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
  • C09K8/02—Well-drilling compositions
  • C09K8/04—Aqueous well-drilling compositions
  • C09K8/06—Clay-free compositions
  • C09K8/12—Clay-free compositions containing synthetic organic macromolecular compounds or their precursors
• • 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
  • C09K8/02—Well-drilling compositions
  • C09K8/04—Aqueous well-drilling compositions
  • C09K8/14—Clay-containing compositions
  • C09K8/18—Clay-containing compositions characterised by the organic compounds
  • C09K8/22—Synthetic organic compounds
  • C09K8/24—Polymers
• • 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
• • 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
  • C09K2208/32—Anticorrosion additives

Definitions

• the present invention relates to methods and compositions for use in subterranean operations. More particularly, the present invention relates to tar stabilizing polymers used to treat tar resident in a well bore and associated methods of use.
• tar is a relatively tacky substance that may readily adhere to any surface that it contacts, including the surfaces of the well bore and/or any equipment utilized during the drilling operation.
• Tar also may dissolve into many synthetic treatment fluids used in the course of drilling operations, increasing the tack and adhesive properties of the tar. If a sufficient amount of tar adheres io surfaces in the well bore or drilling equipment, it may, among other problems, prevent the driilstring front rotating, prevent fluid circulation, or otherwise impede the effectiveness of a drilling operation. In. some cases, it may become necessary to remove and/or disassemble the driilstring in order to remove accretions of tar, a process which may create numerous cost and safety concerns. The accretion of tar on drilling equipment and/or in the well bore also can. impede an subsequent operations dovvnhoie, .including cementing, acidizing, fracturing, sand control, and remedial treatments. In addition, soft, tacky tar that manages to reach the surface may foul surface equipment, including solids screening equipment,
• the present invention relates to methods and compositions for use hi subterranean operations. More particularly, the present invention relates to tar stabilizing polymers used to treat tar resident in a well bore and associated methods of use.
• An embodiment of the present invention provides a method for treatment of well bore tar.
• the method may comprise contacting tar resident in a well bore with a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an aerylate polymer, a styrene-acrylate polymer, and any combination thereof.
• the method may further comprise allowing the tar stabilizing polymer to interact with the tar to at least -partially reduce the tendency of the tar to adhere to a surface.
• Another embodiment of the present invention provides a method for treatment of well bore tar.
• the method may comprise using a drill bit to enlarge a well bore in a subterranean formation comprising tar.
• the method may further comprise circulating a • drilling fluid past the drill bit to remove cuttings from the drill bit, wherein the drilling fluid comprises an aqueous fluid and a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an aerylate polymer, a styrene- acrylate polymer, and any combination thereof.
• the treatment fluid may comprise an aqueous fluid.
• the treatment fluid may further comprise a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene -polymer, an aerylate polymer, a styrene-acrylate polymer, and any combination thereof
• the present invention relates to methods and compositions for use hi subterranean operations. More particularly, the present invention relates to tar stabilizing polymers used to treat tar resident in a well bore and associated methods of use.
• tar stabilizing polymer refers to a polymer that can interact with tar resident in a well bore such that the tar becomes less tacky and/or less able to adhere to a surface.
• One of the man.v advantages o the present invention, manv of which are not discussed or alluded to herein, is that iar treated by the compositions and methods disclosed herein may be substantially less tacky and/or less able to adhere to a surface.
• tar treated in this manner may be susceptible to screen separation from treatment fluids, drill cuttings, tar sands, and the like,
• Embodiments of the present invention disclose tar stabilizing polymers comprising a styrene polymer, an aerylate polymer, a sfyrene-acrylate polymer, or any combination thereof.
• the suitable tar stabilizing polymers generally can be emulsified in an aqueous fluid m accordance with present embodiments.
• the tar stabilizing polymers may be ionic or nonionic in nature.
• the tar stabilizing polymers may interact with the tar resident in a well bore such that the properties of the ta are altered, in certain embodiments, the tar stabilizing polymers may bind or coat the tar such that the tar becomes less sticky.
• styrene polymers that may be suitable for use in embodiments of the present invention include, but are .not limited to, styrene copolymers which include co-monomers of styrene or any derivative thereof.
• the styrene polymer may be made by polymerizing styrene, which, may be substituted or unsuhstituted.
• the styrene may be substituted with any number of different groups that will be evident to those of ordinary skill in the art, including without limitation cbioro groups, bromo groups, fluoro groups, alkyl groups, a!koxy groups, alkenyl groups, alkynyl groups, aryl groups, and substituted versions thereof. Combinations of styrene polymers may also be suitable, in certain embodiments, in some embodiments, the styrene polymer may comprise styrene in an amount, in a range of about.
• the styrene polymer may consist of styrene. In some embodiments, the styrene polymer may be essentially free of aer late and/or acrylic acid.
• the aery!ate may be substituted with, any .number of different groups that will be evident to those of ordinary skill in the art, including without limitation eliioto groups, bromo groups, f uoro groups, alkyl groups, alkoxy groups, alkenyl groups, alkynyl groups, aryl groups, and substituted versions thereof.
• the acrylate may comprise two or more units individually selected from the group consisting of -acrylate, -methacrylate, - ethylacrylate, -propylacrylate, -butyiaerylate, -ii?r -buty1 -acrylate, -n-hydroxy ethyl methacrylate, -potassium acrylate, -penfcabrombbenz l acrylate, -methyl me hacrykte, -ethyl methacrylate, -n-mtrophenyl acrylate, -methyl 2- ⁇ acyloxymefhyl)aerylate, -cyc!ohexyi acrylate, -n-ethyihexyl acrylate.
• the acrylate polymer may be formed by polymerizing acrylic acid, which may be subsequently neutralized to form the acrylate copolymer.
• the acrylate polymer may comprise acrylate in an amount in a .range of about 90% to about 100% by weight of the acrylate polymer, about 95% to about 100% by weight of the acrylate polymer, or about 99% to about 100% by weight of the acrylate polymer.
• the acrylate polymer may consist of acrylate.
• the acrylate polymer may be essentially free of styrene,
• the tar stabilizing polymers may be provided in the form of a latex emulsion or a powder.
• a latex emulsion may be used that comprises the tar stabilizing polymer.
• the latex, emulsion may be in the range from about 5% to about 60% active by weight.
• the latex emulsion may have a pH in the range of about 2 to about 4,
• the la tex emulsion may further comprise a surfactant.
• any surfactant that will emulsify and/or suspend the tar stabilizing polymers may he used in embodiments of the fluids of the present invention.
• the surfactants may be present in an amount sufficient to emulsify and/or suspend the tar stabilizing polymers. This amount may depend on, among other things, the type of surfactant used and the amount of ta stabilizing polymer to be emulsified and/or suspended. A person of ordinary skill in the art will recognize, with the benefit of this disclosure, the type and amount of surfactant that should be added for a particular application.
• the tar stabilizing polymers may be provided m the form of a powder that can, for example, be dispersed in water.
• the iar stabilizing polymer may have, for example, a particle size of less than about I micron, less than about 500 nanometers, or less than about 100 nanometers,
• treatment fluid refers to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose.
• treatment fluid does not imply any particular action by the fluid or any component thereof.
• Treatment fluids may be used, for example, to drill, complete, work over, fracture, repair, or in any way prepare a well bore for recovery of materials residing in a subterranean formation penetrated by the well bore.
• treatment fluids include, but are not limited, cement compositions, drilling fluids, spacer fluids, and spotting f uids.
• At least one tar stabilizing polymer may be included in a treatment fluid in a quantity sufficient, to treat the tar in the well bore.
• the concentration of the tar stabilizing polymer in the treatment fluid may be at least about 1 % by volume of the fluid, and up to an amount such that the tar stabilizing polymer will precipitate out of the fluid.
• the concentration of tar stabilizing polymer in the treatment fluid may be in the range of from about 1% to about 70% by volume of the fluid, in. certain, embodiments, the concentration, of tar stabilizing polymer in the treatment fluid may be in the range for from about 1% to about 10% by volume of the fluid.
• the tar stabilizing polymer may be added to the treatment fluid in the form of a latex-type emulsion or as dispersed particles.
• a latex-type emulsion or as dispersed particles.
• the treatment fluid may further comprise an aqueous fluid
• the tar stabilizing polymer may be dispersed in the aqueous fluid to form the treatment fluid.
• a latex emulsion comprising a tar stabilizing polymer may be dispersed in the aqueous fluid.
• a powder comprising a tar stabilizing polymer may be dispersed in the aqueous fluid.
• the aqueous fluid utilized in the treatment fluids of the present invention may be fresh water, distilled water, or salt water (e.g., water containing one or more salts dissolved therein).
• the treatment fluid may be an aqueous-based fluid.
• the water can be from an source, provided thai it does not contain compounds that undesirably affect other components of the treatment fluid,
• the treatment fluids of the present invention may further .comprise a viscosifler, for example, to aid in suspending the tar stabilizing polymer in the treatment fluid.
• Suitable viscosifying agents may include, bui are not limited to, colloidal agents (e.g., clays such as benfoniie, polymers, and guar gum), emulsion- forming agents, diatomaceous earth, biopolymers, synthetic polymers, chitosans, starches, gelatins, or mixtures thereof.
• treatment fluids of the present invention may comprise any such additional additives that do not undesirably interact with the tar stabilizing polymer or other components of the fluid.
• the treatment fluids used in methods of the present invention optionally may comprise any number of additional additives, including, but not limited to.
• gases e.g., nitrogen, carbon dioxide
• tackifying agents foamers
• foamers corrosion inhibitors, scale inhibitors, catalysts, clay-control, agents, biockles, friction reducers, a tifoam agents, bridgin agents, dispersants, floeenla ts, hydrogen sulfide scavengers, carbon dioxide scavengers, oxygen scavengers, lubricants, breakers, weighting agents (e.g., bariie), relative-permeability modifiers, resins, particulate materials (e.g., proppant particulates), wetting agents, coating-enhancement agents, and the like.
• Weighting agents may be used, for example, in treatment fluids, such as, drilling -fluids to provide a density sufficient to, fo example, control formation pressures.
• treatment fluids such as, drilling -fluids
• weighting agents may be used, for example, in treatment fluids, such as, drilling -fluids to provide a density sufficient to, fo example, control formation pressures.
• embodiments of the treatment fluids may be used in a variety of subterranean operations for treatment of tar resident in a well bore
• a tar stabilizing polymer As described herein, the adhesiveness of the tar may be reduced, thus facilitating removal of the tar from a well bore or other surface, for example.
• the present invention discloses a method comprising contacting tar resident in a. well bore with a tar stabilizing polymer, and allowing the tar stabilizing polymer to interact with the tar to at least partiall y reduce the tendency of the tar to adhere to a surface.
• a treatment fluid comprising the tar stabilizing polymer may be introduced into the well bore such that the tar stabilizing polymer contacts the tar.
• a treatment fluid comprising the tar stabilizing polymer may be introduced into the well bore such that the tar stabilizing polymer contacts the tar.
• a treatment- fluid comprisin a tar stabilizing polymer may be introduced into a well bore as a drilling fluid.
• a drill bit may be used to enlarge the well, bore, and the treatment fluid comprising the tar stabilizing polymer may be circulated in. the well bore past the drill bit.
• the dril ling fluid may be passed down through the inside of a drill string, exiting at a distal end thereof (e.g., through the drill bit), and eturned to the surface through an annul us between the drill string and a well bore wall.
• the drilling fluid may have a density in the range of from about 7.5 pounds per gallon ("lb/gal") to about .18 lb/gal, and alternatively from about 12 lb/gal to about 1 8 lb/gal,
• tar may be encountered in the course of drilling the well bore.
• the zones of the well bore may be intentionally or unintentionally contacted during the course of drilling.
• embodiments may include drilling through zones of the well bore that contain tar sands.
• tar sands does not imply or require an specific amount of tar to be present.
• one or more generally horizontal well bores may be drilled through the tar sands.
• a tar stabilizing polymer may be included in the drilling fluid as the well bore is drilled in these tar-containing zones.
• the tar stabilizing polymer contained in the treatment fluid may modify at least a portion of tar such that is becomes less tackv, making it less likely to stick, to drill strings and other tubulars used in drilling operations. Tar modified in this way may yield tar cutting that can he removed more effectively from the well bore. Additionally, tar that is dri lled through may be less likely to flow into the well bore or the subterranean, formation as the plastic properties of the tar maybe altered. Similarly, the treated tar that forms about the surface of the well bore may act to stabilize the well bore. In addition, tar treated with the tar stabilizing polymers ma be separated from a treatment fluid by passing the fluid through a screen or similar separation apparatus.
• a. treatment fluid comprising a tar stabilizing polymer may be introduced Into a well bore as a pill for spot treatment, wherein the treatment fluid is introduced into the well bore to interact with tar in a. specific portion of the well bore.
• the pill may be introduced into a zone of the well bore that contains tar sands.
• Hie pill should enter the well bore and interact with tar resident in the well bore, thus modifying at least a portion of the tar such that is become less tacky, in certain embodiments of this type, the tar stabilizing polymer may be allowed to interact with the tar resident in the well bore for at least a time sufficient to at least partially reduce the adhesiveness of the tar, in some embodiments, this may be more than, about one hour, in others, more time will be required to at least partially reduce the adhesiveness of the tar, depending upon, among other factors, the temperature inside the well bore and the amount of tar in the portion of the well bore being treated, One of ordinary skill in the art.
• the pill may be used ahead of and or behind a non-aqueous drilling fluid, which may comprise any number of organic liquids, including, but are not limited to, mineral oils, synthetic oils, esters, paraffin oils, diesel oil, and the like.
• the amount of the tar stabilizing polymer present in the treatment fluid may be monitored while the tar stabilizing polymer is circulated in the well bore. For example, once a unit of tar stabilizing polymer in a treatment fluid is allowed to interact with a unit of tar in a well bore, that unit of the tar stabilizing polymer may be depleted from the treatment fluid and thus unable to interact with additional tar. For this reason, it may be desirable to monitor the concentration, of the tar stabilizing polymer in the treatment fluid to determine if more should be added.
• the tar stabilizing polymer may be added to the treatment fluid before the treatment fluid is introduced into the well bore, for example, a batch-mixing process, in some embodiments, it may be desirable to continue to add the tar stabilizing polymer to the treatment fluid (e.g., "on-the- ly" mixing) according to the monitored concentration of the tar stabilizing polymer in the treatment fluid.
• the concentration of tar stabilizing polymer hi the treatment fluid ma be monitored by direct measurement.
• the concentration of tar stabilizing polymer in the treatment fluid ma be monitored indirectly by measuring ihe depletion of the tar stabilizing polymer from the treatment fluid.
• the concentration of the tar stabilizing polymer in the treatment fluid may be monitored, for example, by analytical polymer spectroscopy, chromatography, gravimetry, and quantitative precipitation.
• a nonaqueous-base fluid was also formulated as shown in Table 2.
• a 50 g sample of tar sand (25% tar by mass) was placed in a first i/2 lab barrel along with 133.1 g of Base Fluid i and a steel test rod, A 12.5 g sample of tar was placed in a second 1/2 lab barrel along with. 216.9 g of Base Fluid 2 and a steel test rod.
• the barrels were then hot rolled for 16 hours ai I SO i F (appro*. 66,7 °C) under 200 psi in a rolling cell, and Hie test rods were visually inspected for tar accretion.
• Base Fluid ⁇ was contaminated with tar sand, and tar was accreted on the test rod.
• Base Fluid 2 was contaminated with tar, and tar was accreted on the test rod.
• the two fluid samples were prepared as set forth in Table 3 using Base Fluid I described in ' Fable 1 , The fluid samples are designated Sample A and B in the table below.
• the styrene-acrylate polymers used in this example were obtained as an emulsion and used as received.
• Baraeor 700 M corrosion inhibitor is an anti-corrosion additive commercially available from Halliburton Energy Services, Houston, Texas.
• I SO approximately 66,7 3 ⁇ 4 C
• tar was screened from, tar-containing fluids.
• Base fluid I was combined with tar sand and, in two cases, a treatment additive, as illustrated in Table 4 below.
• the tar-containing fluids were hot rolled then poured across a vibrating screen material to assess potential screen clogging properties. A screen may be considered fouled if the tar is adhesive and begins to seal/clog the screen openings thereb preventing a fluid from effectively draining.
• Sample C was a baseline reference of nontreated, adhesive tar and yielded adhesive screen fouling.
• Sample D was an unsuccessful treatment with a sodium salt that also yielded adhesive screen fouling.
• Sample E was a chemical treatment of tar with, styrene-aeryiate polyiBers that yielded a non-adhesive tar and minimized screen fouling.
• the styrene-acrylate polymers used in this example (E) were the same as in the previous tests.
• Fluid samples were prepared by adding a styrene copolymer to Base Fluid 3 in different quantities to determine its effect on well bore tar, as set forth in Tabie 6 below.
• the fluid samples are designated Samples F and G in. the tabie below.
• the styrene copolymer was obtained as a latex emulsion (approx. 45 wt % active) and used as received.
• a steel rod was used to mimic the drill strings interaction with the tar sands.
• the tar sands were placed in a lab barrel together with the respective fluid sample and the steel rod.
• the system was then aged by rolling at approximately 77 °F (approx. 25 °C) for 16 hours in a rolling cell.
• the mass of the steel rod was determined prior to testing without any accreted tar and after testing with accreted tar.
• the mass of the rod was also measured after rinsing under a stream of water.
• the tar sands were placed in a iab barre! together with the respective fluid sample and the steel rod.
• the system was then aged by rolling at approximately 77 ,3 F (approx, 25 °C) for 16 hours in a rolling cell.
• the mass of the steel rod was determined prior to testing without any accreted tar and after testing with accreted tar.
• the mass of the rod was also measured after rinsing under a stream of water.
• compositions and methods are described in terms of “comprising,” “containing,” or ''including' ' various components or steps, the compositions and methods can also “consist, essentially of or “consist of the various components and steps.
• any number and any included range failing within the range are specificall disclosed, in particular, every range of values (of the form, "about a to about h,” or, equivalently, “from approximately a to b,” or, equivalent! ⁇ ', "from approximately a-b' * ) disclosed herein is to be lindersiood to set forth every number and range encompassed within the broader range of values.

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• Chemical & Material Sciences (AREA)
• Life Sciences & Earth Sciences (AREA)
• General Life Sciences & Earth Sciences (AREA)
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• Materials Engineering (AREA)
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• Dispersion Chemistry (AREA)
• Compositions Of Macromolecular Compounds (AREA)
• Agricultural Chemicals And Associated Chemicals (AREA)
• Lubricants (AREA)
• Solid-Sorbent Or Filter-Aiding Compositions (AREA)
• Treatments Of Macromolecular Shaped Articles (AREA)

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• 2013
  • 2013-02-08 CA CA2862053A patent/CA2862053A1/en not_active Abandoned
  • 2013-02-08 EP EP13706353.3A patent/EP2812408A1/en not_active Withdrawn
  • 2013-02-08 MX MX2014009589A patent/MX351168B/es active IP Right Grant

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