EP2622041A1 - Process for separating kinetic hydrate polymer inhibitors - Google Patents

Process for separating kinetic hydrate polymer inhibitors

Info

Publication number
EP2622041A1
EP2622041A1 EP11761076.6A EP11761076A EP2622041A1 EP 2622041 A1 EP2622041 A1 EP 2622041A1 EP 11761076 A EP11761076 A EP 11761076A EP 2622041 A1 EP2622041 A1 EP 2622041A1
Authority
EP
European Patent Office
Prior art keywords
hydrate inhibitor
kinetic hydrate
process according
inhibitor polymer
aqueous mixture
Prior art date
Legal status (The legal status 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 status listed.)
Withdrawn
Application number
EP11761076.6A
Other languages
German (de)
French (fr)
Inventor
Guillo Alexander Schrader
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Original Assignee
Shell Internationale Research Maatschappij BV
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
Application filed by Shell Internationale Research Maatschappij BV filed Critical Shell Internationale Research Maatschappij BV
Priority to EP11761076.6A priority Critical patent/EP2622041A1/en
Publication of EP2622041A1 publication Critical patent/EP2622041A1/en
Withdrawn legal-status Critical Current

Links

Classifications

    • 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
    • C10G25/00—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents
    • C10G25/02—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents with ion-exchange material
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
    • B01D61/02—Reverse osmosis; Hyperfiltration ; Nanofiltration
    • B01D61/027—Nanofiltration
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D61/00—Processes of separation using semi-permeable membranes, e.g. dialysis, osmosis or ultrafiltration; Apparatus, accessories or auxiliary operations specially adapted therefor
    • B01D61/14—Ultrafiltration; Microfiltration
    • B01D61/145—Ultrafiltration
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D71/00—Semi-permeable membranes for separation processes or apparatus characterised by the material; Manufacturing processes specially adapted therefor
    • B01D71/02—Inorganic material
    • B01D71/024—Oxides
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/44—Treatment of water, waste water, or sewage by dialysis, osmosis or reverse osmosis
    • C02F1/444—Treatment of water, waste water, or sewage by dialysis, osmosis or reverse osmosis by ultrafiltration or microfiltration
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/22—Hydrates inhibition by using well treatment fluids containing inhibitors of hydrate formers

Definitions

  • the present invention is directed to a process for separating kinetic hydrate inhibitor polymers having a molecular weight of at least 1000 Da from an aqueous mixture further comprising hydrocarbons and salts.
  • Low-boiling hydrocarbons such as methane, ethane, propane, butane and iso-butane
  • conduits which are used for the transport and processing of natural gas and crude oil. If a substantial amount of water also is present, it is possible that the water/ hydrocarbon mixture form gas hydrate crystals under conditions of low temperature and elevated pressure.
  • Gas hydrates are clathrates (inclusion compounds) in which small hydrocarbon molecules are trapped in a lattice consisting of water molecules. As the maximum temperature at which gas hydrates can be formed strongly depends on the pressure of the system, hydrates are markedly
  • Melting point depressants also are referred to as
  • thermodynamic hydrate inhibitors thermodynamic hydrate inhibitors.
  • kinetic hydrate inhibitors which prevent the formation of hydrates on a macroscopic scale, i.e. as observable by the naked eye
  • hydrate anti-agglomerants which are capable of preventing agglomeration of hydrate crystals.
  • already small amounts of kinetic hydrate inhibitors or hydrate anti-agglomerants are normally effective in preventing the blockage of a conduit by hydrates.
  • Liquefied natural gas is natural gas (predominantly methane) that has been converted temporarily to liquid form for ease of storage or transport.
  • the actual practice of removing these compounds is quite complex but usually involves condensate removal, water removal, separation of natural gas liquids and sulfur containing compounds and carbon dioxide removal.
  • hydrate inhibitor polymers are often added to raw natural gas streams before pipeline transport or any further treatment. These hydrate inhibitor polymers generally are separated and removed before liquefaction as there they can create problems such as depositing on heat exchanger equipment. Furthermore, the presence of hydrate
  • treatment as such treatment may not be able to deal with these polymers in that the polymers may be poorly bio- degradable and/or tend to block the pores of water treatment filtration equipment.
  • hydrate inhibitor polymers have the property that their solubility in water decreases with increasing temperature and therefore they exhibit reverse solubility versus temperature behavior. This phenomenon is especially well known for glycols.
  • the cloud point temperature of hydrate inhibitor polymers is the temperature above which the mixture starts to phase separate and two phases appear for a given polymer concentration and at given salinity. There are even less methods for removing these kinds of polymers as their removal is restricted by the maximum operating temperature which can be applied.
  • US-A-2008/0312478 describes a method for removing kinetic inhibitors from an aqueous phase which method involves heating the aqueous phase to a temperature above the boiling point of the water. This separation method is disadvantageous from an energy efficiency point of view while it could lead to problems in removing a polymer having a cloud point below the distillation temperature.
  • concentration of kinetic hydrate inhibitor polymer is at most 20 % of the kinetic hydrate inhibitor polymer concentration of the aqueous mixture. It is preferred that the concentration of hydrate inhibitor polymer of the permeate is at most 15 %, more preferably at most 10 %, more specifically at most 5 % of the kinetic hydrate inhibitor polymer as present in the aqueous mixture.
  • the membranes preferably are ceramic membranes, more specifically refractory oxide membranes, most preferably zirconia and/or titania ceramic membranes. Ceramic membranes which have been found to be especially
  • preferred for use in the present invention are those having a pore diameter of at least 0.7 nm, more
  • the pore diameter is at most 3.5 nm, more specifically at most 3.3 nm, most specifically at most 3.1 nm.
  • the pore diameter is
  • membranes which have been found to be suitable are titania membranes having an average pore diameter of from 0.9 nm up to and including 1.0 nm and zirconia ceramic membranes having an average pore diameter of 3.0 nm. The choice of the pore size is determined by the pressure drop over the membrane which is acceptable and the amount of feed to be recovered as permeate .
  • a further advantage of the above process is that it has been found that by choosing the right pore diameter for the membrane, hydrocarbons can be removed besides the kinetic hydrate inhibitor polymer while salts are allowed through.
  • the presence of hydrocarbons in the retentate is advantageous in that it makes the permeate water even purer.
  • the hydrocarbonaceous retentate comprising kinetic hydrate inhibitor polymer can either be sent to an incinerator, wet air oxidation unit, supercritical water oxidation unit or be recycled. Recycling has the
  • hydrocarbons will become part of the hydrocarbonaceous phase instead of the aqueous phase.
  • Another advantage of the process according to the present invention is that salts can be removed as part of the permeate.
  • the salts are separated from the kinetic hydrate inhibitor polymer which prevents build-up of salts in case of recycling the kinetic hydrate inhibitor polymer.
  • the retentate generally will be a kinetic hydrate inhibitor polymer containing water/hydrocarbon mixture.
  • the exact amount of water in the retentate depends on the process conditions applied. If the viscosity of the retentate is high, it can be preferred to add solvent to the retentate before it is processed further such as by recycling .
  • the kinetic hydrate inhibitor polymer for use in the present invention preferably is a water-soluble polymer having a molecular weight of at least 1000 Da, preferably of at least 1500 Da, more specifically at least 2000 Da, more preferably at least 3000 Da.
  • the molecular weight is the weight average molecular weight which can be
  • a further characteristic of hydrate inhibitor polymers is that they inhibit hydrocarbon molecules becoming trapped in a water lattice.
  • the structure of such compounds can vary widely.
  • these polymers are water-soluble polymers containing at least one amide group, preferably comprising a plurality of amide groups.
  • the polymers can be either homopolymers or copolymers containing amide groups.
  • the kinetic hydrate inhibitor polymers preferably are polyamides and/or polyester amides.
  • the expression polymers indicates any large molecule having the
  • Such polymer can contain a large number of small repeat units.
  • An example of a linear polyamide hydrate inhibitor polymer is polyvinyl pyrrolidone.
  • the polymer can be a hyper- branched, also referred to as dendritic, polymer which is functionalized to provide the necessary properties.
  • Preferred hydrate inhibitors are dendrimeric
  • a branch is composed of structural units which are bound radially to the core and which extend outwards.
  • the structural units have at least two reactive monofunctional groups and/or at least one monofunctional group and one multifunctional group.
  • the term multifunctional is understood as having a
  • hydrate inhibitors are dendrimeric polyester amides, more specifically those as described in WO-A-2001/77270.
  • HYBRANE S1200 and HYBRA E HA1300 are especially preferred. These compounds are commercially obtainable from DSM, Geleen, the
  • the dendrimeric compounds as a solution of the compound in an organic solvent such as an alcohol .
  • the separation of kinetic hydrate inhibitor polymers can be carried out under process conditions
  • the pressure perpendicular to the membrane at the retentate side preferably is at most 60 bara.
  • kinetic hydrate inhibitor polymer preferably is at most 90 °C. If the kinetic hydrate inhibitor polymer has a cloud point under actual
  • the operating temperature preferably is at most 60 °C, more specifically at most 50 °C. Sufficient cross-flow should be applied during operation to minimize build-up of polymeric contaminants.
  • a process into which the present invention can be incorporated is a process comprising
  • step (a) adding a kinetic hydrate inhibitor polymer having a molecular weight of at least 1000 Da to raw natural gas, (b) sending the mixture obtained in step (a) to a slug- catcher, and
  • step (c) separating the kinetic hydrate inhibitor polymer from at least part of the product of step (b) in a process according to the present invention.
  • the kinetic hydrate inhibitor polymer containing retentate obtained in step (c) can be added to raw natural gas either as such or after having been treated further .
  • the product of the slug catcher can be sent to a phase separator in which the mixture is separated into a hydrocarbonaceous gas, a liquid hydrocarbonaceous
  • step (c) only the bottom aqueous fraction is to be subjected to the process according to the present invention in step (c) .
  • the permeate obtained in step (c) preferably is subsequently subjected to condensate removal, water removal, separation of natural gas liquids and sulfur and carbon dioxide removal before being transported and/or liquefied .
  • Raw natural gas is gas as obtained from underground gas fields or extracted at the surface from the fluids produced from oil wells.
  • the temperature and pressure of the raw natural can vary widely.
  • the kinetic hydrate inhibitor polymer can be added to the raw natural gas in any way known to be suitable by someone skilled in the art.
  • the kinetic hydrate inhibitor is added as a solution as this
  • the slug catcher for use in step (b) is a vessel with sufficient buffer volume to store plugs of liquid, called slugs, which exit the pipeline.
  • the slug catcher feeds liquid at a lower rate to downstream processing units which prevents liquid overload of those units.
  • a phase separator which is optionally used for further treating the product of step (b) preferably is a three-phase separator comprising a normally horizontal vessel defining a liquid separation space and a gas space, which vessel has an inlet end space provided with a feed inlet and an outlet end space provided with separate outlets for the gaseous, the hydrocarbonaceous and the aqueous phase.
  • a preferred separator has been described in US patent specification 6537458.
  • Stripping involves treating the aqueous mixture with an inert gas such as clean natural gas or steam to remove gaseous hydrocarbons such as dissolved sour gases for example hydrogen sulphide. Steam is often used in a heated column. It has been found that stripping of the aqueous mixture can facilitate the membrane separation.
  • an inert gas such as clean natural gas or steam to remove gaseous hydrocarbons such as dissolved sour gases for example hydrogen sulphide. Steam is often used in a heated column. It has been found that stripping of the aqueous mixture can facilitate the membrane separation.
  • Another option is to treat the aqueous solution in the process according to the present invention and subsequently subject the permeate to stripping. This has the advantage that the kinetic hydrate inhibitor polymer will not interfere in the stripping column. Circumstances such as the line-up and kinetic hydrate inhibitor polymer applied, determine whether stripping is to be applied and if so, whether it is to be applied before or after the membrane treatment.

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Water Supply & Treatment (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Nanotechnology (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Inorganic Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Addition Polymer Or Copolymer, Post-Treatments, Or Chemical Modifications (AREA)
  • Separation Using Semi-Permeable Membranes (AREA)

Abstract

Process for separating kinetic hydrate inhibitor polymers having a molecular weight of at least 1000 Da from an aqueous mixture further comprising hydrocarbons and salts which process comprises contacting the aqueous mixture with the feed side of a membrane having an average pore diameter of from 0.7 to 4nm, and obtaining at the permeate side of the membrane an aqueous permeate of which the concentration of kinetic hydrate inhibitor polymer is at most 20 % of that of the aqueous mixture.

Description

PROCESS FOR SEPARATING KINETIC HYDRATE POLYMER INHIBITORS
The present invention is directed to a process for separating kinetic hydrate inhibitor polymers having a molecular weight of at least 1000 Da from an aqueous mixture further comprising hydrocarbons and salts.
Low-boiling hydrocarbons, such as methane, ethane, propane, butane and iso-butane, are normally present in conduits which are used for the transport and processing of natural gas and crude oil. If a substantial amount of water also is present, it is possible that the water/ hydrocarbon mixture form gas hydrate crystals under conditions of low temperature and elevated pressure. Gas hydrates are clathrates (inclusion compounds) in which small hydrocarbon molecules are trapped in a lattice consisting of water molecules. As the maximum temperature at which gas hydrates can be formed strongly depends on the pressure of the system, hydrates are markedly
different from ice.
Gas hydrate crystals which grow inside a conduit such as a pipeline are known to be able to block or even damage the conduit. In order to cope with this undesired phenomenon, a number of remedies has been proposed in the past such as removal of free water, maintaining elevated temperatures and/or reduced pressures or the addition of chemicals such as melting point depressants (anti- freezes) . Melting point depressants, typical examples of which are methanol and various glycols, often have to be added in substantial amounts, typically in the order of several tens of percent by weight of the water present, in order to be effective. This is disadvantageous with respect to costs of the materials, their storage
facilities and their recovery which is rather expensive. Melting point depressants also are referred to as
thermodynamic hydrate inhibitors.
Another approach to keep the fluids in the conduits flowing is the addition of kinetic hydrate inhibitors which prevent the formation of hydrates on a macroscopic scale, i.e. as observable by the naked eye, and/or hydrate anti-agglomerants which are capable of preventing agglomeration of hydrate crystals. Compared to the amounts of antifreeze required, already small amounts of kinetic hydrate inhibitors or hydrate anti-agglomerants are normally effective in preventing the blockage of a conduit by hydrates.
Liquefied natural gas is natural gas (predominantly methane) that has been converted temporarily to liquid form for ease of storage or transport. Water, hydrogen sulfide, carbon dioxide and other components that will freeze under the low temperatures needed for storage or that will be destructive to the liquefaction facility, have to be removed beforehand. The actual practice of removing these compounds is quite complex but usually involves condensate removal, water removal, separation of natural gas liquids and sulfur containing compounds and carbon dioxide removal. To prevent hydrate formation, hydrate inhibitor polymers are often added to raw natural gas streams before pipeline transport or any further treatment. These hydrate inhibitor polymers generally are separated and removed before liquefaction as there they can create problems such as depositing on heat exchanger equipment. Furthermore, the presence of hydrate
inhibitors becomes unnecessary as soon as the system operates outside the stable hydrate conditions. If these kinetic hydrate inhibitor polymers are present in the produced aqueous phase, they may have to be removed from the aqueous phase before conventional waste water
treatment as such treatment may not be able to deal with these polymers in that the polymers may be poorly bio- degradable and/or tend to block the pores of water treatment filtration equipment.
However, removal of hydrate inhibitor polymers from waste water has been found to be difficult. The choice in removal methods furthermore is limited because these polymers may deposit on the equipment used if the salt concentration is too high and/or the temperature of the aqueous solution is too low. Some hydrate inhibitor polymers have the property that their solubility in water decreases with increasing temperature and therefore they exhibit reverse solubility versus temperature behavior. This phenomenon is especially well known for glycols. In the present application, the cloud point temperature of hydrate inhibitor polymers is the temperature above which the mixture starts to phase separate and two phases appear for a given polymer concentration and at given salinity. There are even less methods for removing these kinds of polymers as their removal is restricted by the maximum operating temperature which can be applied.
US-A-2008/0312478 describes a method for removing kinetic inhibitors from an aqueous phase which method involves heating the aqueous phase to a temperature above the boiling point of the water. This separation method is disadvantageous from an energy efficiency point of view while it could lead to problems in removing a polymer having a cloud point below the distillation temperature.
It has now surprisingly been found that kinetic hydrate inhibitor polymers having a molecular weight of at least 1000 dalton (Da) can be removed from an aqueous mixture further comprising hydrocarbons and salts by the process according to the present invention which
comprises contacting the aqueous mixture with the feed side of a membrane having an average pore diameter of from 0.7 to 4 nm, and obtaining at the permeate side of the membrane an aqueous permeate of which the
concentration of kinetic hydrate inhibitor polymer is at most 20 % of the kinetic hydrate inhibitor polymer concentration of the aqueous mixture. It is preferred that the concentration of hydrate inhibitor polymer of the permeate is at most 15 %, more preferably at most 10 %, more specifically at most 5 % of the kinetic hydrate inhibitor polymer as present in the aqueous mixture.
The membranes preferably are ceramic membranes, more specifically refractory oxide membranes, most preferably zirconia and/or titania ceramic membranes. Ceramic membranes which have been found to be especially
preferred for use in the present invention are those having a pore diameter of at least 0.7 nm, more
specifically at least 0.8 nm, most specifically at least 0.9 nm. Further, it is preferred that the pore diameter is at most 3.5 nm, more specifically at most 3.3 nm, most specifically at most 3.1 nm. The pore diameter is
measured by the method described in the article by Cao, G.Z., Meijerink, J., Brinkman, H.W. and Burggraaf, A.J. (1993) : Permporometry study on the size distribution of active pores in porous ceramic membranes, J. Membr. Sci.
83, no. 2: pp. 221-235. Specific membranes which have been found to be suitable are titania membranes having an average pore diameter of from 0.9 nm up to and including 1.0 nm and zirconia ceramic membranes having an average pore diameter of 3.0 nm. The choice of the pore size is determined by the pressure drop over the membrane which is acceptable and the amount of feed to be recovered as permeate .
A further advantage of the above process is that it has been found that by choosing the right pore diameter for the membrane, hydrocarbons can be removed besides the kinetic hydrate inhibitor polymer while salts are allowed through. The presence of hydrocarbons in the retentate is advantageous in that it makes the permeate water even purer. The hydrocarbonaceous retentate comprising kinetic hydrate inhibitor polymer can either be sent to an incinerator, wet air oxidation unit, supercritical water oxidation unit or be recycled. Recycling has the
advantage that it allows inhibitor polymers to be used again and will make that some of the recycled
hydrocarbons will become part of the hydrocarbonaceous phase instead of the aqueous phase.
Another advantage of the process according to the present invention is that salts can be removed as part of the permeate. In such case, the salts are separated from the kinetic hydrate inhibitor polymer which prevents build-up of salts in case of recycling the kinetic hydrate inhibitor polymer.
The retentate generally will be a kinetic hydrate inhibitor polymer containing water/hydrocarbon mixture. The exact amount of water in the retentate depends on the process conditions applied. If the viscosity of the retentate is high, it can be preferred to add solvent to the retentate before it is processed further such as by recycling .
The kinetic hydrate inhibitor polymer for use in the present invention preferably is a water-soluble polymer having a molecular weight of at least 1000 Da, preferably of at least 1500 Da, more specifically at least 2000 Da, more preferably at least 3000 Da. The molecular weight is the weight average molecular weight which can be
determined by someone skilled in the art with the help of chromatography as described by ASTM method D5296-05. A further characteristic of hydrate inhibitor polymers is that they inhibit hydrocarbon molecules becoming trapped in a water lattice. The structure of such compounds can vary widely. Preferably, these polymers are water-soluble polymers containing at least one amide group, preferably comprising a plurality of amide groups. The polymers can be either homopolymers or copolymers containing amide groups. The kinetic hydrate inhibitor polymers preferably are polyamides and/or polyester amides. The expression polymers indicates any large molecule having the
indicated molecular weight. Such polymer can contain a large number of small repeat units. An example of a linear polyamide hydrate inhibitor polymer is polyvinyl pyrrolidone. Alternatively, the polymer can be a hyper- branched, also referred to as dendritic, polymer which is functionalized to provide the necessary properties.
Preferred hydrate inhibitors are dendrimeric
compounds which are three-dimensional, highly branched molecules comprising a core and two or more branches. The end of the branches preferably is functionalized, more specifically by containing an end-group comprising both nitrogen and oxygen. A branch is composed of structural units which are bound radially to the core and which extend outwards. The structural units have at least two reactive monofunctional groups and/or at least one monofunctional group and one multifunctional group. The term multifunctional is understood as having a
functionality of 2 or higher. To each functionality a new structural unit may be linked, a higher branching
generation being produced as a result. Most preferred hydrate inhibitors are dendrimeric polyester amides, more specifically those as described in WO-A-2001/77270.
Examples of a specific class of dendrimeric compounds are the compounds commercially referred to as HYBRANES (the word HYBRANE is a trademark) . Of these, HYBRANE S1200 and HYBRA E HA1300 are especially preferred. These compounds are commercially obtainable from DSM, Geleen, the
Netherlands .
It is preferred to use the dendrimeric compounds as a solution of the compound in an organic solvent such as an alcohol .
The separation of kinetic hydrate inhibitor polymers can be carried out under process conditions
conventionally applied for membrane filtration processes.
The pressure perpendicular to the membrane at the retentate side preferably is at most 60 bara. The
temperature of the aqueous mixture from which the kinetic hydrate inhibitor polymers are to be separated,
preferably is at most 90 °C. If the kinetic hydrate inhibitor polymer has a cloud point under actual
operating conditions, it should be ensured that the operating temperature is below the cloud point. The actual operating temperature preferably is at most 60 °C, more specifically at most 50 °C. Sufficient cross-flow should be applied during operation to minimize build-up of polymeric contaminants. The percentage of kinetic hydrate inhibitor polymer removed in the process
according to the present invention is to be measured at 15 bara operating pressure and at 15 %wt recovery of the aqueous mixture supplied.
A process into which the present invention can be incorporated is a process comprising
(a) adding a kinetic hydrate inhibitor polymer having a molecular weight of at least 1000 Da to raw natural gas, (b) sending the mixture obtained in step (a) to a slug- catcher, and
(c) separating the kinetic hydrate inhibitor polymer from at least part of the product of step (b) in a process according to the present invention.
The kinetic hydrate inhibitor polymer containing retentate obtained in step (c) can be added to raw natural gas either as such or after having been treated further .
The product of the slug catcher can be sent to a phase separator in which the mixture is separated into a hydrocarbonaceous gas, a liquid hydrocarbonaceous
fraction and a bottom aqueous fraction. In such case, only the bottom aqueous fraction is to be subjected to the process according to the present invention in step (c) .
The permeate obtained in step (c) preferably is subsequently subjected to condensate removal, water removal, separation of natural gas liquids and sulfur and carbon dioxide removal before being transported and/or liquefied .
Raw natural gas is gas as obtained from underground gas fields or extracted at the surface from the fluids produced from oil wells. The temperature and pressure of the raw natural can vary widely.
The kinetic hydrate inhibitor polymer can be added to the raw natural gas in any way known to be suitable by someone skilled in the art. Preferably, the kinetic hydrate inhibitor is added as a solution as this
facilitates mixing of the inhibitor with the fluid. It is possible to add further oil-field chemicals such as corrosion and scale inhibitors and demulsifiers . If any of these compounds are polymers of sufficiently high weight, these polymers can also be recovered in the process according to the present invention and also can be recycled.
The slug catcher for use in step (b) is a vessel with sufficient buffer volume to store plugs of liquid, called slugs, which exit the pipeline. The slug catcher feeds liquid at a lower rate to downstream processing units which prevents liquid overload of those units.
A phase separator which is optionally used for further treating the product of step (b) preferably is a three-phase separator comprising a normally horizontal vessel defining a liquid separation space and a gas space, which vessel has an inlet end space provided with a feed inlet and an outlet end space provided with separate outlets for the gaseous, the hydrocarbonaceous and the aqueous phase. A preferred separator has been described in US patent specification 6537458.
It can be advantageous to strip the product of the slug catcher and/or the phase separator before subjecting it to the process of the present invention. Stripping involves treating the aqueous mixture with an inert gas such as clean natural gas or steam to remove gaseous hydrocarbons such as dissolved sour gases for example hydrogen sulphide. Steam is often used in a heated column. It has been found that stripping of the aqueous mixture can facilitate the membrane separation.
Another option is to treat the aqueous solution in the process according to the present invention and subsequently subject the permeate to stripping. This has the advantage that the kinetic hydrate inhibitor polymer will not interfere in the stripping column. Circumstances such as the line-up and kinetic hydrate inhibitor polymer applied, determine whether stripping is to be applied and if so, whether it is to be applied before or after the membrane treatment.
The various fractions obtained in the process of the present invention can be treated further as known to the skilled person to be advantageous for a given set of circumstances .

Claims

C L A I M S
1. Process for separating kinetic hydrate inhibitor polymer having a molecular weight of at least 1000 Da from an aqueous mixture further comprising hydrocarbons and salts which process comprises contacting the aqueous mixture with the feed side of a membrane having an average pore diameter of from 0.7 to 4 nm, and obtaining at the permeate side of the membrane an aqueous permeate of which the concentration of kinetic hydrate inhibitor polymer is at most 20 % of the kinetic hydrate inhibitor polymer concentration of the aqueous mixture.
2. Process according to claim 1, wherein the membrane is a ceramic membrane having a pore diameter of from 0.9 to 3 nm.
3. Process according to claim 2, wherein the kinetic hydrate inhibitor polymer has a molecular weight of at least 1500 Da.
4. Process according to any one of claims 1-3, wherein the kinetic hydrate inhibitor polymer is chosen from the group consisting of homopolymers and copolymers
containing amide groups .
5. Process according to any one of claims 1-4, wherein the temperature of the aqueous mixture is at most 90 °C.
6. Process according to any one of claims 1-5, wherein the aqueous mixture comprises liquid natural gas
condensate .
7. Process according to any one of claims 1-6, wherein the kinetic hydrate inhibitor polymer is a dendrimeric compound .
8. Process comprising
(a) adding a kinetic hydrate inhibitor polymer having a molecular weight of at least 1000 Da to raw natural gas,
(b) sending the mixture obtained in step (a) to a slug- catcher, and
(c) separating kinetic hydrate inhibitor polymer from least part of the product of step (b) in a process according to any one of claims 1 to 7.
EP11761076.6A 2010-09-27 2011-09-23 Process for separating kinetic hydrate polymer inhibitors Withdrawn EP2622041A1 (en)

Priority Applications (1)

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EP11761076.6A EP2622041A1 (en) 2010-09-27 2011-09-23 Process for separating kinetic hydrate polymer inhibitors

Applications Claiming Priority (3)

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EP10180196 2010-09-27
PCT/EP2011/066612 WO2012041785A1 (en) 2010-09-27 2011-09-23 Process for separating kinetic hydrate polymer inhibitors
EP11761076.6A EP2622041A1 (en) 2010-09-27 2011-09-23 Process for separating kinetic hydrate polymer inhibitors

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US (1) US20140144810A1 (en)
EP (1) EP2622041A1 (en)
AU (1) AU2011310681A1 (en)
RU (1) RU2013119654A (en)
WO (1) WO2012041785A1 (en)

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