Apparatus and Method For Remote Actuation of A Downhole Assembly

Abstract

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.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No. 61/358,331, filed Jun. 24, 2010.

FIELD OF THE INVENTION

The invention is directed to apparatus, systems and methods for remotely actuating equipment in a wellbore.

BACKGROUND

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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

The invention may be observed by reference to one or more Figures as follows.

FIG. 1 shows a schematic of a configuration of the invention;

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;

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;

FIG. 3 is a flowchart schematic of a second configuration of the invention which employs a hydraulic system for control of sleeve position;

FIG. 4A shows a cross-sectional view of the second embodiment of the invention with the sleeve in the closed position;

FIG. 4B illustrates a cross-sectional view the second embodiment of the invention after the sleeve is opened by activation of the hydraulic system;

FIG. 4C shows a cross-sectional view of the apparatus of FIGS. 4A-4B, taken along lines 4C-4C shown in FIG. 4B, revealing one possible arrangement of components;

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 58a, 58b which in FIG. 2A are not aligned for fluid communication with apertures 60a, 60b, 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.

FIG. 2B shows the first embodiment of the invention of FIG. 2A at a later point in time, wherein the ports 58a, 58b are in communication (alignment) with apertures 60a, 60b. 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 60a, 60b 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.

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.

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 96a, 96b can be seen in FIG. 4A out of alignment with ports 94a, 94b 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. 4A/4B). A screen connection 90 mates with mandrel 110.

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, 4B and 4C. 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 96a is moved by linear force into alignment with port 94a as illustrated by FIG. 4B. Likewise, aperture 96b is moved into alignment with port 94b, 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 96a and 96b in alignment with apertures 94a and 94b respectively. Mandrel 110 and sleeve 106 may be configured with more than two ports and two apertures respectively, depending upon the specific configuration.

FIG. 4C shows a cross-sectional view of the apparatus 75 taken along line 4C-4C 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.

Further, as shown in FIG. 4C, there may be three or more ribs 115a-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.

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.

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.

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).

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.

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.

Claims

1. An apparatus for remotely operating a downhole tool within a wellbore, the wellbore extending from a ground or subsea surface downward into the earth, the downhole tool comprising a production assembly having at least one sleeve adapted for movement from a first closed position blocking entry of formation fluids past the sleeve and into the wellbore to a second open position that allows entry of formation fluids, the downhole tool having an internal cavity, the internal cavity being adapted for passage of wellbore fluids, the apparatus comprising:

(a) a sensor, the sensor being configured to receive transmitted signals and then generate electrical signals responsive to the value of such transmitted signals;

(b) a control module, the control module being adapted for receiving electrical signals from the sensor, the control module further comprising operating instructions representing predetermined parameters, the control module being configured to receive from the sensor signals corresponding to values and to compare such values to predetermined parameters such that when received values exceed predetermined parameters the control module is capable of sending action signals in response; and

(c) a motor configured to receive such action signals from the control module, the motor being adapted for applying force to open or close a sleeve of a production assembly to alter the flow path of formation fluids through the sleeve.

2. The apparatus of claim 1 additionally comprising the following:

(d) a hydraulic system connected to the motor, the hydraulic system further comprising a pump, the pump being configured for applying hydraulic force to control lines, the control lines being operatively engaged to a sleeve of the production assembly to open or close the sleeve, thereby altering the flow path of formation fluids.

3. The apparatus of claim 1 further wherein the sensor is a pressure sensor, further wherein the pressure sensor is adapted for receiving pressure pulse signals, further comprising a signal generating device positioned remotely from the pressure sensor, the signal generating device being configured to create pressure pulses in a fluid passing through the internal cavity, the pressure pulses having predetermined intensity and time values.

4. The apparatus of claim 1 further comprising a battery configured for supplying power to at least one of the following: sensor, control module, motor.

5. The apparatus of claim 1 configured for deployment in connection with a multi-zone wellbore completion system having a plurality of production assemblies.

6. The apparatus of claim 1 further comprising a shroud and mandrel, the shroud being configured as a conduit for flow of formation fluids among a plurality of production assemblies, further wherein the shroud is configured to be lockable in rotation with the mandrel.

7. The apparatus of claim 3 further comprising an additional pressure sensor, wherein the additional pressure sensor is positioned downhole, the additional pressure sensor being configured for measuring changes in pressure due to pressure drop generated by turbulent flow.

8. The apparatus of claim 1 wherein the apparatus further comprises a first temperature sensor positioned below the ground or subsea surface, the first temperature sensor being configured to measure temperature, further wherein the control module comprises instructions representing predetermined temperature parameters.

9. The apparatus of claim 8 wherein the control module comprises instructions to refrain from sending action signals when the temperature measured by said first temperature sensor is below a predetermined minimum temperature parameter.

10. The apparatus of claim 1 wherein the sensor comprises an electromagnetic sensor.

11. 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 wellbore extending from a ground or subsea surface downhole into a subterranean formation, the subterranean formation having at least one producing zone, the method of the invention comprising the steps of:

(a) activating a sensor, the sensor being adapted to receive transmitted signals and generate in response electrical signals correlated to the value of received transmitted signals;

(b) detecting with a control module electrical signals from the sensor, the control module being adapted for receiving signals from the sensor, the control module further comprising operating instructions having predetermined parameters, the control module being configured to receive from the sensor electrical signals;

(c) comparing received signal values to predetermined parameters to determine if measured signal values exceed predetermined parameters, thereby triggering the production of action signals;

(d) sending action signals to a motor, the motor being configured to receive action signals and apply forces which operate on the sleeve in response, and

(e) manipulating the sleeve of the production assembly to alter the flow of formation fluids.

12. The method of claim 11 wherein a pumping apparatus generates such transmitted signals in the form of pressure pulses in the fluid within the wellbore, such pressure pulses having certain defined and predetermined intensity and time values, the pulses propagating 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.

13. The method of claim 11, wherein the motor is operably connected to the sleeve of the production assembly, wherein the manipulating step further comprises activating a hydraulic system connected to the motor, such hydraulic system being configured with a pump that receives forces from the motor, the hydraulic system having hydraulic control lines capable of applying force to the sleeve of the production assembly.

14. The method of claim 11 wherein the manipulating step comprises opening the sleeve to facilitate the flow of formation fluids beyond the sleeve and into the production assembly.

15. The method of claim 12 wherein, prior to the step of generating pressure pulses, a fracturing fluid is passed through the wellbore and into the subterranean formation, thereby fracturing a first zone of the subterranean formation to form a first fractured zone.

16. The method of claim 15 further including the step of gravel packing the first fractured zone following the fracturing step.

17. The method of claim 11 wherein the sensor comprises an electromagnetic sensor.