WO2005095844A1

WO2005095844A1 - Method and apparatus for transporting fluids

Info

Publication number: WO2005095844A1
Application number: PCT/GB2005/001285
Authority: WO
Inventors: Kashmir Singh Johal
Original assignee: J. P. Kenny Limited
Priority date: 2004-04-03
Filing date: 2005-04-01
Publication date: 2005-10-13
Also published as: GB0407659D0

Abstract

A method of transporting produced fluid, the method comprising: adding carrier fluid to the produced fluid at a first point (18); the carrier fluid suitable to allow a portion of any gaseous component of the produced fluid to move into the liquid phase; moving the well fluid and carrier fluid to a second point (16). In preferred embodiments the method transports hydrocarbons from near a subsea wellhead (20) to an offshore host facility (16). The host facility (16) separates out normally liquid hydrocarbons which are reinjected back at, or close to, the wellhead. The gas phase in the fluid produced by the well is absorbed by the reinjected liquid hydrocarbons allowing the produced well fluids to proceed from the wellhead to the host facility substantially in the liquid phase.

Description

METHOD AND APPARATUS FOR TRANSPORTING FLUIDS This invention relates to a method and apparatus for transporting produced fluids, particularly but not exclusively from an oil or gas well to a host facility. The oil and gas exploited from both offshore and onshore reservoir fields require the transportation of produced oil, gas and water (sometimes called "production fluids") through well tubing and pipelines to the host fluids processing facility. The transportation of these production fluids causes a number of operational related problems such as slugging, hydrate formation, wax deposition, scale, corrosion, erosion, emulsions etc. These problems may cause the entire offshore / onshore production system to inadvertently shut down or the integrity of the system compromised through a flow path blockage. The production system shut down causes a substantial loss in oil production with associated loss in revenue and therefore reduced the Net Present Value (NPV) for the field development. Further there is a risk that an extended unplanned shutdown may cause a complete hydrate or wax blockage of part or all of the system with serious economic consequences for the development.

According to the present invention there is provided a method of transporting produced well fluid, the method comprising: adding carrier fluid to the produced well fluid at a first point; the carrier fluid being suitable to allow a portion of any gaseous component in the produced well fluid to move into the liquid phase; moving the produced well fluid and carrier fluid to a second point.

Typically the produced well fluid comprises a gas phase.

Typically the carrier fluid comprises a liquid phase.

Preferably a portion of the gas phase of the produced well fluid enters the liquid phase of the carrier fluid, before moving the produced well fluid and carrier fluid to a second point. The present invention also provides a method of transporting produced well fluid, the well fluid comprising liquid and gas phases, the method comprising: adding carrier fluid to the produced well fluid at a first point; allowing a portion of the gaseous component of the produced well fluid to move into the liquid phase; moving the well fluid and carrier fluid to a second point.

Preferably the carrier fluid comprises hydrocarbons, more preferably light end liquid hydrocarbons. The light end liquid hydrocarbons may comprise C3-C6 hydrocarbons, such as propane, butane, pentane or hexane and sometimes (preferably small) quantities of C6+ hydrocarbons which may have been entrained from a host processing facility.

Preferably the well fluid and carrier fluid move from the first point to the second point substantially in a liquid phase.

The first point can be proximate to a production wellhead, optionally a subsea production wellhead. Typically a flowline is provided at or proximate to the first point - the flowline typically looping around from an input to an output. The first point could also be the reservoir or well, that is typically below any wellhead.

Preferably the input of the flowline receives the carrier fluid. Typically each production wellhead is in fluid communication with the flowline. Preferably the carrier fluid and produced well fluid flow through the output.

Two or more flowlines may be provided each preferably having the features of the said flowline.

Preferably the second point is a host facility, for example, an offshore platform or Floating Production Storage vessel (FPSO) . Alternatively the second point may be an onshore host processing facility.

Preferably the host facility comprises a processing mechanism to separate the constituent parts of the produced well fluid. More preferably the processing mechanism removes light end liquid hydrocarbons from the produced well fluid or mixture of produced well fluid and carrier fluid.

Even more preferably the light end liquid hydrocarbons removed from the produced well fluid or mixture of produced well fluid and carrier fluid are re-injected into the produced fluids at or proximate to the first point typically in order to allow a portion of the gaseous component of well fluid produced to change to the liquid phase and proceed to the second point such as the host facility.

According to a further aspect of the present invention, there is provided a method comprising the steps of: (a) producing fluid comprising liquid hydrocarbons from at least one well; (b) moving said liquid hydrocarbons from the at least one well to a host facility, (c) optionally separating the liquid hydrocarbons from other fluids produced by the at least one well; (d) moving the liquid hydrocarbons from the host facility to the proximity of a wellhead of at least one second well; (e) allowing a portion of gases produced from the at least one second well to be absorbed by said liquid hydrocarbons; (f) moving the liquid hydrocarbons and absorbed gases to the host facility.

The at least one well and the at least one second well can be the same well.

The liquid hydrocarbons may comprise C3-C6 hydrocarbons, such as C5 hydrocarbons.

The present invention also provides a method of recycling a portion of produced well fluid back to a production wellhead in order to change a portion of further produced well fluid from a gaseous to a liquid phase.

Preferably the recycled well fluid comprises light end liquid hydrocarbons, particularly C3-C6 hydrocarbons, such as propane, butane, pentane or hexane.

Wax, scale and corrosion inhibitors may be added to the produced well fluid re-injected at the production wellhead.

Typically the light end liquid hydrocarbons are re- injected after processing at the host facility.

The method is typically used in deep-water systems.

According to a further aspect of the invention, there is provided an apparatus for recovering production fluids from a well, the apparatus comprising: a production flowline adapted to transfer produced well fluid, the production flowline in use extending from the proximity of at least one wellhead to a host facility, and an injection flowline adapted to transfer a carrier fluid, the injection flowline in use extending from the host facility to the proximity of at least one wellhead.

According to a further aspect of the present invention there is provided an assembly for recovering production fluids from a well, the assembly comprising a production flowline extending from an area proximate to at least one wellhead to a storage or production facility, and an injection flowline extending from the storage or production facility back to the at least one wellhead.

Preferably the apparatus and/or assembly according to the further aspects of the invention is/are used to perform the method according to any earlier aspect of the invention. Preferably the storage or production facility includes a processing facility to separate the produced fluids.

Preferably the injection flowline is adapted to transfer a carrier fluid. Preferably the carrier fluid comprises light end liquid hydrocarbons. Preferably the production flowline is adapted to transfer produced well fluid mixed with the carrier fluid.

Preferably the production and injection flowlines form part of an overall third flowline which extends from the storage or production facility to an area proximate to at least one wellhead, loops around and extends back to the storage or production facility.

Optionally the assembly comprises a pump to pump produced fluid from the area proximate to the wellbore to the storage or production facility. Preferably the production wellheads are connected to the flowline via tee connectors. Preferably the production wells are connected to the flowline directly and not via other production wellheads.

Preferably the flowline is adapted to create turbulent flow in order to mix the carrier fluid and production fluid. Optionally a mixer may be provided to increase the turbulent flow.

A pumping station may be provided to pump fluids from the area proximate to the production wells to the host facility.

Typically the host facility comprises separators, preferably heaters, preferably pumps and preferably coolers in order to separate produced fluid (often with carrier fluid) to remove produced water, any gases present and preferably to separate the hydrocarbon components so that some may be recovered whilst others may be reinjected.

Optionally a boiled or heated hydrocarbon fraction including one suitable for use as a carrier fluid (for example a C5 fraction) may be used to heat a fluid stream in another part of the host facility, such as a stream comprising hydrocarbons on route to a separator. Thus the host facility may comprise a heat exchanger. Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying figures, in which: Fig. 1 is a diagrammatic view of a subsea production well and host facility; Fig. 2 is a diagrammatic view of a subsea wellhead production ring; Fig. 3a is a diagrammatic view of a host facility including processing system; Fig. 3b is a diagrammatic view of an alternative processing system; Fig. 4 is a graph showing the expected production profile of a particular deepwater field; Fig . 5 is a graph showing the extent of hydrate mitigation using single component (C4 and C5 ) re-inj ection fluids ; Fig. 6 is a graph showing the temperature of hydrate formation using the method in accordance with the present invention compared to another method; Figs. 7a and 7b are schematic view of the flow characteristics of fluids through pipelines in prior art systems; Fig. 7c is a schematic view of flow characteristics though a pipeline for certain embodiments of the present invention; Fig. 8 is a graph showing the phase changes of C0₂; Fig. 9 is a graph showing the solubility of C0₂ in water; Fig. 10 is a graph comparing the corrosion occurring using a prior art method and using one method in accordance with the present invention; Fig. 11a to lie are graphs showing the wax deposition within pipelines using known methods of fluid transport; Fig. 12 is a graph showing the requirements to avoid wax deposition in a 12" pipeline for known methods of fluid transport; and, Fig. 13 is a graph showing that no wax is precipitated within a pipeline using a method in accordance with the present invention; Fig. 14 is a graph comparing the erosion due to sand production in known methods and a method in accordance with the present invention.

As shown in Fig. 1 apparatus 10 comprises a processing facility/vessel 16 connected to a well site 18 (and associated risers) by a single production pipeline 12 with no insulation and a pipeline 14 to re-cycle light end liquid hydrocarbons.

Fig. 2 is a schematic view showing subsea equipment architecture comprising ring mains 18, wellheads 20 and tee connectors 22. The recycle pipeline 14 connects to the ring mains 18 via a pressure control valve 24. A single or dual ring mains system can be installed depending upon the system requirements and flexibility of production operations. At the opposite end of the ring mains 18, the ring mains 18 connects to the production pipeline 12 via a pumping station 26 for pumping liquids back to the host facility 16 via the production pipeline 12.

The natural mixing that will occur will enable the gas from the production wells 20 to be absorbed by re- circulated light hydrocarbon liquids from the re- injection line 14. However where more mixing is required, for example if production from the wells 20 are not to be operated in the turbulent flow regime, a mixer (not shown) can also be included upstream of the pump 26. The mixer can comprise a spiral vane which allows fluids to pass thereover and be mixed. Preferably the mixer does not include any moving parts.

For certain embodiments of the present invention the recycle pipeline may be directed to inject the recycled fluids back into the well or reservoir, beneath the wellhead. Some of the gases in the well can then be mixed with and absorbed into the recycled fluids before they reach the wellhead.

Fig. 3a shows a processing system 30 within the host vessel 16 for separating the produced liquid into water, hydrocarbon gas, light end liquid hydrocarbons, and other liquid hydrocarbons. The host facility 16 connects to the production line 12 and recycle pipeline 14 and includes a choke (not shown) , heaters 40 & 48, coolers 44 & 52, separators 42, 46 & 50, a storage tank 54, a pump 56 and a control valve 58. The interconnection between these components is described below.

Multiphase production fluids from the wells 20 are mixed via the tee 22 at the production tree with re- cycled light end liquid hydrocarbons from the recycle line 14. The re-cycled light end liquid circulation is controlled by a pressure control valve 24 at the inlet to the subsea ring main loop 18 and by the control valve 58 on the host processing facility. The re-cycled light end hydrocarbon liquid mixes with the well production fluids at each of the tees in the ring main 18.

Gas from the multiphase production fluid is completely absorbed by the re-cycled light end liquid hydrocarbons so that the production fluids (with mixed in light end liquid hydrocarbons) are only in the liquid phase prior to passing into the pump station 26.

The gas-liquids phase equilibrium of the production fluid is modified at the production well heads 20. The production fluids are pumped (if required) via the subsea pump station 26 and transported to the host facility 16 via the production pipeline 12, where they are separated and processed. The fluids enter the host facility via the production riser 12, and are choked to reduce pressure.

Depending upon the quantities of gas to be handled, a compact type vertical separator (not shown) may be installed between the riser choke (not shown) and upstream of the first stage separator 42 in order to remove the majority of the gas phase and also to minimise the size of the gravity separators 42 & 46 in the overall scheme. The separated gas is sent to the gas stream for further processing and compression (not shown) .

The production stream is then directed to the heater 40 where it is heated to a temperature that enables gasification of the light end liquids up to the C6 component or higher component if required. The fluid proceeds to the first stage separator 42 where hydrocarbon 'gas, hydrocarbon liquid and water are - separated.

The separated gas stream is directed to a cooler 44 where it is cooled to enable the light end liquids (primarily the C3 to C6 components but very small quantities of other hydrocarbon components may also be present) to be further separated from the gas phase consisting of CI and C2 components. This fluid is separated into gas and liquid phases by separator via 46. The CI and C2 gas stream is sent for further processing / compression. The oil stream from the first stage separator 42 is directed to the heater 48 where it is heated to separate C3 to C6 components from the bulk oil stream. These are separated in separator 50. The bulk oil stream is directed towards storage tanks (not shown) and transported onshore by conventional means (not shown) .

The separated C3-C6 light end liquids from the separator 50 are then directed to the cooler 52 where they are cooled and then mixed with the C3 to C6 light ends stream from the separator 46 in the storage tank 54.

This mixed stream of light end hydrocarbons in the storage tank 54 forms the carrier fluid for re- cycling. The proportion of C3, C4, C5 and C6 components are optimised for the particular system' s environmental and operational conditions. The optimised ratio of C3-C6 components and the quantity required are functions of application and the requirements to mitigate hydrates, wax and slugging and whether the application is an oil or gas condensate field development.

For example where more hydrate formation is expected, a higher proportion of C5 and C6 is included, whereas where less hydrate formation is expected more C3 can be included in the re-injection fluid. Light ends hydrocarbon stream can then be pumped by the pump 56 at a controlled rate by a valve 58 to the circulation ring 18 via the recycle line 14.

The production fluids composition change is a direct function of the quantity of circulated light end liquids re-injected.

Fig. 3b shows an alternative processing system 130 provided within a host facility (not shown) such as a vessel or onshore facility. The processing system 130 also separates produced liquid into water, hydrocarbon gas, light end liquid hydrocarbons, and other liquid hydrocarbons. It has been specifically designed to maximise the purity of C5 hydrocarbons for reinjection at the well heads 20.

The processing system 130 comprises first and second stage separators (not shown) , a third stage separator 70, an atmospheric storage tank 72, a pump 76, a heater 78, a heat exchanger 80, a further separator 82, a recycle pump 84 and a cooler 86. Their interconnections are described below.

The produced fluid mixture is received from the wells 20, as described above with reference to Fig. 3a. In the first and second stage separation (not shown) most of the produced water, CI & C2 gases and C3 & C4 hydrocarbons are removed. The liquid mixture proceeds to a third stage separator 70, which operates at 2 barg and ambient temperature, to remove any residual produced water. The C3+ hydrocarbon mixture proceeds to the atmospheric storage tank 72 where it can be held at ambient temperature and 0 barg pressure until required. An atmospheric vent 74 is provided in the atmospheric storage tank 72.

When, required, the pump 76 (duty = llkW) pumps the C3+ mixture, at ambient temperature and a pressure of 1 barg, to the crude heater 78 (duty = 7.7MW) via the heat exchanger 80 (duty = 15MW) . The mixture receives some heat from the heat exchanger 80 to raise it to, for example, 66°C. The C3+ mixture is further heated by the heater 78 to around 100°C and then proceeds to a separator 82.

(The uty' is the power requirement and the figures given here are exemplary and may be varied.)

The C5 fraction within the C3+ stream is evaporated in the separator 82 at a pressure of 1 barg and a temperature of 100°C and is then ready for reinjection at the well heads 20. Before the C5 is directed to the well heads 20 or to a storage tank (not shown) , it passes by the heat exchanger 80 in order to exchange heat with some of the upstream C3+ hydrocarbons on route to the heater 78. The pump 84 (duty = 0.3MW) can pump the C5 fraction to the well heads 20 at a rate of 25,500 bpd. The cooler 86 (duty = -4MW) cools the recovered crude to around 40°C for export, at a rate of around 19,800bpd.

Thus a benefit of a configuration as shown in Fig. 3b is that the C5 component is maintained in the liquid phase before being separated and recycled. This can be more efficient than the configuration shown in Fig. 3a where the C5 components are aloud to proceed into the gas and the liquid phases before being recovered.

The configuration of the host processing facility is typically tailored to the specific reservoir fluid to be recovered and operating conditions encountered on a case by case basis. Thus numerous different configurations of the host processing facility are possible depending on the specific requirements of the well or wells to be produced. The host processing facility used for certain embodiments of the invention may also be retro-fitted onto an existing processing facility, particularly when utilised onshore.

The present invention can be referred to as Gas to Liquid Absorption Technology (GTLA) .

Certain embodiments of the present invention benefit from the fact that the subsea equipment architecture requires no large manifold as simple junction Tees are incorporated at each production tree location. Whilst trie ring configuration 18 is shown in the example riere, the method of the present invention can be used with other manifolds including existing subsea manifolds .

Certain embodiments of the present invention benefit from the fact that the requirement for hydrate and wax inhibitors is eliminated or reduced since the hydrate formation and wax appearance temperature is lowered below the ambient seawater temperature. Thus less or no insulation on the production pipeline and riser is required since the production fluids are predominantly or exclusively in the liquid phase when travelling therethrough. This method thus provides the opportunity to remove the pipeline insulation so that the production fluids are transported to the host facility as cold flow which benefits the oil-gas field development economics.

Furthermore the production can be transported through a single pipeline in most cases since the gas phase is no longer present.

Fig. 6 shows a typical hydrate formation envelope for an Oil-Gas-Water mixture and the significant effect of the gas absorption described herein on this hydrate envelope .

The hydrate formation envelope has moved to the left reaching hydrate formation temperatures of -18°C at a pressure of lOObara. As this temperature is well below the temperature of the ambient water body, hydrates will not form even for unplanned and extended system shutdowns .

This can be achieved without hydrate inhibitors of any kind to mitigate hydrates using this system. Further no heat energy or heat retention methods i.e. pipeline insulation is required.

The data for a particular oilfield development is given below.

Development of a deepwater field In Angola (West: Africa) . Water Depth = 2000m. Tie-back distance to an FPSO processing vessel = up to 50km. Gas to Liquid Ratio = 300scf/stb. Well Head, flowing pressure = 50bara. Well Head, flowing Temperature = approx. 50°C Reservoir Pressure = 200 bara Reservoir temperature = 55°C.

The expected production profile is shown in Fig. 4.

The requirements for light end hydrocarbons liquid circulation requirements to mitigate slugging are also superimposed on the production characteristics. The production reservoir fluids composition is shown in Table 1 below.

Table 1 The hydrate mitigation requirements circulating either pure C4 or C5 are shown in Fig. 5.

Onshore pipelines can extend for hundreds or even thousands of miles between wells and a processing facility and so mitigation or elimination of wax or other problems with onshore pipelines would be beneficial. Wax formation is a particular problem for onshore pipelines. Certain embodiments of the present invention may be used onshore.

Certain embodiments of the present invention benefit from the fact that slugging in the production pipeline is eliminated or reduced since the re-circulated light end liquid hydrocarbons absorb most or all the free produced gas. Certain embodiments of the present invention benefit from the fact that slugging in the production flow line and riser are completely mitigated by transporting in the liquid (oil and water) phase. This is achieved by retaining the gas in the liquid phase by the absorption process prior to pressure boosting and transport to the host facilities vessel. Figs. 7a and 7b show the flow characteristics of multiphase transportation whilst Fig. 7c shows the single liquid phase flow characteristics of certain embodiments of the present invention. A related benefit is that since there is no slugging in the pipeline, production can be reduced or increased without operational instability. Further no high forces resulting from riser base initiated high velocity slugs as is common with multiphase transport are seen. This means that the overall technical risk for the asset is reduced and production availability and productivity increased.

Certain embodiments of the present invention benefit from the fact that the internal (and external) corrosion in the production pipeline is considerably reduced since the quantity of C0₂ absorbed by the water phase is reduced by absorbency of the C0₂ by the re- circulating light end liquids.

This is achieved by absorbing the free gas phase by the high absorption liquid and pressure boosting the production fluids. This avoids any further transfer of C0₂ into the water phase as gas is not allowed to be dissolved from the liquid and transferred to the water phase.

Fig. 8 shows the typical phase boundaries of C0₂ and the solubility in the water phase with pressure and temperature respectively. As can be seen from Fig. 8 the C0₂ component of the production fluids at reservoir conditions is in the liquid (oil) phase. As both the pressure and temperature decline with production fluids travelling towards the well head, the C0₂ changes from the liquid to the gas phase. Thus most if not all of the C0₂ is in the gas phase at the well head.

Fig. 9 shows the effect of pressure and temperature on C0₂ solubility. By absorbing the gas phase containing the C0₂ by the high absorbing liquid, the C0₂ is kept in solution and in the liquid, thus avoiding contact and transfer to the water phase. C0₂ phase behaviour calculations show that based even on C0₂ partial pressure calculations before and after the gas absorption process, corrosion rate reduction of up to 30-60% can be achieved, Fig. 10.

Thus, certain embodiments of the present invention benefit from the fact that production pipelines can be made from carbon steel rather than the expensive corrosion resistant alloys used to make some existing production pipelines. Certain embodiments of the present invention benefit from the fact that where paraffin wax is present within produced fluids, this will be diluted by the re-cycled light end liquid hydrocarbons. This will reduce the weight percent of wax having the potential to precipitate during transport in the production pipeline. Further, the small chain length molecules (e.g. C5) can prevent the long chain wax forming components (typically paraffins and aromatics) from forming wax crystal nucleation and wax deposits in pipeline systems.

Fig. 11a shows the rate of wax deposition for an insulated 8" and 50km production pipeline and riser having U of 3W/m2K and 10W/m2K respectively in 2000m water depth using the typical method of transporting the fluids in a multiphase gas/liquid mixture.

Figs, lib and lie show the effect of increasing both the pipeline diameter and level of insulation on the pipeline. These predictions show that wax precipitation and deposition still occur in both the pipeline and riser at low production rates so insulation alone is not a total solution to wax problems.

Fig. 12 shows the power requirements in combination with pipeline insulation to avoid wax deposition in a 12" pipeline. Predictions show that for a 12" and 50km pipeline having an insulation to achieve ϋ of 3W/m2K will still require a power of lOOW/km (5MW per pipeline) .

Fig. 13 shows that with certain embodiments of the present invention no wax in precipitated or deposited along the pipeline even without pipeline insulation nor power for active heating.

If wax should begin to deposit in the pipeline, then certain embodiments of the present invention allow an appropriate wax solvent to be circulated through the production pipeline at a pre-defined frequency.

Another problem found in such pipelines is calcium carbonate scales resulting from the C0₂ component coming out of solution from the crude oil during multiphase fluid transport.

With certain embodiments in accordance with the present invention, the re-cycled light end liquid hydrocarbons that are mixed with the production fluids plus the pressure boosting subsea keeps the C0₂ within the crude oil. Further as a decrease in the production fluid temperature increases the solubility of calcium carbonate, the present invention will have a beneficial effect since the production fluids temperature will reach the ambient water temperatures over a very short distance from the production wells. The ambient water temperatures are considerably lower than the wellhead flowing temperatures. Thus when the production fluids are transported in accordance with the present invention, calcium carbonate scaling can be avoided in the production system from the wellhead to the host receiving facility.

Certain embodiments of the present invention benefit from the fact that internal pipeline erosion resulting from sand production is virtually eliminated. Using certain methods of the present invention, the fluid is in the liquid phase only and thus the high velocities caused by gas expansion as a result of pressure drop along the pipeline no longer occur.

Fig. 14 shows a direct comparison of the sand erosion rates in the riser for the known multiphase and the new ^λGTLA' methods in accordance with the present invention.

As can be seen the erosion due to sand production via the GTLA method is virtually eliminated in comparison to the multiphase production method. Certain embodiments of the present invention benefit from the fact that tight emulsions that occur between the crude oil and the water phase is controlled through the circulating light end hydrocarbons.

The light end hydrocarbon high gas absorption liquid mixed with the production fluids at the wellhead reduces the mixture crude oil density. Thus Certain embodiments of the present invention benefit from the fact that the probability of forming a tight emulsion between the water and oil phases is reduced.

If emulsions are suspected during production conditions, then the rate of the circulating liquid can be increased. This re-circulation increase will allow the emulsion occurrence production water/oil cut conditions displaced outside the emulsion regime.

Certain embodiments of the present invention benefit from the fact that the viscosity of crude oils is substantially reduced by the circulating light end liquid hydrocarbons.

Certain embodiments of the present invention benefit from the fact that increased fluids separation efficiency especially for heavy crude oils at the host processing facility is achieved with the circulating light end liquid hydrocarbons.

Certain embodiments of the present invention benefit from the fact that pipeline expansion movement is reduced, thereby reducing stresses so pipe wall thickness can be reduced, thereby saving on costs.

Certain embodiments of the present invention benefit from the fact that there is a reduction in risk of upheaval buckling and associated design, expansion joints and burial. Certain embodiments of the present invention benefit from the fact that the system allows production fluids pressure boosting using a liquid pump because the produced fluids are now in liquid phase (oil and water) . Therefore this system offers multiphase production boosting using a liquid pump for deepwater and long distance production fluids transport.

The tubing for chemical inhibitors such as hydrate, wax, scale, corrosion and emulsions that usually form part of the umbilical are no longer required with some embodiments of the present invention.

The cost benefit of removing the inhibitor tubing from the umbilical, is that the materials cost of the umbilical can be reduced by 50% or more.

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

Claims

1. A method of transporting produced well fluid, the method comprising: adding carrier fluid to the produced well fluid at a first point; the carrier fluid being suitable to allow a portion of any gaseous component in the produced well fluid to move into the liquid phase; moving the produced well fluid and carrier fluid to a second point.

2. A method as claimed in claim 1, wherein the produced well fluid comprises a gas phase.

3. A method as claimed in claim 1 or claim 2, wherein the carrier fluid comprises a liquid phase.

4. A method as claimed in claim 3 when dependent on claim 2, wherein a portion of the gas phase of the produced well fluid enters the liquid phase of the carrier fluid, before moving the produced well fluid and carrier fluid to a second point.

5. A method as claimed in any preceding claim, wherein the well fluid and carrier fluid move from the first point to the second point substantially in a liquid phase.

6. A method as claimed in any preceding claim, wherein the carrier fluid comprises hydrocarbons.

7. A method as claimed in claim 6, wherein the carrier fluid comprises C3-C6 hydrocarbons.

8. A method as claimed in any preceding claim, wherein the first point is proximate to a production wellhead.-

9. A method as claimed in claim 8, wherein the production wellhead is a subsea production wellhead.

10. A method as claimed in any preceding claim, wherein the second point is a host facility.

11. A method as claimed in claim 10, wherein the host facility is an offshore host facility.

12. A method as claimed in claim 11 or claim 10 when dependent upon either claim 8 or claim 9, wherein a pump is provided proximate to the production wellhead and the fluid is pumped from the proximity of the production wellhead to the host facility.

13. A method as claimed in any one of claims 10 to 12, wherein the host facility comprises a processing mechanism operable to separate at least a portion of the constituent parts of the produced well fluid.

14. A method as claimed in claim 13, wherein the processing mechanism separates at least a portion of normally liquid hydrocarbons from the produced well fluid or from a mixture of produced well fluid and carrier fluid.

15. A method as claimed in claim 13 or claim 14, wherein the portion separated from the produced well fluid or from the mixture of produced well fluid and carrier fluid is re-injected into produced well fluid proximate to the first point.

16. A method comprising the steps of: (a) producing fluid comprising liquid hydrocarbons from at least one well; (b) moving said liquid hydrocarbons from the at least one well to a host facility; (c) substantially separating the liquid hydrocarbons from other fluids produced by the at least one well; (d) moving the liquid hydrocarbons from the host facility to the proximity of a wellhead of at least one second well; (e) allowing a portion of gases produced from the at least one second well to be absorbed by said liquid hydrocarbons; and, (f) moving the liquid hydrocarbons and absorbed gases to the host facility.

17. A method as claimed in claim 16, wherein the at least one well and the at least one second well are the same well.

18. A method as claimed in claim 16 or claim 17, wherein the liquid hydrocarbons comprise C3-C6 hydrocarbons.

19. An apparatus for recovering production fluids from a well, the apparatus comprising: a production flowline adapted to transfer produced well fluid, the production flowline in use extending from the proximity of at least one wellhead to a host facility, and an injection flowline adapted to transfer a carrier fluid, the injection flowline in use extending from the host facility to the proximity of at least one wellhead.

20. Apparatus as claimed in claim 19, wherein the host facility includes a processing facility to separate at least a portion of the produced well fluids.

21. Apparatus as claimed in claim 19 or claim 20, wherein the host facility is adapted to separate C3 - C6 hydrocarbons from the produced well fluid.

22. Apparatus as claimed in any one of claims 19 to 21, wherein the flowline is adapted to create turbulent flow in order to mix the carrier fluid and production fluid.

23. Apparatus as claimed in claim 22, comprising a mixer having a spiral vane shaped to mix the carrier fluid and production fluid.

24. Apparatus as claimed in any one of claims 19 to 23, wherein the production and injection flowlines form part of an overall third flowline having: a first portion which extends from the host facility to the proximity of at least one wellhead, said first portion forming the injection flowline, and, a second portion extending from the proximity of the at least one wellhead back to the host facility, said second portion forming the production flowline.

25. Apparatus as claimed in claim 24, wherein during use, a plurality of production wellheads are connected to the third flowline via tee connectors.

26. Apparatus as claimed in claim 25, wherein during use, the production wellheads are connected to the flowline directly and not via other production wellheads.