US20090134068A1 - Separation of water from hydrocarbons - Google Patents

Separation of water from hydrocarbons Download PDF

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Publication number
US20090134068A1
US20090134068A1 US12/289,295 US28929508A US2009134068A1 US 20090134068 A1 US20090134068 A1 US 20090134068A1 US 28929508 A US28929508 A US 28929508A US 2009134068 A1 US2009134068 A1 US 2009134068A1
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water
hydrocarbon
treating agent
solvent
blend
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US12/289,295
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Robert J. Falkiner
Bal K. Kaul
Ian D. Campbell
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SAS Institute Inc
ExxonMobil Technology and Engineering Co
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ExxonMobil Research and Engineering Co
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Priority to US12/289,295 priority Critical patent/US20090134068A1/en
Publication of US20090134068A1 publication Critical patent/US20090134068A1/en
Assigned to SAS INSTITUTE INC. reassignment SAS INSTITUTE INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: FOLSOM, TODD C., LESLIE, SCOTT PAUL
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    • 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

  • This invention relates to a method for the separation of water from hydrocarbons, especially liquid hydrocarbons such as petroleum naphthas, natural gas condensates, petroleum fuels such as gasoline, middle distillates such as road diesel fuel and kerojet, particularly under low temperature conditions.
  • the water removed may be present as such in the hydrocarbons or mixed with other water-miscible materials or contaminants which may be removed simultaneously with the water.
  • Petroleum refinery streams may be treated with water, steam or various aqueous solutions during processing in order to carry out the processing and to meet various quality specifications.
  • Steam stripping, caustic treating and amine treating are frequently used in conventional refinery processing and although much of the water introduced in this way can be removed by simple settling procedures, a certain amount of water remains in the fuel after removal of the bulk of the water.
  • Water removal may usually be effected by the addition of a dehydrating agent or hydrate suppressor such as ethylene glycol followed by separation of the water/glycol phase from the hydrocarbon liquids in the conventional manner.
  • a dehydrating agent or hydrate suppressor such as ethylene glycol
  • Coalescing devices are particularly effective where the volume of liquid to be removed is small in comparison to the volume of the phase from which it is removed so that the technique is of potential application for the separation of small quantities of water from hydrocarbon fuels.
  • the Gardener article discusses the factors that are relevant to the coalescence of droplets of the discontinuous phase from the continuous phase and the ease or difficulty of separation of the immiscible phases. These factors include the physical properties of the phases such as density, viscosity, surface tension and interfacial tension. In addition, the properties of the system such as drop size, curvature of the liquid/liquid interface, temperature, concentration gradients and vibrations may also affect the effectiveness of the coalescence. As noted in U.S. Pat. No.
  • the type of coalescer employed for the separation depends on the difficulty of separation or coalescence as influenced by the various relevant factors outlined above.
  • the type of fluids being separated frequently determines the nature of the packing used in the coalescence device. Glass fibers have found widespread industrial application in commercial devices. Frequently, however, the presence of surfactants in water/hydrocarbon emulsions lowers the interfacial tension to a value less than about 20 dynes/cm at which the emulsions are stable enough to resist being broken through processing in conventional mesh packing/glass fiber coalescers as well as by other techniques.
  • While electrostatic precipitators may be effective on such emulsions down to interfacial tensions below 10 dyne/cm, their use is rather less favored than the relatively cheaper coalescence method.
  • Surfactants disarm conventional glass filters coalescers by bonding with glass fibers, allowing water molecules to flow through the coalescers with the hydrocarbons. Frequent changes of the cartridge material in the coalescers may obviate this problem but the increased labor and disposal costs associated with frequent cartridge change out are undesirable as is the continued need to monitor the quality of the product to ensure that appropriate specifications are being met.
  • the use of various polymeric materials such as phenolic or acrylic resins which act primarily as binding agents for glass fiber packings may be effective to reduce disarming of coalescers to a significant extent, but the problem remains.
  • U.S. Pat. No. 5,443,724 discloses a coalescer-separator apparatus which enables longer coalescer cartridge life to be obtained as a result of improved flow distribution within the device.
  • the device is stated to be particularly suitable for the separation of water from organic liquids such as fuels and is capable of achieving extended life using a more compact unit with the same or improved level of performance compared to larger conventional units.
  • the coalescence is carried out using a packing material which has a critical wetting surface energy which is intermediately critical wetting surface tension (CWST) of the discontinuous and continuous phase liquids.
  • CWST critical wetting surface tension
  • coalescence separation of liquids by the coalescence technique requires three stages to be successful. First of all, filtration is required to remove fine particles such as iron oxide and iron sulfide that stabilize emulsions and for this purpose, mesh, screen, packed and sand filters are normally satisfactory. Filtration is followed by the coalescence step which, in the case of water and hydrocarbon fuels, is normally accomplished by the use of fluoropolymer membranes which are effective emulsion breakers in liquids with an interfacial tension of greater than about 1 dyne/cm.
  • hydrophobic barrier membrane again normally formed from a polymeric material such as fluoropolymer, which permits the hydrocarbon fuel to flow through the cartridge while preventing transfer of the water across the membrane.
  • a method has been devised for the removal of dissolved water or water and ice from hydrocarbon liquid products in a manner which enables the hydrocarbon products to be readily treated by the coalescence/separation technique while reducing the potential for plugging filters and other equipment with ice crystals or solid deposits.
  • dissolved water or water/ice is removed from liquid hydrocarbons by contacting the a feed stream of the hydrocarbon with a liquid treating agent having an affinity for water prior to subjecting the hydrocarbon/treating agent mixture to coalescence/separation to remove the water from the hydrocarbon.
  • the treating agent is separated, together with water removed from the feed stream, from the hydrocarbon product by the coalescence/separation step and recirculated to the feed.
  • composition of the circulating aqueous phase comprising the treating agent and removed water is controlled to achieve the desired level of water removal to meet relevant product specifications. Consistent with the removal of the water during the coalescence/separation, the water concentration of the circulating treating agent/water blend will tend to increase gradually with transfer of the water in the feed to the circulating fluid. This progressive increase in water content can be compensated by controlled addition of pure treating agent solvent to the recirculating fluid coupled with accumulation of the treating agent/water mixture and continuous or periodic dumping of excess mixture. Alternatively, the circulating mixture may be subjected to continuous or batch regeneration or disposed of in any other way which is convenient and economical.
  • the treating agent which finds a wide degree of utility as well as being economically favorable comprises a mixture of (i) water with (ii) a water-hydrocarbon co-solvent.
  • the preferred class of co-solvents are the alcohols, especially methanol, but other water-miscible organic compounds may also be used, as described below.
  • Other, generally less favorable treating agents which may be used include strong aqueous salt solutions, as well as organic and inorganic liquids such as amines or even acids, particularly if it is desired to remove a contaminant from the hydrocarbon which can be reacted with the treating agent or a component of it.
  • FIGURE of the accompanying drawings is a schematic flowchart of a system for removing water from hydrocarbon liquid products using a coalescence/separation technique.
  • the amount of water which is present in these materials prior to separation will be relatively small, typically not more than about 5 volume percent, but product specifications will normally require a much lower water content in order to be acceptable.
  • product specifications will normally require a much lower water content in order to be acceptable.
  • D2 diesel fuel is required to contain no more than 0.2% combined water and sediment and similar requirements will be encountered with aviation kerosenes in view of the very low temperatures encountered by military and commercial jet aircraft at high altitudes.
  • the present separation technique is not dependent upon the chemical composition of the hydrocarbon fuel except to the extent that the chemical composition affects physical properties such as specific gravity, interfacial surface tension, miscibility with water and viscosity.
  • the chemical composition may also affect the degree to which surfactants added during processing or spontaneously formed during the processing (for example, during caustic washing) and the effect the surfactants may have on the other properties, especially emulsion stability, micelle formation, reverse micelle formation.
  • the present method is also applicable to the separation of water from natural gas liquids also known as natural as condensates.
  • These low viscosity hydrocarbon liquids generally comprise propane, butane and possibly higher hydrocarbons separated from the lower boiling methane and ethane in natural gas from subterranean wells.
  • Natural gas may, as noted above, need to be treated at or near the wellhead to remove either produced water or water combined with various chemicals such as hydrate suppressors, for instance, ethylene glycol, which have been used to treat the produced gas and which have separated out with the liquids as a result of their boiling in the temperature range set for the liquids.
  • the present invention provides an effective method for the removal of water/glycol (ethylene glycol) mixtures from natural gas liquids.
  • a liquid treating agent which has an affinity for the water in the hydrocarbon feed is mixed with the liquid hydrocarbon before the fuel is subjected to coalescence/separation treatment.
  • the treating agent causes the water and possibly other contaminants to form an aqueous mixture which, when in fully coalesced form, is substantially immiscible with the hydrocarbon although initially it may be suspended in the majority hydrocarbon phase and not readily separable from it by other means. It is this aqueous mixture which is then separated from the hydrocarbon in the coalescence/separation step.
  • the treating agent and water are separated in the form of a single coalesced phase which is substantially immiscible with the hydrocarbon majority component and recirculated for further addition to the feed.
  • An illustrative schematic of the process configuration is shown in the attached FIGURE by way of example.
  • the treating agent has for its required effect to have an affinity for the water which is to be removed from the hydrocarbon feed. It may also desirably have an affinity for any other contaminants in the feed which should be removed at this time.
  • the feed also contains an acidic contaminant such as hydrogen sulfide
  • the use of an amine as the treating agent may be used to effect removal of the hydrogen sulfide as well as of the water.
  • the feed is, for example, a refinery stream containing basic contaminants such as alkalis from caustic treatment
  • the use of an acidic treating agent may be effective to remove both water and the residual alkali.
  • the reactive components of the treating agent may make up the entire treating agent or may be added as additive components.
  • a very useful treating agent is a mixture of water and a co-solvent, miscible with both the alcohol and with the hydrocarbon. This has been found to be very effective in removing water from refinery liquid fuel products such as gasoline and middle distillates such as road diesel, kerojet or heating oil. As noted below, it may also be used with natural gas condensates.
  • refinery liquid fuel products such as gasoline and middle distillates such as road diesel, kerojet or heating oil.
  • it may also be used with natural gas condensates.
  • One preferred embodiment of the invention is shown in the drawing and is described below by reference to the treatment of a refinery fuel with such a treating agent.
  • a refinery fuel such as mogas, road diesel or kerojet is introduced by way of line 11 to prefilter 12 with the alcohol/water mixture being added through line 13 .
  • Prefilter 12 is suitably a mesh or screen filter with additional packing, e.g. compressed glass fibers or polymer (nylon, polyolefin) mesh, adapted to remove fine particulate matter such as iron oxide, silica, which may stabilize emulsions and possibly damage the coalescer/separation units.
  • additional packing e.g. compressed glass fibers or polymer (nylon, polyolefin) mesh
  • Use of a high efficiency prefilter such as a sand filter may result in some removal of water.
  • coalescence/separation unit 15 After passing through prefilter 12 , the blend of hydrocarbon, alcohol and water passes through line 14 to coalescence/separation unit 15 .
  • Coalescer unit 15 is divided into two stages, comprising a first or coalescence stage 16 and a second or separation stage 17 .
  • the coalescence stage the suspended particles of water are subjected to coalescence into larger droplets in the presence of a suitable coalescing medium through which the liquids pass in order to effect the desired coalescence of the water, now with the added co-solvent.
  • separation stage 17 the combined fluids pass over a separation membrane which is selected to have a surface energy favoring passage of the hydrocarbon phase through the walls of the separation membrane while excluding the aqueous phase comprising the co-solvent and the water.
  • the liquid hydrocarbon fuel, now containing only a small and acceptable amount of water passes out of the coalescence/separation unit through line 18 to product storage while the separated co-solvent/water phase, now containing water removed from the original fuel feed, is removed through line 19 for recirculation to the feed.
  • a control valve 20 is provided in the recycle loop under control of manual or automatic controller 21 to permit actuation of the recycle when required. Recirculation is generally not required for operation above freezing point (0° C.) when only the normal coalescence of free water is required, with no hazard of ice crystal formation.
  • injection and recirculation of the co-solvent/water blend can be initiated in order to prevent filter and equipment plugging by ice crystals.
  • Actuation of the injection of the co-solvent/water blend into the feed and recirculation can be initiated either manually or automatically in response to ambient temperature sensors or, preferably, by a pressure sensor on a filter responsive to pressure increase upon plugging with ice crystals.
  • the alcohol/water blend passes from control valve 20 to injection line 13 through line 22 with additional co-solvent being injected to the circuit through line 24 in order maintain the desired co-solvent/water ratio for effective coalescence and separation.
  • additional co-solvent being injected to the circuit through line 24 in order maintain the desired co-solvent/water ratio for effective coalescence and separation.
  • excess co-solvent/water mixture may be purged through the circuit through line 25 and to dump tank 26 from which the blend may be removed through line 27 .
  • the same technique may be used to separate water/glycol mixtures from natural gas condensates.
  • similar considerations apply except that the residual water content in the gas may not be as low as required for high quality fuel products, being set, however, by pipelining specifications which may vary according to the temperature conditions prevailing along the pipeline with more stringent specifications prevailing in the colder climates and for undersea pipelines.
  • the co-solvent which is used in the blend with the water to promote removal of the water from the hydrocarbon feed is a liquid which is miscible with both water and the hydrocarbon majority component, at least to a limited extent.
  • Organic liquids such as oxygenates are generally suitable and preferred for this purpose in view of their availability, cost and functioning in the present process.
  • oxygenate esters such as the esters of lower fatty acids and lower alcohols such as ethyl acetate, ethyl propionate, propyl acetate, ethyl butyrate, amyl acetate
  • esters of the lower alkanols such as methanol, ethanol, propanol and the lower oxo-alcohols with lower fatty acids such as hexanoic acid, octanoic acid (e.g.
  • 2-ethyl hexanoic acid as well as other oxygenates such as the ketones, such as acetone, methyl ethyl ketone (MEK), methyl propyl ketone, aldehydes, ethers such as dimethyl ether and methyl propyl ether, may be used
  • the preferred co-solvents are alcohols, especially the lower alkanols such as methanol, ethanol and propanol. Alcohols are particularly suited to the removal of water/glycol mixtures from natural gas condensates in view of their miscibility for with both the water and the glycol hydrate suppressor.
  • the extent to which the co-solvent is required to be miscible with both water and the hydrocarbon is not important as long as the selected co-solvent is miscible with water in all proportions which are used in the process and that the co-solvent has an affinity for water. It is the co-solvent's affinity for water which effects the dehydration of the hydrocarbon e.g. the fuel or NGL (natural gas liquids) and its miscibility with the water which enables the blend of co-solvent and water to be effectively removed from the hydrocarbon by the coalescence technique.
  • the extent to which the co-solvent may be miscible with the hydrocarbon may affect the extent to which the dehydration is completed, a factor which may be significant with fuels.
  • the lower alkanols which from the preferred class of co-solvents for use in the present process are those which have a limited solubility in liquid refinery hydrocarbon fuels and NGL. Since the compositions of fuel and NGL may vary, the selected alcohol may vary also. As with other potential co-solvents, the alcohols will be selected for their mutual solubility in hydrocarbons and water as well as their convenient availability and favorable economics.
  • the alcohols may be monohydric, dihydric or higher alcohols although monohydric and dihydric alcohols (glycols) will normally be preferred.
  • ether groups may also be present on the alcohols, for example, ether groups, although halogens will normally not be preferred for reasons of cost, toxicity, and corrosion potential; hydroxyamines should normally be excluded in view of their potential to act as surfactants for the hydrocarbon/water system.
  • the preferred monohydric alcohols are methanol and ethanol although propanol may also be used to advantage and glycols such as ethyleneglycol, propyleneglycol, dipropyleneglycol, as well as glycol ethers such as ethyleneglycol methylether, diethyleneglycol methylether and others will be found suitable.
  • Alcohols with relatively higher solubilities in the hydrocarbon phase may be used at the expense of excessive losses to treated fuels and NGL unless they are combined with relatively high amounts of water, a measure which detracts from the dehydration which is the object of the process.
  • the loss of alcohol or other selected co-solvent to the fuel is not, however, in it self necessarily undesirable since the alcohol may act as a deicer in the fuel product, both during distribution and subsequent use, so eliminating the need for a separate deicing additive injection.
  • salt solutions may be found very effective in warmer climates where freezing problems will not be encountered.
  • the use of salt solutions may also be economically favorable.
  • the same simple conventional methods may be used to maintain the concentration of the salt in the solution to restore its functionality as the dehydrating agent, e.g. by the addition of fresh salt and removal of a portion of the circulating volume of liquid or by regenerating the solution, for example, by distillation or membrane separation (osmosis).
  • salt solutions may be cheap enough to be used on a once-through basis with regeneration, particularly if used only intermittently.
  • Suitable amines for this purpose many include substituted amines such as triethanolamine and diethanolamine as well as simple amines such as monoethanolamine.
  • These treating agents may be useful for removing water simultaneously with acidic contaminants such as hydrogen sulfide or carbonyl sulfide from natural gas liquids.
  • the amount of the treating agent, e.g. co-solvent/water blend which is added relative to the feed and the relative amounts of co-solvent and water in the blend are codependent variables to a certain extent.
  • a loss of the co-solvent to the hydrocarbon does take place but this can be controlled by increasing the amount of water in the blend which is injected into the fuel.
  • the addition of more water detracts from the effectiveness of the dehydration if resort is made to this expedient in order to limit the loss of co-solvent to the fuel.
  • Another factor which requires consideration is the effect of the co-solvent upon the fuel product specifications.
  • the amount of water in the co-solvent/water blend will depend upon the selected co-solvent, its solubility in the hydrocarbon components of the fuel or other hydrocarbon liquid, the ratio of water/co-solvent blend to the hydrocarbon, operating temperature and other factors. Taking the lower alcohol, methanol, as the selected solvent, the ratio of methanol to water will normally vary between 20/80 and 80/20 by volume. This ratio will vary with other alcohols and other co-solvents according to the specific alcohol or other co-solvent selected, its solubility characteristics with water and the hydrocarbon and the extent to which transfer of the alcohol to the hydrocarbon fuel can be tolerated and the amount of water in the initial hydrocarbon feed. Normally, however, with methanol as the alcohol, the volume ratio of alcohol and water will be from about 75:25 to 25:75 with approximately 50:50 blends being normally adequate.
  • the preferred alcohol for use in the present process is methanol which is selected not only for its low cost, low viscosity and boiling point (if reclaiming is desired) but also for its effectiveness in dissolving solid ice when present.
  • a 50:50 methanol/water blend has been found to be extremely effective and this ratio is sufficiently concentrated to dehydrate the fuel down to low water levels.
  • the freezing point of a 50/50 methanol/water mixture is below 40° C. so the process is capable of operating at ambient temperature over wide limits from less than ⁇ 40° C. up to relatively high ambient temperatures. This reperesents a very useful working range, especially for use with fuel treatment in cold climates and for gas condensate treatment when low temperature gas pipeline specifications have to be met.
  • Methanol has the additional advantage that loss to the hydrocarbon fuel majority component is relatively small, as compared to higher alcohols and for this reason, process losses may be minimized.
  • Combinations of alcohols such as methanol with dipropyleneglycol may be used when it is desired to achieve some losses to fuels in order to provide residual deicing capability for the treated fuel product.
  • the amount of the co-solvent/water blend which is added to the hydrocarbon feed is typically less than 10% by volume of the total feed although the exact amount selected will be depend upon the degree of dehydration desired, the co-solvent e.g. alcohol selected, the ratio of water to co-solvent in the blend and any relevant product specifications such as flash point for treated fuel products. Also relevant would be the ratio of water and glycol in treating natural gas condensates which have been treated with glycol hydrate suppressor. Normally, in the case of alcohol/water blends, the amount of the alcohol/water blend will be from 0.1 to 10% by volume of the total fuel feed and in most cases from 0.5 to 5% of the feed will be found sufficient. In many cases, about 1% by volume of the feed will be adequate with the 50/50 methanol/water blend selected for the dehydration.
  • the prefilters which are used ahead of the coalescer may be any suitable type of conventional filter, including sand filters, metal or polymer meshes, or other porous material capable of removing small solid particles which would tend to stabilize the fuel/water emulsions and which might result in damage to the more delicate coalescer membranes.
  • Polyester and nylon mesh filters are suitable, typically with crush strengths in the range of 70-145 kg.cm ⁇ 2 (75-150 psi) and other non-woven filter materials may be used as convenient alternatives.
  • the filter material may be contained in a conventional filter housing and the filter material in any convenient configuration which provides the desired filter life, filtration capacity and flow rate, for example, pleated mats, cylindrical sheets or mats, helical or spirally wound mats.
  • the material of the coalescer and separation elements in the coalescing unit and the separation unit may be provided in a form which provides the necessary mechanical strength, liquid flow rate and unit life.
  • the media serving as the coalescer and separator materials may be provided in sheet form which may be formed either as flat sheets, pleated or corrugated sheets or in other suitable arrangements e.g. cylindrically, helically or spirally wound sheets, as disclosed in U.S. Pat. No. 5,443,724 to which reference is made for a disclosure of suitable coalescer and separator materials and configurations for them.
  • the coalescer promotes the coalescence of the discontinuous or highly divided phase of the hydrocarbon/water mixture in which the water is in the form of finely divided droplets which are immiscible with the hydrocarbon phase into larger and coarser droplets.
  • the coalescing material is used in the form of a packing in which the material has a critical wetting surface energy intermediate the surface tensions of the liquids forming the continuous and discontinuous phases, that is, of the hydrocarbon majority component and the water which is to be removed. In practice, this means that the medium needs a surface energy of less than about 72 dynes/cm.
  • the material of the separating element is selected so as to have a surface energy which permits passage of the majority hydrocarbon component through the small pores of the separator material but to preclude transfer of the water across the wall.
  • the separator materials are selected to have a critical surface energy (CWST) below the surface tension of water which is typically about 72 mN ⁇ m ⁇ 1 .
  • CWST critical surface energy
  • materials preferred for use as the phase barrier material for the separator include silicones, such as silicone treated paper and more preferably fluoropolymeric materials of which fluorocarbons or perfluorocarbons (perfluoro resins) are particularly preferred.
  • a preferred separator material includes a coating of one of these materials on a stainless steel screen or a pleated paper pack.
  • suitable materials include those disclosed in U.S. Pat. No. 4,759,782 to which reference is made for a disclosure of such materials.
  • the phase barrier material which acts to prevent the discontinuous phase passing through it is selected to have pores smaller than a substantial amount of the droplets of the liquid which forms the discontinuous phase.
  • the pore size of the functional part of the separator material is selected to be from 5 to 140 microns, preferably 40 to 100 microns.
  • the pore size is preferably approximately 80 microns.
  • the coalescing unit and the separation unit may suitably be contained in a housing which provides and adequate number of coalescing/separating elements with these elements being suitably arranged inside the housing for reasons of functionality and operating convenience.
  • a suitable arrangement is shown in U.S. Pat. No. 5,443,724, using coalescer and separator cartridge elements arranged in super posed relationship with one another in a cylindrical type housing which permits ready access to the cartridges when they require replacement.
  • other configurations may be used and reference is made to commercial suppliers of this equipment including Pall Corporation of East Hills, N.Y. 11548.

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  • 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)
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WO2010069075A1 (fr) * 2008-12-19 2010-06-24 Suncor Energy Inc Rupture d'émulsion de charges à base d'hydrocarbure
US9068130B2 (en) 2009-04-22 2015-06-30 Suncor Energy Inc. Processing of dehydrated and salty hydrocarbon feeds
US9126879B2 (en) 2013-06-18 2015-09-08 Uop Llc Process for treating a hydrocarbon stream and an apparatus relating thereto
US9149749B2 (en) 2012-11-13 2015-10-06 Hollingsworth & Vose Company Pre-coalescing multi-layered filter media
US9149748B2 (en) 2012-11-13 2015-10-06 Hollingsworth & Vose Company Multi-layered filter media
US9284493B2 (en) 2013-06-18 2016-03-15 Uop Llc Process for treating a liquid hydrocarbon stream
US9283496B2 (en) 2013-06-18 2016-03-15 Uop Llc Process for separating at least one amine from one or more hydrocarbons, and apparatus relating thereto
US9327211B2 (en) 2013-06-18 2016-05-03 Uop Llc Process for removing carbonyl sulfide in a gas phase hydrocarbon stream and apparatus relating thereto
US9683178B2 (en) 2009-08-28 2017-06-20 Suncor Energy Inc. Process for reducing acidity of hydrocarbon feeds
US10195542B2 (en) 2014-05-15 2019-02-05 Hollingsworth & Vose Company Surface modified filter media
US10399024B2 (en) 2014-05-15 2019-09-03 Hollingsworth & Vose Company Surface modified filter media
US10625196B2 (en) 2016-05-31 2020-04-21 Hollingsworth & Vose Company Coalescing filter media
US10828587B2 (en) 2015-04-17 2020-11-10 Hollingsworth & Vose Company Stable filter media including nanofibers
US10953352B2 (en) 2017-05-19 2021-03-23 Baleen Process Solutions Fluid treatment system and method of use utilizing a membrane
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US11090590B2 (en) 2012-11-13 2021-08-17 Hollingsworth & Vose Company Pre-coalescing multi-layered filter media
WO2023122046A1 (fr) * 2021-12-20 2023-06-29 The Texas A&M University System Séparation de phases de coalescence électrostatique perpétuelle continue et rapide et désémulsification d'huile, d'eau et de solides à l'aide d'un plasma dans des conditions standard

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