTAR® safety valve commercially-available from Halliburton Energy Services of Houston, Tex., USA. The safety valve  112  may be controlled using a control line  116  that extends from a remote location (not shown), such as the Earth&#39;s surface or another location within the wellbore  102 , to the safety valve  112 . In at least one embodiment, the control line  116  may be a surface-controlled subsurface safety valve control line that controls the actuation of the safety valve  112 . 
     In some embodiments, the crossover coupling  114  may be an electro-hydraulic wet connect that provides an electrical wet mate connection between opposing male and female connectors. In other embodiments, the crossover coupling  114  may be an inductive coupler providing a releasable electromagnetic coupling or connection with no contact between the crossover coupling  114  and the internal tubing. Exemplary crossover couplings  220  that may be used in the disclosed system  100  are described in U.S. Pat. Nos. 8,082,998, 8,079,419, 4,806,928 and in U.S. patent application Ser. No. 13/405,269, each of which is hereby incorporated by reference in their entirety. 
     One or more control lines  118  may extend external to the production tubing  103  from a remote location (e.g., the Earth&#39;s surface or another location within the wellbore  102 ) to the crossover coupling  114 . At the crossover coupling  114 , portions of the control line  118  may be coupled to or otherwise extend within the crossover coupling  114  and be configured to communicably couple devices or mechanisms arranged within the outer completion string  101  to the surface, as will be described in greater detail below. Moreover, at least one length or portion of the control line  118 , labeled as a surveillance line  119 , may run past the crossover coupling  114 , as illustrated, and extend externally along the outer surface of the outer completion string  101 . 
     Although only one control line  118  and associated surveillance line  119  is shown in  FIG. 1 , it will be appreciated that any number of control lines  118  (and associated surveillance line(s)  119 ) may be used in the system  100 , without departing from the scope of the disclosure. For example, the illustrated control line  118  may be representative of or otherwise include one or more hydraulic lines, one or more electrical lines, and/or one or more fiber optic lines that extend from the surface external to the production tubing  103  until reaching the crossover coupling  114 . The hydraulic and electrical lines may be configured to provide power to various downhole equipment, but may also be configured to receive and convey command signals and otherwise transmit data to and from the surface of the well. The fiber optic lines, as will be discussed in more detail below, may be configured to monitor one or more fluid and/or well environment parameters, such as pressure, temperature, seismic waves (e.g., flow-induced vibrations), radioactivity, water cut, flow rate, etc. 
     The outer completion string  101  may have a top packer  120  including slips (not shown) configured to support the outer completion string  101  within the casing  106  when properly deployed. Disposed below the top packer  120  is a first flow control device  122   a  (shown in dashed) and a first sand screen  124   a . A first isolation packer  126   a  is disposed below the first sand screen  124   a  and a second circulating sleeve  122   b  (shown in dashed) and a second sand screen  124   b  are disposed below the first isolation packer  126   a . A second isolation packer  126   b  is disposed below the second sand screen  124   b  and a third circulating sleeve  122   c  (shown in dashed) and a third sand screen  124   c  are disposed below the second isolation packer  126   b . The circulating sleeves  122   a - c  may be movably arranged within the outer completion string between open and closed positions. Although described herein as movable sleeves, those skilled in the art will readily recognize that each circulating sleeve  122   a - c  may be any type of flow control device, without departing from the scope of the disclosure. 
     A first annulus  130   a  may be defined between the first formation zone  104   a  and the outer completion string  101 . Second and third annuli  130   b  and  130   c  may similarly be defined between the second and third formation zones  104   b  and  104   c , respectively, and the outer completion string  101 . First, second, and third ports  132   a ,  132   b , and  132   c  may be defined in the outer completion string  101  at the first, second, and third circulating sleeves  122   a - c , respectively. When the respective circulating sleeves  122   a - c  are moved into their open positions, the ports  132   a - c  become exposed and may provide fluid communication from the interior of the outer completion string  101  into the corresponding annuli  130   a - c.    
     In some embodiments, a sump packer  128  may be disposed below the third sand screen  124   c  around a lower seal assembly (not shown). In at least one embodiment, the outer completion string  101  is lowered into the wellbore  102  until engaging the sump packer  128 . In other embodiments, the outer completion string  101  may be lowered into the wellbore  102  and stung into the sump packer  128 . In yet other embodiments, the sump packer  128  is omitted from the system  100  and the production tubing  103  may instead be blanked off at its bottom end so that there is no inadvertent production directly into the outer completion string  101  without first passing through at least the third sand screen  124   c . In embodiments where the system  100  is deployed in an open hole section of the wellbore  102 , suitable inflatable packers or expandable packers could be used in place of the sump packer  128 , the top packer  120 , and the isolation packers  122   a,b.    
     In order to deploy the outer completion string  101  downhole, the sump packer  128  may be lowered into the wellbore  102  and set by wire line at a predetermined location below the various formation zones  104   a - c . The outer completion string  101  is then assembled at the surface starting from the bottom up until the outer completion string  101  is completely assembled and suspended in the wellbore  102  up to a packer or slips (not shown) arranged at the surface. The outer completion string  101  may then be lowered into the wellbore  102  on the production tubing  103  (i.e., work string) which is generally made up to the top packer  120 . In some embodiments, the crossover coupling  114  may be located approximate to the top packer  120 , as illustrated. The safety valve  112  may be added approximate to the well head (not shown). Spacing on the production tubing  103  may be verified and the well head is then attached to the production tubing  103 . 
     The outer completion string  101  may then be lowered into the wellbore  102  on the production tubing  103  until engaging the sump packer  128 . Upon aligning the sand screens  124   a - c  with the corresponding production zones  104   a - c , the top packer  120  may be set and serves to suspend the outer completion string  101  within the wellbore  102 . The isolation packers  126   a,b  may also be set at this time, thereby axially defining each annulus  130   a - c . The top packer  120 , and the isolation packers  126   a,b , may further include or otherwise be configured for control line bypass which allows the surveillance line  119  to pass therethrough external to the outer completion string  101 . 
     At this point, an inner service tool (not shown), also known as a gravel pack service tool, may be assembled and lowered into the outer completion string  101  on a work string (not shown) made up of drill pipe or tubing. The inner service tool may include one or more shifting tools (not shown) used to open and close the circulating sleeves  122   a - c  and also open and close corresponding flow control devices  134   a ,  134   b , and  134   c  (shown in dashed) movably arranged within each sand screen  124   a - c . In some embodiments, the flow control device  134   a - c  may be a sliding sleeve, axially movable within its corresponding sand screen  124   a - c . Accordingly, in at least one embodiment, the flow control devices  134   a - c  may be characterized as inflow control device. 
     As will be discussed in greater detail below, each flow control device  134   a - c  allows fluid communication from an adjacent formation zone  104   a - c  into the outer completion string  101  via its corresponding sand screen  124   a - c . In some embodiments, the inner service tool has two shifting tools arranged thereon, one shifting tool configured to open the circulating sleeves  122   a - c  and the flow control devices  134   a - c , and a second shifting tool configured to close the circulating sleeves  122   a - c  and the flow control devices  134   a - c . In other embodiments, more or less than two shifting tools may be used, without departing from the scope of the disclosure. 
     Before producing hydrocarbons from the various formation zones  104   a - c , each formation zone  104   a - c  may be hydraulically fractured in order to enhance hydrocarbon production, and each annulus  130   a - c  may be gravel packed to ensure limited sand production into the outer completion string  101  during production. The fracturing and gravel packing process for the outer completion string  101  may be accomplished in step-wise fashion for each individual formation zone  104   a - c , starting from the bottom up. In one embodiment, for example, the third formation zone  104   c  may be fractured and the third annulus  130   c  may be gravel packed first. To accomplish this, the second isolation packer  126   b  is set, thereby effectively isolating the third annulus  130   c  from the first and second annuli  130   a,b . The one or more shifting tools may then be used to open the third circulating sleeve  122   c  and the third flow control device  134   c  disposed within the third sand screen  124   c.    
     A fracturing fluid may then be pumped down the work string and into the inner service tool. In some embodiments, the fracturing fluid may include a base fluid, a viscosifying agent, proppant particulates (including a gravel slurry), and one or more additives, as generally known in the art. The incoming fracturing fluid may be directed out of the outer completion string  101  and into the third annulus  130   c  via the third port  132   c . Continued pumping of the fracturing fluid forces the fracturing fluid into the third formation zone  104   c , thereby creating or enhancing a fracture network therein while the accompanying proppant serves to support the fracture network in an open configuration. The incoming gravel slurry builds in the annulus  130   c  between the sump packer  128  and the second isolation packer  126   b  and forms what is known as a “sand face.” The sand face, in conjunction with the third sand screen  124   c , serves to prevent the influx of sand or other particulates from the third formation zone  104   c  into the outer completion string  101  during production operations. 
     Once a desired net pressure is built up in the third formation zone  104   c , the fracturing fluid injection rate is slowed or stopped altogether, and a return flow of fracturing fluid flows through the third sand screen  124   c  and flow control device  134   c  and back into the outer completion string  101  in order to reverse out any excess proppant that may remain in the outer completion string  101 . When the proppant is successfully reversed, the third circulating sleeve  122   c  and the third flow control device  134   c  are closed using the one or more shifting tools, and the third annulus  130   c  is then pressure tested to verify that the sleeves  122   c ,  134   c  are properly closed. At this point, the third formation zone  104   c  has been successfully fractured and the third annulus  130   c  has been gravel packed. 
     The inner service tool may then be moved within the outer completion string  101  to locate the second formation zone  104   b  and first formation zone  104   a , successively, where the foregoing process is repeated in order to fracture the first and second formation zones  104   a,b  and gravel pack the first and second annuli  130   a,b . To accomplish this, the first isolation packer  126   a  is set to isolate the second annulus  130   b  from the first annulus  130   a , and the one or more shifting tools are then used to open the second circulating sleeve  122   b  and the second flow control device  134   b . Fracturing fluid may then be pumped into the second annulus  130   b  via the second port  132   b . The injected fracturing fluid fractures the second formation zone  104   b , and the gravel slurry builds another sand face in the second annulus  130   b  between the second isolation packer  126   b  and the first isolation packer  126   a . Once the second annulus  130   b  is pressure tested, the inner service tool may then be moved to locate the first formation zone  104   a  and again repeat the process. The one or more shifting tools are used to open the first circulating sleeve  122   a  and the first flow control device  134   a . Fracturing fluid may then be pumped into the first annulus  130   a  via the first port  132   a . The injected fracturing fluid fractures the first formation zone  104   a , and the gravel slurry builds yet another sand face in the first annulus  130   a  between the first isolation packer  126   a  and the top packer  120 . Once the first annulus  130   a  is pressure tested, the inner service tool (i.e., the gravel pack service tool) may be removed from the outer completion string  101  and the well altogether, with the circulation sleeves  122   a - c  and flow control devices  134   a - c  providing isolation during installation of the remainder of the completion, as discussed below. 
     Referring now to  FIG. 2 , with continued reference to  FIG. 1 , illustrated is a partial cross-sectional view of the single trip multi-zone system  100  having an exemplary insert string  202  arranged therein, according to one or more embodiments. The insert string  202  may be run or otherwise conveyed through the production tubing  103  until landing off at an anchor profile  204  provided in the outer completion string  101  or production tubing  103 . As illustrated, the anchor profile  204  may be arranged downhole from the crossover coupling  114  and may be configured to anchor the insert string  202  such that the insert string  202  is secured or otherwise “hung off” at this point. In other embodiments, however, the anchor profile  204  may be arranged above or uphole from the crossover coupling  114 , without departing from the scope of the disclosure. 
     The insert string  202  may be communicably coupled to the system  100 , or otherwise the outer completion string  101 , at the crossover coupling  114 . As illustrated, the insert string  202  may include an integrated umbilical  206  that extends longitudinally therein and conveys one or more hydraulic, electrical, and/or fiber optic lines to devices or mechanisms arranged within the insert string  202 . Upon appropriately anchoring the insert string  202 , the crossover coupling  114  may be configured to provide either an electro-hydraulic wet mate connection or an electromagnetic induction connection between the integrated umbilical  206  and the control line  118 . As a result, the control line  118  may be communicably coupled to the integrated umbilical  206  such that the control line  118  is, in effect, extended into the interior of the insert string  202  in the form of the integrated umbilical  206 . 
     The insert string  202  may be run into the wellbore  102  using any type of suitable conveyance mechanism (not shown) such as, but not limited to, work string, drill string, production tubing, coiled tubing, wire line, or the like. Once the insert string  202  is suitably hung off the anchor profile  204  and communicably coupled to the system  100  at the crossover coupling  114 , the conveyance mechanism may be detached therefrom and removed from the well. 
     The insert string  202  may also include one or more control and data acquisition modules  208  (three shown as  208   a ,  208   b , and  208   c ) axially spaced along the insert string  202 . Each control and data acquisition module  208   a - c  may be spaced or otherwise arranged at or adjacent a corresponding formation zone  104   a - c  and configured to interact with the flow control device  134   a - c  of a corresponding sand screen  124   a - c . For example, the first control and data acquisition module  208   a  may be arranged adjacent the first formation zone  104   a  and sand screen  124   a , the second control and data acquisition module  208   b  may be arranged adjacent the second formation zone  104   b  and sand screen  124   b , and the third control and data acquisition module  208   c  may be arranged adjacent the third formation zone  104   c  and sand screen  124   c.    
     Each gauge control and data acquisition module  208   a - c  may also include one or more mechanical coupling mechanisms  210  (two shown on each control and data acquisition module  208   a - c ) configured to locate and manipulate the axial position of a corresponding flow control device  134   a - c , thereby moving the flow control device  134   a - c  between open and closed positions. In one embodiment, the mechanical coupling mechanisms  210  may be actuatable arms. For instance, the mechanism(s)  210  of the first control and data acquisition module  208   a  may be configured to engage and move the first flow control device  134   a  arranged within the first sand screen  124   a , the mechanism(s)  210  of the second control and data acquisition module  208   b  may be configured to engage and move the second flow control device  134   b  arranged within the second sand screen  124   b , and the mechanism(s)  210  of the third control and data acquisition module  208   c  may be configured to engage and move the third flow control device  134   c  arranged within the third sand screen  124   c . Moving the flow control devices  134   a - c  into an open position provides fluid communication from the formation zones  104   a - c  into the outer completion string  101  via the corresponding sand screens  124   a - c . In some embodiments, each flow control device  134   a - c  may form part of an integrated mechanical interval control valve configured to exhibit variable flow capability. For example, adjusting the position of each flow control device  134   a - c  with a corresponding control and data acquisition module  208   a - c  may serve to choke or otherwise regulate the production flow rate through each sand screen  124   a - c.    
     In order to accurately locate the flow control devices  134   a - c , the mechanisms  210  (e.g., actuatable arms) of each gauge control and data acquisition module  208   a - c  may be actuatable. As illustrated, the integrated umbilical  206  may extend to each gauge control and data acquisition module  208   a - c , thereby conveying one or more hydraulic, electrical, and/or fiber optic control lines to each gauge control and data acquisition module  208   a - c , as initially conveyed from the surface via the control line  118 . Accordingly, each gauge control and data acquisition module  208   a - c  may be powered hydraulically or electrically in order to actuate the mechanisms  210  and provide the necessary shifting force to open or close the flow control devices  134   a - c.    
     In some embodiments, the mechanisms  210  may be electro-hydraulically actuated. In other embodiments, however, the mechanisms  210  may be actuated or moved via any suitable method including, but not limited to, mechanically, hydraulically, electromechanically, and the like. In some embodiments, the mechanisms  210  may be actuatable in an axial direction along an actuator body  214  arranged within each gauge control and data acquisition module  208   a - c . For instance, the mechanisms  210  may be configured to translate up and down the body  214  of a corresponding control and data acquisition module  208   a - c  until properly locating the corresponding flow control device  134   a - c . In other embodiments, the mechanisms  210  may be actuatable radially and configured to extend and contract radially with respect to the gauge control and data acquisition module  208   a - c . In yet other embodiments, the mechanisms  210  may be pivotably coupled to the body  214  such that the mechanisms  210  are rotatably actuatable in order to locate and engage a corresponding flow control device  134   a - c . In even further embodiments, the mechanisms  210  may actuatable in any combination of two or more of the preceding actuation formats described above, without departing from the scope of the disclosure. 
     Once the mechanisms  210  of each gauge control and data acquisition module  208   a - c  find their corresponding flow control device  134   a - c , the mechanisms  210  may be configured to axially move the flow control devices  134   a - c  between open and closed positions. Electronics associated with each control and data acquisition module  208   a - c  may be configured to measure and report to the surface how far each flow control device  134   a - c  has been opened. Accordingly, the position of each flow control device  134   a - c  may be known and adjusted in real-time in order to choke or otherwise regulate the production flow rate through each corresponding sand screen  124   a - c . In some embodiments, it may be desired to open one or more of the flow control devices  134   a - c  only partially (e.g., 20%, 40%, 60%, etc.) in order to choke production flow from one or more formation zones  104   a - c . At a later time, it may be desired to adjust the position of the flow control device  134   a - c  again either to a more open or more closed position. 
     As the flow control device  134   a - c  is moved from its closed position into an open position (either fully or partially open), a corresponding port (not shown) defined in the outer completion string  101  is uncovered or otherwise exposed, thereby allowing the influx of fluids into the outer completion string  101  from the respective formation zone  104   a - c . In some embodiments, the port may have an elongated or progressively enlarged shape in the axial direction required to move the flow control device  134   a - c  from closed to open positions. As a result, as the corresponding flow control device  134   a - c  translates to its open position, the volumetric flow rate through the port may progressively increase proportional to its progressively enlarged shape. In some embodiments, for example, one or more of the ports may exhibit an elongated triangular shape which progressively allows an increased amount of fluid flow as the corresponding flow control device  134   a - c  moves to its open position. In other embodiments, however, one or more of the ports may exhibit a tear drop shape, and achieve substantially the same fluid flow increase as the flow control device  134   a - c  moves axially. Accordingly, each flow control device  134   a - c  may be characterized as an integrated flow control choke device. 
     In other embodiments, however, one or more of the flow control devices  134   a - c  may be autonomous variable flow restrictors. For instance, at least one of the flow control devices  134   a - c  may include a spring actuated movable sleeve that opens and closes autonomously, depending on the pressure experienced within each production interval. This may prove advantageous in equalizing fluid flow across multiple production intervals. Other exemplary autonomous variable flow restrictors that may be appropriate for the disclosed embodiments are described in U.S. Pat. No. 8,235,128, incorporated herein by reference in its entirety. 
     The control and data acquisition modules  208   a - c  may also include one or more gauges or sensors  216  arranged thereon and communicably coupled to the integrated umbilical  206 . In particular, the sensors  216  may be communicably coupled to one or more fiber optic and/or electrical lines forming part of the integrated umbilical  206  and configured to detect or otherwise measure one or more fluid and/or well environment parameters such as, but not limited to, pressure, temperature, flow rate, seismic waves (e.g., flow-induced vibrations), radioactivity, combinations thereof, and the like. 
     The sensors  216  arranged inside the outer completion string  101  may work in conjunction with the sensing capabilities provided by the surveillance line  119  disposed outside the outer completion string  101  and extending along the sand face. The surveillance line  119  may include, for example, a fiber optic line and one or more accompanying fiber optic gauges or sensors (not shown). The fiber optic line may be deployed along the sand face and the associated gauges/sensors may be configured to measure and report various fluid properties and well environment parameters within each gravel packed annulus  130   a - c . For instance, the fiber optic line may be configured to measure pressure, temperature, fluid density, seismic activity, vibration, compaction, combinations thereof, and the like. In some embodiments, the fiber optic line may be configured to measure temperature along the entire axial length of each sand screen  124   a - c  and measure fluid pressure in discrete or predetermined locations within the sand face. 
     The surveillance line  119  may further include an electrical line coupled to one or more electric pressure and temperature gauges/sensors situated along the outside of the outer completion string  101 . Such gauges/sensors may be arranged adjacent to each sand screen  124   a - c , for example, in discrete locations on one or more gauge mandrels (not shown). In operation, the electrical line may be configured to measure fluid properties and well environment parameters within each gravel packed annulus  130   a - c  or radially adjacent to where the insert string  202  is located. Such fluid properties and well environment parameters include, but are not limited to, pressure, temperature, fluid density, vibration, radioactivity, combinations thereof, and the like. In some embodiments, the electronic gauges/sensors can be ported to the inner diameter of each sand screen  124   a - c.    
     Accordingly, the fiber optic and electrical lines of the surveillance line  119  may provide an operator with two sets of monitoring data for the same or similar location within the sand face or production intervals. In operation, the electric and fiber optical gauges may be redundant until one technology fails or otherwise malfunctions. As will be appreciated by those skilled in the art, using both types of measurement provides a more robust monitoring system against failures. Moreover, this redundancy may aid in accurately diagnosing problems with the wellbore equipment, such as the gauge mandrels  208   a - c , the flow control devices  134   a - c , etc. In other embodiments, the surveillance line  119  may also include a hydraulic line configured to provide a conduit for deploying additional fiber optic fibers or electrical lines. 
     Those skilled in the art will readily recognize the several advantages afforded by instrumenting the wellbore  102  both external and internal to the outer completion string  101 . For example, the flow of the fracturing fluid injected into each formation zone  104   a - c  may be monitored by the surveillance line  119 , thereby determining where it is located. This may be determined by temperature changes in the fluids within the annuli  130   a - c , as measured by one or more distributed temperature sensors (not shown) associated with the surveillance line  119 . In other embodiments, the sensors and/or gauges associated with the surveillance line  119  may also be configured to monitor each annulus  130   a - c  for water break through or zonal depletion. 
     The monitoring capabilities provided by the surveillance line  119  may be used in conjunction with the sensors  216  arranged inside the outer completion string  101 . For example, the sensors  216  and the various sensors/gauges associated with the surveillance line  119  may be configured to monitor pressure and temperature differentials between the sand face and the interior of the outer completion string  101 . Such data may allow an operator to determine areas along the wellbore  102  where collapse or water break through has occurred, or when a formation zone  104   a - c  may be nearing zonal depletion. Pressure drops may be measured and reported through the gravel pack of each annulus  130   a - c  and/or through the filtration of each sand screen  124   a - c . The pressure drop, for instance, may be monitored long term to determine or map any significant changes. An increased pressure drop may be indicative of a general decline in production, thereby allowing the operator to proactively treat the formation zone(s)  104   a - c  via, for example, an acid treatment or other simulation configured to improve production rates. 
     In some embodiments, the flow path of production fluids through the sand screens  124   a - c  to the respective flow control device  134   a - c  (i.e., flow control device) may be traced by monitoring the pressure and/or temperature external and internal to the outer completion string  101 . To accomplish this, the production from a particular formation zone  104   a - c  may be shut off, then slowly restarted. Monitoring the gauges associated with the surveillance line  119  and the sensors  216  arranged inside the outer completion string  101  may be useful in demonstrating the flow path through the gravel pack of each annulus  130   a - c.    
     Isolating and measuring fluid properties from each formation zone  104   a - c  may also reveal fluid flow between adjacent zones  104   a - c  and leak detection in various equipment associated with the system  100 . If a leak is detected, diagnostics can be run to determine exactly where the leak is occurring. 
     As will be appreciated, such measurements may prove highly advantageous in intelligently producing the hydrocarbons from each formation zone  104   a - c . For instance, by knowing production rates and other environmental parameters associated with each formation zone  104   a - c , an operator may be able to adjust fluid flow rates through each sand screen  124   a - c  using the respective control and data acquisition modules  208   a - c . As a result, the formation zones  104   a - c  may be more efficiently produced, in order to maximize production and save time. Moreover, by continually monitoring the environmental parameters of each formation zone  104   a - c , the operator may be able to determine when a problem has resulted, such as formation collapse, water break through, or zonal depletion, thereby being able to proactively manage production and save costs. 
     Another significant advantage provided by the system  100  is the ability to disconnect the insert string  202  from the outer completion string  101  and retrieve it to the surface without having to remove the outer completion string  101  from the wellbore  102 . For instance, in the event a portion of the insert string  202  fails, such as a gauge control and data acquisition module  208   a - c  or associated sensor  216 , the conveyance mechanism used to initially run the insert string  202  into the wellbore  102  can once again be attached to the insert string  202  and pull it back to the surface. Once at the surface, the failed or faulty devices located on the insert string  202  may be rebuilt, replaced, or upgraded. In other cases, the problems associated with the insert string  202  may be investigated such that improvements to the insert string  202  may be undertaken. The repaired or upgraded insert string  202  may then be reintroduced into the wellbore  102  and communicably coupled once again to the system  100  at the crossover coupling  114 , as generally described above. In the interim, the circulating sleeves and flow control devices  122   a - c ,  134   a - c  may be closed, thereby preventing inadvertent flow into the production tubular  103 . 
     Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.