WO2013142601A1 - Inondation par tensioactif à concentration ultra faible - Google Patents

Inondation par tensioactif à concentration ultra faible Download PDF

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Publication number
WO2013142601A1
WO2013142601A1 PCT/US2013/033152 US2013033152W WO2013142601A1 WO 2013142601 A1 WO2013142601 A1 WO 2013142601A1 US 2013033152 W US2013033152 W US 2013033152W WO 2013142601 A1 WO2013142601 A1 WO 2013142601A1
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WO
WIPO (PCT)
Prior art keywords
formation
oil
surfactant
injection
water
Prior art date
Application number
PCT/US2013/033152
Other languages
English (en)
Inventor
Egil Sunde
Original Assignee
Glori Energy Inc.
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 Glori Energy Inc. filed Critical Glori Energy Inc.
Priority to MX2014011277A priority Critical patent/MX2014011277A/es
Priority to CN201380014404.XA priority patent/CN104271875A/zh
Priority to CA2867308A priority patent/CA2867308A1/fr
Priority to RU2014140337/03A priority patent/RU2581854C1/ru
Priority to GB1416292.9A priority patent/GB2519224B/en
Publication of WO2013142601A1 publication Critical patent/WO2013142601A1/fr

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Classifications

    • 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
    • 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

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.
  • 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.
  • the amount of surfactant required is small compared with existing surfactant water flooding methods.
  • the surfactant may be susceptible to premature depletion as a result of microbes within the formation consuming the surfactant.
  • embodiments of the invention involve preventing the microbes from consuming the surfactants.
  • the surfactants used in the flooding process are oleophilic surfactants.
  • FIGURE 1 shows a diagram of a system for implementing methods according to embodiments of the invention
  • FIGURE 2 shows a flow chart illustrating steps according to embodiments of the invention
  • FIGURE 3 illustrates equipment that may be used to carry out core flood experiments according to embodiments of the invention.
  • FIGURE 4 shows a graph of results achieved from experiment; according to embodiments of the invention.
  • FIGURE 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 FIGURE 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. See E. Sunde, B.-L. Lilleb0, T. Torsvik, SPE 154138, Towards a New Theory for Improved Oil Recovery from Sandstone Reservoirs, the disclosure of which is incorporated herein by reference in its entirety.
  • 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.
  • 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. Skaelaaen, I. 2010,
  • FIGURE 2 shows a flow chart illustrating steps according to embodiments of the invention.
  • Method 20 includes step 201, which involves
  • 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.
  • the concentration of surfactant to injected water is 100 mg/L or less.
  • the concentrations may be in the range of 0.1 to 100 mg/L of injected water.
  • the concentrations may be in the range of 0.1 to 75 mg/L of injected water.
  • 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 is not necessary for the
  • commercially available surfactants such as sorbitan trioleate (commercial name Span 85), sorbitan tristearate (commercial name Span 65), sorbitan monooleate (commercial name Span 80), and sorbitan monolaurate (commercial name Span 20); compounds comprising amyl alcohols, hexyl alcohols, decyl alcohols, cresols and p-nonyl phenol, and combinations thereof.
  • 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.
  • To begin prepare a cylindrical sandstone core to resemble a reservoir in the residual situation having water and oil in representative positions. Embed a sandstone core in epoxy, evacuated to 9 torr and make water wet by saturating with brine. Determine the physical properties of the core. For example, determine the core's length, diameter, pore volume and absolute permeability. Fill the core with crude oil and then flood with brine until residual oil concentration is reached. Introduce an oil soluble surfactant such as those described herein to the core at concentrations in the range of 0.1- 100 mg/L. Following surfactant introduction, 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 No. 13/166,382 entitled Microbial Enhanced Oil Recovery Delivery Systems and Methods, filed June 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 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.
  • 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.
  • FIGURE 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 (20g/L NaCl, 4g/L Na 2 S0 4 , Sodium Bicarbonate at 1M (1: 100 concentration), 1M HC1 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).
  • FIGURE 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.
  • 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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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Chemical & Material Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Organic Chemistry (AREA)
  • Materials Engineering (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Agricultural Chemicals And Associated Chemicals (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Removal Of Floating Material (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

L'invention concerne un procédé de récupération de pétrole à partir d'une formation qui comprend l'utilisation de tensioactifs à de faibles concentrations. Le tensioactif peut être un tensioactif oléophile. Le procédé peut consister à conditionner un système de récupération de pétrole permettant d'inhiber les microbes qui pourraient consommer le tensioactif oléophile. Un procédé qui détermine la concentration d'un tensioactif qui est suffisante pour changer la tension interfaciale entre le pétrole et l'eau dans une zone de puits de forage proche d'un puits d'injection dans une formation mais ne requiert pas de changement la tension interfaciale entre le pétrole et l'eau à l'extérieur de la zone de puits de forage proche.
PCT/US2013/033152 2012-03-23 2013-03-20 Inondation par tensioactif à concentration ultra faible WO2013142601A1 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
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
CA2867308A CA2867308A1 (fr) 2012-03-23 2013-03-20 Inondation par tensioactif a concentration ultra faible
RU2014140337/03A RU2581854C1 (ru) 2012-03-23 2013-03-20 Заводнение пласта поверхностно-активным веществом сверхнизкой концентрации
GB1416292.9A GB2519224B (en) 2012-03-23 2013-03-20 Ultra low concentration surfactant flooding

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US201261614882P 2012-03-23 2012-03-23
US61/614,882 2012-03-23
US13/826,827 2013-03-14
US13/826,827 US20130248176A1 (en) 2012-03-23 2013-03-14 Ultra low concentration surfactant flooding

Publications (1)

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WO2013142601A1 true WO2013142601A1 (fr) 2013-09-26

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US (1) US20130248176A1 (fr)
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)

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CN107676064B (zh) * 2017-10-18 2020-05-08 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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US4498539A (en) * 1983-11-16 1985-02-12 Phillips Petroleum Company Selective plugging of highly permeable subterranean strata by in situ _gelation of polymer solutions
US20030083206A1 (en) * 2001-08-08 2003-05-01 Newpark Canada Inc. Oil and gas production optimization using dynamic surface tension reducers
WO2009042224A1 (fr) * 2007-09-26 2009-04-02 Verutek Technologies, Inc. Procédé d'extraction et de récupération d'un produit à l'aide d'un agent de surface
US20110236496A1 (en) * 2010-03-26 2011-09-29 Peter Markland Emulsions for Microencapsulation Comprising Biodegradable Surface-Active Block Copolymers as Stabilizers

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CN102002354A (zh) * 2010-11-02 2011-04-06 上海大学 超低油水界面张力驱油剂及其应用

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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4081029A (en) * 1976-05-24 1978-03-28 Union Oil Company Of California Enhanced oil recovery using alkaline sodium silicate solutions
US4498539A (en) * 1983-11-16 1985-02-12 Phillips Petroleum Company Selective plugging of highly permeable subterranean strata by in situ _gelation of polymer solutions
US20030083206A1 (en) * 2001-08-08 2003-05-01 Newpark Canada Inc. Oil and gas production optimization using dynamic surface tension reducers
WO2009042224A1 (fr) * 2007-09-26 2009-04-02 Verutek Technologies, Inc. Procédé d'extraction et de récupération d'un produit à l'aide d'un agent de surface
US20110236496A1 (en) * 2010-03-26 2011-09-29 Peter Markland Emulsions for Microencapsulation Comprising Biodegradable Surface-Active Block Copolymers as Stabilizers

Also Published As

Publication number Publication date
CN104271875A (zh) 2015-01-07
GB2519224A (en) 2015-04-15
MX2014011277A (es) 2014-10-06
AR093203A1 (es) 2015-05-27
GB2519224B (en) 2016-03-16
GB201416292D0 (en) 2014-10-29
US20130248176A1 (en) 2013-09-26
CO7101236A2 (es) 2014-10-31
RU2581854C1 (ru) 2016-04-20
CA2867308A1 (fr) 2013-09-26

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