AU2013274971B2

AU2013274971B2 - Using wellstream heat exchanger for flow assurance

Info

Publication number: AU2013274971B2
Application number: AU2013274971A
Authority: AU
Inventors: Bianca Maria Mita NOGUEIRA; Kjell Olav Stinessen
Original assignee: Aker Subsea AS
Current assignee: Aker Solutions AS
Priority date: 2012-06-14
Filing date: 2013-06-12
Publication date: 2017-07-06
Anticipated expiration: 2033-06-12
Also published as: WO2013187771A1; BR112014031103A2; AU2013274971A2; NO20120694A1; AU2013274971A1; NO335391B1

Abstract

Method for facilitating transportation of flowable hydrocarbons through an: insulated pipeline comprising passing a flow of hot flowable hydrocarbons (4) through a separator (1) for separation into a gaseous phase (5) and a cold liquid phase (3a). Thereafter, passing the cold liquid phase (3a) through at least one heat exchanger (3) downstream said separator (1). The heat exchanger also receives heat from a flow of hot flowable hydrocarbons (4), whereby the temperature of said cold liquid (3a) is increased to a desired level. The liquid (3b) flowing out from said heat exchanger (3) is transported to the main pipeline for onward transportation. An apparatus for carrying out the method is also disclosed.

Description

1 2013274971 25 May 2017

FIELD OF THE INVENTION

The present invention in general, relates to a method and apparatus for flow assurance of flowable hydrocarbons along a pipeline, such as but not limited to those comprising passing a well stream of flowable hydrocarbons through a 5 separator for separation thereof into a gas phase and a liquid phase.

More specifically, the present invention relates to a method and apparatus for flow assurance of flowable hydrocarbons along insulated pipelines, such as but not limited to a method and apparatus wherein precipitation of undesirable 10 substances during fluid hydrocarbon transportation, such as wax deposition and hydrate formation are prevented.

More particularly, the present invention relates to a method for flow assurance of flowable hydrocarbons along a pipeline and to an apparatus therefore. 15

TECHNICAL BACKGROUND OF THE INVENTION

In onshore, offshore subsea operations such as for hydrocarbon exploration and production, application of insulated pipelines for fluid transport is common. 20

For example subsea processing plants such as subsea compression stations have long export distance to shore and for that purpose, flowable hydrocarbons, that may be a mixture of oil and water, can be transported along insulated pipelines for flow assurance over long distances to avoid temperature drop 25 below an acceptable level if heating of the lines are not used neither chemicals. Main fields requiring such flow assurance for fluid hydrocarbon pipelines include subsea condensate export pipelines, onshore condensate and oil export pipelines located in a cold environment and so on.

30 Formation of undesirable precipitates is a common problem encountered in transportation of such fluid hydrocarbon. Especially, when transporting unrefined or only partially refined products. Obviously, such precipitates cause 9100650_1 (GH Matters) P98729.AU 2 2013274971 25 May 2017 immense hindrance in the flow of fluid hydrocarbon and may lead to reduced flow rates and even clogging of the flowline.

The precipitates as referred to in the preceding paragraph may be wax, 5 hydrates, asphaltenes, resins, napthalenes, aliphatic hydrates and so on, as known to persons skilled in the art. In general, there is a risk of formation of undesirable deposits in the flow line, when the temperature of the fluid drops below Wax Appearance Temperature (hereinafter referred to as WAT) or hydrate formation. 10 A multiphase well stream may have a temperature as high as 700 C to 1000 C. or even 130°C. This is much higher than the usual hydrate formation temperature, which is around 20°C and the wax formation temperature, which is around 30°C. If the fluids are transported through non-insulated flow lines, the 15 temperature will drop to close to seawater temperature after 5-10 km. If the flow line is insulated, this temperature drop can be extended to about 50 km. The drop in temperature may result in increased hydrate and wax formation.

It is clear that insulation alone can be sufficient only for relatively short 20 distances. Today it is desirable to transport hydrocarbons over a distance up to 100-200 km.

The most common means for preventing hydrate formation is by the use of hydrate preventing chemicals (and correspondingly to use waxing preventing 25 chemicals). The disadvantage is that use of large amounts of chemicals is necessary, which has a significant cost impact. To reduce the consumption of the most commonly used hydrate preventing chemical, monoethyleneglycol (MEG), regeneration plants are used, which increases investment costs and adds technical complexity and weight on platforms. Chemicals also pose 30 potential threats to the environment, and equipment for separation and neutralization of chemicals are necessary to achieve the goal of “zero emission”.

9100650 1 (GH Matters) P98729.AU 3 2013274971 25 May 2017

Direct Electric Heating (DEH) to warm up the pipelines for preventing precipitate formation is also an alternative. However, this method is grossly expensive, having regard to the length of pipelines applied. 5 On the other hand, it is also known that cooling of the hot well stream prior to its entry into a separator is beneficial to improve gas and liquid separation. It is also highly beneficial that the gas entering a compressor is cool. That reduces the energy required for compression. However, overcooling causes deposits/precipitates as stated in the preceding paragraph, especially when the 10 products are transported over long distances where the ambient temperature is low.

To solve the draw back of the overcooling of the liquid phase, attempts have been made to relocate the inlet cooler to cool down the gas line only, but in that 15 event an additional high efficiency scrubber is needed downstream of this cooler, to separate the remaining liquid phase before entering the compressor. This invites complication in the system and adds on to the cost.

Granted US patent 7261810B2 teaches to solve this problem by cooling the hot 20 hydrocarbons to be transported consecutively in a reactor and a heat exchanger, so that the undesirable substances are precipitated in the reactor and the heat exchanger in that order. Thereafter, the hydrocarbons are transported, supposedly free of precipitating solids. However, this technique does not sufficiently prevent precipitate formation over substantially long 25 distances, and safe transport can not be achieved in its entirety by this method of cooling.

Furthermore, the above method requires a source of cold fluid containing small crystals for its addition to the hot fluid hydrocarbon and the basic principle is 30 mixing of the hot fluid hydrocarbon with this cold fluid for lowering the

temperature of the fluid hydrocarbon to be transported, for precipitation of unwanted substances. The crystals in the cold fluid act as nucleation points for 9100650 1 (GHMatters) P98729.AU 4 2013274971 25 May 2017 precipitation of similar substances from the hot fluid. Hence, the method is cumbersome as well and can not be entirely relied upon.

Addition of chemicals for delaying or preventing formation of precipitates is 5 another technique but this apart from being costly, has been not found to be technically sufficient for preventing precipitate formation during transportation over long distances. The chemicals will also have to be separated from the products after the transport. 10 Accordingly, there is a long felt need for developing a method and apparatus for flow assurance of fluid hydrocarbon along a network of insulated pipelines in a technically reliable and cost effective manner, whereby the disadvantages of prior art as contemplated above, are substantially minimized or eliminated. 15 The present invention meets this aforesaid long felt need and other needs associated therewith.

ADVANTAGES OF EMBODIMENTS OF THE INVENTION 20 It is an object of the present invention to provide a method and apparatus for flow assurance of flowable hydrocarbons along a, preferably insulated, pipeline in a technically reliable by utilization of the heat content of the well stream upstream a subsea processing plant, e.g. a compression station or excessive heat from equipment of the station, such as gas compression, whereby the 25 disadvantages of prior art are substantially minimized or eliminated. It is desirable that the method and apparatus are cost effective.

It would be advantageous for the present invention to provide a method and apparatus for flow assurance of flowable hydrocarbons along a, preferably 30 insulated, pipeline, such that formation of undesirable precipitates during transportation over substantially long distances is prevented.

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It would be advantageous for the present invention to provide a method and apparatus for flow assurance of flowable hydrocarbons along a, preferably insulated, which is simple and does not involve complicated steps or components. 5

It would be further advantageous for the present invention to provide a method and apparatus for flow assurance of flowable hydrocarbons along, preferably insulated, pipelines by effecting heat exchange between hot flowable hydrocarbons from a well stream and flowable hydrocarbons to be transported, 10 so that the temperature of the flowable hydrocarbons to be transported is increased to a desired level for preventing formation of undesirable precipitates.

The general principle of the present invention is to use heat from the well stream upstream of a subsea processing plant and possibly also heat 15 generated by equipment in the plant, especially compressors, to prevent formation of hydrates, precipitation of wax and precipitation of other components, by transferring this heat from the well stream and/or said heat generating component to the fluids by indirect heat exchange and thereby using this heat to keep the temperature sufficiently high. 20

More specifically, one or more embodiments of the invention may relate to flow assurance by utilization of heat from a well stream upstream of a cooler and a separator and possibly also heat generated by equipment, such as by compressing gas, in a subsea processing system, and heat exchange of 25 mentioned heat with liquid pipelines downstream the process separator. Flow assurance may be achieved by warming up the outlet liquid line of the separator to above hydrate formation temperature, wax appearance temperature (cloud point), and above precipitation temperature of other components (e. g. asphaltenes) that can clog the flow by accumulation below certain 30 temperatures.

To keep the temperature above problematic level in long transport lines along the seabed with its low temperature, it will normally be necessary to insulate the 9100650_1 (GH Matters) P98729.AU 6 2013274971 25 May 2017 lines. The described method of utilizing excess heat in combination with insulated fluid transport lines can be a much cheaper solution than electric heating of said lines or use of chemicals. Even if this method should not ensure flow assurance alone the whole length of long lines, or during some modes of 5 operation (e.g. low flow) or shutdown, it can significantly reduce the need for heating or chemicals for instance to only inject chemicals or switch on electric heating at shutdown.

How the foregoing objects are achieved and the advantageous aspects may be 10 achieved will be clear from the following non-limiting description.

All through the specification, including the claims, the words “pipeline”, “flowable hydrocarbons”, “cold fluid”, “separator”, “inlet cooler”, “heat exchanger”, “onshore”, “offshore”, “hot well stream1', and ’’hot flowable hydrocarbons” are to 15 be interpreted in the broadest sense of the respective terms and includes all similar items in the field known by other terms, as may be clear to persons skilled in the art. Restriction/limitation, if any, referred to in the specification, is solely by way of example and understanding the present invention.

20 SUMMARY OF THE INVENTION

According to a first aspect of the present invention there is provided a method for flow assurance of flowable hydrocarbons along a pipeline, comprising letting a stream of hot flowable hydrocarbons flow through a separator for separation 25 thereof into a gas phase and a liquid phase, wherein heat from the hot flowable hydrocarbons is extracted before the hot flowable hydrocarbons enters the separator and transferred to the liquid exiting the separator.

Preferably the pipeline is an insulated pipeline. The method may comprise 30 exchanging heat between a flow of hot flowable hydrocarbons or hot well stream and the fluids to be transported. The hot well stream flows into a separator. The separator separates the well stream into a gas phase and a

9100650_1 (GHMatters) P98729.AU 7 2013274971 25 May 2017 liquid phase. In order to facilitate the gas-liquid separation, the well stream is cooled by an inlet cooler located upstream the separator.

According to an embodiment of the method of the present invention, the liquid 5 phase is thereafter passed through at least one heat exchanger, located downstream of the separator. The heat exchanger may have a constant flow of hot well stream. This may ensure that the temperature of the cold liquid from the separator is increased to a desired level and finally the liquid flowing out from the heat exchanger is transported to the main pipeline, for onward 10 transportation.

More preferably, the hydrocarbons of the well stream exiting from the heat exchanger is recycled back to the well stream line or preferably to the line downstream an inlet cooler, through which the hot flowable well stream passes, 15 before entering the separator.

Also disclosed is an apparatus for carrying out the method according to the first aspect. 20 According to a second aspect of the present invention there is provided an apparatus for flow assurance of flowable hydrocarbons, comprising: at least one insulated pipeline; a separator for separating hot flowable hydrocarbons into a gas phase and a liquid phase; 25 at least one heat exchanger located downstream said separator for receiving inflow of the liquid phase and adapted to receive hot flowable hydrocarbons or hot seawater, for transferring heat to increase the temperature of said liquid phase to a desired level by heat exchange.

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BRIEF DESCRIPTION OF THE ACCOMPANYING FIGURES

Having described the main features of the invention above, a more detailed and non-limiting description of some preferred embodiments will be given in the 5 following with reference to the drawings, in which:

Figure 1 is a schematic line drawing of a preferred embodiment of the apparatus according to the present invention and also illustrates how the apparatus is applied to run a process according to an embodiment of the 10 present invention.

Figures 2 and 3 illustrate line drawings of two more preferred embodiments of a part of the apparatus according to the present invention and also illustrate how those apparatuses are applied to run a process according to an embodiment of 15 the present invention.

Figure 4 illustrate an embodiment of the present invention when using heat generated by equipment, in this example a compressor. 20 Figure 5 illustrates a further alternative embodiment of the invention, were separated gas is used as a heating medium.

Figure 6 illustrates yet another embodiment where the well stream heats seawater that is stored in a tank and subsequently used to heat the liquid 25 condensate.

DETAILED DESCRIPTION OF THE INVENTION

The following provides a detailed non-limiting description of some preferred 30 embodiments of the present invention which are purely exemplary.

Hot well stream referred to hereinbefore and hereinafter may come from one or more drilling hole well(s) or through a transport line from a nearby oil or gas 9100650_1 (GH Matters) P98729.AU 9 2013274971 25 May 2017 field, as known to persons skilled in the art. Further, hereinbefore and hereinafter for the sake of explanation and simplicity, only hot well stream is referred to. It is to be understood that such term also embraces, hot flowable hydrocarbons, such as from a hydrocarbon process plant or similar, which may 5 be at an elevated pressure.

Further, due to similar reasons, precipitates have been referred to as wax and hydrates. It includes other precipitates as known in the field as well and as explained under the heading ’’Technical Background of the Invention”. 10

Now referring to the accompanying figure 1, a preferred embodiment of the invention will be explained in detail. A hot well stream flows along the line 4.

The line 4 is branched into a first line 4a’, which extends through an inlet cooler 2 and enters the separator 1 along line 4’. This hot well stream prior to entering 15 inlet cooler 2, is at an elevated temperature. The inlet cooler may be of the type described in the applicant’s Norwegian patent application NO 2011 0946, which is hereby incorporated by reference.

The inlet cooler 2 is preferably applied to bring down the temperature of hot well 20 stream for ensuring condensation of the liquid fraction of the hydrocarbons, so that the gas and liquid fractions may be separated. In the separator 1, the hot well stream separates into dry gas 5 (the gas 5 should be as dry as possible in order for it to be efficiently compressed by a compressor in a later stage) and cold liquid 3a. The liquid may be gas condensate, oil and/or water. The liquid 25 may also contain small proportions of gas. This cold liquid is to be transported along the export pipelines.

The cold liquid 3a which leaves the separator 1 is allowed to enter a heat exchanger 3. This heat exchanger 3 is located downstream the separator 1, 30 along a pipeline.

From the hot well stream is also branched off a second line 4a which leads to the heat exchanger 3 located downstream the separator 1. In the heat 9100650_1 (GHMatters) P98729.AU 10 2013274971 25 May 2017 exchanger 3 the hot well stream exchanges heat with the cold liquid from the separator 1 in order to increase the temperature of the cold liquid. At the same time the temperature of the well stream through the heat exchanger 3 is reduced. 5

The heat exchanger 3 may be configured so as to be co-current or counter current and this is not consequential to the present invention. The dry gas 5 may be transported separately, which is not shown in detail. 10 The heat exchanger 3 is preferably having a constant feed of hot well stream along line 4a. So, when the cold fluid enters the heat exchanger 3, it finds the hot fluid hot well stream there. Consequently, heat exchange takes place between the hot well stream and the cold fluid. Alternatively the line 4a may have a valve (not shown) that can be adjusted to provide the exchanger 3 with 15 a flow of hot fluid adapted to the heating requirements to bring the temperature of the liquid from the separator 1 to the optimal level.

Although only one heat exchanger 3 is shown, there may be a plurality of such heat exchangers located downstream of the separator, all having constant feed 20 of hot well stream in the same manner. Further, there may be a plurality of separators 1 as well and all function in the same manner.

The temperature of the cold fluid is thus increased to a desired level. Hence, the liquid 3b which exits the heat exchanger 3 has a desired temperature as 25 exemplified hereinafter, which prevents formation of wax or hydrate or other precipitates. This liquid 3b is now transported to the main pipeline for onward transportation (not shown in detail).

The well stream which leaves the heat exchanger 3 along the line 4b has a 30 lower temperature, as compared to the hot well stream 4 which enters the inlet cooler 2 along 4a’. The temperature may be comparable to the well stream which enters the separator 1 along line 4’.

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As shown in the figure 1, preferably, the well stream which leaves the heat exchanger 3 along line 4b is re-circulated back to the separator 1 by connecting the line 4b to line 4’ downstream of the inlet cooler 2. Alternatively, depending on the temperature, this well stream flowing through line 4b may be mixed with 5 the hot well stream 4 at line 4a’.

Figures 2 and 3 illustrate two alternative embodiments where the heat exchanger 3 is integral with the separator 1 but in any event is located downstream to it. Here, the like reference numerals represent like features and 10 the functioning is also essentially the same, as will be appreciated by persons skilled in the art.

Figure 4 illustrate possible enhancement to embodiments of the present invention. It illustrate a well stream 4 that is led through an inlet cooler 2 and 15 enters a separator 1 along a line 4’. From the separator 1 the gas exits through a gas line 5 to a compressor 6. The gas exits the compressor 6 through a compressed gas line 6’. The liquid exits the separator 1 through a liquid line 3a and is further through a heat exchanger 3. After the heat exchanger the liquid enters a liquid transport line 3b. 20 A part of the compressed gas is branched off from the line 6’ to a branch line 6a and is led through the heat exchanger 3. After the heat exchanger 3 the gas enters a further gas line 6b. This is described as a separate invention in a copending application to the present. However, this arrangement may also be 25 used to enhance embodiments of the present invention to ensure sufficient heat availability.

As will be understood from the above, instead of branching off a part of the well flow, as per the embodiment of figure 1, in the alternative embodiment of figure 30 4, a part of the compressed gas that has been heated during the compression

in the compressor (6) s branched off from the hot discharge line 6‘ to the branch line 6a and used to heat up the liquid that enters the heat exchanger 9100650J (GH Matters) P98729.AU 12 2013274971 25 May 2017 from the line 3a. The gas in the line 6b may be led back to the line 6’ or to the well stream line 4 depending on the chosen process strategy.

According to one or more embodiments, the present invention thus proposes 5 system configurations to allow heat transfer between the hot well stream and the cold liquid, preferably condensate or oil-water stream.

The heat transfer takes place in a heat exchanger 3 where the well stream 4 or the compressed gas is the hot fluid and flows into the heat exchanger 3 along 10 the line 4a or 6a, respectively. The cold liquid 3a also flows into the heat exchanger 3. The well stream or gas flows out of the heat exchanger along line 4b or line 6b, with lower temperature than its inlet temperature and the liquid 3b flows out with higher temperature than its inlet temperature. 15 For all configurations of the apparatus according to embodiments of the present invention, the well stream return along line 4b may be directed into the inlet well stream 4 upstream or downstream of the inlet cooler 2 along line 4’, or in the alternative, the gas may be returned from the line 6b to the compressed gas line 6’, the uncompressed gas line 5 or the well stream at line 4 or line 4’. This 20 depends on the return temperature desired or other process strategies.

Pressure drop is ensured for the circulation of the well stream along line 4b. An existing pressure drop may be used, as injecting the well stream return line 4b downstream the inlet cooler 2. If that is not enough, an additional pressure drop 25 is created in the system by means known per se to the person of skill. The same applies for the gas in line 6b, depending on where it is returned.

Thus, embodiments of the present invention combined with standard pipeline insulation makes it possible to export gas and/or condensate through long 30 pipelines with sufficient operating temperature to avoid formation of unwanted precipitates during transportation over substantially long distances. The ideal operating temperature is dependent on the length of the pipeline and heat lost per unit length during transit.

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The present invention according to one or more embodiments may achieve its goal of substantially precipitate free transportation of hydrocarbon for substantially long distances along a pipeline, by applying efficient exchange of heat between the flowable hydrocarbons to be transported and the hot well 5 stream.

The exemplary table 1 below shows some results for a subsea processing and compression station case where the condensate WAT (Wax Appearance Temperature) is 34°C. The condensate export line is of 8” diameter and more 10 than 100 km length. The seawater temperature considered to calculate the heat loss on the pipeline is 5°C.

Table 1: Condensate pipeline length at above WAT

Gas stream % mass flow Duty (MW) Gas Temp. ("C) Condensate Temp. <”C) Insulation Thickness Condensate Pipeline (in) Lenght pipeline for temperature drop to 36X (km) Insulation thermal conductivity (W/mK) T outlet eC In Out In Out 15 14,25 100 50 15 92 1 44 0,16 36,0 15 14,25 100 50 15 92 2 81 0,16 36,6

The table 1 shows that, e.g., if 15% of the hot well stream (100°C) mass flow exchanges heat with the condensate line, the initial condensate export temperature will be 92°C instead of 15°C. So, the condensate pipeline operates 20 above WAT condition for a substantial length of the export pipeline. This is perfectly achievable as the condensate mass flow is around 10% of the total gas mass flow.

If the calculated heat loss of the transported hydrocarbons is great enough to 25 bring the temperature below the WAT, it is possible to equip the last portion of the transportation line with DEH in order to keep the temperature high enough throughout the transportation distance. The need for DEH will, however, be substantially less than without embodiments of the present invention.

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From the foregoing description and also from the appended claims it would be clear to persons skilled in the art, that all the objectives of the present invention are achieved. Embodiments of the present invention may be applicable in respect of all types of transportation of flowable hydrocarbons along network of 5 pipelines as clarified before.

The present invention has been described with reference to preferred embodiments and drawings for the sake of understanding only and it should be clear to persons skilled in the art that the present invention includes all 10 legitimate modifications within the ambit of what has been described hereinbefore and claimed in the appended claims.

Figure 5 shows a further alternative embodiment of the present invention, where the hot gas is used for heating the liquid. The figure shows, the well flow 15 4 entering a first separator 1a without first being led through an inlet cooler. The well flow is separated into a predominantly liquid phase 3a and predominantly gas phase 5. However, the gas phase 5 does have a fair amount of residual liquid. The gas is led through an inlet cooler 2 before entering a second separator 1b, where the remaining liquid is removed from the gas and exited 20 through a liquid line 3c. The predominantly dry gas is led through a gas line 5c to a compressor 6.

Before the gas 5 with residual liquid enters the inlet cooler 2, some of the gas is branched off to a line 5a and led through a heat exchanger 3, where heat from 25 the gas is transferred to the liquid 3c exiting from the separator 2. The thus heated liquid is led to the liquid line 3a through a line 3b, while the now cooled gas 5b is led to the inlet of the separator 1 b.

Figure 6 shows a yet further embodiment of the invention where the hot well 30 stream is used to heat seawater, which in turn is used to heat the liquid condensate. The well flow 4 is led through an inlet cooler 2 and then to a separator 1, where it is separated into a gas phase 5 and a liquid phase 3a.

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Seawater 7 is drawn into the inlet cooler 2 and receives heat from the hot well flow 4. The hot seawater 7a is transferred to a storage tank 8. From this tank hot seawater is drawn through a line 7b to a heat exchanger 3 and used to heat the liquid phase 3a. The now cooled seawater 7c that exits the heat exchanger 5 3 may be transported to shore or expelled to the surrounding waters, depending on the environmental regulations. The heater liquid 3b is transported to shore.

This embodiment is suitable for situations were the heating requirements are varying. Since hot seawater is stored in the tank 8, more water can be drawn 10 from the tank when the liquid production from the separator 1 is high. When the liquid production is low, i.e. more gas is produced; seawater will be accumulated in the tank 8.

In this case a heat exchanger may be used as described in the applicant’s 15 Norwegian patent application NO 2011 0946, which is hereby incorporated by reference. The coolers described in Norwegian patents 173890 and 321304 or in Norwegian patent application 20091914 may also be used. These are also incorporated herein by reference. 20 Other combinations of the embodiments described and variations of the embodiments are also possible, within the common knowledge of the person of skill.

In the claims which follow and in the preceding description of the invention, 25 except where the context requires otherwise due to express language or necessary implication, the word “comprise” or variations such as “comprises” or “comprising” is used in an inclusive sense, i.e. to specify the presence of the stated features but not to preclude the presence or addition of further features in various embodiments of the invention. 30

It is to be understood that, if any prior art publication is referred to herein, such reference does not constitute an admission that the publication forms a part of the common general knowledge in the art, in Australia or any other country.

9100650 1 (GH Matters) P98729.AU

Claims

THE CLAIMS DEFINING THE INVENTION ARE AS FOLLOWS: 1. Method for flow assurance of flowable hydrocarbons along a pipeline, comprising letting a stream of hot flowable hydrocarbons flow through a separator for separation thereof into a gas phase and a liquid phase, wherein heat from the hot flowable hydrocarbons is extracted before the hot flowable hydrocarbons enters the separator and transferred to the liquid phase exiting the separator.
2. Method according to claim 1, wherein the stream of hot flowable hydrocarbons is fed through an inlet cooler prior to entering said separator.
3. Method according to claim 2, wherein at least a part of the stream of hot flowable hydrocarbons is branched off prior to entering the inlet cooler and is led to at least one heat exchanger to heat the liquid exiting the separator.
4. The method according to claim 3, wherein the flowable hydrocarbons exiting said heat exchanger is recycled back to the stream of hot flowable hydrocarbons upstream of the separator, either upstream or downstream said inlet cooler.
5. The method of claim 1, wherein at least a part of the gas phase from the separator is led to a heat exchanger to heat the liquid phase from the separator.
6. The method of claim 5, wherein the gas phase is compressed, whereby the gas phase is heated by the compression, and at least a part of the compressed gas phase is led to the heat exchanger to heat the liquid phase from the separator.
7. The method of claim 5 or 6, wherein the gas phase exiting the heat exchanger is recycled back to the stream of hot flowable hydrocarbons upstream of the separator or recycled back to the gas phase upstream or downstream of the compression stage.
8. The method of claim 1, wherein a coolant is led through a heat exchanger to be heated by the stream of hot flowable hydrocarbons and the heated coolant is used for heating the liquid phase from the separator.
9. The method of claim 8, wherein the heated coolant is stored in a tank prior to being used to heat the liquid phase from the separator.
10. The method of claim 8 or 9, wherein the coolant is seawater, which is drawn from a surrounding sea and expelled to the sea after use.
11. The method according to any one of the claims 1 to 10, wherein said liquid phase from the separator is a fluid condensate such as oil and/or natural gas or oil-water.
12. An apparatus for flow assurance of flowable hydrocarbons, comprising: at least one insulated pipeline; a separator for separating hot flowable hydrocarbons into a gas phase and a liquid phase,; and at least one heat exchanger located downstream said separator for receiving inflow of the liquid phase and adapted to receive hot flowable hydrocarbons or hot seawater for transferring heat to increase the temperature of said liquid phase to a desired level by heat exchange.
13. The apparatus according to claim 12, wherein said heat exchanger is integral with said separator.
14. The apparatus according to any one of claims 12 or 13, wherein said heat exchanger is a counter current heat exchanger.
15. The apparatus according to any one of claims 12 or 13, wherein said heat exchanger is a co-current heat exchanger.
16. The apparatus according to any one of claims 12 to 13, wherein said heat exchanging in heat exchanger is via forced convection.
17. The apparatus according to any one of claims 12 to 13, wherein said heat exchanging in heat exchanger is via natural convection.