WO1999041342A1 - Composition tensioactive et procedes pour nettoyer des surfaces d'un forage ou d'un champ petrolifere - Google Patents

Composition tensioactive et procedes pour nettoyer des surfaces d'un forage ou d'un champ petrolifere Download PDF

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Publication number
WO1999041342A1
WO1999041342A1 PCT/GB1999/000410 GB9900410W WO9941342A1 WO 1999041342 A1 WO1999041342 A1 WO 1999041342A1 GB 9900410 W GB9900410 W GB 9900410W WO 9941342 A1 WO9941342 A1 WO 9941342A1
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WIPO (PCT)
Prior art keywords
alkyl
surfactant composition
composition
mbing
wellbore
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PCT/GB1999/000410
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English (en)
Inventor
Albert Foon-Chiu Chan
William Mark Bohon
David James Blumer
Kieu Troung Ly
Original Assignee
Atlantic Richfield Company
Arco British Limited
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Filing date
Publication date
Priority claimed from US09/023,521 external-priority patent/US5874386A/en
Priority claimed from US09/023,916 external-priority patent/US6112814A/en
Priority claimed from US09/023,909 external-priority patent/US5996692A/en
Application filed by Atlantic Richfield Company, Arco British Limited filed Critical Atlantic Richfield Company
Publication of WO1999041342A1 publication Critical patent/WO1999041342A1/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
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/524—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes

Definitions

  • This invention relates to methods for the removal of deposits comprising heavy hydrocarbonaceous materials and finely divided inorganic solids from wellbore surfaces and from other surfaces, such as the inside of piping such as tubing or casing and flowlines, using an alkyl polyglycoside surfactant composition, and to a surfactant composition suitable for use in the methods.
  • Mixtures of oil, gas and water are frequently produced from oil fields. Processes for treating such mixtures to produce separate streams of oil, gas and water are well known.
  • the oil is separated and recovered as a product; the gas may be separated and recovered as a product; or, alternatively, the gas may be injected into a gas cap above an oil-bearing zone, into an oil-bearing zone or the like as recovered or as a miscible injectant which comprises the produced gas adjusted by the addition of nitrogen, carbon dioxide, hydrocarbons containing from one to about five carbon atoms and the like to adjust the specific gravity of the gas to produce a miscible injectant.
  • the water may be recovered for injection or disposal by other means as known to those skilled in the art.
  • the separation is frequently accomplished in large settling tanks where the oil, gas and water are allowed to gravimetrically separate.
  • the mixture of oil, gas and water is passed to central processing facilities for separation with the oil being recovered as a product and with the gas being either wholly or partially recovered as a product also.
  • the gas is distributed to injection wells and injected; and, in some fields, the water is similarly recovered, passed to injection wells and injected into the formation for the disposal of the water, for secondary oil recovery and the like.
  • the schmoo is a slimy, oily substance which adheres to almost any surface with which it comes in contact, and is difficultly removed from any surface and particularly from the inner surfaces of flowlines, water injection lines into the formation, wellbore surfaces and the like.
  • the material is removable by pigging from flowlines which are of a sufficient size and configuration that pigs can be run through the lines. Such lines are routinely cleaned by pigging.
  • Other lines, such as injection lines into wells, small diameter flowlines, the settling tank surfaces and formation surfaces are not accessible by pigging operations and, accordingly, the schmoo accumulates on the inner surfaces of these pipe lines, on the surfaces of the well and the like. The schmoo is detrimental to continued operations for a number of reasons.
  • Such deposits in wellbores are particularly common in wells which are used for alternating water and gas injection.
  • the schmoo dries on the inner surfaces of the tubing during gas injection and subsequently cracks and falls into the wellbore, thereby eventually plugging the wellbore, sometimes to a considerable depth.
  • a continuing search has been directed to the development of an economical method for the removal of such deposits including deposits which have dried and fallen into the wellbore or otherwise been deposited into the wellbore to the extent that the wellbore is plugged with such deposits.
  • This invention in one aspect thereof, provides an improved method for the removal of such deposits.
  • the invention provides a surfactant composition suitable for use in said method for the removal of deposits and drilling fluid solids.
  • a surfactant composition consisting essentially of an aqueous solution containing from about 0.1 to about 10.0 weight percent of an alkyl polyglycoside surfactant selected from alkyl polyglycosides containing alkyl groups containing from about 8 to about 19 carbon atoms and mixtures thereof; from about 0.1 to about 10.0 weight percent of an ethoxylated alcohol selected from the group onsisting of ethoxylated alkyl alcohols containing from about 6 to about 16 carbon atoms in the alkyl alcohol and from about 2 to about 6 ethylene oxide groups and mixtures thereof, and ethoxylated alkyl phenols containing from about 8 to about 14 carbon atoms in the alkyl group and from about 2 to about 8 ethylene oxide groups and mixtures thereof, and mixtures of the ethoxylated alkyl alcohols and the ethoxylated alkyl phenols; from about a surfactant composition consisting essentially of an aqueous solution containing from about 0.1 to about
  • the surfactant composition can be produced from an aqueous surfactant composition concentrate by dilution with an aqueous solution such as water, brine or the like to provide the surfactant composition.
  • the aqueous surfactant composition concentrate comprises an aqueous solution containing from about 4.0 to about 20.0 weight percent of said alkyl polyglycoside surfactant; from about 1.0 to about 15.0 weight percent of said ethoxylated alcohol; from about 4.0 to about 30.0 weight percent of said caustic; and from about 0.5 to about 10.0 weight percent of said at least one alkyl alcohol containing from about 4 to about 6 carbon atoms.
  • the present invention provides a method for removing deposits comprising heavy hydrocarbonaceous materials and finely divided inorganic particulate materials from a tubing in a water injection well, the method comprising:
  • a method for removing such deposits from a tubing in an alternating water and gas injection well comprising
  • a method for unplugging wells plugged with deposits comprising
  • a method for removing such deposits from a flowline comprising
  • the deposits may be deposited in the well and flake off or otherwise be deposited in the bottom of the well to a substantial depth. Such deposits can reach a depth such that contact with the surfactant at the top of the deposit is not effective to remove the deposits.
  • the deposits produce such a quantity of finely divided inorganic solids to constitute a plugging problem after removal of the hydrocarbonaceous materials. In such cases, the above described methods for removing the deposits may be less effective. Accordingly, and in accordance with a sixth aspect of the invention, there is provided a method for cleaning a wellbore plugged with deposits comprising heavy hydrocarbonaceous materials and finely divided inorganic solids, said method comprising
  • drilling fluids may contain emulsified oil, mineral oil, synthetic oil, diesel oil, residual crude oil or other suitable organic liquids having a suitable density and other properties required in a drilling fluid.
  • These drilling fluids typically contain weighting materials, which comprise finely divided solids, and also, immediately upon initiation of drilling, finely divided inorganic solids removed from the subterranean area through which the well is drilled. These solids become oil-covered during drilling and may be covered with not only the oil used in the oil-based drilling fluid, but also with some crude oil when an oil- bearing formation is penetrated. During drilling operations, some fluid from the drilling fluid leaks off into the formation, as well known to those skilled in the art.
  • the solids comprise finely divided inorganic solids coated with emulsified oil or heavy oil components. These solids tend to agglomerate and are difficult to displace from the formation, even when the production of fluids from the formation is commenced. This can result in formation damage and result in the production of lower volumes of fluid from the formation than would otherwise be possible.
  • These drilling fluid solids when coated with emulsified oil, tend to agglomerate and form masses of solids which are not readily dislodged from formation pores, passageways and the like. Further, cakes of the solids deposited on the face of the formation may not be removed by the production of fluids from the formation. In both instances, the production of fluids from the formation is restricted.
  • a seventh aspect of the invention there is provided a method for removing oil-covered drilling fluid solids comprising heavy hydrocarbonaceous materials and finely divided inorganic solids from a wellbore, said method comprising
  • FIG. 1 is a diagram of the molecular structure of an alkyl polyglycoside
  • FIG. 2 shows four oil/ water systems including Type I, Type II and Type III microemulsions
  • FIG. 3 is a schematic diagram of an oil field operation wherein an oil, gas and water mixture is produced with injection of oil, gas and water;
  • FIG. 4 is a schematic cross-sectional view of a deposit particle containing heavy hydrocarbonaceous materials and a finely divided inorganic particle;
  • FIG. 5 is a schematic cross-sectional view of a line coated with schmoo on its inner surfaces
  • FIG. 6 is a schematic diagram of a water or a water and gas injection well through which water, or alternate slugs of water and gas, are injected into a subterranean formation through a tubing in a casing in the wellbore;
  • FIG. 7 is a schematic diagram of the well of Figure 6 showing a coiled tubing positioned in the well;
  • FIG. 8 is a schematic diagram of a flowline
  • FIG. 9 is a schematic cross-sectional view of a sand grain or a particle of drilling fluid solids coated with emulsified oil or heavy carbonaceous materials.
  • FIG. 10 is a schematic diagram of a well completed for the production of fluids from a subterranean formation
  • FIG. 11 graphically shows the test results from Example 1.
  • FIG. 12 graphically shows the test results from Example 2.
  • the surfactant composition of the present invention consists essentially of an aqueous solution containing from about 0.1 to about 10.0 weight percent, and preferably from about 0.2 to about 4.0 weight percent, of an alkyl polyglycoside surfactant selected from alkyl polyglycosides containing alkyl groups containing from about 8 to about 19 carbon atoms and mixtures thereof; from about 0.1 to about 10.0 weight percent of an ethoxylated alcohol selected from the group consisting of ethoxylated alkyl alcohols containing from about 6 to about 16 carbon atoms in the alkyl alcohol and from about 2 to about 6 ethylene oxide groups and mixtures thereof, and ethoxylated alkyl phenols containing from about 8 to about 14 carbon atoms in the alkyl group and from about 2 to about 8 ethylene oxide groups and mixtures thereof, and mixtures of the ethoxylated alkyl phenols and the ethoxylated alkyl alcohols; from about 0.5 to about 10.0 weight percent of
  • the alkyl polyglycoside, ethoxylated alcohol, and alkyl alcohol comprise from about 0.5 to about 6.0 weight percent of the aqueous solution.
  • the alkyl polyglycoside surfactant has a DP number from about 1.30 to about 1.80.
  • the DP number is a measure of the degree of polymerization of the alkyl polyglycoside as defined in Alkyl Polyglycosides: Technology. Properties and Applications, edited by Karlheinz Hill, Wolfgang Von Rybinski and Gerhard Stoll, VCH Verlagegesellschaft Mbh, Weinhein (Federal Republic of Germany) and NCH Publishers Inc., New York, New York 1997, pp 11-12.
  • the alkyl polyglycoside surfactant may comprise a first surfactant consisting essentially of an alkyl polyglycoside selected from the group consisting of alkyl polyglycosides containing alkyl groups containing an odd number of carbon atoms from about 9 to about 13 carbon atoms and mixtures thereof, and having an oligomer distribution from 1 to 12, and a second surfactant consisting essentially of alkyl polyglycosides selected from the group consisting of alkyl polyglycosides containing alkyl groups, a major portion of which are even numbered alkyl groups which contain from about 12 to about 18 carbon atoms and having an oligomer distribution from 1 to 12.
  • the alkyl polyglycoside surfactant contains from about 20 to about 90 mole percent of the first surfactant.
  • the second surfactant may also contain alkyl polyglycosides containing alkyl groups containing odd numbers of carbon atoms from about 9 to about 19 carbon atoms. Either odd-numbered or even-numbered alkyl groups may be used in either the first or the second surfactant as desired to optimize the surfactant properties.
  • the even numbered alkyl groups are representative of naturally occurring alkyl groups and tend to have a higher pour point and are less convenient to use as surfactants in wellbore operations and the like. Such surfactants are much more viscous and tend to gel at lower temperatures and are otherwise more difficult to handle than the corresponding alkyl polyglycosides containing alkyl groups containing an odd number of carbon atoms.
  • the alkyl groups containing odd numbers of carbon atoms are representative of refinery product streams and are not naturally occurring.
  • the ethoxylated alcohol is present in an amount equal to from about 0.2 to about 4.0 weight percent.
  • the ethoxylated alkyl alcohol may be selected from ethoxylated linear alkyl alcohols, branched alkyl alcohols, Guerbet alcohols, mixtures thereof, and the like.
  • the ethoxylated alkyl phenols may contain linear, branched, Guerbet or a mixture of linear, branched and Guerbet alkyl groups. It is preferred that die ethoxylated alcohol be selected from ethoxylated alkyl alcohols containing from about 6 to about 16 carbon atoms in the alkyl alcohol and from about 2 to about 6 ethylene oxide groups.
  • the caustic material is desirably present in an amount equal to from about 1.0 to about 5.0 weight percent of the aqueous solution.
  • the caustic is a necessary component of the surfactant composition since it is required in combination with the alkyl polyglycosides and the ethoxylated alcohol to effectively dissolve and remove the deposits.
  • the alkyl alcohol be present in an amount equal to from about 0.2 to about 3.0 weight percent.
  • the alkyl alcohol may be a linear or branched alkyl alcohol.
  • the alcohol facilitates mixing and aqueous surfactant composition stability. In the absence of the alcohol, an alkyl polyglycoside surfactant layer and a caustic layer may form in the surfactant composition. While all of the ingredients are present in each layer, they are present in different proportions. With the alkyl alcohol, a homogenous 10
  • the surfactant composition comprises primarily water. Accordingly, it is less economical to transport the surfactant composition in this form. It is preferred that the surfactant composition be produced at the location where it is to be used by dilution of an aqueous surfactant concentrate.
  • a concentrate of the aqueous surfactant composition can be produced for dilution with an aqueous solution to produce the surfactant composition.
  • the concentrate composition comprises an aqueous solution containing from about 4.0 to about 20.0 weight percent of said alkyl polyglycoside surfactant; from about 1.0 to about 15.0 weight percent of said ethoxylated alcohol; from about 4.0 to about 30.0 weight percent of said caustic; and from about 0.5 to about 10.0 weight percent of said at least one alkyl alcohol.
  • the concentrate composition is from about 4.0 to about 12.0 weight percent alkyl polyglycoside surfactant in the aqueous solution; from about 1.0 to about 8.0 weight percent ethoxylated alcohol in the aqueous solution; from about 6.0 to about 22.0 weight percent caustic in the aqueous solution; and from about 1.0 to about 10.0 weight percent alcohol in the aqueous solution.
  • surfactant compositions may be used at substantially any temperature between their freezing points and their boiling points, it is preferred that they be used at temperatures above about 49°C (120°F). At lower temperatures, longer contact times may be required to remove the schmoo.
  • the concentrate may be used at full strength or at any desired dilution.
  • the concentrate contain a suitable hydrotrope to improve the phase stability of the concentrate and the surfactant composition.
  • the hydrotrope may be a hydrotrope such as monosodium salt of N-lauryl-/3-iminodipropionic acid, an alkyl polyglycoside containing linear or branched alkyl groups containing from about 4 to about 8 carbon atoms or the like.
  • the surfactant composition functions as an alkaline cleaner which solubilizes and disperses the schmoo by suspending it in the surfactant composition in such a fine state that the surfactant composition and suspended schmoo can be injected directly into 11
  • subterranean formations without damage to the formation or circulated out of the wellbore.
  • the injection of the surfactant composition into subterranean formations has been observed to increase the injectivity of such formations.
  • the surfactant composition is a foaming surfactant
  • an antifoaming compound such as, for example, a silicon-based antifoam compound.
  • the antifoaming additive is added at a concentration of about 10 to about 100 ppm to the aqueous solution containing the caustic before addition of the other materials.
  • Alkyl polyglycoside surfactants consist of a polar glucose head and an organic carbon chain off of the hemiacetal linkage.
  • a representation of the molecule is shown in FIG. 1.
  • the lipophilic portion of the molecule resides in the alkyl chain R.
  • R can be a linear or branched alkyl group containing from about 8 to about 18 carbon atoms or a Guerbet alkyl containing from about 9 to about 19 carbon atoms.
  • the ratio of components be adjusted by testing with the deposits to be removed to form a Type III microemulsion in the wellbore.
  • Such microemulsions are referred to as Windsor Type III or middle phase microemulsions and are described in some detail in "Micellization, Solubilization and Microemulsions", Vol. 2, K. L. Mittal, Plenum Press, New York, 1977.
  • FIG. 2(a) shows oil (o) and water (w) containing surfactants in a container 10 to a level 11 and having an interface 12.
  • FIG. 1 shows oil (o) and water (w) containing surfactants in a container 10 to a level 11 and having an interface 12.
  • a Type I microemulsion 13 which is an oil-in- water microemulsion, is shown below an excess oil layer (o).
  • Such microemulsions are water soluble and contain quantities of solubilized oil, as shown by the level of the new interface 12' which is above the original interface 12.
  • a Type II microemulsion 14 which is a water-in-oil microemulsion, is shown above an excess water layer (w).
  • Such microemulsions are oil soluble and contain quantities of solubilized water as shown by the level of new interface 12' which is below the original 12
  • FIG. 2(d) shows a Type III microemulsion 15, which is located between the excess oil (o) and excess water (w) phases and extends above and below original interface 12.
  • Type III microemulsions are preferred for pipe and wellbore cleaning operations since their interfacial tensions and solubilization properties toward both oil and water can greatly facilitate the removal of both from wellbores, pipes or other surfaces. Since it is desirable that the deposits be solubilized and dispersed in the aqueous surfactant, it is desirable that the aqueous surfactant be formulated to produce a Type III microemulsion in the wellbore or pipe.
  • microemulsions are much more effective in dissolving hydrocarbonaceous materials in the presence of aqueous solutions than either Type I or Type II microemulsions. It is not necessary that the composition be adjusted to form the desired Type III microemulsion, but it is considered mat the surfactant composition is more effective when adjusted to form a Type III microemulsion in the treated area.
  • the microemulsions have better injectivity and propagate through subterranean formations more readily because of their lower interfacial tension and their lower viscosity.
  • FIG. 3 A typical oil field operation which produces such deposits is shown in FIG. 3.
  • an oil-bearing formation 10 is shown positioned above a water-bearing formation 12 and beneath a gas cap 14.
  • Gas cap 14 in turn, is positioned beneath an overburden 16 and beneath a surface 18.
  • Oil, gas and water are produced from oil- bearing formation 10 through a line 30.
  • sea water may be injected into water-bearing formation 12 as shown by an arrow 20
  • a miscible gas may be injected into gas cap 14 as shown by arrow 24
  • produced water may be injected into water-bearing formation 12 as shown by an arrow 22 with produced gas being optionally introduced into gas cap 14 via a line 26.
  • the produced oil, gas and water stream from oil-bearing formation 10 is passed via a line 30 to an oil, water and gas separator 32.
  • Separator 32 is typically a relatively large vessel to allow a quiescent zone for the gravimetric separation of oil, gas and water.
  • the gas may be recovered, as shown, through a line 38 and passed to a natural gas liquids separation zone 40.
  • natural gas liquids separation zone 40 natural gas liquids such as butanes, pentanes and the like may be recovered and passed via a line 42 to combination with the crude oil 13
  • the crude oil and natural gas liquids in line 36 are passed to sale or use as a crude oil product.
  • the lighter gases from natural gas liquids separation unit 40 may be passed to use as a natural gas product via a line 44 or, as shown, may be combined, via a line 45, with a portion of the natural gas recovered from separator 32 via a line 38' and passed via line 26 back to injection into the gas cap 14.
  • the produced water is recovered through a line 34 from separator 32 and may be passed with or without further treatment back to water-bearing formation 12 via line 22.
  • Deposits of heavy hydrocarbonaceous materials in combination witii finely divided inorganic particulates may occur in lines such as line 30 through which the oil, gas and water mixture is passed to separator 32, in line 34 which is a produced water injection line, or in any other lines wherein water is present, such as the tubing in water injection and water and gas injection wells and in the formations in fluid communication with such wells.
  • the deposits are generally believed to comprise a finely divided inorganic particle which may comprise hydraulic fracturing proppant (approximately 1000 microns), formation sand (approximately 100 microns), formation fines (approximately 10 microns) and precipitates such as iron sulfide (approximately 1 micron).
  • a finely divided inorganic particle which may comprise hydraulic fracturing proppant (approximately 1000 microns), formation sand (approximately 100 microns), formation fines (approximately 10 microns) and precipitates such as iron sulfide (approximately 1 micron).
  • These finely divided inorganic solids form a site which may become coated with a corrosion inhibitor or with heavy hydrocarbonaceous materials. These materials are found in crude oil and in many instances are believed to selectively adhere to the inorganic particulate particles.
  • these coated particles adhere to pipe surfaces, separator surfaces, formation surfaces, equipment surfaces and nearly any o er surface with which they come in contact. They can accumulate over relatively short periods of time to plug formations, lines and the like. As discussed previously, they also contribute to accelerated corrosion of flowlines, injection lines and the like.
  • the larger particles are separated in the settling tank.
  • the smaller particles such as coated iron sulfide, finely dispersed oil and the like are primary constituents of the schmoo in pipes and other surfaces downstream from the separation tank. As a result, these materials, 14
  • FIG. 4 A schematic of a typical particle of schmoo is shown in FIG. 4.
  • the particle comprises an inorganic solid particle nucleus 46 surrounded by a corrosion inhibitor film 48 and by a layer of oil 50.
  • the oil which may be heavier hydrocarbonaceous materials, may be selectively retained on the particles with the lighter hydrocarbonaceous materials floating more readily to the surface for recovery as oil.
  • a sticky, oily mass of this material is typically produced in oil field operations, is readily transported into operating lines, formations and the like, and creates significant operational problems.
  • FIG. 5 a section of a pipe 52 which is encased in insulation 56 and a sheathing 58 is shown.
  • Pipe 52 has a center axis 60 and has become coated on its inner surfaces by a layer of schmoo 54.
  • the schmoo has resulted in the establishment of colonies of bacteria which can generate sulfides and other corrosive materials which are effectively sheltered beneath the layer of schmoo from treatment by conventional biocide materials.
  • Pits 62 are formed by the bacteria and can lead to early pipe failure. Such pipe failure is typically localized so that the life of the pipe is greatly shortened.
  • an injection well 68 is shown.
  • the injection well comprises a wellbore 70 and includes a casing 78 which is cemented in place in wellbore 70 with cement 80.
  • the well includes a well head 88, which is adapted for the injection of water or alternate slugs of water and gas.
  • a production tubing 84 extends downwardly from well head 88 inside casing 78 to a depth near a formation 76 into which water and/or gas is to be injected.
  • Casing 78 has been perforated by perforations 82 in formation 76 to permit the injection of water and/or gas. It will be understood that the well may be completed with or without casing through the formation of interest, as known to those skilled in the art.
  • the well in the formation of interest may be open hole and the injection may be made directly into formation 76.
  • a packer 86 is positioned between tubing 84 and casing 78 to prevent the flow of liquids or gas upwardly between tubing 84 and casing 78.
  • a valve 92 in a water injection line 90 is opened and a valve 96 in a gas injection line 94 is closed. Water is men flowed downwardly through tubing 84 and into formation 76.
  • produced water for instance from an 15
  • deposits can become a problem in wells which are used only for water injection.
  • the deposits can accumulate to a level sufficient to restrict flow and, as discussed previously, can result in the formation of spots of active bacteria which may result in the formation of pits in tubing 84 which may eventually extend through tubing 84. Accordingly, it is necessary to clean such deposits from tubing 84 periodically and it is also necessary to clean such deposits from me inside of casing 78 below tubing 84 and the inside of any open-hole portion of the well extending into or through formation 76. Similarly, such deposits can form in the near wellbore portions of formation 76 and restrict flow into the formation.
  • Such deposits can be removed by a method consisting essentially of injecting the aqueous surfactant composition described above into the tubing in an amount sufficient to substantially fill the tubing and portions of the well in fluid communication with the tubing.
  • the aqueous surfactant composition is then held in place by maintaining pressure on line 90 or by closing valve 92.
  • formation 76 will have sufficient pressure to prevent the flow of the surfactant composition into formation 76.
  • the aqueous surfactant composition is desirably maintained in the tubing and wellbore for a suitable period of time which typically is at least 1 hour, frequently is from about 1 to about 4 hours and, in many instances, is about 3 hours. Longer times may be used if necessary for thicker deposits and the like.
  • the surfactant solution may be flushed into subterranean formation 76 by injecting an aqueous solution such as water, brine or the like, through tubing 84.
  • an aqueous solution such as water, brine or the like
  • an amount of water or brine may be injected sufficient to push a portion of the surfactant composition into formation 76 in a zone 100, as shown in FIG. 6 by pushing from about 1/2 to about 3/4 of the aqueous surfactant composition in the well into the formation by the injection of a limited amount of water or brine.
  • This solution may then be held in the formation for a second period of time comparable to the first period of time to remove deposits from the perforations and near wellbore formation.
  • the aqueous surfactant composition may then be flushed into the surrounding formation by resumption 16
  • the well When the well is used for alternate water and gas injection, the well is desirably treated as discussed above immediately prior to the resumption of gas injection.
  • the treatment is basically the same as described above, except that after a short period of water injection to flush the surfactant composition into the surrounding formation, gas injection is commenced.
  • the schmoo tends to dry during gas injection and crack and fall from the tubing and casing walls into the lower portion of the wellbore and may, in some instances, accumulate to a sufficient depth to plug perforations 82.
  • the deposits can accumulate to a substantial depth and may cover the perforations even when multiple injection zones are used.
  • the practice of the method described above has been found effective to remove such deposits from the tubing and other well surfaces in some instances so that operations can be continued without formation plugging, tubing failure and me like.
  • FIG. 7 is a schematic representation of the well of FIG. 6 wherein the same feamres are represented by the same reference numerals, which well is provided additionally with coiled tubing 102 positioned in the well.
  • the schmoo may be deposited in the well and flake off or otherwise be deposited in the bottom of the well to a substantial depth.
  • the schmoo deposits reach a depth such that contact with the surfactant composition at the top of the deposit is not effective to remove the deposits, or when the deposits comprise a sufficient quantity of finely-divided inorganic solids to constitute a plugging problem after removal of me heavy hydrocarbonaceous materials, then it is necessary to use other treatments to remove the schmoo deposits.
  • the soaking method is less effective since only a small area at the top of me plugging deposits can be contacted by die surfactant composition.
  • coiled tubing treatments which circulated solvents such as xylene and diesel oil in the well, have been used to remove the plugging deposits. It has now been discovered that me surfactant composition of the present invention may be used in such coiled tubing treatments.
  • plugging deposits have accumulated in well 68 to a depth 98 which renders tiieir removal by me soaking method difficult.
  • a coiled tubing 102 extends through tubing 84 into well 68 to a depth near me top of the plugging deposits.
  • the surfactant solution is injected through coiled tubing 102, preferably at a velocity sufficient to maximize me mechanical cleaning action of the coiled tubing and agitate the top layer of die plugging deposits.
  • the coiled tubing may be, and desirably is, equipped witi a washing tool, a jet or other suitable tool as known to the art.
  • the injected surfactant composition containing dissolved or entrained heavy hydrocarbonaceous materials and finely-divided inorganic solids is circulated upwardly through the annulus between me outside of the coiled tubing and the inside of the production tubing 84 for recovery at the surface via line 90 or line 94.
  • a variety of circulation arrangements may be used and the coiled tubing can be raised and lowered 18
  • Such circulation can be used to remove particulates from the well.
  • the recovered surfactant composition may be filtered or otherwise cleaned or adjusted prior to re-injection or all fresh surfactant composition may be used.
  • the use of coiled tubing for such operations using other materials is well-known to those skilled in the art and need not be described in further detail.
  • the coiled tubing may be lowered to keep the surfactant composition injection point near me top of me plugging deposits until substantially all of the plugging deposits have been removed.
  • the well may men be treated to remove schmoo deposits from the near wellbore formation by injecting and maintaining surfactant composition in a near wellbore area 100 for a period of time from about 1 hour to about 4 hours.
  • the surfactant composition is then flushed into the formation by injection of a quantity of an aqueous solution.
  • Flowline 202 includes a valve 204 and a valve 206.
  • the section of flowline 202 between valves 204 and 206 may be treated by flowing the aqueous surfactant composition of me invention into flowline 202 to fill the section of flowline 202 between valves 204 and 206 and thereafter closing valves 204 and 206 for a selected time period, which is desirably from about 1 to about 4 hours.
  • me valves are reopened and an aqueous solution is passed through flowline 202 to flush dissolved hydrocarbonaceous material, finely divided inorganic particles and the like from flowline 202.
  • flowlines are required for oil field operations and many are not accessible for pigging operations. All such flowlines may readily be treated by me method of me present invention by simply filling the flowlines with the aqueous surfactant composition and permitting the surfactant composition to remain in contact with the flowline surfaces for a selected period of time with the surfactant composition then being flushed from the flowlines with an aqueous solution such as water, brine or sea water.
  • an aqueous solution such as water, brine or sea water.
  • the aqueous surfactant composition may also usefully be employed in the removal of oil-covered drilling fluid solids from a wellbore.
  • FIG. 9 A schematic of a typical oil-covered drilling fluid particle 310 is shown in FIG. 9.
  • the oil-covered particle comprises an inorganic solid particle nucleus or a sand grain 312 surrounded by a layer of emulsified oil 314.
  • a well 320 is shown extending from a surface 328 tiirough an overburden 330 and penetrating an oil-bearing formation 332.
  • Well 320 includes a wellbore 322 and a casing 324 cemented in place with cement 326.
  • the casing extends to approximately the top of oil-bearing formation 332.
  • Well 320 also includes a production tubing 334 positioned from the surface to near the top of oil- bearing formation 332 and includes on its lower end and extending into or through formation 332 a slotted or perforated liner 342.
  • a packer 338 is positioned between tubing 334 and casing 324 near the bottom of tubing 334 to prevent flow through the annular space between the tubing and the casing.
  • a wellhead is shown schematically as a valve 336 and should be understood to represent a wellhead adapted to control the flow of fluids into and from well 320.
  • the procedure for drilling such wells is well known to those skilled in the art and basically comprises rotating a drill bit positioned on the lower end of a drillstring with passage during drilling of a drilling fluid, sometimes called a drilling mud, downwardly through the drillstring, outwardly through the drill bit and then upwardly tiirough the annular space between the outside of the drillstring and the inside of the wellbore. As the well is deepened, additional sections of drillstring tubing are added to the drillstring. 20
  • the well is drilled by rotation of the drill bit by rotation of the drillstring with cuttings and the like being removed from the well upwardly through the annular space between the outside of the drillstring and the inside of the wellbore.
  • Such drilling practices are very well known to the art and need not be discussed further.
  • an oil-based drilling fluid or drilling mud In the drilling of wells, it is advantageous in many instances to use an oil-based drilling fluid or drilling mud.
  • the oil component is selected to meet the requirements of the particular drilling operation and may be diesel oil, mineral oil, synthetic oil, residual crude oil or the like.
  • a casing is typically set in the wellbore to a desired depth and cemented in place. Cementing is accomplished by passing a cement slurry downwardly through the casing and then upwardly to fill the annular space between the outside of the casing and the inside of the wellbore. A spacer fluid or the like may be used ahead of the cement slurry to improve the cement bonding.
  • wells may be cased to or through the zone of interest.
  • the drilling fluid contains weighting components, which may be finely divided particulates, and in any event contains finely divided particulates (inorganic solids) of the materials comprising the formation through which the well is drilled. These particulate materials are typically suspended but not dissolved in the drilling mud.
  • a portion of the oil in the drilling mud frequently bleeds off into the formation as a result of the pressure in the well urging the drilling mud to the surface.
  • the dispersed solids in the drilling fluid are deposited on the inner surfaces of the well and in the portions of the formation around the wellbore. These deposits are frequently referred to as filter cake.
  • the filter cake is oil- wet.
  • the solids may be deposited on the inner surfaces of the wellbore and in the pores and other passageways in the formation for a small distance outside the wellbore (near wellbore zone). These solids are initially oil-covered and may become covered with additional heavier hydrocarbonaceous materials from the oil-bearing formation. With a finely divided particle as a nucleus, the carbonaceous materials may surround the nucleus forming an oil-covered particle which is relatively stable and is not readily removed from the face of the formation or from the near wellbore region.
  • the use of the aqueous surfactant composition described above is effective to remove these oil-covered particles. Since it is desirable that the oil-covered drilling fluid solids be dissolved, dispersed, and removed in the aqueous surfactant, it is desirable that the aqueous surfactant be formulated to produce a Type III microemulsion in the wellbore. Such microemulsions are much more effective in dissolving hydro-carbonaceous materials in the presence of aqueous solutions than either Type I or Type II microemulsions. It is not necessary that the composition be adjusted to form the desired Type III microemulsion, but it is considered that the surfactant composition is more effective when adjusted to form a Type III microemulsion in the treated area. Furthermore, the microemulsions have better injectivity and penetrate subterranean formations more readily because of their lower interfacial tension and their lower viscosity. 22
  • the materials are removed by injecting the aqueous surfactant composition into the wellbore, maintaining it in the wellbore for a selected period of time which is typically at least about 1 hour and suitably may be from about 1 to about 4 hours, and thereafter producing fluids from formation 332 through well 320.
  • the surfactant composition may be placed in contact with formation 332 by injecting it through tubing 334 in a quantity sufficient to fill well 320 to a selected level which is a level sufficient to fill that portion of well 320 beneath tubing 334 or at least the portion of well 320 in fluid communication with the formation of interest.
  • the surfactant composition, as injected, is then maintained in position by closing valve 336.
  • the surfactant composition may be used at substantially any temperature between its freezing point and boiling point, it is preferred that it be used at wellbore temperatures above about 49 °C (120°F). At lower temperatures, longer contact times may be required to remove the oil- covered drilling fluid solids.
  • the surfactant composition functions as an alkaline cleaner which solubilizes and disperses the oil from the oil-covered drilling fluid solids into the surfactant composition.
  • valve 336 is opened and the surfactant composition is flushed from the well by producing fluids from formation 320.
  • the solids are readily displaced by the production of fluids from the formation and are recovered with the produced fluids containing the aqueous surfactant composition or with subsequently produced fluids.
  • the produced fluids containing the aqueous surfactant composition generally are segregated in a slop oil tank or the like for treatment and disposal. It has been found that the use of the aqueous surfactant composition is very effective to disperse hydrocarbonaceous- material-coating inorganic particles.
  • the vials were placed in a rotator (held in a 60° angle from the horizontal plane) and then rotated at 24 rpm for 15 minutes. Rotation of the vials provided a controlled and reproducible amount of agitation to remove any lightly adhering schmoo residue.
  • the coupons were then removed, dried, and reweighed. The difference between the pre- and post-clean weights was the amount of schmoo removed by the dispersant.
  • the amount of schmoo removed divided by the amount of schmoo applied was the "schmoo removal efficiency" for that combination of formulation, soak time, and temperature. Such cleaning tests were performed for various dispersant formulations, with each test series being repeated three times to test reproducibility.
  • the total weight % of the alkyl polyglycoside (APG) + ethoxylated alcohol (EA) was held constant, and the relative amounts of the two surfactants were varied (0 ⁇ APG / (APG + EA) ⁇ 1).
  • the results were plotted as the schmoo removal efficiency versus mole % of APG for the dispersant and are shown in FIG. 11. Good schmoo removal was achieved in all tests shown.
  • the dispersant contained 1.5 weight percent of APG and EA, 1.5 weight percent of n-Butanol, and 2.75 weight percent of sodium hydroxide.
  • the well selected for the test was a produced water injection and gas injection well that had a history of requiring a fill-cleanout following each switch from produced 24
  • the surfactant consisted of an aqueous solution containing 1.5 weight percent mixture of C 9 .j 6 APG and C 9 . n ethoxylated alcohol containing 4 ethylene oxide groups per molecule of alcohol, 1.5 weight percent n-Butanol and 2.75 weight percent sodium hydroxide.
  • the well was shut in at the PW manifold.
  • a surfactant injection line was connected to the well line.
  • the surfactant was pumped into the well line, displacing PW out of the well line, well tubing and lower portions of the well.
  • the surfactant was injected at 66°C (150°F).
  • the surfactant was allowed to soak in the well for approximately 3 hours.
  • the well was then put back on PW to flush the surfactant into the reservoir. After about a 4-hour flush, the well was shut in, and subsequently swapped to MI with no plugging.
  • test well had been taking PW at a rate of about 3466m 3 (21,800 barrels) of water per day.
  • PW injection rates improved markedly, eventually stabilizing at about 4340m 3 (27,300 barrels) of water per day for an injectivity increase of 25%.
  • the choke setting and the injection pressure were the same before and after the treatment.
  • FIG. 9 shows the injectivity of the test well in thousands of barrels of water per day (MBWPD) during the 21 days prior to the treatment at various pressures.
  • the injection rate at 13.62 MPa (1975 PSIG) immediately prior to the treatment is shown at point A.
  • the higher injectivity of the test well at a lower pressure of 13.10 MPa (1900 PSIG) after the treatment is shown at Point B.
  • the injection of the surfactant composition has increased the injectivity of the formation penetrated by the test well.
  • the cleaning of the formation by the surfactant composition is more effective when the surfactant composition is partially displaced from the well after the first time period and held in the formation for a second 25

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Abstract

On décrit un procédé et une composition tensioactive servant à nettoyer des surfaces d'un forage ou d'une goulotte de leurs dépôts de matériaux hydrocarbonés denses et de matières particulaires inorganiques finement divisées. Pour ce faire on utilise une composition contenant un polyglycoside d'alkyle, un éthoxy alcool, une substance caustique et un alcanol.
PCT/GB1999/000410 1998-02-13 1999-02-10 Composition tensioactive et procedes pour nettoyer des surfaces d'un forage ou d'un champ petrolifere WO1999041342A1 (fr)

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
US09/023,909 1998-02-13
US09/023,916 1998-02-13
US09/023,521 1998-02-13
US09/023,521 US5874386A (en) 1998-02-13 1998-02-13 Method for cleaning drilling fluid solids from a wellbore using a surfactant composition
US09/023,916 US6112814A (en) 1998-02-13 1998-02-13 Method for cleaning wellbore surfaces using coiled tubing with a surfactant composition
US09/023,909 US5996692A (en) 1998-02-13 1998-02-13 Surfactant composition and method for cleaning wellbore and oil field surfaces using the surfactant composition

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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2000019062A1 (fr) * 1998-09-26 2000-04-06 Atlantic Richfield Company Composition tensioactive acide et procede servant a nettoyer des surfaces de puits de sondage et de conduits d'ecoulement au moyen de cette composition
US7134496B2 (en) 2004-09-03 2006-11-14 Baker Hughes Incorporated Method of removing an invert emulsion filter cake after the drilling process using a single phase microemulsion
US7709421B2 (en) 2004-09-03 2010-05-04 Baker Hughes Incorporated Microemulsions to convert OBM filter cakes to WBM filter cakes having filtration control
US8091644B2 (en) 2004-09-03 2012-01-10 Baker Hughes Incorporated Microemulsion or in-situ microemulsion for releasing stuck pipe
WO2021003476A1 (fr) * 2019-07-04 2021-01-07 Conocophilips Company Élimination de dépôt de cire à l'aide d'un tensioactif aqueux

Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1992014031A1 (fr) * 1991-01-30 1992-08-20 Atlantic Richfield Company Nettoyage de puits a l'aide de compositions de polyglycoside d'alkyle caustiques

Patent Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1992014031A1 (fr) * 1991-01-30 1992-08-20 Atlantic Richfield Company Nettoyage de puits a l'aide de compositions de polyglycoside d'alkyle caustiques

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2000019062A1 (fr) * 1998-09-26 2000-04-06 Atlantic Richfield Company Composition tensioactive acide et procede servant a nettoyer des surfaces de puits de sondage et de conduits d'ecoulement au moyen de cette composition
US7134496B2 (en) 2004-09-03 2006-11-14 Baker Hughes Incorporated Method of removing an invert emulsion filter cake after the drilling process using a single phase microemulsion
US7687439B2 (en) 2004-09-03 2010-03-30 Baker Hughes Incorporated Method of removing an invert emulsion filter cake after the drilling process using a single phase microemulsion
US7709421B2 (en) 2004-09-03 2010-05-04 Baker Hughes Incorporated Microemulsions to convert OBM filter cakes to WBM filter cakes having filtration control
US7838467B2 (en) 2004-09-03 2010-11-23 Baker Hughes Incorporated Microemulsions to convert OBM filter cakes to WBM filter cakes having filtration control
US8091644B2 (en) 2004-09-03 2012-01-10 Baker Hughes Incorporated Microemulsion or in-situ microemulsion for releasing stuck pipe
WO2021003476A1 (fr) * 2019-07-04 2021-01-07 Conocophilips Company Élimination de dépôt de cire à l'aide d'un tensioactif aqueux
US11427749B2 (en) 2019-07-04 2022-08-30 Conocophillips Company Wax deposit removal using aqueous surfactant

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