[go: up one dir, main page]

WO2019200269A1 - Systèmes de gélification s'autoassemblant adaptatifs - Google Patents

Systèmes de gélification s'autoassemblant adaptatifs Download PDF

Info

Publication number
WO2019200269A1
WO2019200269A1 PCT/US2019/027243 US2019027243W WO2019200269A1 WO 2019200269 A1 WO2019200269 A1 WO 2019200269A1 US 2019027243 W US2019027243 W US 2019027243W WO 2019200269 A1 WO2019200269 A1 WO 2019200269A1
Authority
WO
WIPO (PCT)
Prior art keywords
acid
carboxylic acid
percent
injection fluid
reaction mixture
Prior art date
Legal status (The legal status 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 status listed.)
Ceased
Application number
PCT/US2019/027243
Other languages
English (en)
Inventor
Cengiz YEGIN
Nirup Nagabandi
Mustafa Akbulut
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Incendium Technologies LLC
Original Assignee
Incendium Technologies LLC
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 Incendium Technologies LLC filed Critical Incendium Technologies LLC
Publication of WO2019200269A1 publication Critical patent/WO2019200269A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

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
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/584—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific surfactants
    • 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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • 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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds

Definitions

  • the invention relates to adaptive self-assembling gelation systems, in other words “intelligent” viscosifiers, specifically those having adjustable physical properties.
  • Crude oil and natural gas are two of the most important energy sources that are commercially viable and will continue to maintain high demand for the years to come. While oil and gas extraction has been practiced and improved for several hundred years, two of the more recently established methods of oil and gas recovery include Enhanced Oil Recovery (EOR) and hydraulic fracturing. EOR includes the injection of a fluid into an identified reservoir to push the trapped oil to a collection well.
  • EOR includes the injection of a fluid into an identified reservoir to push the trapped oil to a collection well.
  • Hydraulic fracturing injects fluid into a horizontal well of a shale deposit, pressurizes the fluid in the well making small cracks or fissures in the deposit to release trapped hydrocarbons, and removing the fluid to allow for these hydrocarbons from the deposit to come to the surface for collection.
  • the injection or fracturing fluid is a key component to a successful EOR or hydraulic fracturing operation.
  • Several physical properties dictate the efficiency of the processes in both the amount of energy required to get the oil and gas to the surface and the percentage of the total oil and gas in the reservoir that is recovered.
  • one property is ideal for achieving, for example, low energy cost for injecting fluid into the reservoir the same property is detrimental to the percentage of oil or gas that is recovered from the reservoir. Therefore, to this point a balancing of the characteristics of the injection fluid is required to the overall efficiency of the recovery process.
  • Crude oil and gas are two major fossil fuel hydrocarbon energy resources that will meet a substantial part of the U.S. and global energy demand in the upcoming several decades.
  • Oil/natural gas recovery can be achieved by two methods: (1 ) enhanced oil recovery (EOR) in which conventional reservoir oil is swept to the earth ' s surface via hydraulic pressure using injection fluids, and (2) hydraulic fracturing where shale deposits are horizontally drilled and then fractured to extract trapped oil and gas.
  • EOR involves pushing the crude oil by various injection fluids including water flooding, polymer flooding and C02 injection.
  • a key point to maximize oil recovery in EOR is to match the gelling strength (i.e.
  • viscosity of the injected fluid and the reservoir oil to minimize interfacial tension, avoid fingering of the injected fluid through the oil, and form a flat fluid/oil interface.
  • the injected fluid must be sufficiently strong when in contact with the reservoir oil to sweep it to the ground (2 in FIG. 1A). Meanwhile, its initial viscosity should be low during injection and pumping for easy operation, which will both contribute to the efficiency of the operation (1 in FIG. 1 A).
  • Flydraulic fracturing involves opening small-sized cracks (fissures) along the shale deposit; pumping the injection fluid (fracking fluid) at high pressures of up to 15,000 psi ( ⁇ 100 MPa) including all values and ranges therein, to further enlarge these cracks with the help of additives, and sand particles (proppants) suspended in the fracking fluid, in order to prevent their closing due to geological pressure; and finally release pumping pressure and flowback the fracking fluid to let the oil/gas fill in the horizontal well.
  • the fracking fluid must be resistant to these high pressures and possess sufficiently high gelling strength (i.e. , viscosity) to suspend and transfer proppants to the cracks.
  • the gelling strength should be adjusted to a lower value during flowback to release the suspended proppants in the cracks and easily withdraw the fluid (Figure 2).
  • the injected fluids are exposed to elevated temperatures, such as temperature in the range of 50°C to 100°C, including all values and ranges therein, due to geothermal gradient, and thus they are required to maintain their structural integrity at a wide temperature range.
  • the proposed adaptive self-assembling gelation systems namely“intelligent” viscosifiers are stimuli- responsive solutions that are activated by varying parameters including, e.g., pH, temperature, light, sound, electromagnetic waves, electric field, magnetic field and pressure, and adjust the gelling strength of injection fluids reversibly.
  • the “intelligent” viscosifier solutions increase gelling of injection fluids which match the viscosity of the injection fluid and crude oil upon contact in an oil reservoir for enhanced sweeping efficiency.
  • high gelling strength provided by these solutions enables the injection fluid to easily transport proppants in a fracking operation.
  • tunable properties of the“intelligent” viscosifier solutions enable keeping the gelling strength low during injection in EOR and flowback in hydraulic fracturing to reduce operational and energy costs.
  • The“intelligent” viscosifier solutions which possess adjustable viscosity and self- healing behaviors, and high temperature tolerance, were obtained by complexation of carboxylic acids with organic amino-amides in water.
  • the responsive “intelligent” viscosifier solution can reversibly tune the viscosity of the injection fluid many times at even the lowest concentrations in weight, such as in the range of 0.2 to 5.0 % by weight in the total solution, including all values and ranges therein.
  • Preliminary sweeping efficiency tests have verified that injection fluids including the“intelligent” viscosifier solutions can significantly increase the amount of recovery compared to those include traditional polymer-based gelling agents. Replacement of the current gelling agents with the“intelligent” viscosifier solutions will increase the hydrocarbon recovery factor in oil and natural gas reservoirs.
  • The“intelligent” viscosifier solutions are made of natural building blocks and may be highly biodegradable, which may reduce environmental impacts of injection fluids. All constituents of the developed solutions are eco-friendly and may mitigate environmental and public concerns against hydraulic fracturing such as contamination of aquifers and extinction of soil and plant life in the operation areas.
  • a method of producing a viscosifier including reacting a first reaction mixture including an amine with a first carboxylic acid via a condensation reaction to form an amino-amide, wherein the amine includes 4 to 6 carbon atoms and is at least one of a diamine and a triamine and the first carboxylic acid includes 8 to 20 carbon atoms and is at least one of a dicarboxylic acid or a tricarboxylic acid.
  • the method further includes reacting a second reaction mixture including the amino-amide with a second carboxylic acid via a complexation reaction, wherein the second carboxylic acid includes 3 to 6 carbon atoms.
  • the amine is provided at a weight percent in the range of 30 percent to 40 percent of the total weight of the first reaction mixture and the first carboxylic acid is provided at a weight percent in the range of 60 percent to 70 percent of the total weight of the first reaction mixture.
  • the first reaction mixture further includes a catalyst.
  • the catalyst is present at a weight percent in the range of 0.60 percent to 0.75 percent of the total weight of the first reaction mixture.
  • the first reaction mixture further includes an absorbent.
  • the absorbent is present at a weight percent in the range of 0 percent to 0.5 percent of the total weight of the first reaction mixture.
  • the amine is selected from at least one of N,N-diethylenediamine, N,N-diethylenediamine, N-1 ,3 propanediamine, isopropyl-1 ,3- propanediamine, N,N'-diethyl-2-butene-1 ,4-diamine, N,N-dimethylethylenediamine, and N,N'-dimethyl-1 ,2-ethanediamine.
  • the first carboxylic acid is selected from at least one of arachidic acid, palmitic acid, pentadecylic acid, palm oil, coconut oil, corn oil, avocado oil, and lauric acid.
  • the second carboxylic acid is selected from at least one of maleic acid, malonic acid, glutaric acid, aconic acid, citraconic acid, citric acid, and carballylic acid.
  • the amino-amide is present at a weight percent in the range of 10 percent to 25 percent of the total weight of the second reaction mixture.
  • the second carboxylic acid is present at a weight percent in the range of 80 percent to 90 percent of the total weight of the second reaction mixture.
  • the second reaction mixture includes water.
  • a method of providing an injection fluid includes mixing a viscosifier with an aqueous solution, wherein the viscosifier comprises an amino-amide complexed with a second carboxylic acid, wherein the amino- amide comprises a condensation reaction product of a amide and a first carboxylic acid, wherein the amine includes 4 to 6 carbon atoms and is at least one of a diamine and a triamine, the first carboxylic acid includes 8 to 20 carbon atoms and is at least one of a dicarboxylic acid or a tricarboxylic acid, and the second carboxylic acid includes 3 to 6 carbon atoms.
  • the aqueous solution includes salt present in the range of 0.1 to 5% by weight of the total solution weight.
  • the salt includes one or more of the following: sodium, chloride, magnesium, sulfate, calcium, carbonates, gypsum, bromine and fluoride.
  • the method further includes adding a proppant to the injection fluid.
  • a method of extracting fossil fuel hydrocarbons includes injecting an injection fluid in a reservoir containing a fossil fuel hydrocarbon, wherein the injection fluid comprises a viscosifier mixed with an aqueous solution, wherein the injection fluid exhibits a first viscosity.
  • the method further includes increasing the pH of the injection fluid to a pH in the range of 6 to 9, increasing the viscosity of the injection fluid to a second viscosity greater than the first viscosity.
  • the fossil fuel hydrocarbon is then extracted from the reservoir.
  • the viscosifier comprises an amino- amide complexed with a second carboxylic acid, wherein the amino-amide comprises a condensation reaction product of a amine and a first carboxylic acid, wherein the amine includes 4 to 6 carbon atoms and is at least one of a diamine and a triamine, the first carboxylic acid includes 8 to 20 carbon atoms and is at least one of a dicarboxylic acid or a tricarboxylic acid, and the second carboxylic acid includes 3 to 6 carbon atoms
  • the pH of the injection fluid is increased due to the pH level of the reservoir.
  • the pH of the injection fluid is increased by adding a base to the injection fluid.
  • FIG. 1 A depicts a cross section of a method of recovering crude oil from an underground reservoir according to the principles of the present invention
  • FIG. 1 B depicts a portion of a cross section of an interface between crude oil and injection fluid of an underground reservoir according to the principles of the present invention
  • FIG. 1 C depicts a portion of a cross section of an interface between crude oil and injection fluid of an underground reservoir according to the principles of the present invention
  • FIG. 2 depicts a cross section of a method of extracting natural gas from an underground shale deposit according to the principles of the present invention
  • FIG. 3 is a representation of synthesizing the viscosifiers according to the principles of the present invention
  • FIG. 4 is a flowchart depicting a method of synthesizing the viscosifiers according to the principles of the present invention
  • FIG. 5 is a depiction of working viscosifiers according to the principles of the present invention.
  • FIG. 6 is a depiction of the synthesis and function of viscosifiers according to the principles of the present invention.
  • FIG. 1 a schematic depicting a method of recovering crude oil 10 from an underground reservoir 12 is illustrated and will now be described.
  • the underground reservoir 12 is a volume of crude oil 10 trapped between the several layers of the earth’s crust 14.
  • a system 16 is constructed to bring the crude oil 10 from the reservoir 12 to the ground surface 32.
  • the system 16 includes at least a first injection pump 18, an injection well 20, and a collection well 22. More specifically, the injection pump 18 is hydraulically connected to the underground reservoir 12 through the injection well 20 located at a first end or boundary 24 of the reservoir 12.
  • a second injection pump 26 and injection well 28 are located some distance away from the first injection pump 18 and well 20 proximate an opposite end of the reservoir 12.
  • the collection well 22 is located equidistant from each of the first and second injection wells 20, 28.
  • the system 16 requires pumping or injecting an injection fluid 30 into the reservoir
  • the injection fluid 30 is engineered to capitalize upon at least two measures of efficiency in the process of recovering crude oil 10 from the underground reservoir 12.
  • the first measure of efficiency is the work required by the pumps 18, 26 to push the injection fluid 30 into the reservoir 10 through the injection wells 20, 28.
  • the second measure of efficiency is the fraction of crude oil 10 that is actually recovered from the reservoir 12.
  • a physical property of the injection fluid 30 that is most closely associated with pumping efficiency is viscosity. In general, a fluid with relatively high viscosity requires more work to pump than a fluid with relatively low viscosity.
  • the injection fluid may exhibit a relatively low viscosity, such as in the range of 1 mPa * s to 10 mPa * s, including all values and ranges therein, while it is being pumped through the injection wells 20, 28 and into the reservoir 12.
  • a relatively low viscosity such as in the range of 1 mPa * s to 10 mPa * s, including all values and ranges therein, while it is being pumped through the injection wells 20, 28 and into the reservoir 12.
  • Such viscosities may be exhibited at relatively high temperatures or relatively low pH values, including a pH of less than 6, such as in the range of 2 to 6.
  • the second efficiency measure is the amount of crude oil 10 that is recovered from the reservoir 12 over the amount of oil 10 that was originally in the reservoir 12. While attempting to achieve a high efficiency in this measure is similar to the first efficiency measure, an injection fluid 30 having a higher viscosity will provide the better results.
  • the concept requires the viscosity of the injection fluid 30 to be similar to that of the crude oil 10, and the injection fluid 30 may exhibit a viscosity greater than 100 mPa * s, such as in the range of 100 mPa * s to 1000 mPa * s, including all values and ranges therein. Such viscosities may be exhibited at relatively higher pH values, such as those of 6 or above, such as in the range of 6 to 9.
  • the injection fluid exhibits a viscosity of 300 Pa * s to 350 Pa * s at a pH of 8 at a temperature of 22 °C and a viscosity of 10 Pa * s to 20 Pa * s at a pH in the range of 8 and at a temperature of 75 °C.
  • the viscosity may be tuned between the ranges above by altering the pH in the range of 2 to 9, including all values and ranges therein, such as from 4 to 8.
  • the viscosity may further be tuned by adjusting the temperature of the fluid.
  • the injection fluid 30 has a similar viscosity to that of the crude oil 10 in the reservoir 12, the result is an interface 32 between the injection fluid 30 and crude oil 10 having minimal surface area of fluid 20 in contact with oil 30 as shown in FIG. 1 C. Accordingly, in aspects, the difference between the viscosity of the injection fluid and the viscosity in the crude oil is controlled. Having a differential between the viscosities of injection fluid 30 and that of the crude oil 10 that is too large results in the interface 32 between the fluid 30 and oil 10 having a relatively high amount of surface area as the result of“fingering” or fluid 30 penetrating into the oil 10 and vice versa. An example of fingering is shown in FIG. 1 B.
  • the injection fluid 30 since an improved injection fluid is required to at one point in the process, have a relatively low viscosity and while at another point in the process possess a different, relatively high viscosity the two efficiency measures require contradicting or opposing physical properties in the same fluid.
  • the injection fluid 30 herein exhibits an adjustable viscosity, self-healing characteristics, and relatively high temperature tolerance.
  • the injection fluid 30 has a low shear viscosity so that when a shear force is applied to the fluid 30 such as in a small cross-sectional area pump and injection well, the fluid 30 viscosity breaks down and acts like a fluid having relatively lower viscosity, lower than that of the fluid prior to the application of force to the fluid.
  • Self-healing is due, at least in part, to various intermolecular interactions between the molecules of the injection fluid, which disassociate during injection and re-associate once in the well.
  • intermolecular forces include but are not limited to, e.g., hydrogen bonding, dipole-dipole interactions, hydrophobic interactions, and London dispersion force.
  • tolerance to higher temperatures is also a characteristic exhibited by the injection fluid 30.
  • the boiling point of the fluid may be affected by factors such as altitude and salt content. In most instances, higher temperatures result in lower fluid viscosity. However, the injection fluid 30 maintains its viscosity as the temperature in the fluid and its environment increases.
  • Another mechanism that allows the injection fluid to both regain the lost viscosity after entering the reservoir is the effect on the fluid 30 by the pH level of the reservoir 12 environment.
  • the reservoir 12 is a relatively basic environment, having a pH of 6 or greater such as in the range of 6 to 9 and, in further aspects from 7.5 to 8, the viscosity of the fluid 30 will increase significantly.
  • the reservoir 12 is not a relatively basic environment, having a pH of less than 6, micro emulgents or microspheres are added to the injection fluid 30.
  • the microspheres contain a basic additive that is released when pressure on the fluid reaches a specified level. The basic additive then mixes with the injection fluid 30, increases the PH of the fluid 30, and therefore increases viscosity of the fluid 30.
  • the underground shale deposit 52 contains a volume of natural gas 50 between the several layers of the earth’s crust 54.
  • a system 56 similar to the system 16 described above, is constructed to bring the natural gas 50 from the shale deposit 52 to the ground surface 58.
  • the system 56 includes an injection pump 60, a vertical injection well 62, and a horizontal injection well 64. More specifically, the injection pump 60 is hydraulically connected to the shale deposit 52 through the vertical and horizontal injection wells 62, 64. An injection fluid 66 is pumped into the injection wells 62, 64.
  • the horizontal injection well 64 includes a casing or pipe having perforations thus hydraulically communicating the interior of the horizontal injection well 64 with the shale deposit 52.
  • the injection pump 60 continues to pump injection fluid 66 and increases the pressure of the injection fluid 66 inside the horizontal injection well 64. Since the horizontal injection well 64 is perforated, the pressure of the injection fluid 66 in the shale deposit 52 increases until small fissures or cracks 68 are formed in the shale deposit.
  • the injection fluid 66 enters into the cracks 68 until the injection pump 52 is reversed and pumps the injection fluid 66 out of the horizontal and vertical injection wells 62, 64.
  • the trapped gas 50 that has been liberated from shale deposit 52 through the cracks 68 enters the horizontal injection well 64 and flows back through the vertical injection well 62 and is collected at the surface 58.
  • the first measure of efficiency is the work required by the injection pump 60 to push the injection fluid 66 through the injection wells 62, 64 and into the shale deposit 52.
  • the second measure of efficiency is the fraction of natural gas 50 that is actually recovered from the shale deposit 52.
  • a physical property of the injection fluid 66 that is most closely associated with pumping efficiency is viscosity.
  • a fluid with relatively high viscosity requires more work to pump than a fluid with low viscosity.
  • the injection fluid 66 may exhibit a relatively low viscosity, such as in the range of 1 mPa*s to 10 mPa*s, including all values and ranges therein, while it is being pumped through the injection wells 62, 64 and into the shale deposit 52.
  • Such viscosities may be exhibited at relatively high temperatures or relatively low pH values, including less than a pH of 6, such as in the range of 2 to 6.
  • the second efficiency measure is the amount of natural gas 50 that is recovered from the shale deposit 52 over the amount of natural gas 50 that was originally in the shale deposit 52. While attempting to achieve a high efficiency in this measure similar to the first efficiency measure an injection fluid 66 having a higher viscosity, in the range of 150 mPa*s to 10 6 mPa*s, including all values and increments therein, will provide better results. Such viscosities may be exhibited at relatively higher pH values, such as those of 6 or above, such as in the range of 6 to 9.
  • the injection fluid exhibits a viscosity of 300 Pa*s to 350 Pa*s at a pH of 8 at a temperature of 22°C and a viscosity of 10 Pa*s to 20 Pa*s at a pH in the range of 8 and at a temperature of 75 °C.
  • the viscosity may be tuned between the ranges above by altering the pH in the range of 2 to 9, including all values and ranges therein, such as from 4 to 8.
  • the viscosity may further be tuned by adjusting the temperature of the fluid.
  • the viscosity may be adjusted to provide a minimum surface area of fluid in contact with the natural gas and to prevent“fingering” of either the injection fluid or natural gas into the other composition, as illustrated in FIG. 1 B.
  • the injection fluid 30, 66 includes an aqueous solution to which the“intelligent viscosifier is added.
  • the aqueous solution includes, e.g., water, brackish water, sea water, or brine.
  • the aqueous solution includes up to 5% of salt, including all values and ranges from 0.1 % by weight to 5.0 % by weight of the total solution, such as 0.1 % to 4.0 % by weight of the total solution.
  • the salt includes but is not limited to, for example, sodium and chloride; however, it may be appreciated that other ions include magnesium, sulfate, calcium, carbonates, gypsum, bromine and fluoride may additionally or alternatively be present.
  • the injection fluid 30, 66 also includes a proppant 70 which is a small particle that is forced into the cracks 68 created in the shale deposit 52 and left in the cracks 68 when the injection fluid 66 is evacuated back to the surface 58.
  • the proppants 70 keep the cracks 68 open to allow the natural gas to escape when the pressure that opened the cracks 68 originally is removed by the reversal of the injection pump 60 and removal of the injection fluid 66. Delivery and disposal of the proppants into the cracks 68 of the shale deposit 52 is most effectively accomplished with a high viscosity or high gel strength injection fluid 66.
  • proppants include, but may not be limited to, silica sand and ceramic beads
  • the proppants exhibit an average particle size in the range of 8 mesh ( ⁇ 2.4 mm) to 140 mesh ( ⁇ 100 pm), including all values and ranges therein.
  • the proppants are added to the injection fluid in a range of 4 to 10 % by total weight of the injection fluid, including all values and ranges therein.
  • an injection fluid 66 for the system 56 illustrated in FIG. 2 is required to at one point in the process have low viscosity and while at another point in the process possess a different viscosity the two efficiency measures require contradicting or opposing physical properties in the same fluid.
  • the injection fluid 66 has an adjustable viscosity, self-healing characteristics, and high temperature tolerance.
  • the method 100 includes a first step 102 of a condensation reaction of an amine or a multi- amine (more than one amine in same molecule) organic building block with a long chain acid or a mixture of long chain acids under an inert environment, such as an argon or nitrogen environment.
  • This condensation reaction is in the presence of a catalyzer and a water absorbent in small amounts.
  • the resultant product is rinsed with a solvent to remove residual amine and dried for about six hours.
  • the long chain acid may include a first carboxylic acid including one or more of a saturated or unsaturated dicarboxylic or tricarboxylic carboxylic acid including 8 to 20 carbon atoms in the chain.
  • a saturated or unsaturated dicarboxylic or tricarboxylic carboxylic acid including 8 to 20 carbon atoms in the chain.
  • di- or tri- carboxylic acids including arachidic acid, palmitic acid, pentadecylic acid, palm oil, coconut oil, corn oil, avocado oil, and lauric acid.
  • other long chain acids, oils or mixture of oils may be considered without departing from the scope of the invention.
  • the amine organic building block includes a di-amine or a tri-amine including from 4 to 6 carbons in the molecule and selected from at least one of N,N-diethylenediamine, N,N-diethylenediamine, N-1 ,3 propanediamine, isopropyl-1 , 3-propanediamine, N,N'- diethyl-2-butene-1 ,4-diamine, N,N-dimethylethylenediamine, and N,N'-dimethyl-1 ,2- ethanediamine.
  • other reactants of the amine organic building block may be used without departing from the scope of the invention.
  • the amine may be provided at 30 to 40 weight percent of the total reaction mixture, including all values and ranges therein, and the carboxylic acid may be provided at a weight percent in the range of 60 to 70 weight percent of the total reaction mixture, including all values and ranges therein.
  • the amine and acid may be provided at a weight ratio of 1 amine to 2 acids.
  • the catalyst includes, for example, a sodium fluoride catalyst.
  • the catalyst may be provided in an amount in the range of 0.60 to 0.75 weight percent, including all values and ranges therein such as 0.68 weight percent of the total reaction mixture.
  • an absorbent may be provided, such as aluminum oxide to absorb hydrous byproduct of the condensation reaction.
  • the absorbent may be provided in an amount in the range of 0 to less than 0.5 weight percent of the total reaction mixture including all values and ranges therein, such as 0.1 to 0.4 weight percent.
  • the resulting product is an organic compound, which is referred to herein as an amino-amide 114.
  • a second step 104 of the method 100 includes a complexation reaction in water, or another aqueous solution, of the organic amino-amide compound 114 from the first step 102 and a second, organic carboxylic acid including 3 to 6 carbons and at least one carboxyl group including, but not limited to, at least one of maleic acid, malonic acid, glutaric acid, aconic acid, citraconic acid, citric acid, and carballylic acid.
  • the second carboxylic acid may exhibit a relatively smaller chain length that the di- or tri-carboxyl ic acid.
  • the second carboxylic acids have a chain length similar in size or greater than that of the first carboxylic acid.
  • the complexation reaction may be completed through microwave radiation and/or ultrasonic-dispersion/mechanical agitation.
  • the reaction may take place at temperatures of 20 °C to 70 °C, including all values and ranges therein.
  • the sample reaction includes the amino-amide 114 of the first step 102 and maleic acid 116 resulting in the viscosifier 118.
  • the amino-amide is present in the reaction mixture in the range of 10 to 25 weight percent of the total reaction mixture, including all values and ranges therein, and the second carboxylic acid is present in the range of 80 to 90 weight percent, including all values and ranges therein.
  • the weight ratio of the second carboxylic acid, if a dicarboxylic acid, to the amino-amide is 1 to 5. In another aspect, the weight ratio of the second carboxylic acid, if a tricarboxylic acid, to the amino-amide is 1 to 4.
  • the resulting viscosifier may then be added to the aqueous solution of the injection fluid and mixed at temperatures in the range of 20 °C to 70 °C, including all values and ranges therein, such that the viscosifier is present in the range of 0.2 to 5.0 % by weight of the total injection fluid.
  • the characteristics of the viscosifiers, and thereby the injection fluids can be tailored for a particular formation.
  • Variable characteristics of a formation include pH level and the viscosity of the crude oil among others.
  • Static gelling strength (i.e. , viscosity) of the obtained solution is measured via a viscometer and a rheometer. The effect of temperature and shear stress on the properties of the solution is also tested by rheometry.
  • the viscosifier solution is synthesized using a foundation molecule (FM) 130, being the product of the complexation reaction from step 104 of FIGS. 3 and 4, and an activator molecule (AM) 132.
  • the FM is preferably a long chained organic molecule having at least 6 carbon atoms 134 and interaction sites 136.
  • the AM is a multi-functional organic molecule that can interact with the FM through non-permanent forces such as van der Waals, electrostatic, hydrogen bond, and dipole interaction to a different degree given varying conditions.
  • the varying conditions or stimuli 138 include, but is not limited to, pH, temperature, pressure, light, sound, magnetic, electric, and chemical environment.
  • the stimulus is a pH modifier and, in particular, a base or acid.
  • the pH modifier may be a base, such as NaOFI/Water solution and added in an amount such that the pH is in the range of 6 to greater, including all values and ranges therein, such as 6 to 9 and in further aspects from 7.5 to 8. It may be appreciated that some environments into which the injection fluid is introduced into an already basic and additions to increase pH is not necessary.
  • micro-emulgents or microspheres including a basic additive that is released when pressure on the fluid reaches a given level may be added to the injection fluid.
  • the pH may be adjusted to a pH in the range of less than 6, including all values and ranges therein, such as a pH from 4 to 5.
  • the conditions can be controlled or altered to change the strength of the FM/AM interaction to form or deform the assemblies of FM and AM that will result in a desired change in viscosity.
  • the non- permanent forces 40 are established between the interaction sites 136 and can be altered in response to specific stimuli 138.
  • a first step is a condensation reaction 158 of an amine organic building block 160 with a long chain acid 162 under an inert gas environment provides the FM 150.
  • the long chain acid 162 may be one of an arachidic acid, palmitic acid, pentadecylic acid, palm oil, coconut oil, corn oil, avocado oil, and lauric acid.
  • other long chain acids, oils or mixture of oils may be considered without departing from the scope of the invention.
  • the diamine organic building block 160 may be one of N- lsopropyl-1 ,3- propanediamine, N,N'-Diethyl-2-butene-1 ,4-diamine, N,N- Dimethylethylenediamine, and N,N'-Dimethyl-1 ,2-ethanediamine.
  • other reactants of the diamine organic building block or any organic molecule possessing more than one amine groups with at least one primary/secondary amine may be used without departing from the scope of the invention.
  • the combinations for diamines can include primary-primary, primary-secondary, secondary-secondary, primary-tertiary, and secondary-tertiary pairs of amines.
  • multi amine molecules consisting any combinations with at least one primary/secondary amine.
  • the obtained FM 150 is mixed vigorously in water with AM 152 in weight ratios ranging from 0.01 to 5 wt% of FM 150 to AM 152 to form a complexation via heat and/or ultrasonic dispersion/mechanical agitation.
  • the AM 152 may include but is not limited to organic molecules having multiple carboxylic acid groups such as maleic acid, malonic acid, glutaric acid, aconic acid, citraconic acid, citric acid, and carballylic acid.
  • the amount of the organic compound in water can be adjusted to attain a desired concentration.
  • the viscosity may be altered by varying pH 164 and temperature 166.
  • the self-healing behavior is exhibited when subjected to high shear and temperature 166.
  • the stimuli- responsive solution can reversibly tune the viscosity of the injection fluid nearly two orders of magnitude at concentrations as low as 1 % in weight but could need upwards of 5 wt.% depending on the application.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Detergent Compositions (AREA)

Abstract

L'invention concerne des agents gélifiants s'autoassemblant (agents améliorant l'indice de viscosité intelligents) qui sont incorporés dans des fluides d'injection destinés à être utilisés en récupération de pétrole brut et de gaz naturel à partir de gisements souterrains et de dépôts de schiste. L'agent améliorant l'indice de viscosité comprend un amide aminé complexé avec un second acide carboxylique, l'amide aminé comprenant un produit de réaction de condensation d'une amine et d'un premier acide carboxylique, l'amine comprenant 4 à 6 atomes de carbone et étant au moins l'une d'une diamine et d'une triamine, le premier acide carboxylique comprenant 8 à 20 atomes de carbone et étant au moins l'un d'un acide dicarboxylique ou d'un acide tricarboxylique et le second acide carboxylique comprenant 3 à 6 atomes de carbone.
PCT/US2019/027243 2018-04-12 2019-04-12 Systèmes de gélification s'autoassemblant adaptatifs Ceased WO2019200269A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201862656625P 2018-04-12 2018-04-12
US62/656,625 2018-04-12

Publications (1)

Publication Number Publication Date
WO2019200269A1 true WO2019200269A1 (fr) 2019-10-17

Family

ID=68164614

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2019/027243 Ceased WO2019200269A1 (fr) 2018-04-12 2019-04-12 Systèmes de gélification s'autoassemblant adaptatifs

Country Status (1)

Country Link
WO (1) WO2019200269A1 (fr)

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2304369A (en) * 1940-08-03 1942-12-08 Arnold Hoffman & Co Inc Condensation product
US20020094943A1 (en) * 2001-01-16 2002-07-18 Goldschmidt Chemical Company Blend of imidazolinium quat and amido amine quat for use in fabric softeners with premium softening, high-viscosity at low-solids and non-yellowing properties
US20080273925A1 (en) * 2007-05-04 2008-11-06 Borden Robert C In situ pH adjustment for soil and groundwater remediation
US8772211B2 (en) * 2009-07-08 2014-07-08 The Lubrizol Corporation Polymer blends useful as viscosity modifiers

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2304369A (en) * 1940-08-03 1942-12-08 Arnold Hoffman & Co Inc Condensation product
US20020094943A1 (en) * 2001-01-16 2002-07-18 Goldschmidt Chemical Company Blend of imidazolinium quat and amido amine quat for use in fabric softeners with premium softening, high-viscosity at low-solids and non-yellowing properties
US20080273925A1 (en) * 2007-05-04 2008-11-06 Borden Robert C In situ pH adjustment for soil and groundwater remediation
US8772211B2 (en) * 2009-07-08 2014-07-08 The Lubrizol Corporation Polymer blends useful as viscosity modifiers

Non-Patent Citations (3)

* Cited by examiner, † Cited by third party
Title
CHEN, I ET AL.: "Use of pH-responsive amphiphilic systems as displacement fluids in enhanced oil recovery", SPE JOURNAL, vol. 19, no. 6, 1 December 2014 (2014-12-01), pages 1035 - 1046, XP055644524 *
HAO, L ET AL.: "Thermo-responsive gels based on supramolecular assembly of an amidoamine and citric acid", SOFT MATTER, vol. 14, no. 3, 1 January 2018 (2018-01-01), pages 432 - 439, XP055644516 *
YEGIN, C ET AL.: "Novel Hydraulic Fracturing Fluids with Improved Proppant Carrying Capacity and pH-Adjustable Proppant Deposition Behavior", JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, vol. 145, 21 June 2016 (2016-06-21), pages 600 - 608, XP029672076 *

Similar Documents

Publication Publication Date Title
US10590324B2 (en) Fiber suspending agent for lost-circulation materials
AU2013404976B2 (en) Methods for enhancing propped fracture conductivity
El-Karsani et al. Polymer systems for water shutoff and profile modification: a review over the last decade
Zhang et al. Preformed-particle-gel transport through open fractures and its effect on water flow
AU2013215081B2 (en) Cellulose nanowhiskers in well services
US8082994B2 (en) Methods for enhancing fracture conductivity in subterranean formations
US20090308599A1 (en) Method of enhancing treatment fluid placement in shale, clay, and/or coal bed formations
CN107686723B (zh) 一种co2响应就地凝胶封窜溶胶及其制备方法与应用
CN111394086B (zh) 一种环保节水型压裂液的制备方法
AU2012299397A1 (en) Fracturing process to enhance propping agent distribution to maximize connectivity between the formation and the wellbore
Chen et al. Preparation and performance of high-temperature-resistant, degradable inorganic gel for steam applications
US9617458B2 (en) Parylene coated chemical entities for downhole treatment applications
CN106958438B (zh) 一种聚合物驱堵塞井的解堵方法
Yang et al. High-Temperature, Salt-Resistant, and High-Strength-Controlled Consolidated Resin Slurry for Fracture Plugging during Oil and Gas Well Drilling
Jia et al. Solid-free flexible colloidal completion fluid with variable density for gas well completion in high-temperature and high-pressure reservoirs: Experimental study and pilot test
AL-Obaidi et al. Improvement of oil recovery in hydrocarbon fields by developing polymeric gel-forming composition
Zhao et al. Using associated polymer gels to control conformance for high temperature and high salinity reservoirs
Sun et al. Application of Thickeners in Supercritical Carbon Dioxide EOR and Fracturing: A Review
Guzmán-Lucero et al. Water control with gels based on synthetic polymers under extreme conditions in oil wells
WO2019200269A1 (fr) Systèmes de gélification s'autoassemblant adaptatifs
SH IMPROVEMENT OF OIL RECOVERY IN HYDROCARBON FIELDS BY DEVELOPING POLYMERIC GEL-FORMING COMPOSITION.
US11866644B1 (en) Fracturing fluid based on oilfield produced fluid
CN119463822A (zh) 一种油基钻井液用抗高温提粘剂及其制备方法
Zhai Comprehensive Evaluation of Novel Medium-Temperature and High-Temperature Resistant Re-Crosslinkable Preformed Particle Gels for Conformance Control
WO2016201013A1 (fr) Auxiliaire de fracturation

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 19784431

Country of ref document: EP

Kind code of ref document: A1

DPE1 Request for preliminary examination filed after expiration of 19th month from priority date (pct application filed from 20040101)
NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 19784431

Country of ref document: EP

Kind code of ref document: A1