WO2020130850A1 - A method for desalting produced hydrocarbons - Google Patents
A method for desalting produced hydrocarbons Download PDFInfo
- Publication number
- WO2020130850A1 WO2020130850A1 PCT/NO2019/050286 NO2019050286W WO2020130850A1 WO 2020130850 A1 WO2020130850 A1 WO 2020130850A1 NO 2019050286 W NO2019050286 W NO 2019050286W WO 2020130850 A1 WO2020130850 A1 WO 2020130850A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- water
- salinity
- reduced
- produced hydrocarbons
- produced
- Prior art date
Links
- 229930195733 hydrocarbon Natural products 0.000 title claims abstract description 98
- 150000002430 hydrocarbons Chemical class 0.000 title claims abstract description 98
- 238000000034 method Methods 0.000 title claims abstract description 27
- 238000011033 desalting Methods 0.000 title claims abstract description 21
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 90
- 238000004519 manufacturing process Methods 0.000 claims abstract description 58
- 239000012530 fluid Substances 0.000 claims description 34
- 238000002347 injection Methods 0.000 claims description 6
- 239000007924 injection Substances 0.000 claims description 6
- 239000007764 o/w emulsion Substances 0.000 claims description 5
- 239000007762 w/o emulsion Substances 0.000 claims description 4
- 239000013535 sea water Substances 0.000 claims description 3
- 239000007788 liquid Substances 0.000 description 20
- 239000007789 gas Substances 0.000 description 12
- 238000000926 separation method Methods 0.000 description 9
- 235000002639 sodium chloride Nutrition 0.000 description 8
- 239000013505 freshwater Substances 0.000 description 7
- 150000003839 salts Chemical class 0.000 description 7
- 230000015572 biosynthetic process Effects 0.000 description 6
- 238000003860 storage Methods 0.000 description 6
- 239000000839 emulsion Substances 0.000 description 5
- 239000000126 substance Substances 0.000 description 5
- 239000012535 impurity Substances 0.000 description 4
- 239000004215 Carbon black (E152) Substances 0.000 description 3
- 238000010924 continuous production Methods 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 230000005684 electric field Effects 0.000 description 2
- 239000008398 formation water Substances 0.000 description 2
- 150000007524 organic acids Chemical class 0.000 description 2
- 235000005985 organic acids Nutrition 0.000 description 2
- 150000002902 organometallic compounds Chemical class 0.000 description 2
- 239000011435 rock Substances 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 241000191291 Abies alba Species 0.000 description 1
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 1
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 1
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 1
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical class [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 239000011575 calcium Substances 0.000 description 1
- 229910052791 calcium Inorganic materials 0.000 description 1
- 235000011148 calcium chloride Nutrition 0.000 description 1
- 239000004020 conductor Substances 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000010790 dilution Methods 0.000 description 1
- 239000012895 dilution Substances 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- -1 oil Chemical class 0.000 description 1
- 235000011164 potassium chloride Nutrition 0.000 description 1
- 230000035484 reaction time Effects 0.000 description 1
- 238000007670 refining Methods 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 229910052708 sodium Inorganic materials 0.000 description 1
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
- C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
- C10G31/08—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by treating with water
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/38—Arrangements for separating materials produced by the well in the well
-
- 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
- C10G2300/1033—Oil well production fluids
-
- 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
- C10G2300/4037—In-situ processes
Definitions
- the present invention relates to the treatment of produced hydrocarbons, and in particular to desalting in produced hydrocarbons.
- Liquid hydrocarbons are typically produced from a reservoir in a formation, and are conveyed from the reservoir via a production well.
- Produced liquid hydrocarbons typically contain a variety of impurities and/or foreign substances.
- impurities and/or foreign substances include water, salts (which may be contained in the water), gases, organometallic compounds and organic acids, and solids.
- the liquid hydrocarbons are typically processed at a processing facility.
- Typical processing steps performed at the processing facility include gas/liquid separation, oil/water separation, and desalting.
- the desalting step may form part of the oil/water separation step.
- One desalting method involves the addition of fresh (i.e. reduced-salinity or low-salinity) water to dilute high-salinity formation/produced water contained in the produced liquid hydrocarbons.
- the fresh water is mixed into the liquid hydrocarbon to dilute the high-salinity formation/produced water.
- the mixing intensity applied during addition of fresh water results in water-in-oil (WiO) emulsions, and contact between the high-salinity formation water and the added fresh water.
- WiO water-in-oil
- the mixing efficiency is known to reach maximum levels of ⁇ 75% during operation. However, the mixing efficiency is often much lower and in the range of 10-40% for one-stage desalting, meaning that only 10 to 40% of the added fresh water can contribute to reducing the salinity of the produced water. A low E value will increase the quantity of fresh water required to obtain sufficient desalting.
- the emulsion formed can contain water droplets with varying salinity.
- the water can be separated from the liquid hydrocarbon using gravitational forces or using an electrical field (electrocoalescence) to meet market-acceptable levels of water and salt.
- an electrical field for example in a coalescer, which is a vessel with internal electrodes.
- the oil may therefore still contain undesirable amounts of salt following the desalting procedure.
- a method for desalting produced hydrocarbons comprises injecting reduced-salinity water into produced hydrocarbons in a production well or riser, to dilute high-salinity produced water contained in the produced hydrocarbons.
- the reduced-salinity water may have a salinity lower than seawater in a body of water above a field in which the production well is located, and/or has a salinity lower than the high-salinity produced water.
- the reduced-salinity water may have a salinity of less than 60 000 mg/L, preferably less than 55 000 mg/L, more preferably less than 40 000 mg/L, and still more preferably less than 31 000 mg/L.
- the reduced-salinity water may be injected into the produced hydrocarbons through one or more openings in production tubing located in the production well, or one or more openings in the riser.
- the one or more openings in the production tubing or production riser may be provided with valves to control the inflow of reduced-salinity water.
- the produced hydrocarbons may be contained in production tubing located in the production well, wherein the reduced-salinity water is injected deep in the production well such that injection takes place close to a lower completion section.
- the reduced-salinity water may be injected in an amount sufficient to create an oil-in water emulsion in which the produced hydrocarbons are suspended as a dispersed phase within a continuous phase provided by the reduced-salinity water.
- the reduced-salinity water may be injected in an amount sufficient to create a water-in- oil emulsion in which the reduced-salinity water is suspended as a dispersed phase within a continuous phase provided by the produced hydrocarbons.
- the reduced-salinity water may be configured to provide a mixing efficiency of greater than 50%, preferably greater than 60%, and still more preferably greater than 75%, with the produced hydrocarbons.
- the reduced-salinity water may have a higher temperature than fluids in a reservoir from which the produced hydrocarbons are produced.
- the reduced-salinity water may be injected into the produced hydrocarbons in combination with gas.
- the reduced-salinity water and the gas may be injected simultaneously into the produced hydrocarbons in the production well.
- Figure 1 shows a system for injecting a treatment fluid into a production well.
- Figure 2 shows a system for injecting a treatment fluid into a flowline.
- Figure 3 shows a system for injecting a treatment fluid into a riser.
- Figure 4 shows a high-level flow diagram describing a method in accordance with the invention.
- the invention is beneficial in that a conduit, e.g. a well, production riser, production tubing, or production flowline, that conveys produced liquid hydrocarbons at least part of the way between a reservoir and a processing facility is used as a‘reactor’, i.e. a processing container, to perform processing steps that may otherwise need to be performed at the processing facility.
- the processing facility may be, for example, an oilfield facility located between a production well and a storage tank, a topsides processing facility located e.g. on a floating platform, or a processing facility located on the seabed at a riser base between a flowline and a riser.
- the processing steps performed in the conduit may completely replace, or render obsolete, processing steps that would otherwise be performed at the processing facility, or processing steps may be performed partially in the conduit and partially at the processing facility.
- the substance(s) required for the processing steps which may be a treatment fluid such as reduced-salinity or low-salinity water for desalting, are injected into the produced liquid hydrocarbons while the hydrocarbons are located in the conduit. This means that the time taken for the produced liquid hydrocarbons to traverse the conduit, and to traverse any subsequent part of the production structure before the processing facility, is usefully exploited to increase the temperature, contact time and/or the potential for mixing between the treatment fluid(s) and the liquid hydrocarbons, thereby increasing the efficacy of the processing.
- the temperature of the conduit can be increased using heated liquids from the processing facility, resulting in more efficient processing.
- One or more processing stages may be performed before the treatment fluid is injected into the produced hydrocarbons.
- a desalting stage may be performed at a subsea facility before the produced hydrocarbons enter a flowline, where the treatment fluid is injected into the produced hydrocarbons.
- oil/water separation may be performed on produced hydrocarbons downhole, before the treatment fluid is injected into the produced hydrocarbons at a later stage in the production tubing in the well.
- the injection of the substance(s) into the liquid hydrocarbons while the liquid hydrocarbons remain under near-reservoir conditions, i.e. at desirable pressure (and, optionally, temperature), is an early intervention that may remove the need for processing steps that would otherwise be required at the processing facility.
- Produced hydrocarbons often contain water, and the produced water contained in the produced hydrocarbons can have a high salinity, mostly due to the presence of sodium, calcium and/or potassium chlorides. Lower concentrations of other salts may be present.
- the produced water is typically dispersed within the produced hydrocarbons in a water-in-oil emulsion, but may form a continuous phase in which the produced hydrocarbons are dispersed, i.e. an oil-in-water emulsion.
- Liquid hydrocarbons, e.g. oil must meet certain standards with respect to salinity and water content before the oil can be transported away from a field, e.g. via pipeline, and/or sold to a customer.
- a desalting method in accordance with the invention comprises injecting reduced-salinity or low-salinity water into produced hydrocarbons contained in a conduit for conveying the produced hydrocarbons, to dilute high-salinity produced water contained in the produced hydrocarbons.
- the conduit is, for example, a production well, production tubing in a production well, a flowline, a production flowline, a riser, or a production riser.
- the reduced-salinity water is injected into the produced hydrocarbons before the produced hydrocarbons reach a processing facility, and before the produced hydrocarbons are subjected to any processing stages at a processing facility.
- one or more processing stages for example, separation in the well, subsea separation or separation at a wellhead platform, which may in effect be desalting operations— may be performed on the produced hydrocarbons before the reduced-salinity water is injected into the produced hydrocarbons.
- this desalting method exploits the time that the produced hydrocarbons spend in the conduit to perform processing operations, in this case desalting, that would otherwise need to be performed at a processing facility.
- Figure 1 shows a well 1 14, in particular a production well, extending through a formation 122, and through a cap rock 1 13.
- the well has a conductor 1 1 1 and casings 1 12.
- Produced hydrocarbons 124 are conveyed in production tubing 126 from a reservoir 120.
- the production tubing 126 is located within the well 1 14.
- the produced hydrocarbons 124 typically contain liquid hydrocarbons, and impurities such as water, salts (which may be contained in the water), gases, organometallic compounds and organic acids, and solids.
- the liquid hydrocarbons are referred to here as oil.
- the formation 122 is a subsea formation and a Christmas tree (xmas tree) 102 is located on the seafloor above the well 1 14.
- the produced hydrocarbons 124 are routed through the xmas tree 102 to a processing facility 105, which is located between the xmas tree 102 and a storage tank 106.
- the produced hydrocarbons are subjected to processing stages such as gas/liquid separation and oil/water separation at the processing facility 105.
- oil may be stored in storage tank 106, and/or transported away via pipeline or flowline.
- Treatment fluid 108 is injected into the produced hydrocarbons 124 before the produced hydrocarbons reach the processing facility 105.
- the treatment fluid 108 is injected into the produced hydrocarbons while the produced hydrocarbons are in the production tubing 126 located in the well 1 14.
- the treatment fluid is conveyed by a tube 101 towards the xmas tree 102, and is conveyed through the xmas tree to an annulus 103 between the production tubing 126 and a tubular outside the production tubing, e.g a casing.
- the treatment fluid 108 is injected into the produced hydrocarbons in the production tubing via an opening in the production tubing.
- the opening contains a valve 104 to control the inflow of treatment fluids into the production tubing.
- the tube extends through the xmas tree and the annulus and terminates at the opening in the production tubing.
- the opening is located below the water, below the seafloor and below the cap rock, close to a lower completion section.
- the treatment fluid 108 is water or an aqueous solution
- gas 107 as well as treatment fluid 108 is injected into the production tubing, in line with the simultaneous water and gas lift (SWAGL) technique described in WO2017158049, the entire contents of which is incorporated herein by reference.
- the gas 107 may be combined with the treatment fluid 108 in the tube 101 before entering the well, or may be injected using separate tubing and a separate opening in the production tubing.
- the injection of both water and gas simultaneously reduces pressure losses both due to friction and gravity.
- the gas 107 may be sour gas. Without adding further pressure, the well pressure itself may be sufficient to transport the production fluids to the surface in combination with the reduction of pressure losses after injection of water and gas.
- the treatment fluid may be heated before injection, and injected at a temperature higher than fluids in the reservoir from which the produced hydrocarbons are produced. Injecting heated treatment fluids will increase the temperature of the conduit, and increase the temperature of the produced hydrocarbons in the conduit. This will decrease the viscosity of the liquid hydrocarbons, increasing the mixing efficiency and facilitating transport of the produced hydrocarbons through the conduit.
- the treatment fluid may be injected at a temperature lower than, or substantially equal to, fluids in the reservoir from which the produced hydrocarbons are produced.
- the treatment fluid is reduced-salinity water that is injected into the produced hydrocarbons to dilute higher-salinity water contained in the produced hydrocarbons.
- Injecting reduced-salinity water into the produced hydrocarbons in accordance with the invention eliminates, or at least mitigates, the need for a desalting stage at the processing facility.
- the reduced-salinity water has a salinity lower than seawater in a body of water above the field in which the production well is located, and/or has a salinity lower than the higher-salinity water contained in the produced hydrocarbons.
- the reduced-salinity water has a salinity of less than 50 000 mg/L, preferably less than 55 000 mg/L, more preferably less than 40 000 mg/L, and still more preferably less than 31 000 mg/L.
- the reduced-salinity water is injected in an amount sufficient to create an oil-in-water emulsion in which the produced hydrocarbons are suspended as a dispersed phase within a continuous phase provided by the reduced-salinity water.
- Creating an oil-in-water emulsion in this way increases the mixing efficiency, i.e. the likelihood that the reduced-salinity water will contact the higher-salinity water contained in the produced hydrocarbons, to thereby dilute the higher-salinity water, is increased.
- the overall volume fraction of higher-salinity water in the mixed fluid is also reduced by the addition of the reduced-salinity water.
- the reduced-salinity water is injected to provide a mixing efficiency of greater than 50%, preferably greater than 60%, and still more preferably greater than 75%, with the produced hydrocarbons.
- the reduced-salinity water may be injected in smaller amounts sufficient to create a water-in-oil emulsion wherein the reduced-salinity water is suspended as a dispersed phase within a continuous phase provided by the produced hydrocarbons.
- Mixing efficiency is dependent on water droplet size in oil (for oil-continuous production), water droplet collision frequency, reaction time and oil viscosity.
- Figure 2 shows an embodiment which is functionally similar to the embodiment of Figure 1 , with the exception that the location of the processing facility and the location at which the treatment fluid is injected are different.
- Produced hydrocarbons 224 are conveyed from a reservoir via a production well 214 and through an xmas tree 202.
- the produced hydrocarbons 224 may be stored in storage tank 206 before being transported via production flowline 215 to a processing facility 205.
- the processing facility 205 is shown at or near the base of a riser 216.
- the processing facility 205 may output oil and/or other products of the processing to a further flowline or other conduit.
- Treatment fluid 208 is injected into the produced hydrocarbons while the produced hydrocarbons are located in the production flowline 215, and before the produced hydrocarbons reach the processing facility 205.
- the treatment fluid 208 is injected via an opening in the production flowline.
- the opening may contain a valve 204 to control the inflow of the treatment fluid.
- Figure 3 shows an embodiment which is functionally similar to the embodiment of Figure 1 and Figure 2, with the exception that the location of the processing facility and the location at which the treatment fluid is injected are different.
- Produced hydrocarbons 324 are conveyed from a reservoir via a production well 314 and through an xmas tree 302.
- the produced hydrocarbons 324 may be stored in storage tank 306 before being transported via production flowline 315, riser base 317 and riser 316 to a topsides processing facility 305 located on a platform 318.
- the platform 318 may be, for example, a floating platform anchored to the seabed by cables, or another type of floating unit, e.g. a floating production storage and offloading (FPSO) unit.
- FPSO floating production storage and offloading
- Treatment fluid 308 is injected into the produced hydrocarbons while the produced hydrocarbons are located in the production riser 316, and before the produced hydrocarbons reach the processing facility 305.
- the treatment fluid 308 is injected via an opening in the production flowline.
- the opening may contain a valve 304 to control the inflow of the treatment fluid.
- FIG. 4 shows a high-level flow diagram illustrating the method.
- step S402 reduced-salinity water is injected into produced hydrocarbons in a production well, flowline or riser, to dilute high-salinity produced water contained in the produced hydrocarbons.
Landscapes
- Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Geology (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Physics & Mathematics (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Environmental & Geological Engineering (AREA)
- Organic Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Transition And Organic Metals Composition Catalysts For Addition Polymerization (AREA)
Abstract
Description
Claims
Priority Applications (5)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
AU2019403728A AU2019403728A1 (en) | 2018-12-21 | 2019-12-19 | A method for desalting produced hydrocarbons |
US17/415,880 US20220056346A1 (en) | 2018-12-21 | 2019-12-19 | A method for desalting produced hydrocarbons |
CA3124548A CA3124548C (en) | 2018-12-21 | 2019-12-19 | A method for desalting produced hydrocarbons |
NO20210876A NO20210876A1 (en) | 2018-12-21 | 2019-12-19 | Treatment of produced hydrocarbons |
BR112021012070-0A BR112021012070A2 (en) | 2018-12-21 | 2019-12-19 | TREATMENT OF PRODUCED HYDROCARBONS |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GB1821093.0 | 2018-12-21 | ||
GB1821093.0A GB2580145B (en) | 2018-12-21 | 2018-12-21 | Treatment of produced hydrocarbons |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2020130850A1 true WO2020130850A1 (en) | 2020-06-25 |
Family
ID=65364574
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/NO2019/050286 WO2020130850A1 (en) | 2018-12-21 | 2019-12-19 | A method for desalting produced hydrocarbons |
Country Status (7)
Country | Link |
---|---|
US (1) | US20220056346A1 (en) |
AU (1) | AU2019403728A1 (en) |
BR (1) | BR112021012070A2 (en) |
CA (1) | CA3124548C (en) |
GB (1) | GB2580145B (en) |
NO (1) | NO20210876A1 (en) |
WO (1) | WO2020130850A1 (en) |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2310673A (en) * | 1942-04-22 | 1943-02-09 | Petrolite Corp | Process for treating pipeline oil |
US2677666A (en) * | 1951-12-29 | 1954-05-04 | Sun Oil Co | Process for removing contaminants from crude oils |
US3491835A (en) * | 1967-12-29 | 1970-01-27 | Phillips Petroleum Co | Recovering,desalting,and transporting heavy crude oils |
WO2009120822A2 (en) * | 2008-03-27 | 2009-10-01 | National Tank Company | Low pressure mixing system for desalting hydrocarbons |
Family Cites Families (24)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2355678A (en) * | 1939-08-21 | 1944-08-15 | Petrolite Corp | Method for removing impurities from hydrocarbons |
US2318714A (en) * | 1940-01-24 | 1943-05-11 | Sinclair Refining Co | Emulsion |
US3428127A (en) * | 1966-12-28 | 1969-02-18 | Union Oil Co | Method for increasing the recovery of oil from water-sensitive formations |
US3437141A (en) * | 1967-10-09 | 1969-04-08 | Mobil Oil Corp | Multistep method of waterflooding |
US3796266A (en) * | 1972-12-13 | 1974-03-12 | Texaco Inc | Surfactant oil recovery process |
JPS5589389A (en) * | 1978-12-27 | 1980-07-05 | Hitachi Ltd | Desalination of fuel oil |
US4230182A (en) * | 1979-08-30 | 1980-10-28 | Texaco Inc. | Oil recovery method employing alternate slugs of surfactant fluid and fresh water |
GB8328232D0 (en) * | 1983-10-21 | 1983-11-23 | British Petroleum Co Plc | Desalting crude oil |
GB8432278D0 (en) * | 1984-12-20 | 1985-01-30 | British Petroleum Co Plc | Desalting crude oil |
US4957646A (en) * | 1987-08-26 | 1990-09-18 | Shell Oil Company | Steam foam surfactants enriched in alpha olefin disulfonates for enhanced oil recovery |
US4966235A (en) * | 1988-07-14 | 1990-10-30 | Canadian Occidental Petroleum Ltd. | In situ application of high temperature resistant surfactants to produce water continuous emulsions for improved crude recovery |
CA2244974A1 (en) * | 1996-02-12 | 1997-08-14 | Phillips Petroleum Company | Process for reducing salt content in a hydrocarbon containing fluid |
EP1586620A1 (en) * | 2004-04-15 | 2005-10-19 | Total S.A. | Process for purifying well oil, process for breaking a hydrocarbon emulsion and apparatuses to perform them |
BRPI0511628B8 (en) * | 2004-05-28 | 2017-03-28 | Bp Corp North America Inc | method of recovering hydrocarbons from a porous underground hydrocarbon-containing formation by injecting a low salinity water into the formation from an injection well and injection well |
CN104541022B (en) * | 2012-08-09 | 2017-09-08 | 国际壳牌研究有限公司 | System for producing and separating oil |
CA2912268A1 (en) * | 2013-05-30 | 2014-12-04 | Exxonmobil Research And Engineering Company | Petroleum crude oil desalting process and unit |
US9505990B2 (en) * | 2014-04-18 | 2016-11-29 | Cameron Solutions, Inc. | System and method of delivering dilution water droplets within an oil-and-water stream |
US10358609B2 (en) * | 2014-12-23 | 2019-07-23 | Statoil Petroleum As | Process for removing metal naphthenate from crude hydrocarbon mixtures |
CN105038842A (en) * | 2015-06-17 | 2015-11-11 | 成都高普石油工程技术有限公司 | Crude oil desalting and dewatering technique |
AU2017234995B2 (en) * | 2016-03-15 | 2022-05-12 | Equinor Energy As | Artificial lift method |
US10082010B1 (en) * | 2017-11-21 | 2018-09-25 | Phillips 66 Company | Processing of oil by steam addition |
US10087732B1 (en) * | 2017-11-21 | 2018-10-02 | Phillips 66 Company | Processing of oil by steam addition |
US10006276B1 (en) * | 2017-11-21 | 2018-06-26 | Phillips 66 Company | Processing of oil by steam addition |
US10513663B2 (en) * | 2018-01-09 | 2019-12-24 | Saudi Arabian Oil Company | Gas oil separation plant systems and methods for rag layer treatment |
-
2018
- 2018-12-21 GB GB1821093.0A patent/GB2580145B/en active Active
-
2019
- 2019-12-19 CA CA3124548A patent/CA3124548C/en active Active
- 2019-12-19 AU AU2019403728A patent/AU2019403728A1/en active Pending
- 2019-12-19 US US17/415,880 patent/US20220056346A1/en active Pending
- 2019-12-19 WO PCT/NO2019/050286 patent/WO2020130850A1/en active Application Filing
- 2019-12-19 NO NO20210876A patent/NO20210876A1/en unknown
- 2019-12-19 BR BR112021012070-0A patent/BR112021012070A2/en not_active Application Discontinuation
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2310673A (en) * | 1942-04-22 | 1943-02-09 | Petrolite Corp | Process for treating pipeline oil |
US2677666A (en) * | 1951-12-29 | 1954-05-04 | Sun Oil Co | Process for removing contaminants from crude oils |
US3491835A (en) * | 1967-12-29 | 1970-01-27 | Phillips Petroleum Co | Recovering,desalting,and transporting heavy crude oils |
WO2009120822A2 (en) * | 2008-03-27 | 2009-10-01 | National Tank Company | Low pressure mixing system for desalting hydrocarbons |
Also Published As
Publication number | Publication date |
---|---|
GB201821093D0 (en) | 2019-02-06 |
NO20210876A1 (en) | 2021-07-07 |
CA3124548A1 (en) | 2020-06-25 |
GB2580145B (en) | 2021-10-27 |
BR112021012070A2 (en) | 2021-09-21 |
CA3124548C (en) | 2024-06-18 |
GB2580145A (en) | 2020-07-15 |
US20220056346A1 (en) | 2022-02-24 |
AU2019403728A1 (en) | 2021-08-05 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
JP5620625B2 (en) | How to process crude oil | |
CA2463692C (en) | An installation for the separation of fluids | |
US8919449B2 (en) | Offshore drilling and production systems and methods | |
AU2018346659B2 (en) | Underwater system and method for pressurization of an underwater oil reservoir by independent injection of water and gas | |
CA3124548C (en) | A method for desalting produced hydrocarbons | |
CN110475941B (en) | Mitigating carbon steel pipe corrosion and surface scale deposition in oilfield applications | |
US11820940B2 (en) | Organic acid surfactant booster for contaminant removal from hydrocarbon-containing stream | |
Marjohan | How to Increase Recovery of Hydrocarbons Utilizing Subsea Processing Technology | |
US11965131B2 (en) | Treatment of produced hydrocarbons | |
Verbeek et al. | Downhole separator produces less water and more oil | |
US20050155768A1 (en) | Methods and apparatus for enhancing production from a hydrocarbons-producing well | |
GB2377711A (en) | Thinning of crude oil in a bore well | |
US20220056790A1 (en) | Pour point avoidance in oil/water processing and transport | |
GB2611554A (en) | Method for processing hydrocarbons for the removal of oxygenates | |
CN107429559B (en) | Oil recovery chemicals removal from produced fluids | |
WO2003008761A1 (en) | Method for producing heavy crude oil |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
121 | Ep: the epo has been informed by wipo that ep was designated in this application |
Ref document number: 19898843 Country of ref document: EP Kind code of ref document: A1 |
|
ENP | Entry into the national phase |
Ref document number: 3124548 Country of ref document: CA |
|
NENP | Non-entry into the national phase |
Ref country code: DE |
|
REG | Reference to national code |
Ref country code: BR Ref legal event code: B01A Ref document number: 112021012070 Country of ref document: BR |
|
ENP | Entry into the national phase |
Ref document number: 2019403728 Country of ref document: AU Date of ref document: 20191219 Kind code of ref document: A |
|
ENP | Entry into the national phase |
Ref document number: 112021012070 Country of ref document: BR Kind code of ref document: A2 Effective date: 20210618 |
|
122 | Ep: pct application non-entry in european phase |
Ref document number: 19898843 Country of ref document: EP Kind code of ref document: A1 |