GB2342665A - Production optimisation tool for wellbore operating system - Google Patents

Abstract

A wellbore operating method and system in which a casing, tubing and an annulus defined therebetween serve to extract fluid products from below the surface of the earth via at least one producing formation communicating with the tubing, in which a fluid pressure operated control device is selectively placed in the wellbore to control a particular isolated formation and having choke devices to regulate the flow and pressure drop from the formation, said device having its operation controlled from the surface via a fluid pressure control line and also having a piston arranged to provide a pressure imbalance at the surface which can be interpreted as a downhole measurement of the wellbore.

Description

PRODUCTION OPTIMISATION TOOL This invention relates to a production optimisation tool for use in a method and a system for extraction of fluid products from below the surface of the earth.

In the petrochemical industries, oil, gas and water wells allow the extraction of products from below the surface of the earth. The wells may be drilled to a great depth amnd are periodically cased with a large diameter metal pipe called"casing", in order to avoid collapse of the newly drilled hole. The wells are normally completed with a pressure sealing conduit called"tub~ng"which runs from the wellhead or xmas tree valve assembly on surface to near the bottom of the well. Both ends are sealed in order to provide a pressure tight communication between the surface facilities and the producing formation (a typical wellbore production system is shown in Figure 1). The wellhead will seal this casing/tubing annulus at the surface and a device called a packer will seal pressure downhcle near the producing. formations. Often there will be many producing formations at different depths in the wellbore below the packer. These producing formations each may have differing concentrations of oil/gas an water ad may contain these elements at a variety of pressures. In order to prevent or minimise flow from one zone to another and to assist efficient flow to surface, the wellbore ana production facilities must be properly managed.

Efficient extraction of wellbore fluids and gasses may be significantly assiste by monitoring such parameters as flow rate, gas/oil/water ratio, wellhead pressure and bottom hole pressure. Mih ~.. e exce-~ion of bottom hole pressure, most other measurements are ava'table on surface relatively easily. Bottem hele pressure may be recorded on a wireline set and retrievable pressure gauge which records pressure and temperature for a limiled period. This provides useful information but is costly and intermittent. A permanent system exists comprising of a downhole mandrel which houses an electronic means of measuring pressure, an electronic system to transmit the pressure data, an electric armoured cable clamped to the tubing and running up the length of the well in the Lubing/-~.,. ng annulus to the surface and a surface display/recording unit. All the downhole apparatus is shielded from the ambient hydrostatic and well pressure but may be exposed to high temperatures.

Known disadvantages of this system are the unreliability of the electronics system-especially when associated with high temperatures found at the bottom of some wellbores, fragility of the electric cable and other components and the tendency of the connections top and bottom to pressure ingress. The systems are also costly to purchase and install.

Where only one zone is producing, in-ils possible to divert the well stream away from the normal production process equipment and into a test. rator. The data gathered from this separa-vr will reveal flowrates of gas, oil and water, fluid properties and fluid/gas gravity's.

Periodically testing a well in this way can indicate changing production conditions allowing remedial action to be undertaken. A well producing from a number of formations with co-mingied flow may indicate that remedial action is required, but further investigation is required.

Flow elements of flow and other measurements from a particular formation may be acquired by lowering a Production Logging Tool on a wireline and passing or logging this tool across the formation of interest. Sensors in the tool can detect flow (turbine flowneter) procure, temperature and fluid type (resis ivity tool). Surveys of this type require a wireline intervertion which can be costly and will require well down time which dimi shes production. A crew of specialist engineers will be required onsite to operate the equipment. Sometimes the well will be remote, sub sea or may be obstructed by other well construction equipment preventing any intervention.

Information gained from these and other systems-allows fine tuning of the production system, prediction of water production (which will decrease the oil production) or perhaps the data required to initiate the closure of a particular formation due to excessive gas, sand or water production or other reasons. This may be effected by intervention in the wellbore with wireline, coiled tubing or similar to physically plug off water producing formations.

Mechanical plugs, straddles or placement of cement will shut of the water production formations effects such as cross flow whereby production from one formation may flow to another lower pressured formation may also be detected. This phenomenon is particulawrly pronounced when the well is shut in and can lead to permanent damage of the thief formation and diminished total production. Little can presently be done to prevent this happening.

Using the gathered data may allow the well to be produced more efficiently or may increase the ultimate recovery available from the well by providing a calculated pressure drop downhole which may avoid or postpone some or all of these conditions. Production optimisation is presently achieved by selecting a ccke or orifice through which the well is produced upon exiting the wellhead. Larger choke sizes will decrease the back pressure in the well and increase flow rate. An excessively large choke may initially provide for maximum production, but may also damage the formations by promoting sand production as a result of formation break down or may encourage premature water or gas production.

Wellbores may also periodically require the use of chemicals to be placed downhole. These may be to inhibit corrosion of the production tubing, to inhibit scale precipitation on the production tubing, to prevent the formation of paraffin's, asphaltines, hydrates, to prevent crude from foaming or for other purposes. Dosage rates vary and the chemicals may be inserted by the three following means.

1) Bulk chemicals may be pumped down the wellbore tubing using large capacity pumps at great expense.

Treatments of this sort can only economically be performed very periodically.

2) An injection valve (check valve) may be placed in the wellbore at the well construction phase and the annulus filled with chemicals. Additional chemicals pumped into the annulus from surface will displace those around the injection valve into the wellbore providing a continuous metered facility. Known disadvantages of this system are the deleterious effects oi temperazure on the treating chemicals affecting their performance (the large volumes necessitating long retention times) the the likelihood of the dirty annular cavity env providing debris which may clog or plug the injection valve. Also, a large volume of chemical is required Lc begin the process which may be expensive.

3) A chemical injection sub may also be used which is placed near the well bottom and directly linked to surface by a hydraulic liie or control line. This sub is located downhole during the well construction phase, is an integral part of the tubing and comprises an injection port and check valve. Small dosages of chemicals may be accurately and economically placed in the wellbore. Plugging problems are less likel-; as all--uids nay be filtered prior co use.

The present invention seeks to provide a production optimisaticn tool--use iri a method and a system for extracting fluid products from below the surface of the earth via a wellbore and which has the ability to perform one or more of the following three functions : 1) To selectively control or close off the flow from a producing formation or lateral ; 2) To transmit pressure data from an area close to the producing formation to surface ; 3) To provide a chemical injection and hydraulic oil refreshment facility.

The performance of these three functions will provide optimised well production by provision of data upon which optimisation decisions may be influenced. Changing well and formation parameters may be quantified and dealt with. When a zone of interest is passed through a surface test separator and others closed accurate flow data concerning that zone may be collected. Based on this and downhole pressure data, selective zonal regulation and shutoff preventing cross flow, minimising water/gas breakout and maximising production will be achieved. Removing the need for well interventions when a zone finally does require to be closed off is also possible. The chemical injection facility ensures that this and other apparatus in the wellbore is fit for use many years after installation. The closure option alsc allows for selective acidisation or other treatments of the formations withe J. t further interventions.

According to ~ne aspect of the invention there is provided a. method of operating a wellbore as defined in claim 1.

Preferred aspects of the method are set out in dependent claims 2 tu 4.

According to a further aspect of the invention there is provided a system for controlling the operation of a wellbore as defined in claim 5. Preferred features of the system are defined in depender. claims 6 to 9.

Preferred embodiments of production optimisation rool, for use in a method and system according to the invention for extraction of fluid products from below the surface of the earth, will be described in detail, by way of example, with reference to the accompanying drawings in which : Figure 1 is a schematic illustration of a typical design of wellbore for use in extracting oil and gaseous hydrocarbons from producing formations located below the surface of the earth ; Figure 2 is a view, similar to Figure 1, showing a production optimization tool for use in a method and system of the invention, when applied to an oilvell as shown in Figure 1 ; Figure 3 is an enlarged view f a tubing retrievable control valve for use in the arrangement shown in Figure 2; Figure 4 is a schematic illus'ration of a surface piston chamber with indicator rod, for use in measuring downhole operating parameters ; Figure 5 is an enlarged view of a control valve nipple for use with the arrangement shown in Figure 2; Figure 6 is an enlarged view of a wireline retrievable control valve for use in the arrangement of Figure 2; and Figure 7 is a detail enlarged view of a wireline retrievable control valve shown inside a control valve nipple, also for use in the method and system of the invention.

The device s located near the bottcm of a borehole and adjacent to the producing formation to be controlled. A packer above and below the device isolate the formation from other formations by providing a pressure tight seal. See Figure 2. The device takes the form of a tubular member assembly and provides a flow path through it for production fror. lower formations and from the adjacent formation. An hydraulic control line runs from the device through an hydraulic bypass situated in the packer to the surface where it exits the wellhead in a pressure tight seal (a suitable by-pass which can be used comprises a Raker Oil Tools SBT with injection line by-pass). The control line runs through the annular space between the production tubing and the well casing.

An operating or motive piston housed in the device controls the three functions as mentioned. Applied hydraulic pressure from surface will cause the piston to move downwards. Wu, l pressure will cause Xhe piston to return upwards if hydraulic oil is withdrawn from the system at surface. Thus the piston may be moved to a number of positions by either injecting or removing hydraulic oil using only one hydraulic line. This operating piston provides the motive force for positioning a"flow sleeve"in any desired position (see Figure 3). The sleeve is telescopically linked to the motive piston and it may be selectively positioned to align an array of orifices or chokes of differing sizes with flow ports. situated in the structural inner member of the device. The chokes may be manufactured from an abrasion resistance material such as ceramic or tu gsten carbide in order to withstand er, s Qr. due tO pentiai sand production.

The chokes, prefe-cably will take the form of a replaceable insert fastened to the flow sleeve. The position of the sleeve will be known at any time by recording the volume injected or removed from the system and comparing this with a sleeve position table which features volume as its units.

The chokes regulate the flow through the flow sleeve from the formation (and the pressure drop) into the tubing. Seals positioned either side of the chokes but sealing on the inner member prevent pressure and flow from bypassing the chokes.

Scraper rings on the outside of the flow sleeve but inside the outer housing prevent rhe ingre < of dirt and ensure free movement at ail times. A'C'ring or similar located on the bottom outside of the flow sleeve acts as a detent assembly and engages with an external profile. This serves to locate the sleeve so that the w ports and also locks the flow sleeve until acted upon by the hydraulics. Differing arrays of chokes with graduated openings or total closure (blank chokes with no orifice) may be selected by moving the sleeve to the desired position. The closure option obviates the need for well intervention which has previously been the case when a formation has to be shut off. Intervention is always expensive, may have an element of risk due to the well conditions and may even be impossible due to the remote or sub sea nature of the well. Also, the closure option may form an additional barrier preventing the escape cf well fluids in the event of an accident or equipment failure.

A surface piston assembly connected to the system with a floating piston and swept volume similar to that of the downhole fl. oating piston can indicate by means of an integral indicator rod, the current position qu t downhole flow sleeve. This also provides another pressure barrier with the downhole system (see Figure 4).

Well pressure may also be measured utilising the "motive"piston. The piston is telescopically linked to the flow sleeve such that it may be influenced by well pressure when not bottomed out in either direction as described before, but may also push or pull the flo ; < sleeve. A known volume corresponding to half of the volume of the telescopic stroke may be injected or withdrawn from he system after the motive piston has pushed or pulled the flow sleeve to a new position in order to place the motive cison at mid stroke.

It will sense formation pressure beow by means of a communication port to outside he device and upstream of the choke sleeve and will transmit this sandface pressure to the hydraulic oil above which in turn will transmit the pressure along the hydraulic control line to surface to be measured.

The hydraulic control line is filled with a light hydraulic oil selected for its low specific gravity and bulk modulus properties.

Most oil and gas reservoirs feare a downhcle pressure in excess of the fluid gradient pressure. It is this very feature which allows an oil well to flow to surface. Indeed, some well may have a wellhead pressure of thousands of p. s. i. For example, a 10,000ft deep well may have a bottom hole pressure of 6, 500psi. tA water column rhis high will measure 4,330 psi at its case.) A static column of hvdraulic oil with a specific gravity of 0. 870 10,000ft. deep will exert a bottom hole pressure of 3, 770 psi, If a floating isolation piston were placed between the well fluid and this hydraulic oil at 10,000ft. depth aIi, mbalance of 2,730 psi would register on the surface of the hydraulic fluid line.

When in any particular position except for top and bottom stroke, an imbalance between he formation pressure and the hydrostatic head of hydraulic control line pressure will cause a positive pressure Lo be read at surface. This pressure plus the known hydrostatic pressure for the given oil used will equal the bottom hole pressvre. The bottom hole pressure would be calculated at 2, 730 psi system surface pressure plus the hydrostatic of 3,776 psl = 6,500 psi.

Certain gas and artificial lift wells which feature low bottom hole pressure may not be suitable for the system as described as sufficient pressure must exist to lift the hydrostatic pressure of hydraulic oil.

The stroke or the dcwnhcle pisicn is important in that it must contain sufficient volume to compress the total volume of the con-l line and system for a given pressure change. A particular hydraulic oil to be used has a bulk modulus which gives a u. 5 change in volume per 1,000 psi pressure channe Tne system stem volume for a 15,000ft. deep well using 1/4" control line with a 0.12" internal diameter is approximately 7 gallons. Approximately 1@3 pint of fluid is required to be injected into this system to provide a pressure increase of 1,000 psi. If o @ownhole pressure range of 2,000 psi was anticipated, it would be sensible to size the swept volume of the downhele pisten / sleeve to be 1 pint, thus allons @ for a 50 contingency. Calculations for expansion of the control line due to pressure are ignored as most of the lengtr of the control line will have an external pressure exerted by the annular fluids similar to or higher than the internal pressure. The exF, nsion effect of the upper portion of'he control line is so small that it is not worth consider ng.

Calibration and accuracy checks may be performed on the pressure measurement system by using wireline techniques to place an accurate pressure memory gauge in the wellbore at the same point as the piston/sleeve and noting both pressures simultaneously. This may provide a useful comparison and assist calibration of the system. Two of the borehole subs when run together with a restriction of a known size between could form the basis of a flowmeter.

Calculations based on the pressure drop across the restriction relative to the restriction size combined with flow properties, expansion factors, e. t. c. will provide a flowrate. This techn. ique will be obvious to anyone skilled in the art.

It is a known disadvantage of downhole systems featuring a hydraulic control line that gas will eventually ingress the system through the seals and the hydraulic oil will degrade and change its properties with time. This is a known problem with downhole safety valves. The pressure measuring system is therefore provided with a facility to dump the contents of the control line through the pressure sensing piston.

This is achieved b displacing the piston and flow sleeve to bottom stroke where an injection valve on the bottom of the flow sleeve will be pushed open and clean filtered fluid injected from surface will displace the system contents through-he pistDn and into the wellbore. The fluid path for this runs through drillings in motive piston, through a coil of hydraul-c pipe which is fed around the telescoping joint and compensates for relative movement between the motive and flow sleeves, through drillings in the flow sleeves which has had a straight section of hydraulic pipe inserted and is ter-are in a bottom injection sleeve which houses a mechanically opened injection valve. In addition to the injection valve, the sleeve or piston is also equipped with one or more check valves upstream of the injection valve for safety purposes in the event that the hydraulic contro'line becomes damaged. mre check valve (s) will prevent well pressure and fluids frcrl flowing through the control line and into the annulus should leaks occur in the control line. The check valves are calibrated to open at around 100 psi dl-ferential pressure. When in injection mode and prior to the valves opening, the increased hydraulic pressure above the piston or sleeve will displace the fluid below the piston and push the piston to bottom stroke where the injection valve is mechanically opened. A port in the outer casing allows the chemicals/hydraulic fluid to egress into the sandface area.

It can be seen that by use of this system, chemicals may be pumped down the control line from surface and injected. The chemicals are then chased with clean hydraulic oil refreshing the system tc its pressure monitoring role.

As seals and packings can grip cylinders and pistons, the hydraulic operating sleeve or piston may feature as few as two low friction seals in order to minimise the system friction. A"dither"function may be included whereby the valve is occasionally fractionally repositioned by injection of small amounts of fluid from surface in order to prevent frictional increases caused by the seals binding or locking with time.

A suggested operating schedule would be to fully cycle the device perhaps once a week. Firstly, hydraulic oil is removed from the system until a sharp pressure drop is seen at surface indica : a he downhole ro,. on has bottomed out top stroke. A datum may be noted at this time. Injection of hydraulic oil will then result in a pressure increase until the injection valve opens tpiston bottomed out one bottom stroke) when hydraulic fluid or chemicals may be injected.

When the injection has stopped, after waiting a few minutes and observing the pressure drop off and stabilisation, removal of the required volume wili position the sleeve to the preferred position. This operating schedule will ensure that the mechanism is frequently cycled, the oil is fresh and that scale and debris are frequently swept away. It also provides for a full functionality check.

A plurality of the described systems may be installed in a well by using multiple packers equipped with many hydraulic feed through's. At surface, a nydraulic feed through can be provided for each control line. The device as previously described would be introduced into the wellbore as part of the tubing string and would not be retrievable except in the event that the pipe or tubing was itself removed from the wellbore-an unwelcome operation which would be avoided unless a failure in some well architecture made this necessary.

This embodimenr of the device as previously described is called a"Tubing Retrievable Control Valve". Preferably, all the elastomeric :---nd moving parts would be housed within a cartridge which may be retrievable independently of the tubing allowing for servicing and specification modification.

This embodiment is called a Nireline Retrievable Control Valve (WRCV,.

The WRCV has two main sections, namely the Nipple and the valve Insert (see Figure 5). Th- Nipple provides a structurally strong ^using ana location for the valve to sit in and has similar mechanical properties to the rest of the tubing string. It features internally from top to bottom, a profile for a locking mechanism to engage in, an exit point for the control line to communicate hydraulically with the valve inser hich has polished seal bores above and below (to accept : ~ndraulic-solation packings), an array of openings through which the formation flow will pass and a second exit point teX the control line which has polished seal bores above and below which will allow for chemical injection. The bottom of the nipple features an upset locator plate which will assist in orient. ng the valve insert such that it rotates during installation, aligning the choke flow ports with the flow openings of the nipple.

Externally, a control line will run from an upper point of the nipple to the surface as described before and a small length will run from this point to the base of the nipple to provide the fluid path for injection nurposes. This short length will be strapped to the outside of the nipple and will run between the flow openings. The nipple is threaded to the tubing above and below and equals or exceeeds the yield strength of the tubing. It may be run into the ground. with or without the valve insert installed.

The control valve insert features a standard wireline lock assembly on top (see Figure 6). This is a well established piece o equipment and is commonly found in most wells. It provides a means of locking a flow control device with a nipple or production tubing. The lock also provides a handling means whereby an intermediate running or pulling tool allows the interface between wireline of different types or coiled tubing, bath of which are used tc convey devices into or out of a wellbore Below this are two sets of seals which engage on a polished bore on the nipple. They isolate the control line hydraulic fluid from the tubing pressure.

Below these s a piston chamber where the hydraulic fluid supplied by the control line may act upon the motive piston.

The motive p-ston-. = of the sleeve type and has low friction seals inside and ou* :. it is telescopically linked to the flow sleeve which has been described in detail previously.

At the bottom of the insert is a sprung key which locates in the nipple orientation plate and turns the body of the insert durino installation such that the @@@@ ports align with those of the nipple. Abc"e this are the two seals which straddle the chemical injection poinc provided by the short control line extension. Fixed to the body of the insert but protruding above the bottom face of the control valve sleeve chamber is an injection valve. This seals hydraulic pressure until pushed open by the flow sleeve Infection of fluids necessitates pumping from surface t ; pos t-on the flow sleeve at bottom stroke and then a slight pressure increase to overcome the two check valves and injection valve. Control line fluids can then be displaced into the void between the nipple and insert to flow through the choke insert and up the wellbore. The flow sleeve may then be re-positioned to the desired position in the same way as described before. The insert can be seen installed in the nipple in Figure 7.

With the control valve insert removed, the nipple allows for a blanking sleeve to be installed should the control valve or producing formation be ccmpletely finished with. This comprises a plain tube with sets of seals top and bottom which isolate the flow ports and contro'~ line exit points from interna tubing pressure. The tube is positioned and located by the same lock as was previously used for the control valve. This option may be necessary should the control line suffer catastrophic damage. It also allows for the formation to be produced, but the control line to be blanked off should the same scenario occur.

Similarly, the insert fea'ures a small blanking mandrel with hydraulic ports between the top sets of seals and adjacent to the entry point for hydraulic pressure from the control line (see Figure 5). This allows for fitment of a third d set of upper seals located by a replacement unported mandrel. This blanks off the short control line jumper and chemical injection facility should only this become damaged.

The described method and apparatus may also be used in injection wells wherebj fluids or gas is pimped down a wellbore for storage or for the purpose o : secondary recovery for other producing wells to booost reserv@ir pressures. By use of the apparatus, flow may be selectively directed to particular formations or distributed to a number of formations as desired by altering the choke setting for each formation.

Improvements to the device may include addition of electronic or other sondes for the acquisition of data or additional flow control functions. These may communicate to surface by electric cable, fibre optic cable or other means and may complement the functions as previously detailed. A single or many fibre optic strands may be inserted in the hydraulic control line and run through the hydraulic passage from surface to downhole. This wi]'rrovide additional information such as temperature gradients throughout the wellbore. Two or more devices may be linked by the same hydraulic control line but be selectively addressed by means of hydraulic or other switching apparatus. Similarly, the control line may be used to initially set a packer or perform an additional function prior to its control valve purpose.

The line would be spliced to provide hydraulic communication with another device. Said device having operated may then cease to have an effet on the hydraulic system.

The control valve may be ! Tiodif4-ed provide a locking facility when the flow sleeve is in the close position.

This may take the form of a shearahle pin which locks shut the device until opening is required. At this time, applied hydraulic pressure of a certain value will overcome the locking pins and allow the sleeve to function normally. This feature may be particularly useful when introducing the tubing and production equipment into the wellbore for the purposes of pressure testing.

KEY TO DRAWINGS 1. Wellhead/Xmas tree 2. Annulus 3. Casing 4. Tubing 5. Packer 6. Producing formations 7. Cement 8. Hydraulic line 9. Packer featuring hydraulic by-pass 10. Zone No 1 11. Zone No 2 12. Interval control valve 13. Thread (female) 14. Hydraulic chamber 15. Operating or motive piston 16. Flow sleeve 17. Flow ports 18. Outer housing 19. Fluid egress point 20. Thread (male) 21. Telescopic joint 22. Choke orifices 23. Scraper rings 24. Choke seals 25.'C'ring detent assy 26. Flow sleeve 27. Check valves 28. Injection valve 29. Indicator rod 30. Indicator piston 31. Pressure gauge 32. Low friction seals 33. Control line to surface 34. Locking profile 35. Polished bore 36. Hydraulic exit point 37. Injection fluid path 38. Flow ports 39. Second hydraulic exit points (chemical injection) 40. Locator plate 41. Lock assembly 42. Seals 43. Seals (chemical injections) 44. Choke seals 45. Motive piston 46. Flow sleeve 47. Choke orifices 48. Scraper ring 49. C ring detent assy 50. Spring key for orientation 51. Injection valve

Claims (11)

1. Claims: 1. A method of operating a wellbore having a casing, tubing and an annulus defined therebetween and for extracting fluid products from below the surface of the earth via at least one producing formation communicating with the tubing, in which a fluid pressure operated control device is selectively placed in the wellbore to control a particular isolated formation and having choke devices to regulate the flow and pressure drop from the formation, said device having its operation controlled from the surface via a fluid pressure control line and also having a piston arranged to provide a pressure imbalance at the surface which can be interpreted. as a downhole measurement of the wellbore.
2. 2. A method according to claim 1, in which the control device is hydraulically controlled, and said piston is a hydraulic piston.
3. 3. A method according to claim 2, including a facility for introducing pressurised fluid into r',-.-wel. lbore using the same hydraulic piston used for pressure measurement and flow control, but opening valve means when at top or bottom stroke of the piston to allow hydraulic fluid to discharge.
4. 4. A method according to any one of claims 1 to 3, and using a plurality of control devices selectively placed in the wellbore to cooperdte with and to control respective producing formations to provide an overall well management system.
5. 5. A system for controlling the operation of a wellbore having a casing, tubing and an annulus defined therebetween and extracting fluid products from below i : he surface of the earth via at least one producing f@ mation communicating with the tubing, said system comprising a fluid pressure operable control device selectively positionable in the wellbore to control a particular isolated formation and having choke devices to regulate the flow and pressure drop from the formation, said device being controllable from the surface via a fluid pressure central line and Iso having a piston arranged to provide a pressure imbalance at the surface which can be interpreted as a downhole measurement of the wellbore.
6. 6. A system according to claim 5 and conveyed on tubing or pipe of the wellbore.
7. 7. A system according to claim 6, including an outer nipple section conveyed on the tubing or pipe, and an inner replaceable section conveyable by wireline or similar techniques.
8. 8. A system according to any one of claims 5 to 7, and configured for the purposes of injection into the wellbore.
9. 9. A method according to claim 1 and substantially as hereinbefore described with referer @ to, and as shown in the accompanying drawings.
10. 10. A system according to claim 5 and substantially as hereinbefore described with reference to, and as shown in the accompanying drawings.
11. 11. A system according to claim 10, and incorporated in a wellbore.

    11. A system according to claim 10, and incorporated in a wellbore.

    Amendments to the claims have been filed as follows 1. A method of operating a wellbore having a casing, tubing and an annulus defined therebetween and for extracting fluid products from below the surface of the earth via at least one producing formation communicating with the tubing, in which a fluid pressure operated control device is selectively placed in the wellbore to control a particular isolated formation and having choke devices to regulate the flow and pressure drop from the formation, said device having its operation controlled from the surface via a fluid pressure control line and also having a piston arranged to provide a pressure imbalance at the surface which can be interpreted as a downhole measurement of the wellbore.

    2. A method according to claim 1, in which the control device is hydraulically controlled, and said piston is a hydraulic piston.

    3. A method according to claim 2, including a facility for introducing pressurised fluid into the wellbore using the same hydraulic piston used for pressure measurement and flow control, but opening valve means when at bottom stroke of the piston to allow hydraulic fluid to discharge.

    4. A method according to any one of claims 1 to 3, and using a plurality of control devices selectively placed in the wellbore to cooperate with and to control respective producing formations to provide an overall well management system.

    5. A system for controlling the operation of a wellbore having a casing, tubing and an annulus defined therebetween and extracting fluid products from below the surface of the earth via at least one producing formation communicating with the tubing, said system comprising a fluid pressure operable control device selectively positionable in the wellbore to control a particular isolated formation and having choke devices to regulate the flow and pressure drop from the formation, said device being controllable from the surface via a fluid pressure control line and also having a piston arranged to provide a pressure imbalance at the surface which can be interpreted as a downhole measurement of the wellbore.

    6. A, system according to claim 5 and conveyed on tubing c pipe of the wellbore.

    7. A system according to claim 6, including an outer nipple section conveyed on the tubing or pipe, and an inner replaceable section conveyable by wireline or similar techniques.

    8. A system according to any one of claims 5 to 7, and configured for the purposes of injection into the wellbore.

    9. A method according to claim 1 and substantially as hereinbefore described with reference to, and as shown in the accompanying drawings.

    10. A system according to claim 5 and substantially as hereinbefore described with reference to, and as shown in the accompanying drawings.