EP2134803A1 - Procédé et système de traitement de formations d'hydrocarbures - Google Patents

Procédé et système de traitement de formations d'hydrocarbures

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Publication number
EP2134803A1
EP2134803A1 EP07870111A EP07870111A EP2134803A1 EP 2134803 A1 EP2134803 A1 EP 2134803A1 EP 07870111 A EP07870111 A EP 07870111A EP 07870111 A EP07870111 A EP 07870111A EP 2134803 A1 EP2134803 A1 EP 2134803A1
Authority
EP
European Patent Office
Prior art keywords
brine
hydrocarbon
composition
fluid
model
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.)
Withdrawn
Application number
EP07870111A
Other languages
German (de)
English (en)
Other versions
EP2134803A4 (fr
Inventor
Gary A. Pope
Jimmie R. BARAN Jr.
Vishal Bang
Mukul M. Sharma
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.)
3M Innovative Properties Co
University of Texas System
Original Assignee
3M Innovative Properties Co
University of Texas System
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 3M Innovative Properties Co, University of Texas System filed Critical 3M Innovative Properties Co
Publication of EP2134803A1 publication Critical patent/EP2134803A1/fr
Publication of EP2134803A4 publication Critical patent/EP2134803A4/fr
Withdrawn legal-status Critical Current

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/04—Aqueous well-drilling compositions
    • C09K8/14—Clay-containing compositions
    • C09K8/18—Clay-containing compositions characterised by the 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
    • C09K8/58—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

Definitions

  • brine is present in hydrocarbon-bearing geological formations in the vicinity of the wellbore (also known in the art as the "near wellbore region").
  • the brine may be naturally occurring (e.g., connate water) and/or may be a result of operations conducted on the well.
  • liquid hydrocarbons also known in the art as "condensate"
  • condensate liquid hydrocarbons
  • the presence of condensate can cause a large decrease in both the gas and condensate relative permeabilities, and thus the productivity of the well decreases.
  • brine and/or gas condensate in a near wellbore region of a hydrocarbon-bearing geological formation can inhibit or stop production of hydrocarbons from the well, and hence is typically undesirable.
  • One approach involves a fracturing and propping operation (e.g., prior to, or simultaneously with, a gravel packing operation) to increase the permeability of the hydrocarbon-bearing geological formation adjacent to the wellbore.
  • Chemical treatments e.g., injection of methanol
  • the latter treatments are typically injected into the near wellbore region of a hydrocarbon- bearing geological formation where they interact with the brine and/or condensate to displace and/or dissolve it, thereby facilitating increased hydrocarbon production from the well.
  • the present invention provides a method of treating a hydrocarbon-bearing formation having brine and at least one temperature, wherein the brine has at least one first composition
  • the method comprising: obtaining first compatibility information for a first model brine and a first treatment composition at a model temperature, wherein the first model brine has a composition selected at least partially based on the first brine composition, wherein the model temperature is selected at least partially based on the formation temperature, and wherein the first treatment composition comprises at least one first surfactant and at least one first solvent; based at least partially on the first compatibility information, selecting a treatment method for the hydrocarbon-bearing formation, wherein the treatment method is Method I or Method II, wherein Method I comprises: contacting the hydrocarbon-bearing formation with a fluid, wherein the fluid at least one of at least partially solubilizes or at least partially displaces the brine in the hydrocarbon-bearing formation; and subsequently contacting the hydrocarbon-bearing formation with the first treatment composition; and wherein Method
  • the first compatibility information indicates that the first model brine and the first treatment composition are at least partially incompatible. In some embodiments, the compatibility information indicates that the first model brine and the first treatment composition are compatible, and wherein the second treatment composition has the same composition as the first treatment composition. In some embodiments, the first compatibility information comprises information concerning the phase stability of a mixture of the first model brine and the first treatment composition. In some embodiments, the compatibility information comprises information concerning salt precipitation from a mixture of the first model brine and the first treatment composition. In some embodiments, the at least one of the first surfactant or the second surfactant is a nonionic fluorinated polymeric surfactant.
  • the surfactant is a nonionic fluorinated polymeric surfactant comprises: at least one divalent unit represented by formula:
  • R f represents a perfluoroalkyl group having from 1 to 8 carbon atoms;
  • R, Ri 1 and R 2 are each independently hydrogen or alkyl of 1 to 4 carbon atoms;
  • n is an integer from 2 to 10;
  • EO represents -CH 2 CH 2 O-; each PO independently represents -CH(CHs)CH 2 O- or
  • each p is independently an integer of from 1 to about 128; and each q is independently an integer of from 0 to about 55.
  • the fluid is essentially free of surfactant.
  • the fluid comprises at least one of toluene, diesel, heptane, octane, or condensate.
  • the fluid comprises at least one of a polyol or polyol ether, wherein the polyol and polyol ether independently have from 2 to 25 carbon atoms.
  • the polyol or polyol ether is at least one of 2-butoxyethanol, ethylene glycol, propylene glycol, poly(propylene glycol), 1,3 -propanediol, 1,8-octanediol, diethylene glycol monomethyl ether, ethylene glycol monobutyl ether, or dipropylene glycol monomethyl ether.
  • the fluid further comprises at least one monohydroxy alcohol, ether, or ketone independently having from 1 to 4 carbon atoms.
  • the fluid comprises at least one of water, methanol, ethanol, or isopropanol.
  • the fluid comprises at least one of nitrogen, carbon dioxide, or methane.
  • the at least one of the first solvent or the second solvent comprises at least one of a polyol or polyol ether, wherein the polyol and polyol ether independently have from 2 to 25 carbon atoms; and wherein the solvent comprises at least one of monohydroxy alcohol, ether, or ketone independently having from 1 to 4 carbon atoms.
  • the hydrocarbon bearing formation is clastic or nonclastic.
  • the first compatibility information is represented in a contour map that can pictorially depict the phase behavior relationships between system variables (e.g., temperature, solvent composition, and brine concentration).
  • Method I further comprises: obtaining second compatibility information for a second model brine and the first treatment composition at the model temperature, wherein the second model brine has a composition selected at least partially based on the second brine composition, and wherein the second compatibility information indicates that the first treatment composition and the second model brine are compatible.
  • the present invention provides a method of treating a hydrocarbon-bearing formation having brine and at least one temperature, wherein the brine has at least one first composition
  • the method comprising: obtaining first compatibility information for a first model brine and a treatment composition at a model temperature, wherein the first model brine has a composition selected at least partially based on the first brine composition, wherein the model temperature is selected at least partially based on the formation temperature, wherein the treatment composition comprises at least one surfactant and at least one solvent, and wherein the first compatibility information indicates that the treatment composition and the first model brine are at least partially incompatible; contacting the hydrocarbon-bearing formation with a fluid, wherein the fluid at least one of at least partially solubilizes or at least partially displaces the brine in the hydrocarbon- bearing formation, and wherein after the fluid contacts the hydrocarbon-bearing formation, the formation has a second brine composition; obtaining second compatibility information for a second model brine and the treatment composition at the model temperature, where
  • the surfactant is a nonionic fluorinated polymeric surfactant, comprising: at least one divalent unit represented by formula:
  • R f represents a perfluoroalkyl group having from 1 to 8 carbon atoms
  • R, Ri, and R 2 are each independently hydrogen or alkyl of 1 to 4 carbon atoms; n is an integer from 2 to 10; EO represents -CH 2 CH 2 O-; each PO independently represents -CH(CH 3 )CH 2 O- or
  • each p is independently an integer of from 1 to about 128; and each q is independently an integer of from 0 to about 55.
  • Fig. 1 is a schematic illustration of an exemplary embodiment of an offshore oil and gas platform operating an apparatus for treating a near wellbore region according to the present invention
  • Fig. 2 shows the near wellbore region with a fracture in greater detail (for those embodiments related to a fractured formation); and Fig. 3 is a schematic illustration of the core flood set-up to testing cores samples and other materials using the compositions and methods of the present invention.
  • water refers to water having at least one dissolved electrolyte salt therein (e.g., having any nonzero concentration, and which may be less than 1000 parts per million by weight (ppm), or greater than 1000 ppm, greater than 10,000 ppm, greater than 20,000 ppm, 30,000 ppm, 40,000 ppm, 50,000 ppm, 100,000 ppm, 150,000 ppm, or even greater than 200,000 ppm).
  • downhole conditions refers to the temperature, pressure, humidity, and other conditions that are commonly found in subterranean formations.
  • brine composition refers to the types of dissolved electrolytes and their concentrations in brine.
  • homogeneous means macroscopically uniform throughout and not prone to spontaneous macroscopic phase separation.
  • hydrocarbon-bearing formation includes both hydrocarbon-bearing formations in the field (i.e., subterranean hydrocarbon-bearing formations) and portions of such hydrocarbon- bearing formations (e.g., core samples).
  • fracture refers to a fracture that is man-made. In the field, for example, fractures are typically made by injecting a fracturing fluid into a subterranean geological formation at a rate and pressure sufficient to open a fracture therein (i.e., exceeding the rock strength).
  • hydrolyzable silane group refers to a group having at least one Si-O-Z moiety that undergoes hydrolysis with water at a pH between about 2 and about 12, wherein Z is H or substituted or unsubstituted alkyl or aryl.
  • ionic groups e.g., salts
  • normal boiling point refers to the boiling point at a pressure of one atmosphere (100 kPa).
  • polymer refers to a molecule of molecular weight of at least 1000 grams/mole, the structure of which includes the multiple repetition of units derived, actually or conceptually, from molecules of low relative molecular mass.
  • polymeric refers to including a polymer
  • solvent refers to a homogenous liquid material (inclusive of any water with which it may be combined) that is capable of at least partially dissolving the nonionic fluorinated polymeric surfactant(s) with which it is combined at 25 0 C.
  • water-miscible means soluble in water in all proportions.
  • composition information refers to information concerning the phase stability of a solution or dispersion.
  • productivity and “productivity information” as applied to a well refers to the capacity of a well to produce hydrocarbons; that is, the ratio of the hydrocarbon flow rate to the pressure drop, where the pressure drop is the difference between the average reservoir pressure and the flowing bottom hole well pressure (i.e., flow per unit of driving force).
  • cloud point of a surfactant refers to the temperature at which a nonionic surfactant becomes non-homogeneous in water. This temperature can depend on many variables (e.g., surfactant concentration, solvent concentration, solvent composition, water concentration, electrolyte composition and concentration, oil phase concentration and composition, and the presence of other surfactants).
  • substantially free of precipitated salt refers to the amount of salts found in water under downhole conditions that precipitates.
  • substantially free of precipitated salt is an amount of salt that is the less than 5% higher than the solubility product at a given temperature and pressure.
  • a formation becomes substantially free of precipitated salt when the amount of salt in the formation has been reduced, dissolved or displaced such that the salts do not interfere with the interaction (e.g., adsorption) of the nonionic fluorinated polymeric surfactant with the formation.
  • the term "essentially free of surfactant” refers to fluid that may have a surfactant in an amount insufficient for the fluid to have a cloud point, e.g., when it is below its critical micelle concentration.
  • a fluid that is essentially free of surfactant may be a fluid that has a surfactant but in an amount insufficient to alter the wettability of, e.g., a hydrocarbon-bearing formation under downhole conditions.
  • a fluid that is essentially free of surfactant includes those that have a weight percent of surfactant as low as 0 weight percent.
  • the present invention includes the use of compatibility information to determine compositions and methods for removing water from the near-wellbore portion of a hydrocarbon-bearing formation and penetrated by a wellbore, and more particularly, to the use of treatment compositions to improve well productivity.
  • formations that may be treated using the present invention include dry gas reservoirs, wet gas reservoirs, retrograde condensate gas reservoirs, tight gas reservoirs, gas storage reservoirs and combinations thereof.
  • surfactants that may be useful in methods according to the present invention include anionic surfactants, cationic surfactants, nonionic surfactants, amphoteric surfactants (e.g., zwitterionic surfactants), and combinations thereof. Many of each type of surfactant are widely available to one skilled in the art.
  • surfactants include fluorochemical, silicone and hydrocarbon-based surfactants.
  • Useful surfactants that may be used to treat clastic formations may include cationic, anionic, nonionic, amphoteric (e.g., zwitterionic surfactants).
  • Non-clastic formations may be treated with anionic, amphoteric (e.g., zwitterionic surfactants).
  • alkylammonium salts having the formula C 1 H 21+I N(CHs) 3 X, where X is, e.g., OH, Cl, Br, HSO 4 or a combination of OH and Cl, and where r is an integer from 8 to 22, and the formula C S H S + JN(C 2 Hs) 3 X, where s is an integer from 12 to
  • gemini surfactants for example, those having the formula: [Ci 6 H 33 N(CH 3 ) 2 C t H 2t+ i]X, wherein t is an integer from 2 to 12 and X is, e.g., OH, Cl, Br, HSO 4 or a combination of OH and Cl; aralkylammonium salts (e.g., benzalkonium salts); and cetylethylpiperidinium salts, for example, CIeH 33 N(C 2 H 5 )(CsHi 0 )X, wherein X is, e.g., OH, Cl, Br, HSO 4 or a combination of OH and Cl.
  • gemini surfactants for example, those having the formula: [Ci 6 H 33 N(CH 3 ) 2 C t H 2t+ i]X, wherein t is an integer from 2 to 12 and X is, e.g., OH, Cl, Br, HSO 4 or a combination of
  • amphoteric surfactants include alkyldimethyl amine oxides, alkylcarboxamidoalkylenedimethyl amine oxides, aminopropionates, sulfobetaines, alkyl betaines, alkylamidobetaines, dihydroxyethyl glycinates, imidazoline acetates, imidazoline propionates, ammonium carboxylate and ammonium sulfonate amphoterics and imidazoline sulfonates.
  • hydrocarbon nonionic surfactants include polyoxyethylene alkyl ethers, polyoxyethylene alkyl-phenyl ethers, polyoxyethylene acyl esters, sorbitan fatty acid esters, polyoxyethylene alkylamines, polyoxyethylene alkylamides, polyoxyethylene lauryl ethers, polyoxyethylene cetyl ethers, polyoxyethylene stearyl ethers, polyoxyethylene oleyl ether, polyoxyethylene octylphenyl ethers, polyoxyethylene nonylphenyl ethers, polyethylene glycol laurates, polyethylene glycol stearates, polyethylene glycol distearates, polyethylene glycol oleates, oxyethylene-oxypropylene block copolymer, sorbitan laurate, sorbitan stearate, sorbitan distearate, sorbitan oleate, sorbitan sesquioleate, sorbitan trioleate, polyoxyethylene sorbitan laur
  • nonionic surfactants also include nonionic fluorinated surfactants.
  • nonionic fluorinated surfactants such as those marketed under the trade designation "ZONYL” (e.g., ZONYL FSO) by E. I. du Pont de Nemours and Co., Wilmington, DE.
  • Nonionic fluorinated polymeric surfactants such as, may also be used.
  • the nonionic fluorinated polymeric surfactant comprises: (a) at least one divalent unit represented by the formula:
  • R f represents a perfluoroalkyl group having from 1 to 8 carbon atoms.
  • exemplary groups R f include perfluoromethyl, perfluoroethyl, perfluoropropyl, perfluorobutyl (e.g., perfluoro-n- butyl or perfluoro-sec-butyl), perfluoropentyl, perfluorohexyl, perfluoroheptyl, and perfluorooctyl.
  • R, Ri, and R 2 are each independently hydrogen or alkyl of 1 to 4 carbon atoms (e.g., methyl, ethyl, n-propyl, isopropyl, butyl, isobutyl, or t-butyl).
  • n is an integer from 2 to 10.
  • EO represents -CH 2 CH 2 O-.
  • PO represents -CH(CH 3 )CH 2 O- or -CH 2 CH(CH 3 )O-.
  • Each p is independently an integer of from 1 to about 128.
  • Each q is independently an integer of from 0 to about 55.
  • Useful nonionic fluorinated polymeric surfactants typically have a number average molecular weight in the range of from 1,000 to 10,000 grams/mole, 20,000 grams/mole, or even 30,000 grams/mole, although higher and lower molecular weights may also be used.
  • nonionic fluorinated polymeric surfactants may be prepared by techniques known in the art, including, for example, by free radical initiated copolymerization of a nonafluorobutanesulfonamido group-containing acrylate with a poly(alkyleneoxy) acrylate (e.g., monoacrylate or diacrylate) or mixtures thereof. Adjusting the concentration and activity of the initiator, the concentration of monomers, the temperature, and the chain-transfer agents can control the molecular weight of the polyacrylate copolymer. The description of the preparation of such polyacrylates is described, for example, in U.S. Pat. No. 3,787,351 (Olson).
  • Methods described above for making nonafluorobutylsulfonamido group-containing structures can be used to make heptafluoropropylsulfonamido groups by starting with heptafluoropropylsulfonyl fluoride, which can be made, for example, by the methods described in Examples 2 and 3 of U.S. Pat. No. 2,732,398 (Brice et al.), the disclosure of which is incorporated herein by reference.
  • the hydrocarbon-bearing clastic formation has at least one fracture.
  • the fracture has a plurality of proppants therein.
  • Fracture proppant materials are typically introduced into the formation as part of a hydraulic fracture treatment.
  • Exemplary proppants known in the art include those made of sand (e.g., Ottawa, Brady or Colorado Sands, often referred to as white and brown sands having various ratios), resin-coated, sintered bauxite, ceramics (i.e., glasses, crystalline ceramics, glass-ceramics, and combinations thereof), thermoplastics, organic materials (e.g., ground or crushed nut shells, seed shells, fruit pits, and processed wood), and clay.
  • Sand proppants are available, for example, from Badger Mining Corp., Berlin, WI; Borden Chemical, Columbus, OH; and Fairmont Minerals, Chardon, OH.
  • Thermoplastic proppants are available, for example, from the Dow Chemical Company, Midland, MI; and BJ Services, Houston, TX.
  • Clay-based proppants are available, for example, from CarboCeramics, Irving, TX; and Saint-Gobain, Courbevoie, France.
  • Sintered bauxite ceramic proppants are available, for example, from Borovichi Refractories, Borovichi, Russia; 3M Company, St. Paul, MN; CarboCeramics; and Saint Gobain.
  • Glass bubble and bead proppants are available, for example, from Diversified Industries, Sidney, British Columbia, Canada; and 3M Company.
  • the proppants form packs within a formation and/or wellbore.
  • Proppants may be selected to be chemically compatible with the fluids and compositions described herein.
  • Particulate solids may be introduced into the formation, for example, as part of a hydraulic fracture treatment, sand control particulate introducible into the wellbore/formation as part of any sand control treatment such as a gravel pack or frac pack.
  • surfactants useful in practicing the present invention may interact with at least a portion of the plurality of proppants, (i.e., change the wettability of the proppants).
  • Some surfactants may interact with the plurality of proppants, for example, by adsorbing to the surfaces of the proppants (in either clastic or non-clastic formations).
  • Methods of determining the interaction of surfactants with proppants include the measurement of the conductivity of the fracture.
  • surfactants useful in practicing the present invention modify the wetting properties of the rock in a near wellbore region of a hydrocarbon-bearing formation (in some embodiments, in a fracture). Although not wanting to be bound by theory, it is believed the surfactants generally adsorb to formations under downhole conditions.
  • surfactants generally adsorb to the surfaces of proppants and the rock surface in hydrocarbon-bearing formations and typically remain at the target site for the duration of an extraction (e.g., 1 week, 2 weeks, 1 month, or longer).
  • organic solvents examples include organic solvents, water, and combinations thereof.
  • organic solvents include polar and/or water-miscible solvents such as monohydroxy alcohols independently having from 1 to 4 or more carbon atoms (e.g., methanol, ethanol, isopropanol, propanol, and butanol); polyols such as, for example, glycols (e.g., ethylene glycol or propylene glycol), terminal alkanediols (e.g., 1,3-propanediol, 1 ,4-butanediol, 1 ,6-hexanediol, or 1,8-octanediol), polyglycols (e.g., diethylene glycol, Methylene glycol, or dipropylene glycol) and triols (e.g., glycerol, trimethylolpropane); ethers (e.g., diethyl ether, methyl t-
  • the various model brines and treatment compositions used herein may be prepared by any suitable method including, manually or mechanically shaking and/or stirring the various components thereof.
  • Information concerning the temperature and brine composition of a hydrocarbon-bearing formation is typically obtained by measurement of the pertinent condition(s) in or near a wellbore located at a particular geological zone of interest in a hydrocarbon-bearing formation. Suitable measurement methods are known to the skilled artisan. In some, instances further manipulation of data (e.g., computer calculations) obtained from hydrocarbon-bearing formation may be useful, and such manipulation is within the scope of the present invention.
  • the compatibility information (i.e., the first and/or second compatibility information) may be generated by various methods including, computer simulation, physical measurements or a combination thereof.
  • the compatibility information may be as small as a single set element (e.g., a measurement of compatibility between the surfactant-solvent formulation and the brine and optionally condensate at a given temperature), or it may contain any higher number of set elements.
  • the choice of surfactant- solvent formulations and temperatures to be studied and the results included within the compatibility information will be apparent to the skilled artisan performing the method (but not a requirement) in light of the present disclosure.
  • One convenient method of evaluating compatibility involves combining (e.g., in a container) a model brine and optionally model condensate with a surfactant-solvent formulation (i.e., treatment composition) at a given temperature, and then mixing the model brine and optionally model condensate with the surfactant-solvent formulation (i.e., treatment composition).
  • the mixture is evaluated over time (e.g., 5 minutes, 1 hour, 12 hours, 24 hours or longer) to see if it phase separates or becomes cloudy.
  • model brine and optionally model condensate and the surfactant-solvent formulation By adjusting the relative amounts of model brine and optionally model condensate and the surfactant-solvent formulation, it is possible to determine the maximum brine and/or condensate uptake capacity (above which phase separation occurs) of the surfactant-solvent formulation at a given temperature. Varying the temperature at which the above procedure is carried out typically results in a more complete understanding of the suitability of surfactant solvent formulations as treatment compositions for a given well.
  • first and second compatibility information may be obtained either simultaneously or sequentially and in either order.
  • the treatment composition is typically selected to be homogenous at temperature(s) found in the portion of hydrocarbon-bearing formation (e.g., a near well bore region) to be treated.
  • Fluids (including liquids and gases) useful in practicing the present invention at least one of at least partially solubilizes or at least partially displaces the brine in the hydrocarbon-bearing clastic formation.
  • the fluid at least partially displaces the brine in the hydrocarbon-bearing clastic formation.
  • the fluid at least partially solubilizes brine in the hydrocarbon-bearing clastic formation.
  • the brine may be connate or non-connate water, mobile (e.g., crossflow) or immobile (e.g., residual) water, naturally occurring water or water resulting from operations on the formation (e.g., water from aqueous drilling fluids or aqueous fracturing fluids).
  • the brine is connate water.
  • useful fluids include polar and/or water-miscible solvents such as monohydroxy alcohols having from 1 to 4 or more carbon atoms (e.g., methanol, ethanol, isopropanol, propanol, or butanol); polyols such as glycols (e.g., ethylene glycol or propylene glycol), terminal alkanediols (e.g., 1,3-propanediol, 1 ,4-butanediol, 1,6-hexanediol, or 1,8-octanediol), polyglycols (e.g., diethylene glycol, triethylene glycol, or dipropylene glycol) and triols (e.g., glycerol, trimethylolpropane); ethers (e.g., diethyl ether, methyl t-butyl ether, te
  • Useful fluids also include liquid or gaseous hydrocarbons (e.g., toluene, diesel, heptane, octane, condensate, methane, and isoparaffmic solvents obtained from Total Fina, Paris, France, under trade designation “ISANE” and from Exxon Mobil Chemicals, Houston, TX, under the trade designation "ISOPAR”) and other gases (e.g., nitrogen and carbon dioxide).
  • ISANE e.g., toluene, diesel, heptane, octane, condensate, methane, and isoparaffmic solvents obtained from Total Fina, Paris, France, under trade designation “ISANE” and from Exxon Mobil Chemicals, Houston, TX, under the trade designation "ISOPAR”
  • other gases e.g., nitrogen and carbon dioxide
  • a fluid may be used to treat the formation prior to contacting the formation.
  • Method I is selected.
  • the fluid amount and type is selected so that it at least one of solubilizes or displaces a sufficient amount of brine in the formation.
  • the fluid amount and type may be selected so that it at least one of solubilizes or displaces a sufficient amount of brine in the formation such that when the composition is added to the formation, the surfactant has a cloud point that is above at least one temperature found in the formation.
  • the fluid amount and type is selected so that it at least one of solubilizes or displaces a sufficient amount of brine in the formation such that when the composition is contacting the formation, the formation is substantially free of precipitated salt.
  • Method II is selected, and the second treatment composition has the same composition as the first treatment composition.
  • a treatment method and/or composition is chosen based at least in part on the compatibility information.
  • a treatment composition is chosen that closely resembles, or is identical to, a surfactant-solvent formulation from the compatibility information set, but this is not a requirement.
  • cost, availability, regulations, flammability, and environmental concerns may influence the specific choice of treatment composition for use in testing and/or commercial production.
  • a contour map can be created in multiple dimensions plotting selected variables against one another.
  • the variables to choose from can include, but are not limited to: temperature, brine concentration, total water concentration, alcohol content, condensate concentration, solvents, other chemical components, etc.
  • a map can be created that plots brine concentration vs. total water concentration on the x and y axes, vs. temperature on the z-axis.
  • the user can plot the phase behavior of a particular solvent composition in three-dimensions, identifying such areas in phase space where, for example, there is a single phase system, salt precipitates and where the surfactant is insoluble. Multiple solvent combinations could be plotted on the same graph and may be done so in an automated manner depending on the data sources.
  • the data can be to plot water concentration vs. weight percent alcohol concentration in a particular formulation on the x and y axes, then plot vs. temperature on the z-axis. In this instance, the user plots the different brine concentrations on one plot.
  • a contour map the skilled artisan will be able to determine whether a preflush would be needed or not, if a particular solvent combination could be used under those conditions or what the options for the composition based on additional variables, such as flashpoint. In fact, the maps also allow the user to determine if and which core tests might not be needed.
  • the treatment compositions and methods may be further evaluated; for example, by injection into a specimen (e.g., a core sample) taken from a particular geological zone to be treated, or a closely similar specimen.
  • a specimen e.g., a core sample
  • This may be performed in a laboratory environment using conventional techniques such as, for example, those described by Kumar et al. in "Improving the Gas and Condensate Relative Permeability Using Chemical Treatments", paper SPE 100529, presented at the 2006 SPE Gas Technology Symposium held in Calgary, Alberta, Canada, 15-17 May 2006.
  • the solvent in a first and/or second treatment composition
  • the solvent is generally capable of solubilizing and/or displacing brine and/or condensate in the formation.
  • brine include connate or non-connate water, mobile or immobile water, naturally occurring water or water resulting from operations on the well and the like.
  • the solvent may be capable of at least one of solubilizing or displacing brine in the formation.
  • the solvent may be, for example, capable of at least one of solubilizing or displacing condensate in the formation.
  • methods according to the present invention are typically useful for treating formations in hydrocarbon-bearing formations containing brine and optionally condensate.
  • compositions and methods described herein for improving the permeability of a particular formation having brine (and/or condensate) therein will typically be determined by the ability of the composition and/or fluid to dissolve the quantity of brine (and/or condensate) present in the formation.
  • greater amounts of compositions and/or fluids having lower brine (and/or condensate) solubility i.e., compositions that can dissolve a relatively lower amount of brine or condensate
  • compositions and/or fluids having higher brine (and/or condensate) solubility containing the same surfactant at the same concentration.
  • compositions useful in practicing the present invention include from at least 0.01, 0.015, 0.02, 0.025, 0.03, 0.035, 0.04, 0.045, 0.05, 0.055, 0.06, 0.065, 0.07, 0.075, 0.08, 0.085, 0.09, 0.095, 0.1, 0.15, 0.2, 0.25, 0.5, 1, 1.5, 2, 3, 4, or 5 percent by weight, up to 5, 6, 7, 8, 9, or 10 percent by weight of the nonionic fluorinated polymeric surfactant, based on the total weight of the composition.
  • the amount of the nonionic fluorinated polymeric surfactant in the compositions may be in a range of from 0.01 to 10; 0.1 to 10, 0.1 to 5, 1 to 10, or even in a range from 1 to 5 percent by weight of the nonionic fluorinated polymeric surfactant, based on the total weight of the composition. Lower and higher amounts of the nonionic fluorinated polymeric surfactant in the compositions may also be used, and may be desirable for some applications.
  • the amount of solvent in the treatment composition typically varies inversely with the amount of components in compositions useful in practicing the present invention.
  • the solvent may be present in the composition in an amount of from at least 10, 20, 30, 40, or 50 percent by weight or more up to 60, 70, 80, 90, 95, 98, or even 99 percent by weight, or more.
  • the treatment compositions useful in practicing the present invention may further include water (e.g., in the solvent).
  • compositions according to the present invention are essentially free of water (i.e., contains less than 0.1 percent by weight of water based on the total weight of the composition).
  • ingredients for treatment compositions described herein including surfactant and solvent can be combined using techniques known in the art for combining these types of materials, including using conventional magnetic stir bars or mechanical mixer (e.g., in-line static mixer and recirculating pump).
  • the amount of the surfactant and solvent (and type of solvent) is dependent on the particular application since conditions typically vary between formations in hydrocarbon-bearing formations, for example, formations at different depths in the formation, and even over time in a given formation.
  • methods according to the present invention can be customized for individual formations and conditions.
  • Methods according to the present invention may be useful, for example, for recovering hydrocarbons (e.g., at least one of methane, ethane, propane, butane, hexane, heptane, or octane) from hydrocarbon-bearing subterranean formations (in some embodiments, predominantly sandstone) or from hydrocarbon-bearing subterranean non- formations (in some embodiments, predominantly limestone).
  • the hydrocarbon-bearing formation comprises at least one of shale, conglomerate, diatomite, sand or sandstone.
  • Method I Method II
  • Method II may be used if a second treatment composition is found that is compatible with the model brine.
  • Method I is selected.
  • an exemplary offshore oil and gas platform is schematically illustrated and generally designated 10.
  • Semi-submersible platform 12 is centered over submerged hydrocarbon-bearing formation 14 located below sea floor 16.
  • Subsea conduit 18 extends from deck 20 of platform 12 to wellhead installation 22 including blowout preventers 24.
  • Platform 12 is shown with hoisting apparatus 26 and derrick 28 for raising and lowering pipe strings such as work string 30.
  • Wellbore 32 extends through the various earth strata including hydrocarbon-bearing formation 14.
  • Casing 34 is cemented within wellbore 32 by cement 36.
  • Work string 30 may include various tools including, for example, sand control screen assembly 38 which is positioned within wellbore 32 adjacent to hydrocarbon-bearing formation 14.
  • fluid delivery tube 40 having fluid or gas discharge section 42 positioned adjacent to hydrocarbon-bearing formation 14, shown with production zone 48 between packers 44, 46.
  • work string 30 and fluid delivery tube 40 are lowered through casing 34 until sand control screen assembly 38 and fluid discharge section 42 are positioned adjacent to the near-wellbore region of hydrocarbon-bearing formation 14 including perforations 50.
  • a composition described herein is pumped down delivery tube 40 to progressively treat the near-wellbore region of hydrocarbon-bearing formation 14.
  • a treatment zone is depicted next to casing 34, cement 36 within perforation 50.
  • fracture 57 is shown in which proppant 60 has been added. Fracture 57 is shown in relation to "crushed zone" 62 and regions surrounding wellbore 32 region showing virgin hydrocarbon-bearing formation 14. Damaged zone 64 has a lower permeability and is shown between virgin hydrocarbon formation 14 and casing 34.
  • compositions and methods for treating a production zone of a wellbore may also be suitable for use in onshore operations.
  • the drawing depicts a vertical well the skilled artisan will also recognize that methods of the present invention may also be useful, for example, for use in deviated wells, inclined wells or horizontal wells.
  • Core flood apparatus 100 used to determine relative permeability of the substrate sample is shown in Fig. 3.
  • Core flood apparatus 100 included positive displacement pumps (Model No. 1458; obtained from General Electric Sensing, Billerica, MA) 102 to inject fluid 103 at constant rate in to fluid accumulators 116.
  • Multiple pressure ports 112 on core holder 108 were used to measure pressure drop across four sections (2 inches (5.1 cm) in length each) of core 109.
  • Pressure port 111 was used to measure the pressure drop across the whole core.
  • Two back-pressure regulators Model No. BPR-50; obtained from Temco, Tulsa, OK
  • 104, 106 were used to control the flowing pressure downstream and upstream, respectively, of core 109.
  • High- pressure core holder (Hassler-type Model UTPT- Ix8-3K- 13 obtained from Phoenix, Houston, TX) 108, back-pressure regulators 106, fluid accumulators 116, and tubing were placed inside pressure -temperature-controlled oven (Model DC 1406F; maximum temperature rating of 650 0 F (343°C) obtained from SPX Corporation, Williamsport, PA) at the temperatures tested.
  • Model DC 1406F maximum temperature rating of 650 0 F (343°C) obtained from SPX Corporation, Williamsport, PA
  • shut-in time after formation in the hydrocarbon-bearing formations are contacted with the compositions described herein.
  • Exemplary set in times include a few hours (e.g., 1 to 12 hours), about 24 hours, or even a few (e.g., 2 to 10) days.
  • hydrocarbons are then obtained from the wellbore at an increased rate, as compared the rate prior to treatment.
  • the fracture has at least one first conductivity prior to contacting the fracture with the composition and at least one second conductivity after contacting the fracture with the composition, and wherein the second conductivity is at least 5 (in some embodiments, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 110, 120, 130, 140, or even 150) percent higher than the first conductivity.
  • Methods according to the present invention may be practiced, for example, in a laboratory environment (e.g., on a core sample (i.e., a portion) of a hydrocarbon-bearing formation) or in the field (e.g., on a subterranean hydrocarbon-bearing formation situated downhole in a well).
  • methods according to the present invention are applicable to downhole conditions having a pressure in a range of from about 1 bar (100 kPa) to about 1000 bars (100 MPa) and a temperature in a range from about 100 0 F (37.8°C) to 400 0 F (204 0 C), although they may be useful to treat hydrocarbon-bearing formations under other conditions.
  • other materials e.g., asphaltene or water
  • Methods according to the present invention may also useful in those cases.
  • Coil tubing may be used to deliver the treatment composition to a particular zone in a hydrocarbon-bearing formation.
  • Nonionic Fluorinated Polymeric Surfactant A was prepared essentially as in Example 4 of U. S. Pat. No. 6,664,354 (Savu), except using 15.6 grams (g) of 50/50 mineral spirits/organic peroxide initiator (tert-butyl peroxy-2-ethylhexanoate obtained from Akzo Nobel, Arnhem, The Netherlands under the trade designation "TRIGONOX-21-C50") in place of 2,2'-azobisisobutyronitrile, and with 9.9 grams of 1-methyl- 2-pyrrolidinone added to the charges.
  • mineral spirits/organic peroxide initiator tert-butyl peroxy-2-ethylhexanoate obtained from Akzo Nobel, Arnhem, The Netherlands under the trade designation "TRIGONOX-21-C50”
  • a core with the dimensions specified below was cut from a source rock block.
  • the core was dried in an oven at 100 0 C for 24 hours and then was weighed.
  • the core was then wrapped with polytetrafluoroethylene (PTFE), aluminum foil and shrink wrapped with heat shrink tubing (obtained under the trade designation "TEFLON HEAT SHRINK TUBING" from Zeus, Inc., Orangeburg, SC).
  • PTFE polytetrafluoroethylene
  • Aluminum foil obtained under the trade designation "TEFLON HEAT SHRINK TUBING" from Zeus, Inc., Orangeburg, SC.
  • the wrapped core was placed into a core holder inside the oven at the experimental temperature.
  • a preflush was conducted using a fluid pre-flush before treating a gas condensate sandstone formation that has high salinity brine and/or high water saturation.
  • the example was performed using a Berea sandstone core at a reservoir temperature of 322°F (161 0 C).
  • the initial gas permeability was measured using nitrogen at 75°F (23.9°C).
  • the initial brine saturation of 30% was established by injecting a measured volume of brine into the vacuumed core.
  • the salinity of brine used was 180,600 ppm. NaCl.
  • the gas relative permeability at initial water saturation was measured using nitrogen at 75°F (23.9°C). Table 1 (below) summarizes the properties of the core and the procedure conditions.
  • a synthetic hydrocarbon mixture was prepared that exhibits retrograde gas condensate behavior.
  • Table 2 (below) gives the composition of the synthetic gas mixture.
  • a two-phase flood with the fluid mixture was done using the dynamic flashing method, which is also known as the pseudo- steady state method, by flashing the fluid through the upstream back-pressure regulator set above the dew point pressure at 5500 psig (37.91 MPa) to the core pressure set below the dew point pressure by the downstream back-pressure regulator. This experiment was done at a core pressure of 2600 psig (17.92 MPa).
  • Table 3 summarizes the results for the pre-treatment two- phase flow.
  • the core was then flushed with 20 pore volumes of fluid (described in Table 5 (below)).
  • the pre-flush displaces the high salinity brine from the core and thus prevents the treatment solution (composition given in Table 4 (below)) from reaching the cloud point which could happen in the presence of high salinity brine or high water saturation.
  • the core was then treated with 20 pore volumes of Composition A, described in Table 4 (below), and then shut-in for 15 hours.
  • the steady state two-phase flow of gas and condensate was then done under the same conditions as the pre-treatment two-phase flow.
  • Table 3 summarizes the results for the post-treatment two-phase flow. The results show that the chemical treatment increased the gas and condensate relative permeability by a factor of about 1.7.
  • Table 6 (below) shows the compatibility test results between Composition A and the brine used in Example 1 at 16O 0 C.
  • pre-flush with fluid provides an effective means of treating sandstone formations producing gas condensate fluids with high salinity brine present.
  • the pre-flush will also be useful in treating formations that have high water saturation, as the pre-flush may solubilize or displace most of the water before the formation is treated with the surfactant.
  • the fluid pre-flush may reduce or eliminate the possibility of the treatment solution reaching the cloud point while treating the above-mentioned formations, and thus makes the treatment more effective.
  • This procedure used a fluid pre-flush before treating a low permeability gas condensate sandstone formation that has high salinity brine (Brine 22.8 % NaCl and 1.5 % CaCl) present.
  • the procedure was performed on a sandstone reservoir plug core having the characteristics as described in Table 7 (below) at the reservoir temperature of 279 0 F (137.2 0 C).
  • Table 7 (below) summarizes properties of the core and the procedure conditions.
  • Core preparation The core was dried in an oven at 100 0 C for 24 hours and then was weighed. The core was then wrapped with polytetrafluoroethylene (PTFE), aluminum foil and shrink wrapped with "TEFLON HEAT SHRINK TUBING". The wrapped core was placed into a core holder inside the oven at 279 0 F (137.2 0 C). The initial gas permeability was measured using nitrogen at 75 0 F (23.8 0 C). The initial brine saturation of 15% was established by injecting a measured volume of brine into the vacuumed core. The salinity of brine used was 230,000 ppm with the brine composition of Table 8 (below). The gas relative permeability at initial water saturation was measured using nitrogen at 75 0 F (23.8 0 C). Compatibility Test.
  • PTFE polytetrafluoroethylene
  • Nonionic Fluorinated Polymeric Surfactant A (0.06 gram (g)) and 3 grams 70 weight % propylene glycol 30 weight % isopropanol were added to a vial.
  • 0.25 g was added to the vial, and the vial was placed in a heated bath at 90 0 C for one hour.
  • the vial was removed from the bath, and then visually inspected to determine whether the sample was one phase. If the sample was one-phase, the brine addition and heating steps were repeated until the sample was no longer one -phase. The amount of brine that was added with no phase separation was 21.5% by weight. When 36.4% by weight brine was added, phase separation occurred.
  • a synthetic hydrocarbon mixture was prepared that exhibits retrograde gas condensate behavior.
  • Table 9 (below) gives the composition of the synthetic gas mixture.
  • a two-phase flood with the fluid mixture was done using the dynamic flashing method, which is also known as the pseudo- steady state method, by flashing the fluid through the upstream back-pressure regulator set above the dew point pressure at 5500 psig (37.91 MPa) to the core pressure set below the dew point pressure by the downstream back-pressure regulator. This experiment was done at a core pressure of 2600 psig (17.92 MPa).
  • Table 10 (below) summarizes the results for the pre- treatment two-phase flow.
  • the core was then flushed with 9 pore volumes of fluid (described in Table 11, below).
  • the pre- flush displaces the high salinity brine from the core and thus prevents Composition B (described in Table 11 , below) from reaching the cloud point which can happen in the presence of high salinity brine present in the core.
  • the core was then treated with 20 pore volumes of the composition given in Table 11 (below) and then shut-in for 15 hours.
  • the steady state two-phase flow of gas and condensate was then done under the same conditions as the pre-treatment two- phase flow.
  • Table 10 summarizes the results for the post-treatment two-phase flow. The results show that the chemical treatment increased the gas and condensate relative permeability by a factor of about 1.36.
  • EXAMPLE 3 This example demonstrates the benefits of using a solvent pre-flush before treating a gas condensate sandstone formation that has initial water present.
  • the example was performed using a Berea sandstone core at a reservoir temperature of 275°F (135 0 C).
  • a core with the dimensions specified below was cut from a source rock block.
  • the core was dried in an oven at 100 0 C for 24 hours and then was weighed.
  • the core was then wrapped with polytetrafluoroethylene (PTFE), aluminum foil and shrink wrapped with "TEFLON HEAT SHRINK TUBING".
  • PTFE polytetrafluoroethylene
  • the wrapped core was placed into a core holder inside the oven at 275°F (135°C).
  • the initial gas permeability was measured using nitrogen at 75 0 F (23.8 0 C).
  • the initial brine saturation of 26% was established by injecting a measured volume of brine into the vacuumed core.
  • the gas relative permeability at initial water saturation was measured using nitrogen at 75°F (23.8 0 C).
  • Table 13 summarizes the properties of the core and procedure conditions.
  • a synthetic hydrocarbon mixture was prepared that exhibits retrograde gas condensate behavior.
  • Table 15 (below) gives the composition of the synthetic gas mixture.
  • a two-phase flood (condensate flood- 1) with the fluid mixture was done using the dynamic flashing method, which is also known as the pseudo-steady state method, by flashing the fluid through the upstream back-pressure regulator set above the dew point pressure at 4500 (37.91 MPa) psig to the core pressure set below the dew point pressure by the downstream back-pressure regulator. This example was done at a core pressure of 1500 psig (17.92 MPa).
  • Table 16 (below) summarizes the results for the pre-treatment two-phase flow.
  • the core was then flushed with 16 pore volumes of methanol to displace brine.
  • the solvent was flushed out by flowing two-phase gas condensate mixture through the core.
  • the core was then treated with 19 pore volumes of the composition given in Table 17 (below) and then shut-in for 24 hours.
  • the steady state two-phase flow of gas and condensate (condensate flood-2) was then done under the same conditions as the pre -treatment two-phase flow.
  • Table 15 summarizes the results for the condensate flood-2. The results show that the chemical treatment had negligible effect on the gas and condensate relative permeability.
  • the porosity was measured using either a gas expansion method or by the weight difference between a dry and a fully saturated core sample.
  • the pore volume is the product of the bulk volume and the porosity.
  • Synthetic Condensate Composition A synthetic gas-condensate fluid containing 93 mole percent methane, 4 mole percent n-butane, 2 mole percent n-decane, and 1 mole percent n- pentadecane was used for the core flood evaluation. Approximate values for various properties of the fluid are reported Table 19, below.
  • the core was dried for 72 hours in a standard laboratory oven at 95 0 C and then wrapped in aluminum foil and heat shrink tubing (obtained under the trade designation
  • TEFLON HEAT SHRINK TUBING from Zeus, Inc., Orangeburg, SC.
  • the wrapped core 109 was placed in core holder 108 inside oven 110 at 75 0 F (24 0 C).
  • An overburden pressure of 3400 psig (2.3 x 10 7 Pa) was applied.
  • the initial single-phase gas permeability was measured using either nitrogen or methane at a flowing pressure of 1200 psig (8.3 x 10 6 Pa).
  • Brine containing 92.25% water, 5.9% sodium chloride, 1.6% calcium chloride, 0.23% magnesium chloride hexahydrate, and 0.05% potassium chloride, was introduced into the core 109 by the following procedure.
  • the outlet end of the core holder was connected to a vacuum pump and a full vacuum was applied for 30 minutes with the inlet closed.
  • the inlet was connected to a burette with the brine in it.
  • the outlet was closed and the inlet was opened to allow a known volume of brine to flow into the core.
  • a 26% water saturation i.e., 26% of the pore volume of the core was saturated with water
  • the permeability was measured at 26% water saturation by flowing nitrogen or methane gas at 1200 psig (8.3 x 10 6 Pa) and 75 0 F (24 0 C).
  • the surfactant composition was then injected into the core without first injecting a fluid into the core to attempt to solubilize or displace brine. After at least 20 pore volumes of the surfactant composition were injected, the surfactant composition was held in the core at 275 0 F (135 0 C) for about 15 hours.
  • the synthetic gas condensate fluid described above was then introduced again at a flow rate of about 690 mL/hr using positive displacement pump 102 until a steady state was reached.
  • the gas relative permeability after treatment was then calculated from the steady state pressure drop. Following the relative permeability measurements, methane gas was injected, using positive displacement pump 102, to displace the condensate and measure the final single-phase gas permeability to demonstrate that no damage had been done to the core.
  • A, B, C, or combinations thereof refers to all permutations and combinations of the listed items preceding the term.
  • A, B, C, or combinations thereof is intended to include at least one of: A, B, C, AB, AC, BC, or ABC, and if order is important in a particular context, also BA, CA, CB, CBA, BCA, ACB, BAC, or CAB.
  • expressly included are combinations that contain repeats of one or more item or term, such as BB, AAA, MB, BBC, AAABCCCC, CBBAAA, CABABB, and so forth.
  • the skilled artisan will understand that typically there is no limit on the number of items or terms in any combination, unless otherwise apparent from the context.

Abstract

Compositions et procédés de traitement de formation porteuse d'hydrocarbures comportant de la saumure et présentant au moins une température. La saumure a au moins une première composition, et l'on détermine une première information de compatibilité pour une première saumure modèle et une première composition de traitement à une température modèle, sachant que la première saumure modèle a une composition choisie au moins partiellement sur la base de la première composition de la saumure, la température modèle étant choisie au moins partiellement sur la base de la température de la formation, et que la première composition de traitement comprend au moins un premier tensio-actif et au moins un premier solvant; puis, au moins partiellement sur la base de la première information de compatibilité, on choisit un procédé de traitement pour ladite formation, et on traite cette formation par le procédé en question.
EP07870111A 2007-03-23 2007-12-30 Procédé et système de traitement de formations d'hydrocarbures Withdrawn EP2134803A4 (fr)

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