WO2014209639A1 - Reducing sugar-based sulfide scavengers and methods of use in subterranean operations - Google Patents
Reducing sugar-based sulfide scavengers and methods of use in subterranean operations Download PDFInfo
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- WO2014209639A1 WO2014209639A1 PCT/US2014/042361 US2014042361W WO2014209639A1 WO 2014209639 A1 WO2014209639 A1 WO 2014209639A1 US 2014042361 W US2014042361 W US 2014042361W WO 2014209639 A1 WO2014209639 A1 WO 2014209639A1
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- WO
- WIPO (PCT)
- Prior art keywords
- sulfide
- fluid
- treatment fluid
- ions
- fluids
- Prior art date
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Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
- C09K8/532—Sulfur
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/06—Arrangements for treating drilling fluids outside the borehole
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/20—Hydrogen sulfide elimination
Definitions
- the present disclosure relates to fluids, additives, and methods for use in subterranean operations, and more specifically, to improved methods and additives for eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids.
- Hydrocarbon producing wells may contain many different formation liquids and gases such as methane, ethane, and other higher hydrocarbons, as well as hydrogen sulfide, water, and other compounds.
- methane, ethane, and other higher hydrocarbons as well as hydrogen sulfide, water, and other compounds.
- it is often useful to obtain information by analyzing the component concentrations of the produced fluid from a formation or an individual well.
- Numerous systems have been developed to evaluate a downhole fluid composition and the relative component concentrations in the downhole fluid.
- Hydrogen sulfide is a very toxic, flammable, and pungent gas that causes numerous problems in various aspects of the oil and gas industry.
- H2S is extremely corrosive to metal, which may damage or destroy tubing, casings, or other types of well bore equipment.
- H 2 S also presents health risks to operations personnel that may be exposed to H 2 S gas at a well site or in processing of well bore fluids.
- Severe iron sulfide scaling may also choke production, either in the production piping, perforations or within the producing formation itself.
- H 2 S gas can sometimes be controlled by maintaining the pH of the fluid containing H 2 S above 10. However, in many cases, it is not practical or possible to maintain this level pH in a fluid for extended periods of time.
- Sulfide scavengers are often used to react with H 2 S and convert it to a more inert form.
- Conventional H 2 S scavengers include certain aldehydes, certain amine-based chemicals, triazines, copper compounds, hydrogen peroxide, zinc compounds, and iron compounds.
- the reaction products of many of these compounds with H 2 S are poorly soluble in treatment fluids and/or fluids in the well bore, or may decompose, thereby releasing H 2 S.
- many conventional sulfide scavengers themselves may have undesirable environmental and/or toxicity problems, and as such may be impractical to use or prohibited altogether in certain circumstances and/or jurisdictions.
- the present disclosure relates to fluids, additives, and methods for use in subterranean operations, and more specifically, to improved methods and additives for eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids.
- the present disclosure provides a method comprising: providing a treatment fluid comprising a base liquid and a sulfide scavenging additive comprising one or more reducing sugars; introducing the treatment fluid into at least a portion of a subterranean formation; and allowing at least a portion of the sulfide scavenging additive to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a precipitate comprising one or more sulfur species.
- the present disclosure provides a method comprising: providing a treatment fluid comprising a base liquid and a sulfide scavenging additive comprising one or more reducing sugars chelated with one or more metal ions; introducing the treatment fluid into at least a portion of a subterranean formation; allowing at least one of the metal ions to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a first product comprising one or more sulfur species; and allowing the reducing sugar to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a second product comprising one or more sulfur species.
- the present disclosure provides a method of treating a fluid comprising a first concentration of hydrogen sulfide or sulfide ions, the method comprising: adding a sulfide scavenging additive comprising one or more reducing sugars to the fluid; and allowing at least a portion of the sulfide scavenging additive to interact with at least a portion of the hydrogen sulfide or sulfide ions in the fluid to reduce the concentration of hydrogen sulfide or sulfide ions to a second concentration that is lower than the first concentration.
- Figure 1 illustrates an example of a well bore drilling assembly that may be used in accordance with certain embodiments of the present disclosure.
- the present disclosure relates to fluids, additives, and methods for use in subterranean operations, and more specifically, to improved methods and additives for eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids.
- the fluids and sulfide scavenging additives of the present disclosure generally comprise one or more reducing sugars.
- reducing sugar is defined herein to include any saccharide that includes an aldehyde functional group or can isomerize to form an aldehyde functional group in basic solution.
- the fluids and sulfide scavenging additives of the present disclosure may be substantially free of compounds having aldehyde functional group prior to placement in basic solution.
- the reducing sugar may be chelated with a metal ion, such as iron.
- a chelated reducing sugar When added to a fluid comprising a liquid, a chelated reducing sugar may interact with H 2 S and/or sulfide ions present in the fluid to produce one or more sulfur species (e.g. , metal sulfides (such as Fe 2 S 3 and FeS) and elemental sulfur), inter alia, in the form of a precipitate that can be removed from the liquid. In certain embodiments, this may be accomplished without further oxidization of the metal ions.
- sulfur species e.g. , metal sulfides (such as Fe 2 S 3 and FeS) and elemental sulfur
- the methods and compositions of the present disclosure may, among other things, provide a means of reducing or eliminating concentrations of hydrogen sulfide or soluble sulfide ions in fluids found and/or used in subterranean formations with significantly less risk of environmental damage and/or health and safety hazards. Such methods and compositions may be more compatible with regulatory requirements in various jurisdictions.
- the sulfide scavenging additives of the present disclosure comprising one or more reducing sugars may be effective at a wider range of pH levels ⁇ e.g., pH ranges above about 8) than other sulfide scavenging additives known in the art, and may reduce or eliminate concentrations of hydrogen sulfide or soluble sulfide ions in fluids more effectively.
- the methods and compositions of the present disclosure also may be more cost effective than other sulfide scavenging methods and additives known in the art.
- the reducing sugars used in the methods, fluids, and sulfide scavenging additives of the present disclosure may comprise any reducing sugar (or combination thereof) known in the art.
- Such reducing sugars may comprise monosaccharides, disaccharides, polysaccharides, and/or combinations thereof.
- reducing sugars examples include, but are not limited to, glucose, glucosamine, acetyl glucosamine, fructose, sucrose, lactose, maltose, cellobiose, galactose, mannose, ribose, ribulose, xylose, lyxose, rhamnose, arabinose, erythrose, and/or combinations thereof.
- the reducing sugars used in the methods, fluids, and sulfide scavenging additives of the present disclosure may have a molecular weight of from about 180 daltons to about 360 daltons.
- the reducing sugar optionally may be chelated with any metal ion known in the art, including but not limited to iron, zinc, copper, nickel, manganese, and the like.
- Chelated reducing sugars that may be suitable for use in certain embodiments of the present disclosure include, but are not limited to, ferric fructose, ferrous sucrose, and the like.
- the sulfide scavenging additives used in the present disclosure may exhibit, among other features, an enhanced ability to scavenge sulfides as compared to conventional sulfide scavengers due, at least in part, to the manner in which they react with sulfides and other components of the fluid.
- sulfide scavenging additives of the present disclosure that comprise one or more metal ions chelated with reducing sugars may exhibit a dual sulfide scavenging mechanism wherein the metal ion and the reducing sugar each interact with hydrogen sulfide or sulfide ions to produce different products that may be precipitated or otherwise removed from of the fluid.
- the interaction of the metal ions with hydrogen sulfide or sulfide ions may proceed according to one or more reactions similar those discussed in paragraph [0015] below.
- the interaction of the reducing sugar with hydrogen sulfide or sulfide ions may involve the degradation of the reducing sugar and the reaction of those degradation products with hydrogen sulfide or sulfide ions.
- the reducing sugar may interact with hydrogen sulfide or sulfide ions to form an intermediate sulfur- containing compound, the sugar moiety in which may fragment to form other sulfur containing species.
- the chelation of the reducing sugar with the metal ion also may inhibit the conversion of the metal ion to a metal hydroxide, leaving the metal ion free to interact with and/or scavenge hydrogen sulfide or sulfide ions present in the fluid.
- the reaction mechanisms disclosed herein are provided only as non-limiting illustrations of how the sulfide scavenging additives of the present disclosure may react in certain embodiments, and are not intended to limit the scope of the claims.
- the iron (III) ions in the ferric fructose may react with hydrogen sulfide to produce iron (III) sulfide (Fe 2 S 3 ).
- the iron (III) ions may be reduced by hydrogen sulfide to their iron (II) oxidation state, producing elemental sulfur (S°) (see Equation (1) below).
- the reduced iron (II) ion may react with additional hydrogen sulfides to produce iron (II) sulfide (FeS) (see Equation (2) below).
- Equation (3) the overall result for the ferric ion in this embodiment of the present disclosure may be expressed according to Equation (3) below:
- the elemental sulfur and iron (II) sulfide may form a precipitate in the fluid being treated, which may be removed from the fluid. Similar reactions may occur using metallic ions other than iron. In embodiments where divalent metallic ions are used, elemental sulfur may not be formed.
- the fructose may interact with hydrogen sulfide or sulfide ions to produce various sulfur species that may precipitate or be removed from the fluid being treated.
- the reducing sugar may be added to or included in a fluid in any concentration that effectively eliminates or reduces by the desired amount concentrations of H 2 S or sulfide ions that are present or expected to be present in the fluid.
- the reducing sugar may be added in a stoichiometric amount relative to the estimated amount of H 2 S or sulfide ions in the fluid.
- the reducing sugar may be present a fluid in a concentration of about 0.1 to 5 pounds per barrel.
- an initial amount of the sulfide scavenging additives of the present disclosure comprising one or more reducing sugars may be added to a fluid, and subsequently, additional amounts of the sulfide scavenging additives of the present disclosure may be added to the same fluid.
- This technique may be used, among other purposes, to increase and/or maintain a concentration of the reducing sugar that is sufficient to effectively eliminate or reduce by the desired amount concentrations of H 2 S or sulfide ions in the fluid throughout the course of a given operation.
- the additives of the present disclosure may be used in conjunction with any fluid, which may include, but are not limited to, treatment fluids introduced into a subterranean formation as well as fluids found in a subterranean formation ⁇ e.g., formation water, hydrocarbon fluids, etc.) and/or any combination thereof.
- the treatment fluids and formation fluids in the present disclosure generally comprise a base liquid, which may comprise any liquid known in the art, such as aqueous liquids, non-aqueous liquids, or any mixture thereof.
- the base liquid comprises an aqueous liquid, it may comprise fresh water, salt water ⁇ e.g. , water containing one or more salts dissolved therein), brine (e.g., saturated salt water), or seawater.
- the water can be from any source, provided that it does not contain compounds that adversely affect other components of the fluid.
- the base liquid comprises a non-aqueous liquid
- it may comprise any number of organic liquids.
- suitable organic liquids include, but are not limited to, mineral oils, synthetic oils, esters, and the like.
- the treatment fluids and/or formation fluids in the present disclosure may comprise emulsions (including invert emulsions), suspensions, gels, foams, or other mixtures of liquids with solids and/or gases.
- the fluids used in the present disclosure optionally may comprise any number of additional additives, including, but not limited to, salts, surfactants, acids, fluid loss control additives, gas, nitrogen, carbon dioxide, surface modifying agents, tackifying agents, foamers, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, friction reducers, antifoam agents, bridging agents, dispersants, flocculants, additional H 2 S scavengers, C0 2 scavengers, oxygen scavengers, lubricants, viscosifiers, breakers, weighting agents, relative permeability modifiers, resins, particulate materials (e.g., proppant particulates), wetting agents, coating enhancement agents, and the like.
- additional additives including, but not limited to, salts, surfactants, acids, fluid loss control additives, gas, nitrogen, carbon dioxide, surface modifying agents, tackifying agents, foamers, corrosion inhibitors, scale inhibitors, catalysts, clay control agents
- the methods, fluids, and/or additives of the present disclosure may be used during or in conjunction with any subterranean operation wherein a fluid is used or treated.
- the methods, fluids, and/or additives of the present disclosure may be used in the course of drilling operations.
- the methods, fluids, and/or additives of the present disclosure may be used to reduce or eliminate concentrations of 3 ⁇ 4S from a drilling fluid used in drilling a well or borehole, for example, in a hydrocarbon-bearing subterranean formation where 3 ⁇ 4S is often encountered.
- Suitable subterranean operations may include, but are not limited to, preflush treatments, afterflush treatments, hydraulic fracturing treatments, sand control treatments (e.g., gravel packing), acidizing treatments (e.g., matrix acidizing or fracture acidizing), "frac-pack" treatments, well bore clean-out treatments, and other operations where a treatment fluid may be useful.
- treatment fluids may include, but are not limited to, drilling fluids, preflush fluids, afterflush fluids, fracturing fluids, acidizing fluids, gravel packing fluids, packer fluids, spacer fluids, and the like.
- the reducing sugar may be provided in an additive in a solid form, liquid form (e.g. , in solution of water or another solvent), or a combination thereof.
- the sulfide scavenging additives of the present disclosure may be added to a fluid by any means known in the art.
- the additive may be added to the fluid, for example, in the mud pit before the fluid has circulated or before the fluid contains any detectable amount of sulphur or H 2 S, as a prophylactic measure against any H 2 S the fluid may encounter downhole.
- the additive may be added after the fluid has been circulating downhole and has already encountered sulphur or 3 ⁇ 4S and contains same.
- the amount of the additive added to the fluid may be controlled and/or varied during the course of an operation based on, among other things, the amount of sulfur or 3 ⁇ 4S detected in fluids exiting the well bore.
- any system or technique capable of monitoring or detecting sulfur or H 2 S content in fluids exiting the well bore may be used.
- the sulfide scavenging additives of the present disclosure may be added to a fluid in multiple portions that are added to the fluid at separate intervals over a period of time. For example, a first amount of a scavenging additive of the present disclosure may be added to a fluid at one point in time in the course of a particular operation.
- an elevated amount of sulfur or 3 ⁇ 4S may be detected exiting the well bore, at which point a second amount of a scavenging additive of the present disclosure may be added to the fluid based at least in part on the amount of sulfur or H 2 S detected.
- the exemplary fluids and additives disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed fluids and additives.
- the disclosed fluids and additives may directly or indirectly affect one or more components or pieces of equipment associated with an exemplary wellbore drilling assembly 100, according to one or more embodiments.
- FIG. 1 generally depicts a land-based drilling assembly, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.
- the drilling assembly 100 may include a drilling platform 102 that supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108.
- the drill string 108 may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art.
- a kelly 1 10 supports the drill string 108 as it is lowered through a rotary table 1 12.
- a drill bit 1 14 is attached to the distal end of the drill string 108 and is driven either by a downhole motor and/or via rotation of the drill string 108 from the well surface. As the bit 1 14 rotates, it creates a borehole 1 16 that penetrates various subterranean formations 1 18.
- a pump 120 (e.g. , a mud pump) circulates drilling fluid 122 through a feed pipe 124 and to the kelly 1 10, which conveys the drilling fluid 122 downhole through the interior of the drill string 108 and through one or more orifices in the drill bit 1 14.
- the drilling fluid 122 is then circulated back to the surface via an annulus 126 defined between the drill string 108 and the walls of the borehole 1 16.
- the recirculated or spent drilling fluid 122 exits the annulus 126 and may be conveyed to one or more fluid processing unit(s) 128 via an interconnecting flow line 130.
- a "cleaned" drilling fluid 122 is deposited into a nearby retention pit 132 (i. e. , a mud pit). While illustrated as being arranged at the outlet of the wellbore 1 16 via the annulus 126, those skilled in the art will readily appreciate that the fluid processing unit(s) 128 may be arranged at any other location in the drilling assembly 100 to facilitate its proper function, without departing from the scope of the scope of the disclosure.
- One or more of the disclosed additives may be added to the drilling fluid
- the mixing hopper 134 may include, but is not limited to, mixers and related mixing equipment known to those skilled in the art. In other embodiments, however, the disclosed additives may be added to the drilling fluid 122 at any other location in the drilling assembly 100. In at least one embodiment, for example, there could be more than one retention pit 132, such as multiple retention pits 132 in series. Moreover, the retention pit 132 may be representative of one or more fluid storage facilities and/or units where the disclosed additives may be stored, reconditioned, and/or regulated until added to the drilling fluid 122.
- the disclosed fluids and additives may directly or indirectly affect the components and equipment of the drilling assembly 100.
- the disclosed fluids and additives may directly or indirectly affect the fluid processing unit(s) 128 which may include, but is not limited to, one or more of a shaker (e.g. , shale shaker), a centrifuge, a hydrocyclone, a separator (including magnetic and electrical separators), a desilter, a desander, a separator, a filter (e.g.
- the fluid processing unit(s) 128 may further include one or more sensors, gauges, pumps, compressors, and the like used store, monitor, regulate, and/or recondition the exemplary fluids and additives.
- the disclosed fluids and additives may directly or indirectly affect the pump 120, which representatively includes any conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically convey the fluids and additives downhole, any pumps, compressors, or motors (e.g. , topside or downhole) used to drive the fluids and additives into motion, any valves or related joints used to regulate the pressure or flow rate of the fluids and additives, and any sensors (i. e. , pressure, temperature, flow rate, etc.), gauges, and/or combinations thereof, and the like.
- the disclosed fluids and additives may also directly or indirectly affect the mixing hopper 134 and the retention pit 132 and their assorted variations.
- the disclosed fluids and additives may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the fluids and additives such as, but not limited to, the drill string 108, any floats, drill collars, mud motors, downhole motors and/or pumps associated with the drill string 108, and any MWD/LWD tools and related telemetry equipment, sensors or distributed sensors associated with the drill string 108.
- the disclosed fluids and additives may also directly or indirectly affect any downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers and other wellbore isolation devices or components, and the like associated with the wellbore 116.
- the disclosed fluids and additives may also directly or indirectly affect the drill bit 114, which may include, but is not limited to, roller cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, etc.
- the disclosed fluids and additives may also directly or indirectly affect any transport or delivery equipment used to convey the fluids and additives to the drilling assembly 100 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the fluids and additives from one location to another, any pumps, compressors, or motors used to drive the fluids and additives into motion, any valves or related joints used to regulate the pressure or flow rate of the fluids and additives, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.
- any transport or delivery equipment used to convey the fluids and additives to the drilling assembly 100
- any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the fluids and additives from one location to another
- any pumps, compressors, or motors used to drive the fluids and additives into motion
- any valves or related joints used to regulate the pressure or flow rate of the fluids and additives
- sensors i.
Abstract
Description
Claims
Priority Applications (5)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GB1519521.7A GB2527722A (en) | 2013-06-26 | 2014-06-13 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations |
MX2015015271A MX2015015271A (en) | 2013-06-26 | 2014-06-13 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations. |
CA2912393A CA2912393C (en) | 2013-06-26 | 2014-06-13 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations |
AU2014303002A AU2014303002B2 (en) | 2013-06-26 | 2014-06-13 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations |
NO20151489A NO20151489A1 (en) | 2013-06-26 | 2015-11-04 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/927,714 US20150000984A1 (en) | 2013-06-26 | 2013-06-26 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations |
US13/927,714 | 2013-06-26 |
Publications (1)
Publication Number | Publication Date |
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WO2014209639A1 true WO2014209639A1 (en) | 2014-12-31 |
Family
ID=52114505
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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PCT/US2014/042361 WO2014209639A1 (en) | 2013-06-26 | 2014-06-13 | Reducing sugar-based sulfide scavengers and methods of use in subterranean operations |
Country Status (8)
Country | Link |
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US (1) | US20150000984A1 (en) |
AR (1) | AR096730A1 (en) |
AU (1) | AU2014303002B2 (en) |
CA (1) | CA2912393C (en) |
GB (1) | GB2527722A (en) |
MX (1) | MX2015015271A (en) |
NO (1) | NO20151489A1 (en) |
WO (1) | WO2014209639A1 (en) |
Families Citing this family (5)
Publication number | Priority date | Publication date | Assignee | Title |
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US9557312B2 (en) | 2014-02-11 | 2017-01-31 | Schlumberger Technology Corporation | Determining properties of OBM filtrates |
US10731460B2 (en) * | 2014-04-28 | 2020-08-04 | Schlumberger Technology Corporation | Determining formation fluid variation with pressure |
US10544344B2 (en) * | 2016-09-09 | 2020-01-28 | Saudi Arabian Oil Company | Methods and systems for neutralizing hydrogen sulfide during drilling |
US11634622B2 (en) | 2017-03-15 | 2023-04-25 | Rhodia Poliamida E Especialidades S.A. | Compositions and methods for scavenging H2S |
CA3210867A1 (en) * | 2021-02-08 | 2022-08-11 | Uniquem Inc. | Environmentally friendly additives |
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US20040167037A1 (en) * | 1999-07-29 | 2004-08-26 | Eric Davidson | Method and composition for scavenging sulphide in drilling fluids |
US20100108315A1 (en) * | 2008-11-03 | 2010-05-06 | Stevens David K | Method for reducing the H2S content of an H2S-containing subterranean formation |
US20120067783A1 (en) * | 2010-09-21 | 2012-03-22 | Gregory Kaplan | Hydrogen sulfide scavenger compositions, methods for making and processes for removing hydrogen sulfide from liquid hydrocarbon media |
US20120132443A1 (en) * | 2009-06-19 | 2012-05-31 | Jiri Peter Thomas Van Straelen | Process for the removal of carbon dioxide and/or hydrogen sulphide from a gas |
US20120220500A1 (en) * | 2011-02-24 | 2012-08-30 | United Laboratories International, Llc | Process for Removal of Hydrogen Sulfide in Downhole Oilfield Applications |
US20130056203A1 (en) * | 2011-09-07 | 2013-03-07 | E.I. Du Pont De Nemours And Company | Reducing sulfide in oil reservoir production fluids |
Family Cites Families (3)
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CA1047243A (en) * | 1973-06-28 | 1979-01-30 | Irwin Fox | Porous fe304 drilling mud additive |
US4548720A (en) * | 1983-04-21 | 1985-10-22 | Diamond Shamrock Chemicals Company | Removal of hydrogen sulfide from drilling fluids |
US7748456B2 (en) * | 2006-08-11 | 2010-07-06 | Halliburton Energy Services, Inc. | Dual functional components and associated methods |
-
2013
- 2013-06-26 US US13/927,714 patent/US20150000984A1/en not_active Abandoned
-
2014
- 2014-06-13 CA CA2912393A patent/CA2912393C/en not_active Expired - Fee Related
- 2014-06-13 WO PCT/US2014/042361 patent/WO2014209639A1/en active Application Filing
- 2014-06-13 AU AU2014303002A patent/AU2014303002B2/en not_active Ceased
- 2014-06-13 MX MX2015015271A patent/MX2015015271A/en unknown
- 2014-06-13 GB GB1519521.7A patent/GB2527722A/en not_active Withdrawn
- 2014-06-25 AR ARP140102400A patent/AR096730A1/en not_active Application Discontinuation
-
2015
- 2015-11-04 NO NO20151489A patent/NO20151489A1/en not_active Application Discontinuation
Patent Citations (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20040167037A1 (en) * | 1999-07-29 | 2004-08-26 | Eric Davidson | Method and composition for scavenging sulphide in drilling fluids |
US20100108315A1 (en) * | 2008-11-03 | 2010-05-06 | Stevens David K | Method for reducing the H2S content of an H2S-containing subterranean formation |
US20120132443A1 (en) * | 2009-06-19 | 2012-05-31 | Jiri Peter Thomas Van Straelen | Process for the removal of carbon dioxide and/or hydrogen sulphide from a gas |
US20120067783A1 (en) * | 2010-09-21 | 2012-03-22 | Gregory Kaplan | Hydrogen sulfide scavenger compositions, methods for making and processes for removing hydrogen sulfide from liquid hydrocarbon media |
US20120220500A1 (en) * | 2011-02-24 | 2012-08-30 | United Laboratories International, Llc | Process for Removal of Hydrogen Sulfide in Downhole Oilfield Applications |
US20130056203A1 (en) * | 2011-09-07 | 2013-03-07 | E.I. Du Pont De Nemours And Company | Reducing sulfide in oil reservoir production fluids |
Also Published As
Publication number | Publication date |
---|---|
AU2014303002B2 (en) | 2017-03-30 |
GB201519521D0 (en) | 2015-12-23 |
US20150000984A1 (en) | 2015-01-01 |
CA2912393C (en) | 2018-03-27 |
MX2015015271A (en) | 2016-06-02 |
NO20151489A1 (en) | 2015-11-04 |
CA2912393A1 (en) | 2014-12-31 |
AR096730A1 (en) | 2016-01-27 |
GB2527722A (en) | 2015-12-30 |
AU2014303002A1 (en) | 2015-11-12 |
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