WO2011092637A2 - Utilisation de solides et de fibres réactifs dans des applications de nettoyage et de stimulation d'un puits de forage - Google Patents

Utilisation de solides et de fibres réactifs dans des applications de nettoyage et de stimulation d'un puits de forage Download PDF

Info

Publication number
WO2011092637A2
WO2011092637A2 PCT/IB2011/050345 IB2011050345W WO2011092637A2 WO 2011092637 A2 WO2011092637 A2 WO 2011092637A2 IB 2011050345 W IB2011050345 W IB 2011050345W WO 2011092637 A2 WO2011092637 A2 WO 2011092637A2
Authority
WO
WIPO (PCT)
Prior art keywords
fluid
particle size
average particle
acid
wellbore
Prior art date
Application number
PCT/IB2011/050345
Other languages
English (en)
Other versions
WO2011092637A3 (fr
Inventor
M. Nihat Gurmen
Daniel Kalinin
Ryan Hellman
Oscar Bustos
J. Ernest Brown
Michael J. Fuller
Ling Kong Teng
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
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 Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited filed Critical Schlumberger Canada Limited
Priority to CA2787381A priority Critical patent/CA2787381A1/fr
Priority to EP11736692.2A priority patent/EP2516580A4/fr
Priority to EA201290742A priority patent/EA201290742A1/ru
Priority to MX2012008854A priority patent/MX2012008854A/es
Publication of WO2011092637A2 publication Critical patent/WO2011092637A2/fr
Publication of WO2011092637A3 publication Critical patent/WO2011092637A3/fr

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/52—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
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/30—Viscoelastic surfactants [VES]

Definitions

  • This invention relates to methods and fluids used in treating a subterranean formation.
  • the invention relates to the preparation and use of reactive solids and fibers in wellbore clean-out and stimulation applications.
  • This invention relates to a composition and method for stimulation and for removing impermeable layers created for fluid loss control in a subterranean formation. More particularly it relates to the use of a fluid containing a delayed solid acid material that can either remove drilling mud filtercakes or create a self-destructing filtercake in subterranean formations that require fluid loss control.
  • a thin layer of impermeable material is deposited on the reservoir rock by the drilling fluid (or mud).
  • This thin layer of material is called a filtercake and aids in controlling drilling fluid leak-off into the formation and restricts the inflow of reservoir fluids into the well during completion. If the filtercake that is created during the drilling process is not removed prior to or during completion of the well, problems may occur when the well is put on production. These may include completion equipment failures, such as erosion and plugging of the equipment, and impaired reservoir productivity, which may be in the form of early water production or water coning.
  • the major components typically found in conventional drilling mud filtercake include such materials as polymers, carbonates and other inorganic salts, and clays. Removal of the mud filtercake can be accomplished through mechanical means (scrapping, jetting, underreaming, etc).
  • Conventional chemical treatments for removing filtercake include pumping aqueous solutions with an oxidizer (such as persulfate), inorganic acids (such as HCl), organic acids (such as acetic or formic acids), chelating agents (such as EDTA), enzymes or combinations of these.
  • an oxidizer such as persulfate
  • inorganic acids such as HCl
  • organic acids such as acetic or formic acids
  • chelating agents such as EDTA
  • enzyme or oxidizer soaks to hydrolyze polymeric components of the filtercake
  • an acid treatment is also ineffective, since the reaction of the acid with carbonate bridging agents in the absence of coating with polymeric components (as it would be after the enzyme or oxidizer soak) is much faster than the reaction of acid with all components of the filtercake intact, causing the same problems.
  • Embodiments of this invention relate to a method to treat a subterranean formation including introducing a fluid comprising degradable material into a wellbore, contacting a surface of the wellbore with the fluid, and stimulating a surface of a subterranean formation, wherein the contacting the wellbore surface and stimulating the formation occur over a time period that is tailored by the properties of the degradable material.
  • the properties of the degradable material include a chemical composition, a surface area, a geometric shape of a particle of the material, a concentration of the material in the fluid, a density of the material, a dimension of a particle of the material, or a combination thereof.
  • Figure 1 shows the rheology of 5% NaCl brine and 6% erucic amidopropyl dimethyl betaine at 207 degress F.
  • Fii *ure 2 is a plot of pH as a function of time for Tests 1-3 of Table 2 at 158 degrees F.
  • Fii *ure 3 is a plot of pH as a function of time for Tests 4-6 of Table 2 at 158 degrees F.
  • Fii *ure 4 is a plot of pH as a function of time for Tests 7-9 of Table 3 at 158 degrees F.
  • Fii *ure 5 is a plot of pH as a function of time for Tests 10-12 of Table 3 at 158 degrees F
  • Fij *ure 6 is a plot of pH as a function of time for Tests 1 and 3 of Table 2 at 200 degrees
  • Fii *ure 7 is a plot of pH as a function of time for Tests 4 and 6 of Table 2 at 200 degrees
  • Fii *ure 8 is a plot of pH as a function of time for Tests 7 and 9 of Table 3 at 200 degrees
  • Figure 9 is a plot of pH as a function of time for Tests 10 and 12 of Table 3 at 200 degrees F.
  • composition used/disclosed herein can also comprise some components other than those cited.
  • each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context.
  • a concentration range listed or described as being useful, suitable, or the like is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10.
  • the process of cleanout and stimulation happens simultaneously or one after the other. For example, once the solid acid hydrolyzes, acid is generated, then acid reacts with the filtercake, and any remaining hydrolyzed acid will react with the carbonate formation. In the wellbore, there is enough solid acid to react with carbonate material in the filter cake and additionally to react with the formation.
  • the hydrolyzed acid performs a wellbore enlargement and/or fissure cleanout, which could be considered one stimulation technique.
  • hydrolysis of the solid or chelant, such as solid acid will not be intermediate. Therefore, the non-hydrolyzed solid acid will form temporarily filtercake and will block any pinholes which would lead to more even mud cake dissolution; eventually all solid acid will hydrolyze and be consumed.
  • This technology utilizes solid acid, such as polylactic acid, to dissolve calcium carbonate- based filter cake from water based fluids. Also, the acid stimulates the near-wellbore region in openhole wells completed in carbonate formations.
  • the solid acid is an inert substance under surface conditions but hydrolyzes into an acid under downhole conditions after a certain time influenced by bottomhole temperature. This mechanism will allow for a delayed reaction time which will be useful when it is placed with a rig after drilling the openhole section. It will give the rig time to pull out of hole and skid off the well before the acid reacts, preventing losses and well control issues.
  • the solid acid will also simplify pumping operations since the fluid is non- corrosive and simple to place.
  • the solid acid will be mixed with a carrier fluid and pumped from the surface and placed in the openhole section.
  • the solid acid will then hydrolyze and react with the near-wellbore region, allowing for wellbore cleanout and matrix stimulation. This could be applied in hydrocarbon producing wells or water injection wells.
  • Degradable material like PLA, PGA, etc. could be used to enhance productivity or injectivity of wells as described here. Generally, as the material degrades, it releases acid that may stimulate the surfaces it encounters. Time and temperature of exposure will influence the solubility of the material and how the material degrades. Some embodiments may benefit from the use of a prepad treatment to cool the formation, which is especially important for high temperature wells when delay of the reaction is needed. The concentration of the material may be varied depending on various parameters of the system. Some embodiments may benefit from the material in concentrations of about 0.5 ppa of degradable material.
  • the pH of the fluid is important to how the system works. Specifically, the fluid should be tailored to have a neutral pH in a range of 5-8 pH. The pH will be reduced as the degradable solid hydrolyzes under downhole temperature and pressure. Also, having an initially neutral pH is critical to delaying filtercake dissolution. More reactive (higher or lower pH) systems may have premature breakthrough.
  • the density of the fluid may also be tailored to a specific optimized level. This optimized density may help maintain a specific hydrostatic level to deliver pressure downhole and to suspend degradable solid particles.
  • This material could not leak-off into formation and may act as fluid loss agent, although this is not the primary intention of the use.
  • Degradation of the material is controlled by temperature of the subterranean formation so an appropriate material would be selected to provide sufficient time for retracting the pipe (if used for the placement) and run in the wellbore completion or otherwise prepare the well for production or injection. Degradation of the material via hydrolysis would result in forming a certain amount of organic acid.
  • This acid would react with the bridging material of mud filtercake (typically calcium carbonate) and subterraneous rock, thus enhancing its permeability to reservoir or injected fluids or gases. Low reaction rate of the acid also permits squeezing it into formation either under pressure of hydrostatic column or intended injection.
  • Degradable material could be in form of beads, fiber, chips, flakes, powder, or others. A combination of sized round particles could be used to enhance slurried degradable material ability to flow and reduce risk of leaving placement tubulars downhole if stuck due to local concentration of the material (degradable nature of material would make it possible to free pipe after a certain time, however, delay may not be desired).
  • Use of degradable material as standalone stimulation system is desirable and differs from use of degradable solid beads in fracturing or fiber in matrix stimulation. Use of this material for mud filtercake removal also has a potential for long reaction retardation.
  • Degradable particles would later hydrolyze and in turn react with remaining bridging material of the filtercake or reactive material of formation similarly to above example. This is different from use of fiber-like degradable material for fluid diversion because diversion would occur after placement of the reactive solution.
  • Degradable material to be introduced into a stream of fluid iniected into subterraneous formations for pressure support or other reasons whenever increase of injectivity or alteration of its distribution along length of wellbore is desired. Once enough material is placed into the wellbore, injection could be temporarily suspended or slowed to allow temperature increase to promote hydrolysis of the degradable material into stimulation fluid which would react with the subterraneous formation on wellbore face or by leaking into later, thus increasing its ability to receive more fluids or altering injectivity profile in a favorable manner. Slowing or suspending injectivity may not be required for certain degradable materials upon exposure to downhole temperatures. Such use of degradable particles as a sole stimulation system is desirable.
  • Degradable materials such as solid acids including solid polymeric acid, that may be used in this process include polylactic acid, polyglycolic acid, and benzoic acid.
  • the solid polymeric acid precursor may be made from at least one of homopolymers of lactic acid, glycolic acid, hydroxybutyrate, hydroxyvalerate and epsilon caprolactone; random copolymers of at least two of lactic acid, glycolic acid, hydroxybutyrate, hydroxyvalerate, epsilon caprolactone, L- serine, L- threonine, and L-tyrosine; block copolymers of at least two of polyglycolic acid, polylactic acid, hydroxybutyrate, hydroxyvalerate, epsilon caprolactone, L-serine, L- threonine, and L-tyrosine; homopolymers of ethylenetherephthalate (PET), butylenetherephthalate (PBT) and ethylenenaphthalate (PEN)
  • the identity of the degradable material may be selected to optimize degradation delay based on the temperature of the formation.
  • Polyglycolic acid may be more desirable when the formation temperature is low, polylactic may be more desirable when the formation temperature is above 150degF.
  • the particulate material has a first average particle size and the degradable particulate material has a second average particle size, wherein the second average particle size is between three to twenty times smaller than the first average particle size.
  • the second average particle size may be between five to ten times smaller than the first average particle size.
  • the degradable particulate material has further an amount of particulates having a third average particle size, wherein the third average particle size is between three to twenty times smaller than the second average particle size.
  • the third average particle size may be between five to ten times smaller than the second average particle size.
  • the particulate material may be of any geometry that is appropriate for the task. Fibers, flakes, cylinders, round, oblong, rod-like, beads, or other shapes that are selected for their dimensions, high-aspect-ratio size, surface area to volume ratio, surface area, volume, or any other geometry parameter that may be tailored to help the material degrade with a desired profile. Some embodiments may benefit from a mixture of particle shapes or sizes. Some embodiments may benefit from a mixture of degradable and non-degradable materials.
  • the carrier fluid for the solid acid may be any variety of fluids including drilling muds, drilling fluids, fracturing fluids, and other fluids employed by the oil field services industry.
  • Water-based fluids may benefit from the optional inclusion of additional additives including enzymes, surfactant, microemulstion, demulsifier, acid, buffers, (mutual) solvent, and carrion inhibitor.
  • Oil-based fluids may also benefit from the optional inclusion of additional additives including surfactants, microemulsions, solvents, demulsifier, and corrosion inhibitor.
  • the concentration of additives in oil-based muds may be higher than the concentration in water-based muds. Further, the oil-based fluid systems may benefit from a solvent based preflush step.
  • oil based mud may contain oil (linear paraffin, diesel, etc., water, calcium chloride, primary and secondary emulsifiers, viscosifiers such as modified clay, lime, fluid loss agent, and weighing agent such as barite or calcium carbonate.
  • oil-based fluids may be an invert emulsion, i.e., emulsions in which the non-oleaginous fluid is the discontinuous phase and the oleaginous fluid is the continuous phase.
  • the oleaginous fluid may be a liquid and more preferably is a natural or synthetic oil and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, mixtures thereof and similar compounds known to one of skill in the art; and mixtures thereof.
  • diesel oil such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl
  • the concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms, and the concentration of the oleaginous fluid may be less than about 99% by volume of the invert emulsion.
  • the amount of oleaginous fluid is from about 30% to about 95% by volume of the invert emulsion fluid and more preferably about 40% to about 90% by volume of the invert emulsion fluid.
  • the oleaginous fluid in one embodiment may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.
  • the non-oleaginous fluid used in the formulation of the invert emulsion fluid disclosed herein may be a liquid and preferably may be an aqueous liquid. More preferably, the non- oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof.
  • the amount of the non-oleaginous fluid is typically less than the theoretical limit needed for forming an invert emulsion. Thus in one embodiment the amount of non-oleaginous fluid is less that about 70% by volume of the invert emulsion fluid and preferably from about 1% to about 70% by volume of the invert emulsion fluid. In another embodiment, the non-oleaginous fluid is preferably from about 5% to about 60% by volume of the invert emulsion fluid.
  • emulsifiers and emulsifier systems for stabilizing the emulsion.
  • emulsifier, emulsifying agent, and surfactant are used
  • the emulsifying agent serves to lower the interfacial tension of the liquids so that the non-oleaginous liquid may form a stable dispersion of fine droplets in the oleaginous liquid.
  • a full description of such invert emulsions may be found in Composition and Properties of Drilling and Completion Fluids, 5th Edition, H. C. H. Darley, George R. Gray, Gulf
  • Emulsifiers that may be used in the fluids disclosed herein include, for example, fatty acids, soaps of fatty acids, amidoamines, polyamides, polyamines, oleate esters, such as sorbitan monoleate, sorbitan dioleate, imidazoline derivatives or alcohol derivatives and combinations or derivatives of the above. Additionally, the fluid may also contain surfactants that may be characterized as wetting agents. Wetting agents that may be suitable for use in the fluids disclosed herein include crude tall oil, oxidized crude tall oil, organic phosphate esters, modified imidazolines and amidoamines, alkyl aromatic sulfates and sulfonates, and the like, and combinations or derivatives of these.
  • the invert emulsion may be of the reversible type, whereby the invert emulsion may be converted from a water-in-oil type emulsion to an oil-in-water type emulsion upon exposure to acid, for example.
  • reversible oil-based fluids include those described in U.S. Patent Nos.
  • the viscosity of the fluid may be tailored to maintain suspension of degradable solid particles uniformly along the length of openholse sections to minimize settling.
  • a variety of additives may be used including viscoelastic surfactants and polymers such as guar, HEC, xantham, guar derivative, cellulose, cellulose derivative, heteropolysaccharide, heteropolysaccharide derivative, polyacrylamide, CMHPG, cationic guar, diutan, partially hydrolyzed polyacrylamide, copolymers of partially hydrolyzed polyacrylamide alginate, chitosan, or a combination thereof.
  • viscoelastic surfactants and polymers such as guar, HEC, xantham, guar derivative, cellulose, cellulose derivative, heteropolysaccharide, heteropolysaccharide derivative, polyacrylamide, CMHPG, cationic guar, diutan, partially hydrolyzed polyacrylamide, copolymers of partially hydrolyze
  • VES fluid system is a fluid viscosified with a viscoelastic surfactant and any additional materials, such as but not limited to salts, co-surfactants, rheology enhancers, stabilizers and shear recovery enhancers that improve or modify the performance of the viscoelastic surfactant.
  • the useful VES's include cationic, anionic, nonionic, mixed, zwitterionic and amphoteric surfactants, especially betaine zwitterionic viscoelastic surfactant fluid systems or amidoamine oxide viscoelastic surfactant fluid systems.
  • suitable VES systems include those described in U.S. Pat. Nos. 5,551,516; 5,964,295; 5,979,555; 5,979,557; 6,140,277; 6,258,859 and 6,509,301.
  • the system of the invention is also useful when used with several types of zwitterionic surfactants.
  • suitable zwitterionic surfactants have the formula:
  • R is an alkyl group that contains from about 14 to about 23 carbon atoms which may be branched or straight chained and which may be saturated or unsaturated; a, b, a', and b' are each from 0 to 10 and m and m' are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and (a+b) is from 2 to about 10 if m is 0; a' and b' are each 1 or 2 when m' is not 0 and (a'+b') is from 1 to about 5 if m is 0; (m+m') is from 0 to about 14; and the O in either or both CH 2 CH 2 0 groups or chains, if present, may be located on the end towards or away from the quaternary nitrogen.
  • Preferred zwitterionic surfactants include betaines.
  • betaines Two suitable examples of betaines are BET-0 and BET-E.
  • the surfactant in BET-O-30 is shown below; one chemical name is oleylamidopropyl betaine. It is designated BET-O-30 because as obtained from the supplier (Rhodia, Inc. Cranbury, New Jersey, U. S. A.) it is called Mirataine BET-O-30 because it contains an oleyl acid amide group (including a C 17 H 33 alkene tail group) and contains about 30% active surfactant; the remainder is substantially water, sodium chloride, and propylene glycol.
  • BET-E-40 An analogous material, BET-E-40, is also available from Rhodia and contains an erucic acid amide group (including a C 21 H 41 alkene tail group) and is approximately 40% active ingredient, with the remainder being substantially water, sodium chloride, and isopropanol.
  • VES systems, in particular BET-E-40 optionally contain about 1 % of a condensation product of a naphthalene sulfonic acid, for example sodium polynaphthalene sulfonate, as a rheology modifier, as described in U. S. Patent No. 7,084,095.
  • the surfactant in BET-E-40 is also shown below; one chemical name is erucylamidopropyl betaine.
  • BET surfactants and other VES's are described in U. S. Patent No. 6,258,859.
  • BET surfactants make viscoelastic gels when in the presence of certain organic acids, organic acid salts, or inorganic salts; in that patent, the inorganic salts were present at a weight concentration up to about 30%.
  • Co-surfactants may be useful in extending the brine tolerance, and to increase the gel strength and to reduce the shear sensitivity of the VES-fluid, in particular for BET-O-type surfactants.
  • An example given in U. S. Patent No. 6,258,859 is sodium dodecylbenzene sulfonate (SDBS), also shown below.
  • SDBS sodium dodecylbenzene sulfonate
  • suitable co-surfactants for BET-O-30 are certain chelating agents such as trisodium hydroxyethylethylenediamine triacetate.
  • the rheology enhancers may be used with viscoelastic surfactant fluid systems that contain such additives as co-surfactants, organic acids, organic acid salts, and/or inorganic salts.
  • Some embodiments use betaines; for example BET-E-40. Although experiments have not been performed, it is believed that mixtures of betaines, especially BET-E-40, with other surfactants are also suitable.
  • surfactants are used at a concentration of about 0.5 to about 10%, or from about 1 to about 6%, and or from about 1.5 to about 6%.
  • erucic amidopropyl dimethyl betaine may be selected, which is commercially available from Rhodia of Cranbury, New Jersey.
  • VES viscoelastic surfactant
  • other non-polymeric materials may also be used to viscosify the fluid provided that the requirements described herein for such a fluid are met, for example the required viscosity, stability, compatibility, and lack of damage to the wellbore, formation or fracture face.
  • Testing was performed to examine a wellbore cleanout fluid utilizing solid polylactic acid intended for water-based mud (WBM) applications.
  • the base cleanout fluid was 5% NaCl brine; in order to obtain good suspension of solid polylactic acid, 6% was utilized as viscosifier.
  • a B5 bob is used for the test and shear ramping: 118 rpm (100 s “1 ), 88.5 rpm (75 s “1 ), 59 rpm (50 s “1 ), 29.5 rpm (25 s “1 ), 59 rpm (50 s “1 ), 88.5 rpm (75 s “1 ), 118 rpm (100 s “1 ).
  • Interval stir rate is set at 118 rpm (100 s "1 ) between each temperature interval.
  • CaC0 3 based mud cake is prepared on a Berea Core Plug (150mD) by applying 500psi differential pressure.
  • FIG. 1 illustrates the rheology of 5% NaCl brine and 6% erucic amidopropyl dimethyl betaine at 207degF. It provides a baseline viscosity and shear rate that are relatively stable over 120 minutes.
  • the treatment fluid consists of based fluid which is 1 lppg NaBr brine, 50gallon/1000gallon of proprietary amine oxide surfactant, 25gallon/1000gallon of ethyleneglycol monobutyl ether (EGMBE), 2 gallon/1 OOOgallon of acid corrosion inhibitor and 0.5PPA of PLA-2040.
  • the retain permeability test was conducted by utilized the ceramic filter disc, 100% hydro lyzed of solid polylactic acid was observed after 12days of soaking at 207 degF. The retained permeability of the ceramic filter disc was 89.57%.
  • test bottle was placed into the pre -heated oven at 207degF for 12 days.
  • Solid polylactic acid was replaced with acetic acid in the treatment fluid to measure the difference in reactivity between the solid polylactic acid and the acetic acid. 47.9% of mud cake dissolved and dispersed after 4 days of soaking at 207degF with the treatment fluid contains solid polylactic acid. 86% of the mud cake dissolved and dispersed after 2 days of soaking at 207degF with the treatment fluid contains acetic acid. This indicate the solid polylactic acid have some delay in reaction.
  • the initial permeability of the clean ceramic disc was determined, oil based mud cake was formed with the ceramic disc.
  • the treatment fluid consists of based fluid which is 1 lppg NaBr brine, 50gallon/1000gallon of proprietary amine oxide surfactant, 25 gallon/ lOOOgallon of ethyleneglycol monobutyl ether (EGMBE), 2 gallon/1 OOOgallon of acid corrosion inhibitor and 0.5PPA of PLA-2040 was poured into the HTHP cell and soaked for 12 days at 207 degF. Final permeability of the ceramic disc was obtained. The 89.57% of retained permeability show good oil based mud-cake removal property.
  • Test 1 Test 2 Test 3 Test 4 Test 5
  • PLA-2040 0.1 ppa 0.2 ppa 0.3 ppa 0.4 ppa 0.1 ppa

Landscapes

  • 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)
  • Detergent Compositions (AREA)
  • Electrotherapy Devices (AREA)
  • Paints Or Removers (AREA)
  • Soil Conditioners And Soil-Stabilizing Materials (AREA)

Abstract

La présente invention a pour objet un procédé et un appareil pour traiter une formation souterraine comprenant les étapes consistant à introduire un fluide comprenant un matériau dégradable à l'intérieur d'un puits de forage, à mettre en contact une surface du puits de forage avec le fluide, et à stimuler une surface d'une formation souterraine, la mise en contact de la surface du puits de forage et la stimulation de la formation se déroulant sur une période de temps qui est ajustée sur mesure par les propriétés du matériau dégradable. Dans certains modes de réalisation, les propriétés du matériau dégradable comprennent une composition chimique, une surface spécifique, une forme géométrique d'une particule du matériau, une concentration du matériau dans le fluide, une densité du matériau, une dimension d'une particule du matériau, ou leur combinaison.
PCT/IB2011/050345 2010-02-01 2011-01-26 Utilisation de solides et de fibres réactifs dans des applications de nettoyage et de stimulation d'un puits de forage WO2011092637A2 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CA2787381A CA2787381A1 (fr) 2010-02-01 2011-01-26 Utilisation de solides et de fibres reactifs dans des applications de nettoyage et de stimulation d'un puits de forage
EP11736692.2A EP2516580A4 (fr) 2010-02-01 2011-01-26 Utilisation de solides et de fibres réactifs dans des applications de nettoyage et de stimulation d'un puits de forage
EA201290742A EA201290742A1 (ru) 2010-02-01 2011-01-26 Использование реакционноспособных твердых веществ и волокон при очистке ствола скважины и применения, связанные с интенсификацией
MX2012008854A MX2012008854A (es) 2010-02-01 2011-01-26 Uso de fibras y solidos reactivos en aplicaciones de estimulacion y limpieza de pozos.

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US30020310P 2010-02-01 2010-02-01
US61/300,203 2010-02-01
US12/971,927 2010-12-17
US12/971,927 US20110186293A1 (en) 2010-02-01 2010-12-17 Use of reactive solids and fibers in wellbore clean-out and stimulation applications

Publications (2)

Publication Number Publication Date
WO2011092637A2 true WO2011092637A2 (fr) 2011-08-04
WO2011092637A3 WO2011092637A3 (fr) 2011-12-29

Family

ID=44319920

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/IB2011/050345 WO2011092637A2 (fr) 2010-02-01 2011-01-26 Utilisation de solides et de fibres réactifs dans des applications de nettoyage et de stimulation d'un puits de forage

Country Status (6)

Country Link
US (1) US20110186293A1 (fr)
EP (1) EP2516580A4 (fr)
CA (1) CA2787381A1 (fr)
EA (1) EA201290742A1 (fr)
MX (1) MX2012008854A (fr)
WO (1) WO2011092637A2 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2941468A4 (fr) * 2013-01-04 2016-10-19 Halliburton Energy Services Inc Procédés utilisant des fluides de forage et de complétion aptes à une stimulation

Families Citing this family (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013040427A2 (fr) * 2011-09-15 2013-03-21 M-I L.L.C. Procédés d'utilisation de fluides oléagineux pour des opérations de complétion
CN104520946A (zh) * 2012-01-27 2015-04-15 威廉马歇莱思大学 磁性碳纳米带和磁性功能化碳纳米带的合成
WO2017062086A1 (fr) 2015-10-05 2017-04-13 Schlumberger Technology Corporation Placement de pilier organique solide in situ dans des réseaux de fractures
WO2017099705A1 (fr) * 2015-12-07 2017-06-15 Halliburton Energy Services, Inc. Traitement de produits solides commercialisés récupérés pour une utilisation dans des fluides pétroliers
US10876042B2 (en) 2016-06-17 2020-12-29 Schlumberger Technology Corporation In situ formed inorganic solids in fracture networks
US11118095B2 (en) * 2016-09-15 2021-09-14 Schlumberger Technology Corporation Compositions and methods for servicing subterranean wells
US11591907B1 (en) * 2019-10-18 2023-02-28 Horizon Mud Company, Inc. Systems and methods for providing fluid lighteners while reducing downhole emulsifications
US11802852B2 (en) 2020-06-25 2023-10-31 Saudi Arabian Oil Company Testing methodology to monitor the on-set of solid acid hydrolysis using sonic waves
US11732180B1 (en) 2022-11-30 2023-08-22 Halliburton Energy Services, Inc. Treatment composition including a polylactic acid for a well and method relating thereto

Family Cites Families (37)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5551516A (en) * 1995-02-17 1996-09-03 Dowell, A Division Of Schlumberger Technology Corporation Hydraulic fracturing process and compositions
US6218342B1 (en) * 1996-08-02 2001-04-17 M-I Llc Oil-based drilling fluid
US6806233B2 (en) * 1996-08-02 2004-10-19 M-I Llc Methods of using reversible phase oil based drilling fluid
US5964295A (en) * 1996-10-09 1999-10-12 Schlumberger Technology Corporation, Dowell Division Methods and compositions for testing subterranean formations
US6258859B1 (en) * 1997-06-10 2001-07-10 Rhodia, Inc. Viscoelastic surfactant fluids and related methods of use
US5979555A (en) * 1997-12-02 1999-11-09 Akzo Nobel Nv Surfactants for hydraulic fractoring compositions
US6140277A (en) * 1998-12-31 2000-10-31 Schlumberger Technology Corporation Fluids and techniques for hydrocarbon well completion
US6509301B1 (en) * 1999-08-26 2003-01-21 Daniel Patrick Vollmer Well treatment fluids and methods for the use thereof
WO2002008546A1 (fr) * 2000-07-22 2002-01-31 Hubertus Greschbach Module pour la construction de plates-formes
US7084095B2 (en) * 2001-04-04 2006-08-01 Schlumberger Technology Corporation Methods for controlling the rheological properties of viscoelastic surfactants based fluids
DE10140854A1 (de) * 2001-08-21 2003-03-06 Bosch Gmbh Robert Überdruckventil für einen Verpackungsbehälter und Vorrichtung zum Anbringen des Überdruckventils an einer Materialbahn
US6608006B2 (en) * 2001-09-14 2003-08-19 Halliburton Energy Services, Inc. Methods of drilling well bores using invertible oil external-water internal drilling fluids
US6978838B2 (en) * 2002-07-19 2005-12-27 Schlumberger Technology Corporation Method for removing filter cake from injection wells
US7219731B2 (en) * 2002-08-26 2007-05-22 Schlumberger Technology Corporation Degradable additive for viscoelastic surfactant based fluid systems
US7677311B2 (en) * 2002-08-26 2010-03-16 Schlumberger Technology Corporation Internal breaker for oilfield treatments
US7066260B2 (en) * 2002-08-26 2006-06-27 Schlumberger Technology Corporation Dissolving filter cake
US7265079B2 (en) * 2002-10-28 2007-09-04 Schlumberger Technology Corporation Self-destructing filter cake
EP1783188A1 (fr) * 2003-01-24 2007-05-09 Halliburton Energy Services, Inc. Fluide d'entretien renversable de puits de forage
EP1646702B1 (fr) * 2003-02-03 2007-05-16 M-I L.L.C. Agent de changement de phase retarde pour fluide de forage a emulsion inverse
US7833944B2 (en) * 2003-09-17 2010-11-16 Halliburton Energy Services, Inc. Methods and compositions using crosslinked aliphatic polyesters in well bore applications
US7222672B2 (en) * 2004-01-16 2007-05-29 Halliburton Energy Services, Inc. Wellbore fluids containing additives for removing a filter cake and methods of using the same
GB2412391A (en) * 2004-03-27 2005-09-28 Cleansorb Ltd Process for disruption of filter cakes
GB2412389A (en) * 2004-03-27 2005-09-28 Cleansorb Ltd Process for treating underground formations
US7475728B2 (en) * 2004-07-23 2009-01-13 Halliburton Energy Services, Inc. Treatment fluids and methods of use in subterranean formations
US7275596B2 (en) * 2005-06-20 2007-10-02 Schlumberger Technology Corporation Method of using degradable fiber systems for stimulation
US7665522B2 (en) * 2004-09-13 2010-02-23 Schlumberger Technology Corporation Fiber laden energized fluids and methods of use
US7677315B2 (en) * 2005-05-12 2010-03-16 Halliburton Energy Services, Inc. Degradable surfactants and methods for use
US7337839B2 (en) * 2005-06-10 2008-03-04 Schlumberger Technology Corporation Fluid loss additive for enhanced fracture clean-up
US7691789B2 (en) * 2006-03-31 2010-04-06 Schlumberger Technology Corporation Self-cleaning well control fluid
US7398829B2 (en) * 2006-09-18 2008-07-15 Schlumberger Technology Corporation Methods of limiting leak off and damage in hydraulic fractures
US7287590B1 (en) * 2006-09-18 2007-10-30 Schlumberger Technology Corporation Internal breaker for oilfield fluids
US7565929B2 (en) * 2006-10-24 2009-07-28 Schlumberger Technology Corporation Degradable material assisted diversion
US7998908B2 (en) * 2006-12-12 2011-08-16 Schlumberger Technology Corporation Fluid loss control and well cleanup methods
US7735558B2 (en) * 2007-02-22 2010-06-15 Halliburton Energy Services, Inc. Crosslinked acids comprising derivatized xanthan and subterranean acidizing applications
US7754658B2 (en) * 2007-02-22 2010-07-13 Halliburton Energy Services, Inc. Crosslinked acids comprising derivatized xanthan and subterranean acidizing applications
US7789146B2 (en) * 2007-07-25 2010-09-07 Schlumberger Technology Corporation System and method for low damage gravel packing
WO2010001323A1 (fr) * 2008-07-01 2010-01-07 Schlumberger Canada Limited Système, procédé et appareillage pour des opérations de nettoyage de puits d'injection

Non-Patent Citations (2)

* Cited by examiner, † Cited by third party
Title
None
See also references of EP2516580A4

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2941468A4 (fr) * 2013-01-04 2016-10-19 Halliburton Energy Services Inc Procédés utilisant des fluides de forage et de complétion aptes à une stimulation
US9528044B2 (en) 2013-01-04 2016-12-27 Halliburton Energy Services, Inc. Methods using stimulation-capable drill-in and completion fluids

Also Published As

Publication number Publication date
EP2516580A4 (fr) 2013-06-26
EA201290742A1 (ru) 2013-02-28
WO2011092637A3 (fr) 2011-12-29
US20110186293A1 (en) 2011-08-04
MX2012008854A (es) 2012-09-07
CA2787381A1 (fr) 2011-08-04
EP2516580A2 (fr) 2012-10-31

Similar Documents

Publication Publication Date Title
US20110186293A1 (en) Use of reactive solids and fibers in wellbore clean-out and stimulation applications
US7219731B2 (en) Degradable additive for viscoelastic surfactant based fluid systems
AU2011343384B2 (en) Treatment of illitic formations using a chelating agent
US7939474B2 (en) Wellbore fluids containing additives for removing a filter cake and methods of using the same
US7398826B2 (en) Well treatment with dissolvable polymer
CA2833522C (fr) Systemes agents de fragmentation a basse temperature respectueux de l'environnement et procedes s'y rapportant
US9006153B2 (en) Oxidative internal breaker system with breaking activators for viscoelastic surfactant fluids
US9284482B2 (en) Acidic internal breaker for viscoelastic surfactant fluids in brine
AU2014212849B2 (en) Low-temperature breaker for well fluid viscosified with a polyacrylamide
US20060084579A1 (en) Viscoelastic surfactant mixtures
WO2003048267A1 (fr) Bouchon de regulation du filtrat sans effet destructeur et procede d'utilisation de ce dernier
US8955588B2 (en) Electron-poor orthoester for generating acid in a well fluid
US9745509B2 (en) Process to treat subterranean formations using a chelating agent
Sullivan et al. Oilfield applications of giant micelles
CA2540988C (fr) Liquide de fracturation ameliore et son procede d'utilisation
US10563115B2 (en) Activators for inorganic oxide breakers

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 11736692

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 2787381

Country of ref document: CA

WWE Wipo information: entry into national phase

Ref document number: 2011736692

Country of ref document: EP

WWE Wipo information: entry into national phase

Ref document number: MX/A/2012/008854

Country of ref document: MX

NENP Non-entry into the national phase

Ref country code: DE

WWE Wipo information: entry into national phase

Ref document number: 201290742

Country of ref document: EA