AU2011224929B2 - Treatment of produced hydrocarbon fluid containing water - Google Patents

Abstract

It is described a method for treating a flow of fluid hydrocarbons containing water wherein the flow of fluid hydrocarbons is introduced into a first separator separating at least free water from said flow of fluid hydrocarbons, wherein a remainder of said fluid hydrocarbon flow is introduced into a system converting free/condensed water in the fluid hydrocarbon flow in said system to gas hydrates, and providing at least a first fluid flow and a second fluid flow, wherein said first fluid flow is a liquid phase comprising gas hydrates, said first fluid flow is recycled into the first separator, and wherein the second fluid flow having a content of dry gas and/or condensate/oil. The invention also provides a system for treatment of a flow of fluid hydrocarbon fluid containing water, said system including the following elements listed in the flow direction and connected with each other: connection to a hydrocarbon production source (1), a first separator (3) operative to separate at least free water from said fluid flow, a converting system (5) for converting free/condensed water to gas hydrate, a pipeline (6, 18) for transporting a dry gas or condensate/oil; and in addition a line (7) which leads from the converting system (5) to the first separator (3) providing a first recycling flow comprising gas hydrates.

Description

INTRODUCTION

The invention concerns a system for treating a flow of fluid hydrocarbons containing water, and a method for such treatment.

BACKGROUND

Some of the world’s largest gas fields are found offshore in deep water (e.g.

Ormen Lange) or in remote areas in the artic (e.g Snohvit and Shtockman). The usual way today to transport such unprocessed well fluids in a pipeline to a landside terminal is by adding monoetylene glycol (MEG) at the wellheads. This requires large infrastructure and cost in order to inject and regenerate MEG.

For very long pipelines (e.g. Shtockman), processing and drying (water) of the gas phase may be needed prior to subsea pipeline transportation, e.g. at a platform or a ship. A full gas drying, e.g. by a tri ethylene glycol (TEG) process, will here require significant space and weight.

One common way to solve water problems and to minimize the hydrate problems in the industry, is to use glycol injection/adsorption and regeneration in a closed glycol system. Though in widespread use, such systems are plagued with a host of recurring problems - most of which can be traced back to poor efficiency of the first-stage separator for a well fluid. Glycol processes are dependent on such separation being 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. ,

Though much focus is presently on gas fields and avoidance of their water problems, many of the same problems also appear in liquid-rich oil/condensate systems, where even small fractions of water in the total system may over time lead to significant problems or flow blockages. Water and its solidification is thus a general problem for modern oil and gas production systems. US 6,774,276 is used as one possible way 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 shore 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 a system for treating a production flow of gas, hydrocarbon liquid and water from a hydrocarbon production field in a simple system and enabling further processing and/or transport of the desired products through a transportation system, including one or more pipelines.

In a first aspect the invention provides a method for treating a flow of fluid hydrocarbons containing water, wherein the flow of fluid hydrocarbons is introduced into a first separator separating at least free water from said flow of fluid hydrocarbons , wherein a remainder of said fluid hydrocarbon flow is introduced into a system converting free/condensed water in the fluid hydrocarbon flow in said system to gas hydrates, and providing at least a first fluid flow and a second fluid flow, wherein said first fluid flow is a liquid phase comprising gas hydrates, said first fluid flow is recycled into the first separator, and wherein the second fluid flow having a content of dry gas and/or condensate/oil.

The fluid flow may be a production flow from at least one wellbore. The flow of fluid hydrocarbons may alternatively be a production flow from a gas field, and wherein separating in the first separator comprising separating free water and liquid condensate from said production flow and introducing a gas phase into the converting system. The first fluid flow may contain gas hydrate particles and condensate/oil.

In an embodiment the first separator may have a temperature above a hydrate equilibrium temperature for the fluid flow. The gas hydrates may be melted in said first recycled fluid flow to free water and/or free gas/condensate/oil in the first separator. Heat may be added to the first separator if the temperature of the flow of fluid hydrocarbons is too low. The recycled first fluid flow may also be used as a counter current flow cooling the remaining fluid hydrocarbon flow from the first separator before the remaining hydrocarbon flow enters the reactor.

An excess water aqueous phase may be separated out from said first separator, wherein said excess water is re-injected into a reservoir, or depressurized, cleaned of hydrocarbons and released to the surroundings, or it may be used for any other suitable purpose. Condensate/oil may also be separated out from said first separator, wherein said condensate/oil is stored at the field, transported in a ship or a separate pipeline, or mixed with a fluid flow containing condensate/oil from said converting system. For a liquid-dominated system the dry gas, and/or the dewatered oil/condensate may be separated out from said first separator, wherein said dry gas and/or dewatered oil/condensate are further processed or provided to a pipeline for transport.

Salt may be added to said remaining fluid hydrocarbon flow decreasing a partial water vapor pressure (water dew point) over hydrate and controlling the growth of said hydrates. The added salt may be one of formation water from the first separator, seawater or direct salt injection. A water dew point in said second fluid flow may be decreased by using at least one molecular sieve.

In an embodiment the converting system entails mixing the remaining hydrocarbon fluid flow in a reactor with particles of gas hydrates which are also introduced into said reactor, the effluent flow of hydrocarbons from the reactor is cooled in a heat exchanger to ensure that all water therein which can be converted to hydrates is in the form of gas hydrates, said flow is then treated in a second separator to be separated into the first flow and the second flow, and further separating a third flow from said first flow, wherein said third flow is recycled to the reactor to provide the particles of gas hydrates, and wherein a remaining part of the first flow is recycled into the first separator. The liquid fluid phase in the converting system may originate from condensed liquid hydrocarbons from said flow of fluid hydrocarbons or any other suitable fluid. A first concentration of gas hydrate in said first flow and a second concentration of gas hydrates in said third flow may be controlled. Further, the first flow may comprise a first concentration of gas hydrate and said third flow comprising a second concentration of gas hydrates, wherein said first concentration is less than the second concentration, The second concentration of said gas hydrates is preferably larger than 0.5 vol%. A concentration of salt in said remaining hydrocarbon flow or said third recycled fluid flow may be increased, providing decreasing a partial water vapor pressure (water dew point) over hydrate in said hydrocarbon flow and controlling the growth of said hydrates. A temperature in said second separator may be kept near or slightly above a minimum temperature in an export pipeline for said dry gas and/or condensate/oil.

As disclosed herein there is provided a system for treatment of a flow of fluid hydrocarbon fluid containing water, said system including the following elements listed in the flow direction and connected with each other: connection to a hydrocarbon production source, a first separator operative to separate at least free water from said fluid flow, a converting system for converting free/condensed water to gas hydrate, a pipeline for transporting a dry gas or condensate/oil; and in addition a line which leads from the converting system to the first separator providing a first recycling flow comprising gas hydrates. A pressure control valve or choke may be provided between the hydrocarbon source and the first separator providing lowering of a pressure and temperature of the fluid flow before entering the separator.

The first separator may in be provided with an outlet for an excess aqueous phase. The first separator may be provided with an outlet for a hydrocarbon liquid condensate/oil, wherein said liquid condensate/oil is subsequently stored, transported, or mixed with the dry gas fluid flow in the pipeline. A first cooler for cooling the fluid flow before entering the converting system may be provided. The first recycling flow may be a countercurrent in said first cooler.

Further, an adding means for adding different chemicals to the flow of hydrocarbons may be provided. A second adding means for adding salt to the fluid flow decreasing a partial water vapor pressure (water dew point) over hydrate, and controlling hydrate particle size and morphology may also be provided. The salt may be one of formation water from the first separator, sufficiently clean seawater or provided from direct salt injection. At least one molecular sieve may be provided in the fluid flow line leading from the converting system further decreasing the water dew point.

According to a second aspect the invention provides a system for treatment of a flow of fluid hydrocarbon fluid containing water, said system including the following elements listed in the flow direction and connected with each other: connection to a hydrocarbon production source, a first separator operative to separate at least free water from said fluid flow, and separating a resulting fluid from the converting system into at least a first fluid flow and a second fluid flow, wherein the first fluid flow is directly recycled into the first separator through a line leading from the converting system to the first separator, and wherein the second fluid flow having a content of dry gas or condensate/oil, and a pipeline for transporting the second fluid flow, and an adding means for adding salt to the fluid flow decreasing a partial water vapor pressure (water dew point) over hydrate, and controlling hydrate particle size and morphology.

In an embodiment, the converting system may comprise a reactor, a cooler, and a second separator providing the first recycling flow in the line leading from the converting system to the first separator. The converting system may further comprise a third separator in said line separating said first recycled flow into a second recycling flow leading back to the reactor and a remaining part of the first recycling flow leading to the first separator. The converting system may further be provided with a pumping device in said line between the second separator and the third separator. The converting system may be provided with at least one pump or compressor. The system may be placed subsea, on a platform or onshore. The first separator, second separator, and third separator and pump may be placed on a platform or a ship. The reactor and cooler may be an uninsulated pipeline at a sea bottom. The liquid fluid phase in the converting system may originate from condensed liquid hydrocarbons from fluid flow or any other fluid suitable for the process in the converting system. The hydrocarbon production source may be a gas field or condensate/oil field, and wherein at least one satellite well is directly connected to the converting system. A more compact and economic process for condensate and water takeout from a wellhead gas stream, or water removal from an oil flow, may be obtained by the present invention situated at/near the wellhead/production platform/ship or subsea. Warm wellhead fluid (gas/condensate/oil/water) is here passed into a first separator where free water or condensate/oil and free water are separated from the fluid stream. Unlike a traditional first separator, e.g. used in a TEG process for a gas field, this separator also contains an inlet for a fluid stream of condensate/oil and gas hydrates. The temperature in the separator is above the hydrate equilibrium temperature, ensuring melting of all incoming hydrates. The hydrate containing fluid is obtained by drying of the gas or gas/condensate/oil stream from the given first separator by a system as e.g. described in US 6,774,276 as mentioned above. While US 6,774,276 aims to make water transportable, the present invention preferably removes water from the production stream. Dry gas from the present invention is preferably exported to a pipeline. Excess condensate/oil is drained from the separator and exported in a pipeline or degassed before storage. Liquid water from the given separator is reinjected in a field, or heated/degassed and cleaned before being released to sea. Alternatively, for a liquid-dominated system, the dry gas, and dewatered oil or condensate may go on to further processing, or to pipeline transport.

The present invention may be conducted at or near wellhead pressure, which may eliminate the need for export compressors at the field. The need of chemicals (e.g. MEG) to the export pipeline may be eliminated or reduced to e.g. handle corrosion.

In many cases it is advantageous to add different chemicals to the flow of hydrocarbons. The system may accordingly contain a means for adding such chemicals to the flow.

In the present invention system (5) may be any system suitable for the purpose, but may preferably make use of US 6,774,276 as an integral part. Other systems for converting free water/condensed water to gas hydrates may alternatively be used, as e.g. described in US patent application 2002/0120172, US patent no. 5,460,728 (or one of the many similar applications), WO 2007/095399, WO 2008/056250, or by use of choking to cool the stream and precipitate hydrates, or any other suitable means to achieve a hydrate particle laden slurry flow.

An additional new inventive aspect compared to US 6,774,276 is introduced by the present invention through the water dew point effects which will occur due to any salts present in the aqueous phase. In addition to lowering the water dew point (and thus controlling hydrate formation) other beneficial effects of salt-containing water contribute to the novelty of this invention. As described in US provisional 61/312,790, the presence of salt, or the addition of salt (or other thermodynamic hydrate inhibitor compound like e.g. methanol or glycol), helps to control the hydrate formation process by keeping local conditions close to thermodynamic equilibrium. Salt on its own also helps control and limit the size of hydrate particles and aids the avoidance of enclosed, unreacted water, which would otherwise pose a deposition and agglomeration risk.

Compared with prior art in glycol injection/adsorption and regeneration systems, the present invention simplifies the problem considerably, by allowing the first stage separator to be a simpler design, as the downstream system here is much less sensitive to the contents of the production stream. The first stage separator here only needs to remove the major part of free, condensed water, and act as a heating vessel for generated gas hydrates, with no need for pre-cooling to promote condensation.

Water condensation is in the present invention promoted onto gas hydrates in later stages of the process, with much higher water 'removal' efficiency than most first-stage separators. In systems with saline water, the present invention also achieves a further amount of protection by lowering the water dew point well below the operation temperatures, as water is promoted in the presence of saline solutions. This simplification also means that the present invention is an energetically favourable technology compared to glycol systems, both for onshore and offshore applications.

The ability to let the production stream flow at high pressure throughout the system of the present invention, also means that energy is saved compared to sometimes large recompression needs in traditional technology. Additionally, weight savings on offshore facilities (through e.g. the removal of a glycol regeneration system) are important, and can be made possible by the present invention.

BRIEF DESCRIPTION OF DRAWINGS

Example 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 transportation 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 numerals are used for similar or corresponding features in all the drawings.

Reference is made to Figure 1. A production fluid flow of hydrocarbons and water (1) is introduced into a first separator (3) together with a fluid flow (7) containing gas hydrate and condensate/oil. In separator (3) the temperature is sufficiently high (20° C or higher) to melt all incoming hydrates into free water. In separator (3) most free water (more than 99%) is separated from the production flow (1). At the same time hydrates in fluid flow (7) is melted to free water and gas/condensate/oil in separator (3).The remainder of the production flow (1) and fluid flow (7), which is gas/condensate/oil, is taken out (4) of separator (3) and introduced into a system (5). Condensate/oil may also be taken out (8) of separator (3) and stored at the field, transported in ship or a separate pipeline, or mixed with a fluid flow (18) containing condensate/oil from system (5). Separator (3) may be any type of separator.

In system (5), which may be any system suitable for the purpose, the fluid flow (4) is cooled in order to convert any free or condensed water from fluid flow (4) into gas hydrates. The resulting fluid flow in system (5) is then after treatment, separated into an essentially dry gas (6) (with a water dew point below ambient conditions), a condensate/oil phase (18) (condensate/oil fields), and a liquid slurry phase (7) consisting of hydrocarbon liquid and gas hydrates. Fluid flows (6) and (18) may be combined in a single fluid flow.

Said flow (1) of fluid hydrocarbons (gas/condensate/oil), will normally come from one or more drilling hole wells and will be relatively warm and will be under pressure. It may sometimes be advantageous to attain a lower pressure and temperature in fluid flow (1) by passing the fluid flow through a choke (2) before introducing the fluid flow into separator (3). Choke (2) may be any type of choke.

Flow (9) separated out from the first separator (3), consisting mainly of water from production flow (1) and from melted hydrates in the liquid slurry phase (7), may be re-injected into a reservoir, it may be depressurized, cleaned of hydrocarbons and released to the surroundings, or it may be used for any other suitable purpose.

In some embodiments, saline water may advantageously be added to system (5) to enhance the water dew point reduction in the dry gas (6) separated out from system (5). The effect of saline water will be explained in detail later.

Referring to Figure 2. in this embodiment, a production flow (1) from a gas field is entered into a first separator (3). The first separator has a temperature above hydrate equilibrium temperature for the fluid flow. A second fluid flow (7) containing gas hydrate particles and condensate is also introduced into separator (3). In the first separator (3) liquid condensate and free water is separated from the production flow (1). At the same time hydrates in the second fluid stream (7) is melted to free water and gas in the first separator (3). The remainder of the production flow, which is a gas phase, is taken out (4) and introduced into a system (5). In system (5), any free water in the gas phase flow (4) or condensed water in system (5) is converted into gas hydrate before returned to separator (3) as the second fluid flow (7). Any condensate in the gas phase flow (4) or condensate condensed in system (5) is also returned to separator (3) by the second fluid flow (7). Condensate in separator (3) is taken out (8) and stored at the field, transported in ship or a separate pipeline, or mixed with a fluid flow (6) containing dry gas from system (5). Water in separator (3) is taken out through an outlet (9) and either processed or re-injected in a reservoir.

In system (5), which may be any system suitable for the purpose, the gas phase fluid flow (4) is cooled in order to convert any free or condensed water from gas phase fluid flow (4) into gas hydrate. Vapor hydrocarbons in (4) may also condense to liquid in this process. The resulting fluid flow in system (5) is then after treatment, separated in system (5) into an essentially dry gas (6) (with a water dew point below ambient conditions), and a liquid slurry phase (7) consisting of hydrocarbon liquid and gas hydrates. On average, equal amounts (except for the remaining vapor in (6)) of water (in the form of hydrates and water) and condensate added to system (5) in fluid flow (4) are returned from system (5) to separator (3) by the second fluid flow (7) (liquid slurry phase). In separator (3) the hydrates are melted to liquid water and free gas by the temperature level.

The production flow (1) will generally come from one or more drilling hole wells, and will be relatively warm and under pressure. It may be advantageous to attain a lower pressure, and at the same time somewhat cool the production flow, by flowing it through an expansion valve (2) before introducing it into separator (3).

Flow (9) separated out from the first separator (3), consisting mainly of water from production flow (1) and from melted hydrates in the liquid slurry phase (7), may be re-injected into a reservoir, it may be depressurized, cleaned of hydrocarbons and released to the surroundings, or it may be used for any other suitable purpose.

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

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

Said flow (1) of fluid hydrocarbons will normally come from one or more drilling hole wells and will be relatively warm and will be under pressure. It may sometimes be advantageous to attain a lower pressure and temperature in fluid flow (1) by passing the fluid flow through a choke (2) before introducing the fluid flow into separator (3). Choke (2) may be any type of choke.

The gas phase (4), from separator (3), will normally contain vapour hydrocarbons and water vapour. The gas phase (4) is conveyed into a system (5), which in the embodiment in Figure 3 is illustrated by use of the reactor system with feedback loop (10, 11, 12, 13, 14, 16) as described in US 6,774,276 and which is hereby included by reference in its entirety. In Figure 3, the gas phase fluid flow (4) is conveyed to a reactor (10), where it is mixed with cold (temperature below the melting temperature of the gas hydrate) fluid (16) from a separator (15). Said cold fluid (16) from the separator (15) contains particles of dry hydrate.

Water vapour and heavier hydrocarbon components which are present in the gas phase (4), will condense at cooling in reactor (10). As described in US 6,774,276, this water will moisten hydrate (16) from the separator (15) in the reactor (10) and in the cooler (11). In the reactor (10) and cooler (11) the water which moistens the hydrate will be converted to hydrate. New hydrate which is formed will accordingly grow on the hydrate particles from the separator (15) and also form new hydrate particles when large hydrate particles break up. New hydrate seed may also be formed elsewhere in the reactor (10) and cooler (11).

Fluid flow (4) may be mixed with the slurry of liquid and gas hydrate particles (16) in different ways in reactor (10), including being bubbled through a liquid slurry column, or by any suitable mechanical or other means of mixing.

Sub-cooling (the actual temperature being lower than the hydrate equilibrium temperature) of the fluid (normally below 20° C), is required in order to form hydrates. The sub-cooling for formation of hydrate in the reactor (10) is accomplished by adding cold fluid from the separator (15) and from cooler (11).

At the bottom of the ocean or under artic conditions or in other cold environments said reactor (10) and said cooler (11) may be an uninsulated pipe. The cooler (11) may also be any type of cooler which even may be an integrated part of the reactor (10).

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

Residual fluid from separator (12) is recycled through a line (13) by means of a pump (14) to a separator (15). The pump (15) may be any type of pump, able to handle the hydrate particles. The pump may also be situated before separator (12). One or more pumps or compressors may also be placed anywhere in the system (3) to (17).

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

The third separator (15), with the flows (7) and (16) as effluents, may be constructed in such a way as to let the larger part (usually above 80 volume %) of the flow (13) go in line (16). The concentration of hydrate particles in flows (7) and (16) may be similar, or may be intentionally made different by different separator designs, depending on the system being treated. The separator (15) may also include an outlet (17) for hydrocarbon liquid. The hydrocarbon liquid (17) may also contain surplus gas hydrate particles, which may be mixed with the dry gas flow (6) for transport.

In separator (3) any hydrate particles from the fluid flow (7) from separator (15) will melt to water and gas components when the temperature in the separator is above hydrate equilibrium temperature (normally above 20° C). The melting process of hydrates will decrease the temperature of the fluid from fluid flow (1).

Water from separator (3) is conveyed to line (9) where it may be injected into a reservoir, or depressurized, cleaned and released to the surroundings.

Hydrocarbon liquid fluid from separator (3) may be taken out and conveyed to a line (8) where it may be depressurized and stored or cooled and conveyed to pipeline (6).

The liquid fluid phase in the loop from reactor (10) to line (16) may originate from condensed liquid hydrocarbons from fluid flow (1) or any other fluid suitable for the process.

Salt water may be added to the said loop ((10) through (16)) in order to further decrease the partial water vapour pressure (water dew point) over hydrate in the second separator (12). The effect of having hydrates formed from the water phase and thus increasing the concentration of salt in the hydrocarbon liquid fluid, is to ' enhance the effect that lowers the water dew point. Lowering the due point makes it more difficult to precipitate hydrate at downstream locations, thus creating a better protection against lower temperatures and possible water condensation elsewhere in the system. The salt additions may also contribute beneficially in controlling particle size (small) and surface area (large). Salt (or other thermodynamic inhibitors) in the system will have specific effects which may be controlled to achieve certain results, as described below.

Salt or salt water may be added to systems without salt, or with salt concentrations below 3 volume% in the flow of fluid hydrocarbons, in order to regulate the amount of hydrates which are formed (through thermodynamic inhibition), and to also make sure that the process of crystal growth always takes place at or near hydrate equilibrium (each particle will be in local equilibrium with its immediate surroundings). This ensures that there is a buffer against sudden changes (e.g. when a water slug or similar enters the system). What is also achieved is that any further growth is also at or near equilibrium, ensuring that the growth habit is in the form of regular solid crystals rather than dendrites or other crystal forms which may enclose water and/or be prone to mechanical agglomeration due to the growth form. When hydrates form in saline water, salt is excluded from the crystals, and the salinity in the water will increase due to the crystal growth. The growth process stops when the salinity reaches a concentration which is sufficient for thermodynamic inhibition of the hydrates. This level varies with the actual pressure and temperature conditions, but is well-known and can be calculated in each case. Thus, a higher salinity in the water at the start of the crystal growth process (initial salinity) means that the growth stops at an earlier stage, and with smaller hydrate particles than for cases where the initial salinity is comparatively lower - other conditions being equal. Hydrate particle sizes may thus be controlled in a similar manner, by adjusting the salt level. More salt will result in smaller particles, while less salt leads to larger ones.

Preferably, 5 to 10 weight per cent of salt or salt water is added to systems without salt to achieve the above effects.

Hydrate slurry in line (7) may be countercurrent in a cooler to fluid flow in line (4) in order to cool fluid in line (4) before entering reactor (10) and melt hydrates in line (7) before entering separator (3).

The invention may be placed subsea, on a platform or onshore. Part of the invention, e.g. separators (3) and parts of system (5) (Figure 3), e.g. (12) and (15) and pump (14) in Figure 3, may in an offshore field be placed on e.g. a platform/ship while e.g. reactor (10) and cooler (11) in Figure 3 may be e.g. an uninsulated pipeline at the sea bottom.

The invention may be applied to a hydrocarbon fluid stream (1) of any pressure capable of forming gas hydrates.

Water dew point in fluid flow (6) may after separator (12) be further decreased by any suitable means known in the art, e.g. by molecular sieves, if wanted or needed.

In e.g. a gas/condensate field, satellite wells may 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 view for a system where the water has some concentration of salt or other thermodynamic inhibitor.

In Figure 4 (a), we see the situation immediately after the mixing of 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 increases in concentration in the water phase until thermodynamic inhibition is achieved at the actual temperature and pressure for the particle. The salt concentration ci on the recirculated particle is thus higher than the concentration c2 in the incoming produced water. Hydrophilic processes make sure that the produced water coats the wet particles, and we will for a short period have a two-layer salt concentration, and a particle at the low recirculation temperature T4, the higher bulk mixing temperature of Ti, and the system pressure of P,. For the sake of generality, we will assume that Ti is above the equilibrium melting temperature for hydrate at the salt content of c2. The right-most part of Figure 4 (a) indicates the equilibrium lines corresponding to the different salt concentrations.

Figure 4 (b) shows the situation at a later time step than Fig. 1 (a), after mixing (diffusion due to concentration differences) has also taken place in the water layer on the hydrate (particle) surface. The salt concentration c3 lies between Ci and c2. The temperature, T2, is slightly lower than Ί·\ (the bulk phase is cooling), but still high enough to mean that hydrates will melt under these conditions. The hydrate surface will thus start to melt, releasing fresh water and hydrocarbon (which may be in gaseous or liquid form - see later discussion). The released phases will have a larger volume than the melted hydrate, and will induce expansion (which becomes relevant in the next stage, and also in the later discussion). The salt concentration will start to be diluted, bringing the local equilibrium curve to the right, towards higher temperatures, thus in effect minimizing the driving forces for melting of the hydrate particle.

In Figure 4 (c), the next step in the process is shown. The melting of hydrate is •highly endothermic, meaning that the temperature will drop quickly, allowing the system to reach equilibrium temperature T3 - at least locally. The water film is at this point supersaturated with hydrate former, and likely also hydrate nuclei and/or precursors surviving from the melting process at the surface. New growth thus does not require nucleation or high supercooling, and starts quickly. It is perhaps most likely to happen at the water-bulk interface, where momentary depletion of hydrate former is most easily overcome. This growth quickly results in hydrate surrounding the particle and water layer. The new salt concentration in the now trapped water layer, c4 is higher than c3, (due to salt exclusion from the growing hydrate layer), and has an equilibrium line further to the left. One significant additional factor at this point, is that the pressure P3 in the enclosed salt water layer will now be higher than the bulk pressure Pi. This will be due to the effect from the volume expansion from the melting hydrate core (as long as the enclosing layer forms, c4 increases, and core melting continues).

Figure 4 (d) has progressed even further in time, and thermodynamic and mechanic equilibrium has now been reached: the temperature has reached T4, the cold recirculation temperature (ambient to the pipeline), and the hydrate layer formation and core melting has progressed until the water layer has reached an elevated salt concentration, C5 which corresponds to the equilibrium condition at T4 and P4 (which is equal to Pi) and which is therefore equal to ci.

This idealised equilibrium situation is taken further in Figure 4 (e), where we indicate how the inert gliding layer of saline water between the particle and its outer hydrate shell layer can be broken up by fairly small shear forces, resulting in a large number of very small hydrate particles, with their own layer of water with a salt concentration of C1 - basically 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, of sub-micron or a few microns’ size. This is observed in our experiments more or less as a hydrate “fog”, with particles beyond the practical observation limits in the equipment used so far. Such a development is also of course aided by the expansion forces and volume changes briefly mentioned earlier. The outer hydrate layer will e.g. experience a volume change of about 16% [Stern et al. . Polycrystalline Methane Hydrate: Synthesis from Superheated Ice, and Low-Temperature Mechanical Properties, Energy & Fuels 1998, 12, 201-211] when freezing to solid hydrate. If the hydrocarbon hydrate former is taken from outside the spherical shell, this process may have a net expansion effect, resulting in stress cracking and/or buckling of the hydrate shell - particularly for very small particles (a few micrometers in diameter).

As a general observation for systems with salt water, we may state that any melting dilutes the salt concentration, and thereby provides a larger stability region, which reduces the driving force for melting. This is a classic negative feedback loop, resulting in a dampening effect on any melting of the hydrate particle phase.

The large heat of formation for hydrates keeps the system temperature very close to equilibrium for a significant time, making sure that the driving force for agglomeration is very low. Also, growth morphology thus becomes more regular, with little chance of trapping unreacted water between crystal dendrites, etc. For the salt-containing systems, we have the additional effects that there will always be a local equilibrium for the hydrate-saline water system, with growth progressing until inhibition is achieved. This means that any temperature rise in a stable particle/water layer will give rise to melting. Salt-containing systems will be at their local equilibrium at any realistic temperature/pressure point inside the initial equilibrium line for the system (which is based on the gas/oil composition and produced water salinity).

In hydrocarbon fluid systems with enclosed water inside hydrate covered water droplets or between a hydrate particle and an outer hydrate shell, one way to break up the hydrate shells is by adding fresh or salt water to the system. By a salt concentration difference between added water and the hydrate enclosed water, osmotic pressure difference may break the hydrate shells and release enclosed water. With the most concentrated saline water on the outside of a hydrate shell the osmotic pressure force will be from the inside towards the outside of the shell. With lower salt concentration in the water on the outside of a hydrate shell the osmotic pressure will be from outside inwards. This method may be a stand-alone method for controlling hydrate characteristics and behaviour in a hydrocarbon fluid system. Injection of water or salt (or both) in a controlled manner at the correct point in a hydrocarbon fluid flow containing free water in a cooling process may break up “traditionally" formed hydrate particles (with enclosed water) and give a “proper" cold hydrate slurry with particles that will not deposit on e.g. pipe walls or agglomerate.

Hydrate particles may become buoyant during a melting process. This may be advantageously exploited e.g. in separation processes in the topside processing facilities e.g. topside a platform or a pipeline terminal onshore. Instead of adding enough heat to melt all hydrates in a fluid stream and before standard separation technology, hydrates in a fluid flow may be partially melted by adding warm water, thereby making the particles float to the top of the fluid phase. Hydrate particles may here be skimmed off, or otherwise mechanically separated from the bulk fluid. Added water may also contain magnetic particles which after being adsorbed to melting hydrate particles may separate the hydrates form the fluid phase by use of a magnet. In addition to the flotation effect achieved in this manner, the same action may be used as a flocculation help - making particles stick more together through the effect of water bridging. If the buoyancy effect of partly hydrate melting is negative (dependent on hydrate forming components), hydrate particles and free water will sink to the bottom of the fluid phase where they may be skimmed off or removed by any convenient procedure. The salinity of the injected water may be adjusted to achieve various rates of melting (and buoyancy) of the hydrate particles, thus controlling the process. This separation process may also be performed by partly melting hydrate particles by raising the temperature in the fluid flow, by reducing the pressure of 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 a comprehensive list of possible implementations, and is included here to serve as informational examples only, and in no way should be seen as constricting future or alternative embodiments.

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

An implementation of the present invention might include the following steps: • The gas production is choked down to a suitable pressure, if needed. • The gas and any liquid first passes through a warm (usually above 20°C) separator (which is also used to melt excess hydrate from later process steps). • Gas (4) and condensate (8) from the warm separator (3) pass on to the mixing point (10)(Figure 3), where they meet a cold (usually -2 to 8° C) gas hydrate slurry (16) from a cold separator (15) • The mixture is flowed through a pipeline (11) which utilizes heat exchange with cold outside water (or air) as a means of cooling. • Whenever suitable, satellite wells may be connected to the flow (11) with shorter or longer tie-backs, or alternatively be lead into the warm separator (3) as extra production stream (directly from the satellite to the platform). • The line (11), where the fluids are cooled, and hydrates will precipitate, ends 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 as gas hydrates (or concentrated to a higher salinity according to hydrate equilibrium conditions)). • The gas outlet (6) from the cold separator (12) consists of cooled gas, dry enough for direct export from the platform (water being removed into hydrate, and water dew point being further lowered (depending on gas composition, pressure and temperature) by any remainder of high salinity (according to hydrate equilibrium conditions) water in the loop (11) and cold separator (12) • Saline water may if needed be added as formation water from the warm separator (3), sufficiently clean seawater, or by direct salt injection, in order to achieve beneficially lower water dew point and/or smaller particle sizes and more particle surface area, and to avoid water inclusions. • The surplus condensate (17) from the cold separator (15) may also be transported with the gas in the export pipeline (6). It may contain a small (less then 5 volume %) fraction of hydrate particles, but not enough to appreciably influence the flow conditions. • The flow pattern in the export pipe (6) may, if needed, be controlled in such a way as to minimize the potential for deposition and build-up of hydrate particles, e.g. through ensuring annular flow. • Hydrate slurry 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 warm separator (3), and starts the cooling flow loop (11). • Concentrated (usually above 10 volume%) hydrate slurry from the cold separator (15) may be pumped to the warm separator (3) for melting back to gas, condensate, and water. (Further concentration of the slurry in e.g. a cyclone may be advantageous before injecting it into the warm separator (3)). • The water which is separated out in the warm separator (3) will contain minimal amounts of hydrocarbons, and may probably be re-injected directly into the reservoir formation, or discharged to sea after any needed cleaning.

Example 2: Gas production from a subsea installation For most purposes in this embodiment, the process flow will be the same as described in Example 1 above. The main difference is that all equipment is moved subsea, to a central location where production from the most gas-rich and formation water rich production wells are gathered, allowing enough heat to apply the melting step for excess hydrate slurry in the warm separator (3). The remaining production wells (less gas, less formation water) may be simply phased into cooling loop (11) through shorter or longer tie-backs.

Example 3: Oil production from a subsea installation, or a platform, with processing possibilities both subsea and topsides.

An implementation of the present invention is in many respects identical to the preceding, and might include, but not limited to, the following steps: • The production flow (1), containing oil, gas, water, and/or condensate, is choked (2) down to a suitable pressure, if needed. • The fluid flow (1) first passes through a warm (usually above 20°C) separator (3) (which is also used to melt excess hydrate from later process steps). • Liquid hydrocarbon (8) and gas (4) (containing water vapour) from the warm separator (3) pass on to the mixing point (10) (Figure 3), where they meet a cold (usually -2 to 8° C) gas hydrate slurry (16) from a cold separator (15) • The mixture is flowed through a pipeline (11) which utilizes heat exchange with cold outside water (or air) as a means of cooling. • Whenever suitable, satellite wells may be connected to the flow (11) with shorter or longer tie-backs, or alternatively be lead into the warm separator (3) as extra production stream (directly from the satellite to the platform). • The line (11), where the fluids are cooled, and hydrates will precipitate, ends in the cold separator (12) on the platform (or alternatively subsea), with a properly cooled mixture (usually around -2 to 8° C) where the water has been precipitated as gas hydrates (or concentrated to a higher salinity according to hydrate equilibrium conditions)). • The gas outlet (6) from the cold separator (12) consists of cooled gas, dry enough for direct export, as in previous examples. Alternatively, the gas may be flared or otherwise disposed of. • The oil and condensate (17) from the cold separator (15) may be transported in an export pipeline (6). It may contain a small (less then 5 volume %) fraction of hydrate particles, but not enough to appreciably influence the flow conditions. The dried gas (6) may be combined with this flow if desired. • Hydrate slurry (16) from the cold separator (15) is pumped to the previously mentioned mixing point (10), where it meets the oil/condensate (8) and gas (4) flow from the warm separator (3), and starts the cooling flow loop (11). • Concentrated (usually above 10 volume%) hydrate slurry from the cold separator (15) may be pumped to the warm separator (3) for melting back to oil, gas, and water. It may be concentrated by extra means (e.g. a cyclone) in order to minimise return of hydrocarbon liquid. The cold separator (15) is therefore advantageously situated in close physical proximity to the warm separator (3).

The water which is separated out in the warm separator (3), which will be the majority of the water in the system, will contain minimal amounts of hydrocarbons, and may probably be re-injected directly into the reservoir formation, or discharged to sea after any needed cleaning. A number of other combinations or variations of the aspects of the present invention will be evident to persons skilled in the art, and fall within the scope of the present invention, which is to be determined from the following claims.

Claims (21)

1. A method for treating a flow of fluid hydrocarbons containing water, wherein said flow of fluid hydrocarbons is a production flow from at least one wellbore, the method comprising: - introducing the production flow and a liquid phase comprising gas hydrates into a first separator, the first separator having a temperature above 20°C melting the gas hydrates into free water, - separating out most of the free water from said production flow and the liquid phase in the separator, wherein a remainder fluid hydrocarbon flow of the production flow and the liquid phase is taken out of the separator and introduced into a converting system, - converting in the converting system free/condensed water in the remainder fluid hydrocarbon flow to gas hydrates and thereafter separating a resulting fluid flow from converting system in at least a first fluid flow and a second fluid flow, wherein said first fluid flow is a liquid phase comprising gas hydrates, said first fluid flow is recycled into the first separator to provide the liquid phase comprising gas hydrates, and wherein the second fluid flow having a content of dry gas and/or condensate/oil is conveyed for transport in a pipeline.

2. The method according to claim 1, wherein said production flow is a production flow from a gas field.

3. The method according to claim 1 or claim 2, wherein said production flow is a production flow from a gas field, and wherein separating in the first separator comprising separating free water and liquid condensate from said production flow and introducing a gas phase into the converting system.

4. The method according to any one of the previous claims, wherein said first fluid flow containing gas hydrate particles and condensate/oil.

5. The method according to any one of the previous claims, comprising melting the gas hydrates in said first fluid flow to free water and/or free gas/condensate/oil in the first separator.

6. The method according to any one of claims 2-5, comprising adding heat to the first separator.

7. The method according to any one of the previous claims, wherein said first fluid flow is used as a counter current flow cooling the remainder fluid hydrocarbon flow from the first separator before the remainder fluid hydrocarbon flow enters the converting system.

8. The method according to any one of the previous claims, comprising separating out an excess water aqueous phase from said first separator, wherein said excess water aqueous phase is - re-injected into a reservoir, or - depressurized, cleaned of hydrocarbons and released to the surroundings.

9. The method according to any one of claims 1 -2 or 4-8, comprising separating out condensate/oil from said first separator wherein said condensate/oil is stored at the field, transported in a ship or a separate pipeline, or mixed with a fluid flow containing condensate/oil from said converting system.

10. The method according to any one of claims 1 -9, comprising separating out the dry gas or dewatered oil/condensate from said first separator, wherein said dry gas and/or dewatered oil/condensate are further processed or provided to a pipeline for transport.

11. The method according to any one of the previous claims, comprising adding salt to said remainder fluid hydrocarbon flow decreasing a partial water vapor pressure (water dew point) over hydrate and controlling the growth of said hydrates.

12. The method according to claim 11, wherein said added salt is one of formation water from the first separator, seawater or direct salt injection.

13. The method according to any one of claims 1 -12, comprising further decreasing a water dew point in said second fluid flow by using at least one molecular sieve.

14. The method according to any one of claims 1 -13, wherein the converting system entails mixing the remainder fluid hydrocarbon flow in a reactor with particles of gas hydrates introduced into said reactor, the effluent flow of hydrocarbons from the reactor is cooled in a heat exchanger, the effluent flow from the heat exchanger is then treated in a second separator separating the effluent flow from the heat exchanger into the first flow and the second flow, and further separating a third flow from said first flow, wherein said third flow is recycled to the reactor to provide the particles of gas hydrates, and wherein a remaining part of the first flow is recycled into the first separator as the liquid phase comprising gas hydrates.

15. The method according to claim 14, wherein the liquid fluid phase in the converting system originates from condensed liquid hydrocarbons from said flow of fluid hydrocarbons or any other suitable fluid.

16. The method according to claim 14 or claim 15, comprising controlling a first concentration of gas hydrate in said first fluid flow and a second concentration of gas hydrates in said third fluid flow.

17. The method according to any one of claims 14-16, wherein said first flow comprising a first concentration of gas hydrate and said third flow comprising a second concentration of gas hydrates, wherein said first concentration is less than the second concentration.

18. The method according to claim 17, wherein said second concentration of gas hydrates is larger than 0.5 vol%.

19. The method according to any one of claims 1 -8, 14-17, comprising increasing a concentration of salt in said remaining hydrocarbon flow or said recycled third fluid flow decreasing a partial water vapor pressure (water dew point) over hydrate in said hydrocarbon flow and controlling the growth of said hydrates.

20. The method according to any one of the previous claims, comprising keeping a temperature in said second separator near or slightly above a minimum temperature in an export pipeline for said dry gas and/or condensate/oil.

21. A method for treating a flow of fluid hydrocarbons containing water, wherein said flow of fluid hydrocarbons is a production flow from at least one wellbore substantially as hereinbefore described with reference to any one of the examples.