GB2413600A - Hydraulically powered borehole pump - Google Patents

Abstract

A hydraulically powered pump 1 adapted to be placed in a well 4 to pump fluids from the well to the surface. The pump may comprise a reciprocating piston within a cylinder bore and be adapted to allow fluid within the well to bias the piston in a first direction and wherein fluid in a separate part of the well is adapted to urge the pump in a second direction opposite the first. The pump may comprise a resilient seal adapted to seal the pump within a portion of production tubing 2. Also independently claimed is an apparatus for recovering fluids from a well, comprising a hydraulically powered pump and conduit 3 and a downhole pump to remove fluids from a wellbore comprising first and second power transmission lines and a piston configured to be displaced within a cylinder.

Description

24 1 3600 1 Apparatus and Method 3 This invention relates to an apparatus

and method to 4 recover fluids from a well and particularly but not exclusively to pump fluids from a gas well where 6 fluid, such as water, hinders the release of the 7 gas. However embodiments of the present invention 8 may also be used to recover oil, particularly in 9 low-producing wells with insufficient natural pressure to produce oil of their own accord.

12 Production of hydrocarbon gas from wells is 13 frequently prevented by the hydrostatic pressure of 14 fluids, water and hydrocarbons which have entered the well bore. To cope with this, fluid is removed 16 from the well using artificial lift methods 17 including but not restricted to electric submergible 18 pumps, progressive cavity pumps and beam-operated 19 pumps.

21 Because of the tight confines of wellbores, it is 22 often not feasible to deploy certain traditional 1 pumping apparatuses to their subterranean depths.

2 Prior artificial lift systems have employed downhole 3 pumps that are actuated by a reciprocating rod. The 4 rod typically extends to the surface where a motor assembly reciprocates the rod, thereby oscillating 6 the downhole pump and bringing the fluids to the 7 surface. While effective, systems of this type 8 usually require the permanent installation of a 9 motor assembly (one having structural support) and the manufacture of a long lift rod to extend down 11 the hole to the subterranean pump. Therefore these 12 systems are costly and require considerable power 13 supply facilities for their operation, making them 14 uneconomical for wells having low levels of production.

17 According to a first aspect of the present invention 18 there is provided a hydraulically powered pump, 19 adapted to be placed in a well and pump fluids from the well to the surface.

22 Preferably the pump is a reciprocating pump.

24 Preferably the pump comprises a reciprocating piston and a cylinder, the cylinder having a bore, wherein 26 the piston is adapted to move within at least a 27 portion of the bore of the cylinder.

29 Preferably the pump is adapted to allow fluid within the well to bias the piston in a first direction.

1 More preferably the pump is adapted to allow pumped 2 fluid within the well to bias the piston in the 3 first direction.

Preferably the piston is biased towards an upper 6 direction. More preferably the pumped fluid biases 7 the piston towards the upper direction.

9 Preferably the pump is adapted to allow fluid in a separate part of the well to urge the piston in a 11 second direction. Preferably the second direction 12 is opposite the first direction.

14 Preferably the piston is urged by the well bore pressure below the pump in the second direction.

16 Preferably the second direction is a lower 17 direction.

19 'Upper' and 'lower' above refer to the general orientation of the pump in use.

22 Preferably a hydraulic chamber is provided which, 23 when pressurized, is adapted to urge the piston in 24 the second direction, the second direction being the opposite direction to the first direction.

27 The hydraulic chamber may comprise, for example, an 28 annular space and a conduit leading to the annular 29 space.

31 Preferably a portion of the bore of the cylinder is 32 shaped to receive well bore fluids.

1 Preferably the cylinder comprises a first valve to 2 allow or prevent fluid communication between the 3 well and the bore of the cylinder.

Preferably the piston has a central bore.

6 Preferably a second valve is provided between the 7 central bore of the piston and the cylinder in order 8 to allow or prevent fluid communication between the 9 central bore of the piston and the bore of the cylinder.

12 Preferably the first and second valves are ball and 13 seat type valves.

Preferably the portion of the cylinder which can 16 communicate with the bore of the piston via the 17 second valve is the same portion of the cylinder 18 which can communicate with the well via the first 19 valve.

21 Preferably the pump comprises a resilient seal 22 adapted to seal the pump within a tube, such as a 23 portion of production tubing.

Preferably a second piston is adapted to compress 26 the resilient seal in order to form a seal between 27 the pump and the tube. Preferably retraction of the 28 second piston causes the seal to decompress and, in 29 use, disengage from the tube.

1 Preferably the second piston is adapted to move 2 following pressurization of a second hydraulic 3 chamber.

The second hydraulic chamber may comprise, for 6 example, an annular space and a conduit leading to 7 the annular space. Preferably a third valve is 8 provided between the second hydraulic chamber and 9 the first hydraulic chamber.

11 Preferably the third valve is adapted to allow 12 hydraulic fluid to flow from the first hydraulic 13 chamber to the second hydraulic chamber when a 14 certain pressure level is reached and preferably resist flow of hydraulic fluid from the second 16 hydraulic chamber to the first hydraulic chamber, 17 preferably regardless of the pressure level.

19 Preferably a radially extendable grip is also provided on an external face of the pump in order to 21 grip a tube such as the production tubing.

23 Preferably a breakable seal is provided between a 24 portion of the pump which, in use and once broken, allows fluid communication between the production 26 tubing and the well below the seal of the pump and 27 the production tubing.

29 Preferably a moveable housing is provided on the outside of the pump and is adapted to engage, and 31 typically move with, the second piston; all with 32 respect to a main body of the pump. Preferably 1 shear pins are provided to resist movement of the 2 housing with respect to the main body of the pump.

4 Preferably a third hydraulic chamber is provided which, when pressurized, urges the housing away from 6 the main body of the pump. Therefore, in use, 7 sufficient pressurization of the third hydraulic 8 chamber can cause the shear pins to break and can 9 cause the housing typically along with the second piston to move with respect to the main body of the 11 pump which preferably, in turn, allows the seal to 12 decompress and disengage from the production tubing.

14 According to a second aspect of the present invention there is provided an apparatus for 16 recovering fluids from a well comprising a 17 hydraulically powered pump and a hydraulic conduit.

19 Preferably the pump according to the second aspect of the invention is the pump according to the first 21 aspect of the invention.

23 Preferably the pump is, in use, suspended in a well 24 by the hydraulic conduit.

26 Preferably the hydraulic conduit is a flexible 27 conduit, that is, it is not rigid enough to transfer 28 a compressing force along its elongate axis.

Preferably the apparatus comprises a system at the 31 surface which is adapted to pressurise the hydraulic 32 conduit and in turn the pump.

1 Preferably the system comprises a timing device in 2 order to repeatedly pressurise and depressurise the 3 hydraulic conduit in order to cause the piston in 4 the pump to reciprocate.

6 According to a third aspect of the present invention 7 there is provided a method for removing fluid from a 8 well, the method comprising: 9 lowering a hydraulically activated pump into a wells 11 the pump being connected to the surface via a 12 hydraulic conduit; 13 hydraulically activating the pump to pump fluid 14 from the well to the surface.

16 Preferably the method according to the third aspect 17 of the invention is performed with the pump 18 according to the first aspect of the invention and 19 more preferably the apparatus according to the second aspect of the invention.

22 Preferably a portion of the pump is secured in 23 production tubing within the well. Preferably the 24 pump is sealed within said production tubing. For certain embodiments of the invention, particularly 26 where the production tubing is above a point where 27 hydrocarbons may enter the well, a portion of the 28 pump is secured in the production tubing whilst the 29 piston and cylinder are spaced away therefrom such that the piston and cylinder are lower than said 31 point where hydrocarbons may enter the well.

1 Preferably the fluid within the production tubing 2 biases the piston of the pump in a first direction.

4 Preferably the pressure within the well, outside the production tubing and preferably below said seal 6 between the pump and production tubing, urges the 7 piston of the pump in a second direction.

8 Preferably the first direction is opposite the 9 second direction.

11 Preferably the hydraulic line is pressurised to a 12 sufficient pressure in order to pass the first valve 13 and urge the second piston down, preferably causing 14 the seal to engage with the production tubing and form a seal therebetween.

17 Preferably the hydraulic line is activated to move 18 the piston from its biased position to the opposite 19 position.

21 Preferably the hydraulic line is repeatedly 22 pressurised and depressurised in order to 23 reciprocate the piston.

The hydraulic line may be provided substantially 26 within the production tubing and can be generally 27 concentric with the production tubing.

29 Optionally further pressure may be applied to the production tubing at the surface in order to 31 increase the pressure therein.

1 In order to remove the pump, the production tubing 2 pressure may be increased by a surface facility to 3 break the breakable seal, thereby equalising the 4 pressure above and below the seal between the production tubing and the pump.

7 The pressure in the hydraulic conduit may be 8 increased in order to break the shear pins and move 9 the second piston along with the housing both with respect to the main body of the pump, thereby 11 allowing the seal to decompress and disengage from 12 the production tubing.

14 The present invention also provides a downhole pump to remove fluids from a wellbore, the pump 16 comprising: 17 a first power transmission line and a second 18 power transmission line; 19 a piston, said piston configured to be displaced within a cylinder from a first 21 upward position to a second downward position) 22 said piston within said housing defining a 23 first fluid chamber and a second 24 fluid chamber said piston urged into said first downward 26 position when pressure within said 27 first power transmission line is increased; 28 said piston urged into said second upward 29 position when pressure within said second power transmission line is 31 increased) and 1 a fluid return line connected to outlets of 2 said first and second fluid 3 chambers.

Pressure within said first and said second power 6 transmission lines may be controlled by a surface 7 pump.

9 The pump may be powered by solar energy.

11 The said first and said second power transmission 12 lines and said fluid return line may extend through 13 a hydraulic pack-off isolating the wellbore from the 14 atmosphere.

16 Gas may be produced from the wellbore simultaneously 17 with the production of fluids through the fluid 18 return line.

The first and said second power transmission lines 21 may extend down the wellbore in a parallel 22 arrangement.

24 The first and said second power transmission lines may extend down the wellbore in a coaxial 26 arrangement.

28 A working fluid used within said first and said 29 second power transmission lines may be the same as the fluids produced through said fluid return line.

1 The first power transmission line may include an 2 injection valve, wherein said injection valve is 3 configured to allow the bleeding of gas from the 4 first power transmission line and the injection of a chemical substance therethrough.

7 The second power transmission line may include an 8 injection valve to allow the bleeding of a chemical 9 substance therethrough.

11 The present invention also provides a method to 12 produce fluids from a wellbore, the method 13 comprising: 14 installing a hydraulically actuated pump to a desired depth within the wellbore; 16 operating the hydraulically actuated pump with 17 a surface power pump, wherein the surface power 18 pump pressurizes power transmission lines 19 extending from the surface of the wellbore to the depth within the wellbore; 21 reciprocating a piston within the hydraulically 22 actuated pump with a surface control system, 23 the surface control system configured to 24 alternate pressure to the power transmission lines to oscillate the piston from a first 26 position to a second position; 27 and pumping the fluids from the wellbore up a 28 fluid return line when the piston is oscillated 29 between the first and the second position.

1 Chemicals may be injected to the desired depth 2 through an injection valve located within the power 3 transmission lines.

Gas may be bled from the power transmission lines 6 through an injection valve mounted thereupon 8 To recover production fluids, a well is normally 9 drilled cased, and cemented. The casing is then preferably connected to a wellhead valving system 11 and the well is preferably perforated at a depth to 12 produce fluids. One embodiment of the present 13 invention preferably includes deploying a pump 14 assembly through the cemented casing or production tubing. The pump assembly for said one embodiment 16 preferably includes a system having three hydraulic 17 lines with a hydraulically actuated pump disposed 18 thereupon. Two of the hydraulic lines preferably 19 transmit hydraulic power to the pump and the third hydraulic line preferably carries the fluids to be 21 produced and discharged from the wellbore.

23 Preferably, fluids are produced through the 24 production line on both strokes (up and down) of the hydraulic pump, but a separate line for each stroke 26 may be desired and used instead. Preferably, the 27 production hydraulic line includes a standing valve 28 or check valve in it to keep fluids from "falling" 29 back down the hydraulic line and returning back to the pump assembly downhole after discharge.

1 Embodiments of the invention will now be described 2 by way of example only with reference to the 3 accompanying figures, in which: Fig. 1 is a schematic sketch of a hydraulically 6 actuated downhole pump assembly in accordance 7 with an embodiment of the present invention; 8 Fig. 2 is a schematic sketch of the 9 hydraulically actuated downhole pump assembly of Fig. 1 and a surface control scheme in 11 accordance with the Fig. 1 embodiment of the 12 present invention; 13 Fig. 3 is a schematic diagram of a valving 14 configuration of a pumping method and apparatus for the Fig. 1 embodiment of the present 16 invention; 17 Fig. 4a is a representation of a gas production 18 well completion including a reciprocating 19 pumping apparatus of an alternative embodiment of the invention, before pumping has begun; 21 Fig. 4b is a representation of the gas 22 production well completion and reciprocating 23 pumping apparatus of Fig. 4a, after pumping has 24 begun; Fig. 5a is a simplified front sectional view of 26 the reciprocating pumping apparatus of Fig. 4a 27 with its piston positioned at the upper end of 28 its stroke; 29 Fig. 5b is a simplified front sectional view of the reciprocating pumping apparatus of Fig. 4a 31 with its piston positioned towards the lower 32 end of its stroke; 1 Figs. 6a-6c are detailed upper, middle and 2 lower front section views of the reciprocating 3 pumping apparatus of Fig. 4a; 4 Figs. 7a-7e are front sectional views of the reciprocating pumping apparatus of Fig. 4a 6 showing its piston in a variety of different 7 positions; 8 Figs. 8a-8e are front sectional views of the 9 reciprocating pumping apparatus of Fig. 4a showing a mechanism for securing and sealing 11 the reciprocating pump within production 12 tubing; 13 Fig. 9 is a simplified front sectional view of 14 a reciprocating pumping apparatus used in an oil production well completion; 16 Fig. 10 is a simplified front sectional view of 17 the reciprocating pumping apparatus of Fig. 4a 18 showing the main bearing surfaces within the 19 apparatus; and, Fig. 11 is a representation of a gas production 21 well completion including a reciprocating 22 pumping apparatus of a further alternative 23 embodiment of the invention, before pumping has 24 begun; Fig. 12 is a representation of the gas 26 production well completion and reciprocating 27 pumping apparatus of Fig. 11, after pumping has 28 begun.

Referring initially to Figure 1, a schematic 31 hydraulic pump assembly 200 is shown. Pump assembly 32 200 preferably includes three hydraulic lines, L1, 1 L2, and L3. L1 is shown as a hydraulic down-stroke 2 operation line, L2 is shown as a hydraulic up-stroke 3 operation line, and L3 is shown as a production 4 fluid return line. While the lines are shown as three distinct lines, it should be understood by one 6 of ordinary skill in the art that lines L1, L2, and 7 L3 may be constructed as a single co-axial line 8 having three distinct fluid flow passages. Pump 9 assembly 200 includes a pump 201 with a hydraulic piston assembly P that reciprocates up and down 11 within a housing of pump assembly 200. Piston P 12 defines two pumping chambers, 211 and 212 and two 13 pressure actuation surfaces U and D. Pressure from 14 line L1 engages surface D and drives piston P down.

As piston P is driven down, chamber 211 fills with 16 production fluids through inlet valve It and 17 production fluids within chamber 212 are forced 18 through outlet valve 02 to line L3. Next, pressure 19 from line L2 engages surface U and drives piston P upward. As piston P is driven upward, chamber 212 21 fills with production fluids through inlet valve I2 22 and production fluids within chamber 211 are forced 23 through outlet valve O1 to line L3. The upward and 24 downward movement of piston P is alternated at a desired frequency to allow production fluids to flow 26 from the wellbore, through line L3, and up to the 27 surface. Valves, It, I2, O1, and 02 are preferably 28 one-way check valves that only allow flow of 29 production fluids in a single direction. Injection valves IV1, IV2 allow for elevated pressures within 31 lines L1, L2 respectively to be released therefrom.

1 Once the apparatus is in location, the hydraulic 2 lines L1, L2 are connected to a surface hydraulic 3 power system 220 that includes a series of valves 4 V1, V2, V3 & V4 and a surface pump 221.

6 Referring briefly to Figure 2, a schematic of the 7 surface hydraulic power system 220 can be described 8 with reference to the hydraulic pump assembly 9 provided in a wellbore 230.

11 The wellbore 230 has casing 231 with perforations 12 232. A wellhead 233 is provided at the top of the 13 well and the lines L1, L2, L3 are sealed therein by 14 packers (not shown). The line L3 (which recovers the hydrocarbons) is directed to a holding tank 229.

16 A line L4 is provided at the top of the well to 17 recover gas for sale. A further gas line L5 may be 18 provided to recover gas to be used as a power source 19 for the surface pump 221.

21 The surface power system 220 comprises a solar panel 22 222, batteries 223, a controller 224 and an RTV 225.

23 The controller 224 controls valves V1, V2, V3 and 24 V4. Pressure monitors 226, 227 are provided on the lines L1 and L2. The surface pump 221 has a pump 26 reservoir 228.

28 To operate the downhole pump 201, fluids are 29 preferably pumped down line L1 with all valves closed except for valve V1. This forces fluid out of 31 injection valve IV1 to purge line L1. This step is 32 capable of removing air bubbles or gas from line L1.

1 Next, valve V1 is closed and valve V2 opened and air 2 is similarly bled through injection valve IV2 to 3 purge line L2. Next the surface pressure required 4 for the surface pump 221 to operate piston P is preferably set on the surface control logic such 6 that the operating pressure to function the downhole 7 pump 201 is less than the pressure required to open 8 injection valves IV1, and IV2. In addition to their 9 use in purging lines L1 and L2 from air or gas bubbles, injection valves IV1 and IV2 can also be 11 used as chemical injection ports for wells that 12 require the addition of chemicals downhole. Next, by 13 switching the surface valves in an appropriate 14 sequence, the surface pump 221 oscillates piston P upward and downward to deliver fluids from the 16 wellbore 230 up line L3. The surface power system 17 220 provides the switching and logic for activating 18 the downhole pump assembly 200. The surface power 19 system 220 powers the downhole pump assembly 200.

Using the apparatus and method gas fluids are 21 capable of being simultaneously produced from the 22 well with gas production. Using a three-line 23 wellhead packoff, fluid pressure (gas or liquid) can 24 be maintained with lines L1, L2, and L3 extending therefrom and continuing to operate downhole pump 26 201. The weight of hydrostatic pressure within lines 27 L1 and L2 allow minimal power input from the surface 28 pump to operate piston P of downhole pump 200.

29 Furthermore, lines L1, L2, and L3 can be manufactured of continuous hydraulic line (or hose), 31 or jointed sections of line or pipe, depending on 32 preferences of the well operator.

2 Referring to Figure 3A, a method of operating a 3 downhole pump like the pump 201 disclosed in Figures 4 1-2 can be described. The method preferably includes opening line L1 and valves V1 and V4 and closing 6 valves V2, V3 and V5. Next, when pressure within 7 line L1 reaches a set pressure, V3, V5 are opened, 8 V1, V4 are closed and line L1 is vented to the pump 9 reservoir tank 228 via valve V3.

11 Next, valves V1, V4 and V5 are closed, valve V2 and 12 V3 are opened and fluid is pumped down line L2. When 13 L1 reaches the set pressure, V3 is closed, V5 is 14 opened and V2 is then closed. V5 is then closed and V4 opened allowing L2 to be vented via valve V4 to 16 the pump reservoir 228. When pumping down line L1, 17 valves V4 and V1 are opened by the surface 18 controller and valves V2, V3, and V5 are closed.

19 When pressure in line L1 reaches the set pressure, valve V4 is closed, valve V5 is opened, and valve V1 21 is closed. Next, valve V5 is closed, valve V3 is 22 opened, and valve V2 is opened. When pumping down 23 line L2, valves V3 and V2 are open and valves V1, 24 V4, and V5 are closed. When pressure in line L2 reaches the set pressure, valve V3 is closed, valve 26 V5 is opened, and valve V2 is then closed. Next, 27 valve V5 is closed, valve V4 is opened and valve V1 28 is opened. The process is then repeated, preferably 29 with computer control of valves V1, V2, V3, V4, and V5 to maximize the speed of operation of downhole 31 pump 201.

1 Optionally, the system can include the use of a gas 2 operated surface pump using the well pressure for 3 power as part of the system. The system can include 4 powering the surface pump with chemical energy from gas. The system can include powering the surface 6 pump with solar power. The lines in the system can 7 extend downhole in parallel or concentrically. The 8 system can include running multiple fluid conduits 9 to transmit the power fluid and a separate fluid conduit to transmit the produced fluids to the 11 surface. The system can include timing and 12 switching the hydraulic power fluid at the surface 13 between the hydraulic power conduits running from 14 surface to the depth of the well. The system can include having a downhole injection valve built into 16 each of the hydraulic control lines down at the 17 bottom end in the well to be opened by applying 18 sufficiently high pressure to open them and allow 19 fluid to discharge into the well therethrough. The system can include the hydraulic power fluid being 21 the same as the produced fluid. The system can 22 include the power fluid as a separate fluid from the 23 produced fluid, for example, a fluid with 24 lubricating qualities. The system can include a power fluid having corrosion inhibitors, scale 26 inhibitors, hydrate inhibitors, paraffin inhibitors, 27 and wax inhibitors. The piston of the downhole pump 28 of the system can optionally be biased with springs.

Fig. 4a shows a reciprocating pump 1 secured and 31 sealed within production tubing 2 suspended within a 32 well bore 4 and hydraulically connected, via a 1 hydraulic conduit 3, to a hydraulic pumping system 2 24 located at the surface. Water within the well 3 bore 4 prevents gas entrained in a formation 5 from 4 entering the well bore 4 and being recovered. As described below, production of water to the surface 6 via the reciprocating pump 1 and production tubing 2 7 reduces the height of the water column in the well 8 bore 4 as shown in Fig. 4b, allowing the gas 9 entrained within the formation 5 to enter the well bore 4 and flow to surface for recovery.

12 The conduit 3 can be made from any suitable material 13 such as stainless steel, inconel or titanium. A 14 first annular space 81 is formed above the pump 1 between the hydraulic conduit 3 and production 16 tubing 2. The outer diameter of the conduit 3 is 17 around A".

19 One typical outer diameter of production tubing is 2 3/8", with an inner diameter or bore of 2". The 21 diameter of the pump 1 suitable for operation in 22 such a size of production tubing is 1.905".

23 However, pumps in accordance with the present 24 invention may be larger or smaller in order to be operable with production tubing of correspondingly 26 different sizes or for other reasons.

28 Figs. 5a and 5b diagrammatically represent the 29 reciprocating pump 1 which comprises a piston 18 having an axial bore 23, a cylinder 50 enclosing the 31 piston 18, a manifold 30 and a pack-off assembly 6 1 for securing and sealing the pump 1 within the 2 production tubing 2.

4 The piston 18 has a head 60 at its lower end, an end face 64 at its upper end and a bearing flange 62 6 extending radially outwards around its centre. The 7 head 60 and bearing flange 62 each have upper and 8 lower bearing faces 60u & 601, 62u & 621 9 respectively.

11 The cylinder 50 has a bore 16 which encloses the 12 piston 18. A seal 69 seals the piston head 60 in 13 the bore 16. The portion of the bore between the 14 seal 69 and the end of the cylinder 50 is hereinafter referred to as the bore 16'.

17 A finger 70 from the manifold 30 extends into the 18 bore 23 of the piston 18. A second annular space 82 19 is defined within the bore 16 of the cylinder 50 between the finger 70 and the end face 64 of the 21 piston 18.

23 The diameter of the bore 16 is slightly less at its 24 upper end than its lower end. A step 54 separates these areas of differing diameter and defines a 26 third annular space 83 between the piston 18, step 27 54 and bearing flange 62 of the piston 18.

29 An inwardly extending flange 66 is provided on the bore side of the cylinder 50 and has a seal 68 to 31 seal the piston 18 between the piston's head 60 and 32 the piston bearing flange 62. The flange 66, piston 1 18 and the piston bearing flange 62 define a fourth 2 annular space 84 above the flange 66; and a fifth 3 annular space 85 below the flange 66, between the 4 flange 66, the piston 18 and the piston head 60.

6 The forth annular space 84 is in fluid communication 7 with the first annular space 81 via grillings 8, 9 8 and bore 23. Therefore the pressure within the 9 production tubing 2 acts on the lower face 621 of the flange 62 of the piston 18 urging the piston 18 11 in an upwards direction.

13 The hydraulic conduit 3 is connected, via a drilling 14 11, to the second annular space 82 in the bore 16 between the finger 70 and the upper end of the 16 piston l8. Therefore the pressure within the 17 conduit 3 acts on an upper face 64 of the piston 18 18 urging it in a downwards direction. The hydraulic 19 fluid within the conduit 3 has a specific gravity less than that of the water contained within the 21 first annularspace 81 and thus exerts less force 22 than the water in the first annular space 81, unless 23 pressurized.

The well bore 4 below the reciprocating pump 1 is 26 connected via passages 12 and 13 to the fourth and 27 fifth annular spaces 84 and 85 and to the bore 16' 28 within the reciprocating pump 1. Therefore the 29 pressure within the well bore 4 acts on the upper face 62u of the bearing flange 62, via the fourth 31 annular space 84, to urge the piston 18 downwards.

32 Also, the pressure within the well bore 4 acts on 1 the upper face 60u of the piston head 60, via the 2 fifth annular space 85, also to urge the piston 18 3 downwards.

The bore 16' will also be exposed to well bore 6 pressure in use and thus urges the piston 18 in an 7 upwards direction. The pressure within the bore 23 8 (equalised with the production tubing pressure) of 9 the piston 18 will urge the piston 18 downwards.

11 Thus to summarise the various forces acting on the 12 piston 18: 14 The hydrostatic pressure from water present in the production tubing 2 (via the fourth annular 16 space 84) along with the pressure within the well 17 bore 4 (via bore 16') act to urge the piston 18 in 18 an upwards direction.

- The hydrostatic pressure from water present in 21 the production tubing 2 (via the bore 23), the 22 hydrostatic pressure (and any applied pressure) in 23 the hydraulic conduit 3 (via the second annular 24 space 82) and the well bore pressure (via the third and fifth annular spaces 83, 85) act to urge the 26 piston 18 in downwards direction.

28 By selection of the sizing of the reciprocating pump 29 1, and the various bearing surfaces, the piston 18 is biased to the upper extent of its allowed 31 movement. The piston 18 may be moved toward the 32 lower extent of its allowed movement by pressurising 1 the hydraulic conduit 3 which increases the pressure 2 in the second annular space 82 to a sufficient 3 extent to overcome the bias of the piston to its 4 upper extent and therefore lower the piston 18.

When the applied pressure within the hydraulic 6 conduit 3 is released, the piston 18 will again be 7 biased and therefore move toward the upper extent of 8 its allowed movement.

The hydraulic fluid used in the hydraulic conduit 3 11 - even when no pressure is applied - will also 12 affect the movement of the piston 18 due to its 13 weight. However the specific gravity of hydraulic 14 fluid is less than that of water and thus the pressure caused by the weight of the water in the 16 production tubing 2 overcomes the pressure caused by 17 the weight of the hydraulic fluid in the hydraulic 18 conduit 3.

Fig. 10 is a further view of the simplified pump 1 21 highlighting the annular spaces and other areas 22 which act on the piston 18. In the following 23 calculation: A82 - A85 = Surface area of bearing faces acting to 26 move the piston within the annular spaces 82-85 27 respectively 28 B16' = Surface area of bearing face acting to 29 move the piston within the bore 16' B23 = Surface area of bearing face acting to 31 move the piston within the bore 23 32 Pw = Well Pressure 1 Pt = Production tubing pressure 2 Pc = Pressure in conduit 3 4 Thus, 6 Pt(A84-B23) = Force acting to raise the piston 18 7 Pw(A85+A83-B16') + A82Pc = Force acting to lower 8 piston 18 The net effect of the production tubing pressure is 11 to urge the piston 18 upwards whilst the net effect 12 of the well pressure is to urge the piston 18 13 downwards.

The weight of the hydraulic fluid in the conduit 3 16 urges the piston 18 downwards.

18 The force acting to raise the piston 18: 19 = (B16' x Pw) + (A84 x Pt) The force acting to lower the piston 18: 21 = (A85 x Pw) + (A83 x Pw) + (A82 x Pc) + (B23 x Pt) 22 Exemplary data are as follows: 24 Setting Depth 10,000 feet.

Tubing Fluid - Water S.G. = 1.00 26 Pressure in Tubing (Pt) = 4330 psi.

27 Conduit Fluid - Hydraulic Oil S.G.= 0.92 28 Pressure in Conduit (Pc) without any applied force = 29 3984 psi.

31 The dimensions of the various bearing faces on the 32 piston 18 areas are as follows: 2 B16' = 2.074 sq.in.

3 A85 = 1.473 sq.in.

4 A84 = 1.169 sq.in.

A83 = 0.881 sq.in.

6 A82 = 0.690 sq.in.

7 A6 = 0.196 sq.in.

9 Well Bore Pressure (Pw) can vary. In this example it is taken to be 50 psi.

12 Upward Force on Piston = (2.074 x 50) + (1.169 x 13 4330) 14 =51651bf.

Downward Force on Piston = (1.473 x 50) + (0.881 x.

16 50) + (0.690 x 3984) + (0.196 x 4330) 17 =37151bf (pounds of force).

18 Resulting Upward Force on Piston = 1450 lbf.

19 Applied pressure required on A82 via hydraulic conduit 3 to equalise the forces on the piston: 21 = Force/Area 22 = 1450/0.69 23 = 21001b/sq inch.

In another example where the Well Bore Pressure (Pw) 26 = 1200 psi.

27 Upward Force on Piston = (2.074 x 1200) + (1.169 x 28 4330) 29 = 7550 lbf.

Downward Force on Piston = (1.473 x 1200) + (0.881 x 31 1200) + (0.690 x 3984) + (0.196 x 4330) 32 = 6422 lUf.

1 Resulting Upward Force on Piston = 1128 lbf.

2 Applied pressure required on A82 via hydraulic 3 conduit 3 to equalise the forces on the piston: 4 = Force/Area = 1128/0.69 6 = 1635 lb/sq inch 8 Therefore allowing the well pressure (below the 9 pump) to act on the piston 18 to urge the piston downwards reduces the pressure which is required to 11 be applied to the hydraulic conduit 3, thus saving 12 power.

14 In alternative embodiments the piston 18 may be biased in the opposite direction by, for example, 16 directing the pressure within the production tubing 17 and/or conduit 3 to the to the 3rd and 5th annular 18 spaces 83, 85 - although this is less preferable.

19 Optionally the size of the various bearing faces may be adjusted in order to bias the piston in a 21 downwards direction.

22 Referring back to Figs 5a, 5b, the head 60 of the 23 piston 18 includes a first ball valve 19 in a seat 24 20. The ball 19 is adapted to lift from its seat thereby opening the valve when the piston 18 is 26 moved in a downwards direction due to the pressure 27 rise in the bore 16' because of the reduction in 28 volume of the bore 16' between the seal 69 of the 29 piston head 60 and the end of the cylinder 50. When open, the valve 19 allows communication between the 31 bore 16' of the cylinder and the bore 23 of the 32 piston 18.

2 A second ball valve 21 is provided in a seat 22 at 3 the lower end of the cylinder 50. The ball 21 is 4 adapted to lift from its seat thereby opening the valve when the piston 18 is moved in an upwards 6 direction due to the pressure drop in the bore 16' 7 because of the increase in volume of the bore 16' 8 between the seal 69 of the piston head 60 and the 9 end of the cylinder 50. When open, the valve 21 allows communication between the bore 16' and the 11 well bore 4. Figs. 7a-7e show more detailed views 12 of the pump 1 at various point in the piston cycle.

14 Thus in use, the pressure of the hydraulic fluid in the second annular space 82 is increased by control 16 of the hydraulic conduit 3 and the piston 18 moves 17 in a downwards direction. The ball 21 is firmly 18 pressed against its seat 22 preventing water within 19 the bore 16' from egress into the well bore 4 whilst the ball 19 is lifted from a seat 20 allowing the 21 water in the bore 16 to egress into the bore 23 of 22 the piston 18 (see Fig. 7b). The water can 23 thereafter proceed via drillings 8 into the first 24 annular space 81 between the production tubing 2 and the conduit 3. When the piston 18 reaches the 26 bottom of its stroke (see Fig. 7c) the applied 27 pressure in the hydraulic conduit 3 is removed 28 causing a drop in pressure in the second annular 29 space 82 and the resulting return of the piston 18 to the upper extent of its movement (since it is 31 biased in this direction by the hydrostatic pressure 32 of the fluid within the production tubing 2).

1 During the piston's upward stroke, the ball 19 is 2 firmly pressed onto the seat 20 whilst the ball 21 3 is lifted from the seat 22 and water from the well 4 bore 4 is drawn into the bore 16 of the reciprocating pump 1 (see Fig. 7d).

7 The piston 18 can then be returned to the lower 8 position (as shown in Fig. 7c) which expels the 9 water into the bore 23 as described above.

11 By sequential manipulation of the pressure of the 12 hydraulic fluid in the hydraulic conduit 3 using a 13 timing device of known technology in the hydraulic 14 pumping system 24, the piston 18 of the reciprocating pump 1 may be repeatedly moved between 16 the upper and lower extents of its allowed movement 17 and water from the well bore 4 lifted via the first 18 annular space 81 between the production tubing 2 and 19 the conduit 3 to surface.

21 In the absence of the water, well bore gas is then 22 allowed to expand and flow up the annulus between 23 the production tubing 2 and casing 7.

An advantage of certain embodiments of the present 26 invention is that heavy rods between the pump and 27 the surface are not required to reciprocate the 28 piston. The weight of these rods in known systems 29 adds drag to the pump and thus require more power to operate.

1 A further advantage of certain embodiments of the 2 present invention is that the fluid produced by the 3 pump aids the return of the piston, thus reducing 4 the amount of power required to operate the pump.

6 A yet further benefit of embodiments of the 7 invention is that the power required to move the 8 piston in the opposite direction is less since the 9 well pressure urges the piston in this direction.

11 The features required to mount, seal and disengage 12 the pump 1 from the production tubing 2 will now be 13 described with reference to Figs. 6a-6c which show a 14 more detailed view of the reciprocating pump 1.

16 The pack-off assembly 6 comprises serrated slips 37 17 (Fig. 6b) for securing the pump 1 within tile 18 production tubing 2 and above the slips 37, a 19 resilient seal 43 for sealing the pump 1 within said production tubing 2. The serrated slips 37 are 21 mounted on slidable support sleeves 38, 39 and are 22 retained by retaining cups 40, 41; each above and 23 below the slips 37.

An outer annular space 36 is defined by the outer 26 face of the cylinder 50, an outer jacket 45 provided 27 around the cylinder 50, a slidable sleeve 42 and a 28 second piston 44. The outer annular space 36 can be 29 pressurized to move the slidable sleeve 42 and piston 44.

1 The slidable sleeve 42 extends downwards from the 2 outer annular space 36, past the resilient seal 43, 3 to the upper support sleeve 39 of the serrated slips 4 37 and is adapted to move the serrated slips 37 radially outward when the sleeve 42 is moved 6 downwards.

8 The resilient seal 43 is mounted on said slidable 9 sleeve 42. The second piston 44 holds the resilient seal 43 in place and is adapted to compress the seal 11 43 when the piston 44 is moved with respect to the 12 sleeve 42, causing the seal to move radially 13 outwards and form a seal between the pump 1 and the 14 production tubing 2.

16 A one-way pressure relief valve 33 is connected to 17 the drilling 11 and is adapted to allow passage of 18 hydraulic fluid above a certain predetermined 19 pressure level. This pressure level is greater than the normal operating pressure of the pump 1 and so 21 in normal use, the valve 33 is closed. The valve 33 22 leads, via drilling 35 and annular gallery 34, to 23 the outer annular space 36.

Thus in order to set the pump 1 in the production 26 tubing 2, the pump 1 is lowered via the hydraulic 27 conduit 3 below the gas formation into the water 28 which is blocking the flow of gas. Sufficient 29 hydraulic pressure is applied via the conduit 3 and drilling 11 to pass the check valve 33 and 31 pressurise the outer annular space 36 via the 32 drilling 35. (A side effect is that the piston 18 1 moves to its lowermost position, but this does not 2 affect the operation of securing the pump 1 to the 3 production tubing 2.) Pressure within the annular space 36 moves the 6 piston 44 and slidable sleeve 42 (carrying the 7 resilient seal 43) downwards. The sleeve 42 engages 8 the support sleeve 39 of the serrated slips 37 and 9 drives it together with the lower support sleeve 38 forcing the serrated slips 37 radially outwards to 11 engage with the production tubing 2, see Fig. 8b.

12 Continual pressure applied to the outer annular 13 space 36 forces the piston 44 downwards further 14 (with respect to the sleeve 42 which can move no further and is now stationary), compressing the 16 length of the resilient seal 43 causing it to expand 17 radially to seal against the production tubing 2, 18 see Fig. 8c. The pressure applied within the annular 19 space 36 is maintained by the valve 33 after the hydraulic pressure applied via the conduit 3 is 21 removed, leaving the reciprocating pump 1 secured 22 and sealed within the production tubing 2.

24 Pumping operations can then be conducted as described above with respect to Figs. 5a, 5b.

27 Referring back to Figs. 6a-6c, the components 28 involved in the disconnection procedure will now be 29 described. The outer jacket 45 is rigidly connected to a housing or 'fishing neck' 29 which is connected 31 to the top of the manifold 30 of the pump 1. A stop 32 pin 25 is provided generally within the bore of the 1 housing 29 and connects to the manifold 30 of the 2 pump 1. The stop pin 25 has a threaded connector 26 3 for connection to the hydraulic conduit 3 (not shown 4 in Figs. 6a-6c) and a drilling 27 which links the threaded connector 26 of the stop pin 25 to the 6 hydraulic fluid input drilling 11 of the manifold 7 30.

9 When the pump 1 is to be removed from the well, the outer jacket 45 and connected housing 29 move 11 together with respect to the stop pin 25 and 12 manifold 30 as described further below.

14 Shear pins 28 extend through the housing 29 and connect to the manifold 30 to resist relative 16 movement of the housing 29 with respect to the 17 manifold 30. A drilling 32 from the drilling 27 in 18 the stop pin 25 leads to a further annular space 31 19 between the stop pin 25, manifold 30 and housing 29.

When pressurized the annular space 31 urges the 21 housing 29 and manifold 30 apart. The shear pins 28 22 are adapted to break when the pressure is increased 23 above operating and setting pressure and allow the 24 disengagement of the pump from the production tubing 2 before recovery, as described further below.

27 Before disengagement, the pressure differential on 28 either side of the seal 43 needs to be equalised.

29 To provide for this, a fragile disk 46 is provided in the piston 18 and is adapted to rupture at a 31 predetermined pressure level. When ruptured a 32 communication is formed between the bore 23 of the 1 piston 18 via third annular space 83 and passage 12 2 to the well bore 4 below the reciprocating pump 1.

3 This equalises the pressure in the first annular 4 space 81 between the production tubing 2 and conduit 3 and that in the well bore 4.

7 Thus, on completion of pumping operations a high 8 pressure is applied to the first annular space 81 9 and consequently to the drilling 8 and bore 23 of the piston 18 via a surface facility (not shown).

11 The pressure is of sufficient magnitude to rupture 12 the fragile disc 46 which then provides 13 communication between the well bore 4 and the first 14 annular space 81 between the production tubing 2 and the conduit 3, allowing equalization of the 16 pressures on either side of the resilient seal 43.

17 Then, hydraulic pressure is applied via the conduit 18 3 to the drilling 32, check valve 33 and drilling 35 19 to annular space 31 (and outer annular space 36).

As stated above, pressure within the annular space 21 31 urges the housing 29 and manifold 30 apart. The 22 pressure is increased until the shear pins 28 break, 23 see Fig. 8d, causing the housing 29 with attached 24 outer jacket 45 to move upwards with respect to the manifold 30.

27 The pressure within the annular space 36 ensures 28 that the slidable sleeve 42 does not, at this stage, 29 move with the jacket 45 and housing 29. However a connection between the lower end of the jacket 45 31 and the piston 44 causes the piston 44 to move 32 upwards with the housing 29. The piston 44 thus 1 disengages from the resilient seal 43 which returns 2 to its former geometry and disengages from the 3 production tubing 2.

After the seal has disengaged from the production 6 tubing 2, continued movement of the housing 29 with 7 respect to the manifold 30 causes the slidable 8 piston 44 to engage with a step 72 of the slidable 9 sleeve 42, Fig. 8d, and move the support sleeve 42 along with the piston 44 and housing 29 all with 11 respect to the manifold 30.

13 Movement of the slidable sleeve 42 causes it to move 14 the upper support sleeve 39 of the serrated slips 37 which disengages the serrated slips 37 from the 16 production tubing 2.

18 The pump 1 can then be winched to the surface by the 19 hydraulic conduit 3.

21 In an alternative embodiment shown in Figs. 11 and 22 12, a pump 101 has the piston and cylinder 23 components of the pump 1 separate from the manifold 24 and pack-off components. A tube 14 (around 3/8" diameter) joins them together whilst a hydraulic 26 line (not shown) of around 1/4" is provided to power 27 the piston. Other features are similar with the 28 features already described with respect to the pump 29 1. This embodiment has particular application where the lowermost end of production tubing 2 in a given 31 well is above the perforated interval in the casing 32 7 which receives the hydrocarbon gas from the 1 formation 5. The pack-off assembly 106 secures the 2 manifold into the production tubing 2 whilst the 3 tube 14 spaces the pump 101 including the piston and 4 cylinder to below said perforated interval. The pump 101 operates in a similar fashion to the 6 previous embodiment of the pump 1 - fluid in the 7 well is produced through the conduit 14 and 8 thereafter through the production tubing 2 to the 9 surface. The weight of the fluid in the production tubing 2 (now combined with tube 14) continue to act 11 on the piston as described for the pump 1.

13 In a further alternative embodiment, a hydraulic 14 pumping system may be provided at the surface to pressurize the production tubing, thus increasing 16 the force acting to bias the piston in an upwards 17 direction. Manipulation of the pressure within the 18 production tubing 2 may therefore be utilised to 19 optimise the sequential time of the stroke of the reciprocating pump and hence control the rate at 21 which fluid is removed from the well. This option 22 is particularly beneficial when producing liquid 23 hydrocarbons from the well rather than removing 24 water to allow gaseous hydrocarbons to escape.

26 Fig. 9 demonstrates a method for producing oil from 27 a well using the reciprocating pump 1. In this 28 embodiment the first annular space 81 between the 29 production tubing 2 and the conduit 3 is maintained at a pre- determined pressure by a hydraulic pumping 31 system 47 incorporating a pressure relief valve 48.

32 Said pre-determined pressure providing bias to move 1 the piston 18 of the reciprocating pump 1 to the 2 upper extent of its allowable movement whilst 3 hydraulic pressure provided via the conduit 3 4 provides bias to return the piston 18 of the reciprocating pump 1 to the lower extent of its 6 allowable movement. By repeatedly sequencing the 7 application of the hydraulic pressure applied via 8 the conduit 3 the piston 18 may therefore be 9 reciprocated and oil produced to surface via the annular space 81 between the production tubing 2 and 11 the conduit 3. In a further alternative the bearing 12 faces within the pump 1 can be altered in order to 13 overcome the lower specific gravity of the produced 14 oil compared with the hydraulic conduit fluid. The piston can therefore be biased towards the upper 16 direction and liquid hydrocarbons recovered through 17 the production tubing as described previously 18 without having to pressurise the production tubing.

19 Thus the dimensions of the pump may be sized to produce water or oil. Nonetheless, a pump with 21 bearing faces sized to produce water may still be 22 used to produce oil by manipulation of the pressure 23 within the production tubing.

Improvements and modifications may be made without 26 departing from the scope of the invention.

Claims (1)

1 Claims 3 1. A hydraulically powered pump, adapted to be 4 placed in a

well and pump fluids from the well to the surface.

7 2. A pump as claimed in claim 1, comprising a 8 reciprocating piston and a cylinder, the cylinder 9 having a bore, wherein the piston is adapted to move within at least a portion of the bore of the 11 cylinder.

13 3. A pump as claimed in claim 2, wherein the pump 14 is adapted to allow fluid within the well to bias the piston in a first direction.

17 4. A pump as claimed in claim 3, wherein the 18 piston, in use, is biased towards an upper 19 direction.

21 5. A pump as claimed in claim 3 or claim 4, 22 wherein fluid in a separate part of the well is 23 adapted to urge the pump in a second direction, 24 preferably opposite the first direction.

26 6. A pump as claimed in any preceding claim, 27 comprising a resilient seal adapted to seal the pump 28 within a tube, such as a portion of production 29 tubing.

1 7. An apparatus for recovering fluids from a well 2 comprising a hydraulically powered pump and a 3 hydraulic conduit.

8. Apparatus as claimed in claim 7, wherein the 6 hydraulic conduit is a flexible conduit.

8 9. Apparatus as claimed in claim 7 or claim 8, 9 comprising a hydraulic power source which is adapted to pressurise the hydraulic conduit and in turn the 11 pump.

13 10. A method for removing fluid from a well, the 14 method comprising: lowering a hydraulically powered pump into a 16 well; 17 the pump being connected to the surface via a 18 hydraulic conduit; 19 hydraulically activating the pump to pump fluid from the well to the surface.

22 11. A method as claimed in claim 10, wherein a 23 portion of the pump is secured in production tubing 24 within the well.

26 12. A method as claimed in claim 11, wherein fluid 27 within the production tubing biases the piston of 28 the pump in a first direction.

13. A method as claimed in any one of claims 10 to 31 12, wherein pressure within the well, outside the 1 production tubing, urges the piston of the pump in a 2 second, preferably opposite, direction.

4 14. A method as claimed in any one of claims 10 to 13, wherein the hydraulic line is repeatedly 6 pressurised and depressurised in order to 7 reciprocate a piston of the pump.

9 15. A method as claimed in any one of claims 10 to 14, wherein the fluid includes water and the method 11 includes the step of recovering gaseous hydrocarbons 12 from a formation proximate to the well.

14 16. A method as claimed in any one of claims 10 to 15, wherein pressure is applied to the production 16 tubing at the surface in order to increase the 17 pressure therein.

19 17. A method as claimed in any one of claims 10 to 16, wherein the pump is operated from a point below 21 where hydrocarbons may enter the well.

23 18. A downhole pump to remove fluids from a 24 wellbore, the pump comprising: a first power transmission line and a second 26 power transmission line; 27 a piston, said piston configured to be 28 displaced within a cylinder from a first 29 upward position to a second downward position; said piston within said housing defining a 31 first fluid chamber and a second 32 fluid chamber 1 said piston urged into said first downward 2 position when pressure within said 3 first power transmission line is increased; 4 said piston urged into said second upward position when pressure within 6 said second power transmission line is 7 increased; and 8 a fluid return line connected to outlets of 9 said first and second fluid chambers.

12 19. The downhole pump of claim 18 wherein 13 pressure within said first and said second power 14 transmission lines are controlled by a surface pump.