Method to manipulate a well using an underbalanced pressure container

Abstract

A method to manipulate a well comprising providing an apparatus (60) in a well (14) below a packer (22) or other annular sealing device, the apparatus comprising a container (68) having a volume of gas which is sealed at the surface and nm into the well, such that the pressure in the container (68) is at a lower pressure than the surrounding well. When the apparatus is below the packer, a wireless control signal, is sent to operate a valve assembly (62) to selectively allow fluid to enter the container whereby at least 50 litres of fluid is drawn into the container. In this way, the apparatus can be used independent of perforating guns, to clear perforations or other areas in the well or may be used for a variety of tests such as an interval test, drawdown test or a connectivity test such as a pulse or interference test.

Claims

1. A method to manipulate a well, comprising: providing a pressure sensor in the well; providing an apparatus in the well below an annular sealing device, the annular sealing device engaging with an inner face of one of a casing and a wellbore in the well, and being at least 100 m below a surface of the well, providing a connector for connecting the apparatus to the annular sealing device, the connector being above the apparatus and below the annular sealing device; the apparatus comprising: a container having a volume of at least 50 litres (l); a port to allow pressure and fluid communication between an inside and an outside of the container; a mechanical valve assembly having a valve member adapted to move and one of to selectively allow and to selectively resist fluid entry into at least a portion of the container, via the port; a control mechanism to control the mechanical valve assembly, comprising a communication device configured to receive a control signal for moving the valve member; sealing the container at the surface, at least a portion of the container being at least one of being evacuated and having at least 85 vol % gas; and then deploying it into the well such that the apparatus moves from the surface into the well below the annular sealing device with the container sealed; the pressure in at least a portion of said inside of the container being less than said outside of the container for at least one minute prior to moving said valve member; sending a control signal from above the annular sealing device to the communication device at least in part by a wireless control signal transmitted in at least one of the following forms: electromagnetic and acoustic; moving the valve member in response to said control signal to allow fluid to enter the container; and, drawing in at least 5 l of fluid into the container caused by the pressure in at least a portion of said inside of the container being less than said outside of the container for at least one minute.

2. A method as claimed in claim 1, wherein the valve member is moved at least two minutes before and/or at least two minutes after, any perforating gun-activation.

3. A method as claimed in claim 1, wherein the pressure sensor is below the annular sealing device and the pressure sensor is coupled to a wireless transmitter and data is transmitted from the wireless transmitter, to above the annular sealing device in at least one of the following forms: electromagnetic and acoustic.

4. A method as claimed in claim 1, wherein a barrier is provided in the well and the port of the apparatus is provided below the barrier when the valve is moved to allow fluid to enter the container.

5. A method as claimed in claim 4, wherein at least a section of the well has been one of suspended and abandoned below the barrier.

6. A method as claimed in claim 1, wherein the apparatus is conveyed on one of tubing, drill pipe and casing/liner, and wherein the apparatus is optionally deployed into the well in the same operation as deploying the annular sealing device into the well.

7. A method as claimed in claim 1, wherein the well is shut in, at one of surface and downhole, after the apparatus has been run and before the valve member moves in response to the control signal.

8. A method as claimed in claim 1, wherein the annular sealing device is a first annular sealing device and the port of the apparatus is provided above a second annular sealing device.

9. A method as claimed in claim 8, including conducting a short interval test and wherein the first annular sealing device and the second annular sealing device are less than 10 m apart, optionally less 5 m, or less than 2m, or less than 1 m, or less than 0.5 m apart.

10. A method as claimed in claim 1, including using the apparatus to conduct one of an interval test, drawdown test, flow test, build-up test, pressure test, and a connectivity test such as one of a pulse and interference test.

11. A method as claimed in claim 1, also comprising conducting a procedure on the well wherein the procedure includes at least one of image capture, a build-up test, drawdown test, connectivity test such as an one of an interference and a pulse test, flow test, pressure test, drill stem test (DST) extended well test (EWT), well/reservoir treatment such as an acid treatment, interval infectivity test, permeability test, hydraulic fracturing or minifrac procedure, injection procedure, gravel pack operation, perforation operation, string deployment, workover, suspension and abandonment.

12. A method as claimed in claim 1, wherein the well is a gas well, and the apparatus is used to draw in fluid from the well into the container to reduce the hydrostatic head of a lower section of a zone.

13. A method as claimed in claim 1, wherein the container comprises a fluid chamber in fluid communication with the port, and a dump chamber and wherein the control mechanism controls fluid communication between the fluid chamber and the dump chamber.

14. A method as claimed in claim 1, wherein the apparatus comprises a choke optionally one of fixed and adjustable.

15. A method as claimed in claim 1, wherein the container has a volume of at least 100 l and at least 100 l of well fluid is drawn into the container.

16. A method as claimed in claim 1, wherein in addition to the container, there is at least one secondary container having a volume of at least 1 l, the at least one secondary container having a control device for controlling communication between an inside and an outside of the secondary container, wherein the control device includes a mechanical valve assembly, and wherein the pressure inside the secondary container is higher than an outside the secondary container.

17. A method as claimed in claim 1, wherein in addition to the container, there is at least one secondary container having a volume of at least 1 l, the at least one secondary container having a control device for controlling communication between an inside and an outside of the secondary container, wherein the control device includes a mechanical valve assembly, and the apparatus comprises a pump which pumps fluid to/from an inside of the at least one secondary container from/to an outside of the secondary container.

18. A method as claimed in claim 1, wherein the control mechanism is configured to be controllable by the control signal more than 24 hours after being run into the well, optionally more than 7 days, more than 1 month, more than 1 year or more than 5 years.

19. A method as claimed in claim 1, wherein the container is defined, at least in part, by one of casing and liner.

Description

(1) Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying figures in which:

(2) FIG. 1 is a schematic view of a first apparatus which may be used in the method of the present invention;

(3) FIG. 2 is a schematic view of a second apparatus including a floating piston and a choke insert which may be used in a method in accordance with the present invention;

(4) FIG. 3 is a schematic view of a well illustrating a method in accordance with an embodiment of the present invention;

(5) FIG. 4 is a schematic view of a well with multiple zones, illustrating another aspect of the present invention;

(6) FIG. 5 is a schematic view illustrating an apparatus used in an interval test in accordance with one aspect of the present invention;

(7) FIG. 6 is a cut-away schematic view of a further embodiment of an apparatus which may be used in the method illustrated in FIGS. 3 and 4; and,

(8) FIG. 7 is a front view of an embodiment of a valve assembly for use with the various apparatus whilst conducing the method in accordance with the present invention.

(9) FIG. 1 shows the apparatus 60 in accordance with the present invention in the form of a modified pipe formed from three (or more) lengths of drill pipe and comprising a side opening 61, a valve 62, a control mechanism comprising a valve controller 66 and a wireless receiver (or transceiver) 64, a battery 63 and a container 68 with a volume capacity of, for example, 1000 litres. There is an underbalance (for example 1000 psi) of pressure between the container 68 and a surrounding portion of a well. (The breadths of the apparatus here and in other figures have been exaggerated for ease of illustration.)

(10) A battery 63 is provided in the apparatus 60 which serves to power components of the apparatus 60 for example the valve controller 66 and the transceiver 64. Often a separate battery is provided for each powered component.

(11) The apparatus 60 also comprises a valve 62. The valve 62 is configured to isolate the opening 61 to seal the container 68 from the surrounding portion of the well in a closed position and allow pressure and fluid communication between a portion of the container 68 and the surrounding portion of the well via the side opening 61 in an open position.

(12) The valve 62 is controlled by the valve controller 66. The transceiver 64 is coupled to the valve controller 66 which is configured to receive a wireless control signal. In use, the valve 62 is moved from the closed position to the open position in response to the control signal.

(13) The components of the control mechanism (the transceiver 64 and the valve controller 66 which controls the valve 62) are normally provided adjacent each other, or close together as shown; but may be spaced apart.

(14) In some embodiments, the container 68 is filled with a gas, such as air, initially at atmospheric pressure. In such embodiments, the gas is sealed in the container at the surface before being run into the well to create an underbalance of pressure between the container and the surrounding portion of the well (which is at a higher pressure than atmospheric pressure on the surface).

(15) FIG. 2 shows an embodiment of the apparatus 160. Like parts with the FIG. 1 embodiment are not described in detail but are prefixed with a ‘1’. Whilst not illustrated, the apparatus 160 may also be formed from adjoined drill pipe as illustrated in FIG. 1. However, in contrast to the embodiment shown in FIG. 1, FIG. 2 shows an embodiment of an apparatus 160 wherein a control valve 162 and a choke 176 are located in a central portion of the apparatus in a port 163 between two sections of the container 168—a fluid chamber 167 and a dump chamber 169.

(16) The floating piston 174 is located in the container 168 above the control valve 162. The fluid chamber 167 is initially filled with oil below the piston 175 through a fill port (not shown).

(17) In the present embodiment the floating piston 174 functions as the valve assembly having a valve member to allow or resist fluid entry into the fluid chamber 167 of the container 168. When the floating piston 174 is located at the top of the fluid chamber 167 it isolates/closes the fluid chamber 167 from the surrounding portion of the well, and when the floating piston 174 is located at the bottom of the fluid chamber 167 the opening 161 allows fluid to enter the fluid chamber 167 via flow port 165 from outside of the container, normally the surrounding portion of the well. The location of the floating piston 174 is controlled indirectly by the flow of fluid through the control valve 162, which is in turn controlled via signals sent to a valve controller 166.

(18) In use, the sequence begins with the control valve 162 in the closed position and the floating piston 174 located towards the top of the fluid chamber 167. Due to an underbalance of pressure (for example 1000 psi) in the dump chamber 169 of the container 168, the fluid in the well attempts to enter the fluid chamber 167 via the opening 161 but is resisted by the floating piston 174 and oil therein whilst the control valve 162 is in the closed position. A signal is then sent to the valve controller 166 instructing the control valve 162 to open. Once the control valve 162 opens, oil from the fluid chamber 167 is directed into the dump chamber 169 by the well pressure acting on the floating piston 174, and fluids from the surrounding portion of the well are drawn into the fluid chamber 167. The rate at which the oil in the fluid chamber 167 is expelled into the dump chamber 169, and consequentially the rate at which the fluids from the well can be drawn into the container 168, is controlled by the cross-sectional area of the choke 176. In alternative embodiments, the choke 176 and control valve 162 positions can be in the opposite order to that illustrated, or may be combined. Indeed the control valve 162 can be at the port 161, albeit it is preferred to have the choke 176 between the fluid chamber 167 and dump chamber 169. In this way, the choke 176 and oil regulates the flow of fluid into the fluid chamber 167 irrespective of the properties, such as the density or viscosity, of the well fluids.

(19) This embodiment is particularly suited for flow tests or short interval tests (see FIG. 5) where flow in a controlled manner is desirable.

(20) FIG. 3 and FIG. 4 shows the apparatus 60 of FIG. 1 positioned in a well and activated to draw in fluid in order, for example, to attempt to clear debris from a local area.

(21) FIG. 3 shows a well 14 with well apparatus 10 including an annular sealing device having a packer element 22 provided between the well and upper 18 and lower 16 tubulars. The tubulars 16, 18 have a longitudinal bore and extend below and above the packer element 22, which is one type of annular sealing device. The tubing 16 and perforating gun 50 serve as a connector to connect the apparatus 60 to the annular sealing device.

(22) The well apparatus 10 also includes an apparatus 60 below the packer element 22. The apparatus 60 and other like parts have been previously described in FIG. 1.

(23) The well apparatus 10 can be used during a drill stem test (DST). The apparatus 60 is activated prior to the DST and after perforating guns 50 have created perforations 52 in the lower tubular 16. Once the perforations 52 have been created, there is often debris in the well 14 which could inhibit the flow of fluids and potentially block, or partially block, the communication paths, such as perforations, between the well 14 and the reservoir 51. The container 68 is underbalanced, therefore opening the valve 62 causes a surge of fluid into the container 68. It is an advantage of certain embodiments of the present invention that the apparatus 60 is activated after creating the perforations to help clear the well of debris, thus helping to mitigate the problem of a blocked, or partially blocked, communication path, which could inhibit flow and so compromise the accuracy of data from the DST.

(24) This embodiment of the invention will now be described in more detail.

(25) The illustrated well 14 is a substantially vertical well comprising liner string 12a and a casing string 12b. Inside each of the liner/casing strings 12a, 12b there is an annulus 90A & 90B respectively. The well 14 includes a liner hanger 29. The liner hanger 29 is part of a liner hanger assembly from which the liner string 12a can be hung.

(26) The liner string 12a contains perforations 52 in the lower part of the well 14 which allows well fluids to flow into the well. The packer element 22, along with a packer upper tubular 26 and a packer lower tubular 24, makes up a packer 20.

(27) A perforating gun 50 is provided on the lowermost part of the lower tubular 16 to create perforations 52 in the liner string 12a. The perforating gun 50 may be wirelessly activated by wireless signals, independent of activation of the apparatus 60.

(28) The packer 20 is a temporary packer which is run into the well 14 with the tubulars 16, 18 such that it is provided between the liner string 12a and the tubulars 16, 18. In use, it is activated to expand and set against the liner string 12a to create a longitudinal seal between the tubulars 16, 18 and the A-annulus.

(29) An instrument carrier 41 is provided on the lower tubular 16. The instrument carrier 41 comprises a pressure sensor 43 which is coupled physically and/or wirelessly to a wireless relay 45. The relay 45 comprises a transceiver which can transmit data from below the packer element 22 and send it onwards, such as towards the surface of the well, optionally via relays 44, 48 on further instrument carriers 40, 46 provided on the upper tubular 18. These further instrument carriers 40, 46 also comprise pressure sensors 42, 49 which are coupled to the wireless relays 44, 48. The relays 44, 48 comprise transceivers which can also receive control signals from the surface and send it below the packer element 22 to the transceiver 64 of the valve controller 66, optionally via the wireless relay 45.

(30) A discrete temperature array 53 is provided adjacent to the perforations 52 and connected to a controller 55. In this embodiment the array has multiple discrete temperature sensors along the length of a small diameter tube.

(31) A tester valve 30 is provided in the upper tubular 18 above the packer element 22. The well apparatus 10 further comprises a flow sub 32 which provides a flowpath between the well and the longitudinal bore of the tubulars 16 & 18, and also the tester valve 30.

(32) The tester valve 30 is configured to allow or resist the flow of fluids through the tubular 18. Together with the packer 22, they form isolating components.

(33) The apparatus 60 is located below the packer 20 and also below the perforating guns 50.

(34) The transceiver 64 coupled to the valve controller 66 is configured to receive a wireless control signal, and also to transmit data from the apparatus 60 below the packer element 22 to above the packer element 22.

(35) During a DST, the tester valve 30 can be instructed to close to allow the build-up of pressure in the reservoir and the well 14 beneath the packer element 22. The build-up of pressure can be monitored for useful data. Upon re-opening the tester valve 30, the flow of well fluids can also provide useful data. The data can be indicative of information on reservoir properties, such as the reservoir pressure, and recoverable reserves.

(36) During production or for a DST, after the liner string 12a has been perforated by the perforating guns 50, well fluids can flow into the well 14 via the perforations 52 and into the lower tubular 16 via the ports in the flow sub 32. The fluids pass through the lower tubular 16 towards the upper tubular 18 and then continue, via the tester valve 30, towards the surface.

(37) However, after the perforating guns 50 have fired, there is often debris in or around the perforations which could inhibit the flow of fluids to the surface. The apparatus 60 can be used to create a pressure surge into the container 68 to clear the debris before testing or production.

(38) In use, there is an underbalance of pressure between the container 68 and the surrounding portion of the well. After the valve 62 is opened to allow pressure and fluid communication between the portion of the container 68 and the surrounding portion of the well, there is a surge of fluid into the container 68, due to this negative pressure. This rapid drawdown can help to clear debris from the well in the vicinity of the apparatus 60, such as debris from the perforations.

(39) It may also be an advantage of certain embodiments of the present invention that the reliability and/or quality of data received from the well after the debris is cleared is improved, such as during a DST. Furthermore, it may be an advantage of embodiments of the present invention that the pressure connectivity in the well is improved which can subsequently improve the flow rate from the reservoir.

(40) If the well 14 is suspended or abandoned or if specific zone(s) are shut-in after the DST, it is an advantage of certain embodiments to have an apparatus 60 in the well 14, because it can be used to clean the perforations and/or pores of the formation to improve the quality of the data received from monitoring the reservoir. This is especially useful where there is an overbalance of “kill” fluid in the well 14 as this can result in the pores of the formation being blocked, or partially blocked, by sediment which has come out of the fluid. In certain circumstances an operator may kill the well, retrieve the string, and run an observation string with the apparatus 60 and the container 68 but not the guns. In such circumstances, there may be remnants of sediment inhibiting the pressure connectivity from the reservoir and the apparatus 60 can be activated to improve connectivity.

(41) A corrosion sensor may be provided in the well, especially where the well is to be monitored for an extended period of time.

(42) Alternatively, rather than retrieve the string, the apparatus 60 (and optionally other elements of the string) may be left in the well and activated at a later date, for example 6 months later.

(43) For alternative embodiments, the apparatus 60 can be activated at any time not just prior to the DST.

(44) FIG. 4 shows an alternative embodiment of the present invention. Where the features are the same as FIG. 3 they have been labelled with the same number except preceded by a “1”. These features will not be described in detail again here.

(45) FIG. 4 shows a well 114 comprising a liner hanger 129 and a liner string 112a and two sets of apparatus 60a and 60b, including the features of the apparatus 60 described in FIG. 1 and FIG. 3. The well 114 also comprises an upper annular sealing device comprising an upper packer element 122a, a wirelessly controlled upper sleeve valve 134a, an upper apparatus 60a as well as the upper slotted liner 154a. The well 114 further comprises a lower annular sealing device comprising a lower packer element 122b, a wirelessly controlled lower sleeve valve 134b, a lower apparatus 60b and a lower slotted liner 154b. The tubing 118 connects the apparatus 60a to the upper annular sealing device, and the tubular 116 connects the apparatus 60b to the lower annular sealing device.

(46) Thus this embodiment comprises a multi-zone well 114 with well apparatus 110 which comprises two packer elements 122a & 122b which splits the well into two sections. The first, upper section comprises the upper packer element 122a, the upper sleeve valve 134a, the upper apparatus 60a and the upper slotted liner 154a. The second, lower, section comprises the lower packer element 122b, the lower sleeve valve 134b, the lower apparatus 60b and the lower slotted liner 154b.

(47) The slotted liners 154a, 154b create communication paths between the inside of the liner 154 and the adjacent formation.

(48) The well 114 further comprises a packer such as a swell packer 128 between an outer surface of the liner string 112a and a surrounding portion of the formation.

(49) The upper tubular 118 and lower tubular 116 are continuous and connected via the upper packer element 122a and the lower packer element 122b.

(50) The first and second sections contain well apparatus which is run into the well on the same string, that is on the tubulars 116,118.

(51) Instrument carriers 140, 141 and 146 are provided in each section and also above the packer element 122a. Each instrument carrier comprises a pressure sensor 142, 143, and 148 respectively, and a wireless relay 144, 145, and 149 respectively.

(52) Isolating the sections from each other provides useful functionality for manipulating each adjacent zone individually.

(53) In use, the well 114 flows from a lower zone through the lower slotted liner 154b and into the lower tubular 116 via the sleeve valve 134b. The flow continues through the lower tubular 116 past the lower packer element 122b, the upper apparatus 60a and instrument carrier 146 before continuing through the upper tubular 118 towards the surface. Thus in contrast to the FIG. 3 embodiment, the apparatus 60a is configured to allow flow through the tubing without the need to divert the flow outside thereof, since it does not take up the full bore of the upper tubular 118.

(54) From an upper zone, the well flows through the slotted liner 154a and into the upper tubular 118 via the sleeve valve 134a. The flow continues through the upper tubular 118, past the upper packer element 122a towards the surface.

(55) In use, the flow may be from the upper zone adjacent the well 114 only, the lower zone adjacent the well 114 only or may be co-mingled, that is produced from the two zones simultaneously. For example, fluids from the slotted liner 154b combine with further fluids entering the well 114 via the upper slotted liner 154a to form a co-mingled flow.

(56) The features of the FIG. 4 embodiment are especially suitable to being used in production, injection, well testing or observation operations. For example, in certain embodiments, the apparatus can be used to help clean the perforations and the pores of the formation prior to flowing the well or after initial flow.

(57) In other embodiments, after a zone has been shut-in or killed it can then be reopened or monitored to perform a connectivity test between the upper and lower zones or other wells. In such embodiments, the apparatus can be used to help clear the communication paths of the “kill” fluid or clear other formation damage.

(58) A pressure gauge can monitor the pressure within the containers. Moreover, the gauges or other devices can be powered by the battery.

(59) In some embodiments, the lower packer element 122b is a permanent packer with a polished bore on the inner face which engages with the seals on the tubular 116, and together they form an annular sealing device.

(60) FIG. 5 shows such a short interval test using the apparatus 160 as previously described in FIG. 2. Where the well features are the same as previous FIGS. 3 and 4 they have been labelled with the same number except preceded by a “2”. These features will not be described in detail again here.

(61) Annular sealing devices in the form of packer elements 222a and 222b are set in the casing 212, and a perforating tool 250 receives a wireless signal to activate and punch a hole 252 in the casing 212 and adjacent formation 251.

(62) The apparatus 160 then receives a control signal to open the valve 162 and the container 168, which has an underbalanced portion 169, receives flow in a controlled manner from the perforated interval 252 between the two packer elements 222a and 222b. Pressure is monitored by a pressure sensor 243 before the valve 162 is opened, and as the flow enters the fluid chamber 167 above the floating piston 174. Concurrently a control fluid, such as oil, moves through the valve 162 from the fluid chamber 167 (below the floating piston 174) into the dump chamber 169.

(63) The valve 162 is closed before significant pressure has built up in the dump chamber 169. This maintains a more constant pressure differential between the dump chamber 169 and fluid chamber 167, which in turn provides a more constant flow rate of fluids entering the fluid chamber 167 and so provides more meaningful data.

(64) In alternative embodiments, the valve 162 is not closed, but instead the piston abuts against the lower extent 167B of the fluid chamber 167. For such embodiments, the valve 162 can thus be a relatively simple single-shot valve.

(65) A relatively limited flow test can thus be conducted in the short interval between the packer elements 222a, 222b. Data from pressure sensors 243 or other sensors in communication with the short interval, such as between the two packer elements 222a, 222b or below the lower packer element 222b in the flow port 165, can provide useful flow test information. This can obviate the need to conduct a time consuming and much more expensive procedure of a full well test, or even a closed chamber test where well fluids are displaced at the surface. Data from the pressure sensor(s) can be transmitted wirelessly, for example by acoustic or electromagnetic signals, to the surface for monitoring.

(66) A variety of alternatives are available for such a flow test of a short interval. Two or more such flow tests can be conducted. In one embodiment, the valve 162 can be opened again and more fluid enters the fluid chamber 167, and this open/close sequence can be repeated until the fluid chamber 167 is full. Alternatively or additionally, further underbalanced containers may be provided to conduct the further flow test. In either case, an operator can unseat the packer elements 222a, 222b, reposition the apparatus 160, re-seat the packer elements 222a, 222b, and then conduct a subsequent flow test of a different short interval.

(67) In one alternative embodiment, a pump controls the port 163 (or a further port) between the fluid chamber 167 and the dump chamber 169. This can be operated after the procedure described above, to pump fluid from the dump chamber 169 back into the fluid chamber 167, and the apparatus 160 can be used again. Indeed, for such embodiments, the port 161 can have an outlet to annulus area 291A below the packer element 222b. When the control fluid is pumped back into the fluid chamber 167 (below the floating piston 174) the fluid above the floating piston 174, previously taken from the interval, can be exhausted into the annulus area 291A, outwith the interval and below the packer element 222b.

(68) As a further option, a second underbalanced container is provided, preferably configured as the container 60 shown in FIG. 1. This can be used to purge the interval, before the apparatus 160 is used to conduct the flow test on the short interval, as described above.

(69) After the short interval test, it may be useful to control the interval by adding ‘kill’ fluid. Optionally therefore, a sleeve valve 230 can be provided between the tubing string 218 and surrounding annulus 290A which can be opened to allow pressure connectivity between the interval and the string above, for example to allow kill fluid to enter the interval.

(70) The apparatus 60, 160 can be used in a variety of wells and are not limited to the illustrated examples.

(71) In FIG. 6, an alternative embodiment of an apparatus 260 with a container 268 is illustrated. Common features with earlier embodiments are not described again for brevity. In contrast to earlier figures the container 268 with a valve 262 is in part defined by the surrounding casing 212. Such an apparatus 260 is normally run on the casing 212 when completing the well. An advantage of such an embodiment is that the container can have larger volumes without running further tubing into the well. The apparatus 260 may have flow bypass 92 controlled by a pump 93 for cementing during completion. Such embodiments are useful for clearing a toe of a horizontal well.

(72) Moreover, embodiments can be used to clear liquid, such as water, from a gas well. In certain situations, a gas well produces from an upper zone, or section of a zone and a liquid column resists gas production from a lower zone, or section of a zone which has insufficient pressure to overcome the combined hydrostatic head of the liquid column and pressure of the upper zone, or section of a zone. The liquid column is thus ‘trapped’ in the well and prevents production from a lower zone, or section of a zone. Certain embodiments of the present invention, such as the FIG. 6 embodiment, can be used to remove a portion of the liquid column to allow the lower zone, or section of a zone to produce.

(73) A variety of valves may be used with the apparatus described herein. FIG. 7 shows one example of a valve assembly 500 in a closed position A and in an open position B. The valve assembly 500 comprises a housing 583, a first inlet port 581, a second outlet port 582 and a valve member in the form of a piston 584. The valve assembly further comprises an actuator mechanism which comprises a lead screw 586 and a motor 587.

(74) The first port 581 is the inlet and the second port 582 is the outlet. The first port 581 is on a first side of the housing 583 and the second port 582 is on a second side of the housing 583, such that the first port 581 is at 90 degrees to the second port 582.

(75) The piston 584 is contained within the housing 583. Seals 585 are provided between the piston 584 and an inner wall of the housing 583 to isolate the first port 581 from the second port 582 when the valve assembly 500 is in the closed position A; and also to isolate the ports 581, 582 from the actuator mechanism 586, 587 when the valve assembly is in the closed A and/or open B position.

(76) The piston 584 has a threaded bore on the side nearest the motor 587 which extends substantially into the piston 584, but does not extend all the way through the piston 584. The lead screw 586 is inserted into the threaded bore in the piston 584. The lead screw 586 extends partially into the piston 584 when the valve assembly 500 is in the closed position A. The lead screw 586 extends substantially into the piston 584 when the valve assembly is in the open position B.

(77) In use, the valve assembly is initially in the closed position A. A side of the piston 584 is adjacent to the first port 581 and a top side of the piston 584 is adjacent to the second port 582 so that the first port 581 is isolated from the second port 582. This prevents fluid flow between the first port 581 and the second port 582. Once the actuator mechanism receives a signal instructing it to open the valve, the motor begins to turn the lead screw 586 which in turn moves the piston 584 towards the motor 587. As the piston 584 moves, the lead screw 586 is inserted further into the piston 584 until one side of the piston 584 is adjacent to the motor 587. In this position, the first port 581 and the second port 582 are open and fluid can flow in through the first port 581 and out through the second port 582.

(78) Modifications and improvements can be incorporated herein without departing from the scope of the invention. For example various arrangements of the container and electronics may be used, such as electronics provided in the apparatus below the container.

(79) Alternative embodiments may transmit from the apparatus to the surface without relays, especially those using EM communication. The relays may be provided in other positions in the well such as the casing.

(80) Moreover, whilst the chokes illustrated here are reduced diameter chokes, other forms of chokes can be utilised, for example an extended section with a restricted diameter.