GB2409691A

GB2409691A - Separating apparatus and method for phases of a downhole produced fluid

Info

Publication number: GB2409691A
Application number: GB0404870A
Authority: GB
Inventors: Stuart Gordon; Paul R Shotter
Original assignee: Pump Tools Ltd
Current assignee: Pump Tools Ltd
Priority date: 2003-03-05
Filing date: 2004-03-04
Publication date: 2005-07-06
Anticipated expiration: 2024-03-04
Also published as: GB0404870D0; GB0304962D0; GB2409691B

Abstract

Separating apparatus for, and a method of separating phases of, downhole produced fluid, the different phases possibly being made up of a solids phase such as sand, a first liquid phase such as water, a second liquid phase such as liquid hydrocarbons and a fourth phase of gaseous hydrocarbons. A fluid flow path is defined by a flow path member (4), which may be a helically arranged auger (4), having a longitudinal length, the fluid flow path being arranged to be a greater distance than the said longitudinal length so that the multiphase produced fluid is rotated whilst flowing along the flow path. The multiphase downhole fluid enters the apparatus through a fluid flow inlet (3), flows along, and is separated by the fluid flow path. A first portion such as the latter three phases flows through a primary fluid flow outlet and may flow onto a pump (9) and a second portion such as the solids phase passes through a secondary fluid flow outlet (8) which may lead toward a disposal zone.

Description

1 2409691 1 Separating Apparatus and Method 3 The present invention

relates to separating 4 apparatus for use with fluid pumps in downhole well bore applications.

7 In the extraction of resources from beneath the 8 earth's surface, and especially in the oil and gas 9 exploration and production industry, it is often necessary to overcome pressure differentials 11 (hydrostatic head) between the fluid reservoir and 12 the surface. This is often achieved using a pump 13 such as an Electrical Submersible Pump (ESP), which 14 uses a pumping action to extract the fluid from the reservoir and pump it toward the surface, thereby 16 overcoming the hydrostatic head pressure. In 17 operation, such pumps are often situated in 18 inaccessible positions, deep within the well bore 19 making maintenance both very difficult and costly; indeed, such pumps can be located over one mile 21 deep. Clearly a device which would extend the life 22 of such pumps, whilst operating within the confines 1 of a well bore, will have significant applications 2 in the oil and gas industry as well as in the 3 extraction of water for e.g. drinking water and 4 dewatering of oil and gas wells as well as dewatering coal bed methane wells where natural 6 pressure drive is insufficient and pumps have to be 7 used.

9 An important factor determining the lifetime of such pumps is the quantity and size of solid particles 11 present in the fluids passing through the pump. The 12 presence of such solid particles is rarely desired 13 in the produced fluids, and causes excessive erosion 14 of the pump components such as seals, bearings and impellers. The prevention of solid particles from 16 entering the pump will therefore result in prolonged 17 pump lifetime and maintenance intervals.

19 Conventionally this has been done using separating devices such as cyclones, but these devices can 21 suffer from the problem that the removed solids can 22 re-enter the flow path to the pump. These devices 23 can also be relatively inefficient.

According to the present invention there is provided 26 separating apparatus for separating phases of 27 downhole produced fluid, the separating apparatus 28 comprising a fluid flow path defined by a flow path 29 member having a longitudinal length, the fluid flow path being arranged to be a greater distance than 31 the said longitudinal length; 1 a fluid flow inlet through which the downhole 2 produced fluid to be separated is arranged to flow 3 and which is in fluid communication with the said 4 fluid flow path; a primary fluid flow outlet through which a 6 first portion of the downhole produced fluid is 7 adapted to pass; and 8 a secondary fluid flow outlet through which a 9 second portion of the downhole produced fluid is adapted to pass.

12 According to the present invention there is also 13 provided a method of separating phases of downhole 14 produced fluid, comprising: providing a fluid flow path downhole defined by 16 a flow path member having a longitudinal length, the 17 fluid flow path being arranged to be a greater 18 distance than the said longitudinal length; 19 arranging for the downhole fluid flow to pass along the fluid flow path, such that a first portion 21 of the downhole produced fluid flows through a 22 primary fluid flow outlet and a second portion of 23 the downhole produced fluid flows through a 24 secondary fluid flow outlet.

26 Preferably, the primary fluid flow outlet is in 27 fluid communication with downhole pump means.

28 Typically, the secondary fluid flow outlet is in 29 fluid communication with a receptacle which is adapted to retain the second portion of the downhole 31 produced fluids. Typically, all the downhole fluid 32 flow passes along the fluid flow path.

2 Preferably, the fluid flow path comprises a 3 substantially helically arranged fluid flow path.

4 Typically, the fluid flow path is in the form of a helix about a longitudinal axis, and the downhole 6 produced fluids preferably rotate about the 7 longitudinal axis in a helixing manner such that the 8 second portion of the downhole produced fluid is 9 forced to move toward the radially outermost portion of the fluid flow path.

12 Preferably, the first portion of the downhole 13 produced fluids has had solids, of a greater size 14 than a maximum size, substantially removed, and the maximum size may be predefined.

17 Preferably, the second portion of the downhole 18 produced fluids substantially contains solids of a 19 greater size than a maximum size.

21 Typically, the fluid flow at the fluid flow inlet 22 comprises a number of fluid phases. Typically, the 23 fluid flow at the fluid flow inlet comprise any one 24 of, combinations of or all of a first phase substantially comprising solids such as sand, a 26 second phase substantially comprising water, a third 27 phase substantially comprising liquid hydrocarbons 28 and a fourth phase substantially comprising gaseous 29 hydrocarbons.

1 Preferably, an outer sleeve member is provided which 2 circumferentially surrounds at least a portion of 3 the fluid flow path.

Preferably, the outer sleeve member is of a 6 substantially similar diameter to that of the fluid 7 flow path.

9 Alternatively, the outer sleeve member is of a larger diameter than that of the fluid flow path.

12 Typically, an upper seal is provided which is 13 adapted to prevent any fluid flow from passing up a 14 well bore section above the separating apparatus until the fluid flow has passed through the 16 apparatus, by partially blocking the upper well bore 17 section.

19 Optionally, a lower seal is also provided which prevents the second portion of the downhole produced 21 fluid from recentering the fluid flow path from the 22 second portion receptacle, by partially blocking a 23 lower well bore section.

Preferably, the fluid flow inlet comprises a 26 plurality of outer slots provided through the outer 27 sleeve member.

29 Optionally, the outer slots provide an initial rotational velocity to the fluid upon entering the 31 outer sleeve member.

1 Preferably, the outer slots are located at or toward 2 the upper end of the outer sleeve member.

4 Alternatively, the outer sleeve member is open at both ends.

7 Preferably, the primary fluid outlet is in fluid 8 communication with a suction pipe member and 9 typically the first portion of the downhole produced fluids are transported toward the downhole pump 11 means by the suction pipe member.

13 Preferably, the suction pipe member projects 14 longitudinally through the centre of the fluid flow path and outer sleeve member.

17 Preferably, the primary fluid flow outlet comprises 18 a plurality of apertures provided through the 19 suction pipe member.

21 Preferably, the apertures are located toward a lower 22 end of the fluid flow path and more preferably, the 23 apertures are located at or toward a lower portion 24 of the suction pipe member.

26 Alternatively, the suction pipe member is open at 27 the lower end.

29 Preferably, the suction pipe member is adapted to remove gaseous substances from the fluid flow path.

31 Typically a plurality of apertures are provided 32 through the suction pipe member, at or toward the 1 upper end of the fluid flow path, which are suitable 2 for gaseous substances to pass through, and are less 3 suitable for liquids and solids to pass through.

The secondary fluid portion receptacle may be 6 adapted to remove the second portion of the downhole 7 produced fluid to a further remote disposal zone.

9 Thus embodiments of the apparatus according to the present invention separate solid particles which may 11 be larger than a maximum size from a fluid with no 12 moving parts and has a minimal pressure drop across 13 the entire apparatus. Those skilled in the art will 14 also realise that embodiments of the present invention offer simpler installation and maintenance 16 over previously used devices, and are replaceable at 17 each pump changeout without resorting to wellbore 18 maintenance.

An embodiment of the present invention will now be 21 described, by way of example only, with reference to 22 the accompanying drawing in which: 24 Fig. 1 shows a schematic partial cross sectional view of the separating apparatus.

27 Referring to Fig. 1 there is illustrated separating 28 apparatus in accordance with the present invention 29 comprising a helical auger member 4 in the form of an auger 4 surrounding a central suction pipe 6, an 31 outer sleeve 12 surrounding the auger 4, an upper 32 seal 2a partially blocking the upper section of a 1 well bore 1 by forming a seal between the inner 2 surface of the well bore 1 and the outer surface of 3 the central suction pipe 6, and a lower seal 2b 4 partially blocking the lower section of the well bore 1 by forming a seal between the inner surface 6 of the well bore 1 and the outer surface of the 7 outer sleeve 12. The upper 2a and lower 2b seals 8 may be in the form of packer devices.

The upper end of the central suction pipe 6 is 11 connected to a pump 9 (not shown). The central 12 suction pipe 6 has a number of apertures 7 formed 13 through its sidewall and located towards the lower 14 end of the central suction pipe 6. The central suction pipe 6 is provided with a cap (not shown) 16 which seals off its lower end. Furthermore, the 17 central suction pipe 6 has a number of vents 10 18 formed through its sidewall and located along its 19 length which have dimensions suited to removing gases. These vents 10 may be situated along the 21 entire length of the central suction pipe 6 or may 22 be concentrated at an area where build up of gas is 23 likely, such as the area 10 shown in Fig. 1.

The auger 4 surrounds the central suction pipe 6 26 circumferentially, the pitch and length being 27 adjustable during manufacture. The length of the 28 auger 4 is such that it continues down the central 29 suction pipe 6 beyond the apertures 7.

31 The auger is made of standard fittings and tube 32 sizes to allow integration with any pump type.

1 Typical sizes are 5 1/2", 7" & 9 5/8", although any 2 size can be manufactured to suit larger or smaller 3 well bores, based on calculation for scaling of the 4 separation efficiency.

6 The outer sleeve 12 takes the form of a tube 7 substantially similar in inner diameter to the outer 8 most edge of the auger 4, and has outer slots 3 9 formed through its sidewall and provided on the upper end of the sleeve 12. Furthermore, the sleeve 11 12 is provided with a cap at its upper end (not 12 shown) which seals off the upper end of the sleeve 13 12 with respect to the outer diameter of the central 14 suction pipe 6.

16 The upper seal 2a occupies the space between the 17 central suction pipe 6 and the well bore 1 and 18 extends circumferentially around the central suction 19 pipe 6. The upper seal 2a is of a thickness and is made of a suitable material which is capable of 21 withstanding the pressure differentials likely to be 22 exerted upon it.

24 The lower seal 2b occupies the space between the outer sleeve 12 and the well bore 1 and extends 26 circumferentially around the outer sleeve 12. The 27 lower seal 2b is of a thickness and is made of a 28 suitable material which is capable of withstanding 29 the pressure differentials likely to be exerted upon it.

1 In use, the upper end of the separating apparatus is 2 connected to the lower end of a pump 9 (not shown), 3 which is in turn typically connected to a wire line 4 (not shown), and is inserted into the well bore 1.

Upon activation of the pump, fluid (mixed with 6 particles) enters the well bore 1 from the reservoir 7 (not shown) between the upper 2a and the lower 2b 8 seals. The upper seal 2a serves to prevent the 9 fluid from progressing up the well bore 1 through any means other than the central suction pipe 6, 11 thereby ensuring that all fluid progressing up the 12 well bore 1 passes through the separating apparatus.

13 The lower seal 2b prevents any previously separated 14 particles from recentering the pump system post separation. The fluid passes through the outer 16 slots 3 and into the outer sleeve 12. As the fluid 17 progresses downwards along the helical member 4 it 18 is caused to rotate within the outer sleeve 12.

19 Although Fig. 1 shows the outer slots 3 arranged parallel to the longitudinal axis of the apparatus, 21 it will be appreciated that the outer slots 3 may be 22 tangentially arranged in order to further facilitate 23 circulation of the fluid within the outer sleeve 12.

24 This rotational movement of the fluid results in a centrifugal force on the fluid and on any particles 26 suspended in the fluid. Accordingly, the heavier 27 substances within the fluid migrate toward the 28 outside of the helical member 4 until they are 29 restrained by the outer sleeve 12, and lighter substances will be urged towards the core of the 31 helical member/auger 4. In the context of the 32 present invention this results in particles of dirt, 1 sand eta collecting on the inner surface of the 2 outer sleeve 12 and gas collecting on or around the 3 central suction pipe 6. Furthermore, the pumping 4 action acting in the downwards direction through the helical member/auger 4 results in the heavy 6 particles migrating down through the helical 7 member/auger 4 towards a disposal zone 8. Upon 8 reaching the lower end of the helical member/auger 4 9 the heavy particles are deposited in the disposal zone 8, under the action of gravity.

12 Accordingly, the auger 4 provides a helically 13 arranged flow path along which the combined phase 14 fluid must pass. The gas deposited on or around the central suction pipe 6 is able to escape through the 16 vents 10 and into the inner bore of the central 17 suction pipe 6 and then onwards toward the surface, 18 thereby removing the possibility of any gas locking 19 in the separating apparatus.

21 The separated fluid now passes through the apertures 22 7 into the inner bore of the central suction pipe 23 and then onwards toward the pump (not shown) and 2 4 therefore the surface.

26 The solids can then be collected in either the 27 disposal zone 8 or collected in a suitable 28 receptacle (not shown) prior to being transported to 29 the surface where the sand production rates can then be calculated. The sand can be transported by 31 removing the pump and retrieving the sand directly, 1 or by using a by-pass access line with the pump 2 remaining in position.

4 Alternatively, the disposal zone 8 may be fitted with a removal device 11 which is capable of 6 fluidising the deposited solids and hence removing 7 them to a remote solids disposal site (not shown).

8 This remote site may be either in another part of 9 the well bore 1 or on the surface. The provision of such a device prevents the disposal zone 8 from 11 becoming full and therefore adversely affecting 12 operation of the apparatus.

14 Modifications and improvements may be made to the foregoing without departing from the scope of the 16 invention. For example, it will be understood by 17 those skilled in the art, that the length and pitch 18 of the helical member/auger 4 can be varied during 19 manufacture to provide varying amounts of separation. A longer helical member 4 produces 21 greater separation of solids, but has the 22 disadvantage of resulting in a greater pressure drop 23 across the separating apparatus. An increase in 24 pitch angle of the helical member 4 also results in greater separation, but the increase in velocity 2 6 through the helical member 4 caused by such an 2 7 increased pitch angle, results in greater erosion of 28 the apparatus and its components. Typically, the 29 pitch angle of the helical member 4 should be set at between 10 and 70 degrees, depending on the 31 separation requirements and erosion and pressure 32 loss limits.

2 Furthermore, the outer sleeve 12 may be of a 3 slightly greater diameter than the helical member 4 4 providing a gap between the two members 12, 4 so that solid particles may pass directly down the 6 inside of the outer sleeve 12 rather than 7 accumulating on the outside edges of the helical 8 member 4. This may be particularly useful in 9 situations where the concentration and dimension of solid particles is high.

12 Furthermore, the length of the outer sleeve 12 that 13 extends between the lower seal 2b and the lower end 14 of the auger 4 can be greatly increased such that the lower end of the sleeve 12 protrudes through the 16 lower seal 2b until it is below the perforation such 17 that the solids would fall into the rathole or sump 18 at the bottom of the well. Alternatively, the lower 19 seal 2b can be replaced by a capped end provided on the lower end of the sleeve 12, such that the lower 21 end of the outer sleeve 12 acts as a trash can or 22 receptacle for retaining solids. Alternatively, the 23 upper seal 2a can be replaced by a sealed shroud 24 suspended from the ESP pump above it's intake.

Alternatively, the separating apparatus can be 26 suspended from an ESP pump by-pass system (Y-tool) 27 to allow wireline access to the receptacle for 28 bailing purposes; i.e. removal of solids from trash 29 can without requiring removal of the ESP pump.

Claims

1 CLAIMS: 3 1. Separating apparatus for separating phases of 4 downhole

produced fluid, the separating apparatus comprising: 6 a fluid flow path defined by a flow path member 7 having a longitudinal length, the fluid flow path 8 being arranged to be a greater distance than the 9 said longitudinal length; a fluid flow inlet through which the downhole 11 produced fluid to be separated is arranged to flow 12 and which is in fluid communication with the said 13 fluid flow path; 14 a primary fluid flow outlet through which a first portion of the downhole produced fluid is 16 adapted to pass; and 17 a secondary fluid flow outlet through which a 18 second portion of the downhole produced fluid is 19 adapted to pass.

21 2. Separating apparatus according to claim 1, 22 wherein the primary fluid flow outlet is in fluid 23 communication with downhole pump means.

3. Separating apparatus according to either of 26 claims 1 or 2, wherein the secondary fluid flow 27 outlet is in fluid communication with a receptacle 28 which is adapted to retain the second portion of the 29 downhole produced fluids.

1 4. Separating apparatus according to any preceding 2 claim, wherein the fluid flow path comprises a 3 substantially helically arranged fluid flow path.

5. Separating apparatus according to claim 4, 6 wherein the fluid flow path is in the form of a 7 helix about a longitudinal axis.

9 6. Separating apparatus according to claim 5, wherein the downhole produced fluids rotate about 11 the longitudinal axis in a helixing manner such that 12 the second portion of the downhole produced fluid is 13 forced to move toward the radially outermost portion 14 of the fluid flow path.

16 7. Separating apparatus according to any preceding 17 claim, wherein the first portion of the downhole 18 produced fluids has had solids, of a greater size 19 than a maximum size, substantially removed.

21 8. Separating apparatus according to any preceding 22 claim, wherein the second portion of the downhole 23 produced fluids substantially contains solids of a 24 greater size than a maximum size.

2 6 9. Separating apparatus according to any preceding 27 claim, wherein the fluid flow at the fluid flow 28 inlet comprises a number of fluid phases.

10. Separating apparatus according to any preceding 31 claim, wherein the fluid flow at the fluid flow 1 inlet comprise any one of, combinations of or all 2 of: 3 a first phase substantially comprising solids 4 such as sand; a second phase substantially comprising water; 6 a third phase substantially comprising liquid 7 hydrocarbons; and 8 a fourth phase substantially comprising gaseous 9 hydrocarbons.

11 11. Separating apparatus according to any preceding 12 claim, wherein an outer sleeve member is provided 13 which circumferentially surrounds at least a portion 14 of the fluid flow path.

16 12. Separating apparatus according to claim 11, 17 wherein the outer sleeve member is of a 18 substantially similar diameter to that of the fluid 19 flow path.

21 13. Separating apparatus according to claim 11, 22 wherein the outer sleeve member is of a larger 23 diameter than that of the fluid flow path.

14. Separating apparatus according to any preceding 26 claim, wherein an upper seal is provided which is 27 adapted to prevent any fluid flow from passing up a 28 well bore section above the separating apparatus 29 until the fluid flow has passed through the apparatus, by partially blocking the upper well bore 31 section.

1 15. Separating apparatus according to claim 3 or to 2 any of claims 4 to 14 when dependent upon claim 3, 3 wherein a lower seal is provided which prevents the 4 second portion of the downhole produced fluid from recentering the fluid flow path from the second 6 portion receptacle, by partially blocking a lower 7 well bore section.

9 16. Separating apparatus according to claim 11 or to any of claims 12 to 15 when dependent upon claim 11 11, wherein the fluid flow inlet comprises a 12 plurality of outer slots provided through the outer 13 sleeve member.

17. Separating apparatus according to claim 16, 16 wherein the outer slots provide an initial 17 rotational velocity to the fluid upon entering the 18 outer sleeve member.

18. Separating apparatus according to either of 21 claims 16 or 17, wherein the outer slots are located 22 at or toward the upper end of the outer sleeve 23 member.

19. Separating apparatus according to claim 11 or 26 to any of claims 12 to 18 when dependent upon claim 27 11, wherein the outer sleeve member is open at both 28 ends.

20. Separating apparatus according to any preceding 31 claim, wherein the primary fluid outlet is in fluid 32 communication with a suction pipe member.

2 21. Separating apparatus according to claim 20, 3 wherein the first portion of the downhole produced 4 fluids are transported toward a downhole pump means by the suction pipe member.

7 22. Separating apparatus according to either of 8 claims 20 or 21, wherein the suction pipe member 9 projects longitudinally through the centre of the fluid flow path and outer sleeve member.

12 23. Separating apparatus according to any of claims 13 20 to 22, wherein the primary fluid flow outlet 14 comprises a plurality of apertures provided through the suction pipe member.

17 24. Separating apparatus according to claim 23, 18 wherein the apertures are located toward a lower end 19 of the fluid flow path.

21 25. Separating apparatus according to either of 22 claims 23 or 24, wherein the apertures are located 23 at or toward a lower portion of the suction pipe 24 member.

26 26. Separating apparatus according to any of claims 27 20 to 25, wherein the suction pipe member is open at 2 8 the lower end.

27. Separating apparatus according to claim any of 31 claims 20 to 26, wherein the suction pipe member is 1 adapted to remove gaseous substances from the fluid 2 flow path.

4 28. Separating apparatus according to any of claims 20 to 27, wherein a plurality of apertures are 6 provided through the suction pipe member, at or 7 toward the upper end of the fluid flow path, which 8 are suitable for gaseous substances to pass through, 9 and are less suitable for liquids and solids to pass through.

12 29. Separating apparatus according to claim 3 or to 13 any of claims 4 to 28 when dependent upon claim 3, 14 wherein the secondary fluid portion receptacle is further adapted to remove the second portion of the 16 downhole produced fluid to a further remote disposal 17 zone.

19 30. A method of separating phases of downhole produced fluid, comprising: 21 providing a fluid flow path downhole defined by 22 a flow path member having a longitudinal length, the 23 fluid flow path being arranged to be a greater 24 distance than the said longitudinal length; arranging for the downhole fluid flow to pass 26 along the fluid flow path, such that a first portion 27 of the downhole produced fluid flows through a 28 primary fluid flow outlet and a second portion of 29 the downhole produced fluid flows through a secondary fluid flow outlet.

1 31. A method according to claim 30, wherein the 2 primary fluid flow outlet is in fluid communication 3 with downhole pump means.

32. A method according to either of claims 30 or 6 31, wherein the secondary fluid flow outlet is in 7 fluid communication with a receptacle which is 8 adapted to retain the second portion of the downhole 9 produced fluids.

11 33. A method according to any of claims 30 to 32, 12 wherein all the downhole fluid flow passes along the 13 fluid flow path.

34. A method according to any of claims 30 to 33, 16 wherein the fluid flow path comprises a 17 substantially helically arranged fluid flow path.

19 35. A method according to claim 34, wherein the fluid flow path is in the form of a helix about a 21 longitudinal axis, and the downhole produced fluids 22 rotate about the longitudinal axis in a helixing 23 manner such that the second portion of the downhole 24 produced fluid is forced to move toward the radially outermost portion of the fluid flow path.

27 36. A method according to any of claims 30 to 35, 28 wherein the fluid flow at the fluid flow inlet 29 comprise any one of, combinations of or all of: a first phase substantially comprising solids 31 such as sand; 32 a second phase substantially comprising water; 1 a third phase substantially comprising liquid 2 hydrocarbons; and 3 a fourth phase substantially comprising gaseous 4 hydrocarbons.

6 37. A separating apparatus substantially as 7 hereinbefore described with reference to the 8 accompanying drawing.

38. A method of separating phases of downhole 11 produced fluid substantially as hereinbefore 12 described with reference to the accompanying 13 drawing.