Abstract:
A completion apparatus for completing a wellbore includes a tool to alternatively open and close a throughbore; a tool to alternatively open and close an annulus between the outer surface of the completion and the inner surface of the wellbore; a tool to alternatively provide and prevent a fluid circulation route from the throughbore of the completion to the annulus; and at least one signal receiver and processing tool capable of decoding signals received. The apparatus is run into the well bore, the throughbore is closed and the fluid pressure in the tubing is increased to pressure test the completion; the annulus is closed and a fluid circulation route is provided from the throughbore to the annulus and fluid is circulated through the production tubing into the annulus and back to surface. The fluid circulation route is then closed and the throughbore is opened.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is a continuation of U.S. patent application Ser. No. 12/677,660, which entered the national stage under 35 U.S.C. 371 on Mar. 11, 2010. U.S. patent application Ser. No. 12/677,660 is a national-stage filing of PCT/GB2008/050951, filed Oct. 17, 2008. PCT/GB2008/050951 claims priority to GB 0720421.7, filed Oct. 19, 2007. U.S. patent application Ser. No. 12/677,660, PCT/GB2008/050951, and GB 0720421.7 are incorporated herein by reference. 
     
    
     BACKGROUND 
       [0002]    1. Field of the Invention 
         [0003]    The present invention relates to a method of completing a well and also to one or more devices for use downhole and more particularly but not exclusively relates to a substantially interventionless method for completing an oil and gas wellbore with a production tubing string and a completion without requiring intervention equipment such as slick line systems to set downhole tools to install the completion. 
         [0004]    2. History of the Related Art 
         [0005]    Conventionally, as is well known in the art, oil and gas wellbores are drilled in the land surface or subsea surface with a drill bit on the end of a drillstring. The drilled borehole is then lined with a casing string (and more often than not a liner string which hangs off the bottom of the casing string). The casing and liner string if present are cemented into the wellbore and act to stabilise the wellbore and prevent it from collapsing in on itself. 
         [0006]    Thereafter, a further string of tubulars is inserted into the cased wellbore, the further string of tubulars being known as the production tubing string having a completion on its lower end. The completion/production string is required for a number of reasons including protecting the casing string from corrosion/abrasion caused by the produced fluids and also for safety and is used to carry the produced hydrocarbons from the production zone up to the surface of the wellbore. 
         [0007]    Conventionally, the completion/production string is run into the cased borehole where the completion/production string includes various completion tools such as:—
       a barrier which may be in the form of a flapper valve or the like;   a packer which can be used to seal the annulus at its location between the outer surface of the completion string and the inner surface of the casing in order to ensure that the produced fluids all flow into the production tubing; and   a circulation sleeve valve used to selectively circulate fluid from out of the throughbore of the production tubing and into the annulus between the production string and the inner surface of the casing string in order to for example flush kill fluids up the annulus and out of the wellbore.       
 
         [0011]    It is known to selectively activate the various completion tools downhole in order to set the completion in the cased wellbore by one of two main methods. Firstly, the operator of the wellbore can use intervention equipment such as tools run into the production tubing on slickline that can be used to set e.g. the barrier, the packer or the circulation sleeve valve. However, such intervention equipment is expensive as an intervention rig is required and there are also a limited number of intervention rigs and also personnel to operate the rigs and so significant delays and costs can be experienced in setting a completion. 
         [0012]    Alternatively, the completion/production string can be run into the cased wellbore with for example electrical cables that run from the various tools up the outside of the production string to the surface such that power and control signals can be run down the cables. However, the cables are complicated to fit to the outside of the production string because they must be securely strapped to the outside of the string and also must pass over the joints between each of the individual production tubulars by means of cable protectors which are expensive and timely to fit. 
         [0013]    Furthermore, it is not unknown for the cables to be damaged as they are run into the wellbore which means that the production tubing must be pulled out of the cased wellbore and further delays and expense are experienced. 
         [0014]    It would therefore be desirable to be able to obviate the requirement for either cables run from the downhole completion up to the surface and also the need for intervention to be able to set the various completion tools. 
       SUMMARY 
       [0015]    According to a first aspect of the present invention there is a completion apparatus for completing a wellbore comprising:—
       a) a tool to alternatively open and close a throughbore of the completion;   b) a tool to alternatively open and close an annulus defined between the outer surface of the completion and the Inner surface of the wellbore;   c) a tool to alternatively provide and prevent a fluid circulation route through a sidewall of the completion from the throughbore of the completion to the said annulus;   d) a signal processing tool capable of decoding signals received relating to the operation of tools a) to c); and   e) a tool comprising a powered actuation mechanism capable of operating tools a) to c) under instruction from tool d).       
 
         [0021]    According to a first aspect of the present invention there is a method of completing a wellbore comprising the steps of:— 
         [0000]    i) running in a completion comprising a plurality of production tubulars and one or more downhole completion tools, the completion tools comprising:—
       a) a means to alternatively open and close a throughbore of the completion;   b) a means to alternatively open and close an annulus defined between the outer surface of the completion and the inner surface of the wellbore;   c) a means to alternatively provide and prevent a fluid circulation route through a sidewall of the completion from the throughbore of the completion to the said annulus;   d) a signal processing means capable of decoding signals received relating to operation of tools a) to c); and   e) a tool comprising a powered actuation mechanism capable of operating tools a) to c) under instruction from tool d);
 
ii) wherein tool d) instructs tool e) to operate tool a) to close the throughbore of the completion;
 
iii) increasing the pressure within the fluid in the tubing to pressure test the completion;
 
iv) wherein tool d) instructs tool e) to operate tool b) to close the said annulus;
 
v) wherein tool d) instructs tool e) to operate tool c) to provide said fluid circulation route such that fluid can be circulated through the production tubing and out into the annulus and back to surface;
 
vi) wherein tool d) instructs tool e) to operate tool c) to prevent the said fluid circulation route; and
 
vii) wherein tool d) instructs tool e) to operate tool a) to open the throughbore of the completion.
       
 
         [0027]    Preferably, tool d) may further comprise at least one signal receiving means capable of receiving signals sent from the surface, said signals being input into the signal processing means and said signals preferably being transmitted from surface without requiring intervention into the completion and without requiring cables to transmit power and signals from surface to the completion and further preferably comprises transmitting data wirelessly and more preferably comprises either or both of:—
       coding a means to carry data at the surface with the signal, introducing the means to carry data into the fluid path such that it flows toward and through at least a portion of the completion such that the signal is received by the said signal receiving means and most preferably the means to carry data comprises an RFID tag; and/or   sending the signal via a change in the pressure of fluid contained within the throughbore of the completion and more preferably comprises sending the signal via a predetermined frequency of changes in the pressure of fluid contained within the throughbore of the completion such that a second signal receiving means detects said signal and typically further comprises verifying that tool b) has been operated to close the said annulus.       
 
         [0030]    Additionally or optionally tool d) may comprise a timed instruction storage means provided with a series of instructions and associated operational timings for instructing tool e) to operate tools a) to c) wherein the method further comprises storing the instructions in the storage means at surface prior to running the completion into the wellbore. 
         [0031]    According to a second aspect of the present invention there is a method of completing a wellbore comprising the steps of:— 
         [0000]    i) running in a completion comprising a plurality of production tubulars and one or more downhole completion tools, the completion tools comprising:—
       a) a means to alternatively open and close a throughbore of the completion;   b) a means to alternatively open and close an annulus defined between the outer surface of the completion and the inner surface of the wellbore; and   c) a means to alternatively provide and prevent a fluid circulation route from the throughbore of the completion to the said annulus; and   d) at least one signal receiver means and a signal processing means;
 
ii) transmitting a signal arranged to be received by at least one of the signal receiver means of tool d) wherein the signal contains an instruction to operate tool a) to close the throughbore of the completion;
 
iii) increasing the pressure within the fluid in the tubing to pressure test the completion;
 
iv) transmitting a signal arranged to be received by at least one of the signal receiver means of tool d) wherein the signal contains an instruction to operate tool b) to close the said annulus;
 
v) transmitting a signal arranged to be received by at least one of the signal receiver means of tool d) wherein the signal contains an instruction to operate tool c) to provide a fluid circulation route from the throughbore of the completion to the said annulus and circulating fluid through the production tubing and out into the annulus and back to surface;
 
vi) transmitting a signal arranged to be received by at least one of the signal receiver means of tool d) wherein the signal contains an instruction to operate tool c) to prevent the fluid circulation route from the throughbore of the completion to the said annulus such that fluid is prevented from circulating; and
 
vii) transmitting a signal arranged to be received by at least one of the signal receiver means of tool d) wherein the signal contains an instruction to operate tool a) to open the throughbore of the completion.
       
 
         [0036]    Preferably, the completion tools of the method according to the second aspect further comprise e) a tool comprising a powered actuation mechanism capable of operating tools a) to c) under instruction from tool d). 
         [0037]    Typically, the production tubulars form a string of production tubulars. Typically, the method relates to completing a cased wellbore, and the apparatus is for completing a cased wellbore. 
         [0038]    Preferably, step ii) further comprises transmitting the signal without requiring intervention into the completion and without requiring cables to transmit power and signals from surface to the completion and further preferably comprises transmitting data wirelessly and more preferably comprises coding a means to carry data at the surface with the signal, introducing the means to carry data into the fluid path such that it flows toward and through at least a portion of the completion such that the signal is received by the said signal receiver means of tool d) and most preferably the means to carry data comprises an RFID tag. 
         [0039]    Preferably step iii) further comprises increasing the pressure within the fluid in the tubing to pressure test the completion by increasing the pressure of fluid at the surface of the well in communication with fluid in the throughbore of the completion above the closed tool a). 
         [0040]    Preferably step iv) further comprises transmitting the signal without requiring intervention into the completion and without requiring cables to transmit power and signals from surface to the completion and further preferably comprises transmitting data wirelessly and more preferably comprises sending the signal via a change in the pressure of fluid contained within the throughbore of the completion and most preferably comprises sending the signal via a predetermined frequency of changes in the pressure of fluid contained within the throughbore of the completion such that a second signal receiving means of tool d) detects said signal and typically further comprises verifying that tool b) has operated to close the said annulus. 
         [0041]    Preferably step v) further comprises transmitting the signal without requiring intervention into the completion and without requiring cables to transmit power and signals from surface to the completion and further preferably comprises transmitting data wirelessly and more preferably comprises sending the signal via a change in the pressure of fluid contained within the throughbore of the completion and most preferably comprises sending the signal via a different predetermined frequency of changes in the pressure of fluid contained within the throughbore of the completion compared to the frequency of step iv) such that the second signal receiving means of tool d) detects said signal and acts to operate tool c) to provide a fluid circulation route from the throughbore of the completion to the said annulus. 
         [0042]    Preferably step vi) further comprises transmitting the signal without requiring intervention into the completion and without requiring cables to transmit power and signals from surface to the completion and further preferably comprises transmitting data wirelessly and more preferably comprises coding a means to carry data at the surface with the signal, introducing the means to carry data into the fluid path such that it flows toward and through at least a portion of the completion such that the signal is received by the said first signal receiver means of tool d) and most preferably the means to carry data comprises an RFID tag. 
         [0043]    Preferably step vii) further comprises transmitting the signal without requiring intervention into the completion and without requiring cables to transmit power and signals from surface to the completion and further preferably comprises transmitting data wirelessly and more preferably comprises sending the signal via a change in the pressure of fluid contained within the throughbore of the completion and most preferably comprises sending the signal via a different predetermined frequency of changes in the pressure of fluid contained within the throughbore of the completion compared to the frequency of steps iv) and v) such that the second signal receiving means of tool d) detects said signal and acts to operate tool a) to open the throughbore of the completion. 
         [0044]    Preferably, tool c) is located, within the production string, closer to the surface of the well than either of tool a) and tool b). 
         [0045]    Typically, tool c) is run into the well in a closed configuration such that fluid cannot flow from the throughbore of the completion to the said annulus via side ports formed in tool c). Typically, tool c) comprises a circulation sub. 
         [0046]    Typically, tool a) is run into the well in an open configuration such that fluid can flow through the throughbore of the completion without being impeded or prevented by tool a). Typically, tool a) comprises a valve which may comprise a ball valve or flapper valve. 
         [0047]    Typically, tool b) is run into the wellbore in an unset configuration such that the annulus is not closed by it during running in and typically, tool b) comprises a packer or the like. 
         [0048]    Preferably, the at least one signal receiving means capable of receiving signals sent from the surface of tool d) comprises an RFID tag receiving coil and the second signal receiving means of tool d) preferably comprises a pressure sensor. 
         [0049]    Preferably, tool d) and e) can be formed in one tool having multiple features and preferably tool e) comprises an electrical power means which may comprise an electrical power storage means in the form of one or more batteries, and tool e) further preferably comprises an electrical motor driven by the batteries that can provide motive power to operate, either directly or indirectly, tools a) to c). Typically, tool e) preferably comprises an electrical motor driven by the batteries to move a piston to provide hydraulic fluid power to operate tools a) to c). 
         [0050]    According to a further aspect of the present invention there is provided a downhole needle valve tool comprising:—
       an electric motor having a rotational output;   an obturating member for obturating a fluid pathway;   wherein the obturating member is rotationally coupled to the rotational output of the electric motor;   and wherein rotation of the obturating member results in axial movement of the obturating member relative to the electric motor and the fluid pathway   such that rotation of the obturating member in one direction results in movement of the obturating member into sealing engagement with the fluid pathway and rotation of the obturating member in the other direction results in movement of the obturating member out of sealing engagement with the fluid pathway.       
 
         [0056]    Preferably, the obturating member comprises a needle member and the fluid pathway comprises a seat into which the needle may be selectively inserted in order to seal the fluid pathway and thereby selectively allow and prevent fluid to flow along the fluid pathway. 
         [0057]    Preferably, the needle valve tool is used to allow for selective energisation of a downhole sealing member, typically with a downhole fluid and piston, and more preferably the downhole sealing member is a packer tool and the downhole fluid is fluid from the throughbore of a completion/production tubing. Alternatively, the packer could be hydraulically set by pressure from a downhole pump tool operated by tool e) of the first aspect or by an independent pressure source. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0058]    Embodiments in accordance with the present invention will now be described by way of example only with reference to the accompanying drawings, in which:— 
           [0059]      FIG. 1  is a schematic overview of a completion in accordance with the present invention having just been run into a cased well; 
           [0060]      FIG. 2  is a schematic overview of the completion tools in accordance with the present invention as shown in  FIG. 1 ; 
           [0061]      FIG. 3  is a further schematic overview of the completion tools of  FIG. 2  showing a simplified hydraulic fluid arrangement; 
           [0062]      FIG. 4  is a sectional view of a downhole device according to the second aspect of the invention; 
           [0063]      FIGS. 5-7  are detailed sectional consecutive views of the device shown in  FIG. 4 ; 
           [0064]      FIG. 8  is a view on section A-A shown in  FIG. 5 ; and 
           [0065]      FIG. 9  is a view on section B-B shown in  FIG. 7 . 
           [0066]      FIG. 10  is a cross-sectional view of a motorised downhole needle valve tool used to operate the packer of  FIGS. 1-3 ; 
           [0067]      FIG. 11  is a schematic representation of a pressure signature detector for use with the present invention; 
           [0068]      FIG. 12  is the actual pressure sensed at the downhole tool in the well fluid of signals applied at surface to downhole fluid in accordance with the method of the present invention; 
           [0069]      FIG. 13  is a graph of the pressure versus time of the well fluid after the pressure has been output from a high pass filter of  FIG. 11  and is representative of the pressure that is delivered to the software in the microprocessor as shown in  FIG. 11 ; 
           [0070]      FIG. 14  is a flow chart of the main decisions made by the software of the pressure signature detector of  FIG. 11 ; and 
           [0071]      FIG. 15  is a graph of pressure versus time showing two peaks as seen and counted by the software within the microprocessor of  FIG. 11 . 
       
    
    
     DETAILED DESCRIPTION 
       [0072]    A production string  3  made up of a number (which could be hundreds) of production tubulars having screw threaded connections is shown with a completion  4  at its lower end in  FIG. 1  where the production tubing string  3  and completion  4  have just been run into a cased well  1 . In order to complete the oil and gas production well such that production of hydrocarbons can commence, the completion  4  needs to be set into the well. 
         [0073]    In accordance with the present invention, the completion  4  comprises a wireless remote control central power unit  9  provided at its upper end with a circulation sleeve sub  11  located next in line vertically below the central power unit  9 . A packer  13  is located immediately below the circulation sleeve sub  11  and a barrier  15 , which may be in the form of a valve such as a ball valve but which is preferably a flapper valve  15 , is located immediately below the packer  13 . Importantly, the circulation sleeve sub  11  is located above the packer  13  and the barrier  15 . 
         [0074]    A control means  9 A,  9 B,  9 C is shown schematically in  FIG. 2  in dotted lines as leading from the wireless remote control central power unit  9  to each of the circulation sleeve sub  11 , packer  13  and barrier  15  where the control means may be in the form of electrical cables, but as will be described subsequently is preferably in the form of a conduit capable of transmitting hydraulic fluid. 
         [0075]    As shown in  FIG. 1  and as is common in the art, there is an annulus  5  defined between the outer circumference of the completion  4 /production string  3  and the inner surface of the cased wellbore  1 . 
         [0076]    In order to safely install the completion  4  in the cased wellbore  1 , the following sequence of events are observed. 
         [0077]    The completion  4  is run into the cased wellbore  1  with the flapper valve  15  in the open configuration, that is with the flapper  15 F not obturating the throughbore  40  such that fluid can flow in the throughbore  40 . Furthermore, the packer  13  is run into the cased wellbore  1  in the unset configuration which means that it is clear of the casing  1  and does not try to obturate the annulus  5  as it is being run in. Additionally, the circulation sleeve sub  11  is run in the closed configuration which means that the apertures  26  (which are formed through the side wall of the circulation sleeve sub  11 ) are closed by a sliding sleeve  100  provided on the inner bore of the circulation sleeve sub  11  as will be described subsequently and thus the apertures  26  are closed such that fluid cannot flow through them and therefore the fluid must flow all the way through the throughbore  40  of the completion  4  and production string  3 . 
         [0078]    An interventionless method of setting the completion  4  in the cased wellbore  1  will now be described in general with a specific detailed description of the main individual tools following subsequently. It will be understood by those skilled in the art that an interventionless method of setting a completion provides many advantages to industry because it means that the completion does not need to be set by running in setting tools on slick line or running the completion into the wellbore with electric power/data cables running all the way up the side of the completion and production string. 
         [0079]    The wireless remote control central power unit  9  will be described in more detail subsequently, but in general comprises (as shown in FIG.  3 ):—
       an RFID tag detector  62  in the form of an antenna  62  and which provides a first means to detect signals sent from the surface (which are coded on to RFID tags at the surface by the operator and then dropped into the well);   a pressure signature detector  150  which can be used to detect peaks in fluid pressure in the completion tubing throughbore  40  (where the pressure peaks are applied at the surface by the operator and are transmitted down the fluid contained within the throughbore  40  and therefore provide a second means for the operator to send signals to the central power unit  9 );   a battery pack  66  which provides all the power requirements to the central power unit  9 ;   an electronics package  67  which has been coded at the surface by the operator with the instructions on which tools  11 ,  13 ,  15  to operate depending upon which signals are received by one of the two receivers  62 ,  150 ;   a first electrical motor and hydraulic pump combination  17  which, when operated, will control the opening or closing of the sleeve  100  of the circulation sleeve sub  11 ;   a motorised downhole needle valve tool  19  (which could well actually form part of the packer  13  and therefore be housed within the packer instead of forming part of and being housed within the central power unit  9 ); and   a second electric motor and hydraulic pump combination  21  which has two hydraulic fluid outlets  21 A,  21 B which are respectively used to provide hydraulic pressure to a first hydraulic chamber  21 U within the fall through flapper  15  and which is arranged to rotate the flapper valve  15  upwards when hydraulic fluid is pumped into the chamber  21 U in order to open the throughbore  40  and a second hydraulic fluid chamber  21 D also located within the fall through flapper  15  and which is arranged to move the flapper down in order to close the throughbore  40  when required.       
 
         [0087]    In general, the completion  4  is set into the cased wellbore  1  by following this sequence of steps:— 
         [0000]    a) the completion  4  is run into the cased hole with the flapper  15  in the open configuration such that the throughbore  40  is open, the circulation sleeve sub  11  is in the closed configuration such that the apertures  26  are closed and the packer  13  is in the unset configuration;
 
b) in order to be able to subsequently pressure test the completion tubing (see step C below) the flapper valve  15  must be closed. This is achieved by inserting an RFID tag into fluid at the surface of the wellbore and which is pumped down through the throughbore  40  of the production string  3  and completion  4 . The RFID tag is coded at the surface with an instruction to tell the central power unit  9  to close the fall through flapper  15 . The RFID detector  62  detects the RFID tag as it passes through the central power unit  9  and the electronic package  67  decodes the signal detected by the antenna  62  as an instruction to close the flapper valve  15 . This results in the electronics package  67  (powered by the battery pack  66 ) instructing the second electric motor plus hydraulic pump combination  21  to pump hydraulic fluid through conduit  21 B into the chamber  21 D which results in closure of the fall through flapper valve  15 ;
 
c) a tubing pressure test is then typically conducted to check the integrity of the production tubing  3  as there could be many hundreds of joints of tubing screwed together to form the production tubing string  3 . The pressure test is conducted by increasing the pressure of the fluid at surface in communication with the fluid contained in the throughbore  40  of the production string  3  and completion  4 ;
 
d) assuming the tubing pressure test is successful, the next stage is to set the packer  13  but because the flapper valve  15  is now closed it would be unreliable to rely on dropping an RFID tag down the production tubing fluid because there is no flow through the fluid and the operator would need to rely on gravity alone which would be very unreliable. Instead, a pressure signature detector  150  is used to sense increases in pressure of the production fluid within the throughbore  40  as will be subsequently described. Accordingly, the operator sends the required predetermined signal in the form of two or more pre-determined pressure pulses sent within a predetermined frequency which when concluded is sensed by the pressure signature detector  150  and is decoded by the electronics package  67  which results in the operation of the motorised downhole needle valve tool  19  (as will be detailed subsequently) to open a conduit between a packing setting chamber  13 P and the throughbore of the production tubing  3  to allow production tubing fluid to enter the packing setting chamber  13 P to inflate the packer. The setting of the packer  13  can be tested in the usual way; that is by increasing the pressure in the annulus at surface to confirm the packer  13  holds the pressure;
 
e) It is important to remove the heavy kill fluids which are located in the production tubing above the packer  13 . This is done by sending a second signal of two or more pre-determined pressure peaks sent within a different predetermined frequency which when concluded is sensed by the pressure signature detector  150  and is decoded by the electronics package  67  as an instruction to open the circulation sleeve sub  11 . Accordingly, the electronics package  67  instructs the first electric motor and hydraulic pump combination  17  to move the sleeve  100  in the required direction to uncover the apertures  26 . Accordingly, circulation fluid such as a brine or diesel can be pumped down the production string  3 , through the throughbore  40 , out of the apertures  26  and back up the annulus  5  to the surface where the heavy kill fluids can be recovered;
 
f) an RFID tag is then coded at surface with the pre-determined instruction to close the circulation sleeve sub  11  and the RFID tag is introduced into the circulation fluid flow path down the throughbore  40 . The RFID detector  62  will detect the signal carried on the coded RFID tag and this is decoded by the electronics package  67  which will instruct the electric motor and hydraulic pump combination  17  to move the circulation sleeve  100  in the opposite direction to the direction it was moved in step e) above such that the apertures  26  are covered up again and sealed and thus the circulation fluid flow path is stopped; and
 
g) the final step in the method of setting the completion is to open the flapper valve  15  and this is done by using a third signal of two or more pre-determined pressure peaks sent within a different predetermined frequency which travels down the static fluid contained in the throughbore  40  such that it is detected by the pressure signature detector  150  and the signal is decoded by the electronics package  67  to operate the electric motor and hydraulic pump combination  21  to pump hydraulic fluid down the conduit  21   a  and into the hydraulic chamber  21   u  which moves the flapper to open the throughbore  40 .
 
         [0088]    The well has now been completed with the completion  4  being set and, provided all other equipment is ready, the hydrocarbons or produced fluids can be allowed to flow from the hydrocarbon reservoir up through the throughbore  40  in the completion  4  and the production tubing string  3  to the surface whenever desired. 
         [0089]    The key completion tools will now be described in detail. 
         [0090]    The central power unit  9  is shown in  FIGS. 4 to 9  as being largely formed in one tool housing along with the circulation sleeve sub  11  where the central power unit  9  is mainly housed within a top sub  46  and a middle sub  56  and the circulation sleeve sub  11  is mainly housed within a bottom sub  96 , each of which comprise a substantially cylindrical hollow body. In this embodiment, the packer  13  and the flapper valve  15  could each be similarly provided with their own respective central power units (not shown), each of which are provided with their own distinct codes for operation. However, an alternative embodiment could utilise one central power unit  9  as shown in detail in  FIGS. 4 to 9  but modified with separate hydraulic conduits leading to the respective tools  11 ,  13 ,  15  as generally shown in  FIGS. 1 to 3 . 
         [0091]    The wireless remote controlled central power unit  9  (shown in  FIGS. 4 to 9 ) has pin ends  44   e  enabling connection with a length of adjacent production tubing or pipe  42 . 
         [0092]    When connected in series for use, the hollow bodies of the top sub  46 , middle sub  56  and bottom sub  96  define a continuous throughbore  40 . 
         [0093]    As shown in  FIG. 5 , the top sub  46  and the middle sub  56  are secured by a threaded pin and box connection  50 . The threaded connection  50  is sealed by an O-ring seal  49  accommodated in an annular groove  48  on an inner surface of the box connection of the top sub  46 . Similarly, the top sub  96  of the circulation sleeve sub  11  and the middle sub  56  of the central control unit  9  are joined by a threaded connection  90  (shown in  FIG. 7 ). 
         [0094]    An inner surface of the middle sub  56  is provided with an annular recess  60  that creates an enlarged bore portion in which an antenna  62  is accommodated co-axial with the middle sub  56 . The antenna  62  itself is cylindrical and has a bore extending longitudinally therethrough. The inner surface of the antenna  62  is flush with an inner surface of the adjacent middle sub  56  so that there is no restriction in the throughbore  40  in the region of the antenna  62 . The antenna  62  comprises an inner liner and a coiled conductor in the form of a length of copper wire that is concentrically wound around the inner liner in a helical coaxial manner. Insulating material separates the coiled conductor from the recessed bore of the middle sub  56  in the radial direction. The liner and insulating material is typically formed from a non-magnetic and non-conductive material such as fibreglass, moulded rubber or the like. The antenna  62  is formed such that the insulating material and coiled conductor are sealed from the outer environment and the throughbore  40 . The antenna  62  is typically in the region of 10 metres or less in length. 
         [0095]    Two substantially cylindrical tubes or bores  58 ,  59  are machined in a sidewall of the middle sub  56  parallel to the longitudinal axis of the middle sub  56 . The longitudinal machined bore  59  accommodates a battery pack  66 . The machined bore  58  houses a motor and gear box  64  and a hydraulic piston assembly shown generally at  60 . Ends of both of the longitudinal bores  58 ,  59  are sealed using a seal assembly  52 ,  53  respectively. The seal assembly  52 ,  53  includes a solid cylindrical plug of material having an annular groove accommodating an O-ring to seal against an inner surface of each machined bore  58 ,  59 . 
         [0096]    An electronics package  67  (but not shown in  FIG. 4 ) is also accommodated in a sidewall of the middle sub  56  and is electrically connected to the antenna  62 , the motor and gear box  64 . The electronics package, the motor and gear box  64  and the antenna  62  are all electrically connected to and powered by the battery pack  66 . 
         [0097]    The motor and gear box  64  when actuated rotationally drive a motor arm  65  which in turn actuates a hydraulic piston assembly  60 . The hydraulic piston assembly  60  comprises a threaded rod  74  coupled to the motor arm  65  via a coupling  68  such that rotation of the motor arm  65  causes a corresponding rotation of the threaded rod  74 . The rod  74  is supported via thrust bearing  70  and extends into a chamber  83  that is approximately twice the length of the threaded rod  74 . The chamber  83  also houses a piston  80  which has a hollowed centre arranged to accommodate the threaded rod  74 . A threaded nut  76  is axially fixed to the piston  80  and rotationally and threadably coupled to the threaded rod  74  such that rotation of the threaded rod  74  causes axial movement of the nut  76  and thus the piston  80 . Outer surfaces of the piston  80  are provided with annular wiper seals  78  at both ends to allow the piston  80  to make a sliding seal against the chamber  83  wall, thereby fluidly isolating the chamber  83  from a second chamber  89  ahead of the piston  80  (on the right hand side of the piston  80  as shown in  FIG. 6 ). The chamber  83  is in communication with a hydraulic fluid line  72  that communicates with a piston chamber  123  (described hereinafter) of the sliding sleeve  100 . The second chamber  89  is in communication with a hydraulic fluid line  88  that communicates with a piston chamber  121  (described hereinafter) of the sliding sleeve  100 . 
         [0098]    A sliding sleeve  100  having an outwardly extending annular piston  120  is sealed against the inner recessed bore of the middle sub  56 . The sleeve  100  is shown in a first closed configuration in  FIGS. 4 to 9  in that apertures  26  are closed by the sliding sleeve  100  and thus fluid in the throughbore  40  cannot pass through the apertures  40  and therefore cannot circulate back up the annulus  5 . 
         [0099]    An annular step  61  is provided on an inner surface of the middle sub  56  and leads to a further annular step  63  towards the end of the middle sub  56  that is joined to the top sub  96 . Each step creates a throughbore  40  portion having an enlarged or recessed bore. The annular step  61  presents a shoulder or stop for limiting axial travel of the sleeve  100 . The annular step  63  presents a shoulder or stop for limiting axial travel of the annular piston  120 . 
         [0100]    An inner surface at the end of the middle sub  56  has an annular insert  115  attached thereto by means of a threaded connection  1 . 11 . The annular insert  115  is sealed against the inner surface of the middle sub  56  by an annular groove  116  accommodating an O-ring seal  117 . An inner surface of the annular insert  115  carries a wiper seal  119  in an annular groove  118  to create a seal against the sliding sleeve  100 . 
         [0101]    The top sub  96  of the circulating sub  11  has four ports  26  (shown in  FIG. 9 ) extending through the sidewall of the circulating sub  11 . In the region of the ports  26 , the top sub  96  has a recessed inner surface to accommodate an annular insert  106  in a location vertically below the ports  26  in use and an annular insert  114  that is L-shaped in section vertically above the port  26  in use. The annular insert  106  is sealed against the top sub  96  by an annular groove  108  accommodating an O-ring seal  109 . An inner surface of the annular insert  106  provides an annular step  103  against which the sleeve  100  can seat. An inner surface of the insert  106  is provided with an annular groove  104  carrying a wiper seal  105  to provide a sliding seal against the sleeve  100 . The insert  114  is made from a hard wearing material so that fluid flowing through the port  26  does not result in excessive wear of the top sub  96  or middle sub  56 . 
         [0102]    The sleeve  100  is shown in  FIGS. 4 to 9  occupying a first, closed, position in which the sleeve  100  abuts the step  103  provided on the annular insert  106  and the annular piston  120  is therefore at one end of its stroke thereby creating a first annular piston chamber  121 . The piston chamber  121  is bordered by the sliding sleeve  100 , the annular piston  120 , an inner surface of the middle sub  56  and the annular step  63 . The sleeve  100  is moved into the configuration shown in  FIGS. 4 to 9  by pumping fluid into the chamber  121  via conduit  88 . 
         [0103]    The annular piston  120  is sealed against the inner surface of the middle sub  56  by means of an O-ring seal  99  accommodated in an annular recess  98 . Axial travel of the sleeve  100  is limited by the annular step  61  at one end and the sleeve seat  1 . 03  at the other end. 
         [0104]    The sleeve  100  is sealed against wiper seals  105 ,  119  when in the first closed configuration and the annular protrusion  120  seals against an inner surface of the middle sub  56  and is moveable between the annular step  63  on the Inner surface of the middle sub  56  and the annular insert  115 . 
         [0105]    In the second, open configuration, the throughbore  40  is in fluid communication with the annulus  5  when the ports  26  are uncovered. The sleeve  100  abuts the annular step  61  in the second position so that the fluid channel between the ports  26  and the throughbore  40  of the bottom sub  96  and the annulus  5  is open. The sleeve  100  is moved into the second (open) configuration, when circulation of fluid from the throughbore  40  into the annulus  5  is required, by pumping fluid along conduit  72  into chamber  123  which is bounded by seals  117  and  119  at its lowermost end and seal  99  at its upper most end. 
         [0106]    RFID tags (not shown) for use in conjunction with the apparatus described above can be those produced by Texas Instruments such as a 32 mm glass transponder with the model number RI-TRP-WRZB-20 and suitably modified for application downhole. The tags should be hermetically sealed and capable of withstanding high temperatures and pressures. Glass or ceramic tags are preferable and should be able to withstand 20,000 psi (138 MPa). Oil filled tags are also well suited to use downhole, as they have a good collapse rating. 
         [0107]    An RFID tag (not shown) is programmed at the surface by an operator to generate a unique signal. Similarly, each of the electronics packages coupled to the respective antenna  62  if separate remote control units  9  are provided or to the one remote control unit  9  if it is shared between the tools  11 ,  13 ,  15 , prior to being included in the completion at the surface, is separately programmed to respond to a specific signal. The RFID tag comprises a miniature electronic circuit having a transceiver chip arranged to receive and store information and a small antenna within the hermetically sealed casing surrounding the tag. 
         [0108]    Once the borehole has been drilled and cased and the well is ready to be completed, completion  4  and production string  3  is run downhole. The sleeve  100  is run into the wellbore  1  in the open configuration such that the ports  26  are uncovered to allow fluid communication between the throughbore  40  and the annulus. 
         [0109]    When required to operate a tool  11 ,  13 ,  15  and circulation is possible (i.e. when the sleeve  100  is in the open configuration), the pre-programmed RFID tag is weighted, if required, and dropped or flushed into the well with the completion fluid. After travelling through the throughbore  40 , the selectively coded RFID tag reaches the remote control unit  9  the operator wishes to actuate and passes through the antenna  62  thereof which is of sufficient length to charge and read data from the tag. The tag then transmits certain radio frequency signals, enabling it to communicate with the antenna  62 . This data is then processed by the electronics package. 
         [0110]    As an example the RFID tag in the present embodiment has been programmed at the surface by the operator to transmit information instructing that the sleeve  100  of the circulation sleeve sub  11  is moved into the closed position. The electronics package  67  processes the data received by the antenna  62  as described above and recognises a flag in the data which corresponds to an actuation instruction data code stored in the electronics package  67 . The electronics package  67  then instructs the motor  17 ;  60 , powered by battery pack  66 , to drive the hydraulic piston pump  80 . Hydraulic fluid is then pumped out of the chamber  89 , through the hydraulic conduit line  88  and into the chamber  121  to cause the chamber  121  to fill with fluid thereby moving the sleeve  100  downwards into the closed configuration. The volume of hydraulic fluid in chamber  123  decreases as the sleeve  100  is moved towards the shoulder  103 . Fluid exits the chamber  123  along hydraulic conduit line  72  and is returned to the hydraulic fluid reservoir  83 . When this process is complete the sleeve  100  abuts the shoulder  103 . This action therefore results in the sliding sleeve  100  moving downwards to obturate port  26  and close the path from the throughbore  40  of the completion  4  to the annulus  5 . 
         [0111]    Therefore, in order to actuate a specific tool  11 ,  13 ,  15 , for example circulation sleeve sub  11 , a tag programmed with a specific frequency is sent downhole. In this way tags can be used to selectively target specific tools  11 ,  13 ,  15  by pre-programming the electronics package to respond to certain frequencies and programming the tags with these frequencies. As a result several different tags may be provided to target different tools  11 ,  13 ,  15  at the same time. 
         [0112]    Several tags programmed with the same operating instructions can be added to the well, so that at least one of the tags will reach the desired antenna  62  enabling operating instructions to be transmitted. Once the data is transferred the other RFID tags encoded with similar data can be ignored by the antenna  62 . 
         [0113]    Any suitable packer  13  could be used particularly if it can be selectively actuated by inflation with fluid from within the throughbore  40  of the completion  4  and a suitable example of such a packer  13  is a 50-ACE packer offered by Petrowell of Dyce, Aberdeen, UK. 
         [0114]    An embodiment of a motorised downhole needle valve tool  19  for enabling inflation of the packer  13  will now be described and is shown in  FIG. 10 . 
         [0115]    The needle valve tool  19  comprises an outer housing  300  and is typically formed either within or is located in close proximity to the packer  13 . Positive  301  and negative  303  dc electric terminals are connected via suitable electrical cables (not shown) to the electronics package  67  where the terminals  301 ,  303  connect into an electrical motor  305 , the rotational output of which is coupled to a gear box  307 . The rotational output of the gearbox  307  is rotationally coupled to a needle shaft  313  via a splined coupling  311  and there are a plurality of O-ring seals  312  provided to ensure that the electric motor  305  and gear box  307  remain sealed from the completion fluid in the throughbore  40 . The splined connection between the coupling  311  and the needle shaft  313  ensures that the needle shaft is rotationally locked to the coupling  311  but can move axially with respect thereto. The needle  315  is formed at the very end of the needle shaft  313  and is arranged to selectively seal against a seat  317  formed in the portion of the housing  300   x . Furthermore, the needle shaft  313  is in screw threaded engagement with the housing  300   x  via screw threads  314  in order to cause axial movement of the needle shaft  313  (either toward or away from seat  317 ) when it is rotated. 
         [0116]    When the needle  315  is in the sealing configuration shown in  FIG. 10  with the seat  317 , completion fluid in the throughbore  40  of the production tubing  3  is prevented from flowing through the hydraulic fluid port to tubing  319  and into the packer setting chamber  13 P. However, when the electric motor  305  is activated in the appropriate direction, the result is rotation of the needle shaft  313  and, due to the screw threaded engagement  314 , axial movement away from the seat  317  which results in the needle  315  parting company from the seat  317  and this permits fluid communication through the seat  317  from the hydraulic fluid port  319  into the packer setting chamber  13   p  which results in the packer  13  inflating. 
         [0117]    A suitable example of a barrier  15  will now be described. 
         [0118]    The barrier  15  is preferably a fall through flapper valve  15  such as that described in PCT Application No GB2007/001547, the full contents of which are incorporated herein by reference, but any suitable flapper valve or ball valve that can be hydraulically operated could be used (and such a ball valve is a downhole Formation Saver Valve (PSV) offered by Weatherford of Aberdeen, UK) although it is preferred to have as large (i.e. unrestricted) an inner diameter of the completion  4  when open as possible. 
         [0119]      FIG. 11  shows a frequency pressure actuated apparatus  150  and which is preferably used instead of a conventional mechanical pressure sensor (not shown) in order to receive pressure signals sent from the surface in situations when the well is shut in (i.e. when barrier  15  is closed) and therefore no circulation of fluid can take place and thus no RFID tags can be used. 
         [0120]    The apparatus  150  comprises a pressure transducer  152  which is capable of sensing the pressure of well fluid located within the throughbore  40  of the production tubing string  3  and outputting a voltage having an amplitude indicative thereof. 
         [0121]    As an example,  FIG. 12  shows a typical electrical signal output from the pressure transducer where a pressure pulse sequence  170 A,  170 B,  170 C,  170 D is clearly shown as being carried on the general well fluid pressure which, as shown in  FIG. 12  is oscillating much more slowly and represented by sine wave  172 . Again, as before, this pressure pulse sequence  170 A- 170 D is applied to the well fluid contained within the production tubing string  3  at the surface of the wellbore. 
         [0122]    However, unlike conventional mechanical pressure sensors, the presence of debris above the downhole tool and its attenuation effect in reducing the amplitude of the pressure signals will not greatly affect the operation of the apparatus  150 . 
         [0123]    The apparatus  150  further comprises an amplifier to amplify the output of the pressure transducer  152  where the output of the amplifier is input into a high pass filter which is arranged to strip the pressure pulse sequence out of the signal as received by the pressure transducer  152  and the output of the high pass filter  156  is shown in  FIG. 13  as comprising a “clean” set of pressure pulses  170 A- 170 D. The output of the high pass filter  156  is input into an analogue/digital converter  158 , the output of which is input into a programmable logic unit comprising a microprocessor containing software  160 . 
         [0124]    A logic flow chart for the software  160  is shown in  FIG. 14  and is generally designated by the reference numeral  180 . 
         [0125]    In FIG.  14 :— 
         [0000]    “n” represents a value used by a counter;
 
“p” is pressure sensed by the pressure transducer  152 ;
 
“dp/dt” is the change in pressure over the change in time and is used to detect peaks, such as pressure pulses  170 A- 170 D;
 
“n max” is programmed into the software prior to the apparatus  150  being run into the borehole and could be, for instance,  105  or  110 .
 
         [0126]    Furthermore, the tolerance value related to timer “a” could be, for example, 1 minute or 5 minutes or 10 minutes such that there is a maximum of e.g. 1, 5 or 10 minutes that can be allowed between pulses  170 A- 170 B. In other words, if the second pulse  170 B does not arrive within that tolerance value then the counter is reset back to 0 and this helps prevent false actuation of the barrier  17 . 
         [0127]    Furthermore, the step  188  is included to ensure that the software only regards peak pressure pulses and not inverted drops or troughs in the pressure of the fluid. 
         [0128]    Also, step  190  is included to ensure that the value of a pressure peak as shown in  FIG. 13  has to be greater than 100 psi in order to obviate unintentional spikes in the pressure of the fluid. 
         [0129]    It should be noted that step  202  could be changed to ask:— 
         [0000]    “Is ‘a’ greater than a minimum tolerance value”
 
such as the tolerance  208  shown in  FIG. 15  so that the software definitely only counts one peak as such.
 
         [0130]    Accordingly, when the software logic has cycled a sufficient number of times such that “n” is greater than “n max” as required in step  196 , a signal is sent by the software to the downhole tool to be actuated (i.e. circulation sleeve sub  11 , packer  13  or barrier  15 ) such as to open the barrier  17  as shown in step  206 . The frequency pressure actuated apparatus  150  is provided with power from the battery power pack  166  via the electronics package  167 . 
         [0131]    The apparatus  150  has the advantage over conventional mechanical pressure sensors that much more accurate actuation of the tools  111 ,  113 ,  115  is provided such as opening of the barrier flapper valve  17  and much more precise control over the tools  111 ,  113 ,  17  in situations where circulation of RFID tags can&#39;t occur is also enabled. 
         [0132]    Modifications and improvements may be made to the embodiments hereinbefore described without departing from the scope of the invention. For example, the signal sent by the software at step  206  or the RFID tags could be used for other purposes such as injecting a chemical into e.g. a chemically actuated tool such as a packer or could be used to operate a motor to actuate another form of mechanically actuated tool or in the form of an electrical signal used to actuate an electrically operated tool. Additionally, a downhole power generator can provide the power source in place of the battery pack. A fuel cell arrangement can also be used as a power source. 
         [0133]    Furthermore, the electronics package  67  could be programmed with a series of operations at the surface before being run into the well with the rest of the completion  4  to operate each of the steps as described above in e.g. 60 days time with each step separated by e.g. one day at a time and clearly these time intervals can be varied. Moreover, such a system could provide for a self-installing completion system  4 . Furthermore, the various individual steps could be combined such that for example an RFID tag or a pressure pulse can be used to instruct the electronics package  67  to conduct one step immediately (e.g. step f) of stopping circulation with an RFID tag) and then follow up with another step (e.g. step g) of opening the flapper valve barrier  15 ) in for example two hours time. Furthermore, other but different remote control methods of communicating with the central control units  9  could be used instead of RFID tags and sending pressure pulses down the completion fluid, such as an acoustic signalling system such as the EDGE™ system offered by Halliburton of Duncan, Okla. or an electromagnetic wave system such as the Cableless Telemetry System (CATS™) offered by Expro Group of Verwood, Dorset, UK or a suitably modified MWD style pressure pulse system which could be used whilst circulating instead of using the RFID tags.