AU2013274973B2

AU2013274973B2 - Heat exchange from compressed gas

Info

Publication number: AU2013274973B2
Application number: AU2013274973A
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: 2016-11-10
Anticipated expiration: 2033-06-12
Also published as: WO2013187773A1; BR112014030960A2; AU2013274973A1; NO335390B1; NO20120695A1

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 a flow of hot compressed gas (6a), 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 2013274973 22 Sep 2016

FIELD OF THE INVENTION

The present invention in general, relates to a method and apparatus for flow assurance of flowable hydrocarbons along a pipeline, comprising passing a well stream of flowable hydrocarbons through a separator for separation thereof into 5 a gas phase and a liquid phase.

More specifically, the present invention relates to a method and apparatus for flow assurance ensuring flowable hydrocarbons along insulated pipelines, such that precipitation of undesirable substances during fluid hydrocarbon 10 transportation, such as wax deposition and hydrate formation, are prevented.

TECHNICAL BACKGROUND OF THE INVENTION

In onshore, offshore subsea operations such as for hydrocarbon exploration 15 and production, application of insulated pipelines for fluid transport is common.

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 20 pipelines for flow assurance over long distances to avoid temperature drop 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. 25

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 immense hindrance in the flow of fluid hydrocarbon and may lead to reduced 30 flow rates and even clogging of the flowline.

The precipitates as referred to in the preceding paragraph may be wax, hydrates, asphaltenes, resins, napthalenes, aliphatic hydrates and so on, as 8226763J (GHMatters) P98723.AU 2 2013274973 22 Sep 2016 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. 5 A multiphase well stream may have a temperature as high as 70° C to 100° 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 10 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 15 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 20 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 25 potential threats to the environment, and equipment for separation and neutralization of chemicals are necessary to achieve the goal of “zero emission”.

Direct Electric Heating (DEH) to warm up the pipelines for preventing precipitate 30 formation is also an alternative. However, this method is grossly expensive, having regard to the length of pipelines applied.

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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 5 deposits/precipitates as stated in the preceding paragraph, especially when the 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 10 been made to relocate the inlet cooler to cool down the gas line only, but in that 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. 15 Granted US patent 7261810B2 teaches to solve this problem by cooling the hot 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 20 does not sufficiently prevent precipitate formation over substantially long 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 25 crystals for its addition to the hot fluid hydrocarbon and the basic principle is 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 precipitation of similar substances from the hot fluid. Hence, the method is 30 cumbersome as well and can not be entirely relied upon.

Addition of chemicals for delaying or preventing formation of precipitates is another technique but this apart from being costly, has been not found to be 8226763_1 (GHMatters) P98723.AU 4 2013274973 22 Sep 2016 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. 5 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, may be substantially minimized or eliminated.

10 SUMMARY OF THE INVENTION

It is the principal 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 and cost effective manner by 15 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 disadvantages of prior art are substantially minimized or eliminated. 20 Embodiments of the present invention may also provide a method and apparatus for flow assurance of flowable hydrocarbons along an insulated pipeline, having the advantage that formation of undesirable precipitates during transportation over substantially long distances may be prevented. 25 Embodiments of the present invention may also provide a method and apparatus for flow assurance of flowable hydrocarbons along an insulated pipeline, which advantageously is simple and does not involve complicated steps or components. 30 In at least one embodiment, the present invention may also provide a method and apparatus for flow assurance of flowable hydrocarbons along insulated pipelines by effecting heat exchange between compressed gas and flowable hydrocarbons to be transported, so that advantageously the temperature of the

8226763J (GHMatters) P98723.AU 5 2013274973 22 Sep 2016 flowable hydrocarbons to be transported may be increased to a desired level for preventing formation of undesirable precipitates.

The general principle of at least some embodiments of the present invention is 5 to use heat generated by equipment in the plant, such as compressors, to prevent formation of hydrates, precipitation of wax and precipitation of other components, by transferring this heat from the heat generating component to the fluids by indirect heat exchange and thereby using this heat to keep the temperature sufficiently high. 10

More specifically, embodiments of the invention may relate to flow assurance by utilization of heat generated by equipment, such as by compressing gas, in a subsea processing system, and heat exchange of mentioned heat with liquid pipelines downstream the process separator. Flow assurance may be achieved 15 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 temperatures. 20 To keep the temperature above problematic level in long transport lines along the seabed with its low temperature, it may be necessary to insulate the 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 25 assurance alone the whole length of long lines, or during some modes of 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. 30 How the foregoing advantageous features may be achieved, still not disclosed in prior art, will be clear from the following non-limiting description.

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All through the specification, including the claims, the words “pipeline”, “flowable hydrocarbons”, “cold fluid”, “separator”, “inlet cooler”, “heat exchanger”, “onshore”, “offshore”, “hot well stream", and ’’hot flowable hydrocarbons” are to be interpreted in the broadest sense of the respective terms and includes all 5 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.

According to a first aspect of the present invention there is provided a method 10 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, and compressing the gas phase exiting the separator, wherein heat from the compressed gas is extracted and transferred to the liquid phase exiting the separator. 15

The pipeline is preferably an insulated pipeline. According to an embodiment, the method comprises 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 20 gaseous phase and a liquid phase. In order to facilitate the gas-liquid separation, the well stream may be cooled by an inlet cooler located upstream the separator.

According to an embodiment of the method of the present invention, the liquid 25 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 compressed gas. 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 30 transportation.

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Preferably, the gas exiting from the heat exchanger is recycled back to the well stream line upstream of the separator or more preferably to the gas line upstream or downstream the compressor. 5 According to a second aspect of the present invention there is also provided an apparatus for flow assurance of flowable hydrocarbons, comprising at least one pipeline, a separator for separating hot flowable hydrocarbons into a gas phase and a liquid phase, at least one heat exchanger located downstream said separator for receiving inflow of the liquid phase and adapted to receive hot 10 flowable hydrocarbons or hot seawater, for transferring heat to increase the temperature of said liquid phase to a desired level by heat exchange.

Also disclosed is an apparatus for carrying out the method according to the first aspect. 15

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 20 following with reference to the drawings, in which:

Figure 1 illustrate an embodiment of the present invention where heat generated by a compressor is utilized. 25 Figures 2 and 3 illustrate line drawings of two 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 the present invention.

30 DETAILED DESCRIPTION OF THE INVENTION

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

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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 field, as known to persons skilled in the art. Further, hereinbefore and 5 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 be at an elevated pressure. 10 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”.

Now referring to the accompanying figure 1, a preferred embodiment of the 15 invention will be explained in detail. It illustrate a well stream 4 that is led through an inlet cooler 2 and 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 exists the compressor 6 through a compressed gas line 6’. The liquid exists the separator 1 through a liquid line 3a and is further through a heat exchanger 3. 20 After the heat exchanger the liquid enters a liquid transport line 3b.

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. 25 The inlet cooler 2 is preferably applied to bring down the temperature of hot well 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 30 cold liquid 3a. The liquid may be gas condensate, oil and/or water. The liquid may also contain small proportions of gas. This cold liquid is to be transported along the export pipelines.

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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, along a pipeline. 5 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.

The heat exchanger 3 may be configured so as to be co-current or counter 10 current and this is not consequential to the present invention. The dry gas 6’ that is not branched off to the heat exchanger 3, may be transported separately.

The heat exchanger 3 is preferably having a constant feed of hot gas. So, when the cold fluid enters the heat exchanger 3, it finds the hot gas there. 15 Consequently, heat exchange takes place between the hot gas and the cold fluid. Alternatively the line 6a may have a valve (not shown) that can be adjusted to provide the exchanger 3 with a flow of hot gas adapted to the heating requirements to bring the temperature of the liquid from the separator 1 to the optimal level. 20

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 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. 25

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 exemplified hereinafter, which prevents formation of wax or hydrate or other precipitates. This liquid 3b is now transported to the main pipeline for onward 30 transportation (not shown in detail).

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The gas which leaves the heat exchanger 3 along the line 6b has a lower temperature, as compared to the hot gas 6’. The temperature may be comparable to the well stream which enters the separator 1 along line 4’. 5 The gas which leaves the heat exchanger 3 along line 6b may be re-circulated back to the compressor 5 or to the gas line 6’ downstream of the branch line 6a. Alternatively, it may be circulated back to the separator 1 by connecting the line 6b to line 4’ downstream of the inlet cooler 2. Further alternatively, this gas flowing through line 6b may be mixed with the hot well stream 4 at line 4a’. This 10 depends on the return temperature desired or other process strategies.

Embodiments of the present invention thus propose system configurations to allow heat transfer between the hot gas and the cold liquid, preferably condensate or oil-water stream. 15

The heat transfer takes place in a heat exchanger 3 where the compressed gas is the hot fluid and flows into the heat exchanger 3 along the line 6a. The cold liquid 3a also flows into the heat exchanger 3. The gas flows out of the heat exchanger along line 6b, with lower temperature than its inlet temperature and 20 the liquid 3b flows out with higher temperature than its inlet temperature.

Pressure drop is ensured for the circulation of the gas along line 6b. An existing pressure drop may be used, as injecting the gas line 6b downstream the inlet cooler 2. If that is not enough, an additional pressure drop is created in the 25 system by means known per se to the person of skill.

Thus, embodiments of the present invention combined with standard pipeline insulation makes it possible to export gas and/or condensate through long pipelines with sufficient operating temperature to avoid formation of unwanted 30 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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Embodiments of the present invention may achieve 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 stream. 5

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 than 100 km length. The seawater temperature considered to calculate the heat 10 loss on the pipeline is 5°C.

Table 1: Condensate pipeline length at above WAT

Gas stream % mass flow Duty (MW) Gas Temp. C'C) Condensate Temp. CC) Insulation Thickness Condensate Pipeline (in) Lenghl pipeline for temperature drop to 36°C {km) insulation thermal conductivity {W/mKj Toutlet *C 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 SI 0,16 36,3 15

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 above WAT condition for a substantial length of the export pipeline. This is 20 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 bring the temperature below the WAT, it is possible to equip the last portion of 25 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 utilizing embodiments of the present invention.

Embodiments of the present invention may be applicable in respect of all types 30 of transportation of flowable hydrocarbons along network of pipelines as clarified before.

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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 5 legitimate modifications within the ambit of what has been described hereinbefore and claimed in the appended claims.

An alternative embodiment of the invention is to use seawater to transfer the heat from the hot gas to the liquid condensate. A heat exchanger against 10 seawater is inserted in the line 6’ and the seawater is thereafter used to heat the liquid flowing through the heat exchanger 3. A storage tank for hot seawater may be situated in the seawater line between the heat exchanger with the hot gas and the heat exchanger with the cold liquid. From this tank hot seawater can be drawn to the heat exchanger 3 and used to heat the liquid phase 3a. 15 The now cooled seawater that exits the heat exchanger 3 may be transported to shore or expelled to the surrounding waters, depending on the environmental regulations.

This embodiment is especially suitable for situations where the heating 20 requirements are varying. If hot seawater is stored in the tank, more water can be drawn from the tank when the liquid production from the separator is high. When the liquid production is low, i.e. more gas is produced; seawater will be accumulated in the tank. 25 In this case a heat exchanger may be used as described in the applicant’s 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. 30

Other combinations of the embodiments described and variations of the embodiments are also possible, within the common knowledge of the person of skill.

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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. 5

In the claims which follow and in the preceding description of the invention, 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 10 stated features but not to preclude the presence or addition of further features in various embodiments of the invention.

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Claims

Patent claims 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, and compressing the gas phase exiting the separator, wherein heat from the compressed gas is extracted and transferred to the liquid phase exiting the separator.
2. Method according to claim 1, wherein the hot well stream of flowable hydrocarbons is fed through an inlet cooler prior to entering said separator.
3. The method of claim 1, wherein at least a part of the gas phase from the separator is led to the heat a exchanger to heat the liquid phase exiting the separator.
4. The method of claim 3, wherein the gas exiting the heat exchanger is recycled back to a well stream upstream of the separator or the gas phase upstream or downstream of the compression stage.
5. The method of claim 1, wherein a coolant is led through a heat exchanger to be heated by the compressed gas and the heated coolant is used for heating the liquid phase from the separator.
6. The method of claim 5, wherein the heated coolant is stored in a tank prior to being used to heat the liquid.
7. The method of claim 5 or 6, wherein the coolant is seawater, which is drawn from the surrounding sea and expelled to the sea after use.
8. The method according to any of the claims 1 to 7, wherein the liquid phase is a fluid condensate.
9. The method according to claim 8, wherein the fluid condensate is oil and/or natural gas or oil water.
10. An apparatus for flow assurance of flowable hydrocarbons, comprising at least one pipeline, a separator for separating hot flowable hydrocarbons into a gas phase and a liquid phase, 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.
11. The apparatus according to claim 10, wherein said heat exchanger is integral with said separator.
12. The apparatus according to claim 10 or 11, wherein said heat exchanger is a counter current heat exchanger.
13. The apparatus according to claim 10 or 11, wherein said heat exchanger is a co-current heat exchanger.
14. The apparatus according to any one of claims 10 to 13, wherein said heat exchanging in heat exchanger is via forced convection.
15. The apparatus according to any one of claims 10 to 13, wherein said heat exchanging in heat exchanger is via natural convection.