WO2003097995A1 - Liquides tensioactifs viscoelastiques stables a des concentrations elevees de saumure et procedes d'utilisation associes - Google Patents

Liquides tensioactifs viscoelastiques stables a des concentrations elevees de saumure et procedes d'utilisation associes Download PDF

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WO2003097995A1
WO2003097995A1 PCT/EP2003/004927 EP0304927W WO03097995A1 WO 2003097995 A1 WO2003097995 A1 WO 2003097995A1 EP 0304927 W EP0304927 W EP 0304927W WO 03097995 A1 WO03097995 A1 WO 03097995A1
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fluid
surfactant
brine
fluids
density
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PCT/EP2003/004927
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English (en)
Inventor
Diankui Fu
Yiyan Chen
Zhijun Xiao
Mathew Samuel
Sylvie Daniel
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Sofitech N.V.
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Schlumberger Holdings Limited
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Priority claimed from US10/308,619 external-priority patent/US20030166471A1/en
Application filed by Sofitech N.V., Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V., Schlumberger Holdings Limited filed Critical Sofitech N.V.
Priority to AU2003229781A priority Critical patent/AU2003229781A1/en
Publication of WO2003097995A1 publication Critical patent/WO2003097995A1/fr

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    • 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
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • 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
    • 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 generally to the art of making and using oilfield treatment fluids viscosified with surfactants that gel in aqueous systems. More particularly it relates to making and using such fluids that tolerate high density brines. Most particularly it relates to making and using such fluids that are more viscous at higher temperatures in high density brines than in low density brines.
  • Viscous fluids play an important role in oilfield service applications ranging from fracturing fluids, gravel pack fluids, drilling fluids, cleanout fluids, acid diverting reagents, fracture fluid diverting agents and many more.
  • Nearly all of the traditional fluids for these applications are polymer based and have several intrinsic drawbacks due to their polymeric nature, such as irreversible formation damage and high friction pressure.
  • a new technology based on viscoelastic surfactant (VES) fluids has several distinctive, advantages over polymer-based fluids.
  • VES based fluids are excellent particle suspension media. Unlike polymer fluids, when the VES systems break they form solids-free fluids, minimizing damage wherever they are used.
  • VES fluids are very sensitive towards high brine concentrations, especially heavy brines, often not gelling at all. Therefore their use as fluids for gravel pack applications, drill-in or completion fluids, especially for deep wells, and all other applications demanding heavy fluids to balance the well pressure is still very limited. In order to overcome these limitations new developments of brine insensitive fluids are necessary.
  • U. S. Patent Application Publication No. 2002-0033260 which is assigned to the assignee of the present application, describes a wellbore fluid made with a high brine carrier fluid having a density of at least 1.3 kg/L (10.8 pounds per gallon) containing 1) a component selected from organic acids, organic acid salts, and inorganic salts; 2) a co-surfactant that may be a) sodium dodecylbenzene sulfonate (SDBS), sodium dodecylsulfate (SDS) or a mixture of the two, or b) a hydroxyemylaminocarboxylic acid such as hydroxyethylethylenediaminetriacetic acid; and 3) a zwitterionic surfactant, preferably a betaine, most preferably an oleyl betaine.
  • SDBS sodium dodecylbenzene sulfonate
  • SDS sodium dodecylsulfate
  • U. S. Patent Application No. 10/065,144 which is assigned to the assignee of the present application, describes the optional addition of an alcohol, preferably methanol to an aqueous oilfield treating fluid containing erucylamidopropyl betaine surfactant (in an alcoholic solvent as purchased) and at least 15 percent by weight acid.
  • the material is used as a diverting agent in carbonates, with which the acid reacts.
  • the alcohol is said to compensate for any loss of alcoholic solvent during mixing of the fluid before pumping, and to improve the solubility of the surfactant in the high concentration of spent acid at high temperature, preventing the phase separation of surfactant from brine solution and thus improving the gel stability at high temperature. ..
  • surfactant fluid gels preferably erucylamidopropyl betaine viscoelastic surfactant fluid gels
  • surfactant fluid gels can be made that are extremely stable to brines having densities above about 1.5 kg/L (about 12.5 ppg) at high temperatures.
  • a first embodiment of the present invention is a viscous aqueous high density well treatment fluid composition containing a surfactant, preferably erucylamidopropyl betaine, but in general having the formula:
  • Another embodiment of the present invention is a method of forming gels that are stable and viscous in high density brines from an aqueous mixture of a surfactant, preferably erucylamidopropyl betaine, but in general having the formula:
  • Another embodiment of the present invention is a method of forrning aqueous gels, that are more stable and viscous in high density brines than in low density brines or water, from an aqueous mixture of a surfactant, preferably erucylamidopropyl betaine, but in general having the formula:
  • Another embodiment of the present invention is a viscous aqueous high density well treatment fluid composition containing a surfactant, preferably erucylamidopropyl betaine, but in general having the formula:
  • Yet another embodiment of the present invention is a method of making aqueous gels, containing a surfactant, preferably erucylamidopropyl betaine, but in general having the formula:
  • Yet another embodiment of the present invention is a method of making aqueous gels, containing a surfactant, preferably erucylamidopropyl betaine, but in general having the formula:
  • gels sufficiently stable and viscous in high density brines are used at very high temperatures and long times in oilfield treatments and then degrade by decomposition of the surfactant rather than by destruction of the gel structure, without the need for dilution by formation water or brine or by oil or condensate, and without the need for addition of breakers or breaker precursors, so that the decomposition products will not damage formations, proppant or gravel packs, screens or wellbores; so that formation of sludges or emulsions with oils will be minimized; and so that none of the original surfactant will remain to affect wetability, form foams or have other deleterious effects sometimes observed when certain surfactants are present after oilfield treatments.
  • Oilfield treatment method embodiments of the invention with these fluids include gravel packing, hydraulic fracturing (using the fluid in the pad and/or in the proppant stages), acid fracturing (using the fluid in the pad and/or in stages that alternate with acid stages), diversion, fluidloss pills, kill pills, temporary selective water shutoff, cementing, and wellbore cleanout.
  • Particularly preferred embodiments include cleanout of undesired fluid and/or particulate matter from wellbores, especially horizontal or deviated wellbores, by injecting the fluids of the invention into the wellbores through coiled tubing so that they carry fluid and/or particulate matter out of the wellbores.
  • Figure 1 shows the rheology of prior art viscoelastic surfactant gels in two brines.
  • Figure 2 shows the rheology of prior art viscoelastic surfactant gels in two other brines.
  • Figure 3 shows the rheology of a fluid of the invention in four heavy brines.
  • Figure 4 shows the rheology of a fluid of the invention in three heavy mixed brines.
  • Figure 5 shows the rheology of a fluid of the invention in four very dense mixed brines.
  • Figure 6 shows the rheology of a fluid of the invention in four very dense mixed brines.
  • Figure 7 shows the rheology of a fluid of the invention in a heavy brine at three different shear rates.
  • Figure 8 shows the rheology of the fluid of Figure 7 at three different shear rates after aging at elevated temperature for 24 hours.
  • Figure 9 shows the rheology of the fluid of Figure 7 at three different shear rates after aging at elevated temperature for 48 hours.
  • Figure 10 shows the rheology of a fluid of the invention in a heavy brine at three different shear rates after aging at elevated temperature for 24 hours.
  • Figure 11 shows the rheology of a fluid of the invention in a heavy brine at three different shear rates after aging at elevated temperature for 48 hours.
  • Figure 12 shows the rheology of a fluid of the invention in a heavy brine at three different shear rates after aging at elevated temperature for 72 hours.
  • Figure 13 shows the rheology of a fluid of the invention in a dense monovalent brine.
  • Figure 14 shows the effect of heating and cooling cycles on the rheology of a fluid of the invention.
  • Figure 15 shows the rheology of a fluid of the invention at very low shear rates.
  • surfactant fluid gels for example erucylamidopropyl betaine surfactant fluid gels
  • erucylamidopropyl betaine surfactant fluid gels can be made to be surprisingly stable in and tolerant of high salinity and high density (heavy) brines (defined as brines having a densities above about 1.5 kg/L (about 12.5 ppg).
  • Many surfactants that form VES gels in aqueous systems will form gels only over a certain, often narrow, electrolyte concentration range; with too little salt, or too much, they will not form stable gels, and especially at high temperatures and in dense brines they will phase separate.
  • Some surfactants are compatible with heavy brines, but not at high temperatures.
  • aqueous gels made from cationic surfactants such as those made from 3% of a mixture of N,N'-bis-(2-hydroxyethyl)-N-methyl-9- octadecen-1-ammonium chloride, C ⁇ 2 -C ⁇ 8 alkyl bis-(2-hydroxyethyl) ammonium chlorides, and C 2 o-C 2 alkyl bis-(2-hydroxyethyl) ammonium chlorides are compatible with heavy calcium brines, but only up to a temperature of about 71 °C (160 °F); when further mixed with 3% (Z)-13 docosenyl-N-N- bis (2-hydroxyethyl) methyl ammonium chloride, they form aqueous gels stable up to about 93 °C (200 °F) in heavy calcium brines.
  • cationic surfactants such as those made from 3% of a mixture of N,N'-bis-(2-hydroxyethyl)-N-methyl-9-
  • zwitterionic surfactants have been found to be particularly useful in forming aqueous gels of exceptional thermal stability even in high salinity and heavy brines. Their compatibility with heavy brines at unexpectedly high temperatures is an important feature of embodiments of the present invention.
  • suitable zwitterionic surfactants have the formula:
  • BET-O and BET-E Two examples of betaines are, respectively, BET-O 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 ⁇ 7 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 2 ⁇ H 4 ⁇ alkene tail group) and is 40% active ingredient, with the remainder being substantially water, sodium chloride, and isopropanol.
  • the surfactant in BET-E-40 is also shown below; one chemical name is erucylamidopropyl betaine.
  • BET surfactants, and others, are described in U. S. Patent No. 6,258,859. According to that patent, BET surfactants make viscoelastic gels when in the presence of certain organic acids, organic acid salts, or inorganic salts; the inorganic salts may be 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
  • Other suitable co-surfactants for BET-O-30 are certain chelating agents such as trisodium hydroxyethylethylenediamine triacetate.
  • Betaines will gel aqueous solutions without the need for added salts, as is necessary for many other surfactants that form VES fluids.
  • Preferred embodiments of the present invention use BET-E-40.
  • BET-E-40 improves the stability of BET-E-30 in heavy brines.
  • mixtures of BET-E-40 with other surfactants (as with BET-O-30) will also form stable aqueous gels, in heavy brines, that are more stable than gels made with the other surfactants but without the addition of BET-E-40.
  • Such mixtures are within the scope of embodiments of the invention.
  • a problem with some VES fluids based on surfactants other than those of embodiments of the present invention is their tendency to separate into two phases in the presence of high electrolyte concentrations.
  • a surfactant layer on top of a water layer is commonly observed.
  • a system robust towards high brine concentrations is advantageous.
  • a fluid containing 10% BET- O-30 and 0.3% SDBS in 160% CaBr 2 (1.79 kg/L) (14.94 ppg (pounds per gallon)) shows no tendency for phase separation, although this specific system has a low viscosity.
  • phase separation was not observed when aqueous gels of BET- E-40 were heated in heavy divalent brines and then cooled. In the examples that follow, only the viscosities were measured at high temperatures.
  • the fluids of embodiments of the invention are particularly useful for cleaning out wellbores.
  • Particles such as beads, may be used in jetting operations in wellbores and afterward it may be desirable to remove this material.
  • Produced "sand" (including proppant) accumulating in the production tubing during fluid flow to the wellbore can greatly restrict hydrocarbon production.
  • Other undesired particulates such as cuttings, fibers, other proppant flowback control agents, fluid loss additives, and debris, including debris formed by perforating, may be present.
  • undesired fluids that may or may not contain solid particles, may accumulate in low spots.
  • Coiled tubing has been widely used as a means to clean out materials from a wellbore.
  • Fluids used for coiled tubing cleanout should have low friction pressure (to minimize hydraulic horsepower requirements) and sufficient viscosity for good material carrying and/or displacing capability to aid in carrying and/or displacing the material to the surface for disposal.
  • light fluids are preferred to reduce the possibility of fracturing and to minimize the hydraulic horsepower needed to return the fluid to the surface.
  • VES fluid systems are advantageously used for coiled tubing cleanout applications, in particular in horizontal or inclined wellbores, because VES fluids have superior drag reduction properties (that is, low friction pressures); they can be foamed; they generally undergo “disruptive shear thinning" (see below) at high shear rates (high flow rates and/or great turbulence in the tubing); the very low viscosity fluid that has undergone disruptive shear thinning can enter the sand mass and pick the sand up easily; and since they recover viscosity quickly, the sand will remain suspended as it is moved back up the wellbore.
  • many VES systems are not compatible with the high-density brine used to increase the fluid density.
  • VES fluids which have lower viscosities under appreciable shear.
  • Those skilled in these operations are familiar with equipment and procedures adapted for employing viscous and/or dense fluids.
  • the fluids and methods may also be used for injection wells (such as for enhanced recovery or for storage) or for production wells for other fluids such as carbon dioxide or water.
  • High density brines for oilfield use are usually made from salts of divalent metals such as calcium and zinc, although brines made from potassium, ammonium, sodium, cesium and the like may also be used.
  • Organic cations such as ammonium and tetramethylammonium may also be used.
  • Typical inorganic anions for high density brines include chloride and bromide, although organic anions such as formate and acetate may also be used.
  • Such mixtures are within the scope of embodiments of the invention, as are brines containing any other salts provided that none of them disrupts the structures giving rise to the surfactant gels in high density brines to the point where they no longer give sufficiently stable high viscosity gels at the temperatures at which they are needed.
  • a fluid is described as being made by adding a salt, this may mean by combining anhydrous or hydrated salts with a fluid or by combining a brine (such as a concentrated or saturated brine) with a fluid, and the combining may be done in any order.
  • additives such as alcohols, polymeric materials, other surfactants, chelating agents and the like may be included, again provided that none of them disrupts the structures giving rise to the surfactant gels in high density brines to the point where they no longer give stable high viscosity gels at the temperatures at which they are needed.
  • As-received surfactants often include lower alcohols (like propanols) and/or glycols to reduce their viscosities and/or to lower their freezing points to make them easier to handle and use.
  • addition of alcohols is intended to mean in addition to alcohols already present in the as-received material.
  • Some alcohols are known to stabilize aqueous BET gels.
  • U. S. Patent No. 6,258,859 describes addition of alcohols to betaines. These alcohols are described as medium to long chain alcohols (preferably alkanols), preferably having five to ten carbon atoms.
  • methanol, ethanol, isopropanol, and mixtures of these alcohols stabilize fluid embodiments of the invention.
  • the preferred alcohol is methanol.
  • the alcohol if added, is added in an amount up to about 10 volume percent, preferably in an amount of about 1 to about 6 volume percent.
  • a fluid that contains about 0.2 to about 20% active surfactant, with a preferred concentration range of from about 1 to about 12% active surfactant.
  • the surfactant, water and salt may be blended in any order either in the field or at a separate location. Alternatively, some of the components can be premixed on site or at a separate location and then one or more other component(s) may be added later.
  • the fluids may be batch mixed or mixed on the fly.
  • aqueous gelled fluids are shear thinning but not shear degrading.
  • Shear thinning in this context is used with the conventional meaning for a viscous fluid: as the shear rate is increased, the viscosity decreases. This type of shear thinning is reversible; that is, the viscosity increases again if the shear rate is decreased. Shear thinning is beneficial because this behavior reduces the hydraulic horsepower required during pumping. Shear degradation is a deficiency of fluids thickened with polymers, especially crosslinked polymers; their chemical bonds are permanently broken and they do not recover their viscosity (reheal) when the shear rate is reduced or shearing is stopped.
  • Disruptive shear thinning is characterized by an almost complete loss of viscosity such that above a certain shear rate the viscosity of the fluid is close to that of water.
  • VES fluids undergo disruptive shear thinning is primarily a function of the shear rate, the nature and concentration of the surfactant, the temperature, the nature and concentration of co-surfactants and other additives (such as alcohols) if they are present, and the nature and concentration of electrolytes if they are present.
  • Disruptive shear thinning is reversible; when the shear rate is reduced, the structure reforms and the viscosity returns. The disruption and recovery take time and each can be retarded or accelerated by additives.
  • disruptive shear thinning may be desirable or undesirable.
  • disruptive shear thinning is undesirable because when the fluid is temporarily very thin it cannot suspend the gravel or proppant.
  • Conventional shear thinning is acceptable provided that the fluid remains sufficiently viscous to transport the gravel or proppant.
  • BET-E-40 fluids generally do not undergo disruptive shear thinning (although it cannot be ruled out for all formulations and if disruptive shear thinning is important, specific fluid formulations should be tested), and so would be particularly suitable for gravel packing or hydraulic fracturing.
  • the fluids of embodiments of the present invention are particularly useful in gravel packing, where the high-density fluids carry the gravel to the bottom of the wellbore with a minimal amount of pumping (little hydraulic horsepower needed) because of the density difference between the gravel packing fluid and the fluid already in the wellbore.
  • An agent that promotes disruptive shear thinning may be added, provided that it does not disrupt the structures giving rise to the surfactant gels in high density brines to the point where they no longer give sufficiently stable high viscosity gels at the temperatures at which they are needed.
  • higher viscosity helps the fluid to carry the particles to the surface, so it is desirable for the disruptive shear thinning to be temporary.
  • laboratory tests should be conducted to ensure compatibility of the disruptive shear thinning agent with the fluid, and to ensure that the disruptive shear thinning agent does not interfere with the performance of the fluid. Conducting such tests on any additive or additives is considered to be within the scope of the invention.
  • the gels will eventually degrade at high temperatures without the need for either a) dilution by formation water or oil or condensate, or b) addition of a separate breaker or breaker precursor.
  • the time at which this degradation occurs at a given temperature can be controlled by the choice of surfactant, surfactant concentration, other additives, and brine.
  • additional breakers or breaker precursors especially at lower temperatures, such as some of those described in U. S. Patent Application Publication No. 2002-0004464, assigned to the same assignee as the present application, if desired.
  • breakers and breaker precursors described in that application will be satisfactory for all of the surfactants described in the present application.
  • Other breakers that may be used are described in U. S. Patent Application Publication No. 2002-193257, assigned to the same assignee as the present application.
  • Example 1 shows the rheology of 10% BET-O-30 with 0.3% SDBS in- two different CaCl 2 brines. Fluids were prepared by mixing as-received BET-O-30 with SDBS and then adding the mixture to the brines in a blender. The fluids were then degassed at 82 °C (180 °F) in a water bath overnight before rheology measurements. (This degassing procedure was used only in the experiments of example 1 and is not normally done in the field.
  • concentrations of the as-received surfactant mixtures added to the fluids are given in volume percent; the concentrations of the added salts and other solids are given in weight percent. (For example, "100 weight percent CaBr 2 " means that a weight of salt equal to the weight of water was added to the water.)
  • Figure 2 shows the rheology of 10% BET-O-30 with 0.3% SDBS in two different CaBr 2 brines.
  • the fluids made with CaBr 2 showed similar rheological profiles for the two different brine densities examined. Up to about 104 °C (220 °F), the two fluids had a nearly linear viscosity of about 130 cP at 100 sec "1 .
  • the temperature up to which the viscosity was at least about 50 cP was up to about 121 °C (250 °F) with 60% CaBr 2 (1.38 kg/L) (11.50 ppg) and at least 127 °C (260 °F) with 100% CaBr 2 (1.56 kg/L) (12.98 ppg).
  • the fluids of Figures 1 and 2 were all shear thinning (in the conventional sense).
  • Example 2 Data from Fann 50 experiments showed that formulations of 7.5% and 10% BET-E-40 in 1.44 to 2.16 kg/L (12 to 18 ppg) CaCl 2 and CaCl 2 /CaBr 2 mixtures had rheological stability beyond 149 °C (300 °F).
  • Figure 3 shows the rheology of 7.5% BET-E-40 in CaCl 2 with densities ranging from (1.09 to 1.31 kg/L (9.1 to 10.9 ppg). The fluids shown in Figure 3 also contained 1% methanol.
  • Figure 4 shows the rheology of 10% BET-E-40 fluids in mixed CaCl 2 and CaBr 2 brines with fluid densities up to 1.81 kg/L (15.1 ppg).
  • the CaBr 2 /CaCl 2 weight ratio in the 1.56 kg/L (13 ppg) fluid was about 2.0; the ratio in the other two fluids was about 2.8.
  • the three fluids were shear thinning (in the conventional sense) over the entire temperature range shown. 1.81 kg/L (15.1 ppg) is the highest density available for this brine.
  • Table 3 shows rheological data from Fann 50 experiments for a fluid made with 10% as-received BET-E-40 in a 1.56 kgL (13 ppg) CaBr brine at various shear rates. There were no other components in the fluid. When this fluid was cooled after these runs, it looked the same as it had before it was heated; there was no indication of any decomposition of the surfactant. However, when the fluid was heated to above 191 °C (375 °F), the gel did not reform when the fluid was cooled, indicating the high- temperature degradability of this fluid at that temperature. Thus, it is possible using the methods of embodiments of this invention to form aqueous gels at temperatures at which the viscous fluids are not stable for very long.
  • VES fluids In addition to this excellent rheological performance in heavy brines, as shown in Figures 3 and 4, the low friction pressure characteristic (not shown) of VES fluids is also advantageous for CT cleanout applications, especially in deep wells.
  • the drag reduction of VES fluid has been well documented in CT fracturing treatments and CT cleanout jobs using other VES systems.
  • Example 3 Figures 5 and 6 show the rheology of stable VES gels made with BET-E-40 and mixed brines containing zinc bromide. This combination clearly extends the upper limits of temperature and brine density of these systems beyond what was previously achievable. All the fluids contained 10% as-received BET-E-40 by volume.
  • the ZnBr 2 /CaBr 2 brines were made by diluting a 2.30 kg/L (19.2 ppg) ZnBr 2 /CaBr 2 brine (the highest density obtainable with this brine) with water; the ZnBr 2 /CaBr 2 /CaCl 2 brines ( Figure 6) were made by diluting that brine with 1.39 kg/L (11.6 ppg) CaCl 2 brine.
  • All of these fluids were shear thinning (in the conventional sense) under all conditions except that the fluid of Figure 6 in the 2.02 kg/L (16.8 ppg) brine was essentially Newtonian at temperatures of about 146 °C (295 °F) and higher. It is clear that depending upon the viscosity needed, some of these fluids can be used at temperatures in excess of about 177 °C (350 °F).
  • Example 4 In these experiments, fluids made with 10% BET-E-40 in 1.52 kg/L (12.7 ppg) CaBr 2 brine were aged at 160 °C (320 °F) for 24 or 48 hours.
  • Figure 7 shows the rheology of the freshly made sample on a Fann 50;
  • Figure 8 shows the rheology after aging at 160 °C (320 °F) for 24 hours; and
  • Figure 9 shows the rheology after aging at 160 °C (320 °F) for 48 hours.
  • Example 5 In these experiments, fluids made with 10% BET-E-40 in 1.52 kg/L (12.7 ppg) CaBr 2 brine and 10% methanol were aged at 160 °C (320 °F) for 24, ' 48 or 72 hours.
  • Figure 10 shows the rheology after aging at 160 °C (320 °F) for 24 hours;
  • Figure 11 shows the rheology after aging at 160 °C (320 °F) for 48 hours;
  • Figure 12 shows the rheology after aging at 160 °C (320 °F) for 72 hours.
  • Example 6 shows a gel in a high density brine made with a monovalent cation.
  • the sample was made from 10% as-received BET-E-40 in 1.52 kg/L (12.7 ppg) NaBr.
  • Example 7 Studies were performed to show the effect of heating and cooling cycles on a surfactant fluid of embodiments of the invention.
  • the fluid contained 10% BET-E-40 in a CaBr 2 brine. It can be seen that even when this 1.70 kg/L (14.2 ppg) fluid is repeatedly heated under shear to about 138 °C (280 °F) and cooled to about 24 °C (75 °F) it still retains the desired properties of forming a gel that slowly degrades.
  • Example 8 Experiments were performed at high temperature and very low shear, at which disruptive shear thinning would not mask any chemical decomposition of the surfactant molecules themselves, as opposed to a change in the structure of the fluids.

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Abstract

L'invention concerne une composition aqueuse visqueuse de traitement de puits, de densité élevée, stable à température élevée, contenant un tensioactif et des sels inorganiques. Elle concerne aussi des procédés de préparation de ce liquide et d'augmentation de sa stabilité et de sa viscosité. Ce liquide sert dans le nettoyage, la fracturation hydraulique, le gravillonnage de crépines, la réalisation, la dérivation acide, la réduction de circulation perdue, l'arrêt, la cimentation, l'interruption d'eau sélective, et la dérivation de liquide de fracturation dans un puits.
PCT/EP2003/004927 2002-05-21 2003-05-12 Liquides tensioactifs viscoelastiques stables a des concentrations elevees de saumure et procedes d'utilisation associes WO2003097995A1 (fr)

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WO2006059257A2 (fr) * 2004-11-22 2006-06-08 Schlumberger Canada Limited Modification de la rheologie de tensioactifs viscoelastiques
CN105626018A (zh) * 2014-10-29 2016-06-01 中国石油天然气股份有限公司 压井开始时间的确定方法及压井方法
CN106639977A (zh) * 2016-12-12 2017-05-10 张会利 一种采油过程中油井的选择性堵水方法
US9982520B2 (en) 2013-07-17 2018-05-29 Bp Exploration Operating Company Limited Oil recovery method

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WO2002070862A1 (fr) * 2001-03-01 2002-09-12 Sofitech N.V. Compositions et procedes de limitation des pertes de fluides auxiliaires de puits a base de tensio-actifs
WO2003048267A1 (fr) * 2001-12-03 2003-06-12 Sofitech N.V. Bouchon de regulation du filtrat sans effet destructeur et procede d'utilisation de ce dernier

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WO1998056497A1 (fr) * 1997-06-10 1998-12-17 Rhodia Inc. Fluides contenant des tensioactifs viscoelastiques et leurs methodes d'utilisation
WO2001083946A1 (fr) * 2000-05-03 2001-11-08 Trican Well Service Ltd. Liquide de fracturation
WO2002024831A2 (fr) * 2000-09-21 2002-03-28 Sofitech N.V. Fluides d'agents de surface viscoelastiques a haute concentrations de saumure
WO2002070862A1 (fr) * 2001-03-01 2002-09-12 Sofitech N.V. Compositions et procedes de limitation des pertes de fluides auxiliaires de puits a base de tensio-actifs
WO2003048267A1 (fr) * 2001-12-03 2003-06-12 Sofitech N.V. Bouchon de regulation du filtrat sans effet destructeur et procede d'utilisation de ce dernier

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2006059257A2 (fr) * 2004-11-22 2006-06-08 Schlumberger Canada Limited Modification de la rheologie de tensioactifs viscoelastiques
WO2006059257A3 (fr) * 2004-11-22 2007-02-08 Schlumberger Ca Ltd Modification de la rheologie de tensioactifs viscoelastiques
US7341980B2 (en) 2004-11-22 2008-03-11 Schlumberger Technology Corporation Viscoelastic surfactant rheology modification
US9982520B2 (en) 2013-07-17 2018-05-29 Bp Exploration Operating Company Limited Oil recovery method
CN105626018A (zh) * 2014-10-29 2016-06-01 中国石油天然气股份有限公司 压井开始时间的确定方法及压井方法
CN106639977A (zh) * 2016-12-12 2017-05-10 张会利 一种采油过程中油井的选择性堵水方法
CN106639977B (zh) * 2016-12-12 2019-04-02 张会利 一种采油过程中油井的选择性堵水方法

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