WO2015138429A1 - Formulation de récupération de pétrole, procédé de production d'une formulation de récupération de pétrole et procédé de production de pétrole au moyen d'une formulation de récupération de pétrole - Google Patents

Formulation de récupération de pétrole, procédé de production d'une formulation de récupération de pétrole et procédé de production de pétrole au moyen d'une formulation de récupération de pétrole Download PDF

Info

Publication number
WO2015138429A1
WO2015138429A1 PCT/US2015/019670 US2015019670W WO2015138429A1 WO 2015138429 A1 WO2015138429 A1 WO 2015138429A1 US 2015019670 W US2015019670 W US 2015019670W WO 2015138429 A1 WO2015138429 A1 WO 2015138429A1
Authority
WO
WIPO (PCT)
Prior art keywords
oil
formation
water
oil recovery
recovery formulation
Prior art date
Application number
PCT/US2015/019670
Other languages
English (en)
Inventor
Jeffrey George Southwick
Volodimir Mikolajovitsj KARPAN
Rouhollah Farajzadeh
Marinus Johannes FABER
Quoc An On
Carolus Hendricus Theodorus VAN RIJN
Cornelia Alida Krom
Original Assignee
Shell Oil Company
Shell Internationale Research Maatschappij B.V.
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 Shell Oil Company, Shell Internationale Research Maatschappij B.V. filed Critical Shell Oil Company
Publication of WO2015138429A1 publication Critical patent/WO2015138429A1/fr

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
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/588—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 polymers

Definitions

  • OIL RECOVERY FORMULATION PROCESS FOR PRODUCING AN OIL RECOVERY FORMULATION, AND PROCESS FOR PRODUCING OIL
  • the present invention is directed to a process for producing an oil recovery formulation, to an oil recovery formulation, and to a process for recovering oil from an oil- bearing formation with the oil recovery formulation.
  • One enhanced oil recovery method utilizes an alkaline-surfactant ("AS") or an alkaline-surfactant-polymer (“ASP”) flood in an oil-bearing formation to increase the amount of oil recovered from the formation.
  • An aqueous dispersion of an alkaline component, a surfactant, and optionally a polymer is injected into an oil-bearing formation to increase recovery of oil from the formation, either after primary recovery or after a secondary recovery waterflood.
  • the AS or ASP flood enhances recovery of oil from the formation by lowering interfacial tension between oil and water phases in the formation, thereby mobilizing the oil for production.
  • Interfacial tension between the oil and water phases in the formation is reduced by the surfactant of the ASP flood and by the formation of soaps by alkali interaction with acids in the oil.
  • the polymer increases the viscosity of the ASP fluid, typically to the same order of magnitude as the oil in the formation, so the mobilized oil may be forced through the formation for production by the ASP flood.
  • an AS or ASP oil recovery formulation is formulated to minimize interfacial tension between oil and water in an oil- bearing formation, enhancing oil recovery from the formation.
  • the AS or ASP oil recovery formulation is typically designed to produce an ultra-low interfacial tension between oil and water in the formation, resulting in a stable microemulsion of oil and water in the formation. The microemulsion may be pushed through the formation for production and recovery from the formation.
  • the AS or ASP oil recovery formulation may be designed to produce an ultra- low interfacial tension between oil and water in the formation by selecting or tailoring the surfactant(s) of the oil recovery formulation to induce the formation of a stable oil-water microemulsion at the salinity of the formation water.
  • the interfacial tension between formation oil and water in the presence of an AS or ASP oil recovery formulation is sensitive to the salt concentration of the aqueous AS or ASP dispersion and the salt concentration of water in the formation.
  • An AS or an ASP oil recovery formulation may be formulated by adapting the total salt concentration of the oil recovery formulation to match the total salt concentration of water in the oil-bearing formation into which the oil recovery formulation is to be introduced, and selecting or tailoring the surfactant(s) used in the oil recovery formulation to induce the formation of a stable oil- water microemulsion, which is indicative of an ultra- low oil/water interfacial tension at the salinity of the water of the oil- bearing formation.
  • the resulting AS or ASP oil recovery formulation is then injected into the oil-bearing formation to enhance oil recovery from the formation.
  • a difficulty presented by AS or ASP enhanced oil recovery is separation of produced oil from produced water upon recovery from the formation.
  • the mobilized microemulsion of oil and water generated by contact with the AS or ASP oil recovery formulation is relatively stable, and does not easily separate into oil and water phases.
  • a portion of the produced oil will be present in the stable microemulsion, and steps such as adding a demulsifier, heating, or adding a salt to the microemulsion may be required to break the microemulsion and recover the oil therefrom.
  • a portion of the surfactant of the AS or ASP oil recovery formulation may be adsorbed from the oil recovery formulation by the formation minerals and clays upon injection into the formation. The adsorbed surfactant may remain in the formation when oil and the oil recovery formulation are recovered from the formation.
  • surfactant is often the most expensive component of an AS or ASP oil recovery formulation, the economic viability of oil recovery utilizing AS or ASP flooding may depend on the extent to which surfactant is lost in the formation.
  • a surfactant has been utilized in a low salinity waterflood enhanced oil recovery technique to realize the benefits of increased oil recovery of both low salinity waterflooding (salinity of up to 5000 ppm) and surfactant based enhanced oil recovery methods (See Enhanced Oil Recovery (EOR) by Combining Surfactant with Low Salinity Injection, A. Johannessen & K. Spildo, Energy Fuels 2013, 27, 5738-5749).
  • the low salinity surfactant (LSS) process showed improved oil recovery relative to a low salinity process alone.
  • a difficulty with the LSS process, particularly when the source water available for a waterflood has a relatively high salinity, is desalination of the source water. Desalination units add significant capital expense, and, due to their size, may prohibit use of an LSS process on offshore platforms for subsea oil recovery.
  • AS and ASP enhanced oil recovery processes and compositions are desirable.
  • processes and compositions effective to enhance oil recovery from an oil-bearing formation utilizing an AS or ASP oil recovery formulation that reduce or eliminate steps for separation of produced oil from a microemulsion of oil and water are desirable.
  • processes and compositions effective to inhibit loss of surfactant from an AS or ASP oil recovery formulation in an AS or ASP enhanced oil recovery process are desirable.
  • the invention is directed to a process for preparing an oil recovery formulation for recovering oil from an oil-bearing formation, comprising: determining a total dissolved salt concentration, by weight, in water from the oil-bearing formation; selecting a total concentration of alkali salts to be included in the oil recovery formulation; preparing a mixture of oil and a brine, wherein the brine has a total dissolved salt concentration, by weight, of from 10,000 ppm to 30,000 ppm greater than the total dissolved salt concentration, by weight, of the water from the oil-bearing formation plus the total concentration of alkali salts to be included in the oil recovery formulation;
  • the invention is directed to an oil recovery formulation composition
  • an oil recovery formulation composition comprising: water having a total dissolved salt concentration of greater than 5000 ppm; an alkali dissolved in the water wherein the alkali optionally comprises one or more alkali salts; and a surfactant formulation mixed in the water, wherein the surfactant formulation is effective to form a type-Ill Windsor microemulsion in a mixture of oil and brine where the brine has a total dissolved salt concentration 10,000 ppm to 30,000 ppm, by weight, greater than the total dissolved salt concentration of the water inclusive of any alkali salts in the water, and the ratio of oil to brine in the mixture of oil and brine, by volume, is from 2:1 to 1:2.
  • the present invention is directed to a process for recovering oil from an oil-bearing formation, comprising: providing an oil recovery formulation comprised of water having a total dissolved salt concentration of greater than 5000 ppm and within 5000 ppm, by weight, of the total dissolved salt concentration of water from the oil-bearing formation, an alkali dissolved in the water wherein the alkali optionally is comprised of an alkali salt, and a surfactant mixed in the water, wherein the surfactant formulation is effective to form a type-Ill Windsor microemulsion in a mixture of oil and brine, where the brine has a total dissolved salt concentration 10,000 ppm to 30,000 ppm, by weight, greater than the total dissolved salt concentration of the formation water plus the total concentration of alkali salts in the oil recovery formulation, and the ratio of oil to brine in the mixture of oil and brine, by volume, is from 2:1 to 1:2; introducing the oil recovery formulation into the oil-bearing formation; contacting the oil recovery formulation with
  • Fig. 1 shows a system for practicing the process of oil recovery of the present invention. Detailed Description of the Invention
  • the present invention is directed to a process for preparing an Alkaline-Surfactant (AS) or an Alkaline-Surfactant-Polymer (ASP) oil recovery formulation.
  • AS or ASP oil recovery formulation is prepared with a surfactant formulation comprised of one or more surfactants wherein the total dissolved salt concentration of the oil recovery formulation is greater than 5000 ppm and is from 10,000 ppmw ("parts per million, by weight")(1.0 wt.%) to 30,000 ppmw (3.0 wt.%) less than the optimum total dissolved salt concentration for the surfactant formulation, where the optimum total dissolved salt concentration for the surfactant formulation is the total dissolved salt concentration at which the surfactant formulation produces a minimum interfacial tension in a brine/oil mixture as demonstrated by the formation of a type-Ill Windsor microemulsion.
  • the present invention is directed to an AS or ASP oil recovery formulation containing a surfactant formulation comprised of one or more surfactants wherein the total dissolved salt concentration of the oil recovery formulation is greater than 5000 ppm and is from 10,000 ppmw (1.0 wt% ) to 30,000 ppmw (3.0 wt.%) under the optimum total dissolved salt concentration for the surfactant formulation as defined above.
  • the present invention is directed to using an AS or an ASP oil recovery formulation composition as described above, or an AS or ASP oil recovery formulation prepared as described above in a process to recover oil from an oil-bearing formation.
  • the AS or ASP oil recovery formulation mobilizes oil for production from the oil-bearing formation, where a signficantly greater portion of the mobilized oil may be produced from the oil-bearing formation as oil from an oil bank, rather than in a microemulsion of oil and water, compared to conventional AS or ASP oil recovery processes.
  • Oil from the produced oil bank may be separated from water produced from the formation without substantial demulsification efforts as required to separate produced oil from a microemulsion of oil and water.
  • adsorption of surfactant from the oil recovery formulation by the oil-bearing formation may be inhibited by use of the "under- optimum" salinity AS or ASP oil recovery formulation of the present invention relative to adsorption of surfactant observed utilizing a conventional "optimum" salinity AS or ASP oil recovery formulation.
  • the amount of oil recovered from an oil-bearing formation utilizing the "under-optimum" salinity AS or ASP oil recovery formulation of the present invention may be substantially the same as the amount of oil recovered from an oil-bearing formation utilizing a conventional "optimum" salinity AS or ASP oil recovery formulation.
  • an "under-optimum" salinity AS or ASP oil recovery formulation composition of the present invention or an "under-optimum” salinity AS or ASP oil recovery formulation prepared in accordance with the present invention, enables recovery of similar quantities of oil from an oil-bearing formation as a conventional "optimum" salinity AS or ASP oil recovery formulation while inhibiting surfactant loss in the formation and enhancing the ease of separation of produced oil from produced water.
  • the total dissolved salt content, by weight, of water from, or in, an oil-bearing formation is determined.
  • Water samples from the oil-bearing formation may be collected by several methods that are conventional in the art. For example, water from a formation may be collected by a conventional drill stem test or a wireline formation test. Formation water may also be separated from fluids produced from the formation, for example at a production well.
  • the total dissolved salt content of the formation water may be determined according to conventional methods for measuring water salinity.
  • a total concentration of alkali salts to be included in the oil recovery formulation is selected.
  • the total concentration of alkali salts to be included in the oil recovery formulation may be selected based on the total concentration of alkali selected to be included in the oil recovery formulation, where the alkali to be included in the oil recovery formulation includes the alkali salts to be included in the oil recovery formulation, if any.
  • the total concentration of alkali to be included in the oil recovery formulation may be selected based on the amount of alkali required in the oil recovery formulation to be effective to form a soap with acid components in the oil in the oil-bearing formation, which may be determined by the acidity of the oil as measured by the total acid number ("TAN") of the oil.
  • TAN total acid number
  • the total concentration of alkali to be included in the oil recovery formulation may be selected to range from 10 ppmw ("parts per million by weight")(0.001 wt.%) to 50,000 ppmw (5.0 wt.%), or from 50 ppmw (0.005 wt.%) to 30,000 ppmw (3 wt.%), or from 100 ppmw (0.01 wt.%) to 10,000 ppmw (1 wt.%) of the oil recovery formulation.
  • the total concentration of alkali to be included in the oil recovery formulation may be selected to produce a pH in the oil recovery formulation of from 8.5 to 12.0, or from 9.0 to 11.5, or from 9.5 to 11.0.
  • the total concentration of alkali salts to be included in the oil recovery formulation may be selected to range from 0 ppmw (0 wt.%) up to the total concentration of alkali selected to be included in the oil recovery formulation, or from 0 ppmw (0 wt.%) to 50,000 ppmw (5.0 wt.%), or from 50 ppmw ( 0.005 wt.%) to 30,000 ppmw (3.0 wt.%), or from 100 ppmw (0.01 wt.%) to 10,000 ppmw (1.0 wt.%) of the oil recovery formulation.
  • the total concentration of alkali salts to be included in the oil recovery formulation may be selected to produce in the oil recovery formulation a pH of from 8.5 to 12.0, or from 9.0 to 11.5, or from 9.5 to 11.0.
  • alkali is defined as any base that has a solubility in water in water at 25°C and 0.101 MPa of at least 1 gram per 100 grams of water and forms hydroxide ions or the solution of a base in water.
  • the alkali may be selected from the group consisting of ammonia; an alkali salt selected from the group consisting of sodium carbonate, sodium bicarbonate, potassium carbonate, potassium bicarbonate, and lithium carbonate; and mixtures thereof.
  • a mixture of oil and brine is then prepared, where the brine has a total dissolved salt concentration, by weight, of from 10,000 ppmw (1.0 wt.%) to 30,000 ppmw (3.0 wt.%), or 10,000 ppmw to 20,000 ppmw, or 10,000 ppmw to 15,000 ppmw greater than the total dissolved salt concentration, by weight, of the formation water plus the selected total concentration of alkali salts to be included in the oil recovery formulation.
  • the brine may be prepared by adding from 10,000 ppmw (1.0 wt.%) to 30,000 ppmw (3.0 wt.%) of one or more non-alkali water soluble salts to formation water and optionally adding an amount of one or more alkali salts to the formation water effective to provide the brine with a concentration of alkali salts equivalent to the selected total concentration of alkali salts to be included in the oil recovery formulation, e.g. from 0 ppmw (0 wt.%) to 50,000 ppmw (5.0 wt,%) of alkali salts.
  • the brine may be prepared by adding one or more non-alkali water soluble salts, as a pure salt or in a concentrated aqueous solution, to fresh water, where the non-alkali water soluble salts are added in an amount effective to provide a total dissolved non-alkali salt concentration of from the formation water total dissolved salt concentration (by weight) +10,000 ppmw to the formation water total dissolved salt concentration (by weight) + 30,000 ppmw, and also optionally adding one or more alkali salts to the water, as a pure salt or in a concentrated aqueous solution, in an amount effective to provide the brine with a concentration of alkali salts equivalent to the selected total concentration of alkali salts to be included in the oil recovery formulation.
  • the brine may be prepared by adding one or more water soluble non-alkali salts, as a pure salt or in a concentrated aqueous solution, to a source water having a total dissolved salt concentration less than the formation water total dissolved salt concentration (by weight) + 10,000 ppmw to raise the total dissolved salt concentration of the source water to a range of from the formation water total dissolved salt concentration (by weight) + 10,000 ppmw to the total dissolved salt concentration of the formation water (by weight) +30,000 ppmw, where the source water may be selected from seawater, brackish water, estuarine water, aquifer water, well water, lake water, or river water, and adding an amount of one or more alkali salts to the source water effective to provide the brine with a concentration of alkali salts equivalent to the selected total concentration of alkali salts to be included in the oil recovery formulation, e.g.
  • a source water having a total dissolved salt concentration greater than the formation water total dissolved salt concentration (by weight) + 30,000 ppmw may be partially desalinated, for example by nanofiltration or by reverse osmosis, to provide a brine having a total dissolved salt concentration of from the formation water total dissolved salt concentration (by weight) +10,000 ppmw to the formation water total dissolved salt concentration (by weight) + 30,000 ppmw, and also optionally adding one or more alkali salts to the desalinated water, as a pure salt or in a concentrated aqueous solution, in an amount effective to provide the brine with a concentration of alkali salts equivalent to the selected total concentration of alkali salts to be included in the oil recovery formulation.
  • the method of producing the brine is not critical to the process of the present invention.
  • a non-alkali water soluble salt added to the formation water or other source water to produce the brine may be any salt that is substantially soluble in water that does not produce any significant quantities of undissolved solids or scale upon being added to and mixed with the water and does not raise the pH of the water significantly (e.g does not raise the i 1 of the water by more than 0.5 i I units).
  • at least a portion of the non-alkali water soluble salts of the brine are selected from the group consisting of lithium chloride, sodium chloride, potassium chloride, and mixtures thereof.
  • the brine may be formed by adding selected non-alkali salts to formation water, where the salts are selected based upon the salt composition of the fonnation water and are added to form the brine in quantities proportional to that in the fonnation water,
  • a portion of formation water may be concentrated by distilling off a portion of the formation water, and the concentrated formation water may be added to a separate portion of formation water to produce the brine.
  • the alkali salts may be selected from the water soluble alkali salts described above.
  • Suitable alkali salts for use in producing the brine may be selected from the group consisting of lithium carbonate, sodium carbonate, sodium bicarbonate, potassium carbonate, potassium bicarbonate and mixtures thereof.
  • the alkali salts may be added to the fonnation water or other source water in an amount effective to provide the brine with a total alkali salt concentration equivalent to the selected total alkali salt concentration to be included in the oil recovery formulation, which may be from 0 ppmw (0.0 wt.%) to 50,000 ppmw (5 wt.%), or from 50 ppmw (0.005 wt.%) to 30,000 ppmw (3 wt.%), or from 100 ppmw (0.01 wt.%) to 10,000 ppmw (1 wt.%) of an alkali salt.
  • the oil mixed with the brine to form the mixture of oil and brine may be a crude oil, The crude oil may be produced from an oil-bearing formation. In a preferred
  • the oil is a crude oil produced from the same oil-bearing formation as the formation water.
  • the oil and the brine may be mixed in a ratio effective to permit the formation of an emulsion of the oil and brine upon contact of a surfactant formulation with the mixture of the oil and brine, and to permit the formation of a type-Ill Windsor microemulsion of the oil, brine, and surfactant formulation upon contact with a surfactant formulation effective to form such a microemulsion with the mixture of oil and brine, as discussed below.
  • the oil and brine may be mixed in a volume ratio of from 1 part oil to 2 parts brine to 2 parts brine to 1 part oil, or from a volume ratio of from 2 parts oil to 3 parts brine to 3 parts oil to 2 parts brine.
  • the oil and brine mixture contains equal parts oil and brine, by volume (1: 1 volume ratio). The ratio of oil to brine may be selected based upon a ratio of oil to formation water in the oil-bearing formation.
  • Windsor microemulsion in the mixture of oil and brine upon being mixed with the mixture of oil and -brine. Formation of a type-Il l Windsor microemulsion is indicated by the formation of a stable liquid 3-phase system having an aqueous phase layer, a
  • microemulsion layer a microemulsion layer, and an oil phase layer. Formation of a type-Ill Windsor
  • microemulsion indicates that the interfacial tension in the brine- surfactant-oil mixture is at or near a minimum and the surfactant formulation is effective to produce ultra-low interfacial tension between the oil and the brine at the salinity of the brine.
  • Ultra- low interfacial tension between the oil and brine is defined herein as a surface tension of 0.001 mN/m or less.
  • the surfactant formulation, oil, and brine are combined and mixed together and then allowed to settle and stabilize.
  • the surfactant formulation, oil, and brine may be mixed together by vigorous shaking to form a homogenous mixture.
  • the mixture Prior to mixing or upon mixing the oil, bri ne, and surfactant formulation, the mixture is preferably heated to a temperature within a range of temperatures within the oil-bearing formation. A temperature within the oil-bearing formation may be determined, and prior to mixing, or upon mixing the oil, brine, and surfactant formulation the mixture may be heated to a temperature within 10°C of the temperature of the oil-bearing formation.
  • the mixture may be heated to a temperature from 40°C to 90°C either prior to mixing or upon mixing the oil, brine, and surfactant formulation.
  • the mixture is then allowed to equilibrate, typically by allowing the mixture to settle over a period of 1 to 2 days.
  • the mixture is preferably allowed to equilibrate while maintaining the mixture at a temperature within a range of temperatures within the oil-bearing formation or within 10°C of a determined formation temperature, typically in a range of from 40°C to 9()°C.
  • the equilibrated mixture may then be observed to determine whether a stable liquid -phase type-Ill Windsor microemulsion has formed.
  • the surfactant formulation is comprised of one or more surfactants, where a surfactant useful in the surfactant formulation may be any surfactant effective to reduce the interfacial tension between oil and water in the oil/brine mixture and in the oil-bearing formation.
  • a surfactant in the surfactant formulation may be an anionic surfactant.
  • the anionic surfactant may be a sulfonate-containing compound, a sulfate-containing compound, a carboxylate-containing compound, a phosphate-containing compound, or a blend thereof.
  • An anionic surfactant in the surfactant formulation may be an alpha olefin sulfonate compound, an internal olefin sulfonate compound, a branched alkyl benzene sulfonate compound, a propylene oxide sulfate compound, an ethylene oxide sulfate compound, a propylene oxide-ethylene oxide sulfate compound, an alcohol propoxy sulfate compound, or a blend thereof.
  • the anionic surfactant may contain from 12 to 28 carbons, or from 12 to 20 carbons.
  • a surfactant of the surfactant formulation may comprise an internal olefin sulfonate compound containing from 15 to 18 carbons or a propylene oxide sulfate compound containing from 12 to 15 carbons, or a blend thereof, where the blend contains a volume ratio of the propylene oxide sulfate to the internal olefin sulfonate compound of from 1:1 to 10:1.
  • the surfactant formulation may be formed of a mixture of surfactants selected to promote the formation of a type-Ill Windsor microemulsion upon being mixed with the oil and brine mixture.
  • Surfactants having more hydrophilic character may be mixed with surfactants having more hydrophobic character, and the quantities of each may be adjusted to improve the microemulsion-forming effectiveness of the surfactant mixture.
  • Surfactants having more hydrophilic character and surfactants having more hydrophobic character may be identified by those having skill in the art. For example, surfactants containing significant quantities of propylene oxide are known to be hydrophobic.
  • the surfactant formulation will have a more hydrophilic character so that the formation of viscous emulsions may be avoided upon introducing the oil recovery formulation into the oil-bearing formation.
  • the surfactant formulation is mixed with the mixture of oil and brine in an amount effective to permit the identification of the formation of a type-Ill Windsor microemulsion in the oil/brine/surfactant formulation mixture.
  • the surfactant formulation may be added to the oil and brine mixture such that the amount of surfactant formulation in the oil/brine/surfactant formulation mixture is from 0.05 wt.% to 5 wt.%, or from 0.1 wt.% to 3 wt.%.
  • the AS or ASP oil recovery formulation is prepared utilizing the identified surfactant formulation.
  • the AS or ASP oil recovery formulation is prepared by mixing together the identified surfactant formulation, water or brine, an alkali, optionally a polymer, and optionally a co-solvent.
  • the total dissolved salt concentration of the oil recovery formulation minus the total concentration of alkali salts in the oil recovery formulation is greater than 5000 ppm, and is within 5000 ppm, by weight, of the total dissolved salt concentration of the formation water (inclusive of any alkali salts in the formation water).
  • the identified surfactant formulation, water or brine, and any alkali, polymer, and/or co-solvent may be mixed according to any conventional mixing method for mixing liquids, optionally with particulate dissolvable solids, for example by mixing in a mechanically stirred tank.
  • the water or brine utilized to prepare the AS or ASP oil recovery formulation may be formation water produced from the oil-bearing formation.
  • the water or brine may be provided from a source water selected from seawater, estaruine water, aquifer water, lake water, river water, or brackish water.
  • the total dissolved salt concentration of water or brine that is from a source water other than formation water may be adjusted to provide the AS or ASP oil recovery formulation with a total non-alkali dissolved salt concentration of greater than 5000 ppm and to within 5000 ppm, by weight, of the total dissolved salt concentration of the formation water (inclusive of any alkali salts in the formation water).
  • the total non-alkali dissolved salt concentration of a fresh water source or a saline water source having a total dissolved salt concentration of less than the formation water total dissolved salt concentration (by weight) - 5,000 ppmw may be adjusted by adding one or more non-alkali water soluble salts, as a pure salt or in a concentrated aqueous solution, to water from the water source.
  • the non-alkali water soluble salts are added to the water in an amount to provide a total non-alkali dissolved salt concentration of from the formation water total dissolved salt concentration (by weight, inclusive of dissolved alkali salts) -5,000 ppmw to the formation water total dissolved salt concentration (by weight, inclusive of dissolved alkali salts) + 5,000 ppmw.
  • a source water having a total dissolved salt concentration greater than the formation water total dissolved salt concentration (by weight) + 5,000 ppmw may be desalinated, for example by nanofiltration or by reverse osmosis, to adjust the total dissolved salt content of the source water to a range from the formation water total dissolved salt concentration (by weight, inclusive of dissolved alkali salts) -5,000 ppmw to the formation water total dissolved salt concentration (by weight, inclusive of dissolved alkali salts) + 5,000 ppmw.
  • a non-alkali water soluble salt added to water from a water source in the production of the AS or ASP oil recovery formulation may be any salt that is substantially soluble in water that does not produce any significant quantities of undissolved solids or scale upon being added to and mixed with the water and does not raise the pi I of the water by more than 0.5 pi I units.
  • Non-alkali water soluble salts added to water from a water source may be selected from the group consisting of lithium chloride, sodium chloride, potassium chloride, and mixtures thereof.
  • An alkali is mixed with the water, surfactant formulation, and optionally polymer and co-solvent in the production of the AS or ASP formulation.
  • the alkali may be present in the AS or ASP formulation in an amount effective to interact with crude oil in the formation to form a soap.
  • the alkali may be present in the AS or ASP formulation in an amount of from 10 ppmw (0.001 wt.%) to 50,000 ppmw (5 wt.%), or from 50 ppmw (0.005 wt.%) to 30,000 ppmw (3 wt.%), or from 100 ppmw (0.01 wt.%) to 10,000 ppmw (1 wt.%) of the AS or ASP oil recovery formulation. At least a portion of the alkali may be present in the water or brine from a water source used to produce the AS or ASP
  • An alkali may be added to the mixture of water or brine and surfactant formulation, and optionally polymer and co-solvent, to provide a total alkali concentration, by weight, of from 10 ppmw (0.001 wt.%) to 50,000 ppmw (5 wt.%), or from 50 ppmw (0.005 wt.%) to 30,000 ppmw (3 wt.%), or from 100 ppmw (0.01 wt.%) to 10,000 ppmw (1 wt.%) of the AS or ASP oil recovery formulation.
  • the AS or ASP oil recovery formulation may contain an amount of alkali effective to provide the oil recovery formulation with a pH of greater than 8.5, preferably from 9.0 to 12.0.
  • the AS or ASP oil recovery formulation may contain an amount of an alkali effective to provide the AS or ASP oil recovery formulation with a pH of from 8.5 to 12,0, or from 9.0 to 11.5, or from 9.5 to 11.0.
  • the alkali may be selected from the group consisting of ammonia; an alkali salt selected from the group consisting of sodium carbonate, sodium bicarbonate, potassium carbonate, potassium bicarbonate, and lithium carbonate; and mixtures thereof.
  • the alkali may be free of an alkali salt, for example, the alkali may consist of ammonia.
  • the alkali may be comprised of an alkali salt, where if the alkali comprises an alkali salt, the alkali salt may comprise a portion, or all, of the alkali in the AS or ASP oil recovery formulation.
  • Alkali salts may be mixed with formation water or other source water, surfactant formulation, and optionally polymer and co-solvent in an amount to provide the AS or ASP oil recovery formulation with from 10 ppmw (0.001 wt.%) to 50,000 ppmw (5 wt.%), or from 50 ppmw (0.005 wt.%) to 30,000 ppmw (3 wt.%), or from 100 ppmw (0.01 wt.%) to 10,000 ppmw (1 wt.%) of the alkali salts.
  • the identified surfactant formulation is mixed in the AS or ASP oil recovery formulation in an amount effective to enhance recovery of oil from an oil-bearing formation upon contact of the AS or ASP oil recovery formulation with the oil-bearing formation in an AS or ASP oil recovery process.
  • the surfactant formulation may be mixed in the AS or ASP formulation in an amount effective to provide the AS or ASP fonnulation with from 0,05 wt.% to 5 wt.%, or from 0.1 wt.% to 3 wt.% of a surfactant or combination of surfactants from the surfactant formulation.
  • the oil recovery formulation may be an ASP oil recovery formulation containing one or more water soluble polymers.
  • One or more water soluble polymers may be mixed with the water or brine, the surfactant formulation, the alkali, and optionally a co-solvent, of the oil recovery formulation to provide an ASP oil recovery formulation.
  • the one or more water soluble polymers utilized to form the ASP oil recovery formulation may be selected from the group consisting of polyacrylamides; partially hydrolyzed
  • polyacrylamides polyacrylates; ethylenic co-polymers; biopolymers;
  • carboxymethylcelloluses polyvinyl alcohols; polystyrene sulfonates;
  • polyvinylpyrrolidones polyvinylpyrrolidones; AMPS (2-acrylamide-methyl propane sulfonate); co-polymers of acrylamide, acrylic acid, AMPS, and n-vinylpyrrolidone in any ratio; and combinations thereof.
  • ethylenic co-polymers include co-polymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and acrylamide.
  • biopolymers include xanthan gum, guar gum, and scleroglucan.
  • the molecular weight average of the polymer in the oil recovery formulation should be sufficient to provide sufficient viscosity to the oil recovery formulation to drive the mobilized oil through the formation.
  • the polymer may have a molecular weight average of at least 10000 daltons, or at least 50000 daltons, or at least 100000 daltons.
  • the polymer may have a molecular weight average of from 10000 to 30000000 daltons, or from 100000 to 15000000 daltons.
  • the one or more water soluble polymers may be mixed in the ASP oil recovery formulation in an amount effective to provide the ASP oil recovery formulation with a viscosity on the same order of magnitude as the viscosity of oil in the oil-bearing formation under formation temperature conditions so the ASP oil recovery formulation may drive mobilized oil across the formation for production from the formation with a minimum of fingering of oil through the oil recovery formulation and/or fingering of the oil recovery formulation through the oil.
  • the quantity of the polymer in the oil recovery formulation may be sufficient to provide the oil recovery formulation with a dynamic viscosity at formation temperatures on the same order of magnitude, or, less preferably a greater order of magnitude, as the dynamic viscosity of the oil in the oil-bearing formation at formation temperatures so the oil recovery formulation may push the oil through the formation.
  • the quantity of the polymer in the oil recovery formulation may be sufficient to provide the oil recovery formulation with a dynamic viscosity of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP) at 25°C or at a temperature within a formation temperature range.
  • the concentration of polymer in the oil recovery formulation may be from 250 ppm to 10000 ppm, or from 500 ppm to 5000 ppm, or from 1000 to 2000 ppm.
  • the quantity of polymer in the ASP oil recovery formulation required to provide the desired viscosity to the formulation may be significantly less than that required in a conventional "optimum salinity" ASP oil recovery formulation since the viscosity provided by a water soluble polymer in an aqueous solution is typically inversely related to the salinity of the solution.
  • a co-solvent may be mixed with the surfactant formulation, water or brine, alkali, and optionally polymer to form the AS or ASP oil recovery formulation.
  • the co-solvent may be included in the AS or ASP oil recovery formulation to inhibit the formation of a viscous emulsion upon deploying the AS or ASP oil recovery formulation in the oil-bearing formation to recover oil therefrom.
  • the co-solvent may be a low molecular weight alcohol including, but not limited to, methanol, ethanol, and iso-propanol, isobutyl alcohol, secondary butyl alcohol, n-butyl alcohol, t-butyl alcohol, or a glycol including, but not limited to, ethylene glycol, 1,3-propanediol, 1,2-propandiol, diethylene glycol butyl ether, triethylene glycol butyl ether, or a sulfosuccinate including, but not limited to, sodium dihexyl sulfosuccinate.
  • the co-solvent may comprise from 100 ppm to 50000 ppm, or from 500 ppm to 5000 ppm of the oil recovery formulation.
  • the oil recovery formulation may be free of a co- solvent.
  • the present invention is directed to an AS or an ASP oil recovery formulation composition.
  • 'Hie oil recovery formulation composition is comprised of water having a total dissolved non-alkali salt concentration of greater than 5000 ppm, an alkali dissolved in the water, where the alkali optionally comprises one or more alkali salts, and a surfactant formulation mixed in the water, wherein the surfactant formulation is effective to form a type-Ill Windsor microemulsion, as described above, in a mixture of oil and brine where the brine has a total dissolved salt concentration that is 10,000 ppm to 30,000 ppm, or 10,000 ppm to 20,000 ppm, or 10,000 ppm to 15,000 ppm by weight, greater than the total dissolved salt concentration of the water inclusive of any alkali salts dissolved in the water, and the ratio of oil to brine in the mixture of oil and brine, by volume, is from 2:1 to 1 :2.
  • the surfactant formulation, alkali, water, and dissolved non-alkali salt(s) of the oil recover ⁇ ' formulation may be as described above with respect to preparing the oil recovery formulation.
  • the oil recovery formulation composition may contain from 0.05 wt.% to 5 wt. , or from 0.1 wt.% to 3 wt.% of the surfactant formulation, from 0.001 wt.% to 5 wt.%, or from 0.005 wt.% to 3 wt.%, or from 0.01 wt.% to 1 wt.% of one or more alkalis.
  • the oil recovery formulation composition may have a pH of from 8.5 to 12.0, or from 9.0 to 11.5, or from 9.5 to 11.0.
  • the oil recovery formulation composition may include one or more water soluble polymers, as described above, and one or more co- solvents, as described above.
  • the oil recovery formulation composition may contain from 250 ppm to 10,000 ppm, or from 500 ppm to 5,000 ppm, or from 1,000 ppm to 2,500 ppm of one or more water soluble polymers.
  • the oil recovery formulation composition may contain from 100 ppm to 50,000 ppm, or from 500 ppm to 5,000 ppm of one or more co- solvents.
  • the present invention is directed to using an AS or ASP oil recovery formulation prepared by the process described above, or an AS or ASP oil recovery formulation composition as described above, in a process for recovering oil from an oil-bearing formation.
  • the oil-bearing formation comprises oil that may be separated and produced from the formation after contact and mixing with the oil recovery formulation.
  • the oil contained in the oil-bearing formation may be a light oil or an intermediate weight oil containing less than 25 wt.%, or less than 20 wt.%, or less than 15 wt.%, or less than 10 wt.%, or less than 5 wt.% of hydrocarbons having a boiling point of at least 538°C (1000°F) and having an API gravity of at least 20°, or at least 25°, or at least 30°.
  • the oil of the oil bearing-formation may be a heavy oil containing more than 25 wt.% of
  • hydrocarbons having a boiling point of at least 538°C and having an API gravity of less than 20°.
  • the oil contained in the oil-bearing formation may have a dynamic viscosity under formation conditions (in particular, at temperatures within the temperature range of the formation) of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP).
  • the oil contained in the oil-bearing formation may have a dynamic viscosity under formation temperature conditions of from 1 to 10000000 mPa s (1 to 10000000 cP).
  • the oil-bearing formation may be a subterranean formation.
  • the subterranean formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6000 meters, or from 100 meters to 4000 meters, or from 200 meters to 2000 meters under the earth's surface.
  • the subterranean formation may be a subsea subterranean formation.
  • the porous matrix material may be a consolidated matrix material in which at least a majority, and preferably substantially all, of the rock and/or mineral that forms the matrix material is consolidated such that the rock and/or mineral forms a mass in which substantially all of the rock and/or mineral is immobile when oil, the oil recovery formulation, water, or other fluid is passed therethrough.
  • the rock and/or mineral is immobile when oil, the oil recovery formulation, water, or other fluid is passed therethrough so that any amount of rock or mineral material dislodged by the passage of the oil, oil recovery formulation, water, or other fluid is insufficient to render the formation impermeable to the flow of the oil recovery formulation, oil, water, or other fluid through the formation.
  • the porous matrix material may be an unconsolidated matrix material in which at least a majority, or substantially all, of the rock and/or mineral that forms the matrix material is
  • the formation may have a permeability of from 0.0001 to 15 Darcies, or from 0.001 to 1 Darcy.
  • the rock and/or mineral porous matrix material of the formation may be comprised of sandstone, shale, and/or a carbonate selected from dolomite, limestone, and mixtures thereof— where the limestone may be microcrystalline or crystalline limestone and/or chalk.
  • Oil in the oil-bearing formation may be located in pores within the porous matrix material of the formation.
  • the oil in the oil-bearing formation may be immobilized in the pores within the porous matrix material of the formation, for example, by capillary forces, by interaction of the oil with the pore surfaces, by the viscosity of the oil, or by interfacial tension between the oil and water in the formation.
  • the oil-bearing formation is also comprised of water, which may be located in pores within the porous matrix material.
  • the water in the formation may be connate water, water from a secondary or tertiary oil recovery process water-flood, or a mixture thereof.
  • the formation water has a total dissolved salt concentration, where the total dissolved salt concentration greater than 5000 ppm, by weight, and may range from 5000 ppmw to 300,000 ppmw, or from 10,000 ppmw to 250,000 ppmw.
  • the water in the oil-bearing formation may be positioned to immobilize petroleum within the pores. Contact of the oil recovery formulation with the oil and water in the formation may mobilize the oil in the formation for production and recovery from the formation by freeing at least a portion of the oil from pores within the formation by reducing interfacial tension between water and oil in the formation.
  • the system includes a first well 201 and a second well 203 extending into an oil-bearing formation 205 such as described above.
  • the oil-bearing formation 205 may be comprised of one or more formation portions 207, 209, and 211 formed of porous material matricies, such as described above, located beneath an overburden 213.
  • An oil recovery formulation comprising a surfactant formulation, water having a total dissolved non-alkali salt concentration of greater than 5000 ppm, and an alkali, and optionally a polymer and/or a co-surfactant, as described above.
  • the provided oil recovery formulation has a total dissolved non-alkali salt concentration within 5000 ppmw of the total dissolved salt concentration (inclusive of alkali salts) of the formation water, as described above with respect to the method of preparing the oil recovery formulation.
  • the oil recovery formulation may be provided from an oil recovery formulation storage facility 215 fluidly operatively coupled to a first injection/production facility 217 via conduit 219.
  • First injection/production facility 217 may be fluidly operatively coupled to the first well 201, which may be located extending from the first injection/production facility 217 into the oil-bearing formation 205.
  • the oil recovery formulation may flow from the first injection/production facility 217 through the first well to be introduced into the formation 205, for example in formation portion 209, where the first injection/production facility 217 and the first well, or the first well itself, include(s) a mechanism for introducing the oil recovery formulation into the formation.
  • the oil recovery formulation may flow from the oil recovery formulation storage facility 215 directly to the first well 201 for injection into the formation 205, where the first well comprises a mechanism for introducing the oil recovery formulation into the formation.
  • the mechanism for introducing the oil recovery formulation into the formation 205 via the first well 201— located in the first injection/production facility 217, the first well 201, or both— may be comprised of a pump 221 for delivering the oil recovery formulation to perforations or openings in the first well through which the oil recovery formulation may be introduced into the formation.
  • the oil recovery formulation may be introduced into the formation 205, for example by injecting the oil recovery formulation into the formation through the first well 201 by pumping the oil recovery formulation through the first well and into the formation.
  • the pressure at which the oil recovery formulation is introduced into the formation may range from the instantaneous pressure in the formation up to, but not including, the fracture pressure of the formation.
  • the pressure at which the oil recovery formulation may be injected into the formation may range from 20% to 95%, or from 40% to 90%, of the fracture pressure of the formation.
  • the oil recovery formulation may be injected into the formation at a pressure equal to, or greater than, the fracture pressure of the formation.
  • the volume of oil recovery formulation introduced into the formation 205 via the first well 201 may range from 0.001 to 5 pore volumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore volumes, where the term "pore volume" refers to the volume of the formation that may be swept by the oil recovery formulation between the first well 201 and the second well 203.
  • the pore volume may be readily be determined by methods known to a person skilled in the art, for example by modelling studies or by injecting water or the oil recovery formulation having a tracer contained therein through the formation 205 from the first well 201 to the second well 203.
  • the oil recovery formulation spreads into the formation as shown by arrows 223.
  • the oil recovery formulation contacts and forms a mixture with a portion of the oil in the formation.
  • the oil recovery formulation may mobilize the oil in the formation upon contacting and mixing with the oil and water in the formation.
  • the oil recovery formulation may mobilize the oil in the formation upon contacting and mixing with the oil, for example, by reducing capillary forces retaining the oil in pores in the formation, by reducing the interfacial tension between oil and water in the formation, and/or by forming a microemulsion with oil and water in the formation.
  • the mobilized mixture of the oil recovery formulation and oil and water may be pushed across the formation 205 from the first well 201 to the second well 203 by further introduction of more oil recovery formulation into the formation.
  • the oil recovery formulation may be designed to displace the mobilized mixture of the oil recovery formulation and oil through the formation for production at the second well 203.
  • the oil recovery formulation may contain a polymer, wherein the oil recovery formulation comprising the polymer may be designed to have a viscosity on the same order of magnitude as the viscosity of the oil in the formation under formation temperature conditions, so the oil recovery formulation may drive the mobilized mixture of oil recovery formulation, oil, and water across the formation while inhibiting fingering of the mixture of mobilized oil and oil recovery formulation through the driving plug of oil recovery formulation and inhibiting fingering of the driving plug of oil recovery formulation through the mixture of mobilized oil and oil recovery formulation.
  • Oil may be mobilized for production from the formation 205 via the second well 203 by introduction of the oil recovery formulation into the formation, where the mobilized oil is driven through the formation for production from the second well as indicated by arrows 229 by introduction of the oil recovery formulation into the formation via the first well 201.
  • the oil mobilized for production from the formation 205 may include the mobilized oil/oil recovery formulation mixture.
  • Water and/or gas may also be mobilized for production from the formation 205 via the second well 203 by introduction of the oil recovery formulation into the formation via the first well 201.
  • a significant portion of the oil mobilized for production from the formation via the second well 203 may be in the form of an oil bank, as opposed to a microemulsion of oil, surfactant, and water, due to the "under-optimum" salinity of the oil recovery formulation.
  • an aqueous polymer formulation may be introduced into the formation 205 through the first well 201 subsequent to introducing the oil recovery formulation into the formation to drive the mobilized oil and oil recovery formulation across the formation to the second well 203 for recovery from the formation. From 0.1 to 10 pore volumes, or from 0.2 to 5 pore volumes, or from 0.25 to 2 pore volumes of the aqueous polymer solution may be introduced into the formation through the first well 201 to drive the mobilized oil and the oil recovery formulation across the formation.
  • the aqueous polymer solution may have a total dissolved salt concentration within 10,000 ppm, by weight, of the total dissolved salt concentration of the formation water or of the oil recovery formulation.
  • the aqueous polymer solution may be comprised of a water soluble polymer selected from the group consisting of of polyacrylamides; partially hydrolyzed polyacrylamides; polyacrylates; ethylenic co-polymers; biopolymers;
  • carboxymethylcelloluses polyvinyl alcohols; polystyrene sulfonates;
  • polyvinylpyrrolidones polyvinylpyrrolidones; AMPS (2-acrylamide-methyl propane sulfonate); co-polymers of acrylamide, acrylic acid, AMPS, and n-vinylpyrrolidone in any ratio; and combinations thereof.
  • ethylenic co-polymers include co-polymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and acrylamide.
  • biopolymers include xanthan gum, guar gum, and scleroglucan.
  • the molecular weight average of the polymer in the aqueous polymer solution should be sufficient to provide sufficient viscosity to the aqueous polymer solution to drive the mobilized oil and the oil recovery formulation through the formation.
  • the polymer may have a molecular weight average of at least 10000 daltons, or at least 50000 daltons, or at least 100000 daltons.
  • the polymer may have a molecular weight average of from 10000 to 30000000 daltons, or from 100000 to 15000000 daltons.
  • the one or more water soluble polymers may be mixed in the aqueous polymer solution in an amount effective to provide the aqueous polymer solution with a viscosity on the same order of magnitude as the viscosity of oil in the oil- bearing formation and the oil recovery formulation under formation temperature conditions so the aqueous polymer solution may drive mobilized oil and the oil recovery formulation across the formation for production from the formation.
  • the quantity of the polymer in the aqueous polymer solution may be sufficient to provide the aqueous polymer solution with a dynamic viscosity at formation temperatures on the same order of magnitude, or, less preferably a greater order of magnitude, as the dynamic viscosity of the oil in the oil- bearing formation at formation temperatures and the oil recovery formulation in the formation so the aqueous polymer solution may push the oil and the oil recovery formulation through the formation.
  • the quantity of the polymer in the oil recovery formulation may be sufficient to provide the oil recovery formulation with a dynamic viscosity of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP) at 25°C or at a temperature within a formation temperature range.
  • the concentration of polymer in the oil recovery formulation may be from 250 ppm to 10000 ppm, or from 500 ppm to 5000 ppm, or from 1000 to 2000 ppm.
  • oil may be recovered and produced from the formation via the second well 203.
  • the system of the present invention may include a mechanism located at the second well for recovering and producing the oil from the formation 205 subsequent to introduction of the oil recovery formulation into the formation, and may include a mechanism located at the second well for recovering and producing the oil recovery formulation, water, and/or gas from the formation subsequent to introduction of the oil recovery formulation into the formation.
  • the mechanism located at the second well 203 for recovering and producing the oil, and optionally for recovering and producing the oil recovery formulation, water, and/or gas may be comprised of a pump 233, which may be located in a second injection/production facility 231 and/or within the second well 203.
  • the pump 233 may draw the oil, and optionally the oil recovery formulation, water, and/or gas from the formation 205 through perforations in the second well 203 to deliver the oil, and optionally the oil recovery formulation, water, and/or gas, to the second injection/production facility 231.
  • the mechanism for recovering and producing the oil— and optionally the oil recovery formulation, water, and/or gas— from the formation 205 may be comprised of a compressor 234 that may be located in the second injection/production facility 231.
  • the compressor 234 may be fluidly operatively coupled to a gas storage tank 241 via conduit 236, and may compress gas from the gas storage tank for injection into the formation 205 through the second well 203.
  • the compressor may compress the gas to a pressure sufficient to drive production of oil— and optionally the oil recovery formulation, water, and/or gas— from the formation via the second well 203, where the appropriate pressure may be determined by conventional methods known to those skilled in the art.
  • the compressed gas may be injected into the formation from a different position on the second well 203 than the well position at which the oil— and optionally the oil recovery formulation, water, and/or gas— are produced from the formation, for example, the compressed gas may be injected into the formation at formation portion 207 while oil, oil recovery formulation, water, and/or gas are produced from the formation at formation portion 209.
  • Oil optionally in a mixture with the oil recovery formulation, water, and/or gas may be drawn from the formation 205 as shown by arrows 229 and produced up the second well 203 to the second injection/production facility 231.
  • the oil may be separated from the oil recovery formulation, water, and/or gas in a separation unit 235 located in the second injection/production facility 231 and operatively fluidly coupled to the mechanism 233 for producing oil and, optionally, the oil recovery formulation, water, and/or gas, from the formation.
  • the separation unit 235 may be comprised of a conventional liquid-gas separator for separating gas from the oil, oil recovery formulation, and water; and a conventional hydrocarbon-water separator including a demulsification unit for separating the oil from water and water soluble components of the oil recovery formulation.
  • the ease of separation of oil from the water and oil recovery formulation may be enhanced relative to oil/water/surfactant separation in a conventional AS or ASP oil recovery process due to recovery of a substantial portion of the oil in an oil bank rather than in a microemulsion.
  • Surfactant(s) of the surfactant formulation of the oil recovery formulation may also be recovered in the separation unit 235, where more surfactant may be recovered in the "under optimum salinity" oil recovery process of the present invention relative to conventional AS or ASP oil recovery processes due to reduced loss of surfactant in the formation.
  • the separated produced oil may be provided from the separation unit 235 of the second injection/production facility 231 to an oil storage tank 237, which may be fluidly operatively coupled to the separation unit 235 of the second injection/production facility by conduit 239.
  • the separated gas if any, may be provided from the separation unit 235 of the second injection/production facility 231 to the gas storage tank 241, which may be fluidly operatively coupled to the separation unit 235 of the second injection/production facility 231 by conduit 243.
  • the first well 201 may be used for injecting the oil recovery formulation into the formation 205 and the second well 203 may be used to produce oil from the formation as described above for a first time period, and the second well 203 may be used for injecting the oil recovery formulation into the formation 205 to mobilize the oil in the formation and drive the mobilized oil across the formation to the first well and the first well 201 may be used to produce oil from the formation for a second time period, where the second time period is subsequent to the first time period.
  • the second injection/production facility 231 may comprise a mechanism such as pump 251 that is fluidly operatively coupled the oil recovery formulation storage facility 215 by conduit 253, and that is fluidly operatively coupled to the second well 203 to introduce the oil recovery formulation into the formation 205 via the second well.
  • the first injection/production facility 217 may comprise a mechanism such as pump 257 or compressor 258 fluidly operatively coupled to the gas storage tank 241 by conduit 242 for production of oil, and optionally the oil recovery formulation, water, and/or gas from the formation 205 via the first well 201.
  • the first injection/production facility 217 may also include a separation unit 259 for separating produced oil, oil recovery formulation, water, and/or gas.
  • the separation unit 259 may be comprised of a conventional liquid-gas separator for separating gas from the produced oil and water; and a conventional hydrocarbon- water separator for separating the produced oil from water and water soluble components of the oil recovery formulation, where the hydrocarbon-water separator may comprise a demulsifier.
  • the separation unit 259 may be fluidly operatively coupled to: the oil storage tank 237 by conduit 261 for storage of produced oil in the oil storage tank; and the gas storage tank 241 by conduit 265 for storage of produced gas in the gas storage tank.
  • the first well 201 may be used for introducing the oil recovery formulation into the formation 205 and the second well 203 may be used for producing oil from the formation for a first time period; then the second well 203 may be used for introducing the oil recovery formulation into the formation 205 and the first well 201 may be used for producing oil from the formation for a second time period; where the first and second time periods comprise a cycle.
  • Multiple cycles may be conducted which include alternating the first well 201 and the second well 203 between introducing the oil recovery formulation into the formation 205 and producing oil from the formation, where one well is introducing and the other is producing for the first time period, and then they are switched for a second time period.
  • a cycle may be from about 12 hours to about 1 year, or from about 3 days to about 6 months, or from about 5 days to about 3 months.
  • Oil recovery and surfactant retention utilizing on oil recovery process with an ASP oil recovery formulation in accordance with the present invention was compared with oil recovery and surfactant retention in a conventional ASP oil recovery process conducted with an ASP oil recovery formulation at the surfactant's "optimal salinity".
  • Bentheimer cores were prepared from the same block of Bentheim rock. Four core flood tests were performed with the Bentheimer cores using an alkali- surfactant-polymer oil recovery composition containing 20,000 ppmw Na 2 C0 3 , 1.0 wt.% sec-butyl alcohol co- solvent, 0.6 wt.% ENORDETTM 0242, a commercially available C20-C24 internal olefin sulfonate surfactant, and from 1250 ppm to 1450 ppm of a hydrolyzed polyacrylamide polymer (FLOPPAMTM 3330S) at total dissolved salt concentrations of 25,000 ppmw, 30,000 ppmw, 35,000 ppmw, and 40,000 ppmw (inclusive of the Na 2 C03).
  • an alkali- surfactant-polymer oil recovery composition containing 20,000 ppmw Na 2 C0 3 , 1.0 wt.% sec-butyl alcohol co- solvent, 0.6 w
  • the amount of the polymer in an oil recovery formulation varied depending on the total dissolved salt concentration of the formulation, where the amount of polymer included in a formulation was effective to provide the formulation with a viscosity of 7 mPa s at 7s "1 at 52°C.
  • the core flood tests were conducted by placing a core in a core holder placed vertically in an oven, where the tests were conducted at 52°C. All fluids except crude oil were injected into the core from the bottom of the core, where the crude oil was injected into the core from the top of the core. The core was flushed with C0 2 for 30-40 minutes. Subsequently the core was saturated with 10 pore volumes of a brine solution having a total dissolved salts concentration equivalent to the total dissolved salts concentration of the oil recovery formulation utilized in the test (25,000 ppmw, 30,000 ppmw, 35,000 ppmw, or 40,000 ppmw) except the brine solution contained only sodium chloride as a dissolved salt.
  • Tests 3 and 4 show that using an oil recovery formulation having a total dissolved salt concentration of 10,000 ppmw and 15,000 ppmw, respectively, below the optimal salinity for forming a type-Ill Windsor microemulsion with the surfactant of the oil recovery formulation is unexpectedly as effective to recover oil from a core formation as an oil recovery formulation having the optimal salinity for forming a type-Ill Windsor microemulsion with the surfactant of the oil recovery formulation (Test 1).
  • an oil recovery formulation having a total dissolved salt concentration of 10,000 ppmw less than the optimal total dissolved salt concentration (Test 3) was shown to recover 63.95% of the oil left in the core after a waterflood
  • an oil recovery formulation having a total dissolved salt concentraton of 15,000 ppmw less than the optimal total dissolved salt concentration (Test 4) was shown to recover 66.02% of the oil left in the core after a waterflood
  • an oil recovery formulation having an optimal total dissolved salt concentration for forming a type-Ill Windsor microemulsion (Test 1) was shown to recover 64.91% of the oil left in the core after a waterflood.
  • the oil recovery formulations of Tests 3 and 4 were shown to have significantly reduced surfactant retention in the core, 0.07 mg/g and 0.23 mg/g, respectively, than the optimum salinity oil recovery formulation of Test 1 at 0.35 mg/g.

Landscapes

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

Abstract

L'invention concerne un procédé de préparation d'une formulation de récupération de pétrole à base d'une substance alcaline-tensioactive ou d'une substance alcaline-tensioactive-polymère "sous-optimale", dans lequel une formulation tensioactive, efficace pour former une microémulsion de Windsor de type III avec un mélange de pétrole/eau salée à une concentration totale en sel non alcalin dissous de 10 000 ppm à 30 000 ppm au-dessus de la concentration totale en sel dissous de la formulation de récupération de pétrole, est utilisée pour préparer la formulation de récupération de pétrole. L'invention concerne également une composition de récupération de pétrole à base d'une substance alcaline-tensioactive ou d'une substance alcaline-tensioactive-polymère sous-optimale comprenant une telle formulation tensioactive, ainsi qu'un procédé de production de pétrole à partir d'une formation pétrolifère à l'aide d'une telle formulation de récupération de pétrole.
PCT/US2015/019670 2014-03-12 2015-03-10 Formulation de récupération de pétrole, procédé de production d'une formulation de récupération de pétrole et procédé de production de pétrole au moyen d'une formulation de récupération de pétrole WO2015138429A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201461951772P 2014-03-12 2014-03-12
US61/951,772 2014-03-12

Publications (1)

Publication Number Publication Date
WO2015138429A1 true WO2015138429A1 (fr) 2015-09-17

Family

ID=52684751

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2015/019670 WO2015138429A1 (fr) 2014-03-12 2015-03-10 Formulation de récupération de pétrole, procédé de production d'une formulation de récupération de pétrole et procédé de production de pétrole au moyen d'une formulation de récupération de pétrole

Country Status (1)

Country Link
WO (1) WO2015138429A1 (fr)

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2018095881A1 (fr) 2016-11-24 2018-05-31 Shell Internationale Research Maatschappij B.V. Procédé de récupération de pétrole
WO2024088444A1 (fr) * 2022-10-27 2024-05-02 中国石油天然气股份有限公司 Microémulsion à phase intermédiaire, et procédé de préparation s'y rapportant et utilisation correspondante

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4323463A (en) * 1980-06-11 1982-04-06 Texaco Inc. Secondary recovery process
US20100022421A1 (en) * 2008-07-25 2010-01-28 Intevep, S.A. Process for preparing thermally stable oil-in-water and water-in-oil emulsions
US20110071057A1 (en) * 2009-09-22 2011-03-24 Board Of Regents, The University Of Texas System Method of manufacture and use of large hydrophobe ether sulfate surfactants in enhanced oil recovery (eor) applications
WO2011150060A2 (fr) * 2010-05-25 2011-12-01 Board Of Regents, The University Of Texas System Formules de polymère basique sans tensioactif pour la récupération de pétrole brut réactif

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4323463A (en) * 1980-06-11 1982-04-06 Texaco Inc. Secondary recovery process
US20100022421A1 (en) * 2008-07-25 2010-01-28 Intevep, S.A. Process for preparing thermally stable oil-in-water and water-in-oil emulsions
US20110071057A1 (en) * 2009-09-22 2011-03-24 Board Of Regents, The University Of Texas System Method of manufacture and use of large hydrophobe ether sulfate surfactants in enhanced oil recovery (eor) applications
WO2011150060A2 (fr) * 2010-05-25 2011-12-01 Board Of Regents, The University Of Texas System Formules de polymère basique sans tensioactif pour la récupération de pétrole brut réactif

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
A. JOHANNESSEN; K. SPILDO: "Enhanced Oil Recovery (EOR) by Combining Surfactant with Low Salinity Injection", ENERGY FUELS, vol. 27, 2013, pages 5738 - 5749

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2018095881A1 (fr) 2016-11-24 2018-05-31 Shell Internationale Research Maatschappij B.V. Procédé de récupération de pétrole
WO2024088444A1 (fr) * 2022-10-27 2024-05-02 中国石油天然气股份有限公司 Microémulsion à phase intermédiaire, et procédé de préparation s'y rapportant et utilisation correspondante

Similar Documents

Publication Publication Date Title
US9840657B2 (en) Method, system, and composition for producing oil
Mandal Chemical flood enhanced oil recovery: a review
EP2686400B1 (fr) Procédé de récupération de pétrole pour réservoirs carbonatés
CA2849483C (fr) Injection d'un agent tensio-actif ameliore par polymere pour des carbonates permeables
US20140048273A1 (en) Method, system, and composition for producing oil
RU2656282C2 (ru) Способ, система и композиция для добычи нефти
RU2679464C2 (ru) Способ и композиция для добычи нефти
US20140352958A1 (en) Process for enhancing oil recovery from an oil-bearing formation
US10094207B2 (en) Oil production using multistage surfactant polymer chemical flood
WO2015138429A1 (fr) Formulation de récupération de pétrole, procédé de production d'une formulation de récupération de pétrole et procédé de production de pétrole au moyen d'une formulation de récupération de pétrole
US20170362493A1 (en) Process and composition for alkaline surfactant polymer flooding
BANERJEE¹ et al. Binary Combinations for Chemical EOR: Role of Alkalis
Banerjee et al. Binary Combinations for Chemical EOR: Role of Alkalis
OA17805A (en) Process for recovery of oil from an oilbearing formation.

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: 15710405

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 15710405

Country of ref document: EP

Kind code of ref document: A1