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WO2011018733A1 - Emulsion réversible incorporée solide pour une boue de fracturation - Google Patents

Emulsion réversible incorporée solide pour une boue de fracturation Download PDF

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Publication number
WO2011018733A1
WO2011018733A1 PCT/IB2010/053505 IB2010053505W WO2011018733A1 WO 2011018733 A1 WO2011018733 A1 WO 2011018733A1 IB 2010053505 W IB2010053505 W IB 2010053505W WO 2011018733 A1 WO2011018733 A1 WO 2011018733A1
Authority
WO
WIPO (PCT)
Prior art keywords
fluid
emulsion
wellbore
poly
acid
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/IB2010/053505
Other languages
English (en)
Inventor
Hemant K. Ladva
Syed Ali
Don Williamson
Mathew M. Samuel
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Holdings Ltd
Prad Research and Development Ltd
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Holdings Ltd
Prad Research and Development Ltd
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 Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Schlumberger Technology BV, Schlumberger Holdings Ltd, Prad Research and Development Ltd filed Critical Schlumberger Canada Ltd
Publication of WO2011018733A1 publication Critical patent/WO2011018733A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/64—Oil-based compositions
    • 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
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/536—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning characterised by their form or by the form of their components, e.g. encapsulated material
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
    • C09K8/76—Eroding chemicals, e.g. acids combined with additives added for specific purposes for preventing or reducing fluid loss
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material

Definitions

  • This invention relates to fluids for use in the oil field services industry.
  • the invention relates to methods and compositions including degradable particles in an emulsion.
  • An improved composition is needed to decrease fluid loss into the fractured formation, minimize the thickness of the filtercake, reduce damage to the formation, enhance fracture conductivity, increase fracture length, improve cleanup of the filtercake and enhance production of hydrocarbons.
  • Direct application of a degradable acid generating, solid particulate additive for emulsion reversal from water-in-oil to oil-in- water, fluid loss control, altering wettability from oil wet to water wet, generating acid in- situ and enhancing fracturing conductivity either in drilling or fracturing applications is needed.
  • Some embodiments relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid containing a reverse emulsion and a degradable material, introducing the fluid into a wellbore, and allowing the degradable material to degrade.
  • Some other embodiments relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid comprising a reverse emulsion and a fluid loss additive, introducing the fluid into a wellbore, and allowing the fluid loss additive to degrade.
  • Figure 1 is a schematic figure illustrating the behavior of a reversible emulsion.
  • Figure 2 is a schematic figure illustrating a filtercake with particulate additive and trapped water droplets that reverses with time through hydrolysis of the particulates.
  • Figure 3 is a plot of viscosity and temperature as a function of time for a fluid comprising 2 weight percent PGA compared to a baseline of an embodiment of the invention.
  • Figure 4 is a plot of viscosity and temperature as a function of time for a fluid comprising 3 weight percent PGA compared to a baseline of an embodiment of the invention.
  • Figure 5 is a plot of fluid loss as a function of time comparing an emulsion and 3 weight percent PGA fluid for an embodiment of the invention.
  • Figure 6 is a plot of electrical stability as a function of volume of citric acid for an embodiment of the invention.
  • compositions of the present invention are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than the ones already cited.
  • Embodiments of this invention prevent high fluid loss from a conventional water based fracturing fluid which often results in a thick and highly concentrated polymer filtercake on the fracture surface and high formation damage, reduced fracture conductivity, reduced fracture length and low production rate across the fracture and fracture surface.
  • embodiments of the invention address the cleanup of the concentrated polymer filtercake on the fractured surface and within the fracture for improved conductivity.
  • fluid loss reduction has relied on a combination of polymers and solid particulates.
  • preference is given to oil based fluids.
  • Both an emulsion and solid particulates can be used together.
  • the emulsion is specifically designed to be reversible and to reduce fluid loss.
  • the water-in-oil emulsion is reversed to oil-in-water and vice versa by reducing or increasing the pH respectively. This reversible feature allows better cleanup of the emulsion cake that is formed on the subterranean wall or the fracture surface.
  • an emulsion lowers the fluid loss compared to water based drilling fluids.
  • the solid particulates are used as bridging agents and as fluid loss agents initially.
  • the multi-functionality features of the additives include control of fluid loss, generation of acid in situ, self-degradation, cleaning the filtercake, and improving fracture conductivity.
  • the concept uses a degradable material that initially helps to control fluid loss and subsequently degrades resulting in an improved conductivity.
  • An effective fluid contains a reversible emulsion and an acid generating, degradable solid particulate additive.
  • the reversible emulsion of water-in-oil contains an amphoteric surfactant that allows reversing of the emulsion to oil-in-water when the pH is reduced towards the acid range.
  • the pH reduction is obtained by the particulate additives that generate acid upon hydrolysis with temperature.
  • the solid particulate additive acts as bridging agent initially and helps to control the fluid loss into the formation. Subsequently, with time and temperature, the particulates hydrolyze and generate acid that reverses the emulsion.
  • the reversed emulsion helps alter the wettability of the formation from oil wet to water wet thus enhancing the productivity. It also helps in the cleanup of the emulsion filtercake and improves the fracture conductivity.
  • the fluid loss is controlled by the solid particulates that are degradable and may comprise of poly glycolic acid (PGA), poly vinyl acetate (PVAc), poly lactic acid (PLA), or its copolymer, or its different degree of hydrolysis or its mixture added to a conventional fracturing fluid.
  • the particulates may be of different molecular weight, size distribution, shape, and concentration selected to control fluid loss, cake compressibility, and/or the rate of hydrolysis.
  • the rate of hydrolysis may also be controlled by coating the particles.
  • liquid acids may be selected that are encapsulated.
  • encapsulated fumaric acid may be used in some embodiments.
  • the acids any suitable encapsulation material or method may be used.
  • the acid is encapsulated with oil, which may affect acid dissolution and/or hydrolysis rates.
  • the particle size distribution of the additive when optimized will help improve fluid loss control.
  • the rate of hydrolysis will control the rate at which the emulsion is reversed, the fracture is cleaned, and the polymer degrades.
  • the smaller size particles will have higher surface area that will hydrolyze faster compared with larger size particles.
  • the use of PGA, PVAc, PLA, or its copolymer, or its different degree of hydrolysis or its mixture may also be used in conjunction with other fluid loss additives, polymers, polymer breakers, crosslinked polymers, and crosslinkers.
  • the additive materials may be in any shape: for example, powder, particulates, chips, fiber, bead, ribbon, tubular, platelet, film, rod, strip, spheroid, toroid, pellet, tablet, capsule, shaving, any round cross-sectional shape, any oval cross-sectional shape, trilobal shape, star shape, flat shape, rectangular shape, cubic, bar shaped, flake, cylindrical shape, filament, thread, or mixtures thereof.
  • the additives may be solid materials, either amorphous or/and crystalline in nature, may even be hollow. Additive densities are not critical, and will preferably range from below about 0.1 to about 4 g/cm3 or more.
  • the additives may be naturally occurring and synthetically prepared, or mixture thereof.
  • An effective fluid contains a reversible emulsion and an acid generating, degradable solid particulate additive.
  • the reversible emulsion of water-in-oil contains an amphoteric surfactant with a hydrophilic end and a lipophilic end that aids in reversing the emulsion to oil-in-water when the pH is reduced towards the acid range. On increasing the pH towards the basic range the emulsion can revert back to water in oil.
  • Figure 1 shows a schematic of a reversible emulsion.
  • the degradable acid generating particulates may contain poly glycolic acid (PGA), poly vinyl acetate (PVAc), poly lactic acid (PLA), or its copolymer, or its different degree of hydrolysis or its mixture.
  • PGA poly glycolic acid
  • PVAc poly vinyl acetate
  • PLA poly lactic acid
  • any suitable acid generating compound may be used in the particulate, including, but not limited to esters, aliphatic polyesters, ortho esters, poly(ortho esters), poly(lactides), poly(glycolides), poly(e-caprolactones), poly(hydroxybutyrates), poly(anhydrides), diol esters and polyolesters such as glycol diesters and monoesters, including ethylene glycol monoesters and ethylene glycol diesters like ethylene glycol monoformate, ethylene glycol diformate, diethylene glycol diformate, diethylene glycol monoformate, triethylene glycol diformate, triethylene glycol monoformate; glyceryl esters, mono esters, diesters or triesters including glyceryl monoformate, glyceryl diformate, glyceryl triformate, and other esters such as formate esters of pentaerythritol, and in general any esters such as acetates, propionates
  • the particulate additive generates acid upon hydrolysis. Initially the solid particulate additive gets collected on to the formation face, acts as bridging agents, controls fluid loss and becomes an integral part of the filtercake through the filtration process. Subsequently, with time and temperature the particulates hydro lyze and generate acid that reverses the emulsion.
  • the emulsion reversal helps in altering the formation wettability from oil wet to water wet thus enhancing the productivity.
  • the deformable water droplets accumulated in the filtercake helps in the hydrolysis of the solid particulate additives and cleans up the filtercake as shown in Figure 2. In addition the emulsion also significantly reduces the fluid loss compared with a conventional water based fluid.
  • the pH of the system may be controlled by adding either organic or inorganic acids that are in the solid or liquid form.
  • Preferred mineral acids include hydrochloric acid, sulfuric acid, nitric acid, phosphoric acid, hydroflouric acid, and hydrobromic acid.
  • Preferred organic acids include citric acid, tartaric acid, acetic acid, propionic acid, glycolic acid, lactic acid.
  • the acid may also be generated through hydrolysis of polyanhydrides, polyesters, polyamides, polyurethanes, polyurea and polycarbonates.
  • the specific polymers for hydrolysis includes aliphatic polyesters; poly(lactides); poly(glycolides); poly( ⁇ -caprolactones); poly(hydroxybutyrates); aliphatic polycarbonates; poly(orthoesters); poly(amides); poly(urethanes); poly(hydroxy ester ethers); poly(anhydrides); aliphatic polycarbonates; poly(orthoesters); poly(amino acids); poly (ethylene oxide).
  • the pH control is highly desirable since it is used as a trigger to reverse the emulsion. While any suitable pH value may be used to achieve the benefits of the invention, a typical range of operation is from about 2 to about 12. At high pH (basic) the emulsion is water in oil. On lowering the pH (acidic) the emulsion becomes oil in water. Thus the water phase is now continuous. This has many advantages including the following.
  • An example is of PLA, PGA, polyvinyl acetate and polysuccinimide solids that will hydro lyze with time at or above about 107 0 C for PLA, polyvinyl acetate and polysuccinimide, and at or below about 107 0 C for PGA. These materials are capable of generating acid in situ and will reverse the emulsion.
  • the PLA, PGA etc will initially act as fluid loss additive however with time and temperature it will degrade through hydrolysis.
  • the formation temperature range in which some methods are optimally applied are from about 49 0 C to about 121 0 C.
  • reversible emulsion fluids used in some embodiments may be used to transport and suspend particles such as proppant, sand, gravel, and the like, to a target area in the formation.
  • solid particles are added stabilize emulsions, at least in part.
  • the incorporation of solids into the emulsion may allow a slow down the breakdown of emulsion in the preparation phase, and thus require less emulsifier and less mixing time and energy.
  • the may help mixing the emulsion on the fly during an operation, rather than batch mixing.
  • Figure 3 illustrates how 2 weight percent of PGA added to the baseline (reversible water-in-oil emulsion only) lowers the viscosity at 79 0 C.
  • the viscosity increases initially and thereafter decreases and remains steady for up to 15 hours. This shows that time and concentration may be tailored to control viscosity.
  • the repeat data plot illustrates the variability in the trials. To summarize, generally, over time, the emulsion reverses.
  • Figure 4 shows that at 3 weight percent of PGA, the viscosity of the emulsion increases at 79 0 C, 93 0 C and 107 0 C. This feature may be desired where the fluid needs to be used as a proppant carrier and have hindered settling and may be especially important for gravel packing operations that are performed at high temperature or for clean-up operations that need particle suspension. In addition, after the initial increase in viscosity it remains constant for up to 15 hours. There is no evidence of viscosity degrading with time. The same behavior was observed at 2 weight percent PGA concentration at 79 0 C. That is, increased PGA concentration leads to increased viscosity in this embodiment.
  • Figure 5 is a plot of fluid loss as a function of time comparing an emulsion and 3 weight percent PGA fluid for an embodiment of the invention. Adding acid generating solids (3 wt% PGA) to the fluid reduces fluid loss. This is desirable because the resulting filter cake is thinner than systems that do not have the solid PGA present.
  • Figure 6 is a plot of electrical stability and pH as a function of volume of citric acid. The electrical stability drops sharply with increasing acid indicating emulsion reversal from water dispersed to water continuous phase. However, the pH gradually changes and does not follow the same slope as the electrical stability, although this trend may be not exact because it is difficult to measure pH of an emulsion. Generally, this plot indicates that the emulsion is reversing as the pH decreases. However, this plot was collected at 20 0 C and the phenomena may be different for 175 0 C applications.

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  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Colloid Chemistry (AREA)
  • Compositions Of Macromolecular Compounds (AREA)
  • Processes Of Treating Macromolecular Substances (AREA)

Abstract

Les modes de réalisation de la présente invention concernent un procédé de traitement d'une formation souterraine pénétrée par un puits de forage comprenant la formation d'un fluide comprenant une émulsion inverse et un matériau dégradable, l'introduction du fluide à l'intérieur d'un puits de forage, et l'étape consistant à permettre au matériau dégradable de se dégrader. D'autres modes de réalisation de la présente invention concernent un procédé de traitement d'une formation souterraine pénétrée par un puits de forage comprenant la formation d'un fluide comprenant une émulsion inverse et un additif de perte de fluide, l'introduction du fluide à l'intérieur d'un puits de forage, et l'étape consistant à permettre à l'additif de perte de fluide de se dégrader.
PCT/IB2010/053505 2009-08-14 2010-08-02 Emulsion réversible incorporée solide pour une boue de fracturation Ceased WO2011018733A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US12/583,134 US20110036582A1 (en) 2009-08-14 2009-08-14 Solid incorporated reversible emulsion for a fracturing fluid
US12/583,134 2009-08-14

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Publication Number Publication Date
WO2011018733A1 true WO2011018733A1 (fr) 2011-02-17

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WO (1) WO2011018733A1 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9828567B2 (en) 2012-03-30 2017-11-28 Idemitsu Kosan Co., Ltd. Lubricating oil composition for refrigerating machines

Families Citing this family (3)

* Cited by examiner, † Cited by third party
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US8770279B2 (en) * 2011-01-13 2014-07-08 Halliburton Energy Services, Inc. Nanohybrid phase interfaces for foaming in oil field applications
US20140054039A1 (en) * 2012-08-23 2014-02-27 Schlumberger Technology Corporation Materials and methods to prevent fluid loss in subterranean formations
GB2537509B (en) * 2014-01-17 2021-05-12 Halliburton Energy Services Inc Methods and compositions to use shape changing polymers in subterranean formations

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WO1998005733A1 (fr) * 1996-08-02 1998-02-12 M-I Drilling Fluids L.L.C. Fluide de forage ameliore a base d'huile
US20040147404A1 (en) * 2003-01-24 2004-07-29 Thaemlitz Carl J. Invertible well bore servicing fluid
EP1493898A1 (fr) * 2003-06-03 2005-01-05 Halliburton Energy Services, Inc. Traitement de puits de forage avec des émulsions inversables huile-eau
WO2007088322A1 (fr) * 2006-01-31 2007-08-09 Bp Exploration Operating Company Limited Fluide de forage comprenant un fluide de base et un agent de pontage particulaire
US20080139416A1 (en) * 2006-12-12 2008-06-12 Rimassa Shawn Mccleskey Fluid Loss Control and Well Cleanup Methods
WO2009006326A2 (fr) * 2007-07-02 2009-01-08 M-I Llc Fluide porteur pour filtrage de graviers avec marteau interne

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KR100615099B1 (ko) * 2005-02-28 2006-08-22 삼성전자주식회사 저항 소자를 구비하는 반도체 소자 및 그 제조방법.
US7565929B2 (en) * 2006-10-24 2009-07-28 Schlumberger Technology Corporation Degradable material assisted diversion
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Publication number Priority date Publication date Assignee Title
WO1998005733A1 (fr) * 1996-08-02 1998-02-12 M-I Drilling Fluids L.L.C. Fluide de forage ameliore a base d'huile
US20040147404A1 (en) * 2003-01-24 2004-07-29 Thaemlitz Carl J. Invertible well bore servicing fluid
EP1493898A1 (fr) * 2003-06-03 2005-01-05 Halliburton Energy Services, Inc. Traitement de puits de forage avec des émulsions inversables huile-eau
WO2007088322A1 (fr) * 2006-01-31 2007-08-09 Bp Exploration Operating Company Limited Fluide de forage comprenant un fluide de base et un agent de pontage particulaire
US20080139416A1 (en) * 2006-12-12 2008-06-12 Rimassa Shawn Mccleskey Fluid Loss Control and Well Cleanup Methods
WO2009006326A2 (fr) * 2007-07-02 2009-01-08 M-I Llc Fluide porteur pour filtrage de graviers avec marteau interne

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9828567B2 (en) 2012-03-30 2017-11-28 Idemitsu Kosan Co., Ltd. Lubricating oil composition for refrigerating machines

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