US20130248176A1 - Ultra low concentration surfactant flooding - Google Patents

Ultra low concentration surfactant flooding Download PDF

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Publication number
US20130248176A1
US20130248176A1 US13/826,827 US201313826827A US2013248176A1 US 20130248176 A1 US20130248176 A1 US 20130248176A1 US 201313826827 A US201313826827 A US 201313826827A US 2013248176 A1 US2013248176 A1 US 2013248176A1
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United States
Prior art keywords
formation
oil
surfactant
injection
water
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Abandoned
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US13/826,827
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English (en)
Inventor
Egil Sunde
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New Aero Technology LLC
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Glori Energy Inc
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Application filed by Glori Energy Inc filed Critical Glori Energy Inc
Priority to US13/826,827 priority Critical patent/US20130248176A1/en
Priority to CN201380014404.XA priority patent/CN104271875A/zh
Priority to CA2867308A priority patent/CA2867308A1/fr
Priority to PCT/US2013/033152 priority patent/WO2013142601A1/fr
Priority to MX2014011277A priority patent/MX2014011277A/es
Priority to GB1416292.9A priority patent/GB2519224B/en
Priority to RU2014140337/03A priority patent/RU2581854C1/ru
Priority to ARP130100954A priority patent/AR093203A1/es
Assigned to GLORI ENERGY INC. reassignment GLORI ENERGY INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: SUNDE, EGIL
Publication of US20130248176A1 publication Critical patent/US20130248176A1/en
Priority to CO14221460A priority patent/CO7101236A2/es
Assigned to NEW AERO TECHNOLOGY LLC reassignment NEW AERO TECHNOLOGY LLC ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: GLORI ENERGY, INC.
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20—Displacing by water

Definitions

  • Crude oil remains an important energy source. Crude oil producers typically produce oil by drilling wells into underground oil reservoirs in a formation. For some wells, the natural pressure of the oil is sufficient to bring the oil to the surface. This is known as primary recovery. Over time, as oil is recovered by primary recovery for these wells, the natural pressure drops and becomes insufficient to bring the oil to the surface. When this happens, a large amount of crude oil may still be left in the formation. Consequently, various secondary and tertiary recovery processes may be employed to recover more oil. Secondary and tertiary recovery processes may include: pumping, water injection, natural gas reinjection, air injection, carbon dioxide injection or injection of some other gas into the reservoir.
  • Water is the most economical and widely used.
  • Water flooding involves the injection of water into an oil-bearing reservoir. The injected water displaces the oil from the reservoir to a production system of one or more production wells from which the oil is recovered. Water, however, does not displace oil efficiently because water and oil are immiscible due to high interfacial tension between these two liquids.
  • the interfacial tension between the surfactant treated water and the reservoir oil should be reduced to less than 0.1 dyne/cm for low-tension water flooding to provide effective recovery.
  • adding one or more surface active agents or surfactants to the injected water forms a solution or emulsion of surfactants that sweeps through the formation and displace oil.
  • surfactants are designed to be miscible with water and have relatively low affinity for oil so that the surfactants can be transported deep into the reservoir and interact with the surface of the residual oil and reduce the interfacial tension over a large volume of the residual oil.
  • To cover this large volume of residual oil requires the application of a large volume of surfactant, which makes the surfactant flooding process expensive.
  • breakthrough may occur and cause emulsion problems in the produced oil. Breakthrough occurs when the flood water makes its way to the producing well and the residual oil is recovered in a state of emulsion with the flood water. It is difficult to separate emulsified oil into its constituent components (i.e. oil and flood water).
  • Embodiments of the invention include a method of recovering oil from a reservoir in a formation that includes injecting a fluid into the reservoir and injecting a surfactant into the reservoir at a predetermined concentration range of the injected fluid.
  • the predetermined concentration range is based on providing sufficient surfactant to lower the interfacial tension between flood water and oil in the near well bore area but there is no requirement that the predetermined concentration range affects the interfacial tension between flood water and oil outside the near well bore area.
  • the interfacial tension between flood water and oil outside the near well bore area is not affected by the surfactant. Because only the near well bore area is effectively being treated by the surfactant, the amount of surfactant required is small compared with existing surfactant water flooding methods.
  • the surfactant when lower concentrations of surfactant are used in the formation, the surfactant may be susceptible to premature depletion as a result of microbes within the formation consuming the surfactant. As such, embodiments of the invention involve preventing the microbes from consuming the surfactants.
  • the surfactants used in the flooding process are oleophilic surfactants.
  • FIG. 1 shows a diagram of a system for implementing methods according to embodiments of the invention
  • FIG. 2 shows a flow chart illustrating steps according to embodiments of the invention
  • FIG. 3 illustrates equipment that may be used to carry out core flood experiments according to embodiments of the invention.
  • FIG. 4 shows a graph of results achieved from experiment; according to embodiments of the invention.
  • FIG. 1 shows a diagram of a system for implementing methods according to embodiments of the invention.
  • System 10 includes an injection well 100 and a production well 101 .
  • Oil 102 resides in oil-bearing formation 105 .
  • Oil-bearing formation 105 may be any type of geological formation and may be situated under overburden 104 .
  • formation 105 is shown as being onshore in FIG. 1 , it should be appreciated that formation 105 may be located onshore or offshore.
  • oil 102 primarily exists as strands 102 - 1 to 102 -n within formation 105 .
  • the strands are of various lengths and may extend from injection well 100 to production well 101 as shown.
  • the strands are 3-dimensional in nature and may cross link to other strands throughout formation 105 .
  • oil 102 is trapped within formation 105 , not as unique distinct droplets, but as strands (e.g. strands 102 - 1 to 102 -n) in portions of formation 105 's network of pores small enough to put up resistance to the surrounding drag and pressure drop of surrounding water flow.
  • Oil 102 is continuous and present throughout the pore networks between injection well 100 and production well 101 . Between the pore networks, there may be other parts of formation 105 where water flow has almost completely cleared out the oil.
  • the oil will self-organize according to the sum of pressures acting on it and the available pore network, thereby also redistributing some of its surrounding film of water. This and the fact that oil and water will seek the greatest possible separation to minimize friction, will leave the residual oil in continuous oil strands occupying pore spaces in all three dimensions. However, the general orientation of the oil strands will be parallel to the direction of flow due to the effect of shear forces.
  • the branched oil strands being continuous throughout the reservoir, will not be produced because they are trapped by capillary bound water in the pore throat in regions close to the production well. As a consequence, shallow chemical treatment of production wells is often successful in releasing this trapped oil.
  • surfactant water flooding oil is recovered from a formation by pumping surfactant sufficient to treat, for example, the section of formation 105 shown as section 108 . That is, current methods of surfactant water flooding seek to treat, with a surfactant, all or most areas where there is oil in the formation. This current method is based on the theory, mentioned above, that the oil exists in the formation primarily as droplets.
  • the capillary bound water blocking the pore throat must be removed. This can be achieved in at least two ways. First, the water may be removed from the pore throat by reducing the capillary forces in the pore throat. Second, the water may be removed by increasing the pressure in the oil strand.
  • a blocking pore throat has become oil-filled, the strand will easily be emptied into production well 101 because of the existing pressure gradient in the formation. This is similar to stepping on a tube of toothpaste.
  • the water does not push the oil strand from the end, but squeeze it from all sides. This implies that water molecules are displaced on a scale of pore diameters, while the oil can move hundreds of meters in a short time span, because it flows as a continuous phase with minimal friction.
  • pressure pulses can also be created by skilled application of surfactants.
  • the pressure pulse can be obtained by applying surfactants to reduce the surface tension of the oil strand at the water injection well. Surfactants can break down surface tension to a level where the oil/water interface collapses and the oil flows out.
  • Mathematical modeling indicates that the oil that flows out moves towards the water flow and the pressure gradient. Sk ⁇ laaen, I. 2010, Mathematical Modelling of Microbial Induced Processes in Oil Reservoirs. PhD thesis, University of Bergen, Bergen, Norway (2010). A consequence of this will be the creation of a sinusoidal pressure pulse in the opposite direction into the strand.
  • This pulse travels at the speed of sound in oil and its amplitude is increased as the strand diameter becomes smaller.
  • the pulse hits the water filled pore throat and the kinetic energy is converted to pressure. Although this is a relatively small force, it will add to the external pressure gradient, so that the water in the pore throat is expelled by the oil and the strand will be quickly emptied.
  • FIG. 2 shows a flow chart illustrating steps according to embodiments of the invention.
  • Method 20 includes step 201 , which involves determining a specific surfactant and determining the concentration range of a surfactant that allows the surfactant to change the interfacial tension between oil and water in near well bore area 103 of injection well 100 but does not require the surfactant to affect the interfacial tension between oil and water outside near well bore area 103 .
  • the surfactant does not affect the interfacial tension between oil and water outside near well bore area 103 . Because the surfactant is directed to changing interfacial tension in the near well bore area 103 and not to other areas, the concentration of surfactant used is low compared to traditional methods. In embodiments of the invention, the concentration of surfactant to injected water is 100 mg/L or less. In embodiments, the concentrations may be in the range of 0.1 to 100 mg/L of injected water. In embodiments, the concentrations may be in the range of 0.1 to 75 mg/L of injected water. In embodiments, the concentrations may be in the range of 0.1 to 50 mg/L of injected water.
  • the concentrations may be in the range of 0.1 to 25 mg/L of injected water.
  • the traditional use of surfactants with low affinity for oil in order to treat a large area e.g. section 107 ) is not necessary for the embodiments described herein.
  • the oleophilic surfactants or the concentration ranges of the oleophilic surfactants or both that may be used for water flooding may be determined by methods such as core flood experiments, simulation experiments etc. It should be noted that the core flood experiments may include experiments on core samples from the formation being considered.
  • the following method may be used to carry out core flood experiments.
  • a cylindrical sandstone core to resemble a reservoir in the residual situation having water and oil in representative positions.
  • set the injection pump rate to 0.1 ml/min and produced oil and water may be collected at the rate of one fraction per hour.
  • oleophilic surfactant is injected, at step 202 , at the determined concentration range.
  • a drive fluid such as flood water
  • flood water is injected into formation 105 via injection well 100 to displace oil towards production well 101 .
  • formation 105 has been waterflooded to a residual oil saturation.
  • the flood water in embodiments, may be produced water.
  • steps 202 and 203 may be carried out together. That is, the oleophilic surfactant may be mixed with the fluid, such as water, at the determined concentration. Alternatively or additionally, oleophilic surfactant may be injected separately from the injection of the fluid at step 203 .
  • oleophilic surfactant may be injected into formation 105 via a capillary tube directly to well bore area 103 at a rate that achieves the determined concentration range, taking into account the volume of fluid injected via injection well 100 .
  • Capillary tubes for injecting oxygen are disclosed in U.S. patent application Ser. No. 13/166,382 entitled Microbial Enhanced Oil Recovery Delivery Systems and Methods, filed Jun. 22, 2011, the disclosure of which is hereby incorporated by reference in its entirety. Similar to some of the methods in that disclosure, capillary tubes may be used to introduce oleophilic surfactants into formation 105 .
  • the capillary tubes may be made from any suitable material such as stainless steel, other metals, polymers and the like.
  • the capillary tube can have the cross sectional area with the shape of a circle.
  • the cross sectional area of the capillary tube may include any shape such as ellipse, polygon the like and combinations thereof. It should be noted that whichever method is used to inject the oleophilic surfactant, the injection may be done continuously or intermittently (i.e. in batches).
  • the injection of surfactant sufficient to reduce the interfacial tension between oil and water in near well bore area 103 without necessarily changing the interfacial tension within section 107 facilitates the production of oil strands 102 - 1 to 102 -n through section 107 to production well 101 .
  • reduction of interfacial tension between flood water and the portion of the oil strands 102 - 1 to 102 -n in near well bore area 103 causes a pulse that is propagated within oil strands 102 - 1 to 102 -n through the formation and moves oil strands 102 - 1 to 102 -n through formation 105 to production well 101 , from which the oil is recovered.
  • the concentration of surfactant is low, the surfactant may be consumed as substrate by microbes in the formation.
  • this conditioning may include reducing the microbe population in near well bore area 103 . This can be accomplished either before, simultaneously with, or after step 202 and/or step 203 .
  • Various methods may be used to achieve this. These methods may be performed by exposing the microbes to biocides and biostats, either high or low pH, a particular temperature and combinations thereof. For example, a biocide may be injected into formation 105 at near well bore area 103 to kill the microbes.
  • the capillary tubes described above for injecting the surfactant may be used to introduce the biocide into the near well bore area. Further, an initial high concentration of oleophilic surfactant may be used, which is toxic to microbes. Further yet, reducing the microbe population may include exposing the microbes to a temperature or pH that is known or predetermined to inhibit growth of the microbes or to kill the microbes.
  • injecting the surfactant directly into formation 105 allows the initial concentration of the surfactant to be high. Ultimately, however, the overall concentration of the oleophilic surfactant will be reduced as the relatively large volume of flood water is injected.
  • any combination of biocide treatment, initial high concentration of oleophilic surfactant, temperature control and pH control may be used to prevent the microbes from consuming the oleophilic surfactant.
  • step 204 may be eliminated because there is no issue with respect to the microbes consuming the surfactant in a particular formation. Other steps may be eliminated for other reasons.
  • step 203 can be performed before or simultaneously with step 202 .
  • FIG. 3 illustrates the equipment that was used to carry out this experiment.
  • a rock core plug was cleaned by solvent extraction, dried to constant weight and encased in epoxy.
  • the encased rock core plug 301 was tested with pressure and vacuum cycles to assure integrity.
  • Encased rock core plug 301 was then saturated with a 2.5% (w/v) synthetic salt water solution under vacuum (20 g/L NaCl, 4 g/L Na 2 SO 4 , Sodium Bicarbonate at 1M (1:100 concentration), 1M HCl pH to 7.42, Autoclaved, Gassed with N 2 ).
  • the saturation of encased rock core plug 301 is done by using pump 303 to pump synthetic salt water solution from fluid reservoir 302 into encased rock core plug 301 .
  • Digital sensor 304 measures differential pressure and back pressure valve 305 helps to maintain pressure in encased rock core plug 301 .
  • the volume required for saturation determined the pore volume within encased rock core plug 301 .
  • Additional synthetic salt water solution was injected through encased rock core plug 301 for a period greater than 24 hours, after which crude oil was injected into the core until no additional water was displaced.
  • the oil volume and saturation in encased rock core plug 301 were calculated by mass balance of injected and recovered fluids.
  • rock core plug 301 was then flooded with synthetic salt water solution and the volumes of oil and water recovered from encased rock core plug 301 were tracked. Once no additional oil had been recovered for at least one pore volume, encased rock core plug 301 was considered to be at residual oil saturation after water flood.
  • Encased rock core plug 301 used for this experiment was a berea sandstone with the following characteristics: 100 mD permeability, 19.8% porosity, 17.2 ml pore volume, 3.8 cm (diameter), 7.6 cm (length).
  • FIG. 4 shows a graph of the results achieved by this experiment.
  • the x-axis shows pore volumes after surfactant injection.
  • the y-axis shows the percentage of original oil in place that is recovered.
  • the concentration of the surfactant is 100 mg/l in a near well bore area then the concentration outside the near well bore area would be much lower as a result of dilution. Consequently, this low concentration of surfactant lowers the interfacial tension between flood water and oil in the near well bore area but does not affect the interfacial tension between flood water and oil outside the near well bore area.
  • surfactants such as oleophilic surfactants
  • breakthrough instances in the recovery process are avoided. That is, there is minimal surfactant present in the produced fluid to cause emulsification of oil and water emanating from the production well.
  • surfactants are chemicals that can affect the properties of the oil being produced. At the low levels of concentration of surfactants used in embodiments of the invention, this chemical effect on the produced oil can be significantly minimized if not completely eliminated.

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  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
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  • Removal Of Floating Material (AREA)
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US13/826,827 2012-03-23 2013-03-14 Ultra low concentration surfactant flooding Abandoned US20130248176A1 (en)

Priority Applications (9)

Application Number Priority Date Filing Date Title
US13/826,827 US20130248176A1 (en) 2012-03-23 2013-03-14 Ultra low concentration surfactant flooding
GB1416292.9A GB2519224B (en) 2012-03-23 2013-03-20 Ultra low concentration surfactant flooding
CA2867308A CA2867308A1 (fr) 2012-03-23 2013-03-20 Inondation par tensioactif a concentration ultra faible
PCT/US2013/033152 WO2013142601A1 (fr) 2012-03-23 2013-03-20 Inondation par tensioactif à concentration ultra faible
MX2014011277A MX2014011277A (es) 2012-03-23 2013-03-20 Inundacion con tensioactivo de concentracion ultrabaja.
CN201380014404.XA CN104271875A (zh) 2012-03-23 2013-03-20 超低浓度表面活性剂驱油
RU2014140337/03A RU2581854C1 (ru) 2012-03-23 2013-03-20 Заводнение пласта поверхностно-активным веществом сверхнизкой концентрации
ARP130100954A AR093203A1 (es) 2012-03-23 2013-03-22 Inyeccion de tensioactivo en concentracion ultrabaja
CO14221460A CO7101236A2 (es) 2012-03-23 2014-10-07 Inundación con tensioactivo de concentración ultrabaja

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Application Number Priority Date Filing Date Title
US201261614882P 2012-03-23 2012-03-23
US13/826,827 US20130248176A1 (en) 2012-03-23 2013-03-14 Ultra low concentration surfactant flooding

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CN (1) CN104271875A (fr)
AR (1) AR093203A1 (fr)
CA (1) CA2867308A1 (fr)
CO (1) CO7101236A2 (fr)
GB (1) GB2519224B (fr)
MX (1) MX2014011277A (fr)
RU (1) RU2581854C1 (fr)
WO (1) WO2013142601A1 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN107676064A (zh) * 2017-10-18 2018-02-09 中国石油天然气股份有限公司 一种水驱油藏含水率预测方法及其预测装置

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US4438002A (en) * 1982-09-20 1984-03-20 Texaco Inc. Surfactant flooding solution
US4814096A (en) * 1981-02-06 1989-03-21 The Dow Chemical Company Enhanced oil recovery process using a hydrophobic associative composition containing a hydrophilic/hydrophobic polymer
US5014783A (en) * 1988-05-11 1991-05-14 Marathon Oil Company Sequentially flooding an oil-bearing formation with a surfactant and hot aqueous fluid
US20030139297A1 (en) * 2001-12-14 2003-07-24 Lirio Quintero Surfactant-polymer composition for substantially solid-free water based drilling, drill-in, and completion fluids
US20040122111A1 (en) * 2000-04-25 2004-06-24 Ramesh Varadaraj Stability enhanced water-in-oil emulsion and method for using same
US20060076139A1 (en) * 2004-10-12 2006-04-13 Conrad Greg A Apparatus and Method for Increasing Well Production Using Surfactant Injection
US20060116296A1 (en) * 2004-11-29 2006-06-01 Clearwater International, L.L.C. Shale Inhibition additive for oil/gas down hole fluids and methods for making and using same
US7082996B2 (en) * 2003-02-25 2006-08-01 General Oil Tools, Lp Method and apparatus to complete a well having tubing inserted through a valve
US7332459B2 (en) * 2002-06-13 2008-02-19 Bp Exploration Operating Company Limited Method for scale inhibition in oil wells
US20090178806A1 (en) * 2008-01-11 2009-07-16 Michael Fraim Combined miscible drive for heavy oil production
US20100307757A1 (en) * 2009-06-05 2010-12-09 Blow Kristel A Aqueous solution for controlling bacteria in the water used for fracturing

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US4814096A (en) * 1981-02-06 1989-03-21 The Dow Chemical Company Enhanced oil recovery process using a hydrophobic associative composition containing a hydrophilic/hydrophobic polymer
US4438002A (en) * 1982-09-20 1984-03-20 Texaco Inc. Surfactant flooding solution
US5014783A (en) * 1988-05-11 1991-05-14 Marathon Oil Company Sequentially flooding an oil-bearing formation with a surfactant and hot aqueous fluid
US20040122111A1 (en) * 2000-04-25 2004-06-24 Ramesh Varadaraj Stability enhanced water-in-oil emulsion and method for using same
US20030139297A1 (en) * 2001-12-14 2003-07-24 Lirio Quintero Surfactant-polymer composition for substantially solid-free water based drilling, drill-in, and completion fluids
US7332459B2 (en) * 2002-06-13 2008-02-19 Bp Exploration Operating Company Limited Method for scale inhibition in oil wells
US7082996B2 (en) * 2003-02-25 2006-08-01 General Oil Tools, Lp Method and apparatus to complete a well having tubing inserted through a valve
US20060076139A1 (en) * 2004-10-12 2006-04-13 Conrad Greg A Apparatus and Method for Increasing Well Production Using Surfactant Injection
US20060116296A1 (en) * 2004-11-29 2006-06-01 Clearwater International, L.L.C. Shale Inhibition additive for oil/gas down hole fluids and methods for making and using same
US20090178806A1 (en) * 2008-01-11 2009-07-16 Michael Fraim Combined miscible drive for heavy oil production
US20100307757A1 (en) * 2009-06-05 2010-12-09 Blow Kristel A Aqueous solution for controlling bacteria in the water used for fracturing

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN107676064A (zh) * 2017-10-18 2018-02-09 中国石油天然气股份有限公司 一种水驱油藏含水率预测方法及其预测装置

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CA2867308A1 (fr) 2013-09-26
WO2013142601A1 (fr) 2013-09-26
GB201416292D0 (en) 2014-10-29
GB2519224B (en) 2016-03-16
MX2014011277A (es) 2014-10-06
RU2581854C1 (ru) 2016-04-20
AR093203A1 (es) 2015-05-27
CN104271875A (zh) 2015-01-07
CO7101236A2 (es) 2014-10-31
GB2519224A (en) 2015-04-15

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