US20110009298A1 - Ultra High Viscosity Pill and Methods for Use with An Oil-Based Drilling System - Google Patents

Ultra High Viscosity Pill and Methods for Use with An Oil-Based Drilling System Download PDF

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US20110009298A1
US20110009298A1 US12/833,673 US83367310A US2011009298A1 US 20110009298 A1 US20110009298 A1 US 20110009298A1 US 83367310 A US83367310 A US 83367310A US 2011009298 A1 US2011009298 A1 US 2011009298A1
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pill
fluid
high viscosity
ultra
pressure transmission
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James W. Dobson, Jr.
Kim O. Tresco
Benjamin K. Geerdes
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Texas United Chemical Corp
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Texas United Chemical Corp
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Priority to US12/833,673 priority Critical patent/US20110009298A1/en
Assigned to TEXAS UNITED CHEMICAL COMPANY, LLC reassignment TEXAS UNITED CHEMICAL COMPANY, LLC ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: DOBSON, JAMES W., JR., GEERDES, BENJAMIN K., TRESCO, KIM O.
Publication of US20110009298A1 publication Critical patent/US20110009298A1/en
Priority to US13/739,979 priority patent/US9850417B2/en
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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
    • C09K8/02—Well-drilling compositions
    • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
    • C09K8/34—Organic liquids
    • 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
    • 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
    • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
    • 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
    • C09K8/40—Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure

Definitions

  • the inventions disclosed and taught herein relate generally to hydrocarbon drilling and exploration operations, and more specifically are related to fluid pressure transmission pills and their manufacture and use in support of drilling and exploration operations.
  • Typical operations include fracturing subterranean formations, modifying the permeability of subterranean formations, logging operations, and sand control, among others.
  • MPD managed pressure drilling
  • Managed pressure drilling is a relatively recent adaptive drilling process, similar in some aspects to under-balanced drilling, used to precisely control the annular pressure profile throughout the well during the course of a drilling operation, thereby reducing drilling problems.
  • the primary objective of the MPD concept is to maintain a balanced well bore pressure within the critical tolerances defined by the pore pressure, well bore stability, and fracture pressure.
  • MPD could be used to manage and maintain the pressure between the pore pressure and the fracture pressure of a reservoir, while simultaneously compensating for the influx of fluids that may occur during drilling without encouraging such an influx.
  • MPD uses a number of tools to mitigate the risks and costs associated with drilling wells by managing the annular pressure profile. Typical techniques applied to date have included controlled backpressure, fluid density, fluid rheology, annular fluid level, circulating friction, and hole geometry [see, Hannigan, D., SPE paper 92600, 2005].
  • problems in deep wells can be caused by well bore pressure deviating outside the pressure gradient window during drilling operations, resulting in non-productive time. For example, at shallow depths, if the well bore pressure deviates below the pore pressure gradient, water or gas can flow into the well bore, and a kick can occur, or in some instances the well bore may become unstable and collapse on the drill pipe. A major problem when pressure exceeds the fracture pressure-gradient is lost circulation, with a loss of mud into the formation with subsequent reservoir damage. These pressure deviation issues account for numerous drilling problems, which in turn have a significant impact on drilling costs and well performance. Consequently, new methods and systems for managing well bore pressure in drilling operations, based on managed pressure drilling (MPD) technologies, is needed to alleviate these drilling issues.
  • MPD managed pressure drilling
  • FPTP fluid pressure transmission pills
  • MPD managed pressure drilling
  • ultra-high viscosity well treatment pill compositions also referred to herein equivalently as fluid pressure transmission pills (FPTPs), suitable for use in managed pressure drilling (MPD) operations, wherein the composition has an overall viscosity greater than 100,000 centipoise (cP) (measured at 0.0660 sec ⁇ 1 ), a mud weight of at least 7.0 lb/gal, and which exhibits pill stability for more than 24 hours.
  • FPTPs fluid pressure transmission pills
  • a fluid pressure transmission pill for use in a managed pressure drilling (MPD) operation
  • the pill comprises an oleaginous (hydrocarbon oil) phase, a thixotropic viscosifying agent, an activator, an emulsifier/wetting agent, a fluid loss control additive, and a weighting material.
  • the thixotropic viscosifying agent is an organophilic clay, present in an amount ranging from about 6 lb/bbl to about 16 lb/bbl, and more preferably from about 10 lb/bbl to about 14 lb/bbl.
  • the weighting material is a solid-phase material selected from the group consisting of barite, calcite, hematite, ilmenite, or combinations thereof.
  • an ultra-high viscosity treatment pill for use in managed pressure drilling (MPD) operations
  • the pill composition comprises a low aromatic content mineral oil, an organophilic clay, a polar activator, an emulsifier/wetting agent, a fluid loss control additive, and a weighting material.
  • the organophilic clay is included in the composition in an amount ranging from about 6 lb/bbl to about 16 lb/bbl
  • the activator is included in an amount which is about 0.1 on a weight-to-weight basis of the amount of the organophilic clay in the composition.
  • the weighting material is a solid-phase material selected from the group consisting of barite, calcite, hematite, ilmenite, or combinations thereof. In one additional aspect of this embodiment, the weighting material is preferably barite.
  • a method of drilling a subterranean well utilizing a fluid pressure transmission pill (FPTP) in conjunction with an oil-based drilling fluid in a managed pressure drilling (MPD) operation is described, wherein the drilling fluid comprises an oleaginous liquid, a thixotropic viscosifying agent, emulsifiers, wetting agents, fluid loss control additives, and weighting material, all of which are described within this disclosure.
  • FPTP fluid pressure transmission pill
  • MPD managed pressure drilling
  • the drilling fluid may include a brine solution to form an invert (water-in-oil) emulsion wherein the aqueous phase is dispersed within the oleaginous phase, and stabilized by one or more emulsifiers which are effective in invert emulsions.
  • invert water-in-oil
  • emulsifiers which are effective in invert emulsions.
  • FIG. 1A illustrates a 12.5 lb/gal fluid pressure transmission pill (FPTP) composition of the present disclosure above 12.5 lb/gal CaBr 2 brine and below 17.0 lb/gal Zn/Br 2 brine at hour 0 at a vertical orientation.
  • FPTP 12.5 lb/gal fluid pressure transmission pill
  • FIG. 1B illustrates the FPTP (12.5 lb/gal) composition of FIG. 1A at 24 hours at a vertical orientation.
  • FIG. 1C illustrates the FPTP (12.5 lb/gal) composition of FIG. 1A at 48 hours at a vertical orientation.
  • FIG. 1D illustrates a FPTP (12.5 lb/gal) composition of the present disclosure above 12.5 lb/gal CaBr 2 brine and below 17.0 lb/gal Zn/Br 2 brine at hour 0 at a 45° angle of deviation.
  • FIG. 1E illustrates the FPTP (12.5 lb/gal) composition of FIG. 1D at 24 hours at a 45° angle of deviation.
  • FIG. 1F illustrates the FPTP (12.5 lb/gal) composition of FIG. 1D at 48 hours at a 45° angle of deviation.
  • FIG. 1G illustrates a FPTP (12.5 lb/gal) composition of the present disclosure above 12.5 lb/gal CaBr 2 brine and below 17.0 lb/gal Zn/Br 2 brine at hour 0 at a 60° angle of deviation.
  • FIG. 1H illustrates the FPTP (12.5 lb/gal) composition of FIG. 1G at 24 hours at a 60° angle of deviation.
  • FIG. 1I illustrates the FPTP (12.5 lb/gal) composition of FIG. 1G at 48 hours at a 60° angle of deviation.
  • FIG. 2 demonstrates a reduced viscosity FPTP (12.5 lb/gal with 6 lb/bbl of organophilic clay) mixing with 15.0 lb/gal CaBr 2 /ZnBr 2 brine during pill placement in a vertical orientation.
  • FIG. 3A shows brine (15.0 lb/gal CaBr 2 /ZnBr 2 ) descending through a 12.5 lb/gal reduced viscosity FPTP (8 lb/bbl of organophilic clay) in a vertical orientation.
  • FIG. 3B illustrates the top view of a 12.5 lb/gal reduced viscosity FPTP (8 lb/bbl of organophilic clay) after all the 15.0 lb/gal CaBr 2 /ZnBr 2 has channeled through the pill.
  • FPTP fluid pressure transmission pill
  • balanced mud pill ‘balanced mud pill’
  • a fluid pressure transmission pill for use in controlling and/or balancing subterranean pressures during a drilling operation within a well bore
  • the pill has an ultra-high viscosity (the term ‘ultra-high viscosity’ as used herein meaning a viscosity greater than about 100,000 cP, measured at 0.0660 sec ⁇ 1 ), and comprises at least a fluid phase, a thixotropic viscosifying agent, an activator, and a weighting material.
  • the composition may optionally comprise one or more emulsifiers and/or wetting agents, and fluid loss control additives, as appropriate, and in association with the viscosifying agent.
  • the fluid phase which is suitable for use in the fluid pressure transmission pill (FPTP) compositions of the present disclosure include but are not limited to hydrocarbons and oleaginous liquids.
  • oleaginous liquid means a hydrocarbon or an oil which is a liquid at 25° C. and is substantially immiscible with water.
  • Oleaginous liquids suitable for use herein typically include substances such as diesel oil, mineral oil (including low aromatic content mineral oils), synthetic oil such as polyolefins or isomerized polyolefins, ester oils, glycerides of fatty acids, aliphatic esters, aliphatic ethers, aliphatic acetals, or other such hydrocarbons and combinations of these fluids.
  • the fluid phase includes an oleaginous liquid that is a low aromatic mineral oil.
  • low aromatic mineral oil means that the oil contains less than about 1% aromatics.
  • the thixotropic viscosifying agents suitable for use herein include, but are not limited to, clays, and in particular include organophilic clays.
  • the organophilic clay is a well-known, commercially available thixotropic viscosifying agent for organic liquids.
  • Suitable organophilic clays also include the reaction products of smectite-type, hectorite clays, or other clays and organic cations, i.e., quaternary ammonium cations (sometimes referred to as organophillic clay gellants); smectite clays; kaolin clays; and the like.
  • the preferred organophilic clays used as a thixotropic viscosifying agent is a smectite-type clay that is selected from the group consisting of bentonite, hectorite, montmorillonite, nontronite, biedellite, saponite, stevensite, and mixtures thereof, most preferably bentonite or hectorite.
  • the preferred quaternary ammonium cations in the event that the clay used is the reaction product of a clay and a quaternary ammonium compound, are selected from the group consisting of methyl trihydrogenated tallow ammonium, dimethyl dehydrogenated tallow ammonium, dimethyl benzyl hydrogenated tallow ammonium, methyl benzyl dehydrogenated tallow ammonium, and mixtures thereof.
  • Exemplary organoclays and clay gellants suitable or use with the compositions described herein are set forth in the following U.S. patents, all incorporated herein by reference in relevant part: U.S. Pat. No. 2,531,427; U.S. Pat. No. 2,966,506; U.S. Pat. No.
  • organophilic clays suitable for use with the compositions described herein are CLAYTONE® IMG 400, available from Southern Clay Products, Inc., Gonzalez, Tex., U.S.A., or BENTONE® 38 Organoclay (a commercial hectorite-based product, available form a number of suppliers).
  • the activator suitable for use in accordance with the compositions and methods of the present disclosure includes any suitable activator for use with clay-type thixotropic viscosifying agents.
  • Suitable activators for use with the presently described compositions include, but are not limited to, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, calcium carbonate, sodium carbonate, potassium carbonate, alkyl carbonates, calcium hydroxide, sodium hydroxide, potassium hydroxide, sodium sulfate, polar, aprotic compounds, and mixtures thereof.
  • the polar activator is a cyclic carbonate, propylene carbonate.
  • the amount of polar activator included in the fluid pressure transmission pill compositions is generally less than the amount of thixotropic viscosifying agent added to the composition, on a weight-to-weight basis.
  • the amount of polar activator included in the composition with regard to the amount of thixotropic viscosifying agent is in a ratio ranging from about 1:5 to about 1:10, as well as ratios within this range, and more preferably in a ratio of about 1:7 of activator to viscosifying agent.
  • the ultra-high viscosity fluid pressure transmission pill may also include an emulsifier, a wetting agent, or both (that is, a compound that may be classified as either an emulsifier or a wetting agent).
  • Emulsifiers and wetting agents suitable for use with the compositions of the present disclosure include nitrogen containing compounds, such as quaternary amines having one or more straight or branched alkyl chains containing from 6 to 20 carbon atoms.
  • fatty acid soaps including oxidized tall oil soaps, preferably the calcium soaps whether pre-formed or prepared in-situ in the fluid; polyamides; alkylamidoamines; imidazolines; alkyl sulfonates; fatty acyl esters; lecithin; and the like.
  • fatty acid soaps including oxidized tall oil soaps, preferably the calcium soaps whether pre-formed or prepared in-situ in the fluid
  • polyamides alkylamidoamines; imidazolines; alkyl sulfonates; fatty acyl esters; lecithin; and the like.
  • primary emulsifiers and secondary emulsifiers.
  • Exemplary emulsifiers suitable for use with the compositions and methods of the present disclosure include, but are not limited to, those described in U.S. Pat. Nos.
  • the preferred oil-soluble polymeric fluid loss control additive for use in the invention comprise styrene-butadiene copolymers known in the art as SBR (styrene-butadiene rubber).
  • SBR styrene-butadiene rubber
  • the styrene content of the SBR is preferably from about 15% by weight to about 45% by weight of the SBR, more preferably from about 20% to 35% by weight, and most preferably from about 20% to about 25% by weight of the SBR.
  • the cold process results in a SBR which contains less branching than in the hot process, i.e., the SBR molecules from the cold process contain more linear molecules than the SBR from the hot process. It is preferred that the SBR be prepared using a cold process. It is also preferred that the SBR not be crosslinked.
  • Other oil-soluble polymers for use in this invention include, but are not limited to, polystyrene, polybutadiene, polyethylene, polypropylene, and copolymers consisting of at least two monomers selected from the group consisting of styrene, butadiene, isoprene, ethene and derivatives thereof, and propylene.
  • the weighting material suitable for use in accordance with the present disclosure is preferably a solid-phase material selected from the group consisting of anglesite (PbSO 4 ), barite (BaSO 4 ) and other barium-containing minerals or materials, calcite (CaCO 3 ), celestite/celestine (SrSO 4 ), crocoite (PbCrO 4 ), hematite (Fe 2 O 3 ), ilmenite (FeTiO 3 ), or combinations thereof.
  • anglesite PbSO 4
  • BaSO 4 barite
  • other barium-containing minerals or materials calcite
  • SrSO 4 celestite/celestine
  • PbCrO 4 crocoite
  • hematite Fe 2 O 3
  • ilmenite FeTiO 3
  • the weighting agent is barite, a solid-phase barium-containing compound or mineral, or a sulfate of the Strunz Class 07.A or 07.AD (as described in the Nickel-Strunz 10 th Ed. Mineralogical Tables, by Hugo Strunz and Ernest H. Nickel).
  • a preferred weighting agent includes preferentially the naturally occurring mineral composed primarily of barium sulfate, BaSO 4 (although other minerals may be included therein, such as lead, zinc in the form of zinc sulfide, and the like), although drilling grade barite such as produced from barium sulfate-containing ores from a single source or by blending material from several sources may also be used.
  • Exemplary barium-containing minerals which may be used as a weighting material in accordance with the compositions of the present disclosure include but are not limited to alstonite (CaBa(CO 3 ) 2 ), barite (BaSO 4 ), barytocalcite (BaCa(CO 3 ) 2 ), celsian (BaAl 2 Si 2 O 8 ), kukharenkoite (Ba 3 CeF(CO 3 ) 3 ), psilomelane (Ba(Mn 2+ )(Mn 4+ ) 5 O 16 (OH) 4 ), sanbornite (BaSi 2 O 5 ) and witherite (BaCO 3 ), as well as combinations thereof.
  • API American Petroleum Institute
  • API Specification 13A Section 2
  • standards include a minimum density of about 4.1-4.2 g/cm 3 , a weight average particle size diameter between about 5 ⁇ m and about 75 ⁇ m, an amount of water-soluble alkaline earth metals (as calcium) of less than about 40 ppm, and an amount of barite particles having a size less than about 6 mm by weight in an amount of no more than 25 wt. %.
  • the weight average particle diameter of the weighting agent suitable for use in the compositions disclosed herein ranges from about 5 ⁇ m to about 50 ⁇ m.
  • the weighting agent includes at least 50% by weight particles in the range of about 10 ⁇ m to about 50 ⁇ m.
  • the weighting agent includes at least 70% by weight of particles in the range of about 5 ⁇ m to about 50 ⁇ m.
  • the fluid pressure transmission pills (FPTP) described herein may also include a number of other additives, including but not limited to corrosion inhibitors, scale inhibitors, and fluid loss control additives.
  • Any of the typically used fluid loss control additives known in the industry can be present in the fluid pressure transmission pill, such as gilsonite, asphalt, oxidized asphalt, organophilic lignites, and the like.
  • Exemplary organophilic lignites suitable for use in compositions of the present disclosure are set forth in the following U.S. Pat. Nos.
  • the fluid pressure transmission pills (FPTP) described herein can be used in a number of applications related to hydrocarbon exploration, including, but not limited to, managed pressure drilling (MPD), both horizontal and vertical drilling operations, tripping operations, wireline logging operations, completion operations, well control operations, well logging operations, and the like.
  • MPD managed pressure drilling
  • the compositions described herein are particularly suited for use in high-pressure, high-temperature subterranean environments.
  • the FPTP described herein exhibits thermal stability across a broad range of temperatures, and may be used with a drilling fluid for drilling wells in subterranean formations having a variety of geologies, wherein the subterranean formation has temperatures ranging from about 15° F. to about 450° F.
  • additives suitable for use in subterranean well bore drilling operations also may be present in the drilling fluids of the present invention if desired, including but not limited to, antifoams, biocides, bridging agents, corrosion control agents, dispersants, flocculants, fluid loss additives, foamers, H 2 S scavengers, lubricants, oxygen scavengers, scale inhibitors, viscosifiers, and weighting agents.
  • antifoams include but not limited to, antifoams, biocides, bridging agents, corrosion control agents, dispersants, flocculants, fluid loss additives, foamers, H 2 S scavengers, lubricants, oxygen scavengers, scale inhibitors, viscosifiers, and weighting agents.
  • the fluid may further comprise one or more brines.
  • Suitable brines for use with the FPTP compositions of the present disclosure include, but are not limited to, both light and heavy brines comprising KCl brines, NaCl brines, CaCl 2 brines, NaCO 2 H brines, KCO 2 H brines, CsCO 2 H brines, NaBr brines, CaBr 2 brines, KBr brines, CaCl 2 /CaBr 2 brines, ZnBr 2 brines, ZnCl 2 brines, ZnBr 2 /CaBr 2 brines, and ZnBr 2 /CaBr 2 /CaCl 2 brines, alone or in combination as appropriate.
  • the brines can be described in accordance with certain aspects of the present disclosure as an aqueous solution which contains from about 10 to about 350,000 parts per million of metal ions, such as lithium, sodium, potassium, magnesium, cesium, zinc, or calcium ions.
  • metal ions such as lithium, sodium, potassium, magnesium, cesium, zinc, or calcium ions.
  • the brines used in the compositions described herein may be described as containing from about 2% by weight to the saturated amount (e.g., about 35% by weight for CaCl 2 ) of the salt, which will vary by salt used in forming the brine.
  • the brines used to in the compositions of the present invention may also contain various amounts of other dissolved salts, including but not limited to sodium bicarbonate, sodium sulfate, sodium acetate, sodium borate, potassium chloride, or sodium chloride, without limitation.
  • the fluid compositions of the present invention include at least one oleaginous liquid, and may include a brine so as to form an emulsion, an invert fluid, or oil-as based invert emulsions.
  • oil based drilling fluids as used herein are defined as a hydrocarbon-based drilling fluids.
  • Oil based invert emulsions have an oil “continuous” phase and an aqueous internal phase.
  • emulsion as used herein is used to describe systems in which water is the external or continuous phase and oil is dispersed within the external phase.
  • invert it is meant that the hydrocarbon-oil substance is the continuous or external phase and that an aqueous fluid, such as water or a brine, is the internal phase.
  • the ratio of water (or brine) to oil in emulsions of the present invention should generally provide as high a brine content as possible while still maintaining a stable emulsion since a high water content drilling fluid is less expensive and less objectionable to work with than a drilling fluid containing a low water content.
  • Oil/brine ratios in the range from about 95 to 5 (95:5) to 50 to 50 (50:50) have been found to work satisfactorily, depending upon the particular oil/oleaginous fluid chosen.
  • the water (or brine) content of a typical fluid prepared according to the teachings of the invention may have, in accordance with certain embodiments, an aqueous (water or brine) content ranging from about 0 volume percent (vol. %) to about 50 volume percent, with the most preferred range being about 5 to 40 volume percent.
  • CLAYTONE® IMG 400 available from Southern Clay Products, Inc., Gonzalez, Tex.
  • PUREDRILL® HT-30 available from Petro-Canada, Calgary, Canada
  • JEFFSOL® propylene carbonate
  • Barium sulfate (Barite, available from Federal Wholesale Drilling Mud, Houston, Tex.) at a concentration of 288 lb/bbl was then added, and the final fluid composition was mixed for an additional 30 minutes at 5000 rpm before analyzing and testing as described below.
  • a viscosity measurement for the ultra-high viscosity pill thus prepared was performed by determining the Low Shear Rate Viscosity (LSRV) with a Brookfield LVDII+ viscometer at 0.3 rpm using a No. 3 cylindrical spindle. The result is shown in Table 1, below.
  • LSRV Low Shear Rate Viscosity
  • organophilic clay CLAYTONE® IMG 400 available from Southern Clay Products, Inc., Gonzales, Tex.
  • An amount of organophilic clay ranging from about 6 lb/bbl to 8 lb/bbl was added to 0.772 bbl of a low aromatic mineral oil (PUREDRILL® HT-30, available from Petro-Canada, Calgary, Canada) and allowed to disperse equally before adding 0.12 gal/bbl of propylene carbonate (JEFFSOL®, available from Huntsman Petrochemical Corp., Houston, Tex.).
  • the ingredients were then mixed for 15 minutes at 4600 RPM with an impeller-style mixer, forming a ‘clay gel’.
  • a clay gel composition was added 0.30 gal/bbl of emulsifier/wetting agent (STAB 2-CA, available from Quim Export, Inc., Houston, Tex.), and the solution mixed for 5 minutes before adding 298 lb/bbl of barium sulfate (Barite, available from Federal Wholesale Drilling Mud, Houston, Tex.).
  • STAB 2-CA emulsifier/wetting agent
  • Barite barium sulfate
  • the complete pill composition was then mixed for an additional 15 minutes at 3000 rpm before analyzing and testing as described below.
  • Viscosity measurements were carried out as described above, and were obtained at 0.0636 sec ⁇ 1 and 0.0660 sec ⁇ 1 . The results of these viscosity tests are presented in Table 1, below.
  • FIGS. 2 , 3 A, and 3 B show that the 6 lb/bbl (12.5 lb/gal) pill does not establish a barrier and mixes with the 15.0 lb/gal brine as it is pipetted into position, while the 8 lb/bbl pill allows the 15.0 lb/gal brine to channel through to the brine below, thereby displacing the pill upward.
  • cP thixotropic viscosifier
  • the fluid pressure transmission pill can be used in various other hydrocarbon recovery operations, including well-killing operations such as the simultaneous killing and cementing of a live well (e.g., kill the well so that the cement could be placed and allowed to set while at the same time not breaking down and losing circulation into the weak upper zones).
  • well-killing operations such as the simultaneous killing and cementing of a live well (e.g., kill the well so that the cement could be placed and allowed to set while at the same time not breaking down and losing circulation into the weak upper zones).
  • the phrase “well-killing operation” refers to the operation of placing a column of heavy fluid into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface, the procedure operating on the principle that the weight of the “kill fluid” or “kill mud” will be enough to suppress the pressure of the formation fluids.
  • the various embodiments of the ultra-high viscosity pill composition and methods of preparation and use in subterranean operations can be included in combination with each other to produce variations of the disclosed methods and embodiments. Discussion of singular elements can include plural elements and vice-versa.

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Cited By (24)

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US9169700B2 (en) 2010-02-25 2015-10-27 Halliburton Energy Services, Inc. Pressure control device with remote orientation relative to a rig
US20110203802A1 (en) * 2010-02-25 2011-08-25 Halliburton Energy Services, Inc. Pressure control device with remote orientation relative to a rig
US8201628B2 (en) 2010-04-27 2012-06-19 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US8261826B2 (en) 2010-04-27 2012-09-11 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US8820405B2 (en) 2010-04-27 2014-09-02 Halliburton Energy Services, Inc. Segregating flowable materials in a well
US8833488B2 (en) 2011-04-08 2014-09-16 Halliburton Energy Services, Inc. Automatic standpipe pressure control in drilling
US9080407B2 (en) 2011-05-09 2015-07-14 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US9447647B2 (en) 2011-11-08 2016-09-20 Halliburton Energy Services, Inc. Preemptive setpoint pressure offset for flow diversion in drilling operations
US20140020886A1 (en) * 2012-02-02 2014-01-23 Baker Hughes Incorporated Thermally Conductive Filler Suspended by Thixotropic Agents in Lubricant Oil
US10233708B2 (en) 2012-04-10 2019-03-19 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
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US10563111B2 (en) * 2012-08-20 2020-02-18 Tucc Technology, Llc Solubilized polymer concentrates, methods of preparation thereof, and well drilling and servicing fluids containing the same
US20140051606A1 (en) * 2012-08-20 2014-02-20 Tucc Technology, Llc Solubilized Polymer Concentrates, Methods of Preparation Thereof, and Well Drilling and Servicing Fluids Containing the Same
US20140209388A1 (en) * 2013-01-29 2014-07-31 Halliburton Energy Services, Inc. Wellbore Fluids Comprising Mineral Particles and Methods Relating Thereto
US20140209391A1 (en) * 2013-01-29 2014-07-31 Halliburton Energy Services, Inc. Wellbore Fluids Comprising Mineral Particles and Methods Relating Thereto
US20160068733A1 (en) * 2013-01-29 2016-03-10 Halliburton Energy Services, Inc. Wellbore fluids comprising mineral particles and methods relating thereto
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US20140209307A1 (en) * 2013-01-29 2014-07-31 Halliburton Energy Services, Inc. Wellbore Fluids Comprising Mineral Particles and Methods Relating Thereto
US20140209387A1 (en) * 2013-01-29 2014-07-31 Halliburton Energy Services, Inc. Wellbore Fluids Comprising Mineral Particles and Methods Relating Thereto
US9920604B2 (en) * 2013-01-29 2018-03-20 Halliburton Energy Services, Inc. Wellbore fluids comprising mineral particles and methods relating thereto
US20140209290A1 (en) * 2013-01-29 2014-07-31 Halliburton Energy Services, Inc. Wellbore Fluids Comprising Mineral Particles and Methods Relating Thereto
US10407988B2 (en) * 2013-01-29 2019-09-10 Halliburton Energy Services, Inc. Wellbore fluids comprising mineral particles and methods relating thereto
US20140209390A1 (en) * 2013-01-29 2014-07-31 Halliburton Energy Services, Inc. Wellbore Fluids Comprising Mineral Particles and Methods Relating Thereto
AU2014269066B2 (en) * 2013-05-21 2016-09-22 Halliburton Energy Services, Inc. Wellbore fluids comprising mineral particles and methods relating thereto

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EP2451886B1 (en) 2020-01-08
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WO2011006076A1 (en) 2011-01-13
RU2016117590A (ru) 2018-10-25
AR078061A1 (es) 2011-10-12
RU2724060C2 (ru) 2020-06-19
HUE049420T2 (hu) 2020-09-28
US20130130944A1 (en) 2013-05-23
US9850417B2 (en) 2017-12-26
CA2771045A1 (en) 2011-01-13
RU2016117590A3 (es) 2019-10-28
RU2012104567A (ru) 2013-08-20
AU2010271272A1 (en) 2012-03-01
EP2451886A1 (en) 2012-05-16

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