Method of and apparatus for completing a well

A completion apparatus (4) for completing a wellbore comprises a) a tool to alternatively open and close a throughbore (15) of the completion; b) a tool (13) 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 from the throughbore of the completion to the said annulus (11); and d) at least one signal receiver and processing tool (9) capable of decoding signals received relating to the operation of tools a) to c).

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.

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.

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.

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; anda 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.

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.

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. 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.

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.

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); ande) a tool comprising a powered actuation mechanism capable of operating tools a) to c) under instruction from tool d).

According to a first aspect of the present invention there is a method of completing a wellbore comprising the steps of:—

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); ande) 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.

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/orsending 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.

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.

According to a second aspect of the present invention there is a method of completing a wellbore comprising the steps of:—

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; andc) a means to alternatively provide and prevent a fluid circulation route from the throughbore of the completion to the said annulus; andd) 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.

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).

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.

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.

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).

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.

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.

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.

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.

Preferably, tool c) is located, within the production string, closer to the surface of the well than either of tool a) and tool b).

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.

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.

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.

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.

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).

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.

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.

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.

A production string3made up of a number (which could be hundreds) of production tubulars having screw threaded connections is shown with a completion4at its lower end inFIG. 1where the production tubing string3and completion4have just been run into a cased well1. In order to complete the oil and gas production well such that production of hydrocarbons can commence, the completion4needs to be set into the well.

In accordance with the present invention, the completion4comprises a wireless remote control central power unit9provided at its upper end with a circulation sleeve sub11located next in line vertically below the central power unit9. A packer13is located immediately below the circulation sleeve sub11and a barrier15, which may be in the form of a valve such as a ball valve but which is preferably a flapper valve15, is located immediately below the packer13. Importantly, the circulation sleeve sub11is located above the packer13and the barrier15.

A control means9A,9B,9C is shown schematically inFIG. 2in dotted lines as leading from the wireless remote control central power unit9to each of the circulation sleeve sub11, packer13and barrier15where 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.

As shown inFIG. 1and as is common in the art, there is an annulus5defined between the outer circumference of the completion4/production string3and the inner surface of the cased wellbore1.

In order to safely install the completion4in the cased wellbore1, the following sequence of events are observed.

The completion4is run into the cased wellbore1with the flapper valve15in the open configuration, that is with the flapper15F not obturating the throughbore40such that fluid can flow in the throughbore40. Furthermore, the packer13is run into the cased wellbore1in the unset configuration which means that it is clear of the casing1and does not try to obturate the annulus5as it is being run in. Additionally, the circulation sleeve sub11is run in the closed configuration which means that the apertures26(which are formed through the side wall of the circulation sleeve sub11) are closed by a sliding sleeve100provided on the inner bore of the circulation sleeve sub11as will be described subsequently and thus the apertures26are closed such that fluid cannot flow through them and therefore the fluid must flow all the way through the throughbore40of the completion4and production string3.

An interventionless method of setting the completion4in the cased wellbore1will 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.

The wireless remote control central power unit9will be described in more detail subsequently, but in general comprises (as shown in FIG.3):—an RFID tag detector62in the form of an antenna62and 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 detector150which can be used to detect peaks in fluid pressure in the completion tubing throughbore40(where the pressure peaks are applied at the surface by the operator and are transmitted down the fluid contained within the throughbore40and therefore provide a second means for the operator to send signals to the central power unit9);a battery pack66which provides all the power requirements to the central power unit9;an electronics package67which has been coded at the surface by the operator with the instructions on which tools11,13,15to operate depending upon which signals are received by one of the two receivers62,150;a first electrical motor and hydraulic pump combination17which, when operated, will control the opening or closing of the sleeve100of the circulation sleeve sub11;a motorised downhole needle valve tool19(which could well actually form part of the packer13and therefore be housed within the packer instead of forming part of and being housed within the central power unit9); anda second electric motor and hydraulic pump combination21which has two hydraulic fluid outlets21A,21B which are respectively used to provide hydraulic pressure to a first hydraulic chamber21U within the fall through flapper15and which is arranged to rotate the flapper valve15upwards when hydraulic fluid is pumped into the chamber21U in order to open the throughbore40and a second hydraulic fluid chamber21D also located within the fall through flapper15and which is arranged to move the flapper down in order to close the throughbore40when required.

In general, the completion4is set into the cased wellbore1by following this sequence of steps:—

a) the completion4is run into the cased hole with the flapper15in the open configuration such that the throughbore40is open, the circulation sleeve sub11is in the closed configuration such that the apertures26are closed and the packer13is in the unset configuration;
b) in order to be able to subsequently pressure test the completion tubing (see step C below) the flapper valve15must 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 throughbore40of the production string3and completion4. The RFID tag is coded at the surface with an instruction to tell the central power unit9to close the fall through flapper15. The RFID detector62detects the RFID tag as it passes through the central power unit9and the electronic package67decodes the signal detected by the antenna62as an instruction to close the flapper valve15. This results in the electronics package67(powered by the battery pack66) instructing the second electric motor plus hydraulic pump combination21to pump hydraulic fluid through conduit21B into the chamber21D which results in closure of the fall through flapper valve15;
c) a tubing pressure test is then typically conducted to check the integrity of the production tubing3as there could be many hundreds of joints of tubing screwed together to form the production tubing string3. The pressure test is conducted by increasing the pressure of the fluid at surface in communication with the fluid contained in the throughbore40of the production string3and completion4;
d) assuming the tubing pressure test is successful, the next stage is to set the packer13but because the flapper valve15is 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 detector150is used to sense increases in pressure of the production fluid within the throughbore40as 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 detector150and is decoded by the electronics package67which results in the operation of the motorised downhole needle valve tool19(as will be detailed subsequently) to open a conduit between a packing setting chamber13P and the throughbore of the production tubing3to allow production tubing fluid to enter the packing setting chamber13P to inflate the packer. The setting of the packer13can be tested in the usual way; that is by increasing the pressure in the annulus at surface to confirm the packer13holds the pressure;
e) It is important to remove the heavy kill fluids which are located in the production tubing above the packer13. 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 detector150and is decoded by the electronics package67as an instruction to open the circulation sleeve sub11. Accordingly, the electronics package67instructs the first electric motor and hydraulic pump combination17to move the sleeve100in the required direction to uncover the apertures26. Accordingly, circulation fluid such as a brine or diesel can be pumped down the production string3, through the throughbore40, out of the apertures26and back up the annulus5to 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 sub11and the RFID tag is introduced into the circulation fluid flow path down the throughbore40. The RFID detector62will detect the signal carried on the coded RFID tag and this is decoded by the electronics package67which will instruct the electric motor and hydraulic pump combination17to move the circulation sleeve100in the opposite direction to the direction it was moved in step e) above such that the apertures26are 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 valve15and 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 throughbore40such that it is detected by the pressure signature detector150and the signal is decoded by the electronics package67to operate the electric motor and hydraulic pump combination21to pump hydraulic fluid down the conduit21aand into the hydraulic chamber21uwhich moves the flapper to open the throughbore40.

The well has now been completed with the completion4being 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 throughbore40in the completion4and the production tubing string3to the surface whenever desired.

The key completion tools will now be described in detail.

The central power unit9is shown inFIGS. 4 to 9as being largely formed in one tool housing along with the circulation sleeve sub11where the central power unit9is mainly housed within a top sub46and a middle sub56and the circulation sleeve sub11is mainly housed within a bottom sub96, each of which comprise a substantially cylindrical hollow body. In this embodiment, the packer13and the flapper valve15could 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 unit9as shown in detail inFIGS. 4 to 9but modified with separate hydraulic conduits leading to the respective tools11,13,15as generally shown inFIGS. 1 to 3.

The wireless remote controlled central power unit9(shown inFIGS. 4 to 9) has pin ends44eenabling connection with a length of adjacent production tubing or pipe42.

When connected in series for use, the hollow bodies of the top sub46, middle sub56and bottom sub96define a continuous throughbore40.

As shown inFIG. 5, the top sub46and the middle sub56are secured by a threaded pin and box connection50. The threaded connection50is sealed by an O-ring seal49accommodated in an annular groove48on an inner surface of the box connection of the top sub46. Similarly, the top sub96of the circulation sleeve sub11and the middle sub56of the central control unit9are joined by a threaded connection90(shown inFIG. 7).

An inner surface of the middle sub56is provided with an annular recess60that creates an enlarged bore portion in which an antenna62is accommodated co-axial with the middle sub56. The antenna62itself is cylindrical and has a bore extending longitudinally therethrough. The inner surface of the antenna62is flush with an inner surface of the adjacent middle sub56so that there is no restriction in the throughbore40in the region of the antenna62. The antenna62comprises 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 sub56in 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 antenna62is formed such that the insulating material and coiled conductor are sealed from the outer environment and the throughbore40. The antenna62is typically in the region of 10 meters or less in length.

Two substantially cylindrical tubes or bores58,59are machined in a sidewall of the middle sub56parallel to the longitudinal axis of the middle sub56. The longitudinal machined bore59accommodates a battery pack66. The machined bore58houses a motor and gear box64and a hydraulic piston assembly shown generally at60. Ends of both of the longitudinal bores58,59are sealed using a seal assembly52,53respectively. The seal assembly52,53includes a solid cylindrical plug of material having an annular groove accommodating an O-ring to seal against an inner surface of each machined bore58,59.

An electronics package67(but not shown inFIG. 4) is also accommodated in a sidewall of the middle sub56and is electrically connected to the antenna62, the motor and gear box64. The electronics package, the motor and gear box64and the antenna62are all electrically connected to and powered by the battery pack66.

The motor and gear box64when actuated rotationally drive a motor arm65which in turn actuates a hydraulic piston assembly60. The hydraulic piston assembly60comprises a threaded rod74coupled to the motor arm65via a coupling68such that rotation of the motor arm65causes a corresponding rotation of the threaded rod74. The rod74is supported via thrust bearing70and extends into a chamber83that is approximately twice the length of the threaded rod74. The chamber83also houses a piston80which has a hollowed centre arranged to accommodate the threaded rod74. A threaded nut76is axially fixed to the piston80and rotationally and threadably coupled to the threaded rod74such that rotation of the threaded rod74causes axial movement of the nut76and thus the piston80. Outer surfaces of the piston80are provided with annular wiper seals78at both ends to allow the piston80to make a sliding seal against the chamber83wall, thereby fluidly isolating the chamber83from a second chamber89ahead of the piston80(on the right hand side of the piston80as shown inFIG. 6). The chamber83is in communication with a hydraulic fluid line72that communicates with a piston chamber123(described hereinafter) of the sliding sleeve100. The second chamber89is in communication with a hydraulic fluid line88that communicates with a piston chamber121(described hereinafter) of the sliding sleeve100.

A sliding sleeve100having an outwardly extending annular piston120is sealed against the inner recessed bore of the middle sub56. The sleeve100is shown in a first closed configuration inFIGS. 4 to 9in that apertures26are closed by the sliding sleeve100and thus fluid in the throughbore40cannot pass through the apertures40and therefore cannot circulate back up the annulus5.

An annular step61is provided on an inner surface of the middle sub56and leads to a further annular step63towards the end of the middle sub56that is joined to the top sub96. Each step creates a throughbore40portion having an enlarged or recessed bore. The annular step61presents a shoulder or stop for limiting axial travel of the sleeve100. The annular step63presents a shoulder or stop for limiting axial travel of the annular piston120.

An inner surface at the end of the middle sub56has an annular insert115attached thereto by means of a threaded connection111. The annular insert115is sealed against the inner surface of the middle sub56by an annular groove116accommodating an O-ring seal117. An inner surface of the annular insert115carries a wiper seal119in an annular groove118to create a seal against the sliding sleeve100.

The top sub96of the circulating sub11has four ports26(shown inFIG. 9) extending through the sidewall of the circulating sub11. In the region of the ports26, the top sub96has a recessed inner surface to accommodate an annular insert106in a location vertically below the ports26in use and an annular insert114that is L-shaped in section vertically above the port26in use. The annular insert106is sealed against the top sub96by an annular groove108accommodating an O-ring seal109. An inner surface of the annular insert106provides an annular step103against which the sleeve100can seat. An inner surface of the insert106is provided with an annular groove104carrying a wiper seal105to provide a sliding seal against the sleeve100. The insert114is made from a hard wearing material so that fluid flowing through the port26does not result in excessive wear of the top sub96or middle sub56.

The sleeve100is shown inFIGS. 4 to 9occupying a first, closed, position in which the sleeve100abuts the step103provided on the annular insert106and the annular piston120is therefore at one end of its stroke thereby creating a first annular piston chamber121. The piston chamber121is bordered by the sliding sleeve100, the annular piston120, an inner surface of the middle sub56and the annular step63. The sleeve100is moved into the configuration shown inFIGS. 4 to 9by pumping fluid into the chamber121via conduit88.

The annular piston120is sealed against the inner surface of the middle sub56by means of an O-ring seal99accommodated in an annular recess98. Axial travel of the sleeve100is limited by the annular step61at one end and the sleeve seat103at the other end.

The sleeve100is sealed against wiper seals105,119when in the first closed configuration and the annular protrusion120seals against an inner surface of the middle sub56and is moveable between the annular step63on the inner surface of the middle sub56and the annular insert115.

In the second, open configuration, the throughbore40is in fluid communication with the annulus5when the ports26are uncovered. The sleeve100abuts the annular step61in the second position so that the fluid channel between the ports26and the throughbore40of the bottom sub96and the annulus5is open. The sleeve100is moved into the second (open) configuration, when circulation of fluid from the throughbore40into the annulus5is required, by pumping fluid along conduit72into chamber123which is bounded by seals117and119at its lowermost end and seal99at its upper most end.

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.

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 antenna62if separate remote control units9are provided or to the one remote control unit9if it is shared between the tools11,13,15, 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.

Once the borehole has been drilled and cased and the well is ready to be completed, completion4and production string3is run downhole. The sleeve100is run into the wellbore1in the open configuration such that the ports26are uncovered to allow fluid communication between the throughbore40and the annulus.

When required to operate a tool11,13,15and circulation is possible (i.e. when the sleeve100is 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 throughbore40, the selectively coded RFID tag reaches the remote control unit9the operator wishes to actuate and passes through the antenna62thereof 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 antenna62. This data is then processed by the electronics package. 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 sleeve100of the circulation sleeve sub11is moved into the closed position. The electronics package67processes the data received by the antenna62as described above and recognises a flag in the data which corresponds to an actuation instruction data code stored in the electronics package67. The electronics package67then instructs the motor17;60, powered by battery pack66, to drive the hydraulic piston pump80. Hydraulic fluid is then pumped out of the chamber89, through the hydraulic conduit line88and into the chamber121to cause the chamber121to fill with fluid thereby moving the sleeve100downwards into the closed configuration. The volume of hydraulic fluid in chamber123decreases as the sleeve100is moved towards the shoulder103. Fluid exits the chamber123along hydraulic conduit line72and is returned to the hydraulic fluid reservoir83. When this process is complete the sleeve100abuts the shoulder103. This action therefore results in the sliding sleeve100moving downwards to obturate port26and close the path from the throughbore40of the completion4to the annulus5.

Therefore, in order to actuate a specific tool11,13,15, for example circulation sleeve sub11, a tag programmed with a specific frequency is sent downhole. In this way tags can be used to selectively target specific tools11,13,15by 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 tools11,13,15at the same time.

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 antenna62enabling operating instructions to be transmitted. Once the data is transferred the other RFID tags encoded with similar data can be ignored by the antenna62.

Any suitable packer13could be used particularly if it can be selectively actuated by inflation with fluid from within the throughbore40of the completion4and a suitable example of such a packer13is a 50-ACE packer offered by Petrowell of Dyce, Aberdeen, UK.

An embodiment of a motorised downhole needle valve tool19for enabling inflation of the packer13will now be described and is shown inFIG. 10.

The needle valve tool19comprises an outer housing300and is typically formed either within or is located in close proximity to the packer13. Positive301and negative303dc electric terminals are connected via suitable electrical cables (not shown) to the electronics package67where the terminals301,303connect into an electrical motor305, the rotational output of which is coupled to a gear box307. The rotational output of the gearbox307is rotationally coupled to a needle shaft313via a splined coupling311and there are a plurality of O-ring seals312provided to ensure that the electric motor305and gear box307remain sealed from the completion fluid in the throughbore40. The splined connection between the coupling311and the needle shaft313ensures that the needle shaft is rotationally locked to the coupling311but can move axially with respect thereto. The needle315is formed at the very end of the needle shaft313and is arranged to selectively seal against a seat317formed in the portion of the housing300x. Furthermore, the needle shaft313is in screw threaded engagement with the housing300xvia screw threads314in order to cause axial movement of the needle shaft313(either toward or away from seat317) when it is rotated.

When the needle315is in the sealing configuration shown inFIG. 10with the seat317, completion fluid in the throughbore40of the production tubing3is prevented from flowing through the hydraulic fluid port to tubing319and into the packer setting chamber13P. However, when the electric motor305is activated in the appropriate direction, the result is rotation of the needle shaft313and, due to the screw threaded engagement314, axial movement away from the seat317which results in the needle315parting company from the seat317and this permits fluid communication through the seat317from the hydraulic fluid port319into the packer setting chamber13pwhich results in the packer13inflating.

A suitable example of a barrier15will now be described.

The barrier15is preferably a fall through flapper valve15such 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 (FSV) offered by Weatherford of Aberdeen, UK) although it is preferred to have as large (i.e. unrestricted) an inner diameter of the completion4when open as possible.

FIG. 11shows a frequency pressure actuated apparatus150and 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 barrier15is closed) and therefore no circulation of fluid can take place and thus no RFID tags can be used.

The apparatus150comprises a pressure transducer152which is capable of sensing the pressure of well fluid located within the throughbore40of the production tubing string3and outputting a voltage having an amplitude indicative thereof.

As an example,FIG. 12shows a typical electrical signal output from the pressure transducer where a pressure pulse sequence170A,170B,170C,170D is clearly shown as being carried on the general well fluid pressure which, as shown inFIG. 12is oscillating much more slowly and represented by sine wave172. Again, as before, this pressure pulse sequence170A-170D is applied to the well fluid contained within the production tubing string3at the surface of the wellbore.

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 apparatus150.

The apparatus150further comprises an amplifier to amplify the output of the pressure transducer152where 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 transducer152and the output of the high pass filter156is shown inFIG. 13as comprising a “clean” set of pressure pulses170A-170D. The output of the high pass filter156is input into an analogue/digital converter158, the output of which is input into a programmable logic unit comprising a microprocessor containing software160.

A logic flow chart for the software160is shown inFIG. 14and is generally designated by the reference numeral180.

In FIG.14:—

“n” represents a value used by a counter;

“p” is pressure sensed by the pressure transducer152;

“dp/dt” is the change in pressure over the change in time and is used to detect peaks, such as pressure pulses170A-170D;

“n max” is programmed into the software prior to the apparatus150being run into the borehole and could be, for instance,105or110.

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 pulses170A-170B. In other words, if the second pulse170B does not arrive within that tolerance value then the counter is reset back to 0 and this helps prevent false actuation of the barrier17.

Furthermore, the step188is included to ensure that the software only regards peak pressure pulses and not inverted drops or troughs in the pressure of the fluid.

Also, step190is included to ensure that the value of a pressure peak as shown inFIG. 13has to be greater than 100 psi in order to obviate unintentional spikes in the pressure of the fluid.

It should be noted that step202could be changed to ask:—

“Is ‘a’ greater than a minimum tolerance value”

such as the tolerance208shown inFIG. 15so that the software definitely only counts one peak as such.

Accordingly, when the software logic has cycled a sufficient number of times such that “n” is greater than “n max” as required in step196, a signal is sent by the software to the downhole tool to be actuated (i.e. circulation sleeve sub11, packer13or barrier15) such as to open the barrier17as shown in step206. The frequency pressure actuated apparatus150is provided with power from the battery power pack166via the electronics package167.

The apparatus150has the advantage over conventional mechanical pressure sensors that much more accurate actuation of the tools111,113,115is provided such as opening of the barrier flapper valve17and much more precise control over the tools111,113,17in situations where circulation of RFID tags can't occur is also enabled.

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 step206or 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.

Furthermore, the electronics package67could be programmed with a series of operations at the surface before being run into the well with the rest of the completion4to 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 system4. 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 package67to 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 barrier15) in for example two hours time. Furthermore, other but different remote control methods of communicating with the central control units9could 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.