WO2020018172A1 - Hydrogen sulfide removal process by use of a sulfur dye catalyst - Google Patents
Hydrogen sulfide removal process by use of a sulfur dye catalyst Download PDFInfo
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- WO2020018172A1 WO2020018172A1 PCT/US2019/032793 US2019032793W WO2020018172A1 WO 2020018172 A1 WO2020018172 A1 WO 2020018172A1 US 2019032793 W US2019032793 W US 2019032793W WO 2020018172 A1 WO2020018172 A1 WO 2020018172A1
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1468—Removing hydrogen sulfide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1412—Controlling the absorption process
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1425—Regeneration of liquid absorbents
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1493—Selection of liquid materials for use as absorbents
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/48—Sulfur compounds
- B01D53/52—Hydrogen sulfide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
- B01D53/86—Catalytic processes
- B01D53/8603—Removing sulfur compounds
- B01D53/8612—Hydrogen sulfide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/96—Regeneration, reactivation or recycling of reactants
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B17/00—Sulfur; Compounds thereof
- C01B17/16—Hydrogen sulfides
- C01B17/167—Separation
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B17/00—Sulfur; Compounds thereof
- C01B17/64—Thiosulfates; Dithionites; Polythionates
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
- C10L3/103—Sulfur containing contaminants
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/20—Reductants
- B01D2251/206—Ammonium compounds
- B01D2251/2062—Ammonia
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/30—Alkali metal compounds
- B01D2251/304—Alkali metal compounds of sodium
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/30—Alkali metal compounds
- B01D2251/306—Alkali metal compounds of potassium
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/40—Alkaline earth metal or magnesium compounds
- B01D2251/404—Alkaline earth metal or magnesium compounds of calcium
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/60—Inorganic bases or salts
- B01D2251/604—Hydroxides
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/60—Inorganic bases or salts
- B01D2251/606—Carbonates
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2255/00—Catalysts
- B01D2255/70—Non-metallic catalysts, additives or dopants
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2256/00—Main component in the product gas stream after treatment
- B01D2256/24—Hydrocarbons
- B01D2256/245—Methane
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/10—Recycling of a stream within the process or apparatus to reuse elsewhere therein
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/12—Regeneration of a solvent, catalyst, adsorbent or any other component used to treat or prepare a fuel
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
- C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
- C10L2290/547—Filtration for separating fractions, components or impurities during preparation or upgrading of a fuel
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/58—Control or regulation of the fuel preparation of upgrading process
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/60—Measuring or analysing fractions, components or impurities or process conditions during preparation or upgrading of a fuel
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- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P20/00—Technologies relating to chemical industry
- Y02P20/50—Improvements relating to the production of bulk chemicals
- Y02P20/584—Recycling of catalysts
Definitions
- the present disclosure is directed to a method and apparatus for continuously removing hydrogen sulfide gas (H 2 S) from a fluid stream and the subsequent selective production of a thiosulfate product.
- the method includes absorption of the H 2 S in an aqueous treatment solution followed by an oxidation reaction to produce thiosulfate using a catalyst containing vat dyes.
- the spent catalyst is regenerated in an oxidizer using an oxygen-containing gas and is recycled for use as part of the aqueous treatment solution.
- This disclosure relates to a process for treating a feed stream containing an industrial gas or liquid stream contaminated with H 2 S to obtain a scrubbed H 2 S -free fluid stream and a separate liquid aqueous stream containing thiosulfates.
- the present disclosure accepts a feed stream that is first contacted in an absorber with an aqueous treatment solution preferably maintained at a pH of greater than 7.
- the treatment solution contains a catalyst as described in detail below and can contain anions of alkali or ammonia salts and cations of hydroxide, sulfide or carbonate, such as, potassium carbonate, potassium hydroxide, calcium carbonate, sodium hydroxide, sodium carbonate, ammonia, and potash.
- solutions of ammonia or alkali metal salts of weak acids such as carbonic, boric, phosphoric and carbolic acids, or aqueous solutions or organic bases such as ethanol-amines can be used, as well as, aqueous solutions of alkali metal salts of amino-carboxylic acids such as glycine or alanine.
- the salt concentration in the treatment solution is preferably between 0 wt.% and a quantity sufficient to saturate the solution.
- the feed stream and treatment solution preferably contact each other in a countercurrent flow scheme.
- the absorber may contain physical components to assist in the contacting of the feed and treatment solution, such as, baffling, packing, trays, static mixers, valves, fiber film type materials, or other materials that increase the contact area between the feed stream and the treatment solution.
- the amount of treatment solution used is based on the concentration of H 2 S in feed, as well as the feed rate.
- sulfide ions are formed upon H 2 S absorption in the treatment solution which are then adsorbed on the catalyst for the further reaction.
- the sulfide ions are oxidized in the separate oxidizer to form thiosulfate.
- the produced thiosulfate remains in the treatment solution.
- potassium salts are present in the treatment solution, potassium thiosulfate is selectively formed.
- a substantially H 2 S -free product stream is removed from the absorber for further processing or transportation.
- the catalyst used to oxidize the sulfide ions to thiosulfate in the oxidizer is preferably in the form of vat dyes or metal sulfates and more preferably in the form of sulfur dyes and/or sulfurized vat dyes.
- Sulfurized vat dyes are chemically and structurally similar to sulfur dyes including having the disulfide/thiolate functionality. They are given the vat dye designation because they are typically obtained using a vat dye process.
- Sulfur dyes and sulfurized vat dyes which may be utilized in accordance with the method of the invention include but are not limited to the following (“C.I” stands for“Color Index”): C.I.
- Sulfur Yellow 1 2, 3, 4, 5, 6, 8, 9, 10, 11, 12, 13, 14, 16, 20 and 23, C.I. Leuco Sulfur Yellow 2, 4, 7, 9, 12, 15, 17, 18, 21, 22 and 23 and C.I. Solubilized Sulfur Yellow 2, 4, 5, 19, 20 and 23;
- catalysts for the conversion of sulfide to thiosulfate which may be used include: sulfate lignin, copper salts of sulfate and chloride, iron salts of hydroxide, chloride, sulfide, or sulfate, phthalocyanines of copper and cobalt, manganese salts of sulfate or chloride, polyvalent phenols such as pyrocatechol or pyrogallol, and quinones such as tetra-t-butyl stilbene quinone.
- the reaction of the sulfide ions with the catalyst in the absorber causes the catalyst to undergo a reduction process.
- the treatment solution containing the spent catalyst and the thiosulfate is preferably removed from the absorber (or first oxidation step) and introduced into an oxidizer vessel (the second oxidations step) where the spent catalyst is oxidized to its catalytically active form.
- An oxygen containing gas for example, air, is preferably introduced into the oxidizer in the form of a sparged gas stream, but can also be introduced by any type of gas/liquid contact device such as across mixers, valves, packing, or membranes. The oxygen reacts with sulfides bound to the catalyst to form thiosulfate and regenerated catalyst in oxidized state.
- a residence time in the oxidizer vessel of at least 5 minutes is usually sufficient to fully oxidize the spent catalyst. Excess oxygen-containing gas that is not consumed in the oxidation reaction is removed as an off-gas stream from the top of the oxidizer.
- the regenerated treatment solution containing the thiosulfates are removed from the oxidizer and can be recycled back to the absorber for contacting with the incoming feed stream containing H 2 S, thus completing a continuous processing operation.
- Fresh treatment solution can be added to this recycled regenerated treatment solution as make-up stream.
- a portion of the regenerated treatment solution can be removed to prevent a buildup of thiosulfate in the treatment solution.
- This removed portion of the regenerated treatment solution is then further processed as described in more detail below to remove the regenerated catalyst for recycle and to produce a thiosulfate product stream that is a useful product in a variety of industrial and agricultural manufacturing processes, for example the production of fertilizer.
- the operating parameters of the above-described absorber/oxidation processes include temperatures in the range of from about 15 °C to about 100 °C, preferably in the range from about 40-70 °C.
- the pressure of the vessels can range from atmosphere to 150 barg, preferably from about 0.5-30 barg.
- Reaction times can range from about 5-240 mins, preferably less than 30 min.
- the process can be run as a batch or continuous operation.
- the present disclosure also provides a treatment process where“produced water” can be processed to supply useful on-site chemicals useful in the scrubbing and removal of H 2 S from fluid feed streams.
- Produced water is a term used in the oil industry to describe water that is produced or collected as a byproduct along with oil and gas recovered from wells.
- Oil and gas reservoirs often have significant quantities of water, as well as hydrocarbons, sometimes in a zone that lies under the hydrocarbons, and sometimes in the same zone with the oil and gas. Oil wells sometimes produce large volumes of water with the oil, while gas wells tend to produce water in smaller proportion. To achieve maximum oil recovery, it is sometimes necessary to employ waterflooding, in which water is injected into the reservoirs to help force the oil to the production wells. The injected water eventually reaches the production wells, and so in the later stages of waterflooding, the produced water proportion of the total production increases.
- the water composition ranges widely from well to well and even over the life of the same well.
- Much of the produced water is recovered having varied high concentration of salts (i.e., hardness) and having high amounts of total dissolved solids, thus rendering the produced water unacceptable for beneficial reuse. All produced water also contains oil and suspended solids. Some produced water contains metals such as zinc, lead, manganese, iron and barium.
- the water hardness in the form of dissolved ions, especially alkali carbonates, contained in produced water can be reused by the presently disclosed process to capture the hydrogen sulfide contaminate in the natural gas and oil thereby reducing the demand for oilfield chemicals.
- produced water can be first subjected to a traditional 3 -phase separator, where gas, hydrocarbon and aqueous phases are separated from each other.
- the produced water could be mixed with a portion of regenerated liquid treatment solution and then separated in a 3 -phase spearator.
- the aqueous phase is then directed to the above-described oxidizer vessel where it contacts the sparged oxygen-containing gas, spent treatment solution and newly oxidized (regenerated) treatment solution.
- the aqueous phase usually contains some amount of sulfides, typically in the range from about 2 ppm to about 1,200 ppm, as a result dissolved H 2 S, the oxygen in the sparged gas combined with the newly regenrated catayst causes oxidation of these aqueous phase sulfides and converts them to thiosulfate. These produced thiosulfates from the aqueous phase remain in the treatment solution as the treatment solution continues to undergo regneration in the oxidizer.
- the removed regenerated treatment solution that now contains the treated aqueous phase recovered from the produced water has an Oxidation Reduction Potential (ORP) greater than that of the ORP of both the original separated aqueous phase and the spent treatment soultion.
- ORP Oxidation Reduction Potential
- ORP also referred to as reduction potention, oxidation/reduction potential or redox potential is a measure of the tendency of a chemical species to acquire electrons and, as such, be reduced.
- ORP is measured in volts (V), or millivolts (mV).
- V volts
- mV millivolts
- Each species has its own intrinsic reduction potential; the more positive the potential, the greater the species' affinity for electrons and tendency to be reduced.
- ORP is a commonly used as a measurement for water quality.
- reduction potential is a measure of the tendency of the solution to either gain or lose electrons when it is subject to change by introduction of a new species.
- a solution with a higher (more positive) reduction potential than the new species will have a tendency to gain electrons from the new species (i.e. to be reduced by oxidizing the new species) and a solution with a lower (more negative) reduction potential will have a tendency to lose electrons to the new species (i.e. to be oxidized by reducing the new species).
- reduction potentials are defined relative to a reference electrode. Reduction potentials of aqueous solutions are determined by measuring the potential difference between an inert sensing electrode in contact with the solution and a stable reference electrode connected to the solution by a salt bridge.
- a measurement of the ORP of the solution in the absorber and/or in the oxidizer can be used to control the flow or amount of oxygen containing gas that is introduced into the oxidizer.
- the treated aqueous phase and regenerated treatment solution referred to as a recyle treatment stream is then sent to the absorber where it is contacted with the feed stream containing oil, gas, or both.
- the recycled treatment stream is contacted with the oil/gas to the extract the hydrogen sulfide contaminants from the oil/gas forming sulfides that are then oxidized to form thiosufates.
- the resultant treatment solution that now contains spent cataylst is sent to the oxidizer vessel where the spent catalyst is oxidized to its active form and making it available for the oxidation of any residual sulfides, including sulfides entering the oxidizer vessel in the aqueous stream separated from the produced water.
- the regenerated treatment solution containing the treated aqueous phase can now be removed from the oxidizer vessel when the ORP of the regenerated solution is greater than -0.4 mV.
- This removed regenerated treatment solution can then be filtered to remove the regenerated catalyst, yielding a stream of water with thiosulfate ions ranging in concnetration from about 0 wt.% to about saturation.
- the saturation concentration depends on type of cation, e.g. ⁇ 5l wt.% for potassium. .
- the filter media that recovers and holds the removed catalyst can be periodically backflushed with a flush solution, preferably a flush solution containing dissolved sulfides.
- Performing the back flushing operation on the filter media allows the regenerated catalyst to be removed and reused in the process, thus minimizing catalyst loss and reducing the amount of fresh (make-up) treatment solution.
- a flushing solution containing sulfides the solubility of the filtered regenerated catalyst is enhanced and improves the efficiency of cleaning the filter.
- aqueous phase that can be fed to the oxidizer it may be necessary, depending on the source of the produced water, to increase the measured hardness by adding to the produced water and/or separated aqueous phase lime, potash, other sources of alkali hydroxide or carbonate, and mixtures thereof.
- the catalyst is filtered, it is now possible to send all or a portion of this filtered regenrated treatment solution to dispossal via well injection in a manner similar to current practice of injecting recovered produced water.
- the treatment of the gas or oil and then subsequent disposal of the aqueous phase directly on-site or close to the oil/gas wells provides a method that greatly reduces the costs of procuring chemicals and instead uses chemicals that are readily available in the produced water.
- prior known sulfur treating units such as amine/claus systems or iron-redox require significantly more capital due to their corrosive nature.
- the low temperature and pressure of the oxidizer in presently disclosed system provides for signifcant ease of operation, reduced operating cost, and lower capital expense.
- the processes of the present disclosure are suitable for the treatment of hydrogen sulfide from various sources including natural gas, condensate, landfill gas, and other acid gases.
- they are useful to employ a sulfur dye catalyst to oxidize the absorbed hydrogen sulfide into a thiosulfate ion in the absorber vessel. It is economically desirable to recover the catalyst for reuse from the partially or fully spent solution. .
- One possible method for the recovery of the catalyst requires the use of an appropriate filtration unit operation, where membranes or filter media, such as granular activated carbon, are used to trap and recover the catalyst from a liquid stream.
- membranes or filter media such as granular activated carbon
- the catalyst is particularly suitable for separation from the liquid solution of thiosulfate ions produced from the oxidation of sulfides that occurred in the oxidizer vessel.
- the presently disclosed process handles high volume of sulfides, the near complete oxidation of sulfide ions to thiosulfate is preferred for effective filtration. .
- the complete oxidation of the catalyst is preferred, i.e.
- ORP greater than -0.4 mV for sufficient seperation of the oxidized (i.e. regenerated catalyst) from potassium thiosulfate solution via filtration. .
- it is also advisible to perform back flushing of the filter media with a solution containing a small amount of sulfide or other reducing medium which solubilizes the catalyst and removes it from the filter media such that it can then be introduced back into the process.
- This filtration/recovery method can also be used to recover sulfur dye catalysts from other industrial waste streams and to then utilize the recovered catalyst as a reagent in the process of treating hydrogen sulfide contaminated streams.
- sulfur dye catalyst could be recovered from an aqueous solution by adsorption on a solid media, for example, Calgon Filtrasorb 200 carbon.
- a solid media for example, Calgon Filtrasorb 200 carbon.
- the catalyst will reduce to its soluble form and will be released from the carbon adsorption media.
- the soluble catalyst can then be used with the regenerated catalyst to oxidize sulfides in a feed stream to produce thiosulfate. Subsequent addition of an oxygen containing gas stream will oxidize the catalyst back to its insoluble form (i.e., a slurry or semi-solid).
- filter media can be used, for example, membranes like Tri-sep Flat XN45 polypiperiazine amide (PPA) nano-filtration membrane having a membrane cut-off of 500 Da and being compatible in 2-11 pH.
- PPA polypiperiazine amide
- a portion of the regenerated treatment solution can be removed from the oxidizer to not only prevent a build- up of thiosulfate within the process, but also to recover the thiosulfates as useful and economically valuable byproduct.
- a removed liquid stream would preferably be filtered as described above to recover the catalyst present in the regenerated treatment solution.
- an aqueous solution containing thiosulfate anions and salts is obtained. This thiosulfate solution can then be fed to an ion exchange resin system.
- the resin can be either anion or cation exchange, for example, acrylic or methacrylic with various crosslink monomer, sulfonated copolymer resins of styrene and divinyl benzene, quaterinized amine resins, and dimethylethanol amine copolymer resin, to name a few.
- the thiosulfate ions can be exchanged to improve the strength (concentration) of the solution or swap cations.
- a cation exchange resin can be pre-loaded with sodium cations through treatment of the resin with a solution of sodium chloride.
- the ammonia (ammonium cation) will be swapped for sodium to produce a liquid stream of sodium thiosulfate.
- the ammonia saturated resin can then be regenerated exposing the resin to a sodium chloride solution to displace the ammonia such that the swap of the stored ammonia from the resin will yield an ammonium chloride solution while regenerating the resin with sodium ions for reuse.
- Potassium thiosulfate can also be made by exchanging the ammonium cation in an ammonium thiosulfate solution for potassium ions in a regenerable, potassium-loaded ion exchange resin under ion exchange conditions.
- the resulting potassium thiosulfate product can be packaged as a liquid fertilizer product either with or without an intermediate concentration step.
- the ammonium-laden resin is regenerated to its potassium form by contact with a solution of potassium chloride under suitable ion exchange conditions.
- the ammonium chloride solution produced by the regeneration step can be also used as a lower grade liquid fertilizer.
- this embodiment makes two fertilizers of different grades for valuable production on each phase of the ion exchange process cycle.
- the ion exchange to make potassium thiosulfate is performed at a temperature within the range from about 10° C. to about 35° C., and most preferably at an ambient temperature within a range from about 15° C. to about 30° C.
- the ion exchange temperature ranges for regenerating the resin and forming ammonium chloride are generally the same as those used for the ion exchange.
- the resin is charged with 20 wt.% potassium chloride at ambient temperature.
- the total content of K + charged to the system should be 1.25 times higher than the total capacity of the resin.
- One possible processing scheme of the present disclosure is to treat a feed that contains hydrogen sulfide in an absorber vessel such that the feed stream flows upward from the bottom of the absorber and contact a liquid treatment solution flowing upward in the absorber such the liquid treatment solution mixes with the feed.
- the liquid treatment solution contains a sulfur dye catalyst.
- the residence time of contact between the liquid treatment solution and feed stream within the absorber is controlled such that the hydrogen sulfide is absorbed into the liquid treatment solution and converted into sulfide ions.
- a spent treatment solution containing the sulfide ions, spent sulfur dye catalyst, and dissolved gas is removed from the absorber vessel and is introduced into an oxidation vessel, where an oxygen containing gas is fed.
- the oxygen contacts the spent treatment solution causing the sulfide ions to oxidize to thiosulfate and to convert the spent sulfur dye catalyst to regenerated sulfur dye catalyst.
- the amount of oxygen fed to the oxidizer is controlled based on measured ORP in the absorber or oxidizer or both.
- Any excess oxygen containing gas from the oxidation vessel is removed.
- a liquid stream of regenerated liquid treatment solution comprising the thiosulfate and the regenerated sulfur dye catalyst is also removed from the oxidizer separately.
- the regenerated liquid treatment solution can be recycled back to be mixed with the liquid treatment solution being fed to the absorber.
- the amount of liquid treatment solution fed to the absorber can be controlled based on measured ORP in the absorber, oxidizer or both.
- the thiosulfate concentration is maintained at a predetermined amount in the regenerated liquid treatment solution by removing a portion of the regenerated liquid treatment solution from the process.
- the spent treatment solution is first introduced into a flash drum where a reduction in pressure causes the dissolved gas to separate from the spent treatment solution forming a flashed gas.
- the degassed spent treatment solution is then introduced into an oxidation vessel and the flashed gas removed from the flash drum can be introduced into a second absorber vessel and contacted with a second liquid treatment solution to convert any residual hydrogen sulfide present.
- produced water is removed and recovered from an oil and gas well and then subjected to a separation process, preferably a 3- phase separation process, where an aqueous phase is obtained from the produced water.
- the aqueous phase is then fed to the oxidizer vessel.
- Still another variant of the present disclosure includes dividing the liquid stream of regenerated liquid treatment solution comprising the thiosulfate and the regenerated sulfur dye catalyst into a first and a second portion, where the second portion of regenerated liquid treatment solution is recycled to the absorber.
- the first portion is fed into a separate separation process where the regenerated sulfur dye catalyst is separated from the thiosulfate by a filtration step and is recirculated to the absorber vessel.
- the filtration step uses a filter media that collects the regenerated sulfur dye catalyst and produces a thiosulfate solution that can be introduced into an ion exchange column where a thiosulfate product stream is produced.
- a back flushing step that removes the regenerated sulfur dye catalyst from the filter media so that it can be recovered and reused.
- One possible back flushing step comprises contacting the filter media with a liquid solution containing sulfide ions.
- Figure 1 schematically illustrates one possible embodiment of the present disclosure
- Figure 2 schematically represents a variation of the process flow scheme depicted in Fig. 1;
- Figure 3 schematically represents another variation of the process flow scheme depicted in Fig. 1;
- Figure 4 schematically represents yet another variation of the process flow scheme depicted in Fig. 1.
- FIG. 1 illustrates a continuous process using an absorber vessel 5 and an oxidization reactor 11 operating in series flow.
- a feed stream 1 for example, a feed composed of natural gas containing about 100 ppm H 2 S is fed at 30 barg pressure to the bottom of absorber 5 and directed in an up-flow manner for countercurrent contact with a liquid treatment solution 2 introduced at the top of absorber 5.
- the feed may contain no hydrocarbon component, for example, the feed could contain hydrogen sulfide and a non-hydrogen gas.
- a non-hydrogen gas could be air recovered from an amine system or C0 2 recovered from a sour water stripping process.
- the absorber may contain a solid media or may be a type of bubble column.
- Other feed streams containing hydrogen sulfide can be processed, including those containing sour gas (at 0-100%), refined products (at 0-20 ppm), fuel gas (at 0-5%), synthesis gas (at 0-5 vol. %), acid gas (at 0-100 vol. %), natural gas (0-2 vol. %), landfill gas (0-1 vol. %), sour air, stripper overhead, crude oil, hydrocarbons, sour flash gases, and well treating fluids.
- the liquid treatment solution could be composed of a mixture of fresh treatment solution 3 with regenerated treatment solution as described below.
- the liquid treatment solution for example, could contain a sulfur dye catalyst and potassium carbonate and, in the case where regenerated treatment solution is mixed with the fresh treatment solution, an amount of potassium thiosulfate.
- the liquid treatment solution could contain cations selected from the group consisting of ammonia, lithium, calcium, magnesium, potassium, and sodium.
- the liquid treatment solution can contain anions, including hydroxide and carbonate.
- cations and anions can be found in produced water, evaporator blowdown, process water, cooling water blowdown, or any aqueous stream containing the anions/cations in any concentration between 0 wt.% and the solubility limit of the ions.
- a solid media 20 may be used to increase the contact surface area between the downward flowing treatment solution and the up flowing gas stream.
- the ratio of the liquid treatment solution to the gas feed is dependent on the quantity of H 2 S in the gas feed 1, but contains a molar ratio of catalyst greater than 1 as compared to the moles of H 2 S in the feed.
- the H 2 S present in the gas stream 1 is absorbed into the treatment solution 2 as sulfide ions.
- the sulfur dye in its oxidized form reacts with the sulfide ions to form the dye’s reduced state.
- a substantially H 2 S-fee gas stream 6 is removed from the top of the oxidizer and sent for storage, transportation, released to the atmosphere, or further processing.
- a spent treatment stream 7 containing spent catalyst and potassium thiosulfate is removed from the absorber 5 and introduced into flash drum 8 where the pressure is reduced to less than 5 barg to remove soluble gases, such as C0 2 and H 2 0, via stream 9. Any unconverted H 2 S, if present, would also be removed in stream 9. Where unconverted H 2 S is found in the gases removed from flash drum 8, the off-gas stream 9 could be introduced into a second smaller absorber 40 to absorb and convert any remaining H 2 S (see Fig. 2).
- This smaller absorber 40 could also be a counter-current contactor with a solid media support where fresh and/or regenerated liquid treatment solution is introduced through line 41 and scrubbed H 2 S-free gas is removed from absorber 40 via line 42.
- Spent treatment solution 43 is removed from the small absorber 40 and introduced into the oxidizer 11, preferably by mixing with liquid stream 10 that is removed from the flash drum 8 such that both liquid streams are fed to oxidizer 11 as shown in Fig. 2.
- the amount of oxygen added to the oxidizer is controlled by monitoring oxidation reduction potential (ORP) values.
- ORP oxidation reduction potential
- one method would include using a sensor located in the absorber and/or in the oxidizer to measure the ORP values of the solution(s). The measured ORP could be monitored by control valve 200 which then adjusts the amount of oxygen containing gas supplied to the oxidizer 11 through line 13.
- the ORP value of the regenerated liquid treatment solution exiting the oxidizer in line 14 could be measured, monitored and used to control the flow or amount of oxygen containing gas that is introduced into the oxidizer.
- another method could include using the measured ORP values obtained from sensors in the absorber and/or in the oxidizer to operate control valve 201 which then adjusts the amount of liquid treatment solution that is fed to the absorber 5 through line 2.
- the concentration of H 2 S in the product gas stream 6 can be monitored and measured to control the amount of oxygen that is added to the oxidizer. Excess oxygen-containing gas is removed from the top of the oxidizer 11 through line 12. As mentioned, the spent catalyst fed from absorber 5 is regenerated by an oxidation reaction in oxidizer 11. Oxidation of the catalyst causes the catalyst to convert from a soluble form to an insoluble form (i.e., forming a slurry), which as described below can be recycled back to the absorber. The catalyst-sulfide complex formed in the absorber 5, is also oxidized to thiosulfate and return to the aqueous solution.
- a regenerated liquid stream of treatment solution containing the regenerated catalyst and thiosulfates is removed from the oxidizer via stream 14 and recycled for use in absorber 5, where it can be mixed with fresh or make-up treatment solution 3 containing active sulfur dye catalyst and potash.
- a portion of stream 14 is removed via stream 15 for further processing, as will be described in more detail below, to recover the thiosulfate as a useful byproduct.
- the regenerated catalyst should be removed by filtration first and recycled back to the absorber. Additional dewatering may also be required of the recovered thiosulfate solution or the thiosulfate solution byproduct can be treated to recover the thiosulfate ion through an ion exchange process.
- Figure 3 represents one possible flow scheme where produced water 31 is obtained from well 30 and supplied to a three-phase separator 32 where residual gas is removed via line 37, residual oil is removed via line 34 and an aqueous phase comprising water and dissolved salts is removed via line 35.
- the aqueous phase in line 35 can then be introduced into oxidizer 11 directly or, as shown in Fig. 3, mixed with the spent liquid treatment solution in line 10.
- the residual oil in line 34 or the residual gas in line 37 or both can be introduced into line 1 as part of the feed.
- the filtration step 37 can employ a flush stream 50 containing sulfides that will solubilize and wash/dislodge the catalyst from the filter media.
- a source of sulfides for stream 50 can be a portion of stream 10.
- a water/thiosulfate solution is removed from the filtration unit operations 37 via line 38 and can be disposed of by injection into on site oil/gas wells. This disposal method avoids transportation or further disposal costs normally associated with recovered produced water and also utilizes the dissolved salts as valuable reagents in the H 2 S removal process.
- the stream 15 is further treated using a combination of a filtration unit operation 60 and an ion exchange operation 70.
- This variant is schematically shown in Fig. 4 where the regenerated liquid treatment solution is introduced into a filtration process 60.
- a filter media is used to collect and separate the regenerated catalyst that is suspended in the liquid treatment solution as a slurry or semi-solid when it is removed from the oxidizer.
- the filtration process is run until the filter media becomes occluded or full.
- the filtration process 60 would include process piping where a flushing liquid 50, preferably containing sulfides, could be used to backflush and clean the collected catalyst from the filter media.
- This backflush of recovered catalyst would be removed as stream 62 and could be fed back to the H 2 S removal process, for example, as shown in Fig. 4, by introduction into line 14.
- Preferably two or more filtration units could be operated in parallel (in a swing configuration) to maintain a continuous filtering operation.
- the flow could be diverted from the occluded filter media to a clean filter so that back flushing of the occluded filter could be performed.
- the cycle would be repeated each time the filter media becomes full of the catalyst.
- the liquid treatment solution separated from the regenerated catalyst is removed from the filtration step via line 61 and fed to an ion exchange process 70.
- the ion exchange system 70 preferably uses a plurality of one or more discrete ion exchange resin column beds 78,79 disposed in serial, cascading flow relation. To maintain a continuous operation, it may be necessary to have two or more of these serial beds arranged in parallel so that a swing-type operation could be employed similar to that described for the filtration process 60.
- Appropriate valves 90-97 and control systems that are within the existing skill of the art can be used to control the switchover from a column sequence operating in exchange mode to operation in regeneration mode. When properly performed, the ion exchange batch operation can be operated as a substantially continuous process.
- Resin regeneration solution is introduced through lines 71, 80 and 81 and removed through lines 74, 76 and 83.
- An ion exchanged liquid product comprising thiosulfate is removed via line 82.
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Abstract
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Priority Applications (7)
Application Number | Priority Date | Filing Date | Title |
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AU2019308471A AU2019308471A1 (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process by use of a sulfur dye catalyst |
CA3103924A CA3103924C (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process by use of a sulfur dye catalyst |
CN201980043588.XA CN112423862B (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process by using sulfur dye catalyst |
NO20210144A NO20210144A1 (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process by use of a sulfur dye catalyst |
GB2018796.9A GB2588540B (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process |
CN202310404673.2A CN116422106A (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process by using sulfur dye catalyst |
MX2020013125A MX2020013125A (en) | 2018-02-27 | 2019-05-17 | Hydrogen sulfide removal process by use of a sulfur dye catalyst. |
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US16/036,471 US10661220B2 (en) | 2018-02-27 | 2018-07-16 | Hydrogen sulfide removal process |
US16/036,471 | 2018-07-16 |
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Citations (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3098033A (en) * | 1959-02-13 | 1963-07-16 | Raffinage Cie Francaise | Process for refining petroleum products |
US4367212A (en) * | 1979-05-03 | 1983-01-04 | Fmc Corporation | Control of thiosulfate in wet desulfurization process solutions |
US20030072707A1 (en) * | 2001-06-27 | 2003-04-17 | Ray Michael F. | Process for aqueous phase oxidation of sulfur or sulfide to thiosulfate, bisulfite or sulfite ions using air |
-
2019
- 2019-05-17 WO PCT/US2019/032793 patent/WO2020018172A1/en active Application Filing
Patent Citations (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3098033A (en) * | 1959-02-13 | 1963-07-16 | Raffinage Cie Francaise | Process for refining petroleum products |
US4367212A (en) * | 1979-05-03 | 1983-01-04 | Fmc Corporation | Control of thiosulfate in wet desulfurization process solutions |
US20030072707A1 (en) * | 2001-06-27 | 2003-04-17 | Ray Michael F. | Process for aqueous phase oxidation of sulfur or sulfide to thiosulfate, bisulfite or sulfite ions using air |
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