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WO2014089147A1 - Procédés pour augmenter la perméabilité d'une formation souterraine - Google Patents

Procédés pour augmenter la perméabilité d'une formation souterraine Download PDF

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Publication number
WO2014089147A1
WO2014089147A1 PCT/US2013/072984 US2013072984W WO2014089147A1 WO 2014089147 A1 WO2014089147 A1 WO 2014089147A1 US 2013072984 W US2013072984 W US 2013072984W WO 2014089147 A1 WO2014089147 A1 WO 2014089147A1
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WO
WIPO (PCT)
Prior art keywords
hydrolyzed liquid
subterranean formation
liquid ester
treatment fluid
ester
Prior art date
Application number
PCT/US2013/072984
Other languages
English (en)
Inventor
Eric Davidson
Steven Ray Blattel
Original Assignee
Halliburton Energy Services, 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 Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Publication of WO2014089147A1 publication Critical patent/WO2014089147A1/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
    • E21B43/25—Methods for stimulating production
    • 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
    • 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
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds

Definitions

  • the present invention relates to methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore. More particularly, the present invention relates to the use of non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst.
  • Acidizing fluids have been used to increase the productivity of oil and gas from calcareous formations by effecting the removal of reactive materials from naturally occurring fractures and pore spaces in the formations whereby the sizes thereof are increased. Acidizing fluids also have been used to create new fractures in formations with the acid acting to etch the fractures so that they remain open and have a high flow capacity.
  • reaction time The time required for the acidizing fluid to become spent.
  • reaction time The time required for the acidizing fluid to become spent.
  • the present invention relates to methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore. More particularly, the present invention relates to the use of non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst.
  • Some embodiments of the present invention provide methods comprising : providing a subterranean formation that has been fractured; providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid; introducing the treatment fluid into the fracture at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate into at least a portion of the subterranean formation surrounding the fracture; and leaving the treatment fluid in contact with the subterranean formation surrounding the fracture for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid .
  • Other embodiments of the present invention provide methods comprising : providing a subterranean formation surrounding a wellbore; providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid; introducing the treatment fluid into a portion of the subterranean formation surrounding a wellbore at matrix flow rates to allow the non- hydrolyzed liquid ester to penetrate the formation; and leaving the treatment fluid in contact with the subterranean formation surrounding a wellbore for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid .
  • the present invention relates to methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore. More particularly, the present invention relates to the use of non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst.
  • the present invention provides a method of treating a portion of a carbonate-containing subterranean formation to increase the formation permeability.
  • a treatment fluid comprising a non- hydrolyzed liquid ester is introduced into the portion of the subterranean formation and allowed to penetrate into the formation at matrix rate/pressure. Once placed, the non-hydrolyzed liquid ester is allowed to remain in contact with the portion of the subterranean formation. Over time under formation temperature, the non-hydrolyzed liquid ester hydrolyzes to produce an acid that is capable of chemically attacking the carbonate portions of the formation to create additional porosity and permeability therein.
  • the methods of the present invention are able to generate an acid to increase formation permeability using a non-hydrolyzed liquid ester without the necessity of any catalyst or enzyme. Rather, the acid is generated directly from the non-hydrolyzed liquid ester in contact with water over time and temperature.
  • the non-hydrolyzed liquid ester is able to penetrate deep into the formation before the acid is created and consumed in the carbonate attack. Because of this, the methods of the present invention are capable of increasing permeability deep in the formation, rather than just at the fracture face.
  • the methods of the present invention are suitable for use in any acid-soluble formation make-up, but may be particularly useful in limestone, dolomitic, or chalk formations. However, the methods of the present invention may be less suited for use in sandstone formations, which often has acid soluble material as the inter-grain cementing material and so the introduction of the proposed non-hydrolyzed liquid esters destabilize the treated section.
  • the non-hydrolyzed liquid ester is placed into a portion of the subterranean formation as part of a larger treatment fluid .
  • the treatment fluid comprises a base fluid and may comprise additional additives as well .
  • the non-hydrolyzed liquid esters are included in the treatment fluid in an amount ranging from about 5% to about 40% by volume of the treatment fluid . In some preferred embodiments, the non-hydrolyzed liquid esters are included in the treatment fluid in an amount ranging from about 10% to about 30% by volume of the treatment fluid .
  • Suitable base fluids for use in conjunction with the present invention are generally aqueous-based fluids such as fresh water, saltwater (e.g. , water containing one or more salts dissolved therein), brine (e.g. , saturated salt water), seawater, and any combination thereof. Brines may be particularly preferred . Any brine known in the art may be suitable for use in the methods of the present invention, such as calcium-bromide, magnesium- bromide, potassium-bromide, sodium-bromide; calcium-chloride, magnesium- chloride, potassium-chloride, or sodium-chloride; and combinations thereof.
  • the brine may comprise salts of monovalent cations or salts of organic acids, such as formate brines or acetate brines.
  • Suitable non-hydrolyzed liquid esters for use in the present invention may include, but are not limited to formate esters, acetate esters, and lactate esters.
  • the non-hydrolyzed liquid ester may be diethylene glycol diformate, a glycolate, glycerin triacetate (also known as triacetin), glycerin diacetate (also known as diacetin), ethyl lactate, acetate esters, methyl lactate, ethylene glycol monoformate, ethyl formate, methyl formate, or a combination thereof.
  • the non- hydrolyzed liquid ester for use in the present invention is a formate ester or a combination of formate esters.
  • selection of the non-hydrolyzed liquid ester will be dependent, at least in part, on the temperature of the formation being treated .
  • ethyl lactate reacts too slowly at 70°C to be suitable for use in treating formations at that temperature.
  • diethylene glycol diformate and ethylene glycol monoformate may be well-suited for treatment at 70°C, but less well suited for a higher temperature formation .
  • diethylene glycol diformate is well-suited for formation temperatures up to about 90°C and ethyl lactate is well-suited for formation temperatures above 90°C and as high as 150°C.
  • the non-hydrolyzed liquid ester Once the non-hydrolyzed liquid ester is placed into a subterranean formation, it must be allowed to remain in contact for a period of time ranging from about 1 hour and above.
  • the contact time may range from about 2 hours to about 72 hours.
  • the methods of the present invention are well suited for subterranean formations that exhibit a natural temperature of at least about 50°C, preferably at least about 70°C. While lower temperature formations can be treated with the methods of the present invention, the time it takes for the ester to hydrolyze may make the methods impractical in that they would require lengthy shut-in periods. Similarly, formations that exhibit temperatures greater than 175°C may result in such rapid hydrolysis of the ester that the penetration into the formation is less than desired.
  • the non-hydrolyzed liquid ester is placed deep into the formation to provide a wide area of treatment.
  • the non-hydrolyzed liquid ester is placed at least about 300 cm into the formation before the acid is spent. In other preferred embodiments, the non-hydrolyzed liquid ester may be placed several meters into the formation before the acid is spent.
  • the treatment fluid comprising a non- hydrolyzed liquid ester is placed into the formation surrounding a fracture directly after the fracturing treatment is completed and before the fracture pressure has been released .
  • the treatment fluid itself is not put into the formation at a pressure sufficient to cause additional fracturing, rather it is placed at matrix rates.
  • the treatment fluid comprising a non-hydrolyzed liquid ester may be placed directly into a subterranean formation, with or without a fracture being formed in advance.
  • a pre-flush fluid may first be introduced into the subterranean formation .
  • Pre-flush fluids may aid in removing debris from the flow path, displacing reservoir fluids, and/or preconditioning the unconsolidated particulates for accepting the non-hydrolyzed liquid ester.
  • Suitable examples of pre-flush fluids for use in the methods of the present invention may include, but are not limited to aqueous fluids, solvent-based fluids, or gas-based fluids.
  • the aqueous pre-flush fluid may comprise, for example, fresh water; saltwater; brine and any combinations thereof.
  • aqueous pre-flush fluids may be from any source, provided that they do not contain components that adversely affect the stability and/or performance of the treatment fluids of the present invention .
  • solvent-based pre-flush fluids may comprise a glycol ether solvent, such as diethylene glycol monomethyl ether; diethylene glycol dimethyl ether; ethylene glycol monobutyl ether; diethylene glycol monobutyl ether, dipropylene glycol monomethyl ether; or any combinations thereof.
  • a gas pre-flush fluid is applied, the fluid may be applied in an amount from about 25 to about 200 cubic feet per foot of the interval to be treated, depending on the temperature and pressure of the interval of interest.
  • a pre-flush may be performed multiple times, as needed . Multiple pre-flush treatments may include the same or different pre-flush fluids.
  • post-flush fluid may facilitate removal of excess treatment fluid from the pore spaces in the subterranean formation and may enhance post-treatment permeability.
  • suitable post-flush fluids include, but are not limited to, a gas (e.g. , air, nitrogen, and the like); an aqueous fluid, a foamed aqueous fluid (e.g. , a brine); and a hydrocarbon fluid (e.g., diesel, kerosene, and the like).
  • the fluid may be applied in an amount from about 25 to about 200 cubic feet per foot of the interval to be treated, depending on the temperature and pressure of the interval of interest.
  • the fluid may be applied in an amount from about one to two times the volume of the treatment fluids used .
  • One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate type and amount of post-flush fluid to include in the methods of the present invention .
  • the pre-flush, treatment, and post-flush of the present invention may further comprise one or more additives suitable for use in the particular subterranean operation.
  • Suitable additives may include, but are not limited to, a salt, a weighting agent, an inert solid, a fluid loss control agent, an emulsifier, a dispersion aid, a corrosion inhibitor, an emulsion thinner, an emulsion thickener, a viscosifying agent, a gelling agent, a surfactant, a particulate, a proppant, a gravel particulate, a lost circulation material, a foaming agent, a gas, a pH control additive, a breaker, a biocide, a crosslinker, a stabilizer, a chelating agent, a mutual solvent, a reducer, a friction reducer, a clay stabilizing agent, and any combinations thereof.
  • the pre-flush, treatment, and post-flush fluids of the present invention may be prepared by any method suitable for a given subterranean operation.
  • certain components of the treatment fluids may be provided in a pre-blended powder, solid, or liquid form, which may be combined with the treatment fluids of the present invention at a subsequent time.
  • the pre-flush, treatment, and post-flush fluids of the present invention may be bullheaded into the well (i.e. , pumped into the wellbore without the use of isolation tools or barrier devices) or placed using coiled tubing or jointed pipe to treat specific intervals of interest.
  • a pressure pulsing or rotating hydrojetting tool may be coupled with the coiled tubing or jointed pipe to aid in placement of the treatment or post-flush fluids in the subterranean formation.
  • Embodiments disclosed herein include methods comprising : providing a subterranean formation surrounding a wellbore; providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid; introducing the treatment fluid into a portion of the subterranean formation surrounding a wellbore at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate the formation; and leaving the treatment fluid in contact with the subterranean formation surrounding a wellbore for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid.
  • the methods may have one or more of the following additional elements in any combination :
  • Element 1 The method wherein the subterranean formation surrounding a wellbore has been fractured .
  • Element 2 The method wherein the non-hydrolyzed liquid ester hydrolyzes to produce an acid without the presence of a catalyst or enzyme.
  • Element 3 The method wherein the non-hydrolyzed liquid ester agent comprises a formate ester, a lactate ester, and any combination thereof.
  • Element 4 The method wherein the non-hydrolyzed liquid ester agent comprises diethylene glycol diformate, a glycolate, glycerin triacetate, glycerin diacetate, ethyl lactate, an acetate ester, methyl lactate, ethylene glycol monoformate, an ethyl formate, a methyl formate, and any combination thereof.
  • Element 5 The method wherein the step of introducing the treatment fluid into the fracture at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate into at least a portion of the subterranean formation surrounding the fracture, causes the non-hydrolyzed liquid ester to penetrate into the formation to a depth of at least about 300 cm .
  • Element 6 The method wherein the period of time is at least about 2 hours.
  • Element 7 The method wherein the subterranean formation surrounding the fracture has a temperature above about 50°C and below about 175°C.
  • Element 8 The method wherein the non-hydrolyzed liquid ester is present in the treatment fluid in an amount ranging from about 5% to about 40% by volume of the treatment fluid.
  • Element 9 The method wherein the base fluid is an aqueous fluid
  • exemplary combinations include Elements 1, 4, and 5; Elements 2, 7, and 8; and Elements 4, 6, and 8.
  • EXAMPLE 1 One medium permeability limestone core and one low permeability limestone core were tested for initial and post-treatment permeability. Before testing began, each core was vacuum saturate with 3% KCI bine overnight. The medium permeability limestone core had an initial permeability of 153 mD and the low permeability limestone core had an initial permeability of 5.8 mD. Each of the cores was injected with a 10% by volume of diethylene glycol diformate in a sodium bromide brine having a specific gravity of 1.2.
  • the injected cores were then held static for 16-hours at 70°C. Following the hold period, the permeability was re-checked and the medium permeability limestone core had a revised permeability of 192 mD (a 25% increase) and the low permeability limestone core had an initial permeability of 14.7 mD (a 153% increase).
  • EXAMPLE 2 A low permeability core was injected with a 10% by volume of ethyl lactate in a sodium bromide brine having a specific gravity of 1.2. Before testing began, the core was vacuum saturated with 3% KCI brine overnight. The injected core was then held static for 48-hours at 70°C. No significant increase in permeability was detected . As a follow-up, a low permeability core was injected with a 17.5% by volume of ethyl lactate in a sodium bromide brine having a specific gravity of 1.2. Before testing began, the core was vacuum saturated with 3% KCI brine overnight. The injected core was held static at 120°C for 48 hours. Again, no increase in permeability was detected .
  • EXAMPLE 4 Two limestone cores were initially evaluated to determine average pore diameters before and after treatment. The cores analyzed were treated with 10% by volume diethylene glycol diformate in a 1.2 specific gravity sodium bromide brine at 70°C for 16 hours. The pore diameter results were as follows:
  • the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein.
  • the particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein.
  • no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention.
  • the invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein.
  • compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed . In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
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Abstract

L'invention concerne des procédés pour augmenter la perméabilité d'une portion de formation souterraine entourant un puits de forage au moyen d'esters liquides non hydrolysés pour attaquer les carbonates dans des formations acidosolubles sans nécessité d'utiliser un catalyseur ou une enzyme. Certains procédés comprennent les étapes consistant à obtenir un fluide de traitement comprenant un ester liquide non hydrolysé dans un fluide de base ; introduire le fluide de traitement dans une formation souterraine à des débits de matrice qui permettent à l'ester liquide non hydrolysé de pénétrer dans au moins une portion de la formation souterraine ; et laisser le fluide de traitement en contact avec la formation souterraine pendant une période de temps pendant laquelle au moins une partie de l'ester liquide non hydrolysé s'hydrolyse pour produire un acide.
PCT/US2013/072984 2012-12-06 2013-12-04 Procédés pour augmenter la perméabilité d'une formation souterraine WO2014089147A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US13/706,930 2012-12-06
US13/706,930 US20140158359A1 (en) 2012-12-06 2012-12-06 Methods for Increasing Subterranean Formation Permeability

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WO2014089147A1 true WO2014089147A1 (fr) 2014-06-12

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CA3089878A1 (fr) 2018-02-15 2019-08-22 Saudi Arabian Oil Company Procede et materiau d'isolement d'une zone de perte importante
US10954427B2 (en) 2018-05-17 2021-03-23 Saudi Arabian Oil Company Method and composition for sealing a subsurface formation
US10745610B2 (en) 2018-05-17 2020-08-18 Saudi Arabian Oil Company Method and composition for sealing a subsurface formation
US10920121B1 (en) 2020-03-18 2021-02-16 Saudi Arabian Oil Company Methods of reducing lost circulation in a wellbore using Saudi Arabian volcanic ash
US11820707B2 (en) 2020-03-18 2023-11-21 Saudi Arabian Oil Company Geopolymer cement slurries, cured geopolymer cement and methods of making and use thereof
US11015108B1 (en) 2020-03-18 2021-05-25 Saudi Arabian Oil Company Methods of reducing lost circulation in a wellbore using Saudi Arabian volcanic ash
US11098235B1 (en) 2020-03-18 2021-08-24 Saudi Arabian Oil Company Methods of converting drilling fluids into geopolymer cements and use thereof
US11066899B1 (en) 2020-03-18 2021-07-20 Saudi Arabian Oil Company Methods of sealing a subsurface formation with saudi arabian volcanic ash
US11820708B2 (en) 2020-03-18 2023-11-21 Saudi Arabian Oil Company Geopolymer cement slurries, cured geopolymer cement and methods of making and use thereof

Citations (5)

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Publication number Priority date Publication date Assignee Title
US7237609B2 (en) * 2003-08-26 2007-07-03 Halliburton Energy Services, Inc. Methods for producing fluids from acidized and consolidated portions of subterranean formations
US7825073B2 (en) * 2004-07-13 2010-11-02 Halliburton Energy Services, Inc. Treatment fluids comprising clarified xanthan and associated methods
US20110028358A1 (en) * 2009-07-30 2011-02-03 Welton Thomas D Methods of Fluid Loss Control and Fluid Diversion in Subterranean Formations
US20110214868A1 (en) * 2010-03-05 2011-09-08 Funkhouser Gary P Clean Viscosified Treatment Fluids and Associated Methods
WO2012171858A1 (fr) * 2011-06-13 2012-12-20 Akzo Nobel Chemicals International B.V. Procédé pour fracturer une formation sous-terraine à l'aide d'un agent chélatant

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7237609B2 (en) * 2003-08-26 2007-07-03 Halliburton Energy Services, Inc. Methods for producing fluids from acidized and consolidated portions of subterranean formations
US7825073B2 (en) * 2004-07-13 2010-11-02 Halliburton Energy Services, Inc. Treatment fluids comprising clarified xanthan and associated methods
US20110028358A1 (en) * 2009-07-30 2011-02-03 Welton Thomas D Methods of Fluid Loss Control and Fluid Diversion in Subterranean Formations
US20110214868A1 (en) * 2010-03-05 2011-09-08 Funkhouser Gary P Clean Viscosified Treatment Fluids and Associated Methods
WO2012171858A1 (fr) * 2011-06-13 2012-12-20 Akzo Nobel Chemicals International B.V. Procédé pour fracturer une formation sous-terraine à l'aide d'un agent chélatant

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AR093868A1 (es) 2015-06-24
US20140158359A1 (en) 2014-06-12

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