GB2580195A

GB2580195A - Apparatus for liquid transport in a hydrocarbon well

Info

Publication number: GB2580195A
Application number: GB1909163.6A
Authority: GB
Inventors: Aasheim Robert; Fiveland Torbjøm; Kaasa Øyvind
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2019-06-26
Filing date: 2019-06-26
Publication date: 2020-07-15
Anticipated expiration: 2039-06-26
Also published as: GB2580195B; GB201909163D0

Abstract

Transporting liquid, preferably wellbore fluid, in a system having a multiphase flow of hydrocarbon fluid. A liquid accumulator 31 accumulates liquid from the multiphase flow and a turbine 32 generates power by a passage of the flow of fluid past the turbine 32. A pump 33 pumps liquid accumulated by the liquid accumulator 31 away from the liquid accumulator, preferably through a tubing to a well surface, platform or rig. The pump 33 is powered by the turbine 32 and may be powered electrically using an electrical power generator and battery to store the electrical power or mechanically using a gear mechanism and drive shaft. There may also be a communications module to receive signals for controlling the pump 33 via a pump control unit. There may further be a sensing unit having a temperature, fluid pressure, fluid velocity or liquid-gas ratio sensor. The liquid accumulator 31 may be one ore more accumulation chambers positioned around the circumference of an internal wall of casing or riser 35, each chamber having opening to allow an annular film liquid (mist flow) to flow into the chamber.

Description

APPARATUS FOR LIQUID TRANSPORT IN A HYDROCARBON WELL

Field of the invention

The present invention relates to an apparatus and method for transporting a multiphase liquid in a hydrocarbon well, and more specifically to mitigating liquid accumulation in a gas well.

Background

The term "natural gas" is used here to refer to gas extracted from underground reservoirs, where natural gas is often associated with oil deposits. Natural gas is a combustible mixture of hydrocarbon gases. While it is typically primarily methane, it can also include ethane, propane, butane and pentane. The particular composition will depend on the reservoir. It is well-known to extract natural gas from underground reservoirs, where natural gas is often associated with oil deposits. The reservoirs are frequently located under the seabed. When natural gas is extracted its temperature (e.g. 100° C) is significantly higher than that of the sea and its pressure (e.g. 80 bar) is much higher than atmospheric pressure. The pressure within the reservoir is typically not only sufficient to lift the gas to the surface, but also to lift liquids (e.g. water and/or condensate) up to the surface. Typically when the velocity of the gas is high, the gas moves to the centre of the pipe, forming a vortex commonly known as gas core. The liquid can be pushed out of the gas core and onto the pipe wall forming a film. Due to the high shear at the gas-liquid film interface, the liquid film can be atomized into droplets. Some droplets are transported upwards via the gas core, while some are deposited back into the film. This flow pattern is known as annular-mist flow and occurs in gas wells which also produce liquids.

The pressure of the well will slowly decrease over time and the pressure will also vary along the extraction path. At lower gas velocities, the liquid film starts to bridge the gas core and the liquid close to the pipe wall starts to fall back. This progressively leads to new flow patterns such as churn, slug and finally bubble flow at the lowest gas velocity. The amount of liquid per pipe section along the well is known as liquid holdup and varies depending on the flow pattern at hand. Over time, an increasing presence of liquid (i.e. increased liquid holdup) in the well can create a recirculation of liquid to the well bottom. The accumulation of liquid at the well bottom generates an excess pressure at the sand-face, which can hinder or stop gas production altogether. This problem is commonly known as liquid loading or minimum flow.

Statement of invention

According to a first aspect of the invention there is provided an apparatus for transporting liquid in a system comprising a multiphase flow of hydrocarbon fluid, the apparatus comprising: a liquid accumulator configured to accumulate liquid from the multiphase flow of fluid; a turbine configured to generate power by a passage of the flow of fluid past the turbine; and a pump configured to pump liquid accumulated by the liquid accumulator away from the liquid accumulator, wherein the pump is powered by the turbine.

The apparatus may further comprise a length of tubing, wherein the pump is arranged to pump accumulated liquid from the liquid accumulator through the tubing. The tubing may extend to a platform or rig. The tubing may have at least one opening provided for allowing the liquid to exit the tubing and re-enter the downstream flow of fluid.

Optionally, the at least one opening may comprise a spray nozzle configured to disperse the liquid as droplets into the flow of fluid.

Optionally, the turbine comprises an electrical power generator, the pump is an electrically powered pump, and the apparatus further comprises an electrical connection between the power generator and the pump. In this case, the apparatus may further comprise a battery, wherein the battery is configured to store the electrical power generated by the electrical power generator and supply the electrical power to the pump. Alternatively, the apparatus may further comprise a mechanical power transfer mechanism connecting the turbine to the pump, wherein, optionally, the mechanical power transfer mechanism comprises a gear mechanism and a drive shaft.

The apparatus may further comprise a pump control unit configured to control the pump, wherein controlling the pump comprises setting a pumping rate. Optionally, the apparatus further comprises a communications module, configured to receive signals for controlling the pump via the pump control unit.

The apparatus may further comprise a sensing unit having at least one sensor, wherein the sensor is one of a temperature sensor, fluid pressure sensor, fluid velocity sensor or a liquid-gas ratio sensor.

The liquid accumulator may comprise one or more accumulation chambers, wherein the system comprises a tubular portion and wherein the accumulation chambers are positioned proximate to the internal wall of the tubular portion, wherein each chamber has one or more openings to allow an annular film liquid to flow into the chamber, and wherein the openings face upstream or downstream. In this case, the one or more accumulation chambers may comprise a cylindrical chamber extending around the circumference of the internal wall. Alternatively, the liquid accumulator may comprise a tank having an inlet, wherein the inlet is arranged to receive at least a portion of the flow of fluid and the received fluid is separated into a liquid component and gas component in the tank under the force of gravity, and wherein the gas component is supplied to the remaining portion of the flow of fluid and the liquid component is supplied to the pump. Optionally, the inlet is spiral shaped, and configured to provide a centrifugal force on the fluid to aid the liquid-gas separation.

The apparatus may further comprise at least one supplementary pump and at least one supplementary turbine downstream of the turbine and pump.

The apparatus may further comprise a fluid conduit between the liquid accumulator and the pump.

According to a second aspect of the invention there is provided a method of transporting liquid in a system comprising a multiphase flow of hydrocarbon fluid comprising liquid and gas, the method comprising: accumulating liquid from the flow of fluid; generating power by harvesting the energy from the flow of fluid with a turbine; and pumping, with a pump powered by the generated power, the accumulated liquid away from the location where the liquid is accumulated.

The step of pumping the accumulated liquid away from the location where the liquid is accumulated may comprise pumping the accumulated liquid to a platform or rig. Alternatively, the step of pumping the accumulated liquid away from the location where the liquid is accumulated may comprise lifting the liquid to a predetermined height, and in this case, the method further comprises: at the predetermined height, reintroducing the liquid into the flow of fluid. Optionally, reintroducing the liquid into the flow of fluid comprises dispersing the liquid as droplets into the flow of fluid.

After generating power by harvesting the energy from the flow of fluid with a turbine, the method according to the second aspect may further comprise: storing the generated power at a battery; and supplying the stored power to the pump.

Before pumping the accumulated liquid away from the location where the liquid is accumulated, the method may further comprise: receiving a communications signal, and based on the communications signal, setting a pumping rate.

The method according to the second aspect may further comprise: obtaining measurements of at least one of: temperature, pressure, fluid velocity and liquid-gas ratio, and based on the obtained measurements, setting a pumping rate.

The flow of fluid may comprise a liquid film flowing along the wall of the system and a gas core, and the step of accumulating liquid from the flow of fluid may comprise: at the wall, collecting at least a portion of the liquid film. Alternatively, the step of accumulating liquid from the flow of fluid may comprise: allowing at least a portion of the upstream flow of fluid to into a tank via an inlet; separating the fluid in the tank into a liquid component and gas component under the force of gravity; and supplying the gas component to the remaining portion of the upstream flow of fluid and supplying the liquid component to the pump. Optionally, the inlet is a spiral inlet to generate a centrifugal force on the fluid.

The method according to the second aspect may further comprise: receiving the pumped liquid at a supplementary pump; using a supplementary turbine proximate to the supplementary pump to generate a power supply for the supplementary pump; and pumping, with the supplementary pump, the accumulated liquid further in a downstream direction.

According to a third aspect of the invention there is provided an assembly comprising a plurality of the apparatus according to the first aspect of the invention provided in series in a well or tubular.

Figures Preferred embodiments of the invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Figures la and lb are schematic representations of a well stream processing apparatus; Figure 2 illustrates an example arrangement of the well stream processing apparatus as shown in Figures la and lb; Figures 3a and 3b illustrate an example of the well stream processing apparatus configured to accumulate an annular liquid film; Figures 4a and 4b illustrate a further example of the well stream processing apparatus configured to accumulate an annular liquid film; Figure 5 illustrates the well stream apparatus of any of Figures 1 to 4 with an additional pump and turbine provided; and Figure 6 is a flow diagram.

Detailed description

The inventors have realised that liquid can be transported up a gas well by transforming some of the energy in the gas flow itself into mechanical work. The mechanical work can be carried out by a pump which lifts the liquid. Figure la is a schematic representation of a well stream processing apparatus, suitable for carrying out this improved method of liquid transportation, as follows.

Referring to Figure la, the well stream processing apparatus comprises a liquid accumulator 1. The liquid accumulator 1 traps or otherwise accumulates liquid L from a liquid-gas well stream LG. The well stream is assumed to be biphasic, comprising both liquids and gas components in a liquid-gas mixture, as denoted by the reference numeral LG. Typically, the liquid component includes hydrocarbon liquids and water, and the gas component includes hydrocarbon gases. Other liquids and gases may be present, as well as solids, such as sand.

Various techniques for accumulating liquid L from a liquid-gas LG flow are known. For instance, Figure la illustrates an example wherein at least part of the liquid-gas LG stream flows in to a tank via an inlet. The inlet may be a spiral inlet to produce a centrifugal flow within the tank, allowing liquid to separate out due to centrifugal forces.

Under the gravitational and/or centrifugal forces, the liquid L is separated from the gas G. In this example, a liquid outlet on or near the bottom of the tank allows the accumulated liquid L to be output from the liquid accumulator 1 via a liquid outlet. A gas outlet on or near the top of the tank allows the separated gas G to flow out of a gas outlet. Preferably, a liquid accumulator 1 is installed within the well or flowline itself without disrupting the gas flow significantly.

In some cases, the liquid accumulator 1 does not accumulate a significant gas component in the process of liquid accumulation, meaning a gas outlet is not necessarily required, as discussed in more detail below. However, if a gas outlet is provided, then gas G from the gas outlet is fed back into the fluid stream, as shown in Figure la. In any case, liquid is accumulated by the liquid accumulator 1.

The gas stream flows through or past a turbine 2, causing the turbine 2 to rotate. Due to earlier removal of liquid from the fluid stream, the remaining fluid stream is substantially comprised of gas G'. By 'substantially', it is meant that the gas may be a wet gas G', containing some liquid as droplets particles suspended therein. Typically, the turbine 2 is typically designed to tolerate and function effectively with a wet gas G' liquid content in a range of up to, for example, around 5% by volume. The turbine 2 may also be placed upstream of the accumulator 1, but in the present embodiment the turbine is provided downstream of the accumulator 1 because the type of turbine 2 used in this embodiment is more efficient when the gas content is high.

As the turbine 2 rotates, some of the energy from the (wet) gas stream G' is converted into mechanical or electrical energy. The turbine 2 is coupled to a pump 3, as indicated by the dotted line in Figure la. The turbine 2 and pump 3 may be coupled by any suitable means. For instance, the mechanical power generated by the turbine 2 can be used to directly drive the pump 2 by way of a mechanical coupling. Alternatively, a generator can convert the mechanical power into electricity to power the pump. A battery may be used to store electrical energy before driving the pump.

If an electrical pump is used, the turbine 2 drives an electrical power generator. The power generator is connected to a battery or directly to the pump 3. The pump 3 is an electrical pump which is driven by the power generated by the turbine 2.

If a mechanical power transfer between the turbine 2 and the pump 3 is used, a mechanical power transfer mechanism connects the turbine 2 to the pump 3. The transfer mechanism comprises a gear mechanism because the turbine 2 rotates at a different speed than the pump 3, which is a rotary pump in this specific example. A drive shaft is further used to transfer the rotational motion over the distance between the turbine and the pump.

The pump 3 pumps liquid L from the liquid accumulator 1 in a downstream direction or to a location outside the well or tubular where the liquid can be stored or disposed.

Generally, a fluid conduit (i.e. any suitable channel or pipework) is provided between the liquid accumulator 1 and the pump 3. The liquid L may be pumped through any suitable pipe or tubing known in the art up to a platform, for collection or processing at the surface. Typically, the pipe or tubing carrying the pumped liquid L has a smaller diameter than the well casing or pipe in which the apparatus is used. Advantageously, the amount of liquid carried by the remaining gas stream G' is reduced, prolonging production and/or delaying liquid loading from occurring.

The inventors have further realised that, in some cases, the accumulated liquid L need not be pumped all the way up to a platform. Figure lb illustrates the same key components as Figure la, though in this case the liquid L is reintroduced to the well stream at a point P in the well at a given height above the turbine/pump assembly. The liquid L can be reintroduced at a location where liquid accumulation is less likely or less problematic than at the location from where the liquid is removed.

The liquid L is conveyed between the pump and the point P by a length of pipe or tubing. At the point P, the liquid L exiting the pipe is reintroduced into the well stream in a suitable manner to promote mist or annular-mist flow. For example, a spray nozzle 4 may be provided, designed to disperse the liquid into droplets as it exits the pipe. The 'point' P may stretch over a height, or comprise a series of points distributed over a given height. Advantageously, higher up in the well, the gas velocity increases naturally due to reduction in gas density, meaning that the well stream at the point P can efficiently transport the liquid droplets upstream, for example, to the surface.

It should be understood that Figures la and lb illustrate components of the present invention conceptually, and are not intended to represent a literal arrangement. It will also be appreciated that the liquid L and gas G are conveyed between the processing components by suitable pipe work as is commonly employed in the art of subsea processing systems. Various shut-off or other flow valves may also be incorporated into such pipe work in order that equipment can be isolated for example for safety purposes. Bypass pipes may also be provided where appropriate in order that gas or liquid can bypass one or more pieces of equipment if necessary.

Figure 2 illustrates an example arrangement of the apparatus shown in Figures la and lb. In this example, the apparatus is positioned within a well having a well casing 25, and the turbine 22 has an outer diameter approximately equal to the well casing 25 diameter. The liquid accumulator 21 and pump 23 are positioned below and proximate to the turbine 22. The outer perimeter of turbine 22 is coupled to the well casing 25, with the pump 23 and liquid accumulator 21 supported by the turbine 22.

A length of tubing 26 extends up concentrically through the centre of the turbine 22. Liquid L is conveyed from the liquid accumulator 21 and up the tubing 26 by the pump 23. The tubing 26 extends above the turbine, and may be supported by one or more brackets (not shown in Figure 2) along the well casing 25. As outlined above, the pipe 26 may extend directly to the surface, or, have an outlet and/or spray nozzle to reintroduce the liquid in to the fluid stream.

The type of arrangement illustrated in Figure 2 may be designed such that it can be retrofitted into an existing well, riser or tubular. The arrangement can be lowered into the wellbore when the well pressure drops or can be lowered to a specific location where liquid accumulation occurs. The arrangement can be lowered by wireline.

In some embodiments, the liquid accumulator is configured to accumulate liquid from the well walls. It is known that when a well stream undergoes annular mist flow, a liquid component travels as a film up the walls of the well. As such, the liquid accumulator may comprise one or more accumulation chambers positioned on or near the well wall. By way of example, Figure 3a illustrates a liquid accumulator 31 comprised of a cylindrical chamber extending around the circumference of the well casing 35. The liquid accumulator 31 comprises an opening extending around the circumference of the chamber on the upstream side facing the fluid flow, allowing the annular film of liquid to flow up and into the chamber of liquid accumulator 31. The arrows labelled L and G' indicate the flow direction of the fluids. The liquid accumulator 31 further comprises at least one channel 37 in fluid communication with pump 33, such that accumulated liquid L accumulated can pass via channel 37 to pump 33. In the illustrated example, the pump is below the accumulator 31 and the channels 37 are arranged downwardly such that the liquid moves to the pump through a combination of gravity and the pumping action. The pump may include a reservoir for temporarily storing liquids. As described above, the pump 33 then pumps the accumulated liquid L up tubing 36.

Figure 3b illustrates the apparatus of Figure 3a in more detail. In this example, two channels 37 are provided to connect the liquid accumulator 31 to pump 33 (though any suitable number of channels 37 may be provided). The downstream inside end of liquid accumulator 33 is configured in a curved U' shape to enable smooth flow of the liquid film up and over into the channels 37. Although not shown in Figure 3b, the tubing 36 extends up through a turbine 32, as discussed above.

Figure 4a illustrates a further example apparatus, wherein the liquid accumulator 41 is configured to accumulate liquid from the well walls. In this case, the liquid accumulator 41 comprises a sleeve having a conical portion. The conical portion is tapered with the narrowest part at the downstream end. The flow channel defined by the sleeve therefore has a reduced diameter, which increases the flow speed and also increases the annular liquid accumulation. The downstream end of the sleeve is spaced from the well casing 45 to define a groove 48. The downstream end of the liquid accumulator 41 is configured in a curved 'U' shape to enable smooth flow of an annular liquid L film along the sleeve and over into the groove 48. In effect, the groove provides an opening facing in a downstream direction. Again, the liquid accumulator 41 further comprises at least one channel 47 in fluid communication with pump 43, such that accumulated liquid L accumulated can pass via channel 47 to pump 43. In the illustrated example, the pump 43 is below the accumulator 41 and the channels 47 are arranged downwardly such that the liquid L collected in the groove 48 moves to the pump 43 through a combination of gravity and the pumping action. The pump 43 may include a reservoir for temporarily storing liquids. Figure 4b illustrates the apparatus of Figure 4a in more detail. Channel(s) 47 and turbine 42 have been omitted from Figure 4b for clarity.

In any of the above examples, the apparatus may further comprise a storage tank coupled to the liquid accumulator and pump. Liquid L accumulated by the liquid accumulator is stored by the storage tank. The liquid L may then be pumped from the storage tank at a constant rate. Alternatively, liquid L may be pumped out of the storage tank at variable rate capped at a preset threshold, thereby ensuring the pump 3 is not overloaded in the event of a liquid surge.

While Figures 1 to 4 generally illustrate a vertical arrangement, it should be understood that the apparatus may also be positioned in horizontal or non-vertical parts of a well. In a horizontal portion of the well, a liquid film or flow may naturally form on the bottom side of the well, meaning the liquid accumulation may be assisted by gravity. For instance, the apparatus of Figures 3a or 3b may be particularly suited operating in both horizontal and vertical conditions, or an angle in between. The apparatus may also be used in a riser or other tubular of a production system.

The apparatus of any of the examples discussed above may further comprise a number of additional components. For example, a pump control unit may be provided, configured to control the pump, e.g. by setting a pumping rate. Optionally, the apparatus may further comprise a communications module, configured to receive signals for controlling the pump via the pump control unit. The received signals may be sent from an external device, for example, in a control room or on an offshore platform.

In some examples, the apparatus may further comprise one or more sensors configured to measure the temperature; pressure, fluid pressure fluid velocity and/or liquid-gas ratio of the well stream. In this case, the pumping rate may be set, by the pump control unit, based on the acquired measurements according to a preset rule.

Alternatively, or in addition, the acquired measurements may be transmitted periodically or continuously via the communications module to an external device, for analysis. In this way, a controller may analyse the measurements and send a signal to set a pumping rate accordingly.

The apparatus may be installed before production starts by affixing the apparatus to a well casing. The apparatus may be fixed using any suitable means known in the art, such as mechanical means or magnetic latching. The apparatus may be installed using wireline methods, prior to production. In some cases, the apparatus may be moved up or down during production to a required position in the well using the wireline.

Furthermore, while the above examples are related to the assembly of a single pump and turbine, the apparatus may further comprise at least one supplementary turbine 52a and at least one supplementary pump 53a, as shown in Figure 5. Figure 5 illustrates use of the same apparatus as shown Figure 2, though with one further turbine 52a and one further pump 53a provided at a higher level up the well (not to scale). Whilst only one supplementary turbine 52a and pump 53a is shown, a series of any number of turbines and/or pumps may be provided along the length of the well. In this way, the liquid flow L may be periodically boosted, for example, at regular intervals along the well length.

The apparatus may further comprise an active cooling arrangement operable to circulate a cooling medium (e.g. sea water) past at least a part of the turbine and/or pump.

The apparatus may also be used in conjunction with other known methods or apparatus for mitigating liquid loading. For instance, the apparatus may also be used in conjunction with known subsea compression technology. The apparatus disclosed herein may also be used in conjunction with one or more pumps based at the top of the well (e.g. on a platform).

Figure 6 illustrates a method, including the steps of accumulating liquid from the flow of fluid (Si), generating power (S2) by harvesting the energy from the flow of fluid with a turbine; and pumping (S3), with a pump powered by the generated power, the accumulated liquid away from the location where the liquid is accumulated Although the invention has been described in terms of embodiments as set forth above, it should be understood that these embodiments are illustrative only and that the claims are not limited to those embodiments. Those skilled in the art will be able to make modifications and alternatives in view of the disclosure which are contemplated as falling within the scope of the appended claims. Each feature disclosed or illustrated in the present specification may be incorporated in the invention, whether alone or in any appropriate combination with any other feature disclosed or illustrated herein.

Claims

CLAIMS: 1. An apparatus for transporting liquid in a system comprising a multiphase flow of hydrocarbon fluid, the apparatus comprising: a liquid accumulator configured to accumulate liquid from the multiphase flow of fluid; a turbine configured to generate power by a passage of the flow of fluid past the turbine; and a pump configured to pump liquid accumulated by the liquid accumulator away from the liquid accumulator, wherein the pump is powered by the turbine.
2. The apparatus of claim 1 further comprising a length of tubing, wherein the pump is arranged to pump accumulated liquid from the liquid accumulator through the tubing.
The apparatus of claims 2, wherein the tubing extends to a platform or rig.
4. The apparatus of claims 2, wherein the tubing has at least one opening provided for allowing the liquid to exit the tubing and re-enter the downstream flow of fluid.
5. The apparatus of claim 4, wherein the at least one opening comprises a spray nozzle configured to disperse the liquid as droplets into the flow of fluid.
6. The apparatus according to any of the preceding claims, wherein the turbine comprises an electrical power generator, wherein the pump is an electrically powered pump, and wherein the apparatus further comprises an electrical connection between the power generator and the pump.
7. The apparatus of claim 6, further comprising a battery, wherein the battery is configured to store the electrical power generated by the electrical power generator and supply the electrical power to the pump.
8. The apparatus according to any one of claims 1 to 5, further comprising a mechanical power transfer mechanism connecting the turbine to the pump.
9. The apparatus according to claim 8, wherein the mechanical power transfer mechanism comprises a gear mechanism and a drive shaft.
10. The apparatus of any preceding claim, further comprising a pump control unit configured to control the pump, wherein controlling the pump comprises setting a pumping rate.
11. The apparatus of claim 10, further comprising a communications module configured to receive signals for controlling the pump via the pump control unit.
12. The apparatus of any preceding claim, further comprising a sensing unit having at least one sensor wherein the sensor is one of a: temperature sensor, fluid pressure sensor, fluid velocity sensor or a liquid-gas ratio sensor.
13. The apparatus of any preceding claim, wherein the liquid accumulator comprises one or more accumulation chambers, wherein the system comprises a tubular portion and wherein the accumulation chambers are positioned proximate to the internal wall of the tubular portion, wherein each chamber has one or more openings to allow an annular film liquid to flow into the chamber, wherein the openings face upstream or downstream.
14. The apparatus of claim 13, wherein the one or more accumulation chambers comprises a cylindrical chamber extending around the circumference of the internal wall.
15. The apparatus of any of claims 1 to 12, wherein the liquid accumulator comprises a tank having an inlet, wherein the inlet is arranged to receive at least a portion of the flow of fluid and the received fluid is separated into a liquid component and gas component in the tank under the force of gravity, and wherein the gas component is supplied to the remaining portion of the flow of fluid and the liquid component is supplied to the pump.
16. The apparatus of claim 15, wherein the inlet is spiral shaped, and configured to provide a centrifugal force on the fluid to aid the liquid-gas separation.
17. The apparatus of any preceding claim, further comprising at least one supplementary pump and at least one supplementary turbine downstream of the turbine and pump.
18. The apparatus of any preceding claim, further comprising a fluid conduit between the liquid accumulator and the pump.
19. A method of transporting liquid in a system comprising a multiphase flow of hydrocarbon fluid comprising liquid and gas, the method comprising: accumulating liquid from the flow of fluid; generating power by harvesting the energy from the flow of fluid with a turbine; and pumping, with a pump powered by the generated power, the accumulated liquid away from the location where the liquid is accumulated
20. The method of claim 19, wherein pumping the accumulated liquid away from the location where the liquid is accumulated comprises pumping the accumulated liquid to a platform or rig.
21. The method of claim 19, wherein pumping the accumulated liquid away from the location where the liquid is accumulated comprises lifting the liquid to a predetermined height, and wherein the method further comprises: at the predetermined height, reintroducing the liquid into the flow of fluid.
22. The method of claim 21, wherein reintroducing the liquid into the flow of fluid comprises dispersing the liquid as droplets into the flow of fluid.
23. The method of any of claims 19 to 22, wherein after generating power by harvesting the energy from the flow of fluid with a turbine, the method further comprises: storing the generated power at a battery; and supplying the stored power to the pump.
24. The method of any of claims 19 to 23, wherein before pumping the accumulated liquid away from the location where the liquid is accumulated, the method further comprises: receiving a communications signal, and based on the communications signal, setting a pumping rate.
25. The method of any of claims 19 to 24, further comprising obtaining measurements of at least one of: temperature, pressure, fluid velocity and liquid-gas ratio, and based on the obtained measurements, setting a pumping rate.
26. The method of any of claims 19 to 25, wherein the flow of fluid comprises a liquid film flowing along the wall of the system and a gas core, and wherein accumulating liquid from the flow of fluid comprises: at the wall, collecting at least a portion of the liquid film.
27. The method of any of claims 19 to 25, wherein accumulating liquid from the flow of fluid comprises: allowing at least a portion of the upstream flow of fluid to into a tank via an inlet; separating the fluid in the tank into a liquid component and gas component under the force of gravity; and supplying the gas component to the remaining portion of the upstream flow of fluid and supplying the liquid component to the pump; wherein, optionally, the inlet is a spiral inlet to generate a centrifugal force on the fluid.
28. The method of any of claims 19 to 27, further comprising: receiving the pumped liquid at a supplementary pump; using a supplementary turbine proximate to the supplementary pump to generate a power supply for the supplementary pump; and pumping, with the supplementary pump, the accumulated liquid further in a downstream direction.
29. An assembly comprising a plurality of the apparatus of any of claims 1 to 18 provided in series in a well or tubular.