US20130306310A1 - Pipeline reaction for removing heavy metals from produced fluids - Google Patents

Pipeline reaction for removing heavy metals from produced fluids Download PDF

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Publication number
US20130306310A1
US20130306310A1 US13/895,612 US201313895612A US2013306310A1 US 20130306310 A1 US20130306310 A1 US 20130306310A1 US 201313895612 A US201313895612 A US 201313895612A US 2013306310 A1 US2013306310 A1 US 2013306310A1
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United States
Prior art keywords
fluid
pipeline
mercury
fixing agent
heavy metals
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Abandoned
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US13/895,612
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English (en)
Inventor
Darrell Lynn Gallup
Sujin Yean
Lyman Arnold Young
Dennis John O'Rear
Russell Evan Cooper
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Chevron USA Inc
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Chevron USA Inc
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Priority to US13/895,612 priority Critical patent/US20130306310A1/en
Assigned to CHEVRON U.S.A. INC. reassignment CHEVRON U.S.A. INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: COOPER, RUSSELL EVAN, YOUNG, LYMAN ARNOLD, O'REAR, DENNIS JOHN, GALLUP, DARRELL LYNN, YEAN, SUJIN
Publication of US20130306310A1 publication Critical patent/US20130306310A1/en
Abandoned legal-status Critical Current

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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
    • C10G53/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes
    • C10G53/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only
    • C10G53/04—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only including at least one extraction step
    • 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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • C10G21/08—Inorganic compounds only
    • 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
    • C10G19/00—Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment
    • 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
    • C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
    • C10G31/08—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by treating with water
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/35—Arrangements for separating materials produced by the well specially adapted for separating solids
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/205—Metal content
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/36—Underwater separating arrangements

Definitions

  • the invention relates generally to a process, method, and system for removing heavy metals including mercury from hydrocarbon fluids such as crude oil and gases.
  • Pipelines are widely used in a variety of industries, allowing a large amount of material to be transported from one place to another.
  • the transport can be for a short distance as within a plant or over a long distance such as a continent.
  • a variety of fluids, such as oil and/or gas, as well as particulate, and other small solids suspended in fluids, are transported cheaply and efficiently using pipelines.
  • Pipelines can be subterranean, submarine, on the surface of the earth, and even suspended above the earth. Submarine pipelines especially carry enormous quantities of oil and gas products indispensable to energy-related industries, often under tremendous pressure and at low temperatures and at high flow rates.
  • Oil and gas pipelines typically carry production fluids from one of the production wells including subsea wells.
  • These fluids may be, but are not limited to, a gas, a liquid, an emulsion, a slurry and/or a stream comprising solid particles (oil sand).
  • the production fluid can be a single phase, a two phase or even a three phase admixture.
  • 6,268,543 discloses a method for removing elemental mercury with a sulfur compound.
  • U.S. Pat. No. 6,350,372 discloses removing mercury from a hydrocarbon feed by contact with an oil soluble or oil miscible sulfur compound
  • U.S. Pat. No. 4,474,896 discloses using polysulfide based absorbents to remove elemental mercury)(Hg° from gaseous and liquid hydrocarbon streams.
  • the invention relates to a method for simultaneously transporting and removing a trace amount of heavy metals from a produced fluid.
  • the method comprises: extracting a produced fluid containing heavy metals from a production well; injecting into the produced fluid an effective amount of at least fixing agent and a dilution fluid forming a mixture; transferring the mixture through a pipeline from the production well for a sufficient distance for at least a portion of the heavy metals to react with the mixture, at least a fixing agent, and be extracted into the dilution fluid as complexes; and separating the dilution fluid containing the heavy metal complexes from the produced fluid for a treated produced fluid having a reduced concentration of heavy metals.
  • the invention in another aspect, relates to a method for simultaneously transporting and removing mercury from a crude.
  • the method comprises: extracting the crude containing a trace amount of mercury from a production well; injecting into the crude an effective amount of at least fixing agent and a sufficient amount of water forming a mixture; transferring the mixture through a pipeline for a sufficient distance for at least a portion of mercury to react with the fixing agent forming a soluble mercury complex in water; separating the water containing the soluble mercury complex from the crude for a treated crude having reduced mercury concentration.
  • FIG. 1 is a diagram of an embodiment of a pipeline conditioning system from one or more subsea wells to a floating production, storage and offloading (FPSO) unit.
  • FPSO floating production, storage and offloading
  • FIG. 2 is a diagram of a pipeline conditioning system with one or more intermediate collection and/or processing facilities.
  • Hydrocarbons refers to hydrocarbon streams such as crude oils and/or natural gases.
  • “Produced fluids” refers hydrocarbon gases and/or liquids such as crude oil that is removed from a geologic formation via a production well, including mixtures of hydrocarbons and water that is typically extracted with the hydrocarbons.
  • “Crude oil” refers to a hydrocarbon material, including both crude oil and condensate, which is typically in liquid form. Under some formation conditions of temperature and/or pressure, the crude may be in a solid phase. Under some conditions, the oil may be in a very heavy liquid phase that flows slowly, if at all, e.g., as a slurry phase comprising oil sand or bitumen flecks. While the description described herein sometimes refers to “crude” or “crude oil,” the description of “crude oil” also includes hydrocarbon gases unless specified otherwise.
  • Production well is a well through which produced fluids are carried from an oil-bearing geological formation to the earth's surface, whether the surface is the seafloor, a fixed or floating structure on water, or land. Surface facilities are provided for handling and processing the produced fluids from the formation upon the surface. Production well may be used interchangeably with wellhead or well.
  • “Produced water” refers to the water generated in the production of oil and gas, including formation water (water present naturally in a reservoir), as well as water previously injected into a formation either by matrix or fracture injection, which can be any of connate water, aquifer water, seawater, desalinated water, industrial by-product water, and combinations thereof.
  • produced water is a component of produced fluids.
  • FPSO floating production, storage and offloading unit
  • FPSO floating production, storage and offloading unit
  • the FPSO processes an incoming stream of crude oil, water, gas, and sediment, and produce a shippable crude oil with acceptable properties including levels of heavy metals such as mercury, vapor pressure, basic sediment & water (BS&W) values, etc.
  • heavy metals such as mercury, vapor pressure, basic sediment & water (BS&W) values, etc.
  • Peline conditioning system refers to a pipeline that contains produced fluids and at least one chemical reagent for the removal of at least a heavy metal from the produced fluids.
  • Race amount refers to the amount of heavy metals in a produced fluid. The amount varies depending on the source of the fluid and the type of heavy metal, for example, ranging from a few ppb to up to 30,000 ppb for mercury and arsenic.
  • Heavy metals refers to gold, silver, mercury, osmium, ruthenium, uranium, cadmium, tin, lead, and arsenic. While the description described herein refers to mercury removal, in one embodiment, the treatment removes one or more of the heavy metals from the produced fluids.
  • Mercury sulfide may be used interchangeably with HgS, referring to mercurous sulfide, mercuric sulfide, or mixtures thereof. Normally, mercury sulfide is present as mercuric sulfide with a stoichiometric equivalent of one mole of sulfide ion per mole of mercury ion.
  • Mercuric sulfide can be in any of the common crystal forms, e.g., cinnabar, metacinnabar, hypercinnabar, or combinations thereof.
  • Fibering agent refers to chemical reagents that are added to the pipeline to form complexes with the heavy metals in the produced fluid, or to convert the heavy metals into compounds that are soluble in the dilution fluid, e.g., water, that is added to the pipeline to assist the flow of the produced fluid in the pipeline.
  • dilution fluid e.g., water
  • the invention relates to a method for simultaneously transporting and removing heavy metals contained in produced fluids such as crude oil, gases and the like.
  • produced fluids such as crude oil, gases and the like.
  • a sufficient amount of dilution fluid e.g., water including produced water and/or lighter hydrocarbon
  • sufficient mixing occurs in the pipeline for reactions to take place between the fixing agent and heavy metals such as mercury, arsenic, etc. to be extracted into the dilution fluid or to precipitate out of the crude.
  • Heavy metals such as lead, zinc, mercury, silver, arsenic and the like can be present in trace amounts in all types of hydrocarbon streams such as crude oils and natural gases. Some crude oils contain trace amounts of heavy mercury and/or arsenic. The amount of mercury and/or arsenic can range from below the analytical detection limit to several thousand ppb depending on the feed source.
  • Arsenic species can be present in produced fluids in various forms including but not limited to trimethylarsine, arsine (AsH 3 ), triphenylarsine (Ph 3 As), triphenylarsine oxide (Ph 3 AsO), arsenic sulfide minerals (e.g., As 4 S 4 or AsS or As 2 S 3 ), metal arsenic sulfide minerals (e.g., FeAsS; (Co, Ni, Fe)AsS; (Fe, Co)AsS), arsenic selenide (e.g., As 2 Se 5 , As 2 Se 3 ), arsenic-reactive sulfur species, organo-arsenic species, and inorganic arsenic held in small water droplets.
  • trimethylarsine arsine (AsH 3 ), triphenylarsine (Ph 3 As), triphenylarsine oxide (Ph 3 AsO), arsenic sulfide minerals (e.
  • Mercury can be present in produced fluids as elemental mercury Hg°, ionic mercury, inorganic mercury compounds, and/or organic mercury compounds. Examples include but are not limited to: mercuric halides, mercurous halides, mercuric oxides, mercuric sulfide, mercuric sulfate, mercurous sulfate, mercury selenide mercury hydroxides, organo-mercury compounds and mixtures of thereof.
  • Mercury can be present as particulate mercury, which can be removed by filtration or centrifugation. The particulate mercury in one embodiment is predominantly non-volatile.
  • the produced fluid is a crude oil containing at least 50 pbbw mercury.
  • the mercury level is at least 100 pbbw.
  • less than 50% of the mercury can be removed by stripping (or more than 50% of the mercury is non-volatile).
  • at least 65% of the mercury in the crude is non-volatile.
  • at least 75% of the mercury is of the particulate or non-volatile type.
  • the produced fluid for transporting in the pipeline is in the form of a mixture of crude oil and water.
  • the amount of produced water in the crude can be as much as 98% of the crude/water mixture transported in the pipeline.
  • the pipeline reaction system effectively reduces levels of heavy metals such as mercury and/or arsenic from produced fluids with the addition of at least a chemical reagent as a fixing agent to the pipeline.
  • the fixing agent can be introduced into the pipeline along with a dilution fluid or separately by itself without a dilution fluid, into the production well at the well head, into a manifold, into a location downhole in the wellbore, an intermediate location into a pipeline between the production well and a processing facility, or combinations of the above.
  • the dilution fluid is produced water in the production fluids.
  • the fixing agent is introduced into the pipeline at an entry point at the wellhead or close to the well head, e.g., within 1000 ft of the well head, and separate from the dilution fluid.
  • the fixing agent is introduced into the production well along with a dilution fluid.
  • the fixing agent is introduced into a pipeline carrying a crude in a processing facility for the reaction to take place in the pipeline before the crude reaches its destination such as a piece of equipment in the facility.
  • the dilution fluid is non-potable water, e.g., connate water, aquifer water, seawater, desalinated water, oil field produced water, industrial by-product water, or combinations thereof.
  • the dilution fluid is a lighter hydrocarbon, e.g., pentane, diesel oil, gas oil, kerosene, gasoline, benzene, toluene, heptane, and the like.
  • the volume ratio of dilution fluid to the produced fluid in the pipeline may range from 20:1 to 1:20 in one embodiment, 5:1 to 1:5 in another embodiment, and 4:1 to 1:1 in a yet another embodiment.
  • the fixing agent effectively extracts heavy metals from the produced fluid into a dilution fluid such as water.
  • the pipeline is of sufficient length so that, in the course of transferring produced fluid through it, sufficient mixing of produced fluids and water occurs for reactions to take place between the fixing agent and the heavy metals, for heavy metals such as mercury to form insoluble complexes, or be extracted from the produced fluid into the water phase.
  • the heavy metals can then be removed by filtration, settling, or other methods known in the art, e.g., removal of solids from a or gas liquid stream to produce a hydrocarbon product with reduced mercury content.
  • the Hg-enriched water phase can be separated from the crude by means known in the art, e.g., gravity settler, coalescer, separator, etc., at a processing facility at the destination of the pipeline to produce a hydrocarbon product with reduced mercury content.
  • the pipeline is sufficiently long for a residence time of at least one minute in one embodiment, at least 10 minutes in another embodiment, at least 30 minutes in yet another embodiment, at least 10 hours in a fourth embodiment.
  • the pipeline can be in the range of 20-200 hours that extends for hundreds if not thousands of kilometers.
  • the reaction takes place over a relatively short pipeline, e.g., at least 10 m but less than 50 meters for intra-facility transport.
  • the reaction takes place in pipeline sections for a long distance transport of at least 0.5 km, at least 50 km, at least 500 km and less than 10,000 km in another embodiment.
  • the flow in the pipeline is turbulent, and in another embodiment the flow is laminar.
  • the pipeline has a minimum superficial liquid velocity (based on combined oil and water phases) of at least 0.1 m/s in one embodiment; at least 0.5 m/s in a second embodiment; and at least 5 m/s in a third embodiment.
  • the natural mixing in the pipeline can be augmented with the use of mixers at the point of introduction of the fixing agent, or at intervals downstream in the pipeline. Examples include static or in-line mixers as described in Kirk-Othmer Encyclopedia of Chemical Technology, Mixing and Blending by David S. Dickey, Section 10, incorporated herein by reference.
  • the temperature of the pipeline is maintained at a temperature of at least 5° C. in one embodiment, at least 10° C. in a second embodiment, and at least 10° C. in a second embodiment.
  • the produced fluid can be mixed with a heated dilution fluid at the production site before being pumped through the pipeline for the mixture in the pipeline to have a temperature in the range of 5-70° C. at the entry point of the fixing agent.
  • steam or hot water containing fixing agents is injected at the entry point, or at intervals along the pipeline for the desired chemistry and temperature for the pipeline reaction to take place.
  • the pipeline reaction system can be either land-based or located subsea, extending from a production site to a crude processing facility and receiving production flow from a surface wellhead or other sources. Examples include subsea pipelines, where the great depth of the pipeline can make the pipeline relatively inaccessible, and where the pipelines include a header or vertical section that forms a substantial pressure head.
  • the pipeline system can be on-shore, off-shore (as a platform, FPSO, etc), or combinations thereof. For off-shore locations, the pipeline system can be a structure rising above the surface of the water (well platform) or it can be sub-surface (on the sea bed).
  • the pipeline system includes intermediate separation, collection and/or processing facilities.
  • the intermediate facilities contain one or more supply tanks to dispense fixing agents and/or other process aids, e.g., foamants, NaOH, diluents, etc., to facilitate the flow of produced fluids in into the pipeline.
  • the intermediate facilities may also include equipment such as gravity separator, plate separator, hydroclone, coalescer, centrifuge, filter, collection tanks, etc. for the separation, storage, and treatment of recovered water after separation from the crude. The separation is carried out at the destination in one embodiment, and at intervals along the pipeline in another embodiment.
  • the pipeline may extend from a first equipment to another equipment located at a different location or section of the facility.
  • the first equipment can be a vessel where the fixing agent is first introduced or mixed with the produced fluid.
  • the second equipment can be a separator for the oil/water separation or another vessel.
  • additional chemical reagents such as complexing agents can be added to the second equipment to facilitate the oil/water separation to recover treated crude oil and waste water for subsequent water treatment or discharge.
  • the wastewater after being separated from the treated crude is injected back into the oil or gas reservoir (in production or depleted) in one embodiment.
  • the wastewater is further treated being injected into the reservoir prior to being discharged.
  • the wastewater is treated to meet environmental regulations for water quality and discharged.
  • At least 50% of mercury is removed from the produced fluid for a mercury concentration of less than 100 ppbw in the treated hydrocarbon.
  • at least 50% of arsenic is removed from a produced fluid such as shale oil for an treated shale oil having less than 100 ppbw arsenic in the treated hydrocarbon.
  • at least 50% of mercury is removed from the produced fluid for a mercury concentration of less than 50 ppbw in the treated hydrocarbon.
  • at least 50% of arsenic is removed from a produced fluid such as shale oil for an treated shale oil having less than 50 ppbw arsenic in the treated hydrocarbon.
  • a least 75% of the heavy metals such as mercury and/or arsenic is removed from a produced fluid such as crude oil in one embodiment; and at least 90% in a second embodiment.
  • the fixing agent is a sulfur-based compound for forming sulfur complexes with the heavy metals.
  • examples include organic and inorganic sulfide materials (including polysulfides), which in some embodiments, convert the heavy metal complexes into a form which is more soluble in an aqueous dilution fluid than in a produced fluid such as shale oil.
  • the sulfur based compounds are selected from sodium polysulfide, ammonium polysulfide, and mixtures thereof.
  • the fixing agent is a water-soluble monatomic sulfur species, e.g., sodium sulfides and alkali sulfides such as hydrosulfides or ammonium sulfides, for the extraction of mercury into an aqueous dilution fluid as soluble mercury sulfur complexes.
  • the sulfur-based compound is any of hydrogen sulfide, bisulfide salt, or a polysulfide, for the formation of precipitates which require separation from the treated produced fluid by filtration, centrifugation, and the like.
  • the fixing agent is an organic polysulfide such as di-tertiary-nonyl-polysulfide.
  • the sulfur based compound is an organic compound containing at least a sulfur atom that is reactive with mercury as disclosed in U.S. Pat. No. 6,685,824; the relevant disclosure is included herein by reference.
  • Examples include but are not limited to dithiocarbamates, sulfurized olefins, mercaptans, thiophenes, thiophenols, mono and dithio organic acids, and mono and dithiesters.
  • the fixing agent is a polysulfide (organic or inorganic) which converts the elemental Hg into a species that is dissolved in the dilution fluid, e.g., HgS 2 H—.
  • the fixing agent is an oxidizing agent which converts the heavy metal to an oxidation state that is soluble in water.
  • Examplary fixing agents include elemental halogens or halogen containing compounds, e.g., chlorine, iodine, fluorine or bromine, alkali metal salts of halogens, e.g., halides, chlorine dioxide, etc; iodide of a heavy metal cation; ammonium iodide; an alkaline metal iodide; etheylenediamine dihydroiodide; hypochlorite ions (OCl ⁇ such as NaOCl, NaOCl 2 , NaOCl 3 , NaOCl 4 , Ca(OCl) 2 , NaClO 3 , NaClO 2 , etc.); vanadium oxytrichloride; Fenton's reagent; hypobromite ions; chlorine dioxine; iodate IO 3 (such as potassium io)
  • the fixing agent is selected from KMnO 4 , K 2 S 2 O 8 , K 2 CrO 7 , and Cl 2 .
  • the fixing agent is selected from the group of persulfates.
  • the fixing agent is selected from the group of sodium perborate, potassium perborate, sodium carbonate perhydrate, potassium peroxymonosulfate, sodium peroxocarbonate, sodium peroxodicarbonate, and mixtures thereof.
  • a complexing agent is also added to the fixing agent to form strong complexes with the heavy metal cations in the produced fluids, e.g., Hg 2+ , extracting heavy metal complexes from the oil phase and/or the interface phase of the oil-water emulsion into the water phase by forming water soluble complexes.
  • complexing agents to be added to an oxidizing fixing agent include hydrazines, sodium metabisulfite (Na 2 S 2 O 5 ), sodium thiosulfate (Na 2 S 2 O 3 ), thiourea, thiosulfates (such as Na 2 S 2 O 3 ), ethylenediaminetetraacetic acid, and combinations thereof.
  • the fixing agent is added to the pipeline first to oxidize the heavy metal, then the complexing agent is subsequently added to form a complex that is soluble in water.
  • the complexing agent can be injected at intervals along the pipeline, or it can be subsequently added after the introduction of the fixing agent.
  • the fixing agent can be added as in a solid form, or slurried/dissolved in a diluent, e.g., water, alcohol (such as methanol, ethanol, propanol), a light hydrocarbon diluent, or combinations thereof, in an effective amount for the treated produced fluid to have a mercury concentration of less than 100 ppbw.
  • Effective amount means a sufficient amount for a molar ratio of fixing agent to heavy metals ranging from 1:1 to 100,000:1 in one embodiment, 5:1 to 20,000:1 in a second embodiment; from 50:1 to 10,000:1 in a third embodiment; from 100:1 to 5,000:1 in a fourth embodiment; and from 150:1 to 500:1 in a fifth embodiment.
  • the amount as molar ratio of complexing agent to soluble mercury ranges from 2:1 to about 100,000:1 in one embodiment; from 5:1 to about 3,000:1 in a second embodiment; and from 20:1 to 500:1 in a third embodiment.
  • the fixing agent can be injected into the pipeline or into a location downhole using conventional equipment known in the art such as metering pumps or jet pumps.
  • the oxidant can be added to the pipeline and then mixed by a first static mixer.
  • the complexing agent can be added and mixed with a second static mixer, then allowed to enter the pipeline for the reaction to go to sufficient conversion.
  • the fixing agents may require special handling, e.g., corrosion resistant equipment and/or safety procedures.
  • the solution can be generated on-site with the use of commercially available electro-chlorination system, allowing the generation of sodium hypochlorite on-site for injection directly into the pipeline.
  • the pipeline reaction is allowed to take place in a section that provides sufficient residence time for the removal of the target heavy metals from the produced fluids.
  • the pipeline reaction section requiring special handling can run from the production well to an intermediate processing facility located a short distance from the production well, for the collection and separation of the treated produced fluids from waste water containing heavy metals and corrosive fixing agents. Additional aqueous dilution fluid can be injected into the pipeline for the transport of the treated produced fluids from the intermediate processing facility to the final destination, e.g., shipping terminal or FPSO.
  • FIG. 1 is a diagram of an exemplary floating production, storage and offloading (FPSO) unit with a pipeline conditioning system for removing heavy metals from hydrocarbons such as oil and gas from one or more subsea wells 102 .
  • FPSO floating production, storage and offloading
  • a system 104 for dispensing at least a fixing agent into the pipeline deployed in conjunction with the facility 100 is located at a water surface 106 .
  • the dispensing system 104 services one or more subsea production wells 102 residing in a seabed 108 .
  • each well 102 includes a wellhead 112 and related equipment positioned over a wellbore 114 formed in a subterranean formation 116 .
  • Production fluid is conveyed to a surface collection facility such as the FPSO 100 or separate structure, such as an intermediate collection and/or processing facility (not shown), via a pipeline 120 .
  • the fluid may be conveyed to the surface facility 100 in an untreated state or after being processed, at least partially, by an intermediate collection and/or processing facility (not shown).
  • the line 120 extends directly from the wellhead 112 or from a manifold (not shown) that receives production flow from a plurality of wellheads 112 .
  • the flow line 120 includes a vertical section or riser 124 (not shown) that terminates at the FPSO 100 .
  • the dispensing system 104 continuously or intermittently injects at least a fixing agent into the flow line 120 or the well 102 for the removal of heavy metals.
  • the dispensing system 104 can be utilized with one or more sensors 132 positioned along selected locations along the flow line 120 and the well 102 .
  • the dispensing system 104 supplies (or pumps) one or more fixing agents to the flow line 120 .
  • This supply of fixing agents may be continuous, intermittent or actively controlled in response to sensor measurements.
  • the dispensing system 104 receives signals from the sensors 132 regarding a parameter of interest relating to a characteristic of the produced fluid, e.g., temperature, pressure, flow rate, amount of water, concentration of heavy metals in the produced fluids based on the formation of intermediate complexes, etc. Based on the data provided by the sensors 132 , the dispensing system 104 determines the appropriate type and/or amount of fixing agents needed for the pipeline reactions to take place to reduce the concentration of mercury, arsenic, and the like.
  • the dispensing system 104 can include one or more supply lines 140 , 142 , 144 that dispense fixing agents, e.g., fixing agents such as sodium hypochlorite, etc., into the pipeline 120 at a location close to the wellhead, or right at the wellhead 102 , in a manifold (not shown) or into a location downhole in the wellbore 114 , respectively.
  • the supply tank or tanks 146 and injection units 148 can be positioned on the surface facility 110 for continuous supply to the dispensing system 104 .
  • one or more of the supply lines 140 , 142 , 144 can be inside or along the pipeline 120 , for intermittent dispensing of fixing agents into the pipeline 120 for the removal of heavy metals.
  • dispensation points are shown in FIG. 1 , it should be understood that a single dispensation point may be adequate.
  • the above-discussed locations are merely representative of the locations at which the fixing agents can be dispensed into the production fluid for the pipeline reactions.
  • the pipeline 120 can extend on land between a production well at a remote location to a facility 100 located in a refinery or a shipping terminal.
  • the dispensing system 104 is not limited to the dispensing of fixing agents for the removal of heavy metals. It can also be used for the addition of other process aids into the pipeline.
  • the pipeline reaction system further includes intermediate collection and/or processing facilities.
  • oil platform 2 is connected to receive production fluid from a wellhead 4 via pipeline 10 , and pipeline 12 for the supply of a dilution fluid needed for the removal of heavy metals.
  • the wellhead tree 4 is connected by an output pipeline 6 to a first processing facility 8 , which is connected by pipeline 10 and pipeline 12 to a second processing facility 14 situated remotely therefrom.
  • the facilities 8 and 14 may be floating and/or tethered to the seabed.
  • the facilities contain one or more supply tanks to dispense fixing agents or other process aids into the pipeline 10 .
  • the facility may include equipment such as gravity separator, plate separator, hydroclone, coalescer, centrifuge, filter, etc., for the collection and separation of crude oil from water containing heavy metals, and the discharge of waste water containing removed mercury into pipeline 86 to a reservoir under wellhead 78 .
  • equipment such as gravity separator, plate separator, hydroclone, coalescer, centrifuge, filter, etc.
  • the term “include” and its grammatical variants are intended to be non-limiting, such that recitation of items in a list is not to the exclusion of other like items that can be substituted or added to the listed items.
  • the terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Unless otherwise defined, all terms, including technical and scientific terms used in the description, have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.

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  • Engineering & Computer Science (AREA)
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  • General Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Life Sciences & Earth Sciences (AREA)
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  • Mining & Mineral Resources (AREA)
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  • General Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Inorganic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Removal Of Specific Substances (AREA)
  • Extraction Or Liquid Replacement (AREA)
US13/895,612 2012-05-16 2013-05-16 Pipeline reaction for removing heavy metals from produced fluids Abandoned US20130306310A1 (en)

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US8790427B2 (en) 2012-09-07 2014-07-29 Chevron U.S.A. Inc. Process, method, and system for removing mercury from fluids
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US9199898B2 (en) 2012-08-30 2015-12-01 Chevron U.S.A. Inc. Process, method, and system for removing heavy metals from fluids
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WO2013173602A1 (en) 2013-11-21
CA2872804A1 (en) 2013-11-21
AU2013262703A1 (en) 2014-11-06
EP2850154A4 (en) 2015-12-16
AU2013262703B2 (en) 2018-02-22
EP2850154A1 (en) 2015-03-25
CN104302738A (zh) 2015-01-21
MY172152A (en) 2019-11-14
CL2014003085A1 (es) 2015-02-20
AR094994A1 (es) 2015-09-16

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