WO2011112102A1 - Traitement d'hydrocarbures liquides produits contenant de l'eau - Google Patents

Traitement d'hydrocarbures liquides produits contenant de l'eau Download PDF

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Publication number
WO2011112102A1
WO2011112102A1 PCT/NO2011/000081 NO2011000081W WO2011112102A1 WO 2011112102 A1 WO2011112102 A1 WO 2011112102A1 NO 2011000081 W NO2011000081 W NO 2011000081W WO 2011112102 A1 WO2011112102 A1 WO 2011112102A1
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WO
WIPO (PCT)
Prior art keywords
flow
separator
fluid
water
gas
Prior art date
Application number
PCT/NO2011/000081
Other languages
English (en)
Inventor
Are Lund
Roar Larsen
Jon Harald Kaspersen
Erlend Oddvin Straume
Martin Fossen
Kai W. Hjarbo
Original Assignee
Sinvent As
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US12/761,039 external-priority patent/US9068451B2/en
Application filed by Sinvent As filed Critical Sinvent As
Priority to DKPA201200561A priority Critical patent/DK201200561A/da
Priority to RU2012143399/04A priority patent/RU2553664C2/ru
Priority to BR112012022730A priority patent/BR112012022730A2/pt
Priority to AU2011224929A priority patent/AU2011224929B2/en
Publication of WO2011112102A1 publication Critical patent/WO2011112102A1/fr
Priority to NO20121114A priority patent/NO20121114A1/no

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17D—PIPE-LINE SYSTEMS; PIPE-LINES
    • F17D3/00—Arrangements for supervising or controlling working operations
    • F17D3/14—Arrangements for supervising or controlling working operations for eliminating water
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D9/00—Crystallisation
    • B01D9/0004—Crystallisation cooling by heat exchange
    • B01D9/0009—Crystallisation cooling by heat exchange by direct heat exchange with added cooling fluid
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D9/00—Crystallisation
    • B01D9/005—Selection of auxiliary, e.g. for control of crystallisation nuclei, of crystal growth, of adherence to walls; Arrangements for introduction thereof
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
    • C10G31/06—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by heating, cooling, or pressure treatment
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G33/00—Dewatering or demulsification of hydrocarbon oils
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G5/00—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas
    • C10G5/06—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas by cooling or compressing
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G70/00—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00
    • C10G70/04—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes
    • C10G70/044—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes by crystallisation
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/108—Production of gas hydrates
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1025—Natural gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1029—Gas hydrates
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4081—Recycling aspects

Definitions

  • the invention concerns a system for treating a flow of fluid hydrocarbons containing water, and a method for such treatment.
  • MEG monoetylene glycol
  • 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.
  • US 6,774,276 is used as one possible way to precipitate hydrate particles from the water in the system.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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, 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.
  • 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.
  • 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
  • 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
  • the system may accordingly contain a means for adding such chemicals to the flow.
  • 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
  • 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.
  • 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
  • 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
  • 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.
  • 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.
  • separator (3) the temperature is sufficiently high (20° C or higher) to melt all incoming hydrates into free water.
  • separator (3) most free water (more than 99%) is separated from the production flow (1).
  • 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.
  • 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 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.
  • 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.
  • 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).
  • liquid condensate and free water is separated from the production flow (1).
  • 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).
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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
  • 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).
  • 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).
  • separator (15) 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
  • 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.
  • 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
  • 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.
  • 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.
  • a higher salinity in the water at the start of the crystal growth process 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.
  • 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 ( 1 ) 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.
  • satellite wells may be connected to (10) or ( 1 ) without any previous treatment, only limited by the hydrate melting capacity in separator (3).
  • Figure 4 shows a conceptual view for a system where the water has some concentration of salt or other thermodynamic inhibitor.
  • 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 c 2 .
  • the temperature, T 2 is slightly lower than Ti (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.
  • the new salt concentration in the now trapped water layer, c 4 is higher than c 3 , (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, c 4 increases, and core melting continues).
  • 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, 201-21 1] 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).
  • 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).
  • one way to break up the hydrate shells is by adding fresh or salt water to the system.
  • 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.
  • the same action may be used as a flocculation help - making particles stick more together through the effect of water bridging.
  • 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.
  • 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 mixture is flowed through a pipeline (11) which utilizes heat exchange with cold outside water (or air) as a means of cooling.
  • a pipeline (11) which utilizes heat exchange with cold outside water (or air) as a means of cooling.
  • 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 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).
  • hydrate slurry from the cold separator may be pumped to the warm separator (3) for melting back to gas, condensate, and water.
  • 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
  • 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).
  • cooling loop (11) 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
  • the production flow (1) containing oil, gas, water, and/or condensate, is choked (2) down to a suitable pressure, if needed.
  • 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.
  • 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 gas outlet (6) from the cold separator (12) consists of cooled gas, dry enough for direct export, as in previous examples.
  • the gas may be flared or otherwise disposed of.
  • 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).
  • 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.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
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  • General Chemical & Material Sciences (AREA)
  • Crystallography & Structural Chemistry (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Physical Water Treatments (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

L'invention porte sur un procédé pour le traitement d'un flux d'hydrocarbures liquides contenant de l'eau, le flux d'hydrocarbures liquides étant introduit dans un premier séparateur séparant au moins l'eau libre dudit flux d'hydrocarbures liquides, le reste dudit flux d'hydrocarbures liquides étant introduit dans un système convertissant l'eau libre/condensée présente dans le flux d'hydrocarbures liquides dans ledit système en hydrates de gaz, et produisant au moins un premier flux de liquides et un second flux de liquides, ledit premier flux de liquides étant une phase liquide comportant des hydrates de gaz, ledit premier flux de liquides étant recyclé dans le premier séparateur, et le second flux de liquides ayant une teneur en gaz sec et/ou en condensat/huile. L'invention porte également sur un système de traitement d'un flux d'hydrocarbures liquides contenant de l'eau, ledit système comprenant les éléments suivants énumérés dans le sens de la circulation et reliés les uns aux autres : un raccordement à une source de production d'hydrocarbures (1), un premier séparateur (3) pouvant fonctionner pour séparer au moins l'eau libre dudit flux de liquides, un système de conversion (5) pour la conversion de l'eau libre/condensée en hydrates de gaz, une canalisation (6, 18) pour le transport d'un gaz sec ou d'un condensat/huile, et en plus une conduite (7) qui mène du système de conversion (5) vers le premier séparateur (3) fournissant un premier flux de recyclage comportant des hydrates de gaz.
PCT/NO2011/000081 2010-03-11 2011-03-11 Traitement d'hydrocarbures liquides produits contenant de l'eau WO2011112102A1 (fr)

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DKPA201200561A DK201200561A (en) 2010-03-11 2011-03-11 Treatment of produced hydrocarbon fluid containing water
RU2012143399/04A RU2553664C2 (ru) 2010-03-11 2011-03-11 Обработка потока жидких углеводородов, содержащего воду
BR112012022730A BR112012022730A2 (pt) 2010-03-11 2011-03-11 método de tratamento de fluxo de hidrocarbonetos fluidos que contém água e sistema de tratamento de fluxo de hidrocarboneto fluidos que contém água
AU2011224929A AU2011224929B2 (en) 2010-03-11 2011-03-11 Treatment of produced hydrocarbon fluid containing water
NO20121114A NO20121114A1 (no) 2010-03-11 2012-10-01 Behandling av produsert hydrokarbonfluid inneholdende vann

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US12/761,039 US9068451B2 (en) 2010-03-11 2010-04-15 Treatment of produced hydrocarbon fluid containing water
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WO2015142629A1 (fr) * 2014-03-17 2015-09-24 Shell Oil Company Systèmes de production de condensats gazeux fonctionnant avec de longues distances de décalage
WO2017020096A1 (fr) * 2015-08-06 2017-02-09 Subcool Technologies Pty Ltd Système et procédé de traitement de gaz naturel produit à partir d'un puits sous-marin
CN109899326A (zh) * 2019-03-27 2019-06-18 中国石油大学(华东) 一种油田伴生气用离心压缩机的在线流道除垢方法
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CN110408445A (zh) * 2019-07-03 2019-11-05 北京科技大学 一种井口天然气脱水除湿装置和方法
RU2765440C1 (ru) * 2021-01-11 2022-01-31 Общество с ограниченной ответственностью "Газпром добыча Уренгой" Способ оптимизации процесса подготовки товарного конденсата и устройство для его осуществления

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WO2015142629A1 (fr) * 2014-03-17 2015-09-24 Shell Oil Company Systèmes de production de condensats gazeux fonctionnant avec de longues distances de décalage
CN106103885A (zh) * 2014-03-17 2016-11-09 国际壳牌研究有限公司 长距气体冷凝物生产系统
US10578128B2 (en) 2014-09-18 2020-03-03 General Electric Company Fluid processing system
WO2017020096A1 (fr) * 2015-08-06 2017-02-09 Subcool Technologies Pty Ltd Système et procédé de traitement de gaz naturel produit à partir d'un puits sous-marin
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RU2553664C2 (ru) 2015-06-20
BR112012022730A2 (pt) 2018-06-26
RU2012143399A (ru) 2014-04-20
AU2011224929A1 (en) 2012-11-08

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