NO20121114A1 - Treatment of produced hydrocarbon fluid containing water - Google Patents

Abstract

There is disclosed a method of treating a stream of hydrocarbon fluids containing water, wherein the stream of hydrocarbon fluids is introduced into a first separator which at least separates free water from said stream of hydrocarbon fluids, where a residue of said hydrocarbon fluid stream is introduced into a system that converts freely. condensed water in the hydrocarbon fluid stream of said gas hydrate system, providing at least a first fluid stream and a second fluid stream, said first fluid stream being a liquid phase comprising gas hydrates, and said first fluid stream being recirculated to the first separator, and wherein the second fluid stream has a dry gas and / or condensate / oil content. The invention also provides a system for treating a stream of fluid hydrocarbon fluids containing water, said system including the following elements listed in the flow direction and connected to each other: connection to a hydrocarbon production source (1), a first separator (3) which acts to at least separate free water from said fluid stream, a conversion system (5) for converting free / condensed water to gas hydrate, a pipeline (6, 18) for transport of dry gas or condensate / oil; and in addition, a conduit (7) leading from the conversion system (5) to the first separator (3) thus providing a first recycle stream comprising gas hydrates.

Description

INTRODUCTION

The invention relates to a system for treating a stream of hydrocarbon fluids containing water and a method for such treatment.

BACKGROUND

Some of the world's largest gas fields have been found in deep water offshore (for example Ormen Lange) or in remote areas in the Arctic (for example Snøhvit and Shtockman). The usual way to transport such unprocessed well fluids in a pipeline to a terminal on land is currently to add monoethylene glycol (MEG) at the wellheads. A large infrastructure and costs are required to be able to inject and regenerate MEG.

For very long pipelines (eg Shtockman), processing and drying (water) of the gas phase may be necessary prior to transport in an underwater pipeline, for example on a platform or a ship. A complete gas drying, for example with a triethylene glycol (TEG) process, will here require significant space and weight.

A common way to solve water problems, and to minimize hydrate problems in industry, is to use glycol injection/adsorption and regeneration in a closed glycol system. Although in widespread use, such systems will be plagued by a number of recurring problems - largely due to poor efficiency in the first stage separator for a well fluid. Glycol processes will therefore depend on such a separation to be able to remove liquid hydrocarbons and water, solids, corrosion inhibitors, etc. That task is formidable and results in high cost equipment and high operating costs.

Although today there is a lot of focus on gas fields and avoiding their water problems, many of the same problems also appear in liquid-rich oil/condensate systems, where even small fractions of water in the overall system can lead to significant problems or power blockages over time. Water and its solidification are thus a general problem for modern production systems for oil and gas.

US 6,774,276 is used as a possible way to be able to precipitate hydrate particles from the water in the system. In US 6,774,276, water is made transportable in the pipeline with the hydrocarbon fluid to land or to a central platform by converting water from the well fluids to hydrate.

SUMMARY OF THE INVENTION

The present invention provides a method and system for treating a production stream of gas, hydrocarbon liquid and water from a hydrocarbon producing field in a single system and enables further processing and/or transport of the desired products through a transport system, which includes one or more pipelines.

In a first aspect, the invention provides a method for treating a stream of fluid hydrocarbons containing water, where the stream of fluid hydrocarbons is introduced into a first separator and separates at least free water from said stream of fluid hydrocarbons, where a residue of said fluid hydrocarbon stream is introduced into a system which converts free/condensed water in the fluid hydrocarbon stream in said system into gas hydrates, and which provides at least a first fluid stream and a second fluid stream, where said first fluid stream will be a liquid phase comprising gas hydrates, said first fluid stream is recycled into the first separator, and where the second fluid stream has a content of dry gas and/or condensate/oil.

The fluid flow could be a production flow from at least one wellbore. The stream of hydrocarbon fluids could alternatively be a production stream from a gas field, and in which separation in the first separator comprises separating free water and liquid condensate from said production stream and introducing a gas phase into the converting system. The first fluid flow may contain gas hydrate particles and condensate/oil.

In one embodiment, the first separator will be able to have a temperature that is higher than a hydrate equilibrium temperature for the fluid stream. The gas hydrates will be able to be melted in said first recycled fluid flow, into free water and/or into free gas/condensate/oil in the first separator. Heat can be added to the first separator if the temperature in the stream of hydrocarbon fluids is too low. The recycled first fluid stream will also be able to be used as a countercurrent flow that cools the remaining hydrocarbon fluid stream from the first separator before the remaining hydrocarbon stream enters the reactor.

An aqueous phase of excess water can be separated from said first separator, in which said excess water is reinjected into a reservoir, or is depressurized, cleaned of hydrocarbons and released to the environment, or it can be used for any other suitable purpose . Condensate/oil will also be able to be separated from said first separator, in which said condensate/oil will be stored in the field, transported in a ship or a separate pipeline or mixed with a fluid stream containing condensate/oil from said conversion system. For a liquid-dominated system, the dry gas and/or the dewatered oil/condensate will be able to be separated from said first separator, in which said dry gas and/or dewatered oil/condensate will be further processed or supplied to a pipeline for transport.

Salt will be able to be added to said remaining hydrocarbon fluid stream and reduce a partial water vapor pressure (dew point for water) above hydrate as well as control the growth of said hydrates. The added salt could be one of formation water from the first separator, seawater or direct salt injection. A dew point for water in said second fluid stream will be able to be reduced by using at least one molecular sieve.

In one embodiment, the conversion system will involve mixing the remaining hydrocarbon fluid stream in a reactor with particles of gas hydrates that will also be introduced to said reactor, where the outlet stream of hydrocarbons from the reactor will be cooled in a heat exchanger to ensure that all the water therein, which can be converted to hydrates, is in the form of gas hydrates. Said stream will then be processed in a second separator to split into the first stream and the second stream, and further separate a third stream from said first stream, wherein said third stream will be recycled to the reactor to provide particles of gas hydrates, and wherein the remaining portion of the first stream will be recycled into the first separator. The liquid fluid phase in the conversion system could arise from condensed liquid hydrocarbons from said stream of hydrocarbon fluids or any other suitable fluid.

A first concentration of gas hydrate in said first stream and a second concentration of gas hydrates in said third stream can be regulated. Furthermore, the first stream may comprise a first concentration of gas hydrates and the third stream may comprise a second concentration of gas hydrates, wherein said first concentration is less than the second concentration. The second concentration of said gas hydrates will preferably be greater than 0.5% by volume.

A concentration of salt in said remaining hydrocarbon stream of said third recycled fluid stream will be able to be increased and thus provide a reduction of partial water vapor pressure (dew point of water) over hydrate in said hydrocarbon stream and regulate the growth of said hydrates. The temperature in said second separator can be kept close to or slightly above a minimum temperature in an export pipeline for said dry gas and/or condensate/oil.

In another aspect, the invention will provide a system for treating a stream of fluid hydrocarbon fluid containing water. Said system includes the following elements, listed in the flow direction and interconnected: connection to a hydrocarbon production source, a first separator operative to separate at least free water from said fluid stream, a conversion system for converting free/condensed water from gas hydrate, a pipeline to transport a dry gas and condensate/oil; and in addition a conduit extending from the conversion system to the first separator and providing a first recycle stream comprising gas hydrates.

A pressure control valve or choke valve may be provided between the hydrocarbon source and the first separator, which will provide a lowering of the pressure and temperature of the fluid stream before it enters the separator.

The first separator can be equipped with an outlet for an excess of aqueous phase. The first separator can be provided with an outlet for a hydrocarbon liquid of condensate/oil, in which said liquid condensate/oil can then be stored, transported, or mixed with the dry gas fluid stream in the pipeline.

A first cooler to cool the fluid stream before it enters the conversion system may be provided. The first recycling flow can be a countercurrent flow in said first cooler.

Furthermore, an addition device for adding various chemicals to the hydrocarbon stream could be provided. A second addition device for adding salt to the fluid stream to reduce a partial water vapor pressure (dew point of water) above hydrate, and to control hydrate particle size and morphology would also be provided. The salt could be one of formation water from the first separator, sufficiently clean seawater or supplied from direct salt injection. At the very least, a molecular sieve could be provided in the fluid flow line leading from the conversion system to reduce the dew point of the water.

In one embodiment, the conversion system may comprise a reactor, a cooler and a second separator which provides the first recycle stream in the conduit leading from the conversion system to the first separator. The conversion system can further comprise a third separator in said line which separates said first recycling stream into a second recycling stream, which leads back to the reactor, and a remaining part of the first recycling stream which goes to the first separator. The conversion system can be equipped with a pump device in said line between the second separator and the third separator. The conversion system may be provided with at least one pump or compressor. The system can be placed underwater (subsea), on a platform or on land. The first separator, the second separator and the third separator and the pump can be placed on a platform or a ship. The reactor and cooler can be an uninsulated pipeline on a seabed. The liquid fluid phase in the conversion system may originate from condensed liquid hydrocarbons from the fluid stream or any other fluid suitable for the process in the conversion system. The hydrocarbon production source can be a gas field or condensate/oil field, and where at least one satellite well is directly connected to the conversion system.

A more compact and economical process for condensate and water withdrawal from a gas stream in the wellhead, or removal of water from an oil stream, can be achieved by placing the present invention at/near the wellhead/production platform/vessel or underwater. Hot wellhead fluid (gas/condensate/oil/water) is sent into a first separator where free water or condensate/oil and free water are separated from the fluid stream. In contrast to a traditional first separator, for example used in a TEG process for a gas field, this separator will also contain an inlet for fluid flow of condensate/oil and gas hydrates. The temperature in the separator will be above the hydrate equilibrium temperature and thus ensure melting of all incoming hydrates. The hydrate-containing fluid will be obtained by drying the gas or the gas/condensate/oil stream from a given first separator with a system as, for example, described in US 6,774,276 as mentioned above. While US 6,774,276 intends to make water transportable, the present invention will preferably remove water from the production stream. Dry gas from the present invention will preferably be exported to a pipeline. Excess condensate/oil will be drained from the separator and exported in a pipeline or degassed before storage. Liquid water from the given separator is re-injected into a field or heated/degassed and cleaned before being released into the sea. Alternatively, for a liquid-dominated system, the dry gas and the dewatered oil or condensate could continue for further processing, or for pipeline transport.

The present invention can be performed at or near a wellhead pressure, which can eliminate the need for export compressors in the field. The need for chemicals (eg MEG) for the export pipeline can be eliminated or reduced to, for example, handle corrosion.

In many cases it will be beneficial to add different chemicals to the hydrocarbon stream. The system will therefore contain a device for adding such chemicals to the flow.

In the present invention, the system (5) can be any system suitable for the purpose, but can preferably use US 6,774,276 as an integral part. Alternatively, other systems for converting free water/condensed water into gas hydrates can be used, as for example described in US patent application 2002/0120172, US patent no. 5,460,728 (or one of the many similar patent applications), WO 2007/095399, WO 2008/056250, or using throttling to cool the stream and precipitate hydrates, or any other suitable means to obtain a stream of slurry loaded with hydrate particles.

A further new inventive aspect compared to US 6,774,276 is introduced by the present invention through the effects of the dew point of the water, which may take place in the event of the presence of salt in the aqueous phase. In addition to lowering the water's dew point (and thus regulating hydrate formation), other beneficial effects of salt-containing water can contribute as a novelty to this invention. As described in Provisional Patent Application US 61/312,790, the presence of salt, or the addition of salt (or other thermodynamic hydrate-inhibiting compound, such as methanol or glycol) will assist in regulating the hydrate formation process by keeping local conditions close to thermodynamic equilibrium. Salt alone will also help to regulate and limit the size of hydrate particles and helps to avoid trapped, unreacted water that would otherwise have given rise to a deposition and agglomeration risk.

Compared to the prior art in glycol injection/adsorption and regeneration systems, the present invention will greatly simplify the problem by allowing a simpler design for the first stage separator, as the downstream system here is much less sensitive to the content of the production stream. The first-stage separator will here only need to remove the main part of free, condensed water and act as a heat container for generated gas hydrates, without any need for pre-cooling to promote condensation.

In the present invention, water condensation is promoted on top of gas hydrates in later stages of the process, with much higher water removal efficiency than most first-stage separators. In saltwater systems, the present invention will also achieve an additional amount of protection by lowering the dew point of the water well below operating temperatures, as water is promoted in the presence of saline solutions. This simplification also means that the present invention will be an energetically favorable technology compared to glycol systems, both for onshore and offshore applications.

The ability to allow the production stream to flow under high pressure throughout the system of the present invention also means that energy will be saved compared to the sometimes large recompression requirements of traditional technology. In addition, weight savings on offshore facilities (through, for example, the removal of a glycol regeneration system) will be important, and can be made possible with the present invention.

BRIEF DESCRIPTION OF DRAWINGS

Exemplary embodiments of the invention will now be described with reference to the following drawings, where: Figure 1 is a schematic illustration of a treatment and transport system for produced hydrocarbons containing water according to an embodiment of the invention. Figure 2 is a schematic illustration of a further embodiment of the invention, and Figure 3 is a schematic illustration of an even further embodiment of the invention. Figure 4 is a schematic illustration of salt effects on hydrate formation in a system according to the present invention.

DETAILED DESCRIPTION

The same reference numbers are used for similar or corresponding features in all the drawings.

Reference will now be made to Figure 1. A production fluid stream of hydrocarbons and water (1) is introduced into a first separator (3) together with a fluid stream (7) containing gas hydrate and condensate/oil. In separator (3), the temperature will be sufficiently high (20 °C or higher) to be able to melt all incoming hydrates into free water. In separator (3), most of the free water (more than 99%) will be separated from the production stream (1). At the same time, hydrates in the fluid flow (7) will be melted into free water and gas/condensate/oil in separator (3). The remainder of the production stream (1) and the fluid stream (7), which is gas/condensate/oil, will be taken out (4) by the separator (3) and introduced into a system (5). Condensate/oil will also be able to be taken out (8) from separator (3) and stored in the field, transported in a ship or a separate pipeline, or mixed with a fluid

stream (18) containing condensate/oil from system (5). Separator (3) could be any type of separator.

In system (5), which will be any system suitable for the purpose, the fluid flow (4) will be cooled down to convert all free or condensed water from fluid flow (4) into gas hydrates. The resulting fluid stream in system (5) will then, after treatment, be split into a mainly dry gas (6) (with a water dew point that is under ambient conditions), a condensate/oil phase (18)

(condensate/oil field), and liquid mud phase (7) consisting of hydrocarbon liquid and gas hydrates. Fluid flows (6) and (18) will be able to be combined into a single fluid flow.

Said stream (1) of hydrocarbon fluids (gas/condensate/oil) will normally come from one or more borehole wells and will be relatively hot and will be under pressure. It can sometimes be advantageous to achieve a lower pressure and temperature in fluid flow (1) by sending the fluid flow through a throttle (2) before the fluid flow is fed into separator (3). Throat (2) could be any type of throat.

Stream (9) which is separated from the first separator (3), consisting mainly of water from production stream (1) and from molten hydrates in the liquid sludge phase (7), will be able to be reinjected into a reservoir, it will be able to be depressurized, cleaned of hydrocarbons and released to the environment, or it could be used for any other suitable purpose.

In some embodiments, salt water can advantageously be added to a system (5) to improve the water's dew point reduction in the dry gas (6) separated from system (5). The effect of salt water will be explained in detail later.

With reference to Figure 2, a production stream (1) from a gas field will, in this embodiment, enter a first separator (3). The first separator has a temperature that is above the hydrate equilibrium temperature of the fluid stream. A second fluid stream (7), containing gas hydrate particles and condensate will also be introduced into separator (3). In the first separator (3), liquid condensate and free water will be separated from the production stream (1). At the same time, hydrates in the second fluid stream (7) will be melted into free water and gas in the first separate

clean (3). The remainder of the production stream, which is a gas phase, will be taken out (4) and fed into system (5). In system (5), all free water in gas phase stream (4) or condensed water in system (5) will be converted to gas hydrate before being returned to separator (3) as the second fluid stream (7). Any condensate in the gas phase flow (4) or condensate that is condensed in system (5) will also be returned to the separator (3) with the other fluid flow (7). Condensate in separator (3) will be withdrawn (8) and stored in the field, transported in ships or a separated pipeline, or mixed with a fluid stream (6) containing dry gas from system (5). Water in separator (3) will be withdrawn through an outlet (9) and either processed or reinjected into a reservoir.

In system (5), which can be any system suitable for the purpose, gas phase fluid flow (4) will be cooled in order to convert all free or condensed water from gas phase fluid flow (4) into a gas hydrate. Vapors of hydrocarbons in (4) can also be condensed into liquid in this process. The resulting fluid flow in system (5) will then, after treatment, be separated in system (5) into a mainly dry gas (6) (with a dew point for water that is under ambient conditions), and a liquid sludge phase (7) consisting of hydrocarbon liquid and gas hydrates. On average, equal amounts (apart from the remaining steam in (6)) of water (in the form of hydrates and water) and condensate added to system (5) in fluid stream (4) will be returned from system (5) to separator (3) ) of the second fluid flow (7) (liquid sludge phase). In separator (3), the hydrates will be melted into liquid water and free gas by the temperature level.

The production stream (1) will generally come from one or more borehole wells, and will be relatively hot and will be under pressure. It would be advantageous to be able to achieve a lower pressure and at the same time cool down the production flow somewhat, by allowing it to flow through an expansion valve (2) before it is fed into the separator (3).

Stream (9) that is separated from the first separator (3), which consists mainly of water from production stream (1) and from molten hydrates in the liquid sludge phase (7), will be able to be reinjected into a reservoir, it will be able to be depressurized , cleaned of hydrocarbons and released to the environment, or it will be able to be used for any other suitable purpose.

In some embodiments, salt water can advantageously be added to system (5) to improve the reduction of the water dew point in the dry gas (6) separated from system (5). The effect of salt water will be explained later.

Reference will now be made to Figure 3. In this embodiment, a fluid stream of hydrocarbons and water (1) will be introduced into a first separator (3) together with a fluid stream (7) containing gas hydrate and condensate. In separator (3), the temperature will be sufficiently high to melt all incoming hydrates into free water. If the temperature from fluid flow (1) is too low for this purpose, heat can be supplied to separator (3) by any given device. Separator (3) could be any type of separator.

Said stream (1) of hydrocarbon fluids will normally come from one or more borehole wells, and will be relatively hot and will be under pressure. It can sometimes be advantageous to achieve a lower pressure and temperature in fluid flow (1) by sending the fluid flow through a throttle (2) before the fluid flow is fed into separator (3). Throat (2) could be any type of throat. The gas phase (4), from separator (3), will normally contain steam of hydrocarbons and water vapour. The gas phase (4) is fed into system (5), which in the embodiment in Figure 3 is illustrated using a reactor system with return loop (10, 11, 12,13, 14, 16) as described in US 6,774,276, and which is hereby incorporated by reference in its entirety. In Figure 3, gas phase fluid flow (4) is fed into reactor (10), where it is mixed with cold (temperature below the gas hydrate's melting temperature) fluid (16) from separator (15). Said cold fluid (16) from the separator (15) contains particles of dry hydrate.

Water vapor and heavier hydrocarbon components that are present in the gas phase (4) will condense during cooling in the reactor (10). As described in US 6,774,276, this water will wet hydrate (16) from the separator (15) in the reactor (10) and in the cooler (11). In the reactor (10) and the cooler (11), the water that moistens the hydrate will be converted to hydrate. New hydrate that is formed will similarly grow on the hydrate particles from the separator (15) and will also form new hydrate particles when large hydrate particles break up. New hydrate nuclei will also be able to form elsewhere in the reactor (10) and the cooler (11).

Fluid flow (4) will be able to be mixed with sludge of liquid and gas hydrate particles

clay (16) in various ways in reactor (10), which will include bubbling through a liquid slurry column, or by any other suitable mechanical or other mixing device.

Subcooling (the actual temperature will then be lower than the hydrate equilibrium temperature) for the fluid (normally below 20°C) will be necessary to be able to form hydrates. The subcooling for hydrate formation in the reactor (10) can be achieved by adding cold fluid from the separator (15) and from the cooler (11).

On the seabed or under arctic conditions or in other cold environments, said reactor (10) and said cooler (11) could be an uninsulated pipe. The cooler (11) could also be any type of cooler which could even be an integral part of the reactor (10).

In the separator (12), dry gas will be separated from the resulting fluid flow from the reactor/cooler (10), (11), and will be taken out for further processing and/or transport through, for example, a pipeline (6) for export to a central platform or to shore. The temperature in the separator (6) may be allowed to approach or be slightly above (typically 0.5 to 5°C depending on the total pressure) the minimum temperature (typically -2 to 4°C) in the export pipeline (6), as it is known from the literature that the partial pressure of water vapor over hydrate will be less than over water/ice. Separator (12) could be any type of separator.

Remaining fluid from separator (12) will be recycled through a line (13) by pump devices (14) to a separator (15). The pump (15) could be any type of pump capable of handling the hydrate particles. The pump can also be placed before the separator (12). One or more pumps or compressors will be able to be placed elsewhere in the system (3) to (17).

In separator (15), excess hydrates and hydrocarbon condensate, which do not need to be mixed with (4), will be separated from the fluid phase and introduced through pipeline (7) (as a liquid sludge phase) to separator (3). A further pump could be included in the line (7). Residual amounts of the total amount of hydrate particles and residual fluid from the separator (15) will be recycled through a line (16) to the reactor (10). A further cooler could be included in the line (16). Surplus hydrocarbon fluids will also be able to be led from separator (15) to pipeline (6) through a line (17). Separator (15) could be any type of separator and could include any devices for concentrating hydrate particles from fluid flow (13) to the liquid sludge phase in fluid flow (7). Separators (12) and (15) will be able to be combined in one separator.

The third separator (15), with the streams (7) and (16) as drains, will be able to be built in a way that will allow the largest part (usually over 80 vol%) of the stream (13) to enter the line (16). The concentration of hydrate particles in the streams (7) and (16) could be similar, or could be deliberately made different with different separator designs, depending on the system being treated. The separator (15) will also be able to include an outlet (17) for hydrocarbon liquid. The hydrocarbon liquid (17) will also be able to contain an excess of gas hydrate particles which will be able to be mixed with the dry gas stream (6) for transport.

In separator (3), any hydrate particles from the fluid flow (7) from separator (15) will be melted into water and gas components when the temperature in the separator rises above the hydrate equilibrium temperature (normally above 20°C). The melting process of hydrates will reduce the temperature of the fluid from fluid flow (1).

Water from separator (3) will be led to line (9) where it will be able to be injected into a reservoir, or be depressurized, cleaned and released to the environment.

Liquid hydrocarbon fluid from separator (3) will also be able to be taken out and led to a line (8) where it will be depressurized and stored or cooled down and led to pipeline (6).

The liquid fluid phase in the loop from reactor (10) to line (16) could arise from condensed liquid hydrocarbons from fluid stream (1) or any other fluid that is suitable for the process.

Salt water could be added to the aforementioned loop ((10) to (16)) to further reduce the partial pressure of water vapor (dew point of water) over hydrate in the second separator (12). The effect of having hydrates formed from the water phase and thereby increasing the concentration of salt in the liquid hydrocarbon fluid will be to improve the effect that lowers the water's dew point. Lowering the dew point will make it more difficult to precipitate hydrate in downstream locations, thus creating better protection against lower temperatures and possible water condensation elsewhere in the system. The salt additions will also be able to contribute to the regulation of particle size (small) and surface area (large). Salt (or other thermodynamic inhibitors) in the system will have specific effects that can be regulated to achieve certain results, as described below.

Salt or salt water can be added to systems without salt, or with salt concentrations of less than 3 vol% in the flow of hydrocarbon fluids, in order to be able to regulate the amount of hydrates that are formed (through thermodynamic inhibition), and also to ensure that the process of crystal growth always takes place at or near the hydrate equilibrium (each particle will be in local equilibrium with its immediate surroundings). This ensures that there will be a buffer against sudden changes (for example when a water surge or similar enters the system). What is also achieved is that any further growth will also be at or close to equilibrium, thus ensuring that the growth process will be in the form of ordinary solid crystals rather than dendrites or other crystal forms that will be able to contain water and/or be exposed to mechanical accumulation due to the growth form. When hydrates form in salt water, salt will be excluded from the crystals and the salinity of the water will increase as a result of the crystal growth. The growth process will stop when the salinity reaches a concentration sufficient for thermodynamic inhibition of the hydrates. This level will vary with the actual pressure and temperature conditions, but will be well known and will be able to be calculated in each case. Thus, a higher salinity in the water from the start of the crystal growth process (initial salinity) will mean that growth will stop at an earlier stage, and with smaller hydrate particles than in cases where the initial salinity is comparatively lower, other conditions being equal. Hydrate particle sizes will thus be able to be regulated in a similar way, by adjusting the salt level. More salt will result in smaller particles, while less salt will result in larger particles. Preferably, 5 to 10 percent by weight of salt or salt water will be added in systems without salt to achieve the effects mentioned above.

Hydrate sludge in line (7) could be countercurrent in a cooler to fluid flow in line (4) to cool down fluid in line (4) before it enters reactor (10) and melt hydrates in line (7) before it goes into separator (3).

The invention will be able to be placed underwater, on a platform or on land. A part of the invention, for example separators (3) and parts of system (5) (Figure 3), for example (12) and (15) and pump (14) in Figure 3, will be able to be placed offshore on, for example, a platform/ship, while reactor (10) and cooler (11) in Figure 3, for example, could be an uninsulated pipeline on the seabed.

The invention will be able to be applied to a hydrocarbon fluid flow (1) with any pressure that is capable of forming gas hydrates.

After separator (12), the dew point of water in fluid flow (6) can be further reduced by any suitable device known in the art, for example by molecular sieves, if it should be desired or necessary.

In, for example, a gas/condensate field, satellite wells will be able to be connected to (10) or (11) without any previous treatment, only limited by the hydrate melting capacity in separator (3).

The effects of salt

Figure 4 shows a conceptual consideration of a system where the water has a certain concentration of salt or another thermodynamic inhibitor.

In Figure 4 (a) we see the situation immediately after mixing a cold stream with hydrate particles and a warm stream with free water. The hydrate surface (shaded area) already has a layer of water with a salt concentration of Ci, due to the fact that salt is excluded from a growing hydrate crystal structure, and therefore will increase in concentration under the water phase until thermodynamic inhibition has been achieved at the real temperature and the pressure for the particle. The salt concentration Ci on the recycled particle will thus be higher than the concentration C2 in the incoming produced water. Hydrophilic processes will ensure that the produced water settles around the wet particles and we will for a short period have a two-layer salt concentration and a particle at the low recycling temperature T4, higher bulk mixture temperature Ti and system pressure Pi. For reasons of generality, we will assume that Ti will be above the equilibrium melting temperature for hydrate at the salt content C2. The part of Figure 4 (a) which is furthest to the right indicates the equilibrium lines corresponding to the different salt concentrations.

Figure 4 (b) shows the situation at a later time than Fig. 1 (a), after mixing (diffusion as a result of concentration differences) has also taken place in the water layer on the hydrate (particle) surface. The salt concentration C3 will lie between and C2. The temperature, T2, will be slightly lower than Ti (the bulk phase is cooled), but will still be high enough for hydrates to melt under these conditions. The hydrate surface will thus begin to melt, thereby releasing fresh water and hydrocarbon (which could be in the form of gas or liquid - see later discussion). The released phases will have a larger volume than the molten hydrate, and will induce expansion (which will become relevant at the next stage, and also at the later discussion). The salt concentration will begin to be diluted and will thus move the local equilibrium curve to the right, towards higher temperatures and will thus in reality minimize the driving forces for melting the hydrate particles.

In Figure 4 (c), the next step in the process is shown. Melting of hydrate is highly endothermic, meaning that the temperature will drop rapidly and allow the system to reach an equilibrium temperature T3- at least locally. The water film will at this point be supersaturated with hydrate formers and probably also with hydrate nuclei and/or precursors that have survived the melting process on the surface. New growth will thus not require nucleation or high supercooling, and will start quickly. It will perhaps most likely happen at the water-bulk interface, where momentary emptying of hydrate formers can be overcome in the simplest way. This growth will quickly result in hydrate surrounding the particle and the water layer. The new salt concentration in the now trapped water layer will now be higher than the bulk pressure Pi. This will be due to the effect of volume expansion from the melting hydrate core (as long as the enclosing layers, C4, increase and core melting continues).

Figure 4 (d) has progressed even further in time, and thermodynamic and mechanical equilibrium will now have been reached: the temperature has reached T4, the cold recirculation temperature (surrounding the pipeline), and hydrate layer formation and core melting have now occurred that the water layer has reached an elevated salt concentration, C5 which will correspond to the equilibrium condition in T4 and P4 (which will be equal to Pi) and which will therefore be equal to Ci.

This idealized equilibrium situation is taken further in Figure 4 (e), where we indicate how the inert sliding layer will be able to be broken up by fairly small shear forces, which will result in a large number of very small hydrate particles, with its own water layer with a salt concentration of Ci- essentially identical to the "original" particle in Fig. 4 (a), except for the size. Such a process should result in a large number of very small particles with sizes of less than a micrometer or a few micrometers. This will be observed in our experiments as more or less a "hydraulic fog", with particles that will be outside the practical observation limits of the equipment that has been used so far. Such a development will naturally also be aided by the expansion forces and volume changes as was briefly mentioned earlier. The outer hydrate layer will, for example, experience a volume change of around 16% [Stern et al. Polycrystalline Methane Hydrate: Synthesis from Superheated lee, and Low-Temperature Mechanical Properties, Energy & Fuels 1998, 12, 201 -211] when it freezes into solid hydrate If hydrocarbon hydrate formers are taken from the outside of the spherical shell, this process could have a net expansion effect, which could result in stress cracking and/or cracking of the hydrate shell - especially for very small particles (a few micrometers in diameter).

As a general observation for systems with salt water, we will be able to determine that any melting will dilute the salt concentration, thereby providing a larger stability area, which will reduce the driving force for melting. This will be a classic negative feedback loop, which will result in a dampening effect on any melting of the hydrate particle phase.

The large heat of formation for hydrates will keep the system temperature very close to equilibrium for a considerable time, and will thus ensure that the driving force for agglomeration will be very slow. Moreover, growth morphology will thus become more regular, with little chance of capturing unreacted water between crystal dendrites and the like. For the saline systems, we will have the additional effects that there will also be a local equilibrium for the hydrate-saline water system, with growth progression until inhibition is achieved. This would mean that any increase in temperature in a stable particle/water layer would give rise to melting. Saline systems will be at their local equilibrium at any realistic temperature/pressure point within the initial equilibrium line for the system (which will be based on the gas/oil composition and salinity of the produced water).

In hydrocarbon fluid systems with enclosed water within hydrate-covered water droplets or between a hydrate particle and an outer hydrate shell, one way to break up the hydrate shell is by adding fresh water or salt water to the system. With a difference in salt concentration between the added water and the hydrate enclosed water, an osmotic pressure difference will be able to break the hydrate shells and release the enclosed water. With the most concentrated salt water on the outside of a hydrate shell, the osmotic pressure force will come from the inside and go towards the outside of the shell. With a lower salt concentration in the water on the outside of a hydrate shell, the osmotic pressure will come from the outside and go inwards. This method could be a stand-alone method for regulating hydrate properties and behavior in a hydrocarbon fluid system. Injection of water or salt (or both) in a controlled manner at an appropriate point in a hydrocarbon fluid stream containing free water in a cooling process will be able to break up "traditionally" formed hydrate particles (with entrained water), producing a "suitable" cold hydrate mud with particles that will not stick to, for example, pipe walls or agglomerate.

Hydrate particles may become liquefied during the melting process. This would be advantageously used in, for example, separation processes in upstream processing facilities, such as a platform or a pipeline terminal on land. Instead of adding enough heat to melt all hydrates in a fluid stream and prior to standard separation technology, hydrates in a fluid stream could be partially melted by adding hot water, thereby causing the particles to float to the top of the fluid phase. Here, hydrate particles can be skimmed off, or mechanically separated from the bulk fluid in other ways. Added water may also contain magnetic particles which, after being adsorbed into melting hydrate particles, will be able to separate the hydrates from the fluid phase using a magnet. In addition to the buoyancy effect that would be achieved in this way, the same action could be used as a flocculation aid - by making the particles stick together better through the effect of water bridging. If the buoyancy effect of partial hydrate melting is negative (depending on hydrate-forming components), hydrate particles and free water will sink to the bottom of the fluid phase where they can be skimmed off or removed by any convenient procedure. The salt content of the injected water will be able to be adapted to achieve different levels of melting (and flow properties) of the hydrate particles, and will thus regulate the process. This separation process could also be carried out by partial melting of hydrate particles by increasing the temperature in the fluid flow, by reducing the pressure in the system, or by any other suitable means.

Further possible embodiments of the present invention can be illustrated through the following examples. This is not an exhaustive list of possible implementations, and is included only to serve as informative examples, and should in no way be construed as limiting future or alternative embodiments.

Example 1: Gas production from an offshore field with a production platform or a ship (or onshore gas production in a cold area).

An implementation of the present invention could include the following steps:

• Gas production will be throttled down to a suitable pressure, if necessary.

• The gas and any liquid will first pass through a hot (typically above 20°C) separator (which will also be used to melt excess hydrate from later stages in the process). • Gas (4) and condensate (8) from the hot separator (3) will proceed to the mixing point (10) (Figure 3), where they will meet a cold (typically -2 to 8 °C) gas hydrate slurry (16) from a cold separator (15). • The mixture will be flowed through a pipeline (11) which will use heat exchange with outside cold water (or air) as a means of cooling. • When appropriate, satellite wells could be connected to the stream (11) with shorter or longer feedback links, or alternatively could be fed into the hot separator (3) as an additional production stream (directly from the satellite to the platform). • The line (11), where the fluids are cooled, and the hydrates are precipitated, will end in the cold separator (12) on the platform, with a properly cooled mixture (usually around -2 to 8 °C) where the water has been precipitated out as gas hydrates (or concentrated to higher salinity according to the hydrate equilibrium conditions)). • The gas outlet (6) from the cold separator (12) will consist of cooled gas, which will be dry enough for direct export from the platform (water will be removed to hydrate, and the water's dew point will be further lowered (depending on gas composition, pressure and temperature) of any remaining highly saline (according to hydrate equilibrium conditions) water in the loop (11) and the

cold separator (12).

• If necessary, salt water can be added as formation water from the hot separator (3), as sufficiently pure seawater or by direct salt injection, to achieve an advantageous lower water dew point and/or smaller particle sizes and more particle surface area, and to avoid

inclusions of water.

• The excess condensate (17) from the cold separator (15) will also be able to be transported with the gas in the export pipeline (6). It could contain a small (less than 5 vol. %) fraction of hydrate particles, but it does not

enough to be able to affect the flow conditions noticeably.

• The flow pattern in the export line (6) will, if necessary, be able to be regulated in a way that will minimize the possibility of deposition and accumulation of hydrate particles, for example by ensuring annulus flow. • Hydrated sludge from the cold separator (15) is pumped to the previously mentioned mixing point (10), where it meets the gas (4)/condensate (8) flow from the hot separator (3), and starts the cooling flow loop ( 11). • Concentrated (usually over 10 vol. %) hydrate sludge from the cold separator (15) is pumped to the hot separator (3) to be melted back into gas, condensate, and water. (Further concentration of the sludge in, for example, a cyclone could be beneficial before it is injected into the hot separator (3)). • The water that will be separated out in the hot separator (3) will contain minimal amounts of hydrocarbons, and will probably be able to be re-injected directly into the reservoir formation, or be released into the sea after any necessary cleaning.

Example 2: Gas production from an underwater installation.

For most purposes in this embodiment, the process flow will be the same as described in Example 1 above. The main difference will be that all equipment will be moved underwater, to a central location where production from the most gas-rich and formation water-rich production wells will be gathered, thus allowing enough heat to be able to contribute in the melting stage for excess hydrate sludge in the heat separator (3) . The remaining production wells (less gas, less formation water) will simply be able to be gradually fed into the cooling loop (11) through shorter or longer feedback connections.

Example 3: Oil production from an underwater installation, or a platform, with processing options both underwater and above water.

An implementation of the present invention will in many respects be identical to the preceding one, and may include, but not be limited to, the following steps: • the production stream (1), which contains oil, gas, water, and/or condensate, throttled (2) down to a suitable pressure, if necessary. • The fluid stream (1) first passes through a hot (usually above 20 °C) separator (3) (which is also used to melt excess hydrate from later stages in the process). • Liquid hydrocarbon (8) and gas (4) (containing water vapor) from the hot separator (3) proceed to the mixing point (10) (Figure 3), where they meet a cold (typically -2 to 8°C) gas hydrate mud (16) from a cold

separator (15).

• The mixture flows through a pipeline (11) which uses heat exchange with cold water from outside (or air) as a means of cooling. • When appropriate, satellite wells could be connected to the stream (11) with shorter or longer feedback links, or alternatively could be introduced into the hot separator (3) as an additional production stream (directly from the satellite to the platform). • The line (11), where the fluids are cooled, and the hydrates are precipitated, ends in the cold separator (12) on the platform (or alternatively underwater), with properly cooled mixture (usually around -2 to 8 °C) where the water have been precipitated as gas hydrates (or concentrated to higher salinity according to

the hydrate equilibrium conditions)).

• The gas outlet (6) from the cold separator (12) will consist of cooled gas, which will be dry enough for direct export, as in previous examples. Alternatively, the gas could be burned in an incinerator or on others

ways are disposed of.

• The oil and condensate (17) from the cold separator (15) will be able to be transported in an export pipeline (6). It may contain a small (less than 5 vol%) fraction of hydrate particles, but not enough to be able to noticeably affect the flow conditions. The dried gas (6) will be able to remain

combined with that current if desired.

• Hydrated sludge (16) from the cold separator (15) will be pumped to the aforementioned mixing point (10), where it will meet the oil/condensate (8) and gas (4) stream from the hot separator (3), and will begin it

cooling current loop (11).

• Concentrated (usually over 10 vol. %) hydrate mud from the cold separator (15) will be able to be pumped to the hot separator (3) to be melted back into oil, gas and water. It will be possible to concentrate additional funds

(eg a cyclone) to minimize the return of hydrocarbon liquid. The cold separator (15) will therefore advantageously be placed in close physical proximity to the hot separator (3).

The water that is separated out in the hot separator (3), which will be the majority of the water in the system, will contain minimal amounts of hydrocarbons, and will probably be able to be reinjected directly into the reservoir formation, or be released into the sea after any necessary cleaning.

Claims (39)

1. Method for treating a stream of fluid hydrocarbons (1) containing water, where said stream of fluid hydrocarbons is a production stream from at least one wellbore, where the method comprises: - introducing the production stream and a liquid phase (7) comprising gas hydrates in a first separator (3), where the first separator has a temperature above 20 °C which melts the gas hydrates into free water, - to separate out most of the free water from said production stream and the liquid phase (7) in the separator (3), where a remainder of said fluid hydrocarbon stream (4) of the production stream and the liquid phase (7) is taken out of the separator (3) and introduced into a conversion system (5), - to convert in the conversion system (5) free/condensed water in the remaining fluid hydrocarbon stream (4) to gas hydrates, and then separating a resulting fluid stream from the conversion system (5) into at least a first fluid stream and a second fluid stream, wherein said first fluid stream (7) is a liquid phase comprising gas hydrates, said first fluid stream is recycled to the first separator (3) to provide the liquid phase (7) comprising gas hydrates, and where the second fluid stream (6, 18) which has a content of dry gas and/or condensate/oil is led to transport in a pipeline. 2. Method according to claim 1, where the production flow is a production flow from a gas field. 3. Method according to claim 1 or claim 2, where the production stream is a production stream from a gas field, and where separation in the first separator comprises separating free water and liquid condensate from said production stream and introducing a gas phase into the conversion system. 4. Method according to one of the previous claims, wherein said first fluid stream contains gas hydrate particles and condensate/oil. 5. Method according to one of the previous claims, comprising melting the gas hydrates in said recycled first fluid flow to free water and/or free gas/condensate/oil in the first separator (3). 6. Method according to one of claims 2-5, comprising adding heat to the first separator (3). 7. Method according to one of the previous claims, where said recycled first fluid flow is used as a countercurrent flow which cools down the remaining fluid hydrocarbon flow from the first separator before the remaining hydrocarbon flow enters the conversion system (5). 8. Method according to one of the previous claims, comprising separating out an aqueous phase with excess water from said first separator (3), where said excess water - is reinjected into a reservoir, or - is depressurized, cleaned of hydrocarbons and released to the environment. 9. Method according to one of claims 1-2 or 4-8, comprising separating condensate/oil from said first separator (3), where said condensate/oil is stored in the field, transported in a ship or a separate pipeline, or mixed with a fluid stream containing condensate/oil from said conversion system (5). 10. Method according to one of claims 1-9, comprising separating out the dry gas or dewatered oil/condensate from said first separator, where said dry gas and/or dewatered oil/condensate is further processed or provided to a pipeline for transport. 11. Method according to one of the previous claims, comprising adding salt to said remaining fluid hydrocarbon stream to reduce a partial pressure of water vapor (dew point of water) over hydrate and to regulate the growth of said hydrates. 12. Method according to claim 11, where said added salt is one of formation water from said first separator, seawater or direct salt injection. 13. Method according to one of claims 1-12, further comprising reduction of a dew point for water in said second fluid stream using at least one molecular sieve. 14. Method according to one of claims 1-13, where the conversion system (5) involves mixing the remaining fluid hydrocarbon stream in a reactor (10) with particles of gas hydrates which are also introduced into said reactor, the outlet stream of hydrocarbons from the reactor being cooled in a heat exchanger (11), said stream is then processed in a second separator (12) which separates the outlet stream from the heat exchanger into the first stream (13) and the second stream (6), and further separation of a third stream from said first stream, wherein said third stream (16) is recycled to the reactor (10) to provide the particles of gas hydrates, and wherein a remaining part (7) of the first stream is recycled to the first separator (3) as the liquid phase (7) comprising gas hydrates. 15. Method according to claim 14, where the liquid fluid phase in the conversion system (5) originates from condensed liquid hydrocarbons from said stream of liquid hydrocarbons (1) or any other suitable fluid. 16. Method according to claims 14 or 15, comprising regulation of a first concentration of gas hydrate in said first stream and a second concentration of gas hydrates in said third stream. 17. Method according to one of claims 14-16, where said first stream comprises a first concentration of gas hydrate and said third stream comprises a second concentration of gas hydrates, where said first concentration is less than the second concentration. 18. Method according to claim 17, wherein said second concentration of gas hydrates is preferably greater than 0.5 vol%. 19. Method according to one of claims 1-8, 14-17, comprising increasing a salt concentration in said residual hydrocarbon stream or said third recycled fluid stream to reduce a partial water vapor pressure (dew point for water) over hydrate in said hydrocarbon stream and regulate the growth of said hydrates. 20. Method according to one of the previous claims, comprising keeping a temperature in said second separator close to or slightly above a minimum temperature in an export pipeline for said dry gas and/or condensate/oil. 21. System for treating a stream of fluid hydrocarbon fluids containing water, said system including the following elements listed in the direction of flow and connected to each other: coupling to a hydrocarbon production source (1), a first separator (3) operative for in the minimum to separate free water from said fluid flow, a conversion system (5) to convert free/condensed water to gas hydrate, a pipeline (6, 18) to transport a dry gas or condensate/oil; and in addition a line (7) leading from the conversion system (5) to the first separator (3) and providing a first recycle stream comprising gas hydrates. 22. System according to claim 21, comprising a pressure control valve (2) or throttle valve (2) placed between the hydrocarbon source (1) and the first separator (3). 23. System according to one of claims 21 or 22, where the first separator (3) is equipped with an outlet (9) for an excess of an aqueous phase. 24. System according to one of claims 21 or 22, where the first separator (3) is equipped with an outlet (8) for a hydrocarbon liquid of condensate/oil, where said condensate/oil liquid will then be stored, transported, or mixed ( 17) with the dry gas fluid flow in the pipeline (6). 25. System according to one of claims 21 -24, comprising a first cooler (4) to cool down the fluid stream before it enters the conversion system (5). 26. System according to claim 25, where the first recycling flow (7) is a counterflow in said first cooler (4). 27. System according to one of claims 23-26, comprising an addition device for adding different chemicals to the hydrocarbon stream. 28. System according to one of claims 21-27, comprising a second addition device for adding salt to the fluid flow, to reduce a partial pressure for water vapor (dew point for water) over hydrate, and to regulate hydrate particle size and morphology. 29. System according to claim 28, where said salt is one of formation water from the first separator (3), sufficiently clean seawater or direct salt injection. 30. System according to one of claims 21-28, comprising at least one molecular sieve in the fluid flow line (7). 31. System according to one of claims 21 -28, where the conversion system (5) further comprises a reactor (10), a cooler (11) and a second separator (12) which will provide the first recycling flow in said line (7). 32. System according to claim 31, where the conversion system (5) further comprises a third separator (15) in said line (7) which separates said first recycling stream into a second recycling stream (16) which leads back to the reactor (10), and a remaining part of the first recycling stream (7) going to the first separator (3). 33. System according to claim 32, where the conversion system (5) is further equipped with a pump device (14) in said line (7) between the second separator (12) and the third separator (15). 34. System according to claim 32, where the conversion system (5) is equipped with at least one pump or compressor. 35. System according to one of claims 21-33, where said system is placed under water, on a platform or on land. 36. System according to claim 33 or 34, where the first separator (3), the second separator (12), and the third separator (15) and pump (14) are placed on a platform or on a ship. 37. System according to one of claims 31-36, where the reactor (10) and the cooler (11) are an uninsulated pipeline on the seabed. 38. System according to one of claims 21-37, where the liquid fluid phase in the conversion system (5) originates from condensed liquid hydrocarbons from fluid flow (1) or any other fluid suitable for the process in the conversion system (5). 39. System according to one of claims 21-37, where said hydrocarbon production source is from a gas field or a condensate/oil field, and where at least one satellite well is directly connected to the conversion system (5).