EP2931844A1 - Methods and compositions for removing solids from hydrocarbon streams - Google Patents

Methods and compositions for removing solids from hydrocarbon streams

Info

Publication number
EP2931844A1
EP2931844A1 EP13861547.1A EP13861547A EP2931844A1 EP 2931844 A1 EP2931844 A1 EP 2931844A1 EP 13861547 A EP13861547 A EP 13861547A EP 2931844 A1 EP2931844 A1 EP 2931844A1
Authority
EP
European Patent Office
Prior art keywords
solids
demulsifying agent
sulfosuccinate
succinate
hydrocarbon stream
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.)
Granted
Application number
EP13861547.1A
Other languages
German (de)
French (fr)
Other versions
EP2931844B1 (en
EP2931844A4 (en
Inventor
Lawrence N. Kremer
Gerald O. HOFFMAN
Jerry J. Weers
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.)
Baker Hughes Holdings LLC
Original Assignee
Baker Hughes Inc
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 Baker Hughes Inc filed Critical Baker Hughes Inc
Priority to EP19161382.7A priority Critical patent/EP3514216A1/en
Publication of EP2931844A1 publication Critical patent/EP2931844A1/en
Publication of EP2931844A4 publication Critical patent/EP2931844A4/en
Application granted granted Critical
Publication of EP2931844B1 publication Critical patent/EP2931844B1/en
Active legal-status Critical Current
Anticipated expiration legal-status Critical

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
    • C10G33/00—Dewatering or demulsification of hydrocarbon oils
    • C10G33/04—Dewatering or demulsification of hydrocarbon oils with chemical means

Definitions

  • the present invention relates to methods and compositions for separating solids from a hydrocarbon stream, and more particularly relates, in one non-limiting embodiment, to a demulsifying agent added to a hydrocarbon stream for separating at least a portion of the solids from the hydrocarbon stream where the demulsifying agent may be or include at least one maleic acid derivative.
  • Hydrocarbon streams such as crude oils, asphalt, bitumens, etc typically carry varying amounts of solids within the hydrocarbon stream. Additional solids from the sludge of a crude storage tank may also be incorporated into the hydrocarbon stream once the hydrocarbon stream enters the crude storage tank.
  • the solids and/or sludge include inorganic solids, paraffin wax, and the like.
  • the amount of solids may vary from about 20 pounds per thousand barrels (ptb) (about 1 1 kilograms per thousand barrels) to about 2500 ptb (about 1 133 kg per thousand barrels), or in the case of sludge, the sludge accumulation may range from several centimeters to over one meter deep.
  • a layer of sludge typically forms at the bottom of a crude storage tank as crude oil is discharged into the crude storage tank and later discharged from the crude storage tank. This sludge appears to be a complex emulsion stabilized by inorganic and/or organic solids within the emulsion.
  • the salty sludge is picked up from the bottom of the crude storage tank by the velocity of the crude oil.
  • the specific gravity of the sludge within the crude storage tank is lighter than water and is easily dispersed into the hydrocarbon stream.
  • the sludge is a complex emulsion of hydrocarbon, brine, and inorganic solids, and paraffin wax.
  • the inorganic solids may include iron oxides, sulfides, sand, silt, clay, and the like. These solids arise from several sources, such as brine contamination as a result of the brine associated with the oil in the formation. Most minerals, clay, silt, and sand come from the formation around the oil wellbore.
  • the iron oxides and iron sulfides are a result of corrosion during production, transport, and/or storage of the crude oil.
  • the sludge poses several problems, such as reducing the volume of the working crude storage tank and crude unit upsets. When the crude storage tank is taken off-line for inspection and/or needs to be repaired, the sludge poses additional concerns related to worker safety, environmental release of the sludge, disposal costs, cost to remove the sludge, downtime, etc.
  • a demulsifying agent may be added to the hydrocarbon stream for subsequent separation of the solids from the hydrocarbon stream in an effective amount to water-wet at least a portion of the solids.
  • the demulsifying agent may be or include, but is not limited to, at least one maleic acid derivative.
  • a demulsifying agent may be added to the emulsion in an amount ranging from about 0.1 ppm to about 30 ppm to water-wet at least a portion of the solids.
  • the demulsifying agent may be or include at least one maleic acid derivative.
  • the demulsifying agent may be added to the emulsion at a location upstream from a desalter.
  • the water-wet solids may then separate from the oil phase of the emulsion for subsequent removal of the solids.
  • a treated hydrocarbon stream in a crude storage tank may include a plurality of water-wet solids and a demulsifying agent.
  • the demulsifying agent may be or include, but is not limited to at least one maleic acid derivative.
  • the amount of the demulsifying agent may range from about 0.1 ppm to about 30 ppm.
  • the plurality of water-wet solids are more water-wet as compared to a plurality of solids within a hydrocarbon stream in the absence of the demulsifying agent.
  • the demulsifying agent appears to water-wet the solids in such a way to allow the solids to separate from a hydrocarbon stream or oil phase of an emulsion, and then the solids may be removed or incorporated into a water phase.
  • a chemical such as a demulsifying agent
  • the demulsifying agent may be added to a tank having the hydrocarbon stream; alternatively, the demulsifying agent may be added to the hydrocarbon stream at a location upstream from a desalter.
  • the chemical may be added directly to the desalter for separating solids from the hydrocarbon stream; however, the chemical has more contact time and therefore better performance by the chemical when it is added as a pre-treatment to the hydrocarbon stream upstream from the desalter.
  • a pre-treatment allows the chemical to have more contact time with the solids and thereby better separation of the solids as well as other functions, such as but not limited to solids wetting capabilities, better surface tension and improved oil-water partition, etc.
  • 'Upstream from the desalter' means the demulsifying agent may be added to the hydrocarbon stream at any point prior to feeding the hydrocarbon stream into the desalter.
  • the added amount of time by using the chemical as a pre- treatment instead of adding the chemical directly to a desalter allows for improved resolution of micro-emulsions that can be present within the hydrocarbon stream, as well as provide solids separation from a solids laden sludge that is carried with the normal crude feed.
  • Many potential secondary benefits include fewer crude unit upsets, better desalter operation, less crude unit preheat system fouling, improved crude unit corrosion control, reduced water slugs, and combinations thereof.
  • This type of pre-treatment allows for reduced time for crude storage tank maintenance, lower sludge disposal costs, and better quality raw crude oil charged to the crude storage tank.
  • 'Pre-treatment' is defined herein to mean that the chemical is added to the hydrocarbon stream and the chemical rests with the hydrocarbon stream for a specified amount of time prior to the injection of the hydrocarbon stream into the desalter.
  • the pre-treatment chemical may rest with the hydrocarbon stream for a period of about 10 minutes independently to about 7 days prior to the injection of the pre-treated hydrocarbon stream into the desalter, alternatively from about 30 minutes independently to about 5 days, or from about 30 minutes independently to about 120 hours.
  • a 'pre- treated' hydrocarbon stream is defined herein to be a hydrocarbon stream that has the chemical therein where the chemical has rested with the hydrocarbon stream for a period of time that falls within at least one of the given ranges above.
  • "independently" means that any lower threshold may be used together with any upper threshold to give a suitable alternative range.
  • the hydrocarbon stream may be part of an oil-in-water emulsion and/or a water-in-oil emulsion (hereinafter referred to as 'the emulsion'), and the demulsifying agent may be added to either the oil phase, the water phase, or both of the emulsion.
  • the amount of water within the emulsion may be greater than 50 vol%, or range from about 2 vol % independently to about 95 vol%, alternatively from about 0.01 vol % independently to about 20 vol%.
  • the hydrocarbon stream may be or include, but is not limited to crude oil, asphalt, bitumen, shale condensates, decant oil (also known as treated slop oil), and combinations thereof.
  • the types of crude oil may be or include heavy Canadian crudes, bitumen, shale oils, heavy Californian crudes, South American crudes, Russian crudes, topped crudes, West Texas intermediate crude(WTI), and combinations thereof.
  • specific crudes may include crudes produced by Steam Assisted Gravity Drainage (SAGD) or PFT, Dillbit (diluted bitumen also known as Synbit), and conventional crudes.
  • SAGD Steam Assisted Gravity Drainage
  • PFT Dillbit
  • Synbit diluted bitumen also known as Synbit
  • 'Heavy' as used in the context of crudes is a crude that has an API gravity less than about 30; API gravity is a measure of how heavy or light a petroleum liquid is when compared to water.
  • the solids may be or include inorganic solids, such as but not limited to metal oxides, metal dioxides, metal sulfides, metal sulfates, metal carbonates, sand, silt, clay, paraffin wax, dolomite, coke fines, zinc compounds and combinations thereof.
  • metal oxides may be or include iron oxides (FeO, Fe 2 03, Fe 3 04, Fe 2 03), copper oxides (Cu 2 0 and/or CuO), manganese oxides (MnO, ⁇ 3 ⁇ 4, Mn 2 0 3 , Mn0 2 , and Mn 2 07), zinc oxides, nickel oxides, and combinations thereof; a non-limiting example of metal dioxides may be or include titanium dioxide.
  • Non-limiting examples of the sulfides, sulfates, and carbonates may be or include iron sulfides (e.g. FeS, FeS 2 , Fe 3 S 4 ) and the like.
  • the size of the solids may be less than about 0.45 microns, alternatively from about 0.1 microns independently to about 5 microns.
  • the demulsifying agent may be injected into the hydrocarbon stream as it enters into the crude storage tank, e.g. one injection location may be the suction of the crude transfer pump or injection pump, or the demulsifying agent may be added to the hydrocarbon stream once the hydrocarbon stream is already in the crude storage tank.
  • the demulsifying agent may be or include, but is not limited to maleic acid derivatives, which may be used in conjunction with naphthalene sulfonates, alkyl diphenyloxide disulfonate, and combinations thereof.
  • the naphthalene sulfonates may have from 1 aromatic ring to 4 aromatic rings; alternatively, the naphthalene sulfonate may have 2 aromatic rings.
  • Non-limiting examples of the naphthalene sulfonate include mono-alkyl substituted naphthalene sulfonates, di-alkyl substituted naphthalene sulfonates (e.g. di-isopropyl naphthalene sulfonate), methanolamine dibutyl naphthalene sulfonate, sodium benzyl naphthalene sulfonate, and the like.
  • a non-limiting example of the alkyl diphenyloxide disulfonate is Dowfax 2A1 TM, which is supplied by Dow Chemical Company.
  • At least one maleic acid derivative may be used as the demulsifying agent; in one non-limiting embodiment, two or more maleic acid derivatives may be used as the demulsifying agent.
  • the maleic acid derivative may be a sulfosuccinate having a C 6 -Ci8 sulfosuccinate, and the maleic acid derivative may be a sodium salt, an amine salt, a potassium salt, an ammonium salt, and combinations thereof.
  • Maleic acid derivatives include, but are not necessarily limited to, di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl pheno succinate, dodecyl diphenyl succinate, ditridecyl succinate, dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium 1 -icosyl 2 sulfosuccinate, ammonium 1 ,4 didecyl sulfosuccinate, dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate, sodium lauryl sulfoacetate, salts thereof, and combinations thereof.
  • the succinate may be a sulfosuccinate.
  • the maleic acid derivative may be used in conjunction with an alkali salt, such as sodium, in one non-limiting embodiment.
  • the demulsifying agent includes at least one maleic acid derivative, e.g. dioctyl sulfosuccinate, and at least one naphthalene sulfonate, even though the maleic acid derivative is effective when used alone.
  • Particular ratios of the maleic acid derivative and the naphthalene sulfonate that are beneficial range from about a 50/50 ratio of maleic acid derivative to naphthalene sulfonate independently to about a 95/5 ratio of maleic acid derivative to naphthalene sulfonate.
  • Alternative ratios may include an 80/20 ratio of maleic acid derivative to naphthalene sulfonate, a 90/10 ratio of maleic acid derivative to naphthalene sulfonate, and the like.
  • a primary demulsifier may also be used with the demulsifying agent to promote the activity by the demulsifying agent.
  • the primary demulsifier may be mixed with the demulsifying agent for injection of the primary demulsifier at the same time as the demulsifying agent.
  • the primary demulsifier may be injected at a different location altogether from the demulsifying agent. As long as a primary demulsifier is used with the demulsifying agent, regardless of whether it is injected at the same time or a different time as the demulsifying agent, the demulsifying agent will be capable of performing its functions.
  • Non-limiting examples of primary demulsifiers may be or include alkoxylated resins, alkoxylated dipropylene glycols, maleic esters, cross-linked alkoxylated resins, alkoxylated glycols, alkoxylated glycerins, and trisaminoemethane alkoxylates, and combinations thereof.
  • the specific primary demulsifier to be used will depend on the composition and amount of the demulsifying agent used.
  • the solids may be suspended in the hydrocarbon stream or oil phase of the emulsion. Adding the demulsifying agent to the hydrocarbon stream or oil phase of the emulsion allows for the demulsifying agent to rest with the hydrocarbon stream and separate the solids therefrom prior to the injection of the hydrocarbon stream into a desalter, even if there is no sludge present in the crude storage tank.
  • the demulsifying agent destabilizes the solids from the emulsion and affects rapid coalescence of water and preferentially water wets the solids.
  • the water-wet solids are then carried into the water phase of the emulsion, thereby providing a reduced amount of solids within the hydrocarbon stream or oil phase of the emulsion.
  • the water and the water-wet solids may then be removed for proper recovery of the hydrocarbon components with fewer solids. Overall, removal of the solids prior to the injection of the hydrocarbon stream causes fewer problems in the refinery and other processing downstream.
  • the introduction of the demulsifying agent into the hydrocarbon stream by itself may be sufficient mixing, or there may be an additional process for intentional mixing, such as a paddle stirrer or the like as one non-limiting example.
  • the hydrocarbon stream is kept still or held quiescent in the crude storage tank for enough time to allow or permit the solids to water- wet by the demulsifying agent.
  • the water-wet solids may settle to the bottom of the crude storage tank under the influence of gravity.
  • a goal of the method is to reduce the solids content in the hydrocarbon stream to an acceptable level for the hydrocarbon stream to be processed in a refinery.
  • the methods described are considered successful if a majority of the solids are separated, i.e. greater than 50 wt%, alternatively from about 60 wt% independently to about 90 wt% of the solids are separated, or from about 80 wt% independently to about 90 wt% in another non-limiting embodiment.
  • separating solids from the hydrocarbon stream is defined herein to mean any and all partitioning, sequestering, removing, transferring, eliminating, dividing, removing, dropping out of the solids from the hydrocarbon or crude oil to any extent.
  • the hydrocarbon stream would be treated with the demulsifying agent until a predetermined target concentration is reached.
  • the dosage of the demulsifying agent would be adjusted to accomplish yielding a hydrocarbon stream with the necessary amount of solids content, types of solids, and/or size of solids threshold in the time required.
  • the exact dosage will be very dependent upon the particular hydrocarbon stream and the needs of the particular refinery. Optimum dosages will have to be developed with experience and would be very difficult to predict in advance.
  • the amount of the demulsifying agent may range from about 0.1 ppm independently to about 200 ppm, alternatively from about 2 ppm independently to about 100 ppm, or from about 3.5 ppm independently to about 25 ppm in another non-limiting embodiment.
  • the treatment dosage of the demulsifying agent may be much lower than the treatment dosage for a hydrocarbon stream that is to be stored in a crude storage tank for about 3-5 hours.
  • a higher dosage may provide better resolution of the emulsion in a shortened time period.
  • the amount of the demulsifying agent may also depend on the rate at which it is injected into the hydrocarbon stream and/or the crude storage tank. This amount may be adjusted as the crude flow rate changes to assure the refiner that all of the hydrocarbon stream receives the correct amount of demulsifying agent.
  • One method of doing this is to use a variable speed chemical injection pump where a signal from an in-line flow sensor automatically adjusts the chemical injection rate as the flow rate of the hydrocarbon stream changes.
  • Settling agents may also be useful in facilitating the settling of various solids to the bottom of the crude storage tank.
  • Suitable settling agents include, but are not necessarily limited to alkyoxylated phenolic resins; oxyalkylated polyamines, including, but not necessarily limited to ethoxylated and/or propoxylated 1 ,2-ethanediamine, N1 -(2-aminoethyl)-N2-[2-[(2- aminoethyl)amino]ethyl]-, and polymers with 2-methyloxirane and oxirane; oxyalkylated alkanol amines, including, but not necessarily limited to, ethoxylated and/or propoxylated 1 ,3-propanediol, 2-amino-2-(hydroxymethyl)- 1 ,3-propanediol, and again polymers with 2-methyloxirane and oxirane; Mannich reaction condensation products of alkyl phenols and polyamines and mixtures
  • Amines suitable to make these settling agents may range from ethylene diamine to tetraethylene pentamine or higher.
  • Suitable alkyl phenols for use in these settling agents may be those having one or more R group substituent, where R may be defined from C1 to C36 linear, branched, cyclic alkyl groups and combinations of these.
  • the amounts of such settling agents may range from about 5 ppm independently to about 1000 ppm; alternatively from about 50 ppm independently to about 250 ppm.
  • additives may be added to the hydrocarbon stream including, but not necessarily limited to, corrosion inhibitors, demulsifiers, pH adjusters, metal chelants, scale inhibitors, hydrocarbon solvents, and mixtures thereof.
  • corrosion inhibitors demulsifiers
  • pH adjusters pH adjusters
  • metal chelants metal chelants
  • scale inhibitors scale inhibitors
  • hydrocarbon solvents hydrocarbon solvents, and mixtures thereof.
  • the method is practiced ahead of a refinery desalting process that involves washing the crude emulsion with wash water.
  • the present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed.
  • the method may consist of or consist essentially of separating at least a portion of solids from a hydrocarbon stream having solids therein by adding a demulsifying agent to the hydrocarbon stream in an effective amount, where the demulsifying agent may be or include at least one maleic acid derivative, and the demulsifying agent water-wets at least a portion of the solids.
  • the composition may consist of or consist essentially of a treated hydrocarbon stream in a crude storage tank including, but not limited to a demulsifying agent comprising at least one maleic acid derivative, in an amount ranging from about 0.1 ppm to about 200 ppm.
  • the treated stream may further include a plurality of water-wet solids within the hydrocarbon stream where the plurality of solids are more water-wet as compared to a plurality of solids within the hydrocarbon stream in the absence of the demulsifying agent.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

A demulsifying agent may be added to a hydrocarbon stream in an effective amount where the hydrocarbon stream includes a plurality of solids. The demulsifying agent may be added to the hydrocarbon stream at a location that is upstream from a desalter. The demulsifying agent may water-wet at least a portion of the solids for subsequent separation of the solids from the hydrocarbon stream. The demulsifying agent may be or include but is not limited to at least one maleic acid derivative, such as di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl pheno succinate, dodecyl diphenyl succinate, ditridecyl succinate, dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium 1 -icosyl 2 sulfosuccinate, ammonium 1,4 didecyl sulfosuccinate, dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate, sodium lauryl sulfoacetate, salts thereof, and combinations thereof.

Description

METHODS AND COMPOSITIONS FOR REMOVING SOLIDS
FROM HYDROCARBON STREAMS
TECHNICAL FIELD
[0001] The present invention relates to methods and compositions for separating solids from a hydrocarbon stream, and more particularly relates, in one non-limiting embodiment, to a demulsifying agent added to a hydrocarbon stream for separating at least a portion of the solids from the hydrocarbon stream where the demulsifying agent may be or include at least one maleic acid derivative.
BACKGROUND
[0002] Hydrocarbon streams, such as crude oils, asphalt, bitumens, etc typically carry varying amounts of solids within the hydrocarbon stream. Additional solids from the sludge of a crude storage tank may also be incorporated into the hydrocarbon stream once the hydrocarbon stream enters the crude storage tank. The solids and/or sludge include inorganic solids, paraffin wax, and the like. Depending on the quality of the crude oils and the length of time and/or whether the crude storage tank has been in storage, the amount of solids may vary from about 20 pounds per thousand barrels (ptb) (about 1 1 kilograms per thousand barrels) to about 2500 ptb (about 1 133 kg per thousand barrels), or in the case of sludge, the sludge accumulation may range from several centimeters to over one meter deep. A layer of sludge typically forms at the bottom of a crude storage tank as crude oil is discharged into the crude storage tank and later discharged from the crude storage tank. This sludge appears to be a complex emulsion stabilized by inorganic and/or organic solids within the emulsion. The salty sludge is picked up from the bottom of the crude storage tank by the velocity of the crude oil. The specific gravity of the sludge within the crude storage tank is lighter than water and is easily dispersed into the hydrocarbon stream. [0003] As noted, the sludge is a complex emulsion of hydrocarbon, brine, and inorganic solids, and paraffin wax. The inorganic solids may include iron oxides, sulfides, sand, silt, clay, and the like. These solids arise from several sources, such as brine contamination as a result of the brine associated with the oil in the formation. Most minerals, clay, silt, and sand come from the formation around the oil wellbore. The iron oxides and iron sulfides are a result of corrosion during production, transport, and/or storage of the crude oil. The sludge poses several problems, such as reducing the volume of the working crude storage tank and crude unit upsets. When the crude storage tank is taken off-line for inspection and/or needs to be repaired, the sludge poses additional concerns related to worker safety, environmental release of the sludge, disposal costs, cost to remove the sludge, downtime, etc.
[0004] Regardless of the source of the solids within the hydrocarbon stream, several treatment approaches have been made to reduce or remove the total amount of solids, but these have traditionally centered on the removal of solids at the desalter unit. Desalting or removing the solids, or at least reducing their presence, is necessary prior to further processing since these solids would otherwise cause fouling and deposits in downstream heat exchanger equipment and/or the solids would be detrimental to crude oil processing equipment. Effective crude oil desalting can help minimize the effects of these contaminants on the crude unit and downstream operations. However, some types of crude oil have higher levels of solids that stabilize the emulsion, and this poses a problem for removal of a high level of solids by the desalter alone.
[0005] It would be desirable if methods were devised that would at least partially remove solids from the hydrocarbon stream prior to the injection of the hydrocarbon stream into the desalter, which would allow for better efficiency and use of the desalter. SUMMARY
[0006] There is provided, in one form, a method for separating at least a portion of solids from a hydrocarbon stream having a plurality of solids therein. A demulsifying agent may be added to the hydrocarbon stream for subsequent separation of the solids from the hydrocarbon stream in an effective amount to water-wet at least a portion of the solids. The demulsifying agent may be or include, but is not limited to, at least one maleic acid derivative.
[0007] There is further provided in another non-limiting embodiment, a method for separating at least a portion of solids from an oil phase of an oil/water emulsion having a plurality of solids therein. A demulsifying agent may be added to the emulsion in an amount ranging from about 0.1 ppm to about 30 ppm to water-wet at least a portion of the solids. The demulsifying agent may be or include at least one maleic acid derivative. The demulsifying agent may be added to the emulsion at a location upstream from a desalter. The water-wet solids may then separate from the oil phase of the emulsion for subsequent removal of the solids.
[0008] In another non-limiting embodiment, a treated hydrocarbon stream in a crude storage tank is described. The treated hydrocarbon stream may include a plurality of water-wet solids and a demulsifying agent. The demulsifying agent may be or include, but is not limited to at least one maleic acid derivative. The amount of the demulsifying agent may range from about 0.1 ppm to about 30 ppm. The plurality of water-wet solids are more water-wet as compared to a plurality of solids within a hydrocarbon stream in the absence of the demulsifying agent.
[0009] The demulsifying agent appears to water-wet the solids in such a way to allow the solids to separate from a hydrocarbon stream or oil phase of an emulsion, and then the solids may be removed or incorporated into a water phase. DETAILED DESCRIPTION
[0010] It has been discovered that adding a chemical, such as a demulsifying agent, as a pre-treatment or preconditioning for a hydrocarbon stream when the chemical is added to the hydrocarbon stream for better mixing of the demulsifying agent with the hydrocarbon stream, and therefore better separation of the solids by the time the hydrocarbon stream reaches the desalter. The demulsifying agent may be added to a tank having the hydrocarbon stream; alternatively, the demulsifying agent may be added to the hydrocarbon stream at a location upstream from a desalter. The chemical may be added directly to the desalter for separating solids from the hydrocarbon stream; however, the chemical has more contact time and therefore better performance by the chemical when it is added as a pre-treatment to the hydrocarbon stream upstream from the desalter. Such a pre-treatment allows the chemical to have more contact time with the solids and thereby better separation of the solids as well as other functions, such as but not limited to solids wetting capabilities, better surface tension and improved oil-water partition, etc. 'Upstream from the desalter' means the demulsifying agent may be added to the hydrocarbon stream at any point prior to feeding the hydrocarbon stream into the desalter.
[0011] The added amount of time by using the chemical as a pre- treatment instead of adding the chemical directly to a desalter allows for improved resolution of micro-emulsions that can be present within the hydrocarbon stream, as well as provide solids separation from a solids laden sludge that is carried with the normal crude feed. Many potential secondary benefits include fewer crude unit upsets, better desalter operation, less crude unit preheat system fouling, improved crude unit corrosion control, reduced water slugs, and combinations thereof. This type of pre-treatment allows for reduced time for crude storage tank maintenance, lower sludge disposal costs, and better quality raw crude oil charged to the crude storage tank.
[0012] 'Pre-treatment' is defined herein to mean that the chemical is added to the hydrocarbon stream and the chemical rests with the hydrocarbon stream for a specified amount of time prior to the injection of the hydrocarbon stream into the desalter. For example, the pre-treatment chemical may rest with the hydrocarbon stream for a period of about 10 minutes independently to about 7 days prior to the injection of the pre-treated hydrocarbon stream into the desalter, alternatively from about 30 minutes independently to about 5 days, or from about 30 minutes independently to about 120 hours. Similarly, a 'pre- treated' hydrocarbon stream is defined herein to be a hydrocarbon stream that has the chemical therein where the chemical has rested with the hydrocarbon stream for a period of time that falls within at least one of the given ranges above. As used herein with respect to a range, "independently" means that any lower threshold may be used together with any upper threshold to give a suitable alternative range.
[0013] The hydrocarbon stream may be part of an oil-in-water emulsion and/or a water-in-oil emulsion (hereinafter referred to as 'the emulsion'), and the demulsifying agent may be added to either the oil phase, the water phase, or both of the emulsion. The amount of water within the emulsion may be greater than 50 vol%, or range from about 2 vol % independently to about 95 vol%, alternatively from about 0.01 vol % independently to about 20 vol%. The hydrocarbon stream may be or include, but is not limited to crude oil, asphalt, bitumen, shale condensates, decant oil (also known as treated slop oil), and combinations thereof. The types of crude oil may be or include heavy Canadian crudes, bitumen, shale oils, heavy Californian crudes, South American crudes, Russian crudes, topped crudes, West Texas intermediate crude(WTI), and combinations thereof. For example, specific crudes may include crudes produced by Steam Assisted Gravity Drainage (SAGD) or PFT, Dillbit (diluted bitumen also known as Synbit), and conventional crudes. 'Heavy' as used in the context of crudes is a crude that has an API gravity less than about 30; API gravity is a measure of how heavy or light a petroleum liquid is when compared to water.
[0014] The solids may be or include inorganic solids, such as but not limited to metal oxides, metal dioxides, metal sulfides, metal sulfates, metal carbonates, sand, silt, clay, paraffin wax, dolomite, coke fines, zinc compounds and combinations thereof. Particular non-limiting examples of the metal oxides may be or include iron oxides (FeO, Fe203, Fe304, Fe203), copper oxides (Cu20 and/or CuO), manganese oxides (MnO, Μη3θ4, Mn203, Mn02, and Mn207), zinc oxides, nickel oxides, and combinations thereof; a non-limiting example of metal dioxides may be or include titanium dioxide. Non-limiting examples of the sulfides, sulfates, and carbonates may be or include iron sulfides (e.g. FeS, FeS2, Fe3S4) and the like. The size of the solids may be less than about 0.45 microns, alternatively from about 0.1 microns independently to about 5 microns.
[0015] The demulsifying agent may be injected into the hydrocarbon stream as it enters into the crude storage tank, e.g. one injection location may be the suction of the crude transfer pump or injection pump, or the demulsifying agent may be added to the hydrocarbon stream once the hydrocarbon stream is already in the crude storage tank. The demulsifying agent may be or include, but is not limited to maleic acid derivatives, which may be used in conjunction with naphthalene sulfonates, alkyl diphenyloxide disulfonate, and combinations thereof. The naphthalene sulfonates may have from 1 aromatic ring to 4 aromatic rings; alternatively, the naphthalene sulfonate may have 2 aromatic rings. Non-limiting examples of the naphthalene sulfonate include mono-alkyl substituted naphthalene sulfonates, di-alkyl substituted naphthalene sulfonates (e.g. di-isopropyl naphthalene sulfonate), methanolamine dibutyl naphthalene sulfonate, sodium benzyl naphthalene sulfonate, and the like. A non-limiting example of the alkyl diphenyloxide disulfonate is Dowfax 2A1 TM, which is supplied by Dow Chemical Company.
[0016] In one non-limiting embodiment, at least one maleic acid derivative may be used as the demulsifying agent; in one non-limiting embodiment, two or more maleic acid derivatives may be used as the demulsifying agent. The maleic acid derivative may be a sulfosuccinate having a C6-Ci8 sulfosuccinate, and the maleic acid derivative may be a sodium salt, an amine salt, a potassium salt, an ammonium salt, and combinations thereof. Maleic acid derivatives include, but are not necessarily limited to, di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl pheno succinate, dodecyl diphenyl succinate, ditridecyl succinate, dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium 1 -icosyl 2 sulfosuccinate, ammonium 1 ,4 didecyl sulfosuccinate, dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate, sodium lauryl sulfoacetate, salts thereof, and combinations thereof. In one non- limiting embodiment, the succinate may be a sulfosuccinate. The maleic acid derivative may be used in conjunction with an alkali salt, such as sodium, in one non-limiting embodiment.
[0017] In one non-limiting embodiment, the demulsifying agent includes at least one maleic acid derivative, e.g. dioctyl sulfosuccinate, and at least one naphthalene sulfonate, even though the maleic acid derivative is effective when used alone. Particular ratios of the maleic acid derivative and the naphthalene sulfonate that are beneficial range from about a 50/50 ratio of maleic acid derivative to naphthalene sulfonate independently to about a 95/5 ratio of maleic acid derivative to naphthalene sulfonate. Alternative ratios may include an 80/20 ratio of maleic acid derivative to naphthalene sulfonate, a 90/10 ratio of maleic acid derivative to naphthalene sulfonate, and the like.
[0018] A primary demulsifier may also be used with the demulsifying agent to promote the activity by the demulsifying agent. The primary demulsifier may be mixed with the demulsifying agent for injection of the primary demulsifier at the same time as the demulsifying agent. Alternatively, the primary demulsifier may be injected at a different location altogether from the demulsifying agent. As long as a primary demulsifier is used with the demulsifying agent, regardless of whether it is injected at the same time or a different time as the demulsifying agent, the demulsifying agent will be capable of performing its functions. Non-limiting examples of primary demulsifiers may be or include alkoxylated resins, alkoxylated dipropylene glycols, maleic esters, cross-linked alkoxylated resins, alkoxylated glycols, alkoxylated glycerins, and trisaminoemethane alkoxylates, and combinations thereof. However, the specific primary demulsifier to be used will depend on the composition and amount of the demulsifying agent used.
[0019] The solids may be suspended in the hydrocarbon stream or oil phase of the emulsion. Adding the demulsifying agent to the hydrocarbon stream or oil phase of the emulsion allows for the demulsifying agent to rest with the hydrocarbon stream and separate the solids therefrom prior to the injection of the hydrocarbon stream into a desalter, even if there is no sludge present in the crude storage tank. The demulsifying agent destabilizes the solids from the emulsion and affects rapid coalescence of water and preferentially water wets the solids. The water-wet solids are then carried into the water phase of the emulsion, thereby providing a reduced amount of solids within the hydrocarbon stream or oil phase of the emulsion. The water and the water-wet solids may then be removed for proper recovery of the hydrocarbon components with fewer solids. Overall, removal of the solids prior to the injection of the hydrocarbon stream causes fewer problems in the refinery and other processing downstream.
[0020] One non-limiting example of this occurs in the crude storage tank where the hydrocarbon stream or crude oil in the top of the crude storage tank is sufficiently low in solids, and the water containing the water-wet solids may be drained from the crude storage tank. Over a period of weeks to months, significant reductions in sludge volume may be achieved. Exposure of the bottom sludge from the crude storage tank to a crude oil treated with the demulsifying agent slowly reduces the level of sludge in the crude storage tank.
[0021] The introduction of the demulsifying agent into the hydrocarbon stream by itself may be sufficient mixing, or there may be an additional process for intentional mixing, such as a paddle stirrer or the like as one non-limiting example. Subsequently, the hydrocarbon stream is kept still or held quiescent in the crude storage tank for enough time to allow or permit the solids to water- wet by the demulsifying agent. In the instance of sludge removal, the water-wet solids may settle to the bottom of the crude storage tank under the influence of gravity. [0022] A goal of the method is to reduce the solids content in the hydrocarbon stream to an acceptable level for the hydrocarbon stream to be processed in a refinery. Said differently, complete separation of the solids from the hydrocarbon stream is desirable, but it should be appreciated that complete separation is not necessary for the methods discussed herein to be considered effective. Success is obtained if more solids are separated using the demulsifying agent than in the absence of the demulsifying agent.
[0023] In one non-limiting embodiment, the methods described are considered successful if a majority of the solids are separated, i.e. greater than 50 wt%, alternatively from about 60 wt% independently to about 90 wt% of the solids are separated, or from about 80 wt% independently to about 90 wt% in another non-limiting embodiment. By "separating" solids from the hydrocarbon stream is defined herein to mean any and all partitioning, sequestering, removing, transferring, eliminating, dividing, removing, dropping out of the solids from the hydrocarbon or crude oil to any extent.
[0024] In one non-limiting embodiment, the hydrocarbon stream would be treated with the demulsifying agent until a predetermined target concentration is reached. In another non-restrictive version, there may be a fixed amount of time before the hydrocarbon stream must be processed in the refinery. Thus, the dosage of the demulsifying agent would be adjusted to accomplish yielding a hydrocarbon stream with the necessary amount of solids content, types of solids, and/or size of solids threshold in the time required. However, it should be realized that the exact dosage will be very dependent upon the particular hydrocarbon stream and the needs of the particular refinery. Optimum dosages will have to be developed with experience and would be very difficult to predict in advance.
[0025] The amount of the demulsifying agent may range from about 0.1 ppm independently to about 200 ppm, alternatively from about 2 ppm independently to about 100 ppm, or from about 3.5 ppm independently to about 25 ppm in another non-limiting embodiment. However, it is difficult to determine the exact amount of the demulsifying agent to be added for optimum separation of the solids from the hydrocarbon stream because the amount depends on many variables, such as but not limited to the type of results desired, the type of hydrocarbon stream being processed, the amount of mixing, the temperature of the crude storage tank, the amount of settling time, the geometry of the crude storage tank, injection points, and constituency of the emulsion, etc. For example, if the treated hydrocarbon stream is to be stored in the crude storage tank for several hours, e.g. 10 hours, the treatment dosage of the demulsifying agent may be much lower than the treatment dosage for a hydrocarbon stream that is to be stored in a crude storage tank for about 3-5 hours. A higher dosage may provide better resolution of the emulsion in a shortened time period.
[0026] The amount of the demulsifying agent may also depend on the rate at which it is injected into the hydrocarbon stream and/or the crude storage tank. This amount may be adjusted as the crude flow rate changes to assure the refiner that all of the hydrocarbon stream receives the correct amount of demulsifying agent. One method of doing this is to use a variable speed chemical injection pump where a signal from an in-line flow sensor automatically adjusts the chemical injection rate as the flow rate of the hydrocarbon stream changes.
[0027] Settling agents may also be useful in facilitating the settling of various solids to the bottom of the crude storage tank. Suitable settling agents include, but are not necessarily limited to alkyoxylated phenolic resins; oxyalkylated polyamines, including, but not necessarily limited to ethoxylated and/or propoxylated 1 ,2-ethanediamine, N1 -(2-aminoethyl)-N2-[2-[(2- aminoethyl)amino]ethyl]-, and polymers with 2-methyloxirane and oxirane; oxyalkylated alkanol amines, including, but not necessarily limited to, ethoxylated and/or propoxylated 1 ,3-propanediol, 2-amino-2-(hydroxymethyl)- 1 ,3-propanediol, and again polymers with 2-methyloxirane and oxirane; Mannich reaction condensation products of alkyl phenols and polyamines and mixtures thereof. Amines suitable to make these settling agents may range from ethylene diamine to tetraethylene pentamine or higher. Suitable alkyl phenols for use in these settling agents may be those having one or more R group substituent, where R may be defined from C1 to C36 linear, branched, cyclic alkyl groups and combinations of these. The amounts of such settling agents may range from about 5 ppm independently to about 1000 ppm; alternatively from about 50 ppm independently to about 250 ppm.
[0028] Other additives may be added to the hydrocarbon stream including, but not necessarily limited to, corrosion inhibitors, demulsifiers, pH adjusters, metal chelants, scale inhibitors, hydrocarbon solvents, and mixtures thereof. As noted, in one non-limiting embodiment, the method is practiced ahead of a refinery desalting process that involves washing the crude emulsion with wash water.
[0029] In the foregoing specification, the invention has been described with reference to specific embodiments thereof, and has been described as effective in providing methods and compositions for separating solids from a hydrocarbon stream having solids therein. However, it will be evident that various modifications and changes can be made thereto without departing from the broader scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, hydrocarbon streams, crude oils, demulsifying agents, and solids falling within the claimed parameters, but not specifically identified or tried in a particular composition or method, are expected to be within the scope of this invention.
[0030] The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. For instance, the method may consist of or consist essentially of separating at least a portion of solids from a hydrocarbon stream having solids therein by adding a demulsifying agent to the hydrocarbon stream in an effective amount, where the demulsifying agent may be or include at least one maleic acid derivative, and the demulsifying agent water-wets at least a portion of the solids. [0031] Alternatively, the composition may consist of or consist essentially of a treated hydrocarbon stream in a crude storage tank including, but not limited to a demulsifying agent comprising at least one maleic acid derivative, in an amount ranging from about 0.1 ppm to about 200 ppm. The treated stream may further include a plurality of water-wet solids within the hydrocarbon stream where the plurality of solids are more water-wet as compared to a plurality of solids within the hydrocarbon stream in the absence of the demulsifying agent.
[0032] The words "comprising" and "comprises" as used throughout the claims, are to be interpreted to mean "including but not limited to" and "includes but not limited to", respectively.

Claims

CLAIMS What is claimed is:
1. A method for separating at least a portion of solids from a hydrocarbon fluid having solids therein comprising:
adding a demulsifying agent to the hydrocarbon fluid in an effective amount for subsequent separation of at least a portion of the solids from the hydrocarbon fluid; wherein the demulsifying agent water- wets at least a portion of the solids; wherein the demulsifying agent comprises at least one maleic acid derivative.
2. The method of claim 1 , wherein the adding the demulsifying agent occurs upstream from a desalter.
3. The method of claim 1 , wherein the demulsifying agent further comprises a second component selected from the group consisting of naphthalene sulfonate, alkyl diphenyloxide disulfonate, and combinations thereof.
4. The method of claim 1 , 2, or 3, wherein an emulsion comprises an oil phase and a water phase; and wherein the oil phase comprises the hydrocarbon fluid; and wherein the adding of the demulsifying agent is added to a phase selected from the group consisting of the oil phase, the water phase, and combinations thereof.
5. The method of claim 4, further comprising separating at least a portion of the water-wet solids from the hydrocarbon fluid.
6. The method of claim 5, further comprising mixing at least a portion of the water-wet solids into the water phase of the emulsion after separating at least a portion of the water-wet solids from the hydrocarbon fluid.
7. The method of claim 1 , 2, or 3 wherein the at least one maleic acid derivative is a C6-Ci8 sulfosuccinate,
8. The method of claim 1 , 2, or 3, wherein the at least one maleic acid derivative is selected from the group consisting of di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl phenyl succinate, dodecyl diphenyl succinate, ditridecyl succinate, dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium 1 -icosyl 2 sulfosuccinate, ammonium 1 ,4 didecyl sulfosuccinate, dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate, sodium lauryl sulfoacetate, salts thereof, and combinations thereof.
9. The method of claim 1 , 2, or 3, wherein the effective amount of the demulsifying agent ranges from 0.1 ppm to 200 ppm based on the hydrocarbon fluid.
10. The method of claim 1 , 2, or 3, wherein the adding the demulsifying agent is added to hydrocarbon fluid at a location selected from the group consisting of a crude storage tank, the suction of a transfer pump for subsequent injection into a crude storage tank, and combinations thereof.
1 1 . The method of claim 1 , 2, or 3, wherein the solids are inorganic solids selected from the group consisting of metal oxides, metal dioxides, metal sulfides, metal sulfates, metal carbonates, sand, silt, clay, paraffin wax, dolomite, coke fines, zinc compounds and combinations thereof.
12. A treated hydrocarbon fluid in a crude storage tank comprising:
a demulsifying agent comprising least one maleic acid derivative, wherein the amount of the demulsifying agent ranges from 0.1 ppm to 30 ppm based on the hydrocarbon fluid; and a plurality of water-wet solids within the hydrocarbon fluid, wherein the plurality of solids are more water-wet as compared to a plurality of solids within the hydrocarbon fluid in the absence of the demulsifying agent.
13. The treated hydrocarbon stream of claim 12, wherein the demulsifying agent further comprises a second component selected from the group consisting of naphthalene sulfonate, alkyl diphenyloxide disulfonate, and combinations thereof.
14. The treated hydrocarbon stream of claim 12 or 13, wherein the at least one maleic acid derivative is selected from the group comprising di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl phenyl succinate, dodecyl diphenyl succinate, ditridecyl succinate, dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium 1 -icosyl 2 sulfosuccinate, ammonium 1 ,4 didecyl sulfosuccinate, dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate, sodium lauryl sulfoacetate, salts thereof, and combinations thereof.
EP13861547.1A 2012-12-13 2013-12-12 Methods for removing solids from hydrocarbon streams Active EP2931844B1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
EP19161382.7A EP3514216A1 (en) 2012-12-13 2013-12-12 Methods and compositions for removing solids from hydrocarbon streams

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US201261736659P 2012-12-13 2012-12-13
US14/102,976 US20140166537A1 (en) 2012-12-13 2013-12-11 Methods and compositions for removing solids from hydrocarbon streams
PCT/US2013/074689 WO2014093633A1 (en) 2012-12-13 2013-12-12 Methods and compositions for removing solids from hydrocarbon streams

Related Child Applications (2)

Application Number Title Priority Date Filing Date
EP19161382.7A Division-Into EP3514216A1 (en) 2012-12-13 2013-12-12 Methods and compositions for removing solids from hydrocarbon streams
EP19161382.7A Division EP3514216A1 (en) 2012-12-13 2013-12-12 Methods and compositions for removing solids from hydrocarbon streams

Publications (3)

Publication Number Publication Date
EP2931844A1 true EP2931844A1 (en) 2015-10-21
EP2931844A4 EP2931844A4 (en) 2016-08-31
EP2931844B1 EP2931844B1 (en) 2019-08-14

Family

ID=50929702

Family Applications (2)

Application Number Title Priority Date Filing Date
EP19161382.7A Withdrawn EP3514216A1 (en) 2012-12-13 2013-12-12 Methods and compositions for removing solids from hydrocarbon streams
EP13861547.1A Active EP2931844B1 (en) 2012-12-13 2013-12-12 Methods for removing solids from hydrocarbon streams

Family Applications Before (1)

Application Number Title Priority Date Filing Date
EP19161382.7A Withdrawn EP3514216A1 (en) 2012-12-13 2013-12-12 Methods and compositions for removing solids from hydrocarbon streams

Country Status (7)

Country Link
US (1) US20140166537A1 (en)
EP (2) EP3514216A1 (en)
CN (1) CN104837960B (en)
CA (1) CA2894671C (en)
ES (1) ES2751385T3 (en)
PT (1) PT2931844T (en)
WO (1) WO2014093633A1 (en)

Families Citing this family (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9834730B2 (en) 2014-01-23 2017-12-05 Ecolab Usa Inc. Use of emulsion polymers to flocculate solids in organic liquids
US20160251568A1 (en) 2015-02-27 2016-09-01 Ecolab Usa Inc. Compositions for enhanced oil recovery
US10808165B2 (en) 2016-05-13 2020-10-20 Championx Usa Inc. Corrosion inhibitor compositions and methods of using same
WO2018005341A1 (en) * 2016-06-28 2018-01-04 Ecolab USA, Inc. Composition, method and use for enhanced oil recovery
US11214742B2 (en) 2017-03-03 2022-01-04 Exxonmobil Research And Engineering Company Apparatus and methods to remove solids from hydrocarbon streams

Family Cites Families (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2626902A (en) * 1950-12-01 1953-01-27 Petrolite Corp Process for breaking petroleum emulsions
US3756959A (en) * 1971-10-20 1973-09-04 American Cyanamid Co Nsions ecologically acceptable method of breaking mineral oil emulsionssuspe
US4336129A (en) * 1980-03-04 1982-06-22 Nippon Steel Chemical Co., Ltd. Method for treating a water-containing waste oil
IT1164263B (en) * 1983-06-03 1987-04-08 Energeco Spa AGENT AND DEMULSION COMPOSITION IN PARTICULAR FOR THE TREATMENT OF WATER-OIL EMULSIONS WITH HIGH SOLID CONTENT AND RELATED PROCEDURE
US20050284637A1 (en) * 2004-06-04 2005-12-29 Halliburton Energy Services Methods of treating subterranean formations using low-molecular-weight fluids
KR101340718B1 (en) * 2006-07-10 2013-12-12 에스케이에너지 주식회사 Method of removing the calcium from hydrocarbonaceous oil using maleic acid or its derivatives
KR101606515B1 (en) * 2008-01-24 2016-03-25 도르프 케탈 케미칼즈 (인디아) 프라이비트 리미티드 Method of removing metals from hydrocarbon feedstock using esters of carboxylic acids
CA2647964C (en) * 2008-12-19 2015-04-28 Richard A. Mcfarlane Processing of hydrocarbon feeds
US8540784B2 (en) * 2010-04-23 2013-09-24 Tellus Renewables Llc Fuel compositions
US20120187049A1 (en) * 2010-08-05 2012-07-26 Baker Hughes Incorporated Method of Removing Multi-Valent Metals From Crude Oil

Also Published As

Publication number Publication date
ES2751385T3 (en) 2020-03-31
CA2894671A1 (en) 2014-06-19
WO2014093633A1 (en) 2014-06-19
EP2931844B1 (en) 2019-08-14
PT2931844T (en) 2019-11-12
CA2894671C (en) 2019-07-02
EP2931844A4 (en) 2016-08-31
EP3514216A1 (en) 2019-07-24
US20140166537A1 (en) 2014-06-19
CN104837960B (en) 2018-06-08
CN104837960A (en) 2015-08-12

Similar Documents

Publication Publication Date Title
US9963642B2 (en) Additives to enhance metal and amine removal in refinery desalting processes
EP2931844B1 (en) Methods for removing solids from hydrocarbon streams
US7771588B2 (en) Separatory and emulsion breaking processes
US20120187049A1 (en) Method of Removing Multi-Valent Metals From Crude Oil
US20060272983A1 (en) Processing unconventional and opportunity crude oils using zeolites
US10745626B2 (en) Desalter operation
CA3066096C (en) Compositions and methods of removing contaminants in refinery desalting
US20140202923A1 (en) Methods and compositions for removing phosphorous-containing solids from hydrocarbon streams
US20180216019A1 (en) Methods and compositions for removing fine solids from hydrocarbon streams
CA2911920C (en) Steam diluent generator
US20210261871A1 (en) Liquid/liquid extraction of hydrocarbons in bulk storage tanks
CA3022131C (en) Method and apparatus to produce sales oil in a surface facility for a solvent based eor process
WO2022178463A1 (en) Liquid-liquid extraction of hydrocarbons in bulk storage tanks
EP4294895A1 (en) Liquid-liquid extraction of hydrocarbons in bulk storage tanks

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20150624

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

AX Request for extension of the european patent

Extension state: BA ME

DAX Request for extension of the european patent (deleted)
A4 Supplementary search report drawn up and despatched

Effective date: 20160803

RIC1 Information provided on ipc code assigned before grant

Ipc: C10G 33/04 20060101AFI20160728BHEP

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: EXAMINATION IS IN PROGRESS

17Q First examination report despatched

Effective date: 20180220

GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: GRANT OF PATENT IS INTENDED

INTG Intention to grant announced

Effective date: 20190301

RAP1 Party data changed (applicant data changed or rights of an application transferred)

Owner name: BAKER HUGHES, A GE COMPANY, LLC

RAP1 Party data changed (applicant data changed or rights of an application transferred)

Owner name: BAKER HUGHES, A GE COMPANY, LLC

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE PATENT HAS BEEN GRANTED

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

Ref country code: AT

Ref legal event code: REF

Ref document number: 1167015

Country of ref document: AT

Kind code of ref document: T

Effective date: 20190815

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602013059300

Country of ref document: DE

REG Reference to a national code

Ref country code: PT

Ref legal event code: SC4A

Ref document number: 2931844

Country of ref document: PT

Date of ref document: 20191112

Kind code of ref document: T

Free format text: AVAILABILITY OF NATIONAL TRANSLATION

Effective date: 20191031

REG Reference to a national code

Ref country code: NL

Ref legal event code: FP

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

REG Reference to a national code

Ref country code: NO

Ref legal event code: T2

Effective date: 20190814

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191114

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 1167015

Country of ref document: AT

Kind code of ref document: T

Effective date: 20190814

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: AL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: RS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191214

REG Reference to a national code

Ref country code: GR

Ref legal event code: EP

Ref document number: 20190403308

Country of ref document: GR

Effective date: 20200213

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

REG Reference to a national code

Ref country code: ES

Ref legal event code: FG2A

Ref document number: 2751385

Country of ref document: ES

Kind code of ref document: T3

Effective date: 20200331

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20200224

Ref country code: SM

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

REG Reference to a national code

Ref country code: DE

Ref legal event code: R097

Ref document number: 602013059300

Country of ref document: DE

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

PG2D Information on lapse in contracting state deleted

Ref country code: IS

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

26N No opposition filed

Effective date: 20200603

REG Reference to a national code

Ref country code: BE

Ref legal event code: MM

Effective date: 20191231

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191212

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191212

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191231

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191231

Ref country code: BE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191231

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

Ref country code: HU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO

Effective date: 20131212

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190814

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: PT

Payment date: 20221123

Year of fee payment: 10

Ref country code: IT

Payment date: 20221122

Year of fee payment: 10

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GR

Payment date: 20221123

Year of fee payment: 10

P01 Opt-out of the competence of the unified patent court (upc) registered

Effective date: 20230526

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: NL

Payment date: 20231121

Year of fee payment: 11

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20231121

Year of fee payment: 11

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: NO

Payment date: 20231123

Year of fee payment: 11

Ref country code: FR

Payment date: 20231122

Year of fee payment: 11

Ref country code: DE

Payment date: 20231121

Year of fee payment: 11

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: ES

Payment date: 20240102

Year of fee payment: 11

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PT

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20240612

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PT

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20240612

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GR

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20240712