METHOD AND DEVICE

Abstract

A device for use downhole comprises a body housing: a power source arranged to supply power to a driver; and a hydraulic system including a piston sealed in a chamber and an outlet provided at each opposing end of the chamber wherein each outlet is in communication with a respective reservoir, the driver being actuable to drive the piston in a first direction, such that fluid is driven out of the chamber through one outlet and simultaneously fluid is drawn into the chamber through the other outlet at the opposing end.

Description

The present invention concerns a method of completing a well and a device for use downhole.

The method of the invention is particularly, though not exclusively, suitable for use in deviated wells, hereinafter referred to as “horizontal wells”. The method is particularly advantageous for use in wells of long horizontal extent.

Advances in drilling technology have enabled oil and gas wells to be drilled in a direction deviating from a vertical orientation relative to the surface of the earth. The general term “directional drilling” is used to describe deviations from vertical drilling. Directional drilling enables wells to penetrate into oil or gas formations or reservoirs that have a much greater lateral than vertical extent. This can offer significant production improvements over vertical wells in such formations.

FIG. 1 shows a typical method of completion of a prior art horizontal well. A borehole is drilled having a relatively vertical portion 12 and a relatively horizontal portion 18. The transition between the vertical portion 12 and the horizontal portion 18 is known as the heel 14 of the well and the end point of the horizontal portion 18 spaced furthest from the heel 14 is referred to as a toe 16 of the well. A production tubing or pipe 22 is then run into the borehole. In the horizontal portion 18, the pipe 22 has a number of ports 23 through which hydrocarbons can be produced. The pipe 22 in the region of each port 23 is surrounded by a sand screen 24 that restricts ingress of formation particles such as rocks and sand above a predetermined size through each port 23 and into the pipe 22.

Once production of the well begins, fluids are produced through the pipe 22 via the ports 23. However, conventional completions suffer from the disadvantage that the differential pressure between the formation 10 and the fluid within the pipe 22 can cause uneven inflow through the ports 23a, 23b, 23c. Typically, downstream reservoir zones are drained substantially faster (e.g. through port 23a) than upstream reservoir zones (e.g. through port 23c) causing uneven drainage of the formation 10. A further problem caused by uneven drainage of the reservoir is that water and/or gas can enter through the ports 23 into the pipe 22. This effect is often referred to as “water coning” or “gas coning” and is a particular problem experienced in the production of horizontal wells.

Flow control devices are known and these can be incorporated into the ports 23 at surface to choke the ports 23 in the horizontal portion 18. For example, inflow from downstream zones can be choked at the port 23a to a greater extent than upstream reservoir zones where for example, the port 23c can be fitted with an insert at surface that allows the port to remain in a more open position. In this way, the flow through the ports 23a, 23b, 23c can be manipulated such that there is a predetermined, but controlled, radial inflow of reservoir fluids throughout the pipe 22.

According to a first aspect of the present invention, there is provided a method of preparing a well for production including the steps of:—

(a) providing a pipe having a throughbore and a plurality of ports spaced axially along the pipe, each port having an associated obturation member;
(b) arranging each port in a closed configuration in which the port is substantially obturated by the obturation member to restrict fluid communication between the throughbore and an annulus surrounding the pipe;
(c) running the pipe into a well with each port in the closed configuration; and
(d) actuating relative movement of at least one of the port(s) and associated obturation members to change at least one port from the closed configuration to an open configuration, in which there is fluid communication between the annulus and the throughbore of the pipe.

Preferably, a port is provided on a sub and a plurality of subs are spaced axially along the pipe. A “sub” as used herein is intended to refer to any sub-component or collection of sub-components of a pipe string.

The well is preferably a well used in the production of hydrocarbons, such as an oil or gas well. Step (c) can include running the pipe into a deviated well. “Deviated well” is intended to refer to any well that deviates from a substantially vertical orientation and includes all horizontal and substantially horizontal wells. Step (c) can include running the pipe into a substantially horizontal well.

Step (d) can allow production to commence by opening a fluid flow path from the annulus exterior of the pipe to the throughbore of the pipe.

The method can include actuating at least two of the subs to move from the closed configuration to the open configuration. The method can include actuating at least two of the subs to move from the closed configuration to the open configuration at different times.

The method can include sequentially actuating the subs from the closed to the open configuration. The method can include sequentially actuating the subs to move from the closed to the open configuration from a toe of the well towards a heel of the well.

Sweeping the well in this manner by sequential opening of the ports from the toe towards the heel of the well is advantageous since a high pressure differential is maintained between the pipe and external reservoir during production of each reservoir zone.

The method can include providing an end sub having an orifice located towards or at a leading end of the pipe and performing step (c) with the said orifice in the open configuration. The method can include associating an obturation member with the orifice and actuating relative movement of the obturation member and the orifice to move the end sub into a closed configuration prior to or during step (d).

Each sub can be incorporated as part of a sandscreen sub. Thus, the pipe in the region of the ports can be surrounded by sandscreen. The sandscreen can be coaxial with the pipe. The size of the sandscreen mesh can be determined according to the maximum acceptable size of formation particles travelling through the port and in the pipe.

The method can include stabilising the well following step (c) by circulating fluid through the pipe. The fluid is preferably a high density fluid or mud such as kill fluid, selected to substantially restrict a pressure blow out of the well.

The method can include remotely actuating relative movement of the obturation member and the port(s), preferably without need for either electric or hydraulic cables run all the way from the surface to the subs and also preferably without need for intervention equipment such as a shifting tool run on slickline or coiled tubing to be deployed into the well to manually shift each respective obturation member.

The method can include incorporating a reader or signal sensor into each sub and method step (d) can be achieved by circulating at least one tag through the reader, wherein the at least one reader is arranged to read data from the tag when the tag passes therethrough. The tag and the reader can communicate using radio frequency identification. The reader can be arranged coaxial with the sub and the pipe. The reader can form part of a device according to the second aspect of the invention.

Features of a second aspect of the invention can be incorporated into the first aspect of the invention as appropriate.

The method can include electrically actuating relative movement of the obturation member and associated port(s).

The method can include coupling each obturation member to a timer and actuating relative movement of the obturation member and associated port(s) following a predetermined time delay.

Relative movement of the obturation member and the port(s) can be electrically actuated and the timer can be incorporated into a control circuit responsible for the actuation.

The obturation member can be in the form of a sliding sleeve.

The method can include actuating relative movement of the obturation member and the port(s) into an intermediate configuration in which the obturation member partially obturates the port(s) to thereby choke the ports.

According to a second aspect of the invention, there is provided a device for use downhole comprising a body housing:

• • a power source arranged to supply power to a driver; and
  • a hydraulic system including a piston sealed in a chamber and an outlet provided at each opposing end of the chamber wherein each outlet is in communication with a respective reservoir;
  • and wherein the driver is actuable to drive the piston in a first direction, such that fluid is driven out of the chamber through one outlet and simultaneously fluid is drawn into the chamber through the other outlet at the opposing end.

The hydraulic system is preferably a closed hydraulic system.

The driver can also be actuable to drive the piston in a second direction, such that fluid is driven out of the chamber through one outlet and simultaneously fluid is drawn into the chamber through the other outlet at the opposing end.

Each outlet can also function as an inlet.

One advantage of the device is that no separate hydraulic line from surface is required for the device to produce a synchronised output and input.

The body can be a tubular body. The tubular body can be an element in a pipe string.

The hydraulic system, the power source and the driver can be housed in a sidewall of tubular body.

The tubular body can include one or more cylindrical bores extending parallel to the longitudinal axis of the body for housing at least one of the power source, the actuator, the driver and the hydraulic system.

The cylindrical bore(s) can extend from one end of the tubular parallel to a longitudinal axis. A plug may be provided to substantially seal the ends of the bore(s) following insertion of at least one of the power source, the actuator, the driver and the hydraulic system in the bore(s).

One cylindrical bore can accommodate a power source. Another cylindrical bore can accommodate the driver and hydraulic system.

The power source can be a battery. The driver can be a motor. The motor can include a gearing mechanism to step up the torque provided by the motor.

The driver can be coupled to a rod arranged to drive the piston. The rod can be a threaded rod and the rod and the piston can be rotatable relative to each other such that rotation of the rod causes axial movement of the piston in the chamber.

The device can incorporate a second piston. The outlets at each end of the chamber can be in fluid communication with opposing sides of the second piston. Thus, actuation of the driver in one direction can cause resultant movement of the second piston in one direction.

The area of the second piston on which hydraulic fluid acts can be greater relative to the area of the piston in the hydraulic system on which hydraulic fluid acts. Thus there will be greater travel of the piston in the hydraulic system required for a given amount of travel of the second piston.

The second piston can be an annular piston. The second piston can form part of a sliding sleeve.

The device can also comprise an actuator wherein the actuator is arranged to selectively actuate the driver. The actuator can also be coupled to the power source.

The actuator can include a reader electrically coupled to an electronics pack, wherein the reader is arranged to read a signal from a remote source and wherein the signal can be processed by the electronics pack to selectively actuate the driver. The reader can comprise an antenna arranged to remotely communicate using radio frequency identification.

Alternatively, the actuator can comprise an electronic circuit and a timer switch coupled to the driver to actuate the driver after a predetermined period of time.

Embodiments of the invention will now be described with reference to the accompanying Figures, in which:—

FIG. 2 is a schematic view of a horizontal well prior to initiation of production;

FIG. 3 is a schematic view of a horizontal well in full production;

FIG. 4 is a sectional view of a downhole device according to the second aspect of the invention;

FIGS. 5-7 are detailed sectional consecutive views of the device shown in FIG. 4;

FIG. 8 is a view on section A-A shown in FIG. 5; and

FIG. 9 is a view on section B-B shown in FIG. 7.

FIGS. 2 and 3 show a well drilled into a formation 10. The well has a vertical portion 12, a horizontal portion 18, a heel 14 at the transition between the vertical portion 12 and the horizontal portion 18, and a toe 16 located at an end of the horizontal portion 18. The well is shown in FIGS. 2 and 3 having production tubing or pipe 42 inserted therein.

It should be noted that FIGS. 2 and 3 are not to scale and that the horizontal portion 18 of the well may be many hundreds of metres or several kilometres long. Typically, the pipe 42 is formed from a plurality of individual pipe lengths that are interconnected and sealed to form a continuous hollow tubing. The pipe 42 can also incorporate other downhole devices and porting as appropriate.

In the horizontal portion 18 of the well, the pipe 42 incorporates several downhole devices 44 (shown in FIG. 4) spaced at various points along the pipe 42. Each device 44 is provided with a series of ports 26 denoted consecutively 26a, 26b, 26c from the heel 14 towards the toe 16 of the well. The devices 44 are shown incorporated in part of a sand screen 24. In FIG. 2 each port 26 is shown covered by a sleeve 100 and again each sleeve is consecutively denoted 100a, 100b, 100c from the heel 14 to the toe 16 of the well. At the toe 16 of the well, the pipe 42 has a closed end and orifices 26d are provided adjacent the closed end. A sleeve 100d is provided to selectively obturate the orifices 26d at the toe 16 of the well. In FIG. 2, the sleeve 100d is shown as it will be positioned when the pipe 42 is run in, with the orifices 26d in fluid communication with the annulus surrounding the pipe 42.

The downhole device 44 (shown in FIGS. 4 to 9) has pin ends 44e enabling connection with a length of adjacent pipe 42. The device 44 includes a top sub 46, a middle sub 56 and bottom sub 96, each of which comprise a substantially cylindrical hollow body. 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.

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 and the middle sub 56 are joined by a threaded connection 90 (shown in FIG. 7).

An inner surface of the middle sub 56 is provided with an annular recessed portion 60 that creates an enlarged bore 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 portion 60 of the middle sub 56 in the radial direction. The liner and insulating material are formed from a non-magnetic and non-conductive material such as fibreglass, 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.

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 45. 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.

An electronics pack (not shown) 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 pack, the motor and gear box 64 and the antenna 62 are all electrically connected to and powered by the battery pack 66. The electronics pack is also provided with a timer so that once the antenna 62 has read a signal that corresponds to an actuation command, the actual step of actuation can be carried out at a predetermined time interval after the command is received.

The motor and gear box 64 are arranged to rotationally drive a motor arm 65. The hydraulic piston assembly 45 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 by a thrust bearing 70 and extends into a chamber 83 that is approximately twice the length of the threaded rod 74. The chamber 83 houses a piston 80. The piston 80 has a hollowed centre 82 arranged to accommodate the threaded rod 74. A nut 76 is axially fixed to the piston 80 and rotationally coupled to the threaded rod 74 such that rotation of the threaded rod 74 causes axial movement of the nut 76 and the piston 80. Outer surfaces of the piston 80 are provided with annular wiper seals 78 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. The chamber 83 is in communication with a hydraulic fluid line 72 that communicates with a piston chamber 123 (described hereinafter). The second chamber 89 is in communication with a hydraulic fluid line 88 that communicates with a piston chamber 121 (described hereinafter).

The sliding sleeve 100 has an outwardly extending annular piston 120 that is sealed against the middle sub 56 by an O-ring 99 accommodated in an annular groove 98 of the piston 120. 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 portion having an enlarged bore. The annular step 61 presents a shoulder for limiting axial travel of the sleeve 100 in a second direction. The annular step 63 presents a shoulder for limiting axial travel of the annular piston 120 also in the second direction.

An inner surface at the end of the middle sub 56 has an annular insert 115 attached thereto by means of a threaded connection 111. The annular insert 115 is sealed against the inner surface of the middle sub 56 by an annular groove 116 accommodating an O-ring 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.

The top sub 96 has four ports 26 (shown in FIG. 9) extending through a sidewall. In the region surrounding the ports 26, the top sub 96 has a recessed inner surface to accommodate an annular insert 106 in an location upstream of the ports 26 in use and a further annular insert 114 that is L-shaped in section and located downstream of the ports 26 in use. The annular insert 106 is sealed against the top sub 96 by an annular groove 108 accommodating an O-ring 109. An inner surface of the annular insert 106 provides an annular step 103 against which the sleeve 100 can seat and limit axial travel of the sleeve 100 in a first direction. Adjacent the step 103, the insert 106 is provided with an annular groove 104 carrying a wiper seal 105 to provide a seal against the sliding sleeve 100. The insert 114 located downstream of the ports 26 in use, is made from a hard wearing material so that production through the port 26 does not result in excessive wear of the top sub 96 or middle sub 56.

The sleeve 100 is shown in a first closed configuration in the FIGS. 4 to 9, in which the sleeve 100 abuts the annular step 103 provided on the annular insert 106. In the first closed configuration, the piston chamber 121 is filled with hydraulic fluid from the hydraulic line 88. The sleeve 100 is also movable into a second open configuration. The transition between the first closed and the second open configuration is achieved when the opposing piston chamber 123 is filled with hydraulic fluid from hydraulic line 72 to move the sleeve 100 in a second direction so that the end of the sleeve 100 seats against the step 61 and the annular piston 120 abuts the step 63. In the second open configuration, the ports 26 are uncovered and the throughbore 40 is in fluid communication with an annulus surrounding the pipe 42.

RFID tags (not shown) for use in conjunction with the antenna 62 described above can be those produced by Texas Instruments such as a 32 mm glass transponder with the model number RI-TRP-WRZB-20 suitably modified for use 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 pressure of 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 according to the present embodiment. Similarly, prior to being included in the device 44 at the surface each of the electronics packs coupled to the respective antenna 62, 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.

Prior to being run into the well, the pipe 24 is made up incorporating a plurality of downhole devices 44. The devices 44 are located along the pipe 24 string so that once run in, they will be positioned adjacent areas of the formation 10 that contain hydrocarbon reservoirs of interest. Once a borehole has been drilled and the well is ready to be completed, the pipe 24 is run downhole into the position shown in FIG. 2. As the pipe 42 is run downhole, the sleeves 100a, 100b, 100c of each of the downhole devices 44 are in the closed position, in which the sleeve 100 substantially obturates the respective ports 26, except for orifices 26d positioned at the end of the pipe 42. At the end of the pipe 42, the sleeve 100d is in the second open configuration in which the orifices 26d are in fluid communication with the annulus surrounding the pipe 42.

Kill fluid is then pumped downhole into the well. The kill fluid is typically a high density mud that substantially restricts egress of reservoir fluids out of the formation 10 and into the pipe 42 or the annulus surrounding the pipe 42. The sleeves 100a, 100b, 100c remain in the first closed position in FIG. 2 with the ports substantially obturated while the kill fluid is pumped downhole. Since the sleeves 100a, 100b, 100c obturate the ports 26a, 26b, 26c, there is no access to the annulus from the throughbore 40 until the end open orifices 26d are reached at the toe 14 of the well. As a result, an operator can be sure that kill fluid pumped into the throughbore 40 of the pipe 42 reaches the toe 14 of the well once the requisite volume of kill fluid has been pumped downhole. Therefore, complete circulation of kill fluid can be achieved by pumping fluid directly down the pipe 42 since the kill fluid cannot escape through the ports 26a, 26b, 26c.

Conventionally, pipe 22 is run downhole with all ports 23 in the sandscreen 24 sub open, as shown in FIG. 1. As a result, previous methods of ensuring kill fluid reaches the toe 14 of the well have required a separate step of running washpipe through the tubing and flowing kill fluid down the washpipe. This is both extremely time consuming and expensive. The presently described method of running the pipe 42 downhole with all ports 26a, 26b, 26c closed, except for the end orifice 26d, obviates the need for the additional step of using wash pipe to fill the well with kill fluid. At this point the lower completion has been substantially installed and the well is ready for the next work required to achieve production.

One or more pre-programmed RFID tag(s) is/are then weighted if required, and dropped or flushed into the well with the kill fluid. Alternatively, the tag can be circulated through the pipe 42 to reach the devices 44 with brine or diesel flushed downhole after the kill fluid.

After travelling through the vertical portion 12 and throughbore 40 of the pipe 42, the selectively coded RFID tag reaches the downhole devices 44 that the operator wishes to actuate. The tag passes through the throughbore 40 and the antenna 62 of each device 44. During passage of the RFID tag (not shown) through the middle sub 56, the antenna 62 housed therein 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 processed by the electronics pack.

According to the present example, the RFID tag has been programmed at the surface by the operator to transmit information instructing that each sliding sleeve 100a, 100b, 100c is to be opened. Before running the devices 44 downhole, the timer of each electronics pack was set so as to carry out the actuation command at a predetermined time interval after the command is received. For example, the timer in the electronics pack coupled to the sleeve 100c is set to initiate actuation after one hour. Similarly the timer coupled to sleeve 100d will cause actuation after one hour. In this example, the sleeves 100b, 100a will be actuated after a further 24 and 48 hours respectively, once the timers have received the actuation command.

Thus, one hour after receiving the actuation command from the tag, the penultimate sliding sleeve 100c, before the toe 16 of the well, is moved into the second open configuration. The electronics pack processes the data received by the antenna 62 of the device 44c as described above and recognises a flag in the data which corresponds to an actuation instruction data code stored in the electronics pack. Following the requisite time delay, the electronics pack then instructs the motor 64, powered by the battery pack 66, to drive the hydraulic piston assembly 45 of that downhole device 44.

The motor arm 65 is then rotated in the appropriate direction corresponding to the command from the tag. Thus, the threaded rod 74 is rotated since it is coupled to the motor arm 65 via the coupling 68. The threaded rod 74 rotates through the nut 76 causing axial movement of the nut 74 and the attached piston 80 in a direction towards the motor and gear box 64. Hydraulic fluid is urged out of the chamber 83, through the hydraulic line 72 and into the piston chamber 123 to urge the annular piston 120 in the second direction towards the top sub 46. Simultaneously, hydraulic fluid is drawn out of the piston chamber 121, the volume of which decreases as the annular piston 120 is moved towards the annular step 63. This fluid is drawn into the chamber 89 ahead of the piston 80 as the piston 80 advances towards the motor 64. When this process is complete the annular piston 120 abuts the step 63 and the ports 26c are uncovered to open a path from the interior of the pipe 42 to the annulus surrounding the pipe 42.

According to the present embodiment, the tag is intended to reach the downhole device 44 closest to the toe 16 of the well. The tag contains a command for the sub at the end of the pipe 42 to operate the mechanism in reverse and close the orifices 26d. Therefore, following the requisite time delay, the motor arm 65 is rotated in the opposing direction causing corresponding rotation of the threaded rod 74. The threaded rod 74 rotates through the nut 76 causing axial movement of the nut 74 and the attached piston 80 in a direction away from the motor and gear box 64. Hydraulic fluid is thereby urged out of the chamber 89 ahead of the piston 80, through the hydraulic line 88 and into the piston chamber 121 to urge the annular piston 120 in the first direction towards the bottom sub 96. Simultaneously, hydraulic fluid is pushed out of the piston chamber 123, the volume of which decreases as the annular piston 120 is moved towards the annular step 103. This fluid is drawn into the chamber 83. When this process is complete the orifices 26d are substantially obturated to restrict fluid communication between the interior of the pipe 42 and the annulus surrounding the pipe 42.

Several tags programmed with the same operating instructions for individual devices 44 can be added to the well, so that at least one of the tags will reach the desired antenna 62 enabling the operating instructions to be transmitted. Once the data is transferred to the device 44, the other RFID tags encoded with similar data can be ignored by the antenna 62.

The orifices 26d at the toe 16 of the well are now obturated and the ports 26c are fully open. Thus, reservoir fluids such as hydrocarbons from the formation 10 flow through the sandscreen 24c and the ports 24c and into the throughbore 40 of the pipe 42. A high pressure differential is maintained between the formation 10 and the throughbore 40 of the pipe 42, which allows production of hydrocarbons from the reservoir adjacent the ports 26c without hydrocarbons simply escaping back into the formation 10 via another downstream port 26a, 26b. This is because all downstream ports 26a, 26b are in the closed configuration.

Following the predetermined time delay, the sleeve 100b is moved into the open configuration to uncover the ports 26b and allow production from another part of the formation 10 in the same manner as previously described. The same procedure is subsequently followed to open the ports 26a. The sliding sleeves 100a, 100b, 100c, are shown in the second (open) position in FIG. 3 with the ports 26a, 26b, 26c allowing fluid communication between the exterior of the pipe 42 and the throughbore 40.

In this way ‘sweeping’ of the well over a period of time is possible to produce reservoir fluids from the formation 10 from the toe 16 towards the heel 14 of the well as efficiently as, and at the highest flow rates, possible. This method of production maintains a high pressure differential between the formation 10 and the pipe 42 during production of each phase thereby facilitating production and reducing the need for artificial lift and the likelihood that hydrocarbons will escape back into the formation 10 through a downstream port 26a. It also reduces the probability of gas and water coning.

In practice there are likely to be many more devices 44 spaced axially along the pipe 42 than shown in the schematic on FIG. 3. However, a similar method can be employed. Several devices 44 adjacent a particular part of the formation 10 can be opened simultaneously. Certain devices 44 can remain in the closed configuration if data is gathered to suggest to an operator that an adjacent formation 10 contains mainly gas or water.

According to an alternative embodiment, in order to actuate a specific sleeve, a tag programmed with a specific signal is sent downhole. Each antenna 62 is responsive to the signal of a specific tag. In this way tags can be used to selectively target certain devices 44 by pre-programming antennas 62 and corresponding tags. Thus, several different tags may be provided to target different devices 44. Although, the method of using timers actuated by the tags is preferred, since once a well begins production, it may be difficult to flush further tags downhole to reach the antennae 62 of the devices 44.

The tags may also be designed to carry data transmitted from antennas 62, enabling them to be re-coded during passage through the pipe 42. In particular, useful data such as temperature, pressure, flow rate and any other operating conditions of the device can be transferred to the tag. The antenna 62 can emit a radio frequency signal in response to the radio frequency signal it receives. This can re-code the tag with information sent from the antenna 62.

The method of the invention does not have to be used in conjunction with the specific downhole device 44 described herein. According to an alternative embodiment, the production tubing or pipe 42 is provided with a modified device or tool 44 containing an electrically operated timer device for operating the sliding sleeve. The sliding sleeve is connected to an actuation mechanism incorporating a timer. Thus the pipe 42 can be run downhole with all the ports (except the end open orifices) substantially obturated and following a certain time delay, the sleeves are electrically actuated to move into the open configuration. Upstream sleeves can be programmed to move after a shorter time delay than downstream sleeves so that sweeping of the well is possible.

The length of the time delay is determined according to many factors including the specific well and reservoir conditions. The advantage of the preferred method i.e. using timers in conjunction with RFID tags, is that the sleeve 100 actuation sequence can be initiated as soon as the well is ready to be produced. The timers simply serve to ensure that the well is swept sequentially from the toe 16 to the heel 14. However, if timers alone are used to cause actuation of the sleeves 100 between the closed and the open configurations, then there is no method of initiating production of the well beyond the set predetermined program, once the timers are set and run downhole.

Moreover, an advantage of having a separately programmable electronics pack that communicates with a tag using the antenna 62 is that the devices 44 and the sleeves 100 can be actuated in response to prevailing downhole conditions. This increases the options for future production, without having to pull pipe 42 out of the well or intervene and manipulate the device 44 directly.

According to the above embodiment, the sleeves 100a, 100b, 100c, 100d are described as moveable between a first closed and a second open configuration. However, the sleeves may also be movable to a plurality of intermediate configurations in which the sleeve 100 partially obturates the ports 26 to controllably and selectively restrict or choke but not completely stop the flow of fluid.

Other methods of remote actuation of the devices can be used. For example, the devices can be constructed to respond to pressure pulses, such as mud telemetry, to selectively open or obturate the ports. Alternatively, the devices could be constructed to respond to acoustic or electromagnetic signals. For example, other but different remote control methods of communicating 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 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. According to another embodiment, an alternative downhole tool can be used in preference to the device 44. The tool can comprise an antenna, and a power source and a mechanical means such as a spring can be coupled to a sleeve and actuated in order to move the sleeve between the closed and the open configuration.

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.

Modifications and improvements can be made without departing from the scope of the invention. The ports can be obturated by means other than a sleeve. For example, if the sleeve is part of a sandscreen sub, actuation of the mechanism for moving the obturation member between first and second configurations can cause movement of an annular plate rather then a sleeve to selectively obturate the ports.

Claims

1. A method of preparing a well for production comprising the steps of:

(a) providing a pipe having a throughbore and a plurality of ports spaced axially along the pipe, each port having an associated obturation member;

(b) arranging each port in a closed configuration in which the port is substantially obturated by the obturation member to restrict fluid communication between the throughbore and an annulus surrounding the pipe;

(c) running the pipe into a well with each port in the closed configuration; and

(d) actuating relative movement of at least one of the port(s) and associated obturation members to change at least one port from the closed configuration to an open configuration, in which there is fluid communication between the annulus and the throughbore of the pipe.

2. A method according to claim 1, wherein at least one of the ports is provided on a sub and a plurality of subs are spaced axially along the pipe.

3. A method according to claim 1, wherein in step (c) the pipe is run into a deviated well.

4. A method according to claim 1, wherein in step (d) production commences by opening a fluid flow path from the annulus exterior of the pipe to the throughbore of the pipe.

5. A method according to claim 2, wherein at least two of the subs are actuated to move from the closed configuration to the open configuration.

6. A method according to claim 5, wherein the at least two subs move at different times.

7. A method according to claim 6, wherein the subs are sequentially actuated from the closed to the open configuration.

8. A method according to claim 7, wherein the subs are sequentially actuated to move from the closed configuration to the open configuration from a toe of the well towards a heel of the well.

9. A method according to claim 2, wherein the method further includes the step of providing an end sub having an orifice located towards or at a leading end of the pipe and performing step (c) with the said orifice in the open configuration.

10. A method according to claim 9, wherein the method further comprises the step of associating an obturation member with the orifice and actuating relative movement of the obturation member and the orifice to move the end sub into a closed configuration prior to or during step (d).

11. A method according to claim 2, wherein each sub is incorporated as part of a sandscreen sub.

12. A method according to claim 11, wherein the sandscreen can be coaxial with the pipe.

13. A method according to claim 11, wherein the size of the sandscreen mesh is determined according to the maximum acceptable size of formation particles travelling through the port and in the pipe.

14. A method according to claim 1, wherein the method further includes the step of stabilising the well following step (c) by circulating fluid through the pipe.

15. A method according to claim 14, wherein the fluid is a high density fluid or mud such as kill fluid, selected to substantially restrict a pressure blow out of the well.

16. A method according to claim 1, wherein the method further includes the step of remotely actuating relative movement of the obturation member and the port(s).

17. A method according to claim 16, wherein the relative movement is remotely actuated without need for either electric or hydraulic cables run all the way from the surface to the subs and also without need for intervention equipment to be deployed into the well to manually shift each respective obturation member.

18. A method according to claim 2, wherein the method further includes the step of incorporating a reader or signal sensor into each sub and method step (d) can be achieved by circulating at least one tag through the reader, wherein the at least one reader is arranged to read data from the tag when the tag passes therethrough.

19. A method according to claim 18, wherein the tag and the reader communicate using radio frequency identification.

20. A method according to claim 19, wherein the reader is arranged coaxial with the sub and the pipe.

21. A method according to claim 1, wherein relative movement of the obturation member and associated port(s) is electronically actuated.

22. A method according to claim 1, wherein the method includes the step of coupling each obturation member to a timer and actuating relative movement of the obturation member and associated port(s) following a predetermined time delay.

23. A method according to claim 1, wherein the method further includes actuating relative movement of the obturation member and the port(s) into an intermediate configuration in which the obturation member partially obturates the port(s) to thereby choke the ports.

24. (canceled)

25. A production string for inclusion in a well comprising:

(a) a pipe having a throughbore and at least one port spaced axially along the pipe, each port having an associated obturation member;

(b) the obturation member being adapted to selectively obturate and open the port to respectively restrict and permit fluid communication between the throughbore and an annulus surrounding the pipe in use of the production string;

(c) a signal transmission means capable of transmitting signals from the surface of the well to the obturation member, wherein said signals contain instructions to move the obturation member between the obturate and open configurations; and

(d) a downhole power mechanism capable of moving the obturation member when instructed to do so by the signal transmission means.

26. A production string apparatus according to claim 25, wherein at least one of the ports is provided on a sub and a plurality of subs having ports are spaced axially along the pipe.

27. A production string apparatus according to claim 26, wherein each sub is incorporated as part of a sandscreen sub.

28. A production string apparatus according to claim 27, wherein the sandscreens are coaxial with the pipe.

29. A production string apparatus according to claim 28, wherein the size of the sandscreen mesh is determined according to the maximum acceptable size of formation particles travelling through the port and in the pipe.

30. A production string apparatus according to claim 26, wherein the signal transmission means is a wireless signal transmission means without need for either electric or hydraulic cables run all the way from the surface to the subs and also without need for intervention equipment to be deployed into the well to manually shift each respective obturation member.

31. A production string apparatus according to claim 26, wherein the signal transmission means comprises a reader or signal sensor associated with each sub and at least one tag capable of being circulated through the reader, wherein the at least one reader is arranged to read data from the tag when the tag passes therethrough.

32. (canceled)

33. A downhole power device for use downhole in a wellbore, the downhole power device comprising a tubular body housing incorporating:

a driver;

a power source arranged to supply power to the driver; and

an actuator for selectively actuating the driver;

wherein the tubular body includes two or more cylindrical bores extending parallel to the longitudinal axis of the body, and formed in a sidewall of the body, one of said cylindrical bores for housing at least one of the power source, the actuator and the driver and another of said cylindrical bores for housing at least another of the power source, the actuator and the driver.

34. A downhole power device according to claim 33, further comprising a hydraulic system including a piston sealed in a chamber, wherein the piston is connected to the driver and is moveable upon actuation of the driver.

35. A device according to claim 33, wherein the cylindrical bores extend from one end of the tubular parallel to a longitudinal axis.

36. A device according to claim 33, wherein a plug is provided to substantially seal the ends of the bores following insertion of at least one of the power source, the actuator, the driver and the hydraulic system in the bores.

37. A device according to claim 33, wherein one cylindrical bore accommodates a power source.

38. A device according to claim 37, wherein the power source is a battery.

39. A device according to claim 39, wherein another cylindrical bore accommodates the driver and hydraulic system.

40. A device according to claim 33, wherein the driver is a motor.

41. A device according to claim 40, wherein the motor comprises a gearing mechanism to step up the torque provided by the motor.

42. A device for use downhole comprising a body housing:

a power source arranged to supply power to a driver; and

a hydraulic system including a piston sealed in a chamber and an outlet provided at each opposing end of the chamber wherein each outlet is in communication with a respective reservoir;

and wherein the driver is actuable to drive the piston in a first direction, such that fluid is driven out of the chamber through one outlet and simultaneously fluid is drawn into the chamber through the other outlet at the opposing end.

43. A device according to claim 42, wherein the hydraulic system is a closed hydraulic system.

44. A device according to claim 42, wherein the driver is actuable to drive the piston in a second direction, such that fluid is driven out of the chamber through one outlet and simultaneously fluid is drawn into the chamber through the other outlet at the opposing end.

45. A device according to claim 42, wherein each outlet also functions as an inlet.

46. A device according to claim 42, wherein the body is a tubular body.

47. A device according to claim 46, wherein the tubular body is an element in a pipe string.

48. A device according to claim 46, wherein the hydraulic system, the power source and the driver are housed in a sidewall of tubular body.

49. A device according to claim 42, wherein the device also comprises an actuator wherein the actuator is arranged to selectively actuate the driver.

50. A device according to claim 49, wherein the tubular body includes one or more cylindrical bores extending parallel to the longitudinal axis of the body for housing at least one of the power source, the actuator, the driver and the hydraulic system.

51. A device according to claim 50, wherein the cylindrical bore(s) extend from one end of the tubular parallel to a longitudinal axis.

52. A device according to claim 49, wherein a plug is provided to substantially seal the ends of the bore(s) following insertion of at least one of the power source, the actuator, the driver and the hydraulic system in the bore(s).

53. A device according to claim 50, wherein one cylindrical bore accommodates a power source.

54. A device according to claim 53, wherein another cylindrical bore accommodates the driver and hydraulic system.

55. A device according to claim 42, wherein the power source is a battery.

56. A device according to claim 42, wherein the driver is a motor.

57. A device according to claim 56, wherein the motor includes a gearing mechanism to step up the torque provided by the motor.

58. A device according to claim 42, wherein the driver is coupled to a rod arranged to drive the piston.

59. A device according to claim 58, wherein the rod is a threaded rod and the rod and the piston are rotatable relative to each other such that rotation of the rod causes axial movement of the piston in the chamber.

60. A device according to claim 42, wherein the device incorporates a second piston.

61. A device according to claim 42, wherein the outlets at each end of the chamber are in fluid communication with opposing sides of the second piston, thus actuation of the driver in one direction causes resultant movement of the second piston in one direction.

62. A device according to claim 60, wherein the area of the second piston on which hydraulic fluid acts is greater relative to the area of the piston in the hydraulic system on which hydraulic fluid acts.

63. A device according to claim 60, wherein the second piston is an annular piston.

64. A device according to claim 60, wherein the second piston forms part of a sliding sleeve.

65. A device according to claim 49, wherein the actuator is coupled to the power source.

66. A device according to claim 49, wherein the actuator includes a reader electrically coupled to an electronics pack, wherein the reader is arranged to read a signal from a remote source and wherein the signal is processed by the electronics pack to selectively actuate the driver.

67. A device according to claim 66, wherein the reader comprises an antenna arranged to remotely communicate using radio frequency identification.

68. A device according to claim 49, wherein the actuator comprises an electronic circuit and a timer switch coupled to the driver to actuate the driver after a predetermined period of time.

69. (canceled)