Method, device and apparatus

BACKGROUND OF THE INVENTION

This invention relates to a method, device and apparatus for obtaining or controlling flow of fluid from more than one production zone, in particular, for achieving co-mingled flow of hydrocarbons in oil and gas wells.

After a wellbore has been drilled for an oil, gas or water well and the required depth has been reached, the well is fitted with production equipment. This is referred to as “well completion”. At this stage, a well will be cased and the necessary production tubing installed, incorporating various isolation seals to ensure integrity and safety of the well. Following installation of the production tubing, fluids can be produced from the various subsurface formations. Fluids may be recovered either through a single producing zone or a plurality of producing zones.

There are several known ways of producing from a plurality of producing zones, often referred to as multi-zone wells. The simplest option involves simultaneous production from all zones. FIG. 1 shows a sectional view of a known type of well completion having multiple production zones. Production tubing 18 is provided within a casing 10. The annular space is isolated towards the lower end of the production tubing 18 by a production packer 14.

First, second and third production zones 11, 12, 13 respectively, are formations containing hydrocarbons. The production tubing 18 and the casing 10 are perforated in the region of the zones 11, 12, 13 to allow hydrocarbons from each zone simultaneously to flow into the production tubing 18. These hydrocarbons are prevented from flowing up the full length of the annulus by the production packer 14. An annular space between each zone 11, 12, 13 and the production tubing 18 is isolated by zone isolation packers 16. The apparatus of FIG. 1 allows simultaneous production from all zones 11, 12, 13.

However due to the potentially differing flow rates and pressures in the different zones 11-13, cross-flow may occur resulting in no production from one of the zones. The term “cross-flow” is used to describe a situation when fluids from one zone flow into a different zone rather than into production tubing and out of the well. Moreover the sediment within the fluid from the higher pressure zone can block any subsequent attempt at producing from the lower pressure zone.

One method to alleviate this problem, often used in the UK continental shelf, involves isolating each zone and then producing each zone sequentially. Once production is completed in one zone, an inflow control valve is closed and another zone is produced by opening a corresponding inflow control valve. The inflow control valve is often a sliding sleeve which may be operated by coiled tubing in the well. Sticking of such a sleeve in one position is a common failure associated with the sliding sleeve.

Another method of producing from multi-zone wells, commonly employed in Africa and the Far East, is the use of dual completion strings. This method entails running two sets of completion tubing into the well. One or more zones can then produce up one completion string, with the remaining production zones using the second completion string. Each set of tubing is separated from the other and the respective zones are separated using isolation packers. This method can be used in combination with the sequential production method described above, which includes sliding sleeves, to allow production from each zone in turn.

FIG. 2 shows a sectional view of a dual completion prior art well and is a known example of apparatus for producing from multiple zones. A casing 20 houses two sets of production tubing, 27, 28. Hydrocarbons from a first formation, zone 21, can be produced using the production tubing 27. Hydrocarbons from the first zone 21 can be prevented from entering an annular space between the casing 20 and production tubing 27, 28 by a production packer 24. The second and third zones 22, 23 can be produced using the production tubing 28 and hydrocarbons from these zones 22, 23 are prevented from mixing with hydrocarbons produced in the first zone 21 by a zonal isolation packer 26.

The amount of equipment required and the high cost of installing an additional set of production tubing makes dual completion an expensive method of multi-zone production.

So-called “intelligent wells” are an alternative method of producing from multiple zones and these provide choke valves for each production zone. Intelligent wells are generally acceptable for zones with small pressure differences. However for zones with larger pressure differences, the pressure of the fluid from the higher pressure production zone remains relatively high after proceeding through the choke valve (which primarily controls its rate) and thus the same problems can occur with cross-flow between the production zones.

Other disadvantages associated with intelligent wells include the large expense required for installation, operation and maintenance. Additionally, the complicated valves and permanent gauge systems such as those used in intelligent wells can be unreliable. Repairing damaged choke valves is also conventionally difficult and expensive.

An object of the present invention is to alleviate any of the problems associated with the prior art.

BRIEF SUMMARY OF THE INVENTION

According to a first aspect of the present invention, there is provided a method of obtaining fluid from a first production zone and a second production zone, the method comprising:

(a) providing a first device to produce or control flow of fluid from the first production zone;

(b) in a well, providing a first well connector proximate to, and in fluid communication with, the first production zone;

(d) providing a second device to produce or control flow of fluid from the second production zone;

(e) in the well, providing a second well connector proximate to, and in fluid communication with, the second production zone;

(f) connecting the second device to the second well connector;

(g) producing fluids from the first and second production zones through the well connectors and optionally through the devices.

The method is not limited to performing steps (a) to (g) in any particular order unless specifically stated. Preferably the well is a hydrocarbon producing well. Preferably at least one well connector is provided in the well during completion of the well. Typically the first and second devices are independently operated. Typically the well comprises casing with production tubing provided therein, and at least one well connector is provided in a side pocket provided in the production tubing, wherein when the device is connected to the well connector, the device is typically substantially located in the side pocket. Preferably each well connector is located in a side pocket. Preferably at least one device is releasably connected to at least one well connector. Preferably at least one device also connects to a power connector provided in the well, to supply the device with power. Preferably the device connected to a power connector is releasably connected to the power connector. The power connector may be in-built into the well connector so that a single connection connects the well connector and device with power and fluid. Alternatively separate connecting members may be provided for power and fluid connections. There may be more than two production zones. Typically each zone has a corresponding well connector and device. Optionally one zone, typically the one with the highest formation pressure, may not have a device. Preferably each zone is isolated from the other zones such that production fluid cannot pass from one zone to another. Preferably each device is releasably connected to each well connector.

Depending on the pressure of the first and second production zones, the first and second devices or pumps may, in use, independently reduce the pressure and/or flow rate of the fluid from the zones, or alternatively increase the pressure and/or flow rate from the zones.

According to a second aspect of the present invention, there is provided a device for producing or controlling fluid from a well, the device comprising a means to control or produce the flow of fluid from a zone, and a connector to releasably connect with a well connector, the well connector, in use, in fluid communication with the production zone.

Preferably the device according to the second aspect of the invention is used in the method according to the first aspect of the invention. The device typically comprises a valve. Alternatively the device may comprise a pump assembly. The device is typically adapted to connect with a power connector provided in the well connector. The device may be hydraulically powered. The device may be electrically powered. The device typically has a main longitudinal axis and is lowered within a well to form the connection with the well connector, the device is typically lowered in a direction generally parallel to said longitudinal axis, and a portion of the device which connects to the well connector may extend transversely with respect to said longitudinal axis. Typically the well connector provides for fluid communication between the device and the production zone. The valve may be used as a gas lift valve whereby gas is pumped down the annulus between casing and production tubing and exits through a side pocket into the well.

Pumps suitable for this application include suitably modified electric submersible pumps, progressive cavity pumps and jet pumps. For electric submersible pumps, a variable controller is typically provided which may be located at the surface or downhole. Preferably the device comprises a further connector adapted to connect with an electrical connector provided in the well. The pump is typically provided as a pump assembly comprising a plurality of parts, wherein the pumping action is provided in one part, the first connector in a second part and the second connector in a further part.

Where the device comprises a valve, typically the valve is a proportional valve, that is the proportion of fluid which can pass the valve is continuously variable from zero to a maximum value. Typically the device is shaped and adapted to be lowered and raised within a well by an elongate member, such as a wireline. The device is preferably shaped and adapted to be raised and lowered in the production tubing of a well.

Preferably the well connector comprises a check valve—thus it is not necessary to have a check valve in the device. This prevents back flow into the well connector when the valve or pump is removed.

According to a third aspect of the invention, there is provided a well apparatus comprising:

(a) a casing lining a well and a production tubing provided within the casing;

(b) a first well connector proximate to a first production zone, the first well connector, in use, in communication with the production zone;

(c) the well connector being connectable to a first device, said device comprising a means to control or produce a flow of fluid from the production zone;

(d) a second well connector proximate to a second production zone, the second well connector, in use, in communication with the second production zone;

(e) wherein the second well connector is connectable to a second device, said second device comprising a means to control or produce a flow of fluid from the production zone.

Preferably the device according to the third aspect of the invention is the device according to the second aspect of the invention. Preferably the apparatus comprises the device.

Preferably the apparatus according to the third aspect of the invention is used with the method according to the first aspect of the invention. Optionally at least one device comprises a valve. Alternatively at least one device comprises a pump. Preferably the well connector is provided in a side pocket of the production tubing between the casing and the production tubing. At least one well connector may be provided such that the device connects on the underside of the well connector. This can reduce the amount of debris which can fall into the well connector when it is not connected to the device. At least one well connector can comprise a valve operable in a non-axial direction with respect to the borehole. The valve may be operable in a substantially transverse direction.

The well apparatus may comprise a power and/or control line which extends down the well to the well connector which further comprises a power connector for connection to the device. Typically the control line is a hydraulic control line. A single control line may extend from the surface to the bottom of the well. An indexing pilot valve may then control each device. Each device can thus be controlled from a single line.

The line may extend on the outside of the production tubing and optionally connections are made through the tubing to the device located in the side pocket. The power connector may be an electrical connector. For example if an electric submersible pump is used or a stepping motor for a valve.

A single electrical power line may provide power for a plurality of devices. The single electrical power line may comprise a first earth core, a second core operating at positive voltage and a third core operating at negative voltage. The voltages are at least 500 dc or ac, preferably more than 750 dc or ac preferably around 1000 dc or ac.

The power connector may be a hydraulic connector. For example if a jet pump was used or a hydraulically activated valve.

The devices are preferably arranged in the well to allow full bore access to the well beneath the devices.

Typically the borehole comprises casing preferably also production tubing and therefore the well connector, in use, preferably connects the production zone to casing and more preferably to production tubing.

The production tubing preferably comprises a side pocket extending transversely into the well which is adapted to receive the device. Preferably the side pocket comprises the well connector. The power/control line(s) may extend directly to the device.

Optionally, the well connector can also comprise a check valve to prevent fluid backflow into the zone. According to a further aspect of the present invention, there is provided an apparatus for controlling or producing fluid from a well, the apparatus comprising a cartridge, the cartridge comprising a first device and a second device; the devices as herein described.

Preferably the cartridge is adapted to be removably connectable to the well. Thus the cartridge is adapted to be lowered and raised within a well by an elongate member, such as a wireline.

Preferably the apparatus according to the further aspect of the invention is performed using the method according to the first aspect of the invention.

The first and second devices can independently be a pump, a choke or other devices.

‘Proximate’ as used herein preferably means within 20 m of perforations in the well casing or the open bore at the end of the well, preferably within 10 m, more preferably within 5 m.

Any feature of any aspect of any invention or embodiment described herein may be combined with any feature of any aspect of any other invention or embodiment described herein mutatis mutandis.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING

Embodiments of the present invention will now be described, by way of example only, with reference to and as shown in the accompanying drawings.

FIG. 1 is a sectional view of a known well completion showing simultaneous production from several zones;

FIG. 2 is a sectional view of a known dual completion;

FIG. 3 is a sectional view of a portion of a well completion and apparatus according to one embodiment of the invention;

FIG. 4 is a sectional view of a cartridge according to another embodiment of the invention;

FIG. 5 is a sectional view of a well completion and the FIG. 4 cartridge;

FIG. 6 is a sectional view of a well completion in accordance with the present invention ready for producing fluids from multiple zones;

FIG. 7 is a sectional view of the well completion of FIG. 6 containing apparatus according to the invention;

FIG. 8
a is an enlarged view of a portion of the well completion of FIG. 6;

FIG. 8
b is an enlarged view of a portion of the well completion and apparatus of FIG. 7 showing a pump assembly according to the invention being run in;

FIG. 8
c is a further view of the FIG. 8b well completion and apparatus with the pump assembly in a position ready to pump fluids to the surface;

FIG. 9
a is an enlarged view of a portion of the well of FIG. 6 containing an embodiment of a valve assembly according to the invention being run in;

FIG. 9
b is a further view of the FIG. 9a well completion and valve assembly in a position ready to produce fluids to the surface;

FIG. 10
a is an enlarged view of a portion of the well completion of FIG. 6 containing a second embodiment of a valve assembly according to the invention being run in;

FIG. 10
b is a further view of the FIG. 10a well completion and valve assembly in a position ready to produce fluids to the surface;

FIG. 11
a is a sectional view of a well completion in accordance with one embodiment of the present invention;

FIG. 11
b is a sectional view of the FIG. 11a well completion with a pump being run in;

FIG. 11
c is a plan view of a the FIG. 11a well completion;

FIG. 12
a is a sectional view of a well connector and first portion of a device according to a yet further aspect of the invention, in a mated position;

FIG. 12
b is a sectional view of the FIG. 12a well connector and first portion of a device in a separated position;

FIG. 13
a is a sectional view of a first portion of a valve assembly according to a further aspect of the invention;

FIG. 13
b is a sectional view of a second portion of the valve assembly of FIG. 12a;

FIG. 13
c is a sectional view of both portions of the valve assembly of FIGS. 12a and 12b, showing the valve in a closed position;

FIG. 13
d is a further sectional view of the valve assembly of FIGS. 12a and 12b, with the valve in a fully open position;

FIG. 13
e is a sectional view of a J-pin used in the valve assembly of FIGS. 12-12d; and

FIG. 14 is an illustrative view of a series of pump assemblies in accordance with one aspect of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 3 shows a simplified sectional view of one embodiment of the apparatus according to one aspect of the invention in use. Zones 31, 32, 33 contain hydrocarbons and are in vertically spaced relation. A casing 30 is installed and set in the well after drilling through the zones 31, 32 and 33. Production tubing 38 is provided within the casing 30. The resulting annular space between the casing 30 and the production tubing 38 is separated by packers 36 above each zone 31, 32, 33.

A pump 39 is provided with an entry port (not shown) to allow inflow of hydrocarbons from zone 33 only. An arrow 29 indicates the direction of hydrocarbon flow. A wire wrapped screen 34 is provided before the entry port of the pump 39 for separating sand and other particles out of the hydrocarbons prior to entering the pump.

The pump 39 controls the rate and pressure at which hydrocarbons from the zone 33 enter the production tubing 38. Once in the production tubing 38, hydrocarbons can flow up the tubing, bypassing higher pumps.

Similarly, pumps 35, 37 have an entry port with a wire wrapped screen (not shown) to accept hydrocarbons from zones 31, 32 respectively; arrow ‘A’. The pumps 35, 37, 39 are surface controlled and the pressure at which hydrocarbons leave these pumps can be boosted or retarded relative to the formation pressure of the corresponding zones 31, 32, 33. Thus the flow rates and pressure of the hydrocarbons being discharged from each pump 35, 37, 39 can be equalised regardless of the potentially differing formation pressures in the zones 31, 32, 33. This enables the hydrocarbons from all zones to mix and proceed together up the production tubing 38 for recovery.

A sliding sleeve (not shown), or other shut off device such as a check valve, is provided to seal the perforations in the production tubing 32 if any of the pumps 35, 37, 39 are removed for maintenance and replacement. The pumps 35, 37, 39 can be removed individually on wirelines, leaving the production tubing in place. Thus sliding sleeves used in this way only move to close the perforations in the production tubing and are not used to regulate hydrocarbon flow from the well, as with certain known systems. Since they are therefore used infrequently compared with such known systems, they are far more reliable.

The pumps 35, 37, 39 shown in FIG. 3 are positioned in a side pocket mandrel, such that the installed pumps do not obstruct the production flow path. This construction allows unrestricted wireline access to the bottom of the production tubing.

“Formation pressure” as used herein is intended to refer to pressure of the zone. This term can encompass the natural pressure of the zone or the natural pressure when artificially enhanced by means such as steam injection.

Pressure sensing apparatus (not shown) can be provided to measure the pressure differential between the intake and the discharge of the pumps 35, 37, 39. Such data can be transmitted to the surface where a computer (not shown) may be utilised to assimilate and process the information to artificially control pressure and flow at the pumps 35, 37, 39 discharge to ensure co-mingled flow of fluids or hydrocarbons from each zone 31, 32, 33.

Pumps suitable for this application include electric submersible pumps, progressive cavity pumps and jet pumps. Pumps used in the present invention are preferably manufactured from corrosion resistant materials.

Alternatively, the flow rate through the pump may be calculated rather than measuring the flow rate using sensors. Flow rate and pressure may also be measured in the well connectors.

The electric submersible pump (ESP) provides a downhole centrifugal pumping system to generate electrically driven artificial lift of fluids passing through the pump. Under certain conditions, they may be used to reduce flow rate and pressure, rather than create more lift. ESPs are useful for recovery of hydrocarbons from zones or formations with high water cuts (percentage of water to oil). Standard ESPs can be customised for multi-zone production.

Pump motor power can be provided electrically or hydraulically. Electrical power can be transmitted to the pumps using electric cable on the exterior or interior of the production tubing 18. FIG. 14 shows a first and second pump assembly 701 & 702 supplied by a single 3-core cable. Each pump assembly comprises a pump 720, a motor 722 and a commutator 724. The cable comprises an earth core (not shown), a second core operating at +1000 vdc 710 and a third core 712 operating at −1000 vdc. Thus the effective useful power to the pump assemblies 701, 702 is 2000 v. However, having the cable at positive and negative voltages facilitates the insulation in the cable to cope with a such a large voltage difference of 2000V. The commutators 724 convert this current to an alternating current. Thus a number of different pump assemblies can be ‘daisy chained’ from a common power supply without having to run separate cables down the well. Telemetry can be multiplexed up the DC cables 710, 712 to allow each motor to be independently controlled from the surface.

It is also possible to provide a wet-connect, enabling the cable to be positioned within a tubular which carries fluid or hydrocarbons. In the case of a jet pump, hydraulic drive fluid can be transmitted using a hydraulic umbilical positioned either externally or within the production tubing. Alternatively, the hydraulic umbilical can be operated by coiled tubing. Optionally hydraulic drive fluid can be production fluid from the well.

FIG. 4 shows a further embodiment 50 with pumps 55, 57, 59 mounted in a cartridge 58. Isolation packers 54 are attached to the exterior of the cartridge.

FIG. 5 shows a further well completion in hydrocarbon containing zones 41, 42, 43 with the further embodiment 50 therein. A casing 40 lines the borehole 52, with production tubing 48 arranged substantially centrally therein. Zonal isolation packers 46 are provided to isolate the annular spaces between the casing 40 and production tubing 48, above the zones 41, 42, 43.

The cartridge 58 is lowered into, and linearly aligned with, the production tubing 48 such that a fluid tight seal is created by the packers 54 between the cartridge 58 and the production tubing 48 around the zones 41, 42, 43. The cartridge 58 functions in a similar way to the apparatus shown in FIG. 3 where hydrocarbons from each zone 41, 42, 43, arrow ‘A’, only flow through respective pumps 55, 57, 59 with hydrocarbons from each lower zone 42, 43 bypassing the higher pumps in the production tubing 58.

Provision of the cartridge 58 allows the entire unit to be conveniently removed for servicing, repair or replacement of any of the pumps.

FIGS. 6 and 7 show a more detailed sectional view of a portion of an alternative apparatus and well completion in accordance with the present invention. The well completion has a casing 60 and production tubing 68. The casing 60 is perforated in the region of zones 61, 62, 63. Either side of these perforations the annular space between the production tubing 68 and the casing 60 is sealed using packers 66.

Well connectors or side pocket flow valves 71, 72, 73 are provided to allow respective flow from each zone 61, 62, 63 therethrough. As shown in FIG. 7, in use, the valves 71, 72, 73 are connected to respective pumping assemblies 75, 77, 79.

Electrical wet-connects 74 (shown in FIG. 6) supply electrical power to drive electric submersible pump assemblies 75, 77, 79 (shown in FIG. 7) and these wet-connects 74 are located in the annulus between the production tubing 68 and the casing 60. An electrical conduit (not shown) supplying power to drive the pumps is run down the outside of production tubing 68 to each wet-connect 74.

FIG. 7 shows the electric submersible pump assemblies 75, 77, 79 suspended within the casing 60. The pump assemblies 75, 77, 79, connect to the electrical conduit via the wet-connects 74 and to the valves 71, 72, 73.

Annular flow passages 81, 82, 83 are defined between the production tubing 68 and the casing 60 in the region above each pump 75, 77, 79. A series of apertures 84-89 is provided in the production tubing 68 adjacent to and above each pump 75, 77, 79 to allow for fluid communication between the production tubing 68 and the annular flow passages 81, 82, 83 so that flow from below any of the pumps 75, 77, 79 is diverted into the adjacent annular flow path 81, 82, 83 before mixing with the flow emitted by the pumps 75, 77, 79 as described in more detail below.

The pressure or flow rate of the hydrocarbons emitted from each pump may be continuously adjusted in response to fluctuations in formation pressure. Among the factors that can typically influence the recovery of hydrocarbons from different formations are the different natural formation pressures, different grades of hydrocarbons, well penetration and the ratio of gravity to viscosity of fluid.

FIGS. 8
a, 8b, and 8c show a more detailed view of the pump assembly 77 being run into the well. FIG. 8a shows the well completion before a pump assembly is run in. FIG. 8b shows the apparatus of FIG. 8a with the pump assembly being run into the production tubing 68 using a wire running tool 111. This example shows the pump assembly 77 being run into the well using a wireline 113, but coiled tubing may also be used. FIG. 8c shows the pump assembly 77 connected to the side pocket valve 72 and wet-connect 74.

The pump assembly 77 comprises a fluid side pocket sub 124, a pump 127, an electric side pocket sub 118 and a motor 116. The lower end (in use) of the pump 127 is connected to the side pocket sub 124. The upper end of the pump 127 is connected to the electric side pocket sub 118. The electric motor 116, provided to drive the pump 127, is connected to the upper end (in use) of the electric side pocket sub 118.

The detailed view of FIG. 8a shows that side pocket valve 72 comprises a check valve 107 and a fluid connect 101. The fluid side pocket sub 124 is connectable to the fluid connect 101. The electric side pocket sub 118 is connectable to the electrical wet-connect 74. The pump 127 has a pump discharge 122 to enable fluid communication between the pump 127 and annular flow path 82 via the apertures 87 in the production tubing 68.

Once the pump assembly 77 is run into the tubing 68, it is located at the appropriate wet-connect 74 and side pocket valve 72 as shown in FIG. 8c. There are preferably locating means (not shown) incorporated into the pump assembly 77 and on the production tubing 68 to activate the locating means in the correct position allowing the pump assembly 77 to mate with the wet-connect 74 and side pocket valve 72.

An aperture (now shown) is provided in the production tubing 68 adjacent to each side pocket flow valve 71-73 to allow fluid produced from any of the pumps below said valves to bypass the respective pumping assembly 75, 77, 79 by flowing into the annular flow paths 81, 82, 83.

Referring to FIG. 8c, it is illustrated that in use, fluid from lower zone 63 flows up the production tubing 68 as shown by an arrow 133. This fluid flows through said aperture (not shown) in the production tubing 68 and into the annular flow passage 82, arrow 134. It continues up the annular flow passage 82 and mixes with further fluid from the adjacent production zone 62 as described further below.

Fluid from the production zone 62 adjacent the pump 77 first flows through the check valve 107 as indicated by an arrow 131. The fluid then flows though the fluid connect 101 to enter the fluid side pocket sub 124, from where the fluid is drawn into the pump 127 where its pressure and flow rate are equalised with that of the fluid received from the lower zone 63. The pump 127 is driven by the electric motor 116. Power for operating the electric motor 116 is supplied via the electric wet-connect 74 and the electric side pocket sub 118.

Fluid from the zone 62 proceeds from the pump assembly 77 to the annular flow passage 82 via the pump discharge 122 and apertures 87 in the production tubing 68. There, it mixes with the fluid from the lower zones, flows past the electric wet-connect 74, and the combined flow then re-enters the production tubing 68 via the apertures 86. The packer 66 at the top of the annular flow passage 82 prevents the fluid from continuing up the annular flow passage 82.

The combined flow then takes the corresponding route past the upper pump 75 (i.e. diverted via annular flow path 81) as described here for flow from the lower pump 79 and corresponding zone 63.

In alternative embodiments, the flow released from any of the pumps, for example pump 77 may be released directly into the production tubing 68 above the motor 116 rather than through the apertures 122.

A further option is to have pumps and associated assemblies smaller than the production tubing and to have the fluid pumped up through a further annulus between the pumps and the production tubing.

Pressure of hydrocarbons at the pump discharge can be controlled or boosted by the pump 127 such that they are comparable or equivalent to the pressure and flow rate of hydrocarbons from the other zones.

One advantage of such embodiments of the present invention is that the risk of cross-flow is reduced because the pressure of the fluid emitted from the various pumps is the same regardless of the pressure in the various production zones to which the pumps communicate.

A further benefit of certain embodiments of the present invention is that the flow rate of the fluid from different production zones can be boosted to the natural flow rate of the zone with the highest formation pressure, or even higher. Thus hydrocarbons can be recovered much quicker than conventional choke valves which attempt to restrict the flow rate to that produced by the production zone with the lowest formation pressure.

Instead of or in addition to the wire wrapped screens on the pumps, other suitable filtration methods or sand control techniques such as gravel packing and sand consolidation can be used.

The embodiment of FIG. 8a-8c may be used in a well with a single production zone. If required during use, the pump 77 can be recovered back to the surface.

FIGS. 9
a and 9b illustrate an electrical powered valve assembly 230 being run into the casing 60 using wireline 211 and installed in position within the production tubing 68 shown in FIG. 8a.

The electrical pump of FIGS. 8a and 8b has been replaced with the electrical powered valve assembly 230, shown in FIGS. 9a and 9b. In this embodiment, production rates of hydrocarbons can be controlled by varying the choke sizes, thereby altering the flow rate. This is a less preferred embodiment since the pressure control is inferior to that afforded by pumps. The valves are however removably connectable to the side pocket valve 72 and can thus be conveniently replaced in the event of failure.

The valve assembly 230 comprises a fluid side pocket sub 224, a variable area choke 270 and an electric side pocket sub 218. The sub 224 is a short adaptor branching the connect 101 and the variable choke area 270. The upper end (in use) of the fluid side pocket sub 224 is connected to the lower end of the variable area choke 270. The upper end (in use) of the variable area choke 270 is connected to the electric side pocket sub 218. The variable area choke 270 adjusts the flow of fluid appropriately and is operated by power supplied by an electrical conduit (not shown) via the electric wet-connect 74 and the electric side pocket sub 218.

An arrow 233 illustrates the flow of fluid from lower zones before it bypasses the valve assembly 230. Fluid from the zone 62 passes check valve 107 and the fluid connect 101 to enter the fluid side pocket sub 224 as shown by an arrow 231. The fluid passes through variable area choke 270 and exits electric side pocket sub 218 into the production tubing 68 as shown by an arrow 237. Fluid flowing out of electric side pocket sub 218 mingles with flow from lower zones shown by the arrow 232 on exiting apertures 87 to create a combined flow through the annular flow path 82.

The embodiment of FIGS. 9a-9b may be used in a well with a single production zone. If required during use, the valve assembly 230 can be recovered back to the surface.

An alternative arrangement is shown in FIGS. 10a and 10b. FIGS. 10a and 10b show similar apparatus to that shown in FIGS., 9a and 9b with like components having the prefix “3” instead of “2”. In this embodiment, the valve assembly 330 does not include an electric side pocket sub for connection with the electrical wet-connect 74. The wet-connect 74 is thus redundant when such an embodiment is used.

FIG. 10
a shows a variable area choke 370, being run into the production tubing 68 (shown in FIG. 8a) using a wireline 311. In use formation fluid flows through the check valve 107 and into a fluid side pocket sub 324 via the fluid connect 72, from where it passes into the variable area choke 370. The variable area choke 370 controls the rate of flow of fluids exiting the choke shown by an arrow 337. These fluids progress up the production tubing 68 where apertures 87 in the production tubing 68 allow combined flow and mixing with fluids from lower zones in the annular flow path 82. The direction fluid flow from lower zones is indicated by arrows 333 and 332.

Thus the embodiments using valves and no pumps allow for co-mingled flow. In the event of failure of any of the valves they may be recovered to the surface by a wireline, such as wirelines 211, 311.

Various choke sizes may be used, allowing hydrocarbons to be produced up the tubing from various formation pressures.

For alternative embodiments of the invention, each producing zone may have a corresponding pump assembly to control the pressure and flow rate of the fluid, except one of the zones, typically the zone with the largest formation pressure. Sensors may be added to such a zone and from these sensors, combined with calculations on the data on the flow rates through the pumps in other zones, the flow rates of the pumps may be manipulated to allow for co-mingled flow.

The embodiment of FIGS. 10a-10b may be used in a well with a single production zone. If required during use, the valve assembly 330 can be recovered back to the surface.

In certain embodiments, the pump or valve is provided in a side pocket of the well, as shown in FIGS. 11a and 11b. In FIG. 11a, a casing 502 encloses production tubing 504. The casing 502 is normally concentric with the production tubing but adjacent to a well connector 510, the production tubing 504 deviates from concentric alignment with the casing 502 to define a side pocket 508. The well connector 510 is provided in the side pocket 508 for connection to the pump or valve 506, as shown in FIG. 11b. The pump or valve 506 and well connector 510 can function as described for any other embodiment disclosed herein.

The side pocket may also be provided by a length of production tubing which is wider than the remaining production tubing in order to provide space for the well connector 510 and the pump 506 but still provide access to the well below.

To launch the pump 506, it is lowered down through the production tubing 504. Adjacent to the side pocket 508, a kick-over tool (not shown) is activated to cause the pump 506 to move into the side pocket 505 through a port 505 in the production tubing 504. The pump then mates with the well connector 510.

Such a configuration allows full bore access through the production tubing 504 to the well below the pump or valve 510 in contrast to certain known designs where such access is not possible.

The well connector 510 and pump 506 are shown in more detail in FIG. 12a and FIG. 12b. The pump has seals 512 surrounding electrical connectors 514 which mate with electrical connectors on the well connector 510. In use, fluid from the well flows from the well connector 510 into a bore 516 of the pump 508 and then proceeds to the surface via the production tubing 504. Thus the electrical and fluid connection are conveniently made by the same connection.

One will appreciate that a plurality of pumps, such as the pump 506, may be provided in a series of side pockets for a plurality of production zones, as detailed for earlier embodiments. The embodiment of FIGS. 10a-10b may be used in a well with a single production zone.

In any case, if for any reason a pump needs to be retrieved to the surface, this can be done and without removing any pumps thereabove. Thus the pumps are independently retrievable. Wireline, coiled tubing or pipe may be used to retrieve the pumps.

For certain embodiments, a well connector may be provided in a side pocket such that it receives a pump assembly/valve etc from below. This provides the benefit that when the well connector is not engaged with a pump/valve etc, fluids are less liable to enter the well connector 510 and damage components therein or inhibit a subsequent connection. A pump assembly can be mated with the well connector in a similar way—a kick-over tool moves the pump assembly transversely when it passes a port below the well connector. The pump assembly is then moved in an upwards direction in order to connect the pump assembly and the well connector.

A further embodiment of a valve assembly 430 in accordance with one aspect of the present invention is shown in FIGS. 13a to 13d. The valve assembly 430 comprises a first upper portion 491 shown in FIG. 13b and a second lower portion 492 shown in FIG. 13a.

Referring to FIG. 13b, the upper portion 491 comprises a housing 480 with a fishing neck exterior 481, and a central bore 482. An aperture 496 is provided in the housing 480 to allow production fluid to exit the bore 482 of the housing 480 to the exterior of the valve assembly 430.

A piston 493 is provided in the housing 480 and is connected to a spear valve 495, which in use regulates the access for fluid to exit the valve assembly 430 via the aperture 496.

At a head 493H of the piston 493, a hydraulic chamber 497 is defined by seals 498. A hydraulic line 499 leads to said hydraulic chamber 497 which in use controls movement of the piston 493 and attached spear valve 495, as described below. A spring 494 urges the piston 493 to return the spear valve 495 to its closed position in the absence of any other forces.

A J-pin 489, shown in FIG. 13e, is provided in a slot 480S in the housing 480 and can engage with recesses 493R and 493R′ in the piston 493 in order to hold the piston 493 in a position which corresponds to a valve fully open position, a valve closed position, and a number of intermediate positions. Alternatively the hydraulic pressure in the hydraulic chamber 497 may be varied in order to allow the piston 493 and valve 495 to adopt any position between the valve fully open and the valve closed position.

Referring to FIG. 13a, the lower portion 492 of the valve assembly 430 comprises a housing 580, a central bore 582, a hydraulic line 599 and a hydraulic input 570. The hydraulic input 570 of the lower portion 492 is connected to a hydraulic line which is provided within the annulus between production tubing and casing of the well (not shown) in which the valve assembly 430 is operated.

In use, the upper portion 491 is landed on the lower portion 492, as shown in FIG. 13c, such that the lower portion 492 is inserted into the bore 482 of the upper portion 481. Seals 571 and 572 seal the portions together around their respective hydraulic lines 499, 599 which align together. The spear valve 493 of the upper portion 481 seals the bore 582 of the lower portion.

In use production fluid is produced and directed up the bore 582 of the lower portion 492 by a connection (not shown) with the producing zone, typically via a valve such as a side pocket flow valve 72 shown in FIG. 8a. When the spear valve 493 is in its closed position, as shown in FIG. 13c, the production fluid cannot flow any further.

To operate the valve assembly 430 the hydraulic line is pressurised at the surface, which in turn pressurises the hydraulic lines 599, 499 and hydraulic chamber 497 to urge the piston 493 in an upwards direction against the action of the spring 494. Movement of the piston 493 causes the connected spear valve 495 to move and gradually allow access between the bore 482 of the housing 490 and the exterior of the valve assembly 430 via the aperture 496. Thus the amount of fluid flow permitted between these two regions can be controlled by the pressure of the hydraulic fluid applied to the hydraulic chamber 497. In particular the valve functions as a proportional valve—allowing a proportion of the production fluid to flow through the aperture 496 depending on that required by an operator or computer controller. The J-pin can maintain the piston 493 and valve 495 in a number of positions allowing the hydraulic pressure to be released from the hydraulic chamber 497.

The desired amount of fluid can then flow from the bore 582 of the lower portion through the aperture 496 and outside of the valve assembly 430. The fluid continues up the production tubing to the surface.

The aperture 496 may be aligned with an aperture in the production tubing to allow fluid to flow into the annulus between the production tubing and casing. Alternatively the fluid can proceed up the production tubing between the valve assembly 430 and the production tubing.

A series of such valve assemblies can be provided and the flow rate of the production fluid controlled via the proportional valves such that flow from a plurality of production zones can be recovered simultaneously.

A benefit of certain embodiments of the invention, such as those shown in FIGS. 13a-13e, is that they can be easily retrieved from the well for maintenance or for other reasons. In contrast sliding sleeves, known in the art, are difficult to maintain and repair in the event of failure.

In further embodiments, a side-pocket may be provided in the production tubing, with an on/off valve, such as the side pocket flow valve 72, provided in said side-pocket. A proportional valve, similar to that shown in FIGS. 13a-13d, may be lowered into said side pocket and connected to the on/off valve. The hydraulic power is preferably provided by a line which extends from the surface down the well between the production tubing and the casing.

Although the embodiments show zones in vertically spaced formations, the apparatus and method of the present invention may also be used to retrieve fluid from lateral bores.

Improvements and modifications may be made without departing from the scope of the invention.

Method, device and apparatus

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Priority Claims (1)