GB2424011A - A method of obtaining fluid from a multizone well - Google Patents

Abstract

A method of obtaining fluid, typically hydrocarbons, from a first production zone 31 and a second production zone 32, the method comprising: (a) providing a first pump 35 or valve 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; (c) connecting the first device to the first well connector; (d) providing a second pump 37 or valve 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. Certain embodiments allow the devices to be retrieved from the well and access to the well below the pumps is also afforded. Also an apparatus and a releasable device for use in related methods.

Description

1 "Method, Device and Apparatus" 3 This invention relates to a method,

device and 4 apparatus for obtaining or controlling flow of fluid from more than one production zone, in particular, 6 for achieving co-mingled flow of hydrocarbons in oil 7 and gas wells.

9 After a weilbore has been drilled for an oil, gas or water well and the required depth has been reached, 11 the well is fitted with production equipment. This 12 is referred to as "well completion". At this stage, 13 a well will be cased and the necessary production 14 tubing installed, incorporating various isolation seals to ensure integrity and safety of the well.

16 Following installation of the production tubing, 17 fluids can be produced from the various subsurface 18 formations. Fluids may be recovered either through 19 a single producing zone or a plurality of producing zones. * * * *. S S... * S... * S S 55.

1 There are several known ways of producing from a 2 plurality of producing zones, often referred to as 3 multi-zone wells. The simplest option involves 4 simultaneous production from all zones. Fig. 1 shows a sectional view of a known type of well 6 completion having multiple production zones.

7 Production tubing 18 is provided within a casing 10.

8 The annular space is isolated towards the lower end 9 of the production tubing 18 by a production packer 14.

12 First, second and third production zones 11, 12, 13 13 respectively, are formations containing 14 hydrocarbons. The production tubing 18 and the casing 10 are perforated in the region of the zones 16 11, 12, 13 to allow hydrocarbons from each zone 17 simultaneously to flow into the production tubing 18 18. These hydrocarbons are prevented from flowing 19 up the full length of the annulus by the production packer 14. An annular space between each zone 11, 21 12, 13 and the production tubing 18 is isolated by 22 zone isolation packers 16. The apparatus of Fig. 1 23 allows simultaneous production from all zones 11, 24 12, 13.

26 However due to the potentially differing flow rates 27 and pressures in the different zones 11-13, cross- 28 flow may occur resulting in no production from one 29 of the zones. The term "cross-flow" is used to: . describe a situation when fluids from one zone flow S..

31 into a different zone rather than into production 32 tubing and out of the well. Moreover the sediment * S S... a. S

1 within the fluid from the higher pressure zone can 2 block any subsequent attempt at producing from the 3 lower pressure zone.

One method to alleviate this problem, often used in 6 the UK continental shelf, involves isolating each 7 zone and then producing each zone sequentially.

8 Once production is completed in one zone, an inflow 9 control valve is closed and another zone is produced by opening a corresponding inflow control valve.

11 The inflow control valve is often a sliding sleeve 12 which may be operated by coiled tubing in the well.

13 Sticking of such a sleeve in one position is a 14 common failure associated with the sliding sleeve.

16 Another method of producing from multi-zone wells, 17 commonly employed in Africa and the Far East, is the 18 use of dual completion strings. This method entails 19 running two sets of completion tubing into the well.

One or more zones can then produce up one completion 21 string, with the remaining production zones using 22 the second completion string. Each set of tubing is 23 separated from the other and the respective zones 24 are separated using isolation packers. This method can be used in combination with the sequential 26 production method described above, which includes 27 sliding sleeves, to allow production from each zone 28 in turn.

Fig. 2 shows a sectional view of a dual completion 31 prior art well and is a known example of apparatus 32 for producing from multiple zones. A casing 20 * *.* * * *1*S * * * 1 houses two sets of production tubing, 27, 28.

2 Hydrocarbons from a first formation, zone 21, can be 3 produced using the production tubing 27.

4 Hydrocarbons from the first zone 21 can be prevented from entering an annular space between the casing 20 6 and production tubing 27, 28 by a production packer 7 24. The second and third zones 22, 23 can be 8 produced using the production tubing 28 and 9 hydrocarbons from these zones 22, 23 are prevented from mixing with hydrocarbons produced in the first 11 zone 21 by a zonal isolation packer 26.

13 The amount of equipment required and the high cost 14 of installing an additional set of production tubing makes dual completion an expensive method of multi- 16 zone production.

18 So-called "intelligent wells" are an alternative 19 method of producing from multiple zones and these provide choke valves for each production zone.

21 Intelligent wells are generally acceptable for zones 22 with small pressure differences. However for zones 23 with larger pressure differences, the pressure of 24 the fluid from the higher pressure production zone remains relatively high after proceeding through the 26 choke valve (which primarily controls its rate) and 27 thus the same problems can occur with cross-flow 28 between the production zones. 29 a

Other disadvantages associated with intelligent 31 wells include the large expense required for 32 installation, operation and maintenance. * S S... * . S

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1 Additionally, the complicated valves and permanent 2 gauge systems such as those used in intelligent 3 wells can be unreliable. Repairing damaged choke 4 valves is also conventionally difficult and expensive.

7 An object of the present invention is to alleviate 8 any of the problems associated with the prior art.

According to a first aspect of the present 11 invention, there is provided a method of obtaining 12 fluid from a first production zone and a second 13 production zone, the method comprising: 14 (a) providing a first device to produce or control flow of fluid from the first production 16 zone; 17 (b) in a well, providing a first well connector 18 proximate to, and in fluid communication with, the 19 first production zone; (c) connecting the first device to the first 21 well connector; 22 (d) providing a second device to produce or 23 control flow of fluid from the second production 24 zone; (e) in the well, providing a second well 26 connector proximate to, and in fluid communication 27 with, the second production zone; S...

28 (f) connecting the second device to the second 29 well connector; (g) producing fluids from the first and second 31 production zones through the well connectors and 32 optionally through the devices. * S S... S...

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2 The method is not limited to performing steps(a) to 3 (g) in any particular order unless specifically 4 stated.

6 Preferably the well is a hydrocarbon producing well.

8 Preferably at least one well connector is provided 9 in the well during completion of the well.

11 Typically the first and second devices are 12 independently operated.

14 Typically the well comprises casing with production tubing provided therein, and at least one well 16 connector is provided in a side pocket provided in 17 the production tubing, wherein when the device is 18 connected to the well connector, the device is 19 typically substantially located in the side pocket.

21 Preferably each well connector is located in a side 22 pocket.

24 Preferably at least one device is releasably connected to at least one well connector.

27 Preferably at least one device also connects to a 28 power connector provided in the well, to supply the 29 device with power. 30..

31 Preferably the device connected to a power connector 32 is releasably connected to the power connector. S... * S

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2 The power connector may be in-built into the well 3 connector so that a single connection connects the 4 well connector and device with power and fluid.

Alternatively separate connecting members may be 6 provided for power and fluid connections.

8 There may be more than two production zones.

9 Typically each zone has a corresponding well connector and device. Optionally one zone, 11 typically the one with the highest formation 12 pressure, may not have a device.

14 Preferably each zone is isolated from the other zones such that production fluid cannot pass from 16 one zone to another.

18 Preferably each device is releasably connected to 19 each well connector.

21 Depending on the pressure of the first and second 22 production zones, the first and second devices or 23 pumps may, in use, independently reduce the pressure 24 and/or flow rate of the fluid from the zones, or alternatively increase the pressure and/or flow rate 26 from the zones. S..,

28 According to a second aspect of the present 29 invention, there is provided a device for producing or controlling fluid from a well, the device 31 comprising a means to control or produce the flow of 32 fluid from a zone, and a connector to releasably I... *

* IS S *5Se * * * S 1 connect with a well connector, the well connector, 2 in use, in fluid communication with the production 3 zone.

Preferably the device according to the second aspect 6 of the invention is used in the method according to 7 the first aspect of the invention.

9 The device typically comprises a valve.

11 Alternatively the device may comprise a pump 12 assembly.

14 The device is typically adapted to connect with a power connector provided in the well connector.

17 The device may be hydraulically powered.

19 The device may be electrically powered.

21 The device typically has a main longitudinal axis 22 and is lowered within a well to form the connection 23 with the well connector, the device is typically 24 lowered in a direction generally parallel to said longitudinal axis, and a portion of the device which 26 connects to the well connector may extend 27 transversely with respect to said longitudinal axis. 28::.

29 Typically the well connector provides for fluid communication between the device and the production 31 zone. t I... * SI * * I.

1 The valve may be used as a gas lift valve whereby 2 gas is pumped down the annulus between casing and 3 production tubing and exits through a side pocket 4 into the well.

6 Pumps suitable for this application include suitably 7 modified electric submersible pumps, progressive 8 cavity pumps and jet pumps.

For electric submersible pumps, a variable 11 controller is typically provided which may be 12 located at the surface or downhole.

14 Preferably the device comprises a further connector adapted to connect with an electrical connector 16 provided in the well.

18 The pump is typically provided as a pump assembly 19 comprising a plurality of parts, wherein the pumping action is provided in one part, the first connector 21 in a second part and the second connector in a 22 further part.

24 Where the device comprises a valve, typically the valve is a proportional valve, that is the 26 proportion of fluid which can pass the valve is 27 continuously variable from zero to a maximum value.

29 Typically the device is shaped and adapted to be lowered and raised within a well by an elongate 31 member, such as a wireline. S... S * S. S

1 The device is preferably shaped and adapted to be 2 raised and lowered in the production tubing of a 3 well.

Preferably the well connector comprises a check 6 valve - thus it is not necessary to have a check 7 valve in the device. This prevents back flow into 8 the well connector when the valve or pump is 9 removed.

11 According to a third aspect of the invention, there 12 is provided a well apparatus comprising: 13 a casing lining a well and a production tubing 14 provided within the casing; a first well connector proximate to a first 16 production zone, the first well connector, in use, 17 in communication with the production zone; 18 the well connector being connectable to a first 19 device, said device comprising a means to control or produce a flow of fluid from the production zone; 21 a second well connector proximate to a second 22 production zone, the second well connector, in use, 23 in communication with the second production zone; 24 wherein the second well connector is connectable to a second device, said second device 26 comprising a means to control or produce a flow of 27 fluid from the production zone. 28 e

29 Preferably the device according to the third aspect of the invention is the device according to the 31 second aspect of the invention. Preferably the 32 apparatus comprises the device. *0**

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2 Preferably the apparatus according to the third 3 aspect of the invention is used with the method 4 according to the first aspect of the invention.

6 Optionally at least one device comprises a valve.

8 Alternatively at least one device comprises a pump.

Preferably the well connector is provided in a side 11 pocket of the production tubing between the casing 12 and the production tubing.

14 At least one well connector may be provided such that the device connects on the underside of the 16 well connector. This can reduce the amount of 17 debris which can fall into the well connector when 18 it is not connected to the device.

At least one well connector can comprise a valve 21 operable in a non-axial direction with respect to 22 the borehole. The valve may be operable in a 23 substantially transverse direction.

The well apparatus may comprise a power and/or 26 control line which extends down the well to the well a...

27 connector which further comprises a power connector cm 28 for connection to the device. a..

Typically the control line is a hydraulic control 31 line. a a a

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1 A single control line may extend from the surface to 2 the bottom of the well. An indexing pilot valve may 3 then control each device. Each device can thus be 4 controlled from a single line.

6 The line may extend on the outside of the production 7 tubing and optionally connections are made through 8 the tubing to the device located in the side pocket.

The power connector may be an electrical connector.

11 For example if an electric submersible pump is used 12 or a stepping motor for a valve.

14 A single electrical power line may provide power for a plurality of devices.

17 The single electrical power line may comprise a 18 first earth core, a second core operating at 19 positive voltage and a third core operating at negative voltage.

22 The voltages are at least 500dc or ac, preferably 23 more than 750dc or ac preferably around l000dc or 24 ac.

26 The power connector may be a hydraulic connector.

27 For example if a jet pump was used or a..

28 hydraulically activated valve. a..

The devices are preferably arranged in the well to 31 allow full bore access to the well beneath the * 32 devices. I... S * a a. *

2 Typically the borehole comprises casing preferably 3 also production tubing and therefore the well 4 connector, in use, preferably connects the production zone to casing and more preferably to 6 production tubing.

8 The production tubing preferably comprises a side 9 pocket extending transversely into the well which is adapted to receive the device. Preferably the side 11 pocket comprises the well connector.

13 The power/control line(s) may extend directly to the 14 device.

16 Optionally, the well connector can also comprise a 17 check valve to prevent fluid backf low into the zone.

19 According to a further aspect of the present invention, there is provided an apparatus for 21 controlling or producing fluid from a well, the 22 apparatus comprising a cartridge, the cartridge 23 comprising a first device and a second device; the 24 devices as herein described.

26 Preferably the cartridge is adapted to be removably 27 connectable to the well. Thus the cartridge is 28 adapted to be lowered and raised within a well by an: . 29 elongate member, such as a wireline. * * *

31 Preferably the apparatus according to the further 32 aspect of the invention is performed using the

S I ** S

1 method according to the first aspect of the 2 invention.

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

7 Proximate' as used herein preferably means within 8 20m of perforations in the well casing or the open 9 bore at the end of the well, preferably within lOm, more preferably within 5m.

12 Any feature of any aspect of any invention or 13 embodiment described herein may be combined with any 14 feature of any aspect of any other invention or embodiment described herein mutatjs mutandjs.

17 Embodiments of the present invention will now be 18 described, by way of example only, with reference to 19 and as shown in the accompanying drawings, in which:- 22 Fig. 1 is a sectional view of a known well 23 completion showing simultaneous production from 24 several zones; Fig. 2 is a sectional view of a known dual 26 completion; S...

27 Fig. 3 is a sectional view of a portion of a 28 well completion and apparatus according to one 29 embodiment of the invention; Fig. 4 is a sectional view of a cartridge 31 according to another embodiment of the 32 invention; *5**

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1 Fig. 5 is a sectional view of a well completion 2 and the Fig. 4 cartridge; 3 Fig. 6 is a sectional view of a well completion 4 in accordance with the present invention ready for producing fluids from multiple zones; 6 Fig. 7 is a sectional view of the well 7 completion of Fig. 6 containing apparatus 8 according to the invention; 9 Fig. 8a is an enlarged view of a portion of the well completion of Fig. 6; 11 Fig. 8b is an enlarged view of a portion of the 12 well completion and apparatus of Fig. 7 showing 13 a pump assembly according to the invention 14 being run in; Fig. 8c is a further view of the Fig. 8b well 16 completion and apparatus with the pump assembly 17 in a position ready to pump fluids to the 18 surface; 19 Fig. 9a is an enlarged view of a portion of the well of Fig. 6 containing an embodiment of a 21 valve assembly according to the invention being 22 run in; 23 Fig. 9b is a further view of the Fig. 9a well 24 completion and valve assembly in a position ready to produce fluids to the surface; 26 Fig. ba is an enlarged view of a portion of 27 the well completion of Fig. 6 containing a S.:.' 28 second embodiment of a valve assembly according: ..

29 to the invention being run in; Fig. lob is a further view of the Fig. lOa well 31 completion and valve assembly in a position 32 ready to produce fluids to the surface; S...

S S S. 5

1 Fig. ha is a sectional view of a well 2 completion in accordance with one embodiment of 3 the present invention; 4 Fig. llb is a sectional view of the Fig. ha well completion with a pump being run in; 6 Fig. hlc is a plan view of a the Fig. ha well 7 completion; 8 Fig. 12a is a sectional view of a well 9 connector and first portion of a device according to a yet further aspect of the 11 invention, in a mated position; 12 Fig. 12b is a sectional view of the Fig. 12a 13 well connector and first portion of a device in 14 a separated position; Fig. 13a is a sectional view of a first portion 16 of a valve assembly according to a further 17 aspect of the invention; 18 Fig. 13b is a sectional view of a second 19 portion of the valve assembly of Fig. 12a; Fig. 13c is a sectional view of both portions 21 of the valve assembly of Figs. 12a and 12b, 22 showing the valve in a closed position; 23 Fig. 13d is a further sectional view of the 24 valve assembly of Figs. 12a and 12b, with the valve in a fully open position; 26 Fig. 13e is a sectional view of a J-pin used in I...

27 the valve assembly of Figs. 12 - l2d; 28 Fig. 14 is an illustrative view of a series of: ..

29 pump assemblies in accordance with one aspect of the present invention. *

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1 Fig. 3 shows a simplified sectional view of one 2 embodiment of the apparatus according to one aspect 3 of the invention in use. Zones 31, 32, 33 contain 4 hydrocarbons and are in vertically spaced relation.

A casing 30 is installed and set in the well after 6 drilling through the zones 31, 32 and 33.

7 Production tubing 38 is provided within the casing 8 30. The resulting annular space between the casing 9 30 and the production tubing 38 is separated by packers 36 above each zone 31, 32, 33.

11 A pump 39 is provided with an entry port (not shown) 12 to allow inflow of hydrocarbons from zone 33 only.

13 An arrow 29 indicates the direction of hydrocarbon 14 flow. A wire wrapped screen 34 is provided before the entry port of the pump 39 for separating sand 16 and other particles out of the hydrocarbons prior to 17 entering the pump.

19 The pump 39 controls the rate and pressure at which hydrocarbons from the zone 33 enter the production 21 tubing 38. Once in the production tubing 38, 22 hydrocarbons can flow up the tubing, bypassing 23 higher pumps.

Similarly, pumps 35, 37 have an entry port with a 26 wire wrapped screen (not shown) to accept 27 hydrocarbons from zones 31, 32 respectively; arrow 28 A'. The pumps 35, 37, 39 are surface controlled: ..

29 and the pressure at which hydrocarbons leave these pumps can be boosted or retarded relative to the 31 formation pressure of the corresponding zones 31, 32 32, 33. Thus the flow rates and pressure of the a...

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1 hydrocarbons being discharged from each pump 35, 37, 2 39 can be equalised regardless of the potentially 3 differing formation pressures in the zones 31, 32, 4 33. This enables the hydrocarbons from all zones to mix and proceed together up the production tubing 38 6 for recovery.

8 A sliding sleeve (not shown), or other shut off 9 device such as a check valve, is provided to seal the perforations in the production tubing 32 if any 11 of the pumps 35, 37, 39 are removed for maintenance 12 and replacement. The pumps 35, 37, 39 can be 13 removed individually on wirelines, leaving the 14 production tubing in place. Thus sliding sleeves used in this way only move to close the perforations 16 in the production tubing and are not used to 17 regulate hydrocarbon flow from the well, as with 18 certain known systems. Since they are therefore 19 used infrequently compared with such known systems, they are far more reliable.

22 The pumps 35, 37, 39 shown in figure 3 are 23 positioned in a side pocket mandrel, such that the 24 installed pumps do not obstruct the production flow path. This construction allows unrestricted 26 wireline access to the bottom of the production 27 tubing.

29 "Formation pressure" as used herein is intended to refer to pressure of the zone. This term can 31 encompass the natural pressure of the zone or the a... * S... a * * a

1 natural pressure when artificially enhanced by means 2 such as steam injection.

4 Pressure sensing apparatus (not shown) can be provided to measure the pressure differential 6 between the intake and the discharge of the pumps 7 35, 37, 39. Such data can be transmitted to the 8 surface where a computer (not shown) may be utilised 9 to assimilate and process the information to artificially control pressure and flow at the pumps 11 35, 37, 39 discharge to ensure co-mingled flow of 12 fluids or hydrocarbons from each zone 31, 32, 33.

14 Pumps suitable for this application include electric submersible pumps, progressive cavity pumps and jet 16 pumps. Pumps used in the present invention are 17 preferably manufactured from corrosion resistant 18 materials.

Alternatively, the flow rate through the pump may be 21 calculated rather than measuring the flow rate using 22 sensors. Flow rate and pressure may also be 23 measured in the well connectors.

The electric submersible pump (ESP) provides a 26 downhole centrifugal pumping system to generate 27 electrically driven artificial lift of fluids 28 passing through the pump. Under certain conditions, 29 they may be used to reduce flow rate and pressure, rather than create more lift. ESP5 are useful for 31 recovery of hydrocarbons from zones or formations 32 with high water cuts (percentage of water to oil) . **

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1 Standard ESPs can be custornised for multi-zone 2 production.

4 Pump motor power can be provided electrically or hydraulically. Electrical power can be transmitted 6 to the pumps using electric cable on the exterior or 7 interior of the production tubing 18. Fig. 14 shows 8 a first and second pump assembly 701 & 702 supplied 9 by a single 3-core cable. Each pump assembly comprises a pump 720, a motor 722 and a commutator 11 724. The cable comprises an earth core (not shown), 12 a second core operating at +l000vdc 710 and a third 13 core 712 operating at -l000vdc. Thus the effective 14 useful power to the pump assemblies 701, 702 is 2000v. However, having the cable at positive and 16 negative voltages facilitates the insulation in the 17 cable to cope with a such a large voltage difference 18 of 2000V. The commutators 724 convert this current 19 to an alternating current. Thus a number of different pump assemblies can be daisy chained' 21 from a common power supply without having to run 22 separate cables down the well. Telemetry can be 23 multiplexed up the DC cables 710, 712 to allow each 24 motor to be independently controlled from the surface. S...

27 It is also possible to provide a wet-connect, 28 enabling the cable to be positioned within a tubular: 29 which carries fluid or hydrocarbons. In the case of a jet pump, hydraulic drive fluid can be transmitted 31 using a hydraulic umbilical positioned either 32 externally or within the production tubing. *. I... S S *

1 Alternatively, the hydraulic umbilical can be 2 operated by coiled tubing. Optionally hydraulic 3 drive fluid can be production fluid from the well.

Fig. 4 shows a further embodiment 50 with pumps 55, 6 57, 59 mounted in a cartridge 58. Isolation packers 7 54 are attached to the exterior of the cartridge.

9 Fig. 5 shows a further well completion in hydrocarbon containing zones 41, 42, 43 with the 11 further embodiment 50 therein. A casing 40 lines 12 the borehole 52, with production tubing 48 arranged 13 substantially centrally therein. Zonal isolation 14 packers 46 are provided to isolate the annular spaces between the casing 40 and production tubing 16 48, above the zones 41, 42, 43.

18 The cartridge 58 is lowered into, and linearly 19 aligned with, the production tubing 48 such that a fluid tight seal is created by the packers 54 21 between the cartridge 58 and the production tubing 22 48 around the zones 41, 42, 43. The cartridge 58 23 functions in a similar way to the apparatus shown in 24 Fig. 3 where hydrocarbons from each zone 41, 42, 43, arrow A', only flow through respective pumps 55, 26 57, 59 with hydrocarbons from each lower zone 42, 43 S...

27 bypassing the higher pumps in the production tubing 1,555 28 58. S..

Provision of the cartridge 58 allows the entire unit 31 to be conveniently removed for servicing, repair or 55.

32 replacement of any of the pumps. 55..

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2 Figs. 6 and 7 show a more detailed sectional view of 3 a portion of an alternative apparatus and well 4 completion in accordance with the present invention.

The well completion has a casing 60 and production 6 tubing 68. The casing 60 is perforated in the 7 region of zones 61, 62, 63. Either side of these 8 perforations the annular space between the 9 production tubing 68 and the casing 60 is sealed using packers 66.

12 Well connectors or side pocket flow valves 71, 72, 13 73 are provided to allow respective flow from each 14 zone 61, 62, 63 therethrough. As shown in Fig. 7, in use, the valves 71, 72, 73 are connected to 16 respective pumping assemblies 75, 77, 79.

18 Electrical wet-connects 74 (shown in Fig. 6) supply 19 electrical power to drive electric submersible pump assemblies 75, 77, 79 (shown in Fig. 7) and these 21 wet-connects 74 are located in the annulus between 22 theproduction tubing 68 and the casing 60. An 23 electrical conduit (not shown) supplying power to 24 drive the pumps is run down the outside of production tubing 68 to each wet-connect 74. S...

27 Fig. 7 shows the electric submersible pump 28 assemblies 75, 77, 79 suspended within the casing: . 29 60. The pump assemblies 75, 77, 79, connect to the electrical conduit via the wet-connects 74 and to S * 31 the valves 71, 72, 73. 55. *s.. $ . S

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1 Annular flow passages 81, 82, 83 are defined between 2 the production tubing 68 and the casing 60 in the 3 region above each pump 75, 77, 79. A series of 4 apertures 84 - 89 is provided in the production tubing 68 adjacent to and above each pump 75, 77, 79 6 to allow for fluid communication between the 7 production tubing 68 and the annular flow passages 8 81, 82, 83 so that flow from below any of the pumps 9 75, 77, 79 is diverted into the adjacent annular flow path 81, 82, 83 before mixing with the flow 11 emitted by the pumps 75, 77, 79 as described in more 12 detail below.

14 The pressure or flow rate of the hydrocarbons emitted from each pump may be continuously adjusted 16 in response to fluctuations in formation pressure.

17 Among the factors that can typically influence the 18 recovery of hydrocarbons from different formations 19 are the different natural formation pressures, different grades of hydrocarbons, well penetration 21 and the ratio of gravity to viscosity of fluid.

23 Figs 8a, 8b, and 8c show a more detailed view of the 24 pump assembly 77 being run into the well. Fig. 8a shows the well completion before a pump assembly is 26 run in. Fig. 8b shows the apparatus of Fig. 8a with I...

27 the pump assembly being run into the production 28 tubing 68 using a wire running tool ill. This 29 example shows the pump assembly 77 being run into the well using a wireline 113, but coiled tubing may 31 also be used. Fig. 8c shows the pump assembly 77 S... * S S's. I.,. S p es S

1 connected to the side pocket valve 72 and wet- 2 connect 74.

4 The pump assembly 77 comprises a fluid side pocket sub 124, a pump 127, an electric side pocket sub 118 6 and a motor 116. The lower end (in use) of the pump 7 127 is connected to the side pocket sub 124. The 8 upper end of the pump 127 is connected to the 9 electric side pocket sub 118. The electric motor 116, provided to drive the pump 127, is connected to 11 the upper end (in use) of the electric side pocket 12 sub 118.

14 The detailed view of Fig. 8a shows that side pocket valve 72 comprises a check valve 107 and a fluid 16 connect 101. The fluid side pocket sub 124 is 17 connectable to the fluid connect 101. The electric 18 side pocket sub 118 is connectable to the electrical 19 wet-connect 74. The pump 127 has a pump discharge 122 to enable fluid communication between the pump 21 127 and annular flow path 82 via the apertures 87 in 22 the production tubing 68.

24 Once the pump assembly 77 is run into the tubing 68, it is located at the appropriate wet-connect 74 and 26 side pocket valve 72 as shown in Fig. Bc. There are - I...

27 preferably locating means (not shown) incorporated es" 28 into the pump assembly 77 and on the production 29 tubing 68 to activate the locating means in the correct position allowing the pump assembly 77 to 31 mate with the wet-connect 74 and side pocket valve .3' 32 72.

* St C * . C 2 An aperture (now shown) is provided in the 3 production tubing 68 adjacent to each side pocket 4 flow valve 71-73 to allow fluid produced from any of the pumps below said valves to bypass the respective 6 pumping assembly 75, 77, 79 by flowing into the 7 annular flow paths 81, 82, 83.

9 Referring to Fig. Bc, it is illustrated that in use, fluid from lower zone 63 flows up the production 11 tubing 68 as shown by an arrow 133. This fluid 12 flows through said aperture (not shown) in the 13 production tubing 68 and into the annular flow 14 passage 82, arrow 134. It continues up the annular flow passage 82 and mixes with further fluid from 16 the adjacent production zone 62 as described further 17 below.

19 Fluid from the production zone 62 adjacent the pump 77 first flows through the check valve 107 as 21 indicated by an arrow 131. The fluid then flows 22 though the fluid connect 101 to enter the fluid side 23 pocket sub 124, from where the fluid is drawn into 24 the pump 127 where its pressure and flow rate are equalised with that of the fluid received from the 26 lower zone 63. The pump 127 is driven by the 27 electric motor 116. Power for operating the 28 electric motor 116 is supplied via the electric wet- 29 connect 74 and the electric side pocket sub 118. a... 30..

31 Fluid from the zone 62 proceeds from the pump 32 assembly 77 to the annular flow passage 82 via the 1 pump discharge 122 and apertures 87 in the 2 production tubing 68. There, it mixes with the 3 fluid from the lower zones, flows past the electric 4 wet-connect 74, and the combined flow then re-enters the production tubing 68 via the apertures 86. The 6 packer 66 at the top of the annular flow passage 82 7 prevents the fluid from continuing up the annular 8 flow passage 82.

The combined flow then takes the corresponding route 11 past the upper pump 75 (i.e. diverted via annular 12 flow path 81) as described here for flow from the 13 lower pump 79 and corresponding zone 63.

In alternative embodiments, the flow released from 16 any of the pumps, for example pump 77, may be 17 released directly into the production tubing 68 18 above the motor 116 rather than through the 19 apertures 122.

21 A further option is to have pumps and associated 22 assemblies smaller than the production tubing and to 23 have the fluid pumped up through a further annulus 24 between the pumps and the production tubing.

26 Pressure of hydrocarbons at the pump discharge can 27 be controlled or boosted by the pump 127 such that 28 they are comparable or equivalent to the pressure 29 and flow rate of hydrocarbons from the other zones.

31 One advantage of such embodiments of the present I..

32 invention is that the risk of cross-flow is reduced 1 because the pressure of the fluid emitted from the 2 various pumps is the same regardless of the pressure 3 in the various production zones to which the pumps 4 communicate.

6 A further benefit of certain embodiments of the 7 present invention is that the flow rate of the fluid 8 from different production zones can be boosted to 9 the natural flow rate of the zone with the highest formation pressure, or even higher. Thus 11 hydrocarbons can be recovered much quicker than 12 conventional choke valves which attempt to restrict 13 the flow rate to that produced by the production 14 zone with the lowest formation pressure.

16 Instead of or in addition to the wire wrapped 17 screens on the pumps, other suitable filtration 18 methods or sand control techniques such as gravel 19 packing and sand consolidation can be used.

21 The embodiment of Fig. 8a - 8c may be used in a well 22 with a single production zone. If required during 23 use, the pump 77 can be recovered back to the 24 surface.

26 Figures 9a and 9b illustrate an electrical powered 27 valve assembly 230 being run into the casing 60 28 using wireline 211 and installed in position within S..

29 the production tubing 68 shown in Fig. 8a.

31 The electrical pump of Figs. 8a and 8b has been 32 replaced with the electrical powered valve assembly 1 230, shown in Figs. 9a and 9b. In this embodiment, 2 production rates of hydrocarbons can be controlled 3 by varying the choke sizes, thereby altering the 4 flow rate. This is a less preferred embodiment since the pressure control is inferior to that 6 afforded by pumps. The valves are however removably 7 connectable to the side pocket valve 72 and can thus 8 be conveniently replaced in the event of failure.

The valve assembly 230 comprises a fluid side pocket 11 sub 224, a variable area choke 270 and an electric 12 side pocket sub 218. The sub 224 is a short adaptor 13 branching the connect 101 and the variable choke 14 area 270. The upper end (in use) of the fluid side pocket sub 224 is connected to the lower end of the 16 variable area choke 270. The upper end (in use) of 17 the variable area choke 270 is connected to the 18 electric side pocket sub 218. The variable area 19 choke 270 adjusts the flow of fluid appropriately and is operated by power supplied by an electrical 21 conduit (not shown) via the electric wet-connect 74 22 and the electric side pocket sub 218.

24 An arrow 233 illustrates the flow of fluid from lower zones before it bypasses the valve assembly 26 230. Fluid from the zone 62 passes check valve 107 27 and the fluid connect 101 to enter the fluid side 28 pocket sub 224 as shown by an arrow 231. The fluid 29 passes through variable area choke 270 and exits electric side pocket sub 218 into the production ** 31 tubing 68 as shown by an arrow 237. Fluid flowing.... 0***

32 out of electric side pocket sub 218 mingles with 1 flow from lower zones shown by the arrow 232 on 2 exiting apertures 87 to create a combined flow 3 through the annular flow path 82.

The embodiment of Fig. 9a - 9b may be used in a well 6 with a single production zone. If required during 7 use, the valve assembly 230 can be recovered back to 8 the surface.

An alternative arrangement is shown in Figs. lOa and 11 lOb. Figs. lOa and lOb show similar apparatus to 12 that shown in Figs, 9a and 9b with like components 13 having the prefix "3" instead of "2". In this 14 embodiment, the valve assembly 330 does not include an electric side pocket sub for connection with the 16 electrical wet-connect 74. The wet-connect 74 is 17 thus redundant when such an embodiment is used.

19 Figure lOa shows a variable area choke 370, being run into the production tubing 68 (shown in figure 21 8a) using a wireline 311. In use formation fluid 22 flows through the check valve 107 and into a fluid 23 side pocket sub 324 via the fluid connect 72, from 24 where it passes into the variable area choke 370.

The variable area choke 370 controls the rate of 26 flow of fluids exiting the choke shown by an arrow 27 337. These fluids progress up the production tubing 28 68 where apertures 87 in the production tubing 68 S..

29 allow combined flow and mixing with fluids from lower zones in the annular flow path 82. The 31 direction fluid flow from lower zones is indicated 5::* 32 by arrows 333 and 332.

2 Thus the embodiments using valves and no pumps allow 3 for co-mingled flow. In the event of failure of any 4 of the valves they may be recovered to the surface by a wireline, such as wirelines 211, 311.

7 Various choke sizes can be used, allowing 8 hydrocarbons to be produced up the tubing from 9 various formation pressures.

11 For alternative embodiments of the invention, each 12 producing zone may have a corresponding pump 13 assembly to control the pressure and flow rate of 14 the fluid, except one of the zones, typically the zone with the largest formation pressure. Sensors 16 may be added to such a zone and from these sensors, 17 combined with calculations on the data on the flow 18 rates through the pumps in other zones, the flow 19 rates of the pumps may be manipulated to allow for co-mingled flow.

22 The embodiment of Fig. lOa - lob may be used in a 23 well with a single production zone. If required 24 during use, the valve assembly 330 can be recovered back to the surface. * S* 26 5S

27 In certain embodiments, the pump or valve is 28 provided in a side pocket of the well, as shown in 29 Figs. lla and llb. In Fig. lla, a casing 502 S...

encloses production tubing 504. The casing 502 is ** 31 normally concentric with the production tubing but I...

32 adjacent to a well connector 510, the production 1 tubing 504 deviates from concentric alignment with 2 the casing 502 to define a side pocket 508. The 3 well connector 510 is provided in the side pocket 4 508 for connection to the pump or valve 506, as shown in Fig. llb. The pump or valve 506 and well 6 connector 510 can function as described for any 7 other embodiment disclosed herein.

9 The side pocket may also be provided by a length of production tubing which is wider than the remaining 11 production tubing in order to provide space for the 12 well connector 510 and the pump 506 but still 13 provide access to the well below.

To launch the pump 506, it is lowered down through 16 the production tubing 504. Adjacent to the side 17 pocket 508, a kick-over tool (not shown) is 18 activated to cause the pump 506 to move into the 19 side pocket 505 through a port 505 in the production tubing 504. The pump then mates with the well 21 connector 510.

23 Such a configuration allows full bore access through 24 the production tubing 504 to the well below the pump or valve 510 in contrast to certain known designs 26 where such access is not possible. *:::: 27 e. * **

28 The well connector 510 and pump 506 are shown in S..

29 more detail in Fig. l2a and Fig. 12b. The pump has 0*** seals 512 surrounding electrical connectors 514 31 which mate with electrical connectors on the well 5'*1** S...

32 connector 510. In use, fluid from the well flows 1 from the well connector 510 into a bore 516 of the 2 pump 508 and then proceeds to the surface via the 3 production tubing 504. Thus the electrical and 4 fluid connection are conveniently made by the same connection.

7 One will appreciate that a plurality of pumps, such 8 as the pump 506, may be provided in a series of side 9 pockets for a plurality of production zones, as detailed for earlier embodiments. The embodiment of 11 Fig. lOa - lOb may be used in a well with a single 12 production zone.

14 In any case, if for any reason a pump needs to be retrieved to the surface, this can be done and 16 without removing any pumps thereabove. Thus the 17 pumps are independently retrievable. Wireline, 18 coiled tubing or pipe may be used to retrieve the 19 pumps.

21 For certain embodiments, a well connector may be 22 provided in a side pocket such that it receives a 23 pump assembly/valve etc from below. This provides 24 the benefit that when the well connector is not engaged with a pump/valve etc, fluids are less 26 liable to enter the well connector 510 and damage 27 components therein or inhibit a subsequent 28 connection. A pump assembly can be mated with the S..

29 well connector in a similar way - a kick-over tool S...

moves the pump assembly transversely when it passes.. : 31 a port below the well connector. The pump assembly S...

S S. *

1 is then moved in an upwards direction in order to 2 connect the pump assembly and the well connector.

4 A further embodiment of a valve assembly 430 in accordance with one aspect of the present invention 6 is shown in Figs. l3a to 13d. The valve assembly 7 430 comprises a first upper portion 491 shown in 8 Fig. l3b and a second lower portion 492 shown in 9 Fig. 13a.

11 Referring to Fig. 13b, the upper portion 491 12 comprises a housing 480 with a fishing neck exterior 13 481, and a central bore 482. An aperture 496 is 14 provided in the housing 480 to allow production fluid to exit the bore 482 of the housing 480 to the 16 exterior of the valve assembly 430.

18 A piston 493 is provided in the housing 480 and is 19 connected to a spear valve 495, which in use regulates the access for fluid to exit the valve 21 assembly 430 via the aperture 496.

23 At a head 493H of the piston 493, a hydraulic 24 chamber 497 is defined by seals 498. A hydraulic line 499 leads to said hydraulic chamber 497 which I..

26 in use controls movement of the piston 493 and 27 attached spear valve 495, as described below. A 28 spring 494 urges the piston 493 to return the spear S..

29 valve 495 to its closed position in the absence of any other forces. S.

31 * S.....DTD: S S S S* *

1 A J-pin 489, shown in Fig. 13e, is provided in a 2 slot 4805 in the housing 480 and can engage with 3 recesses 493R and 493R' in the piston 493 in order 4 to hold the piston 493 in a position which corresponds to a valve fully open position, a valve 6 closed position, and a number of intermediate 7 positions. Alternatively the hydraulic pressure in 8 the hydraulic chamber 497 may be varied in order to 9 allow the piston 493 and valve 495 to adopt any position between the valve fully open and the valve 11 closed position.

13 Referring to Fig. l3a, the lower portion 492 of the 14 valve assembly 430 comprises a housing 580, a central bore 582, a hydraulic line 599 and a 16 hydraulic input 570. The hydraulic input 570 of the 17 lower portion 492 is connected to a hydraulic line 18 which is provided within the annulus between 19 production tubing and casing of the well (not shown) in which the valve assembly 430 is operated.

22 In use, the upper portion 491 is landed on the lower 23 portion 492, as shown in Fig. 13c, such that the 24 lower portion 492 is inserted into the bore 482 of the upper portion 481. Seals 571 and 572 seal the I...

26 portions together around their respective hydraulic 27 lines 499, 599 which align together. The spear 28 valve 493 of the upper portion 481 seals the bore S..

29 582 of the lower portion.

* * *5

S S S

31 In use production fluid is produced and directed up rn,, .5.

32 the bore 582 of the lower portion 492 by a 1 connection (not shown) with the producing zone, 2 typically via a valve such as a side pocket flow 3 valve 72 shown in Fig. 8a. When the spear valve 493 4 is in its closed position, as shown in Fig. l3c, the production fluid cannot flow any further.

7 To operate the valve assembly 430 the hydraulic line 8 is pressurised at the surface, which in turn 9 pressurises the hydraulic lines 599, 499 and hydraulic chamber 497 to urge the piston 493 in an 11 upwards direction against the action of the spring 12 494. Movement of the piston 493 causes the 13 connected spear valve 495 to move and gradually 14 allow access between the bore 482 of the housing 490 and the exterior of the valve assembly 430 via the 16 aperture 496. Thus the amount of fluid flow 17 permitted between these two regions can be 18 controlled by the pressure of the hydraulic fluid 19 applied to the hydraulic chamber 497. In particular the valve functions as a proportional valve - 21 allowing a proportion of the production fluid to 22 flow through the aperture 496 depending on that 23 required by an operator or computer controller. The 24 J-pin can maintain the piston 493 and valve 495 in a number of positions allowing the hydraulic pressure *u..

26 to be released from the hydraulic chamber 497. SS * *S * I.

28 The desired amount of fluid can then flow from the S..

29 bore 582 of the lower portion through the aperture 496 and outside of the valve assembly 430. The. : 31 fluid continues up the production tubing to the 32 surface.

2 The aperture 496 may be aligned with an aperture in 3 the production tubing to allow fluid to flow into 4 the annulus between the production tubing and S casing. Alternatively the fluid can proceed up the 6 production tubing between the valve assembly 430 and 7 the production tubing.

9 A series of such valve assemblies can be provided and the flow rate of the production fluid controlled 11 via the proportional valves such that flow from a 12 plurality of production zones can be recovered 13 simultaneously.

A benefit of certain embodiments of the invention, 16 such as those shown in Figs. 13a - 13e, is that they 17 can be easily retrieved from the well for 18 maintenance or for other reasons. In contrast 19 sliding sleeves, known in the art, are difficult to maintain and repair in the event of failure.

22 In further embodiments, a side-pocket may be 23 provided in the production tubing, with an on/off 24 valve, such as the side pocket flow valve 72, provided in said side- pocket. A proportional valve, #1*.

26 similar to that shown in Figs. l3a - 13d, may be 27 lowered into said side pocket and connected to the 28 on/off valve. The hydraulic power is preferably 29 provided by a line which extends from the surface down the well between the production tubing and the 31 casing. S...

S I I . S

1 Although the embodiments show zones in vertically 2 spaced formations, the apparatus and method of the 3 present invention may also be used to retrieve fluid 4 from lateral bores.

6 Improvements and modifications may be made without 7 departing from the scope of the invention. S., * S ** 54 5 * 3 5 * * * S.. a 5... * S

_ S

S * * S.,. I...

S I S * S

Claims (1)

1 Claims 3 1. A method of obtaining fluid from a first 4 production zone

and a second production zone, the method comprising: 6 (a) providing a first device to produce or 7 control flow of fluid from the first production 8 zone; 9 (b) in a well, providing a first well connector proximate to, and in fluid communication with, the 11 first production zone; 12 (c) connecting the first device to the first 13 well connector; 14 (d) providing a second device to produce or control flow of fluid from the second production 16 zone; 17 (e) in the well, providing a second well 18 connector proximate to, and in fluid communication 19 with, the second production zone; (f) connecting the second device to the second 21 well connector; 22 (g) producing fluids from the first and second 23 production zones through the well connectors.

2. A method as claimed in claim 1, wherein at

I

26 least one well connector is provided in the well 27 during completion of the well. : 29 3. A method as claimed in either preceding claim, wherein the well comprises casing with production * .* * 31 tubing provided therein, and at least one well I...

32 connector is provided in a side pocket in the.

1 production tubing, and when at least one device is 2 connected to the at least one well connector, the 3 device is substantially located in the side pocket.

4. A method as claimed in any preceding claim, 6 wherein at least one device is releasably connected 7 to the well connector.

9 5. A method as claimed in any preceding claim, wherein at least one device also connects to a power 11 connector provided in the well, to supply the device 12 with power.

14 6. A method as claimed in claim 5, wherein at least one device connected to a power connector is 16 releasably connected to the power connector.

18 7. A method as claimed in any preceding claim, 19 wherein the first and second devices are provided in a cartridge which is lowered into the well and the 21 devices provided on the cartridge connect with the 22 well connectors.

24 8. A well apparatus comprising: a casing lining a well and a production tubing S...

26 provided within the casing; 27 a first well connector proximate to a first 28 production zone, the first well connector, in use, 29 in communication with the production zone; the well connector being connectable to a first S...

31 device, said device comprising a means to control or S...

32 produce a flow of fluid from the production zone; **

I

1 a second well connector proximate to a second 2 production zone, the second well connector, in use, 3 in communication with the second production zone; 4 wherein the second well connector is connectable to a second device, said second device 6 comprising a means to control or produce a flow of 7 fluid from the production zone.

9 9. An apparatus as claimed in claim 8, wherein each well connector is provided in a side pocket of 11 the production tubing.

13 10. An apparatus as claimed in claims 8 or 9, 14 wherein at least one well connector comprises a valve operable in a non-axial direction with respect 16 to the borehole.

18 11. An apparatus as claimed in claim 10, wherein 19 the valve is operable in a transverse direction.

21 12. An apparatus as claimed in any one of claims 8 22 to 11, comprising a power and/or control line which 23 extends down the well to at least one well connector 24 which further comprises a power connector for connection to at least one device. I...

27 13. An apparatus as claimed in claim 12, wherein 28 the power connector is an electrical connector.

14. An apparatus as claimed in claim 13, wherein 31 the electrical connector and the well connector are 32 integrated. I,

2 15. An apparatus as claimed in claim 13 or 14, 3 wherein a single electrical power line provides 4 power for a plurality of devices.

6 16. An apparatus as claimed in claim 15, wherein 7 the single electrical power line comprises a first 8 core operating at positive voltage and a second core 9 operating at negative voltage.

11 17. An apparatus as claimed in claim 12, wherein 12 the power connector is a hydraulic connector.

14 18. An apparatus as claimed in any one of claims 8 to 17, wherein the apparatus comprises at least one 16 of said device.

18 19. An apparatus as claimed in claim 18, wherein 19 the device comprises a valve.

21 20. An apparatus as claimed in claim 18, wherein 22 the device comprises a pump.

24 21. An apparatus as claimed in any one of claims 18 to 20, wherein the devices are arranged in the well S... * S

26 to allow full bore access to the well beneath the S. * . S 27 devices. S..

29 22. A device for producing or controlling fluid from a well, the device comprising a means to S..

31 control or produce the flow of fluid from a 32 production zone, and a connector to releasably, : 1 connect with a well connector, the well connector, 2 in use, in fluid communication with the production 3 zone.

23. A device as claimed in claim 22, comprising a 6 valve.

8 24. A device as claimed in claim 23, wherein the 9 valve is a proportional valve.

11 25. A device as claimed in claim 24, comprising a 12 pump assembly.

14 26. A device as claimed in any one of claims 22 to 25, wherein the device is adapted to connect with a 16 power connector provided in the well connector.

18 27. A device as claimed in claim 26, wherein the 19 device is hydraulically powered.

21 28. A device as claimed in claim 26, wherein the 22 device is electrically powered.

24 29. A device as claimed in any one of claims 22 to 28, wherein the device is shaped to be lowered and S...

26 raised within a well by an elongate member, such as 27 a wireline. * S.

29 30. A device as claimed in any one of claims 22 to 29, wherein the device is shaped to be lowered and * . * 31 raised in the production tubing of a well. *5S. S * *

1 31. A device as claimed in any one of claims 22 to 2 30, having a main longitudinal axis and, in use, is 3 lowered within a well to form the connection with 4 the well connector, the device is lowered in a direction generally parallel to said longitudinal 6 axis, and a portion of the device which connects to 7 the well connector extends transversely with respect 8 to said longitudinal axis. *0*S * * S... S. * * . S * S. * .. * **. * S S *. S *.S. * S **5a I... * S S. 0