WO2010111226A2 - Composition et méthode pour empêcher l'agglomération d'hydrates dans des pipelines - Google Patents

Composition et méthode pour empêcher l'agglomération d'hydrates dans des pipelines Download PDF

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WO2010111226A2
WO2010111226A2 PCT/US2010/028241 US2010028241W WO2010111226A2 WO 2010111226 A2 WO2010111226 A2 WO 2010111226A2 US 2010028241 W US2010028241 W US 2010028241W WO 2010111226 A2 WO2010111226 A2 WO 2010111226A2
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agglomeration
surfactant
meoh
hydrates
water
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WO2010111226A3 (fr
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Abbas Firoozabadi
Dalton York
Li Xiaokai
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Yale University Office Of Cooperative Research
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    • 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
    • E21B37/00—Methods or apparatus for cleaning boreholes or wells
    • E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting, e.g. eliminating, the deposition of paraffins or like substances
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/10—Liquid carbonaceous fuels containing additives
    • C10L1/14—Organic compounds
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/003—Additives for gaseous fuels
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17D—PIPE-LINE SYSTEMS; PIPE-LINES
    • F17D1/00—Pipe-line systems
    • F17D1/02—Pipe-line systems for gases or vapours
    • F17D1/04—Pipe-line systems for gases or vapours for distribution of gas
    • F17D1/05—Preventing freezing
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17D—PIPE-LINE SYSTEMS; PIPE-LINES
    • F17D3/00—Arrangements for supervising or controlling working operations
    • F17D3/14—Arrangements for supervising or controlling working operations for eliminating water
    • F17D3/145—Arrangements for supervising or controlling working operations for eliminating water in gas pipelines
    • 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
    • C09K2208/22—Hydrates inhibition by using well treatment fluids containing inhibitors of hydrate formers
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/10—Liquid carbonaceous fuels containing additives
    • C10L1/14—Organic compounds
    • C10L1/18—Organic compounds containing oxygen
    • C10L1/1817—Compounds of uncertain formula; reaction products where mixtures of compounds are obtained
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/10—Liquid carbonaceous fuels containing additives
    • C10L1/14—Organic compounds
    • C10L1/18—Organic compounds containing oxygen
    • C10L1/182—Organic compounds containing oxygen containing hydroxy groups; Salts thereof
    • C10L1/1822—Organic compounds containing oxygen containing hydroxy groups; Salts thereof hydroxy group directly attached to (cyclo)aliphatic carbon atoms
    • C10L1/1824—Organic compounds containing oxygen containing hydroxy groups; Salts thereof hydroxy group directly attached to (cyclo)aliphatic carbon atoms mono-hydroxy
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/10—Liquid carbonaceous fuels containing additives
    • C10L1/14—Organic compounds
    • C10L1/18—Organic compounds containing oxygen
    • C10L1/185—Ethers; Acetals; Ketals; Aldehydes; Ketones
    • C10L1/1852—Ethers; Acetals; Ketals; Orthoesters
    • C10L1/1855—Cyclic ethers, e.g. epoxides, lactides, lactones
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/10—Liquid carbonaceous fuels containing additives
    • C10L1/14—Organic compounds
    • C10L1/18—Organic compounds containing oxygen
    • C10L1/192—Macromolecular compounds
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/10—Liquid carbonaceous fuels containing additives
    • C10L1/14—Organic compounds
    • C10L1/22—Organic compounds containing nitrogen
    • C10L1/222—Organic compounds containing nitrogen containing at least one carbon-to-nitrogen single bond
    • C10L1/2222—(cyclo)aliphatic amines; polyamines (no macromolecular substituent 30C); quaternair ammonium compounds; carbamates

Definitions

  • This application is related to compositions and methods for preventing hydrate masses from impeding the flow of fluids particularly in gas and oil pipelines.
  • Natural gas has a high hydrogen to carbon ratio compared to petroleum fluids and coal. Due to availability, as well as economical and environmental considerations, natural gas is projected to be the premium fuel of the 21st century. It is also a clean burning fuel, which results in low production of CO 2 . A large portion of natural gas is produced from the deep sea where the temperatures are low.
  • gas hydrates crystalline inclusion compounds
  • Water co-produced with natural gas, forms lattice structures by hydrogen bonding, the structures stabilized by guest molecules such as methane, propane, etc., under high pressures, and low temperatures in the range of a few degrees to 25 0 C.
  • Formation of gas hydrates occurs rapidly, unlike corrosion, scale, or wax buildup. This rapidity has undesirable safety and environmental consequences. Plug formation from hydrate may lead to production shutdowns, necessitating costly downtime to remove the plug. Hydrate formation in pipelines is a problem in gas and oil production from offshore fields.
  • thermodynamic inhibitors such as alcohols which affect bulk phase properties and inhibit hydrate formation.
  • Thermodynamic inhibitors such as methanol are effective but sometimes a large quantity of methanol is needed, at ratios as high as 1 to 1 volume of alcohol to water, often these are significant amounts which have undesirable environmental and safety impacts.
  • ком ⁇ онентs have been used, generally in ratio of 0.005-0.02 volume of surfactant to water, for either inhibiting hydrate formation or reducing the rate of accumulation.
  • the limitation with kinetic inhibitors is the ability to work under low subcooling conditions. In some deep sea environments, the subcooling can be as high as 20-25 0 C, because the sea bed temperature is about 4 0 C. Kinetic inhibitors are not effective at such subcooling temperatures.
  • compositions containing a surfactant such as a Rhamnolipid biosurfactant or a quaternary ammonium surfactant compound, combined with an alcohol co-surfactant provide anti-agglomeration with both tetrahydrofuran (THF) hydrates and cyclopentane hydrates, which are close in properties to the gas hydrates which occur in the fluid pipelines, and consequently, that such a composition would be effective as an anti-agglomeration agent in oil and gas pipelines, even at high subcooled temperatures and at relatively high water cuts.
  • a surfactant such as a Rhamnolipid biosurfactant or a quaternary ammonium surfactant compound
  • Bio-surfactants can be very effective at low concentration, and the present inventors have found that the presence of an alcohol co-surfactant such as methanol at low concentration serves to enhance the anti-agglomeration effect.
  • THF hydrates were first used to determine the anti-agglomeration effects with a combined bio-surfactant and methanol, as THF forms structure II hydrates and is much more soluble in water than any species in natural gas.
  • THF hydrates may be different from methane hydrates, as THF hydrates may form in the bulk phase whereas methane and propane hydrates may from on an interface between water and oil phases.
  • Formation of THF hydrates unlike methane hydrates occurs at atmospheric pressure, which while an advantage in conducting experiments, left open the question of whether the composition would actually be effective in the field.
  • the inventors conducted tests with cyclopentane hydrate formation, as these have a low solubility in water, and are in some respects close to hydrates from natural gas species. Cyclopentane was also used as the oil phase to form a water-in-oil emulsion, to confirm the anti-agglomeration effectiveness of the inventive composition containing a low concentration of a surfactant and an alcohol cosurfactant.
  • compositions comprising a surfactant and an alcohol co-surfactant provided in effective amounts to cause anti-agglomeration of hydrates at high subcooling temperatures and/or at high water-cuts.
  • the surfactant is a Rhamnolipid biosurfactant and preferably, the alcohol cosurfactant is methanol, the alcohol cosurfactant being present at concentrations low enough such that side effects such as salt deposition are avoided.
  • the alcohol cosurfactant should be present at from about 0.5-5% wt., with the surfactant present at from about 0.001 to 10% wt., more preferably 0.01-5% wt.
  • agglomeration of hydrates in gas and oil pipelines can be reduced using low levels of the inventive composition, also being effective at relatively high water cuts, and at relatively high subcooling temperatures.
  • Figure 1 Multiple screening-tube rocking apparatus.
  • FIG. 2 Typical freeze-thaw cycle data for THF mixture of two parts isooctane and no MeOH; example for mixture of 1.5 wt. % rhamnolipid.
  • FIG. 3 Typical freeze-thaw cycle data for THF mixtures with two parts isooctane and 5 or 2 wt. % MeOH; example for mixture with 0.5% rhamnolipid and 5% MeOH.
  • FIG. 4 Typical freeze-thaw cycle data for THF mixtures with two parts isooctane and 0.5 wt. % MeOH; example for mixture with 0.05% quat.
  • FIG. 5 Agglomeration state results for THF mixtures with four parts isooctane and small amounts of rhamnolipid. In all cases, significant adhesion of hydrate upon vial walls occurs immediately at all minimum temperatures (represented by • symbol). Data represents behavior of a given composition across ail minimum temperatures.
  • Figure 6 Significant adhesion observed in THF mixtures of four parts isooctane, very low concentrations of rhamnolipid, and 5 wt. % MeOH or less, data shown in Figure 5.
  • Sample shown in image contains 0.01 wt. % rhamnolipid and 5 wt. % MeOH.
  • FIG 7 Typical plug appearance when small amounts, i.e., zero to two parts by weight, of isooctane are used in THF mixture.
  • vial is upside down with most of vial volume blocked by hydrate; mixture being tested in this image is one containing two parts isooctane.
  • Calculations using measured THF hydrate density 55 show the volume fraction of hydrate in mixtures of two parts isooctane is roughly 0.25.
  • the sample shown in this image is for a mixture of two parts isooctane and 1.5 wt. % quat. Small bubbles seen in this image, as well as in Figure 15, are present in the bath fluid due to bath operation.
  • Figure 8 - Agglomeration state results for THF mixtures with two parts isooctane and rhamnolipid with and without MeOH: ( ⁇ ) stable dispersion — i.e., effective anti- agglomeration, ( • ) immediate and significant adhesion upon vial walls, (x) plugging tendency. Plugging tendency means that either total plugs occurred, i.e., steel ball is unable to move, or partial plugs occurred, i.e., steel ball is unable to move through the entire length of vial. Data represents behavior of a given composition across all minimum temperatures.
  • FIG. 9 Image of hydrate slurry in THF mixtures with two parts isooctane. This image was taken with vial almost horizontal in agitator rack and thus prior to complete slurry settling; due to high hydrate volume present in vial, it was not possible to capture a clear image of the slurry separate from the oil phase.
  • This mixture shown here is for 0.5 wt. % rhamnolipid and 2 wt. % MeOH co-surfactant.
  • Figure 10 - Agglomeration state results for THF mixtures with two parts isooctane and ARQUAD 2C-75 with and without MeOH: ( ⁇ ) stable dispersion — i.e., effective anti- agglomeration, ( • ) plugging tendency.
  • Plugging tendency means that either total plugs occurred, i.e., steel ball is unable to move, or partial plugs occurred, i.e., steel ball is unable to move through the entire length of vial.
  • Data represents behavior of a given composition across all minimum temperatures.
  • FIG 11 Average of freeze-thaw cycle data for THF mixtures including two parts isooctane with or without rhamnolipid. Given are Tc (shown as a solid triangle), t c ,
  • Figure 12 Average of freeze-thaw cycle data for THF mixtures including two parts isooctane, rhamnolipid, and low MeOH concentrations. Given are Tc (shown as a solid triangle), t c , (shown as columns), and Td (shown as ⁇ ). Error bars are present for all points; some Td and T]. ⁇ rror bars overlap and may not be clear.
  • Figure 13 Average of freeze-thaw cycle data for THF mixtures including two parts isooctane with or without ARQUAD 2C-75. Given are Tc (shown as a solid triangle), t c , (shown as columns), and Ta (shown as ⁇ ). Error bars are present for all points; some may not be clear due to magnitude.
  • FIG 14 Average of freeze-thaw cycle data for THF mixtures including two parts isooctane, ARQUAD 2C-75, and low MeOH concentrations. Given are Tc (shown as a solid triangle), t c , (shown as columns), and Ta (shown as ⁇ ). Error bars are present for all points; some Ta and Tc error bars overlap and may not be clear.
  • Figure 15 Partial plug that appears more as a concentrated hydrate slurry in a THF mixture of zero parts isooctane, 1.5 wt. % rhamnolipid, and 10 wt. % MeOH. Steel ball is barely visible, but the air bubble shows the vial is not filled with a solid hydrate plug as would be expected.
  • the vial in this image is tilted at a roughly 45° angle away from the borescope, as evidenced by bubble position.
  • FIG. 21 Agglomeration states for mixtures of CP/H 2 O/THF/Rh of composition 4/1 /x/y (weight ratio to water), where THF amount x and Rh amount y are control variables: (+) stable dispersion; (O) dispersible hydrate, hydrates that looks like plug but can be dispersed by heavy shaking, (x) plugging tendency. Plugging tendency means that either total plugs occurred, i.e., steel ball is unable to move, or partial plugs occurred, i.e., steel ball is unable to move through the entire length of vial .
  • FIG. 23 Agglomeration states for mixtures of CP/H 2 O/THF/Rh/MeOH of composition 2/1 /x/y /z, (weight ratio to water) where THF amount x, Rh amount y, and MeOH amount z are control variables: (+) stable dispersion; (O) dispersible hydrate, hydrates that looks like plug but can be dispersed by heavy shaking, (x) plugging tendency. Plugging tendency means that either total plugs occurred, i.e., steel ball is unable to move, or partial plugs occurred, i.e., steel ball is unable to move through the entire length of vial.
  • FIG. 25 Stable dispersion observed for mixtures of CP/H 2 O/THF/Rh of composition 2/1/0.02/x (weight ratio to water), where Rh x is 0.003-O.Olfor the data shown in Figures 23 and 24.
  • Sample shown in image contains 0.005 wt. Rh and 0 wt. MeOH. Vial is tilted roughly 60° from horizontal with the bottom side up.
  • FIG. 26 Agglomeration states for mixtures of CP/H 2 O/THF/Rh/MeOH of composition 1.5/l/0.02/x/y(weight ratio to water): stable dispersion, where Rh amount x and MeOH amount y are control variables : (+) stable dispersion; ( ⁇ ) hydrates attached to bottom or wall of the vial.
  • ( x ) plugging tendency means that either total plugs occurred, i.e., steel ball is unable to move, or partial plugs occurred, i.e., steel ball is unable to move through the entire length of vial.
  • FIG. 27 Significant hydrates being adhered to the side walls and bottom observed in mixtures of CP/H 2 O/THF/Rh/MeOH of composition 1.5/1/0.02/0.003/0.005 (weight ratio to water); data shown in Figure 26 and 20. Vial is tilted roughly 60° from horizontal with the bottom side up.
  • thermodynamic inhibitors such as alcohols often in significant amounts which have undesirable environmental and safety impacts.
  • Thermodynamic inhibitors affect bulk phase properties and inhibit hydrate formation.
  • An alternative is changing surface properties through usage of polymers and surfactants, generally effective at 0.5 to 3 weight % of co-produced water.
  • LDHI low dosage hydrate inhibitors
  • a second group of LDHI are anti-agglomerants (AA), which prevent agglomeration of small hydrate crystallites.
  • AA anti-agglomerants
  • AA facilitate hydrate crystallite slurries that can be transported as a typical fluid can be, without fear of foiiiii ⁇ g hydiate blockages.
  • work on hydrate anti-agglomeration has been very limited.
  • This invention centers on the effect of combining small amounts of alcohol co- surfactant in hydrate-forming mixtures with different anti-agglomerants.
  • THF tetrahydrofuran
  • the alcohol co-surfactant employed was methanol, though other alcohols could also be used.
  • Results show that combining with alcohol co-surfactants may provide anti- agglomeration when traditional anti-agglomerants alone are ineffective.
  • traditional AA alone may be ineffective is when the water-cut (i.e., ratio of water volume to that of oil) is too high.
  • water-cut i.e., ratio of water volume to that of oil
  • AA's are thought to be ineffective if water-cut is 50 % or greater, but smaller water-cuts may also be detrimental to anti- agglomeration.
  • traditional AA's up to 1.5 weight % are ineffective when water cut in these model mixtures increases from roughly 17 % to 34 %. That is, traditional AA alone in our model mixtures are effective when water-cut is 17 % but become ineffective at a 34 % water-cut.
  • alcohol co- surfactant may be an effective aid in anti-agglomeration when water-cuts are increased in this manner.
  • co-surfactant As low as 0.5 weight % methanol co-surfactant is shown to be effective in anti-agglomeration when water-cut is increased from 17 % to 34 %. Without the co- surfactant there will be agglomeration independent of the AA concentration, up to 1.5 weight % AA. Other alcohols will likely provide similar benefit, with the benefit believed to be effective with water-cut increases up to roughly 69%.
  • the inventive method thus uses small amounts of alcohol co-surfactant in combination with AA's administered to hydrate-forming mixtures where the traditional AA alone is ineffective at facilitating hydrate slurries.
  • composition and method will be used when oil or natural gas is being produced iogeiher wixh co-produced waier from subsurface weiib, followed by transport of the fluid mixtures in pipelines to downstream processing equipment. Specifically, it can be used under conditions when water-cut increases to a certain point where traditional AA alone are ineffective at facilitating hydrate slurries or those conditions where high subcooling is likely to occur.
  • Alcohol co-surfactants may enable anti-agglomeration when traditional AA alone are ineffective, such as when water-cut becomes too large.
  • thermodynamic inhibitors such as methanol
  • traditional thermodynamic inhibitors such as methanol
  • thermodynamic inhibitors such as methanol
  • traditional thermodynamic inhibitors such as methanol
  • thermodynamic inhibitors are required in such large amounts that their presence encourages the precipitation of dissolved salts in the water phase. This can lead to increased problems with flow and cause corrosion in production equipment.
  • small amounts of alcohol co-surfactants can be used with an AA in a mixed compositions, then the problem of salt deposition can be eliminated as well as the need for large amounts of thermodynamic inhibitors.
  • Inhibition by AA is very attractive because small concentrations are effective even at very large hydrate subcoolings, which occur more as wells are being developed further offshore.
  • the addition of alcohol co-surfactant is another way to ensure that AA may still be used for process flow assurance in situations where large amounts of thermodynamic inhibitors may be the only other hydrate inhibition option.
  • a quaternary ammonium chloride salt i.e., a quat
  • a quaternary ammonium chloride salt i.e., a quat
  • biochemical surfactants are less toxic and biodegradable and thus their use may prove beneficial even if at concentrations higher than chemical surfactants.
  • Thermodynamic inhibitors shift equilibrium conditions to lower temperature and higher pressure. 2 Although well-characterized, these inhibitors often require large concentrations, as high as 60 to 100 wt. % of co-produced water, which increase costs and have serious environmental impacts. 3
  • thermodynamic inhibitors An alternative to thermodynamic inhibitors is the use of low-dosage hydrate inhibitors (LDHI).
  • LDHI low-dosage hydrate inhibitors
  • KHI Kinetic hydrate inhibitors
  • 4 ' 5 KHI may result in complete inhibition of hydrates 6 but do not perform well at pipeline/well shut-in conditions or at high operating subcoolings, i.e., NT op , the difference between equilibrium temperature and operating temperature at a given pressure.
  • Shut-in conditions that is when pipeline flow is paused for a period of time, may occur when pipeline/well maintenance is necessary or when inclement weather occurs.
  • a second class of LDHI are anti-agglomerants (AA) which prevent agglomeration but not formation of hydrate crystals and enable hydrate transportation as slurries.
  • AA are generally effective at high t ⁇ l op or at shut-in conditions. 7"9 AA may also possess kinetic inhibition features. 10"12 They are generally surfactants but may be low molecular weight oligomeric species. 9 ' 13 AA have not been studied as extensively as KHI. Insight into hydrate anti-agglomeration and mechanism are found in surfactant and colloidal science. 14"
  • AA structure is key to their effectiveness and mechanism.
  • 17 Effective AA contain the head group that can interact with a water lattice, such as amine or carbonyl groups, through hydrogen bonding or electrostatic attraction.
  • AA compounds may also contain head groups that act as hydrate guest molecules. This feature combined with hydrogen bonding may incorporate the AA into crystals. Molecules in this case may adsorb too strongly and become engulfed in the growing crystal, requiring higher concentrations. The hydrophobic tail renders hydrate more oil-wet, thus dispersible in the oil phase, and prevents separate crystals from agglomerating.
  • 18 AA often produce water-in-oil (w/o) emulsions — thus limiting hydrate growth to water droplets dispersed in oil phase. 9 ' 17 ' 19'24 However, emulsion stability is generally undesired in gas and oil production. 25 ' 26
  • phase separation be attainable so that product quality standards can be met. If these emulsions are too stable, then additional processing or additives may be required once hydrate formation is of no concern.
  • AA may become ineffective if water occupies one third or more of the total liquid volume of the process stream, i.e., limited to 50 % water-cut. This requirement may be related to w/o emulsion formation, but other reasons such as high slurry viscosity with high hydrate volume fraction is also cited in the literature. 17 ' 19 ' 27 In most gas production flow-lines, the amount of hydrocarbon liquid is more than the amount of co-produced water and, therefore, the generation of w/o emulsions may not be an issue. However, in some cases, water production may be high and therefore the study of varying fluid composition on anti-agglomerant performance becomes necessary.
  • Alcohol co-surfactants are discussed in the literature. It is known that co-surfactants aid in micro-emulsion formation, by interacting with primary surfactant in the interfacial region and reducing oil/water interfacial tension. 30 There is also evidence of co-surfactant effects such as modifications in primary surfactant packing and head area, reduction in interfacial layer thickness, and variation in continuous-phase viscosity. 31 ' 32 The effect of different alcohols has been studied and it is found that medium-chain alkanols may be the most efficient co-surfactants, yet the smaller chain species such as MeOH are also effective. 30 ' 33
  • Rhamnolipids glycosides of rhamnose (6-deoxymannose) and B-hydroxydecanoic acid. Rhamnolipids are known to reduce surface and interfacial tension 41 and have been used to create stable micro-emulsions. 42 Typical commercial products consist of both the mono-rhamnolipid and di-rhamnolipid forms and are generally more expensive than the chemical counterparts.
  • THF is used as the guest molecule, since it forms structure II hydrates at atmospheric pressure, the same type that forms in most pipelines. 43 There are differences between THF and real systems, but THF is still considered to be an adequate model system. THF may partition significantly between the aqueous and organic phases. 21 Another major difference is THF is much more soluble in water than any species found in a typical natural gas mixture. THF and some gases, e.g., CO 2 , may initiate hydrate in the bulk water phase. 44 ' 46 However, some authors present data and show methane, methane-ethane, and methane-propane hydrates form at the water/oil interface. 46 ' 47 Since surfactants will reside at or near the interface in any system, AA shown effective for THF systems may also be effective for systems where hydrate formation and growth occur at the interface. 21
  • Figure 1 It consists of a motor-driven agitator, with a rack holding up to 20 separate borosilicate glass scintillation vials with dimensions of 17 (diameter) by 60 (height) mm, submerged in a temperature bath. Each vial holds roughly 7.4 mL of a test mixture and an approximately 8 mm diameter stainless steel 316 ball to aid agitation as well as for visual observations. A Teflon-lined plastic screw-cap is used along with Teflon tape around the threads to seal the vials. The rack rotates the vials 150° to either side of the vertical direction, completing a cycle every 5 seconds.
  • the temperature bath used is a Huber CC2- 515 vpc filled with 10 cSt at 24 0 C with silicon oil from Clearco Products Co., Inc., Bensalem, PA.
  • Thermocouples with an accuracy of ⁇ 0.2 0 C from 70 0 C down to -20 0 C, is attached to the outside of the vials when crystallization and melting data are desired.
  • thermocouples An Agilent 34970A data acquisition unh, recording temperature every 20 seconds, and an ice bath as fixed junction reference temperature is used with all thermocouples.
  • Agglomeration state images are obtained with a - 169 mm rigid borescope, a Hawkeye Pro Hardy from Gradient Lens Corp., Rochester, NY, and a Nikon Coolpix 5400 digital camera with samples still in bath fluid.
  • deionized water obtained from a Barnstead Nanopure Infinity system with quality of roughly 5.5 x 10 2 ⁇ s/cm, and 99.5%+ purity THF (from Acros) are used.
  • the oil phase consists of 99% purity 2,2,4-trimethylpentane (i.e., isooc:ane, from Acros).
  • rhamnolipid product JBR 4205 was obtained from Jeneil Biosurfactant Co., Madison, WI.
  • ARQUAD 2C-75 dicetyl dimethyl ammonium chloride, was obtained from Akzo-Nobel. It consists of 75 wt.% surfactant in solvent consisting of water (at 5-10 wt. %) and isopropanol (at 15-20 wt.%). Both were used as supplied. All the above chemicals used are the same as discussed in our previous work. 38 As co- surfactant, 99.8 % anhydrous MeOH with less than 0.05 ppm water was obtained from Acros.
  • MeOH used as a co-surfactant was effective in preventing agglomeration
  • a systematic series of tests were conducted to examine the limits of both MeOH and AA concentration required in anti-agglomeration.
  • MeOH concentrations of 5, 2, 0.5, and 0.1 wt. % were employed in the study.
  • Limited agglomeration state testing was conducted with zero or one part isooctane; in these cases, up to 10 wt. % MeOH and only 1.5 wt. % AA was employed to examine the effect on agglomeration.
  • MeOH in the amount of 10 wt.% is not used extensively in this study because much lower concentrations prove effective.
  • Temperature data was acquired separate from visual observations, since half of the sample vial surface area is covered when thermocouples are attached. However, temperature control of the bath and agitation are the same for both types of experiments.
  • T c crystallization temperature
  • Td dissociation temperature
  • composition was prepared in triplicate and experiments were repeated five times per sample. Thus, each sample was reused for five consecutive experiments. Some tests were separated by periods of heating at 7 0 C for 20 minutes. In other cases, un-agitated samples were kept in the bath overnight as it gradually warmed to room temperature before proceeding to the next test. There is no difference between the results from the use of samples exposed to room temperature and to those limited to heating at 7 0 C. Data shown below is the average of fifteen separate experiments per composition.
  • FIG 8 shows the results of such tests with Rhamnolipid as AA. Plugs, either fully blocked or partially blocked such that the steel ball was blocked from moving across the entire length of the vial, were still observed when up to 1.5 wt. % Rhamnolipid was added without MeOH. However, when just 0.5 wt. % MeOH is added to these mixtures, flowable hydrate slurries are formed. The same is seen with up to 5 wt. % MeOH. An example of such slurries is shown in Figure 9. A significant difference exists over the slurries seen in our previous work 38 due to increased hydrate volume present in these samples. However, there is some agglomeration when a very low concentration of 0.1 wt. % MeOH co-surfactant is used.
  • FIGS 11-14 show results of freeze-thaw cycles for select mixtures of both rhamnolipid and quat with 5, 2, and 0.5 wt. % MeOH, as well as mixtures without AA and/or MeOH.
  • AA was used in the amounts of 1.5, 0.5, and 0.05 wt. %.
  • the difference between the dissociation temperature Td and the crystallization temperature T c is the onset subcooling denoted by ⁇ T on ,.
  • Table 1 and Table 2 provide emulsion stability results for quat and rhamnolipid, respectively, along with standard deviations.
  • Mixtures of select AA concentration with 5, 2, 0.5, and 0 wt. % MeOH were tested using both "fresh" and “used” samples.
  • AA was used in the amounts of 1.5, 0.5, and 0.05 wt. %. Average and standard deviations are given to the nearest 0.1 minute, due to the relative instability of most compositions tested.
  • MeOH as a co-surfactant
  • low concentration is highly desirable. This is analogous to the LDHI concept, in that inhibitors effective at low concentrations should be used to reduce costs and other impact.
  • Thermodynamic inhibitors, especially MeOH may give rise to salt precipitation in petroleum fluid mixtures 50 , and so it is crucial in this respect as well to be able to identify low concentrations at which MeOH co-surfactant will be effective.
  • Water-cuts well below 50 % may still cause agglomeration in these model mixtures.
  • Mixtures with one part isooctane contain a water-cut of roughly 69 % and so it is truly expected for blockages to form in them.
  • mixtures of two parts isooctane contain roughly 34 % water-cut and results still show plug formation unless 0.5 wt. % or more MeOH co-surfactant is added. Since water-cut limitations will be different in real fluids, all that can be concluded from these observations is that more than water-in-oil emulsification and a 50% water-cut limit may be required for effective anti- agglomeration.
  • MeOH co-surfactant enables anti-agglomeration to occur. In low amounts, MeOH does not lead to salt deposition. 50 It is also thought that MeOH will be present mostly in the bulk water phase and the aqueous-side of the interfacial region in these mixtures. Thus, it appears that MeOH co-surfactant will be effective above a specific minimum concentration, and higher MeOH concentration will not be required. This concentration is believed to be around 0.5 wt .% or slightly less. Other alcohols may also be used as co-surfactants.
  • the presence of MeOH co-surfactant does aid anti- agglomeration via Rhamnolipid, down to very low Rhamnolipid concentrations.
  • Rhamnolipid At 0.1 wt.% Rhamnolipid, significant adhesion occurs no matter how much MeOH is added.
  • slurries exist in mixtures down to 0.5 wt. % MeOH. It was desired to determine if any Rhamnolipid concentrations between these two values would also facilitate slurries. Thus, 0.25 wt.% Rhamnolipid was also tested and it was found that slurries are facilitated by this amount of surfactant specifically when 2 to 5 wt. % MeOH co-surfactant is added.
  • 0.5 wt. % MeOH mixtures with 0.25 wt. % Rhamnolipid show a tendency to allow significant hydrate adhesion upon vial walls, defining a lower limit for these concentrations.
  • the quat is effective at anti-agglomeration over all the concentrations studied, i.e., down to 0.01 wt. %.
  • a similar behavior is reported in our previous work and seems to indicate that the quat is effective at inducing steric repulsion between hydrate crystallites as well as in hydrate-wall interactions, whereas Rhamnolipid may only be effective at both classes of repulsion when present in sufficient amount.
  • the quat solution contains 15-20 wt. % isopropanol, but it is assumed this does not play a co- surfactant role at the lower concentrations. For example, when 0.5 wt.% quat is added in mixtures of two parts isooctane, only about 0.05 wt.
  • t c values are generally larger than the values in mixtures of four parts isooctane due to the increased amount of hydrate being formed when water-cut is larger.
  • Figures 11 and 13 reveal a decrease in dissociation temperature with an increase in concentration of AA, as expected.
  • the MeOH co-surfactant does not appear to alter t c values significantly. As seen in Figure 3 and Figure 4, the crystallization peaks in presence of MeOH are generally broader so this is likely offsetting the affect of increased driving force, i.e. supersaturation, 51 at lower T 0 . Only in about half the cases does the data show thai addition of MeOH co-surfactant increases t c .
  • Emulsion Stability results in Table 1 and Table 2 reveal the same effect in used samples, those that have undergone freeze-thaw cycling, as seen in our previous work. 38 However, these emulsions are mostly unstable, so the difference between the two test types is small. Stable emulsions in real pipeline fluids are undesirable 25 ' 26 and therefore low stability values are acceptable. In general, the differences between the two tests are more significant for higher amounts of AA and MeOH co-surfactant. For fresh mixtures, there is little or no difference between stabilities of rhamnolipid or quat mixtures, with or without MeOH. There is some difference between rhamnolipid and quat mixtures for the used samples, but only at 1.5 and 0.5 wt. % AA.
  • MeOH is an effective co-surfactant as established through visual observations with a multiple screening-tube rocking apparatus using high operating subcooling and residence time as indicators of performance. Shut-in and emulsion stability tests also lend supporting evidence.
  • the experimental setup used in this work is similar to the one discussed above for THF hydrate anti-agglomeration, that is, the setup is a multiple screening-tube rocking apparatus which consists of a motor-driven agitator with rack holding up to 20 separate borosilicate glass scintillation vials, all as described above.
  • thermocouples with accuracy of ⁇ 0.2 0 C from 70 0 C down to -20 0 C are attached to the outside of the vials when crystallization and melting data are desired.
  • the thermocouples are attached to the outside wall of the vials, which are ideal for sample preparation and containment.
  • An Agilent 34970A data acquisition unit recording temperature every 20 seconds and ice bath as fixed junction reference temperature is used with all thermocouples.
  • a sketch of the apparatus is shown in Figure 1.
  • Rhamnolipid biosurfactant (product JBR 425) (Rh) was obtained from Jeneil Biosurfactant Co., Madison, WI. It is a mixture of two forms at 25 wt. % in water. Rh was used as supplied and is the same as discussed above.
  • the cosurfactant is 99.8% anhydrous MeOH with less than 0.05 ppm water, obtained from Acros.
  • Temperature data was acquired separately from visual observations, since half of the sample vial surface area is covered when thermocouples are attached. However, temperature control of the bath and agitation are the same for both types of experiments.
  • Mixtures of x/l/0.02/y and x/l/0.02/y/z of CP/water/THF/surfactant and CP/water/THF/surfactant/cosurfactant, by weight are prepared and homogenized by shaking by hand for 1 minute. The time it takes for 60 vol % of the initial aqueous phase to separate is measured and used as an indicator of emulsion stability.
  • Helper molecules such as methane are used only under high pressure because of the solubility of these gases in water.
  • THF was employed as a helper molecule because of its high solubility in water at atmospheric pressure.
  • the results clearly indicate that the presence of THF as a helper molecule give rise to hydrate formation.
  • the dissociation temperature is around 7.0 °C in agreement with data from Refs. 57 and 58.
  • the results reveal that THF does not measurably affect the dissociation temperature of CP hydrates. At higher concentrations than used, THF concentration may affect dissociation temperature or possibly THF hydrates may form.
  • Rh Rhamnolipid
  • Figure 17 shows the freeze-thaw cycle data for a sample of CP/H 2 0/THF/Rh with composition of 0.4/1/0.03/0.01. Due to 3% fHF and 1% Rh in the mixture, no ice forms to a temperature of -4 0 C. For a conclusive study of anti-agglomeration of hydrates, the formation of ice should be avoided. In this experiment the weight ratio of CP to water is 0.4 : 1, and the molar ratio is 1 :10 which is higher than the hydrate stoichiometric molar ratio of 1 :17. 48 Figure 17 shows that the hydrate formation with surfactant Rh is accompanied by a high growth rate as compared to Figure 16.
  • the amount of CP in the mixture affects the ratio of hydrates to the sample volume.
  • the total volume of the mixture is fixed at 7 mL.
  • CPZH 2 O ratio of 0.4/1 more hydrates form followed by a ratio of 2/1 and then 4/1.
  • dissociation temperature data in Figure 19 clearly show that CP amount does not affect the dissociation temperature as expected.
  • the addition of MeOH suppresses the dissociation temperature of CP hydrates.
  • the data in Figure 20 reveal a decrease in dissociation temperature with increasing concentration of MeOH.
  • Rh and MeOH in reduction of Td-
  • the increase of Rh from 0.001 to 0.005 suppresses T d by 0.54 0 C; the addition of MeOH by 0.01 lowers Td by 1.85 0 C.
  • the combined effect of concentration increase of Rh from 0.001 to 0.005, and the addition of MeOH by 0.01 lowers T d by 3.45 0 C, which is greater than the sum of the contribution from the increase in Rh and in MeOH when added individually by about 1°C.
  • the purpose here is to confirm the anti-agglomeration (AA) effectiveness of the inventive composition with cyclopentane hydrate particles.
  • the agglomeration state was determined by testing mixtures Of CPm 2 OZTHFZRh of compositions 4ZlZ0.02Zx and 4ZlZ0.03Zx by weight. As Figure 21 shows, dispersible hydrates are formed with a low concentration of Rh. The samples with 0.02 THF were cooled to -2 0 C then kept at 1.5 0 C for AA state observation, while the samples with 0.03 THF were cooled to -3 0 C then kept at 1.5 0 C for AA state observation. There was no ice formation in the tests.
  • Rh concentration 0.01-0.05 part of Rh
  • -2 0 C 0.01-0.05 part of Rh
  • the concentration of Rh is 0.003 to 0.01 without MeOH.
  • the Rh concentration is high, in the range of 0.03 to 0.05, the AA effectiveness decreases probably due to the high viscosity effect. Plugs, either full or partial, appear when the Rh concentration is lower than 0.003.
  • FIG. 26 shows the results. Plugs are formed to a Rh concentration of 0.01 when there is no MeOH. When the concentration of MeOH is only 0.005, hydrate slurries are formed at Rh concentrations of 0.005 and 0.01. When the concentration of Rh is 0.003, a MeOH concentration of 0.01 is required to form stable dispersion. In mixtures of 2 parts and 1.5 parts CP, a MeOH concentration of 0.002 MeOH is not effective in anti-agglomeration.
  • the results in Fig 26 correspond to a subcooling of about of about 6 to 10 0 C.
  • emulsion stability in hydrate anti-agglomeration has been suggested to be very important. 21 As discussed above, emulsion stability may not be critical when using the inventive composition. Using the methodology discussed above to measure emulsion stability, the time it takes to form 60% of water to separate in the mixture was determined. Table 3 gives average emulsion stability results with two duplicate tests. The weight ratio of CP to water in the mixtures was 1, 1.5 and 4 parts, with Rh at 0.001, 0.002, 0.003 0.005 and 0.01. For samples with 1.5 CP ratio to water, methanol concentration was 0, 0.002, 0.005. As can be seen from the Table, the Rh concentration increases emulsion stability in all mixtures. The CP concentration also increases emulsion stability. Addition of methanol generally increases emulsion stability, but the effect is not significant.
  • the present invention thus provides an anti-agglomeration composition for gas hydrates, effective at high subcooling temperatures which contains a combination of a surfactant and an alcohol cosurfactant.
  • the anti-agglomeration composition is effective using relatively low amounts of both the surfactant and co-surfactant to limit environmental effects as well as to reduce the cost of separation in downstream operations.
  • the anti-agglomeration composition of the invention also does not require a stable water in oil emulsion to provide the beneficial anti-agglomeration effects.
  • the composition comprises a surfactant and an alcohol co-surfactant provided in effective amounts sufficient to cause anti-agglomeration of hydrates, which is particularly useful where high subcooling temperatures and/or at high water-cuts occur.
  • the surfactant is a Rhamnolipid biosurfactant and the alcohol cosurfactant is methanol, the alcohol cosurfactant being present at concentrations low enough such that side effects such as salt deposition are avoided.
  • the alcohol cosurfactant should be present at from 0.05-5% wt., with the surfactant present at from 0.001 to 10% wt., more preferably, 0.01 to 5% wt.
  • agglomeration of hydrates in gas and oil pipelines can be reduced using low levels of the inventive composition, which is also effective at relatively high water cuts, and at relatively high subcooling temperatures.

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Abstract

L’invention concerne une composition anti-agglomération pouvant empêcher l'agrégation d'hydrates et la formation consécutive de bouchons dans des pipelines, notamment des hydrates provenant de puits de gaz sous-marins. La composition de l'invention contient une combinaison d'un tensioactif et d'un cotensioactif alcool, tous deux présents en faible quantité pour limiter leur incidence sur l'environnement ainsi que pour réduire les coûts de séparation en secteur aval. La composition de l'invention contient un tensioactif et un cotensioactif alcool présents chacun dans des quantités pouvant empêcher efficacement l'agglomération d'hydrates à des températures de sous-refroidissement élevées et/ou à des teneurs en eau élevées. De préférence, le tensioactif est un biotensioactif de rhamnolipides, et le cotensioactif alcool est méthanol et est présent à des concentrations suffisamment faibles pour éviter des effets secondaires tels que le dépôt de sel. En règle générale, le cotensioactif alcool devrait être présent à un taux de 0,05 à 5 % en poids et le tensioactif à un taux de 0,01 à 10 % en poids, de préférence à un taux de 0,01 à 5 % en poids. Le procédé de l'invention permet de réduire l'agglomération d'hydrates dans des gazoducs ou des oléoducs.
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US8728599B2 (en) 2011-10-26 2014-05-20 General Electric Company Articles comprising a hydrate-inhibiting silicone coating
CN105090747A (zh) * 2015-08-14 2015-11-25 中国石油化工股份有限公司 一种含鼠李糖脂的复配型水合物阻聚剂
CN105179939A (zh) * 2015-08-14 2015-12-23 中国石油化工股份有限公司 一种含鼠李糖脂复配型水合物防聚剂的应用
US9988568B2 (en) 2015-01-30 2018-06-05 Ecolab Usa Inc. Use of anti-agglomerants in high gas to oil ratio formations
WO2019094615A1 (fr) * 2017-11-08 2019-05-16 Locus Oil Ip Company, Llc Composition multifonctionnelle pour récupération améliorée de pétrole, meilleure qualité de pétrole, et prévention de corrosion
WO2020161407A1 (fr) 2019-02-06 2020-08-13 Arkema France Composition pour prévenir l'agglomération d'hydrates de gaz
US10844276B2 (en) 2017-03-03 2020-11-24 Locus Oil Ip Company, Llc Composition and methods for microbial enhanced digestion of polymers in fracking wells
US10907106B2 (en) 2017-06-21 2021-02-02 Locus Oil Ip Company, Llc Treatment for upgrading heavy crude oil
US11396623B2 (en) 2017-09-27 2022-07-26 Locus Oil Ip Company, Llc Materials and methods for recovering oil from oil sands
US11434415B2 (en) 2018-04-30 2022-09-06 Locus Oil Ip Company, Llc Compositions and methods for paraffin liquefaction and enhanced oil recovery in oil wells and associated equipment
US11447684B2 (en) 2018-08-20 2022-09-20 Locus Oil Ip Company, Llc Methods for paraffin removal and extended post-primary oil recovery
US11549053B2 (en) 2018-07-30 2023-01-10 Locus Solutions Ipco, Llc Compositions and methods for enhanced oil recovery from low permeability formations
US11608465B2 (en) 2018-03-27 2023-03-21 Locus Solutions Ipco, Llc Multi-functional compositions for enhanced oil and gas recovery and other petroleum industry applications
US11834705B2 (en) 2016-12-11 2023-12-05 Locus Solutions Ipco, Llc Microbial products and their use in bioremediation and to remove paraffin and other contaminating substances from oil and gas production and processing equipment

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US8728599B2 (en) 2011-10-26 2014-05-20 General Electric Company Articles comprising a hydrate-inhibiting silicone coating
CN103555381A (zh) * 2013-11-19 2014-02-05 湖南大学 柴油反胶束体系、制备方法、应用及生物柴油和制备方法
US9988568B2 (en) 2015-01-30 2018-06-05 Ecolab Usa Inc. Use of anti-agglomerants in high gas to oil ratio formations
CN105090747A (zh) * 2015-08-14 2015-11-25 中国石油化工股份有限公司 一种含鼠李糖脂的复配型水合物阻聚剂
CN105179939A (zh) * 2015-08-14 2015-12-23 中国石油化工股份有限公司 一种含鼠李糖脂复配型水合物防聚剂的应用
US11834705B2 (en) 2016-12-11 2023-12-05 Locus Solutions Ipco, Llc Microbial products and their use in bioremediation and to remove paraffin and other contaminating substances from oil and gas production and processing equipment
US11473007B2 (en) 2017-03-03 2022-10-18 Locus Oil Ip Company, Llc Compositions and methods for microbial enhanced digestion of polymers in fracking wells
US10844276B2 (en) 2017-03-03 2020-11-24 Locus Oil Ip Company, Llc Composition and methods for microbial enhanced digestion of polymers in fracking wells
US10907106B2 (en) 2017-06-21 2021-02-02 Locus Oil Ip Company, Llc Treatment for upgrading heavy crude oil
US11441082B2 (en) 2017-06-21 2022-09-13 Locus Oil Ip Company, Llc Treatment for upgrading heavy crude oil
US11396623B2 (en) 2017-09-27 2022-07-26 Locus Oil Ip Company, Llc Materials and methods for recovering oil from oil sands
US12012548B2 (en) 2017-09-27 2024-06-18 Locus Solutions Ipco, Llc Materials and methods for recovering oil from oil sands
US12065613B2 (en) 2017-11-08 2024-08-20 Locus Solutions Ipco, Llc Multifunctional composition for enhanced oil recovery, improved oil quality and prevention of corrosion
US11549052B2 (en) 2017-11-08 2023-01-10 Locus Solutions Ipco, Llc Multifunctional composition for enhanced oil recovery, improved oil quality and prevention of corrosion
WO2019094615A1 (fr) * 2017-11-08 2019-05-16 Locus Oil Ip Company, Llc Composition multifonctionnelle pour récupération améliorée de pétrole, meilleure qualité de pétrole, et prévention de corrosion
US11608465B2 (en) 2018-03-27 2023-03-21 Locus Solutions Ipco, Llc Multi-functional compositions for enhanced oil and gas recovery and other petroleum industry applications
US11434415B2 (en) 2018-04-30 2022-09-06 Locus Oil Ip Company, Llc Compositions and methods for paraffin liquefaction and enhanced oil recovery in oil wells and associated equipment
US11891567B2 (en) 2018-04-30 2024-02-06 Locus Solutions Ipco, Llc Compositions and methods for paraffin liquefaction and enhanced oil recovery in oil wells and associated equipment
US11549053B2 (en) 2018-07-30 2023-01-10 Locus Solutions Ipco, Llc Compositions and methods for enhanced oil recovery from low permeability formations
US11447684B2 (en) 2018-08-20 2022-09-20 Locus Oil Ip Company, Llc Methods for paraffin removal and extended post-primary oil recovery
WO2020161407A1 (fr) 2019-02-06 2020-08-13 Arkema France Composition pour prévenir l'agglomération d'hydrates de gaz

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