WO2002048284A1 - Procede de recuperation d'hydrogene sulfure - Google Patents

Procede de recuperation d'hydrogene sulfure Download PDF

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Publication number
WO2002048284A1
WO2002048284A1 PCT/GB2001/005499 GB0105499W WO0248284A1 WO 2002048284 A1 WO2002048284 A1 WO 2002048284A1 GB 0105499 W GB0105499 W GB 0105499W WO 0248284 A1 WO0248284 A1 WO 0248284A1
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WO
WIPO (PCT)
Prior art keywords
hydrogen sulphide
formaldehyde
fluid
water
scavenging
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Application number
PCT/GB2001/005499
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English (en)
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WO2002048284A8 (fr
Inventor
John Andrew Hardy
Waleed John Georgie
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Amerada Hess Limited
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Amerada Hess Limited filed Critical Amerada Hess Limited
Priority to AU2002222189A priority Critical patent/AU2002222189A1/en
Priority to CA002432071A priority patent/CA2432071A1/fr
Priority to DE60111778T priority patent/DE60111778D1/de
Priority to AT01270582T priority patent/ATE298779T1/de
Priority to EP01270582A priority patent/EP1349904B8/fr
Priority to US10/450,601 priority patent/US20040074813A1/en
Priority to BR0116164-4A priority patent/BR0116164A/pt
Publication of WO2002048284A1 publication Critical patent/WO2002048284A1/fr
Publication of WO2002048284A8 publication Critical patent/WO2002048284A8/fr
Priority to NO20032669A priority patent/NO20032669L/no

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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
    • C10G29/00—Refining of hydrocarbon oils, in the absence of hydrogen, with other chemicals
    • C10G29/20—Organic compounds not containing metal atoms
    • C10G29/22—Organic compounds not containing metal atoms containing oxygen as the only hetero atom
    • C10G29/24—Aldehydes or ketones

Definitions

  • This invention relates to a high efficiency chemical scavenging method for reducing hydrogen sulphide in multiphase well streams, in particular where conventional methods of removal such as the use of an amine plant is not commercially viable .
  • Hydrogen sulphide is an undesirable contaminant which presents many environmental and safety hazards . It is corrosive, malodorous, toxic if inhaled, a strong irritant to eyes and mucous membranes and is associated with the formation of acid rain. Accordingly it is necessary to remove hydrogen sulphide from hydrocarbon production, or at least reduce the levels of hydrogen sulphide in hydrocarbons during the production, storage or processing of hydrocarbon fluids to levels that satisfy safety and product specification requirements.
  • non-regenerative chemical scavengers are injected into the gas phase.
  • the non-regenerative scavengers such as triazines typically react with the toxic hydrogen sulphide in-line to form a sulphur- containing by-product.
  • Such non-recoverable systems are described for example in GB 22900542 A, EP-A- 0411745, US5354453, US6063346, US5674377, US5554349 and US5744024.
  • TJS60G3346 describes the use, inter alia, of formaldehyde to scavenge hydrogen sulphide non- regeneratively from a hydrocarbon fluid that contains, by weight of the fluid, between 5ppm and 200ppm of hydrogen sulphide prior to treatment.
  • formaldehyde to scavenge hydrogen sulphide non- regeneratively from a hydrocarbon fluid that contains, by weight of the fluid, between 5ppm and 200ppm of hydrogen sulphide prior to treatment.
  • contactor-based recoverable scavenging systems are used to treat hydrocarbon fluids containing high concentrations of hydrogen sulphide, these systems have had limited application away from processing sites or for relatively small fields with low production rates, whether on-shore or off-shore. This is largely because of the high capital and operating costs and the safety issues that bringing such high levels of hydrogen sulphide onto offshore platforms present. Furthermore, it has been generally considered the non-recoverable in-line methods would require the use of prohibitively high amounts of chemical scavenger in order to reduce the hydrogen sulphide levels sufficiently and would promote the undesirable formation of large amounts of reaction products. Accordingly, the development of small offshore oil fields that contain such high levels of hydrogen sulphide (250 ppm or more) has not been considered to be economically viable or safe and thus oil production form such fields is presently extremely rate.
  • a method for reducing the amount of hydrogen sulphide in a multiphase hydrocarbon produced fluid prior to phase separation and processing comprising the step of adding formaldehyde to the produced fluid, which produced fluid had, prior to the addition of formaldehyde, a concentration of hydrogen sulphide of at least 250ppm by weight of the fluid.
  • formaldehyde can be used successfully to reduce the hydrogen sulphide content of produced fluid that initially contains such high levels of hydrogen sulphide which can be 10,000 ppm or more in the gas phase and more particularly more than 250 ppm by weight of the multiphase hydrocarbon fluid overall.
  • Such technology is highly advantageous since it allows, for example, oil production from fields containing reservoir fluids having a hydrogen sulphide content that is too high to satisfy safety requirements or for commercial acceptance, and which would otherwise be left undeveloped, in a manner which is highly effective and provides significant safety benefits at relatively low cost.
  • the method of the invention is particularly valuable because of its effectiveness on the liquid phase of the multiphase system.
  • the multiphase system will be crude oil which typically comprises a liquid phase and an associated gas phase and may contain water as a liquid phase additional to an oil phase and/or as part of an oil/water phase. It is any such system which is referred to herein as "produced fluid".
  • the method thus has particular application in the oil industry, for example where the hydrocarbon fluid is an oil reservoir fluid, such as crude oil and its associated gas, and where the oil well produced fluids (crude oil having a liquid phase and associated gas phase) flow through a sub-sea flowline.
  • oil reservoir fluid such as crude oil and its associated gas
  • oil well produced fluids crude oil having a liquid phase and associated gas phase
  • the method of this invention can be used to good advantage when the produced fluid flows through an on-shore pipeline, the method is particularly useful for in-line scavenging of hydrogen sulphide from a subsea well-produced sour crude oil containing very high hydrogen sulphide levels and where the well is tied back via a flow line to a host facility at which there is no provision for H 2 S scavenging and/or where a H 2 S removal facility is too expensive and/or impractical to install.
  • the hydrogen sulphide content of the crude oil that is delivered to the platform is reduced to safe and commercially acceptable levels and reaction by-product formation is manageable.
  • This process thus advantageously provides a low cost manner of developing sour oil fields that would otherwise not be safe or economically viable to develop or advantageously provides a way of modifying existing processes of handling sour hydrocarbon fluids, for example, within oil fields already in production, such that the method according to the present invention can replace and/or supplement existing methods.
  • the method of this invention is particularly suitable for reducing the H 2 S content of the produced fluid by at least 95%.
  • the examples which follow how efficiency of scavenging to such an extent can be obtained.
  • the method can also be used to achieve less efficient scavenging for example by a minimum of say 20%, for example 50%, 70% or 90%. This lower efficiency may be acceptable when the H 2 S-reduced produced fluid is to be co-mingled with a sweet produced fluid.
  • the invention relates to a process for scavenging (reducing or removing) hydrogen sulphide from any hydrocarbon fluid that contains high levels of hydrogen sulphide.
  • high is meant that the hydrogen sulphide is contained in the produced fluid in an amount, by weight of at least 250ppm, preferably at least 500ppm, more preferably at least lOOOppm and most preferably at least 2000ppm.
  • This method is particularly useful for scavenging hydrogen sulphide from a produced fluid containing, by weight from 500 to ⁇ OOOppm so that, for example, the costs of the method are economically justifiable.
  • the formaldehyde is usually added as an aqueous solution, in the form of formalin.
  • the formalin solution typically comprises 30 to 40% active formaldehyde, commonly being 37% active, with 5 to 10% methanol added as a stabiliser. Where reference is made hereinafter to quantities of formaldehyde, these are related to 37% active formalin. Obviously, adjustments are to be made in respect of formalin solutions of different concentrations .
  • the amount of methanol may be increased in order to increase the low temperature stability of formaldehyde and to compensate for possible loss via the delivery systems.
  • the chemical scavenger, formaldehyde is added to the produced fluid in a concentration sufficient to reduce substantially the amount of hydrogen sulphide in the fluid.
  • the formaldehyde will be used in an amount in excess of stoichiometric with respect to the hydrogen sulphide in the multiphase production.
  • the formaldehyde is added to the fluid in a ratio by weight of formaldehyde to hydrogen sulphide in the multiphase production of from 2:1 to 8:1. It has been found that where a higher ratio of formaldehyde to hydrogen sulphide then stoichiometric is used, the fate of hydrogen sulphide removal may be increased.
  • a weight ratio of formaldehyde to hydrogen sulphide of from 2:1 to 6:1 is preferred and a ratio of between 2 : 1 to 4:1 is optimal.
  • the formaldehyde disperses through the produced fluid substantially homogeneously by the natural turbulence of the fluid flow.
  • a mixing device may be also be used to achieve thorough mixing if desired.
  • the contact time of the formaldehyde and hydrogen sulphide is preferably at least 20 minutes. More preferably, the contact time is from 30 to 60 minutes.
  • the temperature is preferably in the range 60 to 75 deg C and, although no advantage in efficiency at higher temperatures is seen, there is no detrimental effect at up to 120 deg C.
  • the efficiency and rate of reaction is also pressure dependent and minimum pressure is preferably 20 bar, more preferably 30 bar, and although reaction continues at lower pressure, the scavenging may not be to the same level .
  • the formaldehyde is preferably added upstream at a point which provides an appropriate residence time of the hydrogen sulphide and formaldehyde in the production fluid.
  • the hydrogen sulphide content of the fluid should generally have been reduced to relatively safe and conventionally treatable levels, such as between 0 to 600ppm by volume in the gaseous phase .
  • formaldehyde may be added into the production tubing downhole as deep as may be necessary to provide sufficient residence time to effect the scavenging process .
  • Any residual hydrogen sulphide that has not been scavenged by the formaldehyde can be easily removed from the gas phase by any conventional physical or chemical method of reducing/ emoving hydrogen sulphide from the separated gas phase containing low levels, typically less than 600 ppm by volume.
  • a chemical scavenger such as a triazine compound can be added to the gaseous phase in the conventional manner.
  • a methyl triazine compound may be preferred due to its efficiency in removing hydrogen sulphide from gaseous hydrocarbon streams.
  • the triazine can be added at a ratio, by weight of triazine to hydrogen sulphide, of between 15:1 to 6:1, most preferably between 8:1 to 13:1 and optimally at 10:1, to maximise the residual hydrogen sulphide removal at minimum cost .
  • the method further comprises the step of adding water to the hydrocarbon fluid. This is likely to be necessary with dry crude oil production before water production has occurred. When water production has occurred, water content of the multiphase system may become sufficiently high for water addition to be obviated.
  • the presence of water advantageously improves the efficiency of the scavenging reaction and provides a carrier phase for some of the reaction products. If water is added, addition is preferably at a point substantially upstream of the processing facility in order to enhance the dispersion of some insoluble reaction products, which may be the by-products of the hydrogen sulphide and formaldehyde reaction.
  • the water is added at substantially the same time as the formaldehyde to be sure that water is present from the start of the formaldehyde/hydrogen sulphide reactions. It has been found that the addition of water does not reduce the efficiency of hydrogen sulphide removal by the formaldehyde in this method and has no effect on the stoichio etry o the reaction, which requires 1 ol of formaldehyde as such for 1 mol of hydrogen sulphide . Dry crude oil is regarded as being "substantially free of water", by which is meant here less than 2% by volume of water is present in the produced fluid.
  • mercaptan level is low or does not prevent formation of insoluble products the presence of a water phase allows dispersion of the water insoluble reaction products.
  • “manageable amount” is typically meant less than 30 nag of solids formation per ml of the water phase.
  • the water used in the water addition step may be sea water, modified sea water or fresh water depending on availability and compatibility.
  • the water is preferably added in an amount such that the reduction of the capacity of the lines for carrying production fluid is minimised, whilst the dispersion of insoluble by-products is maximised.
  • the method of the present invention has been found to be particularly efficient in circumstances where the C0 2 content of the produced fluid is high. For example up to 140 mol% of the gas phase. Indeed in circumstances where the produced fluid comprises a gaseous phase containing carbon dioxide, the formation of insoluble products is minimised whilst hydrogen sulphide removal remains efficient.
  • Figure 1 shows a schematic diagram showing the application of the method of the present invention to scavenge hydrogen sulphide from sour crude oil produced via a subsea well;
  • Figure 2 is a schematic diagram of a high pressure test loop used in examples set out hereinafter and
  • a stabilised formaldehyde solution containing 37% formaldehyde and 7% methanol is stored in the storage tank 1.
  • the tank 1 is connected by an injection or umbilical line 2 to a valve injector (not shown) which is fitted into the wall of the flow line 3 immediately down stream of a remote sub-sea wellhead 4.
  • the valve injector has a spray nozzle for atomising the formaldehyde solution into the flowing stream of the well produced crude oil flowing through the flowline 3 from the wellhead 4 to the platform 5.
  • Low sulphate sea water is supplied from facility 6 through an injection or umbilical line 7 to a valve injector (not shown) which is fitted into the wall of the flow line 3 immediately down stream of the formaldehyde injection point 15.
  • Methyl triazine is stored in the storage tank 8.
  • the tank 8 is connected by an injection or umbilical line 9 to a valve injector (not shown) which is fitted into the wall of the on-platform line 10.
  • Line 10 carries the gaseous phase of the production on the platform after separation of the fluid stream.
  • the flowing gaseous phase is analysed from time to time for example (at points 20, 21 and 22) in the conventional manner to determine the hydrogen sulphide content of the gaseous phase.
  • the flow of formaldehyde is adjusted in the conventional manner to add an amount that is sufficient to reduce the crude oil hydrogen sulphide concentration to less than 600ppm by volume in the gaseous phase, at the point where the crude oil is brought onto the platforms . This concentration is measured at point 20.
  • the residence time is approximately one hour and the temperature within the flowline is around 65°C and average pressure is 30 bar
  • approximately 2 to 3 litres of the formaldehyde solution per kg of hydrogen sulphide to be scavenged is sufficient to reduce the hydrogen sulphide concentration to lOOppm by volume in the gaseous phase, at the point where the crude oil is brought onto the platform.
  • the ratios of formaldehyde added to hydrogen sulphide to be removed depends on the temperature and residence time.
  • the crude oil is delivered to the platform 5 and fed into a separator 11, which separates the gaseous hydrocarbon phase, liquid hydrocarbon phase and aqueous phase into separate lines 10, 12 and 13 on the platform.
  • the aqueous phase, containing some formaldehyde/hydrogen sulphide reaction by-products is delivered by flow line 13 to a disposal well .
  • the liquid hydrocarbon phase containing less than lOppm hydrogen sulphide by weight of the liquid and some oil soluble reaction product is delivered by line 12 for export or further processing.
  • the gaseous phase containing lOOppm by volume of hydrogen sulphide in the gaseous phase is delivered by line 10 for further scavenging treatment.
  • methyl triazine stored in tank 8 is injected into the line 10, at a weight ratio of methyl triazine to hydrogen 'sulphide of approximately 10:1, in the conventional manner, in order to scavenge the residual hydrogen sulphide not removed by the sub-sea formaldehyde treatment .
  • the oil reservoir crude oil fluid that, prior to formaldehyde treatment contained hydrogen sulphide at a concentration of approximately 2000ppm by weight of the crude oil fluid is delivered to the platform containing, in the gaseous phase, a hydrogen sulphide concentration of lOOppm by volume of the gaseous phase and contains an insignificant amount of solid byproducts, typically less than 30 mg of the solids per ml of the aqueous phase.
  • the gaseous phase contains less than lOppm by volume of hydrogen sulphide.
  • the liquid phase, in line 12 contains less than lOppm by weight of liquid.
  • This example compares the effectiveness of two scavengers, formaldehyde and triazine, in reducing hydrogen sulphide from a crude oil stream containing, prior to the addition of scavenger, hydrogen sulphide at a concentration of 8,500ppm by volume in the gaseous phase of the crude oil .
  • the crude oil stream was treated in a line using the scavengers at a ratio by weight of scavenger to hydrogen sulphide as shown in Table 2 and at a temperature of 65°C.
  • Table 2 The results are set out in Table 2 below.
  • the data was generated in a closed test loop as shown in Figure 2 of the accompanying drawings and which was constructed and operated as follows.
  • a test loop 100 having a volume of 340 litres was constructed from a 70.5m length of 7.6cm diameter stainless steel pipe and incorporated a vertical separator vessel 31 having a volume of 197 litres and a centrifugal circulation pump 32.
  • a gas by-pass line 33 was extended from the top of the vessel 31 to a 28mm flow restriction orifice 34 located in the pipework between flanges approximately 5m downstream of the pump 32 and acting as a venturi to produce a vacuum when oil was circulated. This sucked the gas from the top of the separator vessel 31 into the loop 100 so creating a gas circulation when a gas by-pass valve 35 was opened.
  • the venturi 34 allowed gas circulation to be restricted when the by-pass valve 35 was closed.
  • venturi 34 acted to ensure a constant flow rate by balancing the outlet from pump 32 with the fluid level in the separator vessel 1, which was maintained at an approximate level of 700-800mm by adjusting vessel outlet valve 36.
  • test loop incorporated also three in-line mixer units 37a, 37b, 37c spaced around the loop at approximately 0.7m, 29.5 m and 48.8m from the restriction orifice at 36. These were removable to determine the effect of different mixing regimes .
  • Temperature control was provided by heat tracing the loop and separator vessel and insulation of the system insulated.
  • test loop Additional features of the test loop are injector 38 for scavenger, sampling valves 39a, 39b and 39c and vent stack 40 and flushing valve 41.
  • This example demonstrates the effect of the presence of carbon dioxide in the gaseous phase on the scavenging efficiency of formaldehyde when treating the crude oil under similar condition in terms of high H 2 S in the gas phase (about 8000 - 10000 ppm) , namely same chemical ratio of H 2 S scavenger, 65 C and 60. bar pressure.
  • high H 2 S in the gas phase about 8000 - 10000 ppm
  • H 2 S scavenger 65 C and 60. bar pressure
  • This example demonstrates the effect of temperature on the scavenging efficiency of formaldehyde when treating the crude oil mixture under similar conditions to earlier examples at 60 bar pressure, using 4:1 scavenging ratio, with 10% water by volume having been added to the dry crude oil.
  • the data were generated using a high pressure autoclave. The results are set out in Table 6 below.
  • This example demonstrates the scavenging efficiency of formaldehyde under different ratios by weight of formaldehyde to hydrogen sulphide when treating the crude oil stream of Example 1 under the same conditions as Example 1 except that 50% water by volume was added to the dry crude oil.
  • the data were generated using a high pressure autoclave. The results are set out in Table 7 below.
  • This example demonstrates the effect of different mixing rates on the scavenging efficiency of formaldehyde when treating a dry crude oil mixture under similar conditions to earlier examples at 75°C, 60 Bar, i -. l scavenging ratio, with 10% water by volume added to the dry crude oil.
  • the data were generated using a high pressure autoclave.
  • the data were generated using a high pressure autoclave.
  • Table 8 The results are set out in Table 8 below.
  • This example demonstrates the effect of pressure on the scavenging efficiency of formaldehyde at different degrees of mixing of formaldehyde with dry crude oil and 10% water added. Testing was carried out using the test loop; of Figure 2. Different mixing regimes were achieved by controlling the flow of the gas phase through the dedicated separator and into the circulating liquid. The gas flow into the main oil loop was controlled by the valve in the gas line. The results are set out in Table 9 below.

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Abstract

Procédé pour récupérer l'hydrogène sulfuré dans un système à phases mixtes et notamment dans un liquide d'hydrocarbures ayant une phase liquide et une phase gazeuse. Le liquide d'hydrocarbures contient un taux élevé d'hydrogène sulfuré, qui peut même dépasser 5000 ppm en poids en phase gazeuse avant le traitement. On ajoute au liquide du formaldéhyde et de préférence de l'eau. Le procédé est particulièrement utile pour la récupération en ligne de l'hydrogène sulfuré à partir du brut acide contenant des taux très élevés d'hydrogène sulfuré. La concentration de l'hydrogène sulfuré dans le brut acheminé vers la plate-forme est réduite jusqu'à un niveau sûr et commercialement acceptable; la formation de sous-produits solides est négligeable. Ce procédé offre la possibilité de développer à faible coût des gisements pétroliers acides qui, en d'autres circonstances, ne seraient pas développés pour des raisons de sécurité ou de viabilité économique; en variante, il offre un moyen de modifier les processus existants de traitement des fluides d'hydrocarbures acides, par exemple, à l'intérieur des gisements pétroliers en fonctionnement. De cette manière, le procédé de l'invention permet de remplacer les procédés actuellement employés.
PCT/GB2001/005499 2000-12-14 2001-12-13 Procede de recuperation d'hydrogene sulfure WO2002048284A1 (fr)

Priority Applications (8)

Application Number Priority Date Filing Date Title
AU2002222189A AU2002222189A1 (en) 2000-12-14 2001-12-13 Hydrogen sulphide scavenging method
CA002432071A CA2432071A1 (fr) 2000-12-14 2001-12-13 Procede de recuperation d'hydrogene sulfure
DE60111778T DE60111778D1 (de) 2000-12-14 2001-12-13 Verfahren zum vernichten von wasserstoffsulfid in kohlenstoffprodukten
AT01270582T ATE298779T1 (de) 2000-12-14 2001-12-13 Verfahren zum vernichten von wasserstoffsulfid in kohlenstoffprodukten
EP01270582A EP1349904B8 (fr) 2000-12-14 2001-12-13 Procede d'elimination d'hydrogene sulfure de charges hydrocarbures
US10/450,601 US20040074813A1 (en) 2000-12-14 2001-12-13 Hydrogen sulphide scavenging method
BR0116164-4A BR0116164A (pt) 2000-12-14 2001-12-13 Método de sequestrar sulfeto de hidrogênio
NO20032669A NO20032669L (no) 2000-12-14 2003-06-12 Fremgangsmåte ved utlufting av hydrogensulfid

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB0030555.7 2000-12-14
GBGB0030555.7A GB0030555D0 (en) 2000-12-14 2000-12-14 Hydrogen sulphide scavenging method

Publications (2)

Publication Number Publication Date
WO2002048284A1 true WO2002048284A1 (fr) 2002-06-20
WO2002048284A8 WO2002048284A8 (fr) 2003-01-09

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PCT/GB2001/005499 WO2002048284A1 (fr) 2000-12-14 2001-12-13 Procede de recuperation d'hydrogene sulfure

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US (1) US20040074813A1 (fr)
EP (1) EP1349904B8 (fr)
AT (1) ATE298779T1 (fr)
AU (1) AU2002222189A1 (fr)
BR (1) BR0116164A (fr)
CA (1) CA2432071A1 (fr)
DE (1) DE60111778D1 (fr)
GB (1) GB0030555D0 (fr)
NO (1) NO20032669L (fr)
WO (1) WO2002048284A1 (fr)

Cited By (4)

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Publication number Priority date Publication date Assignee Title
US8080225B2 (en) 2005-11-07 2011-12-20 Specialist Process Technologies Limited Functional fluid and a process for the preparation of the functional fluid
US9752083B2 (en) 2012-08-21 2017-09-05 Lonza, Inc. Method of scavenging hydrogen sulfide and/or sulfhydryl compounds
RU2665475C2 (ru) * 2016-11-23 2018-08-30 Руслан Адгамович Вагапов Способ получения эффективных реагентов, обладающих высокой скоростью поглощения сероводорода и меркаптанов, стабильных при низких температурах
RU2749133C1 (ru) * 2020-07-29 2021-06-04 Публичное акционерное общество "Метафракс" Способ получения раствора альдегидного морозостойкого (варианты)

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CA3006730C (fr) * 2017-06-02 2021-04-20 Baker Hughes, A Ge Company, Llc Materiaux architecturaux comme additifs visant a reduire ou empecher la formation de solide et le depot de calcaire et ameliorer le ravage de sulfure d'hydrogene
JP2020019898A (ja) * 2018-08-01 2020-02-06 独立行政法人石油天然ガス・金属鉱物資源機構 生産流体処理システム及び生産流体の処理方法
US10787614B2 (en) * 2018-10-15 2020-09-29 Merichem Company Hydrogen sulfide removal process

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US6063346A (en) * 1998-06-05 2000-05-16 Intevep, S. A. Process for scavenging hydrogen sulfide and mercaptan contaminants from a fluid
WO2001046553A1 (fr) * 1999-12-21 2001-06-28 Bp Exploration Operating Company Limited Procede de traitement d'un puits de forage

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US1991765A (en) * 1932-01-23 1935-02-19 Dupont Viscoloid Company Aldehyde-hydrogen sulphide reaction product
US2426318A (en) * 1945-11-15 1947-08-26 Stanolind Oil & Gas Co Inhibiting corrosion
FR2651500A1 (fr) * 1989-09-05 1991-03-08 Hoechst France Nouvelles emulsions eau dans huile et leur application a l'elimination du sulfure d'hydrogene.

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6063346A (en) * 1998-06-05 2000-05-16 Intevep, S. A. Process for scavenging hydrogen sulfide and mercaptan contaminants from a fluid
WO2001046553A1 (fr) * 1999-12-21 2001-06-28 Bp Exploration Operating Company Limited Procede de traitement d'un puits de forage

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8080225B2 (en) 2005-11-07 2011-12-20 Specialist Process Technologies Limited Functional fluid and a process for the preparation of the functional fluid
US8591767B2 (en) 2005-11-07 2013-11-26 Specialist Process Technologies Limited Functional fluid and a process for the preparation of the functional fluid
US9752083B2 (en) 2012-08-21 2017-09-05 Lonza, Inc. Method of scavenging hydrogen sulfide and/or sulfhydryl compounds
EP2888340B1 (fr) * 2012-08-21 2020-12-09 Lonza, Llc Procédé d'épuration des composes sulfhydryles
RU2665475C2 (ru) * 2016-11-23 2018-08-30 Руслан Адгамович Вагапов Способ получения эффективных реагентов, обладающих высокой скоростью поглощения сероводорода и меркаптанов, стабильных при низких температурах
RU2749133C1 (ru) * 2020-07-29 2021-06-04 Публичное акционерное общество "Метафракс" Способ получения раствора альдегидного морозостойкого (варианты)

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EP1349904A2 (fr) 2003-10-08
BR0116164A (pt) 2004-02-25
DE60111778D1 (de) 2005-08-04
US20040074813A1 (en) 2004-04-22
NO20032669D0 (no) 2003-06-12
ATE298779T1 (de) 2005-07-15
GB0030555D0 (en) 2001-01-31
EP1349904B8 (fr) 2005-08-31
WO2002048284A8 (fr) 2003-01-09
EP1349904B1 (fr) 2005-06-29
NO20032669L (no) 2003-08-14
CA2432071A1 (fr) 2002-06-20
AU2002222189A1 (en) 2002-06-24

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