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CROSS REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims priority to U.S. Provisional Patent Application No. 61/358,331, filed Jun. 24, 2010. 
     
    
     FIELD OF THE INVENTION 
       [0002]    The invention is directed to apparatus, systems and methods for remotely actuating equipment in a wellbore. 
       BACKGROUND 
       [0003]    In the production of oil and gas, recently drilled deep wells reach as much as 25,000 or even 30,000 feet or more below the ground or subsea surface. Offshore wells may be drilled in water with a depth of as much as 10,000 feet or more. The total depth from offshore platform to the bottom of the wellbore can be as much as eight miles. Such extraordinary distances in modern well construction cause significant challenges in equipment, drilling and servicing procedures. 
         [0004]    Tubular strings are introduced into a well in different ways. A wellbore service string may require many days to make a “trip” into a wellbore, which may be due in part to the time consuming practice of making and breaking pipe joints. The time required to assemble and deploy any service tool assembly downhole for such a long distance is very time consuming and costly. In well service operations, saving time and steps is very important, because the cost per hour to operate a drilling or production rig is very expensive. Each trip into the wellbore adds expense. and increases the possibility that tools may become lost in the wellbore requiring still further operations for their retrieval. 
         [0005]    Various companies offer enhanced so-called “single trip” multizone systems that are designed to enable the fracturing and/or gravel packing of multiple oil producing zones. Such systems, including the ESTMZ™ system marketed by Halliburton Energy Services of Dallas, Tex. are directed at minimizing the number of rig days required to complete conventional fracture and gravel packing operations in multiple pay zones. By “single trip”, it is meant that the service of fracturing or gravel packing multiple zones may be performed in some instances using one trip into the wellbore for such operations. The systems allow an operator to fracture and gravel pack wells without making multiple “trips” into the well for each fracturing or gravel packing operation. 
         [0006]    However, once the fracturing operations are complete, and the fracturing fluid has been pumped through the service tool into the formation in multiple zones, it is customary to proceed into the wellbore once more (another time or trip) using an isolation string carrying a mechanical shifting tool. Such a shifting tool is employed to open mechanical sliding sleeves that were closed during the fracturing operations, thereby allowing production of formation fluids into the wellbore. 
         [0007]    Another commercially available system is known as ComPlete™ MST multizone system marketed by BJ Services Company of Houston, Tex. This system isolates and then fractures individual zones in a multizone well using a mechanical assembly. It is common for such mechanical assembly systems to have a total length of 1,000 feet or more. Then, after the zones are isolated and treated with this lengthy assembly, using one trip, it is common to run another trip into the well employing an upper production string or “inner” string. This additional step typically requires running back into the well to open production sleeves with mechanical shifting tools, thereby allowing formation fluids to flow into the wellbore. 
         [0008]    In many deep wells offshore, the amount of time needed to run an additional string down the wellbore following a fracturing event, to close production sleeves and facilitate production may be very significant. For example, it is not unusual for such a trip procedure to require as much as 10-30 hours of time on a drilling rig. On some offshore rigs, the calculated daily cost of “rig time” can be as much as one million dollars per day, or more. Thus, the cost measured in time of a single trip may be very large. 
         [0009]    Mechanical shifting tools contact and mechanically shift production sleeves to facilitate production of formation fluids into the wellbore. Unfortunately, in soft rock formations, significant losses of completion fluids of as much as 300 barrels of completion fluids per hour may be experienced once the first screen or sleeve is opened. These losses may occur into the subterranean formation. Drilling rigs are limited in the quantity of completion brine carried on the rig. Large losses of brine to the formation may lead to the necessity to use viscous pills or other means to reduce such losses. Viscous pills may cause formation damage, especially if they are used subsequent to fracturing operations. 
         [0010]    A continuing challenge in the industry is to develop and complete multi-zone wells using the least amount of rig time and the least amount of trips into the wellbore. Furthermore, it is a challenge to conduct wellbore operations while reducing losses of completion fluid to the formation. This invention is directed to improvements in apparatus and methods for conducting such operations. 
       BRIEF SUMMARY OF THE INVENTION 
       [0011]    An apparatus and method is disclosed for remotely operating a downhole tool within a wellbore. The wellbore extends from a ground or subsea surface downward into the earth. The apparatus may comprise a downhole tool having a production assembly with at least one sleeve adapted for movement from a first sleeve position facilitating entry of formation fluids past the sleeve into the wellbore to a second sleeve position that retards entry of formation fluids. The downhole tool may be provided with an internal cavity adapted for passage of wellbore fluids under elevated pressure. The downhole tool may be operated in connection with tubular screens or sand screens provided with annular concentric flowpaths separating the fluid from the internal cavity. Further, there may be a separation between the concentric space within the downhole tool and the production sleeve having an external shroud. 
         [0012]    The apparatus may include a sensor configured to measure a value as a function of time. In some embodiments, this value(s) transmitted comprises fluid pressure as a function of time, in which the sensor is a pressure sensor configured to receive pressure pulses and generate electrical signals correlated to the value of such pressure pulses. In other embodiments, the sensor may be an electromagnetic sensor adapted to sense electromagnetic signals, and then generate electrical signals. In either of such embodiments, a control module may be adapted for receiving and analyzing electrical signals received by the control module from the sensor. The control module may include operating instructions representing predetermined parameters, and may be configured to receive from the sensor signals corresponding to transmitted values. A control module is capable of comparing such values to predetermined parameters so that when such values exceed predetermined parameters the control module sends action signals. 
         [0013]    A motor is configured to receive action signals sent from the control module. A motor may be adapted for applying direct or indirect force to open or close a sleeve of a production assembly to alter the flow path of formation fluids through the sleeve. For example, following fracturing one or more producing zones, it may be desirable to open the sleeve of a production assembly to facilitate the flow of formation fluids beyond the sleeve into the production assembly. 
         [0014]    In one embodiment of the invention, a hydraulic system may be connected to a motor. The hydraulic system may include a pump configured for applying hydraulic forces to control lines. Control lines may be operatively engaged, directly or indirectly, to the sleeve of the production assembly. Upon activation of control lines, it is possible to open or close the sleeve, thereby altering flow path of formation fluids. The sleeve may be opened or closed several times as required by deployment or production operations. 
     
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         [0015]    The invention may be observed by reference to one or more Figures as follows. 
           [0016]      FIG. 1  shows a schematic of a configuration of the invention; 
           [0017]      FIG. 2A  shows a cross-sectional view of a first embodiment of the invention using a direct drive from a motor to a sleeve, with the sleeve in the closed position; 
           [0018]      FIG. 2B  shows a cross-sectional view of the first embodiment of the invention with the sleeve in the open position, after activation of the direct drive to open the sleeve, thereby allowing formation fluids to flow into the apparatus; 
           [0019]      FIG. 3  is a flowchart schematic of a second configuration of the invention which employs a hydraulic system for control of sleeve position; 
           [0020]      FIG. 4A  shows a cross-sectional view of the second embodiment of the invention with the sleeve in the closed position; 
           [0021]      FIG. 4B  illustrates a cross-sectional view the second embodiment of the invention after the sleeve is opened by activation of the hydraulic system; 
           [0022]      FIG. 4C  shows a cross-sectional view of the apparatus of  FIGS. 4A-4B , taken along lines  4 C- 4 C shown in  FIG. 4B , revealing one possible arrangement of components; 
           [0023]      FIG. 5  illustrates in a flow diagram the control of the second embodiment of the invention, wherein an action signal may be generated to cause a hydraulic system to move the production sleeve; and 
           [0024]      FIG. 6  is a graph showing pressure versus time for pressure pulses employed in connection with the invention, wherein a sensed pressure is compared to a predetermined pressure condition to determine if action signals should be sent to move the sleeve from a closed position to an open position. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0025]    As indicated, a sensor may be employed to receive signals in the practice of the invention. These signals are not random, but instead are deliberate and designed to be of a format (intensity and time) that would not occur under normal conditions. Thus, a signal generating device may be employed and positioned remotely from the sensor. The signal generating device (such as a pump, electromagnetic generating apparatus or other similar device) may be configured to create signals. Such signals may represent, in some cases, pressure pulses in fluids passing through or along the internal cavity from a point adjacent the ground or subsea surface to a lower position downhole. In other embodiments, the signal generating device may be configured to produce electromagnetic signals. Such signals typically will be created for predetermined intensity and time values. Such values are chosen to avoid intensity and time values that would be seen in normal operation, to avoid an inadvertent trigger of the apparatus. 
         [0026]    In the practice of the invention, the signal generating device could be a commercially manufactured pump, as would be used in oilfield service industry for fluid pumping applications. In other embodiments, the signal generating device may be an electromagnetic signal generating device. 
         [0027]    A battery may be configured for supplying power to the sensor, the control module and/or the motor. The apparatus may be configured for deployment in connection with a multi-zone wellbore completion system having a number of screen assemblies. A shroud is provided, the shroud being configured as a conduit for flow of formation fluids among or between a number of screen assemblies. 
         [0028]    In other embodiments of the invention which employ pressure pulses, such embodiments may employ a second or additional pressure sensor wherein the second pressure sensor is positioned near or opposite the first pressure sensor, and can be used to determine the difference in pressure between the two sensors. The additional pressure sensor may be configured to receive pressure pulses and generate signals to the control module. The additional pressure sensor may be configured to measure changes in pressure due to frictional pressure drop generated by turbulent flow. The control module may be configured to evaluate the difference between pressure signals measured at both pressure sensors when more than one such sensor is employed. 
         [0029]    In another aspect of the invention, a first temperature sensor may be positioned below the ground or subsea surface. The first temperature sensor may be configured to measure temperature, and the control module may include instructions representing predetermined temperature parameters. These temperature parameters may be pre-loaded into the control module and selected for a particular well servicing event. The control module may be configured to refrain from sending action signals so long as the temperature measured at the first temperature sensor is below a predetermined minimum temperature parameter. In this manner, the chances of accidental or inadvertent sending of action signals may be minimized by combining temperature and pressure measurements. 
         [0030]    The invention also may be described as a method for remotely controlling the production flow path of formation fluids through the sleeve of a production assembly in a fluid-containing wellbore. The method may include the step of generating signals for transmission in a wellbore, such that the signals travel downhole from a point near the ground or subsea surface. The signals may be pressure pulses and may have certain defined and predetermined intensity and time values. The pressure pulses may propagate from a position near the ground or subsea surface through the fluid and into a cavity within the wellbore to a production assembly positioned downhole. In other applications, the signals may be electromagnetic signals. 
         [0031]    It is desirable in certain applications of the invention to activate a pressure sensor, the sensor being configured to measure fluid pressure variations as a function of time. The pressure sensor may be adapted to receive pressure pulses and then generate in response electrical signals correlated to the value of received pressure pulses. 
         [0032]    A control module may detect electrical signals from the pressure sensor. The control module may be adapted for receiving signals from the pressure sensor. The control module may be pre-loaded with operating instructions having predetermined pressure and temperature parameters chosen by an operator for a particular well or well configuration. The control module may be configured to receive from the pressure sensor electrical signals corresponding to pressure pulse values. 
         [0033]    The control module may be configured to compare received pressure pulse values to predetermined parameters to determine if the measured pressure pulse values exceed predetermined parameters. If the values exceed or meet predetermined parameters, action signals may be sent to a motor. Then, it may be useful to manipulate the sleeve of a production assembly to alter the flow of formation fluids beyond the sleeve and into the wellbore, allowing production of formation fluids to commence. 
         [0034]    The motor may be connected to the sleeve of the production assembly. In some applications, a hydraulic system may be connected to the motor. The hydraulic system may be configured with a pump to receive forces from the motor. The hydraulic system may include as well hydraulic control lines that are capable of applying force to the sleeve of a production assembly. In many cases, a sleeve will be opened using the hydraulic system to facilitate flow of formation fluids beyond the sleeve and into the production assembly. The method may be performed following the fracturing (i.e. stimulation) of one or more zones of the formation. The method in some cases may be performed following gravel packing operations or other operations, including for example squeeze and circulating procedures and real time annulus monitoring operations. 
         [0035]    In one embodiment of the invention, a control module may be used to control a hydraulic tool. The hydraulic system may include control lines for providing forces to the sleeve. A pump may drive hydraulic fluid along a circuit, the pump being controlled by electronic signals from a control module. The control module may be programmed to respond to a specific trigger, such as a pressure pulse, or a signal representing a temperature measurement, or an electromagnetic signal, or any of these types of signals. This may be accomplished with or without control lines, depending upon the configuration. 
         [0036]    In one specific embodiment, the system may respond to a pre-defined pressure pulse generated at the surface for a pre-defined period of time. In such a case, it is advantageous to choose a pressure pulse that would be highly unlikely to be produced during normal operations to avoid inadvertent triggering of the motor by the control module. Pressures applied outside of the predetermined values and time intervals may be ignored, allowing unlimited pressure points to be applied downhole without activating the apparatus. The control module may be configured to distinguish its own commands from naturally occurring applied pressures or pressure pulses generated by the gravel pack or fracturing operations. Once a trigger has been detected and executed, the apparatus is capable of reset to wait for another trigger to initiate the next task. 
         [0037]    It is anticipated that the control module could be applied to essentially any hydraulically operated tool. The system facilitates remote and wireless communication with a downhole production assembly. In some applications, the energy storage capacity, or battery life, may limit the amount of time that the apparatus is capable of responding, but in the practice of the invention a battery configuration may be chosen that will develop sufficient power for a sufficient length of time to achieve the advantages of the invention. The invention may be coupled with downhole power generation sources to recharge the battery or directly power the control module, sensors and motor/pump assembly. Downhole power may be generated from the surface and transmitted by various means available (i.e. fluid, tubing, control line). Energy available downhole can be used to drive an in situ power generation system in some embodiments of the invention. 
         [0038]    Referring now to the Figures,  FIG. 1  shows a basic operational configuration of a first embodiment of the invention wherein a signal generating device  10  positioned remotely from the sensor creates pressure pulses for transmission through a fluid in the wellbore. The pressure pulse comprising fluid signal  12  is propagated downhole to a location where it may be received by one or more pressure sensor(s)  14 . A control module  18  interacts with the pressure sensor(s)  14  under power of battery  16 . The control module  18  communicates with motor  20  which under the direction of the control module  18  and is capable of imparting movement to sleeve  22 . 
         [0039]      FIG. 2A  illustrates a cross sectional view of a first embodiment of the invention in which motion of the sleeve  22  is created by action of motor  20 . In a subterranean formation  28 , an apparatus  27  is oriented longitudinally in a wellbore  36 . The orientation of the wellbore  36  may be seen by the downhole end  31  which is oriented towards the earth. An uphole end  29  is oriented towards the upper portion of the wellbore  36  towards the ground or subsea surface. Perforation tunnels  30 , which are made in a manner known to those having skill in the art, may be seen extending from proppant pack  34  through the casing  33  and cement  32  and into the subterranean formation  28 . The apparatus  27  comprises an outer shroud  38  around the periphery of the apparatus  27 , which provides the limiting margin to outer annulus  40  of the apparatus  27 . Central fluid cavity  42  carries a pressure pulse or pressure signal from uphole end  29  towards downhole end  31 . 
         [0040]    In  FIG. 2A , the motor  20  receives signals from the control module (not shown in  FIG. 2A ). The control module receives the pressure pulse values actually received by sensor  14 , and compares such pressure pulse values to predetermined parameters such that when the pressure pulse values exceed predetermined parameters the control module is capable of sending action signals. The motor  20  receives such action signals, and turns shaft  50  using power from battery  16 . The motor  20  turns threaded member  51 . The rotation of shaft  50  produces a linear motion of member  51  and sleeve  22 . Member  51  is fixed within or is part of sleeve  22 . Sleeve  22  is typically constrained against rotation. This movement of member  51  causes linear movement of sleeve  22  relative to mandrel  54 . Mandrel  54  additionally comprises ports  58   a ,  58   b  which in  FIG. 2A  are not aligned for fluid communication with apertures  60   a ,  60   b , hence the sleeve  22  of apparatus  27  is in the closed position, which does not allow formation fluids to pass into apparatus  27 . Additionally, screen connection  56  mates with mandrel  54 , and is shown in  FIG. 2A . 
         [0041]      FIG. 2B  shows the first embodiment of the invention of  FIG. 2A  at a later point in time, wherein the ports  58   a ,  58   b  are in communication (alignment) with apertures  60   a ,  60   b . hence the sleeve  22  of apparatus  27  is in the open position, facilitating the passage of formation fluids into apparatus  27 . The first embodiment could also be employed by using a variety of pressure and temperature signals to partially open and close the sleeve  22  of the apparatus  27 . Apertures  60   a ,  60   b  would be replaced by a series of holes of increasing diameter allowing the area open to flow to be progressively increasing between cavity  42  and annulus  40  as a function of the amount of travel of sleeve  22 . 
         [0042]    A second embodiment of the invention is illustrated schematically in  FIG. 3 . In this embodiment, the motor  66  comprises part of a hydraulic system  67 . The motor  66 , when instructed to do so by the control module (not shown in  FIG. 3 ), activates a pump  68 . Pump  68  receives hydraulic oil from oil reservoir  72 , and generates hydraulic force upon control lines  69 , which in turn drives one or more piston(s)  70 . Then, piston(s)  70  acts to move the sleeve  71 . In most embodiments, the piston  70  would act to open the sleeve  71  allowing for passage of formation fluids, but in other embodiments the piston  70  could act to close the sleeve  71  if it was desirable to do so. 
         [0043]    The second embodiment of the invention is illustrated by  FIG. 4A  as well, in cross-sectional view. In  FIG. 4A , an apparatus  75  is in the closed position, with sleeve  106  closed. Outer annulus  112  is seen inside of the shroud  88 . In this embodiment, the downhole end  76  of subterranean formation  80  is shown at the bottom of  FIG. 4A , while the uphole end  77  is seen at the top of  FIG. 4A . Perforation tunnels  82  are shown and extend through casing  84  and laterally from proppant pack  86 , beyond cement  85  into the subterranean formation  80 . The proppant pack  86  is located on the outside of the apparatus  75 , just inside the easing  84  which is inside of the cement  85 . Central fluid cavity  92  carries fluid, which may communicate pressure pulses, to pressure sensor  102 . Sleeve  106  is in the closed position in  FIG. 4A . Apertures  96   a ,  96   b  can be seen in  FIG. 4A  out of alignment with ports  94   a ,  94   b  of mandrel  110  indicating that the sleeve  106  of apparatus  75  retards the flow of formation fluids into apparatus  75 . A battery/motor/pump assembly  108  receives signals along electric cable  100 , and transmits signals along first control line  98  to a control module (not shown in FIGS.  4 A/ 4 B). A screen connection  90  mates with mandrel  110 . 
         [0044]    Pressure sensor  102  ( FIG. 5 ) detects fluid pressure as a function of time, and is configured to receive pressure pulses from a signal generating device (not shown) which is located towards the uphole end  77  well beyond the apparatus  75  ( FIG. 4B ). The sensor  102  generates electrical signals correlated to the value of such pressure pulses that are received by the sensor  102 , and sensor  102  passes signals to electric cable  100  and to the battery/motor/pump assembly  108 . The hydraulic system  126  is discussed herein with reference to  FIG. 5 , and also  FIGS. 4A ,  4 B and  4 C. The hydraulic system  126  is comprised of battery/motor/pump assembly  108  and may be activated when the control module interface  117  determines that the comparison  120  of pressure pulse or signal values received by the sensor  102  meet or exceed predetermined parameters. In that instance, the difference  122  corresponds to action signals  124  are sent to motor  118  of the battery/motor/pump assembly  108 . Sleeve  106  is driven (moved) by the application of hydraulic system  126  through control line  98  relative to the mandrel  110  to a position wherein the aperture  96   a  is moved by linear force into alignment with port  94   a  as illustrated by  FIG. 4B . Likewise, aperture  96   b  is moved into alignment with port  94   b , as shown in  FIG. 4B . The apparatus  75  can be configured to generate a movement of relative rotation between mandrel  110  and sleeve  106  to linearly move apertures  96   a  and  96   b  in alignment with apertures  94   a  and  94   b  respectively. Mandrel  110  and sleeve  106  may be configured with more than two ports and two apertures respectively, depending upon the specific configuration. 
         [0045]      FIG. 4C  shows a cross-sectional view of the apparatus  75  taken along line  4 C- 4 C of  FIG. 4B . In this cross-sectional view, the battery/motor/pump assembly  108  is shown in more detail, comprising battery  116 , control module  117 , and motor/pump  118 , each being securely attached and held in place upon mandrel  110 . Shroud  88  forms the periphery of outer annulus  112 . Shroud  88  is attached to mandrel  110  in a way that provides mechanical locking between the two parts and allows for the transmission of torque and axial force from one to the other. Shroud  88  may be mounted in a way that is permanent or temporary. In  FIG. 4C , sleeve  106  is shown in position on the inner periphery of mandrel  110 . The sleeve  106  achieves motion relative to mandrel  110  by linear translation in the second embodiment of the invention. However, it should be recognized by one of skill in the art that similar mechanical configurations could be constructed in which a sleeve of different shape could be moved by shifting, sliding, hinging, or some other mechanical means of achieving closure. The shroud  88  and mandrel  110  are locked together in the embodiment of  FIGS. 4A-4C  to transmit rotational torque from the shroud  88  to the mandrel  110  in order to make up the connection between apparatus  75  and the screen connection  90 . Shroud  88  and mandrel  110  may be locked permanently or temporarily. The shroud  88  may be configured as a conduit for flow of formation fluids among a plurality of production assemblies. The shroud  88  may be configured to be lockable in rotation with the mandrel  110 . 
         [0046]    Further, as shown in  FIG. 4C , there may be three or more ribs  115   a - c  positioned at approximately 120 degrees of each other. Other means of locking shroud  88  to mandrel  110  could be used.  FIG. 5  illustrates the sequence of events that move the sleeve  106  relative to the mandrel  110 . When pressure sensor  102  measures pressure, it transmits a signal to the control module interface  117 . The control module interface  117  then determines in step  120  if the pressure at the sensor meets or exceeds predetermined pressure parameters. If the pressure measurement and duration of the pressure step predetermined parameters then it sends an action signal  124  to the motor/pump  118 . The motor/pump  118  acts in concert with the hydraulic system to move the sleeve  106  by linear translation or rotation into position to allow formation fluids to pass beyond the sleeve  106  and into the internal cavity  92  of apparatus  75 , as discussed herein. 
         [0047]      FIGS. 5-6  show the manner in which the pressure of a pressure pulse traveling downhole may vary as a function of time. A signal generating device (not shown) may generate pressure pulses of a certain pressure for a certain length of time, in a predetermined series. A comparison is made of the pressure at the sensor to predetermined values in step  120 . If that pressure difference exceeds predetermined parameters, an action signal  124  may be sent to the motor  118 , as shown in step  122  of  FIG. 5 . The motor  118  is under the direction of hydraulic system  126 . When there is no match to predetermined values, the sleeve  106  remains closed. But, when a match occurs to a predetermined value, then the sleeve  106  is opened as described herein, under the direction of control module interface  117 . Control module interface  117  may be configured to open or close sleeve  106  several times to provide downhole flow control capability during well production.  FIG. 6  shows graphically the pressure and time variables that may be observed according to the steps of  FIG. 5 . 
         [0048]    For purposes of this invention, it is believed that a battery of about 7 to about 22 volts can be used as a source of power, for either the first or second described embodiments. The pump may be chosen to deliver in the range about 5,000 psi of pumping force, but less or more force could be deployed, for example about 3000 to about 10,000 psi, depending upon the configuration. 
         [0049]    An additional pressure sensor could be positioned on mandrel  110  on the opposite end to the first sensor  100 . A second sensor could measure pressure and/or temperature inside annular space  112 . A third sensor could be positioned on the same end of mandrel  110  as the first sensor  102 , but measuring pressure and temperature inside annular space  112 . The difference in pressure between the second and third pressure sensors could provide an indication of the rate of production whether or not the frictional loss in annular space  112  is such that sleeve  106  should be opened. It is assumed that apparatus  75  would have remained closed by choice. Further sensor arrangements could be designed as to detect water production and shut off flow from annulus  112  into cavity  92  ( FIG. 4C ). 
         [0050]    In another embodiment of the invention (not specifically illustrated in the Figures), the control module could be physically separated a considerable distance from the production sleeves. The control module could be provided having one or several pressure and temperature sensors, an electric motor, and a hydraulic pump connected to one or more hydraulic control lines. The control module could be located above the modular screens (uphole) and quite some distance away from the screens. In such an embodiment, the control module could be connected to the multiple production sleeves by hydraulic control lines running along the screens inside cavities provided for this purpose, for a considerable distance along the apparatus. The control lines would be capable of transmitting hydraulic power to multiple production sleeves adjacent to multiple producing zones of a formation to shift them open or closed, as required. Thus, the invention could find application in production assemblies designed for many producing zones in a formation. 
         [0051]    This disclosure and description of the invention are illustrative, and various changes in the method of deployment of the apparatus of the invention may be employed without departing from the spirit and scope of the invention. By way of example, the signal generating device described herein could be an electromagnetic signal generator that is used with corresponding receivers (such as electromagnetic sensors) to achieve the purpose or advantages of the invention. In one such embodiment, a wireless data communications system could be employed either as one way or bi-directional, and this could be accomplished using a wireless transmission method, including for example acoustic waves, acoustic stress waves, electrical, electromechanical force, electromagnetic force (“EMF”), optical or other means.

Summary:
An apparatus and method is disclosed for remotely operating a downhole tool within a wellbore. The wellbore extends from a ground or subsea surface downward into the earth. The apparatus includes a tool having a production assembly with at least one sleeve adapted for movement from a first sleeve position facilitating entry of formation fluids past the sleeve into the wellbore to a second sleeve position that retards entry of formation fluids. The downhole tool may be configured to resume production following fracturing, gravel packing or other operations without the need for additional trips into the well for the purpose of opening production sleeves. A fluid pressure pulse or electromagnetic signal or other signal may be delivered downhole for remote mechanical actuation of the apparatus.