EP2931844B1 - Verfahren zur entfernung von feststoffen aus kohlenwasserstoffströmen - Google Patents

Verfahren zur entfernung von feststoffen aus kohlenwasserstoffströmen Download PDF

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Publication number
EP2931844B1
EP2931844B1 EP13861547.1A EP13861547A EP2931844B1 EP 2931844 B1 EP2931844 B1 EP 2931844B1 EP 13861547 A EP13861547 A EP 13861547A EP 2931844 B1 EP2931844 B1 EP 2931844B1
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EP
European Patent Office
Prior art keywords
solids
demulsifying agent
hydrocarbon stream
succinate
crude
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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.)
Active
Application number
EP13861547.1A
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English (en)
French (fr)
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EP2931844A4 (de
EP2931844A1 (de
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
Baker Hughes a GE Co LLC
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Publication date
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Priority to EP19161382.7A priority Critical patent/EP3514216A1/de
Publication of EP2931844A1 publication Critical patent/EP2931844A1/de
Publication of EP2931844A4 publication Critical patent/EP2931844A4/de
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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 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 demulsifying agent as defined in claim 1.
  • 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 11 kilograms per thousand barrels) to about 2500 ptb (about 1133 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 method for separating at least a portion of solids from a hydrocarbon stream having a plurality of 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 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; and wherein the demulsifying agent water-wets at least a portion of the solids; and separating at least a portion of the water-wet solids from the hydrocarbon fluid; wherein the demulsifying agent is selected from the group consisting of di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl phenyl succinate, dodecyl diphenyl
  • the demulsifying agent appears to water-wet the solids in such a way to allow the solids to separate from a hydrocarbon stream, and then the solids may be removed or incorporated into a water phase.
  • a demulsifying agent as a pre-treatment or preconditioning for a hydrocarbon stream allows 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 is added to the hydrocarbon stream at a location upstream from a desalter.
  • the agent has more contact time and therefore better performance by the agent when it is added as a pre-treatment to the hydrocarbon stream upstream from the desalter.
  • Such a pre-treatment allows the agent 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 demulsifying agent as a pre-treatment instead of adding the agent 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 demulsifying agent is added to the hydrocarbon stream and the agent 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 agent rests with the hydrocarbon stream for a period of 30 minutes to 5 days prior to the injection of the pre-treated hydrocarbon stream into the desalter, alternatively from about 30 minutes to 120 hours.
  • a 'pre-treated' hydrocarbon stream is defined herein to be a hydrocarbon stream that has the agent therein where the agent 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 is a crude oil.
  • 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.
  • 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 O 3 , Fe 3 O 4 , Fe 2 O 3 ), copper oxides (Cu 2 O and/or CuO), manganese oxides (MnO, Mn 3 O 4 , Mn 2 O 3 , MnO 2 , and Mn 2 O 7 ), zinc oxides, nickel oxides, and combinations thereof; a non-limiting example of metal dioxides may be or include titanium dioxide.
  • 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 as defined in claim 1 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 2A1TM, which is supplied by Dow Chemical Company.
  • the demulsifying agent is selected from di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl pheno succinate, dodecyl diphenyl succinate, ditridecyl succinate, sodium lauryl sulfoacetate, salts thereof, and combinations thereof.
  • the demulsifying agent may be used in conjunction with an alkali salt, such as sodium, in one non-limiting embodiment.
  • the demulsifying agent includes at least one agent as defined in claim 1, and at least one naphthalene sulfonate, even though the demulsifying agent is effective when used alone.
  • Particular ratios of the demulsifying agent and the naphthalene sulfonate that are beneficial range from about a 50/50 ratio of demulsifying agent to naphthalene sulfonate independently to about a 95/5 ratio of demulsifying agent to naphthalene sulfonate.
  • Alternative ratios may include an 80/20 ratio of demulsifying agent to naphthalene sulfonate, a 90/10 ratio of demulsifying agent 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. 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.
  • 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 ranges from 0.1 ppm independently to 200 ppm, alternatively from 2 ppm independently to 100 ppm, or from 3.5 ppm independently to 25 ppm in another non-limiting embodiment.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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 is defined in claim 1, and the demulsifying agent water-wets at least a portion of the solids.

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  • 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)

Claims (4)

  1. Verfahren zum Abtrennen mindestens eines Teils von Feststoffen aus einem Kohlenwasserstofffluid, das Feststoffe darin aufweist, umfassend:
    Zugeben eines Demulgators zu dem Kohlenwasserstofffluid in einer wirksamen Menge für eine nachfolgende Abtrennung mindestens eines Teils der Feststoffe aus dem Kohlenwasserstofffluid; wobei eine Emulsion eine Ölphase und eine Wasserphase umfasst; und wobei die Ölphase das Kohlenwasserstofffluid umfasst; und wobei das Zugeben des Demulgators zu einer Phase zugegeben wird, die ausgewählt ist aus der Gruppe bestehend aus der Ölphase, der Wasserphase und Kombinationen davon; und wobei das Demulgatorwasser mindestens einen Teil der Feststoffe benetzt; und
    Abtrennen mindestens eines Teils der benetzten Feststoffe aus dem Kohlenwasserstofffluid;
    wobei der Demulgator ausgewählt ist aus der Gruppe bestehend aus Dilaurylsuccinat, Dioctylsuccinat, Dihexylsuccinat, Octylphenylsuccinat, Dodecyldiphenylsuccinat, Ditridecylsuccinat, Natriumlaurylsulfoacetat, Salzen davon und Kombinationen davon;
    wobei die wirksame Menge des Demulgators im Bereich von 0,1 ppm bis 200 ppm, bezogen auf das Kohlenwasserstofffluid, liegt;
    wobei der Kohlenwasserstoffstrom ein Rohöl ist und wobei das Zugeben des Demulgators einem Entsalzer vorgeschaltet erfolgt und der Demulgator mit dem Kohlenwasserstoffstrom für einen Zeitraum von 30 Minuten bis 5 Tagen vor Injektion in den Entsalzer ruht.
  2. Verfahren nach Anspruch 1, wobei der Demulgator ferner einen zweiten Bestandteil umfasst, der ausgewählt ist aus der Gruppe bestehend aus Naphthalinsulfonat, Alkyldiphenyloxiddisulfonat und Kombinationen davon.
  3. Verfahren nach Anspruch 1, oder 2, wobei das Zugeben des Demulgators zu dem Kohlenwasserstofffluid an einer Stelle zugegeben wird, die ausgewählt ist aus der Gruppe bestehend aus einem Rohlagertank, dem Sog einer Übertragungspumpe für nachfolgende Injektion in einen Rohlagertank und Kombinationen davon.
  4. Verfahren nach Anspruch 1 oder 2, wobei die Feststoffe anorganische Feststoffe sind, die ausgewählt sind aus der Gruppe bestehend aus Metalloxiden, Metalldioxiden, Metallsulfiden, Metallsulfaten, Metallcarbonaten, Sand, Schlick, Ton, Paraffinwachs, Dolomit, Koksfeinstoffen, Zinkverbindungen und Kombinationen davon.
EP13861547.1A 2012-12-13 2013-12-12 Verfahren zur entfernung von feststoffen aus kohlenwasserstoffströmen Active EP2931844B1 (de)

Priority Applications (1)

Application Number Priority Date Filing Date Title
EP19161382.7A EP3514216A1 (de) 2012-12-13 2013-12-12 Verfahren und zusammensetzungen zur entfernung von feststoffen aus kohlenwasserstoffströmen

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 (de) 2012-12-13 2013-12-12 Verfahren und zusammensetzungen zur entfernung von feststoffen aus kohlenwasserstoffströmen
EP19161382.7A Division EP3514216A1 (de) 2012-12-13 2013-12-12 Verfahren und zusammensetzungen zur entfernung von feststoffen aus kohlenwasserstoffströmen

Publications (3)

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

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EP13861547.1A Active EP2931844B1 (de) 2012-12-13 2013-12-12 Verfahren zur entfernung von feststoffen aus kohlenwasserstoffströmen
EP19161382.7A Withdrawn EP3514216A1 (de) 2012-12-13 2013-12-12 Verfahren und zusammensetzungen zur entfernung von feststoffen aus kohlenwasserstoffströmen

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US (1) US20140166537A1 (de)
EP (2) EP2931844B1 (de)
CN (1) CN104837960B (de)
CA (1) CA2894671C (de)
ES (1) ES2751385T3 (de)
PT (1) PT2931844T (de)
WO (1) WO2014093633A1 (de)

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US9834730B2 (en) 2014-01-23 2017-12-05 Ecolab Usa Inc. Use of emulsion polymers to flocculate solids in organic liquids
CA2976263C (en) 2015-02-27 2023-03-21 Ecolab Usa Inc. Compositions for enhanced oil recovery
WO2017196938A1 (en) 2016-05-13 2017-11-16 Ecolab USA, Inc. Corrosion inhibitor compositions and methods of using same
CA3029400A1 (en) 2016-06-28 2018-01-04 Ecolab Usa Inc. Composition, method and use for enhanced oil recovery
WO2018160787A1 (en) * 2017-03-03 2018-09-07 Exxonmobil Research And Engineering Company Apparatus and methods to remove solids from hydrocarbon streams

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US2626902A (en) * 1950-12-01 1953-01-27 Petrolite Corp Process for breaking petroleum emulsions
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IT1164263B (it) * 1983-06-03 1987-04-08 Energeco Spa Agente e composizione demulsionante in particolare per il trattamento di emulsioni del tipo acqua-olio ad elevato contenuto di solidi e relativo procedimento
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KR101340718B1 (ko) * 2006-07-10 2013-12-12 에스케이에너지 주식회사 말레인산 또는 그 유도체를 이용한 탄화수소류유분으로부터 칼슘의 제거방법
BRPI0905734B1 (pt) * 2008-01-24 2017-11-14 Dorf Ketal Chemicals I Method for removal of metals from raw materials using carboxylic acid esters
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US20120187049A1 (en) * 2010-08-05 2012-07-26 Baker Hughes Incorporated Method of Removing Multi-Valent Metals From Crude Oil

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CA2894671A1 (en) 2014-06-19
ES2751385T3 (es) 2020-03-31
CA2894671C (en) 2019-07-02
CN104837960B (zh) 2018-06-08
WO2014093633A1 (en) 2014-06-19
EP2931844A4 (de) 2016-08-31
PT2931844T (pt) 2019-11-12
CN104837960A (zh) 2015-08-12
EP2931844A1 (de) 2015-10-21
EP3514216A1 (de) 2019-07-24
US20140166537A1 (en) 2014-06-19

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